GENERAL INTEREST Quick Takes
Petrobras to increase asset stake in blocks north of Brazil
Petróleo Brasileiro SA (Petrobras) signed agreements with BP Energy do Brasil Ltda to take over BP’s entire stakes in six ultra-deepwater blocks, offshore northern Brazil, some 120 km from the state of Amapá, in an exploratory frontier on the Brazilian equatorial margin.
The blocks—FZA-M-57, FZA-M-59, FZA-M-86, FZA-M-88, FZA-M-125, and FZAM-127—were acquired by the consortia in the 11th bidding round of Blocks of the National Agency of Petroleum, Natural Gas and Biofuels (ANP) in 2013.
Blocks FZA-M-57, FZA-M-86, FZA-M-88, FZA-M-125 and FZA-M-127 in the Foz Do Amazonas basin are owned by Petrobras (30%), Total (40%), and BP (30%). Petrobras signed an agreement to assume operation and Total’s stakes in these contracts, still subject to ANP approval, in September 2020 (OGJ Online, Sept. 28, 2020). The FZA-M-59 block is owned by a consortium of Petrobras (operator, 30%) and BP (70%).
The agreement with BP will allow Petrobras to hold 100% interest in these six blocks. Completion is subject to regulatory approvals.
Malaysia, Brunei formalize agreement for maritime boundary
Malaysia, through its national oil company Petronas, formalized a unitization agreement with the government of Brunei Darussalam for Gumusut-Kakap and Geronggong-Jagus East fields which straddle the Malaysian-Brunei maritime boundary.
The agreement establishes a platform for joint development of the fields by Petronas and the National Unitisation Secretariat of Brunei.
Evolution acquires non-operated Barnett shale assets
Evolution Petroleum has agreed to acquire non-operated oil and gas assets in the Barnett shale from TG Barnett Resources LP, a wholly owned subsidiary of Tokyo Gas Americas Ltd. for $23.25 million in cash. The properties have potential upside drilling and workover opportunities, Evolution said Mar. 30.
The asset footprint consists of 23,000 net acres held by production across 9 counties in North Texas with current net production of 22 MMcfd of natural gas and 1,300 b/d of liquids. The acreage has an average working interest of 17% with a 14% average revenue interest. Blackbeard Operating LLC, an NGP portfolio company, is operator for most of the properties. Most of the wells were completed from 2007-2010. On average, the commodity mix is 30% natural gas liquids and 70% natural gas.
Exploration & Development Quick Takes
Equinor strikes oil in Norwegian Sea
Equinor Energy AS and partners plan to immediately begin production of an oil and gas discovery considered commercial in a new segment belonging to Tyrihans field in Norwegian Sea production license 073. Resources are estimated at 3.0-4.2 million standard cu m of recoverable oil equivalent (19–26 MMboe).
Tyrihans field lies 25 km southeast of Åsgard field and 220 km northwest of Trondheim.
Well 6407/1-A-3 BH, the sixth exploration well on the field and the fifth in the license, was drilled by the Transocean Norge drilling rig from subsea template A at Tyrihans North in 288 m of water to a vertical depth of 3,998 m and a measured depth of 5,332 m subsea. The well was completed in the Åre formation from the lower Jurassic period.
The purpose of the well was to prove petroleum in lower-mid Jurassic reservoir rocks (Ile and Tilje formations).
The well struck a gas column of about 43 m and an oil column of about 15 m in the Ile formation, including about 76 m of moderate to good reservoir quality sandstone. Moderate to good quality water-bearing reservoir was encountered in the Tilje formation.
Data acquisition and sampling were carried out. The well was not formation tested. The pilot will be permanently plugged.
The rig will now continue drilling producer well 6407/1-A-3 CH on Tyrihans field.
Equinor is operator of the license with 58.767%. Partners are Total E&P Norge AS (29.143%) and Vår Energi AS (12.09%).
Central Petroleum to breathe new life into Mereenie field
Central Petroleum Ltd., Brisbane, has engaged Eastwell Group to recomplete four existing wells and drill two new development wells in Mereenie gas field in the Amadeus basin of the Northern Territory, Australia.
The intent is to return the field production capacity towards 45 terajoules/day of gas from the current flow of 32 terajoules/day. This will produce at least an additional 45 petajoules of gas over the lifetime of the wells.
The new work will enable Mereenie joint venture to commit to new gas sales into the Australian east coast domestic market.
Development activities are part of the long-term field development plan that aims to convert undeveloped 2P reserves of more than 40 petajoules into developed 2P reserves, Central said.
Recompletions will begin in April, while the first development well (a vertical) will be spud in May. On completion both new wells will be tied into the existing gathering network, the first expected on stream before July.
Mereenie field spans two licences (OLs 4 and 5) about 230 km west of Alice Springs. Central is operator with 50% interest. Macquarie Group Ltd. has the remaining 50%.
Kuwait Energy discovers oil in Abu Sennan license
Kuwait Energy found oil in the Abu Sennan license, 12 km to the northeast of producing Al Jahraa field, in Egypt’s Western Desert, partner United Oil & Gas PLC said in an Apr. 6 release.
ASD-1X—drilled by the EDC-50 rig to 3,750 m on Mar. 30—encountered about 22 m net oil pay, interpreted across several reservoirs, including the Abu Roash C (AR-C), Abu Roash E (AR-E), Lower Bahariya, and Kharita formations.
Well testing is planned, and if successful, will be followed by an application to Egyptian General Petroleum Corp. for a development lease.
The rig will now move to Al Jahraa field within the concession to drill the AJ-8 development well targeting the Abu Roash and Bahariya reservoirs in an undrained portion of the field.
Abu Sennan is operated by Kuwait Energy Egypt (25%). Joint venture partners are United Oil & Gas (22%), Global Connect Ltd. (25%), and Dover Investments (28%).
Drilling & Production Quick Takes
Esso brings West Barracouta gas field on stream
Esso Australia’s West Barracouta gas field in Bass Strait, off the Victorian coast, has been brought on stream to supply eastern Australia’s domestic gas market.
The $400-million (Aus.) project has been described as the largest domestic gas development for eastern Australia this decade. It will deliver gas to help mitigate the shortfall in gas supplies predicted for southeast Australia as early as 2023.
The new development comprises two production wells and associated subsea production facilities, a 5 km-long pipeline and 6 km control umbilical connected to existing Bass Strait infrastructure that feeds gas into the onshore gas processing plant at Longford, near Sale in eastern Victoria.
Esso, along with its 50% joint venture partner BHP, has been supplying domestic gas from Bass Strait for 50 years and says the region has the potential to supply one third of southeast Australia’s gas needs well into the future.
Norway production decreased in March, NPD says
Norway’s liquids production averaged 2.094 million b/d in March, the Norwegian Petroleum Directorate reported. Norway’s daily liquids production averaged 2.108 million b/d in February (OGJ Online, Mar. 19, 2021).
Oil production in March is 0.7% lower than the NPD’s forecast, and 0.2% lower than the forecast so far this year.
The average daily liquids production in March consists of 1.773 million b/o, 309,000 bbl of NGL, and 12,000 bbl of condensate.
The total petroleum production for the first 3 months in 2021 is about 59.2 million standard cu m oil equivalents.
Ring Energy drills more wells in Permian Northwest Shelf
Ring Energy Inc. initiated the next phase of its Permian Northwest Shelf drilling program with three wells in Yoakum County, Tex.
Drilling of the first well, Bevo 664 C #2H, is complete and drilling operations are under way on the second well, Bevo 664 A #4H. Drilling operations on the third well, Bevo 664 A #3H, are expected to commence in late April. Each of the three wells target the San Andres formation and are 1 mile in length. Bevo 664 C #2H is expected to be on production before end-April. Bevo 664 A #4H and Bevo 664 A #3H are expected to come online before end-May.
These wells follow four that were placed on production in first-quarter 2021 (OGJ Online, Feb. 22, 2021). The four-well package included an average completed lateral length of 7,239 ft for three 1.5-mile wells and 4,983 ft for one 1.0 mile well. All four are performing favorably despite impact from the winter storm in Texas in February and produced a cumulative 37,550 gross boe (94% oil) during March 2021, the company said.
Due to the storm, Ring shut in over 60% of production. Full restoration took more than 2 weeks to complete.
Aker BP to progress drilling, workovers
Aker BP ASA has been granted consent by the Petroleum Safety Authority Norway for use of the Deepsea Stavanger semisubmersible rig for drilling, completion, recompletion, and plugging of wells on Skarv oil and gas field in PL 212 in the northern part of the Norwegian Sea. Water depth at the site is 350-450 m.
Well 6507/5-B-7 H will be drilled and completed, well J-3 H (Gråsel) will be recompleted, and well 6507/5-A-3 H will be plugged.
Skarv, discovered in 1998, lies 35 km southwest of Norne field and is a joint development of Skarv and Idun deposits. The field has been developed with a production, storage and offloading vessel tied to subsea templates. Fifteen development wells consisting of 5 gas producers, 6 oil producers, and 4 gas injectors have been drilled and completed. Production started in 2013.
Aker BP is operator (23.84%) with partners Equinor Energy AS (36.17%), Wintershall Dea Norge AS (28.08%), and PGNiG Upstream Norway AS (11.92%).
PROCESSING Quick Takes
CNOOC-Shell JV commissions new units at Huizhou
Royal Dutch Shell PLC subsidiary Shell Nanhai BV and China National Offshore Oil Corp. (CNOOC) started up new units to complete the Phase 2 expansion of their 50-50 joint venture CNOOC & Shell Petrochemicals Co. Ltd.’s (CSPC) petrochemical complex in Daya Bay Economic & Technological Development Zone, Huizhou City, Guangdong Province, China.
Newly commissioned installations include China’s largest styrene monomer and propylene oxide (SMPO), which—equipped with Shell’s proprietary SMPO process technology—produce up to 630,000 tonnes/year of styrene monomer and 300,000 tpy of propylene oxide, as well as three additional units that—using Shell’s advanced Polyols technologies for the first time in China—process propylene oxide into as much as 600,000 tpy of polyols for performance products such as coatings, adhesives, sealants, elastomers, and foams, Shell said Apr. 14.
Preceded by commissioning of a 1.2-million tpy ethylene cracker—the site’s second—in 2018, startup of the remaining Phase 2 units enables CSPC’s complex to supply customers with up to 6 million tpy of high-quality intermediate and performance chemicals, including polyols, ethylene, glycol, polyethylene, and polypropylene, according to the company.
Shell also confirmed plans also are under way to proceed with a previously proposed Phase 3 expansion at the Huizhou complex, which would include construction of a new 1.5-million tpy ethylene cracker equipped with Shell’s proprietary advanced linear alpha olefin technology (OGJ Online, May 18, 2020).
Following a 2020 memorandum of understanding with CNOOC, Shell said the JV partners also are exploring the addition of a commercial-scale polycarbonate production unit at the CSPC complex.
Ongoing expansion of the CSPC JV comes as part of both companies strategy of collaborating to expand China’s petrochemicals industry as well as their goal of supplying essential and premium chemical products to the region.
IOC lets contract for Panipat refinery expansion
Indian Oil Corp. Ltd. (IOC) has let a contract to Chevron Lummus Global LLC (CLG)—a partnership of Chevron USA Inc. and Lummus Technology LLC—to license a suite of process technologies for the operator’s previously announced plan to expand its 15-million tonnes/year integrated Panipat refining and chemical complex in Haryana, India, north of New Delhi.
As part of the Apr. 13 contract award, CLG will provide licensing of its proprietary Isocracking, Isodewaxing, and Isofinishing technologies for a new catalytic dewaxing unit designed to produce mainly premium API Group III base oils by processing unconverted oil from an upstream hydrocracking unit, the service provider said.
Alongside licensing, CLG’s scope of delivery under the contract also includes delivery of basic engineering, proprietary equipment, catalyst, and technical services for the unit, which aims to help reduce India’s current dependence on base oil imports.
According to a 2018 summary of the project IOC submitted to the Indian government, the new catalytic dewaxing unit will have a nameplate capacity of 560,000 tpy.
The contract follows IOC’s February 2021 approval of the refinery expansion, which will increase crude processing capacity at the site by 10 million tpy to 25 million tpy.
Designed to improve operational flexibility of the refinery to help meet domestic energy demand, the capacity expansion project—which will include installation of a polypropylene unit—would also increase production of petrochemicals and value-added specialty products to elevate margins and derisk IOC’s companywide exposure to its conventional fuel business.
Budgeted at an estimated cost of 329.46-billion rupees, the Panipat capacity expansion is slated for commissioning by September 2024, IOC said in February.
SOCAR wraps Sumgait petrochemical plant revamp
State Oil Co. of Azerbaijan Republic (SOCAR) subsidiary Azerikimya Production Union (APU) has completed its previously announced modernization and reconstruction of APU’s ethylene and polyethylene (PE) production plant in Sumgait, north of Baku (OGJ Online, Mar. 10, 2016).
Despite challenges presented by the coronavirus (COVID-19) pandemic, Technip Energies in February completed contractual performance testing at the plant showing that all technological modifications introduced as part at the project’s execution are functioning properly, the service provider said in April.
Now handed back over to APU and fully operational, the plant is producing on-demand ethylene and propylene meeting all requisite capacity and quality specifications, according to Technip Energies.
SOCAR let a contract to the service provider in November 2016 for delivery of engineering, procurement, and construction services for the revamp project, the scope of which included modernization of the EP-300 steam cracker, including construction of cracker furnaces licensed by Technip Energies, as well as installation of a refinery dry gas treatment unit, ethylene and propylene storage, and related utilities and off sites.
Technip Energies now confirms it also completed commissioning and startup activities for the project.
Details regarding current capacity rates of APU’s modernized ethylene and PE plant were not disclosed.
TRANSPORTATION Quick Takes
Uniper repurposes LNG terminal site to hydrogen
Under the name Green Wilhelmshaven, Uniper SE plans to establish a German national hub for hydrogen in Wilhelmshaven and is working on a corresponding feasibility study. Uniper had been exploring construction of a 7-million tonne/year (tpy) floating LNG import terminal at the Wilhelmshaven site, but decided that long-term demand was insufficient to support the project (OGJ Online, Nov. 9, 2020).
Commissioning of an import terminal for green ammonia is planned for the second half of this decade. The terminal is planned to be equipped with an ammonia (NH3) cracker for producing green hydrogen and will be connected to a planned hydrogen network. A 410-Mw electrolysis plant is also planned, which—in combination with the import terminal—would be capable of supplying around 295,000 tpy of hydrogen, or 10% of the demand expected for the whole of Germany in 2030.
Generated hydrogen will primarily be used to supply local industry but will also be fed into the national hydrogen network. This approach will help to solve one of the key problems of energy transition: security of supply, said Uniper. The NH3-splitting plant for producing green hydrogen would be the first scaled plant of its kind, according to project developers.
“Germany plans to generate 14 Tw-hr of green hydrogen in 2030, but the demand for that year is forecast to be 90–100 Tw-hr. The discrepancy between these two figures is abundantly clear. We will be heavily dependent on imports if we want to use hydrogen to help us achieve our climate goals,” said Uniper chief operating officer David Bryson.
First Gen leases BW Gas FSRU for Philippines terminal
FGEN LNG Corp., a subsidiary of First Gen Corp., has executed a 5-year time charter with BW FSRU IV Pte. Ltd., a subsidiary of BW Gas Ltd., for charter of its 162,400-cu m, floating storage and regasification unit, BW Paris. The vessel will be used by FGEN LNG as part of its 5-million tonne/year interim offshore LNG terminal project to be built at First Gen’s Clean Energy Complex in Batangas City, Philippines.
BW Paris has nominal and peak gas send out capacities of 500 MMscfd and 750 MMscfd, respectively. The vessel can also reload LNG into trucks and smaller LNG vessels for distribution elsewhere in the Philippine archipelago.
The project will allow FGEN LNG to bring LNG to the Philippines as early as third-quarter 2022, First Gen said in a stock exchange filing.
The country seeks to replace production from Shell Philippines Exploration BV-operated Malampaya gas field, which peaked at 400 MMscfd and is now in decline, according to First Gen. Malampaya production began in 2001. Shell says gas from Malampaya is used to generate more than 20% of electricity used in the Philippines.
DNV publishes new CO2 pipeline recommended practice
DNV has published new procedures designed to provide the safety needed to transport CO2 by pipelines and strengthen the development of carbon capture and storage (CCS) projects. Publication follows the CO2SafeArrest joint industry project (JIP) between Energy Pipelines CRC (Australia) and DNV, work supported by the Norwegian funding body CLIMIT and the Australian Commonwealth Government under the Carbon Capture & Storage Research Development and Demonstration Fund.
The JIP involved two large-scale CO2 crack arrest tests being carried out on 24-in. OD pipelines to better understand the safety implications of CO2 releases. The testing was performed at DNV’s UK research and development center.
The need to transport CO2 is expected to increase significantly, according to DNV, as part of the widespread view that CCS is a viable means to reduce CO2 emissions. An updated recommended practice (RP), “DNVGL-RP-F104 Design and Operation of Carbon Dioxide Pipelines,” has been published based on the results from the CO2SafeArrest JIP, resulting in a new empirical model for the assessment of running ductile fractures in CO2 pipelines. The RP can also be used alongside DNVGL-ST-F101 Submarine Pipeline Systems.
Transport of CO2 can use either existing pipelines or newbuild pipeline systems. DNVGL-RP-F104 supports both the design of new pipelines and the reuse of existing infrastructure by describing a process to requalify pipelines for CO2 transport through various steps.
PipeChina building Tianjin-Hebei gas pipeline
China Oil & Gas Piping Network Corp. (PipeChina) has begun building a 6.6 billion cu m/year natural gas pipeline from Tianjin to Xiong’an New Area, Hebei Province. The 413.5-km, 43.5-in. OD line will cost $1.31 billion.
The pipeline will move gas from the 2.2-million tonne/year LNG terminal in Tianjin. Interconnections are also planned with the Power of Siberia pipeline, importing Russian gas and domestic pipelines delivering from the Xinjiang Autonomous Region.
Construction of the pipeline is associated with plans to move non-essential government functions from Beijing to the Xiong’an New Area and continue the coordinated development of the Beijing-Tianjin-Hebei region, the Chinese government said.
PipeChina, formed in December 2019, last year acquired pipeline assets from PetroChina Co. Ltd. and Sinopec Kantons Holding Ltd. (OGJ Online, July 27, 2020).