Hydrokinetic system to begingenerating electricity at Igiugig

l E X P L O R AT I O N & P R O D U C T I O N

l E X P L O R AT I O N & P R O D U C T I O N

l G O V E R N M E N T

State adds online lease sales inDNR proposed regulation changes

The Department of Natural Resources has published pro-

posed changes in its regulations for, among other things, pay-

ment of oil and gas royalties, rents and bonuses and oil and

gas leasing procedures.

The proposed regulation changes deal with payment meth-

ods, bidding methods, requirements for bid submission,

requirements for applications, rental provisions and defini-

tions regarding mineral leasing.

“The proposed changes will facilitate online oil and gas

lease sales,” DNR said in the notice of the proposed regula-

tions.

But that doesn’t mean the Division of Oil and Gas, which

see REG CHANGES page 8

see ALKAID HOPES page 10

see AGDC CUTS page 10

see KITIMAT LNG page 10

page2

Vol. 24, No. 29 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of July 21, 2019 • $2.50

Kitimat LNG project revivedChevron Canada and its Australian partner Woodside have

made sweeping promises to regulators in their latest bid to revive

the Kitimat LNG project.

In a 186-page filing to British Columbia and Canadian envi-

ronmental agencies, they have promised their KLNG plant would

“outperform current best-in-class global LNG plants and the

more stringent government of B.C.’s LNG intensity benchmark”

by utilizing electric-motor-drive technology for all processes.

Their pledge is to operate at a level below British Columbia’s

limit for “emissions intensity” of 0.16 carbon-dioxide equivalent

metric tons for each metric ton of LNG produced.

The partners said they hope to make a final investment deci-

sion in 2023, and target completion of the first phase by 2029.

Pantheon hopes to put Alkaidonline earlier, in 2020 vs. 2021

London-based Pantheon Resources, which acquired the North

Slope assets of Great Bear Petroleum in January, says current

planning could result in the Alkaid/Phecda phased production

project coming online as early as summer 2020, versus 2021.

In a mid-July update, the company said the advanced schedule

was “subject to completion and timing of a successful farmout,”

noting pre-application meetings with state and federal agencies

for the pilot production testing of the Alkaid discovery had taken

place, with “positive and supportive feedback.”

No permitting issues were identified, Pantheon said.

The Alkaid discovery, drilled but never tested by Great Bear

in 2015, was successfully flow tested in March by Pantheon’s

local subsidiary, Pantheon Alaska Petroleum Operating. The

Eni going for oil Drilling picks up at Nikaitchuq, NN-02 exploratory well in works for winter

By KAY CASHMANPetroleum News

Eni US Operating Co.’s plans for its North Slope

assets are still evolving, but definitely moving

forward, as expected.

The U.S. subsidiary of the Milan-based major now

owns 100% of two oil producing units between

Prudhoe Bay and the National Petroleum Reserve-

Alaska, as well as 350,000 undeveloped acres to the

east between Prudhoe and Point Thomson.

According to a reliable Petroleum News source,

Eni plans to drill one, possibly two injector wells in its

nearshore Nikaitchuq unit prior to finishing drilling

and then testing its offshore Nikaitchuq North explo-

ration well, NN-01, in early 2020.

NN-01, the longest extended reach well of its type

in Alaska at an expected measured depth of approxi-

mately 35,000 feet, will also likely be sidetracked as

NN-02.

Revisiting ANWR debateBig structures in eastern deformed 1002 area continue to raise questions, interest

By KAY CASHMANPetroleum News

A lthough only those oil companies

that co-own 2D seismic data of the

ANWR 1002 area shot in the mid-1980s

will have subsurface data prior to a lease

sale later this year, there is other valuable

geologic information coming from

Interior’s U.S. Geological Survey that will

help bidders understand the oil potential of

the region. (The lucky consortium of companies that

have access to the vintage 2D data include Anadarko,

BP, Chevron, ConocoPhillips, ExxonMobil, Hess,

Marathon, Murphy, Oxy, Shell and Total.)

The effort to provide bidders with more info on

the 1002 area is led by USGS senior

research geologist Dave Houseknecht, a

long-time expert on northern Alaska petro-

leum geology, who

talked to Petroleum

News July 10 (see July

14 story in PN) and then

again on July 12, which

yielded the information for this sequence

of articles.

In conjunction with field work over the

last two summers in and near the 1002 area, the

agency has completed a grounds-up reprocessing of

1,451-line miles of the 2D seismic collected from the

area in 1984 and 1985, the purpose of which was to

Trudeau’s version of logicCanadian PM hails recruitment of anti-pipeline activist to contest Quebec seat

By GARY PARKFor Petroleum News

Canadian Prime Minister Justin

Trudeau made a three-day stop in

Alberta as part of his warm-up cam-

paigning for an Oct. 26 election.

He started in Edmonton on July 11

with the promise of an announcement

the next day on the Trans Mountain

pipeline expansion, TMX.

That sent a quiver of hope through the oil patch.

What did he have in mind? Word of a formal

resumption of construction on TMX? The sale of a

stake in the Trans Mountain system to a coalition

of First Nations?

Not even close. All he wanted to do

was personally tell Albertans that his gov-

ernment had reapproved TMX. In other

words, what he had told the nation almost

a month earlier on June 18.

For many Albertans that was nothing

more than an insult, a sign that Trudeau

holds out little hope for his governing

Liberal Party can build on its Alberta toe-

hold that included electing only four of 34

Liberal Members of Parliament in 2015.

In fact, Trudeau was apparently so unsure of

himself that he held only a private reception in

Calgary and avoided a likely hostile reception at

the annual Calgary Stampede.

see GOING FOR OIL page 11

see REVISITING ANWR page 7

see TRUDEAU TOUR page 6

Eni … to drill one, possibly two injectorwells in its nearshore Nikaitchuq unit

prior to finishing drilling and then testingits offshore Nikaitchuq North exploration

well, NN-01, in early 2020 … will …likely be sidetracked as NN-02.

DAVE HOUSEKNECHT

JUSTIN TRUDEAU

AGDC cuts staff; will focus on completing FERC permitting process

The direction of the Alaska Gasline

Development Corp., which manages the

Alaska LNG Project for the state, changed

last year after Gov. Mike Dunleavy was

elected. Dunleavy replaced a majority of

AGDC board members, and the new board

replaced AGDC’s president and returned to

a stage-gate process, which requires an

evaluation of whether the project should

advance at specified stages in the process.

A previous iteration of the Alaska LNG

Project, in which the state partnered with BP, ConocoPhillips and

ExxonMobil, reached such a stage-gate in 2016 following com-

JOE DUBLER

2 PETROLEUM NEWS • WEEK OF JULY 21, 2019

EXPLORATION & PRODUCTION

LAND & LEASING

2 Igiugig hydrokinetic gets launch party

4 Egan state’s largest rooftop solar array

4 Oil production steady in North Dakota

4 Beaufort final best interest finding out

11 US drilling rig count down 5 to 958

3 Significant upside in unmanned flight

Unmanned aircraft go up, some costs fall; step by step by inch,regulatory hurdles fall as uses for aerial workhorses proliferate

ALTERNATIVE ENERGY

Eni going for oilDrilling picks up at Nikaitchuq, NN-02 exploratory well in works

Revisiting ANWR debate Structures in eastern deformed 1002 area continue to raise interest

Trudeau’s version of logicPM hails recruitment of anti-pipeline activist to contest Quebec seat

ON THE COVER

State adds online lease sales inDNR proposed regulation changes

Pantheon hopes to put Alkaidonline earlier, in 2020 vs. 2021AGDC cuts staff; will focus oncompleting FERC permitting processKitimat LNG project revived

TMI?l E X P L O R A T I O N & P R O D U C T I O N

l U T I L I T I E S

l G O V E R N M E N T

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l A L T E R N A T I V E E N E R G Y

Igiugig hydrokinetic gets launch partyBy KRISTEN NELSON

Petroleum News

I giugig in southwestern Alaska celebrated July 16 as

the Igiugig Village Council and Ocean Renewable

Power Co. prepared for deployment of the company’s

first commercial hydrokinetic system in the Kvichak

River.

Alaska Gov. Mike Dunleavy was among a crowd of

more than 60 people gathered at Lake Iliamna and the

Kvichak River for the unveiling of ORPC’s first com-

mercial device, a 40-kilowatt RivGen Power System. It

will be deployed long term in the Kvichak River in the

next few days, the company and the Igiugig’s Village

Council said in a July 16 press release. The system will

provide up to one-half of the Igiugig community’s elec-

tricity needs annually.

The village and ORPC said plans are underway for

installation of a second device “in conjunction with

smart microgrid electronics and energy storage.” When

that installation is completed, the system will reduce

diesel usage in Igiugig by 90%.

The Igiugig Village Council received a 10-year pilot

project license for the in-river turbine power generation

project from the Federal Energy Regulatory Commission

in late May and is the first tribal entity in the United

States to receive this approval. (See FERC’s description

of the project in story in June 23 issue of Petroleum

News.)

The village and ORPC have been collaborating on the

project since 2009.

The Igiugig Hydrokinetic Project is supported by the

U.S. Department of Energy’s Office of Energy

Efficiency and Renewable Energy, the U.S. Department

of Agriculture, the Alaska Energy Authority, the Igiugig

Village Council and private investors.

ORPC works with more than 80 partners, contractors

and consultants in Alaska and has spent more than $5

million in the state since 2009.

see LAUNCH PARTY page 4

Alaska Gov. Mike Dunleavy was among a crowd of morethan 60 people gathered at Lake Iliamna and the KvichakRiver for the unveiling of ORPC’s first commercial device, a40-kilowatt RivGen Power System.

CO

URT

ESY

PH

OTO

By STEVE SUTHERLINPetroleum News

Dr. Catherine F. Cahill, director of the

Alaska Center for Unmanned Aircraft

Systems Integration at the University of

Alaska Fairbanks, has a drone to pick

regarding terminology.

“I’m talking about unmanned aircraft

you guys,” she said in remarks to the Alaska

Oil and Gas Association conference in

Anchorage May 30, “You all call them

drones ... we have lost the battle.”

The center is, however, serious about the

advantages unmanned aircraft can bring to

Alaska and its oil and gas industry.

“We are the lead for the entire system of

the University of Alaska for this particular

technology,” she said. “We’ve been doing

this since 2001, so we actually are some of

the granddaddies of the field and we do a

wide variety of missions — anything from

helping the FAA to integrate the unmanned

aircraft into the air space to helping with

wildlife surveys, marine mammal surveys,

mapping — you name it, we’ve probably

done it.”

Unmanned aircraft are safer, repeatable

and environmentally friendly, at a substan-

tial fuel savings over a helicopter, she said,

adding that “terabytes per day” of quality

data can be gathered by unmanned craft.

Unmanned aircraft “can be less expen-

sive to operate, but right now with the regu-

latory situation it’s not there yet,” Cahill

said. “For short distances and line of sight,

often it is less expensive — also we can

potentially fly where aircraft may not be

able to fly.”

The program includes much more than

just flying aircraft, Cahill said.

“Only when you put a payload on it is it

worth something,” she said. “We need to

have payloads; we need to be able to adapt

them; we need to be able to talk to the pay-

loads; we need to be able to talk to the air-

craft — command and control; we need to

have a team that can effectively put this to

use for missions of value.”

The center has a diverse fleet with a

diverse set of missions.

“We have quite a fleet so we’ve been

practicing,” Cahill said. “We do everything

from the little tiny ones for the school out-

reach, getting kids excited about flying tech-

nology and engineering ... thinking about

careers in this field, to one that happens to

have a 16-foot wingspan.

“We can do pipeline surveillance; we can

look for cracks; we can look for leaks; we

can look for someone approaching the

pipeline when they shouldn’t,” she said.

“We can do cargo delivery, medical supplies

— if there happens to be an emergency,

repair supplies, mammal surveys, the list is

endless in terms of potential here but the key

is we have do it safely. We want to make

sure that whatever we do, it does not conflict

with manned aviation, and guarantee that

we hold to the highest safety standards.

“We can do a lot of pilot programs,” she

said. “We did some of the initial flare stack

inspections, way back when, with ENI.”

Regulatory test of patienceACUASI is the site of one of seven

Federal Aviation Administration unmanned

aircraft test centers, Cahill said.

“We are working on FAA regulations;

we’re flying beyond the line of sight, what a

big win for Alaska,” she said. “We need to

be able to do ... monitoring 24/7, 365 days a

year — beyond the line of sight of the oper-

ator.

“The FAA is having trouble with this.

and we’re pushing them hard,” Cahill said.

“Hopefully, the rules will evolve and even-

tually instead of putting people in helicop-

ters at risk we can use unmanned aircraft.”

The upside is apparent, but implementa-

tion comes slowly.

“The main challenge is the FAA,” Cahill

said. “We are working very hard to work

with the FAA to advance the rules and regu-

lations for space integration, especially here

in Alaska.”

The major concern is the smooth interac-

tion of unmanned operations with general

aviation.

“General aviation loves to fly where we

want to be — that’s under 500 feet, so a lot

of challenges making sure that we are not

going to interfere with general aviation that

doesn’t have transponders,” she said. “If

people are going to have an accident it’s not

going to be your trained operator, it’s going

to be an unlicensed user probably first.

“Fast forward, we are working with the

FAA to develop what’s called detect and

avoid, our sense-and-avoid technology,” she

said. “If you lose contact with the aircraft,

the aircraft will spot other aircraft in the air,

and avoid. We’re doing the cutting edge here

in Alaska.

“We are working towards an Alaskan

solution and we have had priority given to

us by FAA,” she said.

“We are making strides in being able to

operate with 11 miles between the aircraft

and the operator — that is more space than

the FAA is giving anybody, so step by step.”

“They seem to think that doing a

Popsicle delivery is sufficient, we want to be

able to use it to do tools for several hundred

miles,” she said. “We keep pushing; we are

working on getting a commercial air carrier

certificate.”

Practical missions underwayACUASI is collaborating on a number of

development projects of commercial value.

The center flies the Sea Hunter, a 325-

pound 16-foot wingspan unmanned aircraft.

“We are doing meteorological measure-

ments and sea ice measurements off the

coast, helping prove that we can work in and

out of working airports,” Cahill said, adding

that ConocoPhillips supported the mission.

The center is also partnering with

Alyeska Pipeline Service Co. to test the use

of unmanned aircraft for the surveillance of

the trans-Alaska oil pipeline.

And, building on work done previously,

the center is working with BP to develop a

new ultralight methane detection system.

“We took a 14-kilogram spectrometer

down to 1 kilogram and flew it with a small

helicopter ... to do leak detection remotely

beyond the line of sight,” Cahill said.

“Exciting stuff.”

BP says such new technology is sweeten-

ing its bottom line already.

“We’re ushering in and using a lot more

technology, whether it’s drones or big data

or virtual reality and digitization of our facil-

ities,” Janet Weiss, president of BP

Exploration (Alaska) told the Alaska

Support Industry Alliance’s Meet Alaska

conference on Jan. 18. “We’re seeing costs

come down through technology.”

BP is executing its inspections more safe-

ly and efficiently with unmanned aircraft,

Randy Sulte, BP program execution manag-

er, told the Resource Development

Council’s 2018 annual conference in

November.

After spring flooding and subsequent

road damage on the North Slope, an

unmanned aircraft captured high quality

images for appraising the situation. An over-

flight in conventional aircraft was not imme-

diately possible because of low clouds. l

l E X P L O R A T I O N & P R O D U C T I O N

Significant upside in unmanned flightUnmanned aircraft go up, some costs fall; step by step by inch, regulatory hurdles fall as uses for aerial workhorses proliferate

PETROLEUM NEWS • WEEK OF JULY 21, 2019 3

229-6000

“We actually are some of thegranddaddies of the field and wedo a wide variety of missions.”

—Dr. Catherine F. Cahill, director,Alaska Center for Unmanned

Aircraft Systems Integration at theUniversity of Alaska Fairbanks

Contact Steve Sutherlin at stevepna@hotmail.com

4 PETROLEUM NEWS • WEEK OF JULY 21, 2019

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Call 907.522.9469

DENALIUNIVERSAL.COM

Setting the Standard for INTEGRATED FACILITY MANAGEMENT and SECURITY SERVICES

Goal sustainabilityIgiugig Village, 48 miles southwest of

Iliamna and 56 miles northwest of King

Salmon, has 69 residents, mainly Yup’ik

Eskimos, Aleuts and Athabascan Indians.

“The project is a centerpiece of the

community’s long-term economic and

environmental vision, sustainably fits

with the local river’s salmon resource and

addresses occurrences such as seasonal

ice impacts in the Kvichak,” said Igiugig

Village Council President AlexAnna

Salmon.

“I will be closely following the

progress of the deployment of the RivGen

system over the coming months and I am

hopeful that similar projects can be devel-

oped to reduce energy costs for our small-

er communities,” Dunleavy said in the

release.

Steve DeWitt, U.S. Department of

Energy, said the project would increase

knowledge of marine energy systems,

interaction of underwater turbines with

salmon and how system contribute to pro-

viding stable power for local microgrids.

“With this data in hand, we hope that

other communities considering similar

systems will be able to make, with greater

confidence, the right decisions for their

community’s future,” DeWitt said. He

called what was being done in Igiugig “a

model for what can happen throughout

Alaska and Canada, in other similar

small, independent communities.”

Christopher Sauer, ORPC chairman,

co-founder and CEO, said “ORPC’s

RivGen Power System is the future of

sustainability for remote river communi-

ties around the world,” and noted that

some 700 million live in remote commu-

nities dependent on diesel. l

continued from page 2

LAUNCH PARTY

LAND & LEASINGBeaufort final best interest finding out

The Alaska Division of Oil and Gas has issued a final best interest finding for

Beaufort Sea areawide oil and gas lease sales, covering 2019-28.

The finding, signed by division acting Director James Beckham, with concur-

rence by Department of Natural Resources Commissioner Corri Feige, is dated

July 12.

Best interest findings are issued every 10 years; annually, prior to areawide oil

and gas lease sales, the division issues a call for any substantial new information

which has become available since the most recent final best interest finding.

The director’s final written finding is that “the potential benefits of the lease

sales outweigh the possible negative effects, and that the Beaufort Sea Areawide

oil and gas lease sales will best serve the interests of the State of Alaska.”

The finding is available on the division’s website at:

https://dog.dnr.alaska.gov/Services/BIFAndLeaseSale.

After the preliminary BIF was issued the division received comments from the

Alaska Department of Fish and Game, the North Slope Borough and the Alaska

Eskimo Whaling Commission.

The division said it added ringed and bearded seals to the list of threatened or

endangered animals in the sale area based on a comment from Fish and Game’s

Habitat Division and incorporated additional information describing NSB

requirements for offshore oil and gas activities to protect subsistence resources

and activities based on comments from the NSB.

—KRISTEN NELSON

EXPLORATION & PRODUCTIONOil production steady in North Dakota

State officials say oil production in North Dakota held steady this spring.

The state’s wells produced 1.39 million barrels of crude per day in May, just

800 per day more than in April. Despite the steady May numbers, North Dakota’s

oil production is near the record set in January. And, the high level is creating

some transportation challenges. Statewide, companies are flaring off 19% of all

gas produced, higher than the 12% target.

Department of Mineral Resources Director Lynn Helms tells the Bismarck

Tribune work is underway on a number of facilities to capture more of that gas,

including several processing plants and Oneok’s Elk Creek Pipeline, which will

carry natural gas liquids from eastern Montana to Kansas.

—ASSOCIATED PRESS

Egan state’s largest rooftop solar arrayAnchorage has unveiled the state’s largest rooftop solar project at the Egan

Civic and Convention Center, a report said.

The project is also the first effort by the municipality to operate a large rooftop

solar power project, Alaska Public Media reported July 15.

The project’s 216 solar panels are expected to power up to 9% of the conven-

tion center’s electricity needs for the year, officials said.

The $200,000 project was funded from a pool set aside for capital improve-

ments from the Convention Center Room Tax Fund.

The project is expected to save the center between $20,000 and $25,000 annu-

ally, said Stephen Trimble, CEO of Artic Solar Ventures.

The company installed the panels using a crew of eight Alaska contractors over

four nights.

The project is an example of the city trying something new that could add clean

energy jobs, said Anchorage Mayor Ethan Berkowitz.

“This is a sign that we can develop new industry in Anchorage and across

Alaska,” Berkowitz said.

The Egan center solar panels and similar projects are expected to help extend

the life of the gas fields that currently fuel most of Anchorage, he said.

“We can do it in ways that are fiscally responsible and in ways that help satisfy

our responsibility in terms of addressing climate change,” Berkowitz said.

The project is a fulfillment of some of the city’s priorities identified in its

Climate Action Plan, which was adopted by the Anchorage Assembly in May.

The city also plans to install solar panels on Fire Station 10 and the Anchorage

Regional Landfill building, officials said.

—ASSOCIATED PRESS

ALTERNATIVE ENERGY

Steve DeWitt, U.S. Department ofEnergy, said the project wouldincrease knowledge of marineenergy systems, interaction of

underwater turbines with salmonand how system contribute to

providing stable power for localmicrogrids.

PETROLEUM NEWS • WEEK OF JULY 21, 2019 5

ABR Inc.AcurenAfognak Leasing LLCAirgas, an Air Liquide companyAK LoftsAlaska DreamsAlaska Frac Consulting LLCAlaska Frontier Constructors (AFC)Alaska Marine LinesAlaska MaterialsAlaska RailroadAlaska Rubber & Rigging Supply Inc.Alaska Steel Co.Alaska TextilesAlaska West ExpressAlpha Seismic CompressorsAmerican MarineArctic ControlsARCTOS Alaska, Division of NORTECHArmstrongASTAC Broadband, LLCAT&TAvalon DevelopmentAviator HotelBombay DeluxeBPBrandSafway ServicesBrooks Range SupplyCalista Corp.Carlile TransportationChosen ConstructionColville Inc.Computing AlternativesCONAM ConstructionCook Inlet Tug & BargeCruz Construction

Denali Industrial Supply, Inc.Denali Universal Services (DUS)Distribution NowDOWLDoyon AnvilDoyon AssociatedDoyon DrillingDoyon, Limitedexp Energy ServicesF. R. Bell & Associates, Inc.FairweatherFlowline AlaskaFluorFoss MaritimeFugroGMW Fire ProtectionGolderGreer Tank & WeldingGuess & Rudd, PCHDR, Inc.ICE Services, Inc.InspirationsJudy Patrick PhotographyLittle Red Services, Inc. (LRS)Lounsbury & AssociatesLynden Air CargoLynden Air FreightLynden Inc.Lynden InternationalLynden LogisticsLynden TransportMagTec AlaskaMapmakers of AlaskaMaritime HelicoptersNabors Alaska DrillingNalco Champion

NANA WorleyParsonsNEI Fluid TechnologyNordic CalistaNorth Slope TelecomNorthern Air CargoNorthern SolutionsNRC Alaska

PENCOPetroleum Equipment & Services, Inc.PND Engineers, Inc.PRA (Petrotechnical Resources of Alaska)Price Gregory InternationalRaven Alaska – Jon AdlerResource Development CouncilSALA Remote MedicsSaltchuk Alaska Family of Companies Carlile Transportation Systems Cook Inlet Tug & Barge Delta Western Petroleum Northern Air Cargo Tote Maritime AlaskaSecurity AviationSourdough ExpressStrategic Action AssociatesSummit ESP, A Halliburton ServiceTanks-A-LotThe Local PagesTOTE – Totem Ocean Trailer Express

Weston SolutionsWolfpack Land Co.Worley

A round of applause to Keiran Wulff and his team

at Oil Search on the closing of their company’s

$450 million deal with Armstrong for Pikka and Horseshoe area leases.

Keiran Wulff

Congratulations Oil Search!

‘Star’ candidate recruitedBut he did take the chance to crow

about recruiting a “star” Liberal candidate

in Montreal — an anti-pipeline activist

Trudeau said will ensure his government

(if re-elected) listens to the “voices of

Canadians.”

In defending his move to open the

Liberal doors to candidates who oppose a

fixed policy on proceeding with TMX, a

project that is owned outright by the

Trudeau government, he argued that his

administration “understands that

Canadians have a broad range of views on

a lot of different issues. That is why we

have a great and diverse team that we are

building.”

At the same time, he said the Trans

Mountain system is vital to get Canadian

crude resources to offshore markets,

regardless of pipeline opposition.

“In order to get on that path we need to

make sure we’re gathering together voic-

es from all different perspectives across

the country,” Trudeau said.

“The world has changed,” he said.

“We’re not in a situation where a govern-

ment can decide this is where we are lay-

ing down a railroad or a pipeline and it’s

just going to happen. The processes we

have to go through are more complicated

now.”

While Albertans were left to grapple

with Trudeau’s version of logic they are

doggedly pushing ahead with their own

efforts to rehire construction workers for

TMX this summer.

Project Reconciliation offerThe biggest of those hopes is now tied

to a formal offer by Project

Reconciliation, representing a large slice

of indigenous communities across British

Columbia, Alberta and Saskatchewan,

which has submitted to Trudeau’s office a

formal bid to acquire 51% of the Trans

Mountain pipeline system.

But Natural Resources Minister

Amarjeet Sohi kept a tight lid on how the

government will react to that proposal,

saying it won’t jump at the first offer on

the table.

He said Trans Mountain is an opportu-

nity for the Trudeau administration to

work with indigenous communities to

ensure they “benefit from economic

resource development.”

Delbert Wapass, executive chair of

Project Reconciliation, said the “reconcil-

iation pipeline” will deliver not just dilut-

ed bitumen from Alberta’s oil sands to the

Pacific Coast, but deliver optimism and

prosperity to First Nations.

“We’ve been so conditioned to admin-

istering poverty it’s time we started

administering wealth,” he said.

Project Reconciliation said it would

pay C$2.3 billion for a 51% share of the

existing pipeline and fund 51% of TMX

at a cost of C$4.6 billion, assuming

Trudeau government will retain 49% to

ensure the project moves forward.

New legal challengeNot so enthusiastic is a group of

British Columbia First Nations that has

filed new legal challenges of the

Canadian government’s latest round of

consultations with indigenous communi-

ties that they insist were no better than the

first and claim were tainted by the gov-

ernment’s desire to get TMX moving

ahead.

“The federal government is in a con-

flict of interest as the owner, regulator

and enforcer (of the project),” said Tsleil-

Waututh Nation Chief Leah Gorge-

Wilson, arguing the government’s deci-

sion to buy the existing Trans Mountain

pipeline and the planned TMX for C$4.5

billion means it is “impossible for them to

make an unbiased, open-minded deci-

sion.”

Perry Bellegarde, national chief of the

Assembly of First Nations, said an

indigenous stake in Trans Mountain

won’t end a national debate about

whether TMX should even proceed.

“Canadians are divided, provincial

premiers are divided, (indigenous) chiefs

are divided,” he said calling for “dia-

logue, discussions, debate and that the

rights and titleholders (along the TMX

right of way) determine the best next

steps.”

Compounding the legal tangle, two

British Columbia environmental groups

have started a lawsuit in the Federal Court

of Appeal, claiming the government

failed to meet its obligations to protect

endangered southern resident killer

whales.

Costs risingWhile litigation drags on, getting no

closer to a resolution, Trans Mountain

Corp., the federal government’s appoint-

ed agency for the pipeline system, said

the year-long delay in construction has

pushed the TMX costs above the most

recent estimate of C$7.4 billion to boost

capacity by 590,000 barrels per day to

890,000 bpd.

Ian Anderson, chief executive officer

of the corporation, said oil could be flow-

ing by mid-2022 if permits are granted

quickly, but declined to provide the

updated project budget, citing an uncer-

tain work schedule and regulatory

process.

However, he said Trans Mountain will

soon apply to the National Energy Board

for a license to resume work.

Regardless of the delays and squab-

bling, a new poll has reinforced broad

Canadian support for reapproval of the

TMX plans.

Conducted by Nanos, the poll showed

68% of Canadians either supported or

somewhat supported the decision, while

27% were opposed, with support peaking

at 84% in the three Prairie provinces to a

clear 61% in British Columbia and 56%

in Quebec, the two provinces where the

governments are resolutely opposed to

new oil pipelines. l

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continued from page 1

TRUDEAU TOUR

tease out more detail than was initially

apparent.

Houseknecht had hoped the reprocessed

data would be available to consortium com-

panies, but the U.S. Department of

Interior’s Office of the Solicitor ruled

against releasing it.

Nonetheless, with the aim of reducing

geological uncertainties the reprocessed 2D

data gave Houseknecht’s team a better

understanding of the area: “We are not per-

mitted to show or publish images of the

reprocessed ANWR data, so our public pre-

sentations use analogs from offshore and

state lands west of the Canning River. In

both areas, we are permitted to show images

of seismic data that we have licensed from

certain seismic companies,” he said.

Houseknecht presentationsHouseknecht has already released some

of his team’s updated 1002 area informa-

tion, starting with the Arctic Technology

Conference in October in Houston.

He has been using the title “Current and

future exploration frontiers in Arctic

Alaska,” covering his perspective of the

entire region, divided into six areas, one of

which is the ANWR 1002 area and the adja-

cent offshore.

He next spoke at the Arctic Oil and Gas

Symposium in Calgary, using the same title

and format, but adding even more new

information.

Both Houseknecht and Kate Whidden

presented at the AAPG Annual meeting in

San Antonio in May: “Dave Houseknecht:

Geological and petroleum systems frame-

work of the ANWR coastal plain,” a talk,

and the other a poster, which he said came

from “Whidden and others,” titled,

“Stratigraphy and facies of the Hue Shale in

northern Alaska: Evidence for a viable con-

tinuous resource play in an emerging

basin.”

Although the poster title does not specify

the ANWR 1002 area, it will include it and

state lands.

How soon will all the new information

be released?

“My slides and Kate Whidden’s poster

must go through USGS internal peer review

before we can release them, even on the

AAPG Search and Discovery site. Our field

season (which just started on the North

Slope) is delaying that process, but we hope

to complete the process by end of summer,”

Houseknecht said.

Big structures to east“Before we did our 1999 reassessment

there was a lot of consensus that big reser-

voir potential was in the eastern part of the

1002 area. The big structures that everyone

always coveted are there,” Houseknecht

said July 12.

Not having access to information from

the only well drilled in the 1002 area, the

KIC No. 1 in the deformed, or structural,

area, the USGS’s 1999 reassessment allo-

cated more oil to the undeformed, or strati-

graphic, section to the west — specifically

to the younger Brookian reservoirs versus

the deeper Ellesmerian reservoirs in struc-

tural traps on the eastern side.

USGS’s evaluation increased the mean

(50% probability) estimate of in-place total

1002 reserves from the 13.8 billion in its

1987 assessment to 20.7 billion barrels of

oil in 1999. And even though the agency

used a conservative oil recovery rate, which

was (at the time) approximately 33% lower

than that at Prudhoe Bay, and assumed it

would take a 512 million barrel field to be

commercial, the 1999 recoverable oil esti-

mates were still impressive, set between 5.7

billion and 16 billion barrels, with a mean

value of 10.4 billion barrels.

The increased numbers for the western

part of the 1002 area, which came in part as

a result of several new discoveries on the

North Slope since 1987, were not disputed

by industry or the state of Alaska.

Eastern decrease disputedBut the 1999 reassessment’s reduction of

recoverable reserves for the eastern part of

the area was questioned.

Even though they were forbidden by a

Supreme Court order from directly talking

about it publicly, the organizations that

questioned the 1999 assessment were the

agencies and companies who had access to

the most important geological data from the

ANWR 1002 area — the results of the KIC

No. 1 well.

In the eastern deformed area north and a

little west of the Niguanak High, a geologic

structure that the 1987 assessment credited

with something like 75% of the 1002 area’s

estimated reserves, was drilled to a depth of

15,193 feet at a cost of more than $40 mil-

lion. Drilled over two seasons by operator

Chevron and BP, the 50/50 partners leased

92,000 acres of Native land within the 1002

area. (The Native regional corporation for

PETROLEUM NEWS • WEEK OF JULY 21, 2019 7

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THE TEAM THAT

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continued from page 1

REVISITING ANWR

CO

URT

ESY

USG

S

Older map of the ANWR 1002 area shows the unnamed KIC No. 1 well as a tight hole in the deformed area and the Aurora well as an oildiscovery just offshore. The Native lands under lease by Chevron and BP encompass the two large structures, the Niguanak High (KIC well)and to the south, the Aurora Dome.

see REVISITING ANWR page 8

northern Alaska, Arctic Slope Regional

Corp., owns the subsurface oil and gas min-

eral rights and the village corporation in the

area, Kaktovik Inupiat Corp., owns the sur-

face, hence the well name KIC.)

Chevron, BP and ASRC unsuccessfully

sued the state in 1988 to keep the KIC well

results completely confidential, claiming

among other things that “three-fourths of

the land located within three miles” of the

well was unleased.

The court ruled that a limited release of

the information was permissible, so in addi-

tion to BP, Chevron and ASRC, a handful of

state of Alaska geoscientists have also been

able to see KIC well data.

The strongest public statement came in a

carefully worded statement from then-BP

spokesman Paul Laird to Petroleum News

following release of the 1999 reassessment.

He said USGS “did not have sufficient data

to substantiate the conclusion, or to justify

the conclusion, that most of the potential is

in the western 1002 area” and he re-stated

BP’s “belief in the prospectivity of the east-

ern 1002 area, as well as our belief in the

western 1002 area.”

Neil Ritson, then-exploration vice presi-

dent for BP in Alaska, was quoted in the

same time period in a press release about

BP and Chevron’s renewal of the 92,000-

acre Native lease as saying, “ANWR offers

the greatest potential for a world-class oil

discovery on the North Slope.”

Quoted in the same press release Dave

Birsa, Chevron exploration manager for

Alaska, said what state geoscientists have

continued to echo: “The ANWR coastal

plain … is on trend with the prolific oil

fields of the central North Slope and has

significant geological potential.”

Myers favored test well near KICIn 2003, when Mark Myers, then the

director of the division and privy to the KIC

well results, put together a plan for drilling

a stratigraphic test well on state lands off-

shore the 1002 area, his preferred location

for a test well was in the eastern deformed

area, southeast of the KIC well and just

north of the Niguanak High.

Common in frontier areas, a strat well

was designed to provide geologic data

about an area, such as defining the nature

of petroleum systems, identifying source

rock potential and assessing reservoir qual-

ity, etc. In this case the well would have

been funded by an industry consortium,

although for several reasons it never

became a reality.

In the 1999 assessment Houseknecht

said USGS recognized the big structures

in the east but assigned a “large uncertain-

ty” there, “so even though the mean value

was relatively low, there is good upside

potential.”

He said at the time (and partly repeated

in the July 12 interview), “it’s important to

distinguish between the results of our

assessment and what may or may not hap-

pen at a lease sale. … The oil industry has

demonstrated worldwide time and time

again that it will assume a lot of risk in test-

ing big structures — like those in the east-

ern 1002 area. And, those structures are so

large that they are well defined, even with

the relatively poor quality two-dimensional

seismic data that exists in the 1002 area.”

“The regional truncation of the older and

older rocks going north is what the concern

is in ANWR,” Houseknecht said in his lat-

est PN interview.

Prudhoe Bay-type reservoirs?The open file report done by USGS’

ANWR team in 1999 (98-34) is still basi-

cally representative of what is publicly

known to those who do not have access to

the vintage 2D seismic or the drilling results

from the KIC well, Houseknecht said.

Information on the bedrock geology of the

area comes mainly from surface exposures

in the mountains immediately south of the

1002 area and from wells to the west and

offshore.

The area to the south and east of the

Marsh Creek anticline is part of the Brooks

Range thrust and fold belt. In this part of the

1002 area deformation occurred episodical-

ly throughout the Cenozoic time

The answer to the question of whether

the Shublik source rock and Ellesmerian

strata (including the Ivishak) with Prudhoe

Bay-type reservoirs are present in the east-

ern part of the 1002 area — and specifically

in the area’s two large structures (the

Niguanak High and the Aurora Dome) — is

important to the region’s oil and gas poten-

tial, per the open file report and PN’s July

12 interview with Houseknecht.

It’s mainly the presence of the

Beaufortian rocks (Kingak shale) on the

surface in the Niguanak area and in the low-

ermost 1,200 feet of the offshore Aurora

well that offers the possibility of a big oil

discovery.

The KIC well and the Aurora well are

drilled on the same big structure; the adja-

cent map also shows the general location of

the other big structure, which is at a higher

elevation and to the south and east in the

Native land.

“In many ways the two structures are

look-alikes,” Houseknecht said. “They look

like they formed in the same way and have

very similar characteristics.”

There are a few blocks on either side of

the higher structure to the south outside the

Native-owned land (see adjacent map) that

will likely be offered in the upcoming

Interior lease sale. l

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holds the state’s oil and gas lease sales,

plans to switch to online sales.

Kyle Smith, petroleum land manager

at the division, told Petroleum News July

17 that the regulation changes address

various matters and said many of the reg-

ulations hadn’t been changed for 20 or 30

years, so were being updated to work

with today’s technology.

Adding online sales makes that option

possible, he said, but it doesn’t obligate

the division to hold online sales. A lot of

other states and the federal government

are holding online sales, Smith said, and

this updates Alaska’s business model.

And the division would still be required

to open and announce bids publicly, he

said.

The federal Bureau of Land

Management, which has been holding

annual lease sales in the National

Petroleum Reserve-Alaska on the state’s

North Slope, has been livestreaming its

bid openings.

The state’s fall bid opening is sched-

uled for Dec. 11 at 9 a.m. in the Dena’ina

Center. It includes the Beaufort Sea,

North Slope and North Slope Foothills

areawide sales, and the Gwydyr Bay,

Harrison Bay and Storms blocks within

the Beaufort and North Slope sales.

Proposed changesThe proposed change in the regula-

tion for method of bidding, which cur-

rently includes just “sealed bid or at pub-

lic outcry auction” is the addition of

“including online bidding” to methods.

A new section on bid service charges

says: “A bidder will be responsible for

commission or like compensation

payable to any third-party vendor host-

ing an online offering for submitted

bids; including handling and transfer of

bid deposits.”

The bid deposit requirement has been

repealed and readopted and covers cash;

cashier’s or certified check; money

order; and “electronic funds transfer,

wire transfer, or automated clearing

house transaction for the use and benefit

of the State of Alaska, including, if a

third-party vendor approved by the

department hosts an online disposal.”

Bids are amended to include online

bidding with bids submitted to the com-

missioner, other officer “or other entity

authorized by the commissioner con-

ducting the sale.”

The bid opening is amended by

adding bids received online to bids

which must be opened publicly.

Amendments not related to sales

include a new section which requires

that for leases with rental increases dur-

ing the primary term “an application for

a rental reduction determination under

the terms of a lease agreement must be

received at least 90 days prior to the

lease anniversary date where the rental

rate increases above $20.00 per acre,”

and must be on the form required by the

department.

A section is added requiring rental

payment to continue for a “lease that is

expired but otherwise remains subject to

a pending application or appeal.”

The comment period on the proposed

regulations closes Aug. 9, after which

DNR will either adopt the proposed reg-

ulation or other provisions dealing with

the same subject without further notice

or decide to take no action.

—KRISTEN NELSON

continued from page 1

REG CHANGEScontinued from page 7

REVISITING ANWR

PETROLEUM NEWS • WEEK OF JULY 21, 2019 9

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

jim5thgn@outlook.com,

jim@applecapital.net, or (907) 394-

9148.

10 PETROLEUM NEWS • WEEK OF JULY 21, 2019

company combined Alkaid with the nearby Phecda

prospect, a remapping process that included merging in

additional 3D seismic data. It showed Alkaid and Phecda

were part of the same Brookian structural accumulation.

Alkaid/Phecda was estimated to contain 900 million bar-

rels oil in place, with 90-135 million barrels of P50 techni-

cally recoverable oil.

In its mid-July update, Pantheon said the nearby Talitha

prospect was thought to also hold 900 million barrels of oil,

with the same recoverable resource.

The company also provided an update on the farmout

process.

Pantheon officials are working closely with geophysics

specialist eSeis on preparation of a data room, which was on

target to open later in July in Houston.

According to a June 24 Pantheon press release, eSeis

was under contract to “process, analyze and interpret geo-

physical data,” as well as “help manage Pantheon’s asset

sale process in Alaska.”

Furthermore, eSeis was doing the work for a “heavily

discounted rate” in exchange for a 1% overriding royalty

interest.

In its mid-July update, Pantheon said it had already been

approached by, and started discussions with, several indus-

try and financial groups and was hoping to drill a minimum

of two wells in “winter/spring 2019/2020, most likely one

at Talitha and one at Alkaid/Phecda.”

Generating early, regular cash flowThe Alkaid/Phecda oil field is near the Dalton Highway

and the trans-Alaska oil pipeline, possibly allowing for

some early year-round oil sales to generate income, which

is unusual for North Slope projects under development

since most of the region has no permanent roads. (Ice roads

and pads are allowed in roadless areas when the tundra is

frozen in the winter. Great Bear was previously allowed to

drill in the summer from rig mat drill pad locations along

the Dalton Highway.)

In a June 6 press release and webcast, Pantheon said it

would use mobile production units to handle output from

three or four delineation wells adjacent to the Dalton in the

highway’s already-established transportation corridor,

trucking the oil north to Pump Station No. 1 of the trans-

Alaska oil pipeline until full-scale development of approxi-

mately 50 wells and related infrastructure with a central

processing facility could be completed.

Pantheon expects the year-round operation of these three

or four wells will produce about 1,500 barrels of oil per day

each.

Technology has improvedAfter the March testing, Pantheon said its primary target,

the Brookian, was at an 8,100-foot depth, flowing 80-100

barrels per day of high quality, light oil (40 API) from a 6-

foot perforated interval within a 240-foot interval of net pay.

Future development wells will be drilled horizontally

and fracked, typical for North Slope Brookian develop-

ments, which Pantheon said, “should result in vastly

improved flow rates.” The Talitha exploration well will be

near the Pipeline State No. 1 discovery well drilled by

ARCO, predecessor to ConocoPhillips, in 1988

“They didn’t have 3D at the time. Drilling technologies

weren’t as advanced as they are today,” Bob Rosenthal,

Pantheon’s technical director, said in the June webcast.

“ARCO drilled the well looking for a thick, clean sand

and instead found a thick zone of interbedded, laminate-

type sands and shales. The sands were oil-bearing but at the

time given the … $10 price of oil and the fact completion

technology wasn’t as advanced as it is today, the well was

plugged and abandoned. … With today’s horizontal drilling

technology, we believe we have a significant discovery” at

Talitha, he said.

—KAY CASHMAN

continued from page 1

ALKAID HOPES

pletion of preliminary front-end engineering and design,

with the industry partners declining to move forward into

FEED based on economic issues, and AGDC taking over

on behalf of the state as the project’s sole proponent.

This was under former Gov. Bill Walker, who has been

a proponent of an Alaska LNG project for decades.

Using a tolling model, where infrastructure would be

paid for by shipping fees on the pipeline and processing fees

at the liquefaction facility, AGDC under Walker signed a

preliminary joint development agreement in November

2017 with China Petrochemical Corp., CIC Capital Corp.

and the Bank of China Ltd. to work on commercialization

of Alaska North Slope natural gas with 75% of the natural

gas going to China.

January updateIn a January presentation to the Alaska Support Industry

Alliance’s Meet Alaska Conference, Revenue

Commissioner Bruce Tangeman said Dunleavy was very

familiar with the Alaska LNG project and with mega proj-

ects and the stage-gate process because of the state’s former

industry partners. He said it was a great comfort that the

state doesn’t have to be out there welding pipe because it

had partners who’d done this around the world.

“We were going to jump on their back and ride them

across the finish line to a successful and profitable project,”

Tangeman said of the project when it included North Slope

producers as partners.

He emphasized that the initial goal of the project —

under its pre-Walker leadership — was a profitable eco-

nomic driven project, not a schedule driven project.

It has been several years since there was a stage-gate dis-

cussion, Tangeman said, and several years since the

Legislature has really been involved.

He said the Dunleavy administration looked forward to

re-engaging with its North Slope partners and said the

administration would be discussing the project with the

state’s former partners to see if they were interested in reen-

gaging with the state.

He emphasized that a stage-gate approach would be put

in place, “so we know — and Alaskans know — exactly

how we are going to move the project forward.”

Under the previous administration, 100% of the risk was

brought inhouse to the state. “Gov Dunleavy is not comfort-

able with that,” Tangeman said: It is important to bring part-

ners back in — if this is to move forward, the state needs to

share the risk.

In March, BP and ExxonMobil began working with the

state to evaluate project economics, and later committed to

participate financially.

CutbacksAGDC received lump-sum funding from the state

Legislature and required budgetary approval, but not an

annual budgetary allocation. It has been cutting back on its

spending for some time, stretching out monies it had as it

sought approval to accept third-party investment to move

the project forward, authority which it has not received.

AGDC’s goal under the Dunleavy administration has

been to complete the Federal Energy Regulatory

Commission permitting process. FERC issued a draft envi-

ronmental impact statement for the project at the end of

June, putting the project online to receive a final EIS next

year, followed by a record of decision for the project.

Following receipt of the FERC DEIS, AGDC reduced

staff.

It had been operating with 20 positions of an author-

ized 26.

AGDC released a statement from interim President Joe

Dubler July 11, describing cuts to staff.

“AGDC is restructuring to reflect our primary focus on

1completing the FERC permitting process to advance the

Alaska LNG project,” Dubler said. “AGDC will continue to

pursue FERC authorization, expected in June 2020, with an

eight-person technical staff plus contract support as needed,

and reduce employee headcount by twelve. Completing the

permitting process will substantially de-risk Alaska LNG

and open the door to a wider range of potential project par-

ties with the broad expertise required to unlock the value

and manage the risks associated with a project of this mag-

nitude.”

MOUDubler, who had been in senior leadership positions at

AGDC between 2010 and 2016, told legislators in March

presentations that one reason he was interested in coming

back to the project was that the Dunleavy administration

was working on re-engaging with the North Slope produc-

ers. All three were approached and BP and ExxonMobil

were willing to enter into a non-binding memorandum of

understanding.

Lt. Gov. Kevin Meyer told the Alaska Oil and Gas

Association’s annual conference in Anchorage May 30 that

BP and ExxonMobil were each contributing up to $10 mil-

lion toward getting the Alaska LNG project through FERC

certification, something he said AGDC estimated would

take another year and $30 million.

Under the MOU AGDC, BP and ExxonMobil had

undertaken a review of commercial and technical issues,

Dubler told legislators in March, with a meeting scheduled

in April in Houston with engineers from all three entities.

The goal, he said, was to lower the total installed cost.

The futureIn response to questions on the status of commercial and

marketing activities at AGDC following the current staff

cutbacks, Tim Fitzpatrick, AGDC vice president, external

affairs and government relations, told Petroleum News in a

July 17 email that AGDC is focused on completing FERC

permitting.

“The market, not the state, is better suited to unlock the

value and manage the risks associated with a project of this

magnitude. AGDC remains enthusiastic about the benefits

of monetizing North Slope natural gas and will continue to

represent the state in the project in its role as a sovereign

entity.” He said “AGDC believes that there may be a path

to commercial success for Alaska LNG. A successful com-

mercial outcome is more achievable if the project is led by

parties with the broad expertise required to unlock the value

and manage the risks associated with a project of this mag-

nitude.”

While AGDC completed the permitting for the in-state

project, the Alaska Stand Alone Pipeline, ASAP, and

shelved those permits, Fitzpatrick said “ASAP and Alaska

LNG share a number of permitting characteristics but the

business cases underlying each project are very different,”

with the economics for ASAP challenged because of

demand limits from Alaska’s small population — that proj-

ect is for in-state gas delivery only.

“Alaska LNG can overcome that challenge by monetiz-

ing a larger quantity of gas, both for in-state and export

sales. It will ultimately be up to the market to determine

whether Alaska LNG continues beyond the permitting

stage,” Fitzpatrick said.

—KRISTEN NELSON

The KLNG proponents applied to Canada’s National

Energy Board in April to almost double their LNG exports

to 18 million metric tons a year from 10 million metric tons

and double their license to 40 years from the 20 years pre-

viously granted — a permit that expires at the end of 2019.

The first phase of the revised KLNG plan would have

two trains of 6 million metric tons each for shipment to

Asia.

Work on the liquefaction site and tanker terminal has

already involved spending estimated at hundreds of mil-

lions of dollars at Kitimat on the northern B.C. coast, but

construction has been stalled for two years since the left-

wing New Democratic Party government of B.C. set new

targets for greenhouse gas emissions, regardless of the ear-

lier approval of the Royal Dutch Shell-led LNG Canada

project at Prince Rupert.

LNG Canada, backed by a C$225 million federal contri-

bution towards gas turbines, is scheduled to start exports in

2025.

KLNG has gone through a series of ownership shifts

since it was launched a decade ago, including Woodside’s

decision in 2015 to acquire a 50% stake from Apache.

The partnership has proposed to build Coastal GasLink

to deliver feedstock gas to the Kitimat liquefaction plant at

a cost of C$6.2 billion but faces a campaign by seven

Wet’suwet’en chiefs who want to block the pipeline.

However, Canada’s Finance Minister Bill Morneau

issued a warning in late June that any anti-pipeline protest-

ers should follow a B.C. Supreme Court injunction prevent-

ing pipeline workers from being blockaded.

—GARY PARK

continued from page 1

AGDC CUTS

continued from page 1

KITIMAT LNG

In its 11th Nikaitchuq plan of develop-

ment, which runs through September and

was approved by the Alaska Department of

Natural Resources and the U.S. Bureau of

Ocean Energy Management, Eni was look-

ing at converting eight existing wells into

multilaterals.

Per PN’s source, Eni plans multilateral

drilling after finishing NN-01 and drilling

NN-02. Not all eight wells will necessarily

get converted to multilaterals because Eni

will wait to first evaluate the results of the

first two.

The company is also tentatively planning

to do some new drilling in the Oooguruk

unit in 2020, where it assumed operatorship

on Aug. 1. (The Oooguruk plan of develop-

ment for 2020 is due Dec. 1.)

Finally, in 2018 when Eni acquired the

350,000 acres in 124 leases on the eastern

North Slope, the company said it planned to

“apply its business model and experience,”

involving “fast-track exploration” and “a

short time to market” for the “potential new

discoveries.”

The next step, per PN’s source, is seis-

mic-related work. It must be completed

before the drilling of an exploration well can

be approved and budgeted for 2020-21.

First goal 30,000 bpdAfter announcing it had acquired 100%

ownership and would eventually be taking

over operatorship of the Oooguruk unit, Eni

said it planned to drill more production

wells at both Oooguruk and its nearby

Nikaitchuq unit, with an initial target to

increase its total Alaska oil production to

more than 30,000 barrels per day.

Although new drilling is not yet taking

place in Oooguruk, the company is doing

some drilling in its Nikaitchuq unit.

In May, Oooguruk unit output averaged

9,293 bpd, with Nikaitchuq coming in at

16,640 bpd, a total of 25,933 barrels.

The Nikaitchuq unit, which began pro-

ducing oil in early 2011, lies north of the

Kuparuk River unit and northeast of the

adjacent Oooguruk unit that came online in

2008.

Wildcat drilling After an 11-year hiatus Eni returned to

explore in Alaska in late December 2017

with the spudding of the first of two ultra-

extended reach wells north from Spy Island,

a man-made Beaufort Sea island in the

Nikaitchuq unit.

The exploration program was expected

to take two years. Due to a series of delays,

drilling was still not able to be finished this

past winter.

In a May 2018 strategy meeting Eni

CEO Claudio Descalzi said the company

was doing well in Alaska and planned to

increase investment in the state; a statement

that proved true.

The current plan approved by DNR’s

Division of Oil and Gas and BOEM said the

drilling of the second exploration well, NN-

02, “targeting the same seismic anomaly of

the first well” was contingent upon NN-01

results.

The anomaly identified from 3D seismic

shot over Nikaitchuq North was not identi-

fied in the company’s approved plan. The

Schrader Bluff formation that is produced

from the Nikaitchuq unit is known to extend

a long way north under the Beaufort Sea,

but, there were some hints in Eni’s Oil

Discharge Prevention and Contingency Plan

application that appear to be based on tap-

ping the Jurassic Alpine sands, which would

certainly qualify as an anomaly in the area.

Whatever the case, the 25,957 bpd in the

contingency plan application could not be

referring to the heavy Schrader Bluff oil that

can’t flow unassisted.

Also, this and the measured depth and

angle of the well suggest one of the Jurassic

sands.

The previous Nikaitchuq unit operator,

Kerr-McGee, talked about the possibility of

testing the Jurassic Nuiqsut sandstone to the

north.

Expanding eastWhen Eni announced it had acquired

350,000 undeveloped exploration acres in

two blocks on the eastern North Slope from

Caelus Natural Resources, the company

said the acreage was relatively unexplored

but close to infrastructure, including the

trans-Alaska oil pipeline.

Shortly after acquiring the leases in

2015, Caelus attained 175 square miles of

new 3D seismic data and reprocessed anoth-

er 275 square miles of existing 3D to image

prospects in the acreage — data now held

by Eni.

“Adjacent infrastructure with available

capacity reduces threshold volumes

required for developing discoveries in the

sub-100 million barrels of oil recoverable

range,” Caelus said in 2015. “Multiple play

types within proven stratigraphic horizons

provide significant upside potential in previ-

ously poorly-imaged structural trends

and/or subtle stratigraphic traps.”

Surrounding legacy wells “confirm

deeper petroleum system elements and de-

risked shallower Brookian reservoirs and

hydrocarbon charge and phase within the

area,” Caelus said, much of which was

mostly ignored in North Slope drilling until

Armstrong and Repsol discovered major

oil finds in the Brookian Nanushuk at

Pikka and Horseshoe west of the central

North Slope. l

PETROLEUM NEWS • WEEK OF JULY 21, 2019 11

At Flowline Alaska, we’ve spent decades helping to

today and tomorrow.

(907) 456-4911

We know pipes.Inside and out.

continued from page 1

GOING FOR OIL

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Deadhorse

Prudhoe Bay

Milne Point

Duck Island

Liberty

BeecheyPoint

Kuparuk River

Oooguruk

Placer

Prudhoe Bay

Nikaitchuq

Guitar

Bear ToothGreaterMoosesTooth

NikaitchuqNorth

Pikka

SouthernMiluveach

Northstar

ColvilleRiver

Trans - Alaska Pipeline

Dalto

n Hw

y

Alaska Seaward Boundary

National PetroleumReserve - Alaska

Yellow represents a state of Alaska unit; green a federal unit; orange a state/federal unit; pale green a state/federal/Native unit; blue-gray a state/Native unit.

STA

TE O

F A

LASK

A

North Slope O&G units in area

EXPLORATION & PRODUCTIONUS drilling rig count down 5 to 958

On July 12 the number of rigs drilling for oil and natural gas in the U.S. was down

five from the previous week to 958.

A year ago, the count was 1,054 active rigs.

Houston oilfield services company Baker Hughes reported that 784 rigs targeted

oil (down four from the previous week) and 172 targeted natural gas (down two). Two

miscellaneous rigs were active (up one).

The company said 70 of the U.S. holes were directional, 831 were horizontal and

57 were vertical.

Colorado was up two rigs from the previous week; Louisiana and Oklahoma were

each up one.

In New Mexico, North Dakota, Ohio, Pennsylvania, Utah, West Virginia and

Wyoming the rig counts were unchanged from the previous week.

Alaska and California were each down one rig.

Texas, with the most active rigs in the country, 456, was down seven rigs from the

previous week.

Baker Hughes shows Alaska with eight rigs active, up two from a year ago.

The U.S. rig count peaked at 4,530 in 1981. It bottomed out in May 2016 at 404.

—KRISTEN NELSON

The company is also tentativelyplanning to do some new drilling

in the Oooguruk unit in 2020,where it assumed operatorship on

Aug. 1.

12 PETROLEUM NEWS • WEEK OF JULY 21, 2019

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