The Tuscaloosa Marine Shale: America’s Next ”Hot Money” Oil Play?admin
You know what makes the Bakken oil play so special? It is oily AND over-pressured. All that means is that at a certain depth, there is more pressure than normally should be there—because there’s fluid there.
If that fluid is oil—it’s trapped—then it’s bursting to get out. It sure makes for great flow rates to get the Market excited.
And that’s what is making the new Tuscaloosa Marine Shale (TMS) in Louisiana one very intriguing tight oil play in the US.
You look around at almost all the other places in the US that produce oil, and they are either oily OR over pressured. Some parts of the Permian have both. But it’s not that usual.
If a tight oil play is surrounded by impermeable rock deep underground, the oil and gas can’t go anywhere—it just sits there under huge and building pressures. Sometimes the oil and gas can migrate a bit, but still be under huge pressures.
When they first get drilled and fracked, they can produce some BIG flow rates.
The other thing very impressive about the TMS? It covers at least 2.7 million acres just in Louisiana, and stretches into southwest Mississippi.
(And like every other big tight oil playout there, there’s an independent study that says it has billions of barrels of oil. The TMS study says 7 billion barrels, but hey, that was 1997. There’s probably a lot more since then. ;-))
The last, single most impressive thing about the TMS—it’s proven. There are several wells with over 1000 bopd IP rates. Goodrich Petroleum (GDP-NYSE) has already run from $12-$27 on this play. Sanchez has gone from $17-$27 on this play.
The TMS is the source rock for the lower Tuscaloosa Sandstone and Austin Chalk formations which have produced oil for decades. Like most horizontal plays, the industry has long known the oil existed in the TMS. The mystery was how to get it out economically.
The TMS exists between the upper and lower units of the Tuscaloosa formation, which has been the source of conventional oil production in the area for decades for the “Tuscaloosa Trend.”
During conventional vertical well development of the “Tuscaloosa Trend,” the TMS was viewed as nothing more than a nuisance zone that slowed drilling on the way to the lower Tuscaloosa.
Occasionally, though, it did show some oil when the drill bit passed through it which put the TMS on the radar of a few geoscientists who were long-term dreamers.
The TMS attracted some more attention in 1997 when Louisiana State University’s Basin Research Institute released a study estimating that 7 billion barrels of oil lay in place awaiting recovery.
BENEFITS AND CHALLENGES OF THE TMS
Like the Bakken and Eagle Ford before it, horizontal drilling, multi-stage fracturing and some serious trial and error now appear set to release some of that giant oil prize.
The Cretaceous-age TMS is big. It covers at least 2.7 million acres in Louisiana and crosses into southwestern Mississippi.
And like I said up top, it’s important to note the TMS is not a “combo” play that is a mix of oil and natural gas or condensate (gets the same price as oil) production.
This is an oil play—and there aren’t many of them.
Early wells have shown production to be weighted 90% to 95% light oil.
The TMS is being targeted at depths of 11,000 to 13,000 feet, where the rocks have a thickness of 100 to 250 feet.
The play is extremely overpressured (0.70 psi/ft versus a more typical ~0.45 psi/ft), which results in high oil saturations and helps to naturally lift the oil up the wellbore. The upside is BIG flow rates.
The downside is that it makes wells more expensive.
But I think the TMS play has several advantages that outweigh cost.
One advantage is its location–Louisiana and Mississippi have a large amount of infrastructure already in place. The region already has pipelines, refining capabilities and people with experience in the industry. That reduces development costs.
And there is no severance tax on hydrocarbons recovered using horizontal wells in Louisiana or Mississippi for two years or until the producer recovers their costs of the well–that sure helps economics.
A third is how close it is to the St. James terminal located on the Gulf Coast of Louisiana. Oil sold to the St. James terminal has received a premium to WTI which reached $10 to $20 in 2012. That premium has since shrunk, but could return if pipeline and rail infrastructure can’t keep up with the pace of production growth.
And I keep coming back to this–fourth, this is very “oily” production. Wells drilled so far in the TMS are 90% to 95% black sweet oil. And that 5% associated gas has a high BTU content with approximately 80 to 100 barrels of NGLs per million cubic feet produced.
While the TMS has been compared favorably to the Eagle Ford, the play is deeper and therefore has more expensive wells—the Big Negative. The oily part of the Eagle Ford is 5,000 to 10,000 feet deep, and wells cost $7 to $8 million.
Meanwhile, wells targeting the TMS which is at depths of 11,000 to 13,000 feet, costs for single wells are running at $13 million and higher.
That means that for the TMS to match the economics of the Eagle Ford, either well costs have to come down or production has to outperform.
Goodrich Petroleum (GDP) believes that the cost per well could be shaved down from $13 million for a single well to closer to $10 million if a full development drilling program was to be rolled out. A full development plan brings with it economies of scale and improvements in drilling efficiency through experience.
Goodrich’s competitor Halcon Resources also believes that a well cost of $10 million is a reasonable target that could be achieved.
Both Goodrich and Halcon are operators with considerable experience in the Eagle Ford and have a good idea of gains that can be made as drillers become more experienced with a play and more efficient.
Assuming a base casetype curvethat allows for 600,000 BOE of gas to equal the amount of energy in one barrel of oil. (barrels of oil equivalent) to be recovered (that’a the EUR–the Estimated Ultimate Recovery) and a $10 million well cost, a TMS well has an IRR of 75% (at $100 WTI). At a high case type curve that predicts 800,000 BOE of gas to equal the amount of energy in one barrel of oil.will be recovered the IRR jumps to 156%. That’s a little bit bigger than the Bakken.
In its last quarterly conference call Goodrich Petroleum indicated that its recent Crosby well had produced in excess of 100,000 barrels equivalent in 5 months, and that it is still producing approximately 375 BOE per day at the end of 6 months of production.
According to Goodrich, plotting that 375 BOE of gas to equal the amount of energy in one barrel of oil.per day of production on their 800,000-barrel equivalent “high case”type curveat the 6 month point puts them above the curve.
That is encouraging obviously as that well would be considered very economic.
But it is just one well.
Normally that wouldn’t get me too excited.
But there is more than just one well. Several operators have hit strong wells–so the industry has a bit of tweaking to do, but they have already “cracked the nut” on this play; they know how to produce from it.
Goodrich which has a market capitalization of under $900 million just acquired an additional 185,000 acres in the TMS. That is a big commitment for a company of this size. They now have 300,000 net acres.
The other big player in the TMS? Canada’s Encana (ECA-NYSE/TSX)—the 5th largest natural gas producer in the US. The wells they are drilling and operating actually have the best IP rates I see in the TMS. (I own ECA)
Sanchez Energy (SN-NYSE) just spent $78 million to get what I calculate from a complicated press release to be 40,000 net acres—or just under $2000 an acre.
Conclusion—deeper wells mean more expensive wells, but that can also mean higher EURs to compensate for that.
And infrastructure is in place and being close to the Gulf Coast Refinery Complex means lower transport costs and for now high pricing.
The Bakken in North Dakota and the Cline Shale in Texas have been the “hot money” oil plays in the US (the Eagle Ford is more gassy), and the TMS could be the 2014 play.
Posted: October 3rd, 2013 under ACCESSWIRE.