This is an older blog post, you will find one on more recent data here
This interactive presentation contains the latest gas production data from all (7055) horizontal wells in Pennsylvania since 2010, through October. Ohio data through September is included, though by default deselected (use the “basin” selection to include it).
Gas production from these wells dropped for the 2nd month in October, and made a new low in 2016 at just above 13 BCF/day. The shut-in of older wells appears to have caused at least part of this decline.
In the last tab (“Top operators”), we can see that Cabot has taken over the leading producer position from Chesapeake.
The new ‘Advanced Insights’ presentation is displayed below:
This “Ultimate recovery” overview shows the relationship between gas production rates, and cumulative gas production, for all the wells that started production in a specific quarter.
If you cycle through the quarters since the 2nd half of 2014 (by clicking on the quarters in the legend), you’ll notice that average well productivity appears to have stagnated since then.
The next 2 sheets in this presentation are new :
In the “Cumulative production ranking”, you’ll find the ranking of all wells by cumulative gas production. This makes it easy to find the wells that have produced the most (or least) so far. If you change the ranking to “Operator (current)”, you can see the ranking of all operators, based on cumulative production through October. Tooltips are available with more information.
The “Well status map” overview is meant to show geographically the status of all these horizontal wells. You can cycle through time using the slider at the top. For each month you’ll see the status of all selected wells on the map. This makes it easier to locate where wells have been spud, completed, or plugged for example.
For a more detailed description of the other overviews in this presentation, please visit the first version of this advanced presentation for ND available here.
Coming Tuesday (Jan 3rd ), I plan another update on the Niobrara, followed by posts on the Eagle Ford and Permian.
For this presentation, I used data gathered from the following sources:
- Ohio Department of Natural Resources
- Pennsylvania Department of Environmental Protection
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.
actually, I just read this classic paper by Charles Vanorsedale in 1987 who actually analyzed the production decline of many vertical shale gas wells in the Appalachian area and found that the decline is very slow after 5 years. The Arp’s decline curve “b” factor was as high as 2.37.
Of course the initial 1 year decline is also slower than horizontal and fracked wells nowadays (<30% versus over 40%), but we also have to bear in mind that today's horizontal super fracked wells have initial production more than 10 or 50 times the old vertical wells.
So far, Enno's website data on Appalachian shale gas wells seem to indicate that the "b" factor in Arp's decline curve ranges from 1.0 to over 2. This gives shale gas wells an edge over conventional wells because the conventionals usually have "b" under 1 without external flooding or enhanced recovery. Depending on the final values of "b", the shale gas EURs could be 120% to 250% as high as estimate from conventional method/reservoirs.
The work on decline rates in the Appalachian Basin gas wells is often referenced by Terry Engelder’s research.
Short story is that the decline is significantly lower in the AB than many other areas.
Easy to overlook is the brief history of the unconventional development in the AB.
It was late 2004 when the Renz 1, a producing vertical from Range, was fractured similar to Barnett horizontals.
Took another few years for successfully applying that fracturing process to then newly-drilled horizontal wells.
The continuing expansion of the shallower Upper Devonian wells should be very instructive as their recognized “flat” production curves are viewable even today.
There is no reasonable way Enno could differentiate Marcellus production from Utica, Point Pleasant, Burket, Genesee, Rhinestreet, Middlesex, amongst others, with the reporting protocol the PA DEP currently uses. (Thanks again, Enno. The last new additions up above are great. About 150 wells with cums over 9 Bcf).
But EQT’s intention of drilling 81 UD wells in 2017 (along with 119 Marcellus) should provide data on what these formations may offer in years to come.
I read Prof. Engelder’s PPT when I first dipped into shale gas as an outsider 4 years ago.
I knew nothing about shale gas and Engelder’s exciting PPTs caught my attention and convinced me the potential in shale, even though at that time it did not have a lot of data to support the long lifetime of the new horizontal shale wells.
Actually I just revisited his PPT, and there I saw his citation on Vanorsedale’s 1985 SPE work again, and Engelder’s reservoir model really sounds reasonable and more logically correct to me now. But I also feel there needs to have some modifications too, because Engelder’s PPT is only counting on open versus closed system to exlain shale gas production and attribute the steady decline to a closed system or in fact interferences between offset wells. I am more buying into the theory that the sub micron pores and nanometer channels of the shale rocks are releasing gases in a different way than conventional sandstone reservoirs. Stanford researcher has a different model for this.
for shale oil, it takes another model or theory to explain the slow decline in Bakken and fast drain in EF.
Wish you and everyone happy new year!!!
so for shale gas EUR the story/history goes like this:
in the 40’s, some 162 vertical shale gas wells were drilled in the upper Devonian shale and the results surprised everyone a little after 40 years, because although they started with small IP, they declined only 30% first year and quickly after 2nd year the decline rate dropped below single digit and could last 40 years and still have commercial values. Charles Vaorsedale used Arp curve to fit the production curve and get a “b=2.367” —quite different than conventional oil and gas without secondary recovery efforts, where the “b<1" usually. This gives shale wells a long lifetime attribute and with an EUR much higher than their initial small start.
in 2005-07, when Range Resources copied Barnnett success to Marcellus and got IP over 1MMCFD, they predict the EUR will be over 10BCF (or over 15~20 times the first year's IP) using the b=2.367 and first year decline rate of only 30%. Prof. Engelder quickly asserted that Marcellus alone will be able to supply 50TCF producible gas, enough to supply the whole country for over 20 years! CHK and others followed and Wallstreet joined in to collect money from investors using this ultra EUR and almighty shale discovery.They also copied the same b=2.367 for shale oil when oil price went to $150.
After 3 more years, people find the first year decline is actually over 50% for these horizontal mega fracked wells, and second year still declined as much as 40%, and 3rd year decline still in the 20s%. The peakers and the anti-fracking started to amplify this fast decline and totally let the public forget that shale has this b=2.367 long lifetime and high EUR, and CHK and RRC are simply cheating investors and themselves.
Now, after 9 years, results are in and the b value again go back to above 1 and quite nicely above 1.5 for all the wells in Marcellus. This means that the most realistic EUR is somewhere in between 8~12 times the 1st year IP.
Very interesting, thank you. Your following comment made me curious
“Now, after 9 years, results are in and the b value again go back to above 1 and quite nicely above 1.5 for all the wells in Marcellus.”
Could you expand on this, e.g. show how you’ve determined this?
The reason I ask this is that we can see that quite many of the curves on the semi-log plot of the “Ultimate Recovery” overview appear quite straight. This holds for both oil & gas production, and for several different basins. A straight line on this plot indicates a harmonic function, or b = 1. For the Marcellus, I imagine that it could turn out to be slightly above, or slightly below 1, as more data comes in, but above b=1.5 appears rather optimistic to me from the current data?
Also note that refracked wells are not filtered out, and the effect of this causes at least somewhat the appearance of a lower decline (and a higher b value), than we would have seen from natural decline.
Thank you both for your interesting comments.
@Gerard: I’m glad you like the changes. I’m also rather fond of them, for example that it is now so easy to compare cumulative gas or oil production in several ways (e.g. between wells, operators, counties, formations), by just changing the ranking dimension in the new “Cumulative production ranking” view. And indeed as you say, although the Pennsylvania production data is probably the most easy to deal with from all the states, unfortunately no detailed formation data is provided for each well.
@Everybody : A happy and prosperous 2017! I’m sure this year will bring us many more interesting lessons, and I hope this site will play a small role in that.
I am not an engineer nor a geoscientist so I would appreciate if you would explain the b-factor for me. Over the past 8 years, I have seen many type curves used by many of the unconventional pubcos during their quarterly conference call but what I have notices is that b-factors always seem to be between 1.5 and 1.75 on these type curves and the cumulative production always seems to grow with a higher b-factor. I haven’t looked at any of these for some time so I apologize if this is a miss statement.
Also can you direct me to any conventional producing oil/gas fields with a b-factor of 2 for comparison to a non conventional oil/gas field with a b-factor of 2?
I have in the past invested in oil/gas prospects and cumulative production in analog fields is an important metric for me. The geologists that I know tell me that, as a rule of thumb, if a formation is not commercial in a vertical/conventional field that it is very unlikely to be commercial in an unconventional horizontal field so it would be very helpful comparison.
And finally Happy New Year to one and all!
Enno, I hope you have great success this year!
I recommend the following article to see this b-value in the right context:
In my opinion, it’s not important to follow the exact mathematics, but it is helpful to understand roughly how this b-value impacts the overall decline curve; As the article explains, the different b-values don’t make much of a difference in the short-term, but do make a huge difference over the long haul. This makes it so important for correct accounting, well economics, and reserves booking.
I’m also curious to answers for your other questions, and hope someone can answer those.
Happy new year, everyone!
I agree with Enno that my estimate is not that accurate and might raised the “b” by 0.2 to 0.5 for now.
But the standard depends on many things
1. I am using 2nd year production as the base IP and this reduced the EUR by a factor of 2 — which I also said that the EUR modified has to be ~50% of the initial guess by RRC and Engelder.
2. If you drop out the possible refracks effects. If you seriously discount the effects of refracks, it seems to me “b” could be over.
From Enno’s data/functions, I do see similar shale gas production curve with obvious “b>1” from other basins/plays including EF, Permian and Bakken; while oil production curve is definitely well below 1 for EF especially and also below 1 for Permian It might be around 1 for Bakken oil.
here are some plots/pics for illustrative purposes
the above picture/PPTs and this one here are from Engelder’s PPTs.
Thanks for this Nuassembly,
Regarding the graph you show here: as you can see the number of wells included greatly differs over time (162 wells in the beginning, <71 wells near the end).
The main reason that I often show the performance of wells, grouped by the year, quarter, or month, in which they started flowing, is to avoid including wells from very different vintages in the same group. The reason is that if there are differences in decline profiles of between vintages, grouping them all together in this way could lead to very wrong conclusions.
For example, we can quite clearly see that in the Bakken, the early wells in Montana and North Dakota, peaked lower, but produced higher for longer, compared with the average from later vintages. This means that decline curves can, and do sometimes, greatly vary over time. If you would group these wells, with later vintages, and show a single decline curve, you would incorrectly conclude that all those wells will keep a higher performance later in life.
Sorry, I looked again on the basins and seems that EF gas is also below 1.
But Bakken and Permian should be over 1.
Sorry, I didn’t understand your following remarks:
“and might raised the “b” by 0.2 to 0.5 for now.”
” If you seriously discount the effects of refracks, it seems to me “b” could be over.”
Regarding your last statement:
“But Bakken and Permian should be over 1.”
Although I think we can quite clearly see that the decline rate is lower for oil production in the Bakken, and recently also in the Permian, I must say I don’t find it obvious that the b-value is greater than 1 in these two basins. Also here, I take the “Ultimate recovery” overview, displayed with a semi-log scale, as my guidance: The curves appear rather straight, and even show some indication of sloping downwards (which is equal to a b-value < 1). Therefore, can you show me why you think differently about this?
There seems to be atleast some confusion as to semantics. Let’s first correct that. By definition, Exponential declines are b=0. Hyperbolic declines are 0 [less than] b [less than] 1.
The EF, Haynesville, Barnett, Permian and Bakken are ALL Hyberolic decline curves given one looks at the data by well or by vintage atleast. As Enno rightly points out, the prior graphs not separating production accordingly will give the errant results; intended, I suspect.
Insofaras the 1985 Vanorsdale SPE Paper showing a selection of Appalachia shales experiencing b factors in the harmonic range, i can show atleast that many conventional Pettet wells in teh ET Basin doing the same. The problem though is they are at rates far below commerical rates, ie, less than 1 BOPD.
I suspect Appalachia, like all the other basins, will see with these unconventional developments, early exponential declines right into very low (sub Commercial) tails as it is only “front-loading” the recoveries for large multiples greater @ t=0 costs. Why would one want to do that anytime, especially during ZIRP times?
I will withhold any more of my opinions on Appalachia for now as it is the only region I have not viewed enough of the unconventional completions to feel very confident b factors will be less than 1.0; although, I am highly suspicious of suggestions it is an anomaly compared with ALL the other regions which leave little to no doubt b factors will be less than 1.0 given the above criteria.
The Permian appears to be the best area to some observers based upon it’s early production histories and rapidly increases lateral lengths and numbers of stages. The question has always been what is the return for not only unconventional well economics but also betwinxt longer laterals and higher frac densities.
I like folks who put their money where their mouth is so I am willing to bet anyone a cold beer the Permian average well, per lateral, EURs are in the end, little different than similar Bakken wells. Why? Because I believe the Bakken wells are going to get some modicum of “tail” above commercial rates due to it having better matrix contributions. Whereas the true nano-darcy shales are gonna go straight line exponential into non-commercial territory and game over.
Enno’s work seems to me to be concluding the Permian will be little different than the other basins in terms of ultimate EURs – maybe even a little less than Bakken given the above. While they are drilling much longer laterals and much higher frac densities, resulting in some instances higher EURs, EURs greater than 300 kBO are fleeting for ALL PERMIAN WELLS (certainly in the main); even the newer longer lateral / higher frac density don’t seem to be able to overcome this high water mark. The recent wells certainly come in higher IPs but the EURs do not seem to be increasing making the eCONomics even worse. Enno’s distribution work shows very poor distribution of Unconventional well EURs outside the main, ie, in the basins he covers, Pareto’s Principle is optimistic when compared to the actual well results.
Thank you for the clarification.
Indeed it appears that wordpress blogs, like this one, have an issue with the “unequal to” signs.
If you wish to update a past comment, you can send me an email, and I’ll update it.
Regarding your last comment:
“harmonic are b (greater than sign) 1.0.”
I belief this should be equal to 1.0, correct?
See below, from:
sorry for my typos and grammar errors
I meant to say that instead of 0.8 to 1.1 as you prescribed, I stated “>1 and over 1.5”, that’s 0.2~0.5 over what you said. But, this could be caused by the standard we used, or blame the quality of the data being unable to filter out refracks etc. I already included the refrack effect which obviously it suddenly reverse some wells decline and “b will be overflowing”.
NO, they will NOT. Atleast within the realm of reason and economic activity.
I agree with Enno that Vanosedale dropped some wells probably due to the production was below commercial threshold? This will seriously affect the final EUR of the whole basin — much lower than what Prof. Engelder predicted, and I also overlooked here. But, with much higher IP and even the 3rd year IP still much higher than previous vertical shale gas well. AB wells should last a much longer time with 10MCFPD above commercial cut off line, the 7 year old wells on average have over 500MCFPD right now, and with “b=0.8”, it will be over 100 years when it dropped to 10MCFPD; and over 150 years for “b=1”. If you use 100MCFPD as the cut off, it will be over 30 years for “b=0.8” and over 100 years for “b=1” — I believe nuclear fusion will be displacing natural gas before 2117, and cut them out earlier?
I’ve posted this am some “By Well” DCAs and eCONs for what I believe are “typical Barnett” unconventional wells. I’ve done similar analyses on internet MB Blogs for about 8 years now.
I also noted this morning the Tallgrass / REX Line Capacity increase is now open for firm cap bids. That will allow another 1/3 increase of AB gas into the south. For this reason, and that I am a practicing PE in the South with my own private companies’ interests at heart from a competitive perspective, could one of you deadbeat and similarly starving northern engineers do a little work as I’ve done and produce what you beleive will be representative of the “Typical” AB DCA and eCON please?
If you are not willing to put your actual name on your analysis, I would kindly ask you not go to the trouble. I’ve seen plenty of UFSA TBTF WS Public Portfolio PONZI Fraud Shalers’ “PwrPt Type Wells” to last me a lifetime.
The REX Zone 3 line will now transport 2.6 BCFD (up from 1.8 BCFD I believe) from AB to Southern States’ headers and now requires me to evaluate my investments, future prospecting for A&D and Drilling Prospects Generation, which requires high-grading of basins, etal. THAT is what I am seeking to do with other reputable PEs here.
Thank You in advance……..
I think there is a mistake in the vertical axis of the total production per day.
It should be “MMCF/D” NOT “MCF/D”.
The math is quite surprising to me because there are about 6.5k wells producing, and with 13BCF/d, that’s almost 2MMcf/d for each well.
It seems to me that in the past year with about 500 wells putting into production, AB is able to hold production relatively steady. We could calculate what’s the expected reserve that could sustain 13BCF/d production.
I realized that your other unit in vertical axis 14M means “14 million” which then make the numbers correct. But, that’s unconventional in oil and gas where “M” means “K” — see, people in oil industry had been using this trick to collect investor money from the first day of the industry. This is much worse than price tag of $999.98
Indeed, there is no mistake with the units, but they are a little confusing: The software I am using uses “K” for thousand, and “M” for million. Therefore, when you see 13M (Mcf/d), that actually means 13 BCF/d, not 13 MMCF/d.
I hope eventually everybody will be using SI units (“k” for thousand, “M” for million”), but that may take a couple of millennia.
“because there are about 6.5k wells producing, and with 13BCF/d, that’s almost 2MMcf/d for each well. ”
That is correct; that is roughly the current average well production rate. It is not that strange, if we use a value conversion factor of 20 Mcf, for 1 bo, that would mean an average rate of 100 bo/d, which is what the Bakken did some time ago.
Why would you use 20,000 cubic feet of gas to equal 1 barrel of oil (if I’m interperating your comment correctly), when a 6 to 1 ratio is commonly used?
I am counting the wells in Pennsylvania – using the more precise 5.8/1 ratio – to see how many “million barrel of oil equivalent” wells there are. That is, how many have already produced 5,800,000,000 cubic feet.
Number appears to be in the 500 to 600 well range.
With 7,500 +/- producers, that is a high figure for “million boe” wells.
Gerard is stating the simple truth — AB is the closest in all shale plays in terms of getting to MMBOE EUR with average well flowing at 300BOE/d with 99% gas.
Bakken the 2nd, with foreseeable future EUR in the 500MBOE range, and average well is producing 100BOE/d like Enno said.
Permian is actually the 3rd, with foreseeable future EUR in the 300-400MBOE range, and average well is producing 100BO/d and an astonishing 2MMCF/d of gas — I just checked the rough numbers, and it looks best to topple the current EUR limit.
EF is 4th with foreseeable future EUR in the 200MBOE limit on average, and average wells are producing 60BO/d and 300MCF/d of gas.
Enno, you and I have always both agreed on the BOE scam that prevails throughout the shale industry and I appreciate very much that you have used 20:1 in your comment above. Given current WH prices, that’s about right. For all purposes related to economics and discussion of sustainability, gas should be converted to oil on a price basis only. In the AB, a shale gas basin, BOE should not be used at all. It is intentionally misleading.
Furthermore, in shale oil basins, BOE IP90 should NOT be used to book reserves; the E in BOE should be established at the time the well ceases to be flared and is actually tied into market. If that takes 6 months, as it often can, it changes the EUR picture significantly. In the Bakken, where it took 4-5 years to get associated gas to market, BOE should never have been used at all. BTU’s are worthless if they are going up a flare stack.
BOE is a whopper of a lie used very conveniently by the shale industry to mislead the public about its profitability.
“Why would you use 20,000 cubic feet of gas to equal 1 barrel of oil (if I’m interpreting your comment correctly), when a 6 to 1 ratio is commonly used?”
I’m happy you ask this question. I think it’s an important topic, so I’ll try my best to lay out my view.
Just to be sure, I did not equate 20 cubic feet of gas to 1 barrel of oil, but 20 thousand cubic feet of gas to 1 barrel of oil. I did so based on their rough market price ratio.
My reasoning for this is as follows:
1. These products are produced by companies, not to burn them for their heat content, but to sell them in the market. Therefore, from an economic point of view, what is important is the market price ratio between these products.
2. The market prices of both oil and gas have heavily fluctuated in the past several years. The annual price ratio between 1 barrel of oil, and thousand cubic feet of gas, has fluctuated between 17.2 and 34.2, from 2010 till 2016 (see image attached). Although this value has dropped, this ratio in the futures market (Dec 2017), is still 16.5, and the overall average over these years is 22 (!).
3. So, this clearly shows that the market price ratio of these products in current times is not close to 6, but much closer to 20.
4. This is also why, from an economical point of view, it does not make any sense to me to lump these products together based on their heat content. I sometimes use the analogy of gold companies: suppose that gold companies lump together their gold and copper (which is often co-produced with gold), based on weight, and only provide this weight information to investors, what would you think the reaction will be? How useful is that information?
5. If production is only given in BOE terms, without knowing the oil content, using the ratio 6:1, we can’t attach an economic value to this, as the market price of 1 BOE of oil is about 3 times the price of 1 BOE of gas.
6. Furthermore, as you can see in the graphs on this site, the decline profiles of gas & oil are very different: in general oil production declines steeper than gas. Without understanding these factors, from just a BOE decline profile (which you encounter often), it is easy to get the wrong idea about current and future economic value generation.
7. As Mike has also stated, sometimes part of the gas production is flared, while still counted to the production & EUR numbers.
So far, you’ve given two arguments to support a 6:1 conversion:
1. Others are doing it. (you say: “is commonly used”)
2. There may be future developments that will make the value of these products converge to this ratio.
Your first argument is a logical fallacy, an
“argumentum ad populum”. Just because your stated conversion rate is common does not make it right (or wrong).
You may be well turn out right with your second argument. However, in the past couple of years, and also for the coming year (see the futures market), the market doesn’t agree with you. Therefore, producers still can’t sell their gas for the value that you attach to it. If this has changed on a consistent basis, I’ll be happy to update the conversion rate when I do so (I typically don’t try to convert these products, but if I did, I would do so based on the prevalent market ratio).
Given all these factors, I agree with Mike that BOE seems extremely misleading, and useless. This is why I will never combine oil & gas in my analyses (based on heat content), and I expect neither will others.
I like to be very open-minded, so I really hope you come back to this to support your position better, and why you think it is not distortive & misleading. I also hope that you lay out to me where you think my reasoning is incorrect.
I do not hold that their is a correct/incorrect, right/wrong stance regarding ‘boe’, ‘bo’, ‘Mcf’ when discussing hydrocarbon matters as long as both clarity and understanding are present.
Somewhat akin to the discussion awhile back on other sites whether to frame production via actual producing days versus calendar days/months, there can be a large misperception if one is unaware of the distinction, while the underlying numbers (output and time) are undeniably accurate.
If a well in northeast McKenzie county comes online today, 12 months from now it will have produced a set, known amount of product.
If this well is presented as a one year old well, while others categorize it as, say, 10 months’ production due to 60 days offline, both scenarios can claim accuracy.
In somewhat the same vein, when I mentioned 600 PA Marcellus wells produced the energy equivalent of 1,000,000 barrels of oil (a few are from the tiny number of drilled Deep Utica. Story for another time), that fact is both irrefutable and illustrative.
There has never been, anywhere, as far as I know, an unconventional oil well that has passed the 1,000,000 barrel mark in production.
To see such a huge amount of hydrocarbon energy produced in gaseous form from PA is, I think, highly noteworthy.
Addressing the misleading descriptions from the operators … this has gone to a new level with customary descriptions now including percentage breakdowns of gas, oil, and NGLs while leaving a studious observer to determine the actual oil content.
Ditto the frequent inclusion of ‘liquids’ in the ‘boe’ claim while not clearly stating that ‘liquids’ can also be inflating the overall boe claim significantly versus a pure oil content.
These machinations are longstanding and are greatly exacerbated by the recent product mix coming from OK and TX.
Now, when Mr. Lloyd mentions the value difference, the arbitrage pricing of oil versus gas, he is alluding to what I feel is a coming paradigm shift in this area … namely the increasing displacement of gasoline/diesel by natgas in the transportation sector.
Not if, but when, natgas can be more effectively handled than today, the energy content in 6,000 cubic feet of natgas – costing 18 bucks will compete with the energy equivalence of 1 barrel of oil costing 50 bucks.
That time may not be as far off as one might think.
“I do not hold that their is a correct/incorrect, right/wrong stance regarding ‘boe’, ‘bo’, ‘Mcf’ when discussing hydrocarbon matters as long as both clarity and understanding are present.”
I disagree: Although any metric may have its uses in certain cases, it is definitely possible to argue the pros and cons of metrics in specific contexts, and for specific purposes. Which metric leads to the best understanding of the question involved? What is it that we actually want to measure?
So in the context of total energy production, or potential changes in the market that would more utilize the BTU content of natural gas, such as substitutions in the transportation sector, the “BOE” metric may have its uses, as it reflects total (potential) energy production.
However, in the, in my opinion more typical context, of business/economic evaluation, the BOE metric has only disadvantages, as I’ve stated. Without knowing more, a well that is expected to produce 800k BOE could be either great or bad.
I consider it the responsibility of the analyst to figure out what are the right metrics to use in a specific situation. The blind use of the “BOE” metric reflects in my mind bad on analysts & companies. The intent appears not to be to inform readers about economic prospects.
“Somewhat akin to the discussion awhile back on other sites whether to frame production via actual producing days versus calendar days/months, there can be a large misperception if one is unaware of the distinction, while the underlying numbers (output and time) are undeniably accurate.”
Also in this case, the question is not which of the possible metrics is accurate, but which one helps understanding the question involved best.
I struggle to see in which cases it may be more useful to talk about the actual days produced, versus the calendar days. I can see a case where the discussion about operating costs for every actual day that a well is operated. But down-time is a common component in this business, even the shut-in of nearby wells. Operators in general are already motivated to keep these shut-ins as few as possible, as makes economic sense. Therefore, in a discussion about economic performance, this kind of down time should not just be excluded. There are many parallels to other businesses. Do you see Wallmart reporting sales per actual opening hours? In most situations, it’s not a helpful metric. Furthermore, it is not the case that nothing is happening underground when a well is shut-in.
I challenge you to explain in which case this “days actually producing” metric (or the “BOE” metric) is a more helpful metric to use, outside the contexts I’ve described. I note that you did not counter my arguments, or provided more supporting arguments for the BOE usage.
As Albert Einstein already described, that a metric is accurate does not mean it is helpful/meaningful:
“Not everything that can be counted counts, and not everything that counts can be counted.”
It depends on the context & purpose, and this can (and should!) be motivated.
why not using the 1 year average WH price for AB when converting to BOE then, let’s use 40:1 or 50:1?
The same apply to any oil/gas, not just shale. They all cheated from day 1 before Standard oil started.
Do you think OPEC also give false numbers? ARAMCO might over blow their reserve to get the higher IPO price.
I have been in the oil and gas business for 50 years and it was only a decade or so ago, and the onslaught of unconventional resource plays, that BOE began being used extensively. I am quite certain that Mr. Rockefeller never heard of BOE.
Rarely do I see ME reserves reported in BOE, https://en.wikipedia.org/wiki/Oil_reserves_in_Saudi_Arabia
I can’t control what OPEC does or does not do but I can call out the US LTO industry for the stuff it tries to pull, whenever I can, including exaggerated EUR’s and how BOE at 6:1 exaggerates the exaggeration.
A gas well that makes 1% liquids is a gas well, as in MCF, not an oil well, as in BOE. That’s my story and I am stickin’ to it.
Mr. Mike Shellman
The operators have been very lavish in lumping in the gas component to oil projections.
Continental and Marathon are touting potential 3 million boe from their Oklahoma holdings.
Misleading approaching deception, perhaps, caveat emptor.
But there is s flip side to the dollars versus energy potential that may pose a bigger challenge to those involved in oil production … namely that natgas is producing equivalent energy to $20/bbl oil.
That, far more than the hugely disruptive events wrought by unconventional development this past decade, will impact the oil producers as CNG, via adsorption technology, makes inroads in the transportation sector.
The numbers I cited above – 600 or so wells – that have produced the energy equivalent of wells with one million barrels of oil output, done in a very few yesrs’ time, with multi decades ahead of more … that is a huge disruption coming down the pike.
Just did a quick, rough tabulation using Enno’s work and other sources, and came up with about 620 wells with production over 5.8 Bcf each.
Susquehannah and Bradford counties (Cabot and Chesapeake country) had about 440, Wyoming county 67, Greene 55, Lycoming – Sullivan – Washingto had 25, 17 and 17, respectively.
Greene and Washington (Range territory) counties can be somewhat deceptive as their liquid content is very high.
In addition, these two counties are the locales of some of the successful Deep Utica wells.
The Scott’s Run from EQT (Deep Utica) has produced over 11 Bcf in about 15 months online.
Stick to “Value Equivalents” Enno. You are exactly correct in that assessment as are you Mike Shellman.
If the arbitrage betwinxt achieving 1 MMBOE Type Wells was so easy as simply reporting it as UFSA TBTF WS Public Portfolio PONZI Fraud Shalers do on a 6:1 equivalency, we would see far more NG Use in the transport sector.
The very fact NG has still not captured major market share in US Transport to great extent tells one all (s)he needs to know about the BOE Frauds. “Value” is what drives everything on real markets.
And before someone let’s go a wise crack, teh US Public Mkts have not been representative of “value” nor anything but manipulated prices and suspended GAAP frauds for a long long time. THAT is why BOEs were even necessary, ie, to attempt to fool some folks.
If one can’t go sell it as crude oil; it ain’t crude oil. Check the spreads for NGLs, Ethane, Propane, etal. THAT makes AB closer to 40 MCF : 1 BO; most times of the year.
You are apt to rue these times when you choose to not take in both the incremental movement towards natgas fueled transport in the US coincident with the furious charge to commercialize the recent, competing breakthroughs in Adsorbed Natural Gas.
The activated carbon boys are, right now, able to provide formable tanks in the 17 Gallon of Gas Equivalent range.
The fuzzy heads over in Bezerkley have tweaked the Metal-Organic Framework gizmos so sub 500 psi storage and handling are technically doable.
With these breakthroughs, Mr./Mrs. Jones will in the not-so-distant future, be topping up their CNG vehicle right at their natgas supplied residence.
The economics favoring this are overwhelming.
unfortunately, this Berkerley Metal Organic Framework (MOF), along with other busted nano graphene or tubes, for adsorbed CNG are much worse than the PONZI Fraud Shalers.
Adsorbed low pressure CNG is not new — people tried it and developed full theory behind it and the correct theory for adsorption is that for Methane and Hydrogen, the adsorption medium has to be cooled down to -60C and -80C in order to have the desired performance, or multiple layer adsorption. So, it is not yet practical in the foreseeable future to see adsorbed CNG replacing CNG yet.
There is also an analogy misconception about adsorption playing a huge role in the shale gas reservoir model — or what gives the long lifetime of shale gas wells. Still many people believe that there is MOF like stuff in shale that could adsorb so much CNG gas there — if it is true then we should really just get shale kerogens out and use it in our cars. The ironic and lucky truth is that the remaining shale gas that gives the long lifetime for shale wells is still simple CNG, not adsorbed version. THis simple CNG storage maintains the pressure for the remaining shale gas production for a long lifetime. If only 500psi adsorbed CNG storage, then they could not get out of the nano pores and the shale wells won’t even have the initial high pressure of 1,000s of psi and high IP.
600 well/7,500 wells = 8% of well that have cumulatively produced 1 mm BOE. That 22:1 market price ratio looks pretty important to me.
Will these 600 wells pay off the debt incurred by the shale producers? 401k, pension funds, retirement funds may rue the day long before some “transformative” technology steps in to deliver utopia to the masses.
I personally have dealt with orphan abandoned wells, wells sites, unpaid royalty and the inevitable fist fight/ brawls that occur when a soon to be bankrupt or financially stressed operator refuses to live up to its obligations.
Somehow, I anticipate the shale apologists (seeking alpha) will have nothing to say to the PA surface owners when those bills come due, are never paid, and left to the taxpayers to handle.
A few facts and my personal opinions in response:
1. “There has never been, anywhere, as far as I know, an unconventional oil well that has passed the 1,000,000 barrel mark in production.”
Fact: I can point you to several “Conventional” 1+ MMBO EUR individual wellbores but ZERO Unconventional in the US. Obviously, the ME, N. Africa, etal have far better current oil recoveries due to relative infancy of their E&P Industries.;
2. “You are apt to rue these times when you choose to not take in both the incremental movement towards natgas fueled transport in the US coincident with the furious charge to commercialize the recent, competing breakthroughs in Adsorbed Natural Gas.
The activated carbon boys are, right now, able to provide formable tanks in the 17 Gallon of Gas Equivalent range.”
Fact: I was using a 500 gal propane tank in teh back of my farm truck as a young farm kid working to fund my university PetrEngr Degree back in 1978. I bought propane – with farm discount – at $0.40/gal then. I had a naturally-aspirated carbueretor on that old 1970 4×4 Truck with an underkickpanel switch that allowed me to switch back and forth betwinxt octane liquid gasolines and propane. I also spit on an electric cattle fence once. I am far wiser today.
I may live to see the day when adsorption technology makes a dent into large scale commercial transport vehicles. But that day is not apparent at the moment. I believe adsorption will experience what Moore’s Law did in semiconductors in taht there exists limits bound by our ambient natural conditions; especially wrt temperatures. Heck, the phase equalibrium of NGLs themselves can be utilized if one wants to build the equivalent of a perishable foods cooling van to keep your C2+ in liquid states.
There are a few small high-pressure CNG tankage vehicles but I would not recommend for many reasons. When / If Low Pressure adsorption delivers, I will change my opinion on hte Mid-term prospects for 6 MCF : 1 BO valuations to accomodate what could only then “begin to arbitrage” what is now just more shameful and fraudulent accounting practices by UFSA TBTF WS Public PORTFOLIO PONZI Fraud Shalers with USG and SEC complicity.
it is not easy to exclude 1 or 2 exceptional unconventional well that might hit 1MM BOE with close to 80% oil.
I just found that EF has a Devon Oliver D 1H well that output close to 800M of oil and 2BCF of gas.
I forgot to mention that I found the Oliver D 1H from this website — all because of Enno.
I also wish to highlight the recent super well (ANGUS TRUST) reported by CLR in STACK, it has 4MBOE IP with 42% oil cut, and according to the offset BODEN well, it might be able to easily pump out 600MBOE in a year, and let me guess — another 250MBOE in the 2nd and another 150MBOE the 3rd, it will become a 1MMBOE with over 35% oil cut well with good chance.
“I just found that EF has a Devon Oliver D 1H well that output close to 800M of oil and 2BCF of gas.”
I caution against looking at individual well results in Texas, as these production histories are estimated. It may be completely accurate in cases where the lease contained 1 well, and in the Eagle Ford many leases luckily do so, but it may not be in other cases.
North Dakota has several wells that have produced more than 1 million bo, and one that produced more than 1.5 million bo. These are impressive numbers. Still, there have been many unproductive wells as well, and therefore I typically find the average, or the trend, much more interesting. I don’t really understand this focus on the positive outliers.
“it might be able to easily pump out 600MBOE in a year, and let me guess — another 250MBOE in the 2nd and another 150MBOE the 3rd, it will become a 1MMBOE with over 35% oil cut well with good chance.”
How do you know? How does oil production decline in comparison with gas production in these wells?
I remember there is a website about Bakken production and there are several wells really have over 7MBO/D IP. They should/might easily put out 1MBO in 3-4 years.
“How do you know? How does oil production decline in comparison with gas production in these wells?”
=== that’s why I said “might” for the CLR STACK well as well.
It is based on several past facts:
1. NFX wells there have relatively slow decline similar to Bakken
2. Geology there is similar in terms of lithology — mostly lime and siltstone, not like EF more shale
3. Exit rate and pressure of the well
Thanks for the clarification Nuassembly.
I hope that I’ll get my hands one time on a big set of production data for the STACK/SCOOP, as it would probably allow a better picture than what we can learn from a couple of publicly announced well results.
I am personally aware of several Eagle Ford wells drilled by GeoSouthern (Devon) wells in DeWitt County having produced over 1M BO. So what? I stand by a recent comment I made on Oilpro suggesting 18,500 shale oil wells in the Eagle Ford play cost close to 146 billion dollars to drill and complete. Using TRRC data the EF play has now produced 2.02G BO since 2008. At something in the order of 48 dollars per barrel net back oil prices to the working interest for the same 8 year period, the EF has generated only 98 billion dollars of net revenue to that WI. The play is therefore only 65% to payout. Add midstream expenditures to all that and man, its money losing dog. Now Enno says 2/3rds to those wells now produce <50 BOPD.
Same in the Marcellus/Utica play, 600 wells are going to make 15BCF. So what? The Bakken has the same so what scenarios and I assure when the lights are finally turned off in the Permian, it too will be the same. Unconventional shale oil is woefully unprofitable to produce at prices less than 85 dollars a barrel of oil. A few good wells here and there do not make a resource play and they definitely do not make a company.
Often when I read shale oil and shale gas analyses I feel like I am sitting on a beach in Mexico and one 'vendor' after another comes by wanting to sell me trinkets. If they don't have anything you want on the supply side, they'll try and sell you something on the demand side. If one is day trading unconventional shale oil and shale gas stocks, that dribble belongs on Seeking Alpha and that Fool thing, whatever that is. Here, using Enno Peter's data, I am interested in the role unconventional shale will have on short term product prices, and in the long run, on America's energy future. After 15 years of shale gas, and 8 years of shale oil, I am not too impressed with any of it.
Thank you, Enno. Sorry about stirring everybody's oatmeal up about the BOE trinket.
Could we see that conventional oil and gas here in the US could be profitable at $40? what’s the percentage of conventional wells could make over 1MMBOE right now?
I am trying to clear one myth of shale gas wells (oil is different) here, i.e. they are not all as short lived as the maninstream media put them. After 2-3 years, the decline rate actually match or even beat conventional wells.
The trouble with EF is that if oil price stays at below $60 for the next 4 years, the EUR will not make it profitable at all due to the nature of the fast decline there and there is no more undecided after 4 years for the existing wells. For Bakken, it might be different because the slow decline will be able to make it profitable in 20 years, especially if oil price go back to $80 and above.
Same for Marcellus, if gas price could go back to $5 or $6 ($3 or $4 for local price), I think the percentage of wells that could payback will be increasing significantly there. Even now investors are losing money, they could at least get some comfort seeing the low gas prices help the clean electricity generation, help create jobs in other sectors and make American energy independence/balance a closer reality. If they are in Marcellus and Bakken, they could don’t lose hope on the long lifetime of the wells that might turn into a profit in the future.
Nu, I think its very important to recognize that you and I likely come from different ends of the perspective with regards to shale sustainability; oil or gas. I wish to stay out of the Marcellus/Utica gas business because I don’t know as much about it as I should, or care to, and I am skeptical about decline curve modeling in unconventional shale, or shaley carbonates. We, the oil and gas business, has not been down this shale road very long and I think clay and silt content in this lousy rock, proppant embedment and fracture closure could all whack those long EUR tails in half, even in gas wells. People with no experience in the oil business like to use models. Trust me, it never works out like you want, or expect. I appreciate, however, that you recognize gas and oil are two different things with regard to flow conductivity to a wellbore.
I don’t deal in what ifs. I have never drilled a well in my long career hoping it would work economically, only if prices would increase. Far too many shale enthusiasts hang their beanies on the hope for higher prices. The shale “growth” model, at the expense of profitability, is now a disaster because the shale industry was quite certain product prices would stay high forever, in spite of oversupply. I trust you will agree that was a big, stupid mistake.
“Investors” in the shale business model are interested in returns, not in the knowledge they are helping their country become more energy independent, or in the case of the Marcellus, a more cleaner, natural gas burning country. I know you did not mean that.
Remember something for me, pardner; bigger is not always better. In the end fewer than 1% of the shale wells drilled in America are going to come close to 1M BOE UR and all those stinkin’ shale wells cost lots of money. WAAAAYYYY more money than the shale oil industry wants ‘stock traders’ to believe they cost. Don’t get hoodwinked. I can show you that in most of these shale basins right now it is going to take 500K BO, not BOE, just to get to payout and those kinds of wells are going to be the exception, not the rule. The Permian is taking advantage of Wall Street ADD; those wells will not be much better economically than the EF or the Bakken. There is just more country to put the damn things in.
Until the time comes when the shale industry cries for crop subsidies, and that time is coming, its all about making money. The shale industry has not, is not, and will not work in a world of low, volatile product prices. Energy independence on the back of shale, is a very, very bad bet.
Damn Great Sentence and Synopsis Mike Shellman:
“If one is day trading unconventional shale oil and shale gas stocks, that dribble belongs on Seeking Alpha and that Fool thing, whatever that is. Here, using Enno Peter’s data, I am interested in the role unconventional shale will have on short term product prices, and in the long run, on America’s energy future. After 15 years of shale gas, and 8 years of shale oil, I am not too impressed with any of it.”
In fact, over my 30+ Yr professional PetrEngr Career with what was the 3rd Largest US Public E&P at time (first decade) and now 20+ Yrs owning and operating my Private E&Ps, I will state the Public E&P Realm is an overall LOSING PROPOSITION for a “Buy and Hold, Long Term Equity Investor”.
As 10k Boomers per day have now begun to retire each and every day, the PONZI Fraud that their 401k retirement savings enabled will begin to accelerate its’ unwind and leave the Public Mkts exposed – and destroyed – for atleast another generation. For same reasons and by same way as in post-GD 1930s as those frauds began to be exposed and unwound.
The Public Corps are able to lever the hell outta plays by showing “ones and twos” of Pareto Principle type wells whilst the mean, average, median, and in most cases majority of their wells are far below positive ROAs. Heck, just look at the Public COs’ own annual reports of RORs to see the “Best” of them XOM, CVX, etal have +-5% RORs in the BEST YEARS whilst given the choice in leanest years to either kick the can, ie, load up with more rehypothecated equity and unpayable debts, or report losses.
First year ROIs of +-50% on Half-Cycle basis for shalers’ wells declining at 85%, 65%, 50%……., will guarantee one will never achieve Return “of” Capital, much less Return “on” Capital in the Public Equity Mkts.
I, like you, am only interested in what this unwind will do to this Nations’ short term fossil prices and long term supplies. I suspect it will be akin to the past such PONZI Frauds where the unwind was much slower than anyone expected. Especially if we continue the “Pre-Packaged BKs” which are a usurpation and shame upon this Nations’ BK Code itself – where the only two parties’ not destroyed are those most responsible for each Public CO’s appearance in BK, ie, C-Suite and TBTF WS.
Just more frauds upon and begging of the REAL ECONOMY, Private Entreprenuer, and Main Street ‘Murika.
This country does not have a Peak Oil problem. We have a Peak TBTF WS Bankster / FedRes problem facilitated by Peak Public E&P PONZI Fraud Shaler problem. All perpetuated by USG, FedRes/TBTF WS Banks, and SEC, etal.
“For Bakken, it might be different because the slow decline will be able to make it profitable in 20 years, especially if oil price go back to $80 and above.”
Seriously, are you really recommending that your readers/followers at “Seeking Alpha” invest their savings/retirement funds in something that might be profitable in 20 years? How many will still be alive in 20 years?
More to the point, John, what would the Enterprise Value of those heavily indebted Public Shalers look like in 20 Years?
Their debt levels would actually double and then double again at the current blended rates of 7%. So, that means a company unable to carry say $4B today, could under NUASSBLY’s arguement, carry $16B in 20 Yrs when / if oil & NG prices increased to say $80/BO and $3-$4/MMBtu.
NOPE. That’s teh problem with engaging in Debt in E&P. One’s income is a linear funtion whilst the magic of Fraudnance is exponential interest rates. It gets WORSE, not better, for indebted shalers in 20 Yrs.
Forgot who it was on here defending WoodsMac as “otherwise reasonable folks” but I much disagreed then as I do today.
More TBTF WS FRAUDNANCE NEWS from WoodsMac themselves at link below:
That was me… forever to hang my head in shame… though they are right on the capex trends, for better or worse.
If anyone wants a good laugh, look at the Sanchez Energy presentation on their EF acquisition today. 400kbo EUR per well!
After your comment, I looked at Sanchez Energy web site and investor presentation. To my pleasant surprise, I discovered that I know one of the board of directors at Sanchez Energy. So I fired off an e-mail to him with a link to Enno’s web site and a picture of Anadarko’s cumulative well production profile and asked him how Sanchez could tell the investing public these Anadarko EF wells could cum 400k BO given its historical results.
I’ll post his answer if he responds.
Very interesting guys.
Below is what I have on Anadarko in the EF region, for all horizontal wells in the Eagle Ford formation. 400 kbo indeed seems challenging.
Will be interested in that John, thanks for asking. If he’s on the board, but not management, he won’t be ‘signing off’ on public statements, but he will be asked to approve the transaction; he may not be aware of the real trends.
Enno – exactly the first thing I did after seeing that presentation was cross-check on here. I’ve looked at the same graph, by month of start-up, for 2016 (to take in to account the ‘latest completion techniques’ etc) – it’s even worse! Even the best month (June) looks set to fall woefully short.
The recent ‘Centennial’ presentation is another one along the same lines.
This industry is something else. It’s ok not to have great rock: everything has a price at which it works. But they simply lie about what the data means, and even if they had a bunch of great rocks that make money at $30 (which they don’t), they’d plough every dollar back in to the ground until they ran out of good rocks and were back on the awful stuff again.
Mr. Wheel, I appreciate your insights. I understand your observations about what I hope you mean is the shale industry, not the real oil and natural gas industry. The two are not one in the same, I assure you, sir. Much of what is occurring in the US shale industry with regards to financing schemes, distortion of reserve estimates, destroying shareholder equity, bankruptcies; the half truths and blatant untruths…it makes me ashamed to tell people I have been in the industry for over 50 years. I am glad my father and grandfather are not here anymore to see it. They would not like it.
Thanks Mr. Shellman.
To clarify, I do mean the publically listed shale industry (the vast majority of it). I have also seen other troubling examples of similar but smaller-scale behaviour in the E&P industry in Europe, a few years ago, and some of the “MLP” (Master Limited Partnership). From what I understand, you are a private operator who will ultimately answer to his own long-term P&L, and cash flow; even if you operated in the same way as much of the shale industry (which I understand you don’t), I don’t think it would be anyone else’s business.
It is really the nexus of (1) some elements of a genuinely good story; (2) the layers of poorly-designed incentives of various participants in the public markets that are misaligned and; (3) weak regulation.
What do I mean?
(1) The good story: there are year on year improvements in efficiencies. Wells are being drilled quicker and cheaper (even stripping out changes in service pricing); companies are learning how to improve completions in terms of cost/squeezing out more from the poor rock (as we can see, EURs are not improving nearly as quickly as IPs – but they are inching up); and there’s going to be further improvements in the coming years as R&D efforts in the service industry are put to work. Whatever the ‘right’ starting point is for the real breakeven price in every single different basin and county, that number is coming down gradually over time. (The irony here of course is that those who take their time, will reap the biggest benefits further down the road of the incremental improvements the industry makes)
(2) Poor incentives
In a very different setting, I read a good phrase: “the key is to set a system that makes bad people do good things”. We have the opposite.
– E&P management incentives: Per EOG’s presentation (EOG being the closest to a sensible company in the shale E&P industry, ironic seeing as they came from Enron), most management incentives are based upon reserves and production growth. How do you achieve this? Spend more money. How do you get more money? Over-hype your story.
– Investor (“buy-side”) incentives: most funds have to publish and are judged on the performance of their investments relative to the market, and may have some grace period, but 2-3 years of underperformance against the market becomes a problem and leads to withdrawals. So they have to start obsessing about what the rest of the market thinks and is going to value – not what the value of the companies they own is going to be in, say, 5 or 10 years’ time.
– Analyst/sell-side incentives: The sell-side is ultimately judged on their usefulness to investors – to provide information, debate. But a key part of their job involves conversing with management and other company contacts – likely a lot more difficult in the context of a ‘sell’ recommendation, and even more difficult if they said “these EURs look like rubbish”. On top of that, you have the theoretical separation between banking/research that, in some banks, will be more theoretical than others. And with a lot of equity issuance, there’s a lot of business to be won.
(Thinking about this, I should probably throw one or two reserve auditors in to this as well, seeing as they will be signing off on the end of year reserve reports, and are appointed by the companies themselves).
(3) regulators: really asleep at the wheel on a number of these issues. I just don’t think they have the resources or capability to fact check what is going on.
Apologies for the long post.
Thanks for the comment Greasy Wheel,
I agree with a lot of what you’re saying, and the important place that incentives have in all this.