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Catalytic Gas
in Deltaic Basins
A Field Test in the Gulf of
Mexico
Petroleum Habitats, LLC
Abstract:
A new assay for measuring catalytic
activity (Assay) and a model for predicting % gas
with depth (Model) were tested in Bastian Bay and
Midland fields in southern Louisiana, GOM. The Model
accounts for 90% of the gas in Bastian Bay, 55% of
the gas in Midland, and 87% of the gas in the basin.
Its greatest power was in answering the three
mysteries that characterize this basin (Paine et
al., 1968) : why is gas associated with outer-neritic
shales, why is oil preserved on the flanks of salt
domes, and why is there a transition from high oil
probability to high gas probability at 10,000 ft?
Because outer-neritic shales are
the most active rocks in this basin, reservoirs on
the flanks of salt domes are sterile and thus the
least active rocks in the basin, and the sharp
transition from oil to gas reflects the exponential
nature of catalytic gas generation in rocks of this
activity range.
The results suggest that most of
the gas in deltaic reservoirs (> 50%) is indigenous
catalytic gas. The Assay and the Model are new tools
for understanding the dynamics of gas generation and
for predicting the distribution of oil and gas in
these basins.
Activity logs of strategic
wells map oil and gas in three dimensions, thus
highlighting opportunities for hydrocarbon-specific
(oil or gas) drilling. This is something totally new
in exploration, with powerful implications where oil
or gas carries a premium.
Introduction:
The scientific discovery that a
source rock was naturally catalytic in the
conversion of oil to gas (Mango et al., Nature
368, p 536, 1994) had broad
implications, but they were never pursued because
measuring rock activity at that time was tedious
(the experiments took several days to weeks) and
inaccurate. This changed in 2004 with a new rock
assay (Assay) (US Patent allowed 8/06) that measured
rock activity in hours with > 80% accuracy
(cuttings, core, and outcrop). Since only one rock
(a source rock) had been analyzed at that time,
there was no way of knowing whether or not ordinary
reservoir rocks were catalytic. And, if they were,
could the Assay account for the amounts of gas
typically found in basins and predict % gas with
depth? We chose a deltaic basin to field test the
Assay because they are generally rich in gas and
because other models had been largely unsuccessful,
rarely predicting gas with greater than statistical
chance.
The southern Louisiana portion of
the giant Gulf of Mexico geosyncline was selected
because of the wealth of data in Paine et al. (AAPG
Memoir 9, Vol I, pp 376-581, 1968). We also had
access to old well cuttings and cores, warehoused
here in Houston (BEG). Over 30 samples were assayed,
mostly from Bastian Bay Field (Plaquemines Parish)
and Midland Field (Acadia Parish).
Field Test Purpose:
Can rock activities measured by Assay
account for Paine’s observations that characterize
this basin:
- 84% gas in Bastian Bay
Field
- 91% gas in Midland Field
- 66% gas in the basin
- High gas probability in
reservoirs with interbedded outer-neritic shales
- High oil probability in
reservoirs on the flanks of salt domes
- A transition from high
oil probability to high gas probability at 10,000
ft.
The basic idea of the model is
simple. The rate of catalytic gas generation
increases exponentially with depth (temperature) and
it can be modeled from basic assumptions (Model).
The Model generates a % Gas vs Depth curve for each
rock activity. Figure 1 is a 3-D graphic
representation of the Model (a family of curves)
showing the relationship between hydrocarbon mix (%
Gas), measured rock activity (ppb), and depth for
reservoir rocks in a deltaic basin, GOM.
Figure 1.
Hydrocarbon composition in deltaic reservoirs, Gulf of
Mexico.
Field Test Results:
- Predicting % Gas in
Bastian Bay, Midland, and the Basin:
Model accounted for 90% of the gas
in Bastian Bay, 55% of the gas in Midland, and 87%
of the gas in the basin.
- Accounting for high
gas probabilities in reservoirs with outer-neritic
shales:
Sandstone rocks with outer-neritic
shale showed robust activities. The most active
(Atlantic – Cowen well, 10,881 ft, Midland Field)
varied between 2000 and 4000 ppb depending on the
amount of shale in the sample; they were on average
50 times more active than average reservoir rocks.
The Model projects only gas in these reservoirs at
all depths > 10,000 ft (Figure 2).
- Accounting for high
oil probabilities in reservoirs on the flanks of
salt domes:
Our experiments show that the
sulfates in evaporites are toxic to active metals,
sterilizing a rock’s capacity to convert oil to gas.
Reservoirs on the flanks of salt domes should be
sterile, thus incapable of converting oil to
catalytic gas. The Model predicts oil in these
reservoirs to 22,000 ft and greater based on
estimated activities at ppt levels.
Figure 2.
Hydrocarbon composition in deltaic reservoirs, Gulf of
Mexico. A) Normal sandstone reservoirs. B) Estimated
rock activities for sulfate sterilized reservoirs
adjacent to salt domes. Cram cites deep deposits of oil
on the flanks of salt domes in this basin (Cram, “Deep
Hunting Grounds” AAPG Bulletin, 12, 2009-2014, 1963) and
Paine cites a high probability for oil on salt domes
throughout the basin (Paine et al., AAPG Memoir 9,
376-578, 1968).
- Accounting for the
transition from high oil probability to high gas
probability at 10,000 ft :
Assuming reservoir depths cited in
Paine and measured activities for our rock set, the
Model shows a clear oil to gas habitat transition at
10,000 ft (Figure 3).
Figure 3. % Gas generated in 1,000 reservoirs with
activities measured by Assay. Figure 3. 1,000 Model
simulations assuming random activities within measured
activities (10 to 1,000 ppb) and random depths within
the limits of actual depths. Sulfate-poisoned reservoirs
(ppt activities) were not included in these simulations
because the intention was to highlight the transition in
normal reservoirs rocks (ppb activities).
CONCLUSIONS:
The Model gives a simple,
and totally new picture of gas generation in deltaic
basins. Gas is mainly indigenous, formed in-place
catalytically. The major source of hydrocarbons was
probably marine Type II source rocks, and the
original reservoir charge was oil with associated
primary thermal gas (~ 20%). There is no need to
invoke unidentified gas-prone source rocks to
explain the large amounts of gas in this basin
because the reservoirs are sufficiently catalytic to
convert their original oil charge to the gas
currently in-place .
Perhaps its greatest power
was in solving the three mysteries that characterize
this basin (Paine et al., 1968): why is gas often
found in reservoirs containing outer-neritic shales,
why is oil predominantly found on the flanks of salt
domes, and why is there a sharp transition from high
oil probability to high gas probability at 10,000
ft? Very simply, outer-neritic shales are the most
active rocks in this basin, reservoirs on the flanks
of salt domes are sterile and thus the least active
rocks in the basin, and the sharp transition from
oil to gas reflects the exponential nature of
catalytic gas generation at these activities.
No other model or theory can
explain all of this. The fact that the Model can,
and does so concisely, argues that the Model is
fundamentally correct.
Frank Mango, PhD
Founder, President, and CEO
Petroleum Habitats, LLC
281-497-0384
f mango@petrohabs.rr.com
www.petroleumhabitats.com
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Gulf of Mexico
