Saturday, September 29, 2012

Parnell, Sullivan promote Alaska LNG in Asia

Tim Bradner
Alaska Journal of Commerce

Gov. Sean Parnell and state Natural Resources Commissioner Dan Sullivan have been in Japan and Korea in the last two weeks, drumming up interest in a large Alaska liquefied natural gas project.

North Slope producers and TransCanada Corp., a gas pipeline company, are due to submit a progress report to Parnell Sept. 30 on their work on a gas pipeline and LNG project.

In a related development, a spokesman for TransCanada says the company, which has teamed up with the North Slope producers on LNG, is “encouraged” by the results from its recent solicitation of interest. Under terms of a state contract, TransCanada recently solicited market interest in a gas project although expressions of interest were nonbinding.

TransCanada cannot reveal the identity of firms that expressed interest, however.

Parnell was in Japan conducting an economic trade mission with energy officials in Japan and Korea with a focus on promoting Alaska’s gas in Pacific Rim markets.

“We look forward to capitalizing on the enormous potential that exists for Alaska’s North Slope natural gas in our state and in Pacific Rim nations,” Parnell said in a statement issued in Asia. “This is a great opportunity to strengthen existing relationships and build new ones that will grow economic opportunity with Japan and South Korea.”

Parnell met with the CEO of Korea Gas Corp., or KOGAS, to discuss Alaska’s longtime role as a reliable exporter of LNG to Asia from Kenai, and the state’s plan boost those exports with a major Alaska gas pipeline to tidewater.

Separately, the Korea Chamber of Commerce and Industry arranged for meetings between Parnell and executives from several Korean companies including Samsung C&T, STX Energy, Daesung Industrial Co., Ltd., Korea Midland Power Co., GS Global Co., LG International Corp., Hyundai Heavy Industries, and Korea Kumho Petrochemical Co., Ltd.

Parnell said there was significant progress being made on an all-Alaska gas pipeline to tidewater and the investment potential for these companies in Alaska.

In his visit to Korea prior to Parnell’s arrival, Sullivan met with senior government officials as well as executives with KOGAS and Korean National Gas Corp, or KNOC.

Sullivan had also been invited to speak Sept. 19 at the LNG Producer-Consumer Conference, one of the world’s major LNG conferences, and separately at a special briefing Sullivan gave organized by the U.S. Embassy in Tokyo.

Six hundred people had been registered to attend the Producer-Consumer Conferenc but Sullivan said the actual count was closer to 1,000.

The Asia LNG managers for BP and ExxonMobil, two major North Slope producers, were at the LNG conference along with government officials and companies promoting competing LNG projects, which gave Sullivan a chance to listen to competitors’ pitches.

About 70 invited industry and government officials attended the separate embassy briefing by Sullivan, which lasted for three hours.

Sullivan said his private, individual meetings with officials and industry executives were basically to lay the groundwork for Parnell, who followed him.

“He was there to meet with the ministers and CEOs,” Sullivan said, after the commissioner’s sessions with lower-level officials and managers.

Sullivan said he hit strongly on Alaska’s 40-plus years of reliability in serving Asian customers with LNG shipments from Kenai, and said he wasn’t shy about contrasting that with the spotty record of competitors like Russia, which has used gas supply as a political lever.

“I was pretty blunt. They have a crummy reputation for reliability. If they don’t like you, they cut you off,” Sullivan said.

Similarly, there was a buzz at the LNG conference about projects at Kitimat, B.C., but Sullivan had the chance to point out that the development of shale gas on which the projects depended has yet to happen on a major scale and that First Nations issues affecting the pipelines needed for the plants have yet to be resolved.

Alaska’s advantage is that the gas resource is known and secure. “There is zero resource risk. The infrastructure for production is in place. There is political stability. There’s no other place that offers those things except northern Alaska,” Sullivan said.

In terms of TransCanada’s solicitation of interest, company spokesman Shawn Howard said there was interest from potential shippers and “major players from a broad range of industry sectors and geographic locations,” including North America and Asia. He declined to name them, citing confidentiality.

He wouldn’t say if preference was shown for a project that serve North America markets or for one that would allow for liquefied natural gas exports overseas.

The non-binding solicitation ended Sept. 14. The expressions of interest are just that: not firm commitments to any one project.

Howard says TransCanada continues to work with the North Slope’s major players to evaluate options for bringing Alaska gas to market.

In 2010 TransCanada and ExxonMobil, its partner, conducted an open season for an earlier plan to build an all-land pipeline to Alberta, for delivering Alaska gas ultimately to Lower 48 markets.

The development of inexpensive shale gas had disrupted that plan, however, and attention has now turned to a pipeline to southern Alaska and an LNG terminal at a south Alaska port.

Tim Bradner can be reached at tim.bradner@alaskajournal.com.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/September-Issue-5-2012/Parnell-Sullivan-promote-Alaska-LNG-in-Asia/#ixzz27yxZj1la

Point Thomson advances; Alaska proposes granting pipeline right of way; wait for federal permit continues

Wesley Loy
For Petroleum News

ExxonMobil is close to securing a state right of way for a pipeline to support its planned Point Thomson development on Alaska’s North Slope.

But prospects for another key authorization remained unclear as the U.S. Army Corps of Engineers missed its target date for deciding on a wetlands permit for the project.

ExxonMobil is planning to produce petroleum liquids from the remote Point Thomson field, located on state land about 60 miles east of Prudhoe Bay. State officials have long pushed for production at Point Thomson, and in March signed a legal settlement with ExxonMobil and its partners laying out a development schedule.

Ultimately, the leaseholders could spend billions of dollars to fully develop the field, which holds an estimated 8 trillion cubic feet of natural gas and hundreds of millions of barrels of crude oil and other petroleum liquids.

On Sept. 19, state Natural Resources Commissioner Dan Sullivan signed a proposed lease decision for the Point Thomson Export Pipeline.

The pipeline will carry Point Thomson liquids 22 miles west across state land, feeding it into the existing North Slope pipeline network at the Badami field.

Sullivan’s preliminary conclusion is ExxonMobil is “fit, willing and able to construct and operate a pipeline in a manner required by present and future public interest,” a state public notice said.

Public comment invited

The State Pipeline Coordinator’s Office, part of DNR, is taking written public comment on the proposed lease through Oct. 30.  DNR is holding public hearings in three North Slope villages: Barrow, Oct. 23; Kaktovik, Oct. 24; and Nuiqsut, Oct. 25. A hearing also is planned in Fairbanks on Oct. 29.

The commissioner intends to issue the right-of-way lease provided no major issues arise from the public comment period.

The commissioner’s analysis and proposed decision is available at http://dnr.alaska.gov/commis/pco.

In leasing land for pipeline rights of way, state law requires the DNR commissioner to make a written finding that the applicant is “fit, willing and able.” The commissioner also must prepare an analysis of the application.

In this case, the applicant is PTE Pipeline LLC, a newly formed company created specifically to build and operate the Point Thomson Export Pipeline. PTE is a subsidiary of ExxonMobil Pipeline Co., which operates an extensive network of pipelines around the United States.

Another state agency also is considering the proposed pipeline.

PTE has applied to the Regulatory Commission of Alaska for a “certificate of public convenience and necessity.”

The commission has scheduled a public hearing for 1:30 p.m. Oct. 23 in Anchorage.

PTE has asked the commission to make a decision on its application by Nov. 30, so that construction can begin this winter.

$204 million project

Total cost to build the Point Thomson pipeline is estimated at $204 million, the commissioner’s analysis says. The annual operating cost is estimated at $26 million.
The design life of the pipeline is 30 years, which matches the length of the proposed right-of-way lease.

“A 30-year design life does not indicate that the pipeline and associated structures will be used up, failure-prone, or requiring replacement at the end of the lease,” the analysis says.

The state has high hopes that the pipeline and the development of the Point Thomson field will lead to an expansion of oil and gas activity across the remote eastern North Slope.

ExxonMobil initially plans to produce a modest 10,000 barrels a day of petroleum liquids from the Point Thomson field. But the common carrier pipeline will have the capacity to handle a much larger throughput — up to 70,000 barrels per day, which is “commensurate with full field development” at Point Thomson, the commissioner’s analysis says.

In building the pipeline, the state is “encouraging the applicant to fill jobs with residents, to the extent practical and possible.”

The pipeline construction workforce is expected to peak at 210 people, the analysis says.

PTE will lay the pipeline from ice roads over two upcoming winter construction seasons.

The pipeline will run roughly parallel to, and just inland from, the Beaufort Sea coast. It will traverse lonely state land, with no communities along the route. The local government, the North Slope Borough, supports the project.

The pipeline, 12 inches in diameter, will connect the main, or central, well pad at Point Thomson to the 12-inch, BP-owned Badami pipeline.

The Point Thomson line will be elevated 7 feet off the ground, mounted on 2,200 vertical support members along its 22-mile length. Elevating the line will allow caribou as well as snowmachines to pass underneath.

The pipeline will feature a “non-shiny exterior metal insulation wrap to minimize visual impacts,” the commissioner’s analysis says.

Part of the line also will feature a thicker steel wall to resist possible stray bullets from subsistence caribou hunters along the coast.

The proposed lease stipulates that pipeline employees and contractors will not be allowed to hunt, fish or trap within the right of way. However, PTE must give the general public access.

Awaiting federal permit

Before construction can begin on the Point Thomson development, ExxonMobil still needs a U.S. Army Corps of Engineers permit to fill wetlands.
The Corps has been considering the company’s application for the permit since late 2009, and had not yet made a decision as Petroleum News went to press.

ExxonMobil has promised the state it will begin production from Point Thomson by the winter of 2015-16. But to achieve that goal, the company says it needs the permit in time for construction to start this winter.

This initial Point Thomson development is a gas cycling project. Natural gas from wells will go to a central processing plant, which will separate out liquid hydrocarbons known as condensate. Dry gas will be injected back into the reservoir, with the condensate going into the Badami-bound pipeline. From there, the Point Thomson production will flow into the trans-Alaska oil pipeline.

In August, the Army Corps said it was aiming to render a “record of decision” by Sept. 21 on the wetlands permit. But the Corps cautioned that date wasn’t firm, saying the record of decision and permit “may not be complete until as late as Nov. 21.”
 
http://www.petroleumnews.com/pntruncate/925439681.shtml

Friday, September 28, 2012

Sullivan plays hardball; Alaska LNG most competitive he tells Asians; also pushing upstream investment

Kay Cashman
Petroleum News

Using a combination of “diplomacy” and “hardball advocacy” on his recent trip to Japan and South Korea, Dan Sullivan was not afraid to criticize Alaska’s competition in the LNG market, while touting the state’s geographic proximity, political and legal stability, and cost competitiveness.

“My goal was to get out in front of potential buyers and essentially say, ‘look we know you are going to need gas as you look to fill supplies over the next decade. When the producers — BP, ExxonMobil and ConocoPhillips — come to you with their portfolios … of projects across the globe … we want you to ask for Alaska gas, not just any gas,” the commissioner of the Alaska Department of Natural Resources told both Japanese and South Korean buyers of liquefied natural gas and their government officials, who are influential in contract decisions.

Sullivan spoke at the Sept. 19 LNG Producers-Consumers Conference in Tokyo. With about 1,000 attendees, it was the world’s largest gathering of senior government officials from LNG producing and consuming countries, as well as senior business executives from the largest LNG producers and buyers, his office said. In addition to numerous meetings with individual companies and government offices, the U.S. Embassy of Japan put together an event in which Sullivan gave a presentation on Alaska gas and mineral opportunities that 70 people attended.

As well as pushing the benefits of buying Alaska gas, Sullivan took advantage of LNG buyers’ interest in getting in on the drilling and production part of the business.

“The downstream is always looking to have a piece of the upstream,” he said.

“‘You want upstream investment potential,’ I said, ‘here’s our lease sale information. And, by the way … you might find a lot of oil, too. If you are interested, see me afterwards,’” he said during presentations.

Several companies asked for information.

“We sent out six or seven CDs today,” offering to follow up with “a lot more information,” as well as meeting with companies.

“We can send our DNR’s resource team to meet with them,” Sullivan said. “Bill Barron and his team have been traveling a lot to give people the details.”

While declining to name the companies that asked him for more information about Alaska’s oil and gas resource, he did say, “they were all very respectable Korean and Japanese companies,” upstream and downstream.

“It’s kind of tight if they are looking at bidding in the November lease sale, though.”

Sullivan said DNR has been “making the pitch” to invest in Alaska “all over the country, all over world” and not just for oil and gas. At the U.S. Embassy function in Japan, his presentation included Alaska’s strategic and critical minerals.

“We do this very regularly,” he said. “Sometimes it doesn’t lead to anything; sometimes it leads to follow up with more detailed briefings; some ultimately participate in a lease sale.”

Main emphasis was LNG

Still, the main focus of the trip was to promote Alaska gas.
“The biggest thing I emphasized was the competitiveness of Alaska LNG. … And I certainly was not adverse as to what I saw as shortfalls in other potential suppliers, Alaska’s competitors,” Sullivan told Petroleum News in a Sept. 25 interview.

“I took the gloves off with Kitimat,” he said referring to the proposed LNG export terminal in British Columbia.

“They haven’t touched their Native claims issue. It can take years to resolve. … Alaska’s First Nation and Native land claims issues have already been resolved.”

Another challenge for Kitimat, he said, is that it’s a shale gas resource.

“It will take hundreds, if not thousands, of wells to develop,” noting that Prudhoe Bay alone “reinjects 8 billion cubic feet of gas per day,” which is enough to meet Canada’s daily gas needs.

Alaska low on risk

“A lot of these proposed LNG export projects, such as Cheniere (Energy Partners) in Louisiana, do not have the advantages we do — there’s no resource risk with a North Slope LNG project. It’s conventional gas. With shale gas, you don’t always know where it’s coming from. … Your source of supply is locked down with an Alaska LNG project. Even the Qataris can’t do it,” Sullivan said, noting Alaska gas is not part of the hydraulic fracturing debate that could potentially shut down much of the shale gas production in the Lower 48 states.
Alaska gets kudos

Sullivan also talked about the progress the State of Alaska has made on gas commercialization, including LNG, noting there were two state-backed projects.
He emphasized the reliability of Alaska’s gas supply, pointing out that Alaska is the only state in the U.S. currently exporting LNG.

In the 40-plus years that the Kenai Peninsula facility has been exporting LNG to Asia, mainly Japan, it has never missed a shipment, Sullivan told the audiences he addressed and the people he met with.

To his delight, he wasn’t the only official who praised Alaska’s reliability.

In the Sept. 19 LNG Producers-Consumers Conference, Hiroshi Okuda, governor of Japan Bank for International Cooperation, and one of the “most prominent speakers on the Japanese side, highlighted Alaska,” Sullivan said.

“In that culture it was a big deal. Mr. Okuda, formerly chairman and CEO of Toyota … first highlighted the Qataris, who were there in force, because after the 2011 Fukushima nuclear disaster, Qatar stepped up to help Japan.”

Then Okuda praised the state of Alaska’s “strong record of reliability in really pioneering LNG trade,” the commissioner said. “The head of Tokyo Gas was not as effusive, but he also acknowledged Alaska.”

Later, when Sullivan was introduced, he “acknowledged both their kind words and then repeated them.”

What about price?

Although LNG pricing was a “hot topic” at the conference and elsewhere, Sullivan said he refused to engage in the debate.

Most LNG suppliers want to see the price they get for LNG continue to be tied to an oil index versus to lower natural gas prices.

For example, recently Mark Papa, top executive at EOG Resources, which has a 30 percent slice of Kitimat, said that “project is not going to go anywhere” until it gets “an oil index contract with a Far East buyer for a majority of the off-take,” calling the project “kind of a long putt.”

“It was certainly one of the Japanese …goals to start that conversation. … (But) I am not dipping into that debate,” Sullivan said, admitting it was a “pretty raging debate at the conference.”

What he would tell people was that Alaskans “are working on the most capital efficient competitive project possible. The details on all these price regimes in different parts of the world and how they are going to come together I did not focus on; I did not answer questions on that topic.”

Sullivan’s dialogue and supporting materials concentrated on the competitiveness of Alaska LNG, emphasizing the state’s reliability of supply, and pointing to the Brookings Institution’s 2012 policy brief that discussed the strong competitive position of a potential, large-scale Alaska LNG to Asia project, and Wood Mackenzie’s 2011 study for the State of Alaska that evaluated the economic competitiveness of Alaska LNG in comparison to other projects competing for the same customers.

Wood Mackenzie concluded Alaska LNG would be competitive and could generate between $220 and $419 billion, delivering a cost structure below $10 per million Btu. Most competing Australian projects and proposed North American LNG exports, it noted, had yet to secure final investment decisions and were expected to deliver LNG to Asia at a cost of $10-$12 per million Btu.

Paving the way for Parnell

Sullivan’s trip to Japan and South Korea, which began Sept. 17 and concluded Sept. 21, was partly paving the way for Alaska Gov. Sean Parnell’s visit to the same counties Sept. 24-Oct. 1.
Whereas the commissioner met mainly with company and government officials on his level — “deputy ministers, senior vice presidents, chief operating officers” — the governor would meet with fewer officials, but the “next level up,” Sullivan said.

Tuesday, September 25, 2012

The Permanent Fund relies on Big Oil









by First National Bank Alaska

A while back, when talking about who owns "Big Oil," we mentioned a 2011 study which found that 97 percent of corporate shares are held by public and private funds like 401(k)s, individual investors, asset management companies and the like.

What we didn't mention at the time was the Alaska Permanent Fund.

The annual royalty check received by most Alaskans every October is a beloved tradition, and has helped families pay for everything from college educations, to home remodels, to everyday basics like heating oil and fuel. But did you know that more than 20 percent of the Permanent Fund’s top 50 stock holdings is made up of oil and gas companies?

That's right. When these companies make money, Alaskans benefit from a good investment. Fostering a healthy, high-performing Permanent Fund is another reason why Alaskans have good reason to celebrate oil and gas companies’ solid financial performance.

For more information about the mutually beneficial relationship that Alaskans share with the Oil & Gas Industry, visit the Alaska Oil and Gas Association at http://www.aoga.org


Thursday, September 20, 2012

Exploration up; Plans call for 10-20 wells; higher number reliant on funding or weather

Kay Cashman
Petroleum News

The upcoming winter oil exploration drilling season on Alaska’s North Slope is shaping up to be busier than last winter, but with fewer companies involved — four versus six.

However, the total exploration well count during the coming short winter season will likely be higher — somewhere between 10 and 20 oil wells versus the seven that were completed last winter.

The companies planning exploration drilling onshore or nearshore on the North Slope during the coming winter exploration season are Repsol, Brooks Range Petroleum, Linc Energy and UltraStar Exploration.

One of the companies not drilling an exploration well this winter, Pioneer Natural Resources, plans to drill an appraisal well, the Nuna No. 2, based on last year’s successful drilling of the Nuna No. 1 exploration well, with the intention of shoring up the resource for a proposed Nuna development plan, which it will submit to Pioneer’s management committee. That committee will look at a number of factors, including well results and Alaska’s production tax take, before it decides to sanction Nuna.

Another dropout from last year’s winter exploration drilling, ConocoPhillips, recently announced an oil find at its Shark Tooth prospect on the fringe of the Kuparuk unit, which it drilled this past winter.

The company declined to offer details about the results of the Shark Tooth No. 1well, but a notice on its website says, “This area is being evaluated to assess further development potential.”

Another company, Brooks Range Petroleum, is moving forward this winter with development of a discovery at its Mustang prospect in its Southern Miluveach unit, adjacent to the Kuparuk River unit, that was confirmed with an exploration well last winter. Mustang is expected to be in production in early 2014, with peak production of 14,000 barrels of oil a day reached in 2016.

The company also plans at least one exploration well in its Tofkat unit.

Two other companies, Linc and UltraStar, did not drill last winter but plan to drill this winter.

Savant Alaska drilled an exploration well last winter, but appears to have no plans to do any exploration drilling this winter.

Under its Placer unit agreement with the state of Alaska, ASRC Exploration was expected to reprocess and reinterpret newly licensed seismic data shot across the unit by the end of the year, which it has done, and drill and log a new exploratory well, or re-enter and test the Placer No. 1 well, by June 30, 2013. But the company has submitted new unit paperwork, including a revised plan of operations, to the state’s Division of Oil and Gas.

According to division Director Bill Barron, “ASRC, as part of the application to expand the Placer unit, requested to amend the POE and defer the well obligation by one year, until June 30, 2014. The basis for the unit expansion application is the modeling and analysis of this seismic set.”

Division and ASRC staff were expected to meet Sept. 13 about the application.

Placer lies between the Kachemach and Southern Miluveach units.

Great Bear pulled from report

Excluded from the above well and company counts for both North Slope winter exploration seasons is Great Bear, the company that is pioneering the possibility of oil production on the North Slope using the hydraulic fracturing techniques in source rocks that have proved so successful elsewhere in North America. Unlike other North Slope onshore and near shore explorers, Great Bear is able to drill year-round because its first six proposed test wells are in an existing transportation corridor of the Dalton Highway and the trans-Alaska oil pipeline.

To date the company has drilled one vertical test hole and is in the process of drilling another, both spud this past summer and both reportedly yielding core samples from all three of northern Alaska’s source rocks, the Shublik, lower Kingak, and an assemblage called the Hue shale and HRZ or GRZ.

Once the first two vertical wells are finished, Great Bear has said it will immediately go back and do a lateral well at the first site.

Great Bear wants to complete the two vertical wells and two horizontal wells, and to drill another vertical well at a third site before the end of 2012, when it has to turn Nabors Drilling Rig 105AC over to Repsol for its winter drilling program.

Great Bear President Ed Duncan has not recently discussed the company’s plans for 2013 in great detail. But on July 31, in response to a question about near-term expectations, Duncan said the company could be producing hydrocarbons by the end of the year.

“We expect to be testing and producing and … selling produced hydrocarbons potentially by the end of the year, and certainly early next year,” Duncan said.

Sans Cook Inlet, Nenana basin, Chukchi and Beaufort wells

Also excluded from this North Slope winter exploration report are Southcentral Alaska’s Cook Inlet basin wells, the Nenana basin well Doyon hopes to drill in Interior Alaska, and Shell’s drilling in its federal Burger and Sivulliq prospects in the Chukchi and Beaufort seas, respectively. All of Shell’s holes will be completed during the Arctic Ocean’s open water season before the North Slope exploration season onshore and in nearshore state waters gets under way in the last half of December.

Brooks Range’s plans

“In regard to upcoming exploration, we plan a delineation well and one or two sidetrack(s) offsetting our Tofkat No.1 Kuparuk discovery close to the NPR-A boundary in the Tofkat unit. These wells will test Brookian 3D anomalies, confirm the size of our Kuparuk discovery and test the deeper Jurassic offsetting two high flow rate Jurassic wells in ConocoPhillips’ Nanuq field area,” Brooks Range told Petroleum News in a Sept. 13 email. The company was in negotiations for a drilling rig. Beechey Point unit drilling had been moved to winter 2014 per an extension from the state.

Telemark drilling was also deferred to 2014 “pending negotiations for a joint drilling agreement with Savant Alaska in the adjoining Badami unit,” Brooks Range said.

There is a possibility one or two exploration wells will be drilled in the company’s Kachemach unit.

“Decisions on proceeding … will be made in the next few months and will be based on working interest owners’ technical and capital budgeting priorities,” Brooks Range said.

Linc aims for 5 wells

Linc Energy (Alaska) plans to drill five wells at the Umiat field on the border of NPR-A this winter, using the Kuukpik No. 5 drill rig, including a disposal well. The other four wells are three vertical, two shallow and one deep, and a horizontal well in to the Lower Grandstand formation.

Repsol finishes last winter’s program

This winter Repsol will essentially complete the five-pad program it initially proposed for last winter.

Using three rigs (Nabors 105AC, 99AC, 9ES), the company plans to get at least one vertical well drilled at Qugruk 1, Q6 and Q3 ice pads. Q2, where last winter’s shallow gas kick occurred, has been renamed Q6 and given a slightly different bottom hole location.

Repsol expects to get a well test on Q1 and Q6, drilling a vertical and a horizontal hole on both, and testing the horizontals. Depending on how much time it has before the season closes, the company might try to sidetrack those locations.

At Q3 it hopes to get a vertical test well drilled in the upcoming season.

UltraStar looking at one well

Earlier this summer, UltraStar executive Jim Weeks was optimistic the Alaska-based independent would be able to drill the North Dewline No. 1 well in the first quarter 2013.

But a final decision is not yet available from the company.

Wednesday, September 19, 2012

Alaska Energy Dudes and Divas Circle of Influence

Received great feedback regarding Alaska Energy Dudes and Divas (DDs) yesterday from social media experts evaluating DDs circle of influence. The public is not utilizing traditional media as much for their news and information, and are participating in sharing with others to "help each other." DDs has found a niche, and is the place you go for energy issues. Especially, Alaska oil and gas issues.

Dudes and Divas:

  • "Deborah Brollini." is an authentic advocate for energy issues, and is a highly influential blogger, and "gifted" writer. However, Ms. Brollini prefers "storyteller."
  • 92% of "Nielson" participants trust "advocates," and are three times more trusted.
  • DDs has built an audience and built a successful brand
  • Ms. Brollini is not influenced by incentives (freebies), and not paid. DDs does have one sponsor Perkins Coie that has not presented undo influence on content, or Ms. Brollini. She has been given a great deal of freedom.
  • Ms. Brollini has build credibility by not being compensated. However, prefers "earned content."
  • DDs is an audience "connection" and used as a source for energy issues and a trusted a source
  • Ms. Brollini and DDs has a high level of influence, which has been demonstrated through content with value.
  • DDs has real influence which leads to relevant action. DDs inspires action by others to act or changes the audience's point of view, perception or emotion.
  • 49% of those online are searching for experts. DDs audience feels they have real access to energy experts, and feel they can interact with these experts through social channels.
  • The DDs team is an "expert" source which breathes credibility
  • Pictures and videos add credibility "videos are seen and therefore true," e.g. Thoughtful Thursdays, and the 1986: The year Alaska's economy crashed videos, and pictures are a great addition, and posts have gone viral.
  • DDs is organized and curated, easy to follow, uses graphs, and the writing is concise.
  • Ms. Brollini has spent a great deal of time developing authentic relationships with the public, media, and elected officials.
Ms. Brollini has a high circle of influence due to her personal advocacy efforts for energy issues, and has done a good job with branding and staying focused, keeping her political action group, and personal online activity separate from DDs. Thus, giving her credibility that is far reaching and credible.

Tuesday, September 18, 2012

Exploration up; Plans call for 10-20 wells; higher number reliant on funding or weather

Kay Cashman

Petroleum News

The upcoming winter oil exploration drilling season on Alaska’s North Slope is shaping up to be busier than last winter, but with fewer companies involved — four versus six.

However, the total exploration well count during the coming short winter season will likely be higher — somewhere between 10 and 20 oil wells versus the seven that were completed last winter.

The companies planning exploration drilling onshore or nearshore on the North Slope during the coming winter exploration season are Repsol, Brooks Range Petroleum, Linc Energy and UltraStar Exploration.

One of the companies not drilling an exploration well this winter, Pioneer Natural Resources, plans to drill an appraisal well, the Nuna No. 2, based on last year’s successful drilling of the Nuna No. 1 exploration well, with the intention of shoring up the resource for a proposed Nuna development plan, which it will submit to Pioneer’s management committee. That committee will look at a number of factors, including well results and Alaska’s production tax take, before it decides to sanction Nuna.

Another dropout from last year’s winter exploration drilling, ConocoPhillips, recently announced an oil find at its Shark Tooth prospect on the fringe of the Kuparuk unit, which it drilled this past winter.

The company declined to offer details about the results of the Shark Tooth No. 1well, but a notice on its website says, “This area is being evaluated to assess further development potential.”

Another company, Brooks Range Petroleum, is moving forward this winter with development of a discovery at its Mustang prospect in its Southern Miluveach unit, adjacent to the Kuparuk River unit, that was confirmed with an exploration well last winter. Mustang is expected to be in production in early 2014, with peak production of 14,000 barrels of oil a day reached in 2016.

The company also plans at least one exploration well in its Tofkat unit.

Two other companies, Linc and UltraStar, did not drill last winter but plan to drill this winter.

Savant Alaska drilled an exploration well last winter, but appears to have no plans to do any exploration drilling this winter.

Under its Placer unit agreement with the state of Alaska, ASRC Exploration was expected to reprocess and reinterpret newly licensed seismic data shot across the unit by the end of the year, which it has done, and drill and log a new exploratory well, or re-enter and test the Placer No. 1 well, by June 30, 2013. But the company has submitted new unit paperwork, including a revised plan of operations, to the state’s Division of Oil and Gas.

According to division Director Bill Barron, “ASRC, as part of the application to expand the Placer unit, requested to amend the POE and defer the well obligation by one year, until June 30, 2014. The basis for the unit expansion application is the modeling and analysis of this seismic set.”

Division and ASRC staff were expected to meet Sept. 13 about the application.

Placer lies between the Kachemach and Southern Miluveach units.

Great Bear pulled from report


Excluded from the above well and company counts for both North Slope winter exploration seasons is Great Bear, the company that is pioneering the possibility of oil production on the North Slope using the hydraulic fracturing techniques in source rocks that have proved so successful elsewhere in North America.

Unlike other North Slope onshore and near shore explorers, Great Bear is able to drill year-round because its first six proposed test wells are in an existing transportation corridor of the Dalton Highway and the trans-Alaska oil pipeline.

To date the company has drilled one vertical test hole and is in the process of drilling another, both spud this past summer and both reportedly yielding core samples from all three of northern Alaska’s source rocks, the Shublik, lower Kingak, and an assemblage called the Hue shale and HRZ or GRZ.

Once the first two vertical wells are finished, Great Bear has said it will immediately go back and do a lateral well at the first site.

Great Bear wants to complete the two vertical wells and two horizontal wells, and to drill another vertical well at a third site before the end of 2012, when it has to turn Nabors Drilling Rig 105AC over to Repsol for its winter drilling program.

Great Bear President Ed Duncan has not recently discussed the company’s plans for 2013 in great detail. But on July 31, in response to a question about near-term expectations, Duncan said the company could be producing hydrocarbons by the end of the year.

“We expect to be testing and producing and … selling produced hydrocarbons potentially by the end of the year, and certainly early next year,” Duncan said.

Sans Cook Inlet, Nenana basin, Chukchi and Beaufort wells

Also excluded from this North Slope winter exploration report are Southcentral Alaska’s Cook Inlet basin wells, the Nenana basin well Doyon hopes to drill in Interior Alaska, and Shell’s drilling in its federal Burger and Sivulliq prospects in the Chukchi and Beaufort seas, respectively. All of Shell’s holes will be completed during the Arctic Ocean’s open water season before the North Slope exploration season onshore and in nearshore state waters gets under way in the last half of December.

Brooks Range’s plans

“In regard to upcoming exploration, we plan a delineation well and one or two sidetrack(s) offsetting our Tofkat No.1 Kuparuk discovery close to the NPR-A boundary in the Tofkat unit. These wells will test Brookian 3D anomalies, confirm the size of our Kuparuk discovery and test the deeper Jurassic offsetting two high flow rate Jurassic wells in ConocoPhillips’ Nanuq field area,” Brooks Range told Petroleum News in a Sept. 13 email. The company was in negotiations for a drilling rig.

Beechey Point unit drilling had been moved to winter 2014 per an extension from the state.

Telemark drilling was also deferred to 2014 “pending negotiations for a joint drilling agreement with Savant Alaska in the adjoining Badami unit,” Brooks Range said.

There is a possibility one or two exploration wells will be drilled in the company’s Kachemach unit.

“Decisions on proceeding … will be made in the next few months and will be based on working interest owners’ technical and capital budgeting priorities,” Brooks Range said.

Linc aims for 5 wells

Linc Energy (Alaska) plans to drill five wells at the Umiat field on the border of NPR-A this winter, using the Kuukpik No. 5 drill rig, including a disposal well.

The other four wells are three vertical, two shallow and one deep, and a horizontal well in to the Lower Grandstand formation.

Repsol finishes last winter’s program This winter Repsol will essentially complete the five-pad program it initially proposed for last winter.

Using three rigs (Nabors 105AC, 99AC, 9ES), the company plans to get at least one vertical well drilled at Qugruk 1, Q6 and Q3 ice pads.

Q2, where last winter’s shallow gas kick occurred, has been renamed Q6 and given a slightly different bottom hole location.

Repsol expects to get a well test on Q1 and Q6, drilling a vertical and a horizontal hole on both, and testing the horizontals. Depending on how much time it has before the season closes, the company might try to sidetrack those locations.

At Q3 it hopes to get a vertical test well drilled in the upcoming season.

UltraStar looking at one well


Earlier this summer, UltraStar executive Jim Weeks was optimistic the Alaska-based independent would be able to drill the North Dewline No. 1 well in the first quarter 2013.

But a final decision is not yet available from the company.

Sunday, September 16, 2012

Alaska battles rep with resource industry

Tim Bradner
Alaska Journal of Commerce

Alaska is now attracting more interest from the world’s petroleum and minerals industries, Alaska Natural Resources Commissioner Dan Sullivan says.

However, the state still has a lingering reputation as a tough place to do business that is casting a long shadow, he said.

Sullivan spoke to business and community leaders in Anchorage Sept. 6 at the Resource Development Council’s first fall bi-weekly meeting of fall 2012.

“Alaska’s reputation still isn’t the greatest,” Sullivan said. “I believe this is ‘old thinking’ but the conventional wisdom is still that this is a difficult place to do business, to invest, to get permits, and that the government is hostile.”

Sullivan and other state officials are chipping away at the bad reputation but it’s slow going. What doesn’t help is that lot of Alaskans “are living a little in the past,” he said.

“As long as the pipeline was over 1 million barrels a day we didn’t have to hustle. But we’re in a different era now,” Sullivan said, with the oil in the Trans Alaska Pipeline System less than 600,000 barrels per day.

“We have the resource base but we now need to hustle,” he said. “Capital is going all over the world.”

Taxes come up a lot in the commissioner’s discussions with potential investors.

“We can only tell them we’re working on it,” Sullivan said.

Gov. Sean Parnell has proposed adjustments to the state’s oil production tax, which is among the highest in the world, but the proposals bogged down in the Legislature in 2011 and 2012 sessions.

Sullivan is on the road a lot, speaking at energy and minerals conferences and knocking on doors at corporate offices.

He was in Houston at the North America Prospect Expo, better known as NAPE, from Aug. 20 to Aug. 24.

On Sept. 19 he will be in Tokyo at the LNG Producer-Consumer Conference, a major event sponsored by Japan’s Ministry of Economy, Trade and Industry, or METI, and will also stop in South Korea for other gas-related meetings.

There was one positive development at the NAPE Houston conference. A major private equity investor, Tudor, Pickering & Holt, sponsored a luncheon focused on Alaska, giving Sullivan a stage to pitch the state to 60 potential investors.

In Tokyo, Sullivan will be able to test the waters before an expected Sept. 30 report by North Slope producers on a major Alaska LNG project, and also gauge reaction by Japanese companies to Russian President Vladimir Putin’s promise to develop a major LNG project at Vladivostok to supply Japan

Sullivan says his message is received with interest and that 50 percent of the “cold calls” he makes on corporate executives result in requests for more detailed information.

Inevitably, the negatives come up, though. Costs are high, taxes are high, lawsuits are many, and the regulatory environment is tough.

There’s not a lot the state can do about high costs in remote operating environments, and while progress is being made in streamlining state permit procedures, Alaska has to reinforce its message that environmental standards are high.

That is actually a positive, Sullivan said.

A lot of negative press comes with Shell’s long effort to get its Arctic offshore exploration approved by the federal government, which now appears to be happening.

But there is also the government’s apparent inability to complete its decision on the Point Thomson environmental impact statement for the multi-billion-dollar gas and condensate project. If that goes past mid-October, ExxonMobil will be unable to mobilize in time to start construction this winter. As many as 1,000 jobs could be created for Point Thomson construction this winter.

Sullivan said he and other state officials are making phone calls daily to get the Point Thomson EIS decision out in September, the original goal of the U.S. Army Corps of Engineers.

“Those guys are getting sick of my phone calls,” he said.

All that said, Alaska has some big selling points. The sheer size of the resource base is one, but there are others. For example, Alaska’s North Slope is the only place where a company can pursue a shale oil resource as well as a conventional oil resource.

“You won’t find 100-million-barrel conventional oil finds in the Bakken (N.D.) shale oil region, but you will here,” Sullivan told the RDC.

There are also actions by some major companies on the North Slope that haven’t been widely noticed, the commissioner said. One is ConocoPhillips’ acquisition of a large acreage position south of Point Thomson in a 2010 state lease sale, and Shell’s acquisition of state leases in near-shore submerged lands within the state’s three-mile offshore territorial limit, Sullivan said.

Results of the state’s December, 2011 area-wide lease sale were encouraging, too. The state received more than 300 bids from more than 15 bidders including companies new to Alaska like Repsol and Royale Energy, Sullivan said.

“It was one of the most successful sales in recent Alaska history,” he said.

Cook Inlet state lease sales have seen a steady increase in companies bidding and new firms entering the basin, with the 2011 lease sale particularly strong.

The next North Slope area-wide lease sale is set for Nov. 7 and, like last year, will be held in coordination with the U.S. Bureau of Land Management in offering National Petroleum Reserve-Alaska leases.

On the permitting and regulatory reform front, the state and the North Slope Borough recently signed a Memorandum of Understanding to coordinate permitting actions, Sullivan said. This will help remove any stumbling blocks between a developer having to get permits from state agencies as well as the borough, which is the regional municipal government for the North Slope.

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/September-Issue-3-2012/Alaska-battles-rep-with-resource-industry/#ixzz26hFKpSLB

Tuesday, September 11, 2012

ConocoPhillips finds oil at Shark Tooth well in Kuparuk

—Eric Lidji

Although details remain scarce, ConocoPhillips is reporting success from an appraisal well it drilled earlier this year in its Kuparuk River unit on Alaska’s North Slope.

The Shark Tooth No. 1 well “discovered hydrocarbons in the Kuparuk sands, in accordance with expectations, and confirmed mapped volumes,” the company said.

In January and February, ConocoPhillips used Doyon rig 141 to drill the “appraisal step-out well” from an ice pad in the southwestern portion of the Kuparuk River unit.

The company declined to offer further details about the results of the well, but in a notice on its website said, “This area is being evaluated to assess further development potential.

Prior to drilling the well, ConocoPhillips said Shark Tooth would “provide additional reservoir information in this area and narrow uncertainty around reservoir description parameters including oil-water contact, sand quality and thickness, and oil viscosity,” and was “critical for any future development of this part of the Kuparuk reservoir.”

Read more: http://www.petroleumnews.com/pntruncate/565744152.shtml

Saturday, September 8, 2012

Fire Island, Eva Creek set to begin producing wind power

Tim Bradner
Alaska Journal of Commerce

A rotor for one of the 12 wind turbines is moved into position at the Eva Creek wind project near Healy. The 25-megawatt project is set to begin producing power in October after an August ribbon-cutting.

A rotor for one of the 12 wind turbines is moved into position at the Eva Creek wind project near Healy. The 25-megawatt project is set to begin producing power in October after an August ribbon-cutting.

The new Fire Island 17.6 megawatt wind power project developed by Cook Inlet Region Inc. will be generating power in a week or two.

Commissioning of the 11 wind turbines on the island is expected to be completed by Sept. 8 or 9 and a 72-hour test of the facility is expected the week of Sept. 10.

“After that, the contractors turn the keys over to us,” CIRI spokesman Jim Jager said.

Meanwhile, a second wind power project will be supplying electricity to the Southcentral–Interior Alaska “railbelt” power grid in late October.

It is Golden Valley Electric Assoc.’s Eva Creek project, which has 12 turbines with a capacity of 25 megawatts.

Eva Creek is near Healy, between Anchorage and Fairbanks on the Parks Highway.

Fairbanks-based Golden Valley, the electric cooperative serving Interior Alaska, held a ribbon-cutting ceremony at Eva Creek with state and local officials in late August.

Golden Valley will use Eva Creek power in its own system, while CIRI will sell power from Fire Island to Chugach Electric Assoc.

Fire Island is in Cook Inlet just offshore from Ted Stevens Anchorage International Airport.

CIRI owns most of the land on Fire Island and developed the wind project with a first-phase cost of $65 million. The project was intended to be larger but was scaled back to 11 turbines in a first phase to allow for the variable wind power to be efficiently integrated into Chugach’s system.

The State of Alaska contributed $20 million to the project to pay for submarine cables connecting the island to the mainland, and for the connections to Chugach’s power grid. The total cost, including both the CIRI and state investment, is $85 million.

Golden Valley is developing Eva Creek for about $95 million, which includes $10 million contributed by the state to help pay for site access and other infrastructure. Golden Valley had to build a 10-mile road to the site from Mile Post 260 on the Parks Highway 14 miles north of Healy.

Eva Creek is coming on line at a good time for Golden Valley. The co-op is having to raise its rates 6 percent because of an 11 percent increase in fuel costs, mostly for oil and naphtha used at Golden Valley’s 120 Megawatt generating plant at North Pole, east of Fairbanks.

Wind power won’t result in lower rates but will help dampen possible future increases in oil costs, Golden Valley has said in the past. The Fairbanks utility has a goal of generating 20 percent of its power needs from renewable energy by 2014.

Eva Creek is expected to generate about 76,700 megawatt/hours of electricity annually, while Fire Island is expected to produce about 50,000 megawatt/hours per year.

Jager, of CIRI, said wind storms like Anchorage experienced the night of Sept. 4 are not really good for wind projects.

When wind speeds exceed 55 miles per hour, wind project operators must close the system down or the turbines can become destabilized and risk damage, he said.

“Our optimum wind speed for power generation is about 42 miles per hour. We can start making power at wind speeds of 7 to 9 miles per hour,” he said.

Wind speeds are expected to be strongest at the Fire Island site during December, which generally coincides with Chugach Electric’s winter peak demand for power

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/September-Issue-2-2012/Fire-Island-Eva-Creek-set-to-begin-producing-wind-power/#ixzz25tZc0ad0

Vitus bringing competition to Alaska


Tim Bradner
Alaska Journal of Commerce

Vitus Marine owners Mark Smith, seated, and Justin Charon are seen on Government Hill overlooking the Port of Anchorage and the eventual site of their planned site of 5-million gallon bulk fuel storage tanks at Port MacKenzie. Vitus gained fame this winter by arranging the fuel delivery to iced-in Nome and is now bringing competition to the Alaska fuel market.

Vitus Marine owners Mark Smith, seated, and Justin Charon are seen on Government Hill overlooking the Port of Anchorage and the eventual site of their planned site of 5-million gallon bulk fuel storage tanks at Port MacKenzie. Vitus gained fame this winter by arranging the fuel delivery to iced-in Nome and is now bringing competition to the Alaska fuel market.

The scrappy entrepreneurs who organized last winter’s emergency shipment of fuel through frozen seas to Nome are at it again.

Mark Smith and Justin Charon, who own and manage Vitus Marine along with Shaen Tartar, another partner, are busy delivering fuel this summer to remote western Alaska rural communities using new, technologically-advanced tug and barge units.

They are now also developing an independent 5 million-gallon bulk fuel storage plant at Port MacKenzie, the Matanuska-Susitna Borough’s port on Knik Arm across from Anchorage.

Site preparation is under way now and the company hopes to have construction of the facility begin next year.

The bulk storage plant, being done under an affiliate company, Central Alaska Energy, is intended to serve a niche market with specialized services, such as inventory management and fuel storage for customers, Smith and Charon said.

The large fuel operators could also be customers for Central Alaska Energy themselves, the two said.

Still, Central Alaska will be new blood in the Southcentral Alaska fuel business, and that’s just what’s needed, state officials who study the state’s energy situation have said.

Last January, Vitus Marine became briefly famous, thanks to intense international media coverage of the unprecedented shipment of fuel through sea ice assisted by the U.S. Coast Guard icebreaker Healy.

Bonanza Fuels in Nome had been caught short of fuel when a scheduled late season barge delivery was blocked by a Bering Sea storm.

Rather than fly the fuel in, which would have been prohibitively expensive, Bonanza turned to a new company, Vitus, for fresh ideas.

Smith and Charon are long-time veterans in the rural fuel and barge business, but their company, Vitus, was a new entity. Vitus had just started operation in the region last summer with two new tug and barge sets built under a long-term agreement with Alaska Village Electric Cooperative, or AVEC.

The solution for Nome is now well-known. Vitus arranged for a Russian tanker, the Renda, to deliver the badly needed fuel, and for the Healy to cut a path through the icepack in the Bering Sea and Norton Sound.

It all went off without a hitch. Nome got its fuel, and the Coast Guard got a chance to strut its stuff in the international media and, by the way, to remind Washington, D.C., that the nation has only one operating icebreaker, the Healy, which is really designed to support research and not break heavy ice for commercial shipping.

Two other U.S. icebreakers, which are heavier than the Healy, are laid up and only one is likely to be brought back into service.

Vitus’ business is delivering fuel, though.

The company got its start with the AVEC fuels contract and an agreement for the cooperative, which operates 53 small rural utilities, to finance the two tug-and-barge sets and buy fuel from Vitus on a multi-year contract.

“AVEC had been seeing year-over-year increases in fuel costs and its board asked for a long-range rate stabilization plan. We put together a proposal that would bring us in as new competition in the market,” Charon said.

Under the plan, AVEC financed and built the tugs and barges and leased them to Vitus as operator. AVEC remains as the owner, although Vitus may eventually purchase the equipment, Smith said.

The arrangement has precedents. Before Alaska became a state, the federally-owned Alaska Railroad, which historically operated steamboat service on the Yukon River and tributaries, built modern diesel-powered river towboats and leased them to Yutana Barge Lines. Crowley purchased Yutana, and now operates the Yukon barge service.

The tugs and barges were built in 2010 and delivered and went into service in western Alaska late 2011. One barge has a capacity of 8,000 barrels and the second a capacity of 10,000 barrels.

This year is the first full operating year for Vitus using the new equipment, Smith said, and so far things are going well for deliveries despite the usual glitches with weather and water depths in some rivers. Vitus has other customers in western Alaska besides its anchor customer, Smith said.

Meera Kohler, AVEC’s president, said, “It’s a little early to say exactly what the impact of receiving our fuel from Vitus has had on our delivered cost. I think our arrangement is saving us about 12 to 15 cents a gallon but I’ll be able to do a much more rigorous analysis when the year is closed out.”

What is unusual about the new tugs and barges is that they link together to effectively operate as a single unit, like a ship, Charon said. This has important advantages over the conventional tug and barge setup where the tug pulls and maneuvers the barge with towlines, which are metal cables or heavy rope.

This makes the combined units easier to maneuver when making beach deliveries in rough seas, where there are no docks, Smith said. The operation is also safer because it avoids the periodic breaking of towlines, which happens with the conventional setup. Breaks in lines and lash-backs of cables are a common source of injuries.

The tugs and barges, when linked, also have a speed advantage of about 20 percent over a conventional tug towing a barge, Smith said. The downside is that the units are typically more expensive than conventional equipment, he said.

Southcentral fuel storage

Meanwhile, the Central Alaska Energy venture involves the construction of six bulk storage tanks with a combined storage capacity of 5 million gallons. The company has a 5.5-acre lease at the site, so there is room for expansion.

“The advantage of the location compared with, for example, the Port of Anchorage is that the water depths at the dock are deeper, at 40 feet to 60 feet, compared with 40 feet and less at the Anchorage port,” Charon said.

There is also less of a siltation problem.

An expansion at Port MacKenzie would also not face the same kind of public opposition as has happened in Anchorage, where Government Hill residents overlooking the port worry about large quantities of fuel being stored at the base of the hill.

There is also some road and trucking distance advantage at Port MacKenzie for some customers, such as those in Interior Alaska who would be served via the Parks Highway.

The borough road to Port MacKenzie is gradually being improved. It is paved for half its length and the remaining gravel road is in excellent condition, Smith said. Still, it’s not the Parks Highway, he acknowledged.

If the planned Alaska Railroad link is built to Port MacKenzie it would improve access, he said. The rail bed is now under construction, but the Mat-Su Borough must still raise funds for the rails to be laid.

A principal advantage of the Central Alaska facility is its modest size, which means it can be efficiently served with small or large shipments. Vitus has looked at building bulk storage elsewhere such as in Seward, but the tanks would have to be large and the facility would be best served by large shipments. The ability to efficiently work with smaller shipments will give Central Alaska more flexibility to meet particular customers’ needs.

“We’ll be small, and will provide an alternative for people who want a different level of service,” Charon said. “For example, a customer could lease space in one of our tanks, providing a way to store fuel. For some customers, such as construction contractors, having the ability to ensure a supply of fuel at a known cost is important.”

Read more: http://www.alaskajournal.com/Alaska-Journal-of-Commerce/September-Issue-2-2012/Vitus-bringing-competition-to-Alaska/#ixzz25tR4M4CU

Friday, September 7, 2012

CH2M Hill's Tom Maloney speaks with the Political Insider team

Tom Maloney speaks about the 3,000+ employees working in their three core businesses; engineering consulting, construction, and operation and maintenance, and well support services. CH2M Hill is an oil services support company whose businesses are reliant on oil production activity. Increased oil production increases jobs on the North Slope, throughout the state and across the board. If you are looking for employment please see their career site.

In addition to CH2M Hill's North Slope business activity, CH2M Hill was chosen to oversee construction of an estimated $4 billion worth of sports venues, including an 80,000-seat stadium, and related infrastructure projects in preparation for the 2012 Olympic Games in London. Read more http://tinyurl.com/cwbj78x

Tom's interview starts at 33:00.


Commissioner Dan Sullivan Department of Natural Resources

DNR Commissioner Dan Sullivan speaks to the Resource Development Council. (Slides)

September 6 RDC Breakfast: Featuring Commissioner Dan Sullivan from Resource Development Council on Vimeo.

Sunday, September 2, 2012

Umiat reserves saga; Linc Energy refines reserve estimates in advance of winter exploration program

By Eric Lidji
For Petroleum News

Linc Energy Inc. has released third-party estimates of the reserve potential at its Umiat prospect and they show both a big increase and a small decline from previous figures.

The consulting firm Ryder Scott Co. LP estimates the undeveloped oil field in the Brooks Range foothills contains reserves of 154.5 million barrels of proved and probable (P2) oil equivalent and 194 million barrels of proved, probable and possible (P3) oil equivalent.

When the Australian independent Linc acquired Umiat last summer, it estimated the field held some 108 million barrels of P2 reserves and 201 million barrels of P3 reserves.

For the purposes of the reports, “probable” means at least a 50 percent chance of actual recovered volumes meeting or exceeding the P2 estimate, and “possible” means at least a 10 percent chance of actual recovered volumes meeting or exceeding the P3 estimate.

The Umiat field is generally believed to have around 1 billion barrels of oil in place.

This winter, Linc plans to drill as many as three vertical wells — two shallow and one deep — a horizontal well into the Lower Grandstand formation and a disposal well at Umiat. The company intends to bring the field into production within five to seven years.


‘Unpredictable’ Umiat


Even though it’s been decades since any drilling occurred in the region, Umiat reserve estimates have risen dramatically in recent years as technological advances have given companies increasing confidence in the amount of oil they can recover from the reservoir.
Umiat is the largest oil field the U.S. Navy discovered during its far-reaching exploration campaign across what is now known as the National Petroleum Reserve-Alaska, and because all 12 wells drilled at the prospect to date have been government efforts, the field carries a unique public record of reserve estimates over the 60 years since its discovery.

Between 1945 and 1952, the Navy drilled 11 wells at Umiat, discovering and delineating the prospect. From the start, researchers understood Umiat to have a unique reservoir.

“Behavior of the wells during testing was unpredictable,” U.S. Bureau of Mines petroleum engineer Oren C. Baptist wrote in a 1960 study of the formation. “For example, one well was abandoned as a dry hole after all tests failed to recover any oil, yet an offset well, only 200 feet from the dry hole, produced 400 barrels of oil a day.”

Geology presumably caused some this unpredictable performance. The Umiat reservoir is shallow, partially frozen in permafrost and low pressure, making production tricky.

But engineering played a role, too.

Baptist hypothesized that warm drilling mud had thawed the permafrost, allowing water to seep into the formation, freeze the sand and eventually plug the well. And for a long time, engineers debated whether rotary or cable tool drilling worked better at the tricky field.

Estimates and revisions


These challenges made it difficult to determine recoverable reserves.
At a meeting in June 1951, before the end of the initial drilling campaign, six groups presented different and wide ranging estimates of the recoverable reserves at Umiat.

Just within government agencies, the Navy estimated between 2 million and 17 million barrels while the U.S. Bureau of Mines estimated 151 million barrels. Upon request of the Navy, Union Oil Co. of California studied the available information and estimated 30 million barrels with an additional 10 million barrels possible from additional exploration.

The firm DeGolyer and MacNaughton estimated 57 million barrels and the firm Arctic Contractors offered an estimate between 64 million and 107 million barrels. The geologist Andrew Milek placed his recoverable reserves estimate at 85 million barrels.

In a June 1953 Navy-commissioned report, Arctic Contractors used those figures to put forth 70 million barrels as a “reasonable average estimate” of the recoverable oil reserves.

Within two years, though, the more bullish groups all revised their estimates down.

After incorporating reservoir information from an analysis of one of the later wells in the program, DeGolyer and MacNaughton dropped its estimate to between 18.8 million and 37.6 million barrels, but allowed for a slight bump if a shallower sand proved productive.

Using the same geologic assumptions, but a more optimistic recovery rate, Arctic Contractors dropped its estimate to between 51.6 million and 103.2 million barrels.

After also adjusting its calculations to incorporate information from later delineation wells, the Bureau of Mines cut its estimate down to 122 million. And after calculations suggested the reservoir might cover a smaller area than original thought, the Bureau of Mines considered revising its estimate further to 93 million. The smaller aerial extent would also have likely dropped the Milek estimate, to between 62 million and 75 million.

A ‘no-go’ for decades

Those figures had something in common: they didn’t justify development.
In addition to concerns about reservoir pressure and permafrost impacting recovery, even the most optimistic assessments could not overcome the remoteness of the prospect.

The field is considered far-flung today, and in the years before the discovery of Prudhoe Bay and the subsequent construction of the trans-Alaska oil pipeline, any oil field in northern Alaska needed to be large enough to support a pipeline to southern Alaska.

And so the 70 million barrel “reasonable average estimate” stayed around for decades, even after the Navy drilled the Seabee No. 1, deeper test well in the region, in 1979.

The Alaska Division of Oil and Gas used a similar figure in a 1997 evaluation of the petroleum potential of the eastern National Petroleum Reserve-Alaska, citing a 1993 U.S. Department of Energy analysis as it source. The U.S. Geological Survey estimated Umiat contained between 30 million to 100 million recoverable barrels, a range roughly bookending those earlier estimates.

Increasing optimism

With high oil prices, declining North Slope production and improved technology in the 2000s, though, interest in Umiat increased and reserve estimates increased as well.
The Colorado-based independent Arctic Falcon Exploration picked up the Umiat leases from a sister company in early 2001, but did not explore on its own. Through a series of deals, the Texas independents Renaissance Alaska LLC and Rutter and Wilbanks Corp. acquired Umiat leases and the three companies formed Renaissance Umiat LLC in 2007.

Around the same time, Anadarko Petroleum Corp. was conducting a geologic assessment of the Brooks Range foothills, a region where it was leasing more than 3 million acres.

Its assessment included the Umiat area.

“Reserves are questionable in that area, but we think there’s up to about 100 million barrels recoverable from Umiat,” Greg Hebertson, in corporate and strategic planning for Anadarko at the time, told Petroleum News in May 2002. Specifically, he noted how Umiat and other areas across the foothills had a “propensity for multiple structural traps.”

Renaissance staked 10 well locations before the winter of 2007 and 2008, but put drilling plans on hold because of weather issues and commissioned a seismic survey instead.

Following the survey, a subsequent assessment of field reserves by Ryder Scott Renaissance estimated that Umiat contained some 250 million barrels of economically recoverable (P3) oil in its main horizons. The large increase came from incorporating technological advances such as horizontal drilling, and modern secondary and enhanced oil recovery techniques, according to Jim Watt, then president and CEO of Renaissance.

After weather issues forced Linc to delay its drilling program last winter, the company spent an additional year processing and interpreting its seismic. Its newest assessment, also by Ryder Scott, estimates lower recoverable reserves in the P3 or best-case scenario than Renaissance, but higher recoverable reserves in the P2 or more likely scenario.

And with its program this winter, Linc is in a rare position: assessing Umiat by drilling.

Read more: http://www.petroleumnews.com/pntruncate/548320664.shtml