This is an older blog post, you will find one on more recent data here
These interactive presentations contain the latest oil & gas production data from all 18,480 horizontal wells in the Permian (Texas & New Mexico) that started producing since 2008/2009, through October.
Oil production in the Permian kept rising at a rate of ~1 million bo/d y-o-y through October. I expect that after revisions total output topped 3 million bo/d. That also means that almost 60% of October oil production came from wells that started in 2018, as is visualized in the graph above.
Gas production has seen a very similar growth path and is now over 9 Bcf/d (switch ‘Product’ to gas to see this).
Despite increased completion activity, well productivity has still slightly increased since 2016, as you’ll find in the ‘Well quality’ tab. Recent wells are on a path to recover on average around 200 thousand barrels of oil in the first 2 years on production.
Important factors behind this increase in well performance are longer laterals and bigger frac jobs. The following screenshot, from our ShaleProfile Analytics service, shows that average cumulative oil production in the six months rose on both sides of the state border since 2012.
Interestingly, results are on average better in New Mexico, even though laterals are shorter and proppant loadings are smaller.
The final tab shows that all 5 leading operators have roughly tripled their output in the past 3 years.
The ‘Advanced Insights’ presentation is displayed below:
This “Ultimate recovery” overview shows the average production rate for these wells, plotted against their cumulative recovery. Wells are grouped by the quarter in which production started.
Initial well productivity has kept rising through the last quarters. The more than 1,000 wells that started in Q3 last year peaked over 800 bo/d in their first full calendar month.
Let’s also take a look at the terminal decline in this basin, as we did in our last 2 posts, even though the average well age is much younger here. I again used the ‘Terminal decline’ dashboard from our Professional Analytics service. See here the result:
The performance is shown of all the horizontal oil wells in the Permian, that started production between 2011 and 2014. Only wells are selected that fell below a production rate of 60 bo/d not later than May 2016 (this ensures that we have at least 30 months of data for all wells), from which they never recovered.
There were 3,183 such wells, from in total 6,065 horizontal oil wells that started in the Permian in these 4 years.
The top chart shows the oil production rate (logarithmic scale) of these wells, by the number of months since they fell below 60 bo/d. The wells are grouped by the year in which they started. The bottom chart shows the average annual decline, calculated based on the plot above.
If you have also seen the previous 2 posts, you’ll note that terminal decline rates are lower here than in the DJ Basin & the Eagle Ford. The decline rates drop to a level between 15 and 25%, before they stabilize or start to increase again. As noted above, data after 30 months is not complete (not all wells have more historical data).
Also here you’ll see that younger wells experience larger decline rates. Again I would like to emphasize that part of that is expected, as they earlier in their hyperbolic decline curve, where decline rates are naturally higher. But it still appears that even if you correct for that, younger wells decline faster. Likely there are several effects in play, such as changing economic limits & completion designs and more infill drilling. As more and more wells enter this phase, this could increase the decline rate of the whole population (e.g. a certain vintage), negatively impacting EURs and reserves.
If you have any thoughts on this topic, please share them below in the comments section.
Next week we are at the NAPE summit in Houston, so if you happen to be there, please come visit our booth (#2331). We still have time available earlier in the week for 1-on-1 meetings in Houston, so please contact us if you’re interested in understanding how we might help you.
Early next week we will have a post on all 10 covered states in the US. We also plan to launch a new (cheaper!) version of our Analytics service then.
Production data is subject to revisions.
Note that a significant portion of production in the Permian comes from vertical wells and/or wells that started production before 2008, which are excluded from these presentations.
For these presentations, I used data gathered from the following sources:
- Texas RRC. Oil production is estimated for individual wells, based on a number of sources, such as lease & pending production data, well completion & inactivity reports, regular well tests and oil proration data.
- OCD in New Mexico. Individual well production data is provided.
The above presentations have many interactive features:
- The above presentations have 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.
- 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.
Enno. I am not the best at math after all these years.
Can you give readers an idea of what percentage of the wells with first flow in the past twelve months merely offset all prior years wells’ declines?
How does that compare to prior years. I assume that percentage continues to increase? Seems I recall reading SLB’s CEO discuss the rate of 85%, but that might be an estimate for 2019 and might apply to all shale fields.
What I am driving at is the newly discovered term (by me at least) called “managing the plateau.” While you are at NAPE, I suggest you see if you can discuss that with any of the industry insiders. It appears as basins mature, completion rates may slow as companies want to maximize infrastructure over a period of more than a year or two.
COP stated in its CC that they are “managing the plateau” in the Bakken now, will be in EFS in the near future, but are far away in the PB. Likewise, HES indicated that “plateau management” for it is predicted in 2021, with plateau production maintenance of 4-5 years until basinwide permanent decline sets in.
Will be interested to see if you hear any discussion of plateau management of shale basins at NAPE. If so, hope you can share.
The first graph already roughly visualizes the answer to your question: in October you can see that around 40% of the dark blue area added (wells starting in 2018) offset the decline in all the legacy wells (shown by the decline of the top of the light blue area since end 2017). This thus means that about 40% of the wells from 2018 covered this legacy decline, the remaining 60% was all growth.
The Permian is relatively young, and the boom has been recently particular strong, which is why this percentage is quite low.
I think it makes sense for the whole industry to manage a basin in such a way that peak production is relatively flattened, as infrastructure expenses are very high. I am very curious to see if this will actually happen, as there are so many active market participants.
It is doubtful that there will be a plateau in output for 5 years, at least for the US as a whole because the various plateaus in different tight oil plays are unlikely to coincide. If we assume the Permian basin is developed slowly as larger oil companies buy up smaller companies and other smaller plays continue to be developed as they have in the past, I get the following scenario (with URR for US tight oil of about 87 Gb.) This assumes oil prices follow the EIA’s AEO 2018 reference scenario for Brent Oil prices.
Same scenario with contributions from various plays.
I was just referring to what two companies said about their Bakken operations and one (HES) is planning substantial growth until 2021, and then hopes to hold flat 4-5 years thereafter. COP said it doesn’t plan on further growth with regard to its Bakken assets.
I agree that there will not be a plateau overall US for awhile, unless WTI stays below $55 for quite awhile. However, I suspect regardless of price, some companies may be finally thinking about maximizing financial returns rather than YOY growth, at least based on the CC comments I referred to above. If so, this could impact the peak rate as well as annual decline rates?
Much depends on oil prices which are not known as well as technically recoverable resources, also not known. I use USGS mean estimates for TRR and EIA’s AEO for future prices and then reasonable economic assumptions based on what I have learned from you, Mike Shellman and Rune Likvern. Clearly the ramp up in completion rate is a guess, I recently revised the Permian ramp up based on cutbacks in capex announced by some producers, the completion rates I have chosen may still be too aggressive, but it is based in part on the ramp in 2017 and 2018 when oil prices were relatively low (mostly under $60/b for WTI over that period). I am open to other suggestions and yes I realize individual producers may try to maintain a plateau, the fact that there are so many producers and all their plans are slightly different is likely to lead to a gradual peak and then decline, probably in the 2022 to 2025 time frame.
Another factor is the uncertainty about when new well EUR will start to decrease as sweet spots become fully drilled, this may have already occurred in the Eagle Ford(2019), Bakken is likely to follow soon and probably Niobrara and finally Permian Basin (2025).
This will only be clear about two years after it has occurred.
Note that my “reasonable” economic assumptions I mean 32.5% royalty and taxes combined and an LOE of about $13/b, I also use AEO 2018 reference oil price case for future oil prices. My work has only been reviewed by Paul Pukite and a similar Bakken analysis by Jean Laherrere, though I have learned much from others such as shallow sand.
Let the inquisition begin:
2015 PXD Wells 1 MMBOE- right.
Jim: I truly hope this goes somewhere. I have my doubts, but we will see.
Let’s say all it does is eliminate the Powerpoint EUR claims.
Look at PEs latest presentation- search for EUR- it shows up twice in the disclaimer but nowhere in the presentation I can find.
So an analyst has to figure out why he should recommend investing in your company when you can’t tell them what your investment performance metrics are.
So the analyst must rely on your P&L…. isn’t that what we want?
If that’s what it accomplishes – isn’t that a lot?
if you really dig the unfounded EURs you will find the following,
Somewhere in 2012, Permian operators had claims of 1 million EUR with then mostly 5,000′ laterals.
Then, above in 2015, they replaced the lateral length with close to 10,000′.
After bashing shale oil for so much, we kinda forgot seeing similar EUR claims history in Barnett and then Haynesville shale gases, and the shale gas scam bashing claims by the all famous and familiar experts. But, where are they now?
The hope for shale oil operators is to find a “Marcellus” in shale oil patches and then call their EURs come true.
How did the 1million BOE or 6BCF EURs for 5,000′ really started? The PPTs by shale oil operators can not be based on thin air, but has to follow certain rules in oil and gas accounting.
Actually, the shale gas lateral’s EUR is based on historic producing vertical unfracked shale gas wells in the last century which boasts really low low decline rate, much lower than conventional gas wells. This low decline rates of course never happened with Barnett and Haynesville, and all skeptics got high in blaming shalers as scam masters. Luckily, Marcellus gets close to the low decline rate, and now skeptics famous or not just have to point their fingers to the cash flow, which is not that good due to persistently below $3 gas prices, yet even that is improving while growth in the Appalachians continues.
Similar claims of shale oil’s 1 million EUR is also based on vertical unfracked verticals EUR in history, which is about 40K BOE EUR for 200′ of producing verticals in Permian. With 5,000′ of lateral, we should see 1million BOE by simple math.
Also in 2012, SPE paper 155655 “Evaluation of Coreflooding, Well Testing, and Reservoir Simulation” found an average Middle Bakken Well to make 363 MSTBO using 8828′ horizontal and 15 stages.
Which, if you look at the numbers, is likely close to the average result achieved.
As to the Permian, how does one define a 200′ “pay interval”. Is there some petrophysical (log) analysis which uses some constraint as to net/gross ratio? If there is, I haven’t done enough research to find it. Also, on what spacing were those 40k vertical wells drilled?
EUR’s reported by Permian (shale) oil operators for HZ laterals are NOT based on historical UR’s from vertical wells. Yikes! I’d like to see evidence of that somewhere. The only 200 feet of gross interval I am aware of with those kind of 40K BO recovery rates were sections of the upper and sometimes middle parts of the Spraberry in the Midland Basin. Those wells were drilled on 40’s.
EUR’s are based on DCA and done at the worse time in fluid flow regimes, or the best time, depending on what your motive is, and using clever Arps tweaks. That led to exaggerations all to hell and back…before rising GOR and Death By Bubble Point (Lapierre). Jim, help me out here.
I don’t blame the shale oil industry, or its cheerleaders, for being nervous about this investigation out of Louisiana; ooooweee, what a mess it would be if there were not sufficient assets to properly collateralize all that debt.
So 40 acres made 40000 so you need 1000 acres for a million.
So you drill a 10000 footer you need to drain over 900′ side to side laterally WHILE NOT INTERFERING WITH THE WELL (STAGE) LESS THAN 150′ AWAY. So that’s how it’s done.
The lawyers have the 2015 claims and wells. Far enough along to recognize the 100% promote; especially by the time settled. Time inures to the plaintiff’s benefit. Next they’ll have the 2016s and 2017s. Then the eur claims stop. But they have 3 years of easy pickings.
Be interesting to watch.
Yes, based on the claims regarding how EUR’s are determined, that is correct. A 900 foot wing on a frac is awesome stuff; I’ve never even seen it imagined, must less in real life. Think of the billions saved in CAPEX if you could drain a thousand acres in the Wolfcamp D.
Whatever, folks have damn funny ideas how this shale stuff works physically, and not a clue how it works economically.
The investigation you referenced is going to be very interesting. And it makes Enno’s work regarding terminal decline rates all the more relevant. I mean, really…forget the financial plight of the shale oil phenomena, America needs to know what its REAL reserves are. We need reserve “transparency” like we demand from the ME. If we get that maybe we won’t export all of our stuff to China before somebody higher up, wises up.
40acres is a radius of 745′, and if porosity is 5%, and height of vertical section is 200′, then we are talking about 3.39million bo in place, and with 40k bo recovery, we are looking at a 1.2% recovery.
With 900′ X 10,000′ X 200′ (vertical) SRV, and porosity at 5%, we are looking at 40million BO in place, and only 2.5% recovery needed to do 1million BO. That’s why they believe with the almighty new fracking technology, the recovery should be 5%, or be a aggressive, 10%. CLR is now claiming 15% last October in Bakken, and was at 8% back in 2011.
Did you include reservoir water in your calculation? It can be anything from 15% to almost 100% in Wolfcamp B (https://www.breakingviews.com/wp-content/uploads/2018/06/permian_produced_water-_slowly_extinguishing_a_roaring_basin.pdf)
Looking at the accelerating terminal decline curves, rough visual analysis says we might end up with ~350k bo ultimate recovery with the average 2016- wells. Back of the napkin calculation suggests such wells are probably not making money at today’s Permian prices.
Pioneer’s Q4 2018 PPT still gives 1.6MM BOE per 9,800′ lateral.
They don’t care about the law suite.
Its not a lawsuit, its an “inquiry.” Pioneer cares, I assure you; they invented these ridiculous EUR’s for their 4Q18 stuff before all this recent hubbub came into the MSM limelight. They sure better care.
BOE at 6:1 has always been a big whopper; in the Permian, given Waha postings, the truth at the moment is about 32:1 gas to oil. Rising GOR makes EUR BOE’s look really terrific, particularly if you omit, or don’t make a point to say, what portion of the revenue stream is gas, what the market is like, and that everything seems to be getting gassier.
Using volumetrics and implied recovery rates of OOIP to determine EUR in shale is ridiculous. In the example given no consideration is given to water, gas or oil saturations and the implied recovery per acre foot of “reservoir,” or stimulated shale container, is way out in left field. In the the 200 feet of gross interval used, if indeed it is Spraberry (it can’t be anything else), the “net” pay in that interval is no more than 50 feet, max. I drilled it. It put the ‘m’ in marginal and the ‘l’ in lousy rock.
It would be good if folks listened to real oil men, like Brooker, Likvern and Shallow. And the realized production data that Enno provides. How can you refute real production data? If you look at real production data and still want to believe the shale oil industry, and 1.6MM BOE’s, you can’t be helped. Nobody is bashing the shale oil industry just to be bashing it. After a decade, economically…it sucks.
How many hz Permian wells have cumulative of 1 million BOE to date? I know we are early into the Permian, but one would think there would be some monsters that have hit one million already, if the average well EUR is claimed to be 1 million.
And again, we best not confuse BOE with BO, as the E cannot be sold for very much.
Pioneer’s BOE growth already much faster than BO growth, just in Permian, how could they keep the GOR down. They could only say “we are not producing less oil, just a lot more gas”
What is not discussed is handling of NG and NGL. I see that NG has increased a lot in 2018. If there are pipeline limitations for oil, I would expect there will be a bigger limitation for NG and NGL handling. Growth by flaring NG and NGL is never a good option and I am not sure whether Texas RRC is imposing flaring rules.
Permian gas production has increased by some 2.6 BCF/day in 2018 alone. Since there are pipeline limitation for oil, it is safe to assume that there is pipeline limitation for NG and NGL.
Pioneer in their q4 press release had BOPD of 194k for q4. For 2019, they are projecting an average of between 203k and 213k BOPD. That’s growth of a maybe 15k bpd from q4 of this year. Not exactly a big amount. A lot more growth in BOEPD than BOPD.
Declines are definitely accelerating. I calculated for ten months, 2017 wells declined at 52.8%. That means by December, the one year decline rate is likely a little bit above 60%. 2016 wells had a first year decline rate of 54.5% and 2015 wells, a first year decline of 52.7%.
Assuming 2018 wells come in December at around 1,800k bpd, with a 63% decline rate, that suggests decline just from this year’s wells of about 1,135k bpd. As just a wild ass guess, in 2019 if they drill 4400 wells (pretty close to what this year will likely end up at based on 3660 so far this year) and average around 480k bpd (likely a small boost from around 460k bpd this year) that adds 2,110k bpd in 2019 before any decline. Taking away the estimate of 1,135 for 2018 decline, the Permian increases by 975k bpd before all the legacy decline from 2017 wells and prior. As a pure wild ass guess of 350k decline on that base of about 1,200k bpd or so, that would mean an increase in the Permian of about 625k bpd for the year.