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Thanks for the link.

Let’s talk about the claim journalists CHRISS W. STREET made.

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Temporarily closing down production at a vertical oil well usually results in substantial “stoppage of the pores of the oil-bearing rock.” This reduces “bottomhole pressure” that force oil up through the well tube to the surface and limits the future production capability of the well. But since U.S. horizontal drilling injects water and solvents to free oil from shale and creates its own pressure to push oil up through a cement-lined casing to the surface, shale oil wells can be closed and reopened with virtually no future production capability lost.

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Chriss is confused. He first describes hydraulic fracturing that occurs before the well goes into production. That is the “injects water and solvents to free oil from shale”. This is done to create pathways for the oil/gas to flow out of the formation. It creates cracks and uses sand or other proppant to hold the cracks open.

Next “creates its own pressure to push oil up through a cement-lined casing to the surface” - False.

It does nothing to create or hold pressure. The fluid is pumped out prior to the well starting production. The extra pressure used to create the cracks is gone before production starts.

He doesn’t know what he is talking about. I’ll take the words of the Petroleum Engineering/Geologist over the journalist who read a few words about the industry but has no understanding of what is done.

I read that part. Now, I'd like to know just what makes the writer think that a few extra fractures makes the vast bulk of the reservoir immune to ordinary reservoir dynamics.

I want to see the case studies and data to back what I am 99.99% sure is a ridiculous supposition.

You still have the same pore throats, the same bubble points, the same (if not more) moveable solids which can adversely affect production in any reservoir, and these are tight reservoirs with low inherent permeability to begin with--otherwise, they'd have been the target of widespread vertical exploration and development instead of hit-and miss wells which depended on natural fracture systems induced by tectonics (Nesson Anticline (south end), on the Billings Nose, and in the Sanish Play around Newtown, which produces from a sand developed at the base of the Bakken known as the Sanish Sand.)

Even the early Bakken Horizontal wells seldom paid out because the target was the shale, and not the more conventional tight dolomite, sand, fragmental limestone and siltstone mix found in the Middle Bakken.

Aside from the means of exploration (horizontal drilling) and the fact that the distribution of oil and gas is nearly universal where thermal maturity has been achieved, the Bakken is a classic tight reservoir--as is the Three Forks, sourced by the Upper and Lower Bakken Shales. (We have known there is oil in there for as long as I have been involved in Williston Basin Geology, well over three decades. Getting it out has been the problem.)

As a tight reservoir, the rock itself (keep in mind that the size of a lease is two square miles in most cases) has fractures (permeability pathways) induced after drilling a six inch diameter hole, by hydraulic fracturing, which allow a much greater surface area of exposure to the lower pressures which allow the oil and gas to flow from the rock. Those pressures decline after the frac, as does production. While those fractures are a vast improvement over the inherent permeability of the formation, they will follow the paths of least resistance in the rock, and as such are not universally distributed, despite using multistage fracs to improve the distribution. The intervening rock is still the same tight reservoir.

If you pull a well off line when the pressure difference is greatest, immediately after the frac, that is also when the production is higher. The well won't reach payout sitting idle, and if the oil can be sold to recoup the investment, this is the time when the well will produce best.

Otherwise, to cut expenses, wells which have been through the initial phase of the decline curve (about 80% in roughly two years) will be the most expensive to operate on a day-to-day basis in terms of production yielded, and closer to payout if not past payout on the initial investment. While they are more expensive to operate in terms of returns, the difference is profit.

Would you shut those in?

Economically, no, and those are also the wells which have reached lower pressures by virtue of production and with that lower differential across the pore throats, are most susceptible to formation damage.

Would you shut in new wells?

How are you going to recoup the investment, although those wells are likely less susceptible to developing formation problems that won't clear up on re-start if they are past flowback.

Or do you leave drilled but not yet fracced wells to sit idle or produce at reduced rates because they have not been fracced, letting the rest of your production cover expenses and pay for those wells without optimally recouping your investment in the current market?

From a reservoir standpoint, better not to shut in the well at all, if you don't have to.

From an economic standpoint, it depends on the extent of your producing reserves and the fiscal health of your company whether you can afford to risk future production to mitigate what may be less than optimal prices.

Then there is the option of selling off paid-off production (past the initial decline curve) to sustain the rest of the operation, but you would do so at fire-sale prices.

I'm not an economist, though, I'm a geologist. I suspect the writer's credentials are closer to the former than the latter.