Emerging Plays

Into the night sky, a modest flare from the Bentley 34-1H bore the news in early December of Louisiana’s horizontal Eagle Ford oil and gas-liquids discovery well along T.L. James Timber Road, just west of Alexandria. “My head is still spinning,” admits Bill Pritchard, chairman of Houston-based Indigo Minerals LLC, which owns most of the acreage across the state’s newest shale fairway that may be as much as 100 miles wide.

While the well met with mechanical-pump interruption in its first several days online, it made 543 barrels of oil and gas liquids—fourfifths oil—in one functioning 24-hour period. At press time, it was making 200 barrels of oil and 300,000 cubic feet of wet, 1,520-million-Btu gas, consisting of about 100 barrels of gas liquids, or more than 300 barrels of total liquids a day combined.

“It’s about where we thought: 500 barrels in its first 24 hours and averaging 230 barrels over its first 30 days,” Pritchard says. “If it hangs in, we’re there—at about a 200,000-barrel-equivalent EUR (estimated ultimate recovery) type curve. I’d like to drill 10 more.”

The new Louisiana Eagle Ford is the latest headline-maker on the U.S. oil and gas scene and other operators are working on yet more—to name a few, Lower Smackover or Brown Dense, Tuscaloosa Marine Shale, Woodbine or Eaglebine, Hogshooter and Three Forks II—from what had been declining, vertically tapped provinces. Here are details on each.

Louisiana Eagle Ford

Indigo Minerals LLC came into the Louisiana Eagle Ford play an old-fashioned way: It married into it. Mrs. Pritchard is a childhood friend of Mrs. Martin, wife of Roy Martin whose Roy O. Martin Lumber Co. is the largest private mineral owner in Louisiana. They served in each other’s weddings.

As the South Texas Eagle Ford play took off after Petrohawk Energy Corp.’s horizontal discovery well in late 2008, the potential for the Louisiana fairway of the Eagle Ford was sparked and the Martins were approached by several shale operators to buy or lease the mineral rights. The Martins had a better idea: Contribute the rights to a partnership with an E&P, retaining the interests and more exposure to upside.

Pritchard and his Yorktown Partners LLC-backed Indigo immediately came to mind. “Roy called me and said he wanted to do something with his minerals. I got on a plane to Alexandria and we worked something out. We’ve known each other for almost 30 years,” Pritchard says. In the arrangement, Martin owns half of Indigo II, which was formed this past January from Indigo’s oilier assets; York-town and Indigo management own the other half.

The Bentley 34-1H in Rapides Parish, Louisiana, is just west of where the oil-rich but problematic muddy clay of the Tuscaloosa Marine shale in eastern Louisiana and western Mississippi ebbs and the higher-calcite- and lower-clay-content Eagle Ford appears as more like that found in South Texas.

“The mineralogy differs somewhat from the South Texas Eagle Ford, but the depositional environment is similar in this age-equivalent rock,” Pritchard says. “Our prospect area sits on the Cretaceous carbonate platform, distal from fluvial input—the same as in South Texas.”

Pritchard and the Indigo team are familiar with pushing play boundaries, having built and sold a Granite Wash-focused E&P, Peak Energy Resources Inc., to Forest Oil Corp. and a Barnett-focused E&P, Peak Energy II, to XTO Energy Inc., now part of ExxonMobil Corp.

Indigo Minerals was launched in 2006, initially about 90% gas-focused in the Cotton Valley, Hosston and Austin Chalk plays of East Texas and North Louisiana, and sold some of its gas assets while the Henry Hub price was some $13 per million Btu.

Dropping its oilier assets, such as mineral rights in the Bakken play, into Indigo II a year ago, it raised another $150 million in private-equity funding from Yorktown, which has been Pritchard’s capital partner since his Peak Energy days. Included in Indigo II are 315,000 acres of mineral rights it acquired from Martin in central Louisiana and 300,000 acres of mineral rights it bought from Callon Petroleum Corp. there and in the Bakken in late 2008.

It has also leased another 150,000 acres over Louisiana Eagle Ford and Austin Chalk, bring- ing its company-wide holding to roughly 765,000 gross acres, of which 460,000 are in the center of the state.

“Our goal, when we formed the company, was to put as many of the Martin minerals in play as we could,” Pritchard says.

In late 2008, Indigo noticed a significant show in the Hodges Martin Timber #1 vertical well in Louisiana through the brittle Eagle Ford shale interval. Further review revealed that many of the wells drilled deeper in the area in the 1970s and 1980s had also encountered promising shows.

“You had oil on the pits and all the things you look for as you’re drilling through a shale interval that indicate they’re hydrocarbon bearing,” Pritchard says.

Its Bentley 32-1 vertical, drilled in early 2011 for about $5 million and taking a core of some 360 feet through Eagle Ford, showed the Louisiana rock to be the stratigraphic equivalent of the South Texas shale. “There is a high-resistivity interval at the base of the Eagle Ford. We started about 100 feet above that interval and then drilled 60 feet below.”

Porosity is some 7% to 8%. “Our matrix permeability, at 200 nanodarcies, is somewhat lower than in South Texas, but we think we’ll overcome that with a significant microfracture network and moderate overpressure. Certainly, the reservoir has acted that way so far.”

The horizontal discovery well cost some $10.6 million, including a vertical pilot. Its 15 frac stages and 4,100-foot lateral are modeled upon wells in the South Texas play. “We think we can drill those wells for around $7 million each in a development program, where we’re not drilling a vertical pilot as well.”

Central Louisiana oil production is priced like that of Louisiana Light Sweet or LLS crude, which is marked to the higher Brent or waterborne oil price than to the lower WTI price. Also, the horizontal was drilled to its full lateral length without having to set a second string of intermediate casing at the curve where the vertical wellbore turns lateral. Future wells may have a spud-to-total-depth rate of 20 days.

Such spending by a PE-backed E&P is unusual, as PE tends to fund more exploitation-based stories, but Indigo has existing cash-flow-producing assets and Pritchard has a track record of successfully pushing play boundaries, such as in the Granite Wash and Barnett. Of course, pushing a play into neighboring counties incurs one kind of risk analysis; in Louisiana, it is pushing a play into another state, some 400 miles from the South Texas epicenter.

“It’s not rank exploration, but, right, it isn’t typical for what I’ve done or for what York-town has done. But we do have a lot of other assets in Indigo II. We have roughly 700,000 mineral acres, including our Bakken position and the Master’s Creek Field, which is productive from the Austin chalk. It’s not the only thing we have going in Indigo II or, yes, we would be taking on more risk than Yorktown probably ever has.”

Its maverick position is quite fortunate. “Part of why we’re out in an island is that we essentially control all of the acreage in that part of the play. It’s difficult for anyone else to gain a kind of foothold.”

Three Forks 2, 3, 4

As if the Middle Bakken and Upper Three Forks plays aren’t big enough, the plays’ founder, Continental Resources Inc., is proving yet another layer of oil reservoir—the second bench of the four-bench Three Forks—in the vast Bakken petroleum system.

“When we started drilling the Middle Bakken in the early 2000s, we didn’t think the Three Forks was much of a reservoir,” says Jack Stark, Continental senior vice president, exploration. Core samples that incorporated the uppermost Three Forks showed oil, however, and, in 2008, the Enid, Oklahoma-based E&P drilled its first horizontal Three Forks tests, Bice 1-29H and Mathistad 1-35H, which proved the uppermost Three Forks to be a commercial zone.

Later, a well was dropped into Middle Bakken just 50 feet above the Mathistad well, which had already produced approximately 100,000 barrels of oil, and proved the reservoirs to be independent. That presented another layer of oil reserves and begged another question: “In early 2011, we set out to answer ‘How far down into the Three Forks could this oil saturation go?’”

It launched another science project, taking six cores some 115 miles north to south to the bottom of Three Forks. “What we found was remarkable: Not only did we have oil in the upper or first bench of the Three Forks, we also had oil saturation in the second, third and fourth benches. We started out exploring and developing the Middle Bakken and then followed with the Upper Three Forks.

“Now we have three more benches or layers of Three Forks that could add reserves to the play.”

Its Three Forks II horizontal discovery well, Charlotte 2-22H in McKenzie County, North Dakota, tested 1,140 barrels of oil equivalent (BOE) per day, mostly oil, from a 9,700-foot lateral after 30 frac stages on a 26/64-inch choke. “It is a very commercial well and is acting just like a standard first-bench producer,” Stark says.

While additional wells will need to be drilled, science and history suggest Three Forks II will be proven to produce independent of the first bench, Stark says. “You think it would because there is shale between the two dolomite benches. But there are slightly different characteristics to them, so are there effective seals between the first and second benches?

“We don’t know at this point. It will take some further testing, but Charlotte is performing very nicely.”

The 15,000-square-mile Bakken petroleum system—incorporating three pervasive layers of Bakken, the occasional Sanish, which sits atop Three Forks in some areas, and the four layers of Three Forks—is sealed by the Lodgepole limestone at the top and uber-tight anhydrides of Birdbear (aka Nisku) at the bottom, resulting in an overpressured system between the two normal-pressured seals.

Each dolomite of the Middle Bakken—with varying amounts of limestone, sandstone and shale mixed in as it moves across the Williston Basin from Montana into North Dakota—and each mostly dolomite Three Forks bench is fed by the organic-rich upper and lower Bakken shales.

What’s the Three Forks look like down there? The Charlotte core cut 220 feet of total Three Forks interval, finding 114 feet of oil-bearing dolomite sections. “Almost half of the core had oil saturation in it.” In that core, the first bench is about 50 feet thick with about 30 feet of dolomite; the second showed about 25 feet of dolomite; the third, about 30; the fourth, about 30.

Continental’s six cores, plus two other known cores of the entire Three Forks, suggest the first bench is ubiquitous throughout the basin. The second seems slightly thinner but is equally widespread. The third and fourth appear to be more localized, with the third being more widespread than the fourth.

“We’ve gone from essentially one layer of reservoir to five. It’s true exploration. The beauty of it is that, when you’re in large fields, they tend to continue to get better. The Three Forks is up to 270 feet thick. So we have a much larger petroleum system here than we envisioned initially.”

Should the second bench prove to be an independent reservoir, the potential exists for significant recoverable reserves to be added to the Bakken petroleum system from the second and possibly the third and fourth benches of Three Forks.

“Yes, it’s like déjà vu. We’re doing it again,” Stark says. “It just makes sense that we have incremental reserves to add from these additional benches.”

It’s too soon in Charlotte’s production history to develop an EUR for the well, but “we like how we see it performing.” And, the discovery doesn’t generate a whole new leasing frenzy in the play: In North Dakota, acreage is held by production from anywhere between Lodgepole and Birdbear in the Bakken system. In addition, Three Forks II wells should cost as much as Three Forks I wells, he adds, as the second bench is only about 50 feet deeper and the rock is mostly the same.

Continental had 198 million BOE of proved reserves booked on its leasehold in the Bakken and Upper Three Forks as of year-end 2010. As the Charlotte 2-22H continues to produce and additional Three Forks II wells are dropped in, the producer expects to book additional reserves. “That’s a real game-changer we haven’t accounted for yet.”

The U.S. Geological Survey is already updating its 2008 estimate of 4.8 billion BOE of recoverable reserves in the Bakken system that was based at the time on development through June 2007. The estimate essentially represented Middle Bakken reserves only, and was based on the relatively few wells that existed at the time and best practices of the day.

“Our own estimate is that the Bakken petroleum system contains 24 billion BOE of recoverable reserves from the Middle Bakken and Upper Three Forks alone. Now we have the second, third and fourth benches to consider. There are three other reservoirs out there.”

Hogshooter

No calculator needed here: The economics of this play may be clear. From far northern Texas, Forest Oil Corp. has stunned equity analysts with results from its first horizontal Hogshooter well: It came online with a first-24-hour rate of 2,803 barrels of oil, 436 barrels of gas liquids and 4 million cubic feet of gas or a combined 3,900 BOE.

In its first 30 days online, the roughly $7.25-million well into the Pennsylvanian-age sandstone that is also known as Missouri Wash made more than 83,000 BOE and, in early November, it was putting out 2,800 BOE per day.

An EUR would be premature, but Craig Clark, Forest president and chief executive officer, says, “It blew away the type curve by a country mile.”

In the Texas Panhandle where Forest has 172,000 gross and 103,000 net acres, with a great deal of it held by production from deeper Granite Wash and other formations, it is fast-tracking the Hogshooter program, planning 30 more wells in 2012 and dedicating a rig amongst its fleet to the zone.

Hogshooter sits above the more commonly known Des Moines Granite Wash benches near the liquids-prolific Cleveland/Marmaton and below the liquids-prone Douglas, Tonkawa and Cottage Grove in the western Anadarko Basin, which hosts more than two dozen stacked pays down to deep Springer dry gas and oily Mississippian-age limestone.

Other operators are also proving Hogshooter, including SM Energy Co. whose Tony Best, president and CEO, is putting three rigs to work on the zone. “We really like it,” Best says. “The returns there are going to be as solid as any of our other programs.”

International E&P Apache Corp., which sprung from an Oklahoma oil and gas platform in the 1970s, reports its newest Hogshooter well, Thetford 5-23H in Beckham County, Oklahoma, at about 11,000 feet, flowed an initial 889 barrels of oil and 4.6 million cubic feet of gas. This joins Apache’s earliest successful laterals in Hogshooter from which, by midyear, it made an average first-30-day rate of 1,100 barrels of oil and 2.7 million cubic feet a day of wet gas at a cost of some $7.5 million each. It had two rigs at work on the payzone in November.

Also making a play out of Hogshooter is Chesapeake Energy Corp., which also sprung from Oklahoma oil and gas fields and controls more than 2 million acres across the Greater Anadarko Basin.

“It’s not all that different from the Granite Wash,” Todd Stephenson, Chesapeake vice president, geoscience, northern division, says of Hogshooter. “It’s just younger in age.”

With thousands of vertical wells drilled through Hogshooter during the past century for deeper zones, it’s easily mappable, he adds. Indications are that it is some 60 miles wide from Wheeler County, Texas, into Washita County, Oklahoma.

“The interval itself is not as wide as the overall Granite Wash play as far as we can tell, but it looks prospective for us as an uphole zone. We have the benefit of just having so much HBP (held by production) acreage that we can go after this in a prudent way.”

The zone’s porosity varies widely amongst these earliest wells but may average about 7%; permeability is 0.001 to 0.005 millidarcy, similar to that found in the Granite Wash. To date, Chesapeake has made seven operated Hogshooter producers, beginning in early 2011 with the JML Trust 7-11-20 1H coming online at more than 500 barrels of liquids per million cubic feet of gas.

The seven-well average is some 275 barrels per million. EUR ranges among the seven from 345 million cubic feet equivalent to more than 8 billion equivalent. The average is about 2.6 billion. “But it’s still early. We’ll see what it eventually looks like.”

Stephenson joined Chesapeake in September 2010 after 20 years with Amoco Corp. and 10 years with BP Plc, lastly as U.S. onshore chief geologist where he was screening and evaluating basins for conventional and unconventional plays. Upon taking an early retirement from BP in early 2010, he was recruited to Chesapeake, where he says the speed at which play ideas are pursued is “like night and day” in comparison with that of an international super-major.

Chesapeake already produces from horizontal Granite Wash, Cleveland/Marmaton and Tonkawa in the western Anadarko Basin. “Our operations team, watching wells going deeper, was seeing interesting shows on the logs. We started out with drilling a bunch of pilot holes in Hogshooter and taking lots of extra logs.”

The earliest Hogshooter wells cost about $8.6 million, but that is to fall to between $7-and $7.5 million in 2012, he expects. Lateral length is between 4,000 and 4,400 feet; frac jobs number eight per well, similar to the number performed on Granite Wash wells. Proppant is simple sand.

“It’s showing to be mappable and easily responds to the type of frac design that has been successful in some of the deeper zones out there. It’s definitely shown to be liquids-prone. That’s a big plus—the liquids.”

Woodbine/Eaglebine

In Brazos County, Texas, just north of Houston, privately held, Fort Worth-based Crimson Energy Partners III LLC is making liquids-rich producers using horizontal wellbores and multistage fracture stimulation from the long-known, vertically produced, oily Woodbine sandstone.

Its most recent Woodbine completion, Jackie Robinson 2-H, came on at 371 barrels of oil, 20 barrels of gas liquids and 55,000 cubic feet of dry gas or a combined 400 BOE in its first 24 hours on a restricted 16/64-inch choke. It made an average of 270 BOE per day in its first 30 days on a 22/64 choke. The EUR is some 350,000 BOE.

Wells in this new play, which is currently focused in Grimes, Madison, Leon and Brazos counties, cost about $4.5 million apiece for 6,000-foot laterals and 21 frac stages spaced about 225 feet apart. “Part of the lower cost is because it’s shallow at about 7,500 feet,” says Frank Starr, Crimson Energy president.

Also, because of the conventional nature of the rock, a low-horsepower rig of about 1,000 HP may be adequate. And, frac jobs in the mostly sandstone formation are at relatively low pressures compared with completing a well in a shale, for example.

The Woodbine formation also makes very little water compared with the low-service-intensity Mississippi Lime play in northern Oklahoma, for example. Proppant is simple 20/40 sand with a bit of resin-coated sand pumped in near the end of the frac job. Spud-to-release on Crimson Energy’s most recent Woodbine horizontal was 21 days.

“It’s a sandstone. Porosity is 12% to 15%. The perm is 0.15 millidarcy. It’s tight for a sandstone, but it’s better than a shale,” says Tripp Rivers, vice president, exploration.

Just south of the play is Kurten Field, where vertical Woodbine wells in the past century made as much as 200,000 BOE and averaged 37,000 BOE apiece. “We’re extending Kurten Field to the north and applying horizontal and multistage frac technology to it,” Rivers says.

Backed by Scotia Waterous’ private-equity firm, SW Capital Partners LP, Crimson III was launched in 2009 specifically to focus on East Texas oil-rich targets. The team divested its South Texas-focused Crimson I and its 160 billion cubic feet equivalent of proved reserves in 2004 and, in 2008, sold its Crimson II assets that were focused in the same area.

“In Crimson III, we have a few wells producing in South Texas from the Olmos formation, but the majority of our focus right now is Brazos County and the acreage position we have there,” says Aaron Thesman, vice president, land and legal.

Crimson III began putting together its approximately 28,000 net and mostly contiguous leasehold over Woodbine primarily in Brazos County in 2005 and was interested at the time in the oily, fractured-carbonate Buda and Georgetown where combination EURs average 180,000 BOE per well.

Its initial two Buda horizontals have 7,000-foot laterals. “They really don’t need stimulation. We can turn them around in 25 to 30 days and into sales. They cost about $2- to $2.5 million each. In reference to the Mississippi limestone in terms of the rock properties, they are pretty similar,” says Starr.

While working the Buda and Georgetown, however, the Crimson III team identified Woodbine as another target. It began that program with a short 3,500-foot lateral; its longest now is 6,000 feet and others in the industry are going out to 8,000 feet and beyond. The E&P has four Woodbine horizontals to date with its partner, Tyler-based East Texas Oil & Gas LLC, and had a rig at work on another at press time.

“We are always looking to bring the cost down more. Between $4- and $4.5 million will probably be the range, assuming service costs stay in line,” says Mark Holcomb, vice president, operations. “From an operations standpoint, there aren’t a whole lot of surprises. We won’t say it’s ‘cookie cutter,’ but it’s a very manageable area.”

While the Brazos County attention is northeast of the South Texas Eagle Ford shale hotspot, Eagle Ford does sit below Woodbine in this area north of Houston that is west of the Sabine Uplift and north of the Harris Delta, thus an increasingly used new oilfield term: “Eaglebine.”

In that shale, the Crimson Energy team has identified two benches through advanced logging and whole cores that appear prospective. Farther below Buda and Georgetown, its acreage position also has dry-gas prospects in the Knowles and Deep Bossier that may be drillbit worthy on a better-gas-price day.

“There is a significant amount of serendipity in the area, with numerous oil reservoirs and gas reservoirs,” Starr says. “We have more than 1.5 billion barrels in place under our acreage position and more than 380 locations. That’s just the oil and locations in the Woodbine, Buda and Eagle Ford. In the Woodbine, you have almost 4 million barrels in place per 640-acre section; in the Eagle Ford, about 30 million per 640.”

Chesapeake chairman and CEO Aubrey Mc-Clendon has told equity analysts he’d like more Woodbine leasehold, but a large acreage position is hard to grow in the area organically. Starr says, “We’re obviously always open to entertaining an offer. Based on our current strategic plan and forecasted drilling activity, we’ll possibly look at the market in the first half of 2012.”

Tuscaloosa Marine Shale

East of the Eagle Ford trend of Texas and western Louisiana, the shale meets with ancient history: The muddy delta of the rogue Mississippi River that has jumped its banks for a new, quicker course to the Gulf of Mexico every 1,000 years or so, until reined in by a sophisticated lock-and-levee system this past century.

To date, making a commercial well in the Tuscaloosa Marine shale has been like trying to drill and complete a hole in quicksand, according to various industry sources. The formation likes to suck up money too: The newest horizontal attempts cost some $12 million apiece.

But the prize is tantalizing: The TMS is estimated to contain 7 billion barrels of potential, overpressured oil across 2.7 million acres in southwestern Mississippi and southeastern Louisiana—mostly in the “Florida Parishes” there or the toe of the state that was once part of Spain’s Florida.

Currently, Devon Energy Corp. is putting its super-independent E&P might behind the bit in this sloughing shale, accumulating more than 250,000 net acres over the formation this past year. Another large indie, Canada’s Encana Corp., is also making attempts with 270,000 net acres leased, some 100,000 of it from Denbury Resources Inc., which inherited it from the last E&P, Encore Acquisition Co., to wrestle the TMS horizontally.

Also, international independent EOG Resources Inc. has an unconfirmed 120,000 acres over the Cretaceous-age, dark-gray source rock that sits at between 10,000 and 15,000 feet.

“This is Wave No. 3 of exploration in the TMS. They have to solve the fracture-stimulation riddle or it will become another black eye for the play,” says Kirk Barrell, president of The Woodlands, Texas-based Amelia Resources LLC. He has studied TMS history back to the 1960s.

Numerous E&Ps showed TMS oil while on their way to the deeper Tuscaloosa sandstone beginning in the 1960s, Barrell explains. With that and other data, the late Mississippi wildcatter Alfred Moore went to work on the TMS in 1969 and, with Sun Oil Co., made one vertical attempt. After Sun quit, Moore went after it again, partnering with a fellow Mississippian, the late John Callon, founder of Natchez-based Callon Petroleum Co. This one made oil but not a commercial amount.

It did show permeability to range from 0.01 to 0.06 millidarcy, however; porosity, 2% to 8%, Barrell says. A core showed 40 natural fractures. During the next 20 years, other E&Ps made small producers from TMS fraught with flow problems; others made blowouts. A couple of horizontal attempts were tried in the late 1990s, after LSU Basin Research Institute director and state geologist Dr. Chacko John published the estimate of 7 billion barrels in potential reserves.

But, again, the rates were non-commercial.

While oil was approaching $150 a barrel in 2008, Fort Worth-based Encore took on the challenge, leasing 200,000 net acres and drilling four horizontals among which two cost more than $15 million each. Three made oil—more than 60,000 barrels combined to date. The fourth—Board of Education 1H in Amite County, Mississippi—wasn’t completed, as oil prices collapsed.

From Denbury, which bought Encore in 2010, Encana took over the TMS operation and completed the fourth well in late 2011. It had two more horizontals under way at press time at 11,000 feet with 7,500-foot laterals and 30 frac stages each at a cost of some $10 million apiece.

Pritchard, whose Indigo Minerals operates in Louisiana’s western Eagle Ford play, says the formation was a challenge for operators who were targeting the deeper Tuscaloosa sandstone in the past.

“You would have about 72 hours to get the well logged and cased because the TMS would slough in on you and essentially start flaking off the sides of the walls. You could go back in and your hole would have filled up with the TMS because it’s much higher clay content and more ductile in that area,” Pritchard says. “Hopefully, companies the size of Encana and Devon will solve that puzzle with the technology that exists today. There is a lot of hydrocarbon in that system.”

Within industry, early terminology is lumping the TMS into reference to the Louisiana Eagle Ford. Pritchard explains, “It’s age equivalent, but it’s just a totally different depositional environment.”

The resistive target in the Eagle Ford shale of western Louisiana and South Texas sits above a tight, Cretaceous carbonate, the Edwards limestone, while the TMS sits above potentially water-bearing Lower Tuscaloosa sandstone. Also, the Eagle Ford of South Texas has more calcite—thus easier to drill and frac—and less clay content—thus easier to keep propped.

“It’s early in our western Louisiana Eagle Ford program, but we also see a dramatic difference in the hydrocarbons present,” Pritchard says. “We are producing 45° API oil at 10,700 feet whereas you need to be at least 2,000 feet deeper for similar light oil over in the TMS.”

Although Indigo has TMS mineral rights that were contributed by Martin Lumber in 2006, it is content to let Devon, Encana, EOG and others crack the frac code on the TMS to the east while it works its 255,000-net-acre position in the Louisiana Eagle Ford window.

Clint Moore, a vice president with Ion Geophysical Corp. and son of the early TMS champion, donated his father’s files to the LSU Basin Research Institute. Barrell, who was Amoco’s Tuscaloosa sand geologist until 1995, has evaluated more than 700 TMS penetrations and, today, blogs almost daily about TMS activity. “Confirmed TMS drilling locations now total 15 in this newest ‘TMS Era,’ with six locations by Devon,” he says.

“Devon’s initial plans are making sense. Their ‘cross’ well pattern tests the TMS in strike and dip directions. After completing these wells, they will have rock properties, pressures and the hydrocarbon mix across their acreage position.”

Equity analysts concede that the oil is there. “But, the challenges are in the drilling and completion phase,” one says. He isn’t getting excited about the play yet.

Of course, Texas wildcatter George Mitchell worked more than 20 years on making economic wells from the Barnett shale. Eventually, he succeeded.