The industry’s ongoing infatuation with Canada’s oil sands, the Rockies’ tight gas sands and most any shale deposit anywhere might suggest the long-productive and mostly conventional Gulf Coast reservoirs have lost their allure.
Not the case.
It was indeed timely that a forum on the Gulf region’s potential for continuing the supply leadership was held at the recent Summer NAPE event in Houston.
The offshore – particularly the deep water – continues to attract the operators, despite the fact that a few high profile names have exited the scene, according to AAPG member Bob Fryklund, vice president of industry relations at IHS Energy, which sponsored the forum.
Onshore, he said, many plays look to be struggling to stay in place from a reserves standpoint.
On the other hand, there are land plays that are doing quite well.
“There are some bright spots like the Cotton Valley play in Texas and Louisiana where the wells are still holding up nicely,” Fryklund noted. “The overall gas is close to 700 million cubic feet a day out of the Cotton Valley play.”
In fact, continuing interest in the conventional onshore Gulf Coast reaches far and wide – much further than you might think.
A visit to the Pryme Oil and Gas booth at NAPE left no doubt that eyes from a whole other continent are focused on the region’s potential.
Australia-based Pryme is going full-tilt in Louisiana, where it holds – and continues to acquire – considerable interests in myriad locales in the state, including LaSalle, Calcasieu, Lincoln, Avoyelles and East Baton Rouge parishes.
“Seven years ago, some of us invested in a U.S. company and learned a couple of lessons about how to drill for oil and gas, and how much things really cost,” said Justin Pettett, managing director at Pryme. “We worked in the United States for close to five years, principally in Oklahoma and LaSalle Parish.
“We had the most success on a financial and geological basis in Louisiana,” Pettett said. “The LaSalle project, now with 25 producing wells, continues to be a consistent, low maintenance income generator for Pryme.”
When queried about such a distant base of operations versus staying at home, Pettett, who has a background in financial services and capital markets, said “The physical cost to do business in Australia is very high … Transportation and infrastructure cost can be two to three times the cost to drill a well.
“However, we have a niche in Australia as far as our capital markets,” Pettett added, “and we wanted to make the opportunities we saw (in the United States) available to Australian investors.”
In keeping with its plan, the company established relationships early on with geologists and geophysicists who have honed their expertise in Louisiana. This led to affiliations with prospect-generating Amelia Resources and Wave Exploration based in The Woodlands, north of Houston.
Pryme’s current plans include drilling its high-impact deep Atocha exploration prospect in 2008 in central Louisiana’s famed Tuscaloosa Trend play. The well is expected to be drilled to approximately 17,000 feet. In contrast, the company’s recently drilled Spinks-Middlebrooks #11-1 well in Lincoln Parish reached TD at 10,900 feet, tested for a September completion in the Upper Jurassic Cotton Valley sands.
“As a company, we have diversified risk,” Pettett noted. “We’re keeping more of an interest in lower risk, lower capital cost projects and farming out higher risk, higher reward projects.”
‘Something for Everyone’
Even though all NAPE meetings typically include a host of Gulf Coast prospects, a “something for everyone” approach tends to characterize each expo.
In fact, Houston-based Benchmark Oil and Gas was ensconced in a booth next door to Pryme at the recent event, showing its Gulf Coast deals, located in Orange and Lavaca counties, Texas, alongside an Alaskan prospect at Cook Inlet.
“We also looked at the (nearby) Susitna area, but it’s all wildlife refuge,” said AAPG member Robert Pledger, president of Benchmark. “People are taking leases there, but they’re years away from drilling because of environmental issues.
“After having drilled in California, we’ve been to that rodeo,” Pledger noted. “At Benchmark, we only go where there’s infrastructure, where everything’s developed.”
Summer NAPE exhibitor Hewitt Energy Group’s specialty is bringing renewed life to old fields using new methodology.
Opportunities in Kansas – long a hot spot for improved recovery projects – figured prominently at Hewitt’s NAPE display.
The company has become adept at ramping up production in abandoned and stripper wells using a methodology it pioneered in 1991, according to Douglas Hewitt, CEO and president. He noted they refer to the technique as “hydrostatic reduction, allowing for hydrocarbon expansion.”
The process – similar to de-watering – entails production of large volumes of water to lower the pressure in the reservoir, enabling the hydrocarbons to expand and move to the wellbore, resulting in increased production. The application has proven to be successful in producing large amounts of oil in places thought to be depleted, according to Hewitt.
“We go to an area where a lot of oil and gas has been produced, determine essentially the original oil in place, deduct reported production and figure out what percent of the reservoir system has been produced,” Hewitt said.
“Based on our methodology, we know we can recover 75 percent of reserves in place, but typically we say 40 to 50 percent.”
Hewitt presented an example of what can be accomplished in a field using a large disposal well in combo with big mechanical pumps in the wellbore.
“We put a well on line in this field, and the first day we made 36 barrels of oil moving 4,700 barrels per day of water,” he said. “That was two weeks ago, and today we’re at 74 barrels of oil a day.
“By the time we’re fully done with this field – and it could be three-to-five years from now – I suspect it probably will level out between 300 and 500 barrels of oil per day at a cost of two and a half-million dollars to us and be 100 percent successful.”