Friday, November 22, 2013

New study recommends state consider equity investment in LNG project

Tim Bradner
Alaska Journal of Commerce

State officials are mulling a plan to take an equity stake in a large Alaska gas pipeline and natural gas liquefaction project.

Such a move could ease fiscal issues that the project sponsors, North Slope producers BP, ConocoPhillips, ExxonMobil, and pipeline company TransCanada have cited. That’s a conclusion of a major study of state royalty issues released Monday.

The state contracted earlier this year with Kansas-based Black & Veatch to do the study. State investment in the project a one major recommendation.

“Having a direct stake could solve a lot of problems for us and the project sponsors,” said state Natural Resources Commissioner Joe Balash in an interview.

“Direct state equity participation in the (gas) project can provide key benefits to the state including alignment of interests (among the parties), transparency through the midstream portion of the supply chain, facilitation of third-party access to the midstream and potentially improved state cash flows along with improved producer economics,” the report said in its conclusions.

Black & Veatch outlined options for the state in improving fiscal terms in its study and said that without changes in the terms, a large LNG project may not be viable.

Balash said one of the biggest problems the companies have with the state’s current terms is the one-eighth royalty share and the state’s ability, under leases held by producers, to switch taking its royalty from in value, or cash payment, to in-kind, or in the form of gas, and to switch back and forth at six month’s notice.

“The sponsors have complained that the present structure has them obligated to finance 100 percent of the project but get only 7/8 of the benefits,” because they have the obligation to ship the state’s one-eighth royalty gas share through a portion of the pipeline they would have to fund.

If the state were to invest in and own a share of the project equal to its one-eighth share, or perhaps as much as 25 percent if the tax obligation was included, it could better align the interests of the parties, Balash said.

The producers and the state would each finance a share of the project sufficient to ship gas each party owns, he said. It would also spread risks, like cost overruns, more equitably.

Black & Veatch said the improved profitability of the overall investments could make the difference in making the project attractive enough for the producers to back it, Balash said.

If the state having a stake in the project solves a problem for the companies, it helps the state with other difficulties, Balash said. As an owner the state would have access to the inner workings of the project finances, which would help ensure the state’s tax and royalty collections wouldn’t be disadvantaged, he said.

Ensuring fair payment for tax and royalty assumed even more importance after the project switched from the original plan for an all-land pipeline to the continental U.S. to a pipeline and a large natural gas liquefaction project serving an export market.

Much of the state’s previous work on royalty terms became obsolete when the plan switched to include LNG, Balash said.

The gas treatment plant and pipeline will be regulated by the U.S. Federal Energy Regulatory Commission as far as tariffs and rates, but not so the LNG plant.

“FERC gives us a transparent process as far as it goes, but the LNG part of the project is more opaque,” Balash said. “The project sponsors are likely to operate this as an integrated venture, so we see opportunities for shifting profits in ways that could not be in our interest.”

Having a seat at the table helps the state solve this, he said.

One problem the arrangement would present, however, is it leaves Alaska with the obligation to market its royalty gas as LNG. That could be more than 1 billion cubic feet a day of gas per day if the state takes a one-fourth share.

Arrangements could always be made with one or more of the producers to market the state’s gas under contract but there would likely be fees associated with this, Balash said. Alternatively the state could set up its own LNG marketing organization, but such a group would always be at a disadvantage in competing for sales with others in the project, like BP and ExxonMobil with long experience in LNG.

Balash said one possible solution could be in working with TransCanada, which is now part of the project group but which does not have its own gas to ship, unlike other parties.

“We could become TransCanada’s customer,” Balash said.

http://www.alaskajournal.com/Alaska-Journal-of-Commerce/Breaking-News-2013/New-study-recommends-state-consider-equity-investment-in-LNG-project

Sunday, November 17, 2013

The water problem; Alyeska Pipeline, North Slope producers work to reduce TAPS freeze-up threat

Wesley Loy
For Petroleum News

With the onset of winter, the operator of the trans-Alaska pipeline system enters another season of challenges to prevent catastrophe due to potential freezing in the line.

Alyeska Pipeline Service Co. is using a range of tactics to avoid a freeze-up, including operations to add heat to the crude oil as it makes the 800-mile journey south from the North Slope.

Another tactic is minimizing the amount of water that’s mixed in with the oil.

In fact, Alyeska “appears to be concentrating on the option of water removal,” said the newly released 2013 annual report from the State Pipeline Coordinator’s Office.

Potential for calamity

In recent years, Alyeska has faced a mounting problem — the decline in the volume of oil moving daily on the trans-Alaska pipeline system, or TAPS.

The pipeline is oversized, having been designed to ship three or even four times the current throughput of around 550,000 barrels per day.

The low flow means the oil moves slower to the pipeline terminus in Valdez.

This means the warm oil is exposed longer to arctic weather conditions in winter. About half the line is above ground.

If for some reason the pipeline must shut down for an extended period, and the oil chills too much, freezing and other problems could develop. Restarting the pipeline could become difficult, if not impossible.

To date, Alyeska has always managed to restart the line promptly after winter shutdowns. But multiday outages following a January 2011 spill at Pump Station 1 caused serious worry about potential freezing and wax buildup severe enough to idle the pipeline until the summer thaw.

Obviously, a shutdown of that duration would be an economic calamity for the state, and a technical nightmare for Alyeska and the North Slope oil producers.

Declining water content

It’s the small amount of water mixed in with the oil that poses much of the freeze-up threat.

Water and natural gas are found naturally with the oil in North Slope reservoirs. Companies also inject water underground to enhance oil recovery.

“Processing plants remove the majority of produced water,” the pipeline coordinator’s annual report said. However, a significant fraction remains. And a bit of sediment, too.

By policy, the TAPS owners aim to limit water and sediment content to no more than 0.35 percent of the crude oil delivered to Pump Station 1.

“However, in recent years the North Slope oil fields have averaged water contents below this limit,” the annual report said. “Reports indicate that the average ... is typically in the range of 0.10 to 0.21 percent.”

In addition, operators have cut the magnitude and number of water pulses, up to 2.5 percent, than can sometimes occur, the report said.

Still, water remains a concern when coupled with the low oil throughput.

As flow decreases and becomes laminar, or less turbulent, water can drop out as the oil and water separate. This can increase internal corrosion, especially at the bottom of the pipe.

Free or fixed ice has potential to cause myriad problems: disabled instrumentation, plugged pump screens, frozen valves and so forth.

Getting it out

So, how can the troublesome water be wrung out of the oil?

“This could involve something as simple as a large tank at PS 1 that allows water to settle to the bottom, where it can be drained,” the pipeline coordinator’s report said. “Reduction of water and sediment content below the current standard might reduce problems caused by ice formation.”

Alyeska spokeswoman Katie Pesznecker told Petroleum News that several technologies for removing water from crude oil are being considered.

“We have conducted tests with static separation in tanks and expect to do so again next summer,” she said.

Pesznecker defined static separation as letting the crude oil “rest” in a tank so separation of oil and water occurs, with the water falling to the tank bottom.

The testing was conducted in existing tanks at Pump Station 1, she said.

The state pipeline coordinator’s annual report said Alyeska would conduct ice studies at the University of Oklahoma.

“Very few facilities have the capability of performing flowing ice studies of hydrocarbon mixtures,” the report said. “The primary focus of this set of investigations is to characterize the rate and volume of ice formation at various water concentrations and the conditions under which ice forms.”

http://www.petroleumnews.com/pntruncate/281142877.shtml

Tuesday, November 12, 2013

Shell files plan; Exploration plan for 2014 drilling in Chukchi goes to BOEM for review

Alan Bailey
Petroleum News

Shell has filed a revised plan for exploration drilling in Alaska’s Chukchi Sea, the company announced Nov. 6. The plan, which the company says “is required to keep the company’s 2014 exploration options viable” and which apparently details the drilling of multiple Chukchi Sea wells, has gone to the Bureau of Ocean Energy Management for review. Shell has no near-term plans for Beaufort Sea drilling.

The company has already contracted the use of Transocean’s Polar Pioneer semi-submersible drilling rig to replace the damaged Kulluk floating drilling platform so that, together with the drill ship Noble Discoverer, the company will have two drilling vessels available for use in the Arctic.

However, the company faces some significant challenges if it is to drill in 2014, given the need to permit all of the vessels in the company’s substantial Arctic drilling fleet before the drilling operations can begin. And, presumably, decisions over mobilizing the fleet will need to be taken long before the drilling season starts.

New rules

Meantime, the Bureau of Safety and Environmental Enforcement, or BSEE, is in the process of preparing a new set of safety rules for drilling on the Arctic outer continental shelf. BSEE spokesman Nicholas Pardi confirmed to Petroleum News in a Nov. 4 email that, despite the recent government shutdown, the agency is still on target for issuing a draft version of the new rules by the end of the year for public review. Issue of the rules in final form will depend on completion of the subsequent public review period and revision of the rules in the light of public comments.

And environmental organizations are busy lining up their opposition to Shell’s plans.

“The specter of Shell planning to move forward in the Chukchi Sea is the scariest Halloween trick yet,” said Susan Murray, deputy vice president, Pacific, for Oceana. “Instead of continuing to ignore risks and pushing to drill, Shell ought to scrap its plans for the Arctic along with the Kulluk … there is no proven technology that would allow companies to drill safely in Arctic Ocean conditions, and the risks far outweigh any potential benefits.”

“Before Shell starts boasting about its new plans for the drilling in the Arctic Ocean, the company should explain why it couldn’t safely conduct its operations under last year’s plans,” said Earthjustice attorney Holly Harris. “Drilling in the Arctic Ocean is just too risky and no company has figured out how to respond to an oil spill in icy waters.”

Read more: http://www.petroleumnews.com/pntruncate/544108218.shtml

Friday, November 8, 2013

C-P may add 55K barrels/day by 2018

Tim Bradner
Alaska Journal of Commerce

Two ConocoPhillips employees overlook pipelines on the West Sak oil field on Alaska’s North Slope. Projects now in development for ConocoPhillips on the Slope could add 55,000 barrels of production per day by 2018, according to company estimates.

ConocoPhillips is pushing ahead with projects that could add about 55,000 barrels per day of new North Slope oil production by 2018, the company said. This will help dent the current decline in production, which averages about 6 percent yearly, from existing North Slope fields.

The 55,000 barrels per day estimate includes 16,000 barrels per day expected from the new CD-5 project; 8,000 barrels per day from a new drill site in the Kuparuk River field, and 30,000 barrels per day anticipated from a new production site in the National Petroleum Reserve-Alaska.

In addition, a new drill rig put into service in the Kuparuk River field earlier this year has resulted in about 1,800 barrels per day of new production, ConocoPhillips said.

The CD-5 project has been long-planned but work on the other projects was accelerated after the Legislature approved Senate Bill 21, which modified state oil production taxes, ConocoPhillips has said.

BP Exploration, which operates the large Prudhoe Bay field, is also planning new projects in that field.

Construction will begin this winter on the CD-5 project, with Anadarko Petroleum Corp. is a minority owner. Preliminary placement of gravel will also be done this winter for the new drill-site Kuparuk 2-S in the Kuparuk field, ConocoPhillips spokeswoman Natalie Lowman said.

The CD5 construction will span two years, with ice road building, hauling of gravel and bridge construction this winter and completion of the bridge and construction of pipelines and production facilities the following year.

Some additions to infrastructure at the Alpine Central Facility, for the processing of additional oil and gas, will also be required.

The company must still give final approval for construction of the drill site and its related infrastructure. That will be requested of ConocoPhillips’ board in late 2014, Lowman said. BP is also an owner in the Kuparuk field and is a partner in the new project.

At CD-5, contractors will begin mobilizing for construction late this fall. The project involves a bridge over the Colville River, a production pad in the west side of the river as well as related roads, pipelines and utilities.

“Construction of CD-5 is planned to begin in January 2014 and continue in winter 2014-2015. First production is expected in late 2015 and the initial gross production rate is estimated in the range of 16,000 barrels per day,” of oil, Lowman wrote in an email.

CD-5 will be the first commercial oil production from the NPR-A. The small field is west of the producing Alpine field, which is on state of Alaska lands, but because CD-5 is on the west side of the Colville River it is within the federally-owned NPR-A.

ConocoPhillips has also released cost and production estimates for the Kuparuk 2S drill site which is in the southern part of the Kuparuk River field, and the GMT-1 project in the National Petroleum Reserve-Alaska.

Kuparuk 2S is planned for construction in late 2014 with first production is expected in 2015. Costs are estimated at $595 million and peak production is expected to be 8,000 barrels per day.

The GMT-1 project in the petroleum reserve is estimated to cost $890 million to develop and is expected to produce 30,000 barrels per day with first production in 2017, Lowman said.

GMT-1 is within the Greater Moose’s Tooth Unit a few miles further west in NPR-A, and would be the second oil producing project within the reserve.

ConocoPhillips is the operator and majority owner of GMT-1 and CD-5 with 78 percent interest, with Anadarko owning a 22 percent interest.

The 30,000 barrels-per-day estimate for GMT-1 represents an increase over earlier estimates of its potential production. In a 2011 presentation to financial analysts in New York the company had put the production estimate at 15,000 barrels per day to 20,000 barrels per day.

Lowman would not comment on the revised estimate but said 30,000 barrels per day is the number the company is now working with.

CD-5 and GMT-1 will provide the first oil produced on a commercial basis from NPR-A but gas has been produced for several years at Barrow, in the far northern part of NPR-A. The gas field there is owned and operated by the North Slope Borough, the regional municipality.

It supplies Barrow Utilities, the local electric and gas co-op, which serves the Inupiat community of Barrow.

The 23-million-acre NPR-A covers the western part of the North Slope. It was created as a naval petroleum reserve in 1923 but did not see exploration until the 1950s and 1960s, which resulted in the gas discovery at Barrow and an oil discovery at Umiat, in the southeast part of the reserve.

The Umiat discovery was not economic when it was found but Australian independent Linc Energy began drilling last winter to delineate the field and will continue this winter. Linc hope to eventually produce 50,000 b/d from Umiat.

Meanwhile, CD-5, near the Alpine field, is within the federal reserve but the subsurface mineral rights are owned by Arctic Slope Regional Corp. of Barrow. That means ASRC will receive royalties from production at CD-5. Under terms of the Alaska Native Claims Settlement Act of 1971, the federal law under which ASRC onbtained the mineral holdings, 70 percent of the royalties must be shared with other Alaska Native corporations.

Also, Kuukpik Corp., the village corporation for Nuiqsut, the nearest Inupiaq community, is reported to hold a small overriding royalty interest in ASRC’s royalty share of the CD-5 subsurface, but the details of that are confidential.

ASRC also owns some mineral rights on state of Alaska leases on the Alpine field, which in the Colville River delta east of the NPR-A.

Third quarter earnings down vs. 2012

ConocoPhillips earned $494 million from its Alaska oil and gas production in the third quarter of 2013, the company announced Oct. 31. This is down from $585 million in earnings in the second quarter, mainly due to lower oil production.

The company’s Alaska production was down about 20,000 barrels per day during the quarter, much of its due planned turnarounds at its Prudhoe Bay and Kuparuk River fields and the natural decline of aging oil fields.

Production averaged 178,000 barrels per day in the third quarter, down from 197,000 barrels per day in the second quarter. However, ConocoPhillips’ third quarter production was roughly on par with third quarter 2012 with 176,000 barrels per day in production. Its net income for Alaska was down 7.6 percent, from $535 million to $494 million, compared to the 2012 third quarter while its overall net income as a company increased 7 percent in the same period.

ConocoPhillips is the only Alaska oil and gas producer that breaks out its Alaska earnings separately when it issues a financial report for worldwide activities.

As has been the case in previous quarters the company paid nearly twice as much in government taxes and royalties than it earned. Total taxes and royalties were about $900 million in the third quarter, with about two-thirds of this, or $652 million, paid to the State of Alaska during the third quarter.

“As we have reported historically, under the ACES production tax regime we pay almost twice as much in taxes and royalties as we keep,” said Bob Heinrich, ConocoPhillips’ Alaska vice president for finance.

“The recent oil tax change passed by the Legislature, with Senate Bill 21, improves the business climate in Alaska. As a result of these improvements we are now looking forward to increasing our North Slope investment.”

Alaska is a significant source of income for ConocoPhillips because most of the company’s earnings in the state are from crude oil, while in the Lower 48 states a good portion of income is from natural gas, which has experienced low prices.

Still, the company’s Lower 48 oil producing fields have seen significant increases in production, up 54 percent in the third quarter, compared with a 15 percent decline in Alaska oil production.

The figures are from ConocoPhillips’ presentation to financial analysts on Oct. 31.

Tuesday, November 5, 2013

Tesoro takes over; Refiner seeks right of way for new $50 million oil pipeline across Cook Inlet

Wesley Loy
For Petroleum News

Construction of a new subsea pipeline to carry crude oil across Alaska’s Cook Inlet now appears imminent.

Tesoro, which operates a refinery at Nikiski on the inlet’s east side, has assumed control of the project. The concept had originated with Cook Inlet Energy LLC, a westside oil and gas producer.

On Oct. 23, the newly incorporated Trans-Foreland Pipeline Co. LLC submitted an amended pipeline right-of-way lease application to the Alaska Department of Natural Resources. State records show the company has an address in San Antonio, Texas, where Tesoro is based.

Tesoro Alaska Co. is shown as the 100 percent owner of Trans-Foreland Pipeline Co. Three company managers are listed: Charles S. Parrish, G. Scott Spendlove and Gregory J. Goff.

The application package indicates a great deal of planning work has gone into the proposed $50 million pipeline. Project construction is scheduled to start in February and run through October.

Need for pipeline

Oil production peaked in Cook Inlet long ago, and the Tesoro refinery has been in operation since 1969.

It might seem curious, then, why a bold new pipeline is planned now.

Project backers cite a number of compelling reasons. First, the pipeline could eliminate risky tanker runs across the icy, turbulent inlet. Second, the line could provide westside oil producers a reliable alternative to the Drift River terminal where tankers load. Flooding from eruptions of the nearby Redoubt volcano in 2009 knocked the terminal out of service, hampering oil production for months.

A third benefit from the pipeline is potentially lower oil transportation costs.

The proposed pipeline, 8 inches in diameter, will have a design life of 30 years and a capacity of 62,600 barrels per day, the right-of-way application says.

The sponsors believe the project “will need to attract shipping commitments of approximately 4,000 bbls per day to make the tariff competitive with the existing CIPL system,” the application says. “However, given the increased operational reliability and environmental benefits offered by this line the project may be viable at lower throughput levels.”

CIPL is Cook Inlet Pipe Line Co., the Hilcorp subsidiary that operates Drift River terminal and related pipelines.

U-shaped route

It was Cook Inlet Energy that, in November 2012, filed the initial application to DNR for a right of way for the Trans-Foreland Pipeline. Cook Inlet Energy sells its oil to Tesoro.

The project takes its name from the fact that the pipeline will run between the West Foreland and East Foreland points on either side of the inlet.

The pipeline will begin at Cook Inlet Energy’s Kustatan production facility, which processes oil from the company’s offshore Osprey platform. The line will end at the tank farm at the Tesoro refinery.

The pipeline won’t run straight across the inlet. Rather, it will loop south and then north, coming ashore below Nikiski. From there the line will run, buried, along the Kenai Spur Highway to the Tesoro tank farm.

Laying the pipeline in a U-shaped configuration will make construction easier.

“The forelands represent the narrowest part of Cook Inlet and have high currents and a deep trench,” says a project description prepared by Michael Baker Jr. Inc.

The selected route will “minimize tidal stresses on the pipeline and avoid water depths greater than 200 feet, the maximum depth for safe operation by marine divers,” the project description says, adding the pipeline route doesn’t cross any seismic faults.

The underwater segment of the pipeline will run about 22 miles. Counting the onshore bits on either side, the line will run a total of 29 miles.

130 construction jobs

The right-of-way application estimates the cost of materials at $15 million, and the cost of construction at $35 million.

The estimated annual cost to operate and maintain the line is $5.2 million.

The project is expected to generate 130 construction jobs. A dozen people, eight in the field and four in the office, will be needed to operate and maintain the pipeline, the application says.

Two contractors are being considered for pipeline installation: Price Gregory and CONAM Construction, and NANA Construction.

A lay barge will install the subsea pipe, the application says. Most of the in-water construction work is scheduled for May and June, prior to the commercial salmon season. This is also a timeframe when annual tidal velocities are lowest, and beluga whales are out of the area.

The pipeline will rest anchored on the seafloor, and will be buried where conditions allow subsea trenching.

The pipeline will have a number of safety features including a leak detection system. It’ll accommodate smart pigs, devices that slide through a pipeline to test for problems such as corrosion. An epoxy coating on the pipeline, plus cathodic protection, will provide further defense against corrosion. The pipeline wall will be half an inch thick.

Most of the pipeline route crosses state lands. DNR’s State Pipeline Coordinator’s Office has set a Dec. 31 deadline for submitting written objections to the requested pipeline right-of-way lease.


Read more: http://www.petroleumnews.com/pntruncate/303162471.shtml