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

From this morning: Reminder for later: Brent, Equinor, Mariner, Brassey

• Equinor acquires stake in Rosebank project offshore the UK
• Equinor Rosebank deal good for UK upstream -- Rigzone
• Brent - wiki
• Equinor - Mariner 
• Statoil -- Bressay
• oil sands - API -- wiki 

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:

August 3, 2018: natural gas reserves are "dangerously low."

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:

• GM and Honda team up: EVs.
• Will Ford and Tesla be next? Many think so.

Happy Together, The Turtles
Making America great again: Dow hit an all-time record today.

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

Back to The Bakken

Active rigs:

$76.18💪💪	10/3/2018	10/03/2017	10/03/2016	10/03/2015	10/03/2014
Active Rigs	65	57	33	68	188

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:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	8-2018	31	11081	11033	9680	9831	8939	0
BAKKEN	7-2018	31	12157	12119	10689	10459	8965	532
BAKKEN	6-2018	30	13283	13261	11861	9934	8482	431
BAKKEN	5-2018	31	12953	13039	10748	9026	6753	1266
BAKKEN	4-2018	30	16648	16633	15390	12130	6074	4097
BAKKEN	3-2018	31	20807	20900	21866	12733	5915	4409
BAKKEN	2-2018	28	22590	22465	25176	13676	7280	3814
BAKKEN	1-2018	31	26722	26704	33136	17924	13520	1364
BAKKEN	12-2017	27	14371	14369	18379	8339	2272	4386
BAKKEN	11-2017	30	17493	17345	21327	9561	505	7006
BAKKEN	10-2017	22	28683	28727	554	16075	0	12881
BAKKEN	9-2017	0	0	0	0	0	0	0
BAKKEN	8-2017	0	0	0	0	0	0	0
BAKKEN	7-2017	0	0	0	0	0	0	0
BAKKEN	6-2017	0	0	0	0	0	0	0
BAKKEN	5-2017	5	89	64	10	58	0	40
BAKKEN	4-2017	30	661	663	148	541	0	292

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:

BAKKEN	2-2009	28	3977	3981	1094	1655	1655	0
BAKKEN	1-2009	13	1728	1448	960	659	659	0
BAKKEN	12-2008	17	2035	2098	467	596	596	0
BAKKEN	11-2008	30	2863	3008	537	1113	1113	0
BAKKEN	10-2008	31	2550	2550	378	975	975	0
BAKKEN	9-2008	30	2511	2590	407	1160	1160	0
BAKKEN	8-2008	31	3426	3223	615	1587	1587	0
BAKKEN	7-2008	31	4013	4080	708	1657	1657	0
BAKKEN	6-2008	30	5714	5895	975	1797	1797	0
BAKKEN	5-2008	24	6990	6599	1117	0	0	0
BAKKEN	4-2008	12	903	696	303	0	0	0

Amazing, huh?

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

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

Updates

March 29, 2019: production updated --

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	1-2019	31	4348	4336	266	2600	2324	24
BAKKEN	12-2018	31	4476	4481	371	2615	2104	259
BAKKEN	11-2018	30	4833	4848	588	2211	1967	0
BAKKEN	10-2018	31	4337	4300	752	1582	1328	2
BAKKEN	9-2018	8	814	779	509	289	230	0
BAKKEN	8-2018	0	0	0	0	0	0	0
BAKKEN	7-2018	4	0	0	0	1	0	0
BAKKEN	6-2018	17	832	892	349	1455	1165	158
BAKKEN	5-2018	31	1804	1877	251	2915	2609	59

February 9, 2019: production data for the three Austin wells at the bottom of this page has been updated. 

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

• 16990, 3,744, EOG, Austin 5-14H, Parshall, a single section/short lateral well, TD = 14,693 feet; t5/08; cum 703K 12/18, recent production:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	10-2018	31	4337	4300	752	1582	1328	2
BAKKEN	9-2018	8	814	779	509	289	230	0
BAKKEN	8-2018	0	0	0	0	0	0	0
BAKKEN	7-2018	4	0	0	0	1	0	0
BAKKEN	6-2018	17	832	892	349	1455	1165	158
BAKKEN	5-2018	31	1804	1877	251	2915	2609	59
BAKKEN	4-2018	30	1770	1720	182	2753	2512	0
BAKKEN	3-2018	31	1945	1916	192	3039	2679	109

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; data updated above; won't be updated here;

Recent production:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	8-2018	0	0	0	0	0	0	0
BAKKEN	7-2018	4	0	0	0	1	0	0
BAKKEN	6-2018	17	832	892	349	1455	1165	158
BAKKEN	5-2018	31	1804	1877	251	2915	2609	59
BAKKEN	4-2018	30	1770	1720	182	2753	2512	0
BAKKEN	3-2018	31	1945	1916	192	3039	2679	109

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 --

Date	Oil Runs	MCF Sold
8-2018	6845	1463

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

Date	Oil Runs	MCF Sold
8-2018	5782	1779

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

Date	Oil Runs	MCF Sold
8-2018	7093	1402

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 Pool Date Days BBLS Oil Runs BBLS Water MCF Prod MCF Sold Vent/Flare BAKKEN 8-2018 27 10072 9989 18310 7418 0 6197 BAKKEN 7-2018 3 13 13 1039 185 0 182 BAKKEN 6-2018 0 0 0 0 0 0 0 BAKKEN 5-2018 0 0 0 0 0 0 0 BAKKEN 4-2018 0 0 0 0 0 0 0 BAKKEN 3-2018 0 0 0 0 0 0 0 BAKKEN 2-2018 0 0 0 0 0 0 0 BAKKEN 1-2018 0 0 0 0 0 0 0 BAKKEN 12-2017 0 0 0 0 0 0 0 BAKKEN 11-2017 0 0 0 0 0 0 0 BAKKEN 10-2017 0 0 0 0 0 0 0 BAKKEN 9-2017 0 0 0 0 0 0 0 BAKKEN 8-2017 0 0 0 0 0 0 0 BAKKEN 7-2017 0 0 0 0 0 0 0 BAKKEN 6-2017 0 0 0 0 0 0 0 BAKKEN 5-2017 10 762 907 130 870 682 53 BAKKEN 4-2017 30 2547 2560 457 2827 2354 12

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: