Is the Tuscaloosa Marine Shale the next Bakken? - Part 2

Housley Carr for RBN Energy

The potential for the Tuscaloosa Marine Shale (TMS) tight-oil play to become the next big thing in U.S. oil production is attracting exploration and production companies willing to put some money at risk in the hope of big payoffs. The TMS seems to have a lot going for it. The play in central Louisiana and southwestern Mississippi is said to have seven billion barrels of oil in place deep below ground but only a stone’s throw from the pipeline networks, terminals and refineries of the Gulf Coast. But succeeding in TMS requires overcoming the play’s challenging characteristics through nuanced drilling techniques and completion formulas. Today in the second part of our series on TMS we examine what the E&P pioneers have accomplished so far in drilling and production, what they’re learning from their experience, and what it would take to turn TMS’s potential into reality.

In Part 1, we examined the 6.6-million-acre TMS play in detail, and considered the physical and geological conditions that make it both so promising and so tricky. We also looked at the mostly failed efforts in the past to make drilling in TMS pay, why things may be different now, and who is out front in testing the play’s potential. TMS is a sedimentary rock formation several hundred feet thick and between 10,000 and 15,000 feet below the surface; the dark gray marine shale within the formation consists of fine-grained, organic-rich sedimentary silts and clays. The depth and low permeability of TMS have scared off many a driller, as has the very thin layer within it that offers natural fracturing (and increased permeability). Still, some companies active in TMS have been reducing drilling costs and tweaking their completion formulas to better deal with the play’s softer rock and clay-like material. (see Tales of the Tight Sands Laterals for more on hydraulic fracturing). Those completion-improvement efforts may increase the estimated ultimately recoverable (EUR) oil from TMS wells and, with that, the likelihood that TMS will emerge as a profitable and important play (see our The Truth is Out There series for more on drilling economics).

The relatively small set of companies active in the TMS includes EnCana, Goodrich Petroleum, Sanchez Energy, and EOG Resources. EnCana and Goodrich, for example, each have more than 300,000 acres in TMS under lease. Goodrich and Sanchez in recent months have been expanding their holdings significantly, Goodrich through the July purchase of Devon Energy’s two-thirds share of leases on about 277,000 TMS acres. In August, Sanchez bought leases on about 40,000 acres—like the others, much of the acreage is in what has become the very active heart of the play: the state-border area between southwestern Mississippi and the Louisiana parishes an hour’s drive north of Baton Rouge (see Figure 1).

Figure 1

Source: Sanchez Energy (October presentation; aqua-colored line is the state border)

As in most plays, there is a significant learning curve in TMS as drillers come to better understand the characteristics of the formation, and what works and what doesn’t in maximizing a well’s output. Thanks to data-sharing agreements among the TMS players, the learning curve is shorter than it might otherwise have been. Key subsurface lessons learned from the nearly 20 wells drilled in the past two years or so include the benefits of longer laterals and completions enhanced with the increased use of sand, clay stabilizers and proppant—all to help prevent the softer rock and clay-like material in TMS from self-sealing (see Getting Proppant to the Wellhead for more on proppant materials). An executive at one company active in the play tells us that longer laterals increase the number of two-to-four-inch-wide fractures the wellbore passes through, and that laterals of up to 10,000 feet are the ultimate goal. “Lateral length will be very important [in TMS], as will zeroing in on the right amount of proppant,” he says, noting that while more proppant is needed in TMS than most other plays, “too much proppant will damage the formation.”

An October summary by Sanchez Energy of TMS wells put on production between the fall of 2011 and early-summer of 2013 reveals what is emerging as typical or average for the play: a well with true vertical depth (TVD) of about 12,500 feet; lateral length of about 5,500 feet, with an average of 20 frac stages; and about 400,000 lb of proppant/stage (see Figure 2).

Figure 2

Source: Sanchez Energy (October presentation; well data as of mid-2013)

The data shows that the 24-hour initial production (IP) of the wells ranges widely—from 35 to 1,540 barrels of oil equivalent (BOE) —and averages just under 700 BOE, while the 30-day initial production (IP - available only for wells in production for at least five months) ranges from 85 to 1,137 BOE/day, and averages 613 BOE/day. The cumulative output of at least two of the wells had topped 100,000 BOE as of July 1, and a few other wells passed that mark since then or soon will. The now-common expectation among those active in TMS is that the expected ultimate recovery (EUR) for most wells is between 400,000 and 800,000 BOE, with many in the upper half of that range with flat declining curves (for more explanation of EURs and decline curves refer to our The Truth is Out There series). Goodrich’s Crosby 12H-1 well, which came online in February 2013, has been performing even better than its 800,000 EUR with current production of 250 BOE/day and a very flat decline curve. Drillers believe that as they continue to fine-tune their completion formulas the number of Crosby-like success stories will increase. Companies also are successfully reducing their drilling and completion costs. Some earlier wells in TMS cost as much as $20 million to drill and complete, but most participants in the play are working to reduce per-well costs to $15 million or less; some are shooting for $10 million or even $9 million, goals that may be achievable by late 2014 or early 2015. The reductions are achieved through several means, among them multi-well pad drilling, improved completion practices, and increased competition among service companies as the TMS catches on. “All the wells drilled to date have been one-offs,” that TMS-active executive tells us. Now that companies are starting to commit to multiple rigs, he says, service companies “are starting to be drawn” to TMS. The economics of a 600,000 or 800,000 EUR well that costs only $10 million to drill and complete are compelling: internal rates of return (IRRs) of 38% to 80% at oil prices of $80/Bbl and IRRs of 70% to 140% at oil prices of $100/Bbl.

Whether TMS takes off like a rocket or fizzles depends on a lot of things, perhaps none more important than continued success with the next 20 to 40 wells drilled and completed. Also, time will tell whether the existing wells’ decline curves stay relatively flat and the big-number EUR’s  pan out. If they do, the play has other positives that could prod it along too. As we noted in Part 1 of this series, TMS doesn’t just offer significant amounts of oil at a time when the oil-to-natural-gas price ratio is so favorable, it offers it in a region flush with water, spitting distance from major terminals and refiners, and eager to encourage drilling through tax credits and low taxes. “You couldn’t ask for a better place for oil to be located,” says the executive who talked with us. One other big plus he notes: A “forced-pooling” regulatory regime in TMS that compels landowners in designated spacing areas to participate jointly in mineral development there. Forced pooling is “a very efficient way to drain the rock,” he says, and also prevents operators from depriving landowners of their fair share of the oil and gas under their land.

TMS’s break-out year may well be 2014, as the larger participants in the play ramp up their planned capital expenditures (cap ex) to previously unheard of levels. Goodrich, for example, plans to spend $300 million of its $375 million in 2014 cap ex on TMS (up from $65 million in 2013), where it currently has two rigs running. It plans to add a third rig in the first quarter of the new year, and two more by the end of 2014, with the aim to drill or participate in at least 24 new wells, and maybe more. EnCana, meanwhile, plans to invest $200 million to $300 million in TMS in 2014 and to run as many as three rigs; EnCana also has identified TMS as one of five major focus areas in the U.S. and Canada. Sanchez, finally, plans to quadruple its TMS drilling and completion budget to $40 million in 2014.


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