GENERAL INTEREST Quick Takes
Oil prices soar on OPEC+ agreement
The US oil benchmark, WTI crude, jumped early on Mar. 4 to above $64/bbl, soaring by more than 5%, after OPEC and allied countries (OPEC+) decided to leave most oil production cuts in place next month. Brent crude prices jumped above $67/bbl, up by 5%.
OPEC+ had been debating whether to restore as much as 1.5 million b/d of output. As Saudi Arabia advocated for production restraints to keep prices supported, members agreed to hold steady at current levels—with the exception of modest increases granted to Russia and Kazakhstan.
Meantime, Saudi Arabia will maintain its 1 million b/d voluntary production cut, saying it is in no hurry to bring back the supply.
Russia and Kazakhstan secured exemptions, allowing them to boost output by 130,000 b/d and 20,000 b/d in April, respectively, due to continued seasonal consumption patterns. The two nations were granted similar allowances for February and March.
As oil demand is recovering amid the rollout of vaccines, the OPEC+ decision is signaling a tighter crude market in the months ahead. However, higher crude prices could spur additional drilling activity by US shale explorers. Domestic oil rigs are already at the highest level since May 2020.
OPEC+ is expected to meet again on Apr. 1 to discuss production levels for May.
ExxonMobil to cut 300 jobs in Singapore
ExxonMobil will reduce staffing levels at its Singapore affiliate as part of an ongoing effort to improve and sustain long-term competitiveness, the company said in a release Mar. 3.
Some 300 positions will be impacted by end-2021, representing about 7% of the over 4,000 employees in Singapore, the company continued.
Unprecedented market conditions resulting from the COVID-19 pandemic accelerated ongoing reorganization and work-process changes aimed at improving the company’s long-term cost competitiveness and ability to manage through near-term challenges, the company said.
In October 2020, the company noted plans to cut US jobs primarily impacting management offices in Houston, Tex. (OGJ Online, Oct. 29, 2020).
NEO Energy to acquire Zennor Petroleum
NEO Energy agreed to acquire Zennor Petroleum Ltd., which includes a portfolio of assets in the Central and Northern North Sea, for total consideration up to $625 million, including deferred and contingent payments.
NEO estimates its production will grow to a stable production base in 2022-2026 of 90,000-100,000 boe/d from 80,000 boe/d in 2021. The company expects to operate about 55% of the production growth.
The deal “provides a further immediate uplift to NEO’s production and resource base with several high-quality follow-on development opportunities,” said Russ Alton, chief executive officer of NEO Energy, and “is a further demonstration of the scale of our ambition in the UKCS, with a clearly defined target of achieving 120,000 boe/d in 2023,” he said.
In February, NEO Energy agreed to acquire a portfolio of non-operated North Sea oil and gas assets from ExxonMobil (OGJ Online, Feb. 24, 2021).
With the Zennor deal, NEO will take ownership of a portfolio of assets centered around Britannia and ETAP production hubs, with near-term growth prospects from sanctioned projects including the operated Finlaggan tie-back, scheduled for first production later this year, and a series of future development opportunities including the operated Greenwell and Leverett projects (tie-backs to Britannia), and Murlach (tie-back to ETAP).
The Zennor portfolio adds about 40 MMboe of reserves and more than 90 MMboe of unrisked resource to NEO and is expected to bring NEO’s oil-to-gas weighting to 60-40.
Following completion, the Zennor team will join NEO, increasing headcount to over 180 people.
NEO is backed by private equity investor HitecVision.
Engie, Equinor to investigate hydrogen development
Engie and Equinor signed a memorandum of understanding to investigate the development of joint low-carbon hydrogen activities in Belgium, the Netherlands, and France. The partners will investigate the production and market potential for hydrogen from natural gas whereby the CO2 will be captured and stored permanently offshore.
In the coming months, the companies will begin discussions with potential customers to assess the project, as well as with stakeholders and relevant authorities.
Development of low-carbon and renewable hydrogen projects at scale is needed to make it possible for industrial customers to significantly reduce CO2 emissions before 2030, the companies said in a joint statement. “This development of low carbon and renewable hydrogen will accelerate the construction of new hydrogen infrastructure and the repurposing of current natural gas infrastructure, thus paving the way for net zero in 2050,” they said.
Exploration & Development Quick Takes
ExxonMobil readies second Canje block well offshore Guyana
ExxonMobil was slated to begin drilling Jabillo-1 on Canje block, offshore Guyana, on Mar. 10. The well is a 1,000 MMbbl oil prospect targeting a Late Cretaceous, Liza-age equivalent, basin floor fan, said indirect interest holder Westmount Energy Ltd. in a release Mar. 9.
To be drilled by the Stena Carron drillship, the exploration well is the second of three scheduled for drilling in the block this year (OGJ Online, Jan. 26). The first, Bulletwood-1, was drilled in 2,846 m of water to its planned target depth of 6,690 m in early March. The well encountered quality reservoirs but with non-commercial hydrocarbons (OGJ Online, Mar. 4, 2021).
Operated by ExxonMobil subsidiary Esso Exploration & Production Guyana Ltd. (35%), the block lies 180 km offshore in 1,700-3,000 m of water adjacent to the also-operated Stabroek block. Partners in Canje are Total (35%), JHI Associates Inc. (17.5%), and Mid-Atlantic Oil & Gas Inc. (12.5%). Westmount holds a 7.7% interest in JHI.
Wintershall to explore East Damanhour with Cheiron, INA
Wintershall Dea, Cheiron Petroleum Corp., and INA Industrija Nafte DD will jointly explore the East Damanhour block onshore Egypt. The Egyptian Minister of Petroleum and Mineral Resources, H.E. Eng. Tarek El Molla, approved a deed of assignment agreement.
The new exploration partners will contribute financially and with technical expertise, Wintershall said in a Mar. 9 release. Plans are to drill up to seven wells on the concession over the coming years, with the first three planned wells expected to begin this year.
The concession was originally signed between the Egyptian Natural Gas Co. (EGAS), representing the Arabic Republic of Egypt; and Wintershall Dea, as contractor, on Feb. 10, 2020. Egypt-based Cheiron will hold a 40% working interest of the contractor’s share, while the Croatian INA acquires a 20% working interest. Wintershall Dea will remain operator with a working interest of 40% of the contractor’s share.
The block lies west of Wintershall’s Disouq project in the onshore Nile Delta, where the company has produced gas since 2013.
“We know the area well, so we anticipate low geological risks. Furthermore, our existing infrastructure at Disouq means that we are well placed to quickly develop any commercial discoveries,” said Sameh Sabry, senior vice-president and managing director, Wintershall Dea in Egypt.
ConocoPhillips, 3D Oil JV to run seismic offshore Tasmania
ConocoPhillips Australia and its joint venture partner, 3D Oil Ltd., Melbourne, contracted Shearwater Geoservices to run a 3D seismic survey over permit T/49P in the Tasmanian sector of the offshore Otway basin.
The survey, to be conducted by the Geo Coral vessel, will cover 2,700 sq km. It is scheduled to take 60 days beginning in August.
The seismic program is being undertaken by ConocoPhillips at no cost to 3D Oil as part of ConocoPhillips’ December 2019 farm-in arrangements to earn 80% interest and operatorship in the permit (OGJ Online, Dec. 18, 2019).
The terms originally called for a minimum seismic coverage of 1,580 sq km. The increase in size of the acquisition area will provide coverage of all leads within the permit and tie in with the previously acquired Flanagan 3D survey.
On completion of the acquisition, processing and interpretation, ConocoPhillips may elect to drill an exploration well that will fulfil the current Year 6 work program obligation for T/49P, 3D Oil said.
If ConocoPhillips does drill the well, 3D Oil will be carried up to $30 million in drilling costs, after which it will contribute 20% of costs in line with its interests in the permit.
Drilling & Production Quick Takes
Chevron starts production at Sarta well in Kurdistan
Chevron started production of the Sarta-2 well at Sarta field in the Kurdistan region of Iraq, partner Genel Energy said in a Mar. 8 release (OGJ Online, Feb. 18, 2019).
Gross field production is more than 10,000 b/d. Field production is expected to increase from the existing two producing wells as facility optimization continues after production start-up. The block covers an area of 90,000 net acres (363 sq km) and the main reservoir is Lower Jurassic Mus-Adayah.
The 2021 appraisal drilling campaign is scheduled to begin at the start of this year’s second quarter, with the Sarta-5 and Sarta-6 wells set to be drilled back to back.
Chevron is operator of the Sarta production sharing contract (50%) with partners Genel Energy (30%) and the Kurdistan Regional Government (20%).
Chyrsaor begins drilling in southern North Sea
Chrysaor Norge AS started drilling the Jerv 15/12-25 exploration well in production license (PL) 973, close to the UK border in the southern North Sea, directly south of Grevling and Storskrymten discoveries. An early drill decision was taken to accelerate identification of additional resources in the area to support ongoing field development plans.
The COSL Innovator will drill the well—the first of a two-well program including Ilder 15/12-26. A contingent sidetrack and well testing may be performed to evaluate any discovery.
Chrysaor is operator of PL973 (50%) with partners OKEA (30%) and Petoro AS (20%).
Equinor advances Veslefrikk shutdown, decommissioning plan
Equinor Energy AS and partners have commenced work to shut down Veslefrikk field in Norwegian North Sea Block 30/3. An environmental impact assessment was conducted, and a decommissioning plan sent to authorities in autumn 2020. Shutdown of the field is planned for spring 2022.
After over 30 years onstream, the field has produced more than 400 MMboe.
Veslefrikk B is a semisubmersible production platform tied into the Veslefrikk A fixed wellhead platform. In 2002 the field became the host of Huldra with a shared control room and crew. Veslefrikk is operated from Sandsli outside Bergen, where it is organized together with the operation of the Oseberg area.
Before Veslefrikk B can be brought ashore, wells must be plugged, platform systems must be shut down and cleaned, and oil and gas export pipelines must be cleaned and disconnected. A total of 24 wells will be plugged from the drilling system in an effort that began in January under existing framework contracts. Archer holds the contract for rig operations. Baker and Ardyne are contracted for drilling and well services.
Veslefrikk B will be towed to shore for dismantling in autumn 2022. Veslefrikk A is scheduled for removal in 2025-2026.
Contracts for removal and dismantling of Veslefrikk A, dismantling and recycling of Veslefrikk B, and seabed work in connection with export pipeline cleaning and disconnection are scheduled for award in this year’s first half.
Equinor is operator of the field (18%) with partners Petoro AS (37%), Repsol Norge AS (27%), and Wintershall Dea Norge AS (18%).
PROCESSING Quick Takes
YPFB to add renewable diesel plant at Santa Cruz refinery
The government of Bolivia and state-owned Yacimientos Petrolíferos Fiscales Bolivianos (YPFB) Corp. have unveiled plans for construction of a grassroots renewable diesel production plant at YPFB subsidiary YPFB Refinación SA’s 24,000-b/d Guillermo Elder Bell refinery in Santa Cruz de la Sierra.
Part of Bolivian President Luis Arce Catacora’s 2020-25 government plan to secure the country’s energy security, the proposed plant will process 450,000 tonnes/year of vegetable oils and waste-animal fat feedstocks to produce 9,000 b/d—or 3 million bbl/year—of renewable diesel, YPFB said in a series of early-March releases.
Specific feedstocks currently considered for processing at the proposed $250-million plant include soybeans, totaí, motacú, jatropha, used cooking oils, palm, and pine nuts, among other products, which will be sourced from domestic private companies and business ventures, according to the government.
YPFB said it expects to launch a tender to secure an engineering, procurement, construction, and commissioning partner for the project during third-quarter 2021, with plant startup targeted for fourth-quarter 2024.
The operator also confirmed it already has entered confidentiality agreements to explore data and information regarding process technologies for the plant with service providers Axens Group of France, Honeywell UOP LLC, and Haldor Topsoe AS.
Alongside contributing to increased energy efficiency and improved environmental performance, YPFB’s planned renewable diesel plant at Santa Cruz—which, once completed, will be the first of its kind in South America—will be a definitive step in establishing energy independence for Boliva, which up to now spends more than $1 billion to import diesel into the country, President Arce said.
In addition to two crude units with capacities of 18,000 b/d and 6,000 b/d, respectively, YPFB’s Santa Cruz refinery hosts two 3,200-b/d catalytic reforming units and a 6,000-b/d light gasoline isomerization unit, according to the company’s website.
Brooge lets contract for Phase 3 refining, storage development at Fujairah
Brooge Energy Ltd., through its subsidiaries Brooge Petroleum and Gas Investment Co. FZE (BPIC) and Brooge Petroleum and Gas Investment Co. Phase III FZE (BPGIC III) has let a contract to Ernst & Young (EY) to conduct a feasibility study for the oil storage installation of its proposed Phase 3 refinery and storage expansion at its existing terminal operations in Fujairah, UAE, outside the Strait of Hormuz, adjacent to the east coast port of Fujairah on the Gulf of Oman (OGJ Online, Aug. 6, 2020; Apr. 23, 2020).
EY’s feasibility study will progress BPIC III’s plans as it prepares for the construction stage on the Phase 3 development that, once completed, will add up to 3.5 million cu m—or 22 million bbl—of oil storage capacity to make Brooge Energy the Port of Fujairah’s largest independent oil storage and service provider, the company said on Feb. 16.
“Given the shortage of oil storage globally, we are excited to make progress with our project to expand our capacity in Fujairah, which is one of the largest oil hubs in the world. The [Phase 3 development] will include crude oil capabilities, as well as adding more capacity for fuel oil and clean products,” said Nicolaas L. Paardenkooper, chief executive officer of Brooge Energy and BPGIC.
The feasibility study contract award to EY follows the 2020 completion of front-end engineering design and start of preconstruction work—including the soil investigation and environmental impact assessment report—for Phase 3, which will include the new storage terminal as well as a new 180,000-b/d refinery (OGJ Online, Oct. 22, 2020; July 15, 2020).
Brooge Energy most recently said it expects the Phase 3 development to be operational in late 2022.
Senex reaches nameplate production at Atlas CSG project
Senex Energy Ltd., Brisbane, has reached nameplate capacity production of 32 terajoules/day of gas (12 petajoules/year) at its Atlas coal seam gas project in the Surat basin of southeast Queensland.
A further non-firm capacity of 8 terajoules/day is also available from the Atlas plant, the company said.
The project came on stream in late 2019 (OGJ Online, Oct. 8, 2019).
It currently comprises production from 60 wells, gathering pipelines, and production infrastructure and a 60 km gas pipeline to connect to the Wallumbilla gas hub.
The permit area covers 58 sq km and lies 20 km southwest of Wandoan. There are plans to increase the number of wells to 100 during the course of its life.
Last year, Senex was awarded additional acreage adjacent to the Atlas permit that it says will enable it to increase production up to 56 terajoules/day (20 petajoules/year).
All the gas is earmarked for domestic consumption.
The initial Project Atlas acreage has a 2P reserve estimate of 144 petajoules of gas.
Senex owns 100% of the upstream side of the project, while infrastructure company Jemena owns and operates the pipelines and the gas production plant.
TRANSPORTATION Quick Takes
Cheniere initiating wellhead-to-delivery emissions tracking
Cheniere Energy Inc. plans to begin providing its LNG customers with greenhouse gas (GHG) emissions data associated with each LNG cargo produced at its Sabine Pass and Corpus Christi liquefaction plants. The cargo emissions tags (CE tags) are designed to enhance environmental transparency by quantifying the estimated GHG emissions of LNG cargoes from wellhead to cargo delivery. The company expects to provide CE tags to customers beginning in 2022, with the ultimate goal of providing dynamic GHG emissions data.
The CE tags will use Cheniere’s proprietary lifecycle analysis (LCA) model, built incorporating accounting frameworks from LCAs created by the US Department of Energy’s National Energy Technology Laboratory, and will use publicly available data from value chain participants, as well as operational data from both Sabine Pass and Corpus Christi.
Cheniere’s 30-million tonne/year (tpy) Sabine Pass plant has been operating since 2016. It produces from five trains and the company expects to put a sixth train in service during 2022 (OGJ Online, Aug. 7, 2020). Cheniere’s 10-million tpy Corpus Christi plant has been producing from two trains since 2019 and expects to add a third in 2021.
One of the sticking points in expanding US LNG exports to Europe has been concern on the part of potential customers regarding GHG emissions.
NuStar to expand Albuquerque refined products pipeline
NuStar Energy LP plans to develop 6,000 b/d of incremental pipeline capacity for delivery of refined products, including gasoline, diesel, and jet fuel, into the Albuquerque, NM, region.
NuStar will upgrade pump stations on a pipeline system it jointly owns with Phillips 66 Partners that transports refined products from Amarillo, Tex., to Albuquerque. In addition to increasing capacity on the system, the project will install larger and more efficient electric pumps and a modern, efficient, diesel-driven pump, providing for higher flow while reducing emissions by eliminating two diesel-driven pump stations. The project is expected to be complete by mid-2022.
In August 2020, NuStar reactivated an idled pump station on its refined products Colorado Springs Pipeline system, increasing capacity by 6,000 b/d into the Colorado Springs and Denver markets. Both markets had lost supply when HollyFrontier Corp.’s 52,000-b/d refinery in Cheyenne, Wyo., closed last year to convert into a renewable fuels plant (OGJ Online, June 2, 2020).
Damietta LNG loads first cargo since 2012
Eni SPA’s 7.56 billion cu m/year Damietta LNG plant in Egypt has produced and loaded its first cargo since 2012. An agreement to fully restart operations has been authorized by governmental authorities and is expected to close first-half March 2021.
Eni in late 2020 signed agreements for the plant’s restsart with Egypt, Egyptian General Petroleum Corp., Egyptian Natural Gas Holding Co. (EGAS), and Spanish company Naturgy (OGJ Online, Jan. 4, 2021).
Damietta LNG is owned by Segas, which is 40% held by Eni through Union Fenosa Gas (50% Eni, 50% Naturgy). Union Fenosa will be transferring its ownership stake to Eni and EGAS as part of the restart agreements.
Ongoing development of Egypt’s offshore Zohr and Nooros gas fields has allowed the country to reenter the LNG export market.