A year ago, the nascent Tuscaloosa Marine shale play in Mississippi and Louisiana hosted a dozen completed, producing wells and a still-uncertain future as the holes were costing more than $15 million and initial rates of 1,000-plus barrels remained elusive.

Now, several upsized wells have come online in the region, which offers favorable tax rates, take-away infrastructure at the ready and Louisiana Light Sweet pricing discounted by just $2 for the short haul to pipe.

And small-cap Goodrich Petroleum Corp. has firmly forged its stock as the one to own to have a nearly pure-play piece of what may be a 60,000-square-mile oil field. In early July, upon rumblings of potentially good reserve-life news from Goodrich's six-month-old Crosby 12H-1, the $12 stock began to soar. By early October, after reporting Crosby had made more than 100,000 barrels of oil equivalent (BOE), 94% oil, in its first five months, shares topped $28.

Its Smith 5-29H-1 then came online with a 24-hour peak rate of 1,045 BOE. Meanwhile, it picked up two-thirds interest in an additional 277,000 gross acres, producing about 750 BOE a day, for $23.7 million from Devon Energy Corp. The add has brought its position to more than 300,000 net acres.

Buoyed by the new stock price, Goodrich raised $166 million net in an oversubscribed, 6.9-million-share sale. It exchanged $167 million of 5% convertible senior notes due 2029 for new notes due 2032, pushing the initial call to October 2016. Its bank facility was increased to $270 million with none drawn at year-end. Cash on hand became $59 million and an additional $52 million was in a restricted account.

By early November and online for 8.5 months, the Crosby well had made 138,000 BOE. It and five of Goodrich's other wells were looking like they would ultimately give up more than 600,000 barrels each.

The recipe

Goodrich's TMS entry was in 2011 with nearly a decade of experience already in horizontal, tight-rock plays, beginning with the Cotton Valley and then the Haynesville and Eagle Ford. For it and its predecessors, however, the Tuscaloosa journey had been a climb that required earnest capital commitment and unprecedented geoscience to solve for expandable-clay content and a rubble zone that wants to grab the drillpipe and not let go.

Much has been learned to date. For example, the formation’s natural fractures trend west to east so laterals are being driven north and south to cross as much of the open rock as possible, says Rob Turnham, Goodrich president and chief operating officer. On the far eastern side of the ancient deposit, the fractures bend a bit so laterals will be drilled southwest and northeast. Also, what the Crosby and other TMS wells have demonstrated to date is that, while they are producing from the natural fractures initially, the frac-induced TMS itself is contributing to longer well life—unlike the 1980s and 1990s Austin Chalk play, which contributed oil
and gas from only the natural cracks.

“If it were producing from just the natural fractures, you would be concerned because, after you drain your fractures, your production rate would become much lower,” Turnham says. “It would be a much steeper decline curve rather than a hyperbolic-shaped decline. The matrix of the [TMS] itself is releasing hydrocarbons when you fracture-stimulate the wells, contributing to long-life production and reserves.” The same age as the Eagle Ford and also located along the old Gulf of Mexico shoreline, the TMS similarly hosts sandy, silty streaks, providing permeability and porosity, particularly in the bottom third of the 100- to 250-foot-thick formation where most of the oil is trapped.

Where Goodrich is drilling, the bottom of the TMS—which is at about 10,000 feet on the northern side of the deposit and 15,000 feet on the southern end—is at about 12,000 feet. Oil saturation is between 15% and 25%. Total organic carbon (TOC) is 1.5% to 3% compared with between 1% and 6% in the Eagle Ford. The reservoir is similarly over-pressured at 0.65 to 0.7 psi per foot. The rock is up to 25% quartz, up to 25% calcite and up to 50% clay.

Of the clay, about a sixth is swelling clay.

“When you look at the core data, the upper portion is higher in clay than the lower third. The lower 20% of that is even lower in clay than the rest of the section. As you get lower in the section, the quality of the rock gets better,” Turnham says. “There is no question that landing in the lower third of the TMS is clearly where you need to be.”

Furthermore, it appears that landing the lateral below the rubble zone—a roughly 10-foot layer of highly fractured rock above the bottom 25 feet of TMS—makes for a good well, but it’s tricky. “It wants to crumble on you. In the absence of high pressure, that would be fine. But, if you get caught in that rubble zone when drilling through it in high pressure, it wants to grab the pipe. You’re at risk of getting stuck.

“The better wells drilled so far—the Crosby and the Andersons [17H-1, 17H-2 and 18H- 1]—have landed below that rubble zone, but we have several wells now that were landed above it that seem to be pretty close to being as good as the ones below it.

“The difference is that the ones landed above the rubble zone can be drilled faster and easier. You have more leeway in where you drift while drilling the lateral.”

The knock on new TMS attempts beginning in 2012 was that the rock contained too much clay; the hole would close. Turnham notes that it is important to measure the swelling-clay content.

“The Crosby well has more than 60% clay by weight, but the expandable clay is the only portion that actually swells.” The swelling-clay content is a sixth of the total clay.

“That’s important. When people note the clay, they should focus on just the clays that swell when fluids hit them. You’re looking at 8% to 10%, which is fairly low compared with other formations. If you looked at the clay content by weight in the Crosby core, without any other knowledge, you would say, ‘Well, the Crosby well has the most clay so it is probably the worst well.’

“But the reality is it is the best well. So it appears that clay is not an issue, or how we are completing the wells [by using a clay stabilizer] is minimizing the effect of the swellable clays.”

Bigger fracs
Goodrich is working now on applying its successful drilling and completion practices on more of its leasehold as well as on the ex-Devon acreage. In analyzing the data on six ex-Devon wells, Goodrich believes the position, which is primarily on the Louisiana side of the play, should be as productive as what it is making on the Mississippi side and along the border. Lining up these and its Crosby well on a grid, the clay, quartz, calcite and TOC in each are similar. Several of the Devon wells are actually in more quartz, which provides more permeability and porosity, and in more calcite, which is more easily cracked. “If you look at all of these wells, you see only subtle differences,” Turnham says. “Crosby is less brittle and more soft yet, again, it doesn’t matter because the production coming from the Crosby is so good. And the TOC is about the same.”

What is different is that the Crosby well had a longer lateral of some 6,700 feet, 24 frac stages spaced about 270 feet apart, five clusters and 35 holes per stage, with 227 tons of sand, pumped with 65% slickwater at a rate of 75 barrels per minute. Its first-30-day rate was 1,137 barrels a day. In contrast, for example, the lowest-30-dayrate Devon well, Beech Grove 68H-1, has a 3,000-foot lateral, and was fraced in 12 stages about 225 feet apart with three clusters and 54 holes per stage. The 89 tons of sand was pumped with 41% slickwater at 49 barrels per minute.

“It really gets into how long the laterals are and how the wells were completed,” he says, adding that “holes per stage” is a new development. “The more holes you have, the more you’re stimulating the near wellbore versus [mostly] reaching out away from the wellbore. The development over the past six months is that more perforations or holes per stage work better.”

Goodrich has also determined that a hybrid-fluid frac job is more effective. “In the past, you did a slickwater frac or a gel frac.” In the hybrid job, however, slickwater is pumped first to create fracture complexity. “Then, you introduce the gel [to carry] your sand. If you’re not pumping that slickwater, you’re not getting as many fractures. Sixty percent of our fluid is slickwater upfront so we’re getting a more complex fracture system.”

As for proppant volume, the best of the six Devon wells—Weyerhaeuser 14H-1—is the one in which the most sand was used. The well had an initial-30-day rate of 692 barrels a day.

“There is a very good correlation of proppant volume and production,” Turnham says. Examining the core data from the seven wells, “our thesis is that these wells were just understimulated.” Turnham was expecting results in late January from the first Goodrichstyle completion on the Devon acreage with its new-drill Weyerhaeuser 51-1H-1.

Meanwhile, it continues to use a clay stabilizer on all of its TMS wells. Early thinking in the Barnett play in the Fort Worth Basin was that a clay stabilizer was necessary but, before play founder Mitchell Energy & Development Corp. merged with Devon, it was determined that it wasn‘t.

Turnham says, “Perhaps it is not as material in the TMS or effective as we think.” But, considering the myriad, costly other factors in what appears to be best TMS practices, “it isn’t that much incremental cost to assure that you make the best wells possible. We’re working on optimal completion for optimal production and willing to spend the money to get there.”

The completion recipe proved effective with CMR-Foster Creek 20-7H-1, Goodrich’s newest well online as of year-end. In it, coiled tubing became stuck yet it came on with 527 barrels a day from just 2,100 feet of usable lateral on a quarter-inch choke.

As for mechanical issues, Goodrich was fishing out frac debris in late December that piled up at a plug when flowing back its Huff 18-7H-1. The company is working to solve for this problem with wells that are up to 15,000 feet deep and another 6,000 feet horizontally.

“At some distance, it is harder to control the coiled tubing. You just reach a limitation and you can’t get to the remaining [frac] plugs,” Turnham says. One option is drilling the plugs out with a snubbing unit; the other is the use of a new kind of plug that is being deployed in other fraced plays. In this, a plastic ball is used to seal each perforation during the staged stimulations. Rather than fishing it out later, the ball merely dissolves over time.

Economics and capex
As for returns, the state of Mississippi has adjusted its severance-tax rate to further encourage TMS drilling. The new rate is 1.3% until payout and then 6%. The Louisiana rate is 0% until payout and then 12.5%. Will Louisiana lower its rate? Turnham says the rate is actually better. “It is counter-intuitive but it results in 1% more on your internal rate of return [than Mississippi’s rate]. It’s because of the 1.3% coming off the top while your volumes are the highest.”

While further delineating its leasehold, which it can renew at an average of $144 an acre, and maximizing production, Goodrich is looking to pare well costs upon entering development mode, thus increasing the scale of operations and more service-pricing competition.

“And, then, you get better at drilling these too. If we can shave 10 days off these TMS wells, it’s $1 million [in savings]. And, once pad drilling kicks in—even though we’re a long way from drilling multiple wells in one unit—we can build a common pad within as many as four units. That’s five or six hours between wells versus five or six days to move to a new location.

“And we will be able to frac the wells simultaneously with zipper fracs, keeping the equipment running, which saves about 40% of your time. That is a significant savings. That’s why, over time, we think we can take [TMS wells] from $13 million to $10 million.”

Goodrich plans to spend $300 million in 2014—up from $75 million in 2013—on the TMS for up to 31 gross, 24 net, wells with three rigs at work in this quarter and five rigs by year-end. It added a second rig in the TMS in the fourth quarter.

The $300 million is of a $375-million companywide capex plan. Eagle Ford spending will decrease from $100 million in 2013 to $30 million as the company will have captured its acreage there by production.

It aims to have 75% to 80% of its TMS leasehold held by production by 2018. “I think it is just execution at this point,” Turnham says. “By the end of 2014, we will have a good bit of our acreage de-risked. The second challenge is how quickly we can eliminate drilling or completion issues and how quickly service costs drop. We’re expecting 30 to 60 wells will be drilled in 2014—not just by us. That is going to be huge in the development of the play.

“We’ve basically been limping along with a fairly low well count, but activity is about to pick up dramatically.”

The TMS co-leader, Encana Corp., holds 302,000 net acres with an average working interest of 75%. It plans to spend between $125-and $150 million in the play in 2014—about half as much as it had previously estimated.

Jeff Balmer, Encana vice president, emerging plays, says the cut reflects plans for a measured pace of appraisal work until the play is deemed commercial for the company. Its 2013 TMS exit rate was some 820 barrels a day, net. Its expectations in 2014 are for between nine and 12 net wells with one to three rigs at work. It estimates its acreage may be able to hold 1,300 gross wells, costing between $12- and $14 million each. Its current estimate of ultimate recovery of some 700,000 barrels per well would generate a rate of return of between 40% and 50%.

Encana passed on picking up the Devon acreage that Goodrich acquired. “We already have a large position,” Balmer says. “The Devon acreage was interesting, but we like where we are in the play and have a lot on our plate right now with it.”

The Encana-operated Anderson 17H-3 had a 24-hour peak rate of 970 BOE on choke. Its Anderson 17H-2 had a peak of 1,660. Encana and Goodrich collaborated on these and several wells, sharing the cost and the data.

“It’s been tremendously helpful here,” Balmer says. “There are only a handful of players here. The wells are expensive to drill and they’re complicated. The first wells were $20 million, give or take, and even a company the size of Encana doesn’t want to put $100 million into five wells and only have five datapoints.

“It makes sense for us, since a majority of the acreage is captured. It is a noncompetitive situation in that respect.”

Also looking at the TMS is EOG Resources Inc., which made its Horseshoe Hill 10- H1 some 30 miles west of where Encana and Goodrich have been drilling. Dupuy Land Co. 20H had initial-30-day production of 435 BOE a day from a 4,855-foot lateral and 19 frac stages. Two other EOG wells were waiting on completion in December.

A bonus for Goodrich in its acquisition of the Devon acreage is that it inherited a third-interest partner—the cash-loaded Chinese national oil company Sinopec Group. Turnham says, “It’s a very attractive partner. We have some of their engineers in our office. We’re sharing data with them and we’re including them in our discussions of how we do things.”

Goodrich may bring in a third-interest partner in its pre-existing acreage and they are the logical candidate.

Turnham thinks that investors and analysts are increasingly overcoming initial concerns about the TMS’ clay content. “Going into the play, that was the primary concern, but that was before people would look at the data. We feel like we’ve pretty much put that to bed and we just need to work our way through these other issues. We were early in the [horizontal] Cotton Valley, Haynesville, Eagle Ford. In each of those, there was skepticism. “We put the numbers on the scoreboard. We converted those skeptics.” The ultimate concern with the TMS may not be one of geoscience, he concludes. “We just need to maintain a reasonable oil price so we don’t prove up an oil play here and have the price fall out from under us."