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.



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Replies to This Discussion

Overall, this is a good article that summarizes some of the results of the recent activity in the Louisiana AC trend as well as the TMS trend. But I would also note that this is written totally from a non O&G operator perspective.

I would encourage anyone reading this to do some research as to the backgrounds of the author and those referenced in the article. And then consider their almost total lack of technical education, training, oilfield expertise and experience (with the exception of Kirk Barrell / who is only very briefly and inadequately referenced) when you read this article. 

  • An example, in my opinion, of inadequate comments and reporting is the EOG Eagles Ranch 14H-1 well. Aside from being the FIRST well in the trend (and where has the first well in any new play area been a rousing success?), the failure to include comments about the published details for this well (e.g. lateral being drilled toe down and out of target zone in a relatively short lateral wellbore) as well as the fact that every unconventional horizontal play shows extreme production decline over its first 1-2 years of production is a glaring omission and misleading to any reader.
  • Digging into the details and laying out a more complete story instead of just skimming the surface with an ill supported few comments is not the approach that I would take in discussing a key point as to the Louisiana AC Hz Frac play concept. 

The ultra damning but attention getting headline paints an initial condemning tone with respect to the Louisiana AC play and what the operators have been doing. Typical of the approach that many authors seem to be taking today so as to grab the readers' attention.

But what the author as well as the contributing "experts" fail to address is that the approach taken by the operators in this trend is the "norm" for jumping into a new play concept area. And oftentimes, these new plays fail. There are numerous examples of this happening across the USA as well as internationally in the oilfield. Just as there are examples of this aggressive approach working for those companies that took the plunge to get into these areas ahead of the pack.

Instead, the title and content of this article seems to be saying that this is an infrequent occurrence in the oil field. And even goes as far as to hint that the operators don't know what they are doing.

This is what O&G operators and exploration companies do - pour money into various areas after extensive research in an effort to discover and exploit new economic O&G resources. One only needs to look at all the dry holes and associated barren acreage that have been drilled over the life of oil field.

And what is happening in Louisiana in the AC trend is no different.

Are the initial results in the Louisiana AC Hz Frac play disappointing and mostly negative - absolutely yes!

But if you consider the number of wells that have been drilled in this HUGE play area, only a very small part of the trend has been evaluated.

Remember that the "sweet spot" in the Texas AC Hz Frac play that everyone talks about (I.e. the Karnes Co EOG core area) covers only about 50-60 square miles. And that other results in the Ac Hz Frac play along the trend that spans from Mexico to the Tx / Louisiana border cover the spectrum from dismal to variably economic & successful.

It takes a lot of time and a lot of $$$$$$$$$$$$ to figure out a new play concept in a new area. The amount of money spent to date on leasing, seismic, drilling and testing is just a drop in the bucket as to what it eventually take to figure out if the Ac Hz Frac play in Louisiana will work. And where it will work.

Let's not give up on this play concept and area yet!

Although I agree with Rock Man's exceptions to the article I would like to point out that the author, Matt Zborowski, is the Technology Editor for the Journal Of Petroleum Engineers.  SPE is among the most authoritative sources of articles on the O&G industry.



Yes, Matt Z is Technology Editor. But look up his background on LinkedIn. LSU grad in 2009 with BA in mass communications and minor in political science. And zero expertise in any technology related field prior to being named Technology Editor.

I don't know how SPE screens articles written by their editors, but it is not apparent here that a lot of engineering and/or geoscience effort as well as oil field acumen went into the construction of this article. 

One can research and pull together information from various sources, but does that constitute a true understanding of what you are writing about?

Just my opinion as always on this and other issues.

PS - I am a member of SPE as well as AAPG and numerous other technical organization. 

I get the JPE newsletters and have downloaded a number of SPE papers.  I have always found the articles in the newsletter and the scientific papers of interest and well written although I stick to the Haynesville/Bossier Basin or Louisiana and do not venture beyond what informs my work. Since Matt Zborowski is an "editor", I wonder who else at JPE may have contributed to this article.  Although JPE is a science based organization the article does seem to have a certain approach that I am familiar with when there is an intent to get an article picked up and posted by multiple media outlets across the Internet.  The article I posted directly from JPE yesterday has now hit my inbox a half dozen times this morning from other sources.  I bet those outlets are doing so based on the article title and the source.

Headlines grab attention! Seems to be a mantra that is being followed in all aspects of journalism IMO. A short surfing trip thru the internet seems to confirm this.

Guess it is something that we have to get used to living with point forward.

I have been critical of articles penned by this author in the past.

To other readers, the underlying theme of my long winded initial posting should probably be "Don't take everything you read as the gospel!"

I am closing the book on this topic right now..

Rock Man,

I agree with just about everything you said and would like to add a few points.

First of all, I would like to say that I was not all that thrilled with Conoco's play selection. They essentially made one "play" in a very large basin. In other words, they really put all their money on one bet. I have mapped the AC from Texas to the Pearl River in both Louisiana and Mississippi and can assure you that it varies significantly across that area. It is not monolithic and, from my analysis, is not a true "resource" play. Even Kirk Barrel (who was trying to promote HIS acreage holdings) admitted that it was a "porosity play" in that you had to target the lower permeable zone of the Austin. Think about that. If the Austin has intrinsic perm (and porosity), then you MUST have a natural trapping mechanism in order to have an accumulation. Based on the data that I have been able to gather, it appears that ALL of the porosity and perm is fracture derived with little or no matrix porosity. This is supported by the fact that mudlogs that I have seen through the oil productive Austin rarely have "oil shows" noted. The reason is that the oil is contained in the fractures and when the rock is ground up by the bit the oil that is released is emulsified by the mud. The microcrystalline chalk has no porosity to hold the oil in cuttings.

Secondly, if you look at the places where production has occurred, most appear to have some sort of updip structural or stratigraphic barrier that traps the accumulation (see e. g. Moncrief, Bayou Jack, et al).  Even Masters Creek seems to have a true perm barrier to the north.

Thirdly, I find the Eagles Ranch well to be a very interesting well. It is WAY downdip but has produced about 140,000 barrels thus far from only a 4200' lateral with 19 stages. Because of the unusual depositional and structural history of the chalk, there are wells that are a MILE updip that look identical to this well. I've always wondered what kind of well it would have been if that mile had been drilled laterally instead of vertically. it also appears to me that some of the more updip wells have more favorable gravities and GORs. 

Regarding the TMS, there are a few fairly impressive wells in the TMS and once again I think part of the problem was that several companies kind of put all their eggs into one basket. THE best well is in 2N-4E and trendwise is one of the most updip locations drilled. It has produced 517,000 BO and is currently doing about 185 BOPD. It also has one of the longer laterals of about 7100' (to the south, downdip). The second best well, slightly south, has a 9754' north lateral and has made about 450,000 BO and is doing 155 BOPD. I don't know what the EUR is going to be but the curves are pretty flat. The problem with the TMS over much of the tested area is simply not enough intrinsic porosity to hold highly commercial amounts of oil. There are areas that have much better porosity and thermal characteristics that have never been tested.

I think part of the problem is the herd mentality and closeology comfort found in the large companies. In the case of Conoco,  they played an area where there had been some "shows" in the chalk AND near where other companies were playing.

I was tickled by the comment above "at 15,000 to 20,000' the weight of the overlying rock is immense". Obviously not written by a technical person.  

MJ, lots of good comments in your posting. And your very last sentence says it all about the author issue.

I think that Conoco tried to take what they learned in their Live Oak / Bee / Karnes County EF /AC area and apply that to the Louisiana part of the trend. I wish I had some of the core results for some of these areas to "see" the P&P systems that are being pursued in the AC.

Thanks again for posting - always learning after almost 42 years!

I learn something new almost everyday. One of my favorite wines now comes in a can!

Off topic.... but interesting.  What's the brand?  LOL

Cupcake Sauvignon Blanc. It's one of the lower priced sauvignon blancs from the Marlboro region of New Zealand which unquestionably produces the finest sauvignon blancs on the planet.

It comes in a 375 ml can which is basically a 12 ounce can. Two of them are equal to a standard 750 ml wine bottle so one could say he had a couple of cans of wine instead of a bottle. Sounds better to me. 

I like Sauvignon Blanc.  I'll look for some to take to my upcoming LSU vs Florida tail gate.  Thanks.

If you have a Trader Joe's near you, they have two very good proprietary ones (in bottles) called Picton Bay and Sauvignon Republic, both $7.99. I have found that many of the less expensive ones are every bit as good as the pricier ones. ALL are far superior to anything out of California. The only can version I've seen is Cupcake and that was from Publix.

Wal Mart carries Cupcake and another one called Wiki something, which is very good and only 7.99. 

By the way, where are you located if you don't mind my asking. Are you a Florida fan or LSU? I am in SC so this year I am a Clemson fan (Carolina just can't get it together), especially when they whip up on Alabama. 


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