Enno Peters
This is an older blog post, you will find one on more recent data here
This interactive presentation contains the latest gas (and a little oil) production data from all (8453) horizontal wells in Pennsylvania and Ohio since 2010, through September.
Gas production in 2016 has stayed within a narrow range, near 18 BCF/day, as the output from new wells covered the production decline from existing ones. Pennsylvania production data typically has some upward revisions, so we may eventually see a higher final production for September.
Oil production is not a large component in this basin, and, as you can see when you switch to oil (“product” selection in the top right), it has showed a drop of about 35% in 2016.
The graphs in the “Well quality” tab reveal that, on average, wells in the last couple of years have shown steady improvements.
From the Pennsylvania data it appears that there is also still a relatively large inventory of drilled, but uncompleted wells (see “Well status” tab).
The last tab shows that Chesapeake and Cabot are the largest operators in this basin.
The new ‘Advanced Insights’ presentation is displayed below:
This “Ultimate Return” overview shows the relationship between gas production rates, and cumulative gas production, for all the wells that started production in a specific quarter. This view also makes clear the extent that improvements in well productivity are having on their path towards the ultimate return.
Whereas early 2010 wells are bound to hit a production rate of around 500 MCF/day after reaching a cumulative return of about 3 BCF, recent wells are likely to do so only after a far higher cumulative return (I would put a ballpark estimate at 5-7 BCF).
The next view (“Productivity ranking”) shows that of the main operators, Cabot has an average well productivity well ahead of the others. By clicking on the bar behind “Cabot”, you’ll see that all of its wells are located in the prolific North East of Pennsylvania (Susquehanna county).
For a more detailed description of these new overviews, please visit the first version of this advanced presentation for ND available here.
Coming Wednesday (Dec 14th), I’ve planned another update on North Dakota, followed by a post on all covered US states on Friday.
For this presentation, I used data gathered from the following sources:
- Ohio Department of Natural Resources
- Pennsylvania Department of Environmental Protection
- fracfocus.org
====BRIEF MANUAL====
The above presentation has many interactive features:
- You can click through the blocks on the top to see the slides.
- Each slide has filters that can be set, e.g. to select individual or groups of operators. You can first click “all” to deselect all items. You have to click the “apply” button at the bottom to enforce the changes. After that, click anywhere on the presentation.
- Tooltips are shown by just hovering the mouse over parts of the presentation.
- You can move the map around, and zoom in/out.
- By clicking on the legend you can highlight selected items, and include or exclude categories.
- Note that filters have to be set for each tab separately.
- The operator who currently owns the well is designated by “operator (current)”. The operator who operated a well in a past month is designated by “operator (actual)”. This distinction is useful when the ownership of a well changed over time.
- If you have any questions on how to use the interactivity, or how to analyze specific questions, please don’t hesitate to ask.
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31 Comments
I see the 2014 Utica and Point Pleasant Wells illustrated an exponential decline of 60% per year up to the 26th month when they are making 1,475 MCFPD.
Extrapolated straight, reserves are 900 MMCF. At some point I guess one has to hope it goes hyperbolic, but will they be making enough to matter? Double the 900 MCF and add to the 2.1 BCF and they are 4 MMCF wells.
Does that work at $10 MM per?
That is a lot of gas on those charts. Ive been asking myself those very same questions, Jim. I wish there had the answer.
I’m sorry my 4 MMCF should be 4 BCF.
Jim
4MMCF is actually 4 million CF, not 4BCF
Utica wells in OHIO is generally not that deep and cheaper to drill and complete and has more oil in general.
Jim,
Good questions, I also would like to know if this works economically.
@Nuassembly : Jim is correct (4 BCF = 4 million MCF).
nuassembly
The location of the Utica wells in Ohio play a big role both in the depth and composition of produced output.
Belmont and Monroe counties have extraordinarily productive wells, consist almost 100% methane, and are deeper than 9,000′, on the whole.
This past quarter, Ascent brought online the 4 well Cravat pad which, cumulatively, has produced almost 6 1/2 Bcf.
Over in Susquehanna county, PA, Cabot’s King D 4 flowed 34 Bcfd for September, totalling over one Bcf.
These past several months, a number of 3/5 well pads have come online with average flow for extended periods of over 15 MMcfd.
Remarkable productivity.
Below is a query of Enno’s database – Well Performance filtered for Belmont and Monroe Counties all formations. Will the 87 2014 Wells average 6 BCF EUR? It looks like a challenge to me.
I’m not interested in “coffee shop” production. If Enno’s data is wrong or something like a facility constraint is masking the reservoir deliverability, I’m all ears.
Jim,
I would like to clarify one thing in these charts (in the “Well quality” tab): they do suffer from the “incomplete tail-effect” if you group by year or quarter of first flow. What I mean by that is that not all those 87 wells have gone through all 33 months on production yet. If you click on the any of the last 11 points of that 2014 graph (or any of the other vintages), you’ll see that the tooltip shows that less than 87 wells are included in these last data points in the tail. The reason is that wells that started later than Jan 2014 have less than 33 months on production under their belt. For example, the severe drop you see at the end of the tail, is caused by just 2 wells.
This is why, when using the “year of first flow” display in this view, I recommend ignoring the end of the tails, as they may still wiggle around when more data comes in. If you use “quarter of first flow”, this only happens for the last 2 data points, and you will not have this effect of course when you use “month of first flow”, as then the wells do not have any age difference between them.
Please let me know if this is clear.
So, if you ignore steep drop at the end of that 2014 vintage (which is caused by 2 wells that started in Jan 2014), I don’t think 6 BCF is completely out of range, right?
Exponentional decline I come up with 7313 in month 15 and 3336 in month 27. Gives me 80%= 1/T ln(q/qi).
Then I use 2,300*365/0.80 assume straight line and get about a bcf. Cum is around 4.5.
Make it 6-7 if you want ….
But I think the companies’ are claiming 15 BCF “type curves”.
I know about your tails I am trying to eat only the filet. But if you could figure out a way to massage around them, it would make it clearer for everyone.
Jim
Jim,
Unfortunately, there is no good alternative. You will always have this effect when you group wells by a longer period (e.g. years or quarters) than the periods from which you have production info (months), as then you will always have some age difference between the wells in a particular vintage (group).
I could hide the incomplete tails, but that would remove a lot of useful data: e.g., we would need to wait until we have 2016 Dec data, before all 2016 wells have at least 1 calendar month of production, and therefore the 2016 vintage would show up (with 1 data point, the first month on production). This is what happens in the “Ultimate Return” view, which is why, if you select to group by “year of first flow”, you will not see 2016 show up yet.
If I find a more intuitive solution, I’ll implement it. Until then, I hope the extra explanation, and the tool tips, are sufficient.
I see blue dash below as D=ln(1000/2300)*12/20= -0.50 Exponential Decline.
Between 2,300 and 1,000= (2,300-1000)*365/0.5 = 950 MMCF.
Added to the 4.5 Cum you get 5.5 B making 1,000 MCF per day.
Jim
Im sorry Enno that is month 8 and month 20 datapoints… 7330 and 3336
Mr. Broker
Your interest or disinterest in coffee shop production is certainly your decision, but any sincere student in Ohio’s unconventional production, specifically output from Monroe and Belmont counties, need spend less than 30 minutes accessing the raw, complete data from the Ohio DNR site.
At this point in time, it is an exceptionally minimal amount of data, clearly presented in a single page, Excel format alphabetized by operator.
Mr. Gerard-
Thanks for your response. These data are what Enno Peter’s charts are based upon I believe.
I think Enno and myself share a common goal- to seek the truth about the development costs of these reserves; the ultimate aim is to determine the true marginal cost of oil and gas supply.
A very large and critical industry depends upon the most accurate analyses of that information.
Jim
Mr. Booker
You are correct in stating that Enno uses the DNR numbers for his work.
He must put in a great deal of time and effort, especially when all 60 thousand plus wells from the several basins are incorporated.
Like you, I greatly appreciate Enno’s efforts.
I’ve followed, and still follow, this so called Shale Revolution primarily from an operational perspective.
As you noted, accuracy and completeness are paramount to gaining valid insight into this industry.
Jim, Gerard,
Thank you both for your comments. I greatly welcome views from all angles here on this forum, and hope to foster a civilized debate. This should have the greatest chance to a good understanding of all developments.
I would like to make one comment about my well data. While it is very difficult for me to prove that all production data here is accurate, it should be quite easy for anybody to prove that it is not. As I list individual well production, just finding a single well that shows an incorrect production would already provide evidence of inaccuracy. So far nobody has, even though several readers have combed through the data (as listed here on the site, and from purchases of the data).
Hello Jim and Enno. Nice work Enno, it has been sorely needed.
Jim, I have been curious if these Appalachia wells were as good as folks are touting as it matters, when / if takeaway improves, to my private E&P as it does yours from an A&D valuation and competitive perspectives as we engage in those markets.
Trying to resolve this issue as the data was unavailable till now (did I remember to Thank You Enno?) I engaged a guy I worked decades ago with in the large Public CO who lives here in Dallas. He was one of the principles of “The Unconventionals” guys here in Dallas that were to large extent responsible for some of this. Especially Trevor’s position. They are Geologists and he’s very humble. His response “I don’t know if they are gonna CUM 15 BCF or not” is likely selling himself short but so be it. Now, thanks to Enno, we can do some real engineering work and answer that question.
Anyway, we can now see actual Appalachia unconventional well performance is pretty similar to the other Unconventional Basins in that true “Type Wells” bear little resemblence to the Public COs’ PowerPoint 15 BCF EUR Wells in their ubiquitously touted shareholder presentations.
Jim, I would point out to you that you kept your EconLimit at 1 MMCFGPD on your calc for the Ohio “Type Well” average which yielded 5.5 BCFG. Sorry to pick but surely (I don’t know) those heavily constrained and process-limited NG Takeaway Prices will allow a bit lower EL – not that it makes a lot of difference. But dropping it to 250 MCFD EconLimit, confirms Ohio “Type Wells” are 6 BCFG EURs.
A long ways from 15 BCFG EURs but I know two industry veterans who are not even a tiny bit surprised in the magnitude of the discrepancies.
Mark.
Mark-
Thanks for your comment. I was just trying to project it straight exponentional to 1 MM as an illustration anticipating the argument that it will go hyperbolic at some point… but I am trying to get across the idea the if the rate is low enough, that turn becomes immaterial.
But you’re right the true economic limit is probably 100 MCFPD or something..
This has the making of a great website. Beats IV and seeking alpha all to hell for info.
Jim
Mark,
Great to hear that, and welcome here! You already made a nice entry; looking forward for more insights from you.
Mr. Lloyd
We will all get more clarity on the EURs of these Appalachian Basin wells as time goes by.
However, regarding 15 Bcf cum EURs, there are already 80 Marcellus wells in Pennsylvania that have surpassed the 10 Bcf mark, most online four years or less.
Gerard-
You may have found a problem with Enno’s data. He only has 12 wells over 10 BCF from the Marcellus at 48 months. But there are 95 wells under 1 BCF at 48 months. So if one averages (10*12+95*1)/107 one gets 2 BCF after 48 months.
Guess what the 50 percentile well is? 2 BCF. After 48 months. Man that is awful. How much money was lost?
By the time we get clarity, an industry will be destroyed.
Jim
Mr. Brooker
I apologize ahead of time if my somewhat casual reference of 4 years online was not clear in indicating 4 years of recorded producing days (1,460 days).
I just checked the top 21 producing Marcellus PA wells and punched in a 4 1/2 year (1,642 days) online production metric and 18 of the 21 produced from 11.8 Bcf to 18.4 Bcf cum within that timeframe.
This approach – utilizing actual production days – differs from Enno’s calendar reference method.
Doing this checking, 3 wells may be of special note – the 3 Franclaire wells from Chesapeake, #’s 6H, 8H, and 7H.
Although the wells produced 13.4/13.3/12.6 Bcf cum respectively, the oldest, #6, did it in 4 years while the two most recent did it in 23 months.
Jim,
Yes, I saw your purpose and on that point, great job. My change made very little difference and the magnitude of the discrepancies is an order of magnitude betwinxt the Public CO advertised “Type Well” and Enno’s average well cums by basin, operator, and well vintage. Seems a bunch of somebody’s have been taking great advantage of reporting leniency by regulators for a long time.
And what in the hell is the b factor on that Permian Gold PXD Type Curve you posted? Gotta be 1.6+, no?
Makes me wonder what they are not teaching these university PE Grads these days!
And I agree this site beats teh pants off iV and SA. Thanks Enno. I have not yet figured out how to navigate the comments section tho. I posted my b factor inquiry on on your PXD Gold Curve on teh Permian SEP 2016 page and not sure if they all merge or one must revisit where they last left posts seeking replies???
In any event, my rhetorical inquiry wrt the Arps Eq abuses was one for exposure of said websites and supposed PEs rather than objective discussions as I’m sure you know. But it is kinda funny that our generation was not taught Ethics in university – altho my Professional Liscensing Org requires it AFTER / IF one gets caught abusing what THE ORG unilaterally determines to be violations.
Have I mentioned I’ve yet to see an article in JPT (Journal of Petroleum Technology) the Monthly Periodical for the Society of Petroleum Engineers quantifying, or hell even acknowledging, the magnitudes of discrepancies in Public Corps’ “Type Wells” and what Enno is producing as the average recoveries, by basin and vintage completion year, wells?
We live in interesting times.
Thanks Enno. You have done a very large service to a very lost Industry, the US Upstream E&P Industry. Atleast those taking enuf pride in their work to demand only the best and honesty.
Mark.
Mr. Brooker, I must immediately disqualify myself as an engineer; I am not. I have been an independent producer for over 40 years, however, using my own money, and industry money, and must often “pretend” to be an engineer almost every day or my family, or my employee’s families, don’t eat. I concur with your 5.5 to 6.0 BCF estimates in the App Basin and believe using full cost accounting methods, including leasehold and infrastructure costs, those wells are NOT economic. Rather, those type of wells would not have been economical to drill and complete until just a few months ago when prices started to increase. Nor will they be economical again when, and if, take-away is improved in that region and over 2000 shut in wells are brought on line, and driving the price down again.
6 BCF is not economic, nor is 400K BO of UR in any of America’s shale oil plays at 45 dollar oil prices, of which my guess is fewer than 10% of total shale oil wells in the US drilled to date will ultimately produce that much oil. Further, the marginal price of shale oil and/or shale gas now must include the cost of servicing enormous old, “legacy” debt that will someday also require being paid back.
America has been duped, brainwashed is likely a better term, into a false sense of shale abundance. I am ashamed of that deception. Americans deserve better and its up to our industry to begin to tell the truth about profitability and sustainability. I think the shale industry is incapable of the truth, personally. I appreciate very much your comments here, and hope Mr. Loyd and others will begin to join you.
Merry Christmas, sir.
Mike Shellman
Mr. Shellman (I will call you Mike if you will call me Jim)
Thank you.
I have been doing this for 30 years, twenty years with my own money, as you.
I concur with all that you say. But every deal that hasn’t involved a pipe setting decision (the Clinton/Medina, Berea, Sprayberry, etc) is always the same, isn’t it? Now, oil prices of $90 per barrel and gas at $5 per MCF was a different ballgame, so there is a level of realistic understanding of how we reached this place.
I think we just all want truthfulness in the EUR claims. We have the tools (thanks to Enno Peters) to do it now. Wasn’t it Jean Kirkpatrick who said ” Never underestimate the ability of a small group of informed people to change the world, in fact it is the only thing that ever has.”
Jim
Jim it is, thank you. I enjoyed your comment recently about your minimum requirements for time to payout and ROI; to give you some idea of my (ultra conservative) business model all these years, I require 36 month payouts, maximum, and 3:1 ROI, undiscounted (though as old as I am I think I should START discounting, quickly). That’s getting harder to do, but still doable (just finished one last week); it does mean, however, the only time I visit with my banker is at open houses and funerals.
I agree regarding EUR claims. My belief is that profitability has taken a back seat to reserve “growth” in the shale business model. Profit margins for shale well manufacturing are insufficient for the shale oil industry to stand on its own feet and work from net cash flow and reserve growth only works (considering shale declines) if product prices go up, not down. “Exaggerated UR’s” are therefore a gross distortion of the entire model. For the life of me I cannot understand why money keeps pouring into these shale plays. Maybe that will begin to change ever so slightly after yesterdays FED move.
Mike
Hello Mike. I joined Jim in this debate long ago on some internet MBs. I too am a 30-Yr practicing Petr Engr with first 10 at what was 3rd Largest US Public E&P and last 20 Yrs running my own private E&Ps. I endured lots of personal abuse (as Jim can confirm) for producing real reservoir engineering work based upon actual monthly production and “All In” Costs, forecasted using GAEP like Arps Eqs and real-time as well as forensic NPV Econometric forecasting of those products flows, etal.
In fact, six years ago I began exposing the Haynesville Shale and have continued thru to this day on each of the shale basins. It was just that I had to try and educate shareholders who were certain these Public CO SH Presentations must be accurate.
Nothing and NoOne has put it as simple as Enno has with this site. Jim, I and other practicing Reservoir Engrs knew what they were doing by simply running them out on Arps Eqs and Econometric forecasting. But that involves a skill level that most shareholders do not have and it apparently was beyond my ability to convince / educate them otherwise.
And I share your disgust at the Public COs abuses of the Nations’ trust, currency and credits. And THAT is the ONLY REASON these frauds ever come to be. But unless and until we demand the End of the Federal Reserve and TBTF WS Banks, we can expect to revisit these Fraudulent TBTF WS Public Portfolio PONZI games.
Merry Christmas to you…….
Mark.
Yes, the interest rate rises to we “Ship of Fools” who are debt free are likely more important than oil prices right now.
Jim
Without a doubt Jim. Of course, we’ve heard down here in Texas where the Dallas Fed recently went to Houston to meet with Wells Fargo, Frost, etal to advise them to continue to do “covenant lite” loans, provide waivers from existing covenant violations where possible, and similar.
To be fair, the Dallas Fed initially denied it. Going so far as to even deny taking the trip to Houston.
To be complete, a few weeks later some evidence emerged exposing the Dallas Feds’ denials of hte above trip, etc, forcing the Dallas Fed to Walk Back their prior lies. Not sure if we can beleive anything coming from a member of the Fed or TBTF WS at this point.
And so long as they give C-Suite of TBTF WS Public Portfolio Shale COs Bonuses based upon Increasing Production irrespective of its’ commerciality, retail shareholders can expect more losses and acts contrary to investors’ interests in that space.
The banks end up iwth the assets in BK Courts anyway and now the C-Suite is being given, incredulously, “Pre-Packaged BK Approvals” by these BK Judges which totally runs afoul of hte prior justifications for BK Courts and their protections given to BK Debtors, ie, shield them from civil suits pending liquidations of their assets. Their assets are not being liquidated in these Pre-Pack BKs.
The Two Parties “Most Responsible” for the BK Filings (C-Suite and TBTF WS Bankers) are the ONLY Parties not harmed in the proceedings now with Pre-Packs all the rage and BK Court Judges everywhere approving them! Sabine and Linn Energy are but the tip.
Mark.
Howdy from a chilly S. Texas, Mr. Loyd. Again I wish to say how important it is, really to all of America, that gentlemen like you and Mr. Brooker carry on this fight. Enno’s work is catching on like wildfire now and your comments, and the weight they hold because of your credentials, are very important. I was interviewed by the WSJ some months ago and when I told them about Enno’s work the interviewer actually called me back on it, rather amazed I could substantiate my EUR claims with actual data from Enno’s site. A colleague and I, a geologist from Ft. Worth, and creator of the ELM model for net exports, speculated five years ago that fewer than 30% of shale oil wells drilled in America would so much as reach payout, regardless of price. I think we were structurally high.
I have some favorite “role models” in the shale industry I would want to steer my grandkids from; Petrohawk’s founder, Magnum Hunter’s former CEO has a Facebook page dedicated entirely to his fine work, Ultra Petroleum is a goodun and my all time No. 1 on the hit parade list is the feller who was captain of the USS Sandridge. He jumped ship with 90 million dollars before the passengers could even get to the life boats.
Mike
Thanks Mike. Please call me Mark.
You’ve done some great work in assisting with spreading the word as well it seems. Thank You.
I’ve also read Jeff’s work back several years ago on ELM. Funny how TBTF WS and their Public Portfolio Corps and FedRes contorted Jeff’s work to justify engaging in the largest PONZI Fraud and destruction of capital that man has ever seen!
Find a warm spot friend. We are expecting 32F in Dallas for a high on Sunday!
Mark.