Note: this article is one of several feature stories in an issue titled “The Final Energy Frontier.”
Two summers ago, a premonition of sorts appeared in the windswept sage of Wyoming’s Upper Green River Basin. The rig that Questar Corporation used to drill its Pinedale deep well was big, but what lay beneath was truly remarkable. The well, which was finished this August, reaches nearly 20,000 feet down — more than three and a half miles — to tap tight-sands natural gas, one of several flavors of so-called “unconventional” gas.
The well punches through tight-sands deposits that Paul Matheny, Questar’s vice president for the Rockies, likens to “a 5,000-foot stack of big potato chips.”
“You drill through hundreds and hundreds of these sandstone deposits,” he says. “Each one of them doesn’t produce a super-large volume of gas, but they will combine to provide a viable gas well.”
The cost so far for the well, which has yet to produce anything: At least $10 million.
Though it may seem like trying to make a full meal out of scraps, the Pinedale well is the face of future drilling. “As conventional gas depletes, to replace it, you go to the places that aren’t developed, or aren’t completely developed yet, and that tends to be these unconventional reservoirs,” says Matheny. “And the majority of it is in the Rockies.”
The U.S. Department of Energy predicts that from now until 2025, as gas deposits in the Gulf of Mexico begin to be tapped out, “the largest increase in Lower 48 onshore natural gas production is projected to come from the Rocky Mountain Region, primarily from unconventional gas deposits.” Tight-sands gas, or “tight gas,” is found primarily in Wyoming’s Upper Green River Basin, the Piceance Basin in Colorado, the Uinta Basin in Utah, and the San Juan Basin in New Mexico; coalbed methane — another type of unconventional gas — is found in a much larger swath that runs from Montana to New Mexico.
Unconventional gas is far more expensive to reach than its conventional counterpart, but high prices are making that point moot. Questar and other companies, which have long drilled for tight-sands gas at shallower depths, are now contemplating deep wells to push for gas trapped at ever-greater depths.
Companies are “working their way toward the poorer and poorer quality stuff,” says Matheny. “Every little increment of increase in the cost of gas makes the next increment of poorer reservoir economic to develop.”
More wells, more damage?
Unconventional gas in any form, however, yields only to aggressive drilling and production, so it carries big environmental impacts. The harm caused by drilling for coalbed methane is legion, from brackish water being dumped over the land to contamination of drinking-water wells (HCN, 3/7/05: Wastewater goes unwatched). There could be five times as much tight-sands gas as coalbed methane, and tight-gas drilling, too, brings big environmental impacts.
The gas is wedged in tight pockets, so a single well can tap only a limited amount. “There’s three things they keep discovering,” says Peter Aengst, the Wilderness Society’s energy campaign coordinator. “There’s more gas than they thought; it’s tighter than they thought; and because it’s tighter, they have to do even denser drilling.”
In the Upper Green River Basin, gas companies, which currently are limited to one well for every 40 acres, are pushing for even closer spacing. EnCana Corp. and other companies have asked the BLM to approve an “infill” proposal for the Jonah tight-gas field outside of Pinedale, Wyo., that would allow 10-acre spacing in exchange for a habitat-mitigation fund. The impacts would be enormous. EnCana, which has already drilled about 600 wells, wants to drill an additional 3,100 wells, disturbing more than half of the land in the 30,000-acre field (HCN, 8/8/05: Industry walks a fuzzy line between preservation and extortion).
But at the same time that some companies are preparing for a full-court press on tight gas, they are working to reduce their impacts. Shell has developed a new proposal for denser well spacing in the Pinedale field, but multiple wells will angle outward from individual “megapads.”
“Regardless of if you drill 32 or 64 wells per (square mile),” says J.R. Justus, manager of the company’s U.S. onshore assets, “the plan would be to drill all of that from a single pad.” Justus says this “directional” drilling adds about $100,000 to $400,000 to the cost of each well, but it also means moving drilling rigs around less and disturbing less wildlife habitat.
Shell’s plan, says Aengst, provides a “model of how we could have more environmentally sensitive natural gas development.” It’s a fresh contrast to what he calls “the Jonah approach, which is to develop it up to the limit of what’s allowed, and then come back asking for more.”
But as gas production worldwide comes closer and closer to peaking, the turn toward more marginal supplies is also a sign that the industry is being driven by the law of diminishing returns. “There are vast volumes of gas in the Rockies,” says Questar’s Matheny. “The gas is there. The difficulty is that, as we drill these poorer and poorer quality reservoirs, it takes three or four wells today to deliver the same volume of gas that one conventional well would’ve yielded 10 or 15 or 20 years ago.”
Matt Jenkins is HCN associate editor.
This article appeared in the print edition of the magazine with the headline Tapping into energy’s fringe.
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