l LAND & LEASING Eni buys Caelus blocks · Eni said the eastern exploration acreage "is con-sidered...
Transcript of l LAND & LEASING Eni buys Caelus blocks · Eni said the eastern exploration acreage "is con-sidered...
l E X P L O R A T I O N & P R O D U C T I O N
l P I P E L I N E S & D O W N S T R E A M
l L A N D & L E A S I N G
Vol. 23, No. 35 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of September 2, 2018 • $2.50
page2
Smith Bay deferred again, Nutrien still working to getgas to re-open Nikiski plant
RUMOR HAS IT CAELUS ENERGY
ALASKA will use part of the funds it
receives from Eni for its eastern North Slope
acreage (see page 1 story in this issue) to
either test its two Tulimaniq wildcat wells in
Smith Bay off the coast of the National
Petroleum Reserve-Alaska or do more
appraisal drilling at the prospect. An explo-
ration program was planned for early 2017
and again in early 2018, but both were deferred by the local
subsidiary of the Texas independent.
But the rumors are wrong, Pat Foley, senior vice president
IGU gets Houston LNG proposalfrom Knik, Siemens for new plant
On Aug. 21 Knik Tribe and industrial manufacturing com-
pany Siemens presented to the board of the Interior Gas
Utility a proposal for the construction of a liquefied natural
gas plant near Houston, next to a spur of the Alaska Railroad.
LNG would be transported to Fairbanks by rail in support of
an expanded supply of natural gas for the city and its sur-
rounds. The plant would be built on Native land zoned for
industrial development and owned by Knikatnu, the Native
village corporation for Knik and Wasilla.
The proposal comes as an alternative to expanding the
existing Titan LNG plant near Point Mackenzie. The increased
LNG supply is planned as part of the Interior Energy Project,
Results from Doyon/CIRI TotchaketNenana basin well not commercial
The Totchaket No. 1 exploration well, drilled in the Nenana
basin this summer by Doyon Ltd. and Cook Inlet Region Inc,
encountered multiple gas shows but did not find commercial
oil or gas, CIRI has reported. CIRI said that, based on drilling
results conducted so far in the basin, it continues to view the
basin as holding considerable resources.
Drilling of the Totchaket well, on the east side of the
Tanana River, about 20 miles north of the town of Nenana,
began on June 6 and ended on July 5. The well has since been
plugged and abandoned. According to data published by the
Alaska Oil and Gas Conservation Commission, the well was
drilled to a vertical depth of 11,225 feet.
Oil Search plans appraisal wellsat Pikka unit this winter season
Australia-based Oil Search Ltd. said in its Aug. 21 first half
results call with analysts that it plans to drill two appraisal wells
in 2018-19 at the Pikka unit it operates on Alaska’s North Slope.
Petroleum News has previously reported that the company plans
to use two drilling rigs for work this winter, an early indication of
plans to drill two wells.
Peter Botten, Oil Search managing director, reviewed the
company’s progress in Alaska since it acquired interests at Pikka,
Horseshoe and elsewhere on the North Slope from Armstrong
Energy last year. He discussed four stages of planned growth in
Alaska: development of the Nanushuk in the Pikka unit;
Nanushuk expansion, south into Horseshoe; exploration with a
focus on tie-back opportunities; and new business, including
see INSIDER page 10
see LNG PROPOSAL page 11
see WELL RESULTS page 10
see OIL SEARCH page 8
Rig contracted for Winx prospect2019 drilling by Captivate Energy
Eni buys Caelus blocksItalian major confirms acquisition of 350,000 acres on eastern North Slope
By KAY CASHMANPetroleum News
As reported in Oil Patch Insider in Petroleum
News’ Aug. 19 issue, Eni has acquired Caelus
Alaska’s eastern North Slope acreage, which con-
sists of 350,000 onshore acres between the
Prudhoe Bay and Point Thomson units (see accom-
panying map).
At that time a formal announcement had not
been made, but the Italian major confirmed the
purchase of the 124 state oil and gas leases in an
Aug. 29 press release.
Eni previously held some 35,120 acres on the
North Slope, bringing its new total to more than
385,000 acres.
Eni said the eastern exploration acreage "is con-
sidered a prime area with high potential and multi-
ple proven plays.” The company plans to “apply its
business model and experience,” involving “fast-
track exploration” and “a short time to market” for
the “potential new discoveries.”
A price was not disclosed. Eni also said the
EIS is publishedBOEM favors Hilcorp’s proposal to develop Liberty from offshore island
By ALAN BAILEYPetroleum News
The federal Bureau of Ocean Energy
Management has issued a final
Environmental Impact Statement for Hilcorp
Alaska’s planned Liberty oil field development in
the Beaufort Sea. The agency has confirmed a pre-
ferred alternative accepting Hilcorp’s proposal to
develop the field from a small gravel island in 19
feet of water about five miles offshore, and the lay-
ing of a buried subsea pipe-in-pipe pipeline to
carry crude oil to shore. The pipeline would con-
nect with the existing Badami pipeline for trans-
porting the Liberty oil to the trans-Alaska pipeline.
BOEM says that it anticipates the EIS being
published in the Federal Register on Aug. 31, with
a record of decision for the document being issued
30 days or more later.
Construction scheduleHilcorp has previously said that it hopes to start
building the 9.3-acre gravel island in late 2019,
Alberta now 17-0Notley elated by Supreme Court verdict against attempt to block Trans Mountain
By GARY PARKFor Petroleum News
The Alberta government is “batting a
thousand” in its legal defense of the
Trans Mountain pipeline project after
notching its 17th straight court victory,
the province’s Premier Rachel Notley
declared when the Supreme Court of
Canada rejected an appeal against expan-
sion of the line from Alberta to the
Pacific Coast.
“When the British Columbia government tried
to overstep its legal and constitutional authority,
we took bold action (threatening to cut off ship-
ments of Alberta crude to B.C.) — and they backed
down,” she said in a social media post.
“When the City of Burnaby tried to
block the Trans Mountain pipeline in
court, we intervened — and we won in
court.”
The Burnaby appeal of the project
approval by Canada’s National Energy
Board was one of the final court chal-
lenges being waged by British Columbia
and First Nations against the Alberta and
federal governments.
Burnaby asked Canada’s highest court
to overturn a lower court decision that allowed
pipeline owner Kinder Morgan to bypass local
bylaws during construction of the pipeline expan-
sion.
The court also ordered Burnaby to pay all of the
see ENI ACQUISITION page 12
see LIBERTY EIS page 9
see COURT VERDICT page 8
To the west of Prudhoe Bay, Eni owns andoperates the Nikaitchuq oil field and is aminority owner in the adjacent Caelus-
operated Oooguruk oil field, with a totalnet production of approximately 20,000
barrels of oil equivalent a day.
Shell Oil Co. discovered oil in the area ofthe Liberty field between 1982 and 1987,through the drilling of four wells into the
Kekiktuk formation from two artificialgravel islands.
RACHEL NOTLEY
2 PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018
GOVERNMENT
PIPELINES & DOWNSTREAM
EXPLORATION & PRODUCTION
FINANCE & ECONOMY4 Enbridge tops up Spectra offer by 10%
2 Nordic-Calista rig contracted for ’19 well
4 State OKs Seaview exploration plan
5 A pause on tighter efficiency standards
DOT, EPA propose to freeze fuel efficiency standards for lightvehicles at 2020 levels for model years 2021 through 2026
Eni buys Caelus blocksItalian major confirms acquisition of 350,000 North Slope acres
EIS is publishedBOEM favors Hilcorp plan to develop Liberty from offshore island
Alberta now 17-0Notley elated by court verdict against attempt to block Trans Mtn.
ON THE COVER
Oil Patch Insider: Smith Bay deferred again,Nutrien working to get gas to re-open Nikiski plant
IGU gets Houston LNG proposalfrom Knik, Siemens for new plantResults from Doyon/CIRI TotchaketNenana basin well not commercialOil search plans appraisal wellsat Pikka unit this winter season
Petroleum News Alaska’s source for oil and gas newscontents
Keeping youcovered
l E X P L O R A T I O N & P R O D U C T I O N
Nordic-Calista rig contracted for ’19 wellBy KRISTEN NELSON
Petroleum News
88 Energy said Aug. 29 that its wholly owned subsidiary
Captivate Energy Alaska has contracted the Nordic-
Calista Services rig 3 to drill the Winx prospect.
Winx is on a block of four Great Bear Petroleum Leases
in which 88 Energy Ltd., Otto Energy Ltd. and Red Emperor
Ltd. acquired a collective 90 percent interest earlier in the
year. The lease terms, set to expire April 30, were extended
by the Division of Oil and Gas to April 30, 3021, contingent
on the drilling of an exploration well by May 30, 2019.
The 88 Energy consortium said when the lease acquisi-
tion and extension were announced that they would meet
that drilling commitment and said they would target the
Nanushuk play. The block on which the Winx prospect lies
is east of discovery wells at Horseshoe and west of
Meltwater.
88 Energy said at that time that Otto Energy had used
seismic data acquired from the division to identify a
prospect at a depth of some 5,000 feet in the Nanushuk.
In its Aug. 29 statement 88 Energy said the Winx 1 well
will test a 3-D seismically defined oil prospect in the
Nanushuk play fairway “comprising multiple stacked objec-
tives with a gross mean unrisked prospective resource” of
400 million barrels. The company rated the geological
chance of success at 25-30 percent.
Nordic-Calista Services rig 3 is a single module, self-pro-
pelled drilling rig, capable of drilling to depths of 12,000-
14,500 feet, 88 Energy said, and has previously been used
for grassroots drilling, exploration, sidetracks ad workovers
on the North Slope.
Western Block88 Energy said it is earning a 36 percent working interest
in the four leases in the western block, totaling 22,171 acres,
with its consortium partners Otto Energy and Red Emperor
Resources, with Otto eventually having a 22.5 percent inter-
est and Red Emperor 31.5 percent.
All three companies are based in Australia.
The companies have posted a $3 million performance
bond to the state and will fund 100 percent of the costs of the
well. The bond was a requirement of the state to extend the
term of the leases, along with the requirement to drill a well.
88 Energy has been investigating the potential for source
rock development on leases straddling the Dalton Highway,
and is also investigating conventional prospects on its
acreage. Project Icewine was 88 Energy’s first North Slope
venture, with a gross acreage position of some 475,000
acres, 301,000 acres net to 88 Energy. Icewine 1 has been
drilled and evaluated. Drilling at Icewine 2, an appraisal
well, concluded in 2017, with production testing at that well
concluded in June.
These wells targeted the HRZ.
The company said conventional prospects have been
identified in recently acquired 2-D and 3-D seismic across
project acreage.
88 Energy also has 100 percent working interest via a
subsidiary in Yukon Gold leases acquired earlier this year,
some 14,194 acres. The leases contain the Yukon Gold 1, a
historic discovery well. The company said 3-D seismic was
acquired in early 2018 to assist with evaluation of the
Yukon Gold acreage. l
6 Seawall would protect homes, oil industry
7 Governor’s race may hinge on PFD checks
5 Judge rules developer can’t sue Earth First
7 Judge confirms city’s right in lawsuit
PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018 3
Rig Owner/Rig Type Rig No. Rig Location/Activity Operator or Status
Alaska Rig StatusNorth Slope - Onshore
Doyon DrillingDreco 1250 UE 14 (SCR/TD) Milne Point, MPLU-14 Hilcorp Dreco 1000 UE 16 (SCR/TD) Standby Dreco D2000 Uebd 19 (SCR/TD) GMTU, MT6-08 ConocoPhillipsAC Mobile 25 StandbyOIME 2000 141 (SCR/TD) Stacked 142 (SCR/TD) Kuparuk 1H-104 ConocoPhillips TSM 700 Arctic Fox #1 Stacked
Hilcorp Alaska LLC Rig No.1 Milne Point Hilcorp Alaska LLC
Kuukpik Drilling 5 Deadhorse Available
Nabors Alaska DrillingAC Coil Hybrid CDR-2 (CTD) Stacked in Deadhorse BPAC Coil CDR-3 (CTD) Kuparuk, 1H-21 ConocoPhillipsDreco 1000 UE 2-ES (SCR-TD) Stacked AvailableMid-Continental U36A 3-S Stacked AvailableOilwell 700 E 4-ES (SCR) Stacked AvailableDreco 1000 UE 7-ES (SCR/TD) Stacked ConocoPhillipsDreco 1000 UE 9-ES (SCR/TD) Stacked ConocoPhillipsOilwell 2000 Hercules 14-E (SCR) Deadhorse AvailableOilwell 2000 Hercules 16-E (SCR/TD) Stacked Brooks Range Petroleum Oilwell 2000 Canrig 1050E 27-E (SCR-TD) Stacked Glacier Oil & Gas Oilwell 2000 33-E Deadhorse AvailableAcademy AC Electric CANRIG 99AC (AC-TD) Stacked RepsolOIME 2000 245-E (SCR-ACTD) Stacked ENIAcademy AC electric CANRIG 105AC (AC-TD) Stacked in Deadhorse Doyon LtdAcademy AC electric Heli-Rig 106AC (AC-TD) Stacked Great Bear Petroleum
Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay AvailableSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay AvailableIdeco 900 3 (SCR/TD) Prudhoe Bay AvailableRig Master 1500AC 4 (AC/TD) Oliktok Point ENI
Parker Drilling Arctic Operating Inc. NOV ADS-10SD 272 Prudhoe Bay DS 18 BPNOV ADS-10SD 273 Prudhoe Bay DSW-59 BP
North Slope - Offshore
BPTop Drive, supersized Liberty rig Inactive BP
Doyon DrillingSky top Brewster NE-12 15 (SCR/TD) Spy Island NN-01 ENI
Nabors Alaska DrillingOIME 1000 19AC (AC-TD) Cold Stacked Caelus Energy LLC
Cook Inlet Basin – Onshore
BlueCrest Alaska Operating LLCLand Rig BlueCrest Rig #1 Anchor Point, BlueCrest Alaska Operating LLC drilling production section of H14
Glacier Oil & Gas Rig 37 West McArthur River Unit Workover Glacier Oil & Gas
All American Oilfield LLCIDECO H-37 AAO 111 In All American Oilfield’s yard in Kenai, Alaska Available
Aurora Well ServicesFranks 300 Srs. Explorer III AWS 1 Stacked out west side of Cook Inlet Available
SaxonTSM-850 147 Stacked Hilcorp Alaska LLCTSM-850 169 Stacked Hilcorp Alaska LLC
Cook Inlet Basin – Offshore
Hilcorp Alaska LLCNational 110 C (TD) Platform C, Stacked Hilcorp Alaska LLC Rig 51 Steelhead Platform, Stacked Hilcorp Alaska LLC Rig 51 Monopod Platform, Drilling Hilcorp Alaska LLC Spartan Drilling Baker Marine ILC-Skidoff, jack-up Spartan 151, Stacked Seward
Furie Operating AlaskaRandolf Yost jack-up Nikiski, OSK dock Furie
Glacier Oil & GasNational 1320 35 Osprey Platform, activated Glacier Oil & Gas
Mackenzie Rig Status
Canadian Beaufort Sea
SDC Drilling Inc.SSDC CANMAR Island Rig #2 SDC Set down at Roland Bay Available
Central Mackenzie ValleyAkitaTSM-7000 37 Racked in Norman Wells, NT Available
Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of August 30, 2018.
Active drilling companies only listed.
TD = rigs equipped with top drive units WO = workover operations CT = coiled tubing operation SCR = electric rig
This rig report was prepared by Marti Reeve
Baker Hughes North America rotary rig counts* Aug. 24 Aug. 17 Year AgoUnited States 1,044 1,057 940Canada 229 212 217Gulf of Mexico 16 19 17
Highest/LowestUS/Highest 4530 December 1981US/Lowest 404 May 2016 *Issued by Baker Hughes since 1944
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4 PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018
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FINANCE & ECONOMYEnbridge tops up Spectra offer by 10%
Canadian multinational energy transportation company Enbridge has dug
deeper into its pockets to sweeten its bid to make a complete takeover of Spectra
Energy Partners for $4.3 billion, 10 percent more than its initial offer.
Enbridge, which already owns 83 percent of the Houston-based unit of
Spectra, is eager to reduce complexity in
the wake of its US$37 billion takeover of
Spectra Energy, gaining control of a vast
network of North American pipelines.
Spectra Energy Partners is a master lim-
ited partnership, MLP, and owns interests
in pipeline and storage facilities for natural
gas and crude oil.
Enbridge said acceptance of its latest
offer would deal with a U.S. tax ruling that
stopped MLPs from claiming allowances on fees charged to companies which
ship crude.
The change reduced the appeal of exploiting the MLPs to help fund billions of
dollars in growth projects and prompted Enbridge to initiate buyout offers earlier
this year.
Calgary-based Enbridge is selling assets and restructuring operations as part of
its C$22 billion program of major projects, including the C$9 billion Line 3 oil
pipeline from Alberta to Superior, Wisconsin, that replaces a 60-year-old corroded
line and double capacity to 760,000 barrels per day.
So far this year Enbridge has sold assets for C$7.5 billion, including Canadian
natural gas gathering and processing facilities — a move welcomed by bond-rat-
ing agencies.
—GARY PARK
Enbridge said acceptance of itslatest offer would deal with aU.S. tax ruling that stopped
MLPs from claimingallowances on fees charged tocompanies which ship crude.
l E X P L O R A T I O N & P R O D U C T I O N
State OKs Seaviewexploration plan
By KRISTEN NELSONPetroleum News
T he Alaska Department of Natural
Resources Division of Oil and Gas
has approved a lease plan of operations
for the exploration phase of Hilcorp
Alaska’s Seaview pad.
Hilcorp applied in late May for con-
struction of the Seaview pad on the south-
ern Kenai Peninsula near Anchor Point,
telling the division it planned to drill two
exploration wells from the new pad. The
company had permitted and drilled seven
shallow stratigraphic test wells in the area
last summer and began permitting activi-
ties early in the year for the pad and
exploration wells.
The proposed wells, Seaview 8 and 9,
will be drilled within ADL 392667, the
division said Aug. 24 in approving the
exploration phase of the project. Work
was planned to begin this summer and
end in early November, although the orig-
inal schedule, with pad construction pro-
posed to begin in mid-July, has slipped.
The division said the wellbore loca-
tions for the two wells “were derived
from stratigraphic wells drilled on private
lands near ADL 392667 and other prior
wells drilled in the surrounding area.”
The Seaview 8 will extend beyond ADL
392667, the state said, exploring for oil
on fee simple land.
The state said there are three separate
stages for each well, beginning with the
directional drilling and insertion of sur-
face casing through subsurface of poten-
tial hydrocarbon-bearing zones within the
Lower Sterling and Beluga formations,
with well evaluation including downhole
instrumentation. Well control equipment
and casing will isolate gas-bearing zones.
In stage two the well will be deepened
beyond the state lease with a lateral hori-
zontal evaluating the Lower Tyonek,
Hemlock and deeper formations on fee
simple lands.
The third stage would involve evaluat-
ing potential hydrocarbon reservoirs by
perforating and flow-back testing, follow-
ing which the well may be temporarily
secured or formally suspended while data
is evaluated.
The division said the first 5,500 feet of
the Seaview 8 would be perforated to
evaluate gas zones, which are partially
within ADL 392667, while the bottom-
hole location, on fee simple land, would
be evaluated for oil resources.
The division said the Seaview 9 would
be drilled some 10,000 feet measured
depth northwest of the pad and is a gas
exploration well only.
Pad specificsExisting access roads will be used and
pad construction will be within an active
mine site, so no rehabilitation is planned,
with cleanup work required to be done to
the satisfaction of the private landowner
and any applicable agencies and/or stake-
holders.
The pad is within one-half mile of the
Anchor River, with the exploration tar-
gets of the wells bounded by the one-half
mile Cook Inlet buffer to the west and the
one-half mile Anchor River buffer to the
east.
Environmental and social impact is
mitigated by the fact that the pad location
has already been disturbed, is an active
mine site with ongoing activities and will
result in no loss of wetlands or wildlife
habitat.
The primary target of the Seaview 8
well is gas; the target of the Seaview 9
well is only gas.
The division said the waiver allowing
the pad within one-half mile of the
Anchor River is appropriate because no
other location is practicable, with
Hilcorp’s proposal for locating the pad
offering the smallest possible extent of
environmental impact within ADL
392667.
Proposed facilities are temporary and
the gravel drill pad will be constructed at
the western extent of the parcel to mini-
mize the distance from the Anchor River
and buffer sound impacts to landowners
to the south and west.l
The division said the wellborelocations for the two wells “werederived from stratigraphic wells
drilled on private lands near ADL392667 and other prior wells
drilled in the surrounding area.”
PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018 5
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A pause on tighterefficiency standardsDOT and EPA propose to freeze fuel efficiency standards forlight vehicles at 2020 levels for model years 2021 through 2026
By ALAN BAILEYPetroleum News
T he U.S. Department of Transportation
and the Environmental Protection
Agency have proposed to call a halt to the
further tightening of fuel efficiency standards
for light vehicles. In a notice of proposed
rulemaking, published in the Federal
Register on Aug. 28, the agencies said that
they propose to lock the standards for cars
and light-duty trucks for model years 2021
through 2026 at the standards set for 2020.
The proposed rule would set in motion a
process for taking comments on possible
alternatives for future standards. The agen-
cies have already modeled several options
for the standards, including the freeze on
standards that they now propose.
Under federal statutes, the agencies have
to set fuel efficiency standards for road
vehicles. The standards are set in five-year
increments.
In 2012 the Obama administration
issued standards for model years 2017 and
beyond, tightening the standards as part of
the administration’s policies aimed at
reducing U.S. greenhouse gas emissions.
However, under the terms of the appropriate
statutes, at that time the administration
could not enforce the standards beyond
2021.
First step in new standardsThe proposed new rule represents the
first step in setting enforced standards for
the 2021 to 2026 years.
The agencies say that the current strin-
gent standards have been a factor in the ris-
ing cost of new automobiles, putting new
automobiles out of reach for many
American families. And, since a study by
the National Highway Traffic Safety
Administration shows that new vehicles
tend to be safer than older vehicles, the abil-
ity of more people to purchase new vehicles
will increase road safety as well as improv-
ing overall fuel efficiency for the vehicle
fleet, the agencies say.
“There are compelling reasons for a new
rulemaking on fuel economy standards for
2021-2026,” said Secretary of
Transportation Elaine Chao. “More realistic
standards will promote a healthy economy
by bringing newer, safer, cleaner and more
fuel-efficient vehicles to U.S. roads and we
look forward to receiving input from the
public.”
“We are delivering on President Trump’s
promise to the American public that his
administration would address and fix the
current fuel economy and greenhouse gas
emissions standards,” said EPA Acting
Administrator Andrew Wheeler. “Our pro-
posal aims to strike the right regulatory bal-
ance based on the most recent information
and create a 50-state solution that will
enable more Americans to afford newer,
safer vehicles that pollute less. More realis-
tic standards can save lives while continu-
ing to improve the environment. We value
the public’s input as we engage in this
process in an open, transparent manner.”
Concerns raisedThe Environmental Defense Fund has
responded to the proposals by commenting
that a freeze on the fuel efficiency standards
could eliminate the possibility of cutting as
much as 140 million metric tons of carbon
dioxide emissions, just in 2030. Moreover,
the environmental organization said, by not
pursuing further fuel efficiency, American
companies will lose ground in the competi-
tive global market for automobiles.
According to an Associated Press report,
Sen. Tom Carper, D-Delaware, has accused
the Trump administration of supporting the
oil industry to the detriment of the rest of
society.
“American businesses, consumers and
our environment are all losers under this
plan,” Carper said. “The only clear winner
is the oil industry. It’s not hard to see whose
side President Trump is on.” l
The agencies say that the currentstringent standards have been afactor in the rising cost of new
automobiles, putting newautomobiles out of reach for many
American families.
PIPELINES & DOWNSTREAMJudge rules developer can’t sue Earth First
A federal judge has dismissed a second defendant from a $1 billion racketeer-
ing lawsuit that the developer of the Dakota Access oil pipeline filed against envi-
ronmental groups, leaving Greenpeace as the only remaining group facing the
claim.
Texas-based Energy Transfer Partners failed to make a case that Earth First is
an entity that can be sued, U.S. District Judge Billy Roy Wilson said in a ruling
dated Aug. 22.
The Center for Constitutional Rights had argued that Earth First is a philoso-
phy or movement similar to Black Lives Matter, and thus can’t be sued. ETP
unsuccessfully tried to serve the lawsuit to Florida-based Earth First Journal,
which argued that it wasn’t the same as the movement.
Wilson said that rather than clarifying the matter, an amended complaint filed
by ETP earlier in August was “wholly insufficient” in advancing its case under the
Racketeer Influenced and Corrupt Organizations Act that Earth First “allegedly
provided hundreds of thousands of dollars to fund an international terrorist, drug-
smuggling RICO enterprise.”
Center for Constitutional Rights attorney Pamela Spees applauded the ruling,
calling the lawsuit “far-fetched.” ETP officials have said the company doesn’t
comment on active litigation.
Suits last AugustETP sued Earth First, BankTrack and Greenpeace last August, alleging that
they worked to undermine the $3.8 billion pipeline that’s now shipping North
Dakota oil to a distribution point in Illinois. Opposition to the pipeline by groups
and American Indian tribes who feared environmental harm inspired large
protests in southern North Dakota and resulted in 761 arrests over a six-month
span in late 2016 and early 2017.
In July, Wilson ruled that the company had no claim against BankTrack. The
Dutch environmental group had urged banks not to finance the pipeline, which
Wilson concluded did not amount to radical ecoterrorism.
Wilson gave Greenpeace until Sept. 4 to file its response to ETP’s amended
complaint, which added five individual defendants: a man who is allegedly affil-
iated with Greenpeace, two Iowa women who have publicly claimed to have van-
dalized the pipeline, and two people associated with the Red Warrior Camp, a
protest group alleged to have advocated aggressive tactics such as arson. There
are also 20 unnamed defendants listed as John or Jane Does. Wilson on Aug. 22
gave company attorneys 30 days to identify them or have them dismissed as
defendants.
—ASSOCIATED PRESS
By WILL WEISSERTAssociated Press
As the nation plans new defenses
against the more powerful storms
and higher tides expected from climate
change, one project stands out: an ambi-
tious proposal to build a nearly 60-mile
“spine” of concrete seawalls, earthen bar-
riers, floating gates and steel levees on
the Texas Gulf Coast.
Like other oceanfront projects, this
one would protect homes, delicate
ecosystems and vital infrastructure, but it
also has another priority — to shield
some of the crown jewels of the petrole-
um industry, which is blamed for con-
tributing to global warming and now
wants the federal government to build
safeguards against the consequences of it.
The plan is focused on a stretch of
coastline that runs from the Louisiana
border to industrial enclaves south of
Houston that are home to one of the
world’s largest concentrations of petro-
chemical facilities, including most of
Texas’ 30 refineries, which represent 30
percent of the nation’s refining capacity.
Texas is seeking at least $12 billion for
the full coastal spine, with nearly all of it
coming from public funds. In July, the
government fast-tracked an initial $3.9
billion for three separate, smaller storm
barrier projects that would specifically
protect oil facilities.
That followed Hurricane Harvey,
which roared ashore last Aug. 25 and
swamped Houston and parts of the coast,
temporarily knocking out a quarter of the
area’s oil refining capacity and causing
average gasoline prices to jump 28 cents
a gallon nationwide. Many Republicans
argue that the Texas oil projects belong at
the top of Washington’s spending list.
“Our overall economy, not only in
Texas but in the entire country, is so much
at risk from a high storm surge,” said
Matt Sebesta, a Republican who as
Brazoria County judge oversees a swath
of Gulf Coast.
Should US taxpayers pay?But the idea of taxpayers around the
country paying to protect refineries worth
billions, and in a state where top politi-
cians still dispute climate change’s valid-
ity, doesn’t sit well with some.
“The oil and gas industry is getting a
free ride,” said Brandt Mannchen, a
member of the Sierra Club’s executive
committee in Houston. “You don’t hear
the industry making a peep about paying
for any of this and why should they?
There’s all this push like, ‘Please Senator
Cornyn, Please Senator Cruz, we need
money for this and that.’”
Normally outspoken critics of federal
spending, Texas Sens. John Cornyn and
Ted Cruz both backed using taxpayer
funds to fortify the oil facilities’ protec-
tions and the Texas coast. Cruz called it
“a tremendous step forward.”
Federal, state and local money is also
bolstering defenses elsewhere, including
on New York’s Staten Island, around
Atlantic City, New Jersey, and in other
communities hammered by Superstorm
Sandy in 2012.
Construction could begin soonConstruction in Texas could begin in
several months on the three sections of
storm barrier. While plans are still being
finalized, some dirt levees will be raised
to about 17 feet high, and 6 miles of 19-
foot-tall floodwalls would be built or
strengthened around Port Arthur, a Texas-
Louisiana border locale of pungent chem-
ical smells and towering knots of steel
pipes.
The town of 55,000 includes the
Saudi-controlled Motiva oil refinery, the
nation’s largest, as well as refineries
owned by oil giants Valero Energy Corp.
and Total S.A. There are also almost a
dozen petrochemical facilities.
“You’re looking at a lot of people, a lot
of homes, but really a lot of industry,”
said Steve Sherrill, an Army Corps of
Engineers resident engineer in Port
Arthur, as he peered over a Gulf tributary
lined with chunks of granite and metal
gates, much of which is set to be rein-
forced.
The second barrier project features
around 25 miles of new levees and sea-
walls in nearby Orange County, where
Chevron, DuPont and other companies
have facilities. The third would extend
and heighten seawalls around Freeport,
home to a Phillips 66 export terminal for
liquefied natural gas and nearby refinery,
as well as several chemical facilities.
Focus on refineriesThe proposals approved for funding
originally called for building more pro-
tections along larger swaths of the Texas
coast, but they were scaled back and now
deliberately focus on refineries.
“That was one of the main reasons we
looked at some of those areas,” said Tony
Williams, environmental review coordi-
nator for the Texas Land Commissioner’s
Office.
Oil and chemical companies also
pushed for more protection for surround-
ing communities to shield their work-
forces, but “not every property can be
protected,” said Sheri Willey, deputy
chief of project management for the
Army Corps of Engineers’ upper Texas
district.
“Our regulations tell us what benefits
we need to include, and they have to be
national economic benefits,” Willey said.
Once work is complete on the three
sections, they could eventually be inte-
grated into a larger coastal spine system.
In some places along Texas’ 370-mile
Gulf Coast, 18 feet is lost annually to ero-
sion, threatening to suck more wetlands,
roads and buildings into rising seas.
Protecting a wide expanse will be
expensive. After Harvey, a special Texas
commission prepared a report seeking
$61 billion from Congress to “future
proof” the state against such natural dis-
l G O V E R N M E N T
Seawall would protect homes, oil industry
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Better.
Texas is seeking at least $12billion for the full coastal spine,with nearly all of it coming from
public funds. In July, thegovernment fast-tracked an initial
$3.9 billion for three separate,smaller storm barrier projects that
would specifically protect oilfacilities.
see SEAWALL PROJECT page 9
By BECKY BOHRERAssociated Press
The path to the governor’s office in
Alaska this year may hinge on the oil
check given to state residents.
Each year, the state distributes checks
just for living here — residents’ share of
the state’s oil wealth. For some, it’s discre-
tionary money used for new toys, like big
screen TVs, or socked into savings, while
for others, particularly those who are
lower-income or who live in high-cost
rural Alaska, it’s a part of their income.
The checks went out like clockwork
until 2016, when in the midst of legislative
gridlock over how to address a multibil-
lion-dollar budget deficit Gov. Bill Walker
cut the size of everyone’s check by about
half. He defended the move, along with
additional budget vetoes, as necessary to
preserve the state’s savings. Everyone
could still get a check, he said, just not as
big.
His action, upheld by the state Supreme
Court, set a precedent: Since then, law-
makers have not followed the formula in
state law for calculating the Alaska
Permanent Fund dividend checks. Some
have insisted doing so, while the state is
still in a deficit, would be fiscally reckless.
But the decision has brought with it politi-
cal backlash, which Walker, an independ-
ent, hopes to withstand as he faces a tough
re-election bid against conservative former
state Sen. Mike Dunleavy and Democratic
former U.S. Sen. Mark Begich.
DunleavyDunleavy said people are angry that a
decision of that magnitude was made with-
out their involvement. He supports the for-
mula in state law for calculating the check
and does not support changing that with-
out public involvement, including an advi-
sory vote. That’s because if the Legislature
passes taxes or changes to the checks and
citizens don’t agree, they can pursue a ref-
erendum to try to overturn them, he said.
Money for the checks comes from the
earnings of the oil-wealth fund, the Alaska
Permanent Fund. Legislators have long
resisted using fund earnings to pay for
state government. But after blowing
through billions of dollars in savings amid
gridlock over how best to fill the deficit
and shunning taxes, they ran short of
options and agreed earlier this year to start
using fund earnings to fill much of the
hole.
BegichThe fund’s principal is constitutionally
protected, but earnings can be spent with a
simple majority. Begich favors moving
billions of dollars from fund earnings to
the fund’s principal to ensure it isn’t “sub-
ject to the whims of elected officials” and
limiting the amount withdrawn each year
based on a percentage of the fund’s market
value. Part of the money drawn would go
toward a dividend and part would go
toward funding public education.
He said the dividend should be consti-
tutionally protected, an issue he said he
would make a priority.
“You have to get that Permanent Fund
Dividend issue resolved one way or the
other,” he told a small group at a Juneau
meet-and-greet last week. If not, lawmak-
ers will keep fighting over it and won’t
have time to think about other long-term
issues, he said.
Walker said he’s not opposed to
enshrining some form of dividend in the
constitution. But he doesn’t want to see an
upper limit and whatever is settled on
should be sustainable, he said.
The permanent fund is a nest egg, seed-
ed with oil money and grown through
investments. Lawmakers settled on a
check of $1,600 for this year. That’s about
$1,050 less than what Walker’s budget
office earlier this year predicted the
amount would be if a full dividend were
paid out.
MallottLt. Gov. Byron Mallott, a Democrat,
said Walker’s action saved the dividend
for the future. He said it allowed for pas-
sage of legislation calling for structured
withdrawals of permanent fund earnings.
“And many, many, many more
Alaskans understand that than those who
are trying to create a crisis from it,”
Mallott said.
The bill retained the existing formula in
state law for calculating dividends but
since that has been ignored the past three
years, there’s no guarantee it will be fol-
lowed in the future.
Monte Wallace, a Dunleavy supporter,
said the Wasilla Republican “will give our
PFD back to us.” PFD is permanent fund
dividend. She said Walker has “destroyed
Alaska, the way it was,” citing concerns
she has with crime.
Therese Thibodeau, who attended
Begich’s coffee shop meet-and-greet in
Juneau and said she’s registered with the
Green party, said she supported Walker in
2014 and appreciated his action on the div-
idend. “I thought that’s a good thing,” she
said.
She said she was pleasantly surprised,
though, by what she heard from Begich,
particularly his thoughts on the budget.
“Now, I’m more on the fence than I was
when I walked in,” she said. l
l G O V E R N M E N T
Governor’s race may hinge on PFD checks
PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018 7
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PIPELINES & DOWNSTREAMJudge confirms city’s right in lawsuit
A Maine city’s ordinance prohibiting bulk loading of crude oil onto tankers
does not violate the U.S. Constitution.
That was the Aug. 24 ruling of a federal court that had been considering South
Portland’s “Clear Skies” ordinance. Portland Pipe Line Corp. challenged the ordi-
nance on the grounds that it violated clauses of the Constitution that give
Congress sole power over foreign and interstate trade.
The Portland Press Herald reports the ordinance blocked the company from
reversing the flow of its 236-mile underground pipeline. The pipeline has carried
foreign crude from harbor terminals in South Portland to Canadian refiners for
decades.
The ruling followed a four-day June trial in U.S. District Court in Portland.
South Portland’s City Council banned bulk loading of crude oil on the city water-
front in 2014.
—ASSOCIATED PRESS
The permanent fund is a nest egg,seeded with oil money and grown
through investments.
court costs incurred by Alberta and
Kinder Morgan.
Although the final bills have not been
made public, they are expected to reach
millions of dollars.
But Burnaby Mayor Derek Corrigan is
undeterred, insisting his city will “contin-
ue to oppose this project with all the legal
means available to us,” including four
pending legal challenges.
Greenpeace campaigner Mike
Hudema said the court verdict allows the
Canadian government to override munic-
ipalities that are “just trying to protect the
health and safety of our citizens.”
Government stands by decisionA spokesman for federal Natural
Resources Minister Amarjeet Singh said
the government stands by its decision to
buy the existing Trans Mountain link and
related infrastructure for C$4.5 million,
plus about C$6.3 billion in expansion
costs, noting the additional 590,000 bar-
rels per day of capacity is needed to estab-
lish new markets for Canadian crude.
Although many British Columbia First
Nations oppose the pipeline and are par-
ticipants in a Federal Court of Appeal
challenge, 43 aboriginal communities
have signed benefit agreements and wel-
comed the Supreme Court’s verdict.
Cheam First Nation Chief Ernie Grey
said there is a “growing interest on the
part of indigenous people to take out a
stake in the pipeline.”
“We have the option of buying shares,
but my impression from the leadership in
Alberta, Saskatchewan and B.C. is that
they want a substantial interest in the
pipeline,” he said.
Margot Young, a law professor at the
University of British Columbia, said the
Supreme Court’s decision reinforces that
federal tribunals supersede municipal
governments.
She said it was not surprising that that
the top court did not hear Burnaby’s
appeal, although she said it may hear an
appeal from the B.C. government.
Imports, exports both upWhile the legal fights continue,
imports of gasoline, diesel and jet fuel
through the Port of Vancouver climbed
sharply over the first half of 2018 and
exports of petroleum products also posted
a strong gain, with combined inbound and
outbound volumes up 40.3 percent over
the same period of 2017.
The port authority said oil shipments
for all of 2017 were 1.8 million metric
tons, or 12.6 million barrels, compared
with 1.2 million metric tons, or 8.5 million
barrels in 2016.
Kinder Morgan, which owns the Trans
Mountain pipeline pending an expected
sale to the Canadian government, said the
majority of shipments leaving the compa-
ny’s Westridge Marine Terminal at
Burnaby in Greater Vancouver are des-
tined for the United States, although one
tanker went to Korea and one to China.
“The mix of products and destinations
varies from year to year and is based on
market demand,” Kinder Morgan told the
Vancouver Sun.
Robyn Allan, an independent econo-
mist, said the market conditions make it
attractive for California refineries —
which are looking for new feedstocks to
replace declining supplies from Alaska —
to take advantage of the over-subscribed
Trans Mountain system, noting that
reflects the price of US$26 a barrel
between Western Canada Select heavy oil
and the benchmark West Texas
Intermediate crude which has been close
to US$65 recently.
The port authority’s Chief Executive
Officer Robin Silvester said the import
and export volumes of crude underline
how reliant the Vancouver region remains
on fossil fuels, with the inbound crude
almost exclusively used by consumers.
The Westridge terminal can handle
both imports and exports, making it the
largest volume entry and exit point, but
four other terminals, including a former
Chevron refinery, also play a role in the
crude business. l
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continued from page 1
COURT VERDICT
potential infrastructure sharing with
ConocoPhillips Alaska and portfolio
growth options with Armstrong, Repsol and
others.
The initial focus, on Pikka Nanushuk
development, involves integrating recent
technical advances in drilling and comple-
tion techniques, Botten said. The project is
on track for FEED entry, front-end engi-
neering and development, in the second
quarter of next year, leading to a final
investment decision in mid-2020, he said,
with the final scope of Pikka Nanushuk
development the determination of whether
the facility will be sized for 80,000 barrels
per day or 100,000 bpd, a determination
which will be made based on 2019 season
drilling results.
First oil is expected in 2023.
ExpansionThe second focus, on Nanushuk expan-
sion in the Horseshoe area south of Pikka,
has the potential of 300 million barrels of
resource, Botten said. That work, planned
for 2019, will involve seismic reprocessing,
reservoir modeling and data trades with
ConocoPhillips with drilling planned for
2020.
For the third focus, exploration, he said
Oil Search has identified a number of
opportunities which it is prioritizing as
potential tie-in opportunities to the core
development. That would be a three-plus
year program.
The last focus, new business, is on build-
ing strategic relationships, something
Botten said the company was working to
accomplish in what he called a reasonable
timeframe. Presentation information cate-
gorized this phase as strategic relationships
and listed the potential for infrastructure
sharing with ConocoPhillips Alaska, and
portfolio growth options with Armstrong,
Repsol and others.
Botten said Oil Search is having what he
characterized as very successful discussions
with ConocoPhillips around field develop-
ment, including use of common infrastruc-
ture and how the fields will potentially be
developed.
Focus on PikkaThe immediate focus is a successful
appraisal of the Pikka unit.
He noted recent drilling by
ConocoPhillips at Putu has highlighted
reservoir continuity and the potential for
upside resources in the field.
This winter’s drilling will be at the Pikka
B and Pikka C, with a goal of increasing
proven resources from the 500 million bar-
rels assumed in the acquisition, targeting an
additional 250 million barrels. The Pikka B
and Pikka C locations have been identified
and the sites surveyed, both northeast of
Nuiqsut as shown on a map of the
Nanushuk reservoir extent that was part of
the company’s presentation. Drilling sites
were not specifically identified and the
Alaska Oil and Gas Conservation
Commission has not yet issued drilling per-
mits, which will identify drilling locations
by section, township and range.
Drilling is expected to begin by the end
of the year and be completed in April.
Percentage of ownershipLast year Oil Search purchased a portion
of Armstrong Energy and GMT
Exploration’s interests at Pikka and
Horseshoe, paying $400 million for a 25.5
percent interest in the Pikka unit and adja-
cent exploration acreage and 37.5 percent
interests in the Horseshoe block and the
Hue shale, with an option, exercisable until
June 30, 2019, to purchase all of Armstrong
and GMT’s remaining interest in the
Horseshoe block (25.5 percent and 37.5
percent respectively) as well as an addition-
al 25.5 percent interest in adjacent explo-
ration acreage and 37.5 percent in the Hue
shale, for $450 million.
In its financial overview Oil Search
specified the acquisition of Alaska assets at
US$416 million and said the Alaska
Nanushuk development would be done
with new project finance facilities.
Repsol has partnered with Armstrong
and GMT, holding a 49 percent interest in
Pikka and Horseshoe.
Asked about the percentage of owner-
ship which Oil Search wants, Botten said
they are already preparing a data room and
a team to support divestment, looking at an
ownership of about 30 percent long term.
A slide from the presentation says the
company is beginning the process for cap-
turing the Armstrong value option, aligning
with Repsol to attract quality third parties
continued from page 1
OIL SEARCH
see OIL SEARCH page 12
with the laying of the field’s subsea
pipeline taking place during the following
winter and first oil from the field perhaps
flowing in 2022. The plan is to ultimately
drill 16 wells, presumably a combination
of production, injection and disposal
wells.
Production would likely begin at a rate
of 10,000 to 15,000 barrels per day, peak-
ing at perhaps 60,000 to 70,000 bpd after
about two years. Peak gas production is
anticipated to be around 120 million
cubic feet per day. Hilcorp thinks that the
field holds around 120 million barrels of
recoverable oil and field life is anticipated
to be 15 to 20 years.
Production facilities on the island
would deliver sales grade crude oil into
the subsea pipeline for shipment to shore.
Produced gas would be used for fuel on
the island, for injection into the field’s
reservoir and for gas lift in production
wells. Treated seawater mixed with pro-
duced water would also be injected into
the reservoir for pressure maintenance.
A mine site west of the Kadleroshilik
River would act as source of gravel for
the construction project. Winter construc-
tion activities would require four ice
roads and three ice pads. Gravel would be
moved by ice road for island construction
during the winter. Large equipment, such
as the drilling rig, would be delivered by
barge to the island in the summer. Hilcorp
expects to be able to truck most of the
modules, buildings and materials to the
North Slope, for shipment from Prudhoe
Bay West Dock, or from the Endicott
island. However, some equipment may be
shipped by barge from Dutch Harbor.
Other options consideredThe EIS considers other development
options, including a couple of alternative
possible locations for the production
island, and the possibility of installing
field processing facilities on the Endicott
satellite drilling island, rather than on
Liberty island. The EIS dismisses as tech-
nically and economically infeasible an
option involving ultra-extended reach
drilling from the Endicott island, an
option that BP had proposed in 2005. A
“no action” alternative would eliminate
the economic benefit to be gained from
developing the field.
The Boulder Patch, a seabed feature of
considerable environmental significance,
played a role in assessing the potential
environmental impacts of some options.
Although the proposed plan places the
artificial island outside the Boulder Patch,
alternative island locations could move
the island farther from the environmental-
ly sensitive area. But these options would
raise other issues. One option, for exam-
ple, would place the subsea oil export
pipeline in an area susceptible to seafloor
scouring associated with the nearby
Kadleroshilik River delta.
Discovered by ShellShell Oil Co. discovered oil in the area
of the Liberty field between 1982 and
1987, through the drilling of four wells
into the Kekiktuk formation from two
artificial gravel islands. The Kekiktuk is
the reservoir rock for the Endicott oil
field to the northwest. In 1997 BP con-
firmed the existence of the field through
the drilling of the Liberty No. 1 explo-
ration well.
In 1998 BP proposed developing the
field from an artificial gravel island.
However, in 2001 the company re-evalu-
ated that plan and, in 2005, came up
instead with its plan to develop the field
using ultra-extended reach drilling from
Endicott. The company moved ahead
with that plan, expanded the Endicott
satellite island and installed a purpose-
built drilling rig for the project. However,
following technical problems and some
issues relating to the Deepwater Horizon
disaster, the company cancelled the proj-
ect in 2012.
In 2014 BP sold 50 percent ownership
of the field to Hilcorp. Hilcorp became
field operator and has since moved ahead
with planning the development of the
field along similar lines to BP’s original
1998 concept. l
PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018 9
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Companies involved in Alaska’s oil and gas industryAdvertiser Index
All of the companies listed above advertise on a regular basis with Petroleum News
asters, without mentioning climate change, which scien-
tists say will cause heavier rains and stronger storms.
Local matching requiredTexas has not tapped its own rainy day fund of around
$11 billion. According to federal rules, 35 percent of
funds spent by the Army Corps of Engineers must be
matched by local jurisdictions, and the GOP-controlled
state Legislature could help cover such costs. But such
spending may be tough for many conservatives to swal-
low.
Texas “should be funding things like this itself,” said
Chris Edwards, an economist at the libertarian Cato
Institute. “Texans are proud of their conservatism, but,
unfortunately, when decisions get made in Washington,
that frugality goes out the door.”
State officials counter that protecting the oil facilities
is a matter of national security.
The effects of the next devastating storm could be felt
nationwide,” Rep. Randy Weber, a fiercely conservative
Republican from suburban Houston who has nonetheless
authored legislation backing the coastal spine.
Major oil companies did not return messages seeking
comment on funding for the projects. But Suzanne
Lemieux, midstream group manager for the American
Petroleum Institute, said the industry already pays into
programs such as the federal Harbor Maintenance Trust
Fund and the Waterways Trust Fund, only to see
Congress divert that money elsewhere.
“Do we want to pay again, when we’ve already paid
a tax without it getting used? I’d say the answer is no,”
she said.
Phillips 66 and other energy firms spent money last
year lobbying Congress on storm-related funding post-
Harvey, campaign finance records show, and Houston’s
Lyondell Chemical Co. PAC lobbied for building a
coastal spine.
“The coastal spine benefits more than just our indus-
try,” Bob Patel, CEO of LyondellBasell, one of the
world’s largest plastics, chemicals and refining compa-
nies, said in March. “It really needs to be a regional
effort.” l
continued from page 6
SEAWALL PROJECT
continued from page 1
LIBERTY EIS
Multiyear programDoyon has been conducting an oil and
gas exploration program in the Nenana
basin for a number of years — CIRI has
partnered with Doyon in the drilling of both
the Totchaket well and the previous well
drilled in the basin, the Toghotthele well,
drilled in 2016. The basin is conveniently
located close to the Parks Highway, to the
southwest of Fairbanks. Recently Doyon
has been particularly focusing on making an
oil discovery, although the basin is also
highly prospective for natural gas.
The Nenana basin, one of a number of
Alaska basins formed by the pulling apart of
the Earth’s crust, is filled with a huge thick-
ness of non-marine Tertiary sediments. Coal
seams and shales within the rock sequence
have the potential to source both oil and gas,
depending on the extent to which they are
heated at depth. There are sands with excel-
lent hydrocarbon reservoir potential, inter-
layered with shales that could form hydro-
carbon traps. In broad terms, the basin has a
northeast to southwest trending hourglass
shape, with a deep basin in the north and a
central saddle in the narrower, central part
of the basin, immediately west of the town
of Nenana. The depths reached in the
northerly section of the basin are thought to
be sufficient to have raised the temperatures
in the potential source rocks to levels con-
ducive to oil formation.
Three previous wellsDoyon and partners have previously
drilled three wells in the basin’s central sad-
dle, targeting potential traps identified from
seismic data. The hope was that hydrocar-
bons migrating up into the saddle from
deeper parts of the basin would have
become trapped. Although these wells
failed to discover viable pools of oil or gas,
the wells did encounter evidence of an
active petroleum system. The Toghotthele
No. 1 well, for example, drilled in 2016,
found multiple oil shows, as well as natural
gas. Some of that gas was “wet gas,” con-
taining natural gas liquids that must have
formed through the application of heat
rather than through microbial action on
organic material. But it seems that what
now appears to be a trapping structure had
formed after the oil had migrated through
the rocks.
The Nunivak No. 1 well, drilled in 2009,
also encountered some oil shows. And the
Nunivak No. 2 well, drilled in 2013, found
a 400-foot thick section of gas-bearing rock
that also contained too much water to be
commercially viable.
Focus on northerly prospectsWith the drilling of the Totchaket well,
attention shifted to the deeper more norther-
ly part of the basin, above the presumed oil
and gas kitchen. The well targeted the
Totchaket East prospect, one of five
prospects identified from 3-D seismic data
collected from a survey conducted in 2017.
Apparently the seismic displayed hydrocar-
bon indicators in all of the prospects. And
the mapping of subsurface rock units, using
seismic and gravity data, suggests that the
northern part of the basin may have more
reliable hydrocarbon migration pathways
than farther south, with an absence of the
uplift that may have disrupted hydrocarbon
trapping mechanisms in the central saddle.
—ALAN BAILEY
10 PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018
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of Caelus Energy, told Petroleum News on Aug. 29:
“Caelus will not be conducting work at Smith Bay this
winter.”
In early 2016, Caelus claimed it made one of the
largest recent oil discoveries in Alaska or elsewhere
with its two Tulimaniq wells, announcing 6 billion to
10 billion barrels of oil in place.
Thus far, Caelus has not been able to conduct flow
tests for the oil pool.
Caelus has cited low oil prices and uncertainty over
production tax policy at the state level as its reasons for
not returning to the area.
Tulimaniq is far offshore. Reportedly, $90 million of
the $150 million it spent to drill the prospect’s two
wells was spent on logistics, requiring a $60 oil price to
develop the field, per Caelus.
Still, some government geologists are excited about
Tulimaniq.
Petroleum geologist Paul Decker from Alaska’s
Division of Oil and Gas talked to Petroleum News in
June about the nature and significance of the new finds.
Decker sees the new Nanushuk/Torok oil plays as open-
ing the possibility of further significant oil discoveries
to the west of the central North Slope. The plays may
also prove valuable as a geologic paradigm for oil
prospects in the newly opened 1002 area of the Arctic
National Wildlife Refuge, Decker said.
The three recent major finds consist of the
Pikka/Horseshoe trend in the Nanushuk in the Colville
River delta region, discovered by Armstrong and
Repsol and being developed by their partner Oil
Search, the Willow discovery in the Nanushuk of the
northeastern National Petroleum Reserve-Alaska, dis-
covered and headed to development by ConocoPhillips,
and Caelus’ major oil pool in the Torok under Smith
Bay, Decker said.
—KAY CASHMAN
Nutrien still actively seeking gas supply
NUTRIEN, WHICH WAS FORMED WITH THE
MERGER of Potash Corp. and Agrium in early January,
is still hoping to re-open its Kenai Peninsula fertilizer
facility, its Alaska manager Fred Werth told Petroleum
News Aug. 27.
A long-term natural gas supply
in Cook Inlet is crucial to re-open-
ing the facility, and Werth said
Nutrien is “actively engaged in
really trying to sort out” the situa-
tion.
“Gas price is our biggest chal-
lenge,” natural gas feedstock being
the highest cost component in the
manufacturing process, Werth told
PN in January.
The former Agrium facility employed 400 well-paid
Alaskans when in full operation. It closed in 2007,
when the Cook Inlet gas fields were in significant
decline and the facility was unable to secure enough
supply to operate. The inlet gas industry has since expe-
rienced a resurgence of gas exploration and production.
What Canada-based Nutrien, which trades as NTR
on the Toronto and New York stock exchanges, offers
natural gas producers is a stable, long-term gas con-
tract. Although the price Nutrien can justify would be
under current market value, which is currently high
compared to other markets, it would not be subject to
the fluctuations of consumer demand and thus allow
producers to make long-term development plans, Werth
said in January.
Agrium’s North Kenai/Nikiski facility had been the
second largest producer of ammonia and urea in the
United States, most of which was sold overseas to
South Korea, Mexico and Taiwan.
“The greatest advantage of the merger was that it
brought together Potash Corp. and Agrium’s marketing
and production strengths, making products more readily
available across North America,” Werth said in January,
noting the merged company traded all over the world.
The Alaska facility, consisting of two utility, two
ammonia and two urea plants, “is strategically located
in North Kenai on a deepwater port to distribute to the
Pacific Rim,” he said.
Potash and urea ammonia are used in caring for
crops. Potash adds potassium, while urea ammonia sup-
plies nitrogen.
The fastest developing markets for urea are
Southeast Asia and East Asia.
Urea is the most popular form of solid nitrogen fer-
tilizer, particularly in the developing regions of the
world. Currently, the Southwest Asian region consumes
more than 55 percent of the urea produced worldwide.
“They don’t need any special equipment to put urea
on their fields … they can put it on with a gunny sack
and a coffee can,” Werth explained in January.
Liquid nitrogen, which the North Kenai Nutrien
facility would also produce, is primarily used in North
America, as it is sprayed on. Before U.S. farmers used
nitrogen, their average yield was 100 bushels an acre
for corn; today production is 250 bushels per acre.
The re-opening of Agrium’s mothballed fertilizer
facility could provide a significant economic boost for
the region.
Reportedly, rehabilitating the facility for a restart
would cost about $350 million, whereas the cost for
Nutrien to construct a similar facility elsewhere in the
Pacific Rim could run $2-3 billion.
Werth did not confirm or discuss these estimates.
—KAY CASHMAN
More positive headlines for Alaska’s North Slope
ON AUG. 12 AND AUG. 23 OilPrice.com carried
upbeat stories about the renewal of Alaska North Slope
exploration, triggered by the discovery of the “massive”
Armstrong/Repsol Pikka oil field in the overlooked
Nanushuk formation in 2015.
OilPrice.com’s first story, “Why Is Big Oil So
Excited About Alaskan Crude?,” dwelled on the data
release of several previously overlooked oil deposits,
including Pikka, by the Alaska Division of Oil and Gas,
and provided details about the upcoming November
state lease sale.
“After years of diminishing returns in the once
mighty North Slope, Pikka is just one of three major
recent finds that revived interest in the North Slope,”
wrote Haley Zaremba, referring to Pikka, Willow and
Tulimaniq.
The second story, “Alaska’s Oil Renaissance,” refer-
enced new research from IHS Markit, showing “the
North Slope’s crude output could increase by as much
as a whopping 40 percent in the next eight years.”
The North Slope, “previously considered as a mature
basin, is now being touted in the media as the once and
future ‘super-basin’ thanks to an estimated 38 billion
barrels of oil equivalent in remaining recoverable
resources,” Zaremba wrote.
—KAY CASHMAN
continued from page 1
INSIDER
FRED WERTH
continued from page 1
WELL RESULTS
an Alaska Industrial Development and
Export Authority project to bring afford-
able natural gas to Fairbanks and its sur-
rounds. Fairbank gas utility, Interior Gas
Utility, will need the expanded LNG sup-
ply to support an anticipated increase in
the number of gas consumers in the
Fairbanks region.
Siemens under contract to Knik TribeSiemens would build the proposed
plant under contract to Knik Tribe, which
would own the project. Knik Tribe with
assistance from Siemens would capitalize
the project. IGU would sign a liquefaction
services agreement with Knik Tribe, pay-
ing for this service through a service
charge coupled with a volume-based lique-
faction fee for LNG delivered to an IGU
storage tank in Fairbanks. As currently
envisaged by Knik Tribe and Siemens,
IGU would pay for the transportation of
LNG to Fairbanks by railroad.
Thus, rather than funding the capital
cost of the LNG plant, as is envisaged for
the Titan plant expansion, IGU would pay
Knik Tribe a fee for the production and
delivery of LNG to Fairbanks. This
arrangement would presumably enable
IGU to avoid taking on additional debt in
conjunction with expanding the LNG sup-
ply. And Knik Tribe, as a federally recog-
nized tribe, would have access to federal
programs that could minimize the cost of
capital for the project, explained Kelly
Laurel, director for energy and infrastruc-
ture for Siemens Government
Technologies.
When the LNG plant goes into opera-
tion, the contract between Knik Tribe and
Siemens would result in the liquefaction
services agreement obligations for the
plant to, in effect, flow through to
Siemens.
Siemens officials said that Siemens has
already completed the front-end engineer-
ing and design for the proposed project. If
IGU is interested in moving forward with
the project, there are a number of details
around the interface between IGU’s opera-
tions and the LNG supply arrangements
that would need to be negotiated, Laurel
explained. That would lead to a memoran-
dum of understanding that would enable
Knik Tribe and Siemens to confirm the
LNG pricing model and move towards a
contract.
Three potential gas sourcesThe Siemens proposal includes a pric-
ing model using three potential sources of
natural gas for manufacturing LNG: the
gas supply assumed by IGU in its model-
ing of the Titan plant expansion; an alter-
native gas supply agreement negotiated by
Knik Tribe and Siemens; or a new gas sup-
ply from a wellhead gas resource adjacent
the proposed Houston LNG facility.
Knik Tribe and Siemens say that, with
regard to their own pipeline gas supply,
they are conducting confidential negotia-
tions with current suppliers of gas to
Enstar Natural Gas Co’s pipeline system (a
main Enstar gas transmission line runs not
far the proposed Houston LNG plant site).
IGU’s own assumed gas price for the LNG
supply for the Titan expansion is $7.72 per
mcf, the proposal says.
The proposal provides no information
about the potential wellhead gas resource
at the Houston site but says that this option
is being actively pursued, with a potential
cost of supply in the range of $3 to $5 per
mcf.
“As far as wellhead gas, we are invest-
ing in proving out the well right now,” a
Siemens official told the board.
In 2004 Evergreen Resources drilled
several shallow stratigraphic test wells or
core holes, testing for coalbed methane
resources in the Matanuska-Susitna
Borough. At least one of those wells was to
the immediate northwest of Houston. The
coalbed methane exploration program
came to an end shortly after the drilling,
following a political uproar from local res-
idents over land access and concerns about
potential pollution.
Siemens officials told the IGU board
that it sees its involvement in the proposed
Houston LNG plant as an anchor project
for more involvement by the company in
Alaska’s evolving economy. And the
industrial park where the plant would be
located has ample space for further indus-
trial development, should the LNG plant
come to fruition. Moreover, additional
LNG processing at the site for applications
other than the Fairbanks gas supply could
significantly reduce the unit cost of the
LNG.
Range of price possibilitiesThus the proposal presents a range of
possible prices for LNG delivered to
Fairbanks, depending on the nature of the
gas supply and the extent of the LNG
development. Modeling using IGU’s
assumed future gas demand profile for
Fairbanks and IGU’s assumed gas supply
pricing results in an anticipated price of
$17.98 per mcf for LNG delivered to the
Fairbanks storage tank. That price could
drop to $15.02 per mcf, depending on what
alternative pipeline delivered gas supply
Knik Tribe and Siemens may be able to
negotiate. The use of an on-site wellhead
gas supply could drop that price to $13.93.
A pipeline gas supply in combination with
increased industrial activity at Houston
could drop the price to $12.04, while a
wellhead supply with increased industrial
activity could drop the price to $10.96.
And rather than assume a single price
model for the entire period that the
Houston plant would be in operation, there
would likely be opportunities to progres-
sively bring the costs down as, for exam-
ple, further industrial development takes
place or the gas supply opportunities
change, Laurel told the board.
The pricing includes an assumed cost
for the transportation of LNG by railroad
from Houston to Fairbanks. However, a
determination of the burner-tip price of gas
for Fairbanks consumers would require the
inclusion of LNG storage and gas distribu-
tion costs in Fairbanks.
Modular designThe LNG plant would be constructed
using a modular Siemens design that can
be scaled up in increments to meet climb-
ing LNG demand. An initial plant could be
shipped and assembled for operation with-
in 12 months of a contract with IGU being
signed. And the contract would include a
not-to-exceed cost that would eliminate
IGU’s exposure to construction cost over-
run risk, the proposal says.
In terms of security of supply, the pro-
posal says that the potential Houston LNG
plant would have the capability to load
LNG into LNG trucks for transportation to
Fairbanks by road, should some problem
arise with the use of the railroad.
Moreover, the efficient shuttling of LNG
containers on the railroad requires more
containers than are actually in use at any
specific time — the excess containers in
Houston, coupled with LNG storage capa-
bilities there, could provide contingency
storage of up to 720,000 gallons, to back
up the storage that IGU will have available
in Fairbanks.
Knik Tribe and Siemens have suggested
a program of negotiations that they think
could lead to the signing of a contract by
the end of this year. That could lead to the
LNG plant going into operation at the
beginning of 2020. IGU board members
indicated that they want to conduct a side-
by-side comparison of the two LNG
expansion concepts, the Titan expansion
and the Siemens option, to be able to make
a considered decision on which option to
choose. In addition, AIDEA, as financier
for IGU’s LNG expansion project, would
need to be involved in any decision.
—ALAN BAILEY
PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018 11
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continued from page 1
LNG PROPOSALIGU board members indicated thatthey want to conduct a side-by-side
comparison of the two LNGexpansion concepts, the Titan
expansion and the Siemens option,to be able to make a considered
decision on which option to choose.
12 PETROLEUM NEWS • WEEK OF SEPTEMBER 2, 2018
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350,000 acres is close to existing infra-
structure and to the trans-Alaska oil
pipeline and approximately 20 miles
southeast of Deadhorse, which is an unin-
corporated community consisting mainly
of facilities for oilfield workers and firms
that have contracts with the nearby oil
fields, including Prudhoe. Deadhorse is
accessible via the Dalton Highway and
the Deadhorse Airport.
To the west of Prudhoe Bay, Eni owns
and operates the Nikaitchuq oil field and
is a minority owner in the adjacent
Caelus-operated Oooguruk oil field, with
a total net production of approximately
20,000 barrels of oil equivalent a day.
Oooguruk is adjacent to the Pikka unit
where the huge Pikka and Horseshoe oil
discoveries were made in 2016 by
Armstrong and Repsol and are under
plans for development by their partner Oil
Search.
Multiple play types revealed on seismic
Shortly after acquiring the eastern
North Slope leases in 2015, which are in
two blocks, Caelus acquired 175 square
miles of new 3-D seismic data and
reprocessed another 275 square miles of
existing 3-D to image prospects on the
acreage.
“Adjacent infrastructure with available
capacity reduces threshold volumes
required for developing discoveries in the
sub-100 MMBO recoverable range,”
Caelus said. “Multiple play types within
proven stratigraphic horizons provide sig-
nificant upside potential in previously
poorly-imaged structural trends and/or
subtle stratigraphic traps.”
Surrounding legacy wells “confirm
deeper petroleum system elements and
de-risked shallower Brookian reservoirs
and hydrocarbon charge and phase within
the area,” Caelus said, much of which has
been previously reported in PN.
Nikaitchuq North wildcat and unit drilling
Eni’s plan to resume oil drilling at
Nikaitchuq and indications of positive
results from the company’s Nikaitchuq
North wildcat well preceded Eni’s Aug.
29 announcement.
Eni CEO Claudio Descalzi said at a
recent 2018-21 strategy meeting that the
company was “doing well” in Alaska and
had plans for “increased investment” in
the state (see Oil Patch Insider, April 22
issue of PN).
In its 11th plan of development for the
Nikaitchuq unit, Eni announced plans to
drill as many as three new wells and to
add laterals to as many as eight existing
single lateral wells at its Spy Island
Drillsite as soon as October, depending
on “the results and scope of exploration
work” at Nikaitchuq North, which
involved drilling an ultra-extended reach
well from the Spy Island Drillsite into
federal waters north of the Nikaitchuq
unit.
The rig that was used for the wildcat,
Doyon 15, required considerable modifi-
cation and will also be used for drilling
the unit wells.
From the beginning, the purpose of the
wildcat was to add reserves to Nikaitchuq
and to increase production from the unit. l
Note: For more information on Eni’splan of development see this article in theJuly 29 issue of PN: “Eni says drilling atNikaitchuq could resume as early as thisfall.”
continued from page 1
ENI ACQUISITION
linked to exercising the option and undertaking joint divest-
ment.
The company has an option, good through next June, to
acquire the other 50 percent of Armstrong equity in the proj-
ect.
A ‘world-class team’Botten said building a world-class team in Alaska was
critical to the company’s success, with some 50 people
working in Anchorage, a number expected to grow to about
100 by year-end.
In an overhead prepared for the presentation Oil Search
said it is investing in local talent in Alaska, with 70 percent
of its employees residents of Alaska and 9 percent Alaska
Natives.
The company said the team has strong Alaska and inter-
national capability, with the overhead noting 335-plus years
of U.S. oil and gas experience, 240-plus years of Alaska
North Slope experience and extensive global experience.
Oil Search highlighted the diversity of its Alaska team:
28 percent of the leadership team is composed of women;
30 percent of the Oil Search Alaska team are women; and
16 percent are expats transferring Oil Search knowledge to
Oil Search Alaska.
—KRISTEN NELSON
continued from page 8
OIL SEARCHBotten said building a world-class team in
Alaska was critical to the company’s success, withsome 50 people working in Anchorage, a number
expected to grow to about 100 by year-end.