Washingtons Columbia Basin, where the first drilling projects in decades raised hopes last year for a natural-gas strike, has yet to become the site of a producing well, though some drillers still believe the basin has potential to yield large reserves.
EnCana Corp., of Calgary, Alberta, said in October that its U.S. subsidiary had concluded its exploration program in the basin after drilling three wells there.
Each well indicated the presence of natural gas, EnCana said in its third-quarter earnings report. Although commercial flow rates were not established in these wells, there remains potential for large natural gas accumulations in the basin, which has only partially been tested.
EnCana, which has numerous exploration properties elsewhere, said that because its wells in the Columbia Basin werent a core part of its exploration efforts, it expected any future drilling on its sites there likely would be funded by third-party capital.
As a result, EnCana has no immediate plans for additional drilling.
Delta Petroleum Corp., of Denver, plans to drill whats being called the Gray 31-23 well next year in its 35,000-acre Bronco prospect, which is part of a huge swath of land in the lower central part of the state that industry geologists believe could be overpressured with natural gas deep beneath the earth.
We will not drill that well until we have a partner; were hoping to have some news on that by the end of the year, says Andrea Brown, manager of investor resources for Delta. While Delta also has plans for a second well in the basin, Brown says she expects the company will drill just one well next year and will evaluate the results from it before drilling a second well. She adds that drilling in the basin is expensive, in part because cracking through thick layers of basalt that overlay gas-bearing sands is difficult. It costs $15 million to drill a well there, she says.
Industry officials say that if commercial extraction ever is done in the Columbia Basin, revenue would flow into state coffers, and many goods and services would be purchased in communities in the region.
On Nov. 8, Delta, which has about 450,000 acres of land under lease in the basin, said in its quarterly earnings release that, The companys primary objectives in the Columbia River Basin are the tight gas sands of the Roslyn formation, which is approximately 4,500 feet thick. In tight, or hard, sands, gas doesnt flow as readily as it does through loose, beach-like sand, and developing gas fields in tight sands can require drilling numerous wells.
Delta said that based on its geologic interpretation and analyses, two of EnCanas three wells either didnt reach the Roslyn formation or encountered only a few hundred feet of it. Delta said it believes that to test the Roslyn formation fully, a well should be drilled completely through the formation.
It said that Shell Oil Co., of Houston, drilled in the 1980s a well known as the BN 1-9 that produced about 5 million cubic feet per day of natural gas even though it only went through two of some 33 layers of sand in the Roslyn formation.
The company remains optimistic as to the potential of the basin, Delta said.
In August, Exxel Energy Corp., of Houston, announced it had raised $14.5 million (Cdn.) in a private-placement financing and had bought an interest in leases in the basin that cover 390,000 acres. The $13.8 million (U.S.) acquisition included an interest in the Brown 7-24 well, near Mattawa, Wash., that was one of EnCanas three wells, Exxel said. Exxel also said it had entered into an acquisition exploration agreement with EnCanas U.S. subsidiary and two other parties that covers certain areas there.
We remain very encouraged with the progress made in the basin to date and are excited about what we believe is world-class potential, Exxel CEO Cliff Adams said.
Exxel has hired William S. Lingley Jr., who was chief geologist of the Washington state Department of Natural Resources when the department auctioned drilling leases in Eastern Washington in October 2006, producing what Lingley called spectacular results. Bidders paid an average of $62.14 an acre for leases, compared with $2 an acre paid by some bidders in 1998.
Were very keen on the basin and are moving ahead in anticipation of staking several positions for additional drilling, Lingley, who is Exxels vice president of exploration in its western division, now says.
We dont interpret EnCanas results as being particularly negative, Lingley says. The results do support our approach to exploration in the basin.
Nonetheless, skepticism remains.
Eric Nuttall, a research analyst with Sprott Asset Management Inc., of Toronto, says Delta has searched for months for a partner to participate in its drilling project, but hasnt found one yet.
There seems to be a difference of opinion as to what the true prospectivity in the Columbia Basin is, Nuttall says. One side, EnCana, believes the gas isnt there. The other side believes the gas is there, but EnCana didnt truly prospect the area where the gas is most heavily concentrated.
Nuttall, who last year called one of EnCanas wells the most watched well in the entire oil and gas industry, now says the Columbia Basin has been a bit of a disappointment.
With natural-gas prices realized by producers having fallen to as low as $3 to $5 per 1,000 cubic feet, from $11 to $14 in late 2005, and with inventories of stored gas at high levels, industry doesnt have much incentive to drill exploratory wells in the basin, where costs are high, Nuttall says.
Yet, Lingley says the drilling industry is only in a brief holding pattern in the basin while the companies digest the results from the wells that have been drilled so far. Theres a tremendous amount of work that needs to be done. Theres gigabytes of information that must be looked at.
Exxel decided to become the operator of the Brown 7-24 well near Mattawa because some data gathered from that well still needs to be evaluated, says Lingley. He doesnt expect that any more drilling will occur for another four months, because drill sites would need to be permitted, environmental reviews would have to be wrapped up, and drilling rigs would need to be contracted for and moved into place.
Still, while Exxel has other projects in the Rocky Mountains and Nevada, I think the Columbia Basin remains our marquee play, Lingley says.
Every geologist from every company that has worked in the basin continues to believe in it, he says. He adds that it would be rewarding to be a member of the exploration team that unlocks the basins potential.
I love prospecting, he says. The basin is very exciting.
Unlocking the basins potential wont be easy. To reach the sandstone where the gas lays, drillers must drill deep, in addition to penetrating basalt.
EnCana, for example, planned to drill 14,000 feet down with its three wells, and all three were at or near their target depth, says Ron Teissere, the states oil and gas supervisor.
He adds that the reservoir rocks deep in the basin are of moderate to poor quality, being not very permeable, which would keep gas from moving through the rock readily, and not very porous, which means theres little room in the rock for gas to accumulate.
EnCana caught the drilling industrys eye with its projects because it did completion activities with its wells. That means a driller, after sinking a shaft, has seen enough encouraging signs to go to the added expense of putting casing in a well and performing tests to see if the well will be a commercial producer.
At its well near Mattawa, EnCana set off carefully targeted explosions to perforate the wells casing in a couple of places and begin to form channels into the sandstone formation, Teissere says. EnCana also did fracturing, in which a driller pumps hydraulic fluid or sand and hydraulic fluid into those channels under great pressure, fracturing rocksometimes for hundreds or even thousands of feetand creating pathways for gas to flow into the wells bore hole. Teissere says the results were either negative or not particularly encouraging.
At EnCanas Anderson 11-5 well, near Sunnyside, Wash., the company did some work while drilling, including opening up the drill stem by taking off the blowout preventer to see if gas would flow upward, Teissere says. The results were, as far as I know, not particularly exciting, he says. They did perforate it in one zone, but it didnt look to me like they got very much.
EnCana since has moved the drilling rig off of that well site, he says. If you think youll have more activity, you probably wouldnt do that because it costs a lot to move a rig, Teissere says.
EnCanas wells havent been closed properly, which involves plugging them with cement and then with a mixture of a gel and drilling mud, Teissere says. Other than Deltas well, no other drilling projects are planned currently that Teissere knows of, and he adds that the state isnt seeing a lot of demand for leases, although a lot of land was leased in the October 2006 auction, and much of it remains to be explored.
Contact Richard Ripley at (509) 344-1261 or via e-mail at firstname.lastname@example.org.
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