BR Case 30888 To Place Sixteen Wells In A 3840-Acre Unit -- Sixteen 3-Mile Horizontals -- May 2, 2024

Locator: 47037BR.

From the NDIC May, 2024, hearing dockets, this is a case, not a permit:

Case 30888, BR, Elidah-Bakken, i) terminate two overlapping 2560-acre unit; ii) establish an overlapping 3840-acre unit, 16 wells, McKenzie County --

On a six section standup drilling unit, the company would likely put sixteen wells at the halfway mark and drill eight 3-mile wells to the north, and eight 3-mile wells to the south. Because it's a new drilling unit, in which there are no current wells, this means that the operator will drill sixteen wells in the six-section unit.

The case:

The maps: 

The wells on confidential list:

• 36613, conf, BR, Shafer 2B-MBH, Elidah,
• 36614, conf, BR, Sandie 2B-UTFH, Elidah,
• 36615, conf, BR, Sandie 2C-UTFH, Elidah,
• 36616, conf, BR, Sandie 2C-MBH, Elidah,

Three older, producing wells:

• 19083, 183, CLR, Shafer 1-21H, Elidah, t10/10; cum 263K 3/24;
• 19897, 681, CLR, Sivertson 1-9H, Elidah, t9/11; cum 524K 3/24;
• 19776, 352, CLR, Rolla 1-33H, Elidah, t11/12; cum 288K 3/24;

ECO-Pad = $$$$-Pad -- June 24, 2022

Early on in the Bakken, there were many reports of small mom-and-pop mineral owners becoming millionaires overnight. 

A lot of these folks were farmers who happened to still hold their mineral rights after all these years. 

In the early days of the Bakken, operators were drilling as fast as they could for many reasons, but mostly to hold the leases by production. 

To drill that fast, operators often drilled one well in any given spacing unit

Often, the small mom-and-pop mineral owners were "living" off one well. And still becoming millionaires. Maybe some hyperbole, but not much.

Fast forward to 2022. Now, it is the norm to drill mega-pads with six wells on each pad. 

Can you imagine a small mom-and-pop mineral rights owner with one well all these years to now see six new wells coming in. All at once. And with oil at $110 / bbl. 

What a great country. 

Yesterday, as the most recent example: Oasis with six new permits on one pad. That's been the norm for quite some time. Pioneered by Harold Hamm, one might argue. 

More On Pad Drilling From A Reader -- December 12, 2021

With regard to Bakken 4.5, pad drilling, a reader writes:

A few years back, some industry executive was explaining some of the economics behind not only 4 to 6 wells per pad simultaneously being drilled/completed, but also the then-emerging trend of simultaneously developing 3 to 4 pads in close proximity.

Interesting perspective. 

Taking those six Bruin wells that you have noted for example, at $6 million per well, Bruin would have 'pre-paid' $36 million before any revenue came back. 

With a cumulative production just over half a million barrels (~511,000) and $50/bbl pricing, Bruin would have already grossed about $25 million in oil revenue and $2 million from the gas ... roughly. 

It may take till the end of a year, but Bruin may be 'in the money' after 12 month's time.

For operators doing this on, say, four pads simultaneously, the capital outlay could approach $150 million prior to any revenue coming in. 

Definitely a game for the Big Boys. 

(That executive also stressed that the logistics could be daunting trying to develop 16/20 wells simultaneously, but the 'discount/efficiencies' could be well worth it when giving a LOT of business to the chosen oil field service contractors).

By the way, there's another way for smaller companies like Bruin to pay for the fracking. [The drilling costs are almost inconsequential compared to everything else, especially fracking.] Some operators will share in the production with the servicing / fracking companies to pay off the costs of the work. I've seen that talked about elsewhere -- overseas? I don't know if it's being done in the Bakken?  

Regardless, once the cash flow starts, it becomes easier to tackle the next big project. 

 

Pad Drilling -- Update -- January 25, 2019

Re-posting. This is a must-read for those interested in the Bakken.

RBN Energy: part 2, will large-scale pad drilling buoy crude output?  An incredibly good article. I was surprised that the Bakken was not mentioned, unless I missed it.

When crude oil prices crashed in the second half of 2014 and 2015, producers survived by becoming leaner and more efficient. That transition included drastic reductions in the rates paid to services companies while wringing ever more oil and gas out of each well and, in the process, permanently altering the economics of drilling and completion. This year, producers are again facing a lower-price environment; since early October (2018), crude prices have dropped more than 30%. In the current, more conservative investment environment, can producers do it again? Can additional value be squeezed out with bigger well pads and longer laterals? Today, we continue a series exploring the benefits and risks of these highly concentrated and highly complicated operations. 

Earlier we explored the origins of pad drilling and the factors that catalyzed its widespread adoption across the oil patch. By splitting the substantial infrastructure, logistical, and rig-mobilization costs among multiple wells, pad drilling helped improve efficiency the last time crude prices dropped. That blog’s focus was on Northeast gas producers. Now we turn our attention to the crude-focused Permian. We’ll start with a look at a “mega-pad” with more than 60 wells and a couple of somewhat smaller pads, then conclude with a high-level analysis of the pros and cons of “going big.”

Archived. Episode 1 was also archived.

It seems the writer hints at the halo effect but not fully developed. 

Random Look At Six EOG Hawkeye Permits Renewed Today -- November 3, 2016

Earlier today it was noted that EOG renewed six Hawkeye permits in Antelope oil field. This will be a 7-well pad; there is already one producing well on that pad.

I'm mentioned this well in a number of locations on the blog.

• 24337, 2,519, EOG, Hawkeye 3-2413H, Antelope, middle Bakken, 28 stages; 9.7 million lbs sand; 133K in less than four months; t5/13; 2 sections; TD = 20,626 feet; cum 650K 9/16;

This may be the best post. In addition, I follow the EOG Hawkeye in Clarks Creek / Antelope area here.

This is a screenshot of the proposed 7-well pad:

And zooming out to see the general area:

Example Of CLR's Approach To Full-Field Development Using The Jersey Pad As An Example -- September 23, 2014

Take a look at these CLR wells, currently on confidential status with one rig-on-site. Below the graphic a very, very long note from a reader on "field development."

These are the Jersey wells which I posted back on March 26, 2014.

Note: one Jersey well was reported dry, most likely due to "early" casing problems:

• 27832, dry, CLR, Jersey 29-6H, Alkali Creek, a 4-section well; no production data, nothing yet in the file report that might explain what happened;

I hope Vern Whitten documents a photographic history of this mega-pad.

Here is the long note from a reader who discusses these Jersey wells:

At Continental's 3Q13 earnings call last November 7, the one where Harold Hamm laid out his "ears pinned back" program, Winston Bott - Continental's then President and COO, stated they intended to insure they get production online as quickly as possible and "don't inventory capital" as they move to larger and larger pads.

Bott indicated Continental would segregate these mega-pads into subareas to enable them to drill, complete and bring 7 or 8 wells online at a time.  He said they would sequentially go through the entire pad this way until it was completely online.  The implication is Continental will perform simultaneous operations whenever possible, as they develop a mega- pad.

This is the basis of my understanding of their full-field development approach.

Continental has 30 Jersey wells sited in the northeast quarter of section 6-153-93.  The main pad has three strings of 7, 7, and 8 wells running basically north-south in SENE - see the graphic above.  A separate pad with two strings of 3 and 5 wells is located close to the north section line.

Five wells on the main pad's furthest east string have been spud this year, and I believe drilling is finished on them.  These wells are:

• 27828, Jersey 25-6H, spud 7/11
• 27829, Jersey 26-6H2, spud 5/16
• 27830, Jersey 27-6H1, spud 5/16
• 27832, Jersey 29-6H, spud 3/13
• 28333, Jersey 29-6XH, spud 5/16

The 29-6H was the first Jersey well drilled, and as you recently noted the well came off the confidential list about a week ago, and was reported "dry" due to an apparent issue with the surface casing.  The Jersey 29-6XH is its replacement well. [Note the nomenclature.]

The Cyclone 35 rig has been reported on the main Jersey pad since March.  The Active Drilling Rig List has shown it on the Jersey 25-6H well since July 11, until today when the report shows the rig on the Jersey 1-6H well as of September 12.  This latter well is located on the smaller 8-well pad to the north.  I sense Continental may not bother to provide updated rig information to the NDIC.

Six of the wells on the smaller 8-well pad have recently been spud:

• 27997, Jersey 1-6H, spud 8/30
• 27996, Jersey 2-6H2, spud 8/29
• 27995, Jersey 3-6H1, spud 8/28
• 28002, Jersey 4-6H3, spud 9/1
• 28000, Jersey 6-6H2, spud 8/27
• 27999, Jersey 7-6H1, spud 8/29

Based on the directional information Continental provided last fall, it is likely they will complete the four wells already drilled on the main Jersey pad, as they concurrently proceed with drilling the six wells recently spud on the smaller pad.

The Jersey wells provide a somewhat unique challenge with the Lake and topology.  I believe this forced Continental  to utilize a separate pad to accommodate their operations at this venue, and that they will develop future mega-pads without building separate pads whenever possible.

For your reference I scanned and attached as a pdf Continental's Jersey Wells Array Plan prepared in January of this year, and a Vicinity Map of section 6-153-94, the location of the Jersey wells.  These documents were obtained from the Jersey 29-6H well file.  The eight wells on the separate, smaller pad are not listed on the Vicinity Map.  Also, Continental has since removed "Federal" wherever it appeared in the Jersey well names.

 Here are the two graphics the reader sent me; they should be self-explanatory:

Pad Drilling In The Bakken

The Minot Daily News is reporting: (the story was sent to my two readers, thank you)

In 2013, two thirds of the permits issued for drilling wells in the oil patch were for multi-pads, said Alison Ritter, public information officer for the North Dakota Department of Mineral Resources in Bismarck.

The majority of operators in the Bakken are drilling multi-wells on a single pad, Ritter said. "The average number is four on a pad."

But a pad could have eight to 20, she said.

Rory Nelson, of Williston, was named North Dakota's energy impact coordinator last year. Nelson told members of the Minot Area Chamber of Commerce's Energy Committee at a meeting in Minot recently, that by drilling multi wells on a pad more of the formation can be drilled and more oil can be recovered. "It actually makes the infrastructure a little bit easier," he added.

Although pad drilling is being done by most of the Bakken operators, there are some fields with single wells drilled, Ritter said.

Continental was one of the first companies to drill multi-wells on a single pad. The company completed its first multi-wells on a single pad called ECO-Pad in 2010 in Dunn County (four wells from a single drilling pad) from the Three Forks and Middle Bakken Formations of the North Dakota Bakken, according to the company website.

Several story lines follow from that:

• one rig on a pad drilling 20 wells, could take two years to complete; mini-manufacturing site
• two 20-well pads back-to-back (across the road from each other), one rig for both pads: 4 years
• 40 wells x $7 million = $300 million just to drill, complete
• the speed with which operators moved to multi-well pad drilling has been nothing short of phenomenal
• twenty horizontal wells in close proximity leads one to consider different completion techniques
• might operators be able to frack every other horizontal and get about the same production? or frack every third horizontal? come back and frack others later? 

One might get some insight into where completion techniques are headed with Mike Filloon's article over at SeekingAlpha. 

What The Success Of CLR's Hawkinson Unit Means: More Mega-Pads; Four Dedicated Rigs Drilling These Pads

From a Bank of America/Merrill Lynch report following CLR's 3Q13 earnings report:

With the successful initial performance at the Hawkinson Unit, CLR announced that
the first area of full development will be in the Antelope prospect area of McKenzie
and Williams counties. Over the next four to five years, it intends to drill 350 wells on
20 to 30 well pad locations. In 2014, it will have four dedicated rigs with plans to drill the Middle Bakken, TF1, TF2 and T3 on 1,320 ft interval spacing.

350/25 = 14 wells/pad. 

Click here to get an idea of what a 14-well pad will look like. 

This is the screenshot of the CLR Hawkinson graphic from CLR's November 6, 2013, earnings presentation.

Double-clicking on the graphic will open it in another window allowing the user to zoom in.

The Bakken As Laboratory; 48 Wells In A Spacing Unit

Hold this thought:

SeekingAlpha is reporting:

Initially EOG believed that from 640 acres of its Eagle Ford property the company could recover 4.5 million barrels using 65 acre spacing.

Through trial and error, EOG has discovered that 40 acre spacing is actually going to work better which means the company will increase the amount of oil recovered by 42% and the net present value of that acreage from $76 million to $103 million.

In an age of increasing oil prices, I believe holding companies like EOG that control the most oil in the ground is a sound strategy. Time and experimenting with how to develop the land is going to increase the value of the acreage these companies control.

CLR is testing the same hypothesis in the Bakken.

Related links:

• Graphic of lower bench drilling
• Approaching one million bbls -- the monster CLR Whitman well  

Before we get started, let's break down the paragraph in bold:

• through trial and error
• 40-acre is better than 65-acre spacing in some areas of the Eagle Ford
• closer spacing will increase the recovered amount of oil by almost 50%
• closer spacing will increase the value of that acreage from $75 million to $100 million (not trivial)

So, now, back to the Bakken.

• First it was one well in each section; the face of the Bakken was CLR. 
• Then, evidence that middle Bakken and Three Forks do not communicate (CLR). 
• Then it was four-well ECO-pads (CLR).  
• Then it was six-well, eight-well, and 10-well pads (CLR, QEP). 
• Then it was multi-well pads targeting the middle Bakken AND the Upper Three Forks (CLR).
• Then it was pilot projects targeting the MB, and the top three benches of the TF (CLR, KOG).
• Evidence that new fracks help neighboring, older wells (I forget where I posted that; I will see if I can find the post later).
• Then massive fracks (62 stages; 12 million pounds; EOG).

Now, back to an early graphic of targeting multiple sub-formations in same spacing unit (same link as above).

Now, a graphic of how CLR spaced twelve or fourteen wells in one spacing unit in the past. These are the Hawkinson wells in Oakdale oil field. Note how the wells are spaced across (east-to-west) the 1280-acre stand-up (running north-to-south) spacing unit:

It's hard to tell, the wells are pretty bunched up in the small graphic, but there are 12 wells in the north running south (3-1-5-3) and then two additional wells running from the south (14 horizontals total in this spacing unit). And, oh by the way, two old Madison wells that are now abandoned (one produced 110,000 bbls of oil; the other 340,000 bbls of oil).

So, stopping for a minute to catch our breath. Look at again at the milestones above, looking at the Bakken as a laboratory, perhaps led by CRL, QEP, CLR, KOG, and many others.

Now, and this gets most interesting. This was noted by a reader (thank you). I don't read NDIC cases or orders so I would have missed this. I would have eventually seen it, but I would not have seen the back story. And in this case, the back story is as important as the outcome.

This is a graphic from NDIC Case # 20678 and NDIC Order # 22983:

I hope you all see what I'm seeing (and what I think the reader who sent me this link saw); I hope I am not misreading this.

First, this is a stand-up spacing unit, just like the Hawkinson wells in the Oakdale oil field.  These are sections 28 and 33 in T146N-R95W, in Chimney Butte oil field. [Chimney Butte is southeast of Oakdale; they touch at their southeast/northwest corners; both in Dunn County, both outside the reservation.]

This is what I'm seeing.

In the Oakdale/Hawkinson wells, the wells were spaced across the entire spacing unit, west-to-east.

However, in the Chimney Butte/Hartman wells, CLR will place 12 wells (ten new ones, two existing ones) in one-half of one-half the drilling unit. The wells will target the middle Bakken, and the upper three benches of the Three Forks.

If successful, this could work out to 48 wells in one 1280-acre spacing unit. The norm in the Bakken is the long lateral (1280-acre spacing) but if they ever go back to short lateral/640-acre spacing, one could see 96 wells in two sections. Of course, by that time, I will be long gone. And, of course, by then, perhaps water flooding or EOR. I'm still convinced that best recovery occurs closer to the heel (closer to the kick-off point) than the toe (where the horizontal ends). But I digress. Ignore this paragraph.

Now the back story that is in the case/order that I would not have seen had the reader not sent it to me (again, a huge thank you). Both MRO and BR, who have working interests in these wells, objected to the proposal. They wanted a full hearing by the commission, or something along that line (I went through it quickly, and probably missed some of the details). The arguments submitted by MRO and BR: a) too many unnecessary wells; b) correlative rights; and, c) the risk of setting a precedent for density drilling.

My two cents worth, regarding the objections:

• Setting a precedent: ever since the 1960's with the adoption of situational ethics, "precedent setting" pretty much went out the window. By the way, a lot of wind was taken out of the "precedent-setting" argument: CLR already has a 14-well pad in the northwest corner of one section southwest of Williston (see graphic at the bottom of the post).
• Correlative rights: a grab bag term; in a cultural analogy, it is nothing more than playing "the race card." MRO and BR were simply looking to get additional mineral rights owners on their side. My hunch: mineral owners were thrilled to be telling their friends there could be as many as 48 wells on their spacing unit, and all paid for by the oil companies (except for those mineral owners who choose to participate). 
• Too many unnecessary wells: that's a legitimate argument. But we will never know if we don't try, will we? See milestones and links above, as related to the Bakken "as laboratory."

Are you still "holding that thought"? The one at the very top of the blog: through trial and error EOG discovered that 40-acre spacing was much better than 65-acre spacing in the Eagle Ford in 640-acre sections. Trial and error.  The Bakken as laboratory. We won't know until we try.

A few years ago, MRO and BR could have objected to multi-well pad drilling due to a) unnecessary wells; b) setting a precedent; and, c) correlative rights.

I see CLR as the scrappy fighter that keeps pushing the envelope (to coin a phrase) whereas BR (part of COP) as being very, very conservative, and plodding. MRO, ditto, but it pains me to say that.

With the Feds ready to lay down new fracking rules, it might be nice to get as many of these permits approved as possible. Once those rules come down, a nine-month inventory (or more) of permits might be nice to have.

There are still more story lines to this case/order but I will stop for now.

The graphic of CLR's 14-well pad in the northwest corner of section 6-153-101.

The section lines, in red, are horizontal/vertical. The red diagonal line is the Missouri River bridge southwest of Williston. The blue is the Missouri River; the dotted line is the Williams County/McKenzie County line. The little man on the bank is landing an 8-pound walleye. Just joking.

Thirteen (13) New Permits On The 13th -- Newfield Reports a Nice Well -- The Williston Basin, North Dakota, USA

Daily activity report, April 13, 2012 --

Operators: Burlington Resources (6), Zavanna (2), OXY USA, CLR, Whiting, Oasis, Fidelity

Fields: Camel Hump (Golden Valley), Bull Butte (Williams), Stanley (Mountrail), Union Center (McKenzie), Foreman Butte (McKenzie), Little Knife (Billings), Crazy Man Creek (Williams)

It looks like BR will have a 6-well pad in Union Center.

Three wells were released from "tight hole" status; two of the three were completed/fracked, including:

• 19232, 1,423, CLR, Quale 1-1H, McKenzie,

Five producing wells were completed, including:

• 20132, 1,029, XTO, Badlands Federal 21X-13, McKenzie
• 20319, 113, KOG, Koala 2-25-36-15H, McKenzie
• 20347, 2,327, Newfield, Obenour 150-99-21-16-1H, McKenzie
• 20734, 1,093, XTO, Bennie Peer 14X34, McKenzie

Just the other day, a reader and I both questioned what was going with Newfield; we hadn't heard anything from Newfield in a long time. Well, it turns out it appears they got a good well. 

In addition, another eight (8) were said to be plugged or producing. 

Mega-Pads in the Bakken: QEP and WPX in Heart Butte and Deep Water Creek Bay

Mike Filloon mentioned that QEP has finished drilling all the wells on its 10-well pad. There are two fields in which QEP has a number of multi-well pads: Heart Butte and Deep Water Creek Bay.

Heart Butte is an interesting field, a very active field, and one with much history -- for a boom that's in its early stages. The oil field first caught my eye back in March, 2010, when I was transcribing the NDIC hearing dockets for that month:

• 12284: Questar, extending the Heart Butte Field and creating 24 640-acre spacing units in Dunn, McLean and Mountrail Counties, with two horizontal wells in each (48 wells)

This was before Questar split of QEP.

The Heart Butte oil field was also the focus for the Arrow Pipeline, a huge deal at the time for many reasons.

So, now we wait for the IPs for the ten wells that QEP has just completed.

Here are some multi-well QEP pads and WPX pads in Heart Butte and Deep Water Creek Bay:
Two 5-well pads, section 3-149-92:

23331, 2,282, QEP, MHA 1-03-34H-150-92, Heart Butte, 4 sec, t3/13; cum 42K 5/13;
23332, 2,348, QEP, MHA 3-03-34H-150-92, Heart Butte, 2 sec, t3/13; cum 48K 5/13;
23333, 2,310, QEP, MHA 1-03-35H-150-92, Heart Butte, 4 sec, t3/13; cum 40K 5/13;
23334, 1,949, QEP, MHA 3-03-35H-150-92, Heart Butte, 4 sec, t3/13; cum 35K 5/13;
23335, 1,791, QEP, MHA 2-03-35H-150-92, Heart Butte, 4 sec, t3/13; cum 27K 5/13;
23336, conf, QEP, Heart Butte,
23337, conf, QEP, Heart Butte,
23338, conf, QEP, Heart Butte,
23339, conf, QEP, Heart Butte,
23340, conf, QEP, Heart Butte,

Two 5-well pads:

• 23093, conf, QEP, Heart Butte, 
• 23094, conf, QEP, Heart Butte, 
• 23095, conf, QEP, Heart Butte, 
• 23096, conf, QEP, Heart Butte, 
• 23097, conf, QEP, Heart Butte, 
• 23098, 1,632, QEP, MHA 4-06-32H-150-92, Heart Butte, t2/13; cum 24K 5/13;
• 23099, 1,994, QEP, MHA 2-06-32H-150-92, Heart Butte, t2/13; cum 33K 5/13;
• 23100, 1,922, QEP, MHA 3-06-32H-150-92, Heart Butte, t2/13; cum 52K 5/13;
• 23101, 1,777, QEP, MHA 1-06-32H-150-92, Heart Butte, t2/13; cum 107K 5/13;
• 23102, 1,966, QEP, MHA 4-06-31H-150-92, Heart Butte, t2/13; cum 51K 5/13;

Two 5-well pads, 31-150-91
(I don't know if this is the 10-well pad Filloon is referring to), Heart Butte:

• 21551, 2,757, QEP, MHA 3-31-25H-150-92, 4 sec, t10/12; cum 89K 5/13;
• 21552, 2,351, QEP, MHA 2-31-25H-150-92, 4 sec, t10/12; cum 74K 5/13;
• 21553, 2,202, QEP, MHA 4-31-25H-150-92, 4 sec, t10/12; cum 85K 5/13;
• 21554, 2,430, QEP, MHA 1-31-30H-150-91, 4 sec, t10/12; cum 78K 5/13;
• 21556, 2,376, QEP, MHA 3-31-30H-150-91, 4 sec, t10/12; cum 70K 5/13;
• 21557, 2,140, QEP, MHA 1-31-36H-15-92, 4 sec, t5/13; cum 14K 5/13;
• 21558, 2,359, QEP, MHA 3-31-36H-150-92, 4 sec, t5/13; cum 18K 5/13;
• 21559, 2,032, QEP, MHA 5-31-25H-150-92, 4 sec, t5/13; cum 12K 5/13;
• 21560, 673 QEP, MHA 7-31-25H-150-92, 4 sec, t5/13; cum 19K 5/13;
• 21561, 1,731, QEP, MHA 1-31-25H-150-92, 4 sec, t5/13; cum 9K 5/13;

32-150-91, Heart Butte; one 4-well pad and one 2-well pad

• 20487, 606, QEP, t11/11; cum 160K 5/13;
• 20488, 1,571, QEP, t11/11; cum 182K 5/13;
• 20489, 933, QEP, t11/11; cum 141K 5/13;
• 20490, 2,609, QEP, t11/11; cum 243K 5/13;


• 22028, 2,737, QEP,  MHA 2-32-29H-150-91, t11/12; cum 91K 5/13;
• 22029, 1,961, QEP, MHA 4-32-29H-150-91, t11/12; cum 84K 5/13;

A 3-well pad, and two 4-well pads in 31-148-92, Heart Butte:

• 22649, 709, WPX, Charles Blackhawk 31-30HA, t11/12; cum 63K 5/13;
• 22650, 247, WPX, Charles Blackhawk 31-30HX, t11/12; cum 50K 5/13;
• 22651, 219, WPX, Charles Blackhawk 31-30HB, t11/12; cum 62K 5/13;

• 22652, conf, WPX, Charles Balckhawk 31-30HY, 
• 22653, conf, WPX, Charles Blackhawk 31-30HC, 
• 22654, conf, WPX, Charles Blackhawk 31-30HZ,
• 22655, conf, WPX, Charles Blackhawk 31-30HD,

• 21904, 1,542, QEP, MHA 4-06-07H-147-92, Heart Butte, t8/20/12; cum 101K 5/13;
• 21905, 2,223, QEP, MHA 2-06-07H-147-92, Heart Butte, t8/17/12; cum 81K 5/13;
• 21906, 2,142, QEP, MHA 4-32-33H-148-92, Heart Butte, t8/15/12; cum 75K 5/13;
• 21908, 2,180, QEP, MHA 2-32-33H-148-92, Heart Butte, t8/22/12; cum 83K 5/13;

5-149-90, Deep Water Creek Bay

• 21091, 499, QEP, t7/12; cum 54K 5/13; 
• 21092, 436, QEP, t7/12; cum 51K 5/13; 
• 21093, 878, QEP, t7/12; cum 72K 5/13; 
• 21116, 952, QEP, t4/12; ccum 70K 5/13; 
• 21824, 814, QEP, t4/12; cum 53K 5/13; 

18-150-90, Deep Water Creek Bay

• 17434, 880, QEP, t1/09; cum 145K 5/13;
• 17940, 1,217, QEP, t1/10; cum 211K 5/13;
• 18930, PNC, QEP
• 18991, 1,053, QEP, t9/10; cum 148K 5/13;
• 19683, 766, QEP,  t12/11; cum 115K 5/13;
• 20271, 592, QEP, t12/11; cum 102K 5/13; 

Some time ago I mentioned that I was no longer tagging/labeling "multi-well pads" because this was becoming too commonplace. I am now tagging/labeling "mega-pads"which have more than 5 wells on the pad. This is different than the tag "mega-units" which generally refers to 2560-acre spacing units, but at least 1,920 acres.

Note: there may be some errors on the data above; it was done quickly and not double-checked.

Investing: QEP

As of November 14, 2010, this page will follow only QEP, not Questar. 

Yahoo!Finance: QEP

Finance!Yahoo: STR
4Q09 Earnings Conference Call
Annual Report, SEC Filing, 2009

NEWS

June 12, 2015: huge sand fracks.

January 30, 2014: QEP to spin of midstream business, QEP Field Services, will sell off non-core assets.

October 14, 2013: QEP will request permission to unitize the Helis-Grail. 

May 26, 2013: from Mike Filloon --

QEP Resources  has built a position in the Bakken to increase oil production. Some believe it spent too much to get the Helis acreage in northeast McKenzie County. My guess is it wasn't just purchasing the acreage, but also the know-how behind some of the best Three Forks wells in North Dakota. It closed the purchase in September of 2012. At the beginning of this, it began pad development. It has 4 rigs here, and plans a 5th by year end. It plans to stick with 8 wells per 1280 acre spacing. 4 wells will target the middle Bakken and 4 the upper Three Forks. QEP reported much lower crude production than expected in the first quarter. It spent the first three months of the year drilling pad wells in the Bakken. All of the wells must be drilled before completion work starts. This will push the majority of production into upcoming quarters. QEP only turned one South Antelope well to sales in the first quarter. The IP rate was not great at 1,397 boepd, but at the end of the first day of production this increased to 3,100 boepd. I don't like mentioning peak rates for production, but it is meaningful because the peak was at the end of the day and not the beginning. Well costs have decreased to $11 million in South Antelope.

QEP completed 11 Fort Berthold wells in the first quarter. Six (6) were middle Bakken and the other 5 in the upper Three Forks. The average IP rates were 2,190 boepd in this area. In Skunk Creek it completed 5 wells with an average IP rate of 2,479 boepd. A third party produced water gathering system is now completed, it saves QEP $5/barrel. Bakken crude sold for 96% the price of WTI or $90.81/bbl in the quarter. This compares to 88% the price of WTI in the first quarter of 2012. On the reservation, well costs are $10.8 million. It believes under $10 million as a target cost/well is possible by the end of this year. Decreased costs will be seen through pad drilling, fracs with more sand and using ceramic tails, but decreased drilling and completion times. Three rigs are running here. QEP has several pads under development. The most important is the Independence pad in Fort Berthold. It consists of 10 wells. One is being drilled with four waiting on completion. There are two additional four well pads on the reservation. In South Antelope, QEP has two four-well pads and one two-well pad. One of the four well pads has one drilling and three awaiting completion.

April 17, 2013: QEP has permits for 12 wells in one section in Heart Butte, in a 2560-acre spacing unit. 

November 1, 2012: highlights of 3Q12.

August 23, 2012: The Biggest Story of the Year to Date

• QEP Pays $1.3 Billion for Larger Stake in the Bakken
• Includes 27,600 net acres in the Heart of the Bakken 
• Black Hills Corporation sells some Bakken assets to QEP 
• Helis, LLC sells Bakken assets to QEP

April 9, 2012: QEP has completed drilling on its 10-well pad in Heart Butte oil field.

November 12, 2010: Questar approves spin-off.

July 15, 2010: Spin-off and name change, June, 2010. The exploration and development company, now known as QEP, was spun off from Questar Corp (STR) in June, 2010.

April 22, 2010: Questar is considering a tax-free spin-off of its exploration and production (E & P) businesses. One company would be involved with oil and gas exploration and production; the other company would be primarily a pipeline company.

BACKGROUND

I had not  heard of Questar (NYSE: STR) until I started following the Bakken. Questar might be something to consider by those who are concerned about the more speculative, smaller companies operating in the Bakken but don't want to invest in the major players in the Bakken either. Questar seems to be somewhere in the middle.

At first blush I would not have been interested in this company because it seems to be a natural gas play more than an oil play, and I don't know the natural gas industry as well as I think I understand the oil industry. (If I understand 1% of the oil industry, I understand 0.1% of the natural gas industry.)

I do not own any Questar shares and I don't plan to buy any in the near term. Here I look at Questar just as I looked at EOG some weeks ago. I also do not own any EOG shares.

COMMENTARY

A quick look at some basic data points from Yahoo!Financial key statistics regarding STR, compared to a few other companies operating in the Bakken, follows the commentary. The more I look at STR suggests this may be one of the few publicly traded companies that is very, very safe to invest in, and is just getting into the Bakken. This might be an opportunity to actually get into the Bakken if you have not yet invested in the Bakken. But Questar has major exposure to natural gas. Just saying.

Again, here is the link to the 4Q09 conference call.

The downside for me with regard to STR is their huge exposure to natural gas. The upside is the apparent interest by STR to increase their oil presence in the Bakken. The company has lowered its earnings estimates for natural gas going forward.

With regard to earnings, Questar had the second best earnings quarter (4Q09) in the company's history, only $200,000 lower "than the high water mark set in the fourth quarter of 2008." If folks remember correctly, we saw a price spike of $150/barrel of oil in 2008.

Questar is operating in five locations: Haynesville shale (Louisiana, natural gas); Pinedale Anticline Project Area (PAPA, Wyoming, natural gas), Granite Wash (Texas), Woodford Shale (Oklahoma, natural gas), and Bakken Oil.

In addition to these five E&P plays, Questar operates the following businesses:

Wexpro: E&P in the Rockies
Questar Gas Management: midstream business; could be a transforming year in 2010
Questar Pipeline: a regulated business; includes Wyoming
Questar Gas: a regulated business, natural gas distribution (Utah, SW WY)

Relatively high IPs were highlighted by Questar in their 4Q09 conference call, suggesting to me this company knows there is some value to high IPs. North Dakota passed tax incentives in 2007 to encourage drilling in the Bakken; the incentives affect the first 75,000 barrels of production.

Market caps; P/E; P/E, going forward; dividend (%); debt; operating cash flow:

EOG: $24 billion; 44; 15; 0.6%; $2.8 billion; $2.9 billion
STR: $7.5 billion; 19; 15; 1.2%; $2 billion; $1.6 billion
CLR: $6.8 billion; 96; 19; 0%; $0.5 billion; $0.375 billion
MDU: $3.9 billion; N/A; 12; 2.1%; $1.5 billion; $0.8 billion
BEXP: $1.68 billion; N/A; 24; 0%; $0.16 billion; $0.03 billion

Debt as percent (%) of market cap:

EOG: 12%
STR: 27%
CLR: 7%
MDU: 38%
BEXP: 10%

Is MDU an outlier with regard to debt as percent (%) of market cap?

MDU: $1.5/$3.9 = 38%
OTTR: 502 million 730 million = 69%
BKH: 1.15 billion / $1.12 billion = 103%

Is it possible to estimate Questar's potential recoverable oil in the Bakken?

Some data points: Questar has 80,000 net acres in the Bakken. (4Q09 conference call)
80,000 acres/640 acres per section = 125 sections.
In the best field (Parshall), EOG estimates 700,000 barrels EUR (per well)
EOG has been putting one well in each section
CLR opines that dual laterals could increase the EUR by another 400,000 barrels EUR.
36 sections/township: 125 sections / 36 = 3.5 townships.
At least one of "STR's townships" seems to be a "good" area.

Now some "back of the envelope calculations":
Let's say STR's acreage is 1/4 as good as EOG's best estimate: 1/4 of 700,000 = 175,000 bbls/well
125 sections: 125 wells x 175,000 bbls = 22 million barrels

What if they had 1/2 of the 700,000 plus 1/2 of what the dual lateral would add? 350,000 + 200,000 = 550,000.  125 wells x 550,000 = 70 million barrels. 

Activity in the Bakken

2008: three permits

17434, 880, 150-90, Deep Water Creek Bay
17929, permit, 150-90, Wild, nr DWCB
17940, 1,405, 150-90, Deep Water Creek Bay

2009: three permits

18158, 780, 149-90, DWCB
18322, permit, 150-92, Van Hook
18331, permit, 152-92, Van Hook

2010: four permits to date

18665, confidential, 149-91, Heart Butte
18666, confidential, 149-91, Heart Butte
18885, new permit, Deep Water Creek Bay, 150-90
18886, new permit, Deep Water Creek Bay, 150-90

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