Enno Peters
This is an older blog post, you will find one on more recent data here
The above presentation contains the latest oil & gas production data from 9617 selected horizontal wells in the Permian (New Mexico and Texas) until May.
There was a small drop in oil production in May, but as Texas revisions come in over time, this may all but disappear.
If you group production by “state”, you’ll see that since early 2015, the growth in production in Texas has been quite a bit higher than in New Mexico.
Using the “product” selection to switch to gas, we find that gas production is rising more rapidly, and that the natural declines are lower, similar as what we’ve seen elsewhere.
Since the last update, I’ve removed almost 400 horizontal wells on the Texas side. These wells were located on leases with lots of vertical wells, making it more difficult to estimate accurately the individual well production for these wells (as the Texas RRC only provides lease production). These wells were good for about 50 kbo/d, so this production has disappeared from this overview.
Looking at the “Well quality” overview, we can see the reason why the Permian has shown more resilience compared with the other oil basins, as well productivity has risen more sharply.
The Bakken used to be the only oil producing basin where shale wells declined relatively slowly after initial production, so that by month 20 they were still doing about 100 bo/d, dropping to about 50 bo/d by month 60.
We can now see that in the Permian new wells (2015/2016) are also on track to produce on average about 100 bo/d by month 20. It will be very interesting to see whether the declines after that will also go into the direction of the Bakken.
In the “Top companies” slide, we can see that Pioneer Resources has bucked the trend, and has grown quite significantly in oil production.
I expect to have another update on the US on Monday.
====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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13 Comments
Nice dataset.
It looks like they are getting close to a 300 KSTBO average, a shame it took 10000 wells to get there… they have a lot of losses to recoup.
Funny how the bakken was the exact opposite; best stuff was drilled first. With all the holes in the Permian, looks like the best Wolfcamp/Bone Springs etc. shows would have been well known.
If someone has a reason other than improving the dimensionless conductivity (Fcd) of an overdisplaced frac in a 30 nano-darcy rock (frac job improvement); a reason that has to do with the geology, it would be interesting to know.
Jim,
> Funny how the bakken was the exact opposite; best stuff was drilled first. With all the holes in the Permian, looks like the best Wolfcamp/Bone Springs etc. shows would have been well known.
That is indeed a surprise. Also in Montana the best results were obtained in the earlier years. I guess that results in the Bakken were impacted by having more wells per spacing unit.
I also wonder how much of the improvement in the Permian wells stems from longer laterals & bigger fracs.
Enno, with these mega-fracs, ie. more stages, more sand, longer laterals, this is just a means of opening up more surface area, which means more oil/gas will be release from those tight formations. Frac’s don’t change the permeability of the rock, they only changes the porosity. When more surface area is opened up it allows that oil/gas close to that surface area to be released. Once that’s done the rock slowly reverts back to it’s initial permeability. Thus wells with greater surface areas to drain will produce more. These wells will still decline at the same rate, but initially they will produce more and then decline as usual throughout the life of the well. Thus EUR would be greater… well… in a perfect world.
As an example: The Montney Shales in North BC Canada (they are almost completely shale and not a inter-bedded zone of silts, sands and limestone and shale as found in the Permian Basin), has permeability of 0.25 microdarcy and porosity up to 10% from natural fractures. For comparison Granite has a permeability of 0.1 mircodarcy and frac sand would be 1.0 darcy. So at 0.25 microdarcy it would take gas 10,000 years to migrate 1 meter (3.25 feet). So after fracking, all that rock whose surface area is not exposed would have revert back to draining at 0.25 mircodarcy.
Think about it this way, every cubic meter of rock would release more of it’s bounty if you could break it up more, thus the idea of mega-fracs. Mega-fracking allows for more surface area to be opened up, thus allowing more oil/gas to be released.
If they could figure out how to completely pulverize it down there and keep those areas open with sand then these wells would most likely be better than those Saudi wells back in the 60’s and 70’s. With this Mega-fracking they are trying to mimic a conventional zone. After all this is how mother nature created conventional zones in the first place. The oil/gas in conventional zones (high perm and porosity formations) migrated over 10’s of thousands of years from source rock (shale). Fracking is just a ways to speed up mother natures process of filling the void of cracking it and filling it with sand.
The one unknown is how long these cracks will stay open on these new mega-fracs.
There’s lots of oil/gas per cubic meter down there in shale/tight formations, it’s just not easy to release it all. They are saying recover in the Permian was 3.5% of oil in place in 2014 and now they have increased by 0.5%… maybe… So the EUR should only increase by 0.5% not 3 times.
So in physics the more surface area the more oil/gas released. thus more production over the same period of time.
Extrapolating initial production, or even the first 2 years of production to EUR’s that are 3 times greater, isn’t correct. As with most tight/shale wells the first 2 years is the majority of production and after that they’ve declined so much that these mega-fracks aren’t going to help much. They wells run into the low permeability issue.
Hope this helps,
PS: at one time they were thinking of exploding nukes down there to break things up.
Nodeywan,
Thank you so much for this elaborate background info, very interesting, and helpful indeed!
I think your explanation is well supported by what we’re seeing : quite significant improvements in initial production in the first couple of months, but after that a trend towards similar performance of earlier wells. Only here in the Permian does that higher initial productivity now seem to last longer as well, on average, but it’s not clear yet whether that will extend beyond the first 2 years.
Nodeywan
That’s an excellent description and I thank you for the input.
If I may extrapolate a bit on your post ” … if they could figure out how to completely pulverize it down there and keep those areas open with sand …”.
EOG, arguably the leader in the unconventional field, first introduced their “High Density/Mega Frac” to the Bakken with their Riverview 102 32 H after numerous, successful applications in the EF.
With 399 days online, this well has produced over 408,000 barrels of oil and near 1 Bcf gas … all with a lateral 4,300′ long. Still flowing – no AL – at almost 400 barrels/day.
The fracturing had 23 stages and used almost 12 million pounds of #100 mesh sand and just under a million pounds #40/70.
As #100 mesh is less than 6 thousandth of an inch in size, it is utilized more as a scouring/sandblasting agent than a propping instrument.
The increasing use of massive amounts of sands, more effective use of diverting agents to “block/temporarily plug” larger fissures (thus enabling pressure buildup to create more, new fractures), along with other factors, especially the crucial WHERE to precisly land and place the lateral, are all playing a role in increased unconventional output.
There are many other aspects that are in various stages of recognition and effective adoption. Some are the so-called ‘far field’ diverterss which help prevent the spread of the frac half length (thus enabling a closer placement of wells), a greater understanding of hydraulic communication that occurs when nearby wells are frac’d, and many, many other components of the completion aspects of this industry.
All these, coupled with the never ending improvements on the drilling front (15,800’+ one run drilled in the Marcellus by Consol, Antero’s 7,200’+ lateral drilled in 24 hours) are positioning these operators, this approach to hydrocarbon production as becoming the ‘conventional’ rather than ‘unconventional’.
Coffeeguyzz, These type of wells are what I like to call perfect world wells. The geology not only is one of the sweet of the sweet of the sweet spots (rare), it’s also very conducive to fracing. These areas areas with massive production capabilities are few and far between. As the saying goes “all shale is not created equal”, in all fields there are areas where the geology is outstanding and we have these boomer wells and then we have the rest (the majority), which is can be good to total crap.
This well is a great example of increasing frac stages to a perfect world well to increase surface area thus increasing initial production. If you use Enno’s website to bring up all the Riverview wells for EOG, the initial production on 102-32H is outstanding, but it looks like the decline rate is actually quicker than previous wells drilled in 2012. 102-32H has declined around 80% in the first year, even though it’s still producing 400 bbls/day.
In the Permian Basin, “take home pay,” or net-back prices are currently in the general vicinity of $14.00 per barrel after all costs are extracted, including interest expense and G&A. The value of gas in the gas-to-oil conversion (BOE) façade is not relevant at the moment; if you don’t believe me, drive thru W. Texas and see it all being flared. I just did. Tens of millions of MCF’s per day, going up in smoke.
At current prices, a seven million dollar oil well must produce 500,000 barrels of oil just to reach payout, before a nickel of profit is earned. Using Enno’s data it appears to me, and others, the average 2015 Permian HZ well will only make 150,000 BO after 36 months. As an oil operator, and a keen observer of shale oil economics, if a shale oil well, in any play, is not 65-70% to payout after year 3, its not going to get to payout.
The shale oil business is not a game; its not a means of being and oil man, or an oil expert vicariously thru the internet. Its a business. It has to make money or it does not succeed. At the moment the shale oil industry is woefully unprofitable and in serious, serious financial condition.
The Permian Basin HZ plays will not fair any better than any other shale oil play in America. A few wells will be good, but they won’t pay for the tens of thousands that are not.
Mike Shellman
Enno,
I have been trying to keep an eye on PXD, as an indicator of how the Permian is doing. I believe it was in July when Nony and I had a conversation about the EUR of PXD’s wells. I have tried to compare what you have now and what I was looking at then, but can not a access July’s archives. From memory, the PXD per well production seems to have grown significantly.
The search function i was using, is as follows, PXD, 2014-15, Monthly starts.
Oct 2015, seemed to be the stand out month, with 15 wells, and a CUM 126k bo, from memory and only producing 50 bopd. On your latest release, Oct 2015 the 15 wells are up to 147 k bopd and producing, 422 bopd. I understand numbers drift around a bit, especially with the way Texas works, but this does seem a bit extreme?
At the end of the day, I suppose we need to be careful with a single snap shot in time. Thanks for all of your hard work.
Toolpush,
> I have tried to compare what you have now and what I was looking at then, but can not a access July’s archives.
If you click on the July archives, you should see 2 pages. At the bottom of the first page, you’ll have the option to browse to the second page. In that way you should be able to access all old posts.
I have not really changed the algorithm during the last 2 months, except the change I mentioned.
However, because well results in Texas are estimated from lease production, I do recommend looking at large enough samples. E.g. either for at least a whole county, or for a single operator by year/quarter, so that you have about 50-100 wells in each point in the graph.
The reason behind this is that even in the Permian (compared with the other regions in Texas), the average horizontal well to lease ratio is pretty good (about 2.0), but there are large differences within the area. Note also that the Texas RRC may release major revisions each month, which I include when available.
Enno,
Part of my problem is, the July link will not work for me. I have tried resting the curser all over the link, especially the right hand side which I know works better.
All other months work, even if some are a bit touchy.
Strange, looks like a WordPress issue on the resolution you use.
If you have this issue in the future, you can click on the link for an other month, and just change the last part (the date) of the address in your address bar.
Thanks Enno,
It looks like by you weeding out some wells, has increased the average of the remainder.
Going by this update. July and October seem to be stand out months for PXD, with 2016 lagging behind. So much for their continual improvement in production techniques.
I wrote a comparison of water handling in production cost between Midland PXD and STACK NFX.
I think PXD is hiding the real cost. Don’t you hear that Permian is also having more earthquakes now?