Whether the Tuscaloosa Marine Shale turns out to be the kind of prospect that ranks among energy industry biggies is still a waiting game, one of the trend’s followers said last week.
A handful of wells drilled into the Louisiana/Mississippi formation, which covers up to seven million acres, have indicated some solid, early results, but “it’s still early to say” whether the trend is comparable to the Eagle Ford Shale, according to petroleum geologist Richard Barrell.
Barrell, president of privately held explorer Amelia Resources LLC, has been working on the Tuscaloosa trend since the 1990s; his company has around 120,000 net acres in the play. Barrell, who writes a blog about the formation using public data and inside sources, has a stack of technical papers about the trend dating back to 1997. He offered some insight into what he thinks the future holds for explorers in an hour-long conference call hosted by Canaccord Genuity.
While the formation may be on par with the Eagle Ford Shale or other prolific onshore gushers, the data doesn’t indicate that — yet.
“Most companies have taken pilot cores, and the most recent cores are held by proprietary data,” said Barrell of the Tuscaloosa. “We have seen some good, core proprietary data from the wells drilled…Overall, there’s not yet a lot of good comparables to the Eagle Ford. But it’s early and right now it’s hard to compare apples to oranges.
“There have been a lot of good, long laterals…” Fracturing into the rock “is showing good results early on. There’s been a lot of good success, but it’s too early to compare the plays…It will take maybe a year to know. The missing piece is the decline rate. We will know that in six months to about a year.”
Following his analysis of 775 wells in the play, Barrell has concluded that the core of the trend appears to be in the east. The Tuscaloosa, he said, has a total organic content of 1-4%, which would be similar to other big resource plays. The trend has lower resistivity than the Eagle Ford, mostly because the Eagle Ford has more calcite content.
The Tuscaloosa also has a higher clay content, which has been a concern for producers. “One of the big black marks this play had four years ago go to that clay content,” Barrell said. “I think the clay content [issue] is overblown.” At the lower 150-foot zone, there’s a much lower clay content than in the upper portion, he said. In the lower zone, the Tuscaloosa also has more quartz content, which may offer more storage capacity and more conduciveness to fracking.
Encana Corp., the biggest leaseholder in the trend with an estimated 350,000-plus net acres, in June indicated that it was on the prowl for a joint venture partner to help defray drilling costs (see NGI, June 25). Indigo II Minerals LLC is the next-highest acreage holder with 250,000 or so acres, followed by Devon Energy Corp. with 190,000 acres. EOG Resources Inc. hasn’t publicly disclosed its Tuscaloosa position, but Barrell said industry estimates put the Houston-based producer’s acreage holdings at 180,000-plus. Goodrich Petroleum is next with an estimated 132,000-plus net acres.
As interest has grown, so has the price to lease.
“We’ve been leasing since early 2011,” (see NGI, Feb. 28, 2011) said Barrell of his company, “and we’ve been watching what was going on. Encana started in early 2010.” Acreage “was consistently in the $200-250 range until the end of last year when we started to see [drilling] results. Then when Encana’s Weyerhaeuser well results were announced in January, that’s when the escalation started this year.”
The Weyerhaeuser 73H-1 oil well in St. Helena Parish was completed by Encana in November. In January “on the ground observers” said the well was consistently flowing 650-800 b/d of oil, Barrell said. Encana listed the official initial production (IP) rate over 30 days at 280 b/d of oil and 98 Mcf/d. After those well results came in, Tuscaloosa land went higher. Halcon Resources in April agreed to pay around $450/acre for some land in the Louisiana fairway, he noted.
“You can still buy land for $175/acre; there’s still a broad range of prices…But it’s moderately higher from a year ago…We feel the play has risk, but it’s still very low cost.”
Encana may be the most aggressive of the operators in its approach to well design, but that approach has resulted in the highest IP rates, Barrell said. Devon, meanwhile, has taken a more “scientific” drilling approach. EOG apparently has permitted a vertical well in Avoyelles Parish in the western part of the play around a structural “nose” that may have more natural fracturing.
Drilling costs remain the No. 1 concern for all of the operators in the emerging play. However, unlike many fields, operators aren’t expected to see their first savings from well completions, but rather from drilling efficiencies. The veterans that have been drilling in U.S. unconventional fields should have the upper hand because they bring tried-and-proved methods from other onshore plays.
“The last box to check is…to look at the profile over the 12 months,” Barrell said. “We don’t know that yet. It’s the last piece of the puzzle. Encana has proven early on and very quickly what the frack is going to get. But each shale is different. Within each basin there are different parameters. When you look at the Eagle Ford for example, you can get different results, different declines, have min-basins…It’s hard to pinpoint and aggregate. At the end of the day we’ll see what the trend tells us over time.”
Some benchmarks indicate a few things.
“What we know for sure today is that Encana has been the leader so far…it’s had the longest lateral, the best 30-day IP, the most frack stages…No doubt Encana is getting better results per stage, but it’s using more proppant… it’s using more fracks, and it’s got more pressure [business-wise] to be oily, so it’s more aggressive.”
However, the first-year production decline rate will be the true indicator of things to come. “That’s a benchmark parameter that we’ve yet to see.” The combined IP reports to date “haven’t been consistent…So far just a handful of wells have been completed and drilled…About 36 locations to date in the Tuscaloosa Marine Shale,” which include 11 permitted wells, four actively being drilled, four being fracked, and 10 producers.
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