Horizontal Drilling -- Natural Gas Pipeline Expansion From Watford City To Tioga -- September 24, 2022

This post began with a note from a reader. Thank you very much.  

This reminds me of The New Yorker article in 2011:

It also reminds "how much we lost" due to Covid, and how many years (a decade?) we will be paying for that lost year or two.

This story is important for many reasons, has several data points of note.

North Dakota gas plants.

Note, regarding the charg:

• no increase in natural gas processing capacity, 2022 (this year) over 2021 (last year);
• next year, 2023, should see an increase of 200 MMCFD
• from 4,037 to 4,237, a 5% increase

The increase will be at ONEOK's new Demicks Lake III plant.

• Demicks Lake I, in service, 2019: 200
• Demicks Lake II, in service. 2020: 200
• Demicks Lake III, in service, 2023: 200

Will need pipeline for takeaway from Demicks Lake III.

Enter, WBI Energy Transmission, link here:

• Bakken Gas Pipeline Expansion project
• origin: Demicks Lake III, Watford City, ND
• terminus: Northern Border Pipeline interconnect, Tioga, ND --> midcontinent
• 175,000 dt/d expansion of its pipeline system
• in-service: November, 2023
• $32.6 million
• expansion of its existing Line Section 27 system
• two 24-inch-diameter, 500-foot-long pipelines
• two new compressor stations (?) 
• if I'm reading this correctly, $33 million for a 1,000-foot expansion?
  

From The Bismarck Tribune, November 18, 2021:

Work is resuming in McKenzie County on a natural gas processing plant project delayed in 2020 by the coronavirus pandemic. 

Oneok announced this week that it will complete the project known as Demicks Lake III, an expansion of the company's processing facilities near Watford City. 

The company expects work at the site to wrap up during the first quarter of 2023. The new plant will have the capacity to handle 200 million cubic feet of gas per day. It will bring the company's total gas processing capacity across the Williston Basin to 1.9 billion cubic feet per day, which could accommodate about two-thirds of all gas produced in North Dakota. The project is expected to cost $140 million.

I can't say for sure, but it sounds like this partnership / nexus, for three major projects:

• Watford City
• Tioga
• Demicks Lake gas plants (I, II, III -- 2019, 2020, 2023)
• under-the-water pipelines, setting records in the process
• Michels
• Oneok
• MDU
• WBI Energy, a subsidiary of MDU

************************************
Most Recent Major Pipeline Expansion Project

Link here.

From the linked article, November 4, 2021:

Michels completed a 15,426-foot horizontal directional drill (HDD) of a 24-inch pipe crossing of Lake Sakakawea on the Missouri River in North Dakota, extending the limits of trenchless construction.

The crossing is part of a new pipeline being constructed from Tioga, North Dakota, to near Watford City, North Dakota.

The HDD crossing of just less than 3 miles is one of the longest of its kind, surpassing by 3,174 feet a 20-inch HDD crossing Michels completed in the Bakken region in 2019. 

HDD minimized disturbances to the area and provided a delivery outlet for previously untapped energy sources in both instances. Although the crossings were similar in location, length, and technique, each project included its own unique and awe-inspiring accomplishments. 

Prior to pullback, the 15,426-foot pipeline was assembled by Michels Pipeline, Inc., into two sections–one of 426 feet and another of 15,000 feet. 

When laydown space allows, long sections of pipe can be advantageous because they require fewer pull stoppages to weld pipe strings together. While stopping can generally be accomplished, resuming movement of pipe can be challenging, even with a specific and well-planned drilling fluid and lubrication program. Like the 2019 project, the recently completed project used the pilot hole intersect method and two custom-made drill rigs, each with more than 1-million pounds of push/pull capacity.

Abbreviated 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. Full disclaimer at tabbed link.

All my posts are done quickly: there will be content and typographical errors. If anything on any of my posts is important to you, go to the source. If/when I find typographical / content errors, I will correct them.

Blue Hydrogen -- It's Happening -- North Dakota -- August 16, 2021

Updates

January 17, 2023: the update from RBN Energy did not include the Bakken.

August 17, 2021: link here. Blue hydrogen in the UK. Graphic pending, the dual-track blue hydrogen / green hydrogen program in the UK. Blue hydrogen in the UK will exceed CO2-emissions target, link here.

Original Post

A huge "thank you" to a reader for alerting me to The Williston Herald story. 

For background, see this June 2, 2021, post: blue hydrogen, Mitsubishi, Denbury, RBN Energy, and all that jazz. 

For more background, gray hydrogen, blue hydrogen, and green hydrogen, at Forbes, February 22, 2021.

“Green hydrogen is what Europe absolutely wants. But blue hydrogen is what a lot of the world thinks we can afford sooner and it’s probably going to be good enough,” he said. “It’s really more of a market-driven thing than a technology thing.”

From The Williston Herald (by the way, has anyone noticed that the Herald is getting better and better or is that just me?), link here. Data points:

• blue hydrogen hub in the Bakken
• to be built in about half the time "it usually takes" 
• a greenfield plant normally take ten years to build / become operational
• operator says a brownfield plant might take just five years
  
• operator / source of data: Bakken Energy
• announced August 16, 2021 (today)
• the deal:
• official name: the North Dakota Hydrogen Hub
  
• partners: Basin Energy and Mitsubishi Power
  
• Basin Electric Coop will purchase the assets of the Dakota Gasification Company
• Dakota Gasification Company owns the Great Plains Synfuels Plant
• expected to close April 1, 2023
• Synfuels to continue existing operations through 2025
• the plant, when complete:
• 310,000 metric tons of hydrogen per year
• primarily sourced through locally natural gas (CH4 --> CO2 and hydrogen)
• Mitsubishi Powers Americas
• the centrally-located North Dakota Hydrogen systems will connect Mitsubishi's planned wester and eastern US hubs to establish a national hydrogen network
• Mitsubishi: will create: a Change in Power division
  
• the CO2 will end up in CCS projects
  

From the blog, June 2, 2021, linked above:

To that end, Figure 1 below shows a simplified process flow diagram for a typical SMR unit.

Figure 1. Simplified SMR Flow Diagram. Source: RBN

To create hydrogen via SMR, natural gas is first fed into a processing unit called a reformer. There it reacts with high-temperature steam and a catalyst, usually one that is nickel-based, to form hydrogen and carbon monoxide. The resulting gas mix is then fed to the shift conversion unit, where the carbon monoxide reacts with the steam to produce even more hydrogen, plus carbon dioxide (CO₂). The hydrogen and carbon dioxide are then sent to a pressure swing adsorption (PSA) unit, where the CO₂ is removed from the hydrogen.

Natural Gas Production Projection -- August 6, 2021

From Geoff Simon:

The ratio of natural gas to crude oil being produced from Bakken wells will continue to increase, possibly doubling the state's current natural gas output in fewer than 10 years.

That was the message of Justin Kringstad, director of the ND Pipeline Authority, to members of the ND Legislature's interim Energy Development and Transmission Committee this week. Kringstad said the ratio of natural gas to oil typically starts out close to one-to-one, meaning 1,000 cubic feet of natural gas for each barrel of crude oil. But he said the ratio has been steadily climbing as more new Bakken wells are completed.

 

Kringstad said the higher gas-to-oil ratios are not unexpected. He told legislators most new wells today are being drilled in areas where a "parent well" already exists, which means the pressure that holds natural gas in the reservoir has already been reduced.

Click here to listen to Kringstad's comments.

.... the high case of which could have the state's natural gas production approaching seven billion cubic feet per day. The state's output as of the month of May was just under three Bcf per day.

Graphic:

Also from Geoff Simon:

Last year's pandemic-related downturn in oil and natural gas production provided midstream companies some relief in the pace at which new natural gas processing and takeaway capacity was needed. But increasing gas-to-oil ratios mean they will need to return to construction mode quickly.

Helms said the accelerated schedule won't provide midstream companies adequate time to get new processing and takeaway capacity permitted and constructed, but he said tax incentives enacted by the 2021 Legislature will encourage innovative methods of using the additional natural gas. 

SB 2328 established a credit against the oil extraction tax to incentivize use of onsite flare mitigation systems in production operations. The credit is equal to $0.75 per one million BTUs of flare mitigation that results from operating a flare mitigation system on a qualifying well. Credits are capped at a maximum of $6,000 per well per month, for as many as 12 months.

Helms said he's also seeing increased interest in using natural gas and gas liquids to generate electricity.

Notes From All Over -- Saturday Morning Edition, Part 1 -- Juneteenth, 2021

Coal is dead! Long live coal! Wow, how many times have I posted those six words? From social media: US year-to-date coal production totaled 261.5 million shorts tons, 8.7% higher than the comparable year-to-date coal production in 2020. Or go directly to EIA's "weekly coal production" site.

Bakken natural gas -- year-long high: Canadian gas exports on Northern Border reach five-month high despite Bakken growth. Link at S&P Global Platts. Wow, it looks like Platts didn't know which story line to headline. Data points:

• Bakken production reaches year-long high (with 16 active rigs, just saying);
• Bakken gas flaring remains under 7% (how's the Permian doing?)
• Canadian natural gas exports on the North Border Pipeline increased by an average of more than 200 million cfpd over the past seven days (article published June 14, 2021)
• Bakken supply on the pipeline: 1.68 billion cfpd
• lowest amount of Bakken supply on that line since the severe winter storm in mid-February
• freeze-offs dropped it to 1.64 billion cfpd
• okay: 1.68 billion vs 1.64 billion, and that's a headline
• Bakken rigs have climbed nearly 40% since January 1, 2021 (previously posted)

Bloomberg on shale: I had seen this link some time ago, debated whether to post it. Then a reader sent it to me. So it's linked/posted, FWIW. "After blowing $300 billion, US shale finally makes money." Way too many story lines to even begin. All I know is this: a lot of mom-and-pop mineral owners in North Dakota don't mind one bit, smiling all the way to the bank. Which reminds me, the data for the June, 2021, North Dakota Legacy Fund will be posted this next week. Link is here. Currently about $40 million is added each month to the coffers. 

Natural gas reclassification: I understand this not at all but will post the link for the archives. Maybe some day it will make sense.

China: considers lifting all childbirth restrictions by 2025. Link at The WSJ. 

There are so many story lines, I cannot even begin. However, from an energy point of view, and that's all I really care about any more with regard to a blog focused on the Bakken: this tells me all I need to know about China's energy situation. Any decision to drop childbirth restrictions has to be done lock-step with regard to energy requirements. This suggests to me that China feels very comfortable meeting its energy needs going forward. 

That's huge. 

China: I've followed this story for years, mostly from an environmental point of view, but now it's history -- that massive Chinese hydropower plant on the Yaangtze River has begun full operation. Huge. Link here to Charles Kennedy.

• seventh-largest hydropower facility in the world
• 12-generators
• $19 billion
• installed capacity of 10.2 GW
• first started generating electricity one year ago, but now all generators on line
• Wudongde plant aka the "who-done-it" plant
• displaces 12.2 million tons of standard coal and eliminates 30.5 million tons of CO2 annually (FWIF)
• global hydropower capacity:
• China, #1: 1.302 terawatt-hours as of 2019
• Canada, a distant #2: 398 TWh
• China with four of the world's largest hydropower plants, including the massive Three Gorges dam with a capacity of 22.5 GW and Xiluodo aka Xanadu, 13.86 GW

Gasoline demand: the EIA data does not seem to corroborate this story, but Reuters is reporting that US motor vehicle travel jumped by 55% in April, 2021, over 2020 levels. 

Trending on social media: HBO Max releases "Integration test Email #1." 

Exxon feeling pretty good these days? The company rejects union proposal to end Texas refinery lock out. Link here. Seven weeks so far.

And why not? If they were cheap a week ago, they're really cheap now. Three cheap energy stocks to buy right now, from The Motley Fool. By the way, what three things to these three companies have in common?

• Enbridge
• EPD
• OKE

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.

Answer to quiz:

• they're all pipeline companies;
• they're all making a gazillion dollars in the Bakken;
• they all pay a great dividend

The Natural Gas Conundrum In The Bakken -- May 23, 2021

About a week ago I posted a note on the problem with ethane in the Bakken.  

A reader replied with an excellent four-part note. But that note really "bugs" me in a positive way. It was such a great note that I hate to see it "lost" in the comment section only. 

So, here is the four-part note brought up as a stand-along post (hopefully I have them in the same order). No editing but if there are any typographical errors, attribute them to me, not the reader.

I'll come back later and highlight some of this.

First part of that four-part comment: 

It pains me when I see even oil execs not knowing something so basic as what NGLs are. And the popular press and peak oil nitwits are even worse. Talk about stuff and don't understand it. If you follow this sector for years, you need to learn/understand it.

1. First important characteristic of oil and gas is that it is a natural product. This is very different than chemistry where you think of a single molecule. Here we have a soup of different molecules. Thousands of different ones. And different deposits have different mixtures. And many of the fuels also are mixtures still (e.g. gasoline). VERY different than an element or a molecule, something you have pure and in a little Sigma Aldrich bottle to do reactions with. These are MIXTURES.

2. Creating this mixture tendency are two phenomenon: first the incredible complexity of organic compounds. Carbon has four bonds and forms stable molecules with many carbons. You can have different length chains, branches, rings, double/triple bonds, etc. And can have heteroatoms (non-C or non-H, e.g. S).

Secondly, organic molecules are (in general) very soluble in each other. You know oil and water? They don't mix. But different oils DO mix. And even natural gas (methane, one carbon) dissolves to a decent amount in even very heavy oils like tar sand.

Of course, the exact shape (branches and the like) matters. But for very simple assessment, you can think of the number of carbons as determining the properties of the molecules. C-1 (one carbon) is the simplest form and is "pure" natural gas. It has a very low boiling point (requires incredibly cold temps to liquefy into LNG, e.g.) Gasoline is around C-8. It's actually a mixture and branching is important, but for very gross oversimplification, think of it as octane. It has a relatively low boiling point (thus the vapors you can see). Diesel is less volatile (has a higher boiling point). Think of it as C-16. It's actually a mixture and straight(er) chains are important, but think of it as C-16. Heavy fuel oil is even more carbons and higher boiling.

[The different fuels are made by distilling to separate the mixtures in crude oil, thus "distillation towers". It's actually more complex than that with some cleanup, and molecule fiddling (cracking and the like). But for gross simplicity, think of basically taking the oil and distilling it into different "cuts" of hydrocarbon length.

Second part of that four-part comment. 

3. Oil and gas are produced together (in most cases) along with water. An oil well (or a wet gas well) is really an oil/gas/water well. At the well-head, there is a "three phase separator" that gives vapor (top), oil (middle) and water (bottom). This is basically just done by mechanical separation, like in your salad dressing bottle. Can Google for Youtube videos of the mechanism--they are cool looking with some mechanical tricks to allow the separation at decent flow rates. But for simplicity, can think of it as a wide spot in the pipe allowing settling separation.

A gas well typically has a little bit of associated oil. And visa versa. And can even be sort of same amounts of each. In a few cases ("dry gas"), you may have insignificant oil. And even rarer, you may have "dead oil" that has no appreciable gas. But usually you are getting BOTH together. (Along with some useless water.)

From, the 3-phase sep, you get three streams, the first twof which are commercial:

a. The vapor ("wet gas") is mostly C-1, but has appreciable amounts of C-2 to C4, and a little bit of C-5+.

b. The liquid oil is called "crude" or "lease condensate". There is no fundamental chemical difference (like with elements) between crude and lease condensate. The are the same junk, different flavors. In many states (ND, for instance), there is no tax or regulatory difference. And the Feds treat them the same also. A few states (OK, TX) differentiate crude (from mostly-oil wells) and lease condensate (from mostly-gas wells) for tax purposes. And the lease condensate tends to be lower density (higher API gravity). But it is purely a matter of degree. No fundamental difference. The peak oil morons get this messed up all the time.

c. The water is just salt water from the deep earth. Very high salinity and can contain some radioactivity or the like. Honest, it's not that awful. I think deep ocean disposal would hurt nothing because of the dilution. But you ain't allowed to put it in streams or the ocean any more. Have to clean it up or inject it back into the deep earth. Usually the latter.

Third part of that four-part comment:

4. The numbers you see reported for oil and gas production (on the EIA 914 or the NDIC) are C&C (crude and lease condensate) and well-head gas. I.e. they are the amounts produced FROM the 3 phase separators at well pads.

After the well-pad, the C&C goes to refineries where it is (basically) separated into different boiling fractions: light ends (even including a little more natural gas, along with ethane, propane), naphtha, gasoline, diesel, kerosene, heavy fuel oil, and even asphalt. You can think of this as a much more complex, expensive, "second separation" of the liquid petroleum stream from the three-phase sep. High temps are used to drive the separation.

The natural gas from the 3-phase separators also gets a "second squeeze" in centralized, expensive plants, away from the well head. In this case, cold temps are used to separate components. The C-1 (methane) is natural gas. All the other components of the "wet" gas stream are called NGLs (natural gas liquids). Paradoxically most of them are NOT liquid at room temp. But they are still liquid at higher temps than methane.

Ethane, C-2, is separated and used for petrochem (mostly). But in some cases, it is fed back into the natural gas stream when the heat limits allow, if price of petrochem is not good enough. C-3, propane, also has petrochem uses, but is mostly for space heating where natural gas is not available (think of it as transportable natural gas, can use much flimsier cylinders because of it's higher boiling point.

C-4, butane is right at the boundary of boiling. On a cold winter day, it is all liquid. But at room temp, it is a vapor. Can also be stored in flimsier tanks. Your plastic Bic lighter has butane in it...the slight pressure keeps it liquid, but as it comes out it evaporates). Because of the temperature, butane is seasonal. In the winter, it (mostly) gets mixed into gasoline. In the summer, it can't be mixed into gasoline. Also has some petrochem uses, but in many cases, people just store it in summer and sell it in winter.

There are two isomers of butane. The straight chain is used as above. The branched butane is actually sold to refineries as a starting material for making higher octane branched compounds. The branched isomer sells for more, so there is enough incentive to separate the two isomers and sell them separately.

The higher carbon molecules in the gas stream are called "pentanes plus". Since, well, they are C-5 mostly and a small amount of C-6, etc. These molecules ARE LIQUID at room temp. In the wet gas stream, they are a vapor. But the gas processing plant separates them out and collects them as a liquid phase.

C-5+ is sort of oil like. Is (confusingly) called "plant condensate" or "drip gas". But we are talking MUCH higher API gravity (say 90 or so) than wellhead lease condensates (that are in the high 40s-50s or so). However, plant condensates ARE real liquid hydrocarbons--the only NGLs that are room temp liquids.

There is no economic incentive to separate the (three) different isomers of C-5 or the C-6 (and its isomers). Basically pentanes plus is sold as a mixture. The primary application is to just get thrown into an oil refinery (mixed with heavier crude). But it can also be used for gasoline mixing, for diluting tar sands, petrochem, etc. 

Fourth part of that four-part note: 

In general, the gas stream components are more valuable as they get longer. But this depends on the exact supply/demand, transport availability and processing costs. But in general: C-1 is cheapest; C-2 is pricier; C-3 next pricier; normal butane even better; isobutane better than that; and pentanes plus best (close to WTI, maybe a ten buck haircut).

Again, it pains me that people (peak oilers, grrr) follow this stuff and opine on it for years. And don't even learn the first thing about what they are talking about. Not asking for detailed chem engineering and distillation curves. But just basic f... concepts. RBN has explained this several times. And there are many other sources a Google search away. But I still see people who don't know the basic lay of the land.

Rigs Don't Matter -- Not To Be Taken Out Of Context -- April 30, 2021

Link here. This article is archived.

Natural gas processing plants in North Dakota are tracked here.

From the linked article:

Although oil production in most US shale basins is not expected to reach pre-coronavirus levels until at least late 2023, additional processing and higher gas-to-oil ratios might still lead to natural gas growth in the oil-rich Bakken.

Oneok increased its first-quarter natural gas and natural gas liquids volumes processed in the Williston Basin and plans to bring another 200 MMcf/d of processing capacity online before year-end, which will further reduce flaring in North Dakota.

Gas volumes processed in the Rocky Mountain region increased 5% while NGL raw feed throughput volumes grew 20%, the company reported in its first-quarter 2021 earnings call on April 28. This occurred despite winter storm production freeze-offs in February and lower year-over-year drilling activity in the region.

"The Williston Basin continues to surpass our expectations," Oneok CEO Terry Spencer said. "Our increased operations were not reliant on increased rig activity or commodity prices. Instead, it is based on DUC inventory, rising gas to oil ratios and increased ethane demand."

Oneok chief operations officer Kevin Burdick said: "There are 350 DUC wells on our dedicated acreage. With eight completion crews, there is no need for additional drilling or completion crews to maintain our volumes throughout the year. Any additional activity would provide upside."

With more than 200 MMcf/d of natural gas still being flared in the Bakken, according to the latest data by the North Dakota Industrial Commission, more volumes of gas can still be captured even if production stagnates for the foreseeable future, especially with wells demonstrating higher gas-to-oil ratios.

The company is moving forward with its 200 MMcf/d Bear Creek natural gas processing plant expansion and related infrastructure in the Williston Basin, which is slated for completion in the fourth quarter of 2021.

Natural Gas -- North Dakota -- Production -- Processing -- Platts -- October 23, 2019

STAMPED: NOT TRIVIAL!!!!

Natural gas processing plants in North Dakota are tracked here.

From S&P Global, Platts (huge thanks to a reader for spotting this article) :analysis -- Bakken looks to add 445 million cf/d of natural gas processing before year's end.

... as production increased 69 MMcf/d month over month to more than 3 Bcf/d in August, operators lowered flaring to 577 MMcf/d. The startup of the Little Missouri IV processing plant likely led to the decline in flaring, according to S&P Global Platts Analytics. Flaring was still high at 19% for the month, well above the state's 12% mandate.

The drop in flared volumes is a sharp divergence from the prior three months when flaring increased each month. The increase in processed volumes from Little Missouri IV has allowed the Bakken to take an all-time high share of Northern Border Pipeline at the expense of Western Canada imports flowing to the Midwest.

Total Bakken deliveries to the pipeline are at an all-time high so far this month at 1.64 Bcf/d. Western Canadian volumes delivered to the pipeline are currently at 875 MMcf/d, just 10 MMcf/d more than the all-time low set in April, which was due in part to maintenance issues ...

The graphs are staggering:

• the Bakken is an oil play, not a natural gas play
• Canadians hate fossil fuel, doing what they can to destroy that part of their economy -- look at the west Canadian production vs little ol' North Dakota -- all of four counties, and mostly just two or three in the big scheme of things, and much of that natural gas production was flared off

Stamped: not trivial:

Records Being Broken Across The US -- The US Shale Revolution -- October 2, 2019

A reader sent me this:

I know you covered the EIA 914, but one big story has been missed. Texas crossed the magic 5MM bopd line, finally.

https://www.eia.gov/petroleum/production/

Other magic number records that may break later this year:

• GOM: 2 MM bopd
• ND: 1.5 MM bopd
• NM: 1 MM bopd

On the gas side:

• NM just cracked 5 BCF/d for the first time;
• ND is very close to breaking 3 BCF/d (maybe next month);
• PA is close to breaking 20 BCF/d (probably early next year, maybe this year); and, 
• even TX is not that far from breaking 30 BCF/d (probably next year).

https://www.eia.gov/petroleum/production/#ng-tab

WBI Energy's Valley Expansion Project -- North Side Of Fargo -- Has Been Approved By FERC -- Huge Shout-Out To The Bakken Frackers That Made It All Possible -- February 17, 2018

Updates

November 10, 2018: in-service.  

Original Post 

From WBI Energy:

WBI Energy's proposed Valley Expansion Project is an approximately 37.3-mile, 16-inch-diameter pipeline that will deliver natural gas to eastern North Dakota and western Minnesota. The pipeline would connect the Viking Gas Transmission Company pipeline near Felton, Minnesota, to WBI Energy's existing pipeline near Mapleton, North Dakota. New facilities include an electric compressor station near Mapleton, a regulator station in Barnes County, North Dakota, and town border stations in Burleigh and Stutsman counties, North Dakota.

Bakken Natural Gas Productioin Impacting Canadian Imports -- RBN Energy -- February 15, 2018

Jobs: link here --

• forecast: 229K
• actual: 230K 
• increase of 7K from previous week; previous week revised to 223K

Solar: property taxes questioned in Ann Arbor, Michigan. From the linked article:

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

Back to the Bakken

Active rigs:

$60.22↓	2/15/2018	02/15/2017	02/15/2016	02/15/2015	02/15/2014
Active Rigs	57	38	41	137	185

RBN Energy: capacity, demand constraints throttle Canadian gas imports to Chicago area. 

Canada’s natural gas exports — which have been pushed out of the supply-rich U.S. Northeast in recent years — are also facing challenges in Western U.S. markets. Growing supply from North Dakota’s Bakken Shale is increasingly competing for capacity on the same transportation routes as imports and is targeting the same downstream markets.

Meanwhile, the rise of renewable energy in the West region from wind and solar farms is limiting gas demand in those target markets. What does that mean for imports from Canada?

There are three export pipes on the Canada side that move Albert supply to the western US border:

• Enbridge's Westcoast Energy Pipeline, 1.3-Bcf/d; British Columbia to Washington state; 

• TransCanada Foothills which connects to Kingsgate (Idah) and into the Northern Border Pipeline (MT, ND), 2.4-Bcf/d; 

• Veresen/Pembina's Alliance Pipeline, North Dakota; 2.0-Bcf/d pipeline

So both NBPL and Alliance are effectively flowing near capacity and, if anything, imports are gradually losing ground to Bakken supply on these two pipes.

Alliance last March floated the idea of expanding its throughput to Chicago by 500 MMcf/d, and the open season for that is expected sometime this quarter. But as we detailed earlier, Bakken production is expected to continue growing, which means competition for any incremental transportation capacity is likely to be stout, with the effect of intensifying price competition between the supply regions. And, finally, as we noted above, there is still the pushback that both Canadian and Bakken gas are likely to face on the delivery end of these pipes from Marcellus/Utica gas that’s pushing west.

Worth Re-Posting -- February 13, 2018 -- North Dakota Natural Gas Production Setting Records

Rigzone, Eni, and others are making a big deal about the big natural gas field found off-shore near Cyprus (Mediterranean Sea), where Eni says it will produce 2.9 Bcf of natural gas by the end of the year (2018). Don't get too excited: the Bakken, an oily play -- not a natural gas play -- already produces more natural gas than Eni does from the Zohr field. From an earlier post:

February 12, 2018: Turkish warships are impeding a rig from reaching a location of Cyprus where Italian energy company Eni is scheduled to drill for gas. -- from Twitter. Update from Reuters. Turkey is wearing out its "welcome" in the EU. Eni says it will produce 2.9 Bcf per day from Zohr field by second half of 2019. Compare that "2.9 Bcf" to the Bakken: from the last Director's Cut,

What was North Dakota's natural gas production in the most recent month, November, 2017? Yup, another all-time high: 2.1 billion cubic feet / day.

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

Asian Demand For Natural Gas Surging

From Bloomberg:

Asia’s rapacious thirst for liquefied natural gas is sucking supplies from surprising places.

China to Japan and South Korea are paying top dollar for the super-chilled fuel. The pull is so strong that Norway’s Statoil ASA, which usually exports most of its LNG to Europe, is shipping a rare cargo east. It plans to send more.

Asia gets most of its LNG from Australia, including from the giant Gorgon project on the country’s northwest coast. Malaysia, Papua New Guinea and Indonesia are also big suppliers.

Statoil’s tanker, the Arctic Aurora, due in South Korea this week shows how the LNG market is becoming global, with more cargoes traveling long distances from the Atlantic to the Pacific region as China leads a landmark shift to burning gas instead of coal. For Statoil, it’s a chance to squeeze a little more profit from its overall gas production that’s already near full capacity.

“What we’ve seen in Asia is strong prices,” said Peder Bjorland, Statoil’s head of natural gas. But “it doesn’t help to have strong prices if you don’t have the shipping capacity. It’s been difficult to get hold of spot vessels.”

The producer has in the past sent cargoes to Malaysia, China, India and Japan, but it mainly serves the markets in Europe and the Americas.

MDU Transported A Record Volume Of Natural Gas -- Up Almost 10% Year-Over-Year -- Will Increase Again In 2018 -- February 10, 2018

The link at NaturalGasIntel.

MDU Resources Group Inc.’s is planning to bring online later this year a 21-mile, 12-inch diameter natural gas pipeline to serve a manufacturing facility in Gwinner, ND, and other nearby potential customers, CEO Dave Goodin said during a fourth quarter conference call.

The new pipeline comes as Bismarck, ND-based MDU transported a record volume of natural gas -- up 9.6% year/year -- through its system in 2017, partly because of completing two expansion projects that increased pipeline capacity by 62 Mcf/d.

The multi-state utility holding company expects to further boost its natural gas transportation capacity in 2018 to more than 1.8 Bcf/d after completing the 38-mile, 16-inch Valley Expansion project and the 13-mile, 24-inch Line Section 27 expansion project. Construction on both projects, which are headed up by MDU’s WBI Energy subsidiary, is expected to begin this spring.

“This business segment continues to seek additional growth projects to increase transportation capacity, including a continued focus on the Bakken, which is currently producing record volumes of natural gas,” Goodin said.

Much, much more at the link, including an update on their wind farm activity (FWIW).

Director's Cut Has Been Posted; North Dakota Crude Oil Production Data For November, 2017, Has Been Released; Crude Oil Production Increased Month-Over-Month; Producing Wells At An All-Time High; Natural Gas Production Hits Another All-Time High

Director's Cut for November, 2017, data, pending. The Director's Cut should be released today at 11:00 a.m. CT.

Link here. NDIC site for calendar and links for past and current Director Cuts here.

The usual disclaimer applies. I do "this" quickly and there will be typographical and factual errors. If this is important to you, go to the source.

Pricing, most current data I can find, January 12, 2018:

A reader told me that the NDIC uses the pricing at Flint Hills Resources for the oil prices reported at the monthly Director's Cut. At the link, one has a choice of clicking on "EDQ" or "Bulletins." Click on "Bulletins" and then click on "Download." The result should show up as a PDF on your desktop.

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The Data

Natural gas production: in April, 2017, it was reported that North Dakota produced a record amount of natural gas: in that month, natural gas production jumped 6% more than 1.8 billion cubic feet / day. What was North Dakota's natural gas production in the most recent month, November, 2017? Yup, another all-time high: 2.1 billion cubic feet / day.

Oil production

• November, 2017: 1,194,920 bopd
• October, 2017: 1,183,810 bopd
• Delta:  an increase of 11,110 bbls
• Delta: an increase of just under 1%

Producing wells:

• November, 2017: 14,324 (an all-time high)
• October, 2017: 14,253
• Delta: an increase of 71 wells;

Permitting

• December, 2017: 147
• November, 2017: 119
• October, 2017: 147 
• September, 2017: 104
• August, 2017: 101
• July, 2017: 146 (huge jump)

Oil price (WTI), breakeven price statewide = $21

• today: $54.75
• December, 2017: $49.56
• November: $49.75
• October: $43.56
• September: $39.56
• August: $37.93
• July: $35.83
• June: $34.72

Rig count:

• today: 56
• December: 52
• November: 54
• October: 56
• September: 56
• August: 56
• July: 58
• June: 55

Wells not producing, total: about 2,375 not producing; that exceeds the number of wells completed in any year during the boom

• waiting on completion: 883, down from 6 the end of October to the end of November
• estimated inactive well count: 1,492, up 21 from the end of October to the end of December

Takeaway capacity:

• November: takeaway capacity including CBR to coastal refineries is more than adequate
• October data: including CBR to coastal refineries is more than adequate
• September data: including CBR to coastal refineries is more than adequate
• August data: including CBR to coastal refineries is more than adequate
• July data: including CBR to coastal refineries is more than adequate
• June data: including CBR to coastal refineries is more than adequate
• May data: including CBR to coastal refineries is more than adequate (major change in verbiage)

Natural gas capture, has been getting "worse" and FBIR was a major issue; the trend has improved; it looks like ND has "turned the corner" on this issue

• statewide: 86% (previous -- 84% [trend has improved)
• FBIR: 75% (previous -- 74%)
• goal: 88% through October 31, 2020; then 91%
• comment: October, 2017, was terrible; it's getting better on FBIR

The Bakken -- It Just Never Quits -- December 23, 2017

The item is very short:

WBI Energy Transmission Inc. filed an application with the Federal Energy Regulatory Commission for a new section of pipeline to boost transportation capacity to the company's interconnect with Northern Border Pipeline Co. in western North Dakota.

The project would include 12 miles of 24-inch-diameter steel pipeline that would begin at the Spring Creek meter station and end at the Cherry Creek valve setting. The company said it has precedent agreements with Oasis Petroleum Marketing LLC and ONEOK Rockies Midstream LLC for 196,000 Dth/d and 10,000 Dth/d of incremental firm transportation service, respectively.

That was it. My comments/observations:

• huge, huge pipe: 2 feet in diameter -- think about that next time you see pipeline (water, natural gas, sewer, whatever) -- a 2-foot diameter pipe is one huge pipe
• total ND natural gas production: 2,000,000 or 2 million mcf/d 
• 206,000Dth/d = 200,000 mcf/d
• 200,000 / 2,000,000 = 1% -- one percent
• if my figures are correct, this pipeline will move about 1% of all the North Dakota natural gas produced in one day
• the connector is 12 miles; at $1 million / mile = $12 million dollars

This is pretty cool. If you are remotely interested in this project or just want to have some fun looking at FERC documents and maps of North Dakota, simply click on this http://www.wbienergy.com/docs/default-source/demicks-lake-ferc/wbi-demicks-lake-draft-resources-report-10.pdf?sfvrsn=4. A PDF will probably download on your desktop.

It downloads incredibly quickly suggesting it's in the cloud. It will download faster on a cloudy day.

I don't know how long the Bakken will last or how important the Bakken will be in the big scheme of things. All I know is that "they" aren't putting in 12 miles of 2-foot-diameter pipeline for upwards of $15 million for a one-year science project. Art Berman can say it's the "beginning of the end" for the Bakken and The Atlantic can say the boom is over and oilprice can say that US shale is not the answer and yada, yada, yada, but without question there's a lot going on in four little counties in western North Dakota, providing a lot of high-paying jobs for a long, long time, and for the most part not upsetting the gods to any significant extent -- at least the volcanoes in western North Dakota are not erupting, suggesting the gods can't be too mad at "us."

Sort Of Looks Like The Keystone XL Route, Doesn't It? -- April 28, 2017 -- President Obama -- What Were You Thinking?

By the way, I see that Time, Inc, shares this morning are down almost 20%. Wow.

But back to the graphic featuring Tioga and Prairie Rose, North Dakota:

For more on this pipeline, see this post from September 17, 2013. From that post:

Related headlines:

• Aux Sable announces one of the first natural gas facilities in western North Dakota, May 3, 2013
• Enbridge's moat has widened, August, 22, 2012
• Another revenue stream for mineral owners, April 27, 2012
• Tioga to Sherwood, September 28, 2011 

More takeaway capacity for North Dakota natural gas identified.

The Prairie Rose Pipeline, owned by Aux Sable, Calgary, with origins in Burke and Mountrail County, will feed natural gas from these two counties into the Alliance Pipeline, owned by Summit Midstream Partners; this pipeline is 2,300 miles long and runs from western Canada to the Chicago hub.

Capacity:

• Current agreement: 17 million cubic feet/day
• New agreement: 25 million cubic feet/day

 That's almost a 50% increase in one pipeline system.

Curiouser And Curiouser -- Getting Closer And Closer: The "Sleeping Giant" -- The Natural Gas Play In North Dakota (No, This Is Not The Bakken) -- June, 2014

I track the Strata-X wells here. 

Operations have commenced, according to the company's press release:

• Drilling operations on the Rohweder #1-11 well anticipated to start within a week.
• First test of Company's 120,000 net acre shallow gas project.
• Release of the Sleeping Giant Primer Presentation

The directors and management of Strata-X Energy Ltd. are pleased to announce that the Company started operations on the vertical Rohweder #1-11 well located in Emmons County, North Dakota, USA. 

Final location work is currently being completed with the rig mobilization anticipated to begin on or around June 20, 2014. The Rohweder #1-11 well is the Company's first appraisal well in the Sleeping Giant Gas Project. 

Strata-X is the operator of the well and retains a 100% working interest in it. Overall, the Company has acquired exploration rights to 120,000 mostly contiguous net acres in the Sleeping Giant Gas Project.

Back on December 11, 2013, just a few months ago I posted a link to this story: the "Sleeping Giant" in North Dakota, east of the Bakken.

"Anon 1," who hasn't sent a comment in a long time, alerted me to the company's most recent presentation. At the link, there are two presentations: the "USA" presentation has the "Sleeping Giant" update.

A huge thank you to "Anon 1."

More from the linked press release:

The Sleeping Giant Gas Project is targeting biogenic natural gas from the prolific Upper Cretaceous Niobrara formation in the Williston Basin, North Dakota. The Niobrara Formation is a significant petroleum system in the USA and has produced over 1 TCF of natural gas from shallow accumulations including the project's geologic analogue, the Beecher Island field in the Denver-Julesburg Basin (Colorado, USA). 

To date, Beecher Island field has produced over 101 Bcf of natural gas and is expected to ultimately produce 157 Bcf within an area spanning approximately 32 square miles. A field analysis done by Walt King shows that reserves per well average 650,000 Mcf on 160 acre spacing in the Beecher Island Gas Field. It is expected that the Sleeping Giant Gas Project could yield similar economic resources per well due to similar geologic conditions. 

There has been relatively little drilling in the Sleeping Giant Gas Project area to date, with most wells targeting the deeper Cretaceous and Paleozoic targets. Sub-commercial natural gas has been produced outside the mapped closure on the large structures in the project area, with the crestal regions of the structures remaining untested within the targeted zone. The Rohweder 1-11 well will test the Beaver Creek Prospect structure, which is just one of the 26 prospects and leads that have been identified in the Sleeping Giant Gas Project.

The Company anticipates that drilling and casing operations on the Rohweder #1-11 well will be completed by early next week. Thereafter, information obtained during the drilling of the well will be used to design and optimize a completion stimulation of the well. The drilling permit for the Rohweder #1-11 well is one of four permits granted to Strata-X by the North Dakota Industrial Commission. The other drilling permits held by Strata-X on the Sleeping Giant Gas Project are the Aberle #1-31 and Just #1-24 wells located in McIntosh County and the Hoff #1-32 well located in Emmons County, North Dakota.