Drill bits en route to deep targets often cut through zones with minimal hydrocarbon shows.
Sometimes that might be a nuisance. But sometimes it’s best not to write off these shallower, unexpected teasers as trash zones.
They may have great promise – if not now then in the future, using advanced technology that has yet to be developed.
This appears to be the story of the Cretaceous-age Tuscaloosa Marine Shale (TMS), which occurs across central Louisiana and into southwestern Mississippi. It’s age equivalent to the highly productive Eagle Ford in Texas.
The TMS occurs between the upper and lower units of the Tuscaloosa formation, which has produced enormous volumes of hydrocarbons over the years from giant fields in the famed Tuscaloosa Trend. Production is from the lower Tuscaloosa Massive Sand facies.
The deep high-pressure TMS is generally thought to have sourced the highly productive sands in the Tuscaloosa Trend.
Back in time, the TMS was viewed as a kind of nuisance bed, throwing a tad of oil when penetrated by the downward-moving drillbit.
Attempts to produce from the shale in the 1970s were non-commercial. Even so, a well drilled in 1977 in northern Tangipahoa Parish is kicking out a few bopd even now.
A publication in 1997 based on a study conducted by Louisiana State University’s Basin Research Institute (now the Basin Research Energy Section of the Louisiana Geological Survey) revealed the TMS harbors an estimated seven billion barrels of oil awaiting recovery.
Such a number is guaranteed to grab the attention of the E&P crowd.
This potential, combined with ongoing advances in horizontal drilling technology and hydraulic fracturing, meant a play was inevitable.
Problem is, it’s taking a long time to prove commercial.
Getting Started
The TMS play essentially kicked off in 2008 when the former Encore Acquisition drilled four horizontal wells, which met with various problems.
Thus far, 35 permits have been acquired in the play, and 23 wells have been drilled. Twenty completions are on record, with 13 wells currently producing.
The focus is on the updip oil window rather than the much deeper gas window, and true vertical depth for the wells average about 12,500 feet.
Three wells were drilling at the end of May, according to AAPG member Kirk Barrell, president of prospect generator Amelia Resources, based in The Woodlands, Texas.
“Recent results have been very encouraging, but we just wish they happened faster,” said Barrell, who has 23 years’ experience in the Tuscaloosa Trend and is an avid TMS blogger. “I don’t think there’s any question it will work – the geology hasn’t changed.
“What we see now is a fracture design that’s been proven to work,” he noted. “The final piece of the puzzle is to get costs down a little more, ideally in the $11 million range.
“It’s an expensive play compared to some others,” Barrell added, “but the rates and EURs make the economics still look good, even at current costs.”
Accentuating the Positive
Barrell emphasized that early negative perceptions about the play, such as too much clay and being too close to sand, have been proven wrong.
Each step forward, whether big or small, gets this all-out effort closer to commerciality.
For instance, EOG drilled three wells over a time period ranging between 28 and 34 days. Taking into account the day rate and the fracture design, well costs reportedly tallied about $11.5 million or less, making it a benchmark in the play.
Early on, some of the players referred to the TMS in the western area of this new play as the Louisiana Eagle Ford.
Hopes were high.
Alas, that kind of went the way of the Dodo bird when Halcon condemned the western segment via drilling. The core area now is considered to begin in Avoyelles Parish and continue eastward.
Today, chances are you can only be a bystander, as Barrell noted the currently prospective 2.8 million acres are pretty much all leased up. Once the boundaries of the play are defined, he estimates as much as 7.4 million acres eventually could be prospective.
At press time, four operators had a combined total of 13 wells producing:
- Devon.
- Encana.
- EOG.
- Goodrich Petroleum.
The most recent of the 20 completions in the TMS was the Goodrich Petroleum Crosby 12-H-1 well in Wilkinson County, Mississippi.
It’s an attention-getter.
“They used 475,000 pounds of proppants per stage and about 70 percent slickwater and laid in the bottom 60 feet of the shale,” he noted. “Those three criteria appear to be the formula for success.
“The initial test on that well was 1,300 boe per day,” he said. “I think it will be like that Jake well in the Niobrara.”
This would be huge, given that EOG’s #2-01 H Jake well in Colorado’s DJ Basin startled the industry when it tapped into a copious amount of oil in the Cretaceous-age Niobrara formation. It essentially ignited the now-famous Niobrara play.
Barrell noted that the Crosby well had already produced approximately 85,000 boe in about 100 days.
“There’s no question it’s the star thus far,” he said.
Pay It Forward
Barrell emphasized that accurate prediction of estimated ultimate recoveries will occur after approximately 10 to 20 wells have produced for more than a year and decline rates, hydrocarbon mix and pressures are confirmed. This will enable generation of meaningful economic scenarios and type curves.
The hundreds of wells drilled to the deeper Tuscaloosa sands provide prodigious volumes of data for the TMS operators.
Some much-welcome 3-D data soon may be added to this trove.
Once commerciality of the play is confirmed – which Barrell predicts is close – watch for the 3-D action to kick off. Several vendors are said to have expressed interest in acquiring a large 3-D data set.
Besides the TMS, there’s lagniappe to be had in the form of other production potential. This also will benefit from 3-D analysis.
“There’s still a lot of shallow potential in the area,” Barrell noted. “There’s the Austin Chalk, the Wilcox and a significant amount of deep Lower Cretaceous and Jurassic potential that would greatly benefit from 3-D.”