At press time, Crosby 12H-1 was under way in Wilkinson County in the southwestern corner of Mississippi among rolling hills just east of the ancient river and its legendary delta. Goodrich Petroleum Corp., operator with 50% working interest, was just about to finish a targeted 7,300-foot lateral, and the post-completion flow results were highly anticipated.

Yet, frankly, news from every one of these new Tuscaloosa Marine Shale wells is anxiously awaited.

Within a year, the area that hadn’t had a new horizontal Tuscaloosa attempt since 2009 now hosts more than a dozen completed wells and another dozen are in permitting, drilling or completion. Rob Turnham, Goodrich president and chief operating officer, estimates 20 or 25 completed wells by the end of this quarter. With this, Goodrich and other operators may be able to develop decline-curve and estimated-ultimate-recovery (EUR) statistics for the play, forming the basis for determining whether it has an economic future.

Results that have been announced to date have been very encouraging. Encana Corp.’s Anderson 17H, in which Goodrich has a 7% interest, in Amite County averaged a whopping 933 barrels of oil equivalent (BOE) per day, almost all oil, in its first 30 days on a 15/64 choke from a roughly 7,300-foot lateral and 30 frac stages. It posted 1,172 a day in a 72-hour rate and was making 300 a day six months later.

“It’s on artificial lift now,” Turnham says. “Production has flattened, so we’re seeing the hyperbolic curve, indicative of long-life, matrix flow versus an exponential decline which would lead you to believe we were only draining fractures.”

All of the modern TMS wells are making oil. Devon Energy Corp.’s nearby Richland Farms 74H-1 came in at 284 BOE a day on a 9/64 choke from a roughly 5,000-foot lateral with 20 frac stages in Wilkinson County. And, Encana Corp.’s Horseshoe Hill 10H-1 made 656 BOE a day in a 30-day average from a roughly 5,300-foot lateral and 18 frac stages.

South, in Louisiana, Devon made Murphy 63H-1 for 408 barrels a day on an 11/64 choke from some 5,300 feet of lateral in West Feliciana Parish.

Moving east, Devon’s Beech Grove Land Co. 68H-1 made an average of 101 a day over 30 days from a 3,400-foot lateral and 12 frac stages.

Turnham notes that another well, Encana’s Weyerhaeuser 73H-1, has been online for nearly a year now; it came in at an average of 740 BOE a day from a 5,000-foot lateral and 15 frac stages. Its decline curve is promising.

“Just like the Anderson 17H, we see a hyperbolic curve which has us comfortable with the resource potential. Now, our primary focus is getting the well costs down and putting the economics out there, so investors can make their decisions.”

In a year of work, wells are now estimated to cost $12- to $13 million each, if with a 7,500-foot lateral and 25 frac stages, down from early estimates of as much as $19 million. Further cost reduction is possible once the play is proved and more oilfield equipment, crews and infrastructure enter the area. “In fact, EOG (Resources Inc.) reached total depth on a well in 28 days which, by our estimates, would be in the $10-million-completed-well-cost range. This, in our opinion, would generate very high rates of return, and be competitive with other oil plays,” Turnham says.

It appears that the longer lateral—that is, a two-section lateral, which is permitted in Mississippi but not yet in Louisiana—is better. The most impressive wells revealed to date are in Amite County, just east of Wilkinson. After the whopping Anderson 17H-1, Encana’s Anderson 18H-1 averaged 1,072 BOE a day over 30 days from a roughly 8,800-foot lateral and 29 frac stages.

This Mississippi side of the play is where Goodrich is focusing now—about 55% of its 134,000 net, 156,000 gross, acres are there; the balance, in Louisiana. Amongst all its acreage, some 95% of it is where TMS oil pay is at a shallower depth—10,500 to 13,500 feet—than at the 16,000 feet the TMS can reach in some areas.

“If you look at the hundreds of wells drilled through the TMS in the 1970s and early ‘80s for gas, a number of them produced or showed oil in the shallower portion, so our block is where the TMS is shallow.”

Findings to date include that the TMS appears there to be 100 to 160 feet thick with a little higher clay component in the upper portion. The amount is slightly more clay than in the Eagle Ford, but less than in the Utica. “We’re not concerned we have too much clay here,” Turnham says.

Of course, Goodrich and Encana, which have adjacent acreage in Mississippi, aren’t focusing on the upper part of the TMS anyway. Instead, they’re targeting the bottom half or third of the rock, which is also where they’re finding it to be brittle, having natural fracturing.

“Clearly, that is how you’re getting these 1,000-BOE-a-day wells. You’re seeing very good fracturing and pressures providing high initial rates and matrix production from the shale itself, which is giving you the hyperbolic-shaped curve and the long-life resource.”

Rubble trouble

Meanwhile, the pair is also working to solve for the rubble zone. In a joint well, Encana’s Ash 31 H-1, the 6,500-foot lateral was landed above this roughly 10-foot trouble zone that sits some 35 feet above the bottom of the TMS in Amite County. The zone is composed of poker-chip-size pieces of shale that crumble easily.

“It’s fine when you’re drilling through it,” Turnham says. But the key appears to be to enter this zone at a steeper angle because, at 80 or 90 degrees, the wellbore wants to cave in or slough, causing increased rig days while the wellbore is washed and cleaned out.

Rubble rubble, toil and trouble. This happened to Goodrich’s first TMS operated well, Denkmann 33 H-1, adding several rig days. Upon successful repair of a popped casing connection, Denkmann is to flow this year from a 4,000-foot lateral—abridged from a 7,000-foot plan.

Nearby, the famous Anderson 17H-1 entered at a roughly 70-degree angle and had no trouble in the rubble. “The big question for us is if this is unique to this area. What we have seen is, if you take a bit of a steeper angle through the rubble zone, you do seem to stay in it less time and have less of a problem.”

Another option is to land laterals above the rubble zone. Encana’s second Ash well, Ash 31H-2, was being drilled at press time off the same pad as the first; each is expected to be fraced this month. “The question here is if you will stimulate the entire interval if you land above the rubble zone. It shouldn’t be a problem, but it is a question right now.”

Goodrich is testing another option with its Crosby 12H-1 by getting the rubble zone behind about 200 feet of additional well casing. “So, when we come out to replace bits or bottomhole assembly, we just don’t have to deal with the sloughing issue; it’s behind the liner.”

None of this rubble trouble will ruin a well, though. “If you drill the hole with a big enough diameter, you can come up and get it behind your liner. That is a contingency. We just have to make sure we build a big enough hole, so we will have that contingency.”

A decision will ultimately be based on if landing above or below the rubble zone will make a better well. “We think you could stimulate the entire zone. And there has been some microseismic run that suggest you could get 200 or 300 vertical feet of growth when you frac the interval, with stimulation up and down regardless of where you land.

“It could be that you don’t need to land below. But we want to make sure and have a comparison because the two best wells drilled in the TMS to date are the two Anderson wells and each of these landed below the rubble zone. They didn’t have the sloughing issue because they came in at a very high pitch; they didn’t stay in that zone for long because they were in at less than 75 degrees.”

The cheaper approach is sans the additional casing, although it isn’t very expensive, he says. “We need an answer. Once we figure out we’re stimulating the same shale and getting the same results, we would go with the cheaper approach.”

TMS economics

As more wells come online, contributing to estimates of play economics, some surface characteristics will help as well. For example, oil from the area fetches the coastal Louisiana Light Sweet (LLS) price, which is roughly that of Brent, thus some $22 higher than WTI. Royalties average 20%; in South Texas’ Eagle Ford, the average is about 25%. In Mississippi, the severance tax is roughly 6%; in Louisiana, it is none at first, due to state incentives for horizontal drilling.

“And the play itself is 94% oil,” Turnham notes, and it is light and sweet with gravity between 38 and 44 degrees. “With the LLS price and low royalty and tax burden, you have the ability to spend a bit more money to generate rates of return similar to the Eagle Ford.”

Entering this year, Goodrich has participated in eight Tuscaloosa wells, 4.3 net, for a cost of some $40 million. Its leasehold, which it acquired for an average of $245 an acre, has terms ranging from a balance of one year to five years; some 50,000 net acres have “continuous drilling” permission that allows Goodrich to continue to hold it as long as one well is drilled per 180 days.

TMS results the farthest east to date are both from Devon in Tangipahoa Parish. Its Thomas 38H-1 had initial production of 402 BOE a day on a 9/64 choke; its Soterra 6H-1 averaged 176 BOE a day over 30 days from a 4,300-foot lateral with 13 frac stages.

Meanwhile, west of the Mississippi River, EOG’s Dupuy Land Co. 20H—the one that was drilled in just 28 days—was being completed at press time in Avoyelles Parish near Goodrich’s 40,000 net acres in Concordia Parish. Another EOG well, Gauthier 14H, was being drilled at press time, also in Avoyelles Parish.

Floyd Wilson’s new Halcon Resources Corp. has plans more west, in Rapides Parish, where Bill Pritchard’s Indigo Minerals LLC made an Eagle Ford well, Bentley 34-1H, in 2011.

Turnham expects industry to be able to make a ruling on the TMS’ economic future by the end of this quarter, deciding then if Goodrich will bring in a partner—that is, more money. “We feel we have a real shot at proving this play. The resource is there. But, in its early stages, you have to be very cautious with capital until you feel comfortable with the economics.”

Excerpted from January 2013 Oil and Gas Investor article, Emerging Oil

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