Refining, chemical projects move ahead amid demand recovery

Recovering global demand for transportation fuels amid coronavirus (COVID-19) vaccine rollouts and ongoing steady requirements for chemical-based materials used in producing hygiene-related products such as personal protective gear, packaging, medical equipment, detergents, and disinfectants are restoring operators’ confidence in advancing construction of previously announced refining and petrochemical projects, as well as encouraging investments in newly announced grassroots developments.

Despite continuation of conventional hydrocarbon projects, however, considerable investment remains directed at projects geared toward expanding growth in renewables-based downstream projects.

This article provides recent developments on notable refining and integrated petrochemical projects underway as well as a selection of projects launched since publication of OGJ’s November 2020 Construction Update.

Improving, expanding existing assets

As demand slowly returns in the wake of the height of the COVID-19 pandemic, global refiners and petrochemical producers remain focused on advancing construction activities aimed mostly at maximizing value of existing processing and production assets.

In early April 2021, the Nigerian government’s Federal Executive Council (FEC) let a $1.5-billion contract to a subsidiary of Maire Tecnimont SPA to provide a suite of services for the long-planned major rehabilitation of Nigerian National Petroleum Corp. (NNPC) subsidiary Port Harcourt Refining Co. Ltd.’s (PHRC) Port Harcourt refining complex—which includes a 60,000-b/sd hydroskimming refinery and 150,000-b/sd full-conversion refinery—in Rivers state. As part of the contract, Tecnimont SPA will deliver engineering, procurement, and construction (EPC) activities for the full rehabilitation project, which aims to restore the complex to a minimum of 90% of its nameplate capacity by yearend 2024.

Upon awarding the contract, Mallam Mele Kyari, NNPC’s group managing director, said NNPC will continue with the presidential mandate to fix the country’s federally owned refineries, which will include future works at NNPC subsidiaries Warri Refining & Petrochemcial Co. Ltd.’s 125,000-b/sd refinery in Delta state, and Kaduna Refining & Petrochemical Co. Ltd.’s 110,000-b/sd refinery in Kaduna state.

State-owned Ecopetrol SA said in mid-February 2021 it is investing nearly $780 million during the next 2 years on a series of projects aimed at ensuring operational and environmental sustainability of its 250,000-b/d Barrancabermeja refinery in Santander, Colombia. The investment covers works focused on conserving water, reducing emissions, and improving quality of fuel production at the site as part of Ecopetrol’s broader strategy to reduce the refinery’s impacts to air, water, and soil, as well as to guarantee its legal compliance with environmental regulations. Initiatives already under way at Barrancabermeja as part of Ecopetrol’s 2021-23 investment program include a technology upgrade of the refinery’s wastewater treatment plant—now 74% completed—as well as an upgrade and expansion of the complex’s mild hydrocracking unit that will enable the refinery to reduce sulfur content of its gasoline production to 30 ppm by 2025 and 10 ppm by 2030. Alongside a modernization project to improve reliability of the refinery’s water segregation system, the program also includes a project—now in its basic engineering stage—at the complex’s sulfur plants to control emissions of sulfur oxides.

The new Barrancabermeja investment follows $721million spent by Ecopetrol during the last 6 years to ensure the refinery—Colombia’s largest—remains technologically up to date. As a result of rigorous biosafety protocols implemented at Barrancabermeja to maintain continuity of operations amid the COVID-19 pandemic, Ecopetrol confirmed the refinery will continue to execute planned shutdowns in 2021 to carry out works designed to improve reliability and integrity of units, tanks, and boilers. In 2020, Ecopetrol invested a total of $181 million at Barrancabermeja on projects to improve reliability ($100 million), environmental legal compliance ($58 million), quality of fuel production ($12 million), and health, safety and environment (HSE, $11 million) at the site.

Elsewhere in South America, Petróleo Brasileiro SA (Petrobras) in March 2021 said it is undertaking the revamp of an existing hydrotreater to improve both quality and quantity of low-sulfur diesel production at its 239,000-b/d Duque de Caxias (REDUC) refinery in the Baixada Fluminense area of Brazil’s Rio de Janeiro state (Fig. 1). Alongside reducing sulfur content of diesel to 10 ppm from 500 ppm to meet domestic and international market specifications, the hydrotreating unit upgrade also will nearly double Diesel S10 (10 ppm sulfur) production at the site to 9,500 cu m/day from its current 5,000 cu m/day. Scheduled to be completed by second-half 2023 at a proposed investment of 140 million Brazilian real ($25 million), the unit revamp comes as part of the company’s broader strategic objective of producing cleaner, higher-quality, more efficient fuels that have less impact on the environment.

Petrobras said it also plans to undertake similar unit upgrades to expand Diesel S10 production at its 434,000-b/d Refinaria de Paulínia (REPLAN) refinery in Paulínia, São Paulo, and 252,000-b/d Refinaria Henrique Lage (REVAP) refinery in São José dos Campos, São Paulo. While the operator disclosed no further details regarding the REPLAN and REVAP projects, the company did confirm that implementation would increase overall Diesel S10 production by as much as 16,500 cu m/day.

In India, Numaligarh Refinery Ltd. (NRL) in mid-February 2021 let a contract to Axens Group of France to license its proprietary technologies for a naphtha hydrotreating unit, octanizing continuous catalyst regeneration (CCR) reforming unit, C5-C6 isomerization unit, and Prime-G+ FCC gasoline selective desulfurization unit for a gasoline-production block to be built as part of NRL’s long-planned expansion of its 3-million tpy Numaligarh refinery. Alongside technology licensing, Axens will also supply the basic engineering design package, catalysts, adsorbents, proprietary equipment, training, and technical services for the project. Earlier in the year, NRL awarded respective contracts to Lummus Technology LLC and Chevron Lummus Global LLC to provide technology licensing, basic engineering, and additional services for a new Indmax petrochemical fluidized catalytic cracking (PFCC) unit and LC-FINING ebullating-bed residue hydrocracking platform—including an integrated vacuum gas oil hydrotreater—to be added as part of the project.

As part of the government of India’s Hydrocarbon Vision 2030 initiative to help meet growing demand for petroleum products in northeastern India, NRL’s refinery expansion—which will increase overall crude oil processing capacity at Numaligarh by 6 million tpy to 9 million tpy as well as revamp the refinery’s existing 300,000-tpy delayed coking unit to increase its processing capacity to 570,000 tpy—is scheduled to be completed by 2024 and will include construction of a 180,750-b/d, 1,398-km crude pipeline from Paradip to Numaligarh, as well as a 120,500-b/d, 654-km products pipeline from Numaligarh to Siliguri. According to a February 2020 environmental impact assessment for the refinery’s expansion completed by Engineers India Ltd. (EIL), the project will add the following major units and capacities at Numaligarh:

• Combined crude-vacuum distillation unit (with naphtha stabilizer); 6 million tpy.
• Naphtha hydrotreating unit; 1.2 million tpy.
• CCR unit; 750,000 tpy.
• Naphtha isomerization unit; 500,000 tpy.
• PFCC unit; 1.95 million tpy.
• FCC gasoline hydrotreating (desulfurization) unit; 580,000 tpy.
• Diesel hydrotreating unit; 3.55 million tpy.
• Hydrogen generation unit; 95,000 tpy.
• Residue upgrading unit (ebulated bed, with vacuum gas oil hydrotreater); 2 million tpy.
• LPG treating unit; unavailable.
• Fuel gas treating unit; unavailable.
• Sour-water stripping unit; unavailable.
• Amine regeneration unit; unavailable.
• Sulfur recovery unit, tail-gas treatment unit; 230,000 tpy each.

Russian refiners aggressively progressed construction projects to modernize and expand existing assets. In mid-February 2021, PJSC Gazprom Neft confirmed its ongoing 700-billion ruble ($9.156-billion) modernization programs at subsidiaries JSC Gazpromneft-ONPZ’s 22-million tpy Omsk refinery in Western Siberia and JSC Gazpromneft-MNPZ’s 12.2-million tpy Moscow refinery that—now in their second phases and due for full completion by 2025—have increased the sites’ output of light oil products and expanded the resource base necessary for production of new in-demand products. In a Feb. 18, 2021 conference call reporting full-year 2020 earnings, Alexey Yankevich, Gazprom Neft’s chief financial officer, said the company will execute a great deal of work to complete the more-extensive Omsk refinery modernization by 2022.

A major project now nearing startup under the more than 300-billion ruble Omsk modernization program is ONPZ’s 2-million tpy advanced oil refining complex (AORC) that, once online, will use a combination of hydrocracking and sulfur-removal technologies to remove 99.8% of sulfur compounds from unfinished feedstock for production of Euro 5-quality fuel. While it faced slight setbacks as part of Gazprom Neft’s optimization of 2020 capital investment due to COVID-19, ONPZ said on Mar. 31, 2021, that Russia’s Federal Service for Environmental, Technological, and Nuclear Supervision (Rostekhnadzor) confirmed AORC was in full compliance with regulatory requirements for both energy efficiency and industrial and environmental safety. With construction and installation work on the complex now completed, ONPZ said it is testing equipment as part of AORC’s commissioning. Specifically, the AORC complex will enable Omsk refinery to flexibly regulate production levels for automobile and aviation fuels, as well as raw materials for lubricants. The complex’s central hydrocracking unit also will ensure further processing of heavy petroleum fractions into diesel fuel, jet fuel, and other high-quality products in compliance with Euro 5-quality standards (Fig. 2).

With a production capacity of 8.4 million tpy, the more than 60-billion ruble AORC also will feature a suite of technologies designed to reduce emissions at Omsk, including ongoing monitoring of environmental impacts and a closed-loop equipment drainage system allowing recoverable oil products to be sent for recycling. Following startup of the new complex, ONPZ will decommission six existing but obsolete units at the refinery, further reducing the site’s overall environmental footprint.

In March 2021, Gazpromneft-MNPZ let a preliminary EPC contract to DL E&C Co. Ltd. of South Korea and its subsidiary Daelim RUS LLC for a new hydrocracking plant to be built as part of the Moscow refinery’s modernization. The Mar. 11 agreement, which will convert into a formal contract within 90 days, is valued at 327.1-billion won ($293 million) and will run for 42 months from the date of commencing work. While neither Gazprom Neft nor Gazpromneft-MNPZ have revealed specific information regarding the planned grassroots hydrocracking plant, the project presumably comes as part of a third phase of the refinery’s modernization program that will focus on further improving environmental performance and deepening refining capabilities at the site.

The planned hydrocracking unit for the Moscow refinery follows Gazpromneft-MNPZ’s July 2020 commissioning of its 98-billion ruble Euro+ combined oil refining unit (CORU), an element of the manufacturing site’s second-phase modernization designed to improve overall environmental performance as well as its yield of light-end, Euro 5-quality petroleum products, including gasoline, diesel, and aviation kerosine. In its yearend 2020 earnings report released February 2021, Gazprom Neft said overall modernization works at the Moscow refinery were 80% complete, with full ramp-up of the Euro+ CORU in third-quarter 2020 increasing refining depth at the site to 85%. Commissioned during the height of the COVID-19 pandemic, the Euro+ CORU—which consists of a 6-million tpy primary atmospheric-vacuum distillation unit; a 1-million tpy gasoline reforming unit; a 2-million tpy diesel (distillate) hydrotreating unit that includes an iso-dewaxing unit; a gas fractionation unit; and an amine regeneration unit—also has enabled increased production of Euro 5-quality gasoline and diesel fuels, and helped further reduce the refinery’s operational impact on the environment, including a 7% slash in its energy consumption.

Initiated in 2011 and scheduled for completion in 2025 at a final estimated cost of 350 billion rubles, the Moscow refinery’s modernization program has included various initiatives allowing it to reduce its premodernization environmental impacts by 50%, with anticipation of another 50% reduction in impacts to occur once all Phase 2 works are completed in 2021.

In late-March 2021, Russia’s Ministry of Energy (MoE) granted PJSC Lukoil an investment premium to the refundable excise tax on crude oil until Jan. 1, 2031, to support the operator completing construction of a deep conversion, delayed coking complex at subsidiary LLC Lukoil-Nizhegorodnefteorgsintez’s (NNOS) 17-million tpy Kstovo refinery in central Russia’s Nizhny Novgorod region. Once in operation, the complex will enable the Nizhny Novgorod refinery to slash its production of fuel oil by 2.6 million tpy and increase annual output of Russian Class 5 (equivalent to Euro 5)-quality diesel fuel by 700,000 tpy. Additionally, the refinery’s overall product yield will increase to 97%, with yield of light products reaching 74-75%. Fuel oil production from the refinery simultaneously will drop to less than 4%. With core long-lead equipment now installed and installation of on-site pipelines and equipment piping currently under way and scheduled for commissioning in fourth-quarter 2021, Nizhny Novgorod’s new complex will include the following major units:

• 2.11-million tpy delayed coker.
• 1.5-million tpy combined diesel fuel and gasoline hydrotreater.
• 50,000-cu m/hr hydrogen production unit.
• 425,000-tpy gas fractionator.
• 81,000-tpy combined elemental sulfur-sulfuric acid production unit.

Integration projects

While operators continued to undertake standalone refining projects, the bulk of ongoing and newly announced refinery construction activity involved deeper integration of petrochemical operations.

In January 2021, OMG AG announced a €40-million ($48-million) investment to increase ethylene and propylene production capacities at subsidiary OMV Deutschland GMBH’s 3.8-million tpy Burghausen refinery in Bavaria, Germany. Part of the operator’s strategy to realign its downstream operations for a petrochemicals-based future, the project—which will expand and modernize the refinery’s cracker units and petrochemical cold section—aims to increase feedstock for the neighboring Bavarian Chemical Triangle. With initial groundwork for the project already under way and slated for full execution during the refinery’s next turnaround, the expansion of Burghausen cracker units will increase ethylene and propylene production at the site by about 50,000 tpy. The upgraded units are scheduled to enter operation third-quarter 2022. OMV saidthat by 2025 it plans to invest up to €1 billion in three regional refineries—Burghausen, its 9.6-million tpy refinery in Schwechat, Austria, and its 4.5-million tpy Petrobrazi refinery in southeast Romania—with more than 50% of this amount dedicated to petrochemical development at the sites.

In April 2021, Indian Oil Corp. Ltd. (IOC) let a €50-250 million contract to Technip Energies NV to provide EPC and commissioning (EPCC) services for a new 1-million tpy, once-through hydrocracking unit, a fuel gas treatment unit, and associated installations included as part of IOC’s project to expand crude processing capacity at its 6-million tpy Barauni refinery in Begusarai District, Bihar. The new units will enable the refinery to produce Stage VI (BS VI, equivalent to Euro 6-quality standards) fuels as well as petrochemicals such as polypropylene. Scheduled for startup by April 2023, the overall Barauni expansion—which will increase processing capacity by 3 million tpy to 9 million tpy—will include a new 562,000-tpy propylene recovery unit, a new 200,000-tpy polypropylene unit, a new 390,000-tpy LPG treatment unit, and a new 880,000-tpy naphtha splitting unit.

IOC also confirmed in March 2021 it will move forward with construction of a 10-million tpy expansion of its 15-million tpy integrated Panipat refining and chemical complex in Haryana. Designed to improve operational flexibility of the refinery to help meet domestic energy demand, the project—which would include installation of a polypropylene unit and catalytic dewaxing unit—will increase production of petrochemicals and value-added specialty products to elevate margins and derisk IOC’s companywide exposure to the conventional fuel market. Budgeted at an estimated cost of 329.46-billion rupees ($4.4 billion), the Panipat capacity expansion is slated for commissioning by September 2024 and will include a 1.15-million tpy propylene recovery unit and 450,000-tpy polypropylene unit.

In February 2021, Shandong Yulong Petrochemical Co. Ltd.—a joint venture of China’s Nanshan Holdings Co. Ltd. (71%), Wanhua Chemical Group Co. Ltd. (20%), and Shandong Development & Investment Holding Group Co. Ltd. (9%)—let a contract to UOP to provide technology for new units at the aromatics complex of Shandong Yulong’s grassroots 20-million tonne/year (tpy) integrated refining and petrochemical complex under construction as part of the first phase of the Yulong Island Refining and Chemical Integrating Project at Yulong Petrochemical Industrial Park, Yantai City, Shandong Province, China. Specific proprietary technologies and units UOP will provide for production of 3 million tpy of mixed aromatics include:

• A Unionfining naphtha hydrotreating unit and UOP CCR platforming technology to convert naphtha into high-octane gasoline and aromatics for production of multiple synthetic materials.
• Olefin removal process (ORP) and UOP Sulfolane technology for aromatics extraction.
• Isomar isomerization technology.
• Tatoray technology for toluene disproportionation.

The UOP contract for the nearly 127.4-billion yuan ($19.5 billion) Yulong Island Refining and Chemical Integrating Project (Phase 1) follows Shandong Yulong’s late-November 2020 award to Lummus Technology for technology licensing to be implemented at the complex’s two mixed-feed crackers, an ethylbenzene-styrene monomer (EB-SM) plant, and two PP plants as follows:

• The mixed-feed crackers of the complex’s two ethylene plants—each with a capacity of 1.5 million tpy—will use Lummus’s highly selective short residence time (SRT) VII cracking heaters.
• The 500,000-tpy EB-SM plant will be equipped with Lummus-UOP’s EBOne and Classic SM technologies.
• The two 400,000-tpy PP lines will use Lummus Novolen Technology GMBH’s proprietary Novolen gas-phase PP technology.

Scheduled to begin operation in 2022-23, Phase 1 of Shandong Yulong’s integrated complex also will include the following units:

• Two 550,000-tpy aromatics extraction units.
• Two 220,000-tpy butadiene extraction units.
• Two 800,000-tpy ethylene glycol plants.
• Two 400,000-tpy PP plant (separate from Novolen-licensed units).
• One 300,000-tpy PP plant (Japan Polypropylene Corp.-licensed Horizone process).
• One 200,000-tpy low-density polyethylene-ethylene vinyl acetate LDPE-EVA unit.
• One 400,000-tpy LDPE-EVA unit.
• One 300,000-tpy high-density polyethylene (HDPE) unit.

Zhejiang Hengyi Group Co. Ltd. subsidiary Hengyi Industries Sdn. Bhd. in February 2021 let a contract to UOP to license proprietary technologies to expand aromatics production at the operator’s 8-million tpy integrated refining and petrochemical complex on Pulau Muara Besar island in Brunei to help meet the Asia Pacific’s increased demand for paraxylene, the primary component of many plastic resins, films, and fibers. UOP’s scope of delivery for the aromatics block includes its CCR platforming technology to convert naphtha into aromatics, as well as its light desorbent Parex (LD Parex) process for recovery of 2.3 million tpy of high-purity paraxylene from mixed xylenes using a more energy-efficient process. The LD Parex complex will include UOP’s Sulfolane technology for aromatics extraction, Isomar technology to convert xylene isomers into more valuable paraxylene, and Tatoray technology to convert toluene and heavier aromatics into mixed xylenes and high-purity benzene to more than double the yield of paraxylene from naphtha feedstock. Alongside its proprietary naphtha hydrotreating and olefin removal process (ORP) units, the service provider also will deliver the following UOP-licensed new units to the complex:

• A second Sulfolane unit for the extraction of pygas.

• A vacuum gas oil (VGO) Unicracking unit.

• A diesel Unicracking unit targeting maximum naphtha production.

Once completed, the project will equip Hengyi Industries with an overall paraxylene production capacity of more than 3.8 million tpy. The UOP contract comes as part of Hengyi Industries’ Phase 2 development of the Pulau Muara Besar site, which includes expansion of the site’s aromatics and cracker plant as well as increasing the refinery’s crude processing capacity by 14 million b/d to 22 million b/d. The Phase 2 expansion is scheduled for commissioning in 2022.

In mid-January 2021, China Petroleum & Chemical Corp. (Sinopec) let a more than $120-million contract to John Wood Group PLC to provide EPC services for a petrochemical expansion at subsidiary Sinopec Hainan Refining & Chemical Co. Ltd.’s (HRCC) 8-million tpy refinery development in southern China’s Yangpu Economic Development Zone of Hainan Free Trade Zone (FTZ). Wood will deliver EPC services for the sitewide pipe rack and associated pipework, power cables, telecommunications, and lighting for HRCL’s proposed ethylene renovation and expansion project at the operator’s integrated complex. Already well under way and scheduled to be completed as well as commissioned by October 2022, the planned ethylene renovation and expansion project will enable the complex to produce up to 1 million tpy of ethylene derivatives as well as expand the site’s ability to further process crude oil, allowing Hainan FTZ’s ethylene output to serve ethylene demand across China and globally. The project—which aims to boost China’s downstream sector by more than $14.1 billion/year and transform Hainan FTZ into a new engine for regional economic growth—will include 10 sets of unidentified equipment for chemical production, three sets of equipment for oil refining, and supporting storage and terminal installations.

Grassroots projects

In addition to expansion and modernization works, operators continued to advance construction of grassroots refining and petrochemical projects, particularly in regions where industry projections suggest rising demand from still-growing populations will exceed existing supply.

In February 2021, IOC broke ground on subsidiary Chennai Petroleum Corp. Ltd.’s (CPCL) recently approved project to build a new 9-million tpy refinery at Cauvery basin, in Panangudi Village, Nagapattinam District, Tamilnadu, India. Intended to help meet southern India’s demand for petroleum products, the planned Cauvery Basin project will involve dismantling CPCL’s existing 1-million tpy refinery at the site—which ceased operations on Apr. 1, 2019—to make way for the new construction. CPCL is pursuing environmental approval for the greenfield complex, but specific timelines for its completion and commissioning have yet to be determined.

As currently proposed, the new Cauvery Basin refining and integrated petrochemical complex will include the following major units and capacities:

• Combined crude-vacuum distillation unit; 9 million tpy.
• Naphtha hydrotreating unit; 1.5 million tpy.
• Isomerization unit; 570,000 tpy.
• CCR unit; 625,000 tpy.
• Diesel hydrotreating unit; 5 million tpy.
• Vacuum gas oil hydrotreating unit; 3 million tpy.
• INDMAX FCC unit; 2.43 million tpy.
• INDMAX FCC gasoline hydrotreating (desulfurization) unit; 700,000 tpy.
• OCTAMAX unit; 125,000 tpy.
• Polypropylene unit; 475,000 tpy.
• Delayed coking unit; 2.5 million tpy.
• Hydrogen generation unit; 98,000 tpy.
• Sulfur recovery unit (SRU) with independent tail-gas treatment unit (TGTU), Train 1; 432 tonnes/day.
• SRU with independent TGTU, Train 2; 432 tonnes/day.

Start of construction on the refinery follows IOC’s approval for incorporation of a joint venture under which IOC (25%) and CPCL (25%) would hold a combined 50% equity interest in developing the project. Subject to statutory approvals, the remaining 50% interest in the JV would be held by outside financial, strategic, or public investors to be identified later.

In mid-March 2021, Azikel Group subsidiary Azikel Petroleum Ltd. advanced plans for a proposed 12,000-b/sd hydroskimming modular refinery in Obunagha-Gbarain, Yenagoa, Bayelsa State, Nigeria with a contract award to UAE-based Chemie Tech LLC to serve as EPC contractor on the project. Bounded by the River Nun on the south, the refinery—which will receive a reliable feedstock of Nigerian Bonny Light crude and condensate via pipeline directly from Royal Dutch Shell PLC’s Gbarian-Ubie Shell gas gathering at the site’s eastern boundary—will include a crude distillation unit with debutanizer, naphtha hydrotreater, naphtha splitter, catalytic reformer, diesel hydrotreater, and gasoline stabilizer. While Dr. Eruani Azibapu Godbless, president of Azikel Group, said the project will be delivered on schedule and within budget, the operator has yet to confirm a definitive revised timeframe for its commissioning.

Further south on the continent, Angola’s Ministry of Mineral Resources and Petroleum in mid-March 2021 awarded the country’s previously announced tender for construction of a 100,000-b/d grassroots refinery in Soyo, Zaire Province, to US-based Quanten Consortium Angola LLC. Quanten will design, build, own, and operate the proposed deep-conversion refinery at Soyo, which will play a critical role in Angolan President João Lourenço’s program of strengthening the African nation’s economy by helping reduce the country’s current reliance on refined product imports. The refinery currently is slated for startup in 2024.

The planned Soyo refinery is one of several already announced developments under President Lourenço’s national plan to increase domestic crude processing capacity to help considerably reduce the country’s dependence on imports of refined products, encourage increased foreign investment, and create employment opportunities for Angolans. Less than a month earlier, the Angolan Parliament voted unanimously to pass legislation authorizing a series of tax and customs incentives to advance construction of a greenfield refinery on the Malembo plain, 30 km north of Cabinda.

Approval of the incentive package follows the late-2020 final investment decision (FID) by state-owned Sonangol EP (10%) and partner Gemcorp Capital LLP (90%)—a London-based investment management firm—to proceed with the proposed three-phased project. The first $220-million investedwill include construction of a 30,000-b/d crude distillation unit, desalinator, kerosine treating unit, and auxiliary infrastructure, as well as a conventional float anchoring system, pipelines, and a more than 1.2-million bbl storage terminal. At an additional estimated cost of $700 million also covered by the FID, Phases 2 and 3 will add another 30,000 b/d of crude processing capacity, as well as units for catalytic reforming, hydrotreating, and catalytic cracking that will transform the site into a full-conversion refinery. Still on schedule for startup in first-quarter 2022, Phase 1 of the Cabinda refinery will be followed by commissioning of Phases 2 and 3 in second-quarter 2023 and second-quarter 2024, respectively.

Alongside the grassroots Cabinda refinery, Angola also is continuing construction on a new unit at Sonangol’s existing 65,000-b/d Luanda refinery, the country’s only. Scheduled for completion in 2022 at a cost of $235 million, the unidentified unit will increase the refinery’s gasoline production about 10,500 b/d from its current 72,000 b/d output rate, saving Angola about $200 million in expenditures on fuel imports.

Sonangol also is advancing its long-planned project to build a new refinery in Lobito, Benguela Province. Temporarily suspended in 2016, the project remains under reassessment based on new technical and financial assumptions following completion of an updated economic and financial feasibility study in 2020. Following the revised feasibility study—which considered whether to build the Lobito refinery in a single phase or in two phases, with a first-phase capacity of 100,000 b/d and a second-phase capacity of another 100,000-b/d, as well as inclusion of petrochemical production—Sonangol said it has selected its preferred configuration for the future refinery and will soon update front-end engineering design (FEED) for the project, on which JGC Corp. of Japan plans to deliver EPC.

Focus on renewables

With demand for petroleum-based products anticipated to return gradually and still well-below prepandemic levels, downstream operators aggressively continued to pursue investments dedicated to production of cleaner, renewables-based fuels in line with global decarbonization targets to 2050. Between yearend 2020 and early 2021, refiners announced a flurry of new projects involving construction of grassroots renewable fuel plants as well as addition of new or conversion of existing units to enable coprocessing renewable feedstock alongside conventional crude supplies.

In late 2020, Repsol SA let a contract to Axens to license technology for Spain’s first advanced biofuels production plant to be built at the operator’s 220,000-b/d Cartagena refinery. Axens will provide licensing for its proprietary Vegan technology—which hydrotreats a wide range of lipids for production of low-density, high-cetane renewable diesel as well as renewable, sulfur-free jet fuel—to be implemented in a new hydrotreating unit that will use a feedstock of recycled raw materials to produce 250,000 tpy of hydrobiodiesel, biojet fuel, bionaphtha, and biopropane. The €188-million Cartagena renewables investment—which also includes commissioning of a new hydrogen plant—comes as part of Repsol’s commitment to advancing the energy transition and the company’s goal of achieving net-zero emissions by 2050 in accordance with the Paris Agreement.

Emphasizing the importance of the closed-loop, circular economy to promote sustainable development by efficient use of resources, Repsol said it plans by 2030 to double production of high-quality biofuels from vegetable oils (HVO) to 600,000 tpy, half of which will be produced from waste before 2025. to the company has two industrial decarbonization projects planned at its majority owned Petróleos del Norte SA’s (Petronor) 220,000-b/d Bilbao refinery in Múskiz, Vizcaya, including a new €60-million, 50-b/d zero-emissions synthetic fuel production plant based on CO2 and green hydrogen due for startup in 2024,and a grassroots €20-million pyrolysis plant that will use a feedstock of 10,000 tpy of urban waste to produce gas to partly replace traditional fuels currently used in the Bilbao refinery’s production processes. Repsol also confirmed that its 150,000-b/d Puertollano refinery in Spain’s province of Ciudad Real, Castile-La Mancha, produced its first batch of biojet for Spain’s aviation market in July 2020.

Alongside expanding renewable diesel production capacity to 3,000 b/d from 1,000-b/d in early 2021 at its 221,000-b/d Humber refinery at South Killingholme, North Lincolnshire, UK, Phillips 66 confirmed in November 2020 that plans are under way to increase low-carbon, renewable fuels production at the site by another 2,000 b/d, reaching 5,000 b/d by 2024 (Fig. 3). The Humber biofuels project follows Phillips 66’s August 2020 announcement that it is permanently ceasing the processing of crude oil at the 120,000-b/d portion of its San Francisco refining complex in Rodeo, Calif., and converting the plant into a renewable fuels refinery as part of a $750-800 million investment strategy regarding the energy transition to ensure long-term viability and competitiveness.

Phillips 66 also is progressing on a project at the Humber refinery that will use renewable hydrogen to produce fuels at the site. The pilot project—named Gigastack—is a collaboration between Phillips 66 UK subsidiary Phillips 66 Ltd., Danish wind farm developer and operator Ørsted AS, hydrogen systems developer ITM Power PLC, and UK-based consultancy Element Energy Ltd. that aims to harness offshore wind from Ørsted to generate renewable electricity that would be used to power electrolysis for production of hydrogen, a low-emission fuel capable of powering transportation and heavy industry, as well as being usable in multiple refining processes.

As part of the project’s first phase, ITM Power designed a 5-Mw electrolyzer stack that, under the second phase, will be installed and trialed for development of a 100-Mw electrolyzer system equipped to use the renewable electricity to split water into oxygen and hydrogen gas, the latter of which would be fed to Humber for uses that include lowering the sulfur content of diesel fuel. Launched in 2020, the project’s second phase—which has secured £7.5 million in funding from the British government as part of a £90-million package to cut UK carbon emissions—includes execution of a FEED study for the 100-Mw electrolyzer system. The project additionally provides an opportunity for Phillips 66 and its partners to develop a new renewable hydrogen market based on a feedstock of only water and renewable power, in which the Humber refinery would use the hydrogen supply in hydrotreating processes for production of both conventional and waste-based fuels, refueling of refinery heaters, and possible future expansions, such as battery coke, which require hydrotreating capability.

Elsewhere in Europe, Neste Corp. announced in March 2021 that it possibly will build a new renewables refinery in Rotterdam, the Netherlands, as part of the operator’s plan to expand its existing European feedstock and production platform for renewable products. Neste—which has yet to reveal details regarding capacity or precise location of the proposed Rotterdam renewables expansion—said it expects to reach FID on the project by yearend 2021 or early 2022 for targeted start of production in 2025.

Selection of the Rotterdam location follows Neste’s €258-million November 2020 purchase of Bunge Ltd. subsidiary Bunge Loders Croklaan JV’s sustainable plant-based specialty oils and fats refinery in Rotterdam. Neste had previously said it would use the plant to increase pretreatment capacity of complex waste and residue feedstocks in support of expanding production at its more than 1-million tpy renewable diesel refinery in the Port of Rotterdam beyond 2023. Neste also confirmed in March 2021 a feasibility study was under way for a project that, by 2023, would add 450,000 tpy of sustainable aviation fuel (SAF) production at the Rotterdam refinery.

In Singapore, Neste has invested €1.4 billion in a project to expand production of renewable products at the 1.3-million tpy renewable diesel refinery it operates. Currently under way and scheduled to begin commercial operation in 2023, the 1.3-million tpy capacity expansion—which includes optionality to produce up to 1 million tpy of SAF at the plant—will bring Neste’s total global renewable production capacity to 4.5 million tpy. Expansion of its renewable diesel and SAF production platform comes as part of Neste’s two strategic climate commitments: achieving carbon-neutral production by 2035 and reducing customers’ greenhouse gas emissions by at least 20 million tpy by 2030.

Neste’s ongoing renewables investments follow the operator’s late-2020 approval of a restructuring program for its conventional refining operations in Finland that included permanently shuttering processing and production at its 58,000-b/d Naantali refinery by the end of March 2021. Neste said the business transformation comes amid its determination that demand for fossil-based fuel products will continue to decline, requiring fundamental changes to secure the competitiveness of its business, which include increasing its share of renewable energy solutions in line with continued growth of these energy sources moving forward. By 2030, Neste said it expects global renewable diesel demand to exceed 20 million tpy.

Across the Atlantic, Diamond Green Diesel Holdings LLC (DGD)—a 50-50 joint venture of Valero Energy Corp. and Darling Ingredients Inc.—announced in January 2021 construction of a grassroots 470-million gal/year renewable diesel plant at Valero’s 395,000-b/d refinery in Port Arthur, Tex. At an estimated construction cost of $1.45 billion and scheduled for startup in second-half 2023, the new Port Arthur plant—when combined with the partners’ previously announced expansion of Valero’s 290-million gal/year renewable diesel plant in Norco, La.—will increase DGD’s total renewable diesel and renewable naphtha production capacities to 1.2 billion gal/year and 50 million gal/year. For Valero, the Port Arthur renewables project comes as part of its plan to increase existing “long-term competitive advantage in low-carbon transportation fuels” amid ongoing demand for renewable fuels as low-carbon fuel policies continue to expand globally, said Joe Gorder, Valero’s chairman and CEO.

DGD previously let a contract to UOP to license and implement its proprietary Ecofining process technology for a 30,000-b/d renewable diesel production train now under construction at the Norco renewable diesel plant. Scheduled to be completed during fourth-quarter 2021, Norco’s new 400-million gal/year renewable diesel plant—which will become the site’s second production train—will include a renewable naphtha finishing installation adjacent to the existing Train 1.

In March 2021, the government of Bolivia and state-owned Yacimientos Petrolíferos Fiscales Bolivianos (YPFB) Corp. 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 ensure the country’s energy security, the proposed plant will process 450,000 tpy of vegetable oils and waste-animal fat feedstocks to produce 9,000 b/d—or 3 million bbl/year—of renewable diesel. Specific feedstocks currently considered for processing at the proposed $250-million plant include soybeans, totaí, motacú, jatropha, used cooking oils, palm, and pine nuts, sourced from domestic private companies and business ventures. YPFB said it expects to launch a tender to secure an EPCC partner for the project during third-quarter 2021, with plant startup targeted for fourth-quarter 2024. The operator also confirmed it has entered into confidentiality agreements to explore data and information regarding process technologies for the plant with service providers Axens, UOP, and Haldor Topsoe AS.

Calgary-based Parkland Fuel Corp. in February 2021 said by yearend it will expand coprocessing of Canadian-sourced canola and tallow biofeedstocks with conventional crude oil by nearly 125% from 2020 at subsidiary Parkland Refining (B.C.) Ltd.’s 55,000-b/d refinery on Burrard Inlet in North Burnaby, near North Vancouver, BC. Following low-capital investments and work completed during its 2020 turnaround to enable coprocessing of about 44 million l. of canola and tallow biofeedstocks from Canadian sources by yearend, the Burnaby refinery plans to increase coprocessed volumes to 100 million l. during 2021 to deliver customers low-carbon fuel options that include diesel containing up to 15% renewable content. The operator said the annual environmental benefit of increased low-carbon fuel production at the site in 2021 will be equivalent to removing 80,000 passenger vehicles from the road, in line with the company’s commitment to a reduced-carbon future for Canada.