Global refiners focus on upgrading, modernizing existing plants

In July privately held JSC Antipinsky Refinery, the main production enterprise of JSC New Stream, completed a project to expand capacity of the atmospheric residue deep conversion unit at its 181,000-b/d refinery in the Tyumen region of Western Siberia, Russia. Photo from JSC Antipinsky Refinery.

In late 2016, the Perm refinery, which processes blended crudes from northern Perm Oblast and Western Siberia, completed a $50-million reconstruction of the diesel hydrodearomatization section of the site’s hydrocracking unit to enable hydrodewaxing for expanded production of Euro 5-quality diesel.

In February, PJSC Gazprom Neft let a contract to Maire Tecnimont SPA subsidiaries Tecnimont SPA and Tecnimont Russia LLC to deliver engineering, procurement, and construction management (EPCM) services for implementation of a 40,000-b/d delayed coking complex at its 259,000-b/d Omsk refinery in Western Siberia as part of the operator’s ongoing modernization program to reduce environmental impacts and improve processing capacities, conversion rates, energy efficiency, and production qualities at the site. Maire Tecnimont plans to complete its scope of work on the $215-million project within a tight schedule of 29 months from the contract-signing date due to availability of most long-lead items, which Gazprom Neft previously purchased and installed at the site.

Part of Gazprom Neft’s second-phase Omsk modernization works, the delayed coking complex—which aims to expand capacity for conversion of heavy residues to maximize liquids production and enable production of anode-grade quality coke—joins Gazprom Neft’s final installation of major equipment in July 2017 for the 40,000-b/d advanced oil refining complex and a project to upgrade and expand the refinery’s existing delayed coker.

In June, Gazprom Neft said it had reached 89% completion on construction of its previously announced project to build a Euro+ combined oil refining unit (CORU) to enable production of high-performance Euro 5-quality gasoline as part of the ongoing modernization and upgrade of its 243,000-b/d Moscow refinery.

The Euro+ CORU project, which will replace outdated equipment and be fully compliant with Russia’s current ecological standards and environmental regulations, will include the following once completed:

• A 120,500-b/d primary atmospheric-vacuum distillation unit (CDU-VDU 6).

• A 20,000-b/d gasoline reforming unit.

• A 40,000-b/d diesel (distillate) hydrotreating unit, which will include an iso-dewaxing unit.

• A gas fractionation unit.

• An amine regeneration unit.

Alongside reducing the refinery’s total environmental impact from processing activities by 11%/tonne of crude processed, the project will improve the complex’s operational energy efficiency and increase its intermaintenance period to 4 years from a current 2 years. The more than 98-billion ruble Euro+ CORU project remained on schedule for startup by yearend, with the entirety of its more than 250 billion-rubles second-stage modernization program on target for completion in 2020.

In March, PJSC Rosneft subsidiary JSC Ryazan Oil Refining Co. (RNPK) said it produced the first batch of AI-100 high-octane gasoline at its 340,000-b/d Ryazan refinery about 120 miles southeast of Moscow. Production of the low-sulfur gasoline results from Rosneft’s implementation of its broader program to modernize and upgrade operations of its Russian refineries for production of fuels meeting more stringent global environmental quality specifications. According to Rosneft’s web site, the following projects also are currently under implementation at RNPK’s refinery:

• Reconstruction of the diesel fuel hydrotreating unit.

• Construction of a two-unit desulfurization plant for dry hydrocarbon gases with a saturated amines regeneration block.

• Construction of a production complex for elemental sulfur applying the Klaus method, with storage, shipping, and operation infrastructure.

• Construction of the crude-vacuum distillation Unit 5.

• Reconstruction of treatment installations.

• Construction of the vacuum gas oil hydrocracking complex.

The projects come as part of Rosneft’s company-wide refinery modernization plan launched in 2008, which includes the construction of 30 units and reconstruction of more than 20 units at Rosneft’s Russian refineries between 2012 and 2020.

Early this year, PJSC Tatneft commissioned a naphtha hydrotreater and isomerization unit at the 120,500-b/d refinery of subsidiary JSC Taneco’s multiphase integrated refining and petrochemical complex in Nizhnekamsk, 250 km from Tatarstan’s capital city of Kazan. The 22,000-b/d naphtha hydrotreater and 8,400-b/d isomerization unit entered service on Jan. 25, forming the first stage in implementation of a full-scale design for the complex’s production of 100% Euro 5-quality gasoline, with the units respectively enabling output of high-octane gasoline blending components and feedstock for a catalytic reforming unit scheduled for commissioning at the site by yearend.

The newly commissioned units come as part of an ongoing program Tatarstan launched in 2005 to strengthen the republic’s refining industry, and in accordance with basic provisions of a quadripartite agreement on modernization of Russia’s processing industry between oil companies; the Federal Antimonopoly Service of the Russian Federation; the Federal Service for Environmental, Technological, and Nuclear Supervision (Rostechnadzor); and the Federal Agency for Technical Regulating and Metrology (Rosstandart) to reequip and upgrade processing capacities at Russian Federation refineries. Requiring a total investment to date of 307 billion rubles from Tatneft and 24.7 billion rubles from Taneco as of yearend 2017, the modernization program—which is scheduled to be fully completed in 2023—also will include commissioning of kerosine and diesel hydrotreating units this year, and startup of a crude unit, GDU-VDU-6 (also known as ELOU-AVT 6).

Designed to boost nameplate crude oil processing capacity at Nizhnekamsk to more than 280,000 b/d by 2020, GDU-VDU-6 also will enable the refinery to process half of all regional oil production into finished products for the Russian market.

Tatneft previously commissioned a 40,000-b/d delayed coking unit at the refinery, which allowed the manufacturing site to eliminate its yield of dark oil products, increase overall refining depth to 99.2%, and raise its yield of light oil products to 87%.

Elsewhere in the region, privately held JSC Antipinsky Refinery, the main production enterprise of JSC New Stream, Moscow, completed a project to expand capacity of the atmospheric residue deep conversion unit (ARDCU) at its 181,000-b/d refinery in the Tyumen region of Western Siberia, Russia.

Carried out by Tehinzhstroy Construction Co. LLC and completed as of July 11, the modernization and technical upgrade of the ARDCU complex—which includes the refinery’s VDU and delayed coker—increased feedstock processing capacity of the VDU to 540 tonnes/hr from 375 tonnes/hr, boosting the unit’s overall capacity to 90,400 b/d from 60,200 b/d. The project also expanded processing capacity of the delayed coker to 34,100 b/d from its previous 26,100-b/d capacity.

Alongside installation of higher-capacity piping and more powerful pumps and a gas compressor, the upgrading project included replacement of more than 55 tonnes of contact devices inside the vacuum column. Preventative maintenance activities executed during the project included a complete purging of the ARDCU’s pipeline system.

Modernization of the ARDCU follows startup of the refinery’s combined high-octane gasoline production unit—including a continuous catalyst regeneration unit and isomerization unit—that is equipped to produce 600,000 tpy of Euro 5-quality AI-92 and AI-95 gasoline during this year’s second quarter.

First commissioned in 2006, the Antipinsky refinery began producing Euro 5-quality diesel in October 2015 with startup of a 60,200-b/d diesel hydrotreating complex—which includes a hydrotreating unit, hydrogen production unit, gas treating unit, and sulfur recovery unit—followed by commissioning of a second diesel hydrotreating unit in 2016 to boost overall diesel hydrotreating capacity at the site to 80,300 b/d. Founded in July 2004, the refinery—which became Russia’s first independently owned and operated in 35 years—features three crude units and remains the only refinery in the Tyumen region and the Ural Federal District.

North America

In late August, North West Redwater Partnership (NWRP)—a joint venture of NWR (formerly North West Upgrading Inc.) and Canadian Natural Upgrading Ltd., a wholly owned subsidiary of Canadian Natural Resources Ltd.—was completing commissioning activities at the first 80,000-b/d phase of its proposed three-phased greenfield bitumen refinery in Sturgeon County, about 45 km northeast of Edmonton, Alta. With final inspections and tests under way on the remaining two units—including an LC-Finer (or residue hydrocracker) and gasifier—the units were well on their way to startup, which will complete commissioning of all 10 of operator North West Refining Inc.’s refinery’s units in preparation for switchover to bitumen feedstock from Alberta’s oil sands, NWRP said. As of Aug. 31, the refinery had reached a total low-sulfur diesel production of 6 million bbl from the plant’s current feedstock of partially upgraded synthetic crude.

While construction on the refinery itself is completed, NWRP confirmed testing of the refinery’s flare systems and some road construction work would be ongoing until November. The operator, however, did not disclose a definitive timeframe for when bitumen feed to the completed units would begin.

Upon commissioning of all three 80,000-b/d phases, the Sturgeon refinery—which began producing diesel and other products in November 2017—will process 240,000 b/d of Canadian bitumen feedstock to produce ultralow-sulfur diesel, diluent, and other bitumen products for both Canadian and global markets.

Elsewhere, Shell Canada Ltd. completed a hydrocracker debottlenecking project to increase processing of heavy Canadian crude feedstock at its 100,000-b/d refinery in Scotford, Alta. Approved in 2015 and designed to expand production capacity of the Scotford refinery’s 62,000-b/d hydrocracker by 20%, or 14,000 b/d, the debottlenecking project involved modifying existing equipment and replacing unit vessels, compressors, and feed pumps to enable the hydrocracker to process larger volumes of heavy crude produced in Fort McMurray, Alta. Debottlenecking of the hydrocracker was to increase its production of jet fuel by 650,000 l./day and diesel by 3 million l./day.

In Mexico, Mexico’s Petroleos Mexicanos (Pemex), through its processing subsidiary Pemex Transformacion Industrial (formerly Pemex Refinacion), let a contract to a partnership of Saipem SPA and Mexican subsidiary Saimexicana SA de CV for works to be carried out on the heavy oil (H-Oil) plant at Pemex’s 215,100-b/d Miguel Hidalgo refinery in Tula, Hidalgo state. As part of the $39.23-million contract, Saipem will perform rehabilitation and commissioning works at the H-Oil plant, which currently processes amounts of pure diesel and produces hydrodesulfurized diesel with low sulfur content that are sent in bulk to the catalytic plants, and obtaining other products, like diesel, sour gas, dry gas, and acid. The proposed rehabilitation project will upgrade the H-Oil plant to increase production of ultralow-sulfur gasoline in compliance with environmental regulations and expand handling of crude oil for production of other fuels, such as diesel and jet fuel. Upon launch of the tender seeking bids for the project in March, Carlos Trevino Medina, Pemex’s chief executive officer, said he expected the rehabilitated H-Oil plant to be completed by yearend.

The H-Oil rehabilitation project comes amid the ongoing reconfiguration of the Tula refinery Pemex began in 2014. First announced in 2013, the two-phased Tula refinery reconfiguration project is intended to generally modernize crude oil processing, increase efficiency with which vacuum residue is converted into high-value fuels, expand production of higher-value products, increase refining margins, and reduce fuel-oil handling problems at the site. While Phase 1 of the project was about 27% completed by yearend 2016, certain works were delayed and rescheduled—including construction of an 86,000-b/d delayed coking plant and associated installations necessary for its operation—due to budgetary constraints.

With Phase 1 of Tula’s reconfiguration now scheduled to be completed by 2020, Phase 2 of the project—which covers construction of additional processing installations and modernization and integration of existing units—is slated for completion in 2022. Once completed, Pemex said it expects modernization of the Tula refinery will enable the site to increase production of refined products to 220,000 b/d from 154,000 b/d, increasing the refinery’s overall performance by more than 40%.

In the US, Marathon Petroleum Corp. confirmed in early October that it had closed on its acquisition of Andeavor to create the largest US refiner by capacity and one of the top five largest refiners globally. Along with Marathon’s six existing refineries in the US Gulf Coast and Midwest, the combined company will operate 16 US refineries with an overall throughput capacity of more than 3 million b/d.

Marathon also reached substantial engineering completion for the Tier 3 gasoline sulfur standard reconfiguration project at its 571,000-b/d Galveston Bay refinery in Texas City, Tex., that will enable the refinery to achieve updated US Environmental Protection Agency Tier 3 gasoline sulfur standards by 2020 and provide cleaner fuel to US markets. Alongside addition of a selective hydrogenation unit, a naphtha desulfurization unit, and upgrades to the existing naphtha desulfurization unit and the fluid catalytic cracker, the Tier 3 project—scheduled for completion in 2019—also includes modernization of the utilities and offsites to continue the integration of the former Texas City refinery into the adjacent Galveston Bay refinery.

Fluor Corp.—which is delivering EPCM on the Tier 3 project—separately said it is currently delivering engineering and procurement services for Marathon’s South Texas Asset Repositioning (STAR) program at the Galveston Bay refinery, which aims to further integrate Marathon’s former Texas City refinery into the adjacent Galveston Bay refinery—now the second largest refinery in the US—to improve the facility’s efficiency and reliability by increasing the residual oil processing capabilities, upgrading the crude unit, and integrating facility logistics. Once completed, the STAR program will in result in a fully integrated Galveston Bay-Texas City refining complex (the Galveston Bay refinery) equipped with the following capacities: crude distillation, 585,000 b/d; resid processing, 142,100 b/d; catalytic cracking-hydrocracking, 258,400 b/d; alkyation, 52,800 b/d; and aromatics, 33,800 b/d. Previously scheduled for startup in 2021, the STAR program is now slated for full commissioning in 2022.

Early in the year, Delek US Holdings Inc., Brentwood, Tenn., said it is building an alkylation unit to add product flexibility and increase margin potential at its 74,000-b/sd refinery in Krotz Springs, La. Already under construction, the 6,000-b/sd alkylation unit will convert isobutane into alkylate to enable production of multiple summer grades of gasoline and boost octane levels. Addition of the unit will increase gasoline production at the refinery to 44,000 b/sd from 38,400 b/sd while simultaneously reducing output of lower-value products to 8,700 b/sd from 11,100 b/sd. The alkylation project, which will cost an estimated $103 million, is scheduled to be completed in first-quarter 2019.

Alongside the alkylation unit, Delek said it also is exploring other improvement initiatives for Krotz Springs, including a transportation project aimed at reducing costs for crude deliveries into the refinery and a crude flexibility project to increase the site’s ability to access lower-cost crude grades. While the operator disclosed no further details about the crude transportation initiative, regarding expanding crude flexibility, Delek said it is working with its logistics subsidiary to enable Krotz Springs to adjust its crude processing slate between Light Louisiana Sweet and West Texas Intermediate Midland crude grades based on market conditions and refinery runs.

In September, Meridian Energy Group Inc. let a contract to GATE Energy, Houston, to deliver commissioning and start-up services for Meridian’s recently approved grassroots 49,500-b/sd high-conversion Davis refinery to be built in Billings County in the heart of southwestern North Dakota’s Bakken shale region. As part of the letter of intent signed between the two companies, GATE will provide personnel for development planning and execution of the project, and its GATE Completion System, which will ensure the safe and efficient execution of the Davis refinery, on which civil construction recently began. With official construction activities slated to begin in 2019, the Davis refinery is scheduled to be fully operational in 2020.

The September contract follows Meridian’s earlier award to SEH Design Build Inc.—a subsidiary of Short Elliott Hendrickson Inc., Bismarck, ND—to deliver site, civil design, and construction services for the project in July, and the North Dakota Department of Health’s division of air quality June issuance to Meridian of the final permit-to-construct the project based on the first application in history for a full-conversion refinery of this size and complexity to seek and receive permitting to construct under classification as a synthetic minor source of air contaminants.

In March, Valero Energy Corp. let a contract to McDermott to provide technology and equipment for an alkylation project at subsidiary Valero Refining New Orleans LLC’s 340,000-b/d St. Charles refinery in Norco, La. McDermott will deliver technology licensing for its proprietary CDAlky technology, and basic engineering and proprietary equipment for the CDAlky unit. Scheduled for startup in 2020, the CDAlky unit will be equipped to produce 25,000 b/d of alkylate from FCC-derived olefin feedstocks.

South America, Caribbean

In April, Royal Dutch Shell PLC signed an agreement to sell its downstream business in Argentina—including the 100,000-b/d Buenos Aires refinery—to Raizen Group, Sao Paulo, for $950 million in cash proceeds. Alongside the refinery and about 645 retail outlets, the sale will include Shell’s LPG, marine fuels, aviation fuels, bitumen, chemicals, and lubricants businesses, as well its supply and distribution activities in the country. Shell said the agreement is consistent with its strategy to simplify its portfolio through a broader $30-billion divestment program and follows a strategic review of Shell’s Argentinian downstream business that began in August 2016. Following close of the transaction by yearend, the businesses acquired by Raizen will continue their existing relationships with Shell through various commercial agreements, which represent an estimated value of $300 million. Raizen—a 50-50 joint venture formed in 2011 between Shell and Cosan, also of Sao Paulo—is a leading biofuels producer and fuels distributor in Brazil, where it currently manages more than 6,000 Shell service stations.

In October, Petroleo Brasileiro SA (Petrobras) and China National Petroleum Corp. (CNPC) subsidiary China National Oil & Gas Exploration & Development Co. signed an integrated project business model agreement to advance a previously announced plan with CNPC subsidiary China National Petroleum Corp. International for formation of a strategic partnership to complete the 150,000-b/d Comperj refining complex in Itaborai, Rio de Janeiro state. The business model agreement details steps of a feasibility study to evaluate the Comperj refinery’s current technical status, its investment case, and the remaining scope to conclude the refinery and business valuation. A joint team of CNPC and Petrobras specialists, and yet-to-be-identified external consultants, will conduct the studies. Once the full benefits and costs of this project are quantified, the next step would involve creation of a joint venture of Petrobras 80% and CNPC 20% to complete and operate the refinery.

As announced in July, the scope of the partnership, to be designed as an integrated project, also would cover CNPC’s participation in Marlim oil field cluster in the Campos basin off Brazil, which includes Marlim, Voador, Marlim Sul, and Marlim Leste fields. Under the current agreement, Petrobras will retain 80% in and remain operator of all these fields, the production from which perfectly fits the design crude slate to be processed by the high-conversion, heavy oil Comperj refinery.

Alongside forming part of Petrobras’s broader program to revitalize its eastern Brazilian refining and logistics park, the planned partnership—implementation of which depends on successful negotiations of the final agreements and successful results of the Comperj feasibility study with the respective investment decision by the parties—also comes as part of the companies’ intention to strengthen their ties and contribute to deepen the global strategic partnership between Brazil and China.

The October agreement with CNPC follows Petrobras’s earlier announced plans for a process to divest its majority equity interest in refining and logistics operations in the northeastern and southern regions of Brazil. In April Petrobras started the disclosure stage of two divestment opportunities under a model that provides for creation of two subsidiaries—one for each of the geographical regions—upon creation of which the company intends to sell 60% of its equity interest in each. The proposed Northeastern subsidiary would consist of two refineries, including the 333,000-b/d Landulpho Alves refinery in Bahia state and the 130,000-b/d (to be expanded to 260,000-b/d) Abreu e Lima refinery in Pernambuco state, and the following associated logistics assets (pipelines and terminals) operated by Petrobras Transporte SA (Transpetro):

• Two marine terminals (Madre de Deus, Suape).

• Three inland terminals (Candeias, Itabuna, and Jequie).

• Two oil supply pipelines.

• One polyduct and 35 refined products pipelines connecting refineries to distribution terminals and distribution bases (OGJ Online, July 25, 2016).

The proposed Southern company also would include two refineries, including the 207,000-b/d Alberto Pasqualini refinery in Rio Grande do Sul state and the 207,000-b/d Presidente Getúlio Vargas (REPAR) refinery in Parana state, and the following Transpetro-operated associated logistics assets:

• Four marine terminals (Paranagua, Sao Francisco do Sul, Tramandai, and Niteroi).

• Three inland terminals (Guaramirim, Itajai, and Biguacu).

• Two oil supply pipelines.

• Two polyducts and four refined oil pipelines connecting refineries to distribution terminals and distribution bases.

The proposed partnerships—the process for which remains temporarily suspended following a July injunction issued by Brazil’s Federal Supreme Court—come as part of Petrobras’s strategic repositioning in refining, transportation, and logistics segments, and are in line with the operator’s strategic plan and its business and management plan, which provides for establishment of partnerships and divestments as one of the main initiatives for risk mitigation, value addition, knowledge sharing, strengthening of corporate governance, and improving the company’s financiability.

Earlier in the year, Petrobras also confirmed it was moving forward with a proposal to sell subsidiary Pasadena Refining Systems Inc.’s 110,000-b/d refinery in Pasadena, Tex.—including 5.1 million bbl of oil and products storage capacity, an associated marine terminal and logistics system, existing inventory, and land on the Houston Ship Channel usable for potential future expansion—in compliance with the Brazilian operator’s divestments portfolio and a divestment plan from Brazil’s Federal Court of Accounts, or Tribunal de Contas da Uniao. That proposed sale also remains on hold.

In April, state-owned Empresa Nacional del Petroleo (Enap) let a contract to KBR Inc. to provide licensing and engineering services for an upgrading project at subsidiary Enap Refinerias SA’s 116,000-b/d Bio Bio refinery at Hualpen, in Chile’s Bio Bio region. KBR will deliver technology licensing and basic engineering design for a 30,000-b/sd plant equipped with KBR’s proprietary ROSE solvent deasphalting technology. The ROSE unit will split residue from a mix of crude oils into deasphalted oil and asphaltene, allowing the refinery to upgrade a larger proportion of its oil intake into high-grade products.

While it will not change total processing capacity of the refinery, the unit—for which a timeframe for startup has yet to be disclosed—will enable a different product mix and increase the refinery’s flexibility to respond to market developments while reducing the environmental footprint of its products.

The contract award follows Enap’s recent announcement that it will invest an estimated $245 million on environmentally friendly projects at the Bio Bio refinery to strengthen competitiveness, reliability, and sustainability of the manufacturing site. Aimed at incorporating treatment and environmental-control systems, the considered projects will include the following:

• Construction of an acid-water treatment plant (SWS 4) with an estimated treatment capacity of 1,600 cu m/day that will increase the refinery’s estimated total treatment capacity up to 3,700 cu m/day.

• Construction of a sulfur recovery unit (SRU 3) with a nominal production capacity of 140 tonnes/day of sulfuric acid to enable optimization of the sulfur recovery process by reducing the refinery’s emissions of sulfur dioxide and increasing reliability and operational flexibility of the site’s overall sulfur recovery system.

• Updating of the refinery’s steam-supply system by incorporating a boiler to replace an existing one currently in place.

• Construction of three crude tanks of 50,000 cu m each and a slop pond (hydrocarbons for reprocessing) of 5,000 cu m to increase overall crude storage capacity.

• Construction of a loading yard with modernized installations that will include five storage tanks, a pump yard, four multipurpose cargo islands (Class I and II fuels), and a specific island for Class IIIA fuels to trucks.

While it did not confirm an official timeframe for when it would begin work on the proposed upgrades, Enap estimates a project construction phase of 26 months once under way. These latest proposed projects at Bio Bio come as part of Enap’s program to fulfill several short and long-term commitments to Chilean legal and regulatory authorities under which Enap pledges to invest in projects and initiatives intended to reduce impacts of the refinery’s operations on the surrounding environment.

In November, Limetree Bay Refining LLC (LBR), a subsidiary of ArcLight Capital Partners LLC, announced it had reached an agreement in principle with BP PLC’s supply and trading arm to restart the idled 500,000-b/d refinery at Limetree Bay on St. Croix, USVI. Under the contemplated terms, BP would enter into a tolling agreement and serve as the refinery’s supply and offtake counterparty, LBR said.

Announcement of the preliminary agreement with BP for the refinery’s restart follows the 32nd Legislature of the USVI’s July approval of a $1.4-billion operating agreement with ArcLight, whose subsidiary Limetree Bay Terminals LLC (LBT) has restarted since 2016 more than 25 million bbl of storage capacity and terminal assets connected to the former Hovensa LLC-owned refinery at Limetree Bay, which has a peak processing capacity of 650,00 b/d. The refinery restart project, which will be completed by a team led by LBR Pres. Brian Lever, is slated to bring at least $1.5 billion of outside investment into the USVI over the next 14 months, according to USVI Gov. Kenneth Mapp.

Upon announcing the operating agreement in July, the USVI government said the project will lead to more than 1,300 local jobs during construction and as many as 700 permanent jobs on restarting the complex, operations of which are scheduled for commissioning by yearend 2019 with an initial crude processing capacity of about 200,000 b/d. As part of the operating agreement, LBR would pay the government $70 million, and upon restart of the refinery, payments in lieu of taxes of $22.5 million/year, with an adjustment based on the refinery’s performance that could raise the payment to as much as $70 million/year but never below $14 million/year in normal circumstances.

If the refinery performs as the government’s industry experts previously projected, the government would receive more than $600 million during the first 10 years after restart vs. the $330 million Hovensa—a joint venture of Hess Corp. and Petroleos de Venezuela SA—paid the government in corporate income taxes in the more than 30 years it operated the refinery. The $600 million in payments would be in addition to the income generated by LBT’s oil storage terminal, which will continue to make payments currently amounting to $11 million/year as promised under the original terminal operating agreement (OGJ Online, Jan. 8, 2016).

Alongside minor amendments to the existing terminal operating agreement, the deal establishes a refinery operating agreement, under which LBT will transfer its ownership of the refinery to LBR, which in turn will enter into a separate operating agreement with the government and assume independent financial and other obligations, according to government documents. Regarding employment for USVI residents—more than 2,000 of whom became jobless following Hovena’s 2012 refinery closure and a recurrent hurdle facing the original 2016 terminal operating agreement—the refinery operating agreement requires LBR to aggressively advertise open positions, to give preference to qualified local residents over nonresidents, and to use commercially reasonable efforts to ensure that at least 80% of workers are USVI residents.

Elsewhere in the Caribbean, Jamaica is progressing with the long-planned and earlier delayed expansion and modernization of the Jamaican-Venezuelan joint venture Petrojam Ltd.’s 36,000-b/d hydroskimming refinery in Kingston. A technical team comprised of members from the Petroleum Corp. of Jamaica (PCJ) and Petrojam have met with previously engaged but as-yet-to-be identified EPC contractors for expansion of the state-owned refinery, according to Andrew Wheatley, Jamaica’s minister of science, energy, and technology.

Providing an update on the status of the expansion to Jamaican legislators in late May, Wheatley said staff members were working feverishly to advance the first phase of the modernization, which involves installation of a VDU as part of the refinery’s plan to produce low-sulfur fuel for the bunkering industry that complies with pending sulfur specifications designed to reduce environmental pollution from the International Maritime Organization (IMO) to take effect in January 2020. The project aligns with Jamaica’s intention to be able to supply IMO-compliant fuels to cruise and cargo ships that use the island as a transshipment point.

“The money is in place, and the government has made an allocation for this year for us to proceed with the VDU project,” Wheatly said.

Wheatly previously confirmed $100 million is now earmarked for Phase 1 of the refinery upgrade by PCJ, which holds 51% interest in the refinery alongside Venezuela’s state-run Petroleos de Venezuela SA (PDVSA) 49%. In April, Wheatley said Jamaica also was in the process of trying to reacquire PDVSA subsidiary PDV Caribe SA’s interest in Petrojam as the parties evaluate potential tax implications related to the reacquisition. Timeframes for the proposed reacquisition and start of construction on the refinery’s upgrade have yet to be detailed.

In February, the government of the Bahamas approved a multibillion-dollar plan by Oban Energies LLC, Palm Beach Gardens, Fla., to build a grassroots refinery and liquid-bulk storage terminal along the Northwest Providence Channel, off the southern tip of Grand Bahama Island, 35 miles east of Freeport. While Prime Minister Hubert Minnis’s government and Oban Energies signed a heads of agreement on Feb. 19 for the two-phased project—which alongside a 20 million-bbl liquid-bulk storage terminal would include a 250,000-b/d refinery—complaints by environmental groups regarding signing of the HOA without an environmental impact assessment in place has resulted in a reconsideration and likely renegotiation of the original project agreement, Bahamian local media reported in mid-November. A timeframe for any proposed renegotiation, however, has yet to be revealed.

According to original plans, the project’s first phase was to involve construction of 4 million bbl of fuel storage and a 50,000-b/d refinery, both of which were to be expandable to 20 million bbl and 250,000 b/d, respectively, by their fourth year of operation, according to the government and Oban Energies. First-phase development also was to include construction of a harbor and deepsea loading docks equipped to service very large crude carriers. The project’s Phase 2 was to focus on expanding capacity of the refinery that—once completed—would be able to process less-expensive, heavy sour crudes and have the flexibility to process other opportunity crudes as dictated by market economics. With total estimated costs of $1.5 billion for the terminal and $4 billion for the refinery, overall project investment would amount to about $5.5 billion, according to Minnis.

Oban Energies previously let a contract to TECS Netherlands BV to provide all FEED work for the terminal portion of the project. TECS’ scope of work under the FEED contract covers the entire terminal engineering scope, including the VLCC jetty, piping to the inland-support vessel harbor, storage tanks, terminal layout, and all auxiliary installations such as water, wastewater, vapor-treatment, and power-generation facilities, the service provider said in a December 2017 release.