lease sales, inaugurated in 1983, provided the oil industry an opportunity
to explore for oil and gas in the deep water Gulf of Mexico, a southern
extension of the oil-rich offshore Louisiana shelf province.
Key to Shell's success in reducing risk in this high-cost environment
was use of a direct detection of hydrocarbons technique, commonly
called "bright spots."
All of Shell's exploration wells in this play were selected to penetrate
"bright spots." The largest discoveries were found to have the added
benefit of deeper oil sands, where the seismic had weak or no visible
1983, Shell's Cognac field was producing in 1,000 feet of water, and
Exxon, Unocal and Conoco had oil production in fields of similar water
In the first area-wide Central Gulf lease sale, leasing was brisk
in water depths out to about 2,500 feet, concentrating in an area
a few miles from the 600-foot water depth shelf edge. Shell, under
the leadership of Billy Flowers, offshore vice president, and Doug
Beckman, exploration general manager, leased several prospects and
discovered Bullwinkle Field, which held about 150 million barrels.
All of Shell's bids and drilling locations were based on detailed
"bright spot" studies.
In the spring of 1984, several oil companies won leases on salt-related
prospects in deeper water. Shell cautiously made only a few bids because
of economic concerns, especially about technology available for deep-water
subsea wellhead completions. Tom Velleca, general manager of geophysics,
urged the offshore division to organize a team to search for opportunities
in the Garden Banks area, western Gulf of Mexico.
bid and won leases on several "leads," including two blocks in 2,900
feet of water over a salt dome named Auger, which was mapped by geophysicist
At this time, I was named general manager-exploration for Shell Offshore
and, during the next three years, was part of the team that discovered
several major oil and gas fields in the deep water Gulf of Mexico.
Shell shot a proprietary grid of seismic over its Garden Banks area
leases, and Auger was identified as the prospect with the most potential.
Two strong amplitude anomalies with good downdip structural conformity
were observed at depths of about 15,000 feet on the salt dome's west
flank. The "bright spots" extended west from Shells' acreage onto
two adjacent unleased blocks.
Geophysicist Mike Dunn mapped a deeper anomalous amplitude at a depth
of 19,000 feet, but data quality at this depth made the zone speculative.
Shell won the adjacent blocks in the 1985 sale with no competition.
It was early in 1987 before Auger was drilled.
Guaranteeing a Pay-Off
Shell management began discussions about expanding the "bright spot"
play into water depths of 3,000 to 6,000 feet.
Critical technical factors in these water depths were the needs for
thick continuous sands and high flow rates to allow profitable large
fields. Shell teams mapped salt ridges and associated north-south
trending regional synclines, where sands from the ancient Mississippi
River system might have "funneled" into deep water.
Two newly released logs from dry holes drilled by other companies
showed thick sand packages. The probability of commercial reservoirs
in deep water greatly increased. Seismic sequence packages helped
identify the submarine fan facies because the seismic reflection continuity
was much better than that in the shallower channel and levee sequences.
Exploration management asked the production department for guidelines
for field size needed to be economic in water depths between 3,000
and 6,000 feet. Gene Voiland and Carl Wickizer, production department
managers, boldly stated that if the exploration group discovered fields
of at least 100 million barrels, the engineers would find a way to
make Shell's deep-water discoveries economic.
While these exploration and economic studies were in progress, Shell
drilled an exploration test in 3,000 feet of water on Prospect Powell,
mapped by Bill Trojan and leased in the 1984 sale. The well was planned
to penetrate a very strong shallow amplitude anomaly and a deeper,
poorer quality amplitude anomaly that was located on a weak south-plunging
Drilling indicated the shallow anomaly was not associated with commercial
hydrocarbons. However, Don Frederick, division exploration manager,
excitedly reported a 40-foot thick oil pay at the deeper level.
Appraisal drilling and a 3-D seismic survey showed the deeper trap
was stratigraphic -- a submarine fan with channel and levee deposits
and many thin laminated sands.
Shell and Amoco are developing the 250 million barrel field, called
Ram-Powell, using a tension leg platform.
Shell began acquiring leases in water depths up to 6,000 feet. A
large structure called Prospect Mensa in 5,400 feet of water was
mapped and showed an excellent "bright spot" with a "flat spot."
Recognition of a "flat spot" suggested a hydrocarbon-charged sand
of considerable thickness.
monitoring the drilling well in 1987, Shell well-site geologist
Adrienne Allie reported the mud log indicated a marl followed by
a weak "show" in a thin sand at the anticipated depth of the "bright
spot." The disappointment vanished later in the day, when a good
gas "show" in a thick, medium-grained sand was found.
spot" correlated to a 115-foot gas sand, almost exactly as geophysicist
Gordon Li had predicted.
developed the 700 BCF field using three wells with subsea completions.
The Mensa discovery demonstrated the presence of thick, excellent
quality sand that could produce at rates over 100 MMCFG/D per well.
Auger was ready for drilling in 1987. Bill Sullivan, operations
project leader, and his staff prepared a drilling recommendation
on Auger that would test all the "bright spot" intervals, including
the deep speculative anomaly.
results indicated the two "bright spots" at 15,000 feet were associated
with oil and gas zones, but the sands were generally poor quality.
million had been spent on the drilling by this time, and some geoscientists
thought the targeted deep seismic amplitude was a salt reflector.
However, Jim Funk, division exploration manager, strongly recommended
that drilling continue, as every thin sand below 15,000 feet was
maker" oil-bearing sand was found at about 19,000 feet and correlated
to the recognized deep seismic amplitude anomaly.
appraisal drilling, Shell built a tension leg platform to develop
the 250 million barrel field. The 19,000-foot oil pay could be easily
mapped with the use of 3-D seismic, and this mapping in conjunction
with the appraisal drilling data markedly reduced the number of
the first two Auger development wells each tested at rates of over
10,000 BOPD; this production rate and field size caused the oil
industry to re-look at deep-water economics.
Mars story starts in 1986. Roger Baker, district manager, encouraged
his staff to search for prospects within a regional two- by two-mile
seismic grid in the deep water, so that Shell could make a "land
made a regional map over a large area, and one of his favorite "leads"
was named Mars. Dan Newman, Patrick Franklin and Henry Pettingill
continued the prospect evaluation.
strong seismic reflection was observed on two seismic lines located
on the south flank of a shallow salt dome. Additional seismic was
acquired and turbidite sands were projected into the prospect area
by the technical team.
management was in the final stages of bid preparation when Mars
was added to the bid list for the spring 1986 lease sale. The Mars
"lead" was considered speculative acreage, along with many other
Shell bids in that lease sale.
I was reassigned within Shell Oil in mid-1987, detailed seismic
mapping continued to indicate that Mars was a high-risk prospect
-- the chance of success was estimated to be only 10 percent because
the seismic amplitude appeared to continue downdip into a syncline,
and because Shell interpreted thin sands being present as a reservoir.
oil reserve potential and the apparent marginal economics was a
great concern. Jim McClimans, deep water exploration manager, led
the Shell negotiation team that brought in BP as partner.
began in early 1989, and an oil pay was found to be associated with
the mapped "bright spot." The economics were still considered marginal,
but management decided to continue drilling, and many additional
blocky sand oil pays were found hidden as deeper sands that lacked
"bright spot" support on the seismic available at that time.
drilling indicated a 700 million barrel discovery, and Mars is being
developed using a tension leg platform. Individual wells are producing
20,000 to 30,000 BOPD.
the Mars discovery, Bill Broman, general manager-exploration, told
me that he expected Shell to have three to five BBOE discoveries
on their acreage in the Gulf of Mexico deep water.
Shell deep water successes, especially the large production rates
and reserves per well at Auger, caused the oil industry to be more
optimistic about deep water economics, and other companies began competitive
leasing and drilling programs.
This past January, Shell stated that it had interests in about 40
deep water discoveries, with 12 fields on production and an additional
four fields under development.
Shell has participated in half of the eight billion barrels oil and
gas equivalent discovered to date. They operate 600,000 BOE/D of the
1.2 MMBO/D production in the deep water, and Shell working interest
production is about 400,000 BOE/D.
The company spent over $1 billion, including expensive dry holes,
before having enough data to be confident of a successful play.
Of course, profitability is sensitive to oil prices, and there are
many technical challenges in deep water -- but the combination of
large reserves and technology application should result in very favorable
did I learn from the deep water exploration play of the mid/late 1980s?
a good area to explore for large, deep water oil fields is the
downdip extension of oil rich offshore shelf provinces in combination
with a large ancient river system to deposit turbidite sands.
"bright spot" technology was crucial to lowering risks and finding
large reserves in the deep water.
if you're drilling in thin oil sands, keep drilling until you
run out of oil shows.
senior management must have a long-term commitment and strong
"staying power" to be a leader in expensive deep water plays.
early entry into a large potential oil play, based on good geological
concepts using sparse information plus a strong geophysical effort,
can "pay off" with large discoveries.
geologists, geophysicists and engineers need to work closely together
to make deep water discoveries into commercial fields.
Is this the way it really happened?
Maybe ... at least,
that's the way I remember it