Posted on 04/20/2015 5:21:24 AM PDT by thackney
Oil producer EOG Resources Inc has the lion’s share of an estimated 900 North Dakota wells waiting to be fracked, according to state data, showing that even major oil titans are mothballing operations while they hope for a rebound in oil prices.
For months the conventional wisdom in North Dakota’s Bakken shale formation had been that smaller producers with weak cash flow comprised the bulk of that estimate.
While the estimate had been published monthly, it was not clear until a Tuesday update from the state’s Department of Mineral Resources (DMR) who was dominating the list. Oilfield service companies have aggressively sought the information, hoping to drum up new business.
By late May, the number of wells waiting to be fracked is expected to breach 1,000, DMR officials said, fueled largely by cheap oil and a $5.3 billion industry tax break expected to hit in June.
Oil producers have up to a year to frack the wells before they must ask state officials to label them “temporarily abandoned.”
The fact that industry stalwarts like EOG are having to hold off on fracking new wells shows how much low prices make the remote Bakken far less economical compared to other U.S. shale plays.
Prices to transport oil from North Dakota to the U.S. Gulf Coast or coastal refineries add in some cases nearly $10 per barrel to the cost of crude, a steep price not faced for transport from Texas wells, which also are connected to a much-larger pipeline network.
One of the most-respected U.S. shale oil producers, Houston-based EOG said in February that it would pare back North Dakota production this year and focus more on Texas, also partly born from efforts to force oilfield service companies to cut their own costs. Indeed, EOG has kept three North Dakota drilling rigs operating since January, though it has not fracked any of the wells that it has drilled. Most of the uncompleted wells are in the Bakken’s Parshall Field. “These are tremendously productive wells,” said the DMR’s Lynn Helms. EOG is “able to drill a lot of wells and maintain production and still bank a lot of wells for future price increases.”
At the same time, EOG plans to make the Eagle Ford and Permian shale fields in Texas a core focus this year, aiming to increase the number of Permian wells this year by 53 percent.
EOG declined to comment beyond the information provided by Lynn Helms.
As said before, there are valid reasons to delay completions(but not normally this quantity).
1. Awaiting reductions in vendors cost to complete
2. achieving efficiency in capital and created frac geometry by fraccing multiple wells simultaneously or back to back from same pad
3. delay in paying ad valorem taxes due to no reserves until completion occurs.
4. delay in hitting earnings with capital as it is held in suspension until oil begins flowing following completion
EOG is a leader in efficiency.
It will take them the rest of the year to complete these.
I have been wondering about the impact of all these wells delayed completion.
When the price of oil does climb, it will allow more oil to come onto the market sooner, than needing to start drilling first.
On the completion price, while rates may drop down now. It seems to me any jump in oil price is quickly going to leave us short on hydro frac equipment and crews and send that service price soaring even higher than before.
I understand the same delay of completion is becoming common in the Eagle Ford as well.
Sounds like the
R.O.I. of
E.R.M. for
E.O.G. in
N.D. is rather
H.U.G.E.?
“Fun with industry acronyms...”
What is the talk in the industry as to increasing drilling now that it appears that the price of crude has rebounded from its lows in the $42 range?
Number of active drilling rigs continue to fall.
http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-rigcountsoverview
oil producers have stashed crude in about 4,000 drilled but uncompleted wells...
Halliburton exec says U.S. will provide biggest upside in recovery
http://fuelfix.com/blog/2015/04/20/halliburton-posts-643-million-loss-on-oil-slump/
The president of Halliburton says even though his firm’s North American margins are being squeezed by the oil slump today, the region will likely return faster than any other when crude prices rise again.
“One way to look at it is the U.S. unconventional business is now the lowest-cost, fastest-to-market incremental barrel of oil available in the world today,” said Jeff Miller, president of Halliburton, in a quarterly conference call with investors Monday.
He said oil producers have stashed crude in about 4,000 drilled but uncompleted wells, and once prices go back up, there could be a surge of completion work for oil field service companies like Halliburton. He said producers haven’t shared when they might unleash the oil.
Miller called the U.S. shale business the most adaptable in the world, one that could boost Halliburton’s bottom line significantly during a recovery. Halliburton is the largest hydraulic fracturing firm in the United States.
For now, U.S. oil companies have bolstered efforts to perform second rounds of hydraulic fracturing on old wells to get extract more oil – a process called re-fracturing. Producers with access to capital markets have been more willing to experiment with the procedure than others, he said.
Last week, Schlumberger CEO Paal Kibsgaard said the re-fracturing business had the potential to bring on billions in revenue over time, and work on thousands of aging shale wells.
The Houston oil field services firm posted net loss of $643 million in the first-quarter as drilling rigs continued to go silent in North American oil fields and producers asked for pricing concessions for tools and services.
It absorbed $823 million in asset impairments and other charges as the energy slump forced it to write down the value of its oil equipment and record severance costs related to layoffs.
In a written statement, CEO Dave Lesar warned the industry will continue to face challenges in coming quarters and said it’s unclear how long the downturn will last. He noted U.S. drilling activity has fallen by 50 percent since its 2014 peak in November.
“We expect to continue to see pricing pressure for our services until the rig count stabilizes,” he said.
In the call, Miller added historically it has taken three quarters for a rig count to move from peak to trough.
Halliburton’s net loss amounted to an earnings-per-share loss of 76 cents a share, compared to its profit of $622 million, or 73 cents a share, in the first quarter of 2014. Revenue dipped from $7.3 billion to $7.1 billion over the same period.
The company previously disclosed it has planned to cut up to 6,400 jobs because of the downturn, but it did not update that figure Monday.
Halliburton executives said they aren’t cutting into the company’s service delivery platform – such as rail – as deeply as they would in an oil slump because they’re anticipating the massive merger with Baker Hughes later this year, which could lead to higher volumes of input on its infrastructure system.
Halliburton had announced earlier this month it will sell off three drilling units in preparation for the Baker Hughes merger, but the executive leading the integration of the two firms said they will likely need to divest more businesses.
The three units it plans to market make a combined $3.5 billion in revenue, said Mark McCollum, Halliburton’s chief integration officer.
This is not your fathers drilling rig:
The entire trig is movable on crawlers.....at each position drills typically 4 directional holes north and another 4 south....then moves east for another 8...repeat 8 times for 64 producing wells.
Completed production pad looks like this:
Number of wells completed per month continues to fall as well.
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