Murkowski comments on U.S. energy policy

In a speech to an energy policy forum hosted by George Washington University and Arent Fox LLP on June 5 Sen. Lisa Murkowski, R-Alaska, spelled out her ideas on the needed goals for a U.S. energy policy. Murkowski is the ranking Republican on the Senate Energy and Natural Resources Committee. Commenting that the nation does not currently have a coherent or long-term policy at the federal level, Murkowski said that a policy should be non-partisan and should address the need for energy that is abundant, affordable, clean, diverse and secure. “One thing I won’t do is stand here and tell you which resources, which technologies — or even which exact policies — will enable us to meet our energy goals,” Murkowski said. “Some of that will be laid out in the energy plan I intend to release this summer. For now, I’ll simply say that it’s inappropriate for the federal government to focus on one technology, to the exclusion of others. Markets and consumers will make the choice far better than anyone else. What policymakers should focus on instead is outcomes, and we should be open to a number of routes that could help us get there.” Six factors Murkowski outlined six factors that she said would underpin the successful development of legislation to address the energy policy question. First, legislation must be developed through the Congressional committee process, rather than through some other group of lawmakers brought together to work on energy legislation. Second, there needs to be a balance between different energy technologies, encouraging oil and gas production on federal lands while also focusing on innovation. Third, people need to “make some hard decisions” on the extent of the government’s role in technical innovation. “The federal government can help fund research that would otherwise not be undertaken, but our job is not to offer subsidies that never end or subsidies that prop up a technology every step of the way to commercialization,” Murkowski said, citing Department of Energy involvement in North Slope methane hydrate research as a good example of government research funding. Fourth, energy policies must pay for themselves, Murkowski said, commenting that federal economic stimulus funding for clean energy had resulted in a lower payback than anticipated. Fifth, legislation should not directly or indirectly increase the price of energy. And sixth, the energy legislation needs to be brought for consideration on the Senate floor, rather than languishing low down in the legislative priority list as has tended to happen in recent years. Loan guarantees Murkowski later commented in response to a question that, despite the recent tainting of the use of government loan guarantees, with funds going into unsuccessful renewable energy development, she believes that the government does have a role in encouraging new technologies but that “there has to be a kind of glide path out” of a project. “Some are suggesting the plug just needs to be pulled (on the loan guarantee program),” Murkowski said. “I don’t think that needs to be the case. I think we need to make sure that the loan guarantee program operates as Congress intended.” —Alan Bailey

NPR-A draft plan comment period extended

NPR-A draft plan comment period extended The federal Bureau of Land Management has extended the comment period for the National Petroleum Reserve-Alaska draft plan to June 15. comments for the NPR-A sale should be mailed to: State Director, Bureau of Land Management, Alaska State Office, 222 W. 7th Ave. Mailstop 13, Anchorage AK 99513-7504. BLM-Alaska State Director Bud Cribley said in a statement that the agency received requests from several stakeholders to extend the comment period. “The plan is complex,” Cribley said, and the agency “... decided that we could balance the need to complete the plan in a timely manner and the need to be responsive to our stakeholders by extending the comment period for an additional two weeks.” Four alternative future management strategies are proposed in the draft plan, which is the first to cover the entire NPR-A, including lands in the southwest portion of NPR-A not included in previous plans. The plan includes decisions on availability of acreage for oil and gas leasing, surface protections, Wild and Scenic River recommendations and Special Area designations. The comment period began March 30 and with the extension will run 77 days.

A piece of the methane hydrate puzzle

Known to exist in vast quantities in many parts of the world but with as yet no means of commercial production, methane hydrate could eventually become a prolific source of natural gas. This winter’s test of the production of methane, the main component of natural gas, from the Iġnik Sikumi No. 1 methane hydrate test well on Alaska’s North Slope represents a notable step for methane hydrate research in that, among other achievements, it succeeded in producing methane from hydrate for a record-breaking duration of 30 days. However, determining the next steps in researching gas production from hydrates will depend on the analysis of data obtained from the test, David Schoderbek, ConocoPhillips director, gas hydrates, told Petroleum News May 10. A team involving ConocoPhillips, the U.S. Department of Energy, and the Japan Oil, Gas and Metals National Corp. conducted the test. Methane hydrate consists of a white crystalline substance that concentrates natural gas by trapping methane molecules inside an ice-like lattice of water molecules. The material is only stable within a narrow range of temperatures and pressures: Move the temperatures and pressures outside that range, and the material dis-associates into methane and water. Using carbon dioxide Researchers have been investigating the possibility of extracting methane from hydrate by de-pressuring a subsurface hydrate accumulation, thus moving the hydrate out of its stability range and causing dis-association of the material. However, ConocoPhillips with its partners has been researching an alternative approach involving the injection of carbon dioxide into the hydrate, causing the carbon dioxide to exchange with methane in the hydrate lattice. The process releases methane while also trapping carbon dioxide inside the hydrate. Schoderbek said that in laboratory tests scientists had successfully displaced all methane from hydrate samples by flooding the samples with carbon dioxide over an extended time period. This technique, if replicated in the field on a commercial scale, might provide a means of sequestering unwanted carbon dioxide as well as enabling natural gas production from the hydrates. According to information in the Department of Energy website, the use of carbon dioxide for gas production from methane hydrates could present additional benefits: The procedure does not liberate water from the hydrates, would not impact the mechanical stability of the hydrate deposits and, unlike de-pressurization of the hydrates, would not cause the formation of pore-clogging ice or secondary hydrates as a consequence of dis-association-induced cooling. The purpose of the test with the Iġnik Sikumi well was to see if the results from the laboratory test could be replicated in field conditions, Schoderbek explained. Test location The North Slope is an especially suitable location for this type of test because of the known existence of hydrate accumulations in cold rocks under the permafrost, with a high saturation of the hydrates in clean sandstone close to an existing oil and gas infrastructure, Schoderbek said. ConocoPhillips used log data from existing wells to home in on a suitable site for the test well, eventually opting for a location next to an existing well pad within the Prudhoe Bay unit. The test location was close to wells known to have passed through methane hydrate deposits under the permafrost, in a situation where subsurface pressures and temperatures appeared close to those used in the laboratory tests. The well location was conveniently close to infrastructure on the existing well pad. At the same time the use of an ice pad as a base for the drilling would avoid any conflict with regular oilfield operations, Schoderbek said. The research team used subsurface and seismic data to extrapolate the position of hydrate bearing sands from under the existing well pad out to the location of the test well. Drilled in 2011 ConocoPhillips drilled the well in April 2011 to a depth of 2,597 feet, 900 feet below the permafrost and also below the base of the hydrate accumulations. Subsequent well logging with gamma ray, resistivity, sonic, density, and magnetic resonance imaging logs provided necessary data for the characterization of the methane hydrate reservoir, in particular for determining the hydrate and water saturations in the pores of the subsurface reservoir sands. “That allowed us to make a higher quality estimate of what conditions would exist during the test,” Schoderbek said. “So we were able to narrow down what the basis of the (test) design needed to be.” This winter, having completed the test design, the team rebuilt the ice pad; re-entered and perforated the well; and installed a downhole screen to prevent sand from clogging the well bore. The team then injected a mixture of nitrogen and carbon dioxide into the methane hydrate reservoir over a period of 13 days, thus replicating what had been done on a smaller scale in the laboratory. Gas mixture For this phase of the test, the nitrogen and carbon dioxide were transported in liquid form to a built-for-purpose gas mixing skid at the well site. In the skid the liquids were gasified and pressurized for injection down the well. The team also mixed in a couple of other gases to act as markers, used later to determine how much of the injected gas returned to the surface during the production phase of the test. After injecting the gases into the subsurface rock formation, the team spent a couple of days converting the well for production by, among other things, re-directing the gas injection equipment and installing a downhole pump in the well — the pump, powered by produced water from the Iġnik Sikumi wellbore, would be necessary to cause fluid to flow to the surface from the producing formation. In the production test the downhole pump drove a mixture of methane, carbon dioxide, nitrogen and tracer gases to the surface, where the production of the various gas types was measured. No delay The team had determined that there would be no technical advantage to shutting in the well long enough to allow the complete replacement of methane in the hydrate by carbon dioxide as had been done in the laboratory test, Schoderbek explained. By the time that the gas injection process had been completed, the reservoir close to the well bore — the section of the reservoir that would likely produce first — would have already been permeated with carbon dioxide, he said. The measurement of what came out of the well in comparison with what was pumped in would enable the effectiveness of the carbon dioxide replacement to be determined. With the pressure in the reservoir drawn down by the downhole pump, the procedure transitioned from a test involving carbon dioxide replacement of methane to a multi-day test of methane production through depressurization. Data analysis Chemical engineers, reservoir engineers and reservoir modelers are now analyzing the huge volumes of data obtained from the test to determine the extent to which methane production resulted from carbon dioxide exchange rather than depressurization, Schoderbek said. Until this data analysis has been completed and the results of the test assessed it will not be possible to say what might be an appropriate next step, or for that matter what the research timeframe might be, he said. And, with many uncertainties remaining regarding the practicalities of large-scale methane hydrate development, the possibility of commercial gas production from the resource is still many years away. “The hydrate resource, globally, could be larger than all conventional hydrocarbons, but turning it into a reserve is far into the future,” Schoderbek said. http://www.petroleumnews.com/pnads/307447534.shtml

Special session called on oil taxes, in-state line; bill based on Senate’s new field tax

By Kristen Nelson Petroleum News It looked like Senate Finance had an oil tax compromise senators could live with when, after weeks of work on the measure, it moved Senate Bill 192 out of committee April 11. But SB 192 never reached the Senate floor. The bill, a fundamental change of Alaska’s oil and gas production tax system with different tax rates for existing production from legacy fields, incremental production from legacy fields and new oil, couldn’t garner enough support from members of the Senate Bipartisan Working Group. On April 14 another plan surfaced, a tax change affecting only production from new fields. Senate Finance added that measure to House Bill 276, credits for exploration and seismic work in frontier basins (see story in this issue). The Senate passed HB 276 by a vote of 17 to 3, but it got no traction in the House, with portions of HB 276 moved to other legislation and HB 276 withdrawn by its sponsor. The tax change proposed by Gov. Sean Parnell last year, an across-the-board production tax cut, passed the House last year but stalled out in the Senate, with senators saying they needed more information before making tax changes. So the session ended with no major changes in the state’s oil tax system. Within the hour of legislators gaveling out the governor had called a special session to begin April 18, with the oil tax issue, House Bill 9 (the in-state gas pipeline bill) and HB 359, sex trafficking, on the agenda. ‘A new dynamic’ At an April 16 press conference the governor said he was interested in the approach the Senate took in HB 276, and said with the “Senate’s action there’s a new dynamic now at work that I think might lead to a compromise that could produce new production, both now and in the future.” Parnell said the Senate proposal wasn’t the whole answer because any new oil discovered as a result of the credits wouldn’t be going into the pipeline for a number of years, and he was concerned “that vast resources in our legacy fields will remain untapped.” The governor also said the Senate’s approach, focusing only on new fields, “will cost the state billions of dollars across 10 years while we have declining production and no new revenues from new production.” He cited the example of a company proposing to spend $9 billion in the state over the next 10 years on new fields. Under the state’s existing tax structure that company would get credits of between 45 and 65 percent, “so the state will pay half of the cost of that exploration across the next 10 years,” meaning the state would have to come up with $4 billion to $6 billion in that timeframe, while production from existing fields is declining. The governor said he wants to see a proposal which would incentivize new production from existing fields, along with new field production, and believes that with “a significant tax change in existing fields” the state could see as much as 100,000 new barrels a day “within a year and a half or two years.” “I want to see whether we can take what the Senate has already agreed is meaningful in the new field context and make it material enough to do the same in existing fields,” Parnell said. If the Legislature reaches an impasse, Parnell said he would understand. “But I think it’s worth a try to create a competitive environment where more production can be produced,” he said. HB 9 On House Bill 9, a bill moving along work on a small-diameter in-state gas pipeline, Parnell said that if the key provisions in HB 9 don’t pass, “Alaska’s gas line efforts, in my view, will be set back for one to two years.” The governor said he was asking the House and Senate to waive the uniform rules and take up HB 9 where it was when the session ended; both bodies did that April 18. Parnell said he disagrees with House Speaker Mike Chenault on whether the Alaska Gasline Development Corp. needs to come back to the Legislature before a pipeline gets built, and said he’s “not trying to empower AGDC at this moment to go and contract and have an open season and sanction a pipeline; I think we have to have some gates they have to go through where they are held accountable by the Legislature and by the executive.” On the other hand, the governor said he doesn’t agree with legislators who believe AGDC’s “efforts should be killed off.” “I’m not in that camp,” he said, explaining that the state needs alternatives — the large line from the North Slope to markets and the smaller in-state line — because without an option, the process would slow down, as it did under the Stranded Gas Act negotiations “when one party’s negotiations were swept off to the side and ... the process slowed down and the state had no other alternative.” The new bill The governor submitted a new oil tax bill to the House and the Senate April 18, describing it as “a piece of legislation that blends the positions of the House and Senate into a comprehensive approach that will bring economic opportunity to Alaskans for generations to come.” New North Slope oil and gas production is incentivized with a 30 percent exclusion, based on gross value at the point of production or GVPP, from the production tax value used to calculate the base rate and progressivity for the first 10 years of sustained production. This applies to fields not in production or in a unit on Jan. 1, 2008 — which would exclude Point Thomson but include Oooguruk and Nikaitchuq. For currently producing North Slope fields, there is an exclusion, but only from the value used to calculate progressivity: 40 percent of the GVPP would be excluded from the monthly production tax value used to calculate progressivity; progressivity would be capped at 60 percent. The bill also extends tax incentives for well lease expenditures available elsewhere in the state to North Slope activities and allow producers to apply tax credits in one year. The new-oil provision So what would the 30 percent exclusion in calculating base rate and progressivity for the first 10 years of sustained production look like? Senate Finance had PFC Energy model the lifecycle effects for a new small development — a 70 million barrel field with peak production of 10,000 barrels per day at $100 oil. Finance co-Chair Bert Stedman, R-Sitka, said at the April 14 hearing when the proposal was first aired publicly that the “concept of the 30 percent gross revenue allowance was derived out of our previous work on trying to enhance new oil production” with a gross progressivity calculation, and is an approach to incentivizing oil outside of existing developments within the current ACES structure. Gerald Kepes, a partner in PFC Energy and head of the consultancy’s upstream and gas practice, showed models run at the 30 percent gross revenue allowance for new developments at three different development costs: $17 per barrel; $25 per barrel; and $34 a barrel. Kepes said with a $17 per barrel capital cost under the current tax, Alaska’s Clear and Equitable Share or ACES, a lifecycle analysis showed a net present value or NPV of $112 million and an internal rate of return or IRR of 16 percent, with total government take ranging from 67 percent at $60 oil to 75 percent at $100 oil and 79 percent at $150 oil. With the gross revenue allowance of 30 percent applied to ACES, NPV rose to $201 million and IRR to 20 percent; government take ranged from 56 percent at $60 oil to 64 percent at $100 oil and 66 percent at $150 oil. “So it’s a substantial difference for these lower-cost new developments,” Kepes said. Capex of $25 a barrel At development costs of $25 a barrel for the same new development, which Kepes said “is more in line with the costs that we see with these new developments ... away from existing infrastructure,” NPR under ACES would be $24 million and IRR 11 percent, with government take ranging from 68 percent at $60 oil to 75 percent at $100 oil and 79 percent at $150 oil. At the $25 a barrel capital cost with the 30 percent gross revenue allowance, NPV is $121 million and IRR 14 percent, with government take ranging from 51 percent at $60 oil to 62 percent at $100 oil and 67 percent at $150. At a capital cost of $34 a barrel, which Kepes characterized as “among the higher or highest cost rates that we’re looking at,” under ACES NPV is a negative $90 million and IRR 7 percent, with government take ranging from 80 percent at $60 oil, to 77 percent at $100 oil and 79 percent at $150 oil. With the 30 percent gross revenue allowance, NPV on this type of project is a positive $3 million and IRR 10 percent, with government take ranging from 49 percent at $60 oil to 62 percent at $100 oil and 66 percent at $150 oil. Legislators received a letter from 70 & 148 LLC, a partner with Repsol in new developments which have been cited at capital costs of $9 billion over 10 years, expressing “strong support” for passage of the new oil provisions Senate Finance added to HB 276, calling the new field tax changes “exactly what is needed in order to have the oil industry focus on Alaska over other oil producing regions,” but also noting that the company hopes modifications can be made in the tax code “that will make operations within the legacy fields more competitive as well.”

Tax Reform: Who needs it?

Oil tax reform: Who needs it anyway? By Andrew Halcro March 30, 2012: On Wednesday over a thousand Alaskans showed up for a lunch time rally for meaningful oil tax reform. As I looked around the room I asked myself; who are these people and who needs oil tax reform anyway? Honestly, who should care that one in three Alaskan jobs are directly or indirectly related to oil industry. Who should care that those attending the luncheon were engineers, oil & gas subcontractor employees, tele-communication employees, retail store owners, union laborers, freight company employees, trucking companies, construction employees, native corporation employees and more small business owners than you could count? Who should care that oil production is declining, state spending is increasing and by 2020 the Department of Revenue predicts that fifty percent of projected oil production will come from investments yet to be made in a fiscal environment that is currently chasing investment away? Who should care that oil revenues fund everything from classrooms, to courts to cops? Who should care that oil funds organizations like the University of Alaska, which has cultivated professors, whose salaries are paid for by oil revenues, who have been opposing oil tax reform in every major newspaper in Alaska? Who should care that one of those professors got his tail handed to him on this very blog after being caught spreading misinformation to make his case against tax reform? Who should care that the latest proposal by another UAF professor is akin to the Lumpy plan; I'll gladly pay you tomorrow for a hamburger today? And while tax reform opponents use the same Lumpy argument about the producers asking for a tax break today in return for investments tomorrow, over the last six years the legislature has a history of raising taxes retroactively and has proven to be a not so trustworthy bunch when it comes to honoring guarantees. In fact, the state has been the equivalent of a hamburger loan shark. But who should care if the opponents of meaningful tax reform who demand guarantees, are the same ones who told the industry the state didn't need to give guarantees when it came to tax certainty on a $40 billion dollar natural gas pipeline? Think about it. The same lawmakers who are demanding certainty from producers over oil production, are the same ones who refused to grant certainty to the producers for building a $40 billion dollar natural gas pipeline. And who should care that opponents of tax reform have no facts on their side and instead are peddling Alaskans half-truths, revisionist history and down right false information? Who cares that they trumpet oil company profits while bitching about gas prices when the two are mutually exclusive? Who should care? Every Alaskan should care. That's why over one thousand men and women whose job security rests on a healthy oil & gas industry showed up at Wednesday's luncheon rally to support meaningful tax reform. The debate over meaningful tax reform has created a gaggle of opponents who have dug in their heels while offering no legitimate alternatives to boosting production under current tax rates. Furthermore the've purposely glossed over the harsh reality that as oil continues to decline and lawmakers begin dipping into savings, the more state government will be looking at Alaskans pockets to start paying for all the state services they've received for the last thirty years free of charge. The arguments against meaningful tax reform have come from a variety of directions including labor unions who have a vested interest in higher government revenues, hoping they'll translate into more government spending and longtime industry critics like radio mouth Bob Lester who has posted a few videos on You Tube taking a sarcastic look at oil tax reform. And while he talks about "our children's future," he doesn't address that our children will be at risk if production continue to decline thus making investments in education, public safety and roads impossible to keep up with growth and rapidly changing socio-economic demographics. Ironically, Lester is the spokesman for Lithia of Anchorage, an automobile dealership. So with thirty percent of the work force existing due to the oil industry, who does Lester think is buying the trucks and automobiles he hawks on television? I'll tell him. Companies like mine who rent and lease to oil companies and sell cars to Alaskans as well, which in turn generate millions in tax revenues for the state and local governments. Companies like construction contractors who survive off work from the oil industry, and employees who get their paychecks directly and indirectly from employment in the petroleum industry. Those are the folks who are entering showrooms and driving away in shiny new vehicles. Meanwhile in Juneau, a number of red herrings have been caught and mounted by legislative oil tax reform opponents. Audits I n a recent Senate Finance Committee, lawmakers got all twisted up about the fact that the state was behind in their audits. State Senator Bert Stedman (R-Sitka) chastised the Parnell administration for failing to keep current on oil industry audits. Whoa there senator...you should look in the mirror first. On October 6, 2007, during the testimony on ACES, Marcia Davis the former Deputy Commissioner of Revenue under Palin, was asked about the states ability to keep audits current. "We have great auditors, but we just don't have enough of them," Davis told lawmakers. Less than two weeks later, International Oil & Gas expert Pedro Van Meurs was testifying in front of the senate and was asked why the legislature shouldn't raise oil taxes for the second time in two years. Van Meurs responded "You haven't even done you first audit under PPT, so you don't have enough information." Even after these clear warnings that the Palin administration and lawmakers ignored, they went on to pass a tax regime that has confused just about every oil company that does business in Alaska. In Palin's fy08 budget not one dime was requested for auditors, nor did the legislature approve an additional funds after hearing twice during the ACES debate that there were simply not enough auditors. In 2008 after a presentation that highlighted the lack of efficiency in the state's auditing division, Palin requested $24 million for more technology and people, but the senate zeroed out their request. But today, lawmakers like Stedman, who ignored the warnings and then vetoed the request for better analytical tools and more auditors, are hot under the collar that the administration is behind on their audits? Please. After all it's just Alaska's economy we're talking about. Oh and the .92 out of every dollar the oil & gas industry contributes to state employee salaries and retirement benefits, along with a few hundred million that benefit the same professors who oppose oil tax reform. But really, who needs oil tax reform anyway? Alaskans who understand the economy,that's who. Read More :

Arctic OCS reparations

ConocoPhillips files plans for drilling in the Chukchi Sea starting in 2014 By Alan Bailey ConocoPhillips is moving ahead with its plans to drill exploration wells in the Chukchi Sea, starting in the 2014 open water season, Mike Faust, the company’s Chukchi Sea exploration project manager, told the National Marine Fisheries Service’s annual Arctic Open Water meeting on March 8. On March 1 the company filed its Chukchi Sea exploration plan with the Bureau of Ocean Energy Management, Faust said. The agency will review the plan for completeness before publishing it for public review. In February ConocoPhillips filed the corresponding oil spill response plan with the Bureau of Safety and Environmental Enforcement. Devil’s Paw The company’s Chukchi Sea lease positions include two prospects: part of the Burger prospect that Shell plans to drill this year, and the Devil’s Paw prospect. ConocoPhillips has no current plans to drill at Burger but does anticipate drilling one well per year in its Chukchi Sea Devil’s Paw prospect using a jack-up drilling rig, Faust said. Depending on ice and weather conditions, and on drilling progress, it might be possible to drill two wells in a single year, but one well per year is probably a more realistic expectation, he said. “Our plan is to drill one well. We’re going to go out there and be prepared to drill two,” Faust said. In its Devil’s Paw project ConocoPhillips is partnering with Statoil and OOGC, the U.S. subsidiary of the Chinese National Offshore Oil Corp. The Devil’s Paw prospect is located about 120 miles west of the Chukchi Sea coastal village of Wainwright and is about 80 miles from the nearest landfall, Faust said. The prospect is the site of the Klondike well, drilled by Shell into a major Chukchi Sea geologic structure in 1989. Although the Klondike well did not encounter commercial quantities of oil and gas, ConocoPhillips clearly views the geologic setting of the prospect and the results of the Klondike drilling as warranting further investigation at considerable expense. Although previous drilling did not conclusively demonstrate the viability of oil and gas development in the Chukchi Sea, ConocoPhillips believes that there is a good chance of finding the type of very large oil field necessary for commercial success in this remote region, Faust said. “Oil development would lead to significant workforce training opportunities, jobs, careers, increased community investment, and very significant tax revenue for the state and for the (North Slope) Borough,” Faust said, commenting that the necessary supporting onshore pipeline system, for example, would generate property tax revenues. Open water ConocoPhillips will only drill during open water conditions, with the drilling equipment being removed from the drill site should sea ice unexpectedly threaten the drilling operation, Faust said. “We have no plans to drill when there’s any ice on location at all,” Faust said. Based on past ice records, the drilling season should last from mid-July to mid-October, with that October end date allowing time for the drilling of a relief well in the unlikely event of a well blowout — it would likely take about 30 days to drill a well at Devil’s Paw, Faust said. In the interests of anticipating and accommodating any unexpected sea-ice movement, ConocoPhillips has developed an ice alert program, making use of frequently downloaded synthetic aperture radar satellite data to spot ice floes even under a cloud cover or at night. ConocoPhillips plans to use a brand new, state-of-the-art rig, equipped with the latest air emissions equipment and capable of operating in up to four-tenths sea ice cover, even although the rig will not be operating in ice in the Chukchi, Faust said. Ideal location And the location of the Devil’s Paw prospect, relatively far south of the likely summer sea-ice extent and under a water depth of about 160 feet, is especially favorable for a jack-up drilling operation, Faust said. A jack-up rig has huge sliding legs that can be jacked down to the seafloor and then used to lift the rig floor above the maximum height of sea waves. This arrangement creates a stable drilling platform that enables the well blowout preventer and other well control equipment to be located on the rig floor, rather than on the seabed, thus allowing easy access to this equipment, Faust explained. “It’s essentially a land rig sticking up some meters above the sea,” he said. And, being fixed rigidly to the seafloor without the need for propellers to keep it in position, the operation of the rig will be relatively quiet, he said. Capping stack To allow for the possibility of a blowout preventer failure, as happened in the Gulf of Mexico Deepwater Horizon disaster, ConocoPhillips is going to install on the seafloor what is called a “capping stack,” the type of equipment eventually used to seal the spilling Gulf of Mexico well. The approximately 150-ton capping stack, in place from the start of the drilling, with the well string passing through it, will be able to shear through the drill pipe, capping the well at the top of the well casing if necessary, Faust said. “That stack could be triggered from the rig. It could be triggered from a boat,” he said. However, the company does not expect an accident. A well at Devil’s Paw should be very similar in terms of drilling complexity to the more than a thousand wells drilled to date at ConocoPhillips’s Kuparuk River field in the central North Slope, Faust said. “We are constantly drilling this exact same kind of geology,” he said — the three primary drilling engineers working on the Devil’s Paw project have between them more than 90 years of experience. And, with a previous well at the Devil’s Paw location, subsurface conditions are known. ConocoPhillips has also acquired the experience of drilling 50 exploration wells in the Alaska Arctic since 1998, including in some in very remote locations, Faust said. Logistical challenge The logistical exercise of deploying a major Arctic drilling fleet, including all of the necessary oil spill response assets, will be a major challenge, Faust said. At the moment ConocoPhillips is engaged in the detailed planning for the operations and in the procurement of equipment. The company hopes to award all contracts for required vessels and equipment, including the drilling rig, by the end of 2012. “For an operation like this it really does take a couple of years of very detailed planning and a lot of work with all of the different contractors involved,” Faust said. “We have to spend a lot of time planning, ensuring that all of the safety precautions are in place, ensuring that all of the communications and simultaneous activities are really well tied together.” ConocoPhillips has spent much time with North Slope communities and is aware of past concerns expressed by North Slope residents that the oil industry had been moving forward too quickly with offshore development, Faust said. “We’ve really tried to step back and take a paced approach, understand what everyone’s concerns are, address as many of those as we possibly can,” Faust said. “We believe the time is right, now, to step out and actually drill a well.” Environmental studies ConocoPhillips has been involved in offshore environmental studies in the Chukchi Sea since 2006 and is proud of its involvement in the collection of baseline environmental data, Faust said. And in the offshore work that the company has conducted to date there have been no safety incidents and no injuries, he said. During drilling operations marine mammal observers will be stationed on the drilling rig and support vessels, and acoustic recording buoys will detect animals not observed on the sea surface. A monitoring program will determine any impact from permitted discharges from the rig by taking samples from the environment around the rig before, during and after the drilling operations. Some sampling will be done a year after the drilling, although no environmental impact is expected, Faust said. In addition to filing its exploration and spill response plans, ConocoPhillips has filed all of its permit applications for its Chukchi Sea operations, Faust said. The company has also applied for authorizations for the incidental disturbance of marine mammals. “We do believe that it’s appropriate to start working on those applications immediately,” Faust said. “There’s a lot of work that went into building those and we want to make sure that we have a good open dialogue with the agencies, and that … we have those authorizations in hand before we go out and commit hundreds of millions of dollars on equipment.” In early April the company will meet people from the North Slope Borough’s mayor’s office, to go through all of the Chukchi Sea permits in detail — the company will hold similar discussions with any of the North Slope communities that are interested in doing that, Faust said. Petroleum News

Senators iffy on Obama energy promises

By Eric Lidji

The Senate contingency of the Alaska congressional delegation offered faint praise to reassurances that the Obama Administration would include Alaska in its energy strategy.
In a recent speech at the University of Miami about domestic energy production, President Obama said his administration would “make available more than 75 percent of our potential offshore oil and gas resources from Alaska to the Gulf of Mexico.”
“I am heartened to hear the President talk about Alaska and the Arctic when discussing new sources of American-made energy to create jobs and build an economy that lasts,” Sen. Mark Begich, a Democrat, said in a statement following the speech, adding, “It is correct to say we have made significant progress as Shell’s spill response plan for the Chukchi Sea was approved last week, and we are moving ever closer to an active summer of exploration in the Arctic. But more work needs to be done. We need to continue to move forward on efforts for responsible oil and gas development beneath Arctic waters, the National Petroleum Reserve-Alaska and the Arctic National Wildlife Refuge.”
With the public and politicians once again arguing about the cause of rising gasoline prices, Sen. Lisa Murkowski, the ranking Republican on the Senate Energy and Natural Resources Committee, said any solution must include more domestic drilling.
“While I welcome the president’s stated commitment to develop ‘every available’ energy source and his reluctant acknowledgment that increasing domestic production does help reduce prices, many of his recent comments and his administration’s actions have been disappointing to those of us who have long been working to make energy more affordable,” Murkowski said in a statement. “Higher energy prices have been this administration’s policy goal, or at least been acceptable as collateral damage — as evidenced by its support for cap-and-trade legislation, its barrage of EPA regulations, the bureaucratic thicket it forces producers to navigate, and the tens of billions of dollars in tax hikes it’s attempting to impose on those who produce the energy we depend on.”
She said if the administration is “serious” about affordable energy, it should approve the Keystone XL pipeline, open the coastal plain of ANWR and new offshore areas to drilling, and work to streamline the permitting process and reduce costly regulations.

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