Did Chesto Get Ahead Of His Headlights? -- December 16, 2018

A reader updates this story:

A few weeks back, a Rhode Island fishermen's advisory council unanimously voted down Vineyard Wind's project due to the turbines' placement. Shortly thereafter, the Rhode Island Maritime regulatory body postponed a scheduled permitting vote - necessary for the project to proceed - in order for the fishermen and Vineyard Wind to come up with an agreeable compromise (HIGHLY doubtful).

The vote is now scheduled for the end of January.

A Vineyard Wind spokesman has already stated that, absent a positive, timely approval, both Vineyard Wind and all northeast offshore projects might be scuttled.

Fishermen and wholesale fish marketers up and down the East coast are mobilizing to block these wind farms.

The original "Chesto" story was posted yesterday, December 15, 2018;

Winds of change: The blockbuster auction for offshore wind leases that wrapped up today should leave few doubts: The industry has finally arrived in New England.

Three developers backed by major European energy companies won access to 390,000 acres of federal waters nearly 20 miles south of Martha’s Vineyard and Nantucket, after numerous rounds of spirited bidding that stretched over two days. These firms will each pay a record $135 million for the rights to build massive windmills in their respective slices of the ocean.

Walter Cruickshank, head of the US Bureau of Ocean Energy Management, told reporters: “We are completely blown away by this.” He was speaking for the agency that oversaw the auction, of course.

But he also summed up the industry’s reaction. Although these areas will take many years to fully develop, BOEM says the three lease sites combined could eventually support 4,100 megawatts of wind generation, enough juice for 1.5 million homes.

Much more at the link.

The Young And The Beautiful, The Great Gatsby, Lana del Rey

List Of LNG Export Terminals Update -- December 16, 2018

A most important post regarding LNG export terminals in the US was posted on October 12, 2016.

To all of that, add Golden Pass LNG terminal in Texas (existed prior to October, 2016) and now the fact that Qatar plans to expand.

Later, a writer expands on the above --

Quick followup to this LNG export post ... several projects of special note -

Driftwood incorporating modularization to produce HUGE volumes at VERY low cost

Delfin using new generation of 'Floaters' (FLNG) to reduce time and cost even further.

Main Pass Energy Hub to produce - if it comes to fruition - a revolutionary floater approach using 2 ships to produce an astounding 24 million tonnes per year (mtpa) at a cost of $9 billion.

A project proposed to place up in the woods of northeast Pennsylvania: New Fortress Energy will be the operator. A near-Elba Island capacity of 2.1 mtpa LNG plant for under $900 million and an 18 month build time.

I realize that the numbers, scope and terminology of the natgas world can be confusing, but the handling, processing and transportation of this stuff is rapidly evolving with enormous, global implications.

Qatar Helping To Make America Great -- December 16, 2018

This is really, really, really cool.

Back on December 12, 2018, I did not have time to provide the full story, so I simply provided the link and suggested readers connect the dots for themselves. I don't know how many did. That's fine.

That story was huge. There are some big things going on in the Mideast.

But now there's more to the story.

As we all know, links everywhere, Qatar has quit OPEC. Everyone says it's a symbolic move. La-de-dah. In politics, most everything is symbolic. LOL. Be that as it may.

Not only is Qatar leaving OPEC but it now has plans to invest as much as $20 billion dollars in the US in the coming years.

This is $20 billion that is not going to be invested in the Mideast, France, Germany, Russia, China, or Japan. This infrastructure build-out continues to widen the energy gap between the US and the rest of the world.

[By the way, as much as I dislike wind/solar, US renewable energy will outdistance the rest of the world in the long run also.]

But I digress. Back to the linked story.

Qatar Petroleum (QP) is looking to invest at least $20 billion in the United States over the coming few years, its chief executive told Reuters, after the Gulf Arab state unexpectedly quit OPEC this month.

Saad al-Kaabi, who holds the energy portfolio of the world’s top liquefied natural gas (LNG) supplier, also said on Sunday QP aimed to announce its foreign partners for the new LNG trains it is building by the middle of next year, and the company has decided to self-finance the expansion rather than borrowing.

“We are looking at many assets in the U.S. We’re looking at gas and oil, conventional and non-conventional,” Kaabi said in an interview at his office in Doha.

Qatar, a tiny but wealthy country is one of the most influential players in the LNG market due to its annual production of 77 million tonnes. It plans to boost capacity 43 percent by 2023-2024 and will be building four liquefaction trains for the LNG expansion.

Finally, back to the December 12th story: the reason Qatar left OPEC. Because it is the majority owner of the Golden Pass LNG terminal in Texas. Connecting the dots will explain how the two are connected.

The Challenges Of Calculating Breakeven Points In Tight Oil Fields -- December 16, 2018

See this post for background and full production profile.

The well:

• 16677, 101, MRO, Beck 24-8H, Bailey, initial frack, open-hole with 500K lbs sand; 45-stage re-frack in 2017 with only 5.8 million lbs sand, t12/07; cum 172K 10/18;

Disclaimer: I am inappropriately exuberant about the Bakken.

This well was a lousy well by any measure when it was first drilled. We talked about that at the time, but it fulfilled its role: a) it provided geologists an opportunity to look at the geology of the drilling unit; and, b) it held the lease by production for ten years. 

Back in 2007 most of the cost was in drilling the well; the stimulation costs should have been minimal: open-hole stimulation with around 500,000 lbs of sand. Big deal. LOL.

Wells back then were taking up to 45 days or more to drill, from spud to completion. Wow, think about that. Now they are drilling these wells in six days, fourteen days max, and then shutting them in, to come back and frack a group of wells, each frack taking three to five days.

This well was off-line most of its life and would have cost little to maintain.

Then in 2017, it was re-fracked with a small amount of sand, less than 6 million lbs. The operator essentially got a brand new well for the cost of small frack.

The operator did not have to go through the laborious process of obtaining surface rights; mineral rights; building a new pad; building a ten-mile road out to the site; bringing in electricity; putting in a new natural gas fractionator; etc; etc; etc. All the infrastructure was done. In fact, it's possible there are water lines in some areas negating multiple water truck runs. Some areas have waste water pipelines in place. And the cost savings go on and on.

One can calculate the break even cost(s) of this well going all the way back to 2007, but those costs have long been "booked." Anything prior to 2010 is certainly ancient history, some might argue.

On the other hand, some might argue that the break even costs of oil coming up from that well after the re-frack is the "new" break even cost. I don't know.

This is the beauty of drilling in the Bakken. Chevron calls these projects "short-cycle projects." Operators can pick and choose which wells to re-frack based on many factors. The WTI spot price is simply one factor, and perhaps a minor factor in the overall scheme of things.

There are many ways to figure break even costs in tight oil.

In the Permian, and in the Bakken, to some extent, there is even another huge variable. I'll let readers think about that for awhile. A reader mentioned it the other day. 

But what I love most about this well, as noted above: this well was a lousy well by any measure when it was first drilled. Many readers talked about that. Wondering why operators kept drilling wells like this. We talked about that at the time, but this well and many others like it fulfilled their roles: a) these wells provided geologists an opportunity to look at the geology of the drilling unit; and, b) these individual early wells held the lease by production for ten years.

Random Update / Example Of A BR Well In The Core Bakken -- December 16, 2018

This page won't be updated. The Anderson Ranch wells are tracked here.

In the early early days of the boom, in the core Bakken, we might have seen nice 24-hour IPs, but the wells declined quickly. The production after the initial frack might peak at about 8,000 bbls/month; quickly decline; and be lucky to hit 100,000 bbls in two or three years.

Disclaimer: I am inappropriately exuberant about the Bakken.

Now we are seeing more and more wells in the core Bakken, looking like this:

• 32635, 476, BR, Anderson Ranch 3A-MBH, API: 33-053-07585, gas shows were very, very low, averaging 105 units but did register a hight of 8,934 units, Camel Butte, huge well, 23 stages; 9.9 million lbs sand, t5/17; cum 348K 10/18;

Note the initial production. Instead of 8,000 bbls at the peak following the initial frack we are seeing the peak at over 30,000 bbls. Instead of seeing the decline in just a few months, this well was still producing over 30,000 bbls/month  six months later. And then most importantly, in less than 18 months, cumulative at 350,000 bbls.

When the boom began, many thought that the EUR for Bakken wells would be 350,000 bbls.

This well has produced that much in 18 months, and it will go on producing for 35 years. Over its lifetime, it will undergo multiple workovers; mini-re-fracks; major re-fracks; effect of neighboring wells; better re-completion strategies; etc.

This well was off-line in July, 2018, for a workover.

And, oh, by the way, for those folks who might argue that huge amounts of expensive proppant (ceramic, for example) is being used, this used a fairly moderate/large amount of proppant but it was all white sand and mesh; no expensive ceramic. In addition, only 23 stages. Imagine the production ad the typical 50 to 60 stages been employed.

Full production profile for this well:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	10-2018	31	11486	11487	6711	26717	26614	0
BAKKEN	9-2018	30	12782	12798	7942	25442	25343	0
BAKKEN	8-2018	26	10679	10426	8305	17443	12916	4440
BAKKEN	7-2018	0	0	252	0	0	0	0
BAKKEN	6-2018	29	19367	19479	16040	18544	0	18445
BAKKEN	5-2018	31	22183	22091	19238	25502	20060	5337
BAKKEN	4-2018	30	21797	21687	15316	37050	36948	0
BAKKEN	3-2018	11	8088	7960	7842	11864	11817	0
BAKKEN	2-2018	2	902	1225	108	19	11	0
BAKKEN	1-2018	26	28549	28349	7415	47999	47904	0
BAKKEN	12-2017	31	31635	31665	9546	56427	56324	0
BAKKEN	11-2017	28	31025	31014	10065	44732	44638	0
BAKKEN	10-2017	27	24276	24326	8739	37199	37104	0
BAKKEN	9-2017	27	29123	29074	10471	39309	39212	0
BAKKEN	8-2017	31	29309	29298	9810	48612	48509	0
BAKKEN	7-2017	26	26992	27171	9172	41527	41462	0
BAKKEN	6-2017	30	31632	31582	15467	48840	48766	0
BAKKEN	5-2017	22	8519	8224	6791	15897	14904	938