EIA Dashboards For May, 2020

EIA dashboards for May, 2020, have posted:

• EIA pdf, Bakken: https://www.eia.gov/petroleum/drilling/pdf/bakken.pdf
• EIA, pdf, Permian: https://www.eia.gov/petroleum/drilling/pdf/permian.pdf
• EIA, pdf, Eagle Ford: https://www.eia.gov/petroleum/drilling/pdf/eagleford.pdf

The Eagle Ford is a monster. Wow, it is truly amazing.

This Headline Worth 10,000 Words -- May 17, 2020

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Bob Jones Park

Southlake, Texas

May 17, 2020

Update On Vaca Muerta -- December 4, 2018

Another reason why I love to blog. Because of the blog, I know a little bit about the Vaca Muerta; it's tracked here through a link at the sidebar at the right. The Bakken, at 1.3 million bopd, also puts the production goal in the graphic below in perspective:

North Dakota wells, including legacy wells going back decades, currently average just under 100 bbls/well/day. This includes a lot of old legacy wells which produce very, very little.

But let's use the 100 bbs/well/day as a starting point.

60,000 bopd / 100bbls = 600 wells.

$2.3 billion / 600 wells = $4 million / well.

If these are all new wells with production that average much better than 100 bbs / well, then significantly fewer wells and higher cost per well.

Coming at the data from a different direction, if each well costs about $10 million, then we have 230 wells, or 260 bopd per well, which seems about right considering these would be "new" wells producing at the high end of production prior to the typical tight oil decline rate setting in.

Regardless, 60,000 bopd is literally a drop in the bucket compared to global production / demand of 100 million bopd.

How Good Are The "New" Bakken Wells? An Old Graphic Is Fairly Staggering -- November 26, 2018

Re-posting from November 21, 2018.

I wasn't sure if I would ever see this: a reversal in the downward trend of the average amount of oil being produced by North Dakota wells.

After a peak in the early days of the boom, the daily production per well in North Dakota began to fall, hitting an all-time (recent) low of 72 bbls/well/day. I was curious if/when it would level out and if it did level out, at what amount would it plateau?

Well, lookeee here --- after several years of steady decline, the average amount of oil being produced per each North Dakota well increased in the most recent reporting period.

While looking for something else, I ran across this graphic from 2017:

Visually, the graph below is much more impressive than the spreadsheet above.

Note that in the graph below, "91," the current average daily well production is almost off the chart.

A number of observations could be made regarding the graph. The most obvious one: shale operators can respond very quickly to changes in WTI pricing. Note how the operators cut back on initial production during the Saudi Surge.

Barrels Of Oil Per Well Per Month In The Bakken -- May 14, 2018

After posting this earlier, I was curious how production / well in the Bakken was trending (see that data below the graphic):

B is for Bakken. B is for Best. Bakken is the top producer of crude oil among US shale plays -- ranked by "productivity of new wells." This has been previously posted.

Link here: barrels of crude oil per well per day -- average (obviously):

• 2018, two months of data: 84 bbls of crude oil / well / day
• 2017: 79 
• 2016: 80
• 2015: 96
• 2014: 101
• 2013: 96
• 2012: 92
• 2011: 75
• 2010: 65
• 2009: 52
• 2008: 44
• 2007: 34
• 2006: 33
• 2005: 30

US Shale Frackers Eye World Conquest -- One Year Ago -- The Telegraph -- August 23, 2017

This is probably as good a "look-back" as I've seen, from The [London] Telegraph. Archived.

Remember: this article is from a year ago, during the early stages of the "depression."

It's a long article and covers many areas, so let's go through some of the data points with my comments thrown in.

Most remarkable prognostication from the article, from Mark Papa, "a legendary figure in the shale fraternity and now at Riverstone Holdings": 

“I can see a case where US shale is the biggest supplier of oil in the world by 2020. We could turn the whole thing on its ear, producing 13-14m b/d. But it will be really ugly getting through this valley,” he said. 

Most interesting comment from the article, also from Mark Papa:

Mr Papa said it will not be long before engineers work out how to double the efficiency of shale extraction to the 50 percent levels seen in conventional oil wells. "It'll probably come in the next ten years. That's the next big break-through," he said.

For newbies, as I understand it, Mr Papa is talking about "primary production" and does not include enhanced oil recovery using waterflooding or CO2 injection.

This raises the question: what is the current primary production estimated to be in the Bakken? At the beginning of the boom, it was widely accepted that primary production would range between 1 and 3 percent. For a 500-billion bbl original-oil-in-place reservoir, that worked out to 5 to 15 billion bbls.

Around 2014 or so, Whiting and others were suggesting that operators were achieving 7% primary production in the Bakken and reading between the lines, it appeared that some operators might have been achieving as much as 12% or at least trying to hit that target.

At 10% primary production, a 500-billion bbl original-oil-in-place reservoir works out to 50 billion bbls of recoverable oil.

Currently, the Bakken is producing about 350 million bbls annually, or 1 billion bbls every three years. Unfettered, Bentek estimated (and some continue to estimate) that the Bakken can produce 2.2 million bbls daily if the "price was right."

The second most interesting comment from the article: I vividly recall analysts saying that it was impossible for frackers to "turn on a dime," that it would take months for frackers to spud a well and bring it to production. I remember that vividly because I was not seeing that in the Bakken. From spud to production, operators could measure it in days -- generally about 30 days. And bringing in more rigs was not all that difficult. The biggest problem for the Bakken was competition from the Permian for skilled work crews but with things starting to turn a bit sour in the Permian, the Bakken may have some relief. But I digress. From the article:

"Restarting production may be easier than people think. Everything is ready to go. There are plenty of rigs. All the ingredients are there. There is a lot of money looking for the bottom of the cycle, waiting to get back in," he said. 

In the first two or three years of the Bakken boom, there was minimal infrastructure and constrained takeaway capacity. Both of those have been resolved.

Not mentioned in the article, in the Bakken alone:

• 850 DUCs
• 1,500 wells that are shut in for various reasons

At the end of this quote, IHS was thinking specifically of the Bakken, but since 2016, everything changed when the DAPL came on line (early 2017):

IHS said there are three groups of 'invisible barrels' likely to bear the brunt as the market stabilizes: small-scale 'stripper wells' of around 2m b/d, half of them in the US; those with high-fixed costs in North Sea and the Gulf of Mexico that are going into steeper decline; and those in remote locations or with long pipelines, and a $10-$12 disadvantage. "

They are in the eye of the storm," it said. 

Hess disagrees: 

The great unknown for world oil markets is how fast the frackers will come back. John Hess says it will take two years once prices recover.

"It is a big logistical undertaking. You've got to mobilize rigs and find people. Assets need permits in the US, and that takes 90 days," he said. "Balance sheets are in disrepair and there is too much debt. The high-yield market has basically dried up and that was the primary source of financing for the shale boom. Debt agencies are in a panic and running everything through $30 oil for the next few years," he said. 

I think where Hess and I disagree has to do with the definition of "recover." It may take two years for E&Ps to return to historical levels of prosperity (as measured by share price or market capitalization) but it certainly won't take two years to see an incredible rush back into the Bakken if oil prices a) began to trend toward $60; and, b) tea leaves suggest that the trend would continue.

Possibly the most incorrect prognostication:

Scott Sheffield, head of Pioneer, expects trouble in the Eagle Ford and Bakken fields, but it is a different story in the lucrative Permian Basin of West Texas, the "crown jewel" holding steady at 2m b/d even at current prices. He claims it is as big as the giant Ghawar field in Saudi Arabia, and could eventually produce 6m b/d. 

I agree that production will remain steady (or grow) in the Permian, but it may be more financially challenging than first expected. Paying $60,000/acre in an era of "lower for longer" is not going to cut it, as BHP found out.

Break-evens for US operators: no one knows. The "number" is all over the place. Everyone agrees that "very few things make sense at $30. It's better to leave the oil in the ground."

David Hager, head of Devon Energy, said shale frackers have slashed cuts costs way more than outsiders generally realize since the heady days of the boom, when service fees and wages were rocketing.

"A lot of plays work at $45-$50, and the vast majority from $55-$60. They certainly don't need $90," he said.

This is optimistic. A study by Rystad consultants in Norway puts the break-even price at $68, but nobody knows for sure and frackers disagree among themselves.

Shake-out:  again, Mark Papa -- Mr Papa said the 70 percent crash in oil prices since mid-2014 will wipe out those companies that leveraged to the hilt betting that crude prices would stay above $100 forever.

BHP Billiton is a great example. The company itself agrees that it overpaid when it spent $20 billion to enter US shale plays (the Eagle Ford and the Permian), previously posted/linked. Only because of its size and other mining businesses did BHP survive (and thrive, for that matter).

Re-Balancing: perhaps by end of 2016, into 2017, but difficult to predict. This is what caught my eye, and many readers say the same thing. A new bust-boom cycle:

Mr Papa expects the global balance of supply and demand to tighten by 1.6m b/d this year. This would mop up the glut, before gradually eating into record stocks next year.

"The market is going to grow to 100m b/d. Where is the quantity going to come from? Capital spending on mega-projects has stopped cold,” he said.

“I can see a case where US shale is the biggest supplier of oil in the world by 2020. We could turn the whole thing on its ear, producing 13-14m b/d. But it will be really ugly getting through this valley,” he said.

See my most current estimates regarding "re-balancing" at this post.

By the way, I disagree with Mark Papa on this point: 

"The market is going to grow to 100m b/d. Where is the quantity going to come from? Capital spending on mega-projects has stopped cold,” he said.

The tea leaves suggest there is more than enough oil out there to preclude that concern. But the tea leaves also suggest I am in the distinct minority. Most agree that shale cannot make up for all the off-shore CAPEX that has been deferred or canceled. The reason I disagree: Mideast potential, especially Iraq. Much could be written but perhaps for a different day.

Not just shale. 

"Most companies will survive to take advantage of the recovery. We will ramp up, stay alive, meet the challenge, and look forward to a brighter day. It is not just shale that doesn't work at today's prices, nothing much at all works," said Mr Hager.

I did not post it but there was a recent article suggesting that "stripper wells" are returning. Operators that had shut down stripper well operations are are now returning. I didn't post the story because it seemed to be a press release from oil companies in California where fracking is not panning out for political and geologic reasons. But if I'm wrong, and strippers are coming back, that speaks volumes for the oil sector.

Not mentioned in the article: fracking strategies. Sand is getting more expensive; ceramics remain very expensive. The trend toward ever-increasing amounts of proppant to complete a well seems to be coming to an end. Much more sand is being used, but more sand is being mined, and, either God or nature again seems to smile on the US frackers: huge amounts of fracking sand have been discovered in west Texas, in/near the Permian. Rail won't be required; truckers will do the job. Ceramics appears to be "out" -- too expensive and experience suggests sand does just as well. All those concerns about sand "not holding up" may have been more marketing than real. The big change in sand has to do with size of sand. Operators are going to "smaller" sand.

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Addendum

Playing Around With Numbers

In the examples below, one can pick whatever numbers in bold one wants.


The North Dakota Bakken (middle Bakken plus Three Forks first bench)

• Williston to Minot: 120 miles
• Williston to Belfield: 100 miles
• 100 miles x 100 miles = 10,000 square miles -- the North Dakota Bakken

640 acres/square mile = 6.4 million acres

5,000 1280-acre drilling units

500 billion bbl original-oil-in-place reservoir

500 billion bbls OOIP / 6,400,000 acres = 78,125 bbls OOIP/acre

78,125 bbls OOIP/acre x  1280 acres/drilling unit = 100 million bbls OOIP / 1280-acre drilling unit
500 billion bbls OOIP / 5,000 1280-acre drilling units = 100 million bbls OOIP / 1280-acre drilling unit

12 wells / 1280-acre drilling unit

100 million bbls OOIP x 7% production rate = 7 million bbls recoverable oil / 1280-acre drilling unit
7 million bbs / 12 wells = 583,333 bbls / well

Summary: at 7% production rate across the middle Bakken/Three Forks first bench yields:  583,333 bbls/well

Whether one agrees with the assumptions or not (the numbers in bold) it is amazing that the law of large numbers seems to work. I think everyone agrees that EURs of 600,000 bbls is not unrealistic (yes, I know there are a lot of poor Bakken wells out there, but one can also argue that a lot of those poorer Bakken wells were drilled under less than optimal conditions, beginning with poor understanding of the geology and extending through inexperienced roughnecks.

If, in fact, operators are approaching 14% productivity rate in the Bakken, then one can expect million-bbl EURs.

Idle chatter but it helps me validate OOIP estimates; company talk about production rates; and, EURs of wells that are being drilled over time.

Top 20 Fields In The Williston Basin -- August, 2016 Data -- October 13, 2016

Field	July 2016 Production	July Wells	July Oil/Well/Month	Percent Change June-to-July	August 2016 Production	August Wells	AugustOil/Well/Month	Percent Change July -to-August
Sanish	1,334,131	601	2,220		1,357,449	601	2,259	1.75%
Parshall	1,219,070	438	2,783		1,166,153	438	2,662	-4.34%
Grail	1,031,304	178	5,794	6.08%	907,322	178	5,097	-12.02%
Corral Creek	856,387	148	5,786	4.67%	828,103	148	5,595	-3.30%
Antelope-Sanish	848,633	167	5,082	-0.89%	770,322	167	4,613	-9.23%
Alger	732,454	312	2,348		648,600	312	2,079	-11.45%
Blue Buttes	681,982	143	4,769	6.74%	636,129	143	4,448	-6.72%
Spotted Horn	680,174	86	7,909	7.75%	617,749	88	7,020	-11.24%
Banks	666,709	182	3,663		610,666	186	3,283	-10.38%
Siverston	625,387	223	2,804		568,046	223	2,547	-9.17%
Big Bend	526,998	116	4,543	4.47%	518,988	116	4,474	-1.52%
Heart Butte	528,206	179	2,951		510,456	179	2,852	-3.36%
Reunion Bay	551,281	149	3,700		509,052	151	3,371	-8.88%
Camp	589,582	132	4,467	16.57%	490,751	137	3,582	-19.80%
Van Hook	541,306	181	2,991		487,636	185	2,636	-11.86%
Truax	497,181	171	2,907		451,462	171	2,640	-9.20%
McGregory Buttes	453,413	95	4,773	15.47%	448,183	95	4,718	-1.15%
Alkali Creek	483,117	141	3,426		417,891	143	2,922	-14.71%
Robinson Lake	410,682	172	2,388		394,638	172	2,294	-3.91%
East Fork	394,824	104	3,796		381,196	104	3,665	-3.45%

Top twenty oil fields based on average amount of oil / well / for the month of August -- second to last column:

Field	July 2016 Production	July Wells	July Oil/Well/Month	Percent Change June-to-July	August 2016 Production	August Wells	AugustOil/Well/Month	Percent Change July -to-August
Spotted Horn	680,174	86	7,909	7.75%	617,749	88	7,020	-11.24%
Long Creek	197,362	27	7,310	-13.45%	176,932	27	6,553	-10.35%
Corral Creek	856,387	148	5,786	4.67%	828,103	148	5,595	-3.30%
Grail	1,031,304	178	5,794	6.08%	907,322	178	5,097	-12.02%
Lost Bridge	321,767	57	5,645	19.28%	289,573	57	5,080	-10.01%
Pershing	209,341	39	5,368	3.48%	187,481	39	4,807	-10.44%
Bear Den	202,143	44	4,594	-8.07%	207,848	44	4,724	2.82%
McGregory Buttes	453,413	95	4,773	15.47%	448,183	95	4,718	-1.15%
Antelope-Sanish	848,633	167	5,082	-0.89%	770,322	167	4,613	-9.23%
Big Bend	526,998	116	4,543	4.47%	518,988	116	4,474	-1.52%
Blue Buttes	681,982	143	4,769	6.74%	636,129	143	4,448	-6.72%
Camel Butte	142,098	34	4,179	7.02%	147,928	34	4,351	4.10%
Bear Creek	97,805	27	3,622		115,625	27	4,282	18.22%
Eagle Nest	339,938	78	4,358	17.62%	315,273	79	3,991	-8.43%
Johnson Corner	121,544	31	3,921	-1.45%	120,996	31	3,903	-0.45%
North Fork	93,620	43	2,177		217,776	56	3,889	78.62%
Crazy Man Creek	191,066	44	4,342	-9.69%	162,043	44	3,683	-15.19%
Williston	85,265	21	4,060	15.93%	77,247	21	3,678	-9.40%
East Fork	394,824	104	3,796		381,196	104	3,665	-3.45%
Moccasin Creek	234,313	59	3,971	7.57%	215,360	59	3,650	-8.09%

In the table above (the second table), note that, with exception of two fields, the number of wells stayed the same. The exceptions were North Fork and Eagle Nest. The increased number of wells in Eagle Nest was trivial, but the increased number of wells in North Fork was remarkable, increasing from 43 in July, 2016, to 56 in August, 2016.

Note the increase in production in North Fork, up almost 80%, from 93,620 bbls in the month of July to almost 220,000 bbls in the month of August.