Activity growing reserves

Rockies Taking Front-Runner Role

American Association of Petroleum Geologists (AAPG)

The long-famous quote “Go West, young man…,” coined by American newspaper writer John Soule in 1851 and subsequently popularized by Horace Greeley, continues to have meaning today – at least in the oil patch.

Right now, it’s all about the Rocky Mountains – a region that beckons to the oil and gas players like never before.

“While offshore is declining, the Rockies are expanding,” said AAPG member R. Randy Ray, Denver-based consulting geologist/geophysicist and a recognized expert on the region.

“Rockies gas production is the fastest growing area in the U.S.,” he added. “This is where we’re going to find the big reserves to energize our country.”

Recently released results of a study conducted by the U.S. Geological Survey go far to back up Ray’s statements.

The agency announced that it estimates the Upper Devonian-Lower Mississippian Bakken formation in the Williston Basin in Wyoming and North Dakota could harbor about 3.7 billion barrels of oil (see related stories, page 20).

This would be the biggest single deposit in the nation outside of Alaska.

But the already-active Bakken play is just one of many areas seeing heavy action in this part of the world.

Piceance Success Stories

Colorado's Piceance Basin
Mesaverde outcrop. Photo courtesy of Bill Barrett Corp
Colorado's Piceance Basin Mesaverde outcrop. Photo courtesy of Bill Barrett Corp
Colorado’s Piceance Basin is a lively place, according to Steve Cumella, another AAPG member and senior geologist at veteran Rockies player Bill Barrett Corp., which operates in the Piceance and other areas.

Even industry behemoth ExxonMobil holds extensive acreage in the basin.

“Exxon, EnCana and Williams have by far the biggest acreage positions,” Cumella said. “Williams alone has something like 27 rigs drilling.

“There are a lot of other companies operating,” he added, “and very conservatively I’d say there’s 50 to 60 rigs running – maybe closer to a hundred.”

Essentially all the gas production in the Piceance is from tight gas sands of the Cretaceous-age Mesaverde group. Owing to the discontinuous low permeability nature of the sandstone reservoirs, well density is 10 or 20 acres for the most part; well depths average 8,000 feet.

The average reserves per well are 1.5 bcf, and well costs range between $1.5 million and $2.5 million.

“The economics are better now because gas prices are better,” Cumella said. “If you can drill a 1.5 bcf well for one-and-a-half million dollars, that’s highly economic today. In a lot of the basin there’s zero percent dry hole risk, so you drill a well and there’s usually 100 percent chance of success.

“Bill Barrett has drilled close to 300 wells there with no dry holes, and Williams would have drilled close to 3,000 with no dry holes.

“That’s the attraction of these types of basins that are gas plays,” Cumella noted. “If it works like it’s supposed to – according to the model that you would have these thick gas-saturated intervals – then in any given well you have enough pay to make a commercial well.”

A Big Deal at Pinedale

Some of the
Some of the "virtual beehive" of activity at Wyoming's Pinedale field. Photo courtesy of Ultra Petroleum
There’s a virtual beehive of ongoing activity at the Pinedale field in Wyoming where Questar, Shell and Ultra Petroleum are the major operators.

“It’s one of the most active areas in the Rockies right now,” said AAPG member Vinnie Rigatti, general manager-legacy division at Questar. “There’s a lot of focus, a lot of attention on the environmental side and the operations side – it’s just a big deal.”

Pinedale is a huge anticlinal structure in the Greater Green River Basin in southwestern Wyoming, and it has some huge potential – in fact, it’s likely the second largest gas field in North America, Rigatti noted.

AAPG member Fred Julander of Denver-based Julander Energy concurred.

“I think right now the Barnett (in Texas) is the biggest and Pinedale is the second,” Julander said. “The published data may not say that, but I think that’s where we are in real time.”

Pinedale was initially mapped in the 1920s, and the first well was drilled in 1939. Nearly 60 years later, in 1997, Ultra drilled the first commercial well.

A 2006 year-end reserves assessment by Nederland Sewell noted gas in place at Pinedale to be 48 tcf.

Total estimated recoverable reserves for the field are in the range of 20-25 tcf, according to Diana Hoff, general manager of the Pinedale division at Questar. Hoff noted Questar plans to drill 75 wells at Pinedale this year.

Cutting the Timeline

Pinedale field production is from the overpressured tight gas Lance Pool sandstone of Upper Cretaceous age. The average well depth is 13,700 feet, according to AAPG member Sally Zinke, director of exploration at Denver-based Ultra, which currently has 16 operated rigs running and nine non-operated on acreage where it holds an interest.

The company’s average cost to drill, complete and bring a well online (including production equipment) is $5.7 million.

“One thing we’re pretty excited about now is we TD’d a deep exploration test in February, and we’re getting ready to start completion on it this month,” Zinke said. “We drilled to 19,500 feet and tested the Rock Spring, Blair and Hilliard formations.”

Zinke noted that the company’s drilling time and also its drilling costs at Pinedale have decreased significantly during the past year. Where it used to take 40-45 days to drill a well, that’s now down to the 25-day range.

Currently, the company is awaiting a final draft and ultimately a record of decision on a supplemental EIS.

“That will make a large difference in operations in Pinedale, because it would structure us to have year-round drilling, which we’ve not been able to take advantage of in the past,” Zinke said. “In some areas, we’re only allowed to operate between August 1 and November 15, which puts a crimp in the rig fleet and other things – you can’t really set up and have the synergy of staying on a pad and drilling through everything.

“I think the BLM is looking hard at the fact that by moving rigs in and out to fit these windows it’s causing more disturbance than if you park the rig and stay,” Zinke said. “We’re going to use an 11- 12-acre pad that can accommodate 32 wells, so we’ll be able to put a rig or two on and drill for a couple of years without moving a rig out – it provides less disturbance.”

It also makes far more sense for production and overall economics.

“It’s difficult moving rigs in and out because you have a specific date and you may not be finished with a well,” Zinke noted. “Or you need to plan to drill fewer wells in the area because you have to leave sooner.

“We hope to have the record of decision by late summer so we can plan what we’ll be doing before winter hits.”

The Jonah natural gas field on the south edge of Pinedale is another area of operations for Ultra, where it is the third largest operator behind Encana and BP.

Shale Gas Potential

In addition to tight gas sands and coalbed methane plays such as the Powder River Basin in Wyoming and the Wind River Basin in Colorado, the operators are paying considerable attention to shale gas potential in the Rockies.

“A potentially significant thing in the Rockies is there are a lot of companies, including Bill Barrett, who are attempting shale gas plays here,” Cumella said. “We’re exploring in the Paradox Basin, as a specific example, and other companies are doing shale gas plays in a number of the basins.

“Shale gas is a tough learning curve, but this could be a big boom if some start to work,” Cumella said, noting the nowwildly successful Barnett Shale.

“The key would be repeatability,” Cumella noted. “Any time you can work in a play that has minimal dry hole risk, it really helps the economics.”

A year ago, the E&P community was anxiously awaiting results from the first horizontal well being drilled in the Baxter shale in the Vermillion Basin in southwest Wyoming.

They’re still waiting, in a sense.

The well is producing, but it’s in a longterm production test, and operator Questar is evaluating results, according to Rigatti.

“We’ve drilled 23 wells to date in the area assessing the extent of the Baxter accumulation, and we’re watching those wells now,” Rigatti said. “We’ve had mixed results, with a couple of fantastic wells, a couple of disappointments and some middle of the road.

“We’ve drilled three horizontal wells in the Baxter, and the others are vertical wells drilled through the Baxter to the Frontier and Dakota formations.”

Rigatti noted Questar currently is in the third year of a new EIS straddling the Colorado and Wyoming state lines and is anticipating a record of decision perhaps in mid-2009.

3-D’s High Profile

In a region where activity is essentially exploding, it comes as no surprise that 3-D seismic data acquisition programs are expanding as well (see related story, page 26).

Data availability in the Rockies pales in comparison to areas like the Gulf of Mexico and its nearby onshore areas, but the contractors have been revving up the Rockies activity for several years.

“We’re seeing strong demand forecasted for the next several years for both multi-client and proprietary data,” said Mike Bertness, vice president-land library U.S. at CGGVeritas.

Bertness and Rigatti both will present papers at a session addressing the business value of 3-D at the July 9-11 Energy Epicenter meeting in Denver, to be jointly hosted by the Colorado Oil and Gas Association and the AAPG Rocky Mountain Section.

Zinke will also present at the session.

“Right now the Bakken play is the hottest area for 3-D in North Dakota,” Bertness said. “Another area people are looking at seriously where there’s not a lot that’s been shot is the Piceance Basin.

“In the Rockies, there’s a limited time window you can shoot 3-D because of all the different restrictions, either from the BLM, or environmental restrictions for the sage grouse and things like that,” Bertness noted.

“The window is typically late summer to fall, and we see multiple crews working in there during that time frame,” he said. “Some areas you can work year ’round, but most areas have restrictions.”

Not long ago, AAPG member Peter Dea, president and CEO at Denver-based Cirque Resources, noted that the Rockies continues to suffer from over-regulation of federal agencies.

“We’re very conscious of protecting the environment,” Ray noted, “but some people don’t want any activity at all, so it’s always a challenge there.

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