Sunday, November 27, 2011

Rebirth in Cook Inlet? CIRI says more infrastructure needed; CIE calls access ‘progressivity’ of inlet

Kristen Nelson
Petroleum News

There is more oil and gas exploration and development activity in Cook Inlet currently than the basin has seen in many years.

The Resource Development Council heard two perspectives on this activity at its annual conference in Anchorage on Nov. 17. Both were focused on oil rather than natural gas.

Ethan Schutt, senior vice president of land and energy development for Cook Inlet Region Inc., said CIRI has been promoting Cook Inlet development since it was formed.

JR Wilcox, president of Cook Inlet Energy, which was formed and took over operations after Pacific Energy went bankrupt in 2009, focused on the last couple of years.

CIRI is a major landholder in Cook Inlet.

Schutt said CIRI has always been a proponent of Cook Inlet as an oil and gas basin and in the last four or five years has been “pushing hard to get people to pay attention to Cook Inlet.” He noted that with the exception of Escopeta-Furie, all the speakers on the RDC Cook Inlet panel were CIRI lessees in one form or another, “some major, some minor.”

One CIRI lessee missing from the panel was NordAq Energy, Schutt said, noting that NordAq had a significant gas discovery on CIRI leases on the west side of the Kenai National Wildlife Refuge.

Because of its subsurface holdings, he said, CIRI gets “an inside look at what’s going on in this basin.”

“And I think it can’t be overstated that this is a very important moment in time and it is the early phases of a renewed interest in oil and gas potential in this basin.”

He said the interest of Apache in “coming to this basin and shooting an enormous 3-D seismic program” is significant because of Apache’s size and in-house technology. Schutt said he believes that seismic shoot will result in new oil production in commercial volumes.

Value to state

Schutt said that in discussions of the distinctions between the North Slope and Cook Inlet, state revenues are often left out of the equation. He said much of the remaining oil potential on the North Slope is on federal acreage, so if projects can get permitted and into development it’s great for jobs and getting throughput into the trans-Alaska oil pipeline, “but it’s not as great for revenue into the state government coffers.”

“One of the places where this state government can see real potential for royalties and taxes from oil production is here in Cook Inlet because the oil potential in Cook Inlet is in state land,” Schutt said.

While there is much discussion of roads to resources on the North Slope, one thing that would really help drive down the cost of exploration and development on the west side of Cook Inlet is a road-to-resources road, he said.

“We can’t focus all of our efforts on prizes that are up on the North Slope and in the North Slope offshore when one of the things that would most benefit us here in Southcentral would be infrastructure supporting oil and gas development here,” Schutt said.

The other thing that’s needed in Cook Inlet is improved port facilities on the west side, up near Beluga and at West Forelands. Without port infrastructure and road access, it makes oil and gas exploration more difficult and more expensive, he said.

Unexplored potential

Cook Inlet is “an amazing basin that has, amazingly, a whole interval of geological potential that’s basically never been explored,” Schutt said.

Oil was found at relatively shallow depths during early exploration, so explorers didn’t go deep, he said.

“If you drill to bedrock in Cook Inlet you’re going to go through two or three zones of oil potential and there is a whole zone down at the bottom that has two or three exploration wells in the entire history of the basin.”

While Cook Inlet is described as an underexplored basin, people are talking about the number of wells that have been drilled. “If you consider that there’s a whole basement to that basin that has never, for practical purposes, been tested, it’s even that much more potential for oil and gas development,” he said.

The need for gas in Southcentral is well known, but Schutt said with recent discoveries, “we may actually have found the new reserves that over time will be developed to get us healthy. We may have actually turned that page in the book.”

“What we need here, to really get healthy, is more new oil discoveries,” Schutt said. Oil is needed to feed the refinery at Nikiski, he said.

He encouraged the resource development community to work with legislators to figure out “how do we make this basin more attractive until we actually get the reserves up and we get healthier again.”

He acknowledged that CIRI has a stake in this as a major land and resource owner, but said it is something that would benefit Southcentral residents and the Kenai Peninsula Borough.

Cook Inlet Energy

Cook Inlet Energy is a young company, about to celebrate its second anniversary “of actually operating anything,” said the company’s president, JR Wilcox. He said he and the company’s CEO, David Hall, had helped run the assets for Forest Oil and then for Pacific Energy.

2009 was pretty much the nadir for the inlet, Wilcox said, with the oil price crashing, the Redoubt volcano erupting and Pacific Energy going bankrupt.

When people told him it was too bad about Pacific Energy, but he could always get another job, Wilcox said he and Hall said, “no, no; we’re forming a new company; we’re going to get some money from somewhere,” hire people back and start things up again.

“Somehow that actually happened; it still really amazes me,” he said.

Production was shut down in September, he said, and by December Cook Inlet Energy had been approved as the successor operator, hired a staff, and “within about two weeks we had some production going.” Over the next four months they got production at West McArthur River up 400 percent from where it was when the field was shut in, he said.

(See part 2 of this story, in the Dec. 4 issue, for some specifics on Cook Inlet Energy’s work to date.)

Inlet not there yet

“There’s a lot of hustle in the inlet now; it couldn’t be more different than things were in 2009,” Wilcox said. The U.S. Geological Survey report of an additional 600 million barrels of oil and several trillion cubic feet of natural gas yet to be found is positive, he said, and there are a lot of new players, “bringing a lot of new capital, new expertise and new enthusiasm.” He noted Hilcorp, Apache, NordAq, Buccaneer, Escopeta, Linc and Armstrong.

“We’re starting to really see a critical mass of players of a variety of sizes focused on a variety of different things,” Wilcox said.

But, he said, Cook Inlet oil production is off 97 percent from peak production.

“So one shouldn’t mistake green shoots for a crop here,” he said.

“If things seem great in the inlet now that’s in part just because they’ve been so crummy for so long and what we see is a lot of potential and a lot of enthusiasm.”

But, Wilcox said, there’s also been a lot of potential and a lot of enthusiasm for exploration in the Arctic National Wildlife Refuge and for a gas pipeline from the North Slope to market for about 30 years.

“Potential and reality are sometimes a long way apart from one another and it’s going to take a lot of time, money and effort to turn this potential into reality.”

What’s needed in Cook Inlet?

Wilcox warned against a perception that Cook Inlet has recovered.

“That’s not the case. … I think we may have just stopped getting worse,” he said, comparing Cook Inlet to a patient who was critical and has been stabilized. There’s going to be a “lot of effort between that condition and when they’re ready to go out and play football again,” he said.

He said several things are needed in Cook Inlet, including legislation to ensure the preservation of marginal oil and gas production. Cook Inlet Energy believes House Bill 32 does that, he said.

And there are “real problems with access.”

“I think access is almost the progressivity of the Cook Inlet: It stands between a lot of potential prospects and what could be real projects,” Wilcox said.

One access issue is a requirement for ice roads, which are expensive, can’t be built every winter and don’t give you very long to get in and work when they can be built.

Gravel is prohibited except by exception, he said, and “if you don’t have gravel roads and pads it’s really hard to have an oil field.”

There is the Kenai National Wildlife Refuge on the east side and the Susitna Flats and Trading Bay state game refuges on the west side, and there hasn’t been much road and pad infrastructure added since they were established, Wilcox said.

Road access needed

Wilcox said the 28 miles linking Mat-Su to the Beluga-Tyonek area should be “the poster child” of the roads-to-resources program.

It’s a short road across state land in a permitted right of way and has “been on the books since the late ‘60s,” he said.

A road on the west side “would immediately lower the operating cost” for projects on the west side because you could then access the area by truck.

He said it can be more expensive to work on the west side of Cook Inlet than on the North Slope because there is a road to the North Slope, but none to the west side.

Wilcox also said that platform abandonment is an issue the state needs to address.

“There’s no clear abandonment standard and … we went through this with the Osprey platform when we assumed operatorship,” Wilcox said.

He predicted that Escopeta or Buccaneer would find the lack of clear abandonment standards a hurdle if they were to try to put in new platforms.

And he had a comment on the oil production tax fight: A lot of the discussion around House Bill 110 (the governor’s tax change bill) seems premised on the main point of an energy company being to pay taxes, he said.

Taxes are not what energy companies are for, Wilcox said.

“Better than taxes are that they create jobs and they create a dynamic economy. … But even more important than the jobs is the energy security; that’s why energy companies are here, is to provide energy.”

And he called on the Legislature and the administration to continue their support for revitalizing the inlet, to turn “this nascent recovery into a truly prosperous oil and gas picture.”

Republished with the permission of the Petroleum News

Thursday, November 24, 2011

Producers: bleak outlook without tax reform

Tim Bradner
Alaska Journal of Commerce

Major Alaska oil producers presented a pessimistic picture of the North Slope production outlook during presentations to the Resource Development Council’s annual conference in Anchorage Nov. 16.

But other companies, mostly independents, were more upbeat and are planning a surge of exploration drilling this winter. However, the state of Alaska is funding much of the exploration through incentives that pay for more than half the costs of a well, the explorers acknowledged.

Most of the exploration is near existing fields and if discoveries are made, the expected reserve additions are modest.

“We don’t expect to find any Prudhoe Bays,” said Bill Hardham, Alaska operations manager for Repsol.

Repsol will be the most active explorer on the North Slope this winter.

The large producing companies were downbeat, however.

Claire Fitzpatrick, BP’s chief financial officer for Alaska, said her company is expecting a 7 percent to 8 percent decline in annual production declines this year in the fields it operates, which amount to two-thirds of total Slope production, and warned that Trans-Alaska Pipeline System throughput could drop to the 550,000 barrels-per-day range this winter.

This is important because at that level, pipeline operating problems could occur, Fitzpatrick said. A study by Alyeska Pipeline Service Co. released earlier this year forecast increasing problems with water drop-out, wax build-up and freezing in cold weather when oil moving through the pipeline drops below 600,000 barrels per day.

Fitzpatrick’s message, and a similar one conveyed at the conference by Trond-Erik Johansen, ConocoPhillips’ Alaska president, was partly aimed at getting business and community leaders at the conference to lobby the state Legislature for a change in state production taxes.

Fitzpatrick said BP’s 2012 activity level in Alaska would be flat, with no growth in activities like drilling that add new production.

“We’re making significant investments in infrastructure and pipeline upgrades, but capital spending on activities that produce more oil, on drilling, pad expansions, debottlenecking and others, is on hold or significantly limited. If the economics in Alaska don’t improve they’ll remain on hold,” Fitzpatrick said.

There are potential projects that could add new Slope production, but a hefty state production tax pushes these projects below the economic threshold when added to problems of high costs on the North Slope, Fitzpatrick said.

“These are prospects that do not make economic sense in the current business climate in Alaska, prospects that will remain only possibilities unless Alaskans and the oil industry work together to make changes that will make these prospects commercially competitive,” she said.

ConocoPhillips’ Johansen said a perverse effect of the Alaska tax is that it depresses companies’ incentive to invest as oil prices rise, resulting in stagnant or even declining investment by major operating companies at higher oil prices.

That happens because of a formula in the tax law that ratchets up the tax rate at steep rate as oil prices rise.

In contrast, industry investment in the Lower 48 and elsewhere is booming. Even in countries like Norway, with high rates of tax, there is enough profit left for industry that new investments are being made, Johansen said.

Johansen said ConocoPhillips’ 2012 Alaska capital budget will be about the same as 2011 and 2010, in the range of $900 million.

Fitzpatrick said BP’s 2012 capital investment will decline from about $800 million to $700 million.

The bulk of BP’s spending will be on major facility and pipeline maintenance rather than activities that add new production, Fitzpatrick said. Johansen has said that 70 percent of his company’s annual capital investment is going to maintenance.

Fitzpatrick said she forecasts Slope production declining 25 percent by 2020, from the current average of about 600,000 barrels a day, unless the investment environment for new projects improves.

“The Alaska Department of Revenue forecasts a 13 percent decline over the same period, but 52 percent of that (the production in 2010) is from projects not now producing and which are still under evaluation,” Fitzpatrick said.

Given the reluctance of the major operators to make new development investments, a good share of the production the state assumes in its forecast will not appear, she said.

Gov. Sean Parnell has proposed adjustments to the tax law, but the governor’s bill is bogged down in the Legislature.

Lawmakers opposing Parnell’s bill point to an upsurge in planned North Slope exploration this winter as proof that the tax adjustment Parnell proposes isn’t needed.

Marilyn Crockett, executive director of the Alaska Oil and Gas Association, said it typically takes eight to 10 years to get new discoveries into production in northern Alaska.

“The reality we face is that our best prospects for new production and adding throughput to TAPS are within existing fields, but these are the kinds of investments being discouraged by the state tax law,” Crockett said.

Repsol’s manager, Hardham, said its aggressive exploration this year is motivated mainly by lease expiration dates on many tracts in a 500,000-acre position it bought into with Denver-based independent Armstrong Oil and Gas.

“If we make a discovery, we’ll want to have a conversation about the state tax rate,” Hardham said.

Repsol plans to have four to five rigs working on exploration this winter on the Slope, testing prospects north and south of the producing Kuparuk and Alpine fields. The company’s schedule has squeezed the supply of rigs available for exploration, which has created problems for other companies seeking to drill exploration wells.

Savant Resources, Brooks Range Petroleum and LincEnergy, all independents, have encountered difficulties getting rigs, according to industry sources.

Another explorer, Great Bear Petroleum, also encountered problems but its president, Ed Duncan, said the company has located a rig it can move to Alaska in time for testing a potential North Slope shale oil prospect in this upcoming winter season.

Resource Development Council presentations

ConocoPhillips: video | slides
BP: video | slides
Exxon: video | slides

Read more:

Wednesday, November 23, 2011

Gearing up for winter; Companies move forward on what could be bumper exploration season

Alan Bailey & Kay Cashman
Petroleum News

The snow has been falling and the ground freezing in Arctic Alaska, and the various companies planning exploration wells for the coming winter season are lining up for what looks like being one of the busiest ever exploration seasons on the North Slope. The annual freeze-up has yet to reach the point where Alaska Department of Natural Resources can open up state land for off-road travel, but the department said on Nov. 18 that it had been approving the pre-packing of ice roads for a number of projects in its western coastal area, and also for a winter road between the North Slope Haul Road and the lower foothills area.

Brooks Range pre-packing snow

At the Resource Development Council annual conference on Nov. 17, Bart Armfield, chief operating officer of Brooks Range Petroleum Corp., said that his company had just starting pre-packing snow for an ice road that will run from the southwest corner of the Kuparuk River unit to the company’s North Tarn No. 1 well. Brooks Range found oil when drilling this well last winter but it now plans to use the Nabors 7-ES rig to further deepen the well through the Kuparuk C zone and do some flow testing. The company also plans to drill two appraisal wells, the Mustang No. 1 and Mustang No. 2, with these wells and the North Tarn well all being in the newly formed Southern Miluveach unit. In anticipation of what the company calls its “Mustang development” in the unit, this winter the company will also explore for sources of gravel for future roads and pads, Armfield said.

Repsol has largest program

Spanish major Repsol YPF is running by far the biggest exploration program on the North Slope this winter — the company plans to use five drilling rigs at five locations in a partnership with Armstrong Oil & Gas and GMT Exploration Co., drilling multiple wells in their 494,211 acres of state lease holdings.

Repsol’s Alaska operations manager Bill Hardham told the RDC conference on Nov. 16 that his company has been extremely busy gearing up for its winter drilling and that the company will access its drill sites from a network of ice roads originating at the Palm and Meltwater fields.

Four of the drilling locations are in an area of the Colville River Delta where the company has applied for a new Qugruk unit, and the fifth location is called Kachemach, south of the Meltwater field.

Including sidetrack wells, Repsol is permitting a total of 15 wells and five pads, but Hardham anticipates completing about 12 wells, and carrying out two or three drill stem tests.

The company is leasing an office in Anchorage for the winter, as well as establishing a camp office in Deadhorse. And, given the intensity its exploration activity, Repsol has contracted with Alaska Airlines for two flights per week to the North Slope from Anchorage, Hardham said.

He said Repsol’s aggressive approach to exploring in its leases reflects the fact that the leases are set to expire within just six years, although establishing oil production in Alaska as part of the company’s worldwide portfolio is also very important.

According to State of Alaska records, 84 of the company’s leases expire in 2012, 2013 and 2014.

Five wells for Linc at Umiat

Australian independent Linc Energy plans to drill up to five wells in the undeveloped Umiat oil field, on the border of the National Petroleum Reserve-Alaska, to the south of the central North Slope, Corri Feige, Linc general manager for Alaska, told the RDC conference.

The company wants to conduct oil flow testing from three or four of the wells, to obtain data for a field development plan, she said. Permitting for this winter’s drilling is well under way.

Linc will also be installing air quality and weather monitoring equipment this winter, to obtain data needed for future air quality permits for oil production, she said.

The known oil resource at Umiat occurs at shallow depths — Linc also sees possibilities for finding additional oil and gas in deeper structures at Umiat and anticipates starting drilling into those horizons in 2012, Feige said.

Access to Umiat will be by a 90-mile snow-packed road from trans-Alaska pipeline pump station two on the Dalton Highway, she said.

On Nov. 21 Linc spokeswoman Colleen Richards told the Anchorage Chamber of Commerce that the company is still working on securing a rig for its drilling program.

Farther south in Alaska Linc is embarking on another program of exploration drilling, seeking locations for underground coal gasification developments in the company’s state exploration license acreage in the Healy area of the Alaska interior and in the Cook Inlet area. The company has started drilling its first test hole near Beluga on the west side of Cook Inlet and is acquiring some 2-D seismic data for its exploration program, Feige said. The company anticipates drilling four more underground coal gasification wells by the middle of 2012, she said.

Underground coal gasification involves using a controlled underground coal burn to generate synthetic gas for power generation, or for conversion to natural gas or other products.

Anadarko and Pioneer

Back in northern Alaska, Linc will co-locate a portion of its snow packed road to Umiat with a road that Anadarko Petroleum plans to build for access to its Chandler No. 1 gas well. Anadarko plans to conduct some rig-less testing of the Chandler well this winter.

North Slope producer Pioneer Natural Resource plans to drill two wells in its Nuna development on the eastern side of the Colville River, in the southern part of Pioneer’s recently expanded Oooguruk unit.

Savant working on rig deal

Savant Alaska wants to drill a new well on the crest of its Red Wolf prospect in the Badami unit but is still trying to obtain a drilling rig for this project.

In a Nov. 18 email Savant Vice President Greg Vigil told Petroleum News that he expected the drilling project to move ahead this winter and that Savant was currently working a rig deal.

The Red Wolf well will target the Kekiktuk formation, the formation that contains the oil reservoir for the Endicott field, west of Badami.

Rig less likely for UltraStar

UltraStar, a small independent Alaska explorer, has also been looking for a rig to drill the North Dewline No. 1 well, the second well in the Dewline unit, on the coast north of the Prudhoe Bay unit.

At the beginning of November the company notified Alaska’s Division of Oil and Gas that, owing to the lack of an available drilling rig, it was very likely that the company would have to defer its planned drilling into 2013, UltraStar Managing Member Jim Weeks told Petroleum News in a Nov. 20 email. However, the company asked the division to continue processing its permits in case a rig comes available at short notice, should another company change its plans.

Great Bear waiting on permits

Great Bear Petroleum, the company pioneering the possibility of source rock, shale oil development in Alaska, hopes to drill its first test wells on its North Slope acreage in the coming winter.

Ed Duncan, Great Bear’s president and COO, told Petroleum News Nov. 21 that he is considering several rig options, including the possibility of bringing a more modern rig from the Lower 48 that Great Bear thinks may be better suited for drilling in source rock plays; a rig that will have to be made Arctic ready.

Duncan said that he is not going to contract the use of a rig until he is certain of securing all of the permits he needs for his year-round exploration and evaluation program. Permitting is progressing well, he said.

The company has formed a joint venture with oilfield service company Halliburton, in which Halliburton will do some of the test drilling within a limited area of Great Bear’s leases.

Great Bear is permitting six wells on six gravel pads along the Dalton Highway, intending to run short tests on at least four wells before deciding to sanction a pilot plant. It will use a combination of rig mats and existing surface infrastructure at each site, Duncan said.

In Nov. 1 testimony to a special meeting of the Alaska Legislature’s House Resources Committee, Duncan said Halliburton and Great Bear each plans to drill as many as three vertical wells and a lateral from each of those wells.

Friday, November 18, 2011

Budgets flat, down; BP, ConocoPhillips say tax change needed to make projects competitive

Kristen Nelson
Petroleum News

That was the message the Resource Development Council’s annual conference heard Nov. 16 from BP Exploration (Alaska) and ConocoPhillips Alaska, operators of the major fields on Alaska’s North Slope.

Trond-Erik Johansen, president of Conoco Phillips Alaska, and Claire Fitzpatrick, chief financial officer for the Alaska region and senior vice president of BP Exploration (Alaska), both said that if the state wants more oil in the pipeline, it needs to change its tax structure.

And both said that while high oil prices make investment attractive in other oil provinces, they don’t plan additional investments in Alaska in 2012.

Johansen said that while ConocoPhillips’ figures haven’t been finalized for 2012, he expects the company’s capital budget to be flat, about the same it was in 2010 and 2011. He didn’t give figures, but according to the graph he used in his presentation, 2011 spending was up slightly from 2010, both in the $800 million range.

Fitzpatrick said that a year ago BP said it would invest about $800 million in capital in Alaska in 2011, but she expects “our final capital budget will be $700 million” for 2012.

ConocoPhillips’ view

Johansen said throughput in the trans-Alaska oil pipeline has dropped another 7 to 8 percent since November of 2010, while production in the Lower 48 has continued to go up. While Alaska used to be the top producer in the United States, it is now number three after the Gulf of Mexico and Texas — and, he said, it looks as though Alaska will soon drop below California. With production in North Dakota is climbing. Alaska could soon be in fifth or sixth place, he said.

Why isn’t Alaska production increasing?

The “easy oil” has been drilled, Johansen said. The sweet spots were drilled when the fields were developed. In the early days it took a very short time and cost very little money to drill wells.
“And when you put them on, they produced a lot of oil and gas,” Johansen said.

There is a lot of light oil left on the North Slope, he said, but “it’s not easily accessible” as it was in the past.

For one thing, while initial water production was low, 3 million barrels a day of water are now being produced.

“We’re more a water production company than an oil production company,” he said, and that water has to be managed: It’s re-injected and used for waterflood.

The other big problem, Johansen said, is the current production tax system, Alaska’s Clear and Equitable Share or ACES. ACES takes away the incentive to invest at high oil prices, he said.

Cost of wells up

Johansen illustrated relative drilling costs at fields operated by ConocoPhillips — Kuparuk, Tarn, West Sak and Alpine — because ConocoPhillips has the data for those fields.
Using inflation-adjusted figures, he said the early wells in Kuparuk, West Sak and Tarn, cost about $2 million to $4 million a well and took about 10 to 15 days to drill.

“Today it costs four times as much and it takes four times as long,” because wells are no longer vertical or near vertical, but now are horizontal.

“And the bad news is that those wells produce less. So we need more of them.”

ConocoPhillips is still spending a lot of money drilling wells, “but we get less and less oil.”

With the same amount of money and the same number of rigs, there is less production out of each well bore, he said.

“My point is we need to drill more wells. We need to have more people working on more wells. That also means it needs to make commercial sense to us,” Johansen said.

State take an issue

With the progressivity in ACES, the higher the oil price the less incentive there is to drill for challenged oil, he said, compared to other places where taxes and royalties are flat. In North Dakota, he said, taxes and royalties are 55 percent. “Right now it’s about 85 percent in Alaska.”
Other places in the world also have high taxes, but when the price of oil goes up, taxes and earnings rise together.

“We take the risk; we want a fair share of that reward for taking that risk and that’s not happening” in Alaska right now.

Johansen said the question is when Alaska will benefit.

With reduced oil taxes, “If you look at it from a very, very short-term perspective standpoint, the state would see less revenue in the short term.”

But what about the long term, “What about the next generation?” he asked.

If there are “improvements in the fiscal regime here, you will see more action. … You will see more drilling; you will see more projects. … That’s just the way capitalism works.”

He said the question is whether the discussion will be “around short-term gains or are we going to talk about the long-term future?”

BP: prospects exist

Fitzpatrick said BP’s planned activity on the North Slope over the next couple of years “won’t begin to offset” the 7-8 percent decline the company sees in the fields it operates, fields which account for about two-thirds of current North Slope production.
What the company currently plans to spend, she said, represents “maintenance, repair work that needs to get done and also development work that currently makes economic sense.”

But the possibilities that exist include prospects “that represent billions of dollars in new investment and billions of barrels of new oil, billions of dollars of new revenue to the state and permanent fund and thousands of long-term, well paying jobs.”

“But these are prospects that do not make economic sense in the current business climate in Alaska,” Fitzpatrick said, and “will remain merely possibilities unless Alaskans and the oil industry work together to make changes to make these possibilities commercially viable and competitive.”

BP’s current plans include continuing the heavy oil pilot that’s on line, “but we’ll not be investing in any further heavy or viscous development beyond some studies over the next couple of years.”

There will be “significant investments in infrastructure and pipeline upgrades,” but capital spending on activities that produce more oil, such as drilling and pad expansion, are “limited or on hold.”

Production down

Production has dropped more than 140,000 barrels per day since ACES passed, Fitzpatrick said.

The Department of Revenue’s spring forecast predicts a 13 percent decline in statewide production between 2011 and 2020, she said, but the department “was also clear that 52 percent of the forecast volume in 2020 was from projects under development or evaluation, including projects in existing producing fields.”

She said she didn’t know what the next Revenue forecast will show, but BP is showing steeper declines over that period than it was a year ago.

“We’re looking at something like a 25 percent decline between now and 2020,” Fitzpatrick said.

BP’s focus is on sustaining infrastructure, improving the efficiency of its activities “and doing strictly preliminary work to keep things on line that might be economic then under a different fiscal regime.”

Only two things are keeping BP from sustained decline over the next nine years: Liberty, “which is on federal land and not subject to ACES,” and efforts to extract as much oil as possible from existing fields.

But it’s still a 25 percent decline, she said.

A lot of possibilities

“I have a lot of possibilities; I don’t need to go exploring for them,” Fitzpatrick said.

Some of those have had enough work done on them that they are ready for consideration when the investment climate becomes more competitive, she said. Among those are I Pad development at Prudhoe Bay; western region development at Prudhoe; S pad expansion with low salinity water flooding; and Sag River reservoir development at Milne Point.

Fitzpatrick said if those had moved forward over the past four years, “that 25 percent decline that I see would be essentially flat over that timeframe.”

“BP and our partners are poised to invest billions of dollars in new projects,” she said, but those projects can’t compete.

“Alaska’s got major reserves already discovered, but it’s running out of investors willing to spend the billions of dollars necessary to actually make those projects into investment,” Fitzpatrick said.

Two things are required, she said: “New projects have to compete for investment capital and existing activities must generate cash.”

“In this environment, new projects can’t compete for investment; and current activities don’t generate the cash required to actually fund them,” Fitzpatrick said.

“Make the economics less favorable, we do less,” she said. “Make the economics more favorable, like the governor proposed and House Bill 110 would do, we respond accordingly: More investment, more production.”

Work on gas bullet line continues, officials say

By Tim Bradner
Alaska Journal of Commerce

Engineering and planning for a 24-inch natural gas pipeline from the North Slope to Southcentral Alaska by a state of Alaska corporation is continuing for now, despite new gas discoveries in Cook Inlet.

Escopeta Oil recently announced that it had discovered natural gas in Cook Inlet. Escopeta representatives told Anchorage Mayor Dan Sullivan’s Energy Task Force that the company would not be able to confirm proven natural gas reserves until next summer, said Dave Harbour, a spokesman for Alaska Gasline Development Corp., which is planning the 737-mile, 24-inch pipeline project.

Escopeta has estimated its discovery at about 1.4 tcf in recoverable resources, but further testing is needed.

Meanwhile, AGDC officials said work on the 24-inch pipeline from the Slope must continue if the project is to stay on schedule to meet Southcentral Alaska energy needs if Escopeta’s find doesn’t work out.

“The Legislature, with Governor (Sean) Parnell’s support, created the ADGC in 2010 to ensure that by the end of the decade Interior and Southcentral Alaska citizens have adequate supplies of natural gas at the lowest possible price. We remain dedicated to that mission,” Dan Fauske, CEO of the state corporation, said in a statement.

House Speaker Mike Chenault said it is important to continue support for the in-state gas pipeline as a fallback.

There is an estimated 35 tcf of gas that has been discovered on the North Slope. TransCanada Corp. and ExxonMobil Corp. are working on a proposed 48-inch pipeline from northern Alaska to Alberta, but the project appears to have bogged down following large new shale gas discoveries Outside.

Parnell recently asked North Slope producers and TransCanada to reconsider LNG exports from Alaska as an alternative, but whether that might happen is uncertain.

Fauske, of ADGC, has said previously that if a large-diameter pipeline is built from the Slope, the state’s 24-inch pipeline project would become a spur line off the larger pipeline. But if the big line continues to stall the state should be prepared to build the 24-inch line all the way to the Slope, he said.

The state pipeline corporation is now working on a federal Environmental Impact Statement for its project and in securing of a federal right-of-way, said Dave Haugen, project manager. The draft of the EIS is now expected in early spring. The schedule for the EIS has slipped. It had been expected in September.

A right-of-way across state lands has already been secured for the project, he said.

This winter AGDC’s technical group will be evaluating data gathered in the 2011 summer field program, and planning is also under way for the 2012 field program, Haugen said.

Much of the field work is focused on river crossings, including the Yukon and Tanana rivers, as well as at Atigun Pass in the Brooks Range, where there is constricted space because the existing trans-Alaska oil pipeline also uses the pass.

The Legislature has appropriated $44 million over the last two years to support work on the 24-inch pipeline. A state appropriation will be requested for continued work in 2013 but Parnell has not yet approved the amount, according to ADGC financial officer Joe Dubler.

The appropriation is expected to be part of the governor’s fiscal year 2013 budget request that will be released Dec. 15. The Legislature must approve the appropriation.

AGDC has previously said that it will need to spend about $400 million in engineering, planning and the acquisition of permits by the time the project is approved for construction.

Tim Bradner can be reached at Read more:

Monday, November 14, 2011

Winter’s here; utilities beef up Southcentral energy systems

Analysis by Tim Bradner
Alaska Journal of Commerce

Crews work on the new power plant in South Anchorage. The main building has three large boilers that will power a large steam turbine. The joint project between Chugach Electric and ML&P sprawls 40 acres and is due to be completed in 2012. It will feature three new GE LM6000-PF gas turbines that heat the boilers. Each can generate 46 megawatts of power that is then sent to one large steam turbine.

Crews work on the new power plant in South Anchorage. The main building has three large boilers that will power a large steam turbine. The joint project between Chugach Electric and ML&P sprawls 40 acres and is due to be completed in 2012. It will feature three new GE LM6000-PF gas turbines that heat the boilers. Each can generate 46 megawatts of power that is then sent to one large steam turbine.

There’s good news – possibly – about new natural gas discovered in Cook Inlet. But that wouldn’t be in production for two to three years, if Escopeta Oil’s find is proven after more tests and drilling.

Closer at hand, one sure bet is that a new gas storage facility near Kenai will be ready for use next year. It’s in construction now, and it will help the regional utilities insure against cold-weather interruptions in gas supply in 2012.

Likewise, the new Southcentral Power Plant and Fire Island wind projects will be on-line in 2012. Those will significantly reduce the draw on the Southcentral region’s dwindling gas reserves, regional utility managers told the Anchorage Chamber of Commerce Nov. 8 in a joint-briefing on the local energy situation.

The new Southcentral Power Plant will allow Chugach and ML&P to generate power with 25 percent less gas.

“At today’s gas prices the reduced fuel use will save our members $27 million in fuel-use charges in the first full year of the plant operation,” Chugach spokesman Phil Steyer told the Anchorage chamber.

The Fire Island wind project will also result in reduced gas use, about half a billion cubic feet a year, when it is on line in late 2011.

There’s still this winter, however. This year, for the first time, Southcentral Alaska will be without an operating liquefied natural gas plant in Nikiski, which in previous winters diverted gas to the region’s utilities during cold snaps.

Plant owner ConocoPhillips is continuing with plans to mothball the facility in December after making one more shipment of LNG to Asia in late November, according to company spokeswoman Natalie Lowman.

This creates a new uncertainty, one more complication in a delicate regional energy situation. The gas wells that now supply the LNG plant are still available but it’s not as easy to turn them on and off to meet a short-term gas needs for the utilities. When the LNG is operating, the manufacture of the liquefied gas could more easily be turned off, or at least down, and the gas diverted to the utilities.

Some good news for this winter, however, is that the regional utilities have made investments in additional gas compression to beef up the distribution system.

Owners of the Beluga gas field west of Anchorage are investing $90 million in new drilling and compression this year to ensure adequate deliveries of gas, said Jim Posey, general managers of Anchorage’s city-owned Municipal Light and Power, which owns a third of the Beluga field.

About $50 million of the $90 million being spent at Beluga is being invested in compression, and much of the remainder was spent in the drilling of a new production well, Posey said. Beluga field owners, ML&P among them, plan another $258 million in new compression and drilling over the next five years, he said.

The added compression available this winter is important because it will enable the Beluga producers to supply up to 100 million cubic feet a day of gas to customers, Posey said.

In recent years the deliverability of Beluga gas has dropped to 70 million and 80 million cubic feet a day. When it started up three decades ago Beluga was producing up to 200 million cubic feet a day.

Another development is that Enstar Natural Gas Co. has new compression available on its own system and also will have new gas available from independent producers, company spokesman John Sims said. Enstar’s president, Colleen Starring, had spoke to the chamber the previous week.

Enstar’s new suppliers include Anchor Point Energy, a subsidiary of Armstrong Oil and Gas, who will supply about 1.2 billion cubic feet per day, and Buccaneer Energy, who will supply about 1.3 billion cubic feet per day to Enstar in 2012. Enstar also buys gas from long-established Cook Inlet producers Marathon Oil, ConocoPhillips and Unocal, which is owned by Chevron.

Buccaneer and Cook Inlet Energy, which operates the West McArthur River and Redoubt Shoal fields on the west side of Cook Inlet, are also eligible to sell more gas to Enstar under the company’s auction-purchase system.

Armstrong Oil and Gas operates gas wells at the North Fork field east of Homer. Buccaneer Energy has one completed gas producing well near Kenai.

Chugach Electric Association spokesman Phil Steyer said Nov. 8 that if there is a gas supply glitch, the priority among the utilities is to preserve the pressure in Enstar’s gas system because if Enstar’s gas pressure falls below a certain point, the regulators in furnaces kick off and it’s a big problem to get all of them restarted.

Steyer said the electric utilities have options Enstar doesn’t have, like switching some power plants to diesel and purchasing power from Golden Valley Electric Association in Fairbanks.

Energy conservation among consumers and businesses would also be important, he said. The recent “Energy Watch” drill by the utilities and the municipality of Anchorage saw a 1 percent to 2 percent voluntary decrease in use of gas, and in real event the response would be higher, Steyer said.

ML&P’s Posey said voluntary cutbacks by commercial building owners in the Anchorage bowl would be important in a gas supply disruption. In meetings with building owners and managers Posey has urged them to develop an energy conservation strategy.

Joe Griffith, CEO of Matanuska Electric Association, said his utility has a substantial program to upgrade transmission and distribution lines in the MEA service area and is working on engineering and permitting for its own gas-fired power plant, which will be located at Eklutna, north of Anchorage.

This article appears in the AJOC November 13 2011 issue of Alaska Journal of Commerce

Read more:

Sunday, November 13, 2011

Zero to 90

Deborah Brollini

Most who can keep up with me know that I flew to Juneau in February for the Chamber fly-in, and turned the legislature upside down with my testimony to House Resources. Up to that point no one was telling the Alaskan story. I brought reality to the tax debate and a glimpse of what was yet to come for our state because I survived the crash of 1986.

After I returned from Juneau I parked myself at the Loussac Library, and began researching 1986 the year Alaska’s economy crashed. I was young and in my 20s and very busy doing all the things I should have been doing at my age. I was working full-time foreclosing on homes, going to college, and having fun. It was not until I returned from Juneau, and began researching 1986, did I even get how bad things really were, and started hunting down leaders from that time.

After a month of research I run to Joe Beedle, President of Northrim whom in 1986 was referred to as “the hatchet man” and asked him “did our economy crash in 90 days? “ I then go to Scott Hawkins who was an economist at the time who wrote for the Anchorage Times and ask him the same question. Unsatisfied with the answers because they concurred I go to Governor Bill Sheffield and ask him did our economy crash in 90 days? “Yes, Deborah I was there.” Our economy crashed in 90 days, and so what has Alaska learned?

Alaska’s economy crashed because oil prices dropped to $20 on January 1st 1986, and by April 1st 1986 it was over. Alaska got out of it because oil prices rose, and we had lots of oil in our pipeline. Today, Alaskans have a choice. Do we continue on this path, or do we think outside the box, and look at all options? Alaska has so many options and opportunities if we would just get out of our damn way, and everyone has a seat at the Alaska table…. are you in?

To those who think I’m a “shill” for big oil. Would it surprise you to know that I have received my paychecks from the healthcare industry for the past 10 years? This issue has always been about my children’s future. All have access to my research. I am currently writing a white paper about the year Alaska's economy crashed which is kind of turning into a book, and I am doing it at my own expense, and personal time, and all in the vain of Lyndsey and Van’s future. What are you doing for Alaska, and our state's future?

A source of uncertainty; USGS grapples with assessing the North Slope source rock oil potential

Alan Bailey
Petroleum News

With escalating interest in the potential to produce oil directly from source rocks on Alaska’s North Slope, the U.S. Geological Survey is in the process of conducting an assessment of shale oil resources in northern Alaska. The idea is to use whatever information is available about North Slope geology to estimate ranges of hydrocarbon volumes that might be recovered from the source rocks using the horizontal drilling and fracking techniques that have proven so successful in the Lower 48 states.

On Oct. 25 USGS held a meeting in Anchorage, Alaska, to share its approach to its assessment with Alaska geologists and other specialists, to obtain feedback and comments before determining its resource estimates. USGS anticipates proceeding with the assessment in November, with publication of the results likely in January or February, USGS geologist Dave Houseknecht told the meeting.

Assessment method

The USGS method of estimating the volumes of oil and gas that might be recovered directly from an oil source rock involves mapping the disposition of the source rock in the subsurface; estimating the area of source rock that each production well might be able to access; and estimating the total ultimate recovery of oil from each well. By then calculating the total number of wells needed to access the entire area of the source rock and multiplying the number of wells by the per-well ultimate oil recovery it is possible to estimate of the total quantity of oil that might be produced.
But because none of the numbers involved in the estimating procedure are ever completely certain, the scientists use statistical techniques to factor in the various uncertainties involved, eventually deriving a range of possible total oil volumes that may be recoverable.

Uncertainty arises, for example, from the fact that rock properties and the detailed history of the rocks are never completely uniform across an entire play area: Source rock oil plays have “sweet spots” where oil production is particularly prolific, while other areas may be much less productive. And a key to gaining insights into potential oil production in a source rock play is an understanding of the parameters that can identify where oil and gas can likely be produced and where the sweet spots may be located. Parameters include the brittleness of the rock and indicators of likely oil or gas generation.


Houseknecht told the audience at the Oct. 25 meeting that key challenges facing the North Slope assessment include the difficulty of mapping appropriate source rock parameters, given the scarcity of wells penetrating the rocks in areas where source rock oil development might occur. There is also the lack of a history of source rock oil production in the region — ultimate proof of the technical viability of source oil development will depend on drilling some successful production wells.
And, in the absence of any existing North Slope source rock oil development, the USGS assessment depends on identifying shale oil plays elsewhere that can be used as analogues for North Slope source rock plays. Oil productivity from analogues in the Lower 48, for example, can be used for guidance on possible productivity from North Slope source rocks with similar characteristics and geologic histories.

There are three major source rock systems on the North Slope: the late Triassic Shublik, the Jurassic lower Kingak, and an assemblage of rocks of Cretaceous age, including the Hue shale and HRZ or GRZ, within what is known as the Brookian sequence.

Most North Slope source rock oil interest is focused on the Shublik, which has an obvious analogue in the Eagle Ford shale, the rock formation at the center of successful oil shale development in Texas. Both the Shublik and the Eagle Ford have similar organic carbon contents and both are relatively brittle, thanks to an abundant presence of carbonate minerals — rock brittleness is an important factor in the hydraulic fracturing required to induce oil to flow from shale.

Thermal history

However, Houseknecht cautioned about some significant issues relating to the thermal history of North Slope source rocks, when compared with the Eagle Ford and with the Bakken formation, a prolific oil shale in North Dakota.
In a petroleum system such as that on the North Slope, an underground source rock has been heated, progressively passing through temperatures that first generate oil and then natural gas from organic material in the rock. There is a specific temperature window within which oil is generated and a higher temperature window within which gas forms.

As the temperature rises through the gas window, a point is reached at which oil, formed previously at lower temperatures, breaks down to form additional gas. That secondary gas generation from the “cracking” of oil typically leads to elevated fluid pressures within the source rocks, Houseknecht said. And in the Eagle Ford, for example, this “overpressure” from the cracking of oil has driven up the fluid pressure in the petroleum system and has become a factor in oil production, he said.

But, while the oil in the Eagle Ford and the Bakken has formed relatively recently in terms of geologic timescales, most geologists think that the oil in all of source rocks under the North Slope formed much earlier, with generation completed by 50 million to 60 million years ago, Houseknecht said. Thanks to the leakage of fluid from the rocks, the overpressure decays over time thus leading to the probability that overpressures within the North Slope rocks will tend to be lower than in their Lower 48 analogues, Houseknecht said. And the lower overpressures could impact oil production.

The concept that earlier overpressures have decayed seems to be borne out by pressure measurements within wells in the region, with abnormally high pressures limited to rocks in the southern, deeper part of the basin where rapid, deep burial, rather than hydrocarbon production, has likely caused overpressure development.

Thermal measurement

Houseknecht also expressed some caution over the way in which geologists normally assess the thermal history of rocks, and hence determine areas in which oil or gas may have been generated. The standard method of assessing rock temperature histories is the measurement of the reflectivity of vitrinite, a coal component commonly found in rocks containing organic material. According to conventional wisdom, very specific vitrinite reflectance values indicate whether a rock has been heated into the oil or gas generation window. Geologists use the mapping of vitrinite reflectance values from rock samples to delineate areas thought to be prospective for oil or gas, with this technique being used on the North Slope as one of the ways to map potential source rock oil plays.

But recent research has indicated that the vitrinite reflectance boundaries for oil and gas generation are much less clear cut than previously thought, with the reflectance thresholds sometimes varying from one rock formation to another, Houseknecht said. That raises questions over the reliability with which it possible to map areas on the North Slope likely to be conducive for oil or gas generation, especially given the small number of wells penetrating source rocks outside the area of the North Slope oil fields.

Rock variability

Another area of uncertainty when assessing the Shublik is the high level of variability in rock type within the formation. The Shublik consists of various different rock units containing different amounts of materials such as sand, silt and carbonate minerals, University of Alaska Fairbanks scientist Mike Whalen told the Anchorage meeting. And there are three distinct sequences of rock within the Shublik, with the organic carbon content that could generate oil or gas varying from being particularly high in one sequence to being moderate or low in others. The organic carbon content tends to be concentrated into fairly thin rock units, Whalen said.

And depending on exactly which parameters are used to assess the areas of the Shublik likely to have produced oil or gas, the total area of the source rock oil play could range anywhere from 3.7 million to 9.3 million acres for oil, and from 14.9 million acres to 23.6 million acres for gas, Houseknecht said.

The area of a potential source rock play in the Brookian source rocks appears to be smaller than that of the Shublik, but with the Brookian showing overall more potential for oil than for gas. But the rocks in the Brookian do not appear as suitable for hydraulic fracturing as those in the Shublik, thus raising questions over the likely effectiveness of Brookian source oil production. The other North Slope source rock, the lower Kingak, appears to be especially problematic as a target for hydraulic fracturing, since it contains much fairly ductile clay material, Houseknecht said.
Republshed with the permission of Petroleum News

Sunday, November 6, 2011

CIRI drilling confirms coal seams suitable for UCG; seismic planned

Alan Bailey
Petroleum News

After an exploration program involving the drilling of 13 core holes, Cook Inlet Region Inc. has confirmed the existence of a significant coal resource likely to be suitable for underground gasification in the corporation’s land on the west side of Alaska’s Cook Inlet.

“We’ve done a significant amount of exploration work,” Ethan Schutt, CIRI senior vice president for land and energy development, told the Alaska Senate Resources Committee on Oct. 20. “Through that work we’ve confirmed that we have a significant commercial coal resource in a geological setting that is favorable for UCG (underground coal gasification) development.”

CIRI land

Stone Horn Ridge LLC, a joint venture between CIRI and Laurus Energy, is investigating the potential UCG development at a site called Stone Horn Ridge, northeast of the Beluga River, in an area where CIRI owns both the surface and subsurface land. Laurus Energy is a Houston-based affiliate of Ergo Exergy, a UCG technology company based in Montreal, Canada.
UCG involves the pumping of compressed air through a well into a coal seam deep underground to enable the controlled underground combustion of some coal; the heat from the burn converts excess air and the bulk of the coal to synthetic gas for delivery to the surface through production wells. It would be possible to burn the synthetic gas for power generation or to convert it to methane, the prime ingredient of natural gas. Other potential applications include the production of jet fuel by a gas-to-liquids process, or the production of fertilizer.

And, since the coal is processed deep underground, the UCG process eliminates much of the environmental impact of conventional coal mining and burning.

“We believe that UCG is a technology by which you can access this world-class energy resource in an environmentally acceptable manner,” Schutt said.

Schutt also assured the legislators that the underground burn required for the UCG process could be stopped very easily by closing off the flow of air required for combustion.

Multiple coal seams

Schutt said that the Stone Horn Ridge joint venture has found multiple, thick coal seams at depths below 650 feet in the Stone Horn Ridge area. The geologic setting of the coal appears favorable for the development of a UCG plant, although the joint venture is still in the process of collecting data and modeling the geology of the project site, he said.
The 13 core holes drilled for the exploration phase of the project penetrated depths ranging from about 700 feet to about 2,600 feet — the project team collected rock core and wireline data from the holes. Field and laboratory examination of rock samples; logging of the drilling mud; and field tests of the desorption of gas from coal samples also added to the data from the project site. That data have enabled the construction of a comprehensive computer-based geologic model of the site that has provided a preliminary validation of the existence of a commercial UCG resource.

The next step will be to carry out a high-resolution shallow seismic survey, gathering eight line-miles of data along three lines over a period of about 25-30 days.

“With that data we’ll complete our preliminary model of the site, incorporating that with the data that we already have, and that will help us move to the next phase of the program, which is the (resource) characterization phase,” Schutt said.

Conceptual engineering

The joint venture has already commissioned and obtained a conceptual engineering and cost analysis for a UCG development at Stone Horn Ridge, with the analysis considering various options for the use of UCG-generated synthetic gas, Schutt said.
The geologic modeling indicates the existence of about 300 million tons of coal in the Stone Horn Ridge site, a UCG resource equivalent to perhaps a little more than 4.8 trillion cubic feet of natural gas, with potential gas production rates in the range of 20 billion to 90 billion cubic feet per year, Schutt said.

And CIRI thinks that UCG-fueled electricity generation, for example, would prove significantly cheaper than generation from Cook Inlet basin natural gas, Schutt said.

But, with the project being at the leading edge of UCG technology deployment, CIRI is taking its time, being “pretty deliberate and responsible” and talking to stakeholders as the project moves forward, Schutt said.

“We’re pretty excited about the project and its potential, but we do also realize that we’ve got a lot of work in front of us,” he said.

Republished with the permission of the Petroleum News

Pump station plumbing; Alyeska to spend millions to reconfigure piping as safeguard against corrosion

Wesley Loy
For Petroleum News

The operator of the trans-Alaska oil pipeline is embarking on an expensive, three-year program to replace piping in several pump stations.

The work stems from a settlement Alyeska Pipeline Service Co. reached with federal regulators following a corrosion-caused oil spill in January at Pump Station 1 on the North Slope. The leak forced a lengthy shutdown of the pipeline.

Alyeska has told the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration it has completed a risk assessment of pump station piping that’s subject to corrosion and difficult to inspect. It was piping of this sort that leaked at Pump Station 1.

As a result of the assessment, Alyeska is designing plans for work at pump stations 1, 3, 4, 5 and 9.

“These designs will replace buried non-inspectable crude oil piping with piping in an above ground alignment,” says a summary document Alyeska provided at the request of Petroleum News.

Costly campaign

The piping replacement work actually consists of several major projects, each to cost “tens of millions of dollars to complete,” said Alyeska spokeswoman Michelle Egan.
Firms under existing contracts will handle part of the work, with some jobs to be put out for bid, Egan said.

The piping to be replaced is characterized as “dead leg, low and intermittent flow, and concrete encased piping,” the summary document says. Such piping can’t be excavated for inspection, or inspected internally with tools called pigs.

Alyeska has given regulators a schedule for doing the piping replacements. Pump Station 1 will see “the most complex and critical” project, Alyeska says. It will be the first station to have its below-ground crude oil piping rerouted to an above-ground configuration.

The final design for Pump Station 1 will be finished by year’s end, with construction to start in the first quarter of 2012 and conclude in the fourth quarter of 2013, the schedule shows.

Projects will follow at pump stations 3, 4, 5 and 9, with all the piping replacements to be finished by the fourth quarter of 2014.

“Each of the pump stations will have a two year construction season to complete all of the piping work,” the Alyeska summary says. “The first construction season will install civil foundations, pipe supports, trenches, and other preparatory work and the second season will install the piping and make the final tie-ins.”

Aging pipeline

Alyeska is the Anchorage-based consortium that runs the trans-Alaska pipeline on behalf of owners BP, ConocoPhillips, ExxonMobil, Chevron and Koch Industries.
The pipeline has been moving oil from Prudhoe Bay and other North Slope fields since June 20, 1977.

Federal pipeline regulators hit Alyeska with a “notice of proposed safety order” in February, following the leak inside a Pump Station 1 building basement. The leak forced a pipeline shutdown lasting about three and a half days.

The leak was described as a booster pump manifold failure. A manifold is an arrangement of piping or valves designed to control, distribute or monitor fluid flow.

The mainline, 48-inch pipe was not involved.

Alyeska retained Det Norske Veritas, a Norwegian concern specializing in risk management, to do an independent investigation of the Pump Station 1 leak.

A 6-foot section of piping, containing the location of the leak, was removed and shipped to Det Norske Veritas for metallurgical analysis, the Alyeska summary says.

In their proposed safety order, federal pipeline regulators cited “multiple conditions” on the pipeline that appeared to pose an integrity risk. The concerns centered on the pipeline’s declining oil throughput and the potential for freeze-ups and corrosion.

As part of the settlement Alyeska signed with PHMSA in August, Alyeska agreed to replace or remove hard-to-inspect oil piping.

Marine terminal involvement

“It’s important to emphasize that a lot of these piping issues can be attributed to declining flow through our systems and that many of these piping projects were already planned,” Alyeska’s Egan said.
Aside from the pipeline itself, Alyeska operates the Valdez Marine Terminal, where the line ends and where tankers pick up crude for delivery to West Coast refineries. The terminal is a sprawling, waterfront complex of tanks, pipes and piers.

The Alyeska summary says a risk assessment was done not only for pump station piping, but also for marine terminal facility piping.

The summary, however, says nothing about any planned piping replacements at the terminal.

Republished with the permission of the Petroleum News

Tuesday, November 1, 2011

South to the Future: North Dakota’s Oil Boom Series

By Steve MacDonald
Channel 2 News
10:13 a.m. AKDT, October 31, 2011

WILLISTON, North Dakota —
Once upon a time, the town of Williston, North Dakota was a tranquil dot in the middle of the vast prairie, a place where you could drive for hours in any direction and pass maybe one other car.

But today, things are different – and just driving through town means fighting a traffic jam of pickup trucks.

It’s been this way ever since Williston became the epicenter of one of the largest oil fields in North America.

Armed with new technologies, oil companies are reaching into the massive Bakken field, a geological formation that contains a possible 11-billion barrels of recoverable oil.

To get at the oil, thousands of wells must be drilled.

For North Dakota, the hiring boom for workers on the Bakken field looks a lot like Alaska in the 1970s – when thousands of workers rushed to find work on the North Slope.

Among those landing work in the fields are a growing number of Alaskans, who are heading south to jobs in the Bakken field at the same time as oil production declines in Alaska.

Are Alaska’s jobs and people heading South To The Future?

And what should the state do about it?

Contact Steve MacDonald at

Part 1: Alaskans Head South to a New Oil Boom


Part II: Priming Production in North Dakota


Part III: Plenty of Oil, Not Enough Housing