BP, NRDA announce $1 billion early funding deal
BP Exploration & Production Inc. agreed to provide $1 billion to fund early projects to restore Gulf of Mexico resources damaged by oil that leaked from the deepwater Macondo well, the spill's Natural Resource Damage Assessment trustees announced.
The trustees include the US Department of the Interior, the National Oceanic and Atmospheric Administration, and the states of Alabama, Florida, Louisiana, Mississippi, and Texas.
Lamar McKay, BP America Inc. chairman and president, said early restoration will help identify improvements to wildlife, habitat, and related recreational uses in the gulf.
The trustees said the money will be used to rebuild coastal marshes, replenish damaged beaches, and to restore barrier islands and wetlands.
The agreement does not affect BP or any other company's ultimate liability for natural resource damages or other liabilities.
The full NRDA process will continue until the trustees determine the full amount of damages from the spill. At that point, the trustees will take into account any benefits realized from early restoration.
The $1 billion of early restoration projects will be selected first by each state choosing $100 million in projects. DOI and NOAA each will select $100 million in projects. The remaining $300 million will be used for projects selected by DOI and NOAA from proposals submitted by the state trustees, NRDA trustees said.
Four state pension funds' oil and gas holdings did well
Oil and natural gas holdings in four states' pension funds outperformed other investments during 2005-09, a study commissioned by the American Petroleum Institute concluded.
Preliminary findings by Sonecon LLC found that oil and gas stocks made up an average 3.9% of total public pension holdings in Michigan, Missouri, Ohio, and Pennsylvania, yet they accounted for an average 8.6% of total returns.
The impact was even greater in the states' two largest public pension funds: the fund for public teachers and other school employees and the fund for state government employees, API and Sonecon officials said during an Apr. 25 teleconference.
They said that oil and gas holdings made up an average 4% of these funds but contributed an average 10.4% to the funds' total gains during the 5-year period. Returns on oil and gas assets in these state funds averaged 46.5%, compared with 13% for all other assets, according to the Washington economic advisory firm's preliminary findings.
Sonecon plans to issue a report covering oil and gas investments in 17 states' public pension funds this summer.
"During vigorous expansion or deep recession, oil and gas investments outperformed other public pension holdings by more than two times," said Kyle Isakower, API vice president of regulatory and economic policy.
Robert J. Shapiro, Sonecon's chairman and co-founder, said the four states' pension funds had $300 billion of aggregate assets in the 2005-09 period. Oil and gas holdings in each state's fund represented 3.3-4.8% of the total and $1.1-6 billion of assets.
The study did not differentiate between majors and independents. Shapiro said the study's conclusions might have included overseas multinational oil companies trading on US exchanges with US firms.
BP, Rosneft extend deadline for Arctic agreement
BP PLC and OAO Rosneft extended until May 15 an Apr. 14 deadline for completing an Arctic exploration and stock-swap agreement while BP continues working with a Swedish arbitration panel.
The arbitration panel blocked the $8 billion deal in a ruling that upheld a challenge by the Alfa-Access-Renova (AAR) consortium, BP's Russian partner in TNK-BP. AAR said BP's agreement with Rosneft violated a TNK-BP shareholder agreement requiring BP to involve AAR owners in its Russian ventures.
In response to questions from shareholders during BP's annual meeting in London on Apr. 14, BP Chief Executive Officer Bob Dudley said, "We don't believe we violated the shareholders agreement in any way."
Under the stock-swap agreement, Rosneft was to hold 5% of BP's ordinary voting shares, and BP was to hold 9.5% of Rosneft's shares (OGJ, Jan. 24, 2011, p. 25). The deal called for creation of a joint operating company—66.67% Rosneft and 33.33% BP—to explore blocks covering 125,000 sq km in relatively shallow water of the South Kara Sea (OGJ Online, Apr. 4, 2011).
In an Apr. 14 news release, BP said it remains fully committed to TNK-BP as its primary business vehicle in Russia. BP also owns a 1.3% interest in Rosneft.
Speaking with shareholders, Dudley called Russia, "one of the world's most important sources of oil and gas, as well as a massive market. BP needs to be there…. We will continue to pursue all further opportunities there where we can build value for our shareholders."
ExxonMobil finds more oil on Indonesia Cepu block
Subsidiaries of ExxonMobil Corp. made an oil discovery this month on the Cepu block on Java, Indonesia, where the company discovered giant Banyu Urip oil field in 2001.
ExxonMobil didn't give details of the latest find, Kedung Keris-1, other than to say it is 9 miles east of Banyu Urip field.
Cepu block, 150 km west of Surabaya, covers 919 sq km compared with 1,670 sq km when acquired in 2000. ExxonMobil had announced the Sukowati discovery east of Banyu Urip, but Sukowati has been excluded from the block and is now operated by JOB Pertamina.
Mobil Cepu Ltd. is operator of Cepu. Mobil Cepu Ltd. and Ampolex (Cepu) Pte. Ltd., both ExxonMobil subsidiaries, hold 45% interest in the block. Pertamina EP Cepu has 45%, and the Cepu Block Cooperation Body (BKS) has 10%.
Banyu Urip produces oil from Middle Miocene carbonates and sandstones. The discovery well cut nearly 1,000 ft of gross oil pay and more than 300 ft of gross gas pay and flowed at nearly 4,500 b/d of oil. Sukowati flowed at rates rivaling those at Banyu Urip.
Banyu Urip began producing in 2009 and may reach peak production of 165,000 b/d of oil in 2013 (OGJ, July 19, 2010, p. 44).
Banyu Urip succeeded Pertamina's nearby Kawengan field as the largest field in the East Java basin. Estimated ultimate recovery from Banyu Urip is 450 million bbl.
ExxonMobil also said it made a gas discovery on the Cepu block in 2010. In early 2010 the company signed a memorandum of understanding to supply gas from the block to Indonesian gas and power utilities (OGJ Online, Feb. 15, 2010). That gas was to be supplied from Jambaran field with reserves estimated at 1.3 tcf.
OGJ estimated Indonesia's January production at 905,000 b/d of oil and 234 bcf/month of gas (OGJ, Apr. 11, 2011, p. 29).
Reliance has Cauvery-Palar gas-condensate find
Reliance Industries Ltd. reported a gas-condensate discovery at the first well in the Cauvery-Palar deepwater basin off southeastern India.
The CYPR-D6-SA1 discovery well went to 3,815 m in crystalline basement in 1,194 m of water off Chennai on the CYPR-D6 block. Fully described as CY-PR-DWN-2001/3, the 8,600 sq km block was awarded to Reliance in the NELP 3 bid round.
The well encountered multiple hydrocarbon-bearing clastic reservoirs in the Late Cretaceous section. Several tests including modular dynamic testing and drillstem tests confirmed the presence of rich gas-condensate.
The well drillstem tested at rates of 37 MMscfd of gas and 1,100 b/d of condensate through a 56/64-in. choke from the main zone that has a gross thickness of about 230 ft. Another shallower zone was established through MDT sampling where a gas-condensate sample was retrieved.
RIL has 100% participating interest in the block, which is one of the 23 exploratory blocks in which BP Exploration (Alpha) Ltd. would acquire 30% participating interest subject to government approval.
The discovery has been named Dhirubhai-53 and has been notified to the Directorate General of Hydrocarbons. Appraisal is planned to assess the extent of the reservoirs along this play trend.
Mancos/Niobrara eyed in northwestern Colorado
Dejour Energy Inc., Denver, will drill an initial vertical well to test oil and gas potential in the Cretaceous Mancos/Niobrara formation on its 7,000-acre leasehold in Rio Blanco County, Colo.
The company plans to drill the well in May to test the upper and lower Niobrara sections of the Mancos shale and a secondary target in the Castlegate sand member of Mancos. Dejour is operator with 72% working interest. Dry hole cost is projected at less than $500,000.
This leasehold sits on the western flank of the Douglas arch that separates the Piceance and Uintah basins and is south of giant Rangely oil field operated by Chevron Corp. since the 1960s.
Dejour pointed out that private operators R.W. Bayless and Foundation Energy are exploiting the Lower Mancos zone 6 miles to the southwest of Dejour's proposed well location.
Pending a successful outcome of the test well in proving the extension of the play to Dejour's leasehold, Dejour plans to commence a formal horizontal well development program.
Drilling & Production — Quick TakesStatoil, Sinochem close on Peregrino transaction
Statoil on Apr. 14 closed all contracts and approvals related to its sale of 40% of Peregrino heavy oil field off Brazil to Sinochem Group.
Statoil closed all contracts and approvals related to its sale of 40% of Peregrino heavy oil field off Brazil to Sinochem Group. Photo from Statoil.
Statoil maintains 60% ownership and operatorship of the field, which started production last week (OGJ Online, Apr. 11, 2011).
Sinochem Group paid $3.07 billion for a 40% share of Peregrino plus a financial settlement from effective date to closing date.
Peregrino is in 100 m of water, 85 km off Brazil in Campos basin Blocks BMC-7 and BMC-47.
Tanzania approves gas development license
Tanzania's energy minister issued a license to an Aminex PLC subsidiary to develop Kiliwani North gas field on Songo Songo Island off Tanzania.
Aminex's Ndovu Resources Ltd. unit said it should be able to begin deliveries within a year from Kiliwani North's estimated 40 bcf of gas in place and that it plans to drill the Fanjove North prospect that lies within the development area and may contain an independently estimated 200 bcf in place.
The Kiliwani North-1 well flowed at a rate of 40 MMcfd on a production test. The wellhead is less than 3 km from the nearest access point to the process facilities at the input end of the Songas common-user pipeline that delivers gas from Songo Songo field to the city of Dar es Salaam. The process facilities are being upgraded.
Ndovu has negotiated a memorandum of understanding for the future sale of gas to industrial users in the Dar es Salaam area.
Aminex said it expects to spud an exploratory well at nearby Nyuni Island within 2 months targeting a large gas prospect on the Nyuni PSA. It noted that the existing pipeline has limited capacity "but we may expect development of new pipeline infrastructure as a consequence of recent deepwater gas discoveries" (OGJ Online, Apr. 7, 2011).
Negotiations are being concluded with Tanzanian authorities for an enlarged Nyuni PSA to replace the existing PSA when it expires this year, the first renewal of an expired PSA in Tanzania.
If the Nyuni-2 well has not been concluded by the time the PSA expires, the authorities have indicated that they will extend the existing PSA to enable the well to be completed.
Partners in the Kiliwani North development license are Ndovu 65%, RAK Gas Commission 25%, and Key Petroleum and Bounty Oil 5% each.
Water treatment facilities slated for Arroyo Grande
Plains Exploration & Production Co. signed a design-build-operate agreement with Veolia Water for a 45,000 b/d produced water reclamation facility at its Arroyo Grande oil field in San Luis Obispo County, Calif.
The 12-year performance agreement with Veolia calls for performance guarantees on a fixed-fee basis to ensure design performance and high-quality recycled water.
The facility will incorporate Veolia Water's OPUS II technology and includes ceramic membranes as pretreatment prior to ion exchange and reverse osmosis.
The treated water will be used to provide 25,000 b/d for once-through steam generation make-up and 20,000 b/d for surface water discharge, dewatering the Arroyo Grande reservoir.
Veolia Water said that the treatment process produces treated water that meets or exceeds state and federal permit requirements, and the dewatering of the reservoir will reduce the formation pressure to enable increased oil production at the site.
Prior to the agreement, Veolia Water demonstrated the technology on site for 4 months.
PROCESSING — Quick TakesHolly snuffs tank fire; shuts Tulsa crude unit
Holly Corp., Dallas, said it has shut down the crude unit at the west facility of its Tulsa, Okla., refinery due to a mechanical failure that was discovered on Apr. 22.
Unit shutdown, effecting repairs, and restarting the unit would each take several days, a spokesman estimated on Apr. 26.
Crude throughput was expected to be reduced 50% from runs of 110,000-120,000 b/d at the time of the shutdown, Holly said.
A slop and water storage tank at the east facility caught fire Apr. 22 amid several days of thunderstorms and lightning. The fire was extinguished that evening. No injuries were reported. Holly is investigating the causes of both incidents, starting by pumping rainwater from containment dikes.
Holly purchased what it calls the west and east facilities, the former separate Sunoco and Sinclair refineries, respectively, a little more than a mile apart along the Arkansas River in 2009. It planned to connect them by pipelines into a single facility to be operated at a capacity of 125,000 b/sd.
Holly's 2010 annual report said it would integrate the plants "primarily by sending intermediate streams from one facility to the other for further processing."
High-sulfur diesel and various gas oil streams will be sent from the west facility to be processed in the diesel hydrotreater and fluid catalytic cracking units, respectively, at the east facility. Hydrogen and fuel gas will be shared between the two facilities upon completion of additional interconnect pipelines.
Various heavy oil streams are sent from the east facility to be processed in the coker unit at the west facility, and the majority of the naphtha from the west facility is processed at the east facility and is delivered along with gas oils via an existing interconnect line under an existing 10-year agreement.
The company said the new interconnect lines will allow it to eliminate the sale of gas oil at a discount to West Texas Intermediate crude under its 5-year gas oil offtake agreement with a third party, optimize gasoline blending, increase utilization of better process technology, improve yields, and reduce operating costs.
Five more connecting pipelines along with piping inside the two facilities are under construction and somewhat impeded by persistent winter and spring storms.
The company is also expanding the diesel hydrotreater at the east facility at a cost of $20 million to permit the processing of all high sulfur diesel produced to ultralow-sulfur diesel. Other work is in progress to meet federal environmental regulations.
Shell plans to convert Sydney refinery into terminal
Shell Australia said it may convert its Clyde refinery in Sydney into a fuel import terminal since it can no longer compete with megarefineries in India and South Korea that produce more at lower cost.
This means Australia would be forced to obtain from overseas the 10% of its refined products that Clyde currently provides. Clyde produces 75,000 b/d and has been operating for more than a century. About 85% of the crude required to meet the product mix in Australia was imported from Asia in 2008-09 and about 15% from the Middle East.
Andrew Smith, Shell's vice-president of downstream operations, says the fate of Clyde is not yet determined, and a consultation process has begun between management and employees. He said the proposal to turn the refinery into an import facility reflects that Clyde is no longer regionally competitive and requires significant investment, including maintenance turnaround scheduled for mid-2013.
If the proposal is accepted, the turnaround will not be done, and the facility will be converted into an import terminal prior to that date.
The boards of Shell Australia and Shell Refining Australia are expected to decide within weeks whether to close Clyde. However, any decision would be unlikely to affect the company's other Australian refinery at Geelong in Victoria.
IPIC, Oman Oil sign cooperative agreement
Oman Oil Co. (OOC) and Abu Dhabi's state-owned International Petroleum Investment Co. (IPIC) signed a cooperation agreement on investment projects in the sectors of oil, gas, and petrochemicals.
The joint effort is intended to result in the establishment of refineries and petrochemical projects, in addition to the exchange of expertise and technologies, said Nasser bin Khamis Al Jashmi, oil and gas ministry undersecretary and OOC chairman.
IPIC representative Khadim Abdullah Al Qubaisi said the two sides previously "cooperated in several investment projects, and now we hope that this agreement would be a starting point for investment projects in various local or global circles."
TRANSPORTATION — Quick TakesEnergy Transfer increases Eagle Ford gas pipeline
Energy Transfer Partners LP will expands and extend its previously announced Rich Eagle Ford Mainline (REM) natural gas pipeline and build a new processing facility in Jackson County, Tex.
ETP has long-term, fee-based agreements with multiple producers, including Rosetta Resources Operating LP, SM Energy Co., and a subsidiary of Anadarko Petroleum Corp., underpinning the planned construction. The new agreements include volume commitments exceeding 540,000 MMbtu/day.
The REM pipeline expansion, running from ETP's Chisholm Pipeline in DeWitt County east into Jackson County, Tex., will add 70 miles of 36-in. OD pipe to the initial 160-mile, 30-in. REM pipeline announced in February.
The completed pipeline will have a capacity of at least 600 MMcfd. Completion of REM's initial phase remains scheduled for the fourth quarter. Completion of the expansion is scheduled for first-quarter 2013.
The Jackson County gas processing plant will have 600 MMcfd capacity, expandable to 800 MMcfd, and is scheduled for completion in first-quarter 2013. ETP estimates total cost of the REM expansion and Jackson County processing facility at $450 million.
The REM project will expand ETP's midstream infrastructure in the Eagle Ford, which includes the recently completed Dos Hermanas pipeline and the Chisholm pipeline scheduled for completion later this quarter (OGJ Online, Feb. 18, 2011).
Kinder Morgan repairing Trans Mountain Pipeline
Kinder Morgan Canada planned to repair its Trans Mountain Pipeline near Edmonton, Alta., by late Apr. 26 following a small, localized release of crude oil, the company reported.
"During an overnight inspection of the pipe, no free oil was visible during excavation, confirming the small, localized impact of the release," the company said. The pipeline was shut down on Apr. 22 after a farmer reported finding oil in a field. No additional details were immediately available.
"We have been working cooperatively with all involved in responding to and impacted by this response," Kinder Morgan said in a news release. "Environmental mitigation measures are in place…. Access to the pipeline was initially slowed by seasonally high water and wet soil."
The 1,150-km Trans Mountain Pipeline transports oil and refined products from Edmonton to the US.
Shell joins Wheatstone LNG project
Shell Australia has joined the Wheatstone LNG project as both gas supplier and equity participant following the signing of a unitization agreement with project operator Chevron Australia.
Under the agreement Shell, which held a 33.33% stake in retention lease WA-16-R—one of two permits that contain part of the Iago gas field—will now have an 8% interest in the Wheatstone and Iago fields in the Chevron-operated permits WA-253-P, WA-17-R, and WA-16-R.
Shell also will take a 6.4% interest in the proposed Wheatstone project facilities. Front-end engineering and design work for Wheatstone is nearing completion and a final investment decision is expected during the second half of this year after finalization of environmental approvals and other associated agreements with the government.
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