Changes to refining operations ahead of 2020

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Refiners are already investing in changes to their operations ahead of 2020, with European and Russian firms – the world’s largest producers of fuel oil – most affected.

With the specification change now uncomfortably close, producers have stepped up the implementation of their planned upgrades aimed at reducing fuel oil output of fuel oil and increasing the yield of distillates.

In October 2018 Shell commissioned its new solvent deasphalter (SDA) unit at its Pernis refinery in the Netherlands, and converted a hydroprocessing unit into a hydrocracker to process the deasphalted oil from the SDA unit.

The new unit, the first major investment at the site since 2011, will enable Pernis to “process a larger proportion of its oil intake into cleaner transport fuels, including marine gasoil compliant with IMO 2020,” it said.

Almost a year earlier, in nearby Antwerp, Total also launched an SDA unit and a mild hydrocracker – “in anticipation of the new marine fuel regulation that will take effect in 2020,” it said at the time. The market’s focus has been on the cluster around Northwest Europe, as it hosts some of the continent’s biggest refineries and is pivotal in the supply of bunker fuel.

Throughout 2018 traders in Northwest Europe were eyeing the delayed coker launch at ExxonMobil’s Antwerp refinery, starting up at the end of the year. The company is also building a new hydrocracker at its Rotterdam refinery.

The market is also closely monitoring the progress of another delayed coker, at Poland’s Gdansk. Grupa Lotos is yet to set the deadline for its launch after experiencing delays.

Further north, in Sweden, Preem is also gearing up to meet the IMO requirements with plans to start up a new vacuum distillation unit at Lysekil and a new hydrogen unit at Gothenburg. Both units are due online in 2019 and will help to “have less than 20% high sulfur fuel oil left in the product slate from the two Preem refineries,” it said.

In neighboring Finland, Neste commissioned a new SDA unit at its Porvoo refinery in 2017. ExxonMobil has announced plans for “significant upgrades” at its UK Fawley plant involving the construction of a new hydrotreater and a new hydrogen plant.

But as the deadline for the 0.5% sulfur cap comes nearer, some refineries have found that embarking upon new investments might be too late or not make economic sense.

Shell decided to “demobilize” the project of constructing a SDA plant at Wesseling, in the Rhineland refinery, as the planning has shown that “it might not be successfully implemented within the set framework.”

In August 2018 commodities trader Gunvor said it had “decided to put on hold the construction of a delayed coker unit” at its Rotterdam refinery as “the price environment and other relevant economics have changed considerably since Gunvor first began exploring the concept a year ago.”

But the pending IMO regulation is likely to bring back to life at least part of the mothballed Wilhelmshaven refinery in northern Germany, whose vacuum distillation unit might be restarted this year. At the end of last summer, BP started up the upgraded VDU at its Castellon refinery in Spain, which will enable the refinery to increase fuel oil conversion capacity by around 10%.

However, the majority of Spanish refineries had already completed their modernization plans by the early 2010s and as Repsol’s head of refining, Francisco Vazquez, said at a conference in 2017, at Repsol’s Spanish refineries the yield of fuel oil was close to zero. “We have five cokers in four refineries,” he said.

Upgrades at Cepsa’s Spanish refineries around the same time also contributed to their increased middle distillate capacity in a drive to help reduce Spanish diesel imports.

Another Mediterranean country, Greece, also completed an upgrade involving a hydrocracker and flexicoker in the early 2010s. Russian refineries have been heavily investing in hydrocracker units since 2011 as part of the downstream modernization agreement the companies and federal authorities signed in October 2011. But initially the upgrade in conversion units was accompanied by primary processing capacity expansion, resulting in higher fuel oil output.

As the upgrades were gathering speed, sanctions restricted access to foreign equipment and capital, leaving some projects facing delays. Rosneft, Russia’s largest oil company, has put off the completion of its modernization to 2025. But Russia’s own manufacturing has increasingly stepped in to fill the gap, and new projects have been launched.

Lukoil’s Nizhny Novgorod refinery is on track to start up a delayed coker in 2021 and its Perm refinery fully halted fuel oil output after launching its coker three years ago.

Gazprom Neft is also looking forward to fuel oil-free production with the completion of deep conversion upgrades. Both its Moscow and Omsk refineries are undergoing large-scale upgrades due for completion in the next few years.

Another big fuel oil reduction project in Russia, expected to come fully online this year after experiencing some delays, is the new complex for deep processing of residue at Taif’s Nizhnekamsk. In addition to the upgrades, changes in the country’s taxation have made fuel oil exports less attractive, resulting in a gradual decline of fuel oil output.

Increasingly, medium-sized refineries have also started working on new projects that will help reduce their heavy fuel output. In the Middle East, recently built refineries as well as projects due for completion in the next few years are well geared to produce light products. Saudi Aramco is soon due to start up its green field 400,000 b/d Jizan refinery, which will be producing no fuel oil.

As a result of the Clean Fuels Project, which includes new units at Kuwait’s Mina al-Ahmadi and Mina Abdullah refineries, their pooled fuel oil yield is expected to be slashed from 20.7% to just 5.7%. Separately, the new 615,000 b/d refinery at Al-Zour in the south of Kuwait, due to start operations in the next two years, is also set to minimize fuel oil production as it will most likely be using gas as the main source of feedstock for power generation rather than low sulfur fuel oil for power generation, as originally planned.

China’s green field 20 million mt/year Hengli Petrochemical refinery, which had its trial runs in December, does not have any fuel oil in its marketing plan. Meanwhile, the 20 million mt/year Zhejiang Petrochemical refinery plans to start operations early this year and mostly produce light products. PetroChina’s currently under construction Guangdong Petrochemical refinery also does not list fuel oil on its product list.

In addition to running new sophisticated units, European refiners have learned that optimizing the crude slates makes a big difference. What “can turn the economics [is…] how many heavy crudes you can process,” Hellenic Petroleum CEO Grigoris Stergioulis said in 2017.

Hellenic’s refineries have doubled their crude slate over the last few years. Repsol’s refineries now process 70 different types of crude, and Saras’ Sarroch typically processes 40 different types of crude.

With demand for fuel oil waning, heavy crude is likely to lose in value and benefit the complex refineries. For those refiners that can’t rely on sophisticated conversion units, running light sweet crude would be a must.

While European refineries in 2018 were predominantly running heavier barrels, capturing strong fuel oil cracks, with the approach of 2020 demand is likely to turn away from those crudes.

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