PN Bakken: ‘Wake-up call’

Petroleum News ^ | Week of January 20, 2013 | Ray Tyson

[thackney]

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.

“Our expectation was for a 2-to 3 percent increase,” Helms conceded.

Storm blamed for slowdown

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.

Colder weather ahead

“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.

December was a relatively quiet month.

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.

Helms’ wake-up call

“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.

Rig count down again

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.

Leasing activity extremely slow

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.

Oil prices drop in December

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.

[HiTech RedNeck]

Et tu, Brute? -- Shakespeare, Julius Caesar

Winter storm Brutus hits, the place temporarily loses its staffing (even hardy guys have a limit to how hardy they are) and output suffers, and oh heavens the sky must have fallen.

What's this meshugas??? (Craziness)

[wild74]

Going to have to get some major oil & gas pipelines up in that area, shipping the oil by rail will not be enough with the production increases.

[Don Corleone]

Another , “Unexpected?”

[cardinal4]

Bakken is not going anywhere. If anything, there is not enough infrastructure to keep up with production. The cold weather decrease means nothing in grand scheme of things..

[Owen]

They drill about 140 new wells per month. Each of those starts producing oil at about 1200 barrels per day.

But the MOST IMPORTANT parameter is not being advertised. That is that every single well they have drilled starts to decline its output as soon as it starts. There is talk of 30% decline rates/year. That means that 1200 bpd is down to 650 in just 2 years.

The reason that is the MOST IMPORTANT parameter is that there are 4000+ wells declining every single day and they add only 140 new ones per month. This is sprinting up a down escalator whose steps are moving downward at an increasing speed.

You can outdrill that acceleration . . . for a while. But it’s important to understand every such month that goes downward in production is several feet downward on the accelerating downward escalator that has to be made up by even faster sprinting.

This is not a good miracle to bet the nation’s life on.

[thackney]

” Underground pipelines to transport warm fracking water to drill sites, rather than by truck, would help alleviate the problem,

That sounds like nonsense to me.

Why would you build underground pipeline to a well site that needs hydraulic fractured ONE TIME, then not again for years or even more than a decade? Are they fractured at any real frequency in the Bakken?

[South Dakota]

Well said. The fact is the wind and snow made travelimg almost impossible.
My company shut us down.

Frac here then frac there. It takes them longer on the bakken sometimes. I don’t know why.

On the jonah natural gas fields slumber j would set up on one location and run tubing to frac many wells from the same locatiom

[marron]

Just shows the need for pipelines. There are several more pipelines underway. Meanwhile, a winter storm can affect the numbers. Its life in the oil patch.

[Cicero]

Cold weather in North Dakota in mid-winter. Who’d’ve thought it?

Seriously, if companies can work in Alaska, they can learn to work in North Dakota. It will just take a little experience and a little adjusting to conditions.

[Dusty Road]

Some of us are old enough to have seen this several times, different plays play out, nothing last forever but it’s amazing how some things last. I’ve got Wolfcamp wells on the south end of the ranch that are over 50 years old that still make a few barrels a day (enough to keep them running). I’ve got Canyon Sands Wells on the north end that come in with 300 to 400 barrels a day but drop of to 15 or 20 within a year. Our upper section Cline Wells north of town are comming in at 400 to 500 per day with some still holding over 100 after a year. The well we’re drilling now is for the lower level Cline and we’ll see what this one does. On the Cline wells we’re making good wet gas and allot of it.

[thackney]

Each of those starts producing oil at about 1200 barrels per day.

That sounds like a lot higher than the typical well. Or if they start anywhere near that point, they fall down fast. The average for the first 60~90 days is 234 barrels per day according to the North Dakota Industrial Commission, Department of Mineral Resources, Oil and Gas Division.

First 60 - 90 Day Average Bakken Pool Production by Well
https://www.dmr.nd.gov/ndgs/Publication_List/pdf/geoinv/GI-123.pdf

There is talk of 30% decline rates/year.

There is more than just talk. The initial data is even worse.

Source for Graph:
North Dakota Department of Mineral Resources
https://www.dmr.nd.gov/oilgas/presentations/WBPC2011Activity.pdf

[Owen]

Good data:

“I’ve got Canyon Sands Wells on the north end that come in with 300 to 400 barrels a day but drop of to 15 or 20 within a year.”

That’s maybe an average of 200 barrels a day for the year as it declines. That’s 73000 barrels at $80/barrel or $5.8 million coming out of a well that cost what, $15 million with infrastructure? These had better be rare.

[thackney]

BTW,

I do realize the first and second data sets do not match with each other. Both are from ND government. ???

[Owen]

Nod.

There’s oil there and jobs, but this is the most overhyped crap in the history of an industry built on overhyped crap.

That place is going to go into freefall production-wise and the day it is clear “tight oil” is not going to be anyone’s salvation, Brent will go to $200.

[E. Pluribus Unum]

The reason that is the MOST IMPORTANT parameter is that there are 4000+ wells declining every single day and they add only 140 new ones per month.

"Drainage! Drainage, Eli! Drained dry, you boy! If you have a milkshake and I have a milkshake and I have a straw and my straw reaches across the room and starts to drink your milkshake. I drink your milkshake! I drink it up!"

[Dusty Road]

No sir our wells are running us about 2.5 to 3 mil per, thats flowlines and battery’s. We’re not drilling horizontals. We ain’t up with the big dog’s just yet.

[Dusty Road]

Well I can’t drink your milkshake but I might get a little taste as long as it’s within my 40 acres. TRRC frowns on poaching.

[E. Pluribus Unum]

When I suck it up my straw on my 40 acres, capillary action sucks it from all the surrounding 40-acre parcels.

[43north]

“Seriously, if companies can work in Alaska, they can learn to work in North Dakota.”

I worked in the Alaska North Slope oil patch for 26 years. Bad weather is nothing new. Production goes up sometimes but it inevitably goes down. That’s just the way it is.

Oil wells typically produce large quantities of oil right after they are drilled, then gradually taper off. By that time all of the big expenses have (hopefully) been paid for. They do not get capped unless the operating expense exceeds the value of the oil being produced.