Claxton said that during the hydrocracking process, around 20 percent remains as residual unconverted oil, called UCO, consisting of molecules deemed too heavy for fuel products. However, UCO can be hydrodewaxed to produce API Group II or III base oils, depending on feedstock type and processing severity. Claxton said Group III+, an informal designation, can also be produced in the process.

A significant amount of upgrading activity is taking place in the Middle East to to enable refineries to covert UCO to base oil. Of the 6.3 million tons of new Group II/III and gas-to-liquid capacity that will be in place in 2015, about one-half will be supplied from Middle East sites, Claxton claimed.

What About Feedstock Quality?

Highly paraffinic crude is required to produce materials that are suitable for upgrading, said Claxton. Crudes from Asia and the Middle East feature prominently due to their high paraffinic content – Tapis from Asia and Arab Light from the Middle East are typically used to produce Group III base oils.

In contrast, West Texas Intermediate and Brent crudes are medium paraffinic oils, while Alaskan North Slope oil is low paraffinic. All are generally unsuitable for 120+ VI upgrading, Claxton said.

The type of crude will determine base oil yield and VI. Producing so-called Group III+ base oils is most cost-effective using super paraffinic crudes. If you are going to take hydrocracker bottoms, you need a crude oil with a 60 percent or higher paraffin content, Claxton explained. Otherwise, the process will not be as cost-effective compared to processes using crudes with higher wax or paraffin content.

Although Asia is a source of high-paraffinic crudes, they are in limited supply, and base oil refiners there rely on imports from the Middle East. With reserves in excess of 700 billion barrels of mostly high-paraffin crudes, it is not credible to think that the Middle East will not be a major source of feedstock for base oils for the foreseeable future.

One reason Europe and North America are not upgrading a significant amount of hydrocracker bottoms is that refiners would have to import crude from the Middle East to produce Group III base oils. That is why you see all that Group II in the U.S. because their crudes are around 100 VI. And once you try to take that VI further you lose yield, Claxton said.

Refinery Configuration

Claxton noted that the refinery configuration will determine whether or not it is possible to use hydrocracker bottoms and upgrade them to base oils. Refineries were all about making petrol. And if you have to produce petrol instead of diesel, you are going to run your hydrocracker harder, and you are going to have catalytic cracking capacity to facilitate gas or petrol production, she said.

Conversely, refineries built to run heavier crudes have higher coking capacity, but Claxton pointed out they produce unconverted oils like aromatic cyclicals or coker oils that when fed to hydrocrackers do not provide a good outcome. The coking process produces a feed quality unsuitable for base oils, and refineries with high fluid catalytic converting (FCC) and coking capacity usually feed cracked cycle oils to HCUs.

Asia and the Middle East have an advantage over many countries, including the U.S., that have much higher levels of FCC and coking capacity. It is not possible for the U.S. with the largest amount of hydrocracking capacity to convert all that to make lube base oils because the crude is not good enough, and unconverted oils are useless for base oils.

Claxton said the Middle East has three main advantages for long-term competitiveness in Group III 120 VI; namely, an abundance of high-paraffinic crudes, hydrocrackers feeding straight run gas oil and regional organic growth with refineries being built. Asia is also competitive but depends on the Middle East for high-paraffinic crudes.

GTL Outlook

Natural gas infrastructure will be the major determinant for future gas-to-liquids projects, and despite slow progress, Claxton said the process remains important. GTL is Group III++ in the 4-centiStoke range with around 140 VI, and that matters because of changes in Noack volatility. You need over 120 VI, and GTL is way over the 120 bar.

Automakers want both lower cold cranking simulator values and lower Noack volatility for premium engine oils. Claxton said the planned ILSAC GF-6 and PC-11 standards will benefit Group III+ oils, which can be met by GTL base stocks.

The Middle East is in a strong position when it comes to natural
gas reserves, particularly in Iran and Qatar. Five of the ten counties with the largest gas reserves are in the Middle East. With Shells Pearl GTL plant in Ras Laffan, it is not beyond the realm of possibility that another GTL plant could be built in the region. The possibility of sanctions against Iran being lifted and its pent-up need for substantial infrastructure investment make it a prime candidate for a GTL plant as part of the upgrading of its outdated technology.

According to Claxton, even without GTL, a number of options are available to monetize gas plants such as pipeline sales, which is a low-cost investment. Alternatively, further investment offers the potential to produce liquefied natural gas. Natural gas liquids and liquefied petroleum gas are other options in addition to a GTL refinery.

When I looked at all the gas projects going on around the world, about 80 percent of them are here in the Middle East, Claxton said. There are 21 active gas projects in the Middle East, which Claxton estimates have a value of around U.S. $80 billion; yet there are no plans for a GTL refinery.

Despite earlier optimism about the technology, there is a reluctance to build GTL plants, and gas projects currently underway are relatively simple processing plants with lower investment costs and better returns. As was vividly demonstrated with Shells Pearl GTL project, construction costs can soar, and erecting a GTL refinery is much more complicated than say LNG, NGL or LPG plants.

These factors do not augur well for the future of GTL refineries, and it looks unlikely that anything on the scale of Shells GTL plant will emerge, Claxton said. Another factor is the cost and complexity of the Fischer-Tropsch process. Intellectual property is an enormous hurdle and will render most GTL refining investments uneconomic, she noted. Even so, Claxton believes future GTL investment is contingent on increasing demand for the higher VI base oils that fuels hydrocracker bottoms struggle to produce. There is an expectation that 130+ VI premium engine oils derived either from Group III+ or GTL base oils will gain prominence in the next few years, and that suggests GTL may be an option

Still Group I … For Now

The Middle East will continue to be a global source of high-paraffinic crudes for higher viscosity base oils, but the local market is making only modest qualitative changes. Speaking at the ICIS Dubai conference, Sulaiman Bilaus, a base oils and lubricants consultant in Saudi Arabia, believes a number of factors are driving the market.

Despite marketing campaigns by original equipment manufacturers and lubricant blenders to improve consumer awareness about higher specification lubricants, the impact on the market has been mixed. That also goes for local environmental legislation, which Bilaus said has achieved limited progress on legislation to reduce emissions. We have SASO (Saudi Standards, Quality and Metrology Organization) in Saudi Arabia, but their enforcement is not strong compared to similar bodies elsewhere in the world.

Consequentially, Bilaus feels demand for Group I will not decline anytime soon, due mainly to local business conditions. Additionally, climate conditions and short drain intervals influence consumer attitudes to the use of lubricants. Although a number of refiners are investing in new Group II and Group III capacity, Bilaus said most is destined for export markets. Older solvent extraction technology is also in widespread use, and worldwide demand for bright stock will sustain the life of Group I base oil plants at least until 2020.

Rationalization of Group I plants in the U.S. and Europe continues apace, but Bilaus says plants in the Middle East will be the last to be affected. And as Group II consumption increases in Europe, redundant Group I production will find its way to the region. Yet, economics are crucial, and the small premium of Group II prices over Group I will encourage use by blenders as will pressure from OEMs.

According to Bilaus, the three key Middle East lubricant markets are Egypt, Saudi Arabia and United Arab Emirates. The elephant in the room is Iran, by far the largest regional market at 745,000 metric tons, yet predominantly a Group I market.

U.A.E. is the finished lubricants hub, and Bilaus expects domestic demand to reach 200,000 metric tons by 2020. With over 1.2 million tons of blending capacity, the country is the obvious front runner and has steadily built a reputation as a re-export hub to emerging markets.

The Saudi Arabian market is around 460,000 tons with a more limited export market of 50,000 tons, supplied mainly by Petromin and Fuchs. With a population of nearly 30 million and a vehicle penetration of 336 per 1,000 people, Saudi Arabia is the largest auto market in the Middle East and is expected to reach 1 million units by 2020. Luberef, a joint venture between Jadwa Investments and Saudi Aramco, supplies 95 percent of the base oils; it has a 770,000-t/y Group II project underway.

In contrast, Egypts market is approximately 400,000 tons with three local base oil suppliers, but the vehicle population is just 60 per 1,000 people. Despite political uncertainty, the government has encouraged OEMs to set up factories, and companies like BMW, Daewoo, GM, Hyundai, Kia, Nissan, Peugeot and Suzuki have already done so.

The Middle East is investing in new base oil technology as part of a strategy to meet demand in emerging markets. Locally, entrenched consumer attitudes mean switching to higher grades is still some way off.