Hydrocarbon liquids which at surface conditions are high gravity
(e.g., ~ 45-60 oAPI) may be either a light oil (volatile
oil) or a gas condensate. A true condensate is a hydrocarbon LIQUID
at surface conditions that is a GAS at reservoir conditions, while
a volatile oil is a liquid at both surface and reservoir
conditions. Two, general "rules of thumb" for distinguishing
between a volatile oil and a gas condensate include:
(1) When the GOR of a produced petroleum is > 3,000 cu ft of
gas/ barrel oil (cfg/bo), then the liquid is a condensate (i.e.,
exists as a gas in the reservoir; Kingston, 1990).
(2) Condensates typically contain < 12.5 mole
%C7+, while volatile oils typically contain > 12.5
mole% C7+ (Danesh, 1998).
Those general rules of thumb are similar to the criteria
employed by The Organization of Petroleum Exporting Countries
(OPEC) in defining a condensate. Effective January 1, 1989, OPEC
defined condensate as any hydrocarbon liquid with an API of 50° or
higher, a gas:liquid ratio of 5,000:1 or higher, or a
C7+ fraction of 3.5 mole % or less. The OPEC criteria
also allowed certain other liquids that fell outside these limits
to also be considered condensates (depending on a variety of
factors), but a lower limit of 45 oAPI was set, as was a
limit of not more than 8% C7+ fraction (Kingston,
1990).
However, all of the "rules of thumb" listed above are only
general, and do NOT allow one to know with certainty whether or not
a given fluid is a gas condensates or a volatile oil. For example,
although gas condensates typically consist almost entirely of
C5-C10 range hydrocarbons. (Kingston, 1990),
in deep accumulations, due to high pressure and temperature,
relatively high-molecular-weight hydrocarbons may be part of a
condensate. As a case-in-point, Hunt (1996) reports that the
hydrocarbons C1- C18 are present in the gas
phase at 20,000 feet in the Maloosa condensate field, Italy
(reservoir pressure = 15,431 psi, temperature = 153 °C, reservoir =
Triassic dolomite).
The concentration of condensate dissolved in a gas may vary from
<10 to > 400 barrels condensate/ MMCFG, (Kingston et al.,
1990) and the concentration depends on a variety of factors. To
know with certainty whether or not a high-gravity liquid at surface
conditions was a gas or a liquid at reservoir conditions requires
PVT calculations (i.e., the answer must be determined through
"Equation-of-State" or "Pressure-Volume-Temperature" calculations,
e.g., see Danesh, 1998; Meulbroek, 2002; Meulbroek and MacLeod,
2002), and the answer depends on:
- The reservoir pressure
- The reservoir temperature
- The composition of the "dead" hydrocarbon liquid
- The composition of the gas co-produced with the dead
hydrocarbon liquid
- The gas/oil ratio of the co-produced gas and dead oil.
The following text is a discussion of the origin of
volatile oils (i.e., their source and the geological processes
responsible for their formation), and does NOT concern the origin
of "true" condensates. However, for ease of discussion, in the
following text, we refer to these volatile oils as
"condensates".
Condensates (high gravity hydrocarbon liquids) can be formed by
any of the following 5 geological processes:
1. Generation from Type III, gas-prone organic matter
("humic" material) THROUGHOUT the oil window range of maturities
(EARLY to LATE oil window, e.g., see Snowden, 1982
Examples: Condensates in many fluvio-deltaic environments, since
such environments commonly have higher-plant-rich source rocks.
Specific examples inlcude the Neocomian reservoirs of western
Siberia, and the deltaic sands of the Mahakam, Niger, and US Gulf
Coast Tertiary deltas.
Oil geochemistry indicators for this type of liquid:
- Very high pristane/phytane ratio (>2.5). The ABSOLUTE
abundance of these compounds will be low (due simply to their high
molecular weight), but the RATIO of these two compounds is HIGH in
this type of condensate.
- Compared to other types of condensate, in this type there is a
relative abundance of light aromatic compounds (benzene, toluene,
xylenes, etc.), which are a component of woody higher plant
material.
- Although the ABSOLUTE abundance of biomarkers will be low (due
simply to their high molecular weight), the RELATIVE abundance of
certain biomarkers (RELATIVE to other biomarkers of similar
molecular weight), will be high. Specifically, compared to other
biomarkers of similar molecular weight, there is a relative
abundance of higher-plant (angiosperm and/or conifer) diterpane and
triterpane biomarkers
in this type of condensate. Such compounds include saturated
hydrocarbons (e.g., oleananes, lupanes, bicadinanes) and/or
aromatic hydrocarbons (e.g., retene, cadalene, simonellite,
etc).
2. Generation at high maturity (late oil window) from
oil-prone or oil/gas-gas source rocks. Oil geochemistry
indicators for this type of liquid:
- Aromatic steroid maturity parameters suggest high maturity
(e.g., MA1/(MAI+MAII) ~ 1.0; TAI/(TAI+TAII) ~ 1.0).
- No abundance of higher plant biomarkers.
3. Cracking of oil in high-temperature reservoirs
(>140-170 °C, depending on the reservoir
lithology).
Examples: Gas-condensate fields in the Interior Salt basin,
southwestern Alabama, USA., and the Khuff Formation of the Persian
Gulf Region.
Oil geochemistry indicators for this type of liquid:
- High diamondoid concentrations (e.g., Dahl et al., 1999).
These compounds, which are present in all oils, are concentrated
during the oil cracking process, since diamondoids are very stable
and are not destroyed by oil cracking, while the other
non-diamondoid compounds are destroyed by cracking.
- Certain light hydrocarbon components are isotopically heavy
(e.g., Rooney, 1995; Chung et al., 1981) in this type of
condensate.
4. Evaporative fractionation (e.g., Thompson 1987,
1988): A geologic process in which (i) a charge of gas (generally
dry) enters an existing oil accumulation, (ii) the gas then
equilibrates with the light components of the reservoired oil, and
then (iii) the gas is vented from the accumulation, taking with it
dissolved components that originally were part of the oil
accumulation. The migrating gas may then condense out a liquid (or
"retrograde condensate") in a shallower reservoir. Therefore, this
process is the cause of two new fluids: (1) High-gravity retrograde
condensate in a shallower reservoir, and (2) Lower gravity, more
aromatic residual oil (in the original reservoir) depleted in light
paraffins and enriched in the other fractions. This process is
common in deltaic stacked pay sands.
Examples: Certain condensate fields in North Sumatra (Kingston,
1990).
Oil geochemistry indicators for this type of liquid:
- Depleted in light aromatic hydrocarbons relative to light
saturated hydrocarbons (due to the higher vapor pressure of
saturated hydrocarbons relative to aromatic hydrocarbons of similar
molecular weight).
- Depleted in cyclic and branched compounds relative to straight
chain compounds (due to the higher vapor pressure of straight chain
saturated hydrocarbons relative to branched and cyclic hydrocarbons
of similar molecular weight).
- Maturity indicators suggest that the liquid is NOT high
maturity.
- No abundance of higher-plant biomarkers relative to other
biomarkers of similar molecular weight.
- Under certain conditions, evaporative fractionation can also
result in generation of very AROMATIC-HYDROCARBON-RICH condensates.
This occurs when the parent oil undergoes REPEATED gas washing
episodes, such that no saturated compounds are left to be stripped
by migrating gas, and then a subsequent migrating gas is forced to
pick up a very aromatic-rich residue from the parent oil, and
delivers that material to a shallower reservoir where it condenses
out as an aromatic-hydrocarbon-rich condensate (e.g., Thompson,
1987).
5. Generation from relatively lean (i.e.,
organic-matter-poor) source rocks (e.g., <1.0 % TOC) containing
Type II or Type II organic matter where the gas/condensate is
separated from higher molecular weight hydrocarbons during the
primary migration out of the source rock. Oil geochemistry
indicators for this type of liquid:
- Low average molecular weight, due to loss of heavier
components during primary migration out of the source rock.
- Low diamondoid concentrations.
Significant exploration and development considerations for a
basin can often hinge on an understanding of which of the processes
discussed above is responsible for the formation of a given
high-gravity hydrocarbon liquid. Understanding which of these
processes is active in a basin is important because different
processes will result in different vertical and lateral
distributions of:
- hydrocarbon abundance,
- hydrocarbon GOR's, and
- condenstae API gravity.
Therefore, it is important to note that oil geochemistry
provides extremely useful tools for discerning the source and the
geological processes responsible for formation of condensates and
volatile oils.
For more information on the origin of condensates and volatile
oils, or to discuss a specific project, e-mail us at info@oiltracers.com,
or call us at U.S. (214) 584-9169.
REFERENCES:
Chung, H. M., S. W. Brand, and P. L. Grizzle, 1981, Carbon
isotope geochemistry of Paleozoic oils from Big Horn Basin:
Geochimica et Cosmochimica Acta, v. 45, p. 1803-1815.
Dahl, J. E., J. M. Moldowan, K. E. Peters, G. E. Claypool, M. A.
Rooney, G. E. Michael, M. R. Mello, and M. L. Kohnen, 1999,
Diamondoid hydrocarbons as indicators of natural oil cracking:
Nature, v. 399, p. 54-57.
Danesh, A., 1998, PVT and Phase Behaviour of Petroleum Reservoir
Fluids: Developments in Petroleum Science, v. 47: Amsterdam,
Elsevier, 388 p.
Hunt, J. M., 1996, Petroleum geochemistry and geology: San
Francisco, W.H. Freeman Co., 743 p.
Kingston, J., 1990, Estimation of condensate in the assessment
of undiscovered petroleum resources. Open file Report 90-230,
United Staes Geological Survey, 37 p.
Meulbroek, P., 2002, Equations of state in exploration: Organic
Geochemistry, v. 33, p. 613-634.
Meulbroek, P., and G. MacLeod, 2002, PVT properties in
exploration: Organic Geochemistry, v. 33, p. 611-612.
Rooney, M. A., 1995, Carbon isotope ratios of light hydrocarbons
as indicators of thermochemical sulfate reduction, in J.
O. Grimalt, and C. Dorronsoro, eds., Organic Geochemistry:
Developments and Applications to Energy, Climate, Environment and
Human History. Selected Papers from the 17th International Meeting
on Organic Geochemistry, Donostia-San Sebastián, The Basque
Country, Spain: San Sebastian, AIGOA, p. 523-525.
Snowdon, L. R., and T. G. Powell, 1982, Immature Oil and
Condensate: Modification of Hydrocarbon Generation Model for
Terrestrial Organic Matter: AAPG Bulletin, v. 66, p. 775-788.
Thompson, K. F. M., 1987, Fractionated aromatic petroleums and
the generation of gas-condensates: Organic Geochemistry, v. 11, p.
573-590.
Thompson, K. F. M., 1988, Gas-condensate migration and oil
fractionation in deltaic systems: Marine and Petroleum Geology, v.
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