GENERAL INTEREST — Quick Takes
Rosneft, other investors to buy Essar Oil
Owners of Essar Oil Ltd., which operates a 405,000-b/d refin-ery at Vadinar, India, have entered agreements to sell a total of 98% of the company to Russian and other investors for $12.9 billion cash.
A subsidiary of PJSC Rosneft, Petrol Complex Pte. Ltd., will buy a 49% interest. A consortium led by the trading group Trafigura and including United Capital Partners (UCP) of Mos-cow, will buy the other 49% stake.
Essar Energy Holdings Ltd., which owns Essar Oil with Oil Bidco (Mauritius Ltd.), said the deals cover enterprise values of $10.9 billion for the refinery and retail operations and $2 billion for the deepwater Vadinar port in Gujarat.
Enterprise Oil's retail business includes about 2,700 service stations.
Interests in the consortium led by Trafigura are Trafigura and UCP, 49% each, and Essar Holdings, 2%.
Court rejects export of Barmer basin crude
Efforts by Cairn India Ltd. to export crude oil produced in the Barmer basin of Rajasthan have been rejected by the New Delhi high court.
Because state-owned companies are not buying all the production it produces in Rajasthan, the Vedanta Group company must sell to privately held Reliance Industries Ltd. and Essar Oil Ltd. at prices it says are 10-20% below international levels.
The Indian government opposes crude exports, arguing the country is not self-sufficient in oil.
Cairn India operates the Barmer basin fields under a production-sharing contract in which it holds a 70% interest with state-owned Oil & Natural Gas Corp. holding the remainder.
In court, the government argued the PSC doesn't provide for sales abroad.
Production recently was about 200,000 b/d from Mangala, Bhagyam, and Aishwariya fields.
USEA: Shale producers need to address public concern
Tight shale oil and gas producers need to address public con-cerns more effectively as technological processes help them improve recovery rates and reduce surface disruptions, a speaker told the US Energy Association's 2016 Energy Supply Forum on Oct. 6.
Of the 10,000 unconventional wells that have been drilled in Pennsylvania, only 32 have had methane migration problems, said hydrogeologist Dave Yoxtheimer, an extension associate at Penn State University's Marcellus Center for Outreach & Research who also helps advise stakeholders on environmental issues.
"That's about 99.7% of the wells which haven't had to deal with methane migration," Yoxtheimer said. "The real risk is spills at the surface. Better fluids management and secondary containment are part of the answer. But if there are any problems at all, more work needs to done. Pennsylvania's producers and regulators are doing just that."
Unconventional wells represent about half of the nation's to-tal oil and gas production, Yoxtheimer said. Newer ones are much more efficient than their predecessors in several ways, he stated. They take 2 weeks to drill compared with 5-6 weeks. More rigs run on natural gas, which can save up to $1 million/year in drilling costs per rig. Shorter intervals are being hydraulically fractured. Larger laterals also are reducing production costs.
"Obviously, there are seismicity issues in some parts of the country, which means we need to be careful about how we manage fluids disposals," Yoxtheimer said. "Recycling fluids is ideal, but there are cases where they have to be treated. Sometimes, this can be so effective that the fluids can be released into streams. Other times, they need to be reinjected properly into the formations they came from."
Exploration & Development — Quick Takes
BP farms into giant North West Shelf prospect
Just days after announcing its withdrawal from the Great Aus-tralian Bight, BP Australia has acquired an 80% equity and operatorship of offshore Western Australian permit WA-409-P, which contains a giant Triassic-age Mungaroo formation pro-spect in the Carnarvon basin named Ironbark.
BP has farmed into the prospect formerly held 100% by Melbourne-based Cue Energy Resources Ltd. Cue retains 20% interest.
The deal entails BP funding 100% of the work program required for the permit for its first 3 years. BP also has an option until May 2017 to acquire 42.5% equity in permit WA-359-P, which is immediately south of WA-409-P. If BP does exercise the option, it will fund 50% of the cost of drilling a well in the second permit.
A well in WA-359-P is scheduled for first-half 2018, and BP will assist Cue in securing partners for drilling this well.
The Ironbark prospect, which could potentially hold 15 tcf of gas, has an aerial extent of 400 sq km and lies about 40 km north of the North Rankin and Goodwin field infrastructure owned by the Woodside Petroluem Ltd.-led North West Shelf joint venture of which BP is a participant.
The prospect straddles WA-409-P and WA-359-P and is in moderate water depths. If exploration is successful it has been noted that the North West Shelf LNG plant and infrastructure will have spare capacity from 2021. The Woodside-operated Pluto and the Chevron-operated Wheatstone pipeline infra-structure also is within reach.
BP's Ironbark farm-in deal has been in negotiation for some time and is understood to have predated the company's deci-sion to cancel the Great Australian Bight drilling program.
On that front, BP is now working with its partner Statoil ASA and the Australian government to reach an agreement on how to honor its drilling commitments off South Australia.
Statoil, which has 30% of the Bight permit, has said it is not ready to assume the commitments of BP that are necessary to proceed with the exploration program as planned.
NZOG, Beach Energy gain extension for Barque permit
New Zealand Oil & Gas Ltd. and Beach Energy Ltd. have been granted an extension of time for their Canterbury basin permit PEP 52717 offshore New Zealand's south island. The permit contains the prospective Barque prospect.
The joint venture now has until Apr. 10, 2018, to commit to drilling an exploration well, and until June 10, 2020, to ac-tually drill the well if they go ahead with the program.
Barque has the potential to hold 530 million bbl of oil-twice the size of the major Maui discovery offshore Taranaki basin that has been on stream since the 1970s.
New Zealand's Petroleum& Minerals Department decided to allow the permit extension in light of the downturn in activity in the country as a result of the fall in global oil prices.
NZOG and Beach each have equal interest in the permit. NZOG has said it is in talks with potential farm-in partners with the ability to operate the large deepwater prospect.
The extension announcement, however, coincided with a note from Norway's Statoil AS, which has pulled out of the remote Reinga basin in Northland, atop the North Island, because it believes the chances of making an oil discovery are too low to continue with its program.
Quadrant's Roc-2 appraisal confirms gas, condensate
The Quadrant Energy Ltd.-operated Roc-2 appraisal well in the Bedout subbasin offshore Western Australia 160 km north of Port Hedland has produced better-than-expected results during a sustained flow test program.
The well flowed at rates of as much as 51.2 MMcfd of gas along with 2,943 b/d of condensate through a 1½-in. choke. The well flowed at the maximum rate possible with the equipment used.
Quadrant reported insignificant levels of carbon dioxide, hydrogen sulphide, sand, and water in the flow stream.
The drillstem test was undertaken over 5 days. Drawdown for the high flow rate was about 500 psi, which indicates good productivity. Interpreted permeability of the reservoir is about 130 md across the perforated interval.
Roc-2 is in exploration permit WA-437-P and was drilled by Diamond Offshore Drilling's Ocean Monarch semisubmersible drilling rig.
The test exceeded the company's expectations, raising hopes that the well can be turned into a commercial producer. The report added that using standard equipment for North West Shelf developments, Roc-2 would be capable of producing more than 100 MMcfd of gas-equivalent to about 10% of Western Australia's entire domestic demand-from a single well.
The well has provided significant new information about the quality of the Caley formation reservoir and provided comfort for development using a production platform within the Roc and nearby Phoenix South discovery area.
Quadrant has an 80% interest with fellow Perth-based Carnarvon Petroleum Ltd. holding the balance.
Statoil group makes minor finds at Njord North Flank
Exploration well 6407/7-9 S (NF-2) at the Njord North Flank in the Norwegian Sea encountered a 102-m gross oil-bearing reservoir in Middle and Lower Jurassic sandstones of the Ile and 157-m gross gas condensate-bearing column in Lower Jurassic sandstones in the Tilje formation.
Statoil Petroleum AS is operator of production license 107 C. Based on the results of 6407/7-9 S, the partnership drilled sidetrack well 6407/7-9A (NF-3) to test a fault-block lying to the east.
The sidetrack encountered a 195-m gross gas-bearing column in the Tilje formation and 140-m gross gas-bearing column in Lower Jurassic sandstones in the Are formation. No hydrocarbons were encountered in the Ile formation. Both wells are 6 km to the north of the Njord production facility.
Neither well was drillstem tested, but extensive data acqui-sition and sampling has been performed on both wells. Based on the data acquired, a preliminary estimate of the size of the NF-2 discovery is 1.3-18.9 million boe. Sidetrack NF-3 is estimated at 0.6-9.4 million boe.
Partner Faroe Petroleum PLC says the results are in line with predrill estimates. The partners will consider the discoveries along with other nearby discoveries for development with tie-in to Njord field.
Wells 6407/7-9 S and 6407/7-9 A were drilled to measured depths of 4,114 m and 4,931 m below the sea surface, respec-tively, and vertical depths of 4,105 m and 4,127 m below the sea surface, respectively. Both wells were terminated in the Are formation from the Early Jurassic Age. Both wells were drilled in 323 m of water by Songa Offshore AS's Songa Delta drilling facility.
Faroe in June was part of the group that encountered a 39-m gross gas, oil-bearing reservoir in the Brasse prospect in the Norwegian North Sea (OGJ Online, June 16, 2016). The firm now anticipates the spudding by yearend of an exploration well on the Eni SPA-operated Dazzler prospect in the Barents Sea.
Iranian proposal documents due Nov. 19
International oil companies interested in Iranian oil and gas projects must submit prequalification documents by Nov. 19, National Iranian Oil Co. said (OGJ Online, Sept. 1, 2016).
Projects to tendered remain unclear, the company added in an Oct. 17 press statement.
The company is opening projects to international participa-tion under a new contract format replacing the unsuccessful buyback framework. Under the new format, NIOC will form joint ventures and compensate partners with shares of production.
Contract terms will be longer than those of the buyback agreement, which essentially was a service contract.
Earlier this month NIOC signed contracts of the new design with local company Persia Oil & Gas Development Co. for de-velopment of Yaran oil field and improved recovery at Maroun and Koupal oil fields.
It said it expects to sign more contracts with Iranian companies.
For international tenders, a final list of prequalification applicants will be published on Dec. 7, NIOC said on its web site.
The press statement said fields to be tendered to interna-tional bidders might include Azadegan, Yadavaran, and Yaran.
Earlier this month the company said 10 European and Asian companies had submitted proposals to the Ministry of Petrole-um for 15 projects.
Drilling & Production — Quick Takes
First oil export leaves Kashagan field after restart
After years of delays and billions of dollars in cost overruns, the Kashagan project has finally shipped its first export batch of crude oil from its onshore processing plant.
Production from the giant oil field in the North Caspian Sea, 80 km southeast of Atyrau in Kazakhstan, was shuttered just weeks after it first came on stream in 2013 due to a gas leak from its subsea pipeline system (OGJ Online, Sept. 11, 2013).
Field production is expected to gradually increase to 180,000 b/d, with a target of 370,000 b/d to be reached by yearend 2017, partner Eni SPA said. Discovered in 2000, Kashagan's estimated reserves total 35 billion bbl of oil in place.
"We expect a fast ramp-up at Kashagan," commented research and consultancy group Wood Mackenzie Ltd. upon news of the restart. "However, Phase 1 production is limited by physical capacity at onshore and offshore facilities."
Kashagan is operated by the North Caspian Operating Co. BV consortium as part of the North Caspian Sea production-sharing agreement. Partners are Kazakhstan's state-owned KazMunayGas with 16.88% interest; Eni, Total SA, Royal Dutch Shell PLC, and ExxonMobil Corp., each with 16.81%; China Na-tional Petroleum Corp. with 8.33%; and Inpex Corp. with 7.56%.
Aramco extends contracts for jack up rigs
Saudi Aramco negotiated a 3-year contract extension with Asia Offshore Drilling Ltd. (AOD) for the AOD I and AOD II jack up drilling rigs. Those contracts were due to expire in June 2019 and July 2019, respectively.
The rigs have worked for Aramco since 2013, AOD said. Seadrill Ltd. owns 66% of AOD and manages its jack ups.
AOD's third jack up, AOD III, also continues to work with Aramco as a result of a contract extension. An initial 3-year contract for the AOD III, due to expire in October, was extended until Dec. 31.
Aramco maintains an active offshore program in the Persian Gulf.
Subsea power standardization seeks to lower costs
A joint industry project on subsea electrical power standard-ization has published an international industry standard on the design, testing, and qualification of subsea power trans-formers. The standard seeks to reduce subsea field development costs by creating more uniformity.
Operators involved in the effort were Statoil ASA, Royal Dutch Shell PLC, Total SA, Petroleo Brasileiro SA, Chevron Corp., ExxonMobil Corp., and Woodside Petroleum Ltd.
Subsea power transformers reduce high voltage to levels that can be used by pumps, water injectors, and gas compressors.
"The need for transparency, collaboration, and standardiza-tion between operators, contractors, and suppliers is greater than ever before," said Michael Sequeira, deepwater practice leader at OTM Consulting. "The growing complexity and cost of advanced subsea systems dictates the need for cross-industry collaboration."
PROCESSING — Quick Takes
Koch studies sale of Rotterdam refinery
Koch Supply & Trading is considering the sale of its 85,000-b/d refinery in Rotterdam.
The Koch Industries subsidiary acquired the facility in 1998, when it had capacity of 65,000 b/d and processed only condensate (OGJ Online, Sept. 9, 2004).
The refinery now processes a blend of crude and condensate and is, according to the company, the largest producer of naphtha in Northwest Europe.
"We feel the asset's value is likely greater for parties with existing condensate streams or additional operational synergies," said Michael Yates, director of structured finance.
Simmons & Co. International/Energy Specialists of Piper Jaffray is advising Koch on the prospective sale.
Russian ethylene plant due cracking furnaces
PJSC Kazanorgsintez has let a contract to a division of Technip SA for delivery of three furnaces to the operator's ethylene plant in Kazan, Tatarstan, Russia.
Technip Benelux BV, Zoetermeer, the Netherlands, will provide engineering and procurement for three gas-cracking furnaces equipped with Technip's proprietary SMK coil technology, the service provider said.
The project comes as part of Kazanorgsintez's ongoing cracking-furnaces replacement program and follows Technip's previous deliveries of SMK double-cell cracking furnaces to the Kazan plant in 2007 and 2015 (OGJ Online, Feb. 17, 2014).
While it did not disclose a precise amount of the contract, Technip did confirm the value at less than €50 million.
The furnaces are due for mechanical completion in 2018, Technip said.
Yasref taps CLG technology for Yanbu refinery
Yanbu Aramco Sinopec Refining Co. Ltd. (Yasref), a joint ven-ture of Saudi Aramco (62.5%) and China Petrochemical Corp. (Sinopec) (37.5%), has implemented technology licensed by Chevron Lummus Global (CLG), a joint venture of CB&I and Chevron Corp., in the hydrocracker of its 400,000-b/d refinery along the Red Sea in Saudi Arabia's Yanbu Industrial City.
Initially commissioned in September 2015, the 124,000-b/sd, fresh-feed hydrocracker is equipped with CLG's proprietary maximum-conversion Isocracking technology and two-stage reccle configuration design, which has enabled the unit to steadily produce 263,000 b/sd of high-quality, middle distil-lates, Euro 5-quality diesel, and aviation kerosine, CLG said.
Alongside the Yanbu refinery, CLG also has licensed its Isoc-racking technology in Saudi Arabia for two hydrocracking units with a total capacity of 120,000 b/sd at Saudi Aramco Total Refinery & Petrochemicals Co.'s (Satorp) 400,000-b/d full-conversion refinery complex at Jubail, which entered operation in 2014 (OGJ Online, May 23, 2016), according to a July 2008 release from CLG.
Aramco also has let a contract to CLG to provide an Isocrack-ing hydrocracking unit equipped to convert 106,000 b/d of vacuum gas oil into Euro 5-quality diesel at its a 400,000-b/d refinery now under construction at Jazan Economic City (OGJ Online, Feb. 8, 2016), CLG said in a 2011 release announcing the award.
As of early 2016, the Jazan refinery's CLG hydrocracker was still in its detailed-engineering and construction phase, ac-cording to Chevron's Saudi Arabia country web site.
Previously scheduled for startup late this year, the Jazan refinery and associated marine terminal project-which will be coordinated with a large integrated gasification combined-cycle plant-are due to be fully commissioned in 2017.
TRANSPORTATION — Quick Takes
Suncor, Mikisew Cree First Nation sign deal for tank farm
Suncor Energy Inc., Calgary, and Mikisew Cree First Nation (MCFN) signed an equity agreement for Suncor's East Tank Farm Development in the Wood Buffalo area of Alberta.
MCFN will pay 14.7% of the actual capital cost of the devel-opment once the assets become operational, which is expected in second-quarter 2017. MCFN's payment is anticipated to be about $147 million (Can.). The deal is subject to a number of closing conditions.
The agreement follows Suncor's deal in September with Fort McKay First Nation for 34.3% equity (OGJ Online, Sept. 7, 2016). The combined equity interest by Fort McKay and Mikisew would be 49%.
The tank farm will consist of bitumen storage, blending and cooling facilities, and connectivity to third-party pipelines.
PHMSA finalizes excess flow valve rule for gas pipelines
The US Pipeline & Hazardous Materials Safety Administration issued a final rule on Oct. 7 for excess flow valves on new and replaced distribution pipelines. The final rule requires installation of EFVs in new or replaced service lines for multifamily residences-including apartment buildings and other multiresidential dwellings-and small commercial buildings.
The regulation, which becomes effective 6 months after its publication in the Federal Register, also requires gas distribution companies to install curb valves-manually operated shutoff valves located near the service main-or EFVs for all new or replaced service lines with meter capacities exceeding 1,000 scf/hr to protect against uncontrolled gas releases from larger commercial and industrial users, the US Department of Transportation agency said.
The American Gas Association welcomed the final excess flow valve rule. "AGA has been supportive and committed to the expanded use of EFVs, as seen in AGA's Commitment to Enhancing Safety," it said on Oct. 11. "The final rule now codifies these voluntary actions and also incorporates ancillary re-quirements that, while beneficial, may require additional guidance from PHMSA before operators are able to fully comply."
The gas utility trade association hopes PHMSA's announcement of this final rule indicates progress on several remaining rulemakings that are being developed that are intended to en-hance pipeline safety, its statement said. "AGA believes that reasonable rulemakings will allow the industry to move forward, in responding to Congressional directives contained in pipeline safety legislation," it said.
GAIL orders gas pipeline laying work in eastern India
GAIL (India) Ltd. has placed orders for 345 km of natural gas pipelaying work in eastern India, from Phulpur, Uttar Pradesh, to Dobhi, Bihar.
GAIL said JSIW Infrastructure Pvt. Ltd. and IL&FS Engineering & Construction Co. Ltd. will handle the pipelaying of two sections simultaneously. Work will begin by the end of October and is expected to be complete by December 2018.
The work is part of the Jagadishpur-Haldia-Bokaro-Dhamra Pipeline (JHBDPL), designed for 2,539 km across five states. JHBDPL is scheduled for completion in December 2020.