Louisiana Austin Chalk: Hundreds of Millions Down the Drain?

Matt Zborowski, Technology Editor | 30 September 2019

Strong initial results in 2017 from EOG Resources’ Eagles Ranch 14H-1 well sparked a land rush in the Louisiana portion of the Austin Chalk, where some big independents spent nine figures to gain swaths of acreage they hoped would be as productive as the Texas side of the play. 

Their plan was to come into the geologically challenging Louisiana Chalk with modern drilling and completions techniques and produce the oil economically, launching the next big unconventional play. But, after testing the play this year, the most that early driller ConocoPhillips has to show for its work is a whole lot of water.

The Houston independent on 30 September said that it “has discontinued exploration” in the Louisiana Chalk and will record a $120-million pre-tax “dry-hole expense” in the third quarter primarily related to the play.

ConocoPhillips completed three wells in the four-well drilling program, all three of which were duds. The latest was the Erwin No. 1 well, results of which were published on Louisiana’s SONRIS online data portal in late August. The well, completed in late July, initially produced 2,845 B/D of water and just 28.5 B/D of oil and 35.4 Mcf/D of gas.

The Erwin No. 1 numbers resemble those of the first two wells drilled by the operator. Completed in May, Hebert No. 1 flowed a whopping 4,279 B/D of water and just 206 B/D of oil. Two months earlier, McKowen No. 1 came on stream at a rate of 3,498 B/D of water and 60 B/D of oil.

Nick Volkmer, vice president at research firm RS Energy, said when his team first saw the results of ConocoPhillips’ first couple of wells, they thought the company may have performed the tests during flowback. But, based on comments in ConocoPhillips’ second-quarter earnings call, “it's pretty clear that's not the case,” he said.

Even more discouraging for the companies remaining in the play is that a larger sample size of production from Eagles Ranch indicates that it really “is not a great well,” said Volkmer. Testing at 1,120 B/D after it came on stream, production plummeted 94% in its first 17 months with a breakeven price “north of $90/bbl,” he said. 

“The only people happy with the results in the ‘updip’ region of the [Louisiana-East] Austin Chalk play so far are those in the saltwater disposal business! It's not the start that any of us hoped for,” wrote Kirk Barrell, president of Amelia Resources, on his regionally popular blog highlighting the Louisiana Chalk and Tuscaloosa Marine Shale (TMS). New Orleans-based Amelia has scoped out and sold drilling prospects across the Louisiana Chalk.

ConocoPhillips leased more than 200,000 acres in the Louisiana Chalk at a little under $1,000/acre. EOG and Marathon Oil also have more than 200,000 acres there, with Marathon also saying it gained its position at well under $1,000/acre. “These are big-name operators who have made hundred-million-dollar bets on the area, which leads us to believe that they clearly see something,” Volkmer said. “But in at least the public data we have, there's not a lot to get excited about here.”

Other large operators that built positions are Equinor, Cimarex Energy, and Devon Energy. Each has remained mum on the play as new wells results have been posted. They have been waiting for ConocoPhillips and EOG to prove up the play and now are hoping for good news—any news—related to EOG’s Ironwood LLC 37 H and Brunswick wells respectively spudded in April and June.

Unlike its Eagles Ranch well, which lies in a naturally fractured zone, EOG has targeted an unfractured, oil-saturated portion of the Chalk so “they can model their induced fracture network a little bit better,” said Brandon Myers, senior analyst, Lower 48 upstream, at consultancy Wood Mackenzie.

Numbers from those wells have not yet been made available in public filings. “But the rumblings I've heard are not that positive, and that kind of goes with the broader theme of what we're seeing in the area,” Volkmer said. Barrell wrote on his blog that he has heard Ironwood may also be “water plagued.”

While there have not been enough wells drilled to officially write off the play, “as a whole, we're pretty skeptical,” Volkmer said.

Is the TMS Really a Viable Alternative?

The Louisiana Chalk’s initial appeal can be attributed to decades of conventional production in the region and the known oil in place. But, “the depths permitted to drill there are deeper than 98% of all wells drilled in US onshore last year,” noted Volkmer. Drilling reports from operators show multiple mechanical failures, suggesting that perhaps the technology is just not there yet.

“The way they're completing the Chalk wells in Louisiana is with very high intensity, pretty close to 3,000 lb/ft of proppant in some cases, which puts it a little bit ahead of what we're seeing over in the south Texas area,” he said.

And, while the prolific Eagle Ford Shale underlies the Austin Chalk in south Texas, the even more geologically challenging TMS sits beneath the Chalk in Louisiana, which is hardly consolation for operators. Companies such as Encana and Goodrich Petroleum sniffed around the TMS earlier this decade but ultimately deemed it too technically difficult and expensive.

ConocoPhillips said in its second-quarter earnings call—before it pulled out of the region—that it was evaluating targets in the TMS as an alternative to the Chalk. “If you're talking about your TMS prospectively, I don't think it's a great sign,” especially given the company’s position in the TMS, which “is really deep and very gassy,” Volkmer said. However, the core of the TMS is farther north and oiler.

Perth-based Australis Oil & Gas, however, has set out to change the narrative on the TMS. The operator is trying to prove up its 115,000-net-acre core position mostly north of the Louisiana-Mississippi border, some of which it acquired from Encana at a low cost. Australis was formed in 2015 by the founder and executives of Aurora Oil & Gas after Aurora was sold to Baytex Energy. Aurora developed a liquids-rich position in the Eagle Ford, which has a similar depositional history and age as the TMS.

“They’re two for four in the TMS so far—two of their wells are actually pretty good,” said Volkmer. The company has touted those wells’ productivity on a per-foot basis, “but if you look at the well as a whole, it's definitely not great,” he added.

Much of Australis’ TMS acreage is in Mississippi, just north of the Louisiana Austin Chalk wells drilled by ConocoPhillips and EOG. Source Australis.

 

Australis’ Stewart 30H well came online with an IP30 of 1,216 B/D of oil and flowed a cumulative volume of 138,075 BOE/D in 6 months. The Taylor 27H-1 well produced 889 BOE/D, of which 93% was oil, and flowed 67,358 BOE cumulative in the first 2 months.

For comparison, Myers noted that the average well in 2018 across the Wolfcamp A northeast extension subplay in the Delaware Basin produced 132,000 bbl of oil in its first 6 months. Of course, the TMS well is a single parent well and the Wolfcamp A sample includes many child wells. 

“The rock is very tight, so it’s very low permeability,” Myers explained. “With a big frac in the TMS you can see a high IP30, but the downside risk is rapid decline. And it’s actually kind of a similar story in the Austin Chalk in that area where, when you have that low permeability, you can end up with a very ineffective drainage network.”

The other big hurdle has to do with drilling at such great depths, Myers said, as Australis’ Bergold 29H-2 well collapsed and the operator was only able to complete six stages. At 15,000–20,000-ft deep, the weight from the overlying rock is immense. “We see that going forward as a pretty serious risk on the on the drilling side of things,” he said.

Australis on 20 September began stimulation work on its fifth and sixth wells in the play: the Quin 41-30 3H and Saxby 03-10 2H. Completion activity is expected to take 3 weeks with flowback commencing in mid-October.

Saxby 03-10 2H was drilled to 17,560 ft with a lateral length of around 5,000 ft using a high-performance water-based mud system. The system enabled the wellbore to remain stable as drilling was performed, overcoming some of the structural issues that have plagued operators in the TMS and Chalk, the company said in a recent activity update. However, the operator also reported drilling delays on Quin 41-30 3H.

“I think there are large engineering and geologic risks, but when the completion and drilling goes well in the core of the TMS, the wells can be good,” Myers said.

https://pubs.spe.org/en/jpt/jpt-article-detail/?art=6039

 

Views: 1802

Replies to This Discussion

Skip:

Part of the answer lies within your comments.  LOGA and LMOGA are pro-industry business lobbying groups, and not necessarily pro-industry production groups.  The business goes where it can be successful and profitable.  Their lobbying groups cannot lobby to put profitably recoverable hydrocarbons in place, only to facilitate a business-friendly environment where they do operate.  Legacy lawsuits represent an impact (certainly a risk) to the cost of doing business within our state.

If one were to poll upstream stakeholders and decision makers as to if and when presented with prospects with equal risk and opportunity and similar project ROI, with one being in LA and another being in a nearby producing state (e.g., TX, OK, NM) where they would invest their dollars, most would say anywhere other than LA at this point - and the primary cited reason for it would be legacy lawsuits, secondary would be regulatory environment and related obstacles, and third would be general unfamiliarity with operating Louisiana properties.

Combine that with the idea that anything that would be prospective as to infills, offsetting or field extensions that would lie within the vicinity of an older field would create additional potential risks of lawsuits from actions of prior operatorrs in the field (the new prospector would merely be the next in the line), virtually any player of substantial capitalization would be averse to opening themselves up to that legacy risk.  Plaintiffs' bar looks for the deepest pockets whether your acts are integral, peripheral or incidental.

You do bring up the point that "the geology rules" - this is valid.  Now consider that the geology would have be so good so as to outweigh any and/or all the added potential risks (real or perceived) of doing business in Louisiana.

One other thing to consider - although the core acreage of the Haynesville certainly takes in several significant historic fields, the infill drilling in the Haynesville around and between those fields takes in large amounts of acreage where virtually no exploration or production had been successful - these areas therefore had less risk of such suits as one of the key markers that potential litigants use to identify areas where such lawsuits would be successful is in and around prior old production (most likely where "old-school" operations techniques occurred, e.g., unlined pits, uncased or improperly cased holes, old production casing and topside equipment, unmitigated leaks, land farming, etc.).  There is less risk to be had in areas where the first major E&P work is performed using modern techniques and best practices.  Ditto for much of the prospective AC fairway and the TMS.

Well said Dion.

Just a few comments - at least onshore - in wetlands, there is not a requirement to man production facilities 24/7.  I can't speak to new facilities in open water or off the coast.  

If I had to choose from projects with equal chance of geologic success and the same ROI, I would choose TX and OK over LA and NM.  

But the things driving continued development in the Haynesville in Louisiana and Texas is not just "good rock".  Available takeaway capacity, better workforce availability/lower costs, disposal availability, to name a few, influence the ROI and the viability of projects.  

Dion~

The risk of litigation is not unique to Louisiana. Furthermore I suspect that the number of lawsuits against the industry are greater in other states such as W Virginia, Pennsylvania and Ohio. Now admittedly those are not "legacy" as there is a lack of historic E&P activity in those states. A risk that can not be avoided by operating somewhere other than Louisiana.

I doubt that there are many investment decisions that are equal in opportunity between Louisiana and some other state. IMO, Louisiana has very industry friendly regulations and regulators so I'm puzzled how regulations would be a detriment to doing business here. Likewise "unfamiliarity" seems a weak reason for choosing not to operate in Louisiana.

I would place geology at the top of the list regarding company decisions. And in the era of resource plays, Louisiana is lacking. None of these stark, irrefutable factors appear anywhere in LOGA or LMOGA pronouncements. Now I would appreciate your opinion on the focus of those trade group/lobby organizations. I suspect that instead of representing "The Industry" both organizations focus on a subset of the industry. Smaller, independents. The ones that are largely drillers of vertical wells targeting conventional reservoirs in areas with significant historic activity in south Louisiana. That would seem to be where the risk of legacy litigation is greatest. My objection to the LOGA and LMOGA propaganda is that none of this is made clear. In fact the spin imparted to the varied campaigns is that it is a pervasive, state wide problem. I do not believe that it is. I have concerns for limiting the rights of property/mineral owners on a state wide basis for the benefit of a small segment of the industry that operates in one area of the state. The same segment that is most responsible for the outrageous extent of orphan wells that are ticking environmental time bombs.  This is a very revealing investigative report video on orphan wells for those who may be interested..

https://www.fox8live.com/story/36750057/zurik-orphan-wells-and-the-...

Skip:

As per custom, I will address your concerns in reverse order:

Orphan wells are a problem across the producing states, and not so disproportionately in LA.  Per a recent presentation given at the IOGCC Annual Conference, identified orphans across 29 states (some producing more than many others) as upwards of 36,000, and undocumented wells of approximately 188,000.

See Slides 10 &12.

Although I would mostly agree with your characterization of LMOGA, LOGA has majors and major independents to count amongst its members.  One highly touted success of LOGA was the brokering of the LA R.S. 30:10 amendments effective 2012.  While ostensibly helping small independents and RI owners by providing a means of relief and redress for operators paying existing royalty owners HBPed by shallower reservoirs by pass-through payments made to non-participating non-ops, it also lowered the bar for speculative interests to acquire leases subject to lower infill risk-fee penalites, and helped undermine any well-funded lessee attempts to break HA units by administrative and/or legal action.  A victory orchestrated behind closed doors for the major independent producers in the Haynesville by LOGA.

As far as you (or me, for that matter) finding unfamiliarity and discomfort with LA laws being a reasonable excuse as to not invest in LA, frankly, the decision makers are generally not listening to us, they're listening to their legal teams and risk consultants.  Remember how many bad leases were taken (generally with no warranty) because out-of-state companies retaining out-of-state landmen who didn't understand the implications of prescription in long-term producing areas?  They keep track of the money burned in doing that.  They find comfort in being able to operate in states where they pool units and interests how they wish and merely cut out the intractable mineral owners and working interest owners, like Texas and others which model Texas laws and case law into their own mineral law.  In states where there is force pooling, they find solace in operators being able to take effective possession and control of lands and leases who do not consent to terms administratively adjudicated by a state board (such as the AOGC in Arkansas, or the OCC in Oklahoma), complete with enforcement of risk penalties against all interests of 200-400%.  They are better able to quantize risk in other states which limit recovery on legacy and contamination claims either administratively or by statute compared to open-ended awards and punitive damages still allowed by law in LA, which is only restricted as to a "Corbello"-style recovery (plaintiffs lawyers merely sue on grounds specifically excepting those types of claims in order to sidestep the DNR and administrative handcuffs).

Finally, regulatory compliance and documentation is of a higher cost in LA.  The very factors which makes our public information searching ability through SONRIS basically second-to-none is a result of extensive regulatory compliance requirements and frequency of reporting.  Not to call out in a derogatory way, but our communication and compliance regulations and completions of forms in LA make that process for the Oil and Gas Board for the State of Mississippi compare as to filling in a eight-year-old's coloring book.

Also unfortunately, consider that the education and training of most company landmen are through energy and land management programs through accredited schools in Texas and Oklahoma, which emphasize their systems, their laws and their compliance - it's where most of those decision makers feel the most comfortable.

Dion, my length and pithy reply seems lost in cyberspace.  I don't have time to replicate it now but will find time tomorrow.  Drat your reverse order!  LOL!

I await your lost submission.  LOL -- DLW

The fact that other states also have orphan well problems does little to dispel my concern for those in Louisiana.  I do not think that those other states face the problem of inundation and their orphan wells going under water.

I am encouraged that you mostly agree regarding LOGA and LMOGA.  As to highly touted successes, by whom?  LOGA and LMOGA?  Although I completely agree that there is a benefit for the relatively small number of mineral owners/royalty interests stuck between operators and lessees regarding royalty payments, I think we both know that was not a primary concern for either of those organizations.  It is an unintended outcome that they are happy to try to spin as looking out for Louisiana minerals.  They do not.  In fact, the contrary is the case IMO.

The “bad leases” taken, once again in my opinion, are solely the fault of corporate decisions by the managers responsible for the early Haynesville land rush.  I would like to know if all the landmen in Lafayette and south Louisiana, who are familiar with the requisites of Louisiana leasing, were unavailable to the point that those managers had to bring in landmen from other states who were inexperienced in leasing Louisiana minerals.  That is of course a rhetorical question not requiring a response on your part.  Those mangers either didn’t know or didn’t care.  In either case the fall out is solely on their shoulders.

As to force pooling, yes, other states disadvantage mineral owners to the benefit of operating companies and the land companies they employ to a greater extent than Louisiana.  Perhaps some of our East Texas GHS members would care to revisit some of their experiences getting wood shedded by operators regarding their minerals.  Louisiana mineral regs do extend a bit of protection to owners of minerals particularly those who are unleased and most vulnerable under other states’ force pooling statutes.  A small but meaningful difference.  Those with few options should be grateful for even the most modest of consideration upon their behalf.  Operators regularly ignore those requirements and now find themselves in court facing class action lawsuits.

Yes, filing reports for Louisiana’s Office of Conservation is probably onerous in comparison to Texas and Oklahoma.  Maybe LOGA and LMOGA will object to that next.  Comparing Louisiana reporting requirements to MS is a low bar indeed. 

Dion, sorry for the delay.  To the best of my recollection, this is my reply that seemed to disappear into cyber space.  Regards, Skip

Skip,

Have you heard anything about the EOG Ironwood well? They completed it back in July. Seems like they would have gotten some results by now.

Also, I heard that EOG was going to jump across the border and drill a TMS test. Heard anything along those lines?

Thanks!

Mike,  the most recent report in the database, Oct 1, shows Status 31: Shut in Dry Hole; Future Utility.  Usually I see that status code after a well is drilled to TD and waiting on a completion crew for the frac.  Since EOG fracked the Ironwood (7/12  to 7/29) I suspect the Ironwood is not considered sufficiently productive to place on production.  The fact that EOG has plugged their Brunswick well without drilling the lateral and reported it as Status 31 also leads me to believe that EOG did not find what they were looking for in their AC tests.

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