Global refiners move to maximize efficiency, capacities of existing operations

Compania Espanola de Petroleos SA (CEPSA) has implemented gas turbine technology at its 12-million tonne/year Gibraltar-San Roque refinery near Cadiz in southern Spain to help the plant meet Europe's more stringent environmental emissions standards and improve efficiency by enabling the facility to use recycled refinery fuel gas without needing additional water to generate power, which reduced the refinery's purchases of gas and its nitrogen oxide emissions. Photo from CEPSA.

Technip also is working to ensure financing for the project with Italian export credit agency SACE, which may consider an intervention to support the revamp plan, the service provider said.

Last year, ASORC secured $198 million in financing from Saudi-based Islamic Development Bank (IDB) for the proposed project, which is to include a 1.4 million-tonne/year (tpy) diesel hydrocracking complex to convert lower-quality heavy fuels into high-quality petroleum products such as LPG, naphtha, kerosine, and gasoline.

The project, which will require a total investment of $2.8-2.9 billion, is designed to help meet Egypt's rising demand for petroleum products, EGPC and MOP said in 2013.

The diesel hydrotreating complex would increase the refinery's diesel production capacity to about 1 million tpy, LPG production to 76,000 tpy, gasoline production to 442,000 tpy, and jet fuel production to 628,000 tpy, MOP said.

A revised timeline for the project was not disclosed, but the diesel hydrotreating complex previously was scheduled to be operational between 2016 and 2017.

At the Midor refinery, in Alexandria's El Amreya Free Zone, Technip Italy will work on a $1.4-billion modernization project that, in addition to improving the quality of production yields at the plant, would expand the refinery's nameplate crude processing capacity to 160,000 b/d from its current 100,000 b/d.

As part of its agreement with Midor, Technip said, in due course, that it will provide EPC services for the expansion project, as well as immediately begin unidentified activities related to the revamp.

Included in Technip's agreement with the Egyptian state-owned refiner is a commitment by SACE to launch an evaluation process that would ensure an export credit facility to support the expansion project, Technip said.

Once completed, the project would enable the refinery to produce 1.6 million tpy of diesel, 488,000 tpy of gasoline, 71,000 tpy of LPG, and 672,000 tpy of jet fuel, MOP said.

Midor earier this year let two contracts worth a total of $1.4 billion to UOP LLC, a unit of a Honeywell International, to provide engineering designs and licensing for new units to be included as part of the expansion.

At the time, MOP said the expansion would equip the Midor refinery to produce 245,000 tpy of LPG, 1.3 million tpy of high-octane gasoline, and 2.3 million tpy of diesel meeting European quality specifications. The Egyptian government, however, has yet to disclose either a construction timeline or possible commissioning date for the proposed Midor modernization.

Elsewhere in Africa, Dangote Oil Refining Co. (DORC), a division of Nigerian conglomerate Dangote Industries Ltd. (DIL), let a contract in May to Honeywell's UOP LLC, Des Plaines, Ill., for its grassroots integrated refinery and petrochemical plant to be built in southwestern Nigeria's Lekki Free Trade Zone, near the capital of Lagos.

UOP will provide process technology, catalysts, and equipment for the complex, which when completed, will be Africa's largest, helping to reduce Nigeria's dependence on imports.

The proposed complex will produce gasoline, diesel, and jet fuel that meet Euro 5 quality specifications, as well as propylene.

In 2013-14, DIL signed loan agreements amounting to nearly $4 billion with a consortium of international banks for the refining complex, part of which also were to be used for the construction of a greenfield fertilizer manufacturing plant.

The company previously let a contract Engineers India Ltd. (EIL) for project management consultancy and EPC management for the integrated refining complex, which at the time, was to include a 400,000-b/d refinery and 600,000-tpy polypropylene plant.

In September 2014, Nigeria's Department of Petroleum Resources (DPR) issued related licenses to DIL for the establishment of a 500,000-b/d refinery as part of the project, according to DPR data.

DIL, however, has since revised both the cost and capacities of the overall project, according to a series of social media posts from the state government of Lagos on Apr. 30.

Currently the proposed integrated refining complex is to have a processing capacity of 650,000 b/d, while the associated petrochemical plant will have a production capacity of 3.6 million tpy.

Scheduled for completion by yearend 2016, the refinery, petrochemical plant, and fertilizer plant will cost an estimated $11 billion, the Lagos state government said.

The refinery project will include a CDU, a single-train residual fluid catalytic cracking unit, a diesel hydrotreating unit, a continuous catalyst regeneration unit, an alkylation unit, and a polypropylene unit, as well as utilities and off sites, including a captive power plant and associated infrastructure involving an integrated, single-point mooring terminal for crude oil and product handling, EIL said.

While Nigeria holds the second-largest amount of proved oil reserves in Africa-more than 37 billion bbl-the country currently imports most of its refined product requirements due to lack of domestic refining capacity.

The planned refinery comes amid a host of ongoing failed attempts by Nigeria's government to revamp its existing four refineries, according to recent local media reports.

Elsewhere, Uganda earlier this year announced it selected a consortium led by Russia's RT Global Resources, Moscow, as its first choice to construct the country's first refinery.

The proposed 60,000-b/d refinery, to be built in the Lake Albert region of Buseruka Subcounty in Uganda's Hoima District, will be developed in two 30,000-b/d phases and include on-site crude oil and product storage, as well as a 205-km product pipeline to a distribution terminal near Kampala.

Uganda will hold 40% equity in the project, while the winning bidder, as lead investor and operator, will hold the remaining interest.

The refinery will be designed to process Uganda's waxy crude oil (23-33° API, 0.16 wt% sulfur) produced from the Albertine basin to serve petroleum product markets in Uganda, Congo (former Zaire), South Sudan, Rwanda, Burundi, Kenya, and Tanzania.

The refinery's first phase remains on schedule to be commissioned in 2018, with the plant due to reach its full 60,000-b/d capacity by 2020, according to MEMD and RT Global Resources.

Meanwhile, Angola's Sonangol Group late in 2014 announced it had secured a $2-billion line of credit from China Development Bank (CDB) to support expansion projects in the country's oil and gas sector, which would in part fund construction of Sonangol's planned 200,000 b/d Sonaref refinery in Lobito.

First announced in 2009, the Sonaref refinery is a strategic project intended to reduce Angola's reliance on imported fuels by processing Angolan crude for the production of unleaded gasoline, diesel, jet fuel, kerosene, LPG, and small amounts of sulfur.

While initial construction activities on the Lobito plant began in December 2012, construction of the refinery began in earnest in 2015, Sonangol said.

The Sonaref refinery is to be built in two phases.

A first 120,000-b/d phase of 9 low-conversion units designed to process Angolan Girassol crude (30.1° gravity; 0.33 wt % sulfur) initially was scheduled to become operational in 2015, with the second 80,000-b/d phase of 11 remaining high-conversion units aimed at processing heavier and more acidic Angolan crudes to be installed a year later. The company, however, has not released an updated construction timeline for the project.

Asia-Pacific

Chevron New Zealand in May said it would sell its interest in New Zealand Refining Co. Ltd. (NZRC), which operates the 107,000-b/d Marsden Point refinery at Northland on the North Island's east coast. The company finalized a deal with Deutsche Craigs Ltd., under which the investment advisory and management firm procured the sale of Chevron's entire 35.5 million shares, or 11.37% ownership interest, in the refinery to institutional investors.

Construction associated with the $365-million (NZ) Te Mahi Hou (TMH) expansion project at Marsden Point-New Zealand's only refinery-continues to progress as planned, NZRC said.

The TMH project, approved in February 2012 and initially named the Continuous Catalyst Regeneration (CCR) Platformer project, is designed to increase high-quality fuel production by replacing the refinery's semiregeneration platformer and enabling it to process increased volumes of a wider range of crudes more effectively and efficiently.

Indian Oil Corp. Ltd. (IOC) continued to commission units this year at its long-delayed 15 million-tpy, full-conversion refinery at Paradip, on India's northeastern coast.

Designed to process 5.2 million tpy of blended gas oil to produce ultralow-sulfur diesel that with a maximum sulfur content of 10 ppm, the refinery's diesel hydrotreater began operations in October. The diesel hydrotreater uses Shell Global Solutions' (SGS) deep hydrodesulfurization technology.

IOC previously initiated crude processing at Paradip's atmospheric and vacuum distillation unit in late April, with the unit now producing LPG, naphtha, kerosene, gas oil, reduced crude oil, and other products. While secondary units were gearing up for startup at the time, IOC Director Sanjiv Singh said full commissioning of the integrated refining complex likely would take 6-8 months.

The $5-billion grassroots refinery, which began some startup activities in early 2014, initially was scheduled to become fully operational in November 2013, with additional commissioning of units subsequently rescheduled for December 2014.

In August, state-owned Indian Oil Corp. Ltd. (IOC) informed India's government that it will increase crude oil processing capacity at the company's 6 million-tpy Barauni refinery in Begusarai District, Bihar.

IOC will execute the expansion project in two phases, which when completed, will lift processing capacity at Barauni by a total of 3 million tpy to 9 million tpy overall, India's Minister of Petroleum and Natural Gas (MPNG) Shri Dharmendra Pradhan said.

Phase 1 of the project will boost capacity by 1 million tpy to 7 million tpy, with the remaining capacity increase of 2 million tpy to be added during Phase 2.

The proposed 3 million-tpy expansion at Barauni follows a previous request by the government of Bihar for IOC both to expand processing capacity at the refinery to 15 million tpy and set up a petrochemical complex at the site, according to a series of notifications between MPNG and the government of Bihar.

Following a review of the larger expansion proposal, however, IOC determined that increasing the refinery's capacity to 15 million tpy as of October 2014 was not "techno-economically" feasible, MPNG said in an Oct. 7, 2014, notice to the government of Bihar.

MPNG earlier informed Lok Sabha, the lower house of India's Parliament, that IOC's 2008 proposal to set up a 1.1 million-tpy steam cracker and associated petrochemical complex at Barauni was unviable financially due to the inland refinery's lack of readily available naphtha supplies, according to a 2010 government report.

While IOC did not respond to OGJ's request for comments regarding a timeline or budget for the new expansion plans at Barauni, the company currently is assessing capacity augmentation of three crude distillation units at the refinery, MPNG said. A detailed configuration study and techno-economic evaluation for Phase 1 of the expansion are under way, with the project scheduled for execution in 2016-17. A timeline for Phase 2 of the expansion project was not disclosed.

Elsewhere, Binh Son Refining & Petrochemical Co. Ltd. (BSR), a subsidiary of state-owned Vietnam National Oil & Gas Group (PetroVietnam), let a contract to Amec Foster Wheeler for front-end engineering and design (FEED) for the upgrade and expansion of its Dung Quat refinery in Quang Ngai Province, Vietnam.

The expansion will increase the plant's crude processing capacity by 30% to 8.5 million tpy from a current 6.5 million tpy.

Construction on the $1.82-billion expansion and upgrade project, which received federal and provincial government investment approvals in December 2014, is scheduled to run from fourth-quarter 2017 to third-quarter 2021, BSR and PetroVietnam said.

The fully upgraded and expanded refinery is scheduled to be commissioned in 2022.

In Japan, Royal Dutch Shell PLC entered a deal to sell nearly all of its interest in Japanese refiner Showa Shell Sekiyu KK to Idemitsu Kosan Co. Ltd. as part of the company's ongoing strategy to reduce its downstream refining assets. As part of the agreement, Idemitsu Kosan will buy Shell's 33.24% majority interest in Showa Shell Sekiyu for about $1.4 billion.

The divestment, scheduled to close in 2016, includes majority ownership in Showa Shell Sekiyu's three Japanese refineries, aligns with Shell's strategy to concentrate its downstream footprint on a smaller number of assets and markets where it can be most competitive.

Shell's sale of Japanese refining assets follows Shell Australia's announcement last year of the sale of its 118,000-b/d Geelong refinery in Victoria and its network of 870 retail outlets across the country to Dutch group Vitol.

In June, Japan's Taiyo Oil Co. Ltd. implemented process technology from Honeywell's UOP LLC to increase flexibility and production at its 118,000-b/d Shikoku refinery at Kikuma, now part of Imabari, Ehime Prefecture, Japan.

Taiyo Oil is using UOP's proprietary Tatoray process technology at Shikoku that will enable the refinery to produce 300,000 tpy of petrochemicals to be used as feedstock for production of polyester. The Tatoray process will increase production of benzene and xylenes, as well as provide the operator greater flexibility to switch between production of gasoline or petrochemicals based on market demand, the company said.

The Shikoku refinery began using the Tatoray technology process late last year with the commissioning of a 10,000-b/d transalkylation unit at the plant during November 2014.

In April, Brazil's state-owned Petroleo Brasileiro SA (Petrobras) initiated a plan to exit its Japanese refining business, which consists of wholly owned subsidiary Nansei Sekiyu KK's 100,000-b/d Nishihara refinery on Japan's southwestern island of Okinawa.

The exit plan, which is to occur over a yet-to-be disclosed period of time, will include termination of processing activities at the Nishihara refinery, Petrobras told investors.

Petrobras's decision to shed its holdings in the Japanese downstream sector follows the company's announcement last month that it would divest a total of $13.7 billion in global assets during 2015-16 as part of a financial plan aimed at reducing leverage, preserving cash, and focusing on priority investments that mainly involve oil and gas production in Brazil in areas of high productivity and return, according to a Mar. 2 release to investors.

Europe

Total SA said it will spend €600 million to revitalize its refining business in France with projects that include an overhaul of the 220,000-b/d Donges refinery near Saint Nazaire, as well as a permanent shuttering of crude processing activities at the 153,000-b/d La Mede refinery on the French Riviera.

The investment decision comes as part of the company's comprehensive plan to ensure long-term futures for the two refineries, both of which continue to suffer profit losses amid a decline in Europe's demand for petroleum products and increased competition from refiners in the US, Asia, and Middle East for customers in nearby export markets, Total said.

The central focus of Total's strategy for its French refining business is to realign operations and production to changing markets, according to Patrick Pouyanne, Total's chief executive.

"There are three possible responses to the crisis in the European refining industry. The first is to throw in the towel. The second is to do nothing and perish. The third is to innovate and adapt to meet shifting demand trends," Pouyanne said, adding that the company's latest investment plan will accomplish the latter for both Donges and La Mede.

Along with the capacity reduction program at its 200,000-b/d Lindsey refinery in the UK announced earlier this year, execution of Total's program for the two French refineries will result in a 20% reduction in its European refining and petrochemical capacity by 2017, the company said.

At a cost of €200 million, the Donges modernization program includes construction of a desulfurization unit that will use intermediate feedstock to produce low-sulfur fuels that meet Europe's more stringent fuel specifications.

The desulfurization unit will receive its hydrogen supply from a new steam methane reformer, which will be built by a contractor under a long-term hydrogen supply contract with the refinery.

In addition to the new units, the upgrading project will coincide with the rerouting of an existing rail line that extends through the production site and which currently poses an obstacle to future development of refining units at the plant.

A process design package as well as FEED for the Donges upgrade should be finalized in 2016, with contract awards for construction of the new units to follow in 2017. Given this timeline, the new units would be commissioned sometime in 2019, Total said.

While the La Mede manufacturing site will remain in operation, Total will invest €200 million to convert the refinery into a 500,000-tpy biofuels plant for the production of biodiesel from used oils and other renewable feedstocks. The company said it plans to permanently suspend crude processing activities at the refinery by yearend 2016.

Elsewhere, ExxonMobil Corp. is moving ahead with a planned expansion of its hydrocracking operations at subsidiary Esso Nederland BV's 191,000-b/d refinery in Rotterdam, Zuid-Holland, the Netherlands.

The expanded unit, which will use ExxonMobil's proprietary hydrocracking technology, is designed to increase the refinery's ability to upgrade heavier byproducts into high-quality lubricating oils, greases, and ultralow-sulfur diesel.

Following the hydrocracker's expansion, the Rotterdam refinery will be the first in Europe to produce ExxonMobil's EHC Group II base stocks, which are designed to meet evolving industry requirements, and help lubricant blenders both to achieve greater formulation flexibility and simplify global qualification testing. With the project's environmental impact assessment (EIA) already approved and permitting process under way, ExxonMobil said it expects to receive final permits in early 2016, with construction to start soon after. The company tentatively plans to commission the expanded unit in 2018, pending permit approvals.

The Rotterdam project follows a series of previously announced expansions by ExxonMobil to boost production of more profitable products at its Baytown, Tex., Antwerp, Belgium, and Jurong Island, Singapore, manufacturing sites.

Neste Corp. is proceeding with a previously announced plan to invest €60 million in the 3 million-tpy Naantali refinery in Findland as part of the company's broader program to keep its European operations competitive through consolidation of its Finnish refining assets.

The Naantali investment, which will be used to carry out various utility-related enhancements intended to simplify the refinery's structure and improve its processing efficiency, follows the company's October 2014 decision to closely integrate the plant with the 9.8 million-tpy Porvoo refinery so that the sites will operate as a single system.

Naantali will continue to produce diesel and specialty products, including solvents and bitumen, and maintain an important role in producing feedstocks, such as vacuum gas oil, for production lines in Porvoo. Gasoline components produced at Naantali will be refined into finished products at Porvoo, with Naantali's terminal capacity to be used for distributing Porvoo's gasoline production, Neste said. Integration of the Naantali-Porvoo operations also will enable increased diesel production alongside a simultaneous reduction in heavy fuel oil output.

Neste said the refining consolidation program is scheduled to be completed and the new Naantali-Porvoo operating model fully commissioned by mid-2017.

In June, Neste completed a 2-month, €100-million planned maintenance turnaround at the Porvoo refinery, which alongside standard 5-year maintenance to ensure safe and reliable operations, also involved the following projects related to the refinery's future development:

• Installation of furnaces in the crude oil distilling unit.

• Replacement of automation in several unidentified areas of the refinery.

• Preparation of connections for other unidentified, future investment projects.

Neste also plans to build a €200-million solvent deasphalt (SDA) feedstock pretreatment unit at Porvoo as part of the €500-million refining consolidation and integration program.

Designed to improve the refinery's production structure and ability to optimize its crude slate, the SDA unit is slated for completion in 2017.

In Spain, Compania Espanola de Petroleos SA (CEPSA) implemented new gas turbine technology from GE to help meet Europe's more stringent environmental emissions standards without reducing efficiency or increasing operating costs at its 12 million-tpy Gibraltar-San Roque refinery near Cadiz in southern Spain.

The project, which marks the first use of GE's proprietary fuel-flexible High Hydrogen Fuel DLN1 technology at any commercial operation, has increased efficiency of the refinery's GE 6B DLN1 gas turbine by enabling it to use recycled refinery fuel gas (RFG) without needing additional water to generate power.

Since GE completed the conversion process more than a year ago, the gas turbine's use of waste RFG for power generation has allowed CEPSA to reduce purchases of natural gas, resulting in a 7% heat rate improvement at the refinery, as well as enabled a 90% reduction in nitrogen oxide emissions from the plant.

In addition to reducing emissions and improving operational efficiency at the plant, the new technology also has contributed to a reduction in the Gibraltar-San Roque refinery's overall downtime for planned maintenance.

Elsewhere, OAO Rosneft completed a deal for the purchase of Total SA's minority interest in the 11.5 million-tpy PCK Raffinerie GMBH refinery, located along Druzhba pipeline in Schwedt, Germany, about 120 km northeast of Berlin. Rosneft, which already holds an 18.75% stake in the Schwedt refinery, first announced the deal in late 2014 after signing an agreement with Total outlining main terms and conditions for the proposed sale.

At final closing, Rosneft, together with its BP PLC-joint venture Ruhr Oel GMBH (37.5%), will own close to 55% of the German refinery.

Total's decision to shed minority interest in the Schwedt plant is in line with its 2017 target to reduce the company's European refining and petrochemical capacity by 20%, the company said.

Varo Energy BV, a midstream company owned by The Carlyle Group and Vitol Group, announced it will invest more than 50 million Swiss francs ($56 million) into maintenance and modernization projects at its 68,000 b/d Cressier refinery near Neuchatel, Switzerland.

In addition to costs associated with the refinery's scheduled turnaround, the investment also will cover other projects, including a partial conversion of the refinery's energy sourcing to natural gas as well as technical upgrades that will equip the plant to produce gasoline containing up to 5% ethanol from renewable sources.

Late last year, ExxonMobil Petroleum & Chemical BVBA let an EPC contract to Fluor Corp. for a delayed coker to be installed at its 320,000-b/d Antwerp refinery.

The start of construction on the project follows ExxonMobil's announcement earlier in the year that it would invest $1 billion in to install the delayed coker as part of the company's long-term strategy to help the Antwerp refinery better compete in Europe's challenging industry environment by directly addressing a shortfall in regional refiners' capability to convert fuel oil to products such as diesel.

Middle East

Late in the year, Abu Dhabi Oil Refinery Co. (Takreer) finally completed a long-planned expansion project designed to double crude processing capacity of the Ruwais refining complex in the United Arab Emirates, about 385 miles west of Abu Dhabi City.

The Ruwais crude capacity expansion has been fully commissioned, with the refining complex now operating at 100% rates at its newly expanded capacity of more than 800,000-b/d, the company said.

In addition to a new 417,000-b/d crude distillation unit (CDU), other recently commissioned units now operating at full production include associated hydrotreating units, while a new 127,000-b/d residue catalytic cracking (RFCC) unit continues to ramp up to full operating rates from its current production capacity of about 75%.

Alongside the CDU and RFCC, the expanded Ruwais refinery, which initially was due to be completed in 2013 before a delay to first-half 2014, also was to include the following units: a 69,000-b/d heavy naphtha hydrotreater; a 108,000-b/d kerosine hydrotreater; a 75,000-b/d light diesel hydrotreater; a 57,000-b/d heavy diesel/LCO mild hydrocracker; a 37,000-b/d Alkylation unit; and a 27,000-b/d benzene reduction unit.

Takreer previously said it planned to invest about $10 billion in the Ruwais expansion.

In addition to multiple contracts for the construction of the country's long-planned grassroots refinery under construction in southern Karbala province, Iraq let a project management consultancy (PMC) contract in April to Technip and Japanese engineering consultant UNICO International Corp., Tokyo, for the modernization and upgrading of its 140,000-b/d Basra refinery in southern Iraq.

Designed to increase the Basra refinery's gasoline production capacity, the modernization project will involve installation of a fluid catalytic cracking unit and associated units, including a visbreaker, hydrotreater, and hydrogen plant among others.

Alongside its modernization plans for the Basra refinery, Iraq has a longer-term plan to construct four refineries in an effort to add 750,000 b/d of refining capacity. These projects include the 140,000-b/d Karbala refinery, the 300,000-b/d Nassiriya refinery, and two additional refineries in Maysan and Kirkuk, each with a capacity of 150,000 b/d.

Earlier in the year, Yanbu Aramco Sinopec Refining Co. Ltd. (Yasref), a joint venture of Saudi Aramco (62.5%) and China Petrochemical Corp. (Sinopec) (37.5%), began operations at its 400,000-b/d refinery in Yanbu Industrial City on the west coast of Saudi Arabia along the Red Sea.

Initially scheduled for start-up in September 2014 and first commercial shipment of refined products in fourth-quarter 2014, the Yasref refinery reached its full capacity during second-quarter 2015.

The Americas

Across the Atlantic, HollyFrontier Corp., Dallas, announced it a new capital investment program of $325 million during 2015-18 for opportunity projects designed to expand and modernize operations at its five US refining centers.

In addition to the recently completed naphtha fractionation and hydrogen generation units, HollyFrontier is evaluating a $5-million project to debottleneck operations at the El Dorado, Kan., refinery by as much as 6,000 b/d. The refinery's crude unit, which could support an additional 20,000 b/d of crude to fill existing downstream units, already exceeded its processing capacity by 4,000 b/d during August without any active debottlenecking project work in progress at the time. A project designed to address identified constraints at the unit, however, could increase its capacity by an additional 2,000 b/d by early 2016.

Specifically, the project would involve upsizing an atmospheric bottom pump between the crude and vacuum towers as well as improvements to unit piping. Engineering evaluation also is under way to identify and resolve additional constraints at the refinery that could result in an additional 4,000-b/d debottlenecking project at the site.

In its most recent quarterly report, the company said another ongoing project at El Dorado includes installation of a fluid catalytic cracking (FCC) gasoline hydrotreater to help the refinery meet Tier 3 gasoline requirements.

HollyFrontier also plans to continue this year with projects at El Dorado that include upgrades to the crude unit desalter as well as installation of a tail gas treatment unit to reduce air emissions in compliance with the refinery's existing US Environmental Protection Agency consent decree.

In fourth-quarter 2014, HollyFrontier completed an FCC liquid-yield improvement project at El Dorado, which raised incremental liquid-product yields at the unit by 1,000 b/d. The project, which cost about $9 million, included installation of feed nozzle technology as well as a riser termination device.

A $55-million project to improve coker yields at El Dorado also is under consideration, the company said. Sill in its early stages, the project, if approved, would be completed in 2018.

At its Tulsa refineries, which consist of the combined 125,000-b/d Tulsa West and Tulsa East production sites, HollyFrontier is proceeding with a $36-million project to modernize FCC operations. The FCC revamp, which aims to boost capacity at the unit by as much as 4,000 b/d as well as improve conversion rates and yield by 1%, will involve upgrades to the FCC's feed nozzles, catalyst stripper, and riser termination device, the company told investors.

The Tulsa FCC project is due to be completed during spring 2016.

Plans also are under way to address Tier 3 compliance at the Tulsa refineries with a project designed to expand naphtha splitting capabilities. Scheduled for late-2016 completion, the naphtha splitter will improve performance of isomerization catalyst by removing C7s from the feed, which in turn will raise octane by 4 numbers. HollyFrontier said it expects improved octane levels to enable the Tulsa refineries to upgrade 2,000 b/d of light, straight-run naphtha to gasoline. At an estimated cost of $30 million, the project is due to be completed in late 2016.

The company also wrapped a $1 million project to debottleneck propane deasphalting (PDA) operations at the Tulsa refineries. The project, which entailed installation of additional cooling to the PDA unit's propane recovery section and the replacement of a motor on an asphalt pump, has boosted PDA capacity by 1,000 b/d.

In addition to an ongoing $25-million upgrade to the waste water system at the Navajo refinery-which consists of production sites in Artesia, NM, and Lovington, NM-HollyFrontier said it is considering a $35-million project to fix ancillary fractionators that would result in 4,000-b/d debottlenecks at both the crude and distillate hydrotreating units. An already completed $15-million project to debottleneck Navajo has raised the refinery's crude processing capacity to 105,000 b/d from a former 80,000 b/d capacity, the company said.

At its 52,000-b/sd refinery in Cheyenne, Wyo., HollyFrontier said installation of a 10-MMscfd hydrogen plant to replace the refinery's inefficient 4-MMscfd existing plant remains on schedule for completion by yearend 2015. The $34-million hydrogen plant project, along with a recently completed naphtha fractionation project, is designed to help reduce benzene content in gasoline production while simultaneously improve overall liquid yields and light oils production at the refinery.

HollyFrontier also is considering an $8.6-million FCC liquid-yield improvement project at Cheyenne, which the company said it expects to complete in spring 2016.

Engineering and construction continues on Phase 1 of a $400-million expansion project at the company's 31,000-b/sd refinery in Woods Cross, Utah. Scheduled for mechanical completion in this year's fourth quarter, Phase 1 of the expansion is due for start-up by yearend.

In November, PBF Holding Co. LLC, a subsidiary of PBF Energy Inc., Parsippany, NJ, completed its deal with ExxonMobil Corp. and Petroleos de Venezuela SA (PDVSA) to become 100% owner of Chalmette Refining LLC, the former ExxonMobil-PDVSA joint venture that operates a 189,000-b/d refinery in Chalmette, La., outside of New Orleans. During its remaining fourth-quarter 2015 ownership of the refinery, the independent refiner said it plans to operate the refinery at a total throughput of 170,000-190,000 b/d using primarily medium to heavy-sour crudes.

In addition to the dual-train coking refinery, which can process both light and heavy crudes, PBF Energy also acquired the following Chalmette Refining assets:

• 100% ownership of the MOEM pipeline, which provides access to the Empire terminal, as well as to the CAM Connection pipeline, which provides access to the Louisiana Offshore Oil Port (LOOP) through a third-party pipeline.

• 80% ownership interest in both Collins Pipeline Co. and T&M Terminal Co., in Collins, Miss., which together provide the Chalmette refinery access for its clean-product production to reach the Plantation and Colonial pipelines.

• A marine terminal equipped to handle imports of waterborne feedstock as well as loading or unloading of finished products.

• A clean-products truck rack for access to local markets.

• A shell capacity of about 7.5 million bbl in crude oil and product storage.

Alongside its pending acquisition of ExxonMobil Corp.'s 155,000-b/d refinery in Torrance, Calif., PBF Energy's acquisition of the Chalmette refinery will boost its total throughput capacity to about 900,000 b/d to make it North America's fourth largest independent refiner, the company said.

PBF Energy currently operates three US refineries, including a 190,000-b/d refinery in Delaware City, Del., a 180,000-b/d refinery in Paulsboro, NJ, and a 170,000-b/d refinery in Toledo, Ohio. The company is due to complete its purchase of the Torrance refinery during second-quarter 2016.

Late in the year, Marathon Petroleum Corp. said it has canceled a major upgrade of its 522,000-b/d Garyville, La., refinery alongside current market conditions. The company referred to what would have been a $2.2-2.5-billion project as ROUX, for "residual oil upgrade expansion."

Flint Hills Resources LLC, a subsidiary of Koch Industries Inc., however, announced it would move forward with Project Eagle Ford (PEF), a $600-million program designed to increase processing capabilities for US light crude oil production at its 230,000-b/d West refinery in Corpus Christi, Tex.

Wood Group Mustang Inc. will provide detailed engineering, procurement, and other services for the refinery modification project, including module fabrication oversight as well as construction engineering support services. Engineering work on the project is due to be completed in mid-2016.

Initially announced in 2012 and formerly named the Domestic Crude Project, PEF will involve the modification of equipment at the West refinery's continuous catalytic regeneration hot oil heater, as well as the inclusion of a new saturates gas plant and associated hot oil heater.

In addition to equipping the refinery with an ability to process 100% US light US crude from nearby Eagle Ford shale play and boosting its overall crude processing capacity by about 7%, the expansion and modification project will enable reduced criteria air emissions from the Corpus Christi plant by the inclusion of best available control technologies.

PEF also will include installation of a mid-plant cooling tower, equipment piping, process vessels, and two storage tanks at the site.

Construction on the project, which began in December 2014, is scheduled to last 36 months.

Flint Hills most recently let a $300 million contract for PEF to KBR Inc., Houston, to deliver construction management and direct-hire construction services in phases over the next 3 years.

ExxonMobil Corp. also let a contract to Jacobs Engineering Group Inc., Pasadena, Calif., to provide EPCM services for a planned 20,000-b/d capacity expansion at the company's 345,000-b/d refinery in Beaumont, Tex.

Designed to expand the refinery's capacity to process light crudes from US shale, the Beaumont crude flexibility and expansion project also will result in increased production of jet fuel from the plant, according to Jacobs Engineering. Increased processing of light crude feedstock additionally would contribute to quality improvements in the refinery's overall production slate, ExxonMobil said when announcing the project earlier this month.

An official timeline for the proposed expansion has yet to be released.

The capacity expansion plans at Beaumont follow ExxonMobil's move to increase the processing flexibility of its US downstream operations to benefit from growing North American supplies.

Earlier in the year, Dakota Prairie Refining LLC, a joint venture of MDU Resources Group Inc., Bismarck, ND, and its 50-50 partner Calumet Specialty Produces Partners LP, Indianapolis, has started commercial production of diesel fuel and other products at its 20,000-b/d diesel refinery in North Dakota.

The first greenfield plant built in the US since 1976, the refinery previously was scheduled to begin production in late 2014 but experienced delays from severe winter weather in November and late revisions to electrical systems and controls.

In March, Motiva Enterprises LLC announced it would integrate the company's two Louisiana refineries-the 220,000-b/cd Norco facility and the 227,000-b/cd Convent facility-creating the Louisiana Refining System (LRS). The multi-phased project, intends to increase access to light oil and optimize interplant intermediates and conversion units, thereby increasing distillates yield and reducing operating costs.

The first phase of the project, the Maurepas crude pipeline system, will consist of three pipelines that will be built, owned, and operated by affiliates of SemGroup Corp. The Maurepas system will connect the existing LOCAP terminal in St. James, La., to the Norco refinery via a 34-mile pipeline. The Maurepas 35-mile and the 34-mile intermediates pipelines will then directly connect the Norco and Convent refineries "supporting optimization of both plants' conversion units while improving logistics efficiency, alleviating dock congestion, and allowing additional product exports," Motiva said.

When the pipelines are complete, Motiva plans to idle the FCC at its Convent refinery. Additionally, the company intends to reconfigure the existing hydrocracker unit at its Norco refinery to process 30,000 b/d of additional gas oil into diesel.

In South America, state-owned Ecopetrol SA has started operations at its newly expanded crude unit as part of the long-planned expansion and modernization project at subsidiary Refineria de Cartagena SA's (Reficar) 80,000-b/d refinery in the Mamonal Industrial Area on Cartagena Bay, south of Cartagena, on Colombia's northern coast. The first hydrocarbons were introduced into the new unit for processing on Oct. 21, with full commissioning of the sequential 31 plants that will make up the modernized refinery to take place over the next few months.

Shuttered since Mar. 5, 2014, for execution of the nearly $7-billion modernization overhaul, the upgraded crude unit will have a capacity to process 165,000 b/d of low-cost heavy crudes to produce a slate of higher-quality products that meet the highest Colombian and international environmental specifications.

Scheduled to become fully operational during second-quarter 2016, the Cartagena refinery will be equipped to produce the following: 90,000 b/d of ultralow-sulfur diesel (ULSD) with a sulfur content of less than 10 ppm; 40,000 b/d of low-sulfur gasoline with a sulfur content of less than 50 ppm; 10,000 b/d of low-sulfur jet fuel; 5,000 b/d of refinery-grade propylene; 4,000 b/d of LPG; 270 tonnes/day of sulfur; and 2,500 tonnes/day of coke.

Physical progress on a modernization project designed to increase crude processing capacity to 300,000 b/d at Ecopetrol's 250,000-b/d Barrancabermeja in Santander, Colombia, remained suspended at 18.14% as of yearend 2014, unchanged from a year earlier, according to the company's 2014 annual report published in late-April.

The Barrancabermeja modernization, which was recommissioned by the company in September 2014, previously was due to be completed in 2016.

While a portion of the project's 2015 budget continued to await approval from Ecopetrol's board, the company did commission Barrancabermeja's U-5100 cogeneration unit during this year's first half as part of a separate Industrial Services Master Plan (ISMP) undertaking at the site.

ISMP, which aims to increase the reliability and efficiency of industrial services operations at Barrancabermeja had reached 98.6% physical completion by August. Ecopetrol also is evaluating potential implementation of a plan to convert Barrancabermeja into a deep-conversion refinery, which would allow it to process more extra-heavy and heavy crudes produced at local fields, as well as increase production of middle distillates for the local market.

In Peru, state-owned Petroleos del Peru SA (Petroperu) resumed its long-planned modernization and upgrade of the 62,000-b/d Talara refinery at Piura, about 1,200 km north of Lima.

Slated to be completed within 55 months from the start of construction, the project is designed to equip the refinery to produce diesel and gasoline fuels conforming to new Peruvian environmental requirements of a maximum sulfur content of 50 ppm at competitive prices as well as increase the plant's ability to process heavy crudes to improve operational flexibility.

Elsewhere, Petroleo Brasileiro SA (Petrobras) commissioned the first of two 75,000-b/d delayed coking units at its Abreu e Lima refinery (Rnest) at the port of Suape, near Recife, the capital of Brazil's Pernambuco state, completing startup of all processing equipment to be included in Rnest's first 115,000-b/d phase.

While initial startup activities for Rnest's first production train began on Nov. 18 following official approval from Brazil's National Petroleum Agency, furnaces in the first train's atmospheric distillation did not enter service until Dec. 3.

Crude oil processing at the refinery's first train started on Dec. 6, with Rnest's first commercial sale of diesel occurring later in the same month, Petrobras said.