GENERAL INTEREST Quick Takes
Aramco earned $47 billion in first half
In its first disclosure of financial results, Saudi Aramco on Aug. 12 said it earned net income of $46.9 billion on revenue of $163.9 billion in the first half of 2019, compared with net income of $53 billion on revenue of $167.7 billion in the same period a year earlier.
Free cash flow was $38 billion in the first half vs. $35.6 billion in first-half 2018. First-half capital expenditure fell to $14.5 billion from $16.5 billion in last year’s first half. The company reported average production of 10 million b/d of crude oil and 13.2 million b/d of oil-equivalent hydrocarbons in the current-year period. Refining gross throughput was 4.6 million b/d.
Aramco Pres. and CEO Amin H. Nasser said the unprecedented financial disclosure was “part of our $12-billion debut international bond issuance” that “marked a significant milestone in Saudi Aramco’s history.”
Qatar investing in Permian midstream firm
Qatar’s sovereign wealth fund will invest about $550 million in Oryx Midstream Services, a privately held midstream crude operator in the Permian basin.
An affiliate of Qatar Investment Authority (QIA) has acquired “a significant stake” in Oryx from an affiliate of Stonepeak Infrastructure Partners and committed to invest in Oryx development, QIA said.
Oryx has 1,200 miles of crude oil pipelines in service or under construction in eight counties in Texas and two in New Mexico. When construction is finished, its total throughput capacity will exceed 900,000 b/d.
QIA plans US investments totaling $45 billion.
ADNOC buys stake in global storage firm
Abu Dhabi National Oil Co. has acquired a 10% interest in VTTI BV, which owns 15 hydrocarbon storage terminals in 14 countries with total capacity of 60 million bbl.
Terms weren’t reported. Other VTTI interests now are IMF Global Infrastructure Fund and Vitol, 45% each.
VTTI’s terminals are in Asia, Africa, Europe, and Fujairah, where ADNOC has 8 million bbl of storage and is building underground storage with 42 million bbl of capacity (OGJ Online, Feb. 27, 2019).
ADNOC also has closed its $19.2-billion sale of interests in ADNOC Refining to OMV and ENI in a deal that creates ADNOC Global Trading, which will focus on trading ADNOC Refining products (OGJ Online, Jan. 28, 2019).
Bids sought for Videocon oil, gas assets
State Bank of India is soliciting bids for non-Indian oil and gas assets of financially beleaguered conglomerate Videocon Industries, Mumbai. It appointed Deloitte to seek buyers for properties in Brazil and Indonesia.
In Brazil, a Videocon subsidiary holds varying interests in five offshore concessions through its half interest in a joint venture with Bharat Petroleum Corp. Ltd. called IBV Brasil Petroleo Ltda. The concessions are BM-C-30 Campos, BM-SEAL-11 Sergipe, BM-ES-24 and ES-24A off Espirito Santos and Bahia states, and BM-POT-16 Potiguar. Discoveries have been made in three of the Brazilian concession areas.
In Indonesia, Videocon holds a 12.5% working interest in the Nunukan production sharing contract in the Tarakan basin off northeastern Kalimantan.
Oxy completes Anadarko acquisition
Occidental Petroleum Corp. reported the successful completion of its acquisition of Anadarko Petroleum Corp. in a deal valued at $55 billion, including the assumption of Anadarko’s debt. The deal moved to the approval phase in May (OGJ Online, May 10, 2019).
The closing of the transaction follows approval of the deal by Anadarko shareholders at a special meeting held Aug. 8. More than 99% of the shares voted at the meeting were in favor of the Oxy merger agreement.
Anadarko shareholders are receiving $59 in cash and 0.2934 of a share of Oxy common stock per share of Anadarko common stock. Anadarko’s common stock will no longer trade on the New York Stock Exchange as of end of trading Aug. 8.
Exploration & Development Quick Takes
China to ease exploration restrictions
China is opening oil and gas exploration to foreign investors by “scrapping joint-venture restrictions,” the official news agency Xinhua reported.
“The move aims to attract overseas participation in the field and advance the country’s ongoing reform of energy systems,” the Aug. 12 report said.
International companies now participate in technically challenging exploration and production in China through production sharing contracts and joint ventures with state-owned companies. The report didn’t describe future terms of participation or specify JV restrictions to be relaxed.
Tullow Guyana makes oil strike with Jethro-1 well
Tullow Guyana reported making an oil discovery with its Jethro-1 exploration well drilled to 4,400 m TD in 1,350 m of water. The well, drilled in the Orinduik license, encountered 55 m of net oil pay, exceeding Tullow’s predrill forecast.
The Stena Forth drillship drilled the Jethro-1, which hit oil-bearing Lower Tertiary sandstone reservoirs. Tullow will evaluate discovery well data to determine appraisal plans.
Tullow CEO Paul McDade said Jethro-1 is expected to hold more than 100 million bbl. Guyana has no oil production yet although ExxonMobil Corp. expects to start producing in 2020 from the Stabroek block (OGJ Online, May 3, 2019).
ExxonMobil forecasts the Stabroek block will produce more than 750,000 b/d by 2025 with Liza Phase 1 expected to come on stream in 2020. ExxonMobil has announced repeated discoveries on the Stabroek block, estimating its oil reserves at more than 5 billion bbl.
Tullow’s Jethro-1 discovery substantially lowers the risk for other Tertiary prospects in the Orinduik license, including the shallower Upper Tertiary Joe prospect, which Tullow expects to drill later this month. Tullow’s non-operated Carapa 1 well is scheduled to be drilled later this year in the adjacent Kanuku license to test a Cretaceous oil play.
Al Stanton of RBC Capital Markets said, “Jethro is not scheduled to be production tested so we expect the Stena Forth drillship to mobilize swiftly to the Joe location,” adding, “We anticipate this well result before the end of September.”
Stanton said he expects Carapa-1 will spud in September. “Thereafter, we expect the participants to reassess the seismic and well data before inking in their 2020 drilling programs,” he said.
Tullow Guyana operates the Orinduik block with a 60% stake. Total E&P Guyana BV holds 25% with the remaining 15% being held by Eco (Atlantic) Guyana Inc.
BHP makes FID for Ruby project off Trinidad
BHP Group Ltd., Melbourne, has made its final investment decision to develop the Ruby oil and gas project on Block 3A offshore Trinidad and Tobago.
The $500-million project involves a shallow-water tie-back of five production wells to existing processing facilities in Greater Angostura field on Block 2C about 8 km east.
Ruby field, discovered in November 2006, lies in 60-90 m of water about 40 km northeast of the twin-island nation’s coast.
The project has an estimated recoverable 2C resource of 13.2 million bbl of oil and 274 bcf of natural gas.
Start of production is scheduled for 2021 and BHP says it will increase production at peak from its Trinidad and Tobago assets by 16,000 b/d of oil and 80 MMcfd of gas. The gas is expected to be directed to Trinidad and Tobago markets.
BHP is operator with 68.46%. Heritage Petroleum has 20.13% and NGC of Trinidad & Tobago has 11.41% interest.
Aker BP gas strike reported off Norway
Aker BP ASA has plugged an exploration well and an appraisal at what the Norwegian Petroleum Directorate described as “a small gas discovery” 6 km southwest of Boyla oil field in the northern North Sea offshore Norway.
The directorate said the objective of the 24/9-13 wildcat was to prove petroleum in Eocene strata, while the 24/9-13A was to assess oil-water contacts.
The wildcat encountered a 3 m gas column in the Hordaland Group with 2 m of mainly good quality sandstone reservoir. It also cut several sandstone layers with mainly good quality totaling 17 m in the Balder formation.
The sandstones are thought to be remobilized sand from the Paleocene Heimdal and Hermod formations injected into overlying strata in the Eocene-Paleocene Rogaland and Hordaland group. The appraisal well encountered a gas column of about 40 m in injectite zones. A total of 7 m of sandstone had good to very good reservoir quality, interpreted as injected sands of the Hordaland group.
The wells did not encounter petroleum-water contacts. They proved a gas column of at least 77 m, NPD said. The wells, in 118 m of water, were not formation-tested. NPD said Aker BP is studying results for possible further delineation.
The Deepsea Nordkapp semisubmersible drilled the 24/9-13 to 2,272 vertical depth below sea surface and the 24/9-13 A to 2,240 m vertical depth and 3,433 m measured depth.
Aker BP is operator with a 60% interest in the license. Lundin Norway AS and Point Resources AS hold 20% interests each.
Drilling & Production Quick Takes
Hibernia field being prepared to return to production
Hibernia Management & Development Co. Ltd. is preparing to return Hibernia oil field to production following a July 17 oil slick observed by workers offshore Newfoundland and Labrador. The field was shut in July 17 (OGJ Online, July 19, 2019).
HMDC said a pipe from which the original discharge occurred contained a residual oil and water mixture resulting in 0.2 ml being released when valves were opened Aug. 9. HMCD said that was the volume of about 4 raindrops and that the oil dissipated naturally. All possible measures were taken to prevent an additional discharge, with multiple spill response efforts in place to ensure any residual oil and water mixture from the pipe is captured, HMDC said.
Mitigation measures include vessels equipped with spill response equipment and spill detector radar on location.
HMDC has worked in collaboration with regulatory and response agencies, including the Canada Newfoundland and Labrador Offshore Petroleum Board (CNLOPB), independent Certifying Authority Lloyd’s Register, and Eastern Canada Response Corp. to prepare for a return to production. A date for returning the field to production will be determined during continued discussions with CNLOPB.
Expanded Thrace basin well testing mulled
Valeura Energy Inc., Calgary, and Equinor might expand testing of the Inanli-1 appraisal well in their basin-centered gas accumulation play of northwestern Turkey based on results from the first tested zone (OGJ Online, June 25, 2019).
Inanli-1 is the first of two wells drilled to appraise the 2017 Yamalik discovery (OGJ Online, Oct. 9, 2018). The other appraisal well is Devepinar-1. All three Thrace basin wells encountered more than 1,300 m of overpressured tight gas, Valeura reported recently.
The first Inanli-1 reservoir stimulation was relatively small, with one third of the originally planned amount of proppant injected into the zone at 4,263-4,284 m.
Petrophysical data indicate the zone is moderately fractured with 14.2 m of net sand above a 3% porosity cutoff with average porosity of 5%.
On artificial lift through production tubing installed after reservoir stimulation, the well flowed at an average rate of 643 Mcfd for the first 8 days, excluding artificial-lift gas.
Water production during flowback declined steadily to 44 b/d on the eighth day of production.
The measured condensate-gas ratio is 5 bbl/MMcf.
Valeura, the operator, and 50-50 partner Equinor originally planned to stimulate and test four zones in Inanli-1. Valeura said they’re considering increasing the number of stimulations and tests.
Well starts in North Sabah infill program
SEA Hibiscus Petroleum Sdn. Bhd., Kuala Lumpur, has started production from the first of three infill wells planned for St. Joseph oil field under the 2011 North Sabah Enhanced Oil Recovery Production-Sharing Contract offshore Malaysia.
The SJ-105A well flowed at a stabilized rate above 1,000 b/d with no water. About 1,000 ft of the well’s 2,400-ft horizontal section encountered targeted reservoirs.
St. Joseph field is one of four fields in the PSC area that together produced an average of 14,670 b/d of oil from 135 wells in 20 platforms and structures during the first quarter this year.
Hibiscus, which operates the PSC with a 50% interest, expects infill drilling to raise production by 2,000 b/d at St. Joseph field and by 4,000 b/d at nearby SF30 field. It expects incremental reserves of 2.77 million stb at St. Joseph and 3.6 million stb at SF30.
The PSC area, 33 km off Kota Kinabalu, Sabah, has water depths of 18-60 m. Its other producing fields are South Furious and Barton.
Production flows by pipeline to the Labuan Crude Oil Terminal operated by Hibiscus, which processes about 50,000 b/d of crude for Hibiscus and others.
Hibiscus bought its North Sabah PSC interest from two Shell units in 2018 (OGJ Online, Apr. 2, 2018).
Petronas Carigali Sdn. Bhd. holds the other 50%.
PROCESSING Quick Takes
Aramco to take 20% stake in RIL’s downstream business
Saudi Aramco and Reliance Industries Ltd. (RIL) have signed a nonbinding letter of intent regarding Aramco’s proposal to purchase a 20% stake in RIL’s oil-to-chemicals (O2C) division, which includes its refining, petrochemicals, and fuels-marketing businesses.
Based on an enterprise value of $75 billion, Aramco’s planned investment would be one of the largest foreign investments ever made in India, RIL said.
While few details about the letter were revealed, RIL did confirm the proposed investment would result in Aramco supplying 500,000 b/d of Arabian crude oil to RIL’s 580,000-b/d Jamnagar integrated refining and petrochemical complex in Gujarat on a long-term basis.
The crude-supply portion of the agreement follows an already established 25-year supply relationship between the parties under which, to date, Aramco has supplied about 2 billion bbl of crude to Jamnagar, RIL said.
Under the nonbinding letter, the proposed O2C investment is subject to due diligence, and the executed definitive agreement will be subject to regulatory and other customary approvals.
RIL said the parties will make an announcement once a definitive agreement is executed.
NARL’s Come-by-Chance refinery due crude project
NARL Refining LP has filed for registration and review of the environmental assessment process for a crude efficiency project at its 130,000-b/d refinery at Come-by-Chance, Newf., to help achieve compliance with the International Maritime Organization’s (IMO) upcoming global cap of 0.5% sulfur on fuel oil by all oceangoing vessels taking effect in January 2020.
While the crude efficiency project is a measure designed to enable the refinery to produce IMO-compliant fuel, it also will enable the site to increase crude throughput to more than 160,000 b/d, making Come-by-Chance the fourth-largest refinery in Canada, NARL said.
The crude efficiency project includes a $25 million (Can.) investment to install and operate several preheat exchangers and a prefractionation column within the crude unit, as well as several piping modifications.
NARL said it also expects the project to reduce the refinery’s greenhouse gas carbon intensity by 8% and sulfur dioxide emissions by 40%.
Construction is scheduled to begin this summer, with all assets operational by spring 2020.
Announcement of the crude flexibility project follows NARL’s early July filing for registration and review of the environmental assessment process for the construction of a delayed coker at the Come-by-Chance refinery (OGJ Online, July 8, 2019).
If approved, the proposed delay coker would not become operational until 2023, the operator said.
The operator has yet to reveal a precise timeframe for when it might reach a final investment decision on either the delayed coker or crude flexibility projects.
RIL, BP eye retail, aviation fuel JV
Reliance Industries Ltd. and BP PLC are expanding their partnership in India into retail and aviation fuels.
The companies have worked together in the country since 2011, when BP acquired a 30% interest in blocks operated by RIL offshore India. They also have a 50-50 joint venture, India Gas Solutions Pvt. Ltd., to source and market natural gas.
A new heads of agreement calls for formation of a joint venture encompassing a retail service station network and aviation fuels across the country.
The venture will include RIL’s retail network of more than 1,400 sites, aiming to as many as 5,500 sites in 5 years.
It also will include RIL’s aviation fuels business, now operating at more than 30 airports.
RIL will hold 51% of the JV, BP 49%.
TRANSPORTATION Quick Takes
Chevron starts up Gorgon LNG carbon-capture project
Chevron Australia has started up the carbon dioxide-capture system at its Gorgon LNG project on Barrow Island off the Western Australian coast. The system takes CO2 removed from the gas supply coming in from offshore Gorgon field and reinjects it into deep reservoirs under the island.
The carbon-capture program was originally scheduled for start-up in March 2017 soon after the LNG plant came on stream a few months earlier, however technical issues resulted in several delays. The problems are believed to have involved valves and pipeline equipment and were discovered during the commissioning phase of the $1.7-billion injection system.
The delays have meant that about 10 million tonnes of CO2 have been released into the atmosphere since December 2016. Despite this, Chevron says the capture facility will reduce Gorgon’s total greenhouse gas emissions by 40% when it is fully operational.
This will mean capture and injection of 3.4 million-4 million tonnes/year of CO2, which equates to about 100 million tonnes over the 40-year life of the LNG project.
The company is now monitoring the system performance and plans to ramp-up injection volumes during the next few months. It did not specify a timetable for when the project will be operating at full capacity.
The Australian government has paid $60 million (Aus.) towards the capital cost of the project.
Australia emitted 538.2 million tonnes of CO2 equivalent in 2018, an increase of 0.7% from 2017, mainly due to an increase in LNG exports.
The Gorgon project is operated by Chevron. Other JV partners are ExxonMobil Corp., Royal Dutch Shell PLC, Osaka Gas, Tokyo Gas, and JERA.
Agreement allows Niger-Benin crude line
China National Petroleum Corp. has signed an agreement with the government of Benin allowing construction of a 1,900-km crude oil pipeline between CNPC’s Agadem block in Niger and Benin’s Port of Seme.
It said 687 km of the pipeline will be in Benin.
Production on the Agadem block began in 2011, flowing through a 463-km pipeline to a 20,000-b/d refinery at Zinder.
Output is set to increase from discoveries made since 2013.
Trafigura starts oil transport via Cactus II
Trafigura Trading LLC, a wholly owned subsidiary of Trafigura Group Pte. Ltd., has started shipments of crude oil from the Permian basin to the Corpus Christi-Ingleside, Tex., area via the 670,000-b/d Cactus II pipeline system (OGJ Online, Jan. 25, 2018).
The shipments represent the initial commercial service of Cactus II, with its deliveries connecting to a waterborne export service to Europe and beyond.
In January 2018, Trafigura signed a long-term commitment with a Plains All American Pipeline LP subsidiary to transport 300,000 b/d of crude oil on the system.
Inter Pipeline to build Viking Connector oil line
Inter Pipeline Ltd., Calgary, reported plans to construct a $100-million crude oil pipeline connection between its Bow River and Central Alberta pipeline systems. The new line, called the Viking Connector, will link various grades of light crude from the Viking and Mannville formations in east-central Alberta to the Edmonton market hub.
“Producers in the Alberta Viking and surrounding plays are currently limited to pipeline services to the Hardisty hub or costly trucking alternatives,” said Christian Bayle, Inter Pipeline president and chief executive officer.
This latest investment is the second phase of a multi-phased development program for the Central Alberta pipeline system. This phase includes the construction of 75 km of 8-in. pipe that will connect Inter Pipeline’s Throne Station on the Bow River pipeline system to the Central Alberta pipeline system in the Stettler area. In addition, Inter Pipeline will complete upgrades to the Throne Station, which includes reconfiguring existing tank storage and expanding truck offloading capacity.
Construction, which will start immediately, is expected to be completed in first-half 2020.