Trying to take your posts in order of chronological progression:
1. Then you are able to converse at much more than a layman’s perspective on the subject of oil and gas and reservoir engineering in particular. Good. We share the time frame of experience and, save for drilling and completions, similar background.
2. I don’t understand the scare mongering but it does always attract attention. I am not a regular reader of oilprice.com or the other since it seems to not require any qualification to opine there whether you are a petroleum engineer or some kind of sociology major from Queens, NY. I have supposed that professionals write there trying to provide a little clear light on the subjects. Yes indeed though, the chicken little’s and glass half-empty folks do add realism to the sellers of deals blue sky, roses and lollipops.
3. Gas moves best, condensate second and oil last. Thank goodness shale “oil” tends to be uncooked with the light ends present or it would not flow at all!
4. And we agree that the greatest potential is in gas. Much more mobile under a greater number of circumstances than liquids but we can take the liquids with the gas of course. Do you suggest that the reservoirs are retrograde? ...”the only liquids produced are in the form of gas at reservoir conditions (i.e. -condensates and NGLs)”. I hope they are not and their production characteristic does not suggest that they are to my knowledge. Otherwise we would see massive negative effect of condensate banking and as you know that is only partially recoverable at best. What do you say of the Eagle Ford or the deep Wolfcamp (I never thought I would ever see anyone in the far SW part of the Permian Basin) compared to the Bakken with respect to the liquids?
5. I ran economics on full cycle field developments for several unconventional opportunities and could not make the project, as a whole, fly without constant infusions of cash that was returned with high rates of return but the mass of wells and associated production would never sustain a drilling unit. Meaning that a rig could not drill and complete fast enough to capture the moderate production of its flock of wells so that the production from those wells would sustain the operation. I was running economics based on a flock of analyst presentations and as you know, those are about as good a picture as you can have painted for you. This is not to say though that the tail production is not valuable just that it will not spin up cash flow at a good enough rate to sustain the development activities. With efficiency improvements though it might. I’d like to to a bench marking and goal oriented study to see what it would take to have a self-sustaining development operation. Screwing that together and making it happen would be a lot of fun.
6. “I am not following the arguments you postulate here. perhaps rewording for my benefit?” Nicely put, much better than the usual “are you just stupid?” offered by some on this board.
OPEC, particularly the Saudis, have offered more production than I thought they were capable of and flooded the market on their own
Domestic production should have fallen by some percentage of the expected unconventional new well decline rate of 70% per year or so and in proportion to the number of rigs that have been laid down. For the number of rigs that fell, I thought would have generated declines similar to the projections Berman did where he used a population sample as if drilling had ended and projected that. Recall the case of following a population of Bakken wells from 2010 forward. That production, albiet in the sweet spots, fell like a rock. Even my own basin studies have shown that a huge proportion of the annual production gains have come from new wells. Domestic production has not fallen much at all for a year even though the rig count has dropped like a rock. How has production held up? Are the declines of unconventional not as expected? I am really doubtful of that based on what I hear of declines. It is hard to get good timely data to do a first hand analyssi though as you know. Is drilling truly becoming so efficient that fewer rigs can drill enough wells to sustain the peak? I am also doubtful of this since it usually takes a year for the survivors to pull themselves up and get on with improvements. Is completion efficiency improving that much in compensation? I am also doubtful of this since I know a fellow who is a completion / frac techniques leader and he says that things are not a lot better if at all.
I also expected that even a modest increase in consumption would have offset the glut within a year. Consumption has increased but not as much as I thought it would even though we are seeing record total miles driven figures.
All-in-all, I expected production, particularly domestic production, to decline more than it has, the Saudis to not be able to produce much above 10 mmbopd and for consumption to increase by a modest 1.2% and that the glut would have been harvested by now as decline and consumption increase curves crossed. We were just not that far out of balance until the Saudis started flogging the production rates. I expected the signs of balance would have at least been showing by last fall and that by spring we would be at or near balance. None of these things appear to have happened yet.
Is that adequately reworded?
1. yes
2. yes
3. Yes for the three, although the amount of free gas(as well as overpressure) appears to significantly change the ability of reservoir liquids to be produced. The gas drives a lot of liquids to the wellbore as it expands. A super-duper gas expansion mechanism to make it.
4. most not retrograde but exist as gas in reservoir and are transformed to liquids on way to surface. The Bakken I am very familiar with. It is simply a reservoir unmatched elsewhere due to a. a carbonate having heavy fracturing between the two overlying/underlying shales that are the source beds, of world class quality. b. very high overpressurization due to the hydrocarbon expansions into the carbonate c. relatively light liquids. Nothing like it anywhere else as I see.
5. I agree. the big variable, besides pricing of course, is the variance in capital cost modeling. These have proven to be quite different in the unconventionals. Put that with the dominant ability to improve productivity, any static model can be non-descriptive of eventual reality.
6. will think about it and revert.
And I am not really new here, just a change of alias.
bookmark
“Domestic production has not fallen much at all for a year even though the rig count has dropped like a rock. How has production held up?”
I postulate that the severe initial declines relatively quickly(my assessments in 5 years or less to <10%/yr and in 10 years to <5%/yr). Albeit rates are lower, this is a very shallow decline factor caused by a slow process of leakage from tite matrix rock into fractures and into wellbore.
So earlier wells have shallow declines while newer wells are falling fast.
The one element one might not account from when one looks at drilling rigs only is that that correlation is not necessarily true today in unconventionals. Many wells are drilled but not completed immediately. Indeed today, there are 1400 wells in april already drilled like that in just the Eagleford. http://www.bizjournals.com/sanantonio/blog/eagle-ford-shale-insight/2015/04/ihs-39-companies-sitting-on-1-400-drilled-but-left.html
So when prices rise, will rigs immediately follow? Probably not as fast as one would think as the low-hanging fruit are those wells that need completion.