Thursday, September 29, 2011

Lawmakers, state square off in continued tax debate

Tim Bradner
Alaska Journal of Commerce

Sen. Hollis French and state Deputy Revenue Commissioner Bruce Tangeman squared off Sept. 21 in a testy prelude to the Legislature’s oil tax debate that will resume in Juneau in January.

French said oil jobs and investment are up, not down, despite Alaska’s high oil tax. The tax is also bringing huge revenues to the state treasury, and state exploration incentives will spur a sharp increase in drilling this winter.

Tangeman said the increased jobs and capital expenditures are due to maintenance, not new oil development, and that the production decline is continuing. High oil prices are masking the effect of the oil decline, he said. Yes, exploration drilling will be up this winter, but state tax credits are paying most of the cost of that.

If explorers are lucky and find something, they’ll then have to decide whether they can afford to produce it with Alaska’s high taxes.

Tangeman and French squared off in a panel discussion at the Alaska Oil and Gas Congress, an energy conference held in Anchorage.

As Alaska debates reforming its oil tax, North Dakota meanwhile is sucking a lot of investment, Tangeman said. North Dakota’s taxes are a fraction of Alaska’s, and oil production there may surpass Alaska’s as early as next year, he said.

People are leaving to work there, too. “We saw a lot of Alaska license plates down there,” during a recent visit, Tangeman said.

In a separate panel discussion, Rep. Charisse Millet, R-Anchorage, said no matter how you slice the data, the most important number to watch is the amount of oil moving south through the trans-Alaska oil pipeline, and that is still dropping.

Opposing perspectives presented by French, Tangeman, Millet and also by Sen. Bill Wielechowski, D-Anchorage, who appeared on the panel with Millet, illustrate the stark divisions in the Legislature over Gov. Sean Parnell’s bill to ratchet down Alaska’s oil tax, called ACES, or Alaska’s Clear and Equitable Share.

Parnell’s bill, House Bill 110, passed the Republican-led House last session and is now in the Senate, lodged in the Senate Labor and Commerce Committee. Given that Democrats in the Senate like French and Wielechowski, who oppose changing the oil tax, are part of a Senate Republican-Democrat coalition leadership, the prospects for the governor’s bill seem uncertain.

Parnell and House Republicans, who favor the change, hope the May-through-December break between the legislative sessions will put some fresh air into the tax debate.

The arguments made Sept. 21 had a sharp edge, however.

French said the industry’s average tax rate over the four years since the ACES law replaced the previous tax, the Petroleum Profits Tax or PPT, was 32 percent, not the 80 percent and 90 percent that some have claimed.

“The 32 percent average rate is before the generous tax credits are factored in, lowering taxes significantly,” French said.

Also, there are twice as many industry taxpayers, indicating more companies are doing business in the state, French said. They aren’t all small independents exploring, either.

Repsol, a major Spanish oil company, purchased leases on state lands last year and announced it would be spending $750 million in exploration. Among other things, Repsol cited Alaska’s stable political environment in its press release, French said.

Industry hiring is up, too, but state labor department records, “show that 50 percent of the new industry jobs in the state are going to nonresidents.”

French was citing a Department of Labor statistic for August 2010. In a separate response, the Alaska Oil and Gas Association said many industries, including state government, see spikes in nonresident hiring during peak summer work.

Tangeman said the governor feels the changes in ACES went too far, and that the tax rate has impeded investment in new production, as evidenced by the continued decline in production. It is true that Repsol and other companies are exploring, “but we’re covering a lot of their up-front costs through the tax credits,” he said.

“The overall tax is punitive because we’re taking away the upside,” of a producers’ chances for big profits if a risky exploration venture turns out well.

Still, oil prices are high and Alaska is enjoying robust revenues, Tangeman said, so from that perspective, ACES is a great success. “It’s really filling our tank,” at the treasury, he said.

“We do have a lot of money in the bank, but my concern is the drop in production.” Tangeman said.

Alaska oil production is dropping and North Dakota is set to pass Alaska as an oil producing state, he said. Production averaged 450,000 barrels a day in North Dakota in September and is expected to exceed 500,000 barrels per day next year. North Dakota’s tax on oil is 5.5 percent of the sales price when oil prices are below $50 per barrel and 11.5 percent when prices are above that. The tax is simple compared to Alaska’s, Tangeman said, and much lower.

Alaska production meanwhile is headed the other way, with production dropping from 600,000 barrels per day to the mid-550,000 barrels-per-day range. Two years ago Alaska was at 700,000 barrels per day, on average.

Tangeman also challenged French on the notion that jobs are up in spite of the tax increase under ACES, which took effect in 2007. Industry hiring took a sharp hike in 2007 after the late 2006 BP oil pipeline spills on the North Slope. Those were workers employed for pipeline repairs and replacement, and increased maintenance, and they went to work before the new ACES law was implemented, Tangeman said.

As the new tax took effect in 2008 and 2009 industry employment was generally flat, he said.

Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at

Slope oil production decline may be accelerating, state data shows

Tim Bradner
Alaska Journal of Commerce

Production from the North Slope may be declining faster than expected. Production declined 7.45 percent for the 12-month period preceding July 1, compared to the previous 12 months, according to preliminary data from the state Department of Revenue.

Average production for the state’s fiscal year 2011, from July 1 2010, to June 30, 2011, was 596,000 barrels per day, the department said.

The long-term average decline in production has been about 6 percent.

The fall in production also exceeded the average for the previous state fiscal year, fiscal 2010 compared with fiscal 2009, declining 6.94 to an average of 644,000 barrels per day fiscal year 2010, down from 694,000 barrels per day in fiscal 2009, according to Cherie Nienhuis, head of the state’s petroleum economics group.

Nienhuis said an unusual event, an emergency shutdown of the Trans-Alaska Pipeline System for several days last January, brought the 2011 production numbers down.

The effect of the January shutdown on the 2011 numbers, “is a tough one to figure out, but we would probably be looking at a decline of 5.5 percent instead of 7.5 percent. However, events like that can happen at any time,” Nienhuis said in an email.

Alyeska Pipeline Service Co. has warned that there may be increasing interruptions in TAPS operations due to higher maintenance and possible unplanned disruptions as throughput through the pipeline continues to decline.

When throughput drops below the 600,000 barrel per day range, there are increasing problems with wax buildup, water dropout from the crude oil, and water accumulation at low points in the pipeline, which can lead to freezing problems in winter, Alyeska President Tom Barrett has said.

The state has estimated that North Slope production will average 610,000 barrels per day in the current fiscal year, 2012, but the estimate will be revised in December, Neenah’s said.

TAPS is now operating at less than one-third of its maximum capacity. From the early 1980s until 1989, the pipeline carried about 2.1 million barrels per day. Production from the Prudhoe Bay field, the largest on the Slope, began a long-term decline in 1989, and in the mid-to-late 1990s production began falling from other fields on the Slope.

The drop in production was temporarily halted in 1999 and 2000 as the Alpine and Northstar fields started production, but then the decline continued.

Smaller fields have been brought into production since then, including the Oooguruk and Nikaitchuq fields, but the additional production has not been enough to offset the continued decline in the older, larger fields.

The drop in production has become a major point of discussion within state government, because Alaska depends on oil royalties and taxes for about 90 percent of its revenue. So far high oil prices have masked the financial effects of declining production, but Gov. Sean Parnell has proposed changes in the state’s oil tax system to stimulate new investment by the industry.

State legislators are resisting the tax change, however, arguing that it is not needed.

The governor has set a goal to increase slope production to 1 million barrels per day within 10 years.

Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at

Monday, September 26, 2011

DNR commissioner: Oil investments must ramp up

Tim Bradner
Alaska Journal of Commerce

The petroleum industry has to ratchet up Alaska investments in new exploration and development to at least $4 billion a year if the decline in oil production is to be reversed, state Commissioner of Natural Resources Dan Sullivan says.

“We need $4 billion minimum, and we’re not even close to that now,” Sullivan told the Resource Development Council in Anchorage Sept. 15. RDC is natural resource development advocacy group. The number could be higher, too.

The industry is now spending about $2.5 billion a year in capital investment, according to the state Department of Revenue, but most of that is related to facility upgrades in existing fields and not in new drilling or developments that add new production.

Sullivan said he has read reports that 2012 is a record year for new industry capital investment.

“Alaska isn’t part of that and we should be, given our resource endowment and the fact that we have a pipeline that’s only one-third full,” he told the RDC.

The commissioner said the state administration is pursuing a multi-part strategy to get new investment, the centerpiece being Gov. Sean Parnell’s proposal to reduce the state production tax on oil. The governor says the tax is too high and is impeding investment.

Other parts of the strategy include possible modifications of state royalty with economically marginal new fields, authority which the Department of Natural Resources now has, and a new state policy to improve access to oil and gas processing facilities by companies who are exploring but do not own infrastructure.

Meanwhile, Sullivan said he is pounding the pavement in cities like Houston, where oil companies have their headquarters, to drum up interest in Alaska and particularly the annual North Slope areawide lease sale now planned for Dec. 7.

The state will offer almost 15 million acres of unleased state acreage in the central North Slope, the Foothills region of the southern slope, and state-owned submerged lands in the Beaufort Sea out to Alaska’s three-mile territorial limit. State-owned submerged lands off the Arctic National Wildlife Refuge and the National Petroleum Reserve-Alaska may also be included in the sale.

The U.S. Bureau of Land Management also plans a federal lease sale in the National Petroleum Reserve-Alaska in December, and Sullivan said he is hoping the federal sale can be held near the time the state offers its acreage, if not on the same day.

If both sales are held on the same day it is likely they would be at different times, however.

BLM spokeswoman Artealia Gilliard said her agency has not yet set a date for the NPR-A sale, but confirmed it will be in December. BLM is still working on preparations, including a determination of compliance with NPR-A’s National Environmental Policy Act statement and must publish a notice of the sale, Gilliard said.

Sullivan said he is getting a positive response after knocking on corporate doors in the Lower 48.

“Some of them ask me what I’m doing there, that they’re not thinking of Alaska and never have. I reply, ‘That’s why I’m here. You need to be looking at Alaska,’” he said. “Some doors were closed on us but 80 percent of the people we’ve called on have asked for follow-up meetings by our technical teams.”

The upcoming winter exploration season looks promising with several test wells planned by small and large companies, a welcome change from last year when only one exploration well was drilled on the Slope. However, too many Alaskans are misinterpreting this, Sullivan said.

“Some people are saying ‘happy days are here again’ but the explorers are telling us that if they find oil they must still do an analysis of whether they can produce it. They’re saying Alaska still has to be competitive.”

Sullivan’s remark was aimed at some state legislators who say the increased exploration is a signal that no change in the state production tax is needed.

The possibility that shale oil could be produced on the Slope, as it is now in North Dakota and Texas, has excited many people.

Sullivan told the RDC he has tasked Bill Barron, director of the Division of Oil and Gas, to head a special task force on potential shale oil development.

Great Bear Petroleum, a Texas-based independent, acquired 500,000 acres in a state North Slope lease sale held last year and is planning test wells this winter to assess possible production of oil from shale.

Sullivan said the DNR team is working to understand possible shale oil issues for the North Slope including access to water and surface impacts. A state team has been in contact with state regulators in North Dakota where there is intensive activity in shale oil drilling.

“Alaska has huge potential in unconventional oil including shale oil, and we want to facilitate this and not become an obstacle,” by failing to get on top of regulatory issues, the commissioner said.

Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at

Saturday, September 24, 2011

Alaska needs less rhetoric and more innovative thinking

Deborah Brollini
Alaska Energy Dudes and Divas

Alaska needs innovative thinking, not more rhetoric promoting business as usual. Op-eds by Senator Hollis French and Representative Les Gara offered no solutions to the decline in oil production through the Trans Alaska Pipeline (TAPS). We can all agree that we must increase oil production. However, few are thinking outside the box for solutions, and others prefer spewing rhetoric.

If you live in Alaska your quality of life is dependant on North Slope oil production, and keeping TAPS safely operational. Alaskans are blessed to live in a state rich in natural resources and oil wealth, which funds our Permanent Fund Dividend (PFD). Most Alaskans will receive $1,174 on October 6, 2011. The Governor was right when he made his PFD announcement on Tuesday, where he warned Alaskans that they might see diminishing PFD amounts in future years. The lower PFD amounts would be partly due to lower oil production, resulting in less oil revenue to be deposited into the Permanent Fund. The Governor was not attempting to “scare” the public. He was only providing Alaskans with a dose of reality. So what is the reality on the North Slope?

There is increased oil exploration on the North Slope. However, increased exploration does not equal increased oil production. Therefore, without increased oil production there will be less oil revenue for the legislature to run our state government, and to deposit into the Alaska Permanent Fund to invest your PFD dollars. So, how do we increase your PFD dollars?

One of the solutions is to take the oil tax debate out of the hands of the Governor and the state legislature. Seriously, do you really want bureaucrats and politicians messing around in your PFD pie? Of course not. Last session, Senator Lesil McGuire introduced Senate Concurrent Resolution 4, which would of established an "Alaska Oil and Gas Competitiveness Review Task Force.” Resolution 4 has now been incorporated into Senate Bill (SB) 85, which puts into statute the establishment an Oil and Gas Competitiveness Review (OGCR) Board.

The purpose of the Board is to review and provide recommendations to the Legislature each December 1st, on steps to encourage on-going long-term investment in the development of the state’s oil and gas resources. The purpose of the Board is much the same as the Permanent Fund Corporation Board. The PFC Board is designed to oversee and maximize the investment of Alaska’s Permanent Fund. The OGCR Board is designed to monitor and offer recommendations to the Legislature on steps designed to maximize the investment made in Alaska’s oil and gas resources.

The OGCR Board is to be composed of selected Legislators, Commissioners and members of the public. Our neighbors in Alberta made a similar effort that resulted in restoring oil and gas investment to the Province after a substantial downturn due to their windfall profit tax on oil in 2007 (the same year Alaska raised oil taxes). Today, Alberta is experiencing an oil boom.

The purpose of the OGCR Board is to create an ongoing body whose job it is to monitor Alaska’s position in the world oil and gas industry, and provide useful and, ongoing insight to the Legislature on that subject. Senator McGuire discusses the OGCR board during a SB 85 Senate Resources hearing (3:38) after the co-chair of Resources shelved the bill on April 4, 2011.

Last session everyone was at war over HB 110, the Governor’s oil tax reform bill, and SB 85 received very little attention. As an Alaskan the oil tax debate has become more about egos and getting elected, and less about my children’s future, which I find offensive. There is no more room for business as usual, and we need all new ideas on the table, and SB 85 is a start.


SCR4: Creating and relating to the Alaska Oil and Gas Competitiveness Review Task Force

Alaska's Future: Sen. McGuire's proposed competitiveness review is important

Energizing Investment in Alberta

SB 85

SB 85: Documents (4/4/11 Competitive Review)

SB 85 Senate Resources Hearing (Audio): Mary Jackson, Staff to Senator Thomas Wagoner, and Michael Pawlowski, staff to Senator Lesil McGuire, testimony to Senate Resources on March 25, 2011.

SB 85 Senate Resources Hearing (Audio): Catherine P. Foerster, Commissioner Alaska Oil and Gas Conservation Commission, and et al and invited testimony (4:41)

SB 85 Senate Resources hearing (Audio): Invited and public testimony (3/30/11)

SB 85 Senate Resources Hearing (Audio): Michael Pawlowski, staff to Senator Lesil McGuire testimony, and Senator McGuire’s comments on the Oil and Gas Competitiveness Review (OGCR) Board. Senator McGuire asks for recommendations rather than a “no” (4/4/11)

Alaska’s Oil Investment Tax Structure, Establishing A Competitive Alaska, Commonwealth North, March 2011

Friday, September 23, 2011

Pioneer permitting two Nuna appraisal wells targeting Torok

—Eric Lidji

Pioneer Natural Resources Alaska Inc. is permitting a two-well appraisal program at its nearshore Oooguruk unit this winter as part of its nascent Nuna development effort.

Although Pioneer is calling this an exploration program, the bottom hole locations of the two wells are within the existing boundaries of the Oooguruk unit. Petroleum News typically does not classify a well as “exploratory” unless it is outside of a producing unit.

The program this winter involves drilling, hydraulic fracturing and testing two wells — one onshore and one offshore — as well as constructing associated ice roads and ice pads.

The offshore Sikumi No. 1 well would be a vertical well starting on ADL 355037, some two miles southwest of the existing Oooguruk Island, but still within the Oooguruk unit boundaries. The onshore Nuna No. 1 well would be a directional well starting on ADL 25528, some 2.5 miles northwest of KRU drill site 3S within the Kuparuk River unit.

Pioneer hopes to begin drilling Nuna No. 1 in early January and Sikumi No. 1 in mid-February, and continue hydraulic fracturing and flow testing operations through the end of April. Produced fluids would be taken to existing production facilities in the region.

While Sikumi No. 1 would be plugged and abandoned after completion, Pioneer said it plans to preserve Nuna No. 1 as a development well for future work in the region.

Pioneer plans to build an eight-acre ice pad at each drilling location, and a five-acre ice pad east of drill site 3S for storing materials and equipment. The company plans to build one ice road connecting DS-3S to Nuna No. 1 and two others connecting Sikumi No. 1 and Nuna No. 1 to the ice road that Pioneer builds each winter out to Oooguruk Island.

The Alaska Department of Natural Resources is taking comments through Oct. 18.

Targeting Torok formation

Pioneer brought the Oooguruk unit into production in the summer of 2008 by developing the Oooguruk-Kuparuk oil pool and the deeper and larger Oooguruk-Nuiqsut oil pool, but toward the end of last year began detailing a third horizon, the shallow Torok formation.
While most of the wells used to explore and develop Oooguruk to date have passed through the Torok formation, the company wanted to develop some of the reservoir from onshore facilities and outlined a potential Nuna development project that called for two new onshore drill sites and a tie-in pad, plus associated gravel roads and pipelines.

The DNR formed the Torok participating area in June covering 1,560 acres over portions of two leases — ADL 355036 and ADL 355037. Pioneer estimates that the Torok participating area contains 690 million barrels of original oil in place and believes it can recover as much as 25 percent of that using primary and enhanced recovery techniques.

Unlike the other participating areas at the unit, Torok does not enjoy royalty relief.

In September, the DNR expanded the Oooguruk unit to include four leases along its southern edge that bring the entirety of the Torok formation into the unit boundaries.

With the expansion, Pioneer agreed to an exploration plan that requires three pilot Torok wells from the Oooguruk drill site — one is already online and Pioneer expects to complete another soon — by March and a test well from a Nuna drill site by Jun 30 2013.

Pioneer must also decide by June 30, 2014, whether it plans to sanction Nuna. If so, the company plans to build the Nuna DS-1 pad by June 30, 2015 and begin drilling in 2016.

Pioneer said it might also build a second Nuna pad in the future.

Republished with the permission of the Petroleum News

Finding a safe approach; AOGCC seeks view on the future of Alaska offshore oil & gas drilling regulation

Alan Bailey
Petroleum News

Following the Deepwater Horizon disaster in the Gulf of Mexico, in June 2010 the Alaska Oil and Gas Conservation Commission opened an investigation into whether the state needs to overhaul its regulations for offshore drilling in state waters. The commission, which has primary responsibility for drilling safety in Alaska, decided to wait until after publication of some Deepwater Horizon investigative reports before holding a hearing to seek public comments as input to its investigation. And on Sept. 15 and 16, immediately after the Bureau of Ocean Management, Regulation and Enforcement issued its Deepwater Horizon report, that public hearing took place.

When initiating its investigation, AOGCC had asked for comments on various safety-related stipulations that the commission requires of drilling operations. Those stipulations mandate, for example, the use of specific safety equipment and well design features. However, opinions offered during the hearing often also delved into some broader and more fundamental questions about the most appropriate ways to oversee and regulate the oil industry, and about how to maximize drilling safety.

Safety culture

Consultant Elmer Danenberger, an erstwhile regulator with decades of experience working for the U.S. Minerals Management Service, emphasized the importance of a “safety culture,” and the need to move away from the “it can’t happen to me mentality” that leads to complacency over operational risk.

Danenberger talked about the relative merits of regulating through the prescription of specific safety measures versus the setting of safety performance goals, goals that spell out the safety requirements while allowing a well operator the latitude to determine how best to meet those requirements. He said that Norway, with an exemplary safety record in recent years, uses a goal-oriented, safety management approach to regulation, compelling companies to take ownership of potential problems and to find solutions to those problems, with regulators determining whether the solutions are acceptable.

In the context of Deepwater Horizon the imposition of an immediate drilling moratorium, while understandable, might not have been the best strategy in response to the disaster, Danenberger said. Instead, why not require companies to find a way of preventing a similar disaster in future, while threatening a moratorium if a solution is not forthcoming, he asked.

Bad operators love command-and-control, prescriptive regulatory regimes because the regulator, by approving everything that the operator does and then carrying out safety inspections, becomes in effect accountable for any problems that occur, Danenberger said. Not only that, but prescriptive regulators tend to play a constant game of trying to keep regulations in step with evolving industry practices, with new rules taking a long time to enact.

“You can never catch up,” Danenberger said. “You are always going to be chasing the next regulation. You never entirely eliminate the gaps.”

Adjusting to circumstances

Fran Ulmer, chair of the U.S. Arctic Research Commission and previously a member of President Obama’s National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling, picked up on the same theme, saying that Norway’s goal-oriented “safety case” approach to drilling regulation not only puts responsibility for safety firmly in the hands of operators but also readily enables safety measures to be adjusted to fit the circumstances of a particular drilling operation.

“It really emphasizes the responsibility of industry to be primarily focused on the appropriate safety procedures, given the conditions of any particular well and the technology and techniques to use to develop that well,” Ulmer said.

On the other hand, any regulatory regime requires some level of prescriptive rules, Danenberger said. There is normally, for example, a need for plan approval for drilling operations, and there is always going to be a use for operational standards, especially industry standards, he said.

“There always has to be some inspection and enforcement,” Danenberger said. “There always has to be comprehensive accident investigation and there is always a role for government in that.”

Regs have some latitude

Kara Moriarty, deputy director of the Alaska Oil and Gas Association, representing the Alaska oil and gas industry, said that AOGCC regulations do give operators some latitude in the selection of specific well design parameters, allowing a well design to be appropriate to a particular drilling situation while also ensuring that appropriate safety measures are in place.

Accident prevention through risk management should be a primary focus of drilling safety, Moriarty said. AOGCC regulations effectively spell out the state’s well control requirements and the requirements for well blowout preventers, including requirements for blowout preventer testing and the pressure testing of well piping, she said. Those regulations require operators to allow AOGCC to witness the testing, an arrangement that the industry welcomes, she said.

However, Moriarty presented some AOGA recommendations for improvements to the current regulations.

Bowen Roberts from ConocoPhillips Alaska said that his company agrees that current AOGCC regulations strike about the correct balance between being prescriptive and being flexible.

“The commission’s current regulatory structure is not overly prescriptive and allows for flexibility in oil and gas operations, to accommodate situations not necessarily contemplated by the regulations,” Roberts said.

Roberts said that following the Deepwater Horizon disaster ConocoPhillips has developed new drilling guidelines, including a 16-point wells management policy that all of the company’s drilling operations must comply with.

Relief wells

The issue of relief well drilling as a means of stopping a well blowout came up several times during the hearing. Hal Shepherd, oil and gas coordinator for the Kachemak Bay Conservation Society, argued for mandating the drilling of a relief well in parallel with the drilling of the primary well, to enable a near immediate relief-well response to a blowout. However, several other people commented that the concurrent drilling of a relief well would in itself introduce additional drilling risks.

Roberts said that concurrent relief well drilling would add substantial cost with little apparent benefit, given the risks involved. ConocoPhillips supports the specification of a plan for relief well drilling as part of drilling contingency arrangements. However, the use of a blowout preventer or of well capping technology are alternative approaches to bringing a well back under control, with capping technology having proved its worth in many situations.

“Well capping technology has been effectively utilized in re-establishing well control in hundreds of wells in hundreds of well control incidents worldwide,” Roberts said.

Tighten enforcement

Lois Epstein, Arctic program director for the Wilderness Society, said that she agrees in general with new drilling safety rules recommended by Deepwater Horizon investigations.

However, she emphasized the need for effective deterrents to unsafe practices, saying that in her view the State of Alaska has a poor track record on regulatory enforcement. Enforcement needs to focus on regulatory violations that result in human or environmental harm, and on especially egregious and repeated violations, she said. Penalties need to gain public attention, with press releases perhaps being issued for major violations, she said.

Epstein also argued for the establishment of an expert independent agency, along the lines of the National Transportation Safety Board, to investigate oil industry accidents. She said that there is a need for more detailed incident reporting, including the public reporting of accident near misses.

In fact, a general lack of historic incident data was another issue raised in Deepwater Horizon investigations and was mentioned by several people at the AOGCC hearing. Danenberger, for example, said that there are optimistic signs from the oil industry and government regarding initiatives for incident data collection, but that accident trend analysis tends to be pushed into the background by other priorities.

“We still don’t have a proper international database of incidents, of complete, accurate, verified data,” Danenberger said. “It doesn’t exist and that’s inexcusable.”

“Unfortunately in this country our ability to collect the kind of data you need about accidents, about fires, about unintended loss of well control has not been adequate to really be able to answer some of the fundamental questions about how would you change business practices to really reduce risk,” Ulmer said.

Overlapping jurisdictions

Another recurring theme in the hearing was confusion arising from the overlapping jurisdictions of multiple regulatory agencies. In Alaska, AOGCC; Alaska’s Division of Oil and Gas; and the Alaska Department of Environmental Conservation all play roles in the regulation of drilling safety.

Ulmer commented that Norway has addressed jurisdictional confusion within its oil and gas regulatory environment by simplifying to just two agencies, one that oversees safety and another that oversees leasing and resource management. At the federal level in the United States, change of this magnitude would require Congressional action, and there would be a question of how individual states should conduct their regulation. But simplification of the regulatory environment would cut costs for both the regulators and the industry, Ulmer said.

Mark Myers, vice chancellor of research at the University of Alaska Fairbanks, a previous director of Alaska’s Division of Oil and Gas and of the U.S. Geological Survey, said that in Alaska there are significant jurisdictional overlaps between different agencies but that the statutory rewrite to clean this up would be far from simple — the simpler solution would be improved collaboration between agencies.

With risk being inherent in everything people do, including oil and gas development, the regulatory focus should be on risk assessment, with the improved flow of risk-related information between different agencies being a key component of inter-agency cooperation, Myers said.

Michael Munger, executive director of the Cook Inlet Regional Citizen’s Advisory Council, said that, with AOGCC having the necessary technical expertise in issues such as well control, the citizen’s advisory council recommends transferring the oversight of well blowout contingency planning from ADEC to AOGCC.

“AOGCC is responsible for the approval of normal drilling operations and it only makes sense that they should be responsible for the approval of emergency response plans for blowouts,” Munger said.

At the end of the hearing the AOGCC commissioners announced a continuation of the public comment period for its investigation, allowing 30 days beyond the date of issue of a final National Academies Deepwater Horizon report due out this year. The commission may also schedule a further hearing if necessary.

Commissioner John Norman, while thanking AOGA and ConocoPhillips for their participation in the hearing, expressed his disappointment that more experts from industry had not provided comments. Industry has been given the opportunity to provide input to the commission’s findings, Norman said.

Republished with the permission of the Petroleum News

Tuesday, September 20, 2011

Alaskans will benefit from a $1,174 Permanent Fund Dividend check

Steve Pratt

In October, Alaskans will benefit from a $1,174 Permanent Fund Dividend check. The check is the result of a Constitutional requirement to place 25% of all mineral lease and royalty revenue, plus additional monies allocated by the Legislature, into the “Permanent Fund”.

This fund earns investment income, which is paid out as dividends (50% of income), reinvested, or used to run state government.
With oil production declining, fewer dollars can be put into to the Permanent Fund to generate income to be paid out as dividends in the future. All Alaskans have a stake in helping Gov. Parnell achieve his goal of increasing oil production by 500,000 barrels per day over the next decade.

We should all think of ways we can responsibly make that vision a reality.

Saturday, September 17, 2011

Alaska hire: Legislators drill into hiring practices of oil companies

Tim Bradner
Alaska Journal of Commerce

Senate President Gary Stevens, R-Kodiak, and Sen. Linda Menard, R-Wasilla, listen to testimony on resident hire in the oil industry on Alaska’s North Slope at an Alaska Senate Labor and Commerce Committee hearing Sept. 8 in Anchorage.
AP Photo/Dan Joling

State legislators held hearings in Fairbanks and Anchorage Sept. 6 and 8 to drill into hiring practices of North Slope oil producers and contractors and to listen to complaints about nonresidents working in high-paying industry jobs that should be filled by Alaska workers.

The Senate Labor and Commerce Committee, chaired by Sen. Dennis Egan, D-Juneau, held the hearings. It’s all a prelude to the 2012 legislative session, beginning next January in Juneau, when lawmakers resume work on Gov. Sean Parnell’s bill to reduce the state’s production tax on oil, which the governor says is so high that it is hampering new investment by the industry.

Labor leaders and others say the state shouldn’t reduce the tax unless there are assurances that new industry investment will employ Alaskans on the North Slope.

The governor’s bill, House Bill 110, has passed the state House and is lodged in Egan’s Labor and Commerce Committee in the Senate.

Going into the hearings, Egan and other legislators were concerned about data from the state Department of Labor and Workforce Development that showed unusually high rates of nonresident hire during the summer months. Egan said that, according to the labor department data, more than half of the new-hires by North Slope companies in the third quarter of 2010 were not Alaska residents.

At the Fairbanks hearing, Kara Moriarty, deputy director of the Alaska Oil and Gas Association, told the committee that summer spikes in nonresident hiring is not unusual for several Alaska industries, including oil, which have to ramp up for summer work and find the labor market tight at that time of year, particularly for certain skills.

Sen. Joe Paskvan, D-Fairbanks, a member of the senate committee, said he has heard reports of some contractors working on the Slope that employ 100 percent nonresidents. Paskvan asked industry officials who spoke about the reports.

Claire Fitzpatrick, BP’s chief financial officer for Alaska, acknowledged there are some out-of-state contractors working temporary projects that bring their workers, all specialists, with them as teams.

Overall, BP has a strong Alaska-hire record, she said. During the past five years the company has consistently employed 80 percent Alaskans in a workforce of more than 2,000.

“We will always hire the best candidate for the job, but our preference is to hire qualified Alaskans, and our record backs this up,” Fitzpatrick said.

Bill Hurley, ConocoPhillip’s Alaska human resources manager, told the committee that his company has maintained an 87 percent to 93 percent Alaska-hire rate from 2001 to the present. Of people hired so far in 2011, some 83 percent were hired from within Alaska.

AOGA’s Moriarty said the number of out-of-state workers in the oil and gas industry has been generally consistent for the past decade. She based her conclusion on the last set of complete figures in 2009. Alaska Department of Labor tallies since 2001 show 26 percent to 31 percent of workers in the industry have been from out of state each year, she said.

However, Tim Sharp, business manager for Laborers Local 942, said it’s clear to anyone who works in Prudhoe Bay that out-of-state hire is on the rise.

AFL-CIO President Vince Beltrami told the committee he questioned statistics that had been presented on Alaska hire. Anecdotes from workers make it nearly impossible to trust the methodology or accuracy of industry claims of 75 percent or more resident-hire rates, he said.

Moriarty said the long-term employment data from the department also show that industry jobs held by residents increased at a higher rate than nonresident jobs from 2005 to 2009.

“During that five-year period, resident hire grew by 44 percent, while nonresident hire grew by 35 percent,” Moriarty told the committee.

Hiring of residents and nonresidents also move up and down in tandem in the cycles of industry activity.

“We have never seen resident hire declining and nonresident hire increasing. They always move up and down in tandem,” she said.

On the summer spike in nonresident hiring, Moriarty showed the committee labor department job data for other industries. Mining companies also hired nonresidents for more than half of their new-hires in the third quarter, she said, as did seafood processors. Data showed that construction, technical and scientific professionals, health care and even state government hired more nonresidents than residents that quarter, Moriarty said.

On Paskvan’s question about contractors with 100 percent nonresident hiring, BP’s Fitzpatrick said she is aware of one company from out-of-state with mostly nonresident workers and which specializes in facility “turnaround,” or major maintenance, projects.

These are projects where an operating plant, such as a North Slope oil and gas processing facility, is taken off-line for a few weeks in summer for major overhauls of equipment. The company Fitzpatrick spoke of travels to several states and even nations, and comes to the slope for tightly scheduled six- or eight-week jobs.

“The company brings as many as 200 highly experienced workers with it that work as a team and they move together from job to job. These are special skill-sets that are used seasonally and we just can’t find the skills in the state who can do the work in that time period,” Fitzpatrick said.

Paskvan said there are about 3,000 nonresident workers on the Slope.

“It’s hard for me to believe that these are 3,000 people who all have skills that can’t be provided by Alaskan workers,” he said.

Fitzpatrick said the abilities brought by the team include specialty engineering and technical skills that are difficult to find in Alaska.

A problem in getting a clear picture of resident and nonresident workers is that the actual resident workforce tends to be underestimated in the Department of Labor data because of the department’s method for measuring residency, which is eligibility for a permanent fund dividend.

“The Department of Labor’s methodology for calculating workforce residence is based on PFD applications and as such produces a conservative estimate of ‘resident’ employment,” AOGA’s Moriarty said. “A new resident to Alaska must reside in the state for a full calendar year before he or she is eligible to apply for a PFD. Therefore it could take someone almost two years before they are considered an Alaskan resident. Someone who actually lives in the state, owns a home and has a family but is newly arrived would be counted as nonresident for possibly two years.

“While PFD applications are a reliable indicator of residency, other data can provide another, perhaps more up-to-date measure,” Moriarty added. “For purposes of a study McDowell Group is doing for AOGA, several of our members provided detailed payroll data by place of employee residence, as indicated as the mailing address on W-2 tax forms.”

The labor department also has found this. In its 2009 “Nonresidents Working in Alaska” report, the department reported nonresident percentages for specific employers that were higher by several percentage points than the percentage of W-2 tax forms that were sent to out-of-state addresses, Moriarty said.

Also, some nonresidents become residents, Moriarty noted.

“The Department of Labor confirmed that a portion of workers classified as nonresidents actually become residents. In just the oil and gas extraction sector, among workers who were classified as nonresidents in 2008, 13.5 percent became residents in 2009,” Moriarty said.

Many appearing at the hearings said the Legislature’s concern should be to more encourage new production. John Cook, CFO of Airport Equipment Rental in Fairbanks, said lawmakers have done a good job establishing incentives for exploration, but they should do more to encourage production.

The exploration incentives have the state paying for as much as 65 percent of costs of drilling test wells, but when it comes to putting a new discovery into production, the economics often don’t look good with the state tax taking a big slice of any profits, supporters of Parnell’s bill to lower the tax argue.

Cook said the Legislature should also look for ways to ensure that more oil-support business goes to Alaska companies, which would also result in more employment for Alaska residents.

“Our resident private-sector businesses are vastly underdeveloped, and our state is ranked last in business competitiveness,” Cook said.

Employment on the North Slope is strong but “at $100 oil, our employment should be double or triple what its is now. We’re not experiencing anything like the boom in other states, like North Dakota,” he said. “Many of the jobs are also maintenance-related, which require less skills and pay less than jobs related to constructing new production facilities. Summer is busy on the Slope with maintenance, but it’s not enough to offset the slowdown in winter,” when new slope construction is done.

Another businessman speaking at the Fairbanks hearing, Karl Gohlke, of Frontier Supply, said, “We all know that if we increased production, we would not have to worry about Alaska hire.”

BP’s Fitzpatrick agreed. “We think the best way to increase the number of Alaskans working in the industry is to increase the level of oilfield activity and as such increase the number of oil field jobs,” she said.

She said BP would soon add a provision on Alaska-hire performance to criteria the company uses for judging potential new contractors or extending contracts held by companies.

Other criteria BP currently uses include a company’s safety record and cost.

One development in recent years: as the North Slope workforce ages, employees are purchasing a Lower 48 retirement home and then move their families, which is possible because of the two-week-on, two-week-off work rotation schedule many companies use on the North Slope.

Ken Hall, with Lynden Transport, told legislators that the high cost of living in Alaska — along with a schedule that alternates two weeks on, two weeks off — persuades many Alaska residents to relocate to other states once they’ve been hired.

Jim Johnsen, of Doyon Ltd., said the Fairbanks-based Alaska Native corporation that owns Doyon Drilling, a major Slope contractor, said his company also has had trouble maintaining its in-state workers, despite a hiring preference for shareholders and Alaskans.

“It’s less expensive to live Outside — it’s that simple,” he said.

AFL-CIO’s Beltrami resident hire should be the No. 1 issue in considering whether the tax structure should be changed.

“The bottom line here is jobs for Alaskans,” he said. “This should be the first question answered before going one step further in considering what at this point, I think, can only be referred to as a bill that gives our state’s oil wealth away.”

A smaller tax burden on the industry, he said, does not translate into more barrels of oil produced, but would take a slice out of the $3 billion state capital budget that has provided construction jobs throughout the state, Beltrami said.

“Any state revenues that, let’s say, are diverted out of the state coffers and back into the hands of the oil producers, kills capital budget projects, and the jobs that are associated with those.” he said.


Republished with the permission of the Alaska Journal of Commerce. The Associated Press contributed to this article. Tim Bradner can be reached at

Friday, September 16, 2011

Permitting under way; Repsol presents lease plan of operations to drill 15 wells using 5 rigs this winter

Eric Lidji
For Petroleum News

Repsol YPF S.A. is planning to conduct one of the broadest single-season North Slope exploration campaigns in recent memory, according to recently filed documents.

The Spanish major plans to run five rigs this winter to drill as many as 15 wells and sidetracks from five ice pads to onshore and offshore central North Slope targets.

The five proposed drilling locations would run down the fairway between the Colville River unit to the west and the Oooguruk and Kuparuk River units to the east.

Repsol is planning a vertical well and as many as two sidetracks at each location:

• Qugruk No. 1 would be in the Colville River Delta near ARCO Kuukpik No. 3 and Gulf Colville Delta State No. 1. Repsol plans to drill the well using the Nabors rig 2ES.

• Qugruk No. 2 would be about five miles east of Qugruk No. 1. Repsol plans to drill the well using the Doyon Arctic Fox, a lightweight truckable rig that Pioneer Natural Resources Alaska Inc. first used at the NE Storm and Cronus units in 2006 and Anadarko Petroleum Corp. later used to drill two wells at its Gubik Complex in early 2009.

• Qugruk No. 3 would be about five miles south of Qugruk No. 1 and five miles west of the ConocoPhillips’ Placer wells. Repsol plans to drill the well using Nabors rig 105AC.

• Qugruk No. 4 would be an offshore well several miles off the northern coast of the Colville River unit. Repsol plans to drill the well using Nabors 106AC.

• Kachemach No. 1 would be farther south, just east of the Meltwater participating area of the Kuparuk River unit. The proposed site is some five miles southwest of the Chevron Ruby St. No. 1 well and five miles northwest of the BP Exploration (Alaska) Narvaq No. 1 well, and near several of the Union Oil Co. of California White Hills wells.

Repsol plans to drill Kachemach No. 1 using Nabors rig 9ES, the rig that Brooks Range Petroleum Corp. used earlier this year to drill North Tarn No. 1 several miles to the west.

Although it has held offshore leases for years, Repsol picked up 494,211 state acres this past March in a deal with 70 & 148 LLC, the North Slope subsidiary of Denver-based Armstrong Oil and Gas, and GMT Exploration Co. LLC, also based out of Denver.

Repsol acquired a 70 percent interest in 157 leases for $768 million. The vast majority of that money will be directed toward exploration, according to Petroleum News sources.

Field work under way

Repsol is already preparing for that drilling program.
The company conducted fieldwork this summer to define the route and location of the ice roads and pads it plans to build this winter and to indentify water sources for that construction. The company will begin monitoring soil temperatures along the route this month, September, using thermistor strings and pre-pack the roads in November and December.

Once temperatures permit in December and January, Repsol plans to build 30 miles of onshore ice roads and 30 miles of offshore ice roads.

In total, the company will build seven ice pads, two near Drill Sites 3S and 2P in the Kuparuk River unit for staging, and five — four onshore and one offshore — for its 15-well drilling campaign. Repsol plans to drill “at least” one vertical well and, “time permitting,” up to two sidetracks from each pad.

The staging pad near Drill Site 2P will be about 600 feet by 600 feet and used to support the southernmost drilling site; Drill Site 2P is located along existing all season roads that connect to the Dalton Highway. The pad will house a 40 to 60-man camp.

The staging pad near Drill Site 3S will be some 600 feet by 1,200 feet and used to support the four northern drilling locations. The site is also connected to existing all-season roads. The pad will house a 120-man camp. Repsol said it “may share some of the staging capabilities with another operator in the area,” but offered no further details.

The four onshore drilling pads will be about 500 feet by 500 feet, but could be expanded to 600 feet by 600 feet “if needed.” The offshore drilling pad will be larger with additional design elements to accommodate the harsh conditions of Arctic coastal waters.

The company expects to begin demobilization and clean up in April or May.

Republished with the permission of the Petroleum News

Deadline ahead; Shell to decide by end of October on mobilization for 2012 Arctic OCS drilling

Alan Bailey
Petroleum News

With Chukchi Sea lease sale litigation moving towards its conclusion and Shell’s Arctic air quality permits out for public review, the chips are back on the table and the bets down on Shell’s odds of finally being able to sink an exploration drill bit into Alaska’s Arctic outer continental shelf.

And on Sept. 8 Pete Slaiby, Shell’s vice president in Alaska, called the hand for this year when he told a meeting of the Alaska Support Industry Alliance that by the end of October his company would make a go/no-go decision on mobilizing the resources necessary to drill in the Beaufort and Chukchi Seas in the open water season of 2012.

“We’re beginning the process of mobilization now. However, the final decisions for Shell will come a little later, about the end of October,” Slaiby said, commenting that adequate preparations for drilling are necessary and that, given the scale of the operation required for the company’s planned drilling, “it is truly a challenge to go from a standing start to 60 miles an hour fairly quickly.”

Permits needed
Slaiby said that a decision in late October to proceed towards drilling in 2012 will depend on Shell either having the permits it needs for the drilling or being comfortable that the permits will be issued.

The company has filed exploration plans envisaging the drilling of up to six wells in the Chukchi Sea and up to four wells in the Beaufort Sea, starting in 2012. But Chukchi Sea drilling is on hold, pending resolution of an appeal against the environmental impact statement for the 2008 lease sale in which Shell purchased its Chukchi Sea leases. And the Environmental Protection Agency has yet to issue air quality permits for Shell’s Arctic OCS drilling operations — following a multiyear saga of appeals against approval of Shell’s air permits, the EPA has issued new draft permits, with the public comment period on these permits having ended in early August and early September.

In the lease sale litigation, the Bureau of Ocean Energy Management, Regulation and Enforcement has published a final version of a new supplementary EIS for the lease sale, with public comments required on this document by Sept. 26. BOEMRE has placed its review of Shell’s Chukchi Sea exploration plan on hold, pending resolution of the court case, but the agency has conditionally approved Shell’s Beaufort Sea plan.

Shell thinks that the outcome of the Chukchi Sea lease sale litigation will be confirmation of the decision to hold the 2008 lease sale — the company is guardedly optimistic about having an approved Chukchi Sea exploration plan in early December, Slaiby said.

Shell anticipates having the air permits for the drilling vessel Noble Discover by around Sept. 15, and for its floating drilling platform, the Kulluk, by about Oct. 15, Slaiby said. The company expects to use the Noble Discoverer for Chukchi Sea drilling, and the Kulluk for drilling in the Beaufort Sea. And although litigation will likely follow permit issuance, Slaiby said that he thinks that the permits will be robust and that, following the furor over past problems with the permitting process, Shell will receive a fair hearing in any future permit appeal.

$4 billion
To date, Shell has sunk a huge investment into its Alaska venture.

“We will hit the $4 billion mark sometime in the fall in what we’ve spent to be ready (in Alaska), but we’ve never felt more confident about being able to proceed,” Slaiby said. “And frankly we’ve never been more confident about the (Alaska) portfolio that we’re sitting on.”

Slaiby said that Shell is favorably impressed by the potential of the Beaufort Sea portion of its Alaska portfolio, with the company owning leases in Camden Bay, to the east of Prudhoe Bay, and in Harrison Bay, on the northwest side of the central North Slope. Shell thinks that the potential of the Beaufort Sea looks similar to that of the Mars basin in the Gulf of Mexico, a “bread-and-butter” region for Shell’s worldwide operations.

“There’s the potential for years of production at Gulf of Mexico deepwater kinds of (flow) rates,” Slaiby said.

However, the Chukchi Sea is “absolutely key” to Shell’s Alaska program, he said, citing what he characterized as the world-class potential of the Burger prospect on which Shell owns several leases. Burger, known to hold a major pool of natural gas, consists of a 25-mile-diameter structure about 80 miles offshore the western end of the North Slope. Burger could hold hydrocarbon resources in the multibillion barrel range, Slaiby said.

“We truly believe this is a game changer,” he said.

Oil for TAPS
With Shell’s Beaufort Sea leases in relatively close proximity to the existing North Slope oil infrastructure, oil production from the Beaufort could band-aid the trans-Alaska oil pipeline, where low and declining oil flow rates are causing escalating concerns about future pipeline operation.

And a future oil pipeline from the Chukchi Sea through the National Petroleum Reserve-Alaska to the central North Slope could prove to be the catalyst that enables the opening of many small and mid-sized oil fields in the reserve, Slaiby said.

The huge oil potential of the Chukchi could, in itself, prove to be of national and international significance, he said.

“The oil that we are talking about in a place like the Chukchi is really enough to change politics,” Slaiby said. “It would be enough oil, for example, for the U.S. not to require the importation of oil from a country like Saudi Arabia.”

Moving forward
Shell’s initial efforts in its Alaska outer continental shelf program focused on acquiring the 3-D seismic data needed to identify exploration drilling targets, “We’ve had three very, very good years of seismic acquisition, actually the largest seismic acquisition we have ever had at Shell on an exploration play,” Slaiby said.

However, as the company moves towards drilling in some of its prospects, the dynamic has shifted to a debate about whether the company will be able to deal with an offshore oil spill. On the basis of fortune favoring those who are prepared, and working under the imperative of preparing adequately for a low probability but high impact event, Shell has developed a very comprehensive oil spill contingency plan, Slaiby said.

“From the very beginning we identified the need to be prepared,” he said. “We prepared a multi-tiered system … offshore, nearshore and onshore to deal with a very, very unlikely event that we would have an oil spill.”

Following oil industry experience from the Gulf of Mexico Deepwater Horizon disaster, Shell is fitting its blowout preventers with double shear rams — a blowout preventer closes an out-of-control well by causing hydraulic rams to shear through and seal the drill pipe. Shell has also commissioned the construction of a “capping stack” that could be bolted on top of the blowout preventer, should the blowout preventer itself fail. The capping stack will be completed in March 2012, ready for use, Slaiby said.

Oil containment barge
Shell is converting an ice-class barge for use as an oil containment vessel that would separate oil, gas and water being collected from an out-of-control well through Shell’s capping and containment systems, and that would be capable of handling the worst case discharge of oil and gas from a well in any of Shell’s exploration prospects, Slaiby said. Gas gathered on the barge would be flared, while separated oil would be pumped into an Arctic class tanker that Shell retains as part of its Arctic Alaska oil spill response fleet. If necessary, oil could also be flared from the barge, Slaiby said.

A new 30,000 horsepower polar class anchor handling vessel, for use by Shell in the Beaufort Sea, is under construction in Louisiana and is scheduled for launch in February or March 2012, with another new anchor handler to follow if Shell’s planned drilling moves ahead. Shell’s existing anchor handler, the Tor Viking, towed the company’s floating drilling platform, the Kulluk, to Dutch Harbor in the Aleutian Islands in 2010. The Tor Viking, when in Dutch Harbor, also assisted the U.S. Coast Guard by towing a stricken vessel, the Golden Seas, to safety in severe sea conditions, Slaiby said.

54,000 jobs
On the economic benefit side of the Alaska Arctic OCS debate, there are 54,000 potential future jobs at stake in the United States, and potential government revenues close to $300 billion at today’s oil prices, Slaiby said. But there will be an immense amount of scrutiny over what Shell is doing, and the level of oppositional noise will increase as the company moves closer to drilling.

However, people in Alaska understand that there is risk involved in offshore drilling and Shell spends much time managing that risk, Slaiby said.

“We’ve only got one chance to do this right,” he said. “If it looks like we err on the side of caution, I make no apologies for it.”

Republished with the permission of the Petroleum News

BP sees good results with Ugnu heavy oil production test

Tim Bradner
Alaska Journal of Commerce

Nabors Alaska Drilling Co. prepares to drill a heavy oil test well for BP on the North Slope in this file photo. The companies involved have seen good results so far from the efforts.

The first of four test production wells drilled by BP into the large Ugnu heavy oil deposit on the North Slope is performing well. This is significant because unconventional resources like heavy oil could make a major contribution to future North Slope production, but producing companies have to first figure out whether this oil, which is thick and lower quality, can be even produced.

BP’s first test well was encouraging. The well produced up to 650 barrels per day of oil mixed with sand and with the sand removed the net production was about 550 barrels per day, said Eric West, BP’s manager on the project. Production at the first test well began on April 22.

“It was higher than we expected. It is a good well,” West said.

The Ugnu has huge in-place heavy oil resources with estimates as high as 23 billion barrels of oil in place in the reservoir, but BP and other producers have worked for several years on ways of producing the oil, which is very thick is consistency.

The pilot production program underway now is testing two different production techniques with four wells that are also drilled to different spots in the reservoir to assess how differing reservoir conditions will affect production, West said.

“We want to be very careful that we don’t make a judgment based on the performance of one well drilled to a certain part of the reservoir, a false positive,” West said.

A key difference between these tests and heavy oil production technologies used in places like California, where steam is injected, is that BP is hoping to produce Ugnu oil with a cold production process that avoids warming of the permafrost layer that extends to about 2,000 feet under most of the North Slope.

The Ugnu test wells were drilled at S Pad in the Milne Point field. The first well brought on line, designated S-41, is a conventional horizontal production well that works with a progressive cavity pump, West said. The pump creates suction in the well that pulls the oil and sand mixture out of the formation and up the well, West said. The sand, along with solution gas, is separated at the surface.

The first well produced more sand than was expected in a horizontal well, with as much as 20 percent of what came up the well being sand. Learning from this, BP will make changes in the screens installed in the horizontal well that are intended to minimize the sand flowing into the well.

The second well to be brought on line is a “CHOPS” (Cold Heavy Oil with Sand) a well type developed in Canada to produce heavy oil and brought to the North Slope by BP. West said the CHOPS well is drilled vertically. When production begins the progressive cavity pump will draw oil out of the formation and create small fissures that extend into the formation, allowing more fluids to flow.

The CHOPS wells are intended to allow the sand to flow in an up the well with the oil. A special production process plant has been built for the heavy oil test that will separate the sand, which is then trucked to a special facility in the Prudhoe Bay field where it is ground up and injected back underground in an injection well.

BP will test two CHOPS wells and one additional horizontal production well in the test program, West said.

The S-41 well was taken temporarily out of production to allow BP to replace casing where wear had occurred from a rotating rod that runs the progressive cavity pump, and to make changes in the processing plant at the surface to solve a gas-handling problem, but such startup problems were expected with a new production system, West said.

BP and other North Slope producers are looking to production from large unconventional oil resources like the Ugnu heavy oil to supplement declining production from conventional oil fields on the slope. The Ugnu oil produced at S-41 has an API gravity of 12, West said, but the oil quality from different parts of the formation is expected to vary. API gravity is an American Petroleum Institute measurement that is commonly used as an indicator of oil quality.

The test production wells were drilled to a deep part of the Ugnu that is about a 4,000 foot depth, but parts of the reservoir to the west are at shallower depths that will be more difficult to produce, and which may require a heat source to warm the oil if it is to be produced at all, West said.

BP and ConocoPhillips are also producing viscous oil, a somewhat better quality oil that is about 18 degrees API, from the Shrader Bluff deposit in the Milne Point field and the West Sak formation in the Kuparuk River field, which is nearby.

West said the Ugnu formation appears to have good porosity and permeability in the reservoir rocks, which are the pore spaces that hold the oil and gas fluids and the connections between the pores that allow the fluids to flow to a producing well. The porosity and permeability may be superior to that in some of the viscous oil formations on the Slope, in fact.

Tim Bradner can be reached at

Republished with the permission of the Alaska Journal of Commerce

Doyon leads in Interior exploration

Tim Bradner
Alaska Journal of Commerce

The results of geochemical sampling across wide areas of the Yukon Flats show new evidence there is oil and well as natural gas in the region, according to Doyon Ltd., the Interior Alaska Native regional corporation exploring in the area.

Previously most geologists believed the Yukon Flats to be more prone to natural gas discoveries, although some companies also were interested in the possibility of oil from the area.

Doyon is leading an effort to do exploration in the Interior Alaska basins both on its own lands and lands owned by the state of Alaska.

In another development, Doyon is also preparing to do more seismic exploration this winter in the Nenana Basin, west of Fairbanks, where Doyon and several partners hold rights to a half million acres of state lands under a state exploration license, according to Jim Mery, Doyon’s vice president for land.

SA Exploration Co. Inc. of Anchorage, will be contracted to do the work, which will involve at least 125 miles of two-dimensional seismic work, Mery said. The project is expected to cost about $5.5 million. Doyon and its partners drilled an exploration well in the basin in 2009.

In the Yukon Flats Doyon itself, as well as two village corporations, Stevens Village and Birch Creek, own about 2 million acres of land in the flats that are considered very prospective for oil and gas. The two villages are actively supporting the exploration, Mery said.

Doyon is leading the exploration initiatives in both areas, a departure from its previous approach of bringing in an industry partner to lead the exploration, Mery said.

“Our board has decided to take a much more active role in the early stages of exploration both in oil and gas, and minerals. We are doing more work ourselves, and spending more of our own money, to obtain more information and add value to the projects when we take them to potential partners,” Mery said.

There are still partners in the Nenana Basin program: Usibelli Energy LLC, Arctic Slope Regional Corp., Rampart Energy Co. of Denver and Minnesota-based Cedar Creek Oil and Gas Co., but Doyon is the operating partner.

In the Yukon Basin, the Interior regional corporation is pursuing exploration on its own, in cooperation with the local villages.

Trapping the details
Two years ago Doyon and its Nenana Basin partners drilled a natural gas exploration well about eight miles west of the community of Nenana, about 50 miles southwest of Fairbanks. No commercial quantities of gas were found in the well, which was drilled to about 11,000 feet, but important information was obtained, Mery said.

“We learned some important things, most important that there are excellent oil and gas ‘source’ rocks in the basin,” he said.

The drilling results, along with reinterpretation of available seismic data and new “gravity” surveys Doyon conducted last winter, has led the corporation to believe that the sedimentary rocks in the basin go much deeper to the north, although there also appear to be deeper sedimentary rocks in other parts of the basin as well, Mery said.

Gravity surveys are done with instruments that measure the depth of sedimentary rocks. Doyon’s gravity surveys were done with instruments at the surface but airborne gravity surveys are also done.

Mery said Doyon now believes the sedimentary rocks extend deeper than previously believed, to between 23,000 feet and 25,000 feet, he said.

The presence of deep sedimentary rocks is important because the conditions, the combination of pressure and temperature, are usually favorable to the formation of hydrocarbons like natural gas.

If gas is formed in the deep source rocks, hopefully, it would seep upward into shallower “traps” of porous rocks that can become reservoirs from which the gas could be produced.

Mery said there is also evidence of possible geologic structures in the Nenana Basin that could trap natural gas.

If the results of the new seismic activity planned this winter are favorable, Doyon will plan more exploration drilling in the area, Mery said. Wells there could cost $15 million to $20 million each, he said.

If gas is found in the Nenana Basin, it could be brought to market is just a few years, to either serve Fairbanks or supply gas to a natural gas pipeline. The state of Alaska is now working on a plan for a 24-inch pipeline from the North Slope to Southcentral Alaska that follows a route near the Nenana Basin.

The geochemical sampling in the Yukon Flats is part of a detailed assessment of the flats that Doyon has been under way for several years. In 2010, Doyon did a 96-mile seismic exploration program near Stevens Village. In 1989, ExxonMobil Corp. conducted seismic work on Doyon and federal lands. Doyon owns the Exxon data from Doyon-owned lands and has licensed the rest.

Geochemical sampling involves a chemical analysis of mud extracted by drilling shallow core holes in lake bottoms in the flats. An initial phase of the sampling was done last March and the results were favorable enough that Doyon did follow-up sampling program this summer over a broader area, Mery said.

“The analysis indicated the clear presence of thermogenic hydrocarbons, including methane and a number of more complex hydrocarbons including propane, butane and on up,” the scale of heavier hydrocarbons, Mery said. These are strong indications of the presence of oil.

A thermogenic process in where oil and gas is formed in deep rocks under pressure and high temperatures, as compared to a biogenic process that occurs typically in shallower rocks and at lower pressures and temperature.

Through this process only methane, the main component of natural gas, forms through a bacterial (biogenic) action in the rocks.

The indicator of thermogenic action tells Doyon that there is oil and gas in source rocks underneath broad areas of the Yukon flats, Mery said.

“Of course this does not tell us if there are economic accumulations of oil,” he added.

However, reservoir traps also are needed to hold oil and gas seeping from the source rocks, and these need to be found in the Yukon Flats. Doyon’s next step would be to do more seismic surveys and ultimately plan an exploration well, most likely with an industry partner.

One advantage, Mery said, is that the basin is crossed by the Trans-Alaska Pipeline System, which would provide a ready transportation system for any oil that is discovered. If a natural gas pipeline is built from the North Slope, it would be available to transport natural gas from the region.

Republished with the permission of the Alaska Journal of Commerce

Monday, September 12, 2011

Repsol prepares to start work on its various lease holdings

Tim Bradner
Alaska Journal of Commerce

Spanish major Repsol is planning an aggressive North Slope exploration drilling program this winter to evaluate almost half a million onshore and offshore acres in leases acquired last March from two independents, Armstrong Oil and Gas and GMT Exploration.

Repsol told the state Division of Oil and Gas it will soon file surface applications to build ice pads for four onshore location and one offshore location, according to John Easton, surface permit coordinator for the state Division of Oil and Gas.

“We expect their ice pad applications soon, but they have already filed an application to build 60 miles of ice road, about 30 miles onshore and 30 miles onshore,” Easton said.

Repsol holds offshore outer continental shelf leases acquired in the federal 2008 Chukchi Sea OCS Lease Sale 193, but has expanded to a program near the producing North Slope onshore fields with the acquisition of 494,211 acres on 157 state of Alaska leases from Armstrong and GMT.

Some 84 of those leases are set to expire between 2012 and 2014, which is what has motivated the company to get busy with exploration this winter, state officials said on background.

Repsol will file permits for one vertical well and two lateral sidetracks at each location, although not all of these wells may be drilled, the state officials said.

Two other companies, both independents, also plan exploration wells this winter. Australia-based Linc Energy plans to drill on federal leases at Umiat, a known oil accumulation on the Colville River at the southeast corner of the National Petroleum Reserve-Alaska.

The company is now making arrangements to move a drill rig to the site.

Brooks Range Petroleum, an Alaska-based independent, plans to conduct a production test at its North Tarn discovery made last year, and hopes too drill two other wells to delineate the discovery if the production test turns out well, said Jim Winegarner, the company’s lands and external affairs manager.

Anadarko Petroleum Corp. also plans a production test at a gas discovery the company made two years ago in the southern foothills region of the North Slope, the company has said previously. The well was not tested at the time it was drilled because of seasonal constraints on surface activity.

This article republished with the permission of the Alaska Journal of Commerce.

Alyeska warns of more stoppages for pipeline

Tim Bradner
Alaska Journal of Commerce

Alyeska Pipeline Service Co.’s president has warned that more frequent Trans-Alaska Pipeline System interruptions are likely as the pipeline company grapples with problems related to low throughput and increased maintenance needs.

Last January, TAPS was shut down for four days when a leak developed in a pump station pipe. Alyeska was able to restart the pipeline safely in winter conditions but had the restart been delayed two more days there could have been a prolonged shutdown that would have created a fuel emergency in Interior Alaska communities that depend on local refineries supplied by TAPS, Tom Barrett, Alyeska’s president, told a group of Anchorage business leaders.

“We will probably average 600,000 barrels per day this year, but as the decline in throughput continues we are at increasing risk of encountering operating problems,” Barrett said at meeting of the Resource Development Council, an Alaska-based resource advocacy group.

The pipeline has been in operation for 34 years now and has moved about 16 billion barrels since operations began in 1977. However, it now is operating at volumes below its original design parameters, Barrett said.

“This means we’re in unknown territory,” he said.

Those who designed TAPS in the 1970s did a good job, however. The pipeline withstood a magnitude 7.9 earthquake in 2002 with only minor damage and no spilled oil. The earthquake design parameter was 8.0, however, Barrett said.

Alyeska recently completed a two-year, $10 million study of low-flow issues that predicted water settlement problems will develop as throughput approaches 500,000 barrels per day; wax problems will develop as throughput nears 400,000 barrels per day and possible damage to the mainline pipe from frost heaves due to and lack of warm oil in the pipe and freezing soils, could occur at 300,000 barrels per day.

There is now ice flowing in the line in winter under present conditions, Barrett said. There are also problems with increasing vibrations that occur at low flow rates in certain topography, such as the down slopes from mountain passes.

As the decline continues the restart problems could be more serious with another midwinter interruption.

“If we have another winter shutdown there could be serious consequences for the state and our owner companies,” Barrett said.

More frequent scheduled maintenance shutdowns are likely also as Alyeska undertakes modifications on TAPS to deal with the issues. One example of a substantial modification that might be required is a new leak detection system to replace the existing system that may be less reliable with low volumes of oil flowing at slower speeds.

Alyeska is taking steps now to add more heat to the line, Barrett said. An expanded program of recirculating crude oil to warm it at two pump stations is planned for this year. The procedure warms the oil through friction as the crude recirculates through pipes at the pump stations. Tests are also planned with additional insulation added to the pipeline.

The problems develop through a combination of lower volume and lower velocity of the oil and the falling temperature of the moving crude oil, he said. Oil enters the pipeline at 105 degrees to 108 degrees F. on the North Slope but has typically cooled to about 40 degrees by the time it reaches Valdez.

It now takes 15 days for oil to move from the North Slope to Valdez, at the southern terminus of TAPS. At a 300,000 barrels per day throughput it will take 30 days.

North Slope fields are declining in production at rates of 5 percent to 6 percent a year.

“The decline has exceeded our projections and those of the state of Alaska,” Barrett said.

The solution, Barrett said, is increased production on the North Slope. If the TAPS throughput could be restored to 1 million barrels per day, all of the operating problems would vanish, he said.

Republished with the permission of the Alaska Journal of Commerce. Tim Bradner can be reached at

Saturday, September 10, 2011

Going both ways; Marathon files for bidirectional gas flow through Cook Inlet CIGGS line

Alan Bailey
Petroleum News

Marathon Oil Co. has asked the Regulatory Commission of Alaska for approval of an agreement with Chugach Electric Association for the bidirectional flow of natural gas through the Cook Inlet Gas Gathering System, known as CIGGS, under Cook Inlet. And in a parallel RCA filing Marathon has asked for approval of pipeline facility modifications on the Kenai Peninsula to enable the bidirectional flow to operate.

Flexibility needed

Currently CIGGS only carries gas west to east under Cook Inlet from oil and gas fields on the west side of the Inlet. However, faced with ever tightening gas deliverability during cold winter weather, Southcentral Alaska power and gas utilities have been anxious to enable bidirectional flow through CIGGS, to increase the flexibility of arrangements for flowing gas from wells to the places where the gas is needed. Under the agreements filed with RCA, Chugach Electric will fund the CIGGS bidirectional flow project, including the required changes to the pipeline infrastructure, with the state providing a grant for the capital costs of the project.

Chugach Electric is concerned about winter supplies of gas to its gas-fired Beluga power station on the west side of the Inlet. The plant is built over the large Beluga gas field, the primary source of fuel for the plant. However, as production from the aging Beluga field declines, Chugach Electric needs flexibility to source gas from other fields around the Cook Inlet basin. With east to west flow in a bidirectional CIGGS, gas could flow from gas fields on the east side of the Inlet through CIGGS to the west side, and thence through another line, the Marathon-operated Beluga pipeline, to the Beluga power station. In August businesses involved in the Cook Inlet gas industry filed with RCA a tariff settlement for the Beluga line, which already accommodates bidirectional gas flow.

Without bidirectional flow through CIGGS, if Chugach Electric purchases gas on the east side of the Inlet, the utility is dependent on flowing an equivalent volume of gas into its power station from gas utility Enstar Natural Gas Co.’s pipeline system on the west side. Essentially, rather than flowing gas molecules from the Kenai Peninsula to Beluga, east-side gas is simply exchanged for west-side gas.

But Enstar cannot guarantee the availability of gas by for delivery by this mechanism, Marathon said in its CIGGS bidirectional flow RCA filing.

Increasingly important

“Chugach has advised CIGGS that, as gas sourced from the east side has become an increasingly important part of Chugach’s supply portfolio, Chugach has become concerned with the adequacy, availability and security of pipeline transportation from east to west across the Inlet,” wrote Marathon Commercial Manager Craig Chambers in the RCA filing. “Chugach seeks to protect and enhance the reliability of its gas transportation by having access to direct cross-Inlet pipeline capacity to protect against the possibility of cold weather capacity constraints, bottlenecks and outages on the … Enstar system.”

And, with Cook Inlet Natural Gas Storage Alaska building a new gas storage facility on the east side of the Inlet for use by Southcentral power and gas utilities, flexibility in moving gas between different sides of the Inlet would be of more general benefit than just the support of Chugach Electric’s power generation capacity.

However, to meet its own needs, Chugach Electric wants CIGGS bidirectional flow to be available in the winter of 2011-12, a timeframe that requires one of the necessary CIGGS modifications, the installation of piping to bypass some equipment at East Foreland on the Kenai Peninsula, to be started by Oct. 1, Marathon says. Marathon says that it took the opportunity of a scheduled pipeline shutdown in August to carry out another required modification, the removal from CIGGS of some check valves, originally intended to prevent the back flow of gas in the line. The gas flow meter on the Kenai Peninsula, at the point where CIGGS connects with the Kenai Nikiski gas pipeline, will also need to be modified to allow the metering of gas flowing in either direction through the pipeline junction, Marathon says.

Differential pressure

The direction of gas flow through a line such as CIGGS depends on the differential gas pressure across the length of the line — gas flows from high pressure to low pressure. So, to achieve bidirectional flow through CIGGS Marathon plans to install a new gas compressor in the Kenai Nikiski line near the junction with CIGGS, to elevate the pressure of gas from the Kenai Nikiski line above that in the CIGGS line whenever east to west flow through CIGGS is needed. However, given concerns about the future need for flexibility in compression arrangements in the Kenai Nikiski line, Marathon says that it plans to rent, rather than buy, the new compressor.

Marathon is also proposing changes to its CIGGS tariff, to take account of the bidirectional flow arrangement, but the company says that it has closely modeled its new tariff terms on the terms for interconnections with CIGGS in its existing tariff.

Republished with the permission of the Petroleum News

Escopeta begins drilling; passes ‘rigorous’ regulatory review

After passing a tough review from Alaska regulators, Escopeta Oil Co. began drilling its first well in Alaska’s Cook Inlet on Sept. 2, using the Spartan 151 jack-up rig — the first jack-up rig in the inlet since 1994.

About 10 miles north of Nikiski in the Corsair prospect, KLU No. 1 is one of five wells in Escopeta’s multiyear oil and gas exploration program in the offshore Kitchen Lights unit, which includes the Corsair, East Kitchen, Kitchen and Northern Lights oil and gas prospects.

By the morning of Sept. 7, the Spartan 151 had drilled a narrow, 12 and 1/2-inch, hole down to 1,800 feet, and had already begun to re-drill the hole, widening it to 26 inches for 20-inch casing.

The smaller diameter hole was drilled as a safety precaution, to make sure there were no unexpected pockets of natural gas in the well bore, Escopeta spokesman Steve Sutherlin said.

Drillers had reached 1,080 feet with the larger hole by the morning of Sept. 8, when this issue of Petroleum News went to press.

Stopping at 4,800 feet for another inspection

The well’s ultimate depth is about 16,000 feet, which will take it down to the pre-tertiary zone, stratigraphically equivalent to the Jurassic interval.

But to satisfy the concerns of Bill Barron, director of Alaska’s Division of Oil and Gas, Escopeta offered to stop drilling at 4,800 feet for another inspection from state regulators.

In a letter dated Sept. 2, Barron told Escopeta he agreed with the company that “the best way forward” was to drill only to a subsea true vertical depth of about 4,800 feet, a point where the well casing was planned to be changed to 13 and 3/8 inches.

According to Baron’s letter, “after successful installation and testing of this casing,” the company must halt drilling until the state Department of Natural Resources, of which the division is a part, “evaluates and determines the reasonableness and prudence of moving forward with additional drilling.”

One of the factors in the evaluation will be the weather and ice formation in the upper Cook Inlet. Drilling could be suspended until spring.

Barron tough on safety

Barron has been hard on Escopeta, which is drilling its first well in Alaska. The division director demanded an unusual amount of information and pre-drill meetings before allowing the small independent to move forward at Kitchen Lights.

A change in the top leadership at Escopeta weeks before drilling was scheduled to begin appeared to add to his concerns. (See Escopeta story in Sept. 4 edition of Petroleum News.)

The arrival of the Spartan 151 jack-up was welcome news, Barron said, but “A well control incident in Cook Inlet could have devastating consequences for the state and the state’s most vital industry.”

In an Aug. 31 interview with Petroleum News, Barron said the situation had improved and that state officials were proceeding in “a positive, workmanlike relationship with Escopeta.”

In his Sept. 2 letter, which gave Escopeta the final regulatory approval it needed to begin drilling, Barron praised Escopeta’s team and their willingness to work with DNR on shared priorities, which centered on operational safety.

DEC, AOGCC officials comment

Other regulators also praised Escopeta.

In a Sept. 6 letter from the Alaska Department of Environmental Conservation, which had previously approved Escopeta’s Oil Discharge Prevention and Contingency Plan, Laurie Silfven told the company that DEC had conducted a “rigorous review” of Escopeta’s spill plan.

She said the company had “voluntarily offered reports, data, and certificates not necessarily required” by statute, but which helped DEC in its evaluation.

Silfven said DEC appreciated Escopeta’s “responsiveness” to its requirements and the company’s willingness to share information.

Alaska Oil and Gas Conservation Commission inspector Lou Grimaldi, after completing the final rig inspection on Aug. 31, said in an email that in his report to his supervisor he “used the terms outstanding and flawless as these best describe the efforts that your men expended in coming into compliance.”

Escopeta can live with it

Sutherlin told Petroleum News on Sept. 3 that Escopeta is just glad to be drilling, and it can live with the additional inspection from the division.

Company officials are confident they can drill to total depth safely and without rushing before ice buildup in Cook Inlet closes the drilling season, Sutherlin said.

Further, if total depth can’t be achieved, Escopeta can re-enter and finish the well in the spring, he said.

Under a deadline from the division, Escopeta must drill a well in the unit to the pre-tertiary interval by Oct. 31 in order to keep its leases — a deadline that some regulators think is putting too much pressure on Escopeta.

Sutherlin said it is his understanding that Barron has signaled that, if necessary, he would be willing to give Escopeta more time to complete the well and thus keep the Kitchen Lights unit intact.

More gas for Southcentral Alaska?

In 2003, Forest Oil, a former owner of the Corsair leases, said that a pre-drill analysis of the prospect indicated it might hold as much 480 billion cubic feet of natural gas and 137 million barrels of oil.

In May, Escopeta’s general manager in Alaska, Vladimir Katic, said natural gas from a discovery by Escopeta could be available for delivery to consumers in as little as 18 months; oil would take about three years to bring online, he said.

Under Katic’s leadership, the company has begun design engineering studies on production facilities, Sutherlin said.

Katic “presented various development scenarios to the European investors, and management/operations/engineering people from the Texas office in meetings late in August in Anchorage,” Sutherlin told Petroleum News in an email.

Republished with the permission of the Petroleum News