Oil & Gas in the high-tech age

(Editor’s note: This is part of the 2012 Oil & Gas Special Section. Read the entire insert.)

Brace yourself for impact, Colorado. Something’s coming, and you might not be ready. You might not be used to it. You might even have forgotten what it is.

It’s called prosperity.

Even with our ongoing sluggish economy, mediocre employment growth and flabby real estate markets, Colorado is already seeing the effect of powerful new developments in oil and gas exploration and production. These impacts are arising because of the application of new technology, mainly hydraulic fracturing and horizontal drilling, in the Niobrara formation in Weld and Yuma counties and elsewhere.

The center of the early waves of Niobrara exploration and production are being felt most keenly in Greeley, a longtime center of oil activity in Colorado.

“We’ve been a center of oil and gas development for several decades because we’ve got the Wattenberg field that initiated much of the drilling decades ago – in the mid-1980s we really saw a bump,” says Assistant City Manager Becky Safarik. “This latest one, the Niobrara, has been substantial. We feel like we’re the epicenter of oil and gas development in Colorado.”

Hotel rooms are at a premium in Greeley, office space is filling up, and oil, gas and dollars are flowing.

Nor is Greeley the only beneficiary of oil industry growth in Colorado. It seems easy to forget that the state is a major player in the petroleum exploration and production business, but Colorado is the nation’s sixth biggest natural gas producer and 12th biggest crude oil producer. And, thanks to the Niobrara and some other oil and natural gas liquids plays around the state, that latter number appears likely to rise sharply.

“Right now, Colorado is pretty important,” says Doug Hock, spokesman for Calgary-based EnCana Corp. “This year we think we’ll have a total of around 18 drill rigs in the U.S.; nine of those will be in Colorado.”

All those rigs directly translate into overall economic activity. Deeper Niobrara wells cost an average of about $7 million to drill. Companies that have found an exploration sweet spot plan to invest heavily in the state.

The Denver-Julesburg Basin – a huge geological structure ranging from Denver to Wyoming – without a doubt “is one of the hottest basins in the country right now,” says Ensign US Drilling spokesman Will Matthews. “The Bakken Shale in North Dakota is No. 1; the Niobrara is No. 2 because of the presence of liquids,” namely crude oil and natural gas condensate.

The Woodlands, Texas-based Anadarko Petroleum Corp. has leases on about 900,000 net acres in the D-J Basin and extensive holdings in the D-J Basin’s giant Wattenberg Field.

The company has plans for the area calling for billions of dollars in investment.

Anadarko invested about $1.5 billion in Colorado from 2007 to 2010, and $800 million in 2010. And that ain’t all, folks.

“There’s tremendous running room; there’s tremendous opportunity here,” says Anadarko spokesman Brian Cain. “We plan to spend $1 billion in Colorado, more or less in the Wattenberg, this year, 2012. That is a lot of money.”

That capital investment includes a highly skilled workforce of about 1,000 people in Colorado. And, Cain notes, “In that same timeframe, those five years or so, we have paid more than $450 million in taxes, royalties and salaries.”

Wattenberg Field wells, relatively shallow, cost about $4.7 million to drill and complete, according to Ted Brown, Houston-based Noble Energy Inc.’s senior vice president-northern region.

“We’re very early in the Wattenberg drilling program right now,” Brown says. “We have less than 100 wells producing now.”

Over the next five years, Noble plans to spend – ready? – about $8 billion in the Wattenberg Field and Northern Colorado.

“We’ve got a tremendous investment opportunity over the next several years,” Brown says. “This is our biggest onshore play. This year we’ll probably spend about $1.2 billion. It’s about one-third of our capital program for the company.”

Yet oil and gas exploration and production are inherently risky ventures. As they say, past performance is not a guarantee of future profits.

“This is a very, very complicated business. The idea that there is some magical lake of oil down there and all you have to do is put a straw into it and suck it up obviously is a myth,” says John Dill, director of corporate development and government relations for Oklahoma City-based Chesapeake Energy Corp.

Niobrara exploration in Colorado has disappointed Chesapeake, which has shifted focus to similar prospects in Wyoming.

“The Niobrara is a very complex process to try to crack. We have found a very good sweet spot in Wyoming. In light of the fact that this is a 250,000-square-mile area, and in light of the fact that we have only so many rigs, in the face of $2.30 per mcf (thousands of cubic feet) natural gas, it’s no surprise that when you find a place where you can move from exploratory activities that you’re going to concentrate your resources in that area,” Dill says. “But I would not say that in the D-J that all is lost if you are outside of the great Wattenberg Field.”

Dill raises a couple of key points. One is that exploring the Niobrara has gained popularity as the price of natural gas has fallen and the price of crude oil has spiked.

Natural gas fields in the Denver-Julesburg Basin, Colorado’s San Juan Basin and Piceance Basin – not to mention the famously prolific Bakken Formation in North Dakota and Pennsylvania’s Marcellus Shale – have yielded hitherto unimagined amounts of gas. This has driven prices down dramatically and squeezed gas storage and even gas pipeline capacity.

“Natural gas prices have fallen 46 percent over the last 12 months,” says EnCana’s Hock. “Natural gas is still essentially a domestic commodity. In other words, the market price is set here in the United States or in North America, whereas oil is an international commodity. There’s a relationship between the two, but in the last couple of years it has really decoupled. The general rule of thumb has been oil was valued about six times greater than gas. Now it is 40 to one.”

While a great deal for consumers, the natural gas price slump has sent oil and gas producers in search of oil and natural gas liquids.

But not all of them. Some producers have hung in with gas. Tulsa, Okla.-based WPX Energy, which this year was spun out of Williams Cos., focuses on Colorado’s Piceance Basin (pronounced “pee-ahnc”), with productive assets in La Plata County as well.

“The play is gas born of the coal formation. It’s sandstone that is denser than concrete,” says spokesperson Susan Alvillar, who is based in Parachute. “Over the course of our operation in this basin since 1983, we’ve come to know that those rocks are laid down in ellipse shapes, like the lenticular clouds you see in the sky, of about 10 acres each.”

WPX has leased 211,000 net acres in Garfield and Rio Blanco counties, where it has a whopping 4,100 wells – wells that today cost an average of $1.4 million each to drill. The company produces 850 million cubic feet of natural gas in the Piceance, and another 14,000 million cubic feet per day in the San Juan Basin of La Plata County.

Also of note is that WPX in 2010 paid $18 million in severance tax; $40 million in ad valorem tax to the counties where it operates; $62 million in federal royalties; and $162 million in private royalties.

WPX uses a technological predecessor of horizontal drilling called directional drilling to get at its natural gas reserves.

“Every well that we drill today is directional. No well is below the drilling rig. The wells are drilled in an ’S’ shaped curve. The first part of the ‘S’ starts right as the well starts to drill; the last part of the ‘S’ is made down above the pay zone and the well then drops right down into the sweet spot into the middle of that 10-acre piece of rock we call the sand lends,” Alvillar explains.

Alvillar is a geologist as well as a community relations specialist. Since she started out in the late 1980s she has seen “huge improvements in technology and know-how. The time to drill the wells has decreased. The surface lands required to drill these wells has decreased. The amount of traffic has decreased.”

To name one such technology, “The simple utilization of telemetry on these wells, which is a system by which a field person can look at a well without physically having to be at that well, has revolutionized the industry’s ability to lessen its impact on the environment and the public,” Alvillar says. “They can not only look at those wells, but they can adjust them from their laptops and shut those wells off if they need to. In the case of, for example, a wildfire, you want to shut those wells in so that there’s no gas flowing. They can do it with a keystroke.”

Advanced technology enhances even tried-and-true petroleum recovery.

Pioneer Natural Resources leases more than 200,000 acres in the Raton Basin west of Trinidad. The company has drilled 220 coal bed methane wells there since 2008, with another roughly 2,000 producing wells in its portfolio. Coal bed methane, another term for natural gas, is produced from relatively shallow coal seams about 2,000 feet down.

The drilling and fracturing method there is well understood. Pioneer fractures its wells using a combination of water, nitrogen, guar gum, and Dawn dish soap. No kidding.

But coal bed methane recovery is water-intensive, and Pioneer’s high-tech concentrates on water recovery and monitoring. Pioneer’s award-winning monitoring program eyes the watersheds of the Apishapa and Purgatoire rivers to ensure that water quality meets permit standards and to improve knowledge of coal bed methane discharges.

Pioneer also works hard to recapture water used in its drilling and production. “The first thing that comes out of the well bore is some water. We take that produced water and reuse it,” says spokeswoman Karen Brown. “That’s the water we use when we do our light frack.”

Tim Wigley this year moved from Oregon-based lobbyist PAC/WEST to the presidency of the Denver-based Western Energy Alliance. The 400-member group represents the oil and gas business in 13 states.

“Looking back over the last five or 10 years, the level of technological leaps in this industry versus other natural resource extraction industries, like mining, like forest management, agriculture – not to say they haven’t had tremendous developments – but this industry is full of really innovative people,” Wigley says.

“The industry has re-invested heavily, and it is paying off. We are the leaders in the world, the apple of the eye of industries around the world.”

However, technology can be trumped by regulation. And the amount of time and money required to lease on federal lands in particular has increased significantly in the past few years.

For oil and gas explorers-producers, the problem is “more than anything else the lack of certainty energy companies have from the time they get a lease and start down the permitting process road,” Wigley says.

“Having to do the various environmental assessments – air, water and habitat – there are layers and layers and layers. There was a time when you could complete those permitting processes in a year or two, but there are plenty of cases now where it is seven or eight or nine years to actually get a permit,” Wigley adds.

David Banko is principal of the Englewood-based consulting firm Banko Petroleum Management Inc., which specializes in regulatory matters.

Banko, like most industry professionals, has praise for the Colorado Oil and Gas Conservation Commission and Gov. John Hickenlooper, a former petroleum geologist-turned-businessman, in particular.

The federal government is another matter.

While oilfield technology is light years ahead of where it was in the 1980s, the regulatory process is “is much more complex,” Banko says. “The public, and particularly the opposition to oil and gas projects, is weighing in much more heavily on the process. Almost every resource on federal lands takes precedence over energy – even solar and wind right now have their detractors. Any effort to produce energy on federal lands is becoming more and more difficult every day.”

Also, “If you look at the history of oil and gas leasing in the last three years, you will find that leases on federal land that were issued back in 2008 were suspended and ultimately denied.”

The practical effect of these policies is that, “Rifle, Meeker and Grand Junction are struggling because of federal policy.”