page Unconventional production could
12 vault gas to dominant position
A weekly oil & gas newspaper based in Anchorage, Alaska
Vol. 17, No. 25 • www.PetroleumNews.com
Inside: Petroleum News Bakken
1
CASSANDRA
A
SANISH &
PARSHALL
BUCK
2
3 TARPON
HIDDEN
BENCH
4
Week of June 17, 2012 • $2
EXPLORATION & PRODUCTION
Making strides
LEWIS
5 & CLARK
67
BIG
Vol. 1, No. 5 • www.PetroleumNewsBakken.com
COURTESY IRVING OIL
Bakken link to Saint John?
Pushing boundaries
Sonnenberg: Drill the shales, expand Bakken edges laterally, vertically
By KAY CASHMAN
The Canadians, Sonnenberg said,
do not claim to have thermally
S
PetroBakken chases new EOR
methods; its choice natural gas
PetroBakken, a pioneer of technological change in
Bakken-type plays, is testing a full range of natural gas
flooding methods as agents for enhanced oil recovery, Chief
Executive Officer John
Wright told the company’s
John Wright disclosed
annual general meeting.
that PetroBakken is
Asked to compare natural
“pushing hard” with
gas flooding with other
methods,
he
said natural gas flooding and
PetroBakken has examined expects to have six pilots
three “tried and true” con- under way by the end of
cepts in the Bakken —
2012.
waterflooding, natural gas
flooding and carbon dioxide
flooding — and concluded that CO2 is “probably the best
technical solution.”
Natural gas ranks second and waterflooding is viewed as
the least effective, Wright said.
Because of the “incredibly poor quality” of Bakken rock,
injecting fluid is difficult, he said, describing CO2 as a “great
see PETROBAKKEN page 16
Phillips 66 might buy 2,000 rail
cars to haul mid-con shale oil;
sees lower NGL prices thru’ 2017
Phillips 66 is looking at buying as many as 2,000 railroad
tank cars to ship sweet, light crude produced from U.S. midcontinent shale oil fields to refineries, company Chairman
and CEO Greg Garland told attendees of the Citi Global
Energy Conference June 5.
“We’re doing things around
pipelines, we’re doing things around
trucks, we’re doing things around
rail,” Garland said. “We’re considering buying a couple thousand more
railcars so we can get Bakken crude
either east and west.”
Phillips 66, the newly spun-off
downstream arm of ConocoPhillips, has 11 refineries on the
east, west and gulf coasts of the United States. Garland said
those refineries currently handle about 100,000 barrels a day
of shale oil, which “can easily, in the next year or two” be
increased by another 120,000-150,000 bpd of incremental
crude transported by rail.
“Ultimately, we can process about 500,000 barrels a day
see PHILLIPS 66 page 16
Pronghorn
PETROLEUM SYSTEM
Petroleum News Bakken
Refinery in New Brunswick can handle 300,000 bpd. See page 6.
9
Week of June 17, 2012
A semi-monthly newspaper for industry and government
8
page Comparing non-Sanish to Sanish wells,
10 which deliver 1/3 of Whiting’s output
BAKKEN
mature source rocks in their land.
teve Sonnenberg’s advice to Bakken
“They always seem to claim that
operators?
“Don’t forget the shales.”
all the oil migrated out of the
The illustrious geology professor
U.S. but we know that’s not
from the Colorado School of Mines says
entirely the case. Some of that oil
there are plenty of untapped opportuniis self-generated up there.”
ties within the prolific Bakken petroleum STEVE SONNENBERG
system, where almost all drillers are conproduccentrating on two tight reservoirs — the middle ing reservoirs.
Bakken and upper Three Forks.
Although those reservoirs have made North
What’s being largely ignored by industry, Dakota the second largest oil producer in the U.S.,
Sonnenberg says, is the source of the oil in those they contain only a fraction of the light, sweet oil
reservoirs — the upper and lower Bakken, which
are organic-rich shale formations adjacent to the
see PUSHING BOUNDARIES page 12
ENVIRONMENT & SAFETY
‘Vastly exaggerated’
New study of 91,000 wells shows methane emissions are half of EPA estimate
By RAY TYSON
Petroleum News Bakken
A
new, comprehensive study prepared for the
American Petroleum Institute and the
American Natural Gas Association shows that
methane emissions from U.S. natural gas production were half what had been previously estimated
by the federal Environmental Protection Agency.
Both API and ANGA had complained that a
previous survey by the EPA used a limited data set
taken from a sample that was never intended for
developing nationwide emissions estimates.
The new study, conducted by URS Corp. and
the Levon Group, analyzed data from nearly 20
Meanwhile … The (Western Energy)
Alliance said BLM’s proposed rule (to
regulate hydraulic fracturing on public
lands) will impose a cost to society of at
least $1.499 billion and as much as
$1.615 billion annually.
percent of all U.S. natural gas producing wells, a
sample size more than 10 times larger than EPA’s.
“This study confirms that EPA’s estimates on
emissions from operations are vastly exaggerated,”
said Tom Amontree, executive vice president at
Apache moves ahead with Cook Inlet seismic and plans first two wells
By ALAN BAILEY
inlet. Apache is now extending that survey
out into the offshore and plans to drill two
exploration wells on the west side of the
inlet, starting this fall, John Hendrix, generince Apache Corp. started buying leasal manager of Apache Alaska Corp., told
es in Alaska’s Cook Inlet basin in July
Petroleum News June 7.
2010, the company has wasted no time in
“It shows the type of a track record that
moving ahead with an ambitious exploApache has not only set but will continue to
ration program, seeking new oil resources
maintain going forward,” said Lisa Parker,
to re-invigorate the region’s sagging oil
Apache Alaska’s manager, government relaproduction.
JOHN HENDRIX
tions , reflecting on the speed with which
In April and May 2011 the company
shot some test seismic on the west side of the inlet, the company has progressed its Cook Inlet program.
trying out new nodal seismic technology that does not
require the laying of seismic cables. And, having met Moving offshore
with success in that test, in the fall of 2011 the comFollowing the onshore surveying in the Tyonek
pany embarked on a 3-D seismic survey covering a
see APACHE PLANS page 19
swath of land near Tyonek, also on the west side of the
Petroleum News
S
see METHANE STUDY page 15
FINANCE & ECONOMY
Boosting returns
Continental’s Harold Hamm urges fellow Bakken operators to change tactics
cited statistics showing an average 25 perBy RAY TYSON
cent return from the Bakken, versus 40
Petroleum News Bakken
percent from the Permian basin and 50
percent from the Eagle Ford, a major
here are numerous things that
unconventional Texas liquids play and
famed Continental Resources chief
among the Bakken petroleum system’s
executive Harold Hamm likes about the
chief competitors for investment capital.
Bakken and his adopted home, North
“You know that doesn’t cut it,” he
Dakota. But there are a few things that
asserted. “A percentage of that money is
bother the native Oklahoman, particulargoing to compete and go to some other
ly the Bakken’s relatively low rate of HAROLD HAMM
play. That capital goes where the opportureturn on investment compared to some
other unconventional liquids plays in the United nity is. We have to get better at what we do here.”
In the world of finance, rate of return, also
States.
Before a packed house at May’s Williston Basin known as return on investment, rate of profit or
Petroleum Conference in Bismarck, N.D., Hamm
see BOOSTING RETURNS page 14
T
2011 strange energy year
BP notes significant supply disruptions worldwide, but industry met global demand
By ERIC LIDJI
For Petroleum News
The current issue of Petroleum News Bakken is enclosed.
BSEE director tours drilling ships;
Shell strikes first on lawsuits
The Obama Administration recently began inspecting the
rigs and safety equipment Shell plans to use for its offshore
exploratory drilling campaign in the Arctic this summer.
Bureau of Safety and Environmental Enforcement
Director Jim Watson visited the Kulluk and Noble Discoverer
drill ships docked in Seattle on June 13 and planned to continue south to Portland to visit safety equipment Shell plans
to use during drilling.
The BSEE and the U.S. Coast Guard plan to conduct tests
of Shell’s capping stack and containment system in the coming weeks before issuing final permits for drilling, Watson
see BSEE TOUR page 20
Alaska shale opportunities, issues
conference scheduled July 31
Law firm K&L Gates is holding the Alaska Shale
Conference July 31 K&L Gates at the Anchorage Marriott
Downtown. The conference is complimentary, but reservations are needed by June 30 at www.klgates.com/kl-gatesalaska-shale-conference/.
K&L Gates said the focus will be on “new opportunities
for and challenges associated with development of shale plays
in Alaska,” including current resource assessments from state
and federal geologists; state and federal oil and gas leasing
programs and available acreage; and current exploration
activities targeting shale resources.
“Also at the conference, you will receive a clear-eyed
assessment of the potential challenges facing shale oil and gas
development in Alaska,” K&L Gates said, including: how
see SHALE CONFERENCE page 15
FINANCE & ECONOMY
H
ow’s this for confusing: At the launch of the
BP Statistical Review of World Energy 2012,
BP Group CEO Bob Dudley said the newest data
“paints an intriguing picture,” while Chief Economist
Christof Ruehl said the facts and figures look “almost
boring.”
What’s even more confusing is Dudley and Ruehl
are in complete agreement.
“When you think back on 2011, it was a year
which had quite some disruptions,” Ruehl said June
13, as BP released the 61st edition of its annual
appraisal of global energy.
In terms of supply, the Fukushima Daiichi nuclear
disaster increased skepticism of nuclear power in
Japan and subsequently in Germany; the political
unrest of the Arab Spring shut down oil production,
particularly in Libya; and the refinement of drilling
and completion technology boosted unconventional
oil and gas production in North America.
“Intriguing,” you might say.
And yet the major trends of recent years continued
as though nothing happened.
Global energy demand increased by 2.5 percent in
2011, down from 5.1 percent growth in 2010 but still
in line with historical averages. That growth came
largely from the developing world, as demand fell 0.8
percent in Organization for Economic Cooperation
see ENERGY YEAR page 17
PIPELINES & DOWNSTREAM
Energy corridor needed
Task force: Canada needs publicly created, privately run project for Asian market
By GARY PARK
For Petroleum News
T
he Canadian Association of Petroleum
Producers estimates the country’s combined
conventional and oil sands production will climb
from 3 million barrels per day in 2011 to 4.7 million bpd in 2020, 5.6 million bpd in 2025 and 6.2
million bpd in 2030.
That would elevate Canada to one of the world’s
top crude suppliers and achieve Prime Minister
Stephen Harper’s cherished goal of create a “global energy superpower.”
If ….?
And the biggest factor in the “if ” equation is
The task force pressed for “collective
action, rather than a series of
uncoordinated private sector initiatives”
to establish the energy transportation
corridor that would be launched by
governments, regulated as a public utility
and operated by the private sector.
whether the pipeline crunch, resulting partly from
acrimonious and protracted battles over plans to
start shipping oil sands crude to the Texas Gulf
Coast, Eastern Canada and Asia, can be resolved.
see ENERGY CORRIDOR page 18
2
PETROLEUM NEWS
contents
15 US oil, gas rig count up by 4 to 1,984
Making strides
FINANCE & ECONOMY
Apache moves ahead with Cook Inlet
seismic and plans first two wells
8
Task force: Canada needs publicly created,
privately run project for Asian market
9
ALTERNATIVE ENERGY
15 No takers for co-op rig, court papers say
EXPLORATION & PRODUCTION
4
Major materials on order for Pt. Thomson
ExxonMobil says that subject to EIS completion it will be
laying gravel for Point Thomson initial
production system this winter
5
Serenity masks oil sands unease
Dive in oil prices puts project economics under
microscope; analysts say operators could be
forced to put projects on back burner
7
Linc proposing unit at Point Mackenzie
Aussie independent wants
to investigate geologic
feature encountered by
a previous well
and subsequent
seismic acquisitions
Petronas stalled in Canadian takeover
GOVERNMENT
10 DNR: Walker suit has ‘no legal grounds’
BSEE director tours drilling ships;
Shell strikes first on lawsuit
Alaska shale opportunities, issues
conference scheduled July 31
EIA projects $95 WTI 2nd half of year
Agency says dropping crude prices from May to early
June reflect concerns about world economic
conditions and oil demand growth
2011 strange energy year
Energy corridor needed
WEEK OF JUNE 17, 2012
Petroleum News North America’s source for oil and gas news
ON THE COVER
BP notes significant supply disruptions
worldwide, but industry met global demand
•
State officials rebut claims made in appeal of Alaska’s
recent settlement of conflict over the Point
Thomson oil and gas unit
LAND & LEASING
10 State finalizes Beaufort lease expirations
NATURAL GAS
6
Industry adapted to 2011 demand spike
Report says LNG industry responded after tsunami
in Japan, with year-over-year acquisition
of liquefied natural gas up 9 percent
12 How natural gas can grab ‘golden’ status
Unconventional production could
vault gas to dominant global
position, but only if industry
and government win
over public, IEA says
Russia
United States
China
Iran
Saudi Arabia
Australia
Qatar
Argenna
Mexico
Canada
Venezuela
Indonesia
Norway
Nigeria
Algeria
0
25
50
75
13 State revises views on Pt. Thomson oil
2008 PetroTel analysis has been revised, sharply
dropping volume of oil viewed as recoverable
from condensate, oil rim at field
15 Nikiski plant again exporting LNG to Asia
ADVERTISE NOW
Exploring the Alaska-Washington Connection
Beginning with the Klondike Gold Rush in 1897 and secured by the Alaska-Yukon-Pacific Exposition of 1909, the partnership
between the two states impacts our economies now more than ever.
The Alaska-Washington Connection celebrates the enduring economic relationship between Alaska and Washington with a
comprehensive look at new developments in the Alaska-Washington trade. Feature articles in this year's magazine will
include companies, projects and trends in the mining, oil and gas, transportation, tourism, construction and infrastructure
development sectors of the Alaska economy.
Distribution will include 30,000 copies in print and electronic formats to be sent to all Petroleum News and Mining News
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150
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PETROLEUM NEWS
•
3
WEEK OF JUNE 17, 2012
Alaska - Mackenzie Rig Report
Rig No.
Rig Location/Activity
Operator or Status
Alaska Rig Status
The Alaska - Mackenzie Rig Report as of June 14, 2012.
Active drilling companies only listed.
TD = rigs equipped with top drive units WO = workover operations
CT = coiled tubing operation SCR = electric rig
North Slope - Onshore
Doyon Drilling
Dreco 1250 UE
Dreco 1000 UE
Dreco D2000 UEBD
AC Mobile
OIME 2000
14 (SCR/TD)
16 (SCR/TD)
19 (SCR/TD)
25
141 (SCR/TD)
Prudhoe Bay Z-115
Prudhoe Bay MPF-18
Alpine CD4-213
Prudhoe Bay DS 13-15Ai
Kuparuk IR-14
Kuukpik
5
Stacked in Barrow awaiting Barges
Nabors Alaska Drilling
Trans-ocean rig
AC Coil Hybrid
Dreco 1000 UE
Mid-Continental U36A
Oilwell 700 E
Dreco 1000 UE
Dreco 1000 UE
Oilwell 2000 Hercules
Oilwell 2000 Hercules
Oilwell 2000
Emsco Electro-hoist -2
Emsco Electro-hoist Varco TDS3
Emsco Electro-hoist
Emsco Electro-hoist Canrig 1050E
Academy AC electric Heli-Rig
Academy AC electric Heli-Rig
CDR-1 (CT)
CDR-2
2-ES
3-S
4-ES (SCR)
7-ES (SCR/TD)
9-ES (SCR/TD)
14-E (SCR)
16-E (SCR/TD)
17-E (SCR/TD)
18-E (SCR)
22-E (SCR/TD)
28-E (SCR)
27-E (SCR-TD)
105-E (SCR-TD)
106-E (SCR/TD)
Stacked, Prudhoe Bay
Kuparuk 2M-01
Prudhoe Bay Stacked out
Prudhoe Bay Stacked out
Prudhoe Bay X-22A
Stacked out
Stacked out
Prudhoe Bay Stacked out
Prudhoe Bay Stacked out
Prudhoe Bay Stacked out
Stacked, Deadhorse
Stacked, Milne Point
Stacked, Deadhorse
Stacked
Presently in Deadhorse
Stacked at Deadhorse
This rig report was prepared by Marti Reeve
BP
BP
ConocoPhillips
BP
ConocoPhillips
JUDY PATRICK
Rig Owner/Rig Type
North Slope Borough
Available
ConocoPhillips
Available
Available
BP
Available
Available
Available
Available
Available
Available
Available
Available
Available
Great Bear Petroleum
Available
*Nabors 27-E will be under contract at Oooguruk/Nuna for Pioneer this winter
Nordic Calista Services
Superior 700 UE
Superior 700 UE
Ideco 900
1 (SCR/CTD)
2 (SCR/CTD)
3 (SCR/TD)
Parker Drilling Arctic Operating Inc.
NOV ADS-10SD
272
NOV ADS-10SD
273
Prudhoe Bay Drill Site C-27
Prudhoe Bay Well Drill Site B-05C
Kuparuk Well 2T-209
BP
BP
ConocoPhillips
Prudhoe Bay final construction and commission
Prudhoe Bay final construction and commissioning
BP
BP
North Slope - Offshore
BP (rig built & being assembled by Parker)
Top drive, supersized
Liberty rig
Endicott SDI for Liberty oil field
Nabors Alaska Drilling
OIME 1000
OIME 2000
Oilwell 2000
19-E (SCR)
245-E
33-E
Oooguruk ODSN-25
Oliktok Point OI20-07
Prudhoe Bay Stacked out
Doyon Drilling
Sky Top Brewster NE-12
15 (SCR/TD)
Spy Island SP 16-FN3
BP
Pioneer Natural Resources
ENI
Available
ENI
Cook Inlet Basin – Onshore
Aurora Well Service
Franks 300 Srs. Explorer III
AWS 1
At Swanson River assorted workovers
Cook Inlet Energy
Atlas Copco RD20 34
Undergoing winterization
at W. McArthur River Unit
Doyon Drilling
TSM 7000
Arctic Fox #1
Beluga BRU 242-04
Taylor
Glacier 1
Stacked Marathon Yard
Nabors Alaska Drilling
Continental Emsco E3000
Franks
IDECO 2100 E
Rigmaster 850
273
26
429E (SCR)
129
Stacked, Kenai
Stacked
Stacked
Kenai Stacked out
Hilcorp Alaska LLC
Cook Inlet Energy
ConocoPhillips
Kenai Land Ventures
working for Buccaneer
Available
Available
Available
Available
Cook Inlet Basin – Offshore
Hilcorp Alaska LLC (Kuukpik, labor contract)
428
XTO Energy
National 1320
A
National 110
C (TD)
Spartan Drilling
Baker Marine ILC-Skidoff, jack-up
Cook Inlet Energy
National 1320
35
Steelhead Platform,
Well M-29 Workover
Hilcorp Alaska LLC
Baker Hughes North America rotary rig counts*
Coil tubing cleanout planned off Platform
A in the near future
Idle
Spartan 151
Upper Cook Inlet KLU#1
Being assembled Osprey platform
XTO
XTO
Set down at Roland Bay
Cook Inlet Energy
51
Still out of the NWT, but is again
available
US/Highest
US/Lowest
Canada/Highest
Canada/Lowest
4530
488
558
29
December 1981
April 1999
January 2000
April 1992
*Issued by Baker Hughes since 1944
Available
Central Mackenzie Valley
Akita/SAHTU
Oilwell 500
Year Ago
1,855
232
33
Highest/Lowest
Canadian Beaufort Sea
SDC
June 1
1,980
156
47
Escopeta
Mackenzie Rig Status
SDC Drilling Inc.
SSDC CANMAR Island Rig #2
June 8
1,984
230
48
US
Canada
Gulf
Available
The Alaska - Mackenzie Rig Report
is sponsored by:
4
PETROLEUM NEWS
E X P L O R A T I O N
&
•
WEEK OF JUNE 17, 2012
P R O D U C T I O N
Major materials on
order for Pt. Thomson
ExxonMobil says that subject to EIS completion it will be laying
gravel for Point Thomson initial production system this winter
By KRISTEN NELSON
Petroleum News
S
ubject to completion of the environmental impact statement and a record
of decision from the Corps of Engineers,
ExxonMobil will begin infrastructure
work at Point Thomson this winter.
Lee Bruce, ExxonMobil’s senior project manager for Point Thomson, told the
Senate Judiciary Committee June 12 that
all major facilities equipment is on order
for the initial production system, the IPS,
and he said some of those materials, for
vertical support members for pipelines,
were arriving in Seward the evening of the
hearing.
Equipment comes in by ice road and
barge, Bruce said, while personnel travel to
the remote site by helicopter.
He said that from a project standpoint
they’re dealing with a “very remote ... hostile environment ... (with) very limited
access.”
There are old pads at Point Thomson,
and the main pad was substantially rebuilt
earlier for the drilling of two wells, but
there is no infrastructure linking Point
Thomson to existing central North Slope
facilities in the Deadhorse area.
Limited access
www.PetroleumNews.com
Kay Cashman
PUBLISHER & EXECUTIVE EDITOR
ADDRESS
Mary Mack
CHIEF FINANCIAL OFFICER
P.O. Box 231647
Anchorage, AK 99523-1647
Kristen Nelson
EDITOR-IN-CHIEF
Clint Lasley
GM & CIRCULATION DIRECTOR
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ADVERTISING DIRECTOR
Bonnie Yonker
AK / NATL ADVERTISING SPECIALIST
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OWNER: Petroleum Newspapers of Alaska LLC (PNA)
Petroleum News (ISSN 1544-3612) • Vol. 17, No. 25 • Week of June 17, 2012
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Barges have a window of about 90 days
from the middle of July to the latter part of
September, he said, with barging shut
down for two to three weeks around Labor
Day for whaling.
He said the ice road from existing central North Slope infrastructure can be up
running by the end of January, early
February, but by the end of April or the
first week of May the ice road season ends,
allowing about three months to move large
pieces of equipment out by ice road.
Judiciary Chair Hollis French, DAnchorage, asked whether the planned IPS
facilities could be expanded.
Bruce said the facilities are designed to
handle 200 million cubic feet of gas per
day and produce 10,000 barrels per day of
condensate. The gas will be re-injected
once the condensate is removed and the
liquids will be shipped down a new
pipeline to be built to the liquids line
which runs from Badami to central North
Bruce said the facilities are
designed to handle 200 million
cubic feet of gas per day and
produce 10,000 barrels per day of
condensate.
Slope facilities.
Bruce said the IPS will provide an
understanding of the resource, the connectivity of the wells, the reservoir and what it
takes to work in such a remote environment.
The schedule
Bruce said the rig used for the first two
wells came out to Point Thomson by ice
road but was demobilized after drilling
was completed.
The rig comes back out to Point
Thomson again in 2014-15 to drill a disposal well and to complete the first two
wells for production; it will then move to
the west pad and will be in the final stages
of drilling the west pad well when the
facilities start up, he said. The settlement
agreement requires drilling the west pad
well by the winter season of 2016, but
Bruce said it makes more sense to drill it as
soon as the rig is available.
Startup is scheduled for the winter season of 2015-16, but no later than May 1,
Bruce said.
The schedule in the plan ExxonMobil
filed with the Division of Oil and Gas (see
story in May 27 issue) shows infrastructure
construction starting in 2013, with both
infrastructure and gathering lines completed in mid-2015. Main sealift and module
installation happens in 2015 and early
2016.
The IPS is part of the Point Thomson
settlement agreement reached between the
State of Alaska and the Point Thomson
working interest owners earlier this year,
which requires an initial production system for 10,000 barrels per day as the first
phase of development. The IPS would be
followed by either an expanded gas cycling
project, a major gas sale or shipment of gas
to Prudhoe Bay for re-injection there and
ultimate sale of the gas. Contact Kristen Nelson
at knelson@petroleumnews.com
PETROLEUM NEWS
•
5
WEEK OF JUNE 17, 2012
E X P L O R A T I O N
&
P R O D U C T I O N
Serenity masks oil sands unease
Dive in oil prices puts project economics under microscope; analysts say operators could be forced to put projects on back burner
By GARY PARK
For Petroleum News
O
n the surface, it appears like business
as usual in the Alberta oil sands.
Cenovus Energy has received approval
from regulators for the initial 45,000 barrels
per day phase of a 130,000 bpd project at its
Narrow Lakes lease — its third thermal
recovery operation.
BlackPearl Resources launched the regulatory process for its Blackrod project,
seeking approval for an 80,000 bpd thermal
venture, starting at 20,000 bpd.
Nothing unusual. Just the normal steady
stream of new developments working their
way toward construction starts.
But both raised questions about the
industry’s ability to push ahead as falling oil
prices have started to push the oil sands
closer to their economic development
threshold.
Cenovus,
in
partnership
with
ConocoPhillips, hinted at its concern by
delaying the scheduled start of first oil from
Narrows Lake to 2017 from 2016, saying
that depended on “industry activity and the
associated demand for labor and materials.”
A company spokeswoman said some
inflation is anticipated “so there’s no need
for us to rush into it right now,” even though
Cenovus is targeting a doubling of its net
asset value over the 2010-15 period.
Analysts see unease
However, analysts were less constrained,
suggesting the slowdown for Narrows Lake
points to unease as the sector prepares for
work to start in 2015 on a wave of new projects and expansions.
Andrew Potter, with CIBC World
Markets, said the one-year delay is “not
overly significant (but) the fact that the best
operator with the best projects is somewhat
cautious on timing is a negative read
through the industry.”
The announcement coincided with a
report from the Petroleum Human
Resources Council of Canada that at least
6,000 more workers will be needed for oil
sands construction within three years.
Randy Ollenberger, managing director
of BMO Capital Markets, estimated the
first phase of Narrows Lake will cost about
C$30,000-C$32,000 per flowing barrel,
pointing to a cost estimate of C$1.2 billionC$1.28 billion — although the partners
have not released cost projections.
Options for capital
BlackPearl added its own cautionary
note about the C$800 million first phase for
Blackrod, which company President John
Festival said will likely come on stream in
about four years, assuming regulatory
approval within 18 to 24 months.
He said BlackPearl has several options
for raising the capital needed — equity, debt
and selling some non-core properties to
cover costs of about C$100 million a year
— but hedged his bets by leaving the
prospect of a partnership on the table.
Jeff Martin, an analyst with Peters &
Co., agreed BlackPearl has a “large degree
of financial flexibility” to raise the capital,
but added a “financing decision could easily be delayed without compromising the
timelines.”
However, while Cenovus and BlackPearl
embark on their ventures, there is a growing
list of opportunities being dangled in front
of potential bidders.
The latest is Koch Industries, which has
“The volatility in oil prices may
make it more difficult for
companies to complete deals (asset
sales, joint ventures, corporate
sales).” —Andrew Potter, CIBC World
Markets
set an Aug. 9 deadline for bids on stakes in
six properties covering 220,000 net acres,
with total bitumen-in-place estimated at
more than 8 billion barrels, with 2.9 billion
barrels rated as recoverable from total production of 300,000 bpd.
Koch, owned by the billionaire Koch
brothers, has previously backed away from
the oil sands.
In 2003 it decided against proceeding
with the Fort Hills mining project after
years of study and engineering work. That
asset is now owned by Suncor Energy and
France’s Total.
Other assets being marketed include
offerings from ConocoPhillips and Royal
Dutch Shell.
Search for white knights
But the search for white knights generated a note from Potter to investors titled
“Fear and loathing in the oil patch,” warning
that the month-long erosion of West Texas
Intermediate prices is putting many possible
deals on ice.
“The volatility in oil prices may make it
more difficult for companies to complete
deals (asset sales, joint ventures, corporate
sales),” he said.
Potter said the biggest challenge faces
Connacher Oil & Gas, which owns an
Alberta thermal oil sands project, a heavy
oil refinery in Montana and conventional
properties and is reviewing its strategic
alternatives after an executive shake-up.
Samir Kayande, an analyst at IGT
Investment Research, said Connacher’s
struggles could force it to shut in production, which averaged 12,400 bpd in the first
quarter.
The oil price plunge and a glut of crude
has promoted Wood Mackenzie, a global
research consultant, to suggest the oil sands
sector may be forced to put some projects
on the back burner.
“Oil sands projects display some of the
highest breakevens of all global upstream
projects,” the firm said. “The potential for
wide and volatile differentials could result
in operators delaying or cancelling unsanctioned projects.”
During the 2008-09 recession more than
C$80 billion worth of projects were
shelved, amended or cancelled when oil
plunged below US$40 per barrel and corporate credit evaporated.
see SANDS UNEASE page 7
6
PETROLEUM NEWS
N A T U R A L
•
WEEK OF JUNE 17, 2012
G A S
Industry adapted to 2011 demand spike
Report says LNG industry responded after tsunami in Japan, with year-over-year acquisition of liquefied natural gas up 9 percent
By BILL WHITE
Researcher/writer for the Office
of the Federal Coordinator
I
t took a natural disaster to shake up the
industry, but LNG in 2011 proved itself
for the first time as a fuel flexible enough to
supply short-term surges in demand, a new
report on the industry says.
“The role of LNG
as a flexible and
secure energy source
as well as the prompt
response to provide
back-up
through
additional supplies
and cargo diversions
to compensate for the
sudden loss of nuclear
capacity in Japan ... BILL WHITE
has been a credit to
the industry,” said the International Group
of Liquefied Natural Gas Importers in a 38page report titled “The LNG Industry in
2011.”
The LNG industry has been largely
defined by tanker loads sailing fixed routes
under long-term contracts between specific
liquefaction plants and LNG users.
Although that remained the norm for
2011, a significant short-term market
emerged after an earthquake-spawned
tsunami in March 2011 crippled the
Fukushima nuclear power plant in Japan
and prompted that country to idle nuclearpower capacity across the nation. Japan
imported much more LNG, oil and coal last
year as replacement fuels.
In all, LNG buyers worldwide acquired
240.8 million metric tons of LNG last year,
a 9 percent increase. That works out to 32
billion cubic feet of gas per day on average.
About one-quarter of that total, 61.2 million
metric tons, was imported under spot or
short-term (less than four years) contracts, a
50 percent increase.
More tankers diverted
Besides more spot and short-term sales,
more LNG tankers were diverted from their
planned destinations — particularly from
North America and Europe — and rerouted
to more lucrative markets — particularly in
Asia. In addition, 44 cargoes were delivered
last year to North America and Europe and
then immediately re-exported to higher-paying markets; in 2010, this occurred just 19
times, the report said.
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On the LNG-making side of the market,
Qatar was the big winner.
That Persian Gulf nation is the world’s
biggest LNG supplier, and has capacity to
make 82 million metric tons of LNG —
enough to supply 34 percent of global
demand last year. (82 million tons is the
equivalent of about 10.9 billion cubic feet a
day.) Most of that capacity — 52 million
metric tons — came on line since 2009. But
much of that capacity was idle ... until
Japan’s nuclear-power crisis. So Qatar was
well-positioned to serve the demand spike.
Qatar’s exports grew 35 percent last year,
to a total of 75.4 million metric tons, the
report said. Twenty-seven percent of Qatar’s
LNG was sold on a spot and short-term
basis.
Japan imported 79.1 million metric tons
of LNG last year, up 8.2 million metric tons
or 12 percent from 2010. Qatar’s exports to
Japan grew by 4.4 million metric tons last
year.
Japan’s share of LNG grew
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Other highlights from the new report:
•Japan accounted for 42 percent of Asia’s
additional LNG imports last year. Its share
of global LNG consumption grew to 33 percent. Japan received 1,438 LNG shipments
last year, an average of almost four per day.
•In all, Asia nations received 63 percent
of the world’s LNG. Asian consumption
grew 15 percent last year. The world No. 2
LNG consumer, South Korea, imported
35.6 million metric tons, up 9 percent.
China took 13.1 million metric tons, up 36
percent. India imported 12.3 million metric
tons, up 37 percent, as its domestic natural
gas production lagged.
•European imports were flat after growing 25 percent a year earlier.
•North American imports sank 25 percent due mainly to growing production of
less-expensive shale gas. Much of the LNG
contracted for delivery to the United States
ended up in Asia or Europe.
•South American demand grew 14 percent. Strong economies in Argentina and
Chile boosted the total. Brazil imported
much less LNG due to more hydroelectric
generation last year.
•The LNG tanker fleet grew by 16 ships
to total 359 vessels. That compares with 25
tankers added to the fleet in 2010. Fifty-nine
ships were on order, with almost all of them
to be delivered in 2013 or later.
•The world had 24 liquefaction plants
operating in 18 countries at the end of 2011.
Just one LNG site — in Qatar — was commissioned last year. If all the plants operated at full capacity, they could make 278 million metric tons of LNG, compared with
global demand of 241 million.
•Five liquefaction plants were under construction last year — three in Australia, one
in Angola and one in Papua New Guinea.
Their combined capacity will be 46 million
metric tons a year.
•In addition, four Australian and one
Indonesian liquefaction projects got the go
ahead last year to start construction. Their
combined capacity will be 27 million metric
tons a year. A variety of other LNG projects
are under discussion in Australia, Africa, the
United States and Canada.
•As for LNG import terminals, 25 countries host 89 LNG regasification plants.
Their total capacity was 640 million metric
tons a year. As evidence of LNG’s growth:
In 2001, 11 countries had 40 import terminals.
The Paris-based non-profit trade group’s
2011 report itemizes every country’s
imports and exports, each LNG plant and
LNG regasification terminal, and each
tanker. Editor’s note: This is a reprint from the
Office of the Federal Coordinator, Alaska
Natural Gas Transportation Projects,
online at www.arcticgas.gov/lng-industryadapted-well-2011-demand-spike-reportsays.
Š
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PETROLEUM NEWS
•
7
WEEK OF JUNE 17, 2012
E X P L O R A T I O N
&
P R O D U C T I O N
Linc proposing unit at Point Mackenzie
Aussie independent wants to investigate geologic feature encountered by a previous well and subsequent seismic acquisitions
A
s it continues to pursue ventures
across the state, Linc Energy (Alaska)
Inc. plans to return to its first Alaska well
next year to investigate some intriguing
geologic features.
The domestic subsidiary of an
Australian-based independent is asking
state officials to form the Angel unit on
some 1,932 onshore acres in the Cook Inlet
basin. The proposed unit would cover a neat
rectangle including pieces of one State of
Alaska lease and one Alaska Mental Health
Trust Authority lease near Point Mackenzie,
north of Anchorage.
In its application, Linc proposed a twoyear exploration program including seismic
acquisition and drilling, followed by a
potential development plan in late 2014 or
2015.
The Alaska Department of Natural
Resources is taking comments through July
10.
The program would investigate a geologic “feature” of the Pittman Anticline that
extends into both the Tyonek and Hemlock
formations. “At the Tyonek depth the structure appears largely as a southwest plunging
nose with four-way dip closure at crest. At
the Hemlock (or equivalent) depth, the fourway dip closure appears to expand into a
larger, more expansive closure,” Linc wrote
in its application to the state. Additionally,
the company said, recent seismic acquisitions showed “strong amplitude anomalies”
and “apparent velocity-induced depressions
of seismic reflectors over the crest of the
feature,” indicators that “would be expected
in the presence of gas charged sands.”
In the first year of exploration, Linc
would acquire 3-D seismic over the proposed unit area as well as 2-D seismic
extending to the east, beyond the proposed
unit boundaries.
In the second year, Linc would drill a
well into the Tyonek/Hemlock interval.
With successful results, Linc would submit
an application for a participating area within the unit and building infrastructure sometime around late 2014 or 2015, at the earliest.
If Linc failed to meet any of those dead-
lines, the unit would terminate and it would
lose the acreage. Although both leases
expired on June 1, 2012, Linc said it has
been in discussions over the unit with land
managers from both agencies since October
2011.
COURTESY LINC ENERGY ALASKA
By ERIC LIDJI
For Petroleum News
Chasing LEA No. 1
Linc drilled the LEA No. 1 well some
13,000 feet north of the proposed unit in
November 2010, just nine months after
arriving in Alaska. Although the well
encountered several gas-bearing coal
seams, after subsequent tests Linc decided
the structure was “too tight” to produce
without “swabbing” the well with large
amounts of formation water.
“The conclusion from the testing is that
although gas is trapped within the coal,
there is not sufficient natural fracturing in
the coal to allow for the recovery of commercial quantities of gas,” Linc said in May
2011, while noting the well had encountered a “significant” coal seam that
“appears to be highly suitable for
Underground Coal Gasification,” perhaps
even enough to support future development
in the region.
At the time, Linc Energy CEO Peter
Bond said, “At the end of the day exploration is a numbers game, the more smart
wells you drill the more likely you are going
to be successful. Linc Energy has an
extraordinary record of getting our exploration targets right the majority of the time
and I still think the coal measures we’ve discovered via the LEA No. 1 program will
see ANGEL UNIT page 9
continued from page 5
SANDS UNEASE
Wood Mackenzie noted that 16 bitumen
projects are now scheduled for start up by
2016, adding a combined 1 million bpd of
incremental production.
But the sector is faced with mounting
concerns, including high demand for
skilled labor, congested pipelines to the
United States markets and competition for
pipeline space.
The report said there is “little scope to
adjust near-term production, due to the
amount of capital already sunk. However, if
the external environment proves to be unattractive, companies do have the option to
significantly change their longer-term production outlook.”
Wood Mackenzie included Cenovus’
Narrow Lakes along with Canadian natural
Resources’ Horizon, and the Fort Hills and
Joslyn projects by the Suncor-Total partnership on the list of schemes that are “prone
to delay.” Contact Gary Park through
publisher@petroleumnews.com
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8
PETROLEUM NEWS
F I N A N C E
&
•
WEEK OF JUNE 17, 2012
E C O N O M Y
EIA projects $95 WTI 2nd half of year
Agency says dropping crude prices from May to early June reflect concerns about world economic conditions and oil demand growth
By KRISTEN NELSON
Petroleum News
W
est Texas Intermediate crude oil
spot prices fell from $106 per barrel May 1 to $83 per barrel June 1,
“reflecting market concerns about world
economic and oil demand growth,” the
Department of Energy’s Energy
Information Administration said June 12
in its latest Short-Term Energy Outlook.
EIA said it is now projecting WTI to
average $95 per barrel in the second half
of the year, a drop of almost $11 a barrel
from the agency’s May forecast. The U.S.
refiner acquisition cost of crude oil is
projected to average $100 per barrel in
the second half of the year, a similar drop
from EIA’s May forecast.
The agency said it expects oil prices to
remain relatively flat next year. The forecasts are based on a 2.2 percent growth in
U.S. real gross domestic product this year
and a 2.4 percent growth next year, and
on world oil-consumption-weighted real
GDP growth of 3.1 percent this year and
3.5 percent next year.
“The recent economic and financial
news that points towards weaker economic outlooks could lead to lower economic
growth forecasts and further downward
revision of EIA’s crude oil price forecasts,” the agency said.
EIA said WTI is expected to average
$97 per barrel this year and $102 per barrel in 2013, about $7 per barrel lower than
the May forecast.
Markets loosening
EIA said global oil markets have loosened in recent months, with production
outpacing consumption by 700,000 bar-
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Lower 48 onshore production is
expected to grow by 660,000 bpd
this year, Gulf of Mexico
production to stabilize after fall
last year, but Alaska output is
projected to continue to decline by
30,000 bpd.
rels per day in the first quarter, forecast to
grow to 1.2 million bpd in the second
quarter. The agency said its economic
growth assumptions are unchanged from
last month, but its crude oil price forecast
was lowered because of increased current
and forecasted supply, primarily from
countries outside the Organization of the
Petroleum Exporting Countries, OPEC,
“and to reflect changes in the relative
strength of the upside and downside risks
buffeting oil markets.”
Non-OPEC production is expected to
rise by 800,000 bpd this year and a further 1.2 million bpd in 2013, with North
America the largest area of non-OPEC
production growth with production
increases of 890,000 bpd expected this
year and 470,000 bpd next year, “resulting from continued production growth
from U.S. onshore shale and other tight
oil formations and Canadian oil sands,”
EIA said.
Production from Brazil is expected to
increase by 20,000 bpd this year and by
120,000 bpd in 2013, and Kazakhstan is
expected to increase its production by
160,000 bpd next year, with commercial
production beginning from the Kashagan
field.
China, Russia and Colombia are also
expected to have production increases
over the next two years, while production
declines are expected in Mexico and the
North Sea.
OPEC members are expected to produce more than 30 million bpd over the
next two years to accommodate expected
increases in demand and to counterbalance supply disruptions, EIA said, with
an expected increase of 900,000 bpd this
year followed by a decrease of 500,000
bpd in 2013, “as non-OPEC supply
growth increases and stocks remain flat.”
EIA said OPEC members are the
world’s swing producers because only
they have surplus or spare oil production
capacity, capacity expected to average 2.5
million bpd this year and 3.4 million bpd
next year.
U.S. imports down
U.S. crude oil production increased by
an estimated 200,000 bpd to 5.67 million
bpd last year and is forecast to average
6.32 million bpd this year, EIA said, an
upward revision of 150,000 bpd from the
agency’s May forecast, “and the highest
annual level of production since 1997.”
Lower 48 onshore production is
expected to grow by 660,000 bpd this
year, Gulf of Mexico production to stabilize after falling last year, but Alaska output is projected to continue to decline by
30,000 bpd.
Crude oil output for 2013 is expected
to rise a further 400,000 bpd, most of that
from increases in Lower 48 onshore production, “driven by increased oil-directed
drilling activity, particularly in onshore
tight oil formations,” EIA said.
The agency said Baker Hughes reported 1,386 onshore oil-directed drilling rigs
on June 1, up from 777 at the beginning
of 2011.
The share of U.S. consumption met by
crude oil and product imports has been
falling since it peaked at more than 60
percent in 2005, EIA said. It averaged 45
percent in 2011, down from 49 percent in
2010 and the agency said it “expects that
the total net import share of consumption
will continue to decline to 42 percent in
2012 and to 40 percent in 2013 as a result
of the substantial increases in domestic
crude oil production.”
Natural gas use up
EIA said natural gas consumption in
the U.S. is expected to average 69.5 billion cubic feet per day this year, up 2.7
bcf per day (4.1 percent) from last year —
and an increase of 0.7 bcf per day from
the agency’s May forecast.
Total U.S. marketed production of natural gas grew by 4.8 bcf per day last year,
“driven in large part by increases in shale
gas production,” the agency said.
Production is expected to grow this year,
but at a slower rate than last year, “as low
prices reduce new drilling plans.” EIA
said Baker Hughes is reporting a natural
gas rig count of 588 on June 1, down from
a 2011 high of 936 in mid-October, the
lowest gas rig count since 1999.
Domestic natural gas prices averaged
$2.43 per million Btu at Henry Hub in
May, up 48 cents from April, the first
average monthly increase price in almost
a year, EIA said.
“Despite the increases, prices remain
at historically low levels; the May 2012
price averaged 44 percent less than the
May 2011 price,” EIA said, crediting
abundant supplies and a warm winter as
contributing to current low prices.
The agency expects the Henry Hub
price to average $2.55 per million Btu this
year, a small upward revision from $2.45
in May’s forecast. The 2013 forecast has
been revised to $3.23 per million Btu, up
from $3.17 in May. Contact Kristen Nelson
at knelson@petroleumnews.com
JoAnn Zeringue, Sales
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PETROLEUM NEWS
•
F I N A N C E
9
WEEK OF JUNE 17, 2012
&
E C O N O M Y
Petronas stalled in Canadian takeover
By GARY PARK
For Petroleum News
P
etronas is full steam ahead on one of its
Canadian LNG ventures, but sidelined
in its ambition to make a possible C$5 billion acquisition.
Anuar Ahmad, executive vice president
of the Petronas gas group, said the
Malaysian state-owned energy giant’s efforts
to take over an unidentified Canadian natural gas producer have stalled.
“There has been no progress on that,” he
told a press conference at the World Gas
Conference 2012 in Kuala Lumpur.
He offered no further details beyond saying “it would be difficult to mention what
deals we are looking at” when asked what
continued from page 7
ANGEL UNIT
add a lot of value to the company in the
longer term.”
In addition to the previous Linc well, Pan
American Petroleum Corp. drilled the Big
Lake USA No. 1 in 1968 some 4,000 feet to
the east and also encountered gas prone
intervals.
Unitization needed
Given the scant exploration history, Linc
said it is “the only company that has
expressed any interest at any time within the
past 40 years in developing the acreage
within the proposed Angel unit.” With the
general lack of interest in the region, failing
to unitize the leases would be “tantamount
to condemnation” of the region for future
might replace the C$5 billion deal.
The setback comes only two months after
Petronas indicated it expected to announce a
deal within three months.
At the time Shamsul Azhar Abbas,
Petronas’ chief executive officer, said “there
are quite a few candidates out there willing
to talk.”
The assumption was that Petronas, in
going public ahead of a transaction, was
alerting the Canadian government to its
hopes of becoming the largest state-owned
foreign enterprise to enter Canada’s LNG
sector.
However, partners in a Petronas and
Progress Energy Resources LNG venture
have confirmed they are on track for a sanctioning decision in 2014 and possible startup
in 2018.
Last year Petronas paid C$1.07 billion
for a 50 percent stake in 150,000 acres of
Progress shale properties in British
Columbia’s North Montney play and 80 percent ownership of a planned LNG export
terminal on the Pacific coast.
Ahmad said Petronas is talking to some
parties who are interested in joining the project, again without elaborating.
“We’ve narrowed our site selection down
to four sites in the Kitimat and Prince Rupert
areas and we’re currently negotiating on our
two primary selected sites,” Progress Chief
Executive Officer Mike Culbert said in a
webcast from a New York conference.
“With Petronas’ expertise in LNG we’re
also moving along on the off-take customer
discussions in a very robust manner as well,”
he said.
Ahmad said Petronas plans to sell its
LNG exports at prices linked to crude oil.
Culbert said the partners will spend
about C$350 million this year to develop the
joint venture land, which started initial deliveries in late May at 22 million cubic feet per
day, regardless of a Progress decision to cut
its 2012 capital budget by C$200 million
and shut-in 10-15 percent of its gas production because of poor North American prices.
He said discussions are under way with
companies capable of building a 300-mile
pipeline from North Montney to the coast. lease sales.
“While other lessees and potential
lessees have been unwilling or unable to
develop that Angel prospect, Linc is willing
to make that commitment,” Linc wrote to
the state.
Although Linc holds five leases in the
area, covering some 14,758 acres, its proposed unit includes only a small portion of
two of those leases. The company pointed to
state regulations requiring a unit to cover the
minimum area needed to cover a potential
hydrocarbon accumulation. The small portion of the two leases “encompass the extent
of the seismic amplitude anomaly as interpreted by Linc with currently available
data.”
Because of precedent cases, Linc is concerned it might be denied unitization on the
grounds of being the sole working interest
owner in the leases in the proposed unit.
Although permitted, single-lessee units
are seen as less necessary than multiple-lessee units because unitization isn’t needed to
aide private negotiations. In previous cases,
such as the West McArthur River unit and
the Badami unit, the state approved unitization in spite of single lessees, citing other
reasons why unitization served the public
interest.
Linc said unitization is necessary in its
case, in part, because its State of Alaska
lease completely surrounds the non-contiguous Alaska Mental Health Trust
Authority lease.
ment in Alaska.
Linc holds an Underground Coal
Gasification exploration license from the
Alaska Mental Health Trust Authority in
three areas of the Cook Inlet region and the
Interior.
The company also plans to drill five
wells at the Umiat prospect on the North
Slope this winter and recently launched a
website
for
the
project
at
www.lincenergyumiat.com.
Linc arrived in Alaska in March 2010
after purchasing 123,000 acres of Cook
Inlet area state and Native leases from San
Francisco-based GeoPetro Resources in
March 2010. The company later acquired
the Umiat prospect from a subsidiary of
Renaissance Alaska. Umiat project website
In addition to its conventional gas exploration in Cook Inlet, Linc is exploring for oil
and investigating the potential of
Underground Coal Gasification develop-
Contact Gary Park through
publisher@petroleumnews.com
LET’S BE MORE PREPARED
THAN EVER.
Shell is dedicated to preventing and preparing for any safety challenges we may face. To support
2012 plans for drilling up to five exploration wells off the northern coast of Alaska, Shell has created
an unprecedented spill response plan. Offshore, onshore and near-shore response teams and Arctic-appropriate
equipment will be ready 24 hours a day, and operational within an hour. The purpose built, ice-class, spill
response vessel Nanuq and the newly launched Aiviq, a 360-foot ice-class anchor handler, add to Shell’s
capabilities. A sub-sea containment system, enhanced response plan and upgraded blow out preventor further
strengthen the available assets. With these capabilities in place, Shell is more prepared than ever before.
www.shell.us/alaska
Contact Eric Lidji
at ericlidji@mac.com
10
PETROLEUM NEWS
•
WEEK OF JUNE 17, 2012
G O V E R N M E N T
DNR: Walker appeal has ‘no legal grounds’
State officials rebut claims made in appeal of Alaska’s recent settlement of conflict over the Point Thomson oil and gas unit
By WESLEY LOY
For Petroleum News
A
court challenge to the Point
Thomson settlement has no legal
basis and the state will seek to have it dismissed, an official with the Alaska
Department of Natural Resources says.
The comments come in response to an
administrative appeal Bill Walker has
filed in state Superior Court in
Anchorage.
Walker is an Anchorage attorney who
once ran against Gov. Sean Parnell.
He is challenging the state’s recent settlement of litigation surrounding the
undeveloped Point Thomson unit on
Alaska’s eastern North Slope. Walker
contends the agreement, which the
Parnell administration negotiated with
field operator ExxonMobil, is illegal and
a bad deal for the state.
State officials contend the agreement
is a strong one that should, at long last,
compel ExxonMobil and its partners to
start producing from the rich but techni-
LAND & LEASING
State finalizes Beaufort lease expirations
The Alaska Department of Natural Resources finalized the expiration of 13 leases belonging to four different lessees in the state waters of the Beaufort Sea in May.
Starting in the eastern North Slope, ConocoPhillips allowed two leases — ADL
390823 and ADL 390824 — adjacent to the northern border of the Point Thomson
unit to expire.
Savant Alaska LLC allowed three offshore leases — ADL 390829, ADL 390830
and ADL 390831 — adjacent to the western border of its Badami unit to expire.
Continuing west, independent investor Samuel H. Cade allowed seven leases —
ADL 390834, ADL 390838, ADL 390839, ADL 390840, ADL 390841, ADL
390844 and ADL 390845 — in the area near the Duck Island unit and the Liberty
project to expire.
Paul Craig allowed one lease — ADL 390852 — north of the Oooguruk unit to
expire.
And in Cook Inlet, Louis J. Jacober transferred a 0.1 percent royalty interest in two
Cook Inlet leases — ADL 391103 and ADL 391104 — to the Spielman Family Trust.
The leases are on the west side of Cook Inlet and operated by NordAq Energy Inc.
—ERIC LIDJI
cally difficult Point Thomson oil and gas
field.
Further, the deal helps advance the
state’s long quest for a pipeline to develop
the North Slope’s vast but stranded natural gas reserves, the officials say.
‘Secret agreement’
“Mr. Walker has no legal grounds to
file an administrative appeal challenging
a settlement entered into by the Attorney
General, and therefore the court has no
jurisdiction,”
DNR
Deputy
Commissioner Joe Balash said in a statement the agency provided June 13 to
Petroleum News.
The state will move to dismiss the
appeal, he said.
Walker contends the settlement
exceeded the authority the state
Legislature has delegated to the DNR
commissioner.
DNR Commissioner Dan Sullivan led
the state’s settlement negotiations with
ExxonMobil, and signed the deal in late
March along with state Attorney General
Michael Geraghty.
One of Walker’s top complaints is that
the state provided no public notice or
opportunity to comment before the
“secret agreement” was signed.
Walker also argues the DNR commissioner improperly agreed to not follow
agency regulations for managing the unit,
and left the method of field development
up to ExxonMobil.
To rebut Walker’s contentions, Balash
cited documents and testimony given
recently to a legislative committee
reviewing the Point Thomson settlement.
Broad settlement authority
State officials argue the settlement is
not even subject to an administrative
appeal such as Walker’s.
“Alaska’s Attorney General has broad
authority to enter into any agreement to
settle litigation that he or she believes is
in the best interest of the State,” Geraghty
wrote in a June 7 letter to state Sen. Hollis
French, an Anchorage Democrat and
chairman of the Senate Judiciary
Committee. “The exercise of this authority is not subject to legislative approval or
administrative review, and requires no
prior public notice or comment. Settling
litigation is an executive branch function,
and a legislative role would violate separation of powers principles.”
Legislative Counsel Donald Bullock
likewise concluded that the attorney general “has broad authority to settle cases
being litigated by the attorney general on
behalf of the state.”
In a June 8 memo to French, Bullock
went on to say: “While there may be different views as to whether each of the
issues addressed in the PTU settlement
agreement was resolved in the way someone else may have resolved an issue, the
attorney general has the discretion to settle all issues of the case within the settlement. The settlement agreement apparsee WALKER APPEAL page 12
PETROLEUM NEWS
•
WEEK OF JUNE 17, 2012
11
12
PETROLEUM NEWS
N A T U R A L
• WEEK OF JUNE 17, 2012
G A S
How natural gas can grab ‘golden’ status
By WESLEY LOY
Figure 2.1 ‫ ٲ‬5HPDLQLQJUHFRYHUDEOHJDVUHVRXUFHVLQWKHWRSÀIWHHQ
For Petroleum News
countries, end-2011
T
he world is poised for a natural gas
boom, but only if industry and regulators make a good showing that it’s safe
to produce abundant unconventional
resources such as shale gas, a new report
from the Paris-based International Energy
Agency says.
“In our judgment, a key constraint is
that unconventional gas does not yet
enjoy, in most places, the degree of societal acceptance that it will require in order
to flourish,” the report says. “Without a
general, sustained and successful effort
from both governments and operators to
address the environmental and social concerns that have arisen, it may be impossible to convince the public that, despite the
undoubted potential benefits, the impact
and risks of unconventional gas development are acceptably small.”
A year ago, on June 6, 2011, the IEA
released a report that posed the question:
“Are We Entering a Golden Age of Gas?”
The new report is a follow-up to the
first and is titled “Golden Rules for a
Golden Age of Gas.”
It lays out what it’ll take to allow natural gas to maximize its position in the
global energy mix.
The ‘golden rules’
The report looks at three types of
unconventional gas resources — shale
gas, coalbed methane and tight gas — and
the enormous contribution they could
make to overall natural gas production by
Convenonal
Russia
United States
China
Iran
Saudi Arabia
Australia
Qatar
Argenna
Mexico
Canada
Venezuela
Indonesia
Norway
Nigeria
Algeria
Tight
Shale
Coalbed methane
0
25
50
75
100
125
150
tcm
^ŽƵƌĐĞ͗/ĂŶĂůLJƐŝƐ͘
local communities, land use and water
resources. Serious hazards, including the
potential for air pollution and for contamination of surface and groundwater, must
be successfully addressed.”
To overcome public fears, the IEA
report offers a set of “golden rules” for
industry and government to follow.
Among them: Engage local communities
prior to exploration; establish baseline
environmental indicators such as groundwater quality; make sure communities
share in the economic benefits; make
smart decisions about where to drill and
fracture; put into place robust rules on
well design, cementing and so forth; consider minimum depth limits on hydraulic
fracturing to reassure people the operation is well away from the water table;
2035.
The authors estimate that remaining
technically recoverable resources of
unconventional gas worldwide approach
the size of remaining conventional
resources, which amount to 420 trillion
cubic meters, tcm.
But unconventional gas extraction has
ignited controversy, for a variety of reasons.
“Producing unconventional gas is an
intensive industrial process, generally
imposing a larger environmental footprint
than conventional gas development,” the
report says. “More wells are often needed
and techniques such as hydraulic fracturing are usually required to boost the flow
of gas from the well. The scale of development can have major implications for
INTERNATIONAL ENERGY AGENCY
Unconventional production could vault gas to dominant global position, but only if industry and government win over public, IEA says
Applying the golden rules could
increase the cost of developing a
typical shale gas well by 7
percent, the report’s authors
estimate.
recycle fresh water used in operations;
strive for zero venting and flaring of natural gas; support robust regulatory
regimes; and accept independent evaluation of environmental performance.
Especially in the United States, where
the scale and pace of unconventional gas
development has been greatest, the report
warns of the “likelihood that regulation
will be driven by events. For example, an
environmental incident linked to unconventional gas development could crystallize public views and prompt new restrictions on unconventional gas production or
the use of hydraulic fracturing.”
A revolution halted?
In a May 29 press release announcing
the new report, IEA Executive Director
Maria van der Hoeven observed: “The
technology and the know-how already
exist for unconventional gas to be produced in an environmentally acceptable
way. But if the social and environmental
impacts are not addressed properly, there
is a very real possibility that public opposition to drilling for shale gas and other
types of unconventional gas will halt the
unconventional gas revolution in its
tracks. The industry must win public confidence by demonstrating exemplary performance; governments must ensure that
appropriate policies and regulatory
regimes are in place.”
Applying the golden rules could
increase the cost of developing a typical
shale gas well by 7 percent, the report’s
authors estimate.
The report makes two projections: a
“golden rules case” and a “low unconventional case.” The position of natural gas in
the world energy mix is very different
under the two scenarios.
Under the golden rules case, total gas
production surges to 5.1 tcm in 2035,
from 3.3 tcm in 2010.
“Greater availability of gas has a
strong moderating impact on gas prices
and, as a result, global gas demand rises
see GAS STATUS page 14
continued from page 10
WALKER APPEAL
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ently has been adopted by the court and
may now be implemented.”
Balash, in a June 7 letter to French,
wrote that “DNR fully stands behind the
decision to settle the Point Thomson litigation.”
He said DNR has not abrogated its
unit management powers and obligations,
and can oppose a Point Thomson development approach that’s not in the public
interest.
Point Thomson is on leased state
acreage along the Beaufort Sea coast,
next to the Arctic National Wildlife
Refuge. Aside from ExxonMobil, major
stakeholders in the unit include BP and
ConocoPhillips. Contact Wesley Loy
at wloy@petroleumnews.com
PETROLEUM NEWS
•
N A T U R A L
13
WEEK OF JUNE 17, 2012
G A S
State revises views on Pt. Thomson oil
2008 PetroTel analysis has been revised, sharply dropping volume of oil viewed as recoverable from condensate, oil rim at field
By KRISTEN NELSON
Petroleum News
W
hat would the impact of a gas blowdown at Point Thomson be on oil
recovery from Alaska’s eastern North
Slope retrograde gas condensate field?
The State of Alaska has a different opinion now than it did in May 2008, when as
part of the Palin administration’s Alaska
Gasline Inducement Act forum in
Anchorage the Department of Natural
Resources’ Division of Oil and Gas presented a study by PetroTel which projected
a difference of 500 million barrels of oil
between a gas blowdown at Point Thomson
— simply producing the natural gas without extracting condensates — and gas
cycling, which would remove condensate
from the gas and ship that liquid to market,
re-injecting the natural gas to maintain
reservoir pressure and allowing for gas production at a later stage of the field’s life.
“The difference is larger than the
expected ultimate recovery from the Alpine
oil field,” the division said in a May 16,
2008, summary of the PetroTel study.
The Point Thomson owners — at that
time primarily ExxonMobil, Chevron and
BP — objected, telling legislators at the
forum that Point Thomson is no Alpine.
grade gas condensate reservoir.”
He said the 2008 study cannot serve as
a realistic basis to review a specific development plan because no consideration was
given in that study to potential restrictions
such as location or size of surface infrastructure or facilities, development costs,
performance of high-pressure facilities, gas
handling constraints or market conditions.
Balash said the 2008 study did not consider any economic or operational constraints or the challenges of permitting a
full field development.
Oil rim volumes
The 2008 study said as much as 400
million barrels of oil could be recovered
from the Thomson Sands oil rim, which
“lies between an overlying highly mobile
Thomson Sands gas cap and an underlying
water leg,” Balash said in the letter.
But PetroTel has done work for the state
since 2008, he said.
Modeling runs done subsequent to the
2008 report indicate there would be serious
challenges in producing “the thin oil column of the main Thomson reservoir”
because wells intended to produce that oil
“would produce gas instead of oil within a
matter of weeks, effectively ending production from the oil rim.”
PetroTel had estimated 400 million barrels of recoverable oil from the oil rim, and
that, Balash said, “in retrospect, appears
unrealistic given these challenges, the current state of technology, and development
costs.”
A review of the 2008 PetroTel study by
the Department of Energy said the PetroTel
findings were “optimistic and open to
question, especially with respect to the
recovery predicted for oil from the oil rim.”
The DOE concluded that very little of the
oil rim oil was recoverable and estimated
gas reserves at 8 trillion cubic feet and liquids at 300 million barrels of condensate, a
number which the Balash letter characterized as “in stark contrast to the earlier 2008
PetroTel estimates of 620-850 million barrels of petroleum liquids.”
Division’s current understanding
Balash said that since the 2008 study
was issued the division “has learned much
more about the reservoir and the challenges
associated with development of the
resource within.”
After the 2008 study was completed, the
division got access to ExxonMobil’s and
BP’s data room, Balash said.
Using information learned from the data
room, and in conjunction with PetroTel, the
division “concluded that when comparing
similar likely scaled full field developments, the potential liquids lost (in blowdown opposed to cycling) would be far less
than the estimates contained in the 2008
see STATE VIEWS page 14
nabors.com
What’s changed?
What was wrong with the PetroTel 2008
study, DNR Deputy Commissioner Joe
Balash told the Senate Judiciary
Committee June 12 in Anchorage, is that it
looked at the resource potential at Point
Thomson without considering volumes
that could economically be recovered.
There are challenges above and below
ground, Balash said — how the reservoir
performs; how the equipment at the surface
can perform.
In the 2008 study, all they wanted to
understand was how the reservoir would
perform without reference to aboveground
constraints, he said. They looked at volumes of 800 million cubic feet a day and
cost wasn’t taken into consideration nor
was the location of pads around the reservoir. And because the reservoir is underwater off Point Thomson, location of pads is a
challenge, he said.
Then there are the mechanical systems
themselves — all those things need to be
taken into consideration, Balash said.
He compared it to the way the U.S.
Geological Survey estimates resources:
first there’s the in-place resource; then what
is technically recoverable; and finally, what
is economically recoverable. That 2008
PetroTel estimate, he said, was somewhere
between the first two.
But as you move closer to economically
recoverable the numbers drop.
Preliminary analysis
In a June 7 letter to Sen. Hollis French,
D-Anchorage, chair of the Judiciary
Committee, Balash said the 2008 PetroTel
study “was a preliminary analysis and was
not designed to evaluate optimal developments scenarios.” The Resource Evaluation
section of the Division of Oil and Gas contracted with PetroTel in 2007 to “perform
geologic and engineering evaluation of the
Point Thomson Sand reservoir,” he said,
and the goal was a technical assessment,
“an independent analysis of the proven and
potential hydrocarbon resources contained
in the reservoir and gain a better understanding of unique issues associated with
development and production of a retro-
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14
PETROLEUM NEWS
•
WEEK OF JUNE 17, 2012
continued from page 13
continued from page 12
GAS STATUS
by more than 50% between 2010 and 2035,” the report says.
“The increase in demand for gas is equal to the growth coming from coal, oil and nuclear combined, and ahead of the
growth in renewables. The share of gas in the global energy
mix reaches 25% in 2035, overtaking coal to become the second-largest primary energy source after oil.”
Under the low unconventional case, total gas production
reaches 4.6 tcm in 2035, and the share of gas in the global
energy mix increases only slightly, from 21 percent in 2010 to
22 percent in 2035. Gas remains well behind coal.
North America focus
The report summarizes the status of unconventional gas
development around the world.
“Until recently, unconventional natural gas production was
almost exclusively a U.S. phenomenon,” the report says.
“Tight gas production has the longest history, having been
expanding steadily for several decades. Commercial production of coalbed methane began in the 1980s, but only took off
in the 1990s; it has leveled off in recent years. Shale gas has
also been in production for several decades, but started to
expand rapidly only in the mid-2000s, growing at more than
45% per year between 2005 and 2010. Unconventional gas
production was nearly 60% of total gas production in the
United States in 2010. While tight gas and shale gas account
for the overwhelming bulk of this, shale gas is expected to
remain the main source of growth in overall gas supply in the
United States in the coming decades. The United States and
Canada still account for virtually all the shale gas produced
commercially in the world, though ... many countries are now
trying to replicate this experience.”
Those countries include Mexico, which has the fourthlargest shale gas resource base in the world after China, the
United States and Argentina.
Mexico’s government is “keen to exploit shale gas
resources to boost the country’s flagging output of conventional oil and gas.”
In IEA’s golden rules case, total U.S. gas production grows
about 34 percent between 2010 and 2035, with almost all of
the increase coming from shale gas production.
In the low unconventional case, U.S. gas production peaks
around 2015 and then goes into decline.
“On the other hand, higher gas prices and limited unconventional production in the Low Unconventional Case prompt
a mini-renaissance in conventional gas output,” the report
says, “driven by the investment capital and rigs freed up by the
shrinking unconventional sector and the possible opening of
more offshore and Arctic acreage as the United States struggles to reduce its imports and the associated bills.”
The IEA report, which The New York Times called
“required reading for regulators and the industry,” is available
at http://bit.ly/JKm399. Contact Wesley Loy at wloy@petroleumnews.com
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PetroTel study.”
PetroTel did contract work for the
Department of Law beginning in
September 2008 and did additional studies
and refinements to their earlier modeling.
After an extensive review the division
concluded that the potential liquid condensate and oil lost if there were an early blowdown at Point Thomson for a major gas
sale “would be significantly less than the
estimates found in the 2008 PetroTel
study.” Balash said DNR couldn’t disclose
the revised estimate “because this information is protected under Alaska law.”
Balash said the proof would be played
out in a very public way as the field is
developed.
He said there was data and information
the state agreed not to make public, but
said the administration could explore what
information they could share with legislators in a confidential setting.
Original estimates
The 2008 PetroTel study estimated 8.5
tcf to 10.4 tcf of gas in place, with associated condensate of 490 million to 600 million barrels and a potential oil rim of 580
million to 950 million barrels.
With a blowdown, PetroTel estimated
recovery of 6-7 tcf of gas over a 12-15 year
period, but only 127-156 million barrels of
liquids, about 26 percent of the in-place
volume, with oil-rim oil recovery varying
from 30 million to 150 million barrels, a 316 percent recovery, depending on the
number of wells drilled.
PetroTel told legislators in May 2008
that Point Thomson could be “the thirdlargest oil field” on the North Slope, after
Prudhoe Bay and Kuparuk.
If Point Thomson were developed with
gas cycling, 62 percent of the condensate is
recovered over a 10-year period (300-370
million barrels) along with 39 percent of
the oil rim (225-370 million barrels), and
over 20 years of gas recycling, 76 percent
of the condensate is recovered (370-450
million barrels) and 43 percent of the oil
rim (250-400 million barrels).
Exxon, Chevron, BP disagree
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In mid-June 2008, ExxonMobil and
Chevron told legislators that the PetroTel
report was based on erroneous assumptions about how much oil could be recovered from the field under any scenario.
The companies said gas, not oil, is the
primary resource at Point Thomson.
BP did not testify, but delivered a similar message in a letter.
ExxonMobil said it hadn’t seen the
PetroTel report, but said the published
summary of the report appeared to be
based on limited data, and said the estimate
of recoverable liquids and gas didn’t consider fundamental technical work yet to be
done.
Chevron said that based on the published summary of the PetroTel report the
work was strictly theoretical and didn’t
take into consideration economics or location and type of wells. Chevron called the
conclusion “very optimistic” both for
hydrocarbons in place and for recoverable
hydrocarbons.
Chevron said recoverable barrels at
Point Thomson are “substantially less”
than the 500 million barrels expected from
Alpine, and also said that if production of
Prudhoe Bay gas was accelerated because
Point Thomson gas was not available for a
gas pipeline due to a gas cycling project,
the end result could be less overall oil produced on the North Slope. Contact Kristen Nelson
at knelson@petroleumnews.com
PETROLEUM NEWS
•
15
WEEK OF JUNE 17, 2012
ALTERNATIVE ENERGY
No takers for co-op rig, court papers say
A drilling rig at the center of an Alaska bankruptcy case might be sold, but “no
buyer has been found for the rig despite months of efforts to find one.”
So says a recent filing in U.S. Bankruptcy Court in Anchorage.
The National 1320 drilling rig belongs to Naknek Electric Association, a small
power cooperative serving villages in Southwest Alaska.
The co-op filed for Chapter 11 bankruptcy protection from creditors in
September 2010 due to problems with a costly geothermal drilling program.
The co-op has said it bought the National 1320 rig in Eastern Washington in
2009 for $8.5 million, and made $3 million in winterization and other improvements.
The rig has been used to drill one exploratory geothermal well so far, at a site
outside the village of King Salmon.
A group of Naknek Electric creditors including oilfield services company
Baker Hughes on June 7 filed a motion asking the court to approve a settlement
concerning their liens on the rig and related equipment.
The motion says no buyer has been found for the rig, which “is most likely
worth considerably less than” the Baker Hughes lien claim of $3.5 million.
we are the people
of Baker Hughes.
and we’re shaping
the future of
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Justin Vinson, Engineering Manager
—WESLEY LOY
EXPLORATION & PRODUCTION
US oil, gas rig count up by 4 to 1,984
The number of rigs actively exploring for oil and natural gas in the U.S. was up
by four the week ending June 8 to 1,984.
Houston-based oilfield services company Baker Hughes Inc. reported that
1,414 rigs were exploring for oil and 565 were looking for gas. Five were listed as
miscellaneous. A year ago this week, Baker Hughes reported 1,855 rigs.
Of the major oil- and gas-producing states, Colorado gained fours rigs and
Louisiana three, while California, Oklahoma and Texas each were up two.
Oklahoma declined by one.
Alaska, New Mexico, North Dakota, Pennsylvania, West Virginia and
Wyoming all were unchanged.
The rig count peaked at 4,530 in 1981 and bottomed at 488 in 1999.
—ASSOCIATED PRESS
NATURAL GAS
Nikiski plant again exporting LNG to Asia
ConocoPhillips has resumed the export of liquefied natural gas to Asia from its
plant in Southcentral Alaska, though the plant’s future remains unclear.
ConocoPhillips Alaska spokeswoman Natalie Lowman said June 13 she
expects four to five cargo shipments to Asia
this year. She declined to name the customers.
ConocoPhillips Alaska
The first shipment went out in May.
spokeswoman Natalie
She said the company is making plans
Lowman
said June 13 she
through the year, and then will again evaluate
expects
four
to five cargo
the plant’s future. The plant’s export license
shipments to Asia this
expires in March.
In February 2011, ConocoPhillips and thenyear.
partner Marathon Oil Corp. announced plans to
close the plant in Nikiski, on the Kenai
Peninsula, in the coming months, citing market changes that didn’t support continued exports.
The plant, once the largest of its kind in the world, had been the sole supplier
to Japan when it began exports in 1969, but it provided less than one-half of a percent of that market’s supply by 2010, according to testimony given to a special legislative committee last year.
A month after the announcement, in March 2011, an earthquake and tsunami
devastated Japan, a tragedy that also created a market opportunity.
Lowman said the company wound up picking up six spot cargo shipments last
year.
LNG production resumed earlier this year, after being halted for the winter.
—BECKY BOHRER, ASSOCIATED PRESS
continued from page 1
SHALE CONFERENCE
conflicts and controversies in the Lower
48 pertain to Alaska development; what
the key issues concerning Alaska shale
development will be for federal and state
regulators; and special challenges of
developing shale deposits in Alaska.
While the presenters are subject to
change, the current schedule includes: J.
Daniel Arthur, managing partner, ALL
Consulting; North Slope Borough Mayor
Charlotte Brower; Louisiana Cutler, partner, K&L Gates, Anchorage; Ed Duncan,
president, Great Bear Petroleum; Pat
Galvin, vice president of external affairs
and deputy general counsel for Great
Bear Petroleum; Alaska Department of
Environmental
Conservation
Commissioner Larry Hartig; David
Houseknecht of the U.S. Geological
Survey; Alaska Sen. Joe Paskvan, DFairbanks; Alaska Rep. Paul Seaton, RHomer; David Spigelmyer, vice president, government relations, Chesapeake
Energy, and chair, Marcellus Shale
Coalition; Alaska Department of Natural
Resources Commissioner Dan Sullivan;
Craig Wilson, partner & practice group
coordinator, environmental, land and natural resources, K&L Gates, Harrisburg.
Petroleum News and Great Bear
Petroleum Operating LLC are co-sponsors of the conference.
—PETROLEUM NEWS
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16
PETROLEUM NEWS
•
WEEK OF JUNE 17, 2012
Oil Patch Bits
Crowley Maritime Corp. said
June 12 that its shipping services to Cuba reached another
milestone over the weekend
with the first delivery of petroleum products to the U.S. Naval
Station in Guantanamo Bay via
articulated tug-barge tank vessel. The cargo was loaded in
San Diego, Calif., and transported to Cuba aboard Crowley’s ATB Coastal Reliance/550-4.
The fuel delivery was made in support of Crowley customer Military Sealift Command,
which will continue utilizing the Coastal Reliance/550-4 under short-term contract to transport clean petroleum products between the Gulf and East Coasts for the next several
months. Before serving MSC, the Coastal Reliance/550-4 operated on the West Coast for
nearly a decade.
Crowley was the first U.S. carrier to obtain a license from the Office of Foreign Assets
Control of the United States Department of the Treasury in Washington, D.C., to provide
COURTESY CROWLEY
Crowley sends tug-barge to deliver fuel at base
regularly scheduled common carrier services for licensed cargo from the United States to
the Republic of Cuba. Crowley launched its Cuba shipping service in December 2001,
becoming the first U.S. carrier to re-enter Cuba in nearly 40 years, and has maintained a
regularly scheduled service ever since.
Dowland-Bach expands to serve Texas, global markets
Dowland-Bach Corp., a subsidiary of Koniag Development Corp., said June 12 that it has
opened offices in Houston and Midland, Texas, to serve the growing needs of the petroleum
industry.
Dowland-Bach’s expansion into Texas provides a base from which the 37-year-old engineering and manufacturing company will service the worldwide energy industry with its
customized, high-quality wellhead control solutions.
“Establishing operations in Texas enables Dowland-Bach to produce long-term benefits
for our non-Alaska-based customers,” said Lynn Johnson, co-founder and president of
Dowland-Bach. “It will ultimately serve to strengthen our offering to the worldwide
upstream oil and gas industry.”
The new Texas locations serve as sales and support locations for Dowland-Bach’s suite
see OIL PATCH BITS page 20
Companies involved in Alaska
and northern Canada’s oil and gas industry
ADVERTISER
PAGE AD APPEARS
A
Acuren USA
AECOM Environment
Air Liquide
AIRVAC Environmental Group
Alaska Air Cargo
Alaska Analytical Laboratory
Alaska Dreams
Alaska Frontier Constructors
Alaska Interstate Construction (AIC) . . . . . . . . . . . . . . . . . .12
Alaska Marine Lines
Alaska Railroad Corp.
Alaska Rubber
Alaska Steel Co.
Alaska West Express
Alaskan Energy Resources Inc.
Alpha Seismic Compressors . . . . . . . . . . . . . . . . . . . . . . . . . .8
Alutiiq Oilfield Solutions
American Marine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4
Arctic Controls
Arctic Foundations
Arctic Fox Environmental
Arctic Slope Telephone Assoc. Co-op.
Arctic Wire Rope & Supply
ARCTOS
Armstrong
Aspen Hotels
ASRC Energy Services . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10
AT&T
Avalon Development
B-F
Baker Hughes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15
Bald Mountain Air Service
Bombay Deluxe . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6
Calista Corp.
Canadian Mat Systems (Alaska)
Canrig Drilling Technology
Carlile Transportation Services
CGGVeritas U.S. Land
CH2M Hill . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18
Charter College . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .15
Chiulista Services
ClearSpan Fabric Structures
Colville Inc.
Computing Alternatives
ConocoPhillips Alaska
Construction Machinery Industrial
Craig Taylor Equipment
Crowley Alaska
Cruz Construction
Denali Industrial
Donaldson Company
ADVERTISER
PAGE AD APPEARS
Dowland-Bach Corp.
Doyon Drilling
Doyon Emerald
Doyon LTD
Doyon Universal Services
Egli Air Haul
Emerald Alaska . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11
Era Alaska
ERA Helicopters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19
Everts Air Cargo
Expro Americas LLC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20
ExxonMobil
Fairweather
Flowline Alaska
Fluor
Foss Maritime
Fugro
G-M
GBR Equipment
GCI Industrial Telecom
Geokinetics, formerly PGS Onshore
Global Diving & Salvage
GMW Fire Protection
Golder Associates
Greer Tank & Welding
Guess & Rudd, PC
Hawk Consultants . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .19
Haws Integrated
Hoover Materials Handling Group
Inspirations
Intertek Moody
Jackovich Industrial & Construction Supply
Judy Patrick Photography
Kenworth Alaska
Kiska Metals
Kuukpik Arctic Services
Larson Electronics LLC
Last Frontier Air Ventures
Linc Energy
Lister Industries
Lounsbury & Associates
Lynden Air Cargo
Lynden Air Freight
Lynden Inc.
Lynden International
Lynden Logistics
Lynden Transport
Mapmakers of Alaska
MAPPA Testlab
Maritime Helicopters
M-I Swaco
MRO Sales
M.T. Housing
ADVERTISER
PAGE AD APPEARS
N-P
Nabors Alaska Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13
Nalco
NANA Regional Corp.
NANA WorleyParsons
NASCO Industries Inc.
Nature Conservancy, The
NEI Fluid Technology
Nordic Calista
North Slope Telecom
Northern Air Cargo
Northwest Technical Services
Oil & Gas Supply
Opti Staffing Group
PacWest Drilling Supply
PENCO . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4
Pebble Partnership
Petroleum Equipment & Services
PND Engineers Inc.
Polyguard Products . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6
PRA (Petrotechnical Resources of Alaska)
Price Gregory International
Q-Z
SAExploration
Salt + Light Creative
Seekins Ford
Shell Exploration & Production . . . . . . . . . . . . . . . . . . . . . . .9
Sourdough Express Inc.
STEELFAB
Stoel Rives
Taiga Ventures
Tanks-A-Lot . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8
TEAM Industrial Services
The Local Pages
Tire Distribution Systems (TDS)
Total Safety U.S. Inc.
TOTE-Totem Ocean Trailer Express . . . . . . . . . . . . . . . . . . . . .4
Totem Equipment & Supply
Transcube USA
TTT Environmental . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8
Udelhoven Oilfield Systems Services
UMIAQ
Unique Machine . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .20
Univar USA
URS Alaska
Usibelli
Weston Solutions
XTO Energy . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3
All of the companies listed above advertise on a regular basis
with Petroleum News
•
17
WEEK OF JUNE 17, 2012
continued from page 1
ENERGY YEAR
and Development countries but rose 5.3
percent in emerging economies. China continued to boom, accounting for 71 percent
of the total growth in global energy consumption.
Even with supply disruptions, oil production increased 1.3 percent. And despite
the largest drop in European consumption
on record, gas production increased 3.1 percent.
Oil demand grew by 1 percent, natural
gas demand grew by 2.2 percent and coal
demand grew by 5.4 percent. And although
the demand for renewable energy collectively grew by 13 percent, those fuels
account for only about 2 percent of global
energy production.
“When you look at the aggregate numbers — in economic growth and in energy
production and consumption globally — it
looks almost boring,” Ruehl said. “It looks
as if nothing has happened. So what we are
asking this year is: How did the system
cope?”
Price shocks, mostly up
Or, to put it another way: “How was it
possible to overcome these pretty heavy disturbances without leaving a trace in the
aggregate picture?” Ruehl asked.
One answer is: They did, in fact, leave a
trace.
Those
disruptions
significantly
increased energy prices.
The average oil price of $111.26 per barrel is the highest nominal price in history
and the highest inflation-adjusted price
since 1864. And while shale drove down
natural gas prices in the Unites States, oilindexed gas prices rose throughout the rest
of the world.
While Henry Hub averaged some $4 per
World consumption
Million tonnes oil equivalent
13000
Coal
Renewables
Hydroelectricity
Nuclear energy
Natural gas
Oil
12000
11000
10000
9000
8000
7000
6000
5000
4000
3000
2000
1000
86
87
88
89
90
91
92
93
94
95
96
97
98
99
00
01
02
03
04
05
06
07
08
09
10
11
0
World primary energy consumption grew by 2.5% in 2011, less than half the growth rate experienced in 2010 but close to the historical average. Growth decelerated for
all regions and for all fuels. Oil remains the world’s leading fuel, accounting for 33.1% of global energy consumption, but this figure is the lowest share on record. Coal’s
market share of 30.3% was the highest since 1969.
million British thermal units and Canadian
prices fell more than half a dollar below that
in 2011, prices in Europe hovered around
$10 per million Btu and liquefied natural
gas to Japan approached $15 million Btu.
Even coal prices increased in Europe, the
United States and Canada.
BP believes those prices helped the market rebound, but, Dudley said, “With so
many economies dependent on imported oil
and gas, the risk of high prices is that, rather
than economic factors driving energy
prices, energy prices could drive economies
downward.”
A major adjustment
Another answer is: The global energy
system adjusted across five continents.
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After a lag, Saudi Arabia increased oil
production enough to offset the 1.2 million
barrels per day lost to political unrest in
Libya. And increased production from the
United Arab Emirates, Kuwait and Iraq
accommodated rising demand from the
developing world.
Those disruptions required a “reconfiguration of trade” and a “very flexible
European refining capacity” able to handle
increased production of heavier crude,
Ruehl said.
Meanwhile, European gas consumption
fell 9.9 percent as LNG went to Japan to offset the loss of nuclear power and to accommodate growth in China and Saudi Arabia.
That shift might have troubled Europe in
previous years, but the continent didn’t need
as much gas as usual last year because of its
flagging economy, its warmer-than-usual
winter and its increased consumption of
coal, particularly from the U.S. and
Columbia.
And why was the U.S. able to ship coal
across the Atlantic?
Because a glut of shale gas production in
North America drove down prices in a market without many export options, Ruehl
said, allowing power producers to back out
coal.
Markets and infrastructure
Dudley simplified the question even further.
see ENERGY YEAR page 18
COURTESY BP
PETROLEUM NEWS
18
PETROLEUM NEWS
continued from page 1
A looming showdown has stemmed
from various stakeholder groups, many of
them ready to take whatever action they
can to block means of oil sands production
and transportation.
“Simply put, when do the external benefits of collective action outweigh individual interests and concerns and how can one
construct the collective action framework
in a way that minimizes risks, maximizes
public gains and appropriately shares the
benefits of invoking the national interest?”
asked a new report from a joint task force
of the Asia Pacific Foundation of Canada
and Canada West Foundation, two independent, not-for-profit research groups.
To that end, the Canadian government
should consider a publicly created, privately run “energy transportation corridor” to
the British Columbia coast, opening tanker
routes to Asia, to answer what oil producers say is an “urgent need for additional
transportation infrastructure,” the task
force recommended.
The study said the federal government
needs to overcome fierce opposition if it
hopes to build markets for oil sands crude
in Asia, along with Eastern Canada and the
Texas Gulf Coast.
Even the new proposals by Enbridge
and Kinder Morgan to add a combined
975,000 barrels per day of pipelines to
tanker ports on the Pacific Coast, along
with projects for North America, would
add only 2 million bpd of capacity, far
short of CAPP’s long-term projection.
Asia relationship the focus
Call for ‘collective action’
With its focus on how to build an energy relationship with Asia, the task force
said the “potential benefits to Canadians
from diversifying our trade towards Asia
are enormous, but they are accompanied
by real and perceived risks that may be better addressed through collective action
rather than through a series of uncoordinated private sector initiatives.”
With all of the pipeline additions
encountering fierce opposition from environmental and aboriginal interests, it is
time to put an end to a “project-by-project
approach,” said task force co-author Kevin
Lynch, vice chairman of the Bank of
Montreal.
If Asia, where “almost all energy
growth is going to come from non-OECD
ENERGY CORRIDOR
countries,” holds the key to the future of
Canadian oil production, Canada must
decide how it will “increasingly access
those markets,” he said.
The task force pressed for “collective
action, rather than a series of uncoordinated private sector initiatives” to establish
the energy transportation corridor that
would be launched by governments, regulated as a public utility and operated by the
private sector.
It said the “potential benefits to
Canadians from diversifying our trade
towards Asia are enormous” and outweigh
individual interests and concerns, placing
an energy delivery system in the same
“national interest” category as the St.
Lawrence Seaway, the TransCanada highway system, national ports and airports.
CAPP said the forecast of rising crude
oil production in Western Canada “has
resulted in increased awareness regarding
the potential for pipeline constraints,” and
avoiding those barriers “is essential to a
well-functioning crude oil market” as producers are forced to look beyond their
largest traditional market in the U.S.
Midwest.
Short-term use of rail
The industry’s leading lobby group,
•
WEEK OF JUNE 17, 2012
whose member companies account for 90
percent of Canada’s oil and natural gas production, CAPP said that although pipelines
will remain the dominant mode of oil
transportation, the use of rail is expected to
increase sharply over the short term.
Completing new pipelines from growing conventional, oil shale and oil sands
production will take years to complete,
while new rail cars can be introduced within about a year and added in small increments, CAPP said.
It said rail cars handled about 5.73 million barrels of fuel oils and crude in
March, compared with 3.64 million barrels
in March 2011.
CAPP said that based on contractual
commitments underpinning pipelines to
the Texas Gulf Coast, Western Canada producers could deliver at least 1.1 million
bpd into that market by 2020, while
demand for Western Canada crude in the
U.S. Midwest should grow by 470,000 bpd
over the period to 2030.
In addition Western Canadian producers could compete for market opportunities
with refineries in California and
Washington, it said. Contact Gary Park through
publisher@petroleumnews.com
continued from page 17
ENERGY YEAR
CH2M HILL has the broadest spectrum of local services, capabilities, equipment, and
The energy system adjusted because of
markets and infrastructure. “We need open
markets to channel supplies to where they
are needed. And we need the infrastructure
to ensure sufficient supplies are available.
The open market is something that governments provide — while the infrastructure is
largely something industry provides,” he
said.
Ruehl concurred.
The disruptions and recoveries of 2011
proved “the more interdependent the energy system is allowed to be, the more integrated markets are, the more people are
allowed to trade, the safer countries are.” If
Japan hadn’t been able to turn to the global
market the Fukushima accident might have
presented a greater supply challenge, he
hypothesized.
For that reason, BP sees the U.S. as a
model for energy policy.
Pointing to shale oil, oil sands and deepwater oil as the future of the most popular
fuel on the planet, Ruehl said, “It is no accident that all these technologies have been
developed in North America, in particular
the U.S. and Canada. Why is it no accident?
Because there is an investment regime
which allows for open access and for competition.”
facilities available to serve you and your project. With over 3,000 people in Alaska
Plenty of fossil fuels left
and 30,000 globally, we have the global resources to get your job done safely, on
Concerning long-term supplies, BP isn’t
worried about peak anything.
“At today’s consumption rates, the world
has proved reserves sufficient to meet current production for 54 years for oil and 64
years for gas,” Dudley said.
The global outlook, though, presents
bad news and good news for carbon emissions.
“The bad news is that last year, again,
coal was the fastest growing fuel and therefore carbon emissions, again, will have continued to rise substantially,” Ruehl said.
But, he added, “In the U.S., carbon emissions actually slowed down. The reason for
this is the replacement of coal for power
generations by abundant natural gas.” And,
Ruehl made sure to note, the decline came
in a country without any carbon markets,
taxes or caps. Serving Alaska’s Mining and Oil & Gas
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PETROLEUM NEWS
•
19
WEEK OF JUNE 17, 2012
continued from page 1
APACHE PLANS
area, the survey operation is now starting
to move into the offshore, working back
and forth between the onshore survey area
and leases held by Furie Operating Alaska
in the middle of the inlet, Hendrix
explained.
Apache had considered starting its
exploration drilling program with one
well on the west side of the inlet and one
well on the east side. But, not yet having
gathered seismic on the east side, the
company has decided to drill both wells
on the west side, with drilling expected to
start in the fall. Apache wants good quality 3-D seismic to identify drilling targets, rather than attempting to use old 2D data, Hendrix said.
“We’re going to shoot good quality 3D seismic and use that information to
help us determine the right bottom-hole
locations,” he said.
Given the tight schedule for initiating
the drilling, Apache is expediting the processing of the seismic data that it is gathering while also starting the permitting of
its wells.
“We have a few prospects lined up …
but we have to start the permitting
process as we further define the interpretation of the seismic,” Hendrix said. “I
anticipate we’re going to be drilling by
September.”
Apache is bringing in the Akita 61
drilling rig from Canada for the drilling,
with the rig being contracted through
Doyon Drilling, an Alaska drilling company, Hendrix said.
Parker said that surveyors are already
out in the field identifying potential sites
for gravel drilling pads.
Deep wells
Once the drilling targets are more
clearly defined using the new seismic, it
may be necessary to drill deviated wells
to reach those targets from the pads,
Hendrix said. Apache plans to drill to
below the Jurassic, underneath the
Tertiary strata of the basin, seeking oil in
both the Tertiary and the older rocks. That
may mean drilling to depths of around
16,000 feet in the prospect areas,
although the seismic survey was designed
to accommodate drilling down to 20,000
feet, Hendrix said.
“We don’t want anybody coming back
behind us and saying ‘look what I’ve
Apache plans to drill to below the
Jurassic, underneath the Tertiary
strata of the basin, seeking oil in
both the Tertiary and the older
rocks.
got,’” Hendrix said. “You’re down there.
You’re drilling. You might as well go the
extra mile, or a thousand feet, or whatever it is.”
For many years people have speculated about the possibility of finding preTertiary oil in the Cook Inlet basin — the
oil in the Tertiary reservoirs of the current
oil fields originated in the Jurassic.
“We’re writing the book on the subsurface seismic, the subsurface geology of
the Cook Inlet,” Hendrix said. “It’s never
been written before.”
The seismic should provide confidence in deciding where to drill, whether
into a structure large enough to warrant a
standalone development or whether into
something than can be developed quickly,
close to existing infrastructure, he said.
East side
The seismic surveying that Apache has
embarked on forms part of a major threeyear seismic program that the company
plans to carry out across large areas of the
Cook Inlet basin. To plan and conduct
this program, the company has divided
the Cook Inlet area into nine planning
regions, although it may be advantageous
to combine more than one region into a
single seismic permit, Hendrix said.
Having started in an area on the west
side of the inlet, the company plans to
start a major 3-D seismic survey on the
east side, starting in September and covering a broad area of land on the southern
Kenai Peninsula as well as a three mile
offshore fairway, from Anchor Point up to
Kasilof.
Apache is using a survey technique in
which each seismic recorder works within its own sealed node, each node independently recording the sound signals
from the seismic sound source while
using global positioning system technology and satellite-based timing to accurately position and time the recording. There
is no need for cabling to connect seismic
receivers to some central recording system. After use, the data are downloaded
from each node into a computer system
for data storage and processing.
The nodes used for a land survey
weigh about five pounds each and are
about the size of a large food can; they
are carried to and from location by backpack. And with no cabling involved, it is
not necessary to cut seismic trails through
forest and other vegetation. The absence
of cabling also makes it very straightforward to conduct a survey in an area where
there is a building or other structure.
The system is very non-invasive for
landowners, Hendrix said.
It is also fast to use.
“We’re in and out of a square mile area
every day,” Hendrix said.
Soldotna, Homer and Nikolaevsk, he
said.
The company has also been working
with Native corporations, Native villages
and Native organizations.
“We’re always talking with people.
The phone lines are always open,”
Hendrix said.
In fact, Hendrix thinks that gaining the
alignment of all people in Alaska over oil
exploration and development is one of the
main challenges that his company faces.
“Working together, diligently, we can
be successful,” he said.
Offshore technique
Commitment
Offshore, the nodes are disc shaped,
tethered along lines lying on the seafloor.
Placing the recorders on the seafloor,
rather than towing them behind a seismic
vessel at the surface, should result in better quality data than from a traditional
marine survey, Hendrix said. That should
enable Apache to differentiate detail previously unseen in the subsurface geology,
he said.
The strings of nodes are laid parallel to
the tidal currents, to minimize the shifting of the nodes under the effects of those
currents. A surface vessel uses sound signals to verify the positions of the nodes
once they have been laid.
But exceptionally strong tidal currents, shifting boulders the size of beat-up
buses along the seafloor and potentially
lifting and moving the seismic nodes,
make offshore seismic in the Cook Inlet
especially challenging, Hendrix said.
“The (Cook Inlet) seismic is probably
the most challenging in the world,” he
said.
But these very challenges attract highcaliber personnel.
“We’ve had a lot of people wanting to
join our seismic team because they’re
attracted by the challenges: the tides, the
weather conditions,” Hendrix said.
At the same time, Apache’s lease position, as the largest leaseholder in the
Cook Inlet basin, tells something about
the company’s long-term commitment to
Alaska exploration, Hendrix said.
“Apache wants to be here 30 years
from now,” he said, commenting that
Apache is a large independent oil company with the resources to stay the course in
Alaska. “You don’t come in and buy this
much acreage with a short-sighted plan.
We’re not a one-well wonder and we don’t
have to bet the farm on one well. … It’s a
proven basin and we think it’s been underexplored. But it’s not an easy basin. It’s a
very complex basin. It’s very complex to
drill and it’s very complex from the geology (standpoint).”
But the company likes what it has seen
so far in its exploration efforts.
“We’re encouraged,” Hendrix said.
“Apache is excited about being here and
we’re excited that Alaskans like us here
… we want to be the oil company of
choice in the Cook Inlet and we want
eventually to be the oil company of
choice for Alaska. I think it’s the right
timing for Apache and the right timing
for Alaskans for Apache to be here.” Working with communities
Although Apache is moving rapidly
ahead with its exploration, the company
is very cognizant of the need to work with
other people and groups in the region. For
example, the company has been meeting
with fishing organizations, to listen to
their concerns and to try to address those
concerns, Hendrix said. The company has
conducted presentations about its plans
and operations to communities across the
Kenai Peninsula, at places such as Kenai,
A New Era in Remote Site Access
Flying is our passion, Safety is our mission
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Contact Alan Bailey
at abailey@petroleumnews.com
20
PETROLEUM NEWS
continued from page 1
BSEE TOUR
said. If the agencies issue permits, they
would test the equipment again in the
Arctic.
The agencies might also conduct
“unannounced” equipment and deployment inspections throughout the process,
Watson said. “BSEE engineers and
inspectors will conduct careful and thorough reviews to ensure our standards for
safety and preparedness are met before
any drilling is approved,” he added in a
prepared statement. “If Shell meets the
standards, BSEE professionals will
ensure that any drilling activities comply
with the most rigorous safety and oversight program ever deployed. Over the
coming days and weeks, our team will be
implementing and overseeing a rigorous
schedule of tests, inspections, and exercises to ensure that safety is front and
center every step of the way.”
Shell wants to drill two wells in the
Beaufort and three wells in the Chukchi
this summer.
Pre-emptive strike
Although Shell is closer to drilling in
the Arctic than at any point in its most
recent attempt to explore the region, it is
continuing its pre-emptive strike against
lawsuits in the run-up to its summer cam-
paign. The company recently asked a federal court to endorse a series of U.S. Fish
and Wildlife Service authorizations for
the exploration program.
The federal agency recently issued six
authorizations — three each for the
Beaufort and Chukchi seas — outlining
how the company can interact with
wildlife during its program.
On June 5, Shell asked the U.S.
District Court for the District of Alaska to
declare that the U.S. Fish and Wildlife
Service complied with the federal Marine
Mammals Protection Act and the National
Environmental Policy Act when it issued
the authorizations.
Calling a legal challenge to the authorizations “a virtual certainty,” Shell said it
needs the court to endorse the ruling to
get ahead of expected lawsuits that could
upend its unforgiving timetable. The
agency issued the authorizations only a
month before the scheduled start of a seasonal drilling program expected to last
only a few months itself, Shell said, making the authorizations “uniquely vulnerable to procedural litigation.”
The 14 environmental groups Shell
listed as defendants in its request have
“long expressed through both word and
deed the intent to prevent drilling on the
Alaska Outer Continental Shelf by any
means necessary, including litigation”
and have “followed through by filing
challenges to every major approval relat-
ed to offshore drilling in Alaska generally, as well as the approvals specific to
Shell’s planned operations this summer.”
Generally, the authorizations concern
“takes,” or the amount of a given species
an applicant can or cannot “harass, hunt,
capture or kill” in the course of some
activity.
The current regulations for the
Beaufort and Chukchi seas grew out of
industry requests dating back to 2005,
leading to guidelines for each sea. The
U.S. Fish and Wildlife Service ultimately
approved the limits against the protests of
some environmental groups.
The authorizations outline the incidental taking of polar bears and walruses by
harassment, in the legal sense, and intentional taking of polar bears for “deterrence.”
The rules are designed to have a “negligible impact” on species.
The authorizations remain valid until
the end of November.
In a similar move to head off potential
legal challenges, Shell previously filed
pre-emptive lawsuits asking the court to
endorse both its oil spill response plan
and its incidental harassment authorizations from the National Marine Fisheries
Service.
—ERIC LIDJI
Contact Eric Lidji
at ericlidji@mac.com
Expro
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products and service you need to measure, improve,
control and process flow from high-value oil and gas wells.
We provide tailor-made solutions across the lifecycle of a
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In Alaska our expertise includes:
• Well Testing
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Telephone: 907-344-5040
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•
WEEK OF JUNE 17, 2012
continued from page 16
OIL PATCH BITS
of reliable wellhead safety systems,
integrated control panels, chemical
injection solutions and automation
engineering services. The Midland office
will serve the booming Permian basin
and other onshore domestic activity,
while the Houston location will focus on
large-scale projects and international
and offshore markets.
To lead its Houston operations,
Dowland-Bach has hired Pat Trickett, a
22-year oilfield veteran, as its global
sales manager. Geoff Wheeler will continue to serve as vice president, based
in Midland.
AES announces
fabrication staff promotions
ASRC Energy
Services Inc. said
May 15 that it
has promoted
Corey O’Meara
to the position of
project manager
and Jeremy
Waltman to the
position of shop
superintendent. COREY O’MEARA
O’Meara will
oversee all phases of fabrication
projects at the
Anchorage
Fabrication
Facility. He joined
AES as a
roustabout in
2001, where he
advanced to the
position of shop JEREMY WALTMAN
superintendent.
Waltman joined AES in 2000 working as a roustabout and was later promoted to piping general foreman. In his
new role, he will be responsible for
supervising all craft disciplines and
managing the daily fabrication activities.
AES Anchorage Fabrication Facility
has had no lost time accidents since
July 18, 2000, and no recordable
injuries since Feb. 14, 2009. This represents more than 2,790,331 man-hours
of work performed without a single
work-related accident or injury.
Editor’s note: All of these news
items — some in expanded form —
will appear in the next Arctic Oil & Gas
Directory, a full color magazine that
serves as a marketing tool for
Petroleum News’ contracted advertisers. The next edition will be released
in September.
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