Thursday, June 30, 2011

Alyeska completes Low Flow Study

Alyeska has completed a comprehensive Low Flow Impact Study (LoFIS) on behalf of the TAPS owners. The study evaluated the potential risks associated with declining throughput and lower oil temperatures and identified mitigation measures.

“The Low Flow Impact Study is a critical step toward addressing the many challenges associated with declining throughput,” said Tom Barrett. “I want to thank Pat McDevitt and the study team for a job well done.”

“The study findings make it clear that the technical challenges compound and increase in complexity as throughput declines. The simplest, most direct and cost effective path to dealing with these challenges is to stop the decline by adding more oil.”

The LoFIS identified potential challenges with throughput levels between 600,000 and 300,000 barrels per day (BPD). Potential challenges include:

  • Water, present in oil as small droplets, is expected to separate out in a layer at the bottom of the pipe at 500,000 BPD and lower. Separated water will increase the potential for ice formation and corrosion.
  • Wax build up in the pipeline is present at current throughput levels and will continue to increase as throughput declines.
  • As throughput drops below 550,000 BPD, oil temperature will have the potential to drop below the freezing point of water and form ice in the pipeline during the winter months. Ice could damage pumps and equipment.
  • Crude oil temperatures at 350,000 BPD could allow soils surrounding buried sections of the pipeline to freeze, which would create the potential for ice lenses. Ice lenses could cause movement and damage the pipeline via frost heaves.

Mitigation measures recommended in the study include:

  • Minimize the impact of temperature decline by adding heat and insulation.
  • Modify the water and temperature specifications for crude oil entering TAPS.
  • Adjust the pipeline pigging program as throughput declines.

To see the complete study, click on the following link:

Alyeska Low Flow Study

Thursday, June 23, 2011

Yes, as an Alaskan you do have power

The one thing I most love about my state is her people. The beauty of Alaska is that we are family, and when one community hurts we all hurt, and we will do whatever it takes to help one another regardless of party. As Alaskans we also have total access to our Governor, and elected officials unlike other states.

I meet folks all the time who are baffled at my access to those in power. All Alaskans have the same access. These men, and women are making decisions about our future, and I am always surprised at the complacency of the public when so much is at stake. I would hope that Alaskans do not feel intimidated because they shouldn’t be. We should be holding all those in elected office accountable.

Alaska’s future is at stake, and the last thing this state needs is a public sitting by and hoping for the best. We had 547,853 barrels of oil travel down our pipeline on June 16, 2011, and the public seems unfazed, while Tom Barrett, President of Alyeska Pipeline Service Company begs for more oil.

There needs to be a huge educational effort to teach Alaskans about heavy oil, the importance of the Trans Alaska Pipeline (TAPS) to our state’s economy, and the life and safety issues to our citizens if there was to be another TAPS shutdown. There is plenty of blame to go around in regards to the complacency of Alaskans, and enough of the rhetoric already. We need to engage one another, and the public regarding issues of our economy, and not just at paid business luncheons, or commercials during session. Real public outreach like I did with the Alaska Native Tribal Health Consortium.

In 1986 Alaska’s economy crashed in 90 days, and it is up to Alaskans whether or not we repeat history.

Eric Bolling telling it like it is about the Obama Administration tapping the Strategic Petroleum Reserve

Monday, June 13, 2011

Silly Little White Bear

Momma bear abandoned baby polar bear and our oil service workers rescued her and she is growing up fast.

Read Jill Burke's story Video: Polar bear cub enjoying summer stay at Alaska Zoo

Saturday, June 11, 2011

Geothermal news heats up; Troubled Alaska electric co-op taps viable alternative power source, experts say

Wesley Loy, Petroleum News

A small Alaska electric cooperative’s quest to establish a geothermal energy source is finally generating some positive news.

GeothermEx, a subsidiary of oilfield services giant Schlumberger, has assessed Naknek Electric Association’s first well and concluded the utility is on its way toward a geothermal project that “can make economic sense.”

The GeothermEx memorandum was among papers NEA’s attorney filed June 2 in U.S. Bankruptcy Court in Anchorage.

The rural electric co-op, which serves the Bristol Bay area in Southwest Alaska, was forced to file for Chapter 11 protection from creditors in September 2010 due to cost overruns and other issues related to the geothermal drilling project.

The court papers indicate NEA still faces much work, and tens of millions of dollars in additional costs, to get a geothermal power plant up and running. But the co-op sounds determined to take on additional debt and achieve an alternative to burning expensive diesel to generate power.

NEA “believes it is in the interest of its members and creditors that it continue to pursue” a $50 million loan guaranty from the U.S. Department of Agriculture’s Rural Utilities Service, NEA’s court filing said.

The loan would “permit the repayment of geothermal development debt and development of two additional wells and a geothermal power plant.”

Difficult first well

The GeothermEx memo provides extensive detail on the troublesome drilling of NEA’s first exploratory geothermal well, known as G-1. The memo also presents “the justification for drilling well G-2.”
“Valuable lessons learned while drilling well G‐1 will be used to drill well G-2,” the memo says.

NEA serves the villages of Naknek, South Naknek and King Salmon in Southwest Alaska. Like many electric utilities in bush Alaska, it must haul in diesel to run its generators.

The co-op purchased a drilling rig for its geothermal campaign, and drilled the G-1 well in 2009 and 2010 at a site about seven miles northeast of King Salmon.

The well was planned for 14,000 feet but full depth was never reached.

After problems including the loss of several drill bit cutting heads in the hole at 11,218 feet, drillers bored a sidetrack to 11,387 feet.

However, rock formations in the sidetrack were unstable and sloughing blocked the hole, causing the drill string to become stuck repeatedly. To keep the hole open, a heavy drilling mud laden with barite was used. Barite is a dense mineral commonly used as a weighting agent for drilling fluids, according to Schlumberger’s online oilfield glossary.

Despite this, the string ultimately got stuck and couldn’t be freed, and the bit and part of the bottomhole assembly were left in the hole. After attempts to retrieve the equipment failed, a “fish” was left below 10,480 feet, making this the effective total depth of the G-1 well.

The decision to use the barite-rich drilling mud was unfortunate as it clogged the fractures, reducing permeability in the production interval, the GeothermEx memo says.

NEA was forced to bring in additional equipment to air-lift the well in an effort to clean out the barite.

Despite the drilling problems, the G-1 well showed hopeful signs.

The well can produce geothermal fluid at a temperature of 190 degrees, and possibly as high as 235 degrees.

At the lower temperature, the well has the potential to provide a net generation of about 325 kilowatts from each 1,000 gallons per minute of fluid produced, the GeothermEx memo says. At 230 degrees, the potential is about 550 kilowatts.

While a temperature of 230 degrees is “relatively modest compared to other geothermal developments worldwide,” NEA’s geothermal project “can make economic sense” considering the avoided cost of generating power with diesel fuel, the memo says.

NEA’s second geothermal well is expected to go deeper, to 12,000 feet, and seek a higher temperature zone than that found in the G-1 well, the GeothermEx memo says.

“Having learned valuable lessons while drilling its first geothermal well with its own drilling rig, NEA is well positioned to drill well G‐2,” the memo says. “The conductor casing has already been installed at the G‐2 well site, and many of the elements required for this well are already on site, including the rig, nearly all of the drilling ‘tangibles’ (wellhead, casing, etc.) and most of the cement needed to complete the well. NEA has developed a 92‐day drilling program, with the well costing an estimated $10 million.”

A “likely outcome” for NEA’s project is “a pilot development consisting of a geothermal well doublet, with G‐2 as the production well and G‐1 as the injection well.”

But whether further drilling and construction of a geothermal power plant will proceed remains an open question, judging from the June 2 bankruptcy filing.

Much apparently hinges on NEA receiving word by fall of whether the loan guaranty will be granted.


Republished with the permission of Petroleum News

Friday, June 10, 2011

Alaska could see another record in coal exports

Alaska could see another record in coal exports: "ANCHORAGE, Alaska - Industry insiders say Alaska could see another record year for coal exports.

The Alaska Journal of Commerce reports Usibelli Mine Inc., which produces coal near Healy, is con..."

Wednesday, June 8, 2011

Social Media Revolution 2011

Alaska Energy Dudes and Divas does know how to use social media!!

New Push to Reduce Energy Costs in Bush Community

Oil Patch Insider: The Nigerian Connection emerges again for Agrium plant at Kenai

Eric Lidji, Petroleum News

The strange saga of the Agrium nitrogen fertilizer plant keeps pointing to Nigeria.

The Dutch shipping company Fairstar Heavy Transport N.V. recently announced that it was awarded a $28-million contract to move the mothballed plant from Kenai, Alaska, to Ossiomo, Nigeria.

But Agrium said the plant hasn’t been sold yet.

Fairstar said it plans to use its two open stern, semi-submersible vessels — the Fjord and the Fjell — to move 111 modules and 70 containers from the plant starting this August.

Agrium mothballed the Kenai Peninsula plant in late 2007 because tightening natural gas supplies in Cook Inlet made it increasingly difficult for the plant to obtain feedstock.

“Fairstar has successfully arranged the first ‘door-to-door’ contract ever awarded to a marine heavy transport company,” Chris Muilwijk of Fairstar’s Client Services Group said in a prepared statement on the Norwegian Stock Exchange. “The complexity of this assignment gives Fairstar a unique opportunity to showcase not only the special features of Fjord and Fjell as two of the most versatile open stern semi-submersible vessels in the global fleet today, but also shows the value of the Fairstar Team as project managers.”

Despite the announcement, Agrium insisted that its plans for the plants remain uncertain.

“Agrium has yet to make a final decision on our Kenai operation,” Paul Poister, manager of U.S. government relations for Agrium, told Petroleum News on May 31.

Fairstar offered many details about the project, though.

The company said the ships would first transport the components by sea from Kenai to Koko, Nigeria, where they would then be shipped by land to a greenfield site in Ossiomo.

The $28 million contract only covers the marine transport. “The cost of land transport will be established once the tender process has completed and the winning sub-contractors have been selected,” Fairstar CEO Philip Adkins said in a prepared statement.

The Fjord and Fjell are currently transporting tugboats from Singapore to Venezuela.

Word about the Nigerian deal broke earlier this year, after Dave Harbour, a former Regulatory Commission of Alaska commissioner, posted a report from Heavy Lift & Project Forwarding International on his blog Northern Gas Pipelines. The report claimed that Fairstar “signed a Letter of Intent to provide a total land and marine logistics solution to transport 115 modules as well as related equipment from the Agrium Kenai Nitrogen Operations, comprising Plants 4, 5, and 6, from Kenai, Alaska to Ossiomo, Nigeria.”

Old hopes for revival

Although closed for more than three years, the Agrium fertilizer plant never died.
For months after the announcement, Agrium continued work on its long-standing Blue Sky project, studying the possibility of converting the plant to run on hydrogen generated from gasified coal, but ultimately decided in early 2008 that it wasn’t economic.

Hope remerged again when Enstar Natural Gas proposed a 500 million cubic foot per day “bullet line” from the natural gas fields in the foothills of the Brooks Range to the Southcentral transmission grid as a way to bolster declining supplies in the Cook Inlet.

Because of the scope of the project, Enstar said that having big industrial customers like Agrium would be essential for keeping the shipping rates low for smaller customers.

Agrium showed interest in the idea, but said it would need to happen quickly.

“The longer that facility just sits, the more difficult it is to restart,” Agrium spokeswoman Lisa Parker told Petroleum News in March 2008, adding that a serious proposal for an in-state natural gas pipeline would have to come forward within a few years to be feasible.

Those plans for a bullet line ultimately slowed, though.

This summer, more than three years later, the Alaska Gasline Development Corp. will present a report to the Alaska Legislature on the economics of an in-state gas pipeline, so that lawmakers can then decide whether to move ahead with the project.

Now, even if they do, it might be too late for Agrium.

The rise and fall and rise of North American LNG exports

These are interesting days for liquefied natural gas.
In late May, the U.S. Department of Energy gave Cheniere Energy Inc. permission to ship up to 2.2 billion cubic feet of LNG per day over 20 years from the Sabine Pass LNG Terminal, an import facility in Louisiana, to any country where U.S. trade is allowed.

Practically, exports won’t begin anytime soon. The Federal Energy Regulatory Commission must still weigh in, and Cheniere must finance, design and build an export operation at its import terminal. Symbolically, though, the news is a big deal.

Sabine Pass is the first LNG operation in the country to get an export license from the federal government since the Federal Power Commission gave Phillips Petroleum Co. and Marathon Oil Co. a 15-year license to export Cook Inlet LNG from Alaska in 1967.

The Sabine Pass project is seen as a sign that shale gas plays across the Lower 48 are completely upending the dynamics of natural gas production in the United States.

To prove that domestic needs wouldn’t be crimped by exports, Cheniere pointed to reports from the U.S. Energy Information Administration, the Potential Gas Committee, the Massachusetts Institute of Technology and the ARI Resource Report showing that shale development is increasing natural gas drilling, production and reserve estimates.

“The evidence does not show a present or likely future threat to energy security in relation to the adequacy of domestic natural gas supplies,” the DOE concluded.

Cheniere is hardly the only company looking to export LNG. In fact, the glut of natural gas on the market from shale development is creating a rush of export proposals.

In late April, Freeport LNG Development L.P. asked the DOE for permission to export up to 24 bcf of LNG over two years from its receiving terminal on Quintana Island, Texas. And in early May, Lake Charles Exports LLC — a jointly owned subsidiary of BG Group plc and Southern Union Co. — asked the DOE for permission to export up to 2 bcf per day over 25 years from an existing import terminal in Lake Charles, La.

And those are just the official requests. Other LNG operators, most notably Dominion Cove Point LNG in Maryland, are publicly mulling over the idea of exports. Meanwhile, drillers in western Canada increasingly believe the proposed Kitimat LNG export facility is the only way to develop remote shale plays like the Horn River and Montney basins.

So what does it all mean for Alaska?

All this is going on as LNG exports are winding down in Alaska.
While Cheniere is negotiating supply agreements overseas, ConocoPhillips and Marathon are preparing their final shipments to China and Japan before mothballing the Kenai LNG plant this fall because they could no longer secure contracts from Asia past April 2013.

Shale became a thorn in the side of Alaska in 2008, after geologists announced that the Marcellus Shale in Pennsylvania might be one of the largest natural gas fields in the world. The size of that thorn is up for debate, though. Optimists, including Gov. Sean Parnell, say that domestic natural gas will at most delay a natural gas pipeline from the North Slope. Pessimists believe that shale effectively killed the Alaska gas pipeline.

The Sabine Pass license, though, might actually bode well for Alaska.

While BP and ConocoPhillips recently threw up their hands after they couldn’t get enough customer commitments to justify Denali—The Alaska Gas Pipeline, a roughly $35 billion natural gas pipeline from the North Slope to Alberta, a TransCanada-ExxonMobil joint venture backed by the State of Alaska is required to seek FERC certification for its pipeline regardless of whether or not it gets shippers to commit.

And that project includes the possibility of exports, if shippers want it.

The supporters of that “all-Alaska pipeline” from the North Slope to Valdez have long had to answer charges that the federal government would never allow domestic energy supplies to be shipped overseas. Sabine Pass throws that assumption into question.

Even if the North Slope pipeline fails to take off, some policymakers in Alaska have expressed hope that an in-state pipeline could be used to restart the Kenai LNG facility.

And Alaska might even gain an advantage over the Lower 48.

The Sabine Pass application raised issues that didn’t sidetrack Cheniere but could grow as more companies seek to export LNG. Those include the environmental charges against shale gas and the possibility that sustained LNG exports would “link” the United States to the world, creating a global natural gas market as problematic as the global oil market.

For once, Alaska might benefit from being isolated.

Republished with the permission of the Petroleum News

Monday, June 6, 2011

Expo to host upbeat industry; Oil and gas event draws 500 exhibitors

Alaska and Alberta raised oil taxes in 2007. The oil industry packed up and left Alberta due the windfall profits tax they passed in law. Alberta initiated a competitiveness review of their oil tax regime, and they made the necessary changes to their oil tax structure, and Alberta is now experiencing an oil boom. Alberta continues to evaluate its oil tax structure for competitiveness.

Read more about how Alberta learned from their mistakes of passing a windfall profits taxes, and their road to economic recovery and prosperity.

Friday, June 3, 2011

My fight against ACES - Anchorage Press: News

My fight against ACES - Anchorage Press: News:

"My fight for Alaska began in 2009. I had already been uncomfortable with the direction Alaska was heading, and I knew it was Alaska's Clear and Equitable Share (ACES) tax regime that was the culprit of our state's economic downturn. I attended a luncheon...."