PN Bakken: ‘Wake-up call’

North Dakota has now recorded back-to-back months in which the massive Bakken petroleum system has failed to live up to production expectations.

Reasons behind lackluster performances in October and especially in November have led the state’s top oil man, Lynn Helms, to issue a “wake-up call” for those who believed the good times would continue unabated.

“We’ve gotten very used to the increase in production, almost regardless of what was happening out there,” Helms, director of the Department of Mineral Resources, said in a Jan. 11 conference call.

For the first time in 19 months, North Dakota’s oil production declined in November, the most recent month for which production statistics are available. Output fell 2.2 percent, from an average 749,212 barrels per day in October to 733,078 bpd in November.

Winter storm Brutus was blamed for most of the November decline. It brought operations to a halt for several days and, more telling, exposed infrastructure shortcomings, in particular the heavy dependence on trucks and a snow and ice-vulnerable road system to transport fracking water and other materials to drill sites and production to rail and pipeline terminals. “When you encounter something like that winter storm, you have to shut wells in, you can’t use the oil,” Helms said, noting that the number of new wells waiting to be hydraulically fractured and put on production in November jumped by 50 to 410 because of bad weather.

The huge backlog in hydraulic fracturing jobs has evolved into a major headache for the department, Helms said, adding that during the first half of 2012, service companies assured the state that they would be “bringing in lots and lots of workers and equipment” to the Williston Basin to catch up on the work. Several of the largest companies alone hired an additional 1,500 workers to address the problem.

“And the trend seemed to be going in the right direction,” Helms said. “Now we have two (slow) months in a row as we enter colder weather, where fracking has really slowed up. We may be finding ourselves in a paradigm where the winter months are much more difficult than anybody had anticipated. And it is a serious concern.” Ironically, as Helms answered questions from reporters on the Web and live from the state capitol in Bismarck, N.D., much of the Midwest was being hammered by yet another snowstorm. And though it appeared the brunt of this storm was going to skirt North Dakota’s oil patch, “I think it could have some impact on January production,” Helms said.

North Dakota also has become a state that’s “all about Bakken production,” with most of the oil patch concentrated in a “fairly tight” four-county area, making it particularly susceptible to disruptions, Helms said. Williams County caught the worst of the November storm, experiencing the snowiest day in more than 110 years.

“So, (it’s) unlike the state of Texas where they have Eagle Ford, they have the Permian Basin, and they have East Texas all producing,” Helms said. “All our eggs are sort of in one basket. That’s why I call it a wake-up call. We are so in tune with Bakken and Three Forks development, so dependent on truck transportation, and so dependent on hydraulic fracturing.” Underground pipelines to transport warm fracking water to drill sites, rather than by truck, would help alleviate the problem, Helms said. He noted that the state is working on legislation to establish rights of way and easements, “so we can bury those pipes six feet underground.”

North Dakota’s oil production did increase in October, but at a much slower pace compared to previous months. Factors that contributed to October’s underperformance also contributed to November’s decline — operators transitioning to higher efficiency drilling rigs and implementing cost-cutting measures at the end of their 2012 capital budgets.

“Rapidly escalating well costs consumed capital spending budgets faster than many companies anticipated, and uncertainty surrounding future federal policies on taxation and hydraulic fracturing impacted capital investment decisions,” Helms said in his January “Director’s Cut” report.

The Williston Basin drilling rig count averaged 184 in December, down from 186 in November and 188 in October. The count stood at 181 on Dec. 11. The all-time high of 218 rigs was reached on May 29, 2012. The utilization rate for rigs capable of 20,000-plus feet is down to about 80 percent, and for shallow well rigs — to 7,000 feet or less — utilization remains about 60 percent, according to the department.

There were 8,101 producing wells in November compared to 8,035 in October, a gain of 66 wells.

Drilling permits issued in December stood at 154, down from 211 in November and 370 in October.

“Drilling permit activity was lower in December due to the number of holidays,” Helms noted in his report. “We continue to have a sufficient permit inventory to accommodate more multi-well pads, the desire to not build locations during winter, and the time required to publish hydraulic fracturing rules if required.”

Crude oil takeaway capacity reportedly remains adequate to keep up with a majority of oil now shipped by rail to East Coast, Gulf Coast, and West Coast destinations.

North Dakota leasing activity is said to be extremely slow, mostly renewals and top leases in the Bakken-Three Forks area. Williston Basin natural gas production of 782,078 thousand cubic feet (mcf) per day in November was down slightly from October’s 797,785 mcf per day.

Construction of processing plants and gathering systems was also severely affected by weather, Helms said, noting that U.S. natural gas storage is up to 11 percent above the five-year average.

“This indicates continuing low prices for the foreseeable future,” he added. “North Dakota shallow gas exploration is not economic at near term gas prices.”

Natural gas delivered to Northern Border at Watford City, N.D., is down to $2.85 per mcf, resulting in a current oil-to-gas price ratio of 31 to 1. But the high liquids content makes gathering and processing of Bakken gas economic. Additions to gathering and processing capacity are helping with the percentage of gas flared dropping to 29 percent. The historical high was 36 percent in September 2011.

North Dakota sweet crude averaged $77.09 per barrel in December, compared to $80.86 in November and $87.00 in October. The price stood at $87.25 per barrel on Jan. 11. The all-time high reached $136.29 on July 3, 2008. Meanwhile, the number of rigs actively drilling on federal surface in the Dakota Prairie Grasslands was reported to be down to zero. But the number of rigs drilling on the Fort Berthold Reservation has increased to 28 with four on fee lands and 24 on trust lands.

There are now 793 active wells — 96 on trust lands and 697 on fee lands — producing 135,380 barrels of oil per day — 6,730 from trust lands and 128,650 from fee lands. There are 113 wells waiting on completion.

Additionally, there are 291 approved drilling permits — 266 on trust lands and 25 on fee lands, with 1,479 additional potential future wells — 1,426 on trust lands and 53 on fee lands.

In other developments draft Bureau of Land Management, BLM, regulations for hydraulic fracturing on federal lands have been published in the Federal Register. The comment period closed on Sept. 10, 2012. BLM received over 170,000 comments and has indicated a final rule will be published mid-2013.

Also, Draft Environmental Protection Agency, EPA, guidance for permitting hydraulic fracturing using diesel fuel has been published. The comment period closed on Aug. 23, 2012. EPA received over 97,000 comments and has set a target of spring 2013 for final guidance document publication.

From above “That’s just the way it is.” And it’s that way far more severely for horizontals.

On the graph, horizontals die vertically. Well known reality carefully NOT talked about by those who have to hype the drilling of the next well.

As for nat gas, the word is 40% of nat gas produced in the Bakken is flared. They are drilling so frantically and desperately fast to overcome that down escalator that they dare not pause to lay capture infrastructure.

And here is a delightful photo to prove it. See if you can find the huge city on a map making that huge swath of (gas flare) light in western NoDak on a map, or south of Austin where the Eagleford is flaring.

http://media.zenfs.com/en_us/News/ap_webfeeds/32af7f4336fedb22220f6a7067009098.jpg

That’s what desperate, frantic drilling looks like, folks, and it’s not going to get any better. Ever.

My suspicions lie with there is likely very little gas produced from the typical Bakken well compared to the oil. That gives little chance for profit on a natural gas payoff for the investment in all the gathering lines.

They are getting some extensions in the permitting, but that is not going to last forever. They are going to be forced to start recovering that gas.

PN Bakken: ND’s gas woes
http://www.freerepublic.com/focus/f-news/2965819/posts
Week of December 02, 2012

Finding a solution to North Dakota’s ballooning gas-flaring problem will require a “very difficult balancing act” that could take until the end of the decade to work out.

“We have to balance the ability to build gathering systems against the waste that takes place with flaring,” Lynn Helms, director of the state’s Department of Mineral Resources, said in a Nov. 20 Webcast.

“So we’re looking at toward the end of this decade before we really get this flaring dynamic under control.”

Gas production continues to increase at a faster rate than the more desirable crude oil, setting yet another production record in September at 793,546 thousand cubic feet, mcf, per day. Average oil output for the month was 728,494 barrels per day, also a record.

I don't think the major pipelines is the problem, it is the multitude of gathering lines that are not in place.

I don't think the big lines coming out of Canada running through the area around the Bakken run at full capacity anymore. Our Natural Gas imports from Canada have fallen a bit without any real loss in pipeline capacity.

For that data:

U.S. Natural Gas Pipeline Imports From Canada
http://www.eia.gov/dnav/ng/hist/n9102cn2m.htm

Hey Dusty,

The point was not anything envirowacko. Don’t care about that.

Don’t really even care about the waste.

But I do care about the hype. This “story” is being leaned on for BS projections of US energy independence (always bogus phrasing since only oil brings food to grocery store shelves, and only oil drives the 400 Hp tractors that get it planted in 50,000 acres before planting season expires).

Sorry, digression. This field is being leaned on and hyped as the salvation of US oil production and elimination of US oil imports and it’s BS. Oil is measured in barrels/day. Not in barrels. It doesn’t matter what’s under the ground there if the rate it comes up peaks and falls.

There is some fracking going on in West Texas now, too, and the Eagleford is on that photo. They aren’t immune to geology. Their horizontals die vertically, too. You’re in the biz so you KNOW California is in freefall. You KNOW Oklahoma is down about 85% from the 1930s. You KNOW Illinois oil output is down a similar 75% from the 1930s. This isn’t going to reverse. This is forever. These shale plays are a blip on the relentless down escalator.

“I agree I’m just saying it takes time to catch up.”

It does, and you have that time available on conventional vertical wells.

Horizontals die so fast you DON’T have time to catch up. That’s why it is so frantic. If you take time to get nat gas capture infrastructure into place, the oil output is avalanching so fast from your multiple wells that you start to lose enough cash to fund that infrastructure.

These shale plays are very short lived things. You gotta do them. The oil doesn’t do anyone any good underground. But they are not going to change anything. They will peak and fall. Steeply.

Thanks thackney.

North Dakota sweet crude averaged $77.09 per barrel in December, compared to $80.86 in November and $87.00 in October. The price stood at $87.25 per barrel on Jan. 11. The all-time high reached $136.29 on July 3, 2008. Meanwhile, the number of rigs actively drilling on federal surface in the Dakota Prairie Grasslands was reported to be down to zero. But the number of rigs drilling on the Fort Berthold Reservation has increased to 28 with four on fee lands and 24 on trust lands. There are now 793 active wells -- 96 on trust lands and 697 on fee lands -- producing 135,380 barrels of oil per day -- 6,730 from trust lands and 128,650 from fee lands. There are 113 wells waiting on completion. Additionally, there are 291 approved drilling permits -- 266 on trust lands and 25 on fee lands, with 1,479 additional potential future wells -- 1,426 on trust lands and 53 on fee lands.

Hmm, all time high during a POTUS election year, how odd. /s

You are spot-on, thackney.

Warm fracking water?

The economics of building a pipeline to transport fracking water to a wellsite would limit fracking operations to summer, and the pipelines would have to be surface and temporary or the backlog for completions would be determined by pipeline crews.

A buried line would be more expensive.

It has been done: Brigham built a temporary (agricultural/irrigation pipe --8 inch iirc) surface line to a location from Trenton ND, about 8 miles. The line saved them a fortune in trucking costs for the fracking of three wells, the pit from the first frac used to store the water was used to store water for two offset wells.

However, 8 miles is a pretty short distance to a water source, and this was done while the weather was warm. Multiple wells in that area made it more economical, as they were able to pump water overland from that pit to the other wellsites.

Most wells are farther from water, and building a temporary line more problematical over less friendly terrain. Regulation of storage pits has become more intense as well, even though the water was well water--something not readily available in all areas, especially in that quality and quantity.

As far as a permanent line to a well for fracking, you frac to find out what the well will do, there are no guarantees, and that would be a tremendous up-front expense for an unknown return.

Perhaps piping water to regional locations to reduce transport distances would be a plus, with the infrastructure available for potable water later on.

It may be that Director Helms is considering using the lines in to wellsites for oil/gas pipelines out, but that would likely involve different construction specifications. I think the goal there would be to reduce flaring gas.

Anyway, weather has traditionally messed with oilfield operations here, and the last two winters have been unusually mild. This one is behaving a little more like winter, and for outfits who have been spoiled by a couple of years of 'nice' winter weather, the adjustment may take a season or two.

Well known reality carefully NOT talked about by those who have to hype the drilling of the next well.

I don't have to hype the next well, but I tell every royalty onwer I know to bank the first three royalty checks, and at least half of the next five, then see what they get because of the decline curves. I explain to them that the production falls off rapidly from IP, and usually ends up at the 150-200 BOPD mark after a couple of years. If they look at the first check and load up for Beverly Hills (Jed Clampett joke), they're liable to come back on a Greyhound when they can't make the payments. Most are older folks who are reasonably careful with their money anyway, and they fare pretty well--they just treat the money like a bumper crop, and don't count on a steady stream of it to continue.

Joe thats exactly what we did. We built one pit by our two water wells then staged 3 more coming around the nth side of the mountains all connected with 4 inch poly lines and polylines running to each well. When we finished we started selling water to Whiting who was drilling nth of us.

I hear ya on the royalty checks I’ve seen several go from riches to rags in just a couple of years. You try and tell them but they won’t listen.

“I explain to them that the production falls off rapidly from IP, and usually ends up at the 150-200 BOPD mark after a couple of years.”

This, btw, is another aspect of the hype. Specifically:

“This oil field is the future of America! It will be producing oil for the next 80 years!”

Be sure to include those exclamation marks. All those wells will be stripper wells in 5 years. In 80, maybe a handful will still do 2 barrels/day. The rest capped and abandoned. But those handful are there and thus “here we are 80 years later, still producing!!”

This is why reserves are not the critical parameter. Extraction rate is the critical parameter because rates are what consumption is all about. Extraction rate (aka production, but I’ve always hated calling it “oil production” — Mother Nature did the producing, the industry is just extracting it) is how one measures oil.

Don’t know if you guys have seen the study. Some Norwegian reasonably smart guy has looked at first 12 month output of Bakken wells now, vs first 12 month output of Bakken wells a year ago and two years ago. Just the first 12 months.

The number is falling. The conclusion he suggests is the low hanging fruit, the highest odds for big flow, were drilled first. Thackney guy up above noted that I quoted 1200 bpd as initial flow and that the graph showed lower. This is likely part of the same thing.

This field is just flat out overhyped.

haha yes, it’s climbing.

Like US new home sales. Celebrating and hyping 2 and 3% rises when it’s down something like 60% from 2005.

Oklahoma oil production was 780K bpd in about 1928. That was the peak. Now it’s at 260K. That’s down what, about 67%? And that’s with 85 years of technology improvements applied. So it was down 75%, has risen a smidgeon, and now it’s down 67%. Hallelujah!

Good call thackney on the whole easy vs not easy oil. I don’t measure easy in dollars. I measure in joules. How many joules did it take to build a 25 foot wooden tower on site, drill a hole and then stick a pipe over the gusher . . . . vs build a 30 story tall marine rig, stick a ten thousand horsepower engine on it, helicopter a crew to it, drive it for several months several thousand miles to the drill site and then drill in 2 miles of water to the sea floor and down another 10 miles below it?

Folks want to yell about liberalism and printing money . . . sorry, the reason civilization is disintegrating is because of that joules ratio. It is HUGELY more expensive joules-wise to get the 5.6 million BTUs of energy in 1 barrel of oil out of the ground than it used to be. The net joules coming out of the ground have been smashed by the end of easy oil — and this is forever.

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