Gas-Oil Ratios (GOR's) may vary substantially among petroleum
accumulations in a basin due to a variety of factors. These factors
fall into 3 categories:
(1) Source-related factors
- Organic matter Type. Type III organic matter
(derived primarily from higher plants) is more gas prone than Type
II or Type I organic matter (derived primarily from algae).
Therefore, differences in organic matter type across a basin can
result in differences in the GOR of the various accumulations. This
effect is commonly seen in deltas, for example, where the average
GOR of petroleum accumulations sourced from a higher-plant-rich
delta-plain facies is greater than the average GOR of accumulations
sourced form more algal-rich pro-delta facies
- Source rock maturity: As a source rock
matures, the GOR of the expelled products rises. Differences in
source maturity across a basin can therefore affect the GOR of the
various overlying petroleum accumulations.
(2) Migration-related factors:
- The classic "Gussow" fill-spill migration sequence
(Gussow, 1954): In a series of traps that have a
fill-spill relationship away from the source kitchen (where traps
spill from the bottom of one trap to the next up-dip trap, and then
spill from the bottom of that trap to the next up-dip trap), traps
closest to the kitchen would have a higher GOR (assuming a
completely efficient gas and oil seal for all of the traps in the
sequence).
- Differences in seal efficiency between traps:
The most efficient seals with respect to both oil and gas are
evaporites (halite, anhydrite, etc.), mineralized shales, and
igneous rocks. Other rock types (such as normally pressured shales)
create less efficient seals. For such imperfect seals (which form
the seals of most accumulations), an accumulation is most likely to
leak where the column height is greatest (e.g., at the crest of a
structure), since the capillary pressure is highest there. Since a
gas phase, if present in the accumulation, is located at the top of
the petroleum column, accumulations at bubble point will
selectively lose gas if there is a sufficiently thick petroleum
column (e.g., Sales, 1993). Therefore, a gas is more likely to be
lost from an accumulation than is oil. As a result, differences in
seal lithology between traps in a basin can result in differences
in the GOR of the accumulations, even if the GOR at the time each
trap was charged were the same among the various traps. Some points
to note regarding the discussion above:
- In all cases (except diffusion), the petroleum must be at
bubble point for phase separation to occur.
- The effect of the height of the column on capillary pressure
has a much more important effect on seal leaking than does
differences in the sealing capacity between gas and oil. In
general, gas has higher surface tension and less wetability than
oil, so at a given capillary pressure, a seal will more effectively
hold back gas than oil. However, gas is less dense than oil, and,
as a result, for a given column height, the added buoyancy of the
gas (relative to a similar column height of oil) overcomes the
higher surface tension of the gas relative to oil.
- Exactly the same seal efficiency concept applies to fault
seals. Faults may, or may not, be good seals (e.g., Brown, 2003):
the sealing capacity of a fault depends on factors such as (i) what
lithology is juxtaposed against what, and (ii) the composition of
the fault gouge (e.g., Allan, 1989). Therefore, differences in seal
lithology and fault characteristics between one trap and another
plays an important role in determining the GOR of an accumulation
(e.g., Watts, 1987). An accumulation is most likely to leak across
a fault where the column height is greatest, since the capillary
pressure is highest there. Since a gas phase, if present in the
accumulation, is located at the top of the petroleum column,
accumulations at bubble point will selectively lose gas across a
fault if there is a sufficiently thick petroleum column. Therefore,
a gas, if present, is more likely to be lost across a fault seal
than is oil.
- Evaporative fractionation: Sometimes called
"Gas Washing", this is a geologic process in which (1) a charge of
gas (generally dry) enters an existing oil accumulation, (2) the
gas then equilibrates with the light components of the reservoired
oil, and then (3) the gas leaks 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 at lower
pressure. 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
(e.g., Thompson, 1987, 1988).
(3) In-Reservoir Alteration:
- Cracking of oil in high temperature reservoirs
(>140oC when TSR is active; >150-170oC
when TSR is not active).
- Bacterial gas formation: In shallow
biodegraded accumulations (reservoir temperatures
<80oC), bacterial reduction of CO2 to form
biogenic gas can raise the GOR of biodegraded accumulations (e.g.,
Larter et al., 2006).
Oil
geochemistry and Gas Geochemistry can be
used to evaluate which of the items above are responsible for
differences in GOR between accumulations in a basin. For example,
Gas Chromatography (GC) and biomarker
analyses can indicate whether oils from different
accumulations were generated from sources rocks with different
organic matter type. Similarly, GC and biomarker analyses can
indicate whether oils from different accumulations were generated
from sources rocks of different maturity. The presence or absence
of post-emplacement
alteration can also be evaluated using oil
geochemistry and gas geochemistry.
Migration modeling can be used to evaluate aspects of (2) above.
Characterization of the trap and seal geology can help evaluate
other aspects of (2) above.
In summary, a report that integrates oil geochemistry, gas
geochemistry, migration modeling, and geology can lead to an
improved understanding of the causes of GOR variations in a
basin.
For more information on the approaches described here, or to
discuss a specific project, e-mail us at info@oiltracers.com,
or call us at U.S. (214) 584-9169.
REFERENCES:
Allan, U.S., 1989, Model for hydrocarbon migration and
entrapment within faulted structures: AAPG Bulletin, v. 73, p.
803-811.
Brown, A., 2003, Capillary effects on fault-fill sealing: AAPG
Bulletin, v. 87, p. 381-395.
Gussow, W. C., 1954, Differential entrapment of oil and gas: a
fundamental principle: AAPG Bulletin, v. 38, p. 816-853.
Larter, S., H. Huang, J. Adams, B. Bennett, O. Jokanola, T.
Oldenburg, M. Jones, I. Head, C. Riediger, and M. Fowler, 2006, The
controls on the composition of biodegraded oils in the deep
subsurface: Part II - Geological controls on subsurface
biodegradation fluxes and constraints on reservoir-fluid property
prediction: AAPG Bulletin, v. 90, p. 921-938.
Sales, A., 1993, Closure vs. seal capacity: a fundamental
control on the distribution of oil and gas: in.: AAPG
Hedberg Conference: Seals and Traps: a multidisciplinary approach:
June 1993, Crested Butte, CO (Abstr.).
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.
5, p. 237-246.
Watts, N. L., 1987, Theoretical aspects of cap-rock and fault
seals for single- and two-phase hydrocarbon columns: Marine and
Petroleum Geology, v. 4, p. 274-307.