Both wells have casing cemented in place, both wells have some pressure differential, and after the flowback period of relatively high production after a frac or IP in an overpressured reservoir, the lithostatic pressure exerted on the fluids in the pore spaces is the same as any similar rock at the same depth, the fluid dynamics subject to the same influences, and the reservoir rock subject to the same sorts of degradations associated with shutting a vertical well in.
The only differences are that the horizontal wellbore has much more exposure to the pay, and that the rock has fractures induced by the frac job--which may be present in a vertical well also.
Those fractures do not pulverize the rock, they open permeability corridors through which oil can flow after it comes out of the pores into the fractures. While certainly more efficient, it is not a vaccination against bubble points, moveable solids, or other pore blockages, which will severely impair future production when the attempt is made to put the well back on line.
The only way to get that well back anywhere close to IP, or even the former production is to re-frac the well, and that presents certain mechanical difficulties if the liner was perforated as the frac stages were run. The inside of that production liner is no longer smooth, and setting packers to isolate portions of the wellbore for a multistage re-frac would be incredibly difficult, if you could even get the frac string to bottom.
That means the new frac would have to be less efficient because there would be less control over what part of the wellbore was fracced.
All of that is expensive--getting up there with drilling costs.
Of the 8-10 million dollars spent on drilling and bringing a Bakken well on line, only about 4 million are spent drilling and casing the hole. The rest goes to leases, permits, and production costs, chief among which is the frac.
Right now, the last wells I'd shut in would be the ones with the highest differential pressure (still in the steep part of the depletion curve).
The oil coming out of those wells is likely being delivered to fulfill contracts at a higher price than current spot (with the market in decline), and since those may be producing at 4-5 times the rate of more mature wells (say, 2-3 years old), you'd want to keep them online.
The problem is that the wells which have reached a nearly level depletion curve are the ones which would be most susceptible to formation damage from being shut in because the differential pressure is less than with virgin reservoir. To renew that production would require production work on more wells for the same amount of production off line, and due to the nature of production being high at first and tapering off steeply to 25-30% of IP, they are more likely to have reached payout.
You'd be taking a chance on screwing them up when they are at the point in their life where the production is profit.
Now that may work differently in different basins and rock types, I have only worked wells in the Williston Basin and the Rockies for 35 years and may not have encountered those situations, which is why I asked.
You guys are making a brave effort to educate but I’m afraid you will not often meet success. The only way to get 30 or 40 years of understanding and experience is a similar amount of time doing the thing.
15 years ago I wrote a report predicting oil price events of higher frequency and amplitude. So far I’ve been right. We’ll see about this one in about 8 months. By then there will be a lot of blood in the streets and a lot of opportunity.
The last two crashes were on bottom for about 4 months if remember it right. The common string of shale wells old and new combined declines 50% in 11 to 18 months. Without a high short term price shale does not make sense. The production is squandered for low gain. V