hp_2011_09

SEPTEMBER 2011

HPIMPACT

SPECIALREPORT

TECHNOLOGY

Rare earths in demand

REFINING DEVELOPMENTS

Improve storage tank inspections and repair

New solutions will supply ‘clean’ fuels globally

Alloys mitigate metal dusting corrosion in heat exchangers

New blend rules: Bad news for US refiners?

www.HydrocarbonProcessing.com

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SEPTEMBER 2011 • VOL. 90 NO. 9 www.HydrocarbonProcessing.com

SPECIAL REPORT: REFINING DEVELOPMENTS

37 47 53 59 69 75 81 85 91 97

Understand differences between thermal and hydrocracking Successful operation and product yields are controlled by reactions at the molecular level S. Sayles and S. Romero

New era in refining—Keys to sustenance Changing feedstocks and environmental rules alter past and future process investments and profitability A. Subramanian and S. Krishnamurthy

Cover Sinopec RIPP’s Clean Gasoline and Propylene (CGP) technology was applied in this 2.8 million tpy grassroots FCC unit in Hainan province, China. Photo courtesy of Shaw Group.

Refining outlook: Capacity expansion and rationalization Many factors are reshaping the global refined product industry; change is inevitable P. Ruwe

Achieve success in gasoline hydrotreating Case history describes achieving top performance in FCC gasoline hydrotreater K. Sanghavi and J. Schmidt

HPIMPACT 15

Rare earths and lubricant demand to grow worldwide

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New requirements could raise the cost of gas and shutter US refineries

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Tesoro releases report on Anacortes explosion

Alternative transport fuels: An Indian perspective Many factors influence the possibility of new fuels replacing gasoline and diesel S. K. Singal, W. Kamei, A. K. Jain and M. O. Garg

A perspective on China’s refining industry Statistics show how this nation has progressed from 2006 to present day X. Li, W. Ren, Q. Zhu and J. Ren

Fast track to fuel—getting the right mix An innovative application of biology and chemical engineering cuts time and cost out of biofuel production G. W. Luce

Consider new processes for clean gasoline and olefins production Advanced technologies promote propylene yield while reducing olefins in gasoline J. Long, Y. Xu, J. Zhang, D. Dharia, A. Batachari, E. Yuan, S. Gim and S. Xu

Maximize propylene from your FCC unit

COLUMNS

Innovative use of catalyst and operating conditions increases on-purpose olefin production J. Knight and R. Mehlberg

Investigate processing near-zero-sulfur gasoline This study considers the effectiveness of undercutting and hydrotreating fluid catalytic cracking feeds to yield ‘cleaner’ fuels D. Stratiev

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HPIN RELIABILITY Consider a new twist on data collection

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HPINTEGRATION STRATEGIES Standards needed for laboratory system integration

13

HPIN ASSOCIATIONS International HPI conference gathers in Singapore

FLUID FLOW AND ROTATING EQUIPMENT

105

Optimize compressor configurations for hydrocarbon applications Extend the life of the compressor-driver package A. Almasi

ENGINEERING AND CONSTRUCTION 2011—SUPPLEMENT

111

Engineering and Construction 2011 Guide on new developments for capital projects

MAINTENANCE AND RELIABILITY

127 131

Prevent failures in olefin-cracking operations Failure analysis identifies root causes for damages to selective exchangers R. P. Gupta and H. Pathak

Prevent tank-bottom failure through reliability analysis Apply service-life methods to optimize inspections and maintenance for storage units L. Liu and T. Liu

ENGINEERING CASE HISTORIES

137

Case 64: Averages can be misleading on service life data Take care when making important decisions on data T. Sofronas

DEPARTMENTS 7 33 34 138

HPIN BRIEF • 21 HPIN CONSTRUCTION HPIN CONSTRUCTION PROFILE HPI CONSTRUCTION BOXSCORE UPDATE HPI MARKETPLACE • 141 ADVERTISER INDEX

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API’s 2011 Fall Committee on Petroleum Measurement Standards Meeting

Other energy group titles include: World Oil® Petroleum Economist Publication Agreement Number 40034765

Printed in U.S.A

The meeting that measures up (and down).

October 24-28, 2011 Hyatt Regency Savannah Savannah, Georgia Register now at API.org/meetings For more info email registrar@api.org or call 202-682-8195.

Copyright 2011 – American Petroleum Institute, all rights reserved.

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I SEPTEMBER 2011 HydrocarbonProcessing.com

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HPIN BRIEF BILLY THINNES, TECHNICAL EDITOR

BT@HydrocarbonProcessing.com

Hestya Energy has signed an agreement to purchase the Wilhelmshaven oil refinery, tank farm and marine terminal in Germany from an affiliate of ConocoPhillips. Hestya will then restart the refinery, which has been mothballed for about two years. The Wilhelmshaven refinery is located on the German North Sea coast. It has a deepwater port and crude oil processing capacity of 260,000 bpd, making it one of Europe’s leading refineries in terms of scale. The refinery had been mothballed by ConocoPhillips for most of the past two years, following a May 2010 fire, that led to poor margins.

Industrial gases major Praxair has entered into a long-term environmental research collaboration with the State Key Lab of Pollution Control and Resource Reuse Study at Tongji University in Shanghai, China. Praxair will cooperate with Tongji University on the development of environmental technologies at the United Nations Environmental Program, Tongji Institute of Environment for Sustainable Development. Praxair has also established environmental scholarships to support study and research by Chinese students in several key environmental areas, including water treatment. The agreement was signed by Wu Jiang, vice president of Tongji University, and Ray Roberge, Praxair’s senior vice president and chief technology officer.

Engineering and construction major KBR has officially opened a new operating center in Luanda, Angola. Present at the opening ceremony for the facilities were senior executives from KBR; US and UK embassy staffers; and client executives from Sonangol, Chevron, BP and Total. KBR has been present on the African continent for nearly 60 years and in Angola since 1968.

While past projects have been focused primarily on the downstream and gas monetization sectors, the office opening is part of KBR’s strategic plan to expand geographically and diversify its in-country offerings with the goal of becoming an EPC company in the oil and gas sector, company officials said. Operations out of this facility include engineering, project management and construction management services. In preparation for the office opening, a group of 12 Angolan engineers have undergone significant training at KBR facilities in the UK and Houston.

Foster Wheeler announced that its Singapore subsidiary, Foster Wheeler Asia Pacific, won six workplace safety and health (WSH) awards in Singapore for performance in 2010. The awards are presented annually by the WSH Council, in collaboration with Singapore’s Ministry of Manpower. For the third year running, Foster Wheeler won a gold award for its overall safety performance in Singapore, the company said. The Foster Wheeler-led joint venture executing a major petrochemical project in Singapore has also won a silver award. In addition, a further four of the company’s projects in Singapore, namely a refinery modifications project and three others that form part of the major petrochemical project, each received safety and health recognition awards.

The American Petroleum Institute (API) and National Petrochemical and Refiners Association (NPRA) each issued statements of support after the US House of Representatives passed the North American-Made Energy Act, which seeks to speed up the permitting process for the proposed Keystone XL pipeline. The Keystone XL pipeline is an extension of the original Keystone pipeline owned by TransCanada that has been operational since June 2010. The Keystone XL would transport Canadian oil to the US Gulf Coast. The issue of granting final approval for the project has been held up by environmental concerns, wrangling in the US Congress and politics in general. The API contends that this project will generate 20,000 new US jobs, and says that investing in Canadian oil will support 600,000 Americans jobs by 2035. HP

■ Dow optimistic about natural gas George Biltz, Dow Chemical’s vice president of energy and climate change, recently testified before a US Senate committee about the future of natural gas and the opportunity for a US manufacturing renaissance fueled by competitively priced natural gas.

“Natural gas can be a game changer. It can fuel a renaissance in American manufacturing, but only if we produce enough of it, use it wisely and don’t repeat the mistakes of the past,” Mr. Biltz said. “We can create the best opportunity if we enact policies to encourage natural gas production, avoid legislating natural gas demand and enact a comprehensive energy policy.”

Dow is one of the largest industrial users of natural gas, using it both as a fuel for heating, cooling and processing, as well as a raw material for the manufacturing of chemicals and other products. Manufacturers like Dow turn natural gas and natural gas liquids into routine products, such as insulation and food packaging, and advanced materials that support wind and solar energy.

Biltz informed the committee that using natural gas for manufacturing provides an eight-fold multiplier in value to the economy by adding jobs and products into the market. He said that research has shown that a 25% increase in ethane supply, a petrochemical byproduct of natural gas, would generate: 17,000 direct, highpaying jobs; $4.4 billion in annual tax revenue; a $33 billion increase in US chemical production; and $132 billion in US economic output.

Leveraging US natural gas reserves, Dow said it is investing more than $500 million on ethane cracking and ethylene supply improvements on the US Gulf Coast and has proposed further plans representing billions of dollars. The company is also focusing on increasing its ethylene and propylene production, as well as integrating feedstock supply from recent shale gas discoveries.

“The future of natural gas is very bright,” Mr. Blitz said. HP

HYDROCARBON PROCESSING SEPTEMBER 2011

I7

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HPIN RELIABILITY HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR HB@HydrocarbonProcessing.com

Consider a new twist on data collection The following abbreviated sequence of correspondence is real, although we quite obviously had to hide some names. Still, it is quite typical of many discourses our editors carry on with readers or conference participants over a year.

The client. It started with an e-mail from XYZ, a mid-level technical employee with Central Refining Industries (CRI) we had first met decades ago. He asked: My question is how often our vibration group should be doing their routes on every piece of equipment. We collect data on all fans, gearboxes, pumps and motors monthly. I believe this is too frequent for most machines, but thought I would get your opinion before I stuck my head out too far. I have read a lot of articles and see that no one agrees.

We seem to be in the “paralysis by analysis” mode of doing business.

We answered XYZ by affirming that many reliability managers are unaware of the main reason for gathering vibration data: to get the operators out of the control room. We claimed, somewhat tongue-in cheek, that operators will not leave their control room if: a) Ambient temperatures climb above +75°F; operators fear the risk of heat stroke b) Temperature drops below +66°F; there’s the real fear of frostbite c) Wind speed exceeds 4 mph; understandably, they fear being blown off their bicycles.

Who collects the data. So, best-of-class refineries use a good portable data collector (Fig. 1) to check if and when operators leave their control rooms. For them, vibration monitoring, is often of secondary importance. We explained to XYZ that best-of-class refineries ask experienced vibration analysts to limit their involvement to interpreting out-of-limit data. The operators do the data collecting for the reasons mentioned above. Assigning both the collecting and analyzing of data to a highly trained vibration technician is a rare practice.

At best-of-class companies, experienced reliability professionals will also examine in-house records of failure frequency, repair cost and downtime risk. In oil refineries, considerable judgment is required and equipment criticality is important. Data collection frequency is based on this criticality and can vary from monthly to twice yearly.

FIG. 1

In addition to warning of component deterioration, state-of-art data collectors such as Ludeca’s/Prueftechnik’s VIBXPERT II serve as monitoring tools to ascertain scheduled field presence by responsible personnel.

such a program requires time, competence, monetary resources and continuity of effort. It represents an investment in the future and cannot ever be a “flavor of the month” thing.

Next question. To again quote XYZ:

All or most of our unit supervisors are on too much of a “good buddy” relationship with their operators to make them get out of the control rooms so as to look, feel and listen to their equipment. They operate by alarms, so to speak. Just recently we lost 4 boiler feedwater pumps out of a total of 7.

We were certain that CRI had never measured the width and concentricity of its slinger rings. They had probably purchased them from the lowest bidder, who probably had skipped the important annealing step. In the future, CRI will have to budget the right price for oil rings that don’t distort.

Findings. It was again confirmed that best-of-class plants get

their exceptional (9.4 years) pump MTBF by systematically upgrading and paying attention to every detail. As always, we appreciated the discourse with CRI because it updated us on the state of affairs in small and mid-size refineries. Some of these refineries become progressively less profitable and the root causes of their problems and issues are often both cumulative and elusive.

Putting it more bluntly, the correspondence with CRI filled in the picture, and the picture is not pretty. HP

New question. Our mid-level technical person replied:

I forwarded this message to our maintenance manager who, by the way, never had anything to do with maintenance in a refinery until four years ago. He is in his late 30s and most of his staff are fresh out of college. However, the maintenance manager often mentions “operator involvement in reliability,” about which he had heard at a conference.

CRI was not involving its operators in reliability stewardship.

To be successful, such an involvement presupposes a well-structured training and technical education program; implementing

BIBLIOGRAPHY Bloch, H. P., Pump Wisdom: Problem Solving for Operators and Specialists, John Wiley & Sons, Hoboken, New Jersey, 2011.

The author is Hydrocarbon Processing’s Reliability/Equipment Editor. A practicing consulting engineer with close to 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance cost avoidance topics. He has authored or co-authored 18 textbooks on machinery reliability improvement and over 490 papers or articles dealing with related subjects.

HYDROCARBON PROCESSING SEPTEMBER 2011

I9

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HPINTEGRATION STRATEGIES PAULA HOLLYWOOD, CONTRIBUTING EDITOR editorial@HydrocarbonProcessing.com

Standards needed for laboratory system integration Organizations in the hydrocarbon processing industry (HPI) and elsewhere frequently underestimate the value of the analytical laboratory to the enterprise. The perception is that the lab is a cost center that contributes little to product value. Production supervisors may view the QA/QC lab as a bottleneck as they await testing results before releasing product. This lack of visibility and understanding generally leaves the lab at the back of the line when budgets are allocated. But this doesn’t have to be the case.

Seamless flow of information. The single-supplier laboratory is a rarity. The typical analytical lab is an assortment of analyzers and instruments from a host of suppliers, as it should be. End users should have the freedom to select what they believe to be the best tool for the job. The issue is that lab device suppliers typically use proprietary file formats. While this can be advantageous for the supplier, it leaves end users to wrestle with integration issues, both in the lab itself and within the enterprise’s IT systems. As more data and information are generated by plant laboratories, the need for data exchange formats becomes more acute.

Proprietary data formats result in a virtual Tower of Babel.

There’s a lot of talking, but little understanding. This situation forces reformating data to communicate effectively with other systems. In addition to being tedious, reformatting is expensive and error-prone. Vendor-neutral data formats based on industry standards would alleviate incompatibility issues and facilitate integration inside and outside the lab.

The benefits from industry standards are well known. However, efforts to standardize the lab have not gained much traction.

The OPC Foundation tackled the issue of a common data method for analyzers and data models and released the OPC Analyzer Devices Integration (ADI) Specification for integrating process analyzers with production control systems in November 2009.

OPC ADI is a step in the right direction, but the ADI model is generic and requires adaptation prior to implementation. ADI must be incorporated into a UA Server and establish the address space according to the OPC UA specification for utilization.

Integration issues. Instrument integration involves more than device connectivity. In a collaborative production environment, a strategy that aligns plant operations with the business needs of the enterprise is critical. Enterprises can achieve significant benefits through economies of scale, utilizing IT resources more efficiently, better alignment of IT with business needs, reducing implementation costs, lowering support and maintenance costs, and improving integration to create greater information visibility across the enterprise. With integrated systems, employees can make better decisions based on more complete and timely information.

data easily. Recognizing that the inability to integrate laboratory systems impedes maximizing the effectiveness and productivity of laboratory work, the Institute for Laboratory Automation (ILA) in Groton, Massachusetts, is attempting to re-energize efforts to standardize and integrate laboratory systems. The Institute’s objective is to address issues inhibiting development of laboratory automation and the effective use of technologies in lab work.

ILA’s project proposal is to investigate and pursue establishing a foundation for laboratory systems integration.

It is not ILA’s intention to start from scratch, but rather to leverage existing work. In the initial phase of the project, ILA will examine standards such as that of HL7 and the Clinical and Laboratory Standards Institute (CLSI) to determine what could be adapted for general laboratory work. Assuming the project is deemed feasible and industry support is forthcoming, further work will commence.

Value of data. Integrated instrument and laboratory data

offer many benefits. These include improved data quality and transparency, ERP-level access to analytical data, maximizing throughput, improving product quality and reducing waste.

Despite these benefits, lab integration continues to challenge manufacturers due to the lack of standardized file formats and interfaces. ARC Advisory Group believes that independent third parties, such as ILA, can provide the spark required to advance standardization.

ILA will not have to reinvent the wheel in this effort as others have blazed the standardization trail. As in the lab, HPI plants include a mix of devices that previously utilized proprietary software tools for configuration, operation, diagnostics and integration. This resulted in a complex automation architecture that was not user friendly and severely inhibited adoption of digital fieldbus technologies. Thanks to a number of different standardization efforts, this has been overcome. As a case in point, what began in 2003 as an ad hoc, joint interest group of automation suppliers, the FDT Group has morphed into an international organization focused on standardizing the interfaces between field devices and frame applications in automation systems. At present, 82 companies in the process and factory automation industries support FDT technology.

ILA seeks support from both the end-user and supplier communities to undertake this long overdue and desperately needed initiative. The Phase I deliverable would be an analysis of project feasibility and development plan for future work. For more information, readers can visit the Institute for Laboratory Automation at http://www.institutelabauto.org/index.html. HP The author has nearly 30 years’ experience in the areas of sales and product

New efforts to standardize. The perceived lack of value

for the analytical lab is due largely to the inability to access lab

marketing in industrial field instruments that utilize a vast array of technologies including magnetic, Coriolis, radar, electrochemistry, capacitance and ultrasonic.

HYDROCARBON PROCESSING SEPTEMBER 2011

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HPIN ASSOCIATIONS HYDROCARBON PROCESSING EDITORS Editorial@HydrocarbonProcessing.com

International HPI conference gathers in Singapore Hydrocarbon Processing’s International Refining and Petrochemical Conference (IRPC)—Asia gathered industry experts from around the world in Singapore, July 19–21. Following the success of the first conference held in Rome in 2010, HP broadened the technical program to include petrochemical-refining integration as part of the second forum’s agenda. Attendees and presenters represented the full-spectrum of the global HPI. Carlos Cabrera, CEO and president of the National Institute of Clean and Low Carbon Energy (NICE) and former CEO of UOP, opened the IRPC—Asia conference with his view on how to sustain HPI businesses in the present economy. Sustainability is a term hijacked by environmentalists. According to Cabrera, sustainability is the core in which HPI companies must consider to adapt and to grow in the future. The reality check is that conditions are and will continue to change in the HPI. Cabrera made several key points to take away; they include: • Consider all stakeholders—owners, stockholders, employees, nations and communities that your business serves. Invest in people; train your employees for the future and invest in newer technologies.

• Focus on shifts in the total refinery life cycle. Reducing business risk management will be facilitated by a better approach to asset management. All refiners will need to continue improving process efficiencies via byproduct/waste minimization, process intensifications and advanced separation technologies • The HPI is a cyclic business; embrace strategies that help you and your company mitigate these cycles.

• Embrace and invest in technology and appreciate the game-changing role it can play.

The two track (technology, maintenance and operations) format provided a balanced wide-scope view of the problems challenging the HPI and, more important, the possible solutions to these problems. Speakers and attendees agreed that future growth in transportation fuels and petrochemical products will be driven by the developing economies of Asia-Pacific nations. China and India are the primary nations in which significant new infrastructure will be needed. Rajkumar Ghosh, Executive Director of the Panipat Refinery of Indian Oil Corp.

(IOC), discussed how IOC is meeting the challenges for refining and petrochemical product demand. For India, a basket of alternative transportation fuels will be necessary to meet domestic demand. India will not be a strictly diesel-oriented market. According to Ghosh, refining operations are the platform to produce cracked LPG, naphtha and kerosine—all are feedstocks for the much needed petrochemical products. IOC invested $6.1 billion at the Panipat complex over six years to diversify the company’s portfolio, along with the integration of refining and petrochemical operations. IOC found synergy in fuel and petrochemical operations that reduced energy consumption, improved cost competitiveness of prod-

Carlos Cabrera opens IRPC—Asia to an eager audience.

Attendees network during the two-day event.

ucts, decreased maintenance costs, shared utilities and lowered overhead costs for the complex. The Panipat complex fully demonstrates finding value for all molecules available in crude oil for petrochemical products (MEG, HDPE, LLDPE/LDPE, PP, butadiene and benzene.)

Attendees agreed that the HPI is changing. Product demand growth will be uneven. Paul Ruwe, Managing Director, Asia with Muse Stancil, discussed that Europe and North America will need less refined transportation fuels by 2015. In contrast, Asia-Pacific, especially China, The Middle East, Africa and Latin America show trends of increasing demand for transportation fuels. Much of the change in developed markets stem from increasing regulations on refineries and greenhouse gas emissions, regional demand destruction through CAFE rules and growing inclusion of renewables in the fuels mix.

According to Ruwe, the 2008–2010 downturn slowed refining capacity expansions, thus allowing demand to recover and increase in 2012–2013. Unfortunately, about 3.5 million bpd of new capacity is expected to come online beginning in 2014; much of the new capacity will be located in China, Latin America and the Middle East. Such a wave of new capacity will depress operating rates for some time.

HPIn Associations continued on page 140

HYDROCARBON PROCESSING SEPTEMBER 2011

I 13

Our contribution to clean energy is cleaning energy.

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As a consequence, LNG (liquefied natural gas) is becoming an increasingly important transport option. Although LNG is a very clean energy source, liquefaction requires refrigeration to a temperature of –160° C before transport is possible. In this condition, the gas has only 1/600 of its original volume and can be transported more economically. To ensure the cleanest possible energy source the natural gas can be purified using Lurgi’s Omnisulf ® process prior to liquefaction. This process involves a combination of various technologies designed to meet even the most stringent purity requirements. Contact us and we will be pleased to deliver a solution tailored to your specific needs.

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HPIMPACT BILLY THINNES, TECHNICAL EDITOR

BT@HydrocarbonProcessing.com

Rare earths and lubricant demand to grow worldwide The Freedonia Group has two reports out that will be of interest to Hydrocarbon Processsing readers. The first examines world demand for rare earths, which is expected to grow 7.1% per year to reach 180,000 metric tons by 2015 (Table 1). The second report addresses the globe’s thirst for lubricants, which is predicted to rise 2.6% a year until 2015, with demand in that year projected to be 41.7 million metric tons.

Rare earths. With demand for rare earths increasing at a 7.1% clip per year, this means that, in dollar terms, sales are expected to more than triple from $3.0 billion in 2010 to $9.2 billion in 2015. Consumption will be driven by increases in battery alloy, electronic product, motor vehicle and permanent magnet output. Market growth is expected to accelerate substantially from the 2005–2010 period, when demand in most nations was negatively impacted by substantial and unexpected reductions in Chinese exports (beginning in 2009) that led to a sharp rise in rare earths prices. Neodymium and dysprosium are expected to post the fastest growth rates of any rare earth types, spurred by increased sales of heat-resistant neodymium-ironboron (NdFeB) permanent magnets. However, cerium will remain the most widely used rare earth, accounting for almost onethird of the 2015 tonnage total.

Permanent magnets are the largest rare earths market, in terms of both value and volume. Sales will be fueled by increases in consumer electronics, electric motor, and hybrid electric and other motor vehicle production.

NdFeB magnets, also known as “neo-magnets,” will account for the majority of sales.

World demand for rare earths used in metal processing applications will climb 7.8% annually through 2015 to 19,350 metric tons. Sales will be stimulated by increased levels of global steel production, particularly high-strength steels and steels with elevated anti-oxidation properties.

China has held a virtual monopoly on rare earths production since the turn of the century. In 2010, Chinese mines pro-

duced 111,000 metric tons of rare earths, accounting for over 90% of world output.

Among the major Chinese suppliers are Inner Mongolia Baotou Rare-Earth HiTech, China Minmetals and Jiangxi Copper. However, the emergence of non-Chinese suppliers, including Molycorp, Lynas and Great Western Minerals, combined with increased research and development in rare earths refining technologies, will boost overall rare earths supplies and eventually reduce upward pricing pressures.

Lubricants. Getting back to The Freedonia Group’s report on lubicrants, it sees lubricant demand being driven primarily by strong economic growth, as countries continue to recover from the impact of the global economic recession in 2009. The company predicts the fastest increases will continue to be in Asia, followed by the Africa/Middle East region and Central and South America (Table 2). In addition to strong economic growth, all three of these regions will benefit from above-average increases in motor vehicle sales. Healthy advances in Eastern Europe will reflect a rebound in the region’s industrial output.

Motor vehicles are the largest market for lubricants, and growth will be led by strong gains in the developing Asian countries,

particularly in China and India. However, the trend toward increased drain intervals, influenced in part by the growing availability of superior, high-performance synthetic lubricants, will result in declining demand in Western Europe and North America.

The fastest growth in lubricant demand through 2015 will be in manufacturing and other markets. The Asia-Pacific region, led by China, will continue to be the primary driver of growth in these markets due to companies worldwide pursuing the region’s key advantages of relatively low labor costs and political stability. Central and South America and the Africa/Middle East region will also achieve favorable growth in manufacturing as significant countries in both regions continue their industrial development.

In terms of product types, engine oils will continue to account for the greatest share of lubricant demand going forward.

This will primarily reflect the importance of transportation in an increasingly global economy, from both a consumer and a commercial perspective. Hydraulic fluids will post the fastest growth due to a combination of increased demand in manufacturing operations and strong global growth in natural resource extraction industries such as mining and oil and natural gas production.

TABLE 1. World rare earths demand projected from 2005–2015 World rare earths demand (metric tons) Item 2005 World rare earths demand

113,280

2010

2015

128,000

180,000

% Annual growth 2005–2010 2010–2015 2.5

7.1

North America

15,350

12,800

17,000

–3.6

5.8

Western Europe

15,660

10,300

13,700

–8.0

5.9

Asia-Pacific

77,055

99,600

143,000

5.3

7.5

Central and South America

1,070

1,150

1,405

1.5

4.1

Eastern Europe

2,585

2,600

2,990

0.1

2.8

Africa/Middle East

1,560

1,550

1,905

–0.1

4.2

TABLE 2. World lubricant demand projected from 2005–2015 World lubricant demand (thousand metric tons) Item 2005 2010

2015

World lubricant demand

36,250

36,700

41,650

0.2

North America

10,800

8,820

9,300

–4.0

1.1

Western Europe

5,250

4,800

5,000

–1.8

0.8

11,570

13,530

16,500

3.2

4.0

8,630

9,550

10,850

2.0

2.6

Asia-Pacific Other regions

% Annual growth 2005–2010 2010–2015 2.6

HYDROCARBON PROCESSING SEPTEMBER 2011

I 15

HPIMPACT New requirements could raise the cost of gas and shutter US refineries A new study says that upcoming US Environmental Protection Agency (EPA) requirements could raise the cost of manufacturing gasoline, lead to the closing of domestic refineries, and force the US to double its gasoline imports while causing increased carbon dioxide (CO2 ) emis-

sions. Baker and O’Brien executed the study on behalf of the American Petroleum Institute (API).

“The new EPA requirements could be devastating to consumers and communities across the nation,” said Bob Greco, API’s group director of downstream operations. “Consumers would be hurt by the increased cost of fuel projected by the study, and the closing of refineries could put local economies at risk, meaning there

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would be fewer jobs. In addition, we would be forced to rely even more on foreign fuel supplies, and that can only weaken our nation’s economy and national security.”

The study examines the potential costs of the EPA’s “Tier 3” fuel standard for gasoline blends, which could be proposed at the end of the year. It determined that the new requirements could boost the cost of making gasoline by up to 25 cents per gallon and could shutter up to seven US refineries. The study also predicted this scenario could drive up CO2 emissions by up to 7.4 million tpy because of the increased energy needed to manufacture the new fuel blend.

“These regulations don’t make sense environmentally or economically,” said National Petrochemical and Refiners Association President Charles Drevna. “The proposal would increase greenhouse gas emissions, hurt American consumers by adding billions of dollars to the cost of manufacturing gasoline, hurt communities and workers by threatening to put some fuel manufacturing plants out of business, and weaken America’s economic and national security.”

AAM report. In 2009, the Alliance of

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Automobile Manufacturers (AAM) published a report documenting costs and benefits of a single US national standard for gasoline quality with significant reductions in sulfur and Reid vapor pressure (RVP) that would apply to all states except California. The AAM report called the new gasoline standard “national clean gasoline.”

Baker and O’Brien undertook this study in response to the AAM report, seeking to determine the potential supply and cost impacts of lowering the specifications for sulfur and RVP in gasoline. Included in the study is a refinery-by-refinery breakdown to see how these refineries would and could comply.

According to the study, implementing a nationwide (save for California) summer season 7 pounds per square inch (psia) RVP specification and sulfur limits of 20 ppm per gallon cap and 10 ppm per company annual average would remove a large quantity of natural gas liquids (NGLs) from gasoline. The modeling indicates that US domestic gasoline production would decrease by 1,157 thousand bpd during the summer, which is equivalent to 14% of projected summer 2016 hydrocarbon gasoline consumption. Under this scenario, summer gasoline imports would need to increase by 125%. However, the volume of gaso-

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HPIMPACT line with lower sulfur and lower RVP that would be available from foreign refineries is not clear. Regardless, regulations that close US refineries or lead to reduced output will make the US that much more vulnerable to supply disruptions, as more refined product will have to be obtained from overseas.

Implementation costs. Domestic refinery investment costs for implementing the lower sulfur and lower RVP standards could range from $10–$17 billion. The study’s authors predict that if such standards are implemented, the US could see the closure of four to seven refineries. These refineries would make the decision to close rather than make the required investments to be compliant. Total compliance costs for the US domestic refining industry would be in the range of $5–$13 billion.

If the specifications for sulfur and RVP in gasoline are lowered, the additional hydrotreating and fractionation required to comply would result in an increase in CO2 emissions from refineries that continue to operate. On average, the study’s authors predict the total increase in CO2 emissions at US and foreign refineries is estimated at 2.9 million tpy to 7.4 million tpy.

These findings differ from those found in the AAM report. The AAM report used only three aggregate refinery models. The Baker and O’Brien study analyzed individual models of 112 refineries. It is also noted that the AAM report did not appear to consider the lost value of NGLs that would be removed from the gasoline pool, and its estimate of the volumes that would be removed is much smaller than that of the Baker and O’Brien team.

Another key difference is that the AAM report assumes that many refineries already have the capability to produce 5-ppm sulfur gasoline. This report indicates that most refineries will require capital investments to produce 5-ppm or 10-ppm sulfur gasoline. Further, this study included FCC feed hydrodesulfurization revamps, expansions and new units, whereas the AAM report did not. If your interest is piqued and you want to read the study, it can be found in its entirety on the API website (www.api.org).

Tesoro releases report on Anacortes explosion

occurred when a heat exchanger in the refinery’s naphtha hydrotreater unit ruptured, causing an explosion and fire that fatally injured seven employees.

Findings. Examination of the damaged

exchanger identified high temperature hydrogen attack (HTHA) as the cause of the failure. Weakened by HTHA damage, the steel shell of the failed exchanger could not withstand operating pressures resulting

in the shell rupture and subsequent fire.

The HTHA damage to the carbon steel was visible in laboratory samples under high magnification but could not be identified through normal visual inspection.

Prior to the incident, specialized inspection for HTHA was not performed on the exchanger that subsequently failed as corrosion experts did not recommend the failed exchanger for an HTHA inspection in any of the five corrosion reviews previously. HP

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HPIN CONSTRUCTION HELEN MECHE, ASSOCIATE EDITOR HM@HydrocarbonProcessing.com

North America Gevo, Inc. has plans with South Hampton Resources, Inc., a subsidiary of Arabian American Development Co., to build a hydrocarbon processing demonstration plant at its facility just outside of Houston in Silsbee, Texas. This demonstration plant is expected to process up to 10,000 gallons of Gevo’s isobutanol per month into various renewable hydrocarbon materials including jet fuel for engine testing, isooctane for gasoline and isooctene and paraxylene for polyethylene terephthalate (PET), and will supply other potential customers with material for product qualification and evaluation. The demonstration plant is slated for completion before the end of 2011. The contract between the companies is for two years with one-year extensions thereafter.

South Hampton Resources, Inc., has agreed to provide Gevo with toll-manufacturing services at its Silsbee facility and to complete the final design and engineering package for the demonstration plant. Gevo will own all the intellectual property that results from the work, including the plans, designs and systems developed for the demonstration plant and future commercialscale plants.

NexLube Tampa LLC plans to construct a used-oil re-refinery and blending plant in Tampa, Florida, using Axens’ and Viscolube’s Revivoil technology. The facility is expected to process 24 million gpy of dehydrated used oil. The re-refinery unit will produce API Group II base oil and various grades of motor oil, hydraulic fluid, transmission fluid and other specialty products after onsite blending.

Re-refined products will be marketed in a closed-loop process, where NexLube will provide its branded products to a municipality or other customer that has its own fleet of vehicles. The fleet uses the branded product and then returns the used oil to the re-refining plant.

Axens’ innovative Revivoil technology was jointly developed with Viscolube of Italy, reportedly one of the world’s leading spent lube-oil re-refiners.

TPC Group Inc. has received the Texas Commission on Environmental Qual-

ity (TCEQ) air permit necessary for the planned refurbishment, upgrade to airemission controls and restart of one of its idle dehydrogenation units. Construction of the system’s required new components, along with refurbishment of the existing unit, began following receipt of the permit.

The company has also completed the project’s primary phase of engineering, which commenced in January of this year. The company’s board of directors has approved moving forward with the next phase of engineering, which is expected to be completed by the end of 2011.

The isobutylene produced from this dehydrogenation unit will provide an additional strategic source of feedstock for the company’s rapidly growing fuel products and performance products businesses, which include polyisobutylene, high-purity isobutylene and diisobutylene.

TPC Group estimates the project will produce approximately 650 million lb/yr of isobutylene from isobutane, a natural gas liquids (NGL) feedstock whose production volumes continue to increase as a result of US shale gas development. Plans forecast the dehydrogenation unit to be operational in the first quarter of 2014.

CB&I has a contract, valued in excess of $300 million, for a new natural gas processing plant in the northeastern US. CB&I’s work scope includes the engineering, procurement and construction (EPC) of a 200 million cfd natural gas processing plant, including full fractionation and treatment capabilities, storage tanks and loading systems. In addition, CB&I’s Lummus Technology business sector is providing its proprietary NGL-Max recovery technology. The contract is scheduled for completion in 2012.

KBR has an engineering, procurement and construction (EPC) contract from a wholly owned subsidiary of Molycorp to build a new chlor-alkali plant as part of Molycorp’s Project Phoenix. The chlor-alkali plant construction is one of various projects that make up Molycorp’s estimated $781 million program to reactivate the company’s rare earth oxides (REO) mine, and expand and modernize

its flagship rare earth facility in Mountain Pass, California. Molycorp is the Western Hemisphere’s only producer of REO. KBR will build upon its existing global experience in chlorine products to construct a facility implementing the chlor-alkali process, an important part of the modernization of Molycorp’s rare earth manufacturing facility.

South America As of 2013, Braskem will reportedly have yet another alternative feedstock source. In addition to sugarcane ethanol, which is used to make green plastic, the company will begin using naphtha made from post-consumption recycled plastic.

The product will be supplied by Novaenergia, a company from the Wastech Group located in Bahia state specializing in waste treatment, which will build its first advanced recycling plant along the Cia Aeroporto highway in Salvador, Bahia.

Braskem is expected to acquire initially 1.4 million liters/yr of naphtha made from plastic waste, which will be processed at its basic petrochemicals unit in the Camaçari complex.

The plant will process 450 tpd of waste and will transform plastic waste into synthetic oil. Every 36 tons of this waste will yield 30,000 liters/day of light oil that will

Trend analysis forecasting Hydrocarbon Processing maintains an extensive database of historical HPI project information. The Boxscore Database is a 35-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc. Many companies use the historical data for trending or sales forecasting.

The historical information is available in comma-delimited or Excel® and can be custom sorted to suit your needs. The cost depends on the size and complexity of the sort requested.

You can focus on a narrow request, such as the history of a particular type of project, or you can obtain the entire 35-year Boxscore database or portions thereof. Simply send a clear description of the data needed and receive a prompt cost quotation.

Contact: Lee Nichols P.O. Box 2608, Houston, Texas, 77252-2608 713-525-4626 • Lee.Nichols@GulfPub.com HYDROCARBON PROCESSING SEPTEMBER 2011

I 21

HPIN CONSTRUCTION be used by Braskem to make naphtha, as well as fuel oil and diesel oil with lowsulfur content (S < 10 ppm). The installation of Novaenergia’s recycling unit in Bahia will require investment of some R$25 million, with startup expected by the end of 2012.

A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has been awarded a contract by YPF

S.A. for the delayed coker heater for the new delayed coking unit at YPF’s Complejo Industrial La Plata in Argentina. Foster Wheeler’s scope of work includes engineering, equipment supply and supervision to construction and startup.

The fired heater, an integral part of the new coker, uses Foster Wheeler’s leading Selective Yield Delayed Coking (SYDEC) technology. Foster Wheeler is providing the detailed engineering, procurement

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services and assistance with construction and plant startup for the new coker. The delayed coker heater for the new delayed coking unit is expected to be completed by June 2012.

Over the past several months, Elliott Group has won contracts from Petroleo Brasileiro S.A. (Petrobras) to supply compressors for expansion projects at the company’s REGAP and REMAN refineries, as well as the new northeast refinery, RNEST. The projects will aid the company’s efforts to increase domestic production of highquality diesel fuel.

Elliott equipment for the projects includes a high-pressure hydrogen recycle compressor driven by a steam turbine for the REGAP refinery expansion, a motordriven wet gas compressor for the REMAN expansion and duplicate coker strings for the RNEST delayed coking unit. Elliott will also provide auxiliary systems for the compressor packages, including lubrication, buffer and control systems. The equipment will be manufactured at the company’s Jeannette and Belle Vernon, Pennsylvania, facilities, with staggered shipments beginning in January 2012.

Saipem has been awarded new engineering and construction onshore contracts in South America and West Africa worth approximately $800 million. In Suriname, the national oil company Staatsolie awarded Saipem the contract for the expansion of the Tout Lui Faut refinery, which is located 20 km south of the capital, Paramaribo. Saipem has already carried out 10 months of engineering activities based on a reimbursable agreement. The agreement has now been converted into a full engineering, procurement and construction (EPC) contract, encompassing engineering, procurement and fabrication, and construction activities.

The project is aimed at achieving a twofold increase in the Suriname refinery’s capacity to 15,000 bpd. The fabrication of the plant’s preassembled portion will be carried out at the Saipem Arbatax fabrication yard in Italy. The project will be completed in 43 months.

In Nigeria, Saipem has been awarded the contract for the Otumara-SagharaEscravos gas pipeline by Shell Petroleum Development, as part of Shell’s program to reduce gas flaring in the country.

The project will be completed in 18 months and will be fully executed in

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HPIN CONSTRUCTION Nigeria, including project management and procurement activities. Furthermore, Saipem has agreed to increases in the scope of its work on existing onshore contracts in Nigeria.

Europe Süd-Chemie, a member of the Clariant Group, has started construction of what will reportedly be the largest German plant for manufacturing climate-friendly biofuel cellulosic ethanol from agricultural waste materials. From the end of 2011, the plant, which is being built very close to the Bavarian BioCampus in Straubing, will produce up to 1,000 tpy of cellulosic ethanol, primarily from wheat straw from the Straubing area. It, therefore, constitutes a key milestone on the road to the technology’s commercialization.

Since 2009, Süd-Chemie’s sunliquid process has been successfully tested on a pilot scale. This is an innovative, biotechnological process for producing bioethanol from plant waste materials such as cereals or corn stalks. Construction of the demonstration plant is the essential interim step for the planning of energy-efficient and cost-effective production facilities with optimum greenhouse-gas savings.

The total project volume is around €28 million: €16 million in investment and just under €12 million for accompanying research measures. The Bavarian state government and the German Federal Ministry of Education and Research (BMBF) have each put around €5 million into this and other research initiatives relating to the project.

Invensys Operations Management has two contracts to provide comprehensive automation solutions and services to help drive control, environment and safety excellence at TNK-BP’s Saratov oil refinery in western Russia. The 7 million tpy refinery markets more than 20 products, including high-quality gasoline, low-sulfur diesel, naphtha, vacuum gasoil, fuel oil and bitumen.

Invensys will supply its Foxboro I/A Series distributed control systems and Triconex emergency shutdown and critical control systems, as well as Foxboro measurement, instrumentation and control devices for the refinery’s hydrofining and isomerization units. The company will also provide project management, documentation development and other services, including engineering, delivery, installation, testing and startup, along

with a full range of training courses for the systems, covering development, commissioning and maintenance.

Siemens Belgium is installing an integrated Manufacturing Execution System (MES) at a new tank farm on the Taman Peninsula, in Russia’s Krasnodar region.

The order was awarded by the United Transport and Forwarding Company OTEKO, which intends to use the system

to manage operating schedules in the tank terminal. All data collected from the MES can be called up in real time, resulting in optimized operational control. Specific components like order and access management or stock accounting cover typical terminal management needs. Delivery of the MES is scheduled for commissioning during the second half of 2011.

Siemens Russia is commissioning the electrical and automation equipment of

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HPIN CONSTRUCTION the liquefied petroleum gas (LPG), crude oil and fuel oil terminal on the Taman peninsula. To further maximize the performance of the terminal complex, the transportation company OTEKO has also awarded a contract for the installation of Sitas IT, the Siemens Terminal Automation System. This industry-specific IT package is based on Simatic IT, the MES from Siemens. It will be supplied by Siemens S.A. Belgium, the competence cen-

ter for tank terminals within the Industry Solutions Division.

Gazprom Neft has selected Elliott Group to build the compressor string for a new hydrogen recovery unit at its Omsk refinery. Elliott will provide a feed gas string consisting of a 15MB8 motor-driven barrel compressor. Control and buffer gas systems are included in the package.

The hydrogen recovery unit is part of

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an overall expansion and environmental initiative that includes a new catalytic cracking hydrotreatment plant and a diesel fuel hydrotreatment plant. The hydrogen pressure-swing recovery unit will use UOP adsorption technology to purify the product stream in the diesel hydrotreatment plant.

Gasoline and diesel products produced at the new hydrotreater complex will meet Euro-4 and Euro-5 emission standards for environmentally friendly motor fuels.

The compressor will be built and tested in Elliott Groupâ&#x20AC;&#x2122;s US manufacturing facility in Jeannette, Pennsylvania. System packaging will be completed in Elliottâ&#x20AC;&#x2122;s facility in La Spezia, Italy. Delivery is scheduled for late 2011.

Shell and Paques Holding B.V. have agreed to form a 50-50 joint venture (JV), Paqell B.V., to focus their efforts on the marketing of biological desulfurization in the oil and gas sector for high-pressure gas applications using THIOPAQ oil and gas (O&G) technology.

THIOPAQ has been deployed by Paques in the water business for atmospheric biogas desulfurization since the early 1990s.

Paques then formed a technology alliance with Shell in 1997, and saw the successful deployment of THIOPAQ to the broader oil and gas industry, particularly in largescale hydrogen sulfide (H2S) removal and sulfur recovery. THIOPAQ is being applied in four sites in the oil and gas industry, with seven projects under construction.

A new research and development program will be concluded by the end of next year, aiming to provide the next-generation THIOPAQ O&G technology with a step change in efficiency and capacity. Once this research program is successfully completed, Paqell will operate from the Watercampus in Leeuwarden, the Netherlands, where there is a high level of expertise available in sustainable water technology. For now, Paqell operates from Leeuwarden, Amsterdam and Balk in the Netherlands. Machiel van der Schoot will be managing director of Paqell B.V.

Middle East Creating Value.

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Morgan Thermal Ceramics has a contract to supply Superwool 607 HT Pyro-Bloc Modules as part of a world-class refinery being constructed by the Saudi Aramco Total Refining and Petrochemical Co. (SATORP), a joint venture between Saudi Aramco and TOTAL S.A. Morgan Thermal Ceramics received the order from KTI Corp., supplier of the fired heaters for

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HPIN CONSTRUCTION a portion of the project. SATORP will be installing prefabricated panels of Thermal Ceramics Superwool 607 HT Pyro-Bloc Modules into six fired heaters at the facility, located in Jubail, Saudi Arabia. Delivery on the fast-track project is expected to be completed by early 2011.

SATORP specified that insulation used for this portion of the 400,000-bpd refinery and petrochemical project be composed of non-refractory ceramic fiber (RFC)

material in response to workplace environmental control concerns.

ABB has an order worth more than $30 million, from Saipem S.p.A. and Samsung Engineering Co., Ltd., to provide a range of power and automation equipment for a natural gas processing plant in Abu Dhabi, the United Arab Emirates.

The plant is located in the Shah natural gas field 180 km southwest of Abu Dhabi, and has a production target of one billion

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cfd of sour gas. Abu Dhabi is developing its sour or high-sulfur gas reserves as domestic power consumption soars. The hydrogen sulfide (H2S) content of the gas must be reduced to acceptable levels before it can be used.

For this project, ABB Italy and ABB South Korea will supply low-voltage switchgear, intelligent motor-control units and variable-frequency drives.

The boards of directors of both the Dow Chemical Co. and the Saudi Arabian Oil Co. (Saudi Aramco) have approved the formation of a joint venture (JV) to build and operate a world-scale, fully integrated chemicals complex in Jubail Industrial City, Kingdom of Saudi Arabia. The authorization for the new JV, named Sadara Chemical Co., comes after an extensive project feasibility study and front-end engineering and design (FEED) effort that began in 2007.

Comprising 26 manufacturing units, building on Saudi Aramco’s project management and execution expertise, and utilizing many of Dow’s industry-leading technologies, the complex will reportedly be one of the world’s largest integrated chemical facilities, and the largest ever built in one single phase. It will possess flexible cracking capabilities and will produce over 3 million metric tons of highvalue-added chemical products and performance plastics.

Construction will begin immediately and the first production units will come online in the second half of 2015, with all units expected to be up and running in 2016.

BASF will expand its presence in the Middle East region by building a state-ofthe-art plant for customer-specific antioxidant blends (CSB) in Bahrain. CSBs are key additives for the production of polymers for the plastics industry, especially for the Middle East region.

Construction of the new facility will start in September 2011. It will reportedly become one of the world’s largest CSB plants with a capacity of about 16,000 metric tpy. The new plant will be operational by the end of 2012.

Shell Global Solutions International B.V. has an agreement with the South Refineries Co. of Iraq to provide technology licenses to a refinery in Basrah, Southern Iraq.

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HPIN CONSTRUCTION Shell Global Solutions will provide a license for a sulfur-recovery unit and visbreaker unit as part of the agreement.

Together with the refinery expansion, these technologies will contribute to optimized operations at the Basrah refinery, significantly boosting capacity. The sulfurrecovery unit is likely to enable the refinery to meet and exceed world standards for emissions, while the visbreaking unit will help increase overall upgrading, building

a future-proof solution for the long term.

The upgrading of the refinery with Shell Global Solutions’ leading technologies will contribute to fulfilling Iraq’s expected future demand for oil products.

Asia-Pacific Stamicarbon, the licensing and IP center of Maire Tecnimont S.p.A., has signed a license agreement with Hengang Huahe Coal Chemical Industry, Ltd. for

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a urea plant with a capacity of 1,860 metric tpd. The plant will be built in Hegang City, Heilongjiang Province, Peoples’ Republic of China.

The urea plant will use Stamicarbon Urea2000Plus Technology, which features a pool reactor, minimum equipment and minimum plant height. By using Safurex stainless steel for the high-pressure synthesis section, low oxygen intake can be obtained.

Stamicarbon will deliver the process design package, related services and all proprietary high-pressure equipment, pool reactor and piping. Startup is planned in 2014.

Kraton Performance Polymers, Inc., has a framework agreement with Formosa Petrochemical Corp. (FPCC) that sets forth the major terms and conditions that will, upon completion of the necessary definitive agreements, govern the formation of a 50/50 joint venture (JV). This JV will construct and operate a 30-kiloton hydrogenated styrenic block copolymer (HSBC) plant to be located in Mailiao, Taiwan.

The agreement governs all commercial, operational, technical and management aspects of the planned JV company. Kraton and FPCC expect to finalize documentation by December 31, 2011, and plan to have the plant operational in the second half of 2013. The cost of the plant is expected to be in the range of $165 million to $200 million.

As proposed in the framework agreement, the design of the JV plant will incorporate Kraton’s proprietary polymerization technology, and the plant will produce Kraton’s high-value-added HSBC polymer grades. The plant will be operated by the JV and Kraton will undertake the global marketing of all products manufactured at the facility.

CB&I has a contract, valued in excess of $500 million, for the engineering, fabrication and construction of two160,000 m3 liquefied natural gas (LNG) storage tanks, as well as additional work for a LNG liquefaction project in the Asia-Pacific region.

CB&I’s contract is expected to be completed in 2015.

A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has an understanding to form a jointly owned company with the State

Select 158 at www.HydrocarbonProcessing.com/RS 30

HPIN CONSTRUCTION Oil Company of Azerbaijan Republic (SOCAR) in the Republic of Azerbaijan.

The new jointly owned company will focus on providing process, engineering, procurement, construction supervision and project management services associated with the development of the new oil, gas processing and petrochemical complex.

The new entity will provide the same services for upstream, midstream and downstream oil and gas projects developed

by SOCAR both in the Republic of Azerbaijan and in other countries.

Foster Wheeler and SOCAR will prepare a joint action plan for establishing and incorporating the new company, with its headquarters in Baku.

The Linde Group has been commissioned to build and operate two large air separation plants to supply gases onsite to Yantai Wanhua in Shandong, East China.

The project contract will involve investment of around €130 million. The two plants, which are to be built by Linde’s Engineering Division, each have a capacity of 55,000 Nm3h of oxygen. They are expected to come onstream between the

end of 2013 and the start of 2014, when they will supply oxygen and nitrogen to Yantai Wanhua’s production plants. In addition, Linde will produce liquefied products for the open market in the Shandong region. The project includes the construction of a 20-km pipeline in the Yantai Economic and Technology Park.

UOP LLC, a Honeywell company, has been selected by Zhejiang Julong Petrochemical Co. Ltd. (ZJLPC) to provide key technology for a new unit to produce propylene at its facility in Pinghu City, Zhejiang Province, China. Honeywell’s UOP will provide engineering design, technology licensing, catalysts, adsorbents, equipment, staff training and technical service for the project. The unit is expected to start up in 2013 and to produce 450,000 metric tpy of propylene.

The new propane dehydrogenation unit at the facility will use UOP’s C 3 Oleflex technology to convert propane to propylene, which is used in producing chemicals and materials such as films and packaging. Compared to competing PDH processes, Oleflex technology is said to

provide the lowest cash cost of production and the highest return on investment, enabled by low operating and capital costs, high propylene yield and reliability, and maximum operating flexibility.

BASF has chosen Fluor Corp. as an engineering partner for chemical and petrochemical projects across Asia and Europe. BASF has awarded Fluor umbrella services agreements in these regions for undisclosed contract values.

The partnering agreements will cover capital investment projects with separate service orders throughout Asia and Europe.

Services provided on projects covered by the agreement will include front-end engineering and design (FEED), project management services and/or detailed engineering, procurement and construction management services.

Fluor’s Haarlem office in the Netherlands will lead efforts for the European partnership agreement and will interface with BASF’s global headquarters. Multiple other Fluor operations centers will also be utilized as necessary for project execution. HP

Select 178 at www.HydrocarbonProcessing.com/RS HYDROCARBON PROCESSING SEPTEMBER 2011

I 31

Effluent Wa Water Quality

Before

After

solve processing problems with heavy crudes. we’ll share our experience.

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can improve your heavy crudes processing performance.

HPIN CONSTRUCTION PROFILE BEN DUBOSE, ONLINE EDITOR Ben.DuBose@HydrocarbonProcessing.com

Eni starts slurry technology project at Italy refinery Italian oil and gas major Eni has started work on applying Eni Slurry Technology (EST) at its Sannazzaro de’ Burgondi refinery, located near Pavia in northern Italy.

EST is Eni’s proprietary technology for the conversion of heavy oil residues in fine products, gasoline and gasoil. The process converts waste oil, heavy crude and tar sands into high-quality and performance fuels.

The project is scheduled to be completed by the end of 2012 with the start of a 23,000-bpd plant.

What is EST? The EST technology, funded by Eni with an investment of over €1.1bn, is based on a hydro-conversion process developed through a special catalyst and a current of hydrogen self-produced starting from methane.

That means that EST also can transform methane into a highquality liquid fuel through hydrogen production, the company said.

Switching away from traditional technologies. The technology allows Eni to produce gasoline and gasoil without coke or fuel oil, making the Sannazzaro a zero-fuel-oil refinery.

Company officials noted that coke and fuel oil markets were “constantly declining”.

On the other hand, EST is significantly more beneficial than traditional technologies because it is able to enhance non-conventional oil resources found throughout the world, especially in Canada and Venezuela, they said.

FIG. 1

Construction of Eni’s plant is ongoing and will be complete by late 2012.

Overall, non-conventional oil resources account for roughly three times the estimated reserves of conventional crude, the company said.

History of project. Work commenced during the 1990s at the company’s San Donato Milanese labs.

Works continued at the Taranto refinery, where a 1,200-bpd demo plant started operations in 2005, representing the reference point of the Sannazzaro plant.

The design of the new plant, which will be carried out in accordance with the highest technological and environmental standards, began in mid-2008 and involved Saipem for the engineering activities, company officials said.

Supply of the reactor, which is the core of the chemical process, began in 2009.

Present activity. About 1,000 construction employees are currently on site at the refinery, with as many as 2,000 expected at its peak, Eni said.

Thus far, workers have logged about 500,000 hours without an injury. That figure reflects Eni’s commitment to proper safety procedures, it said.

Construction should wrap up by late 2012. HP

FIG. 2

Diagram of EST project technology.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 33

HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Project

Ex Capacity Unit

Woodside Energy Ltd Orica Australia Party Ltd PTT FLNG Ltd/PTTEP Australasia PetroChina BP Zhuhai Chemical Co Linde Invista Inc. INEOS Phenol Indian Oil Corp Ltd Jurong Aromatics Corp SK Energy Nghi

Karratha Newcastle Offshore Dagang Guangdong Shandong Shanghai Zhangjiagang Ennore Jurong Incheon Thanh Hoa

MEG Recovery Ammonia (2) RE LNG Floating (FLNG) Refinery EX PTA (Purified Terephthalic acid) EX Air Separation (2) Fibers Phenol Refinery Xylene, Ortho Hydrocracker Kerosene, HDS

Lukoil Neftochim Bourgas INA Industrija Nafte Total Tamoil Raffinazione Polish Oil & Gas Petrom Sibur TANECO Nizhnekamsk Refinery Total E & P

Burgas Rijeka Gonfreville Cremona Swinoujscie Ploesti Kstovo Nizhnekamsk Nizhnekamsk Sullom Voe

Hydrocrack, Gasoil Refinery Lube Hydroprocessing Refinery LNG Terminal Coker, Delayed EPC Services Aromatics Complex Sulfuric Acid Gas Plant

Escobar Canoas Itaborai Undisclosed Salamanca Malvinas

LNG Hydrotreater, ULSD Benzene Refinery Gasoline Desulfurization Cryogenic Gas Plant (5)

Kharg Island Karbala Shuaiba Salalah Sohar Ceyhan

Methanol (2) Refinery Clean Fuels PET (2) Sulfur Recovery Unit (3) Refinery

Cost Status Yr Cmpl Licensor

Engineering

Constructor

Aker Solutions ACSA Linde

Aker Solutions ACSA

ASIA/PACIFIC Australia Australia Australia China China China China China India Singapore South Korea Vietnam

None m-tpd m-tpy bpd m-tpy cmd kty Mtpy None 200 Mm-tpy 40 Mbpd None

U E S H E U E E P E H E

2012 2015 2016 2014 2012 2013 2014 2013 2016 2014 2016 2013

500

U C H U P E H C E U

2012 2011 2012 2012 2014 2014 2012 2011 2012 2014

Mcfd m-bpd Mtpy 8400 MMtpy Mbpd 345 MMscfd 45

C E E S E E

2011 2013 2013 2015 2015 2013

4430 m-tpy 632 200 bpd 6500 None 527 Mt 296 155 t/a 15 MMtpy 10000

H F E U P F

2013 2016 2013 2012 2015 2012

C P

2011 2015

H C E

2014 2011 2013

1150 2 200 1.7 132 11 400

187

5000

ACSA

Rosneft Linde

Linde

UOP CLG Axens

UOP CLG

SKEC

Axens

Technip

CLG

CLG WorleyParsons

Lummus Technology Technip UOP Haldor Topsøe Petrofac

CB&I Lummus|FW

Invista INEOS Phenol

EUROPE Bulgaria Croatia France Italy Poland Romania Russian Federation Russian Federation Russian Federation Scotland

RE RE EX EX EX

37 Mbpd None 8 Mbpd 90 kbpd 5 Bcmy 36 Mbpd 450 Mtpy 210 Mtpy 55 m-tpd 500 Mcfd

539 600 957 1332 5000

GS E&C

GS E&C

Petrofac

Petrofac

Excelerate Energy Skanska

Skanska

LATIN AMERICA Argentina Brazil Brazil Costa Rica Mexico Peru

YPF Argentina Petrobras Petrobras CNPC/Recope Pemex PlusPetrol Peru

TO EX

500 38 600 10 25 520

Haldor Topsøe Axens CDTECH

CDTECH CB&I

Davy Process|JM

Namvaran Technip Fluor

MIDDLE EAST Iran Iraq Kuwait Oman Oman Turkey

Kharg Petrochemical RKC KNPC Octal Holding & Co Oman Refinery Co LLC DAPRAS/IOCL/SOCAR JV

RE

IIND Saipem

Uhde Inventa-Fischer Jacobs Nederland BV Shaw

UNITED STATES Mississippi Oregon

Gulf LNG Jordan Cove Energy

Pascagoula Coos Bay

LNG Storage LNG Terminal

160 Mm3 1 Bcf

Texas Texas Texas

Eastman Chemical Citgo Samsung Eng

Beaumont Corpus Christi Houston

Coal Gasification Cracker, FCC (3) Chlorine

None 163 bpd 816 MMtpy

1200 1.5 400

BOXSCORE DATABASE

Technip Black & Veatch

ENTREPOSE|Kiewit Energy Vinci Construction

ONLINE

THE GLOBAL SOURCE FOR TRACKING HPI CONSTRUCTION ACTIVITY For more than 50 years, Hydrocarbon Processing magazine remains the only source that collects and maintains data specifically for the HPI community, publishing up-to-the-minute construction projects from around the globe with our online product, Boxscore Database. Updated weekly, our database helps engineers, contractors and marketing personnel identify active HPI construction projects around the world to: • Generate leads • Market research • Track trend analysis • And, decide future budget planning.

Now, we’ve made our best product even better!

Enhancements include: • Exporting your search results to Excel so you can compile your research • Delivering the latest updated projects directly to your inbox each week • Designing customized construction reports for your company using our 50 years of archived projects.

For a Free 2 -Week Trial, contact Lee Nichols at +1 (713) 525-4626, Lee.Nichols@GulfPub.com, or visit www.ConstructionBoxscore.com

34

I SEPTEMBER 2011 HydrocarbonProcessing.com

Select 160 at www.HydrocarbonProcessing.com/RS

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refining your profit

UOP helps you exceed your goals with innovative technology, catalysts and optimization solutions specifically designed to meet your needs.

UOP hydroprocessing solutions and optimization services are designed to help you maximize your return on investment and grow your business. As regional market demands shift, we provide the process technologies, catalysts and services that will meet your changing business needs. Our experts work closely with you to meet your desired yields and product specifications including ultra-low sulfur diesel standards while improving your operational efficiency.

Backed by over 50 years of hydroprocessing innovations, UOP offers the best and most advanced solutions to keep your business one step ahead.

For more information about UOP, visit www.uop.com ©2010 UOP. All Rights Reserved.

REFINING DEVELOPMENTS

SPECIALREPORT

Understand differences between thermal and hydrocracking Successful operation and product yields are controlled by reactions at the molecular level S. SAYLES and S. ROMERO, KBC Advanced Technologies, Houston, Texas

O

ptimizing performance from existing residual upgrading equipment is achieved through maximum asset utilization. During the upgrade of residual facilities, economic goals of the project required operating at the upper end of the design envelope due to equipment limitations. The solution may involved new equipment to remove the identified bottlenecks. But, budget and investment constraints can limit funding, and careful prioritization is needed to justify capital expenditures. Understanding the conversion, yields and product qualities between competing conversion processes allows better investment selection. This case history discusses in detail thermal cracking kinetics—a common link between coking—and residual hydrocracking.1 Generic coker kinetics and simulation models. For

many years, the coking chemical reaction has been studied by the refining industry, and the kinetics are fairly well understood.

A simplified coker cracking mechanism consists of cracking and polymerization reactions, as shown in Fig. 1. Thermal cracking reactions form lighter liquid products than the feedstock and solid coke. The formation mechanism of the lighter products is achieved by rejecting hydrogen from the larger feed molecules, thus producing a hydrogen-deficient reactant—coke.

To demonstrate this mechanism, a delayed coker will be used to evaluate the process mechanics. The same evaluation can be used for any thermal cracking processes, for example visbreaking, fluidized cokers or flexicokers. A simulation model can provide the fundamental kinetic representations of the delayed coker operaCracking reactions Light gases Light Resid feed oils Heavy oils

Polymerization reactions Heavy oils

Combine to form larger heavy oils

Vacuum resid or other coker feeds Liquids

FIG. 1

500

1,000 1,500 2,000 Boiling point, °F

Coker cracking mechanism.

Resid hydrocracker kinetics and simulation model.

The simple hydrocracker kinetics have also undergone extensive investigation, and they are believed to be fairly well understood.

The hydrocracker kinetics are complicated by the ability to vary the operating temperature, pressure, reaction time and catalyst type. Residual hydrocracking is typically done at high pressure, temperature and reaction times. Hydrocracking catalyst are limited to cobalt/molybdenum (Co/Mo) or nickel/Mo (Ni/Mo) types with a selection of pore distribution to control sedimentation or hetro atom removal. Ebullated-bed or moving-bed reactors can maintain the hetro atom removal by catalyst addition, and product stability is improved by catalyst activity.4 Fig. 2 shows a simple representation of the hydrocracking kinetics. The comparison to coker conversion was made by using an ebullated bed reactor. The same comparison can be made using moving-bed or fixed-bed residual hydrocrackers.

New model. A new simulation model was developed for a residual hydrocracker. This model utilizes fundamental reaction and reactor kinetics to predict residual hydrocracker performance.

The following discussion uses a simplified version of the model Basic kinetics

Reactor configurations

Conversion dC rRi = k –––Ri dti rRi = Rate of reaction CRi = Concentration of Resid ti = Residence time ti + 1 CRi + 1 Rxn segment

yst t tal en Ca cem la rep Fixe

db

ti

Coke 0

tion. This discussion used a simplified version of the simulation model thermal cracking kinetics to explore the reaction yield effects for a single feedstock to allow comparison to hydrocracker yields and products.

2,500

CRi

ed

Simplified ebullated bed reactor Upflow Oil recycle Cup or pan Ebullated catalyst bed Catalyst addition Down comer or and withdrawl recycle line Feed Recycle or ebullation pump Simplified fixed bed reactor Downflow Distributor tray Fixed bed of catalyst

3,000

FIG. 2

Simple kinetics for hydrocracking reactions.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 37

SPECIALREPORT

REFINING DEVELOPMENTS TABLE 1. Feedstock qualities

Reactor WABT increase with time deactivation for constant % HDS

Temperature increase, % total ΔT

100 90 80 70 60 50 40 30 20 10 0

on ersi

nv

co sed

a

e Incr

HDS

y bilit t sta

reas

Dec

0

10

20

30

40 50 60 70 Relative time, % run

80

Bitumen

Production method

SAGD

% Diluent in blend, vol%

0

API

9

Elemental Analysis, Dry, w%

uc

rod ed p

Description

90

100

C

84.1

H

10

S

4.6

N

0.4

Metals, wppm FIG. 3

Catalyst activity over run length.

170

Others

300

Oxygen, w%

0.8

1,500

Total, w%

100

1,300 Normal boiling point, °F

60

V 1,600

1,400

1,200 1,100 1,000 900 800 700 Whole bitumen Residue Gasoil

600 500 400 0 FIG. 4

10

20

30

40 50 60 Cumulative, wt %

70

80

90

100

Product cuts of SAGD Athabasca Bitumen.

kinetics to explore the reaction yield effects for the same feedstock as used for the delayed coker yield projection.

Conversion. Coking and hydrocracking kinetic models

use a thermal-cracking mechanism to simulate conversion of residual feed into lighter products. The individual coking and hydrocracking thermal cracking kinetics were developed independently using data from each process. No comparison or usage of one mechanism by the other was conducted until this study that has demonstrated the two are nearly identical and was confirmed by recent pilot unit testing.1,2 Catalytic cracking of residual does not occur in the hydrocracking process.

Kinetic studies and recent pilot data indicate that the thermal conversion with or without catalyst is within the experimental error once adjustments are made for residence time effects. The extent of conversion is controlled by either lack of hydrogen (coking) or hydrogen addition (hydrocracking). Hydrocracking allows hydrogen to fill the split chain that short circuits the polymerization or condensation reactions; such reactions prevent coke formation.

The “hydrogen addition” process has a product slate higher in hydrogen content than the feed, and it is all liquid, with only a 38

Ni

I SEPTEMBER 2011 HydrocarbonProcessing.com

small amount of sediment formation. Hydrogen addition lowers the product’s liquid density, which realizes a higher than 100% volume liquid yield.

Coking allows polymerization or condensation to continue until coke is formed, thus increasing the liquid-product hydrogen content by removing carbon. This is referred to as “carbon rejection.” The coke removal results in a volume liquid yield less than about 75%.

While catalytic cracking does contribute to conversion, without catalyst, conversion is limited to a relatively low level due to the lack of hydrogen replacement. Vacuum reside (VR) conversion without catalyst is limited to about 25 wt%–30 wt% at 1,000°F+ conversions. At higher conversion, the unconverted reaction products, in the same boiling range as the feed, are unstable causing sedimentation downstream of the reactors and equipment plugging. The unconverted reaction products’ instability is possibly a function of the lower asphaltenes content of the feed and removal of the asphlatene solubilizing resin fraction.

Reactors. The reactor type plays an important part in the total hydroconversion levels. The conversion is limited to about 35%–45% for fixed-bed reactor systems due to product sedimentation and catalyst deactivation. Ebullated-bed or moving-bed VR hydrocrackers allow catalyst replacement online, and higher conversions are possible before the sedimentation limit occurs. Catalyst type plays an important part in mitigating sedimentation. Pore size distribution and catalytic metals are important factors to maximize conversion for a given VR feed.

Correlations between feedstock quality and conversion focus on the saturates, aromatics, resins and asphaltene (SARA) feed contents. Different ratios of SARA components have been related to higher conversion potential of the feed. Using low-activity slurry catalysts indicate that some surface area is required to allow conversion and product stabilization.3 One of the exciting opportunities in residual hydrocracking is developing a catalyst that is active for cracking. This is an high interest research area by the catalyst manufactures.

Cokers. For coking units, conversion is a function of the Conradson Carbon Residue (CCR) in the feedstock. The liquid product is a function of: 100-CCR ⫻ feedfactor. The feedfactor varies from 1.5 to 2 and depends on feedstock quality. The CCR is typically less than 30 wt% resulting in a conversion to liquid

Since 1968

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of about 70 wt% along with a net feed liquid loss of about 30 wt%. In contrast, hydrocracking conversion is limited to about 70 wt% with the unconverted product remaining a liquid. Some refining operations are running at conversion exceeding 70 wt% with special circumstances for handling the liquid product. For this study, the conversion was kept at 70 wt% to allow the comparison to coking.

Hetro atom. The downflow reactor has a fixed-catalyst volume,

and catalyst activity decreases with time. Catalyst deactivation increases due to feed contaminants. To maintain a constant HDS activity, the reactor temperature is increased, thus decreasing product stability as shown in Fig. 3. Ebullated-bed reactors and other catalyst replacement technologies allow adding fresh catalyst while maintaining the catalyst activity, reactor temperatures and conversion at constant levels. The corresponding product stability is achieved at higher conversion levels.

Feedstock. For this example, the feedstock is a typical Atha-

basca bitumen as produced by the steam assisted gravity drainage (SAGD) method. Table 1 lists the qualities of the SAGD produced bitumen.1 The diluent distillates were removed, and the VR product meets feed quality. The new model was used to fractionate the SAGD Athabasca bitumen to a 1,020째F-residue cut point, as shown in Table 2 and Fig. 4.

General assumptions. The operation was assumed to process 100,000 bpd of VR from SAGD bitumen (see Tables 1 and 2). The delayed coker and associated equipment were assumed to make equivalent final liquid product with a sulfur contents similar to the ebullated-bed hydrocracker. This requires hydrotreating all liquid products in fixed-bed units

TABLE 2. Product characteristics of SAGD Athabasca bitumen Vol%

Whole bitumen

Gasoil

Residue

100.00

47.72

52.28

API

9.00

16.37

2.88

UOP K

11.33

11.40

11.27

MW

527

384

763

C/H, wt

8.70

8.02

9.26

Sulfur, Wt%

4.60

3.45

5.55

Nitrogen, ppm

4,000

2,299

4,756

MCC, wt%

14.5

1.1

25.7

Metals, ppm

530

207.75

776

plus the associated hydrogen production. The 100,000-bpd ebullated-bed hydrocracker and hydrogen plant were assumed to provide a unit capable of 70% conversion and allow comparison directly to the coker yields. Perfect fractionation of the products was used to facilitate this comparison. Other considerations such as offsites, location, utilities or relative economics were not considered.

Coking. Severe thermal conversion occurs in the delayed coker.

The coker drum requirements for processing the 100,000 bpd of VR was assume to be 6 drums or 3-2 drum modules. The current practice is to target a four to five year run length with slowdowns for heater cleaning. Online spalling is assumed to extend the heater run.

Technology. The latest drum technology would be used with automatic unheading for the drum associated with automated coke cutting. The blowdown system recovers all produced vapor HYDROCARBON PROCESSING SEPTEMBER 2011

I 39

SPECIALREPORT

REFINING DEVELOPMENTS

Delayed coker yields - mass 1.7%

0.1% 3.6% 1.7% 1.5% 12.3%

32.6%

18.3%

Delayed coker yields - sulfur 26.4

H2S NH3 Light gas Propane/propylene Butane/butylene Naphtha (c5-400 °F) LCGO (400-650°F) HCGO (650 °F plus) Coke (427 lbs/BFOE)

48.4% 1.1% 6.4%

H2S Naphtha (c5 - 400 °F) LCGO (400-650 °F) HCGO (650 °F plus) Coke (427 lbs/BFOE)

17.6%

28.4% 15.1%

Hydrocracker yields - mass 3.8%

0.1% 5.9% 3.5% 2.4%

29.1%

5.9%

22.5%

H2S NH3 Light gas Propane/propylene Butane/butylene Naphtha (c5-400 °F) LCGO (400-650°F) HCGO (650 °F plus) 1,000 °F plus residual

26.9% FIG. 5

4.3% 0.6% 0.01%

H2S Naphtha (c5 - 400 °F) LCGO (400-650 °F) HCGO (650 °F plus) 1,000 °F plus residual 80%

FIG. 6

Coker and hydrocracker sulfur balance.

Delayed coker and hydrocracker yields.

Delayed coker and hydrocracker yields Delayed coker

Hydrocracker

H2S, %

1.7

3.8

NH3, %

0.0

0.1

Light gas, %

3.6

5.9

Propane/propylene, %

1.7

3.5

Butane/butylene, %

1.5

2.4

Naphtha (C5–400°F), %

12.3

5.9

LCGO (400°F–650°F), %

18.3

22.5

HCGO (650°F plus), %

28.4

26.9

Coke or residual, %

32.6

29.1

and has an onsite sour-water stripper (SWS). The pad coke is loaded to a grisly then to a conveyor belt system that loads the coke into rail cars for shipment. Fines suppression and containment are an integral part of the design.

Hydrocracking. The residual hydrocracker operating targets used a moderate conversion to stay within the operating constraints of sedimentation and reactor stability. The 100,000-bpd unit would have two trains with one to three reactors per train.

The gas-recovery system would allow recovering the majority of the unconverted hydrogen for recycling to the reactors. To maintain conversion levels (70% conversion,) an ebullated-bed or slurry-type reactor would be required due to catalyst the replacement. Operating conditions vary depending on the number of reactors in the train, reactor type (ebullated bed or slurry) and the feedstock type. Table lists the typical operating conditions for an ebullated bed unit.5 40

Hydrocracker yields - sulfur

I SEPTEMBER 2011 HydrocarbonProcessing.com

Catalyst addition. VR conversion at 70% requires a reactor design with catalyst replacement. The ebullated-bed reactor design is currently the only commercially demonstrated design that meets the conversion and catalyst replacement criteria. In the ebullatedbed process, batch replacement of catalyst is used to maintain catalytic activity. Emerging technologies may also achieve this or higher conversions and offer a new perspective on residual upgrading. The ebullated-bed reactor catalyst replacement rate is proportional to the metals level in the feed.6 This study uses a catalyst addition rate sufficient to provide a reasonable product sulfur level for producing synthetic crude.

Operational run targets. The operational target would be a two year run length between shutdowns for equipment cleaning and a four to five year turnaround cycle. During the run, VR conversion, hydrodesulfurization (HDS), hydrodenitrification (HDN), hydrodemetalization (HDM) and CCR reduction would all be maintained due to the ability to replace catalyst.

Other catalyst replacement technologies. Catalyst replacement is not limited to ebullated-bed units, and several technologies offer replacement in a bunker-type operation for a trickle-bed design.12–14 These processes typically have lower conversion targets since catalyst replacement is at a lower rate. The VR conversion is also expected to be thermal and is a function of the space velocity and temperature.

Emerging technologies. Although we are focusing on ebullated-bed processes for VR destruction, several new processes are being brought to market. These processes use a fine catalyst in a slurry instead of the ebullated-bed extrudates.8–11 The process claims are improved conversion, along with lower investment and operating costs. The slurry catalyst having a smaller particle size is believed to reduce the transport effects between the large residual molecule and the catalyst pore. Incorporated into the new technologies are improved catalysis that increases activity,

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Delayed coker yields - carbon

Delayed coker yields - nitrogen

3.2% 1.6% 1.5%

26.4 1.1% 6.4%

12.4% H2S Naphtha (c5 - 400 °F) LCGO (400-650 °F) HCGO (650 °F plus) Coke (427 lbs/BFOE)

66.3%

33.7%

17.6%

18.7%

Light gas Propane/propylene Butane/butylene Naphtha (c5 - 400 °F) LCGO (400-650 °F) HCGO (650 °F plus) 1,000 °F plus residual

28.9%

Hydrocracker yields - carbon

Hydrocracker yields - nitrogen

5.4% 24.2% 30.6% 0.01% 58.9% 5.6%

3.4% 2.4% 6%

NH3 Naphtha (c5 - 400 °F) LCGO (400-650 °F) HCGO (650 °F plus) 1,000 °F plus residual

11.2%

23.6%

Light gas Propane/propylene Butane/butylene Naphtha (c5 - 400 °F) LCGO (400-650 °F) HCGO (650 °F plus) 1,000 °F plus residual

28.5% FIG. 7

Coker and hydrocracker nitrogen balance.

reduce sedimentation and allow lower operating temperatures or pressures for initial conversion of residual. These technologies are still believed to achieve the conversion via thermal cracking, and the catalyst improvements are in hydrogenation activity.

FIG. 8

Coker and hydrocracker hydrogen balance.

Yield comparison. The mass yields were developed using

the protocols discussed in the preceding sections. A comparison shows the mass yield distributions are similar between the delayed coker and the residual hydrocracker units, as shown in Fig. 5. The HYDROCARBON PROCESSING SEPTEMBER 2011

I 41

SPECIALREPORT

REFINING DEVELOPMENTS

Delayed coker yields, CH wt ratio

30

Crude unit Delayed coker Hydrocracker

25

Vacuum unit

Vacuum gasoil

Vacuum bottoms

20

Hydrocracker Delayed coker

15

Coker gasoil

10

Crude unit

5

Vacuum bottoms

Coker/ residual

HCGO (650 °F plus)

LCGO (400-650 °F)

Naphtha (c5-400 °F)

Butane/ butylene

Propane/ propylene

Light gas

0

Vacuum unit

Hydrocracker Hydrocracker residual (1,000°F)

Delayed coker

11

FIG. 10

Configurations

10

TABLE 4. Liquid product quality comparison

CH wt ratio

9 Hydrocracking curve 8

Liquid products Coking curve

7

6 0 0

FIG. 9

10

20

30

40 50 API gravity

60

70

80

90

Carbon to hydrogen ration for delayed coker and hydrocracker.

TABLE 3. Ebullated-bed operating conditions Condition Reactor temperatures, °F

Range 770–825

Reactor outlet pressure, psig

1,620–2,650

Reactor hydrogen outlet pressure, psia

1,100–1,850

Conversion range, % @ 975°F

55–80

Hydrogen consumption, SCFB

760–1,700

Delayed coker Hydrocracker API Sulfur, Nitrogen, API Sulfur, Nitrogen, gravity Wt% ppm gravity Wt% ppm

Naphtha (C5–400°F)

62.5

0.5

630

76.6

0.0

6

LCGO (400°F–650°F)

28.3

2.1

2,358

45.4

0.1

976

HCGO (650°F+)

13.5

3.7

3,712

25.7

0.7

1,628

1,000°F plus residual

N/A

8.8

10,813

7.2

2.3

7,919

H2S. Liquid products have about 25 wt% of the total sulfur and require additional hydrotreating to meet clean fuels specifications, as shown in Fig. 6.

Nitrogen balance. In hydrocracking, the nitrogen mostly concentrates in the residual bottoms product. Nitrogen is concentrated in the asphaltenes and are difficult to remove via hydrotreating. Nitrogen removal achieved in the form of ammonia (NH3).

In coking, the nitrogen mostly reports to the coke because nitrogen is concentrated in the asphaltenes. Relatively small amounts of NH3 remain, because there is no hydrotreating or free hydrogen reactions. Nitrogen content is higher in the liquid products (approximately twice the hydrocracker), as shown in Fig. 7.

HDS, wt%

60–85

Carbon and hydrogen balance. Hydrocracking is a hydro-

HDCCR, wt%

40–70

HDM, wt%

65–88

gen-addition process, but the carbon is still rejected to the heavy residual stream. Carbon rejection (1,000°F plus stream) is a function of conversion and catalyst life. The delayed coker is a carbon rejection process with a high concentration of carbon leaving with the coke. As shown in Figs. 8 and 9, the liquid products are carbon rich and are generally aromatic. The hydrocracker injects hydrogen into the balance and both saturates the residual bottoms and removes sulfur and nitrogen from the liquid products (Fig. 10).

comparison shows that the yield distribution is nearly identical for the two processes. The major difference is the hydrogen addition to the lighter fractions instead of hydrogen removal.

Sulfur balance. In the hydrocracker, most sulfur is hydrogen sulfide (H2S) due to the catalytic activity of the process. Products do not meet the clean fuels specifications for sulfur but the liquid products (C5 to 1,000°F) have about 5 wt% of the total sulfur. The remaining sulfur content is in the gas phase as H2S. Additional hydrotreating is needed to meet clean fuels specifications. In the delayed coker, sulfur mostly reports to the coke and 42

I SEPTEMBER 2011 HydrocarbonProcessing.com

Liquid product quality. The hydrocracker yields are much less aromatic and have been hydrotreated. As summarized in Table 4, coker products have lower sulfur and nitrogen levels with the coke receiving a greater portion of the contaminates—despite the lack of hydrogen and active removal of sulfur and nitrogen.

Select 72 at www.HydrocarbonProcessing.com/RS

SPECIALREPORT

REFINING DEVELOPMENTS

Configurations. Conversion in delayed coking and

hydrocracking are both via thermal-cracking kinetics. Most heavyoil streams must undergo multiple refining steps to produce finished products. The economics favor a multi-step process and capitalize on the strengths of both processes. Other issues that can play in the analysis and economics are: • Conversion in the hydrotreater • Hydrogen availability • Coke disposal—market value • Product margins (diesel vs. gasoline market).

Options. The conversion in hydrocracking and coking are both

thermal kinetically driven. The yield difference is primarily in the production of liquid fuel oil (hydrocracking) or coke (delayed coking). The future opportunity for hydrocracking catalyst development may allow a yield shift due to the catalyst cracking activity. At this time, in residual hydrocracking, the yield shift has not been observed. HP LITERATURE CITED Romero, S. and S. Sayles, “Comparison of thermal cracking and hydrocracking yield distributions,” Bitumen Upgrading and Refining Conference 2009, 5th NCUT, Sept. 14–16, 2009.

2 Jan Verstraete, “Reactivity of Athabasca residue and of its SARA fractions during residue hydroconversion,” Bitumen Upgrading and Refining Conference 2009, 5th NCUT, Sept. 14–16, 2009.

3 Benharn, “Canmet residuum hydrocracking advances through the control of polar aromatics,” 1996 NPRA annual Meeting.

4 Sayles, et al., “Catalyst Addition in Ebullated Bed units,” PTQ Q2, 2005.

5 Edwards, et al,” Maximizing high quality distillates form LC-Finning residue hydrocracking,” 5th International Bottoms of the Barrel Technology Conference and Exhibition, Oct. 11–12, 2007.

1

6

Sayles, S., “The Ebullation Factor,” Hydrocarbon Engineering, March 2006.

Plain, “Bottom of the barrel conversion strategy: Two options,” Asia BBTC 2008 Conference, May 13–14, 2008.

8 Gillis, “UOP’s Slurry hydrocracking process,” Asia BBTC 2008 Conference, May 13–14, 2008.

9 Gillis, “Breaking through the bitumen upgrading barriers with the UOP,” UniflexTM Process UOP LLC, Bitumen Upgrading and Refining Conference 2009, 5th NCUT, Sept. 14–16, 2009.

10 Stratiev, D., et al., “Residue upgrading: Challenges and perspectives New hydrocracking technology efficiently ‘cracks’ heavy end cuts for distillates,” Hydrocarbon Processing, September 2009, pp. 93–96.

11 Butler, et al., ”Maximize liquid yield from extra heavy oil Next-generation hydrocracking processes increase conversion of residues,” Hydrocarbon Processing, September 2009, pp. 51–55.

12 Reynolds, “Chevron’s on-stream catalyst replacement (OCR) provides enhanced flexibility to residue hydrotreaters,” NPRA Annual Meeting, March 1992, AM-92-61.

13 Ouwerkerk, et al., “Shell’s residue HDM/HCON Process,” Canadia Society Chemical Engineer, Vancouver, Oct. 3–6, 1982.

14 Van Zull Langhout, et al.,” Development of and experience with the Shell residue hydroprocess,” 88th AIChE National Meeting, June 1980.

7

Scott Sayles is a principal consultant with KBC Advanced Technologies, Inc., Houston, Texas. He has over 30 years of refinery and petrochemical experience, ranging from refinery plant manager to research engineer. Mr. Sayles has 15 patents and holds a BS degree in chemical engineering from Michigan Technological University and an MS degree in chemical engineering from Lamar University.

Sim Romero is a principal consultant with KBC Advanced Technologies. He has 30 years experience in delayed coking and heavy oils. His expertise includes simulating delayed coker operations, test-run execution and analysis, delayed coker yields and furnace model development, unit optimization and reliability management, unit troubleshooting, unit start-up and general delayed coker operations. Additionally, he is proficient in other heavy oil operations—vacuum units, visbreakers, ROSE and solvent deasphalting units.

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REFINING DEVELOPMENTS

SPECIALREPORT

New era in refining— Keys to sustenance Changing feedstocks and environmental rules alter past and future process investments and profitability A. SUBRAMANIAN and S. KRISHNAMURTHY, KBR, Houston, Texas

Industry under pressure. Yet, despite a remarkable historical record of sustenance, the oil industry appears to conclude that its very survival is embedded only in the ownership of monetizable reserves and finished products, thus relegating refining to a less desirable processing step within the energy supply chain. The stakeholders and the investing public clearly view these monetizable tangible underground resources as the higher value component over the above ground manufacturing assets crafted in steel. It is not surprising that refiners find themselves sandwiched as refining margins are squeezed between the pressures of higher crude oil prices and the need to maintain lower-priced transport fuels.

The industry’s response to this pressure was to consolidate the processing step while attempting to derive benefits from larger distillation capacities. As recent history has shown, while the immediate short-term benefits derived from favorable transactions involving consolidation of small- and medium-size low complexity refineries was very encouraging, the underlying deficiencies could not be overcome. These refineries were designed to process light sweet crudes with limited or no resid conversion capabilities.

Finding profit. A conscientious study of the 650 operating

refineries in the world revealed that margins are sustained not by capacity or complexity, but by an effective combination of these

two factors. As refiners evaluate their assets and invest to derive the ability to process distressed low-value opportunity crudes, and take on the burden of producing higher quality transport fuels, the tendency to gravitate toward traditional low-risk, low-benefit solutions remains remarkable. In that context, one can argue that the basic principles that govern refinery margins are often not fully examined.

At a simplistic level, refining is the process of changing the carbon-to-hydrogen ratio of naturally occurring crude oils. On any given day, every refinery attempts to accomplish this change, processing high carbon-to-hydrogen ratio crude oils to produce high hydrogen-to-carbon ratio transport fuels. The crudes and products are routinely characterized by distillation, specific gravity and other refinery inspection properties. Lost in this entire mix is the realization that these streams are composed of molecules, and the refinery property is nothing but a compositional manifestation of a blend of these molecular structures. The required intensity Average growth/yr. 2005-2030 350 Overall 1.3% 300 1.5% 2.0%

250 Primary energy, MBDOE

W

ith the continuing change in global economics, geopolitical realities and environmental regulations, coupled with the relentless emphasis and pressure on short-term financial performance, the refining industry now finds itself at a crossroads that will eventually determine its very future. The genesis of crude oil and refining dates back to a Mesopotamian writ from almost 2,000 years ago—“strange wells near the caravan road do not contain water but liquid earth. A man there boils the earth until it becomes water, which makes torches burn brighter.” Since pre-historic times, crude oil and crude oil refining have been arguably the single largest contributors to the development of mankind and they still remain the beacon of hope for the future. While the emerging alternate energy sources have recently found great favor, statistical evidence suggests that these alternatives will only have a small impact on the growing energy demand. Most projections suggest that fossil fuels will still dominate the energy supply-demand chain in the future (Fig. 1). With demand growth now stimulated by a large population segment aspiring for a better quality of life, it is somewhat ironic that this industry faces a difficult financial climate.

Renewables 0.9%

200 Nuclear 150

1.7% 100

Coal Gas

1.2%

50 Oil 0 1980 FIG. 1

2005

2030

Primary energy resources: 1980 to 2030.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 47

SPECIALREPORT

REFINING DEVELOPMENTS

of the process and energy needed to accomplish this change is governed by the underlying treatment and transformation of the structure of naturally occurring crude oil molecules. When not properly managed, the desire to exploit these “opportunity crude” molecules to produce high-value product molecules will require capital-intensive assets that subject the molecule to a torturous transformation path at high operating costs. While the gate-to-gate targets can be achieved, they can only be done so at low margins.

Better management of molecules. The benefits of complexity and capacity can only be fully exploited by applying principles promoting effective molecule management. Molecule management is the process of understanding and deriving the best value of every molecule in naturally occurring crude oils in every processing step as the crude oil makes its transition from storage tanks to the finished products. In some instances, this requires recognizing that the best value for these molecules may not always be in traditional diesel or gasoline products but may be derived from ancillary industries—including petrochemical, fine chemicals, detergent, lubricants, cement, steel or other industries. This can be argued to be the true definition of complexity, and, going forward, the best approach for sustained high refinery margins.

Investment dilemma. Historically, the risk-averse refining industry is slow to increase complexity and has, under intense pressure, only responded incrementally to the changing crude and product specifications, thus avoiding significant capital invest-

Light/heavy differential, $/bbl

45 40

USGC Singapore

35 30 25 20 15 10 5 0 1985

Light products minus fuel oil, constant 2011 dollars per barrel 1990

1995

2000

2005

2010

2015

2020

2025

Source: Purvin & Gertz

FIG. 2

World light/heavy differentials of US Gulf Coast and Singapore—1985 to 2015.

100

Crude oil, 2008 $/bbl

80 60 40

Suez crisis

OPEC 10% quota increase PDVSA strike Asian financial crisis Iraq war Asian growth weaker Iran/Iraq dollar war Series of Iranian OPEC cuts revolution Gulf 4.2 million war barrels

20 US price controls

0

Recession 9/11

47 51 55 59 63 67 71 75 79 83 87 91 95 99 03 07 Source: WTRG

FIG. 3

48

Crude oil prices influenced by man-made events, in 2008 US dollars.

I SEPTEMBER 2011 HydrocarbonProcessing.com

ments. While this has been a short-term survival tactic, the industry finds is under continuous stress as the changes in crude reserve composition and regulated products specifications outpace investments, often rendering them obsolete, long before their true monetary benefits are realized. In turn, this makes the investor more cautious creating a vicious cycle that has tended to demagogue this industry as a whole.

A classic example of this phenomenon is the evolution and treatment of the residuum. Starting with atmospheric distillation and well into the first half of the last century, the atmospheric residue was seen as the primary source for fuel then referred to as “furnace oil.” Triggered by World War II demands, and as pressure mounted on the economics of crude oil, primary gasoil conversion technologies such as fluid catalytic cracking (FCC) developed. While vacuum distillation enabled primary conversion, it came with the incompatible fuel oil, “vacuum residue.” Expensive cutter stocks were needed to accomplish atomization and combustion in the furnaces.

The industry’s response was to invest in incremental thermal processing technologies—from low-conversion visbreaking to thermal cracking, and eventually delayed coking. All along, the residuum remained the lowest value refined product and the continuous source of intense regulatory and economic pressure. Driven by short-term survival instincts, the refineries did just enough to reach a status quo that seemed adequate for the moment, while maintaining an acceptable black oil product outlet. All along, refiners understood that the evolving environment regulations will eventually catch up and render the last investment obsolete.

Over the turn of this century, buoyed by favorable light-heavy differentials (Fig. 2), and the desire to increase conversion capacity, the industry announced and built a substantial number of delayed cokers. The refining industry had adopted the coker as a proven and trusted investment. Apparently lost in this decisionmaking process was a clear understanding of the energy resource base and the looming advent of large volumes of shale gas that would quickly make these choices obsolete. While the delayed coker provides incremental liquid yields, it leaves behind another low quality byproduct—high-sulfur coke, which, if history is any indication, will become untenable and will be the target of intense regulatory pressure in the future. Consistent with the historical trends that have plagued other partial solutions, the coker will become a classic example of a solution focused on nibbling around the edges of a problem, while the next problem arrives before its economic benefits are consummated.

With impending stationary fuel and maritime regulations, the need for the next-generation investment to manage the residuum squarely places the refining industry again at a familiar decisionmaking point. Will the tradition of resistance and stop-gap measures continue or will the industry take this head on, analyze the influencing factors and invest to eliminate this cloud on sustenance once and for all?

Fundamentals not changed. Refining still remains the pro-

cess of changing carbon to hydrogen ratios. At a molecular level, this can only be achieved by either carbon rejection or hydrogen addition. The influencing factors will still predominantly be the type and cost of crude oil, type and cost of natural gas, investment threshold and the reliability and long-term sustainability of the proposed investment. High crude oil prices and low natural gas prices will favor hydrogen addition economics, significantly threatening the delayed coker as the de-facto solution.

Is the advent of a slew of new slurry-phase hydrogen addition technologies in the market an indication of a changing mind set? Is

REFINING DEVELOPMENTS the industry finally freeing itself from the pressure of living on the edge, and offering investors a vision of sustainable long-term returns?

When commercialized and demonstrated would that signal the demise of the coker?

Let’s walk through each of these principle factors and attempt to get a glimpse of the future.

Type and cost of crude are the predominant factors in the overall operational economics. Historical crude price spikes have generally been influenced by man-made events such as wars and embargoes, or by natural disasters, and those price increases could not be sustained (Fig. 3). The present increase in crude prices can be directly attributed to large demands from the rapid demand growth

by China and India. It is safe to assume that this desire of over 40% of the world population for a better quality of life is not reversible.

The combined capacity of all the 650 operating refineries in the world totals to about 85 million barrels per day (MMbpd) of crude, with about 83 MMbpsd derived from conventional sources and 2 MMbpsd from unconventional sources. As is evident from the decreasing crude API of the composite blend, almost all new conventional crudes coming onto the marketplace are substantially heavier than the present crude basket.

The more telling statistic when projecting long-term viability lies in the current estimates of recoverable reserves to production ratio (R/P ratios) of naturally occuring deposits. Based on published data by BP and other sources estimate, the R/P for conventional crudes at 46 years and that for unconventional bitumen deposits at over 800 years. Admittedly, simplistic analysis is somewhat skewed by the lack of data on the next frontier of conventional crude exploration and the low current production rates of bitumen (oil sands) deposits. But from an investors’ perspective, and as demonstrated by the industies gravitation toward block ownership, it is safe to assume that the exploration of the next frontier of conventional crudes or the development of bitumen deposits will eventually happen and there will be little or no resistance to technology development and investment to monetize these reserves.

While the future remains complex, one can infer that the demand side growth is likely to be sustained, and the supply-side cost of production for heavier crude deposits will be more expensive. From a refiners’ perspective, the higher cost for crude will only mean that throwing away any part of this expensive resource through carbon rejection will result in detrimental economics.

In addition, the resid volume in these new crudes will be higher (40%–60%), and its quality will be substantially lower, with higher Forecast in Constant $/Bbl

carbon residue, asphaltenes and metal-containing impurities. Any resid upgrading investment must be consistent with processing these difficult feeds if long-term sustenance is to be achieved.

Availability and cost of natural gas, as principle hydrogen source, is the second most important determining factor. The entry of shale gas into the natural gas mix and the development and commercialization of shale gas exploration technologies has dramatically influenced the size of this resource pool and cost for this commodity (Fig. 4). With the benefit of hindsight, it is clearly unfortunate that the refining industry did not factor in this potential development in the investment decision-making VGO Vacuum residue 1st stage reactor

Hot separator

2nd stage Off gases, reactor Cold separator sulfur etc.

Recycle gas compressor

Gas cleaning C4

Additive

Naphtha

Heater

H2 Makeup compressor

FIG. 5

Middle distillate

Vacuum flash

Vacuum gasoil

Residue

Fractionator

Flow diagram of a refinery slurry-phase hydrocracking unit.

Forecast in Constant $/MMBtu

120

12 WTI, Cushing Henry Hub

100 Natural gas prices

SPECIALREPORT

10

80

8

60

6

40

4

20

2

0 1990

1995

2000

2005

2010

0 2015

Source: Purvin & Gertz

FIG. 4

Natural gas prices—1990 to 2015.

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49

SPECIALREPORT

REFINING DEVELOPMENTS

process—thus, the spate of carbon rejection installations over the past decade. The energy cost of crude at present crude prices is likely to settle at around $16/MMBtu and that of natural gas at about $6/MMBtu—when factored in as 2011 dollars. This makes natural gas addition to crude an economically attractive technology option. It is also safe to assume that the sheer value of the shale gas resource to block owners will be a sufficient incentive to invest and develop solutions to any environmental challenges that may be brought on the production facilities.

Deployment and demonstration of the slurry phase hydrocracking technology is the third major influencing factor.

While the concept of slurry-phase hydrocracking has been around and practiced in a limited fashion over the years, its economic relevance to today’s refinery needs has never been better. The first set of these units (Fig. 5) will be onstream within the next two years, and it is likely to dramatically change the dynamics and future of resid handling. For sustenance, the hydrogen-addition process must be immune to the type and quality of residuum irrespective of the crude source, must perform complete conversion, produce Euro V grade distillate products and must have little or no impact to the existing refinery infrastructure. Like every resid processing facility, it will have to endure and address any future regulatory impact in relation to the carbon footprint. Luckily in this case, the problem is nicely isolated to the hydrogen manufacturing unit, wherein the carbon dioxide will be concentrated at high pressure making future capture options tenable.

The economic outliers, including crude and gas prices and the elements of sustenence are compelleing once deployed, and, demonstrated successfully, the slurry-phase hydrocracker is likely

to become the new generation platform. In such a scenario, the historic carbon rejection options would become both economically and environmentally irrelevant.

So what is the future of refining? In the face of serious

regulatory and economic challenges, large refineries will have a compelling incentive to invest. Medium and small refineries will benefit from increased complexity but will lack size. A need to consolidate resid volumes and upgrade to benefit from the economy of scale may be in order.

New refiners would need to reassess their options. Compelling circumstances often breed new thinking.

If the margins are in the processing of the residuum and not in topside distillation, does it make sense to do conventional top-to-bottom development? Should we instead concentrate on stranded residue streams from medium and small refineries as the “new opportunity crude source” and install resid upgraders as the primary building block and in time integrate upwards to the light side? Is it time to do just the opposite to traditional thinking? This industry has endured years of economic and regulatory pressures to still remain relevant.

Under the current resource climate and with new thinking aimed at sustenance, a new era in refining may be in the offing. HP Anand Subramanian is vice president for New Technologies at KBR in Houston, Texas. He has 25 years of industry experience, and 21 years of experience at KBR in various process and technology management positions.

Sujatha Krishnamurthy is a process engineer for New Technologies at KBR India, focused on resid upgrading and VCC technology. She holds a bachelor’s degree in chemical engineering from Anna University in India.

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50

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REFINING DEVELOPMENTS

SPECIALREPORT

Refining outlook: Capacity expansion and rationalization Many factors are reshaping the global refined product industry; change is inevitable P. RUWE, Muse, Stancil & Co., Singapore

G

lobal refinery construction continues at a healthy rate, driven by growth in the global demand for refined products. Not all regions, however, share the same demand fundamentals. Therefore, as some regions continue to add capacity, in other regions, we continue to see refinery capacity rationalization and restructuring. This of course can be explained by the maturing of the western economies and the continued rapid growth of emerging economies. A deeper look into the fundamental drivers of this capacity expansion and rationalization reveals additional emerging trends that will shape the future of the global refining industry.

China, the Middle East, India and Latin America are the leaders.

But there is also stagnant to declining demand in mature economies—Japan, Europe and the US. Changing trade patterns. The crude oil and refined product markets are very efficient, and lower cost supplies easily find their way into higher priced markets. The Atlantic Basin and Southeast Asia are typically the market balance points for supply and demand. Frequently, political factors and not economics will influence supply and demand and, therefore, trade patterns.

Environmental regulation. The increasing need for cleaner and lighter fuels heavily influences the need for downstream

Key drivers of expansion and rationalization. The financial performance of individual refineries and the viability of new refinery construction are influenced by a complex mixture of economics, political policy and local factors. The global trends in the industry are determined by three primary drivers: Demand growth. Growth in product demand drives the need for refinery capacity, and the world has plenty of growth today:

90 85 80 75 70 65 60 World refining capacity World crude production

55 50 1981

1986

1991

1996

2001

2006

Source: U.S. Energy Information Administration

FIG. 1

14 12 10 8 6 4 2 0 -2 -4

Global crude oil production vs. refining capacity—1981 to present.

USGC NW Europe SE Asia

Margins, $/bbl

pace with growth in crude oil production. As shown in Fig. 1, the large excess of refinery capacity accumulated during the 1980s had been rationalized through refinery shutdowns and consolidation of refining companies by the mid-1990s. Global refining capacity has been growing since 1995, with operating rates averaging 83%.1 Refinery operating rates have not been uniform between those located in developed countries compared to emerging economy countries. Operating rates have improved from a rather anemic 76% in 2000 to 80% in 2010 in non Organization for Economic Cooperation and Development (non-OECD) countries; and have decreased from 89% to 83% over the same period in OECD countries. This is primarily the result of strong growth in product demand in the non-OECD countries and stagnant demand growth in OECD countries.

Refining margins are improving, but only for high conversion refineries. Fig. 2 shows the regional cash contribution index for key refining regions. The rate of margin growth is greatest for US Gulf Coast refineries due to a greater concentration of coking capacity. NW European refineries are predominately cracking refineries and are also seeing improving margins. SE Asia margins have not seen any improvement due to the predominance of lower conversion hydroskimming refineries.

Production and refining capacity, MMbpd

A little history. Construction of refinery capacity has kept

1995

1997

1999

2001

2003

2005

2007

2009

Source: Muse, Stancil & Co.

FIG. 2

Cash contribution margins by regions—1995 to present.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 53

SPECIALREPORT

REFINING DEVELOPMENTS

95

Utilization, %

90 85 80 OECD Non-OECD

75 70

2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 Source: BP Statistical Review of World Energy 2011

FIG. 3

Global refinery utilization rates-OECD nations vs.non-OECD nations.

World refinery capacity additions

toward mid-decade if there are not delays in projects scheduled to come onstream in the 2014–2015 timeframe,which, based on the history of refinery project development, is quite likely.

Most of the new refining capacity is in non-OECD countries driven by strong demand growth. The largest growth countries— China, India, Brazil and the Middle East—are pursuing a policy of building refining capacity to meet or exceed domestic demand thereby eliminating finished product imports. The largest volume of growth is in China; this nation has been adding capacity equivalent to one or two world-scale refineries each year. At this pace, China may have significant excess refining capacity by mid-decade that will result in lower refinery operating rates unless Chinese refiners choose to export excess product. India has already built excess capacity and is aggressively pursuing the export markets. Middle East countries with some of the highest product demand growth rates are building excess capacity targeted for the export markets.

Capacity additions, Mb/d

4,000 3,000 2,000

North America Europe China Other Asia

Middle East Africa FSU Latin America

1,000 0

-1,000 2010

2011

2012

2013

2014

2015

Source: Muse, Stancil & Co. Forecast

FIG. 4

Refinery capacity additions by region-2010 to 2015.

processing equipment. Air-quality regulations are lowering sulfur specifications. Fuel-efficiency standards are shifting the balance between gasoline and diesel—and the greenhouse gas (GHG) issue has the potential to further restructure the industry.

Demand growth and demand destruction. Fig. 3 shows how refinery utilization rates have been changing in developed vs. emerging countries. The trend helps to explain how and where we can expect to see refinery capacity expansion and rationalization.

Demand destruction, partially driven by higher crude and product prices, has been occurring in OECD countries. Stagnant demand growth and the inability to compete with more efficient or better located refineries have led to the closure or capacity reduction of 1 million bpd (1MMbpd) of capacity in Europe, the US and Japan in the last two years and another 700,000 bpd announced for the next two years. The number of sales of refineries has increased in Europe and the US as major refiners restructure their downstream businesses. Over 1.5 MMbpd of capacity are on the market today. Some of the recent sales have been to strategic buyers who will continue to operate refineries that might otherwise be closed. This has led to less rationalization of capacity than some forecasters have expected. The continued operation of these refineries may contribute to the declining trend in utilization in these regions.

Fig. 4 shows the forecast of probable refinery capacity additions over the next five years. Current probable capacity additions total 9 MMbpd of crude distillation capacity by 2015. Compared to the IEA’s current forecast of 5 MMbpd of increased product demand, we conclude that there will be adequate refining capacity to meet demand.2 Global operating rates may trend downward 54

I SEPTEMBER 2011 HydrocarbonProcessing.com

Changing global oil trade patterns. European consolidation and restructuring have been driven by declining domestic crude production and an inability to compete in product markets. Crude oil imports have trended downward with refinery rationalization. European refiners have long looked to move excess gasoline to the US East Coast. But, as the US is becoming more self sufficient in gasoline supply, the gasoline trade flow is slowing that has partially forced European capacity rationalization. With lower European refining capacity and growing imbalance between gasoline and diesel demand in Europe, the US has been able to move increasing quantities of distillate to Europe.

North America has seen both rationalization and expansion driven by lower-cost Canadian heavy crude and a strengthening export market. Increased Canadian oil sands production has already resulted in the conversion of several mid-continent refineries to process this heavy crude. As oil sands production increases further and finds its way to the US Gulf Coast, it will displace the declining volumes of heavy crude from Mexico and will force Venezuela to seek new markets for its heavy crude. US refiners have enjoyed comparatively good operating rates due to their ability to export product to Europe and Latin America. They risk lower operating rates in the future, as refinery capacity will modestly increase over the next couple of years. Operating rates will also be impacted if export growth cannot be sustained, particularly to South America, which is expanding refining capacity to meet local demand.

Asia-Pacific countries, notably China and India, are motivated by a desire to be crude importers rather than product importers. An over build of capacity may encourage them to expand product exports. This product can fill a deficit in product supply in the rest of Asia-Pacific, but they may also look to the Atlantic Basin markets.

Middle East producers are looking to move down the value chain by refining more of their own crude production, and are planning to become major product exporters. With the decline in refining capacity in the west, Middle Eastern crude producers are also increasingly moving more crude oil to the east to feed the increased refinery capacity in Asia. Fig. 5 summarizes what may become a major pivot point in product trade flows. Excess product in the Middle East may find an already crowded Pacific basin, and, if they cannot find adequate markets in the east, they may move into the increasingly oversupplied Atlantic Basin. Without additional capacity rationalization or capacity expansion deferrals, they may very well become the swing producer of refined products just as have done so in the crude markets.

REFINING DEVELOPMENTS Environmental regulation. At present, environmental

regulation has been one of the significant drivers of refinery processing configuration and consolidation of capacity. The greatest negative impact of environmental regulations will be in OECD countries. Higher efficiency standards for transportation vehicles are limiting transportation fuel demand growth and, in some countries, are contributing to demand destruction. Higher efficiency cars are also changing the comparative growth in diesel vs. gasoline demand, particularly in Europe. The lack of demand growth in developed economies will continue the trend to rationalize and consolidate marginal refinery capacity. Developed countries are also including the refining industry in efforts to reduce GHG emissions that may lead to large capital expenditures to reduce refinery carbon emissions. Since these investments typically result in low or no investment return, refinery owners that face large expenditures for environmental regulation compliance may elect to reduce capacity or close a refinery. The ocean shipping industry is also in the early stages of implementing international regulations that will significantly limit sulfur emissions TABLE 1. Global refinery upgrading capacity as percentage of crude distillation capacity Capacity, Thousand bpcd

Installed 2010

Additions 2011â&#x20AC;&#x201C;2015

Forecast 2016

Crude distillation

93,100

8,175

101,275

Upgrading

32,543

6,339

38,882

35

78

38

%

SPECIALREPORT

from ocean going ships. Since ocean going ships account for an increasing amount of heavy fuel-oil sales, these regulations may cause a significant reduction in demand for high-sulfur heavy fuel oil if ship owners do not opt for a shipboard stack scrubber compliance scheme.

Non-OECD countries face increasing fuel quality standards, primarily lower sulfur levels in all refined products. The demand for new hydrotreating capacity should remain strong as developing nations increase fuel quality to help improve air quality that has become a significant problem in most developing country cities.

The declining use of heavy fuel oil use in power generation and Crude Reduced crude runs t 3FEVDFE .JEEMF &BTU BOE North Africa imports %FDMJOJOH /PSUI 4FB QSPEVDUJPO t 3FQMBDFE CZ 8FTU "GSJDB BOE '46 JNQPSUT

Products Reduced crude runs t -PXFS FYQPSUT UP /PSUI America t *ODSFBTFE JNQPSUT GSPN 64 '46 .CQE

64 .CQE

"TJB 1BDJmD .CQE

0UIFS .CQE

Canada (-230 Mbpd) 64 .CQE

.JEEMF &BTU .CQE

North Africa (-280 Mbpd) (SFFO JOEJDBUFT UIF BNPVOU PG JODSFBTFE WPMVNFT 3FE UIF BNPVOU PG EFDSFBTFE WPMVNFT

West Africa (225 Mbpd)

Source: BP Statistical Review

FIG. 5

Trade movements (2010 vs. 2005) of refined product.

Source: IEA and Muse, Stancil & Co.

WEBCAST

Available to view at www.HydrocarbonProcessing.com

HEINZ BLOCH:

SUCCESSFUL MACHINERY SELECTION, PROCUREMENT AND RELIABILITY ASSESSMENT

Listen as Heinz Bloch, HP equipment/reliability editor is interviewed by Hydrocarbon Processing editor, Stephany Romanow. Heinz presents proven techniques for the successful selection, procurement and reliability assessment of plant machinery.

To ensure safe and reliable operations, rotating machinery must be purchased from competent bidders; there must be a suitable speciďŹ cation. The meaning or interpretation of such speciďŹ cations must be the same for ALL parties. Heinz will help you establish how to determine a vendorâ&#x20AC;&#x2122;s capability. Before signing on the dotted line, the vendor and purchaser will have to agree on a formal design audit (and future follow-up reviews). Audits must take place â&#x20AC;&#x153;before metal is cut;â&#x20AC;? reviews commence once metal is being cut. The latter are being performed as the detailed design evolves and end after ďŹ eld installation and testing. After the design enters the manufacturing phase, ongoing reviews ascertain that the details embedded in the design speciďŹ cation are being carried out. Heinz will guide listeners through these processes.

During the 60-minute webcast, Heinz covers total lifecycle costs when purchasing major equipment, not just initial capital cost.

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HYDROCARBON PROCESSING SEPTEMBER 2011

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REFINING DEVELOPMENTS

SPECIALREPORT

manufacturing industries has led to stagnant growth in the heavy fuel oil markets. As a result, most of the new refining capacity being added is high complexity and high conversion with little or no heavy fuel oil production. Table 1 shows the International Energy Agency’s forecast of refinery upgrading additions (defined as gross capacity additions of coking, hydrocracking, visbreaking, FCC or RFCC capacity) as a percentage of crude distillation capacity. New upgrading capacity is forecast to be 78% of crude distillation capacity, which will add significantly to the global refining fleet’s ability to upgrade the bottom of the barrel. These numbers indicate that much of the new capacity is deep-conversion capacity designed to process heavier higher-sulfur crude oils. It also indicates that existing refineries are adding capacity to upgrade the bottom of the barrel. Since the total quality of worldwide crude oil production has remained fairly constant, some of the new conversion capacity may not be fully utilized if there are not adequate quantities of heavy crude oil to fill downstream processing units.

The upside of increasing complexity of the Asia-Pacific refining fleet will be an improvement in cash contribution margins for Asian refiners as the overall yield of fuel oil production decreases.

There will be continued rationalization of refineries that do not have a competitive position or that face a new round of heavy environmental compliance cost. This rationalization is likely to impact OECD countries disproportionately, although smaller, less complex refineries worldwide may be affected if some of the new, large export refineries decide to market aggressively. Although there may be a few refinery closures, rationalization may take the form of refiners focusing on increasing efficiency and lowering costs to address inevitable reduced utilization rates. Trade patterns will continue their shift from west to east as crude oil moves east to fill new refinery capacity. Excess products will also move east to satisfy growing Asian demand. HP

The outlook. Overall, the outlook is for continued robust con-

Paul Ruwe is a principal at Muse, Stancil & Co., and is managing director of Muse,

struction of new refinery capacity over the next five years. There will be adequate capacity to meet the demand increase for refined product s, and the challenge may be to maintain today’s operating rates if part of the new construction planned for the 2014–2015 timeframe is not delayed. The imbalance suggests that some of these projects will be rescheduled unless there is stronger than forecast demand growth over the next two years.

OF

ACKNOWLEDGMENT Revised and updated from an earlier presentation at the International Refining and Petroleum Conference-Asia, 19–22 July 20011 at Singapore.

1 2

LITERATURE CITED BP p.l.c., “BP Statistical Review of World Energy 2011.”

International Energy Agency, “Medium-Term Oil & Gas Markets 2011.”

Stancil (Asia) Pte., an international consulting firm specializing in the downstream energy industry. He leads the commercial development practice for the firm, and manages its Singapore office. Mr. Ruwe has held a number of senior level positions in operating companies, including Atlantic Richfield, Lyondell Petrochemical, Destec Energy and Reliant Energy. Throughout his career, he has led major projects assisting clients to develop downstream energy projects and providing technical and economic advice in energy transactions. Projects include project feasibility studies, troubled project and bankruptcy workout, contract negotiation support, transaction due diligence, supply/demand/price forecasting and asset valuations.

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t -PXFS $BQFY UIBO %FMBZFE $PLJOH BOE $PLF (BTJýDBUJPO 0QUJPOT

t "CVOEBOU $MFBO 'VFM (BT 1SPEVDU GPS 3FýOFSZ 6TF PS $PHFO 1SPKFDUT

t 6OJRVF 'JU GPS 0JM 4BOET 6QHSBEJOH

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REFINING DEVELOPMENTS

SPECIALREPORT

Achieve success in gasoline hydrotreating Case history describes achieving top performance in FCC gasoline hydrotreater K. SANGHAVI, Alon USA, Big Spring, Texas; and J. SCHMIDT, Axens North America, Inc., Houston, Texas

S

uperior FCC gasoline hydrotreating performance is achievable by selecting the optimal process scheme to minimize octane loss. Enlisting help from a refinery process consultant (PC) and technology licensor and collaborating early in the design stage, further ensures the success in determining the better design for the facility. Consequently, maintaining cost-effective solutions for a staged project investment and operating the world’s shortest FCC main fractionator subjected Alon Big Spring Refinery (BSR) with difficult project challenges. The roadmap used for a two-phase project and the lessons learned during Phase I (Interim Case) contributed to the successful implementation of Phase II (Ultimate Case). By knowing the key process and operational principals, the Alon’s Big Spring new hydrotreater yields world class performance with an excellent economic advantage.

Case history. In early 2002, Alon, being an owner of a single

refinery in Big Spring, Texas, was granted the status of a small refiner and was initially required to reduce sulfur (S) in refinery’s gasoline pool to less than 300 ppm between 2004–2009 (Interim Case) and thereafter the refinery had to meet EPA’s ultimate requirement of less than 30 ppm S (Ultimate Case). Typically, the refinery’s PC would initially lead all process aspects of such a major project such as determining the process design basis including, feed analysis, selecting processing scheme and/or process licensor and setting process scope. Early evaluations revealed that treating FCC gasoline would be the most optimal investment solution for the BSR. Of the five different processing schemes available at the time, the initial study narrowed down the list to three processes for further study. Then BSR acquired access to an idle 6,000 bpd (6 Mbpd) straight-run (SR) naphtha hydrotreater (NHT) complete with a recycle compressor from an adjacent idle reformer.

Consequently, the refinery management asked the PC these questions loaded with monumental challenges: a) Can we relocate and revamp the acquired idle equipment sized for only 6 Mbpd of SR naphtha to a 13.8 Mbpd unit treating FCC gasoline rich with 36 vol% olefins? b) Can we decrease FCC gasoline sulfur from 3,000 ppm to 30 ppm with enviably limited octane loss? c) Can we do all this with an intermediate operation (Interim Case) with undercut FCC gasoline with 1,650 ppm S–1,700 ppm S and achieve 90% sulfur reduction, to differ capital expenditure and thus utilize the advantage of being a small refiner?

The PC believed that it can all be done by working with a lot of due diligence and fiduciary responsibility and selecting a gamechanger FCC gasoline hydrotreating process as well as selective hydrodesulfurization catalyst. This task was even more difficult at BSR as: • The refinery has the world’s shortest FCC main fractionator, at only 61 ft in height with 15 trays and two packed-bed sections.

Thus, the FCC gasoline can have some heavy and tough-to-treat sulfur compounds from the light cycle oil (LCO).

• The semi-regen reformer is the refinery’s sole source for hydrogen, where hydrogen purity varies from 88.6% at start of run to 74% at the end of the run. When reformer is down, hydrogen purity from purchased liquid hydrogen is 99.9%.

FCC hydrodesulfurization principles. The key to treating FCC gasoline is in the ability to achieve the required sulfur reduction while maintaining octane levels. Octane loss results from hydrosaturation of olefins in the feed during hydrodesulfurization (HDS) of thiophenes and benzothiophenes in FCC gasoline in several steps. Both reactions occur in parallel and are shown here:

Olefin + Hydrogen r Paraffin Example: 4-Methyl -2-pentene +H2 r 2-Methyl-pentane Thiophene + Hydrogen r Butane + H2S Fig. 1 shows the olefins and sulfur distribution in BSR’s FCC gasoline, with the highest amount of olefins and lowest sulfur occurring in the front end. Table 1 lists the octane numbers for TABLE 1. Octane number of olefins and saturated paraffins RON

MON

1-Pentene

Octane numbers C5 olefin

91

77

2-Methyl-2-butene

C5 olefin

97

85

n-Pentane

C5 paraffin

62

62

3-Methyl-2-pentene

C6 olefin

97

81

4-Methyl-2-pentene

C6 olefin

99

84

n-Hexane

C6 paraffin

25

26

2,2,4-Trimethyl-1-pentene

C8 olefin

> 100

86

2,2,4-Trimethyl-2 pentene

C8 olefin

n-octane

C8 paraffin

> 100

86

Minus 19

Minus 15

HYDROCARBON PROCESSING SEPTEMBER 2011

I 59

SPECIALREPORT

REFINING DEVELOPMENTS

FIG. 1

Olefins, vol %

Cumulative sulfur

Selective hydrogenation principles. In the selected 80 60 Sulfur 70 55 Olefins 60 50 45 50 40 40 35 30 30 25 20 20 10 15 0 10 100 125 150 175 200 225 250 275 300 325 350 Cut end point, °F

Cumulative sulfur and olefins distribution vs. cut-end point.

LCN to pool, TAME or alky unit New hydrotreating unit 1st step

Challenges of the Interim Case. With the idle 6,000 bpd-

Splitter SHU Prime-G+ selective HDS

ULSG

FRCN H2 makeup FIG. 2

Design flow scheme for the Interim and Ultimate FCC gasoline hydrotreating process.

olefins vs. resulting saturated paraffins. Fractionation upstream of the HDS section is an attractive first step to concentrate the olefin-rich light-cat gasoline (LCG) as a product and the sulfurrich heavy-cat gasoline (HCG) for hydrodesulfurization (HDS).

BSR focused on several essential characteristics and challenges in selecting a successful process including: • Minimize octane loss. Gasoline is hydrodesulfurized selectively and collateral damage that can occur through olefin saturation is minimized; accordingly, the scheme achieves the total lower octane loss.

• Minimize hydrogen consumption per barrel of feed was another important consideration for BSR. Olefin and aromatic preservation is essential; otherwise, a large amount of hydrogen would be used in saturating these compounds as compared to desulfurizing them.

• Retain excellent gasoline yield with no Rvp increases.

This is vital for maximizing product. This is attainable with mild operating conditions that avoid cracking reactions, • Maintain catalyst cycle length inline with the FCC turnaround schedule to avoid untimely blending issues due to offspec FCC gasoline.

• Conserve total capital investment to cover both the Interim and Ultimate Case operations.

Detailed evaluation showed that for BSR, the selected gasoline hydrotreating processing scheme could meet all of the essential characteristics for both the Interim and Ultimate requirements.

Fig. 2 outlines the basic process flow diagram.

60

scheme, for the Ultimate Case, the feed would be pretreated in a selective hydrogenation unit (SHU) to convert lighter mercaptans and light sulfides to heavier sulfur species and also to saturate unstable dienes with no octane loss and minimal hydrogen consumption. Dienes, unless removed through saturation, would thermally decompose and agglomerate into a coke crust; thereby accelerating pressure drop buildup in the downstream HDS reactor. This would then shorten the unit’s run length.

Pretreated feed would then be fractionated in a splitter to remove about 29 vol% to 33 vol% of the feed as onspec LCG with less than 30 ppm sulfur and rich in high-octane olefins.

In most cases, the balance of the feed stream, HCG, would be hydrodesulfurized to reduce sulfur to below 30 ppm. LCG can be blended back with HCG. Otherwise, if a separate storage sphere is available, then the LCG can be segregated for blending flexibility.

BSR chose the former option for LCG. Selectivity of the HDS catalyst to minimize octane saturation while treating heavier sulfur compounds in HCG would determine the total octane loss.

I SEPTEMBER 2011 HydrocarbonProcessing.com

SR naphtha hydrotreater available as part of the FCC gasoline hydrotreater revamp, the first of many project challenges were presented. In combination with a minimal investment requirement for the Interim Case, the challenges increased significantly. A joint effort between BSR and licensor to develop a scheme was initiated to not only minimize investment but to meet the required HDS level with acceptable octane loss for both the Interim and Ultimate Cases.

Roadmaps. BSR developed roadmaps for both Interim and Ultimate Cases so that the least amount of equipment would be wasteful during the transfer from the Interim to Ultimate processing schemes. The licensor and BSR worked closely to arrive at the final Interim and Ultimate cases that encompassed the project challenges and requirements. For the Interim Case, a simpler initial flow scheme was developed to meet the immediate processing requirements, while simultaneously considering future requirements for the Ultimate Case. Despite the challenges presented, the design basis for each case was studied, and the technology licensor provided BSR with the final process design package. Both cases are shown in Fig. 3.

Lessons learned contributed to success. The Interim Operation during January 2004 to September 2009 was with full-range gasoline feed to the HDS reactor without pretreatment by the SHU. This operating mode provided an opportunity to study features needed for optimal Ultimate Operation. Fig. 4 shows that the pressure drop buildup in the HDS reactor during Interim Operation determined the unit’s run length. The high pressure drop would require frequent outages to skim the top-bed catalyst or a complete catalyst changeout. This was attributed to the absence of SHU pretreating and the protection it offers to the HDS reactor. The importance of installing an SHU reactor in the Ultimate Case was further strengthened. With a 30-wppm S gasoline pool requirement for the Ultimate Case, frequent unit downtime would jeopardize refinery economics/blending.

Analysis of crusts from the reactor revealed high coke buildup from thermal decomposition and agglomeration of unstable dienes in the feed, as shown in Fig. 5. Also, the catalyst deactivation rate was high during the Interim Operation. Analyses done on the spent catalysts revealed significant arsenic contamination which was linked to the feed. The lessons learned confirmed

REFINING DEVELOPMENTS

SPECIALREPORT

New thinking for the ultimate operation. The ultra-

low-sulfur gasoline (ULSG) requirement of 30-ppm sulfur in the gasoline pool was required by BSR starting after 2009. To meet the regulation, the Interim operation was now set to be revamped to the Ultimate operation. Not only was it necessary for the product sulfur to meet requirements but also 1) excellent octane retention to meet refinery economics and 2) a continuous catalyst cycle to meet the four-year FCC turnaround schedule. Also during the Interim operation, the BSR crude capacity increased thus raising the FCC gasoline rate. This required a new study to assess the impact from a higher feedrate to the HDS section, from the original Ultimate Case value of 8 Mbpd to 10.8 Mbpd.

A common industry practice is to design the unit’s reactor and heat transfer equipment including the heater(s) based on a) both reactors being at the start of the run (SOR) and/or both reactors being at the end of the run (EOR), in tandem, based on a four-year run length and b) the average hydrogen purity at 80.2% for BSR. But during mid-2008 when restarting work for the Ultimate Case to increase operational flexibility and economic advantage, the refinery’s PC asked that other scenarios be considered in the design and equipment to cover: a) Staggered reactor operation, with SHU reactor being at SOR while HDS reactor continues to run its course and vice versa, which de-couples the reactors b) Unit flexibility to cover the expected 74%–88.6% hydrogen purity as the semi-regen reformer cycle progresses.

This revised basis increased sizes for the HDS reactor and the unit’s heat exchange equipment, as well as the sizes of the hydrogen heater and reactor effluent air-fin condenser, as shown in Table 3.

Reactor ΔP, psi

the need for feed filters, feed pretreatment LCN with SHU and arsenic guard as a part of the product grading system for the HDS reactor. Table 2 SHU reactor New equipment/piping-Phase 2 Ultimate highlights the design feed characteristics for Revamp equipment-Phase 2 case feed Existing equipment/piping-Phase 1 the Interim and Ultimate Cases.

F/E heat BSR full-range FCC gasoline has a lonInterim Splitter exchangers case feed ger end-point tail than normal due to its Stripper very short FCC main column. This material was being undercut for the Interim Case F/E heat Makeup H2 H2 heater exchangers operation. When compared to typical FCC Recycle naphtha feedstocks, the BSR feed proves to compressor be one of the most difficult with high sulA/B/C D fur and olefin content. The concentration HDS reactor of dienes, as measured by MAV analysis, is Reboiler Product separator exceptionally high and resulted in frequent pressure drop buildup events during the Purge Amine Interim Case.

HCN product Effluent cooler contactor Despite the difficult feedstock processed even during the Interim Case, the results Liquid quench met BSR product sulfur specification with Wash water excellent octane retention. Fig. 6 highlights FIG. 3 Final process design for BSR FCC gasoline revamp. the feed sulfur and (R+M)/2 octane loss during the Interim Case while meeting the 150 ppm S gasoline pool specification. The 80 higher than design feed sulfur during the Interim Case was the result of processing higher end-point material, a step closer to the planned future ultimate case full-range feed. During this period, 60 there were refinery hydrogen limitations. To conserve hydrogen in the diesel hydrotreater, LCO make was reduced by increasing 40 the Interim Case gasoline end point.

20 0 0

150 300 450 600 750 900 1,050 1,200 1,350 1,500 1,650 1,800 Days since 1st startup Pressure drop due to buildup in the HDS reactor due to lack of pretreating feed.

FIG. 4

TABLE 2. Design feed characteristics for Interim and Ultimate Cases Feed properties

Undercut full range, FCCN

Full range, FCCN

Sulfur, wppm

1,650–1,700

3,069–4,132

Olefins, vol%

36.0

35.0–37.0

15–22

12–21

MAV, mg/g D-86, vol%

°F

°F

10%

110–120

114

90%

310–355

95%

330–375

415–420

FBP

380–430

450–475

Also the refinery’s PC requested adding a macroporous trapping media for scales as a part of the HDS reactor grading system and using wedges and pins in place of traditional nuts and bolts for reactor internals, for easier installation and removal. Additionally, due to the arsenic measured on the catalyst during the Interim operation, a layer of arsenic trap was installed on top of the main HDS catalyst bed.

HYDROCARBON PROCESSING SEPTEMBER 2011

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REFINING DEVELOPMENTS

FIG. 5

Example of coke buildup on catalyst and the agglomeration from unstable dienes in feed.

3,500 3,000

3.5 Feed sulfur

(R+M)/2 loss

3.0 2.5

2,000

2.0

1,500

1.5

1,000

1.0

500

0.5

0

0.0 0 150 300 450 600 750 9001,0501,2001,3501,5001,6501,800 Days since 1st startup

FIG. 6

Feed sulfur and octane loss during the Interim operating case while meeting 150-ppm S in gasoline.

(R+M)/2 loss

2,500

Sulfur, wppm

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Another unit re-design included a continuous wash-water injection system due to the extra bay at the reactor effluent air-fin condensers, which were susceptible to chlorides in the makeup hydrogen. It also provided the option for a future water-wash column to minimize amine carryover.

High-quality control valves and accessories with low cost of ownership are what it takes for economic production.

Startup of ultimate operation. In 2009, the BSR started

the revamped Ultimate Case. The successful startup was contributed to several key factors: 1) The technology licensor and BSR inspectors performed a detailed conformance check of new vessels and trays. The SHU and HDS reactor internals were a focal point to ensure proper installation and levelness.

2) Safe loading of pre-sulfided, pre-activated catalyst, that does not require in-situ sulfiding or activation step, was supervised by catalysts provider/BSR verifying correct layers and loading densities.

3) Combined efforts in writing detailed start-up procedures and complete technical assistance during startup.

4) Around the clock technical support by technology licensor and BSR technical engineers.

Modified startup procedures were necessary as BSR did not have the typical feedstock (low olefinic naphtha) required for startup. A more difficult feedstock (the normal feedstock from A01051EN

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REFINING DEVELOPMENTS

SPECIALREPORT

FCC) was used. It required several startup issues to be resolved and incorporated into the final startup procedures. Additionally, BSR provided detailed training to operations, technical support and maintenance outlining the finalized procedures. Color-coded process flow diagrams for each step with associated operating parameters were used in training. The diagrams as part of the training contributed to the successful start-up.

effectively resolved with installing feed filters, SHU and macroporous media to the HDS reactor grading system, as evidenced by pressure drop charts for both SHU and HDS reactor, as shown in

Results. Post startup audit and an outside review have revealed that this unit: 1) meets the BSR gasoline pool sulfur specifications of 30 ppm S and 2) has the best performance amongst other similar functional competitor’s units, achieving very low octane losses in a single-stage unit when processing feed with high olefin and high sulfur, nominally at 2,100–2,400 ppm S, as shown in Fig. 7.

The refinery has experienced enviable octane losses as low as 0.3–0.5. The refinery PC recently developed an excellent correlation for predicting octane losses as a function of feedrate and % HDS. This helps BSR manage octane losses in the range of 0.7–0.8 at normal feedrates with 2,300 ppm S and 97.2 % HDS. Most other typical FCC gasoline hydroprocesses treat feed with less than 1,300 ppm S and while % HDS is typically less severe, at less than 96.1%, and still experience octane losses commonly in the range of 1.4–1.5 or higher. On this basis, BSR has reached top of the class in FCC gasoline hydrotreating. Higher S feeds at BSR is directly due to processing of higher sulfur West Texas sour crude, providing BSR another great economic advantage over refineries processing sweet crudes.

The issue related to high HDS reactor pressure drops has been

Makeup H2 purity, %

80.2

74.0

Recycle gas, MW

8.4

10.56

TABLE 3. Revised equipment sizes for greater flexibility

Reciprocating compressor, acfm

1,320

H2 flow, lb/hr

17,758

SHU reactor steam preheater, ft2 HDS reactor effluent air cooler, MMBtu/hr

Feed sulfur, wppm

H2 heater, MMBtu/hr

4,500 4,000 3,500 3,000 2,500 2,000 1,500 1,000 500 0

FIG. 7

88.6 3.07 1,320

22,257

6,678

260

603

22

42.3

10.7

13.34

4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0 50 100 150 200 250 300 350 400 450 500 550 600 Days since 1st startup Feed sulfur

0

Alternative cases Low – High

(R+M)/2 loss

(R+M)/2, loss

Base case average

Purity case

Feed sulfur and octane loss for Ultimate Case.

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REFINING DEVELOPMENTS

SHU DP

16

HDS DP

12 8 4 0 0

Duplex Filtration

50 100 150 200 250 300 350 400 450 500 550 600 Days since 1st startup

FIG. 8

Pressure drop across the HDS and SHU.

Automated continuous filtration with uninterrupted process flow

TABLE 4. Ultimate operation HDS reactor performance Time

Strainers & Self-Cleaning Filtration Continuous filtration for uninterrupted process flow

10/23/2009

1/31/2011

5/30/2011

Day onstream

14

460

575

HCG feed, bpd

7,964

7,890

7,925

HCG HDS, %

99.0

98.1

98.5

Normalized ⌬P, psi

4.3

6.6

6.9

Deactivation rate

< 0.5°F/month

Fig. 8 and Table 4. The HDS reactor is almost close to start of run temperature after one-half years of operation. The arsenic contamination of HDS reactor seems to be effectively resolved too.

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Successful project. BSR FCC gasoline HDS unit is in a position to provide the refinery excellent economic advantage and leverage. It has demonstrated that it will not constrain refinery operations while processing lower-cost sour crude oils that in turn results in feeds with higher sulfur. This can be classed as an extraordinary achievement, especially for the world’s shortest FCC main fractionator and restrictions imposed by repurposing an idle 6 Mbpd NHT and reformer compressor. Intelligent factors contributing to top of class performance are: (1) Superior processing scheme, based on saturation of unstable dienes in a selective hydrogenation unit and separation of the front-end FCC Gasoline as LCG before HCG is treated in reactor with selective HDS catalyst. This scheme would always assure process success in terms of superior octane retention and four-year unit run length.

(2) Early roadmaps prepared for both Interim and Ultimate Cases ensure minimal wastage of investment.

(3) Implementing lessons learned from the Interim Case into Ultimate Case design resolved issues related to high reactor pressure drops, catalyst activity, catalyst stability and catalyst arsenic contamination.

(4) Excellent capability of the refinery’s PC to guide the licensor and also for setting right design basis and process direction and infusing new thinking for a more robust unit. HP Kirit Sanghavi is senior refinery process engineering consultant at Alon’s Big Spring Refinery. He is responsible for the largest capital projects at this refinery. Previously, Mr. Sanghavi worked at Esso Chemical and Imperial Oil in Canada for 15 years and for four Engineering Companies in the US, UK and Canada during his career. He earned a bachelor’s degree in chemical engineering from London University.

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REFINING DEVELOPMENTS

SPECIALREPORT

Alternative transport fuels: An Indian perspective Many factors influence the possibility of new fuels replacing gasoline and diesel S. K. SINGAL, W. KAMEI, A. K. JAIN and M. O. GARG, Indian Institute of Petroleum, Council of Scientific and Industrial Research, Dehradun, India

R

ising crude oil prices are hindering the economic expansion for many nations.

Elevated energy prices are one of the main drivers for high inflation in developing nations such as India. No single alternative transport fuel can replace gasoline and diesel usage in the Indian economy. A basket of alternative fuels are needed to meet the ever increasing demand for transportation fuels.

This article discusses the experimental studies conducted to evaluate alternative transport fuels—methanol, ethanol, biobutanol, methyl esters and ethyl esters from non-edible oil seeds, like jatropha carcus and karanja, along with gaseous fuels (compressed natural gas and liquefied petroleum gas). This study also reviewed futuristic fuels such as dimethyl ether (DME), syngas—Fischer-Tropsch (FT) diesel—green diesel and hydrogen. Results showed that alternative fuels may have a great potential in reducing vehicular emissions along with lowering dependence on crude oil imports for India.

Background. Alternative fuels have gained importance due to global concerns from environmental and economic issues associated with conventional fuels. Alternative transport fuels such as alcohols, biobutanol, biodiesel, compressed natural gas (CNG), liquefied pettoleum gas (LPG), hydrogen, DME, FT diesel and green diesel are some of the potential options that can partially replace conventional transportation fuels. Ethanol is mainly used in Brazil and the US as transport fuel. The Indian government has already passed a policy requiring the blending of 5% ethanol in gasoline. CNG is another fuel that has substantially replaced conventional fuels in India, particularly in Delhi. The Indian government plans to extend CNG distribu-

tion network to around 200 cities in the near future.1 With this action, CNG, as auto fuel, is poised to become even more popular. Also, India has the potential for biodiesel production and utilization.

However, blending biodiesel in diesel has not been possible in India mainly due to the nonavailability of non-edible oil seeds.

Different oil seeds, identified as having possible application for biodiesel production in India, are jatropha carcus and karanja, etc.

With scientific cultivation, plants like jatropha curcas can grow in wasteland unsuitable for crop cultivation. In India, over 100 million hectares are classified as degraded land.2 This land can be used to grow such plants slated for biodiesel production. Other alternative fuel candidates such as DME, FT diesel, biobutanol, green diesel and hydrogen also have great potential in India. However, these fuels are still at the laboratory scale and are yet to be commercialized.

In this article, the experimental studies carried out over the last 25 years at the Indian Institute of Petroleum (IIP) are reported on various mix of alternative transportation fuels including methanol, ethanol, biobutanol, biodiesel, CNG, LPG and hydrogen CNG (HCNG). The scope for futuristic fuels like DME, FT diesel, green diesel and hydrogen will also be discussed.

The data related to engine and vehicle performance, as well as exhaust emissions, are investigated to understand the merits from alternative fuels as well as the constraints these fuels may pose for their adaptability in the present market.

CNG VEHICLES

India has proven reserves of natural gas amounting to 0.71 billion tons of oil equivalent as compared to 0.76 billion tons

of recoverable crude oil reserve.3 Natural gas (NG) is mostly used for fertilizer, power plants and process industry in India, but still large quantities would be allocated for the transportation sector. The technical feasibility of using CNG as transport fuel has already been established as is the case of the bus fleet in Delhi. In the late 1990s, IIP initiated work on CNG-fueled vehicles.

Initially, the research work focused on using CNG as a sole fuel in spark-ignition (SI) engines, thus fully replacing gasoline or as a supplementary fuel in compressionignition (CI) engines in dual-fuel mode partly replacing diesel. In either case, the option to switch back to gasoline or diesel operation was kept due to the lack of CNG supplies at various locations.

Demonstration trials were also carried out on the buses of the Delhi Transport Corp. for diesel-CNG dual-fuel operation.

Later on, it was felt that CNG could be a good fuel option to control emissions, particularly particulates from the diesel vehicles running in the urban areas of Delhi. However, the diesel-CNG dual-fuel mode was considered to be inappropriate, and conversion of diesel vehicles to sole CNG was identified as the better option.

The conversion kits to CNG operation were internationally available, and the next step was to retrofit Indian engines and convert the engines to spark-ignition mode. The IIP established the required R&D infrastructure for the conversion of diesel vehicles to CNG and evaluated the performance and emissions from the converted engines. In the mid-1990s, a few CNG-fueled buses were introduced in Delhi. Between mid-2001 and late 2002, Delhi’s buses switched rapidly from diesel to CNG, with diesel buses making HYDROCARBON PROCESSING SEPTEMBER 2011

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SPECIALREPORT

REFINING DEVELOPMENTS

almost a complete exit by late 2002 due to Supreme Court intervention.4 Similarly, gasoline driven three-wheelers were switched over to CNG between 1998 and 2002. As far as the taxis are concerned, despite the increasing numbers of CNGfueled taxis, Delhi still has a significant number of diesel-fueled taxis in operation, as taxis with permits can travel outside Delhi. The so-called all-India-permit taxis have been exempted by the court from mandatory conversion to CNG. Gasoline to CNG converted vehicles. The pre-2000 model gasoline cars,

having a carbureted engine, were converted to use CNG. The cars showed a comparable-to-somewhat better fuel economy on CNG due to the leaning effect. A substantial reduction in carbon monoxide (CO), comparable hydrocarbon (HC) and NOx emissions were observed. However, the CNG cars showed an approximate 15% power loss compared to gasoline operation.5 This power loss could be avoided in new engines designed for dedicated CNG mode. To convert gasoline-based two-stroke engine powered three-wheelers to CNG operation, a separate lubrication system and a suitable gas-air mixer were developed. The throttle response and acceleration are slow with CNG operation. The drivability of CNG vehicle is comparable to gasoline.

Diesel to CNG converted vehicles.

Pre-2000 model buses of Delhi Transport Corp. were converted to diesel-CNG dualfuel mode. The conversion criteria was that the power in diesel-CNG mode should match closely with that in the diesel mode, and the CNG induction should begin after speeds of 30 km/h to avoid quenched combustion at lower speeds. The converted bus using an advanced electronic conversion kit showed higher power/torque in diesel-CNG mode at all speeds and a diesel replacement of 32%–86% was achieved. A substantial reduction in black smoke with the diesel-CNG operation was seen under full-load operation of the bus. NOx emissions were also witnessed to be lower in dual-fuel mode.

A pre-2000 diesel bus engine was converted from compression-ignition to spark-ignition mode for dedicated CNG operation. The CNG conversion system consisted of an electronically controlled capacitor discharge ignition system and an intake vacuum-operated gas-powered valve with provisions for settings of full load and partial load gas flows to achieve 70

I SEPTEMBER 2011 HydrocarbonProcessing.com

optimum air-fuel ratio. An oxidation-type exhaust catalytic converter was also used.

The exhaust gas recirculation (EGR) system was used to control NOx emissions.

However, the CNG engine provided 12.4% lower power and 6.7% higher torque. It was observed that optimizing the ignition timing could make the CNG engine performance very close to that of the diesel model.

For the city of Delhi, the conversion of all diesel-based buses to CNG helped to reduce particulate matter (PM10,) CO and sulfur dixode (SO2) concentrations.4 However, similar benefit was not achieved by converting all the three-wheelers to CNG. Most of the three-wheelers had a two-stroke engine, and the separate lubrication system designed for operating on CNG contributed to an increase in PM10 from these vehicles. However, the new three-wheelers have four-stroke engine, and in-use vehicles with two-stroke engine are slowly being phased out of Delhi.

Mixture of CNG and HCNG. In a

CNG engine, replacement of CNG by hydrogen was tried by many researchers. A 20% hydrogen mix by volume with CNG was registered as Hythane. Hythane can be used in any CNG vehicle, but engine optimization is necessary to get emission benefits. IIP also started R&D work on a mixture of CNG and hydrogen called HCNG. An experimental study was done on a stoichiometric burn spark-ignition engine of a passenger car converted to run on CNG fuel using different levels of hydrogen in the CNG.6 It was observed that adding 20% hydrogen on a volume basis in CNG, at stoichiometric operation, provided comparable engine efficiency when compared with neat CNG operation under similar conditions. The concentrations of HC and CO emissions decreased with increasing hydrogen percentages in CNG. NOx emission values generally increase with higher hydrogen content, but it can be controlled by retarding ignition timing without sacrificing on engine output and efficiency.

Brake specific fuel consumption values were comparable or lower with increasing hydrogen content in CNG. LPG VEHICLES

In India, LPG availability is about onethird of the total demand; large imports are necessary to meet domestic demand. LPG fuel system technology is well developed and it is mostly mechanical based designed as “second fuel system” to be added onto gasoline-fuel system for operation either on

gasoline or LPG. In India, private-sector gasoline-powered car owners became interested in converting their cars to LPG due to its easy availability and lower cost. The government legalized LPG as a transportation fuel in August 2000, with the directive that the gas was to be stored in custommade canisters that had a safety release valve instead of the unsafe domestic gas cylinders.

IIP has conducted research work on using LPG in gasoline and diesel engines.3,5 Gasoline to LPG converted vehicles. The performance tests carried out

on a passenger car converted for dual-fuel LPG/gasoline operation showed that power output with LPG was 1%–5% lower than that of gasoline operation. 3,5 The LPG fuel consumption was 11.2 km/l (gasoline equivalent) as compared to 12.5 km/l on gasoline operation. A three-wheeler converted to run on captive propane showed better fuel consumption than on gasoline operation. The CO and HC emissions were lower for the propane operation than for gasoline operation; whereas, NOx emissions were higher for propane over gasoline. The NOx emissions from propane fueled engines can be reduced to the level similar to gasoline operation by using an exhaust gas recirculation and less advanced ignition timing.

Diesel to LPG converted engines.

Test results on a dual fuel LPG-diesel bus and tractor diesel engines showed that, under full-load operation, engine performance improves with LPG induction, and the brake specific fuel consumption and exhaust emissions are lower.7–9 At partial loads, however, the brake specific fuel consumption increases due to quenched combustion and higher ignition delay with LPGdiesel operation. Significantly lower smoke emissions were observed, but HC emissions were higher primarily due to the quenched combustion of a lean LPG-air mixture.

NOx emissions were lower at partial loads but were 25%–50% higher at full load.1 A diesel-operated bus engine was converted to operate as spark-ignited captive LPG engine.

It was seen that the maximum torque developed was similar to diesel engines; whereas the maximum power was 94.9 bhp for LPG, compared to 110 bhp for diesel.5 METHANOL

A major study covering all aspects of methanol in all categories of engines/ vehicles was undertaken at IIP during 1982–1987, funded by the United Nations Industrial Development Organization

REFINING DEVELOPMENTS (UNIDO). Methanol was used both as a partial and full replacement in two-wheeler and diesel engines.

Gasoline-methanol in small twostroke SI engines. In the study, it

was observed that 15% methanol (M15) blends can be used in existing engines without any modifications with marginally more power and an average 3%–4% improvement in fuel economy, 40% reduction in CO and marginal reduction in HC emissions.10 The field study had shown improvement in driveability with M15.

The field studies with M12 fuel on 14 vehicles consisting of mopeds, scooters and motorcycles over a year had demonstrated that the overall vehicle performance were comparable to that of gasoline vehicles.

The study showed similar engine deposits and no corrosion of fuel system components except the tarnishing of brass. The increase in cast-iron piston ring wear with the M12 blend was observed. The results showed excellent participant acceptability of part methanol fuel vehicles.

Neat methanol in small engines. A

two-stroke engine was converted for methanol utilization based on the conventional carburetor engine concept.11 The modifications required for optimum use were minor and retained the basic simplicity of design. There was no requirement of intake heating. Better performance with methanol was observed and driveability was acceptable. A new intake system developed for reducing short circuiting was suggested for methanol application to reduce unburned fuel emissions.

Methanol in diesel engine. Metha-

nol fumigation had been identified as an important step upto the stage of demonstration fleet trials. The study concluded that lubricant requirements generally had not increased; deposits were less; and piston ring wear was marginally higher.12 Face and side wear of the top piston ring revealed that the rate of pressure rise affected wear, and the methanol percentage significantly increased the wear rates. The fleet trials demonstrated an overall diesel replacement of 15%.13–14

The fuel-injection-nozzle needle wear was found to increase by 30%–40% when methanol was used. This wear could not be controlled by mixing castor oil or another lubricant oil. Piston-ring wear on a glowplug engine was higher during 50 hour tests.

Specially formulated oils performed better than normal diesel engine crankcase oil.

This comprehensive research by IIP was conducted in the 1980s and can be taken as an example indicating that elaborative effort is needed to look into the feasibility when adopting any new fuel even in the existing vehicle fleet. Adoption of this alternative fuel was hindered due to insufficient cost-effective methanol supplies in the marketplace, which is key to successfully switching over the existing fleet to any new fuel. This was contrary to the success achieved in the trials switching over the whole fleet to CNG in Delhi where the CNG supply chain was either intact or could be made so.

BIODIESEL

Many researchers have extensively studied biodiesel for fuel properties, performance and emissions. However, most of the studies are reported for methyl esters while very little work was done for ethyl esters. At IIP, a detailed study was also done on jatropha carcus derived ethyl ester.

Engine performance, emissions and field trials were carried out for blends of ethyl ester and diesel. Methyl esters of jatropha carcus and karanjia were also studied.

Ethyl ester. Jatropha carcus derived ethyl ester (JEE) was investigated for performance and emission characteristics in an automotive diesel engine.15 The mass emissions of NOx showed a 4%–9% increase with 10%–20% JEE blends. PM emissions for JEE-20 were almost same as that of diesel.

There was no significant change in brake horse power of both blends when compared to diesel. Deposit rating of critical engine components was done after a 30,000 km field trial of a diesel passenger car running on 5% JEE blend. The deposit rating results showed that no severe deposits and abnormalities of any kind on engine components occurred during the trial. Also, there was no adverse impact on fuel injector coking, piston deposits and top groove filling.

Neat methanol in diesel engines.

Two approaches for methanol operation of heavy duty engines were selected: • Glow plug ignited in-cylinder injection engine • Methanol vapor spark ignited engine.

Methyl ester. The mass emissions results of jatropha carcus derived methyl ester (JME) in blends of 5%–20% in diesel gave reductions of 7%–15% in PM with a marginal decrease of 4% in NOx with 5%

SPECIALREPORT

blend.16 In case the of 5% karanja methyl ester (KME), PM was observed to be 26% lower with an increase of 13% in NOx. However with 20% blend of karanja, both PM and NOx were observed to be higher.

Neat biodiesel (JME) was also investigated for performance and emission characteristics.17 There were benefits in terms of CO, HC and NOx for the neat biodiesel.

A 10%–14% reduction in NOx was also observed. There was no appreciable change in the engine’s brake horsepower. Neat biodiesel was found to be suitable for the engine in terms of both emissions and performance.

BIOBUTANOL

This alternative fuel is commonly produced by an acetone-butanol-ethanol (ABE) fermentation process. Butanol has an energy content closer to that of gasoline and can be easily added to conventional gasoline.18 However, unless cost-competitive production technologies are not in place, it is difficult for butanol to be used as a transportation fuel. Much work is needed to be done in this direction.19 Very limited data of butanol-engine testing is available.

Therefore, at IIP, laboratory experiments were conducted for evaluation of vehicular performance and tailpipe emissions from butanol/gasoline and ethanol/gasoline blends on a four-stroke motorbike on a chassis dynamometer.19 In the study, 5% and 10% blends of ethanol/gasoline and butanol/gasoline by volume were prepared by splash-blending method. All of the alcohol blends showed reductions in mass emissions for HC and CO. Slightly higher NOx emissions were observed in the case of butanol blends. All of the butanol blends gave smooth engine operation.

DIMETHYL ETHER

DME has a much higher cetane number compared to diesel fuel, and it is sulfur free. This alternative fuel has a low ignition temperature that is in the range of diesel fuel. Thus, DME is a good alternative fuel candidate for compression-ignition engine.

DME can be produced from natural gas and conveniently transported over a long distance. NKK Corp. has estimated the price of DME produced at a natural gas field and transported to Japan. 20 DME prices strongly depend on natural gas price and plant capacity. Various studies indicated advantages of using DME as a fuel.21– 31 However, DME’s fate as automotive fuel will depend on the cost effectiveness and the logistics in place.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 71

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REFINING DEVELOPMENTS FT DIESEL

This alternative diesel is produced through a gas-to-liquids (GTL) chemical conversion process known as the FT process. FT diesel can be produced from both renewable and nonrenewable feedstocks such as natural gas, coal and biomass. It has the advantages of ultra-low levels of sulfur and aromatics along with a high cetane index. Therefore, it has the potential to significantly reduce emissions in diesel engines. FT diesel can be produced from remote reserves of stranded natural gas that otherwise are difficult to be economically transported to the market. Different studies on FT diesel showed reduced emissions.32–34 Therefore, it is a promising candidate to replace diesel in distant future.

GREEN DIESEL

This diesel can be produced via a hydroprocessing route; hydrogen is used to remove oxygen from the triglyceride molecules. From an investment standpoint, green diesel is competitive with biodiesel.35 Green diesel has the same quality attributes as syndiesel, including total compatibility with petroleum diesel, high energy density, low specific gravity, excellent storage stability and very low combustion emissions.36 Green diesel has superior fuel properties compatible with conventional diesel engines and meets ASTM D-95 and EN-590 specifications.37 Compared with petroleum diesel, green diesel has between 66%–84% and 41%–85% savings for fossil and GHG emissions, respectively, depending upon study assumptions.35 HYDROGEN

Hydrogen can be used both in IC engines and fuel cells. However, hydrogen has several issues to be addressed before it can become a commercial automotive fuel. Sustainable hydrogen production technologies would have to be developed before it can be economically produced from renewable sources.

Current onboard hydrogen storage technology based on lightweight carbon-fiber for compressed hydrogen is able to deliver a high driveability range. However, different options are being investigated worldwide to develop a more suitable storage technology. Affordable fuel cell technology that can deliver the required power also needs to be developed before hydrogen fuel cell vehicles could be economically developed.

Fuel of the future. An Indian perspective for alternative transport fuels is discussed here both from an historical context as well as

current status of supply chain and usage. Various stages of development efforts are needed to streamline the change over of the existing vehicle fleet to any new fuel. Supply and demand as well as infrastructures still must be be identified in effectively introducing alternative fuels to the Indian market. HP ACKNOWLEDGEMENT Revised and updated from an earlier presentation at the International Refining and Petrochemical Conference—Asia, 19–21 July 2011 at Singapore.

LITERATURE CITED Complete literature cited is available online at HydrocarbonProcessing.com.

S. K. Singal is Scientist ‘G’ and the Head of Automotive Fuels and Lubricants Application Division at the Indian Institute of Petroleum, Dehradun. He holds an M.Tech degree from IIT, Delhi and a PhD from the University of Roorkee. Dr. Singal has large number of publications to his credit. He has been working at IIP for the last 30 years.

Wittison Kamei is a Scientist at the Indian Institute of Petroleum, Dehradun. He has six years of research experience in the area of alternative fuels. His previous works included fuel quality and emissions studies of biofuels. Mr. Kamei received a BE degree in mechanical engineering from the Visvesvaraya National Institute of Technology, Nagpur.

A. K. Jain obtained a BE (mechanical) degree and an ME (mechanical) degree with gold medal from University of Roorkee. He joined the Indian Institute of Petroleum, Dehradun in 1981 as Scientist-B and is presently working as ScientistG in the Automotive Fuels and Lubricants Application Division. Mr. Jain is head of the Gasoline Fuel Quality and Engine Emissions Area. He has authored 41 research papers and 76 technical reports and holds three patents.

He received the “Best Indian Paper on Environmental Pollution Award” for his research paper at the International Automotive Technology at ARAI, Pune in January 2007.

M. O. Garg is the director of the Indian Institute of Petroleum, Dehradun. He earned a Gold Medalist in B.Tech. in chemical engineering from Nagpur University and M. Tech. from IIT-Kanpur. In 1976, he joined the Research & Development Division of Engineers India Ltd., New Delhi. Dr. Garg served on the faculty of the University of Melbourne from 1980-81. He returned back to Engineers India Ltd. in 1982, where he worked on several areas closely linked with the refining industry. In 1994, he joined Kinetics India Ltd. as general manager of process system services division and was responsible for providing advanced process engineering services to the refining industry. In July 1998, he joined the Indian Institute of Petroleum as Scientist ‘G’ and became head of the refining technology division.

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REFINING DEVELOPMENTS

SPECIALREPORT

A perspective on China’s refining industry Statistics show how this nation has progressed from 2006 to present day X. LI, W. REN, Q. ZHU and J. REN, Petrochemical Research Institute, PetroChina, China

45,000

14 11.6

10.3 13

35,000 GDP Growth rate

30,000

9.6

12

9.2

10

25,000

8

20,000

6

15,000

Percent

40,000

Billion RMB

4

10,000 2

5,000 0

0 2006

FIG. 1

2007

2008

2009

2010

The development of China’s economy. Source: China National Bureau of Statistics.

600 500 400

14 Processing quantity Refining capacity Share in the world

8.66

9.85

11.24

11.61 12

10.23 10 8

300 6 200

4

100

2 0

0 2006 FIG. 2

Percent

Current situation. With the fast development of its national economy, China’s refining industry, as the country’s pillar industry of energy and raw material, has made great progress and plays an important role in the national economic and social development. Also, its station in the world’s refining industry appears to be on the rise.

Sustained refining capacity growth. China’s GDP increased from 21,192 billion RMB in 2006 to 39,798 billion RMB in 2010, a growth rate of about 10% every year. China has passed Japan to have the second largest GDP economy in the world, and it is expected that the country’s economic growth momentum will continue over the next decade. The projected GDP growth rate from 2011–2015 is expected to be 7% each year, with the GDP reaching 55,000 billion RMB in 2015. This accelerated GDP growth offers an excellent economic environment and domestic market opportunity for the refining industry.

From 2006–2010, there has been a substantial increase in China’s refining capacity, from 369 MMtpy in 2006 to 512 MMtpy in 2010, with the average annual growth rate at about 7.8%. This growth has made China the country with the second largest refining capacity in the world.

The world’s refining capacity also grew during this time, but with an annual growth rate of only 0.89%. The proportion of China’s refining capacity in the world shows a rising trend, from 8.3% in 2006 to 11.6% in 2010.

In China, there are three large state-owned oil companies.

Sinopec is the largest refiner, with a capacity of 222 MMtpy.

The second largest refiner is China National Petroleum Corp.

(CNPC). CNPC is the parent company to PetroChina, and has a refining capacity of 154 MMtpy. The third company is China National Offshore Oil Corp. (CNOOC), which has over 30 MMtpy of refining capacity. There are also regional and local refineries in China (known as “teapots”), and these contribute about 100 MMtpy to the country’s refining bottom line.

Increasing production and consumption of gasoline and diesel. The production and sale of automobiles have significantly

increased. Compared to 2009, China’s automobile production in 2010 was up to 18.27 million, an increase of 32.4%.

With the booming automobile industry, the consumption of gasoline and diesel has bumped up substantially. Gasoline consumption increased from 52.48 MMtpy in 2006 to 69.86 MMtpy in 2010, and the growth rate was about 8.3%/yr. Diesel consumption increased to 156 MMtpy in 2010 from 116.46 MMtpy in 2006, with a growth rate of 8.5%/yr. In 2010, the production of gasoline and diesel rose to 76.75 MMtpy and 158.87 MMtpy, respectively.

Million tons

G

reat progress has been made in China’s refining industry in recent years. Refining capacity and oil production have increased substantially, but challenges still remain. Obstacles facing China’s hydrocarbon processing industry include a tight petroleum supply, stringent product specifications, energy conservation trends, and government directed pollution reduction efforts.

2007

2008

2009

2010

The development of China’s refining capacity. Source: China Ministry of Industry and Information Technology.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 75

SPECIALREPORT

REFINING DEVELOPMENTS

Over the past five years, gasoline and diesel production not only met domestic market demand, but also saw surpluses exported to Singapore, Indonesia and other countries.

Refinery scale. The average scale of China’s refineries is over 6.1 MMtpy. The average refinery scale of worldwide refineries is 6.7 MMtpy. The overall refining capacity of the top 10 global refiners is 1,674 MMtpy and accounts for 38% of the world’s refining capacity. There are 21 refineries with a capacity of more than 20 MMtpy in the world, with PDVSA Paraguana in Venezuela being the world’s largest refinery with a capacity of 47 MMtpy.

By the end of 2010, there were 21 Chinese refineries (PetroChina 7, Sinopec 13 and CNOOC 1) with more than 10 MMtpy capacity. Several additional 10 MMtpy refineries are being constructed or planned in Guangdong, Sichuan, Henan and Yunan. Along with the wave of refinery construction, several large-scale ethylene projects have been built, expanded or revamped to form a series of PC-integration bases, including Dalian, Dushanzi, Zhenhai, Yanshan and Qilu.

Future challenges. China’s refining industry faces challenges within the context of globalization, sustainable development and low-carbon economy. From 2006–2010, the production of crude oil in China has been stable, at a level of 190 MMtpy or so. The crude oil import has over 50% in 2009. In 2010, the apparent consumption of crude oil in China is up to 439 MMt. The net import amount achieved 236 MMt, and the dependency of domestic petroleum consumption on import is about 53.8%.

China’s crude oil demand will continue to grow into the future. The demand for crude oil in 2015 is projected to break through 500 MMt, and it will reach 600 MMt in 2020. Import dependence is expected to grow from 53.8% in 2010 to 62% in 2015, reaching 68% by 2020. Some international scholars argue that a country with an import dependence approaching 50% is putting itself in a risky security situation. Thus, the projected Chinese level of import dependence in 2020 has got to be worrying to its government.

In 2010, the top 10 global exporting countries accounted for about 80% of China’s crude oil imports. Over the 2006–2010 period, the top three sources of China crude oil imports were

TABLE 1. Key financial data for PetroChina and Sinopec in 2010 Items

PetroChina

Sinopec

Sales revenue/profit, billion RMB

1465/140.0

1913/71.9

10

7

5

26

Refining capacity, Mt

154

222

Processing oil quantity, Mt

122

211

Gasoline output, Mt

23.3

35.9

Diesel output, Mt

53.7

76.1

Rankings of Fortune Global 500 Rankings of world top 50 petroleum companies

PetroChina Sinopec CNOOC

Distribution map of China’s refineries with capacity of over 10 MMtpy.

500 450 400

43.12

46.15

51.17

47.94

53.79

Million tons

30

250 200

3.13 2.89

FIG. 5

100

4.11 3.36 4.20

10

50 0

11.55

16.15

21.35 18.65

4.70

0 2006

2007 Output Import amount

2008

2009

2010

5.26 6.37

Apparent consumption Import dependency

China’s oil supply and demand. Source: China’s National Bureau of Statistics.

I SEPTEMBER 2011 HydrocarbonProcessing.com

6.63 FIG. 6

Saudi Arabia Angola Iran Russia Oman Congo Equatorial Guinea Sudan Yemen Venezuela Others

China’s crude oil import sources in 2006. Source: China’s General Administration of Customs.

20

150

19.05 16.44

11

40

300

FIG. 4

3.34 3.63 3.73 9.08

50

350

76

60

Percent

FIG. 3

*In 2010, the sales revenue and profit of CNOOC was 149.1 billion RMB and 54.4 billion RMB, and CNOOC was ranked 48 in the world top 50 petroleum companies.

16.46 8.91

Saudi Arabia Angola Iran Oman Russia Sudan Iraq Kazakhstan Kuwait Brazil Others

China’s crude oil imports sources in 2010. Source: General Administration of Customs of China.

REFINING DEVELOPMENTS

Green tech and trade barriers. International trade protectionism has become more of an issue in recent years and China’s petrochemical industry is dealing with this. For example, the European Union’s (EU) Registration, Evaluation, Authorization and Restriction of Chemical substances (REACH) legislation was implemented in 2007, meaning that the quality requirement for petrochemicals exported to the EU is continuously rising. In 2010, the US Congress moved to amend the Toxic Chemical Safety Act, ensuring the public and the environment are protected from risks of chemical exposure. At the same time, Japan and South Korea are instituting similar regulations regarding the import of petrochemicals. Surveys from the EU, India and Brazil TABLE 3. China’s refineries with capacity of over 10 MMtpy Refinery

1

Zhenhai

Zhejiang

Sinopec

2

Dalian

Liaoning

PetroChina

20.5

3

Tianjin

Tianjin

Sinopec

15.5

4

Shanghai

Shanghai

Sinopec

14

5

Maoming

Guangdong

Sinopec

13.5

6

Jinling

Jiangsu

Sinopec

13.5

7

Guangzhou

Guangdong

Sinopec

13

8

Fujian

Fujian

Sinopec

12

9

Huizhou

Guangdong

CNOOC

12

10

Gaoqiao

Shanghai

Sinopec

11.3

11

Yanshan

Beijing

Sinopec

11

12

Qilu

Shandong

Sinopec

10.5

13

Lanzhou

Gansu

PetroChina

10.5

14

Fushun

Liaoning

PetroChina

10

15

WEPEC, Dalian

Liaoning

PetroChina

10

16

Dushanzi

Xinjiang

PetroChina

10

17

Guangxi

Guangxi

PetroChina

10

18

Jilin

Jilin

PetroChina

10

19

Huangdao

Shandong

Sinopec

10

20

Yangzi

Jiangsu

Sinopec

10

21

Luoyang

Henan

Sinopec

10

TABLE 2. Chinese refined fuel supply and demand in 2006–2010, MMt

34.0

Product oil Item

2006

2007

2008

2009

2010

33.5

Gasoline

Output

55.91

59.94

63.48

71.95

76.75

33.0

Import

0.06

0.23

1.99

0.04

0

Export

3.51

4.64

2.04

4.94

5.17

52.47

55.53

63.43

67.05

71.58

32.0

Output

116.53

123.7

133.24

141.27

158.87

31.5

Import

0.71

1.62

6.25

1.84

1.8

31.0

Export

0.78

0.66

0.63

4.51

4.67

116.46

124.66

138.86

138.6

156

Apparent consumption Diesel

Apparent consumption

Location

Company

Refining capacity, MMtpy

No.

23

1.30

API°

1.20

1.10

32.5

1.00

API° S content, wt%

0.90 2009

FIG. 7

S content, wt%

Saudi Arabia, Angola and Iran. Compared to 2006, crude oil imports from Saudi Arabia, Angola and Sudan increased, and crude oil imports from Iran, Russia and Oman decreased in 2010.

Iraq, Kazakhstan, Kuwait and Brazil are also top exporting countries that China relies upon.

In terms of remaining crude oil reserves in the world, the proportion of high-sulfur and heavy crude oil increases every year.

The trend of worldwide crude oil quality is that the production of low-sulfur and light crude oil will run down steadily, and the production of sulfur-containing and heavy crude oil will increase continuously. In 2009, the average quality of worldwide crude oil was as follows: API° 33.3 and S content 1.11%. By 2030, API° is projected to decrease by 0.4, and S content will increase by 0.11%.

Heavy oils. Although most China-originated crude oil is classified as low-sulfur, there is a severe shortage of this kind of oil in the country. The country’s crude oil imports are typically highsulfur and heavy. Over the next 20 to 25 years, recoverable reserves are expected to increase by 180–200 MMtpy, with the proportion of low-permeability heavy oil increasing. In 2010, the high-sulfur and highly sour crude oil processing share of PetroChina and Sinopec was about 50%. Due to the deterioration of crude oil quality, refineries must upgrade processing facilities and increase the complexity and severity of refining.

Environmental regulations. In recent years, quality requirements for motor gasoline and diesel in the world have become more stringent, demanding fuels that are low-sulfur and ultra-lowsulfur. The current quality specifications limit the sulfur content in fuels as follows: gasoline (US 30 ppm, Europe 10 ppm and Japan 10 ppm) and diesel (US 50 ppm, Europe 10 ppm and Japan 10 ppm). It’s projected that 50 ppm gasoline will account for an 80% share of global gasoline consumption by the end of 2011. By 2015, the share of low-sulfur and ultra-low-sulfur gasoline consumed in the world will increase to 75% from present day 65%.

China’s refined oil standard is nearly consistent with the world level. The China III standard (S, 150 ppm) for diesel and gasoline has been implemented. It is estimated that by January 1, 2014, the standards for motor gasoline and diesel will all rise to China IV, and even China V standards (S, 10 ppm) in some metropolian cities. The China V standard is expected to apply in Beijing in 2012.

The Ministry of Environmental Protection released regulations that further restrict the content of hazardous materials. China’s refining industry faces the serious challenge of clean fuel production and quality upgrading.

SPECIALREPORT

2010

2015

2020

2025

2030

Prediction of worldwide crude oil quality during 2010– 2030. Source: IFQC WRFS 2010-2030.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 77

SPECIALREPORT

REFINING DEVELOPMENTS

have cast China’s polyvinyl chloride, plastic products, shoes and toys in a negative light.

Emissions reduction. Energy savings, response to climate change and sustainable development have all become buzz words in the refining industry. For China’s refining industry, the work of CO2 emissions reduction is just beginning. China has set the obligatory targets, with energy consumption and CO2 emissions per unit of GDP scheduled to decrease by 16% and 17% respectively, and the country plans to have its total amount of contamination emissions reduced by 8%–10% in 2015 when compared to 2010.

International Energy Agency data shows that China was the largest CO2 emissions emitter in 2008. Under the Copenhagen Accord, China promised to reduce CO2 emissions per unit of GDP by up to 45% in 2020 when compared with 2005.

Sustainable development. The 2011–2015 National Petroleum and Chemical Plan, issued in guideline form from the Chinese government, highlights the following goals: optimizing organization structure, adjusting industry layout, improving the supply capability of gasoline and diesel, accelerating the development of high quality petrochemicals, driving technology innovation, reducing emissions and increasing energy efficiency.

Recommendations. China’s refining industry should accelerate development of the Bohai Sea area, the Changjiang Delta, the Zhujiang Delta and the Middle West refining and chemical enterprise circles. Small-scale, less efficient and pollution prone refineries and units should be phased out gradually. In April 2011, the National Development and Reform Commission announced it will mandate the closure of refineries with capacity of less than

2 MMtpy by the end of 2013, and restrict projects to build CDUs with capacity of less than 10 MMtpy. Restrictions on small scale FCC units, hydrocracker and reformers were also issued.

The time period of 2011–2015 will see China develop highly energy-efficient technologies along with value-added green technologies. R&D investment should be increased to develop heavyoil upgrading and clean fuel production technologies. Alternative energy sources (coal, natural gas, biofuels) should be developed to supply technical support for sustainable development. Other subjects that should be explored include molecule refining and desktop simulation refineries. HP Xuejing Li is the deputy director of the strategic research and information division of the PetroChina Petrochemical Research Institute. She graduated from the East China University of Science and Technology and Lanzhou University and obtained a bachelor’s degree in engineering and an MBA. Ms. Li has been engaged in refining and petrochemical strategy research for nearly 20 years with Sinopec and PetroChina.

Wenpo Ren is an engineer of the strategic research and information division of the PetroChina Petrochemical Research Institute. He graduated from the China University of Petroleum (East China) in 2010 with a doctorate degree in chemical engineering and technology.

Qingyun Zhu is an engineer in the strategic research and information division of the PetroChina Petrochemical Research Institute. She graduated from the East China University of Science and Technology and has been engaged in refining and petrochemical strategy research for 15 years with Sinopec and PetroChina.

Jing Ren is an assistant engineer in the strategic research and information division of the PetroChina Petrochemical Research Institute. She graduated from Jiangnan University in 2009 with a bachelor’s degree in Chinese language and literature.

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REFINING DEVELOPMENTS

SPECIALREPORT

Fast track to fuel— getting the right mix An innovative application of biology and chemical engineering cuts time and cost out of biofuel production G. W. LUCE, Terrabon Inc., Houston, Texas

M

any people believe biofuels are a fairly new idea, but the fact is engineers and scientists have been working on ways to convert biological feedstocks to viable engine fuels for many years. Some processes, such as the well-known Fischer-Tropsch synfuel process, have been around for almost a century, spurred by Germany’s high demand, combined with a limited supply of traditional hydrocarbon fuels.

Today a variation on the Fischer-Tropsch process is the basis for gas-to-liquid conversion as a way to harvest stranded gas or solution gas recovered in oil production and convert it to a compatible liquid for mixing into the liquid flowstream. But the technique can also be used in a thermochemical platform to reduce biomass down to its purest form (gasified polysaccharide and hydrogen) which is then passed over a catalyst to yield ethanol.

Although the thermochemical approach works, other processes have shown promise.

It is useful to examine them to reveal the pros and cons of each as a commercially viable method for drop-in biofuel generation, namely gasoline and jet fuel.

Three processes. Recently, scientists

at Texas A&M University examined three promising techniques for conversion of biomass to fuel: the aforementioned thermochemical platform, a sugar platform and a carboxylate platform.

The fundamental process studied involved the conversion of an ideal lignocellulosic biomass, consisting of cellulose and other polysaccharides and lignin to polysaccharides that can be converted to ethanol, and subsequently to liquid fuels with the aid of chemical catalysts. An “ideal biomass” was chosen so that the rela-

tive yields of each process could be fairly evaluated and compared. The mixture chosen consisted of 31.7% lignin and 68.3% polysaccharides with no ash.

It was noted that to form fuel products, lignin must be processed thermochemically, whereas polysaccharides can be processed using either thermochemical or anaerobic biological techniques. It would seem, then, that the lignin is the “fly in the ointment” because of its unique processing requirements. The lignin can be used for combustion supported by oxygen injection that gasifies it into carbon monoxide, carbon dioxide and hydrogen. The carbon monoxide can be converted to hydrogen by the addition of water.

The polysaccharides are converted to ethanol using three methods: The thermochemical platform is a four-step process in which the lignin is separated from the polysaccharide, the polysaccharide is gasified, the lignin is gasified and converted to hydrogen and the resulting gases are catalyzed to yield ethanol. Scientists observed that while conversion using this platform is possible, it can be difficult. The per-pass conversion is very low, and the theoretical yields are difficult to achieve in practice.

The sugar platform also comprises four steps. Carbohydrate polymers are hydrolyzed to sugars using acids or enzymes, the resulting sugars are fermented to ethanol and CO2, any remaining lignin is gasified and converted to hydrogen and the hydrogen is used to convert the CO2 to more ethanol. This process works fairly well and handles the lignin issue elegantly.

The carboxylate platform is quite similar to the sugar platform except for one critical difference. The process completely converts ideal biomass using these four

steps: carbohydrate polymers are hydrolyzed to sugars using enzymes naturally produced by pure or mixed cultures, the resulting sugars are fermented into acetic acid or mixed acids, the remaining lignin is gasified and converted to hydrogen and the hydrogen is used to convert the CO2 to form ethanol.

The thermochemical platform has a slightly lower yield than either the sugar or the carboxylate platform. For the former, 1 mol of sugar produces 2.5 mol of ethanol, whereas in the latter two processes a yield of 3 mol of ethanol is achieved. The next step is to convert the ethanol to a hydrocarbon, specifically gasoline or jet fuel.

This transformation can be accomplished whether the thermochemical, sugar or carboxylate platforms are used to create Simultaneous saccharification and co-fermentation (SSCF) Biomass A

Ethanol

Alcohol production Enzyme

Biomass B

Enzyme production

Carbon dioxide

Oxygen

Consolidated bioprocessing (CBP) Biomass A

Alcohol production

Ethanol

Enzyme Biomass B

FIG. 1

Enzyme production

Ethanol

Biomass conversion using SSCF and CBP.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 81

SPECIALREPORT

REFINING DEVELOPMENTS

the ethanol. For example, by using zeolite catalysts, alcohols such as ethanol can be dehydrated to alkenes (olefins). These subsequently oligomerize into hydrocarbons such as gasoline, diesel or jet fuel with a typical mass yield of 60.9%.

However, the technique used affects yield, efficiency and cost. For example, if the thermochemical approach is taken, the hydrocarbon yield per kilogram of ashfree biomass is 95.8 gal/ton compared to 115 gal/ton for either of the two biological approaches. This is a significant difference.

Considering the thermal energy requirements, the energy efficiency of the thermochemical platform is 67.5% compared to 81.0% for the biological approaches.

Results suggest the end-game.

Putting the lower yield thermochemical approach aside, two biological processes evolved and are graphically described in Fig. 1. The first uses simultaneous saccharification and co-fermentation anaerobically to convert the majority of biomass

TABLE 1. Theoretical yield (gal acid/gal reactant) and theoretical gasoline produced from acid (TGPA) yield of various acids from various sugars C2–C8 acids

From hexose/pentose Th. yield Th. TGPA

From hexan Th. yield Th. TGPA

From pentan Th. yield Th. TGPA

Acetic

0.667

76.8

0.741

85.3

0.758

87.3

Propionic

0.822

127.7

0.913

141.9

0.934

145.1

Butyric

0.488

89.1

0.542

99.0

0.555

101.3

Pentanoic

0.488

98.9

0.542

109.9

0.555

112.4

Hexanoic

0.429

93.4

0.477

103.7

0.488

106.1

Heptanoic

0.481

110.4

0.534

122.6

0.547

125.4

Octanoic

0.400

95.6

0.444

106.2

0.455

108.6

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A to ethanol. In the meantime, enzymes produced from biomass B are introduced to complete the conversion of the remainder of biomass A. Oxygen and CO2 are byproducts.

The second, consolidated bioprocessing, produces ethanol from both biomasses with no byproducts. Because the consolidated processes are integrated, lower capital cost is anticipated. And because aerobic gas transfer is not required, lower energy consumption is expected.

At the end of the day, three key factors tilt the scale toward the carboxylate platform augmented by high-throughput catalysts—energy efficiency, throughput and yield. The analysis is somewhat complex, yet the data clearly show that the carboxylate platform achieved the highest alcohol yield. Accordingly, higher liquid fuel yields are expected, assuming the chemical catalyst process is reasonably efficient.

The Texas A&M University study gave highest marks to the carboxylate platform, citing these advantages: • Highest product yields are achieved.

• Gasified lignin is used effectively to create hydrogen using the efficient watershift reaction.

• Biomass conversion to carboxylic acids uses a mixture of microorganisms that does not require a sterile environment.

• All lignin biomass is biologically converted, which is more energy-efficient • All enzymes and cells produced are useful.

• Residual enzymes and cells can be recycled and metabolized to useful byproducts, like carboxylic acid.

• Conversion of lignin to hydrogen is an easy step compared to the requirements of other platforms.

Carboxylate platform process. A

commercial version of the carboxylate platform has been introduced. The complicated path that leads a laboratory-scale biochemical process to a commercial scale is full of all sorts of business, environmental and practical obstacles. The commercial process must be thoroughly understood and segmented into practical steps that are compatible with regulations. Every attempt must be made to maximize process efficiency and yield to produce a product that is competitive and adds value to the fuel energy spectrum.

Terrabon has developed a process that takes all of these elements into consideration. It can be implemented by targeting low-cost, small-capitalization projects that use multiple feedstocks and yield mul-

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SPECIALREPORT

REFINING DEVELOPMENTS

tiple products. As a result, economic risk is minimized. Unlike the primary alcohol approach taken by Texas A&M, Terrabon takes advantage of a secondary alcohol approach to minimize hydrogen consumption and energy density loss that occurs in the de-hydrolysis step of the catalyst phase.

Basically, the biological process is followed by a powerful mix of catalysts to build a fast track to the end product—gasoline or jet fuel. First, mixed-acid fermentation uses natural enzymes to convert fiveand six-carbon sugars (xylose and glucose respectively) from biomass to C2–C8 fatty acids. Table 1 shows the yield of each acid.

After the acid is buffered to an organic salt (carboxylate salt), concentrated and thermally converted to ketones, high-throughput chemical catalysts take over, rapidly converting the mixed ketone feed into gasoline or kerosine-range hydrocarbons.

The catalysts are provided by Terrabon’s strategic partner, CRI/Criterion, under license. Typically, in the chemical and petrochemical industry, catalyst development entails a formal process first developed and validated at laboratory scale. Following this step, reaction conditions are optimized and scale-up begins. Finally, the engineers

develop and test the commercial process flowsheet that terminates in the engineering and construction of a plant. The entire process can consume several years.

However, using CRI’s high throughput tools, an array of catalysts can be developed and tested in parallel. These catalysts can be used in several applications for chemical production, refining and in biofuel development. 150 combinations of catalysts and process conditions were tested in parallel fixedbed reactors, yielding a total of 5,000 responses. These were subjected to statistical analysis to see which best met the desired objectives of the process. From this, Terrabon was able to develop a process flow scheme, along with parameters for the design of a recycle compressor and a hydrogen plant. Small volumes of 0.5 cm3 of catalyst were screened in test reactors to validate the process, which quickly showed the commercial viability of the overall program and its expected yield.

Most importantly, the work was completed in less than nine months.

In addition to validating the process as a means to achieve the desired product, other important parameters were established.

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These included such things as energy required, hydrogen consumption, recycle ratio, purge rate, losses and byproducts.

Bottom line. The Terrabon carboxylate

platform process is stimulated by proprietary high-throughput catalysts, resulting in several advantages: • Development of a commercial process characterized by low-cost, small-footprint, front-end facilities suitable for serving local communities • Process based on multiple feedstocks and yielding multiple products • Risk diversification • Easy-to-implement, non-sterile processes • Use of established chemical processes • Leverages a secondary alcohol pathway to produce green olefins as an intermediate to a green gasoline and jet fuel • Environmentally friendly, can use contaminated water, no groundwater needed • Uses an indigenous anaerobic biomass culture from landfills with natural enzymes—cheap and readily-available • Replicable.

To elaborate on the feedstock requirements, it has been postulated by some scientists that critical food grains would be used in the creation of biofuels, thus straining the world’s food supply. In fact, the process can use a variety of food waste products such as cornstalks and leaves, processed sugarcane dross and other biological material that is typically burned.

As concluded by the Texas A&M University study, the carboxylate platform is more efficient than either the thermochemical platform typified by the Fischer-Tropsch process, or the sugar platform that requires extra steps and creates undesirable byproducts. HP Gary W. Luce has served on Terrabon’s board of

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directors since June 2007 when he arranged and closed a large investment in the company on behalf of a private investment group. Mr. Luce has more than 25 years of senior management strategic planning and operating experience in the energy sector. He has previous work experience with McKinsey & Company, EOTT Energy Partners and Reliant Resources. In 2004, he cofounded K-L Energy Partners, which focused on investments in the midstream and downstream sectors of the energy industry. Since June 2007, he has been the principal architect of the company’s technology deployment, and has led its financial and management transition from a development-stage entity to a standalone, operating technology company. He graduated summa cum laude from Texas A&M University and Stephen F. Austin State University with degrees in chemical engineering and physics. He also received an MBA from Houston Baptist University.

REFINING DEVELOPMENTS

SPECIALREPORT

Consider new processes for clean gasoline and olefins production Advanced technologies promote propylene yield while reducing olefins in gasoline J. LONG, Y. XU and J. ZHANG, Sinopec Research Institute of Petroleum Processing, Beijing, China; D. DHARIA, A. BATACHARI, E. YUAN, S. GIM and S. XU, Shaw Energy & Chemicals Group, Houston, Texas

include cracking, hydrogen transfer, isomerization and alkylation of hydrocarbon molecules. The rates of various reactions change with the conversion depth of the feedstock while the hydrocarbons pass through the riser.

The cracking reactions are endothermic and will take place in the initial step, or the lower section of riser, where the feed and hot catalysts are in intimate contact. The other converting reactions (hydrogen transfer, alkylation and isomerization, etc.) will

150 ppm

No limit

40

50

1,000 ppm

50

Sulfur content, max ppm wt Benzene, max vol % Aromatics, max vol % OleďŹ ns, max vol %

40

35

35

30 ppm

30 20 18

10 5.0 0 Cat 1 US tier 0 Euro 1

2.5

1.0

10

Cat 2 Cat 3 WWFC gasoline categories US tier 1 US/cal LEV Euro 1 or 2 Euro 3

10 ppm

Two-zone riser. Major chemical reactions in an FCC riser

occur in the later step, or the middle or upper section of the riser.

In the sequential reactions, olefins are produced from cracking reactions and then are consumed by subsequent secondary reactions, thus converting some olefins to paraffins or aromatics as shown in Fig. 2.

However, those converting reactions in the second step are exothermic and are favored or accelerated under a temperature lower than the cracking temperature. The conventional FCC riser, which is essentially a straight pipe, does not have applicable means to provide the two distinct temperature zones, i.e., the high temperature zone for cracking reactions and the low temperature zone for converting reactions.

Based on the two-step reaction mechanism, an innovative twozone riser was developed in late 1990s to optimally accommodate the desired FCC reactions to reduce olefins in FCC gasoline.2 As shown in Fig. 3, the two zones are connected in series with a larger diameter Zone 2 on top of a smaller diameter Zone 1. Zone 1 is designed, similar to a conventional FCC riser, to operate at high temperature and short residence time, while Zone 2 operates at

Gasoline components, maximum vol. %

R

efiners must meet increasingly stringent specifications for cleaner gasoline, as shown in the gasoline standards defined by the Worldwide Fuel Charter (WWFC), a global agreement between the major motor manufacturers in the US, Europe and Japan.1 Fig. 1 shows the trend of WWFC standards toward progressive reductions of sulfur, olefins, benzene and aromatics.

The high level WWFC categories of gasoline have been or soon will be, adopted by the gasoline standards of the US, Europe and many other countries.

For the gasoline components with similar molecule weights, isoparaffins, iso-olefins and aromatics provide the highest octane numbers. The gasoline specifications actually require more isoparaffins to compensate for the octane number losses due to reductions of olefins and aromatics mandated by newer regulations.

The fluid catalytic cracking (FCC) naphtha contributes high percentages of olefins and sulfur in gasoline pools. Hydrotreating is a common method to remove sulfur in FCC gasoline. However, the olefins are also saturated by hydrotreating, which causes significant octane loss. A desired approach is to improve the FCC to process and produce more isoparaffins with less olefins, sulfur and benzene in the FCC naphtha.

In addition to gasoline, the refinery FCC process also produces one-third of the global propylene supply. It is desirable for refiners to produce high-quality gasoline, while an FCC unit is shifted to higher propylene production. This article will discuss several new FCC technologiesâ&#x20AC;&#x201D;maximizing isoparaffins, and clean gasoline and propylene, that can meet the increasingly stringent environmental regulations for cleaner gasoline and produce more propylene. These processes can produce much better quality gasoline than a conventional FCC unit, while almost doubling the propylene yield.

10 1.0 Cat 4

US/cal LEV Euro 4

Source: WWFC limits on gasoline components, Worldwide Fuel Charter, 4th ed., September 2006

FIG. 1

Progressive reductions of sulfur, olefins, benzene and aromatics in gasoline.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 85

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REFINING DEVELOPMENTS lower temperature and longer residence time. The riser temperature profile is controlled by a quench stream or recycled catalyst injected between the two zones, with the two zones operated at distinct environments that favor the endothermic and exothermic reactions sequentially.

The novel two-zone riser reactor was investigated and studied by extensive cold-modeling tests and CFD simulations to optimize its configurations, dimensions and fluidization conditions.

Optimal design of the new riser reactor is a combination of a dilute pneumatic transport section in Zone 1 and a fast fluidized bed in Zone 2 to best suit for the FCC reaction mechanisms.

The Zone 1 operates at a dilute pneumatic transport regime and is just like a conventional FCC riser, with high temperature, large catalyst-to-oil ratio and short residence time. The high temperature and large catalyst-to-oil ratio increase the cracking reactions to convert heavy oils into intermediate components including olefins, while the short residence time prevents excessive secondary cracking reactions. The higher conversion in Zone 1 can also improve the gasoline octane number by decreasing the n-paraffins and cyclo-paraffins content that depress octane numbers.

Zone 2 is a fast fluidized bed, different from that in conventional FCC risers. The temperature of Zone 2 is lower, while the residence time is longer than in Zone 1. These operating conditions favor reactions to convert olefins and other intermediates into isoparaffins and aromatics. Commercial applications have shown that the two-zone risers can maintain all the benefits of modern FCC technology with high conversions, and at the same time reduce nonselective cracking reactions to decrease dry gas and coke make.

The chemical reaction mechanisms on the reduction of olefins, sulfur and benzene in the two-zone riser are:3 • Reduction of olefins in the gasoline is mainly achieved because of the double-molecule reactions involving olefin molecules in Zone 2, form isoparaffins and aromatics.

• Sulfur compounds (mainly mercaptans and thiophenes) in FCC gasoline are formed from cracking or regrouping of the sulfur compounds in the feedstock. Zone 2 enhances hydrogen transfer reactions to favorably convert mercaptans and thiophenes into either gas sulfur (H2S) or coke sulfur, thus lowering sulfur content in the gasoline. The H2S would be less likely to react with olefins to form gasoline sulfur since the concentration of gasoline olefins are much lower in Zone 2 than in conventional riser.

• Alkylation reaction between benzene and olefins in Zone 2 effectively reduces both benzene and olefins in gasoline, while more alkyl benzenes are produced.

Isoparaffin technology. The first commercial application of the new isoparaffins technology was in 2002 for a revamp of an FCC unit at Sinopec’s Gaoqiao Petrochemical Branch Co. (Gaoqiao) in Shanghai, China. Since then, to meet market demand and maximize clean gasoline production, 17 isoparaffin units have been installed in China (14 revamps of FCC and three grassroots application), with the unit capacities ranging from 0.44 to 2.8 million tpy. Industrial applications have shown that isoparaffin units have significantly improved the product yields and qualities, with overall operation costs similar to a conventional FCC.4 Similar to a conventional FCC unit (FCCU), an isoparaffin unit consists of a riser reactor, a catalyst regenerator and gas plant to separate the reactor effluent into liquefied petroleum gas

SPECIALREPORT

(LPG), gasoline and other products. The unique features include: • A two-zone riser (Fig. 3), with the two zones operated at different conditions to favorably promote chemical reactions that improve the quality and yield of gasoline • A quench stream or recycled catalyst is injected into the second zone, to lower the temperature and increase the catalystto-oil ratio in Zone 2 • Optional proprietary catalyst enhances the converting reactions while cracking heavy feeds.

This process can provide several advantages over conventional FCC: • Cleaner gasoline • Reduces content of olefins (20%–50%), sulfur (20%–40%) and benzene (up to 33%) • Improved octane numbers • Higher yield of gasoline Cracking 1st

Hydrocarbon

Hydrocarbon + Olefins

Isomerization

2nd Olefins

Hydrogen transfer

Alkylation FIG. 2

Isoolefins

Hydrogen transfer

Isoparaffins

Isoparaffins and aromatics

Isoparaffins/Alkylaromatics

The two step sequential reactions to produce and consume olefins in an FCC riser.

Quench stream

Zone 2

Zone 1

Regenerated catalyst Feed

FIG. 3

Configuration of the two-zone riser.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 87

REFINING DEVELOPMENTS

Items

FCC

Isoparaffin process

896.7

896.6

4.0

4.7

H content, m%

12.8

12.9

Saturates content, m%

55.4

59.2

60

60

515

497

Temperature of Zone 1, °C

–

505

Reactor pressure (G), MPa

0.18

0.19

6.5

5.9

Feedstock Density, kg/cm3 CCR, m%

Activity of equilibrium catalyst Operating conditions Riser outlet temperature, °C

Ratio of catalyst to oil Product distribution, m% Dry gas

3.8

2.9

LPG

15.4

14.6

Gasoline

44.2

49.3

Diesel

22.6

21.3

Slurry

4.6

3.0

Coke

8.9

8.6

Loss

0.5

0.3

Sum

100.0

100.0

82.2

85.2

Olefin content, vol%

43.1

34.1

Isoparaffins, vol%

29.5

39.6

0.437

0.307

RON

89.4

88.8

MON

79.2

80.2

CST,* m%

10.4

5.8

Total liquid yield Gasoline properties

Benzene content, vol%

*

Coefficient of sulfur transfer is defined as the sulfur content in gasoline divided by the sulfur content of feedstock, multiplied by 100%.

• Increase isobutane (feedstock for alkylation), up to 40% in LPG • Higher total liquid yield and less dry gas and slurry.

Operation and performance data from Sinopec’s Gaoqiao FCCU before and after the isoparaffin revamp are listed in Table 1. The results show that isoparaffin technology has reduced the olefin content by 20 vol%, benzene content by 30 vol% and sulfur by 44 vol% in FCC gasoline, with a slight improvement in octane numbers. In addition, this process increased gasoline yield by 5.1 % over FCC, while dry gas and coke were significantly reduced.

The isoparaffins in the gasoline were 34 vol% higher.

Clean gasoline and olefin process. The two-zone riser configuration has added superior controllability to the FCC reactions, and it can dramatically increase propylene yield while improving the quality of gasoline. Compared with the isoparaffin process, the clean gasoline and olefin reactor is operated at higher temperature and longer residence time in Zone 1 of the riser, for deeper catalytic cracking reactions to increase the propylene yields. The recycled catalyst increases the catalyst-to-oil ratio to an even higher level in Zone 2, and some gasoline olefins can 88

I SEPTEMBER 2011 HydrocarbonProcessing.com

40 Isoparaffin process Clean gasoline and propylene process

35 30 25 20 15 10 5 0

1990 1991 1992 1993 1994 1995 1996 1997 1998 1990 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010

TABLE 1. Comparison of FCC and isoparaffin unit in Sinopec Gaoqiao

Incremental gross profit offered, $ million/yr

SPECIALREPORT

FIG. 4

Historical back-testing of profitability over conventional FCC. (Based on US Gulf Coast price and 1.4 million tpy unit.)

be selectively cracked further into propylene. At the same time, more gasoline olefins are converted to isoparaffins and aromatics in Zone 2, in the way similar to the isoparaffins process. It is the combination of catalyst formulation and specific operating conditions in the two-zone riser that produces both the higher yield of propylene and better quality gasoline than a conventional high-severity FCC. The clean gasoline and olefin catalyst has an unique matrix and pore structures and acidity distributions to maintain proper activities, even after being coked in Zone 1 of the riser.3,5 To maximize the propylene yield, an active component with the MFI structure was mixed into the catalyst during its preparation.

A metal element was also added to enhance cracking gasoline olefins to propylene. The new catalyst design can retain the active sites after passing Zone 1, and continue to promote hydrogen transfer and cracking reactions in Zone 2.

Since 2004, to meet the market demand for production of both clean gasoline and propylene, 18 clean gasoline and olefin units have been installed in China (15 revamps of FCC and three grassroots units), with capacities ranging from 0.5 to 3 million tpy.

The unique design features of clean gasoline and olefin are similar to those listed in the isoparaffin process with the exception that a proprietary catalyst and different operating conditions are required. Applications of the clean gasoline and olefin technology have shown several advantages over conventional FCC: • Cleaner gasoline • Reduction of olefins (20%–50%), sulfur (20%–40%) and benzene (up to 33%) • Improved octane number • Higher yield of propylene (up to 9 w% of feedstock) and LPG • More isobutane (up to 40%) in LPG • Less dry gas and slurry.

Table 2 lists performance test data of the clean gasoline and olefin unit at Sinopec’s Jiujiang Petrochemical Branch Co. Table 2 shows that the clean gasoline and olefin technology had reduced olefins and sulfur in gasoline by 67 vol% and 23 vol%, respectively, while propylene yield (based on the feedstock) increased by 2.7 wt%, compared to the residue FCC unit before

REFINING DEVELOPMENTS revamp. The research octane number (RON) of gasoline was significantly improved.

Economic benefits. At present, there are a total of 35 clean

gasoline and olefin and isoparaffin units operating in China, with many more units in the design or construction phase. The total throughput of the units has reached more than 50 million tpy, accounting for about 50% of the total FCC capacity of China.

Performance data from the operating gasoline and olefin and isoparaffin units showed that even with inferior feedstock qualities, the yields of dry gas, slurry and coke are reduced on average by more than 1.5 wt%, while cleaner gasoline and/or more propylene are produced.

On average, the olefins and sulfur content in gasoline were reduced 14.3 vol% and 28 vol%, respectively, while the RON and MON increased 0.4 and 1.2 points. Commercial data has also shown that gasoline and olefin and isoparaffin units consume less energy than conventional FCC units. This benefit is primarily attributed to the lower feed pre-heat temperature and less reaction heat required in the two-zone risers.

Fig. 4 shows one of the historical back-testing results of gasoline and olefin and isoparaffin unit profitability over conventional FCC. It is clear that both gasoline and olefin and isoparaffin units would always be more profitable than conventional FCC, although the profit margins appear to fluctuate with prices of feedstock and products. The profit margins of gasoline and olefin unit would be more sensitive to market demand, especially with regard to propylene prices.

TABLE 2. Comparison of FCC and clean gasoline and propylene process in Sinopec Jiujiang Items

FCC

Clean gasoline and propylene process

895.1

909.7

Feedstock Density, kg/cm3 CCR, m%

3.86

4.59

H content, m%

12.78

12.58

Saturates content, m%

60.61

57.26

Aromatic content, m%

22.22

30.02

61.4

65.0

509

496

–

524

0.184

0.186

6.1

6.0

Activity of equilibrium catalyst Operating conditions Riser outlet temperature, °C Temperature of 1st reaction zone, °C Reactor pressure (G), Mpa Ratio of catalyst to oil Product distribution, m% Dry gas

Continuing development. Dry gas and coke are the FCC

byproducts with low added value. The yields of these byproducts can be significantly decreased by using the flexibility of the twozone riser operations. The same level of catalytic cracking conversion can be reached either by a higher temperature with a lower catalyst-to-oil ratio, or by a lower temperature with a higher catalyst-to-oil ratio. Experiments have shown that the temperatures and catalyst-to-oil ratios in the two zones of the riser can be readily optimized and controlled to minimize dry gas and coke at the same conversion level as a conventional FCC. Aromatics in the gasoline from the new process are in a range of 10 vol%–25 vol%, which is well below the allowable aromatics limits of 40% or 35% in the standards (Fig. 1). An effective way to improve the octane number is to shift some aromatics from light diesel to gasoline. Efforts are ongoing in researching new ways to convert light diesel into premium gasoline components. Light diesel contains a high percentage of mono-aromatic rings with long alkyl branches. These long alkyl branches can be catalytically broken from the aromatic rings in the two-zone riser to produce more premium gasoline components that are rich in isoparaffins and mono-aromatic rings with short alkyl branches.

The gasoline can have a high octane number (RON > 100) and antiknock index, while benzene content is less than 0.5 wt%.

The olefins content in the gasoline from the new processes, is predominately iso-olefins, which is much lower than that in conventional FCC gasoline. For this reason, the octane loss from olefins saturation in the downstream desulfurization hydrotreatment will be much less than that seen for conventional FCC gasoline. Studies and experiments have shown that the octane loss of gasoline in hydrotreating is less than 0.2 RON, in comparison with the loss of 1.0 RON for conventional FCC gasoline in the same level of desulfurization severity.

SPECIALREPORT

3.7

3.5

LPG

19.1

27.4

Gasoline

40.7

38.2

Diesel

21.9

16.3

Slurry

5.2

5.1

Coke

8.9

9.0

Loss

0.5

0.5

Sum

100.0

100.0

Total liquid yield

81.7

81.9

Propylene yield

6.3

9.0

Olefin content, vol%

41.1

13.4

RON

91.6

93.5

Gasoline properties

MON CST, m%

83.9 9.52

7.30

Looking ahead. The innovative two-zone riser reactor has been developed and applied for two new FCC technologies.

Gasoline quality produced from the new gasoline and olefin and isoparaffin technologies has been dramatically improved by decreasing olefins, sulfur and benzene with an increase in gasoline octane number when compared to a conventional FCC. HP LITERATURE CITED Worldwide Fuel Charter, Fourth Ed., September 2006.

2 Long, J., Y. H. Xu, J. S. Zhang and M. Y. He, “Research and Development of Maximizing Iso-Paraffins (MIP),” Technology, Engineering Science, Vol. 1, No. 2, December 2003.

3 Gong, J. H., Y. H. Xu, C. G. Xie, J. Long, et al., “Development of MIP Technology and Its Proprietary Catalysts,” China Petroleum Processing and Petrochemical Technology, No. 2, June 2009.

4 Cheng, C. L. and Y. H. Xu, “The MIP Technology and Its Commercial Application,” China Petroleum Processing and Petrochemical Technology, No. 2, June 2009.

5 Qiu, Z. H., J. Long, H. P. Tian and W. Peng, “Development and Application of the CGP-2 Catalyst in the MIP-CGP Process,” China Petroleum Processing and Petrochemical Technology, No. 4, December 2007.

1

Author biographies and photos available online at www.HydrocarbonProcessing.com.

HYDROCARBON PROCESSING SEPTEMBER 2011

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REFINING DEVELOPMENTS

SPECIALREPORT

Maximize propylene from your FCC unit Innovative use of catalyst and operating conditions increases on-purpose olefin production J. KNIGHT and R. MEHLBERG, UOP LLC, A Honeywell Co., Des Plaines, Illinois

propylene demand and supply contribution by source. Although conventional-fuels-based FCC yields approximately 4 wt%–6 wt% of propylene; operating conditions, catalyst system and technology via revamps can increase propylene yields by as much as 5 wt%. In addition, new technologies are now available for both revamp and new unit applications and that enable propylene yields over 20 wt%. The fundamental question remains, what is the most economic propylene production solution from an FCC that takes into account the following: 10

Demand Ethanol MTBE

Prices

8

6 2000

2005

2010

2015

2020

2025

Data Source: Global Petroleum Market Outlook 2011, Purvin and Gertz

FIG. 1

Gasoline demand growth and ethanol contribution.

120 New FCC Based C3=

FCC on-purpose Refinery/other (incl. FCC) Steam cracker

100 80 60 40 20

2020

2019

2017

2018

2015

2016

2013

2014

2011

2012

2009

2010

2007

0 2008

outlook in global propylene demand will outstrip co-production from available ethylene crackers, FCC units and other sources.

This anticipated supply gap is expected to be filled through additional on-purpose propylene production from FCC units and other on-purpose cracking solutions. Fig. 2 provides the expected

Ethanol

2005

Worldwide propylene. In contrast to gasoline, the 10-year

Imports Production-exp.

CAFE

Propylene demand, million metric tpy

In general, demand for clean transportation fuels will outpace demand growth for other refined products; this is an encouraging projection for the conversion-based refiners. Conversely, data indicates that the outlook for US gasoline demand to 2020 shows a lower overall demand and a gradual decline (Fig. 1). This demand behavior can be explained by a number of factors: • A sharp price increases since 2004 causing the first wave of demand destruction • The post recession recovery for US gasoline demand in 2010 is nearly 8% lower than its peak in 2004. It is expected to decline to less than 0.5%/yr.

• Ethanol blending is displacing petroleum-derived gasoline.

From 2000–2009, ethanol usage as a gasoline blendstock steadily increased to its present average level of 4.5 vol%.

• The Energy Independence and Security Act (EISA) was signed into law by President Bush in December 2007. The EISA mandates, among other items, transportation efficiency improvements that include: 0 By 2016, the CAFE (corporate average fuel economy) standards for new light duty vehicles will increase by 40%.

0 The Renewable Fuels Standard (RFS) calls for a total of 36 billion gallons/yr of renewable fuel by 2022.

0 Propagation of hybrid power train technologies.

Demand, million bpd

MARKET OVERVIEW

2006

F

luidized catalytic cracking (FCC) technology was developed to increase gasoline production derived from crude-derived vacuum gasoil (VGO) and, in some cases, atmospheric resids.

T his continues to be the primary objective. According to a Purvin and Gertz study, as of 2010, cracking-based conversion accounts for approximately 50% of the world’s refining capacity with an additional 10%–15% for the North American refining market. As fuels market needs to evolve, FCC technologies are being repurposed to produce high-grade petrochemical feedstocks along with transportation fuels. This article investigates FCC evolving operations to meet future market needs.

Data Source: CMAI 2010 World Light Olefins Analysis (WLOA)

FIG. 2

Expected worldwide propylene demand.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 91

SPECIALREPORT

REFINING DEVELOPMENTS

Propylene yield, wt%FF

24 Pure play C3= producers

18

12.5

12

feed 11.8

feed

6 0 Base FCC

FIG. 3

Increasing FCC processing severity

New technology

FCC propylene yield as a function of feed and reactor severity.

Gasoil FCC catalyst Naphtha olefins ZSM-5 -C≠CX

FCC catalyst +H

C3= X

C2=

FIG. 4

C4= C5=

X FCC catalyst +H

Paraffins Naphthenes Aromatics

FCC reaction pathways to produce olefins.

1. Expected fuels demand. Propylene production from an FCC has a direct negative impact on the quality of fuel products produced, in particular FCC naphtha. The impact is measured in terms of reduced naphtha yield and a shift in its molecular composition, 2. The highest propylene yield achievable given feedstock quality. The total potential for propylene from a particular FCC feed is determined largely by its hydrogen content.

CHEMISTRY OF PROPYLENE PRODUCTION

As the operating (reactor) severity of the FCC is increased, liquefied petroleum gas (LPG) and propylene production increases.

Propylene production is accomplished through the cracking of olefinic naphtha to lower molecular weight olefins. Fig. 3 shows that there is a broad, continuous range of propylene yield from FCC technology for a gasoline operation at 4 wt%–6 wt-% propylene to a petrochemical operating mode exceeding 20wt% propylene yield. This figure summarizes the general relationship between yields for propylene at increasing operating severities for different quality feedstocks.

Operating variables and chemical principles. Propylene

production from an FCC unit is framed by several factors that when combined with licensed technology provide the means for propylene/petrochemical modes of operation. These factors include: 92

I SEPTEMBER 2011 HydrocarbonProcessing.com

FCC feed quality is the most critical parameter in determining propylene production potential. There is a strong positive correlation between the FCC feed hydrogen content and propylene yield. Feeds that are richer in hydrogen are capable of producing more propylene largely due to increased feedstock conversion.

Furthermore, this potential for propylene is harnessed by the FCC technology and process conditions. The continuum of propylene yield as a function of technology and operating conditions is conveyed in Fig. 3.

The feed hydrogen content is responsible for the width of the band in Fig. 3. Refiners with upstream feed-pretreating capability may be able to leverage this condition to further extend propylene production capacity.

Unit conversion drives propylene yield and is closely related to feed hydrogen content. Propylene yield increases nearly linearly with conversion. A conversion increase is typically accomplished via rising reactor temperature and catalyst-to-oil ratio for a given feed and catalyst system.

In the catalyst system, two elements that must be considered are the formulation of cracking catalyst USY zeolite and the level of pentasil within the system. As shown in Fig. 4, the first function of the catalyst system is VGO conversion to naphtha olefins. The second function of a high-propylene catalyst system is a pentasil function to rapidly crack the naphtha olefins into light olefins.

Pentasil containing additives (ZSM-5) can increase propylene yield by a factor of two to three depending on the pentasil quantity. While ethylene co-production is generally understood, this is a kinetically controlled process that must be moderated for propylene maximization.

An additional consideration is the formulation parameters that mitigate hydrogen transfer reactions of olefins to paraffins and aromatics. The level of USY zeolite and its rare earth exchange directly impacts hydrogen transfer reactions.

The pentasil and the cracking catalyst must function cooperatively as a system, and the pentasil quantity must be balanced with the characteristics of the cracking catalyst.

Reactor hydrocarbon partial pressure can shift the FCC reaction equilibrium to favor low molecular weight olefins. The reduced partial pressure is achieved collectively with lowering operating pressure and the addition of reactor steam. An FCC utilizing new propylene technology fundamentals can operate at much lower partial pressure than a typical FCC while producing 50% higher propylene yields for the same feed, catalyst and conversion.

A major engineering study was conducted to determine the relationship between propylene yield and plant cost. Larger equipment is required to process the increased molar flow and to ensure the larger vapor volumes resulting from the higher light-ends yields. These principles can also be applied to existing units, though a partial pressure floor is imposed by throughput and equipment design. Results of this study are data, as shown in Fig. 5. The data describe the relationship between propylene yield and relative plant cost for a reduction in partial pressure.

Equilibrium. Pilot plant and commercial studies have determined that commercial-scale FCC operation at high severity and with a ZSM-5 enhanced catalyst system produces light olefins in an equilibrium distribution. This equilibrium limit was determined by extensive monitoring of high propylene FCC units, bench-scale pure compound studies and circulating riser pilot-plant testing. Fig. 6 shows the distribution of light olefins by carbon number in the riser effluent (red bars).

REFINING DEVELOPMENTS

COMMERCIAL APPLICATION

Considering that a base fuels FCC operation produces exreactor propylene yields in the range of 4wt%–6 wt%, we examine the requirements to further increase reactor propylene yield. Three categories can be defined that are characterized by the extent of scope, with each requiring additional capital and operational expense. For simplicity, these brackets do not consider the refiner’s base operation and configuration in terms of open capacity or propylene specific equipment. Considerations for open and available capacity include, but are not limited to: • Reactor section to address the additional molar flow • Regeneration section to address additional coke make due to higher operating severity • Recovery section to address change in vapor liquid distribution and propylene recovery • Treating section to meet the polymer-grade propylene product requirements.

Incremental reactor propylene yield above the Base Case is bracketed according to these factors: a. 3% to 5%—Achieved through modifications to the catalyst system (use of shape selective ZSM-5 additive, modifying the cracking catalyst formulation) and an increase in reactor temperature. Typically, such increases require only modest changes to the recovery section and a metallurgical check to determine capacity to accommodate the reactor temperature increase.

5x 3x

2x

Relative plant cost

C3= yield, wt% FF

C3= yield Plant cost

1x 1 1

FIG. 5

0

Partial pressure

Plant cost as a function for propylene yield.

56 Riser outlet partial pressure, kPa

Equilibrium calculations indicate that the light olefin products distribute by molecular weight and that this distribution is governed by thermodynamic equilibrium. Superimposing the distribution of light olefins from an equilibrium model calculation (blue bars) on the data from an FCC operating in enhanced LPG operating mode shows the C3–C5 olefins to be nearly in equilibrium.

This observation suggests that the reactions producing light olefins may be controlled by equilibrium. To achieve propylene yields significantly in excess of 12 wt% for an average FCC feedstock, we must consider technology that acts to shift the equilibrium.

To test the hypothesis of equilibrium-limited propylene, C3– C5 olefins were independently added to a VGO feed and processed in a circulating pilot plant with a high ZSM-5 equilibrium catalyst. The results validated the equilibrium hypothesis. When propylene is added to the VGO feed, the net propylene yield decreased from over 10 wt% to less than 4 wt% while at the same time, the net yield of C4–C8 olefins increased measurably. The independent addition of 1-butene decreased the net yield of total butenes and increased the net yield of propylene. The testing also showed that ethylene is also influenced by equilibrium, although not to the same extent, as residence time has the dominating effect. A comparison of the equilibrium calculations against the commercial unit data confirms that an equilibrium model of FCC reactions can be used as an accurate predictive tool. In short, reactions producing light olefins are controlled by an equilibrium mechanism and the thermodynamic equilibrium limits propylene production from the FCC. Based on this evaluation, a three-year comprehensive pilot plant, modeling and commercial benchmarking program were used to develop two models to handle the full spectrum of low to high-propylene FCC operations—the VGO and resid model and the olefin re-cracking model. The former augments the traditional yield and heat balance calculation with the effects of ZSM-5 interactions with reaction variables, while the latter describes riser cracking of light naphtha C4–C10 olefins over ZSM-5 modified catalyst systems.

SPECIALREPORT

Equilibrium

49 42

Equilibrium World-scale LPG + gasoline

Commercial High ZSM-5 Operation

35 28

High ZSM-5 Appears to Equilibrate C3= to C5=

21 14 7 0

FIG. 6

C 2=

C 3=

C 4=

C5=

C6=

C7=

C8=

C 9=

C10=

FCC light olefin equilibrium distribution.

b. 5% to 9%—Same as list in item a, along with reduced hydrocarbon partial pressure. This is achieved by lowering the reactor pressure and/or adding reactor steam. Implementation may require modifications to enable additional wet-gas-compression capacity, main column condensing capacity and sour-water condensing capacity. c. Greater than 9+%—Same as in item b, along with targeted recycle (LPG and light naphtha) and may also wish to consider the applicability of new maximum propylene technology. This represents the ultimate propylene production scenario and will require reconfiguration of the gas concentration unit to facilitate use of the targeted recycle. The new propylene technology will require extensive reactor/regenerator section modifications since a second reactor will be added.

European refiner. This refiner operates a stacked configuration FCC unit that was designed in 1960 for low conversion of VGO. This unit was the subject of a subsequent technology upgrade and feed capacity revamps over the last 40 years. In the late 1990s, the refiner commissioned a hydrocracker, resulting in a higher quality feed. Subsequently, an FCC revamp was commissioned to handle the higher conversion and increased yield of propylene associated with better quality feed.

Prior to the feed quality change and unit revamp, the unit yielded approximately 4.5 wt% propylene, and a marginal increase was expected with the hydrogen-rich feed. A major revamp was conducted as a high-conversion enabler. The scope of the revamp included adding a new riser separation system with improved feed distributors. This revamp enabled a conversion increase that resulted in a 4 wt% increase in propylene yield.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 93

SPECIALREPORT

REFINING DEVELOPMENTS

The refiner is considering further propylene production increases in conjunction with the catalyst manufacturer that would produce a propylene yield of nearly 13 wt%. This exemplifies increases in propylene yield that can be achieved as a result of FCC technology upgrades that enable effective increases in conversion and improvements to selectivities, a tuned catalyst system and feed quality improvements.

Other refiner. A refiner replaced its 1940s thermal catalytic

cracking (TCC) unit reaction section with a new high propylene FCC process so that it could substantially increase its propylene production through a simultaneous reactor-regenerator technology upgrade and a feed rate increase. Although a total reactorregenerator replacement was required, the product-recovery section was revamped for higher propylene yield and recovery, and a propylene-recovery unit was installed. It was commissioned to produce 140,000 metric tpy of polymer-grade propylene.

The new propylene-focused FCC unit was a major revamp of an obsolete cracking technology that substantially increased polymergrade propylene production. This refiner has achieved more than 16 wt% propylene using an Arabian Light VGO. Existing FCCs can be, and have been, converted for operations at or near high propylene FCC conditions. Recently, a newer FCC operating with enhanced LPG yields revamped its reactor section TABLE 1. Spent catalyst recycle impact on unit heat balance Base

Base + reactor process

Reactor temp, ºF

990

990

Coke, wt%

5.3

5.2

1,234

1,301

Regenerator temp, ºF Cat/oil ratio (Rx-Reg), lb/lb Cat/oil ratio (Riser), lb/lb Delta coke, wt%

FIG. 7

94

10.7

8.0

8.1

15.7

0.50

0.65

Latest maximum propylene technology configuration.

I SEPTEMBER 2011 HydrocarbonProcessing.com

to emulate the new high propylene FCC operations. As a result of this technology upgrade, this unit achieved an 18% increase in its propylene yield.

The new high propylene FCC technology utilizes low partial pressure, high reactor temperature, a ZSM-5 catalyst system and features spent catalyst recycle technology. The spent catalyst recycle technology recycles carbonized, active catalyst from the stripper to the riser mix zone where it is mixed with regenerated catalyst. Since the recycled catalyst is heat balance neutral, the spent catalyst recycle can facilitate a significant increase in the riser catalyst-to-oil ratio. This technology also helps to suppress the riser inlet temperature, which in turn reduces dry gas yields, and the higher catalyst-to-oil ratio contributes associated with its operation to higher conversion. It allows the catalyst/oil ratio to be increased well beyond typical limits imposed by a traditional FCC heat balance. This enables a higher ZSM-5 content in the riser at any specific ZSM-5 concentration in the circulating equilibrium catalyst inventory. Furthermore, applying the spent catalyst technology with a ZSM-5 enhanced catalyst system works to improve the catalyst’s effectiveness, thus increasing conversion of light naphtha olefin and selectivity from the catalyst-to-oil increase.

More on spent catalyst recycle technology. This technology can be used as a revamp option and can produce similar benefits including selectivity improvement and dry-gas management. In addition, because of its heat balance neutral effect, the net effect of the spent catalyst recycle is a delta coke increase that manifests as a regenerator temperature increase. This can prove to be invaluable for refiners processing severely hydrotreated feeds or is operating at a very low delta coke. Symptomatic of low delta coke operation is after burn and elevated carbon monoxide (CO) in flue gas that may require the elevated excess oxygen, an inefficient practice, and the use of CO promoter. Table 1 summarizes actual pre/post data for an FCC unit where the spent catalyst recycle technology was added to address the low regenerator temperature. Since its 2005 commercialization, the technology is operating in six units and is being designed or is in construction for an additional 12 units.

Commercial application. Because propylene production is equilibrium limited, recycling higher molecular weight olefins can be used as another technique to maximize propylene yields.

The linking of reaction equilibrium concepts with reactor and regenerator technologies results in the latest maximum propylene FCC technology. This latest technology—highest-yield propylene FCC process—uses a multi-stage reactor system comprising a primary hydrocarbon feedstock reaction stage, and a secondary recycle reaction stage utilizing a common regeneration stage with continuous circulation of fluidized catalyst between both reactor stages and the regeneration stage. The reactor/regenerator section is shown in Fig. 7. This system uses two reaction stages primarily to overcome equilibrium limitations to propylene yield and selectivity, and secondarily to maximize product flexibility.

For propylene production relative to the severity/feed quality continuum, the highest-yield technology is represented at the far right side of Fig. 8 for those refiners that choose to maximize the production of propylene.

This technology extends propylene yields to greater than 20 wt%. This substantial shift is achieved by the second reactor that recracks C4+ olefins to propylene. The second riser can be part of a major revamp, but plot plan considerations require case by

REFINING DEVELOPMENTS

greatest yield of propylene per unit cost of production. It can provide exceptional performance through the reduction of non-reactive diluents from the second-stage feedstock, which consists of only convertible species or those that participate in the equilibrium shift.

In a comparative study of 500,000 metric tpy propylene (50,000 bpsd fresh feed) units, application of the reactor technology required 12% less capital and 7% less operating cost per unit of propylene relative to a comingled product recovery system design. The lower expenses were due to decreased equipment sizes and the associated energy consumption. Moreover, the reactor technology produces a net reactor propylene yield in excess of 20 wt%, which exceeds the capability of currently available traditional FCC technologies.

REFINING/PETROCHEMICAL INTEGRATION OPTIONS

The FCC refining community will be faced with many interesting challenges over the next few decades. A shrinking forecasted US gasoline demand, coupled with potential economic and legislative factors will likely reshape the future for refining conversion. This will leave US refiners with the challenge of how to best utilize the expected open capacity while preserving the fixed asset base. As propylene demand grows, refiners can leverage their FCC technology through implementation of the concepts outlined in this article.

Propylene’s remarkable demand growth requires new technologies to capture growth opportunities. Until recently, refiners were able to capture incremental shifts that had been met with success for meeting local demand. The first principles for propylene production from an FCC unit lend well to understanding the propylene potential, reactor conditions and catalyst selection for achieving incremental in propylene production shifts. In particular, the influence of equilibrium and the introduction of equilibrium manipulation augment these first principles. Potential propylene yields in excess of current practice and convention underscore the necessity for new technology offerings that allow the refiner to achieve propylene yields well in excess of the current commercial experience. HP ACKNOWLEDGMENT Revised and updated from an earlier presentation at the 2011 NPRA Annual Meeting, March 21–22, 2011, San Antonio, Texas.

Riser pilot plant C4= conversion C4 – LCN recycle blend

C4= conversion, wt %

case evaluation. This latest technology provides the ability to deliver the maximum propylene yield from the conversion of traditional FCC feeds. It can be the ultimate solution to those refiners whose primary objective from their FCC has shifted to maximize propylene production.

The critical technology features of the latest maximum propylene process technology are: • Maximum riser containment. Each reactor riser is designed with its own proprietary riser termination device (RTD) and high-flux stripper to minimize post-riser vapor residence time.

The post-riser reactions that occur at high reactor temperatures that can favor propylene production are accompanied by non selective gas yields and the undesirable hydrogen transfer of olefins to alkanes.

• High catalyst to oil riser reactors. The reactors apply tightly contained riser reactor systems that operate at a very high (15–30) catalyst-to-oil ratio. Riser reactors were chosen over fluidized-bed reactors to minimize dilute-phase dry-gas formation and minimize hydrogen transfer reactions that are promoted by the extensive backmixing of fluidized bed reactors.

• Second-stage riser cracking. The spent catalyst recycle reactor technology allows the second riser catalyst-to-oil ratio to increase beyond typical limits imposed by heat balance. This enables a higher ZSM-5 content in the riser at any specific ZSM-5 concentration in the circulating equilibrium catalyst inventory.

Fig. 9 shows the second riser butene conversion and propylene yield increase with C/O ratio well beyond the 5–9 available from a traditional reactor configuration (without reactor technology).

This increases conversion per pass and decreases recycle in the unit against a specific propylene production target, and enables direct conversion of butenes to propylene in the second riser without an intermediate step of polymerization.

• Product recovery and targeted recycle. Effluent from each reactor is routed to independent main columns and partially integrated gas concentration. The first stage reactor effluent is routed to a standard main column with LCO, HCO and slurry products.

Naphtha and lighter material are taken overhead to an enhanced absorption based product recovery system. This recovery system recovers propylene and produces a superheated C4-light naphtha stream that is feed to the second stage reactor.

The second stage reactor effluent is quenched in a small column that preheats the fresh feed. The unconverted naphtha and C4reaction products are routed to a depropanizer and debutanizer.

This multi-stage reactor and product separation system can be the most capital selective design; this configuration produces the

Conventional FCC Enhanced propylene FCC High propylene FCC

SPECIALREPORT

20 C/O Higher conversion at constant ZSM-5 achieved with spent catalyst recycle 5 C/O

Latest propylene FCC technology 0

FIG. 8

5

10 15 Propylene yield, wt-% FF

20

Mapping new reactor technology on the propylene continuum.

25

ZSM-5, wt% FIG. 9

New reactor process contribution to butene conversion.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 95

Results

Linde has built a history of proven results with over 250 synthesis gas plants and 2,800 air separation plants installed worldwide.

As a world class supplier of synthesis gas and air separation plants, Linde Engineering and its subsidiary, Selas Fluid, provide single source responsibility for engineering, procurement and construction of complete synthesis gas and air separation plants.

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Investigate processing near-zero-sulfur gasoline This study considers the effectiveness of undercutting and hydrotreating fluid catalytic cracking feeds to yield ‘cleaner’ fuels D. STRATIEV, Lukoil Neftochim, Burgas, Bulgaria

P

rocessing near-zero-sulfur gasoline (NZSG) requires a significant reduction of sulfur from fluid catalytic cracking (FCC) gasoline. FCC gasoline contributes about 90% of the sulfur content in the finished gasoline pool. 1 There are advantages and disadvantages in hydrotreating FCC feed and in post treating FCC gasoline. The main technologies for reducing gasoline sulfur content have been widely discussed.2–7 It is well known that hydrotreating FCC feed considerably improves the economics of the FCC unit.8 However, there is no evidence confirming that hydrotreating FCC feed can consistently meet 10-ppm sulfur (S) levels for FCC gasoline over the long term.

Advances in catalyst technologies allow the FCC-feed hydrotreaters to meet ultra-low-sulfur gasoline (less than 50 ppm) level.9 However, NZSG production remains a challenge for FCC hydrotreating technology. An attempt was made in the Lukoil Neftochim Bulgaria (LNB) FCC unit to produce 10-ppm S FCC gasoline by increasing the severity in the FCC feed hydrotreater. This article discusses the results obtained at the LNB. FCC feed hydrotreater. The LNB

FCC unit consists of a feed hydrotreater section, FCC reactor-regenerator and main fractionator section, and vapor recovery section. More details about this unit is listed in the literature.10 The FCC feed hydrotreater is a Russian VNIINP design operating at 50 bars total pressure.

The reactor section consists of two reactors in series (Fig. 1). The unit was commissioned in 1982 with a design capacity of 32,000 bpd. Now, the unit is operating at 25% higher than the design capacity.

Table 1 summarizes the typical operat-

ing conditions of the LNB FCC feed hydrotreater. The unit processes heavy vacuum gasoil (HVGO) distilled from Ural crude oil. Table 2 lists the properties of this HVGO. From Table 2, the Ural HVGO contains a relatively high amount of arsenic (As), a known very strong and irreversible catalyst poison.

Since 2004, the LNB FCC feed hydrotreater has been using an advanc e d c o b a l t / m o l y b d e n u m ( C o Mo ) hydrotreating catalyst. With this catalyst type, the FCC unit can produce FCC gasoline with sulfur levels between 30 ppm and 50 ppm for operating runs exceeding 12 months. Fig. 2 lists catalyst deactivation data observed over 12 months during the usage of fresh and ex-situ regenerated CoMo catalyst. These data are obtained on the base of 1.6 order kinetics and activation energy of 32 kcal/mol. It was found earlier that a 1.6 order kinetics equation adequately describes hydrodesulfurization of HVGO by the LNB FCC feed hydrotreater.11 The data from Fig. 2 represent the second cycle ex-situ regenerated of the hydrotreating catalyst.

The first cycle was 24 months in length, and, during this cycle, the catalyst charge

in the first hydrotreating reactor absorbed 0.8% nickel (Ni) and 2.6% vanadium (V) and 0.53% As.11 After ex-situ regeneration, the catalyst from the first reactor was reloaded. Regardless of the high metals loading (as shown in Fig. 2), the regenerated catalyst exhibited activity not lower than 10°C of that of the fresh catalyst. The 10°C activity drop is typically reported for TABLE 1. Physical and chemical properties of HVGO, the LNB FCC hydrotreater feed Heavy vacuum gasoil Specific gravity

7.7

Refractive index, 20°C

1.51

Sulfur, %

1.67

Total nitrogen, %

0.1139

Ni, wt ppm

0.1

V, wt ppm

0.4

As, wt ppm

0.29

Total aromatics, wt%

39.9

1-ring aromatics

18.2

2-ring aromatics

10.0

3-ring aromatics

11.7

Distillation ASTM D-1160, °C/(D2887)

TABLE 2. Typical operating conditions in the LNB FCC feed hydrotreater

0.9119

Kinematic viscosity at 98.9°C, cSt

D-1160

D-2887

IBP

246

297

5%

362

344

Space velocity, h-1

1.2

10%

381

362

Total reactor pressure, kg/cm2

50

30%

413

405

Recycle-gas rate, Nm3/m3 oil

316

50%

441

438

70%

472

473

85

90%

513

521

100

95%

529

542

62

FBP

96.0

⌲w

Recycle-gas composition H2, vol% H2S, ppm (vol) Fresh H2 containing gas rate, Nm3/m3 oil H2 content in fresh H2 containing gas

588 11.85

HYDROCARBON PROCESSING SEPTEMBER 2011

I 97

SPECIALREPORT

REFINING DEVELOPMENTS

Hydrotreating reactors

HVGO Recycle H2 to amine treater

Recycle H2

Gas to amine treater

High-pressure cold separator Low-pressure cold separator

Charge heater

Heater

Flue gas to waste heat system generator Main fractionator

To wet gas compressor

Gas to amine treater

Steam Steam

Steam Sour water

Sour water Unstabilized gasoline to VRU

Steam

LCO

HCO

Stabilization column

FCC regenerator

Air blower

Diesel

Hydrotreated HVGO

Air

Steam

HT naphtha

FCC reactor

Heavy fuel oil

FIG. 1

Diagram of hydrotreating section, FCC reactor-regenerator and fractionation sections in the Lukoil Neftochim Bourgas FCC unit.

TABLE 3. LNB FCC unit data obtained at different severity for the FCC feed hydrotreater Day

1

2

3

4

5

6

7

8

9

FCC feed hydrotreater LHSV, h–1

1.2

1.2

1.2

1.2

1.2

1.2

1.2

1.2

1.2

First hydrotreating reactor inlet temperature, °C

347

356

356

366

366

367

367

367

374

Second hydrotreating reactor inlet temperature, °C

370

379

379

388

391

390

391

392

397

Second hydrotreating reactor outlet temperature, °C

375

384

384

391

393

395

395

396

399

WABT, °C

366

375

375

383

384

386

386

386

391

First hydrotreating reactor inlet pressure, kg/cm2

49.2

49.2

49.5

49.4

49.5

49.3

49.6

49.6

49.4

Second hydrotreating reactor inlet pressure, kg/cm2

47.1

47.1

47.2

47.3

47.3

47.1

47.2

47.5

47.4

Second hydrotreating reactor outlet pressure, kg/cm2

44.5

44.5

44.3

44.2

44.1

44.5

44.5

44.3

44.3

310

310

310

310

310

310

310

310

Hydrogen/oil ratio, Nm3/m3

310

FCC feed sulfur (stable hydrogenate), %

0.0690

FCC gasoline sulfur, %

0.0048 0.0037 0.0032 0.0025 0.0022 0.0022 0.0026 0.0025 0.0022

FCC feed sulfur/FCC gasoline sulfur ratio

14.4

0.045 0.0430 0.0235 0.0230 0.0228 0.0200 0.0210 0.0158

12.2

13.4

the ex-situ regeneration of high performance hydrotreating catalysts.12 Therefore, advanced CoMo hydrotreating cata98

I SEPTEMBER 2011 HydrocarbonProcessing.com

9.4

10.5

10.4

7.7

8.4

7.2

lyst proved to have high tolerance against poisoning by metals. The maximum allowable temperature of the LNB FCC feed

hydrotreater reactors is 420°C, which is equivalent to 414°C weight average bed temperature (WABT).

From Fig. 2, it is evident that the cycle length for the fresh catalyst could have been reached 20 months; whereas for the ex-situ regenerated high-metals loaded catalyst could have been used for 17 months. For this period, the LNB FCC unit was able to produce gasoline with less than 50-ppm sulfur content.

NZSG production. The NZSG must be

available in all European Union (EU) petrol stations beginning Jan. 1, 2009, according to European Union Directive 2003/17/ EC). However, production of NZSG must begin earlier to effectively flush lines, storage tanks and pipelines. In early 2008, the LNB FCC feed hydrotreater was loaded with a charge of fresh advanced CoMo hydrotreating catalyst. Two months after the catalyst charge loading a test was done in the LNB FCC unit to verify the unit’s ability to produce 10-ppm S gasoline. Table 3 summarizes the test results.

It was established earlier that the ratio of FCC feed sulfur/FCC gasoline sulfur was about 20.13 However, the data in Table

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SPECIALREPORT

REFINING DEVELOPMENTS

400 395 390 385

WABT, °C

380 375 370 365 360 355 350

Fresh catalyst Ex-situ regenerated catalyst

345

400

380

360

340

320

300

280

260

240

220

200

180

160

140

120

100

80

60

40

20

0

340 Days onstream FIG. 2

Normalized WABT of fresh and ex-situ regenerated catalyst for a 12-month operation cycle in the LNB FCC feed hydrotreater

TABLE 4. Sulfur mass balance of the FCC unit at high severity mode for FCC feed hydrotreater (unstable hydrogenate spill back) FCC feed hydrotreater inlet

wt% of FCC hydrotreater feed

HVGO Hydrogen containing gas

Sulfur, %

Sulfur, wt% of FCC hydrotreater feed

100.0

1.67

1.1

0.00

100

0.43

39.20

10.1

FCC feed pretreater yields, wt% Hydrocarbon gas FCC hydrotreater diesel

12.25

0.0080

0.1

FCC hydrotreater naphtha

0.64

0.2700

0.1

Hydrogen purge

0.29

0.0100

0.0

H2S

1.64

90.0387

88.4

Stable hydrogenate (FCC feed – hydrotreated HVGO)

85.9

0.0257

1.3

Unstable hydrogenate

99.2

0.1952

11.6

FCC riser feed sulfur,

%1

FCC reactor-regenerator, main fractionator and vapor recovery section yields, wt%

0.0766 wt% of FCC feed

Dry gas Propane-Propylene Fraction

5.0

Sulfur, %

Sulfur, wt% of FCC feed (stable hydrogenate)

0.9700

188.5

6.5

0.0050

1.3

Butane-Butylene Fraction

12.9

0.0017

0.8

Gasoline

51.8

0.0025

5.0

LCO

9.4

0.0333

12.2

HCO

4.4

0.1930

32.7

Slurry

6.0

0.1670

39.0

Coke

4.1

0.0176

Total

100

2.8 282

FCC feed sulfur/FCC gasoline sulfur ratio = 10.3 1

FCC riser feed = 69% stable hydrogenate + 31% unstable hydrogenate ; FCC riser feed H2S content = 525 ppm S

3 indicate that this ratio was lower than 20 during the test. This ratio decreased from 14.4 to 7.2 with an increase of the 100

I SEPTEMBER 2011 HydrocarbonProcessing.com

FCC feed hydrotreater severity. This was an indicator that a greater part of the FCC feed was converted to FCC gasoline. To

find explanation for that phenomenon, a sulfur mass balance of the FCC unit was done. Tables 4 and 5 present the sulfur mass balance of the FCC unit at moderate and high-severity operating modes of the FCC feed hydrotreater. These data show that the total FCC products contained more sulfur than the FCC hydrotreated stable hydrogenate (FCC feed) does. At moderate operating modes of the FCC feed hydrotreater, the total FCC products contained 128% sulfur of the stable hydrogenate. While at high-severity operations, the products contained 282%. Definitely the FCC riser feed consisted not only of stable hydrogenate. Analysis of sulfur at the FCC riser inlet showed sulfur levels higher than that of the stable hydrogenate.

It has also shown the presence of hydrogen sulfide (H2S). The stable hydrogenate did not contain H2S, and therefore, a leakage of unstable hydrogenate was assumed.

Sulfur balance. A careful check of the FCC technological scheme revealed a spill back of unstable hydrogenate in the stable hydrogenate. The spill back line were closed and immediately after that double reduction in H2S level in the FCC dry gas was observed. The sulfur mass balance in the FCC unit after exclusion of the unstable hydrogenate from the FCC riser feed (Table 6) indicated that sulfur coming with the dry gas (in the form of H2S) dropped about 2.4 times, and the ratio of FCC feed sulfur/FCC gasoline sulfur increased to 20.

This suggests that H2S plays a significant role in forming gasoline-range sulfur species during catalytic cracking.

For example, the data from Table 4 show 25-ppm S FCC gasoline and 257ppm S stable hydrogenate; thus, the FCC feed sulfur/FCC gasoline sulfur ratio is 10.3. If the ratio is 20 as observed after removal of the H2S from the FCC feed, then the FCC gasoline sulfur would be 12 ppm. Therefore, 13 ppm (52%) more sulfur is generated in the FCC gasoline resulting from the presence of 525 ppm H2S in the FCC feed. The data from Table 5 show that 54-ppm S FCC gasoline when the stable hydrogenate sulfur is 780 ppm, which means a FCC feed sulfur/FCC gasoline sulfur ratio of 14.4. At 20 for this ratio, the FCC gasoline sulfur would be 39 ppm. Therefore, 15 ppm (39%) more sulfur is generated in the FCC gasoline resulting from the presence of 315 ppm H2S in the FCC feed. The presence of H2S in the FCC feed in the range of 315 ppm S to 525 ppm S generated 13 ppm–15 ppm more sulfur in the FCC gasoline.

REFINING DEVELOPMENTS When the target was 50-ppm Sin the FCC gasoline, this condition was not an issue.

However, when the target is 10-ppm S any leakage is crucial.

All findings indicated that 10-ppm S in the FCC gasoline could be achieved when the sulfur level in the FCC feed is 200 ppm. The data in Table 3 show that 200ppm S in the stable hydrogenate can be attained at a WABT of 386°C (start of run temperature). The data on Fig. 2 indicate that from a WABT of 386°C on the catalyst deactivation rate is 4°C/month. With a maximum WABT of 414°C a cycle length of (414–386)/4 = 7 months is obtained for the fresh catalyst. If the catalyst is ex-situ regenerated, a cycle length of 4–5 months could be expected.

Undercutting FCC gasoline. The

FCC feed hydrotreater cycle length could be extended by undercutting the FCC gasoline. A higher sulfur level in the stable hydrogenate from the FCC feed hydrotreater could accommodate production of 10-ppm S FCC gasoline.

The gasoline in the LNB FCC unit was undercut at two severities in the FCC feed hydrotreater. Table 7 summarizes the results of undercutting the LNB FCC gasoline. At the first severity, the stable hydrogenate was 650 ppm S; that led to FCC full-range gasoline of 32 ppm S. Reducing the T 90 distillation gasoline point from 172°C to 152°C lowered the gasoline sulfur levels from 32 ppm to 19 ppm. The severity increase of 10°C led to a stable hydrogenate sulfur of 440 ppm and FCC full-range gasoline sulfur of 22 ppm.

Reducing the T 90 gasoline point from 172°C to 152°C cut the gasoline sulfur levels from 22 ppm to 14 ppm. Undercutting FCC gasoline lowered the sulfur content by 40%. However, the undercutting decreased gasoline yield by 4.4%.

The light cycle oil (LCO) in the LNB refinery is used to produce near-zero-sulfur diesel. Regardless of its high content of aromatics and nitrogen, the LCO distillation end boiling point is not higher than 300°C, which excludes the presence of the most refractory sulfur species. This material is easy to hydrodesulfurize to near-zero sulfur levels.14 The reduced total yield of high-value gasoline + LCO was 3%, and it was at the expense of higher yield of heavy cycle oil (HCO) + slurry; both are used to process fuel oil. At a difference in the price between regular gasoline and fuel oil of $748/ton (April 2008 data), this would be equal to $35 million/year profit loss.

SPECIALREPORT

TABLE 5. Sulfur mass balance of the FCC unit at low severity mode for FCC feed hydrotreater (unstable hydrogenate spill back) FCC feed hydrotreater inlet

wt.% of FCC hydrotreater feed

HVGO Hydrogen containing gas

Sulfur, %

100.0

1.67

1.1

0.00

Sulfur, wt% of FCC hydrotreater feed 100

FCC feed pretreater yields, wt% Hydrocarbon gas

0.23

58.79

8.2

FCC hydrotreater diesel

5.86

0.0277

0.1

FCC hydrotreater naphtha

0.32

0.3170

0.1

Hydrogen purge

0.21

0.0100

0.0

H2S

1.64

89.35

87.3

Stable hydrogenate (FCC feed – Hydrotreated HVGO)

92.8

0.0782

4.3

Unstable hydrogenate

99.2

0.2228

12.7

FCC riser feed sulfur, %1 FCC reactor-regenerator, main fractionator and vapor recovery section yields, wt%

0.1059

Sulfur, %

Sulfur, wt% of FCC feed (stable hydrogenate)

Dry gas

5.0

0.9659

61.7

Propane-propylene fraction

6.5

0.0050

0.4

Butane-butylene fraction

12.9

0.0017

0.3

Gasoline

3.6

wt% of FCC feed

51.8

0.0054

LCO

9.4

0.0686

8.2

HCO

4.4

0.3280

18.3

Slurry

6.0

0.4390

33.7

Coke

4.1

0.0249

Total

100

1.3 128

FCC feed sulfur/FCC gasoline sulfur ratio = 14.5 1

FCC riser feed = 79% Stable hydrogenate + 21% unstable hydrogenate ; FCC riser feed H2S content = 315 ppm S

The data in Table 7 (see Hydrocarbon Processing.com for Table 7) indicate that the mercaptan sulfur represents about 50% of the total gasoline sulfur. At high-severity hydrotreating of FCC feed hydrotreater, the mercaptans in the FCC feed are unlikely to remain. Mercaptans are the most reactive sulfur species in hydrotreating. Therefore, their origin in the FCC gasoline could come from recombination reactions of olefins with H2S in the FCC riser. Treating a sample of FCC gasoline with 15% aqueous solution of NaOH showed that mercaptan sulfur dropped from 6 ppm to 5 ppm, and the total sulfur levels dropped from 14 ppm to 9 ppm. If undercutting + caustic treatment is applied, NZSG could be produced in the FCC unit at feed levels of 440 ppm. In this case, the required start of run WABT in the FCC feed hydrotreater would be 370°C, which is equivalent to a 12-month cycle length. If no caustic treatment is applied, then the full-range FCC gasoline sulfur should be 15 ppm (300 ppm FCC feed sulfur) and the undercut gasoline would have 9-ppm S content. In this case,

the required start of run WABT should be 382 and a cycle length of 8 months could be expected.

Observations. The transition of ultralow FCC gasoline sulfur to near-zero FCC gasoline sulfur production is associated with more than threefold reduction of the cycle length for the FCC-feed hydrotreater.

The cycle length could be extended if undercutting of the FCC gasoline is applied. However, the profit loss in this case is too high to justify this option. Also, H2S appears to play a significant role in forming gasoline-range sulfur species during catalytic cracking. A more detailed study of the sulfur species in the gasoline samples in this work could shed more light about the origin of sulfur in FCC gasoline. HP LITERATURE CITED Petrov, St., D. Stratiev and D. Minkov, “Production of environmental friendly fuels in Lukoil Neftochim Burgas,” Oxidation Communication, Vol. 28, No 1, 2005, pp. 47–55.

2 Shorey S. W., D. A. Lomas and W. H. Keesom, “Improve Refinery Margins and Produce Low1

HYDROCARBON PROCESSING SEPTEMBER 2011

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REFINING DEVELOPMENTS

SOFTWARE • VIDEO • BOOKS

TABLE 6. Sulfur mass balance of the FCC unit at low severity mode of operation of the FCC feed hydrotreater (no unstable hydrogenate spill back) FCC feed hydrotreater inlet

wt% of FCC hydrotreater feed

HVGO Hydrogen containing gas Total in

Sulfur, %

Sulfur, wt% of FCC hydrotreater feed

100.0

1.67

1.1

0.00

100

101.1

1.67

100

FCC feed pretreater yields, wt%

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0.35

35.49

7.4

FCC hydrotreater diesel

6.25

0.0277

0.1

FCC hydrotreater naphtha

0.40

0.3100

0.1

Hydrogen purge

0.25

0.0100

0.0

H2S

1.64

89.35

87.7

Stable hydrogenate (FCC feed – hydrotreated HVGO)

92.2

0.0830

4.6

Unstable hydrogenate

99.2

0.2046

12.7

FCC riser feed sulfur, %1 FCC reactor-regenerator, main fractionator and vapor recovery sections yields, wt.%

0.0830 wt% of FCC feed

Sulfur, %

Sulfur, wt% of FCC feed (stable hydrogenate) 24.7

WinHeat suite provides all the tools for:

Dry gas

5.0

0.4100

Propane-propylene fraction

6.2

0.0050

0.4

• Modeling most fired heater • Generating Property Grids • Insulation and Heat Loss Computations • Air Preheat System Analysis • Ducting Design • ID and FD Fan Sizing • Tube Wall Thickness Calculations • Heater Draft Analysis • Combustion Analysis

Butane-butylene fraction

12.9

0.0017

0.3

Gasoline

51.2

0.0041

2.5

LCO

9.8

0.0800

9.4

HCO

4.1

0.3900

19.3

Slurry

6.8

0.5000

41.0

Coke

4.1

0.0399

2.0

Total

100

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102

Hydrocarbon gas

I SEPTEMBER 2011 HydrocarbonProcessing.com

1

Sulfur Fuels,” World Refining, 1999, pp. 41–48.

Salazar, D., R. Maya, E. Ariaca, S. M. Rodriguez and M. Aguilera, “Effect of hydrotreating FCC feedstock on product distribution,” Catalysis Today, 2004, Vol. 98, pp. 273–280.

4 Valla J. A., A. A. Lappas, I. A., Vasalo, C. W. Kuehler, and N. J. Gudde, “Feed and process effects on the in situ reduction of sulfur in FCC gasoline,” Applied Catalysis A: General, 2004, 276, pp. 75–87.

5 Platenga, F. L. and R. G. Leliveld, “Sulfur in fuels: more stringent sulfur specifications for fuels are driving innovation,” Applied Catalysis A: General, 2003, 248, pp. 1–7.

6 Ivanov, A. and G. Argirov, “Refining technology achievements to produce environmental friendly gasoline,” Oxidation Communication, Vol. 28, No 2, 2005, pp. 253–272.

7 Jaimes L., M. L. Ferreira, G. M. Tonetto and H. de Lassa, “Desulfurization of FCC Gasoline: Novel Catalytic Processes with Zeolites,” International Journal of Chemical Reactor Engineering, Vol. 6, 2008, Review R1.

8 “How FCC feed hydrotreating affects FCC yields and economics,” Sept. 1, 2007, http://rolblog. wordpress.com/.

9 Andonov, G., S. Petrov, D. Stratiev and P. Zeuthen, “MHC mode vs HDS mode in an FCC unit in relation to EURO IV fuels specifications,” European Refining Technology Conference 10th Annual Meeting, 14–16 Nov. 2005, Vienna, Austria.

10 Andonov, G., D. Stratiev, D. Minkov and S. 3

99.5

FCC riser feed = 100% stable hydrogenate; FCC riser feed H2S content = 0 ppms

Ivanov, “Bulgarian refiner evaluates effect of FCC feed hydrotreating catalysts on gasoline quality,” Oil & Gas Journal, Nov. 24, 2003, pp. 64–72.

11 Dobrev, D., D. Stratiev, P. Petkov, T. Tzingov and G. Argirov, “Fluid catalytic cracking Feed hydrotreating a way for production of ultra clean fuels,” Proc. 43rd International Petroleum Conference, Bratislava, Sept. 25–26, 2007.

12 UOP and Albemarle Presentation at the Lukoil Hydroprocessing Meeting, Moscow, Sept. 29, 2006.

13 Stratiev, D., T. Tzingov, G. Argirov and I. Shishkova, “Study examines production of nearzero sulfur FCC gasoline,” Oil & Gas Journal, April 14, 2008, pp. 54–61.

14 Stratiev, D., A. Ivanov, and M. Jelyaskova, “Effect of feedstock end boiling point on product sulfur during ultra deep diesel hydrodesulfurization,” Oil Gas European Magazine, No. 4, 2004, pp.

188–192.

Dicho Stratiev is an associate professor, PhD and chief process engineer with the Lukoil Neftochim Burgas, Bulgaria. He is an author of more than 100 papers. He has taken several positions in the research and production activities during his 20 years with the Lukoil Neftochim. He received an MS degree in chemical engineering and in organic chemistry and PhD and DSc in oil refining from the Burgas University.

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FLUID FLOW AND ROTATING EQUIPMENT

Optimize compressor configurations for hydrocarbon applications Extend the life of the compressor-driver package A. ALMASI, WorleyParsons Services, Brisbane, Australia

O

ne of the most important decisions a plant manager makes is the selection of the right centrifugal compressor train, especially given the context of emerging trends and challenges of modern compressor technology. As part of a comprehensive train optimization program, each compressor train component is examined to find ways to support goals of higher efficiency, lower cost, simpler maintenance and higher availability. Utilizing such a program can lead to higher total efficiency, higher train reliability and lower total cost of ownership. To optimize design and manufacturing, the compressor train concept should reduce the required manufacturing activities, simplify field assembly and extend the life of the compressor-driver package.

Compression unit arrangement. Regarding optimum

compressor configuration, in the basic design stage (early project stage), general questions about series or parallel arrangements, the optimum number of compressor units and standby requirements should be answered. The study of operating scenarios suggests certain requirements for the compression system. Beyond the quest for higher compressor peak efficiencies, the operating requirements usually require a compressor capable of operating over an operating range at reasonably high efficiency. Regarding compressor operation optimization, first consideration involves the capability to cope with changes in flow and head. Plant requirements determine the compressor operating conditions in terms of head and actual flow, and subsequently determine the required power from the driver. The second consideration deals with the fact that the nominal capacity may grow in revamp scenarios, future expansions, etc. The growth scenarios, if foreseeable, drive a compressor station layout to possibly allow additional train(s) or compression station(s) to be installed in the plant. The alternative scenario, where the consumption declines over the years (one example being that the gas supply from the field declines), is also a possibility.

Because the failure or unavailability of a compressor unit can cause significant loss in revenue, the installation of standby capacity may be considered. There is always great debate about the standby concept. In a majority of cases, standby unit are not required for API 617 centrifugal compressors. Modern centrifugal compressors can achieve an availability of 97% and higher. For a few very special processes, standby centrifugal compressor capacity may be considered. These standby capacities can be arranged such that each compression point has one standby unit (this is very rare), or that the standby function is covered by over-sizing all compressor trains and particularly drivers in each compression point. In this

case, failure of a compressor does not mean that the entire system ceases to operate, but rather that the flow capacity of the process is reduced. Since some processes, like gas pipelines, have a significant inherent storage capability (â&#x20AC;&#x153;line packâ&#x20AC;?), a failure of one or more compressors does not have an immediate impact on the total throughput of those processes. Additionally, in a typical compressor station with multiple compressor trains, planned shutdowns due to maintenance can be implemented during times when lower capacities are required.

Compressor configuration. Gas turbine drivers are used in

very large compressor units, in remote areas and where cheap fuel is readily available. Gas turbines are very popular in remote pipeline stations, offshore units, LNG large trains and large compression units for various gas or petrochemical plants. The gas turbines allow for immediate starting capability if the need arises. This is a unique feature and offers great advantages in applications such as gas pipelines where variations in demand are expected and timely response is required. Gas turbines are relatively expensive and in some cases have demonstrated relatively higher maintenance costs.

Electric motors are less expensive than other drivers, such as gas or steam turbines. They are efficient and they also require reduced maintenance compared to other drivers. All of this contributes to lowering the operating costs and increasing the compressor reliability and availability. From an emissions standpoint, they produce very low noise emissions and no exhaust emissions. Electric motor drivers have been increasingly used in recent years with the availability of the latest generation of high-power variable speed drives (VSDs). Electric motor with VSD features a very dynamic power control.

FIG. 1

An example of a compressor train.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 105

FLUID FLOW AND ROTATING EQUIPMENT Steam turbines can readily be speed matched to the compressor. Steam turbines have the ability to operate over a relatively wide speed range, which is ideal for the centrifugal compressor.

Good examples include some petrochemical units such as urea and methanol plants or some refinery units in which steam-generated on a large scale is used as part of a process or for a specific use. For a steam turbine driven centrifugal compressor train, the mezzanine type arrangement is common. Steam condensers, as well as inter- and after-coolers and other auxiliaries, are located below the train operating floor. In this configuration, downward compressor nozzles are usually applied (downward piping branches are preferred). But, depending on plant design, upward compressor nozzles are also used. The steam turbine condenser is installed beneath the train.

Motor driver considerations. Step-by-step, the electric

motor and VSD power outputs are increasing, and an 80 MW VSD electric motor is no longer considered a new or leadingedge. The compression marketplace is quite conservative and no one wants to be the first to try new technology. The size of the motor is mainly tied to the size of the VSD, which in the past has been the limiting component of the electrical chain, especially in the application of large-size induction motors. Competent motor

FIG. 2

An example of a gas turbine.

FIG. 3

An example of a steam turbine.

106

I SEPTEMBER 2011 HydrocarbonProcessing.com

manufacturers now offer high-power VSDs for both synchronous motors and induction motors.

Induction motors. VSDs for induction motors are generally versatile units that can also be used for synchronous motors. The VSD for induction motors is usually based on pulse width modulation (PWM) technology and uses the latest generation of highpower, insulated-gate bipolar-transistor (IGBT) press packs. In combination with induction motors, these converters significantly enhance compressor performance in terms of efficiency, ease of maintenance, low noise and vibration levels. There is no need for harmonic filtering because these converters have been specifically designed to eliminate the most powerful harmonic currents. Extensive harmonic studies on these units have demonstrated that the total harmonic distortion is lower than 2% at every operating point.

The VSDs designed for induction motors are usually medium voltage frequency converters of the voltage source inverter (VSI) type connected to the high-voltage switchboard through transformers. The induction motor is fed by one or more converters according to the power in a fully redundant configuration. In case one converter has a maintenance outage, the motor can be operated at reduced torque by the other converter. VSDs for induction motors presently cover an approximate range of 1 MW to 40 MW. Synchronous motors. VSDs for synchronous motors are usually based on load commutated inverter (LCI) technology and use thyristors. The system is tailored to drive synchronous motor with powers over 10 MW with practically no upper limit. Limits could be set presently around 100 MW. Based on vendor information, units above 100 MW can also be constructed based on market request. Two technologies are considerably different. The transistor switching power technology of induction motor VSDs allows it to turn the transistor on and off at high speed to provide very fast protection, even with high levels of overload current flowing, for improved control. With thyristor technology, the control can only turn the thyristor on, and the current in the thyristor has to fall to zero to turn the thyristor off. Another major difference between the two systems is that the induction motor VSD allows control of the system up to 300 Hz, corresponding to a nominal speed of two-pole electric motors of around 18,000 rpm.

Variable speed induction motors are available for the highspeed drive of compressors. The possibility of operating these electrical machines at high speed allows direct coupling to centrifugal compressors without the need for a step-up gearbox, which is beneficial in terms of installation cost, maintenance, reliability and availability. Induction motors, given their construction simplicity (especially in their rotating components) are more apt to rotate at high speed. VSD drives can also be used when the speed of a compressor, for process reasons, has to be maintained rigorously fixed. This, at first glance, may seem a contradiction in terms, but it is not. If the grid is unstable, small frequency variations may reflect on the motor and thus on the compressor speed. If a variable speed drive is placed between the grid and the motor, this can ensure constant frequency current supply and thus a perfectly even rotation of the motor independently from the grid disturbances. This technology can also be used in soft-start and soft-stop systems. Confidence in the latest generation of VSDs is also gaining momentum in the various critical industries, and an increasing number of applications are foreseen in the near future.

New vs. old. Most attention is usually directed to the relatively new technology of the frequency converters and harmonics correction. There are also reports of problems and issues in matured and old-fashioned equipment technology. Despite the

FLUID FLOW AND ROTATING EQUIPMENT fact that transformers have been in the market since the 1880s, these are failure reports on the old-fashioned transformer instead of the frightening power electronics. Often the transformers used are undersized for the application. In some cases, since the very beginning of operations, the transformers experienced overheating, even when running at partial load. Thermographics is a very useful condition monitoring tool in such cases. Thermographic pictures taken of the equipment (such as transformer’s coils) can show extreme temperatures. Temperatures in excess of expected ones show problems. For example, expected temperatures for class F electrical insulated systems would be in the range of 120°C. Temperatures in excess of 130–140°C can be a good indication for further inspection and monitoring. The overheating leads to early failure-caused short circuits in various electrical systems. There are reports of coil failures of undersized transformers in less than a year of operation. In order to mitigate the overheating problem, and therefore allow continued and trouble-free operation, specially designed forced ventilation can be considered and installed.

Controlling by means of varying the speed is by far the most flexible and efficient way of adjusting the operation of the centrifugal compression trains to the demand of the unit. Under steady-state conditions, the operating conditions that the plant imposes on the compressor show a roughly quadratic relationship between head and flow (since pressure drops are mainly due to friction). In transient conditions, flow may change without instantly changing head. Efficiently controlling the unit with multiple compressor trains requires careful studies. If the compressor trains are about the same size and efficiency (majority of cases), control the train so that the task is accomplished with the smallest number of running trains, with the load evenly shared.

If the trains are different in size and efficiency (which is rare), it is often best to base-load the biggest and most efficient train and take the load swings with the smaller train. However, issues like different maintenance requirements, starting times and reliability have to be considered. Straightforward and simple answer cannot be expected. It is a complex issue.

Gear systems. Gear units are extensively used in centrifugal

compressor trains that are driven by electric motors or gas turbines. For compressor train optimization, considerable knowledge and experience of gear unit operation and selection are necessary.

Gear operation is a combination of rolling and sliding motions.

At first contact between two teeth, the motion is mostly sliding, but, as the two pitch circles become closer and closer, more and more rolling occurs. When the pitch circles intersect, and the teeth are on the center-line between the two shafts, the contact is all rolling. Then, as the teeth go out of mesh, there is progressively more and more sliding.

Gear units are designed, manufactured and selected using some basic rules and some useful codes. The gear unit bearings are based on a certain hydrodynamic or rolling element design and calculations, while the teeth have to withstand the operating fatigue stresses. These stresses are complex to calculate and evaluate. Extensive simulations, studies and rigorous design reviews are required for gear units. Hertzian fatigue loading studies of the gear contact surfaces, similar to a rolling element bearing; plus sliding friction and the lubrication demand review for all pairs of surfaces that involves both sliding and rolling are required for a successful gear unit. Most industrial gear units are using hardened gears somewhere between HRC 54 and HRC 63, and they should never show measurable wear or pitting. It is necessary to understand the gear

contact pattern. The ideal is to have a contact pattern completely across each tooth that is uniform all around each gear. This design is based on full contact, but sometimes there are machining or assembly errors and other times there is distortion of the housing.

Consequently, tooth stress can increase tremendously.

Proper specifications will address these effects. Normal dedendum wear is fine pitting seen in the dedendum of teeth. It occurs after millions of load cycles, when a minimal oil film and sliding contact put the tooth surface into tension. The result is minor cracking and pitting, and slow removal of the dedendum surface.

Destructive pitting. Destructive pitting happens when the lubricant is grossly overloaded and large or sharp pits develop.

The result is a noisy and rough gear in serious trouble with rapidly increasing damage. If the pits are relatively small and well rounded, they can support the lubrication film and the gear will last a long time. At the other extreme, large irregular pits destroy the lubrication film. Sharp and linear pits can cause formidable stress concentrations. Normal dedendum wear results in slow and measurable tooth deterioration which typically allows for a relatively long and predictable life.

Destructive pitting, though, will rapidly grow rougher and noisier, and may result in a catastrophic failure. Early in the gear’s life, it may be difficult to determine if the wear is corrective or destructive, but with corrective pitting the wear rate rapidly drops off. The most common other damage seen on gears occurs when the teeth are so heavily loaded that plastic deformation occurs.

This is commonly called rolling, where metal is rolled or pushed up the active faces of the teeth, and peening, where the shape of the tooth is hammered irregularly until it is no longer an involutes curve. In both rolling and peening, the tooth form is slowly destroyed and both mechanisms show that either the gear is very heavily loaded or there is poor lubrication. The amount of allowable wear depends on the possible consequences of a failure.

With a critical application, the loss may be limited to only 15%. It shows the importance of routine inspection of gear units.

The best advice regarding special purpose gear units for critical compressor trains is the use of an API 613 gear system. API 613 in many places refers to superior selections of codes. Good collections of specifications, metallurgical, design, manufacturing, inspection and test requirements are noted in this code which allows optimum gear unit selection and proper train operation.

Compressor considerations. Competent vendors use state-

of-the-art interactive design and prediction (simulation) tools to optimize aerodynamic, performance and increase efficiencies of compressor flow-path, particularly impellers. Compressor impellers and matched stationary flow-path components are developed using computational fluid dynamics (CFD) analyses and other modern design tools.

Three-dimensional (3D) blade profiles, diffuser flow angles, crossover bend curvatures, area ratios, and return channel vane shapes are optimized for each impeller stage to provide the best possible efficiency and reliability. Additional performance enhancements are achieved by improving the flow distribution channels at the inlet and discharge volutes. These enhancements allow providing some of the industry’s highest operational efficiencies in aerodynamic field for centrifugal compressor 3D impellers.

A key achievement of modern compressor technology is the ability to offer superior, 3D closed-type impeller designs which maximizing performance over a broad range of pressure and flow applications. To verify predicted performance, extensive singleHYDROCARBON PROCESSING SEPTEMBER 2011

I 107

FLUID FLOW AND ROTATING EQUIPMENT

FIG. 4

An example of a modern closed type impeller.

stage testing is performed for each family of 3D impellers. These tests data and information are considered manufacturer proprietary and are not delivered to buyers. Based on experience only some data may be obtained in bidding stage before machine order.

Remember: That after order, vendors only send the machine (each casing or let say combined impeller package) performance curve and data. Fig. 4 shows an example of modern closed-type impeller.

Flow stage ratings. Higher and lower flow stage ratings are derived from the prototype test data to form a family of impellers.

Within each stage family, impeller geometry is fixed; blade heights are varied for higher or lower flows. Using this methodology, several stage families are used to span the desired flow coefficient range. Impellers and stationary components are then scaled up or down for different frame sizes.

For maximum flexibility, aerodynamic components are also scalable within each compressor frame size. Modern impeller manufacturing uses five-axis milling to ensure the quality of the impellers. Impellers are stress relieved, machine finished, balanced statically and dynamically, spin tested, and then mounted with an interference-fit onto the shaft.

Compressors use either fabricated steel diaphragms or a combination cast-and-fabricated steel design. Precision machining ensures dimensional accuracy and significantly improves the diaphragm surface finish. Nearly all diaphragms are horizontally split and finished at all horizontal and peripheral joints and on gas path surfaces.

Optimizing rotor-system design requires extensive researches in the fields of rotor-dynamic stability, aerodynamic cross-coupling stiffness, and rotor-bearing systems. Competent vendors usually have developed proprietary analytical tools for this purpose.

The general trend is to increase rotor stiffness by increasing shaft diameter, reducing impeller weight, and increasing journal bearing sizes. This allows higher torque transmission capabilities and higher-speed operation, with improved rotor stability characteristics, which are essential as gas densities and operating pressures increase. One of the most important factors influencing overall compressor reliability is the rotor-dynamic stability and its response to the unbalance forces.

API 617 covers requirements of rotor-dynamic stability and rotor-dynamic behavior. Compressor manufacturers should be regulated to satisfy all the requirements of this standard without exception. However, some additional requirements can be added on top of the requirements of API 617 to enhance reliability of 108

I SEPTEMBER 2011 HydrocarbonProcessing.com

the compressor. A good recommendation is that the unfiltered vibrations measured during mechanical run tests is limited to 80% of API 617 limits for balanced rotor (for example, a 20μm peak-to-peak unfiltered vibration compared to a 25μm API 617 limit for operation around 12,000 rpm).

Most mechanical running tests are carried out in a vacuum and, therefore, this vibration limit should be lowered at test conditions. This will require tight manufacturing tolerances and sound balancing of individual rotor components and rotor assembly during fabrication to ensure improved reliability of the machine in the field. For compressors with long strings (multi-casing compressors known as complex trains), train torsional analysis as per API 617 should always be specified. Reference and compressor manufacturer past experience of similar applications should be evaluated for aero-dynamics-induced “cross-coupling forces” encountered causing excessive vibrations and instabilities in the shop and in field tests.

Foundation and civil design. Designers should specify the required concrete tensile strength to ensure the foundation has sufficient strength to resist the dynamic forces. Standard concrete cannot receive epoxy grouts for approximately 28 days because of excess free water in the concrete. Steel fibers, placed in the concrete at the time of mixing and cast, help control plastic-shrinkage cracking and increase the tensile strength of the concrete. The increased tensile strength enables the foundation to better resist cracking caused by compressor dynamic forces.

Modern anchor bolts for compressors and drivers are typically made of high-strength steels such as B-7, with strength around 700 Mpa. In older compressor foundations bolts, tensile strength was typically 250 Mpa (comparable to St 37, with tensile strength around 37 ksi). When designed properly, the increased strength of the bolts enables greater clamping force of the machine to the foundation and a smaller bolt diameter. Research on compressor anchor-bolt design has shown that a termination point at the bottom section of the anchor bolt cast into the concrete will reduce the local tensile stresses in the concrete. J-bolts and L-bolts are not recommended. An industry standard practice is to use a heavy hex nut, economical and readily available, as the termination point for an anchor bolt. Spherical washers should be used whenever anchor bolt preload is critical, such as on vibrating rotating equipment. Spherical washers allow the anchor bolt clamping forces to be transferred uniformly across the bearing surface, rather than concentrating at one side of the washer and nut if the anchor bolt is slightly misaligned. Spherical washers offer an economical method of ensuring the anchor bolt loads are transmitted to the foundation.

A precision, non-shrink grout should be used on rotating equipment so that the void between the reinforced concrete foundation and the equipment bearing surface is completely and permanently filled. Concrete has a tendency to shrink as it cures and, therefore, will leave a small void or cause a misalignment of the equipment. Cementitious non-shrink precision grouts were used many years ago, but should not be applied now.

Epoxy grouts. Around 1955, epoxy grouts were developed for use in the petrochemical industry for applications such as gas compressors and for rotating equipment in caustic areas. Epoxy grout has a much higher compressive strength compared to its cementitious counterpart. Epoxy grouts range in compressive strengths from approximately 85 Mpa to 140 Mpa. Its real value comes from it being impervious to lubricant oils and chemicals, and the ability to endure impact from vibrating equipment. The only acceptable grout for modern rotating

FLUID FLOW AND ROTATING EQUIPMENT machine is epoxy grout. Epoxy grouts provide the most effective transfer of static and dynamic loads from heavy rotating equipment to the foundation. Because the linear thermal expansion coefficient of epoxy grouts is typically two to four times that of standard concrete and steel, appropriate material properties must be designed into the expansion joints. Viscosity is another important property in choosing the appropriate epoxy grout, specifically viscosity, during installation.

A product that has desired properties during the final cure, such as a high compressive strength and low creep, may not have a viscosity that will enable straightforward installation. In this case, the epoxy will not make adequate contact with the entire bearing area of the equipment. Epoxy grouts offer a much greater dampening effect to damp vibrations. Oil-resistant sealants, such as a room temperature vulcanizing (RTV) silicone sealant, are a cost-effective solution for seal expansion joints, chock perimeters and the epoxy-chock interface with the compressor frame. RTV silicone will prevent oil and other contaminates from penetrating into the joints and interfaces of the foundation.

and arrangement. Various configurations of centrifugal compressor trains (including electric motor, gas turbine and steam turbine driven packages) are discussed. The VSDs are composed of complex equipment and many complicated electrical, electronic and mechanical systems. Usually, a complex combination of transformers, frequency converters, harmonic filters and cooling systems are required. Modern and latest technology components, as well as old-fashioned equipment such as transformers, should be covered for comprehensive design reviews and inspection programs to ensure the performance and long-term reliability of compressors and power systems. HP LITERATURE CITED Haight, B., “Dresser Rand sells 700th datum centrifugal compressor,” Compressor Tech Two, October 2009.

2 Bloch, H., Compressor and Modern Process Applications, John Wiley, New Jersey, 2006.

3 Chellini, R., “Synchronous and induction motors for compressor drive,” Compressor Tech Two, October 2007.

1

Conclusion. Modern centrifugal compressors and their driv-

ers combine comprehensive modern processes, aerodynamics, mechanical and control knowledge and technologies. The latest manufacturing processes and state-of-the-art machine tools are used to produce them. As a result, modern multistage centrifugal compressor trains lead the compressor industry in both performance and reliability. Transient capabilities, growth capacity, flexibility, availability and total cost of ownership have been studied to offer optimized centrifugal compressor train design

Amin Almasi is lead rotating equipment engineer for Worley Parsons Services in Brisbane, Australia. He previously worked for Technicas Reunidas (Madrid, Spain) and Fluor (various offices). He holds a chartered professional engineer license from Engineers Australia (MIEAust CPEng–mechanical) and a chartered engineer certificate from IMechE (CEng MIMechE). He is also a registered professional engineer in Queensland and holds MS and BS degrees in mechanical engineering. He specializes in rotating machines, including centrifugal, screw and reciprocating compressors, gas and steam turbines, pumps, condition monitoring and reliability. He has authored more than 60 papers and articles dealing with rotating machines.

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ENGINEERING AND CONSTRUCTION

2011

CONTENTS

Special Supplement to

Consider critical issues during a plant turnaround E–113

Corporate Profiles Foster Wheeler E–119

Kock-Glitsch E-121 KTI E–123 The Linde Group E–125

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ENGINEERING AND CONSTRUCTION 2011

Consider critical issues during a plant turnaround L. AMENDOLA AND M.A. ARTACHO, Universitat Politècnica de València, Valencia, Spain; T. DEPOOL, PMM Institute for Learning, Valencia, Spain More project management practices are needed to improve performance in maintenance shutdown Plant shutdowns for major maintenance work are expensive, time-consuming and very complex. An adequate plant turnaround management plan is crucial for improving shutdown performance in terms of cost and time. Our analysis has revealed the most critical issues related to the four main stages of shutdown projects. The critical issues have been related to the most suitable project management practices (PMPs). Moreover, a study of the current use of these PMPs for shutdown projects has been made. Some 89 shutdown experts from 50 chemical firms took part in two separate studies (50 experts in Study 1 and 39 experts in Study 2).

The first study aimed to identify the critical activities and discover which PMPs are currently used by experts. The second study gathered expert opinions about the importance of the application of PMPs. The study identified 32 critical issues related to the main stages of the plant shutdown process.

Derived from these activities, the experts identified 33 suitable management practices, mostly involved in the early stages of the process. However, the results of Study 1 show that most of the practices related to the early phases of shutdown management are not currently used. Most of the practices that are commonly used were judged as being “very important” or “essential.” However, most of the practices that are not in common use were also evaluated as “important” or “very important.” In summary, project management practices related to managing uncertainty during the early stages of a plant shutdown project are insufficiently established at present.

Turnaround impact. Plant turnaround has an important impact on company business plans. Plant shutdowns involve a high volume of work carried out by a large number of people working under pressure and extreme time constraints.1 Thus, proper plant turnaround management is crucial for improving shutdown performance in terms of cost, time, safety and quality. This study analyzes the current managerial skills in plant shutdown projects in the hydrocarbon industry.

The objective of this work is threefold: to find the critical issues involved in plant shutdown processes; identify the existing PMPs related to these issues; and discover the state of the art of PMP application and the importance attributed to these practices by experts. To achieve this, the authors have employed the stategate process proposed by Mr. Amendola as the starting framework. This framework divides the general process into four stages: strategic planning; goal and task definition; execution; and closeout.

The work has been made in two separate studies. In an initial study, the critical issues have been established by experts. These activities have been connected to the main stages of the general shutdown process and related to existing PMPs. Finally, the experts showed which PMP were being used to manage their current shutdown projects.

In a second study, a group of different experts in plant shutdown projects indicated the importance they attach to the PMPs selected in the first study.

Data gathered will enable management teams to discover which practices are currently used, which practices are not in use, and the importance that technicians and plant operators attach to these practices. An understanding of the state of the art of PMP and the repercussion on turnaround practitioners is necessary to improve current managerial skills in this area.

Study objectives. The study has three main objectives: identify critical issues per phase and relate these issues to PMPs; identify which PMPs are used by experts; and, finally, to discover the opinion of experts about the importance of the application of management practices—regardless of whether the experts are applying these practices.

Firstly, a focus group was performed to list and select the most critical issues related to the four stages of the turnaround process. The experts then identified the most suitable PMP related to the selected set of critical issues. Five project management experts and four plant shutdown managers took part in this study— which was divided into two sessions lasting five hours.

Once the PMPs were identified, a questionnaire was prepared to establish if experts used the selected practices. Some 50 experts from 36 chemical plants indicated whether they “use” or “do not use” each PMP in their current working practices during plant shutdowns.

A two-tailed binomial test with normal approximation (p < 0.05) was used to check if significant differences appeared between the respondents for “use” and “do not use” and so discarding a chance effect in the “use of practices” selection.

A second study was carried out to discover the importance that managers attributed to selected practices (in a five-point ordinary scale from “unnecessary” to “indispensable”) in the management of shutdown projects. They also had the option to indicate if they needed more information about the advantages each practice could offer in shutdown management before judging its importance.

This second study involved some 39 experts in turnaround projects (different experts from those who took part in the first study) from 14 chemical businesses (petrochemical, refining and gas). A descriptive analysis was made to discover the frequency results for each importance category for each practice.

Results. Some 32 critical issues and 33 main PMPs were selected after the contribution from the focus group. These critical issues and PMPs can be seen distributed among the different phases of a shutdown project shown in Table 1.

Current PMPs. The results of a binomial test show that 17 out of 33 PMPs were often used by the experts, and 8 out of 33 were not currently used by experts to manage their shutdown projects. The eight remaining practices did not display any robust tendency for use or non-use.

Table 2 shows the accepted importance of project management practices (% of experts in each classification category). Basically, all the selected practices were rated between “important” and “very important”.

What was learned. This work shows the critical issues and PMPs related to each phase of a chemical plant shutdown. Some 32 critical issues and 33 PMPs have been identified. The shutdown experts easily reached a consensus when looking for critical issues. According to Amendola et al.,3 shutdown experts agreed that the early phases (Phase 1 and Phase 2) are the most critical of the process, and account for most of the critical practices found (two thirds of the total). It is worth adding that this work only focused on setting critical issues, irrespective of their relative importance. Identifying a hierarchy among critical issues could be an objective of future studies.

The present work shows the key points to bear in mind before managing plant shutdown projects. Furthermore, experts selected the most suitable PMPs HYDROCARBON PROCESSING ENGINEERING AND CONSTRUCTION 2011

I E-113

ENGINEERING AND CONSTRUCTION 2011

TABLE 1. Critical issues and PMPs in a plant shutdown process Critical issues

Project management practices (PMPs)

Num

Reviewing past events

Plant history review since last shutdown

P1

Monitoring performance

Database development of plant operation features to foresee and control possible events

P2

Formulating policies

Database development of historical equipment failures to foresee and control possible events

P3

Balancing constraints

Use of reliability techniques to fit the project scope

P4

Setting goals

Use of RAM (reliability, availability and maintenance) methodology to define the scope

P5

Leading a team

Use of strategic plan techniques (CMI, PEST, etc.)

P6

Identifying preliminary work

Monitoring the supply of materials and equipment

P7

Monitoring risk

Risk database development and identification of project affected areas

P8

Minimising cost

Personnel assignation to manage identified risks

P9

Defining and limiting the Scope

Risk analysis to forecast and control probable failures

P10

Planning the shutdown

Risk analysis to identify possible opportunities for improvement

P11

Identification of critical equipment during the turnaround process

P12

Risk analysis of critical equipment

P13

Use of risk analysis software

P14

Recording failures caused using FMEA

P15

Risk matrix application to set equipment requirements and frequency of inspection

P16

Development of a mechanical plan with maintenance time and cost of critical equipment

P17

Use of PMBOK guide or similar to manage shutdown project

P18

Setting targets

Delimitation of the work list using the planning thought process

P19

Identifying parts, materials and equipment required

Use of the OCR methodology (optimization, cost and risk) to plan and program turnaround

P20

Defining contingencies

Development of a mechanical plan with technical requirements of turnaround for critical equipment

P21

Reviewing contracts

Creation of a plan with detailed work tasks and personnel assignation

P22

Selecting people

Use of the critical path method to schedule the turnaround project

P23

Assigning responsibility

Use of the critical chain methodology to plan the turnaround project

P24

Forecasting cost

Use of decision tree tools to control event probabilities

P25

Monitoring performance

Use of project management software to program plant shutdown

P26

Use of team communication tools

P27

Controlling emergent work

Use of earn value management (EVM)

P28

Achieving duration

Work list updating to control planned work

P29

Minimizing expenditure

Use of management of chance process to face unforeseen events

P30

Monitoring safety, quality and cost

Use of any project management software for daily control plant shutdown development

P31

Resolving issues

Monitoring the effectiveness of risk control

P32

Reporting and documenting shutdown process, discoveries and needs for future work

P33

Strategic planning

Goals and tasks definition Translating policy into a defined project Fixing a cutoff date for job input before starting the shutdown

Execution Coordinating activities Controlling planned work

Closeout Analysis of performance Reviewing work done Extracting learning Recommending changes

to face critical issues at each phase. The set of PMPs includes the control of issues related to finance and strategy, risk analysis, supply chain management, reliability, availability and maintenance, cost optimization, use of best practices from the project management body of knowledge (PMBOK), decision making tools and management of change. Most of these PMPs are related to the early phases of E-114

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HydrocarbonProcessing.com

plant shutdown process (26 out of 33). Obviously, there are other PMPs that could be used in such complex projects, but the experts focused on the minimal set of PMPs required to guarantee a successful management performance.

Results of the analysis of practices used and not used reveal that 17 out of 33 practices are currently employed by chemical shutdown practitioners. Basically,

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ENGINEERING AND CONSTRUCTION 2011

Headline (2 lines)

TABLE 2. The importance of practices as attributed by experts (shadowed areas show the most often selected category for each practice) %Very %Unnecessary %Optional %Important important

%Indispensable

P1

0

0

10.3

38.5

51.2

P2

2.6

2.6

18.4

44.8

31.6

P3

2.6

2.6

10.3

51.3

33.2

P4

0

7.9

36.8

50

5.3

P5

0

9.1

39.4

48.5

3

P6

0

2.6

23.1

43.6

30.8

P7

0

2.5

10.3

43.6

43.7

P8

2.8

16.2

40.5

35.1

5.4

P9

2.6

10.5

47.4

34.2

5.3

P10

2.7

0

32.4

59.5

5.4

P11

2.8

2.8

52.8

38.8

2.8

P12

0

0

12.8

38.5

48.7

P13

0

0

27

46

27

P14

2.8

8.3

38.9

36.1

13.9

P15

0

0

7.7

53.8

38.5

P16

2.9

2.9

37

54.3

2.9

P17

0

5.1

41

43.6

10.3

P18

2.6

5.3

31.6

47.4

13.1

P19

0

0

15.4

43.6

41

P20

0

8.3

38.9

36.1

16.7

P21

0

5.1

28.2

46.2

20.5

P22

0

0

2.6

35.9

61.5

P23

0

0

18.9

48.6

32.5

P24

0

2.9

28.6

42.9

25.6

P25

2.9

5.9

50

35.3

5.9

P26

0

2.6

20.5

28.2

48.7

P27

0

0

23.1

33.3

43.6

P28

0

0

46.8

46.9

6.3

P29

0

2.6

23.7

47.4

26.3

P30

0

0

21.1

60.5

18.4

P31

0

5.1

17.9

56.5

20.5

P32

2.6

13.2

42.1

31.6

10.5

P33

0

2.6

21.1

34.2

42.1

the PMPs used by managers are related to strategy setting (P6), reviewing past events and historical data management (P1, P2 and P3), supply chain management (P7), basic risk analysis2 (P12, P13 and P15), work list definition (P19), team management (P22 and P27) and the use of project management software to plan, program and control project development (P23, P26, P29, P30 and P31).

It could be said that the most essential PMPs are currently used by practitioners.

However, more advanced practices are not implemented yet and these are related to: scope definition and project planning (P5, P20 and P24); how to turn risk into opportunity (P11); employment of advanced equipment maintenance (P16); use of risk software (P14); use of decision-making and problem-solving techniques (P25); and techniques to combine measurements of scope, schedule, and cost (P28). It is worthwhile mentioning that despite the importance of the early phases in properly managing this kind of project,3 7 out of 8 of the practices that are not E-116

I ENGINEERING AND CONSTRUCTION 2011

HydrocarbonProcessing.com

usually used are related to the early phases. This fact shows that there is still plenty of room for improvement in the management of phases related to strategy, goals and task definition.

Underused practices. A lack of proactive risk control is also shown, since practices devoted to risk control (P8, P10 and P21) are not usually used by experts.

Proper risk monitoring and control during shutdown project development (P9 and P32) are also underused, as a frequent use of these practices should be expected in the correct management of plant shutdowns. Other underused practices include: defining the scope (P4); developing a mechanical plan that encompasses time and cost requirements (P17); and using the principles of PMBOK to manage shutdown projects (P18). Using PMBOK as a guide to managing the plant shutdown process (P18) should be among the often used practices in order to take advantage of the main principles of project management. In this sense, it is interesting to note that using software to plan and control project development is common among practitioners, but it seems evident that using such software without applying the basic principles of PMBOK could lead practitioners to undesirable misunderstandings and inefficiencies.

With regard to the evaluations of the importance of various practices, despite the fact that practices were evaluated by different experts from those in Study 1, the results are basically coherent with the “use/do not use” tendencies. PMPs were mostly marked as “very important”, except for seven PMPs that were evaluated as “important” and seven PMPs that was considered as “indispensable”. All of the PMPs line considered as “indispensable” are currently used by the experts (see Table 2).

Two caption However, half of the unused practices were also mostly evaluated as “very important” (P5, P16, P24, and P28), and the remaining non-used PMPs were considered as “important” (P11, P14, P20; andP25). In this sense, practices without a clear use or non-use tendency were also evaluated as between “very important” (P4, P10, P17, P18 and P21) and “important” (P8, P9, and P32). It is worth adding that these last practices were also the practices most often considered as “optional” and “unnecessary”—although by a very small proportion of the experts.

Regarding knowledge of practices, only six out of 39 experts said they needed more information about the advantages that five of the 33 PMPs (P5, P16, P24, P25 and P28) could offer. Thus, it could be concluded that the selected PMPs were generally well known by the experts. So it is difficult to say if the tendency to not use some PMPs is a consequence of ignorance about the PMP among practitioners. A more in-depth analysis seems necessary to discover why practices considered as “very important” and “important” are not currently used by shutdown practitioners.

Wrap up. In summary, it could be concluded that PMPs are insufficiently established in chemical industry plant shutdowns, despite the fact that experts perfectly understand their importance. The fact that practices aimed at proactive risk prevention, control and monitoring during shutdown projects, and methodologies such as OCR, RAM, and EVM are not currently used by experts reveals that shutdown project management is not as mature as it should be. Therefore, it could be said that experts should enlarge the number of PMPs used in order to improve their performance in shutdown management in the near future, especially those PMPs that help manage uncertainties in the early phases of the plant shutdown process. HP

LITERATURE CITED 1

Lenahan, T., Turnaround, Shutdown and Outage Management, ButterworthHeinimann, Burlington, Massachusetts, 2006.

2 Levitt, A., Promised Joy: a Step-by-step Guide to Managing Project Risk, New Standard Institute, 2007.

3 Amendola, L., T. Depool and M. A. Artacho, “Identification of the critical phases and decision-making criteria for the shutdown of chemical processing plants case studies South America, Spain and Portugal,” International Journal of Industrial Engineering, March 2010.

Author biographies and photos available online at www.HydrocarbonProcessing.com.

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Our talented people, coupled with our focus on sustainable projects in refining, petrochemicals, upstream, power, and pharmaceuticals, make Foster Wheeler your partner of choice for the exciting projects and emerging technologies that are changing our industry.

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CORPORATE PROFILE: FOSTER WHEELER ENGINEERING AND CONSTRUCTION 2011

Foster Wheeler’s “touch of blue” adds value to our clients As an EPC company with more than 100 years of experience, Foster Wheeler designs, engineers and constructs leading-edge processing facilities and related infrastructure for the upstream oil and gas, LNG, refining, chemicals and petrochemicals, gas-to-liquids, coal-to-products, carbon capture and storage, environmental, metals and mining, and power industries, as well as pharmaceutical, biotech and healthcare. From conceptual studies through a complete EPC execution, we continue to deliver technically advanced, reliable facilities and projects all around the world. And, we strive to address environmental integration and sustainability for every project.

Foster Wheeler applies our “Touch of Blue” to each project and initiative, which includes assessing our own environmental performance in our offices and helping to protect the natural environment at project sites. We also work with clients to increase the energy efficiency or energy integration of new and existing oil and gas facilities, and collaborate on exciting new technology solutions to address the challenges and changing regulations in the industry.

We are leaders in downstream solutions ranging from conceptual technical and economic studies to revamps, expansions, and world-scale new builds. We offer a full refinery investment planning consultancy from initial market analysis and feasibility studies to the provision of an overall refinery ‘master plan’. Through our SYDECSM (Selective Yield Delayed Coking) process, we are a technology leader in delayed coking, committed to providing safe, reliable and environmentallyconscious solutions for residue upgrading or zero fuel oil production. Understanding that residue upgrading can be a significant investment, our UOP/Foster Wheeler Solvent Deasphalting (SDA) technology offers a lower cost solution to “bottom of the barrel” upgrading.

In gasification technologies, our project history includes high-value products from clean power, synthetic fuels, and chemicals, to lower value feedstocks. Foster Wheeler has designed, engineered and constructed more than 100 hydrogen and synthesis gas plants, reforming natural gas, refinery gases and light liquid feeds, as well as partial oxidation of both gaseous and liquid feedstocks. We also deliver cost-effective constructible solutions in LNG and Gas-To-Liquids projects in challenging locations around the world.

Increasingly, petrochemical operations are being integrated with refineries to deliver significant synergies. Foster Wheeler has a strong reputation in the chemicals, petrochemicals and polymers market, offering a complete range of expertise for all types of facilities on a global basis. Optimizing the use of hydrogen is also a tremendous driver in today’s refining and petrochemical facilities. Along with our hydrogen technology, we design, supply and erect fired heaters and reformers, and have supplied more than 2,000 fired heaters and waste heat recovery units worldwide including some of the world’s most technically sophisticated units. Many of these heaters are still performing well beyond their original design life. Our cost-effective designs are recognized by clients worldwide with repeat orders.

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CORPORATE PROFILE: KOCH-GLITSCH ENGINEERING AND CONSTRUCTION 2011

Providing solutions for fouling applications: PROVALVE® trays from Koch-Glitsch

Simply Better The key to the patented high-performance PROVALVE tray is its unique valve design.

• The valve has no moving parts, which prevents valve leg or deck wear and eliminates the potential for popped or stuck valves.

• The valve is designed with a large open area, and the tapered cover provides a forward-lateral push across the tray that prevents liquid backflow. The result is uniform liquid and vapor distribution across the entire deck with a low even spray height that enables operation at greater vapor rates.

• The large opening size and cleansing action from the liquid push protects the tray deck from fouling. The sheltered valve design allows a large open area that promotes lower pressure drop and a wider operating range than valves that are extruded from the deck.

120 110 100 Efficiency, %

Koch-Glitsch is a global leader in the design, manufacture, and supply of a complete line of mass transfer and separations technology equipment (trays; structured, random, and grid packing; mist eliminators; and coalescers) for distillation, absorption, stripping, and liquid-liquid extraction columns.

Recent tests by Fractionation Research, Inc. (FRI) confirmed that the fouling resistant PROVALVE® unit combines the capacity and efficiency characteristics of a small, high capacity valve device.

90 80 70

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8%

50 40 Capacity **

De Villiers et. al. “Further advances in light hydrocarbon fractionation”, PTQ, Summer 2004, pp 129–133.

Coker Fractionator Fouling is a major consideration in Coker Fractionators. New Coker Fractionator towers are typically trayed. Due to the severe fouling nature of the Coker Fractionator, Koch-Glitsch recommends the use of PROVALVE fixed valve trays, rather than movable valves, for this application to minimize the risk of fouling the active decks. Fouling is most severe in the bottom section of the Coker Fractionator, but even the upper sections of this column can experience fouling.

There is extensive commercial experience with PROVALVE tray technology in more than 25 Coker Fractionators around the world with diameters ranging from 6½–25 ft (2 to 7.5 m). Some are completely equipped with PROVALVE trays, while others use this technology only in the most critical sections.

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Beer Still Koch-Glitsch has extensive experience using PROVALVE trays in the highly fouling Beer Stripping columns located in bioethanol plants that process corn, wheat, sugar beet, or biomass. More than 50 installations worldwide operate successfully in columns up to 15 ft (4.5 m) in diameter.

Sour Water Stripper Refinery Sour Water Strippers present difficult design and operating challenges because these towers must process sour water feed that can vary significantly in composition. These towers often experience severe foaming as well as fouling.

A major US West coast refinery had two identical Sour Water Strippers processing the same sour feed using sieve trays with ½” (12.7 mm) orifices. Fouling of the sieve trays was so severe that each tower required several shutdowns every year for maintenance.

The entire North stripper was re-trayed with PROVALVE trays. After a typical run length, the South tower with the sieve trays had to be shut down for cleanout.

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CORPORATE PROFILE: KTI

ENGINEERING AND CONSTRUCTION 2011

SCR Retrofits of FCC Units KTI focuses on quality project execution KTI Corporation has a successful track record for retrofit of Fluid Catalytic Cracking Units (FCCUs) with Selective Catalytic Reduction (SCR) emission reduction systems. As the primary money maker in refinery operations, the FCCU is considered to be one of the most important secondary conversion processing units in modern petroleum refineries. FCCUs are also primary sources of NOx, SO2 , CO and Particulate Matter (PM), thereby requiring effective emission reduction strategies to ensure compliance with environmental regulations.

Of available options to mitigate FCCU emissions, an SCR is the most effective and commonly applied technology for reducing NOx. Given that FCCUs generate more NOx than any other refinery combustion process, they are the primary focus of any overall plant NOx reduction strategy. As a continuous process operation, FCCUs must operate with minimal downtime and disruption. Hence, the importance of executing a FCCU SCR retrofit project on time and on budget while achieving target emission reductions. Missing schedule by one day, or failing to meet emission targets consistently, can be extremely costly to the refinery operator.

Quality solutions begin with detailed planning.

There is a simple rule of thumb—the more detailed the plan; the higher quality the engineered solution. Successful retrofit projects are predicated on detailed up-front planning, application of highly qualified expertise and proven methods, and rigorous quality control of which SCR retrofits are no exception. It is the client’s responsibility to define the overall emission reduction objective, and together with an experienced engineering contractor, to define the project scope, cost, and schedule in execution of a successful FCCU SCR retrofit project.

Once an engineering firm, such as KTI, is engaged to design an SCR system, they will begin to evaluate the design parameters necessary for successful implementation and post install operation and maintenance. A few engineering design considerations for an FCCU SCR retrofit include: • Size catalyst pitch and volume appropriately for anticipated normal and upset operating conditions, • Achieve required uniformity of flow and ammonia concentration to meet NOx and ammonia slippage specifications, • Design the SCR reactor housing for construction and maintenance friendly access and ensure the structural support can withstand the potential weight of large quantities of fine particles carried over from the FCCU reactor, and • Consider the need for a design that incorporates standby reactor capacity in the event that a problem occurs with the primary catalyst bed.

Be on the lookout for common project execution issues. With experience in thousands of new capital and retrofit projects, KTI

Dual SCR Reactor

• Validate fabrication QA (KTI uses in-house inspectors) to ensure that the SCR system components (ammonia skid, distribution grid, mixers, turning/distribution devices and maintenance/handling provisions) function as intended, • Protection of the most critical component—the catalyst—to ensure proper handling during transport, storage, installation and commissioning leading up to successful start up of the unit, and • Stay focused on Health, Safety and Environment during the entire project execution cycle.

Contact information 11720 Katy Freeway, Suite 110 Houston, TX 77079 Phone: 281.249.2400 Fax: 281.249.2328 Email: sales@kticorp.com Website: www.kticorp.com

has faced and successfully overcome just about every retrofit project execution challenge imaginable. For an FCCU SCR retrofit, the primary execution challenges include: • Clearly document, articulate and manage project objectives, • Engage qualified suppliers of specialized components early in the project to assure that design solutions are compatible and overall schedule objectives are achieved,

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CORPORATE PROFILE: THE LINDE GROUP ENGINEERING AND CONSTRUCTION 2011

The Linde Group—Ideas become solutions The Linde Group is a world-leading gases and engineering company with approximately 49,100 employees working in more than 100 countries worldwide. In the 2010 financial year it achieved sales of EUR 12.868 bn. The strategy of The Linde Group is geared towards long-term profitable growth and focuses on the expansion of its international business with forward-looking products and services. Linde acts responsibly towards its shareholders, business partners, employees, society and the environment – in every one of its business areas, regions and locations across the globe. The company is committed to technologies and products that unite the goals of customer value and sustainable development. The Group comprises three divisions: Gases and Engineering (the two core divisions) and Gist (logistics services).

The Engineering Division Linde’s Engineering Division is successful throughout the world, with its focus on promising market segments such as olefin plants, natural gas plants and air separation plants, hydrogen and synthesis gas plants, cryogenic plants as well as biotechnology plants. In contrast to virtually all competitors, the company can rely on its own extensive process engineering know-how in the planning, project development and construction of turnkey industrial plants.

Linde plants are used in a wide variety of fields: in the petrochemical and chemical industries, in the steel and pharmaceutical industry, in refineries and fertiliser plants and to treat natural gas. Furthermore Linde has extensive know how in the manufacturing of plant components like coldboxes, plate-fin heat exchangers, coil-wound heat exchangers, tanks for liquefied gases, air-heated and water bath vaporizers as well as spiral-welded aluminium pipes.

For more than 100 years Linde has been constructing plants throughout the world and has developed processes and tools to guarantee high quality and minimized construction periods at competitive costs. Linde is able to streamline the workflow from engineering through procurement and construction and to coordinate subcontractors in a highly efficient and safe way.

With more than 1,000 process engineering patents and 4,000 completed plant projects, Linde ranks among the leading international plant contractors. Customers all around the globe trust Linde’s unparalleled reliability, efficiency and competence in project execution.

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Dr-Carl-von-Linde-Strasse 6-14 82049 Pullach, Germany Phone: +49.89.7445-0 Fax: +49.89.7445-4908 Email: info@linde-le.com Website: www.linde-engineering.com

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MAINTENANCE AND RELIABILITY

Prevent failures in olefin-cracking operations Failure analysis identifies root causes for damages to selective exchangers R. P. GUPTA and H. PATHAK, Reliance Industries Ltd., Nagothane, India

A

t the Nagothane olefins facility, the inner thermal sleeve, constructed with Incolloy 800H, for double-pipe ultraselective exchangers (USXs) of an ethylene cracking furnace showed grooves/pitting/fissures damage after 14 years of service. Metallurgical examination and testing of the damaged samples revealed that the damage to the USX Alloy 800H thermal sleeve occurred due to metal dusting, a phenomenon caused by elevated temperatures and failures in the purge-steam supply. In this case history, the authors discuss how the damaged USXs were replaced and the selection process for a better design without a thermal sleeve was investigated.

Operating parameters. Cracked hydrocarbon gas enters the top of the USX from transfer lines and passes through the inner thermal sleeve. The gas is cooled heat exchange with BFW through the outer pipe. A steam purge is maintained at the top and bottom portion of the USX for more efficient cooling. Table 1 lists details of the USX. Failure investigations. All of the three damaged USX

exchangers of furnace 10-H-10 were replaced with new exchangers in 2008 using the same design. One of the affected USX TABLE 1. Design details of USX

Background. The ethylene gas cracker plant of RIL-Nagothane

unit has five ultra-selective furnaces for the production of ethylene and propylene. The feed, consisting of C2/C3, is cracked in the radiant section of the furnace. The cracked gas then enters into the USXs via transfer lines, where the cracked gas is cooled.

The cooled cracked gas then passes on to primary and secondary transfer-line exchangers, before going to the quench tower. Fig. 1 is the schematic of the process.

Each furnace consists of 12 double-pipe heat exchangers, namely USX type “D” exchangers, where cracked hydrocarbon gas passes through the inner pipe and is cooled by flowing boiler feedwater (BFW) through the outer pipe. There is a continuous steam purge in the top and bottom portion of the USX that subsequently mixes in the cracked hydrocarbon stream through the push-fit region and cools the top and bottom portions of the USX. USX construction material. An Alloy 800H seamless pipe

having unequal wall thicknesses is placed on top of USX heat exchanger to serve as a thermal sleeve. The top, thick-wall end side of the thermal sleeve is welded with low-carbon 20Cr–32Ni centrifugally cast pipe. The bottom portion is a thin wall and silted end that is snug fitted with A213 Gr.T22 forged tubular ID. The bottom part of USXs is welded with an AISI Type 304H forged “T” flange and then with a SS 304H flange suitable for connecting to other facilities. The detailed design of USX heat exchanger is shown in Fig. 2.

Failure details. Grooves and bulging type damage was noticed in upper regions of Alloy 800H thermal sleeve in three of the USX exchangers (USX Nos. 2, 5 and 11) during an internal inspection in 2006. The location of grooves was approximately 200 mm–400 mm from the top. Photographs of the damaged region are shown in Fig. 3.

MOC of inner thermal sleeve

Incolloy 800H

Operating fluid in inner sleeve

Cracked hydrocarbon

Operating pressure in inner thermal sleeve

1 kg/cm2

Inlet temperature of cracked hydrocarbon stream

840°C

Outlet temperature of cracked hydrocarbon stream

600°C

MOC of outer pipe

Incolloy 800H/T22

BFW stream pressure

111 kg/cm2

BFW stream inlet temperature

318°C

BFW stream outlet temperature

500°C

Purge steam line pressure

6–8 kg/cm2

Purge steam line inlet temperature

200°C

Hydrocarbon Convection zone of furnace

Dilution steam

Transfer line

USX Radiant zone of furnace Primary TLX FIG. 1

Secondary TLX

Flow diagram of gas cracker and associated equipment.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 127

MAINTENANCE AND RELIABILITY Cracked hydrocarbon inlet

Concentric T 22 pipe with a narrow gap on ID and wider gap at OD for cooling.

Purge steam inlet nozzle BFW outlet

Alloy 800 H pipe OD reduced for push fit i.e. thermal sleeve MOC: P22

BFW inlet

Purge steam inlet nozzle FIG. 4

Cracked hydrocarbon outlet

Photograph of the affected Alloy 800H thermal sleeve.

MOC: SS 304H

FIG. 2

The USX type “D” exchanger at the plant.

FIG. 3

Damaged USX at the Nagothane facility.

exchangers was plasma cut across the length during a detailed root-cause analysis of the failure. Several tests and inspections were carried out as part of this process: Visual observation. A visual inspection revealed small cracks and fissures covering the ID surface of inner thermal sleeve in addition to grooves and bulging. The bulging-in/deep pitting/ grooves was found in the circumferential directions of the thick wall regions, as shown in Fig. 4.

All of the fissures and surface cracks had occurred at the ID and were in a circumferential/radial direction. Deep cracks in the ID of the transition zone of the inner thermal sleeve (wall thickness reduction region) were identified.

In general, the ID surfaces had the appearances of orange peel (Fig. 6); whereas those on OD were smooth and covered with oxidized scale. Also, noted was that marginal to no wall thickness reduction had occurred on Alloy 800H thermal sleeve at regions free of the bulging-in/deep pitting/grooves.

Inspection of purge steam supply lines was also done. From the inspection, it was noticed that some lines were choked with a tar-type material. Purge steam is basically a dilution steam that 128

I SEPTEMBER 2011 HydrocarbonProcessing.com

contains an oily substance. This oily substance, when exposed to high temperatures, can form dense tar materials that can cause choking of the purge steam lines.

Ultrasonic thickness survey. An ultrasonic thickness survey of the USX inner sleeve was done. The thickness values at deformed portions were found to be 4 mm–4.5 mm against original thickness of 9.5 mm. It was also noticed that marginal to no wall thickness reduction had occurred on the Alloy 800H thermal sleeve at regions free of grooves and pitting.

Microstructural examination. Microstructural examinations both at the surface and cross sections of inner sleeve indicated that the fissure’s edges had a white, precipitate free zone (PFZ), followed by internal regions of dense carbide precipitation with cracks in some cases. The mid wall and OD surfaces indicated coarse grains of austenite with carbide precipitates. Also, the mid wall and the OD surfaces were found to be sound as such but they aged considerably due to prolonged exposure at elevated temperatures, as shown in Fig. 7.

Energy dispersive x-ray (EDS-SEM mode) analysis. Analysis for micro chemical compositions was done on ID, mid wall and OD surfaces of damaged USX thermal sleeve. EDS-SEM analyses provided valuable information on the damaging phenomenon occurring in Alloy 800H thermal sleeve. Nickel (Ni) content on the ID surface was reduced to very low value up to 3.61 wt%. the chromium (Cr) percentage at fissure’s edges was reduced to as low as 5.82 wt%. These zones are about only 30–50-micron wide and appeared white like pure alloy (PFZ—without carbide precipitation). But within 100-micron depth, a zone of high-density carbide precipitates rich in Cr (45.58%) but depleted both in Ni and iron (Fe) was present. Also, some surface cracks were seen within the heavily carburized surface, as shown in Fig. 8.

Micro hardness measurements. The micro hardness values of the new Alloy 800H sample were between 170 BHN and 180 BHN, whereas those of damaged pipe varied more widely in the range of 160 BHN to 235 BHN. Low hardness in damaged samples at the ID was in agreement with Cr loss at ID surfaces as evaluated by EDS micro-chemical analyses. Hardness values at the OD surfaces of the damaged sleeve were in the range of 180 BHN–200 BHN; but at carburized zone, the values were high, between 200–235 BHN.

MAINTENANCE AND RELIABILITY

FIG. 5

Crack occurred from the ID surface and formed through circumferential crack at wall step down regions.

FIG. 6

Close up of the affected Alloy 800H thermal sleeve showing orange peel appearance the ID surface.

FIG. 7

Delta ferrite measurements. Delta-ferrite values were measured on both new and damaged samples of the Alloy 800H. Delta ferrite values in the new Alloy 800H were less than 0.1%, which is acceptable. However, delta ferrite values of the damaged samples varied at the ID, core and OD surfaces. In general, the ID surfaces showed high delta ferrite values ranging from 5.2% to 9.5%; whereas the core varied 1%–2% and OD surfaces varied 1%–3%. These values also reflected Cr loss, particularly at the ID surfaces, as found by EDS measurements.

Metallurgical findings. On the basis of the listed testing and

inspection, these conclusions could be made: • Bulging-in, pits, fissures and cracks occurred at the ID surfaces along the circumference.

• Circumference cracks occurred on the ID surface at the region where wall thickness was reduced from 9.5 mm to 4mm.

In some places, the cracks penetrated through the wall.

• Cracks were inter granular in nature, and cracking developed due to internal stresses resulting from heavy carburization at the ID. • Fissures and pits have penetrated wall thickness in the range of 5% to 60%; all have three zones, a whitish edge, a carburized zone and normal micro structures with Cr contents 5.82, < 40, and 20% respectively.

• Ni content at the ID surface, within thick wedge and carbide-rich regions are 3.61, 8.40 and 15.35 wt% respectively. Iron content was also found to decrease.

• EDS-SEM analyses showed that chemical composition, at cross sections corresponding to the mid wall and at close to OD edges, conforms to Alloy 800H (20Cr, 32Ni, 45Fe and others).

Results from microstructural exams on USX sleeve and pipe.

• ID surface exhibited an orange-peel type scale that became nonprotective.

Metal dusting and factors. Metal dusting is a fast and

catastrophic form of carburization (in the order of mms/yr) that results in disintegration of the carburized surface layer due to graphite growth. This form of attack is only experienced in high-temperature carbon-supersaturated gaseous environments where the metal surface is not covered by oxide, sulfide or other protective layers. Fe, Ni and Co, as well as alloys based on these metals are all susceptible to metal dusting. The corrosion manifests itself as a break up of bulk metal to metal powder, thus the term, metal dusting.

Observations. Damages in Alloy 800H thermal sleeves occurred at ID surfaces at thick wall regions and circumferential crack initiated at the ID surface’s wall reduced regions. Micro structural examinations both at the surface and cross sections indicated that the fissure’s edges had a white, precipitation free zone, followed by internal regions of dense carbide precipitation with cracks in some cases. Detailed studies were done to estimate the damage due to creep phenomenon. As such, the presence of creep cavities could not be detected at sound regions (core and OD).

In some instances cracking developed due to internal stresses induced by heavy carburization. Orange-peel type ID surfaces and fissures only in circumferential direction indicated that surface stresses were present along the longitudinal direction of the thermal sleeve. This may be due to high co-efficient of thermal HYDROCARBON PROCESSING SEPTEMBER 2011

I 129

MAINTENANCE AND RELIABILITY expansion of the Alloy 800H material as compared to steel. Also, the ID surface film was not found to be completely protective due to high carbon activity at 840°C. EDS-SEM analyses provided valuable information on the damaging phenomenon occurring in the Alloy 800H thermal sleeve. The hydrocarbon was in direct contact with the Alloy 800H thermal sleeves ID at 800°C–850°C. Choking of purge steam lines led to higher temperatures in the top portion of the USX, which aggravated differential thermal expansion and carburization.

One side of the thermal sleeve is firmly fixed by welding, and the other thin-wall end was push-fitted on ID of A213 GrT22 low alloy (2.25 Cr- 1Mo) steels. The sleeve being austenitic has a thermal expansion coefficient three times more than that of steel.

Therefore, at high temperatures, the thermal sleeve would experience mismatch in the axial direction; maximum stress is envisaged at transition zone from higher to lower wall thickness. Therefore, all the fissures, wastages and linear pits were found at ID along circumference, and even through wall cracking occurred, at wall thickness transition zone.

EDS-SEM analyses have revealed that Cr depletion occurred at ID surfaces, within the fissures, pits and crack. Cr has found to have decreased to as low as 5%. The Ni content also decreased in all of these regions. The bulk materials was found to conform Alloy 800H. The edges of the pits have different appearance— which is free of precipitates zone indicating the ongoing degradation processes. The bulk materials also contained a large volume of Cr-rich carbide precipitates—the percentage of Cr increased to as high as 45%, also with significant Ni depletion.

It is well known that metal dusting and the carburization phenomenon occur together at temperatures between 430°C and 900°C under reducing environments. Metal dusting can lead to thickness reduction, grooving and pitting in the inner thermal sleeve.

Conclusion. Based on the detailed analysis carried out as above,

the following conclusion can be drawn: • Damage in USX Alloy 800H thermal sleeve ID occurred due to metal dusting phenomenon caused by over heating due to starvation of the purge steam.

• The remaining life the double pipe “D” USX type exchanger may be another five to seven years under the present operating conditions.

Mitigation and remedies. The life cycle of USX D-type heat exchanger could be enhanced by efficient cooling by providing clean steam instead of dilution steam. Clean steam will eliminate the chances of plugging of the purge steam lines. Select alternative USX design without purge steam cooling to replace the damaged USX. HP NOMENCLATURE USX Ultra selective exchanger BFW Boiler feedwater SEM Scanning electron microscopy PFZ Precipitate free zone EDS Energy dispersive X-ray spectroscopy BIBLIOGRAPHY Bibliography available online at Hydrocarbonprocessing.com.

Let Tray-Tec assist you with your next installation of process equipment in your towers, reactors and drums.

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FIG. 8 Select 176 at www.HydrocarbonProcessing.com/RS 130

Results of EDS-SEM analysis on USX sleeve.

MAINTENANCE AND RELIABILITY

Prevent tank-bottom failure through reliability analysis Apply service-life methods to optimize inspections and maintenance for storage units L. LIU, Logistic Engineering University, China; and T. LIU, Sichuan University, China

M

ost oil storage tank failures result from defects like corrosion pits and flaws on the bottom plates.1 Since oil storage tanks in the petroleum and petrochemical industries are usually made from welded steel plates, defects in the tanks should be detectable during the welding process or in storage service phases.2 But even with efforts at advance flaw detection, there is still much complexity and randomness associated with tank-bottom corrosion. This makes it necessary to use probability methods in the reliability analysis and life/mean time between failures (MTBF) calculation for tank bottoms with corrosion pits.

Probability model. The structure of a steel tank bottom can be considered as a series system from the point of view of the failure mechanism, which means that all plates must be in a normal state in order for the bottom to function properly. The tank fails when any one of its bottom plates has the first perfected pit. This model is called a series model or weakest link model.

Then, for a tank bottom made of m plates with the reliability Ri(t) for the ith plate, its reliability, RT (t), is the probability that all plates simultaneously survive to time t and can be expressed under the independence assumption as m

RT (t ) = ∏ Ri (t )

(1)

i=1

RT = min Ri

(3)

i

where Ri is the reliability of the ith plate of the tank bottom. It shows that it is an extreme value distribution.

Therefore, the reliability of a steel tank could be calculated by combining an extreme value distribution and an exponential distribution in the weakest-link or series model.

Calculating tank-bottom reliability. According to extreme value theory, the tank bottom will fail as soon as only one defect penetrates the plate of the tank bottom. When there are n corrosive pits or defects in a tank bottom, the corrosive-resistance function can be expressed as

Z = min ⎡⎣(Tb − ai ) ,i = 1, 2, ,n ⎤⎦

or t = min (t i ,i = 1, 2, , n)

(4)

where Z is the surplus thickness of any one of the tank-bottom plates, Tb is the original thickness of the bottom plates, ai is the depth of the ith corrosive pit or defect, t is the time before failure of the tank-bottom, ti is the time to failure of the ith defect.

Applying the concept of smallest extreme value distribution,3 the probability of failure for the tank-bottom is n n (5) F ( z ) = 1− [1− F (z)] or F (t ) = 1− [1− F (t )] N

N

The failure or hazard rate for a series system can also be expressed by an exponential distribution, where ␭T (t) is the failure rate of the tank bottom, ␭i (t) is the failure rate of the ith plate.3 ⎛ t ⎞⎟ ⎜ RT (t ) = exp ⎜⎜−∫ λT (t ) dt ⎟⎟⎟ ⎜⎜ ⎟⎠ ⎝ 0 (2) ⎛ t ⎞⎟ ⎜⎜ ⎟ Ri (t ) = exp ⎜−∫ λi (t ) dt ⎟⎟ ⎜⎜ ⎟⎟⎠ ⎝ 0

where F(z) or F(t) is the cumulative distribution of defects. For simplicity, assume that n r ∞ and then: (6) FN (t ) = 1− e −nF (t )

In another way, the reliability of a tank mostly depends on the corrosive statuses on its bottom plates. When one plate has defects, the applied stresses or corrosives will increase the size of these defects and, ultimately, failure occurs when the size of any one defect in the plate reaches a critical value. Usually, the defect growth is the main cause of failure and a defect with the least resistance to the applied stress or corrosives will be the first to fail.

In this case, the reliability of the tank bottom of a steel tank will be

where Tb is the thickness of tank-bottom plates, mm; k is the corrosion rate of the tank bottom, mm/year and ai is the original depth of the ith defect.

Assume that the probability density function for the depth of corrosive defects be

It is evident that the time of the plate penetration is proportional to the difference between the plate thickness and the initial depth of defects and there is: 1 t i = (Tb − ai ) (7) k

f a (a ) =

e −a /a a

(8) HYDROCARBON PROCESSING SEPTEMBER 2011

I 131

MAINTENANCE AND RELIABILITY 1.0

1.0 n=5

0.9

a=0

.3

0.9

a=

0.8

0.8

n = 10

Reliability

0.6

0.

6

0.

7

60

0.8

Reliability

a=

a=

n=

0.4

30 n = 40 n=

0.5

a=

0.7

0.5

n = 20

0.6

0.4

a=

0.7

0.5

0.3 0.2 0.1

0.4

k = 0.1 – corrosion rate of tank bottom, mm/yr tb = 5 – thickness of tank bottom plate mm 0.3 n = 10 – number of defects on tank bottom a – average depth of defects on tank bottom, mm/yr 0.2 10 15 20 25 30 Time, yr

K = 0.1 – corrosion rate of tank bottom, mm/yr tb = 5 – thickness of tank bottom plate, mm a = 0.6 – average depth of defects on tank bottom, mm/yr n – number of defects on tank bottom

0.0 10

15

20

25

30

35

Time, yr FIG. 1

Reliability examined with different numbers of defects in a tank bottom.

1.0

FIG. 3

0.9 k = 0.10

0.8

tb = 5.5

k = 0.14

Reliability

6

k = 0.18

0.1

0.6

k = 0.12

0.5 0.4

tb = 5

0.6 0.5

tb = 4

tb = 4.5

0.4

0.3

0.3

0.2 tb = 5 – thickness of tank bottom plate, mm n = 10 – number of defects on tank bottom 0.1 a = 0.5 – average depth of defects on tank bottom, mm/yr k – corrosion rate of tank bottom, mm/yr 0.0 10 15 20 25 30 Time, yr

0.2 K = 0.1 – corrosion rate of tank bottom, mm/yr n = 10 – number of defects on tank bottom 0.1 a = 0.5 – average depth of defects on tank bottom, mm/yr tb – thickness of tank bottom plate, mm 0.0 10 15 20 25 30 Time, yr

FIG. 2

tb = 6

0.7 k=

Reliability

tb = 7

0.9

0.7

35

Reliability considered with different tank-bottom corrosion rates.

where a is the depth of defects, mm, and ā is the average depth of all defects in a tank bottom, mm.

The probability for the failure of the corrosive defects is ⎛ ⎞ 1 F (t ) = P ⎜⎜⎜t i = (Tb − ai ) ≤ t ⎟⎟⎟ =P (ai ≥ (Tb − kt )) ⎝ ⎠ k Tb Tb ⎛ kt ⎞ − = ∫ f a (a )da = e a ×⎜⎜⎜e a −1⎟⎟⎟ ⎜⎝ ⎠⎟

(9)

Tb −kt

Thus, the reliability of a tank bottom is

R(t ) = 1− FN (t ) = e −nF (t ) = exp ⎡⎢−ne −Tb /a (e kt /a −1)⎤⎥ ⎣ ⎦

(10)

The previous formula shows that the reliability of a tankbottom has a correlation with several factors—such as the number and mean depth of defects, the rate of corrosion and the original thickness of the bottom plates—and that it declines with the tank’s service time or MTBF in a double exponential function.

132

Reliability examined with different average depth of the defects in a tank bottom.

1.0

k = 0.08

0.8

35

I SEPTEMBER 2011 HydrocarbonProcessing.com

FIG. 4

35

Reliability comparison of different thicknesses for tankbottom plates.

Analyzing tank bottom reliability. The reliability of

a tank bottom can be shown and perceived more directly by visualizing its calculation in MATLAB.4 By substituting the different values of the number and the mean depth of defects, the corrosion rate and the plate thickness of the tank bottom into Eq.10, the reliabilities of the tank bottom with very different states of defects and plates can be calculated and shown in Fig.1 through Fig. 4. These figures clearly show that reliability drops rapidly with the increase of the defect-number and the corrosive rate as well as the mean depth of defects. This is especially true when the service time is more than 20 years (as shown in Fig.1, Fig. 2 and Fig. 3). It should be noted that an increase of the bottom plate’s thickness of just 1 millimeter or 0.5 millimeter will greatly upgrade the reliability as well as prolong the service time or MTBF of a tank. From the curves in Fig. 4, it can be seen that an increase or decrease of 0.5 millimeter of the bottom plates’ thickness makes the reliability vary greatly at the same service time of the tanks.

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MAINTENANCE AND RELIABILITY Life/MTBF for steel storage tanks. The life/MTBF of a

steel tank can be calculated by rearranging Eq. 10, which results in

t=

T /a a ⎡⎢ e b ⋅ ln R (t ) ⎤⎥ ln 1− ⎥ n k ⎢⎣ ⎦

(11)

The previous equation indicates that the life or MTBF for a tank bottom is a complicated function of reliability, which is affected by the number and depth of defects and the thickness of the bottom plate, while there is a simple linear relation between the life or MTBF and the corrosive rate of the tank bottom.

Ordinarily, the thickness of tank-bottom-plates can be designed and the reliability predicted in advance. The corrosion rate of a tank bottom can be evaluated by its surrounding conditions, such as the tank-base humidity and the water content of oil stored. Thus, the life of a tank bottom will be decided mainly on the number of defects, which can be investigated in periods during the inspection of tanks.

According to the sizes of most oil storage tanks in the industry, set the reliability at 95% and the bottom plate’s thicknesses and corrosive parameters into two groups: one with thinner bottom plates and another with thicker ones, which respectively are:

35

Group A: Tb = 5 mm, 6 mm, 7 mm; k = 0.10, 0.15 mm / a; a = 1.0 mm; Group B: Tb = 8 mm, 10 mm, 12 mm; k = 0.15, 0.2 mm / a; a = 2.0 mm.

With this established, the life or MTBF of these tank-bottoms can be calculated and visualized with different corrosive parameters as shown in Fig. 5 and Fig. 6. The curves show the MTBF descends at the initial of the defects arising in the tank-bottom plates with whatever thicknesses much more than at the later time.

It is during the initial arising of several defects in the bottomplates that for the number of defects increase by one or two will cause MTBF to reduce greatly.

Further, the case that the life/MTBF of a tank-bottom change with its reliability required can be demonstrated in the following examples of calculations. Take two examples: one is the tank with Tb = 5 mm, k = 0.1 mm / year, ā = 0.5 mm and another is the tank with Tb = 10 mm, k = 0.15 mm / year, ā = 1.5 mm. The life/ MTBF function of the tank-bottoms related with variables of the reliability and the number of defects can be visualized in Fig. 7.

The previous calculation results show that the life or MTBF of the tank bottom with a different number of defects will be very different and will decrease with the increasing number of corrosive

35

A

Tb = 5 mm Tb = 6 mm Tb = 7 mm

30

20

MTBF, years

MTBF, years

25 K = 0.1 mm/a, corrosive rate a = 1 mm, mean depth of defects R = 95% reliability of tank bottom

15

K = 0.15 mm/a, corrosive rate a = 2 mm, mean depth of defects R = 95% reliability of tank bottom

20 15

10

10

5

5

0

0 5

10

15 20 Defect number

25

5

30

25

10

15 20 Defect number

25

30

25

B

B

Tb = 5 mm Tb = 6 mm Tb = 7 mm

20

MTBF, years

MTBF, years

Tb = 8 mm Tb = 10 mm Tb = 12 mm

20

K = 0.15 mm/a, corrosive rate a = 1 mm, mean depth of defects R = 95% reliability of tank bottom

15

10

5

K = 0.2 mm/a, corrosive rate a = 2 mm, mean depth of defects R = 95% reliability of tank bottom

15

10

5

0

0 5

134

Tb = 8 mm Tb = 10 mm Tb = 12 mm

30

25

FIG. 5

A

10

15 20 Defect number

MTBF of tank bottoms with thinner plates.

I SEPTEMBER 2011 HydrocarbonProcessing.com

25

5

30

FIG. 6

10

15 20 Defect number

MTBF of tank bottoms with thicker plates.

25

30

MAINTENANCE AND RELIABILITY pits. The higher reliability choice is the selection of thicker bottom plates. This is a very effective method to increase the life/MTBF and the reliability as well as the resistance to corrosion. At the same time, we can also take other measures to protect the bottom plates from being corroded, such as coating them and keeping them away from water. In fact, this calculation and analysis are much more important for planning the inspection and maintenance of a tank for safe storage than for knowing its accurate life/MTBF. Bringing it all together. There is a functional relation between the life/MTBF and reliability of a steel storage tank with defects in its bottom plate, which is also dependent on the parameters of tank-bottom structure and corrosion (such as the corrosion rate and the thickness of the tank-bottom plate). So we can increase the life/MTBF and reliability of steel storage tanks by selecting thicker bottom plates and strengthening the resistance to corrosion. The other key component is to reduce and/or eliminate the factors that cause or accelerate bottom corrosion pits and defects.

The MTBF of a steel storage tank will depend mainly on the defects in its bottom. There seems to be no difference regarding the size of the tank-bottom area in the previous life calculation.

However, usually there are more defects in a larger tank bottom.

40

A n=2 n=4

MTBF, years

LITERATURE CITED Ji-Yi, F., Analysis on a thousand cases of accidents in oil depots, Sino Petrochem Publishing House, pp. 228 and 355, Beijing, 2005.

2 Guang-chen, G. and Z. Zhang, Design and management of petroleum depots, Petroleum University Publishing House, pp. 221-227, Dongying, Shandong, 1991.

3 Shu-Ho, D. and M. Wang, Reliability analysis in engineering applications, Van Nostrand Reinhold, pp. 32–35, pp. 359–361, New York, 1991.

4 Cheng, W., et al, MATLAB 5.3 essentials and programming with advanced application, China Machine Press, pp. 82–87.

1

Lichuan Liu is a professor in the petroleum engineering department of Logistic Engineering University in China. She engages in research on petroleum storage and transportation system design and reliability.

Tianqi Liu is a professor in the electric engineering school of Sichuan University in China. She engages in research on electricity power system design and reliability.

35 30

So, a larger tank should be designed with the thicker bottom plates at the same corrosive environment and reliability level. The larger tanks should also be inspected in shorter periods than the smaller ones in order to maintain proper reliability.

Through the analysis of life/MTBF and reliability, a more reasonable plan for the future inspection and maintenance of a tank bottom can be made. This will greatly increase cost efficiency and avoid both unneeded work and losses that come from not finding the defects that can lead to failure in time. HP

n=1

n=8 n = 16

25 n = 32 20 15

Tb = 5 mm k = 0.1 mm/a a = 1.0 mm

0 0.90

0.92

0.94 0.96 Defect number

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The industry-standard software for instrumentation design

45 B

n=1 40 n=2

35

n=4

MTBF, years

30 25

Features: NEW • Graphs for Control Valves and Flow Elements Version 8.1 • Restriction devices • Material yield strengths file • ISO orifice plate calculations have been updated to ISO 5167, 2003 sudden entrance and exit to the calculations.

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Featuring more than 70 routines associated with control valves, rupture disks, flow elements, relief valves and process data calculations, InstruCalcTM is one of the industry’s most popular desktop applications for instrumentation calculations and analyses.

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FIG. 7

Tb = 10 mm k = 0.15 mm/a a = 1.5 mm 0.92

+1 ((713) 520-4426 l Software@GulfPub.com +1 om www.GulfPub.com 0.94 0.96 Defect number

0.98

The tank-bottom life/MTBF with different numbers of defects.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 135

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ENGINEERING CASE HISTORIES

Case 64: Averages can be misleading on service life data Take care when making important decisions on data T. SOFRONAS, Consulting Engineer, Houston, Texas

W

e have all used averages to determine average stresses, forces, torques, service life and other quantities. But care must be taken when using averages. What if a shaft failed with an average torque meter value of 360 ft-lb.

Spot values show torques of: (300 + 800 + 200 + 400 + 100) / 5 = 360 ft-lb Obviously, it was the 800 ft-lb torque that probably caused the failure, but if the torque meter took hourly averages, it would miss the peaks.

Example. Here is an actual case involv-

ing the wear of a gas-engine compressors power cylinder.1 Excessive warping of a lined cylinder can result in expensive downtimes and piston wear, such as shown in Fig. 1. This was occurring on cylinders that had been relined at a high-quality shop for many years. It was suspected that the cylinders were defective and distorting. When the engine manufacturer was contacted, the reply was that they recommend only new cylinders be used at overhaul time and they don't recommend other shops relining them.

Existing data was collected on the new and relined cylinders. A new analysis on the averages was presented to the engineering department. The new solid cylinder service life until galling (months) is: 16, 12, 7, 48, 14, 48, 24, 2, 24 Average service life = 21.7 months Data on the relined cylinder service life until galling (months) is: 8, 4, 4, 5, 48, 12, 12 Average service life = 13.3 months With only the average values used, it is clear to see how the manufacturer's advice shouldn’t be ignored. The solid cylinders

seem to last almost twice as long as the relined units.

In contrast, engineering calculated these statistics; Solid: Average service life solid = 21.7 months Standard deviation solid = 16.5 months Number of solid = 9 Relined: Average service life relined = 13.3 months Standard deviation relined = 15.7 months Number of relined = 7.

The tip off that the data was the problem is demonstrated by the large standard deviation values. These should usually be much smaller than the average value.

A test was done on the data, called a Student “t” test. It indicated that the average of the solid cylinders over the relined could only expect to be larger in 5 times out of 100 times. This said that there was hardly enough data to make an informed decision and that more data was required.

Value-based decision. This is important since relined cylinders cost $7,500/ unit and new solid cylinders are $15,000/ unit. There are eight cylinders per engine and the cylinders are replaced every four years during overhaul. A wrong decision could cost $60,000 every four years. In addition, numerous engines of this design are used within the company.

The decision was to continue testing until an adequate statistical basis could be reached. The final outcome was to tighten up the reline procedure with detailed specifications as to the fit, materials and assembly procedure and inspection with the supplier. With these refined procedures and additional test data, it was determined that the service life of relined cylinders was the same as new solid cylinders. This was only

FIG. 1

Galled piston due to warped cylinder.

so with proper maintenance of the engine and purchasing relined cylinders from a high-quality repair facility.

Maintenance was a key point addressed from this study since even new cylinders were galling. Better maintenance and eliminating detonation during load changes should address these concerns. HP 1

LITERATURE CITED Sofronas, A., Analytical Troubleshooting of Process Machinery and Pressure Vessels: Including RealWorld Case Studies, John Wiley & Sons, p. 222.

Dr. Tony Sofronas, P.E., was a worldwide lead mechanical engineer for ExxonMobil before his retirement.

Information on his books, seminars and consulting, as well as comments to this article, are available at http://mechanicalengineeringhelp.com.

HYDROCARBON PROCESSING SEPTEMBER 2011

I 137

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HPIN ASSOCIATIONS CONT. HPIn Associations continued from page 13

Using better catalyst systems is one of the ways that refiners and petrochemical producers can improve operations. A growing concern is replacing rare earth metal catalysts due to increasing prices. Catalyst producers are investing in the development of rare-earth free catalyst systems; Grace Davison Refining technologies has made substantial gains in rare-earth free catalyst FCC systems. Interest continues in upgrading the bottom of the barrel and heavy crude oil into lighter products. Criterion and CNOOC Oil & Petrochemicals Co. are making advancements for ultra-low-sulfur diesel and gasoline.

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FREE Product and Service Information—SEPTEMBER 2011 HOW TO USE THE INDEX: The FIRST NUMBER after the company name is the page on which an advertisement appears. The SECOND NUMBER, appearing in parentheses, after the company name, is the READER SERVICE NUMBER. There are several ways readers can obtain information: 1. The quickest way to request information from an advertiser or about an editorial item is to go to www.

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ADVERTISERS in this issue of HYDROCARBON PROCESSING Company Website

Page

RS#

Alfa Laval Packinox . . . . . . . . . . . . . . . . . . 16

(152)

www.info.hotims.com/35907-152

Altair Strickland. . . . . . . . . . . . . . . . . . . . . 10

(70) (151) (165) (155) (53) (67) (84)

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Belco Technologies Corp . . . . . . . . . . . . . 110

(71)

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BIC Alliance. . . . . . . . . . . . . . . . . . . . . . . . 84

(175)

www.info.hotims.com/35907-175

Borsig GmbH. . . . . . . . . . . . . . . . . . . . . . . 73

(172)

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Buchen-ICS GmbH. . . . . . . . . . . . . . . . . . . 31

(178)

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Burckhardt Compression AG . . . . . . . . . . . 79

(79)

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Cameron . . . . . . . . . . . . . . . . . . . . . . . . . . 62

(55)

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Carver Pump Company . . . . . . . . . . . . . . . 26

(156)

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CB&I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74

(59)

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Chemstations Inc. . . . . . . . . . . . . . . . . . . . 44

(163)

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Chesterton . . . . . . . . . . . . . . . . . . . . . . . . 22

(154)

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Chevron Lummus Global . . . . . . . . . . . . . . 17

(74)

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Costacurta SpA Vico . . . . . . . . . . . . . . . . . 23

(57)

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Curtiss-Wright Flow Control Company . . . . . 2

(76)

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Curtiss-Wright Flow Control Company, TapcoEnpro . . . . . . . . . . . . . . . . . . . . . 104

www.info.hotims.com/35907-65

ExxonMobil Research & Engineering . . . . . 58 Flexitallic LP . . . . . . . . . . . . . . . . . . . . . . . . 5 Foster Wheeler . . . . . . . . . . . . . . . . . . .E-118 Gas & Air Systems . . . . . . . . . . . . . . . . . . . 28 Greene, Tweed . . . . . . . . . . . . . . . . . . . . . 72 Gulf Publishing Company Construction Boxscore . . . . . . . . . . . . . . . 34

(101) (93) (103)

Mustang Engineering . . . . . . . . . . . . . . . . 46

(61)

Mustang Engineering . . . . . . . . . . . . . .E-115

(166) (173)

(77) (63) (72) (164) (158) (86)

www.info.hotims.com/35907-86

Johnson Screens. . . . . . . . . . . . . . . . . . . . . 83

(90)

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KBC Advanced Technologies Inc . . . . . . . . . 86

(99)

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KBR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

(60)

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Kinka Valve . . . . . . . . . . . . . . . . . . . . . .E-117

Koch-Glitsch . . . . . . . . . . . . . . . . . . . . .E-120

(97)

KTI Corporation . . . . . . . . . . . . . . . . . . .E-122

(102)

www.info.hotims.com/35907-73

(89)

Linde Process Plants . . . . . . . . . . . . . . . . . 12 www.info.hotims.com/35907-81

Petro-Canada Lubricants . . . . . . . . . . . . . . 67

(83)

www.info.hotims.com/35907-83

Prosernat . . . . . . . . . . . . . . . . . . . . . . . . . 25

(177) (174)

Saint-Gobain Norpro . . . . . . . . . . . . . . . . . 20

(62)

www.info.hotims.com/35907-62

Samson GmbH . . . . . . . . . . . . . . . . . . . . . 63

(168)

www.info.hotims.com/35907-168

Selas Fluid Processing Corp . . . . . . . . . . . . 96

(82)

www.info.hotims.com/35907-82

Servomex Ltd. . . . . . . . . . . . . . . . . . . . . . . 57

(167)

www.info.hotims.com/35907-167

Siemens AG . . . . . . . . . . . . . . . . . . . . . . . 45

(94)

www.info.hotims.com/35907-94

SoundPLAN . . . . . . . . . . . . . . . . . . . . . . . . 65

(170)

www.info.hotims.com/35907-170

Spraying Systems Co . . . . . . . . . . . . . . . . 103

(66)

www.info.hotims.com/35907-66

SPX Flow Technology . . . . . . . . . . . . . . . . . 66

(171)

www.info.hotims.com/35907-171

Sulzer Chemtech, USA Inc.. . . . . . . . . . . . . 27

(168)

www.info.hotims.com/35907-168

Team Industrial Services. . . . . . . . . . . . . . . 29

(95)

www.info.hotims.com/35907-95

(169)

www.info.hotims.com/35907-169

(176)

www.info.hotims.com/35907-176

UOP LLC . . . . . . . . . . . . . . . . . . . . . . . . . . 36 URS Washington Division. . . . . . . . . . . .E-126

(54)

www.info.hotims.com/35907-54

(62)

www.info.hotims.com/35907-62

(65)

(98)

www.info.hotims.com/35907-98

Tray-Tec Inc. . . . . . . . . . . . . . . . . . . . . . . 130 (85)

www.info.hotims.com/35907-89

Linde AG Linde Engineering Div . . . . . . .E-124

Paharpur Cooling Towers, Ltd. . . . . . . . . . . 35

Trachte USA . . . . . . . . . . . . . . . . . . . . . . . 65 (73)

www.info.hotims.com/35907-85

(58)

(159)

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www.info.hotims.com/35907-174

www.info.hotims.com/35907-158

ITT Industries . . . . . . . . . . . . . . . . . . . . . . 64

(100)

www.info.hotims.com/35907-100

Quest Integrity Group LLC . . . . . . . . . . . . . 82

www.info.hotims.com/35907-164

Inpro / Seal Company . . . . . . . . . . . . . . . . 30

(96)

www.info.hotims.com/35907-177

www.info.hotims.com/35907-72

Idrojet . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

(88)

www.info.hotims.com/35907-96

Optimized Gas Treating . . . . . . . . . . . . . . . 31 (160)

www.info.hotims.com/35907-63

HyTorc . . . . . . . . . . . . . . . . . . . . . . . . . . . 43

(78)

Mogas Industries Inc . . . . . . . . . . . . . . . . . 56

(157)

www.info.hotims.com/35907-77

Heurtey Petrochem . . . . . . . . . . . . . . . . . . 90

Merichem Company . . . . . . . . . . . . . . . . . 52 www.info.hotims.com/35907-88

www.info.hotims.com/35907-173

HPI Market Data 2012. . . . . . . . . . . . . . 143 Industry Reports . . . . . . . . . . . . . . . . . . 133 Refining Processes Handbook . . . . . . . . 109 Haldor Topsoe A/S . . . . . . . . . . . . . . . . . . . 68

(92)

www.info.hotims.com/35907-78

www.info.hotims.com/35907-166

HP Webcast—Spraying Systems. . . . . . . . 78

Lurgi GmbH . . . . . . . . . . . . . . . . . . . . .E-112 www.info.hotims.com/35907-92

www.info.hotims.com/35907-160

HP Webcast—Heinz Bloch . . . . . . . . . . . . 55

(91)

www.info.hotims.com/35907-58

Emerson Process Management . . . . . . . . . . 8

(80)

www.info.hotims.com/35907-80

www.info.hotims.com/35907-102

www.info.hotims.com/35907-97

Elliott Company. . . . . . . . . . . . . . . . . . . . 136

Lurgi GmbH . . . . . . . . . . . . . . . . . . . . . . . 14

Kobe Steel Ltd . . . . . . . . . . . . . . . . . . . . . . 99

www.info.hotims.com/35907-91

Eaton Filtration . . . . . . . . . . . . . . . . . . . . . 23

(69)

(87)

www.info.hotims.com/35907-87

Dresser-Rand. . . . . . . . . . . . . . . . . . . . . . . 51

Emerson Process Management (Fisher) . . . . 6

www.info.hotims.com/35907-61

www.info.hotims.com/35907-67

BASF Catalysts LLC . . . . . . . . . . . . . . . . . . 24

RS#

www.info.hotims.com/35907-157

www.info.hotims.com/35907-53

Baker Hughes Inc . . . . . . . . . . . . . . . . . . . 32

Page

www.info.hotims.com/35907-103

www.info.hotims.com/35907-155

Axens . . . . . . . . . . . . . . . . . . . . . . . . . . . 144

Company Website

www.info.hotims.com/35907-93

www.info.hotims.com/35907-165

Ametek Process Instruments . . . . . . . . . . . 25

RS#

www.info.hotims.com/35907-101

www.info.hotims.com/35907-151

API . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Page

www.info.hotims.com/35907-69

www.info.hotims.com/35907-70

API . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Company Website

Velan ABV SpA . . . . . . . . . . . . . . . . . . . . . 19

(153)

www.info.hotims.com/35907-153

(81)

Zyme-Flow . . . . . . . . . . . . . . . . . . . . . . . . 80

(75)

www.info.hotims.com/35907-75

For information about subscribing to HYDROCARBON PROCESSING, please visit www.HydrocarbonProcessing.com HYDROCARBON PROCESSING SEPTEMBER 2011

I 141

HPIN AUTOMATION SAFETY WILLIAM GOBLE, CONTRIBUTING EDITOR wgoble@exida.com

Are you a lawyer or an engineer?

Have you ever questioned some legal decision? I have certainly wondered about the logic behind certain legal cases.

When I read the “warning labels” on certain products, for example, I really wonder why you need this label. One thing seems certain. There are times when my engineering logic seems different from legal logic. I can recall several notorious examples in which the legal cases appeared to not make sense, but there is one that continues to reoccur in some variation. Since I have not really heard an example for a few years, I had assumed this kind of thinking no longer existed. Then a variation of this happened again—HAZOP refused!

Identifying process risks. Several years ago, a manager at

an industrial plant refused to allow a HAZOP (hazard and operability) study to be done. Remember: A HAZOP is a systematic review of possible hazards (things that can go wrong) in a process. During the HAZOP, estimates are made of the likelihood and consequences of each hazard (risk). If the risk of a hazard seems too high, a recommendation is made for improvement or for further study. It has been a commonly applied technique for decades.

So why would a plant manager ever consider not doing a HAZOP? For this company, the lawyers said they (plant management) were liable if they knew about a potential risk; however, if they were unaware, then, they were not liable. What? I am not a lawyer and I do not have formal legal training. Therefore, I cannot confirm the validity of this statement. But, it is clear to the safety engineer in me that this is nonsensical thinking.

Recognizing risk. Identifying risks and taking appropriate

action to reduce risk likelihood and mitigate the consequences would be a better approach. In my opinion, the best long-term risk-reduction policy is identifying risks and taking action to reduce risk likelihood and consequences. The best protection is an active risk-prevention program. The best way to avoid loosing a lawsuit is to avoid the accident!

Example. The most recent variation of this thinking is applied to automatic diagnostics for automation equipment.

While discussing a partial valve stroke test, an automation design engineer stated that he had no interest in an automatic diagnostic test that identified a problem in the valve. Why not?

The answer was: “then I would have to fix it, and we are too busy. If we don’t know about a problem, we don’t have to fix it. If we know about it, company policy requires that we fix it

142

I SEPTEMBER 2011 HYDROCARBON PROCESSING

within 48 hours.” In my opinion, this sure sounds like the kind of thinking applied to the legal case. I wonder if this engineer had experience in a legal case some years ago and was trying to apply the same logic.

It is easy to understand being overloaded. But clearly, the best approach is to know the condition of the automation equipment and to prioritize maintenance. What if a valve that was needed for safety shutdown was stuck and incapable of closing? In most processes, alternative safety measures could be implemented until the valve could be repaired or rebuilt.

Being disturbed by the apparent logical conflict between the legal advice I heard some years back and the value in a HAZOP, I checked further into this “legal” position. It seems that the plant manager or the lawyer got it wrong. There is logic supporting lack of full liability when a hazard is unknown and there are no methods to analyze the risk. But what happens when industry life-cycle safety standards exist, including risk analysis methods such as HAZOP. What happens when most companies in your industry are following these methods? The liability of not following safety standards is quite high.

Automatic diagnostics. What about automatic diagnostics

in automation equipment? Following the presented legal thinking, one might be considered liable by not using all available automatic diagnostic techniques. Of course, new techniques must be well proven and understood. There must be no serious side effects. In the partial valve stroke testing example, the technique has been around for a decade, and during that time, there have been some bad implementation that could cause false trips. And a majority of designs still do not use the technique. But good partial stroke testing designs will provide valuable diagnostic information that will help keep a safety system operational. Despite what you thought your lawyer said, today, a designer has no reason not to use the best techniques available. Lawyers and engineers agree on that. Remember: The best way to avoid losing a lawsuit is to avoid the accident in the first place. HP The author is a principal partner of exida.com, a company that does consulting, training and support for safety-critical and high-availability process automation. He has over 25 years of experience in automation systems, doing analog and digital circuit design, software development, engineering management and marketing. Dr. Goble is the author of the ISA book Control Systems Safety Evaluation and Reliability. He is a fellow member of ISA and a member of ISA’s SP84 committee on safety systems. Dr. Goble can be reached by e-mail at: wgoble@exida.com.

HPI MARKETDATA 2012 PUBLISHING OCTOBER 2011 Produced by the editorial staff of

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