[rockdoc123]

I know rockdof, those doomer metrics don't count, not when you have some good old EBITDA valuation to prop up the equity

if you don't have something intelligent to add I suggest you just keep your unrelated sarcasim to yourself...your comment is unrelated entirely to the points I made, which are factual and based on experience.

[rockdoc123]

Your experience. Not Steve St. Angelo's experience. Not Rune Likvern, Nick Cunningham, David Hughes et al. Get a blog.

none of which have ever worked directly in the industry, none of which have ever had access to the actual data, none of which who actually understand how unconventional reservoirs perform. Pretty easy to stand back and make statements based on never, ever having been actually close to the sand face.

[coffeeguyzz]

Rocdoc

Surprised you engage with old pisstar here, especially when he references that Steve guy.
Of all the massively wrong "prognosticators/analysts" out there, this Steve takes the cake.
And being worse than Hughes is saying a lot.

No need to take my word, just read back the last few years "analysis" compared to reality and see fo yo self.

Biggest reason for huge spike in produced water is the choking back on production first several months, including what used to be copiously produced/categorized as flowback

Again, don't take my word, just pull up Bruce Oksol's milliondollarway blogspot for today and check out the handful of spectacular MRO wells that have been online about 4 months.
Produced water ranges from 150 to 200 thousand barrels or so.
This is 10 times higher than the historical norm.

Reason?

They are KEEPING FRAC FLUID IN GROUND WHILE NOW PRODUCING!
Apparently the elevated, induced pressure is hugely boosting production.
These wells are now producing 100 to 150 thousand barrels oil first few months.

The historical produced water has not changed at all.

[coffeeguyzz]

The wells on Oksol's site are from WPX, not MRO.
One well had 220,000 barrels water first 4 months as 'produced'.

This is NOT the historical produced water. It is the bulk of injected (frac) water now coming out with the hydrocarbons.

One well produced 172,000 barrels oil first 4 months.

[rockdoc123]

coffeeguyz....I did mention the effect you point to that re-frack fluid can come back over time for various reasons. But as you point out sometimes they manage it. Looking at water production without understanding it (as pstarr seems apt to do) is folly.

As to pstarrs comments

He discerns the difference, I discern the difference, even your frosh students (perhaps) understand and discern the difference. 

Exactly how do you discern the difference? Nowhere in his article does he actually tell us how he is figuring out what is re-frack and what is reservoir fluid. In many cases the two are completely indiscernible. And I seriously doubt you even understand the difference let alone how to tell them apart.

DeAngolo said nothing regarding peak oil. Or peak bakken. The post is all about the increasing cost, failed business model that all US fracting reflects and the stupidity if it posters and investors. All money losing.

Lets add illiteracy to stupidity on your less than shiny resume. Here is quote from the article

Furthermore, the rapid increase in the amount of water to oil from a well or field suggests that peak production is at hand

Peak production is Peak Oil, same thing as it applies to a single field or a group of fields.

Oh crap. What nonsense. Of course late stage or EOR methods scrubs a reservoir clean and the end game is a rapid decline. You need to teach your frosh students basic before they fly with the shale playa's

What a moronic statement. Firstly it has absolutely nothing to do with the quote from the article nor my statement as to why that articles observation is incorrect. Please tell us how the statement I made

The initial rate is higher which means the economics of the well are better (time value of money) and associated with higher rates are higher EUR which also improves the per unit economics.

Is incorrect. If you can’t do that then save us all the grief from having to read your mindless blather.

Hello so-called 'closed system' ain't so closed. Additional handling, additional diesel and materials create additional costs. Teacher . . . your student have left the class for more interesting climes.

Do you even understand what a closed system is? It doesn’t require additional handling, it doesn’t require additional diesel or additional materials.

And as to your latest stupidity

Rapidly increasing GOR in the Bakken probably indicates partial reservoir depletion and subsequently decreasing GOR suggests more advanced depletion accompanied by declining reservoir pressure, declining oil production and increasing water cut (Figure 6).

The operative word here is increasing GOR could signal partial reservoir depletion....not probably

Please stop posting pictures from articles where you actually haven't a clue about the science behind any of it. You should be embarassed.

The apparent permeability of gas is always higher than the apparent permeability of oil. It is very easy to cone gas into a well bore either from a free gas cap or along fractures which penetrate a different reservoir. At surface all you see is increasing GOR whereas in the subsurface the oil column is not depleted, it is being by-passed.

And the diagram you posted is only applicable with reservoirs that have pressure dropped below bubble point. This means gas depletion drive where there is no outside pressure support. In water drive support reservoirs the produced pressure can remain above bubble point meaning gas doesn't come out of solution until it is near surface.

[ROCKMAN]

pstarr – "Exactly how do you discern the difference?” Don’t have time to go through his work. But this is how it’s normally done. First, if there is a significantly difference between the reservoir salinity and the frac fluid salinity a simple ratio analysis of the produce fluid will answer the question. Likewise typically there are chemicals in the frac fluid not found in the reservoir fluid. Again a simple ration analysis gets the job done. Or we can add a simple and cheap chemical marker to the working fluid. I’ve done that on many jobs.

[ROCKMAN]

pstarr - How is an increasing water cut a "failed economic model?. As I just explained from trend development standpoint it's fully anticipated. Likewise with an individual well it has been a part of every economic analysis I've seen for 42 yeas.

[rockdoc123]

First, if there is a significantly difference between the reservoir salinity and the frac fluid salinity a simple ratio analysis of the produce fluid will answer the question. Likewise typically there are chemicals in the frac fluid not found in the reservoir fluid. Again a simple ration analysis gets the job done. Or we can add a simple and cheap chemical marker to the working fluid. I’ve done that on many jobs.

the problem with the article is it doesn't say how they have differentiated the two, yes it can be done but given he is describing not one small area but the entire extensive area covered by the formation no one method would likely be possible . And in many slickwater fracks the only additive is friction reducer (essentially soap suds). When the frack fluid mixes with reservoir fluid the two become indistinguishable. As to salinity differences most of the fracks I've been involved with over the years bent over backwards to make sure the frack fluid was fully compatible with reservoir fluid in order to avoid shocking the reservoir and the potential formation of emulsions. I've seen tracer isotopes used in water floods or full immiscible floods but never in a frack job. So, yes you could tell the difference but I doubt the author has the information necessary to do that.

and the answer to pstarr's blathering about extra costs for disposal of water is simply closed sytem fracking, something that has become quite common.