Permian: 2019 & Beyond : Permian Well Productivity is Just Fine

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Permian Well Productivity is Just Fine

 

 

Earnings season is in full swing and once again investors are scrutinizing the spending habits of US shale operators. With concerns over capital discipline come those about well productivity and whether the pace of output growth is sustainable at current crude oil prices.

A July report from analytics firm Kayrros indicates that the average well in the Permian Basin, the primary source of oil production growth in the US and world, is both less productive and more expensive than reflected in public data. This assessment is based on findings that hydraulic fracturing work in the basin was underreported by 21% last year.

Operators have descended on the Permian in recent years, selling off positions in other basins as they have narrowed their focus on productive, liquids-rich areas in West Texas and southeastern New Mexico. In the process, the basin has become more crowded, much of the prospective acreage has been claimed, and many newer wells have not produced like older wells.  

However, consultancy Rystad Energy is not buying into the hype that well productivity there is dropping.

“After careful analysis, we do not find sufficient evidence in the data to support these speculations,” said Artem Abramov, Rystad head of shale research. “We conclude that the average new production per well in the basin matches the all-time highs seen in early 2019—despite depletion concerns.”

jpt_2019_8_rystad_permian_new_production

 

New production is defined as hydrocarbons flowing in a well’s second month of production. The second month is typically the first full month of production, and in most cases, also the peak production month for unconventional wells.

The typical Permian horizontal well currently produces 830 B/D of oil during its second month of production, an all-time high, Abramov said. The pace traditionally has been set by the largest independents, which have benefitted from early entry into the basin, quick learning due to scale, and a number of high-grading opportunities given large acreage positions.

But a new development, Abramov said, is “record-high new well productivity” for the majors based on preliminary second-quarter production data. In fact, the majors “might have surpassed the top 10 public shale [independents] for the first time since 2014–2015.” ExxonMobil, Chevron, and BP all have extensive positions in the Permian.

jpt_2019_8_rystad_permian_new_production

 

A driver of horizontal well performance is the length of the productive interval, or perforated lateral length. The average perforated lateral length in the Permian increased to 8,500 ft in second-quarter 2019 from 5,000 ft in first-quarter 2013.

When new production per horizontal well is normalized to an 8,000-ft well, the most significant structural improvements in average normalized productivity occurred from 2013 to 2016. Things then flattened during 2017–2018 as more operators came into the basin and began developing newer, less mature acreage with lower well productivity.  

“Interestingly, we have been observing a new period of improvement since the second half of 2018 as a result of high-grading in the current capital discipline environment and an increasing share of acreage moving into field development mode,” Abramov said.

 

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IP is increasing alright - because of longer lateral length and higher cluster density/larger sand mass (normalised to length and sand productivity isn’t increasing)

Main trouble is with decline and amassed debt/diluted equity. Shall drilling to stop now - most (if not all) operators will be left deeply in red. Need higher oil price to and continues cost discipline to change current state, IMO. 

https://shaleprofile.com/2019/08/01/permian-update-through-april-2019/

184C7761-78AA-4430-9664-42E7E5CE9EA7.jpeg

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All that posturing about initial production is fine....what is the well doing two years, three years or five years down the road?

Longer laterals for higher IP also means a much higher cost and longer payout.

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10 hours ago, Douglas Buckland said:

All that posturing about initial production is fine....what is the well doing two years, three years or five years down the road?

Longer laterals for higher IP also means a much higher cost and longer payout.

Enno at @shaleprofile has an answer:

image.thumb.png.7cf568e1adbb366db31e76e398064dd7.png

If operator hasn't recovered investment in ~two years - it probably never will. Math seems to be simple - take produced oil, subtract share of land owner, multiply by realized oil price (it was substantially lower than WTI in Permian due to pipeline issue and oil quality), subtract cost of production and taxes and compare with cost of land, drilling, completion (frac is the major component; could >60% AFE) and the capital. No need to bother with NPV.

No wonder @Mike Shellman is skeptical:)

 

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New U.S. pipelines poised to start price war for shale shippers

 

https://finance.yahoo.com/news/u-pipelines-poised-start-price-175849672.html

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On 8/8/2019 at 6:37 AM, Douglas Buckland said:

All that posturing about initial production is fine....what is the well doing two years, three years or five years down the road?

Longer laterals for higher IP also means a much higher cost and longer payout.

Currently we receive royalties from 4 different companies on numerous wells in the Eagle Ford and Austin Chalk of South Texas. Some of these wells were drilled in the beginning of the Eagle Ford. So while I am not an expert of any kind in the oilfield I completely understand what these wells IP at, what they produce several years later, what they produce when they are re-fracked. Huge difference. I will pick on one of our oldest leases in the Eagle Ford. Royalty check first month for Lease X (not the real name) $697,000 royalty check. Fast forward several years  to last month and the royalty check for this lease was a total of $43K. Not bad but a huge difference after several years. These wells are in a top tier area of the Eagle Ford and have been re-fracked approximately 1.5 years ago. So Douglas I completely agree with your first statement. Facts dont lie.

While your second statement in essence is completely accurate in that longer laterals cost more and have a longer payout it is a little misleading. The first wells we had drilled were approximately 5k ft in length. Currently one of the majors that we are leased to only drill 10k ft or longer laterals due to the reduction in over all cost and increased acreage due to regulatory issues. Yes they will eventually need to perform some small lateral wells to get all the product out of the ground but long laterals are their current priority.

Combining leases to have longer laterals are much more efficient. So basically this company is combining 2 different leases that we have with them and instead of having 2 drilling pads, 2 vertical shafts, 2 access roads, 2 sets of tank batters, 2 separate sets of separators, gas and oil lines etc. they have one huge pad with one access road etc. We have numerous drilling pads, miles of pipeline easements and over a mile of very serious roads on several of our properties. I do not like all these pads, easements, roads and do not lease these facilities out cheap. So yes longer laterals are cheaper than short laterals.

Additionally there are the regulatory efficiencies to longer laterals such as less permits needed. I am probably off by a little on the number of feet but I believe the Rail Road Commission (yea that is the regulator authority here in Texas) requires 150 ft clearance between lease lines so by combining leases together that loss of 300 feet is recovered. May not sound like much but multiply 300 ft of play by numerous wells and we are talking significant product. 

On to fraking, just image the saving of only having to rig up all that frak equipment and run miles of portable water pipe to 2 locations as opposed to one. Quite a few other efficiencies for longer laterals but I will stop here because I am just beating this to death.      

We are next up to have 4-10k plus feet wells drilled on one huge pad that combines 2 of our leases so basically 4 wells that would have been 8 wells on 2 pads several years ago. Once the rig is setup it will not rig down until they have drilled all 4 wells. This will probably take less than 4 weeks not counting frak time which now takes several months. 5 years ago it took the same company 3 plus weeks to drill 1 5k ft well.

Douglas, I for one enjoy your posts and routinely agree with most of what you say. But it is hot as hell outside and my office is nice and cool so I decided to stay here in my cool office and enjoy the AC and reply. 

 

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