Down and out: Piceance drilling takes a turn sideways

This rig was used to drill a horizontal well into Mancos/Niobrara shales from an Encana USA pad in the Mamm Creek area near Rifle. Horizontal drilling has unlocked oil and gas reserves in other parts of the country and could vastly extend the life of drilling programs in northwestern Colorado.

Matt Abell, group lead of drilling and completions for Encana USA’s South Piceance area, stands at a pad where horizontal wells were drilled in 2011.



Statewide, horizontal drilling has steadily grown from just 2.8 percent of all well permits approved in 2009 to 32 percent last year and 45 percent so far this year. But of 1,257 horizontal wells on which drilling actually has begun, 976 were in Weld County. Only 26 have been drilled in Garfield County, and 25 in Mesa County. Some of the Garfield wells were drilled the 1990s, and a good portion of the more recent horizontal well drilling in the two counties dates back a few years.

Oil and gas development in western Colorado could someday take a 90-degree turn, based on the early results of energy companies’ exploratory work.

Horizontal drilling, which has proven instrumental in unlocking gas and oil reserves in shale formations in other parts of the country, is proving promising as companies explore shale formations in the Piceance Basin, centered in Garfield, Mesa and Rio Blanco counties.

The drilling technique and the resource potential of shale hold the promise of vastly extending the life of drilling programs in the Piceance Basin, assuming natural gas prices eventually rise enough to justify the costs.

A hint of that potential and promise came last month when WPX Energy, the biggest natural gas producer in the Piceance, announced what it called a “Niobrara shale discovery” involving a horizontal well it drilled in Garfield County. That well initially produced 16 million cubic feet of gas, and when it was choked back to optimize well performance and recovery, averaged 12 million cubic feet a day over 30 days.

Thom Kerr, who heads permitting for the Colorado Oil and Gas Conservation Commission, said that compares to initial production of perhaps 1 million cubic feet a day in a typical Piceance well.

WPX reported an initial flow pressure of 7,300 pounds per square inch.

“That’s a very high pressure,” said Kerr, who said it’s another indication that a well will flow at high rates.

Drilling to date in the highly productive Piceance — now including more than 10,000 wells in Garfield County alone — has focused on the Williams Fork sandstone formation, part of what’s called the Mesaverde group. The Mancos and Niobrara shales lie beneath that sandstone, with the Niobrara considered a lower part of the Mancos shale group.

Williams Fork drilling began with vertical wells and more recently involves directionally drilled ones, resulting in multiple wells drilled from the same pad. However, directional wells are still far different from horizontal wells. They involve drilling down vertically, then snaking out in an S-shaped pattern so that the wells return to a vertical trajectory once they reach the target sandstone.

In contrast, horizontal wells are drilled down, then take a 90-degree turn and bore into the production formation horizontally.

Sweet spots

Matt Abell, group lead of drilling and completions for Encana USA’s South Piceance operations, said one way to understand where a horizontal well might make sense is to visualize a layer cake. If an energy company wants to target a relatively thin, productive oil and gas zone akin to the icing between cake layers, a vertical well will do little good because it will come in contact with so little of that layer before poking through it.

But if the wellbore is turned sideways upon reaching the icing, it can follow that productive layer a long ways. In the Piceance Basin, Encana has drilled two wells extending 10,000 feet, or the better parts of two miles, in their horizontal sections.

This approach allows a company to target specific zones within a shale formation that are sweet spots in terms of energy content; porosity, which contributes to flow; and other characteristics.

The reason horizontal drilling holds more promise in the Mancos and Niobrara shales rather than the overlying sandstone relates to how those formations were created. Abell said the shale was laid down in a fairly calm, marine environment, meaning the deposits are fairly homogenous across extensive distances.

The overlying Williams Fork consists of sands that accumulated in sporadic deposits in floodplain river channels. Those deposits are often described as discontinuous lenses. Continuing his food analogy, Abell envisions them as being like a bowl of potato chips. Companies have been drilling wells every 10 acres to be able to contact and hydraulically fracture most of those chips. There generally aren’t homogenous layers that can be traced at length by horizontal wells.

The Niobrara formation extends to northeastern Colorado, where companies have been drilling into it in search of oil and much of the state’s current drilling is occurring.

Price is deterrent

According to a 2011 Colorado Geological Survey report on Niobrara drilling, the formation is only 200 to 400 feet thick in northeast Colorado, and as thick as 1,500 feet in parts of northwest Colorado. However, those thinner formations are closer to the surface and generally subject to comparably lower temperatures than the deeper Niobrara formations in western Colorado. Higher temperatures and higher pressures deeper underground tend to lead to production of gas rather than oil.

Companies have been drilling in the Niobrara in what is called the Sand Wash Basin in Routt and Moffat counties, and producing more liquids there, Kerr said.

According to the Colorado Geological Survey, the state’s earliest oil production from the Niobrara was in Moffat, Routt and Rio Blanco counties, in the 1920s.

However, “From the data that I’ve seen the Piceance just seems to be in a gas phase,” Kerr said. “Most of the formations we just don’t see much oil production. There are some areas that there are more liquids than in other areas but it’s still more of a gas basin.”

At today’s low natural gas prices, which have resulted in the lowest drilling activity in the Piceance Basin in about a decade, that’s a deterrence to more aggressive shale exploration efforts.

“I think that the gas market is just a big hurdle to overcome,” Kerr said.

“They’re expensive holes,” he added, referring to the added cost of horizontal drilling.

Hsulin Peng, a Robert W. Baird & Co. stock market analyst who tracks WPX, said the production rates at WPX’s Garfield horizontal well “are very encouraging.” But she added that the company hasn’t disclosed the cost of the well.

The company typically spends about $1.4 million drilling and completing a well in the valleys locally, and $2.8 million for a well in the highlands north of Parachute, she said. By contrast, it spends about $6 million drilling a horizontal well in the Marcellus shale in the eastern United States.

“I can’t really tell you how economic it’s going to be without knowing the cost of it,” she said of WPX’s local horizontal shale drilling efforts. “But it does seem like the resource potential is there.”

Lower-value gas

WPX plans to drill two more horizontal wells in the Piceance Basin to help it better evaluate how productive the Mancos/Niobrara is across the basin. However, the company has said that with lease rights to about 180,000 acres in those shale formations beneath its Williams Fork leases in the basin, its discovery suggests the potential for the company to ultimately more than double its companywide 18 trillion cubic feet equivalent of proved, probable and possible reserves. The United States consumed some 24 trillion cubic feet of gas in 2011, according to the federal Energy Information Administration.

Peng said she doesn’t know the liquids content of the gas WPX produced from its test well. Wetter gases that are high in liquids such as propane and butane have more value in today’s price environment. Overall, the Piceance Basin produces relatively dry gas.

If WPX anticipates producing dry gas from shale wells, “ultimately it’s going to depend on long-term gas price to make it work,” she said.

Local WPX spokeswoman Susan Alvillar declined to say much more about the company’s local shale exploration until after the company’s next earnings call with analysts. She acknowledged that gas prices will be a consideration, and also emphasized that it’s the company’s first horizontal well in the basin.

“We’re still kind of in the research mode on it. We’re still looking at how it’s producing,” she said.

Kerr said if horizontal wells in the basin continue to show the kinds of volumes wells to date have been producing, “you are talking about game-changing” in the right price environment.

Abell said he doesn’t think Encana is in a position yet to definitively quantify the potential for local gas development related to shale.

“But quantitatively, yes, I think it has the potential to have a significant impact on the Piceance as a whole.”

Expensive drilling

Encana has drilled more than 20 horizontal wells in the Piceance Basin. The company also has reported initial production rates much higher than Williams Fork wells from horizontal wells.

Randomly pulling up records on one of those wells, Kerr said it produced “huge” initial gas production of 290 million cubic feet in 31 days.

Abell said a typical Williams Fork well might produce 1.5 billion cubic feet over the decades it is active. But it appears some local horizontal wells might yield a billion cubic feet in just a year, he said.

But such wells are costly to drill and complete — perhaps five times the cost for a vertical/directional well Encana drills locally, Abell said. He expects to see that cost come down somewhat as the company drills more and improves its efficiency, but only to a degree.

Abell said Encana is continuing to evaluate things such as the optimal length of a wellbore, proper spacing between wells, and to what degree multiple horizontal segments might be drilled one above the other within the same shale. Meanwhile, Kerr said that as companies learn, the oil and gas commission is learning as well from a regulatory perspective, as it considers issues such as proper well spacing so wells don’t drain areas where companies don’t have the mineral rights.

Local interest in horizontal drilling and shale development has some local residents on edge. Frank Smith with the Western Colorado Congress citizens groups said some people living in places like Battlement Mesa had come to think that if they could just endure the drilling of remaining Williams Fork wells in the region, the impacts of drilling might largely be over.

Instead, “the grin-and-bear-it consideration, that the drilling may be done in 10 years, may go out the window as we consider horizontal drilling” in deeper formations, he said.

He also worries about potential additional environmental risks with horizontal drilling, as well as things such as the additional water needs associated with such extensive fracking of horizontal wells.

The latter is something Encana hopes to handle through its ongoing efforts to recycle the water it uses.

David Ludlam, executive director of the West Slope Colorado Oil and Gas Association, said the industry will continue doing more and more to address public and environmental concerns related to drilling. In the meantime, he has seen numerous companies locally drilling test wells and otherwise evaluating the potential for shale development, which he thinks eventually will involve a mix of horizontal and vertical/directional drilling, taking into consideration factors such as costs. Ludlam is excited that shale formations may represent the long-term future of drilling in a basin with a long history of energy development.

“We hope we continue to find new formations that make (that development) viable for generations,” he said.


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