Expensive and usually remote Arctic oil and gas prospects and discovered fields offer aggressive operators potential production volumes that are difficult to match in warmer climates.

Probably the classic example of that potential shows up in Russia’s Shtokman field, with 113 Tcf of gas and 227 million bbl of condensate.

Even though that field — which probably won’t come on stream until 2013 — lies at about 73º north latitude, it will set a record only for offshore Arctic production when it starts moving gas and condensate.

The northernmost production record goes to Panarctic Oil Ltd. and its Bent Horn field on

ConocoPhillips is operator of Ardalin field in Timan Pechora province in Russia in partnership with Rosneft. (Photo courtesy of ConocoPhillips)
Cameron Island in the Canadian Arctic. Every summer between 1985 and 1996 the M.V. Arctic, a tanker built for the US Great Lakes and reinforced for Arctic work, would make two or three trips to the field to retrieve oil. That field, north of 76º north latitude, produced 2.8 million bbl of oil from Devonian carbonates below the southern margin of the Sverdrup Basin, according to a paper prepared for the 2005 American Association of Petroleum Geologists annual convention in Calgary. Kenneth Drummond of Drummond Consulting wrote the paper titled “Canada’s Discovered Oil and Gas Resources North of 60º.”

Arctic Circle
A lot more oil and gas lies above the Arctic Circle, a moving boundary at about 66º, 33 minutes, 39 seconds that keeps moving as the tilt of the earth’s axis changes. It represents the lowest latitude that has no sunset at the summer solstice and no sunrise at the winter solstice.

The US Geological Survey estimated a full 25% of the earth’s yet-to-be-discovered reserves lie under Arctic ice.

That information won’t start a gold-rush-style stampede to the far north. According to a report titled “Future of the Arctic — A New Dawn for Exploration” from Wood Mackenzie, most of the potential is in gas, most of the markets are far away and everything will drain an operator’s checkbook.

Of the 19 Arctic basins, 10 have no discovered resources and have been explored only minimally.

According to Wood Mackenzie, “Of these 10 basins, North Greenland can be excluded as a
BP’s Northstar project is on an island off the North Slope of Alaska. (Photo courtesy of BP)
viable play. Current technology cannot address the extreme weather conditions and thick pack ice which is present in this basin. East Central Greenland and the Hope Basin between Alaska and eastern Siberia can be excluded due to low prospectivity. The North Chukchi Sea can be excluded as this basin appears to be gas-prone with insufficient reserves to support a pipeline to Alaska or an liquefied natural gas (LNG) solution which can be deployed in the ice conditions.”

The more prospective basins are around Greenland and north of East Siberia, and large areas of many of the basins are covered with pack ice.

Wood Mackenzie added, “The killer issue for these basins could be that they appear to be largely gas-prone, and the only markets which they could reasonably reach in the current environments are in north Russian industrial cities such as Yukutsk and Norilsk.”

Unfortunately, gas prices in Russia are controlled by the state, and that controlled price is far below the range of US $6/Mcf to $8/Mcf that an operator would need to generate a 10% return on investment for delivery to local markets.

Free-market foreign destinations would require a price higher than $10/Mcf, and Gazprom is the only entity that can export gas from Russia.

Among eastern Siberian basins, only the Laptev Sea has the potential to offer a decent return. Prospects there would require $40/bbl oil to reach a 15% return rate.

Russia
The only developed areas in the Arctic are in Russia and Alaska. Russian production starts with the second-largest gas field in the world, Urengoy, with as much as 300 Tcf of gas. The Arctic Circle line cuts across the north end of the field and south of North Urengoy. (The largest gas field in the world is the combined North field offshore Qatar and South Pars offshore Iran.)

The field is in the mainstream of Russian oil and gas production, the Yamalo-Nenetz Okrug, which produces most of the nation’s oil and gas.

Development started spreading north onto the Yamal Peninsula with the discovery of
The Trans-Alaska Oil Pipeline moves oil from the largest fields in the United States to the lower 48 states. (Photo courtesy of BP)
Bovanenkovo gas field and is now driven by the need to replenish natural gas supplies as older fields decline. Among major production centers is the Yamburg gas condensate field.
According to a Gazprom survey, by early 2007 the peninsula was the site of 11 gas and 15 oil and condensate discoveries with a recoverable 367 Tcf of gas, 1.67 billion bbl of condensate and 2.14 billion bbl of oil. Among those fields, Bovenankovo, Kharasavey and Novoportovskoye fields hold reserves of 201.3 Tcf of gas, 734 million bbl of condensate and 1.7 billion bbl of oil. All three fields are operated by a Gazprom subsidiary.

A Gazprom press release also said, “In January 2002, the Gazprom Management Committee had identified the Yamal Peninsula as a region of Gazprom’s strategic interest. Commercial development of Yamal fields will help build up local gas production to 250 Bcm/year (8.8 Tcf/year). Accessing Yamal is of principled significance for securing gas extraction growth.”
Again, the lack of easy markets poses an obstacle. Gazprom wants to start production from Bovenankovo at rate of 530 Bcf a year in the third quarter of 2011 and ramp up to 4.9 Tcf a year.

To do that, however, Gazprom will have to build a 1,522-mile (2,451-km) gas pipeline, including a new line from Bovenankovo to Ukhta to the southeast in Komi province. All permits for that project have been approved.

Pipelines are the key, and they provide political leverage. Although initial production for the under-construction Northern European Pipeline will come from western gas fields in northern Russia, European demand will push Russian exports from nearly 5 Tcf in 2004 to an estimated 6.4 Tcf in 2010.

Eventually supplies for that climbing European demand will come from Shtokman field in the Barents Sea and from the Yamal-Nenetz area.

On the political side, Moscow already has cast doubt on plans to associate Shtokman gas with a LNG plant to export gas to the United States.

Non-Russian companies also are playing a part in Russian Arctic development.
Total signed the first production-sharing agreement involving foreign companies in Russia as it took a 50% share of Kharyaga field with Norsk Hydro as a 40% partner and Nenets Oil company with the remaining 10%. The field, about 56 miles (90 km) north of the Arctic Circle and 100 miles (160 km) north of Usinsk, started producing in 1999 in the Yamal-Nenetz Autonomous area.

The 1.18-billion-bbl field is facing some of the same political issues that have plagued the other two production sharing agreement areas, Sakhalin I and Sakhalin II.

Government inspectors filed claims that the organization is not making enough oil under the contract, and the government threatened to revoke the deal last year, charging the producing group burned off 60% of the produced gas instead of reclaiming it.

Farther to the west, ConocoPhillips and Rosneft are 50-50 partners in the Polar Lights Co., formed in 1992 to develop and operate Ardalin field in Timan Pechora province about 100 miles (160 km) southwest of Varandey on the Barents Sea.

The field started operations in 1992 and added three satellites, Oshkotyn, East Kolva and Dyusushev, since then. The combined operations reached a daily production of almost 13,000 b/d.

In 1994 ConocoPhillips (30%) signed a joint venture deal with LUKOil called OOO Naryanmarneftegaz to develop oil and gas in northern Timan Pechora. The companies anticipate first oil from Yuzhno Khylchuyu field northeast of Ardalin late this year.
The 610-million-bbl Prirazlomnoye field between Novaya Zemla island and mainland Russian illustrates some the difficulty of working in the Arctic. The project was supposed to start in 2003 and progressively has moved backward to at least 2008 and probably beyond.

It uses a gravity base in 66 ft (20 m) of water and will use the old Hutton tension-leg- platform topsides. Plans called for up to 40 wells, including 19 producers, all drilled from the platform with a capacity of more than 160,000 b/d of oil and 35.3 MMcf/d of gas.
The offshore site is ice-bound 110 days of the year, and even though landfall is 37 miles (60 km) to the south, two ice-breaking shuttle tankers will pick up oil from the 710,000-bbl storage tanks in the base and carry it 683 miles (1,100 km) to a loading platform in Pechenga Bay north of Murmansk. From there the oil will load onto supertankers for export.
The team is just assembling the base and topsides this year.

Norway
Norway has no production yet above the Arctic Circle, but its giant Snøhvit gas field is scheduled to start up in December this year piping offshore gas from remotely operated subsea wells to an onshore LNG plant on Melkoya Island near Hammerfest for export.
The massive offshore field contains 6.8 Tcf of natural gas, 113 million bbl of condensate and 5.1 million tons of natural gas liquids sitting in water up to 1,132 ft (345 m) deep.
It will export 70 cargoes of LNG a year, or 4.1 million tonnes, and more than 3.1 million bbl of condensate.

Next in line may be Eni’s Goliat discovery, the first oil field discovered in the Norway segment of the Barents Sea. The Norwegian Petroleum Directorate first estimated 250 million bbl of oil for the field, but subsequent drilling shows it may be larger than that. Eni plans to complete its development concept for the field this year.

Approximately, 68 miles (110 km) northeast of Goliat and 40 miles (65 km) north of Honningsvag, Norsk Hydro logged a discovery at its Nucula prospect with its 7125/4-1 well. It found oil and gas in early Triassic in the 5,223-ft (1,592-m) well.

Canada
Although Canada has minimal current production above the Arctic Circle, the capacity and capability are in place on the Mackenzie Delta and in the Colville Lake area, but the gas-prone region needs the proposed $3 billion Mackenzie Valley pipeline to move gas to the heavy oil fields to the south.

The only production feeds some 3,500 people in and around the town of Inuvik from Ikhil gas field. The field has produced more than 3 Bcf of gas for local consumption.

The Beaufort Sea north of Canada has been explored enough to find some 66 million bbl of oil and 1.4 Tcf of gas in the Mackenzie Delta-Beaufort Sea area and another 332 million bbl of recoverable oil and 17.4 Tcf of gas in the Sverdrup Basin to the northeast.

One of the operators on the Mackenzie Delta is ConocoPhillips. It has been in the area since the 1960s with involvement in 43 significant discovery licenses and one exploration license. It operates 11 of the licenses.

Among the operated licenses, it has a 75% interest in Parsons Lake field with ExxonMobil. That 1972 discovery about 45 miles (72 km) north of Inuvik is one of the three anchor projects for the 1.2 Bcf/d Mackenzie Valley pipeline.

ConocoPhillips also operates Amauligak with Chevron, Anadarko, Imperial Oil and others as partners. This is the largest field yet discovered in the area and lies about 31 miles (50 km) offshore.

According to Arthur Mason in his “Encyclopedia of the Arctic 2004,” the Mackenzie Delta-Beaufort Sea area contains 53 Tcf in undiscovered gas potential.

Combined with 63 Tcf of gas in northern Alaska, 32 Tcf in submerged lands in the Beaufort Sea and 60 Tcf on the shelf of the Chukchi Sea, the 208 Tcf of Arctic gas represents 40% of the total US undiscovered conventional gas resource base of 526 Tcf.

Alaska
Oil production on the North Slope of Alaska comes with 6 Bcf to 8 Bcf of gas a day, which is used for power or reinjected to retain pressure for oil production. That gas also will need a pipeline to convert it from a resource to reserves.

ConocoPhillips is the largest oil and gas producer on the North Slope of Alaska and the largest owner of undeveloped leases with some 1.7 million net acres. Of that, approximately 1.2 million acres are in the National Petroleum Reserve-Alaska.

The Houston company holds 36.1% of BP-operated Prudhoe Bay field, the largest in the United States. It includes satellite fields and the Greater Point McIntyre area fields. That area has more than 1,000 wells, and it still isn’t drilled up. The field reached peak production at more than 1 million b/d of oil in 1988 and dropped to 383,000 b/d of oil in 2005.

The impact of Arctic production showed clearly last year when corroding pipelines forced BP to take 200,000 b/d of production offline. The resulting rush to replace that lost production increased oil prices around the world.

BP also operates Northstar, the northernmost production on the North Slope in the Beaufort Sea.

ConocoPhillips operates the Greater Kuparuk area with a 55.3% interest. It’s the second largest producing onshore oil field in the United States with its four satellite fields. The field produced its 2 billionth bbl of oil in July 2005 and averaged 65,000 b/d for the year.

ConocoPhillips also operates Alpine field some 40 miles (64 km) west of Kuparuk. It’s the largest onshore field discovered in North America in the past 10 years. It averaged 76,000 b/d in 2005 with production anticipated to increase further.

From the tightly packed area surrounding Prudhoe Bay, exploration in Alaska is rapidly moving to the west as far as Barrow, and the US Minerals Management Service has held hearings about rejuvenating exploration in the Chukchi Sea between the United States and Russia.

The areas between countries are highly contested, not only because of oil and gas potential, but also for fishing and mineral rights and transportation rights.