RBN Energy With Nice Update On CBR Tank Cars

Active rigs: 183

RBN Energy: a likely oversupply of tank cars for the CBR market.

A dramatic increase in crude-by-rail shipments over the past two years as well as surging lease rates for hard to come by tank cars encouraged an 18 month backlog of new orders – even while crude shipments only represent a small fraction of total rail carloads. Changes in the crude price differentials that encouraged the growth of crude by rail have reduced both the demand for tank cars and lease rates. Today we present analysis from PLG Consulting that shows rail tank car oversupply is quite possible - barring a few "wild cards."

The article contains a nice description of the two main types of tank cars:

The differences between the two widely used CBR tank car designs are worth further discussion. The higher volume tank car is the general-purpose non-coiled non-insulated car with nominal capacities of 30,000 gallons (GP30) and 31,800 gallons (GP31.8) used for light/sweet crude that is produced in the US shale oil plays. The GP31.8 is a crude optimized car that started being manufactured in 2011. These general-purpose non-coiled non-insulated cars have a lower tare (empty) weight, a higher usable capacity (up to 286,000 lbs. gross-weight-on-rail), and cost less to manufacture.  A GP31.8 car has an ability to haul about 720 Bbl of light crude oil, while a GP30 with a 263,000 lb. gross weight is able to haul about 675 Bbl of light crude oil.

The heavier Canadian Oil Sands type crude requires a more complex coiled and insulated railcar because the commodity is more viscous and needs to be heated to help it flow.  The coils and insulation decrease a tank car’s usable capacity and make it both heavier and more expensive to build.   The optimized “heavy crude” style car has a nominal capacity of 28,800 gallons and ability to haul about 600 Bbl of heavy crude oil.

In general, the leasing community will prefer to own the smaller cars with coils and insulation because they have far more flexibility across numerous commodities (chemicals, etc.), whereas the larger GP cars are more limited in scope (with ethanol, methanol and some refinery chemicals being the only sizeable alternative markets to crude).

The "wild cards" have to do with possible regulatory changes following the Canadian CBR spill and explosion.

By the way, one of the first presentations ever on CBR is still available at the NDIC site: a nice PowerPoint presentation of North Dakota's CBR terminals, click here for NDIC's conference held earlier this year (February, 2011), a PDF file. One presenter did refer to this as "Crude By Rail" but I did not actually see the "CBR" acronym in the presentation. It is possible some used the "CBR" acronym on a website prior to my using the acronym, but it would have been very, very rare. I have a 131 posts tagged with "CBR." The earliest post tagged with CBR was posted February 3, 2011.

Oasis Reports A Nice Well In Montana

From the Fairfield SunTimes:

Richland County

Whiting, two wells:

• Sundheim 44-8-3H; TD, 20,830 feet; 692 bbls
• Sundheim 31-17-1H, TD, 21,434 feet; 463 bbls

CLR, one well:

• Constance-Stoney Butte HSU; TD, 20,590 feet; 237 bbls

Roosevelt County

Oasis, one well:

• Stonewall Federal 2959 43-21H; TD, 20,400 feet; 1,004 bbls

NDIC Will Look To Increase Drilling In Bowman County

One simple rule in the oil patch pretty much eliminated drilling in one county in North Dakota, reports KXNews. But in an attempt to bring back the drilling in Bowman County, the state is "loosening" the rules:

State regulators are finding out that a rule created to make oil sites more environmentally friendly is creating a make or break situation for drilling in certain areas.

In fact, eliminating reserve pits may be influencing some companies to consider drilling in South Dakota instead.

Bowman county used to be the hotspot for oil in North Dakota.

It was the number one producer for years.

In fact it slid from the top spot in July 2008, falling behind Mountrail County, just after the oil industry figured out how to crack the Bakken.

Since then production in Bowman County has decreased.

"Bowman County has pretty much been asleep for a year and a half," says Director of Mineral Resources Lynn Helms.

No rigs are drilling in Bowman County today, but three were there recently.
Helms says he expects that number to pick up.

"That's in response to the industrial commission loosening the rules a little bit on reserve pits," says Helms.

I don't know how the cost of a reserve pit compares to the cost of laying a natural gas pipeline to a remote well, and then constructing a gas processing plant to process the natural gas, but something tells me it's a lot more expensive. And thus: flaring or drilling. This is not rocket science.

By the way, I thought this was an interesting statistic:

South Dakota has had 19 oil wells drilled so far this year with a majority of them in Harding County.

South Dakota produces 1.6 million barrels of oil a year, which is what North Dakota produces in two days.

I noted a lot of those wells on my most recent trip to North Dakota, driving straight through from the Dallas, Texas, area to the Bakken. I started noticing wells in Harding County, South Dakota, just before driving into North Dakota. 

Twin Buttes Oil Field

Twin Buttes oil field is in the northeast corner of Dunn County. It is a long, somewhat rectangular field running east to west (or west to east), sort of 3 x 8 sections in size. It almost has a dumbbell shape with the west "square" the active area and the east "square" almost devoid of any activity.

It is on the south side of Lake Sakakawea.

The "east" square has one well:

• 17003, 100, KOG, Tall Bear 16-15-16H, Twin Buttes, 20 stages; about 3 million lbs; t12/09; cum 17K 9/13; the spacing is ICO, even after four years; 

In the western square there are about a dozen wells (almost all 1280-acre spacing):

• 25293, conf, KOG, Charging Eagle 10-14-11-2H3,
• 25292, conf, KOG, Charging Eagle 10-14-11-2H,
• 25289, conf, KOG, Charging Eagle 14-14-10-3H3,
• 25287, conf, KOG, Charging Eagle 14-14-10-2H3,
• 23953, 2,022, KOG, Charging Eagle 16-21-16-1HA, t8/13; cum 27K 9/13;
• 23952, 2,010, KOG, Charging Eagle 16-21-16-1H3, Twin Buttes, t8/13; cum 20K 9/13;
• 23951, conf, KOG, Charging Eagle 16-21-16-1H, a big well; 23K first month;
• 23950, 2,411, KOG, Charging Eagle 15-21-16-2H3, t7/13; cum 63K 9/13;
• 23949, 2,298, KOG, Charging Eagle 15-21-16-2H, t7/13; cum 51K 9/13;
• 23948, 2,454, KOG, Charging Eagle 15-21-16-3HE, t7/13; cum 53K 9/13;
• 23778, 1,211, WPX, Howling Wolf 28-33HC, sited in Charging Eagle, but a Wolf Bay well;
• 21069, 553, KOG, Charging Eagle 15-22-15-3H3, t11/11; cum 140K 9/13;
• 19925, 609, KOG, Charging Eagle 15-22-15-4H, t11/11; cum 170K 9/13;
• 19506, 1,595, KOG, Charging Eagle 15-14-24-16H, t3/13; cum 117K 9/13;
• 19505, 2,252, KOG, Charging Eagle 15-14-11-4H, t3/13; cum 179K 9/13;
• 17764, 769, KOG, Charging Eagle 1-22-23H, t10/09; cum 120K 9/13;
• 17600, 1,187, KOG, Charging Eagle 1-22-10H, t10/09; cum 182K 9/13;

********************************

23950, 2,411, KOG, Charging Eagle 15-21-16-2H3, t7/13; cum 63K 9/13:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	9-2013	30	15415	15211	16368	10037	0	9947
BAKKEN	8-2013	24	16927	17184	36835	13002	0	12930
BAKKEN	7-2013	30	29196	29279	32335	22282	0	22195
BAKKEN	6-2013	4	1649	691	7483	1628	0	1610

Random Note From Halcon On Decline Rates In The Bakken; Staggering

During the Q&A period of the conference call, a question was asked about the decline rates in the Bakken. The analyst noted that "everyone" in the Bakken is improving production because operators are learning more and more about completion techniques. The analyst asked when Halcon would be sharing their new graphs with updated decline rates. Here was Halcon's answer:

The improvements have been coming so fast and furious, we really can't keep up with it.

We tend to not put out updated type curves until we have significant history on a well. So certainly, some time over the next couple of quarters. But that field [the Fort Berthold area in North Dakota], as you know, has been so drilled in every area that you need type curves in every area. And for our company, we probably have about 6 or 7 type curves.

But then we'd have to start looking at type curves with slickwater fracs and without slickwater fracs, and type curves where you have tight spacing and type curves where you don't have tight spacing.

What I can say is that the initial wave of completion design modifications that we've done from the north end of the field doubled our IPs and our 30-day rates, and down the south end, increased them by 30% to 50%.

That should yield a much higher type curve, but we're just not prepared to put those out there. You can take our old type curves and just assume that the new ones will be higher.

Music to my ears. We've been blogging that since the beginning. 

Earlier in the presentation, this is what Floyd Wilson, the CEO, had to say:

All current wells are dramatically outperforming well drilling completed using previous methods and drilled by previous operators. Most of all -- most all of our 2014 wells will be drilled from pads. Cost reductions should continue.

At Fort Berthold, and this is really important news to us, that Fort Berthold downspacing results have been positive -- early but positive. Three (3) middle Bakken wells drilled on 660-foot spacing came in at nearly 2,700 barrels of oil equivalent per day average per well. And after several weeks, those wells are holding up as expected, with that IP rate as a start.

At another site at Fort Berthold, we set a new company record IP rate of over 3,900 barrel of oil equivalent per day.

At South Fort Berthold, our first slickwater fracs were a significant improvement over nearby wells on a 60-day rate basis. They were nearly 60% better than the nearby wells over the first 60 days.

At North Fort Berthold, our first slickwater-frac-ed well was a 30% improvement over nearby wells.

So this slickwater technique and this concentration of proppant and more complex fracturing, which is our target and others' targets here, seems to be working.

The downspacing issues in the Williston basin could be really important for our company and others. Our total location inventory in the basin could be nearly 1,000 if middle Bakken and Three Forks downspacing testing continues to be fruitful.