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.

First off, consider that the production thus far has come from a formation previously thought to only be productive in rare localities. Instead, this has opened the door to unconventional resource considerations worldwide.

Sure, there are sweet spots, and these have been noted since development began. The initial barnburner discoveries near Stanley ND, and elsewhere in the basin had wells IP at over 3000 BOPD or equivalent. Not shabby at all. Other areas will produce less, and some not at all. I've worked wells which fit all of those, from a regional recordholder to a couple which fell outside the productive area, to wells in between, and have worked over 100 of the Bakken and THree Forks wells now.

The Three Forks, BTW was completely thought to be nonproductive.

Oops, but there is a gain to be had in that as well.

Believe it or not, even after over twelve years of working these wells, we're still developing new technologies to drill them faster, better, and produce them more efficiently.

Now, let me put this in perspective. In the Williston Basin, oil was first found in the 1950s. In that time wells have produced oil and/or gas commercially from eighteen different geological formations varying in age from Triassic to Cambrian.

Horizontal drilling has been applied to the Bakken, but I have worked horizontal wells in the Ratcliffe, Midale, Stonewall, and Red River, as well as the Bakken and Three Forks. Other formations may lend themselves to this production technology.

Prior to horizontal drilling, a 100 BOPD well was considered a fairly good producer. I'm not sure of the number, but, iirc about 30% of US production comes from stripper wells producing under 20bbls of oil per day. They all contribute.

The Williston Basin has been producing oil for 60 years. One of the early fields I worked in, doing re-entry horizontal wells proved the concept: Carbonate reservoirs are anisotropic, and even on a 160 acre spacing, did not yield their full load of oil after twenty years of production: the changes in production volume and even an increase in gas produced in one well when two laterals were drilled at 90 degrees to each other 1 year apart proved this.

Please note that another misleading bit of hype about the Bakken is that it is shale oil. The source rock for the oil is the Upper Bakken Shale, and where present, the Lower Bakken Shale, but the rock in the Middle Bakken is a combination (depending on where you are in the Williston Basin) of micricrystalline to fine crystalline dolomite, siltstone, sandstone, and fragmental limestone. This rock has porosity, even if the natural permeability is low as a rule, and because of the complex nature of the lithology involved, may not register correctly on porosity logs. The ability to model the rock types more efficiently based on density and sonic logs, and to better estimate porosity may yield better production forecasts.

The Basin will be producing oil for a long time to come, as long as there is a market for it.

The only questions are "How Much?" and from "Which Formation?"

As far as hype goes, actually, efforts have been made to NOT hype it, from reserves estimates to recovery estimates, by both the State and the USGS.

If you've been reading pump and dump stock newsletters, you might be getting a different story.

The rest of us (in the oil industry) can't just pull stakes, cash out and move on to selling electronic widget company stock next week.

Because I am a professional geologist, and I live in the Williston Basin, I make a point of never overselling the idea, and would lose credibility among my peers and the public alike if I portrayed the drilling boom here as anything it is not. I have seen booms come and go, and always have been one to preach economic caution in spending habits, both from the public coffers and in private life as well.

There will be plenty of fancy cars and bigger houses available when things slow down in due time, at relatively cheap prices.

That’s good data.

Of course stripper wells contribute. They contribute 5 barrels per day. That’s not going to pay the piper.

Global oil production is what, about 75 mbpd? Oil, not low joule NGLs or ethanol. Proper crude oil. Saudi Arabia is about 9.5 of that. Russia is 10.3. That’s 27% of the total from two places that do NOT do stripper wells. Did you know there are, after just what, five years of frantic drilling, more wells in the Bakken than in all of Saudi Arabia, drilled for 65 years? The Bakken is the poster child for destruction of the joules ratio of in vs out.

This is frantic, desperate drilling using millidarcy enhancement methods that KSA never has to use. They have wells that have flowed about 10,000 bpd for 40 years.

“If you’ve been reading pump and dump stock newsletters, you might be getting a different story.”

You must mean the news releases from Continental Resources, the largest company involved who own more leases than anyone else there?

BTW I do applaud the efforts of NDak’s geology folks to slap down Continental Resources’ hype, but they are failing utterly to stop NY Times hype or even Forbes, who have a reasonbly smart oil reporter.

North Dakota just changed the rules on stripper wells, too. Previously, a group of wells in an area could be declared "stripper" wells (under 20 BOPD, and a different tax status) based on the production data from a few wells nearby. Now it is on a well by well basis.

I know of no horizontal Bakken or Three Forks wells which have been reduced to stripper status (in the current round of drilling, not those from the mid-80s which actually targeted the shales), and I have been working these since 2000.

That is a lot longer to get under 20 BOPD than the projections.

The tendency I have seen is for production to level off at between 10 and 20% of IP after a couple of years and decline more slowly from there.

I don't pretend to have all the data at my fingertips, but causing a panic would benefit some operators as smaller players came up short of venture capital and slowed down or sold out causing a sudden surplus of drilling rigs and service companies.

Oil prices versus drilling/completion costs can drive such a deflation of any 'bubble' present, just as we have seen in the housing market adjustments here.

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