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Pumping Up TAPS: Billions in untapped crude On and nearshore the North Slope billions of barrels of oil await discovery Kay Cashman Petroleum News
With production from major oil fields in northern Alaska declining, there is a common misconception that the North Slope has become a mature province for conventional oil and gas.
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 simply delineated, as evidenced by exploration and development activities in the last decade-plus.
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 onshore and nearshore the North Slope. At the same time, BP’s 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 the use of high-end 3-D seismic techniques to find stratigraphic traps and the use of horizontal drilling to produce from low permeability reservoirs, more North Slope accumulations have become 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 email.
But, he said, “Finding new oil with new ideas is even better. The reason being that new ideas open up new areas to exploration.”
For example, “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,” Boyd said.
“Same with Alpine. The discovery of the Alpine sand — not a turbidite but a new play — is what enabled me to go to (then DNR Commissioner John) Shively and (then-Gov. Tony) Knowles to push getting NPR-A open again. To their credit they did it, and that was a tough sell during the Clinton administration,” Boyd said.
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.
Essentially there are four major rock sequences in northern Alaska: the Franklinian, the Ellesmerian, the Beaufortian and the Brookian, with the huge Prudhoe Bay oil field situated in the Ellesmerian; the Beaufortian hosting fields such as Kuparuk and Alpine; and the Brookian hosting fields including Badami and Meltwater.
Companies are still looking for opportunities in the Ellesmerian, where there are numerous structural plays.
Huge range of potential sizes Although some of the Beaufortian sands can be thin and discontinuous, other areas of more continuous sands have given 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, told Petroleum News.
Success with Alpine, the main field in the ConocoPhillips-operated Colville River unit that came online in 2000, 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’s Badami field have shown that Brookian plays aren’t without risk.
Because the sequence tends to overlie Beaufortian or Ellesmerian rocks, there are opportunities to explore where there is more than one play at the same location, Myers said.
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 concurred 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.
Headed west into NPR-A ConocoPhillips and partner Anadarko spearheaded exploration and development west from the Colville River Delta, at the western extremity of existing central 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 the Colville River unit, which contains the first North Slope fields developed exclusively with horizontal well technology.
The unexpectedly prolific sands at Alpine 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.
Chukchi could open western NPR-A But progress had come to a halt because the U.S. Army Corps of Engineers had refused to permit the construction of an access bridge across the Nigliq Channel of the Colville River, which ConocoPhillips said it needed to develop the NPR-A fields, the first being the Alpine West satellite, from its CD-5 drilling pad. The objections to the permit had come from U.S. Fish & Wildlife Service and the Environmental Protection Agency.
On Dec. 5, the U.S. Department of the Interior announced the agencies had reached “an agreement in principle” with the company.
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 BP, Conoco 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, such as the Prudhoe, Kuparuk and Colville units.
With the exception of its ANWR 1002 area leases, BP sold or dropped all its exploration leases, starting in 2001.
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 the company 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 giant oil discovery in Alaska.
Drop in TAPS tariff drew investment This shift in strategy left northern Alaska wide open to independents and majors alike looking for new opportunities in the state, including non-owners in the Trans Alaska Pipeline System because beginning in 2000, the Regulatory Commission of Alaska, and later the Federal Energy Regulatory Commission and the courts, began ruling against a methodology established in a 1986 settlement between TAPS owners — subsidiaries of BP, ConocoPhillips, ExxonMobil, Koch and Unocal (a mere 1.36 percent) — and state and federal regulators that produced tariffs too high for non-owners to be able to economically produce oil in Alaska.
The November 2000 state areawide lease sales for the North Slope and Beaufort Sea saw the first significant bids from independents, including Anadarko and AVCG LLC of Kansas.
BRPC looking to produce AVCG and its partners eventually formed an operating arm, Brooks Range Petroleum Corp., or BRPC. In the pursuit of fields between 25 million and 50 million barrels, the joint venture drilled five wells and several sidetracks in the last few years, leased more than 330,000 acres in Alaska, and is looking to become one of the most active developers on the North Slope where it has formed five units in the central North Slope, four of which are in the “billion barrel fairway” between the Kuparuk River’s western boundary and the Colville River.
From north to south those units are the Southern Miluveach, Kachemach, Tofkat and Putu units.
BRPC’s first unit, formed in 2009, was the Beechey Point unit in the Gwydyr Bay region north of Prudhoe Bay.
The unit’s onshore and offshore leases, where BRPC has drilled several wells, are long known to overlie several oil deposits considered small, but only by the outsized standards on the North Slope.
BRPC said in agency filings that despite “respectable” results from previous wells in the area by majors, “a cost structure founded on drillsites capable of producing 100,000 bpd was not suitable for ‘marginal’ areas, particularly with commodity prices in the $20 to $30 price range,” and, “as a consequence, these accumulations lay dormant for many years.”
On the top end BRPC’s partners expect to recover as much as 15 million barrels of oil from the unit.
More wells planned at Mustang This winter BRPC has committed to the Division of Oil and Gas to complete three wells or sidetracks in its Southern Miluveach unit’s Mustang prospect, formerly known as North Tarn.
Brooks Range previously estimated the Kuparuk formation at Mustang could contain 6 million barrels of oil, enough to make the play economic. The company also said North Tarn included a target in the shallower Brookian formation that could hold 35 million barrels, but would be more difficult and costly to produce because of complex geology.
Under the terms of its agreement with the Division of Oil and Gas, working interest owners must decide by Oct. 1, 2012, whether they will sanction Mustang development.
More wells, development decisions Under the plan of exploration with the division for its Tofkat unit, BRPC must drill and complete a well and sidetrack into the Kuparuk formation by May 31, 2013. The owners must sanction the Tofkat development by Oct. 1, 2013.
Under its agreement with the state for the Putu unit, BRPC must drill four wells into the Upper Jurassic-age strata of the Kingak formation by May 31, 2013, two targeting the Musketeer trend (Brookian Sequence Boundary C) and two targeting the Big Foot trend (Brookian Sequence Boundary BC).
Under the Kachemach unit agreement, BRPC must complete one well in Block A targeting the Caribou trend (Brookian Sequence Boundary F) and one well in Block A targeting the Moonlight trend (TP4-2 Nanushuk prospect) by May 31, 2013.
If BRPC meets those commitments the company must then commit to complete one well in Block B targeting the Moonlight trend (TP4-1 Nanushuk prospect) by May 31, 2014.
UltraStar focused on Dewline Long-time senior vice president of ARCO Alaska, Jim Weeks, joined newly formed Winstar Petroleum in 2000. Alaska-based Winstar had already acquired 12,000 acres on the North Slope as Petersburg Energy LLC.
Weeks also helped found UltraStar Exploration LLC in 2002. The companies have an overlapping group of investors and leases that are close to infrastructure and processing facilities.
Following Winstar’s dry hole at Oliktok Point, UltraStar obtained 3-D seismic over its leases west of BP’s Point McIntyre field, which showed several prospects.
Weeks decided to pursue the Dewline Deep prospect, believed to hold between 5-20 million barrels of oil in the Ivishak and Sag River formations.
Following years of negotiations that included talk of possibly expanding the Prudhoe Bay unit to include Dewline Deep, UltraStar and BP came to terms on a framework for access to the drill site and for the future use of Lisburne facilities.
UltraStar drilled the Dewline No. 1 well in early 2009, and is planning a second well this winter, if a rig is available.
And then comes Armstrong In October 2001, Denver independent Armstrong Oil and Gas 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, by its partner Pioneer Natural Resources, and the first processing facilities not operated by BP or ConocoPhillips at the Eni Petroleum-operated Nikaitchuq field. (Oooguruk’s crude is processed at the nearby ConocoPhillips-operated Kuparuk River unit.)
Armstrong sold its northern Alaska assets to Eni in 2005, but returned to the North Slope in 2008, doing business through a subsidiary 70 & 148 LLC.
In March 2011, Armstrong and partner GMT Exploration brought in Spanish mega-major Repsol as a 70 percent partner to help explore and develop nearly 500,000 acres on state leases onshore and nearshore.
Repsol paid $768 million for the privilege, with about $750,000, PN sources say, going to be used for exploration, starting with the 2011-12 winter off-road drilling season, when it plans to drill 12 exploration wells from four ice pads.
Initially five pads and 15 wells were planned — one vertical and two laterals per pad, using five drilling rigs — but in consideration of the concerns of local residents the company is expected to pull one of its five applications in mid-December.
Repsol, which has about 20 prospects identified by Armstrong, will likely drill that fifth prospect and several more the following winter of 2012-13; not only is it motivated to bring oil online quickly, but 84 of 157 of the company’s state leases are set to expire in 2012, 2013 and 2014.
Oil production from Repsol’s first five exploration projects is scheduled to come online between 2015 and 2018, peaking at 119,000 barrels a day in 2017 or 2018.
Given the Parnell administration’s reluctance to extend and/or unitize a lease without at least one well from the current leaseholder, it’s safe to assume Repsol will be a very active explorer, as well as a developer and producer, in the next few years.
Pioneer focused on new oil at Oooguruk In Alaska, Pioneer Natural Resources is focused on its nearshore unit, Oooguruk.
After building a gravel island in the state waters of the Beaufort Sea north of the Kuparuk River unit, Oooguruk came online in June 2008.
In early 2009 Pioneer increased its resource estimate for the unit by 40 percent based on initial drilling results.
Initially the company worked only at producing the Kuparuk pool and the deeper and larger Nuiqsut pool, but after years of drilling wells through the shallower Torok, it accumulated enough information to justify developing that formation.
According to Pioneer, Torok consists of 200-250 feet of thinly laminated sands and shales some 1,000 feet above Kuparuk.
Pioneer has drilled 18 wells through the formation, its first producing at an initial rate of 1,100 barrels per day.
Because the Torok reservoir extends past the southern boundary of Oooguruk, and a considerable distance from the existing gravel island, Pioneer proposed the Nuna Development Project in late 2010. The project would include two new onshore drill sites on the east side of the Colville River to allow Pioneer to approach the reservoir from the opposite direction.
The plan currently calls for processing that oil through existing facilities, but Pioneer also held out of the possibility of building a standalone facility.
The Kuparuk River unit currently processes Oooguruk crude, but pioneer is facing problems with that arrangement. In addition to being at the whim of the maintenance schedule of the larger and older field, Pioneer recently said it lost some 2,500 and 3,000 barrels of oil per day of production in 2011 because of water shortages.
The Division of Oil and Gas approved formation of the Torok participating area in July 2011 and agreed to add four leases to the Oooguruk unit in September to bring the entire reservoir into the unit’s boundaries.
Pioneer estimates the Torok holds 690 million barrels of oil in place and that it can produce up to 25 percent through primary and secondary recovery methods, which could greatly exceed current Oooguruk production.
The state gave Pioneer until June 30, 2014, to sanction the Nuna development.
Should Pioneer move ahead, it said it plans to build the gravel roads and the first Nuna drill site pad June 30, 2015, in order to begin drilling in the expansion area by 2016.
This winter it plans to drill two wells as part of that program.
ASRC sees Placer potential Nestled between the Kachemach and Southern Miluveach units, the ASRC Exploration-operated Placer unit covers four leases and 1,480 acres.
The company is beginning its first solely owned exploration project, its main target the Kuparuk C sand.
Under its unit agreement, ASRC must reprocess and reinterpret newly licensed seismic data shot across the unit by the end of the year, and must drill and log a new exploratory well, or re-enter and test the Placer No. 1 well, by June 30, 2013.
ENS pearls about to be strung?
It has been more than 20 years since the phrase “string of pearls” was coined for the infrastructure-led exploration of Alaska’s eastern North Slope. It has taken two more decades for the “string” — a metaphor for new pipelines — to come close to making its way from Pump Station 1 of the trans-Alaska oil pipeline at Prudhoe Bay to the Sourdough discovery on the border of ANWR’s 1002 area, some 70 miles east as a goose flies.
Between the two are numerous on- and offshore discoveries, several of which are thought to hold upwards of 100 million barrels of oil.
The first “pearl” on the string was Endicott in the Duck Island unit, 15 miles east of Prudhoe Bay.
Next, in 1998, BP’s Badami field came online, its 22-mile pipeline, or “string,” connecting it to Endicott.
Although the 35,000-barrel-per-day line was supposed to be nearly filled by 30,000 barrels from Badami at its peak, the line was expandable, and its corridor would allow for a second and larger pipeline if needed.
Within a year of starting production at Badami, BP with several partners was drilling the Red Dog prospect, its next pearl to the east, between Badami and the undeveloped Point Thomson unit, which was operated by ExxonMobil, and of which BP was a sizable owner.
Unfortunately, BP was unable to finish the Red Dog well before the winter drilling season ended.
It was also experiencing serious problems at Badami. While early production had ramped up, as expected, to 18,000 barrels a day, by early 1999 it had dropped to a mere 3,000 barrels.
One of the challenges in developing the field — a known risk going in and part of the reason the capacity of Badami’s pipeline was reduced from 70,000 to 35,000 bpd — was the question of whether its pockets of oil-bearing sands, or channels, would “communicate” so that oil would move from one to the next and into the vertical wellbores.
Published descriptions of Badami’s Brookian accumulation suggest its reservoirs are complex, consisting of 61 identified fans laid down during seven depositional events, with thin and discontinuous reservoir-quality sands.
Following a series of startups and stops, and a great deal of effort to get the reservoir to perform, BP shut down Badami and its pipeline for the last time in 2007, with production at 900 bpd.
Savant steps in
In 2008, BP entered into an agreement with Denver-based Savant to bring Badami back into production using horizontal well technology and possibly advanced hydraulic fracturing techniques. Savant and its minority partner ASRC Exploration agreed to drill two wells in the unit as part of a deal that would eventually give them working interest in key leases and leave BP with an overriding royalty interest. One of the wells was an exploration well in the untested Red Wolf satellite, and the other a new horizontal sidetrack to one of the original vertical producing wells in the unit.
Both wells were drilled and Badami went back online in November 2010.
Production is currently at around 1,000 barrels a day, with a goal up 4,000 barrels.
Savant recently assumed operatorship of the unit.
Close to settling
Even if Savant is not successful at keeping the Badami unit online, the Badami pipeline would likely be available to transport 10,000 barrels of oil and natural gas condensate starting in 2015-16 from the Point Thomson unit, which has several leases that run along the Staines River next to ANWR’s 1002 area.
Too long of a story
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