Wednesday, October 3, 2018

MRO To Exit UK North Sea -- Will Focus On US Shale -- October 3, 2018

From this morning: Reminder for later: Brent, Equinor, Mariner, Brassey
Now this: Marathon (MRO) will exit the UK North Sea.
Marathon Oil is selling its minority stakes in the Foinaven fields in the west of Shetland area operated by BP and interests in the Brae complex northeast of Aberdeen in a sales process run by Jefferies. Bids are expected by December this year.
According to banking sources, Marathon Oil’s assets in the UK North Sea could fetch up to US$200 million. 
Marathon Oil’s assets in the North Sea produce a total of 15,000 barrels of oil equivalent per day, and the resource base is of 31 million barrels.
The company has allocated more than 90 percent of its 2018 development capital to the U.S. resource plays in which it has positions—the Permian, the Eagle Ford, the STACK/SCOOP, and the Bakken.

Trudeau Can't Win -- Now The Canadian Environmentalists Want To Derail The One Project That Had A Chance -- October 3, 2018

From SeekingAlpha:
  • amid the enthusiasm over the final investment decision for the LNG Canada project by the Shell-led consortium, the project's potential carbon emissions have environmental advocates questioning the feasibility of British Columbia's carbon reduction goals
  • "How are we going to meet our legislated greenhouse gas targets when this substantial increase in emissions is happening?" asks Ian Bruce, a director with the David Suzuki Foundation
  • the B.C. government maintains the province will meet its climate change targets even with LNG Canada going ahead, saying the project's estimated carbon output will total 3.45M metric tons/year
  • but a Ministry of Environment spokesperson clarifies the forecast accounts only for Phase 1 of the project, with two production trains; Phase 2 would include two additional trains, which Bruce and others say could increase greenhouse gas emissions by 8M-9M tons annually
  • "This project is a carbon bomb," says Marc Lee, an economist with the Canadian Centre for Policy Alternatives.
Interestingly, if one wants to be consistent in one's reasoning, these folks have a case.

By the way, this is the problem that California now has. The state passed a law that say the state must obtain all electricity from renewable sources by 2045. Everyone knows that won't happen, but it effectively stops any new non-renewable energy projects from here on out. Unless a new non-renewable energy project is offset by a renewable project but that won't happen. Renewable energy projects can't possibly outperform a new non-renewable power project. 

Natural Gas Won't Be An Issue This Winter -- Natural Gas Supply Assocation -- October 3, 2018

Updates

October 15, 2018: oh-oh. Maybe the Natural Gas Supply Association spoke too soon. From SeekingAlpha -- 
Bullish weather forecasts again led to a sharp rally in core winter natural gas contracts to start the week, boosting November natural gas prices by more than $0.08 to $3.242/MMBtu, and spot gas jumped $0.17 to $3.135/MMBtu as early-season cold drove up demand across much of the U.S.
With unseasonably low temperatures expected to persist through the end of October, NatGasWeather expects the coming weather pattern to further raise storage inventory deficits vs. the five-year average to more than 650 Bcf and likely toward 700 Bcf.
The background state will remain bullish for quite some time until record production finally shows signs of improving deficits, “something that’s not expected to happen until after October due to the coming colder-than-normal pattern," the forecaster says.
In the SeekingAlpha note above, the writer suggests the deficit could trend toward 700 Bcf. In the graphic from last week, "stocks were 627 Bcf less than last year at this time and 607 Bcf below the five-year average.

My 30-second elevator speech:
  • natural gas will be the talk of the town in New England as prices rise from $3-nat gas to $6-nat gas
  • natural gas will be the talk of the town but there will be no crises, no emergencies; the drillers and natural gas suppliers will be able to respond -- after all, this is Trump's America 
  • Elizabeth Warren will have all the answers
History of natural gas prices, link here:



Original Post
October 3, 2018 

If this turns out to be accurate, there is no reason for someone like me to track the natural gas fill rate any more. If we get through a "cold" winter with no problems this winter, I will no longer follow the natural gas fill rate.

From twitter:


From Platts:
The Natural Gas Supply Association anticipates lower storage levels will be countered by soaring production this winter, resulting in neutral pressure on wholesale natural gas prices, despite record domestic consumption this winter.
The outlook anticipates a record demand of 102.7 Bcf/d, mostly tied to an increase in electric sector and industrial use of gas, as well as exports, combining to add 3.4 Bcf/d, on average, to consumption.
On the supply side, lower storage inventories at the start of the winter -- 3.3 Tcf versus about 3.8 Tcf last winter -- were seen as exerting upward pressure on prices this winter compared with last. In contrast, offering downward pressure, production this winter was forecast to average 84.9 Bcf/d, up from 77.4 Bcf/d last winter.
Much more at the link.

EVs: Happy Together! -- October 3, 2018:

Updates

Later, 4:50 p.m. CDT: after the market closed, WTI continued to melt up. At 4:50 p.m. CDT, WTI was trading at $76.41.

Original Post

WTI: again, completely missed. I didn't see this until just now. Look at that. Oil closed up over 1%, up almost another dollar, and closed at $76.18. And this was on a day that the EIA reported a whopping increase in the US crude oil inventories. Inventories increased by a whopping 8 million bbls, and in so doing:
  • crossed over the 400 million-bbl threshold (at 404 million bbls)
  • went from "below" the 5-year average (last week) to "now within the 5-year average" (this week)
  • when imports increased again, year-over-year
EVs:
Happy Together, The Turtles

Making America great again: Dow hit an all-time record today.

***********************************************
Back to The Bakken

Active rigs:

$76.18💪💪10/3/201810/03/201710/03/201610/03/201510/03/2014
Active Rigs65573368188

Two new permits;
  • Operator: RimRock Oil & Gas
  • Field: Heart Butte (Dunn)
  • Comments: RimRock has permits for a Two Shields Butte pad in SWSW 21-149-92
Three wells came off the confidential list:
  • 32127, 768, CLR, Burr Federal 6-26H2, Sanish, t7/18; cum 30K after 42 days;
  • 33114, 1,495, CLR, Bailey 11-24H2, Pershing, t6/18; cum 58K 2.5 months;
  • 33533, SI/NC, Hess, AN-Gudbranson-153-94-2215H-8, Elm Tree,
Eight permits renewed:
  • Petro-Hunt (5): two Arsenal Federal and three Mongoose permits, all in McKenzie County
  • EOG: a Hardscrabble permit in Williams County
  • Crescent Point: a CPEUSC Keith permit in Williams County
  • Sinclair: one Bighorn permit in Dunn County
Three producing wells (DUCs) reported as completed:
  • 24235, 2,373, Enerplus, Cheetah 149-93-30A-31H, Mandaree, t8/18; cum 9K after 7 days;
  • 34011, 1,450, XTO, Serrahn 11X-5F, Siverston, t7/18; cum 31K after 1.5 months;
  • 34012, 1,610, XTO, Serrahn 11X-5B, Sivrston, t8/18; cum 28K after 1 month;

I'm Dreaming Of A White Halloween -- October 3, 2018


The Cost Of A Re-Frack In The Bakken -- October 3, 2018; Curious If Readers Disagree With Me

A reader asked if I knew the cost of a re-frack. I would be very interested in an expert chiming in -- the cost of a re-frack in the Bakken.

This was my "not-ready-for-prime-time" reply.
1. During the height of the boom, the cost of drilling and fracking was almost exactly 50-50. So, a $10 million well: fracking cost $5 million. The $10 million did not include the infrastructure as far as I know.

2. Since then, total costs have come way down to complete a well, let's say, $8 million (Whiting and CLR in their presentations say much less, but they probably exaggerate). Drilling costs have come way down but fracking -- due to cost of sand (higher cost and using more of it) -- has increased in cost relative to drilling.

3. So, I'm assuming, a re-frack costs $4 million +/- a million.

4. But, what folks really forget is all the time and cost in getting the infrastructure; the roads (some roads are 20 - 30 miles from the highway, and completely built by the operator), the pad, the electric transmission lines running out to the pad, etc., etc., etc -- none of those costs. No upfront new bonus money to royalty owners; the 1280-acre unit is held by production. So, although $4 million seems on the high side for a re-frack, I think it's very cheap for a brand new well -- sometimes that brand new well is many times better than the original well. In addition, the operator already knows what is there; it's not a wildcat. In the old days, there were such things as "DRY" holes -- something millennials have probably never heard of.

5.  But to answer the question, the cost of a re-frack is $4 million, +/- a million dollars. That's my story and I'm sticking to it until I hear differently.

Random Update Of A CLR Ryden Well In Jim Creek Oil Field -- October 3, 2018

The CLR Ryden wells are tracked here.

This is a great example of how operators "extend" the lives of their Bakken wells. See production profile at this link.

The well:
  • 16646, 257, CLR, Ryden 21-24H, Jim Creek, t7/07; cum 246K 8/18
As you scroll through the production profile of this well (at the link), note these things:
  • this well was never all that great during its first year of life
  • this was was never re-fracked; it was drilled, stimulated, and the operator moved on
  • the well may have had any number of work-over rigs over the years; that I do not know
  • after the initial stimulation, the well produced a maximum of 7,176 bbls (1st month) and 6,736 bbls (4th month); after that it declined and plateaued at about 2,000 bbls/month; becoming a "steady Eddy"; nothing remarkable
  • first production 8/07
  • peaked 11/07 (4 months later)
  • plateaued by 4/08 to about 2,000 bbls/month
  • second plateau by 5/10 to about 1,500 bbls/month
  • continued to decline slowly and then, all of a sudden, 3/15, jumped to 2,600 bbls/month (from 1,000 bbls/month previously) -- probably a work-over rig or neighboring well activity
  • off-line for a couple of months, no doubt due to neighboring well activity
  • 11/15: jump to 5,600 bbls/month
  • some volatility between then and now but still at 3,400 bbls/month -- much better and lasting much longer than the production after it was initially drilled back in 2007
  • this well will most likely be re-fracked two or three more times in it's 35+ year life

Bakken Well Life-Cycle -- MRO's Voigt Well In Bailey Oil Field -- October 3, 2018

Updates

Later, 3:12 p.m. CDT: dollars and (common) sense --
Using $50/bbl as the price of oil at the wellhead, look at the ten months following the re-frack, and the ten months prior to the re-frack:

Monthly
11,081
661
Monthly
12,157
691
Monthly
13,282
623
Monthly
12,953
697
Monthly
16,648
729
Monthly
20,807
632
Monthly
26,722
701
Monthly
14,371
698
Monthly
17,493
687
Monthly
28,683
689
Total: 10 months
174,197
6,808
at $50/bbl
$8,709,850
$340,400

At ten months following the re-frack, which might have cost $4 million, this well has produced almost $9 million in crude oil at $50/bbl. In the ten months prior to the re-frack, this well generated less than $350,000 in crude oil at $50/bbl at the wellhead. Regardless how the operator did, the mineral owners did very, very well.
Later, 2:27 p.m. CDT: cost of a re-frack


Original Post

Huge amounts of time and money were required to drill this greenfield well. The first time. Think about this. Second time around, to re-frack. Like getting a brand new well. But no time getting the lease, pooling, pad built, roads built, other infrastructure, etc; and, all the money saved -- essentially just the cost of a re-frack. And there are thousands of these wells in the Bakken suitable for a first re-frack. And then we have the second re-frack. And a third. Rinse and repeat.

The well:
  • 16964, 315, MRO, Voigt 11-15H, Bailey, t5/18; cum 354K 8/18; re-fracked once;
Recent production:

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN8-20183111081110339680983189390
BAKKEN7-201831121571211910689104598965532
BAKKEN6-20183013283132611186199348482431
BAKKEN5-201831129531303910748902667531266
BAKKEN4-2018301664816633153901213060744097
BAKKEN3-2018312080720900218661273359154409
BAKKEN2-2018282259022465251761367672803814
BAKKEN1-20183126722267043313617924135201364
BAKKEN12-201727143711436918379833922724386
BAKKEN11-20173017493173452132795615057006
BAKKEN10-201722286832872755416075012881
BAKKEN9-20170000000
BAKKEN8-20170000000
BAKKEN7-20170000000
BAKKEN6-20170000000
BAKKEN5-2017589641058040
BAKKEN4-2017306616631485410292

Re-frack: 8/22/17 -- 9/14/18; 4.9 million gallons of water; a small to moderate frack; 87.2% water by mass.

Original frack/geologist's note:
the lateral generated an exposure of 9,006 feet of 6" hole through the gross middle Bakken. The lateral well bore remained approximately 84% in the target zone and 100% in the gross middle Bakken. Background gas as high as 5,000 units. The middle Bakken must have been about 30 feet thick: the well path landed about 15 feet into the middle Bakken in the middle of the target zone. On May 12, 2008, the well was tested after stimulation with 546,700 pounds of 40/70 sand.
Initial production:
BAKKEN2-200928397739811094165516550
BAKKEN1-200913172814489606596590
BAKKEN12-200817203520984675965960
BAKKEN11-20083028633008537111311130
BAKKEN10-200831255025503789759750
BAKKEN9-20083025112590407116011600
BAKKEN8-20083134263223615158715870
BAKKEN7-20083140134080708165716570
BAKKEN6-20083057145895975179717970
BAKKEN5-200824699065991117000
BAKKEN4-200812903696303000

Amazing, huh?

On December 28, 2015, the well qualified for "stripper well status."

Driving Me Nuts -- Problem Solved -- October 3, 2018

Updates

December 1, 2018, from an earlier post: October 3, 2018: #16990. See this post. The well:

  • 16990, 3,744, EOG, Austin 5-14H, Parshall, a single section/short lateral well, TD = 14,693 feet; t5/08; cum 694K 10/18, recent production:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN10-20183143374300752158213282
BAKKEN9-201888147795092892300
BAKKEN8-20180000000
BAKKEN7-20184000100
BAKKEN6-20181783289234914551165158
BAKKEN5-201831180418772512915260959
BAKKEN4-20183017701720182275325120
BAKKEN3-2018311945191619230392679109


Later, 6:37 p.m. CDT: a reader reminded me there were many reasons that a well can come off-line -- not simply due to one reason like neighboring activity. The reader wrote:
Our mineral trust has an interest in the ****** wells in the Grinnell field that were shut down during June and brought back up in August, i.e., about 40 days. Calls to folks in the oil business brought several ideas, the most logical being that producers will often shut down a well when there is a well in a neighboring pool being fracked. Said to help prevent issues with the lines. When the ****** wells came back on line in August, I located the well files for them on the NDIC site and found that the reason for the shutdown was a need to repair tubes and relocate some of the pumps. Anyway, thought this would add to the inventory of reasons why a well might be shutdown. 
Much appreciated; I was pretty naive thinking the only reason a well was shut in was due to neighboring activity. Along that line, it is amazing how incredible this technology is that, for the most part, these wells just keep on pumping, day in and day out, seemingly, for months and years.


Original Post

This well has been driving me nuts. This is a great well. Why was it taken off-line. Nothing is going on in the immediate area? So why was this well taken off line?

The well:
  •  16990, 3,744, EOG, Austin 5-14H, Parshall, t5/08; cum 689K 8/18 -- a short lateral;
Recent production:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN8-20180000000
BAKKEN7-20184000100
BAKKEN6-20181783289234914551165158
BAKKEN5-201831180418772512915260959
BAKKEN4-20183017701720182275325120
BAKKEN3-2018311945191619230392679109


The graphic -- nothing going on in this area. Why was this well taken off line?



Well, I made a mistake. I didn't look far enough out.

Expanding the graphic:


These three wells have been drilled to depth but are still on the conf list but there indications they have been completed/fracked; if not it looks like they might be close to being fracked; FracFocus does not have any frack data when I checked today (October 3, 2018). Generally, when I see production profiles like those below, the wells have been fracked, so we'll see, but at least for me, I understand why a great well was taken off line even though no activity in immediate area:

32720, conf, EOG, Austin 45-1113H, 33-061-03957, Parshall, t--; cum --

DateOil RunsMCF Sold
8-201868451463

32719, conf, EOG, Austin 46-113H, 33-061-03956, Parshall, t--; cum --

DateOil RunsMCF Sold
8-201857821779

32718, conf, EOG, Austin 465-1113H, 33-061-03955, Parshall, t--; cum -- for newbies -- note the chronological number, 465 --

DateOil RunsMCF Sold
8-201870931402

Records, Records, Records -- October 3, 2018

Re-posting:

Record: speaking of economic indicators -- ISM service index soars. Link here, but the story is everywhere. The CNBC senior analyst apparently has not gotten the memo. From the link:
The Institute for Supply Management’s survey of non-manufacturing firms climbed to a postrecession high of 61.6 in September from 58.5. It’s also one of the highest levels ever in an index whose roots stretch back to the late 1990s. 
Interestingly, MarketWatch was actually pretty muted on this. But look at the WSJ:

Ramped up purchases in the services sector and spending by local governments at the end of their fiscal year pushed services-sector activity to the highest level on record.
The Institute for Supply Management on Wednesday said its nonmanufacturing index rose to 61.6 in September, the highest reading on record going back to 2008. A reading above 50 indicates activity is expanding across service and other industries, while a number below 50 signals contraction.
The reason I am re-posting this is because of this graph. Before going further, look at this earlier post

Look at this graphic:


Records, Records, Records -- October 3, 2018

Say what? The senior CNBC financial analyst continues to mis-read the market. Sees a bogeyman behind every economic indicator.

Record: speaking of economic indicators -- ISM service index soars. Link here, but the story is everywhere. The CNBC senior analyst apparently has not gotten the memo. From the link:
The Institute for Supply Management’s survey of non-manufacturing firms climbed to a postrecession high of 61.6 in September from 58.5. It’s also one of the highest levels ever in an index whose roots stretch back to the late 1990s. 
Interestingly, MarketWatch was actually pretty muted on this. But look at the WSJ:
Ramped up purchases in the services sector and spending by local governments at the end of their fiscal year pushed services-sector activity to the highest level on record.
The Institute for Supply Management on Wednesday said its nonmanufacturing index rose to 61.6 in September, the highest reading on record going back to 2008. A reading above 50 indicates activity is expanding across service and other industries, while a number below 50 signals contraction.
Trumponomics: finally, they're talking about the "Trump effect" yet to come. The Trump tax cut? The biggest effect will hit the US in 4Q18. Repeat: the Trump tax cut will have its biggest effect on the US in 4Q18.

Road to Canada -- re-posting:
Another record? From Rigzone -- Canadian oil pain grows as crude discount to WTI hits $40. Wow.
Canadian heavy crude’s discount to West Texas Intermediate futures increased to the widest in almost five years, raising the specter of local oil producers curtailing operations.
Western Canadian Select’s discount for November fell $1.25 to $40.75 a barrel Tuesday, the biggest since November 2013. The plunge came as new supply from Suncor Energy Inc.’s Fort Hills mine helps to fill pipelines to capacity.
“If you get this sustained wide differential, you are going to see these guys start to ramp down production,” Mike Walls, a Genscape Inc.
When discounts widened to $30 a barrel early this year on the back of a pipeline outage, companies including Cenovus Energy Inc. and Canadian Natural Resources Ltd. said they were cutting some production or starting maintenance earlier than planned. Yet, with oil sands maintenance soon to wind down and further maintenance not planned until next spring, there is “no relief valve for the next two to four months,” according to Walls.
Other grades of Canadian crude are also suffering.
While increasing volumes of oil are being shifted onto rail cars, the pickup in crude-by-rail has been slow.
Exports rose one percent in July from June to 207,000 barrels a day. Cenovus said last month it signed oil-by-rail agreements to ship about 100,000 barrels a day on tracks but the agreements won’t go into full effect until the second quarter next year.

Put Your Headline Here -- October 3, 2018

Weekly EIA petroleum report: link here.
  • wow! US crude oil inventories increased by most I have seen in the two years I have followed
  • US crude oil inventories up a whopping 8.0 million bbls
  • refiners are operating at 90.4% of their operable capacity
  • crude oil imports keep increasing; up 10.2% more than the same four-week period one year ago
  • WTI up almost 1%; OPEC up over 2% but let's see what WTI/OPEC basket does by the end of the day
  • at 404.0 million bbls, US crude oil inventories at five-year average; my threshold is 400 million bbls; the five-year average includes the Saud Surge, 2014 - 2016
  • gasoline? awash in gasoline -- inventories decreased by half a million bbls, but gasoline inventories still 7% above five-year average for this time of year
  • gasoline and distillate production right on target: 10.0 and 5.0 respectively
  • 30-second speech: refiners at 90% capacity (autumn maintenance; switch over to winter grades) simply means that inventory built up; once we get to 97% capacity, the inventories will start to drop
  • this happened back in March -- same thing -- spring maintenance; switch over to summer blends
  • by the way, Cushing inventories were getting so low, some thought some tanks would bottom out (previously posted)
Bottom line: not to worry:
  • NOG: up almost 3%
  • OAS: up half a percent
    JAG: up 1.6%
  • COP: flat to slightly negative
    CVX: up 0.4%
  • RDS-B: up 0.3%
  • ENB: up 1.23%
  • EPD: up 0.7%
*********************************** 
The Road To Canada

Another record? From Rigzone -- Canadian oil pain grows as crude discount to WTI hits $40. Wow.
Canadian heavy crude’s discount to West Texas Intermediate futures increased to the widest in almost five years, raising the specter of local oil producers curtailing operations.
Western Canadian Select’s discount for November fell $1.25 to $40.75 a barrel Tuesday, the biggest since November 2013. The plunge came as new supply from Suncor Energy Inc.’s Fort Hills mine helps to fill pipelines to capacity.
“If you get this sustained wide differential, you are going to see these guys start to ramp down production,” Mike Walls, a Genscape Inc.
When discounts widened to $30 a barrel early this year on the back of a pipeline outage, companies including Cenovus Energy Inc. and Canadian Natural Resources Ltd. said they were cutting some production or starting maintenance earlier than planned. Yet, with oil sands maintenance soon to wind down and further maintenance not planned until next spring, there is “no relief valve for the next two to four months,” according to Walls.
Other grades of Canadian crude are also suffering.
While increasing volumes of oil are being shifted onto rail cars, the pickup in crude-by-rail has been slow.
Exports rose one percent in July from June to 207,000 barrels a day. Cenovus said last month it signed oil-by-rail agreements to ship about 100,000 barrels a day on tracks but the agreements won’t go into full effect until the second quarter next year.
**************************************
Slump? What Slump?

What others are saying:


Turkey: imploding. Inflation rate -- 25% -- today's report. Erdogan has a plan. Raid companies who increase prices.

Bakken Well Update -- Random Notes -- October 3, 2018

Mystery solved. Link here. Actually not that much of a mystery, but it's nice to see how this worked out.

Update on some recently fracked wells. See this note. These wells, still SI/NC have been fracked, frack data for #32873 provided; probably similar to other fracks in area:
  • 32975, SI/NC, MRO, Jerome USA 12-23TFH, Reunion Bay, no production data,
  • 32974, SI/NC, MRO, Jorgenson USA 12-23H, Reunion Bay, no production data,
  • 32973, SI/NC, MRO, Joshua USA 12-23TFH-2B, 33-053-07752, fracked 6/5/18 - 6/23/18; 11.6 million gallons; water 89.3% by mass; Reunion Bay, no production data,
  • 19446, IA/24 (no typo), MRO, TAT USA 13-23H, Reunion Bay, 22 stages, 3.2 million lbs, t2/11; cum 90K 3/18; it went off-line 11/17; but has now come back on-line as of 8/18;
**************************
Bakken 2.5

Note recent production of this well drilled/completed back in 2010, about eight years ago. That dreaded Bakken decline rate ... from 2,000 bbls/month back up to 10,000 bbls/month. Wow.
  • 19064, 807, MRO, Weninger USA 44-34H, Reunion Bay, t9/10; cum 373K 8/18;
Monthly Production Data
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
BAKKEN8-20182710072998918310741806197
BAKKEN7-20183131310391850182
BAKKEN6-20180000000
BAKKEN5-20180000000
BAKKEN4-20180000000
BAKKEN3-20180000000
BAKKEN2-20180000000
BAKKEN1-20180000000
BAKKEN12-20170000000
BAKKEN11-20170000000
BAKKEN10-20170000000
BAKKEN9-20170000000
BAKKEN8-20170000000
BAKKEN7-20170000000
BAKKEN6-20170000000
BAKKEN5-20171076290713087068253
BAKKEN4-201730254725604572827235412

So, what gives? Look at this graphic, and then look at the IP of the Colvin well 9#32010:

Four producing wells (DUCs) reported as completed:
  • 32010, 7,448, MRO, Colvin USA 14-34TFH, Reunion Bay, fracked, 6/1/18 - 6/12/18; 6.9 million gallons water; 89% water, t7/18; cum --
  • 33911, 2,705, Hess, BB-Sigrid Loomer-150-95-0817H-8, Blue Buttes, fracked 5/10/18 - 5/14/18; 5.5 million gallons water; 84.6% water, t7/18; cum --
  • 33912, 2,251, Hess, BB-Sigrid Loomer-150-95-0817H-9, Blue Buttes, t7/18; cum --
  • 33913, 2,355, Hess, BB-Sigrid Loomer-LW-150-95-0817H-1, Blue Buttes, t7/18; cum --
The Colvin graphic: