GENERAL INTEREST Quick Takes
Chevron granted Argentina hydrocarbon concession
Chevron Corp. has been granted a concession for the unconventional exploitation of hydrocarbons (CENCH) by the government of Neuquén province Argentina that could open new development in the northern area of the liquids-rich Vaca Muerta shale formation.
The El Trapial Este block covers an area of 282.8 sq km and is derived from the Chevron-operated El Trapial-Curamched area exploitation concession. According to the fluid distribution window, in El Trapial Este, the Vaca Muerta formation is a producer, from west to east, of gas condensate, light oil, and black oil, the government said in an Apr. 9 statement.
“This concession is an important milestone for Chevron Argentina since it will allow unconventional development in the eastern zone of El Trapial,” said Eric Dunning, managing director for Chevron Latin America.
In the 3-year pilot stage, Chevron is expected to invest $65.7 million to drill, complete, and start up five horizontal wells of 2,500-3,000 m and 38-46 fracture stages each. Another $13 million investment is expected for construction of support infrastructure.
The pilot plan wells are in addition to 7 existing area wells.
Uniper developing salt-cavern hydrogen storage
Uniper SE is developing a project to store 100% hydrogen in the former Krummhörn natural gas storage salt cavern in northern Germany. Commissioning of a 250,000-cu m demonstration plant is planned for 2024.
Development of the demonstration plant will involve sinking a new cavern using an existing well. Krummhörn has not been used commercially since 2017. Uniper estimates the cost of the project at €10 million ($10.88 million)
Uniper says that Krummhörn’s proximity to Wilhelmshaven, Germany, will allow connection to its Green Wilhelmshaven project, as part of which the company is developing two projects for green hydrogen production. The first of these is an ammonia import terminal which will be able to convert the ammonia back into hydrogen. In the second project, Uniper plans to develop a 1,000-Mw electrolysis plant to produce green hydrogen.
“Uniper has decided to move forward with this project independent of other funded projects in order to test the technology and processes as quickly as possible. Our goal is to develop a storage solution for green hydrogen on a commercial scale and later offer it on the market. The storage capability of green electricity is one of the core issues of the energy transition and an essential building block for a CO2-free future,” said Managing Director Uniper Energy Storage, Doug Waters.
Uniper is also developing and LNG terminal at Wilhelmshaven. Before Russia’s invasion of Ukraine it was going to be used for hydrogen imports as part of Green Wilhelmshaven (OGJ Online, Mar. 2, 2022). Now both projects are advancing.
Ithaca Energy to acquire Siccar Point Energy
Ithaca Energy, Aberdeen, has agreed to acquire Siccar Point Energy, Aberdeen, doubling Ithaca’s recoverable reserves and supporting production of at least 80,000-90,000 boe/d through the next decade, the company said in an Apr. 7 release.
Consideration includes an upfront payment of $1.1 billion and a series of contingent payments totaling a maximum of $360 million.
The addition of bp-operated Schiehallion (Siccar Point 11.75%) and Equinor-operated Mariner (Siccar Point 8.89%) fields will add immediate production and growth opportunities through future drilling, Ithaca said. The deal also includes an interest in the Central North Sea producing Jade gas field operated by Harbour Energy, where Siccar Point holds 5.57% non-operated interest and Ithaca is an existing partner with 19.93% interest. The deal also includes undeveloped Cambo and Equinor-operated Rosebank (Siccar Point 20%) fields. Final investment decision is expected on both fields in 2023.
Cambo field (Siccar-operated 70%) on its own is expected to deliver up to 170 MMboe during its 25-year operational life.
Subject to regulatory approvals, specifically from the North Sea Transition Authority and the Department for Business, Energy and Industrial Strategy, the deal is expected to close around end second-quarter 2022.
Summit signs MOU for Midwest Carbon Express CCS compression
SCS Carbon Removal LLC, a subsidiary of Summit Carbon Solutions LLC, has signed an MOU with Xebec Adsorption Inc. supporting negotiation of an order for 51 CO2 reciprocating compression packages to be completed by end third-quarter 2023. The compression will be used for Summit Carbon Solutions’ proposed 12-million tonne/year (tpy) Midwest Carbon Express carbon capture and sequestration (CCS) project in the US midcontinent.
Midwest Carbon Express includes CO2 capture from 31 ethanol plants and industry, pump stations in Iowa, Nebraska, South Dakota, Minnesota, and North Dakota, 2,000 miles of up to 24-in. OD pipeline, and Class VI sequestration wells in Oliver and Mercer Counties, ND. Summit Carbon Solution expects it to be the largest CCS project in the world when commissioned.
Summit anticipates a decision on its application with the Iowa Utilities Board in first-quarter 2023. Construction would run into second-quarter 2024, followed by project commissioning and startup (OGJ Online, Feb. 7, 2022).
The Xebec contract would be worth more than $100 million. Midwest Carbon Express’ anticipated cost is $4.5 billion.
Vintage Energy JV buys share of Odin discovery
Vintage Energy Ltd, and its Cooper basin partners, Metgasco and Bridgeport, increased their stake in South Australian Cooper basin retention lease PRL 211 with the acquisition of Beach Energy’s 15% interest.
The license contains the Odin-1 gas discovery well and lies adjacent to the group’s Queensland permit ATP 2021 containing Vali gas field.
The parties will acquire their respective shares in proportion to existing holdings. This will result in Vintage taking 50% and operatorship with Metgasco and Bridgeport each ending up with 25%—in line with the JV’s shares in ATP 2021.
Odin field was discovered and flow tested in October 2021. The structure has been mapped to continue across the permit boundary to the east into ATP 2021.
The Odin discovery is prospective for development due to its proximity to Vali field and the Moomba gas gathering network, said Neil Gibbins, Vintage managing director.
Woodside contracts DOF Subsea for Enfield decommissioning
Woodside Petroleum Ltd. has let a contract to DOF Subsea Australia for decommissioning work on depleted Enfield oil field in the Northwest Shelf license WA-28-L offshore Western Australia.
The project will involve recovery of 18 subsea Christmas trees, 18 flow bases and associated spool sections, one wellhead severance, and the recovery of up to 18 temporary guide bases from the seabed, DOF said.
The contract includes project management, engineering, fabrication, and decommissioning services. Work is scheduled for the third and fourth quarters of this year using the Skandi Hercules vessel, DOF said.
Enfield was originally brought on stream in 2006 via the Nganhurra floating production, storage, and offloading vessel. The field was shut in at the end of its production life in late 2018.
Woodside is operator with 60%. Mitsui E&P holds 40%.
Exploration & Development Quick Takes
Equinor makes discovery near Troll
Equinor Energy AS discovered oil and gas in production license (PL) 293 B, close to the Troll and Fram area of the Norwegian North Sea. Equinor will consider tying this discovery to the Troll B or C platform.
Based on preliminary estimates, the size of the discovery is 4-8 million standard cu m of recoverable oil equivalent, or 25-50 million bbl of recoverable oil equivalent.
Temporarily called Kveikje, this is the sixth discovery in this area since fourth-quarter 2019. More than 300 MMboe were proven in the five former discoveries.
The well was drilled by Deepsea Stavanger. Plans call for Equinor to drill another exploration well in this area in 2022.
Equinor is operator at PL 293B (51%) with partners DNO Norge AS (29%), INPEX Idemitsu Norge AS (10%), and Longboat Energy Norge AS (10%).
ExxonMobil lets follow-up FPSO contracts for Yellowtail
ExxonMobil Corp. subsidiary Esso Exploration & Production Guyana Ltd. (EEPG) has let FPSO contracts to SBM Offshore NV for the Yellowtail development project in Stabroek block, offshore Guyana, following front-end engineering and design studies (OGJ Online, Nov. 17, 2021).
The $10-billion Yellowtail project, which will include six drill centers and up to 26 production and 25 injection wells, was sanctioned by ExxonMobil and Hess Corp. Apr. 4 (OGJ Online Apr. 4, 2022).
Under these FPSO contracts, SBM Offshore will construct, install, lease, and operate the ONE GUYANA FPSO for up to 2 years, after which the FPSO ownership and operation will transfer to EEPGL.
The FPSO will produce 250,000 b/d. It will have associated gas treatment capacity of 450 MMscfd and water injection capacity of 300,000 b/d. The vessel will be spread moored in water depth of about 1,800 m and will be able to store around 2 million bbl crude oil.
The turnkey phase of the project is executed by a special purpose company (SPC) established by SBM Offshore and McDermott. SBM Offshore holds 70% and McDermott holds 30% equity ownership in this SPC. The FPSO will be owned by SBM Offshore.
EEPG is operator and holds 45% interest in Stabroek block. Hess Guyana Exploration Ltd. holds 30% interest and CNOOC Petroleum Guyana Ltd. holds 25% interest.
Eni upgrades resource base offshore Angola
Eni SPA upgraded the resource base in Ndungu field, about 130 km off the coast and about 10 km from the Ngoma FPSO in the West Hub of Block 15/06, offshore Angola.
The Ndungu 2 appraisal well was drilled 5 km from Ndungu 1 and struck 40 m net oil pay (35°API) in the Lower Oligocene reservoirs with good petrophysical properties confirming the hydraulic communication with the discovery well. Intensive data acquisition was performed to assess the discovery’s full potential.
Preliminary data increases field resources to 800–1,000 MMboe in place from initial estimates of 250-300 MMboe (post Ndungu 1), making Ndungu, together with Agogo, the largest accumulation discovered in Block 15/06 since the block award. Ndungu field development will be upgraded following a phased approach, initially extending and increasing plateau of the Ngoma FPSO.
The early production phase of Ndungu started last February through one producer well. A second producer well is expected in this year’s fourth quarter, maximizing utilization of existing facilities in the West Hub (OGJ Online, Feb. 25, 2022). In parallel, appraisals will continue to optimize returns and minimize risks, the company said.
Eni Angola operates the block with 36.84% interest. Partners are Sonangol Pesquisa e Produção (36.84%) and SSI Fifteen Ltd. (26.32%).
RCMA plugs Cervantes, no hydrocarbons encountered
RCM Australia (RCMA) Pty Ltd. has plugged the Cervantes-1 wildcat in North Perth basin permit L14 onshore Western Australia after failing to find hydrocarbons (OGJ Online, Feb. 10, 2022).
Stratigraphic correlation during drilling proved more difficult than anticipated, JV partner Vintage Energy Ltd. said. However, intersection of the Holmwood shale proved that the prospective Permian-age section had been drilled.
Any potential reservoir sands are water-wet based on the lack of oil shows and interpretation of log data obtained while drilling, Vintage added.
The well was funded 50% by Vintage and 50% by Metgasco as farminees to each earn 30% interest in the permit.
RCMA operated the well and retains a 40% interest.
ONGC confirms oil in Proterozoic basin, India
Oil and Natural Gas Corp. Ltd. (ONGC) confirmed the presence of hydrocarbons in Proterozoic basin (Vindhya basin), Son Valley sector of Madhya Pradesh, India.
The Hatta#3 exploratory well was drilled to establish commercial potential with detailed testing to acquire reservoir-specific data. The well tested over 62,044 cu m/d gas.
After development, Vindhya would be the ninth producing basin in India and the eighth by ONGC.
The company is contemplating gas monetization options including direct marketing to industries in the vicinity, cluster-based gas production through cascade systems, CNG bottling at well-head (as the gas is of high calorific value), and transportation through available infrastructure.
Chariot upgrades gas discovery offshore Morocco
Chariot Ltd. upgraded net pay in the Anchois-2 gas appraisal and exploration well on the Anchois gas project within the Lixus license, offshore Morocco.
The well was completed in January to confirm gas resource volumes, reservoir quality, and well productivity of the discovered sands, provide a future production well for field development, and deepen the appraisal well into additional low-risk exploration targets with the aim to establish a larger resource base for longer term growth (OGJ Online, Dec. 15, 2021).
Based on post-well analysis, net gas pay estimates were increased to about 150 m from 100 m. Excellent quality dry gas is confirmed in all seven discovered gas reservoirs, with greater than 96% methane. No detrimental impurities such as H2S or CO2 were found.
Development will require minimal gas processing. Highly consistent gas composition potentially allows all gas produced from the reservoirs to be processed through a single processing plant.
Further well data analysis is ongoing to understand the positive implications on gas resources, as well as scale and economics of the development.
Chariot is operator of Lixus (75%). Office National des Hydrocarbures et des Mines (ONHYM) holds the remaining 25%.
Drilling & Production Quick Takes
Shell Australia brings Prelude FLNG back on line
Shell Australia has resumed production from its 3.6-million tonne/year (tpy) Prelude floating LNG plant in Browse basin offshore Western Australia after nearly 4 months offline. Restart follows last month’s approval from Australia’s National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) to restart the plant after the regulator was satisfied that proper safety systems were fully in place.
Prelude shut down in December 2021 when the vessel suffered a complete loss of power. Essential services that included lighting, communications, potable water systems, sewage treatment, heating, ventilation, and air conditioning were affected.
Shell was instructed by NOPSEMA to investigate and create a plan to take corrective action and demonstrate the plant could operate safely in the event of power loss before production could restart.
In addition to LNG, Prelude has the capacity to produce 1.3 million tpy of condensate and 400,000 tpy of LPG.
Shell has 67.5% interest, Inpex Corp. 17.5%, Korea Gas Corp. 10%, and CPC Corp. 5%.
Murphy Oil starts first oil through King’s Quay FPS
Murphy Oil Corp. achieved first oil from the Khaleesi, Mormont, and Samurai field development project in the deepwater Gulf of Mexico, and production has begun flowing through King’s Quay floating production system (FPS).
The King’s Quay semisubmersible FPS—designed to process 85,000 b/d oil and 100 MMcfd gas—lies in Green Canyon block 433 and is tied back to Khaleesi and Mormont fields, which lie in Green Canyon blocks 389 and 478, respectively, and Samurai field, in Green Canyon block 432. The FPS sits 6.5-10 km from the fields in about 1,100 m of water.
The Khaleesi-Mormont development project will include a total of seven subsea wells. Two have been completed, while completion operations are ongoing for the remaining five. Samurai field will be developed through four subsea wells. The remainder of the wells are expected to come online throughout the year.
CNOOC begins oil production from Weizhou 12-8E
CNOOC Ltd. started production from the Weizhou 12-8E oilfield development project.
The development lies in Beibu Gulf in the South China Sea, with average water depth of about 30 m.
A total of seven development wells are planned, including six oil production wells and one production water reinjection well. Average production of about 4,700 b/d of crude oil is expected this year, with peak production of about 10,000 b/d expected.
The development will utilize existing processing infrastructure of Weixinan oilfields.
CNOOC holds 51% interest in the project. Partners are Roc Oil (China) Co., Horizon Oil (Beibu) Ltd., and Oil Australia Pty Ltd.
Neptune Energy to double gas production at Duva
Neptune Energy Norge AS will double gas production from Duva field in the Norwegian sector of the North Sea, adding 6,500 boe/d from the first half of April to support increased supplies to the UK and Europe.
Duva’s overall production currently stands at 30,000 boe/d, of which 6,500 boe/d is natural gas. Under newly agreed measures, daily gas production will double to 13,000 boe/d for an initial 4-8 months.
Duva, in production license 636, is a subsea installation 14 km northeast of Neptune Energy-operated Gjøa field at a water depth of 340 m. It started production in August 2021 with three oil producers and one gas producer, tied back to the operator’s Gjøa semisubmersible platform. Gas is transported by pipeline to the UK’s St Fergus gas terminal.
Neptune is operator with 30% interest. Partners are INPEX Idemitsu Petroleum Norge AS (30%), PGNiG Upstream Norway AS (30%), and Sval Energi AS (10%).
Santos granted Dorado field production license
Australia’s National Offshore Petroleum Titles Administrator (NOPTA) has granted Santos Ltd. a production license over Dorado oil field in the Bedout subbasin offshore Western Australia.
The license—consisting of four blocks that were previously part of exploration permit WA-437-P—grants Santos the right to produce petroleum from the area and continue to explore for and appraise any additional petroleum within the four blocks. It also allows petroleum production from other areas via the licensed blocks, which means nearby discoveries such as the Pavo oil find can potentially be tied back and produced using the Dorado floating production, storage, and offtake vessel (FPSO).
Dorado, discovered in 2018, lies in 90 m of water about 150 km north of Port Hedland. The front-end engineering and design for Phase 1 is under way with a final investment decision expected midyear.
The $2 billion (Aus.) development proposal includes a reinjection of gas into the reservoir in the initial production phase to maintain reservoir pressure for optimum oil production. Production of 75,000-100,000 b/d is expected. The oil is a light, sweet crude with an API value of 51 degrees.
The field holds 2C contingent resource of 162 million bbl of oil. The gas, which has a low CO2 content of about 1.5%, will be recovered for domestic use at a later stage.
Santos is operator with 80% interest. Carnarvon Energy Ltd. holds 20%.
PROCESSING Quick Takes
PDO completes digitalization, automation upgrades at Omani gas plant
Petroleum Development Oman (PDO) has completed a project to modernize and standardize the control system architecture of PDO’s government gas plant (GGP) in northern Oman using a suite of technologies from Honeywell Process Solutions.
Designed to deliver sustainable and efficient gas processing operations to help PDO satisfy Oman’s rising domestic demand for gas, the plant modernization and digitalization project involved upgrading the GGP’s supervisory control center (SCC) by moving all high-performance process manager controllers to the improved HPS C300 controller, as well as replacing the fail-safe controller with HPS’ proprietary Safety Manager, the service provider said on Apr. 13.
With the SCC changeover completed while keeping the same input and output modules, the modernization project also involves transitioning the plant’s supervisory control level to the latest HPS Experion PKS R511 software, coupled with a refresh of workstation, server, and network platforms, according to HPS.
PDO additionally is implementing the Honeywell Trace solution for better monitoring of critical control assets to achieve a standardized system architecture with advanced control capabilities, HPS said.
Alongside minimizing disruptions to normal plant operations and ensuring efficient execution of its various components, the project’s phased approach also has allowed PDO to maintain consistent gas quality, reduce its risk of unplanned downtime at GGP, and enhance its lifecycle planning capabilities, according to the service provider.
“Our ability to meet gas demand across the Sultanate rests on our ability to process and produce it effectively, and that requires modern control architecture,” said Ahmed Al Harrasi, PDO’s senior control and automation leader for gas assets.
HPS’ solutions have extended the lifecycle of PDO’s critical assets as well as reduced the operator’s project execution risk, Al Harrasi added.
Jointly owned by the government of Oman (60%), Shell PLC (34%), TotalEnergies SE (4%), and Partex Oil & Gas Corp. (2%), PDO operates a 90,000-sq km onshore concession, with 209 producing oil fields, 55 producing gas fields, and more than 8,000 active wells, according to the company’s website.
Cairn lets processing terminal contract
Cairn Oil & Gas, Vedanta Ltd., has let a contract to Petrofac for a new operations and maintenance contract to support Cairn’s Mangala processing terminal (MPT) in Rajasthan, northern India.
MPT, spread over 1.6 sq km, processes crude oil produced from Rajasthan block RJ-ON-90/1, which is spread over 3,111 sq km in the Barmer district. Cumulative production from the block is more than 500 million bbl. After processing, crude oil is transported to refineries through a continuously heated and insulated pipeline.
The 60-month contract is valued at about $60 million.
The award follows a Cairn’s selection of Petrofac earlier this year for integrated operations and maintenance services in support of upstream oil and gas infrastructure at Ravva oil and gas field in Andhra Pradesh. Petrofac also previously completed a lump-sum EPC contract, which Cairn awarded in April 2018 for its RDG field development project.
TRANSPORTATION Quick Takes
Algeria building 424-km LPG pipeline
Algeria’s National Co. for Marketing and Distribution of Petroleum Products (Naftal) has awarded the pipeline division of national oil company Sonatrach Group an engineering, procurement, and construction contract for a 424-km LPG pipeline from Arzew to Algiers. The line will run through Chlef, Algeria, and use 12-in. OD pipe to ship 1.2 million tonnes/year.
In addition to the main filling site in Arzew, project design calls for filling centers in both Chlef and Blida, with a mini filling center in between.
Naftal expects the project to be completed within 4 years at a cost of 52 billion dinar ($363 million).
Coral FLNG awards maintenance contract to Saipem
Coral FLNG SA has awarded Saipem SPA a maintenance services contract for the 3.4-million tonne/year Coral Sul floating LNG (FLNG) plant offshore Mozambique. Activities cover maintenance of the entire plant, onboard supervision, and creation of an onshore logistical base.
Coral Sul will produce natural gas from the 16-tcf Coral field in Rovuma basin, about 250 km northeast of Pemba, Mozambique, and 50 km off the Mozambique coast, starting in 2022 (OGJ Online, Nov. 9, 2021). Saipem describes Coral Sul as the first FLNG plant to operate in ultradeep waters. It will be connected to six subsea wells at a depth of around 2,000 m.
The contract is worth $150 million with a duration of 9 years, plus 1 optional year.
Coral FLNG is a special-purpose entity incorporated in Mozambique by Area 4 partners Eni SPA (operator), ExxonMobil Corp., China National Petroleum Corp., Galp Energia SGPS SA, Korea Gas Corp., and Empresa Nacional de Hidrocarbonetos.
NextDecade to sell Rio Grande LNG output to ENN
NextDecade Corp. has executed a 20-year sales agreement with ENN LNG (Singapore) Pte. Ltd., a wholly owned subsidiary of ENN Natural Gas Co. Ltd., for 1.5 million tonnes/year (tpy) of LNG from NextDecade’s 27-million tpy Rio Grande LNG plant in Brownsville, Tex. The LNG will be sold indexed to Henry Hub on a free-on-board basis, supplied from Rio Grande’s first two trains.
Assuming further sales agreements and financing, NextDecade anticipates making a positive final investment decision (FID) on at least two Rio Grande trains (Phase 1, 11 million tpy) in second-half 2022, with FIDs of its remaining three trains to follow. The first train would start commercial operations as early as 2026.
NextDecade also has a 2-million tpy sales agreement in place with Shell PLC and a 1.5-million tpy agreement with Guangdong Energy Group Natural Gas (OGJ Online, Jan. 4, 2022).
CPC awards Taichung LNG expansion FEED
CPC Corp. has awarded Daigas Gas and Power Solution Co. Ltd. (DGPS), a 100% subsidiary of Osaka Gas Co. Ltd., a front-end engineering and design (FEED) and technical consulting services contract for Phase 4 expansion of the 10-million tonne/year (tpy) Taichung LNG terminal in Taichung, Taiwan. Post-expansion capacity will be 13 million tpy.
The expansion includes four 180,000-cu m storage tanks, additional regasification capacity, and a jetty for LNG tankers. Completion is scheduled for 2029.
DGPS is also providing ongoing technical consulting service for construction of CPC’s third LNG receiving terminal (3 million tpy) in Guantang, Taoyuan City, scheduled for completion by end-2025.
The Taiwanese government has been pursuing an energy policy which targets both phasing out nuclear power and reducing greenhouse gas emissions. As part of this policy, the government is planning to increase natural gas’s share of power generation to 50% by 2025. CPC is expanding its LNG regasification and storage capacity as part of this plan.
Greek gas transmission awards hydrogen-ready compression contract to Baker Hughes
TERNA, the construction arm of GEK TERNA Group, has awarded Baker Hughes a contract to supply gas turbines and compressors that can run on a blend of natural gas and hydrogen for a new compression station of the Greek Natural Gas Transmission System. The compression station will serve domestic gas supply in Greece.
Baker Hughes will provide three compression trains which will include a total of three NovaLT12 hydrogen-ready gas turbines and three Pneumatic Components Ltd. compressors, designed to support the transport of as much as 10% hydrogen. TERNA expects the station to enter operation in 2024 and directly support the European Union’s hydrogen strategy goals to accelerate development of clean hydrogen and ensure its role as a cornerstone of a climate-neutral energy system by 2050.
NovaLT12 design allows for blends of 5-100% hydrogen.