'Bright' Investments Paid Off

Editor's note: This is the third of three articles by Mike Forrest, working in collaboration with Marlan Downey, on the application of "bright spot" technology, which helped Shell discover many large oil and gas fields in the Gulf of Mexico during the late 1960s to the late 1980s. Forrest also wants to thank the several former Shell Offshore employees -- especially Jim Funk -- who made contributions to this article.

Area-wide 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 amplitude anomalies.

Winning the Bid

By 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 depths.

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.

Shell 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 B.B. Hughson.

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

Meanwhile, 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 nose.

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.

Mensa

In 1985, 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.

While 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.

The "bright spot" correlated to a 115-foot gas sand, almost exactly as geophysicist Gordon Li had predicted.

Shell 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

Prospect 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.

Drilling results indicated the two "bright spots" at 15,000 feet were associated with oil and gas zones, but the sands were generally poor quality.

Over $20 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 hydrocarbon bearing.

The "field maker" oil-bearing sand was found at about 19,000 feet and correlated to the recognized deep seismic amplitude anomaly.

After 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 development wells.

In 1991-92, 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

The prospect 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 play."

Hanh Nugyen 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.

A 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.

Shell 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.

After 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.

The small 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.

Drilling 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.

Appraisal 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.

After 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.

Lessons Learned

The 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 economics.

What did I learn from the deep water exploration play of the mid/late 1980s?

That 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.
That "bright spot" technology was crucial to lowering risks and finding large reserves in the deep water.
That if you're drilling in thin oil sands, keep drilling until you run out of oil shows.
That senior management must have a long-term commitment and strong "staying power" to be a leader in expensive deep water plays.
That 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.
That 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.