TAPS Shut Down Because of Leak

TAPS shut down at midnight Friday for replacement pipe installation
Anchorage (Platts)--
Alyeska Pipeline Service Company began a planned 36-hour shutdown of the Trans Alaska Pipeline System as expected overnight to install new piping at Pump Station 1, bypassing a section of damaged pipe that caused TAPS to shut down last Saturday. The shutdown began at 12:07 a.m. Alaska Standard Time (0907 GMT) Saturday. The company is installing 157 feet of 24-inch pipe that had been fabricated in Fairbanks and moved to the North Slope earlier in the week. Federal and state regulators had allowed TAPS to do a temporary restart Tuesday night so that warm crude oil moving in the line would keep critical systems functioning and prevent a freezeup in winter conditions. TAPS was carrying about 630,000 b/d of crude when it was shut Saturday.

Pump station leak shuts down TAPS

Pump station leak shuts down Trans Alaska Pipeline System

By CASEY GROVE

Published: January 8th, 2011 07:23 PM

The 800-mile trans-Alaska oil pipeline is shut down due to a leak at Pump Station 1 on the North Slope.

tool nameclose tool goes here North Slope oil producers have been asked to cut their production to 5 percent of normal.

An oil line encased in concrete leaked an unknown quantity of crude oil just outside a booster pump building, according to Alyeska Pipeline Service Co. spokeswoman Michelle Egan. Alyeska operates the line and its pump stations.

A crew doing a routine inspection noticed the leak this morning and Alyeska shut down the pipeline at about 9 a.m., Egan said.

"There's no visible oil on the tundra," Egan said. "We believe it's all inside that casing."

While Alyeska staff believe the leak is contained, Egan said, they wouldn't know for sure if it had escaped that concrete structure until crews had a chance to excavate around the pipe. Crews are working to determine how to fix the line and get the pipeline running, Egan said.

Alyeska is unsure when oil might start flowing, she said.

"We want to make sure that we aren't going to make the situation worse by restarting, so we're being very careful and methodical about that," Egan said.

BP is in the process of cutting off production at the fields it operates, said Steve Rinehart, Alaska spokesman for the oil company. It will take time for wells to be shut in and pipelines and other facilities to be freeze protected.

Normal production from the North Slope fields averages around 630,000 barrels a day of oil. A 5 percent production level would be about 31,500 barrels a day. The oil fields have limited storage capacity, and the production that occurs will go into storage while the trans-Alaska pipeline is shut off.

BP runs most of the oil fields on behalf of itself and the other leaseholders. Conoco Phillips and Pioneer Natural Resources also run fields. BP, Conoco and Exxon Mobil are the major producers on the North Slope.

Rinehart said it was unclear how long the pipeline shutdown would last.

The pipeline runs from the North Slope to a tanker port in Valdez. Pump Station 1 is at the beginning of the pipeline. Alyeska runs the pipeline for the five oil companies that own it: BP, Conoco, Exxon, Koch Industries and Chevron.

Deep-water drilling in the Gulf of Mexico could resume within weeks

Path Clears for Deep-Water Drilling

By BEN CASSELMAN And DANIEL GILBERT
Deep-water drilling in the Gulf of Mexico could resume within weeks under a policy announced Monday by the Obama administration, which has come under increasing criticism from the oil industry and politicians in the region over the impact of the drilling halt.

Oil and gas exploration in the Gulf's deep waters has been stopped since May, when President Barack Obama announced a six-month drilling moratorium in the wake of the April explosion of the Deepwater Horizon drilling rig, which killed 11 workers and set off the worst offshore oil spill in U.S. history.

The administration lifted the ban in October—a month ahead of schedule—but hasn't issued any permits for new deep water oil wells.

On Monday, The Wall Street Journal reported that the delay has hurt both the oil industry, which has seen billions of dollars in projects put on hold, and the Gulf Coast's economy, which has been hit hard by the slowdown.

The administration said Monday that it would clear the path for 13 companies, including Chevron Corp. and Royal Dutch Shell PLC, to resume work on a handful of wells that were already approved and under way when the moratorium took effect. The 16 projects must still comply with strict new safety rules announced after the Deepwater Horizon disaster, but in most cases won't be subjected to new environmental reviews.

The announcement means that some drilling could resume in a matter of weeks, although the exact timing remains unclear. But the policy doesn't affect the more than a dozen permit requests that were pending when the moratorium took effect or have been filed since. Those must still undergo enhanced environmental reviews.

GE Bets on Deep Water Oil With $1.3 Billion Wellstream Bid Access thousands of business sources not available on the free web. Learn More Michael Bromwich, director of the Bureau of Ocean Energy Management, Regulation and Enforcement, the newly formed federal agency in charge of offshore drilling, said projects that were interrupted by the moratorium deserved special consideration.

"For those companies that were in the midst of operations at the time of the deep-water suspensions, today's notification is a significant step toward resuming their permitted activity," Mr. Bromwich said in a statement.

Oil companies in recent weeks had become increasingly pessimistic about a quick resumption of drilling in 2011, with some predicting that the wait would last into the second half of the year. On Monday, the industry praised the decision but said more details were needed.

"It appears to be a step in the right direction," Randall Luthi, president of the National Ocean Industries Association, a trade group, said in an interview. However, he said, "there are still major questions and some confusion among the companies about what is being required."

Elgie Holstein, a staff expert for the Environmental Defense Fund, an environmental group, said he didn't see any reason for projects halted by the moratorium to be treated as special cases. But he said the new policy was reasonable as long as regulators enforced the new safety and environmental rules. "I actually thought it was a balanced response," Mr. Holstein said. "It does relieve some of the pressure that the Gulf Coast has been feeling from an economic standpoint."

The administration has come under increasing pressure from Republicans and some Gulf Coast Democrats to allow drilling to resume. On Monday, lawmakers reacted cautiously to the announcement. Sen. Mary Landrieu, a Louisiana Democrat who has been a vocal critic of the administration's drilling policy, said some projects could still be thwarted.

"We need to know more about the conditions under which drilling will be allowed to resume and make sure those conditions don't actually undermine the intent," Ms. Landrieu said in a statement.

Doc Hastings, the Washington Republican who is incoming chairman of the House Natural Resources Committee, was also skeptical.

"Today's announcement by BOEMRE only ensures the possibility that previous drilling activity can resume at some point in the future if certain requirements are met," Rep. Hastings said in a statement. "The Obama administration can prove it's serious about resuming drilling in the Gulf by actually issuing permits and allowing people to return to work."

—Siobhan Hughes and Tennille Tracy contributed to this article.

Ethanol Idiocy Will Not Die

When Al Gore drops an environmental fad, it has truly reached its expiration date.

By Rich Lowry

In his wisdom, the Goracle recently acknowledged what almost all disinterested observers concluded long ago: Ethanol is a fraud. It has no environmental benefits, and harmful side effects. The subsidies that support its use are an object lesson in the incorrigibility of Washington's gross special-interest politics. It is the monster that ate America's corn crop.

"It is not good policy to have these massive subsidies for first-generation ethanol," the former vice president and Noble Peace Prize recipient said, referring to corn-based ethanol. He called the fuel "a mistake," and confessed one reason he fell so hard for it is that he "had a certain fondness for the farmers in the state of Iowa." These farmers vote in the First in the Nation caucuses and practically insist that their favored presidential candidates drink ethanol at breakfast and hail it as the nectar of the gods.

Gore's ethanol apostasy is a symptom of a left-right coalition that has arisen to expose the former wonder fuel. (The Gore of old insisted that "the more we can make this home-grown fuel a successful, widely used product, the better off our farmers and our environment will be.") But common sense, even cross-ideological, bipartisan common sense with all the evidence on its side, is no match for Congress' boundless appetite for expensive favors for powerful lobbies and constituent groups.

Tom Harkin and Chuck Grassley, the Democratic and Republican senators from Iowa, stand at the doors of Congress declaring: Ethanol now, ethanol forever. They have graced the Obama-McConnell tax bargain with an extension of a tax credit for ethanol that costs about $6 billion a year, and with an extension of a tariff on ethanol imports. Ethanol is so uneconomical that Congress supports it three different ways -- with a mandate for its use, a tax credit to subsidize it and a tariff to keep out competitors. Rarely are so many levers of government used to prop up one woeful product.

During the last decade, ethanol enjoyed a good run as a notional part of the solution to global warming. Then, environmentalists began to realize it might actually increase greenhouse emissions. Ethanol releases less carbon dioxide per gallon than gasoline. Once the emissions necessary to convert land to corn production and then grow and process it are taken into account, though, ethanol doesn't look so green anymore.

So much corn -- about 40 percent of the US crop -- is feeding into the maw of government-created demand for the fuel that it could be increasing world-wide food prices. In short, in exchange for not reducing greenhouse emissions, ethanol reduces the availability of food to the poor.

The multiple layers of subsidization have their own perversity. Since there's already a mandate to blend ethanol into gasoline, the tax credit is giving away money for something that would happen anyway. Environmental groups say this pads the bottom line of Big Oil. Harry de Gorter of the free-market Cato Institute has a more complicated take -- the subsidy decreases the cost and therefore the price of gasoline, effectively subsidizing its consumption. Your Congress at work.

But who cares about the facts? Once we have fired up a vast machine that from cornfield to distilleries produces 38 million gallons of ethanol a day, it will be nearly impossible to turn it off. Too many people will have a vested interest in continuing the scam, and its supporters -- like Harkin and Grassley now -- will always argue that any change is too disruptive. We'll still be mandating ethanol long after the internal-combustion engine is obsolete.

The ethanol experience should counsel against blithely creating new government-supported industries on the basis of dubious promises of cost-free environmental benefits. Judging by the tax bargain, festooned with all manner of other green subsidies and credits, it's a lesson ignored. In Washington, the boondoggles may lose their luster, but they never die.

http://www.realclearpolitics.com/articles/2010/12/14/ethanol_idiocy_will_not_die_108241.html

Still hope for gas pipeline

Study for DNR suggests future L48 gas prices will support gas from North Slope

Alan Bailey

Petroleum News


Amid current speculation about the future of the Alaska oil and gas industry, as oil production from the North Slope slows down and exploration drilling comes to a near standstill, it has become popular to add what some view as fading hopes for a future North Slope gas line to a general list of woes.

For, as the burgeoning development of plentiful supplies of so-called shale gas in the Lower 48 has caused a paradigm shift in the North American gas market, the price of Lower 48 gas has plummeted to levels below the projected transportation rates on a gas line from the Arctic, perhaps rendering the gas line uneconomic.



Objective analysis

In the interests of taking a rational look at the prospects for future Lower 48 gas prices, to replace worry-driven conjecture by objective analysis, the Alaska Department of Natural Resources commissioned consulting firm Black & Veatch to prepare a report on the future of North American gas prices in the context of the new shale gas revolution.
And the Black & Veatch analysts have found that, although there are major uncertainties around future North American gas markets, it is likely that gas prices in Alberta, Canada, will climb to somewhere between $5 and $7 per thousand cubic feet by 2020, with prices continuing to climb thereafter. And with a possible fee of $3.50 per thousand cubic feet for treating North Slope gas and carrying it by pipeline to Alberta, those gas prices could make a North Slope gas line viable, Antony Scott, a commercial analyst with Alaska’s Division of Oil and Gas, told Petroleum News Nov. 22.

DNR wanted an authoritative set of data, against which to benchmark the gas line project and had obtained funding from the Alaska Legislature for the Black & Veatch study, said Mark Myers, Alaska Gasline Inducement Act coordinator.

“This is a very robust study,” Myers said. “It’s like no other study we’ve seen out there in the literature.”

And Scott emphasized that the study tried to be unbiased in its views of future gas markets and, if anything, had underestimated the future cost and pricing of shale gas.



Technical breakthrough

Shale gas technology involves the extraction of natural gas from the impervious rocks where gas forms, rather than using the conventional approach of drilling into porous and permeable reservoir rocks that have trapped gas as it bubbles through subsurface rock strata. The use of high-tech horizontal drilling techniques that allow a well bore to pass for long distances through a shale gas horizon, coupled with the use of water and chemicals to fracture the rock, thus releasing the gas from the rock lattice, have been key enabling technologies in shale gas development.
The coupling of technical breakthroughs in shale gas production with the realization that vast areas of gas shale underlie various regions of the United States and Canada has triggered the shale gas revolution and caused a massive uptick in estimates of North American natural gas resources.

However, despite much hype about shale gas, with implications of vast gas supplies at rock-bottom prices, shale gas development still only has about a 10-year track record, with most of that record relating to one shale unit, the Barnett shale in Texas, Scott explained.

“It’s really important to recognize that outside of the Barnett we’re in extremely early days of the shale gas story,” Scott said.

But, after assessing various natural gas scenarios, the Black & Veatch analysts have concluded that shale gas production would figure large in any future North American natural gas supply situation.

“No matter what, there’s an awful lot of shale gas that is going to be relatively inexpensive to produce,” Scott said.



Price impact

The arrival of shale gas in the North American gas market, converting tightening production from conventional gas fields to a growing gas glut, caused gas prices that had climbed to levels approaching $8 per thousand cubic feet by 2008 to suddenly collapse, dropping to below $4 currently.
And the import of liquefied natural gas into the Lower 48, thought just a few years ago to be an inevitable growth industry as domestic supplies of natural gas decline, has now been pushed into the background.

“If you look at the price environment … it becomes hard to tell a story in which LNG finds an attractive home in North America,” Scott said.

Key drivers behind Black & Veatch’s view of future Lower 48 natural gas markets are the assumptions that the now-known abundant supplies of North American natural gas, coupled with an environmental preference for the use of gas rather than coal as a fuel, will push up the use of natural gas for electricity generation. On the other hand, while there are major uncertainties regarding future gas demand levels, there are also major uncertainties in estimates of the future costs of developing new shale gas resources.

For example, the supply of water for shale fracturing and the subsequent treatment and disposal of water produced from gas wells has represented a fairly modest cost element in the development of the Barnett shale, but will likely become a major cost factor in the development of shale gas in other basins.



Inconsistent data

But inconsistencies in the way in which finding and development costs for shale gas are reported make it difficult to assess whether those costs are compatible with current gas price levels, and Black & Veatch thinks that current prices may be artificially low.
“Current market prices for natural gas in North America may not provide adequate return for full development of shale resources in North America,” the Black & Veatch report says. “Significant levels of current shale production appear to be driven by requirements to drill to maintain acreage positions.”

Published shale gas finding and development costs in the Lower 48 range from $2.06 to $2.35 per thousand cubic feet, but these numbers do not appear to include factors such as land lease costs and water costs. Estimated costs of $3.25 to $4.25 per thousand cubic feet in western Canadian basins are likely nearer the full cost, although there are differences between cost reporting rules in Canada and the United States, Black & Veatch says.

And an examination of the production history of the Barnett shale provides some revealing insights into possible future shale-gas cost trends.

Essentially, Barnett shale production has seen a series of significant technical breakthroughs, each of which has caused a sudden jump in gas production. But the rate of increase in production has dropped back sharply after each technology-induced spike. And, contrary to popular belief, the cost of finding and developing additional volumes of Barnett shale gas appears to have increased rather than decreased over time.



Rising cost

The explanation for this conundrum seems to lie in the production characteristics of shale gas resources. In essence, a shale gas well achieves high initial production rates as the fractured shale rapidly releases its gas content. But, with the rock being relatively impermeable, that initial production rate drops off quite rapidly, requiring increasing effort to stimulate existing wells and the drilling of new well bores to sustain overall production levels.
The result is a production cost profile that curves upwards as more and more of the gas resource is accessed, until a law of diminishing returns places an upper cap on the total volume of gas that can be viably extracted from a particular shale gas resource, the Black & Veatch analysts concluded.

Recognizing the importance of individually considering the unique characteristics of each shale gas basin, the Black & Veatch analysts applied the upward curving cost model to each of the various U.S. and western Canada basins, to assess future gas production costs in different basin scenarios. Estimated water costs factored high in the distinctions between the scenarios — potential situations ranged from unlimited water access and the disposal of untreated water down wells, as for a Barnett shale development, to limits on water supplies and the need for the treatment of produced water, as would be required for developments in the Marcellus shale in Pennsylvania.

Additional costs, all subject to significant uncertainty and regional variation, include land access and government taxes.



Rising demand

But future demand for natural gas in North America should support the anticipated gradual rise in shale gas costs.
Black & Veatch has its own Lower 48 gas demand forecast that assumes gas demand for electricity generation will rise at an annual rate of 3.2 percent, with greenhouse gas regulation tending to drive the replacement of coal-fired generating capacity by gas-fired power plants. In 2010 the Energy Information Administration, apparently barred from considering potential changes in government energy policies, came up with a lower growth rate of 0.5 percent, on the assumption that there would be no future restrictions on greenhouse gas emissions.

And although the Black & Veatch projection of total demand from all uses of gas through to 2035 also exceeds the equivalent EIA projection, the Black & Veatch projection is “within the fairway” of several independent gas demand forecasts, Scott said.

“Power generation demand is going to be a really big story,” he said. “It’s going to matter a lot.”

Then, when it comes to the interplay between gas costs, gas demand and gas prices, the actual level of gas demand and the actual finding and development costs would appear to be the likely dominant future drivers of gas prices. And Black & Veatch assembled low, medium and high gas price scenarios, using a standard North American gas model to project, for each scenario, likely annual gas prices at different market hubs, together with likely annual production volumes from each shale gas basin, through to 2040.



Price scenarios

The low-price scenario assumes the relatively low EIA projection of future gas demand, together with low water costs; low finding and development cost escalation, along the lines of conventional gas fields; and modest tax rates. The medium-price scenario uses Black & Veatch’s shale-gas cost escalation model, together with Black & Veatch’s projection of future gas demand. The high-price scenario adds in increased environmental restrictions over access to shale gas resources, somewhat higher tax rates and relatively high water costs.
The low-price and high-price scenarios projected into 2020 result in the $5 to $7 per thousand cubic feet price range that may come into play in Canada at around the time when completion of a North Slope pipeline could be in the offing.

“Except in very extreme events we believe the Alaska (gas line) project — given what we know about the tariff structure today, the cost of producing gas at Prudhoe and Point Thomson — it looks like it should work,” Myers said.

http://www.petroleumnews.com

Cap-and-trade will not pass this Congress

Ben Nelson: Cap-and-trade will not pass this Congress
By Michael O'Brien - 10/30/09 10:35 AM ET

A cap-and-trade bill to address climate change cannot pass the Congress this session, Sen. Ben Nelson (D-Neb.) claimed Friday.

Nelson, a centrist Democrat whose vote is key to leaders wielding its 60-vote majority in the Senate, said he and his constituents had not been sold on the cap-and-trade system proposed in House and Senate bills to address global warming.

"No," Nelson simply responded when asked if those cap-and-trade bills can pass through this Congress during an interview on CNBC.

"I haven't been able to sell that argument to my farmers, and I don't think they're going to buy it from anybody else," Nelson said. "I think at the end of the day, the people who turn the switch on at home will be disadvantaged."

The pessimistic assessment makes Nelson a thorn in the side of his party's leaders on climate change legislation, one of their top priorities, as they assiduously court his vote on another key proposal, healthcare reform.

On that issue, Nelson was reluctant to fully stand behind the Senate health bill as has currently been proposed, but said he is working to find a way to support the legislation.

"I don't know that we should conclude that some form of healthcare reform won't pass. I believe that some form will pass," he said. "I'm looking to find a way to vote for healthcare reform because we need it."



Source:
http://thehill.com/blogs/blog-briefing-room/news/65615-ben-nelson-cap-and-trade-will-not-pass-this-congress

Alaska Candidates: Oil is declining, so what do we do?

Tim Bradner
adn.com Economy


When the debate topic turns to state economic policy in the governor's race, the first thing out of the chute is usually petroleum policy and oil taxes, and what we can do to stimulate this industry, which many fear is declining.
Oil is vital to Alaska. Royalties and oil taxes pay for 90 percent of the state budget, the Department of Revenue says. Overall, the industry supports about a third of Alaska's economy directly and indirectly, according to University of Alaska studies.
However, the trends in this vital industry are headed the wrong way. Production is declining, employment is down and new exploration may hit a record low this year.
Don't think a gas pipeline will bail us out, either. State revenues generated by gas will be very modest compared with oil and a pipeline is 10 years away, if then.
What do our governor candidates say about this? Sean Parnell, the incumbent, talks about expanding targeted tax credits for field work. His major opponent, Ethan Berkowitz, talks about negotiation of special fiscal terms for new fields as a way of inducing development.
Both ideas have merit and both are done in Alaska today on a more modest scale, and with success. But neither packs the punch to really turn this industry around. The big problem, which no major party candidate will talk about, is that Alaska's oil taxes are just too high, period.
Retired state economist Roger Marks has authored a new paper showing that Alaska's marginal oil tax rate, in essence the tax rate on profits from new investment, can exceed 80 percent. Alaska now has the dubious distinction of having one of the heaviest tax rates among major oil producing regions of the world, Marks says.
With production, drilling and jobs declining, is this where we want to be? I want to hear some discussion from candidates that we may have overshot in 2007 when we did major surgery on the state oil tax law and adopted a very aggressive tax formula. Do our politicians have the stomach to admit they possibly made a mistake? The proof of this is in the declining production and drilling. Only Ralph Samuels, a candidate in the Republican governor's primary, had the guts to talk about this.
Some legislators raised this in Juneau earlier this year, State Rep. Craig Johnson among them. Most lawmakers weren't interested in taking the issue on, however.
It's not that political leaders are clueless. In fact, our state has adopted some very innovative incentives with very generous investment tax credits for exploration and special royalty terms for development that have brought new companies here, most recently Apache Oil.
These help, particularly for small independent companies, but the problem is that the high overall tax rate really dampens the economics of major exploration projects, the very high-cost, high-risk ventures aimed at making really big discoveries. These are the kind that can really turn things around.
When exploration managers model their risk/reward balance with a new exploration project, for example in a high-cost, remote area, they seek a balance between the small chance they could make a very profitable find and the high probability of failure. The high state tax on a profitable discovery skews this balance, in that if the company wins its gamble the state takes almost all the gain, as Roger Marks shows. The state's current drilling incentives help ease the risk a bit but not enough to overcome the disadvantage of the high tax rate.
We need more discussion of this. Gov. Parnell says he likes targeted investment tax credits because no credit occurs unless the investment is made. He worries that there is no guarantee investment dollars will follow if a general tax reduction is made. Parnell's challenger, Berkowitz, basically follows a similar safe strategy: Unless a company agrees to invest in a negotiated deal, no fiscal agreement occurs.
Again, nothing is wrong with these tried-and-true strategies but they're too cautious. We need something more daring to turn things around. The Legislature had real guts last session in offering up a radical incentive for new drilling in Cook Inlet, a state offer to pay most of the costs of the first three test wells drilled with a jack-up rig. As a result we now have new companies investing in the Inlet. We need something similar for the North Slope, our largest oil basis, and we should engage the discussion now.