What’s new in exploration

In late February 2012, the U.S. Geological Survey (USGS) issued the first estimates of technically recoverable onshore oil and gas from shales on Alaska’s North Slope, as part of the National Oil and Gas Assessment Project. USGS finds there is a maximum potential of 2 Bbbl of oil and 80 Tcf of gas recoverable from kerogen-rich shales spanning the National Petroleum Reserve in Alaska. This makes Alaskan shale oil the second-largest unconventional crude resource in the U.S., after the Bakken formation in North Dakota. Alaska’s conventional oil production in Nov. 2011 was 19.54 MMbbl; natural gas production was 32.306 Bcf, almost all of which came from the North Slope.

Methodology. Oil and gas generated in kerogen-rich rocks that remain trapped within the original source rock and do not migrate, are considered “continuous resources.” These are large volumes of rock, pervasively charged with oil or gas, that do not depend on the buoyancy of oil or gas in water, and cannot be defined by down-dip water contacts. In 2005, James W. Schmoker published a 10-page report, U.S. Geological Survey Assessment Concepts for Continuous Petroleum Accumulations, which describes the fundamental concepts supporting USGS resource assessments of continuous accumulations. The assessment is limited to the quantity of oil and gas that can be added to reserves in approximately one generation, defined as a forecast span of 30 years.

Stacked source rocks. The recent USGS study assessed three main source rocks on the North Slope: Triassic Shublik formation, the lower part of Jurassic-Lower Cretaceous Kingak shale, and Cretaceous pebble shale unit-Hue shale, together called the Brookian shale.

The Shublik formation contains mostly Type I kerogen (sapropelic, predominantly algal and highly likely to generate oil) and Type IIS kerogen (mixed terrestrial and marine—planktonic—that can generate waxy oil, with sulfur). Oil that migrates from the Shublik into conventional accumulations is low gravity (23°–39° API) and contains high (>1.5%) sulfur. Examples include the Kuparuk River (21°-27° API) and Northstar fields (43°-45° API).

The Kingak and Brookian shales contain a mixture of Type II and Type III kerogen (derived from woody, terrestrial material that usually generates gas). Oil that migrates from these source rocks is high gravity (35°–42° API) with low (<0.3%) sulfur. The Kingak shale is the source of the high-quality, 45° API oil in the Alpine field.

Proving the concepts. Recent well tests demonstrate hydrocarbon flow. The Kemek gas discovery on the eastern North Slope flowed 12 MMcfd from the Shublik shale. Production tests of the first two Gull Island exploration wells, drilled in 1976 and 1977, flowed at 1,144-2,971 bopd from the Shublik shale. The West Kuparuk well tests were in the same range.

Several independent exploration companies have amassed significant acreage in North Slope shales, chiefly Texas-based Great Bear Petroleum (with an Anchorage office), Denver-based Armstrong Oil & Gas Inc. and San Diego-based Royale Energy, Inc.

Great Bear Petroleum controls about a half-million acres with oil and gas shale potential on the North Slope, most of which were acquired in Alaska’s October 2010 North Slope lease sale (99 tracts for $7.7 million). In September 2011, Alaska Department of Natural Resources’(ADNR’s) Paul Decker told members of the Alaska Geological Society that his colleagues’ jaws dropped when they “saw what Great Bear was planning.”

At the most recent North Slope lease sale in December 2011, the ADNR Division of Oil and Gas announced that Great Bear Petroleum had 32 winning bids, for 46,000 acres, at a cost of $2.9 million. On two tracts, Great Bear bid $40.11/acre, just $0.01/acre more than newcomer Royale Energy.

As of February 2012, Great Bear plans to drill four test wells off gravel pads near the Dalton Highway this winter season. 

Armstrong Oil & Gas, bidding as 70 & 148 LLC, dominated two consecutive North Slope areawide lease sales. In October 2008, the company won 49 tracts for $4.3 million. In Oct. 2009, it was the successful bidder on 68 tracts, totaling $7.6 million. In March 2011, Armstrong transferred a 70% working interest in all 494,211 acres acquired in the 2008-09 sales to Spain’s Repsol YPF. The companies agreed to a “broad-reaching exploration and development program,” with drilling set to begin soon. Repsol said in a press release, “The North Slope of Alaska is an especially promising area … as it has already shown to be oil-rich and carries low-exploratory risk.”

Meanwhile, Armstrong is rebuilding its acreage position. In the December 2011 sale, the company successfully bid on an additional 11 tracts, covering 37,000 acres, for $2.15 million. Armstrong holds 107,000 acres on the North Slope.

Royale Energy was high bidder on the largest total acreage in Alaska’s Dec. 7 North Slope lease sale, taking 60 tracts in three blocks that cover more than 100,000 acres for $2.7 million. Royale is considering several potential partners, according to its vice president for exploration and production, Dr. Mohamed Abdel-Rahman. The company plans to drill as many as six evaluation wells next winter, two on each of its three lease blocks. Last month, Abdel-Rahman told the Anchorage Daily News, “The potential reward in Alaska is huge. No other shale opportunity comes close to this, not only in the Lower 48, but also in other parts of the world that we can access. This is a prime shale play.”  

LITERATURE CITED
Houseknecht, D.W., et al. 2012, Assessment of potential oil and gas resources in source rocks of the Alaska North Slope, 2012: U.S. Geological Survey Fact Sheet 2012–3013, available online at http://pubs.usgs.gov/fs/2012/3013.