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l E X P L O R A T I O N & P R O D U C T I O N
l P I P E L I N E S & D O W N S T R E A M
l E X P L O R A T I O N & P R O D U C T I O N
Vol. 23, No. 36 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of September 9, 2018 • $2.50
page2
Alyeska to shrink workforce by 10percent as company restructures
Alyeska Pipeline Service Co., theoperator of the trans-Alaska pipeline,expects to shrink its workforce by 10 per-cent in conjunction with a major restruc-turing of the company, Tom Barrett, thecompany president, has announced in aletter to Gov. Bill Walker, Alaska legisla-tors and state commissioners. The joblosses will impact both companyemployees and contractors.
Barrett said that following an initia-tive launched in 2017, to investigate ways whereby Alyeskacould remain technically and economically viable through the
FERC sets schedule for finalAlaska LNG order under NGA
The Federal Energy Regulatory Commission said Aug. 31that it anticipates the issuance of a final order for the AlaskaLNG Project on Feb. 6, 2020. This is about a month earlierthan the March 8, 2020, date FERC published last March.
The Alaska Gasline Development Corp. filed an applica-tion for a permit under section 3 of the Natural Gas Act andPart 153 of FERC regulations on April 17, 2017. The applica-tion covers siting, construction and operation of a new LNGexport terminal and associated facilities near Nikiski, and con-struction of some 871 miles of natural gas pipeline and asso-ciated facilities.
The project would liquefy and export up to 20 million metric
Supreme Court reverses ruling onAlaskan Crude Moose Point lease
The Alaska Supreme Court has upheld an order by the AlaskaDepartment of Natural Resources terminating a lease held on thenorthwest coast of the Kenai Peninsula by Alaskan Crude Corp.,owned by Jim White, a veteran wildcat driller. The court decisionoverturns an earlier Alaska Superior Court ruling that had deter-mined that the lease termination had been invalid.
The lease in question, about 25 miles northeast of the city ofKenai, is the site of the Moose Point Unit No. 1 well, drilled inearly 1978 by Amarex Inc. The well reached a total depth of10,058 feet, was suspended in March 1978, and plugged andabandoned a year later.
State responds to production taxlawsuit by Exxon, Hilcorp, SAE
The state of Alaska has responded to a complaint filed inJune by Exxon Mobil Corp., Hilcorp Alaska LLC andSAExploration Inc., against the Alaska Department ofRevenue’s 2017 advisory bulletin which the complaint said“re-interprets Alaska’s tax code and regulations to increase thetax burden on taxpayers by approximately $110 million in2018 and to retroactively impose back taxes of $50 million(plus an unspecified amount of interest) for tax years 2014-2017.”
The complaint said the 2017 advisory bulletin reversed theposition the Department of Revenue had taken in a 2011 advi-sory bulletin, a reversal made without public comment or dueprocess.
see ALYESKA RESTRUCTURING page 12
see FINAL ORDER page 9
see RULING REVERSED page 6
see LAWSUIT RESPONSE page 8
State challenges tariff increase; RCA sets temporary PTE rate
Final SEIS is issuedBLM supports Conoco plan for Greater Mooses Tooth 2 development in NPR-A
By ALAN BAILEYPetroleum News
The federal Bureau of Land Management haspublished a final supplementary environmental
impact statement for ConocoPhillips’ GreaterMooses Tooth 2 development in the northeasternNational Petroleum Reserve-Alaska. Essentially,the SEIS has as its preferred option ConocoPhillips’plan to build a 14-acre drill pad that could host up to48 wells, to operate, in effect, as a satellite of theAlpine oil field in the Colville River Delta to theeast — produced fluids would be transported bypipeline via the Greater Mooses Tooth 1 pad to theAlpine central processing facility.
ConocoPhillips has previously said that it antic-ipates production rates in the range of 25,000 to
30,000 barrels per day from the project, and thatthe project will cost around $1.5 billion.
The SEIS supplements the EIS published in2004 for ConocoPhillips’ plan for the developmentof Alpine satellite fields. The SEIS also tiers ontoan EIS for BLM’s NPR-A Integrated Activity Plan,published in 2013. The Integrated Activity Planspecifies which areas within the NPR-A are open
Second NEWS phaseConoco schedules startup of Eastern NEWS for 2023; 10,000 bpd from NEWS
By TIM BRADNERFor Petroleum News
A laska producers are cracking the code in tap-ping a huge resource of thick “viscous” oil
on the North Slope. The latest project, called NorthEast West Sak, or NEWS, is now producing aboveprojections and was brought in at almost half ofestimated costs, said officials with ConocoPhillips,which is operating NEWS.
The company’s success has led it to plan anexpansion into the second phase of developmentcalled Eastern NEWS, now scheduled for a startupin 2023.
For decades companies have worked on waysof economically exploiting the West Sak, a large
deposit that overlays conventional oil reservoirs onthe Slope.
Efforts were frustrated, however, by the cool,thick nature of the oil — it flows like cooking oil,
Line takes legal blowCanada’s appeal court halts work on Trans Mountain, possibility of 2-stage rescue
By GARY PARKFor Petroleum News
C anada’s Federal Court of Appeal —second only to the nation’s
Supreme Court — wiped out thousandsof jobs and billions of dollars in govern-ment revenues while doing untold dam-age to Canada’s ability to attract invest-ment in resource projects in a single blowon Aug. 30.
A three-judge panel forced the National EnergyBoard to halt construction work on the C$9.4 bil-lion expansion of Trans Mountain’s pipeline fromAlberta to the Pacific Coast, generating an out-pouring of celebration among First Nations, envi-ronmentalists, some municipal governments and
the British Columbia administration ofleft-leaning Premier John Horgan.
The net result is that Canada’s lastserious hope of obtaining world pricesfor its oil sands production has beenthwarted, potentially adding TransMountain to a list of smoking carcasses,notably Enbridge’s Northern Gatewayproposal and Trans Canada’s plan forEnergy East.
If all three become historical foot-notes, Canada will have lost a chance to export 2.2million barrels per day of raw bitumen to Asia,Europe and even the Middle East, where producerscould have collected up to C$30 per barrel more
see FINAL SEIS page 11
see NEWS STARTUP page 10
see TRANS MOUNTAIN page 8
ConocoPhillips has proposed twoalternative development schedules for theproject, one starting in the fourth quarter
of 2018 and the other starting in thefourth quarter of 2019.
Driscoll said he believes the same kind ofincremental technical leaps that have
made West Sak viscous oil economicallyviable can be applied at Ugnu, the huge
heavy oil resource that has also beidentified on the slope. Ugnu oil is eventhicker or more difficult to produce than
the viscous oil.
RACHEL NOTLEY
TOM BARRETT
2 PETROLEUM NEWS • WEEK OF SEPTEMBER 9, 2018
GOVERNMENT
PIPELINES & DOWNSTREAM
3 National rig count rises by 4 to 1,048
4 Latest Hammerhead discovery 4B barrels
4 Protection for BSEE Alaska whistleblower
6 Kaktovik has boom in polar bear tourism
2 State challenges PTE tariff rate increase
Cost to move condensate from Point Thomson to Badamiwould increase to $20.84 per barrel; current rate, set by settlement, $12.09
3 ANS July production down 13% from June
July average 416,357 bpd, down 55,826 bpd from June;Alpine down 24,013 bpd due to planned maintenance; inlet average 14,904 bpd
10 Enbridge, Fond du Lac Band reach line deal
EXPLORATION & PRODUCTION
Final SEIS is issuedBLM supports Conoco plan for Greater Mooses Tooth 2
Second NEWS phaseConoco schedules startup of Eastern NEWS for 2023
Line takes legal blowCanada’s appeal court halts work on Trans Mountain
ON THE COVER
Alyeska to shrink workforce by 10 percentFERC sets schedule for finalAlaska LNG order under NGASupreme Court reverses ruling onAlaskan Crude Moose Point leaseState responds to production taxlawsuit by Exxon, Hilcorp, SAE
Petroleum News Alaska’s source for oil and gas newscontents
Alaska’sOil and GasConsultants
GeoscienceEngineeringProject ManagementSeismic and Well Data
3601 C Street, Suite 1424Anchorage, AK 99503
(907) 272-1232(907) 272-1344
l P I P E L I N E S & D O W N S T R E A M
State challenges PTE tariff rate increaseCost to move condensate from Point Thomson to Badami would increase to $20.84 per barrel; current rate, set by settlement, $12.09
By KRISTEN NELSONPetroleum News
The Regulatory Commission of Alaska has suspendedPTE Pipeline LLC’s tariff revision and established a
temporary rate equal to the filed rate, subject to refundwith interest, the commission said in an Aug. 29 order.
On July 30, PTEP LLC filed a revenue requirementstudy based on a 2017 case year and proposed a new rateof $20.84 per barrel. The state protested the increased tar-iff and petitioned to intervene in the proceeding, a peti-tion which RCA accepted.
The tariff is for the 22-mile line between the PointThomson unit on Alaska’s North Slope and the BadamiPipeline. The line, owned 68 percent by ExxonMobilPipeline Co. and 32 percent by BP Transportation(Alaska) Inc., went into operation in 2016, moving con-densate from the Point Thomson field.
In 2015 PTE proposed a rate of $20.39 per barrel; boththe state and ConocoPhillips protested. RCA accepted a
settlement rate of $12.09 per barrel effective April 1,2017, based on expected volumes, replacing a rate of$17.56 per barrel which replaced the proposed rate. The$12.09 rate was to end when PTE Pipeline placed newrates into effect, no later than July 1, 2019.
State’s objectionIn its Aug. 20 protest, the Alaska Attorney General’s
office said the proposed tariff “is unjust and unreasonablebecause the proposed tariff rate is based on unsupportedand unexplained assumptions and assertions.”
The proposed new tariff, $20.84, is a 41.9 percentincrease from the settlement rate, the state said.
On specifics of the rate, the state argued the weighted
average cost of capital of 9.68 percent includes a returnon equity of 14.23 percent, “too high relative to otherpipeline carriers in Alaska.” It includes a 1 percent riskpremium.
That risk premium is based on upstream operationalproblems, the state said, adding that “short-term opera-tional issues should not justify a long-term risk premi-um.”
The state said PTE “inadequately supports operatingand maintenance costs,” with are based on master servic-es and operating services agreements provided at cost,but without “data or documents to substantiate the claimthat these services are in fact ‘at cost.’”
The state said throughput estimates are unreasonablylow since the pipeline’s upstream partner “intends to ship10,000 barrels of gas condensate per day.”
The state said it is engaged in discussions with thepipeline “in an attempt to narrow the issues that will bethe subject of this proceeding or potentially to resolve the
PTE also argues that the 4,500-bpd estimate ofthroughput is lower than the rate for calendaryear 2017 but reflects the lower throughput in
the first six months of 2018.
see PTE TARIFF page 4
FINANCE & ECONOMY
To advertise in Petroleum News, contact Susan Crane
at 907.770.5592
By KRISTEN NELSONPetroleum News
Alaska North Slope production, crudeoil and natural gas liquids, averaged
416,357 barrels per day in July, down 12.8percent, 55,826 bpd, from a June averageof 477,364 bpd, and down 4.7 percentfrom an average of 437,067 bpd in July of2017.
The current month-over-month dropwas triggered by summer maintenanceshutdowns, with Alpine down completelyfor more than half of the month and overallSlope production slowed by a 12-hourshutdown of the trans-Alaska oil pipelineJuly 6.
Unless otherwise noted, productiondata is from the Alaska Oil and GasConservation Commission, which pro-vides volumes by well on a month-delaybasis.
Alpine, the ConocoPhillips Alaska-operated Colville River unit, had thelargest month-over-month per-barrel drop,averaging 24,013 bpd in July, down 61.7percent, 38,625 bpd, from a June averageof 62,638 bpd. The field was down 59 per-cent from a July 2017 average of 58,556bpd.
This year’s decline was due to plannedmaintenance. ConocoPhillips toldPetroleum News in June that “a majormaintenance shutdown” was planned forAlpine in mid-July. The field went offlineJuly 13 according to data from theDepartment of Revenue’s Tax Division;the restart began Aug. 13. In addition to oilfrom the main Alpine pool, Colville pro-duction includes satellite production fromFiord, Nanuq and Qannik.
The ExxonMobil Production-operatedPoint Thomson field had the largestmonth-over-month percentage drop, 94.2percent, averaging 72 bpd in July, down1,170 bpd from a June average of 1,242,and down 96 percent from a July 2017average of 1,739 bpd. Facilities at PointThomson were built to handle 10,000 bpdof condensate, but compressor problemshave plagued the field, which came onlinein April 2016.
Prudhoe, KuparukThe BP Exploration (Alaska)-operated
Prudhoe Bay field, the North Slope’slargest, averaged 226,020 bpd in July,191,327 bpd of crude and 34,693 bpd ofNGLs, a combined drop of 5.2 percent,12,422 bpd, from a July average of238,442 bpd, but an increase of 9.2 percentover a July 2017 average of 207,028 bpd.Production from the Prudhoe Bay fieldincludes Aurora, Borealis, Lisburne,Midnight Sun, Niakuk, Polaris, PointMcIntyre, Put River, Raven and SchraderBluff.
The ConocoPhillips-operated KuparukRiver field averaged 102,274 bpd in July,down 5.6 percent, 6,051 bpd, from anaverage of 108,325 bpd in June, and down0.4 percent from a July 2017 average of102,682 bpd. In addition to the main pool,Kuparuk produces from satellites atMeltwater, Tabasco and Tarn, and fromWest Sak.
Other Slope fieldsThe Hilcorp Alaska-operated Milne
Point field averaged 17,346 bpd in July,down 14.4 percent, 2,913 bpd, from a Juneaverage of 20,259 bpd, and down 14.5 per-cent from a July 2017 average of 20,296bpd.
Nikaitchuq, operated by Eni, averaged18,454 bpd in July, down 3.7 percent, 715bpd, from a June average of 19,170, anddown 12.4 percent from a July 2017 aver-age of 21,070 bpd.
The Caelus Alaska-operated Ooogurukfield averaged 9,696 bpd in July, down 9.9percent, 1,062 bpd, from a June average of10,758 bd, and down 1.4 percent from aJune 2017 average of 9,831 bpd.
The Hilcorp-operated Endicott fieldaveraged 6,619 bpd of crude and 649 bpdof NGLs in July, a combined 7,268 bpd, up0.3 percent from a June combined averageof 7,248, and up 2.2 percent from a July2017 average of 7,113 bpd.
Northstar, also operated by Hilcorp,averaged 8,167 bpd of crude and 1,184bpd of NGLs in July, a combined 9,351bpd, up 33.7 percent from a June com-bined average of 6,996 bpd and up 18.6percent from a July 2017 average of 7,885bpd.
Badami, operated by Glacier Oil & Gassubsidiary Savant Alaska, averaged 1,862bpd in July, down 14.6 percent, 318 bpd,from a June average of 2,180 bpd, but up114.7 percent from a July 2017 average of867 bpd.
Cook InletCook Inlet averaged 14,904 bpd in July,
marginally down from 14,914 bpd in June,and down 1.8 percent from a July 2017average of 15,176 bpd.
Hilcorp-operated Beaver Creek aver-aged 84 bpd in July, up 26 percent from aJune average of 67 bpd and down 96.3 per-cent from a July 2017 average of 177 bpd.
Granite Point, also operated by Hilcorp,averaged 2,846 bpd in July, down margin-ally from 2,848 bpd in June and up 21.5
percent from a July 2017 average of 2,343bpd.
The BlueCrest operated Hansen field,the Cosmopolitan project, averaged 865bpd in July, up 7.9 percent from a Juneaverage of 801 bpd and up 214.4 percentfrom a July 2017 average of 275 bpd.
Hilcorp’s McArthur River field, CookInlet’s largest, averaged 4,765 bpd in July,down 4.2 percent from a June average of4,973 bpd and down 4.3 percent from aJuly 2017 average of 4,981 bpd.
Middle Ground Shoal, also operated byHilcorp, averaged 1,219 bpd in July, up26.6 percent from a June average of 963bpd; the field had no production in July2017.
Redoubt Shoal, a Glacier Oil & Gasfield, averaged 1,287 bpd in July, up 2.2percent from a June average of 1,260 bpdand down 35 percent from a July 2017average of 1,980 bpd.
Hilcorp’s Swanson River field aver-aged 1,290 bpd in July, down 11.1 percentfrom a June average of 1,450 bpd, anddown 34 percent from a July 2017 averageof 1,953 bpd.
Trading Bay, also operated by Hilcorp,averaged 1,554 bpd in July, down 0.7 per-cent from a June average of 1,565 bpd anddown 25.6 percent from a July 2017 aver-age of 2,089 bpd.
Glacier’s West McArthur River fieldaveraged 994 bpd in July, up 0.7 percentfrom a June average of 987 bpd and down27.9 percent from a July 2017 average of1,378 bpd.
ANS crude oil production peaked in1988 at 2.1 million bpd; Cook Inlet crudeoil production peaked in 1970 at more than227,000 bpd. l
l E X P L O R A T I O N & P R O D U C T I O N
ANS July production down 13% from JuneJuly average 416,357 bpd, down 55,826 bpd from June; Alpine down 24,013 bpd due to planned maintenance; inlet average 14,904 bpd
PETROLEUM NEWS • WEEK OF SEPTEMBER 9, 2018 3
COMPANIES
37 yearsBUILDING ALASKAF O R M O R E T H A N
Experts in Resource Development and Heavy Civil Construction
Cruz Construction | Alaska Interstate Construction
Cruz Energy Services | Cruz MarineA CIRI Company A CIRI Company
EXPLORATION & PRODUCTIONNational rig count rises by 4 to 1,048
The number of rigs drilling for oil and natural gas in the U.S. increased by fourthe week ending Aug. 31 to 1,048.
At this time a year ago there were 943 active rigs. Houston oilfield services company Baker Hughes reported that 862 rigs target-
ed oil (up two from the previous week) and 184 targeted gas (also up two). Twowere listed as miscellaneous (no change).
Among major oil- and gas-producing states, Louisiana gained one. New Mexicoand Oklahoma each lost one. Alaska, California, Colorado, North Dakota, Texasand Wyoming were unchanged.
The U.S. rig count peaked at 4,530 in 1981. It bottomed out in May 2016 at 404.—PETROLEUM NEWS
The current month-over-monthdrop was triggered by summermaintenance shutdowns, with
Alpine down completely for morethan half of the month and overallSlope production slowed by a 12-
hour shutdown of the trans-Alaskaoil pipeline July 6.
4 PETROLEUM NEWS • WEEK OF SEPTEMBER 9, 2018
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+1.907.868.1185
State’s concerns.”
PTE responsePTE Pipeline responded to the state’s
protest Aug. 24. In response to issuesregarding lack of adequate detail, PTEsaid that to the extent more detail is need-ed, it would provide that once investiga-tion in the docket gets underway.
Among issues to which PTE respondedwere the risk premium. In the response,PTE noted testimony that risks faced bythe pipeline are considerably greater thanthe proxy group and are the same as manyrisks faced by the trans-Alaska oilpipeline in its early years — with addi-tional development risks not faced by theoil line.
PTE disputed the state’s contention
that the stated intention at Point Thomsonwas to produce 10,000 bpd; what theupstream partner has said, PTE argues, isthat the Point Thomson production facili-ties are designed to produce up to 10,000bpd of condensate.
PTE also argues that the 4,500-bpdestimate of throughput is lower than therate for calendar year 2017 but reflects thelower throughput in the first six months of2018.
RCA has appointed a panel to hear theissue, appointed an administrative lawjudge and suspended the proposed tarifffor an initial period of six months, endingMarch 1, 2019, during which the proposedtariff will be collected, subject to refundof the difference between the temporaryrate and the final rate determined by thecommission, with interest. l
continued from page 2
PTE TARIFF
EXPLORATION & PRODUCTIONLatest Hammerhead discovery 4B barrels
ExxonMobil has named its latest oil discovery Hammerhead, but instead of beingoffshore Alaska’s North Slope, this Hammerhead is offshore the tiny South Americannation of Guyana.
The 4 billion-barrel discovery was announced Aug. 30 by Exxon, which notedHammerhead was its ninth offshoreGuyana discovery.
According to a recent statement byWood Mackenzie, a trusted source of com-mercial information about the world’s nat-ural resources, Exxon’s exploration successin the last few years has been 82 percentand established the Guyana basin as one ofthe world’s offshore exploration hot spots.
Alaska’s Hammerhead, renamed Sivulliq by Shell in 2016, straddles an area northof the boundary between state-owned North Slope land and ANWR’s 1002 area. Inthe western part of Camden Bay, the federal prospect is northeast of Exxon’s PointThomson field and has a known oil pool between 100 million to 200 million barrelsin size, per a well drilled by Unocal in the mid-1980s.
Because it was too far from infrastructure at the time — not the case today — thereservoir has not been delineated. In 2012, Shell started drilling an exploration wellat Hammerhead but was only able to complete the top hole section of the well.
Arctic Slope Regional Corp.’s exploration arm, AEX, has since acquired the leas-es from Shell.
—KAY CASHMAN
The 4 billion-barrel discoverywas announced Aug. 30 by
Exxon, which notedHammerhead was its ninthoffshore Guyana discovery.
l G O V E R N M E N T
Protection for BSEEAlaska whistleblower
By DAN JOLINGAssociated Press
The federal office that protects employ-ees against reprisals for whistleblow-
ing is advocating on behalf of a federalemployee in Alaska who complained aboutthe handling of an Arctic offshore lease sale.
The U.S. Office of Special Counselannounced Aug. 28 it’s filing a whistleblow-er retaliation complaint with the MeritSystems Protection Board on behalf ofJeffrey Missal, a regional environmentalofficer for the Department of the Interior’sBureau of Safety and EnvironmentalEnforcement.
Missal was fired after filing a complaintwith the Interior Department’s inspectorgeneral and contending that the departmentviolated environmental regulations to facili-tate Arctic oil exploration.
Interior Department spokeswomanHeather Swift said by email she could notimmediately comment because the com-plaint was a personnel matter.
Missal has been represented by theGovernment Accountability Project, awhistleblower advocacy organization.Missal was fired in January 2016, but theboard halted the termination in August 2017.
“This reprieve kept Mr. Missal from los-ing his home,” the advocacy group said in arelease Aug. 28.
Missal’s work has been restricted at theBureau of Safety and EnvironmentalEnforcement, the group said.
“Even after putting Mr. Missal back onpayroll, it has continued to violate many ofthe details of MSPB stay orders by continu-ing to isolate him and intentionally restrict-ing his normal duties,” said Tom Devine,Missal’s attorney from the advocacy group,
in a prepared statement. According to the Office of Special
Counsel, Missal in 2012 began expressingconcern that the Interior Department hadviolated environmental regulations to facili-tate oil exploration in the Arctic Ocean.
Records from the Merit SystemProtection Board indicate that Missalbelieved the Bureau of Safety andEnvironmental Enforcement violated theenvironmental review process for a leasesale in the Chukchi Sea off Alaska’s north-west coast.
When Missal was not satisfied with theinternal response to his complaints, he fileda complaint with the department’s inspectorgeneral.
In 2014, on the same day a senioremployee was informed of the inspectorgeneral’s inquiry, the senior employeelaunched an investigation of Missal.
Missal was fired based on alleged mis-conduct discovered in the investigation.However, the Office of Special Counselconcluded the termination was retaliatoryfor his complaint to the inspector general.
Missal was reinstated for 45 days inAugust 2017. The special counsel since thenhas obtained eight more stays of the firingwhile negotiating to resolve the case.
The Interior Department has declined toprovide corrective action, so the officemoved forward with a complaint to theMerit Systems Protection Board, saidZachary Kurz, spokesman for the Office ofSpecial Counsel.
“Whistleblowers must have confi-dence they can report wrongdoing with-out facing retaliation,” said SpecialCounsel Henry J. Kerner in the announce-ment. l
Congratulations Hilcorp!
Afognak Leasing LLCAir LiquideAlaska Energy Services, LLCAlaska 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 Catering & Support ServicesArctic ControlsArctic Fox EnvironmentalArctic Slope Telephone Assoc. Coop (ASTAC)Arctic Wire Rope & SupplyARCTOS Alaska, Division of NORTECHArmstrongASRC Energy ServicesAT&TAvalon DevelopmentAviator HotelBombay DeluxeBPBrandSafway ServicesBrooks Range SupplyCalista Corp.Chosen ConstructionCMS, Inc./Hepworth AgencyColville Inc.
Computing AlternativesCONAM ConstructionCruz ConstructionDenali Universal Services (DUS)Dowland-Bach Corp.Doyon AnvilDoyon AssociatedDoyon DrillingDoyon, Limitedexp Energy ServicesF. R. Bell & Associates, Inc.FairweatherFlowline AlaskaFluorFoss MaritimeFrost Engineering Service Co.- NWFugroGeotempsGMW Fire ProtectionGolderGreer Tank & WeldingGuess & Rudd, PCInspirationsJudy Patrick PhotographyKuukpik Arctic ServicesLast Frontier Air VenturesLittle Red Services, Inc. (LRS)Lounsbury & AssociatesLynden Air CargoLynden Air FreightLynden Inc.Lynden InternationalLynden LogisticsLynden TransportMapmakers of Alaska
MAPPA TestlabMaritime HelicoptersMotion & Flow Control ProductsNabors Alaska DrillingNalco ChampionNANA WorleyParsonsNEI Fluid TechnologyNordic CalistaNorth Slope TelecomNorthern Air CargoNRC Alaska
PENCOPetro Star LubricantsPetroleum Equipment & Services, Inc.PND Engineers, Inc.PRA (Petrotechnical Resources of Alaska)Price Gregory InternationalResource Development CouncilSAExplorationSecurity AviationSolar Turbines IncorporatedSourdough ExpressSSS Commercial Real Estate Stewart Smith & Jim PattonSTG, Inc.Tanks-A-LotThe Local PagesThompson Metal Fab, Inc.
Unique MachineVolant ProductsWaste ManagementWeston Solutions
The Bureau of Ocean Energy Management has issued a final Environmental Impact Statement for
Hilcorp Alaska’s planned Liberty oil field development offshore in the Beaufort Sea. The agency has
confirmed a preferred alternative accepting Hilcorp’s proposal to develop the field from a small gravel
island about five miles offshore and the laying of a buried subsea pipe-in-pipe pipeline to carry crude oil to shore. The pipeline would connect with the
existing Badami pipeline for transporting the Liberty oil to the trans-Alaska pipeline.
Hilcorp has previously said it hopes to start building the island in late 2019, with the laying of the subsea pipeline in the following winter and first oil from the
field likely flowing in 2022. The field is thought to hold around 120 million
barrels of recoverable oil.Dave Wilkins and team, we appreciate your on-going efforts in Alaska oil and gas exploration,
development and production.David Wilkins, senior vice president ,
Hilcorp Alaska
PETROLEUM NEWS • WEEK OF SEPTEMBER 9, 2018 5
6 PETROLEUM NEWS • WEEK OF SEPTEMBER 9, 2018
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American MarineServices Group
6000 A Street, Anchorage, AK 99518
907-562-5420Deadhorse, AK
907-659-9010www.amarinecorp.com • www.penco.org
FINANCE & ECONOMYKaktovik has boom in polar bear tourism
A tiny Alaska Native village has experienced a boom in tourism in recent years aspolar bears spend more time on land than on diminishing Arctic sea ice.
More than 2,000 people visited the northern Alaska village of Kaktovik on theBeaufort Sea last year to see polar bears in the wild, Alaska’s Energy Desk reportedSept. 3.
The far north community is located on the north shore of Barter Island on theBeaufort Sea coast in an area where rapid global warming has sped up the movementof sea ice, the primary habitat of polar bears. As ice has receded to deep water beyondthe continental shelf, more bears are remaining on land to look for food.
The village had less than 50 visitors annually before 2011, said Jennifer Reed, ofthe Arctic National Wildlife Refuge.
“Today we’re talking about hundreds and hundreds of visitors, many from aroundthe world each year,” Reed said.
More bears staying on landPolar bears have always been a common sight on sea ice near Kaktovik, but resi-
dents started noticing a change in the mid-1990s. More bears seemed to stay on land,and researchers began taking note of more female bears making dens in the snow onland instead of on the ice.
U.S. Fish and Wildlife Service biologists began hearing reports of increasing num-bers of polar bears in the area in the early 2000s, Reed said. As more attention wasgiven to the plight of polar bears about a decade ago, more tourists started heading toKaktovik.
Most tourists visit in the fall, when bears are forced toward land because sea ice isthe farthest away from the shore. Some bears become stranded near Kaktovik until thesea freezes again in October or November.
The fall is also when residents of Kaktovik kill three bowhead whales. BruceInglangasak, an Inupiaq subsistence hunter who offers wildlife viewing tours, said res-idents were unsure how tourists would react to whaling.
“The community was scared about, you know, activists that was going to try to getus to shut down the whaling — subsistence whaling,” Inglangasak said. “But that’snot true.”
Inglangasak said he’s been offering polar bear tours since 2003 or 2004. Most of his clients are from China and Europe, as well as from the Lower 48 U.S.
states and arrive in Kaktovik on charter planes from Anchorage and Fairbanks. Many tourists stay several days in the village, which has two small hotels,
Inglangasak said. —ASSOCIATED PRESS
Acquired in 2003In 2003 Alaskan Crude acquired the
lease containing the well from lease own-ers, who had acquired the lease in a2001state oil and gas lease sale. The term ofthe lease was seven years, so that the leasewas scheduled to terminate at the end of2008.
But, because the well lay within 1,500feet of a property line, White had to apply tothe Alaska Oil and Gas ConservationCommission for a spacing exception, toprotect the rights of adjacent landowners.The AOGCC issued a conservation order inMarch 2005, allowing the well re-entry andtesting, but prohibiting any production fromthe well until after a commission hearingregarding the ownership rights over the sub-surface resources.
White has told Petroleum News that theMoose Point prospect has high potential forboth oil and gas and that he started drillingoperations at the well in the winter of 2005-06, with drilling recommencing in 2007.White funded the project entirely by him-self, underwriting the project risks.
Unstable gas marketThe Moose Point well is situated not far
from the Kenai Peninsula gas pipeline infra-structure.
And the market for gas from the CookInlet basin impacted Alaskan Crude’s proj-ect, with drilling halting in response to themothballing of the fertilizer plant at Nikiskion the Kenai Peninsula in September 2007— White had seen the fertilizer plant as aprospective buyer of gas from his lease.However, 2008 saw an agreement betweenthe Palin administration and the owners ofthe Nikiski liquefied natural gas plant forstate support for the plant’s export licenseextension in 2009, if the plant owners madeat least 30 million cubic feet per day ofplant capacity available for purchase fromnon-owner Cook Inlet gas producers. Inresponse, White returned to drilling atMoose Point. But, with a mild early winterand with frozen ground being needed foraccess to the well site, drilling operationscould not mobilize until Dec. 20, he toldPetroleum News.
Lease terminationOn Dec. 31, 2008, the last day of the
lease term, a DNR inspector observeddrilling equipment, including a drilling rig,and evidence of well entry at the well site.But on Jan. 2, 2009, DNR notified Whitethat the lease had been terminated.
White subsequently asserted that he hadactually been drilling at the well site on thelease expiry day and that the rules for thelease require a lease extension to be grant-
ed, if drilling is in progress on the date onwhich the lease would otherwise expire.Following an appeal to DNR, the DNRcommissioner withdrew the lease termina-tion notice. However, as a condition for thelease extension, the commissioner requiredAlaskan Crude to continue drilling a welland to complete the well by April 27, 2009,with production from the well to start with-in 90 days of the end of drilling.
Appeal against DNR termsWhite protested, arguing that the April
27 deadline represented a modification tothe original lease terms. White also said thatit would not be prudent to immediately riskfurther capital on the drilling project, giventhe risk of not being able to complete thedrilling before the end of the winter drillingseason. In July 2009 DNR terminated thelease.
When an appeal to the DNR commis-sioner failed to reverse the July lease termi-nation decision, White launched an admin-istrative appeal in Superior Court. TheSuperior Court judge upheld AlaskanCrude’s position, saying that the lease didnot require completion of the well by anyspecific date and did not require it to havesustained production within 90 days. Thejudge said that DNR had not allowed for thedifficulty of continuing the drilling, giventhe need for winter conditions for siteaccess. The court also observed that theAOGCC order for the well precludedAlaskan Crude from complying withDNR’s deadline for the commencement ofproduction.
DNR appealed the Superior Court rulingto the state Supreme Court.
Supreme Court supports DNRThe Supreme Court agreed with the
Superior Court that DNR’s January 2009lease termination had been invalid and hadbreached the terms of the lease. But, whileagreeing that DNR’s subsequent re-instate-ment of the lease cured that breach, thecourt took a view that the April drillingdeadline that DNR had imposed was a jus-tifiable expectation, if Alaskan Crude wereto continue drilling the well with reasonablediligence. And the court agreed with DNRthat, although the dispute over the lease ter-mination had delayed the drilling program,Alaskan Crude would have been able tocontinue the drilling in 2009 within the peri-od of winter conditions at the well site.
White told Petroleum News that, if thedrilling had not been delayed as a result ofthe lease termination dispute, AlaskanCrude could have completed the well.
And despite the setback, White is deter-mined to continue with his ventures, seek-ing wildcat drilling opportunities.
“I’m still here,” White said.—ALAN BAILEY
continued from page 1
RULING REVERSED
PETROLEUM NEWS • WEEK OF SEPTEMBER 9, 2018 7
Congratulations ConocoPhillips!
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Colville Inc.Computing AlternativesCONAM ConstructionCruz ConstructionDenali Industrial Supply, Inc.Denali Universal Services (DUS)Dowland-Bach Corp.Doyon AnvilDoyon AssociatedDoyon DrillingDoyon, LimitedExxonMobilexp Energy ServicesF. R. Bell & Associates, Inc.FairweatherFlowline AlaskaFluorFoss MaritimeFugroGeotempsGMW Fire ProtectionGreer Tank & WeldingGuess & Rudd, PCHand-Y-BermHawk Consultants LLCHDL Engineering Consultants, LLCHDR, Inc.ICE Services, Inc.InspirationsJacobsJudy Patrick PhotographyKuukpik Arctic ServicesLast Frontier Air VenturesLittle Red Services, Inc. (LRS)Lounsbury & AssociatesLynden Air CargoLynden Air FreightLynden Inc.Lynden International
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Hats off to Conoco as it continues to move forward on its plans for a standalone Willow processing facility west of the central North Slope. The project will include the construction, operation and main-tenance of a central processing facility; the construction of up to five well pads, with up to 50 wells on each pad; roads, an air-strip, pipelines and construction of a temporary Beaufort island to facilitate the delivery of project modules. As BLM starts EIS scoping for Willow, Acting State Director Karen Mouritsen says “analyzing the proposed Willow prospect in a single MDP/EIS will result in a quicker and more efficient process for the approval of applications for permits to drill.” ConocoPhillips recently upped its estimated recoverable oil from Willow to 400-750 million barrels, with peak production rates near 100,000 barrels per day. Investment looks to be $2-3 billion over four to five years, with first oil flowing by 2024 to 2025. An additional $2-3 billion would then be spent on cumu-lative drilling over multiple years to sustain production. The Willow discovery involves reservoir sands in the Nanushuk formation, in a near identical geologic setting to the huge Pikka/Horseshoe field that Oil Search and partners Armstrong and Repsol plan to develop on the other side of the Colville River.
Joe Marushack, President ConocoPhillips Alaska
8 PETROLEUM NEWS • WEEK OF SEPTEMBER 9, 2018
than they receive from buyers in theUnited States.
Ironically, the verdict was deliveredless than an hour before shareholders ofKinder Morgan (the owner of TransMountain) voted by 99 percent in favor ofselling the existing 300,000 bpd TransMountain system to the Canadian govern-ment for C$4.5 billion, plus the rights toadd 590,000 bpd of new capacity to thepipeline.
The hunger for an expanded TransMountain was reflected in producer nom-inations for space on the pipeline whichwere oversubscribed by 46 percent in Julyand 43 percent in June.
Government optionsThe government of Prime Minister
Justin Trudeau now has the option to returnthe Trans Mountain application to the NEBfor review and to meet the federal court’sdemand for a new phase of consultationwith First Nations affected by the project,or to appeal directly to the Supreme Courtof Canada.
Appeal court Justice Eleanor Dawsonsaid the Trudeau government had failed,despite nine months of consultations, to“engage, dialogue meaningfully and grap-ple with the real concerns of (indigenouscommunities) to explore the possibleaccommodation (of their) concerns. Theduty to consult was not adequately dis-charged.”
The court also said the NEB review ofKinder Morgan’s application did not give
full consideration to the impact anincreased number of tankers sailing out ofthe Port of Vancouver would have on theregion’s resident killer whales.
Alberta Premier Rachel Notley, afterreveling in 17 earlier decisions by variouscourts that endorsed the Trans Mountainplans, made no effort to hide her anger,faced with estimates that losing thepipeline expansion could reduce Alberta’sGross Domestic Product by 1.5 percent to2 percent by 2023.
“Alberta has done everything right andwe have been let down,” she said. “It’s acrisis.”
Other observers noted that delays inconducting regulatory hearings haveresulted in a net divestment of C$8.6 bil-lion in energy and mining investment overthe last 15 months.
Call for emergency sessionAt the same time Notley called on
Trudeau to hold an emergency session ofParliament and to appeal the case to theSupreme Court, she also delivered a blowto Trudeau’s goal of imposing a federalcarbon tax as the key underpinning of hisclimate change initiative.
She said Alberta will withdraw from thestrategy by refusing to raise the province’scurrent tax of C$30 a metric ton to C$40 in2021 and $50 in 2022, joining Ontario andSaskatchewan in their legal fight againstthe tax.
However, Notley said that if the federalgovernment “acts boldly and gives this cri-sis the attention it deserves,” there mightstill be a chance of work resuming onTrans Mountain by early 2019.
“No one in Canada should accept that
the only way to sell Canada’s resources isthrough the United States,” she said. “Noother country on Earth would accept thisand Canada shouldn’t either, especiallywhen we are doing it to ourselves.”
Notley’s fear now, even though theappeal court verdict was out of Alberta’scontrol, is that she could be ousted frompower in the provincial election expectedin May 2019.
Lori Williams, a political scientist atCalgary’s Mount Royal University, saidNotley was already “facing an uphill battle(in the next election campaign) and the hilljust got steeper. As a single issue (TransMountain) is not as consequential forJustin Trudeau as it is for Rachel Notley.”
However, as some of the initial furyover the appeal court verdict subsidessome analysts have noted that the 250-page judgment and its 800 clauses containpossible hope for Trans Mountain, evengoing as far as suggesting a two-step res-cue plan.
The panel of judges said the federalgovernment cabinet could refer the projectback to the NEB for “reconsideration,”including taking into account concernsraised by the court about the impact oftankers on marine safety and species atrisk, especially the whale population.
The judges suggested a “reconsidera-tion” could take into account any factorsspecified by the federal cabinet, includingstrengthening the Trudeau government’sC$1.5 billion ocean protection plan, whichthey found “insufficient.”
Time limitIn a telling comment, the court also said
the federal cabinet would be within its
rights to “specify a time limit, withinwhich” the NEB should complete itsreconsideration.
Equally significant, the court said thegovernment did not have to secure consentfrom each of the five First Nations whotriggered the court case, or unanimityamong all of those nations.
The judgment made it clear that theobligation to meaningfully consult withFirst Nations and, if possible, accommo-date their interests can be complex anddemanding, but they do not imply a veto.
“Canada is not to be held to a standardof perfection in fulfilling its duty to con-sult,” the appeal court said.
“At the same time, indigenousclaimants must not frustrate (the govern-ment’s) reasonable good faith attempt, norshould they take unreasonable positions tothwart the government from making deci-sions or acting in cases where, despitemeaningful consultation, agreement is notreached.”
Judge Dawson said the concerns ofindigenous applicants are “specific andfocused ... this means that the dialogueCanada must engage in can also be specif-ic and focused.”
“This may serve to make the correctedconsultation process brief and efficientwhile ensuring it is meaningful. The endresult may be a short delay (in construc-tion).”
But that glimmer of hope could easily beshredded in British Columbia, which has along history of getting bogged down in legalfights over resource development. l
continued from page 1
TRANS MOUNTAIN
In its July response the state denied that any publicprocess is required for issuance of advisory bulletins anddenied that the Tax Division of the Department ofRevenue “adopted” the 2017 advisory bulletin. The statealso denied that it was required to rescind the 2011 advi-sory bulletin, and “denies any characterization of the2017 Advisory Bulletin inconsistent with its text.”
The state said in its response that Revenue “admitsthat Revenue Online allows taxpayers the option to entertax credits in any order” but “denies that such an optionrelieves taxpayers of the duty to accurately report andpay tax.”
The complaint argued that prior to the 2017 advisorybulletin, “DOR’s mandatory tax reporting system
Revenue Online allowed taxpayers to apply the SlidingScale Credit to a taxpayer’s tax liability first and thenapply the New Oil Credit and Other Credits to theremaining tax liability.” Prior to the 2017 advisory bul-letin, the complaint said “DOR acknowledged in the2011 Advisory Bulletin that North Slope Producerscould reduce their tax liability below the Minimum Taxby using the New Oil Credit and the Other Credits.”
In its response the state denied that characterization ofthe 2011 advisory bulletin and said that bulletin “speaksfor itself.”
The state denied the allegations that Exxon andHilcorp would be liable for “retroactive taxes,” and saidthey “may owe tax due to Alaska Statutes and the AlaskaAdministrative Code.”
As for advisory bulletins interpreting statutes, thestate cited Alaska statute as providing that “the depart-
ment may issue … advisory bulletins stating the depart-ment’s interpretation of provisions of this chapter and ofregulations adopted under this chapter.” The state saidthat “advisory bulletins are non-binding.”
The complaint had requested that the court find the2017 advisory bulletin “contrary to law and thereforevoid” and that Revenue is prohibited from enforcing thebulletin’s conclusions, analysis or methodology.
The state asks that the complaint be dismissed withprejudice, that the plaintiffs be awarded no relief and thatthe defendant be awarded its attorneys’ fees and costs ofdefending the suit.
The case is scheduled to be heard in 2019. —KRISTEN NELSON
continued from page 1
LAWSUIT RESPONSE
PETROLEUM NEWS • WEEK OF SEPTEMBER 9, 2018 9
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tons of LNG per year. AGDC had initially hoped to have its environmental
impact statement in hand by the end of this year andbegin project construction in 2019. AGDC PresidentKeith Meyer told the board earlier this year that the finalEIS was now expected in the first half of 2019.
Even that proved too optimistic. FERC’s first notice of schedule, issued in March,
identified Dec. 9, 2019, as the final EIS issuance date,but the commission said Aug. 31 that its staff has revisedthe schedule for the final EIS issuance based on AGDC“providing complete and timely responses to any futuredata requests,” and also assuming that cooperating agen-cies provide their input “on a timely basis.”
The notice of availability for the final EIS is now setfor Nov. 8, 2019, with the 90-day federal authorizationdecision deadline for Feb. 6, 2020.
12 applicationsFERC said Aug. 31 that it had issued environmental
schedules for 12 liquefied natural gas export terminalapplications, reflecting its efforts to streamline its review
process. FERC Chairman Kevin McIntyre said significant
strides in streamlining the commission’s regulatoryprogress is a response to increasing numbers and greatercomplexity of LNG applications it is receiving. “Theseprocess improvements have shortened projected envi-ronmental schedules in some cases by nine to 12months,” he said.
“There is widespread acknowledgement that theUnited States is poised to play an important role in serv-ing worldwide LNG demand, and its ability to serve thatdemand quickly will serve the nations national securityand economic interests,” McIntyre said.
FERC has added to its LNG staff. It has also takensteps to save staff time, including: signing an agreementwith the Pipeline and Hazardous Materials SafetyAdministration to coordinate siting and safety review ofLNG facilities; hiring an outside contractor to assist inconstruction inspections; and working with projectapplicants to hire third-party contractors to conductanalyses.
In late June FERC asked AGDC to consider providinga third-party contractor to assist FERC staff in reviewingengineering design for the Alaska LNG Project.
In addition to the Alaska project, other LNG projects
affected by the issuance of regulatory schedules include:Freeport Train 4, Port Arthur, Driftwood LNG, CorpusChristi, Texas LNG, Gulf LNG, Rio Grande LNG,Jacksonville Eagle, Annova LNG, Plaquemines andJordan Cove.
Alaska scheduleAGDC said Sept. 5 that the revised schedule puts the
Alaska LNG project on tract for approval a month earlierthan originally anticipated.
“FERC’s accelerated schedule is a strong signal topotential customers and investors that Alaska LNG issteadily advancing through the regulatory process,” saidAGDC’s Meyer. He credited AGDC’s technical staffwith providing responses to nearly 1,500 FERC datarequests and agency comments.
AGDC Senior Vice President Frank Richards said,“FERC’s efforts to streamline its review process isalready having a positive impact on the Alaska LNGproject,” noting innovative efforts by FERC staff toexpedite the process for environmental review and per-mitting.
—KRISTEN NELSON
continued from page 1
FINAL ORDER
CO
URT
ESY
OPT
I ST
AFF
ING
companies say — along with weak, crum-bling sandstone reservoir rock that brokeloose to clog wellbores and damageequipment.
Now new drilling and production tech-nologies and years of tinkering, mainlywith ways of controlling the loose sand,have turned the corner, making the WestSak wells profitable at current oil prices,Michael Driscoll, ConocoPhillips’ super-visor of viscous development, said in aninterview.
ConocoPhillips, BP and HilcorpEnergy, all North Slope producers, areproducing from viscous oil deposits inconventional fields they operate, butConocoPhillips has been the most con-stant in exploiting the resource.
Work began in mid-1980sWhen work on West Sak viscous oil
began in the mid-1980s the best wellrates were 250 barrels per day, with flowrates impeded by the cool temperature ofthe oil, which is produced from a shallowreservoir, relative to crude producedfrom deeper conventional reservoirs,where oil is warmer and flows more eas-ily.
An added complication was the loosenature of the sandstone, which tended tobreak apart, releasing sand when oil wasextracted. This led to holes being formedin the rock, called “worm holes,” whichallowed productive zones to be bypassed.
Early experiments with screens tokeep sand out of the well bores failedwhen screens became clogged. Otherefforts, on earlier West Sak wells,involved just letting the sand flow outwith the oil. But then the sand had to beremoved from the wells and pipeline,which became expensive.
What didn’t help the West Sak eco-nomics was the lower quality of the oil,ranging from 16 to 19 degrees API grav-ity compared with Prudhoe Bay oil at 29degrees API.
Despite these problems the huge oil-in-place resource was a tempting target.State geologists estimated the viscous oilresource at 5.5 billion barrels to 7.5 bil-lion barrels overlaying the Kuparuk,Prudhoe Bay and Milne Point fields.
Although only a small part of this willbe economically produced, it’s still a lotof oil.
Multilateral wellsConocoPhillips is now boosting West
Sak well rates to rates of 5,000 bpd byusing multilateral wells, where separate
producing legs are drilled off a singlevertical well to surface.
At ConocoPhillips’ latest West Sakdevelopment, in its NEWS project in theKuparuk River field, five horizontal pro-ducing legs, each about 7,000 feet inlength, feed oil into the vertical well.
Drilling horizontal multilateral wellswas a technique pioneered by ARCOAlaska, ConocoPhillips’s predecessor onthe North Slope, and later BP, primarilyto tap thin lateral oil sands in the WestSak and conventional fields that wereeconomically marginal.
The lateral horizontal wells areexposed to much more of the oil-bearingrock than would be the case with a con-ventional vertical producing well andhaving several of them shares the cost ofthe vertical well and surface infrastruc-ture.
There are longer single lateral produc-ing wells being drilled on the NorthSlope but the West Sak wells are chal-lenging because they are shallow, atdepths of 6,000 feet, compared withdeeper conventional wells at depths like9,000 feet, said Ryan Phelps, staff geolo-gist on the project.
Drilling shallow requires the drillersto turn the vertical surface well at higherangles to reach 90 degrees, which isn’teasy. Keeping the drill bits in the WestSak sand layers, which can be as thin asfive feet in thickness, is also tricky,Phelps said.
Wells expensiveMultilateral wells are expensive —
each of the horizontal legs at NEWStakes about 50 days to drill. But the wellsproduce more oil, enough to compensatefor the higher costs, said FedericoCaldelas, senior reservoir engineer onNEWS.
Driscoll said ConocoPhillips is alsomaking progress on sand control, using anew type of ultra-fine mesh screen thatseems to be working.
Another problem that developed whenwaterflooding was introduced, in anattempt to boost production rates, were“breakthroughs” of water through looserocks so water went straight to the pro-ducing well instead of pushing oil aheadof it to the well.
This problem, technically called a“Matrix Bypass Event,” has bedeviled allcompanies working on viscous oil. AtNEWS it is now being mitigated by usinga down-hole device that targets micro-applications of water to specific layers ofoil-bearing sand, a WaterfloodRegulation Valve. These have been usedfor some time in other North Slope fields,like Prudhoe Bay, but this is the firstapplication in the viscous oil deposits.“We’re now able to surgically put the
water exactly where we want it be,”Driscoll said.
November 2017NEWS began operating in November
2017, about three months ahead of sched-ule, and is now producing about 10,000bpd with three producers currently online. A fourth well will start producing inmid-September, which will boost output.ConocoPhillips had estimated peak pro-duction at 8,000 bpd initially.
Driscoll said the higher production is aresult of better-than-expected reservoirperformance and growing experience inworking with the reservoir. However,ConocoPhillips has also reduced the costof the project by 45 percent, he said,through aggressive efforts at cost-cuttingand managing development more effi-ciently.
The lower production cost is really theresult of a concentrated effort to cut WestSak expenses made after oil prices plum-meted in 2015. NEWS was just beginningdevelopment then, “but management halt-ed the program and told us to find ways tocut costs,” Driscoll said.
The team got creative. Among severalmeasures, water-based drilling fluidswere substituted in the plan, for at leastsome wells, in lieu of more expensive oil-based drilling fluids. This change wasmade after the company determined thewater-based fluid could be as safe andeffective as oil-based fluid.
Drilling fluids are critical to the safeoperation of drilling. They are used dur-ing drilling to sustain pressure down inthe well, preventing an oil or gas“blowout,” an uncontrolled release, aswell as to lift rock and cuttings out of thedrill hole to the surface for disposal.
These steps now made ConocoPhillipsmore confident it can put viscous into thecompany’s long-term North Slope devel-opment plans, company spokespersonAmy J. Burnett said. “This has now gonemainstream for us,” she said.
The company is now planning its newphase, Eastern NEWS, in an adjacentarea. It is planned to be producing in2023, according to a ConocoPhillips pres-entation to investors made July 16.
Driscoll said he believes the same kindof incremental technical leaps that havemade West Sak viscous oil economicallyviable can be applied at Ugnu, the hugeheavy oil resource that has also be identi-fied on the slope. Ugnu oil is even thickeror more difficult to produce than the vis-cous oil. l
Editor’s note: Tim Bradner is editor ofthe Alaska Economic Report and is 2018Atwood Professor of Journalism at theUniversity of Alaska Anchorage.
10 PETROLEUM NEWS • WEEK OF SEPTEMBER 9, 2018
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NEWS STARTUP
PIPELINES & DOWNSTREAMEnbridge, Fond du Lac Band reach line deal
Enbridge Energy and the Fond du Lac Band of Lake Superior Chippewa havereached an agreement to build the Line 3 replacement oil pipeline through theband’s reservation in northeast Minnesota.
Both sides announced the agreement Aug. 31. Financial terms are confidential. The agreement gives Enbridge easements for six existing oil pipelines through
2039. Enbridge plans to build the new pipeline in an expanded right-of-way adja-cent to existing pipelines on the reservation.
The band has also agreed not to participate in any opposition to the project, butmay comment on environmental, cultural or other issues affecting the band.
Line 3 was built in the 1960s. It carries Canadian crude from Alberta throughNorth Dakota and Minnesota to Enbridge’s terminal in Superior, Wisconsin.Opponents say the project poses risks of oil spills. Enbridge says the replacementwill be safer.
—ASSOCIATED PRESS
Multilateral wells are expensive— each of the horizontal legs atNEWS takes about 50 days to
drill. But the wells produce moreoil, enough to compensate for the
higher costs, said FedericoCaldelas, senior reservoir
engineer on NEWS.
PETROLEUM NEWS • WEEK OF SEPTEMBER 9, 2018 11
for oil and gas development.BLM will prepare a record of decision for the GMT-2
development once the final SEIS has been announced inthe Federal Register for at least 30 days.
Impacts on surface resourcesThe SEIS says that the impacts of the GMT-2 devel-
opment on surface resources, in particular subsistenceresources, have been key issues for consideration. Interms of subsistence impacts, the proximity of the villageof Nuiqsut to the development site is of particular signif-icance. Potential restrictions in access to subsistencehunting and potential changes in land use by resourcessuch as caribou are concerns.
An analysis of subsistence impacts found that theGMT-2 project “may significantly restrict subsistenceactivities for the village of Nuiqsut, and the cumulativeeffects of GMT-2 and other developments on the NorthSlope may significantly restrict subsistence activities forthe villages of Nuiqsut, Anaktuvuk Pass, Atqasuk andUtqiagvik,” the SEIS says.
However, the SEIS also considered the potential eco-nomic benefits to Alaska Native communities from thedevelopment, as well as a range of other possible
impacts, including impacts on global climate change, onwater quality and on air quality.
Mitigation against adverse impacts includesConocoPhillips’ commitment to use existing lease stipu-lations for the Greater Mooses Tooth unit. The companysupports subsistence activities through financial contri-butions and has incorporated features, such as subsis-tence pullouts on access roads, into its design for theproject, the SEIS says. However, the company hasrequested two deviations from stipulations in theIntegrated Activity Plan: The deviations relate to the dis-tances of facilities from water bodies and the distancesbetween pipelines and roads. BLM will rule on the devi-ation requests in its record of decision for the SEIS.
Evolving planThe plan for the GMT-2 project has changed some-
what, since the initial development concept was pub-lished in 2004 in the EIS for ConocoPhillips’ Alpinesatellite development plan. The development involves anoil accumulation discovered in Alpine sandstones, inparticular by the Spark and Rendezvous explorationwells. Initially, the idea was to develop the oil from a9.1-acre pad accessed by a 6.3-mile gravel road. In 2014,based on updated reservoir information, the proposedpad location was moved 3.2 miles to the south. This,however, would have placed the pad in the Colville
River Special Area, an area of particular environmentalsensitivity. Consequently, the proposed pad location wasmoved again, to a location that would be acceptable froman oil production perspective while also mitigating envi-ronmental impacts.
The evolution of the development plan also involvedan increase in the pad size to 14 acres and an increase inthe planned number of development wells from 20 to 48.The required access road length increased to 8.2 miles,and the development requires a pipeline system 8.6 milesin length. No new bridges are required. Gravel for theproject will come from an Arctic Slope Regional Corp.gravel mine. The planned pad will be located entirely onfederally managed land. The proposed pipeline and roadcorridors cross both federally managed land and landowned by Kuukpik Corp., the Native village corporationof Nuiqsut.
A pipeline segment between the GMT-2 and GMT-1pads will have vertical support members carrying a 20-inch produced fluids pipeline, a 14-inch injection waterpipeline, a 6-inch gas pipeline, an 8-inch miscible injec-tant pipeline, and power and fiber optic cables. The sup-port members will have space for an additional 24-inchpipeline, the SEIS says. Pipelines required for GMT-2would be placed on existing vertical support membersthat carry pipelines from GMT-1 to the Alpine process-
!
Greater Mooses Tooth
Gre
ater
Moo
ses T
ooth
AA 081735
AA 081736
AA081742
AA081743
AA 081745
AA081746
AA 081777
AA081778
AA 081779AA 081780AA 081781
AA 081782
AA 081784AA 081785
AA 081787
AA081788
AA 081795AA 081796
AA 081797
AA081798
AA 081799
AA 081800
AA 081801
AA081802
AA 081803AA 081804
AA 081805AA 081806
AA 081807
AA 081808
AA 081809
AA 081810
AA081818
AA 081819
AA 081820AA 081821
AA 081823 AA 081857
AA 087896
AA 090707AA 090708
AA 090709AA 090710AA 090711
AA 092672
AA 092673AA 092674
AA 093931
AA 093932
GMT 1
CD2
CD3
CD4
CD5
CD1
GravelSource
GMT2
Nuiqsut
No warranty is made by the Bureau of Land Management as to the accuracy, reliability, orcompleteness of these data for individual or aggregate use with other data. Original datawere compiled from various sources. Thisinformation may not meet National Map AccuracyStandards. This product was developed throughdigital means and may be updated without notification.
GMT-2 ProposedInfrastructure
Alt. A PipelineAlt. A RoadGMT-2 ProposedPads
Existing & GMT- 1PermittedInfrastructure
RoadPipelineGravel SourcePad
Map 1.1-10 2 4 6 Miles
Currently Authorized Lease Tractswithin the Greater Mooses Tooth Unit
Land StatusBLM (Native-selected)
Bureau of LandManagement
Alaska Native LandsPatented or InterimConveyed
State of Alaska
Alaska NativeAllotment
Water
National PetroleumReserve in AlaskaBoundary
GMT-2 Project Area
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EAU
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FINAL SEIS
see FINAL SEIS page 12
12 PETROLEUM NEWS • WEEK OF SEPTEMBER 9, 2018
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ing facilities.ConocoPhillips has proposed two
alternative development schedules forthe project, one starting in the fourthquarter of 2018 and the other starting inthe fourth quarter of 2019. Both wouldsee construction completed in thefourth quarter of 2021, at which pointoil production would begin.Construction would take place duringthe winter, making use of seasonal iceroads and ice pads.
Alternatives consideredIn addition to its preferred alterna-
tive, BLM considered two other alter-natives: an alternative involving a dif-ferent road alignment, and a roadlessalternative that would have more facil-ities on site and, thus, involve morelimited site access. The agency alsoconsidered a “no action” alternative butcommented that BLM cannot deny per-mits to drill, associated with appropri-ate mitigation measures, on land leasedfor oil and gas activities.
BLM considered but rejected asimpractical or uneconomic some otherpossibilities including the use of buriedpipelines, a roadless development withseasonal drilling, and the establishmentof an operations center in the village ofNuiqsut.
Reactions to the SEIS“(Interior) Secretary Zinke made a
commitment last year to ‘jump-start’Alaskan energy and this project is agreat example of the Department of the
Interior following through on that,”said Joe Balash, Interior’s assistant sec-retary for land and minerals manage-ment, in response to the publication ofthe SEIS. “Oil and gas development inthe NPR-A is important to meeting ournation’s energy needs and this analysisprovides a responsible path forward inbalance with resource protections. And,throughout the process we are proud ofour efforts of involving the peoplemost affected by development activi-ties on the North Slope of Alaska.”
“This is great news for Alaska andour nation,” said U.S. Sen. LisaMurkowski, R-Alaska. “This newdevelopment, which will produce anestimated 30,000 barrels per day, willhelp refill the trans-Alaska pipeline andprovide Alaskans with good jobs.Development in the NPR-A also bene-fits our nation by increasing our energysecurity, keeping energy affordable,and reducing the federal deficit, so Iappreciate the work the Department ofthe Interior has done to advance thisproject.”
“I want to thank Secretary Zinkeand BLM for keeping their promise tomake Alaska a leader in our country’senergy production,” said CongressmanDon Young, R-Alaska. “Responsibledevelopment of Greater Mooses Toothwill help keep our North Slope activeand will bring much needed jobs to thelocal communities. I look forward tocontinuing to work with SecretaryZinke and the rest of the Department ofthe Interior to ensure Alaska energyproduction remains strong.” l
continued from page 11
FINAL SEIScoming decades, the company had devel-oped a plan that would simplify processesby focusing on maintenance; would opti-mize the company’s operating infrastruc-ture; would continue with technical inno-vation; and would strengthen the compa-ny’s high performance culture.
Barrett commented that, directly orindirectly, his company primarilyengages in activities focused on the main-tenance of the pipeline and Valdez MarineTerminal infrastructure. However, themanner in which the company is current-ly organized is more appropriate for aconstruction company, he said.Consequently, the company is realigninginto three divisions: operations and main-tenance; engineering and risk; and chiefoperating officer. The leadership isalready in place for this reorganizationand has begun planning how to imple-ment the new business strategy. Thisstrategy includes the clarification of deci-sion authority and the delegation of deci-sion making to managers in the field,expediting decision making and actionsthrough the empowerment of people inthe work environment.
Simplified processesThe new strategy also involves simpli-
fying maintenance processes, to betteridentify high priority work while alsoapplying risk-based decision criteria forcompleting that urgent work and conduct-ing other maintenance work quickly andefficiently. The company plans to use itsengineering and risk management expert-ise to improve and strengthen its techni-cal controls. And the emergency planningand response functions for the pipeline,the marine terminal and the marine escortsystem out of Valdez will be centralized.The company will continue to expand theuse of modern technology.
Most jobs in the company will beimpacted in some way by the variouschanges, and the size of the workforcewill drop, with negative impacts for someand new opportunities for others, Barrettwrote. Alyeska anticipates notifying allemployees by early November of actionsaffecting them, he wrote.
“It will be a fundamental and challeng-ing change to our work, but one that isnecessary to ensure the future operationalreliability and efficiency of TAPS,”Barrett wrote. “I am acutely sensitive tothe impacts this will have on our people,who in the past and moving forward arethe foundation of our success.”
—ALAN BAILEY
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ALYESKA RESTRUCTURING
