IEA Key Gas & Oil Trends 2017

IEA Key Gas & Oil Trends 2017

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 Seeks Big Oil’s Help to Develop New Shale Discovery

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.

Shipowners’ Multibillion-Dollar Quandary: Buy Cleaner Fuel or a Fuel Cleaner?

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.

Business Trends: The Impact of Industrial Analytics on the Chemical Industry

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.

 

Refinery Catalysts Outlook

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.”

Marine Fuels
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”.

 

BP Energy Outlook 2018: Energy Demand Grows as Fuel Mix Continues to Diversify

The 2018 edition of BP’s Energy Outlook has been published and considers the forces shaping the global energy transition out to 2040 and the key uncertainties surrounding that transition. The speed of the energy transition is uncertain and the new Outlook considers a range of scenarios. Its “evolving transition” scenario, which assumes that government policies, technologies and societal preferences evolve in a manner and speed similar to the recent past, expects:
  • Fast growth in developing economies drives up global energy demand a third higher.
  • The global energy mix is the most diverse the world has ever seen by 2040, with oil, gas, coal and non-fossil fuels each contributing around a quarter.
  • Renewables are by far the fastest-growing fuel source, increasing five-fold and providing around 14% of primary energy.
  • Demand for oil grows over much of Outlook period before plateauing in the later years.
  • Natural gas demand grows strongly and overtakes coal as the second largest source of energy.
  • Oil and gas together account for over half of the world’s energy.
  • Global coal consumption flatlines and it seems increasingly likely that Chinese coal consumption has plateaued.
  • The number of electric cars grows to around 15% of the car parc, but because of the much higher intensity with which they are used, account for 30% of passenger vehicle kilometers.
  • Carbon emissions continue to rise, signaling the need for a comprehensive set of actions to achieve a decisive break from the past.

The Outlook considers several scenarios and explores the energy transition from three different viewpoints: fuels, sectors and regions. Go to www.bp.com/energyoutlook to download the Outlook or additional country & regional insights, and view other material. Source: BP, 2/20/2018.

India Plans to Raise Refining Capacity by 77% by 2030

Refiners in India, the world’s third-biggest oil consumer and importer, have drawn up plans to raise their capacity by 77% to about 8.8 MMbpd by 2030 to meet the country’s rising fuel demand. India is emerging as one of the key global drivers for refined fuels consumption as its economic expansion and rising industrial activity yields infrastructure improvements and increased energy access for commercial and retail consumers. If current patterns of use continue, India’s fuel demand could rise to as much as 335 million tonnes by 2030, and 472 million tonnes by 2040, from about 194 million tonnes last year, the oil ministry’s report says. The report also forecast a growth of 5 percent or more each year in India’s gasoline, diesel and jet fuel demand to 2030. The report recommended the refiners set up petrochemical projects and cut production of petcoke and fuel oil. Source: Hydrocarbon Processing, 2/9/2018.

TCGR Note:
While there is no doubt India’s growth in transport fuels demand could grow 5% pa through 2040 (which is an important consideration for our members), historically though, the refining infrastructure growth has been slower to date because of lower refining investment, particularly from international partners.

Topsoe Chosen as Technology Licensor of the World’s Largest Methanol Facility

IGP Methanol LLC (Houston; US) has awarded Haldor Topsoe A/S (Lyngby; Denmark) a contract for engineering of a methanol plant that will produce 1.8 million ton/yr, which is part of a planned complex with a total production capacity of 7.2 million ton/yr. Topsoe’s SynCOR Methanol technology will be at the core of the project. IGP plans to construct four identical SynCOR Methanol plants as part of their Gulf Coast Methanol facility in Plaquemines Parish, Louisiana (US). IGP’s Gulf Coast Methanol complex is planned to be the world’s largest methanol production facility and one of the most efficient and environmentally responsible. Source: Haldor Topsoe, 1/30/2018.

TCGR Note: Haldor Topsoe’s integrated SynCOR™ syngas solution is autothermal reforming process applying proprietary catalysts, equipment and engineering applicable to grassroots methanol, ammonia, GTL and H2 manufacture. At 5,000 mt/day it scale rivals the largest plants today. The closest competitors are Lurgi and JM for licensing.

Saudi Aramco, CB&I and Chevron Lummus Global Sign Joint Development Agreement to Demonstrate and Commercialize Thermal Crude to Chemicals (TC2C™) Technology

Saudi Aramco, through its wholly-owned subsidiary Saudi Aramco Technologies, has signed a three-party Joint Development Agreement (JDA) with CB&I, and Chevron Lummus Global (CLG), a joint venture between CB&I and Chevron U.S.A. The JDA will serve to scale up and commercialize Saudi Aramco’s Thermal Crude to Chemicals (TC2C™) technology. The TC2C™ technology has been pioneered at Saudi Aramco’s Research & Development Center over the past few years in order to enable higher chemicals yield than previously achievable. The technology also bypasses conventional refining steps by employing a proprietary direct conversion process. Source: Saudi Aramco, 1/18/18.

TCGR Note:
This is indeed an important future industry trend as refineries and integrated chemical complexes need to add more value-added chemicals production, because transportation fuels have become more threatened over the next decades due to the increasing adoption of EV’s/hybrids within the automobile industry. Need further information! See TCGR’s “Oil-to-Chemicals: Technological Approaches and Advanced Process Configurations” report completed in December, 2017!

 

The Future for Hydrocracking: Part 2

Refineries are gearing up to make more jet fuel/kerosene. For instance, PetroChina has said that it will build a new hydrocracking unit at its Golmud refinery in Qinghai province, China with the capacity to make 150,000 t/y (3200 b/d) of kerosene. The new unit was expected to start up in October 2017. Sinopec’s Fushun Research Institute of Petroleum and Petrochemicals (FRIPP) has developed a new generation of flexible hydrocracking catalyst. This features a smooth and open pore structure that significantly improves utilisation of the active centre, enhancing selective hydrocracking reaction capacity for flexible production of high quality chemical raw materials (high aromatic content heavy naphtha) and clean fuel products (CN-V standard clean diesel or its blending component and high quality jet fuel No. 3). HC-320 from UOP is said to possess superior activity and stability when compared to previous generation hydrocracking catalysts. In addition to diesel, HC-320 can yield ethylene cracker feed, jet A-1/kerosene, and high quality lube base stocks. HC-520 is the newest distillate selective hydrocracking catalyst offered by UOP in the Unity line. HC-520 utilises a new support technology and alternative metals compared to other Unity hydrocracking catalysts to boost the output of distillate. An unidentified grassroots refining/petrochemical complex in China has contracted Chevron Lummus Global (CLG) to license a number of its technologies. These include Isocracking, Isotreating and delayed coking technologies to produce a variety of products including diesel, jet fuel and heavy naphtha. The heavy naphtha will be fed to the petrochemical complex as feed for a BP paraxylene opex-advantaged crystallisation technology to produce paraxylene. A number of hydrocracking catalyst developers have also introduced new heavy naphtha maximisation catalysts in recent years. Heavy naphtha production from the hydrocracker has become more popular recently given expected long-term decline in demand for diesel and the ability of heavy naphtha from the hydrocracker to be fed to a catalytic reforming unit to yield high octane reformate for the gasoline pool or BTX: for instance, Albemarle’s KC 2715 hydrocracking catalyst, Axens’ Craken-Flex, Criterion Catalysts & Technologies’ Z-863, and Haldor Topsøe’s TK-971 zeolitic catalyst. Source: PTQ, Q1 2018, p. 25.

TCG Note: Worth a read! In related news, CLG has introduced a new scheme for a hydrocracker and base plant that’s been commercialized at Tatneft’s Taneco refinery in Russia, which will also be adopted by Pemex at Salamanca in Mexico.