Providing coverage of Alaska and northern Canada's oil and gas industry
November 2022

Vol. 27, No.48 Week of November 27, 2022

This month in history: Hot ice project

Twenty years ago this month: Anadarko to core hydrate well south of Kuparuk

Kristen Nelson

Petroleum News

Anadarko Petroleum Corp. will be testing its modular Arctic platform south of Kuparuk this winter - and drilling the first completely cored gas hydrate well in Alaska

The Arctic platform (see story in Oct. 27, 2002, issue of PNA) will include a modularized state-of-the art mobile testing laboratory to test the hydrates, Anadarko’s Keith Millheim, Ph.D., told PNA Oct. 22. Millheim, the Houston-based manager of operations technology for Anadarko, is involved in both the Arctic platform and the hydrate coring project.

The hydrate coring is “a combination project for us. … It’s research on the hydrates as well as the Arctic platform prototype,” said Mark Hanley, Anadarko’s public affairs manager for Alaska.

When Congress made money available through the U.S. Department of Energy for a hydrate project in Alaska, Anadarko applied, as did BP, Millheim said. Both projects were funded (see story on BP project).

Anadarko’s project is to drill and core “one complete well through the potential hydrate section, which is down to about 3,000 feet. And to evaluate the cores,” Millheim said.

The Mallik hydrate wells have been drilled in the Canadian Arctic, but this well will be a first in Alaska, he said.

“No one has drilled, purposefully, a hydrate well… where you specifically core the hydrates and measure the hydrate content,” he said.

Coring a hydrate well

Anadarko’s proposal was in two phases. The first involved identifying a site with good potential for hydrates, and developing detailed costs and timing for the project. Anadarko also did some testing in Houston with frozen cores to determine how best to recover them.

In addition to coring the well, Anadarko will also evaluate the cores as they come out of the well, and Millheim said that is a unique part of the company’s project.

Anadarko has “constructed a one-of-a-kind mobile laboratory, which will be on the platform, which will evaluate all the properties of the hydrate as it comes out of the well,” Millheim said. The lab is modularized, he said, and can be moved by helicopter.

Anadarko’s gas hydrate prospect is south of the Kuparuk River unit and east of Meltwater. Bill Fowler, Anadarko’s Houston-based environmental supervisor, said the company is permitting three locations. The farthest is some 15 miles from infrastructure, the nearest seven to eight miles. The Alaska Division of Governmental Coordination has begun the Alaska Coastal Management Program consistency review for the project; comment deadline is Dec. 3. DGC said Anadarko has proposed as many as three exploratory gas wells in 2003 and 2004. The company said that if it gets all of its permits, it expects to be coring in March.

Next source of natural gas

Fowler said hydrates are probably going to follow coalbed methane as the next unconventional source of natural gas for the United States and, he said, hydrate research is probably where coalbed methane research was a decade ago.

Successful development of gas hydrates would make tremendous quantities of gas available.

A one-foot cube of hydrate ice, Millheim said, holds approximately 160 cubic feet of natural gas, plus a little bit of water.

Hydrates occur both in the Arctic and in deepwater. Japan, he said, is involved in the Canadian Mallik project and is looking at deepwater hydrates it controls as an energy source.

“It’s an immense resource. It dwarfs the known hydrocarbon resources on the planet,” Millheim said.

Twenty years ago this month: BP’s project to address technical, money issues

BP Exploration (Alaska) Inc. and Anadarko Petroleum Corp. both have gas hydrate projects underway on Alaska’s North Slope. (See separate story on Anadarko.)

The BP project, aimed at characterizing and quantifying the gas hydrate resource in the Prudhoe Bay and Kuparuk River area, is funded by the U.S. Department of Energy. Others contributing to the study include the U.S. Geological Survey, the University of Arizona in Tucson and the University of Alaska Fairbanks, BP petroleum geologist Bob Hunter told an American Association of Petroleum Geologists meeting in Anchorage in May.

The U.S. Geological Survey has estimated the North Slope basin gas hydrate resource at 590 trillion cubic feet in place, he said, “including the better-known Eileen trend gas hydrates (more than 40 tcf in place) and the lesser-known Tarn trend which may contain up to 60 tcf in place.”

These, he said, are “high quality reservoirs beneath existing facility infrastructure” where there is associated geological and geophysical data including extensive three-dimensional seismic.

Gas stored in clathrates

Hydrates are “naturally occurring ice-like solids which are composed of water and gas that trap gas molecules in a very efficient cage-like structure called a clathrate,” Hunter said. Clathrates store up to 164 volumes of methane gas — the most common gas hydrate — per unit of clathrate. Gas hydrates are stable offshore and in from 400 to 4,000 feet subsurface in Arctic permafrost, he said.

Both water and gas must be present to form the clathrate structure and gas hydrates, Hunter said: gas has migrated from deeper accumulations on the North Slope into regionally extensive reservoir-quality shallow sands and hydrates can help form their own trap.

But before the resource can be converted into reserves, he said, “significant technical and economic issues remain to be resolved.”

The project that BP is leading “will focus on reservoir characterization and productivity of the gas hydrate, mainly in the Eileen trend.” In phase one, 2002-04, the goal is to characterize the reservoir and fluids and calculate in-place resource.

“We will also study … the drilling, completion and production methodologies which then would apply to … phase two, to drill and production test.”

In the second phase, studies of reservoir fluids characterization will continue, the best areas for data acquisition will be selected and there will probably also be a short-term production test of the gas hydrate.

“We will drill, complete, acquire data and production test a dedicated gas hydrate well or well of opportunity” at Prudhoe Bay or Milne Point, Hunter said.

Long-term production testing in third phase

If phase two is successful, the third phase would continue earlier studies “proceed into additional probable long-term production testing operations and field test the best possible production methods for gas hydrates in association with moveable gas,” he said.

If phase three is successful, it could lead to a pilot development program.

The technical and economic issues which need to be resolved are very significant, Hunter said. Gas hydrates are an unconventional resource and unconventional resources typically require special technology to extract. Technical challenges include productivity, he said: “the primary unknown variable remains recovery factor.” Innovations in well completions will also be necessary, and non-conventional and multilateral well technology will probably be required, Hunter said.

“This could involve a significant amount of capital investment and technology investment. But what attracts us and the DOE to this research is the potential resource is very large.”



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