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THE Natural Gas Thread (merged)

General discussions of the systemic, societal and civilisational effects of depletion.

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Re: THE Natural Gas Thread (merged)

Unread postby ROCKMAN » Wed 04 Jan 2017, 14:49:31

Goner - "...when it takes years to implement changes...". Actually in the case of LNG exports: possibly decades. LNG sales contracts lock in for 20 years often with an addfitional 10 year option tacked on. IOW if US LNG sellers lock in a lot of foreign contract sales in the next few years all that NG will leave the US market place regardless of domestic demand. Even if domestic NG prices triple our consumers wouldn't even be able to outbid those foreign buyers because the contract price is usually benchmarked to Henry Hub prices.

IOW our consumers will be denied access to ever Btu of LNG exports contracted over the next few years for decades into the future. Same situation with long term contracts currently being signed with pipeline exports to Mexico's PEMEX. Consumer aren't complaining today. But wait until 2027 when folks up north can't heat their homes during an Arctic vortex or manufactures have to shut down for while. Which is what happened a couple of decades ago up north. And we don't have to look that far back. From just last summer:

"California regulators and utility executives are staring down a natural-gas shortage in the Los Angeles area that could trigger up to two weeks of electrical blackouts this summer. The state’s electric grid operator warned Friday that it may call for emergency reductions in electricity use on Monday and Tuesday, when a heat wave in Southern California is expected to push up demand for air conditioning. Without conservation, officials fear power plants could run out of fuel and trigger rolling blackouts."
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Re: THE Natural Gas Thread (merged)

Unread postby AdamB » Thu 05 Jan 2017, 15:45:38

ROCKMAN wrote:Goner - "...when it takes years to implement changes...". Actually in the case of LNG exports: possibly decades. LNG sales contracts lock in for 20 years often with an addfitional 10 year option tacked on. IOW if US LNG sellers lock in a lot of foreign contract sales in the next few years all that NG will leave the US market place regardless of domestic demand. Even if domestic NG prices triple our consumers wouldn't even be able to outbid those foreign buyers because the contract price is usually benchmarked to Henry Hub prices.

IOW our consumers will be denied access to ever Btu of LNG exports contracted over the next few years for decades into the future. Same situation with long term contracts currently being signed with pipeline exports to Mexico's PEMEX. Consumer aren't complaining today. But wait until 2027 when folks up north can't heat their homes during an Arctic vortex or manufactures have to shut down for while. Which is what happened a couple of decades ago up north. And we don't have to look that far back. From just last summer:

"California regulators and utility executives are staring down a natural-gas shortage in the Los Angeles area that could trigger up to two weeks of electrical blackouts this summer. The state’s electric grid operator warned Friday that it may call for emergency reductions in electricity use on Monday and Tuesday, when a heat wave in Southern California is expected to push up demand for air conditioning. Without conservation, officials fear power plants could run out of fuel and trigger rolling blackouts."


Natural gas drillers will love this kind of hysteria, real or imagined, the same way drillers lapped up peak oil fears, and are salivating waiting for the next round.

The good news being that during the release of the full AEO2017 today, the EIA Administrator was quite bullish on natural gas supplies in general, and was asked exactly a question about current inventory levels in the NE, apparently there was a large draw recently, and the questioner from some bank/analytic firm was interested in the topic.

Of more interest to me was Adam's mention of the natural gas/oil price dependency, hadn't ever though about that relationship before, but it is quite critical to the functioning of how their projections work.
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Re: THE Natural Gas Thread (merged)

Unread postby GoghGoner » Sun 08 Jan 2017, 08:48:32

Marcellus prices showing a spike. They are now earning about 300% compared to what they were getting at some points last winter. Anadarko has sold out its remaining Marcellus assets to a private energy firm this past month.

Image

Next up for Anadarko, is to sell-out of Eagle Ford. They are taking advantage of the downturn to upgrade into some profitable stuff after finding out that shale gas stuff is uneconomic.

Anadarko “has been among the most aggressive in selling noncore assets, which will likely continue in 2017 as well, with its Eagle Ford assets in the queue,” Mr. Tameron said.
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Re: THE Natural Gas Thread (merged)

Unread postby ROCKMAN » Sun 08 Jan 2017, 11:21:24

Goner - "Next up for Anadarko, is to sell-out of Eagle Ford." Just one more small bit of perhaps the largest US fossil fuel wealth transfer in history. Folks have highlighting the less then impressive economic results when oil/NG prices were high let alone now that they've dropped. The world of production acquisition/divestiture (the Rockman's specialty) can be the polar opposite of exploration/drilling where the upside is hyped. In the a/d world the downside is hyped by the aquisition side which, in a buyers market, has the leverage over the sellers. Buying PROVED PRODUCING oil reserves today for $12 to $18 per bbl and PROVED PRODUCING NG reserves for $1 to $1.40 per MCF carries much less risk the drilling for unproven reserves.

Companies are buying positive cash flow reserves for less then it has cost them for a decade to generate the same by drilling. You won't see it in the MSM but these are truly boom times in the oil patch...for some companies. ExxonMobil will make a profit on oil reserves it buys today even if prices slip to $35/bbl. And if it increases to $65/bbl in a few years? A much better profit margin then it has seen in a long time.
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Re: THE Natural Gas Thread (merged)

Unread postby coffeeguyzz » Sun 08 Jan 2017, 14:19:22

Rock
That is exactly what happened in this case.
Alta, the company George Mitchell backed when it got started, sold a bunch of high priced leases in PA just as the frenzy started. (Alta got in early/cheaper due to foresight and extensive research).
Anadarko bought large and planned on using Japanese JV money for operational expenses.
Now, for a relatively modest sum, Alta owns near 200,000 acres in prime (Lycoming county) real estate along with a few hundred producing wells putting out near half billion cubic feet a day.
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Re: THE Natural Gas Thread (merged)

Unread postby ROCKMAN » Sun 08 Jan 2017, 14:55:01

Expressoman - Same thing with BHP Billiton: paid $12.1 billion for Petrohawk's position in the Eagle Ford and saw its stock steady decline from the day the deal closed. Started taking a major hit BEFORE oil prices dropped. And that $12 billion ain't nothing compared to its almost $100 billion in decreased stock value at one point after the Petrtohawk acquisition. And the Petrohawk guys (now called Halcon...a type of Mexican hawk) may tried to run the same game in the hopefull eastern extention of the EFS but the timing didn't work out:

"The move to restart drilling comes after Halcón emerged from bankruptcy in September. When the company filed, it listed total debts of nearly $3.15 billion and total assets of almost $2.85 billion. The restructuring eliminated approximately $1.8 billion of the company’s debt plus more than $200 million in future annual interest expense."

Halton also sunk a lot of $'s in the so far unimpressive Tuscaloosa Marine Shale before the bottom dropped out.
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Re: THE Natural Gas Thread (merged)

Unread postby coffeeguyzz » Sun 08 Jan 2017, 15:49:12

RM
A somewhat similar story, with some interesting twists, involved Shell losing their ass in the"Shale World" a few years back.
Guy named Terry Pegula - longtime, small operator in Pennsylvania - made a couple of multibillion dollar sales of Marcellus leases he had worked for decades. Almost $5 billion to Shell.
Bought some professional sports teams including Buffalo Bills.
Shell acted like a bull in a China shop and lost a ton ... selling out much of their acquisitions.

But, here is where it gets interesting.
Shell kept a few hundred thousand acres in Tioga county and quietly persevered with a small, entrepreneureally minded team targeting the Utica.
They are successfully developing this area and have leased a lot more acreage.
Pegula? He got back in the game by forming JKLM as a private company, leased a chunk of land next county over - Potter - and drilled a Utica well, the Sweden Valley, that has produced 3 Bcf in less than 10 months online.
This successful areal expansion of the Utica is one of the more unheralded stories in this Shale World today, IMHO.
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Re: THE Natural Gas Thread (merged)

Unread postby ROCKMAN » Sun 08 Jan 2017, 23:22:27

coffeeguy - Yep...Shell wins and loses big. They paid $1 billion for a single EFS lease in far south Texas. Drilled more than 160 wells very fast. Last time I looked initial production for the average well they had completed was less than 85 bopd. I estimated the sunk $2.5 billion and the ran like a scalded dog.
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Re: THE Natural Gas Thread (merged)

Unread postby AdamB » Mon 09 Jan 2017, 19:46:43

coffeeguyzz wrote:This successful areal expansion of the Utica is one of the more unheralded stories in this Shale World today, IMHO.


Shell was discussing their success in the Utica in NE Pennsylvania at the national AAPG conference, in 2015 I believe. They made the statement during their presentation session that the main gas play in the Appalachian basin will, ultimately, not be the Marcellus.

This seemed to be backed up the local experts right about the time Shell was discussing this.

http://wvutoday.wvu.edu/n/2015/07/14/ut ... -wvu-study
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Re: THE Natural Gas Thread (merged)

Unread postby pstarr » Mon 09 Jan 2017, 19:58:50

AdamB wrote:
coffeeguyzz wrote:This successful areal expansion of the Utica is one of the more unheralded stories in this Shale World today, IMHO.


Shell was discussing their success in the Utica in NE Pennsylvania at the national AAPG conference, in 2015 I believe. They made the statement during their presentation session that the main gas play in the Appalachian basin will, ultimately, not be the Marcellus.

This seemed to be backed up the local experts right about the time Shell was discussing this.

http://wvutoday.wvu.edu/n/2015/07/14/ut ... -wvu-study

Did this post subsequently read . . . "A billion here, a billion there, pretty soon, you're talking real money. - Everett Dirksen" . . .

at precisely Mon Jan 09, 2017 4:46 pm?
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Re: THE Natural Gas Thread (merged)

Unread postby coffeeguyzz » Mon 09 Jan 2017, 23:26:32

The past several months have seen numerous Marcellus wells come online flowing 15/20/25 MMcfd for a few months, but nothing can compare with the few successful Deep Utica wells in SWPA.
The casing pressure on some have approached or exceeded 10,000 psi.
Only a few, the Scotts Run being most noteworthy, have maintained long-term (10 month +/-) high flow rate, but the production is extremely high.
The SR flowed 29 MMcfd for 9 months, has cumulative over 11 Bcf in 15 months online, all with a lateral 3,200' long.

This calendar year, both the Deep Utica potential and the Upper Devonian formations will have several wells drilled and should provide more clarity on future prospects.
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Re: THE Natural Gas Thread (merged)

Unread postby AdamB » Wed 11 Jan 2017, 09:59:51

coffeeguyzz wrote:The past several months have seen numerous Marcellus wells come online flowing 15/20/25 MMcfd for a few months, but nothing can compare with the few successful Deep Utica wells in SWPA.
The casing pressure on some have approached or exceeded 10,000 psi.


I know. The BOP pressure ratings look like something you would see in the Gulf, seeing pieces of them being trucked to location is an amazing thing.

But as with all continuous or resource type plays, not all wells are created equal, and what the E&Ps find in SWPA they might not find anywhere else. Then again, an even higher overpressured area might just be 3 counties over.

One of the reasons that the WVU Utica study is just another piece in the puzzle.

coffeeguyzz wrote:Only a few, the Scotts Run being most noteworthy, have maintained long-term (10 month +/-) high flow rate, but the production is extremely high.
The SR flowed 29 MMcfd for 9 months, has cumulative over 11 Bcf in 15 months online, all with a lateral 3,200' long.

This calendar year, both the Deep Utica potential and the Upper Devonian formations will have several wells drilled and should provide more clarity on future prospects.


The economics of the oil and gas fields of America don't run on singular wells, they run on the average, or more specifically the distribution, and which part of it your leasehold allows you access to. The USGS has been quantifying this type of uncertainty for decades now, for example here are their distributions for the continuous plays they have assessed in the US.

https://pubs.usgs.gov/of/2012/1118/OF12-1118.pdf
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Re: THE Natural Gas Thread (merged)

Unread postby GoghGoner » Thu 12 Jan 2017, 06:55:17

The latest numbers from the STEO. EIA was forecasting a 0.7% rise in 2016 at this time last year -- they were only off by 3.1% (that is a bit of sarcasm). Since NG rig count hit a low in August, it makes sense that we should see at least a plateau for the beginning of 2017. New production per rig in the Marcellus and overall rig count will be worth watching. Total gas-directed rig counts were over 900 in 2011 and currently stand at 135. Drilling is more efficient but there is no comparison in the activity levels from 6 years ago.

Dry natural gas production is estimated to have averaged 72.4 billion cubic feet per day (Bcf/d) in 2016, a decline of 1.8 Bcf/d (2.4%) from 2015, which would be the first time annual average natural gas production has fallen since 2005. Forecast dry natural gas production increases by an average of 1.4 Bcf/d in 2017 and by 2.8 Bcf/d in 2018.
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Re: THE Natural Gas Thread (merged)

Unread postby AdamB » Thu 12 Jan 2017, 12:05:06

GoghGoner wrote:The latest numbers from the STEO. EIA was forecasting a 0.7% rise in 2016 at this time last year -- they were only off by 3.1% (that is a bit of sarcasm).


Do you have any examples of folks who do it better? Then we could take those estimates, call up the EIA, and ask them why other folks are doing better? One of the interesting things about the EIA that I discovered a few years back is they are one of, if not the only, organization that provides their forward looking long and short term price paths as well as matching volume projections. As Rockman has pointed out before, you can't do one without the other (as everyone from peak oilers to the IEA have demonstrated beyond a reasonable doubt), and yet these are the only folks I can find who are even attempting to do it right.

And if everyone else is providing these kinds of projections, closer to target than 3.1%, it would be nice to inform the EIA. I would be more than happy to volunteer to do just that, being on a first name basis with a few of their subject matter experts just as I am with the Texas BEG and the USGS.
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Re: THE Natural Gas Thread (merged)

Unread postby GoghGoner » Thu 12 Jan 2017, 12:43:42

Well, I knew they were wrong 12 months ago. They will also be wrong about 2017 and 2018. The thing you can tell them is this --> look at CHK and RRC financials. These two are top producers in the basins they think are going to make up for the other declining basins. Ask them to tell you what they see. I give you a hint it is DEBT, DEBT, DEBT. These companies shouldn't be given another dime and, at some point this year, they may have to file bankruptcy. How do the top producers grow production when restructuring? The scam is up, Adam. Long live coal.
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Re: THE Natural Gas Thread (merged)

Unread postby GoghGoner » Wed 18 Jan 2017, 09:46:05

I haven't posted on the Drilling productivity report in some time because the forecasted numbers never meet actual production numbers. Well, since the EIA is now forecasting a 300 mcf/day gain in natural gas supplies for February in this report, it caught my attention.

Monthly additions from one average rig represent EIA’s estimate of an average rig’s
contribution to production of oil and natural gas from new wells.

http://www.eia.gov/petroleum/drilling/pdf/dpr-full.pdf

The estimation of new well production per rig uses several months of recent historical data on total production from new wells for each field divided by the region's monthly rig count, lagged by two months.


So the calculation for this month, would use "new rig production/rig" based on a lower rig count and lagging the rig count by two months isn't long enough. It is well-documented and logical that as rig count increases "new rig production/rig" decreases. I defer to drillers on how long it takes to get production from a new well, however, I thought the average was closer to six months.
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Re: THE Natural Gas Thread (merged)

Unread postby ROCKMAN » Wed 18 Jan 2017, 10:51:49

Goner - "I defer to drillers on how long it takes to get production from a new well, however, I thought the average was closer to six months." Averages are so difficult to come up with: it implies every well's time lag has been used to come up with a WEIGHTED AVERAGE. I prertty sure no one has out that data base together.

But here's a TYPICAL time line: production casing is run and rig is "released"...drops off rig tally. Now 1 to 3 weeks to move work over rig on to the well. First we run a " bond log" to confirm there's good cement across the pland productive zone. Critical that it's isolated. If a bad cmt then we perforate casing and pump cement into those holes. This can take a day or two. Also understand most of these are "daylight rigs"...they don't run 24hrs/day. Usually doing good to get 10 useful hours in.

Then production tubing" is run down the casing. The tubing is smaller diameter (2 3/8" or 2 7/8") and is what the oil/NG flows up and out of the well. It set with a "packer"...like a stopper in a bottle. And the a perforating gun is run down the tubing on wireline and fires dozens (or hundreds) of small shaped charges that create holes (about 1/3") thru the steel casing.

And now the average concept goes to sh*t. LOL. If a conventional well then once perforated the rig is moved off. By this point you could be 3 to 6 weeks post drill rig gone. Now you test the completed zone. Has gone done in order to design the production infrastructure. Usually less then a week. It might take a couple of weeks to a couple of months to line up equipment. In the meantime will "permatize" the location with more rock base. So now you're 2 to 3 months post end of drilling. For an oil well with no NG sales a couple of weeks to a month to tie in all the plumbing to the well head, tanks and any pumping equipment if needed.

So the quick time line 2 to 4 months. But if the well has to be frac'd...forget that. You might have to wait a month to several months just for the frac crew to show up. And then 2 to 4 weeks to frac depending on the job. It can take a week just to set up the frac plumbing. So a frac'd shale well: 4 to 6 months. And if the well begins producing during the last week of the month the first production report is small. and even the first full month we typically "bring a well on" slowly: maybe another month before max production rate. Now add 2 to 4 months delay before fist production numbers become public.

And if you need a NG sales line add a month...or maybe 3 months...or more.

So add up what scenario you want but the lag time typically is several months as minimum.
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Re: THE Natural Gas Thread (merged)

Unread postby GoghGoner » Wed 18 Jan 2017, 11:12:17

Thanks, Rock. Maybe you should offer consulting services to the EIA and help out all of those economists.
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Re: THE Natural Gas Thread (merged)

Unread postby rockdoc123 » Wed 18 Jan 2017, 12:26:49

So the quick time line 2 to 4 months. But if the well has to be frac'd...forget that. You might have to wait a month to several months just for the frac crew to show up. And then 2 to 4 weeks to frac depending on the job. It can take a week just to set up the frac plumbing. So a frac'd shale well: 4 to 6 months.


and I would add that sometimes it can be longer when a company is looking to streamline operations as a cost savings. Often when fracking companies look to only mob the frac crews when they have a number of wells to stimulate. Also companies are more and more moving to "zipper fracs" which entail alternating frac stages between adjacent horizontal well bores in order to take advantage of in-situ stresses and the inherent stress field created hence creating a larger integrated fracture network. As a consequence a company might drill 6 or more wells before bringing out the frac crews.
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Re: THE Natural Gas Thread (merged)

Unread postby coffeeguyzz » Wed 18 Jan 2017, 13:46:55

Rocdoc/Gone
That is exactly what has been happening in Pennsylvania this past year.
Range, Cabot, Chesapeake are bringing online 3 to 5 wells at a time with results way higher than previous years.
Shoot, one can go right to the PA DEP site for production data, punch in, say, Cabot, and quickly scroll through November's production numbers which are the most recent.
Updated just the other day.
There are scores of wells (500 total) with monthly production over 200/30O MMcf, ie., over 7/10 MMcfd.
The most recent wells (spud date is shown) are exceptionally strong.
For a few bucks a year, the site Marcellusgasdotorg does all the date compiling and much more for a great insight into Appalachian Basin production.
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