ROCKMAN wrote:Notice that after the tremendous improvement in drilling efficiency including cutting down drilling time and rig movement time the costs have been reduced to $6 to $12 million per well. And bear in mind that there is no such thing as an “average EFS well cost”. The reason for that wide range is that some wells can only be drilled with shorter laterals to comply with the regs. Shorter laterals also mean fewer frac stages. Shorter laterals with fewer stages typically mean a less productive well. Which also implies that there is no “average productivity” of an EFS well. A company can post their average cost to drill and complete a well but that number is meaningless unless you have the specifics of how those wells were drilled. And the companies never release that data. ....
ROCKMAN wrote:DC – “So there does not need to be any change, just more of the same.”. Something of a contradiction IMHO. More of the same means some big changes: more capex spent, more rigs running, more hands hired, more service companies working, etc. That was the reason for the increased drilling activity. I would take more of the same to mean holding activity flat. To reach the rig count being projected would require a lot of change.
The number of rigs running had been increasing significantly a year ago. But this isn’t a year ago today. The rig count has been flat to down a bit at time this year. And it shows in the drop in Bakken oil production we’ve seen this year (http://bakkenshale.com/drilling-rig-count/). The improvement in efficiency has helped but those factors have already kicked in so where would the additional gains be seen? Based on current stats there no reason to believe there will be any significant increase in rig count, number of wells drilled or production added. In fact, even a small increase seems possible.
But, as you say, there are multiple factors that create the end results. And it’s just as easy to slap positive or negative expectations. But in another few months well have the full 2013 stats to look at to give a better view of the current dynamics. But even with those numbers it doesn’t forecast activity in 2014+ in stone.
Pops wrote:The Director's Cut says the backlog is in completions, 90 days waiting list in May and 500 wells on the list.
Yes it could be the weather in whole or part.
ROCKMAN wrote:sparky – I’m not sure I understand your question about 90% vs. 10%. But as far as the meaning of #5: the payout of the well is typically the time it takes to recover 100% of the drilling/completion costs less the royalty, production taxes and operating expenses of a well. A 3 yr p/o isn’t bad but doesn’t represent an outstanding rate of return. Typically we’re always hoping for a p/o on the order of 12 months. Obviously our hopes aren’t always met. LOL.
dcoyne78 wrote:Weather has played some part, but there seems to be a lack of fracking ability (that is not enough crews/equipment) so the impression that things are going flat out (by those in the know) seems correct.
At some point the bottle necks may work themselves out, but this points to increased well completion costs (in order to attract more crews and equipment) rather than the reverse.
It could work out that these two forces (there's that dynamics again) balance (increased operations efficiency vs increased costs to attract fracking services) and completion costs may stay flat. As Rockman likes to remind us it's complex.
DC
Great weather for drilling and hydraulic fracturing activity resulted in a 1.4% production
increase from June to July. That is the smallest month to month percentage increase since
April 2011. The combined effect of several factors has led to a noticeable slowing of
activity and production growth. Rig count has decreased significantly to around 190-195
as operators transition to higher efficiency rigs and implement cost cutting measures.
The idle well count increased significantly indicating an estimated 394 wells waiting on
fracturing services. Rapidly escalating costs have consumed capital spending budgets
faster than many companies anticipated and uncertainty surrounding future federal
policies on hydraulic fracturing is impacting capital investment decisions.
DC – yep…not an uncommon practice for public companies to report just what the actually drilling/completion costs were and leave out the other expenses.
A 5 year payout is nothing to brag about.
Pops wrote:Thanks DC I was being facetious, mention of Leo M. puts me in a tizzy, I appoligize.
I'm just wondering how realistic is it to think new wells per yr will double from 1,700 to 3,600 per yr in just 4 years? Is that just continuously improving technique, more rigs or something else?
I'm sure you've noticed that increase in well numbers has been slowing for the last year - at least through may annualized growth has declined from 52%/a to 36%/a
Of course then production growth has fallen too from 66% to 26%
as we speak horizontal rigs going for oil are down 11% from last year
http://www.reuters.com/article/2013/07/ ... 6220130726
Obviously just a snapshot but thought I'd throw it out, whatdda ya thinK?
Pops wrote:That's great DC, very cool.
So between this and the first you posted we get a possible range. Interestingly they both peak in the late oughts.
TheServant wrote: For the sake of argument, what if it climbs to somewhere closer to 9000/yr?
Oily Stuff wrote:Mr. Dcoyne, thank you for your good work in the Bakken. I always find it interesting and I hope soon that you can begin similar work in the Eagle Ford shale here in S. Texas where I do not believe the wells are near as good as Bakken wells.
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