Official suggests merger of Indian state oil firms
India's finance minister has suggested consolidation of some or all of the oil and gas companies controlled by the central government.
Arun Jaitley, union minister for finance and corporate affairs, introduced the idea while presenting the 2017-18 budget to the parliament.
Most oil and gas companies active in India are "public sector undertakings" (PSUs), in which the government owns varying majority interests.
The largest are Oil & Natural Gas Corp. Ltd. and Oil India Ltd., which are mainly producers; Indian Oil Corp. Ltd., Hindustan Petroleum Corp. Ltd., and Bharat Petroleum Corp. Ltd., which are mostly refiners; and GAIL (India) Ltd., a natural gas and pipeline company.
Among Indian companies not owned by the government are integrated Reliance Industries Ltd. and Essar Oil and independent producer Cairn India Ltd.
In his budget presentation, Jaitley listed among "key initiatives" the "creation of an integrated public-sector 'oil major' to integrate the oil sector PSUs across the value chain and to enhance capacity of oil PSUs to bear higher risks, avail economies of scale, take higher investment decisions, and create more value for the stakeholders."
Delek Group to acquire Ithaca Energy
Delek Group, Tel Aviv, has agreed to buy shares of North Sea producer Ithaca Energy Inc., Aberdeen, that it doesn't now own for $555 million.
Ithaca has interests throughout the UK North Sea and soon will start production from Stella oil and gas condensate field in the Central Graben area of the Central North Sea (OGJ Online, Aug. 2, 2016).
Ithaca's production last year averaged 9,300 boe/d. The company expects average production this year of 19,000-22,000 boe/d, reflecting the Stella start-up.
The company also expects to complete development drilling at Harrier field, which is near Stella, this year.
Ithaca is a partner with privately owned Dyas and Petrofac in development of the Greater Stella Area production hub.
Through a subsidiary, Delek now owns 19.7% of Ithaca, the board of which has approved the takeover.
BP sets 2017 capital spending at $16-17 billion
BP PLC reported it intends in 2017 to spend $16-17 billion, which is equal if not slightly more than the $16 billion the firm spent in 2016.
BP says it now anticipates breaking even by yearend at Brent crude oil prices of around $60/bbl given the mostly second-half startups of its new upstream projects. At the end of third-quarter 2016, the firm said it remained "on track to rebalance organic cash flows next year" at $50-55/bbl.
The British firm reported a fourth-quarter 2016 underlying replacement cost profit of $400 million compared with $196 million for the same period in 2015 and $933 million for third-quarter 2016.
Compared with a year earlier, the quarter's result benefited from higher oil prices and much lower costs, offset by weaker refining margins and higher turnarounds in the firm's downstream segment.
The headline reported result for the full year was a profit of $115 million compared with a loss of $6.5 billion for 2015.
The 2016 headline result included a total of $4 billion nonoperating charges taken through the year associated with resolution of the remaining legacy of the 2010 Deepwater Horizon oil well blowout and spill. The headline profit excluding these legacy charges was $4.1 billion for 2016 compared with $2 billion for 2015.
BP made $7.1 billion in pretax payments related to the Macondo spill through 2016, as processing of outstanding claims accelerated. Total divestment revenues were $3.2 billion in the year.
Cash payments related to the spill in 2017 are expected at $4.5-5.5 billion, before falling to around $2 billion in 2018 and to a little more than $1 billion/year from 2019.
The firm reported a reserves replacement ratio of 109% for 2016.
ConocoPhillips to increase spending slightly in 2017
ConocoPhillips plans to increase spending this year, forecasting capital expenditures of $5 billion compared with $4.9 billion during 2016, executives said Feb. 2 as they released an earnings report.
Separately, Royal Dutch Shell PLC also announced earnings Feb. 2, saying it plans spending of $25 billion during 2017, down from $26.9 billion in spending for 2016.
Ryan Lance, ConocoPhillips chairman and chief executive officer, said, "For the second quarter in a row our cash from operating activities exceeded capital expenditures and dividends paid. Our capital intensity and cost structure are dramatically lower."
Quarterly revenues rose during late 2016 for the first time since 2014, he said. ConocoPhillips reported a fourth-quarter 2016 net loss of $35 million compared with a fourth-quarter 2015 net loss of $3.5 billion. Excluding special items, fourth-quarter 2016 adjusted earnings showed a $318 million net loss compared with a fourth-quarter 2015 adjusted net loss of $1.1 billion.
ConocoPhillips reported a $3.6-billion net loss for 2016 compared with a full-year 2015 net loss of $4.4 billion. Excluding special items, full-year 2016 adjusted earnings showed a $3.3-billion net loss compared with a $1.7-billion adjusted net loss in 2015.
Iran schedules upstream tender for Feb. 15
Iran has set its long-delayed tender for upstream oil and gas projects for Feb. 15. It's the first such tender since international sanctions were lifted from the country in early 2016.
Twenty-nine companies have been qualified to participate.
"The plan was to hold the first tender at the end of January, but it is postponed and has been set to be on Feb. 15," said Ali Kardor, managing director of National Iranian Oil Co.
He said the delay has been caused by incomplete information from some of the participating companies. "BP has not yet sent its information to us." Kardor explained. "Although we said this is an official process and you need to enter your information, they haven't done it."
Other recent deals with international companies signed by Iran include a preliminary agreement with Total SA for a $4.8-billion project to develop an offshore gas field at South Pars, which Iran shares with Qatar; and agreements to develop two oil fields with Gazprom PJSC, and to examine development of other oil fields alongside Royal Dutch Shell PLC.
Iran has increased its production to 3.9 million b/d from 2.6 million b/d in 2013.
Sri Lanka invites bidders for block in Mannar basin
The Sri Lankan government is inviting expressions of interest for appraisal and development of natural gas on offshore Block M2 in the Mannar basin.
M2 lies off western Sri Lanka and covers 2,924 sq km, including the Barracuda and Dorado gas-condensate discoveries.
The Ministry of Petroleum Resources Development said the block, formerly known as 2007-01-001, was recently relinquished by Cairn India Ltd.
A data package containing well data and 2,600 sq km of 3D seismic will be available. Government officials are planning private meetings in March in Houston and London.
Late last year, the ministry signed an agreement with IHS Energy to market M2's seismic and well log data, and conduct preliminary discussions with interested parties.
A bid round for additional acreage, including offshore eastern Sri Lanka, is planned for this year's fourth quarter.
ONGC Videsh plans well offshore Bangladesh
ONGC Videsh Ltd., New Delhi, plans to spud an exploratory well in shallow water offshore Bangladesh "in the next several months," according to an official of Bangladesh Oil, Gas & Mineral Corp. (Petrobangla).
Mahbub Sarwar, Petrobangla director for production-sharing contracts, told the Financial Express of Dhaka the Indian company had completed a 2D seismic survey over two Bay of Bengal blocks last year and plans to drill the first of two commitment wells on Block SS-09 near Moheshkhali.
All Bangladeshi gas production of about 2.7 bcfd comes from onshore fields. Petrobangla estimates consumption at 3.3 bcfd.
ONGC Videsh operates 7,026-sq-km Block SS-09 and holds 45% interest in the production-sharing contract. Partners are Oil India Ltd., 45%, and state-owned Bangladesh Petroleum Exploration & Production Co. (BAPEX), 10%.
Interests are the same in adjacent Block SS-04, which covers 7,226 sq km.
Statoil reports gas discovery near Valemon in N. Sea
Statoil ASA reported a natural gas discovery, Valemon West, in the North Sea thought to hold 20-50 million boe.
The West Elara jack up drilled the 34/11-6 S to a vertical depth of 4,337 m below the sea surface in 133.5 m of water in PL 193 D near the Valemon field.
The Norwegian Petroleum Directorate said the wildcat was terminated in the Drake formation in the Lower to Middle Jurassic. The well encountered gas columns of about 80 m in the Tarbert formation and 35 m in the Ness formation.
NPD said there were 50 m of sandstone with moderate-to-good reservoir quality in the Tarbert and 10 m of sandstone with poor reservoir quality in the Ness. NPD cited preliminary estimates of 3-8 million cu m of oil equivalents recoverable.
Statoil called the Valemon reservoir "complex because it is fragmented and also because of its high pressure and high temperature."
Production from Valemon field began 2 years ago (OGJ Online, Jan. 5, 2015). Statoil said it contains about 192 million boe.
Drilling & Production — Quick TakesShell to decommission part of Brent field in N. Sea
Shell UK Ltd. announced an extended 60-day public consultation on recommendations to decommission certain platforms on Brent oil and gas field in the UK North Sea. Shell submitted a decommissioning program to the UK Department of Business, Energy, and Industrial Strategy (BEIS).
Brent field, 115 miles northeast of the Shetland Islands, has produced about 3 billion boe since 1976.
The decommissioning program recommends removal of Rent Alpha platform's upper steel jacket along with the topsides of the four Brent platforms, seabed debris, and attic oil in the concrete storage cells of the gravity base structures.
Work preparing for Brent field decommissioning started in 2006. More than 300 expert studies were completed. Independent scientists analyzed and verified results of those studies.
Production from Brent Delta platform ceased in 2011 and from Brent Alpha platform and Brent Bravo platform in November 2014. Production from Brent field will continue, via Brent Charlie platform, for several years to come, Shell said.
Shell recommends the three gravity-base structures, Brent Alpha footings, the sediment contained within the concrete storage cells of the gravity-base structures, and the drill cuttings piles remain in place. The three gravity-base structures are Brent Bravo, Brent Charlie, and Brent Delta.
Recommendations require the support of the OSPAR Commission, set up by the OSPAR Convention to protect the marine environment. BEIS will consider the recommendations after the consultation period ends. BEIS will seek support from the OSPAR Commission on Shell's behalf.
The decommissioning program outlines various options for 28 pipelines connected to Brent field.
Wood urges UKCS industry collaboration
Ian Wood, who led development of a strategy to revive oil and gas work on the UK Continental Shelf, says the industry risks falling far short of realizing full North Sea potential.
Speaking in Aberdeen, the retired Wood Group chairman said recently improved operating methods enable recovery of 9-10 billion boe more oil and gas in the UK North Sea.
But industry estimates put the potential at 20 billion boe.
New technology and "serious collaboration" among operators in the development of small fields can add 5-10 billion boe to recovery, Wood said.
In 2013-14, he chaired a committee that made recommendations, many adopted by the UK government, for taxation and regulatory changes aimed at "maximum economic recovery" of the mature UKCS resource (OGJ Online, Aug. 31, 2015).
The committee also called on companies and the government to work together more than they had in the past.
"Collaboration is still the biggest single thing that will lead to improvement," Wood said in Aberdeen.
Eni starts production from East Hub off Angola
Eni SPA has started production from the East Hub development project on deepwater Block 15/06 offshore Angola.
Production is taking place through the Armada Olombendo floating production, storage, and offloading vessel, whose capacities total 80,000 b/d of oil and 3.4 million cu m/day of gas. With 9 wells and 4 manifolds in 450 m of water, the FPSO will bring into production Cabaca South East field, 350 km northwest of Luanda and 130 km west of Soyo.
The East Hub project will add to production from the existing West Hub project covering Sangos, Cinguvu, and Mpungi fields, where another FPSO, the N'Goma, is operating. Production from West Hub started in 2014 (OGJ Online, Dec. 8, 2014). In total, Block 15/06 will reach a peak production of 150,000 bo/d this year.
Eni says it has discovered 3 billion bbl of oil in place through 10 commercial discoveries on Block 15/06. Cabaca South East brings to 5 the number of fields Eni has in production, with 2 more expected to start up before yearend 2018.
Claudio Descalzi, Eni chief executive officer, said East Hub production startup has begun "with a time-to-market of only 3 years and 5 months ahead of schedule" due to "strong field development and project management."
Block 15/06 is operated by Eni with 36.84% interest. Sonangol Pesquisa e Producao controls 36.84% and SSI Fifteen Ltd. has 26.32%. Eni has been present in Angola since 1980 through its subsidiary Eni Angola. Equity production amounted to 124,000 boe/d in 2016.
ONGC to develop field off west coast of India
India's Oil & Natural Gas Corp. Ltd. said it will invest $66 million for development of North West B-173A field off the country's west coast.
ONGC plans one wellhead platform with three wells and production startup by February 2019. The company expects a peak production rate of 2,870 b/d of oil and 56,350 cu m/day of natural gas by 2020.
The field is 5 km northwest of B-173A in 55 m of water. Oil and gas will be shipped south via new pipelines to existing processing facilities in Neelam field.
In April 2014, ONGC drilled the B-173A-8 exploratory well, which resulted in declaration of a field discovery for North West B-173A after it produced 2,246 b/d in conventional testing.
PROCESSING — Quick TakesChinese refiner lets contract for alkylation unit
Shaanxi Yanchang Petroleum (Group) Co. Ltd. (SYPC) has let a contract to CB&I, Houston, to provide technology licensing and related services for an alkylation unit at its 161,000-b/d refinery at Yanan City in China's Shaanxi Province.
As part of the contract, CB&I will deliver engineering design for the grassroots unit, which will be equipped with the service provider's proprietary CDAlky advanced sulfuric acid alkylation technology, CB&I said.
The unit comes in support of SYPC's goal to boost its market competitiveness and reduce environmental impacts of refinery operations by upgrading the quality of gasoline production using high-octane alkylate, CB&I said.
A value of the contract was not disclosed, and the service provider revealed no details regarding either a proposed capacity of the alkylation unit or a timeframe for its commissioning.
In late 2016, SYPC said ongoing improvement projects at the Yanan plant have boosted the refinery's yield of gasoline to 99.49%, which will continue to improve amid a series of unidentified optimization, debottlenecking, and efficiency projects already planned for the coming year, according a company release dated Dec. 22, 2016.
Contract let for Louisiana methanol complex
Yuhuang Chemical Inc. (YCI), a subsidiary of China's Shandong Yuhuang Chemical Co. Ltd. (SYCC), has let a contract to a division of Amec Foster Wheeler PLC (AFW) to supply an auxiliary boiler for YCI's proposed $1.85-billion methanol manufacturing complex now under construction along the Mississippi River in St. James Parish, La. (OGJ Online, July 18, 2014).
AFW's global power group will design and deliver a fully assembled 580,000-lb/hr steam generator that will provide the equivalent of about 60 Mw of high-pressure steam for the first phase of YCI's St. James methanol project, AFW said.
In addition to the natural gas-fired auxiliary boiler, AFW's scope of delivery includes the fan, ductwork, combustion system, as well as heat-recovery and selective-catalytic reduction equipment necessary to meet emissions requirements, the service provider said.
This latest contract follows YCI's previous award to AFW for engineering, procurement, early construction services, and project management for Phase 1 of the grassroots complex, which will include a 1.7 million-tonne/year methanol plant due for startup in early 2018 (OGJ Online, Sept. 16, 2015).
Scheduled to be fully commissioned within 10 years, the $1.85-billion complex will host two methanol plants with a combined capacity of 3 million tpy, as well as a methanol derivatives plant for production of intermediate chemicals, YCI said.
While YCI plans to export most of the complex's methanol production by oceangoing vessels for use in SYCC's production of downstream chemicals in China, about 20-30% will be shipped by barge and rail to be sold to North America.
Saudi propylene producer lets licensing contract
AL WAHA Petrochemicals Co., a joint venture of Sahara Petrochemicals Co. 75% and Basell Arable lnvestissements SAS 25%, has let a contract to Honeywell International Inc. subsidiary Honeywell UOP LLC, Des Plaines, Ill., to provide a suite of cloud-based technology and interactive support services aimed at helping to explore possibilities for maximizing propylene production at its plant in Al Jubail Industrial City, in Saudi Arabia's Eastern Province.
As part of the contract, UOP will implement its proprietary Connected Performance Services (CPS) technology, a cloud-based service that will integrate portions of the plant's specific process data with UOP's history of operating experience to predict potential operational issues and deliver AL WAHA real-time, actionable recommendations and solutions to ensure the plant runs at peak efficiency with the highest reliability.
Specifically, AL WAHA will use CPS' Process Reliability Advisor (PRA) tool to continuously analyze operation of the plant's Oleflex unit, which is equipped to produce 467,600 tonnes/year of propylene as primary feedstock for the production of 450,000 tpy of polypropylene (OGJ Online, June 14, 2016).
In addition to delivering detailed analysis of unit operations, the PRA tool will provide AL WAHA with corrective recommendations to prevent future production interruptions and improve performance, all of which will further the operator's objective of maximizing the unit's on-stream reliability while simultaneously optimizing its consumption of propane.
TRANSPORTATION — Quick TakesPetronas boosts capacity at Malyasian LNG complex
State-run Petronas subsidiary Petronas LNG 9 Sdn. Bhd. (PL9SB) has started commercial operations of the ninth LNG liquefaction train at the Petronas LNG Complex (PLC) in Bintulu, Sarawak, Malaysia (OGJ Online, Feb. 24, 2012).
Equipped with a nameplate capacity of 3.6 million tonnes/year, the new production train entered commercial operation on Jan. 1, said JX Nippon Oil & Energy Corp. (JX NOE), Tokyo, which owns a 10% interest in PL9SB.
Startup of PL9SB's liquefaction plant raises total production capacity at PLC to about 30 million tpy from its previous capacity of 25.7 million tpy.
Announcement of PL9SB's official launch of commercial operations follows initial startup, commissioning, and production activities at the train in September 2016, Petronas said in its latest quarterly earnings presentation to investors.
JX NOE, which purchased equity interest in PL9SB in June 2016, also holds 10% interest in Petronas unit Malaysia LNG Tiga Sdn. Bhd.'s operations at PLC, according to separate June 3, 2016, releases from JX NOE and Petronas.
In 2012, Petronas said Train 9, once completed, will receive its required feed gas of up to 850 MMcfd from various fields off Sarawak and, alongside all associated utilities, include units for gas receiving, acid gas removal, dehydration and mercury removal, fractionation and liquefaction, and LNG rundown.
Gazprom lets contract for Portovaya LNG plant
Russia's PJSC Gazprom, through a contractor, has let a contract to Linde AG, Munich, to provide licensing for a midscale LNG production, storage, and shipment complex in Portovaya, Russia, at the Baltic Sea. As part of the contract awarded by SRDI Oil & Gas Peton LLC-Gazprom's general contractor partner for the Portovaya LNG project-Linde will deliver basic engineering, equipment, and related bulk material for the plant and its cryogenic units, which will be equipped with the service company's proprietary LIMUM technology, Linde said.
The 1.5-million tonne/year LNG plant will process natural gas arriving from the nearby Portovaya compressor station on Gazprom's Nord Stream gas trunk line.
