During a luncheon talk at the 2006 AAPG Annual Convention in Houston, speaker Peter Dea predicted the Rocky Mountains would become the kingpin of domestic natural gas production owing principally to unconventional reservoir development.
The region appears to be well on the way to achieving this status.
The record-breaking crowd of 750 attendees that assembled at this year’s annual 3-D seismic symposium sponsored by the Rocky Mountain Association of Geologists was indicative of the industry’s near-frenzied activity level in the Rockies.
The attendance numbers represented an increase of 150 over the previous year -- the largest one-year increase ever, according to Randy Ray, president of Julander Energy.
“We see a steady level of activity in the Rockies,” said Dea, president and CEO at start-up company Cirque Resources.
“There’s a tremendous amount of development drilling in the Powder River Basin, Pinedale anticline, Jonah, Piceance, parts of the Uinta, the Williston Basin, parts of the Wind River Basin -- basically all the basins are seeing a steady level of development activity,” Dea noted.
“There’s still another decade’s worth of development drilling in select fields in a lot of those basins.”
The drilling and development action is concentrated on resource plays, according to Ray. Many of these are supported with the latest technology, such as 3-D seismic and micro-seismic measurements trying to map the fractures while the wells are being fraced.
There’s seemingly something here for everyone: Tight gas sands, shale, coalbed methane, thrust belt exploration.
A caveat: The economics are no slam-dunk.
The Piceance Basin is a good example.
Pumping in the Piceance
About 100 wells are drilling for gas in the tight Mesaverde sands in the Piceance Basin, according to Steve Cumella, senior geologist at Bill Barrett Corp., which is active here and several other locales in the Rockies. Production and activity in the Piceance have escalated this year, and production from the basin tallies about one Bcf/day from wells that average 8,000 feet in depth.
“The average reserves per well may be 1-1.5 Bcf, and well costs are about $1.5 to $2.5 million,” Cumella said, “so the economics are not real good.
“The appeal of places like the Piceance is predictability -- there’s basically no dry hole risk in a lot of these areas,” he noted. “You can plan a big program, and as long as your wells are economic you can predictably add reserves.
“In some of the Rockies plays where you’re dealing with resource plays, there can be very large areas that can be developed with relatively little dry hole risk,” Cumella said. “The challenge becomes making the wells economic either by keeping well costs as low as possible or by using technology to increase the well’s productivity, or both.”
Much of the tight gas in the Rockies is found in reservoirs comprised of fluvial sandstones that are discontinuous and have very low permeability. This results in limited drainage area for a given well, so well spacing of 20 acres or less is pretty much the norm.
“In much of the Piceance the well density is 10 acres,” Cumella said. “If you have a section of land of 640 acres, that would be 64 wells. At a Bcf or greater, you’d be looking at 60-100 Bcf per section, so that’s the sort of appeal you have here with high well density.
“If you look at where the big rig counts are and high levels of activity -- Jonah, Pinedale, Piceance, parts of the Green River Basin, Natural Buttes -- there’s a pretty common theme of large stratigraphic intervals of gas saturated sandstone with high well densities.”
‘A Lot of Frac Work’
In fact, Ultra Petroleum has even drilled pilot wells on five-acre spacing at Pinedale field in the Greater Green River Basin in southwestern Wyoming. Half of the field has already been approved for 10-acre density, according to Steve Kneller, vice president of domestic exploration.
Ultra currently operates 12 of the 30 rigs running at Pinedale, where the wells average 14,000 feet in depth, and drill and completion costs register a cool $6-$7 million. The company also controls a sizeable position in the active Jonah natural gas field on the south edge of Pinedale.
The productive discontinuous alluvial sand bodies in the Lance Pool section at Pinedale are probably no more than one-two acres in size, yet per well average reserves last year tallied seven Bcf, Kneller noted. This can be credited to reservoir height, given that the average section in the overpressured, super-tight rock (permeability = two-three micro-darcies) measures about 5,500 feet thick. The sands typically are stacked as distinct packages in the reservoir.
“We’re completing the wells with a large number of frac jobs,” Kneller said. “Each is fairly small, but 25 frac jobs per wellbore turns into a lot of frac work. We do them sequentially and open up the whole 5,500-foot section.”
Ultra is the largest operator and owner on the Pinedale anticline, where more than 600 producing wells were kicking out 700 MMcfd from the field at the end of 2006.
A year-end reserves assessment by Nederland Sewell tagged gas in place at Pinedale at 48 Tcf, according to Kneller.
“The estimate for recoverable resources as of year-end was 27 Tcf,” he said. “That’s down to 10-acre well density, and if we go to five it should be more than that. At year end, Pinedale was rated the number two field in the U.S.”
Pinedale was first mapped in the 1920s, and the first well was drilled in 1939. Twenty-something wells were drilled -- all having gas shows -- between 1939 and 1997 when Ultra drilled the first commercial well.
“It was a resource where people knew the structure was there, knew the gas was there, and just couldn’t figure how to get it out,” Kneller said. “It took a better understanding of the geology and geophysics and the completion techniques,” he added, “and getting the thoughts together in the same room at the same time to get that ‘Aha!’ moment that made the difference between what was an uneconomic field and what is now a huge field.”
Buzz in the Baxter
In the late 1980s and early 1990s, the Bakken shale was the focus of considerable activity in the Rockies. The action concentrated on the upper Bakken, which was marginally economic.
In 1995, independent Dick Findley drilled a well in eastern Montana that experienced a big drilling break and telling mud logs in the fractured dolomite middle section of the Bakken -- and a mental light bulb went off. This became the defining moment that eventually led to development of the multi-million barrel Elm Coulee oil field.
(Findley received AAPG’s 2006 Explorer of the Year award in recognition of his work there.)
Today, horizontal wells kick out sizeable volumes of oil from this segment of the Bakken, and Findley noted the play started an incredible amount of activity in North Dakota.
“There are some mixed results in North Dakota, and we’re just starting to see some very nice wells come on,” Findley said. “The operators that are starting to be rewarded by going up the learning curve and sticking with it will be rewarded and remain active.”
Fred Julander at Julander Energy predicts shales may surprise everyone, with the extent and magnitude of recoverable resources just now starting to be tapped.
In fact, there’s considerable buzz about the first horizontal well now being drilled in the Baxter shale. It’s a Questar effort in the Vermillion Basin in southwest Wyoming.
Just don’t expect many details -- yet.
“It’s a tight hole,” said Vinnie Rigatti, general manager legacy division at Questar. “The well is targeting a specific zone within the overpressured Baxter.”
The Baxter interval is 3,500 feet thick, and the company has completed at various points within that interval throughout its 18 producing wells.
Prior to drilling the horizontal well, Questar completed the Trail 13C-15J vertical well, which reached TD of 13,700 feet and came on exceptionally strong compared to the previous 17 wells the company drilled in the play. It’s thought the well either intersected a vertical fracture system or fraced into such a system, Rigatti said. The well produced more than 65 MMcf of gas during its first 11 days on production.
Horizontal wells are noted for increased reservoir contact. The thinking at Questar is that the vertical fractures in the Baxter interval are a big part of the producing mechanism, so the anticipation is that the horizontal wellbore will intersect more vertical fractures than a vertical well.