[wildbourgman]

If you want to know how much fracking was going on during that period just look at the rig counts during that same time in shale areas. In the big picture fracking should directly correlate with shale drilling because shale wells that are drilled must be fracked.

[copious.abundance]

$this->bbcode_second_pass_quote('', 'R')OCKMAN do you happen to know how much fracking was going on in 2009 when prices were low compared to 2011-2014?

[ROCKMAN]

T - According to Drilling Info there were 18 Eagle Ford leases that began production during 2009 from what appears to be 36 wells. The average initial production from each LEASE was 229 bopd. Remember Texas doesn't require per well production but by all the wells on the same lease. Not a very impressive start to the EFS.

And the rest of the story. Notice how the initial production rates have improved: longer laterals and a lot more frac stages. Which also means significantly higher total well costs. Also notice how more lease were drilled on '13 then '12 but fewer wells were drilled in '13.

During 2010: 217 LEASES began producing from 557 EFS wells. The average initial production from each LEASE was 330 bopd.

During 2011: 722 LEASES began producing from 1790 EFS wells. The average initial production from each LEASE was 430 bopd.

During 2012: 1319 LEASES began producing from 2458 EFS wells. The average initial production from each LEASE was 454 bopd.

During 2013: 1569 LEASES began producing from 2283 EFS wells. The average initial production from each LEASE was 580 bopd.

During 2014 thru August: 885 LEASES began producing from 1084 EFS wells. The average initial production from each LEASE was 675 bopd.

[Tanada]

I found this graph, it is just for Montana and ND but I presume it is fairly indicative of all three major plays.



It looks like ND dropped to a low of around 30 working rigs in mid 2009, then climbed fairly quickly to 200 rigs in mid 2011 and has stayed between 180-200 since mid 2011. So if we see a fall much below say 150 rigs in ND that would be a significant change.

The Baker-Hughes data for December 29 says ND had 169 active rigs working that week. A few weeks from now we will know a lot more, its just a matter of patient observation.
http://phx.corporate-ir.net/External.Fi ... U9MQ==&t=1

[ROCKMAN]

Now mentally transpose these Eagle Ford Shale numbers on Goner's chart:

2010: 217 leases/ 557 wells. Averaging initially 330 bopd per lease.
2011: 722 leases/1790 wells. Averaging initially 430 bopd per lease
2012: 1319 leases/2458 wells. Averaging initially 454 bopd per lease
2013: 1569 lease/2283 wells. Averaging initially 580 bopd per lease
2014 thru August: 885 leases/1084 wells. Averaging initially 675 bopd per lease.

Now consider this: losing X wells in 2011 would mean the loss of leases that averaged 430 bopd initially. Now lose that same number of rigs in 2015: a loss of leases initially averaging 675 bopd. So the good news: wells are initially producing more oil now then ever before. The bad news: cancelled wells due to low oil prices will reduce a number of leases that produce more oil then they would have a few years ago.

[Pops]

One reason I think the plateau in either price or production may not be so smooth is exactly those fracked wells.

A typical old conventional well had a long startup and a long life, fracked wells with short spacing over the sweet spots have a short startup and a short life, comparatively. So the old fashion wells, once flowing, would produce for long periods without additional investment, just sit back and watch the money roll in. This made supply more stable.

LTO wells on the other hand flow smaller and deplete faster and must be replaced constantly. Each new well requires a new calculation of profitability, if the price o oil is too low, and seen to be below breakeven for some time the decision might be made to delay development. This makes supply more volitile and responsive to price, especially considering US LTO is the greatest percentage of increasing supply globally.

[rockdoc123]

The shale wells do have a high decline rate over the first couple of years but after that production is relatively flat and predicted to go on for a long time, just at a low level. This is partly why so many wells are drilled. In comparison a well drilled in Leduc back in the sixties might have had production of a couple of thousand bbls/d declining at 10%/annum until it was producing at a couple of hundred bbls/d. For many shale plays you would need twenty wells to equal that production, but it is flat and predictable and should not require a lot of additional work if the completions are done correctly.

[Pops]

Roc, at what percentage do you see them flatlining?
25% of initial flow? 10%?

[ROCKMAN]

Pops – 25%? Not even close with respect to the Eagle Ford. A sample: In 2010 there were 538 EFS wells completed. As of Sept 2014: 114 of those wells are no longer producing. That’s 21% of wells completed less than 4 years ago are producing ZERO bopd today. The well with the best initial production rate of any completed in 2019 was the Geosouthern #1H Hyatt A. It initially tested 1546 bopd and 5 mmcf of NG. It produced 310,065 bo and 1.02 bcf before it stopped producing in Sept 2011. The best LEASE that began producing in 2010 that is still producing today is the EOG Cusack lease in Gonzales Country. From ten wells it had a MAX RATE OF 1,474 BOPD. The lease has produced 1.22 million bo from 10 wells. Currently producing 1,283 bopd from 10 wells. But that’s very misleading:

There’s a problem with looking at lease production…remember Texas doesn’t report by well but by the lease. So the first well on a lease might have been completed in 2011 but if another well was completed in Sept 2014 those numbers will be added to the lease number. Thus the production rate from a lease could increase over time as new wells are added as older wells deplete. The best single well completed in 2010 that is still producing is the Burlington #1 Eskew that came on at 1,185 bopd, has produced 307,630 bo and is currently doing 68 bopd. IOW it has declined to 6% of its initial production rate.

Understand that I cherry picked the better wells. At the other end of the spectrum: Rosetta Resources #95 Gates in Webb County is still producing today: initial rate 94 bopd. Produced 66k bo and is currently doing 22 bopd.

I know we would all like to use generalities to characterize these plays. But it just doesn’t work. There is no “typical” initial production rate for Eagle Ford wells. Nor is there a “typical’ decline rate or a “typical” leveling off rate. Of course, with thousand hours of tedious work one could come up with the stats along with standard deviations and really cool histograms, etc.

So have at it, amigos. LOL.

[sparky]

.
thanks for the info Rockman , I've always had some misgiving about fracking as a cornucopia
still
due to the extremely friendly geo-location , fracking for tight oil can be turned down or turned up in a matter of months
to some extend and disregarding the pain for the rig workers , its a swing production
....first up ....first down , then first up
I could be very very wrong but I don't believe this move will last much more than a couple of years
really , nobody can afford it

[ROCKMAN]

sparky – There will be several factors, beyond the price of oil, that will impact future EFS drilling plans. First, leases expire eventually. Even when wells are producing on a lease they are assigned a certain amount of acreage with the balance outside those units subject to expiring when the primary term is reached. So the decision tree begins: acreage expiring: 1) drop because potential at current price is much to low; 2) if value is marginal drill a breakeven well to hold the lease; 3) good enough opportunity at current price so drill.

But not that simple: company has several rigs on long term contract. Can drop and pay $X million in cancellation penalties. But might be better to drill marginal/submarginal leases and use the cancelation penalty savings as an off book value for those wells. Remember Devon paid $40 million in penalties cancelling contracts on 14 rigs in the Haynesville Shale back in ’08. So another branch in the decision tree: drop rigs and pay penalty or drill marginal wells hoping price will come back up soon. But if prices don’t recover sufficiently they may still have to drop the rigs and pay penalties.

Next hurdle: drilling capex. Does a company have sufficient cash flow to keep drilling? Or does it have a sufficient credit line to keep drilling? But even if there’s an inventory of somewhat viable wells left to drill would the company wait (assuming it can hold those leases for a period of time) so they can satisfy dividend expectations? Which brings us to THE big question: what does management need to do to first, protect their self-interest and, second, satisfy the demands of the major shareholders? The net answer might be to preserve capital or, conversely, keep drilling so reserves can continue to added which MIGHT give the appearance of a company that will do OK during a low price period. And then there will be companies that have nothing viable to drill, insufficient cash flow to pay for drilling but have sufficient credit to drill their crap wells in hopes of boosting stock vale for a while so management and major shareholders can bail before they go belly up and either file bankruptcy or are acquired by another company.

And for the healthier companies this period might also represent a buying opportunity. Company A has some good acreage positions at $60/bbl but either doesn’t have the capex to drill or management/shareholders decide to preserve capital. So Company B subleases Company A acreage and drills. Great deal for Company A if they have drill rigs under long term contracts but most of their remaining locations are submarginal.

I can paint several more viable pictures (including the hedging dynamic) of what will happen going forward but I’m sure you see the complexity of the dynamic. As you know this ain’t my rodeo. Every possibility I mentioned above I’ve dealt with first hand in the last 40 years. And a lot of other equally distasteful/disastrous situations. If prices stay low for the next 12 to 18 months (as I suspect they will) we’re going to see a variety of “interesting” situations develop. Many will remind you of the movie “Gladiator”. LOL

[Subjectivist]

The following 'Wisdom' is currently up on the CNBC web site.

$this->bbcode_second_pass_quote('', 'B')enchmark Brent crude was last down $1.86 at $51.25 a barrel, after falling to $50.96, its lowest since May 2009. U.S. crude was down $2.16 at $47.88 after plumbing an April 2009 low at $47.74.

"I think the likelihood of seeing $46 to $45 is quite likely,'' Phillip Streible, senior market strategist at RJO Futures in Chicago, said. "People, I think, are further understanding that the U.S. is becoming a powerhouse in creating crude oil and that's not going to change anytime soon.''