A joint government, industry and university team investigating gas hydrate deposits under Alaska’s North Slope hit the jackpot in mid-February, when the BP-operated Mount Elbert stratigraphic test well successfully penetrated several hundred feet of hydrate bearing sandstone at Milne Point. Data obtained from the well will enable the scientists engaged in the project to make a more accurate evaluation than ever before of the resource potential of gas hydrates.
“With this project we have significantly increased our understanding of gas hydrate-bearing formations on the Alaska North Slope,” said Scott Digert, BP resource manager and the gas hydrate project’s technical adviser. “The results also illustrate the value of collaborative research,” he said.
Gas hydrate consists of a white crystalline substance that concentrates natural gas by trapping methane molecules inside a lattice of water molecules (methane is the primary component of natural gas). The hydrate crystals remain stable within a certain range of temperature and pressure, but when decomposed the crystals yield about 164 times their volume in methane.
Under the North Slope the gas hydrates permeate relatively shallow sandstones in large trends that straddle the base of the permafrost, around 2,000 feet below the ground surface. And the ability of the hydrates to concentrate natural gas gives rise to some huge estimates of in-place natural gas locked in the hydrate deposits — the U.S. Geological Survey has estimated that those North Slope hydrates may contain as much as 450 trillion cubic feet of methane.
But, although gas hydrates occur in many parts of the world, on ocean floors as well as in areas of permafrost, no one has ever succeeded in continuously producing natural gas from the hydrates. And the economic feasibility of exploiting the hydrates remains unknown.
U.S. government fundingThe huge resource potential of gas hydrates, however, has spurred the U.S. government into funding research into the feasibility of producing natural gas from the hydrates, and the U.S Department of Energy is funding the estimated cost of $4.6 million of drilling the Mount Elbert well. The government wants to understand by 2015 how much of the North Slope in-place gas hydrate resource might be recovered, Ray Boswell, DOE methane hydrates technology manager, said.
The North Slope team has spent the past few years on the first phase of its project, modeling gas hydrate reservoirs, modeling potential ways of producing gas from the hydrates, developing seismic techniques for finding hydrate deposits and mapping potential North Slope hydrate accumulations. Those hydrates lie close to the existing oil industry infrastructure, in a geologic setting where production might be feasible.
“What we believe is that the arctic gas hydrates within sand reservoirs, particularly like the ones we’ve examined on the North Slope of Alaska in this project, are the most favorable for production,” said Timothy Collett, Ph.D., a world-renowned gas hydrate specialist with USGS and a member of the North Slope team.
And the Arctic provides a very good natural laboratory to cost-effectively obtain data from a naturally occurring gas hydrate accumulation, Boswell said.
First test drillingHaving completed the “desktop phase” of the North Slope gas hydrate research, the drilling of the Mount Elbert stratigraphic test well represents the point at which theory starts to turn into practice. The purpose of drilling the well was to test the seismic techniques used to locate gas hydrates and to obtain detailed data about an actual gas hydrate deposit.
“This is an opportunity to gather the fundamental formation and fluid data that we need to help us really understand the potential performance of the reservoir,” Digert said.
Mount Elbert is one of many prospects within what is known as the Eileen trend, one of the two known gas hydrate trends in the central North Slope. Mount Elbert, individually, represents a relatively modest-sized hydrate accumulation but provides a well-defined target for the stratigraphic test, Collett explained. And BP was able to provide seismic data for the Mount Elbert location.
The team used that seismic data to make some predictions about the prospect and then drilled the well to see whether the predictions would prove correct.
“As it turned out our predictions were very correct,” Boswell said.
“We did confirm the presence of gas hydrates in our two primary target zones that we were calling the C and B intervals in the Sagavanirktok group,” Digert said.
Drilled to 3,000 feetDoyon Rig 14 drilled the well to a depth of 3,000 feet from an ice pad 1.4 miles south of the Milne Point B pad, northwest of the Prudhoe Bay oil field. Drilling from an ice pad was necessary because there are no suitable hydrate prospects below any existing gravel drilling pad, Digert explained.
The drillers used an oil-based drilling mud to avoid destabilization of the gas hydrates by the salts within the more conventional water-based mud. And, also to avoid damage to the hydrates, the mud was cooled to about 30 degrees Fahrenheit. A wireline coring system enabled rapid recovery of core from the well, again to ensure that intact hydrate samples could be retrieved for laboratory testing. Several drilling service companies assisted with the drilling and sampling operation.
Once the hydrates samples were recovered they had to be kept cold, to prevent them from decomposing.
In addition to providing samples of gas hydrate-bearing rock, the well enabled a verification of the petroleum geology of a gas hydrate deposit in a relatively shallow reservoir setting.
“We penetrated in the first core a fairly hard shale layer which gave us more confidence that there may be an adequate (reservoir) seal in the shallow sediments,” said Project Manager Robert Hunter of ASRC Energy Services.
Following completion of the coring from the well, the team ran a full suite of well logs, followed by a small-scale “micro-dynamics” test of how the gas from the underground hydrates would flow.
Invaluable dataThe well cores, log data and flow test are providing a wealth of information, to enable a better understanding of the potential for gas hydrate production, both on the North Slope and elsewhere.
“We’ve got a gold mine of data,” Boswell said.
The team will now investigate that data to determine, for example, the precise characteristics of the Mount Elbert reservoir and to refine the models for possible gas hydrate production. That investigation might take up to a year, at which point the team will make a decision on the next phase of its project, Digert said.
The plan for that next phase is currently unknown, but could involve drilling another well, perhaps to do a full-scale flow test from the hydrates. A full-scale production test from gas hydrates has never been done and would require new technologies, Hunter said. Another complication arises from the probable need for a gravel drilling pad for a sustained gas hydrate test well, Digert said.
But meantime the team feels more than satisfied with the results from the Mount Elbert well.
“The big deal here is to cut that core and recover it to the surface with stable hydrates in that cold mud, then to run all of our logging tools … and gather those physical and petrophysical data from the zone and … do the (small-scale) flow tests,” Digert said.
The well has provided a confirmation of the model for the seismic identification of gas hydrate deposits, enabled the first ever retrieval of North Slope gas hydrate well cores and the second ever test anywhere in the world of the pressure response of gas hydrates, Collett said.