Phillips Alaska Inc., inheritor of the ARCO Alaska Inc. legacy and assets, has quickly made its own mark in assuming ARCO's mantle as the largest oil producer in Alaska.
The Alaskan unit of Phillips Petroleum Co., within a year of its acquisition of ARCO's Alaska assets, has managed to start up the North Slope's newest major field and production hub at Alpine, made the first hydrocarbon discoveries in the National Petroleum Reserve-Alaska since the NPR-A was reopened to exploration, and embarked upon its own ambitious exploration program on the slope.
The Alpine and NPR-A finds point to an exciting new stratigraphic play, driven by advances in 3D seismic technology, that has revolutionized explorationists' thinking about the prospectiveness of the otherwise maturing North Slope province.
At the same time, Phillips has made commercialization of its North Slope natural gas reserves a priority by participating with other top slope producers in feasibility studies of proposed pipelines and other options for monetizing the slope's stranded gas.
And the Bartlesville, Okla., company recently initiated operation of its new double-hulled crude oil tanker fleet built specifically for the Alaska trade (see related story, opposite page).
Phillips completed acquisition of ARCO's businesses in Alaska in August 2000 for $965 million. The acquisition added 2.2 billion boe of oil and gas reserves to Phillips's base.
Its presence far predates the ARCO acquisition, however. Phillips was the first company allowed by the federal government to explore for oil in Alaska, in 1952. It has long been a presence in the Cook Inlet region, where it operates Beluga and North Cook Inlet gas fields. And the company was the sole exporter of LNG in the Western Hemisphere with the Kenai Peninsula LNG complex it still operates after 30 years-until a few years ago, when Trinidad and Tobago started exporting LNG.
Phillips Alaska assets
In acquiring the ARCO Alaska assets, Phillips increased its production by 75%, more than doubled its reserves, and added more than 1 million acres to its exploration portfolio in the state.
Following the acquisition, a lawsuit by ExxonMobil Corp. forced a realignment of interests in the Prudhoe Bay Unit (PBU) and switched operatorship to a single company, BP PLC. Previously, BP and ARCO had each operated half of the field. BP's acquisition of ARCO had state and federal authorities concerned about the concentration of North Slope assets under one company, so BP was obliged to sell the ARCO Alaska assets.
While BP was named sole PBU operator, Phillips retained operatorship of Kuparuk River and Alpine oil fields. With the ARCO deal, Phillips acquired more than 8 tcf of net natural gas reserves, making it a key player, along with fellow Prudhoe gas cap interest owners BP and ExxonMobil, in any plans to commercialize North Slope gas.
In addition to its 36% interest in the Greater Prudhoe Bay Unit, Phillips holds interests in the Prudhoe Bay area satellites Northwest Eileen, Aurora, Polaris, and Midnight Sun. Phillips also operates West Sak heavy oil field and the Greater Kuparuk Area satellites Tarn, Tabasco, and Meltwater. And the company holds a 23.7% interest in the Trans-Alaska Pipeline System (TAPS).
Phillips strategy
Phillips's acquisition of ARCO Alaska assets, apart from it being the biggest and most company-transforming transaction in its history, is a centerpiece of a new corporate upstream strategy.
That strategy calls for Phillips to build what it calls "legacy assets"-high-quality oil and gas developments that have a long producing life and provide strong financial returns.
In June 2000, Phillips Chairman and CEO James J. Mulva disclosed, in a speech in Anchorage before the Resource Development Council for Alaska, that he expects the Alaska projects currently under development to add more than 1 billion bbl to the company's reserves base-not taking into account exploration prospects slated for drilling.
After Alpine started up in November 2000, Mulva said, "We expect Phillips's production levels in Alaska to remain [at] 375,000-400,000 boe/d for the next several years."
Alpine landmarks
Alpine is being developed as a stand-alone project on the Colville River delta 34 miles west of Kuparuk River field and 8 miles from the Inupiat village of Nuiqsut.
The $1 billion project is expected to recover 429 million bbl of the field's OOIP, estimated at 800 million-1 billion bbl. Phillips is operator and holds a 78% interest in the field, with the remaining 22% held by Anadarko Petroleum Corp., Houston.
Alpine represents several landmarks for Phillips and North Slope operations, in that it:
- Establishes a new, western production hub close to the burgeoning new exploration play in NPR-A.
- Is the largest onshore oil field found in the US in more than a decade.
- Produces the highest-gravity commercial crude oil on the slope at 38-40°.
- Is the first oil field to be developed exclusively with horizontal wells on the slope. Plans call for drilling 110 horizontal wells at Alpine, representing a total reservoir penetration of more than 60 miles.
- Represents yet another step in the evolution of the oil industry's shrinking footprint on the North Slope. The 40,000 acre field is being developed on 94 acres, or 0.2% of the field area.
- Is the first significant commercial oil production on lands conveyed to an Alaska native corporation under the Alaska Native Claims Settlement Act. Royalties accrue to the state, Kuukpik Village Corp., and Arctic Slope Regional Corp. Under ANCSA, 70% of the net revenues realized by ASRC are distributed among all native regional corporations in Alaska, which in turn share half their receipts with village corporations and at-large shareholders.
Environmental precautions
Perhaps the most significant landmark for Alpine is that it establishes, in terms of environmental precautions, what Mulva called the "standard by which all future arctic developments will be measured."
Alpine is a zero-discharge facility in which all waste generated is reused, recycled, or disposed of under strict state and federal guidelines for high-temperature incineration or shipment out to a designated disposal site. Even rainwater runoff from facilities is collected and injected into a disposal well rather than be allowed to drain onto the tundra.
In addition to the facilities' smaller footprint, there is no permanent road to the field. In the winter, ice roads are built to allow transportation of equipment and drilling supplies to the facilities. Other access is by aircraft.
Special ice roads had to be constructed to barge the massive modules, weighing a combined 15,000 tons, that comprised Alpine field facilities. The Colville River doesn't freeze to the bottom, so a 35-mile ice road was built from Alpine, where the Colville distributaries enter the Beaufort Sea, to Kuparuk River field. This included seven ice bridges, where the ice thickness was built to the river bottom then built up another 5-8 ft to compensate for settlement on the ocean floor.
"This is the first time loads of this magnitude have been moved such a distance over an ice road built on the open ocean," Phillips said.
Because ice floes on the Colville River made a traditional pipeline crossing impossible, four separate boreholes-for pipelines carrying oil, gas, diesel, and fiber optic cable-were drilled horizontally 100 ft below the river.
At Alpine, all drilling cuttings are processed through a special grind-and-inject module for injection into a disposal well.
There was also a novel solution to the dilemma of installing isolation valves on the Alpine oil pipeline, which would have meant building a permanent road for monitoring the valves. Instead, nine vertical pipeline loops that act like siphon breaks were installed on the pipeline. According to Phillips, these loops are cheaper to install, operate, and maintain than isolation valves-and, unlike isolation valves, they don't leak.
A new generation
Alpine represents a fourth generation of oil field development on the slope, with Prudhoe Bay first in the 1970s; Kuparuk in the 1980s; and Endicott, Lisburne, and Point McIntyre in late 1980s and early 1990s, contends Ryan Lance, Phillips Alaska vice-president, western North Slope.
"I think that, from the technological advances, [Alpine is] pretty significant both subsurface and surface-the subsurface side being...really the advent of 3D and even 4D seismic technology and direct hydrocarbon indicators that can help us drill fewer exploration wells, help us locate them, and really dramatically increase our chances of success. So from that whole view, I think starting with Alpine and then moving west has been a huge technological advance for us.
"And then on the surface side, I think what we've done at Alpine is demonstrate with a very low-impact, environmentally sensitive development that we can produce significant amounts of oil and not impact very much of the surface acreage...I think we've demonstrated that we've taken it really to a new level, where there's a whole different set of stakeholders, a different set of partners, and a different set of technological issues that we've addressed and been able to overcome. So I think [Alpine is] truly a quantum leap from where we've come in the past. We still have things to learn and do better, but I think we made a huge stride with Alpine and similar sorts of developments."
Top performer
Alpine's reservoir performance has been a pleasant surprise for Phillips. Although the facilities were designed for a peak rate of 80,000 b/d, the field had reached a record output of over 100,000 b/d in mid-July.
"It's the most favorable-acting reservoir across the whole North Slope," Lance said. "We've been real pleasantly surprised. The long horizontal wells, they're barefoot openhole completions that have performed probably well above our expectations. The formations remain competent...Even though it's a tighter, lower-permeability rock relative to maybe the Prudhoe and Kuparuks of the world...accessing so much reservoir rock with those horizontals is making up for that. We have some 10,000 b/d wells."
Alpine's performance has been so impressive, in fact, that Phillips has had to struggle with accommodating the level at which the field can produce. The company undertook some debottlenecking in order to exceed the facilities' design capacity.
"Most of what we've been doing is changing the set controls on a lot of the vessels and then playing with the inlet temperature of the crude and the pressure of the inlet stream to try and generate more throughput through the plant," Lance said. "So mostly it's just been playing with existing equipment in the control scheme-tweaking the temperature and the pressure in order to stay within the vapor specifications on the pipeline."
This effort has been aided by a lack of water production at Alpine, which enables Phillips to better calibrate volume levels in the separators in order to run them at a more optimum rate.
While Alpine also produces a significant volume of natural gas, there is no free gas cap, and Phillips simply extracts the volatile ends from the production stream and reinjects them into the reservoir. The project started up incorporating an enhanced oil recovery scheme at the outset. Phillips is using a miscible injectant generated at Alpine as well as injecting seawater imported from the water treatment facility at Kuparuk River field.
As of mid-July, Phillips had drilled 20 producers, 14 water injectors, and 3 gas injectors at Alpine. Most of the producers needed for start-up volumes were drilled at the main producing pad. Doyon Ltd.'s Rig 19 in early July was drilling the third well at the second drillpad, which is expected to start up sometime in August.
Alpine as a hub
Phillips is eyeing some measures to undertake a possible capacity expansion at Alpine, especially considering the prospect of tying in future satellites to this new production hub on the western North Slope.
"We're in the process right now of...tabulating what we think, from an engineering design perspective, where our big bottlenecks are that require some capital investment," Lance said. "And we would hope that in a few months or so we'd be in a position to decide if...it makes sense to move forward with those investments. But we think we have the bulk capacity to support some additional investments, we just have to figure out what exactly they are and how much it's going to cost."
At the moment, Phillips is studying how to optimize the single production train at Alpine with the existing pipeline infrastructure back to Kuparuk and Prudhoe. Beyond that effort, the company must weigh its options as to whether to add another production train and more pipeline infrastructure back to Kuparuk or to consider developing satellites sequentially, as capacity becomes available at Alpine. The Alpine satellites include the 50 million bbl Nanuk discovery and the 70 million bbl Fiord find.
While both satellites feature a Jurassic pay sand, as does Alpine, they are different geologic horizons, Lance said. Both have the same Kuparuk C sand that produces at Kuparuk River, and their Jurassic sand is a tighter formation than the Jurassic horizon at Alpine. Both pay sands are targets in any development.
Preliminary engineering is under way on how to develop the two discoveries, and Phillips is trying to gauge the optimum point at which it would proceed with their development.
"We think it's in a less-than-5-year time window as opposed to the greater-than-5-year time window," Lance said.
Another factor to consider is how the prospective field developments in NPR-A figure into this new production infrastructure. If the economies of scale warrant it, the NPR-A discoveries could be develop with another stand-alone processing center; if not, Phillips may decide to tie in those discoveries to an optimized-capacity Alpine complex. Most of the NPR-A discovery wells fall within the "radius of opportunity" for Phillips to tie them into the Alpine facility, if that option is chosen, Lance noted. An integrated team for subsurface and surface is now looking at all the options, from stand-alone to sharing with Alpine. While there are significant gas accumulations, along with crude oil and condensate, involved in the Phillips NPR-A discoveries, an initial development scheme likely would entail cycling the gas and recovering the liquids-at least until a North Slope gas monetization scheme is implemented.
A new play opens
Phillips has generated some excitement among North Slope explorationists with its announcement earlier this year of five successful wells in NPR-A tapping three separate accumulations.
As with Alpine, Phillips is the operator of these wells and holds the same interest, 78%, in partnership in Anadarko, 22%. The discoveries are 15-25 miles southwest of Alpine.
The Spark 1A well tested at a rate of 1,550 b/d of liquids and 26.5 MMcfd of natural gas. Rendezvous A was tested at an unstimulated rate of 360 b/d of liquids and 6.6 MMcfd of gas. Both wells were drilled in spring 2000, and Phillips returned this season to test them. Rendevous 2, a confirmation well, was drilled this year and temporarily suspended; plans call for this well to be tested next season, according to Mike Richter, vice-president of exploration and land for Phillips Alaska.
"Spark 1 was almost a twin to 1A," he said. "We basically twinned the well to complete it for 1A."
Lookout 1 also was temporarily suspended for future testing. At Moose's Tooth C, Phillips encountered some problems and temporarily suspended the well pending a decision on whether to undertake a redrill, sidetrack, or other solution.
While no decision has been made on developing the NPR-A discoveries, Phillips remains confident about their commerciality. While the company won't offer an estimate of their potential reserves, Phillips Alaska Pres. Kevin Meyers was quoted in the Alaska press as saying the NPR-A finds collectively could be comparable in size to Alpine.
"In terms of commerciality, what we know is that we found a commercial-quality reservoir with gas, condensate, and oil," Richter said. "We need to determine the amounts of each to figure what kind of development [is needed] out there."
As important as the discoveries are in terms of NPR-A E&D, their greater significance lies in the extension elsewhere on the slope of the new play concept ushered in by the Alpine strike. It is the first time that a Jurassic sand-in this case, informally dubbed the Alpine sand-has yielded a commercial-quality reservoir on the North Slope.
"In the last 2 years in the NPR-A, we've targeted the Jurassic with five wells, and each of those wells hit...," Richter said. "So what I'd say from that is that we have a new play concept that's working. The seismic has worked so that basically we are at 100% in identifying Jurassic targets."
He characterizes the new play as a pure stratigraphic play driven by 3D, with the targets usually low-permeability reservoirs "that promote commercial rates with the light hydrocarbons we have in them."
This approach could work elsewhere on the North Slope, notes Richter.
"With 3D seismic and our ability to analyze it as carefully as we can today, we have a very good track record looking for stratigraphic traps in the Jurassic and other intervals," he said. "The message...is that whether or not it's specifically a Jurassic sand, we've had good success with our seismic tool. It's working well for us in a variety of intervals, so we're bullish on the resource potential of the North Slope."
Exploration plans
Phillips has an ambitious exploration program on the North Slope. Its portfolio totals more than 100 prospects on a lease inventory that covers more than 1 million acres.
"Our collection of 3D seismic data has been growing pretty much each year, to where now we're collecting or acquiring in some fashion 800-1,000 sq miles of 3D a year. That's the key to replenishing the prospect inventory-to continue to acquire seismic data."
Phillips has a program of drilling 12-14 exploratory wells/year on the slope, targeting anything from satellite size at about 50 million bbl to what it deems to be "significant" stand-alone targets of 200-500 million bbl.
"[The North Slope is] really simply well-explored for billion-barrel-plus prospects and very much underexplored for the targets from 50 million [bbl] to 300-400 hundred million [bbl].
Assimilating ARCO staff
While it might seem daunting to take over the operations of ARCO, which some industry observers considered to be the preeminent exploration company on the North Slope, Phillips ® little difficulty in assimilating the ARCO staff.
Richter noted that the preacquisition ARCO staff is largely intact, in terms of the North Slope exploration team.
"Phillips is very pleased with the program up here and the performance of the program. As we enter this period of capital allocation for the coming year, we have an excellent position. We delivered on our promises of the last 5 years in terms of finding costs and volumes, so I expect that we'll continue to fare well in terms of getting the capital we need to continue and sustain our program."
A few years ago, ARCO estimated that it had participated in recent discoveries in Alaska that together held gross reserves exceeding 1 billion bbl, Richter noted, adding, "We've obviously added to that.
"And the last time that I looked at our finding costs, we were well under a dollar, let's say in the 65-70¢/bbl range-if you measure in terms of the reserves you ultimately expect to recover, not what has been booked on the financial books to date."
The former ARCO's exploration philosophy has dovetailed neatly with Phillips's, Richter said: "It fits Phillips's strategy as well, which is to acquire and grow legacy assets. And clearly Alaska is one of those legacy assets for Phillips; part of that is existing production, but it's also growth for the future...
"The kind of exploration program we have here is frankly what Phillips would like to move to in several other very focused places around the world. So it wasn't a struggle to mesh the two. In fact, we fit very, very well with the strategy that Phillips was already pursuing."