Southwest Research Institute (SwRI) is launching the Advanced Combustion Catalyst and Aftertreatment Technologies II (AC2AT™-II) consortium focusing on engine emissions solutions and innovative catalyst technologies. The AC2AT-II kickoff meeting will be Nov. 15 at SwRI’s headquarters in San Antonio and is open to interested automotive industry manufacturers. SwRI launched the AC2AT consortium in 2014. “In the first phase, AC2AT made considerable advances in understanding how complex emissions control systems affect today’s high-performance, high-efficiency gasoline and diesel engines,” said Scott Eakle, a principal engineer in SwRI’s Diesel Engine and Emissions Research and Development Department. The program developed models to predict deposit formation, growth and composition for urea-based selective catalytic reduction aftertreatment systems, characterized the complex emissions emitted from advanced combustion regimes, as well as evaluated how the physical and chemical properties of lube oil derived ash affect aftertreatment component performance. “We will build on research initiated during the first phase to further our understanding of the effects these complex emissions properties have on aftertreatment systems,” he said. For more information about the AC2AT-II consortium or to attend the meeting, contact Scott Eakle at (210) 522-5095. or visit consortia.swri.org. Source: Southwest Research Institute (SwRI), 9/5/2018.
An industrial-scale pilot plant that will use surplus hydrogen from refinery operations to produce power is taking shape in Australia. Industrial alkaline fuel cell power company AFC Energy on July 12 said it received its first commercial order for a hydrogen power generation unit in Australia from Southern Oil Refining, a subsidiary of Northern Oil. AFC’s alkaline fuel cell technology converts oxygen and hydrogen into electrical energy, producing demineralized water and heat as byproducts. The company recently wrapped up a two-year pilot in Germany at an industrial plant owned by Air Products, which accepted hydrogen from Dow Chemicals. The project, POWER-UP, was a European Union–backed demonstration. The new pilot, expected to be sized between 200 kW and 400 kW, will be located at Northern Oil’s Advanced Biofuels Refinery, near Gladstone, Australia. The refinery currently converts several waste streams, including from sugarcane bagasse, “green waste” from cities, woody weeds like prickly acacia, and tires as feedstock for the production of bio-crude oil. The renewable fuel is refined into saleable kerosene and diesel products, but it requires large volumes of industrial stable biohydrogen to support the refining process. Northern Oil is developing a new hydrogen generation technology that uses steam over iron reduction and chemical looping to deliver hydrogen, processes that are reportedly cheaper than conventional steam methane reforming. Surplus hydrogen generated from this system is expected to be consumed by AFC’s fuel cell system. AFC said the pilot power system could be delivered to the Gladstone refinery in the first half of 2019. The company is now conducting engineering studies to determine the final project size, scope, contract terms, and general logistics for integration of the hydrogen power generation unit fuel system into the refinery. Source: Power, 7/18/2018.
German refineries have historically relied on crude oil from Russia/CIS (35%), the North Sea (32%), the Middle East (18%) and North and West Africa (15%). However, recent decreases in North Sea production require many German refineries to source crude supplies from farther afield, incurring logistical challenges and costs. Refinery throughput in Germany grew by 2% on the year in 2017, to approximately 2 MMbpd. However, it is possible that these figures will significantly decline in 2018 due to the continuing recovery in oil prices and other factors. In response to IMO 2020, Royal Dutch Shell Plc subsidiary Shell Deutschland Oil GmbH is evaluating the potential expansion of residual processing capacity at its 140-Mbpd refinery in Wesseling, Germany. The Wesseling refinery, together with the former Godorf refinery near Cologne, form Shell’s 325-Mbpd integrated Rheinland refinery, which is one of Germany’s largest. Other leading refiners are expected to follow suit. However, tightening environmental requirements may prevent the further expansion of production capacities within the German refining industry, and may even lead to a reduction in crude processing. Germany’s refining situation is aggravated by the fact that the country has very few product pipelines, so most of its oil products are transported via truck, train and barge, with high transportation costs. BP remains a leader in the German refining market and one of the largest product suppliers in the country. The company operates two refineries—the 265-Mbpd Gelsenkirchen complex and the 82-Mbpd Lingen refinery. BP also operates its own storage terminals, as well as five additional storage locations through the JV TransTank. Competition is expected to further tighten due to the influx of major foreign players in the German refining market in recent years. One of them is Russian leading oil producer Rosneft, which increased its ownership in several leading German refineries as a result of a recent deal with BP. Among the refining assets controlled by Rosneft in Germany are Bayernoil (which provides fuel to Bavaria and northern Austria; Rosneft holds a 25% stake), MiRO in Baden-Württemberg (24%) and PCK-Raffinerie (54.17%). As a result of its deal with BP, Rosneft now holds more than 12% of Germany’s refining capacity, making it the third-largest refiner in the country and one of the largest in the EU. Rosneft considers the German refining industry to be a promising area for future growth. The company plans to allocate up to €600 MM ($707 MM) for the development of the sector over the next 5 yr. The 2008 financial crisis and market stagnation of 2009–2016 accelerated the process of rationalization in the European refining sector, which retired 2.35 MMbpd of capacity. Over the last few years, German refining investments have focused on increasing diesel production. However, sophisticated refineries in other regions are flooding the market with low-priced middle distillates, making domestic fuel production less lucrative. Furthermore, rapid growth in distillation and conversion capacity in the Middle East and Asia threaten the German refining sector. The German refining system, with its relatively lower complexity and utilization, faces difficulty in competing against newer, larger, more sophisticated refineries. Source: Hydrocarbon Processing, 6/2018, p.17.
In an effort to diversify their economies, national oil companies from the Middle East and North Africa are investing in chemicals, where they see attractive growth and sustainable prospects. Abu Dhabi National Oil Co. (ADNOC) plans to invest $45 billion, with partners, in its refining and petrochemical complex in Ruwais, United Arab Emirates. Qatar Petroleum and Algeria’s Sonatrach are also spearheading multi-billion-dollar investments. The plans come on the heels of an initiative announced last month by Saudi Aramco to spend $60 billion on petrochemical and refining projects in the U.S., Saudi Arabia, and India. ADNOC says it wants to make Ruwais “the world’s largest and most advanced integrated refining and petrochemical complex.” It will add a refinery to the site, increasing capacity more than 65% up to 1.5 million barrels per day, by 2025. In chemicals, the company plans a mixed-feed ethylene cracker that will triple the site’s petrochemical output to 14.4 million metric tons by 2025. The cracker is an amplification of plans ADNOC and European polyolefins maker Borealis unveiled last year to up capacity in Ruwais to 11.4 million metric tons by 2023. ADNOC is also establishing two industrial parks on nearly 10 km2 of land meant to attract makers of specialty chemicals and other products to Ruwais. ADNOC has already signed on the Spanish firm Cepsa to build a plant for the surfactant raw material linear alkylbenzene (LAB). In Algeria, meanwhile, Total and Sonatrach are planning a $1.4 billion propane dehydrogenation (PDH) and polypropylene (PP) plant with 550,000 metric tons of annual output. A decade ago, the two firms planned a cracker project that didn’t materialize. Source: Chemical & Engineering News (C&EN), 5/21/2018, p.12.
TCGR Note: The world is already responding to the clear trend that transportation fuels globally will gradually decline towards 2030 to 2040 despite shorter term gains due to stricter fuel regulations. So chemicals now to 2040 is hot! And new trends like oil-to-chemicals are even hotter. For more information, see TCGR’s multi-client study, “Oil-to-Chemicals: Technological Approaches and Advanced Process Configurations.”
The outlook for motor fuels is having a strong, increasing influence on petrochemicals capacity investments and promises to rattle the chemical industry status quo. Any company involved in steam cracking and businesses immediately downstream needs to develop scenarios and strategies taking into account the new reality. The world’s big refiners look at tomorrow’s world and see stagnant and probably regionally declining motor fuels demand. The shift in motor fuels demand means that the world’s big refiners are looking at their business differently, eyeing possibly above-GDP petrochemicals growth, replacing that lack of demand from the auto industry. The petrochemical business becomes, as a result, not just a (recently) profitable adjunct to the main thrust of what they do but the generator of product streams that command a great deal more attention. Refineries will, in the future, be run to produce more petrochemical feedstocks and more petrochemicals. An increasing proportion of the oil barrel will be used for petrochemicals – and plastics – manufacture. The problem for the oil refiner is that, currently, the proportion is low, but it is likely to take over as the main source of growth post 2030. Given that scenario, think about the pressure on the oil companies to make more, higher growth products, profitably. Think about the liquid feedstock streams – naphtha and liquefied petroleum gases (LPG) – that will be produced and needed for petrochemicals. Also think about the heavy products from the refinery, including even, perhaps, petroleum coke, that could be used to produce petrochemicals – in this instance, methanol. The influence of the non-integrated petrochemical producers is likely to diminish, with those companies facing a significant competitive disadvantage. Chemical companies will continue to push further downstream or into specialized niches. The world of petrochemicals will be dominated by big oil. Source: ICIS Chemical Business, 4/20/2018, p.10.
TCGR Note: It was also announced this week that KBR will do the FEED study for the Aramco-SABIC project. For more information on the technologies that will be used for the direct oil to chemicals conversion, see the following article.
In 2017, OECD natural gas production grew by 2.4% compared to 2016. This growth was driven by increases particularly in OECD Asia Oceania (+17.7%), whilst the OECD Americas (1.1%) and OECD Europe (0.4%) saw moderate growth. OECD Americas continued to account for nearly three quarters of the total OECD natural gas production in 2017. Indigenous production in OECD Asia Oceania was almost 20 bcm higher in 2017 than in 2016, driven by growth in Australia (+20.5%), where production increased in Surat-Bowen and the Carnarvon basin, along with the beginning of production at the Wheatstone LNG project in October 2017.
Total OECD annual production of crude oil, NGL, and refinery feedstocks increased by 2.6% in 2017 compared to 2016. This trend was driven by the OECD Americas (+3.5%), whilst production decreased in OECD Asia Oceania (-8.7%) and OECD Europe (-1.1%). The United States experienced the highest growth, in absolute terms, despite the effects of Hurricane Harvey in August 2017, increasing production by 4.7% or 25 million metric tons (Mt). Canadian production also grew (+7.8%) on an annual basis, partially due to the recovery from the 2016 wildfires in Alberta. Meanwhile, Mexico experienced the largest decline (-9.6%) in production amongst OECD countries. OECD Europe’s production decline was driven by Norway (-0.8%) and the United Kingdom (-2.0%). Italy’s production recovered by 8.6% as the Val d’Agri field restarted production. The decline in OECD Asia Oceania’s production was primarily due to Australia, where production fell by 9.6% or 1.5 Mt.
Refinery gross output of total products within the OECD increased by 1.2% or 23.2 Mt in 2017 with all OECD regions contributing to this growth. OECD Europe’s output grew (+1.9%) despite the fire incidents at the Pernis refinery in the Netherlands and the Leuna refinery in Germany. Total gasoline was the only product category experiencing a decline (-1.2%) in the region. The OECD Americas’ growth (+0.8%) was led by the United States (+1.4%), in absolute terms, followed by Canada (+6.4%). Mexican output declined (-19.0%), partially due to the fire incident at the Salina Cruz refinery, while Chile’s output remained relatively flat (+0.3%). Growth in OECD Asia (+0.8%) was driven by Korea (+5.2%), where notably the output of naphtha increased by 15.7%. Japan’s reduced output (-2.5%) was primarily due to a 15.9% decline in residual fuel oil output. Source: International Energy Agency (IEA), Key Natural Gas Trends 2017, Key Oil Trends 2017, 4/12/2018.
TCGR Note: Despite the stories, we have also reported about the net increases in renewable energy taking a larger share of energy consumption worldwide. It is interesting to highlight, probably based on the worldwide positive economic growth and outlook, the total production of crude oil, NGL and feedstocks in 2017 increased +2.6% compared to 2016. However, note the overall OECD decline in gasoline by -1.2%.
Bahrain will invite international oil companies to help it develop its first major discovery in decades, hoping to begin production within five years. Production from the new discovery could one day reach 200,000 barrels a day, according to Abdulrahman Ali Buali, a member of Bahrain’s Council of Representatives. The amount of oil and gas that can be recovered from hard-to-reach pockets in shale rocks under the sea is uncertain, and development is potentially an expensive proposition. Halliburton Co. will drill two wells this year in the offshore Khaleej Al Bahrain Basin to appraise how much of the oil contained underground is actually recoverable. Bahrain estimates there are 81.5 billion barrels of shale oil and 13.7 trillion cubic feet of natural gas of resources in the basin. Oman’s Rub Al-Khali Basin area contains an estimated 24 billion barrels of oil, but only 1.2 billion barrels are “technically recoverable,” according to the U.S. Energy Information Administration. Jordan’s Wadi Sirhan Basin resource holds about 4 billion barrels, and just 100 million can be extracted, according to the EIA. Both deposits are onshore. Source: Bloomberg, 4/4/2018.
TCGR Note: Here comes the Middle East to shale oil & gas and fracking. This all sounds easy, but my require different methods and skills for recovery, so it will not be a one-size-fits-all solution for each basin. Also, drilling and recovery off-shore can be significantly more costly, so that opportunity needs to be evaluated separately.
The owners of 60,000 cargo ships are bracing for tighter emissions rules that are forcing them to make a multibillion-dollar choice: Start buying cleaner-burning fuel or invest in a device that treats the ship’s exhaust before letting it out. It isn’t an easy call. Retrofitting a vessel with a sulfur-trapping exhaust system called a “scrubber” costs as much as $10 million a ship, while cleaner fuels are about 55% more expensive than the ones shipping operators use now. Refineries say they will have enough cleaner fuel blends to meet demand, but many shipowners are opting not to wait and see. Scrubber manufacturers expect orders to total between $6 billion and $18 billion by 2026, from less than $300 million last year and just a few million in 2016. The lion’s share will go to big competitors such as Finland’s Wartsila Oyj, Sweden’s Alfa Laval AB and Norway’s Yara Marine Technologies. A study commissioned by the International Maritime Organization (IMO) says about 6.7% of the global commercial fleet, or around 4,000 ships, will be using scrubbers after 2020. Peter Leifland, Alfa Laval’s executive vice president, said a very large crude carrier, or VLCC, would spend $9 million a year using low-sulfur fuel mixes, but a $3.7 million scrubber system would cut the annual fuel cost to $7 million plus an annual service fee of as much as $75,000. Source: The Wall Street Journal, 3/20/2018, p. B1.
TCGR Note: This topic has been frequently covered here in CAP Communications and is now being covered in the Wall Street Journal and Bloomberg. The Bloomberg article highlights the benefits of the new rules to refiners. “80 percent of U.S. Gulf Coast refineries have coking units that can create transport fuels from the residual fuel oil from heavy crude.” “In the European Union, the rule change will raise refining margins by an average of 60 cents, to $8.10 per barrel in 2020.” Maersk, with a fleet of more than 770 vessels, expects that cleaner fuels will add around $2 billion to its average $3.3 billion fuel bill, but adds that using cleaner fuels is the preferred choice as it expects fuel costs to gradually decline.
A major challenge for chemical plants is the cost associated with unscheduled machine downtime. Since companies do not share shutdown information publicly, it is often challenging to calculate asset failure at an industry-wide level. Nevertheless, according to Accenture’s ICIS Chemical Business, the missed profit opportunity alone on a major cracker shutdown in the US Gulf Coast was $1.4 MM/d per world-scale cracker. Furthermore, a calculation by the Aberdeen Group indicates that 2%–5% of production is lost in the petrochemical sector. It should be noted that the chemical industry has achieved productivity gains over the past few years, thereby raising the bar for incremental gains. Industrial analytics provide chemical plants with two important pieces of information. First, when an alert is generated with an accurate time to failure (TTF), plant maintenance staff can schedule repairs in a way that minimizes disruption to production. Secondly, root cause failure analysis helps limit the likelihood of the failure reoccurring elsewhere in the plant. A simple but powerful equation is driving the adoption of industrial analytics: lower machine downtime leads to higher yield rates and increased revenue. At present, many plant owners choose to over-invest in maintenance by using expensive, time-based preventive maintenance. The alternative of unscheduled downtime is both expensive and disruptive to operations. With advances in industrial analytics, chemical plants can receive early alerts of evolving failures, providing the opportunity to remediate before the degradation leads to a shutdown. In addition, root cause failure analysis maintenance crews can focus on the underlying reasons for failure. As a result, the life of a chemical plant asset can be extended. Of course, industrial analytics is only one element of an overall program to extend asset life. Plants may also need to reverse deterioration by performing heavy maintenance repairs and by using equipment as designed. Numerous factors will determine when the benefits of industrial analytics are fully realized. For example, many chemical plants are not capturing and storing the sensor data that is generated, which is the first step toward the implementation of machine learning-based solutions. Source: Hydrocarbon Processing, 2/2018, p.8.
TCGR Note: Of course this presents a solid case for industrial analytics, but it doesn’t present the other side of CAPEX, ROI and/or prioritize where analytics fits in. If the goal is to save 2% in reduced downtime or 2% on O&M budgets but the cost to maintain, analyze as well as pay for an expensive system needs to be considered. One needs to question is this money is better spent elsewhere.
Extract from 3/8/2015 CAP Communications (See full Chemical Week Magazine article here)
Refinery catalyst makers say demand has been solid. The future outlook for refinery catalyst demand is mixed, with tailwinds such as population and economic growth, low-sulfur regulations, and cheaper feedstocks being mitigated by higher fuel economy standards, biofuels, and, eventually, increased penetration of electric and hybrid vehicles. Refinery catalyst makers expect positive demand drivers to more than offset headwinds in the near-term. “The population around the world continues to grow, and GDP continues to increase. So demand for transportation fuels continues to rise,” says Mike Cleveland, global senior business director/catalysts, adsorbents and specialties, refining at Honeywell UOP. But while demand for refined petroleum products remains tied to macro trends such as how quickly economies are growing and trucking miles driven, there is a big “externality” surrounding the penetration of electric and hybrid vehicles, says John Murphy, president of The Catalyst Group Resources (TCGR; Spring House, Pennsylvania). “So the question becomes, when does this cause demand for liquid fuels to stop growing at 1–2% per year and hit 0–1% or less?” Forecasts for EV and hybrid penetration vary. Shell expects demand for gasoline could peak by the 2030s due to fuel-efficient cars and EVs. BP expects this to happen sometime in the 2040s. Many studies peg penetration at around 7.5% of the automotive pool by 2025. “It’s not going to happen as fast as some of the wild forecasts you see out there, for some simple reasons,” says Clyde Payn, CEO at The Catalyst Group. “There will be individual countries, like Sweden, where it might be higher, but the charging infrastructure for these vehicles is not in place, and is not easy to put in place.”
Meanwhile, the International Maritime Organization’s Marpol regulations—which aim to reduce sulfur content in marine fuels—will continue to be a driver of hydroprocessing and hydrotreating catalyst demand. “IMO implementation of MARPOL’s 0.5% [sulfur limit in] marine fuels on a broader basis globally means that you’re going to see more resid upgrading and more hydrotreating to get down to those low-sulfur limits,” Payn says. “This will have some impact on the transportation fuel sector globally, but we are already seeing decisions by some, particularly Middle Eastern refiners like Kuwait Refining and Adnoc, announcing investments to specifically address it,” Payn says. This isn’t surprising, given the region’s high export activity in fuels and chemicals. “They are going to have to meet these standards for lighter fuels faster than most,” he adds. There are several approaches seafaring vessels can use to address MARPOL, but adding scrubbers to a ship’s exhaust stack or retrofitting its engine to substitute for liquid natural gas are both capital-intensive, The Catalyst Group’s Murphy notes. “Switching to low-sulfur fuel is going to become the preferred route to addressing MARPOL,” he adds.
Crude Oil Alternative Conversions
A recent report by TCGR also revealed that increased interest in producing chemicals like olefins and aromatics directly from crude oil could blur the line between refiner and chemical producer. Aramco and SABIC are developing a $20-billion fully integrated crude–to–chemicals manufacturing complex in Saudi Arabia. It will be based at Yanbu and will process 400,000 b/d of crude oil and include a vacuum gasoil platform with capacity to produce approximately 9 million metric tons/year of chemicals and base oils. It is expected to start operations in 2025. Aramco has also signed a three-party joint development agreement with CB&I and Chevron Lummus Global for the development, commercialization, and marketing of crude-to-chemical technologies. “This is a disruption in the typical relationship that a refiner would have to serving the petrochemical markets,” Payn says. “You could have a chemical company who may not be back-integrated into refining considering the possibility of going direct oil-to-chemicals without being dependent on naphtha relationships upstream. That does have an indirect and a direct impact on how a refiner operates, and therefore, an impact on refining catalyst demand.” Source: IHS Chemical Week, 2/26-3/5/2018, p.19.
TCGR Note: For more information on how these trends will shape the catalysis industry in the medium-term, look for the 17th Biennial Edition of “The Intelligence Report: Business Shifts in the Global Catalytic Process Industries, 2017-2023.” For more information on the developments in the area of crude oil conversion directly to chemicals see TCGR’s new multi-client study, completed late last year, entitled “Oil-to-Chemicals: Technological Approaches and Advanced Process Configurations”.