Gas production from tight sands, shale and coalbed methane is fast becoming the dominant source of gas supply in the U.S. Rockies players are making a big contribution to that, moving forward with finely tuned operating strategies to increase production. Using today’s technology, these prolific and low-risk reserves are a staple in many energy producers’ portfolios, despite bargain-basement stock and commodity prices.

“I think 2009 is going to be an interesting year,” says David Howell, general manager, services, for Anadarko Petroleum Corp. “We’ve been presented with some challenges, but the good news is that we have solid assets in the Rockies.”

The Woodlands, Texas-based Anadarko holds about 10 million acres in the Rockies’ most prolific basins and, in 2008, grew its production by some 17%. Anadarko, the largest acreage-holder in Wyoming and the largest gas producer in Utah, anticipates its overall 2009 production to be up by as much as 3%, largely driven by lower-risk development opportunities such as onshore drilling, recompletions and refracs of its large inventory.

“We can do these workover activities or recomplete into a new zone and get similar types of production for about 25% of what a new drill would cost,” says Howell.

Size Matters

Anadarko’s large Rockies position gives it purchasing power, which “comes in very handy when we are negotiating our work programs for the year,” Howell says. “We are actively meeting with vendors to reduce costs for drilling and workover rigs and, in some cases, we are delaying completions. We are also asking our own employees to help find innovative ways to work.”

Anadarko also uses firm pipeline-transportation contracts and hedging programs to reduce costs. “These strategies allow us to watch both sides of the equation,” he says.

The company has hedged the majority of its Rockies production at the Nymex price, less a basis differential of $1.25 per thousand cubic feet, for the rest of this year. For 2010, it has hedged at the Nymex price less $1.28, and less $1 in 2011, to protect against potential wide basis-differential swings going forward.

Meanwhile, Anadarko’s long-time presence and large position have also allowed it to develop expertise with new technology to improve drilling efficiencies. This year, Anadarko reduced its drilling time by about 15% from last year in its three major Rockies operating areas.

“In these big resource plays, we know the gas is there. It’s just a question of using the most effective and efficient way to produce the gas, such as new drillbits, directional drilling, fracture-stimulation methods and down-spacing,” he says.

One innovation is Anadarko’s switch to a polycrystalline diamond compact drillbit. The company is also testing pipe-rotation methods in conjunction with downhole mud motors.

“People ask us how many rigs we have drilling, but the right question is how many wells we’ve drilled, because we now need fewer rigs to drill more wells.”

Anadarko also reduces drillpad footprints and unobtrusively positions wellheads. “In some of our fields, like the Wattenberg, a person could drive right by a cornfield wellhead without seeing it. We are now twinning these wellheads, putting two or three wells as close as 15 feet next to each other, and consolidating the infrastructure to reduce space on the surface.”

Directional drilling also contributes to its discreet profile. Last year, Anadarko won the 2008 Earth Day Award from Utah’s oil, gas and mining division for drilling 16 directional wells from a two-tier pad on the buttes of the White River. “We were able to tap resources under the river, while keeping our operations on the buttes and out of sight of the river’s recreational users.”

Anadarko is also moving forward with its infilling program. In the Wattenberg, it is down-spacing to 20 acres. In the Greater Natural Buttes, it is testing both 20- and 10-acre spacing to evaluate results, which are positive so far. The company also uses enhanced-recovery methods. “We’re injecting carbon dioxide into the Salt Creek Field in Wyoming for tertiary recovery. It’s a world-class oil field that has been around a long time, but there is a tremendous amount of reserves still in the ground that will only be recoverable through CO2 injection,” he says.

For its Powder River Basin coalbed-methane play, Anadarko built a 48-mile water pipeline to take produced water into the Miocene formation under its Salk Creek enhanced-recovery project in Wyoming. The water is then stored in underground aquifers. “So in effect, we are saving a good water source for the future.”

Gothic, Hovenweep Shales

Bill Barrett Corp., formed in 2002, is also focused on shale-gas resources in the Rockies. “What has everyone so keenly interested in the Rockies is that a lot of these Cretaceous shales cover vast areas, extending from northern Canada to Mexico,” says Fred Barrett, chairman and chief executive of Bill Barrett Corp.

“It’s a matter of finding where those shales have the right thermal conditions to generate hydrocarbons and how shallow they are, but we look at shale-gas potential in a variety of ways.”

First, the group looks at shale-gas contributions to existing tight-gas plays, just as Barrett is currently doing in the Piceance Basin, where it targets the Mesaverde formation. “In the Piceance, we are now perforating and stimulating intervening shale beds between the more traditional tight-gas sands,” he says.

Second, he notes that the Rockies host a tremendous thickness of Cretaceous shales that can be perforated and stimulated in a vertical wellbore. For example, the company is testing the siltstone-interbedded Mancos shale in the West Tavaputs area of the Uinta Basin, and the Cody shale in the Wind River Basin and in its Circus area of southwestern Montana.

Third, the producer looks at older Paleozoic shales, like those found in its Yellowjacket play in the Paradox Basin in southwestern Colorado, where it has defined a large fairway of over-pressured Pennsylvanian Gothic shale.

Barrett is a dominant leaseholder in these plays because “this is an area that could spark a new era for the Rocky Mountain region, should it prove to be one of the first Paleozoic shale-gas plays to emerge here,” he says.

Barrett is interested in a shale, similar to the Gothic, called the Hovenweep. To some extent, the two shales overlap and have similar characteristics. The area over the Gothic and Hovenweep is more than 2.1 million acres.

Barrett likes the Gothic shale in part because it is relatively shallow. The company has drilled to about 6,000 feet, then drilled 3,400- to 3,900-foot laterals within an 80- to 160-foot-thick shale. “There is good organic content and decent porosity, and it is overpressured. We are seeing from 50 to 80 cubic feet of gas content per ton of shale.”

The company has finished drilling its sixth horizontal in the play and plans to spud a seventh. While six of the wells were drilled into Gothic shale, one was drilled horizontally into Hovenweep, thus initiating Barrett’s new Greenjacket program. The producer has already completed three wells in Yellowjacket with initial test rates of 3- to 5 million cubic feet per day over a 10- to 15-day period. It has two of them hooked up for sales into Williams Cos.’ Northwest pipeline.

Barrett has reduced drill time from 25 days to about 15, and is testing completion techniques by varying the number of fracs (from six to eight stages), the types of stimulations (e.g., stem-sleeve technology), and using microseismic frac-mapping and flowback designs.

Going forward, the company plans to acquire additional 3-D seismic while infill leasing in the Gothic, with plans to drill about 14 wells in Yellowjacket this year, on 160-acre spacing in the center of each 1,280-acre lease unit.

Elsewhere, in the southwestern Uinta Basin, the company has drilled its first vertical test well into the Mississippian-age Manning Canyon shale in its Hook prospect. “It’s intriguing because the core data gave us gas content higher than any other play we have. We will drill our first horizontal in the Manning this year.”

In the northern Uinta Basin, the company is exploiting an infill program in a yellow-wax oil play in the Black Tail Ridge area. “We found several continuous, highly oil- and gas-charged shale intervals. We refer to the region as Mother Nature’s hydrocarbon storehouse. It smacks of a massive resource play.”

In the Circus area of southwestern Montana, the producer has tested one of its four vertical wells drilled into the 800- to 900-foot-thick Cody shale. Initial production showed more than 1 million cubic feet of gas per day. “It has certainly piqued our interest,” he says. “During 2009, we will complete the other three vertical wells and, with continued success, we will drill a horizontal.”

The Waltman Arch in the Wind River Basin in central Wyoming may also have Cody shale, he says. The company is also looking at the Mowry shale that sits just below the Cody almost everywhere in the Rockies.

Contiguous Strategy

Born in the 1920s, Questar Corp. has always been a Rockies player.

“Even today, some of Questar’s leases go back to the 1920s,” says Charles Stanley, Questar executive vice president and chief operating officer.

“We have substantial assets in the Rockies, including the northern third of the Pinedale anticline in Wyoming,” says Stanley. “This play makes up Questar’s single-largest reserve and production asset. We also have a substantial position in the Uinta Basin in eastern Utah and a number of other legacy assets in the Rockies.”

Questar holds 1.1 million net acres in leases in the Rockies—a large asset base but one controllable through smart strategies. “Our primary focus is on amassing large, contiguous blocks of acreage where we can operate. With disjointed or fragmented acreage positions, it is harder to put together systems that can drive down costs.”

Experience, repetition and working similar plays have allowed Questar to substantially reduce its drilling time. “In 2002, we were taking about 100 days to drill a vertical well from the surface to 14,000 feet at Pinedale. Now we can drill a directional well, with several thousand feet of displacement, in 18 days. We continue to make incremental progress on every well we drill, which drives down costs.”

Typically, Questar uses conventional rigs for directional drilling. In its Pinedale play, the gross gas-bearing interval is, on average, about 5,000 feet thick, so the company fracs each well 15 to 18 times. “Pinedale is a unique field. It has a huge concentration of gas in a relatively small area. It is only 30 miles long and three miles wide, yet it holds over 30 trillion cubic feet of gas equivalent.

“There is a lot of opportunity to invest in infrastructure and environmental projects because of the concentration of the accumulation.”

The wells range in initial production (IP) rates from 5- to 10 million cubic feet per day, depending on their location on the anticline. Some of Questar’s highest-rate wells have IP’d at 15 million or more.

Stanley says the reserves can be 2.5- to 3 billion cubic feet per well on the flanks of the anticline, ranging to more than 10 billion per well on the crest. The production profile of the wells, like most unconventional plays, is steep, with a hyperbolic decline that results in the recovery of about half of the reserves over the first five or six years of the well life. After that, it flattens out to a shallower, exponential decline with the remaining reserves recovered over the next 30 years.

Questar’s tactic is to drill its wells to more than 14,300 feet directionally on five-acre spacing. The company has nine rigs drilling in the Pinedale, the same as last year. It has been working on regulatory approvals from the Bureau of Land Management—a supplement to the environmental-impact statement that was done at Pinedale.

Meanwhile, beginning last year, the company started to diversify from being an almost entirely gas producer with incidental oil production, to focusing on additional oil plays.

“At the end of the day, it’s the same drilling, completion and repetitive motion expertise for oil as it is for gas,” Stanley says. “We picked up a block of acreage in the Bakken play in the Williston Basin, just south of EOG’s and Whiting’s activity at Parshall and Sanish fields. We’ve just drilled and completed our first well there, which showed initial production of 920 barrels of oil equivalent per day.”

Questar is focusing the lion’s share of its capital on the Pinedale and the Haynesville in Louisiana.

“Those are the two plays that are most economic in our portfolio, and probably in the industry’s portfolio, due to low F&D and operating costs.”