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Vol. 24, No.36 Week of September 15, 2019
Providing coverage of Alaska and northern Canada's oil and gas industry

54 tcf possible

USGS estimates undiscovered, recoverable gas trapped in North Slope hydrates

Kay Cashman

Petroleum News

An estimated 53.8 trillion cubic feet of undiscovered, technically recoverable natural gas is trapped within methane gas hydrate formations in Alaska’s North Slope, the U.S. Geological Survey says in a new geology-based assessment released Sept. 10.

The area assessed extends from the National Petroleum Reserve-Alaska on the west through the Arctic National Wildlife Refuge on the east and from the Brooks Range northward to the state-federal offshore boundary, 3 miles north of the coastline. The area covers 41,089 square miles and encompasses federal, state, and Native lands

Access to 3D seismic mapping, along with a greater understanding of gas hydrate reservoir properties, yielded estimates that were more precise, the federal agency reported.

The assessment methodology assumes that the resource can be produced by existing conventional technology. To date, USGS says, there is no known commercial production of natural gas from gas hydrates and the commercial viability of hydrate reservoirs is not yet known.

That assumption is based on both limited field testing and numerical production models of gas hydrate-bearing reservoirs. No analysis was provided in the report as to whether it would be profitable to produce the resources.

There have been two methane hydrate wells drilled on the North Slope, with the Eileen gas hydrate trend being the primary target of both: One, the 2007 Mount Elbert stratigraphic test well enabled the gathering of gas hydrate cores and evaluated the production characteristics of the hydrates that the well penetrated; the second, the Ignik Sikumi well, drilled in 2011-12, tested short term gas production using a couple of production techniques.

The next phase of the project will include drilling at least one more well in the winter of 2021-22, followed by a production testing program in 2021 or 2022.

The permafrost associated hydrates under the North Slope, while extensive, exist in a series of discrete sand reservoirs at various depths and locations and are bounded by faults and downdip water contacts. A production well would obviously need to be located where it can penetrate one or more of these reservoirs.

Group effort

In March, the Department of Energy’s National Energy Technology Laboratory published information on the Ignik Sikumi well. The drilling of the well was part of a project aimed at testing the production of natural gas from hydrate as a potential future commercial gas resource.

NETL had formed a partnership with Japan Oil, Gas and Metals National Corp., USGS and Petrotechnical Resources of Alaska, or PRA, for the drilling of the well. BP, operator of the Prudhoe Bay unit, oversaw the drilling.

The NETL presentation says that the methane hydrate research team had considered a test site on unleased land on the North Slope but had discounted that possibility because of high logistics costs, the lack of support infrastructure, an uncertain regulatory environment and relatively high geologic risk. Instead, the team, in cooperation with the Prudhoe Bay working interest owners, opted for a location on the Slope’s gravel road system in the western part of the unit. The location is clearly understood from a geologic perspective, has multiple hydrate reservoir zones and would minimize any interference with operations in the unit.

The location will enable production testing for at least six months, and optimally 18 to 24 months.

The testing will focus on gas production through depressurization of the hydrates, a technique that testing in the Ignik Sikumi well indicated to be particularly favorable. However, the emphasis will be on the science of hydrate production rather than demonstrating production rates. And thermal, mechanical and chemical well stimulation technologies will be available, as necessary. The intent is to use proven oilfield technology where possible, NETL says.

Best available science

USGS is “committed to providing the most up-to-date, publicly available, peer-reviewed estimates of the nation’s energy resources,” Walter Guidroz, program coordinator for the USGS energy resources program, was quoted as saying in the Sept. 10 release. “As more information becomes available, we sometimes need to revise our assessments to ensure they reflect the best available science.”

The report updates a 2018 USGS assessment that estimated about 85 trillion cubic feet of undiscovered, technically recoverable gas resources within the gas hydrates of the North Slope. It is this refined analysis that yielded a smaller gas volume estimate in the 2018 assessment when compared to the 2008 assessment, USGS says.

Gas hydrates are naturally occurring, ice-like solids in which water molecules trap gas molecules in a cage-like structure. They are only stable within a narrow range of temperatures and pressures and are usually found in seafloor sediments and in Arctic onshore permafrost environments.

Although many gases form hydrates in nature, methane hydrate is by far the most common, and there are thought to be significant natural gas resources contained in the world’s gas hydrate accumulations.

In addition to the North Slope research, USGS says it has been participating in and sometimes managing large-scale drilling projects that investigate the resource potential of gas hydrate throughout the United States, as well as in offshore India and the Gulf of Mexico.

The USGS gas hydrate project conducts multidisciplinary field studies, participates in national and international deep drilling expeditions, and maintains a laboratory program focused on hydrate-bearing sediments, the agency says.

“The study of gas hydrate as an energy resource is still an emerging field,” USGS scientist Tim Collett, lead author of the assessment, says. The agency has been conducting research on gas hydrates since the 1980s. “Every time we conduct these assessments, we incorporate more and higher quality data, and our estimates become more precise.”

Nanushuk, Tuluvak-Schrader Bluff-Prince Creek, and Sagavanirktok

According to its Sept. 10 release, USGS oil and gas assessment methodology begins with the volume of rock to be assessed in the total petroleum system, or TPS, being apportioned into subunits called assessment units, or AUs. The assessment procedure generally estimates the number and size of undiscovered hydrocarbon accumulations and assesses the geologic risk associated with each AU. The northern Alaska gas hydrate TPS includes Cretaceous and Tertiary reservoir rocks divided into three AUs, listed from oldest to youngest: the Nanushuk formation, the Tuluvak-Schrader Bluff-Prince Creek formations, and the Sagavanirktok formation.

Only gas hydrates below the permafrost section were assessed, thus limiting the AUs to the stratigraphic interval below the base of the permafrost and above the base of the gas hydrate stability zone. Free gas potentially trapped below the gas hydrate stability zone was not assessed.

Two critical parts of the USGS assessment procedure are the accurate predictions of the expected size and number of undiscovered hydrocarbon accumulations within each of the delineated AUs. This assessment “relied heavily” on the analysis of 3D seismic data acquired by industry, which were used to characterize the size, number, and distribution of gas hydrate accumulations in each of the three AUs, USGS says.

The minimum accumulation size considered was 30 billion cubic feet of technically recoverable gas. USGS scientists used established gas hydrate seismic attribute analysis techniques to identify 103 seismically inferred gas hydrate accumulations throughout the northern Alaska gas hydrate TPS. These seismically inferred gas hydrate accumulations were used in the latest assessment to estimate the size and number of gas hydrate accumulations in each AU.

Geochemical analyses of drill cuttings and core samples from wells drilled in state lands between the Canning and Colville rivers and within NPR-A indicate that the gas within the drilled and well log inferred gas hydrate accumulations is in part from thermogenic sources, with the thermogenic gas migrating from deeper sources, including known conventional oil and gas accumulations.

Thermal conditions conducive to the formation of permafrost and gas hydrates are believed to have persisted in the Arctic since the end of the Pliocene - about 2.58 million years ago

In addition, most permafrost associated gas hydrate accumulations probably developed from preexisting free gas fields that originally formed in conventional hydrocarbon traps and were later converted to gas hydrates upon the onset of glaciation and cold Arctic conditions, the Sept. 10 assessment says.

Large range of uncertainty

In its assessment summary, USGS said the estimated mean total for the three North Slope gas hydrate AUs is 53.8 trillion cubic feet of gas recoverable.

“These estimates are associated with large ranges of uncertainty, which reflect the immature stage of exploration for this potential resource and concerns associated with producibility of gas hydrates,” the agency says.

“Because of the remaining uncertainty associated with the producibility of gas hydrates, each AU probability was risked at a factor of 0.9, which resulted in the estimate that the total undiscovered gas resources at the F95 probability for each AU could be zero,” USGS says.

The agency’s Alaska assessment team includes Collett, Kristen A. Lewis, Margarita V. Zyrianova, Seth S. Haines, Christopher J. Schenk, Tracey J. Mercier, Michael E. Brownfield, Stephanie B. Gaswirth, Kristen R. Marra, Heidi M. Leathers-Miller, Janet K. Pitman, Marilyn E. Tennyson, Cheryl A. Woodall and David W. Houseknecht.

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