Posted on 04/13/2015 5:12:21 AM PDT by thackney
There are nearly 1,400 wells in the Eagle Ford Shale that have been drilled but not completed, according to new analysis from the firm IHS.
Oil prices are hovering around $50 per barrel, down by half since last summer. And some Eagle Ford oil producers have been drilling but not fracking wells. The delay in completing wells avoids sending new barrels of oil into a cheap market.
For a small handful of operators, IHS reports that the drilled-but-not-completed wells will give them a big advantage over competitors.
Nearly 40 percent of those 1,400 delayed wells have a break-even costs below $30 per barrel, according to IHS.
The operators include BHP Billiton, Chesapeake, Anadarko Petroleum, EOG Resources, ConocoPhillips and Pioneer Resources. (The remainder of the delayed wells belong to 33 other operators).
“In this low oil-price environment, operators in the Eagle Ford and other U.S. shale plays are focused on optimizing the value of their assets and managing their costs, and these drilled, but uncompleted wells enable them to do that more effectively for several reasons,” said Raoul LeBlanc, senior director of research at IHS Energy, and the lead author of the analysis, in a press release.
“First, the drilling costs of these wells were already incurred by operators prior to 2015, and the completion costs — which comprise the majority of well costs — can be negotiated at a cheaper rate since completion crews are now both available and available at cheaper rates. Second, if completion costs are fairly consistent in the play, then it stands to reason that wells with higher production will yield better returns on capital.”
IHS thinks three companies operating in the northeastern core of the field have the biggest upside from the delayed wells.
The report estimates that BHP, ConocoPhillips and Pioneer Resources have better potential in their delayed wells “than their current producing well portfolios, providing them the greatest available options going forward of any operators in the play.”
Things aren’t quite as rosy to the west, where the delayed wells aren’t expected to be as productive. Those operators “may be challenged during the low-price environment and a few may delay completions until oil prices rebound,” IHS says.
In a year, completions of the so-far delayed wells could add 123,000 barrels of oil equivalent to Eagle Ford production, or as much as 269,000 barrels of oil equivalent, according to IHS.
must be on lands that are already producing, otherwise the pressure to complete in order to preserve the leasehold would be great
I think the change to larger units helped producers hold areas of bigger leases with fewer wells.
Larger units is a ploy that producers use to hold acreage, so it does not benefit the mineral owners.
Prime example here, as the producers petition the RRC to increase size of units while in fact more downspacing occurs.
Although I come from a producer, I really get teed off at this as a royalty owner, and I have fought producers at the RRC on this and won.
Most of the blame here is once again GOVERNMENT.
When yields per barrel are high they raise taxes and levies, fees and permitting processes to the hilt. These fees can be fixed (initially being based on his barrel pricing). Then per barrel price falls, fees remains exorbitant, thus the building halts to avoid losses.
If fees were percentage based much of this wouldn’t happen.
“Most of the blame here is once again GOVERNMENT.
When yields per barrel are high they raise taxes and levies, fees and permitting processes to the hilt. These fees can be fixed (initially being based on his barrel pricing). Then per barrel price falls, fees remains exorbitant, thus the building halts to avoid losses.
If fees were percentage based much of this wouldn’t happen.
“
which post of mine are you responding to?
“Agreed, especially speaking as a Royalty owner that lost this argument. “
The reason they did not win mine as they were messing with a reservoir engineer who knows how to prove drainage areas and liquids composition in situ.
That would have helped, no doubt.
Larger units are necessary because of where the bottom of the hole is in relation to the top of the hole.
Interesting reading on new dynamic at work on the operational costs vs. completion costs.
Low Crude Oil Prices Leave Thousands of US Wells Uncompleted
http://247wallst.com/energy-business/2015/04/12/low-crude-oil-prices-leave-thousands-of-u-s-wells-uncompleted/
April 12, 2015
There are roughly 2,500 to 3,500 drilled but uncompleted oil wells in the United States, according to analysts at IHS Inc. As many as 1,400 of those wells are located in the Eagle Ford shale play in south Texas.
That is sheer baloney.
long lateral wells are being presently drilled on 80 acres or less with close spacing between them.
It is for the operator’s favor, not the mineral owner’s.
Before that there were 10 acre units and on top of domes there was no spacing.
You’re answer proved my point.
You have to increase the acreage for the type of well you’re drilling.
With smaller acreage a lot of wells wouldn’t be drilled because it’s too expensive to drill/complete if someone could drill right next to you. Production would drop so fast you could never get payout.
“Before that there were 10 acre units and on top of domes there was no spacing.”
Wow, you are going back a number of decades if that is your point.
My point is that, although agencies like the RRC allow 1280 acre spacing for wells, the actual drainage areas of those wells is far, far less, perhaps as little as 80 acres.
That is not an advantage for royalty owners, but for operators.
Why? because when the spacing exceeds the actual well drainage area, the operator is allowed to hold more acreage than what he should be holding.
One other remark on this I forgot to include.
When I left the working of Bakken, we were noticing improved recoveries occurring when multiple wells were completed simultaneously. These are called zipper fracs or simulfracs.
Reason is that there was no disturbance of differing pressures in the formations, hence the fracs that propogated were more regular, i.e. - they did not ‘beeline’ to the weakest point which is typically lesser pressures.
We did this for 12 well units on 1280 acre spacing.
Could be operators are taking this to another high level.
Interesting. How many wells would be frac'd at the same time?
there are several different ways to do this. With a single frac crew, two wells are ‘zippered’ which means that each alternates a frac stage until completed. Or a well is stage fracced completely, then the next well is immediately done.
Another way is with multiple frac crews(read more expensive and choreographed), where two or more wells can be fracced simultaneously.
The whole idea is to save $ by not having to mob/demob the frac crews and to maximize frac complexity along the wellbores.(more value at less cost) The fact that most horizontals are on multipads begs it to be done this way.
Thanks
Disclaimer: Opinions posted on Free Republic are those of the individual posters and do not necessarily represent the opinion of Free Republic or its management. All materials posted herein are protected by copyright law and the exemption for fair use of copyrighted works.