Low Water Fracks -- Enerplus -- We've Seen This before -- November 19, 2020

We've seen this before:

• 35966, drl/A, Enerplus, Yellowstone 148-95-02B-11H, Eagle Nest, t--; cum 124K 9/20; a 27K month; 33-025-03655; fracked 3/9/20 - 3/21/20; 6.6 million gallons of water; 67% water by mass;
  
• 22574, drl/A, Enerplus, Glacier 148-95-02A-11H TF, Eagle Nest, t--; cum 117K 9/20; a 27K month; 33-025-01651; fracked 3/10/20 - 3/20/20; 6.5 million gallons of water; 67% water by mass;
  
• 35967, drl/A, Enerplus, Everglades 148-95-02A-11H-TF, Eagle Nest, t--; cum 105K 9/20; a 30K month; 33-025-03656; fracked 3/9/20 - 3/21/20; 7.5 million gallons of water; 68%% water by mass; 
  

From "completion strategies, 2020":

Enerplus:

6 - 8 million gallons of water; 65% water by mass; link here; "National Park" wells in Eagle Nest oil field;

Something New In The Bakken? EOG, Fracking, Water Percentage By Mass, Sand -- March 8, 2020

Something new in the Bakken?

It begins at this link, posted a few days ago. It's a long, long note, interrupted by screenshots of data from FracFocus. I've added the notes a reader sent me almost immediately after posting that note. I delayed posting the reader's note until I had a chance to do some background reading.

Now, hold that thought -- the staggering production of that EOG well; the staggering amount of water used; and, the relatively large amount of sand -- relative to water by mass (percentage).

Now, go to these three EOG wells that will come off the confidential list this week. In two of the cases we have FracFocus data. Note again, the relative large amount of sand compared to the amount of water by mass. Generally I expect 87% to 93% water by mass in the FracFocus data but in this case, FracFocus reports 81% water by mass in one case; and, 83% water by mass in the second case.

FracFocus did not have data for the third well.

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Other Wells Of Interest

Completely unrelated to the note above, two wells have been added to the index of wells of interest:

• 28747, Clarks Creek, Slawson, Jore Federal; jump in production; 
• 17421, Union Center, BR, several Midnight Run wells off line without explanation, 1/20; 

It really is not much benefit looking at these wells. I do this for my benefit to remind myself to check back on these wells later. 

Only In The Bakken: A Bakken DUC Out-Produces The Average Permian Well -- March 6, 2020

Comparing the Bakken with the Permian? Here are the dashboards --

EIA dashboards:

• natural gas storage 
• EIA pdf, Bakken: https://www.eia.gov/petroleum/drilling/pdf/bakken.pdf
• EIA, pdf, Permian: https://www.eia.gov/petroleum/drilling/pdf/permian.pdf
• EIA, pdf, Eagle Ford: https://www.eia.gov/petroleum/drilling/pdf/eagleford.pdf

A closer look at the two wells that came off the confidential list today:

• 35100, SI/NC, Oasis, 33-053-086100, Kellogg Federal 5297 12-30 8T, Banks, a DUC, but with huge production; 8.8 million gallons of water; 93.7% water by mass;
• 23958, 2,719, EOG, 33-061-02281, Liberty LR 107-1109H, Parshall, t9/19; cum 178K 1/10; 53 stages, 22.8 million lbs; 12.5 million gallons of water, 82% water by mass;
  

First, #23958, EOG, middle Bakken, 53 stages; 22.8 million lbs (no typo):

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	1-2020	31	21837	21770	36701	17556	17191	4
BAKKEN	12-2019	31	27128	27191	45940	15297	14970	13
BAKKEN	11-2019	30	35307	35346	59040	19680	17412	1918
BAKKEN	10-2019	31	38687	39180	72239	26707	24625	1716
BAKKEN	9-2019	25	55045	54159	95098	38709	37865	0

Now, #35100, Oasis, yes, it's still classified as a DUC. This is pretty good for a DUC:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	1-2020	31	13750	13753	25438	36120	34862	1041
BAKKEN	12-2019	31	18076	18073	31976	44105	41944	1943
BAKKEN	11-2019	30	18196	18197	34993	43173	42075	888
BAKKEN	10-2019	31	23457	23589	37556	51515	46564	4734
BAKKEN	9-2019	10	3059	2918	8109	5921	5832	20
BAKKEN	8-2019	0	0	0	0	0	0	0

Observations:

• mega-frack by EOG -- 22.8 million lbs of proppant; EOG has always pushed the envelope on sand; they had their own sources; first to build a terminal unloading facility in the Bakken, etc.
• and look at this: total gallons of water not all that high in that EOG mega-frack: only 12.5 million gallons; well, if they didn't use so much water mr-know-it-all, why did the proppant "weigh" so much -- look at the percent water to total amount of proppant -- 82%. Generally, operators use around 93% water by mass; sometimes as low as 87% but "never" as low as 82%; EOG used a lot of sand, but not that much more water than usual for the Bakken; sand weights 1.6x that of water;
• for a DUC, #35100 is producing nicely (yes, I know, technically it's no longer a DUC, it's been completed, but according to the NDIC scout ticket, still a DUC - SI/NC)
• #23958, back to that EOG mega-frack; it produced 55K bbls of crude oil in 25 days; extrapolates to 66K bbls in a 30-day month;
• neighboring wells to that EOG mega-frack; both neighbors not that close to the new well, but:
• one: a subtle jump in production; not much production increase, but nice to see a bit of a jump;
• the second: a larger jump in production; not huge, but more noticeable;
• the EOG mega-frack well on a pad with four locations to drill:
• one of the others is still LOC only; #33434;
• the other two are big producers but still on conf status (#33433, #33432)

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FracFocus

Links:
nice review, 2019;
2018;
2019;
minimal info, 2019;

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Commentary

Shortly after posting the original note (and before I added the FracFocus data and the links, I received this note from a reader (and that's why I added the FracFocus data and the links). I purposely delayed posting the reader's note to give me a chance to do some background. Here's the reader's comments:

Bit of a coincidence that, just today, I was reading a bit about a company touting its brand of High Viscosity Friction Reducer (HVFR) that could be variably tweaked to carry a LOT of proppant, if the operator so chose. 

Regarding this EOG well ... 12.5 million gallons water used for frac'ing is ~298 thousand barrels.

Yet, in just a few months, ~309 thousand barrels have been recovered.

I am wondering if EOG has uncovered a method to maintain VERY high pressure underground, deliver a VERY high payload of proppant, and not use an inordinately high amount of water to do this.

Several potential ramifications immediately come to mind ... one being a diminished halo effect (water not travelling/impacting adjacent wells).

Another consequence could be reduced incidence of frac hits (again, lowered water amount and MUCH tighter control of the frac geometry).

As you might say "don't want to get ahead of my headlights", but if my speculations are correct, this could usher in another iteration of well completion technology. Keeping an eye on this well's future production could be very informative.

CO2 Fracking Coming To The Bakken -- July 2, 2015

Bakken.com is reporting:

Utilizing carbon dioxide (CO2) as an energized fracturing fluid is a common practice in Canada. In the United States, however, introducing new methods of enhanced oil recovery and well stimulation usually requires a global oil player to lead the charge.

As reported by Hart Energy’s E&P Magazine, Statoil has a reputation for being open to embracing new and innovative technologies to tackle the big challenges facing the industry. Later this year, Statoil will pursue expanding such innovations and begin stimulation tests on its Bakken acreage using a CO2 enhanced oil recovery method to determine if the process is as promising as its modeling indicates.

According to a Statoil-issued release, the test will be conducted at a well site approximately 15 miles outside of Williston, North Dakota. The trial will evaluate the possible production uplift while reducing the amount of water used in a large, multistage hydraulic fracturing operation. The test will be a step toward the company’s overall goal of increasing the efficiency and sustainability of its unconventional drilling operations in the Bakken, Eagle Ford and Marcellus regions.

As a means to increase the chances of success, Statoil has sought out a partner company for its well stimulation program. The CO2 test is one of several projects being pursued under its Powering Collaboration initiative, the technology partnership between Statoil and GE that seeks to accelerate the development of sustainable energy solutions.

Specifics:

“We will use liquid CO₂ as the initial fracturing medium because we believe that it will create a more complex fracture network, giving increased surface area, which should increase the ultimate oil recovery,” he said. “Our modeling and laboratory experiments suggest that we could increase recovery by 20% to 25%.

We will then complete the stimulation using a more standard water and proppant pack. By using CO₂ for the initial stimulation, we project that we will use 20% to 40% less water than normal in the test phase. Ultimately, as the technology matures, we hope to be able to further reduce water usage in the stimulation process. Providing the test shows positive results, the next phase will be to develop a cost-effective system to capture the CO₂ as it flows back and reuse it for stimulating new wells.

This is where the collaboration with GE comes in. Its main part of the project is to use its world-leading engineering and technical expertise to develop this capture and reuse system. We are very excited about this upcoming test phase and subsequent progress of this project, which is one of several exciting new technologies we are developing with GE as part of our Powering Collaboration Initiative,” Tocher said.

Meanwhile, the USGS has just released a study on water and fracking across the US. Link here. The article doesn't say much that we didn't already know. I talked about water and fracking ad nauseum when I first started blogging about the Bakken, and occasionally re-visit the issue. For newbies: water is not an issue for North Dakota.

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Note to the Granddaughters

Tonight on the nightly news, there was a story about putting peas in/on guacamole. I told our granddaughters I don't want peas on my guacamole and I don't want pee in my pool.

Our 9-year-old is going to make a sign for their swimming pool at home:

"Welcome to our swimming ool. Note there is no "p" in our ool. We would like to keep it that way. Don't put "p" in our ool."

Data Points From Oasis Most Recent Presentation - September 6, 2014

Link here.

These data points taken from the August, 2014, presentation.

The high points for me, from this presentation as well as others:

• the wells are coming down in cost, but will likely rise again going forward due to new completion techniques
• new completion techniques: high volume proppant and SlickWater
• high volume proppant and SlickWater will add $1.5 million to 2.0 million+ to complete a well
• additional completion costs will be offset by lower drilling costs (but probably not by much)
• high volume proppant and SlickWater raising EUR curves by 35% (this number seems consistent among three operators) 
• with two dedicated frack spreads, Oasis still completes less than 40% of their own wells with their own folks
• in future earnings conference calls, analysts need to be asking about the cost of shipping proppant to the Bakken

I doubt much has changed from earlier presentations, but I have a few minutes before I leave for soccer.

Random data points (some numbers rounded).

Bakken (Montana/ND)

• 505,960 net acres
• 17 years of inventory
• 2Q14 production: 44K boepd
• 3Q14: 47 - 49K boepd
• proved reserves: 220 mmboe/ PV-10 of $5.2 billion
• West Williston : 362,000 net acres
• East Nesson: 145,000 net acres
• highest working interest: 68% average WI

Plans to advance/expand infrastructure development

• double Oasis Well Services
• grow Oasis Midstream Services

Operations (2014)

• 16 rigs
• further TFS delineation
• loe: $8.50 - $10.00/boe
• mg&t: $1.20 - $1.60/boe

Rig allocation

• Montana: 2
• West Williston: 8
• East Nesson: 6

Well completion costs

• 2012: $9.7 million
• 4Q13: $7.9 million
• 1H14: $7.6 million

EURs

• vary across the Bakken: 450K boe to 750K boe
• 35% production uplift seen using SlickWater in Montana (Hebron)

Very early in TFS delineation

• the economic boundary of the TFS is expanding (slide 10); it's possible the Cottonwood field will benefit (TF2 and TF3)

Slickwater:

• 1st TFS well produced 37% better than comparable well
• 1st Montana well produced 35% better than Montana type curve

Frack spreads

• 2nd frack spread at 100% utilization as of August, 2014
• 2 spreads will complete up to 40% of Oasis completions
• OWS first spread has returned 2.8x the cash invested into business since inception

Cost Of Slickwater To Complete A Well -- Not Trivial -- September 3, 2014

From a SeekingAlpha article on Oasis:

Oasis had previously established itself as a "fast follower" when it came to drilling and completion techniques. Oasis lets companies like EOG or Whiting be more adventurous with new techniques to enhance productivity and/or lower costs and then tries them out on their own acreage. In particular, Oasis has been targeting a switch to slickwater (from gel fracking fluid), optimized proppant use, and the use of coiled tubing/cemented liners.

So far, the slickwater approach seems to be paying off. Although using slickwater costs about $2 million to $2.5 million more per well (it requires almost four times the volume of water/fluids and more ceramic proppants), it has been boosting production by 30% to 35% in many cases. That's not a trivial difference, and Oasis is looking to use this slickwater approach with about 25% of its second half wells.

Yes, the most recent Halcon report suggests EURs are up 35% using Slickwater. CLR is suggesting the same degree of improvement, about 35% improvement.

750,000 bbls at $50/bbl = $37.5 million

1,000,000 bbs at $50/bbl = $50 million

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Norway's 2015 Oil, Gas Investment To Fall More Than Expected

Reuters via Rigzone is reporting:

Norway's oil and gas investments, a key ingredient of economic growth, are expected to fall more than expected in 2015, a survey showed on Wednesday, weakening the crown and increasing the chance interest rates will be kept low.

Investment on the Norwegian continental shelf (NCS) is now expected to fall 13.9 percent in 2015 from 2014, a faster rate than the 12.3 percent year-on-year drop expected in June, when compared with the same forecast released in June last year.

See also: Statoil is cutting back.

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Trapped By A Thing Called Love

  Trapped By a Thing Called Love, Denise LaSalle
"Trapped By a Thing Called Love" is the debut 1971 crossover hit single by Denise LaSalle. The single was her biggest hit on the R&B chart and her only Top 40 pop hit peaking at number thirteen. "Trapped By a Thing Called Love" was written by Denise LaSalle who also produced the song along with Bill Jones.

Halcon Earnings, 1Q14

Updates

May 13, 2014: 1Q14 Halcon transcript -- 

• almost 75% production growth qoq -- despite very harsh winter
• 25,000 bopd
• IPs improving, 10% better qoq
• in the Fort Berthold area, slickwater fracks continue to outperform the 801K EUR that the company released just a few months ago
• will test slickwater in Three Forks/Fort Berthold, but company thinks "hybrid" fracks will work better
• currently drilling 6 new wells from a single pad; 660 feet apart; IP from one of these wells set a company record of 4,225 boe
• Williams County slickwater completions outperforming the 477K EUR previously set
• El Halcon in East Texas, almost exponential; growing over 800% qoq; 10,000 boepd
• added some TMS acreage; now 316,000 TMS acres
• this is surprising: water is a cost that Halcon struggles with (as do all operators, I assume); it depends on where one is in the basin
• lessons learned in the Bakken will be taken to the TMS
• going from 4 rigs in the Bakken to "three to four rigs" but will complete just as many wells
• will concentrate on Fort Berthold this year; Williams County yet to have its day in the sun
• near the end, mentioned "coil fracking" in passing; so slickwater, coiled, and hybrid all mentioned in this conference call; no major change for Halcon how they complete their wells

Later, 11:40 p.m. central time: is the Bakken grossly undervalued compared to the Eagle Ford?

Later, 11:18 p.m. central time: production surges as earnings beat street -- Motley Fool.

Halcon Resources produced an average of 36,622 barrels of oil equivalent per day. That was above the high end of the company's guidance, which helped it top earnings estimates. Production was also 41% higher than last year's first quarter, as the company's focus on technological innovation yielded strong well results.

The company also was able to push its total operating costs lower by 8% year over year. On top of that, Halcon Resources was able to realize a higher average prices per BOE than in last year's first quarter. The combination of higher production and energy prices along with lower costs had a noticeable impact on the company's bottom line. This was evidenced as net cash provided by operating activities surged from $45.7 million in last year's first quarter to $159.5 million this quarter.

I guess the bad weather in North Dakota was fickle, hitting other operators in the Bakken but sparing Halcon. 

Later, 11:17 p.m. central time: Halcon looking to sell all non-core assets.  As previously announced, the company agreed to divest non-core assets in East Texas for $450M, subject to closing and post-closing adjustments. The transaction is expected to close in May, with an effective date of April 1. The company continues to evaluate all remaining non-core properties for additional divestiture opportunities during 2014.  

Original Post

I will have to wait to see how analysts see this report.

Reconciliation table for additional information), net income was $11.9 million, or $0.03 per diluted share, for the three months ended March 31, 2014. Halcón reported a net loss available to common stockholders of $77.9 million, or $0.19 per diluted share for the quarter. The reported net loss available to common stockholders for the quarter includes a non-cash pre-tax impairment charge of $61.2 million, primarily related to non-core asset sales.

Opening paragraph:

Halcón generated total revenues of $275.1 million for the three months ended March 31, 2014, an increase of 44% compared to the three months ended March 31, 2013. Production for the quarter was above the high-end of guidance and increased to 36,622 barrels of oil equivalent per day (Boe/d), 41% higher than the same period of 2013. First quarter 2014 production was 85% oil, 6% natural gas liquids (NGLs) and 9% natural gas.

Briefing.com confirms that this was a beat by 1 cent.

Disclaimer: this is not an investment site. Do not make any investment decisions based on what you read here or what you think you may have read here.

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A Note to the Granddaughters

Casablanca has always been my favorite movie. When I get into a Casablanca phase, I find myself watching it several times a week for several weeks. The movie may not be as good, and the movie may not have the star power that Casablanca had, but the Great Gatsby story, in some ways, might be better than the Casablanca story. For one thing, the latter is autobiographical and an autobiographical story is (should) always be better than a concocted story, no matter how good the fictional story.

I guess one way to find out whether the Great Gatsby is as good as Casablanca is to see how often I find myself watching it during my GG phase. 

Young and Beautiful, The Great Gatsby, Lana Del Rey

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.

Highlights From Halcon's Barclay's CEO Energy Presentation

From SeekingAlpha.

Three core areas.

Significant spot up in the Bakken/Three Forks, accounts for about half of HK's daily production.

Utica/Point Pleasant: waiting on infrastructure. No production to speak of yet.

Eagle Ford: newest play.

Williston Basin:

• quite a bit of acreage
• involved in several increased density test operated by others, a couple by HK
• moving from 600K EURs to 750K EURs (high end)

Cost:

• have not been able to bring costs down
• completions actually cost more
• just starting to do pad drilling
• echoes: CLR -- pad drilling can save $400K/well; $1 - $2 million/pad

Density:

• Fort Berthold: 660 foot spacing (getting closer to the 500-foot spacing I opined about a long, long time ago)

Slick water completions:

• "The slick water fracks we're doing up in Williams County about double production reserves and IPs on those wells, so that's going to be quite a change."

Future:

• "Over the next five or 10 years, you're going to see a lot more in these shale plays. There's just a lot of smart people working them."

Frac Tech -- "Green" Fracking

[I tried posting this last night but could not get a good wi-fi connection.]

Sent in by "anon 1," Frac Tech.

Locations in Texas, Oklahoma, Colorado, Pennsylvania, and ..... Minot, North Dakota:

Minot, ND
3305 45th Avenue Northwest
Minot, ND 58703-2814
(701) 837-1266 

From their site:

Slickwater Green Customizable Powdered Blend uses the latest green chemistry

Slickwater Green is one of the most environmentally responsible stimulation solutions ever created. In addition to being engineered according to the principles of green chemistry, this revolutionary powdered blend is premixed based on job site specifications and delivered in dry form - simplifying logistics and eliminated the risk of freezing. Slickwater Green's powdered form also may eliminate the need for chemical totes and help reduce the operational footprint. Best of all, application of Slickwater Green produces environmentally responsible results that simplify slickwater stimulation treatments.

Again, the Bakken as a technology laboratory.