Friday, August 31, 2012

Progress made on methane from hydrates

Tim Bradner
Alaska Journal of Commerce

Doyon Drilling’s Rig 14 drilled a BP hydrates test in February 2007 at the Milne Point field on the North Slope. The Mt. Elbert well was a joint BP-U.S. Department of Energy project to drill into a hydrate and extract core samples for analysis and testing.

Government and industry scientists say they are making good progress toward production of methane gas from hydrates, a potentially vast hydrocarbon resource. Methane is the main component of natural gas.

This is still a science project, but knowledge is being gained step-by-step, researchers with the Department of Energy, the U.S. Geological Survey and industry said in interviews with the Journal.

Hydrates are frozen lattice-like structures that form at shallow depths in certain combinations of pressure and temperature offshore or within onshore permafrost areas of the Arctic, including the North Slope. They are capable of holding immense amounts of methane. The question has always been whether methane can be extracted and at rates that are economical to produce.

“It has been only been in the last 10 years, through drilling and coring programs, that we’ve started to get a better understanding of hydrates in their different settings,” said Tim Collett, head of the USGS hydrates program.

This is giving industry more confidence that extracting resources from hydrates might be someday practical, and that it’s not some exotic form of energy, he said.

Some breakthroughs now point toward ways hydrates can be produced. It’s now understood, for example, that the geologic systems that generate conventional petroleum also produce the methane that winds up in hydrates.

“The factors that control the formation of petroleum traps, source rock, migration, a link to sandstone — are all the same as with conventional natural gas,” Collett said. “We know now, for example, that the methane in hydrates in the Prudhoe Bay field leaked out of the Prudhoe and Kuparuk conventional fields, as well as the Ugnu,” heavy oil field.

Another accomplishment, Collett said, is that it has been shown that methane can be produced from hydrates with conventional producing wells and drill rigs.

It has also been demonstrated that production can be done from hydrates in sandstone formations, which is important because sandstone has permeability, allowing the methane to flow.

In contrast, scientists have yet to understand how permeability can be established in the unconsolidated clay and mud formations where most offshore hydrates are commonly found.

Collett said hydrate saturations in sandstones are also typically much greater and therefore more likely to be economically produced than hydrates in the unconsolidated clay and mud.

Production tests

The Ignik Sukumi test well drilled and tested by ConocoPhillips on the North Slope in 2011 and 2012 represented the third production test of methane from a hydrate, and the first to feature testing of methane production initiated by chemical injection followed by depressurization, said Ray Boswell. Boswell heads the hydrates program at the U.S. Department of Energy’s National Energy Technology Laboratory.

In addition to ConocoPhillips, The Japan Oil, Gas and Metals National Corp. and the U.S. DOE were partners in the Ignik Sukumi and contributed funds.

The test well produced for about 30 days.

“Production was erratic at first but stabilized in the last 18 days,” which was encouraging, Boswell said.

The previous sustained hydrate production was from the Mallik well in Canada’s MacKenzie Delta, which flowed about 6 days based on direct well depressurization. There were two separate production tests at Mallik done at different times, making Sukumi well the third test. Boswell said the next step should logically be a longer production test of at least 12 months to 18 months.

Prior to the most recent Mallik test in 2007 and 2008, and the Ignik Sukumi well was the BP-operated Mt. Elbert test drilled in 2007 in the Milne Point field on the Notrh Slope. This wasn’t drilled to test production but to extract core samples for testing and to confirm the ability to even find hydrates through existing seismic data.

An attempt to test production from a hydrate in 2003, Anadarko Petroleum Co.’s Hot Ice No. 1, also on the North Slope, failed because the hydrate that had been predicted wound up not being at the location predicted by seismic.

Following that result, industry and the government agencies stepped up development on seismic procedures to better predict hydrates. The 2007 Mt. Elbert well confirmed those worked — the hydrate was where it was supposed to be, and was even thicker than was predicted. This success was demonstrated again at a larger scale in 2009 in a drilling program conducted by a Chevron group, including the DOE and USGS in the Gulf of Mexico.

Gas hydrate-bearing sands were discovered in accordance with predictions in 6 out of the 7 wells drilled, Boswell said.

Commercializing hydrates

Figuring out how to produce a hydrate commercially is now the challenge.

Temperature and pressure are both factors in hydrate formation, and an initial thought, tested at the Mallik site in 2002, was that the hydrate could be gradually warmed to allow methane to come out, Collett said.

“We looked first at thermal methods but concluded they would require a great deal of energy — you essentially heat the rock around the hydrate — so that brought us to depressurization, which is now the favored approach,” he said.

Depressurization is fairly straightforward because it can be done by drilling into the hydrate and creating a lower pressure zone in the well, just as in any conventional well, said Boswell. The technique was shown to be workable in the Mallik well in Canada.

One complication is that depressurization also has a cooling effect, creating a “freezeback.” Methane can flow briefly but then it freezes up again, Collett said. A solution to this might be a system to provide limited heat right at the well bore to prevent freezing, he said.

More production testing will allow researchers to do the modeling needed to show the right balance. The goal is to control the thermal exchange and predict the rate of gas flow, Collett said.

Meanwhile, ConocoPhillips and the University of Bergen in Norway have developed a third approach — a methane-CO2 “exchange” mechanism. The idea is to inject carbon dioxide into the hydrate so that the C02 molecules replace — and eject — the methane molecules.

The well is then depressurized to enable the released gas to flow. The technique had been demonstrated in the laboratory but ConocoPhillips had been looking for a place to field-test it and chose the North Slope.

What was intriguing about the exchange concept is that the CO2 molecule appears to be preferred by the hydrate over a methane molecule, said, David Schoderbek, ConocoPhillips’ manager for the Ignik Sukumi test.

“This leads us to believe the carbon dioxide hydrate will be more stable than the methane hydrate,” Schoderbek said.

A site for the Ignik Sukumi well was found in the western part of the Prudhoe Bay field. Several hydrate intervals were found by prior industry drilling but only one was tested, a 30-foot-thick zone at 2,200 feet. The gas mixture injected included nitrogen and CO2.

The project was an operational and scientific success, Boswell said.

“We injected nitrogen and C02 as planned without fracturing the formation,” he said. “On subsequent depressurization, we recovered primarily methane with production being very stable over the final two-plus weeks of the test.”

Over the 30-day test, about 210,000 cubic feet of the CO2 and nitrogen mixture were injected in the two weeks prior to the flowback test, and in the following flowback test nearly 1 million cubic feet of methane mixed with some of the CO2 and nitrogen was produced.

“Most of it was methane,” Schoderbek said. “We are encouraged by results but relative to these numbers it is important to remember that the actual field trial tested both exchange and depressurization.”

Boswell said, “We won’t really know what the (production) mechanism was until our analysis is complete — how much of production was due to the exchange and how much from other factors. It’s encouraging but we’re still unsure just what process took place, an exchange or something else. Not all the CO2 came back, so it is likely that there was some exchange.”

An initial analysis won’t be available until the end of the year or early spring, he said.

The C02 exchange has possible advantages over depressurization. One is that it could preserve the hydrate structure, where depressurization essentially dissolves the hydrate. This has implications for preventing surface subsidence where hydrates are shallow, as they are on the North Slope.

Also, exchanging CO2 for methane in the hydrate provides a place to potentially sequester C02. That could be important on the North Slope because the known Prudhoe Bay and Point Thomson conventional gas accumulations contain C02, which must be disposed of when commercial gas production begins.

If Arctic hydrates are to be tested further the work is best done on the Alaska North Slope because of the presence of infrastructure. The Ignik Sukumi and Mt. Elbert wells were both drilled on temporary ice pads but near the all-year road systems and support facilities of the oil fields.

Further testing on temporary pads is still an option the next steps will need a place with year-around access.

Whole lot of hydrates

Hydrates are spread widely across the Arctic in permafrost regions, which cover vast onshore areas of Alaska, Canada’s Mackenzie Delta and Arctic Islands, and Russia.

Where there are sedimentary basins, hydrocarbon source rocks and conventional oil and gas reservoirs overlain by permafrost, it’s likely that methane escaping from the conventional traps will accumulate in hydrates just below or within the permafrost, Collett said.

Hydrates are found offshore on continental shelves. Although the majority of marine hydrate is found at low saturations in the unconsolidated clay and muds, substantial deposits have been discovered offshore Japan, where initial offshore production testing is expected to begin next year, and in the Gulf of Mexico during the 2009 drilling program.

Collett said the understanding gained of the North Slope hydrates from the 2007 test was key to enabling the USGS to make its first assessment of technically-recoverable methane from hydrates in 2008. That assessment indicated 85.4 trillion cubic feet across the North Slope.

Despite the potential, North American markets are saturated with inexpensive shale gas, which dampens the enthusiasm for U.S. producers to tackle a future source of unconventional gas, Collett said.

Given that, Japan, South Korea and India, may lead the next steps with hydrates. Those countries lack domestic oil and gas and are therefore more motivated, he said. DOE and the U.S. Geological Survey hope to stay engaged. It’s probable that at least one North Slope producer would be involved if further tests are done on the Slope, however.

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Doyon to spend $37M on exploration, Nenana test well

Tim Bradner
Alaska Journal of Commerce

A helicopter transports a drill from a staging area at the end of Standard Creek Road overlooking the Minto Flats during the North Nenana seismic program conducted by Doyon Ltd. last winter. The corporation announced Aug. 27 that it would spend $37 million on exploration this year, as well as a second test well in the prospective Nenana basin west of Fairbanks.
Courtesy Doyon Ltd.

Doyon Ltd., the Interior Alaska Native regional corporation, says it will spend $37 million this year on several oil and gas projects in Interior Alaska and will drill second a test well in the prospective Nenana Basin, west of Fairbanks, this winter.

Doyon will also be the first explorer to take advantage of a new Alaska exploration incentive that will have the state pay for 80 percent of the well and extend preferential state tax treatment, Doyon CEO Aaron Schutt said in a Aug. 27 briefing in Fairbanks.

The new well will be Doyon’s second in the Nenana Basin. The first well, Nunivak No. 1 drilled in 2009, found evidence of hydrocarbons but was not a commercial discovery, said Jim Mery, Doyon’s vice president for natural resources.

Doyon is based in Fairbanks.

Permit applications for the ndew well have been made, Mery said. Its location is about 11 miles west of Nenana and about 8 miles west of the Nunivak No. 1 well drilled in 2009, Mery said.

Doyon is also interested in the northern part of the basin following seismic work done there last winter, and more seismic testing is planned for this winter. Applications for permits for two potential wells are being prepared for that area but they will not be drilled this winter, Mery said.

Doyon had four partners in the 2009 well including independents Rampart Energy Co. of Colorado and Minnesota-based Cedar Creek Oil and Gas Co., and two Alaskan firms, Usibelli Energy and Arctic Slope Regional Corp., another Alaska Native corporation.

Those companies have an option to join in on the second well but for now Doyon is proceeding on its own, Mery said.

In the Aug. 27 briefing, Schutt said Doyon’s board has approved $37 million for Interior oil and gas exploration projects this year that include the well and additional seismic in the Nenana Basin as well as seismic exploration in the Yukon Flats basin north of Fairbanks.

“These projects show a lot of promise. If successful, they could provide substantial benefits not just to our shareholders, but also to all Alaskans in terms of jobs and helping alleviate the energy crisis in Interior Alaska,” Schutt said.

The initial target is for natural gas that would serve Fairbanks, about 60 miles east of the exploration site, but there is oil potential as well. Flint Hills Resources operates an oil refinery near Fairbanks and the Trans Alaska Pipeline System, which is operating below its capacity, runs near the city.

The Nenana Basin program is on state-owned lands but in the Yukon Flats Doyon will explore its own lands and lands belonging to nearby village corporations, Mery said. An area near Stevens Village, on the Yukon River, is of particular interest, Mery said. It is also very near the TAPS pipeline, he said.

Doyon and its partners now hold a state exploration license in the Nenana Basin, which gives the corporation rights to explore across approximately 500,000 acres of state lands and to convert some of the license area acreage to leases.

This year Doyon will convert 400,000 acres, most of the land now held under the exploration license, to conventional state leases with seven-year terms.

Besides the Nenana Basin in the Interior the state has issued four other exploration licenses in the Copper River and Susitna River regions, but Doyon is the first to convert areas in the licenses to state oil and gas leases.

Schutt credited the new state incentives with allowing Doyon to proceed with the well. A change in state tax law approved by the Legislature in 2012 extended to Alaska frontier basins special incentives enacted for Cook Inlet three years ago that has now attracted new companies to the Inlet, and that have resulted in new discoveries of natural gas.

The incentives provide for the state to pay directly for 80 percent of well costs and 75 percent of seismic, Schutt said, and also to extend to frontier basins a low state production tax that applies to Cook Inlet rather than a higher tax that applies to the North Slope. That would previously would have applied in frontier basins.

“The recent state legislation expanding exploration incentives and a change in the oil production tax regime in frontier basins including Interior Alaska, were essential for us to move forward with these substantial projects,” Schutt said.

Senate Bill 23, approved by state lawmakers in the 2012 session, included sections creating the new frontier basin incentives.

Schutt gave credit to State Rep. Steve Thompson, R-Fairbanks, and state Sen. Tom Wagoner, R-Kenai, who took the lead in extending the new incentives to the frontier areas.

Thompson, who attended the Doyon briefing in Fairbanks, said, “Doyon is the Interior’s biggest player in oil and gas today and when they talk, we listen. The potential for jobs, lower energy costs and a more positive future outlook is amazing.”

Besides the Nenana Basin the incentives cover the Yukon Flats, the Selawik Basin near Kotzebue where NANA Regional Corp. of Kotzebue hopes to promote exploration, the Copper River basin near Glennallen, and Emmonak, Egegik and Port Moller in southwest Alaska.

Doyon owns about 11 million acres of Interior Alaska lands and its one of the nation’s largest private landowners. It has about 18,500 shareholders, mostly Interior Alaska Athabascan Indians.

Doyon also owns several operating companies including Doyon Drilling, one of state’s major drilling contractors, and pipeline and utility service and operating companies. Besides conducting oil and gas exploration on its lands and state lands, the corporation also has a substantial minerals exploration program underway on lands.

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Thursday, August 30, 2012

Shell drillship to be at Chukchi drill site late Friday

By Tim Bradner
Alaska Journal of Commerce

Shell’s drillship Noble Discoverer is expected to arrive at its Chukchi exploration drill site late Friday. A second Shell drill vessel, the Kuluk, will be near its Beaufort Sea prospect area Sept. 4, a company official said Thursday.
“We still need some time to fuel the Discoverer and to provide provisions, but we expect to start picking up anchors on Saturday or Sunday,” said Pete Slaiby, Shell’s vice president for Alaska.

Slaiby was referring to anchors for the drillship that were set earlier on the sea bottom at Shell’s “Burger A” drill site, its initial prospect in the Chukchi Sea.
Also, Interior Secretary Ken Salazar announced Thursday that the department issued a drilling permit to Shell that would allow the company to begin preparation of the drill site.

That work will include construction of a mud-line cellar for installation of a Blow-Out Preventer, the drilling of a 8.5-inch “pilot hole” to test for shallow gas accumulations, and drilling to the 1,400-foot level with installation of casing.
Salazar said Shell will not be able to drill further to potential hydrocarbon zones until the Arctic Challenger, a specialized spill response barge, completes inspections in a Bellingham, Wash. Shipyard and is on the scene.

Even if Shell can only drill the so-called “top holes” this year, it will consider the season successful. “We got a late start because of ice, but we will have demonstrated a lot of things, mainly that we can work safely,” Slaiby said in a briefing.

Once the barge is on the scene Slaiby said the drillship will have to drill another 6,000 feet, approximately, to reach hydrocarbon zones. Installation of the Blow Out Preventer and drilling to 1,400 feet is expected to take about two weeks. Once the barge is on scene it will take about 7 to 10 days to drill down to the hydrocarbon zone, he said.

Under rules set by the government Shell must stop drilling into hydrocarbon zones on Sept. 24, but well-testing and abandonment work on the well can be done after that, Slaiby said.

The permit issued Thursday is for the Chukchi Sea well only, and no similar permit has been issued yet for the Beaufort Sea well. However, the Kulluk will not begin drilling until after the end of the fall Inupiat subsistence whale hunt in the Beaufort, which has just started, Slaiby said.

The Kulluk will meanwhile wait in a location west of a zone in the Beaufort Sea set aside for whaling activity, he said

Friday, August 24, 2012

Kulluk underway, second drill ship to follow

Tim Bradner
Alaska Journal of Commerce

Shell Oil’s drill ship Kulluk departs Unalaska in this 2011 file photo, en route to a Seattle shipyard for maintenance work. The Kulluk is now underway for the Beaufort Sea after leaving Unalaska Aug. 20. Shell’s second drill ship, the Noble Discoverer, will follow soon for the Chukchi Sea.

Shell Oil’s drill ship Kulluk departs Unalaska in this 2011 file photo, en route to a Seattle shipyard for maintenance work. The Kulluk is now underway for the Beaufort Sea after leaving Unalaska Aug. 20. Shell’s second drill ship, the Noble Discoverer, will follow soon for the Chukchi Sea.

Things are starting to break for Shell.

The drilling vessel Kulluk is now finally en route to the Arctic from Dutch Harbor, and will arrive in the Alaskan Beaufort Sea is about two weeks, Shell spokesman Curtis Smith said.

The second drilling vessel in Shell’s fleet, the Noble Discoverer, will likely depart Dutch Harbor for the Chukchi Sea on the weekend, Aug. 25 or 26, Smith said.

The Kulluk departed Dutch Harbor Aug. 20. It is a conical mobile drill structure built for Arctic offshore drilling that is owned by Shell. The Noble Discoverer is a conventional drillship that has been modified for Arctic summer conditions.

“Once in the Beaufort Sea, the Kulluk will remain on standby until the fall subsistence whale hunt is over,” for Inupiat Eskimo whalers, Smith said.

The Kulluk is being towed by two tugs, the Guardian and the Warrior.

Meanwhile, a spill response barge chartered by Shell to support its drilling is still in Bellingham, Wash., undergoing U.S. Coast Guard and American Bureau of Shipping inspections, Smith said.

“We are making progress with the barge but we are still days away from sailing,” he said.

Completion and final inspections of the spill response barge has been plagued by delays, partly over uncertainties within the Coast Guard and the ABS over the standards to apply to new equipment on the barge for certification, according to marine industry sources speaking on background.

The barge, leased by Shell and retrofitted with spill cleanup and containment equipment, must be on station in the Arctic before Shell can drill and complete exploration wells.

It would be stationed at a location between the two exploration areas in the Chukchi and Beaufort seas. Shell will have to wait until the spill barge is on location and final federal permits are issued before doing any drilling.

“It’s possible we could do mud line cellar work before it (the barge) arrives. That’s something we will seek to confirm with DOI (Department of the Interior). We would not proceed without having that conversation,” Smith said.

Shell hopes to have the barge on location in time to drill completed exploration wells that would penetrate hydrocarbon-bearing zones. The company also plans to drill “top holes,” or partially drilled wells, in other locations to speed the completion of the wells in 2013.

There is uncertainty as to whether Shell could drill the top-holes without the spill barge, however.

“The top hole well (drilling) would be continent on APD’s (Approvals to Drill permits). Whether the containment system would need to be in proximity to the rigs to drill top holes would be up to DOI. We know we can’t drill into hydrocarbon zones without the Arctic Challenger (the spill barge),” Smith said.

Shell has spent over $4.5 billion on its Arctic exploration program since 2007 but has been plagued by setbacks, initially by litigation and then by a revamping of government rules following the Deepwater Horizon disaster.

With the new government rules in place, Shell mobilized its fleet of two drillships and support vessels that exceed 20 ships, but was then delayed by the late breakup of Arctic ice and most recently by the inspection delays on the barge.

The ice is now clearing in areas where Shell wants to drill.

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Wednesday, August 22, 2012

Linc ready for big year; Australian company planning 5 Umiat wells, 3 underground coal gasification wells

Eric Lidji
For Petroleum News

When Linc Energy (Alaska) Inc. makes its second attempt to explore the Umiat oil field this winter, its program will be slightly larger than what it originally laid out last year.

The local subsidiary of an Australian independent still plans to drill as many as five wells this winter at the prospect in the Brooks Range foothills, but in addition to drilling, testing, coring and reservoir analysis, it now also plans to conduct a horizontal well test.

And Linc has set an “aggressive timeline” to bring Umiat online in five to seven years.

The Umiat work comes in addition underground coal gasification exploration in the Cook Inlet and Interior regions and a conventional gas exploration program in Cook Inlet.

Umiat viable without road

After acquiring the Umiat prospect in June 2011, Linc announced its intentions to conduct a multi-well exploration program at the field at the next winter drilling season.

With the onset of winter, though, Linc decided low snow levels in the foothills affected its ability to build a snow road. A snow or ice road is crucial for accessing the remote prospect, some 80 miles west of the trans-Alaska oil pipeline and Dalton Highway.

So Linc delayed its program by one year.

While the 2012 edition is similar the 2011 edition, Linc expects the program to be enhanced by a year of additional technical work, 3-D seismic processing and interpretation, project development and community engagement. In addition to three community meetings in Anaktuvuk Pass and Nuiqsut over the winter and early spring, Linc launched a project specific website,, in April 2012.

This winter, Linc plans to drill as many as three vertical wells — two shallow and one deep — a horizontal well into the Lower Grandstand formation and a disposal well.

The Umiat prospect is one of the white whales of northern Alaska.

The U.S. Navy discovered the field in 1946, during its epic drilling campaign across the National Petroleum Reserve-Alaska. But the field has remained undeveloped because of its remoteness from infrastructure, historically low oil prices and insufficient technology at the time to unlock the shallow oil in a reservoir partially located within permafrost.

With high oil prices and the state considering plans to build an all-season road to Umiat, interest in the prospect increased over the past decade. The small independent Renaissance Umiat LLC announced an exploration program in 2007, but ultimately delayed drilled on numerous occasions before selling the prospect to Linc in mid-2011.

Now, Linc says it is “committed” to developing Umiat, and is studying facilities, pipeline and access scenarios “to determine the best, most efficient, plan for development.” And while a road to Umiat “would have a very positive impact on the Umiat development program,” Linc believes “Umiat could be successfully developed without a road.”

UCG online in five years

Although it hasn’t received as much public attention as its Umiat project, Linc has also been pursuing an underground coal gasification exploration program over the past year.

In late 2011, Linc spud the first hole in its Alaska underground coal gasification program, TYEX01/01X, on the west side of Cook Inlet, less than three miles from the Beluga Power Station. Linc called the results of the 1,450-foot core hole “very encouraging.”

Linc also acquired 2-D seismic over its Interior and Cook Inlet underground coal gasification acreage between September 2011 and April 2012. The company also called those results “very encouraging,” pointing in particular to its acreage in the Interior “where there is very little previous exploration drilling and very few well logs exist.”

Linc plans to drill two more exploration holes on the west side of Cook Inlet this summer and fall followed by one exploration hole in the Interior region, near Healy.

The goal of the program is to target specific sites for future commercialization.

For the upcoming exploration program, Linc commissioned a new, fit-for-purpose rotary-core rig from Buffalo Custom Manufacturing. The dual capabilities allow the rig to “drill at a faster rate and offer greater borehole stability and control than a traditional core rig.”

Linc is aiming to bring synthesis gas production online in Alaska within five years.

Underground coal gasification is a way to “create” natural gas inside coal deposits too deep to mine. The process involves injecting air and water into an ignited coal seam to synthesize the carbon and hydrogen into methane, the main ingredient of natural gas.

Linc announced its underground coal gasification plans as soon as it arrived in Alaska in early 2010, but those plans grew when the Alaska Mental Health Trust awarded the company an underground coal gasification exploration license over three large blocks.

Linc said it currently holds 167,917 acres of exploration licenses.

Waiting on unit decision

And Linc continues to pursue conventional gas targets in Cook Inlet, as well.

While much of the acreage it picked up in March 2010 recently expired after the end of its primary term, the company continues to hold one state and one Alaska Mental Health Trust lease in the Point MacKenzie region north of Anchorage. Linc recently applied to form the Angel unit around those leases and expects to have a decision in August.

The proposed unit is located just southwest of where Linc drilled the LEA No. 1 well in late 2010. Although Linc decided LEA No. 1 couldn’t produce in commercial quantities, “incorporating the data gathered during the LEA No. 1 program into our exploration model resulted in an exciting play development within the proposed Angel Unit.”

Corps’ moving target; Alaska leaders decry potential for further permitting delay on Point Thomson

Wesley Loy
For Petroleum News

The U.S. Army Corps of Engineers says more time might be needed to decide on a permit for ExxonMobil’s proposed Point Thomson development on Alaska’s North Slope.

Since late 2009, the Corps has been considering ExxonMobil’s application for a dredge and fill permit to construct a natural gas condensate development at remote Point Thomson, located about 60 miles east of Prudhoe Bay.

On Aug. 14, the Corps issued a statement on the status of the permit.

The Corps said it remains hopeful it can render a “record of decision” on the permit application by its target date of Sept. 21. However, the timing could change, the agency said.

“The target dates are estimated dates only and are established based on the volume and complexity of information we are reviewing in order to make a decision to ensure we are approving the least environmentally damaging practicable alternative,” the statement said.

The record of decision and permit “may not be complete until as late as Nov. 21,” the Corps said.

‘Bureaucratic foot-dragging’

The Corps issued the statement apparently in response to criticism from Alaska’s governor, Sean Parnell, and its senior U.S. senator, Lisa Murkowski. The two Republican leaders issued weekend press releases decrying what Murkowski’s release termed “bureaucratic foot-dragging” by the Obama administration.
A two-month delay in securing the permit could keep ExxonMobil from starting work in the upcoming winter construction season, they said. That, in turn, could jeopardize the company’s commitment to commencing first production from the field by the winter of 2015-16.

“This unexplained delay threatens to set production at Point Thomson back another year, costing the state of Alaska both jobs and millions of barrels of crude oil that’s urgently needed to boost throughput in the trans-Alaska oil pipeline,” Murkowski said in her Aug. 11 press release.

Parnell sent a three-page letter to Interior Secretary Ken Salazar, asking him to do something about “continued federal permitting delays” on Point Thomson.

The governor noted the Point Thomson project already is a year behind due to Army Corps delays in completing an environmental impact statement.

Parnell and Murkowski said they don’t want a repeat of the long permitting delays ConocoPhillips experienced on its CD-5 oil development in the National Petroleum Reserve-Alaska.

Exxon’s measured response

ExxonMobil spokesman David Eglinton on Aug. 15 provided Petroleum News this statement by email:
“U.S. Army Corps of Engineers approval is critical to progressing the project work required to put Point Thomson into production during winter 2015-16. We continue to work closely with the U.S. Army Corps of Engineers to provide requested information to support its work required for a final decision to allow Point Thomson construction to proceed. We will assess any schedule impacts following the Corps of Engineers’ final decision.”

The Point Thomson field is on state land along the Beaufort Sea coastline, adjacent to the Arctic National Wildlife Refuge.

State officials have pushed for its development for decades, and in March signed a legal settlement with ExxonMobil and its partners laying out a development schedule.

The initial project involves development of three well pads and gas-handling facilities, as well as a 22-mile pipeline. First production is expected to be 10,000 barrels per day of liquid condensate.

Point Thomson development will require billions of dollars in investment, ExxonMobil has said.

The company is working on multiple fronts to permit the site construction and pipeline, and to arrange the many contractors needed for the job. Generally, construction on the North Slope must be done in winter when the fragile tundra is frozen.

What should go where?

ExxonMobil is operator of the Point Thomson unit, with other major stakeholders including BP and ConocoPhillips.
Whether ExxonMobil will get the permit isn’t the issue; it probably will.

The question is what conditions will be attached. Specifically, it appears final decisions have yet to be made on placement of certain well pads, pipelines, roads and other features.

A number of scenarios were offered in the massive final EIS the Corps released July 27.

Because the majority of the Thomson Sand reservoir is beneath the Beaufort Sea, offshore development would maximize access. But such an approach was ruled out because of the added environmental risk and the availability of long-reach drilling technology, allowing for wells drilled from onshore pads, the EIS said.

ExxonMobil prefers placing the pads right on the coastline, and the state concurs. But some federal officials favor pushing some of the pads and other infrastructure inland.

While the Army Corps is the lead permitting agency for Point Thomson, two other federal agencies have been providing input — the Fish and Wildlife Service and the Environmental Protection Agency.

“In evaluating the proposed project under the Clean Water Act, we are committed to making a decision that balances protecting aquatic resources with reasonable development,” the Corps said in its Aug. 14 statement.

ExxonMobil has provided “some conceptual alternate location maps and figures” that weren’t in its permit application, the Corps said. The plans “depict a geographic shift” of the project’s east and west pads away from the coast “in an attempt to meet agency environmental concerns.”

In his letter to Salazar, Parnell wrote: “The Corps has received agency input on the Point Thomson project for almost three years. Any major amendments to the proposed project should not happen during the last stages of the permitting process.”

He asked the secretary to “exercise your authority to improve and coordinate permitting” of Alaska energy projects.

The Corps cautioned it was addressing many issues on the large Point Thomson proposal, and “target dates may move” on making a permit decision.

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Saturday, August 18, 2012

State to hold North Slope oil and gas lease sale on Nov. 7

Alaska Journal of Commerce

The Alaska Department of Natural Resources will hold its annual sale of oil and gas lease tracts in the Beaufort Sea, North Slope, and North Slope Foothills on Nov. 7.

The lease sale area encompasses 14.7 million acres, an area the size of Massachusetts, Vermont, and Connecticut combined. The lease sale’s terms and conditions – revised last year to encourage timely exploration and production from state land – remain unchanged from last year. The 2011 lease sale netted more than 300 bids for North Slope and Beaufort tracts, with a total high bid value of $21 million.

“This is a great opportunity to increase investment and responsible resource development in Alaska,” said DNR Natural Resources Commissioner Dan Sullivan. “We will be working hard to promote this lease sale to potential investors,” he said.

The hydrocarbon potential of state, federal, and private lands in the North Slope region – both onshore and offshore – is enormous. Approximately 40 billion barrels of conventional oil and more than 200 trillion cubic feet of conventional natural gas remain untapped, according to federal estimates of undiscovered, technically-recoverable resources. The region also is estimated to contain tens of billions of barrels of unconventional oil – heavy, viscous and shale – and hundreds of trillions of cubic feet of unconventional gas. The U.S. Geological Survey recently estimated that the North Slope’s undiscovered, technically-recoverable shale resources could be as great as 2 billion barrels of oil and 80 trillion cubic feet of gas.

Similar to last year, the state’s Nov. 7 lease sale will include tracts adjacent to federal acreage in the National Petroleum Reserve-Alaska. The Bureau of Land Management oil and gas lease sale is tentatively set for Nov. 7.

Bids must be received no later than Nov. 5 at 4 p.m., Alaska Standard Time. The public bid opening will begin at 9 a.m. on Nov. 7 at the Dena’ina Civic and Convention Center in downtown Anchorage. For more details regarding the lease sale, visit the Division of Oil and Gas website at

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Gas for CINGSA may be Japan-bound

By Tim Bradner
Alaska Journal of Commerce

Natural gas that could help keep Alaskans warm this winter could be exported to Japan as liquefied natural gas, although it’s not yet certain.

A contract dispute has impaired gas supplies for the new $180 million gas storage facility being developed on the Kenai Peninsula, the operator of the facility, Cook Inlet Natural Gas Storage Alaska, or CINGSA, said Friday.

The producer — which has been identified as Marathon Oil Co. — may instead be sold to Japan as LNG for higher prices, CINGSA said in an Aug. 13 letter the company wrote to the Regulatory Commission of Alaska.

Marathon had committed gas to the facility in 2011 to be used as “pad gas” to provide pressure for gas withdrawals, but says now it will not provide the gas, leaving CINGSA short of the supply it needs to operate efficiently, said John Sims, spokesman for CINGSA.

Marathon signed a contract in March 2011 to supply 3.24 billion cubic feet but gnow asserts that the contract is only an option and that it has no obligations to actually supply the gas.

“CINGSA disagrees with this contention,” Dieckgraeff wrote to RCA.

A Marathon spokesman was unavailable for comment on Friday.

“We have obtained gas or commitments of gas for 5 billion cubic feet and we are actively seeking to purchase 2 billion feet in addition,” Sims said.

Seven billion cubic feet of pad gas is needed to provide enough pressure for withdrawals of stored gas to be done efficiently. The facility can operate with less pad gas but its performance will not be optimal.

Alaska utilities that have contracted for gas storage and who will need the gas this winter are concerned. Brad Evans, CEO of Chugach Electric Association, said his association, the state’s largest electric utility, is an anchor customer for the gas storage facility. Having sufficient pad gas to pressurize the storage reservoir is critical for Chugach and other utility customers being able to withdraw gas at rates they will need during cold weather, Evans said in an interview with the Journal.

Evans said the facility can operate with less pad gas but its performance will not be optimal.

Lee Thibert, Chugach vice president for planning, said the utility will need to withdraw about 30 million cubic feet per day this winter to meet its needs for gas-fired power generation.

The storage facility, located near the city of Kenai, is designed to hold a maximum of 11 billion cubic feet. The facility has five wells for both injection and production of gas. It is located within the Cannery Loop gas field, which is operated by Marathon Oil.

Besides Chugach Electric, Anchorage's city-owned Municipal Light and Power, Chugach Electric and Enstar Natural Gas, the regional gas utility, are CINGSA customers, which is owned by Enstar's parent, Michigan-based Semco Energy, and Mid American Energy Holdings.

CINGSA is a regulated storage facility and must report any changes that will affect its operation to the state regulatory commission.

ConocoPhillips Alaska, which operates the LNG export plant at Kenai, said it cannot comment on the matter.

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Tuesday, August 14, 2012

Army Corps delays Point Thomson decision until November

Tim Bradner
Alaska Journal of Commerce

The U.S. Army Corps of Engineers has delayed its record of decision and final approval of the environmental impact statement for the ExxonMobil-led Point Thomson gas cycling and condensate production project to at least Nov. 1.

Construction this winter on the project could be in jeopardy. Previously the Corps had a target date for the ROD in September.

“This is just an estimated date, as was the earlier target date,” Corps spokeswoman Pat Richardson in a statement Aug. 10. “The dates we estimate for a Record of Decision are just that – target estimates. With a permit application this large with an associated EIS and many issues to address, our target dates will move, as they have with this proposed project.”

Alaska U.S. Sen. Lisa Murkowski and Gov. Sean Parnell criticized the U.S. Army Corps of Engineers for delaying the record of decision.

Parnell is asking Interior Secretary Ken Salazar in intervene with the Corps to keep the project on schedule.

Point Thomson is a large gas and condensate discovery 60 miles east of Prudhoe Bay. ExxonMobil and other leaseowners, BP and ConocoPhillips, plan a gas cycling and condensate production project. ExxonMobil, BP and ConocoPhillips, the owners, are planning a project to recycle gas and produce 10,000 barrels per day of liquid condensates in the first phase of a development project.

The condensates would be moved to Prudhoe Bay by pipeline and mixed with crude oil in the Trans Alaska Pipeline System.

Beginning construction this winter is necessary for the project to be complete and in production by 2016, ExxonMobil told a state legislative panel in Anchorage a few weeks ago.

"This unexpected delay threatens to set production at Point Thomson back another year, costing the state of Alaska both jobs and millions of barrels of oil that is needed to boost throughput in the trans-Alaska oil pipeline," Murkowski said in her statement.

A 500-page environmental impact statement for Point Thomson was finalized in late July and Corps officials said then they would approve the record of decision, the final step in the EIS, in 30 days, Murkowski said in her statement. A Murkowski staff member in Washington said the senator will attempt to meet with the Corps to urge action on the ROD.

Murkowski is the ranking minority member on the Senate Energy and Natural Resources Committee.

ExxonMobil itself was cautious in its response.

“We decline to speculate on the date of issuance of the Record of Decision and the impact, if any, on the project schedule. We are working closely with the U.S. Army Corps of Engineers to provide information requested to support its work to enable issuance of the Record of Decision,” an ExxonMobil spokesman said in a statement.

However, in recent briefings to state legislators in Alaska, ExxonMobil expressed concern about delays in the ROD and final approvals of federal permits tied to the EIS if those are pushed too far into late autumn because the delays could affect the winter construction season, which is vital to keeping the project on track for a startup in 2016.

The company has told congressional staff in Washington, D.C., that it needs the ROD and permits in October, at the latest, to allow time to mobilize contractors and get an ice road under construction to Point Thomson, which is about 60 miles east of Prudhoe Bay on the North Slope.

Other work planned for this winter include an airstrip, gravel roads and installation of vertical support members for a 22-inch pipeline.

Parnell wrote a letter to Salazar Aug. 11 asking for help because of the Interior Secretary's initiative to improve the performance of federal permitting on energy projects in Alaska.

"As the lead federal agency, the Corps had recently committed to issue the ROD by Sept. 21. On August 1 senior state of Alaska officials were given assurances by senior Corps and Department of the Interior officials that the Corps' Alaska District would meet that deadline," Parnell said in the Aug. 11 letter to Salazar.

"State officials have been working hard over the past two years in processing approximately 100 state permits required for the Point Thomson project. The state remains ready to issue these permits as early as next month, enabling construction this winter. If the Corps does not issue its ROD on of near the original target date of September another winter construction season will be lost," Parnell wrote.

The Point Thomson gas and condensate discovery was made in the 1970s but its development was delayed due to lack of a natural gas pipeline. ExxonMobil more recently developed the plan to produce the gas, strip liquid condensates, reinject the gas and then ship the liquids to TAPS through the new 22-inch gas pipeline.

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Monday, August 13, 2012

Murkowski slams NPR-A plan, conservation groups pleased

Tim Bradner
Alaska Journal of Commerce

Interior Secretary Ken Salazar announced Aug. 13 he has chosen a preferred alternative for a land management plan for the 23-million-acre National Petroleum Reserve, although details of the plan remain sketchy.

The newly-proposed “Alternative B-2” management plan would open 11 million acres of the reserve to oil and gas leasing but would also place 13 million acres in special conservation areas, Salazar said. A pipeline crossing of a special use area or other industry activity is not prohibited, he said, but will be subject to special stipulations to protect the uses of the special areas.

“Our plan will not foreclose a pipeline, but when one is proposed it will have to go through the full regulatory process including an environmental impact statement,” the Secretary said.

The Interior Department has been considering several alternatives for managing the reserve, one an Alternative A continues the status quo; a second, more environmentally restrictive Alternative B that establishes large special conservation areas; an Alternative C that is less restrictive, and an Alternative D that essentially opens all of the reserve to oil and gas development.

Until Monday the department had not selected a preferred alternative. The new B-2 plan is now the preferred one, Salazar said. It combines elements of the other plans, but Salazar did not provide details Monday.

The preferred alternative will now be incorporated into a final environmental impact statement for the NPR-A. Salazar’s final approval of the EIS is expected in December, U.S. Bureau of Land Management Director Bud Mike Pool said at the briefing.

“In the next few weeks we will be meeting with the state of Alaska, the North Slope Borough and other concerned Alaska stakeholders to go through the details,” Salazar said.

A major concern for the state and Shell Oil, which plans exploration drilling in the Chukchi Sea, is whether the new management plan will create difficulties in securing a pipeline right-of-way across the reserve.

Alaska Sen. Lisa Murkowski was quick to criticize the plan.

“The administration has picked the most restrictive management plan possible. The environmentally-sensitive Teshepuk Lake area was already under a 10-year deferral for additional study, but this (new) alternative goes vastly beyond that, putting half the petroleum reserve off limits. The decision denies U.S. taxpayers both revenue and jobs at a time when our nation faces record debt and unemployment,” Murkowski said in a statement.

Conservation groups praised the alternative, however.

“If adopted, the preferred management strategy would protect the calving grounds of the Teshepuk Lake and Western Arctic caribou herds,” the Wilderness Society said in a statement issued Monday. “Essential nesting habitat for thousands of shorebirds, molting habitat for geese, and coastlines used for walrus haul-outs and polar bear dens would not be developed under this plan.”

The Audubon Society voiced similar sentiments.

“The Secretary’s plan shows that Americans can protect nature even on lands designated for energy production. It would be a great victory for birds, wildlife and common sense,” Audubon president David Yarnold said in the statement.

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Shell still waiting for completion of work on Arctic Challenger

—Alan Bailey

The bulk of Shell’s Arctic drilling fleet remains on hold in Dutch Harbor in the Aleutians while the company waits for the completion of modifications to its Arctic Challenger containment barge and U.S. Coast Guard certification of the modified vessel.

Shell spokesman Curtis Smith told Petroleum News in an Aug. 8 email that construction on the barge was nearly done. Meantime, three vessels from Shell’s fleet — the Aiviq, Shell’s new ice-capable anchor handler, the Fennica, the icebreaker carrying the company’s new well capping stack, and the icebreaker Tor Viking — headed north from Dutch Harbor early in August to start preparations for drilling at one of Shell’s Chukchi Sea drilling sites.

Shell had originally planned to move its fleet north to the Chukchi in early July, but exceptionally heavy sea ice in the region of its drilling locations coupled with delays in the completion of modifications to the Arctic Challenger have delayed the start of the drilling project.

“Sea ice is still bordering our Chukchi prospects and is still quite persistent in the Beaufort,” Smith said in his Aug. 8 email.

Because of the delays, Shell says that it is scaling back its drilling plans to just one well in its Chukchi Sea Burger prospect and one well in its Beaufort Sea Sivulliq prospect this year — the company had planned to drill up to three wells in the Chukchi and up to two wells in the Beaufort. However, the company plans to drill the top-hole sections of some additional wells, to gain a head start on next year’s drilling program.

Arctic Challenger

Shell contractor Superior Energy is retrofitting the Arctic Challenger in Seattle with Shell’s new Arctic oil containment system, designed to gather oil from a leaking wellhead in the unlikely event of a subsea well blowout. Upon completion of the modifications, the barge will require Coast Guard certification, to ensure that the vessel can be operated safely for its intended purpose. Following an agreement with the Coast Guard in July, the Coast Guard is applying the safety standards for a mobile offshore drilling unit for the certification.
Approval of Shell’s drilling permits by the Bureau of Safety and Environmental Enforcement is apparently contingent on certification of the containment barge.

In an Aug. 6 email Cmdr. Christopher O’Neil of the U.S. Coast Guard told Petroleum News that a stability test of the vessel was successfully completed on Aug. 2 and that the Coast Guard was evaluating the results. Certification of the vessel involves verifying about 400 inspections and review items relating to factors such as the design, construction and installation of safety, structural, electrical and other systems and subsystems, O’Neil said. The timeline for the certification depends on how quickly Shell, Superior Energy or the shipyard can furnish the necessary information to the Coast Guard, as the work on the vessel is completed, O’Neil said.

“The Coast Guard cannot speculate as to how long it will take for the Arctic Challenger to receive a certificate of inspection. What I can tell you is that we continue to provide marine inspectors to attend the vessel as construction and systems are completed and made ready for our inspection,” O’Neil wrote, adding that the Coast Guard’s prime concern is the preservation of life at sea.

Air permits

Before Shell can start drilling in the Chukchi Sea the company also needs approval by the Environmental Protection Agency of requested modifications to the air permit for the Noble Discoverer, the drillship that the company plans to use for its Chukchi Sea wells. EPA has yet to announce any decision on Shell’s request. The agency has said that changes to the permit require a public review but Shell has said that it is working with the agency to obtain a compliance order, enabling the company to continue with its 2012 drilling pending a full review of the permit. Apparently the requested changes do not cause the total emissions from Shell’s operations to exceed permitted levels.

The requested permit changes include an increase to the permitted emissions of particulates from the engine exhaust of the Nanuq, Shell’s purpose-built, ice-capable oil spill response vessel. On Aug. 6 Shell told EPA that, although Shell is requesting an increase to the particulate limit for the Nanuq, recent testing has shown that a smaller increase is required than originally thought.

Shell has also requested some changes to the air permit for the Kulluk, the floating drilling platform that the company plans to use in the Beaufort Sea. However, under the terms of the Kulluk permit, Shell can use the vessel while EPA is reviewing the change request.

Major upgrades

In 2010 Shell spent around $25 million upgrading the Noble Discoverer’s exhaust systems, to reduce the vessel’s air emissions. And in June the company completed a $100 million upgrade to the Kulluk. The Nanuq was purpose built for Shell’s Arctic operations in 2007.

In its application to modify the Noble Discoverer air permit Shell said that it had conducted hundreds of tests on emissions units in the vessel and its support fleet since the issue of the permit and that those tests had revealed issues that warranted additional explanation or permit revisions.

Sunday, August 12, 2012

TOTE will convert to LNG in deal with EPA on emissions

Tim Bradner
Alaska Journal of Commerce

The M/V Midnight Sun serving Anchorage and owned by Totem Ocean Trailer Express is seen at the Port of Tacoma. TOTE will be filling its ships with LNG in Tacoma within four years under a deal signed with the EPA.

Totem Ocean Trailer Express Inc., or TOTE, will convert its two large ocean cargo vessels to use liquefied natural instead of conventional bunker fuel, the first such conversion for large general cargo vessels in the U.S. maritime industry.

Liquefied natural gas tankers, such as those that call at ConocoPhillips’ LNG plant at Kenai, have used LNG as fuel for years but general cargo and other marine vessels have been fueled by conventional bunker fuel and diesel.

TOTE’s decision is part of an agreement with the U.S. Environmental Protection Agency on a waiver for TOTE from new emissions requirements that went into effect Aug. 1.

The waiver will exempt TOTE from the requirements until September 2016, to allow the conversion of the company’s two Orca-class cargo vessels, TOTE president John Parrott said Aug. 6.

TOTE operates the vessels on scheduled service from Tacoma, Wash., to Anchorage, a distance of 1,400 miles each way and 2,800 miles round-trip. They are both 840 feet in length. The ships will be able to carry enough LNG in on-board tanks to make a round-trip from Tacoma, Parrott said.

“Our two vessels are already the ‘greenest’ ships in the U.S. domestic fleet,” Parrott said in separate statement. “When they were delivered in 2003 they were purpose-built to serve the Alaska market and exceeded all regulatory and environmental standards. Post-LNG conversion, the Orca vessels will again set a new standard for environmental responsibility.”

EPA imposed the new rules requiring use of low-sulfur fuels effective Aug. 1 on ocean shippers and cruise ships in an Emissions Control Area that extends from the U.S. west coast to Alaska and 200 miles offshore. The requirement is for vessels to use fuel with no more than 1 percent sulfur as of Aug. 1, and 0.1 percent sulfur after 2015.

Parrott said the estimated capital cost of for conversion of both vessels is $80 million. Each vessel has six engines, four main engines and two auxiliary engines.

TOTE has signed a preliminary agreement with an LNG supplier but Parrott said he could not identify the firm at this time. The plan calls for a small gas liquefaction plant at the Tacoma port, and for the LNG to be delivered to the ships by barge.

“The shoreside LNG infrastructure planned to support the new fuel systems will help other transportation industries in Puget Sound follow TOTE in converting to LNG. This could result in a significant increase in air quality throughout the Puget Sound region,” Parrott said.

Parrott said the use of LNG as fuel will not affect the operations of the ships, including their speed and schedules to and from Alaska. The vessels are rated to cruise at a 24-knot speed but typically operate at about 22 knots on average.

TOTE currently uses a heavy high-sulfur fuel in its two vessels. Prior to the LNG agreement the company had planned to use a blend of its heavy oil with ultra-low sulfur diesel made by refiners for trucks and heavy equipment onshore to meet the requirements.

The blending would have required special handling by fuel suppliers and would have added about 25 percent to fuel costs, Parrott said in a previous interview. That would have translated to about an 8 percent increase in general freight rates.

Parrott could not estimate how the capital cost of the LNG conversions could affect rates because capital costs are handled differently than operating cost increases, such as those for the higher fuel costs had the special fuels been required.

It cannot be assumed that a capital cost will increase rates, Parrott said. As an example, when TOTE made the $320 million investment in the two new ships there was no significant change in rates, he said.

Read more:

Sunday, August 5, 2012

With jack-up, Buccaneer Energy getting busy in Cook Inlet

—Eric Lidji
Petroleum News

With a flurry of announcements over the span of one week, Buccaneer Energy Ltd. made big steps toward several wells its hopes to drill in the Cook Inlet by the end of the year.

First, the Australian independent said its jack-up rig is currently en route to Alaska, allowing the company to drill an initial exploration well at one of its offshore Cook Inlet units in the late summer and early fall. Second, Buccaneer said it expects to close on its purchase of the offshore Cosmopolitan prospect in mid-August, giving it another location for the rig later in the year. Third, Buccaneer said newly processed seismic information suggests its onshore Kenai Loop prospect might be larger than previously thought.

But Buccaneer is now also asking the state for an extension to its offshore drilling commitments at one unit, allowing it to push back the drilling deadlines by a year.

The jack-up rig, called Endeavour — Spirit of Independence, left Singapore July 31 on the Kang Sheng Kou heavy lift vessel, according to Kenai Offshore Ventures LLC, a joint venture between Buccaneer and the Singapore marine company Ezion Holdings Ltd.

“We are very excited to finally have the Endeavour on its way to the Cook Inlet. We spent a significant amount of time and effort outfitting the Endeavour to make it ‘fit for purpose’ for work in the Inlet, and once it’s on station will stay for years to come, providing the citizens of Southcentral Alaska with the key to unlock the vast amounts of oil and gas locked in the Cook Inlet,” Jim Watt, president of Buccaneer Alaska, the local subsidiary responsible for Alaska exploration and development work, said in a statement.

Kenai Offshore Ventures purchased, modified and mobilized the rig through a public-private partnership with the Alaska Industrial Development and Export Authority.

“We are proud to be a partner in this project, pleased that all the work to ready the Endeavour for its mission in Alaska waters is done, and very happy it is on its way,” AIDEA Board Chairman Hugh Short said in a statement. “This is a landmark day in our efforts to help secure long-term energy supplies for Alaskans.”

Buccaneer plans to use the rig for as many as two offshore wells this year, and Kenai Offshore Ventures wants to eventually make the rig available to third parties in Alaska.

Buccaneer expects the journey across the Pacific Ocean to take between 21 and 28 days.

Summer plans unfolding

Upon arriving in Cook Inlet, the rig will be towed to North West Cook Inlet, an offshore unit situated along the northern and northwestern boundary of the North Cook Inlet unit.

Buccaneer also operates a second offshore unit in the Cook Inlet, the Southern Cross unit located further to the south, between the Granite Point and Trading Bay oil fields.

Under its unit agreements, Buccaneer must drill one well each at North West Cook Inlet and Southern Cross by Sept. 30, 2012 and a second well at each by Sept. 30, 2014.

While Buccaneer expects to meet the Sept. 30 deadline for its first North West Cook Inlet well, it recently asked the Alaska Department of Natural Resources to extend its deadlines at Southern Cross by one year. With the extension, Buccaneer would have until Sept. 30, 2013 to drill the first well and until Sept. 30, 2015 to drill the second well.

In its request, Buccaneer said “unavoidable delays have prevented execution of drilling activities this year, but allowed for tremendous improvements” to the jack-up rig.

Specifically, Kenai Offshore Ventures decided to perform additional upgrades beyond the work it initially expected to do to make the rig suitable for operations in Alaska waters.

Those additional upgrades included adding lifeboat capacity on the rig to meet new federal safety regulations and work to extend the certification of the rig with the American Bureau of Shipping. But they also included improvements allowing Endeavour to be used as a standby rig for exploration work in the Beaufort and Chukchi seas and pushing up work planned for next winter to accommodate the drilling at Cosmopolitan.

With the Oct. 31 seasonal deadline for companies to stop drilling in the upper Cook Inlet, to avoid sea ice, Buccaneer said it would not be able to drill at Southern Cross this year.

Further, the company told the state in its request, “there is no other jack-up drilling rig available in Alaska waters for Buccaneer to drill at Southern Cross this year.”

Through a predecessor company, Furie Operating Alaska LLC brought the Spartan 151 jack-up rig to Cook Inlet last year, but is currently using the rig at its offshore prospects.

Buccaneer said it has “had some positive discussions” with state officials and “feels the request will be viewed in a positive light” because of its efforts to bring a jack-up rig to Alaska. The company said it expects a formal decision sometime in mid to late August.

Cosmopolitan close to closing

Buccaneer expects to complete drilling at North West Cook Inlet in early November and move Endeavour south to ice-free waters to begin drilling at the Cosmopolitan prospect.

Buccaneer and a privately owned firm out of Fort Worth, Texas called BlueCrest Energy II, LP announced plans in February to buy the oil and gas prospect from Pioneer Natural Resources Alaska Inc., but as of late July the companies had not yet closed on the deal.

Since February, BlueCrest requested and received two extensions to close the deal, according to Buccaneer. The most recent extension gives the companies until Aug. 14.

Under the proposal, BlueCrest would acquire a 75 percent working interest in the two leases off the coast of Anchor Point in the southern Kenai Peninsula. Buccaneer would acquire the remaining 25 percent interest and also become operator of the prospect.

The companies have not disclosed the value of the deal.

Buccaneer recently announced it had secured financing for its share of the deal.

Buccaneer also said it has been “working with third parties who have expressed an interest in the Cosmo transaction and who have substantial financial capabilities.” These third parties “confirmed that they would like to proceed and fund the acquisition of the remaining 75 percent working interest if BlueCrest is unable to proceed to settlement.”

“More efficient development”

Although Cosmopolitan contains known oil and gas accumulations, the two previous leaseholders, ConocoPhillips and Pioneer, both gave up on the prospect within the past decade because their estimates of its resource potential didn’t justify development.

But because Buccaneer and BlueCrest are much smaller companies than ConocoPhillips and Pioneer, they may be able to make an economic case for developing the prospect.

Pioneer previously estimated Cosmopolitan could contain between 30 million and 50 million barrels of oil and would average 3,000 barrels per day over its 30-year field life.

Buccaneer is currently quoting similar figures.

Using previous drilling, testing and seismic data, Buccaneer estimates Cosmopolitan contains some 31 million barrels of proved oil reserves. It also estimates the prospect could hold as much as 55.2 million barrels of oil equivalent of proved and probable reserves (broken down as 44 million barrels of oil and 90 billion cubic feet of gas).

Although working with similar estimates, Buccaneer believes its jack-up rig provides “a more efficient development plan than was previously available to Pioneer.”

First, Buccaneer can now drill all wells — production and injection — from offshore locations, rather than directionally from an onshore pad. Second, Buccaneer claims the shallower gas reserves at Cosmopolitan can only be reached by offshore drilling.

Buccaneer is planning a two-pronged development at Cosmopolitan. It plans to use its jack-up rig for shallow gas development between 3,000 and 4,000 feet deep, and directional wells started onshore for deeper oil development between 6,000 to 8,000 feet.

The well planned for this winter would target both zones.

Kenai Loop ready to go

As it works to finalize permitting and logistics for its offshore program starting later in the summer, Buccaneer expects to spud the Kenai Loop No. 4 well in early August.

While noting that all permits are in place and the Glacier No. 1 rig is on site, Buccaneer said it couldn’t pin down a precise spud date until it finalizes a bottom-hole location.

Buccaneer is drilling Kenai Loop No. 4 from an existing pad. It expects the 11,000-foot well to take between 35 and 40 days to drill, followed by 10 additional days of testing.

Although it had permits and equipment in place by late June, Buccaneer decided to hold off on drilling until it incorporated data from a recent 3-D seismic acquisition of the region into the geologic model it built from two Kenai Loop wells it drilled in 2011.

Having processed that seismic, Buccaneer now believes the producing formation at Kenai Loop is larger and contains more hydrocarbon anomalies than it originally thought.

The shoot covered a 23.4-mile area over the prospect and focused on two producing Tyonek sands — at 9,700 and 10,000 feet — around the Kenai Loop No. 1 well.

Based on preliminary results, Buccaneer now believes the aerial extent of Kenai Loop stretches 840 acres — or 1,680 acres, if both zones are considered separately.

In a previous assessment based on an aerial extent of 340 acres, Ralph E Davis Associates, Inc. estimated the Kenai Loop prospect contained 31.5 billion cubic feet of proved gas reserves and 38.3 billion cubic feet of proved and probably gas reserves.

Buccaneer said its early analysis also identified “11 new seismic hydrocarbon anomalies from stacked pays in the shallow Sterling and deeper Tyonek formations,” but said it planned to have these reviewed by third parties before finalizing future drilling plans.

The 9,308-acre prospect is adjacent to the northern border of the Cannery Loop unit on the northern Kenai Peninsula. Buccaneer recently applied to form a unit over its leases.

Buccaneer brought the Kenai Loop No. 1 well online in mid-January.

Producing at a rate of 5 million cubic feet per day, Kenai Loop No. 1 generated $2.8 million in gross revenue for Buccaneer in the second quarter, according to the company.

Friday, August 3, 2012

TransCanada again solicits interest, includes LNG export project

Tim Bradner
Alaska Journal of Commerce

TransCanada Corp. is holding a non-binding solicitation of interest in an Alaska gas pipeline and liquefied natural gas project, the company announced July 30. Indications of interest in shipping gas will take place from Aug. 31 through Sept. 14.

TransCanada is soliciting interest in both a land pipeline to Canada or an Alaska pipeline to an LNG export project in the latest solicitation. An open season held in 2010 did not result in enough interest to move forward with a project, which at that time involved a main focus on an overland pipeline from the Alaska North Slope to Alberta but also included the option of a pipeline to an LNG project.

“The solicitation of interest is being conducted to identify parties potentially interested in making future capacity commitments on a pipeline system from the Alaska North Slope to a gas liquefaction terminal at a tidewater location in southcentral Alaska or to an interconnection point near the border of British Columbia and Alberta in Canada,” according to the TransCanada statement.

The solicitation is being done under the company’s contract with the state of Alaska to work on a major gas project. Contract terms require TransCanada to solicit interest from potential gas shippers every two years.

In other gas pipeline developments, state Natural Resources Commissioner Dan Sullivan told a state legislative committee on July 30 that major North Slope producers appear on track to provide details of a plan for a large-diameter pipeline and LNG export project to Gov. Sean Parnell by Sept. 30.

Sullivan said significant progress has been made on the gas project in the last year.

“A year ago things were’nt looking so good. Denali (a BP-ConocoPhillips pipeline project) had folded, the three major North Slope producers were not aligned, and the ground had shifted in the (Lower 48) market,” due to shale gas, Sullivan said. “Now we have alignment among the three producers and the companies working together on a single project. The governor led the shift from the Lower 48 to the Pacific Rim. We’re not ‘there’ yet, but we’ve made significant progress.”

In a related development, Sullivan said the companies and the state-owned Alaska Gasline Development Corp., or AGDC, which is working on a small-diameter “in-state” gas pipeline, are also expected to have completed their assessment of how they can combine activities of the two projects by Sept. 30, Sullivan said.

Dan Fauske, CEO of AGDC, told the legislators that he expects to receive a final environmental impact statement, or EIS, for his project in September. ADGC is working on a 737-mile, 24-inch pipeline from the North Slope to Southcentral Alaska that would deliver gas for consumer and local commercial and industrial customers.

Sullivan said that if enough progress is shown on the LNG proposal by the end of September, the governor will proceed with a plan to submit gas pipeline fiscal legislation to state lawmakers in 2013. A more detailed plan for the LNG and pipeline project is also expected by early spring, he said.

TransCanada’s project, which includes ExxonMobil Corp., involves a proposed large-diameter pipeline built from the North Slope along the existing Trans Alaska Pipeline System corridor through Interior Alaska. If the land pipeline were built, it would leave the TAPS corridor at Delta, east of Fairbanks, and follow the Alaska Highway to British Columbia and Alberta.

The LNG options would involve the gas line following TAPS all the way to Valdez or a route south to the Anchorage and Kenai Peninsula, where ConocoPhillips now operates an LNG plant.

Read more:

Point Thomson could put 1,000 to work this winter

Tim Bradner
Alaska Journal of Commerce

A final environmental impact statement, or EIS, has been issued for the ExxonMobil-led Point Thomson gas cycling and condensate production project east of Prudhoe Bay, an ExxonMobil official told Alaska legislators on July 30.

A Record of Decision by the U.S. Army Corps of Engineers, which prepared the EIS, is expected, Lee Bruce, ExxonMobil Corp.’s manager for the project, told the Legislature’s natural gas caucus, a panel that meets to review gas projects.

ExxonMobil is now hoping for its federal and state permit by late fall, which would allow site construction at Point Thomson to begin in December, Bruce said. The company needs the Corps’ Section 404 permit and other state and federal authorizations. The project will put about 1,000 to work this winter if it proceeds on schedule, he said.

Point Thomson is a large gas and condensate field 60 miles east of Prudhoe Bay. It was discovered in the mid-1970s and delineated with drilling through the 1980s, but development has been stymied for lack of a gas pipeline. The field has an estimated 8 trillion cubic feet of proven gas reserves and about 200 million barrels of liquid condensates.

For several years ExxonMobil and its partners in the field, BP, ConocoPhillips and previously Chevron, were locked in a bitter dispute with the state of Alaska over having failed previous work obligations. An interim agreement allowed preliminary drilling to proceed on the current project in 2008 and 2009, and a full settlement reached this past March resulted in the full project getting underway.

“It is our vision to build trust with the state of Alaska that we can deliver this project as promised, and on time,” Bruce told the legislators.

ExxonMobil purchased Chevron’s interest in Point Thomson at the same time the settlement was reached.

The current project is a limited gas cycling and condensate production project that would ship 10,000 barrels per day of condensates to the Trans Alaska Pipeline System while re-injecting about 200 million cubic feet of gas back to the reservoir. Because Point Thomson reservoir pressure is over 10,000 pounds per square inch, the project would be the world’s highest-pressure gas compression and injection project, Bruce said.

Construction has already started on critical components for the project including storage tanks for 2.4 million gallons of fuel and steel Vertical Support Members for a 22-mile, 12-inch pipeline that will connect Point Thomson with the existing Badami pipeline that extends about 25 miles east of Prudhoe Bay.

A Doyon, Ltd. subsidiary has been awarded the contract to install the pipeline, and Doyon, which is based in Fairbanks, has subcontracted for the VSM fabrication, which is under way at North Pole, east of the Interior city.

Alaska Frontier Construction, another Alaskan firm, has the contract to do civil work at the Point Thomson site. Work in building roads, a 5,600-foot airstrip and expansion of gravel pads will be underway this winter. General Communications Inc., or GCI, is contracted to supply telecommunications to the site.

The infrastructure and pipeline engineering is nearing completion by PND Engineers and Michael Baker Jr., Bruce said, and the engineering on production facilities, by WorleyParsons/Fluor, is about 40 percent complete. A Hyundai subsidiary in Korea has been contracted to build the large process modules, which will be moved to the North Slope by sealift.

ExxonMobil has not released cost estimates for the project. Those were originally estimated at $1.3 billion but the estimates have escalated substantially since, according to state of Alaska officials who spoke on background. Bruce told the legislators that $700 million has been spent in an initial drilling of two development wells in 2008 and 2009.

Bruce said that what is being developed now is a first phase that would test the reservoir’s performance with gas cycling. It the reservoir performs well the condensate production can be increased. Alternatively, the facilities being built now could be used to support gas production for a gas pipeline or, absent that, for gas to be shipped west to the Prudhoe Bay oil field for enhanced oil recovery.

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Wednesday, August 1, 2012

"Thoughtful Thursdays" - June 2012

By Deborah Brollini

My latest video. June photos of Alaskans and visitors being "thoughtful." The momentum is growing. Learn more about "Thoughtful Thursdays" at