FINANCE & ECONOMY Ida’s effect muted
Transcript of FINANCE & ECONOMY Ida’s effect muted
July ANS volumes down 15%; driven by Alpine work, TAPS maintenance
page
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l F I N A N C E & E C O N O M Y
l G O V E R N M E N T
Vol. 26, No. 36 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of September 5, 2021 • $2.50
l E X P L O R A T I O N & P R O D U C T I O N
see SCOPING PERIOD page 7
After Louisiana court injunction BOEM resumes inlet sale work
As a consequence of an injunction in the federal District Court
for the Western District of Louisiana, the Bureau of Ocean
Energy Management is continuing its preparations for an oil and
gas lease sale in federal waters of the lower Cook Inlet, originally
scheduled to be held in 2021. On Jan. 13 of this year the agency
published a draft environmental impact statement for the lease
sale, with a public comment period for the EIS scheduled to run
from Jan. 16 to March 1. However, on Feb. 4, in response to an
executive order by President Biden pausing federal oil and gas
leasing, the agency cancelled the public comment period, thus
postponing the lease sale indefinitely.
see LINE 3 page 11
Hilcorp plans greenfield well at Ivan River on west side of inlet
Hilcorp Alaska is planning to drill a new well at the Ivan River
gas field in the fourth quarter, the first new well at that field in
more than 10 years.
The Alaska Division of Oil and Gas said in an Aug. 25
approval of an amendment to the company’s 2021 plan of devel-
opment for the Ivan River unit that the company originally pro-
posed to do no grassroots drilling at the field during the 2021
POD.
Hilcorp told the division it had identified sufficient gas
reserves in the Sterling and Beluga formations to support drilling
of a grassroots well and plans to drill the IRU 241-01 well in the
fourth quarter of this year to target the identified reserves.
Ivan River is an onshore west side Cook Inlet gas field. The
see IVAN RIVER page 11
see INLET SALE page 12
BLM schedules EIS public meetings; seeks ANWR lease sales comments
The Bureau of Land Management has scheduled meetings
to gather public comments for the scoping of the supplemental
environmental impact statement for the Arctic National
Wildlife Refuge coastal plain oil and gas lease sale program.
The meetings, which will be conducted remotely over Zoom,
will take place on Sept. 14, 15 and 16. On each of these days
there will be two sessions, one from 1 p.m. to 3:30 p.m. and
the second from 6 p.m. to 8:30 p.m. Information about the
meetings is available on the BLM.gov website.
The meetings form part of a 60-day public scoping period
for the SEIS, which is being developed following a June 1 sec-
retarial order, placing a hold on the oil and gas leasing pro-
gram in the coastal plain. The purpose of gathering public
Ida’s effect muted GOM hurricane price impact dulled by delta, end of summer driving season
By STEVE SUTHERLIN Petroleum News
A laska North Slope crude inched lower by 11
cents Sept. 1, to close at $71.35 per barrel,
while West Texas Intermediate gained 9 cents to close
at $$68.59 and Brent dropped by $1.40 to close at
$71.59.
For ANS and Brent, it was the seventh consecu-
tive close above $70 following a plunge into the mid-
$60 range in mid-August and choppy trading all
month long. WTI traded in the high $60s over the
week ending Sept. 1, following its own plunge into
the lower $60s.
The price stability was remarkable given the coun-
tervailing factors pulling on the market, including a
devastating hurricane in the Gulf of Mexico, a pro-
duction adjustment meeting of the Organization of
the Petroleum Exporting Counties and its allies,
ongoing demand fears due to new variants of
COVID-19, the first full FDA approval for a COVID-
19 vaccine, strong inventory draws on U.S oil and
gasoline stockpiles and ongoing negotiations
between the United States and Iran which might
affect sanctions on Iranian oil exports.
Committed to Willow ConocoPhillips obeys court decision; remains dedicated to core Alaska biz
By KAY CASHMAN Petroleum News
The federal District Court in Alaska
recently upheld appeals challenging
the validity of the environmental impact
statement and the associated polar bear
biological opinion for ConocoPhillips
Alaska’s Willow oil field development in
the northeastern National Petroleum
Reserve-Alaska. The result is that
ConocoPhillips will not be able to start any on-the-
ground work to develop the field until the Bureau
of Land Management has reworked and approved
the EIS, and the Fish and Wildlife Service has
reworked the associated biological opinion.
ConocoPhillips had hoped to start gravel work
and road construction for the project in
February of this year.
But the company has not given up on
Willow, which at last estimate will yield
some 586 million barrels of oil over its
30-year field life.
The field will produce oil from the
Nanushuk formation in the Bear Tooth
unit, west of the Greater Mooses Tooth
unit, where oil is already being produced
by the company. Oil production at
Willow is projected at 160,000 barrels per day,
with the field having production capacity of
200,000 bpd.
Field development will involve the construction
Promises … or puffery? Hopes of positive debate on energy during Canada’s election campaign dashed
By GARY PARK For Petroleum News
Canada is in the midst of a federal
election campaign, which gives
many candidates another chance to trash
the petroleum industry.
That means the governing Liberals
led by Prime Minister Justin Trudeau and
the New Democrats, Greens and Bloc
Quebecois, can embark on a free-for-all
of pinning all or most of the blame for climate
change on oil and natural gas producers.
Trudeau is seeking his third term in power by
calling a snap election at the halfway point of his
current mandate, claiming he needs early
approval to steer Canada through
COVID-19 and prepare the country for
an economic recovery.
But analysts are increasingly of the
view that he will do no better than repeat
his minority success in 2019, which
means he will continue to need the back-
ing of the minority parties to pass legisla-
tion in the House of Commons.
The Conservative party under Erin
O’Toole has made surprising gains in the latest
polls, indicating Trudeau’s grand plan could be
frustrated.
see OIL PRICES page 7
see WILLOW DECISION page 11
see ENERGY DEBATE page 9
Line 3 posts court victories: Minn. delivers setbacks to opponents
Enbridge has added two more legal vic-
tories to its battle for final approval of the
Line 3 crude oil pipeline.
The Calgary-based company is now
within sight of starting shipments within
four months of 760,000 barrels per day of
oil sands bitumen from Alberta to its refin-
ing terminal in Wisconsin.
The Minnesota Supreme Court refused
to hear an appeal from opponents of the
pipeline, closely followed on Aug. 30 by
the state’s Court of Appeals which affirmed a decision by the
Minnesota Pollution Control Agency, MPCA, to issue a water
SONYA SAVAGE
OPEC+ will proceed with its scheduled 400,000 bpd oil production increase
in October.
EREC ISAACSON
JUSTIN TRUDEAU
2 PETROLEUM NEWS • WEEK OF SEPTEMBER 5, 2021
Trusted upstream coverage >> www.petroleumnews.com
Petroleum News Alaska’s source for oil and gas news
Ida’s effect muted GOM price impact dulled by delta, end of summer driving season
Committed to Willow Conoco obeys court decision; remains dedicated to core Alaska biz
Promises … or puffery? Hopes of positive debate on energy during Canada’s election dashed
ON THE COVER
BLM schedules EIS public meetings; seeks ANWR lease sales comments
After Louisiana court injunction BOEM resumes inlet sale workLine 3 posts court victories: Minn. delivers setbacks to opponentsHilcorp plans greenfield well at Ivan River on west side of inlet
4 July ANS volumes down 15% at 409,720 bpd
EXPLORATION & PRODUCTION
6 Hilcorp applies to Corps to expand L Pad
6 US rotary rig count gains 5, now at 508
GOVERNMENT
7 RCA wants more info on pipeline transfer
Gardes purchase of North Fork field includes Anchor Point Energy, holder of certificate of convenience and necessity for pipeline
PIPELINES & DOWNSTREAM
5 CD-4 pad expansion project advances
State of Alaska opens 30-day comment period on ConocoPhillips project;19 new wells to access Narwhal, Qannik oil in the Nanushuk
2 State gauging interest in its royalty oil
Division of Oil & Gas has non-binding informal solicitation out for ANS royalty-in-kind oil; responses due by end of September
contents
l G O V E R N M E N T
State gauging interest in its royalty oil Division of Oil & Gas has non-binding informal solicitation out for ANS royalty-in-kind oil; responses due by end of September
By KRISTEN NELSON Petroleum News
The Alaska Division of Oil and Gas has published a
non-binding solicitation of interest to gauge whether
commercial refiners or other parties would like to acquire
some of the state’s North Slope royalty-in-kind, RIK, oil.
Division Director Tom Stokes said in the Aug. 26 solic-
itation that the state’s current RIK contracts end in the third
and fourth quarters of 2022.
The state has received inquiries from potential buyers
for multiyear RIK contracts, and state statutes require com-
petitive bid sales for the state’s royalty oil except in cases
when the Department of Natural Resources commissioner
“determines that the best interest of the state does not
require competitive bidding or that no competition exists.”
“If there is substantial interest expressed by more than
one potential buyer for RIK oil, DNR may issue an
Invitation to Bid and conduct a sealed-bid auction for the
RIK oil consequently,” the solicitation says.
Written responses are due Sept. 30.
(See state’s Aug. 26 solicitation of interest in PDF ver-
sion of this issue of Petroleum News online at
www.PetroleumNews.com.)
Multiyear RIK sales agreements require a review by the
Alaska Royalty Oil and Gas Development Advisory Board
and approval by the state Legislature.
The contract will supply RIK oil for at lease three years,
the solicitation said.
One-year contracts In May DNR published a final best interest finding and
determination for the sale of ANS RIK oil to Marathon
Petroleum Supply and Trading Co. for a negotiated one-
year contract for a portion of the state’s ANS RIK oil.
While multiyear contracts require board review and leg-
islative approval, contracts designed to relieve market con-
ditions are not required to go through that process if they are
for one year or less.
The one-year Marathon contract covered between
10,000 and 15,000 barrels per day between Aug. 1, 2021,
and July 31, 2022.
In approving the one-year contract DNR Commissioner
Corri Feige said the standard approval process takes time,
“and here, could means months without royalty oil being
delivered to the Nikiski refinery.”
The May finding said the state has a long history of sell-
ing North Slope RIK to the Marathon refinery, having sup-
plied ANS crude to that facility between July 1980 and
January 1982, between January 1983 and December 1998
and since February 2014.
The state also asked for expressions of interest from
companies interested in bidding on the state’s ANS RIK
crude oil last September.
At that time the state had a five-year contract with
Tesoro Refining and Marketing Co. which began in 2016
(Tesoro changed its name to Andeavor in 2017 and merged
with Marathon Petroleum in 2018) and a four-year contract
with Petro Star Inc. which began in 2017, although the
state’s Petro Star contract began with a one-year contract
effective Jan. 1, 2017.
From November 1979 through December 2020 the state
disposed of 965 million barrels of oil through RIK sales,
approximately 45% of its North Slope royalty oil.
There are five refineries in the state, with three produc-
ing refined petroleum products (Marathon’s Kenai refinery,
Petro Star’s North Pole refinery and Petro Star’s Valdez
refinery) and small topping plants on the North Slope oper-
ated by Hilcorp and ConocoPhillips. l
SIDEBAR, PAGE 4: Cook Inlet gas down 4.7%
Rig Owner/Rig Type Rig No. Rig Location/Activity Operator or Status Alaska Rig Status
North Slope - Onshore
All American Oilfield LLC IDECO H-37 AAO 111 Deadhorse, Stacked in Cruz Yard Available Doyon Drilling Dreco 1250 UE 14 (SCR/TD) Standby Hilcorp Alaska LLC Dreco 1000 UE 16 (SCR/TD) Standby Dreco D2000 Uebd 19 (SCR/TD) Standby AC Mobile 25 Alpine, MT7-06 ConocoPhillips OIME 2000 141 (SCR/TD) Standby 142 (SCR/TD) Standby TSM 700 Arctic Fox #1 Standby ERD 26 Alpine, CD2-310 ConocoPhillips Hilcorp Alaska LLC Rotary Drilling Innovation Milne Point, S Pad Hilcorp Alaska LLC Nabors Alaska Drilling AC Coil Hybrid CDR-2 (CTD) Milne Point, Cold Stacked Available AC Coil CDR-3 (CTD) Kuparuk, Cold Stacked at 12 Acre Pad ConocoPhillips Ideco 900 3 (SCR/TD) Deadhorse, Stacked Available Dreco 1000 UE 7-ES (SCR-TD) Kuparuk, Startup ConocoPhillips Mid-Continental U36A 3-S Stacked Available Oilwell 700 E 4-ES (SCR) Stacked Available Dreco 1000 UE 9-ES (SCR/TD) Stacked Available Oilwell 2000 Hercules 14-E (SCR) Deadhorse Available Oilwell 2000 Hercules 16-E (SCR/TD) Stacked Brooks Range Petroleum Emsco Electro-hoist Oilwell 2000 Canrig 1050E 27-E (SCR-TD) Stacked Available Oilwell 2000 33-E Deadhorse Available Academy AC Electric CANRIG 99AC (AC-TD) Stacked Available OIME 2000 245-E (SCR-ACTD) 12 Acre Pad, stacked Available Academy AC electric CANRIG 105AC (AC-TD) Stacked Available Academy AC electric Heli-Rig 106AC (AC-TD) Stacked Available Nordic Calista Services Superior 700 UE 1 (SCR/CTD) Deadhorse Available Superior 700 UE 2 (SCR/CTD/TD) Deadhorse, stacked Available Ideco 900 3 (SCR/TD) Deadhorse, stacked Available Rig Master 1500AC 4 (AC/TD) Oliktok Point ENI Parker Drilling Arctic Operating LLC NOV ADS-10SD 272 Deadhorse, Stacked Available NOV ADS-10SD 273 Deadhorse, Stacked Available
North Slope - Offshore
Doyon Drilling Sky top Brewster NE-12 15 (SCR/TD) Spy Island, S102-SE6 ENI Nabors Alaska Drilling OIME 1000 19AC (AC-TD) Oooguruk, Stacked ENI
Cook Inlet Basin – Onshore BlueCrest Alaska Operating LLC Land Rig BlueCrest Rig #1 Stacked BlueCrest Alaska Operating LLC Glacier Oil & Gas Rig 37 West McArthur River Unit Workover Glacier Oil & Gas Hilcorp Alaska LLC TSM-850 147 Stacked Hilcorp Alaska LLC TSM-850 169 Seaview Hilcorp Alaska LLC
Cook Inlet Basin – Offshore Hilcorp Alaska LLC National 110 C (TD) Platform C, Stacked Hilcorp Alaska LLC Rig 51 Steelhead Platform, Stacked Hilcorp Alaska LLC Rig 56 Monopod A-13, stacked Hilcorp Alaska LLC Nordic Calista Services Land Rig 36 (TD) Kenai, stacked Available Spartan Drilling Baker Marine ILC-Skidoff, jack-up Spartan 151, Tyonek Platform Hilcorp Alaska LLC Furie Operating Alaska Randolf Yost jack-up Nikiski, OSK dock Available Glacier Oil & Gas National 1320 35 Osprey Platform, activated Glacier Oil & Gas
Alaska-Mackenzie Rig ReportThe Alaska-Mackenzie Rig Report as of September 1, 2021.
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. 27 Aug. 20 Year Ago United States 508 503 254 Canada 147 156 54 Gulf of Mexico 14 14 13
Highest/Lowest US/Highest 4530 December 1981 US/Lowest 244 August 2020 *Issued by Baker Hughes since 1944
The Alaska-Mackenzie Rig Report is sponsored by:
JUDY
PAT
RICK
Mackenzie Rig Status
Canadian Beaufort Sea SDC Drilling Inc. SSDC CANMAR Island Rig #2 SDC Set down at Roland Bay Available
PETROLEUM NEWS • WEEK OF SEPTEMBER 5, 2021 3
By KRISTEN NELSON Petroleum News
A laska North Slope production saw a
major month-over-month drop in
July largely driven by a major field turn-
around at Alpine and a maintenance shut-
down on the trans-Alaska oil pipeline.
ANS production averaged 409,720
barrels per day in July, down 71,802 bpd,
14.9%, from a June average of 481,522
bpd and down 15% from a July 2020
average of 482,029 bpd. Crude volumes
were 370,903 bpd, 90.5% of the total,
down 60,337 bpd, 14%, from a June vol-
ume of 431,240 bpd and down 14.3%
from a July 2020 volume of 432,764 bpd
and 38,817 bpd of natural gas liquids,
9.5% of total volume, down 11,464 bpd,
22.8%, from a June average of 50,282
bpd and down 21.2% from a July 2020
average of 49,265 bpd.
Production was down from all North
Slope fields except Eni’s Nikaitchuq,
with the largest month-over-month
decreases on the western side of the
Slope.
Turnaround, maintenance shutdown There was a 26-day turnaround at
ConocoPhillips Alaska’s Colville River
unit which began July 9 and ended Aug.
3, affecting the Alpine and Greater
Mooses’ Tooth fields.
In an Aug. 26 email, ConocoPhillips
Alaska spokeswoman Rebecca Boys said:
“The Alpine Turnaround was very suc-
cessful from a scope completion, duration
and safety perspective.”
Work accomplished during the turn-
around included:
•Completion of the Alpine gas expan-
sion (with turbine, compressor, gas cool-
ing and gas dehydration upgrades).
•Completion of Alpine slug-catcher
critical tie-ins.
•Completion of Alpine power expan-
sion critical tie-ins (with switchgear and
fuel gas system upgrades) and
•Completion of final GMT2 tie-ins.
Impacting production Slope-wide was
the 30-hour turnaround July 17-18 of the
trans-Alaska oil pipeline by Alyeska
Pipeline Service Co.
It was the first major maintenance
shutdown of the line since August 2019,
Alyeska said, and the only long-duration
shutdown scheduled for the year (see
story in July 25 issue of Petroleum
News). Two short-duration shutdowns, 12
hours or less, were scheduled for August.
Work during Alyeska’s maintenance
shutdown included:
•Replacement of piping previous used
to inject drag reducing agent at Pump
Station 1 and replacing it with 48-inch
straight piping.
•Installation of new actuators on Pump
Station 1’s two large oil tanks.
•Installation of 87 feet of 48-inch pip-
ing between two valves at Pump Station
7.
•Systemwide upgrading of the safety
integrity pressure protection system and
•Various value work, testing and
cabling repairs.
Colville, Greater Mooses Tooth The largest ANS percentage reduc-
tions were at ConocoPhillips Alaska’s
western North Slope operations, the
Colville River unit and at Greater Mooses
Tooth, with production down following
the July 9 shutdown.
Colville River production averaged
10,651 bpd in July, down 75.7%, 33,174
bpd, from a June average of 43,825 bpd
and down 78.5% from a July 2020 aver-
age of 49,429 bpd.
Production data come from the Alaska
Oil and Gas Conservation Commission
which reports production by field and
well on a month delay basis.
In addition to oil from the main Alpine
pool, Colville production includes satel-
lite production from Nanuq and Qannik.
Crude from Greater Mooses Tooth in
the National Petroleum Reserve-Alaska is
processed at Alpine facilities, and aver-
aged 675 bpd in July, down 1,826 bpd,
73%, from a June average of 2,501 bpd
and down 68% from a July 2020 average
of 2,110 bpd.
Prudhoe Bay, Kuparuk The Hilcorp North Slope-operated
Prudhoe Bay field, the Slope’s largest,
averaged 226,412 bpd in July, down
11.9%, 30,703 bpd, from a June average
of 257,115 bpd and down 9.5% from a
July 2020 average of 250,038 bpd.
Crude production accounted for 84.2%
of Prudhoe output, an average of 190,735
bpd, down 20,374 bpd, 9.7%, from a June
average of 211,109 bpd and down 7%
from a July 2020 average of 205,181 bpd.
Prudhoe NGL production averaged
35,677 bpd, 15.8% of the field’s output,
down 10,330 bpd, 22.5%, from a June
average of 46,007 bpd and down 20.5%
from a July 2020 average of 44,857 bpd.
In addition to the primary reservoir,
production volumes from Prudhoe
include Aurora, Borealis, Lisburne,
Midnight Sun, Niakuk, Polaris, Point
McIntyre, Put River, Raven and Schrader
Bluff.
The ConocoPhillips Alaska-operated
Kuparuk River field, the second largest
Slope field, averaged 89,170 bpd in July,
down 1,737 bpd, 1.9%, from a June aver-
age of 90,907 bpd and down 6.2% from a
l E X P L O R A T I O N & P R O D U C T I O N
July ANS volumes down 15% at 409,720 bpd Decline driven by 26-day turnaround at Alpine beginning July 9 and July 17-18 maintenance shutdown of trans-Alaska oil pipeline
4 PETROLEUM NEWS • WEEK OF SEPTEMBER 5, 2021
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Cook Inlet gas down 4.7% Natural gas production from Cook Inlet averaged 198,599 thousand cubic feet
in July, down 9,846 mcf per day, 4.7%, from a June average of 208,445 mcf per
day and down 0.2% from a July 2020 average of 198,905 mcf per day.
This data is from the Alaska Oil and Gas Conservation Commission, which
reports production on a month-delay basis. For natural gas AOGCC reports meas-
urements in thousands of cubic feet, mcf.
The inlet’s nine largest fields account for the majority of natural gas produc-
tion, 86.5% in July compared to 79% in July 2020.
Hilcorp Alaska’s Kenai field averaged 33,131 mcf per day in July, down 3,899
mcf per day, 10.5%, from a June average of 37,030 mcf per day and up 2.2% from
a July 2020 average of 32,414 mcf per day.
Hilcorp’s Ninilchik field averaged 30,483 mcf per day in July, up 350 mcf per
day, 1.2%, from a June average of 30,133 mcf per day and down 4.2% from a July
2020 average of 31,833 mcf per day.
Hilcorp’s McArthur River averaged 21,481 mcf per day in July, down 1,723
mcf per day, 7.4%, from a June average of 23,204 mcf per day and down 11.8%
from a July 2020 average of 24,353 mcf per day.
The Hilcorp-operated Beluga River field averaged 19,724 mcf per day in July,
down 861 mcf per day, 4.2%, from a June average of 20,584 mcf per day and up
21.3% from a July 2020 average of 16,262 mcf per day.
Hilcorp’s Swanson River averaged 19,231 mcf per day in July, up 129 mcf per
day, 0.7%, from a June average of 19,102 mcf per day and down 22.5% from a
July 2020 average of 24,797 mcf per day.
Hilcorp’s North Cook Inlet averaged 19,071 mcf per day, up 4,242 mcf per day,
28.6%, from a June average of 14,828 mcf per day and up 25.1% from a July 2020
average of 15,249 mcf per day.
Furie’s Kitchen Lights averaged 11,488 mcf per day in July, down 3,144 mcf
per day, 21.5%, from a June average of 14,631 mcf per day and down 9.4% from
a July 2020 average of 12,678 mcf per day.
Hilcorp’s Beaver Creek averaged 8,711 mcf per day in July, down 1,547 mcf
see ANS VOLUMES page 8
see INLET GAS page 8
By KAY CASHMAN Petroleum News
O n Aug. 30, Alaska’s Division of Oil
and Gas opened the 30-day public
comment period on ConocoPhillips
Alaska’s July 23 request for approval of
an amendment to the Colville River unit
plan of operations to move forward with
the expansion of Colville Delta No. 4
pad.
The company proposes to place
55,000 cubic yards of clean gravel fill and
3,400 cy of erosion protection onto 5.1
acres of jurisdictional wetlands and 0.4
acres of non-jurisdictional uplands to
expand the north, south and east sides of
the existing CD-4 pad.
Supporting infrastructure includes 19
new wells, a pipe rack extension, valve
shelters, conductors, mouseholes, ther-
mosyphons, vertical support members, a
new remote electrical instrumentation
module, fuel gas conditioning skid, light-
ing, on-pad trenching for cable installa-
tion, and temporary offices, envirovacs
and break shacks. No new permanent
buildings are anticipated.
Approximately half the wells will be
producers and half injectors.
Upon completion, the larger pad will
have the potential for a total of 63 wells.
The purpose of the expansion project
is to access the Narwhal and Qannik
resources, both in the Nanushuk forma-
tion.
The project is expected to start on Jan.
1 and continue until all wells are drilled
in about 2035, but construction of sup-
porting ice features will actually start
around Nov. 1 and finish at the end of
January.
The infrastructure will be utilized until
the end of field life, ConocoPhillips said.
Gravel, roads, VSMs Gravel placement will occur over one
winter season, with gravel transported
from a commercial gravel source to CD-4
using typical Maxi-Haul end-dumps.
No fill will be placed during the
migratory bird nesting window of June 1
through July 31.
The permitted Western North Slope
Resupply Ice Road will be used to sup-
port the project. Other ice, if required,
will be permitted with the North Slope
Borough separately.
Access to the project area and support
for gravel placement will also be via
existing Alpine gravel roads. No new per-
manent roads are anticipated at this time.
The existing airstrip at CD-1 will be
used to support this project. No new
airstrips are anticipated at this time.
Gravel sources being considered for
use include the ASRC Mine Site and
Kuparuk Mine Site C.
VSMs will be installed as needed to
support various project components.
Sizes and method will vary.
Trenching will be done as needed at
various places on the existing pad and
expansion area to install power and com-
munications.
Project location, land use, water The project area is within the North
Slope Borough Resource Development
District, the surface land is owed by the
Kuukpik Corp. and the mineral rights are
owned by the state of Alaska, specifically
ADL384211, which is leased to
ConocoPhillips.
The project area has been examined in
part by previous cultural resource efforts
during surveys for proposed exploration
drilling and development projects.
ConocoPhillips said it has reviewed
the database of Traditional Land Use
Inventory, or TLUI, Alaska Heritage
Resource Survey site, Native allotments,
and cabins used for subsistence purposes
and there are no known sites within 500
feet of the CD-4 pad expansion area.
The company said it believes there
would be no impact to cultural resources
for the project and it will apply for a
Certificate of TLUI Clearance.
All activities will be conducted in
accordance with federal, state and local
regulations, permit stipulations and gen-
eral concurrence stipulations as appropri-
ate, ConocoPhillips said.
All water sources are or will be per-
mitted with the Alaska Department of
Natural Resources’ Division of Water.
Sources that may support this project
include, but are not limited to, the
Colville River and its channels, ASRC
Mine Site gravel pits, Lakes M9603,
M9607, B8530, M9608, M9606, L9327,
B8531/L9326, M9934, L9325, L9324
and L9323.
Dismantling, removal, restoration At end of field life, ConocoPhillips
must fully dismantle, remove and restore
all temporary and permanent improve-
ments approved by the plan of operations
unless the state of Alaska determines, at
the time of rehabilitation, that different
rehabilitation measures are necessary to
deliver up the land in good order and con-
dition.
A little history ConocoPhillips’ 2018 exploration pro-
gram included a pair of exploration wells
just south of the Colville River unit, near
the village of Nuiqsut.
The play has a long and circular histo-
ry with several names.
ConocoPhillips first asked the state to
expand the Colville River unit to include
acreage to the south in 2002. The
prospect was known at the time as
Titania. The state agreed to the Titania
expansion but in 2004 contracted the
acreage out of the unit after
ConocoPhillips failed to meet its drilling
commitments.
A joint venture operated by Brooks
Range Petroleum Corp. acquired the
acreage through a lease sale and began
referring to the leases as the Tofkat
prospect. The small independent encoun-
tered hydrocarbons on the leases in early
2008 with the Tofkat No. 1 well and two
related sidetracks and in 2011 formed the
Tofkat unit.
The state terminated the unit in late
March 2016, after the company missed
work commitments. The termination pro-
ceedings came as ConocoPhillips was
acquiring the acreage. ConocoPhillips
asked the state to incorporate it into the
Colville River unit.
The state was hesitant to approve the
expansion, but eventually agreed to the
request, pursuant to bonds, guarantees
and conditions.
Under this newest effort,
ConocoPhillips began referring to the
project as Putu. To meet the initial set of
conditions required by the state,
ConocoPhillips drilled the Putu No. 2 and
Putu No. 2A wells and made a $3 million
bonus bid replacement. The company
also drilled four appraisal wells — CD4-
595PH1, CD4-595, CD4-594PH1 and
PETROLEUM NEWS • WEEK OF SEPTEMBER 5, 2021 5
l E X P L O R A T I O N & P R O D U C T I O N
CD-4 pad expansion project advances State of Alaska opens 30-day comment period on ConocoPhillips project;19 new wells to access Narwhal, Qannik oil in the Nanushuk
see PAD EXPANSION page 6
The purpose of the expansion project, which is expected to start
on Jan. 1 and continue until all wells are drilled in about 2035, is to access the Narwhal and Qannik resources, both in the Nanushuk
formation.
6 PETROLEUM NEWS • WEEK OF SEPTEMBER 5, 2021
EXPLORATION & PRODUCTIONUS rotary rig count gains 5, now at 508
The Baker Hughes U.S. rotary drilling rig count was 508 the week ending Aug. 27,
up five from 503 the previous week and up by 254 from 254 a year ago.
When the count dropped to 244 in mid-August 2020 it was the lowest the domestic
rotary rig count has been since the Houston based oilfield services company began
issuing weekly U.S. numbers in 1944.
Prior to 2020, the low was 404 rigs in May 2016. The count peaked at 4,530 in
1981.
The count was in the low 790s at the beginning of 2020, where it remained through
mid-March, when it began to fall, dropping below what had been the historic low in
early May with a count of 374 and continuing to drop through the third week of
August 2020 when it gained back 10 rigs.
The Aug. 27 count includes 410 rigs targeting oil, up by five from the previous
week and up 230 from 180 a year ago, with 97 rigs targeting gas, unchanged from the
previous week and up by 25 from 72 a year ago, and one miscellaneous rig,
unchanged from the previous week and down by one from a year ago.
Twenty-five of the rigs reported Aug. 27 were drilling directional wells, 459 were
drilling horizontal wells and 21 were drilling vertical wells.
The Wyoming rig count (18) was up by two from the previous week.
New Mexico (81), Oklahoma (31) and Texas (232) each gained a single rig week-
over-week.
Counts in all other states were unchanged, week-over-week: Alaska (4), California
(6), Colorado (11), Louisiana (49), North Dakota (22), Ohio (12), Pennsylvania (19),
Utah (11) and West Virginia (9).
Baker Hughes shows Alaska with four rigs active Aug. 27, unchanged from the
previous week and up one from a year ago, when the state’s count stood at three.
The rig count in the Permian, the most active basin in the country, was up by two
from the previous week at 249 and up by 124 from a count of 125 a year ago.
—KRISTEN NELSON
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CD4-594 — beyond its work commit-
ments “to better understand the reservoir
and to test the technical feasibility of
extended reach drilling at shallow depth,”
according to the company.
The next round of commitments
required ConocoPhillips to pay $4 mil-
lion to the state and submit a plan detail-
ing efforts to bring the leases into sus-
tained production.
Based on preliminary testing of its ini-
tial Putu exploration wells, the company
announced the Narwhal discovery, esti-
mated to contain between 100 million and
350 million barrels of oil equivalent.
Willow and Narwhal are different sed-
iment deposits within the Nanushuk for-
mation, with Willow being older.
ConocoPhillips drilled a follow-up
well at Narwhal in the 2019 exploration
season. That summer, the company said
that the results were “encouraging”
enough to justify “an additional unbud-
geted horizontal well from an existing
Alpine drill site into the Narwhal trend”
later in the year. That relatively sponta-
neous decision, at least by North Slope
standards, reflects one of the big strategic
opportunities of the prospect. It is close
enough to the Colville River unit to uti-
lize existing well pads, bringing down
costs and reducing some of the most com-
mon logistical complications of off-road
winter exploration.
Asked about the additional well, a
ConocoPhillips executive said it would
be a “long-term test” to better “under-
stand the long-term deliverability.” He
added, “We also can drill an offset injec-
tion well to this producer from the same
drill site. So, we’re going to take the
opportunity to do that as well. And that
will give us further information on the
Narwhal trend. But it’s really driven by
encouragement and what we saw in the
initial well in the Narwhal, the Putu
appraisal well we call that.”
A long-term flow test conducted on the
Narwhal exploration well also “exceeded
expectations,” according to
ConocoPhillips, at a peak rate producing
4,500 barrels of oil per day. This led the
company to increase its estimated ulti-
mate recovery figure for the prospect by
150 million to 400 million barrels of oil
equivalent.
The company initially envisioned a
two-pronged strategy at the Narwhal
prospect. It would drill about half the
wells horizontally from the existing CD-4
pad in the Colville River unit and the
remaining wells from a new CD-8 pad in
the southern end of the unit.
Under that proposal, the company ini-
tially expected production as early as
2022 from the wells at the CD-4 pad and
production from the planned CD-8 pad as
early as 2025.
But by late 2020, ConocoPhillips was
rethinking its approach. The CD4-594
and CD4-595 appraisal wells had
“stretched the limits” of serviceable
extended reach drilling at shallow depths.
And so the company shifted the project
toward CD-8, which would support
between 20 and 40 wells, depending on
modeling.
All the ConocoPhillips projects at the
Colville River unit and in the NPR-A
(such as Willow) place additional respon-
sibilities on the Alpine infrastructure. In
his Meet Alaska presentation earlier this
year, ConocoPhillips Alaska President
Erec Isaacson described three projects
underway this year to expand the gas-
handling capacity and power generation
and to add a slug catcher at the Alpine
processing facility. The $190 million
projects will allow Alpine to handle addi-
tional production coming online. l
EXPLORATION & PRODUCTIONHilcorp applies to Corps to expand L Pad
Hilcorp North Slope, the Prudhoe Bay unit operator, has applied to the U.S.
Army Corps of Engineers to expand L Pad in the Western Satellite area at
Prudhoe.
Development drilling from L Pad is ongoing.
In a July proposed amendment for the Western Satellites 2021 plan of devel-
opment, Hilcorp told the Alaska Division of Oil and Gas it anticipated completing
as many as six new drill wells within the Orion participating area, as many as
three producers and one injector from L Pad and up to one producer and one injec-
tor from Z Pad.
That drilling was planned for existing pad areas.
In July, Hilcorp applied to the division “to drill up to five boreholes in tundra
adjacent to L Pad” at Prudhoe. In approving the request, an amendment of the unit
plan of operations, the division said: “Future plans for L Pad include a pad expan-
sion and new wells. The purpose of this project is to determine the exact location
of these future wells.” The division said the company anticipated starting the
borehole project Aug. 15.
The public notice of application for permit from the Corps, dated Aug. 30, said:
“The applicant’s stated purpose is to expand the L Pad to accommodate new wells
for increased production and oil retrieval.”
The proposed work would place 25,000 cubic yards of clean gravel onto 3.7
acres of wetlands, expanding the pad into an area 300 feet by 530 feet. Comments
on the proposal are due by Sept. 29.
An illustration of the work that is part of the Corps public notice shows the
expansion off the western end of the pad, with two new well rows, each beginning
on the existing pad and expanding onto the new pad surface.
—KRISTEN NELSON
continued from page 5
PAD EXPANSION Expected timeline 1. Construction of supporting ice features 11/1/2021—1/31/2022. 2. Mobilization of equipment 1/1/2022—1/31/2022. 3. Hauling gravel and construction of gravel expansion 1/15/2022—4/15/2022. 4. Demobilization of gravel installation equipment 4/15/2022—4/30/2022. 5. Final conditioning of gravel 8/1/2022—12/31/2023. 6. Install supporting infrastructure 10/1/2022—12/31/2024. 7. Commence drilling operations 10/1/2022—12/31/2035.
Despite firming near the end of the
month, oil prices fell in August. ANS closed
at $71.46 Aug. 31, down $4.52 from the
July 30 close of $75.87, a loss of 5.9%. WTI
closed at $68.59 Aug. 31, down $5.36 from
the July 30 close of $73.95, a loss of 7.2%.
Brent closed at $71.59 Aug. 31, down $4.74
from the July 30 close of $76.33, a loss of
6.2%.
Hurricane effects muted Prices rose modestly on Aug. 30, the first
trading day after the Category 4 Hurricane
Ida made landfall in Louisiana just before
noon Aug. 29. ANS gained 42 cents Aug. 30
to close at $72.05, WTI lifted 47 cents to
close at $69.21, and Brent popped 71 cents
to close at $73.41.
The hurricane boost was short lived. The
gains of ANS and WTI were relinquished
the next day, and Brent slid as well.
As of 12:30 p.m. EDT Aug. 31, an esti-
mated 94% of oil production and 94% of
natural gas production in federally adminis-
tered areas of the U.S. Gulf of Mexico
remained shut-in, according to the Bureau
of Safety and Environmental Enforcement.
The U.S. Department of Energy said in a
Sept. 1 situation report that seven refineries
in Louisiana remain shut, accounting for
about 1.7 million barrels per day of refinery
capacity, approximately 9% of total U.S.
operable refining capacity.
The refinery and offshore platform shut-
ins are not anticipated to cause immediate
supply issues, DOE said.
“For the week ending on August 20,
Gulf Coast stocks of gasoline and distillate
were 3% and 5% above the seasonal five-
year average,” DOE said, adding that Gulf
Coast stocks of crude oil were essentially in
line with the five-year average, not includ-
ing the Strategic Petroleum Reserve.
The impact of the storm on refined prod-
uct supply initially appeared to be greater
than the impact to crude supply, IHS Markit
said in a Sept. 1 release, but it expects the
impact on pump prices to be muted —
between 2 cents and 5 cents per gallon in
the upper range.
“The spread between demand and sup-
ply was not as skewed towards demand as it
would have been had there not been a resur-
gence of the Delta variant of the coron-
avirus,” said Debnil Chowdhury, IHS
Markit executive director. “This is also the
time of year where seasonal gasoline
demand peaks and starts to fall heading into
winter; as a result, outright prices are not
expected to increase much higher than what
we saw immediately after landfall.”
Most of the shuttered refineries are
expected to be back online within three
weeks, IHS Markit said. A small number of
refineries that sustained significant wind
and flood damage will be down for as much
as two months.
OPEC+ will add production OPEC+ will proceed with its scheduled
400,000 bpd oil production increase in
October.
The production boost was ratified at the
20th OPEC and non-OPEC Ministerial
Meeting, held by videoconference Sept. 1.
OPEC said that while the effects of the
COVID-19 pandemic continue to cast some
uncertainty, market fundamentals have
strengthened, and that Organization for
Economic Co-operation and Development
stocks continue to fall as the recovery accel-
erates.
It said overall conformity to production
continued from page 1
OIL PRICES
PETROLEUM NEWS • WEEK OF SEPTEMBER 5, 2021 7
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l P I P E L I N E S & D O W N S T R E A M
RCA wants more info on pipeline transfer Gardes purchase of North Fork field includes Anchor Point Energy, holder of certificate of convenience and necessity for pipeline
By KRISTEN NELSON Petroleum News
Gardes Holdings purchased the small southern Kenai
Peninsula North Fork gas field from Glacier Oil and
Gas late last year.
The field had been operated by Glacier subsidiary
Cook Inlet Energy.
The Alaska Division of Oil and Gas approved transfer
of operatorship of the North Fork unit to Gardes Holding,
and subsequently to Gardes subsidiary Vision Operating,
in May.
But approval from the Regulatory Commission of
Alaska is still in the works.
The natural gas produced at the field is moved through
the 7.4-mile North Fork Pipeline to a connection with
Enstar’s southern Kenai Peninsula line at Anchor Point.
Anchor Point Energy holds the certificate of public
convenience and necessity for the North Fork Pipeline.
Cook Inlet Energy holds controlling interest in Anchor
Point Energy, the owner of the North Fork Pipeline, and
Cook Inlet Energy and Gardes Holdings have filed jointly
for approval from RCA to transfer CIE’s controlling inter-
est in Anchor Point Energy to Gardes Holdings.
More information On Aug. 31 RCA ordered filings from the companies
on the transfer.
RCA said its regulations require copies of all pipeline
right-of-way agreements or, if ROW agreements are not
finalized, copies of the most recent ROW applications.
The commission said that Gardes and CIE did not file
a copy of the ROW agreement with their joint application
but told the commission that the ROW agreements appli-
cable to the North Fork Pipeline are the same as those
presently on file and said the ROW agreements would not
change as a result of the authorizations the companies
seek.
The commission said that in reviewing previous appli-
cations it found the last application related to the pipeline
was filed in 2014 for ROW agreement ADL 230928.
Parties to that agreement included the state of Alaska and
Anchor Point Energy, RCA said.
But, the commission said, the parties in the present
joint filing said the ROW was held in the name of Cook
Inlet Energy, and RCA said it does not have a copy of a
ROW agreement in the name of CIE in its files.
“The Joint Applicants further state that they would
work to have the right-of-way agreement transferred to
Anchor Point Energy, while maintaining that the applica-
ble right-of-way agreement would not change. We find
these statements inconsistent,” RCA said.
The commission is requiring the joint applicants to
clarify their statements about the ROW agreement and is
requiring that the applicants file a copy of the current
ROW applicable to the North Fork Pipeline and any ROW
transfer applications currently being considered by the
Department of Natural Resources.
RCA also requires the applicants to “report on the sta-
tus of any transfer application being considered by DNR
including whether DNR is requiring any form of financial
assurance as a condition of transfer.”
The filings are due by Sept. 8. l
comments is to determine the scope of issues to be
addressed and to identify any significant issues, includ-
ing any legal deficiencies, in the original EIS approval.
Approved in August 2020 The original EIS for the lease sale program was
approved in August 2020, with then Secretary of the
Interior David Bernhardt signing a record of decision on
Aug. 17 of that year, approving the ANWR coastal plain
lease sale program. Then, on Jan. 6, 2021, BLM conducted
the first ANWR lease sale, with the Alaska Industrial
Development and Export Authority, Knik Arm Services
and Regenerate Alaska, obtaining tracts. The lease sale
program resulted from legislation passed by Congress and
signed by President Donald Trump in December 2017 —
the legislation required the Department of the Interior to
conduct oil and gas lease sales for the coastal plain.
On June 1 of this year the Biden administration sus-
pended the ANWR oil and gas leases, in anticipation of
conducting a new environmental review of the leasing
program — hence the development of the SEIS, which
results from what BLM now claims are deficiencies in the
original EIS.
A hold on permitting Political news outlet Politico has reported that the
Department of the Interior has told the State of Alaska that
DOI will not process permit applications for seismic sur-
veying or related fieldwork in ANWR until the SEIS has
been completed.
AIDEA has been planning to conduct seismic surveying
in the coastal plain for its ANWR leases — on Aug. 4 the
agency issued a notice of intent to award a contract for pre-
development permitting and planning work to
SAExploration Inc., with Kaktovik Iñupiat Corp., ERC
Alaska and SALA LLC to be engaged as subcontractors.
Also according to Politico, BLM turned down an
AIDEA application for a permit to conduct cultural
resources surveys in ANWR in August. Apparently the
processing of an application by Kaktovik Iñupiat Corp. for
an ANWR seismic surveying permit has also been delayed.
At the time of going to press, neither BLM nor AIDEA
had responded to requests by Petroleum News for com-
ments on what Politico has reported.
Repeal of ANWR statutes? Another issue has arisen in conjunction with the budget
reconciliation bill being developed by the U.S. House of
Representatives — the House Natural Resources
Committee has included in the bill a section for repealing
the legislation from 2017 that opened the ANWR Coastal
Plain for oil and gas leasing. Under the proposed bill lan-
guage there would be a buyback of all ANWR leases that
have been issued. The Gwich’in Native people of northern
Alaska and Canada have expressed support for this legisla-
tion, given their strong objections to ANWR oil develop-
ment. The Gwich’in are particularly concerned about the
possible impact of oil industry activities on the Porcupine
caribou herd that calves on the coastal plain and is a pri-
mary subsistence food source for the Gwich’in.
—ALAN BAILEY
continued from page 1
SCOPING PERIOD
see OIL PRICES page 9
8 PETROLEUM NEWS • WEEK OF SEPTEMBER 5, 2021
July 2020 average of 95,018 bpd.
In addition to the main Kuparuk pool,
Kuparuk produces from satellites at
Meltwater, Tabasco and Tarn, and from
West Sak.
Smaller Slope fields Eni’s Nikaitchuq was the only North
Slope field with a month-over-month pro-
duction increase. It averaged 18,629 bpd in
July, up 1,116 bpd, 6.4%, from a June aver-
age of 17,513 bpd although down 3.5%
from a July 2020 average of 19,297 bpd.
Two fields had very small month-over-
month declines.
Badami, operated by Savant, a Glacier
Oil and Gas company, averaged 1,076 bpd
in July, down just 7 bpd, 0.7%, from a June
average of 1,084 bpd. The field was shut-in
last July.
The ExxonMobil Production-operated
Point Thomson field also had a small
month-over-month decline, averaging 9,435
bpd in July, down just 32 bpd, 0.3%, from a
June average of 9,467 bpd and up 4.1%
from a July 2020 average of 9,066 bpd.
Hilcorp’s Milne Point field averaged
34,861 bpd in July, down 2,617 bpd, 7%,
from a June average of 37,478 bpd but up
6.3% from a July 2020 average of 32,784
bpd.
Hilcorp’s Northstar averaged 6,673 bpd
in July, down 18.7%, 1,535 bpd, from a
June average of 8,207 bpd and down 28.7%
from a July 2020 average of 9,356 bpd.
Crude oil from Northstar averaged 4,031
bpd, 60.4% of the field’s production, down
748 bpd, 15.7%, from a June average of
4,779 bpd and down 30.2% from a July
2020 average of 5,775 bpd. Northstar
NGLs, 39.6% of the field’s volume, aver-
aged 2,642 bpd in July, down 786 bpd,
22.9%, from a June average of 3,428 bpd
and down 26.2% from a July 2020 average
of 3,581 bpd.
Eni’s Oooguruk averaged 6,613 bpd in
July, down 3.4%, 233 bpd, from a July aver-
age of 6,846 bpd and down 12.4% from a
July 2020 average of 7,549 bpd.
The Hilcorp-operated Endicott field
averaged 5,525 bpd in July, down 16%,
1,053 bpd, from a June average of 6,578
bpd and down 25.1% from a July 2020
average of 7,380 bpd. Endicott crude, 91%
of the field’s volume, averaged 5,026 bpd in
July, down 12.3%, 705 bpd, from a June
average of 5,731 bpd and down 23.3% from
a July 2020 average of 6,554 bpd. Endicott
NGLs, 9% of volume, averaged 499 bpd in
July, down 41.1%, 348 bpd, from a June
average of 847 bpd and down 39.7% from a
July 2020 average of 827 bpd.
Cook Inlet up 4% July oil volumes from Cook Inlet aver-
aged 9,240 bpd, up 4%, 359 bpd, from a
June average of 8,881 bpd although down
18.5% from a July 2020 average of 11,341
bpd. With the exception of a small volume
of NGLs from the Swanson River unit, 157
bpd in July, 1.7% of the inlet total, Cook
Inlet liquids are crude oil.
Hilcorp’s McArthur River field, Cook
Inlet’s largest, averaged 3,360 bpd in July,
down 91 bpd, 2.7%, from a June average of
3,452 bpd and down 9.3% from a July 2020
average of 3,707 bpd.
Hilcorp’s Granite Point averaged 2,637
bpd in July, up 36 bpd, 1.4%, from a June
average of 2,601 bpd and down 16.4% from
a July 2020 average of 3,155 bpd.
Hilcorp’s Trading Bay averaged 1,050
bpd in July, up 184 bpd, 21.2%, from a June
average of 866 bpd and down 18.4% from a
July 2020 average of 1,286 bpd.
BlueCrest’s Hansen field averaged 893
bpd in July, down 22 bpd, 2.4%, from a
June average of 915 bpd and down 9.1%
from a July 2020 average of 982 bpd.
Hilcorp’s Swanson River averaged 907
bpd in July (750 bpd of crude and 157 bpd
of NGLs), up 43 bpd, 5%, from a June aver-
age of 864 bpd and up 11% from a July
2020 average of 817 bpd.
Hilcorp’s Beaver Creek averaged 393
bpd in July, up 212 bpd, 116.8%, from a
June average of 181 bpd and up 196.5%
from a July 2020 average of 132 bpd.
ANS crude oil production peaked in
1988 at 2.1 million bpd; Cook Inlet crude
oil production peaked in 1970 at more than
227,000 bpd. l
per day, 15.1%, from a June average of
10,258 mcf per day and down 4.5%
from a July 2020 average of 9,118 mcf
per day.
Hilcorp’s Ivan River averaged 8,517
mcf per day in July, down 2,841 mcf
per day, 25%, from a June average of
11,358 mcf per day, and up 247.8%
from a July 2020 average of 2,449 mcf
per day.
AIX’s Kenai Loop averaged 4,646
mcf per day in July, up 541 mcf per
day, 13.2%, from a June average of
4,105 mcf per day and down 5.1%
from a July 2020 average of 4,895 mcf
per day.
Hilcorp’s Cannery Loop averaged
4,138 mcf per day in July, down 1,117
mcf per day, 21.3%, from a June aver-
age of 5,255 mcf per day and down
22.3% from a July 2020 average of
5,328 mcf per day.
Hilcorp’s Deep Creek averaged
3,734 mcf per day in July, down 227
mcf per day, 5.7%, from a June average
of 3,961 mcf per day and down 4.4%
from a July 2020 average of 3,906 mcf
per day.
Hilcorp’s Granite Point averaged
3,707 mcf per day in July, up 101 mcf
per day, 2.8%, from a June average of
3,605 mcf per day and down 0.9%
from a July 2020 average of 3,741 mcf
per day.
Vision Operating’s North Fork aver-
aged 3,119 mcf per day, up 92 mcf per
day, 3%, from a June average of 3,028
mcf per day and down 8.3% from a
July 2020 average of 3,403 mcf per
day.
BlueCrest’s Hansen averaged 2,723
mcf per day in July, down 248 mcf per
day, 8.4%, from a June average of
2,972 mcf per day and down 19.1%
from a July 2020 average of 3,366 mcf
per day.
Hilcorp’s Trading Bay averaged
1,976 mcf per day in July, up 224 mcf
per day, 12.8%, from a June average of
1,752 mcf per day and down 34% from
a July 2020 average of 2,995 mcf per
day.
Hilcorp’s Seaview, which came
online in June, averaged 1,085 mcf per
day in July, up 373 mcf per day, 52.5%,
from a June average of 712 mcf per
day.
Hilcorp’s Lewis River averaged 912
mcf per day in July, down 199 mcf per
day, 17.9%, from a June average of
1,111 mcf per day and down 14.5%
from a July 2020 average of 1,067 mcf
per day.
Amaroq’s Nicolai Creek averaged
383 mcf per day in July, down 28 mcf
per day, 6.8%, from a June average of
411 mcf per day and up 4.9% from a
July 2020 average of 365 mcf per day.
Hilcorp’s Nikolaevsk averaged 340
mcf per day in July, down 64 mcf per
day, 15.9%, from a June average of 404
mcf per day and down 12.2% from a
July 2020 average of 387 mcf per day.
Cook Inlet natural gas production
peaked in the mid-1990s at more than
850,000 mcf per day.
—KRISTEN NELSON
continued from page 4
ANS VOLUMEScontinued from page 4
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FIELD SERVICES
ENGINEERING SERVICES
Equipment Application Engineering
"As Built" Drawings
Equipment Skid Design/Build
Product Integration
Project Management
The inlet’s nine largest fields account for the majority of
natural gas production, 86.5% in July compared to 79% in July
2020.
PETROLEUM NEWS • WEEK OF SEPTEMBER 5, 2021 9
Oil Patch Bits
ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS
Companies involved in Alaska’s oil and gas industry
A ABR, Inc. Acuren Ahtna, Inc. Airport Equipment Rentals Alaska Dreams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .5 Alaska Frontier Constructors (AFC) . . . . . . . . . . . . . . . . . . . .8 Alaska Fuel Services Alaska Marine Lines Alaska Materials Alaska Railroad Alaska Steel Co. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4 Alaska Textiles Alaska West Express Arctic Controls ARCTOS Alaska, Division of NORTECH Armstrong ASTAC (Arctic Slope Telephone Assn. Coop, Inc) AT&T Avalon Development
B-F Bombay Deluxe Brooks Range Supply Calista Corp. ChampionX Coffman Engineers Colville Inc. Computing Alternatives CONAM Construction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11
Construction Machinery Industrial (CMI) Cook Inlet Tug & Barge Cruz Construction Denali Universal Services (DUS) Doyon Anvil Doyon Associated Doyon Drilling Doyon, Limited EEIS Consulting Engineers, Inc. EXP Energy Services F. R. Bell & Associates, Inc. Flowline Alaska Frost Engineering Service Co. – NW . . . . . . . . . . . . . . . . . . .8
G-M GCI GeoLog GMW Fire Protection Greer Tank & Welding Guess & Rudd, PC HDR Engineering, Inc. Inlet Energy Inspirations Judy Patrick Photography Little Red Services, Inc. (LRS) Lynden Air Cargo Lynden Air Freight Lynden Inc. Lynden International Lynden Logistics Lynden Transport
Maritime Helicopters . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .2 Matson
N-P Nabors Alaska Drilling NANA Worley . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12 Nature Conservancy, The NEI Fluid Technology Nordic Calista North Slope Borough North Slope Telecom Northern Air Cargo Northern Solutions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .6 Oil Search . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .3 PND Engineers, Inc. PRA (Petrotechnical Resources of Alaska) Price Gregory International . . . . . . . . . . . . . . . . . . . . . . . . . .7
Q-Z
Resource Development Council SALA Remote Medics SeaTac Marine Services Sourdough Express Strategic Action Associates Tanks-A-Lot US Ecology Alaska Weston Solutions Wolfpack Land Co. Yukon Fire Protection
All of the companies listed above advertise on a regular basis with Petroleum News
Scott Patterson earns high-level NACE certification Coffman Engineers Inc. said Aug. 31 that it is pleased to announce that
Anchorage mechanical engineer, Scott Patterson, has earned the National Association of Corrosion Engineers Senior Internal Corrosion Technologist cer-tification.
A certified senior internal corrosion technologist has a thorough under-standing of electrochemical and corrosion principles and is capable of compre-hensive assessments required to develop and manage corrosion control pro-grams and high-level internal corrosion problems in pipeline systems. Certification candidates must successfully complete the exam, NACE courses, and meet work experience and education requirements.
Patterson is a critical team member on Coffman’s industrial mechanical team. He has supported integrity management and corrosion control engineer-ing work, including developing advanced integrity management analysis tools and solutions for many major clients. Patterson has also worked on performing critical stress analysis and destructive testing of specialized downhole drilling tools.
Patterson is a 2014 graduate of the University of Vermont with dual bache-lor’s degrees in mechanical engineering and mathematics. In addition, he is a U.S. Olympic skier and a three-time U.S. National Champion. He joined Coffman as an intern in 2012. Since then, Patterson has become a prominent figure in the skiing community with the support and sponsorship of Coffman, where he continues to advance his career. SCOTT PATTERSON
While that speculation builds the socialist New
Democrats have been waging their endless campaign to
destroy the fossil fuel industry, although party leader
Jagmeet Singh has never said when or how he proposes
to achieve that end.
The party’s focus for now is on ending subsidies for
the industry which Singh said amounted to C$18 billion
in 2020, citing a report by the activist U.S.-based
Environmental Defense Fund.
Numbers A close look at his numbers show they include multi-
billion dollar green tech programs — the underpinning
of the New Democrats drive to save the planet from envi-
ronmental destruction — that subsidize car battery plants
and low-emission steel production, as well as C$1.7 bil-
lion for capping off and cleaning up inactive oil and gas
wells.
Challenged by reporters to explain how he would
replace what he viewed as petroleum subsidies, Singh
said a New Democratic government would invest direct-
ly in promoting renewable energy programs and remedi-
ating abandoned wells.
The Canadian Association of Petroleum Producers, in
refuting the claims of anti-industry organizations, said
that for every C$1 the oil and gas industry pays in taxes
it uses just 30 cents of the tax exemptions, deductions
and credits at its disposal — the lowest of the top five
industries.
Economist Jack Mintz, at the University of Calgary’s
School of Public Policy, when asked by the Calgary
Herald if Canada’s petroleum industry is subsidized,
said: “In total, no. The latest calculations we’ve done
show the industry, next to finance, is the most highly-
taxed sector in the economy.”
Government statistics estimate the industry creates
about 522,000 direct jobs, generates about C$10 billion
a year in government revenues through taxes and royal-
ties and pumps about C$100 billion into the gross
domestic product.
Conservatives Of the other contentious petroleum issues, O’Toole’s
Conservatives are calling for a revamp of Bill C-69,
which is viewed as a comprehensive regulatory barrier to
all petroleum projects that encroach into federal jurisdic-
tion, and a repeal of Bill C-48 which bans oil tankers off
the northern coast of British Columbia.
The Conservatives also want an LNG export strategy,
a hydrogen energy plan, a pledge to make oil export
pipelines a priority and C$5 billion in tax credits for proj-
ects to advance carbon capture, utilization and storage or
CCUS and develop small modular nuclear reactors.
“We have an energy policy that would ensure Canada
can complete projects and get our products to export
markets, as opposed to (the governing Liberals) doing
everything they can to prevent them,” said Blake
Richards, a Conservative candidate in an Alberta con-
stituency.
While defending itself against accusations of benefit-
ing from federal subsidies, CAPP may have undermined
its position by asking for a 100% tax break on capital
spending and for clean-tech investments.
CAPP, whose member companies account for 90% of
Canada’s oil and gas output, said it is “crucially impor-
tant for the incoming federal government to make policy
decisions that position Canada to succeed in an ultra-
competitive investment market.”
CAPP Chief Executive Officer Tim McMillan said the
proposed tax break would be “vital to developing and
commercializing technologies that reduce (greenhouse
gas) emissions, water use, and more.”
Alberta Energy Minister Sonya Savage and industry
leaders had expressed hope that the campaign might
focus on the success of companies in lowering their
greenhouse gas emissions by 30% since 2008, and their
commitments to achieve net-zero emissions by 2050.
But Savage’s call for “an honest conversation about the
importance of the energy sector” shows every sign of being
swamped with false claims about federal subsidies. l
adjustments by participating countries in the OPEC+
Declaration of Cooperation was 110% in July, “rein-
forcing the trend of high conformity.”
According to a Bloomberg report, the meeting was
wrapped up in less than one hour, in stark contrast to
July’s meeting.
The meeting to establish August production levels
originally scheduled for July 1 was delayed, extended
and then postponed before an agreement was reached
July 14.
The next such meeting will be held Oct. 4. l
continued from page 1
ENERGY DEBATE
continued from page 7
OIL PRICES
Contact Steve Sutherlin at [email protected]
10 PETROLEUM NEWS • WEEK OF SEPTEMBER 5, 2021
The Department of Natural Resources (DNR) is inquiring whether there is
interest among commercial refiners or other parties to acquire some or all of
the State’s North Slope royalty in-kind (RIK) oil that may become available for
sale when the current RIK supply contract obligations terminate in the third
and fourth quarters of 2022 or any additional North Slope royalty volumes
that the State chooses to take as RIK oil. If there is substantiated interest ex-
pressed by more than one potential buyer for RIK oil, DNR may issue an Invi-
tation to Bid and conduct a sealed-bid auction for the RIK oil consequently.
DNR has received inquiries from potential buyers for multi-year RIK con-
tracts. Under AS 38.05.183, the sale of the state’s royalty oil must be by com-
petitive bid except when the Commissioner determines that the best interest
of the state does not require competitive bidding or that no competition exists.
We would like to know if your company might be interested in purchasing
RIK oil and participating in an auction via a competitive sealed bid mechanism
for a contract. We would also like to know the approximate volumetric range
(in barrels per day per year) you would require, and the preferred length of the
contract term (preferably, not less than three years). This is an informal, non-binding inquiry and your response will not create any kind of commitment by you or your company/organization. Your response, and those of other po-
tentially interested parties, will be used only to gauge whether sufficient com-
petition exists for RIK oil, and to determine whether the state will engage in a
competitive disposition in the sale of RIK oil.
Below we have described some of the bidding and contractual terms that
might apply to such a sale. Of course, they are subject to change depending
on circumstances at the time DNR issues an Invitation to Bid, and we invite
you to comment on proposed bidding and contractual term.
Proposed Bidding Terms (subject to change):
• Priority Bidders. The Department proposes to create a class of priority
RIK bidders who will have preference over the general class of RIK bidders.
This priority class of RIK bidders will consist of in-state commercial petroleum
processors, as defined under 11 AAC 03.190, that will (1) provide financial
guarantees in the form of a stand-by letter of credit, a surety bond, or a par-
ent guarantee from a parent with an investment grade credit rating from one
or more recognized credit rating companies (presuming that the Buyer is not
the parent), combined with an Opinion Letter provided by a Financial Analyst
that is independent from the Buyer, the parent, and the credit rating com-
pany, and (2) propose effective, viable Special Commitments that, if imple-
mented, would have an impact on lowering in-state energy costs for
consumers and addressing the need for a greater supply of crude oil for use in
the state. The requirement for proposing Special Commitments is discussed
further below.
• Sealed Bid Auction of RIK Oil Lots. RIK oil may be auctioned under fixed
or variable lots of no less than 3,000 bpd/year, with an estimated total avail-
able amount for sale of 40,000 bpd/year, and potentially varying year by year.
Each of these lots would be offered independently for each year, with deliver-
ies likely beginning in the second half of 2022 through the life of the desired
contract. As such, a bidder may be able to tailor their RIK oil bids in a manner
that comports with its forward-looking expectations concerning demand for
RIK oil. The winner of each lot will be the highest responsible bidder, and such
a winner may be determined by a procedure that considers, among other po-
tential factors, the lowest “RIK Differential” offered (possibly subject to a re-
servation price). The RIK Differential is a reducing element in the netback
pricing method described below. You are invited to comment on this broad
auction framework and bidding approach presented and define your vol-
umetric range requirements for RIK oil.
• Reservation Fee. During the term of the contract, and within certain tim-
ing and volumetric limits, a buyer may change their monthly nomination to a
quantity less than the maximum volume defined in a lot. This provides opera-
tional flexibility for a buyer to match its monthly RIK oil supply to its refinery’s
requirements. Such flexibility, however, comes at a cost to the State by pre-
venting the sale of the remainder of the lot as RIK. To compensate for this
cost, the State proposes to institute a per-barrel reservation fee assessed on
those barrels below the RIK lot maximum not nominated by the buyer. You
are invited to comment on your preferred mechanism for implementing such
a reservation fee.
• Bid Process. Upon evaluating responses to this Non-Binding Solicitation of
Interest, the Department may distribute a public notice and a formal Invitation
to Bid to all potential buyers and the public outlining the auction process in
more detail, if a competitive disposition is selected. Bidders will have at least 30
days after the Invitation to Bid is published to submit bids and documentation.
Proposed Contractual Terms for RIK Disposition (subject to change):
• Sale Oil Quantity. The contract will specify the volume, or “Sale Oil Quan-
tity,” awarded as a result of the nomination or auction. For example, if RIK oil
is auctioned in different lots, and a buyer successfully bids on several of them,
a single RIK Contract would include the total Sale Oil Quantity from all the lots.
The State expects each nomination or bid to be for at least 3,000 bpd/year.
Proposals are sought for nomination ranges from potential buyers.
• State’s RIK Nomination. Because the State must nominate with at least
90 days in advance to take its royalty oil in-kind, all contracts will provide that
DNR will make commercially reasonable efforts to nominate, in accordance
with applicable Unit Agreements, percentages of the State’s estimated royalty
oil from one or more Units that will equal the Sale Oil Quantity nominated by
the buyer. The nomination procedures are basically unchanged from every
RIK contract offered by the Department since the first production of oil at the
Prudhoe Bay Unit. Any former or current buyer of RIK oil should be familiar
with these procedures.
• Volumetric Limits and Proration. The actual Sale Oil Quantity delivered to
all RIK oil buyers may be lower than their total initial nominations. DNR re-
serves the right to limit total Sale Oil Quantity delivered to all RIK oil buyers to
a maximum of 95% of the State’s estimated royalty oil. Whenever total initial
nominations by all buyers exceed 95% of the State’s estimated royalty oil, pro-
ration takes effect and affects RIK buyers’ initial nominations. DNR is consid-
ering several proration mechanisms. You are invited to provide thoughts
concerning an appropriate proration mechanism.
• Price. The price for the Sale Oil is calculated as a simple netback price. The
formula starts with a destination value for the State’s royalty oil on the US
West Coast minus the RIK Differential. The RIK Differential is a numeric vari-
able that may be used as the bid variable in the case of a competitive disposi-
tion. The ownership-weighted average interstate tariff for TAPS and tariffs for
pipelines upstream of TAPS Pump Station No. 1 are also subtracted depending
on the source of the RIK that will be supplied to the buyer. The price formula
also includes a Quality Bank Adjustment and an allowance for line loss. The
price provision in the contract will stipulate that the value of RIK is bounded
below by zero. DNR is open to suggestions for a constant or variable RIK Dif-
ferential value and process. Your thoughts concerning the appropriate pricing
indexes to value ANS on the US West Coast are also welcome.
• Contract term. The contract will supply RIK oil for at least three years,
based on disposition preferences and terms.
• Security Arrangements. The security arrangements protect the State
from the risk of default by requiring a stand-by letter of credit, a surety bond,
or a parent guarantee, if the buyer is not the parent, combined with an Opin-
ion Letter provided by a Financial Analyst that is independent from the Buyer,
the parent, and the credit-rating company.
• Special Commitments. Bidders may be required to propose Special Com-
mitments that will be incorporated into the RIK contract. The Special Commit-
ments should propose means to mitigate the high cost of consumer
petroleum products in Alaska and address the need for a greater supply of
crude oil for use in the state. Examples of a Special Commitments might be a
commitment to make a substantial capital investment to support in-state pro-
cessing, a commitment to lowering the cost of petroleum products to the
consumer and others, etc. You are invited to comment on how Special Com-
mitments might affect your interest in RIK oil and offer alternatives.
I will appreciate a written response to this informal solicitation by Sep-
tember 30, 2021. In the meantime, I invite you to contact Jhonny Meza at
[email protected] to discuss this letter. As stated above, this is an in-
formal, non-binding inquiry and your response will not create any commit-
ment by you or your company.
Tom Stokes, Director, Division of Oil and Gas
First publication: August 26, 2021
PUB 9/5/2021; 9/12/2021
AO 22CM-10-013
Non-binding Solicitation of Interest North Slope Royalty In-Kind Oil Supply
of up to five drill sites, a central process-
ing facility, an operations center pad, up
to 37 miles of gravel roads and an airstrip,
as well as the installation of necessary
pipelines.
“We, and many important stakehold-
ers, remain committed to Willow as the
next significant North Slope project,”
ConocoPhillips told Petroleum News on
Aug. 30.
“The merits of the project represent a
strong example of environmentally
responsible development that offers
extensive public benefits, including sig-
nificant employment of Alaskan skilled
labor from union and non-union trade
associations and financial payments to
federal, state, borough, and community
governments.”
Alaska’s congressional delegation
agreed with ConocoPhillips, Arctic Slope
Regional Corp., and other stakeholders in
the project, weighing in on Gleason’s
decision.
“Yet again another devastating deci-
sion by this federal judge that promotes
the interests of Lower 48 radical environ-
mental groups waging their unrelenting
war on Alaska’s economy, working fami-
lies, and Native communities,” Sen. Dan
Sullivan said. “This decision won’t do
one thing to help the environment. To the
contrary, it further delays one of Alaska’s
most strategic energy development proj-
ects, which will benefit our adversaries
that produce oil, like Russia, Venezuela
and Iran, whose environmental standards
are some of the worst in the world.”
Sen. Lisa Murkowski said Gleason’s
decision was “just plain wrong. … In
partnership with communities on the
North Slope, ConocoPhillips Alaska has
been responsibly producing oil from the
NPR-A region for decades under the high-
est environmental standards and this pro-
posed project will be no different.”
Continues to review decision “In order to determine the best course
of action for advancing the Willow proj-
ect,” ConocoPhillips continues to review
U.S. District Judge Sharon Gleason’s
Aug. 18 decision to vacate BLM’s
approval of Willow.
ConocoPhillips also said it still
“strongly” believes that BLM and cooper-
ating agencies “performed a robust, thor-
ough, and extensive review of the Willow
project,” and will again engage with the
relevant agencies to address the matters
described in the Court’s decision.
“On a parallel path we will continue to
perform engineering design work in
anticipation of a future final investment
decision (FID),” the company said.
However, given the recent Court deci-
sion, ConocoPhillips said it did not expect
to make the FID decision in 2021 as orig-
inally planned and continues to be clear
that it “won’t make the FID until the legal
risks are resolved.”
No impact on core biz Regarding ConocoPhillips’ other explo-
ration, appraisal, development and produc-
tion interests on the North Slope, the com-
pany told Petroleum News: “The Willow
decision on August 18 has no direct impact
on the remainder of the company’s core
business in Alaska.”
Those words are not surprising, in light
of what ConocoPhillips Alaska’s top execu-
tive Erec Isaacson has been saying in recent
weeks: “After working through last year’s
market volatility and the pandemic, the
theme for us this year has been Getting
Back to Work, and we are full speed ahead.”
“Alaskans are back to work on the North
Slope,” he continued, “and ConocoPhillips
is investing in Alaska’s future. The state’s
economy is no doubt still on shaky ground,
but we are fully engaged in multiple large-
scale projects.”
Among those activities:
•The restart of drilling in the Kuparuk
River unit with a workover rig in the third
quarter, followed by a coiled tubing rig in
the fourth quarter and rotary rig drilling in
the second quarter of 2022.
•The first Fiord West well was spud in
second quarter. It will test more than 45 mil-
lion barrels of oil equivalent from the exist-
ing CD-2 pad and be tied back to infrastruc-
ture with first oil scheduled later this year.
•The GMT-2 project is in its third and
final construction season.
•A new oil discovery in the Nanushuk
formation at the Coyote prospect just west
of Kuparuk.
•Alpine expansion, Nuna development
and ongoing work at the Eastern NEWS at
the Kuparuk River unit are a few of those
projects. l
PETROLEUM NEWS • WEEK OF SEPTEMBER 5, 2021 11
RESOURCEBUILDING A
TRIESE INDUS’SALASKA
S
quality certification for the project.
Enbridge said construction is “nearly completed” in
Minnesota, with the Canadian, North Dakota and Wisconsin
sections already finished, setting the stage for the new line
to start operations in the fourth quarter.
Line 3 will replace a pipeline built in the 1960s that oper-
ates at half its original capacity because of corrosion and
cracking risks. The company said the new line, which will
carry an incremental 390,000 bpd, is about safety and main-
tenance, with the upgraded pipe made of thicker steel and
technically advanced coatings that “will better protect
Minnesota’s environment for generations to come.”
Objections remain However, Margaret Levin, director of the Sierra Club’s
Minnesota chapter, said it was disappointing that the appeals
court would not hold the MPCA “accountable for their fail-
ure to protect our clean water … now it’s more urgent than
ever that President (Joe) Biden step in, live up to his com-
mitments to climate action and environmental justice, and
stop Line 3.”
She said Enbridge has “already had dozens of drilling
fluid spills during the course of construction.”
The appeals court said the MPCA’s approval was “sup-
ported by substantial evidence in the record,” including its
certification last November that cleared the way for the U.S.
Army Corps of Engineers to issue the remaining federal per-
mit for the pipeline.
From concept to reality Kevin Birn, analyst with IHS Marketing, said Line 3 is
now “moving from a theoretical concept to something that
is physical.”
“There have been lots of pipeline projects in the past, but
very few have made it to the finish line,” he said. Referring
to the abandonment of three large-scale plans to export
crude bitumen out of Canada — Northern Gateway, Energy
East and Keystone XL, which had potential combined ship-
ments of almost 2.5 million bpd.
Birn noted it has taken an average of more than seven
years for two surviving projects — Line 3 and the Trans
Mountain expansion — to advance from initial regulatory
filings to anticipated completion.
Alberta Energy Minister Sonya Savage, who spent seven
years with Enbridge before entering politics, told the
Calgary Herald that getting Line 3 so close to completion “is
certainly a big relief” for oil sands producers to “have this
additional capacity.”
Enbridge said Line 3 has involved spending of US$287
million in Native American communities and small busi-
nesses and will provide millions of dollars in additional local
spending and tax revenues.
—GARY PARK
continued from page 1
LINE 3
unit was formed in 1967 by Standard Oil Company of
California, the original operator, and initially included
24,439 acres. Hilcorp took over as operator Jan. 1, 2012, the
division said. The unit currently has two participating areas,
the Sterling-Beluga Gas PA and the Tyonek Gas PA, on
2,595.34 acres.
As of July, the field was producing from three wells,
with production averaging 8,517 thousand cubic feet per
day in that month. Hilcorp has done a lot of work at the field
in recent years.
In its 2019 POD Hilcorp told the division that during the
2018 POD it “worked on a comprehensive field study that
would lead to possibly enhancing production.” The field
study “evaluated the Sterling, Beluga and Tyonek reservoirs
for further development,” the company said, and “included
pursuing efficiencies through various well, infrastructure
and facility repairs, including evaluation of shut-in wells for
potential return to service or utility.”
Alaska Oil and Gas Conservation Commission records
show the most recent drilling at the field, the IRU 11-06,
was completed in 2009.
The company has already achieved improved produc-
tion results.
Comparing production in July, the field produced 3,222
mcf per day in 2012, the year Hilcorp took over as operator,
and gradually declined, dropping to 444 mcf per day in July
2019.
But by July 2020, Hilcorp had increased production to
2,449 mcf per day, and this year, the July volume was 8,517
mcf per day, down from a recent peak of 11,358 mcf per day
in June.
In the 51st POD for the field, for 2021, submitted March
1, Hilcorp reviewed work from the 2020 POD. It told the
division it completed “three intervention jobs” during the
2020 POD period:
In the IRU 11-06 the Tyonek sands were isolated and the
Sterling A5 was perforated in July 2020. In the IRU 44-36,
the company isolated the Sterling C1 sand and the Sterling
B2 was perforated in September 2020. In the IRU 41-01 the
Sterling B1 was perforated in February 2021.
In approving the 2020 POD the division noted that
Hilcorp increased annual production at Ivan River by nearly
429% during the 2020 calendar year and said the “drastic
increase” could be primarily attributed to work at the IRU
11-06 and IRU 44-36 wells.
The IRU 44-36, the division said, had been shut-in since
2008.
In the plan proposed for 2021, Hilcorp was evaluating a
rig workover on the IRU 11-06. “The current completion in
the well does not allow for zonal isolation if producing per-
forations were to begin producing significant water and/or
sand. The RWO would replace the current tubing configu-
ration and allow for future isolation of perforations within
the well,” the company said.
—KRISTEN NELSON
continued from page 1
IVAN RIVER
continued from page 1
WILLOW DECISION“In order to determine the best
course of action for advancing the Willow project,” ConocoPhillips continues to review U.S. District Judge Sharon Gleason’s Aug. 18
decision.
In approving the 2020 POD the division noted that Hilcorp increased annual production at Ivan River by nearly 429% during the 2020
calendar year and said the “drastic increase” could be primarily attributed to work at the
IRU 11-06 and IRU 44-36 wells.
12 PETROLEUM NEWS • WEEK OF SEPTEMBER 5, 2021
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In an Aug. 24 filing with the Louisiana
court, responding to the court’s injunction,
the Department of the Interior said that it
has been reviewing information relevant to
its lease sales and anticipates now opening
the EIS public comment period for the
Cook Inlet sale in September or October.
The public comment period had been
scheduled to last for 45 days and would be
followed by additional work on the EIS, in
response to the comments received.
The Louisiana court case was initiated
on March 24 when 13 states, including
Alaska, appealed President Biden’s
February executive order, arguing that the
order contravened the Administrative
Procedures Act, the Outer Continental
Shelf Lands Act and the Mineral Leasing
Act. On June 15, in response to the appeal
and pending final resolution of the court
case, the Louisiana court issued a prelimi-
nary injunction, banning the federal pause
in oil and gas leasing. On Aug. 16 the
Department of the Interior appealed the
injunction to the U.S. Court of Appeals for
the 5th Circuit.
As a consequence of the court injunc-
tion BOEM is also restarting its prepara-
tions for a lease sale in the Gulf of Mexico
— the agency had completed a final EIS
for that sale, which had been scheduled for
March of this year. The agency now antic-
ipates conducting the sale in October or
November.
Interior also said that, in response to the
injunction, the Bureau of Land
Management will continue to plan for
onshore lease sales for federal land without
the constraint of the Feb. 4 executive order.
Obviously, the eventual outcomes of all
of this will depend both on the 5th Circuit
response to the appeal against the injunc-
tion and on the outcome of the Louisiana
court case.
—ALAN BAILEY
continued from page 1
INLET SALE
Service Layer Credits: Sources: Esri,HERE, Garmin, Intermap, increment PCorp., GEBCO, USGS, FAO, NPS,NRCAN, GeoBase, IGN, Kadaster NL,
6634
Cook InletPlanning Area
6759
6809 68106808
6857
6907
6964
7015
7065
6006
6055
6114
6154
6202
6263
6301 6313
6363
6413
6463
6760
6811
68586859 6860 6861
6862
6908 6909 6910 6911 69126913
6957 6958 6959 6960 6961 6962 6963
7007 7008 7009 7010 7011 7012 7013 7014
7057 7058 7059 7060 7061 7062 7063 7064
7107 7108 7109 7110 7111 7112 7113 71147106
6007 6008 6009 6010 6011 6012 60136014
6056 6057 6058 6059 6060 6061 6062 60636064
6105 6106 6107 6108 6109 6110 6111 6112 6113
6155 6156 6157 6158 6159 6160 6161 6162 6163
6204 6205 6206 6207 6208 6209 6210 6211 62126203
6213
6252 6253 6254 6255 6256 6257 6258 6259 6260 6261 6262
6302 6303 6304 6305 6306 6307 6308 6309 6310 6311 6312
63516352 6353 6354 6355 6356 6357 6358 6359 6360 6361 6362
6401 6402 6403 6404 6405 6406 6407 6408 6409 6410 6411 64126436
6486 6451 6452 6453 6454 6455 6456 6457 6458 6459 6460 6461 646264856484
6536 65016535 65026534 6503 6504 6505 6506 6507 6508 6509 65106533 6511 65126532
6586 65516585 65526584 65536583 65546582 6555 6556 6557 6558 6559 6560 6561 6562
6636 66016635 6602 66036633 66046632
6605 6606 6607 6608 6609 6610 6611 6612
NP05-08Kenai
NO05-01Iliamna
NO05-02Seldovia
Nanwalek
Seldovia
Port Graham
Anchor Point
Homer
Ninilchik
151°30'W152°W152°30'W153°W153°30'W
Augustine Island
Kalgin Island
KenaiPeninsula
A L A S K A
Cook I
nlet
KachemakBay
2017 - 2022 Program Area
Cook Inlet Planning Area
OCS Protraction(s)
OCS Block(s)/Block Number(s)
Active OCS Lease(s)0 2010
Km
0 105Miles
Cook Inlet Planning AreaCall for Information and Nominations
Lease Sale 258ALASKA
Anchorage
BOEM Alaska OCS Region | Leasing and Plans | Leasing Section
NAD 83: Alaska Albers Projection
Map ID: AKR2020048v2APRIL 6, 2020
NO05-01
6453Map Location
Interior also said that, in response to the injunction, the Bureau of
Land Management will continue to plan for onshore lease sales for
federal land without the constraint of the Feb. 4 executive order.
To advertise in Petroleum News, call Susan Crane at 907-250-9769