There’s a common misconception that, with production from major oil fields in northern Alaska declining, the North Slope has become a mature oil and gas province.
While it’s true that most of the larger and easier structural plays, particularly onshore, have been drilled, it’s also true that many stratigraphic, and some structural, plays have yet to be discovered or tapped, as evidenced by recent exploration and development activities, especially those close to existing oil and gas infrastructure.
Success in the Tarn and Alpine fields in the late 1990s moved exploration attention away from the big Prudhoe Bay-style structures toward stratigraphic traps on- and nearshore the North Slope. At the same time, the Northstar field, largely in state waters and the first Arctic project with a subsea oil pipeline, demonstrated continued success with structural reservoirs.
In general terms, people widely recognize the petroleum systems of northern Alaska as hydrocarbon-rich but reservoir-poor. So, with an abundance of excellent source rocks and a relative shortage of reservoir-quality rock formations, any isolated stratigraphic trap — a hydrocarbon trap formed by the juxtaposition of reservoir and seal rocks in the rock strata —stands a good chance of containing oil or gas.
Thanks to sustained high oil prices, new found capabilities of high-end 3-D seismic techniques to find stratigraphic traps, the use of horizontal drilling, including the latest advancements in hydraulic fracturing, improved the ability to produce from low permeability reservoirs, so more North Slope accumulation became economic to produce.
“Finding new oil with conventional ideas is good (nothing wrong with a nice Sadlerochit play like, say, Northstar),” former Division of Oil and Gas Director Ken Boyd told Petroleum News in an April 2011 e-mail.
But, he said, “Finding new oil with new ideas is even better. The reason being that new ideas open up new areas to exploration. Badami led to all the new exploration just west of Kuparuk. The lease sales we held after the Badami discovery prove that; lots of new leases on old shelf edges (which is where you find turbidites). Same with Alpine. The discovery of the Alpine sand (not a turbidite but a new play) is what enabled me to go to Shively and Knowles (at the time John Shively was commissioner of the Alaska Department of Natural Resources, of which the division is a part, and Tony Knowles, a Democrat, was governor) to push getting NPR-A open again. To their credit they did it (and that was a tough sell during the Clinton administration).”
Classic North Slope plays
The classic North Slope oil and gas plays occur along a structural high known as the Barrow Arch under the Beaufort Sea coast of the North Slope. These plays originated from the discoveries of oil fields like Prudhoe Bay and Kuparuk River many years ago.
The Prudhoe Bay field consists of a giant combined structural and stratigraphic trap involving Triassic sandstone reservoirs in a Mississippian to lower Cretaceous sequence of sediments known as the Ellesmerian sequence.
Companies are still looking for opportunities in the Ellesmerian, especially near existing oil and gas infrastructure, where there are numerous such structural plays.
The reservoirs for the Kuparuk River field involve sandstones in what’s called the Beaufortian or Rift sequence of Jurassic or lower Cretaceous age — the deposition of the sandstones is associated with rifting or pulling apart of the Earth’s crust that occurred during the opening of the Canada basin of the Arctic Ocean.
Although some of the Beaufortian sands can be thin and discontinuous, other areas of more continuous sands give rise to large reservoirs.
Basically, you get a huge range of potential sizes in the same rift breakup sequence but there are a lot of plays in the 20 million to 70 million or 80 million barrels size.
“There are still plays in the 300 million, 400 million or 500 million to a billion-plus size — they’re still out there, but they’re almost all stratigraphic,” Mark Myers, former director of Alaska’s Division of Oil and Gas and the U.S. Geological Survey, recently told Petroleum News.
Success with Alpine, the main field in the Colville River unit that came online in 2001, and its Beaufortian Jurassic sandstone reservoir, spurred interest in similar Jurassic plays. There is a series of upper Jurassic sands just below the Alpine sands: “There’s at least a billion barrels in place, we think, in that trend,” Myers said.
Because of the low permeability of the reservoirs in the Alpine play the gravity of the oil really impacts the ease of oil production. And the oil gravity depends on which of the multiple source rocks in the area generated the oil.
“The source rock’s critical and often you get multiple source rocks in a given area,” Myers said. “If you look at the Tarn play on the west side of Kuparuk you’ve got 38-to-37 API gravity in close proximity of 26-to-22 gravity in Kuparuk, because of changes in the sourcing.”
Brookian stratigraphic plays
There is a major Cretaceous and Tertiary sequence of petroleum bearing sedimentary rocks above the Ellesmerian and Beaufortian sequences in northern Alaska. Known as the Brookian sequence, this younger rock sequence extends all the way from the northern edge of the Brooks Range out over the North Slope and across the continental shelves of the Beaufort and Chukchi seas.
Stratigraphic plays involving topset or turbidite strata in submarine fans typify this Brookian sequence.
“Some of the … submarine fans are very large,” Myers said: “If you had reservoir quality and if you had closure you could approach the billion-barrel mark in some these if you had structural fill.”
Then there are other situations where you may find smaller fans with as little as 20 million barrels of oil and where several smaller fans stack together the combined volume of oil could reach around 100 million barrels.
However, production problems in the eastern North Slope Badami field (see page 42) have shown that the Brookian plays aren’t without risk. And compaction of reservoir rocks at depth may prove problematic.
“But there are some good looking fans as well,” Myers said. Some of the younger Brookian sandstones contain particularly clean sand because they’ve reworked older sediments.
Because the Brookian sequence tends to overlie Beaufortian or Ellesmerian rocks, there are opportunities to explore for situations where there is more than one play at the same location. Brookian plays may dominate the coastal plain of the Arctic National Wildlife Refuge’s 1002 area, at the eastern end of the North Slope — Myers concurs with a USGS assessment that the Brookian sequence probably contains the preponderance of oil in that area. However, a couple of intriguing structural trends in the northeast of the ANWR 1002 area include potential Kuparuk-style plays. And Ellesmerian plays occur in thrust sheets along the front of the Brooks Range.
Brooks Range Foothills
Geologists have long considered the Brooks Range foothills, in the southern part of the National Petroleum Reserve-Alaska and extending east to the Dalton Highway, to be a gas prone province.
Myers thinks that reservoir quality will prove critical in locating gas fields in this area: “When you look at it there’s a lot of oil-stained rock in outcrop, so the question is ‘can you find enough effective porosity and permeability to make good gas reservoirs?’”
Rock units such as the Cretaceous Fortress Mountain formation and the Lisburne dolomites that outcrop in the foothills probably have enough porosity for gas. However, other rock formations that have been buried to relatively shallow depths exhibit better reservoir characteristics.
And in the foothills some rocks, probably from less deeply buried strata, provide evidence of reasonable thermal maturity for oil, Myers said. There is, in fact, a known oil field being evaluated by Renaissance Alaska at Umiat, about halfway down the eastern side of NPR-A on the northern side of the foothills, which might see five appraisal wells drilled in the winter of 2011-12, if the company can find funding.
The prospect has 37 degree gravity oil, and targets formations between 200 feet and 1,500 feet, with the upper portion of reservoir in permafrost. Development, which is challenged by lack of year-round access, will likely require a 110 mile buried pipeline to the trans-Alaska oil pipeline.
Good news for the area: The State of Alaska has been moving ahead with the permitting of a road west from the Dalton Highway to Umiat.
National Petroleum Reserve-Alaska
ConocoPhillips with its partner Anadarko Petroleum has been spearheading exploration and development west from the Colville River Delta, at the western extremity of existing North Slope oil infrastructure, into the northeastern part of NPR-A.
A series of wells drilled in the area by the partners since the renewal of leasing in NPR-A in 1999 have tested Alpine-equivalent prospects and have yielded discoveries of light oil, condensate and gas in stratigraphic traps, overlooked before the advent of 3-D seismic imaging.
The accumulations can be viably developed by extending the oil pipeline infrastructure west from their Colville River unit, which contains the first North Slope fields developed exclusively with horizontal well technology.
The unexpectedly prolific sands at Alpine, discovered in 1994 and put online in 2000, opened the door to extending a new Beaufortian play beyond the Prudhoe-Kuparuk infrastructure. The concept is to progressively move farther and farther west into NPR-A, opening up new oil pools as access to the pipeline infrastructure becomes available.
But progress has currently come to a halt because the U.S. Army Corps of Engineers has refused to permit the construction of an access bridge across the Nigliq Channel of the Colville River. Operator ConocoPhillips says that it needs this bridge to develop the NPR-A fields, the first being the Alpine West satellite, from its CD-5 drilling pad.
ConocoPhillips, Anadarko and others have also explored much farther west in NPR-A, but viable oil and gas development at such large distances from existing oil infrastructure would require a major oil find of at least 1 billion barrels.
If Shell, ConocoPhillips, Statoil and others develop their Chukchi Sea leases 100 miles offshore NPR-A, about 150 miles west of Barrow, a subsea oil pipeline would likely be brought to shore at the village of Wainwright in the remote Northwest Planning Area of NPR-A, and then run through the petroleum reserve and on to Pump Station 1 at the central North Slope’s Prudhoe Bay field.
A pipeline across NPR-A would open up the petroleum reserve, making it economically viable to drill a number of the larger accumulations there.
Sea change for two majors
Back near the core area of the central North Slope, the high-performance Beaufortian reservoir of the ConocoPhillips Palm discovery on the western edge of the Kuparuk field led to the construction of a new drill site and expansion of the Kuparuk River unit in 2003. A number of satellites were also being developed at Prudhoe by unit operator BP.
By 2002, both BP and the newly merged ConocoPhillips, which had picked up ARCO’s Alaska assets two years earlier through Phillips, had begun concentrating on finding “new” oil in their legacy assets in the state.
BP sold or dropped all its exploration leases, starting in 2001, except its leases in the 1002 area of ANWR, where it and Chevron had drilled the KIC well but were not allowed to continue drilling because the region was subsequently closed to development by the feds.
ConocoPhillips was still exploring, but on federal acreage onshore and offshore, looking for big fields and dropping its state exploration acreage. Over the next decade it dropped even its Beaufort Sea federal leases and pulled back from wildcat exploration in NPR-A, concentrating on its step-out development of the Colville River unit into NPR-A and pulling more oil out of its existing fields. It looked to its federal leases in the Chukchi Sea for its next major oil discovery in Alaska.
This shift in strategy left northern Alaska wide open to independents and majors alike looking for new opportunities in the state.
Anadarko Petroleum was one of the first, beginning major acquisitions the late 1990s, and already a partner with ConocoPhillips in the Alpine field. Canada’s Alberta Energy (AEC Oil & Gas), now EnCana, was another.
The November 2000 state areawide lease sales for the North Slope and Beaufort Sea saw the first significant influx of independents, with numerous winning bids from Anadarko, AEC and newcomer AVCG LLC of Kansas, which had already entered the state with the acquisition of two of Alfred James III’s leases.
AVCG eventually formed an operating arm, Brooks Range Petroleum Corp., or BRPC, and brought in former ARCO Alaska President Ken Thompson, who returned to live in Alaska in 2000.
Long-time senior vice president of ARCO Alaska, Jim Weeks, joined Winstar Petroleum that same year. Alaska-based Winstar had already acquired 12,000 acres on the North Slope as Petersburg Energy LLC. The leases were close to infrastructure and processing facilities, as were those of AVCG.
Eventually impediments to North Slope development by companies other than BP and ConocoPhillips, which operated all the infrastructure on the North Slope, began to disappear — some through litigation, such as the eventual lowering of the tariff through the 800-mile trans-Alaska oil line — and some because BP’s and ConocoPhillips’ interests were elsewhere.
And then comes Armstrong
In October 2001, Armstrong Oil and Gas, a Denver independent, bought its first leases in the state’s areawide North Slope and Beaufort Sea lease sales, leading to the development of the first independent-operated oil field in northern Alaska, Oooguruk, and the first processing facilities not operated by BP or ConocoPhillips, the Eni Petroleum-operated Nikaitchuq field, which came online this year. (Oooguruk’s crude is processed at the nearby Kuparuk River unit, which has spare capacity.)
Armstrong sold its northern Alaska assets to Eni, and turned to developing a gas field on the Kenai Peninsula, which also just came online.
But it returned to the North Slope and just recently brought Spanish mega-major Repsol in as a 70 percent partner to help it explore and develop nearly 500,000 acres on state leases on- and nearshore. Repsol paid $768 million for the privilege, with about $750,000, Petroleum News sources say, going to be used for exploration, starting with next winter’s off-road drilling season, 2011-12.
Lots of room for newcomers
There is still lots of room for newcomers, per Kevin Banks, the current director of the Division of Oil and Gas — and some incredible exploration and development credits available.
“The State of Alaska takes seriously our responsibilities to our leaseholders. We encourage exploration through innovative new programs, paying as much as 40 percent of exploration costs for qualified applicants, and we share our insight into how state and federal agencies interact to help companies navigate smoothly through exploration and development activities. Alaska is a resource development state. We view the people and companies exploring and developing our natural resources as our partners,” Banks said in a recent editorial aimed at oil and gas companies interested in entering Alaska, or investing in those that are already here.
The division has a staff of 95 “highly specialized technical experts” who work in asset teams, one of which is the Resource Evaluation section, which Banks said works with “potential investors to give technical briefings and share their knowledge and non-confidential public domain data. …
“The Division of Oil and Gas mission statement says we manage ‘oil and gas lands in a manner that assures both responsible oil and gas exploration and development and maximum revenues to the state.’”
“Our goal is to support any responsible company that shares this mission,” Banks said. “We want to see you succeed, because when you’re successful, so are we.”
Governor’s goal: 1 million barrels a day
Industry thinks the state’s progressive production tax regime has some problems, especially for the legacy field owners. But the tax, commonly referred to as ACES, also takes a lion’s share of net profits when oil prices are high, in the $100-plus range. It’s very competitive when prices are low, which is where they were when the new production tax was established in 2007.
Alaska’s Republican governor, Sean Parnell, is determined to get northern Alaska production back up to 1 million barrels a day from its current 600,000-plus barrels. He sees lowering the progressivity tax rate and adding even more incentives for explorers and developers as key to that effort. Industry agrees and has wholeheartedly backed him.
The Parnell administration is currently championing a tax change bill, which recently passed the House of Representatives, but is still facing challenges in the Senate; challenges that likely won’t be resolved until the Alaska Legislature reconvenes in January 2012.
Optimistic about the long term
Myers feels optimistic about the long-term future of the oil industry in northern Alaska.
“I think we’ll see just a tremendous amount more oil produced, especially from the stratigraphic plays over time,” he said. “I think someone will stumble into that 500 million to a billion barrel field size.”
And where is that next big find on state acreage?
In 2005, Myers said, “In the long term if I were to bet on a big prospect, the Brookian stratigraphic plays are where I’d put my money.”
In 2011, he also included shale oil (see shale section).
