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Digging Deep Pays Off in Louisiana

‘Bring Lots of Money'

Don't believe it when some of the pundits tell you South Louisiana is "all drilled up." Indeed, there's compelling evidence that the onshore region harbors a vast storehouse of hydrocarbons yet to be tapped by the drillbit.

But it's going to require some deeper digging — and some deep pockets.

This was the message delivered by industry veteran Frank Harrison Jr., president of aptly-named Optimistic Oil Co., during a presentation at the Dealmakers' Conference segment of the recent APPEX show in Houston.

To substantiate his viewpoint, Harrison displayed a map of the area showing 49 wells either completed or drilling below 16,000 feet, with most of these greater than 17,000 feet.

It's all because of 3-D seismic, he said.

"Structures in the 17,000- to 19,000-foot range were either ill-defined or else not-defined by 2-D, but we're finding very attractive, great big, deep structures based on 3-D, especially with better processing, interpretation and gathering," Harrison noted. "And my message is it's going to get even better."

A "snapshot" look at the drilling results on certain of these deeply buried structures showed some significant finds.

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Don't believe it when some of the pundits tell you South Louisiana is "all drilled up." Indeed, there's compelling evidence that the onshore region harbors a vast storehouse of hydrocarbons yet to be tapped by the drillbit.

But it's going to require some deeper digging — and some deep pockets.

This was the message delivered by industry veteran Frank Harrison Jr., president of aptly-named Optimistic Oil Co., during a presentation at the Dealmakers' Conference segment of the recent APPEX show in Houston.

To substantiate his viewpoint, Harrison displayed a map of the area showing 49 wells either completed or drilling below 16,000 feet, with most of these greater than 17,000 feet.

It's all because of 3-D seismic, he said.

"Structures in the 17,000- to 19,000-foot range were either ill-defined or else not-defined by 2-D, but we're finding very attractive, great big, deep structures based on 3-D, especially with better processing, interpretation and gathering," Harrison noted. "And my message is it's going to get even better."

A "snapshot" look at the drilling results on certain of these deeply buried structures showed some significant finds.

For instance, a well at Kent Bayou field in Terrebonne Parish encountered 700 feet of hydrocarbon column reaching down to 18,700 feet where the rock porosity averaged 25 percent, indicating little deterioration. The wells here test on the order of as much as 30MMcfg/d and maybe 5,000 barrels of condensate, Harrison said, with actual gas production generally in the range of 50-60MMcf/d.

At the current price of more than $3/Mcf, revenue is significant. But so is the price tag on the wells: perhaps as much as $14 million.

Harrison's "snapshot" also included activity in that near-legendary set of rocks: the deep Tuscaloosa formation, where fortunes have been made and lost and then made again and again ...

At Judge Digby Field near Baton Rouge, for instance, production occurs down to 23,000 feet, where porosities are in the 20 percent range. The field is making 250 MMcfg/d, according to Harrison, who said there are still more great opportunities in the Tuscaloosa because of 3-D seismic.

"Y'all need to come back and take another look at the deep Gulf Coast basin onshore, because there's clearly a lot of reserves," Harrison said. "Just bring lots of money, because the real future is in the deeper rocks."

Offshore Success Story

But the rocks don't stop at the shoreline, and some folks think it's far more prudent to focus their drilling activity on the seaward side of the coast in federal waters.

In a presentation on the same APPEX program, Ron Neal, president of Houston Energy, noted he and partner Billy Harrison learned quickly that a small company can't afford to spend a lot of money on land costs and seismic data and then not have the prospect drilled because someone else jumped in and leased the target acreage, which is not an uncommon occurrence when prospecting onshore.

Houston Energy debuted in 1988, focusing on the Texas and Louisiana onshore and west Texas. After struggling with the problems of expensive onshore seismic data, unavailable leases and such, the partners cast their collective eyes offshore, ultimately forming partnerships with others in 1994 to work the GOM with 3-D seismic data.

"We thought it made sense to form offshore partnerships because of the high cost to make our first entry into the Gulf," Neal said. "It was a way to share the cost of 3-D and overhead along with the reserves and rewards."

Neal reeled off more than a couple of dozen reasons as to "why offshore," leading off with the contribution of risk modifiers: AVO and bright spots.

"We wanted a shot at looking at something that lit up at night," geologist Neal said, "something that even a geologist could see. And we liked the small, aggressive investor/partner market and the fact that this is an area of higher success rates and generally higher flow rates than onshore."

Some of the myriad other reasons for "why offshore" included:

  • Multiple seismic vendors.
  • Generally higher quality seismic data.
  • Open leases.
  • Scheduled lease sales.
  • Royalty relief.
  • No oyster leases.
  • No severance tax.

Neal also noted there are no unit hearings where the company would risk losing an interest, recalling one such hearing where Houston Energy lost 90 percent of a well it drilled in Louisiana.

"That's when I became a true believer in the offshore," he said.

Still, it's not a perfect world out there in the water, he admitted, even though the negatives comprise a short list:

  • Higher drilling costs.
  • Expensive platforms and production facilities.
  • Higher pipeline costs.
  • Higher operational overhead.
  • More expensive recompletions.
  • Longer time between expenses and first production.
  • More governmental agencies and regulations.

To date, Houston Energy has drilled 120 wells in the GOM federal waters since1995. Of the total reserves found, 58 percent have been found through leases and 42 percent through trades and farmouts.

Neal said economic completions have risen steadily to 66 percent largely because of increased use of AVO, especially volume AVO.

"Our success rate, if we just use amplitude with 2-D AVO, is 66 percent," he said, "and if we have volume AVO response to a prospect, the success is 74 percent."

Next on the agenda, Neal noted, is deep gas — for a multitude of reasons:

  • Royalty relief.
  • Large field potential.
  • Fewer penetrations: Only 702 wells, or about 1.7 percent of total drilling in the GOM, have drilled deeper than 15,000 feet.
  • Higher quality seismic with better deep resolution.
  • Longer cable length data, which allows for more reliable AVO processing.
  • Use of AVO as risk modifier.
  • 3 Availability of volume AVO over large areas.

Given its track record offshore and the big plans to go after deep gas, it's noteworthy that this relatively small company, which now boasts an inventory of 2,300 blocks of 3-D data offshore, got started with a $10,000 investment by each of the two founders who made no further financial contributions and never borrowed funds from any lender or institution, according to Neal.

While many of their peers have succumbed to the lure of the IPO, with its attendant headaches and problems, don't look for Neal and Harrison to follow suit.

"We've heard a lot of talk here today about EBITDA, and I'm not sure what EBITDA is," Neal noted facetiously, "but I do know we don't have it."

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