This is truly staggering. We've been talking about this for more than a decade: rig efficiency. Where the hell have these folks been? These are experts? These are analysts. I even have a "rig efficiency" tag.
I bet these folks don't know we can spud a well and bring it to production and delivered to a refinery in less than thirty days.
And then to see some of the replies. OMG!
And we've come full circle. Back to the future. The Red Queen.
Link here. At link, click on the graphics for enlargement.
Disclaimer: this is not an investment site. Do not make any investment, financial, job, career, travel, or relationship decisions based on what you read here or think you may have read here.
Investing: I would never, never recommend anyone invest in energy companies, nor would I recommend anyone invest in anything. Everyone's situation is different.
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Rigs Matter; Rig Counts Not So Much
This has to do with production, not price of oil.
Of course rigs matter, but when any analyst or reader mentions the number of active rigs on any give day, my eyes glaze over (or roll). The "rig count" is a legacy metric held over from conventional and off-shore drilling. It has a diminished role in unconventional drilling or shale.
Unconventional drilling or shale? They can drill all the holes they want, but if they don't complete them, they don't mean squat. Except for a lot of wasted money, drilling the wells and not completing them.
Across the US shale basins, the important metric is the number of newly completed wells on any given day or any given week.
In the Bakken, specifically, much more important than the rig count, pretty much in this order:
After that, maybe the number of rigs. But probably not. I've probably forgotten something in that list of ten items.
The number of rigs are important in other respects, mostly in terms of measuring activity and providing jobs for roughnecks, geologists, and oil services companies. And that's incredibly important but that's not the issue here. And quit calling me Shirley.
In the Bakken, if all remaining twelve rigs were to quit drilling today and operators focused on completing all DUCs, and opening all shut-in wells, Bakken production would do just fine: link here.
If the state banned fracking today, Bakken production would fall precipitously.
This next February, watch the production, as fracking comes to a standstill.
Pre-Covid, there were about 2,500 wells off-line each month in the Bakken for operational reasons. That's more than twice the number of wells that will be drilled and completed this year.
In the past two months, the number of wells off-line in North Dakota:
Think about that, 7,070 wells off line in May, 2020. A terrible, terrible month. And yet, the state still saw a $10-million Legacy Fund deposit. How much money does the state really need?
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What Is The Optimum Number Of Rigs In North Dakota?
26.
That's it. Twenty-six. Twenty-six active rigs.
In the early days of the boom, the number of days for a single rig to spud one well, drill to total depth, and then move to spud the next well was 60 days.
Now? Six days.
Sure, a bit of hyperbole on both ends, but not much. Does anyone actually think there can be much improvement in the time it takes to drill a Bakken well:
Those are the best I've seen. Probably the expectation going in:
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Quality Of The Wells
Staggering.
See the EIA's July, 2020, dashboard.
Remember: some years ago, several operators opined that they would not drill a Bakken well if the crude oil EUR was not a million bbls. In the early days of the Bakken, the EURs averaged about 350,000 bbls crude oil.
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The Bakken: An Oil Play
The Bakken is an oil play and yet its new wells are outproducing the Permian even with natural gas. Again, see the dashboards.
The daughter wells in the Bakken are doing exponentially better than the parent wells. I can't speak to the Permian because I do not follow the Permian. Or the Eagle Ford, for that matter.
We've been at twelve active rigs for the past year (?) and production has gone from 1.5 million bbls to 800,000 bbls, and my hunch is that the number of active rigs will remain between 10 and 20 in the Bakken through the end of the year and production will gradually move up (unless Saudi Arabia floods the world with oil again and/or demand destruction worsens). But if the economy improves; oil demand improves; oil price improves, the number of active rigs in the Bakken will move very little, if any, and production will increase significantly.
So, we'll see.
About a year or so back, more and more operators were incorporating a 'stages per day' number in their presentations as a way of displaying increased productivity/efficiency in their operations.
Drilling footage per 24 hours is another commonly cited metric.
Seven [frac] stages per day is about the norm, with some touting 12 stages in a day as their record.
It is fairly routine for a frac spread to complete 3 to 5 wells simultaneously on a pad nowadays. At 40 stages per well, for illustration, a 4-well frac will be 160 stages over - maybe - 3 1/2 weeks. While this may be a more relevant criteria as regards near term future production, it is still but one of several factors.
Ultimately, price received (aka revenue) remains the dominant determining component.
Restricted output (choking back), temporary shut ins also figure into these projections.
Overall, it looks to me that this epochal, global Game of Chicken will greatly favor the US independent shale producers. Massive backlog of DUCS can be revenue producers fairly quickly at -relatively - minimal cost. Slashed CAPEX (new drilling) will greatly reduce ongoing expenses. Assets of the inefficient (Chesapeake kinda fits this slot) will be acquired by the better-run outfits, making them even stronger. Precarious times will not last, but the strong will certainly survive.Comment: I agree completely that revenue is the dominant determining component. What I find interesting is comparing conventional onshore vertical wells with tight, unconventional, horizontal wells. To the best of my knowledge -- this was going on before I started following the oil industry -- with onshore vertical drilling, once wells reached total depth they were brought on line fairly quickly. The industry really wasn't talking about DUCs. But with tight, unconventional horizontal wells, there were two components -- the vertical and the lateral. It didn't occur to a lot of folks early on that someday, horizontal wells might be drilled but not completed. That was a completely different twist. I find it quite fascinating.
Year on year, the U.S. count is down 701 rigs from last year's 967, with oil rigs down 600, gas rigs down 102, and miscellaneous rigs up one to two. [Down 73% oil and gas rigs year-over-year.]
The U.S. Offshore rig count is down 2 rigs at 11 and down 13 year-over-year, according to Baker Hughes.
Meanwhile, in Canada the rig count is down four rigs from last week to 17, with oil rigs down two to five and gas rigs down two at 12. The region is down 102 rigs from last year's 119, with oil rigs down 75 and gas rigs down 27.Shale production in the Bakken: we've been in the "manufacturing stage" for several years now. The "manufacturing stage" followed the boom. Name another manufacturing industry in which the number of production units decreases by 73% and production continues to set new records. This is what scares Saudi Arabia.
As Covid-19 shock waves reverberate across U.S. oil towns, perhaps nowhere is their speed and severity more apparent than in America’s newest shale powerhouse.
Just months ago, New Mexico, the third-biggest producer of U.S. oil, approved the state’s largest budget ever, paid for by an oil boom that made up 40% of the state’s revenues in 2019. Now that plan has been slashed by more than $600 million, affecting everything from pay raises for state workers to a program designed to provide free community college to state residents.
Oil-producing states across the U.S. are facing a double whammy with both drilling and overall consumer spending cut back by the pandemic. New Mexico, meanwhile, stands as exhibit A of this boom-to-bust dynamic, with the state’s revenue forecasts plunging and more than 4,600 workers in mining, most of which is oil and gas-related, claiming unemployment insurance in the week ended June 13.
“We were just starting to stand on two legs,” said Reilly White, a finance professor at the University of New Mexico. “All of that stuff that passed, and that we were expecting this year, oil was a big part of that. The rug has just been swept out from under us.”More:
Companies with operations in New Mexico, including Concho Resources Inc., Occidental Petroleum Corp. and Matador Resources Co., have all decreased the number of rigs they plan to run in the state this year. And many producers have also taken the unprecedented step of curtailing significant portions of their existing output.
Highly specialized mobile rigs are literally walking over the oil patch's collection of aging equipment - tamping down sales and profits in a burst of efficiency that's making some drillers victims of their own success.
Large oil field services companies deploy the pricey machines called walking rigs to grab customers from midsize drillers that have to stretch to afford replacing their drilling armadas with the new-generation gear.
But the market is getting tighter for drillers large and small, as producers embrace walking rigs - so-called for the massive mechanical feet that let them move among well sites - and other technologies that let them drill more wells and harvest more oil while spending less on oil field services.
Baker Hughes recently reported a 9 percent rise in the number of wells the average U.S. land drilling rig produced in the fourth quarter (2013), compared with the same period a year ago (2012).
U.S. oil production from tight formations increased in 2019, accounting for 64% of total U.S. crude oil production.
This share grew because of the increasing productivity of new wells that were brought online during 2019. Since 2007, the average first full month of oil production from new wells in regions tracked by the U.S. Energy Information Administration’s (EIA) Drilling Productivity Report (DPR) has increased. The growing initial production rates have helped oil production from tight formations to increase despite the slowdowns in drilling activity when oil prices fell between 2015 and 2016. Since 2017, recovering oil prices and more efficient production from new wells have helped producers cover costs of drilling, production, and the development of new technologies.
The average new well in each DPR region produced more oil in 2019 than wells drilled in previous years in those same regions. This trend has persisted for more than 10 consecutive years. More effective drilling techniques, including the increasing prevalence of hydraulic fracturing and horizontal drilling, have helped to increase these initial production rates. In particular, well productivity was improved because of the injection of more proppant during the hydraulic fracturing process and the ability to drill longer horizontal components (also known as laterals) and perforate more stages.
Increasing well productivity has supported crude oil production even in years such as 2015, when oil prices fell and rig counts dropped. In 2016, rig counts continued to decline sharply, and total U.S. crude oil production decreased for the first time in 10 years. Fewer wells were drilled; however, those that were drilled were drilled more quickly and located in more productive areas, which led to increasing per-well production.
Every Friday, the Baker Hughes oil and natural gas rig count gets released. This is vital field information that energy analysts eagerly await. In essence, the count is supposed to convey the current thinking of the U.S. oil and gas industry. As it is supposed to go, higher oil prices mean higher rig counts which mean higher production. And in the opposite direction, lower prices mean less rigs and falling production. While it is true that more rigs usually enter the fields when prices go up, it can take months of higher prices before drillers are confident enough to bring additional rigs into service. And there is also a lag time with dropping prices, not immediately dragging the rig count lower. Many times lower prices just mean removing the less efficient rigs from the field.The end:
Most can agree that we cannot really blame analysts for being so wrong about the shale revolution, a deficiency likely to continue on into the coming decade.
Going back to 2007, for instance, shale was not even being mentioned as a potential source of major new supply. While probably growing slower in 2020, the industry has transformed global energy markets in ways never thought possible – not even by the oil and gas companies themselves. This helps explain why the IEA forecasts that the U.S. will account for 85% of new global crude output and 35% of new natural gas through 2030. For finances, WTI prices sticking above $65 or $70 would be just the boost the shale industry needs. Ultimately, it will be a burgeoning U.S. export business that will mandate new output. The EIA has domestic gas demand rising 1-2% per year for decades to come, while the country’s oil use will remain flat or even decline slightly.Go to the linked article for everything in between.
Most can agree that we cannot really blame analysts for being so wrong about the shale revolution, a deficiency likely to continue on into the coming decade."... being so wrong ... a deficiency likely to continue on into the coming decade."
Continued production in Oklahoma's SCOOP-STACK demonstrates how tracking rig count to determine production swings has become an antiquated practice in some US shale plays.
For example, crude oil production in the SCOOP-STACK recently reached annual highs of 488,000 b/d even as rigs continued to plummet to new lows last seen in 2016.
While producers had more than 100 rigs deployed across the SCOOP-STACK in January, the number has since fallen to 44 rigs.
While tracking rigs used to be a key indication of where basin production would head in the near-term future, SCOOP-STACK operators have proven in 2019 this modeling concept does not always apply, as the region is expected to grow production 7% year over year, while rigs are down 60% year to date from the most recent drilling data by Enverus.
While well-level efficiencies are a key contributor toward understanding production gains or losses, the SCOOP-STACK happened to significantly draw from their built drilled-but-uncompleted (DUC) inventory for most of 2019, as heightened completion activity from January through May helped operators grow production.
Moving into 2020, Platts Analytics is forecasting the SCOOP-STACK to grow by 11,000 b/d, as operators such as Continental Resources and Encana can continue to utilize the same strategy developed in 2019.
For the oilfield services industry, it’s no longer about merely navigating a downturn. It’s now about survival.
Five years after crude began its plunge to less than $30 a barrel from more than $100, the companies that drill and frack wells are living in a new world. The producers they work for have become increasingly efficient and cost-conscious, reacting to shareholder demands for payback and a crude market that’s recovered only part of that brutal decline.
Meanwhile, the service companies that handed out discounts in the downturn are barely holding on. Schlumberger Ltd. and Halliburton Co., the two biggest, have each fallen by more than 65% since crude started tumbling, and Weatherford International Plc on Monday filed for bankruptcy. Contrast that with the oil producers, collectively down less than 50%.
When crude began recovering in March 2016, the servicers started refortifying. But with their customers keeping a lid on spending, the gear began to pile up. In February, Rystad Energy, an industry consultant, estimated that supplies of U.S. fracking gear -- the pumps that blast water, sand and chemicals underground to release crude in what has become the most expensive part of drilling -- will exceed demand by about 68% by year’s end.
At the same time, producers have enjoyed an output boom in recent years, doing more with less by using new methods and technology. Shortened horizontal drilling times and longer laterals that require fewer wells to be drilled are taking a toll on servicers.
In June 2014, the U.S. pumped 8.4 million barrels of crude using 1,545 drilling rigs. Last month, it produced about 12.2 million barrels, 45% more, with just 788 rigs.Pretty much says it all.
Rigs matter eventually. Even if they have gotten better. Even if there are some DUCs to work off.
I calculate we need about 40 rigs to maintain production.
DUCs are fine, but they are inventory. If you use them up, it's like draining your savings account. If can float you for a while. But eventually, you need to be bringing in as much income as you spend. So, when you look at long term sustainability, I would just ignore DUCs.
Looking at EIA Drilling Productivity Report for Bakken, I calculate about 40 rigs are needed to maintain production near current (1.4 MM bopd) level.
The way to do the calculation is explained by EIA and is pretty simple:
Rigs*(new oil/rig) + base decline = 0
Looking at the EIA charts:
https://www.eia.gov/petroleum/drilling/pdf/bakken.pdf
First panel (upper right) shows the new oil/rig is ~1400 bopd/month/rig. Next two panels directly below show the base decline is running about 67,000 bopd/month.
Doing the high school algebra and solving for rigs as the unknown:
rigs = 67,000/1400 = 47.8 rigs
Note, however, that when you lose rigs, you tend to pull the LESS capable rigs first (mechanically, crew experience, and more importantly rigs running in the less desirable areas like Divide County, etc.). So there is always an effect of rigs getting more efficient as the numbers get lower.
It's like a class's average height getting larger, when you eliminate the shorter third of the students. You didn't actually make any students taller. But the average got higher because of cutting in a non-random manner.
So given all that, it would be something less than 48. I'm saying 40 as a guess, but it might be slightly higher or lower. Don't shoot me if it ends up being 45 or 35.
There is also another effect that takes place during downturns or plateaus. That is that the decline rate gets gentler as the percentage of new wells drops. (This happens during downturns or flat-turns, since less completions are done per month.) This has no immediate effect the first month of a big downturn, but over a year or two it can be substantial...it can lead to "less Red Queen" which means less rigs are needed just to fight shale decline. [The Rystad presentations on the video show this very nicely for the Permian...it's base decline went down from 2014 to 2016.] This also occurred in the Haynesville where 30 rigs were holding production flat (down from 200 at the peak, during growth).
Other effects that can happen over time include technology improvement (practice, efficiency, completion improvement, knowing where better land is), but they also fight depletion of the best rocks (look at EOG using up the Parshall). In any case, I think both of these effects are more long term and tend to offset each other.
Net/net: sure, dropping a rig or two is no big deal. But if we get into the 40s, we will be hurting for growth and in the 30s probably oil production will shrink.
| $58.02* | 12/11/2017 | 12/11/2016 | 12/11/2015 | 12/11/2014 | 12/11/2013 |
|---|---|---|---|---|---|
| Active Rigs | 52 | 40 | 65 | 186 | 192 |
