l exploration & production seismic surge
TRANSCRIPT
Scanning core surface for spectralsignature showing mineralization
l E X P L O R AT 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
Caelus drops 13 of 25 leases fromOooguruk prior to Eni takeover;Wulff, Balash to speak at RDC
AN INTERESTING STEP IN ENI
PETROLEUM’s takeover of operatorship
and full ownership of the Oooguruk oil field
took place on June 17 when the state of
Alaska allowed Caelus Natural Resources to
drop 13 leases in which it has a 100% inter-
est from the southern half of the unit.
In a letter to Caelus Senior Vice President
Pat Foley, the Division of Oil and Gas
approved the voluntary unit reduction from 25 to 12 leases
because no participating area exists in the contraction area
Trudeau regulatory regime changestake bite out of capital spending
The numbers offer a clear picture of the Canadian govern-
ment’s strategy that has dragged its petroleum industry from a
place of prominence on the global stage.
And the worst could be yet to happen based on warnings from
company chief executive officers that new federal legislation will
choke off any hopes of pipeline expansions that are essential if
Canada is to diversify its markets beyond North America.
In its annual forecast on crude oil production, markets and
transportation, the Canadian Association of Petroleum Producers
has delivered the grimmest outlook in history.
Predicting a fifth straight year of shrinking capital investment
in the oil sands from C$33.9 billion in 2014 to an expected C$12
billion this year, CAPP blamed the trend on “continual delays in
see INSIDER page 10
see NUNA PROSPECT page 14
see REGULATORY CHANGES page 10
see PROJECT LICENSE page 11
page9
Vol. 24, No. 25 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of June 23, 2019 • $2.50
Igiugig hydrokinetic pilot getsFERC OK with 10-year license
The Federal Energy Regulatory Commission has issued the
Igiugig Village Council a 10-year pilot project license for the
Igiugig Hydrokinetic Project.
The council applied for the license for an in-river turbine
power generation pilot project in November. FERC issued an
environmental assessment for the project in February.
Ocean Renewable Power Co., which specializes in hydro-
kinetic power generation, has been assisting Igiugig and a
hydrokinetic system was tested in the village in 2014 and
2015.
“I am so pleased this project will be able to move forward,
Seismic surgeBig 3-D seismic surveys in works for North Slope, nearshore Beaufort Sea
By KAY CASHMANPetroleum News
Renewed interest in the North Slope
of Alaska’s untapped oil has led to
an increase in large 3-D seismic surveys,
including the program for the ANWR
1002 area, for which Inupiat
Geophysical Partnership could have a
permit in hand prior to this year’s federal
lease sale.
All but one of the big new surveys have been,
or will be, conducted by SAExploration of
Anchorage. In recent correspondence with Jeff
Hastings, SAE chairman and CEO, Joe Balash,
assistant secretary of Land and Minerals
Management, and a review of 3-D seis-
mic permit filings with the Alaska
Department of Natural Resources,
Petroleum News put together the follow-
ing seismic update (see related map on
page 15 of this issue).
Marsh Creek 3-D Program In mid-2018, SAE filed approvals on
behalf of itself and its partners to conduct
a 3-D seismic survey in the narrow strip
of coast along the Arctic National Wildlife Refuge,
which makes up the 2,600-square-mile 1002 area
that was set aside for potential development by
Once more for TMXCanada announces 2nd approval of TMX; Trudeau holds out hope of ’22 deliveries
By GARY PARKFor Petroleum News
The Canadian government has reap-
proved expansion of the Trans
Mountain pipeline from Alberta’s oil
sands to a shipping terminal in
Vancouver.
Reaction to the announcement on
June 18 by Prime Minister Justin
Trudeau from Canada’s oil industry and
the Alberta government could have been summed
up in two words — “so what?”
This was, after all, the second go-ahead from
the federal cabinet after the project passed three
rounds of regulatory hearings.
Each time the plan to triple capacity
on the system to 890,000 barrels per day
has been tripped up, either by a change of
government or court verdicts.
Who is to say that more of the same
isn’t in store this time?
Within minutes of Trudeau’s news
conference, the old foes had swung back
into action.
The British Columbia government,
the cities of Vancouver, Burnaby and other B.C.
municipalities, the Green Party of Canada, endless
environmental organizations and several First
State terminates unitHilcorp appeals North Trading Bay unit plan of development denial, termination
By KRISTEN NELSONPetroleum News
The state has terminated a small unit
in Cook Inlet, citing regulations
which require “diligent operations … to
restore production” in a unit where pro-
duction has ceased.
In a May 30 letter to operator Hilcorp
Alaska LLC, Jim Beckham, acting
director of the Alaska Department of
Natural Resources’ Division of Oil and Gas, said
that because there “currently are no diligent oper-
ations to restore production” the North Trading
Bay unit has automatically terminated; because
the unit is terminated, Hilcorp’s 2019 plan of
development for the unit has been
denied.
In a June 18 letter, Hilcorp appealed
the termination.
The timeline for work is an issue, with
the state wanting the company to get the
unit back into production. Hilcorp’s
drilling plan, a well from a non-unit plat-
form which would bottomhole in non-
unitized acreage adjacent to the existing
unit, is also an issue. Hilcorp says it wants
to expand the unit, dependent on the success of the
well; the division is focused on the resumption of
production from the existing unit.
see SEISMIC SURGE page 15
see TMX APPROVAL page 13
see UNIT TERMINATED page 14
JOE BALASH
JUSTIN TRUDEAU
JIM BECKHAM
Conoco buys Nuna; Torokprospect could yield 25,000 bpd
ConocoPhillips Alaska has made pub-
lic its agreement to purchase 100% own-
ership in the North Slope Nuna prospect
from Caelus Natural Resources. A Caelus
spokesman had told Petroleum News in
April that the acreage had been sold and
the buyer wanted to withhold its name
until later in the summer.
Five miles southwest of the Oooguruk
unit and just east of the Colville River
within the northern section of the
Colville-Kuparuk fairway, the Nuna prospect includes 11
tracts covering 21,000 acres.
JOE MARUSHACK
2 PETROLEUM NEWS • WEEK OF JUNE 23, 2019
FINANCE & ECONOMY
LAND & LEASING
8 Majors commit to carbon pricing at Vatican summit
PIPELINES & DOWNSTREAM7 Line 3 hits another Minnesota obstacle5 FERC: Eco Green not a ‘qualified facility’
9 US drilling rig count down by 6 to 969
9 Hyperspectral surface scan of core
GOVERNMENT2 Hilcorp fined $30,000 for not reporting
AOGCC says company failed to submit required custody meter performance reports from Cook Inlet units Granite Point, Trading Bay
4 EPA working changes from executive order
Agency’s guidance for Section 401 of the Clean Water Act has now been updated and revised regulations are due out this August
3 Fiord West Kuparuk PA OK’d by landowners
Most of development in this 12,015-acre participating area willbe with extended reach drilling rig ConocoPhillips is bringing in
ALTERNATIVE ENERGY
EXPLORATION & PRODUCTION
Seismic surgeBig 3-D surveys in works for North Slope, nearshore Beaufort Sea
Once more for TMX Canada announces 2nd approval; Trudeau hopes for ’22 deliveries
State terminates unitHilcorp appeals North Trading Bay unit plan of development denial
ON THE COVER
Insider: Caelus drops 13 of 25 leases from fieldprior to Eni takeover; Wulff, Balash at RDC
Conoco buys Nuna; Torokprospect could yield 25,000 bpdTrudeau regulatory regime changestake bite out of capital spendingIgiugig hydrokinetic pilot getsFERC OK with 10-year license
Petroleum News Alaska’s source for oil and gas newscontents
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3601 C Street, Suite 1424Anchorage, AK 99503
(907) 272-1232(907) 272-1344
By KRISTEN NELSONPetroleum News
The Alaska Oil and Gas Conservation Commission
has fined Hilcorp Alaska LLC $30,000 for “failure to
submit required meter performance reports” for custody
transfer meters at the company’s Cook Inlet Granite Point
and Trading Bay units. The commission said in an order
issued June 12 that in addition to the civil penalty, Hilcorp
must provide, within 10 days, “a detailed written explana-
tion that describes how it intends to prevent recurrence of
this violation.”
The commission issued a proposed enforcement action
May 7, which said: “Hilcorp has violated the provisions of
the conditional approval letters for the Granite Point Unit
and Trading Bay Unit custody transfer oil measurement
equipment.”
The commission conditionally approved meter changes
and upgrades designed for the Cross Inlet Pipeline exten-
sion in February. The commission said the changes provid-
ed for two sizes of custody transfer meters at each produc-
tion facility to allow for variable flow rates.
In its May 7 letter to Hilcorp the commission said the
conditional approval in February required “meter prove fre-
quency, notification to AOGCC for opportunity to witness
meter proves, required actions before making changes to
the custody transfer measurement equipment, and reporting
obligations following proves.”
The reporting obligations required Hilcorp to provide
results of monthly meter proves within seven days follow-
ing the proves. The commission said “Hilcorp failed to sub-
mit meter performance reports as directed” in the February
conditional approval.
Not isolated eventsThe commission said in its May 7 letter that Hilcorp’s
failures to report “are not isolated events,” and cited a notice
of proposed enforcement issued in 2016 for a similar viola-
tion at the Bartolowits pad at the Ninilchik unit.
“Hilcorp’s non-compliance history in conducting hydro-
carbon development activities in Alaska includes past fail-
ures to obtain necessary approvals, failures to install, main-
tain, and test required well control safety systems, failures
to perform required tests, and failure to provide reports,” the
commission said, and cited 18 non-civil penalty and seven
civil penalty enforcement actions it has issued against
Hilcorp since January 2012.
“Recurring areas of noncompliance, such as Hilcorp’s
inability to account for specific approval conditions in its
l G O V E R N M E N T
Hilcorp fined $30,000 for not reportingAOGCC says company failed to submit required custody meter performance reports from Cook Inlet units Granite Point, Trading Bay
see HILCORP FINE page 7
By KRISTEN NELSONPetroleum News
An application from ConocoPhillips Alaska Inc. for
formation of the Fiord West Kuparuk participating
area in the Colville River unit has been approved by the
three landowners in the area — Arctic Slope Regional
Corp., the federal Bureau of Land Management and the
Alaska Department of Natural Resources.
A participating area defines the portion of a unit from
which production is expected occur; approval of a PA is
required before production begins.
The state, ASRC and BLM jointly manage the Colville
River Unit. The Fiord West Kuparuk PA includes some
12,015 acres on state oil and gas leases, ASRC oil and gas
leases, leases jointly owned by ASRC and the state and
BLM oil and gas leases.
The majority of the acreage is state. ASRC has owner-
ship of 4,083 acres in the proposed PA. BLM’s ownership
is 240 acres, on a single federal lease, which was included
in the seventh expansion of the Colville River unit in 2017.
In its decision DNR’s Division of Oil and Gas said the
proposed Fiord West Kuparuk PA is about a mile west of
the current Fiord Nechelik PA in a region ConocoPhillips
has referred to as the Fiord West development area. There
are seven exploration wells in the vicinity of the new PA:
Nechelik 1, Temptation 1, Temptation 1A, Nigliq 1, Nigliq
1A, Iapetus 2 and Char 1. “Six of these wells encountered
the Lower Cretaceous Kuparuk River Formation,” the
division said.
“The Kuparuk River sandstone is a shallow marine
transgressive sequence deposited on the Lower Cretaceous
Unconformity,” and varies across the two Fiord PAs from
1 foot thick to 21 feet. The division said the Kuparuk A
sandstone is not present in the area.
Exploration, development historyThe division said drilling began in the area in 1996
when ARCO Alaska drilled the Temptation 1 and a devi-
ated sidetrack, the Temptation 1A, encountering 9 feet of
gross Kuparuk sandstone in the original well and 8 feet
of gross sandstone in the sidetrack.
In its PA application ConocoPhillips said the
Temptation wells “were the first wells west of the fault
trapped CD3 Fiord Kuparuk accumulation to find signif-
icant Kuparuk C thickness and reservoir quality.”
Fiord 5 was drilled to both Kuparuk and Nechelik tar-
gets in 1999, with 15 feet of gross sand in the Kuparuk;
both zones were tested, with the Nechelik interval pro-
ducing 1,400 barrels per day of 29-degree American
Petroleum Institute gravity oil. The combined Nechelik
and Kuparuk test produced 2,500 bpd.
The division said development wells in the CD3 Fiord
Kuparuk field have shown oil gravity in the Kuparuk
area to be above 29 degrees API.
Phillips Alaska drilled Nigliq 1 and Nigliq 1A about 5
miles west of the Fiord 5 well in 2001, the division said,
with 2 feet of gross Kuparuk C sandstone found in Nigliq
1 and 5 feet in Nigliq 1A.
ConocoPhillips Alaska drilled Iapetus 2 in 2005,
encountering 10 feet of gross Kuparuk C sandstone as
well as Nechelik sandstone, the division said; the well
was not tested.
The division said the company drilled Char 1 in 2008,
encountering 12 feet of gross Kuparuk C sandstone. The
well was perforated and flow tested, “producing 23,190
barrels of oil over a seven-day period,” an oil rate which
averaged some 3,620 bpd with an API oil gravity of 39
degrees.
The Kuparuk C has also been penetrated by several
wells as part of the Fiord Nechelik development at CD3,
the division said, with gross thickness between 3 and 8
feet along the eastern edge of the proposed Fiord West
Kuparuk PA.
The Fiord West Kuparuk PA “is defined as the
Kuparuk C sands correlative to the Kuparuk C sandstone
found in the Char 1 well,” the division said, with the top
of the Kuparuk C sandstone in that well at 7,252 feet
measured depth and the base the Lower Cretaceous
Unconformity at 7,264 feet MD.
DevelopmentThe division said ConocoPhillips’ revised plan of
development for the Colville River unit includes an ini-
tial well into the Fiord West Kuparuk PA “to gather data
and support planning reservoir development.”
In its 21st annual update to the Colville River unit
agreement, dated March 15, ConocoPhillips said its
2019 plans included a Fiord West Kuparuk pilot hole in
the first quarter of 2019, “a slant pilot hole well targeting
the Fiord West Kuparuk reservoir near where future
extended reach laterals are planned to be drilled” with
the extended reach drilling rig.
“The purpose of this well is to evaluate static subsur-
face properties and production to assist detailed ERD
well planning and execution efforts,” the company said.
In its approval letter ASRC said ConocoPhillips plans
to drill seven wells for the Fiord West Kuparuk PA, with
production from the first well expected in the second
quarter of this year, and the other six wells to be drilled
by the extended reach drilling rig due onsite in the sec-
ond quarter of 2020. l
l L A N D & L E A S I N G
Fiord West Kuparuk PA OK’d by landownersMost of development in this 12,015-acre participating area will be with extended reach drilling rig ConocoPhillips is bringing in
PETROLEUM NEWS • WEEK OF JUNE 23, 2019 3
The division said ConocoPhillips’ revised planof development for the Colville River unitincludes an initial well into the Fiord WestKuparuk PA “to gather data and support
planning reservoir development.”
By KRISTEN NELSONPetroleum News
In April President Donald Trump
signed two executive orders aimed at
speeding up government approval of
energy infrastructure. One of the orders
dealt, in part, with Section 401 of the
Clean Water Act.
The Environmental Protection Agency
released updated guidance for Section
401 of the CWA June 7. Under Executive
Order 13868, the agency said, “EPA was
directed to issue guidance for federal per-
mitting agencies and state and authorized
tribal authorities to modernize previous
guidance and clarify existing CWA
Section 401 requirements.”
U.S. Sen. Lisa Murkowski, R-Alaska,
said in a June 10 statement that she wel-
comed the announcement and hopes the
new guidance “will reduce abuse of the
Clean Water Act to block infrastructure
needed to provide reliable and affordable
energy.” She said vital protection for
water resources will be maintained under
the updated guidance “while promoting
responsible development of our energy
resources.”
EPA said it new guidance replaces
interim guidance issued in 2010 and also
recommends early collaboration and
coordination for the 401 certification
process among federal agencies, states
and authorized tribes.
Executive Order 13868 also directed
EPA to propose new rules modernizing its
CWA Section 401 and required the
agency to implement new regulations by
Aug. 8.
EPA said it intends to propose regula-
tions further clarifying and streamlining
Section 401 certifications. Since the
Executive Order was issued in April, EPA
said, it has initiated formal consultations
with its state, local and tribal partners,
and outreach to its federal partners, and
invited pre-proposal recommendations
through a public docket.
Section 401Section 401 of the CWA requires
approval by the state or authorized tribe
for federal permits or licenses for any
activity that may result in discharge into
waters of the United States.
EPA said Section 401 of the Clean
Water Act “provides states and authorized
tribes with an important tool to help pro-
tect water quality within their borders in
collaboration with federal agencies,” but
said rules governing the authority have
not been updated in nearly 50 years.
Evolving case law and the agency’s out-
dated guidance “have caused some confu-
sion and resulted in delays in certain
infrastructure projects with potentially
significant national benefits,” EPA said.
EPA said the CWA provides that states
and authorized tribes must act on their
Section 401 authority within “any reason-
able time not to exceed one year,” with
definition of the reasonable period up to
the federal permitting or licensing
agency.
Implementation of executive order EPA said in a June 7 letter to gover-
nors, tribal leaders and cabinet secretaries
that it was rescinding EPA’s April 2010
Interim Handbook, which had provided
guidance to CWA Section 401 water qual-
ity certifications. It said the Interim
Handbook was not a rule, did not substi-
tute for CWA Section 401 or implement-
ing regulations and said EPA had reserved
discretion to revise the handbook.
“The EPA has not updated or modified
the 2010 Interim Handbook since it was
issued, and the document no longer
reflects the most recent case law inter-
preting the plain language of CWA
Section 401,” the agency said.
It also noted that the Interim
Handbook was never finalized and said it
was concerned that an interim handbook,
which has not been updated “and has nei-
ther been finalized nor formally with-
drawn, may lead to confusion for both
regulators and the regulated community.
This is especially true in circumstances,
including litigation, in which such a doc-
ument may be interpreted as mandating
certain actions or outcomes.”
EPA said that it anticipates that its
activities in response to Executive Order
13868, “including additional engagement
with state and tribal stakeholders, issuing
new guidance, and modernizing federal
rules implementing CWA Section 401,
will increase transparency and regulatory
uncertainty.”
The guidanceIn its updated guidance EPA said,
“Section 401 envisions a robust state and
tribal role in the federal permitting or
licensing process, but places limitations
on how that role may be implemented to
maintain an efficient process that is con-
sistent with the overall cooperative feder-
alism construct established by the CWA.”
“The plain language of Section 401
provides a state or authorized tribe a rea-
sonable period of time, which shall not
exceed one year, to act on a Section 401
certification request. Importantly, the
CWA does not guarantee that a state or
tribe may take a full year to act on a
Section 401 certification request, but only
grants as much time as is reasonable.”
EPA cited general provisions of
Section 401 and the agency’s existing
regulations and said, “federal permitting
agencies have the authority and discretion
to establish certification timelines so long
as they are reasonable and do not exceed
one year.”
The timeline for action begins with
receipt of a certification request, EPA
said, and while “the EPA’s prior Section
401 guidance indicated that the timeline
for action begins upon receipt of a ‘com-
plete application,’ the CWA does not use
that term and therefore its use in the
EPA’s guidance document as a regulatory
trigger, without notice and comment rule-
making, is inappropriate.”
EPA goes on to say that Section 401 of
the CWA “makes no mention of a state or
tribe’s authority to determine that a
request is incomplete or delay the start of
the timeline on that basis.”
The agency said the timeline for
review begins upon receipt of a written
request for certification.
“Section 401 of the CWA is a statutory
tool intended to provide states and tribes
with authority to protect water quality
within their jurisdictions,” EPA said,
describing this as “the focused intent of
this provision on the protection of water
quality,” and said it “recommends that
conditions in a Section 401 certification
be limited to ensuring compliance with
the enumerated provisions of the CWA
and other appropriate state or tribal water
quality requirements.”
EPA said there is some regulatory
uncertainty in this area and it “may con-
sider providing additional clarity during
the rulemaking process.”
No CWA provisions require specific
information to be submitted with a
Section 401 certification request,
although no statutory provision prohibits
a state or tribe from requesting specific
l G O V E R N M E N T
EPA working changes from executive orderAgency’s guidance for Section 401 of the Clean Water Act has now been updated and revised regulations are due out this August
4 PETROLEUM NEWS • WEEK OF JUNE 23, 2019
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MACHINE SHOP SERVICES | PREMIUM THREADINGTOOL TESTING | DOWNHOLE TOOL DESIGN
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see EXECUTIVE ORDER page 5
information, EPA said, but noted that a
state or tribe “should only need the appli-
cation materials submitted for the federal
permit or license.” A state or tribe might
request additional information, but, EPA
said, “an outstanding or unfulfilled
request for information or documents
does not pause or toll the timeline for
action on a certification request.”
“Given the interest and attention this
issue has generated, the EPA may consid-
er providing additional clarity during its
rulemaking effort,” the agency said.
For denials of Section 401 certifica-
tion, EPA said it recommends that the
notice be in writing and identify specific
reasons for the denial and any outstand-
ing data or information gaps, “so the
project proponent has a meaningful
opportunity to cure the identified defi-
ciencies in a new request.” l
PETROLEUM NEWS • WEEK OF JUNE 23, 2019 5
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EXECUTIVE ORDER
By KRISTEN NELSONPetroleum News
Eco Green Generation wants Golden Valley Electric
Association to develop an interconnection tariff for a
self-certified hybrid qualifying facility with nine wind
turbines, a battery storage facility and 20 reciprocating
engine cogeneration facilities. Eco Green wants to devel-
op a hybrid wing-propane generation facility and sell the
power to GVEA, with thermal power being used for dis-
trict heating needs.
GVEA filed with the Regulatory Commission of
Alaska for a stay of its obligations to develop a tariff, and
with the Federal Energy Regulatory Commission for a
declaratory order challenging Eco Green’s qualifying
facility status.
FERC granted GVEA’s petition June 6, revoking Eco
Green’s qualifying facility status; RCA granted GVEA’s
petition for stay June 17.
In addition to granting GVEA’s petition to stay, RCA
is also requiring GVEA to notify it when the FERC order
becomes final and non-appealable.
RCA said it previously granted GVEA a temporary
stay of its obligation to provide an interconnection tariff.
There have been numerous RCA filings by both par-
ties, but RCA said that since FERC has revoked Eco
Green’s qualifying facility, QF, status, GVEA is no longer
required to file a tariff under the commission’s regula-
tions.
Because the FERC order can be appealed, RCA said,
“we find good cause to grant GVEA’s Petition for Stay,”
until a FERC decision on the QF status of the Eco Green
hybrid projects becomes final and non-appealable. If
GVEA were required to develop a tariff, its ratepayers
would have to pay the cost.
FERC orderFERC said in its June order that “Eco Green’s facility
does not meet the requirements for QF status under the
Public Utility Regulatory Policies Act of 1978,” and
therefore it revokes the self-certification for QF status
“without prejudice to Eco Green filing new Form No.
556s that address the deficiencies identified in this order.”
FERC said Eco Green’s hybrid facility does not qual-
ify as either a small power production facility or a cogen-
eration facility, and said a facility seeking to qualify as
both must meet the requirements for both.
Eco Green does not quality as a small power produc-
tion QF, FERC said, because it is larger than 80
megawatts, the maximum allowed for a small power pro-
duction facility, and the 20 cogeneration units in the proj-
ect would burn 97% propane, which does not meet the
fuel use requirements for a small power production QF.
FERC said that Eco Green’s hybrid facility not meet
the four criteria to qualify as a cogeneration facility: it
does not meet the definition; Eco Green has not provided
enough information to demonstrate that the hybrid facili-
ty would satisfy the operating and efficiency standards in
federal statute; does not meet the requirement that ther-
mal output be used in a productive and beneficial man-
ner; and does not meet the requirement that the energy
output not be intended fundamentally for sale to an elec-
tric utility.
FERC also said that since Eco Green has not secured
users for thermal power, “the thermal uses of the output
of the facilities are too speculative to justify finding that
at least 50 percent of the total output of the facilities will
be used fundamentally for industrial, commercial, resi-
dential, or institutional purposes.”
Other requests deniedFERC denied requests from both parties.
Eco Green asked FERC to fine GVEA at least
l A L T E R N A T I V E E N E R G Y
FERC: Eco Green not a ‘qualified facility’
see ECO GREEN page 7
6 PETROLEUM NEWS • WEEK OF JUNE 23, 2019
Wolfpack Land Company is Offering 4,761 Acres of Prime
Mineral Interest Ownership in the Kenai, Alaska Area for
Oil and Gas Leasing
Beaver Loop Road Area
Township 5 North, Range 11 West (Surveyed)
Section 1, Lots 6-8, 10, 14, S1/2NE1/4,
N1/2SE1/4, NE1/4SW1/4;
Section 2, Lots 3 and 6, Sl/2NW1/4.
Section 11, Lots 1, 8, 9, W1/2NE1/4,
NW1/4SE1/4, NE1/4SW1/4;
Section 12, Lots 1-13, NE1/4SW1/4,
SE1/4NE1/4, NW1/4SE1/4.
Containing 1,063.51 acres, more or less.
Township 6 North, Range 10 West (Surveyed)
Section 29, SW1/4, S1/2NW1/4
Section 30,Lots 3 & 4, E1/2SW1/4, SE1/4,
S1/2NE1/4
Section 31,Lots 1 & 2, NE1/4NW1/4NE1/4
Section 32,NW1/4NW1/4
Containing 947.98 acres, more or less.
Township 6 North, Range 11 West (Surveyed)
Section 25, El/2SE1/4,El/2SW1/4SE1/4
Section 35, NE1/4NE1/4, N1/2S1/2NE1/4,
N1/2S1/2S1/2NE1/4, SE1/4NW1/4,
E1/2SW1/4SW1/4,
E1/2W1/2SW1/4SW1/4,
W1/2SW1/4SW1/4SW1/4, SE1/4SW1/4,
S1/2SE1/4, S1/2N1/2N1/2SE1/4,
S1/2N112SE1/4.
Section 36,All
Containing 1,105 acres, more or less.
Aggregating 3,116.49 acres, more or less.
Robinson Loop Road Area
Township 5 North, Range 9 West (Surveyed)
Section 6, Lots 2, 3, 5-7, SW1/4NE1/4,
El/2SWl/4, SEl/4;
Section 7, Lots l, 2, El/2NWl/4, NEl/4,
NEl/4SEl/4;
Section 8,Wl/2NW1/4, NWl/4SWl/4.
Containing 926.23 acres, more or less.
Township 5 North, Range 10 West (surveyed)
Section l, Lots l, 2, Sl/2NEl/4, SEl/4;
Section 12, El/2, El/2NWl/4.
Containing 718.96 acres, more or less.
Aggregating l,645.19 acres, more or less.
These fee mineral rights have
significant known hydrocarbons on or
very near them. This prospect is not
in a remote area. Everything is road
accessible, winter and summer, with
easy access to oilfield suppliers.
Seismic data available.
Terms: $3,000/acre, 25% royalty.
For more details contact Wolfpack
Land Company, Houston, Texas, at
[email protected], or (907) 394-
9148.
PETROLEUM NEWS • WEEK OF JUNE 23, 2019 7
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regulatory compliance tracking efforts,
call into question the assurances that cor-
rective actions implemented in response
to past enforcement actions would be
effective in mitigating repeat violations,”
the commission said.
Civil penaltiesThe commission said in its June 12
order that the $30,000 civil penalty was
$15,000 each for the initial violations,
the failure to provide meter perform-
ance reports, at Granite Point and at
Trading Bay.
An AOGCC inspector witnessed ini-
tial functional checks and initial meter
proves at the Trading Bay unit produc-
tion facility on March 1 and at the
Granite Point tank farm on March 2.
Hilcorp performed required monthly
meter proves at both locations April 1,
the commission said.
The commission said it was provided
reports from meter proves and transmit-
ter calibration checks on March 5 but
said no meter factor control charts were
included. No results were provided for
meter proves on April 1 and May 1, the
commission said.
Hilcorp provided copies of the
required reports by email on May 16, and
by letter on May 17 the company
acknowledged receipt of the commis-
sion’s notice and requested an informal
review. That review was held June 6 and
the commission said “Hilcorp asked sev-
eral clarifying questions and provided
verbal assurance that corrective actions
have been implemented.”
The commission’s June 12 order does
not include any specifics from the infor-
mal review, but the commission said:
“Acceptance of arguments that the condi-
tions of approval are new provisions to
Hilcorp operations personnel responsible
for overseeing the custody transfer
meters at Granite Point and Trading Bay
Units would essentially encourage per-
sonnel not to familiarize themselves with
the requirements of applicable orders and
regulations.” The commission said the
approval conditions were not ambiguous
“and the requirements are consistent with
the industry recognized practices found
in API Manual of Petroleum
Measurement Standards.”
Recent improvementsThe commission noted that there have
been improvements in Hilcorp’s compli-
ance over the past two years, but “the
recurrence of failing to account for
approval conditions imposed by AOGCC
calls into question the effectiveness of
corrective actions implemented in
responses to past enforcement actions.”
The commission did note a number of
mitigating circumstances, including
Hilcorp’s partial submittal of information
from the March 1-2 meter proves,
“Hilcorp’s urgency in providing the miss-
ing information to AOGCC after receiv-
ing the Notice, the demonstrated good
performance of the meters as shown in
their respective meter factor control
charts, and no injury to the public.”
The commission noted it did use its
discretion “in significantly reducing the
penalty by not invoking per-day or per-
month assessments for the violations.”
Hilcorp did not respond to a request
for comment in time for this issue’s
deadline. l
continued from page 2
HILCORP FINE
$10,000 for including false facts and
legal requirements in its petition. “We
cannot find on the record before us that
the Petition was made in anything other
than good faith and represents anything
other than vigorous advocacy of Golden
Valley’s position,” FERC said.
Eco Green asked for a waiver of
unspecified regulations to allow it to
retain QF status, “asserting that the air
pollution in Fairbanks is grounds for
granting waiver,” but FERC said the spe-
cific regulations to be waived are not
specified, nor is sufficient explanation
provided for such a waiver, and that
request is also denied.
GVEA asked FERC to require Eco
Green to obtain FERC certification for all
future QF projects that require intercon-
nection with GVEA. FERC denied the
request, saying its regulations do not
require an application to obtain FERC
certification. l
continued from page 5
ECO GREEN
l P I P E L I N E S & D O W N S T R E A M
Line 3 hits anotherMinnesota obstacle
By STEVE KARNOWSKIAssociated Press
Enbridge Energy’s plan to replace an
aging crude oil pipeline that runs
through northern Minnesota hit another
obstacle June 18 when two state agencies
said they would hold up approval of the
project’s permits until problems with its
environmental review are resolved.
The Minnesota Pollution Control
Agency and Department of Natural
Resources said that they can’t take final
action on the permits for the Line 3 project
until the independent Public Utilities
Commission addresses the deficiencies
cited in a state appeals court ruling earlier in
June, including that the project’s environ-
mental impact statement failed to address
the possibility of a spill into the Lake
Superior watershed.
That means the two state agencies won’t
release the draft permits as scheduled July
1, though they said they will continue
reviewing the applications.
Calgary, Alberta-based Enbridge said in
a statement that the PUC will have to deter-
mine how to address the court’s objections.
The commission has not yet laid out a
process or timetable for doing that.
Procedural delays and other court rulings
have pushed back the project schedule sev-
eral times.
“We believe the actions required to
address the spill modeling in the Lake
Superior watershed can be completed effi-
ciently,” the company said.
The $2.6 billion replacement pipeline
would carry Canadian crude from Alberta
across northern Minnesota to Enbridge’s
terminal in Superior, Wisconsin, which sits
near the westernmost tip of Lake Superior.
Enbridge wants to replace the current Line
3, which was built in the 1960s, because it
is increasingly subject to corrosion and
cracking, and runs at only about half its
original capacity for safety reasons.
Environmental and tribal groups fighting
the project argue that it risks oil spills in
pristine areas of the Mississippi River head-
waters region where Native Americans
gather wild rice, and that the Canadian tar
sands oil that the line would carry acceler-
ates climate change. The Court of Appeals
actually rejected most of the plaintiffs’
objections to the environmental review, but
they have until July 3 to seek further review
from the Minnesota Supreme Court.
Other appeals are also pending, includ-
ing one from the state Commerce
Department, which has challenged the
PUC’s approval of the project, saying
Enbridge didn’t provide legally adequate
demand forecasts to establish the need for
the project. The PUC and Enbridge say the
company did.
Jobs for Minnesotans, a coalition found-
ed by business and labor groups, called on
the PUC and other agencies “to work expe-
ditiously through the final steps of the
review process and move the Line 3
Replacement Project forward to con-
struction.” l
The $2.6 billion replacementpipeline would carry Canadian
crude from Alberta acrossnorthern Minnesota to Enbridge’sterminal in Superior, Wisconsin,which sits near the westernmost
tip of Lake Superior.
l F I N A N C E & E C O N O M Y
Majors commit tocarbon pricing atVatican summit
By NICOLE WINFIELD & FRANK JORDANSAssociated Press
Some of the world’s major oil producers
pledged June 14 to support “economi-
cally meaningful” carbon pricing regimes
after a personal appeal from Pope Francis to
avoid “perpetrating a brutal act of injustice”
against the poor and future generations.
The companies, including ExxonMobil,
BP, Royal Dutch Shell, Total, Chevron and
Eni, said in a joint statement at the end of a
Vatican climate summit that governments
should set such pricing regimes at a level
that encourages business and investment,
while “minimizing the costs to vulnerable
communities and supporting economic
growth.”
The CEOs, as well as leaders of major
asset managers such as BlackRock and
BNP Paribas, also called for companies to
provide investors with clarity about the
risks climate change poses to their business-
es and how they plan to transition to cleaner
energy sources.
Closed-door summitThe joint statement was issued at the end
of a closed-door summit in the Vatican gar-
dens, the second time the Holy See has con-
vened the world’s petroleum leaders for pri-
vate talks on climate change, scientific
research and the moral imperative to save
God’s creation.
Francis attended the June 14 session and
told the gathering that a “radical energy
transition” to clean, low-carbon power
sources was needed and that if managed
well, would “generate new jobs, reduce
inequality and improve the quality of life
for those affected by climate change.”
“Faced with a climate emergency, we
must take action accordingly, in order to
avoid perpetrating a brutal act of injustice
toward the poor and future generations,” he
said.
He praised the executives in particular
for taking on the core issue of carbon pric-
ing, which he said was necessary for
humanity to use the resources of creation
wisely and not burden the poor and future
generations with the debt incurred by the
rich.
Joint statementIn their joint statement, the CEOs said
“Reliable and economically meaningful
carbon pricing regimes, whether based on
tax, trading mechanisms or other market-
based measures, should be set by govern-
ments at a level that incentivizes business
practices ... while minimizing the costs to
vulnerable communities and supporting
economic growth.”
The pledge comes ahead of an upcoming
European Union summit at which leaders
will discuss the bloc’s efforts to combat cli-
mate change including a proposal to stop
adding carbon to the atmosphere by 2050.
While the announcement refers to the 2015
Paris accord’s goal of “keeping global
warming below 2 degrees Celsius (3.6
Fahrenheit)” by the end of the century com-
pared to pre-industrial times, experts say
capping the rise at 1.5 degrees Celsius
(2.7F) would be safer.
The Carbon Tracker Initiative, a
London-based group that examines the
impact the shift away from fossil fuels has
on financial markets, welcomed the Vatican
announcement.
“It is important that many of the world’s
largest publicly traded oil and gas compa-
nies and many of the world’s largest
investors have endorsed carbon pricing
regimes,” the group’s executive director,
Mark Campanale, said in a statement.
“Critically, asset owners with trillions of
dollars under management are also calling
for company disclosures of meaningful and
material information on plans and invest-
8 PETROLEUM NEWS • WEEK OF JUNE 23, 2019
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Better.
EXPLORATION & PRODUCTIONUS drilling rig count down by 6 to 969
The number of rigs drilling for oil and natural gas in the U.S. was down by six
the week ending June 14 to 969.
A year ago, the count was 1,059 active rigs.
Houston oilfield services company Baker Hughes reported that 788 rigs target-
ed oil (down one from the previous week) and 181 targeted natural gas (down
five).
The company said 68 of the U.S. holes were directional, 852 were horizontal
and 49 were vertical.
Louisiana was up by two rigs from the previous week.
The rig counts for a number of states were unchanged from the previous week:
California, Colorado, New Mexico, North Dakota, Ohio, Oklahoma,
Pennsylvania, Utah and West Virginia.
Alaska and Wyoming were each down by one rig.
Texas, with the largest number of active rigs in the country, 467, was down by
six rigs from the previous week.
Baker Hughes shows Alaska with five rigs, compared to seven a year ago.
The U.S. rig count peaked at 4,530 in 1981. It bottomed out in May 2016 at
404.
In figures published June 7, Baker Hughes said the average U.S. rig count for
May was 986, down 26 from an average of 1,012 in April, and down 60 from
1,046 rigs counted in May 2018.
The international rig count, excluding the U.S. and Canada, averaged 1,126 in
May (886 land and 240 offshore rigs), up 64 from an April average of 1,062 and
up 159 from the May 2018 average of 967.
—KRISTEN NELSON
see CARBON PRICING page 10
PETROLEUM NEWS • WEEK OF JUNE 23, 2019 9
Forging A Path Forward in the Nanushuk
Resource Development Council @alaskardc
Growing Alaska Through Responsible Resource DevelopmentRESOURCE DEVELOPMENT COUNCIL
44th Annual Membership Luncheon
elcoming RWnor MicervGo
skemarelcoming Rvyhael J. Dunleanor Mic
Joe Balash, Assis
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, Lands anyy,aretant SecrtJoe Balash, Assis
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By STEVE SUTHERLINPetroleum News
Perth, Australia-based Corescan’s
hyperspectral core imaging system
integrates reflectance spectroscopy, visual
imagery and 3-D laser profiling to map the
mineralogy and geochemistry of drill core,
rock chips and other geological samples,
according to the company. The proprietary
designed in-house system offers ultra-high
spectral and spatial resolution.
Dr. Brigette Martini, Corescan chief
geologist, presented May 31 at a technical
breakout session at the state Geological
Materials Center in Anchorage. The session
focused on the potential for new investiga-
tive technologies and machine learning sys-
tems to better assist geoscientists and
resource companies to meet the challenges
of interpreting Alaska geology.
“We have very extensive surface cover-
age, but no penetration into the core itself,”
Martini said.
“The mineralogy and the log that we
give you, we call it semi-quantitative; it is
not whole rock — it is surface, but it’s a lot
of surface.”
Every pixel has a single spectral signa-
ture.
“Every one of those 200,000 pixels has a
spectrum that we then interpret based on
our own internal software; we use USGS
libraries that are highly validated,” Martini
said. “From that we’ve introduced these
beautiful surface maps, so we show you
spatially where all of your mineralogy is.”
Why hyperspectral?“I’m going to really encourage everyone
in oil and gas in particular to pivot a bit here
— we love our nanoscale, really fine reso-
lution,” Martini said. “I encourage you to be
thinking about how we take fine nanoscale
type information, and we can use this type
of continuous mineralogy, that is, a micron
scale to help scale up a lot of our smaller
limited interval-type measurements.
“There are minerals and there are types
of minerals that you can do with infrared
better than you can in other types of tech-
nologies, some of the main ones I always
like to point out is the hydrated silicas,
amorphous silicas, opal, calcinite, those
actually have beautiful spectral signatures,”
she said, adding, “It can be very difficult to
impossible to do in other types of tech-
niques.
“One of the technical integration spe-
cialists that works with a lot of our clients
calls Corescan a lifestyle; it’s not just a sin-
gle instrument, but it’s the logging, it’s the
building of the instrumentation, it’s the
bringing them in to facilities, but it’s also
very importantly the interpretation,”
Martini said. “We are not asking you to
interpret this data, we do all of that.
“What you get when you scan with
Corescan is all the images and the full min-
eral map as well as drive lithology” she
said. “It’s the interpretation of it, then fol-
lowed on by the visualization of it, within
either your own software or with
coreshed.com which is how we serve up
our data.”
High resolution“The important number that you can see
is our spectral resolution is about 3.5
nanometers, that’s how wide our bands are
and that’s really important if you’re trying
to do compositional data and do identifica-
tion of very fine scale mineralogy and com-
positional mineralogy,” Martini said.
“We’re doing digital photography at 50
microns, we’re doing the hyperspectral at
500 microns, and we do run a laser profiler
over the tops of the core to do technical
work — fracture orientations, joint spacing,
et cetera. Those three are all happening at
the same time.
“Currently the vertical resolution is 20
microns vertical, so that’s going to help a lot
with very fine formational boundaries and
structure.” she said. “Depending on what
we’re doing we do scan slower than the
other system on the market. We’re only
doing about 500 meters per day.”
The system is mobile, in containers for
easy transport, and to keep spectrometers
clean, dry and at a constant temperature.
“We do not touch the core unless it needs
l E X P L O R A T I O N & P R O D U C T I O N
Hyperspectral surface scan of coreEvery pixel has single spectral signature indicating mineralization; system offers ultra-high spectral and spatial resolution
Dr. Brigette Martini, Corescan chief geologist
STEV
E SU
THER
LIN
see CORE IMAGING page 11
ments in the energy transition,” he added.
Outside the summit, around half-a-
dozen protesters held up signs urging the oil
executives to listen to the pope.
The meeting was held under unusual
secrecy even by Vatican standards, with the
program and guest list initially unpublished.
A few executives confirmed their presence
ahead of time, including the chief execu-
tives of BP and Eni, Bob Dudley and
Claudio Descalzi.
On the BP blog, Dudley wrote that the
meeting was coming at an urgent time, with
BP’s own latest survey showing carbon
emissions grew by 2% last year, even as
experts say they have to dramatically
decrease to meet standards set by the 2015
Paris climate accord.
Eni’s Descalzi said in a statement that
four years after Paris, “it’s clear we have to
change pace. Progress has been insufficient
and the emissions continue to grow.” l
10 PETROLEUM NEWS • WEEK OF JUNE 23, 2019
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continued from page 8
CARBON PRICING
and none of that acreage is producing oil
or gas.
Although the 13 leases being pulled
from the unit are past their primary term,
the division said they will be extended
an additional 90 days from the contrac-
tion date. (Stay tuned, as this might give
Caelus time to sell those leases to Eni or
another company, so an announcement
might already be in the wind.)
A 30% working interest owner in the
North Slope unit, Eni announced the
deal to acquire Caelus’ 70% interest in
Oooguruk in January. Obviously, that
purchase did not include tracts in which
Eni did not have any ownership.
The division said an application to
assign all working interest in the unit to
ENI is pending with the agency.
This unit contraction approval “does
not relieve Caelus from its obligations
under the individual leases, including to
remove all machinery, equipment, tools
and materials, and to deliver up the
leased area in good condition,” the
agency said, further noting acreage in
the contraction area will be governed
by non-unitized lease language and reg-
ulation.
The division in its approval letter to
Caelus also said the Oooguruk unit’s
automatic 10-year contraction “has been
delayed as a result of Caelus’s request
dated Oct. 12, 2017,” which was not
available on the agency’s website in time
to be included in this report.
POD extended for OoogurukThe contraction approval for
Oooguruk followed a June 4 decision
from the division to extend the unit’s
12th plan of development from Sept. 1,
2019, through Feb. 29, 2020.
During the 12th POD Caelus said it
would maintain production from
Oooguruk. Three rig workovers were
planned to replace electric submersible
pumps with gas lift completions and do
wellbore repairs. Those activities were
conducted as planned, the division said.
And because Caelus is in the process
of divesting its interest in the unit and
subsequently relinquishing operator
responsibilities, the company has not
proposed future work. Instead, Caelus
requested and was granted an extension
of the existing approved 12th POD so
the future operator, in this case Eni, can
develop its own plans for the 13th POD.
That POD will be due Dec. 1, the
division said.
—KAY CASHMAN
RDC’s annual luncheon June 26
OIL SEARCH’S TOP EXECUTIVE in
Alaska, Keiran Wulff, and Joe Balash,
assistant secretary of Land and
Minerals Management at the U.S.
Department of the Interior, are the
keynote speakers at the Resource
Development Council’s annual lunch-
eon in Anchorage on June 26.
The event will open with remarks
from Alaska Gov. Mike Dunleavy.
The event will be held at the
Dena’ina Center and doors will open at
11:15 a.m. The program begins at 12
noon and ends by 1:15 p.m.
To make reservations check out
RDC’s website at
https://www.akrdc.org/annual-member-
ship-luncheon.
—KAY CASHMAN
obtaining increased market access” that
have stalled regulatory approvals for major
pipelines, notably Enbridge’s Northern
Gateway to Prince Rupert on the northern
British Columbia coast and TC Energy’s
proposed Energy East pipeline to the
Atlantic coast in New Brunswick.
Overall capital spending in Canada’s oil
and natural gas industry is expected to
slump to C$37 billion in 2019 from C$81
billion in 2014.
Although the report said Canadian oil
output will reach 5.36 million barrels per
day by 2035, up 1.27 million bpd from cur-
rent levels, that amounts to an annual
increase of only 1.4%, less than half the out-
put of 7.5 million bpd from Western Canada
in 2030 that CAPP projected in its 2014 out-
look.
CAPP said global demand for crude oil
is anticipated to reach 106.3 million bpd in
2040, a gain of 12%, led by consumption
and refinery demand in the Asia-Pacific
region.
But Canada will be “left on the side-
lines,” despite its role as a leading supplier
of “the most responsibly produced oil and
natural gas on the planet. But our lack of
pipelines and inefficient regulatory reality
means that other suppliers, with lesser envi-
ronmental and social standards are taking
our market share,” the report said.
If those challenges are not met and the
industry is denied the chance to recapture
more than C$40 billion of investment,
Canada’s gross domestic product, business
investment, exports, jobs and tax revenues
will all suffer, CAPP said.
Minimal rewrite of C-69On the same day the report was released,
federal Environment Minister Catherine
McKenna said the government of Prime
Minister Justin Trudeau would accept only
62 of 229 Senate recommendations to
rewrite some of Bill C-69, which opens the
door to a sweeping overhaul of Canada’s
regulatory approval process for major
resource projects, while modifying another
37 recommendations.
The effect was to give a distinctly cold
shoulder to all amendments urged by indus-
try groups such as CAPP and the Canadian
Energy Pipeline Association.
By moving ahead with Bill C-69 the
Trudeau government has put itself on a col-
lision course with nine of Canada’s 10 pre-
miers, leaving British Columbia Premier
John Horgan as its only ally.
Industry stepping backRich Kruger, CEO of Imperial Oil
(owned 69.6% by ExxonMobil), said that if
the bill is passed “it will unfortunately cause
us to step back and deeply consider all
future major growth opportunities.”
He said there is no balance in the legis-
lation and “the proof will come over time,
when parties quit investing.”
Birchcliff Energy CEO Jeff Tonken said
Bill C-69 would block access to coastal
tanker terminals “and that will then stop any
growth in Canada.”
CAPP President Tim McMillan said
McKenna’s claims that the opposition
Conservative Party, led by Andrew Scheer,
wants to “pursue economic development at
all costs and put the interests of oil lobbyists
ahead of the interests of Canadians” is proof
that she wants to “profile our industry as if
we are not responsible.”
Backing the industry, six premiers
(including Bob McLeod of the Northwest
Territories) sent a letter telling Trudeau that
he should accept all amendments to Bill C-
69 or risk national unity by driving away
jobs and investment.
The premiers also urged Trudeau to
scrap Bill C-48, which would ban oil
tankers from loading at northern British
Columbia ports.
Trudeau fired back by suggesting it was
the premiers who were “threatening our
national unity” to which Kenney said the
premiers signed their letter “in the best tra-
ditions of cooperative federalism ... this dis-
missive response from the federal govern-
ment is the real threat to the national econ-
omy and to national unity.”
—GARY PARK
continued from page 1
INSIDERcontinued from page 1
REGULATORY CHANGES
Catch thesefall savings
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 N A T U R A L G A S
Vol. 23, No. 37 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of September 16, 2018 • $2.50
page2
Newfield looking at Alaska;Begich, Dunleavy weigh in;L48 shale boom tapering off TEXAS-BASED INDEPENDENT
NEWFIELD EXPLORATION has people visit-
ing Alaska to look at the North Slope’s geo-
logic potential.
Headquartered in The Woodlands, Texas,
the visiting scientists are not handing out busi-
ness cards to everyone they meet, so the visit
is very hush-hush.
Per the big independent’s website,
Newfield is an oil company focused on profitably growing liq-
uids-rich unconventional resource plays in the Anadarko and
Arkoma basins of Oklahoma, the Williston basin (Bakken) of
State looks for RIK gas interest;includes Prudhoe, Point ThomsonThe Alaska Department of Natural Resources, Division of Oil
and Gas, is soliciting interest in potential royalty in-kind naturalgas from the Prudhoe Bay and Point Thomson units.
The solicitation, dated Aug. 31, asks for expressions of interestby letter within 30 days.
DNR said it is considering whether to take the state’s royaltyon future natural gas production from Prudhoe Bay and PointThomson in value or in kind.
“If DNR takes the royalty in kind, it is currently considering anoncompetitive contract,” solicitation says. The department saidthat to consider a noncompetitive contract it “first considerswhether there is a lack of competition and whether a noncompet-
GAO questions lack of preliminarydesign review for polar icebreakersThe U.S. Government Accountability Office has issued a
report raising questions over the reliability of the estimatedcost and schedule for developing new heavy polar icebreakersfor the U.S. Coast Guard. The Department of HomelandSecurity, the agency that includes the Coast Guard, hasaccepted the GAO’s findings.
Currently the Coast Guard only operates two polar capableicebreakers: the Healy, a medium duty icebreaker, much usedas a base for polar research, and the Polar Star, which is aheavy-duty icebreaker but is 41 years old. A third icebreaker,the Polar Sea, sister ship to the Polar Star, is laid up in port andhas become a source of spare parts for the Polar Star.
Colville barges diesel to SlopeTransportation company Colville has transported 2 million
gallons of diesel fuel by barge to Prudhoe Bay on the NorthSlope, the company has announced. This was the first bulkdelivery of fuel to the Slope by barge since the 1990s, andpossibly the largest shipment of its type ever, the companysaid. The supply barge, owned and operated by CrowleyMarine, arrived at Deadhorse on Sept. 6. Because of the shal-low water depths, the barge had to be moored 3 miles off-shore, with the fuel being carried to shore in smaller vessels.Onshore, the fuel was pumped into tanker trucks for transferto Colville’s tank farm in Deadhorse.
The U.S. Coast Guard and BP oversaw the operation, saidDave Pfeifer, Colville president and chief executive officer.
More typically, fuel for use on the North Slope is deliveredto Deadhorse from a refinery in Valdez, using tanker trucks
see INSIDER page 10
see GAS INTEREST page 8
see POLAR ICEBREAKERS page 8
see DIESEL DELIVERY page 7
EIA: Brent averaged $73/barrel inAugust; US crude 10.9 million bpd
Pt Thomson extensionState stays 2019 date in 2012 settlement on Alaska LNG project progress
By KRISTEN NELSONPetroleum News
The state has stayed a deadline in its 2012 set-
tlement with Point Thomson operator
ExxonMobil Production Co.
The settlement required a plan for expansion of
Point Thomson production by the end of 2019 if a
major gas sale hadn’t been sanctioned by June
2016. Late last year the state and ExxonMobil
reached agreement on the company’s expansion
plan. The settlement required either increasing
production to 30,000 barrels per day of condensate
(the current facilities support 10,000 bpd, although
that rate has rarely been achieved) or moving nat-
ural gas to Prudhoe Bay for injection there (requir-
ing an agreement with the Prudhoe Bay working
interest owners and construction of a gas pipeline
between the fields).
Moving natural gas to Prudhoe was
ExxonMobil’s choice.
That work has now been deferred.
An optimistic outlookConocoPhillips ups GMT-2 forecast; moves ahead on Willow, further explorationBy ALAN BAILEY
Petroleum News
In a highly upbeat presentation to a
joint meeting of the Alaska House and
Senate Resources committees on Sept.
10, Scott Jepsen, ConocoPhillips Alaskavice president of external affairs and
transportation, overviewed his compa-
ny’s current exploration and develop-
ment plans in Alaska, and the resulting
major uptick in the company’s expectations for its
future Alaska oil production.
Increased production estimateJepsen said that his company has upped the esti-
mated peak production for its Greater
Mooses Tooth 2 development in the
northeastern National
Petroleum
Reserve-Alaska from 30,000 barrels of
oil per day to 38,000 bpd. The federal
Bureau of Land Management has pub-
lished a final environmental impact state-
ment for the project, with a record of
decision anticipated in October. That
could lead to a final investment decision
for the project later this year, Jepsen said.
Meanwhile the Greater Mooses Tooth 1 devel-
opment is moving ahead, with first oil anticipated
by the end of the year. Peak production is expected
to run at about 30,000 bpd.
Trudeau treads carefullyAdministration examining options to salvage Trans Mountain, including an appeal
By GARY PARKFor Petroleum News
T he future of large-scale resource
projects in Canada depends heavily
on how his government responds to a
federal court ruling that has stalled
progress on the Trans Mountain pipeline
expansion, said Prime Minister Justin
Trudeau.
“What we need is not just this
pipeline. We need to be able to build resource proj-
ects of all different types with appropriate social
license,” he told reporters.
He said the objective is to ensure that Trans
Mountain and other projects do not get “bogged”
down in endless court battles.
Trudeau, firing back at his critics,
noted that TransCanada’s Keystone XL
project was long ago approved in
Canada, but has become entangled in the
United States over a failure to engage in
detailed consultations with communities
along the pipeline right of way.
“This is the way that the world is
going and if we can demonstrate clarity
and certainty for businesses through the
process to the investors we will be able
to get more built,” he said.
Decision impacts communitiesTrudeau called the court decision on Trans
Mountain “frustrating and devastating” for com-
see POINT THOMSON page 12
see CONOCO OUTLOOK page 11
see TRANS MOUNTAIN page 9
Also Sept. 10, the Alaska GaslineDevelopment Corp. announced thatExxonMobil and AGDC had agreed towhat the corporation called “certain keyterms including price and a volume basisfor a Gas Sales Agreement,” captured ina “Gas Sales Precedent Agreement”
signed Sept. 10.
SCOTT JEPSEN
JUSTIN TRUDEAU
A limited offer from Petroleum News!
First time subscribersmention this ad to receive 15% off.
CONTACT
Renee Garbutt [email protected]
reducing local diesel consumption and
energy prices,” U.S. Sen. Lisa
Murkowski, R-Alaska, said in a June 5
statement. “Igiugig’s efforts are blazing a
trail for marine renewable energy and
microgrid solutions around the world —
when we prove these technologies can
work in rural Alaska, we are proving they
can work just about anywhere else on the
planet,” she said.
Igiugig Village Corp. is the first tribal
entity in the United States to achieve this
approval. Igiugig and Ocean Renewable
Power Co., based in Maine, have been
collaborating on the project since 2009,
she said.
The first-of-its-kind RivGen Power
System is scheduled to be installed this
summer, once permits are approved by
the Alaska Department of Fish and Game,
Alaska Department of Natural Resources
and the Alaska Lake and Peninsula
Borough.
Kvichak RiverFERC said the 70-kilowatt hydroki-
netic project will be installed on the
Kvichak River near the outlet of Iliamna
Lake and the village of Igiugig in south-
west Alaska. The village is on the east
bank of the river at the lake outlet, FERC
said, and the project will be installed
some 100 feet from the west bank “in a
deep and high velocity area of the chan-
nel.”
The Igiugig Project consists of “an in-
stream, 35-kW, approximately 52-foot-
long, 12-foot-high, 47-foot-wide pon-
toon-mounted RivGen Power System
Turbine Generator Unit” which will be
installed in Phase I of the project. An
additional 35-kW unit will be installed in
Phase 2 of the project.
Each will have an anchoring system
consisting of a 6,600-pound anchor,
chain, shackles and 200 feet of mooring
to keep the unit in place. The TGU will be
connected to a junction box on an island
east of the deployment site by a 375-foot-
long, coated and weighted combined
power, data and environmental monitor-
ing underwater cable. Another 675-foot
underwater cable will connect the TGU in
Phase 2 to the same junction box, which
will connect to a shore station on the east
bank of the river via a 710-foot-long
buried bundle of six power, data and envi-
ronmental monitoring cables.
The pre-fabricated shore station, 10-
foot by 8-foot, will house project elec-
tronics and controls, as well as other
facilities required for interconnection to
the local grid.
Two phasesInstallation will be in two phases,
FERC said, with one TGU and accompa-
nying anchor and cabling equipment
installed in each phase. “Anchors and
moorings will be installed on the riverbed
prior to deployment of the TGU device
and remain in place throughout the dura-
tion of the project,” the agency said, with
the TGU pushed into place with non-spe-
cialized watercraft and attached to the
anchor lines.
“Following deployment of the TGU
and attachment to the anchor lines, inter-
nal ballast tanks in the TGU pontoons
will be flooded sequentially. As the tanks
are filled, the TGU will settle to the river
bottom where it will stay during opera-
tion.”
FERC said the installation process for
each TGU will take two to four weeks,
with Phase 2 installed after a full year of
Phase 1 operation, in 2020, assuming
Phase 1 is installed this year.
“The TGUs will be retrieved and
inspected on an annual basis,” FERC
said, “but this interval may be extended
once it is determined that all critical sys-
tems are operating appropriately.”
FERC requires the licensee to begin
Phase 1 construction within two years of
issuance of the license and complete
Phase 2 construction within five years
from the license issuance.
Igiugig Village plans to use the pro-
ject’s power to offset diesel generation.
FERC said Igiugig requested a 10-year
license so it could have enough time to
obtain operational data to develop a sub-
sequent license application before the
first license expires.
Fish monitoringThe Kvichak River “supports abun-
dant populations of resident and anadro-
mous fish, including runs of sockeye
salmon that provide regionally important
recreational, commercial, and subsis-
tence fisheries,” FERC said. “The
Kvichak River and other Bristol Bay
river systems produce the greatest num-
ber of sockeye salmon in the world, with
recent annual averages of about 38 mil-
lion adults, 21 percent of which originat-
ed from the Kvichak River system.”
Igiugig Village has a fish monitoring
plan which includes installation of
underwater cameras as part of Phase 1 of
the project. The plan requires that proj-
ect personnel be on-site at all times
while the turbine is deployed during the
sockeye smolt peak migration. In a May
14 letter, Igiugig Village said “a fish
biologist would be on-site during the
peak migration period for sockeye
salmon (May 21 to June 10, 2020) and
would have real-time video monitoring
capability” from the underwater cam-
eras.
FERC said the environmental assess-
ment for the project found that negative
interactions between outmigrating
smolts and the TGUs are unlikely
because previous video monitoring of
project operation found no negative
interactions; most smolt would be able
to swim over or around the TGUs and “if
smolts were to swim through the
devices, the likelihood of injury or mor-
tality due to blade strike is low.”
Igiugig Village will be able to moni-
tor interactions in real time and could
shut down the project within an hour of
observing harm to smolts. Corrective
actions could be developed in consulta-
tion with resource agencies, such as tim-
ing restrictions to protect smolts, FERC
said.
—KRISTEN NELSON
PETROLEUM NEWS • WEEK OF JUNE 23, 2019 11
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to be slightly cleaned; we do not pull the
core out of the box, the box moves back
and forth on the scan table, the scan head
stays stationary,” she said.
Corescan processes data on site and
is capable of analyzing data on site “if
that needs to happen,” Martini said. It
takes between 7 minutes and 12 min-
utes per box for scanning.
“We can scan anything; we’re in the
process of scanning a lot of oils, so
long as they’re viscous enough,” she
said.
“We can also scan liquids, but dom-
inantly we’re scanning a lot of core —
whole core, slab, hand samples, and of
course, cuttings — the vastly ignored
resource of not just oil and gas but min-
ing as well,” Martini said. “Cuttings
are wonderful; they’re quick to scan,
they’re cheap and you get a lot of min-
eralogical information.”
Corescan has, in a study with the
U.S. Geological Survey, made scans of
the Inigok No. 1 well, the Ikpikpuk No.
1 well, and the Phoenix No. 1 well,
each penetrating the Shublik formation
on the western North Slope. Martini
displayed those results to illustrate
capabilities of the technology.
Infrared spectroscopy is very good at
identifying carbonates, she said.
“It’s not just calcites, dolomites, but I
can also tell you spiderite or anchorite or
rhodocrocite, you see all the different
types of carbonates listed off here and it’s
all based off of a combination of that
absorption feature ... which is due to a
carbonate molecule, as well as some
other features that show up, particularly
in the visible when you start getting iron
coming onto the system.
“You could say, ‘I’m a geologist; I can
tell the difference between calcite and
dolomite when I’m looking at core,’” she
said. “But we can do it very rapidly and
non-destructively — no acid bottles.
“Shublik is kind of most dominantly
all calcites, there is some dolomite in it
but it is ... very dominantly calcite,” she
said. “We see with the red colors (in the
display) it’s more strongly calcite, and
with yellow, it’s still calcite — a little bit
less, probably mixing with other things.
We can also do things like grain size;
right now this is relative grain size.
“We do this based off some simple cal-
culations looking at the absorption fea-
ture, the shape of it and the depth of it.”
“In the Kingak shale we have kaolin-
ite, and so not only are we telling you,
you have kaolinite, but we’re showing
you exactly how it’s distributed spatially,
which could be really important, particu-
larly looking at biological indicators, et
cetera,” she said.
Martini said Corescan’s
coreshed.com holds data that can be
combined with a client’s data to more
finely understand scan results.
“Coreshed.com doesn’t have just
Corescan data in it; we pull in people’s
huge historic photo collections all the
time. We can also do some really sim-
ple enhancement of old core photos to
help bring out really cool information,”
she said. l
continued from page 9
CORE IMAGING
Contact Steve Sutherlin at [email protected]
continued from page 1
PROJECT LICENSEFERC said the environmental
assessment for the project foundthat negative interactions betweenoutmigrating smolts and the TGUs
are unlikely …
PETROLEUM NEWS • WEEK OF JUNE 23, 2019 13
Oil Patch Bits
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Nations were pledging to take their cases to court and
some extremists were threatening civil disobedience to
block pipeline construction.
Kenney stance mutedLittle wonder that Alberta Premier Jason Kenney was
among those taking a muted stance.
“This isn’t a victory to celebrate. It is just another step
in a process that has, frankly taken too long,” he told
reporters.
“We’ll measure success not by today’s decision, but by
the beginning of actual construction and, more important-
ly, by completion of the pipeline.”
Calgary Mayor Naheed Nenshi echoed Kenney’s
doubts, noting that Alberta needs “more than one level of
market access” for its crude bitumen, urging Trudeau to
set aside Bill C-69, which is seen as adding more layers
to regulatory approvals for major resource projects, and
Bill C-48, which will ban oil tankers from operating off
the northern B.C. coast.
For the Trans Mountain Expansion, TMX, there is a
degree of comfort in knowing that the Canadian govern-
ment is owner of the existing 300,000 bpd Trans
Mountain system, acquired 10 months ago by the
Trudeau administration for C$4.5 billion, and the planned
590,000 bpd addition, which carries a C$9.3 billion
spending estimate (made two years ago).
At the time his government nationalized Trans
Mountain, Trudeau boldly declared that TMX “will be
built.”
Along with the reapproval, he again went out on a
limb, predicting work will resume this summer, targeting
first shipments in 2022, a promise that is backed by evi-
dence.
Pipe sections stockpiledThe government-owned Trans Mountain Corp., creat-
ed to operate the 65-year-old pipeline and lead the expan-
sion work, has already moved hundreds of pipeline sec-
tions by rail to growing stockpiles at work sites along the
pipeline route.
Kenney turned up the heat, telling Trudeau that
“approval is not construction. So let’s get it built.”
In a bid to win over unimpressed environmentalists,
Trudeau said all profits from TMX — which he estimated
at C$500 million a year — will be spent on clean energy,
which some observers noted means the federal govern-
ment will use fossil fuel revenues to bring about the
industry’s demise.
Trudeau also insisted that getting Alberta crude bitu-
men to the Vancouver tanker port will allow Canada to
gain access to lucrative markets in Asia and end its days
as “prisoners to the American market.”
B.C. focus on regulationsBritish Columbia Premier John Horgan said his gov-
ernment will continue its attempt to get the Supreme
Court of Canada to review his proposed legislation to
restrict the flow of bitumen into B.C. on environmental
grounds, though he conceded the decision is “within fed-
eral authority.”
He said B.C. will now turn its attention to ensuring
regulations are in place to protect the Pacific Coast from
a tanker spill.
B.C. Environment Minister George Heyman said there
are gaps in the C$1.5 billion federal marine response
plan, mainly involving spill preparedness and response
capacity for local governments and First Nations.
However, Richard Johnston, Canada Research Chair
at the University of B.C., said Horgan is now “into a kind
of symbolic phase. What else can he do? It’s clear he
can’t engage in permitting actions whose obvious attempt
is to destroy the pipelines. The courts have made that
clear.”
In the meantime, recent polls show a steady shift of
B.C. public opinion in favor of TMX, with an online poll
by Ipsos finding 60% backing for the pipeline, with 29%
opposed and 11% undecided, compared with 41% sup-
port in 2016, 34% opposed and 25% undecided. Other
polling by Angus Reid and Insights West point to similar
trends.
TMC and Alberta oil producers can now turn their
attention to seeking the necessary permits to build the
pipeline and expanded tanker terminal and what some
view as an even greater challenge — ensuring that Asian
buyers of the unrefined bitumen are still as interested as
they were when the application was filed with regulators
six years ago. l
continued from page 1
TMX APPROVALThe government-owned Trans Mountain Corp.,created to operate the 65-year-old pipeline and
lead the expansion work, has already movedhundreds of pipeline sections by rail to
growing stockpiles at work sites along thepipeline route.
14 PETROLEUM NEWS • WEEK OF JUNE 23, 2019
229-6000
Division’s decisionThe North Trading Bay unit has three state oil and
gas leases and contains two platforms, Spurr and
Spark, both built in 1967 by Marathon Oil Co.
Production from the unit ceased in September 2005.
Marathon made “minor efforts to restore production”
and then made plans for abandonment, Beckham said,
with a long-term conceptual abandonment plan pro-
posed in 2008. That plan was not implemented and
from 2009 through 2013 the platforms were the subject
of litigation, including the Pacific Energy Resources
Ltd. bankruptcy proceedings, in state and federal
courts.
In 2013, Hilcorp took over from Marathon as unit
operator, and Beckham said the division “determined it
was in the best interest of all parties to give the new
operator an opportunity to review the unit and potential
resources.”
But in 2017 the division “began giving Hilcorp writ-
ten notice as part of the POD approval that the unit may
terminate without operations to restore production.”
PlatformsThe Spurr and Spark platforms are in “lighthouse”
mode and while cranes and helidecks are functional the
crew facilities are not and there are no active wells,
Beckham said.
In its 2017 POD Hilcorp said it wouldn’t be eco-
nomic or technically feasible to return either of the
platforms to production and said it had no plans to do
so, he said, but in both its 2017 and 2018 PODs,
Hilcorp proposed a sidetrack from the Monopod in the
Trading Bay unit in an attempt to restore NTB unit pro-
duction. Beckham said the division approved those
PODs “and concluded that Hilcorp had proposed dili-
gent operations to restore production. But this well was
not drilled and no other operations were conducted dur-
ing those years,” he said.
Under state regulations if a unit isn’t producing it
automatically terminates unless the operator is “active-
ly conducting diligent operations to restore produc-
tion,” Beckham said, adding that the regulation does
not consider promises of future work — the work must
be “in progress.”
He said the notice of automatic termination is effec-
tive with the May 30 date of the decision.
2019 PODThe 2019 POD, denied because the unit has been
terminated, again proposed a well from the adjacent
Trading Bay unit. “However,” Beckham said, “this
well will not enter the productive interval within the
NTBU. The potential accumulation is within a lease
adjacent to the NTBU that Hilcorp recently acquired in
the May 9, 2018 lease sale and is not part of the unit.”
He said Hilcorp has said it hopes that if the well is
successful the accumulation under the adjacent lease
would reach into the North Trading Bay unit.
“Hopes about the extent of the potential accumula-
tion are not enough to consider this activity outside the
unit to be diligent operations to restore the unit to pro-
duction,” Beckham said.
There is a 20-day appeal period to the decision.
Hilcorp’s appealHilcorp appealed the decision to DNR
Commissioner Corri Feige on June 18.
The company said it disputes the division’s findings
that previous PODs “proposed diligent operations to
restore production, but Hilcorp did not conduct the
operations,” and that, “the 2019 POD does not propose
operations for the NTBU.”
The company called the division’s decision “prema-
ture.”
It cited the division’s approval of the 2018 POD
which it said “deemed Hilcorp’s intent to return the
NTBU to production by delineation of the North
Trading Bay Field (NTBF) and expansion of the NTBU
as diligent operations.”
(Approval of the 2018 POD, a decision signed by
Beckham for then-Division Director Chantal Walsh,
said: “Hilcorp’s planned well from the Monopod plat-
form is a reasonable step to returning the NTBU to pro-
duction.”)
Extension issueIn its 2018 POD, as revised, Hilcorp described the
well it proposed as a sidetrack to the A-10 well, and
said: “If successful, Hilcorp will apply for unit expan-
sion of the North Trading Bay Unit to include the
newly producing acreage.”
In its approval of the 2018 POD the division noted
that Hilcorp had proposed a sidetrack from the
Monopod into the NTBU in its 2017 POD, but that well
was not drilled. A well was proposed in the 2018 POD
and the division said the “sidetrack will target the
Tyonek G and Hemlock sands, reservoirs that formerly
produced inside the NTBU and may extend outside the
current unit boundary.”
In its appeal Hilcorp said its 2019 POD proposed a
potential target in ADL 18776, “which is a NTBU unit-
ized lease,” and said that while its “proposed opera-
tions fall outside of the NTBU boundary, they are con-
sistent with those requirements of the NTBU
Agreement.”
A portion of ADL 18776 is within the unit boundary;
the well would be drilled to a target east of the existing
unit boundary.
Hilcorp said it has continued to acquire acreage out-
side the North Trading Bay unit boundaries “in con-
junction with its plans to expand the NTBU.”
The company said it proposed the A-04 well in its
2017 POD and substituted the A-10RD sidetrack “to
maximize ultimate recovery,” and said delays in
drilling that well “are necessary in conducting opera-
tions as a prudent operator.”
“Hilcorp’s 2019 POD proposed operations require
expansion of the current unit boundary, similar to the
approved 2018 POD proposed operations,” the compa-
ny said.
Hilcorp said its 2018 POD covers July 1, 2018,
through June 30, 2019. It began work on the sidetrack
under the 2018 POD, the company said, because it was
necessary to “decomplete” the A-10 well before side-
tracking. Those operations began in late April this year,
prior to expiration of the 2018 POD, the company said.
As for the well location, Hilcorp said it filed a per-
mit to drill with the Alaska Oil and Gas Conservation
Commission on May 14, with the bottomhole of the A-
10RD on ADL 18776. That lease, the company said,
accounts for 28.5% of NTBU unitized acreage.
Hilcorp said that based on previous approvals from
the division the company internally approved the proj-
ect and set aside $15 million for the work. The compa-
ny said it has spent more than $5.7 million to date, $2.2
million in October of 2018 when the Monopod Rig 56
was upgraded to ensure it was capable of drilling the
well, and an additional $3.5 million this spring to
decomplete and set up the A-10 well for the sidetrack
drilling operations. l
continued from page 1
UNIT TERMINATED
As a result of the Nuna No. 2 discovery well drilled
during the 2012-13 winter drilling season, former opera-
tor Pioneer Natural Resources increased its estimate of
the areal extent of and ultimate oil recovery from Nuna,
a Torok formation in the Brookian sequence, to between
75 million and 100 million barrels of oil.
A Caelus spokesman in 2017, said that Nuna could
result in production of some 25,000 barrels of oil per day
with a field life of 20-30 years.
Development, Pioneer said at the time, would include
up to two new gravel drill sites likely connected to the
existing Kuparuk River Unit Drill Site 3S.
Next several years to appraise NunaIn its June 17 announcement of the acquisition,
ConocoPhillips said it will appraise Nuna over the next
several years, with a goal of making a final investment
decision.
The transaction is subject to state regulatory approval
and has an effective date of June 14.
“This transaction represents an attractive addition to
our expanding North Slope position and will allow
ConocoPhillips to cost effectively develop Nuna utiliz-
ing Kuparuk River unit infrastructure,” said Joe
Marushack, president of ConocoPhillips Alaska. “We
believe this acquisition could lead to more oil produc-
tion, more revenue for the state and more jobs for
Alaskans.”
—KAY CASHMAN
continued from page 1
NUNA PROSPECTA Caelus spokesman in 2017, said that Nuna
could result in production of some 25,000barrels of oil per day with a field life of 20-30
years.
PETROLEUM NEWS • WEEK OF JUNE 23, 2019 15
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Congress because of its hydrocarbon-rich
geology.
The Marsh Creek 3-D survey was ini-
tially expected to begin during the winter
season of 2018-19 and finish the follow-
ing winter.
SAE, Arctic Slope Regional Corp. and
Kaktovik Inupiat Corp. through SAE’s
joint venture with Kuukpik Corp.,
Kuukpik-SAE, formed Inupiat
Geophysical.
The 35-day federal government shut-
down between 2018 and 2019 necessitat-
ed a change in dates in the permit; now the
seismic is expected to be acquired this
coming winter.
Although there is no substitute for seis-
mic, CGG Canada Services told the U.S.
Department of Interior that it intends to fly
over the 1002 area to collect geophysical
data, per a June 19 Reuters report by
Yereth Rosen. CGG uses gravity gradiom-
etry technology, which “measures minute
changes of surface gravitational qualities
to use as clues to subsurface structures.”
The company does not need any feder-
al authorizations, an Interior official told
Rosen.
“SAE still has a seismic permit pend-
ing and continues to work with USFWS.
As I understand their plans, they would
like to have a permit in hand prior to the
lease sale (expected to be held near the
end of the year). Of course, there is no
way to conduct the seismic program ahead
of the sale unless we delay it for nearly a
year,” Balash told Petroleum News in a
June 19 email. “What Yereth is referring
to is an effort to get at least some informa-
tion out ahead of the sale — it would be
better than nothing, but not the kind of
information one would get from seismic.”
To date, only one well has been drilled
in the ANWR 1002 area — the onshore
KIC well, drilled in 1985 and 1986 by
operator Chevron and partner BP from
surface land owned by Kaktovik Inupiat,
the Native village corporation for
Kaktovik, and into the subsurface oil and
gas mineral rights owned by Arctic Slope
Regional, the Native regional corporation
for northern Alaska — both SAE partners
in the seismic survey.
Barrow Arch 3-D Marine Seismic The massive nearshore Barrow Arch 3-
D Marine Seismic Survey was recently
“cancelled and postponed by the applicant”
TGS-NOPEC Geophysical Co., a DNR
official said June 17.
Per the original permit application,
ocean-bottom node vessel operations/logis-
tics and data acquisition will be managed
and operated by SAE.
The two-year Barrow Arch survey in the
Beaufort Sea would cover 905 square miles,
with about 620 square miles in federal
waters and 285 square miles in state waters.
It extends from eastern Harrison Bay, off-
shore the Colville River Delta, eastward to
about four miles east of Oliktok Point,
encompassing an area of high hydrocarbon
potential.
SAE Staines 3-DThe land and marine seismic survey
known as the SAE Staines 3-D that abuts
the ANWR 1002 area is “still pending,”
Hastings said.
The primary state permit was issued on
Dec. 31 by the Division of Oil and Gas to
run for five months to no later than May 31.
SAE postponed the survey until next winter.
The area to be surveyed is 673 square
miles along the west side of the Staines
River on the eastern North Slope.
The permit is limited to state acreage.
BPXA Greater Prudhoe BayThe 455-square-mile BPXA Greater
Prudhoe Bay 3-D Seismic Survey was
completed this year, per Hastings.
BP Exploration Alaska is setting the
stage to comb the area for smaller oil
pools it can target with advanced drilling
techniques over the next decade or so,
with an eye on adding new production
from the 42-year-old field.
The key to the effort is the massive 3-
D seismic survey conducted by SAE that
BP’s top executive in Alaska Janet Weiss
describes as the largest 3-D survey ever
done at Prudhoe.
SAE Kuukpik 3-D One-third of the SAE Kuukpik 3-D
seismic survey was completed this past
winter and the rest will be finished next
winter, Hastings said.
The 490-square-mile survey is on the
east side of the Colville River, extending
south from the Horseshoe No. 1 well
where Armstrong Energy discovered oil
in the Nanushuk formation in 2017.
The leases involved are held by Oil
Search, Repsol, ConocoPhillips,
Pantheon, Great Bear and SAE.
In a March press release area explorer
88 Energy mentioned “a multi-client 3-D
seismic acquisition” planned in the same
vicinity.
SAE Gas Hydrate VSP Kuukpik-SAE finished the Gas
Hydrate Vertical Seismic Profile survey
this year, Hastings said.
The 11-square-miles program was
around the new methane hydrate well that
was completed in January in the western
part of the Prudhoe Bay unit.
See the March 17 Petroleum News
article, “Partnership plans methane
hydrate testing” for additional informa-
tion. l
continued from page 1
SEISMIC SURGE
7
STA
TE O
F A
LASK
A
16 PETROLEUM NEWS • WEEK OF JUNE 23, 2019
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