Longer Laterals Are Leading To Temporary Production Increases Basin Wide
Permian Basin tight oil production surprised to the upside in 2023 for two reasons, none of which had anything to with greater "rig efficiencies" or "technology improvements." Production went higher than folks thought, in spite of lower rig counts, because over 430 drilled but uncompleted wells (DUC's) were completed in 2023 and lateral lengths increased. Rigs just drill holes in the ground, some faster than others. Permian completions have been remarkaby consistent since April of 2023.[1]
Remaining DUC counts in the Permian that might be economical to complete at $80 oil prices and $1 associated natgas prices are now depleted.
Oil production is surprising to the upside again, in 2024, and the Permian is still growing, be it ever so slowly, because of increased lateral lengths. Well economics are very, very marginal with associated gas prices around $1 per MMBTU and everyone is trying as hard as they can to get the most bang for the D&C costs. The results are higher IP90's, then much faster decline rates. They bigger they are, they harder they fall.
Above is a chart from World Oil Magazine [2] showing increases in footage per wells being drilled; the TVD to various benches in both sub-basins of the Permian are fairly consistent, increases in TMD footage are increases in lateral lengths. New Mexico is Lea and Eddy Counties; TRRC District 7C is mostly the Delaware Basin and some important counties in the Midland Basin, District 8 is the Midland Basin.
Please note the percentage of increase in District 8 the past three years; that is entirely a function of having NO room to drill longer laterals in the core of the Midland Basin. There IS some cubing going on in Midland County, by Exxon, though it does not seem to be a lot, that too most certainly be a function of how many wells Pioneer drilled in its block before bailing out. Cubes would definitely be adding to production levels on a per well basis.
Shell drilled what it called "horseshoe" wells several years ago because of limited space for supposedly more cost effective long laterals and Matador is now bragging about "U" wells, I assume also being tried because of lack of space.
Above is the corresponding chart to Table 1 provided by World Oil Magazine [3] showing the percentage of increases in production related to increased lateral lengths. As we can see, all sub-basins in the Permian increased production dramatically the past 3 years and, as we have discussed here on OSC many times, Lea and Eddy Counties in New Mexico have led all growth in the Permian since 2020 by a significant margin.
The productive limits of the Delaware Basin in New Mexico are mostly all Federal (BLM) land of wide-open spaces and more conducive to longer laterals, higher production, and the ability to sustain production levels. It's some better rock, but mostly vast room to drill longer laterals. New Mexico Federal lands have lower royalty burdens and OPEX is lower because, for the most part, it sends all its produced water to Texas where we inject it and suffer the consequences. Like 5.0 earthquakes.
"Over in neighboring New Mexico, gains in footage drilled per well and oil production have been impressive. The footage drilled per well has jumped 24% higher, from 15,000 ft in 2020 to 18,600 ft in the first half of 2024. The state’s oil production certainly has responded to the longer wells. Output is up an impressive 93%, from 1.027 MMbopd in 2020 to 1.981 MMbopd in first-half 2024."
Consider that the S.W. portion of Lea County, and the S.E. portion of Eddy County have grown tight oil production 93% the past three years, still have 31% of all HZ rigs working in the Permian Basin (Eddy, 55, Lea, 40) and produce 2.1MM BOPD, representing 30% of all Permian tight oil production. The vast majority of Lea and Eddy County tight oil production comes from two benches in the Bone Springs (green, above). There are currently 11,619 producing HZ tight oil wells in this small area of New Mexico. Remove these two partial counties from the mix and the Permian would be in steep decline.
All of these longer laterals in the Permian Basin are being high-graded in Tier 1 and 2 level sweet spots and 85 plus percent of those lateral targets are in the same, most productive benches in both sub-basins, the Wolfcamp and the Bone Springs in the Delaware and the Wolfcamp and Lower Spraberry in the Midland Basin (Enverus, EIA, Novi)
New Mexico has a lot of room to drill super long laterals if, that's the ticket; Texas not so much,
Above is a Texas Railroad Commission GIS map of Midland County in District 8. This is part of the Saudi America that Exxon just bought from Pioneer Resources. Midland County has 22 rigs running in it and 21 of those rigs belong to Exxon, still operating these wells under the name Pioneer. On a larger scale which you can create by clicking on the little thingy, upper right, you can see blue dots. Those represent pending drilling permits, all of which belong to Exxon.
For the record, Midland County is suffering from post-bubble point GOR issues and liquids well productivity is tanking from pressure depletion. Exxon, nevertheless, is hell-bent on drilling themselves out of a bad acquisition, in my opinion. And where they can find the room its lateral lengths are long and getting longer. Which ain't easy...
Here is a drilling permit filed by Exxon (Pioneer) for 13,600 foot lateral in Midland County. This is an illegal allocation well whereby leased mineral owners are forced to pool their acreage into this Tredaway Elkins Unit so Exxon can drill this long lateral. The TRRC allows allocation wells, even though in Texas we do not have forced pooling laws. Allocation wells are sort of a non-issue (90% of the time) because all mineral owners just want more royalty. 10% of the time mineral owners may object to an allocation well, but they're only recourse is to file suits, which there are numerous in Texas courts all waiting for the Texas Supreme Court to rule on. In the mean time, they ARE illegal. The TRRC allows them anyway. Note how irregular the so called, "pooled unit," is in the plat above.
This Exxon permit application is also an exception to SWR 37 for distance from first take point to the unit line. The applicant will have to give notice to all affected parties and those parties will have the right to protest the permit. They won't, of course, because they all want more royalty. Rule 37 exceptions are becoming common place with allocation wells, or production sharing agreements.
My intent in showing you this W-1 plat associated with Exxon's permit is so that you will see how crowded it's getting out there, particularly in the Midland Basin, what an operator has to do to get a long lateral actually drilled, and that they are running out of room in these core counties, like Midland County. I looked at the TRRC permit query for Midland County and 92% of the HZ wells permitted in the country in 2024 are Exxon's and 60 plus percent of those wells are allocation wells. The majority of wells getting permitted in Martin County to the north are allocation wells. Midland and Martin are the two most productive counties in the Midland Basin.
So, clearly, at least to me, rig efficiency, or more wells drilled with fewer rigs, has nothing whatsoever to do with there still be growth in the Permian Basin. Oil production in the Permian Basin is still growing slightly in 2024 because fewer rigs are drilling longer laterals.
These longer laterals decline much faster than older, shorter lateral wells drilled on wider spacing; in the Permian Basin, 73% the first 11 months of production, up from 47% in 2019, left.
As long as the number of completions remain the same in the Permian Basin, and those new wells are in excess of 10,000 TMD, production will appear to be growing because IP90's are higher.
When they run out of room to drill longer laterals, and they will, the steeper decline rates of "new" wells are going to kick in, hard, and Permian production is going to drop very quickly. More rigs will then be its only savior.
Unless you want to grow up and own working interest it HZ tight oil wells in the Permian, the ONLY metric that should matter to you is EURs. [5]
Data-sell companies like to calculate remaining drilling locations under a host of funky metrics, and spacing options; nobody talks much about how many of these long, Permian runways there are left to drill in the core areas.
[1]
[2] [3]
[5]
Regarding productivity, although type curve oil production volumes increase for a 3-mile lateral compared to a 2-mile lateral well (Figure 2), the cumulative oil production per foot deteriorates for extended lateral wells (Figure 3).
Think of it like a big, giant parking lot with very few empty spots left.
I choose to write about the Permian Basin HZ tight oil play because it is the single largest source of crude oil and condensate growth in the United States... and in the entire World. Like all oil plays, unconventional resources in the Permian are now depleting and I am concerned about oil and natural gas exports from the United States and our nation's long term energy security. We should be conserving these hydrocarbon resources for Americans. For our kids future. The sooner we come to grips with depletion, the better; in the end, those nations with the most remaining natural resources, win.
Here is Novi's take on longer laterals, just out...perhaps in response to my post?
You can read about it here on Lindkin: https://www.linkedin.com/posts/ted-cross-tx_long-laterals-are-more-important-than-ever-activity-7265006855918149632-L29u?utm_source=share&utm_medium=member_desktop
Strong economics is qualatative. No well costs mentioned for us to make up our own mind on economics; just a reminder that gas and gas liquids is approaching 50% of the production streams from new Permian wells and WaHa is still a negative number.
Black lines are plus 3 milers and those EUR's are lower, as I have suggested many times.
No word on how many of these super long laterals there are to drill in the Midland Basin, or out West...not many left, IMO.
Improved per-well productivity means on an IP90 basis, as I pointed out in my post...not by EUR. Higher up front cash flow gets to payout faster, but does NOT necessarily make more money in the long term. Novi likes 2 year payouts as that is the basis for much of their remaining drillable location predictions.
This statement by a data-sell company has implications regarding longer laterals that are NOT true; it is qualatative statement depending on the defintion of "effective" resource extraction, increased output per well and optimization of leased areas. IP90's do not make wells more productive by any definition and the bigger they are the first few months the harder they fall.
This headline from a major industry magazine implies reservor recovery is "enhanced" by drilling longer laterals and can NOT be proven to be true at this time. In fact, just the opposite is likely true with regard to recovery rates of OIP along a horizontal lateral or stimulated reservor volume (SRA) surrounding a lateral.
Optimum lateral lengths based on maximizing recovery of oil is way different that those for maximizing up front cash flow.
This is an independent study done by two SPE members on longer laterals in the Bakken. I can find six papers just like this for longer laterals in the Permian, including one in the Journal of Petroleum Technology.
Poor stimulation of perforation clusters toward the toe in a super long lateral actually reduce recovery rates of OIP in the last several thousand feet of lateral. That oil is then stranded and lost forever.
Unless you want to be a working interest owner in $9MM HZ wells that have total ROI's over 12 years of 50%, and are netted like a mullet over up front cash flow, or are a day trader and eaten up with 4% dividend rates, estimated ultimate recoveries from long lateral wells is lower and just one more example of how this amazing resource in America is grossly, negligently, being mismanaged for our nation's long term energy security.
Where's Waldo?
Martin County has a number of plus 12,000 foot laterals, can you find them?
Now find room for plus 18,000 foot laterals.
This is overpressured San Andres country up here and a lot of HZ wells in Martin take an intermediate string of casing and/or liners with OH packer assemblies to be able to drill thru the San Andres. The Upper Spraberry can be very pressure depleted. This is earthquake city up in here, also.
Whats the point in all this?
Then, just like that, it will be over.
EOG is operating appx. 2,200 HZ wells in Lea and Eddy Counties in what appears to be about 367,000 acres in those two counties.
Most of the short lateral wells in red are in the Wolfcamp A&B and Bone Springs 2, I think. In this map see 4 laterals longer than 13,500 feet. This area of Lea County is its most concentrated acreage positions, short of blocks on the NW shelf. You decide how many more 15,000 plus foot laterals can drill in the Delaware Basin; 50 in 2024 may pretty much wind it up. Please note that EOG's EUR's are dropping like a rock in 2023. I don't know. It would be great to know, but we hardly ever really know much of anything, do we?
Here is block of EOG acreage just cross the State line, in Loving County, Texas, in Sandbar Field; they like to pack 'em in there, uh? Try getting a 15,000 footer in that mess.
Exxon accquired the Poker Lake Unit in Eddy County from BOPCO in 2017. The Unit is very large, actually old, circ.1980's and produced from the Delaware series. mostly vertical wells. Poker Lake is unitized so there are no pooling worries. Exxon drilled HZ wells in the Unit in the Bone Springs and they were lousy, so they more or less quit it. Then in 2022 and 2023 started drilling better BOE wells in it. Now they have supposedly finished four, 20,000 foot laterals in the Unit and everyone is awaiting results as we know at least two of them have been frac'ed. I'd say if the news was good we'd already heard from its CEO, who likes to talk stuff up. It is very gassy out there so BOE IP's are liable to look huge.
I don't give a hoot about Exxon, I am only interested in what its doing for America's long term energy security. Since longer laterals are leading to big, temporary, production increases, I am just trying to understand better how many of those things they think they can drill and make money from.
Thank you gents. I've read the replies several times. I found this site because I have my eye on supply and because I was reading about the hastening decline of the Permian wells. Your responses help make sense of the data. On the supply/demand front, I trust you see the same thing I do--the market has been hyper-focused on demand, at least since Covid. I'll be curious to see if this election result changes that focus--in other words, will a sudden upsurge in US demand awaken an awareness of oil supply pressures, regardless of what is going on in China--especially if Trump moves to sanction Iran's oil industry. Fascinating week.
Thank you, Arthur.
So, from my standpoint it takes more horsepower, more sand, more water and more money to effectively stimulate stages toward the toe of a long lateral, they tend to shut down sooner (even sand completely up, sooner) and in terms of EUR, it's not worth it economically. There have been a lot of SPE papers written about this and suggest that on an initial basis, for instance within say IP + 90-120, you can get bigger numbers up front, and more cash flow (the point of my post) but then wells decline faster and that may all have to do with pressure depletion along the lateral.
Novi, before they went over to the other side, wrote a good paper once suggesting optimum lateral lengths for recovery in the Delaware Basin were 8-9,000 feet.
I have a brilliant PE friend in the IB that likes to think of a horizontal lateral as a long lease road with each perforated stage along the lateral like an independent stripper well, some better than others, but all sort of commingled into the same "flow line." Those stripper wells along the lease road all produce at different rates, have different WOR's, different GOR's and reach fluid phase transitions at different times.
Longer laterals, I believe, for the reasons I gave above, result in LESS recovery of oil in place per foot of exposed rock. Of that I am sure and that is a piss poor "reservoir" management. If you drill 3 1/2 sections of Wolfcamp B in a 15,000 foot plus lateral, the last section in the lateral probably only has a 6-7% RR compared to 10-11% up front. That oil is then stranded, immobile, and lost forever.
That may not answer your question entirely, sorry. I understand, sorta, the economics of drilling longer laterals for cash flow reasons, NOT for increased EUR's or better recovery of OOIP along the SRV.
Mike
PS: My hair stands up like Buckwheats when I hear the U.S. has more "liquid gold" under its feet than Saudi Arabia. Take New Mexico, for instance; gassy oil wells are turning into oily gas wells, WOR is going up, liquids productivity per perforated foot is going down and EUR's are down.
Hi Mike. I appreciate the data--thank you for writing extensively. Can you shed more light on the concept that longer laterals decline faster than shorter laterals. Is it something to do with the completions occurring at the far ends of the laterals--are the fractures not as effective or penetrating out there? Or is it something to do with the flow of the hydrocarbon molecules from that distance--are the molecules not as likely to be harvested because they don't migrate efficiently to the vertical bore? Or something completely different? Whatever the answer I would still like to see a metric that incorporates the length of the lateral, in other words, the portion of the resource being tapped. Up here in posthole land, when I make an oil and gas purchase, I build a spreadsheet that includes a value for the number of drilling locations. Obviously that antiquated method doesn't work where the lateral lengths are ever-expanding. But what's not expanding in the Permian is the size of the resource. The pundits don't seem to get that. God knows, I was relieved by the election results, but I cringe every time President Trump says the USA has more oil than Saudi Arabia.
In Belgium on the show '' Can you dance? '' when there is an extraordinary performance the judges say '' Now that is what is called a dance '' . This post of yours Mike is what I would say '' Now that is what is called an analysis '' . Kudos