Wednesday, October 16, 2019

Equinor's Heen Off Line -- Fracking In The Area -- October 16, 2019

The well:
  • 22623, 2,766, Equinor/BEXP, Heen 26-35 3TFH, Todd, t9/12; cum 232K 8/19; off line as of 8/19;
I'm too tired to go into this but this well and surrounding wells are off due to fracking in the area.

Random Update Of An Oasis Crane Federal Well In Willow Creek -- October 16, 2019

The well (full production profile at this post):
  • 21903, 873, Oasis, Crane Federal 5300 41-26H, Willow Creek, t5/12; cum 389K 8/19;
Production period of interest:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Random Update -- BR's Ivan TFH Well In Elidah Oil Field -- October 16, 2019

The well (full production profile at this post):

  • 21542, 2,978, BR, Ivan 11-29TFH, Elidah, t7/12; cum 280K 8/19;
Production period of interest:

On Top Of Everything Else, US Federal Gulf Of Mexico Crude Oil Production Continues To Set New Reocrds -- And Will Continue To Do So -- October 16, 2019

Link here.

Lots of stuff to talk about.

That huge crude oil  build today? Some say it's simply a mismatch in timing of production reports and export reports. If that's true, this "build" will take care of itself. Like all such reports, it's a snapshot in time; the trend is the metric to watch. Even so, this report has to be concerning for Saudi Arabia.

Meanwhile, take a look at EIA's "Today in Energy, " October 16, 2019. Everyone will interpret the report through their own filters.

My filters:
  • peak oil
  • rig counts don't matter
Two screen shots to get started


Takeaways for calendar year 2018 in the Gulf of Mexico:
  • US crude oil production at almost 2 million bopd, set a new annual record
  • EIA expects new annual production records in 2019 and 2020
  • even accounting for shut-ins related to Hurricane Barry in July, 2019
  • accounting for forecasted adjustments for hurricane-related shut-ins for remainder of 2019 and for all of 2020
Peak oil?

Remember all that hand-wringing five years ago that "we" weren't spending enough CAPEX on offshore oil E& P? And we move on.

Second screenshot:

Lots of verbiage: I will let readers read that for themselves.

First question: why was production data not "overlaid" in the graphic above? It would have been quite dramatic, placed on the same graphic as the rig count.

First observation: the EIA cleverly failed to mention that the sudden fall in the price of Brent in 2014 was due to the Saudi's flooding the market with oil trying to crush US oil sector (mostly shale). I've pointed that out on the graphic. Once OPEC cut back on production, the price of Brent returned to a "more normal" level.

  • all-time production record in the Gulf of Mexico, 2018
  • forecast for new all-time records in 2019 and 2020
  • rig count peaked at 200 in 2014 and then took a steep dive, declining quickly to 100 rigs in 2016 and then continuing a downward trend, trending toward 75 and no indication of an inflection point
Even in the Gulf, do rig counts matter? And, again, don't take that out of context.  

Switching gears: decision times and drilling. In the EIA report above, it is noted that "a fair amount of time is needed to discover and develop large offshore projects ..."
  • onshore shale: time that it takes Harold Hamm to make a decision to drill / not drill probably takes about an hour if his folks ask for his input
  • off-shore Gulf of Mexico: time for BP to decide to drill / not drill -- probably takes six months, maybe a year
  • can you imagine how long it would take for the decision to be made if the oil sector were nationalized and turned over to a government agency needing approval of US House, Senate and president?
Okay, enough of this.

Bakken Sets New Records -- EIA Dashboard For October, 2019

The new EIA dashboards have posted: Monthly additions from one average rig: 1,500 bopd.

Rigs matter: 60 rigs * 1,500 =  90,000 bopd.

Quick: what is the corresponding number for the Permian? A paltry 794 bopd.

I Love My Cable Company

I had a minor wi-fi problem today. I called Spectrum and they responded.

MRO WIth Three New Permits In The Prolific Bailey Oil Field -- October 16, 2019

Making money on $50 oil: as previously announced, COP has increased its quarterly dividend by a whopping 38% --

No shame!

API weekly crude oil inventories:
  • forecast consensus: a build of 2.878 million bbls (I love the false precision; down to the nearest thousand barrels)
  • actual: a huge build of 10.45 million bbls
  • EIA: will post tomorrow; EIA reported a 9.9-million-bbl build back on May 1, 2019
  • a build of 9 million bbls is about one day of US shale production
US shale production nears 9 million bopd; the Bakken nears 1.5 million bopd -- EIA, link here:

The new EIA dashboards have also posted:

Wind energy giving back to the community? I've yet to see this from a wind farm, but here's yet another fossil fuel investment in the local community, from ONEOK:

Back to the Bakken

Active rigs:

Active Rigs6069583167

Three new wells, #37093 - #37095, inclusive:
  • Operator: MRO
  • Field: Bailey (Dunn County)
  • Comments:
    • MRO has permits for a 3-well Ruggles/Pomeroy/Wiest pad in section 33-145-93, Bailey oil field
That was all.

EOG Reports A Previously-Identified Monster Well WIth Huge Jump In Production -- October 16, 2019

The well:
  • 20513, 2,365, EOG, Riverview 3-3130H, Clarks Creek, more information here, t3/13; cum 744K 8/19; off line as of 3/19; back on line for two days, 7/19; huge jump in production, 8/19;
Recent production:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Boiler plate sundry form for these EOG wells throughout the Parshall oil field. This is from a sundry form dated May 10, 2019, but I've seen the same boiler plate language for at least the past three years, it seems:
EOG is currently executing a downspacing and infill drilling program. During this process, the new infill wells are being hydraulically fractured offset existing / producing wells. The existing wells in closest proximity to the new infill wells are shut-in during the drilling and completion process. Pressure pulses have been noted in the existing shut-in wells during this process.

Due to the pressure pulses, sand from the completions in the original wells can become dislodged and enter the wellbore. When this occurs wellbore intervention is required to replace the damaged pumping equipment and may also require the wellbore to be cleaned out; both operations are costly and slow the process of returning offset wells to production.

In addition, the low energy system often requires artifical life (rod pump or ESP) which can be difficult to operate with sand production.

As a mitigation measure, EOG is requesting approval to fill the existing wellbore with water and to have the option to use a temporary diverter. The water would increase the bottom hole pressure in the existing well, counteracting the pressure pulses and sand influxes impacting the well from the drilling and completion process of hte infill wells.

Surface-hole pressure will be maintained below EOG's designated pre-fill pressure paramets noted in Figure 1 based on the set tubing depth of the referenced well. The referenced well is connected ao Supervisory control and Data Acquision (SCADA) system which is monitored 24/7. The automated pump kill pressure is set at 90% of total surface pressure. Water will be transported by truck or pipeline for the process.

Another "Second Time 'Round" Well In The Bakken -- And Not Surprising -- A CLR Well -- October 16, 2019

I featured this well back on April 27, 2017, as a "well of interest" to show newbies how all that talk about the dreaded Bakken decline rate is just that  -- a bunch of talk. Back in 2017, this well was featured to show how a Bakken well's decline can be reversed.

Well, what do you know. A year later this well had a huge jump in production that I completely missed.

I used to tag these wells with other phrases. I am now lumping all these examples into "advantaged oil." 

The well:
  • 21488, 1,357, CLR, Antelope 3-23H, Elm Tree, Three Forks, 29 stages, 2.8 million lbs, t8/12; cum 532K 2/17;
Period of production of interest:

The Predictability Of The Bakken -- October 16, 2019

This "monster" well has just come back on line:
  • 22487, 67 (no typo), EOG, Hawkeye 02-2501H, Clarks Creek, t12/13; cum 850K 8/19; went offline 6/19; 3-section spacing; 1,741 acres in the spacing unit; sister well to the well announced earlier with 200,000 bbls in less than 5 months; another 15,000-ft horizontal; trip gas over 4,000 units; remains off line 7/19; back on line 8/19;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

It's sister well, #22486, remains off line.

There are three other wells on this pad, and many, many more wells in the surrounding area.

The three other wells on this pad are all on conf status:
  • 32488,
  • 32489,
  • 32490,
The completed wells in this are are "extended long reach wells -- the horizontals are "3-mile long" horizontals vs the standard "2-mile long" horizontals.

It's almost impossible to find the neighboring well that was recently fracked because of so much activity in the area, but this would be a good candidate:
  • 31808, 1,981, EOG, Riverview 22-3031H, Clarks Creek, t8/19; cum 30K in 16 days; extrapolates to 57K over 30 days:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

By the way, that #22486?
  • 22486, 2,421, EOG, Hawkeye 100-2501H, Clarks Creek (see stand-alone post); 3-section spacing (1,920 acres); will this be a long lateral (9,000 feet) or a much-talked-about-seldom-seen-super-long lateral (14,000 feet)? I'm betting the latter. If accurate, a huge "thank you" to a reader. This well is NORTHEAST of Watford City. [Turned out to be 25,101 feet long. Yes, a super-long lateral, almost 3 sections long.] Did Lynn Helms misspeak or was he misquoted in The Bismarck Tribune when he said there was a gusher NORTHWEST of Watford City? If there is still another gusher NORTHWEST of Watford City that is better than this well, we are talking some big wells in the Bakken, Three Forks; 47 stages; 14 million lbs of sand, 1920-acre spacing unit; t9/12; cum 781K 4/19; remains off line 8/19;

The Predictability Of The Bakken -- October 16, 2019

Again, another example of "how predictable" the Bakken. Over on the "monster well" page, this monster Whiting well was taken off line a few months ago. My hunch: a neighboring well is being fracked. And that was exactly the case.

The following wells all went off line back in April, 2019, and remain off line. Meanwhile, a newer well is reported to be a DUC by the NDIC. FracFocus, however, shows that the well has been fracked. The neighboring wells that are offline while the newer well is being fracked:
  • 17912,
  • 18109,
  • 25331, 
  • 25164 (see below),
The monster well taken off line:
  • 25164, IA/768, Whiting, Hauge 41-3H, t5/13; cum 378K 4/19; went off line 4/19; remains off line 8/19;
  • fracked: 9/9/19 - 9/14/19
  • completion: 8.8 million gallons of water; moderate size frack; 89.66% water by mass; 9.9% sand by mass

Mineral Rights In The Bakken -- October 16, 2019

This is how "amazing" the Bakken is for some "small" mom-and-pop mineral owners in the Bakken, who no doubt inherited minerals from their homesteading parents, some of whom bought land from neighboring farms over the years.

I have a reader who tells me, even ten years into the Bakken, upwards of seven siblings are each receiving royalty checks trending toward $50,000 / month.

Let's work this backwards. Assuming the family "kept" all their minerals over the years.

A twenty percent royalty on $1.75 million = $350,000.

At $35/bbl, $1.75 million = 50,000 bbls/month.

At 2,000 bbls/month/well, that would be 25 wells.

Notes From All Over, Part 2 -- October 6, 2019

Disclaimer: this is not an investment site.  Do not make any investment, financial, career, travel, job, or relationship decisions based on what you read here or think you may have read here.

Inflation watch: long-term inflation expectations -- repeat, expectations -- hit a record low: NY Fed -- The WSJ. Three-year ahead inflation expectations -- repeat, expectations -- fell to 2.4% in September.
The Federal Reserve Bank of New York said Tuesday that longer-run inflation expectations hit the lowest level the bank has ever tracked in its latest monthly Survey of Consumer Expectations.
The central bank said that in September, the public’s expectation of inflation three years from now fell to 2.4% from 2.5% the prior month. That is the lowest reading since the start of the survey in 2013. Shorter-run inflation expectations fared a touch better, however, with the public’s expectation of inflation a year from now moving up to 2.5%, from 2.4% in August.

How did the Fed arrive at this number? Are you sitting down?
The drop in expected inflation three years from now “was driven by the respondents with household incomes less than $50,000 and those with a high-school diploma or less,” the New York Fed said.
Are you kidding? This was a headline story for The WSJ? This is how the NY Fed forecasts long-term interest rates? Okay -- I understand -- they are reporting expectations -- but still, this is a headline story.

Well, for the record, a lot of college-educated folks with incomes greater than $150,000 may have different expectations. 

Garrett watch: it's now being reported that the Dallas coach is on the "hot seat" after three consecutive losses -- including the most recent loss against the weakest team in the league.

Down At The Farm

Sophia learned the difference between tires and wheels. 

Notes From All Over, Part 1 -- October 16, 2019

Disclaimer: this is not an investment site.  Do not make any investment, financial, job, career, travel, or relationship decisions based on what you read here or think you may have read here.

BofA: profit beats expectations; revenue surprisingly rises; stock jumps; also, at Barron's;

JPM: profits rise 8% to top estimates; the nation's largest bank reported a profit of $9.08 billion, or $2.68 a share; forecast: earnings of $2.45 a share. A year earlier, the bank reported a profit of $8.38 billion, or $2.34 per share.

Tesla: show a sudden drop in August and September sales. Credits ending. Link to Fortune
... registrations were up 93.3% year over year in July 2019 in the 22 states the company tracks. However, registrations in August 2019 were down about 38% from the same period in 2018 and by 18.7% in September.

In total, the third quarter of 2019 still had more registrations between the Model 3, S, and X than in 2018, but that was because of the big jump in Model 3s in July: 5,008 in 2018 and 11,823 in 2019. 
Shocked: solar panels don't provide power to one's house during a utility blackout. Home solar panels are tied into the grid; they do not provide electricity to one's own home.
America's most "environmentally conscious" state got a harsh lesson in electrical engineering when many of the tens of thousands of people hit by this week's blackout learned the hard way that solar installations don't keep the lights on during a power outage.
That is "because most panels are designed to supply power to the grid, not directly to houses. During the heat of the day, solar systems generate more juice than a home can handle. However, they don’t produce power at all at night. So systems are tied into the grid, and the vast majority aren’t working this week as PG&E cut power to much of Northern California to prevent wildfires."

Four Wells Comiing Off The Confidential List Today -- October 16, 2019

Four wells coming off the confidential list today -- Wednesday, October 16, 2019: 49 for the month; 49 for the quarter:
  • 35947, SI/NC, XTO, Bronson 31X-14A, Temple, no production data,
  • 34971, 1,533, CLR, Rader 7-24H1, Avoca, t7/19; cum 48K over 46 days;
  • 33782, SI/NC, Crescent Point Energy, CPEUSC Lloyd 7-27-34-157N-100W TFH, Marmon, no production data;
  • 33593, 250, BR, Anderson Ranch 1D TFH, Camel Butte, t7/19; cum 8K over 51 days;
Active rigs:

Active Rigs6069583167

RBN Energy: are northeast natural gas takeaway constraints back?
The Northeast natural gas market was supposed to have turned a new leaf. After years of pipeline takeaway constraints and constraint-driven prices, the region as of late 2018 had ample, even excess, takeaway capacity on its hands. Regional prices strengthened on both an absolute basis and relative to downstream markets, and Marcellus/Utica producers had room to grow. But bearish fundamentals have rattled the Northeast — and U.S. — market in recent months. In-region demand has lagged, even as production has set new highs. Since August, capacity reductions on Texas Eastern Transmission, a key Northeast takeaway route, have limited outflows. And, to top it off, Dominion’s Cove Point LNG went offline last month for an annual three-week-long maintenance, taking another 700 MMcf/d of demand out of the market for a time — it has since come back online, as of this past Monday. But regional prices in late September and early October were pummeled in the process, raising the question: are the Northeast’s takeaway constraints back? Today, we analyze the impacts of shoulder-season dynamics on regional storage and takeaway capacity utilization.
As weak as gas prices have been lately at the national benchmark Henry Hub, Northeast prices have been even weaker. Prices at the Dominion South hub, the benchmark for Appalachian supply, were trading 20 to 40 cents per MMBtu below Henry for most of the first seven months of 2019. But in August, that discount — or basis — plunged to minus 80 cents, and averaged about $1 in the first couple weeks of October. That’s stronger than where basis stood during the worst of the pipeline constraints in prior years, but still weaker than last year at this time, even as the Henry cash price is trading at multi-year lows.