Vol. 16, No. 49 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of December 4, 2011 • $2 ● EXPLORATION & PRODUCTION ● NATURAL GAS ● ALTERNATIVE ENERGY page 4 Apache’s Hendrix tells RDC company’s Cook Inlet seismic shoot under way. 8 8 770 ' 8 8 580 ' 8 8 1780 ' 8 8 400 ' 8 8 1590 ' 8 8 1120 ' 8 8 510 ' F SEALIFT BULKHEAD SERVICE PIER EXISTING PTU-3 PAD PAD TOE BOAT LAUNCH PAD SHOULDER EXPORT PIPELINE & EAST AND WEST GATHERING LINES CENTRAL PAD ROAD PAD DIMENSIONS ARE APPROXIMATE ACTUAL LAYOUT PENDING FINAL DESIGN To Airstrip, Gravel Mine Lion Bay MOORING DOLPHINS Zone Key Drilling Living Facilities Barge Offloading Operations Processing Unit FLARE STACK 1 1 1 2 3 4 5 6 7 8 10 9 11 12 20 13 14 15 16 17 18 19 20 21 22 23 24 25 28 29 26 27 A A B B 1 - DISPOSAL WELL 17 - ACS LAYDOWN AREA 3 - GRIND & INJECT 19 - COLD STORAGE 5 - DRY BULK STORAGE 21 - ACS & MAINTENANCE 7 - CAMP 23 - WASTE 9 - UTILITY MODULE 25 - CAMP PARKING 11 - POWER GENERATORS 27 - STANDBY GENERATORS 13 - PIPE MATERIAL 29 - LIVING QUARTERS 14 - DIESEL 30 - CONSTRUCTION EQUIPMENT 15 - DIESEL/METHANOL 31 - MATERIAL 16 - SUPER SUCKERS 32 - FUEL 30 31 32 31 26 23 7 25 TEMPORARY RAMP SUPPORT Proposed Thomson pad layout ExxonMobil has submitted this proposed central pad layout to the Corps of Engineers as part of its application for Point Thomson facilities and pipeline work. See story on page 13. Tight situation Alaska oil explorers hit the limits on winter drilling rig availability By ALAN BAILEY & KAY CASHMAN Petroleum News T he surge in exploration activity planned for Alaska this winter has placed a major strain on the supply of drilling rigs suitable for use in the demanding conditions of a long Arctic winter. At last count four companies with exploration drilling plans — Linc Energy, Savant Alaska, UltraStar Exploration and Great Bear Petroleum — had yet to sign contracts for drilling rig use. And given the relatively small inventory of Arctic rigs it seems highly improbable that all of these companies will end up drilling in the coming months, assuming that companies with rig contracts do in fact pro- ceed with their planned drilling. Three other companies, Repsol, Brooks Range Petroleum and Pioneer Natural Resources have seven rigs under contract for this coming winter exploration season: Repsol expects to drill 12 wells; Brooks Range, two wells, plus re-enter a third; and Pioneer, two wells. Nabors operates 12 rigs On Nov. 29, David Hebert, general manager of Nabors Alaska Drilling, talked to Petroleum News about some of the issues involved in supplying rigs for Arctic Alaska exploration. Nabors currently operates 12 rigs that are suitable for Arctic use and that are in a fully operational status, Hebert said. An additional Nabors rig on the Kenai Peninsula has not been winterized for the Arctic. Two of the Arctic rigs are workover rigs for in- field use, while another has a design that is not see RIG DEMAND page 18 Mackenzie project lives NWT premier reports ‘some progress’ on fiscal issues; Imperial confirms ‘dialogue’ By GARY PARK For Petroleum News C anada’s Mackenzie Gas Project has received a fresh infusion of hope with confirmation that discussions on a fiscal framework are under way between project leader Imperial Oil and the Canadian government. The election in May of a majority federal govern- ment under Prime Minister Stephen Harper is viewed as the spark that has ended what Imperial spokesman Pius Rolheiser said was a “temporary hiatus” in the dialogue. Bob McLeod, newly elected premier of the Northwest Territories, said he understands “some progress” has been made. He said the Aboriginal Pipeline Group, which has been offered a one-third equity stake in the proposed Mackenzie Valley gas line, and its members have held meetings with a number of federal government cabinet ministers. “They seem to have received some positive sig- see MACKENZIE LIVES page 20 The study, which forecast Mackenzie gas can start flowing when prices rise above US$5.50 per million British thermal units, said the Arctic gas will be needed regardless of the projected growth of shale gas production. Co-op members object Committee wants more information as Naknek Electric works through bankruptcy By WESLEY LOY For Petroleum News M embers of a troubled Southwest Alaska electric power cooperative have raised con- cerns about the utility’s proposed bankruptcy reor- ganization plan. Naknek Electric Association in September 2010 was forced to file for Chapter 11 protection from creditors due to complications with a geothermal energy program. A committee representing the interests of Naknek Electric members on Nov. 28 filed a six- page objection to the co-op’s disclosure statement for its reorganization plan. The filing was in advance of a scheduled Dec. 1 hearing on the plan in U.S. Bankruptcy Court in Anchorage. The members committee raised concerns about the possibility of the co-op continuing with its geothermal drilling project, and the risks this could pose to the utility and to ratepayers. see CO-OP OBJECTIONS page 20 A big worry for the co-op, and for the members, is retaining the utility’s major customers, which could elect to generate their own power if rates increase significantly. Spartan 151 jack-up drilling rig arrives safety in Port Graham The only jack-up rig in Cook Inlet is now in hibernation for the winter. Furie Operating Alaska LLC, formerly Escopeta Oil Co., brought the Spartan 151 into Port Graham on Thanksgiving Day, according to Furie Strategic Officer Steve Sutherlin. The rig will spend the winter getting light maintenance and repairs at the ice-free Cook Inlet port on the southern Kenai Peninsula before heading back out sometime next spring. Furie used the rig this summer and early autumn to drill the first half of Kitchen Lights Unit No. 1, an offshore exploration well in the upper Cook Inlet. The company suspended opera- tions at 8,805 feet on Oct. 28, but plans to drill to a total depth of about 16,500 feet. —ERIC LIDJI BRPC plans 3 Mustang wells in new Southern Miluveach unit A joint venture led by Brooks Range Petroleum Corp. could complete as many as four wells this winter at its North Tarn prospect on the central North Slope of Alaska. In addition to re-entering a sidetrack started this past winter, the local independent operating arm of Kansas-based Alaska Venture Capital Group plans to drill as many as three wells to delineate the prospect on the western boundary of the Kuparuk River unit. The Mustang exploration program would take place from the North Tarn ice pad that Brooks Range Petroleum plans to build in its newly formed the Southern Miluveach unit. The company expects to use Nabors rig 7ES for the pro- gram. Brooks Range Petroleum drilled the North Tarn No. 1 well this past winter and began drilling the North Tarn No. 1-A side- track on leases farmed-in from Eni Petroleum. The company expects to begin construction soon on an ice road running approximately four miles from an existing gravel road in the Kuparuk River unit to the to-be-built North Tarn ice pad, and plans to mobilize its camp and drilling rig toward the end of the year. In early January, Brooks Range Petroleum plans to spend some 15 days re-entering and completing North Tarn No. 1-A see MUSTANG WELLS page 19
Transcript
Vol. 16, No. 49 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of December 4, 2011 • $2
� E X P L O R A T I O N & P R O D U C T I O N
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Apache’s Hendrix tells RDC company’sCook Inlet seismic shoot under way.
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MOORING DOLPHINS
Zone KeyDrillingLiving FacilitiesBarge OffloadingOperationsProcessing Unit
ExxonMobil has submitted this proposed central pad layout to theCorps of Engineers as part of its application for Point Thomsonfacilities and pipeline work. See story on page 13.
Tight situationAlaska oil explorers hit the limits on winter drilling rig availability
By ALAN BAILEY & KAY CASHMANPetroleum News
The surge in exploration activity planned forAlaska this winter has placed a major strain
on the supply of drilling rigs suitable for use in thedemanding conditions of a long Arctic winter. Atlast count four companies with exploration drillingplans — Linc Energy, Savant Alaska, UltraStarExploration and Great Bear Petroleum — had yetto sign contracts for drilling rig use. And given therelatively small inventory of Arctic rigs it seemshighly improbable that all of these companies willend up drilling in the coming months, assumingthat companies with rig contracts do in fact pro-ceed with their planned drilling.
Three other companies, Repsol, Brooks RangePetroleum and Pioneer Natural Resources have
seven rigs under contract for this coming winterexploration season: Repsol expects to drill 12wells; Brooks Range, two wells, plus re-enter athird; and Pioneer, two wells.
Nabors operates 12 rigsOn Nov. 29, David Hebert, general manager of
Nabors Alaska Drilling, talked to Petroleum Newsabout some of the issues involved in supplying rigsfor Arctic Alaska exploration. Nabors currentlyoperates 12 rigs that are suitable for Arctic use andthat are in a fully operational status, Hebert said.An additional Nabors rig on the Kenai Peninsulahas not been winterized for the Arctic.
Two of the Arctic rigs are workover rigs for in-field use, while another has a design that is not
see RIG DEMAND page 18
Mackenzie project livesNWT premier reports ‘some progress’ on fiscal issues; Imperial confirms ‘dialogue’
By GARY PARKFor Petroleum News
Canada’s Mackenzie Gas Project has received afresh infusion of hope with confirmation that
discussions on a fiscal framework are under waybetween project leader Imperial Oil and the Canadiangovernment.
The election in May of a majority federal govern-ment under Prime Minister Stephen Harper is viewedas the spark that has ended what Imperial spokesmanPius Rolheiser said was a “temporary hiatus” in thedialogue.
Bob McLeod, newly elected premier of theNorthwest Territories, said he understands “someprogress” has been made.
He said the Aboriginal Pipeline Group, which hasbeen offered a one-third equity stake in the proposedMackenzie Valley gas line, and its members haveheld meetings with a number of federal governmentcabinet ministers.
“They seem to have received some positive sig-
see MACKENZIE LIVES page 20
The study, which forecast Mackenzie gascan start flowing when prices rise above
US$5.50 per million British thermalunits, said the Arctic gas will be needed
regardless of the projected growth ofshale gas production.
Co-op members objectCommittee wants more information as Naknek Electric works through bankruptcy
By WESLEY LOYFor Petroleum News
M embers of a troubled Southwest Alaskaelectric power cooperative have raised con-
cerns about the utility’s proposed bankruptcy reor-ganization plan.
Naknek Electric Association in September 2010was forced to file for Chapter 11 protection fromcreditors due to complications with a geothermalenergy program.
A committee representing the interests ofNaknek Electric members on Nov. 28 filed a six-page objection to the co-op’s disclosure statementfor its reorganization plan. The filing was in
advance of a scheduled Dec. 1 hearing on the planin U.S. Bankruptcy Court in Anchorage.
The members committee raised concerns aboutthe possibility of the co-op continuing with itsgeothermal drilling project, and the risks this couldpose to the utility and to ratepayers.
see CO-OP OBJECTIONS page 20
A big worry for the co-op, and for themembers, is retaining the utility’s majorcustomers, which could elect to generate
their own power if rates increasesignificantly.
Spartan 151 jack-up drilling rigarrives safety in Port Graham
The only jack-up rig in Cook Inlet is now in hibernation forthe winter.
Furie Operating Alaska LLC, formerly Escopeta Oil Co.,brought the Spartan 151 into Port Graham on ThanksgivingDay, according to Furie Strategic Officer Steve Sutherlin.
The rig will spend the winter getting light maintenance andrepairs at the ice-free Cook Inlet port on the southern KenaiPeninsula before heading back out sometime next spring.
Furie used the rig this summer and early autumn to drill thefirst half of Kitchen Lights Unit No. 1, an offshore explorationwell in the upper Cook Inlet. The company suspended opera-tions at 8,805 feet on Oct. 28, but plans to drill to a total depthof about 16,500 feet.
—ERIC LIDJI
BRPC plans 3 Mustang wells innew Southern Miluveach unit
A joint venture led by Brooks Range Petroleum Corp. couldcomplete as many as four wells this winter at its North Tarnprospect on the central North Slope of Alaska.
In addition to re-entering a sidetrack started this past winter,the local independent operating arm of Kansas-based AlaskaVenture Capital Group plans to drill as many as three wells todelineate the prospect on the western boundary of the KuparukRiver unit.
The Mustang exploration program would take place fromthe North Tarn ice pad that Brooks Range Petroleum plans tobuild in its newly formed the Southern Miluveach unit.
The company expects to use Nabors rig 7ES for the pro-gram.
Brooks Range Petroleum drilled the North Tarn No. 1 wellthis past winter and began drilling the North Tarn No. 1-A side-track on leases farmed-in from Eni Petroleum.
The company expects to begin construction soon on an iceroad running approximately four miles from an existing gravelroad in the Kuparuk River unit to the to-be-built North Tarn icepad, and plans to mobilize its camp and drilling rig toward theend of the year.
In early January, Brooks Range Petroleum plans to spendsome 15 days re-entering and completing North Tarn No. 1-A
Rig Owner/Rig Type Rig No. Rig Location/Activity Operator or Status
Alaska Rig StatusNorth Slope - Onshore
Doyon DrillingDreco 1250 UE 14 (SCR/TD) Prudhoe Bay Z-116 BPDreco 1000 UE 16 (SCR/TD) Prudhoe Bay 01/11i BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD4-03 ConocoPhillipsAC Mobile 25 Prudhoe Bay 04-350 BPOIME 2000 141 (SCR/TD) Kuparuk 3H-34 ConocoPhillipsTSM 7000 Arctic Wolf #2 In Nisku, AB Available
Kuukpik 5 Standbye, waiting on ice road North Slope Boroughconstruction to Walakpa #11
Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Stacked, Prudhoe Bay AvailableAC Coil Hybrid CDR-2 Kuparuk 2K-28A ConocoPhillipsDreco 1000 UE 2-ES Prudhoe Bay Stacked out AvailableMid-Continental U36A 3-S Prudhoe Bay Stacked out AvailableOilwell 700 E 4-ES (SCR) Prudhoe Bay X-22A BPEmsco Electro-hoist 7-E (SCR-TD) Prudhoe Bay DS12-27A BP Dreco 1000 UE 7-ES (SCR/TD) Milne Point MBS BPDreco 1000 UE 9-ES (SCR/TD) Has been released by Brooks Range Available
PetroleumOilwell 2000 Hercules 14-E (SCR) Prudhoe Bay Stacked out AvailableOilwell 2000 Hercules 16-E (SCR/TD) Prudhoe Bay Stacked out AvailableOilwell 2000 17-E (SCR/TD) Prudhoe Bay Stacked out AvailableEmsco Electro-hoist -2 18-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Stacked, Milne Point AvailableEmsco Electro-hoist 28-E (SCR) Stacked, Deadhorse AvailableEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Stacked at Deadhorse, Pioneer
will go to Oooguruk for exploration drilling in JanuaryAcademy AC electric Heli-Rig 106-E (SCR/TD) Stacked at Deadhorse AvailableOIME 2000 245-E Oliktok Point OP12-01 ENI
*Nabors 27-E will be under contract at Oooguruk/Nuna for Pioneer this winter
Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site U-12AL1 BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay Well Drill Site 6-12B BP Ideco 900 3 (SCR/TD) Kuparuk Well 2T-03 ConocoPhillips
Parker Drilling Arctic Operating Inc. NOV ADS-10SD 272 Prudhoe Bay final construction and commission BPNOV ADS-10SD 273 Prudhoe Bay final construction and commissioning BP
North Slope - Offshore
BP (rig built & being assembled by Parker)Top drive, supersized Liberty rig Endicott SDI for Liberty oil field BP
Nabors Alaska DrillingOIME 1000 19-E (SCR) Oooguruk ODST-39 Pioneer Natural ResourcesOIME 2000 245-E Oliktok Point OI13-03 ENIOilwell 2000 33-E Prudhoe Bay Stacked out Available
Doyon DrillingSky Top Brewster NE-12 15 (SCR/TD) Spy Island SP27-N1 ENI
Cook Inlet Basin – OnshoreAurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Stacked out south of Tyonek Available
Nabors Alaska DrillingContinental Emsco E3000 273 Stacked, Kenai AvailableFranks 26 Stacked AvailableIDECO 2100 E 429E (SCR) Stacked Available Academy AC electric Canrig 105-E (SCR-TD) Kenai CLU-1 CINGSARigmaster 850 129 Kenai Stacked out Available
The Resource Development Councilincluded a fairly complete Cook
Inlet update on the program of its annualconference.
From oil and gas, through wind andunderground coal gasification, to naturalgas storage, companies involved in thecurrent upsurge in Cook Inlet activitieswere on the podium Nov. 17.
ApacheApache Corp., Cook Inlet’s newest big
player, with more than 800,000 acres, wasrepresented by its newly named Alaska
general manager,John Hendrix, whotold the RDC audi-ence he remembersCook Inlet in itsheyday, before thediscovery ofPrudhoe Bay. But bythe time he graduat-ed from college andwent to work forSchlumberger, the work was on the NorthSlope.
“All the focus, all the money, weregoing into Prudhoe Bay,” Hendrix said.
Apache is focused on the historic oilplay in Cook Inlet and is looking for oil“with new 3-D seismic technology,” hesaid.
“We feel there’s potential out there.
We’re more focusedon oil — gas willcome along with theoil … but we’re oilfocused.”
Apache hasbegun a three-year12,000-square mile3-D seismic shoot inCook Inlet using anew nodal technolo-
gy. Hendrix said there are 220 people on
the west side of Cook Inlet deployingnodes with the first actual shoot doneNov. 11. He said crews will work untilmid-December and then start back upJan. 15. Twelve small drill rigs will beused to drill the holes onshore; offshoreair guns will be used.
In all of its operations, Apache shootsa lot of seismic, Hendrix said.
“We’re a very seismic, geo-scienceoriented company … and you have toknow the data before you drill. You gath-er the data, you put your strategy forwardand then we drill.”
He also said that Apache’s “chairman,in a number of meetings I’ve been withhim, he doesn’t want us to stop drillinguntil we hit bedrock. We don’t want any-body to come behind us and turn over astone and find there’s oil reserves; wewant to make sure when we drill, that weleave no … stone untouched.”
BuccaneerJim Watt, president and COO of
Buccaneer Alaska, said Buccaneer seesmajors moving out and independentsmoving into Cook Inlet, “normal for a lotof maturing basins.”
But, he said, Cook Inlet is an underex-plored basin where recent U.S.Geological Survey reports show “tremen-dous upside” and where there is existinginfrastructure, a strong local market andattractive natural gas prices.
Buccaneer has some 66,000 acresonshore and at one prospect, Kenai Loop,just north of the city of Kenai, it “leased,permitted and drilled our first well withinnine months.” That natural gas well willbe on production in December, he said.Buccaneer has a contract with Enstar fordelivery beginning in April, “but we hopewe will sell in the spot market” beforethen, Watt said.
At West Nicolai on the west side of
Cook Inlet Buccaneer expects to acquireseismic in 2012 and drill in 2013.
And at West Eagle on the southernKenai Peninsula Buccaneer is reprocess-ing seismic and would like to drill in2012.
The company also has offshoreprospects and has completed purchase ofthe Endeavour jack-up drilling rig for usein Cook Inlet. Buccaneer is also lookingat the potential for liquefied natural gasfor use in Alaska. Watt said “we feel wecan move LNG from the Cook Inlet toFairbanks and be very competitive.”
Furie/EscopetaDrilling engineer Bob Laule, filling in
for Furie Operating Alaska (formerlyEscopeta Oil) President Ed Oliver, gave abrief update.
“Furie came; wedrilled; and wefound gas,” he said.
He said the com-pany got a late startand wasn’t able tocomplete its well,but drilled to 8,800feet and did “sometesting which gaveus some very goodindications of gas in the Sterling and inthe Beluga formations.”
Laule said they will re-enter the wellnext spring, approximately mid-April anddrill to total depth, “set a couple of extraadditional stands of pipe and go into atesting program.”
Then Furie will drill a second well.Laule said he didn’t know if they’d get totesting the second well next year.
Cook Inlet EnergyJR Wilcox, president of Cook Inlet
Energy, said his company “is one of thefew small independent oil producers inthe state.” Cook Inlet Energy re-estab-lished production after Pacific Energydeclared bankruptcy in 2009.
Production was shut down inSeptember and Cook Inlet Energy wasapproved as successor operator inDecember, hired a staff and “within abouttwo weeks we had some productiongoing.”
Over the next four months the WestMcArthur River unit was restarted and
4 PETROLEUM NEWS • WEEK OF DECEMBER 4, 2011
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owned by Petroleum Newspapersof Alaska LLC. The newspaper ispublished weekly. Several of theindividuals listed above work forindependent companies that con-
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ARRC has the logistical know-how, muscle, and infrastructure to keep
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in 2010, Alaska Railroad employees sent more than six million tons of freight across 651 miles of track.
ThinkingRESOURCEFULRESOURCEFUL
Thinking
� E X P L O R A T I O N & P R O D U C T I O N
Cook Inlet energy projects under wayRDC annual conference hears updates from Apache, Buccaneer, Furie, Cook Inlet Energy, Enstar, CINGSA and Cook Inlet Region Inc.
Tensions simmer in Syncrude ranksOperator and largest shareholder unable to agree on timing forC$15 billion expansion of world’s largest synthetic crude plant
By GARY PARKFor Petroleum News
An apparent rift among owners ofSyncrude Canada, the world’s
largest single synthetic crude operation,is stalling plans to increase capacity by250,000 barrels per day to 600,000 bpdby 2020.
First announced in February 2010, theC$15 billion expansion proposal hasoperator Imperial Oil (69.6 percentowned by ExxonMobil) and CanadianOil Sands, the largest stakeholder, atodds over the timing.
The original plans called for an initial50,000 bpd “debottlenecking” followedby a two-phase hike in bitumen produc-tion of 100,000 bpd each in 2014 and2020, placing about 115,000 bpd ofexcess raw bitumen supply on the openmarket.
But a spokesman for Imperial, a 25percent owner, has told reporters that hiscompany no longer believes the expan-sion will take place this decade, althoughhe said it would be “premature to talkabout specific project plans or timing orsequencing.”
However, he said Imperial remainscommitted to “the economic develop-ment of the entire resource at Syncrude.”
A spokeswoman for Canadian OilSands, whose stake is 36.74 percent,countered that all of the partners agreedto the last strategic plan, suggesting thatImperial was simply “putting out theirown view.”
She said there has been talk aboutcooperation between Syncrude and thenearby Kearl project, a joint venture byImperial and ExxonMobil to build a110,000 bpd mine at a cost of C$10.9 bil-lion.
The spokeswoman said the discus-sions have involved sharing labor andsome of the project management, but theImperial spokesman insisted his compa-ny views Syncrude and Kearl separately.
The other Syncrude partners areSuncor Energy 12 percent, China’sSinopec 9.03 percent, Nexen 7.23 per-cent, Murphy Oil 5 percent and MocalEnergy 5 percent.
ExxonMobil hired 4 years agoFollowing a series of unplanned out-
ages, the Syncrude partners hiredExxonMobil four years ago to improveoperations and reduce per barrel costs.
Currently, two processing units at theupgrading plant are offline, including a100,000 bpd coking unit.
Imperial insists that its immediate pri-ority is to improve reliability of the baseoperations.
FirstEnergy Capital analyst MichaelDunn said in a research note he hasreduced capital spending forecasts forCanadian Oil Sands after indications byother partners — “either subtly or direct-ly” — that expansions will not come online this decade.
“Since major expansions requireunanimous partner approval, we havereduced our cap-ex estimates materiallyin the 2012 to 2015 time frame.” Dunn
wrote.He said a spending cut could be posi-
tive for Canadian Oil Sands by easing thestrain on its balance sheet and allowing itto maintain dividend payments.
Suncor has been less than emphaticwhen asked about the future of itsSyncrude stake and the role of Sinopec,which acquired ConocoPhillips’ 9.03percent interest for C$4.65 billion lastyear, has yet to take shape.
Export vs. value-addedMost observers believe Sinopec wants
to pursue exports of raw bitumen fromSyncrude to its refineries in China,which is inconsistent with the Albertagovernment’s goal to see more of thevalue-added end of the oil sands remainin Alberta. But achieving the province’sobjective of upgrading 66 percent ofbitumen production compared with 58percent last year is not a simple matter.
Todd Hirsch, senior economist at ATBFinancial, said that building morerefineries and upgraders in Albertawould satisfy those “who believe weexport too much raw resource when weshould keep those jobs at home.”
“But that doesn’t solve the main prob-lem of cost, which is the primary reasonindustry is not racing to build refineriesin Alberta,” he said.
Alberta currently has 1.2 million bpdof upgrading capacity and expects to add270,000 bpd by 2016, but it is likely to beoutstripped by the growth in bitumen out-put to 3 million bpd in 2016 from 1.6million bpd in 2010.
In the process, the cost of labor, steeland other materials is expected toincrease inflationary pressure, making anuneconomic aspect of the oil sands sectoreven more expensive.
C$5 billion upgrading projectThe biggest upgrading project on the
table is a C$5 billion joint venture byNorth West Upgrading and CanadianNatural Resources to build a 150,000 bpdrefinery near Edmonton in three equalstages.
The Alberta government has alreadyagreed to provide 37,500 bpd of feed-stock bitumen to the plant from its royal-ty-in-kind program.
North West Upgrading Vice PresidentJerry Crail said a final investment deci-sion is targeted for late this year or early2012 as the partners try to head off risingcapital costs.
He said a final plan is in place and pri-vate investors and financial institutionshave pledged funding.
Canadian Natural Resources, which isexpected to supply 12,500 bpd of bitu-men, has indicated it hopes to gain boardapproval for the project in 2012.
Crail agreed there are operational andfinancial risks associated with building arefinery, but noted that substantial workhas already been completed for initialconceptual studies and detailed engineer-ing is due to start in March 2012. �
INTERNATIONALRecord number of vessels transit Arctic
According to a report in the Barents Observer a total of 34 vessels transited theNorthern Sea Route along the Russian coast of the Arctic Ocean this year. Withshrinking Arctic sea ice cover, both the Northern Sea Route and the NorthwestPassage through the Canadian archi-pelago have started to become ice freeafter the summer ice melt. And Russiahas a fleet of nuclear powered ice-breakers to escort ships around itsroute, and assist with navigating theroute when the sea is not entirely icefree.
According to the Barents Observer, the sailing season along the Northern SeaRoute lasted five months this year, from the end of June to the end of November.
The route remained open about one month longer than has become the norm, withthe total of 34 vessels being a record for the number of vessels transiting the route ina single open water season, the Barents Observer said. Of those 34 vessels, 15 carriedliquid cargos, three carried bulk cargo, four carried salmon under refrigeration, twocarried general cargo and 10 sailed in ballast. Of particular note were the fact that asupertanker — the Vladimir Tikhonov — plied the route for the first time, and the75,600-tons-deadweight bulk carrier Sanko Odyssey became the largest bulk carrierever to use the route, the Barents Observer said.
According to the Voice of Russia website, developing the Northern Sea Route, theshortest marine route between Europe and the Far East, has become one of Russia’stop priorities in the far north. In September at the International Arctic Forum, RussianPrime Minister Vladimir Putin said that Russia is developing the Northern Sea Routeby expanding existing ports and building new ports along the route; upgrading thetransportation infrastructure in the region; and expanding the country’s icebreak-er fleet.
—ALAN BAILEY
According to the Barents Observer,the sailing season along the
Northern Sea Route lasted fivemonths this year, from the end of
Potential Alaska state and federal oil and gas lease sales
Agency Sale and Area Proposed Date
DNR Beaufort Sea Areawide Dec. 7, 2011DNR North Slope Areawide Dec. 7, 2011DNR North Slope Foothills Areawide Dec. 7, 2011BLM NPR-A Dec. 7, 2011DNR Cook Inlet Areawide spring 2012DNR Alaska Peninsula Areawide spring 2012DNR Beaufort Sea Areawide fall 2012DNR North Slope Areawide fall 2012DNR North Slope Foothills Areawide fall 2012BLM NPR-A 2012BOEM 2013 Cook Inlet (special interest)BOEM Beaufort Sea 2015BOEM Chukchi Sea 2016
Agency key: BLM, U.S. Department of the Interior’s Bureau of Land Management, manages leasing inthe National Petroleum Reserve-Alaska; BOEM, U.S. Department of the Interior’s Bureau of Ocean
Energy Management (formerly Minerals Management Service), Alaska region outer continental shelfoffice, manages sales in federal waters offshore Alaska; DNR, Alaska Department of Natural Resources,Division of Oil and Gas, manages state oil and gas lease sales onshore and in state waters; MHT, Alaska
Mental Health Trust Land Office, manages sales on trust lands.
� L A N D & L E A S I N G
Deep Creek on holdpending Hilcorp saleAlaska Division of Oil & Gas, Cook Inlet Region Inc., agree todelay discretionary contraction until 6 months after sale or Sept. 1
By KRISTEN NELSONPetroleum News
The Alaska Department of NaturalResources’ Division of Oil and Gas
and Cook Inlet Region Inc., which jointlymanage Union Oil Company ofCalifornia’s Deep Creek unit, have agreedto delay any “discretionary contraction”of the unit “for a reasonable period oftime after close of the pending asset salebetween Union and Hilcorp EnergyAlaska, LLC.”
Division Director Bill Barron toldUnion in a Nov. 23 letter that because ofthe pending sale he will delay any discre-tionary contraction of the unit until sixmonths after the closing of Union’s saleof its Cook Inlet assets to Hilcorp or Sept.1, 2012, whichever occurs earlier.
The ninth plan of development for theDeep Creek unit is due Dec. 31, andBarron said he is extending the expirationdate of the eighth plan for the unit to coin-cide with the discretionary contractiondelay, making the ninth plan due the ear-lier of six months after closing of the saleor Sept. 1, 2012.
Sale announced in JulyThe sale of Union Oil’s Cook Inlet
assets was announced July 19. Union OilCompany of California parent Chevronand Hilcorp did not disclose financialterms, but said in a statement that thetransaction was expected to close by yearend pending customary regulatoryapprovals.
Assets in the sale include Union Oilcontracts and interests in the GranitePoint, Middle Ground Shoals, TradingBay and MacArthur River fields; interestsin 10 offshore platforms; interests inonshore gas fields including the Ninilchikunit and the Beluga River unit; and twogas storage facilities.
The sale also includes interests in theCook Inlet Pipe Line Co. and KenaiKachemak Pipeline LLC.
Unit formed in 2001The 20,000-plus acre Deep Creek unit
is on the southern Kenai Peninsula, somefive miles inland from Ninilchik, and pro-duces natural gas from the Happy Valleyparticipating area in the northern part ofthe unit. The division and CIRI approvedthe formation of the unit effective Dec.31, 2001. Union Oil is 100 percent work-ing interest owner in the unit. The divi-sion and CIRI approved formation of theHappy Valley participating Area Nov. 4,2004.
Alaska Oil and Gas ConservationCommission records show gas productionbegan in 2004; current production is from
seven completions. In its eighth plan of development, sub-
mitted in December 2010, Union said ithad no plans for any exploration drillingin the unit, but said it planned to continueefforts to farm out southern Deep Creekexploration acreage.
Barron said a ninth plan of develop-ment “must provide for the exploration ofthe unitized area and for the diligent andexpeditious drilling necessary for deter-mination of the unit area or areas capableof producing unitized substances in pay-ing quantities in each and every produc-tive formation. The plan must be as com-plete and adequate as necessary for time-ly exploration and development of theremaining unit area outside the HappyValley Participating Area, and must spec-ify the number and locations of any wellsto be drilled and the proposed order andtime for such drilling.”
Several potential accumulationsIn a December 2004 decision denying
a request by another leaseholder toexpand the unit, the division said“Unocal’s initial interpretation indicatedthat the unit area may encompass severalpotential hydrocarbon accumulations andexploration to date has confirmed thepresence of the Happy Valley reservoir inthe northern unit area.”
The 2004 decision said that since theformation of the Deep Creek unit, thecompany drilled 10 wells and acquired105 miles of proprietary seismic data.ConocoPhillips previously acquired fiveseismic lines over the unit area.
Current Alaska Oil and GasConservation Commission records show13 Happy Valley wells drilled between2003 and 2009; two of the 13 are showingas suspended.
The division said it “agrees withUnocal’s assessment that the Deep CreekUnit may contain multiple accumula-tions,” but said in its 2004 decision thatthe only confirmed commercial produc-tion is from the Happy Valley reservoir.
It said “Unocal’s interpretation of thedata also indicates a potential accumula-tion south of the Happy Valley reservoirthat Unocal refers to as the Middle HappyValley Prospect,” and said that the com-pany had planned to drill two wells froma new pad to evaluate the prospect, and inMarch 2004 requested approval of a planto build a road and construct the HappyValley Middle Saddle Pad.
Neither the road nor the pad was con-structed and no Middle Happy Valley wellwas drilled. �
As illustrated by a long-standing disputebetween the State of Alaska and oil
companies over delays in the developmentof the Point Thomson field on the NorthSlope, governments expect firms owningoil and gas leases on public lands to active-ly explore for and develop publicly ownedresources. And a recent “notice to lessees”published by the Bureau of Safety andEnvironmental Enforcement, or BSEE,illustrates something of the federal govern-ment’s expectations for activity by lease-holders on the federal outer continentalshelf.
On Nov. 15 the agency published anappeal decision over a request to extend theterms of some leases in the Gulf of Mexico.The decision will act as guidance over thecircumstances under which the term of anOCS lease may be extended, a procedureknown as a “suspension of production,”BSEE said.
“Suspensions can be granted to lease-holders to extend a lease past the primaryterm for oil and gas leases on the outer con-tinental shelf,” BSEE said. “Typically alease will have a primary term of five, eightor 10 years, depending on the water depth.”
The appeal decision published by BSEErelated to three leases owned byExxonMobil Corp. and Statoil Gulf ofMexico LLC in an area of the Gulf ofMexico known as Walker Ridge.
Due diligenceUnder the terms of the Outer
Continental Shelf Lands Act, a lessee hasthe right to explore for, develop and pro-duce oil and gas in an OCS lease, providedthat the lessee shows “due diligence” indoing so. If a lessee requests a lease termextension the federal government deter-mines whether the due diligence criterion isbeing met by assessing what is termed thelessee’s “commitment to produce,” a criteri-on that requires the lessee to have complet-ed sufficient exploration and appraisalwork within the leased land to enable adecision to proceed to the production of oiland gas.
Apparently, ExxonMobil and Statoilpurchased the Walker Ridge leases in June1998. About three years later the companiesabandoned an initial plan to drill into rocksof Miocene age in their leases afterexploratory wells in neighboring leases hadfailed to encounter oil in equivalent rockunits. But in December 2006, prompted by
some nearby oil discoveries in older anddeeper Paleocene rocks, the companiesdrilled a well into the Paleocene withintheir Walker Ridge leases and found oil.That well was completed in April 2007, bywhich time the leases were in the ninth yearof their 10-year terms.
In February 2008, with only a fewmonths of life left in the leases, MMSapproved lease unitization, withExxonMobil as operator. At about the sametime ExxonMobil started drilling a secondwell in the new unit, again finding pro-ducible oil.
That second well was completed in June2008. And under federal regulationsExxonMobil had 180 days from that date toapply for an extension of the lease beyondthe original lease termination date.
Extension requestIn October 2008 the company duly
applied for a seven-year lease extension, “toallow for proper development,” the appealdecision says. The company said that thistimeframe would accommodate a develop-ment concept in which production wellsfrom the new unit would be tied back tofacilities to be developed by Chevron forsome adjacent fields.
However, ExxonMobil’s extensionapplication expressed some caution aboutwhether Chevron’s development wouldactually take place. The company said thatit was also considering other options for itsown field, including the possibility of astandalone development, but that it couldnot commit to a standalone developmentusing the information that it currently hadavailable.
In February 2009 MMS turned down theapplication for the lease extension, sayingthat, because ExxonMobil’s plan dependedon Chevron’s facility development, a devel-opment not yet under way and not subjectto any form of agreement between the twocompanies, ExxonMobil’s commitment toproduce claim was not based on activitieswithin the company’s control.
Decision appealedFollowing an appeal by ExxonMobil,
the Interior Board of Land Appeals, theDepartment of the Interior’s internal landdecision review body, subsequently over-turned the MMS decision, saying that anagreement between ExxonMobil andChevron to share the cost of front-end engi-neering design for shared field facilitiesdemonstrated a commitment to produce.The board also said that MMS had previ-
ously granted lease extensions in situationswhere there was even less evidence for that“commitment to produce” criterion.
In February 2010 MMS asked RobertMore, the director of Interior’s Office ofHearings and Appeals, to review the board’sdecision — the board is a section within theOffice of Hearings and Appeals. And onMay 31 2011, More issued his review deci-sion, upholding the original MMS decisionto decline the lease extension. It is this deci-sion that BSEE has now issued as guidanceover the circumstances under which leaseextensions may be granted.
Lack of commitmentMore said that the lack of commitment
by ExxonMobil to either a tie-in to the pro-posed Chevron facility or to a standalonefield development demonstrated, at most, acommitment to development, but not therequired commitment to produce.Moreover, under federal regulations, therequested lease extension of seven yearsexceeded a five-year extension limit, hesaid.
The signing of the agreement betweenExxonMobil and Chevron to share the costof developing the facility engineeringdesign came after the date by whichExxonMobil had to establish a commitmentto produce from its unit, More said. And,although by May 2009 MMS had satisfieditself that Chevron was going to build itsfacility for its fields, at that pointExxonMobil had not come to an agreementwith Chevron for the use of that facility, norhad ExxonMobil committed to a standalonedevelopment should negotiations with
Chevron fail, More said. Under the terms ofthe Outer Continental Shelf Lands Act,negotiations to use a third-party productionfacility are not considered to be field devel-opment, he said.
More also said that previous MMS deci-sions over lease extensions did not set aprecedent for the decision under appeal. Headditionally said that the Interior Board ofLand Appeals had erred in not referring theboard’s decision back to MMS for verifica-tion that the decision met the national inter-est in resource development on publiclands.
Agency dutyOn Nov. 15, in commenting on the
appeal decision, Michael Bromwich, thethen director of BSEE, emphasized hisagency’s duty to ensure appropriate devel-opment of public resources.
“BSEE takes its responsibilities astrustee of offshore public lands extremelyseriously,” Bromwich said. “The energyresources that are located on the outer con-tinental shelf belong to all American tax-payers, and BSEE’s responsibilities includeensuring that public resources are devel-oped in an expeditious and orderly way. TheOffice of Hearings and Appeals decisionhighlighted in this notice to lessees under-scores the need for lessees to take concretesteps to develop their holdings in a mannerthat is consistent with the terms of theirlease agreements.” �
PETROLEUM NEWS • WEEK OF DECEMBER 4, 2011 7
Courtesy of Northrim Bank’s Partnershipwith the Alaska World Affairs Council
LOOK WHAT’S COMING!A very special series of speakers discussing
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December 9, 2011 Jose Lima, Vice President of LNG, Gas Monetization & Wind Energy, Shell Upstream Americas – “Global LNG – A Shell View.”
January 20, 2012 Larry Persily, Federal Coordinator for Alaska Natural Gas transportation Projects. Presentation - “Alaska’s Natural Gas: Does any Country need it?”
February 3, 2012 Kevin Book, Managing Director, Research Clearview Energy Partners, LLC.
April 20, 2012 Lou Pugliaresi, President of the Energy Policy Research Foundation Presentation – “The Coming Renaissance in North American Oil & Gas.”
May 11, 2012 Edward Chow, Senior Fellow, the Energy & National Security Program, CSIS.Presentation – “Shifting the International Petroleum Landscape.”
For more information, please visit: alaskaworldaffairs.org
� L A N D & L E A S I N G
When is an OCS commitment a commitment?BSEE publishes appeal decision that agency says clarifies conditions for extending offshore lease term through commitment to produce
A study by Black & Veatch for theAlaska Gas Pipeline Project Office,
GPPO, is recommending that the bestway to provide local off-take from alarge-diameter natural gas pipeline wouldbe to install stubs during construction.
Kurt Gibson, GPPO director, said in aNov. 28 press release that installing stubsas the line is built would provide gas off-takes that “are both reasonable and adapt-able to community needs.”
The focus of the Alaska PipelineProject continues to be a line to commer-cialize Alaska North Slope natural gas,GPPO said.
Gibson said the Black & Veatch“study identified the possibility ofinstalling stubs at strategic locationsalong the route that could be activated —‘hot tapped’ — at some point in time aftercompletion of a big gas line.”
He said that “approach provides flexi-bility for communities, utilities and otherparties interested in accessing natural gasto enter into commercial agreements forobtaining gas on their own schedule.”
Capital costs for a community gas off-take system — not including the localdistribution system — were in the$150,000 to $200,000 range, per loca-tion, with an estimate of $50,000 to$75,000 per year in operation and main-tenance costs per location.
Two options consideredThe Black & Veatch report said GPPO
identified two potential options to facili-tate delivery of natural gas to small com-munities and industry: compressor sta-tion side stream and stub gas delivery.
There will be eight compressor sta-tions along the line to maintain gas pres-sure and they require natural gas atreduced pressures to fuel compressor tur-bines and other utilities, typically 600 psicompared to the 2,500 psi mainline oper-ating pressure.
Drawing off gas at compressor sta-tions would take advantage of thereduced pressure, but Black & Veatchsaid it found that “business and regulato-ry concerns” were likely to make suchdelivery points unfeasible. Also, such gaswould be available only to communities“within a feasible distance to a particularcompressor station.”
The other option studied, the use ofstubs, would include installation of stubsat points on the line identified for off-take during mainline construction.
A small diameter stub piece of pipe“would be welded on and tested duringconstruction of the pipeline. The stubwould not have live gas in it and its endlocation would be marked with a standardpipeline marker for future reference oncea commercial agreement has beenreached for the community the stubwould serve,” the report said.
Hot tappingOnce a local community or industry
reached a commercial agreement to buygas, the pipeline would need to be tapped.
“The hot tapping procedure wouldinvolve removing the stub cap and secur-ing an isolation valve to the end of thestub. Hot tapping equipment would thenbe connected to the isolation valve, the
Customer focused. Safety driven. Process oriented.
Black & Veatch study recommends stubsNatural gas off-take stubs would be built as line from Alaska North Slope is built; activated when commercial agreements reached
A s occurred in Japan, the Arab oilembargo of 1973 hit European util-
ities between the eyes. The six-monthembargo slashed world oil production byabout 4 percent. An assertive OPECpushed a doubling of world oil pricesfrom 1972 to 1975.
Western European demand for oilplunged 23 percent during those years.Europeans wanted new suppliers of ener-gy, and in natural gas they had somegood options.
Russia had giant gas fields lookingfor an export market. Norway had bignew discoveries in the North Sea. AndAlgeria, too, was home to some giantfields.
Gas trading was relatively new inEurope at the time. Belgium, Germanyand France were the first to import natu-ral gas, from a major Netherlands fieldcalled Groningen discovered in 1959.
In trying to figure out how to pricegas to provide a fair return as well as thefortune needed to develop the field andpipelines, the Dutch linked natural gasprices to the prices of substitute fuel oilsand insisted on long-term contracts.
Russia, Norway and Algeria adoptedthat pricing structure for similar reasons,and it persists today for much ofEurope’s pipeline-gas imports. Thosethree nations and their handful of mega-fields remain Europe’s top source of for-eign gas supplies. (Russia, Norway andAlgeria were the world’s No. 1, 2 and 5gas exporters last year, joined by Qatarand Canada in the No. 3 and 4 positions,with the Netherlands at No. 6. As for gaspricing in Europe, the United Kingdomgas market is more like North America’sthan continental Europe’s, as will be dis-cussed below.)
The price link to oil in Europe wasn’tas iron-clad as in Japan, however.Exporters discounted gas prices toreflect the cost of competing fuels —heavy fuel oil for industry and distillatefor power plants, the EIA said. Othernotable contract features: the gas desti-nation was locked in to prevent a buyerfrom diverting gas from a lower-pricedmarket to a higher-priced market theexporter also was serving — blockingunwanted competition — and the gasprice could get renegotiated periodically.
Since the pivotal economic year of2008, this decades-long system has beenunder attack by gas buyers.
The oil-gas price linkWith oil prices currently near historic
highs and the local economies wobbly,many European gas buyers are demand-ing price relief. They’re aiming theirfrustrations at Russia’s Gazprom, whosepipelines dominate the European gastrade.
The big European gas buyers areplaying tough. To show Gazprom theymean business, they have boosted theirspot and short-term buys of LNG, oftenfor lower prices than the pipeline gas.They’ve got a motivated LNG exporterin Qatar, which has far more capacity tomake LNG than it has buyers. Qatar willnegotiate its LNG price. Last year, Qatarsent some 40 percent of its LNG toEurope.
(Qatar gas sold for $15 to $16 per
million Btu in East Asia in June, whileselling for $9 to $12 in Europe thatmonth and $4.25 in Texas, according toArgus.)
European imports of LNG grew by 26percent last year, while pipeline-gasimports from Russia fell by 2 percent,the EIA said.
Gazprom is not powerless in this fight— long-term supply contracts are apotent weapon.
But Gazprom doesn’t want to jeop-ardize its European market share, whichunderpins its export business.
PETROLEUM NEWS • WEEK OF DECEMBER 4, 2011 9
� N A T U R A L G A S
Europe — a loosening link to oil prices
� Part 3 of 4
In some cases Gazprom ischanging the basket of oil prices ituses, often adding spot gas pricesto the formula, so gas-compared-to-gas pricing is gaining a toehold
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valve would be opened, and the pipelinewould be tapped whilst in operation.With the isolation of the valve andremoval of the hot tapping equipment,the gas delivery location would be readyfor service,” the Black & Veatch reportsaid.
The stub would have to be extendedand a metering/regulating stationinstalled, consisting of three sectionswhere the pressure would be reduced inthree steps from the 2,500 psi on themainline to an outlet range of 125-300psi.
Four stages of gas heating would alsobe required.
Black & Veatch said the meter-ing/regulating sections would be prefab-ricated offsite and installed once the sitehas been prepared.
The estimated cost for the meter-ing/regulating station of $150,000 to$200,000 is based on discussions withequipment suppliers, prefabricators andcontractors who build equipment, thereport said. The estimate is also based onthe assumption that several meter-ing/regulating stations are built at thesame time, “and does not include anyline items for the stub, hot tapping oper-ations or the distribution system down-stream of the M/R station,” Black &Veatch said.
Heating value issueThe report said that in addition to the
difference between the mainline operat-ing pressure and gas pressures neededfor local distribution, the mainline gas“will likely have a heating value higherthan what is typically delivered to resi-dential customers.”
Based on available gas analysis pro-vided under the Alaska GaslineInducement Act, Black & Veatch said“The gas specification proposed fortransmission in the pipeline is relativelyuncommon in a number of its character-istics, namely the high calorific value ofthe gas and its low water content.” AGIAincluded “rich” and “lean” gas cases,with the rich gas having a heating valueof 1,118 British thermal units per cubicfoot and the lean case having a heatingvalue of 1,067 Btu.
Black & Veatch said parts of gas sys-tems in Alberta, Canada, and in the east-ern United States, have Btu content rang-ing from 1,000 to 1,110 Btu per cubicfoot without “significant issues” relatedto the high Btu content.
Black & Veatch also looked at vol-umes of potential gas usage by commu-nities along the pipeline in NorthernEconomics’ “In State Gas DemandStudy,” and estimated that the majorityof communities along the pipeline(Wiseman, Coldfoot, Stevens Village,Harding-Birch Lakes, Dot Lake,Tok/Tanacross/Tetlin, NorthwayJunction/Northway Village, Paxson,Gakona, Gulkana, Glennallen, CopperCenter, Willow Creek and Tonsina)would have average usage of less than 1million cubic feet per day. Big Delta,Delta Junction and Deltana are estimatedat 1 million cubic feet per day. Valdez isestimated at 7 million cubic feet per dayand Livengood at 9 million cubic feet perday.
Black & Veatch said it anticipates“that the small diameter stub size willallow for sufficient gas supply volumesfor all potential delivery point sitesexcept for Fairbanks or Anchorage.” �
In some cases Gazprom is changing thebasket of oil prices it uses, often addingspot gas prices to the formula, so gas-com-pared-to-gas pricing is gaining a toeholdover gas-linked-to-oil pricing. Usually, thenew price is good for a fixed period, suchas two or three years. This suits the buyers,who know that oil prices can fall as well asrise.
European buyers also are playing toughwith LNG suppliers, not only by some-times getting better prices than they payfor pipeline gas. Supply contracts areshorter — five to 10 years instead of per-haps 25-year terms from a few years ago.And new language is letting buyers divertcargos to other markets — such as the pre-mium-priced Japan spot market in 2011.
It’s unclear how loose the oil-price linkwill become for continental Europe gasprices. But Norway recently “switched asmuch as 30 percent of their contracted vol-umes to spot-market pricing,” the EIAsaid.
The British differenceNatural gas pricing in the United
Kingdom is different from pricing on thecontinent.
Natural gas is the top fuel source inGreat Britain, while in many Europeancountries gas is a mere sidekick to oil as anenergy source — in Germany gas was No.3 behind oil and coal last year.
Like North America, the gas market inthe U.K. developed over the past severaldecades based on its own gas reserves,often from small to medium-sized fields,not imports. That is different from conti-nental Europe’s high dependence onimports from giant fields, according to theEnergy Charter Secretariat, a group thatupholds international laws to ensure thesmooth flow of energy between exportersand importers.
Further, Great Britain began liberaliz-ing its markets in the 1980s, while conti-nental Europe is still deregulating its ener-gy markets.
The nation even developed a hypotheti-cal trading hub called the NationalBalancing Point, through which gas in thecountry must “pass.” NBP is akin to theHenry Hub in the United States, an actualtrading hub, and the NBP price is typicallycited in lists of European gas prices. Anactive futures market tied to the NBP alsohelped Great Britain separate itself some-what from the rest of Europe on natural gaspricing.
During the peak years of Britain’sNorth Sea production, some gas was dirtcheap, creating another departure from thecontinent’s oil-linked gas prices. Thischeap gas came up wells with oil or valu-able gas condensate. Because gas flaringwas not allowed and gas injection some-times wasn’t cost-effective, producers dis-counted the gas just to get rid of it — justas occurred in Alaska’s Cook Inlet duringthe 1960s and 1970s, the early years ofproduction there.
All this let U.K. price its gas based onsupply and demand within the country, notoil prices. The continent’s oil-linked pricesdid influence U.K. gas prices, however,because excess British production wasexported.
But those exports have ended. GreatBritain hasn’t been self-sufficient in natu-ral gas since 2003. The U.K.’s gas produc-tion plunged 45 percent from 2003through last year, while gas consumptiondipped 2 percent.
As a result, British utilities and othergas consumers import some gas, mainlyvia pipeline from Norway’s North Seafields, but also via pipeline from the
Netherlands, especially during winter. Thismeans the nation’s gas price is not com-pletely divorced from the long-term, oil-linked-pricing contracts found on the con-tinent. But the NBP price usually is a littlelower than prices found on the continent.
Last year, the U.K. also was officiallyEurope’s No. 2 LNG importer, behindSpain. But much of the LNG gas landed inthe U.K. was then piped to the continent —with Britain’s well-developed gas infra-structure and better-developed gas tradingmarkets a catalyst for delivering the LNGthere rather than elsewhere in Europe.(Russia’s Gazprom is a minority investorin one pipeline connecting Britain to thecontinent.)
Editor’s note: This is a reprint fromthe Office of the Federal Coordinator,Alaska Natural Gas TransportationProjects, online atwww.arcticgas.gov/print/Europe-a-loos-ening-link-to-oil-prices.
Annual Average Employment — StatewideAnnual Average Employment — North Slope Borough
Alaska Oil Industry EmploymentStatewide and North Slope Borough 2000-2010*
*Preliminary2010 annual average employment numbers for the North Slope Borough were not available as of the publish date for this chart
Source: Alaska Department of Labor and Workforce Development, Research and Analysis Section and U.S. Bureau of Labor Statistics
Alaska Statistics
Petroleum News will be reproducing this standalone chart from the Alaska Oil and Gas Conservation Commission on a regular basisbecause of the interest in the decline in Alaska’s oil production.
Alaska's Average Daily Oil and NGL Production Rate1960 - 2010
BP Exploration (Alaska) Inc. is amongseveral subsidiaries of BP America
Inc. involved in a complex, multistate set-tlement of “financial assurance” viola-tions with the U.S. EnvironmentalProtection Agency.
“Financial assurance protects taxpay-ers from having to foot the bill for costlycleanups,” Cynthia Giles, assistant
administrator for the EPA’s Office ofEnforcement and Compliance Assurance,said in a Nov. 29 press release out ofWashington, D.C.
The EPA determined that BP Alaska,BP Products North America Inc., BPWest Coast Products LLC, BPCorporation North America Inc. andAtlantic Richfield Co. had inadequatefinance assurance.
The settlement “will ensure that BP’ssubsidiaries have the funds available tocover any necessary cleanup costs,” Gilessaid.
Terms of settlementThe settlement covers hazardous waste
facilities and Superfund sites in eightLower 48 states, plus 10 “non-hazardouswaste underground injection control(UIC) wells” on Alaska’s North Slope.
The BP subsidiaries have agreed topay a $426,500 penalty and ensure thatmore than $240 million in funds aresecured to resolve violations of hazardouswaste, drinking water and Superfundfinancial assurance requirements, the
EPA press release said.Under the settlement, BP has lined up
financial assurance such as letters ofcredit, insurance policies and other formsof coverage, the EPA said.
In Alaska, the 10 injection wells weresubject to financial assurance require-ments under the Safe Drinking Water Act.
BP has provided assurances of $19.2million to address the closure, pluggingand abandonment of the UIC wells, theEPA said.
BP also had inadequate financialassurance coverage for facilities, includ-ing the wells, for which the states haveprimary enforcement responsibility, theagency said.
“EPA worked with its state partners toobtain from BP a total of $76.4 million incompliant financial assurance coveragefor these obligations,” the EPA said.
Petroleum News on Nov. 29 asked BPfor additional information on the allegedAlaska violations, including the fieldlocation and function of the injectionwells.
BP Alaska uses the injection wells “todispose of non-hazardous waste at remoteoil field sites at Prudhoe Bay, Badami,Northstar, Milne Point and the DuckIsland/Liberty project,” BP spokesmanScott Dean said by email. “Most of theinjected fluids are brine, which is pro-duced when oil and gas are extractedfrom the field.”�
12 PETROLEUM NEWS • WEEK OF DECEMBER 4, 2011
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BP Alaska involved in big EPA settlementSubsidiaries agree to pay $426,500 penalty, arrange ‘financial assurance’ to close and clean up contaminated industrial sites
Under the settlement, BP has linedup financial assurance such as
letters of credit, insurance policiesand other forms of coverage, the
EPA said.
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A laska North Slope production aver-aged 624,687 barrels per day in
November, up 6.2 percent from anOctober average of 588,287, according tofigures based on pipeline receipts asreported by the Alaska Department ofRevenue’s Tax Division.
The BP Exploration (Alaska)-operatedPrudhoe Bay field had the largestincrease, 11.1 percent, averaging 361,656bpd compared to 325,502 bpd in October.
October production figures forPrudhoe Bay as reported by PetroleumNews in early November have beenadjusted by adding production from MilnePoint and Northstar. Beginning withNovember, Revenue is reporting MilnePoint and Northstar as part of PrudhoeBay. Previously Prudhoe Bay productionfigures included only Prudhoe Bay and itssatellite fields, Aurora, Borealis,Midnight Sun, Orion and Polaris.
The BP-operated Lisburne field hadthe second-largest month-over-month pro-duction increase, 7.2 percent, averaging
The Alaska District of the U.S. ArmyCorps of Engineers has public
noticed an application from Exxon MobilCorp. and PTE Pipeline LLC for PointThomson project development. The pro-posed work in federal waters at PointThomson, some 60 miles east of PrudhoeBay and 60 miles west of Kaktovik,would initiate commercial hydrocarbonproduction and delineate and evaluatehydrocarbon resources in the PointThomson area.
Three gravel pads, an export pipeline,an airstrip, mine site and support pad areproposed, the corps said in a Nov. 18 pub-lic notice; comments are due on the pro-posal Jan. 3, which is also the closing datefor comments on the draft environmentalimpact statement which was released forpublic comment in mid-November.
The corps said it will prepare a finalEIS after the close of the draft EIS publiccomment period in response to commentsreceived and will make a permit decisionafter the final EIS has been published.
A record of decision will describe itsdecision on the permit application.
The draft EIS analyzes environmentalimpacts of the project proposed by the
applicant, and compares that proposaland three other alternatives to the humanand environmental impacts associatedwith the no action alternative.
Wetland fillThe corps said that the total acreage of
wetland fill for the project as proposed byExxonMobil would be approximately267.5 acres, and would include gravel fordrilling-production pads and connectingroads, airstrip, gravel mine and overbur-den replacement, vertical support mem-bers for in-field pipeline and exportpipeline and pilings for a proposed bargeoffloading facility and service pier. Thefill material would come from a newmine site approximately 2.5 miles inland.
The project would include three gravelpads, five development wells, infieldgathering lines, 12 miles of infield gravelroads, a 5,600-foot airstrip, a gravel mine,processing facilities and support infra-structure and a sales oil pipeline toBadami.
Two of the wells were drilled in 2009-10 from the existing central pad and didnot require new fill.
Long-reach directional drilling will beused to develop the primarily offshoreThomson Sand reservoir from onshorepads near the coast.
The central pad (56 acres including13.2 acres of existing fill) involvesexpansion of the existing Point ThomsonUnit No. 3 pad. Processing facilities atthe central pad would separate hydrocar-bon liquids from natural gas, re-inject thegas and stabilize liquid hydrocarbons fortransport in the Point Thomson export
pipeline. The west pad, approximately 19 acres,
would be a new pad 4 miles west of thecentral pad; the east pad would connect anew 11-acre pad on the coast to the exist-ing 4.6-acre North Staines River No. 1
APPLICANT: EXXON MOBIL CORPORATION &PTE PIPELINE LLC.
� E X P L O R A T I O N & P R O D U C T I O N
Corps public noticesThomson applicationComments due Jan. 3 on ExxonMobil proposal for facilities,pipeline project; construction projected to begin winter of 2012-13
production was up to 400 percent of whatit was when it was shut-in.
Wilcox said the company has contin-ued to optimize wells at its onshore prop-erties.
It took longer to get the Osprey plat-form back into operation, but first oilcame off the platform in June, he said.With a $100 million credit facility workbegan on a big rig for the Osprey platformso the company could begin drilling side-tracks from the platform and increase pro-duction. About a third of that rig is now inNikiski, Wilcox said, and work will beginon the platform in the next few months.
Cook Inlet Energy is also building asmall rig on the west side that will betruck mounted and “should be just anideal rig for drilling gas on the west side.”
The company is “getting set up to exe-cute our second phase of development onthe Osprey platform” with the new rig, iscontinuing to optimize production fromexisting wells and continuing to exploitoil and gas reserves near its facilities,Wilcox said.
Enstar, CINGSAJohn Sims, director of corporate com-
munications for Cook Inlet Natural GasStorage Alaska and Enstar Natural Gas,told the RDC audience that while Enstaris “very cautiously optimistic about allthe activities going on here in CookInlet,” it has concerns until it has a con-tract for gas delivery before theRegulatory Commission of Alaska.
Semco Energy, Enstar’s parent compa-ny, and MidAmerican LLC, partners inCook Inlet Natural Gas Storage Alaska, orCINGSA, were joined in October by FirstAlaska and Cook Inlet Region Inc., Simssaid.
The five injection-withdrawal wellsare being drilled for the storage project,with the project on schedule and slightlyunder budget. The first well cost about $7million and the second two came in atabout $5 million each, prior to perforat-ing.
The middle three wells, technically theeasiest, were drilled first, Sims said. It hastaken about 30 days per well, with abouthalf of that time required to move the rig.The wells should be completed byFebruary.
With four customers for storage capac-
ity — Enstar,Chugach ElectricAssociation, ML&Pand Homer Electriccoming in later —CINGSA is at 11percent capacity forthe 11 billion cubicfeet of gas storage.
There is expan-sion capacity at thefacility and Sims said expansion will be“dependent on performance and also themarket demand.”
Having storage, which will be avail-able for withdrawal in the winter of 2012-13, helps with swing demand in the win-ter, he said, helps producers with produc-tion in the summer when gas is injectedand acts as an insurance policy shouldthere be equipment failure.
Asked whether with successful gasexploration and storage the utilities willstill need LNG, Sims said, “storage isn’tthe savior for Cook Inlet by any means;it’s a part of the puzzle.”
“Another piece involves the additionalexploration and development that we’reseeing.”
But, he said, Enstar and the utilities arestill evaluating the LNG option, “not just
for gasifying going forward put also foran insurance policy.”
And, he said, “until we actually havethose contracts that erase that need, it’ssomething that we’re still going to have tomove forward with.”
Cook Inlet Region Inc. Ethan Schutt, senior vice president,
land and energy development, for CookInlet Region Inc., said the Fire Islandwind project has regulatory approval forcontracts from the RegulatoryCommission of Alaska.
Financing for the project needs to beclosed, “so that we can move into projectconstruction in April,” he said, adding thatthe project has all its permits.
CIRI is also working on an under-ground coal gasification or UCG project.
The Cook Inlet basin has a “world-class coal resource that’s really never beenexploited at a commercial level,” Schuttsaid.
CIRI has been working on UCG foralmost three years, he said, and to date has“drilled 13 stratigraphic core holes to testboth the geology and the resource,” andcollected a suite of oil and gas type dataduring that program, “so we have a prettyrobust data set from that site, a place justnorth of the Beluga River on the northside of Cook Inlet on CIRI surface andsubsurface land.”
The data has been incorporated into ageological model.
CIRI is currently shooting some eightand a half line miles of “shallow high-res-olution 2-D … to tie together all the datapoints that we collected with the drillingprogram and enhance our data set as wemove towards a … characterization pro-gram to begin sometime in 2012.”
The project represents some 300-plusmillion tons of coal, Schutt said, “theequivalent of more than 4 (trillion cubicfeet) of natural gas on an energy basis, sojust in our little site we have quite aworld-class resource in that coal.” �
14 PETROLEUM NEWS • WEEK OF DECEMBER 4, 2011
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exploration pad. The existing pad at theeast pad location would be used for tem-porarily staging equipment and campsduring drilling.
Beginning in 2012-13The corps said construction activities
are proposed to begin in the winter of2012-13 and be completed by the winterof 2015-16, with civil construction —including gravel placement and gravelmining — to be conducted mainly in thewinters of 2012-13 and 2013-14.
Production infrastructure constructionwould begin in early 2013 and be com-pleted in the winter of 2015-16, withlarge processing modules arriving bysealift in the summer of 2015.
Drilling would begin in early 2015 andbe completed in early 2017.
Facility module installation, commis-sioning and startup are planned for 2015and early 2016.
The common carrier export pipelinewould be subject to Federal EnergyRegulatory Commission regulation. The22-mile 12-inch diameter line would takeprocessed liquid hydrocarbons from thecentral processing facility to a connectionwith the sale oil pipeline at the Badamifacility. �
Offshore Newfoundland and Labrador has received a strong vote of confidencefrom a trio of international companies which has committed to spending C$348million exploring two parcels.
The Canada-Newfoundland and Labrador Offshore Petroleum Board saidNorway’s Statoil, Spain’s Repsol and U.S.-based Chevron made successful bids ofC$202 million for one 610,300-acre block in the Flemish Pass/North CentralRidge and C$146 million for a nearby 461,300 acres.
The bids represent the amount of money the companies plan to spend on explo-ration.
Statoil will operate both blocks with a 50 percent stake; Chevron will hold 40percent and Repsol 10 percent.
Among other offerings in the call for bids, privately held Ptarmigan Energysecured rights to two parcels, covering a combined 875,000 acres, offNewfoundland’s west coast for C$2 million.
2009 discovery at MizzenThe Flemish Pass license is adjacent to Statoil’s Mizzen discovery that was
drilled in 2009, with Husky Energy as a 35 percent partner, although the compa-ny has kept a tight lid on information about the well.
It said only that “hydrocarbons were encountered” during deepwater drillingabout 300 miles east-northeast of St. John’s, the capital of Newfoundland, andwould not indicate whether the find was oil or natural gas.
A company spokesman said it would take at least two years to analyze the dataand decide whether to conduct appraisal drilling.
He said that if reserves would support a commercial operation it could takeanother 10 or 15 years before development and production was possible.
Statoil is already involved in the province’s producing Hibernia and Terra Novafields and is a partner in the Hebron project that is moving towards production.
The Flemish Pass area has been only lightly explored, but has been rated as apotentially import frontier.
—GARY PARK
Evaluation of VMT remote control plannedAn oil industry watchdog organization wants to study how remote control opera-
tions are working at the tanker terminal in Valdez.The Prince William Sound Regional Citizens’ Advisory Council says it intends to
hire a consultant by Dec. 15 to conduct the study.The consultant will examine such questions as whether Anchorage-based con-
trollers of assets at the Valdez Marine Terminal, or VMT, are “properly trained,” saysa council request for proposals.
The terminal is where tankers pick up Alaska North Slope crude oil for delivery toWest Coast refineries. Alyeska Pipeline Service Co., an energy company consortiumheadquartered in Anchorage, operates the terminal, which sits at the southern end ofthe 800-mile trans-Alaska pipeline.
The VMT is a massive complex of oil storage tanks, ship piers and loading arms.
Remote operations centersThe pipeline and Valdez terminal have been in operation since 1977.The facilities previously were run from a control center in Valdez. In 2007 and
2008, Alyeska established two new centers, the main one in Anchorage and a backupin Palmer, and shifted to remote control operations.
Alyeska said at the time it was an efficiency move made possible by such techno-logical advances as high-speed Internet and fiber optics.
The citizens’ council, a congressionally sanctioned and industry-funded nonprofitestablished after the Exxon Valdez oil spill, said its consultant will assess the capabil-ity of remote controllers to “reliably control operations at the VMT or to appropriate-ly interface with local controllers at the VMT.”
Specifically, the consultant will identify which VMT assets are subject to remotecontrol and which are under local control; review whether Anchorage-based con-trollers are properly trained; verify the extent to which redundancy of communicationsexists for VMT control; assess the likelihood that damage to communications couldaffect Alyeska’s ability to control the terminal; assess whether remote control providesthe same level of VMT control as when the operations center was located in Valdez;and verify the extent to which Alyeska can control the VMT from Anchorage without“environmental incident.”
The consultant’s final report will be due Aug. 15, 2012.The citizens’ council is charged with oversight of the marine terminal and associ-
ated tankers; it does not have oversight over the length of the pipeline.—WESLEY LOY
PIPELINES & DOWNSTREAM
33,259 bpd in November compared to31,041 bpd in October. Lisburne includesproduction from Point McIntyre andNiakuk.
The BP-operated Endicott field alsosaw an increase in month-over-month pro-duction, up 1.1 percent to 12,024 bpd inNovember from 11,893 bpd in October.Endicott production includes the Savant-operated Badami field.
Kuparuk River field averaged 137,038bpd in November, down 0.5 percentfrom an October average of 137,657.Kuparuk includes production fromMeltwater, Tabasco, Tarn and West Sak,as well as from the Eni-operatedNikaitchuq field and the Pioneer NaturalResources Alaska-operated Ooogurukfield.
The Alaska Oil and Gas ConservationCommission reports production by fieldand pool, but that data is only available
on a delayed basis. AOGCC Octoberdata for Nikaitchuq shows 185,118 bar-rels for the month, an average of 5,972bpd, and a total of 194,878 barrels forOooguruk, an average of 6,286 bpd.
November production from theConocoPhillips-operated Alpine fieldaveraged 80,710 bpd, down 1.8 percentfrom an October average of 82,194 bpd.Alpine includes satellite productionfrom Fiord, Nanuq and Qannik.
AOGCC October production figuresfor Cook Inlet show a total of 335,780barrels, an average of 10,832 bpd.Production comes from Beaver Creek(4,432 barrels), Granite Point (62,479barrels), McArthur River (121,421 bar-rels), Middle Ground Shoal (73,604 bar-rels), Redoubt Shoal (10,997 barrels),Swanson River (16,142 barrels), TradingBay (15,407 barrels) and West McArthurRiver (31,298 barrels). ANS crude oilproduction peaked in 1988 at 2.1 millionbpd; Cook Inlet crude oil productionpeaked in 1970 at more than 227,000bpd. �
Crowley sells CATCO All-Terrain vehicle assets to PeakCrowley Maritime Corp. said Nov. 29 that
it has sold its fleet of company-ownedCATCO® Arctic All-Terrain vehicles and relat-ed assets, including a warehouse and officefacility in Deadhorse, Alaska, to Peak OilfieldServices Co.
Though the sale ends nearly 40 years ofCrowley-provided specialized tundra trans-portation services, the company remains com-mitted to providing tug and barge transporta-tion and project management services forNorth Slope producers.
“Crowley has enjoyed a long successful history with our CATCO operations on the NorthSlope, starting in 1972,” said Crowley’s Craig Tornga, vice president of Crowley’s solutionsgroup. “We’ve used these specialized assets to support North Slope exploration with remoteoff-road arctic transportation and construction of ice islands and ice roads. The CATCO assetswere not a part of our long-term business plans to offer marine services and project solutions.We will continue to offer these specialized services to our customers as we have since theearly days of Prudhoe Bay development.”
Since 1953, Crowley has provided various marine, petroleum distribution and energy sup-port services in Alaska — from the North Slope to Southcentral Alaska and both coastal andinland communities, including those along the Kuskokwim and Yukon Rivers — and today hasoffices and operations throughout the state with more than 650 employees.
Doyon donates $1 million for new health center Alaska Native News said Nov. 24 that Doyon Ltd. is donating $1 million to Tanana Chiefs
Conference in support of the construction of the new Chief Andrew Isaac Health Center. TheDoyon board of directors approved the contribution at their regular quarterly meeting held inmid-November in Fairbanks.
In approving the contribution, the Doyon board stated that it is an investment that willbenefit Doyon shareholders and the Native community as whole. A significant number ofDoyon shareholders and their descendants reside in Interior Alaska and receive health careservices through Tanana Chiefs Conference programs.
“Doyon is pleased to make this donation,” said Aaron Schutt, Doyon’s president and CEO.“It is symbolic of the unity between TCC and Doyon. The clinic and its new features willimprove the health care services provided in Interior Alaska.”
Tanana Chiefs Conference is the traditional tribal consortium of the 42 villages of Interior
16 PETROLEUM NEWS • WEEK OF DECEMBER 4, 2011
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Companies involved in Alaska and northern Canada’s oil and gas industry
Alaska and provides a unified voice advancing tribal governments, economic and socialdevelopment, promoting physical and mental wellness, educational opportunities, protectinglanguage, traditional and cultural values.
Usibelli taps Brown for VP Southcentral operationsUsibelli Coal Mine Inc. said Nov. 23 that it has named Robert
Brown as the new vice president for Southcentral Operations. Brownhas worked for UCM for the past three years as the project managerof the Wishbone Hill coal mining project north of Palmer, as well asthe general manager of Aurora Energy Services’ coal loading facilityin Seward. He is a graduate of the South Dakota School of Mines,and holds a bachelor’s degree in Industrial Engineering.
Brown previously worked for Wilder Construction, now GraniteConstruction, and serves on the Alaska Export Council. In his sparetime, he serves as a coach for his son’s sports teams.
Founded in 1943 by Emil Usibelli, Usibelli Coal Mine Inc. is locat-ed in the Alaska Range near the town of Healy. UCM operates year-round and during more than 60 years of operation, mine production has grown from 10,000tons to an average 1.5 million tons of coal per year.
Crowley christens one of largest ATBs in industryCrowley Maritime Corp. said Nov. 3 that as a part of its industry-leading new vessel build-
ing program, it christened its largest and fastest articulated tug-barge, the Legacy/750-1, inNew Orleans.
The high-capacity tank barge is able to carry up to 330,000-barrels of petroleum productsand the 16,000-horsepower tug can generate speeds of 15 knots or more, making the ATBan industry leader. When coupled together, the vessels measure 674 feet in length, only 23feet shorter than One Shell Square, the tallest building in New Orleans and the state ofLouisiana. The ATB’s design, construction and systems exceed industry standards for thesafest possible transportation of petroleum and chemical products.
“This class of ATB is among the largest, safest and fastest in the trade,” said Crowley’sChairman, President and CEO Tom Crowley. “We are raising the bar in terms of reliability,cargo flexibility and environmental friendliness through our industry-leading new-build pro-gram. And the investments we are making will serve the needs of our customers for manyyears to come.”
Vessel sponsors Christine Crowley, wife of Tom Crowley, and Carole Shaffner, wife ofSenior Vice President of Transportation and Logistics George Shaffner of Marathon PetroleumCorp., performed the time-honored tradition of christening the vessels. More than 200 guestsattended.
Racecar driver Kurt Busch visits Shell oil rigShell said Nov. 17 that driver of the No. 22 Shell-Penzoil Dodge, Kurt Busch, traveled to
New Orleans, La., to the offshore Shell oil rig Brutus. Following a cross-country trip from the Kobalt Tools 500 at Phoenix International
Raceway Nov. 13, Busch visited the rig for an exclusive behind-the-scenes tour to develop afurther understanding of deepwater oil exploration and to meet with the rig crew members,and also recognizing Brutus and Shell for their charitable giving in 2011.
“What an experience! It was one of those situations where you go in not knowing exact-ly what to expect and once you get out there, the ‘WOW FACTOR’ kicks in”, said Busch. “Ihave a whole new appreciation for how technology gets oil out of the ground.”
Brutus is the newest Tension Leg Platform in the Gulf of Mexico for Shell and is an eight-slot platform with facilities processing capacity of 120,000 barrels of oil per day.
Before the trip to the rig, Busch went through a safety briefing and then boarded a heli-copter for the hour-and-a half ride to Brutus. Busch received an overview of deepwater oilexploration on how Brutus produces oil, which was proceeded by a tour of the massivestructure. Kurt also recognized Brutus and Shell for their charitable giving and support of theUnited Way. During the visit he spent time talking with crew members answering questionsand signing autographs.
Editor’s note: All of these news items — some in expanded form — will appear in thenext Arctic Oil & Gas Directory, a full color magazine that serves as a marketing tool forPetroleum News’ contracted advertisers. The next edition will be released in March.
continued from page 16
OIL PATCH BITS
ROBERT BROWN
EXPLORATION & PRODUCTIONGroups appeal Shell’s Beaufort air permit
Earthjustice, on behalf of nine environmental groups, filed an appeal Nov. 28 withthe Environmental Appeals Board against the Environmental Protection Agency’sdecision to issue an air quality permit for Shell’s use of its Kulluk floating drilling plat-form for exploratory drilling in Alaska’s Beaufort Sea starting in 2012.
The appeal comes just over a month after an appeal against the air quality permitfor Shell’s use of the Noble Discoverer drillship in both the Chukchi and Beaufort seas.
“These air permits violate the Clean Air Act and open the door to dangerousdrilling in the Arctic,” said Vera Pardee of the Center for Biological Diversity whenannouncing the appeal. “Rather than turning the pristine Arctic into an industrial zone,the Obama administration should be focusing on safer, cleaner sources of energy.”
“Shell has made every effort to reduce emissions to the lowest possible level. Thatincludes hundreds of millions in upgrades and modifications to both of our drill shipsand the use of ultra low sulfur diesel fuel on all of our vessels,” Shell spokesman CurtisSmith told Petroleum News in a Nov. 29 email. “We are confident in the EPA’s find-ing that our drilling program will have no negative impact on coastal communities andwe are equally confident that we will have a usable air permit once this challenge hasrun its course.”
—ALAN BAILEY
especially suitable for explorationdrilling.
Any of the other active rigs couldpotentially be used for explorationdrilling, but three of those rigs are undercontract for development drilling inNorth Slope oil fields during the winter.Another rig is drilling wells for CookInlet Natural Gas Storage Alaska’s newnatural gas storage facility on the KenaiPeninsula.
All six remaining Arctic rigs arealready contracted for winter explorationdrilling, Hebert said. However, Repsol, acompany that has contracted for the useof four Nabors rigs during the winter, hasrecently informed Nabors that it will notin fact require one of those rigs, thus put-ting one rig back on the market, he said.
However, specific rigs are only suit-able for certain types of explorationdrilling project — the question of whethera particular rig is available for a particularproject will depend on both the design ofthe rig and the nature of the project, heexplained.
“It requires matching a certain rig to acertain type of location.”
Nabors has three rig typesIn particular, the weight and means of
transportation of a rig impacts the type ofdrilling site that a rig can reach, Hebertsaid.
Essentially, Nabors operates three rigtypes: large wheeled, self-propelled rigsthat can traverse ice roads but that cannotcross ice bridges over waterways; truck-pulled rigs that require ice roads but cancross a heavy-duty ice bridge; and modu-lar rigs that can be broken down intotruck loads for transportation to remotesites, crossing floating ice bridges enroute if necessary.
Nabors has an additional wheeled,self-propelled rig that is currently moth-balled and would require at least twomonths of work to bring back into serv-ice, Hebert said, adding that Nabors is notin an immediate position to activate thatrig, given the company’s current work-load.
A second mothballed rig requires sub-stantial refurbishment involving quite afew months of work, he said. And,although Nabors has other mothballedrigs in Alaska, these rigs require majorrefurbishment, involving many millions
of dollars in expense. Given the substan-tial cost and time required to bring any ofthese rigs into operation, an explorationcompany would have to make a firmcommitment for rig use well in advanceof a drilling operation, Hebert said.
“That would take some sizable com-mitment on someone’s part,” he said.“That would not be something that most(drilling) contractors would speculateon.”
Winterization has to be done correctlyAnother way of increasing the size of
the active Alaska drilling rig fleet wouldbe to bring rigs from Canada or from theLower 48. However, winterizing a rig foruse in northern Alaska’s extreme climateis a major exercise, involving significantcost and time, Hebert cautioned.
“It can be done, but it has to be donecorrectly,” he said.
Rig winterization involves attention tomany details — for example, electricalwiring and hydraulic hosing needs to beArctic rated, especially given the likeli-hood of having to transport an unheatedrig over a lengthy ice road in extreme coldbefore a drilling operation starts. Evenrigs from Canada require customizationfor Alaska conditions, Hebert said.
Again, a firm contractual commitmentwell in advance of when a rig is neededwould be essential to embarking on a rigwinterization project. And the rig marketoutside Alaska is tight, potentially mak-ing rig acquisition difficult.
Bringing in new rigs is also an option. Three and a half years ago Nabors
delivered the first purpose-built AC rigsfor the North Slope in 13 months, fromdesign to delivery. Two and a half yearsago the company delivered CDR-2 toConocoPhillips at Kuparuk; it was thefirst purpose-built coiled tubing rigdesigned for the Arctic. It took 18months, from design to delivery.
Tax, in-field demand are factorsAnother variable in rig availability is
the amount of in-field developmentdrilling that is taking place, given thatboth in-field drilling and explorationdrilling draw on the same rig inventory.People are projecting the possibility ofeven more exploration activity in the2012-13 winter season, Hebert said. Butif BP and ConocoPhillips’ field develop-ment activity also increases due to theAlaska Legislature passing the governor’sbill that reduces the state’s production tax,rig availability in 2012-13 would pose aneven bigger challenge than at present.
“We could easily run out of rigs againnext winter,” Hebert said. And some ofthe Nabors rigs currently under contractfor exploration are especially suitable foruse on North Slope oilfield well pads,thus making these rigs especially desir-able for in-field work, he said.
There is time to refurbish mothballedrigs for next winter, but Nabors wouldneed that up-front commitment for rig usebefore bringing a rig out of hibernation,he said.
Seven Doyon rigsRon Wilson, general manager of
Doyon Drilling, told Petroleum NewsNov. 30 that Doyon has seven activedrilling rigs in Alaska.
Special rates for weekly & monthly stays for all petroleum companies.
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Four-month jobs tough sellThe surge in North Slope exploration activity has produced another problem:
convincing experienced rig workers who have left the state for the Bakken shalefields, or elsewhere, to quit their jobs and come back to Alaska for a mere 3-4months.
Or training new workers but only being able to guarantee them a few monthsof work a year in one of the harshest environments in the world.
In most regions of the country exploration drilling is allowed year-round, usingtemporary gravel roads to reach road-less tracts of land.
But temporary gravel roads are rejected by state, federal and borough regula-tory agencies in Alaska, which prefer winter ice roads and pads, thus limiting theannual exploration season to 3-4 months.
Jim Weeks, managing member of Alaska independentUltraStar Exploration and former ARCO Alaska executive,recently wrote a letter for an early November special meet-ing of the House Resource Committee, meeting to hear tes-timony on impediments to filling the Trans Alaska PipelineSystem, or TAPS.
Weeks proposes a change to the current lease form by theDivision of Oil and Gas that requires the use of ice roads andpads, saying allowing temporary year-round gravel roadscould lower the cost of exploration — and speed up bothexploration and development of new fields.
“As it now is, the successful bidder at a lease sale is awarded a contract toexplore, develop and extract oil and gas from that lease,” Weeks wrote. “The con-tract stipulates that there will be no exploration on the lease except from approvedice roads and pads, built only when there is sufficient snow cover and frozen depthto carry the heavy loading of drilling rigs and equipment.
“This restricts the exploration drilling window to generally mid-January to nolater than about April 15, depending upon the status of the well,” he said.
“So there is essentially a 90 day period in which to construct the ice road andpad and move in the rig and associated 50 truckloads of parts, plus camps, shops,generators, fuel storage tanks and other supporting facilities,” restricting the num-ber of wells that can be drilled each year.
“Companies like Repsol, with nearly 400,000 acres to explore and delineate,will require multiple years to prove up commercial reserves and make plans fordevelopment. So it will need to re-build the needed ice roads and pads multipletimes before development decisions are made. Linc Energy faces a similar chal-lenge at Umiat,” Weeks said.
“The state should let private industry decide the most efficient and lowest costmanner to conduct exploration,” he said. “Ice roads and pads may be the best wayforward for close in exploration. But for access to locations further from the roadsystem, re-building ice roads every year for several years gets pretty expensive.”
If existing, or newly constructed permanent or semi-permanent gravel roads,airstrips and drilling pads would be more cost effective, they should be allowed,Weeks said.
Year-round access to leases being explored would shorten the time to produc-tion by years, he said.
“The ability to drill throughout the year will also significantly shave the win-ter peaking demand for drilling equipment, materials and manpower, thereby fur-ther reducing costs,” for the operators.
“An all-weather road to the location of the drilling also provides year roundaccess for emergency response equipment and personnel, adding another level ofsafety to the already very high operating standards for humans and the environ-ment,” Weeks said.
—KAY CASHMAN
JIM WEEKS
continued from page 1
RIG DEMAND
see RIG DEMAND page 19
Another variable in rig availabilityis the amount of in-field
development drilling that is takingplace, given that both in-field
drilling and exploration drillingdraw on the same rig inventory.
JUD
Y P
ATR
ICK
Six of those rigs are under contract toNorth Slope oilfield operators for thecoming winter and the other rig, theArctic Fox, is under contract to Repsol forexploration drilling.
The Arctic Fox is a lightweight rig thatcan be trucked almost anywhere, he said.
Doyon used to own another light-weight exploration rig, the Arctic Wolf,but that rig is now in Canada; it is ownedby Akita Drilling and has been disassem-bled, Wilson said.
One of the Doyon rigs under contractfor in-field work has proved especiallysuccessful in the past for explorationdrilling, although any of Doyon’s rigscould potentially be used for exploration,depending on whether the transportationroute to the drilling site can accommodatethe rig’s weight, Wilson said.
Build rather than convertWilson said that, given the tight rig sup-
ply situation in the Lower 48 and the workrequired to modify a rig for Arctic use, itcould prove simpler to build a new rigrather than convert an existing rig, shouldadditional rigs be needed in Alaska.
However, rig construction might take 16to 18 months and the construction costwould raise the issue of how much a com-pany like Doyon would be willing to investon speculation, Wilson said. The invest-ment risk would best be managed by link-ing rig construction to a specific drillingproject, he said.
Wilson also commented on the difficul-ties that Doyon experienced a few years agowhen trying to use a Canadian rig for ArcticAlaska exploration. Severe cold spells inAlaska seem to last longer than in the areasof Canada where Canadian rigs operate,and northern Alaska can also experiencechallenging wind conditions, he said.
Kuukpik’s 3 rigs drilling in fieldsKuukpik Drilling has an Arctic-
equipped drilling rig, suitable for explo-ration drilling and based in Alaska.However, that rig is under contract for theentire winter of 2011-12, doing gas welldrilling in the Barrow gas fields, at theextreme western end of the North Slope.
Kuukpik anticipates its rig being avail-able for drilling on other projects in thewinter of 2012-13, Randy Hicks, generalmanager of Kuukpik, told Petroleum Newson Nov. 28.
Nordic-Calista Services has threedrilling rigs in operation on the North
Slope. Although one of these rigs was usedin an exploration project a few years ago,all of the rigs are currently under contractfor in-field drilling and are likely to remainin that situation for the foreseeable future,Udo Cassee, Nordic-Calista’s operationssuperintendent, has told PetroleumNews. �
PETROLEUM NEWS • WEEK OF DECEMBER 4, 2011 19
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to drill the Mustang No. 1, Mustang No. 2and Mustang No. 3 wells between Januaryand April and demobilize in May. Thecompany is also planning summer studies.
The joint venture includes BrooksRange Development Corp., Calgary-based independent TG World EnergyCorp. and Nabors subsidiary RamshornInvestments Inc. (Editor’s note: In a dealthat closed in early November, Ramshornpurchased TG World Energy’s Alaskaacreage interest.)
Mounting the MustangThe Mustang project is studying the
potential of the Kuparuk Formation inthe area.
North Tarn No. 1, drilled to 6,223 feet,identified an oil reservoir in the KuparukC sand. Brooks Range previously esti-mated that the Kuparuk Formation atNorth Tarn could contain 6 million bar-rels of oil, enough to make the play eco-
nomic. The company also said NorthTarn included a target in the shallowerBrookian Formation that could hold 35million barrels, but would be more diffi-cult to produce because of complex geol-ogy.
Under the terms of the SouthernMiluveach unit, Brooks Range mustcomplete North Tarn No. 1-A, as well astwo Mustang wells (or a Mustang welland a sidetrack) into the KuparukFormation by May 31, 2012. The work-ing interest owners must also decide byOct. 1, 2012 whether or not they willsanction a development program atMustang.
Brooks Range recently got approval toform four units on state land in the cen-tral North Slope, all in the fairwaybetween the Kuparuk River unit and theColville River. From north to south thoseare the Southern Miluveach, Kachemach,Tofkat and Putu units.
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Co-op members are concerned thatNaknek Electric “emerges from thisprocess with a future,” the objection said.
Members are further concerned theutility “will be pushed to raise additionalcash by increasing rates, but the membersdo not have deep pockets, and raisingrates will also raise the risk that largerusers, with the capacity to buy their owngenerators, will abandon their member-ship thus actually reducing” co-op rev-enue, the objection said.
Expensive wellNaknek Electric serves the Bristol Bay
area, known for its enormous summersalmon fishery. It was incorporated in1949 and began distributing electricity in1960. It is a nonprofit business, owned byits members. The utility has about 700members and 1,100 meters in and aroundthe villages of Naknek and King Salmon.
The utility’s major commercial cus-tomers are fish processing plants. It alsohas an important wholesale customer inthe U.S. Air Force at King Salmon.
In the 1990s, Naknek Electric beganlooking at alternatives to expensive dieselfor running its generators.
In early 2008, the co-op bought a 120-acre drill site some 17 miles outside ofKing Salmon, and the following yearbought a National 1320 drilling rig.
It began drilling its first exploratorygeothermal well on Aug. 16, 2009.
But problems securing grants, unex-pected regulatory requirements and tech-nical problems with the well — whichrefused to flow as hoped — drove the util-ity into bankruptcy court.
By the Sept. 29, 2010, bankruptcy fil-ing date, Naknek Electric said it “hadincurred approximately $40 million ofdebt that was in one way or another asso-ciated with the geothermal project.”
‘Independent verification’ soughtNaknek Electric filed its disclosure
statement and reorganization plan onSept. 15. The plan proposes, among otherthings, selling off the drilling rig, valuedat $11 million, according to the disclosurestatement.
The co-op said that, going forward, itwould focus again on diesel electricitygeneration. But it held out the chance thatthe geothermal program might continue,contingent on federal grants comingthrough.
The co-op has said it was pursuing a$50 million loan guaranty from the U.S.Department of Agriculture’s Rural
Utilities Service, or RUS. The loan wouldbe used to pay off debt and develop morewells and a geothermal power plant.
The members committee, in its Nov.28 objection, said members need to befully engaged in the co-op’s plans.
The committee requested more infor-mation about how the co-op used its exist-ing loans.
And the committee seemed wary ofgetting in deeper with what it called “afailed attempt to switch from diesel powerto geothermal.”
“The Members Committee believesthat before the Debtor again attempts ageothermal project, the proposal shouldbe subjected to independent verificationof assumptions and the Committee shouldbe allowed to weigh in on behalf of thegeneral membership,” the objection said.“For example, if the Debtor proceeds witha RUS loan guarantee for $50 million(half of which is used to pay off existinggeothermal obligations) and the geother-mal assumptions are erroneous, area com-munities would be swamped in huge rateincreases to service that additional debt.The Debtor should explain the process itintend to follow in deciding whether toproceed with geothermal power andwhether it will do so without courtapproval, independent consulting to veri-fy its assumptions, and involvement from
the Members Committee.”
Keeping customersNaknek Electric is expected to file a
revised disclosure statement following theDec. 1 court hearing.
A big worry for the co-op, and for themembers, is retaining the utility’s majorcustomers, which could elect to generatetheir own power if rates increase signifi-cantly.
The members committee said it also isconcerned about the co-op’s ability tohandle new power demand. Some fishprocessors “report they have been turneddown by Debtor when inquiring of theirexpansion plans,” the committee’s objec-tion said.
“An inability to accommodate expan-sion, actually leads to rate base shrinkage,as commercial users either take theplunge to self-generate for the expansion(developing expertise and comfort goingit alone) or begin to expand outside ofDebtor’s service area,” the objection said.
The committee also noted NaknekElectric’s diesel plant is old and needsupgrading. It said the co-op shouldinclude an analysis of the issue in itsrevised disclosure statement. �
continued from page 1
CO-OP OBJECTIONS
nals,” McLeod said. “In their view, everything is lookingpromising and we (the NWT government) are cheeringthem on.”
He said that although he did not have access to thedetails, the indications are “very promising,” but heemphasized that important deadlines are looming.
First deadline in 2013Canadian government approval of the project last
March gives the partners — Imperial 34.4 percent, theAboriginal Pipeline Group 33.3 percent, ConocoPhillips15.7 percent, Shell Canada 11.4 percent and ExxonMobilCanada 5.2 percent — until December 2013 to provideupdated cost estimates and a decision to proceed with theMGP. (Shell said four months ago that it was open to bidsfor its stake, including 100 percent ownership of the 1 tril-lion cubic foot Niglintgak field and seven other pools. Thecompany said it was making relevant data available to a“broad group of prospective purchasers” after deciding to“focus its resources on other options” in the Alberta oilsands and British Columbia shale gas plays. It has yet to
announce a deal.)McLeod said that leaves only two years for the partners
to complete engineering and geotechnical work and forthe Canadian government to include a fiscal package ofroyalties, taxes and other items, in its next budget which isexpected in February or March 2012.
The government approval also requires a start on con-struction in 2015 to allow the first shipments of gas fromthe Mackenzie Delta in 2018.
2013 deadline ‘challenging’However, Rolheiser said the proponents have indicated
the 2013 deadline “will prove challenging, if not difficultto achieve and will be dependent on how long it takes toreach agreement with the federal government on fiscalterms.”
He said the framework is essential to restaff andresume engineering, permitting and field work that wassuspended in 2007 “in order to see thousands of permitswe need before we can make a decision to construct.”
The framework has been “under discussion with thefederal government for quite some time. Our objectiveremains to work with the government to develop a frame-work that provides an appropriate balance of risk and ben-efit to the investors and for the government of Canada,”
Rolheiser said.But, because of the confidential nature of the discus-
sions, he would “not go any further into what may or maynot be under discussion.”
New NEB studyA new National Energy Board study released Nov. 22
gave a lift to the MGP by predicting gas prices willstrengthen enough to justify delivering gas from theMackenzie Delta by 2020, although McLeod said his gov-ernment is still looking at late 2018 or early 2019 as thestartup date.
The study, which forecast Mackenzie gas can startflowing when prices rise above US$5.50 per millionBritish thermal units, said the Arctic gas will be neededregardless of the projected growth of shale gas production.
It said Canadian gas output declined 15 percentfrom 2008 to 2010 and will continue that trend through2015 to 13.1 billion cubic feet per day, before resuminggrowth again in 2016 when gas from the Arctic andunconventional deposits start driving productiontowards 18 bcf per day in 2035. �
