Technical Expert Discussion on US Shale Shut-Ins

Hi y’all,

The Society of Petroleum Engineers published an article in this month’s (June 2020) Journal of Petroleum Technology outlining the thought process many operators are using for which wells to shut in and which ones to keep online or prioritize to bring back online.

I know many of y’all have been interested in this so I wanted to summarize:

  • Generally good wells to shut in:
    • “Good producing” wells (poor producers may not come back online at all. “Good wells are good wells”)
    • Mid-life rod pump wells (low cost and low risk)
    • Wolfcamp Shale wells (higher pressure; tested by Pioneer Natural Resources with downhole sensors providing high-quality data)
    • Dry gas wells (most likely to come back online at higher rates even)
  • Generally poor wells to shut in:
    • High-water-cut wells (corrosion issues, hard to restart, BUT can save disposal costs)
    • New wells brought online quickly (shutting in could cause too much stress cycling on proppant. “slow-back” vs “fast-back” initial flowback choke rates)
    • Wells with electronic submersible pumps (ESPs) (“very finicky” and likely to get damaged)
  • Up for debate:
    • Newest flowing wells (perceived risk to reservoir is high because of above risk to proppant pack, but also likely to return to a good rate because of pressure support. Also best bang for your buck)
    • End-of-life/marginal/”stripper” wells (wells producing less than 6 bbls/day are the obvious wells to target to shut-in because they bring the least amount of cash in, but cumulatively don’t add up to much curtailment and could mean the end of the well due to low pressure support)

Yes, that was a great article. Great summary. As demand increases, supply is used up and prices rise, we will see more wells getting turned back on. Another point to add to the above discussion is the legal lease language. Some wells have to stay on (although perhaps at low rates) in order not to lose the leases. Another possibility is that multiple horizontal wells on the same leasing acreage may have most of the wells shut in, but keep one on to maintain the lease. Operators have quite a few parameters to consider.

Mineral owners need to keep their run statements that come with their checks or get them from the online portals. Keep a list of your wells and watch which ones are shut in. For example, compare your February checks which would have Dec-Jan production with your June-July checks which would have April-May production (or lack thereof), etc. You need to be aware of your lease language and what triggers a shut in payment. In many cases, the mineral owner has to request the payment as they do not automatically happen without nudging.

I suggest that folks set online news alerts for their particular operators to see what they are saying in their quarterly reports, interviews, news stories, etc. Each company is unique and will make decisions based upon their own particular circumstances. Know your state’s online free resources for watching production.


Agreed. So far from what I’ve been reading/tracking, North Dakota is seeing a 7% increase in production this week vs last week, so if ND is seeing it, you can bet OK and TX are as well (but the data is just not a publicly available as quickly as ND).

Parlsey and EOG have shown signs they’ll be bringing wells back online earlier than most. ConocoPhillips looks like they might be in the opposite camp, but I’m sure near-$40 oil might change their mind (though not sure if $40 oil will be a sustainable thing anyway once operators start bringing on wells)

Continuing this discussion, as sourced from the Society of Petroleum Engineer’s Technical Journal:


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