DENVER—How much has the Denver-Julesburg (D-J) Basin changed in the last 100 years? The first well drilled in the basin was a gas well in Boulder County, Colo., in 1901. This is the same county now known for its environmentalism, Peter Mueller said at the recent Rocky Mountain Energy Summit sponsored by the Colorado Oil & Gas Association (COGA). Mueller, who is  CEO and co-founder of EcoVapor Recovery Systems and past chairman of COGA, was a panel moderator at the summit. More recently, the D-J has seen significant changes to its activity.

“In 2007, natural gas was the hot play in Colorado. But in December of 2009, EOG announced the Jake well, still one of the top producers in the basin, which produced about 1,770 barrels of oil per day from Niobrara,” Mueller said. “Then the Redtail prospect was discovered in 2009, with production from four zones: the Niobrara A, B, C, and the Codell/Fort Hays formations. In 2010, some companies began to drill more directional wells and Noble drilled it first horizontal well in the basin and within two years, they switched to an entirely horizontal program.”

The introduction of horizontal drilling work has had an effect on an entirely different county in the region.

“In Weld County, the population increased by almost 25% within those three years and real estate prices have increased by about 50%,” Mueller said.

Now that prices have fallen, Dave Stover, chairman, president and CEO of Noble Energy, told the audience, “we as operators have to control the enthusiasm of the moment of watching oil prices go up a few dollars a barrel like they did a week ago—we have to plan our business for what we can do within a range of expectations and prices. We get excited about drilling efficiency. In 2015, we have essentially two rigs doing the work that four rigs would be doing just a couple of years ago, which means that our spending is about half as much just a few years ago.”

Stover also recalled that when Noble Energy came into the basin in 2005, it was predominately a vertical Codell play. “We were just starting to test the Niobrara and there was a lot of skepticism at that time as to whether it could contribute on its own,” he said. “We started drilling Niobrara only because it was thicker, but we found that Codell was also a good contributor.”

Noble’s EcoNode system that is being used in the basin has centralized well facilities that accommodate up to 24 wells. According to Stover, the EcoNodes are getting more scalable and modular.

“We’re can build the majority of these systems and facilities offsite in modular-type components, bring them in and install them, which has less of an impact through the whole field process. They are also built in a way that you can add and subtract from them and then reuse the facilities,” he said. 

“You can make segments and pieces that you can move where you need them; you can build on it when you need to or reduce it when you need to,” he continued. “I think that goes back to the adaptability of this industry.”

Meanwhile, Jim Volker, chairman, president and CEO of Whiting Petroleum Corp. (NYSE: WLL), said his company’s lower drilling and completion prices give it hope for withstanding falling or fluctuating oil prices.

“We can vertically drill 5,500 ft to 5,800 ft and take the laterals out about 10,000 ft and complete it in about a week,” he said. “At Redtail, we have about 6,200 Niobrara A, B, C and Codell drilling locations on 960-acre spacings. Our drilling and completion costs for a well have been about $4 million and now it’s going down to about $3.75 million.

“In a $47 per barrel price environment, after differentials, royalties, operating expenses and production taxes, we can net about $24 per barrel.”

Volker also said it is important for the company to be “good stewards of the environment.”

“Whiting has implemented green completions with closed flowback systems; the rigs and completion crews use processed natural gas for fuel; and we bring everything in to a central tank battery for a 16-well spacing unit to minimize surface disturbance,” Volker said. “We’ve constructed oil-produced water and freshwater gathering systems to keep truck traffic down, and it’s saving us about 75,000 truck trips per year. And finally, we’re completing from Niobrara A, B, C and Codell all from one pad.”

Both Stover and Volker agreed that one of the biggest changes in the play over the past 10 years is operator engagement in the community where they work. Stover said that “it’s part of our business—it has to be.”

Volker said that Whiting found that being a good listener is a key trait to good community relations. “Someone from our staff attends virtually every open hearing in Weld County with the planning commissions, what the surface owners and mineral interests want and say, including any new or proposed regulations either from the county or the state.”

With both operators now involved end-to-end from production, including gas processing in the field, they are now able to rapidly adjust for changing regulations including those concerning air emissions. Stover said that with Noble’s EcoNode surface facility structures, the product is fully contained and it can be controlled and monitored with pipes and infield gathering systems, without the use of tanks and burners and thousands of truck miles from the roads.

Volker said that some of the larger operators in the basin have had to get out and put in their own gathering systems and plants. “Frankly, the midstream industry didn’t have access to the capital required to service our onsite needs,” he said. “It helped us realize the economics of it. You have to handle the gas if you want to sell the oil.”

Regarding plans for the future, Volker said, “I think that the industry prize for us is probably on the optimistic side that we’re only recovering about 10% of the hydrocarbons in place. I would be shocked if we’re not sitting here in 10 years talking about recovering 15%. I think that Codell with Niobrara together will play a key role— it may not sound like a lot but that’s a 50% increase.”

Volker also said he thinks there’s still more room for improvement. “I think the biggest thing right now is that we’re spreading that frack across typically 40 stages with three entry points per stage,” he said. “I think that 120 different entry points really makes a difference in homogenously being able to break up that rock along the wellbore. Because of the amount of oil that’s in Niobrara and Codell, it’s really the key to making this play last a long, long time.”

Larry Prado can be reached at lprado@hartenergy.com.