Oil & Gas:
A Look Into 2002
Spending in 2002 by Alaska’s two majors will be less
than in previous years, but will remain at healthy levels, exceeding $1.5
billion.
By Patricia Jones
Tapping smaller satellite oil fields located near existing North Slope
infrastructure–a less costly and quick method of maintaining and even boosting
crude production–is the main focus this year for the major players in Alaska’s
oil and gas industry.
Transportation of Alaska crude oil is another focus this year, as both BP
Exploration (Alaska) Inc. and Phillips Petroleum Co. included in their 2002
spending plans funds to cover $200 million double-hulled oil tankers that
transport Alaska oil from the port of Valdez south to West Coast refineries.
Phillips Targets NPR-A
Finally, the search for additional oil and gas deposits continues in Alaska. In
particular, Phillips is funding this year an aggressive exploration program,
with half of the company’s 10 planned wells to be located on untapped lands
located in the western part of the North Slope.
“Our core focus area is NPR-A (National Petroleum Reserve-Alaska),” said Rick
Mott, vice president of exploration for Phillips. “The last two seasons we’ve
drilled six wells in that area, and five of them either found oil and gas, or
gas condensates. We believe we’ve discovered three separate hydrocarbon
accumulations there.”
Expanding and refining the base of geological information about those known
deposits will be the primary focus of this year’s exploration program, according
to Phillips’ executive vice president Kevin Meyers, who outlined the company’s
plans for its Alaska operations during a security analyst briefing late last
November.
“Our role in Alaska is to be a solid foundation upon which to build growth,” he
said, referring to the planned merger of Phillips and Conoco. “Our mission and
strategy is to first properly maintain our production in Alaska so we can
realize this growth.”
In all, spending in 2002 by Alaska’s two majors will be less than the previous
year, but will remain at healthy levels, exceeding $1.5 billion.
BP, which recently announced plans to lay off nearly 200 employees, plans to
spend roughly $700 million in Alaska in 2002, down from $800 million spent last
year, said spokesman Ronnie Chappell. “In our core area, the level of spending
is essentially the same as last year,” he said, referring to BP’s investments in
the Prudhoe Bay and Kuparuk fields.
Phillips plans to spend $807 million in Alaska this year, also a decline from
the overall $940 million spent in 2001, said spokeswoman Dawn Patience. But the
2001 budget included some one-time expenses, primarily the purchase of
additional shares in the trans-Alaska oil pipeline, she explained.
This year, Phillips is spending capital dollars on increasing gas-handling
facilities and developing satellite fields surrounding Prudhoe Bay and Kuparuk.
It’s an economical way to maintain current levels of crude production, with a
gradual overall increase expected in future years, thanks to satellite fields
near Kuparuk and to the Alpine development further west.
“If we did no capital investment at Prudhoe, you’d see a pretty steep base
decline … 14 percent through 2005,” Meyers said. “By doing capital investment,
we’ll offset that to a four percent decline … a big chunk of that is through
satellite development.”
Both well-established giant oil accumulations on the North Slope, Prudhoe Bay
and Kuparuk, also provide processing and transportation infrastructure for
neighboring, smaller pools that, on their own, wouldn’t merit the capital
spending required to develop.
Phillips’ $807 million in 2002 includes $31 million for the Palm project, $20
million for West Sak, $29 million for Meltwater–all fields near Kuparuk; and $17
million for Borealis, located near Prudhoe Bay.
Also, Phillips will spend $47 million to expand processing facilities at Alpine,
which produced record rates of nearly 110,000 barrels a day in recent weeks.
Meyers described the company’s development plan in Alaska as a “relentless
pursuit of driving down the unit cost of our business.”
“Pursuant to driving down expenses, one of our strategies is to increase
recovery in existing fields,” he said. “One of the nice things about big fields
is that they keep getting bigger and they keep getting better.”
BP Tests New Drilling Rigs
That low-cost existing and satellite-field development strategy is echoed by BP
(Exploration) Alaska, another of the North Slope operators looking to decrease
the per unit production costs for Alaska crude oil.
“Satellite fields are a big part of our plans–they can be brought on quickly,”
Chappell said, describing the Borealis field that started production late in
2001. “Most of our new reserves have been added by tapping exiting fields and
applying new technology–growing the pie–or by the discovery of fields in
proximity to fields we already have.”
In addition to tapping satellite fields, BP is looking to advances in drilling
technology to help increase production in existing fields by decreasing
development costs.
“One thing we’re going to do is bring up a new kind of drilling rig on the North
Slope … one that is capable of drilling new wells from the surface at a
significantly less cost than existing technology,” Chappell said.
Called LADS–Light Automated Drilling System–the new, lighter-weight drill rig
requires fewer people to operate, Chappell said. With a footprint about a third
of the size of a conventional drill rig, production costs also are reduced
through integrated, automated equipment for pumping and cementing.
“We’ve committed to use it to drill a number of wells,” Chappell said. “It’s
part of our plan for making viscous
oil competitive.”
Tapping such heavy oil deposits held in shallow underground formations, called
viscous oil, is the second prong in BP’s plan for 2002. West Sak, held by BP and
Phillips, and the BP-owned Schrader Bluffs accumulation, are both large deposits
of viscous oil, previously viewed as uneconomical to tap.
Located between 3,000 and 3,500 feet underground, the heavier oil also is colder
than other deeper North Slope deposits, adding to the difficulty of extraction.
Past wells punched into those deposits have yielded little oil flow, with
considerable cost. After extensive testing, BP believes the answer to tapping
these shallow reserves lies in changes to drilling techniques.
“One of the problems with production is that as viscous oil flows into well
bores, it tends to carry sand with it, chewing up the hardware that we have to
put down the hole to pump oil to the surface,” Chappell said. “The challenge is
to reduce the amount of sand that flows with this oil, and to develop pumping
mechanisms that are less prone to damage from the sand.”
By drilling a number of long horizontal wells, the velocity of oil that flows
into the well bore slows down, thereby greatly decreasing the amount of sand
carried into the pump, Chappell said.
In addition, the company has switched to using jet pumps submerged into the well
bores to bring the colder crude to surface. “They have fewer moving parts and
for that reason are more tolerant of sand in the flow strand,” Chappell said.
Repairs also are much easier on jet pumps, compared to conventional submersible
electric pumps previously used, he added.
“The use of jet pumps and long horizontal wells will give us operating
efficiencies that will allow us to move forward with viscous oil development in
the better part of the Schrader Bluff accumulation,” Chappell said. “It’s a way
to get the well rates up and to reduce the cost of surface infrastructure.”
This year, BP plans to spend $100 million on viscous oil development at Schrader
Bluff, and a total of $175 million over the next several years. Some of the
nearly two billion barrels of oil at that deposit will be processed through the
Milne Point facilities.
“There’s been a lot of money spent on viscous oil development through the
years–several hundred million dollars to make this resource competitive,”
Chappell said. “We feel like we’re on the way to having a solution.”
But development of viscous oil doesn’t carry the same notoriety and financial
impact to Alaska’s work force that large oil development projects have had in
recent years.
Oil Production Increases
The lack of a large headliner development project, such as Alpine or Northstar,
accounts for a significant portion of the oil industry’s decline in capital
spending this year.
“The tough thing is that there are no big projects and no modules being built
this year, like Northstar,” said Larry Houle, general manager of the Alaska
Support Industry Alliance. “There were 400 people a day working at the Port of
Anchorage on that Northstar module.”
Lower oil prices also could be hampering capital spending, said Roger Marks, a
state petroleum economist. “The fact that oil prices are down now seems to be
causing (developers) to be less aggressive than what they had been.”
Yet 2001 will likely be the low point for oil production in Alaska, Marks said.
Thanks to Northstar and Alpine coming online, state oil forecasts call for
annual oil production to creep upward from the 991,000 barrels per day rate
produced in fiscal year 2001.
“In fiscal year 2002, it should go up to 1.012 million barrels per day,” Marks
said. “Things have been going straight down, but if you believe our forecasts,
it will go up slightly until about 2006, then will slowly be heading south
again.”
Those state oil production forecasts include increased recoveries of viscous oil
at West Sak and Schrader Bluffs, Marks added.
What the state forecasts don’t include are oil accumulations still yet to be
discovered and developed. Phillips is leading the search for new oil, focusing
primarily on the National Petroleum Reserve, located on the western part of the
North Slope.
This year, Phillips plans to complete a total of 10 exploration wells, a
decrease from the 15 punched in 2001, but an increase over annual exploration
programs in previous years.
“The second thing we want to do is evaluate and obtain leases in the 2002 NPR-A
lease sale,” Mott said. “We also wish to acquire about 400 square miles of
proprietary seismic data in the area, and we want to continue satellite drilling
around Kuparuk and Alpine fields.”
Several other new prospects will be drilled in 2002, including a wildcat well
more than 30 miles south of the Kuparuk field, called the Kuparuk Uplands. It’s
even further south than the Meltwater field, which started production late in
2001.
“We shot 3-D seismic in the area and have done our geological studies,” Mott
said, about the company’s interest in the Kuparuk uplands area. “We’re playing
off our knowledge of the geology there.”
No NPR-A Drilling for BP
While Phillips has maintained an active exploration plan in 2002, most in the
industry have noted a decrease in exploration activity by BP. Primary is the
company’s decision not to conduct exploration drilling in NPR-A.
“We are not returning to NPR-A this year,” Chappell said. “Last year we drilled
two wells at the Trailblazer prospect and we want to evaluate that work, take
some time and look at other data. We want to evaluate other prospects in NPR-A
before we make a decision to do additional drilling out there.”
BP is participating in some exploratory wells near existing fields, he added.
But now, the company’s focus is maintaining current production and implementing
new technology to existing fields.
“Alaska represents 10 percent of BP production worldwide, and our goal is to
sustain that,” Chappell said. “We plan to take our
7-billion-barrel-oil-equivalent-reserve-base and transfer that into a 30-year
future for BP on the North Slope.”
The company’s decision last fall to relocate its frontier exploration team from
Alaska to Houston, Texas, was based on economics, not on the level of interest
in opportunities in the Last Frontier, Chappell added.
“The only piece of exploration that is done on location is the acquisition of
seismic data, and the actual drilling of wells,” Chappell said. “The rest is a
process of data evaluation and ranking of prospects the company has worldwide …
it’s more efficient to do that work out of our Houston office.”
While a “good prospect will sell itself,” Chappell said, new developments on the
North Slope must compete with prospects in other parts of the world, which are
often closer to market.
“Alaska fields are and can continue to be competitive in the global market,” he
said. “When looking at areas away from the existing infrastructure, we need to
find fields of some size to develop that will compete with fields elsewhere ….
We need huge discoveries to achieve the development and operational costs in
Alaska, and to be able to overcome the significant distance from market.”
