Wednesday, November 2, 2011

Rocky Mountain Glaciers Growing in Size Despite Massive, Man-Made Global Warming -- Implications for the Bakken, North Dakota, USA

Reported by the Associated Press, November 1, 2011:
Scientists who monitor the effects of global warming are watching glaciers shrink all over the world, but this year could be an exception in parts of the Rocky Mountains.

Snow is already piling up in the high country, but not all of the unusually deep snow from last winter has melted. As a result, some glaciers and snowfields are actually gaining volume this year.

Scientists have measured new ice in Montana's Glacier National Park and atop Colorado's Front Range mountains. In northwest Wyoming, there is photographic evidence of snowfield growth after Bob Comey, director of the Bridger-Teton National Forest Avalanche Center, compared photos of peaks from year to year.
So much for melting glaciers and global warming. I love how writers just cannot bring themselves to question global warming. In this case, they call the Rocky Mountain glacier growth phenomenon an exception. In fact, it is occurring elsewhere also. 

The severe flooding in western North Dakota this past spring was blamed on all the snow melt from record snow pack in the Rockies. It appears likely to happen again this year, and another spring at risk of severe flooding. On the radio today, it was reported that despite requests from North Dakota state officials, the US Army Corps of Engineers would not release more water from Lake Sakakawea; state officials say releasing that water now would help prevent a repeat of spring flooding next year. So, we'll see.  A spokesman for the Corps of Engineers did say that some folks were responsible for their own loss of property by building in 100-year flood plains.

Multiple Reasons for Fracking Backlog -- The Bakken, North Dakota, USA


Back on October 16, 2011, I posted the following:
From three different sources -- actually four different sources if you throw in the Red Wing, Minnesota/La Crosse, Wisconsin, angle -- , I am now getting the feeling there may be reasons other than lack of frack teams that may explain the fracking backlog.

Since early this year, the companies have said they would catch up with the fracking backlog by November, but in fact, right now, in October, one out of four wells that come off the confidential list are not completed.

The recent sand/ceramic mix used at the Lucy Hanson well suggests there may be more to this fracking backlog than simply lack of teams.

I will throw this out there, leave it at this, for now, mostly for a time/date stamp if something comes of this.

But I think there's more to the story than lack of fracking teams.
At the time, in the post above, I provided the hints, but I did not come right out and say it (for a couple of reasons), but my conjecture was right: the fracking backlog is due to a number of factors, and lack of fracking sand is one of them.

2011 Budget Increase by Category (in millions)
Non-Operated drilling (40 gross, 5 net wells)     $ 41
Operated Drilling (4 gross, 4 net, 1 re-entry well)(1) 20
Land 17
Facilities 5
Q3 Temporary use of ceramic proppant (2)   17
Total $ 100
(1) Consists of 1 Big Tex well, 1 Big Island well, and 2 Exploration wells
(2) Consists of 20 net wells where ceramic proppant was used due to atemporary sand shortage at a cost of $850K per well.

When this was conjectured, a friend wrote to four oil companies operating in the Bakken and asked if a shortage of sand was contributing to the fracking backlog. One company did not answer. The other three all provided a non-answer: "there are always shortages of various materials in the Bakken, but we are always able to source what we need."

I remember seeing some wells in which absolutely no sand was being used, only ceramics. I thought the company (or companies) wanted to see how good a well could be by using only ceramics. Wrong; they were short of sand. It also explains why some wells were using very, very little sand.

So, trucks, sand, manpower -- all contributing to a fracking backlog.

By the way, if the second biggest Bakken operator is having trouble sourcing sand, can you imagine how difficult it is for smaller players with much less pricing clout and fewer long term commitments to get the sand they need. I can only assume CLR, WLL, BEXP, and a few others are at the head of the line when waiting for material in short supply.

EOG -- Mark Papa -- Mad Money -- November 2, 2011 -- The Bakken, North Dakota, USA

EOG will start moving some of their rigs to the Permian Basin, the Eagle Ford formation in south Texas.

EOG has secured their leases here in the Bakken and now needs to secure their leases in Texas.

Here's the video.

As a reminder, others have said there is a shortage of rigs. This all fits.

This is what Papa said, sent to me by a reader:
Q: Okay. And then when I think about the Bakken rig count decrease next year, is that largely just a function of where that asset is in it's life cycle, more of a development mode, or is it a statement on economics relative to the Eagle Ford?

A (Mark Papa, EOG):
"Yes, it's more a statement of where our leases are. We've been drilling in the Bakken for quite a few years, as you know, and we're in darn good shape on just holding the lease position together. So we have the flexibility in 2012 to not be forced to drill in the Bakken because we have leasehold issues. And so what we're doing is we're basically saying, okay, we'll slowdown in the Bakken a bit and we're going to accelerate in the Permian, particularly in the Wolfcamp. So the economics are not necessarily driving it as much as the leasehold situation is. I had noted that on a few other competitors' earnings calls, they were talking about well costs in the Bakken for long laterals that I believe the numbers that were quoted are somewhere between $10 million and $12 million a well. Our well costs up there for a long lateral, 10,000 foot lateral, are more like $8.2 million to $8.3 million. So I can see where some people might have some pretty skinny economics if you're spending $10 million plus on these kind of wells."

EOG Resources Mark Papa:

"I continue to believe EOG's Eagle Ford position is the highest rate of return, large-scale hydrocarbon play in all of North America, onshore or offshore. I also continue to believe this is the largest oil company -- oil discovery net to any one company in the last 40 years in the U.S."
Staggering. Incredible.

Busy, Busy, Busy -- Fifteen (15) New Permits -- 2/5 Wells Completed -- The Bakken, North Dakota, USA

Daily activity report, November 2, 2011 --

Operators: OXY USA (4), MRO (4), Samson Resources (3), Zenergy (2), Petro-Hunt, CLR

Fields: Fayette, Jim Creek, East Tioga, Fillmore, Lost Bridge, Dore

OXY USA has permits for a 4-well pad in Fayette oil field; MRO has permits for a 4-well pad in Lost Bridge.

Samson Resources has permits for two wildcats in Divide County.

The Fayette oil field was one of the first oil fields to really get me excited about the potential of the Bakken.

Of the five wells released from "tight hole" status, two were completed (fracked). The fracking backlog is over 50%. None of the wells reporting IPs today were particularly remarkable.

Continental Resources 3Q11 Earnings -- The Bakken, North Dakota, USA

Link here.

For now, I think I will let others provide analysis of the 3Q11 earnings for Continental Resources.

For me, this is most important data point:
The Company successfully completed the Charlotte 2-22H (91% WI) in McKenzie County, North Dakota, in October 2011, with the well producing 1,140 gross Boepd in its initial one-day test period. This is the Company’s first horizontal test of a deeper bench in the Three Forks formation.

“We’re very pleased with such a solid well in our first test of the lower benches of the Three Forks,” said Harold Hamm, Chairman and Chief Executive Officer.

Continental is a pioneer in developing the Three Forks formation, initially targeting the first bench of the Three Forks approximately 20 feet below the Lower Bakken Shale in mid-2008. In 2011 Continental expanded its evaluation of the Three Forks by acquiring six cores of the entire vertical thickness of the formation over a distance of 115 miles north to south. The cores revealed that the Three Forks formation, which ranges from 180 feet to 270 feet thick under the Company’s acreage, contains up to four separate benches of dolomite that contain oil.

“The Charlotte 2-22H was drilled horizontally in the second bench, approximately 50 feet below a typical first-bench horizontal well,” Mr. Hamm said. “This successful test demonstrates that the Three Forks second bench has the potential to add incremental reserves to our estimated 24 billion Boe of technically recoverable oil and natural gas in the total Bakken.”
In case you missed that: CLR says that finding oil slightly deeper in the Three Forks has the potential to add incrementally to their estimate that the Bakken formation has 24 billion boe of technically recoverable oil and natural gas.

Statoil Conference Call: BEXP Acquisition -- The Bakken, North Dakota, USA

Link here.

Breakeven economic point: $55

Starting with 12 BEXP rigs; will be discussing with BEXP how to "step up from that."

Whiting Posts Results -- Wow, Wow, Wow -- Look at the Cost/Well --The Bakken, North Dakota, USA

Link here.
Whiting Petroleum Corporation’s  production in the third quarter of 2011 totaled a record 6.50 million barrels of oil equivalent (MMBOE), 83% oil/natural gas liquids and 17% natural gas. The daily average production rate was 70,675 barrels of oil equivalent (BOE), an increase of 10% over the 64,120 BOE per day rate in the second quarter of 2011 and a 7% increase over the 66,120 BOE average daily rate in the third quarter of 2010.

Wow, wow, wow, ---- look at the cost per well -- compare to Newfield's comments:
Our well economics continue to remain robust. From January 2009 through September 30, 2011, we completed 115 Bakken wells with an average first six months production of 97,000 BOE. This average is 13,000 BOE higher than the second ranked Bakken operator and 50,000 BOE better than the average of the next 20 operators. We are currently drilling and completing wells in the Sanish field for approximately $6.0 million. Outside of Sanish, in other North Dakota areas, our completed well costs are currently running between $6.0 and $8.0 million and declining as we move into development mode.

The Purpose of an Oil Field -- The Bakken, North Dakota, USA

Elsewhere they are talking about the purpose of designating an area as a specifically named oil field. The question being asked is what benefits does having a lease inside a designated field have over a lease in an area that is not designated as a field..

A field designation from my point of view is simply an administrative exercise, but a very important one. When oil is discovered in a geographic area, and there is a great likelihood of more oil being produced from that geographic area, a producer will ask the agency with jurisdiction to designate it a named field (or to include the new geographic area in a neighboring existing field).

A designated field has rules by which producers must comply, for example, but not limited to specific well location, spacing, production, and flaring. If a well is drilled outside a field, generally called a "wildcat," the producer must ask for rules, such as spacing, for that individual well. As long as a field is not designated, the producer would have to come back to the regulator to request rules for each new well.

If the well is inside a designated field, the producer knows the spacing and other rules, such as where the well can be located.

On a completely different note, but part of the same discussion: if an geographic area has been designated a field, it has been de-risked. That is, folks know there is recoverable oil there. It is easier for a producer to raise capital to drill a well in a de-risked area than it is to drill a wildcat.

Bottom line: if one has a lease, but no well, inside a designated field, it is more likely that a well will be drilled there than if it was a wildcat. But, if the well is already there, or about to be placed there, it probably makes little or no difference to the average mineral rights owner whether that area has been designated a field.

This Is Incredible: The Green Movement is Burning Forests for Electricity and Fuel -- Absolutely Nothing To Do With The Bakken

Link here.

From Canada, this is incredible, burning trees for fuel and electricity, incredible in the 21st century:
The federal and provincial governments must clamp down on large-scale burning of forest wood for energy and biofuels to prevent an "environmental fiasco," says a new report released on Wednesday by Greenpeace Canada.

The report, entitled "Fueling a Biomess," said that the practice used to consist of small-scale operations that used organic waste to produce energy. But it said that biomass could now be becoming even worse than some traditional fossil fuel options such as coal-fired electricity since producers are now targeting new forest ecosystems for energy.

"Significant forest bioenergy production will lead to an environmental fiasco," the report said. "Burning natural forest biomass — whether for electricity, heat or biofuels — is not carbon-neutral as governments and companies claim. Burning trees contributes to climate change for decades, as shown by the most up-to-date science, until replacement trees fully grow back."
This is incredible. I honestly did not know this was an issue in Canada, burning forests for energy.

And the US is giving a free pass to wind energy developers to kill whooping cranes and other migratory birds.

Somehow the green movement seems to be moving in the wrong direction.

Mexico Scraps Plans To Build Ten (10) Nuclear Plants; Will Switch to Natural Gas -- Implications for the Bakken

Japan, Germany, Mexico, France, Great Britain, the US,  

Link here.
Mexico, one of three Latin American nations that uses nuclear power, is abandoning plans to build as many as 10 new reactors and will focus on natural gas-fired electricity plants after boosting discoveries of the fuel.

The country, which found evidence of trillions of cubic feet of gas in the past year, is “changing all its decisions, amid the very abundant existence of natural-gas deposits,” Energy Minister Jordy Herrera said yesterday in an interview. Mexico will seek private investment of about $10 billion during five years to expand its natural gas pipeline network, he said.

Mexico, Latin America’s second-largest economy, is boosting estimated gas reserves after Petroleos Mexicanos discovered new deposits in deep waters of the Gulf of Mexico and shale gas in the border state of Coahuila. The country was considering nuclear power as part of plans to boost capacity by almost three-quarters to 86 gigawatts within 15 years, from about 50 gigawatts, and now prefers gas for cost reasons, he said. 
All I can say is: very, very interesting.

I can't resist: I guess if the administration/EPA bans fracking in the US, not only will the US be importing $100 oil, but we will be importing $8 natural gas (natural gas currently sells in the US for about $3.50  -- and we have a lot of it.).

I keep thinking of that New York Times article some months back regarding natural gas.

For the Truckers -- The Bakken, North Dakota, USA

We All Call Home, Dierks Bentley

Remember, if you are an automobile driver in the Williston area:
  • At an intersection, when stopping, stop well behind the white line/the intersection, to allow big rigs to make a left turn in front of you
  • If you are the only car waiting, and there's a huge space between you and the next line of cars about a mile back, let that truck go first in making his left turn; if not, he/she will be waiting forever; it will cost you 15 seconds; it will save the trucker 5 minutes (which feels like an eternity when waiting)
  • Fully loaded trucks cannot stop "on a dime"; in fact, I don't think they can stop in a country mile; use your rear view mirror; keep track of where the trucks are; use your signal lights; don't make sudden lane changes
  • If enjoying a Sunday drive, get into the far right lane as soon as possible and let the truck pass you in those new passing lanes
There are other things one can do to help truckers -- some of them are frowned upon by the highway patrol so I won't post them --

If there's a mishap, it may not have been your fault, but that's small comfort when a truck meets a compact.

I was told yesterday that the vehicle count/day on the bypass west of Williston was 6,000 before the boom; the latest vehicle count was 26,000. And it's all trucks. I don't think it's the tourists. If it is, I don't know where they're staying in Williston.

Newfield's Hand-Wringing Over the Cost of Fracking -- Some 'Splainin' To Do -- The Bakken, North Dakota, USA


November 16, 2011: Now, SM says their wells are coming in up to $2 million less than their Bakken competitors.
Well costs continued to increase. This is an area where we keep a very close eye on the margins. We are seeing well costs now $8.5 million to $9 million in our Bakken program and $6 million to $6.5 million in our Three Folks Gooseneck drilling program. I should point out one of the things that it is unique about SM Energy. We are seeing our Bakken wells coming in $1 million to $1.5 million, some cases $2 million less than some of the offset operators. Primary reason for that is we are still drilling 10,000 foot laterals, but as you may know we don’t complete with this many stages.
Wow, what a difference two weeks can make in the Bakken. At this rate, SM will have their costs down to $4 million, as long as they don't frack at all. Smile. 

Original Post: November 2, 2011

From Newfield's conference call regarding fracking:
Well, I think, first of all, I guess I would take issue with your comment on the well cost. We've put ourself out and compared our drilling curves and our costs against all the operators in the area. In each of the areas that we're active, I can tell you that we're very competitive as far as the wells that we're drilling. I will tell you that all our wells this year are proportionally much higher as a result of drilling the 1,000-foot laterals [sic]. Last year and even today, we can back off and drill a 4,000- to 5,000-foot lateral in the neighborhood of $7 million. Earlier this year, we were in an 8.5 to 9.3 environment. And we've seen that number go up to 11. Now the lateral lengths that we have today are between 9,000 and 10,000 feet. And I can tell you in the $11 million, there is some element of trouble cost that are built into that, that are a reflection of what we've seen in 2011. Now many of the costs that you historically see don't have trouble cost built into them. And in the environment that we're currently drilling today, you are far more likely to see increasing costs associated with that area than you are in areas where the rig count is much low. So that is a fully-loaded facilities, trouble cost, as well as drilling complete. Now as we look forward and you see some of the contracts that you have in place for stimulation services roll-off, and you see the basin moderate or more services come in, I fully expect that number will back off. But I'd be naive in thinking that if we would be seeing a $9 million well cost anytime soon.
From MRO:
We're basically targeting now between $8 million and $8.5 million per well. I would say that we have fixed contracts for our drilling and the 10 fracs a month that we have contracted. And so we're not as exposed to further upward pressure on the inflation side. Most of what we've seen in terms of driving our cost up have been the fact that we're now putting 30-stage kit in the ground, and all of our wells next year will be 30-stage frac jobs.
From Whiting:

Our well economics continue to remain robust. From January 2009 through September 30, 2011, we completed 115 Bakken wells with an average first six months production of 97,000 BOE. This average is 13,000 BOE higher than the second ranked Bakken operator and 50,000 BOE better than the average of the next 20 operators. We are currently drilling and completing wells in the Sanish field for approximately $6.0 million. Outside of Sanish, in other North Dakota areas, our completed well costs are currently running between $6.0 and $8.0 million and declining as we move into development mode. [These are all long laterals; short laterals used to cost as much as $6.0 million. Also, note: SLB expects fracking costs to decrease over time.]
From EOG:
"I (Mark Papa) had noted that on a few other competitors' earnings calls, they were talking about well costs in the Bakken for long laterals that I believe the numbers that were quoted are somewhere between $10 million and $12 million a well. Our well costs up there for a long lateral, 10,000 foot lateral, are more like $8.2 million to $8.3 million. So I can see where some people might have some pretty skinny economics if you're spending $10 million plus on these kind of wells."
From Schlulmberger:
In the Reservoir Production Group, deployment of HiWAY technology in the pressure pumping market continues to grow. In North America, the number of customers using HiWAY had grown from 2 only a year ago to more than 20 today, and we completed over 800 stages during the quarter in this market alone. HiWAY continues to deliver higher gas and liquid production, while using significantly less water and proppant compared to conventional fracturing systems. This provides us with significant pricing and cost leverage versus our competitors, a factor that will become even more important when the North America pressure pumping market eventually become saturated with hydraulic horsepower. I would also add that HiWAY is starting to gain momentum in the international markets, including Russia, North Africa and the Middle East.[Translation: pressure pumping market --> fracking; fracking will get more competitive over time; generally competition keeps pressure on prices.]

1,400 Leases in the Gulf of Mexico Extended -- Good News for Shareholders

Link here.
U.S. officials have extended oil-drilling leases for the vast majority of companies that say their work in the Gulf of Mexico was disrupted by the Deepwater Horizon oil spill or the temporary drilling ban that followed the spill.

President Barack Obama announced in May that his administration would grant one-year extensions to certain companies operating in the deep waters of the Gulf. The goal was to give oil companies additional time to drill on their offshore leases following a moratorium on deepwater activity that lasted from May to October 2010.
More than 97% of the lease-extension requests received so far--or 1,381 of 1,413 applications -- had been approved.