Hydrocarbon Processing July 2014

We didn’t build the first Boiler. But in all your born days, you won’t find a manufacturer today that makes a boiler that performs better than a RENTECH boiler. It’s no yarn. Each of our boilers is custom-designed by RENTECH engineers and built in state-of-the-art facilities to operate efficiently in its unique application in a variety of industries. Our innovative, cost-effective technology will add value to your day-to-day operations with lasting benefits for the competitiveness of your business. Don’t wait another day, call us about your next boiler project.

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BONUS REPORT: LNG Data monitoring and simulation improve LNG transport and terminal design ®

HydrocarbonProcessing.com | JULY 2014

SPECIAL REPORT:

Refinery of the Future

CHANGING HPI ECONOMICS New conversion technology cuts ethylene production costs

We didn’t build the first Boiler. But in all your born days, you won’t find a manufacturer today that makes a boiler that performs better than a RENTECH boiler. It’s no yarn. Each of our boilers is custom-designed by RENTECH engineers and built in state-of-the-art facilities to operate efficiently in its unique application in a variety of industries. Our innovative, cost-effective technology will add value to your day-to-day operations with lasting benefits for the competitiveness of your business. Don’t wait another day, call us about your next boiler project.

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JULY 2014 | Volume 93 Number 7 HydrocarbonProcessing.com

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SPECIAL REPORT: REFINERY OF THE FUTURE 49

How to make anything with a catalytic cracker W. S. Letzsch and C. Dean

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Consider high-fidelity online motor fuel characterization M. Trygstad

59

Case history: Modernization of Russia’s refining industry—Part 1 V. V. Galkin, V. Makhianov and M. I. Levinbuk

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Which margin levers impact Group I and Group II base stock competitiveness?—Part 2

DEPARTMENTS 4 10 21 85 86 88 90

COLUMNS 9 Editorial Comment What is the ‘refinery of the future’?

I. Moncrieff

BONUS REPORT: LNG 71

How sensitive is your treating plant to operating conditions? R. Weiland, J. Santos, A. Praderio, N. Maharaj and M. Schultes

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Ethanol-to-ethylene process provides alternative pathway to plastics

29

Project Management What skills will project managers need in the next decade?—Part 1

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Global The reshaping of Latin America’s petrochemical industry

C. Moffatt, S. Hodge and D. Cook

35 Cover Image: Eni’s Venice biorefinery is the first refinery in the world to convert from a conventional refining complex into a biofuel production operation based on the company’s patented Ecofining technology. The refinery is producing mainly high-quality green diesel in balance with the available hydrogen from the former hydroskimming unit. After 2015, the refinery’s biofuel production will be maximized to achieve 500,000 tpy with the addition of a dedicated hydrogen plant.

Automation Strategies HPI demands higher availability of rotating equipment

HPI FOCUS: CHANGING HPI ECONOMICS 81

Reliability Things to know and do before starting new initiatives

Maximize LNG carrier efficiency through integrated optimization P. Guillemin

Industry Perspectives News Industry Metrics Events Marketplace Advertiser Index People

Petrochemicals Major US players bet on propane dehydrogenation

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Gas Processing Eastern nations look to LNG for energy, environmental solutions

41

Boxscore Construction Analysis South Africa—Africa’s clean fuels leader?

45

Viewpoint The journey to a value-adding refinery project

www.HydrocarbonProcessing.com

Industry Perspectives Tale of two continents Growing supplies by non-OPEC countries has introduced some calm for crude oil prices. However, other factors are influencing profitability and margins. In the US, the abundance of shale oil and the 40-year ban on exporting crude oil has created unusual conditions. Now, North American refineries have an advantage as compared to European refiners. According to a new US Energy Information Administration report, companies with refineries primarily located in North America are reaping $6/bbl in profits as compared to those operators with assets in Europe. As illustrated in FIG. 1, the shift in earnings potential began in 2010. That is the same time in which significant supplies of shale oil began entering the North American market. This trend also coincides with the economic recovery of the US. Some of the additional profits can be attributed to the discounting of WTI due to infrastructure bottlenecks. However, these perks will dissipate as more effective distribution infrastructure evolves. According to a recent Wood Mackenzie study, US demand for refined transportation fuels increased on average about 400,000 bpd in 2013. Much of the new demand is for diesel. However, looking forward, the demand increase for diesel will moderate and gasoline demand will effectively endure losses of 200,000 bpd beginning in late 2015.

Company earnings per bbl processed, 2013, $/bbl

ACROSS THE POND The European refining industry contends with a difficult environment. Much of this region’s refineries were configured for gasoline production. The full effects from dieselization are now being seen. Result: Europe must import diesel to meet regional demand. From an economics position, European refiners are at a disadvantage to refine more crude to produce much-needed diesel and coproduce more unwanted gasoline. For Europe, the supply and demand situation for transportation fuels is out of balance, and utilization rates are below 80%, thus compounding the situation further (see Industry Metrics, pg. 21). The true winners are those refiners that can export high-quality refined products to Europe at this time.

Bret Ronk [email protected]

EDITORIAL Editor Managing Editor Reliability/Equipment Editor Technical Editor Online Editor Associate Editor Director, Data Division Contributing Editor Contributing Editor Contributing Editor

Stephany Romanow Adrienne Blume Heinz P. Bloch Billy Thinnes Ben DuBose Helen Meche Lee Nichols Loraine A. Huchler William M. Goble ARC Advisory Group

MAGAZINE PRODUCTION Vice President, Production Manager, Editorial Production Artist/Illustrator Graphic Designer Manager, Advertising Production

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12 Companies with refineries mainly in North America

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PUBLISHER

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Companies with refineries throughout the world

2 Companies with refineries mainly in Europe

0 -2 2004

2005

2006

2007

2008

2009

2010

2011

2012

2013

Source: US Energy Information Administration, based on Evaluate Energy database *Note: 2014 includes data for the first quarter of 2014

FIG. 1. Earnings for refineries in different regions, 2004–2014.

2014*

President/CEO Vice President Vice President, Production Editor-in-Chief Business Finance Manager

Part of Euromoney Institutional Investor PLC. Other energy group titles include: World Oil and Petroleum Economist. Publication Agreement Number 40034765

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John Royall Ron Higgins Sheryl Stone Pramod Kulkarni Pamela Harvey

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Velocys

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Wednesday, July 30, 2014 Agenda 7:30 a.m. 8:30 a.m. 8:45—9:15 a.m. 9:15—9:40 a.m.

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REGISTRATION OPENING REMARKS: John Royall, President and Chief Executive Officer, Gulf Publishing Company KEYNOTE PRESENTATION: TBD The Economics of Monetizing North American Natural Gas Tom Jones, Manager of Studies, Bechtel Hydrocarbon Technology Studies, Inc. COFFEE BREAK

SESSION ONE: SYNGAS 10:10—10:35 a.m. Co–processing of Waste CO2 with Natural Gas to Produce High Value Transport Fuels Paul E Koppel, Vice President, Process Technology, Fluor Enterprises 10:35—11:00 a.m. Autothermal Reforming—a Preferred Technology for Conversion of Natural Gas to Synthesis Gas in Industrial GTL Applications Soren Martin Olsen, Haldor Topsoe 11:00—11:25 a.m. Partial Oxidation Gas–Turbine Based Turbo–POx Syngas Generation Technology for GTL Applications Dr. Steven Fusselman, Program Manager– Energy Services, Aerojet Rocketdyne and Dr. Arunabha Basu, Institute Engineer, Gas Technology Institute 11:25—12:25 p.m. LUNCH SESSION TWO: THE FUTURE OF NON–FT GTL 12:25—12:50 p.m. CO2 and CO Fermentation: A Route from Waste to Fuels and Chemical Building Blocks at Scale Dr. Michael Schultz, Vice President, Engineering, LanzaTech, Inc 12:50—1:15 p.m. A New Era in GTL: Cost–Effective Technology Enables Conversion of Natural Gas to Drop–In Liquid Fuels at Small Scale Dr. George Boyajian, Vice President, Business Development, Primus Green Energy 1:15—1:40 p.m. TBD 1:40—2:10 p.m. COFFEE BREAK SESSION THREE: WHAT’S NEW IN SMALL–SCALE GTL 2:10—2:35 p.m. Microchannel Fischer–Tropsch Reactors: Enabling Smaller Scale GTL Jeff McDaniel, Commercial Director, Velocys 2:35—3:05 p.m. Case Study: GTL Technology Development—The Optimal Path to Micro–GTL Commercialization Ebrahim Salehi, Process Engineer, Hatch 3:05—4:20 p.m. PANEL DISCUSSION: MODULAR GTLS Invited participants include: EmberClear, Oberon Fuels, Velocys and others 4:20 p.m. CLOSING REMARKS: John Royall, President and Chief Executive Officer, Gulf Publishing Company

Thursday, July 31, 2014 Agenda 7:30 a.m. 8:30 a.m. 8:45—9:15 a.m.

9:15—9:40 a.m.

9:40—10:10 a.m.

REGISTRATION OPENING REMARKS: Stephany Romanow, Editor, Hydrocarbon Processing KEYNOTE PRESENTATION: The Economics of Gasto-Liquid Conversion Technologies: Annual Energy Outlook 2014 Vishakh Mantri, Ph.D., P.E., P.M.P., Office of Petroleum, Natural Gas and Biofuels Analysis, U.S. Energy Information Administration Economics of Ammonia Production from Off–Gases V.K. Arora, Director–Process & Operations, Kinetics Process Improvements, Inc. COFFEE BREAK

SESSION FOUR: EMERGING TECHNOLOGY AND FUTURE USERS 10:10–10:35 a.m. Mixed Alcohols as an Oxygenate and Fuel Extender Peter Tijm, Chief Technology Officer, Standard Alcohol Company 10:35–11:05 a.m. Case Study: Refinery Integration with Gasification Dr. K.S. Balaraman, Chief Consultant, Wissenschaftler Consulting Engineers 11:05–11:30 a.m. Methanol to Gasoline Technology - an Alternative for Liquid Fuel Production Mitch Hindman, ExxonMobil Research & Engineering Company 11:30–11:55 a.m. TBD 11:55–12:55 p.m. LUNCH SESSION FIVE: CATALYSTS 12:55–1:20 p.m. Effect of Addition of Zeolite to Iron–Based Activated–Carbon–Supported Catalyst for Fischer– Tropsch Synthesis in Separate Beds and Mixed Beds Avinash Karre, Jacobs Engineering 1:20–1:45 p.m. The New CatFTTM Process, Dr. Thomas Holcombe, President & CEO, Green Impact Fuels, LLC 1:45–2:10 p.m. Revolutionary Fixed Bed Reaction System for GTL FT/MeOH/DME Tim Gamlin, V.P. Gas Conversion, Johnson Matthey Davy Technologies Ltd 2:10–2:40 p.m. COFFEE BREAK SESSION SIX: MODULAR CONSTRUCTION 2:40–3:05 p.m. TBD PANEL DISCUSSION: MODULAR CONSTRUCTION 3:05–4:05 p.m. Invited participants include Chemex, Zeton, Maverick Synfuels and others 4:05 p.m. CLOSING REMARKS: John Royall, President and Chief Executive Officer, Gulf Publishing Company

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Editorial Comment

STEPHANY ROMANOW, EDITOR [email protected]

What is the ‘refinery of the future’? For years, technology experts and engineers have discussed the elements and operations that will define the refinery of the future. The refining industry has made great progress from the early days. However, old and older does not directly correspond to being obsolete. The American Refining Group (ARG) Inc. still operates the oldest continuously running US-based refinery at Bradford, Pennsylvania. This 10,000-bpd refinery began operations in 1881, and it still produces high-quality waxes, lubricant base oils, gasoline and fuels, as well as a wide variety of specialty products. Much has changed in the 130-plus years since this ARG refinery began, and it continues to upgrade Pennsylvania crude into consumer products. By definition. “The refinery of the future is a place where advanced technologies and highly skilled workers will raise to new levels the standards for efficiency, safety and plant intelligence,” said Lance Gyorfi, vice president of refining, Chevron Products Co. He made that statement in 1998 at Chevron’s Salt Lake City, Utah, refinery, when this site was celebrating its 50th anniversary. Gyorfi also said, “Future refineries will meet society’s transportation needs, regardless of how vehicles are powered. They (refineries) will also adapt to a changing slate of raw materials.” In 1998, refineries and petrochemical plants had made huge changes in operations, methodologies and automation. At that time, instrumentation, automation and software companies pushed through old boundaries regarding the connectivity of process information and control, and laid the foundation to bring more “intelligence” to the field and process equipment. That trend still continues. Moving forward. In 2003, an HP editorial discussed the digital refinery or petrochemical facility as the future. To get to the digital age, the HPI would rely on continued improvement and innovations

for process technologies, catalysts, equipment, automation and software. The digital age used advanced communication systems that moved the intelligence to field devices. The information/monitoring network no longer needed direct input from operators. Through advanced computers, software development and miniaturization, operators could now focus on other tasks to increase profitability. Developments. A key to better operations involves improvements between the operator and machine (process) interfaces. Refineries operate on a 24/7 schedule; keeping plant staff at 100% efficiency, especially during night operations, remains a problem. Honeywell has addressed this problem with a new control room console, the Experion Orion Console. This new console uses a large, flexible, ultra-highdefinition display that provides clear status assessments of the process for the operators’ needs (FIG. 1), thus improving their performance on the job, which impacts the safety and efficiency of the facility. The refinery of the future involves both technology and the changing roles of people. Together, amazing tasks can be accomplished; this means that better products, more efficient operations and safer facilities are possible.

INSIDE THIS ISSUE

45 

projects are a means of creating value from assets. The more thorough a project’s planning and management, the more successful it is likely to be. Süleyman Özmen, vice president of refining and chemical licensing for Shell Global Solutions International BV, discusses the journey to ensure that your investment plans remain technically and economically robust in the new environment.

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Refinery of the future.

70 

Bonus report: LNG.

How will crude oil refineries operate in the future? To be profitable, refiners must have the flexibility to adapt to numerous forces; many are beyond the control of the industry. Here are a few new technologies and trends now shaping the international refining industry.

The natural gas market is dominated by upstream development in shale gas production, particularly in North America, and by downstream progress in liquefied natural gas (LNG) technologies and projects. The July bonus report features advances in technologies and market developments for LNG.

81  FIG. 1. Experion Orion Console brings the plant control room of the future to life by meeting the changing needs of the increasingly mobile plant operator.

Viewpoint. Capital

HPI focus: Changing HPI economics.

Tight operating margins make the ethanol-to-ethylene technology marketplace a challenging space in which to compete. However, a secondgeneration route has emerged that can deliver market-leading conversions at lower cost and complexity than existing technologies. Hydrocarbon Processing | JULY 20149

| News API releases three new standards to improve refinery safety The American Petroleum Institute (API) issued three new first-edition standards to enhance refinery safety and inspection programs: • RP 583, Corrosion under insulation and fireproofing: This standard will assist with industry inspection and allow maintenance personnel to fully understand the complexity of corrosion under insulation and fireproofing, as well as the subsequent ways to reduce its occurrence at refineries • RP 584, Integrity operating windows: A key part of process safety is the facility’s inspection program, and this standard was written to assist industry in developing the most efficient and effective inspection program based on each unit’s unique operational history • RP 585, Pressure equipment integrity incident investigation: This standard describes how an effective investigation can be structured so organizations can learn from each incident and use this knowledge to reduce the likelihood of future incidents.

BILLY THINNES, TECHNICAL EDITOR [email protected]

News

The European Commission presented a report on European energy security to the European Council in late June. The report points out that the EU’s energy dependence is not new, but it did gain an added dimension in the light of recent geopolitical events (specifically the Ukrainian crisis). Temporary disruptions of gas supplies in the winters of 2006 and 2009 already provided a wake-up call for the EU, underlining the need of infrastructure development, increased cooperation and of a common European energy policy. Since then, the EU has worked to strengthen its energy security in terms of gas supply. However, the work is not completed yet and further steps are needed. The EU’s energy import dependence has been on the rise since the mid-1990s. Today, the EU spends more than €1 billion every day on importing energy. This is almost a fifth of the EU’s total import bill. In 2012, 53% of the EU’s energy consumption was linked to imports (FIG. 1). In particular, the EU imported 88% of crude oil, 66% of natural gas, 42% of solid fuels (coal, lignite and peat) and 95% of uranium. Who supplies the EU with oil? Based on the latest figures from 2013, a third of imports came from Russia, 11% from Norway and 8% from Saudi Arabia. The EU paid about €300 billion for the crude oil imports. On the subject of gas supply, the 2013 figures show about 39% of imports came from Russia, 34% from Norway and 14% from Algeria. Six EU member states depend on Russia for their entire imported gas supply: Finland, Slovakia, Bulgaria, Estonia, Latvia and Lithuania. In the realm of solid fuels, about 26% of imports came from Russia, 24% from Colombia and 23% from the US. About 240 million tons of solid fuels were imported in the EU in 2012, of which approximately 220 million tons came from non-EU countries.

EU energy mix. Overall, a gradual de-

crease in solid fuels consumption and a growth in the use of renewables can be observed for all EU member states. In 2012, EU energy demand stood slightly above 1,700 million tons of oil equivalent (MMtoe), almost 130 MMtoe below the 2007 pre-crisis level, and similar to 1995 levels. Petroleum products provide 34% of the EU’s energy. The bloc is the second largest oil consumer in the world after the US. Most of it is used in transport (95% of transport fuel comes from oil) and the petrochemical industry. Gas provides 23% of the EU’s energy. Gas is mainly used for heating and in electricity production. Almost 19% of all the electricity generated in the EU comes from gas. The residential and service sectors account for approximately 40%, while industry accounts for about 25% of gross inland consumption. Solid fuels contribute 17% to the EU energy mix. The EU is the third-largest coal-consuming region, after China and North America. Solid fuels are mostly used in electricity production and district heating plants. Europe relies on nuclear for 13% of its energy needs, with 27% of its electricity coming from nuclear sources from plants

in France, the UK, Sweden, Germany, Belgium and Spain. Compared to other world regions, the EU has few fossil fuel resources. At the end of 2012, the EU’s proved oil reserves amounted to only 0.4% of global reserves. Its natural gas reserves amount to 0.9% of global reserves, and coal reserves form 6.5% of global reserves. Comprehensive information on shale gas reserves is not yet available, as exploration is still at an early stage. Between 1995 and 2012, the EU’s primary energy production decreased by almost one-fifth. Natural gas production dropped by 30%, production of crude oil and petroleum went down by 56% and production of solid fuels decreased by 40%. Renewable energy production, on the other hand, has significantly grown during recent years; renewables account for 22% of primary energy production. Increasing the security of supply has been an overarching goal of the EU energy policy for several years. Since the gas crisis in the winters of 2006 and 2009, the Commission has worked to strengthen the EU’s energy security in terms of gas supplies and to reduce the number of member states exclusively dependent on one supplier. Significant progress has been made toward the

60

50

Others Renewable energies Crude oil

Solid fuels Natural gas

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%

Security of energy supply in the EU

30

20

10 0 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 Source: ESTAT SIRENE v2

FIG. 1. Share of EU energy imports, %. Hydrocarbon Processing | JULY 201411

News completion of an internal energy market. Rules for network use have been put in place to avoid congestion in cross-border infrastructure. Another important step to secure uninterrupted supplies in case of external supply disruption involves installing reverse flow options that provide a possibility to operate the pipelines in both directions. To further the EU’s energy security, the report recommends a risk assessment

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(energy security stress test) of the EU energy system to identify supply disruption risks in the upcoming winter. This would be conducted on the regional or EU level by simulating a disruption of the gas supply. The aim is to check how the energy system can cope with security of supply risks and, based on that, develop emergency plans and create backup mechanisms. The exact details of these stress tests have not yet been agreed upon.

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A new way to harness waste heat Vast amounts of excess heat are generated by industrial processes, and researchers around the world have spent decades seeking ways to harness some of this wasted energy. Most such efforts have focused on thermoelectric devices (solid-state materials that can produce electricity from a temperature gradient), but the efficiency of such devices is limited by the availability of materials. Now researchers at MIT and Stanford University have found a new alternative for low-temperature waste-heat conversion into electricity, in cases where temperature differences are less than 100°C. The new approach, based on a phenomenon called the thermogalvanic effect, is described in a paper published in the journal Nature Communications by a collection of postdocs and professors at Stanford and MIT. Since the voltage of rechargeable batteries depends on temperature, the new system combines the charging–discharging cycles of these batteries with heating and cooling, so that the discharge voltage is higher than charge voltage. The system can efficiently harness even relatively small temperature differences, such as a 50°C difference To begin, the uncharged battery is heated by the waste heat. Then, while at the higher temperature, the battery is charged. Once it is fully charged, it is allowed to cool. Because the charging voltage is lower at high temperatures than at low temperatures, once it has cooled, the battery can actually deliver more electricity than what was used to charge it. That extra energy, of course, doesn’t just appear from nowhere—it comes from the heat that was added to the system. The system aims at harvesting heat of less than 100°C, which accounts for a large proportion of potentially harvestable waste heat. In a demonstration with waste heat of 60°C, the new system has an estimated efficiency of 5.7%. The basic concept for this approach was initially proposed in the 1950s, but a key advance is using material that was not around at that time for the battery electrodes, as well as advances in engineering the system. That earlier work was based on temperatures of 500°C or more, while most

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News current heat-recovery systems work best with higher temperature differences. While the new system has a significant advantage in energy-conversion efficiency, for now it has a much lower power density (the amount of power that can be delivered for a given weight) than thermoelectrics. It also will require further research to assure reliability over a long period of use, and to improve the speed of battery charging and discharging.

“Virtually all power plants and manufacturing processes, like steelmaking and refining, release tremendous amounts of low-grade heat to ambient temperatures,” the researchers said in a statement. “Our new battery technology is designed to take advantage of this temperature gradient at the industrial scale. Plus, this technology has the additional advantage of using low-cost, abundant materials and manufacturing processes 19

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that are already widely used in the battery industry.”

Asia to remain dominant force in chemical production Global spending on chemical production capacity additions will peak in 2014 at $120 billion and then begin to decline, according to analysis from IHS. Asia, and China in particular, long the epicenter of global chemical supply and demand, will remain the dominant global force for chemicals beyond 2020. However, Asia will feel the pinch as some capacity additions shift to North America and the Middle East, where feedstocks are less costly—thanks, in part, to unconventional shale energy. “Our analysis shows that global spending on capacity additions will peak in 2014 and then begin to decline,” said Russell Heinen, director of technology and analytics at IHS Chemical. “Since spending precedes capacity additions coming onstream, spending starts to decline prior to the drop in capacity additions. As for Northeast Asia, and especially China, they are still giants in terms of chemical production and demand, and will continue to account for a significant share of future global capacity additions. However, the rate of capacity additions in the region will decline. “Asian producers are starting to feel the effects of an economy that is growing more slowly, but also the impacts of the feedstock cost advantages that their competitors enjoy in the Middle East and in North America. In response, Chinese chemical producers are adding coal-based capacity to take advantage of the one lowcost feedstock they have.” During the last decade, chemical capacity additions on a global basis have largely been driven by Northeast Asia. Since 2000, the world has added nearly 1 billion metric tons of total chemical capacity and Northeast Asia, specifically China, has accounted for more than 70% of this increase, which was driven by the rapid economic growth in China. However, this trend is changing—and overall chemical capacity additions will peak in Northeast Asia in 2014. Capacity additions in North America, which had been very minimal for the last 20 years, Heinen said, are increasing due to the change in feedstock position caused by unconventional development.

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News “We currently expect capacity additions in the US to peak at more than 15 million (MM) metric tons in 2017, accounting for about 20% of the world’s additions,” he said. Despite a reduction in spending on new capacity, China’s contributions to global production will continue to impress. IHS Chemical estimates that, during the period 2000 to 2020, China will grow its basic chemicals capacity pro-

duction (which includes benzene, chlorine, methanol, propylene and ethanol) by nearly 170 MM metric tons. In other words, China will add 47% of the estimated global total additions expected for basic chemical production during the period. The two next largest producing countries for expected capacity additions in basic chemicals during the same period are Saudi Arabia, at 7% additions, followed by the US at 6%.

“From 2013 to 2018, China is going to add 9 MM metric tons of domestic polyethylene capacity alone, which is significant,” said Nick Vafiadis, senior director, global olefins and plastics at IHS Chemical. “Equally significant is the fact that much of this new production capacity will be quite competitive on a cash-cost basis due to advances in coal-to-olefins technologies.”

Iraqi Kurdistan exports first crude cargo via Turkey Several weeks before the ISIS terrorist army began its chaotic and deadly incursion into Iraq from war-torn Syria, Iraqi Kurdistan exported its first cargo of crude oil through Turkey’s Mediterranean port of Ceyhan. This was despite a long-standing dispute with Baghdad over the sharing of oil revenues. Reuters reported that the first 1 million-barrel cargo of piped oil was loaded in Ceyhan, where around 2.5 million barrels of Iraqi Kurdish crude has been stored. The sale was carried out by the Kurdistan Regional Government. Baghdad’s central government claims the sole authority to manage and sell Iraqi oil. Months of talks between the semi-autonomous enclave and the central government have made little progress. Iraqi Kurdistan sent the oil into storage tanks at Ceyhan through a new pipeline in which crude flow started last December. The Turkish government had been waiting for Baghdad’s approval before allowing the independent oil exports. But Turkey felt it had allowed enough time for diplomacy and that there was little point in delaying further.

US EPA advisory committee suggests tightened ozone standards The US Environmental Protection Agency’s (EPA’s) Clean Air Scientific Advisory Committee (CASAC) has decided that the agency should tighten its ozone national ambient air quality standard (NAAQS) from 75 parts per billion (ppb) to a range between 60 ppb and 70 ppb. The CASAC also agreed to suggest to the EPA that a range of 60 ppb to 65 ppb is preferable. The overall 60-ppb to 70-ppb range for the primary helth-based standard is similar to the range that CASAC support16

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News ed in 2008, when the Ozone NAAQS was last revised. Several environmental and health groups are urging the EPA to set a standard no higher than 60 ppb.

Bakken crude properties are similar to other types of light oil The American Fuel & Petrochemical Manufacturers (AFPM) has released findings from a new report that examines the characteristics of Bakken crude oil and the standards required to transport by rail. The report results demonstrate that Bakken crude is well within the safety standards for current rail car designs. More specifically, Bakken crude is comparable to other light crudes and does not pose risks that are significantly different than other crudes or flammable liquids authorized for rail transport. In particular, Bakken crudes are well within the regulatory limits for pressure, flashpoint, boiling point and corrosivity for use in US Department of Transportation (DOT) approved railcars. The data clearly show that the current classification of Bakken crude oil is accurate and appropriate. Bakken crude oil is designated as a flammable liquid under the Hazardous Materials Regulations (HMR) and, as such, is subject to evaluation of its flashpoint and initial boiling point for classification purposes. While Bakken crude and other light crudes may contain higher amounts of dissolved flammable gases compared to some heavy crude oils, the percentage of dissolved gases would not cause Bakken crude to be transported under a DOT hazard class other than Class 3 Flammable Liquid. Therefore, the report says there is no need to create a new DOT classification for crude oil transportation. The maximum vapor pressure observed, based on data collected, was 61% below the vapor pressure threshold limit for liquids under the HMR, demonstrating that Bakken crude oil is properly classified as a flammable liquid. Further, the highest reported value was more than 90% below the maximum pressure that DOT111 rail cars were built to withstand. “The US is very fortunate to be experiencing an increase in domestic energy production and, as a result, more crude oil is being shipped by rail,” said AFPM President Charles T. Drevna. “Although, the transportation of crude oil by rail is extremely safe, we strive to make con-

tinuous improvements and work toward a zero incident rate.” The report is based on a survey of AFPM members conducted in response to information requested by the DOT. In a letter to Cynthia Quarterman, administrator of DOT’s Pipeline and Hazardous Materials Safety Administration (PHMSA) sent in late February, AFPM confirmed that the process was underway to obtain the data necessary to inform future regu-

latory actions. AFPM members were surveyed to determine whether Bakken crude oil poses substantially different transportation risks compared to other crude oils transported by rail. In addressing concerns raised by the DOT, data was collected stemming from an analysis of approximately 1,400 samples of Bakken crude oil. “Rail safety is a shared responsibility and AFPM is committed to doing our part,” said Mr. Drevna.

Select 154 at www.HydrocarbonProcessing.com/RS

19

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HP STAFF [email protected]

Industry Metrics Global refining margins, 2013–2014* 40 35 30 25 20 15 10 5 0 -5

6 4 3 2 1 0

A M J J A S O N D J F M A M J J A S O N D J F M A 2012 2013 2014

90 80 70

US EU 16

Japan Singapore

Selected world oil prices, $/bbl US Gulf cracking spread vs. WTI, 2013–2014*

World liquid fuel supply and demand, MMbpd

May 14

Feb 14

Jan 14

Dec 13

Nov 13

Oct 13

Sep 13

Apr 14

May 14

Apr 14

Mar 14

2015-Q1

Feb 14

2014-Q1

Jan 14

2013-Q1

Dec 13

2012-Q1

-10 -20 -30 Nov 13

2011-Q1

Gasoil, 10 ppm S Fuel oil, 1% S

Oct 13

2010-Q1

Prem. gasoline unl., 10 ppm S Jet/kero

0

Sep 13

-1.0 -1.5

10

Aug 13

0.0 -0.5

20

Jul 13

0.5

30 Cracking spread, US$/bbl

1.0

Gasoil/diesel, 0.05% S Fuel oil, 1% S

Rotterdam cracking spread vs. Dubai, 2013–2014*

May 13

Forecast

Stock change and balance World consumption World production

2.0 1.5

Stock change and balance, MMbpd

96 94 92 90 88 86 84 82 80 78 2009-Q1

Aug 13

Source: DOE

A M J J A S O N D J F M A M J J A S O N D J F M A 2012 2013 2014

Jun 13

60 45

Jul 13

W. Texas Inter. Brent Blend Dubai Fateh

Jun 13

90

Prem. gasoline unl. 93 Jet/kero

May 13

105

75

60 50 40 30 20 10 0 -10

Cracking spread, US$/bbl

120

Mar 14

135 Oil prices, $/bbl

May 14

Apr 14

Mar 14

Feb 14

Jan 14

Dec 13

Nov 13

Oct 13

Sep 13

Aug 13

Jul 13

May 13

60

Production equals U.S. marketed production, wet gas. Source: EIA.

Supply and demand, MMbpd

May 14

Apr 14

Mar 14

Feb 14

Jan 14

Dec 13

Nov 13

Oct 13

Sep 13

Aug 13

100

Jun 13

Monthly price (Henry Hub) 12-month price avg. 12-month price avg. Production

Global refining utilization rates, 2013–2014* Utilization rates, %

5

Jul 13

May 13

7

Gas prices, $/Mcf

Production, Bcfd

US gas production (Bcfd) and prices ($/Mcf) 80 70 60 50 40 30 20 10 0

WTI, US Gulf Dubai, Singapore Arab Heavy, US Gulf LLS, US Gulf Brent, Rotterdam

Jun 13

Margins, US$/bbl

Global energy markets are reaching a new equilibrium, according to Wood Mackenzie analysts. As demand shifts to the East, it will expand to extraordinary proportions. However, the world finds itself in an era of robust energy supplies. A shift from volume to value is rebalancing the energy market to a “supply-push” condition as demand softens. New non-OPEC supplies are contributing to the situation. After the mid-June 2014 meeting, OPEC countries announced that the nations will keep the target production at 30 million bpd for another six months.

Source: EIA Short-Term Energy Outlook, June 2014.

Singapore cracking spread vs. Brent, 2013–2014* Brent Dated vs. sour crudes (Urals and Dubai) spread, 2013–2014*

Cracking spread, US$/bbl

30

6 4

10 Prem. gasoline unl. 92 Jet/kero

0

Gasoil, 50 ppm S Fuel oil, 180 CST, 2% S

02 Jan 09 Jan 16 Jan 23 Jan 30 Jan 06 Feb 13 Feb 20 Feb 27 Feb 06 Mar 13 Mar 20 Mar 27 Mar 03 Apr 10 Apr 17 Apr 24 Apr 01 May 08 May 15 May 22 May 29 May 05 Jun

May 14

Apr 14

Mar 14

Feb 14

Jan 14

Dec 13

Nov 13

Oct 13

Sep 13

Aug 13

Jul 13

Dubai Urals

Jun 13

-10 -20

2

0 -2

20

May 13

Light sweet/medium sour crude spread, US$/bbl

8

* Material published permission of the OPEC Secretariat; copyright 2014; all rights reserved; OPEC Monthly Oil Market Report, June 2014. Hydrocarbon Processing | JULY 201421

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See how SimSci APC 2014 really cuts it by visiting Software.invensys.com/SimSciAPC for your own custom demo. Select 96 at www.HydrocarbonProcessing.com/RS © 2014 Schneider Electric, All Rights Reserved. Schneider Electric, SimSci and SimSci APC 2014 are owned by Schneider Electric, or its affiliated companies in the U.S. and other countries.

Reliability

HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR [email protected]

Things to know and do before starting new initiatives HP editors frequently attend technical conferences to keep informed on the many factors impacting the hydrocarbon processing industry (HPI). The focus of these conferences often differs. However, one particular conference on failure analysis stands out. No exhibitors were present at the event; the majority of the presenters were users or beneficiaries of best-of-class (BOC) root-cause failure analysis methods. The core of the program concentrated on two or three best root-cause failure analysis methods available. Accidents remain an issue. The HPI

still struggles with accidents according to a Chemical Safety Board (CSB) statistic. In the report, the CSB noted the “considerable frequency of significant and deadly incidents at refineries over the last decade.” In 2012 alone, the CSB tracked 125 significant incidents at US petroleum refineries.1 These are disappointing findings. One solution is encouraging HPI management to invest more in training budgets such as technical conferences and workshops. Failure avoidance and safety are inseparable. The mix is a key ingredient to responsibly achieving and sustaining profitability. Continuing education. HP editors also attend reliability-focused forums. These conferences offer different programs. A recent conference incorporated about 80 vendor-exhibitors. A high percentage of the event presentations were closely associated with the exhibitors. Impressive products on view included compact accelerometers and underwater velocity sensors. These and other components have migrated from the aerospace industry to the process and manufacturing industries. Much of this technology transfer will benefit the HPI. More importantly, there are an impressive number of new companies and consultancies now entering the reliability field. Terminology. Exhibitors often use attention-getting terms in their quest to

attract clients. The old “lean and mean” mantra has run its course. A number of exhibitors now select company names or designations that promise “optimization,” “detection,” “compliance,” “management,” “reliability ecosystems,” “automated” and so forth. There is a market for collective, as well as detailed reliabilityfocused, programs. Vendors want to sell “new” initiatives that are really older products or programs with updated names. Using an admittedly sweeping generalization, we characterize these companies as upbeat purveyors of implementation strategies for unrealistically optimistic clients. Both purveyors and clients obviously desire low-budget fixes for persistent problems. But to the experienced and informed, the clients’ problems are often very deeply rooted in past indifference and neglect—which begs the question: Who will do the uprooting?

from being average to becoming BOC performers have to be ethical, competent and highly motivated. Such employees and their managers must make important contributions before either project content or monetary appropriations are finalized. These employees will ensure that the projects include safety and reliability and are solidly based on the cost of reliable equipment, and not just on the lowest initial bid. In other words, the cost-estimating manuals at the core of such projects must reflect pricing for a reliable plant—especially reliable machinery. A realistic project budget estimate must also include the cost of machinery quality assessments (MQAs).2 Remember: You get what you inspect, not what you expect. Implementing and conducting MQAs will typically require a 5% addition to the as-purchased cost for reliable machines. This incremental outlay will often be retrieved within a year.

An observation. Some conferences give

much visibility to newly formed consultancies. These companies offer expertise in operational excellence (OE), a close cousin to asset management. There is nothing wrong with parties seeking, and offering, such visibility. Yet, the existing and potential OE consumer-clients will make progress only if they finally start to address the more fundamental issues. These companies should implement wellfocused efforts to learn and become more fully informed. The word “learning” prompts another key point on OE—be fully aware of your conditions that will shape the final outcome. There are a few solid prerequisites to developing meaningful and sustainable OE programs. Prerequisites to successful initiatives and pursuits are never optional; they are unalterable and non-negotiable requirements. These prerequisite requirements involve hiring, grooming, empowering, compensating, retaining and rewarding the right people. The men and women who will move entire facilities

Initiative success. When examining

reliability improvement and failure avoidance needs for an HPI facility, let’s be sure of one fact: The next “initiative”—by any name or acronym—can be successful only if and when the stated prerequisites are in place. These prerequisites involve intelligent hiring, nurturing, empowering, compensating, retaining and rewarding the right people. The managers authorizing the prerequisites mentioned above must give guidance by demonstrating personal ethics, competence and persistently high motivation. Every one of these commendable attributes is required from the top to bottom layers for a successful organization. Because people with these attributes cannot be acquired or trained on short notice, each prerequisite is a highly tangible long-range action step. Companies and management must stop looking for the “magic bullet,” and organizations must cultivate a new environment for OE and reliability. Unfortunately, there will Hydrocarbon Processing | JULY 201423

Reliability still be those managers who still seek out a “magic bullet” solution. In truth, there really is no cheap implementation route. There are no effective, yet previously unknown, quick-fix initiatives. Back to basics. To achieve effective results, HPI companies must use only the best available investigation and root-cause failure analysis (RCFA) processes. No one single RCFA process suits all situations.

Organizations must discover and report the root causes of failures, whether they are equipment or process related. Once uncovered, do not rest until the sources of these root causes are eliminated. Modify the management strategy and steer training dollars to the right direction. Hard look. This editorial is critical of how certain issues are now addressed by HPI companies. The purpose is not to gloss

over misdirected efforts, especially when addressing safety. Caution is warranted. To always seek salvation in new initiatives will have a price in wasted time and money. Irrespective of names, designations and code letters, any initiative whatsoever will succeed only if it is tightly interwoven with highly motivated and competent employees. Because these men and women are the prerequisites to success, our industry must continue sending young engineers to technical conferences that teach both incident investigation and incident avoidance. Advice for event organizers. Finally,

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an important suggestion to organizers of reliability-focused conferences: When selecting motivational speakers, pick the ones who can lay out the full story. At two recent conferences, the keynote speakers spoke about our shrinking world and the marvels of building the latest-generation passenger plane. The speakers reminded their respective audiences that suppliers from 17 nations around the globe provided major components and subassemblies for the new plane. Glitches with onboard batteries were solved in less than one year by competent contributors stepping up to whiteboards and doing sketches for ease of visualization. “Yes, but,” some of us mumbled; it is also known that the newgeneration passenger plane experienced years of delivery delays. Neither that fact nor its underlying causes were mentioned, and, more importantly, learning opportunities were missed at these conferences. Most conference attendees want to hear the full story and nothing less will do. LITERATURE CITED “Investigation shines new light on fatal 2010 Tesoro refinery explosion,” Hydrocarbon Processing, March 2014, pp. 12–14. 2 Bloch, H. P. and F. K. Geitner, Compressors: How to achieve high reliability and availability, McGraw-Hill Publishing, New York, New York, 2012. 1

HEINZ P. BLOCH is the Reliability/Equipment editor of HP. He has authored 18 textbooks and over 570 papers or articles and was a senior engineering associate for Exxon Chemicals. He is in his 52nd year as a reliability professional, and continues to advise process plants worldwide on reliability improvement, failure avoidance and maintenance cost reduction opportunities. He holds BS and MS degrees from the New Jersey Institute of Technology.

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Tower Technical Bulletin Troubleshooting Distillation Columns – Part 1: The Basics Background Properly designed and operated distillation columns can provide long-term, trouble-free service. However, mechanical failure, process upsets, and other factors can occur, preventing the distillation system from achieving the expected design performance. Taking a tower off-line is time consuming and expensive; before doing so it is important to have a good idea of what is causing the problem. A systematic study of the column should be made (often with the assistance of the column equipment provider). After careful study, a tower inspection should be performed to confirm the cause of the problem and to determine and/ or provide a proper solution. In emergency cases, expected replacement equipment may need to be on site prior to the column opening. Understanding Mass Transfer Fundamentals Is Critical Knowledge of the column thermodynamic and hydraulic functions is the key starting point. Any problem that develops that does not allow the vapor and liquid to contact each other in the manner for which the device was designed, or keeps the vapor and liquid from separating after contact, will adversely affect column performance. For example, the packing shown below will not provide good flow or vapor/liquid contacting efficiency because some of the packing is blocked off by fouling.

Where To Start Ask yourself the following questions: t
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Working Toward A Solution The simple checks should be made first. Check the instrumentation to ensure that flows, levels, temperatures, and pressures are correct. Check to make sure that feed compositions and analyses are correct. Conduct a single gauge pressure survey and a temperature survey as possible. Perform a mass balance across the column—a closure of 3-5% is normally considered acceptable. Once you have this information, review the information with plant engineering and operations. Consult with your equipment vendor to further investigate the problem. Decide on the feasibility of a column gamma scan. If practical, schedule a tower inspection at the first opportunity in order to personally examine the internals. In the meantime, the problem may be temporarily alleviated by reducing rates, changing the reflux and reboiler duties, changing the feed location, and increasing or decreasing the tower pressure.

The Sulzer Applications Group Sulzer Chemtech has over 150 years of in-house operating and design experience in process applications. 8F
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Sulzer has the know-how and the technology to design internals with reliable, high performance. Hydraulic Evaluation Symptoms of hydraulic flooding include excessive or erratic pressure drop, reduced bottoms flow, reduced column temperature profile, and excessive liquid carryover. Conversely, low pressure drop is an indication of missing trays or packing.

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Select 88 at www.HydrocarbonProcessing.com/RS Legal Notice: The information contained in this publication is believed to be accurate and reliable, but is not to be construed as implying any warranty or guarantee of performance. Sulzer Chemtech waives any liability and indemnity for effects resulting from its application.

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Automation Strategies

SAL SPADA ARC Advisory Group, Dedham, Massachusetts

HPI demands higher availability of rotating equipment The performance and uptime of heavy rotating equipment play an important role in business profitability in a wide range of industries, including upstream and midstream gas processing and downstream refining and petrochemical processing. In the North American chemical industry, the shale gas boom has been a windfall opportunity as large manufacturers shift from producing ethylene from oil to ethylene from lower-cost methane and natural gas. The cracked gas compressor, at the heart of these operations, must often deal with multiple feedstocks and is subject to fouling from contaminants. If the compressor should go down, lost production in these types of operations is estimated to cost about $1 million/day. Closing the gap. Compressors, pumps, and fans used in these

and other heavy process industries are often custom-engineered systems. Since each component is often sourced from a different vendor, engineers produce systems that are delivered with a wide range of availability guarantees for the different components. Unfortunately, these don’t always meet the demanding uptime guarantee (with minimum 24-hr advance notice of an event) sought by most end users. To close this performance gap, machine builders need to consider incorporating more advanced condition monitoring, predictive maintenance, and improved equipment designs into their rotating machinery systems. Engineering firms face challenges throughout every facet of design when developing heavy rotating equipment. Requirements for the most critical design elements: AC drive, motor, mechanical drive and coupling are all interrelated, yet, with very few exceptions, the mechanical drives come from different suppliers than do the electrical motors and AC drives. In an interview with a large, global chemical manufacturer, ARC Advisory Group learned that the manufacturer’s internal organization has developed advanced algorithms intended to drive equipment as “close to the edge” of performance as possible, while still protecting equipment and people. This multi-layered strategy integrates equipment protection algorithms, adaptive control algorithms and predictive condition monitoring. The equipment protection algorithms increase resilience to false trips, allowing equipment to stay operational for much longer periods of time. The adaptive control algorithms, which are generally developed for individual pieces of equipment, operate in real time to dynamically modify the control parameters based on the current operating conditions. The predictive condition monitoring systems used in conjunction with real-time control algorithms provide predictive maintenance information. Machinery providers face problems. Based on our interviews with several original equipment manufacturers equipment producers, there appears to be a measurable gap between the

capabilities they can integrate and what leading manufacturers seek. This creates a productivity and performance gap. Failure analysis and predictive maintenance solutions are generally limited to information from a single sensor. The solutions rarely correlate information from multiple sensors. Further, many equipment vendors don’t appear to understand the full potential of the equipment. Most employ off-the-shelf programmable logic controllers (PLCs) and AC drives (some with embedded PLCs) to control and monitor the machinery. Intelligence-to-edge devices. The biggest challenge faced by equipment providers and users alike is the limited processing power provided by the automation embedded in the rotating equipment. The processing power in most PLCs and AC drives is not adequate to execute complex algorithms such as pattern matching, covariance analysis, regression analysis and fast Fourier transforms in real time. Advanced predictive condition monitoring requires processing of large blocks of sampled stochastic data. Furthermore, to close the performance gap, sensors need to incorporate more intelligence for auto calibration, advanced filtering or stochastic signal processing to eliminate electrical noise. In some cases, sensors need to be interconnected. Vibration, acceleration, pressure, and temperature sensors often rely upon external signal analysis systems to perform filtering in noisy environments. This inhibits machine builders from integrating more advanced sensor solutions. Sensors. The “connected machine” will require not just more sensors, but also more intelligent sensors. Sensors must perform more sophisticated signal processing “at the edge” to provide accurate signals that filter out the noise before it gets to the automation system. Machine builders need to work in partnership with sensor suppliers to embed more intelligent sensors into the machinery, and with automation suppliers to embed complex condition monitoring algorithms into automation systems. Automation suppliers, in turn, must strive to provide solutions with the prerequisite processing power to run the advanced algorithms and scan rates that are fast enough for demanding rotating equipment requirements. SAL SPADA is research director for ARC Advisory Group. He has over 15 years of direct experience in motion control system design as a software developer, project manager and product marketing manager. Mr. Spada has been with ARC since 1997 and holds a BS degree and an MS degree in electrical engineering from the University of Massachusetts and an MBA degree from Babson College.

Hydrocarbon Processing | JULY 201427

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Project Management

WILLIAM BADGER, PROFESSOR EMERITUS Del E. Webb School of Construction, Arizona State University

What skills will project managers need in the next decade?—Part 1 The next decade could well be that of the project manager (PM), who is at the core individual of every successful project. It is the PM’s competence and professionalism on which the construction industry’s professional identity and reputation rests. To investigate these competencies, the Construction Industry Institute (CII) launched a research team, RT 281: Project Management Skills of the Future, to determine what PM skills will be needed in the next 10 years. The team’s target was to predict the skills and competencies that will underlie the success of a PM in an increasingly global marketplace beginning in 2022. The research identified new and expanded competencies. The researchers created a list of skills for PMs to benchmark themselves against, and a guide of available tools to acquire these new skills and to improve those that they already possess.

Evolving skill set. Just as the construction

industry is experiencing rapid changes, the role and character of the PM is equally in a transition phase. Over the next 10 years, the PM role will both evolve and broaden—with new and more responsibilities. The PM will continue to oversee and direct the engineering, procurement and construction of capital projects. However, the PM will also evolve into a leader with welldeveloped communications and listening skills that create and nurture the all-important relationships and will motivate, engage and develop others. The research indicates that the PMs of the future will interface with twice as many stakeholders and, consequently, they will require vastly improved leadership, people, and thinking skills. New trends in project management. One important finding was the realization

that there are four disruptive trends on the horizon, as outlined in TABLE 1. Future PM competencies will fall into four key areas with 14 total competencies. Next month. Part 2 outlines needed com-

petencies for global projects. ACKNOWLEDGMENT The Construction Industry Institute (CII) is a unique consortium of more than 130 leading owner, engineering-contractor and supplier firms from both the public and private arenas. CII’s website: www.construction-institute.org. Kim Allen, CII associate director of knowledge management is a coauthor for this article. DR. WILLIAM W. BADGER retired as Professor Emeritus at Arizona State University. For 18 years, he was the director of the Del E. Webb School of Construction. DR. AVI WIEZEL is the dean of facilities and a professor at Arizona State University. His prior positions include chairman of the Del E. Webb School of Construction and the director of graduate studies in construction.

TABLE 1. Four disruptive trends in the project management business Trends forecast Workforce demographics

Challenges for PMs Skilled workforce shortages at all levels

Workforce diversity, dynamics and styles

Knowledge and experience gaps

Multi-gender, multi-cultural, multi-generational, multi-lingual project teams

More dispersed workforce More diverse workforce Globalization

Technology

Global population growth exceeding available resources and straining existing infrastructures

Projects in areas with difficult conditions

Disappearing commercial barriers among nations

Safety issues and training beyond traditional areas

Transfer of wealth between nations

Price/schedule/resource pressure means more competitiveness

Continued focus on security and global terrorism

Global supply chains

Smart machines/robotics

24/7/365 access from all directions

Radically enhanced communications technology using audio (e.g., voice activation), visual and social media

Information collected faster than resources can manage and analyze

Exponential speed of technology innovation

Information for decision making will change within minutes Global, virtual teams

New and changing Global knowledge networks replacing subject-matter experts organizations Breakdown of traditional hierarchical organizations Organization and project structures well beyond traditional organizational boundaries

Increase in number of stakeholders with competing agendas Increase in number of non-full-time/contract employees Shifts in risk-sharing models (more joint ventures, etc.)

Hydrocarbon Processing | JULY 201429

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Global

RINA QUIJADA Senior Director—Latin America, IHS Chemical Insight

The reshaping of Latin America’s petrochemical industry Latin American economies continue to grow. FIG. 1 shows the gross domestic product (GDP) growth rates from 2010 through 2018 for this region. Brazil accounts for 35% of the total GDP growth. For the purposes of this article, Mexico, Central America, South America and the Caribbean are included in Latin America.

Demand for finished goods will continue to grow and will be supplied by local production and imports. The region is a large, and now strategic, market for producers in North America, Asia and Europe. Future exports of surplus resins from 2015–2018 make Latin America an increasingly attractive option for investors.

Demand for products increases. Continued economic growth, while slower, will foster demand for finished goods and services. Only one (Etileno XXI in Mexico) significant grassroots project in the region is planned through 2018. From Mexico to Patagonia, several issues are common to all countries: • Economic growth, while widely varied, moves forward. There is slow but steady GDP performance. • Only one large, grassroots expansion is planned from 2014–2018. • The region is reevaluating capacity expansions in light of new, low-cost feedstock access to North America. • The lack of hard currency throughout the region incurs high risk for importation. • Long-overdue capital expenditure investment aimed at infrastructure is quite necessary. • Limited access to low-cost feedstock is a hindrance to expansion for producers.

Money issues. However, due to limited access to hard cur-

rency, many countries in this region are strapped for effective liquidity, and they lack the flexibility needed to trade and remain 7.5 Latin America World

Real GDP annual growth, %

5.8 5.0 4.3

4.1 3.1

2.5

3.0

2.7 2.6

2.5 2.5

2012

2013

3.2

3.5

3.7 3.8

4.0 3.8

3.9 3.8

2016

2017

2018

2.3

0.0 2010

2011

2014

2015

Source: IHS

FIG. 1. Latin America GDP performance vs. global, 2010–2018.

TABLE 1. Latin America petrochemical capacity changes Country

Product

Capacity change, thousand tpy

Company

Location

Year

Colombia

PVC

100

Mexichem

Cartagena

2014

Ethylene

1,050

Braskem IDESA

Veracruz

2015

LDPE

300

Braskem IDESA

Veracruz

2015 2015

Mexico

Venezuela

Brazil

Bolivia

HDPE

750

Braskem IDESA

Veracruz

Chlor-alkali

60

Cydsa

Nuevo León

2015

Ammonia

600

Pequiven

Morón

2014

Urea

750

Pequiven

Morón

2014

PTA

700

Petroquimica Suape

Pernambuco

2013

PET

450

Petroquimica Suape

Pernambuco

2014

PVC

200

Braskem

Alagoas

2012

Ammonia

750

Petrobras

Mato Grosso do Sul

2015

Urea

1,200

Petrobras

Mato Grosso do Sul

2015

Acrylic acid

160

BASF

Bahia

2015

SAP

30

BASF

Bahia

2015

Ammonia

430

YPBF

Cochabamba

2016

Urea

750

YPBF

Cochabamba

2016

Hydrocarbon Processing | JULY 201431

Global competitive in a global environment. This translates into highrisk imports because exchange rates can change at any point of the process, as players submit purchase orders and arrange delivery of products. Geographic proximity becomes a top priority when trading with Latin America. In essence, this is the added advantage for North American producers in a global context. With only a few production capacity expansions announced in the region, imports will be needed to meet increased domestic demand for end-use products. TABLE 1 summarizes the significant production capacity expansions announced in Latin America through 2018. Influence from the north. The ongoing energy revolution in

North America has prompted a reevaluation of planned capacity expansions in Latin America. Consequently, this new assessment is delaying added production decisions for the region. Countries like Colombia, Brazil and Venezuela are now returning to the drawing board to determine how they will move forward. At the core of their analyses will be each nation’s ability to compete and take advantage of expected capacity additions in North America within the context of low-cost, unconventional feedstocks.

participate in these new energy projects. The full reach of the reform will largely be decided by secondary laws, which are under the approval process. The reality is that industry excitement over Mexico’s energy reform is high. However, this process will take some time to implement. In Argentina, we should follow closely developments at Vaca Muerta. This potential bonanza of large gas reserves should allow producers to gain access to low-cost feedstocks, which, in turn, should support capacity expansions for basic petrochemicals and derivatives in Argentina. However, this is a medium- to long-term proposition. Brazil is also reassessing its feedstock availability for new capacity investments at Comperj. Braskem will assess its options. However, no new grassroots facilities are expected at this time. This is also a medium- to long-term project under evaluation. Looking at 2014–2018, Latin America represents a strategic market for consumption, as well as a key strategic ally to producers from North America. DR. RINA QUIJADA has 30 years of industry experience and now serves as the senior director–Latin America, IHS Chemical Insight. Prior to joining IHS, Dr. Quijada founded, and was the CEO of, Intellichem, Inc. Preceding Intellichem, she was a partner at CMAI. Dr. Quijada’s career began in 1983 at PDVSA/Pequiven, where she held managerial positions at the production, commercial and corporate planning levels. Dr. Quijada holds a PhD in economics and an MA degree in international management.

New energy policies. The energy reform passed last year in Mexico is the largest transformational development emerging from the nation in decades. It has elements like productionsharing and license contracts to major companies. Several international investors are eager to scout out the best way to

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Petrochemicals

BEN DUBOSE, ONLINE EDITOR [email protected]

Major US players bet on propane dehydrogenation Much has been written about the impact of newfound supplies from the US shale boom on the nation’s ethylene industry, culminating in plans for several new ethane crackers. However, a similar trend for olefins producers is also occurring on the propylene side, using shale-derived propane as feedstock. As of today, seven projects have been proposed in the field of propane dehydrogenation (PDH), which converts propane into propylene and byproduct hydrogen. But, at the moment, only one such plant is actually operating in the US. That one is the PetroLogistics facility near Houston, which started operations in 2010 and has a propylene production capacity of 1.45 billion lb/year (658,000 tpy). The plant is one of the largest of its kind in the world.

New hydrogen supply from PDH could benefit US refiners. Another byproduct of the PDH trend is a new source

Flint Hills moves to acquire PetroLogistics. So does

Work remains to be done. The deal for PetroLogistics is not yet complete. Other prospective buyers have until July 6 to file a competing offer, and between that period, customary closing conditions and regulatory approvals, Flint Hills says it does not expect to complete the deal until late 2014. But the agreed-to terms would make the acquisition the largest in Flint Hills’ history, reflecting the confidence that the company has in both the PetroLogistics plant and the role of propane dehydrogenation going forward in the US petrochemical marketplace. “PetroLogistics built this facility from the ground up, and it is a world-class operation,” said Brad Razook, CEO of Flint Hills Resources. “Its capabilities are well aligned with our existing chemical and refining business. We look forward to welcoming PetroLogistics employees to Flint Hills Resources as we work together to build on their success.”

this trend have staying power? Flint Hills Resources, a major US-based refining and petrochemicals producer and a part of Koch Industries, is betting that it does—as evidenced by their $2.1 billion agreement announced in early June to acquire PetroLogistics. “PetroLogistics’ unique capabilities will help us expand our existing chemical and refining business,” Flint Hills said in a statement. “There are also pipeline and supply synergies that will help us create additional value for our customers. We will continue to serve the customers of the business but will look for synergies with our existing business in the future where it makes sense.” One such synergy could come with the existing Flint Hills polypropylene (PP) business, which includes plants in Texas and Michigan and could use the new propylene supply as a raw material in its production process. Propylene trading is another possibility. But another plausible scenario comes in the form of propylene trading. The PetroLogistics plant, located on the Houston Ship Channel (FIG. 1), has strong pipeline interconnections between the plant site and storage facilities in nearby Mont Belvieu. From there, the propylene could be transported almost anywhere through existing infrastructure. And with none of the other seven plants expected to launch production until the second half of this decade, the US propylene market is likely to be tight for the immediate future. That gives Flint Hills, assuming the successful completion of its planned PetroLogistics acquisition, a head start on the market. While most of the PetroLogistics propylene supply is presently under contract, the first major contract ends in December of this year, giving Flint Hills plenty of options and flexibility.

of hydrogen for US refiners, who could then use it to help meet stricter sulfur regulations. The nation’s recently-adopted Tier 3 gasoline standards intend to reduce sulfur levels to 10 parts per million (ppm) from 30 ppm. To accomplish that drop, refiners are expected to need an additional 100-to-200 million cubic feet/day of hydrogen, according to Daniel Yankowski, president of Praxair’s global hydrogen business. Already, PetroLogistics is providing Praxair with 93% of hydrogen produced at its Houston plant. And both Praxair and Air Products, two of the major hydrogen providers within the US, are prepared with existing pipeline infrastructure to transport hydrogen to facilities throughout the US Gulf Coast.

FIG. 1. The PetroLogistics PDH plant near the Houston Ship Channel first started commercial operations in 2010. Hydrocarbon Processing | JULY 201435

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Gas Processing

ADRIENNE BLUME, MANAGING EDITOR [email protected]

Eastern nations look to LNG for energy, environmental solutions With a collective total of more than 2.6 billion (B) people, or 37% of the world’s population, China and India are the two most populous nations on earth. The United Nations expects the two countries to retain these titles through at least 2050, by which time they are estimated to boast a collective population of approximately 3 B people. The two emerging economies are growing increasingly energy-hungry as their populations and transport infrastructures expand. At the same time, China and India are seeking to reduce air pollution levels caused by these expansions. China, in particular, is being pressured to reduce traffic congestion and smog levels in its major cities, which are among the most polluted in the world. The country hopes to achieve cleaner air and clearer skies with a combination of industrial and automotive pollution cuts, clean coal and alternative fuel initiatives, fuel-efficient vehicle use and, most importantly, greater use of natural gas as an industrial and vehicle fuel. In the future, the use of compressed natural gas (CNG)-powered trucks and automobiles will increase in China, and domestic manufacturers are currently developing 100% methanol-powered trucks. Coal-based methanol makes up approximately 8% of the country’s fuel pool. Likewise, India is one of the world’s largest natural gas vehicle (NGV) markets, with a substantial public bus and taxi fleet in New Delhi operating on CNG (FIG. 1). LNG: An Eastern pollution solution?

The import of liquefied natural gas (LNG) is a ready answer to China’s and India’s growing methanol needs and the countries’ efforts to curb air pollution. As a whole, Asia-Pacific is anticipated to surpass Europe as the world’s second-biggest natural gas market as early as 2016. Dozens

of liquefaction and regasification terminals are planned or already under construction. China’s gas demand is forecast to increase by a substantial 56% between 2014 and 2018, to 294 Bcm. In response to this rapidly expanding demand, China’s LNG imports will rise significantly. Domestic LNG imports reached 15 million tons per year (MMtpy) in 2012 and are expected to double by 2015. Meanwhile, Indian gas production meets approximately half of the domestic requirement. However, demand from gasconsuming industries, such as power and fertilizer, is rising steadily. Indian gas demand is forecast to triple by 2017, which will require increased LNG imports. Domestic construction ramps up. One

way China and India are working to boost their LNG use and prepare for increased LNG flows is through the construction of domestic liquefaction and regasification terminals. China has planned more than a dozen new import terminals for completion by 2020, and India aims to build more than a dozen additional LNG import terminals to meet growing demand for natural gas for electricity and fertilizer. However, China’s plans could change should the country successfully develop its vast domestic shale gas reserves, which the US Energy Information Administration estimated in 2013 to be the largest in the world at 1.115 trillion cubic feet (Tcf). The country has a shale gas production target for 2015 of 6.5 Bcm. Meanwhile, India is expanding capacity at its existing LNG terminals and has several new projects in the works. These projects include floating LNG (FLNG) facilities, such as the Kakinada LNG import terminal, and the industry’s first barge-based FLNG regasification unit offshore Andhra Pradesh. Among other recent project announcements, Gujarat State Petroleum Corp.

LNG Ltd. will build a new regasification plant at Mundra in Gujarat state on the country’s west coast. The terminal will have a sendout capacity of 5 MMt and is slated for completion by the end of 2016. Toyo Engineering will provide engineering for the project as well as for a 5-MMtpy expansion project at the Petronet LNG regasification terminal at Dahej in Gujarat. The plant will have a total regasification capacity of 15 MMtpy after the project is completed in early 2017. Foreign projects grab investors. China and India are also investing heavily in LNG projects in major gas-producing regions, such as North America and Russia. Shale gas-advantaged LNG projects in the US and Canada, and developing LNG ventures in nearby Russia, are attracting companies looking to secure long-term gas supplies. North American exports. PetroChina is a stakeholder in the LNG Canada export project in British Columbia, Canada. The

FIG. 1. A CNG-fueled taxi outside of a CNG station in New Delhi, India. Hydrocarbon Processing | JULY 201437

Gas Processing

FIG. 2. An artist’s rendering of the proposed Pacific NorthWest LNG facility on Lelu Island near Port Edward, British Columbia, Canada. Image courtesy of Pacific NorthWest LNG.

joint venture also includes partners Shell Canada, Korea Gas Corp. and Mitsubishi Corp. The project will be constructed in phases, with the first phase having a design capacity of 12 MMtpy upon startup in 2019 or 2020. If needed, capacity can be expanded to 24 MMtpy. Meanwhile, Chinese oil major Sinopec recently bought a 15% share of Malaysian Petronas’ British Columbian gas reserves and the planned Pacific NorthWest LNG

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export project (FIG. 2). The LNG project, with an estimated price tag of C$9 B to C$11 B, will produce as much as 19.68 MMtpy of LNG for 25 years starting in 2018, according to an application to Canada’s National Energy Board. The stake will entitle Sinopec to approximately 1.8 MMtpy of LNG for 20 years. Sinopec also agreed to buy 3 MMtpy of LNG for 20 years from Petronas, making it one of the Malaysian state-owned company’s largest buyers of the fuel. Likewise, Indian Oil Corp. (IOC), India’s largest refiner, purchased a 10% stake in the Petrobras-owned gas fields and the planned LNG export project. The agreement will give IOC the right to 1.2 MMtpy of LNG for two decades from 2018. Following the closing of the IOC and Sinopec acquisitions, Petronas will hold 62% of the integrated project and will continue to secure markets for LNG. IOC follows rivals including Oil & Natural Gas Corp. and GAIL India in securing energy supplies through overseas acquisitions to meet surging demand at home. GAIL India has contracted decades’ worth of LNG supplies from Russian Gazprom and various US LNG projects. In another new development, Chinese offshore oil and gas producer China National Offshore Oil Corp. (CNOOC) is considering the construction of an LNG plant and export terminal in western Canada to send the fuel to China. The plant may be built at Grassy Point near Prince Rupert in British Columbia. CNOOC, through its subsidiary Nexen Energy, signed an agreement to access the land with the government of British Columbia. CNOOC operates LNG facilities in China at Guangdong, Shanghai, Fujian, Zhuhai and Ningbo, with plans to build more to feed China’s increasing appetite for natural gas. Russian developments. Meanwhile, Chinese banks may boost funding for Novatek’s $27-B Yamal LNG venture in Russia to export LNG from Russia’s Arctic region if European banks pull out over the crisis in Ukraine, project partner Total said. There is a risk of a project delay, due for commercial operation in 2017, if the political situation worsens. Total and Novatek reached a final investment decision on Yamal LNG in December 2013, with the Russian company taking 60% of the venture to produce 16.5 MMtpy of LNG, and with Total and China National Petroleum Corp. each holding 20%.

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Boxscore Construction Analysis

LEE NICHOLS, DIRECTOR, DATA DIVISION [email protected]

South Africa—Africa’s clean fuels leader? Around the world, legislation mandating decreased emissions and lower levels of airborne pollutants is coming into effect. In response, refiners are implementing operational and processing changes to reduce sulfur levels in transportation fuels. Notable clean fuels projects are already being constructed in Saudi Arabia and Kuwait. To comply with mandatory sulfur specifications for gasoline and diesel between 2013 and 2016, Saudi Arabia plans to spend billions of dollars to construct multiple clean fuels projects. Saudi Arabia is seeking to reduce sulfur content in diesel and gasoline to 10 parts per million (ppm), and to lower benzene content in gasoline to 1%. Kuwait National Petroleum Co. (KNPC) is investing $31 billion (B) in projects to modernize the country’s Mina Abdullah and Mina Al-Ahmadi refineries, as well as to construct the region’s largest refinery, the Al-Zour plant. The Clean Fuels Project and the New Refinery Project are ambitious plans to overhaul Kuwait’s refining sector. South Africa is also implementing its own clean fuels program. South African Petroleum Refineries (Sapref), a joint venture ( JV) between Shell SA Refining and BP Southern Africa, and National Petroleum Refiners of South Africa (Natref), a JV between Sasol and Total, are each planning their own clean fuels projects. Sapref ’s Clean Fuels 2 and Natref ’s Clean Fuels 2 projects will help improve the quality of transportation fuels by reducing levels of sulfur, benzene and aromatics, thereby meeting enhanced legislative requirements for cleaner-burning transportation fuels. To develop clean fuels, and to prevent a fuel shortage, South Africa’s national oil company, Petroleum Oil and Gas Corp. of South Africa (PetroSA), along with partner Sinopec, plan to construct one of Africa’s largest refineries. Project Mthombo is a $10-B, 300-thousand-barrel-per-day (Mbpd) refinery that will be constructed near Port Elizabeth. Project Mthombo, along with Natref ’s and Sapref ’s Clean Fuels 2 projects, have the ability to ensure that South Africa modernizes its refining industry to reach international transportation fuel standards. These initiatives have the ability to make South Africa the continent’s new clean fuels leader.

Refining operations. South Africa has the third-largest refining

capacity in Africa, surpassed only by Algeria and Egypt. About 95% of South Africa’s crude oil requirements are met by imports from the Middle East and Africa. Major domestic refining operations are located at four refineries (FIG. 1). These include Sapref and Enref (Engen Petroleum), both located in Durban; Chevref (Caltex Oil SA/Chevron), located in Cape Town; and Natref, located in Sasolburg. Total domestic refining capacity is 485 Mbpd (TABLE 1). With the addition of Project Mthombo, domestic refining capacity could climb to nearly 800 Mbpd. South Africa also produces synthetic fuels from low-grade coal and natural gas, using coal-to-liquids (CTL) and gas-toliquids (GTL) technologies. Sasol’s Secunda CTL plant consists of two production units. The Secunda CTL plant produces 160 Mbpd of liquid fuels, making it one of the largest CTL plants in the world. Sasol also operates the Mossel Bay GTL plant. The GTL plant utilizes Fischer-Tropsch technology to produce 45 Mbpd of synthetic liquid fuels, of which more than half is gasoline. Operating refineries Proposed refinery

Namibia

Botswana

Pietersburg Johannesburg

Pretoria

Swaziland

South Africa Kimberley

Lesotho

Durban

Atlantic Ocean Port Elizabeth

Indian Ocean

Cape Town

FIG. 1. Operating and proposed South African refineries.

TABLE 1. South Africa’s refining operations Refinery

Company

Location

Capacity, bpd

Chevref

Caltex Oil SA (Chevron)

Cape Town

110,000

Enref

Engen Petroleum

Durban

118,000

Natref

Sasol-Total JV

Sasolburg

88,000

Sapref

BP-Shell JV

Durban

Mthombo (proposed)

PetroSA

Port Elizabeth

169,000 300,000 Hydrocarbon Processing | JULY 201441

Boxscore Construction Analysis Clean fuels mandate. South Africa lags behind many developed nations in fuel quality standards. Presently, the majority of South African transportation fuels are graded at Euro 2 specifications. These fuels contain anywhere from 300 ppm to 500 ppm of sulfur. The country’s ultimate goal is to develop Euro 5-specification fuels. This would entail developing fuels to contain 10 ppm or less of sulfur, the lowering of benzene from 5% to 1% and the reduction of aromatics from 50% to 35%. Achievement of Euro 5 fuel specifications would allow the country to import more modern, low-emissions vehicles. Most modern cars cannot be imported into South Africa because the lower quality of local fuels would damage the cars’ engines. Importeed cars with sophisticated engines must be reverseengineered to accept the inferior fuels. To combat this issue, South Africa is implementing higher fuel standards to reach Euro 5-specification fuels by the end of the decade. The South African government is implementing new regulations to curb sulfur in transportation fuels. The initiative, Cleaner Fuels Program 2 (CF2), was announced in 2012. The new fuel standards call for upgrades to all of the country’s existing refineries. The CF2 program has several major objectives: • Raise the quality of South Africa’s fuels • Reduce emissions • Encourage trade with the global market • Allow for greater access to new vehicle technology • Protect jobs in the value chain, including refining, car manufacturing and related sectors. The CF2 program was initially designed to begin in 2017, but it has been pushed back to 2020. The extended deadline provides South African refiners with time to make the necessary upgrades to produce cleaner fuels and is a more realistic timetable for the program’s implementation—one that could cost South African refiners billions of dollars in upgrade costs. Natref Clean Fuels 2. Natref is a JV between Sasol and Total

South Africa. Natref operates an 88-Mbpd refinery in Sasolburg. The refinery is designed to process heavy, high-sulfur crude oils. To meet future government requirements mandating increasingly strict emission standards, the company is implementing the Clean Fuels 2 project. The ultimate goal of the Clean Fuels 2 project is to upgrade the refinery to reduce the concentration of sulfur in both gasoline and diesel, thereby meeting Euro 5 specifications for transportation fuels. The project will add, revamp or upgrade the following units: • A new C6 /C7 splitter will be added to minimize benzene precursors to the catalytic reformer • A new naphtha hydrotreater and a new isomerization unit will be added • A new reformate splitter column will be added downstream of the catalytic reformer • The existing diesel hydrotreating unit will be revamped • A new desulfurization unit will be added • A new amine system for new unit offgases will be installed • A new sour water stripper will be added • A new hydrogen plant will be built to increase hydrogen production. Additional construction includes new cooling towers, a new steam and condensate recovery system, a new flare system, new electricity substations and new storage tanks. Select 158 at www.HydrocarbonProcessing.com/RS

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Boxscore Construction Analysis Fluor was awarded a basic engineering services contract for the project in June 2013. The award followed Fluor’s work on the feasibility study and conceptual engineering for the project. The project is scheduled to be completed by 2017.

management (EPCM). With the deadline for the clean fuels mandate pushed back to 2020, the EPCM contract is likely to be awarded in the next few years. Project Mthombo. The Mthombo plant, if built, will be one

Sapref Clean Fuels 2. The Sapref refinery is the country’s

largest refinery. The 169-Mbpd refinery is located in Durban, on the east coast of South Africa. The refinery accounts for nearly 35% of the total domestic refining capacity. As with the Natref clean fuels project, Sapref is conducting its own clean fuels project. The Clean Fuels 2 project is a substantial upgrade to the existing refinery. The modernization program aims to improve the quality of transportation fuels through a reduction in the levels of sulfur, benzene and aromatics. The project was scheduled to be completed by 2017 to adhere to new government regulations, but Sapref has pushed back the completion date to be more in line with the South African government’s 2020 deadline. Fluor has completed the project’s front-end engineering design (FEED) phase. A detailed design and engineering package has also been compiled. The project’s next step is the award for engineering, procurement and construction

of the largest refineries in Africa. The $10-B, 300-Mbpd refinery will be constructed in the Coega Industrial Development Zone near Port Elizabeth. The construction of the refinery will accomplish two goals. The first goal is to prevent a shortfall of domestic refined fuels. The country’s growing demand for transportation fuels is outpacing the country’s refining capacity. Demand for transportation fuels is forecast to grow to more than 400 Mbpd by 2020. If no investment is made, the country will be forced to import almost 200 Mbpd by 2020 to satisfy demand. Additional refining capacity is needed to address domestic supply challenges and reduce imports. Secondly, the modern refinery will have the ability to process medium-sulfur and high-sulfur crude oils to produce higher-grade fuels, thereby meeting the government’s mandate for Euro 5-specification fuels. If greenlighted, the massive refinery project is scheduled to be completed by the end of the decade.

Detailed and up-to-date information for active construction projects in the refining, gas processing, and petrochemical industries across the globe | ConstructionBoxscore.com

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44JULY 2014 | HydrocarbonProcessing.com

Viewpoint

SÜLEYMAN ÖZMEN Vice President, Refining and Chemical Licensing, Shell Global Solutions International BV

The journey to a value-adding refinery project Execute it correctly

Operating manuals

Project objective

Configuration selection

SÜLEYMAN ÖZMEN, vice president of Refining and Chemical Licensing at Shell Global Solutions International BV, has a deep-seated passion for devising solutions for his customers’ refining challenges. He also possesses more than four decades of experience in the downstream sector, along with numerous qualifications, patents and technical papers. Following roles with IFP (three years), BP Amoco (eight years) and UOP (20 years), he joined Shell in 2006 to lead its new worldwide hydroprocessing licensing organization. His portfolio was later extended to include all of Shell’s licensed refinery and petrochemical technologies. In 2009, he was appointed vice president.

EPC support

BEP Technical training

Technology selection FEED support Design basis

Startup support

Poststartup support Long-term catalyst support Long-term technical support

Operational training

Journey to a value-adding project FIG. 1. The Honeycomb Model helps keep investment plans robust in changing environments.

the natural stages of project progression. It also highlights how a strategic licensor can support projects along the journey. Develop the best plan. A project’s

Projects are a means of creating value from assets. The more thorough a project’s planning and management, the more successful it is likely to be. However, it is quite common for a project to become fully operational 4–5 years after its initial definition, during which time the prevailing market conditions are likely to have shifted. For many executives, this is a key concern: How can they ensure that their investment plans remain technically and economically robust in the new environment? To help address such concerns, Shell Global Solutions has developed the Honeycomb Model (FIG. 1). The principal aim of this model is to help ensure that projects capture maximum value through all

Continue to improve it

Value-adding project

Develop the best plan

early planning stages are critical. It is possible to capture substantial value through good project definition and smart refinery configuration. A key activity in the first part of the Honeycomb Model is the combination of technology selection and intelligent configuration. This activity can make a huge difference to a project’s bankability and future economic performance, and numerous pivotal decisions are necessary at this juncture. For instance, the specific technologies for each new process unit in the configuration must be selected. This selection involves evaluating the features and capabilities of the various technologies on the market, but seasoned

project executives will know that there are also several key risks. For example, will the technologies match at the interfaces? Are all the promised benefits likely to materialize? Is the technology well-proven and derisked? If not, does the project’s economic model align with the most likely improvement in the technology over time with utilization and targeted performance? Secondary decisions then follow—for example, feedstock robustness. Should the ability to process heavier, high-sulfur or high-total-acid-number crude oils be built in? Should the hardware necessary to produce premium products, such as winter diesel and low-sulfur marine fuels, be installed? Although these capabilities would increase the capital expenditure, they could have major impacts on future margins. During these early planning stages, the project teams should continuously challenge themselves and ask what changes Hydrocarbon Processing | JULY 201445

Viewpoint could be made to better meet the refiner’s business objectives. Companies can uncover remarkable value by doing this. On a recent project, for example, the owner was struggling with capital constraints. The scheme included a hydrocracker with 99% conversion. However, by working closely with the refinery, it was discovered that the hydrocracker could still achieve its objectives at 85% conversion through integration with another

process unit—an adjustment that made the project economics look very different. Execute it correctly. Another critical point in the lifecycle of a capital investment is the project execution phase. A recurring theme of many successful projects is that all of the parties—including the strategic licensor; the front-end engineering design provider; and the engineering, procurement and construction contrac-

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tors—continue to challenge the assumptions behind the original design well into the execution phase. For instance, during the creation of the basic engineering package, experienced designers may be able to uncover opportunities to simplify refinery processes, to improve energy efficiency, to remove redundancies or to integrate process units. Substantial value can also be won or lost at the startup phase. A three-month delay in startup, for example, can turn a businesscritical project into a regret investment. Typically, the strategic licensor will provide a crew to advise during precommissioning, commissioning and startup, so their level of experience is paramount. Continue to improve it. Once the company begins to take responsibility for, and to operate, the new assets, its executives will have their own concerns. Will the new assets operate reliably enough to generate sufficient cash to cover the financing costs? Will they hit their cycle-length and yield-profile targets? Do these new units have sufficient flexibility to adjust to the prevailing conditions? The final part of the Honeycomb Model is about continuing to improve the new assets by addressing concerns and potential opportunities. The strategic licensor can continue to support the new owner with programs such as the Shell Global Solutions multiplatform Pentagon Model, as well as with service agreements, access to subject-matter experts and availability of help-desk services. Ongoing support is also vital for the catalyst. Regular performance evaluations, data tracking and data monitoring are essential to help maintain long-term performance. Even in the most well-designed and well-run plants, there are often opportunities for improvement because external factors are continually shifting, and technology and catalyst capabilities are improving. Remain vigilant. The reality is that any strategic investment opportunity, however attractive, is at risk of being torpedoed by a suboptimal decision from the project team at any point during its lifecycle. Nevertheless, many projects are getting it right, and the Honeycomb Model describes how strategic licensors have often been involved from the moment of selecting the configuration of the refinery through to startup and beyond.

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A Tristar Global Energy Solutions Company

| Special Report REFINERY OF THE FUTURE “The refinery of the future is a place where advanced technologies and highly skilled workers will raise to new levels the standards for efficiency, safety and plant intelligence,” said Lance Gyorfi, vice president of refining, Chevron Products Co., in 1998. The global refining industry has witnessed many advances over the last two decades. Future refining operations will blend many developments to produce clean refined products with more efficient and safer operations. Photo courtesy of eni

Special Report

Refinery of the Future W. S. LETZSCH, Technip Stone & Webster Process Technologies, Houston, Texas; and C. DEAN, High Olefins FCC Technology Services, LLC, Houston, Texas

How to make anything with a catalytic cracker 3. Rapid separation of the spent catalyst from the reaction products. This quickly terminates the reactions, thus minimizing the dilute-phase residence time and/or the temperature of the product vapors. 4. Stripping should be as efficient since hydrocarbons carried over to the regenerator are primarily gasoline and diesel. Excessive residence time of the hydrocarbons in the stripper will convert them to light gases, thus reducing gasoline yield. 5. Regeneration should be essentially complete since the residual carbon left on the catalyst is associated with the large-pore molecular sieves used in the catalyst.

The first fluid catalytic cracking (FCC) process was introduced almost 72 years ago; yet, this technology remains a principle conversion process in a modern refinery. Much has changed since the original FCC unit (FCCU) became operational. Properly operated, an FCCU can produce a variety of valuable refined products, including olefins and aromatics in addition to high-quality transportation fuel products. Various refined products can be produced via an FCCU only with changes in operating condition, different feedstocks and advanced/specialty catalyst choices. Maximizing individual products. Numerous papers have been presented that focus on maximizing the various products produced by an FCCU. These topics usually appear when the economics favor a particular yield. This article can be used as a reference for FCC operators to apply as a guide on what is necessary to maximize (or minimize) the yield of the many diverse FCC products. To achieve top performance from an FCCU, several factors must be considered. First, the design must be conducive to the making of the particular product. Second, the properties of the feedstock are important since the molecules entering the unit will determine what can potentially be made. Optimization of the many operating variables is required, along with using proper catalyst. Using the right catalyst in the proper way is the single most important action that a refiner can take to maximize FCC performance. Gasoline maximization. From the beginning, the FCCU

was primarily a gasoline machine. Feedstocks were atmospheric gasoil (AGO) and vacuum gasoil (VGO), and the objective was to produce high yields of gasoline. Originally, the gasoline yield was maximized by recycling both light- and heavy-cycle oils. The coke make was almost twice as high as necessary since the recycle rates could be as much as 100% of the fresh feedrate. Some designs had two risers that were of equal size. The present-day design parameters for an FCCU to maximize gasoline are: 1. A straight and vertical reaction system that operates in a gas/solid mode with minimum slip and an optimum residence time. 2. Feed injectors that vaporize the feed as fast as possible and reduce the incoming regenerated catalyst temperature to the mix temperature quickly.

FCC feed. Feedstock has a very marked impact on gasoline

yields.1 Since gasoline typically has a hydrogen content of about 13.5 wt%, a feedstock that is higher in hydrogen will produce more gasoline yield. TABLE 1 shows results from a cracking study done in a circulating pilot plant with a Middle East GO, a severely hydrotreated Louisiana GO, and the atmospheric bottoms from a US shale oil.2 The shale oil data was adjusted to better simulate the expected commercial results. TABLE 1. FCC yields (circulating pilot plant) Feedstock

Arab GO

HT US GO

API °

Utica shale (ATB)*

21

27.8

30.1

S, ppm

2.36

633

470

N, ppm

1,257

422

94

Concarbon

0.27

0.16

0.5

K factor

11.74

12.07

12.70

Hydrogen

12.03

12.99

13.55

Conversion, %

76.5

81.7

89.7

LPG

20.4

22.9

27.7

Gasoline

48.2

54.1

57.1

LCO

14.9

14.5

6.3

DO

8.6

3.6

4.0

* Extrapolated reference

TABLE 2. Effect of reactor temperature on gasoline yield, vol% Rx temp.

930°F

960°F

21 API

57.7

60.9

26 API

66.1

67.7

985°F

1,000°F

1,030°F

62.0

60.7

60.3

66.9

64.5

62.6

Hydrocarbon Processing | JULY 201449

Refinery of the Future TABLE 3. Major operating variables effects on FCCU Scenarios Case ID

Base

Increase ROT

Increase MAT

0

1

2

3

4

5

6

Base case

ROT Base +10°F

ROT Base +20°F

ROT Base +30°F

MAT: Base +1

MAT: Base +2

MAT: Base +3

ROT, °F

980

990

1,000

1,010

980

980

980

Feed preheat, °F

500

500

500

500

475

450

425

Operating conditions

Catalyst MAT C/O

70

70

70

70

71

72

73

6.32

6.49

6.67

6.83

6.29

6.28

6.27

Δ Coke

0.80

0.79

0.78

0.78

0.83

0.85

0.88

Regenerator temp., °F

1,323

1,329

1,335

1,342

1,334

1,343

1,353

HCO recycle, vol% fresh feed

0

0

0

0

0

0

0

Reactor pressure, psig

28

28

28

28

28

28

28

Dry gas

3.45

6.39

3.93

4.16

3.59

3.70

3.84

LPG

17.91

19.39

21.22

22.28

17.98

18.07

18.12

Propylene

5.14

5.75

6.46

6.91

5.17

5.20

5.23

Gasoline

52.45

51.84

50.79

50.42

52.66

52.88

53.06

LCO

14.87

14.08

13.32

12.60

14.50

14.11

13.74

Slurry

5.97

5.97

5.57

5.21

4.90

5.78

5.58

Yields, wt%

Coke

5.04

5.13

5.23

5.32

5.19

5.36

5.52

Conversion

79.17

80.37

81.49

82.51

79.74

80.32

80.87

The data show a direct correlation between hydrogen content of the feed and gasoline yield. Even though the tight oil contains some 1,050°F plus material, the gasoline yield exceeds 57 wt% or 67 vol% on fresh feed. Operating variables must be manipulated to attain high conversion while minimizing coke and light gases make.3 Maximum gasoline yield usually occurs at conversion levels between 80 vol% and 85 vol%. The conversion will be lower when processing aromatic feeds. Highest gasoline yields are achieved by maximizing catalytic activity within the parameters of the reaction system. Too much activity will give too low catalyst-to-oil (C/O) ratio, and it could lead to catalyst deactivation due to higher Δ coke. As summarized in TABLE 2, the reactor temperature will usually be between 960°F and 985°F. Lower temperatures adversely affect the stripper operation, and the higher temperatures will overcrack the gasoline produced. TABLE 3 summarizes the effects of the major operating variables on an FCC operation.4 In this instance, reaction temperatures above 980°F will have lower gasoline yields as did the heavy-cycle oil recycle. Recycle at high conversion is usually used for bottoms cracking rather than for producing more gasoline. Increasing catalyst activity and the C/O ratio (by lowering feed temperature), and reducing the reactor pressure, will increase gasoline yield. While lowering the feed temperature will make more coke, the dry gas yield may be reduced. If heavy feeds are processed, the ability of the feed injection system to vaporize the feed may set a minimum feed temperature. 50JULY 2014 | HydrocarbonProcessing.com

Catalyst impact. Catalyst properties must be tuned to the particular FCC operation. Both the feedstock and equipment limitations impact the choice of catalyst and additives. Gasoline and conversion may not be maximized if the unit is operating against multiple constraints, such as the air blower, wet-gas compressor and catalyst circulation. The main catalyst variables that can be controlled are faujasite zeolite content and type and degree of exchange of the zeolite. Matrix activity, pore structure and total pore volume, and metals passivators are all matrix components, which are varied to optimize the FCCU. Catalysts containing intermediate pore-size zeolites (ZSM5) need to be excluded. This is sometimes forgotten when an equilibrium catalyst is used. The equilibrium unit cell size needs to be optimized as well. For maximum gasoline, values ranging from 24.32 to 24.40 are used. Feeds with few coke precursors would benefit from larger numbers, while heavier or more aromatic feeds normally require lower values. Coke and gas selectivities are usually limited in that case. The starting unit cell size should be as close to the equilibrium value as possible since the fresh catalyst will play a significant role in the overall cracking performance. Diesel maximization. A few years ago, the only products making money for US refiners were the middle distillates, i.e., diesel, kerosine, heating oil and jet fuel. The entire refinery became focused on maximizing middle-distillate products including the

Refinery of the Future TABLE 3. Major operating variables effects on FCCU (cont.) Increase C/O

Increase recycle

Reduce pressure

7

8

9

10

11

12

13

14

15

C/O via preheat Base – 50°F

C/O via preheat Base – 100°F

C/O via preheat Base – 150°F

HCO recycle, %FF Base +5%

HCO recycle, %FF Base +10%

HCO recycle, %FF Base +15%

Operating pressure: Base – 2 psi

Operating pressure: Base – 4 psi

Operating pressure: Base – 6 psi

980

980

980

980

980

980

980

980

980

450

400

350

500

500

500

500

500

500

70

70

70

70

70

70

70

70

70

6.71

7.11

7.49

6.28

6.26

6.24

6.46

6.61

6.77

0.79

0.79

0.78

0.83

0.86

0.89

0.78

0.76

0.74

1,321

1,319

1,316

1,335

1,346

1,358

1,316

1,308

1,301

0

0

0

5

10

15

0

0

0

28

28

28

28

28

28

26

24

22

3.44

3.39

3.36

3.61

3.73

3.90

3.36

3.27

3.17

18.08

18.23

18.36

17.80

17.71

17.62

18.03

18.14

18.26

5.21

5.26

5.31

5.11

5.08

5.06

5.18

5.22

5.26

52.96

53.42

53.61

52.14

51.86

51.58

52.79

53.12

53.49

14.25

13.67

13.15

15.60

16.31

17.01

14.64

14.41

14.15

5.41

5.66

5.37

5.14

5.34

4.69

4.04

5.85

5.73

5.31

5.59

5.85

5.21

5.38

5.56

5.04

5.02

5.02

80.11

80.98

81.73

79.08

79.01

78.97

79.53

79.88

80.25

FCCU. As with gasoline maximization, all aspects of the FCCU must be considered. Diesel is the first product from the cracking reactions, and it reaches a peak before the gasoline yield, as shown in FIG. 1. When diesel-range material cracks, the primary product is gasoline. A riser would be the preferred reactor design with no backmixing. Contact time should be short, and the recycle of unconverted feed is required since the bottoms yield would be excessive. Feed injection systems must vaporize the feedstock quickly while quenching the hot catalyst from the regenerator. This minimizes Δ coke and dry gas make. A quick separation of the hydrocarbons and spent catalyst minimizes dry gas make. While bottoms cracking occurs in the dilute phase of the reactor, it is more effective to recycle the unconverted feed. Efficient stripping minimizes the amount of middle distillates that are burned in the regenerator, thus reducing the loading to the gas plant. Better stripping provides more operating flexibility to optimize other operating variables. Regenerator. Regeneration of the catalyst should be efficient. However, striving for the lowest carbon on catalyst may not be desirable. The strongest acid sites on the catalyst tend to crack the feed all the way to gasoline. Since the residual carbon is associated with these sites, a carbon level of about 0.1 wt% to 0.2 wt% may be desirable, and it would depend on the catalyst (formulation) used. Diesel-free feed. The feed to the cracker should not have any diesel present. This material is preferentially cracked

to gasoline, and there is a large cetane loss. If a cat-feed hydrotreater is being used, then the operator should consider operating it as a mild hydrocracker. This action is more selective to diesel than an FCCU, and it provides a high-quality product for the diesel pool. Hydrocracker. If the refinery has a hydrocracker, it should be operated at capacity. This may require additional hydrogen for the plant, but it should be economical. At lower FCC conversions, the light-cycle oil (LCO) is a higher-quality product and requires less-severe post-treating.5 Feedstocks with two and three aromatic rings will make more LCO than paraffins, since the aromatic nuclei are resistant to cracking reactions. Recycle streams and coker GOs are relatively rich in these molecules, and they will produce more middle distillates. These can be processed in the fresh feed riser or in a separate dedicated reactor riser. Coker GOs boiling in the diesel range would go to a middle-distillate hydrotreater rather than the FCCU. Main fractionators should have a heavy-cycle oil (HCO) draw so that a more coke-selective stream can be sent to the FCC.6 Decant oil should go through dedicated nozzles to preserve the integrity of the regular feed nozzles. Refiners have reported better overall yields when the decant oil is injected well downstream of the fresh feedstock. Catalysts used to maximize LCO should be very low in activity.7 As shown in FIG. 2, this is true for rare earth Y. Type Y or ultra-stable zeolites have large pores, and they are very Hydrocarbon Processing | JULY 201451

Refinery of the Future effective at cracking diesel-sized molecules. Type Y or ultrastable zeolites must be limited to about 5%–10% in a catalyst formulation to prevent overcracking of the LCO. Studies also suggest that smaller crystal sizes would help by allowing the LCO produced to diffuse more rapidly out of the sieve. Matrix activity should be maximized to give higher firstpass cracking, and the catalyst should have mainly intermediate or low-acid strength sites. Strong-acid sites produce gasoline. An open-pore structure is desired to minimize LCO overcracking. Compositions that include magnesium have been proven to make more diesel due to their unique acidstrength distributions. Operating variables are manipulated to give low conversions. TABLE 4 summarizes various operating variables to control. Reactor temperatures of 930°F–950°F are used for GO, while resids may require 950°F–960°F to avoid excessive hydrocarbon carryover from the stripper. Feed preheat may be maximized, and a fired heater would be required for the more crackable feeds. Recycle is essential to improve bottoms cracking with low conversions. Rates of 1%–30% would be required to give LCO/GO ratios of at least 3, and, in many cases, over 5, for these middle-distillate operations. Iso-C4s. The iso-C4 hydrocarbons are very valuable. Refiners

frequently want to maximize or, at least, increase one of them. These molecules are isobutylene and isobutane.3 Both are important feeds to an alkylation unit, and the isobutylene is used to make methyl-tertiary butyl ether (MTBE), the preferred oxygenate used globally except in North America. Isobutylene can also serve as a feed to a catalytic polymerization unit or as a similar process that makes gasoline from light olefins. 100 Davison MAT 900°F, 16 WHSV, 3 C/O Midwest refiner feed API° = 29.4, K = 12.2

80

Isobutane is required for alkylation. Some refiners are short of this material due to a lack of local field butane supplies. Isobutylene. The C4 hydrocarbons are generally one of the

ultimate products from a catalytic cracking unit due to the beta-scission carbenium ion cracking mechanism. Equilibrium concentrations of the various C4s are rarely achieved due to the reactivity of the butylenes. The isobutylene equilibrium sets the maximum amount of isobutylene that can be produced in a typical catalytic cracker.8 At equilibrium conditions, the percentage of isobutylene in the butenes stream varies from 46% at 950°F to 44% at 1,050°F.9 The actual percentage of isobutylene in the butene stream depends on the unit design operating conditions, feedstocks and catalyst. While isobutylene is initially produced, hydrogen transfer reactions can diminish its yield. Unit design features that help preserve isobutylene are: a short reactor contact time, and rapid separation of the spent catalyst and reactor effluent. Reducing the dilute phase temperature and contact time also is important. Low reactor hydrocarbon partial pressures are essential for minimizing hydrogen transfer, and FCCUs operating above 30 psig may not be able to make the needed isobutylene. Dispersion and/or riser stream will lower the hydrogen transfer reactions. Like every other product from an FCCU, feedstock plays an important role in isobutylene manufacturing. In general, high K factor feeds will give more isobutylene than more aromatic stocks. More paraffinic feeds can operate at higher conversions and generate more LPG. Typically, LPG has a hydrogen content well above 15 wt%, so hydrogen-deficient feeds cannot make as many barrels of isobutylene. The percentage of the olefins may be lower, depending on the operating variables and conversion levels. Key feedstock parameters would include the amount and configuration of the naphthenes. The length of the side chains on the ring compounds will deter16

Gasoline and distillate 15 14

Liquids, %

60

Gasoline

13

65 vol% LCO, vol%

40

LCO

12

70 vol% conv. 11

75 vol%

20 10 9

0 0

10

30

50 Conversion, vol% FF 0

70

0 2 Relative zeolite content

90

8

16

FIG. 1. Effect of zeolite content on LCO yield at constant operating severity.

52JULY 2014 | HydrocarbonProcessing.com

100

7 0

2

4

10 6 8 Zeolite input, wt% (Si, AI basis)

FIG. 2. Effect of zeolite concentration on LCO yields.

12

14

16

Refinery of the Future mine whether C3 or C4 olefins are formed. The main operating variable for producing more isobutylene is reactor temperature. The amount of the C4 iso-olefin increases significantly when the gasoline is over-cracked. Other variables that increase conversion can also increase isobutylene yield. These include higher catalyst activity and higher C/O ratios. Both can promote hydrogen transfer reactions; thus, the amount of isobutylene will not be as high as that yielded by increasing reactor temperature. If the conversion is taken too high, then the higher reactivity of the isobutylene will diminish its yield. Catalyst properties can have a very large effect on isobutylene yield. The goal is to get conversion, but with minimum hydrogen transfer. The large-pore zeolite used should be an ultrastable Y (US-Y) rather than a rare earth Y (REY). Minimal RE should be used for stabilization. A lower unit cell size is desirable, and it is important that the fresh catalyst also be low in unit cell size. High unit cell sizes mean the acid sites on the zeolite are closer together, and that promotes hydrogen transfer. An active matrix will provide much needed catalytic activity and has minimal hydrogen transfer activity. Bronsted acid sites would be preferred to Lewis acids since they would promote more skeletal isomerization of the olefins. ZSM-5 tends to increase the isobutylene concentration since the gasoline that cracks within the medium-pore zeolite produces a concentration of isobutylene near the equilibrium value (40% or higher).

TABLE 4. Effect of operating variables for increasing LCO yields Adjustment

Problem

Catalyst activity

Lower

Poorer selectivity

Carbon on catalyst

Increase

Poorer selectivity

1) Steam rate

Increase

Minor variable (mixing)

2) Unit pressure

Decrease

Gas comp. limit

Combine feed temp.

Increase

Regen temp. increase

Reactor temperature

Lower

Octane, olefins

Regenerator temp.

Increase

Metallurgy higher gas make

Recycle, HCO

Increase

Inc. coke capacity

1) IBP

Lower

Poor economics flash pt. 10%

2) FBP

Increase

Color cetane spec.

Feedrate

Increase

Hydraulic limits

Catalyst to oil

Lower

Regen temp. increase

Hydrocarbon partial pressure

Boiling range adj.

Contact time In reactor

Lower

Bottoms cracking

In dilute phase

Lower

Bottoms cracking

Isobutane. Isobutane yield will increase with conversion but

can be cracked thermally in the feed injection zone. When reactor temperatures reach 1,030°F, the base of the riser is near 1,100°F. Since isobutane is a function of hydrogen transfer reactions, the opposite factors for maximizing isobutylene generally apply. To minimize thermal cracking, the best conditions are good feed injection system, low slip factor riser, rapid and high separation of the spent catalyst and reactor products, short dilute phase contact times and/or low temperatures, and a highly effective stripper and regenerator. Feedstocks higher in hydrogen work best for the same reasons outlined in the previous section (isobutylenes). Tight oils would be expected to produce high quantities of isobutane with the proper unit design and operating conditions. While high conversions are desired, catalytic conversion is preferred to thermal conversion (reactor temperature). Higher catalyst activity can be achieved by increasing the activity of the catalyst or the C/O ratio by reducing feed temperature. It is normally more economical to first increase the RE content of the catalyst to raise activity, then increase the large-pore zeolite content, and finally raise catalyst additions. A higher UCS is usually desired. Using ZSM-5 should be reduced or eliminated. Butylenes. Butylenes are the most desirable light olefins in a gasoline-oriented refinery. These often have a value of gasoline or higher since they are the preferred feed to an alkylation unit. Butylenes give the highest octanes and consume less isobutane than propylene. Amylenes are usually only processed to reduce gasoline olefinicity and/or vapor pressure. All of the caveats that applied to making more isobutylene apply to maximizing butylenes. The unit design and feedstock

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53

Refinery of the Future properties would not be different. Reactor temperature is the key operating variable. Normally, a minimum reactor temperature of 980°F would be used to make light olefins. Many refiners will run over 1,000°F reactor temperature when operating in this mode. Low-hydrogen transfer and controlled activity are desired with an ultra-stable zeolite with a unit cell size of 24.32 angstroms or less. Some units might run as low as 24.27 angstroms, but dry gas or low conversion may become a limitation. Some catalyst additives are aimed at increasing butylenes vs. propylene. Since the additive suppliers have more experience with their products than a typical refiner, they should be consulted as to a product recommendation and a yield estimate. Increased matrix activity is also desired for maximizing butylenes and modifications to the ZSM-5 carrier may also help. ACKNOWLEDGMENT This is an updated version of an earlier presentation at the American Fuels and Petrochemical Association Annual Meeting, March 16-18, 2014, at Orlando, Florida. LITERATURE CITED Bryden, K. J. and E. T. Habib, Jr., “Processing shale oils in FCC: Challenges and opportunities,” Hydrocarbon Processing, pp. 59–64, September 2013. 2 Huovie, C., et. al., “Solutions for FCC Refiners in the Shale Oil Era,” AFPM Annual Meeting, March 2006. 3 “Alternative Routes to High Conversion,” The Catalyst Report, TI-805 Engelhard (BASF). 1

4

Gim, S., W. Letzsch, H. McQuiston and C. Santner, “FCC Opportunities at Lower Throughputs,” AFPM Annual Meeting, March 2010. 5 Unzelman, G., “Potential Impact of Cracking on Diesel Fuel Quality,” Katalistics’ 4th Annual FCC Symposium, 1983. 6 Niccum, P., “Maximizing diesel production in an FCC-centered refinery—Part 1,” Hydrocarbon Processing, September 2012. 7 Pillai, R. and P. Niccum, “Select new production strategies for FCC light cycle oil,” Hydrocarbon Processing, February 2013. 8 McLean, J. B. , G. S. Koermer and R. J. Madon, “Maximizing catalytic isobutylene selectivity,” paper from Engelhard. 9 McLean, J. B. and A. Witsoshkin, “Iso-olefins for oxygenate production using Isoplus,” NPRA Annual Meeting, March 1993. WARREN S. LETZSCH has 46 years of experience in petroleum refining including petroleum catalysts, refining, and engineering and design. His positions have included R & D, technical service and sales, which led to senior management positions in sales, marketing and technology development and oversight. He was one of the developers of the Technip/Axens R2R process and has authored over 80 technical papers. Mr. Letzsch holds eight patents in the field of fluid catalytic cracking. He was the FCC/DCC Program manager at Stone & Webster for 10 years and is now a senior refining consultant for Technip as well as a private consultant to the refining industry. CHRISTOPHER DEAN is an independent process engineering consultant with over 37 years in the worldwide refining business with an emphasis on high olefin fluid catalytic cracking (HOFCC) with petrochemical integration. He is the founder and principal consultant for High Olefins FCC Technology Services LLC. His worldwide refining background includes the development and commercialization of the High Severity-FCC Process, the development of several integrated refinery and petrochemical projects, catalyst technical service, process engineering, design and unit operations on a variety of refinery units. He has published or presented over 30 papers and has been issued two patents on FCC gasoline desulfurization and has three other FCC pending process patents.

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Special Report

Refinery of the Future M. TRYGSTAD, Yokogawa Corp. of America, Sugar Land, Texas

Consider high-fidelity online motor fuel characterization Motor fuels are complex products. Various diesel fuel and gasoline grades are prepared from a large range of individual blending components whose individual properties may be extremely variable over time. Each day, refiners must determine the blend recipe based on the properties, value and availability of those components, as well as the target specifications for the product. Once that is done, the operational challenge is to verify that the blended product delivered to the pipeline actually meets those contractually defined specifications. Variation in catalyst and unit operations, unrelenting cost pressures and an ever-wider range of crude oil feedstocks compound the challenge. No matter how daunting these factors are, it still remains the refiner’s job to manage all elements so that they are transparent to the pipeline operator. Meeting specifications can mean either that a property value must not fall below a defined minimum or be greater than a do-not-exceed limit. An obvious example is octane in gasoline. Regulations are designed to ensure that the octane value of gasoline sold as 91 octane is, in fact, not less than 91. Yet, the pipeline operator and the consumer filling up at the gas station are not concerned if the refiner delivers 92 octane instead. But, for the refiner, such property giveaway can be costly. Do-not-exceed specifications include sulfur, Reid vapor pressure (Rvp) and benzene, for which government regulators define maximum values. Similarly, cold properties in diesel—such as cloud point, pour point and cold-filter plugging point—have maximum that vary seasonally. In general, the greater the excursion from specification limits into “safe” territory parts per million (ppm), the greater the potential profit loss for the refiner. Complex product. Gasoline is more complex than diesel in that it typically has a larger range of potential blending components (up to 10). While the individual components may contain 100 or even hundreds of distinct chemical compounds, the blended product may have over 1,000. The objective in blending is not to control the individual components, although toluene may be added to increase octane while butane both enhances octane and improves starting in cold weather. Rather, final blend properties are dialed in during the process by controlling the ratios of the blending components, each of which has its own unique set of properties. The fact that properties often interact in opposing ways further aggravates the difficulties of blending. For example, adding butane boosts octane, but can raise Rvp beyond acceptable limits.

Online analysis of properties in the blended product is critical for meeting specifications and minimizing property giveaway. Refiners without online property analyzers must “blend to tank” and then sample the blended batch before releasing it to the pipeline. Online analyzers do not necessarily eliminate this practice. However, real-time monitoring and feedback control to the blending optimization program help ensure that no rework (batch adjustment) will be required before release to the pipeline. Online property measurements can help minimize errors in manual sampling and testing. Also, the fact that blending control is based on hundreds of measurements (FIG. 1) instead of a few samples taken to the refinery laboratory leverages the statistical benefits. Motor fuel properties. Listed here are properties that are

among the many that must be certified to specifications governing custody transfer via pipelines: • Research octane number (RON), motor octane number (MON) or pump octane, which may be calculated as an average of the two (gasoline) • Rvp (gasoline) • Benzene (gasoline) • Sulfur (gasoline and diesel) • Distillation yield points (gasoline and diesel) • Pour point (diesel) • Cloud point (diesel)

FIG. 1. Blending control is based upon hundreds of measurements. Hydrocarbon Processing | JULY 201455

Refinery of the Future • Cold-filter plugging point (diesel) • Flash point (diesel) • Polycyclic aromatic hydrocarbon (PAH) compounds, also known as polynuclear aromatics (PNAs) for diesel. Given the immense number of properties that must be controlled during blending, a control strategy that uses online analyzers normally depends on having one analyzer for each property or group of properties. Thus, a gas chromatograph can generate values for multiple distillation points, but most other properties require a dedicated analyzer. The analyzer for octane is actually a high-tech engine, called a “knock engine.” These engines are very expensive and labor intensive. The high cost to install, operate and maintain online analyzers has led to the quest for a less complicated, more comprehensive approach. What refiners want is the ability to predict final product characteristics based on the simplest and least expensive analysis methods. For over 20 years, refiners have sought relief for this problem by predicting motor fuel properties based on inferential spectrometry. The earliest and most common example is multivariate near-infrared (NIR) spectroscopy, with Fourier transform infrared (FTIR) and Fourier transform near infrared (FTNIR) being important variants. All of these technologies infer properties via the advanced multivariate statistical modeling discipline known as chemometrics. Proponents of a particular spectroscopy technology argue that theirs has advantages over the others. And while some do excel for very specific, technical reasons (which are beyond the scope of this discussion), none are completely satisfactory. More recently, users have considered Raman spectroscopy and nuclear magnetic resonance (NMR) technologies. What is the problem? No single method has emerged as a fool-proof, always reliable, one-size-fits-all approach. Though inferential spectrometry has well-established capabilities, users hoping for a perfect solution find, instead, that ongoing fidelity demands ongoing modeling. Further, all properties apparently do not lend equally well to this inferential approach. In an effort to make refiners comfortable with their particular type of NIR analyzer, Raman analyzer or NMR analyzer, vendors refer to the sample spectra they measure as “finger-

prints.” They further explain, that because each compound’s spectrum is unique, their combination in various concentrations will produce a spectral fingerprint that is also unique. The job of chemometrics, then, is to correlate a mixture’s fingerprint with its properties. But, as anyone reading a detective thriller knows, this analogy quickly falls apart at two levels. First, spectroscopy adds another dimension, in that it is not just about pattern recognition, but also is quantitative. Extending the analogy, it is like trying to have a crime-scene investigator examine a fingerprint left on a glass and using it to determine how hard a finger was pressed against the surface. Second, the fingerprints of two different gasoline blends may be quite similar (or even identical), given the large number of ways that a refiner can blend products to meet quality specifications. Thus, the expectation is that inferential spectrometry will work for the numerous recipes that combine blending components with a variable property makeup. With the average concentration of compounds in gasoline being 100%/1,000 = 0.1%, consequently, the requirements for developing and updating chemometric models do not square with the expectations for prediction fidelity. At issue is the fact that all compounds in a blend give responses across the same wavelength or frequency scale. What differentiates them is that their signal strength at each wavelength is not the same. But all those individual fingerprints are effectively superimposed on each other in the final spectrum of the blended product. A musical analogy. Compare the process to recording a symphony orchestra. No matter how many instruments there are, what gets recorded via a microphone becomes a single waveform. If you examine that waveform on a computer, you can identify an instrument playing a note at 440 Hz, but you may not be able to tell if that instrument is a clarinet, violin, trumpet, something else or all of the above. If you listen to one instrument at a time, you might be able to identify what you are hearing from the waveform. However, with more instruments, it will become increasingly difficult or even impossible to distinguish among the various components that together produce the music. Such is the case with analyzing motor fuels: you are looking for small but significant differences in the spectrum. Many of the compounds are quite alike and have similar NIR expressions, but recognizing these small but distinct differences is the key to properly quantifying motor fuel characteristics.

Intensity

Can one spectrum define the chemistry? There is no

Wavelength

FIG. 2. Overlaid spectra for a number of different gasoline blends at a single refinery. Although the overall shapes of the spectra are very similar, they differ with respect to the relative intensities of absorbance values from one end to the other.

56JULY 2014 | HydrocarbonProcessing.com

question that the spectrum is determined by the chemical composition, and that all the individual components combine to create the final result. Given all those variables, it is no surprise that developing and keeping high-fidelity models in tune is difficult. The fact that inferential spectrometry works as well as it does attests to the technology, the high information content in the spectra, and the power of chemometric modeling. The possibility exists that two measurably different spectra from two different blends will have practically identical properties (FIG. 2). Moreover, two spectra that are practically indistinguishable may have measurably different property values. In mathematical terms, a chemometric model under-determines the chemistry of the sample. It also means that properties of

Refinery of the Future interest do not express themselves uniquely in a given sample spectrum. In terms of information science, the degrees of freedom in the chemistry of a calibration sample set used to make chemometric models exceed the degrees of freedom in the spectra for those samples. Certainly, correlations exist between the properties and the information in the spectral data, but the correspondence between the chemistry and the spectral data is incomplete. So, the information from any of the measurement methods does not uniquely and completely describe the chemistry of the mix. Ranking the technology. When considering the variety of online analyzer technologies on the market, the strengths and weaknesses of each product should be thoroughly parsed. Remember that obtaining a good result depends on getting solid reference data from the lab, which then becomes the data used in making the model. This means that the modeling sample set must be representative of the full range of blend recipes. The crux of the debate is determining what aspect has more shortcomings, the spectrometer or the modeling? The modeling algorithms are the key, since they will allow for chemometric success. However, sometimes refiners need more than the technology can deliver, and vendors do not like to admit that their product is not up to the task. The solution to this quandary may lie with selecting the best analyzer technology for the application, and then using the data generated by the analyzers in a systematic, technically respon-

sible fashion. NIR has been the default approach for many years for motor fuel analysis. Most users accepted it because, until about a decade ago, there was little in the way of alternatives. But the difficulty in obtaining high-fidelity property predictions has allowed other spectroscopic technology vendors to suggest that the information content in NIR spectra is insufficient. Vendors of Raman and NMR spectrometers for online motor fuel applications have been gaining attention in the market, due to the novelty of these technologies and the disparity between the promise and performance of NIR. Chemists have long relied upon NMR, mid-IR and Raman instruments to elucidate the chemistry and structure of compounds that are nominally pure. This is because the spectral responses are 2 Measurement of spectra of all samples (s1, s2, ..., sn)

1 Population of calibration samples

5 Input into modeling software and model development

6 Model for property “Pi”

4 Data set for property “Pi”

7 Process sample to be analyzed

9 Predicted value for property “pi”

3 Measurement of spectra of all samples (pi1, pi2, pi2, ..., pin) Development of modeling data set for properties “P”

8 Measurement of the spectrum of the “unknown” process sample

Modeling

Property measurement

FIG. 3. Overview and implementation of inferential spectrometry models.

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Refinery of the Future discrete and lend to interpretation unaided by chemometrics. Certainly, the information they generate is more accessible, but the point is that, generally, the value of the methods is secured without chemometrics. By contrast, motor fuel property prediction is a statistical, population-based enterprise: it’s a different game, and different rules apply. In practice, when working with motor fuels, Raman spectroscopy and NMR have a track record similar to NIR when it comes to predicting fuel characteristics. Indeed, claims that superior information content is the key to successful inferential spectrometry ring hollow when it comes to mixtures containing hundreds or thousands of components. On that basis, an informed spectroscopist will reason that the best performance available from any molecular spectroscopy technique cannot exceed that of the best FTNIR spectrometer. Solution. Is the situation hopeless? No, but the answer will not be found in looking for new technology. Instead, the best solution is to be more vigilant about maintaining and applying spectral data sets used to create property models. Refiners seeking to apply online inferential spectrometry for motor fuels analysis have high expectations driven by their need to meet contractual obligations and maximize profits. But the noted gap between those needs and the performance delivered by inferential NIR spectrometry has caused much doubt concerning the latter, with the first assumption being that there must be something wrong with the technology.

The simple fact is that there is no magic. These technologies work, but they must be applied with discipline: • Keep spectral data set models up to date • Be fanatical about reference value accuracy from the lab • Examine and test the model assumptions regularly • Be sensible about data evaluation and realize its limitations. More specifically, inferential spectrometry for motor fuel property prediction depends on attention to elements depicted in FIG. 3. These elements include: • Proper development and selection calibration samples used in modeling • Transfer those samples to the laboratory in a way that preserves sample integrity, followed by properties analysis • Model development consistent with best practices • Initial and ongoing inferential prediction validation by statistical comparison • Constant property model changes via continued modeling data set updates. Motor fuel analysis requires refiners to take control of the situation. Those involved should possess a realistic understanding of what is and is not possible, and have a firm grasp on what information can be extracted dependably. This information must then be used in an intelligent manner to continuously update the inferential analysis, a process that requires experience, engineering expertise and refined judgment. MARCUS TRYGSTAD is a business development manager in advanced analytical solutions for Yokogawa Corporation of America.

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Special Report

Refinery of the Future V. V. GALKIN and V. MAKHIANOV, Gazprom Neft, Moscow, Russia; and M. I. LEVINBUK, Topchiev Institute of Petrochemical Synthesis, Russian State University of Oil and Gas, Moscow, Russia

Case history: Modernization of Russia’s refining industry—Part 1

H2S

Dry gas GFU

SRU

IBP-70 IBP-180

H2

HPU

Isomerizate (blending)

Isomerization

Naphtha HT

70-180 180-240 Kerosine HT Gasoline-stripping 240-350

Reformate (blending)

Reforming

Kerosine (sale)

SDF (sale)

DF HT

Light CCG (blending) LCGO

Crude oil

Sulfur

LPG (sale) Natural gas

Gasoline, DF

Heavy CCG (blending)

CCG HT

FCC Naphtha VGO

VGO HT

BBF (blending/sale)

FCC HCGO

BACKGROUND Changes in Russian law will introduce technical regulations on the quality of oil products, excise duties for various transportation fuels and refined products, and refinery utilization or efficiency without heavy residue processing.4–6 The most effective modifications are processing schemes that maximize middle distillates output. Many mini-refineries will be closed due to economic reasons. Medium-sized refineries with capacities less than 5 MMtpy and without complex and efficient refining processes offer low profitability. However, incorporating flexibility to handle heavy-oil residue can increase their economic efficiency and provide payback for the medium-sized refineries. The new export duties on heavy-oil residue products will start in 2015; they are almost 100% for duties on crude oil.7 Because the majority of produced fuel oil is exported from Russia, this measure would cause sharp decreases in profitability, especially for less-efficient refineries. Russia’s refining industry is composed of large refineries, medium-sized facilities and numerous mini-refineries.1–3 At present, all refineries are under evaluation for future revamps

and modernization. Such an endeavor by an industry poses many questions, such as: • Will installing processing capacity to handle heavy-oil residues provide needed profit with new export duties, especially for medium-sized refineries? • What is the minimum capacity for a refinery to be profitable and provide return on investment (ROI) within a reasonable time? • What is the minimum level of investments necessary to upgrade the refineries? The authors present efficiency assessments for refinery modifications for three refining schemes: gasoline, diesel and

Atmospheric and vacuum distillation

Russian laws governing transportation fuels and crude oil have undergone many changes. These regulatory changes will involve the revamping of Russia’s refining industry. At present, this nation has 22 large refineries—each with a throughput capacity of 5 million tpy (MMtpy), according to the Russian Ministry of Energy’s register.1–3 However, the domestic refining industry includes eight mid-sized refineries with capacities ranging from 1 MMtpy to 5 MMtpy and over 200 small refineries with significantly much lower processing capacity (under 1 MMtpy). Under the new laws, domestic refineries must modernize or shut down. Not all of Russia’s refineries will be upgraded. The following technical review outlines the economic strategies that will be applied to select the refineries that can be modernized cost-effectively. Important questions to be resolved include: What are the possible impacts to Russia’s refining and petrochemical industries? What new process technologies will be most effective to optimize the output of gasoline, middle distillates, or petrochemical feedstocks, and to upgrade heavy oil residues?

VR

Visbreaker Bitumen plant

Commercial fuel oil (sale) Bitumen (sale)

Abbreviations: HT – hydrotreating, CCG – catalytically cracked gasoline, FCC – fluid catalytic cracking, VGO – vacuum gasoil, SDF – summer diesel fuel, HPU – hydrogen production unit, SRU – sulfur recovery unit, HCGO – heavy catalytic gasoil, LCGO – light catalytic gasoil, VBR – visbreaking

FIG. 1. Process flow diagram, gasoline option. Hydrocarbon Processing | JULY 201459

Refinery of the Future Dry gas GFU

IBP-62 (sale)

Sulfur

SRU

Natural gas

H2

HPU

Reformate (sale)

Naphtha HT Reforming

140-240

Kerosine (sale)

Kerosine HT

Gasoline-stripping 240-350

SDF (sale)

DF HT Heavy naphtha

Gasoline DF

Crude oil

Atmospheric and vacuum distillation

62-140

H2S

LPG (sale)

VGO

IBP-62 SHCD (sale) Kerosine (sale) DF (sale)

SHCD Unconverted oil

Commercial fuel oil (sale)

Visbreaker

VR

Bitumen (sale)

Bitumen plant

Abbreviations: VGO – vacuum gasoil, SDF – summer diesel fuel, DF – diesel fuel, HT – hydrotreatment, SHCD – VGO hydrocracker, HPU – hydrogen production unit, SRU – sulfur recovery unit, VBR - visbreaking

FIG. 2. Process flow diagram, diesel option.

Dry gas GFU

LPG (sale) H2S

IBP-62 IBP-140

140-240

Benzene (sale) Toluene (blending/sale)

Kerosine HT

Reforming

Reformate splitter Natural gas

HPU

H2

SDF (sale)

DF HT LCGO

240-350

Light CCG

TAME production

CCG HT

VGO HT DCC HGO

VR

Capital cost. Investment costs for plant construction are calculated on the basis of available data for similar plants, as well as data received from КВС and CLG companies.7 Investments are recalculated for different plant capacities:8

I = Iа × (C / Cа )0.6 TAME fr. (blending/sale) Heavy CCG (blending)

BBF

VGO

ASSESSMENT CRITERIA Three key oil refining models are used in the analysis:1 1. Gasoline based on catalytic cracking 2. Diesel based on vacuum gasoil (VGO) hydrocracking 3. Petrochemicals for maximum production of petrochemical feedstock, based on fluid catalytic cracking (FCC) with maximum yield of С3–С4 olefins. FIGS. 1–3 demonstrate the principal processing configuration. Each configuration integrates heavy-oil residues processes: • Bitumen production • Residue hydrocracking (70% conversion) • Coking • Deasphalting. To achieve fuel specifications, hydroprocessing capacity is also increased. Estimates for the listed products were calculated for throughput capacities ranging from 1 MMtpy to 10 MMtpy, in increments of 1 MMt. This approach clearly shows the trends in economic efficiency for small-, medium- and largesized refineries. The goal of the study was to identify the minimum capacity to revamp that would provide ROI under current Russian Federation legislation. The process model used a minimum set of processes to control project investments. The model focused on producing Euro-5 transportation fuels and residue processing. Crude quality is taken equal to Urals oil, with sulfur and light petroleum product content of 1.4% and 47%, respectively. Export duties are set per current Russian Federation law.2 Crude prices used in the analysis were $90/bbl to $100/bbl. The analysis also considered price decreases of $80/bbl and $60/bbl.

Raffinate (sale) Xylene fr. (sale)

Kerosine (sale)

Gasoline stripping

Gasoline, DF

Atmospheric and vacuum distillation

Crude oil

Isomerizate (blending)

Isomerization

Naphtha HT 62-140

Sulfur

SRU

petrochemicals. These schemes also include consideration to handle heavy-oil residue. A sensitivity analysis of ROI addresses variable oil prices.

MTBE (blending/sale) MTBE production LPG (blending/sale) DFCC Alkylate BBF (blending/sale) (conv.) Alkylation Propylene (sale)

Visbreaker Bitumen plant

Commercial fuel oil (sale) Bitumen (sale)

Abbreviations: HT – hydrotreating, CCG – catalytically cracked gasoline, DFCC – deep fluid catalytic cracking, VGO – vacuum gasoil, SDF – summer diesel fuel, DF – diesel fuel, HPU – hydrogen production unit, SRU – sulfur recovery unit, HCGO – heavy catalytic gasoil, LCGO – light catalytic gasoil, VBR – visbreaking

FIG. 3. Process flow diagram, petrochemical option.

60JULY 2014 | HydrocarbonProcessing.com

where I is the calculated investments for a plant with capacity, C. Iа and Cа are known investments and capacity of a refinery. Construction costs for auxiliary and power facilities, offsite facilities (OSFs) and construction management expenses are estimated as 70% of the cost for the main processing units. This level of costs corresponds to constructing a new refinery. If the refinery has a well-developed infrastructure, then this ratio can be decreased. However, taking into account the process models of small- and medium-sized refineries in Russia, the modification will be comparable to building new refineries. Operating costs are calculated on the basis of actual plant performance at OJSC Gazprom Neft refineries and reference data.7 To minimize operating and capital costs, it is assumed that plants are constructed as complexes rather than as individual units. Complex construction is executed in parallel,

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Refinery of the Future which minimizes the timeframe. The main assessment criteria include: 1. Crude conversion ratio 2. Yield of light petroleum products 3. Breakeven point. Note: If the capital investment for the modifications is high, then depreciation will also account for a large share of fixed costs. 4. Net present value (NPV) 6 Gasoline Diesel Petrochemical

CAPEX, $ billion

5 4 3 2 1 0 0

1

2

3

4 5 6 7 8 9 Refinery capacity, MMtpy

10

11

12 1

Gasoline Diesel Petrochemical

NPV export duties 2015, $ billion

NPV export duties 2012, $ billion

2

1

0

0

-1

-1 0

1

2

3 4 5 6 7 Refinery capacity, MMtpy

8

9

10

0

5. Minimal refinery capacity in which the ROI for the modifications has a payback of less than 15 years. All process models are made and optimized in MS Excel spreadsheets and validated.a

HEAVY-OIL RESIDUE PROCESSING OPTIONS Production of bitumen is the least capital-intensive method for tar processing. A significant drawback of this scheme is the dependence on seasonal fluctuations of the bitumen market in Russia. DurGasoline ing the winter, bitumen consumption 95.8% Diesel 93.2% decreases considerably. FIG. 4 illustrates 91.2% Petrochemical the efficiency by the selected refinery configurations with bitumen production without restrictions on selling bitumi71.0% nous products. 65.9% 62.9% The model allows for the oil conversion ratio at the 91%–96% level and the yield of light petroleum products of 63%–71%. These estimates apply to a Crude conversion, % Yield of light petroleum products, % 10-MMtpy refinery with an estimated $4 billion (B)–$5.2 B capital expense (CAGasoline PEX). Because of the high yield of “dark” Diesel Petrochemical oil products, only oil refineries with capacities of more than 9 MMtpy–10 MMtpy will be profitable under the new 2015 export duties. However, at present export duties, smaller-capacity refineries (4 MMtpy–5 MMtpy) can provide ROI. The breakeven point is 0.6 MMtpy 1 2 3 4 5 6 7 8 9 10 11 12 at the 2012 duties, and it increases up to Refinery capacity, MMtpy 1 MMtpy at the 2015 export duties.

FIG. 4. Efficiency of oil refining schemes with production of bitumen. 7 Gasoline Diesel Petrochemical

6 CAPEX, $ billion

5

Gasoline Diesel Petrochemical 79.7%

85.1% 86.6% 81.9% 76.6%

4 3

67.5%

2 1 0 0

1

2

3

4 5 6 7 8 9 Refinery capacity, MMtpy

10

11

Crude conversion, %

12 1

Gasoline Diesel Petrochemical

NPV export duties 2015, $ billion

NPV export duties 2012, $ billion

1

Yield of light petroleum products, %

0

-1

Gasoline Diesel Petrochemical 0

-1 0

1

2

3 4 5 6 7 Refinery capacity, MMtpy

8

9

10

0

1

2

3 4 5 6 7 Refinery capacity, MMtpy

FIG. 5. Performance of oil refining schemes with process of tar hydrocracking.

62JULY 2014 | HydrocarbonProcessing.com

8

9

10

Residue hydrocracking. Hydrocracking of vacuum residue (VR) is not a widespread method for processing heavy-oil residues, although interest in this process has increased. For example, JSC Lukoil made a decision to construct residue hydrocrackers at the Bourgas (Bulgaria) and Nizhny Novgorod refineries. More importantly, new residue hydrocracking processes are under development, along with modifications to established processes. In 2012, the installation of a new hydrocracking technology at an Italian refinery was announced. Considering the relevance of heavyoil residue processing, Russian research institutes are also engaged in developing hydrocracking technology. The Russian Academy of Science Petrochemical Synthesis Institute is building a demonstration facility, called Topchiev. Construction is scheduled to be finished by 2015–2016. FIG. 5 shows the performance of refineries with residue hydrocracking capacity. Conversion is assumed at 70%. Such

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Refinery of the Future schemes allow attaining processing efficiency at 82%–87% levels and yield of light-oil products at 68%–80%. Needed CAPEX ranges from $5.2 B to $6.2 B, depending on the final product slate (gasoline, diesel or petrochemicals) for a 10-MMtpy refinery. Due to incomplete residue conversion and high investment costs under the 2015 export duties, only refineries with capacities of 8 MMtpy–9 MMtpy are profitable. However, under present export duty options, refineries 6 Gasoline Diesel Petrochemical

CAPEX, $ billion

5

84.3% 79.5%

4

76.7%

3 2 1 0 0

1

2

3

4 5 6 7 8 9 Refinery capacity, MMtpy

10

11

Crude conversion, %

12 1

Gasoline Diesel Petrochemical

NPV export duties 2015, $ billion

NPV export duties 2012, $ billion

1

0

-1

Gasoline Diesel Petrochemical

with capacities of 6 MMtpy–7 MMtpy can provide an ROI. The breakeven point is 0.7 MMtpy at the 2012 duties, and it increases up to 0.8 MMtpy at the 2015 duties level. Deasphalting. Deasphalting is one of the most widespread processes of VR processing. Selection of asphalt-free oil depends on the distribution of metals in the initial VR and its CCR. For the VR produced from Urals oil, 55%–60% yield is realistic.8 Processing schemes with deasphalting of the VR allow reaching a process efficiency of 77%–84% with yield of Gasoline Diesel light products at 63%–78%. The investPetrochemical ment is $4.8 B to $5.5 B for a 10-MMtpy 78.4% refinery, as shown in FIG. 6. Because of 73.3% high asphalt yield (11% for oil) and under the 2015 export duties, only oil re63.0% fineries with capacities over 7 MMtpy are profitable. Under the existing export duties, options with oil refining starting from 6 MMtpy–7MMtpy can provide Yield of light petroleum products, % ROI. The breakeven point is 0.7 MMtpy at 2012 duties, and it increases to 0.8 MMtpy at the 2015 duties.

0

-1 0

1

2

3 4 5 6 7 Refinery capacity, MMtpy

8

9

10

0

1

2

3 4 5 6 7 Refinery capacity, MMtpy

8

9

10

FIG. 6. Performance of oil refining schemes with process of deasphalting. 7 Gasoline Diesel Petrochemical

6 CAPEX, $ billion

5

86.1%

Gasoline Diesel Petrochemical

89.1% 83.6%

82.4% 78.2%

4 3

69.9%

2 1 0 0

1

2

3 4 5 6 7 Refinery capacity, MMtpy

8

9

Crude conversion, %

10 2 NPV export duties 2015, $ billion

NPV export duties 2012, $ billion

2

Yield of light petroleum products, %

Gasoline Diesel Petrochemical

1

0

-1

Gasoline Diesel Petrochemical

1

Next month. In Part 2, the authors

0

-1 0

1

2

3 4 5 6 7 Refinery capacity, MMtpy

8

9

10

0

1

2

FIG. 7. Performance of oil refining schemes with coking process.

64JULY 2014 | HydrocarbonProcessing.com

Coking. Coking installations use varying methods. Delayed coking, fluidizedbed coking and flexicoking are the most common installations to handle heavyoil residues. The coking process was widely applied in the countries of the former USSR to produce coke for the aluminum industry and ferrous metallurgy. Oil processing in Russia has a rich experience for the metals industry, which is very important in the final decision making. FIG. 7 shows the performance of refineries with coking capabilities. Such configurations allow attaining refining efficiency levels of 84%–89% with light product yields of 70%–82%. Investments of $5.2 B–$6.2 B are needed for a 10-MMtpy refinery. Calculations show that, due to the low coke yield and “dark” oil products (6% for oil), the 2015 export duties have no impact on the performance of these schemes. Oil refineries with capacity over 6 MMtpy can provide ROI. The breakdown point is 0.65 MMtpy at 2012 duties, and it increases 0.7 MMtpy at the 2015 duties.

3 4 5 6 7 Refinery capacity, MMtpy

8

9

10

compare the CAPEX and ROI to modernize select Russian refineries to meet new legislation governing transportation fuel qualities and excise duties for crude oil and refined products to begin in 2015.

Special Report

Refinery of the Future I. MONCRIEFF, Kline and Co., Parsippany, New Jersey

Which margin levers impact Group I and Group II base stock competitiveness?—Part 2 This is the second in a two-part series assessing the struggle taking place between Group I and Group II/III for market control and price formation in the global base stocks industry. Part I provided observations on the salient events of the recent past and their impact on the changes in profitability for Group I and Group II plants in their core markets. Part I focused on the past, and this installment looks to the future. Are the events of the previous two years a significant trough in a cycle that will return the base stocks industry to pre2012 norms of pricing relationships and profitability? Or are we seeing the early symptoms of a longer-term change in supply/ demand and price/cost relationships in the upstream segment of the lubricants industry that will bring margins and returns closer to those experienced in mainstream refining? To make those judgments, the next 10 years will be assessed for possible changes in the fundamental forces influencing base stock profitability and how these forces may shape the magnitude and timing of a possible recovery in industry margins.

OVERCAPACITY AND UNCERTAINTY Pricing is a symptom of the interplay between the underlying fundamentals of demand, capacity, plant operations and costs, all comingled in the crucible of competition. Information about these fundamentals is available to all mainstream refinery operators daily (if not in real time). However, the transparency in commoditized refined products markets does not yet extend fully to base stock markets, and is even murkier in finished lubricants. While more limited transparency may be a boon to marketers (creating fertile ground for branding and other forms of differentiation), it is a mixed blessing to base stock producers, particularly those perched precariously on the brink of extinction. It is difficult to develop reliable data on historical demand, supply, capacity or production for time intervals of less than one year. When lubricant consumption estimates are then translated into base stock demand, a further set of complexities is added, due to the need to deduct the estimated volumes of additives, and to add the uncertain quantities of base stocks used in nonlubricating applications. These applications include drilling fluids, solvents and illegal fuel adulteration. Since base stock producers are unable to access near-term assessments of overall market fundamentals, they are forced to rely heavily on their own micro-view of the world. These data limitations can introduce a greater degree of uncertainty into the base stocks market, particularly at times when overcapacity threatens. Marginal Group I producers can plan shutdowns for mainte-

nance turnarounds, but they seem very reluctant to permanently close or mothball plants for economic reasons until there is extensive evidence that a return to profitability is unlikely. One example: A mid-size Group I producer, still in operation, whose aggregate losses in the past two years have reached $90 million. In cases such as this, the permanent shutdown process may be prolonged by the fact that many of the most-affected owners are nationally-controlled, or are independent producers situated in locations with benign socioeconomic policies. In short, the behavioral forces sustaining this inefficient supply overhang have exacerbated the fundamental weakness experienced in base stock markets over the past two years.

TEN YEARS ON The outlook for the key margin levers impacting the global base stock business over the next 10 years can be divided into five sections. These are: • Lubricants consumption • Capacity utilization • Interplay of base stock profitability and capacity utilization • Option values • Inter-group competition. Lubricants consumption. Despite evidence of stagnant global lubricants demand since 2005, conventional wisdom is that the less-developed world and the BRIC countries will be the engines of growth in lube consumption. Recent forecasts generally bracket a compound worldwide growth rate of 1% to 2% a year over the next 10 years, with declining consumption in Europe and North America more than offset by growth elsewhere. A business-as-usual (BAU) projection of 1.4%/year in global lubes demand to 2023 produces an additional 5 million tons per year (MMtpy) of base stock demand by the 10th year. That incremental base stock demand is equivalent to the effective capacity of nearly five Pascagoula’s (Chevron’s lubricant plant in Mississippi), or roughly 12–15 marginal Group I plants. The industry’s past expectations of future lubes demand growth spawned the new investments in Group II and Group III plants that have been announced in the past several years, totaling nearly 10 MMtpy of production if operated at expected calendar day capacity. If all these planned capacity additions come onstream, the BAU demand growth outlook will require some significant capacity rationalization (primarily in Group I) over the next several years, if further erosion of global operating rates is to be avoided. Hydrocarbon Processing | JULY 201465

Refinery of the Future

80

ginal Group I producers for discretionary markets. How does the potential uncertainty in base stock demand interact with projected capacity additions, and what does that imply for the potential ranges of effective global capacity utilization in the future? Effective capacity is defined at 84%–86% of nameplate, taking account of the typical stream day operability of Group II/III plants (around 90%), offset by the lower calendar-day availability of Group I and naphthenics units. The implications of the BAU and “no growth” global lubricant demand scenarios on projected base stock effective capacity utilization, assuming no future shutdowns of underperforming Group I/II plants, are depicted in FIG. 1. The effective capacity utilization outlook in FIG. 1 accounts only for the nearly 170 Mbpd of new Group II/III capacity that is firmly committed to come onstream over the next four years. It excludes a further 50 Mbpd of announced projects that haven’t yet broken ground and are therefore considered uncertain. In FIG. 1’S BAU demand scenario, effective capacity utilization continues to drop, and does not recover to even 2013 levels of 84% until late in this decade. This outcome is fundamentally unsustainable, as low base stock capacity utilization results in lower profitability or operating losses. Moreover, the progressive decline in core Group I markets will put competitive volumetric pressure on all Group I producers, increasing per-barrel fixed costs. Throughput efficiency will be distributed unevenly, with large, integrated Group II/III plants operating at above-average utilization, and smaller and export-dependent Group I plants struggling to survive. If the future of plant utilization is projected to deteriorate further in the next five years, what are the implications of that overcapacity on base stock production margins, and on shutdowns of inefficient plants?

75

Profitability vs. utilization. FIG. 2 incorporates recent research

But what if the demand fundamentals do not evolve as expected? The current and prospective excess of higher-quality Group II/III base stock supply over technical demand is accelerating the displacement of Group I in many traditional formulations. In the automotive market, the drive toward extended drain intervals continues, with fill-for-life the potential end-game. Can growth in industrial lube consumption offset greater efficiency in the automotive dynamic? The macroeconomic forces impacting growth in the global vehicle fleet and in gross domestic product (GDP) are beyond the discussion here, but it would be foolhardy to ignore the market realities of the past eight years. Is a future of no growth in global lubricants demand certain? No, but it would be remiss to ignore the lessons of history without at least considering that scenario when contemplating the future of lubricant demand. Capacity utilization. The rush to add new very-high-viscosity index (VHVI) base stock capacity in the aftermath of the economic rebound of 2010 is likely to be felt well after their startup dates, as large new Group II and III plants compete with mar105 Actual 2007–2013 BAU lubes demand No lube demand growth

100

Capacity utilization, %

95 90 85

70 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

FIG. 1. Actual and projected global base stock effective capacity utilization with no Group I/II shutdowns, 2007–2023. Source: Kline and Co.

20 15

Total feed, $/bbl

10 5 Slope = 75¢/bbl per 1% change in caputil R2 = 0.66 0 -5 -10 80

85 90 95 100 Utilization of global effective capacity (all groups), %

FIG. 2. European Group I cash margins vs. global effective capacity utilization from 2005–2013, excluding 2009. Source: Kline and Co.

66JULY 2014 | HydrocarbonProcessing.com

105

on the relationship between the effective utilization of worldwide base stock capacity (caputil) and cash margins. The data and analysis supporting this relationship are (necessarily) aggregated and thus may not be representative of the specific circumstances of individual plants. Nevertheless, there is empirical evidence of a causal relationship between plant utilization and cash margins, with the consequent impacts on base stock pricing. Group I plants in Europe are worth focusing on, because they are the high-cost/low-value players in the base stock market, and are most vulnerable to bumping against cash cost breakeven or worse. As long as Group I shutdown economics dictate the floor of base stock pricing, it is this supply source that is most critical to price formation in a structurally long market. The slope of the caputil/margin graph is impacted by some uncertainties around the pricing of byproducts, such as the various aromatic extracts, solvent deasphalting (SDA) tars and waxes, and, by the export-dependency of specific producers. Thus, this must be taken as only generally indicative of the impact that overcapacity has on cash margins. The base stock caputil/cash margin relationship slope, at around $0.75/bbl of feed, must then be translated into an equivalent gradient for base stock pricing adjustments. Since Group I plants are on-purpose for base stocks and not for byproducts, the entire incremental margin leverage on feed could be attributed to base stocks. In effect, historical move-

Refinery of the Future

TABLE 1. Cumulative Group I/II shutdowns required to sustain future global effective capacity utilization at certain levels, in Mbpd

120 Required BAU shutdowns Firm capacity additions

100 80 60 40 20 0 -20

Effective capacity utilization, %

BAU demand

No growth demand

80%

70

86

85%

134

151

90%

191

208

Source: Kline and Co.

the next several years, just to sustain effective operating rates at or above 80% cash breakeven in the BAU scenario, with an additional 16 Mbpd of closures required in the “no growth” outlook. The industry is heeding this message, as Shell announced in April plans to close its 7.3-Mbpd Group I plant in Pernis, The Netherlands. Significantly more capacity must be shut down to return medium-term profitability to the global base stocks industry that would be associated with caputil (TABLE 1).

KB/SD

ments in capacity utilization are very largely responsible for the changes in base stock price movements, which have been observed over the past eight years. In FIG. 2, cash breakeven on a typical European domestic market-oriented Group I plant is between 80% and 85% of effective capacity. If projected utilization falls below that range (as portrayed in FIG. 1), all bets are off, since sustained negative profitability will lead inevitably to closure of underperforming assets and a consequent rebalancing of the supply/ demand dynamic. The assets at risk are primarily Group I, but also possibly some less-advantaged Group II units. This capacity closure/caputil dynamic is illustrated in FIG. 3, where projected capacity shutdowns have been adjusted to ensure that effective capacity utilization is maintained at no lower than 80%, the minimum expected cash breakeven level. The projections in FIG. 3 suggest profound consequences. Some 70 Mbpd of inefficient capacity must be shut down in

-40 -60 2014

2015

2016

2017

2018

2019

2020

2021

2022

2023

FIG. 3. BAU capacity shutdowns required to sustain global effective capacity utilization at 80% minimum. Source: Kline and Co.

alves Best V 67 8 since 1

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Hydrocarbon Processing | JULY 201467

Refinery of the Future 25

20

$/bbl

15

10

5

0 2007

2008

2009

2010

2011

2012

2013

2014

Source: Valero

FIG. 4. Premium of ULSD over HSVGO on the US Gulf Coast, 2007 to YTD 2014. Source: Valero.

Option values. The economic competition that takes place

between base stock units and refinery conversion (FCC/HCC) units for access to vacuum gasoil (VGO) feed is well understood. Diesel demand growth has caused pressure on middledistillate supply, leading to more investment and lower-severity operations in diesel-oriented refinery conversion processes. The pressure on VGO feedstock supply to mainstream refinery conversion units has become severe, and US distillate/VGO spreads have narrowed as a result (FIG. 4). While diesel/VGO cracks are unusually thin today, and may recover somewhat as markets rebalance from the extreme North American winter of early 2014, longer-term pressures on middle-distillate supply are unrelenting. Since the majority of base stock plants today are entirely (or, in the case of Group I, significantly) dependent on VGO feed, the future is unlikely to be different from the recent past, as fuel markets dictate the price of feedstock relative to its option value in base stock manufacture. Looking at the Group I slate of products, much has been written about the impact of Group I plant closures on the supply and potential pricing of certain streams, such as highviscosity base stocks and waxes. Today, many Group I producers are looking into what choices they may have for tweaking production to produce more heavy neutrals and brightstocks at the expense of light neutrals, through some combination of adjustments to crude slate and process operations, as well as via enhanced SDA throughput. In effect, the reason for existence of Group I manufacture needs to be revisited, to concentrate progressively on vacuum bottoms deasphalting, with correspondingly diminishing volumes of VGO channeled to the lube unit as low-vis solvent neutral cracks remain weak. Group I plants are uniquely different from Group II and III plants, in that they produce large volumes of byproducts that are not commodity fuels, and which have more limited commercial market options. The most significant of these Group I byproducts, volumetrically, are aromatic extracts and SDA tars. Markets for both byproducts are small, in decline or both, resulting in the majority of Group I plant production of these byproducts finding its way into refinery cracking or coking (where available) units. A majority of the byproduct output of Group I plants is likely to be supplied into refinery feedstock markets where they are discounted in value relative to VGO or 68JULY 2014 | HydrocarbonProcessing.com

vacuum bottoms. There is increasingly negative margin leverage through the lube unit for these materials, representing more than 50% of feed, since the output value is lower than that of the feedstock. A smaller, potentially positive value lever is associated with the diminished production of slack wax or finished waxes (in plants with solvent dewaxing) as Group I plant closures occur. The positive margin contribution of potentially higher wax prices will be more than offset by downward pricing pressures on the larger-volume byproducts. The yield specificity of finished waxes, typically less than 5% of total output, is too small to sustain marginal Group I plants when much of the fundamental production balance (excluding high-viscosity base stocks) is neutral to negative. Inter-group competition. An unintended consequence of the recent decline in worldwide capacity utilization has been the narrowing of traditional price differentials between base stocks as higher-quality materials displace Group I in discretionary (nontechnical) markets. Viscosity has become as important as VI as an axis of price differentiation. Is this a temporary phenomenon, with a prospective return to the way things used to be? The answer is: No. Given the large new capacity of Group II and III about to hit the market, and the likely consequent acceleration in Group I closures, if anything, the prospects are for even greater inter-Group price compression, particularly given the lower cash-cost position of Group II and III production. These capacity additions and closures will bring about substantially greater supplies of low-viscosity, higher-VI products to the market, and reduce production of lower-VI stocks having a broader viscosity spectrum. How markets adjust to these fundamentals is less clear, but a steepening of the viscosity/price gradient is almost inevitable. Surviving higher-efficiency Group I plants, which focus heavily on high-viscosity solvent neutral and brightstock production, will be well-placed to take advantage of such an outcome.

REDEMPTION Amid the potential doom and gloom caused by the looming new capacity overhang, and the uncertain growth prospects for global lubricants demand growth, it is easy to conclude that Group I is moribund. Nothing could be further from the truth. But Group I needs to transition from its past as the dominant source of base stock supply and global price-setter. Group I will, over the next five years, need to embrace the mindset of specialty-niche supplier, focused on products and markets where its combination of viscosity spread, solvency and established product formulations can sustain competitive advantage for the most efficient players on the Group I cash-cost curve. Such an evolution is not unlike that which naphthenics producers have already been required to face. Ultimately, scale, cost-effectiveness, value-chain integration and market optionality will be the key factors determining which Group I plants close and which survive; but there will be a proper place for efficient Group I supply in any future lubricant markets. End of series. Part 1, June 2014. IAN MONCRIEFF is a director of Kline and Co.’s energy practice in Parsippany, New Jersey.

September 16–17, 2014 | Houston, TX

Explore the Latest Opportunities and Trends in North America’s Gas Market The inaugural GasPro North America will bring together gas processing professionals for a twoday, technical conference devoted to discussing the latest trends, technologies, opportunities and challenges in North America’s natural gas market. Falling natural gas prices and increased shale gas production in the US have led to a “golden age” of gas in North America with investment and activity increasing for LNG, GTLs, NGL and more. Boxscore data indicates a 76% growth in new gas processing project announcements within the past year, and numerous LNG terminals are in the planning phase. Canada is also well-poised to increase its shale gas production. North American natural gas is reshaping the global energy industry. GasPro is the perfect opportunity to network with your peers in the industry and keep up-to-date with the latest developments. Don’t miss the opportunity to be part of this important discussion.

The 2014 conference program will focus on:

View the Agenda Online! GasProcessingConference.com

Sponsor/Exhibit at GasPro, Contact Lisa Zadok, Events Sales Manager at +1 (713) 525-4632 or [email protected]. For more information about GasPro, Contact Melissa Smith, Events Director at +1 (713) 520-4475 or [email protected].

• NGL/LNG

• Dehydration/Cryogenics

• GTL/Modular Construction

• Stranded Gas/Sour Gas

• Compressors/Equipment

• Alternative Uses

• Separation Technology/ Catalysts

• Reliability

• North American Infrastructure Development

View the complete agenda online at GasProcessingConference.com

Register Now and Save! Conference Fees

Early Bird (by August 6)

Regular Admission

Single Attendee

$891

$990

Team of Two

$1,634

$1,815

Group of Five

$3,787

$4,208

Invited Speakers From: • Energy Transfer Partners

• Shell Oil

• Saudi Aramco

• Enterprise Products Partners, LP

• Targa Resources Inc.

• URS Corporation

• Valerus

• EnCana Corporation

• Velocys

• Exxon Mobil Research & Engineering Company

• Devon Energy

• Primus Green Energy

• Linde Process Plants

• DCP Midstream LLC

• Spectra Energy Corporation

• Noble Energy

| Bonus Report LNG Liquefied natural gas is a growing source of clean energy for gas-consuming countries and a rising source of revenue for gas-producing nations. A number of new liquefaction and regasification plants have been proposed in North America, Africa, Asia-Pacific and Eastern Europe. Engineering, design and operation of these new terminals—as well as the LNG carriers that transport and deliver the product—can be improved with intelligent simulation and data collection and monitoring, as discussed in this month’s bonus report. Photo: First LNG bunkering at the Port of Civitavecchia in Rome, Italy, May 2014. Image courtesy of LNGEurope.

Bonus Report

LNG R. WEILAND, Optimized Gas Treating Inc., Houston, Texas; J. SANTOS, INEOS Americas, Houston, Texas; A. PRADERIO, ConocoPhillips, Houston, Texas; N. MAHARAJ, Atlantic LNG Company of Trinidad and Tobago, Port of Spain, Trinidad; and M. SCHULTES, Raschig GmbH, Ludwigshafen, Germany

How sensitive is your treating plant to operating conditions? A normal expectation in the course of operating an amine treating plant for acid gas removal is that small changes in operating conditions will result in correspondingly small responses in plant performance. However, such expectations are not always well founded. To establish credibility for the process simulator used in the design of a new LNG plant, the mass-transfer rate-based simulation results for the new plant are compared with performance data from an operating LNG plant. Attention is then turned to another LNG project under study. The project’s carbon dioxide (CO2 ) removal system consists of a single, large absorber serviced by two regenerators in parallel. Initially, the plant would process about 1,400 million cubic feet per day (MMcfd) of gas containing approximately 16 mol% of CO2 . A sensitivity analysis shows potential susceptibility of treating performance to departures of certain operating conditions from design values, and it also provides reasons for this sensitivity.

UNDERSTANDING OPERATING PARAMETERS There are a number of well-accepted limits on plant operating parameter values. Examples are corrosion considerations for carbon steel, which usually limit rich amine CO2 loadings to below 0.4 mole–0.45 mole of CO2 per mole of amine. They also place upper limits on maximum line velocities to prevent the direct scouring of surfaces and the removal of protective films, particularly sulfide layers. Tower internals have natural restrictions on gas and liquid rates.

Beyond these natural hydraulic capacity limits, jet flooding or downcomer backup and choke flooding of trays, or packed column flooding, may occur. Finally, solvent capacity is itself limited by temperature and acid gas partial pressures. Corrosion, temperature and acid gas pressures all limit rich solvent loadings, while limitations on tower hydraulic capacity restrict throughput. These limits restrict performance, but they do not cause oversensitivity of performance to small changes in the values of operating parameters. However, the “smallresponse-to-a-small-stimulus” paradigm has changed with the introduction of fast-reacting solvents, such as piperazine for CO2 removal. The development and availability of highly precise simulation toolsa have encouraged the design and construction of new plants with lower design margins. They have also allowed engineers to assess precisely the effect of operating parameters on performance, and have revealed the existence of operating cliffs or points of instability on the performance map.1 Although, regions of increased sensitivity have been predicted even for moderately fast-reacting CO2 -monoethanolamine (MEA) absorbers, when piperazine is used to promote methyl diethanolamine (MDEA), reaction rates grow very large, and unexpectedly high sensitivity of performance has been observed. None of this has been predictable using the more traditional idealstage simulation tools, even when they have been modified with efficiencies, and even with attempts to force reaction kinetic rates into what is fundamentally

an equilibrium model. What enables the mass-transfer-rate model to reveal what has, for so long, been hidden behind the façade of the ideal stage? A real absorber contains a certain number of actual trays, or a depth of a specific packing, intended to promote contact across the interface between the counter-currently flowing vapor and liquid phases. These flows are always turbulent, to some extent, and the turbulence level depends on the tray or packing design, along with the fluid properties and flows. Turbulence affects the absorption rate because it affects the mass-transfer coefficients that prevail within the phases. In parallel with heat-transfer coefficients in various types and designs of heat exchangers, mass-transfer coefficients for a wide range of tray and packing types have been correlated with design details, flow parameters and properties. In other words, the mass-transfer characteristics of tower internals are well understood and well established; there is no guesswork. Absorption rates also depend on concentration differences between the phases. The separation achieved by a real tray, or a certain depth of real packing, depends directly on the absorption rate of the component as dictated by the masstransfer characteristics of the internals. The model is completely integrated with the operation of real-world equipment. The ideal stage concept, on the other hand, replaces every important detail with the single, simplifying assumption of equilibrium between the phases. However, since there are no composition differences between phases, there is no reason for a separation. Regardless of applying Hydrocarbon Processing | JULY 201471

LNG efficiencies or finessing the equilibrium assumption in any other manner, the ideal stage assumption eliminates reality from the calculations, leaving a model that is not only unable to perceive critically important process details, but that is also vulnerable to gross errors.

LNG CASE STUDIES This article consists of two case studies. The first study asks the question: How closely can the performance of an LNG plant’s CO2 removal section be

predicted? This question is answered by comparing performance predictions with operating data from one of the trains of an operating LNG plant. The second case study is an analysis of certain aspects of the CO2 removal section of a project under consideration. The case study examines the sensitivity of the design to operating and design parameters. Operating LNG plant. A proprietary CO2 removal solvent is used at 41 wt% to treat inlet gas with the composition Water makeup Treated gas Flashed gas

Gas cooler Knockout

Acid gas

#2 202

Mixer 1

13 213

Trim cooler 206

217

#1 Absorber Regeneration gas from dehydration

10 212

HP pump

Regenerator

211 207

Rich flash

303

16

Cross X

15

24

102

Booster pump

Wet gas feed

HC liquid HC liquid

FIG. 1. Simplified process flow diagram for the operating LNG train CO2 absorption system.

Water makeup and wash

Treated gas Flash gas Amine surge gas Acid gas 1 Acid gas 1

Lean amine pump

#1

10

CB

Amine surge tank

Lean amine flow Sour gas Absorber 1

11

Regenerator 1

Lean amine cooler

14

Rich flash

13

Divider 1

Absorber 1-LCV 34

shown in TABLE 1. The process flow diagram (FIG. 1) is fairly conventional, although a substantial portion of the reflux water from the stripper overhead condenser is mixed with process makeup water and returned to the top of the absorber, rather than to the regenerator. At the top of the absorber, four wash trays recover the solvent from the treated gas. There are 20 contacting trays in the absorption section. The rich amine is flashed to remove hydrocarbons, cross-exchanged with hot lean amine, and then sent to the regenerator. The regenerator contains three wash (reflux) trays and 17 stripping trays. The reboiler is energized using hot oil. Absorber temperature and composition profiles indicate that the tower is mass-transfer-rate controlled. Simulated temperatures of various streams throughout the plant are compared with measured data in TABLE 2. Stream numbers refer to those shown in FIG. 1. With the exception of the treated gas temperature, the simulated temperatures of all other streams match plant measurements to better than 1°C; the treated gas differs by only 1.4°C. The measured lean amine loading was 0.04 mole of CO2 per mole of solvent, while the simulated value was 0.036 mole of CO2 per mole of solvent. These values are almost identical, validating the accuracy of the regenerator simulation. The treated gas CO2 level was measured at 25 ppmv, whereas the simulated value was in the range of 50 ppmv– 60 ppmv—a greater discrepancy than expected. However, the feed gas is known to contain heavy ends, and plant personnel have identified the presence of foaming in the column. Even a small amount of foaming in an otherwise normally operating system can increase the vapor-liquid area for mass transfer by 10%–20%, which is sufficient to give a predicted value of 25 ppmv–30 ppmv of CO2 .

35

Regenerator 2

Flash tank LCV Rich lean XCHR

33 32

Hot lean pump 2 Mixer 1 Hot lean pump 1

FIG. 2. Simplified process flow diagram for the study case LNG CO2 absorption system.

72JULY 2014 | HydrocarbonProcessing.com

LNG project under consideration. This LNG plant is in the initial study phase; therefore, the name of the project and the location are not disclosed. However, the study phase is the time to perform sensitivity studies and determine if it will be operable over the entire range of expected conditions, and whether there are regions in which the operation of the plant might be overly sensitive to one design parameter or another. If such

LNG

TABLE 1. Composition of gas to the CO2 absorber CO2, mol%

0.34

Methane, mol%

95.5

C2+, mol%

4.1

N2, mol%

< 0.1

amine in the solvent. At the design lean amine temperature of 115.8°F into the absorber, the treated gas was simulated to contain 21.4 ppmv of CO2 . A study of how overall performance might respond to variations in design and operating parameters revealed that, for the most part, the CO2 content of the treated gas was remarkably insensitive, so the design appeared quite solid from an operational standpoint. However, performance was found to be sensitive to both the depth of packing in the absorber and the temperature of the lean amine. Sensitivity to packing depth. The simulated effect of packed-bed depth on treating performance, as measured by the CO2 level in the treated gas, is shown in FIG. 3. (Note the logarithmic scale on the concentration axis.) The design point of an 8-m-deep packed bed appears to give a comfortable margin away from the 50ppmv specified limit for CO2 . However, reducing the bed depth to 7 m—a difference of only 1 m—would result in the treated gas exceeding this specification by at least 20 ppmv, vs. meeting it with a comfortable 30-ppmv margin. Using appropriate packing depth is critical to achieving a tight design. To ensure a truly safe design, it is necessary to

100 50 ppmv 10 1 1

6

8 10 Total packed depth, m

12

FIG. 3. Sensitivity of CO2 in treated gas to packing depth in the absorber.

Actual temperature, °C

Temperature achieved with simulation tool, °C

Temperature difference, °C

24.8

24.9

−0.1

202

32.5

33.9

−1.4

206

43.3

44.1

−0.8

207

24.2

23.5

0.7

211

81.8

81.8

0

213

111.9

111.8

0.2

13

44.5

44.5

0

24

126.7

126

0.7

103

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TABLE 2. Actual vs. simulated stream temperatures Stream

BORSIG

- BORSIG Linear Quencher (BLQ) - BORSIG Tunnelflow Transfer Line Exchanger (TLE)

1,000 Residual CO2, ppmv

regions exist, then the plant must operate well away from them, or it must have contingencies in place to ensure that stable operation can be maintained. Regarding CO2 , the raw gas to the plant under consideration is at the opposite end of the spectrum from the operating LNG facility. The CO2 concentration in the raw gas is about 45 times higher—nominally 16 mol%. FIG. 2 shows a simplified process flow diagram. A simplified gas analysis with relevant conditions is provided in TABLE 2. The absorber has been designed with three one-pass valve trays to act as wash trays and assist in the recovery of any vaporized, proprietary solvent from the treated gas. This short wash section swages into the absorption section. The main part of the absorber was designed with two identical 4-m-deep beds of proprietary packing rings selected for their excellent hydraulic capacity and high specific surface area.2, 3 In tests, this packing combines high throughput with excellent mass-transfer performance. At 60% of flood, the absorber diameter is just over 25 feet—which, at 48 barg, is a substantial tower shell by any measure (TABLE 3). The regenerator’s design stripping ratio (i.e., the ratio of water vapor to acid gas in the overhead vapor line going to the condenser) is 0.8. The solvent circulation rate is set to achieve a rich amine loading of 0.5 mole of CO2 per mole of

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LNG Absorber performance is exponentially sensitive to packed depth, mainly because the absorber’s performance in

nearing saturation toward the bottom of the absorber. However, throughout the rest of the absorber, the CO2 concentration continues to fall exponentially. Since the CO2 concentration in equilibrium with the What is the best way to control the absorber when lean amine is less than 1 ppmv, the absorber is far from being the lean amine is too warm? The answer is fairly simple: lean-end pinched. Manipulate the variable that will increase the solvent Sensitivity to operating parameters. If the absorber capacity—i.e., its net loading capacity. goes off-specification, then remedial action must be taken. There are several candidates for the engineer having high confidence in this case is controlled—not by the sol- control variables, the most obvious being the accuracy of the height-equivalent-to- vent lean loading, but by the mass trans- lean solvent flowrate, lean solvent tempera-theoretical-plate (HETP) value used fer itself. The easiest way to understand ature and regenerator reboiler duty. This to translate calculations into reality. Un- this concept is to look at the CO2 con- absorber is sized for only 60% of flood. fortunately, information on HETP val- centration profile across the absorber, Therefore, the solvent rate might be an ues in amine systems is often unreliable. shown in FIG. 4. Detail is made visible excellent control variable, at least in terms The proprietary simulator, however, has by using the logarithm of CO2 concen- of tower hydraulic capacity (provided, of a real mass and heat transfer rate basis, tration, and the temperature profile is course, that pumps have been adequately sized). The regenerator reboiler duty, on which allows it to avoid the efficiency shown for reference. and HETP issues. Also, it has been finely The size of the temperature bulge is the other hand, is a poor control variable tuned to a large amount of commercial substantial in the bulge region of the ab- because treating is almost independent of plant performance data; the mass-trans- sorber. The CO2 concentration is only lean loading (provided that the loading is fer rate model deals directly with the real slowly changing in that region because of low enough). FIG. 5 shows the lack of sensiinternals in the tower, not with theoreti- the high CO2 backpressure at such tem- tivity of treating to lean loading. As shown cal HETP values. peratures. In other words, the solvent is in FIG. 5, a 15% increase in reboiler duty results in a lean loading reduction of only 0.0036 loading units, and this decreases 0 0 CO2 in the treated gas by only 2 ppmv. 1 1 Lean solvent temperature is the final control variable considered. As the lean 2 2 amine temperature is increased, tempera3 3 ture increases are expected throughout 4 4 the column. A higher-temperature solvent is unable to hold as much acid gas as 5 5 a low-temperature one. In other words, its 6 6 net loading decreases. This is shown in FIG. 6, where the CO2 level in the treated 7 7 gas and the net solvent loading are shown 8 8 side by side. The rich loading remains 0.001 0.01 0.1 1 10 100 90 100 110 120 130 140 150 160 170 180 190 CO2 in gas, mol% Gas temperature, °F constant between 100°F (37.8°C) and Distance from top of packed bed, m

Distance from top of packed bed, m

have confidence in the reliability of the simulator. If a simulator that uses ideal stages in any form is used, it must rely on

FIG. 4. Temperature and CO2 concentration profiles in gas across the absorber.

35

CO2 in treated gas, ppmv

Rich loading

0.48 0.46 0.44 0.42 0.40 100

110

120 130 140 Lean amine temperature, °F

150

18,000 16,000 14,000 12,000 10,000 8,000 6,000 4,000 2,000 0 100

CO2 in treated gas, ppmv

30 0.50

20 590 MMBtu/hr 15 680 MMBtu/hr 10 5 0 0.005

110

120 130 140 Lean amine temperature, °F

FIG. 6. Net solvent loading and response of CO2 in treated gas to lean amine temperature.

74JULY 2014 | HydrocarbonProcessing.com

25

150

0.01

0.015 0.02 0.025 Lean amine CO2 loading

0.03

0.035

FIG. 5. Insensitivity of CO2 in treated gas to lean amine loading, and reboiler heat duty.

LNG 126°F (52.2°C), regardless of the lean amine temperature, because the solvent under those conditions is able to absorb virtually all of the CO2 (at approximately the 20-ppmv level). However, at or above 126°F, the rich loading begins to drop with increasing temperature. The ability of the solvent to “load up” with CO2 is compromised as it becomes too hot, and what cannot be absorbed must leave in the exiting gas. Therefore, the treated gas quality suffers very severely. The effect is noticeable when dealing with ppm specifications on the treated gas. It is instructive to examine how treated gas composition changes with lean amine temperature in more detail. FIG. 7 is a replot of FIG. 6 (b) on a logarithmic basis to magnify the region where treating fails. The design temperature is 115°F (46°C). As long as the temperature is kept within 10°F (5°C) of the design point, the plant appears to maintain operational stability. However, as FIG. 7 shows, once the lean amine temperature approaches 125°F (52°C), the absorber will become extremely unstable; indeed, it will become

inoperable. As already discussed, the reason for this significant sensitivity to an operating condition has to do with the capacity of the solvent; part of the CO2 in the raw gas cannot be absorbed because of a solvent capacity limit, and so it passes directly into the treated gas. Continuing to decrease the solvent temperature, however, does not result in continued improvement to treated gas quality. Eventually, it starts to have a deleterious effect

because the solvent viscosity is increasing with decreasing temperature, and because mass-transfer resistance to CO2 absorption starts to increase. The remaining question is: What is the best way to control the absorber when the lean amine is too warm? The answer is fairly simple: Manipulate the variable that will increase the solvent capacity—i.e., its net loading capacity. The choices are limited. Increasing solvent strength is always

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TABLE 3. Study case: LNG feed gas to the CO2 absorber Temperature, °C

46

Pressure, barg

54

Volume flow, kNm3/h

FLIR GF-SERIES

1,400

Immediately see gas leaks & identify potential faults Watch the amazing videos

Composition, dry basis CO2, mol%

16

Methane, mol%

79

Ethane, mol%

3

Propane, mol%

1

Butane, mol%

0.5

Other, mol%

0.5

Thermal imaging cameras for gas detection and industrial applications

CO2 in treated gas, ppmv

100,000 10,000

Captured gas leak Gas leak Electrical inspection All FLIR GF-Series thermal imaging cameras are dual-use systems. They not only allow the user to detect gases. They can also be used for industrial maintenance inspections.

1,000 100 10 1 100

110

120 130 140 Lean amine temperature, °F

FIG. 7. Extreme sensitivity of CO2 in treated gas to lean amine temperature.

150

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75

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LNG an option, but it is not a control strategy. Producing a leaner solvent would be completely ineffective because lean loading has only a tiny effect on net loading capacity; in no sense is it controlling. Solvent flowrate, on the other hand, directly affects the solvent’s capacity for CO2; this is the only short-term control variable that would be significantly effective.

TAKEAWAY The operating LNG facility is amenable to simulation using the proprietary simulator’s mass-transfer-rate-based approach. The simulation is predictive, requiring no estimates or other input beyond what is available from data sheets, piping and instrumentation diagrams, and vendor drawings and specifications for tower internals. All temperatures were matched to thermocouple calibrations, and the simulated lean solvent loading was almost identical to measured data. The discrepancy in treated gas CO2 content was easily explained and accounted for by a small amount of foaming suspected to be occurring in the absorber. The study case LNG unit appears to be quite sound and operationally stable, but with the proviso that the lean amine temperature must be kept between 100°F and 125°F. If there is any doubt that this can be achieved throughout the year (which may not always be the case in the region for this study case), then adequate provision must be made for operating at increased solvent flow. This contingency requires adequate design margin in pumps, in heat transfer equipment, and in the regenerator itself. The first case study validated the ability of a proprietary mass-transfer-ratebased simulator to accurately predict amine unit performance in LNG production. In the second case study, the same model was used to explore the operability of a plant still on the drawing board. Without using such a simulator, it would not be obvious that a critical operating temperature exists that cannot be exceeded, and near which the absorber operation will become unstable. There may well be a lower operating temperature, although whether the unit will become unstable at that temperature is a moot point. a

NOTE The proprietary software used in this study is Optimized Gas Treating’s ProTreat simulator.

REFERENCES Weiland, R. H. and N. A. Hatcher, “Foundations of Failure,” Hydrocarbon Engineering, 2011. 2 Schultes, M., “Researching Rings,” Hydrocarbon Engineering, p. 57, November 2001. 3 Schultes, M., “Raschig Super-Ring,” Trans. I. Chem. E., 81A, p. 48, 2003. 1

RALPH WEILAND received BASc and MASc degrees in chemical engineering, as well as a PhD in chemical engineering, from the University of Toronto in Canada. He has been active in basic and applied research in gas treating since 1965. Dr. Weiland founded Optimized Gas Treating (OGT) in 1992, and, in addition to developing the Windows-based ProTreat process simulation software with OGT, he also spent 10 years in tray development with Koch-Glitsch in Dallas, Texas. JESSE SANTOS is a senior technical service leader for the GAS/SPEC Technology Group at INEOS, where he has provided design and field support for amine gas treating units in refineries, ammonia plants, midstream gas treating and LNG facilities since 1989. He is also the global quality leader and the import/export manager for all GAS/SPEC products. Over the course of his career, Mr. Santos has also worked for MPR Services (amine reclamation) and Honeywell/UOP. He earned a BS degree in chemical engineering from the University of Texas at Austin, as well as an MBA degree in operations management from Rice University. He has published several articles in the field of gas and liquid treating. ATTILIO PRADERIO is a principal process engineer for the ConocoPhillips Optimized Cascade LNG process, where he has provided design and field support on distillation and absorption since 2005, through the use of ratebased process simulations. He holds an MSc degree in gas engineering and management. Mr. Praderio has published several papers, and he also holds several international patents. NILIA MAHARAJ joined Atlantic LNG after graduating from the University of the West Indies in Trinidad and Tobago in 2008 with a BSc degree in chemical and process engineering. She has supported HAZOP review projects and has led plant troubleshooting and plantwide alarm management teams. MICHAEL SCHULTES has worked since 1995 at Raschig GmbH in Germany, providing engineering technology to the chemical, petrochemical, refinery and environmental industries. As technical director, he is responsible for the manufacture, design and development of trayed and packed columns worldwide, and he holds various international patents. In 2005, he was awarded a professorship at the Ruhr-Universität Bochum for his ongoing research activities.

Bonus Report

LNG P. GUILLEMIN, Eniram, Helsinki, Finland

Maximize LNG carrier efficiency through integrated optimization When installing a data collection platform onboard new liquefied natural gas (LNG) carriers, the first step is to gather as much knowledge as possible about onboard operations. The results of this data collection help determine vessel efficiency, which, in turn, assists owners in maximizing ship efficiency and operations. Today’s LNG carriers are amazing feats of engineering (FIG. 1). The ship cargo is extremely dangerous because of its highly flammable properties. Furthermore, the dual-fuel/tri-fuel engines used, as well as the occasional presence of reliquefication plants, make these vessels among the most complex floating engineering projects in the world. The transport of LNG can be compared to running with a full soft drink can in a backpack. When the can is shaken, some of its contents will vaporize as CO2 , which increases the can’s internal pressure. A similar process occurs in a tank filled with LNG, although the somewhat inert gas is replaced with a variety of different natural gases [i.e., boiloff gas (BOG)]. The increasing pressure must be relieved by releasing gas from the tank.

used in the engines; the rest was reliquefied. In this type of situation, older LNG ships may have been forced to burn the fuel without using it. Complex vessels should be matched with sophisticated, yet easily understood, data-gathering solutions. The first step of the process is data integration. Data is collected from the various automated systems already installed onboard, as well as from proprietary sensors. Readings are also received from other equipment located on the bridge or in the cargo control room. Monitoring carrier operation. This deep integration is

necessary to obtain the highest level of accuracy regarding the

LNG tank design. LNG tanks are extremely well insulated

to limit the BOG that naturally occurs after a cargo is loaded. Typically, the cargo is loaded at an approximate temperature of −170°C. However, despite the insulation, a small percentage of the LNG cargo is converted to gas during each day of a sea voyage. The size of the percentage will depend on the efficiency of the insulation and the weather patterns en route. Improvements in insulation and clever engineering have increased storage effectiveness. A small number of LNG vessels are now equipped with reliquefication plants that are able to reliquefy the excess BOG and return it to the tanks, making these ships more environmentally efficient. For the majority of vessels not equipped with reliquefication plants, the excess gas can be used for running vessel engines or boilers. In practice, however, LNG carrier operations are more complicated than this description suggests. Transport challenges. Rough seas are part of the scenario. These types of sea states can behave exactly like the example of a soft drink can in a backpack, jostling the cargo about and increasing the pressure in the tanks. On one of the author’s recent LNG carrier trips, the ship encountered not one but two typhoons. Typhoons Francisco and Lekima kept the officers and crew on alert, but the ship was able to sail through the storms without any problems. Some of the excess gas was

FIG. 1. Today’s LNG carriers represent considerable feats of engineering. Photo courtesy of Eniram.

FIG. 2. Speed log device errors can be assessed quickly. A clear offset is seen on the vertical axis, which represents the difference between speed through water and speed over ground. Hydrocarbon Processing | JULY 201477

LNG ship’s physical behavior. Essentially, all of the information being gathered must be validated. Sensors are attempting to analyze real phenomena, and trusting such devices should be done with caution before a proper calibration is performed. This data can be used to observe how offset a speed log is (FIG. 2), or to monitor the reading errors of an anemometer, for example. These actions are essential to understanding the actual performance of a carrier. They also aid in the modeling of ship energy usage and in mapping the breakdown of where energy is consumed. On an LNG vessel, numerous systems are the source of hundreds of variables. The initial target of a data collection platform is to make sense of this information, and to present it in a normalized way. After the integration of all sensors and variables, both the onboard and onshore systems are automatically synchronized. This is the second step of the process. Modeling takes into account a wide variety of variables, such as fuel flowmeters, navigation equipment, engines and reliquefication plant usage. The speed profile, for example, requires automatic updates based on the latest sea current and wind data available onshore. No additional work is required from the navigation officer to import the data, and yet it is achievable in real time. Measurements performed onboard will also be taken into account to better reflect the forecast measurements provided from onshore. Forecast and data share one simple fact: taken alone, the flow coming out of a device or data source is only as reliable as the device or the forecast itself. Ship-wide integration

of a platform can help put into context all of that information, as in the speed log example. The third step of the process is the actual data crunching to provide the optimum guidelines typically seen on the display. Onboard and onshore dedicated calculation servers are provided to improve the accuracy of the optimums. Successful integration. During the installation of the system described earlier, the weather threatened to delay the carrier’s arrival to the next port. However, the integrated system enabled the rapid approximation of an estimated time of arrival, taking into account all of the effects of the rough weather and its energy cost. Engineers could then use the prediction regarding the required energy necessary to reach the next port as close to the original schedule as possible. Officers and engineers aboard an LNG carrier are extremely busy. They require real-time, user-friendly data derived from the vessel’s systems, as well as accurate individual metrics. Maximizing fuel efficiency should not trump other tactical, on-thespot decisions needed to ensure that the ship continues to sail as safely as possible with its strategic cargo. PIERRE GUILLEMIN leads the development team for Eniram’s onshore and onboard platforms. As an enthusiast builder, he has a broad experience in converting ideas into usable, concrete technologies. Prior to Eniram, Mr. Guillemin spent most of his career in startup companies in the data crunching field, from search engine development to crowdsourcing services. He holds an MEng degree in computer science from ESIEA Paris in France.

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Where the Energy Project Industry Meets The inaugural Energy Construction Forum (ECF) will be held November 11–12, 2014 at the Moody Gardens Convention Center in Galveston, TX. ECF is a unique and timely gathering covering all phases of major expansions and new construction projects with a focus on the challenges and solutions facing the industry today. ECF is the only event that brings together all the key stakeholders in the rapidly growing energy projects & construction marketplace. With estimated projects at over $100 billion and growing in North America, ECF is your best opportunity to connect with major project leaders in the energy industry. The Forum caters to companies involved in major projects: expansions, new construction and infrastructure development for the petrochemical, refining, chemical, pipeline, terminals & storage, loading/transfer systems, GTL, LNG and NGLs industries.

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HPI Focus

Changing HPI Economics C. MOFFATT, S. HODGE and D. COOK, BP Downstream Technology, Conversion Technology Center, Hull, UK

Ethanol-to-ethylene process provides alternative pathway to plastics Tight operating margins make the ethanol-to-ethylene technology marketplace a challenging space in which to compete. However, a new, second-generation route can deliver market-leading conversion efficiency at lower cost and complexity than existing technologies. The combination of a proprietary catalyst and milder operating conditions is ultra-selective toward ethylene. More than 24,000 hours of pilot-plant testing has been completed to demonstrate this new technology. Technology overview. Ethanol is dehydrated to form ethylene and water over a supported heteropolyacid (HPA) catalyst. The reaction takes place in two steps: 1. Partial dehydration to diethyl ether and water, which occurs quickly under the optimized operating conditions 2. Slower dehydration of the ether to produce ethylene. In addition to ethylene, only a very small amount of byproducts, including ethane and hydrocarbons up to C5 , are generated. FIG. 1 shows a simplified process flow diagram of the second-generation ethanol-to-ethylene technology. The feed ethanol may require pretreatment, depending on its quality. Feed ethanol is then mixed with the recycle stream containing diethyl ether, ethanol and water (at a controlled composition, such as the azeotrope). This mixed stream is then vaporized and passed to the fixed-bed reaction section. Upon exit of the reaction section, the process stream is cooled before being fed to the separation stages. The ethylene is separated from unreacted ethanol, any product water and the intermediary diethyl ether. Ethanol is recovered from the ethanol and water mix in another column. The ethylene product is taken from the column overheads in the vapor phase, and the vapor is compressed and polished to meet polymergrade specifications. Ethylene produced in a pilot plant has been tested for polymerization activity at an independent laboratory. It showed no discernible difference in comparison to a conventional polymer-grade ethylene feed. Several physical characterization studies have also been performed on the polyethylene (PE) produced from these tests.

and low pressures (typically less than 5 bar). These reaction conditions favor a high ethanol conversion, although a lower ethylene selectivity is achieved. In this second-generation technology, the catalyst can achieve ultra-selectivity at milder temperatures. In an operating envelope of 200°C–270°C and 5 bar–20 bar, the ethylene selectivity is in excess of 99%. This advantage is outlined in FIG. 2. When polymer-grade ethylene is required from a firstgeneration technology, ethane formed in the reaction section must be separated from the crude ethylene. Ethane and ethylene have similar physical properties, so this separation must be undertaken at a high pressure and a low temperature. This unit operation is commonly referred to as a C2 splitter. The use of a C2 splitter is not required with second-generation technology because of its ultra-selectivity and very low ethane make. The lower-pressure operation of first-generation technologies also requires significantly greater compression for the sub-zero refrigerated separation of ethane from ethylene. The higher reaction pressure applied in the second-generation process reduces the amount of compression required prior to product purification. Furthermore, the ultra-selective nature of the catalyst reduces the volume of byproducts that must be removed, which eliminates the requirement for a C2 Ethylene product Purification

Ethanol feed

Primary separation Cleanup

Vaporization

Reaction

Minor impurities

Process recycle

Dewatering

Water

Second-generation

technology

advantages. First-

generation ethanol dehydration technologies typically use alumina-based catalysts at high temperatures (315°C–460°C)

FIG. 1. Simplified process flow diagram of second-generation ethanol-to-ethylene technology. Hydrocarbon Processing | JULY 201481

Changing HPI Economics splitter, a CO stripper and CO2 removal technology, such as a caustic wash. Significant operating cost savings can also be realized. Higher ethylene selectivity delivers improved ethanol utilization while reducing energy requirements. The first-generation technology flowsheet becomes significantly more capital-intensive in comparison to the secondgeneration process when the combination of higher operating temperature, increased compression costs and sub-zero refrigerated separation are considered collectively. The second-generation technology enables production of ethylene to polymer-grade specification, with cost advantages for both capital and operating costs relative to existing technologies. Proprietary catalyst development. Employment of a supported HPA catalyst at a comparatively low temperature of operation (200°C–270°C) leads to a highly active catalyst that is ultra-selective, giving greater than 99% carbon selectivity to ethylene. The differentiated catalyst performance has been proven in a fully recycling pilot plant. This plant was commissioned in 2009 and comprises all of the key unit operations of a commercial-scale plant, including a refrigerated, rather than cryogenic, ethylene polishing column. FIG. 3 highlights the steps taken to ensure that the pilot plant delivers a consistently strong performance (TABLE 1). To date, over 24,000 hours of testing have been completed, leading to the development of an operating regime where the catalyst is robust during startup, shutdown and continued

steady-state operation for a catalyst life in excess of two years. The application of an HPA catalyst in this operating envelope ensures that there is no requirement for decoking to regenerate the catalyst surface. Bioethanol feed pretreatment. Bioethanol is sourced from

a range of materials and can contain a wide variety of trace components/contaminants (FIG. 4). These entities can have significant impacts on the acid catalysts used for ethanol dehydration in terms of catalyst life and byproduct chemistry. Using extensive analytical capability, analyses of over 50 bioethanol samples from various sources and locations have been tested to prove the robust feed flexibility of the secondgeneration technology and enable a thorough understanding of the potential contaminants that may be present. This technology offer is enhanced through the development of a suite of feed cleanup technologies. These contaminants will generally degrade the performance of any dehydration catalyst. Extensive know-how has been developed on these issues, and a simple and inexpensive tool kit of cleanup solutions can be readily installed. Ethanol-to-ethylene chemistry. The dehydration of etha-

nol to ethylene occurs via diethyl ether as an intermediate. The overall endothermic reaction is represented in Eq. 1: ⎛ kJ ⎞⎟ C2 H5OH→C2 H 4 +H2 O⎜⎜ ΔH r = 43,660 ⎟ ⎝ mol ⎟⎠

(1)

The first step of the reaction is the fast, exothermic, partial dehydration to diethyl ether and water (Eq. 2):

TABLE 1. Pilot plant data vs. polymer-grade ethylene specifications CO

CO2

H2

Inerts*

C3H6

Polymer spec, ppm

1

2

5

1,000

20

Pilot plant data

✓

✓

✓

✓

✓

*Sum of methane and ethane

⎛ kJ ⎞⎟ 2C 2 H5OH→C2 H5OC2 H5 +H2 O⎜⎜ ΔH r = –11,270 ⎟ (2) ⎝ mol ⎟⎠

The second phase of the reaction sequence is the slower dehydration of diethyl ether to give ethylene (Eq. 3): ⎛ kJ ⎞⎟ C2 H5OC2 H5 →C2 H 4 +C2 H5OH⎜⎜ ΔH r = 54,930 ⎟ (3) ⎝ mol ⎟⎠

100

Second-generation technology 200°C–270°C

Carbon selectivity, %

98

The reaction conditions have a significant bearing on both the ethanol conversion and, subsequently, on the ethylene selectivity. Depending on the chosen conditions, varying degrees of byproducts can be produced that can have a large influence on the configuration of the ethylene purification unit operations required to meet the desired product specification. Global ethylene market. Ethylene is one of the most impor-

96 Typical first-generation technology, 315°C–460°C

94 Low temperature, high pressure

High temperature, low pressure Operating conditions

FIG. 2. Selectivity advantages from the proprietary catalyst, in comparison to conventional technology.

82JULY 2014 | HydrocarbonProcessing.com

tant intermediates in the petrochemical industry. Global demand for ethylene is expected to increase by 4% per year, with total market demand exceeding 145 million metric tons by 2015. Conventionally, the most common method for ethylene production is via the steam cracking of a petroleum-based feedstock. It is a fundamental building block in the manufacture of derivatives such as PE, ethylene oxide and ethylene dichloride. FIG. 5 shows projected demand for ethylene derivatives in 2015. PE products [linear low-density PE (LLDPE), low-density PE (LDPE) and high-density PE (HDPE)] are expected to dominate demand.

Changing HPI Economics Evolution of ethanol-to-ethylene technology. Ethanol dehydration is by

no means a new concept; it dates back to 1795, when Dutch chemists first described the process. It was practiced industrially in the US and Western Europe in the first half of the 20th century before being displaced by petroleum-based sources. Some limited success was found in Brazil and India in the 1950s and 1960s, respectively, based on local bioethanol supplies. When crude oil prices fell in the 1980s and 1990s, the economics of ethanol-to-ethylene technology became highly challenged. However, the upward trend in crude oil prices in recent years, combined with growing demand for renewable materials, has rekindled interest in ethanol-to-ethylene technology.

FIG. 3. Timeline of technology development.

‘Green’ ethylene production. The

production of chemicals and polymers from renewable sources is a focus area FIG. 4. A wide range of feedstocks can be used in the production of bioethanol. for global research and development. Specific attention is being paid to ethanol dehydration utilizing bioethanol derived from feeds such 2015 ethylene derivatives demand as corn, sugar cane or lignocellulosic biomass. These feedstocks have the advantage of removing CO2 Others, 4% Alpha olefins, 3% from the atmosphere through photosynthesis, which serves Vinyl acetate, 1% Ethylbenzene, 6% to reduce the greenhouse gas (GHG) lifecycle emissions of EDC, 10% LLDPE, 18% the ethylene production process. FIG. 6 compares ethylene production from bioethanol1–5 (average of Brazilian sugar Ethylene oxide cane and US maize feedstock) and from fossil fuel sources,6, 7 LDPE, 14% 15% such as naphtha. The GHG benefits of ethylene derived from bioethanol become clear when sequestration and other credits are taken into account. For example, electricity-related credits are increasing as improved cogeneration technologies become HDPE, 14% available to feedstock processing mills. This trend will continue as more developments are made. FIG. 5. Projected global demand for ethylene derivative products An overall lifecycle emissions advantage of approximately in 2015. Source: IHS Chemical. 3.65 kgCO2 /kgC2H4 is estimated in favor of bioethylene on a like-for-like basis, compared with naphtha-based ethylene at the factory gate. Note: Some variability of CO2 emissions Cola will continue to make investments in its bottle technolexists, depending on which bio-derived source is chosen to ogy, and it aims to use the new packaging for the company’s produce the ethanol feedstock. entire virgin PET supply by 2020.9 If other companies follow Recent commercial developments in this area highlight the this example, the opportunities available within bioethylene variety of applications for which bioethanol can be used. In derivatives may represent an exciting prospect for the future. 2008, Brazil’s largest petrochemical company, Braskem, develEthanol-to-ethylene technology may be an interesting opoped the world’s first internationally certified linear PE made tion for ethylene derivative manufacturers that are remote from 100% renewable materials.8 The ethylene monomer defrom world-scale ethylene infrastructure, or for small-scale capacity additions. In such situations, the low capital intensity rived from bioethanol dehydration is chemically identical to of ethanol dehydration, together with the increasing availabilthe monomer produced via the petrochemical route. Similarly, ity of bioethanol, may make ethanol-to-ethylene an attractive polymers obtained from green ethylene have the same prop“niche” solution for ethylene production. erties and characteristics as petrochemical-derived polymers. The flexibility of the process makes it equally applicable to Also, Coca-Cola has been developing specialized bottle synthetically derived ethanol—e.g., coal-derived syngas—or packaging that uses bioethylene-derived monoethylene glyother emerging routes to ethanol production. col (MEG) to make PE-terephthalate (PET) bottles.9 CocaHydrocarbon Processing | JULY 201483

Changing HPI Economics Takeaway. This second-generation process offers several

compelling benefits relative to existing technologies, enabling more opportunities for the commercialization of ethanol dehydration technology. The higher ethylene selectivity at lower cost and complexity, with a large feedstock flexibility, allows maximum value to be extracted from the ethanol feed. The second-generation technology creates a polymer-grade ethylene product, which is a crucial building block in providing an alternative pathway to the manufacture of conventional plastics.

Bio route -3.65 kgCO2/kgC2H4 Naphtha-based ethylene Bioethanol E2E Sequestration credits

Fossil route

-3.5

-3.0

-2.5

-2.0

-1.5 -1.0 -0.5 GWP, kgCO2e/kgC2H4

0.0

0.5

1.0

Note: Black diamond markers indicate totals once credits have been substracted.

FIG. 6. Average estimated GHG emissions for both ethylene manufacturing routes, from cradle to gate, including sequestration credits.10

1.5

NOTE BP has taken the ethanol-to-ethylene process from inception to commercialization since 2004. BP owns the process patents for this technology, which was announced on November 7, 2013. LITERATURE CITED Khatiwada, D., J. Seabra, S. Silveira and A. Walter, “Accounting greenhouse gas emissions in the lifecycle of Brazilian sugar cane bioethanol: Methodological references in European and American regulations,” Energy Policy, Vol. 47, pp. 384–397, 2012. 2 Cavalett, O., T. L. Junqueira, M. O. S. Dias, C. D. F. Jesus, P. E. Mantelatto, M. P. Cunha, H. C. J. Franco, T. F. Cardoso, R. M. Filho, C. E. V. Rossell and A. Bonomi, “Environmental and economic assessment of sugar cane firstgeneration biorefineries in Brazil,” Clean Techn Environ Policy, Vol. 14, pp. 399–410, 2012. 3 Macedo, I. C., J. E. Seabra and J. E. Silva, “Greenhouse gases emissions in the production and use of ethanol from sugar cane in Brazil: The 2005/2006 averages and a prediction for 2020,” Biomass and Bioenergy, Vol. 32, pp. 582–595, 2008. 4 Seabra, J., “GHG balance of ethanol production in Brazil,” Unicamp Presentation, 2010. 5 De Oliveira, M. E. D., B. E. Vaughan and E. J. R. Jr., “Ethanol as fuel: Energy, carbon dioxide balances, and ecological footprint,” BioScience, Vol. 55, No. 7, pp. 593–602, 2005. 6 PlasticsEurope, “Ethylene, propylene, butadiene, pyrolysis gasoline, ethylene oxide (EO), ethylene glycols (MEG, DEG, TEG),” 2012. 7 Liptow, C. and A.-M. Tillman, “Comparative lifecycle assessment of polyethylene based on sugar cane and crude oil,” Chalmers University of Technology, 2009. 8 “World’s first ‘green’ linear polyethylene launched,” Royal Society of Chemistry, March 31, 2008. 9 McTigue Pierce, L., “Coca-Cola to develop 100% renewable PlantBottles on global scale,” Packaging Digest, December 14, 2011. 10 Patel, M., M. Crank, V. Dornburg, B. Hermann, L. Roes, B. Husing, L. Overbeek, F. Terragni and E. Recchia, “Medium- and long-term opportunities and risks of the biotechnological production of bulk chemicals from renewable resources,” European Commission GROWTH Programme, Utrecht, The Netherlands, 2006. 1

CRAIG MOFFATT is a process engineer on BP Conversion Technology Center’s Licensing and Projects team. He joined BP in 2011 and has worked in Fischer-Tropsch technology development, and as a process engineer in operations on a world-scale syngas facility in Hull. Since 2013, he has been working on the commercialization of BP’s ethanol dehydration technology. Mr. Moffatt holds an MS degree in chemical engineering from the University of Strathclyde in Glasgow, Scotland. STEVE HODGE is a technology manager at BP’s Hull Research and Technology Center. He joined BP in 1986 with a degree in natural sciences and a PhD in organometallic chemistry from the University of Cambridge in Cambridge, UK. During his time with BP, Dr. Hodge has worked in a wide variety of research areas, including developing new speciality chemicals and solvents. Recently, he has been responsible for leading the development of new chemical process technologies from laboratory-scale through commercialization. These developments include new catalysts, the design and operation of pilot-scale facilities, commercial catalyst scale-up and transferring technology to commercial operation. DARREN COOK is the technology team leader for the development of ethanol dehydration technology in the Conversion Technology Center at BP’s Hull Research and Technology Center. He graduated from Imperial College in London with a BSc degree in chemistry and a PhD in organometallic synthesis. He worked for two and a half years as a post-doctoral researcher in catalysis prior to joining BP in 2000. In his 14 years at BP, Dr. Cook has gained experience in a range of roles focused on the development and deployment of new downstream technologies. These roles include process development chemistry and experimental catalysis, technical service, new technology assessment, and technology planning and strategy. In addition, he has worked in business marketing, commercial contract negotiations, business development and project management. He has also served as the lead on a number of high-profile technology collaborations.

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