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page 4 Apache Alaska spuds first Alaska exploration well, near Tyonek ● EXPLORATION & PRODUCTION ● EXPLORATION & PRODUCTION ● FINANCE & ECONOMY Vol. 17, No. 47 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of November 18, 2012 • $2 ● MERGERS & ACQUISITIONS ● LAND & LEASING ● GEOLOGY Vol. 1, No. 15 • www.PetroleumNewsBakken.com A semi-monthly newspaper for industry and government November 18, 2012 BAKKEN page 12 Kodiak production in Williston Basin up 281 percent from a year ago AKKE B N OIL & GAS DIRECTORY Petroleum News Bakken’s first oil and gas directory, a full color magazine, accompanies this issue of the newspaper. The first of its kind, it will appear twice a year, with the next being released in May. It is a work in progress so the publisher welcomes additions, deletions and corrections, asking they be sent to publish- [email protected]. Bakken Oil & Gas Directory inside Window closing Hamm: most government land tied up; fewer takeover opportunities in Bakken By RAY TYSON Petroleum News Bakken W illiston Basin superstar Continental Resources Inc. said following disclosure of its latest Bakken acquisition that opportunities for such mega deals in the region may be coming to an end. “We expect to see those opportuni- ties diminish, and so this is especially one that fits us real well,” Harold Hamm, Continental’s chairman and chief executive officer, said of the com- pany’s recent $650 million deal in a Nov. 8 conference call with analysts and investors. Others have tied up most of the available state and federal acreage, Hamm said, while takeover candidates in the way of smaller exploration and production companies are vanishing. “In my estimation, we’ll see a few of them going forward,” he added. “There’ll still be a few, but perhaps that window is closing.” Deal includes 120,000 acres Continental, in its latest deal, entered into an agreement with an undisclosed seller or sellers to acquire Bakken producing and undeveloped Others have tied up most of the avail- able state and fed- eral acreage, while takeover candidates in the way of small- er exploration and production compa- nies are vanishing, said Continental’s Chairman and CEO Harold Hamm. see MEGA DEALS page 23 Redefining the Sanish ND geological survey considers sands to be Pronghorn unit of Bakken formation By MIKE ELLERD For Petroleum News Bakken F or years people had been seeing a lime- stone/lime mudstone unit between the lower Bakken Shale and the upper Three Forks formation in parts of Stark, Dunn, McKenzie, Billings and Golden Valley counties in western North Dakota, but that limestone/mudstone unit had never been well defined or well described. That was until three years ago when Anschutz Petroleum cut a long core in a well it drilled in far southern Dunn County that fully transcended what for years had been commonly known as the Sanish sand, a unit that has been considered part of the Three Forks formation in the larger Bakken petroleum system. With the information gained from the Anschutz core, the North Dakota Geological Survey now formally considers this lime- stone/mudstone unit to be part of the Bakken formation within the same petrole- um system, and have redefined it as the Pronghorn member. A little history In 1954, NDGS described an “unconfor- mity sand” lying between the lower Bakken shale and the Three Forks formation, and referred to it as the Sanish sand, and included it as part of the Bakken for- JULIE LEFEVER see UNIT DEFINITIONpage 20 ND sale draws robust bids Trust Lands auction price per acre averaged $1,997 on 9,421 acres; 4th highest By MIKE ELLERD For Petroleum News Bakken T he North Dakota Department of Trust Lands Minerals Management Division brought in just over $18.9 mil- lion in its November oil and gas lease auction, selling leases on 9,421 acres in 100 separate parcels in nine western North Dakota counties, for an average of approximately $1,998 per acre. The sale prices at the November auction ranged from a low of $25 per acre to a high of $15,300 per acre. Slightly over half of the acreage sold was in McKenzie County. The average price of $1,998 per acre was the fourth highest auction average going back to 1970. The highest average price per acre was $3,526 set at the November 2011 auction, followed by $2,968 in May 2010, and $2,090 in February 2011. In August, the Minerals Management Division sold a total of 16,665 acres at an average price per acre of $701 per acre. In May it sold 10,447 acres at an average price per acre of $1,000, and in February the total acreage sold was 69,942 with an average price per acre of $1,219. “We were pleased with the sale,” Minerals Management Division Director Dew Combs told see LEASE AUCTIONpage 23 DREW COMBS Alberta opens door on huge resources; formations on parallel with Bakken, say agencies Alberta’s emerging shale and/or siltstone formations could ultimately yield 423.6 billion barrels of oil, 58.6 billion barrels of liquids and 3.3 trillion cubic feet of natural gas, says a long-awaited report by the Alberta Energy Resources Conservation Board and the Alberta Geological Survey. The report is designed to provide baseline data, informa- tion and understanding of the geology, distribution, reservoir characteristics and hydrocarbon resource potential of Alberta shales. The calculations for the formations, including the Duvernay, Montney and Muskwa, put the deposits in the same league as some of the major U.S. shale plays as part of Apache pleased with oil shows in logs from first Bakken well Apache Corp.’s top executive is pleased with what he’s seen from the first well drilled in the company’s newly acquired acreage in Daniels County, Mont., on the northwestern fringe of the Bakken petroleum system. “As we continue to build and exe- cute our global pipeline of exploration activity we’re testing two wells (in two new plays for Apache) — one in the Williston Basin and one in the Mississippi Lime,” G. Steven Farris, company chairman and chief executive officer, said in early November in Apache’s see ALBERTA RESOURCES page 21 see APACHE WELL page 19 G. STEVEN FARRIS PROPHECY PLATINUM CORP. Prophecy Platinum Corp.’s Wellgreen PGE-nickel-copper project in southwestern Yukon could represent 15-20 percent of total platinum production in North America when it goes into production, according to Prophecy’s management. Platinum, a precious metal 10 times more rare than gold and 100 times more rare than silver, is used primarily in catalytic converters, a growing and vital market in an increasingly environment-conscious world. Page 18. A special supplement to Petroleum News WEEK OF November 18, 2012 3 Miners, politicians talk Pebble Alaska delegation voices concerns over EPA’s handling of copper project 10 Yukon First Nations, miners engage New pacts add to roster of existing agreements on resource development 13 A new Ethos emerging in Yukon With C$9M in the bank, junior has plethora of options going into 2013 A semi-annual supplement AKKE B N OIL & GAS DIRECTORY Vol. 1, No.1, Released November 2012 Enclosed this week find the latest issues of Petroleum News Bakken and Mining News as well as the debut of the first Bakken Oil & Gas Directory magazine Inside: PN Bakken, Mining News 1 step forward, 2 back Conoco goes ahead with CD-5; BP halts heavy oil trials, won’t increase viscous By KRISTEN NELSON Petroleum News B P Exploration (Alaska) and ConocoPhillips Alaska, the North Slope’s major operators, delivered similar messages to the Resource Development Council’s annual conference Nov. 14 in Anchorage: The state’s oil and gas tax system needs to be changed. It’s not a new message, but Nick Olds, ConocoPhillips Alaska’s new vice president, North Slope operations and development, said a better busi- ness climate in Alaska is necessary to draw the investment needed for continued development of legacy fields, including high- risk satellite opportunities. John Minge, president of BP Exploration (Alaska), called ACES — Alaska’s Clear and Equitable Share — a good short-term fiscal policy for the state, but said because it’s short-term, BP will have to “adjust our plans and our strat- egy to shorter term, to fit with- in the ACES policies.” Minge said if the state wants to see a long-term sustainable oil industry, and a gas pipeline, it needs to consider a policy to encourage long-term investment. BP Alaska to pay $255M Arbitrators award state damages for production shortfalls following 2006 spills By WESLEY LOY For Petroleum News T wo leaks from major oil pipelines in the giant Prudhoe Bay field in 2006 ignited big trouble for operator BP Exploration (Alaska) Inc. The leaks caused a partial field shutdown that rattled world oil markets, and drew scrutiny from federal regulators and members of Congress who criticized the company’s upkeep of pipelines infested with corrosion. BPXA ultimately was placed on probation for three years and fined $20 million after pleading guilty to a federal pollution misdemeanor. But that wasn’t the end of it. The state filed an aggressive civil suit against BPXA in 2009, seek- ing to recover back taxes, royalties and other dam- ages for the leaks and the production shortfalls resulting from shut-ins and extensive pipeline repairs. At the time the suit was filed, a state lawyer said the damages could exceed $1 billion. The state won’t collect that much. But it has succeeded in winning a very substantial sum, more Oil sands output to rise 250 percent increase in Canadian sands production by 2035, IEA says By GARY PARK For Petroleum News T he next 23 years will see Canadian oil pro- duction rise steadily as oil sands volumes grow by 250 percent to 4.3 million barrels per day, more than enough to offset shrinkage in conven- tional output, the International Energy Agency pre- dicts. If the projection is accurate, based on assump- tions that environmental opposition will be over- come and more crude will be delivered to the United States and Asia, Canada’s oil production will grow to 6.3 million bpd by 2035. But the report emphasizes that “extraordinary growth” in oil and natural gas production in the U.S. will mean a global sea change, with the U.S. becoming a net exporter of gas and almost self-suf- ficient in net energy terms over the forecast period. From Canada’s standpoint, the IEA said the out- look has become clouded by U.S. delays in approving TransCanada’s Keystone XL pipeline to deliver Alberta oil sands crude and Bakken light/tight oil to the Texas Gulf Coast and by oppo- NICK OLDS JOHN MINGE see RDC CONFERENCE page 20 The arbitrators put the state’s royalty loss at 30,344,971 barrels of oil and NGLs, and said the production won’t be recovered until the end of field life. see BP PAYOUT page 19 Without new export capacity, the IEA said Western Canadian oil production will exceed regional consumption and current export capacity before 2016 ... see SANDS OUTPUT page 18 Shell’s drilling fleet departs the Arctic as drilling season ends Following the cessation of drilling operations at the end of October, Shell’s Alaska drilling fleet is heading south out of the Arctic, Shell spokesman Curtis Smith told Petroleum News in a Nov. 13 email. The drillship Noble Discover, which had been drilling at the Burger prospect in the Chukchi Sea, will dock initially in Seward on the Kenai Peninsula, from where it will likely sail to a West Coast shipyard for routine mainte- nance, Smith said. The Kulluk, the floating drilling platform that Shell was using at its Sivulliq prospect in the Beaufort Sea, is heading for Dutch Harbor in the Aleutian Islands — it is possible that Shell may later also move the Kulluk to the West Coast for maintenance work. “The Kulluk and its support fleet are well past Point Barrow and sailing to Dutch Harbor at roughly four knots,” Smith said. Linc building snow road to Umiat, prepping for January drilling Work is under way at Umiat. In preparation for a drilling campaign scheduled for January, Linc Energy Inc. recently began building a snow road to the North Slope oil field, the company said Nov. 12. The 100-mile snow road will begin at the Dalton Highway, near Pump Station 2, and continue to Umiat, located on the boundary of the National Petroleum Reserve-Alaska. Linc is currently pre-packing the road and expects the devel- opment to take 30 days. With the road complete, Linc expects to begin mobilization in mid-December. The mobilization effort involves moving a camp, drilling rig and equipment to the field. During the mobilization, Linc plans to build in-field ice roads and ice pads. Between January and April, Linc plans to drill at least four wells at Umiat, starting with Umiat DS No. 1, a Class II dispos- al well the company plans to spud around Jan. 18. Four-well program Using the Kuukpik No. 5 rig, Linc would move uphill, to the see SHELL DRILLING page 19 see LINC ACTIVITY page 18 JUDY PATRICK PHOTOS
Transcript

  • page4

    Apache Alaska spuds first Alaskaexploration well, near Tyonek

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

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

    � F I N A N C E & E C O N O M Y

    Vol. 17, No. 47 • www.PetroleumNews.com A weekly oil & gas newspaper based in Anchorage, Alaska Week of November 18, 2012 • $2

    � M E R G E R S & A C Q U I S I T I O N S

    � L A N D & L E A S I N G

    � G E O L O G Y

    Vol. 1, No. 15 • www.PetroleumNewsBakken.com A semi-monthly newspaper for industry and government November 18, 2012

    B A K K E N page12Kodiak production in Williston Basin up 281 percent from a year ago

    A semi-annual supplement

    AKKEB NOIL & GAS DIRECTORYVol. 1, No.1, Released November 2012Petroleum News Bakken’s first oil and gas directory, a full colormagazine, accompanies this issue of the newspaper. The first of itskind, it will appear twice a year, with the next being released inMay. It is a work in progress so the publisher welcomes additions,deletions and corrections, asking they be sent to [email protected].

    Bakken Oil & Gas Directory inside

    Window closingHamm: most government land tied up; fewer takeover opportunities in Bakken

    By RAY TYSONPetroleum News Bakken

    Williston Basin superstarContinental Resources Inc. saidfollowing disclosure of its latestBakken acquisition that opportunitiesfor such mega deals in the region maybe coming to an end.

    “We expect to see those opportuni-ties diminish, and so this is especiallyone that fits us real well,” HaroldHamm, Continental’s chairman andchief executive officer, said of the com-pany’s recent $650 million deal in aNov. 8 conference call with analystsand investors.

    Others have tied up most of theavailable state and federal acreage,Hamm said, while takeover candidatesin the way of smaller exploration andproduction companies are vanishing.

    “In my estimation, we’ll see a fewof them going forward,” he added.“There’ll still be a few, but perhaps thatwindow is closing.”

    Deal includes 120,000 acresContinental, in its latest deal,

    entered into an agreement with anundisclosed seller or sellers to acquireBakken producing and undeveloped

    Others have tied upmost of the avail-able state and fed-eral acreage, whiletakeover candidatesin the way of small-er exploration andproduction compa-nies are vanishing,said Continental’sChairman and CEOHarold Hamm.

    see MEGA DEALS page 23

    Redefining the Sanish ND geological survey considers sands to be Pronghorn unit of Bakken formation

    By MIKE ELLERDFor Petroleum News Bakken

    For years people had been seeing a lime-stone/lime mudstone unit between thelower Bakken Shale and the upper ThreeForks formation in parts of Stark, Dunn,McKenzie, Billings and Golden Valleycounties in western North Dakota, but thatlimestone/mudstone unit had never beenwell defined or well described. That wasuntil three years ago when Anschutz Petroleum cut along core in a well it drilled in far southern DunnCounty that fully transcended what for years had beencommonly known as the Sanish sand, a unit that hasbeen considered part of the Three Forks formation in

    the larger Bakken petroleum system. Withthe information gained from the Anschutzcore, the North Dakota Geological Surveynow formally considers this lime-stone/mudstone unit to be part of theBakken formation within the same petrole-um system, and have redefined it as thePronghorn member.

    A little historyIn 1954, NDGS described an “unconfor-mity sand” lying between the lower Bakken shale andthe Three Forks formation, and referred to it as theSanish sand, and included it as part of the Bakken for-

    JULIE LEFEVER

    see UNIT DEFINITION page 20

    ND sale draws robust bidsTrust Lands auction price per acre averaged $1,997 on 9,421 acres; 4th highest

    By MIKE ELLERDFor Petroleum News Bakken

    The North Dakota Department ofTrust Lands Minerals ManagementDivision brought in just over $18.9 mil-lion in its November oil and gas leaseauction, selling leases on 9,421 acres in100 separate parcels in nine westernNorth Dakota counties, for an average ofapproximately $1,998 per acre. The saleprices at the November auction ranged from a lowof $25 per acre to a high of $15,300 per acre.Slightly over half of the acreage sold was inMcKenzie County.

    The average price of $1,998 per acre was the

    fourth highest auction average goingback to 1970. The highest average priceper acre was $3,526 set at the November2011 auction, followed by $2,968 in May2010, and $2,090 in February 2011.

    In August, the Minerals ManagementDivision sold a total of 16,665 acres at anaverage price per acre of $701 per acre.In May it sold 10,447 acres at an averageprice per acre of $1,000, and in Februarythe total acreage sold was 69,942 with anaverage price per acre of $1,219.

    “We were pleased with the sale,” MineralsManagement Division Director Dew Combs told

    see LEASE AUCTION page 23

    DREW COMBS

    Alberta opens door on hugeresources; formations on parallelwith Bakken, say agencies

    Alberta’s emerging shale and/or siltstone formationscould ultimately yield 423.6 billion barrels of oil, 58.6 billionbarrels of liquids and 3.3 trillion cubic feet of natural gas,says a long-awaited report by the Alberta Energy ResourcesConservation Board and the Alberta Geological Survey.The report is designed to provide baseline data, informa-tion and understanding of the geology, distribution, reservoircharacteristics and hydrocarbon resource potential of Albertashales.The calculations for the formations, including theDuvernay, Montney and Muskwa, put the deposits in thesame league as some of the major U.S. shale plays as part of

    Apache pleased with oil showsin logs from first Bakken well

    Apache Corp.’s top executive ispleased with what he’s seen from thefirst well drilled in the company’snewly acquired acreage in DanielsCounty, Mont., on the northwesternfringe of the Bakken petroleum system.

    “As we continue to build and exe-cute our global pipeline of explorationactivity we’re testing two wells (in twonew plays for Apache) — one in theWilliston Basin and one in theMississippi Lime,” G. Steven Farris, company chairman andchief executive officer, said in early November in Apache’s

    see ALBERTA RESOURCES page 21

    see APACHE WELL page 19

    G. STEVEN FARRIS

    PROPHECY PLATINUM CORP.

    Prophecy Platinum Corp.’s Wellgreen PGE-nickel-copper

    project in southwestern Yukon could represent 15-20

    percent of total platinum production in North America

    when it goes into production, according to Prophecy’s

    management. Platinum, a precious metal 10 times more

    rare than gold and 100 times more rare than silver, is

    used primarily in catalytic converters, a growing and vital

    market in an increasingly environment-conscious world.

    Page 18.

    A special supplement to Petroleum News

    WEEK OF

    November 18, 2012

    3 Miners, politicians talk Pebble

    Alaska delegation voices concerns over EPA’s handling of copper project

    10 Yukon First Nations, miners engage

    New pacts add to roster of existing agreements on resource development

    13 A new Ethos emerging in YukonWith C$9M in the bank, junior has ple

    thora of options going into 2013

    A semi-annual supplement

    AKKEB NOIL & GAS DIRECTORYVol. 1, No.1, Released November 2012Enclosed this weekfind the latest issuesof Petroleum NewsBakken and MiningNews as well as thedebut of the firstBakken Oil & GasDirectory magazine

    Inside: PN Bakken, Mining News

    1 step forward, 2 backConoco goes ahead with CD-5; BP halts heavy oil trials, won’t increase viscous

    By KRISTEN NELSONPetroleum News

    BP Exploration (Alaska)and ConocoPhillipsAlaska, the North Slope’smajor operators, deliveredsimilar messages to theResource DevelopmentCouncil’s annual conferenceNov. 14 in Anchorage: Thestate’s oil and gas tax system needs to be changed.

    It’s not a new message, but Nick Olds,ConocoPhillips Alaska’s new vice president, NorthSlope operations and development, said a better busi-ness climate in Alaska is necessary to draw theinvestment needed for continued development of

    legacy fields, including high-risk satellite opportunities.

    John Minge, president ofBP Exploration (Alaska),called ACES — Alaska’s Clearand Equitable Share — a goodshort-term fiscal policy for thestate, but said because it’sshort-term, BP will have to“adjust our plans and our strat-egy to shorter term, to fit with-

    in the ACES policies.” Minge said if the state wants to see a long-term

    sustainable oil industry, and a gas pipeline, it needs toconsider a policy to encourage long-term investment.

    BP Alaska to pay $255MArbitrators award state damages for production shortfalls following 2006 spills

    By WESLEY LOYFor Petroleum News

    Two leaks from major oil pipelines in the giantPrudhoe Bay field in 2006 ignited big troublefor operator BP Exploration (Alaska) Inc.

    The leaks caused a partial field shutdown thatrattled world oil markets, and drew scrutiny fromfederal regulators and members of Congress whocriticized the company’s upkeep of pipelinesinfested with corrosion.

    BPXA ultimately was placed on probation forthree years and fined $20 million after pleadingguilty to a federal pollution misdemeanor.

    But that wasn’t the end of it. The state filed anaggressive civil suit against BPXA in 2009, seek-

    ing to recover back taxes, royalties and other dam-ages for the leaks and the production shortfallsresulting from shut-ins and extensive pipelinerepairs.

    At the time the suit was filed, a state lawyer saidthe damages could exceed $1 billion.

    The state won’t collect that much. But it hassucceeded in winning a very substantial sum, more

    Oil sands output to rise250 percent increase in Canadian sands production by 2035, IEA says

    By GARY PARKFor Petroleum News

    The next 23 years will see Canadian oil pro-duction rise steadily as oil sands volumesgrow by 250 percent to 4.3 million barrels per day,more than enough to offset shrinkage in conven-tional output, the International Energy Agency pre-dicts.

    If the projection is accurate, based on assump-tions that environmental opposition will be over-come and more crude will be delivered to theUnited States and Asia, Canada’s oil productionwill grow to 6.3 million bpd by 2035.

    But the report emphasizes that “extraordinarygrowth” in oil and natural gas production in the

    U.S. will mean a global sea change, with the U.S.becoming a net exporter of gas and almost self-suf-ficient in net energy terms over the forecast period.

    From Canada’s standpoint, the IEA said the out-look has become clouded by U.S. delays inapproving TransCanada’s Keystone XL pipeline todeliver Alberta oil sands crude and Bakkenlight/tight oil to the Texas Gulf Coast and by oppo-

    NICK OLDS JOHN MINGE

    see RDC CONFERENCE page 20

    The arbitrators put the state’s royalty lossat 30,344,971 barrels of oil and NGLs,

    and said the production won’t berecovered until the end of field life.

    see BP PAYOUT page 19

    Without new export capacity, the IEA saidWestern Canadian oil production will

    exceed regional consumption and currentexport capacity before 2016 ...

    see SANDS OUTPUT page 18

    Shell’s drilling fleet departs theArctic as drilling season ends

    Following the cessation of drilling operations at the end ofOctober, Shell’s Alaska drilling fleet is heading south out ofthe Arctic, Shell spokesman Curtis Smith told Petroleum Newsin a Nov. 13 email. The drillship Noble Discover, which hadbeen drilling at the Burger prospect in the Chukchi Sea, willdock initially in Seward on the Kenai Peninsula, from where itwill likely sail to a West Coast shipyard for routine mainte-nance, Smith said. The Kulluk, the floating drilling platformthat Shell was using at its Sivulliq prospect in the BeaufortSea, is heading for Dutch Harbor in the Aleutian Islands — itis possible that Shell may later also move the Kulluk to theWest Coast for maintenance work.

    “The Kulluk and its support fleet are well past PointBarrow and sailing to Dutch Harbor at roughly four knots,”Smith said.

    Linc building snow road to Umiat,prepping for January drilling

    Work is under way at Umiat.In preparation for a drilling campaign scheduled for January,

    Linc Energy Inc. recently began building a snow road to theNorth Slope oil field, the company said Nov. 12.

    The 100-mile snow road will begin at the Dalton Highway,near Pump Station 2, and continue to Umiat, located on theboundary of the National Petroleum Reserve-Alaska.

    Linc is currently pre-packing the road and expects the devel-opment to take 30 days.

    With the road complete, Linc expects to begin mobilization inmid-December. The mobilization effort involves moving a camp,drilling rig and equipment to the field.

    During the mobilization, Linc plans to build in-field ice roadsand ice pads.

    Between January and April, Linc plans to drill at least fourwells at Umiat, starting with Umiat DS No. 1, a Class II dispos-al well the company plans to spud around Jan. 18.

    Four-well programUsing the Kuukpik No. 5 rig, Linc would move uphill, to the

    see SHELL DRILLING page 19

    see LINC ACTIVITY page 18

    JUD

    Y P

    ATR

    ICK

    PH

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    http://www.PetroleumNews.com/

  • 2 PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012

    Petroleum News North America’s source for oil and gas news

    FINANCE & ECONOMY

    EXPLORATION & PRODUCTION

    8 US limits Rockies oil-shale development

    Obama administration scales back to a third of areaproposed by George W. Bush administration; wilderness-quality lands off table

    4 Cook Inlet explorers take next steps

    Apache spuds its first well in the basin while Buccaneerplans to move jack-up rig from Homer for winter drilling at Cosmopolitan

    5 Canada goes conservative

    Service sector ‘cautiously optimistic’ about 2013 drilling,based on technology impact on well count; capital spending could drop 10%

    7 Cook Inlet Energy plans more gas wells

    Anchorage-based firm to spud exploratory well soon at Olsen Creek prospect; fracking operation conducted at neighboring Otter

    6 Feds move to have Furie lawsuit tossed

    DOJ says company acted prematurely in going to courtto try to kill $15 million fine for illegal transport of drilling rig to Alaska

    10 Trans-Alaska pipeline upgrades continue

    Alyeska progresses pump station electrification andinstallation of technology for dealing withlow oil flow through line

    NATURAL GAS

    contents

    12 Begich proposes benefits for in-state gas

    13 Small-scale LNG a niche which can grow

    GOVERNMENT7 Agencies extend habitat rule comment

    PIPELINES & DOWNSTREAM

    Shell’s drilling fleet departs the Arctic as drilling season ends

    Linc building snow road to Umiat,prepping for January drilling

    1 step forward, 2 back

    Conoco goes ahead with CD-5; BP halts heavy oil trials, won’t increase viscous

    BP Alaska to pay $255M

    Arbitrators award state damages for production shortfalls following 2006 spills

    Oil sands output to rise

    250 percent increase in Canadian sands production by 2035, IEA says

    ON THE COVER

    SIDEBAR, Page 12: Valdez lives up to its snowy reputation

    http://www.mthousing.net

  • PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012 3

    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 E-20 workover BPDreco 1000 UE 16 (SCR/TD) Milne Point MPE-03 BPDreco D2000 UEBD 19 (SCR/TD) Alpine CD1-01 ConocoPhillipsAC Mobile 25 Prudhoe Bay Z-10A BPOIME 2000 141 (SCR/TD) Kuparuk 3Q-06 ConocoPhillips

    Kuukpik 5 Stacked in Deadhorse Linc Energy Operations Inc.Umiat Job

    Nabors Alaska DrillingTrans-ocean rig CDR-1 (CT) Prudhoe Bay StackedAC Coil Hybrid CDR-2 Kuparuk 2F-19 ConocoPhillips Dreco 1000 UE 2-ES Prudhoe Bay Stacked out AvailableMid-Continental U36A 3-S Prudhoe Bay Stacked out AvailableOilwell 700 E 4-ES (SCR) Deadhorse AvailableDreco 1000 UE 7-ES (SCR/TD) Prudhoe Bay Available Dreco 1000 UE 9-ES (SCR/TD) Prudhoe Bay Available Oilwell 2000 Hercules 14-E (SCR) Prudhoe Bay AvailableOilwell 2000 Hercules 16-E (SCR/TD) Prudhoe Bay Available Oilwell 2000 17-E (SCR/TD) Prudhoe Bay Stacked Emsco Electro-hoist -2 18-E (SCR) Prudhoe Bay StackedEmsco Electro-hoist Varco TDS3 22-E (SCR/TD) Prudhoe Bay Stacked Emsco Electro-hoist 28-E (SCR) Prudhoe Bay StackedEmsco Electro-hoist Canrig 1050E 27-E (SCR-TD) Prudhoe Bay* Available Oilwell 2000 33-E Prudhoe Bay Available Academy AC electric Canrig 105-E (SCR-TD) Warm Stack Great Bear Petroleum

    *Pioneer winter work

    Nordic Calista ServicesSuperior 700 UE 1 (SCR/CTD) Prudhoe Bay Drill Site D-29A BPSuperior 700 UE 2 (SCR/CTD) Prudhoe Bay Well Drill Site W-02 BP Ideco 900 3 (SCR/TD) Kuparuk Well 3M-13 ConocoPhillips

    Parker Drilling Arctic Operating Inc. NOV ADS-10SD 272 Prudhoe Bay final construction and commission BPNOV ADS-10SD 273 Started acceptance testing on Aug. 2, BP

    scheduled to complete Aug. 11

    North Slope - Offshore

    BPTop drive, supersized Liberty rig Inactive BP

    Nabors Alaska DrillingOIME 1000 19-E (AC) Oooguruk ODSN-29 Pioneer Natural ResourcesOIME 2000 245-E Oliktok Point ENI

    Doyon DrillingSky Top Brewster NE-12 15 (SCR/TD) Spy Island SP30-W1 ENI

    Cook Inlet Basin – Onshore

    Kenai Land Ventures LLC (All American Consultants, labor Contract)Taylor Glacier 1 Kenai Loop Drilling Pad #1 Buccaneer Energy Ltd

    Aurora Well ServiceFranks 300 Srs. Explorer III AWS 1 Happy Valley drilling HV B-16 Hilcorp Alaska LLC

    Cook Inlet EnergyAtlas Copco RD20 34 Finalizing Otter Project west side Cook Inlet Energy

    of Beluga River Field

    Doyon DrillingTSM 7000 Arctic Fox #1 Swanson River SRU 23B-22 Hilcorp Alaska LLC

    Nabors Alaska Drilling99AC North Fork 23-25 Armstrong Cook Inlet LLC

    Continental Emsco E3000 273E Kenai AvailableFranks 26 Kenai StackedIDECO 2100 E 429E (SCR) Stacked in Kenai Available Rigmaster 850 129 Kenai AvailableAcademy AC electric Heli-Rig 106-E (SCR/TD) Tiger Eye 1 NordAq

    Cook Inlet Basin – Offshore

    XTO EnergyNational 110 C (TD) Idle XTO

    Spartan Drilling Baker Marine ILC-Skidoff, jack-up Spartan 151 Furie

    Upper Cook Inlet KLU#1

    Cook Inlet EnergyNational 1320 35 Osprey Platform RU-1, Cook Inlet Energy

    workover

    Hilcorp Alaska LLC (Kuukpik, labor contract)Steelhead Platform Well M-16, Hilcorp Alaska LLC workover

    428 Anna Platform, Hilcorp Alaska LLCReplacing rig’s turbine Generator

    Mackenzie Rig StatusCanadian Beaufort Sea

    SDC Drilling Inc.SSDC CANMAR Island Rig #2 SDC Set down at Roland Bay Available

    Central Mackenzie Valley

    Akita/SAHTUOilwell 500 51 Still out of the NWT, but is again Available

    available

    Alaska - Mackenzie Rig ReportThe Alaska - Mackenzie Rig Report as of November 15, 2012.

    Active drilling companies only listed.

    TD = rigs equipped with top drive units WO = workover operations CT = coiled tubing operation SCR = electric rig

    This rig report was prepared by Marti Reeve

    Baker Hughes North America rotary rig counts*Nov. 9 Nov. 2 Year Ago

    US 1,806 1,800 2,016Canada 370 383 500Gulf 47 48 36

    Highest/LowestUS/Highest 4530 December 1981US/Lowest 488 April 1999Canada/Highest 558 January 2000Canada/Lowest 29 April 1992

    *Issued by Baker Hughes since 1944

    The Alaska - Mackenzie Rig Report is sponsored by:

    JUDY

    PAT

    RICK

    http://www.xtoenergy.com/

  • 4 PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012

    Kay Cashman PUBLISHER & EXECUTIVE EDITOR

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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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    ADDRESSP.O. Box 231647Anchorage, AK 99523-1647

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    OWNER: Petroleum Newspapers of Alaska LLC (PNA)Petroleum News (ISSN 1544-3612) • Vol. 17, No. 47 • Week of November 19, 2012

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    CORRECTIONSmith Bay

    A story about the state’s Nov. 7 oil and gas lease sales in the Nov. 11 issue containedan error.

    The leases which NordAq Energy acquired in the Beaufort Sea areawide sale sur-round existing NordAq acreage in Smith Bay, not Harrison Bay as stated in the story.

    Petroleum News apologizes for the error.

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

    Cook Inlet explorerstake next stepsApache spuds its first well in the basin while Buccaneer plans tomove jack-up rig from Homer for winter drilling at Cosmopolitan

    By ALAN BAILEYPetroleum News

    Two companies, both new to the CookInlet basin, are taking the next steps intheir ventures to find and develop new oiland gas in the basin, company executivestold the Resource Development Council’sannual Alaska Resources Conference onNov. 14.

    Apache Alaska Inc., the company thathas been conducting a major 3-D seismicsurvey program across broad areas of thebasin, has spud its first exploration well inthe basin, near Tyonek, on the west side ofthe inlet, John Hendrix, general manager ofApache Alaska, told the conference.

    “We spud our first well this morning at7:44 in the morning — our first ApacheAlaska drilling operation,” Hendrix said.Apache is primarily looking for oil in thebasin, although the company also expects tofind natural gas in the course of its explo-ration drilling.

    Pushing oil production up to, say, 50,000or 100,000 barrels per day would revolution-ize the Cook Inlet, Hendrix said.

    Apache’s well, the Kaldachabuna No. 2,is being drilled in Cook Inlet Region Inc.subsurface land by the Patterson Rig 191.This is a reservoir play that Apache wants toinvestigate, to assess whether this type ofplay is replicated in other prospects thatApache’s seismic reveals, Hendrix said.

    Mark Landt, vice president, land andbusiness development for BuccaneerAlaska, a subsidiary of Australian independ-ent Buccaneer Energy, said that this winterBuccaneer is going to use the Endeavourjack-up rig that it has brought to the inlet todrill at Cosmopolitan, a known oil pool off-shore Anchor Point in the southern KenaiPeninsula. There are estimated to be around90 billion cubic feet of natural gas at

    Cosmopolitan, in addition to an estimated44 million barrels of oil, Landt said.

    The Endeavour rig is currently positionedat Homer in Kachemak Bay, undergoingsome unanticipated repairs before beingready for service. Buccaneer anticipatesmoving the rig from Homer in about twoweeks for drilling at Cosmopolitan, Landtsaid.

    Buccaneer is in the process of drilling theno. 4 well in its producing Kenai Loop fieldat the City of Kenai and plans a further twoto three wells there in 2013, Landt said. In2013 Buccaneer also plans to drill an explo-ration well in each of its offshore NorthwestCook Inlet and Southern Cross units, and toshoot 3-D seismic and drill a well in its WestEagle prospect in the southern KenaiPeninsula. All told, the company anticipatesdrilling three to four onshore wells and threeoffshore wells in 2013, Landt said.

    Apart from oil potential at Cosmopolitanand Southern Cross, Buccaneer’s currentexploration interest is focused on naturalgas, Landt said.

    Landt said for funding its capital require-ments Buccaneer has entered into a $30 mil-lion revolving credit facility. In addition,since entering the Cook Inlet gas businessBuccaneer has raised $66 million in capitalon the Australian stock exchange, he said. �

    Contact Alan Bailey at [email protected]

    JOHN HENDRIX MARK LANDT

    http://www.craigtaylorequipment.com/

  • By GARY PARKFor Petroleum News

    The Petroleum Services Association ofCanada has unveiled what would nor-mally be seen as a dismal drilling forecastfor 2013, but not in the current upstreamenvironment.

    “We are cautiously optimistic about2013’s drilling activity levels,” said PSACPresident Mark Salkeld in targeting 11,400well completions for next year, up a mere150 from this year’s anticipated tally, part-ly reflecting the significant increase indrilling and completion spending onlonger, more complex wellbores.

    Mike Edmonds, chairman of PSAC’sboard of directors, noted that the totalmeasured depth of the 2013 wells will be22 million meters, about the same as wasdrilled in 2008 by 17,000 wells.

    He said current estimates point to hori-zontal wells accounting for 70 percent ofnext year’s wells, noting that technologyadvances allow for directional drilling atgreater depths than ever before.

    Salkeld said the first quarter of the newyear will see a “typical ramp up of activi-ty,” then a slowing down during the springmelt, shifting to a solid second half as larg-er producers continue with their plans andmid-sized companies gain access to thecapital they need.

    He said oil wells are expected toaccount for 87 percent of the completions,with gas wells only being drilled as need-ed.

    Lucas Mezzano, PSAC’s first vicechairman, said “access to cash flow andcapital depending programs of our cus-tomers will also contribute to drilling-activity trends in the new year.”

    Based on WTI of US$95 PSAC is basing its forecast on average

    gas prices of C$3.25 per gigajoule at theAECO hub in Alberta and West TexasIntermediate prices of US$95 per barrel.

    Salkeld said that “ongoing suppressedgas prices” will see well completions ingas-weighted British Columbia drop 11percent from 2012 to 385, lagging far

    behind the other three Western Canadianprovinces.

    Alberta is forecast to drill 7,045 wells,up 3 percent from this year; Saskatchewan3,199 wells, down 1 percent; and Manitoba750 wells, an increase of 5 percent.

    Roger Serin, managing director andhead of energy research at TD Securities,said capital spending in Western Canadawill likely “pull back a little” in 2013despite a tight recovery in gas prices, butoil sands investment will increase, reflect-ing “both the economics and the long leadtimes” needed in that sector.

    Serin is targeting a 10 percent rise in oilsands cap-ex, following this year’s antici-pated 25 percent increase over 2011.

    “On the conventional basis, we thinkspending will fall by 5 to 10 percent afterabout a 10-15 percent drop this year. Ifanything we’re probably conservative onthat number,” he said.

    Serin is targeting a New YorkMercantile Exchange gas price in 2013 ofUS$4 per million British thermal units,noting the AECO price is usually 50 centslower than Nymex.

    Gas exports downHe noted that Canadian gas exports will

    fall to 55 percent of Canadian productionthis year, down from the historic level of 65percent and “over the next couple of yearsit’s going to fall even more becauseMarcellus production is not only g0ing togrow for the northeast U.S., but we recent-ly started importing Marcellus gas intoCanada to the tune of 500 million cubicfeet per day and that will probably grow to1 billion cubic feet per day.”

    Serin said that trend underscores theurgent need for Canada to move aheadwith LNG exports to Asia — a messagethat does not seem to be resonating, givena forecast by Wood Mackenzie that thefirst shipments from Western Canada arenot likely to occur until 2019.

    “LNG matters, even if you’re not with acompany that’s exporting LNG,” he said.“The reason it matters is it will significant-ly drive activity in the Western CanadaSedimentary Basin and unless we get an

    export opportunity — whether to new mar-kets in the U.S. or Japan, Korea and Chinain the form of LNG — we’re going to beawash in gas for some time.”

    That will confine netbacks on long-term LNG contracts to US$4-US$5, Serinsaid.

    But he welcomed the return of super-majors to Canada’s non-oil sands sector,especially ExxonMobil’s offer to take overCeltic Exploration and start drilling in theDuvernay formation, where wells costC$10 million to C$15 million.

    Serin also expects significant capitalspending in the Montney liquids-rich playwhich straddles the northeastern BritishColumbia and west-central Alberta border,the Cardium tight oil play and the emerg-ing Duvernay liquids-weighted shale play.

    He said the industry has spent aboutC$4.5 billion acquiring Duvernay land inthe last two years and expects capital send-ing in the formation to top C$1 billion in2013.

    Drilling days downThe latest statistics for 2012 covering

    the first nine months show member com-

    panies of the Canadian Association ofOilwell Drilling Contractors logged 82,295operating days, compared with 95,084 inthe same period of 2011, with total metersdrilled declining to 15.86 million metersfrom 16.19 million meters, although wellsaveraged 1,938 meters up from 1,753meters a year earlier.

    Operators across Canada drilled 8,163wells during the January-September peri-od, off 11 percent from 9,178 wells in thefirst three quarters of last year.

    Manitoba was the only province toreport a gain, drilling 463 wells, up almost35 percent, while British Columbia was atthe other end of the spectrum, down 27percent at 347 wells.

    Alberta logged 3,682 oil or bitumenwells, off 62 from a year earlier, whilewells targeting gas or coalbed methaneslumped to 813 from 1,507.

    A similar pattern prevailed inSaskatchewan, where 2,218 oil wells weredrilled compared with 2,350 in the sameperiod of 201. Gas wells in that provincedropped to nine from 32. �

    PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012 5

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

    Canada goes conservativeService sector ‘cautiously optimistic’ about 2013 drilling, based on technology impact on well count; capital spending could drop 10%

    Contact Gary Park through [email protected]

    http://www.amarinecorp.com/http://www.ReactiveGel.com/mav

  • By WESLEY LOYFor Petroleum News

    Federal officials are asking a court to dis-miss a lawsuit an Alaska explorer filedin an effort to kill a $15 million fine for analleged violation of the Jones Act.

    Furie Operating Alaska LLC sued feder-al authorities, including Homeland SecuritySecretary Janet Napolitano, on Aug. 7 inU.S. District Court in Anchorage.

    The suit concerns the ocean transport ofa jack-up drilling rig in 2011 from Texas toAlaska’s Cook Inlet, where Furie is explor-ing for natural gas.

    Federal authorities determined Furie did-n’t have clearance under the Jones Act to usea foreign ship to haul the rig. U.S. Customsand Border Protection, an agency within theDepartment of Homeland Security, assesseda fine of $15 million, which corresponds tothe agency’s determination of the rig’s value.

    In its lawsuit, Furie seeks a judgment thatthe fine is “null and void.” The companyargues the fine is arbitrary and capricious,and unconstitutionally excessive. Furie alsoargues that the rig was not “merchandise” asdefined in the law, and therefore no JonesAct violation occurred.

    On Nov. 9, Department of Justicelawyers representing Homeland Securityanswered Furie’s suit with a motion askingthe court to throw out the case, arguingFurie sued prematurely.

    Waiver inconsistency?The Jones Act requires that cargo trans-

    ported between domestic ports be done withU.S.-made ships, owned and crewed byAmerican citizens.

    A foreign-flag, heavy-lift vessel, theM/V Kang Sheng Kou, hauled the Spartan151 rig from a Texas port to Vancouver,British Columbia. From there, U.S.-flagtugs towed the rig to Cook Inlet, arriving onAug. 11, 2011.

    Escopeta Oil Company LLC originallyarranged the rig transport, but Furieacquired Escopeta on June 29, 2011.

    Furie’s suit says the Kang Sheng Kouwas used because the U.S.-flag Jones Actfleet had no ship capable of safely carryingthe rig around South America, which wasnecessary because the rig was too big topass through the Panama Canal.

    Furie argues that, in 2006, HomelandSecurity granted a Jones Act waiver,although it was for a different jack-up rigand a different foreign transport vessel.

    Problems developed with that rig, and itwas never transported to Alaska.

    In 2010, Furie asked Napolitano toreconfirm the 2006 waiver, saying the basisfor the original waiver had not changed — alooming natural gas shortage inSouthcentral Alaska, home to a major mili-tary base and the Anchorage internationalairport.

    But Homeland Security officials told thecompany the 2006 waiver was no longer ineffect and that it would need to seek a newwaiver or face penalties, the government’sNov. 9 motion says.

    On March 7, 2011, Napolitano deniedFurie’s request for a waiver.

    “Nonetheless, Furie assumed that aJones Act waiver would be granted,” themotion says, and the Kang Sheng Koudeparted Texas with the Spartan 151 rig.

    As the long voyage unfolded, Furie con-tinued talks with federal officials, who atone point said initiating the rig transportafter Napolitano had denied the waiverwould be viewed as an “aggravating factor”in a Jones Act violation.

    Customs and Border Protection officials

    also said the violation was committed forcommercial expediency. They noted thatFurie could be eligible for millions of dol-lars in state drilling tax credits as a result oftransporting the rig in violation of the JonesAct.

    Furie feared Homeland Security offi-cials might seize the rig, but that didn’t hap-pen.

    No need to payJustice Department lawyers argue

    Furie’s suit is premature, as assessment ofthe $15 million penalty does not consti-tute a “final agency action.”

    Furie has not paid any portion of thefine. And although Customs and BorderProtection officials have hit Furie withdemand letters and threats to forward thematter for “collection action,” a violatoris “under no compulsion” to pay a penal-ty that has been merely assessed, the gov-ernment’s motion says.

    Only a court has the authority to com-pel payment, the motion says. And so far,federal authorities haven’t sued to enforceand collect the Jones Act penalty assessedagainst Furie.

    If and when the government files suit,Furie would have an opportunity at thatjuncture to defend against the penalty, themotion says.

    And so Furie’s lawsuit should be dis-missed, the Justice Department argues. �

    6 PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012

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    Feds move to have Furie lawsuit tossedDOJ says company acted prematurely in going to court to try to kill $15 million fine for illegal transport of drilling rig to Alaska

    Only a court has the authority tocompel payment, the motion says.

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  • PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012 7

    GOVERNMENTAgencies extend habitat rule comment

    The U.S. Fish and Wildlife Service and the National Marine Fisheries Servicehave re-opened the public comment period for a proposal to simplify the processfor identifying the critical habitat of species listed under the Endangered SpeciesAct. The original 60-day public comment period closed on Oct. 23 but, followingpublic interest in the proposal and multiple requests for more time for comments,the agencies are extending the comment period by an additional 90 days. Theextended comment period will end on Feb. 6.

    When an animal is listed for protection under the Endangered Species Act, theagency making the listing has to specify a critical habitat for the animal. But theact requires an economic evaluation of the critical habitat designation, with thepotential for excluding areas of critical habitat from designation if the economicdownside of designation outweighs the upside of habitat protection.

    Fish and Wildlife and the Fisheries Service propose changing their EndangeredSpecies Act regulations to require publication of preliminary estimates of the eco-nomic impacts along with a proposed habitat designation — the agencies have inthe past completed the draft economic analysis at some time after the proposedhabitat designation has been published for public review.

    “Completion of the draft economic analyses at the time of (habitat) proposalwould allow the agencies to refine habitat proposals earlier in the process, andprovide the public with additional information to help them understand and com-ment on those proposals,” the agencies said in a Nov. 7 press release.

    The proposal is part of a general effort to find improved ways to conserveimperiled species while also being consistent with an executive order by the pres-ident to identify regulatory changes that will achieve regulatory objectives moreefficiently and effectively, the agencies said.

    —ALAN BAILEY

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

    Cook Inlet Energyplans more gas wellsAnchorage-based firm to spud exploratory well soon at Olsen

    Creek prospect; fracking operation conducted at neighboring Otter

    By WESLEY LOYFor Petroleum News

    Cook Inlet Energy LLC is aiming tospud an exploratory well by mid-December at its Olsen Creek natural gasprospect on the inlet’s west side.

    David Hall, chief executive of theAnchorage-based company, said theOlsen Creek gas structure has “strongpotential.”

    In recent months,the company hasbeen upgrading andextending the roadsystem to theprospect, and hopesto start constructionsoon on the wellpad, Hall said.

    He made thecomments during anOct. 30 conference call for investors inMiller Energy Resources Inc., theTennessee-based parent company ofCook Inlet Energy.

    Potential 84 bcf fieldOlsen Creek is among a number of

    shallow gas prospects Cook Inlet Energyhas on the west side. The Olsen Creekprospect is west of the ConocoPhillips-operated Beluga River gas field.

    The initial well will evaluate the OlsenCreek structure, Hall said.

    “If successful, we see the potential for24 wells on our leases,” he said.

    The company estimates a potential foreach well of up to 3.5 billion cubic feet ofgas, with a potential reservoir size for thefield of about 84 bcf, Hall said.

    Olsen Creek’s oil potential also isbeing evaluated, he said.

    The company is using its own rig 34 todrill the gas prospects. The truck-mount-ed Atlas Copco RD20 rig was brought upfrom Tennessee and extensively modifiedfor work in Alaska.

    The Otter prospectAbout seven miles northeast of Olsen

    Creek is the Otter prospect, where Cook

    Inlet Energy this year drilled the OtterNo. 1 exploratory well.

    Recently the company conducted ahydraulic fracturing operation on OtterNo. 1, using more than 800 barrels ofproppant, Hall said.

    Now the trick is removing the frackingfluid, which is believed to be keeping theformation gas from entering the well-bore, he said.

    “Currently, we are recovering portionsof the frack fluid as the well releases it,”Hall said. “We have recovered 150 bar-rels to date. We’re still very optimisticabout Otter and will continue trying tobring it online once we recover the frackfluids.”

    Hall noted that while drilling Otter,mud pump problems forced a halt to thedrilling at about 5,600 feet on a wellplanned for a depth of 7,000 feet, Hallsaid.

    As a result, only a short section of theBeluga formation and none of the Tyonekformation were evaluated, he said.

    New, more robust mud pumps havebeen purchased for installation on rig 34,and the company is planning a secondOtter well to a minimum depth of 7,500feet, which should yield more potentialgas pay zones for evaluation, Hall said.

    Cook Inlet Energy also operates theWest McArthur River oil field and theoffshore Redoubt unit with the Ospreyplatform.

    During the Miller Energy investorconference call, executives said the com-pany’s total Alaska oil production wasrunning between 1,400 and 1,450 barrelsa day. �

    DAVID HALL

    Olsen Creek is among a number ofshallow gas prospects Cook InletEnergy has on the west side. TheOlsen Creek prospect is west of

    the ConocoPhillips-operatedBeluga River gas field.

    Contact Wesley Loy at [email protected]

    http://www.arcticcontrols.com/http://www.lounsburyinc.com/http://www.askcasey.com/

  • By PAUL FOYAssociated Press

    The U.S. Department of the Interiorscaled back a Bush administrationplan Nov. 9 to lease Western range lands fordevelopment of oil shale and tar sands, theunconventional sources of oil found inpockets of the Rocky Mountains.

    Federal officials said they were set toauthorize 1,250 square miles of public landfor commercial leasing in Colorado, Utahand Wyoming. That’s a third of the rangelands that President George W. Bushplanned to offer, and the new administrationsaid it was taking wilderness-quality landsoff the table.

    On paper, the Rocky Mountain oil shaledeposits could yield a great abundance ofoil — more than 1 trillion barrels — butenvironmental groups say it would involveripping up public lands and depleting scarcesources of water. Political leaders in

    Arizona and Nevada and farmers worryabout a diversion of Colorado River water.Big-game hunters oppose the intrusion ofmining. Thousands of pages of commentshave been filed on the plans.

    The U.S. Bureau of Land Managementsaid it selected the best reserves for oilshale, a rock that contains fossilized algae, aprimitive form of oil that never receivedenough heat or pressure to produce liquidcrude. It’s also a hard nut to crack — majoroil companies are still experimenting withways to make production economical,notably by baking rock in the ground torelease fluids.

    The federal government is making about200 square miles of the federal lands avail-able for tar sands mining in Utah, similar toone project already under way on the state’sown trust lands. The BLM issued the deci-sion Nov. 9 along with a 6,245-page envi-ronmental impact study.

    Environmental groups applauded

    Interior Secretary Ken Salazar’s caution.Utah politicians called it short-sighted.

    “Once again, despite President Obama’scalls for an ‘all of the above’ energyapproach, his administration is moving tolimit American energy production and thejobs that come with it,” said Sen. OrrinHatch, R-Utah.

    Sen. Mark Udall, D-Colo., struck ameasured response, saying he was con-cerned about the use of limited water sup-plies.

    “Nonetheless, I look forward to seeingthis technology explored further. We needan all-of-the-above energy policy,” Udallsaid Nov. 9. “The Interior Department’sdecision ensures that we will not be out overthe front of our skis with untested technolo-gy.”

    The federal government has yet toauthorize widespread development, insteadleasing 160-acre research plots to a handfulof companies testing extraction methods.

    Rifle, Colo.-based American Shale Oil LLCis heating an underground zone by pumpinga pool of oil down a well and blasting it withhot fuel gas.

    The BLM said players must prove theirresearch before winning larger commercialleases. It approved another two researchleases Nov. 9, to ExxonMobil ExplorationCo. and Natural Soda Holdings Inc. for in-ground development in Colorado’sPiceance basin.

    In Wyoming, the BLM said it was put-ting limits on development in areas wheresage grouse gather. That was small comfortto the Laramie-based BiodiversityConservation Alliance, however. The groupsaid any kind of development can chase offsage grouse, the birds that puff themselvesup in mating dances.

    The U.S. Fish & Wildlife Agency isunder court orders to determine by 2015whether sage grouse deserve protectionunder the Endangered Species Act.

    Also in Wyoming, the BLM pulled theRed Desert’s Adobe Town from considera-tion, a 128-square-mile wilderness studyarea rich in fossils.

    A host of Republican politicians sound-ed off Nov. 9.

    “The Obama Administration should can-cel this plan and work with Congress andgovernors on solutions that will create jobsand strengthen our energy security,” saidSen. John Barrasso, R-Wyo.

    Rep. Ed Whitfield, R-Ky., chairman ofthe House Energy and PowerSubcommittee, said the Obama administra-tion was “locking up” as much potentialoil “as the rest of the world’s provenreserves combined.” �

    8 PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012

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  • By ALAN BAILEYPetroleum News

    With oil production from Alaska’sNorth Slope in continuous declinefor many years, Alyeska Pipeline ServiceCo., the operator of the trans-Alaska oilpipeline, has been upgrading the line andtaking other actions to accommodate thetechnical issues caused by decliningpipeline throughput. And an overview ofthe latest status of Alyeska’s efforts todeal with the slowing flow of oil forms acore component of the 2012 StatePipeline Coordinator’s Annual Report,published in October by the AlaskaDepartment of Natural Resources.

    Pipeline throughput peaked at morethan 2 million barrels per day in 1988 buthad dropped to around 600,000 barrelsper day in 2012, the report says. The StatePipeline Coordinator’s Office overseesthe construction and operation of

    pipelines, including the trans-Alaskapipeline, on state right-of-way leases.

    Low flowThe key issue for the trans-Alaska

    pipeline is the speed at which oil flowsdown the line. Essentially, the pipelinehas a fixed internal volume configured tohandle peak oil throughput and, with lessand less oil entering the upstream end ofthe line, oil filling the line takes longerand longer to travel from the North Slopeto Valdez.

    With the slowing oil flow, the originalpipeline pump systems, designed to han-dle relatively high rates of oil throughput,became inefficient and unsuitable forflexibly handling the lower flow rates.And, with the oil taking longer to travelthe pipeline’s 800-mile length, the oil,warm as it exits the oil fields, becomesincreasingly cold along the pipeline route,raising risks associated with the freezingof water carried along with the oil andpotentially increasing the clogging of thepipeline walls with wax deposits.

    Strategic reconfigurationIn the early 2000s, to address the

    increasing inefficiency of the pumpingsystems as oil volumes declined, Alyeskainitiated what it termed “strategic recon-figuration,” a massive project involvingthe replacement of the original turbinedriven pumps by new state-of-the-artelectrically powered pumps — variablefrequency drives on the new pumps wouldenable the pumps to operate over a rela-tively wide range of pump speeds. And aspart of strategic reconfiguration, Alyeskainstalled new remotely operated pipelinecontrol and monitoring equipment, usingmodern digital technology.

    Alyeska completed the electrificationupgrades at pump stations 3, 4 and 9 inthe years 2005 to 2009. Upgrade workstarted on pump station 1 in the 2000s butAlyeska subsequently put this upgrade onhold, the report says.

    With fewer pump stations needed atlower oil throughputs, Alyeska shut in theremaining pump stations, apart frompump station 5, which acts a pressurerelief station on the south downslope ofthe Brooks Range and does not pump oil.

    Pump station 1During the 2011 financial year, which

    ended on June 30 of that year, Alyeskarestarted the upgrade at pump station 1 ina phase of strategic reconfiguration thatthe company called the electrification andautomation project, or EA, the reportsays. The EA project involves the installa-tion of three new mainline pumps, withelectric motors and variable frequencydrives; the installation of a 12-megawattturbine-powered electrical generator; andthe modification of two of the threebooster pumps at the pump station forelectrical service. The project alsoinvolves the construction of a power lineand electrical substation, to enable thenew pumps to use power from thePrudhoe Bay grid in the event of a shut-down of the new generator system.

    As part of the project, by the end ofJune of this year Alyeska had installedabout 200,000 feet of the 293,000 feet ofnew electrical cabling needed at pumpstation 1. The new electrical substationwas completed in the spring of 2012 and

    � P I P E L I N E S & D O W N S T R E A M

    Trans-Alaska pipeline upgrades continueAlyeska progresses pump station electrification and installation of technology for dealing with low oil flow through line

    10 PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012

    As oil throughput in the trans-Alaska pipeline declines, Alyeska Pipeline Service Co. contin-ues to upgrade the line for low-flow conditions.

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  • work on the pump station cabling is pro-gressing around the clock, the report says.The EA project appears to be on target forcompletion in the summer of 2014, thereport says.

    Three eventsFrom the perspective of falling oil tem-

    peratures, the report highlights threeevents that illustrate the vulnerability ofthe pipeline to low-flow problems. InNovember 2006 low flow resulting fromreduced North Slope oil production,storms at sea and some tanker loadingproblems at Valdez caused the internalpipeline temperature to drop to 37 F. In2008 delayed tanker loadings because ofstorms resulted in a temperature drop tobelow 40 F. And in January 2011 an oilleak at pump station 1 on the North Slopetriggered an extended pipeline shutdown,with the oil temperature dipping to 26 F.

    “While these events were cause forconcern, none of them prevented therestart of TAPS,” the report says. “Afuture event with a more extended shutdown or lower flow rate might seriouslyaffect the ability to restart flow.”

    RecyclingSince the January 2011 shutdown inci-

    dent Alyeska has been recycling oil atpump stations 3, 4, 7 and 9 to warm theoil when oil temperatures in the pipelinedrop, the report says. Recycling involvespumping some or all of the oil throughpressure-reducing valves at the pump sta-tions, with the pumps adding energy tothe oil and the pressure reduction convert-ing flow energy to heat.

    However, Alyeska has encounteredsome snags with the recycling arrange-ments, including mechanical problems atpump stations 3 and 4, and flow-inducedvibrations at pump station 7. The compa-ny is upgrading the recycling systems atthese pump stations and anticipates thesystems being fully operational by late2012 or early 2013, the report says.

    Alyeska has also sanctioned a projectdesigned to further increase oil tempera-tures through the use of improved controlvalves for the recycling systems at pumpstations 3 and 4, and through the use ofnew control valves at pump station 7, thereport says.

    The company is investigating the pos-sibility of heating the pipeline oil flow atpump station 5 and is also consideringother possibilities for mitigating the risksto winter pipeline operations. Those pos-sibilities include injecting additives suchas freeze-depressants or emulsifiers intothe oil; removing water from the oil atpump station 1; and tightening the stan-dards for the amount of water and sedi-ment allowed in oil delivered to thepipeline.

    The report also points out that anotherway of addressing the low flow issueswould be to increase production from theNorth Slope oil fields.

    Follow upAs a follow up to the January 2011

    incident and in response to a safety orderby the U.S. Department of Transportation,Alyeska has been replacing or removingsome old piping at pump station 1; con-structing an additional facility betweenpump stations 5 and 10 to launch andreceive the torpedo-shaped “pigs” that areused to clean and inspect the inside of theline; researching the installation ofincreased pump station tank capacity; andstaging equipment needed for cold tem-perature operations or a pipeline restart incold conditions, the report says.

    And the company has revised its pro-cedures for a pipeline cold restart. Undernew procedures, if the oil temperaturedrops below 40 F during a pipeline shut-down, a startup of the pump station recy-cling systems to warm the oil will precedethe startup of oil flow through thepipeline. However, if the oil temperaturedrops below the normal operating temper-

    ature range in a situation where oil flowhas stopped for an extended duration, itmay be necessary to pump oil both northand south in the pipeline to prevent the oilin the line gelling, the report says.

    And, to implement the new cold restartprocedures, Alyeska has installed new540-horsepower booster pumps at pumpstations 7 and 9 and anticipates installing

    a 3,390-horsepower engine for the boost-er pump at pump station 12 in 2013, thereport says.

    The company is improving the recy-cling arrangements at pump station 5 byusing a tank heater to add heat to the oilin the event of a cold restart.

    Alyeska has accepted that the mini-mum safe oil temperature to maintain oilflow is 31 F but the company also saysthat the oil temperature should be main-tained at or above 36 F, with this being thetarget minimum temperature to be main-tained as a result of low flow mitigationprojects, the report says.

    Refinery changesOne particular issue that Alyeska now

    needs to contend with is a further drop inoil temperatures in the southern section ofthe pipeline as a consequence of thereduced temperature and lower volume ofresidue fluids entering the line from theoil refinery at North Pole, near Fairbanks.The refinery uses some oil from thepipeline as feedstock and returns therefinery residues back to the line. Theheat from these residues has been animportant factor in maintaining adequate

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    A staff member from the State Pipeline Coordinator’s Office views pump station 12 modifi-cations designed to facilitate a cold pipeline startup in the winter.

    continued from page 10

    PIPELINE UPGRADES

    see PIPELINE UPGRADES page 12

    http://www.nabors.com/

  • oil temperatures in the pipeline south ofNorth Pole. Since February 2012 an ener-gy savings initiative at the refinery hasreduced the temperature of the residuesby 20 to 25 F, while a cut back in refineryproduction has resulted in a correspon-ding drop in the volumes of refineryresidue, the report says.

    Pipeline vibrationsAlyeska has also been addressing

    issues associated with pipeline vibrationsat the three mountain passes that the linecrosses: Atigun Pass in the BrooksRange, Isabel Pass in the Alaska Rangeand Thompson Pass, north of Valdez. Thevibrations first appeared in the 1990s atThompson Pass, where Alyeska has miti-gated the problem by increasing thedownstream backpressure in the line, thereport says. The company is trying a sim-ilar approach at Atigun Pass.

    “Preliminary indications are thatvibrations have been reduced and APSC(Alyeska) is evaluating the data to see ifTAPS can operate continuously with thisbackpressure,” the report says.

    With metal fatigue damage being pre-dictable by a mathematical analysis, anengineering study of the vibrations con-cluded that vibration induced stresses atAtigun Pass will not result in any risk ofa pipeline rupture “in the intermediate or

    near future,” the report says. However,the vibrations have caused cracks toappear in some of the “shoes” that cradlethe pipeline on the above-groundpipeline support structures in theChandlar Shelf area on the south side ofthe pass. Alyeska now regularly monitorsand, as necessary, replaces the shoes inthe affected area, the report says. Thecompany is also taking steps to improvethe shoe design and is installingaccelerometers for better vibration datalogging and analysis.

    Vibration levels in Isabel Pass,although increasing, are much lower thanin the other two passes, the report says.

    “The original TAPS design has built-in redundancies. Such safety factorsinclude the allowance for limited(pipeline) support failure,” the reportsays. “For these reasons, and others, thevibrations in these areas do not appear toconstitute an integrity threat.” �

    12 PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012

    Valdez lives up to its snowy reputationAs a few roofs in Anchorage collapsed under the weight of record snowfalls in

    the 2011-12 winter, Valdez, the location of the marine terminal where oil from thetrans-Alaska pipeline is loaded into tankers for shipment south, lived up to its rep-utation as the snow capital of Alaska.

    “More than 450 inches of snow fell in Valdez between October and April, withthe majority falling during the month of December 2011,” Alaska’s State PipelineCoordinator’s Office wrote in its annual report, published in October.

    With the rate of snow accumulation quickly outpacing normal snow removalcapabilities, the large volumes of snow on infrastructure such as oil storage tanksat the marine terminal became a prime concern for pipeline and terminal operatorAlyeska Pipeline Service Co. and for state agencies, the report says.

    Alyeska had to prioritize the snow removal needs and mobilize extra snowremoval crews to ensure the safety of personnel and to minimize any oil dischargerisk at the terminal, the report says. Staff from the Alaska Department ofEnvironmental Conservation and environmental program specialists in the StatePipeline Coordinator’s Office monitored snow accumulation and removal daily,consulting with each other and Alyeska to make certain of the safe, continuedoperation of the terminal, the report says.

    —ALAN BAILEY

    continued from page 11

    PIPELINE UPGRADES

    Contact Alan Bailey at [email protected]

    Alyeska has also been addressingissues associated with pipeline

    vibrations at the three mountainpasses that the line crosses: AtigunPass in the Brooks Range, Isabel

    Pass in the Alaska Range andThompson Pass, north of Valdez.

    NATURAL GASBegich proposes benefits for in-state gas

    Sen. Mark Begich said Nov. 12 that he is proposing legislation to apply one-stoppermitting benefits to any Alaska natural gas transportation system — an in-statepipeline, trucking gas or any combination of transportation systems.

    The legislation would amend the Alaska Natural Gas Pipeline Act of 2004, whichcreated a federal office to coordinate with more than 20 federal agencies, the Canadiangovernment, the State of Alaska, tribal governments and other stakeholders with thegoal of seeing a natural gas pipeline constructed to move Alaska’s natural gas to Lower48 or Canadian markets.

    Begich said he was responding to skyrocketing energy prices in Interior and ruralAlaska.

    The bill adds an in-state natural gas transportation system and an in-state gas lineand associated liquefied natural gas project to the purview of the Office of the FederalCoordinator of Alaska Natural Gas Transportation Projects.

    “Alaskans are crying out for some kind of solution to the rising cost of energy —particularly in rural Alaska and communities like Fairbanks,” Begich said in a state-ment. “High energy prices and potential energy shortages threaten our state’s eco-nomic stability. We have to start proposing solutions in an effort to bring costs down.”

    The legislation provides the same regulatory deadlines, expedited judicial reviewand tax advantages currently applicable to a natural-gas pipeline traveling the DaltonHighway to Canada to any natural gas project bringing North Slope gas to a market inAlaska or elsewhere.

    “I have always said the market will determine if we can build a project and where,”Begich said. “It’s government’s role to provide a swift and certain regulatory environ-ment and then get out of the way. This bill does just that. Federal permitting and taxbenefits for an instate natural gas project will make any option more financially fea-sible for private-sector developers and hopefully bring relief to Alaskans facing highenergy prices.”

    Begich said he would seek further comment from stakeholders before formallyintroducing the bill.

    —PETROLEUM NEWS

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  • By BILL WHITEResearcher/writer for the Office

    of the Federal Coordinator

    The famous face of LNG involvesmultibillion-dollar developmentsrescuing stranded treasures of natural gas,shipping it across oceans aboard tremen-dous tankers to distant cities where cus-tomers crave a less polluting alternativeto oil or coal to make electricity and heathomes.

    But running inthe background is amore mundane facetof liquefied naturalgas.

    This facet, unlikeits globe-trottingbrother, doesn’tinvolve multination-al lending consortia,trade-balance con-siderations and national-interest debates.It involves consuming LNG in sips notgulps, deliveries by trucks not tankers.

    This part of the industry might be con-sidered niche LNG.

    The cast of characters includes localgas utilities that want a small cache of gascompactly warehoused for quenchingdemand spikes during cold snaps.

    And pipeline companies that need aspurt of extra gas to maintain pressureand reliability at times of high consump-tion.

    And off-the-pipeline-grid industrialsites — a mine, perhaps, or a small com-munity — that need a fuel that can betrucked in affordably.

    This small side of LNG mainlyencompasses the original commercial useof liquefied natural gas — as a so-calledpeak-shaving fuel for utilities — a use ofnatural gas that started 70 years ago, wellbefore the launch of international trade inLNG.

    But money also is getting invested andplans are being drawn to find other nichemarkets for LNG.

    Small-scale LNG champions dream ofsmall power plants on isolated islandsburning LNG not oil-based fuels.

    They want to extend the reach of natu-ral gas into transportation fuels — adomain oil dominates — with heavy-dutytrucks powered by LNG not diesel, andships burning natural gas not oily bunkerfuel.

    They want oil fields powered by LNGnot diesel. And remote oil fields liquefy-ing associated gas production rather thanburning or venting it.

    “Small-scale LNG is ... increasinglybeing used as a means of monetizingearly gas from fields distant from infra-structure, reducing the need to flare,” aShell executive wrote in “LNG 2012,” aPetroleum Economist publication.

    Much R&D effort is getting channeledto niche LNG, trying to minimize the dis-advantages of small economies of scale inan industry defined by megaprojects.

    If costs can be wrung from themachinery of small-scale liquefaction,transportation, storage, regasification orhow engines consume LNG, the resultingefficiencies can make niche LNG animportant growth sector for the industry.

    “On the back of innovations in small-scale liquefaction and engine technology,the spread of gas to transport may yethave the potential to become a secondwave of the LNG business,” as AjayShah, head of strategy and portfolio inShell’s Global LNG business, put it in

    “LNG 2012.”

    Two forces — economic, environmental It’s almost impossible to draw a sharp

    line separating natural gas liquefied forexport from LNG made for niche uses.

    Some LNG stored to slake utilitydemand spikes — called peak-shavinggas — is homemade and some is import-ed. Some homemade LNG is truckedacross the border as exports.

    Still, certain information is availablethat sketches an outline of the industry:

    In the United States, one plant madeLNG for export — in Nikiski, Alaska —and 59 made LNG for peak shaving,according to Energy InformationAdministration 2008 figures. In addition,the United States had 41 other sites whereLNG was trucked in and stored for peakshaving, but where no LNG makingoccurred.

    Worldwide, about 260 peak-shavingand storage sites exist, according to theUniversity of Texas Center for EnergyEconomics. That compares with 26 plantsin 19 countries that make LNG for exportand about 90 plants worldwide thatreceive, store and regasify large volumesof imported LNG.

    But equating number of plants withLNG production would be misleading,like assuming convenience stores outsellsupermarkets because there are more of

    them. A typical U.S. LNG-for-peak-shav-ing plant can process 5 million to 20 mil-lion cubic feet of gas per day, accordingto Black & Veatch, a global engineeringand construction firm involved in devel-oping LNG projects. (That’s not much; atypical house might consume 50,000cubic feet of gas per year for heat; muchmore in Alaska, less in Alabama.) But theworld’s LNG-for-export plants range in

    size up to 5.4 billion cubic feet a day; theaverage processing capacity is about 1.5bcf, roughly 100 times larger than thetypical peak-shaving LNG plant.

    In other niche markets, LNG has bare-ly a toenail hold. In the United States nat-ural gas provides just 0.2 percent of vehi-cle fuel, and almost all of that gas is com-pressed methane or propane, not LNG.

    As of last year, only 29 of the tens ofthousands of ocean-going vessels usedLNG as their main fuel. Most were ferriesserving the seas around Norway.However, many of the world’s 370 LNGtankers use boil-off, or vaporized, gasfrom their cargo for some of their energyneeds.

    The drive to grow small-scale demandfor LNG stems from two potent forces.

    One is economic. A gap has openedbetween oil and natural gas prices in partsof the world. In an era when oil priceshave averaged a lofty $90 a barrel for thepast five years, pained consumers of oilare hunting for less-expensive fuels.

    In North America the price gap isacutely wide, making fuel switching morealluring. Oil is sold in increments of 42-gallon barrels and natural gas in incre-

    � N A T U R A L G A S

    Small-scale LNG a niche which can grow

    PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012 13

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  • 14 PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012

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    ments of 1,000 cubic feet. Because a bar-rel of oil packs about six times more ener-gy than 1,000 cubic feet of gas, on a pureenergy basis oil should be priced aboutsix times higher than gas. But in NorthAmerica today, amid a shale-gas supplyglut, oil is priced 25 times higher thangas. That kind of gap shortens the break-even moment of switching fuels.

    The other force at play is environmen-tal. Natural gas burns more cleanly thanother fossil fuels, and governments aredemanding fewer toxic and greenhouse-gas emissions from power plants, ships,trucks and other fuel users.

    The most beaming optimists see a glo-rious future for LNG, one in which LNG-powered engines guzzle 31 bcf a day ofthe fuel in North America alone, as oneconsultant predicted at a Canadian energyconference this fall. Or the ocean’s shipsburning 4 bcf a day worth of LNG in theirboilers, as executives with GDF Suez, amajor European energy company, predict-ed in “LNG 2012.”

    Others think that’s crazy talk.Below we look briefly at some niche

    uses of LNG.

    Peak shaving by utilitiesIn the chain of events that routes

    methane from deep underground in somefaraway place to the pilot light on your fur-nace, storage is a key link.

    Storage balances the wild swings innatural gas consumption during the year— high demand for heat during winter,high demand for air conditioning duringsummer — with the steady flow of gasproduction year-round. Excess productiongets stored during slack demand so utilitiescan use the gas later, sort of like canning

    the fall harvest to eat during winter andspring.

    The U.S. Energy InformationAdministration calls gas storage and peakshaving “a risk-management calculation”by the utility or pipeline company. It’s cost-ly to install storage and peak-shavingplants. “However, the cost of a serviceinterruption, as well as the cost to anindustrial customer in lost production, maybe much higher” if they don’t have gaswhen they need it.

    In addition, storing gas means a localutility avoids reserving tremendous — andexpensive — space on supply pipelines,space the utility would use only rarely dur-ing demand spikes. “The objective is tomaintain sufficient local underground nat-ural gas storage capacity and have in placeadditional supply sources such as LNGand propane air to meet large shifts in dailydemand, thereby minimizing capacityreservation costs on the supplyingpipeline,” the EIA says.

    In the gas-storage game, LNG plays abit part.

    Most gas storage occurs in large vol-umes, with gas as a vapor piped under-ground into depleted gas fields, salt cav-erns or aquifers. Heading into this winter,U.S. utilities, producers, traders andpipeline companies has almost 4 trillioncubic feet of gas packed into undergroundstorage — a record amount. With gas pro-duction of about 67 billion cubic feet a dayin the dead of winter and gas consumptionof perhaps 90 bcf a day, this stockpile, plusimported Canadian gas, will help keep thelights on and furnaces warm.

    By contrast, LNG stored in above-ground tanks totals a mere 90 bcf or so, notall of it for peak shaving. The big disad-vantage of LNG storage for peak shavingis that it’s expensive relative to under-ground storage. The big advantage is the

    continued from page 13

    SMALL-SCALE LNG

    see SMALL-SCALE LNG page 15

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  • LNG is close by and can be put to usequickly.

    New England is a hotbed of gas lique-faction for peak shaving because the areahosts no underground storage sites andpipeline capacity into the region is eitherlimited or non-existent in rural areas. Atyear-end 2010, 17 of the nation’s 67 siteswhere LNG was stored largely for peakshaving were in New England, accordingto EIA data.

    Trucking, not piping, LNGLNG is either made at peak-shaving

    sites or trucked there in special insulatedtanks — commonly 40-foot-long Thermosbottles on wheels. LNG is too cold —minus 260 — to be piped anywhere; steelpipe exposed to the frigid LNG wouldshatter.

    The United States doesn’t import muchLNG, but the lion’s share of it arrives at areceiving terminal in Boston harbor. Thatterminal can warm the gas back into avapor and inject it into two interstate natu-ral gas pipelines and the local gas utility’spipes. The terminal also features fourtruck-loading bays that can send out 100million cubic feet a day. The terminal oper-ator, GDF Suez, boasts its customersinclude local gas distribution companiesthroughout New England, power plants,gas marketers and industrial users.

    China is another cradle of truckedLNG.

    Black & Veatch and its Chinese partnerChemtex International have built or arebuilding 16 LNG distribution plants acrossChina, according to “LNG 2012.” A 4-year-old plant called Erdos in remote InnerMongolia has four loading stations that fill33 trucks a day on average.

    “The model for Chinese developmentsis a central LNG plant which distributesLNG to multiple gas users in industrial andresidential markets,” Black & Veatch exec-utives wrote in the article.

    One of the executives, Shawn Hoffart,presented this fall at a London conferenceabout the latest innovation: a new northernChina plant that uses coal from a nearbymine as the feedstock to make LNG andmethanol. He estimated the plant willmake 78 truckloads a day of LNG.

    On a very small scale, some U.S. LNGgets trucked to remote users in Mexico.

    A U.S. company called Applied LNGTechnologies has been trucking LNG toMexico since at least 1998 from a lique-faction plant in Topock, Ariz.

    Last year the company trucked 1.6 bcfacross the border, according to the EnergyDepartment. It’s a niche business, to say

    the least. Last year the U.S. piped 500 bcfof gas to Mexico.

    Applied LNG plans to double thecapacity of its Arizona liquefaction plantso it can sell more LNG as vehicle fuel inCalifornia, another market it serves.

    LNG gets trucked in small quantitieselsewhere around North America to usersoff the gas pipeline grid. For example,since 1998, Fairbanks Natural Gas LLChas trucked LNG from its small liquefac-tion plant served by Alaska’s Cook Inletgas fields to customers 300 miles north inFairbanks. Last year it delivered about 900million cubic feet to 1,100 customers,mostly commercial accounts eager to avoidhigh-cost fuel oil. Fairbanks Natural Gas,and separately the Fairbanks-area electricutility and a nearby oil refinery, are con-sidering trucking larger volumes of LNGabout 350 miles south from Alaska’s NorthSlope fields.

    Hawaiian utilities also are moving toimport LNG instead of burning more cost-ly and dirtier oil-derived fuels. BecauseHawaii’s demand would be so small, thegas utility looks to start with a pilot projectof LNG delivered in insulated containersloaded aboard cargo ships that call on thestate. In time, the gas and electrical utilitiesmight work together to expand the import-ed volume enough to justify tanker deliver-ies rather than truckloads.

    Among pending applications at the U.S.Department of Energy for permission toexport LNG is one from a business eyingthe market of Caribbean utilities that burnoil. Florida-based Carib Energy wants per-mission to export 3.44 bcf a year “to anycountry located within Central America,South America or the Caribbean which hasor in the future develops the capacity toimport LNG” stored in containers thatcargo ships would carry.

    “Carib ... will transport the LNG withinthe United States over highways, using

    approved 40-foot ... LNG containers,” itsapplication says. The project anticipatesloading no more than 11 trucks a day. Theexports could occur from any of a varietyof southern U.S. ports.

    The buyers would include power plants,industrial and commercial customers thatneed small amounts of LNG “and wouldnot otherwise be served by very large sup-pliers of LNG,” Carib’s application says.

    LNG for heavy-duty trucksLNG is a niche fuel for vehicles, too.Only 3,354 vehicles in the U.S. use

    LNG as a fuel, according to the EIA. Many of them are trucks that move

    cargo around the huge neighboring portsof Los Angeles and Long Beach,California. To cut air pollution, those portsprohibit drayage trucks from burning dirtyfuels.

    Most of the trucks now burn clean

    diesel, but some — 8 percent of the LosAngeles port fleet — use LNG. The portshave LNG fueling stations to make sure thegas is available to truckers.

    Some city and regional buses, garbagetrucks, heavy-duty tractors also use LNG.

    Putting more LNG-fueled vehicles onNorth American roads might be confinedto heavy-duty vehicles, even though natu-ral gas is priced so much lower than oil-based fuels. Big fuel-guzzling trucks thatare on the road all day can recoup faster thehigher up-front cost of LNG vehicles.

    Still, LNG vehicles will remain a raresight until the industry surmounts someformidable barriers:

    LNG vehicles are much more expen-sive. “While emission reductions are com-parable ... there is a much greater costassociated with the purchase of LNGtrucks versus new clean diesel trucks,”says a white paper from the Port of LongBeach. The report pegged the cost of anLNG truck at $100,000 above the cost of adiesel truck.

    LNG vehicles need refueling sooner. Agallon of LNG packs less energy than agallon of diesel. An Energy InformationAdministration report said a 150-gallondiesel tank will take a heavy-duty truckabout 1,000 miles compared to about 300to 400 miles for a similar size tank ofLNG.

    Few places exist to refuel. It’s the clas-sic chicken-and-egg riddle. “Unless morenatural gas vehicles enter the market, therewill be little incentive to build more natu-ral gas fueling infrastructure nationally orin local or regional corridors,” the EIA saidin 2010.

    Of the nation’s 3,820 natural gas fueling

    PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012 15

    continued from page 14

    SMALL-SCALE LNG

    see SMALL-SCALE LNG page 17U

    .S.

    DEP

    ART

    MEN

    T O

    F EN

    ERG

    Y

  • 16 PETROLEUM NEWS • WEEK OF NOVEMBER 18, 2012

    Crowley’s tugboat, Guard, performs heroic rescueCrowley Maritime Corp. said Nov. 12 that the crew aboard its tugboat the Guard recently

    performed a heroic rescue of a man who was struggling to stay afloat in the waters outside ofSan Francisco Bay.

    The rescue took place during the early morning hoursof Oct. 31, while the tugboat was standing by outsidethe Golden Gate Bridge, waiting to escort a tanker intoSan Francisco Bay’s anchorage. Crowley’s Perry Overton,captain of the Guard, noticed the man treading water alittle more than a mile and a half from the bridge.Working quickly, the crew tossed the man a life ring andCrowley’s Chief Engineer Keith Madding donned a sur-vival suit and entered the frigid 55 degree waters to helpthe fatigued man climb the Guard’s emergency ladder. Once aboard, the crew removed thehypothermic man’s wet clothing and wrapped him in warm blankets until the Coast Guardarrived and could perform other life-saving treatments.

    Following the rescue, the Guard resumed escort duties on the tanker, bringing it to its desti-nation as scheduled.

    The Guard’s crew has been nominated by the National Park Service for a Citizen’s Award for

    Bravery, which is an honor awarded by the secretary of the Interior in Washington, D.C.Jacksonville-based Crowley Holdings Inc., a holding company of the 120-year-old Crowley

    Maritime Corp., is a privately held family and employee-owned company. The company providesproject solutions, transportation and logistics services in domestic and international markets bymeans of six operating lines of business: Puerto Rico/Caribbean Liner Services, Latin AmericaLiner Services, Logistics Services, Petroleum Services, Marine Services and Technical Services.Offered within these operating lines of business are: liner container shipping, logistics, contracttowing and transportation; ship assist and escort; energy support; salvage and emergencyresponse through its TITAN Salvage subsidiary; vessel management; vessel construction andnaval architecture through its Jensen Maritime subsidiary; government services, and petroleumand chemical transportation, distribution and sales. Additional information about Crowley, itssubsidiaries and business units may be found on the Internet at www.crowley.com.

    Calista Corp. board of directors reinstates GuyCalista Corp. said Nov. 7 that days after its annual meeting of shareholders, the board of

    directors voted to reinstate Andrew Guy as president and CEO. The decision was made at a spe-cial board meeting.

    Earlier in the year, the board placed Guy on administrative leave pending an investigation.

    ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS ADVERTISER PAGE AD APPEARS

    Companies involved in Alaska and northern Canada’s oil and gas industry

    All of the companies listed above advertise on a regular basis with Petroleum News

    AAcuren USAAECOM EnvironmentAggreko LLCAir Energi Air Liquide . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .4Aircaft Rubber Mfg. (ARM-USA)AIRVAC Environmental GroupAlaska Air CargoAlaska Analytical Laboratory . . . . . . . . . . . . . . . . . . . . . . . .17Alaska Dreams . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18Alaska Frontier ConstructorsAlaska Interstate


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