Sunday, February 17, 2013

Director, NDIC, Comments On December's Bakken Production

Kent alerted me to this article.

The Fargo Forum is reporting:
The state produced 768,853 barrels per day in December, a 4.6 percent increase from the previous month and a new all-time high, according to preliminary figures from the department.
Director Lynn Helms said the state added 123 new producing wells in December, enough to increase production as well as make up for November’s 2 percent drop in production, the first decline the state reported in 19 months.
Again, as noted earlier, a new metric:
Helms said he now can estimate that it takes about 90 new wells per month to sustain North Dakota’s current oil production and 100 or more new wells per month to increase production.
He also noted that he thinks rig count will increase in the spring:
Major operators in North Dakota have indicated they plan to bring 15 more drilling rigs into the state, likely beginning in May or June, Helms said.
That would increase the number of drilling rigs from Friday’s count of 182 to approximately 200. The record rig count was set in May 2012 at 218 rigs.
But most interesting, regarding the backlog of 413 wells that need to be completed (fracked) and referred to as "idle wells":
This spring, Helms said he expects to see more fracking crews mobilizing to catch up and reduce the idle well count to closer to 200.
At the link he also spoke about flaring, which I have noted earlier. 

Winter Cold: Same Old Same Old

Wind chill in Washington, DC, for the "global warming" march on the White House: 16 degrees F (-9 C). Well below freezing.

And I see another winter storm developing over the Bakken:
A storm system in the Northern Plains will produce snow and strong winds across portions of eastern Montana, the Dakotas and Minnesota through Monday. Winds will gust up to 45 mph in this area, with blowing snow contributing to blizzard conditions. Travel across this region will be hazardous with reduced visibilities and snow-covered roads. 
This link is a dynamic link and will change.

Disclaimer: I am not a professional weather person, and this is not a weather-related site. Do not make any changes in your travel plans or book ski tickets based on what you read here.

Daytona 500: History Is Made -- Danica Patrick Has The Pole Position

Jeff Gordon also in the front row.

WAWS Water At 13-Mile Corner

CRC provided the link.

Great story. KFYR out of Bismarck reporting:
The demand for water is bigger than ever in western North Dakota, as residential and industrial growth continues to flourish. Thanks to some unique water depots, help is officially on the way. These depots are part of the Western Area Water Supply Project being installed throughout the western half of the state. Unlike most state-run projects, this one is being paid for by the oil industry.

Water is for sale at the 13 Mile Corner and area truckers couldn't be happier.

"Oh this is extremely helpful having this here, it really shortens the distance us truck drivers have to go for water and it makes our turnaround so much faster," said truck driver Rick Ingraham.
Go to the link for some interesting additional data points.

This is a very big story; lots of implications. Key phrase in the article: "state-of-the-art" water depots.


This really was my favorite album at the time it came out:

Wah-Wah, George Harrison

A Nice Human Interest Story: From Riding The Rails to Working on the Rails

The Dickinson Press is reporting:
Scott Steskal hitched rides on freight trains to get to North Dakota’s oil boom.
Now the 51-year-old drives a train at a crude oil transloading facility and is getting his life on the right track.
“Until I got up here, my life was pretty much a wreck,” he said.
Steskal was living in Las Vegas with no job and no transportation when family members encouraged him to look into job opportunities in North Dakota.
He researched how to ride freight trains and found someone to mentor him on how to do it safely.
Steskal left Las Vegas in December 2010 and became what he calls a tramp, hopping on and off freight trains through several states to travel north. People he met during his trip gave him the “track name” of Jesse James.
Go to the link for the rest of the story.

But "researched how to ride freight trains....." that alone probably got him the job.

Don sent me the link. Much appreciated.

Coal To The Northwest Ports

February 18, 2013: it looks like Washington State is about ready to shut down. First, they don't want any more rail traffic if it means more coal to the ports; and, now, the Boeing aircraft engineers are getting ready to strike/walk off the job just when the 787 Dreamliner needs them most. The are voting this week. The article does not say when the votes will be counted. Perhaps Friday after the news cycle is over. 

Original Post

For those who enjoy maps, and I love maps, here is a map of proposed rail routes and ports in Oregon and Washington State for shipping coal from Montana and Wyoming. It may take a moment to load.

It accompanies an article in The Billings Gazette on new coal shipments to the northwest.

A New Poll: Was The Policy Decision to Kill the Keystone XL the Number One Reason For The All-Time High Gasoline Prices We Are Now Seeing?

Time for a new poll.

First the results of the current poll.

The question: Within a few months of production, even if gas is flared, mineral rights owners are paid for the flared gas at market rates (in ND).
  • Yes: 23%
  • No: 77%
I believe the "better" answer is "no." If I recall, North Dakota allows a 12-month grace period before requiring reimbursement for flared gas to be paid, and the state can grant a waiver extending it another six months. However, by 18 months, royalty owners should see reimbursement from flared gas. This is my understanding; not necessarily absolutely accurate. For most respondents, "18 months" is a bit more than "within a few months."

Now the new poll.

Long-time readers know that I never intended to post articles about the Keystone XL. When I first started the blog, I limited my oil and gas posts to the Bakken. But because of reader interest, I posted my first Keystone XL post a long, long time ago, saying I had no dog in that fight and had no interest in that story.

However, over time, it became a much bigger story than I thought it would ever become, and it has become a regular feature of the blog for any number of reasons.

Long-time readers also know that I have opined over and over the killing of the Keystone XL will not affect the price of gasoline in the short term (2012 - 2016) in the United States. There is a glut of US shale oil and plenty of global oil, making the Keystone XL unimportant at this time. At least that's what I've been saying for the past two years.

I am now convinced that I am very, very wrong.

I will post later why I think the policy decision to kill the Keystone is directly responsible for the historically highest gasoline prices on record for this time of the year. But before I do, a new poll.

Was the policy decision to kill the Keystone XL the number one reason for the all-time high gasoline prices we are now seeing, as reported by the Christian Science Monitor?

[Added, February 17, 2012, 12:48: "Obama rejects Keystone project from Canada to Texas," USA Today, January 18, 2012.
Russ Girling, president of TransCanada, the pipeline's builder, said the company would reapply for permitting and asked for the application to be processed in time to get the pipeline online by 2014.
Obama said House Republicans forced his decision by including a provision in last month's legislation for a short-term extension to the payroll tax cut that required him to either issue a permit to allow the 1,700-mile pipeline to be built or explain why it was not in the national interest by Feb. 21.]


30-second sound bite: Canadian oil sands needs condensate to ship (pipeline) bitumen (heavy oil). Those oil fields do not have adequate condensate; they will get it from the Bakken and the Eagle Ford.

30-second sound bite: I think my thoughts on the Keystone XL are very, very wrong. Maybe a stand-alone post on that if I get caught up. 

Background: what makes wet gas wet?

There is a series of articles -- three, to be exact -- on condensates appearing on the web

The series (linked below) is targeted for investors. Disclaimer: my blog is not an investment site. Do not make any investment decisions based on what you read here. These articles are linked because they help me understand the Bakken.

The author is a typical "newsletter" type-of-guy, but better than many, I suppose. He provides readers with lots of interesting "information" and then requires a paid subscription "for the rest of the story."

[Another "Condensate 101" course was posted in mid-January, 2013, and might be a better place to start before reading the series of stories coming up.]

The first at Oil & Gas Investments.

The second at Oil & Gas Investments.

The third, in SeekingAlpha.

The lede from the first article:
Condensate prices in Canada are soaring—now sitting some $14/barrel ABOVE WTI—making it the most valuable Canadian energy product.
It’s creating huge profits for the lucky few natural gas producers who have large condensate volumes in their production stream.Condensate is both a heavy natural gas liquid (NGL), and a super light oil, making it very versatile.
In Canada it’s used to dilute heavy oil from the oilsands, and fast increasing production there is driving condensate demand—and prices.Canadian production of condensate is flat, which is bullish in the face of oilsands growth.
Note:  he says Canadian condensates are priced at $14 above WTI. If true, I would assume pricing is similar for Bakken condensate.

From that same article:
From the Eagle Ford shale in Texas to the Bakken shale in North Dakota and up to the Montney shale in northern BC, oil and gas shales are producing major volumes of condensate.
Some data points from the second article:
In the United States, all this condensate is almost a problem. US refiners spent billions of dollars over the last decade to process more heavy oil. As a result they can’t really handle this light stuff.
In the oil sands, condensate is used as a diluent to ‘thin down’ bitumen – a thick, sludgy substance – so it will flow through pipelines. Since bitumen production is climbing steadily, condensate demand is on the rise. Supply is struggling to keep up.
Canada now uses some 275,000 barrels of condensate per day as diluent. Canadian producers churn out 165,000 barrels per day (bpd), meaning oil sands operators already rely on imports to fill a 110,000-bpd gap.
And finally, the third article, at his website, I suppose, but also in SeekingAlpha, as linked above.

Some data points:
The reason condensate is king in Canada is that oil sands producers need piles of this light oil to dilute their heavy bitumen for transport, and Canadian production can't keep up with demand.
Half of America's refineries lie along the Gulf Coast. With the ability to process 8 million barrels of crude oil every day, this industrial complex truly sets the tone for oil pricing across the country. And guess what? Gulf Coast refineries don't like condensate.
Refineries are picky beasts, each one only able to process crudes within a particular API range. The Gulf Coast army of refineries used to love light oil, but over the last 25 years the world burned through many of its high-quality deposits of light crude. That forced producers to shift towards heavier and sourer crudes. [This is why I believe my thoughts on the Keystone Xl are very, very wrong.]
The only way to feed condensate into these medium and heavy oil refineries is to mix the light oil with a heavier crude to produce a mid-weight blend. But even that is not ideal, because it turns out a mixture of heavy oil and condensate does not produce the same products as a straight crude of similar weight.
Canada needs condensate. US producers are flooded with the stuff and want to sell it to Canadian oil sands operators. The challenge is moving it.
The only pipeline currently moving condensate from the US into Canada is Enbridge's Southern Lights line, which runs from Illinois to Edmonton. It can move 180,000 barrels per day, which can more than handle the 110,000 bpd of condensate being imported now and Enbridge is proposing an expansion.
And more:
The hard part, the bottleneck, is getting it to Patoka, where it can enter Southern Lights. Patoka, it turns out, is not particularly close to the biggest condensate-producing shale in the US, which is the Eagle Ford basin in Texas.
There are ways. For example, Plains All American is using the Louisiana port of St. James as a staging post to route Eagle Ford condensate into the Capline pipeline for shipment to Patoka.
Others are using existing gathering networks to move condensate to Corpus Christi on the Texas Gulf Coast, where it is loaded onto barges and transported to St. James. Magellan Midstream Partners and Copano Energy are taking this one step further, extending one of Copano's pipes by 140 miles to Corpus Christi. That line should soon be moving 100,000 barrels of condensate a day.

Random Updating of Some Nice Wells From Last Year

In the process of going back and correcting a few typographical errors (in this case, misspelling "Williston"), I updated the July 2, 2012, daily activity report, and note some huge wells, including:

A nice example of minimal decline rate (for whatever reason; could be choked back; still flaring some gas); but note, significantly over 100K in less than 12 months and many of those months off-line much of the time:
  • 20812, 1,884, BR, Hammerhead 31-26MBH, Sand Creek, t4/12; cum 413K 8/18;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

These wells with a decline rate but look at the production. This Halverson well with 48K bbls in one month!
  • 21760, 1,776, Hess, CA-Halverson-154-95-0409H-1, t5/12; cum 430K 8/18; not hooked up to a natural gas line:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

The neighboring Halverson well with 148K in less than 8 months; in Hofflund field; not hooked up to a gas line yet:
  • 21761, 1,058, Hess, CA-Halverson-154-95-0409H-2, Hofflund, t6/12; cum 380K 8/18;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

This Oasis well with 112K but with a very erratic production profile:
  • 18855, 792, Oasis, Oasis Meiers 5692 11-19H, Alger, t2/12; cum 334K 8/18;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

And, last, but not least, this Hess well with 113K in less than a year; on a gas line, but flared a very tiny bit in the most recent month:
  • 21730, 992, Hess, GO-Stangeland-155-95-2128H-1, Capa; t5/12; cum 318K 8/18;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

The July 2, 2012, report, was particularly long for some reason, and includes a lot of great wells These four caught my eye for various reasons.

Looking at the flaring issue, my hunch is that if the state makes new rules on flaring too onerous, the oil companies will simply quit drilling in those fields with inadequate infrastructure as long as they have leases held by production. A good example is the Hofflund field above. It appears that entire field is held by production, but the infrastructure is lacking for natural gas gathering. If onerous flaring rules go into effect, expect to see a) monthly production across the board decline; and, b) drilling to stop completely in some fields. Companies might or might not stack rigs; they could move rigs where infrastructure is in-place and adequate.