Most of the new Middle Eastern capacity has come in the form of new construction, some of which is still underway. But industry insiders say that upgrades of existing facilities are another viable route, and that the region has a number of refiners that could consider it. Those that do face a number of options in the technology and equipment that they select. According to one technology provider, their choices should depend on exactly what they hope to accomplish. At Octobers ICIS Middle East Base Oils and Lubricants Conference in Dubai, Gerrit Polhaar of Chevron Lummus Global said the highest quality oils require big investment but that benefits can also be achieved for lesser outlays.

API base oil groups are defined by three parameters – sulfur content, percent of hydrocarbon molecules that are saturated, and viscosity index. Lubricant formulators generally favor higher saturates levels because it means fewer aromatic hydrocarbons and results in improved oxidative stability. Sulfur can aid lubricity, which is generally good, but lower sulfur levels are nevertheless sought for some important applications, such as automotive engine oils, where the element can elevate regulated tailpipe emissions. A higher viscosity index helps lubricants avoid large changes in viscosity as temperature rises or falls.

The qualities of a base oil depend not only on the crude oil available, but also on the technology used to produce it. Polhaar (who has since left his position at Chevron Lummus Global) explained that traditional base oil production consists of three main steps. Feedstock passes through a unit that uses solvents to extract impurities such as sulfur and nitrogen, and aromatic and polar molecules. From there the feed flows to a second unit where another solvent is used to remove wax – unwanted because it detracts from cold-temperature performance. Finally, the oil undergoes a finishing process that uses adsorption to bolster color and stability. Plants configured this way need lubricant-friendly crudes and produce Group I oils almost exclusively.

Group II and III plants use different processes, beginning with a hydrocracker to replace the solvent extraction unit. Hydrocrackers are towers that introduce hydrogen under very high pressure and temperature in order to crack aromatics and other molecules, changing them chemically into longer-chain, saturated hydrocarbons. The result is a fluid that is more uniform, more stable and higher in viscosity index.

Next, the solvent dewaxing unit may be replaced either with catalytic dewaxing or wax isomerization. Both of the latter processes use chemical catalysts to crack wax molecules, Polhaar said, but catalytic dewaxing turns them into gases and naphtha, whereas wax isomerization turns wax molecules into base oil paraffins. Consequently, catalytic dewaxing decreases base oil yield, while isomerization increases it. Both processes result in significantly improved low-temperature performance compared to solvent dewaxing.

The final step, hydrofinishing, is not as dramatic but eliminates reactive molecules by saturating them.

A plant that uses all hydroprocessing technology makes base oils that are higher in saturates, higher in viscosity index, lower in impurities and that have lower pour points than conventional Group I. They will be Group II or Group III, sometimes very high quality Group III depending on the severity of the processes. These processes also give a refinery more flexibility in the crude feed-stocks that run through the base oil plant.

The drawback of hydroprocessing is investment cost. Hydrocrackers alone can cost U.S. $500 million and more, depending on their size. How-ever, Polhaar said, refiners can reduce price tags by installing only some hydroprocessing units. For example, a company could install a hydro-cracker but skip purchasing modern dewaxing technology. In this case it would continue with solvent dewaxing and conventional finishing. Such an operation could produce Group II and III base oils, although they would have lower viscosity index and higher pour points than if catalytic dewaxing or wax isomerization were employed.

Likewise, a plant could install one of the modern dewaxing technologies and hydrofinishing, but not a hydrocracker. Polhaar said this approach should include installation of hydrotreating between the solvent extraction unit and the new dewaxing unit. Base oils from such a plant would only be Group I or II, but the configuration would give the operator greater flexibility in crude selection, compared to an all solvent process.

Polhaar described one more option. A refiner could install hydrotreating, new dewaxing technology and hydrofinishing, but continue to operate the solvent dewaxing and hydro-finishing units. Under this scenario, most of the feedstock would flow from solvent extraction through the new units, emerging as Group I or II base oils. Some feedstock would be diverted through the older dewaxing and finishing processes in order to produce bright stock. The rationale behind this approach is that profit margins for bright stock have improved with the industrys trend toward Group II and III plants due to the fact that they generally do not produce bright stock.

Polhaar said that any of the approaches to upgrading a base oil plant can make sense, depending on what the refiner wants to accomplish. He advised companies to consider first if they want to be in the base oil business, suggesting that it can worthwhile in terms of profits. Base oil margins are typically about [U.S.] $20 to $30 per barrel higher than diesel, he said.

He urged refiners considering an upgrade to perform a market study assessing supply and demand and prices for various grades. They should consider which market they want to be in – Group I, II or III – who their competitors would be and whether they would market their oils locally, regionally or globally. They should also decide if they would prefer to undertake such a project and market their oils alone or with a partner.

Refiners should also consider where their feedstock would come from. Do they have their own supply or would they be buying on the open market? Then the company needs to decide if it is willing to invest in all hydroprocessing units or if it wants to lower capital costs by using some existing equipment.

One Middle Eastern refiner is currently pursuing a hybrid base oil upgrade. Luberef, a joint venture between Saudi Aramco and Jadwa Industrial Investment, is spending $1 billion on a project that will install a hydrocracker, wax isomerization and a hydrofinishing unit at its Group I plant in Yanbu, Saudi Arabia. The new equipment will allow the plant to make Group II oils, but the facility is also expanding its output of bright stock.

Three other grass roots projects opened in the Middle East in the past couple years or are under construction. Shell and Qatar Petroleum opened a gas-to-liquids base oil plant in Ras Laffan, Qatar, with capacity to make 1.3 million metric tons per year of Group II and III stocks. Finlands Neste Oil and Bahrain Petroleum Co. opened a 400,000 t/y Group III plant in Sitra, Bahrain, last year. It is on the site of a Bapco refinery and gets its feedstock from a Bapco fuels hydrocracker. Neste is replicating its joint venture model by partnering with Adnoc (Abu Dhabi National Oil Co.) to build a 650,000 t/y Group III plant in Ruwais, United Arab Emirates. Scheduled to open this year, the facility will receive its feedstock from an existing hydrocracker that is being revamped and will use wax isomerization.

To date, there has been little demand for Group II and III in the Middle East, meaning that projects there were conceived mainly with the idea of exporting to more developed markets. But some observers contend that more highly refined oils are beginning to gain momentum in the region.

Its only a matter of time, and once the commercial aspect [of convincing consumers to use better engine oils] is dealt with, it will happen fast, said T.R. Kumar, manager of lubricants technology at Dubai-based Enoc (Emirates National Oil Co.). If that happens, Middle East Group I producers may have more incentive to upgrade their facilities.

Milind Phadke, of consulting firm Kline and Co., of Parsippany, New Jersey, United States, thinks new Group II and III capacity will make the Middle East into an export hub, but he is cautious about how it will be manifested. Most projects in Middle East are developed with a view to export Group III to Europe and also to South Asia, [but] this may take the form of base stock exports or finished lubricant exports. The regions position as an export hub will depend on how majors view their business.

He points to Shell, Neste and Luberef in particular. Shell has not marketed its [GTL] product, so the product is being exported but only to plants within its system. Neste will market largely into Europe and Luberef will focus sales within the region, with blenders potentially exporting the final product to South Asia.

All of which means a bigger variety of options for base oil producers as they consider whether to upgrade.