OGJ Newsletter

April 28, 2008
General Interest - Quick Takes

Alaska rejects ExxonMobil’s Point Thomson plan

Alaska state officials have rejected ExxonMobil Corp.’s latest plan to develop Point Thomson Unit (PTU) on Alaska’s North Slope. The gas-condensate area has no production.

Alaska Natural Resources Commissioner Tom Irwin said the proposed plan was not in the state’s best interest because it would have involved development on the 106,200-acre PTU, east of Prudhoe Bay, without any commitment to produce gas.

“In light of the history of this unit, I did not trust the appellant’s commitment to follow through with their 23rd plan of development,” Irwin said Apr. 22.

No immediate comment was available from ExxonMobil, PTU operator. It estimates the high-pressure reservoir has reserves of more than 8 tcf of gas and 200 million bbl of condensate (OGJ, Mar. 10, 2008, p. 36.)

ExxonMobil along with BP Exploration (Alaska) Inc., Chevron USA Inc., and ConocoPhillips Alaska Inc. hold working interests in PTU, covering 45 state oil and gas leases. The oil companies have said production hinges upon construction of an Alaska gas pipeline to the Lower 48.

MMS moving forward on alternative energy

The US Department of the Interior’s Minerals Management Service designated five areas on the Outer Continental Shelf as priority areas for research on alternative energy in federal waters.

The agency issued an Apr. 18 published notice that outlines details about the areas along with instructions for a 30-day public comment period.

The five areas are off New Jersey, Delaware, Georgia, Florida, and California. The agency proposes limited, temporary leases in these areas for data collection and technology testing related to wind, wave, and ocean current energy development.

There will be no commercial energy production activity associated with the proposed leases. Randall Luthi, MMS director, said the research is intended to increase understanding of potential offshore renewable energy sources.

Before issuing leases or selecting specific project proposals, MMS is evaluating the five areas as they relate to environmental factors and commercial activities such as fishing and shipping.

Colorado lawmakers introduce Roan leasing bill

US Sen. Ken Salazar and Reps. John T. Salazar and Mark Udall introduced legislation Apr. 17 that the three Colorado Democrats said would protect the Roan Plateau while assuring that Coloradoans would receive a fair share of revenues from oil and gas development there.

S. 2879 would require the US Bureau of Land Management to issue leases on the plateau in phases, initially outside of cutthroat trout watersheds, and consider factors designed to maximize revenues to the federal treasury and to the state while minimizing environmental impacts, according to the federal lawmakers.

Before each new leasing round, BLM would have to confirm that wells necessary to recover 90% of the recoverable natural gas beneath the previously leased development area were completed and that stringent environmental standards were met, they said.

The bill also would expand BLM’s Areas of Critical Environmental Concern to include the headwaters of two creeks, which the lawmakers said are critical native cutthroat trout watersheds. It also would limit development outside the ACECs and within development corridors along existing ridge-top roads to 20% of these areas.

A spokesman for the Independent Petroleum Association of Mountain States in Denver said on Apr. 22 that the organization was pleased that the three lawmakers apparently have dropped their opposition to any further Roan Plateau federal leasing.

But IPAMS Communications Director Jon Bargas also told OGJ that Congress transferred Naval Oil Shale Reserves 1 and 3 from the US Department of Energy to BLM in 1997 with the express purpose of leasing the 73,620 acres. “Since then, BLM has developed one of the most stringent leasing plans we’ve ever seen. Leasing of the Roan Plateau has been delayed long enough,” he said.

Venezuela hits exported oil with new tax

Venezuela has increased taxes on crude oil and oil products moving out of the country.

On their exported oil volumes net of imports, companies must pay a per-barrel tax of 50% of the amount by which the monthly average price of Brent crude exceeds $70/bbl. The tax rate increases to 60% when the Brent price exceeds $100/bbl.

Payments of the new tax are deductible in calculations of income tax. Companies may deduct contributions to Venezuela’s National Development Fund from their new-tax liabilities.

The move is the latest in a series of blows to producers in Venezuela and comes as the government moves to nationalize key industries, including cement and steel.

After welcoming international operators to Venezuelan exploration and production opportunities in the 1990s, the government reversed course after the election of President Hugo Chavez in 1998.

A hydrocarbons law enacted in 2001 raised royalties on production by private companies to 20-30% from 1-17%, guaranteed state-owned Petroleos de Venezuela SA majority interests in new projects, and required that foreign participation in oil and gas projects take the form of joint ventures with PDVSA.

Since then the government has renegotiated agreements in effect when the 2001 hydrocarbons law took effect into joint ventures with PDVSA as controlling partner.

It also has restructured the four “strategic associations” producing extra-heavy crude from the Orinoco belt and raised their royalties and income-tax rates. In response, ConocoPhillips and ExxonMobil Corp. quit their Venezuelan heavy-oil projects.

Iraq expects new energy law, closer EU ties soon

Iraqi Prime Minister Nuri al-Maliki told European parliamentarians that his country’s Oil and Gas Draft Law will be passed soon to attract international energy investment.

Al-Maliki told the European parliament’s foreign affairs committee that his government is nearing a final agreement on the law, which will pave the way for signing strategic partnership agreements and developing investments.

Europe argues that the law’s ratification is essential for development of international investment in Iraq’s energy industry.

Meanwhile, the European Commission said Iraq has offered to increase its supply of natural gas to the European market over the next 3 years. The offer was made during talks between Iraqi Oil Minister Hussein al-Shahristani and EU Energy Commissioner Andris Piebalgs.

The EC said Iraqi officials are ready to sign a draft energy memorandum of understanding, which would open the way to closer EU-Iraqi energy ties.

The EC said Iraq made “a political gesture of goodwill” by promising to export at least 5 billion cu m of gas to the European market by 2011.

It said Iraq also was committed to increasing its oil production to 3 million b/d by yearend and that it aimed for 4.5 million b/d by 2012.

“This should be a favorable contribution toward decreasing oil prices,” the commission reported in a statement. “Iraq confirms it is exploring new areas for production.”

EC Pres. Jose Manuel Barroso said negotiations on a complete energy pact with Iraq “are going on very well” and suggested that a final agreement could be reached by May.

Industry Scoreboard
Click here to enlarge image

null

Click here to enlarge image

null

Click here to enlarge image

null

Exploration & Development - Quick Takes

Dana makes oil find on West Rinnes structure

Dana Petroleum PLC will sidetrack well 210/24a-11 into the neighboring East Rinnes structure on Block 210/24a in the northern UK North Sea after discovering oil on the West Rinnes structure, also on Block 210/24a.

The well produced up to 7,800 b/d of 32º oil during a drill stem test from the Brent reservoir on the West Rinnes structure. Dana said it is confident the size of the East Rinnes structure is similar.

The well reached a total measured depth of 6,470 ft, and the flow rate was limited by test equipment on the drilling rig, the company said. Dana is encouraged by initial tests that the well’s oil quality is similar to that being produced at Hudson oil field 5 km away. The well found excellent quality sands throughout the Brent sequence, Dana reported.

“A comprehensive set of wireline log data has been acquired, including pressure data and oil samples,” Dana said.

Dana said the results “exceeded our predrill expectations” and that the discovery at West Rinnes gives “strong encouragement” for other prospects in the area.

Australia extends continental shelf acreage

The United Nations has allowed Australia to greatly extend its continental shelf after 15 years of lobbying.

The UN found that Australia’s territory should be extended by 2.5 million sq km—an area about five times the size of France. The new area takes in extensions of the Exmouth Plateau and Wallaby Plateau in the west, the Great Australian Bight in the south, and the Lord Howe Rise in the east.

All are areas the government scientific body Geoscience Australia thinks could hold petroleum reserves and are future potential exploration areas.

No one will put a figure on likely petroleum resources in this new offshore territory, but all agree it is virtually unexplored.

The announcement leaves a lot of unexplored territory that may produce Australia’s next oil and gas province, according to Belinda Robinson, Australian Petroleum Production and Exploration Association chief executive.

“We know very little about [the new areas] but a number of them are adjacent to existing producing areas, including the Browse and Carnarvon basins off Western Australia, so we’d be hopeful they may be prospective,” Robinson said.

However, she added that having jurisdiction over the acreage is not enough. The challenge for Australia is to persuade potential investors to risk money here rather than elsewhere.

“This requires a two-pronged approach: first to ensure the availability of baseline geological information and second to ensure that the fiscal framework takes account of the high costs and high risks involved in exploring these areas,” she said.

Husky, CNOOC to develop Madura BD field

Husky Energy Inc., Calgary, has reached an agreement with China’s CNOOC Ltd. to jointly develop Madura BD gas and natural gas liquids field off East Java, Indonesia (OGJ, Jan. 22, 2007, p. 37). The agreement covers the development and further exploration of the Madura Straits production-sharing contract.

Deal specifics include payment of $125 million to Husky by CNOOC to acquire a 50% equity interest in Husky Oil (Madura) Ltd., which holds a 100% interest in the Madura Straits PSC.

Madura Straits PSC covers 2,794 sq km of exploration acreage about 40 km north of East Java. Since 1984, 10 wells have been drilled on this block, resulting in two discoveries: Madura BD and MDA fields. In 2007, Husky signed three gas sale and purchase agreements for the sale of 100 MMcfd of gas from Madura BD field to East Java buyers.

CNOOC subsidiary CNOOC Southeast Asia Ltd. currently operates two blocks in Indonesia and holds interests in numerous other blocks.

Husky holds a 100% interest in the East Bawean II PSC, off Indonesia, and will continue to focus on exploration and drilling activities in Indonesia. Husky recently completed a 1,410 sq km, 3D seismic program over this block in preparation for a two-well exploration program in 2009.

Drilling & Production - Quick Takes

IOR-EOR offers lowest-cost reserves additions

Unlike in past years, improved or enhanced oil recovery is now the least costly method for adding reserves, according to a presentation at the 16th SPE/DOE Improved Oil Recovery Symposium, Apr. 21 in Tulsa.

In his presentation, Rafael Sandrea, president of IPC Petroleum Consultants Inc., Tulsa, estimated that IOR-EOR could add reserves for a capital expenditure of $2-4/bbl. He said this is less than the needed $4.30-6.25/bbl capex for heavy oil production, $4-6/bbl spending for deepwater, $12.86/bbl for acquisitions, and $14.42/bbl for global finding and development costs.

Sandrea also said the target for IOR-EOR remains huge. His estimate of discovered conventional oil in-place to date is 10.9 trillion bbl. In this estimate, he does not include the 3 trillion bbl of heavy oil and bitumen found in Alberta and the Orinoco region of Venezuela.

The world has produced only 1.028 trillion bbl of conventional oil, and Sandrea said that without expanding the use of IOR-EOR methods, the ultimate worldwide recovery factor would be only 22%.

He also cautioned that without extensive increases in recovery factors, world oil demand would face the following supply shortfalls: 2010, 2.7 million b/d; 2015, 5.4 million b/d; 2020, 12.1 million b/d; and 2030, 30.6 million b/d.

Sandrea said the $200-400 billion capital spending needed for adding 100 billion bbl of IOR-EOR reserves is in the same range as the industry’s current global spending of $260 billion/year.

BP begins oil production from Gunashli field

BP PLC has started oil production from the third phase of Azeri-Chirag-Gunashli (ACG) field in the Azerbaijan area of the Caspian Sea.

The field will produce plateau oil levels of 320,000 b/d via the deepwater Gunashli (DWG) platform complex in 175 m of water. The DWG facility has 48 drilling slots and a drilling and production platform bridge linked to a water injection and gas compression platform.

Oil will be delivered through the Baku-Ceyhan pipeline from the Caspian Sea to Turkey’s Mediterranean coast.

BP said: “Production export off the complex is via two 30-in. oil pipeline tie-ins and a single 28-in. gas pipeline tie-in into preinstalled pipeline junctions located on the Azeri field subsea export pipelines to the onshore Sangachal terminal. In addition, uniquely for the ACG project, two subsea water injection manifolds, four water injection supply flowlines, and associated control umbilicals have been installed in the DWG development.”

Oil production is expected to increase as more predrilled wells come on stream during the year. Overall, ACG’s total production will hit more than 1 million b/d, including Chirag, East Azeri, West Azeri, and Central Azeri.

Shell considers carbon capture for Browse

Shell Australia is thinking of introducing a carbon dioxide capture and geosequestration (CCG) side to the proposed floating LNG (FLNG) development at its wholly owned Prelude gas find in the Browse basin off Western Australia.

According to documents lodged with environmental regulators in Australia, the company is planning to build a 3.5 million tonne/year FLNG for the field which lies 450 km northeast of Broome.

Shell says in the application document that the project has potential for CO2 sequestration, thereby reducing its carbon footprint.

The CCG move comes in the wake of Prime Minister Kevin Rudd’s federal government plans to introduce a carbon trading scheme by 2010 as part of its goal to limit greenhouse gas emissions.

If successful, the FLNG proposal at Prelude could be a catalyst for development of other ‘stranded’ gas in Australia and elsewhere. The Prelude plant proposal is for a vessel 480 m long and 70-80 m wide and designed to survive a once-in-10,000 years cyclone. It would be built outside Australia and towed directly to the field location, where it would then be anchored to the seabed.

Preliminary estimates indicate that Prelude field has a reserve of 2-3 tcf of gas. Shell has indicated an ambitious on-stream date of 2012 and expects the plant to run for 25 years.

Eni starts gas production from Badhra field

A joint venture led by Eni SPA has begun gas production from Badhra field, southeast of Bhit gas field in Pakistan, and has commissioned the third train at Bhit gas treatment plant, which will process gas from nearby Badhra field, following the Badhra development and Bhit acceleration projects.

The $50 million Badhra development and Bhit acceleration project has boosted the existing capacity of the Bhit plant capacity by 17% to 315 MMscfd from 270 MMscfd. Badhra field is 250 km northeast of Karachi in Pakistan’s Sindh province.

Processing - Quick Takes

ConocoPhillips settles refinery pollution charges

ConocoPhillips agreed Apr. 8 to pay $1.2 million to settle federal water pollution charges involving a 146,000 b/cd refinery in Borger, Tex., that it operates, the US Department of Justice and Environmental Protection Agency said.

The company allegedly violated the US Clean Water Act (CWA) more than 2,000 times from 1999 through 2006, the agencies said. In a complaint filed with a consent decree in US District Court for the Northern District of Texas, authorities said the case involved two types of pollutants, selenium and whole effluent toxicity.

ConocoPhillips brought the refinery into compliance with its CWA permit limits for both pollutants after federal enforcement actions began, according to DOJ and EPA. They said WRB Refining LLC, the refinery’s current owner, also signed the agreement.

The proposed settlement, still subject to final judicial approval, requires ConocoPhillips to monitor surrounding waters, including Dixon Creek and the Canadian River, for selenium levels as well as for the accumulation of selenium in fish tissue.

The company also will maintain controls it put into place to minimize its selenium discharges and to correct whole effluent toxicity violations, DOJ and EPA said. It also agreed to perform a supplementary environmental project, which will cost an estimated $600,000, to reduce the amount of solids discharged into local waterways during storms, they indicated.

Shell FCC process raises diesel, propylene yields

Shell Global Solutions International BV announced the development of a new process to increase production of diesel and propylene from FCC units.

The middle distillates and lower olefins selective process (MILOS) uses an additional riser in the FCC, either in a revamp or grassroots unit, which gives the refiner options to simultaneously maximize production of diesel and propylene.

“Changing market demands for less gasoline and more diesel and propylene has proved difficult to achieve with the traditional and inflexible layout of the standard FCC. MILOS addresses this by providing the refiner an operational choice,” said Mart Nieskens, global manager, catalytic cracking at Shell Global Solutions (US) Inc. (SGS). “The process is designed to be simple and easy to change between modes to help provide greater flexibility.”

According to Shell, refiners can run an FCC in different modes with the new process. In the propylene mode, propylene production can double compared with a base-case FCC unit while maintaining traditional diesel yields and quality.

In diesel mode, diesel production can increase up to 20% with a seven point rise in cetane number and increased propylene production. The FCC unit can run anywhere between these modes or revert to normal FCC operation by changing operating parameters.

“The MILOS process should be particularly attractive to refineries linked to petrochemical complexes,” said Pankaj Desai, SGS licensing sales manager. “Moreover, because it’s designed to provide increased flexibility, the MILOS process can help refiners to take advantage of the seasonal demand patterns.”

Feed to the additional riser can be different feedstocks, such as FCC naphtha, coker naphtha, visbreaker naphtha, vegetable oil, and GTL process products, or even paraffinic vacuum gas oil, according to Shell.

Transportation - Quick Takes

BLM begins hearings on Ruby gas pipeline

The US Bureau of Land Management has begun a series of public hearings on a proposed $2 billion natural gas pipeline that would run 680 miles between southwestern Wyoming and southern Oregon near the California state line.

The Ruby Pipeline system, which would be built by subsidiaries of El Paso Corp., PG&E Corp., and Bear Stearns Cos., initially would transport 1.2 bcf/day of gas from the Opal Hub across northern Utah and Nevada to an interconnection near Malin, Ore. (OGJ, Dec. 24, 2007, Newsletter).

Two compressor stations, one near the 42-in. pipeline’s origin and a second midway along its route, also would be built initially. Additional compression could increase capacity to 2 bcf/day.

BLM is holding the meetings as a participating agency in the Federal Energy Regulatory Commission’s preparation of an environmental impact statement on the project. The US Forest Service also is participating because the system would cross the Wasatch-Cache National Forest in Utah and the Fremont-Winema National Forest in Oregon.

Iraq’s NOC lets contract for Kirkuk-Banias repair

Iraq’s state-owned North Oil Co. has signed a preliminary agreement with Russia’s Stroytransgaz for the repair of the Iraqi section of the 880-km Kirkuk-Banias oil pipeline. In 2007, Stroytransgaz received a contract to bring the Syrian section of the line back into working condition.

The Kirkuk-Banias pipeline had a carrying capacity of 300,000 b/d before the US-led invasion of Iraq in 2003, but its original capacity when built in the 1950s was 1.4 million b/d.

The pipeline was closed for much of the 1970s and 1980s. In the 1990s, it was reopened so Iraq could bypass the United Nations oil embargo. At the time, reports put Iraq’s exports through the line at about 150,000-200,000 b/d.

BG, Singapore sign LNG supply deal

BG Group PLC and Singapore’s Energy Market Authority (EMA) have signed a memorandum of agreement for BG to provide as much as 3 million tonnes/year of LNG for up to 20 years, starting in 2012.

The deal underpins Singapore’s desire to enhance its energy security and marks the first time it will become an LNG importer. It also has expressed a desire to create an LNG trade hub with spot cargoes.

BG Group, sourcing LNG from its global portfolio, will supply the LNG to the import terminal on Singapore’s Jurong Island that also is scheduled for completion in 2012. PowerGas Ltd., a wholly owned subsidiary of Singapore Power Ltd., was contracted to build, own, and operate the terminal.

The plant’s capacity can be expanded to 6 million tonnes/year and ultimately to 10 million tonnes/year by the mid-2020s.

Both parties declined to reveal the value of the agreement, saying only that the deal had been concluded at “competitive rates.”