Skip to comments.The Niobrara Shale Play – the Next Bakken?
Posted on 10/26/2013 9:32:28 PM PDT by ckilmer
The Niobrara shale formation extends across northeastern Colorado, northwestern Kansas, southwestern Nebraska and southeastern Wyoming. The play ranges in thickness from 275-400 feet deep, with three primary carbonate-rich benches that average 10-25 feet thick with 5-10% porosity.
Within the Niobrara, oil and natural gas are found at 3,000-14,000 feet beneath the earth’s surface. O&G producers tap these resources through both vertical and horizontal wells typically drilled at 7,000-8,000 feet with variable geopressures.
To date, most of the Niobrara’s O&G development focuses on the Denver-Julesburg Basin (“DJ Basin”), with hot spots in the Wattenberg field of Weld County, Colorado, and (to a much lesser degree) Wyoming’s Silo field. Niobrara operators face unique challenges in this formation, but remain hopeful because of new estimates on overall production expectations over the next few years.
Unique Challenges for Oil & Gas
Niobrara’s geological characteristics can impede effective, economical drilling. The formation transitions from limestone to chalk to calcareous shale to sandstone, each with differing depth and thickness. Navigating drills in the thin layers is difficult, and high clay content of the formation makes it less permeable than other areas and complicates extraction.
The variable natural fracturing occurrence that results from the geological variety also impacts successful drilling. Operators seek sections that experience high natural fracture density, which are likely more productive and easier to tap, versus reservoirs with lower fracture density that yields higher water cuts and lower productivity. Early interest has yielded select highly explored drilling areas; however operators face challenges finding suitable locations for new horizontal wells that won’t interfere with existing vertical wellbores.
Water has proved an additional impediment in the Niobrara, from industry and environmental standpoints. The hydraulic fracturing process that revolutionized shale drilling requires high volumes of water. Summer 2012’s severe drought and rampant wildfires in Colorado rendered water scarce and forced O&G operators to spend more on securing access to water from the Colorado River.
Output Results Thus Far
The complexity of the Niobrara petroleum system complicates cumulative data, but estimates show that almost 2 billion barrels of oil equivalent have been produced from the Wattenberg field alone. EOG Resources’ “Jake 2-01h” drilled its first well in 2009 in northern Colorado, producing 50,000 barrels of crude oil in the first 90 days and maintaining outputs of 50,000 barrels per month. Noble Energy’s “Gemini” entered Weld County in 2010 and produced 1,100 barrels per day at its peak.
After a strong start, however, output has been less than predicted. In Weld County, for example, the first half of 2012 produced 11.5 million barrels of oil and 101.4 million cubic feet of gas. This compares to 26.5 million barrels and 238.4 million cubic feet, respectively, in 2011.
Despite lower outputs than expected, interest in the Niobrara play remains high. Notably, the O&G leaders in the play are independents that plan to continue or expand their drilling and E&P programs. As of August 2012, 45 rigs were active – four more than in 2011. New estimates now say that the play is a third bigger than first thought, capable of producing as much as 3.6 billion barrels of oil over the next several years.
An ASD Report estimates that production will pass 3 billion barrels by 2020.
The table below gives a sample of independents with a stake in the Niobrara. As you can see, future plans for the play show increased production going forward.
Although the geology of Niobrara presents challenges, operators are working around them to increase production in the area, and the forecast for this shale play is expected to increase.
The red states need to withdraw form the union.
They will instantly be the wealthiest nations on earth.
And the most free and moral.
Any questions why north east Colorado wants to secede?
Bumping to the moon and back...
Drill baby, drill!
Saudi Arabia couldn’t have broken off diplomatic ties with us at a better time.
The D-J Basis boomed in the 50s, most now stripper and low production wells. But shale could change everything.
Makes you wonder what a pro-energy administration could do to restore this nation in a matter of a decade or less.
The nation won’t be restored until half the country can’t vote to rob the other half that worked for it.
Read it carefully. These are not good numbers.
Rules for reading past oil hype:
1) When “oil equivalent” gets injected into the text, red lights and sirens should go off. They are celebrating 2 billion barrels of oil equivalent. That’s likely to be mostly natural gas — because that’s why the phrase appears, to conceal that the output is not oil.
2) When you see 50,000 barrels noted in months or years, grab your calculator. They said 50K in 90 days. That’s only 550 barrels per day. 550 bpd ain’t gonna fix anything.
3) When you see this -— “As of August 2012, 45 rigs were active four more than in 2011.”, our hype alarm should be at full volume. If the players only added 4 rigs in a full year, they ain’t really expecting much.
An FYI tidbit, rig count in these shale plays are HUGELY important only at first. In the Bakken right now, wells are drilled in 22 days. But the fracking process takes over 100 days. So the rigs can drill like crazy and essentially accumulate unfracked holes like an inventory, awaiting the fracking equipment. So if you pour in rigs for a year or so you can accumulate lots of holes and then pull the rigs out and wait for the frackers to run out of holes. The EIA hasn’t caught up with this year — they are still quoting shale production per rig, and that’s somewhat a useless stat for shales.
It’s kind of hard to pour in rigs if they’re not there. The Eagleford and the Cline shale here in TX has put allot of pressure on available drilling rigs. I’ve got a 12 well package I’d planned to start last month but a rig is still unavailable. We need more drilling rigs capable of going over 10,000 ft.
This article, and your summary, seem to be different than this article:
I live in this area, and they are drilling like crazy.
But, without official numbers, the setups are taking much longer than 22 days. But when they finish, they are quite the setup.
Finally, I knew they were after natural gas.
Unfortunately, CO is no longer “red” because of the Denver metro area.
“Finally, I knew they were after natural gas.”
Almost. Not quite. Natgas is priced too low to pay the bills if the holes gets pricey, and multi fracked holes are pricey.
Holes only get drilled if there is NGL potential. The liquids pay the bills and the gas is a side effect.
Obviously it would be better if it was oil. Not much of it, though. The flow rates are 500ish bpd and (in the Bakken shale) that number collapses about 67% in year 1 and 50ish% in subsequent years. So year 2 will flow 250, then 125, then 62 and 31 and you shut it in eventually in a few years.
These are not like Alaska wells that would erode 4-5% / year. These are huge decline rate wells. You have to drill and frack frantically to overwhelm the declines, and when you finally can’t the flow collapses sharply from lack of new drilling — which can happen hyper fast if oil’s price ever falls much.
The really bad news in this is that indeed a price fall would stop drilling, and knowing that, the impetus is already underway to find ways to automate the drilling/fracking process and fire people.
How the U.S. Shale Boom Is Splitting OPEC Apart
With no access to the west or east coasts.