Hydrocarbon Processing December 2013

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HydrocarbonProcessing.com | DECEMBER 2013

®

HPI FOCUS: TOP CONSTRUCTION

PROJECTSGlobal review of several

outstanding downstream projects

2014 HPI FORECASTReview of future trends for the

refining, petrochemicals and

natural gas industries

SPECIAL REPORT:

Plant Design, Engineering and

Construction

Select 58 at www.HydrocarbonProcessing.com/RS

Cover Image: A hydrogen reformer is in the construction phase. Linde Engineering is building a new turnkey gases facility in Al-Jubail, Saudi Arabia to supply Sadara

Chemical Co. with carbon monoxide, hydrogen and ammonia for use in the production of aromatics, isocyanates, amines and hydrogen peroxide. The plant will be operated

by Linde Gas. Photo courtesy of Linde Engineering North America Inc..

DECEMBER 2013 | Volume 92 Number 12HydrocarbonProcessing.com

SPECIAL REPORT: PLANT DESIGN, ENGINEERING AND CONSTRUCTION 39 Optimize relief loads with dynamic simulation

C. L. Xie, Z. G. Wang and Y. F. Qin 49 Mitigate heat exchanger corrosion with better construction materials

E. Perea 53 Video game technology transforms operator training

D. Coppin 57 Design a staggered depressurization sequence for flare systems

R. Dole, S. Bhatt and S. Sridhar

HPI FOCUS: TOP HPI PROJECTS 63 The design and construction of HPI projects are

multibillion-dollar efforts involving many stakeholders,

licensors, financial groups, E&C companies, equipment

vendors and more. The 2013 top HPI projects demonstrate

the engineering expertise utilized by five global complexes.

HP Staff

SAFETY 71 Rethink the hazards in your process

R. Modi

REFINING DEVELOPMENTS 75 Mitigate fouling in crude unit overhead—Part 3

A. W. Sloley

SAFETY/LOSS PREVENTION 80 Consider process-based failure analysis methods

for piping and equipment

D. L. N. Cypriano, G. B. Costa and M. J. Noronha

DEPARTMENTS

4 Industry Perspectives

10 Brief

13 Impact

17 Forecast

23 Innovations

86 Marketplace

89 Advertiser Index

COLUMNS 9 Editorial Comment

By the numbers

29 Reliability

Demand specifics in designing your asset management programs

31 Integration Strategies

Engineering design tools are moving to the ‘cloud ’

33 Boxscore Construction

Analysis

Iraq’s billion-dollar road to energy stability

90 Engineering Case Histories

Case 76: Simple troubleshooting analysis tips are useful

10

63

4�DECEMBER 2013 | HydrocarbonProcessing.com

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Middle East threatened by North American petrochemical exports

North American petrochemical producers have had lofty margins in recent years, due to abundant ethane feedstocks de-rived from the regional shale boom.

Those margins, in turn, are leading to plans for new capacity, which could eventually give those producers more petrochemi-cal products than the North American market can handle and put key companies in a position to need exports.

Shale sparks North American activity. The plans are sparked by continuing shale gas and oil discoveries throughout North America, leading to an ample and affordable supply of natural gas liquids (NGLs), such as ethane, to be used as ethyl-ene cracker feedstock.

Foreign companies are also beginning to target the lucrative US market. In a deal announced in early November, Mexico’s Mexichem formed a joint venture with US-based Occiden-tal Chemical (OxyChem) to build a 1.2-billion lb/yr ethylene cracker at Oxychem’s existing site in Ingleside, Texas (FIG. 1).

The Mexichem venture would start up operations in 2017, putting it on a similar timetable to several other announce-ments. That means that Middle Eastern producers should have at least a few more years of strong export viability.

Even in a few years, the Middle East will still hold the geo-graphic advantage of closer proximity to Asia and Europe, po-tentially giving Middle Eastern producers lower logistics costs relative to producers in North America. However, the new-found threat of overseas competition appears very real.

An expanded version of Industry Perspectives can be found online at HydrocarbonProcessing.com.

FIG. 1. Mexichem and OxyChem will build a new ethylene cracker at the existing OxyChem complex in Ingleside, Texas.

HP Poll Question: Will Middle East petrochemical producers lose market share in Asia and Europe due to North American exports?

HydrocarbonProcessing.com reader response:

Yes ........................................................................................................................................ 44%No ......................................................................................................................................... 28%Too early to tell ............................................................................................................ 28%

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Editorial Comment

STEPHANY ROMANOW, EDITOR

[email protected]

Hydrocarbon Processing | DECEMBER 2013�9

By the numbers

INSIDE THIS ISSUE

17 Market Data 2014 forecast. This summary

provides a “sneak peek” at Hydrocarbon Processing’s HPI Market Data 2014. This comprehensive report investigates present and projected trends in the refining, natural gas and petrochemical industries. Topics include spending forecasts and construction projects derived from HP’s Construction Boxscore Database; global and regional changes in energy production and use; and developments in oil and natural gas processing.

38 Plant design and E&C. The design and construction

of hydrocarbon processing industry (HPI) facilities is a global business. Often, front-end engineering and design is done by engineering offices located in different countries and time zones. The costs to construct mega-scale HPI complexes keep increasing. Advanced software and information management tools improve the layout of equipment and infrastructure.

63 HPI Focus: Top HPI projects. Construction

of HPI projects involves numerous risks. The design and construction of such complexes can take years. They are also multibillion-dollar efforts. Such projects can entail demonstration of leading-edge technologies. The HPI projects for 2013 are: Williams Energy’s propane dehydrogenation (PDH) project, Redwater, Alberta, Canada; Sasol North America’s ethane cracker and derivatives project, Lake Charles, Louisiana; Ecopetrol’s Cartagena refinery expansion, Cartagena, Colombia; Chevron Australia’s Gorgon LNG project, Barrow Island, Australia; and Indian Oil Corp. Ltd.’s Panipat refinery and petrochemicals complex, Panipat, India.

At times, engineers, bankers, scientists and accountants can be obsessed with numbers. Why? Because numbers are vi-tal, especially in the design and operation of process units and equipment. Anniver-saries, likewise, are numbers. They can be milestones for achievements or reminders that conditions have not changed.

40 years. For example, this year was the 40th anniversary of the first “oil shock,” when members of OPEC shut off crude supplies to the US. Costs for transporta-tion fuels quadrupled almost overnight, and fuel shortages were nationwide. HP’s younger readers may not remember the news images of long lines of vehicles at service stations or signs emphasizing gaso-line shortages and mandatory rationing for fuels. Crude oil was available; however, OPEC had taken a political stand against the US over its support for Israel.

In the 1970s, hydrocarbons met about 90% of the global energy demand. The breakdown was 60% oil, 7% natural gas and 23% coal. Nuclear energy had 9% of the energy market, with very little met through hydropower. According to BP’s latest statis-tical review, global energy demand met by non-hydrocarbons was 12% in 2012.

Hydrocarbons still, and will, remain the primary energy source for some time. The demand shares have changed since 1973; oil is now only 35% of the total energy demand, and coal has about 30% of the energy market. Natural gas demand has increased since the 1970s and holds about 23% of the energy market. More energy will be filled by natural gas, with greater conversion from coal and nuclear energy.

2X. In 40 years, global crude oil consump-tion has nearly doubled, from 55.7 million bpd (MMbpd) to nearly 90 MMbpd in 2013. The US remains the largest transpor-tation fuels market, but developing nations are the new consumer markets for transpor-tation fuels and petrochemicals. China and India are the major consumers of energy.

Some things never really change. History has shown that poor government policies can do more harm than the original problem that the policy was meant to reme-dy. During the 1970s, US price controls on natural gas created a gas bubble that stalled exploration and development, thus con-tributing to shortages. In 1978, the Natural Gas Policy Act in the US abolished price ceilings on old and new wells, spurring ex-ploration efforts and new gas supplies.

In the US, the renewable fuel standard requires that refiners blend designated volumes of ethanol on an annual basis or purchase renewable identification num-bers (RINs) to cover their deficit. Fraud in RIN markets and declining local gaso-line demand have added more chaos to the fuels market.

Ethanol has a place in the transporta-tion fuels market, but government rules hinder how the refining industry can pro-duce quality products for their customers. Free-market solutions would allow the re-fining and distribution industries to find the equable volume of ethanol that can be incorporated into the fuel system.

Likewise, Europe struggles with its en-ergy policies. The EU has the added chal-lenge of moving separate countries to meet the targets set for the 20/20/20 program. Some nations are overachievers, such as Sweden, which has attained its goals of a 20% reduction in greenhouse gas (GHG) emissions and a 20% increase in renewable fuels usage three years ahead of schedule. As a bloc, the EU has only attained a 12.7% decrease in GHG emissions at this time.

For 40 years, the EU’s refining industry has struggled with the aftereffects from the first oil shock. Approximately 11% of the EU’s refining capacity has been shut down for a number of reasons; most of them are pure economic issues. Like the US, the EU’s demand for transportation fuels is flattening out, if not declining.

This editorial has used many recent numbers; however, the old trends continue to dominate industry statistics.

| Brief

After a bitter labor battle, INEOS Grangemouth reopensINEOS Grangemouth (UK) has reopened its petrochemicals plant and oil refinery in

Scotland. The reopening comes after negotiations with the employees’ union resulted

in an agreement, the details of which include no strikes for three years; a move to a

modern pension scheme; a pay freeze for three years; and changes to union agreements

onsite, including no full-time union conveners. The union’s withdrawal of its opposition

to the company’s “survival plan” allows shareholders to invest a further £300 million in

the company, INEOS said. This money will be used to fund ongoing losses and to finance

the building of a gas terminal to bring in shale gas ethane from the US. The Scottish

government has indicated that it will support the company’s application for a £9 million

grant to help finance the terminal and the UK Government has given its prequalification

approval for a £125 million loan guarantee facility.

Photo courtesy of INEOS.


BILLY THINNES, TECHNICAL EDITOR / [email protected]

Brief

Iraq has a $6 billion contract with Swiss company Satarem to build and operate a 150,000-bpd oil refinery in the province of Maysan. The refinery is one of four new projects designed to increase refining capacity by around 740,000 bpd and revamp Iraq’s oil sector. Iraq’s Oil Ministry plans to add one 150,000-bpd refinery in each of the cities of Karbala and Kirkuk, as well as another 300,000-bpd facility in Nasiriyah. That would raise Iraq’s refining capacity to around 1.5 million bpd from 650,000 bpd–750,000 bpd.

In a speech to the European Petrochemical Association’s (EPCA’s) annual meeting in Berlin, Saudi Basic Industries Corp. (SABIC) Vice Chairman and CEO Mohamed Al-Mady said that Europe faces a new reality. He said the industry should focus on more resource and cost-efficient manufacturing, targeting incentives for innovation at the development stage, and instituting a regulatory framework based on clear goals. Regarding SABIC’s operations in Europe, he said the company will continue to play an active role in the region, striving to maintain its in-market manufacturing presence, providing technology from a growing innovative portfolio and utilizing the optimal value chain to develop solutions for both Europe’s shifting demographic profile and its exportable goods and technologies. For SABIC and other global companies to effectively contribute toward Europe’s economic growth, Mr. Al-Mady urged proactive and coordinated support from the various governments in the region.

Phillips 66 is planning to develop a liquefied petroleum gas (LPG) export terminal in Freeport, Texas. The new terminal is intended to help meet growing global market demand for US-supplied products. An executive from the company noted that “a liquefied petroleum gas terminal downstream of our Sweeny complex supports our growth strategy in midstream.” The proposed LPG export terminal would provide 4.4 million bbl/month of LPG export capacity, the equivalent of eight very large gas carriers. It would be located at the site of the company’s existing marine terminal in Freeport.

The LPG export terminal would be supplied with LPG from the Mont Belvieu area and from Phillips 66’s Sweeny complex at Old Ocean, Texas. Startup is planned for mid-2016.

Divestitures continue to drive deal activity in the US oil and gas sector, as foreign buyers and private equity players returned to the table as buyers of energy assets during the third quarter of 2013, according to PwC’s third-quarter M&A analysis for the oil and gas sector. While divestiture activity contributed 36 total transactions, representing 84% of total deal volume, a significant decline in midstream M&A activity, coupled with a lack of mega-deals, resulted in a decline in deal value for the third quarter of 2013 as compared to the same time in 2012.

For the three-month period ended September 30, there were a total of 43 oil and gas deals with values exceeding $50 million, accounting for $16.4 billion. It is a slight decrease from the 45 deals worth $37.6 billion in the third quarter of 2012.

Chevron Phillips Chemical has finalized the sale of its Chinese polystyrene business to Grand Astor. In the deal, Chevron Phillips is selling its affiliate company, Chevron Phillips Chemical (China) Co. Ltd., which owns a polystyrene plant in Zhangjiagang, China. Chevron Phillips Chemical initiated the sale after an internal review revealed that the plant was not a strategic fit for the company.

Lithuania is developing a $767-million project linking the Baltic natural gas transmission grid with the rest of Europe via Poland. The EU included the project in its list of common-interest energy projects, which means the pipeline is eligible for a substantial amount of financing. The new Polish connector, along with planned liquefied natural gas terminals in the Baltic region, will help Lithuania, Latvia and Estonia escape dependence on Gazprom for natural gas supplies. It’s also part of EU plans for a north-south gas corridor linking the Baltic, Black, Adriatic and Aegean seas.

Qatar Petroleum, in partnership with Qatar’s Ministry of Interior, has opened a new college dedicated to emergency and safety professions at Ras Laffan Industrial City. The Ras Laffan Emergency and Safety College (RLESC) opened on November 12. It is offering courses in fire safety engineering and fire safety management. Qatari leaders said the college will be a premier safety academy spread over 100 hectares and equipped with modern facilities. The RLESC will offer vocational training courses and academic programs. Plans for the future include degrees in safety, environment, occupational health, business continuity, incident management, and related fields. Applicants can enroll in single training courses on a specific field of study, or in full-time academic degrees. The first academic degrees will be available starting in September 2014.

Occidental Chemical (OxyChem) and Mexichem have created a 50/50 joint venture called Ingleside Ethylene to build an ethylene cracker with a 1.2-billion lb/yr capacity at the existing OxyChem plant in Ingleside, Texas. The venture includes associated pipelines and storage at Markham, Texas. As part of a long-term strategic supply relationship between the companies, essentially all of the ethylene produced from the cracker will be consumed in the manufacture of vinyl chloride monomer (VCM). The VCM will then be delivered to Mexichem to produce polyvinyl chloride (PVC) and PVC piping systems. The facilities are expected to become commercially operational in the first quarter of 2017.

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Impact

BILLY THINNES, TECHNICAL EDITOR / [email protected]

Fossil fuels dominate global primary energy consumption

Oil, natural gas and coal accounted for 87% of global primary energy consump-tion in 2012, according to a new World-watch Institute study. The relative weight of these energy sources keeps shifting, although only slightly. Natural gas in-creased its share of energy consumption from 23.8% to 23.9% during 2012, coal rose from 29.7% to 29.9%, and oil fell from 33.4% to 33.1%. The International Energy Agency predicts that, by 2017, coal will replace oil as the dominant pri-mary energy source worldwide.

The shale boom in the US is reshap-ing global oil and gas markets. The US produced oil at record levels in 2012 and is expected to overtake Russia as the world’s largest producer of oil and natu-ral gas combined in 2013. Consequent-ly, the US is importing less of these two fossil fuels, while using more domestic natural gas for power generation. This has led to price discrepancies between the US and European natural gas mar-kets, which, in turn, has prompted Eu-ropeans to increase their use of coal power. Coal consumption, however, was dominated by China, which accounted for more than half of the world’s coal use in 2012.

Global natural gas production grew by 1.9% in 2012, led by the US (with 20.4% of the total) and Russia (17.6%). Other countries accounted for less than 5% each of global output.

In 2012, coal remained the fastest-growing fossil fuel globally; Although, at 2.5%, the increase in consumption was weak relative to the 4.4% average of the last decade. China increased its coal use by 6.1%, and India by a significant 9.9%, in 2012. Coal use by members of the Or-ganization for Economic Cooperation and Development (OECD) declined by 4.25%, as an 11.9% decline in US con-sumption outweighed increases of 3.4% in the EU and 5.4% in Japan.

Oil remains the most widely consumed fuel worldwide, but, at a growth rate of 0.9%, it is being outpaced by natural gas and coal for the third consecutive year. The OECD’s share declined to 50.2% of global consumption—the smallest share on record and the sixth decrease in seven years. This reflects declines of 2.3% in US consumption and 4.6% in EU consump-tion. By contrast, usage in China and Ja-pan rose by 5% and 6.3%, respectively.

Conversely, global oil production grew by more than twice as much as con-sumption, to 2.2%, in 2012. This was due mainly to a rise in US output of 13.9%. In comparison, Canada, China and the for-mer Soviet Union saw small increases of 6.8%, 2% and 0.4%, respectively.

Bipartisan fuel policy recommendations for US Congress

A bipartisan group called the US En-ergy Security Council, comprising for-mer military, business and political lead-ers, has issued policy recommendations for the US Congress as it grapples with fuel-related legislative issues. The coun-cil believes the US Congress should cre-ate a topline fuel competition corporate average fuel economy (CAFE) credit for automakers that opens at least half of the vehicles in their fleet to competing fu-els, and ensures automaker compliance with CAFE counts as compliance with greenhouse gas regulations under the Clean Air Act. For flexible-fuel vehicles to count as fuel-competitive vehicles, the council recommends that they should be gasoline-ethanol-methanol flexible, not just gasoline-ethanol flexible. CAFE rule-making should be refocused on the origi-nal goal of energy security, prioritizing the reduction of oil’s importance through a performance-based, technology-neu-tral approach, the group said. As part of this effort, the metric of miles-per-gallon (mpg) in CAFE should be abandoned as the principal measurement of success since energy density differs across fuels.

In the secondary vehicle market, the council encourages the US Environmental Protection Agency (EPA) to further dereg-ulate the conversion kit market to enable safe, but low-cost, conversions to powering with substitute fuels. For fuels certifica-tion, the process that the EPA has recently opened to consider certifying a higher oc-tane fuel in the Tier 3 rulemaking should be expanded to include all alcohol fuels and the broadest range of blends feasible.

Other key policy recommendations from the US Energy Security Council’s new report include:

• Fuel tax fairness: Fuels should be allowed equal treatment under the federal tax code, and thus be taxed on an energy content basis rather than on a volume basis. State and local governments should also tax fuels equivalently using energy con-tent instead of on a volume basis.

• Emission calculation fairness: The EPA should level the playing field and not include upstream emis-sions for non-petroleum fuels when determining the CAFE “compliance value” for light-duty vehicles and for other purposes, since it does not do so for gasoline.

• Flexibility for states: The EPA should remove bureaucratic hurdles that thwart states from utilizing trans-portation fuel strategies that improve air quality to meet Clean Air Act ob-ligations. Congress should consider more innovative solutions to expand this flexibility, including the creation of a market for particulate matter that would cover one pollutant from mul-tiple sources and sectors.

In the realm of international policy, the council membership believes the US should engage in outreach to Brazil and China, offering advice and assistance with an eye toward collaboration. Highlights from this area include suggestions to:

• Form a US-China-Brazil alcohol fuels initiative that can be expand-ed to include other countries with robust alcohol fuels programs

Impact

14

• Expand international collabora-tion on electric vehicles with a spe-cific focus on those research areas that could lead to significant cost reduc-tion in automotive batteries

• Develop international standards for aftermarket retrofits that make vehi-cles flexible fuel or CNG compatible

• Expand the US-China shale gas resource initiative by collaborating with China and other emerging shale

gas producers on the development of new fracking techniques, new frack-ing fluids, safety standards and envi-ronmental best practices

• Engage in international efforts to reduce methane flaring by collabo-rating with major methane flaring nations on identifying economic and environmentally sustainable strate-gies to turn unused methane into us-able fuel.

Global slowdown in annual CO2 emissions

Research published by the Emissions Database for Global Atmospheric Re-search (EDGAR) indicates that global carbon dioxide (CO2 ) emissions in-creased by only 1.1% in 2012, yielding a slowdown in annual global CO2 emis-sions, at 34.5 billion tons in 2012. ED-GAR said that the past decade saw an average annual CO2 emissions increase of 2.7%, but, in 2012, the actual increase was only 1.4%. EDGAR is a joint project of the European Commission Joint Re-search Center and the Netherlands Envi-ronmental Assessment Agency.

A comparison of regional CO2 emis-sion trends revealed large differences in underlying sources, which complicates the evaluation of the robustness of ob-served trends. The top six emitting coun-tries/regions are China (29%), the US (16%), the EU (11%), India (6%) and the Russian Federation (5%), followed by Japan (4%). In 2012, in the US and the EU, CO2 emissions decreased by 4% and 1.6%, respectively. Total CO2 emissions from all OECD countries account for one third of global emissions—the same share as that of China and India, where, in 2012, emissions increased by 3% and 7%, respectively.

China. In 2012, China’s average emission level of 7.1 tons CO2 /cap resulted from a smoothing of the country’s CO2 growth, to only 3%, after an annual growth rate of about 10% over the last decade. The increase in China’s CO2 emissions was mainly due to a continued high economic growth rate, with related increases in fos-sil fuel consumption.

While China’s CO2 emissions per cap-ita would be comparable to those of the EU and to almost half of those in the US, its CO2 emissions per US dollar (USD) are almost double those of the EU and the US, and, since 2004, are similar to CO2 emissions per USD in the Russian Fed-eration. China’s large economic stimulus package, intended to avoid a decrease in annual economic growth during the re-cent global recession, has ended.

With electricity and energy growth at half the pace of its GDP growth, China’s energy intensity per unit of GDP declined in 2012 by 3.6% (twice as fast as in 2011). This slower and structurally changed

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Impact

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growth puts the country back on track to achieve both the national energy con-sumption target for 2015 and that of its 12th five-year plan, with an almost 17% cumulative reduction in energy intensity per unit of GDP, compared to 2010. Chi-na also increased its hydropower capacity and output by 23% in 2012, which had a significant mitigating effect of about 1.5% on its CO2 emissions in that year.

US. The second-largest CO2 -emitting country is the US. It has showed a de-crease in CO2 emissions since 2005, but with 16.4 tons CO2 per capita in 2012, its emissions per capita still rank among the highest of the major industrialized countries. Until 2007, the CO2 per cap-ita remained fairly constant. However, from 2007 onward, per-capita emissions decreased, partially because of a popula-tion growth that was much larger than in other OECD countries, but also because of an absolute decrease in emissions. With 2012 economic growth around 2%, emissions levels were reduced by 4% through a fuel shift from coal to gas in the power sector.

According to satellite observations, flaring emissions in the US have been on the rise, with a 50% increase in 2011. The main cause is the sharp increase in the country’s use of hydraulic fracturing for shale oil production, and the related flar-ing of associated gas. Over the past five years, the share of shale gas has increased to one third of the total US gross gas pro-duction, and the share of shale oil in 2012 represented almost one quarter of total US crude oil production.

EU. The EU, as a whole, remained in eco-nomic recession in 2012: the EU’s GDP in 2012 declined by 0.3%, compared to 2011. However, actual CO2 emissions declined by 1.3% in 2012, compared to 2011—less than the 3.1% decrease in 2011.

The main causes were a decrease in primary energy consumption of oil and gas, a 4% decrease in road freight trans-port, and a 2% decrease in total emissions from power generation and manufactur-ing installations participating in the EU emissions trading system. While the total CO2 emissions for power generation in the EU decreased by 2.3% in 2012, very different trends have been noticed for various EU member states—in particular for coal. There was renewed interest in

the use of coal in electricity production in Europe’s energy mix. In 2012, increased coal consumption was observed in the UK (+24%; the highest consumption lev-el since 2006), Spain (+24%; the second year with an increase after two years of de-creasing consumption), Germany (+4%) and France (+20%), vs. decreases in Po-land (4%) and the Czech Republic (8%).

The low increase in emissions in 2012 may be the first sign of an emis-

sions slowdown. These trends could continue if China achieves its own tar-get for the maximum level of energy consumption by 2015 and its shift to gas with a natural gas share of 10% by 2020; if the US continues its shift in the ener-gy mix toward more gas and renewable energy; and if EU member states agree on restoring the effectiveness of the EU emissions trading system to further re-duce emission levels.

Do you have flows up to 1,400 US GPM (320 m3/hr), heads up to 3,400 feet (1,000 m), pressures upto 1,500 psig (100 bar),temperatures from 20˚F to300˚F (-30˚C to 149˚C), and speeds up to 3,500 RPM?Then you need Carver Pump RS Series muscle!Designed for moderate to high pressure pumping applications,the RS is available in five basic sizes with overall performanceto 1,000HP. As a standard, with a product lubricated radialsleeve bearing and two matched angular contact ball bearingsfor thrust, it only takes a mechanical seal on the low pressure,suction side to seal the pump. Optional features include ballbearings on both ends with an outboard mechanical seal,various seal flushing arrangements and bearing frame cooling.These features make the RS ideally suited for Industrial andProcess applications including Pressure Boost Systems, BoilerFeed, Reverse Osmosis, Desalination and Mine Dewatering.Whatever your application, let us build the muscle you need!

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Creating Value.Carver Pump Company2415 Park AvenueMuscatine, IA 52761563.263.3410Fax: 563.262.0510www.carverpump.com



Forecast

HP STAFF / [email protected]

HPI Market Data 2014 Executive Summary

OPTIMISM PREVAILS FOR 2014The 2014 outlook for the global hydrocarbon processing

industry (HPI) is upbeat. This development is a reversal from previous forecasts. What events and factors orchestrated this switch? Many trends and market conditions are converging to support the uplift of the HPI.

Economic growth. The world gross domestic product is ris-ing, and growth is estimated to average 3.6%/yr in 2013. This increase is directly related to burgeoning demand for energy, especially electrical power and transportation fuels, which are primarily hydrocarbon-based. Over the long term, crude oil, coal and natural gas will still constitute over 80% of global en-ergy demand. Expanding economics of non-Organization for Economic Cooperation and Development (OECD) nations are driving new energy demand. China and India will be responsi-ble for nearly half of the future increase in energy consumption. Renewable energy is growing in market share, but will still be a minor part of the energy mix.

New manufacturing centers. Increased availability of natu-ral gas supplies are redefining energy conditions for several na-tions. New natural gas reserves are shifting the order for produc-ing nations. Shale gas reserves, once difficult to extract, are now being exploited in North America. New horizontal drilling and hydraulic fracturing methods have facilitated production from shale formations.

In particular, the development of shale gas is coproducing shale oil and natural gas liquids (NGLs), which has radically changed hydrocarbon supply levels. Non-OPEC nations are in-creasing their crude oil production efforts and are altering the crude oil market.

CONSTRUCTIONThe global HPI is a cyclical business. Demand expands and

contracts at varying rates. The challenging task is planning new capacity to come online during the uplift in the demand cycle. The 2008 global economic slowdown pushed back completion of major HPI projects. It also shifted demand centers. Devel-oped (OECD) nations will continue to mature in demand for HPI products. Consequently, existing facilities will be able to meet local demand with some support by imports. Also, con-struction activity will continue to revamp and update worn and outdated equipment and inefficient process technologies.

The developing (non-OECD) nations are the new consumer product demand centers and the locations for HPI construction activity. In particular, China is the dominant economy. Sup-

ported by a growing population, this nation will be the largest economy and energy-consuming country in the near term.

As shown in TABLE 1, HPI construction continues in all re-gions. Many factors influence the location, type and scale of an HPI project. As illustrated in FIG. 1, refining and petrochemi-cal projects exceed gas processing projects on an annual basis. These projects include revamps and retrofits of existing facili-ties along with grassroots construction.

SPENDINGThe costs for designing and constructing downstream HPI

facilities have nearly doubled since 2000, as shown in FIG. 2. The sharp rise reflects cost inflation on a global basis for HPI proj-ects and the higher expense for construction projects in high-

FIG. 1. Breakdown of HPI projects by market sector, June 2009 to June 2013.

0200

400

600

800

1,000

1,200

1,400

1,600

1,800

2,000

20132012201120102009

World

wide

HPI c

onstr

uctio

n proj

ects All others

Gas processingRefiningPetrochem/chem

TABLE 1. Worldwide HPI construction projects by region: June 2009 to June 2013

Jun-09 Jun-10 Jul-11 Jun-12 Jun-13

US 714 716 421 485 476

Canada 212 209 155 168 149

Latin America 530 607 469 480 324

Europe 1,261 1,283 956 920 428

Africa 215 231 179 241 189

Middle East 990 1,057 822 795 767

Asia-Pacifi c 1,551 1,629 1,277 1,157 1,102

Total 5,473 5,732 4,329 4,246 3,435


Forecast

risk countries. Sharp increases in steel costs drove this recent surge in construction expenses. Costs for all steel-using projects have been rising. Equipment costs (reactors, heat exchangers, distillation columns, etc.) are now more expensive, thus raising capital costs for HPI facilities on new equipment and replace-ment units. Likewise, the complexity of HPI projects is increas-ing and contributing to higher costs. More importantly, risk also grows, adding more cost to the project.

In 2014, the HPI’s capital, maintenance and operating bud-gets are expected to exceed $279 billion (B) (TABLES 2 and 3). Capital spending is projected to reach $77 B; maintenance spending should reach $82 B; and operating spending is esti-mated at $119 B. The HPI continues to be more cost-conscious.

HPI companies will invest in technologies to support their mission goals, such as improving plant economics, increasing en-ergy efficiency, boosting yields of desired products, eliminating unwanted byproducts or wastes, and increasing sustainability.

REFININGOver the next 10 years, global demand for oil products will

increase; demand will be just below 100 million barrels per day of oil equivalent (MMbdoe). However, this growth will not be evenly distributed. As shown in FIG. 3, the total demand for crude oil (transportation fuels) will increase. However, the de-

mand/consumption by OECD countries is flattening and even declining. OECD nations include Western European countries, the US and Japan. Lower automobile fuel consumption will reduce oil demand by about 0.5%/yr, thereby creating a refin-ing overcapacity environment in some nations. The situation is completely different in developing or non-OECD countries. Due to growing economies for these nations, the GDP is rapidly increasing. For non-OECD countries, demand for oil products will rise at the rate of 2%/yr, as shown in FIG. 3.

China, India, Brazil, and Russia are the nations driving new demand for refined products. Expanding economies and popu-lations are the momentum driving higher demand and con-sumption of energy. China and India are the dominant nations responsible for most of the new demand. The US remains the largest market for refined fuels. However, the US fuels market is now mature and has flattened out.

The market share of the global refining industry continues to shift. As shown in FIG. 4, since 1995, the market share of re-fining capacity has shifted from North America and Europe to the Asia-Pacific region. Over 650 refineries with a combined processing capacity approaching 93 MMbpd are in operation worldwide. Present-day refineries vary in complexity, size and age. The majority of the present distillation capacity uses tra-ditional crude oil feedstocks. However, looking forward, more refining capacity will be designed or revamped to process un-conventional feeds such as low-API-gravity crudes, bitumen and shale oils. Margins are sustained by unique combinations of complexity and capacity.

Transportation fuel demand is driving new refining capacity and associated capital investments (TABLES 2 and 3). Despite fuel subsidies affecting refining investments in certain countries, Asia has successfully attracted investors from other regions. Many crude oil producers outside Asia view investing in new Asian grassroots refineries as a secured crude oil offtake. This trend has been observed in several major refinery investments in China, Vietnam and Indonesia, where the potential investors are crude producers from the Middle East (ME), Russia and Venezuela.

In planning for the future, Asian refiners are configuring refineries to have the flexibility to process heavy crudes. Such crudes are being consumed at the source by new refining proj-ects in the ME and Latin America, leaving less oil available for Asia. There is a mismatch between the expectation and the real-ity with respect to heavy crudes availability. Interestingly, light crudes are expected to be in global surplus largely due to the

TABLE 2. 2014 worldwide HPI spending, billion $

US OUS Total

Petrochemical 41.3 96 137.3

Refi ning 25.4 78.8 104.2

Gas processing/LNG 11.2 26.8 38

Total 77.9 201.6 279.5

TABLE 3. 2014 worldwide total spending by budget, billion $

US OUS Total

Capital 21.7 56 77.7

Maintenance 19.9 62.8 82.7

Operating 36.3 82.8 119.1

Total 77.9 201.6 279.5

FIG. 2. Downstream capital costs index, 2000–2012.

50

Source: IHS CERA20012000 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012

100

150

200

250

Index

, 200

0=10

0

0

10

20

30

40

50

60

70

2000

Liquid

fuels

dema

nd, M

Mbpd

2005 2010 2015 2020 2025 2030 2035 2040Source: EIA, Annual Energy Outlook 2013Howard Gruenspecht, CNA Panel, May 8, 2013

OECD

66

4741

Non-OECD46

FIG. 3. Demand for liquid fuels by OECD and non-OECD nations, 2000 to 2040.

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Forecast

tight oil revolution in the US. New shale oil is transforming the energy industry in North America. This has narrowed the light-heavy differential, which could impact the return on investment for many upgrading projects.

This renaissance in US refining will have a profound effect on the European refining industry. Unfortunately, Europe has lower refinery utilization rates; even worse, this region can ex-pect another round of capacity rationalization. However, this does not necessarily translate into opportunities for Asia. The new investments in the ME and Former Soviet Union (FSU) will better serve the European markets due to their proximity and competitiveness. From 2012 to 2018, the ME will see eight new grassroots refineries come onstream with 2.2 MMbpd of total capacity. The region will have an incremental demand growth of just 1.5 MMbpd. Clearly, the ME is positioning it-self as an export refining center. Similarly, the FSU region is also embarking on residue upgrading investments to make its refin-eries more competitive.

NATURAL GAS/LNGThe natural gas market is dominated by upstream develop-

ment in shale gas production, particularly in North America, and by midstream and downstream progress in gas-to-liquids (GTL) and liquefied natural gas (LNG) technologies and proj-ects. Shale gas reserves, once difficult to extract, are now being exploited in North America. This boom in shale gas production

has coincided with an expansion of global LNG trade and re-newed interest in GTL production, enabling the transport, stor-age and processing of both conventional and unconventional natural gas independently from pipelines.

Globally, gas output is projected to increase by 2%/yr through 2030. Of this growth, 73% is forecast to come from non-OECD countries. The OECD areas of North America and Australia will also show strong growth, more than offsetting de-creases in European output. Gas is projected to contribute 21% of energy demand growth in the power sector and 16% in the transport sector. By 2030, gas will be neck-and-neck with biofu-els in the transport sector as the fastest-growing alternative fuel.

Over the next two decades, North America is likely to be-come self-sufficient in energy, and the US is anticipated to be-come a net exporter of LNG within the next few years. However, slow economic growth and continuing interest in renewable en-ergies will act as a drag on European gas demand. Meanwhile, the development of new gas resources in the ME, West Africa and Asia-Pacific will support demand in those regions. China will grow more import-dependent as its overall energy needs grow. FIG. 5 shows sources of gas supply through 2030 in North America, the EU and China.

The combination of a significant reduction in gas prices over the last several years and an escalation in oil prices has led to a high spread between oil and gas prices. This has drastically improved economics for GTL, and it has made GTL the most promising al-ternative for adding value to natural gas assets in North America. In the US, there is increased interest in mobile processing tech-nologies, especially for GTL and LNG production.

Globally speaking, LNG output is set to expand through 2030, making up more than 15% of global gas consumption in that year. Africa is projected to outpace the ME to become the world’s largest net LNG exporter, while Australia may overtake Qatar as the world’s largest single LNG-exporting country as new projects come onstream.

Also, the rapid increase in gas production from shale forma-tions, along with rising prices for natural gas liquids (NGLs), are encouraging the construction of additional gas processing facilities in the US. In particular, rising propane and ethane sup-plies have posed infrastructure and market challenges to move these new supplies to domestic and export markets.

Spending on gas processing projects is forecast to remain high through 2017, peaking in 2015. Capital investment is on-going to construct gas processing capacity as well as new ca-pacity for LNG imports and exports and capacity for NGLs. Investments reflect ongoing efforts to retrofit existing plants to meet growing demand for energy and natural gas products, to improve processing flexibility, and to comply with environmen-tal and safety regulations.

PETROCHEMICALS The future has arrived. No longer are petrochemical players

debating the reality of shale gas in North America, or if demand will hold up from unconventional sources such as China and India (FIG. 6). While the market mulled over those issues during recent years, it is apparent today that these trends are the new market reality.

In 2013 and beyond, the key questions surround what pet-rochemical players can do to capitalize on those trends. For

Sources: BP Statistical Yearbook; A.T. Kearney analysis

Asia-Pacific

0

20

40

60

80

100

Refin

ing ca

pacit

y by r

egion

, %

AfricaMiddle EastEurope and Eurasia

Latin AmericaNorth America

201020052000199519901985198019751965

FIG. 4. Refining capacity by region, 1965–2010.

FIG. 5. Gas supply sources in North America, Europe and China to 2030.

ChinaNorth America EU

Net pipelineimportsNet LNG importsShale gasproductionOther domesticproduction

1990 2010 2030

Gas s

upply

, Bcfd

1990 2010 2030-20

0

20

40

60

80

100

120

-20

0

20

40

60

80

100

120

-20

0

20

40

60

80

100

120

1990 2010 2030

Intelligence is the big diff erenced

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Forecast

example, how can North American producers best position themselves logistically to receive maximum quantities of shale-derived ethane feedstock? Also, in an increasingly international marketplace, how can producers near China and India use their proximity to demand centers to outweigh cost advantages from US players? And how can producers with none of these geo-graphic advantages, such as those in Europe, stay afloat?

In the US, shale technology has evolved rapidly and continues to improve, led by horizontal wells, lower rig cycle times, multi-ple fracs and multi-well pads. The technology is also scalable and transferable to numerous shale plays. Combine that with the sub-stantial amount of new reserves that are rich in NGLs, and there appears to be a feedstock haven for petrochemicals. In addition, the crack spread for gas continues to widen relative to crude (FIG. 7). That gives midstream producers enough incentive to continue drilling in shale plays.

To fully take advantage of the shale wave, however, the US industry awaits key regulatory decisions that will significantly impact the availability of feedstocks. As of September 2013, the Obama administration had yet to make a decision on the massive Keystone XL pipeline proposal from TransCanada—a network that would bring Canadian crudes to the US Gulf refin-ing belt, which is largely integrated with petrochemical plants. Critics allege that the benefits of Keystone XL are outweighed by environmental concerns.

If pipelines are judged to be too risky to the environment, it would seem the next step would be transporting feedstocks by rail. Indeed, many downstream players are buying stakes in key

North American rail systems. Some are even creating offloading facilities adjacent to their plants, such as Tesoro in the state of Washington. But the rail industry also comes with controversy. In July 2013, the deadly derailment of a crude-carrying train in Quebec killed 47 people, prompting Canadian officials to launch a review into rail safety.

Trucks and barges are options in theory, but they are likely too expensive to work on a larger scale. Thus, for the petrochem-ical industry to fully capitalize on the shale revolution, further regulatory guidance is needed on the pipeline and rail fronts. An-other area where regulatory clarity is needed in the US is on the thorny issue of natural gas exports. Numerous applications to export gas have been submitted, but as of September 2013, only three had been approved. If gas exports occur on a larger scale, that would expose more international players to the US market, thereby raising demand and, potentially, prices. That scenario could lead to lower margins for US petrochemical companies in the years ahead, at least relative to the recent boom years.

While margins relative to feedstock costs are best in North America, developing countries still possess the advantage of proximity to demand (FIG. 8). Even with cheap feedstock access in North America, post-recession demand is not growing quick-ly enough to consume the potential supply. As a result, produc-ers must have domestic or export access to locations such as China, India and other developing Asia-Pacific countries, where demand continues to surge. The IEA projects roughly 6% eco-nomic growth for the region in 2014, including about 9% for China and India, giving incentive to producers to keep operat-ing rates high. Several expansions are also underway, including Reliance’s massive refinery petcoke gasification project at Jam-nagar, India. The project is the largest of its kind in the world.

So, what can petrochemical players do to compete globally if they do not have the built-in advantages of proximity, cheap feed-stocks or high demand? The preferred strategy seems to be inte-gration between refining and petrochemicals, which can provide synergies and which gives the ability to hedge market risks. There are several potential integration types to consider. The first is pro-cess integration, which means innovative designs of downstream petrochemical plants. The second is utility integration, which in-cludes heat, hydrogen, water, steam and electricity. The third and final type of integration is the treatment of fuel gas, such as utiliz-ing the hydrogen and hydrocarbons present in fuel gas as a pet-rochemical feedstock. By region, the ME is the best positioned to execute those plans based on its newer facilities, according to industry officials. Meanwhile, Western European sites, which are specialized, could struggle the most.

FIG. 6. Regional ethylene consumption, 1990–2016.

90 92 94 96 98 00 02 04 06 08 10 12 1414 16

North America West Europe AsiaOthers Middle East South America

Source: IHS

0

10

20

30

40

50

60

70

80

Regio

nal e

thyle

ne co

nsum

ption

, milli

on m

etric

ton

Asia-Pacific regional equivalentethylene consumption to reach76 million metric tons by 2017.

Forecast

FIG. 7. US gas prices compared with crude, 2000–2020.

051015202530354045

0

2

4

6

8

10

12

14

2000 2005 2010 2015 2020

Henry Hub Price

Henr

y Hub

Price

WTI Ratio

Henry Hub natural gas price, constant $/MMBtu

WTI c

rude

/gas

ratio

Note: Crude/Gas Price Ratio is the WTI Cushing price in $/Bbl divided by the Henry Hub gas price in $/MMBTU.Source: IHS

FIG. 8. Ethylene demand in developed, developing countries, 1990–2020.

0102030405060708090

100110120130

90 92 94 96 98 00 02 04 06 08 10 12 14 16 18 20

Developed CountriesDeveloping CountriesWorld

Ethyle

ne, m

illion

metr

ic to

ns

Source: IHS


Innovations

ADRIENNE BLUME, MANAGING EDITOR

[email protected]

Software combines crude management with design

Invensys released its integrated Spiral CrudeSuite crude oil knowledge-man-agement software (FIG. 1) with its SimSci PRO/II design and ROMeo optimization software. The integrated offering gives the hydrocarbon processing industry a single-source software solution that enables ac-cess of crude assay information for refin-ery design, analysis and optimization.

The integrated Spiral CrudeSuite of-fering will provide accurate and com-plete crude assay information through-out plant lifecycle modeling, from design through operations and performance optimization. Spiral CrudeSuite sup-plies detailed, validated crude assay data so that engineers can design accurate refinery processes using the company’s SimSci PRO/II software. Also, its com-prehensive crude assay data helps engi-neers optimize the refinery for maximum profitability using the company’s SimSci ROMeo software.

According to the company, Spiral CrudeSuite software will help refiners understand their exposure to changes in feedstock costs, product demand and re-finery operations; increase the accuracy of their models; and accelerate new designs and revamps.


Gas turbine monitor tracks vibration

CAS DataLoggers provided its Del-phin Expert Vibro Data Acquisition and Control System (FIG. 2), a vibration moni-toring solution, for a refinery relying on a gas turbine-driven generator for power.

The facility uses an older generator that has developed vibrations in its shafts and bearings, causing fatigue failures. Turbine failure could be due to bearing wear, failure damage to turbine blades or a number of other factors; therefore, ef-fective fault diagnosis requires analyzing data collected during critical failure win-

dows. Technicians were required to es-tablish condition monitoring of vibration signals of the engine’s bearings and shafts during operation. Users also needed to acquire process data from the turbine, including temperature, pressure, flow-rate and rotations-per-minute data. Ad-ditionally, the generator’s manufacturer requested remote-monitoring access to this data for maintenance purposes.

The Expert Vibro system’s eight syn-chronous analog inputs enable universal connection for accelerometers and dis-placement sensors at sampling rates of up to 50 kilohertz per channel. The sys-tem also features four analog outputs and eight digital outputs for monitoring. In-tegrated comparators for Keyphasor sen-sors and four digital inputs are included to enable flexible triggering. All channels are galvanically isolated to prevent trans-verse distortions.

The system’s touchscreen display shows configuration and measurement data. The monitor is connected to the control room’s programmable logic con-troller (PLC) to continuously acquire pressure vibrations along with other mea-surements from the turbine. In this way, the Expert Vibro system performs com-prehensive condition monitoring for the gas turbine across every value of interest, using not only vibration data but also pro-cess data, such as bearing temperatures.

Turbine control is provided by the control room’s PLC. In the event of a failure, the PLC will initiate a shutdown command. As soon as the turbine re-ceives the signal to shut off, there is a critical window both before the trigger-ing event and as the turbine slowly spins down. Whenever this event occurs, the Expert Vibro system automatically buf-fers the data from the last 10 minutes in memory before the alarm occurred, so that users can then record that buffer to the system’s non-volatile storage. In this way, users can analyze the data in the software for effective turbine failure diag-nostic purposes.


SNG catalyst used in first CO2 methanation plant

Clariant supplied a proprietary CO2-syngas (SNG) catalyst for the metha-nation unit of Audi’s new power-to-gas facility in Werlte, Germany. The plant was started up in June 2013 and is part of Audi’s comprehensive sustainability initiative. It will produce an average of 1.4 million cubic meters of renewable synthetic methane per year, chemically binding some 2,800 metric tons of CO2 and equivalent to supply 1,500 Audi A3 Sportback g-tron vehicles with an annual mileage of 15,000 CO2-neutral km.

The plant was developed, constructed and built by ETOGAS GmbH (formerly SolarFuel). The technology can also be used to store surplus energy in the gas pipeline system and to balance energy supply against demand.

FIG. 1. Invensys integrated its Spiral CrudeSuite crude oil knowledge-management software (pictured) with its SimSci PRO/II design and ROMeo optimization software.

FIG. 2. The Delphin Expert Vibro Data Acquisition and Control System’s compact design and channel feeds enable easy installation.

24

Clariant’s power-to-gas methanation technology has been under development since 2009. The Center for Solar Energy and Hydrogen Research in Stuttgart, a research and development partner of ETOGAS and a cooperation partner of Clariant’s catalysts business unit, initially developed the technology. The Center has successfully operated several CO2-methanation pilot plants with Clariant’s SNG catalyst.


Temperature aid boosts water cut monitor accuracy

AMETEK Drexelbrook recently added temperature compensation to its Universal IV CM Water Cut Monitor to improve its accuracy and reliability for temperatures up to 71°C (160°F). The temperature-compensated model (FIG. 3) delivers superior water cut measurement accuracy in the low ranges (0%–1%, 0%–5%, 0%–10%, and 0%–30% water), accu-racy down to 0.03% water, and measure-ment resolution down to 0.0002% water.

The unique Perm-A-Seal sensing el-ement installs directly into a main pro-cess line without requiring spool pieces, side-arms or slipstreams, and its proven Cote-Shield technology ignores coating buildup on the probe.

Oil and gas applications for the Univer-sal IV CM monitor include automatic well testing, lease automatic custody transfer, basic sediment and water, separation ves-

Innovations

MSA, the world leader in Fixed Gas and Flame Detection, is known globally for our commitment to quality. Our full line of monitors and controllers are designed with the most advanced technologies to provide complete solutions for your detection needs.

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sels, pipeline slug detection, truck unload-ing, pipe protection, dielectric analysis, and machinery lube oil monitoring.

The monitor has a built-in LCD dis-play and keypad. It can be configured for American National Pipe Thread (NPT) standard tapered or flanged mountings, and it can be installed in all common pipe diameters. It is fully backward-compatible with Drexelbrook’s CM-6 and CM-3 sys-tems, offering users a seamless transition to the Universal IV system.

Its sensing element takes an average of the capacitive property of the fluid over its entire length, ensuring a smoother and more accurate response regardless of the mixture. The capacitance technology is significantly less expensive than micro-wave monitoring, while offering superior accuracy for low-range applications.


Linde enhances H2 transport efficiency

The Linde Group developed a new storage technology that will enable the more efficient transport of large amounts of hydrogen (H2). The new solution works at a high pressure of 500 bar (7,250 psi) and uses new, lighter storage materi-als to more than double the amount of compressed gaseous hydrogen (CGH2) that can be transported in a single truck load. Successful field tests with the first reference customer have confirmed sever-al benefits of the 500-bar technology over 200-bar systems.

According to Linde, the technology reduces the cost of transporting H2 to fueling stations and reduces the required amount of onsite gas storage space. Linde has opened a 500-bar fueling station at its gases center in Leuna, in the German state of Saxony-Anhalt. Linde developed the 500-bar trailers in collaboration with compressed gas storage specialist Wys-trach GmbH.

Each trailer features 100 lightweight, composite storage elements developed in collaboration with Xperion Energy & Environment GmbH. A single trailer can transport over 1,100 kilograms, or 13,000 normal cubic meters, of H2 gas. In addi-tion, the trailers can now be filled and emptied in less than 60 minutes.

This technology offers bulk custom-ers a cost-effective alternative to existing cryogenic transport solutions for liquid

hydrogen (LH2). Going forward, Linde plans to incorporate the new technology into its H2-fueling station concepts.


Submersible pumps save operational costs

In offshore production, submersible well pumps can be high-maintenance and can significantly impact operational costs. The ClydeUnion Pumps Hydraulic Sub-mersible Pump (HSP), an SPX brand, was developed by analyzing the failure modes of traditional electric submersible pumps and designing them out, creating a pump with high reliability and a long service life. This innovative pumping solution has typically three times the life of an electric equivalent and offers increased availabil-ity, providing for substantial reductions in offshore operational expenditures.

The HSP is a hydraulic solution, and the removal of electrical power sys-tems greatly reduces the opportunity for equipment failure. Longevity is enhanced through the use of the power fluid sup-plied from the surface, which provides life support to the critical balance and bearing systems. Rubbing bearings and seals have also been eliminated, improving reliabil-ity and extending the useful working life of the pump.

The HSP operates at high speed and has a high energy density, providing a compact design that is shorter than an equivalent electric motor powertrain. This design feature makes the HSP easier to install. With increased robustness, it reduces the risk of damage during its de-ployment. The single-shaft design of the combined pump and turbine enables the HSP to be supplied, fully assembled and tested from the manufacturing facility.

The HSP is designed with the highest-grade materials to resist wear and corro-sion for the full life of a well. Its flexibility in operation means that it can handle 75% continuous gas content and 100% gas slugs, reducing the occurrence and risks of damage from gas lock. This means that it can handle significant variances in pre-dicted design conditions without com-promising reservoir production rates or being prone to early failure.


Innovations

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Eric BenazziMarketing Director

David Bridgeman Global Licensing Manager

Carlos CabreraExecutive Co-Chairman

Dr. Charles CameronHead of Research & Technology

Giacomo FossataroGeneral Manager

Dr. Madhukar Onkarnath GargFNAE Director

Rajkumar GhoshDirector (Refi neries)

Andrea GragnaniRefi ning Product Line Director

Doug KellyVice President, Refi ning Technology

Dr. Syamal PoddarPresident

Giacomo RispoliExecutive Vice President, Research & Development and Projects

Stephany RomanowEditor

Dr. Ajit SapreGroup President Research and Technology

2014 Advisory Board

Hydrocarbon Processing’s fi fth annual International Refi ning and Petrochemical Conference takes place in Verona, Italy on 24 – 26 June 2014. We invite you to take part in this market-leading event.

IRPC 2014 will explore the latest advancements and best practices in technology and operations in the refi ning and petrochemical industries. One track of the conference will be devoted to Biofuels and Clean Fuels. The conference offers both a local and global perspective and is attended by senior executives and engineers from leading operators, refi neries, petrochemical plant and gas processing plants from around the world. IRPC 2014 participants will have the special opportunity to take part in a tour of Eni’s Venice biorefi nery, the fi rst refi nery in the world to convert from a conventional plant into a biofuels production plant based on Eni’s patented Ecofi ning technology.

IRPC 2014 will Cover:• Clean fuels• Biofuels• Catalyst developments• Plant and refi nery sustainability• Maintenance and reliability

• Energy policy• Profi tability• Effl uence management• Gas treatment technologies

• Rotating equipment• Bio-based petrochemicals• Alternative feedstock fuels (GTL, CTL)

VERONA, ITALY | 24–26 JUNE 2014

Here are 3 Ways You Can ParticipateMake your plans to be a part of IRPC 2014 and take advantage of this exclusive opportunity to learn from and network with many of the global HPI’s most dynamic and innovative executives and engineers.

Call for AbstractsGulf Publishing Company and Hydrocarbon Processing invite you to submit an abstract for the conference. Abstracts should be approximately 250 words in length and should include all authors, affi liations, pertinent contact information, and the proposed speaker (person presenting the paper). Topics should pertain to the Refi ning and Petrochemical industries (please refer to the listing on the page opposite).

>> Please submit to [email protected] by 10 January 2014.

Register Early and Save• More than 40 technical presentations over the two-day, multi-track program• Numerous networking opportunities between technical sessions• Access to the exhibition fl oor• The exclusive tour of Eni’s Venice biorefi nery (available on a fi rst-come, fi rst-serve basis)

>> Register early and take advantage of early bird discounted rates at HPIRPC.com.

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Contact UsFor Sponsor and Exhibit Opportunities: Lisa Zadok, Event Sales Manager, +1 (713) 525-4632 or [email protected]

Speaking Opportunities/General Inquiries: Melissa Smith, Events Director,+1 (713) 520-4475 or [email protected]

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Reliability HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR

[email protected]

Demand specifics in designing your asset management programs

In 2009, an automation journal com-missioned an online survey asking indus-try observers and practitioners to rank technology trends in 2009 and beyond.1 TABLE 1 summarizes the respondents’ preferences on technologies that would be adopted or installed in operating fa-cilities over the next five years.

While this particular survey was re-stricted to the automation and instru-mentation segments of modern industry, the results are probably applicable to the mechanical and maintenance segments. All industrial segments anticipate, and will apply, some or possibly all or similar versions of the automation/monitoring/communication equipment and systems listed in TABLE 1.

Seasoned reliability professionals should welcome these trends. How-ever, successful implementation of automation/monitoring/alarm equip-ment requires tremendous planning and action. Specific training is needed early in the process to translate any of the existing or future trends (TABLE 1)into safe and profitable uptime for the industrial/manufacturing facilities.

User beware. Engineering teams in-volved in automation/monitoring pro-grams should be fully aware of “con-sultant-conceived generalities.” Such generalities add no value unless there is action on relevant specifics. Technol-ogy implementation requires knowledge-based action even on minor items. Get-ting the “big picture” and embracing the concept of asset management (AM) is commendable, but more is needed for sustainable success.

Asset management by definition. AM is a systematic and highly detailed process of operating, maintaining, up-grading and disposing of assets cost-effectively. The AM process is aimed at

achieving the greatest return on plant assets and equipment. It includes pre-dictive maintenance (PdM) and preven-tive maintenance (PM) in facilities to provide the best possible service to all users. This is a very general guideline; however, the importance and urgency of pursuing and implementing specifics is best illustrated by an example.

Example. An equipment alignment problem indicates needed upgrades. Ear-lier this year, a machinery engineer on temporary assignment overseas strug-gled with equipment alignment issues. While shaft alignment may seem to be a very “low technology” issue, the engineer realized that alignment problems could have a demonstrable impact on the avail-ability and reliability of equipment and possibly processing units. The engineer summarized the situation and wrote:2

“Suppose you have very precisely aligned the shafts of pump and driver; nevertheless, the shims placed under the equipment feet to achieve this precise alignment caused the shaft system to slant 0.005 in. or 0.01 in. per foot of shaft length. As a consequence, the brass or bronze oil ring (slinger ring) will now ex-hibit a strong tendency to run ‘downhill.’ While bumping into other pump compo-nents thousands of times per day, the oil ring gradually degrades and sheds numer-ous tiny specks of the alloy material. These metal specks cause progressive oil deterio-ration and, ultimately, bearing distress.”

The engineer relayed more informa-tion and asked several questions:3

“We are currently installing a couple of hundred motor-driven pumps on steel modules. The modules are being built in a Pacific Rim country and will be shipped to another continent when completed. I have a concern now, after reading your book. The pumps are all installed on skids from different manufacturers. After

setting the flatness of the skids’ machined surfaces to the requirements spelled out in an applicable standard (API-686, 0.25 mm/m), we came back the next day or week and found the surfaces out-of-tol-erance due to the sun’s orientation and changes in ambient temperature. The equipment stayed in a common plane, but not within the guidelines of API-686.

Do you have any recommendations? Can you shed more light on the expected equipment or component life reduction if the pump orientation is out-of-flat-ness? Are pumps used on ships different from API-compliant pumps?”

Answer. In short, this author may not have all of the answers, but shaft mis-alignment reduces the expected trouble-free operating time, as shown in FIG. 1. Pumps on shipboard are often grease-lubricated, and the re-greasing frequen-cies on well-managed ships are better than those practiced on land. Regardless of where equipment is installed, bearing life—in oil-lubricated pumps equipped with loose oil rings dipping in the oil sump—will be influenced by oil replace-ment (per PM) frequency. Factors influ-encing the bearing service life include oil cleanliness, degree of immersion in the oil, variation of oil viscosity from an as-designed value, bore roughness of the oil rings, and the degree of horizontality of the shaft system.

TABLE 1. Ranking of technology trends for installation in operating facilities1

Wireless 22%

Asset management 15%

Predictive maintenance 14%

Networking 14%

Alarm management 12%

Security 12%

Enterprise interoperability 10%

Reliability

30

The out-of-roundness of loose oil rings is very important, and some researchers have asked for concentricity within 0.002 in./0.05 mm.5 In 2009, at a facility in South Texas, we measured malfunction-ing oil rings that were over 0.06 in./1.5 mm out-of-round. For loose oil rings,

remaining within the asked-for concen-tricity is difficult. Therefore, flinger discs clamped to the shaft are preferred over loose oil rings. However, if the loose oil rings are required, then these rings should be manufactured with stress relieving as a required fabrication step.

Garbage in, garbage out. Reliabil-ity professionals must fully advise their owners, employers, project managers and superintendents on what may appear to be a small matter. Cheap equipment will require more maintenance, and reliabil-ity professionals must bring these facts to the attention of decision-makers and purchasing teams. If it is too late for the overseas reader to insist on flinger discs, they could now lay much groundwork for upgrading via suitable retrofits.

Upgrading is part of the definition for AM. So, whenever the first one of the read-er’s many skid-mounted pumps fails and is taken to the shop, the needed flinger disc adaptations would be retrofitted.2 A desig-nated responsible implementer would be involved in this follow-up. Carrying out

such upgrades is rarely optional at reliabil-ity-focused facilities. For them, upgrading is mandatory because only the reliability-focused plants will operate safely and prof-itably. Using oil rings and expecting the highest possible equipment reliability are contradictions. Attempts to live with con-tradictions will ultimately cost more than implementing best-available technology during the inception stage of the project.

The message. Effective AM deals with specifics. Not understanding, acknowl-edging these specifics and implementing suitable upgrades will be an expensive process. Experience shows that “average” facilities will run, but they will get locked in a never-ending cycle of repeat failures or random repairs. From the start, these facil-ities will be repair-focused and notably less profitable than their reliability-focused competition. Ideally, an owner-operator should work with design contractors who know, specify and insist on obtaining the lowest failure risk components—down to parts such as flinger discs in locations where “average” users will accept loose oil rings. If the design contractor does not have these insights, the timely and consis-tent application of machinery quality as-sessment is even more important.

LITERATURE CITED 1 Journal of the International Society of Automation,

January 2009. 2 Bloch, H. P. and A. R. Budris, Pump User’s

Handbook—Life Extension, 4th Ed., Fairmont Publishing, Lilburn, Georgia, 2013.

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

4 Piotrowski, J., Shaft Alignment Handbook, 3rd Ed., Marcel Dekker, New York, New York, 2006.

5 Wilcock, D. F. and E. R. Booser, Bearing Design and Application, McGraw-Hill Publishing Co., New York, New York, 1957.

HEINZ P. BLOCH resides in Westminster, Colorado. His professional career commenced in 1962 and included long-term assignments as Exxon Chemical’s regional machinery specialist for the US. He has authored over 500 publications, among them 18 comprehensive books on

practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oil-mist lubrication and practical lubrication for industry. Mr. Bloch holds BS and MS degrees in mechanical engineering. He is an ASME Life Fellow and maintains registration as a Professional Engineer in New Jersey and Texas.

00 50

Misalignment, mils/in.100

1

10

Mont

hs of

cont

inuou

s ope

ration

100

1,000

FIG. 1. High shaft misalignment vs. expected trouble-free operating time.4

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Integration Strategies

DICK SLANSKY, CONTRIBUTING EDITOR

Dslansky.ARCweb.com

Engineering design tools are moving to the ‘cloud’

Design projects in the hydrocarbon processing industry (HPI) have become very large. They are exceedingly complex, have a long duration, and are very expensive. Often, executing these massive projects requires forming joint ventures or partner-ships of engineering, construction and owner organizations. This interdependent joining of disparate stakeholders necessitates us-ing the latest generation of 3D engineering design tools for more efficient project execution.

Beyond the project phase, asset owners now recognize the ad-ditional value that design tools can yield, not only to the project phase but also to the operating of the plant and other industrial assets. According to the ARC Advisory Group’s new market study on engineering design tools, new 3D design applications can play an integral part in determining the optimal design, creation and construction of HPI facilities. Such tools can play an increasingly important role throughout the entire plant’s life cycle.

Increased acceptance of cloud-based engineering tools. ARC is also seeing increased acceptance of cloud-based solutions for engineering design tools and other plant and enterprise appli-cations. These tools support distributed workflows and enable teams located in different offices and countries to collaborate ef-fectively and to compress project schedules. Users can manage assets more efficiently.

Although, historically, engineering and design tools were de-signed largely for design and engineering stakeholders, such as architecture, engineering and construction (AEC); or engineer-ing, procurement and construction (EPC) companies, these offerings have morphed into more-robust collaborative agents. Now owner/operators can also apply such tools to extend the service life and efficiency of their plant assets. For greenfield projects that typically involve considerable capital expenditure, owners also apply engineering design tools at earlier project stag-es to facilitate quicker operational readiness and, subsequently, improvements in the operations and maintenance phases of the asset’s life cycle. Of course, use of common platforms also simpli-fies the handover of the asset from the EPC to the owner/opera-tor, while ensuring comprehensive and up-to-date documenta-tion of the “as-built” assets.

As the number and complexity of present engineering and design tool applications has grown, the cloud has emerged as a delivery mode to customers. At present, some industrial users are reluctant to use the cloud due to security concerns. This is espe-cially true as asset owners begin to apply these tools not only to design and construct new facilities, but also for the post-project phase of the asset’s life cycle.

Most engineering design tool suppliers are adopting the cloud for certain data-rich applications, and they are considering ways to offer additional cloud utilization. For instance, Autodesk is

looking to deliver a few 3D modeling tools to customers using the cloud. Autodesk and other major suppliers, such as AVEVA, Bentley and Intergraph, view cloud computing as a logical de-livery method since 3D rendering and algorithms of embedded analytic tools require significant processing power. Suppliers see costs, collaboration and sharing designs as more reasons to move some applications to the cloud.

Selective use of engineering design tool applications is ideal for cloud computing for many reasons. Service providers create cloud computing systems to meet clients’ business needs in several ar-eas. Typical cloud computing services include virtual IT servers as extensions to a company’s local IT network, commercial or cus-tom hosted software, software as a service, and network storage. In general, cloud computer systems are designed for scalability to support large numbers of customers, as well as demand surges.

Cloud benefits. The benefits of cloud computing include less hardware and software to manage and maintain. It is also highly scalable to meet the users’ needs, which are typically charged on usage. It can also be charged with a more predictable flat rate. However, in this model, customers cannot directly control the stability of the networks, and they are highly dependent on the service provider. In addition, cloud computing often requires sending data over the Internet and storing it on the third-party service provider. The privacy and security risk is of the utmost concern among users.

While cloud-based engineering design tools are becoming more viable, ARC believes that suppliers need to develop a strat-egy for delivering tools to users that reflect their concerns and changing needs. Many users want to own the physical assets and digital information, and, as a result, private clouds rather than public clouds may be more appealing. In other situations, a com-bination of the two may be more appropriate.

Private clouds are the internal computing architectures used to process information behind the firewall. Also, private clouds can use spare internal computing capacity. The private cloud can maintain the data, while a public cloud can provide the process-ing power. The data still must be sent to the public cloud, but it can be done in an encrypted and very secure fashion.

DICK SLANSKY is a senior analyst with the ARC Advisory Group; his responsibilities include directing the research and consulting in the areas of PLM, ALM, and engineering design tools for both discrete and process industries. He has over 30 years of direct experience in manufacturing engineering, engineering design tools, control systems integration, software development, and technical project management. Mr. Slansky holds a BS degree in mechanical engineering from the University of Kansas, and a BS degree in computer science from Seattle Pacific University.

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Boxscore Construction Analysis

LEE NICHOLS, DIRECTOR, DATA DIVISION

[email protected]

Iraq’s billion-dollar road to energy stability

Much of Iraq’s future prosperity hinges on the success of its oil and gas sector. Pe-troleum already accounts for over 90% of the country’s energy needs, with a small percentage being supplied by natural gas and hydropower. Iraq has large domestic reserves, but infrastructure constraints and political disputes have interfered with the ability to satisfy domestic demand.

Iraq is the world’s eighth-largest pro-ducer of petroleum liquids and the third-largest oil exporter. Domestic proven oil reserves are estimated to be 141 billion (B) barrels. Most reserves are concentrated in giant fields in the south around Basra. Iraqi oil production reached 3 million bar-rels per day (MMbpd) in 2012. This de-velopment allowed Iraq to surpass Iran as OPEC’s second-largest crude oil producer.

The International Energy Agency (IEA) has forecast Iraqi oil production to more than double to 6 MMbpd by 2020, and to reach over 8 MMbpd by 2035. This scenario would make Iraq the largest con-tributor to global oil supply growth and enable it to overtake Russia as the world’s second-largest oil exporter. In turn, Iraq could see oil export revenues reach an an-nual average of $200 B through 2035. As the country relies heavily on the oil and gas sector for GDP growth, exploiting the domestic hydrocarbon industry will dramatically alter Iraq’s social and eco-nomic development.

Refining. After being rocked by politi-cal instability and war for decades, Iraq has embarked on an ambitious agenda to substantially develop its oil and gas pro-duction and increase domestic refining capacity. Iraq has 14 refineries account-ing for approximately 750 thousand bar-rels per day (Mbpd) of refining capacity (FIG. 1). Crude oil processing has been constrained due to bottlenecks, needed refinery upgrades and a lack of infrastruc-ture. Coupled with those challenges, the refineries produce too much heavy fuel oil and not enough refined products. This

predicament has led to shortfalls in re-fined fuels, such as gasoline.

To alleviate these shortages, Iraq has instituted ambitious goals to increase do-mestic refining capacity to 1.5 MMbpd by 2017. Development plans call for the expansion of the existing Basra and Daura refineries and the construction of four grassroots refineries. The completion of the Daura and Basra expansions added 140 Mbpd of domestic refining capacity. Domestic refining capacity reached 750 Mbpd in 2013.

Iraqi National Development Plan. In September, the Iraqi Ministry of Planning launched Iraq’s second National Develop-ment Plan (NDP) for 2013–2017. The

NDP 2013–2017 details the government’s development priorities and a pathway for domestic economic growth. Approximate-ly $357 billion (B) will be invested in devel-oping infrastructure projects throughout Iraq. The majority of the focus will be on advancing domestic industrial infrastruc-ture and boosting oil and gas production.

The NDP 2013–2017 identifies major objectives for the Iraqi oil and gas industry:

• Increase crude oil production from 3 MMbpd to 9.5 MMbpd by 2017

• Increase crude oil exports from 2.6 MMbpd to 6 MMbpd by 2017

• Increase refining capacity to 1.5 MMbpd by 2017.

With surging domestic demand for re-fined fuels, especially gasoline, Iraq is in-

BaghdadDaura

Iraq

Kirkuk

Erbil

Operating refineriesNew refineries

Qayyarah

Kasak

Bayji

Al Hadithah

Siniya

Karbala

An Najaf

As Samawah An Nasiriyah

Ad Diwaniyah Maissan

Basrah

PersianGulf

Project Cost, $B Capacity, MMbpdKarbala 5 140Kirkuk 6 150Maissan 6 150Nassiriya 4.4 300

FIG. 1. Existing refineries and facilities under development in Iraq.



vesting $20 B on the construction of four grassroots refineries: Karbala, Kirkuk, Maissan and Nassiriya. These facilities will increase domestic refining capacity by almost 750 Mbpd by 2017. If constructed, these complexes will lessen the gap be-tween supply and demand for refined fu-els, such as gasoline; reduce the volume of costly fuel imports and accomplish goals set forth in the NDP 2013–2017.

Karbala. The Karbala refinery sits 110 km southwest of Baghdad. The $5 B Karbala refinery is a priority for the country. Its strategic central location al-lows feedstocks to be imported from the north and south. The refinery will have a final capacity of 140 Mbpd and include 18 processing units, along with related utilities, infrastructure and a dedicated power plant. Karbala will produce lique-fied petroleum gas (LPG), gasoline, die-sel, kerosine, fuel oil and blown asphalt. All products will be produced according to Euro 4 specifications.

The State Company Oil Project awarded Technip the front-end engineering design

(FEED) and project management consul-tancy (PMC) contracts. FEED was com-pleted in 2010. Technip will also perform PMC services for the engineering, procure-ment and construction (EPC) phase.

The project is expected to be complet-ed by 2015.

Kirkuk. The $6 B Kirkuk refinery is be-ing constructed 300 km north of Bagh-dad. The 150-Mbpd refinery will process Kirkuk Blend crude oil into LPG, gaso-line, kerosine, diesel, fuel oil, asphalt and sulfur. The refinery will consist of 16 pro-cessing units.

North Refinery Co. awarded Shaw En-ergy & Chemicals Inc. the feasibility study and FEED contracts, and Shell Global Solutions won three technology licens-ing contracts. Shell will provide a process license and basic engineering package for the kerosine and diesel hydrotreaters and the VGO hydrocracker. Kirkuk is expected to be fully operational by the end of 2016.

Maissan. South Refineries Co., a sub-sidiary of the Iraqi Ministry of Oil, will

construct a 150-Mbpd refinery in Mais-san. The $6 B project will produce high-quality products mainly for the domestic market. These products include LPG, gasoline, kerosine, diesel, fuel oil, asphalt and sulfur.

The Shaw Group conducted the fea-sibility study and FEED work. The study was completed in 2010, and FEED was completed two years later. Major licens-ing contracts were awarded to KBR and Axens. KBR will provide licensing and ba-sic engineering services for the FCC and solvent deasphalting (SDA) units. KBR will license its FCC technology for the 47-Mbpd FCC unit, and its Residuum Oil Supercritical Extraction (ROSE) technol-ogy for the 45-Mbpd SDA unit.

Axens will provide basic engineering design and process technologies for the following units:

• Naphtha hydrotreater, 35 Mbpd• CCR reformer based on Octanizing

technology, 24 Mbpd• VGO hydrotreater, 56 Mbpd• Deasphalted oil hydrotreater based

on Hyvahl technology, 27 Mbpd

Speaker:

TERRY SCHIAZZABusiness DevelopmentSchneider Electric

Moderator:

STEPHANY ROMANOW EditorHydrocarbon Processing

LIVE WEBCAST: Thursday, December 5, 2013 | 1 p.m. CST, 2 p.m. EST

Mitigating Arc Flash Hazards and Enhancing Personal Protection In our industry the most precious resource is our people. The protection of personnel must be of utmost importance in procedure and practice. In the area of electrical systems, it begins in the design phase and continues through implementation, installation and execution. This session focuses on low voltage electrical distribution equipment and arc fl ash mitigation solutions.

The webinar will feature:• A simple graphic helps visualize fi ve distinct arc fl ash mitigation solution areas

• Explore new technologies in low voltage arc resistant equipment

• How to work through the “Standard Dilemma” for low voltage motor control centers

Webcast presented by:

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The webcast will be available to view on demand following the live presentation.

HP0114_Schneider Hlfhr.indd 1 11/15/13 9:33 AM



• Saturated LPG treatment based on Sulfrex technology, 278 thousand metric tons per year (Mtpy)

• Unsaturated LPG treatment based on Sulfrex technology, 399 Mtpy.

Completion is scheduled for 2016.

Nassiriya. The Nassiriya Integrated Proj-ect calls for the development of the 4-Bbbl Nassiriya oil field in Thi-Qar province, and the construction and operation of the 300-Mbpd Nassiriya refinery. The $4.4 B refinery will process Basra and Mishrif crude and deliver high-quality refined products, mainly to the domestic market.

The Iraqi Ministry of Oil awarded Foster Wheeler the feasibility study and FEED contracts. The scope of work in-cludes developing the configuration of the new refinery, evaluating proprietary technologies, preparing a report covering the feasibility of the project and the de-sign basis of the refinery facilities, engag-

ing the selected licensors and preparing the FEED package for the total project.

Axens and UOP were awarded major licensing contracts. UOP will provide ba-sic engineering, technology licenses, cata-lysts and specialty equipment, as well as reforming, isomerization, FCC and selec-tive hydrotreating technologies. These in-clude UOP’s CCR Platforming and Penex processes to produce high-octane gasoline and the UOP FCC and Selectfining tech-nologies to enable high-yield production of ultra-low-sulfur diesel fuel and gasoline.

Axens will supply the following pro-cess technologies for the refinery:

• H-Oil RC technology to convert vac-uum residue into low-sulfur distil-lates and produce low-sulfur residue

• Prime-D technology for the gas oil desulfurization hydrotreater to pro-duce ultra-low-sulfur diesel

• Prime-K technology for the kero-sine desulfurization hydrotreater

• Butane isomerization technology.In September, the Iraqi Ministry of

Oil, through the Petroleum Contracts and Licensing Directorate, closed the expressions of interest (EOI) bidding round. The EOI called for refinery op-erators to join upstream operators to develop the integrated project. Over 52 international oil companies are taking part in the bidding round. The awards are scheduled to be announced by the end of 2013, and the refinery is expected to be completed by the end of 2016.

LEE NICHOLS is director of Gulf Publishing Company’s Data Division. He has five years of experience in the downstream industry and is responsible for market research and trends analysis for the global downstream construction sector.

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Registration Now Open for the Second Annual Eastern Mediterranean Gas Conference Gulf Publishing Company’s second annual Eastern Mediterranean Gas Conference (EMGC) will take place in Tel Aviv Israel on 10�–�12 March 2014. Noble Energy will return to serve as host sponsor again this year. Focused on the emergence of the natural gas industry, particularly the latest market and technology trends in exploration, drilling, production and processing, EMGC provides you with a unique opportunity to gain the knowledge and insight necessary to get in on the ground fl oor and successfully build business operations in this developing area.

The conference program will explore critical issues such as: resource potential, leasing/permitting, development plans, infrastructure requirements, regulations and more. Event attendees will have the opportunity to network and make valuable business contacts via multiple networking events and a gala dinner during the conference. An optional workshop, Israel: Innovation, supported by Invest in Israel, will feature companies off ering innovative technology applicable to the oil and gas industry.

Who Should Attend?EMGC 2014 caters to companies involved in oil and gas exploration and production, pipelines, natural gas processing, technology/equipment, construction consulting, investment banking, chemicals/petrochemicals, oil and gas services, research and venture/mutual funds. Individuals and company offi cials active in the following roles will

benefi t from attending: production/operations/supply management, business development, licensing, industry analysis, distribution, procurement, corporate planning, marketing, banking and project fi nance. If you’re planning on doing business in Israel, you won’t want to miss EMGC 2014.

What Attendees will Learn:• The latest information on the stages of development for exploration and production, drilling, pipeline and gas processing projects in the region

• What oil and gas operators have planned for off shore Israel and Cyprus

• The projected global market impact of the region’s resources

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| Special Report

PLANT DESIGN, ENGINEERING AND CONSTRUCTION According to Hydrocarbon Processing’s Construction Boxscore Database, over 3,435

construction projects are in various stages of development, and construction continues

in all regions. Many factors influence the location, type and scale of an HPI project.

Much of the grassroots construction activity is located in the Middle East, Latin America

and Asia-Pacific. The costs for designing and building downstream HPI facilities have

nearly doubled since 2000. Likewise, the complexity of HPI projects is increasing and

contributing to higher total capital expenses. With rising costs, greater efforts will be

applied to optimize engineering and construction activities. This month’s special report

investigates advanced design methods and other innovative technologies that are

successfully applied to mega-projects.

Photo courtesy of Intergraph Corp.


Special Report Plant Design, Engineering and Construction C. L. XIE and Z. G. WANG, CPECC East China

Design Branch, Qingdao, China; and Y. F. QIN, SimTech Beijing Ltd., Beijing, China

Optimize relief loads with dynamic simulation

Pressure relief analysis (PRA) is a critical task at the engi-neering design stage of a grassroots oil refinery project. Dur-ing that phase, the relief loads must be determined so that the process units and plant flare systems can be designed.

The key steps of PRA include the determination of individ-ual relief loads and the evaluation/mitigation of each process unit’s overall relief load. Individual relief normally refers to a single piece of equipment or a set of interconnected equipment systems, such as a distillation column protected with a pressure relief valve (hereafter referred to as a “protected system”).

A conventional method based on recommended practices and standards, such as American Petroleum Institute Standard 521 (API 521),1 is normally used for relief load calculation by designers and licensors. However, the conventional method has been widely proved to over-estimate the relief load, lead-ing to the over-design of the flare system. The over-design of the flare system will not only result in unnecessary capital in-vestment, but also lead to design and construction difficulties at very large plants—for example, a refinery with a capacity of several tens of million tons per year (MMtpy).

Many recent reports claim that dynamic simulation is more accurate than the conventional method in predicting relief load.2, 3 The required relief load, as calculated with dy-namic simulation, is always far less compared to the relief load calculated with the conventional method. Furthermore, in the latest edition of API 521, dynamic simulation is a recom-mended method.

Although dynamic simulation would be the best way to predict relief load, building the model for a complete process unit is time-consuming and labor-intensive. Furthermore, this work requires detailed equipment and control system informa-tion that would not be available during the early design phase.

An approach combining the conventional method with dynamic simulation is proposed here. By minimizing the inherent drawbacks of both the conventional method and dynamic simulation, this approach can optimize relief load determination for the entire process unit with minimum modeling efforts.

Relief load optimization approach. The relief load deter-mination procedure for a process unit includes several steps, as shown in FIG. 1. Note: During engineering design, an itera-tive procedure likely will be required due to process modifica-tion, control or safety system reconsideration, etc.; this proce-dure appears to be sequential.

Step 1: Individual load calculation. The conventional method is the simple, fast way to conservatively determine the required relief load and, until now, it has been standard industry practice.

In the first step, the conventional method is applied (FIG. 1). Before the relief load can be calculated, applicable relief cases for a specific protected system must be determined, along with assumptions for these cases based on API 521. These cases and assumptions are used as the basis for later dynamic simulation, since even dynamic simulation should be compli-ant with the API standard.

The calculation for the distillation column is one of com-plicated applications. Three approaches have been used in the industry, including flash drum, gross overhead vapor and un-

1) Individual load calculationby conventional method

2) Ranking of loadsin descending order

3) Matchcriteria of dynamic simulation

for single source?

4) Dynamic modeling and casestudy to get new individual load

5) Summation of individualloads at general failure cases

8) Dynamic modeling and casestudy to get new overall load

9) New overall relief loads at general failure cases

10) Optimized individual and overall reliefloads for relief valve and flare header sizing

7) Match criteriaof dynamic simulation for

multi-source/depressuring?

6) Depressuring load calculation

Noncritical, and atgeneral failure cases

No, and at generalfailure cases

At generalfailure cases

Critical cases

Yes

Yes

No

Others

Others

FIG. 1. Approach for relief load optimization.


Plant Design, Engineering and Construction

balanced heat load methods. However, the flash drum method can only be used as a rough estimation at an early stage of design. The latter two methods are more realistic, although underestimation of relief load is a common occurrence in the second method.

The last method, unbalanced heat load, is the most compli-cated and rigorous method among the three, and it is widely accepted as the industry standard. A number of authors have discussed this method in detail,3, 4 and so it is not repeated here; although, a comparison between the second and third methods is shown in TABLE 1.

The gross overhead vapor method gives a smaller number of figures; therefore, it is not reliable in terms of conservative con-sideration. Here, the unbalanced heat load method is taken as the standard conventional method for the column calculation.

Step 2: Ranking of loads. When individual relief loads for all cases are worked out, these data are sorted by their values in descending order.

As mentioned, dynamic modeling requires considerable engineering time and effort, and it is unwise to apply dynamic simulation for all cases (with the exception of the critical ones with the largest loads). The purpose of this sorting is to pick out the critical cases for which further dynamic simulation is need-ed. Note: Relief to different headers must be treated separately.

An example of a 4.2-MMtpy vacuum gasoil (VGO) hy-drotreater is given in TABLE 2. Individual loads of high-pressure and low-pressure heaters are ranked and listed respectively; the largest two or three cases are candidates for dynamic simula-tion. It is important to keep in mind that the weight relief flow-rate is not necessarily the largest relief load, especially for those relief loads with small molecular weights.

Step 3: Matching criteria. In Step 2, critical cases and cor-responding protected systems are selected. However, not all protected systems can be modeled properly due to simulation limitations, and, for some cases, it is not worthwhile to model them. As a result, further screening of candidates for dynamic simulation is required. In this step, a judgement will be made vs. a set of criteria. These criteria typically include, but are not limited to, the following:

• The protected system can be modeled, and the cases can be executed

• The protected system is a column• The protected system is a reactor loop.FIG. 2 shows a comparison of relief loads estimated by both the

conventional method and dynamic simulation for a 3.7-MMtpy grassroots hydrocracking unit. As can be seen, with the same assumptions as the conventional method, dynamic simulation predicts a much smaller peak relief load for most column cases, thereby improving the relief load estimation.2, 3 Similar phenom-ena is observed for the reactor loop due to its complexity.

However, for the drum (including the separator, the flash drum, the surge drum, etc.) and the compressor, dynamic simu-lation cannot make obvious improvements. The reason is that the valve and the drum are simple pieces of equipment and do not leave enough room for more rigorous modeling against manual calculations. Also, the compressor’s overpressure case is normally a “blocked outlet,” in which almost all inlet vapor must be relieved.

TABLE 1. Comparison between two column relief load methods

Column Process unit

Calculated relief load, kg/hr

Gross overhead vapor method

Unbalanced heat load method

Steam stripper Delayed coker 60,000 168,000

Main fractionator Delayed coker 296,000 448,000

Debutanizer Hydrocracker 69,000 171,000

TABLE 2. Individual loads sorting for a VGO hydrotreater

Relief header Ranking Protected system Cases Individual load, kg/hr

High pressure 1 Reactor loop High rate depressuring 257,000

2 Hot low-pressure separator Vapor breakthrough 127,000

3 Cold high-pressure separator Blocked outlet 117,000

4 Reactor loop Low rate depressuring 64,000

5 Purge gas line Blocked outlet 21,000

Low pressure 1 Product fractionator Single power failure 207,000

2 Product stripper Vapor breakthrough 154,000

3 Rich amine fl ash drum Vapor breakthrough 70,000

4 Sour water fl ash drum Vapor breakthrough 31,000

5 Product fractionator Blocked outlet 23,000

DrumCompressorColumnReactor loop

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FIG. 2. Comparison of dynamic simulation with the conventional method.

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For these reasons, only protected systems of the column and/or reactor loop require dynamic study, and only separated modeling of these systems is required. In this way, much engi-neering time can be saved.

Step 4: Dynamic modeling. As mentioned in Step 3, the dynamic models are built for protected systems with the cri-teria being matched. Relief cases are executed based on the model, and the peak relief loads are documented.

A key point is that the same assumptions as the convention-al method are applied during case studies based on a dynamic model. A typical example is overhead pressure control of the column. When an overpressure case happens, the increasing pressure will push the control valve to open wider, and this will reduce the required relief. However, this conventional instru-mentation response should not be assumed when sizing indi-vidual process equipment pressure relief, according to API 521.

Therefore, in this case study, the pressure controller is set on manual operation, and the control valve is kept in its last position. Another example is a fire case. Not only is the same heat input model as the conventional method used in the dy-namic simulation, but the same assumptions are also applied as the system is isolated and shut down in the occurrence of a fire.

Step 5: Summation of individual loads. Previous steps fo-cused on a single protected system. From these steps, an overall relief load for a process unit is evaluated and altered for general failure cases (GFCs).

GFCs, typically including general power failures (GPFs), general water failures (GWFs) and general instrument air failures (GIAFs), usually are not allowed. The corresponding

safety systems, such as the uninterrupted power supply (UPS), dual water supply and dual air supply, must be designed to pre-vent these failures. However, as far as relief system design is concerned, the extreme cases must still be considered.

Generally speaking, the summation of all individual relief source loads in a GFC should be calculated, yielding a rough and conservative overall load for that case. An example of a 4.2-MMtpy VGO hydrotreater is shown in TABLE 3, where two protected systems relieve to a low-pressure header in a GPF case. Note: The dynamic result in Step 4 should be used in-stead of the conventional method, wherever applicable.

Step 6: Depressuring load calculation. The peak load for depressuring is calculated using the conventional method. The timing of depressuring and its relevance to general failures should be carefully evaluated. The engineering judgement should be made and evaluated if depressuring occurs simulta-neously in a GFC.

Step 7: Matching criteria. One of the advantages of dy-namic simulation is that it considers timing and interconnec-tion of processes. Normally, multiple protected systems relieve in GFCs, although not simultaneously. This scenario provides a good opportunity to mitigate the overall relief load with dy-namic simulation.

In practice, one of the typical situations for which dy-namic simulation can be implemented is a column series with streams and/or heat interconnections. However, with a simple analysis on the summation table at Step 5 (see TABLE 3), if the majority of the relief load (i.e., 80% or higher) is found to be contributed by a single column (e.g., the product fractionator in TABLE 3), then dynamic simulation is not encouraged be-cause no considerable improvement can be expected.

In the same GFC, relief via both the relief valve and the depressuring valve may happen, but they do not peak simulta-neously. This is another typical application of dynamic simu-lation, and a simple summation of those relief loads normally can be mitigated.

Step 8: Dynamic modeling. Dynamic models are built for the systems selected in Step 7, and GFCs are executed. To make the design conservative, the sum of the peak loads of

each protected system should be taken as a design reference instead of the dy-namic peak summation load. This is fur-ther illustrated in the later case study of a delayed coking unit.

Note: The assumptions made for multi-source simulation would differ from those for individual relief analysis. The conservative assumptions for the former simulation are not necessarily the same as in the latter. Therefore, in this step, careful evaluation of the assump-tion is required to ensure that the total relief load is conservative. It is possible that some models in Step 4 are used as part of the model in this analysis, but the assumptions used in other case studies likely will be different.

Step 9: New relief loads in GFCs. For the relief occurring in GFCs but

TABLE 3. Relief load summation in general failure cases

Protected system CasesRelief load at

GPF case, kg/hr Percentage

Product stripper General power failure 46,000 21%

Product fractionator General power failure 171,000 79%

Summation 217,000 100%

Cokerfractionator

Absorber

Spongeabsorber

StripperDebutanizer

Coker gascompressor

Coker drumoverhead vapor

Naphtha product

LPG product

To coker heater

Flue gas

LCGO

HCGO

Coker feed

Steam

Steam

LCGO stripper

HCGO stripper

Absorber stripperfeed drum

FIG. 3. Process flow of the delayed coking unit.

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not included in the analysis at Step 8, individual peak loads should be used to calculate the overall load from Step 8. The summation result is the optimized overall load in the GFC.

Step 10: Optimized loads. The optimized individual relief load in Step 4 can be used to size the relief valve of this protected system. For flare header sizing of this process unit, the maximum individual load, the overall load for the GFC and the depressuring load are collected and sorted, and among them the largest one is taken as the design case. One or more of these loads will be used for the plantwide relief load analysis.

Case study. Relief load optimization for a delayed coking unit with a capacity of 3 MMtpy is performed. The relief of the coker drum is handled separately, and, in this study, only the fractionation section (as shown in FIG. 3) is included.

Recall the approach procedure in FIG. 1. Individual relief loads are calculated in Step 1 using the conventional method, and the three largest loads are listed in TABLE 4. As can be seen, the largest loads come from the coker fractionator in this case, which matches the criteria in Step 3. Then, a dynamic model is built for the fractionators, and its relief cases are executed. The new relief loads are reported in TABLE 4 for comparison.

As expected, the relief loads are considerably mitigated by dynamic simulation for the first two cases, which are only around 60% of the relief loads obtained with the conventional method. No relief occurs for the single power failure case, but the column pressure increases; however, its peak value of 0.23 megapascal gauge (MPaG) is lower than the relief valve set pressure of 0.35 MPaG. At this point, Step 4 is finished.

Step 4 is followed by a summation of individual loads at the GFCs. In this study, the GPF and GWF cases are exam-ined. The relieving equipment in the GPF includes the coker fractionator, the stripper feed drum and the debutanizer, while only the coker fractionator will relieve in the GWF case. Therefore, as per the criteria in Step 7, the GPF case would be further analyzed with dynamic simulation. A summary of the results is listed in TABLE 5.

As shown in the table, a single coker fractionator contrib-utes 80% of the total relief load in the GPF case. For this rea-son, it is not a practical candidate for dynamic studies for mul-tiple protected systems; however, it is still implemented in this study to illustrate Step 8.

As shown in FIG. 4, four protected systems will relieve in the GPF case, and the dynamic summation (black curve) peaks at 275,000 kg/hr. However, to make a conservative estimate, the summation of peak loads of 355,000 kg/hr for four individual sources is taken as the design reference. A large improvement is not seen compared with 376,000 kg/hr at Step 5, due to the reasons mentioned above. This summarizes Step 8.

Note: An additional relieving protected system—a com-pressor interstage drum—was found in the dynamic simula-tion. It splits the relief flow from other sources and does not increase the overall load; however, this phenomenon can only be observed and evaluated through dynamic simulation.

FractionatorInter-stage drumStripper feed drum

DebutanizerDynamic sum

-0:05:000.00E03.00E46.00E49.00E41.20E51.50E51.80E52.10E52.40E52.70E53.00E5

0:05:00 0:10:00 0:15:00 0:30:00 0:40:00 0:45:00 0:55:000:25:00Simulation time

Relie

f load

, kg/

hr

FIG. 4. Dynamic relief curve for multiple protected systems in the GPF case.

TABLE 4. Largest relief loads with the conventional method and dynamic simulation

RankingProtected system Cases

Relief load, kg/hr

Conventional method

Dynamic simulation

1 Coker fractionator

General power failure

448,000 259,000


Blocked vapor outlet

258,000 172,000


Single power failure

85,000 0

TABLE 5. Overall relief loads in general failure cases

General failure case Relief source

Overall relief load, kg/hr

Conventional method Step 5 result Step 8 result

General power failure Coker fractionator 448,0001 259,0002 140,0002

Compressor interstage drum 01 01 160,0002

Stripper feed drum 45,0001 45,0001 50,0002

Debutanizer 72,0001 72,0001 5,0002

Summation 565,000 376,000 355,000

General water failure Coker fractionator 258,0001 172,0002 172,0002

Summation 258,0001 172,0002 172,0002

1Result of conventional method�2Result of dynamic simulation



Finally, the optimized individual relief loads are col-lected and summarized. The results of the conventional method are replaced by the dynamic simulation results, where applicable. These data provide sizing references for individual relief valves. The required orifice size of a re-lief valve can always be reduced through relief load miti-gation. With the coker fractionator, for example, the GPF is the controlling case, and the required relief valve size is reduced from 1,010 cm2 to 623 cm2 (based on the API re-lief valve sizing method). It can be determined that 355,000 kg/hr is the largest relief load for this delayed coking unit at the GPF case, which is only 63% of the load with-out optimization (565,000 kg/hr, as shown in TABLE 5), and this value is used to set the flare header size of the unit.

It is also apparent that modeling the entire flowsheet at Step 8 is unnecessary, since only a slight improvement can be obtained compared to the individual load summations. Therefore, Step 8 is bypassed in real engineering design, lead-ing to considerable savings of modeling time and effort.

Takeaway. The relief load estimation derived by combining the conventional method with dynamic simulation was op-timized as expected, with minimum dynamic modeling ef-forts. This estimation was successfully applied to a relief load case study of a large-scale delayed coking unit. Although a re-finery process is studied here, the approach is also applicable to other oil, gas and petrochemical processes.

ACKNOWLEDGMENTSThe authors thank Xiaobo Liu and Xiuwen Zhao from China Petroleum

Engineering & Construction Corp.’s East China Design Branch; Ximei Lv and Zengfu Zhang from SimTech Beijing Ltd.; and Professor Enxi Lu from South China University of Technology for their contributions to this article.

LITERATURE CITED 1 American Petroleum Institute, “Guide for pressure relieving and depressuring

systems,” API Standard 521, 5th Ed., January 2007. 2 Depew, C. and J. Dessing, “Dynamic simulation improves column relief load

estimates,” Hydrocarbon Processing , December 1999. 3 Nazami, P. L., “Distillation column relief loads—Part 1, 2,” Hydrocarbon

Processing , April 2008/May 2008. 4 Rahimi Mofrad, S., “Tower pressure relief calculation,” Hydrocarbon Processing ,

September 2008.

CHONG LIANG XIE is the chief engineer for China Petroleum Engineering & Construction Corp.’s (CPECC’s) East China Design Branch. He has 27 years of experience in refinery design, with specialized expertise in the delayed coking process and in general configuration design. Mr. Xie holds a BS degree from Northeast Petroleum University in Heilongjiang, China.

ZHI GANG WANG is the director for the general design division of CPECC’s East China Design Branch. He has 20 years of experience in refinery design and is an expert in general configuration design and in the fluid catalytic cracking process. Mr. Wang holds a BS degree from China University of Petroleum in Beijing, China.

YUN FENG QIN is the technical manager for SimTech Beijing Ltd. He has more than 10 years of experience in process simulation. Before joining SimTech, Mr. Qin worked with Invensys/SimSci-Esscor China for eight years as a technical support specialist and consultant. He holds an MS degree in chemical engineering from South China University of Technology in Guangdong, China, and a BS degree in chemical engineering from the Beijing Institute of Light Industry in Beijing, China. Mr. Qin can be reached at [email protected].

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Mitigate heat exchanger corrosion with better construction materials

Unseen corrosion plays a major role in the operational efficiency of process plants. In refining and petrochemical processes, greater demands are placed on construction mate-rials for key processing equipment. The ability to withstand corrosion at elevated temperatures requires special consider-ation, especially for material selection throughout the plant. New guidelines improve choosing corrosion-resistant ma-terials for heat exchangers. Better materials can provide op-timal equipment service life, reduce maintenance, mitigate contamination by corrosion products and minimize heat loss due to fouling.

Harsh operating environments. In refineries and pro-cess plants, greater operating demands are required on the construction materials used in capital equipment. The abil-ity to withstand corrosion at elevated temperatures involves special consideration for materials and metallurgy to be used throughout the plant. It is not just to the material’s suitability in the process, but, more importantly, it is the material’s abil-ity to resist corrosion and perform efficiently and effectively. A well-considered material selection process will provide for optimal equipment service life, reduce maintenance spend-ing and conserve energy.

Refineries now handle high-sulfur-content crude oils. The utilization rates are higher and are geared to find more yield per barrel of oil processed. The need for corrosion-resistant materials is vital to eliminate equipment failure and unit down-time. Throughout the refining process, non-hydrocarbon compounds and additives can build up within process streams and can be the root cause for extensive corrosion problems.

Buildup of such deposits, in or on the tubes of heat ex-changers, can be sourced from the process side due to tena-cious hydrocarbons, process slurries, or even ammonium chloride deposits in the crude unit overhead condensers. Equally important, contaminants can be sourced from cooling water, which may contain sand or sediment. Such sediments can build up due to low flowrates in horizontally mounted heat exchangers. All can have a detrimental effect on a refin-ery’s efficiency and heat transfer needs.

Better construction materials for exchangers. Applying corrosion-resistant materials not only eliminates unscheduled plant shutdowns, but it also reduces the risks from costly lost production and expensive emergency maintenance and repair. Attention should also be given to the formation of crevice cor-

rosion beneath such deposits at temperatures below the criti-cal pitting temperature (CPT) of the material.

Carbon steel (CS) is extremely vulnerable to corrosion, and austenitic stainless steel (SS), widely used in heat-exchanger tubing, can become susceptible to stress corrosion cracking (SCC), particularly in chloride-bearing environments.

Research shows that these materials are highly susceptible to corrosion at the elevated operating temperatures found in refin-eries. Gradually, the industry is recognizing the advantages of duplex SS. It can offer the optimum combination of corrosion resistance, mechanical properties and excellent fabrication ca-pabilities. The cumulative benefit of such an approach is genu-ine cost advantages. Link this with its compatibility with other alloys during the fabrication process and duplex SS is an ideal material, not only for new equipment but also for the retubing of existing heat exchangers, replacing CS and even austenitic SS.

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0(32)

Temperature, °C (°F)

50(120)

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50

100

CVN,

impa

ct str

engt

h, J

150

200

250

300

3506001 b

FIG. 1. Impact strength Charpy-V for duplex SS and CS. Specimen size 10 mm x 10 mm (0.40 in. x 0.40 in.)



ties that provide design advantages, as well as ease of fabrica-tion and toughness.1 It can offer technical benefits and design advantages of the material, together with the cost advantages over conventional SS and CS.

Chemical composition. Due to low nickel (Ni) content, lean duplex SS has a two-phase microstructure with approxi-mately 50% ferrite.1 A high 23% chromium (Cr), compensat-ing for the absence of molybdenum (Mo), can provide high resistance to corrosion, as listed in TABLE 1. The nitrogen con-tent further increases the material’s strength, improving weld-ability and pitting corrosion resistance.

Mechanical properties. Direct comparisons between the mechanical properties of the material, austenitic SS and CS are summarized in TABLE 2. These clearly demonstrate the high yield strength of the material, along with high tensile strength and hardness properties.

The impact strength of the material at various temperatures, in both welded and unwelded conditions, is illustrated in FIG. 1. Its toughness throughout the temperature range makes it far more suitable than CS, which normally has ductile to brittle transitions in the range 0°C to –80°C (32°F to –112°F).

Low thermal expansion. It is the low thermal expansion of duplex SS that offers significant design advantages. As shown in FIG. 2, it is much lower than austenitic SS and very close to that of CS. When used in tubular heat exchangers, whether a new build or to replace existing CS tubes, the low thermal expansion of the duplex SS is a favorable option to use with other alloys.

Corrosion resistance. Even in acid solutions, the lean du-plex SS has better resistance to corrosion than ASTM 304L, owing to its very high Cr content. In fact, it is even better than ASTM 316L in most acid environments. This is demonstrat-ed by the isocorrosion curves, as shown in FIG. 3. This figure illustrates the corrosion rate in formic acid of just 0.1 mm/yr (4 mpy).

Again, the high Cr content of the material also offers good resistance to general corrosion, pitting and crevice corrosion, exceeding that of austenitic grades, as shown in FIG. 3. Duplex SS offers excellent resistance to SCC in aqueous solutions. The lean duplex SS is suitable for use in temperatures around 140°C (284°F) without risk of SCC. By comparison, ASTM 304L and ASTM 316L should only be used in operating tem-peratures below 60°C (140°F), as shown in FIG. 4.

Cost advantages. For many projects, cost is the primary priority. However, the ability of a material to fully meet the application requirements is likewise a major consideration for plant efficiency.

Lean duplex SS1

CS

ASTM 316L

0 5 10Thermal expansion, x10-6

156832 b

FIG. 2. Thermal expansions, mean values.

6004 b

Boiling point curve

Lean duplex SS1

ASTM 316L

ASTM 304L

0 20 40 60 80Acetic acid, HCOOH, wt, %

100

20(68)

40(105)

60(140)

80(175)

100(210)

120(250)

Temp

eratu

re, °C

(°F)

FIG. 3. Isocorrosion diagram showing materials in formic acid.

0.01 0.02 0.05

No pitting

Pitting

ASTM 304L

ASTM 316L

Lean duplex SS1

0.10 0.20 2.01.00.50Cl–, wt%

0(32)

20(68)

40(105)

60(140)

80(175)

100(210)

CPT,

°C (°F

), 30

0 mV S

CE

6006 b

FIG. 4. Critical pitting temperature (CPT) in neutral chloride solutions (potentiostatic determination at 300 mV, SCE).

TABLE 1. Chemical composition (wt%) and microstructure of SS

Cmax Cr Ni Mo N Microstructure

Lean duplex SS1 0.03 23 4 – 0.1 Duplex

ASTM 304L 0.03 18–20 8–12 – – Austenitic

ASTM 316L 0.03 16–18 10–14 2–3 – Austenitic



Strength of the material is a significant factor. For exam-ple, selecting a duplex grade, such as a lean duplex SS, despite a higher price per kg, can prove to be the most economical solu-tion.1 This is because the wall thickness of the tubes subjected to internal pressure or tensile loads is directly related to the ma-terial strength. As thinner wall tubes can be specified, the cost of the duplex material can be around 35% lower. This should be compared to the cost of tubes of other material grades, which would require a thicker wall to achieve the same strength, as summarized in TABLE 3. There are also associated savings to be achieved on transport, installation, welding, etc., when speci-fying the lighter thinner walled duplex grade tubes. For many applications, the material offers economical solutions because of the high corrosion resistance, especially to SCC. The use of computerized life cycle cost calculations, using all relevant data, including maintenance, investment costs, service life, inflation, etc., can clearly demonstrate the savings that are possible.

Better design can save money. Within refineries, along with hydrocarbons, there are chlorides, ammonia compounds, hydrogen sulfides, carbon dioxide, various acids and water. Such mixtures can result in the premature failure of many construction materials, such as copper-based alloys to steels, as well as different types of austenitic SS, due to corrosion. In such environments, duplex SS can provide excellent resistance to corrosion attack as recorded in extensive laboratory testing as well as in successful documented installations in process plants and refineries worldwide. The ease of fabrication, cost savings and the durability of duplex SS can offer significant ad-vantages not only for new equipment, but also when retubing existing heat exchangers.

NOTES 1 Lean duplex SS, such as Sandvik SAF 2304, offers high strength with a yield

strength twice that of ASTM 316L. Sandvik and Sandvik SAF 2304 are trade-marks owned by Sandvik Intellectual Property AB.

EDUARDO PEREA is the global business developer for tube chemicals for Sandvik Materials Technology, and is based in Singapore. He is a metallurgist engineer and graduated from Faculdade de Engenharia Industrial in Brazil. In 2004, Mr. Perea joined the company as a trainee and was later promoted to technical marketing and sales engineer. In 2008, he relocated to Sweden and joined the global technical marketing, high-temperature products group. In 2011, he was promoted to regional sales manager for tube before assuming his present role in 2012.

No SCC

SCC

ASTM 304/304L

Lean duplex SS1

ASTM 316/316L

0 10 100 1,000 10,000Cl–, ppm

50(120)

100(210)

150(300)

200(390)

250(480)

Temp

eratu

re, °C

(°F)

6007 b

FIG. 5. SCC resistance in oxygen bearing (~8 ppm) neutral chloride (Cl) solutions. Test time of 1,000 hr. Load ≥ yield strength at testing temperature.

FIG. 6. Cut-away of horizontal heat exchanger, illustrating flow direction.

TABLE 2. Mechanical properties of lean duplex SS and standard SS at 20°C (68°F)

Grade Yield strength 0.2% off set 1% off set Tensile strengthElongation A,

% min.Hardness Vickers

typical values

MPa ksi MPa ksi MPa ksi

min. min. min. min.

Lean duplex SS1 400 58 450 65 600–820 87–119 25 230

AISI 304L 190 27 220 32 500–700 73–100 35 155

AISI 316L 210 30 240 34 500–700 73–100 35 150

CS* 180–280 26–41 360–600 52–100 20–35 100–160

*Common value

TABLE 3. Cost comparison of lean duplex SS and ASTM 304L/316L for tubes subjected to internal pressure or tensile loads1

Material

Strength RP 0.2,

MPa

Estimated relative

costDensity gm/cm3

Calculated* relative cost/m

Lean duplex SS1 400 1.2 7.75 1

ASTM 304L 190 1 7.9 1.8

ASTM 306L 210 1.4 8 2.3

*Cost of tubes able to withstand the same pressure, load, etc.


Special Report Plant Design, Engineering and Construction D. COPPIN, AVEVA, Cambridge, UK

Video game technology transforms operator training

Virtual reality technology that was developed in the enter-tainment world can now be applied to the process plant indus-try. Thanks to advances in gaming technology, with detailed 3D modeling at the core, it has become practical, affordable and quick to create a fully navigable, hyper-real equivalent of a facility, whether already operational or yet to be constructed.

Gaming, with its commercial potential, has come a long way since the 2D platform games of the 1980s. The sector has entered a period of democratization and diversification, with exciting ramifications for industry.

The change is partly due to the fact that the sophisticated graphics and complex physics engines that lend the games re-alism can now run on entry-level hardware and multiple plat-forms. Meanwhile, increased Internet speeds and bandwidth have also seen massive multiplayer online games (MMOGs) explode in numbers, with every player’s actions updating in real time worldwide and with audio links to further enhance the live-action gameplay. The market conditions are right for a new genre to emerge: industrial gaming.

This might sound interesting, but what are the business jus-tifications for the creation of an industrial virtual world? Why would an owner/operator want to invest in industrial gaming? At the lowest level, the objectives of gaming for entertainment and those of industrial gaming are relatively similar: practice makes perfect.

Dr. Michael Platt, a human performance engineer at Lock-heed Martin, has said that people should not be trained until they get it right; they need to be trained until they do not get it wrong. Similarly, gamers are only allowed to progress when they no lon-ger make errors, trying again and again until they get it right. If they do not get it right, their characters crash or disintegrate.

Central to the application of industrial gaming for oil and gas organizations is a desire to create and maintain skills and understanding in all site personnel through familiarization and repeated practice. Human error is widely recognized as the No. 1 cause of safety incidents, and so, while the enhanced skills gained through repeated practice could aid productivity, they could also serve to eradicate human error from operations.

A new approach. The ability to not just to understand in-formation, but to also retain it is critical to ensuring safety in high-risk environments, and a heuristic or trial-and-error ap-proach to learning significantly improves retention. It utilizes self-educating techniques where individuals evaluate the feed-back resulting from actions to improve performance.

However, in the hydrocarbon processing industry (HPI), allowing trainees to learn by doing in a live environment can be

costly, disruptive to production and potentially hazardous to the individual or the facility, and the consequences of a mistake can be catastrophic.

“Never has the need for improved training in the oil and gas industry been more important,” said Derek Middlemas, COO and head of enterprise solutions for AVEVA. “A lack of experi-enced engineers combined with more complex and automated assets introduces new risks into safe and effective operations. This is where virtual reality comes in. Using industrial 3D gam-ing technology to supplement physical on-the-job training can greatly increase operator effectiveness at zero-risk and opti-mize training costs.”

The use of advanced visual simulation technology, such as that which underpins industrial gaming, enhances data assimi-lation. In the report “Why Simulation Games Work,” the au-thors note that, in many cases, industrial gaming can help make the information more relevant and easier to understand, which is critical for high-risk activity training where full comprehen-sion and retention of safety information are paramount.

Similarly, in a study conducted by New South Wales Mines Rescue Service, it was identified that traditional classroom training (including demonstrations and video presentations) led to, at best, a 50% retention performance. Simulator-based training, where trainees performed actions themselves, lifted that retention level to 75%.

But this perspective is not new; the HPI is playing catch-up. The development of flight simulators has contributed enor-mously to improving air safety by enabling crew members to learn and practice their skills in perfect safety and at a fraction of the cost of flying a real aircraft.

Within a virtual reality environment, trainees can be pro-vided with full on-screen details to follow when introduced

FIG. 1. Virtual reality: People need operational experience to be able to work to the very high standards of safety required.

54

Plant Design

to the training program, and the advice can then be steadily reduced to hints and finally to no-help test modes to ensure complete comprehension of a process. The ability to make mistakes and repeat a course program with no safety or cost consequences ensures that the different learning and reten-tion speeds of each employee can be accommodated easily through self-paced learning.

Increased safety and compliance. Many of the recent in-vestigations into incidents in the HPI have highlighted a level of commonality as to probable causes. These include:

• Limited awareness of operating procedures• Improper identification of safety hazards

and hazardous processes• Inadequate inspection• Inadequately trained workers.The first step toward a safer workforce is ensuring that, be-

fore they set foot in the facility, all site personnel are fully fa-miliar with the environment in which they are working. Many new recruits will not have an understanding of full-scale op-erational plants and may not even be able to identify some of the main components of a facility. To compound the problem, the facilities themselves are often remote, difficult to reach, in-frequently accessed, and sometimes even unmanned.

FIG. 2. In addition to mimicking the exact layout of a facility, industrial gaming environments can reflect different environment conditions (daytime, nighttime, fog/smoke, etc.) for maximum realism.

FIG. 3. By enabling repeated practice of complex or high-risk activities, industrial gaming could serve to eradicate human error, the No. 1 cause of operational safety incidents.

Suncor is selling a significant amount of new inventory including bulk materials, process equipment, vessels and construction equipment. Assets are stored indoors and are in excellent condition with immediate availability and expedited delivery times. Tours are available for interested parties.

View the assets now at www.suncor.com/surplus

Oil, energy and manufacturing industry assets for sale

Items may not be exactly as shown and are subject to availability, and the execution of definitive sales terms between buyer and seller.



55

In such circumstances, there may be no supervisor or safety professional present to review the site for hazards and to in-struct remote workers or new site visitors in avoidance. Us-ing an immersive environment built from the 3D model of the asset, workers can prepare fully for a site visit, by reviewing the layout, hazardous locations, emergency egress routes and assembly areas, and the locations of the nearest safety stations like eye-washes, showers and emergency call buttons.

Adding procedural training to the immersive environment also enables operators to educate new employees, remote workers and all those on site, in site-specific emergency proce-dures, ensuring they respond appropriately in the event of an incident and do not unintentionally compound risk by failing to follow the defined process.

Regulations around the globe already demand it: the forth-coming ISO 55000 regulations will enumerate that safety training is a central recognized and generally accepted good engineering practice (RAGAGEP) pillar for operational readi-ness. Meanwhile, the US Occupational Safety and Health Ad-ministration (OSHA), via its regulation OSHA 1910.119(g)(1) indicates that topics covered by training should, at a mini-mum, include the following:

• Lock-out/tag-out• Hot work• Line and equipment opening• Confined space entry• Emergency response• Operating procedures.Findings published by the Politecnico di Milano Depart-

ment of Materials and Chemical Engineering reveal that pro-cess sequences including startups/shutdowns, hot work and lock-out/tag-out, as well as abnormal conditions (like confined space entry), alarms, failures and accidents are not easily repli-cable in a real plant. The ability to create an immersive virtual environment with comprehensive step-by-step instructions and opportunities to repeatedly test comprehension and retention provides a far better option for ensuring safety.

It is true that improving the speed-to-proficiency in key areas like safety, reliability and risk management prior to en-tering the field has productivity benefits for operators, but im-mersive training is not just for new employees; it is important to ensure that bad working practices do not slip into regular

activities. For example, one of the problems that caused the BP Texas City refinery explosion was that operators relied on knowledge of past startup experiences (passed down by the more skilled veteran operators) and developed informal work practices. The ability to train or evaluate operators at any time, in any location and as often as necessary, allows immersive simulation training to be a vital tool in refresher training for existing employees, too.

Application. The increasing presence of intelligent 3D mod-els in HPI engineering means that the process for creating specific virtual reality environments using industrial gaming development engines can be straightforward and cost-effec-tive. The usability and affordability of the technology means that specific application of the technology to the HPI is lim-ited only by the imagination of operations and maintenance (O&M) and training departments. Some of the use cases have already been outlined:

• Facility familiarization: The orientation of personnel new to a facility, including preparation for emergency proce-dures and evacuation response. Similarly, preparation for a change to the working environment is an intrinsic element of effective management of change (MoC)

• High-risk or complex activity training and rehearsal: The risks of process failure carry significant consequences for individuals and for the facility’s operation, including lock-out/tag-out, safety system isolation, pressure testing or

FIG. 4. The usability and affordability of the technology means that specific application of visualization technology to the HPI is limited only by the imagination of O&M and training departments.




work with dangerous materials, startup/shutdown checks, hot work, line and equipment opening, confined space en-try, fire simulation training and other emergency responses

• Refresher training for collaborative activities: Improv-ing or maintaining the safety and productivity of cross-functional teams required to collaborate, ensuring that bad practices do not appear and are not replicated

• HSE compliance requirements: The advanced planning and rehearsal of toolbox meetings, HAZOP assessments prior to completion of construction, rehearsal of inspec-tion line walk-downs and testing understanding of equip-ment-level relationships.

In addition, there are a multitude of further applications to improve teamwork and increase productivity, including:

• Construction, operations and maintenance planning: Test the feasibility of planned works from construction through operations and maintenance and simulate the pro-cesses involved to test new working methods and to con-duct clash detection or hazard spotting

• Remote problem solving: Allows remote teams to review and address construction or O&M challenges and repeat-edly model scenarios in a virtual environment to predeter-mine the optimum solution prior to arrival on site

• Sign-off for certification and operational readiness: Ac-cess need not be limited to internal teams, as commission-ing and completions companies can now allow the certifi-cation authorities to undertake virtual plant walk-throughs.

This will enable the certifying body to view punch-lists and compare against the design intent well before going to the site, and will speed up the certification process.

• Complex storytelling: Create a sequence of individually driven, interactive, animated environments to demonstrate progress of a particular maintenance activity, or activities associated with field operations. Storytelling provides improved stakeholder comprehension, communication, speed and proficiency for completing planned and un-planned daily activities.

The application of advanced technology to enhance the safety of all field operations personnel is expected to increase significantly over the coming years. Clearly, there are many op-portunities to make full use of existing asset information, in-cluding documentation, maintenance histories and 3D models in the creation of sophisticated virtual reality environments and scenarios. But this is not merely a long-term vision, the use case exists today.

The forthcoming ISO 55000 standard outlines six different asset management subject groups, and details the requisite pro-cesses and capabilities required in each subject group. The ap-plication of immersive environment training supports processes and capabilities across all of the categories.

Virtualization can make a real difference to the safety and reli-ability of a field operations team.

DAVE COPPIN is executive vice president for AVEVA.

presents . . .

Overcoming the Challengesof Tight Oil/Shale Oil Refi ning This webinar will share characteristics, physical properties, and variable nature common to tight oils/shale oils. We will also discuss observed impacts introducing these crudes into refi nery crude blends and showing examples of how these challenges have been overcome to successfully and profi tably process these blends.

REGISTER AT HydrocarbonProcessing.com

STEPHANY ROMANOWEditorHydrocarbon Processing

JEFFREY A. ZURLOSenior Project Manager GE Water & Process Technologies

BRIAN BENOITHydrocarbon Processing Industry LeaderGE Water & Process Technologies

Live Webcast: December 11, 201311 a.m. EST 10 a.m. CST

HP1213_GE Hlfh.indd 1 11/18/13 11:17 AM


Special Report Plant Design, Engineering and Construction R. DOLE, S. BHATT and S. SRIDHAR, L&T-Chiyoda Ltd., Vadodara, India

Design a staggered depressurization sequence for flare systems

Emergency depressurization is one of the most impor-tant design provisions for safeguarding facilities in case of an emergency, such as a fire or an exothermic runaway reaction, that can cause catastrophic failure of equipment and loss of containment. Depressurization reduces failure potential by decreasing the internal stress, thereby extending vessel life at a given temperature. By reducing vessel inventory, the depres-surization of a pressurized vessel minimizes the impact of ves-sel leakage and rupture.

A gas processing plant is typically divided into various iso-latable sections (e.g., gas inlet manifolds, inlet separators, a gas sweetening unit, a gas dehydration unit, etc.), each isolated by emergency shutdown valves (ESVs). Each section can be de-signed as a separate fire zone that is depressurized by a dedi-cated emergency depressurization valve (EDV).

In general, during emergency shutdown conditions, the depressurization of only relevant isolatable sections is carried out to make those sections safe. However, during certain emer-gency circumstances, the whole facility must be depressurized, thereby creating a large load discharge to the flare.

In certain situations, flare systems (including the flare head-er, the flare knockout drum and the flare stack) may not be ade-quate to handle the entire plant’s depressurization load at once. This situation is typically encountered when facilities are re-vamped over time without a major revamp of the flare systems.

To overcome limitations of flare system capacity during such a scenario, depressurization can be practiced in a sequen-tial manner. Presented here are the criteria and calculation methods for designing sequential depressurization, along with guidelines for the implementation of recommended designs.

Design criteria. When designing the depressurizing se-quence, several key guidelines must be considered:

• Priority of depressurization• Number of steps• Time delay between each step.Priority of depressurization. Based on the cause of de-

pressurization, priority for depressurization is assigned to each isolatable section. The following guidelines can be utilized to specify priority:

• If the cause of depressurization is fire or gas leakage, then the section activating the fire or gas detector must be de-pressurized immediately. Nearby areas are assigned later priority for depressurization.

• High-pressure sections should be given depressurization priority over low-pressure sections.

• Depressurization priority can also be assigned based on the nature of the isolatable section. Rotating equipment (e.g., compressors) should be given higher priority. Vessels can be assigned moderate priority. Isolatable sections contain-ing only piping can be given the lowest priority. Care should be taken in determining timing for the centrifugal machine, as keeping it under a pressurized shutdown for a prolonged time would require an external seal gas supply and, based on its availability, the delay timing would need to be adjusted.

Number of depressurization steps. The depressurization requirement is divided into steps to enable nearly uniform peak load at each step. A higher number of steps is better for the utili-zation of the flare system, but it also increases the complexity of sequence implementation and its maintenance.

Time delay between each step. The time delay between each depressurization step is evaluated to create enough ullage for the next depressurization peak load. To calculate the time delay between each step, the flow/time relationship for each de-pressurization valve must be known.

The whole facility can be simulated using modern software programs. Depressurization can be calculated using dynamic features to develop the depressurization curves of flow, in terms of pressure vs. time.

The calculation can be simplified using Eq.1, which can provide reliable depressurization curves. An entire facility de-pressurization model can be built in a spreadsheet, greatly sim-plifying the calculation.

The flowrate through the orifice significantly reduces with time:

F = F0 e–θt (1)

where:t = Time from start of depressurization, minuteF = Flow through orifice (depressurization load

at time t), kg/hF0 = Initial flowrate through orifice (peak

depressurization load), kg/hθ = Exponent coefficient factor depending on

orifice size, minute–1.The exponent coefficient factor θ can be derived from:

P = P0 e–θt (2)



where:P0 = Initial pressure (internal pressure at time t = 0), baraP = Final pressure (internal pressure at time t = t), bara.Depressurization criteria for each valve are determined by

rupture time, rupture pressure, and vapor release due to rup-ture. In a typical depressurization system design, the goal is to reduce the pressure to less than 50% of the design pressure within 15 minutes (min.), or to reduce the internal pressure to 7 barg from the design pressure in 15 min.

For example, depressurization of a system from design pres-sure of 45 barg to 7 barg, in 15 min., would result in θ = 0.12 min–1. A flow profile is described in FIG. 1, based on the applica-tion of Eq. 1 to F0 = 50,000 kg/h.

Case study. For the sake of simplicity, this case study con-siders the depressurization of a single train in a gas processing plant to its dedicated flare system. Each process unit is consid-ered as a single, isolatable system. The depressurization system sizing criteria are summarized in TABLE 1.

The initial peak depressurization load can be evaluated from the depressurization utility available in commercial simu-lators. The initial peak load can be evaluated at the maximum upstream operating pressure instead of the design pressure, if the cause of emergency shutdown is not a fire in that section.

In this case study, the flare system capacity is pegged at 145,000 kg/h. Here, the total depressurization load of all the

sections is 290,000 kg/h. During the depressurization of the entire facility, staggered depressurization is required.

There are several scenarios that can lead to the depressuriza-tion of the entire plant:

• Fire or gas leakage detection in common process areas, such as the inlet manifold, the export manifold, etc.

• Instrument air failure• Low fuel gas supply pressure• A power failure to the safeguarding system.Since the depressurization priority may vary for different

causes, individual depressurization sequences may need to be activated for each cause. The gas inlet manifold area is one place where an entire-facility depressurization can be activated. To design staggered depressurization for the gas inlet manifold, several steps were applied:

Assign depressurization priority to each section. If fire is the cause of an emergency shutdown, priority will be assigned to each isolatable section based on geographical area. The iso-latable section of the gas inlet manifold is affected by fire; there-fore, it should be depressurized immediately (i.e., Priority 1). The next priority is assigned to adjacent areas.

The gas separator and depletion compressor are located ad-jacent to the gas inlet manifold, so these units will be assigned the next level of priority (i.e., Priority 2). Priority of depressur-ization is assigned to other isolatable sections in a similar man-ner. Based on these guidelines, priority for depressurization is assigned, as shown in TABLE 2.

Determine number of depressurization steps. Once the priority of depressurization is assigned based on peak depres-surization load, the valves that can be accommodated at the depressurization step should be determined. The total flaring load during depressurization and the flare system capacity are the major factors used to determine the number of steps.

At the first staggered depressurization step, the flaring load is zero. Depressurization valves with a total peak load that is slightly less than the flare capacity should be initiated. In the subsequent steps, depressurization valves with a total peak load that is near to half of the flare capacity should be initiated. The flaring load can be higher or lower than half of the flare capacity; however, to have an optimum number of depressurization steps, it is recom-

0

20

40

60

80

010,000

20,000

30,000

40,000

50,000

60,000

0 10 20 30 40 50 60

Secti

on pr

essu

re, ba

rg

Flowr

ate, k

g/h

Depressurization time, min.

Flowrate, kg/hSection pressure, barg

FIG. 1. The flow profile of an individual depressurization valve used for calculating the time delay between each step.

TABLE 1. Depressurization data of isolatable section

Isolatable section Initial pressure, barg Final pressure, barg Depressurization time, min.Initial depressurization

load, kg/h

Gas inlet manifold 45 7 15 35,000

Gas separator 45 7 15 30,000

Depletion compressor 70 7 15 25,000

Acid gas removal 70 7 15 30,000

Dehydration 70 7 15 30,000

Mercury removal 70 7 15 20,000

Nitrogen rejection 70 7 15 30,000

NGL recovery 70 7 15 20,000

Fractionation train 60 7 15 25,000

Sweetening unit 60 7 15 20,000

Booster compressor 80 7 15 25,000



mended to have a total load of nearly half of the flare capacity. Ac-cording to this methodology, isolatable sections can be accom-modated in the depressurization steps, as outlined in TABLE 3.

Depressurization steps can have sections with more than one level of priority. For example, in Step 1 of depressurization, sec-tions of Priority 1, Priority 2 and Priority 3 are included based on flare capacity. Similarly, isolatable sections of the same priority can be divided into more than one depressurization step. For ex-ample, the Priority 3 sections are divided into Step 1 and Step 2.

Determine the time delay between each step. The time de-lays are selected to ensure that the flaring load never exceeds the flare system capacity. To determine the appropriate time delay, the flow profile should be generated for each depressurization valve. The exponent coefficient factor can be calculated using Eq. 2. The exponent coefficient factor for each isolatable section is described in TABLE 4.

The flow profile for each isolatable section can be generated using the initial depressurization load and the exponent coeffi-cient factor θ in Eq. 1. The next step is to evaluate the time delay, which can create sufficient ullage for the following step. Step 1 begins with a peak load of 140,000 kg/h, while Step 2 must ac-commodate an additional 80,000 kg/h.

Therefore, Step 2 can begin when the flaring load is reduced from 140,000 kg/h to 65,000 kg/h. As described in TABLE 5, af-ter 6 min. from the start of the depressurization sequence, the

flaring load is reduced below 65,000 kg/h. Step 2 has an addi-tional load of 80,000 kg/h and can be started at 6 min. The time delay for further steps is determined in a similar manner. The flaring load time profile during staggered depressurization is also displayed in FIG. 2.

Implementation aspects. For successful implementation of a staggered depressurization system, a number of detailed de-sign features must be implemented. These features should be included to avoid the simultaneous opening of all EDVs, which would cause the flare load to exceed the design capacity and, ultimately, lead to a catastrophic failure.

Secured instrument air system. Each EDV valve should be provided with a secured instrument air (SIA) buffer vessel. To ensure the workability of the EDV upon instrument air supply failure, the SIA system should be designed to maintain suffi-cient pressure in the buffer vessel for at least three valve strokes. To indicate low air pressure in the SIA, a low-pressure alarm is provided. To prevent backflow from the SIA system during the loss of instrument air header pressure, two non-return valves are recommended. Bleeding devices, such as regulators, should not be used downstream of the non-return valves.

020,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

0 30 60

Mass

flowr

ate to

flare,

kg/h

Depressurization time, min.

Blowdown load to flareTotal flare limit

FIG. 2. Flaring load during staggered depressurization.

TABLE 2. Depressurization priority of isolatable section

Priority of depressurization Isolatable section

Priority 1 Gas inlet manifold

Priority 2 Gas separator

Depletion compressor

Priority 3 Acid gas removal

Dehydration unit

Mercury removal

Priority 4 Nitrogen rejection

NGL recovery

Priority 5 Fractionation unit

Sweetening unit

Priority 6 Booster compressor

TABLE 3. Isolatable section accommodated in depressurization step

Depressurization step Isolatable section Priority of depressurizationInitial depressurization

load, kg/h Flaring load added for step

Step 1

Gas inlet manifold Priority 1 35,000

140,000

Gas separator Priority 2 30,000

Depletion compressor Priority 2 25,000

Acid gas removal Priority 3 30,000

Mercury removal Priority 3 20,000

Step 2

Dehydration Priority 3 30,000

80,000Nitrogen rejection Priority 4 30,000

NGL recovery Priority 4 20,000

Step 3

Fractionation train Priority 5 25,000

70,000Sweetening unit Priority 5 20,000

Booster compressor Priority 6 25,000



Solenoid valves. The use of normally energized solenoid valves with a 1oo1 or 1oo2 configuration is recommended. If normally de-energized valves are used, then the solenoid valve configuration will be 1oo2 (i.e., if one solenoid valve fails to energize or fails to open on energization, then the depressur-izing valve still opens).

Solenoid valves should be controlled from the instrument-ed protective system (IPS). The uninterruptable power sup-ply backup of the IPS should be sized for 30 min. or longer, depending on the overall depressurization cycle time. The exhaust port of the solenoid valve should be provided with port protectors, such as bug screens. Solenoid valves should be provided with resilient disc/seat material that gives a tight shutoff feature.

Takeaway. For a situation where the flare system is inadequate for handling the plant’s entire depressurization load, staggered depressurization is a practical solution to avoid modification of the flare system. During staggered depressurization, isolatable

sections with lower depressurization priority are depressurized with a time delay.

With proper design of a staggered depressurization route, the entire plant can be depressurized without exceeding the flare capacity, thereby preserving the safety of the facility.

TABLE 5. Calculation of time delay between each step

Isolatable section

Flaring load to depressurization valve, kg/h

Step 1 Step 2 Step 3

Time from start of depressurization sequence Peak load 0 min. 6 min. 6 min. 11 min. 11 min.

Gas inlet manifold 35,000 35,000 (0) 16,629 (6) 16,629 (6) 8,943 (11) 8,943 (11)

Gas separator 30,000 30,000 (0) 14,254 (6) 14,254 (6) 7,666 (11) 7,666 (11)

Depletion compressor 25,000 25,000 (0) 9,954 (6) 9,954 (6) 4,620 (11) 4,620 (11)

Acid gas removal 30,000 30,000 (0) 11,945 (6) 11,945 (6) 5,544 (11) 5,544 (11)

Mercury removal 20,000 20,000 (0) 7,963 (6) 7,963 (6) 3,696 (11) 3,696 (11)

Dehydration 30,000 30,000 (0) 13,925 (5) 13,925 (5)

Nitrogen rejection 30,000 30,000 (0) 13,925 (5) 13,925 (5)

NGL recovery 20,000 20,000 (0) 9,283 (5) 9,283 (5)

Fractionation train 25,000 25,000 (0)

Sweetening unit 20,000 20,000 (0)

Booster compressor 25,000 25,000 (0)

Total fl aring load 140,000 60,746 140,746 67,603 137,603

TABLE 4. Exponent coeffi cient factor for each isolatable section

Isolatable sectionInitial depressurization

pressure, bargFinal depressurization

pressure, bargDepressurization time,

min.Exponent coeffi cient

factor θ

Gas inlet manifold 45 7 15 0.1241

Gas separator 45 7 15 0.1241

Depletion compressor 70 7 15 0.1535

Acid gas removal 70 7 15 0.1535

Mercury removal 70 7 15 0.1535

Dehydration 70 7 15 0.1535

Nitrogen rejection 70 7 15 0.1535

NGL recovery 70 7 15 0.1535

Fractionation train 60 7 15 0.1432

Sweetening unit 60 7 15 0.1432

Booster compressor 80 7 15 0.1624

RAHUL DOLE is a process engineering manager with L&T-Chiyoda Ltd. in India. He has over 16 years of experience in process design for oil and gas refineries and petrochemical facilities. Mr. Dole holds a bachelor’s degree in chemical engineering from Mumbai University in India. He is also a registered member of the UK’s Institution of Chemical Engineers and the Indian Institute of Chemical Engineers.

SOHAN BHATT is a senior process engineer with L&T-Chiyoda Ltd. in India. He holds a bachelor’s degree in chemical engineering from the Maharaja Sayajirao University of Baroda in India, where he also received three gold medals for academic excellence. Mr. Bhatt is an active member of the Indian Institute of Chemical Engineers, and he is experienced in the process safety design of gas processing plants, oil refineries and petrochemical plants.

S. SRIDHAR is the head of process engineering at L&T-Chiyoda Ltd. He has more than 30 years of experience in process design. Mr. Sridhar holds a master’s degree in chemical engineering and has served as vice chairman for the Indian Institute of Chemical Engineers’ Baroda Center.

2014

JULY 30–31, 2014Norris Conference Centers – CityCentre Houston, Texas

GTLTechForum.com

Announcing the Second Annual GTL Technology ForumGulf Publishing Company is pleased to announce that the second annual Gas-to-Liquids (GTL) Technology Forum will be held in Houston, Texas from July 30–31, 2014. The inaugural conference included technology presentations, case histories, and panel discussions from GTL experts, including keynote speakers Mark Schnell, General Manager, Sasol; and Iain Baxter, Director of Business Development, CompactGTL.

Join us for the second annual GTL Technology Forum, which will investigate the technology and trends at work as GTL usage and projects rise in popularity. GTL is an increasingly important part of the North American energy industry. The World Bank estimates that over 150 billion cubic meters of natural gas are fl ared or vented annually, an amount worth approximately $30.6 billion. This is equivalent to 25% of US gas consumption, or 30% of EU gas consumption per year. As the natural gas boom in North America continues and new technologies emerge to reduce costs, company interest is increasing—and so is investment. Project announcements and planning from industry innovators like Sasol, Shell, Petrobras and BP are beginning to ramp up in this energy niche.

The GTL Technology Forum is your chance to connect face-to-face with top operators and technology leaders from across the global hydrocarbon processing industry. The 2014 conference program will be organized by an esteemed advisory board, and will cover GTL products, economics, market opportunities and more. The call for abstracts is now open. Please see submission guidelines on the following page.

GTL Technology Forum Advisory Board:

Arun BasuInstitute EngineerGas Technology Institute

Iain BaxterBusiness Development DirectorCompactGTL

Carl HahnDirector, Sales and Process TechnologyPentair Separations Systems

Mark LaCour, P.E.Project Development and Procurement ConocoPhillips

Neils UdengaardHaldor Topsoe, Inc.

Mark SchnellGeneral Manager – Marketing, Strategy and New Business DevelopmentSasol

Paul SchubertChief Operating Offi cerVelocys

Timothy VailPresident & CEOG2X Energy

2014

JULY 30–31, 2014Norris Conference Centers – CityCentre Houston, Texas

GTLTechForum.com

Call for Abstracts Now OpenIf you would like to participate as a speaker, we invite you to submit an abstract

for consideration by our advisory board.

Suggested topics and areas of interest include:• GTL—Fischer-Tropsch

• GTL—MTG/Methanol

• GTL products—fuels, lubes, specialty products, etc.

• Economics, properties, performance, etc.

• Floating GTL

• Financing of GTL projects by owners, equity, banks

• Permitting issues (requirements, thresholds, timing, etc.)

• Market opportunities, market drivers, market analysis

• Co-processing of NG + Biomass and NG + Coal/Biomass for site-specifi c applications

• Production of DME as a GTL product besides FT/MTG/Methanol

• Novel NG-to-syngas manufacturing technologies

• Ammonia production from syngas

• Case studies: operation, catalyst life, troubleshooting, downtime, product quality, etc.

Don’t miss this unique opportunity to share your

knowledge and expertise with your peers in the industry.

Submission Deadline: January 31. Abstracts should be approximately 250 words in length and should include all authors, affi liations, pertinent contact information, and the proposed speaker (person presenting the paper). Please submit via e-mail to [email protected] by January 31.

For More Information contact Melissa Smith, Events Director, Gulf Publishing Company, at [email protected] or +1 (713) 520-4475.

Sponsor/Exhibitor Inquiries: Please contact Lisa Zadok, Events Sales Manager, at [email protected] or +1 (713) 525-4632.

Register Early and SaveTake advantage of Super Early Bird pricing when you register early.

Construction of HPI projects involves numerous risks for several parties. The design and construction of such complexes can take years, from project announcement to commissioning of the complexes. They are also multibillion-dollar efforts. Such projects can entail demonstrations of leading-edge technologies. The HPI projects for 2013 are:

• Williams Energy’s propane dehydrogenation (PDH) project, Redwater, Alberta, Canada• Sasol North America’s ethane cracker and derivatives project, Lake Charles, Louisiana• Ecopetrol’s Cartagena refinery expansion, Cartagena, Colombia• Chevron Australia’s Gorgon LNG project, Barrow Island, Australia• Indian Oil Corp. Ltd.’s Panipat refinery and petrochemicals complex, Panipat, India

Top: Ongoing Gorgon LNG project work includes the installation of three amine absorbers, two condensate stabilization modules and a recycled gas compression module. Photo courtesy of Chevron Australia.�Bottom: The Reficar refinery in Cartagena, Colombia, is expanding capacity to 165 thousand barrels per day (Mbpd). Photo courtesy of Ecopetrol.

| HPI Focus

Top HPI Projects


Top HPI Projects

Among the number of planned lique-fied natural gas (LNG) projects in Aus-tralia, Chevron Australia’s Gorgon LNG project on Barrow Island is unique. Situat-ed approximately 60 kilometers (km) off the northwest coast of Western Australia, the liquefaction terminal’s environmen-tally sensitive location demands special design considerations and careful con-struction planning. Gorgon LNG, which sits on a nature reserve, is also one of the world’s largest natural gas projects and the largest single resource development in Australia’s history.

The Gorgon LNG project received its name from the ship named the SS Gorgon. The SS Gorgon (and its 1933 replace-ment, the MV Gorgon) carried passen-gers, general cargo, sheep, wool and cattle

from Perth, Australia to Singapore from 1918 through the 1960s.

Project scope. Gorgon LNG is a joint venture ( JV) between Chevron Australia (47.3%), ExxonMobil (25%), Shell (25%), Osaka Gas (1.25%), Tokyo Gas (1%) and Chubu Electric Power (0.417%). The project will mark Chevron’s entrance into the realm of large-scale LNG operations.

With a planned liquefaction capacity of 15.6 million tons per year (MMtpy) at three trains, and a projected cost of $59 billion (B), Gorgon LNG is scheduled for completion in 2015 at the earliest. The massive Gorgon gas reserves will sup-port construction of a fourth LNG train, although this segment of the project has been delayed due to mounting costs.

Additionally, the facility’s gas process-ing plant will provide 300 terajoules of gas per day to Western Australia, and LNG for shipment to Asia. The project also in-cludes the construction of LNG and con-densate storage tanks; marine facilities, including a 2.1-km materials offloading fa-cility and 2.1-km-long LNG jetty (FIG. 1); operations and maintenance buildings; and a workforce accommodation village and associated infrastructure.

Contract awards. Gorgon LNG’s con-tractors have been tasked to accommo-date special considerations for the facil-

ity’s environmentally sensitive location. A JV of Kellogg, Brown and Root (KBR) Inc. and partners JGC Corp., Clough Ltd. and Hatch Ltd. was awarded a $2.5 B con-tract to engineer, procure and manage construction (EPCm) of the LNG down-stream, gas processing and treatment, and logistics portions of the project.

The EPCm effort is a modular con-struction strategy to minimize environ-mental impact on Barrow Island during the construction phase, and is being con-ducted from two main operating centers in Perth, Australia and London, UK, with support from global centers in the US, Singapore, Indonesia and Japan. The JV will utilize several fabrication yards across Southeast Asia and Australia to support the planned 250,000 tons of LNG mod-ules. Along with the above scope of work, the JV will implement a comprehensive quarantine-management plan for the is-land. Additionally, CO2 removed from the gas prior to processing will be injected into a reservoir beneath Barrow Island, reduc-ing greenhouse gas emissions from the project by approximately 40%.

The construction portion of the proj-ect will be completed by a JV of Chicago Bridge & Iron Co. (CB&I, 65%) and Kentz Corp. Ltd. (35%). The JV’s $2.3 B construction contract includes structural, mechanical, piping, electrical, instrumen-tation and commissioning support for the construction of the three LNG trains, as-sociated utilities and a domestic gas pro-cessing and compression plant. The con-tract will be completed in 2015 and will create more than 1,650 jobs for construc-tion personnel.

In addition to these companies, Em-erson Process Management will provide control valves and valve actuators for the project. This contract is valued at $67 MM and includes over 1,000 control valves, valve controllers and actuators for appli-cations ranging from inlet gas processing, acid gas removal, liquefaction and frac-tionation to anti-surge and cryogenic con-ditioning. Emerson’s Australian facilities are partnering with Perth-based Western Process Controls to provide training.

Project progress. As of September 2013, Chevron’s latest internal cost review placed the Gorgon LNG project’s total cost at $59 B, up from the $52 B projected earlier. At the project’s conception, the cost was pegged at just $37 B.

FIG. 1. Work continues on the 2.1-km-long jetty, with more than 24 caissons in place. Photo courtesy of Chevron Australia.

CHEVRON’S GORGON

LNG DEFIES LOGISTICAL

AND FINANCIAL CHALLENGES

A. Blume


Top HPI Projects

In Australia, rising construction and installation costs and skilled labor short-ages have contributed to increases in cost projections—and, in some cases, delayed construction time tables—for several LNG projects. For this reason, Chevron Australia and its partners are anticipated to postpone to 2014 design and engineer-ing work on a proposed fourth LNG pro-duction train at Barrow Island. However, recent weakening of the Australian dollar could be a boon for the project’s budget.

In addition to countrywide cost-management considerations, the project partners have faced ongoing challenges related to the project’s location. The en-vironmental demands of operating on a nature reserve often translate into higher costs, which is one factor contributing to the delay in the design for the fourth LNG train. Construction of the original three trains is 70% complete, but the addition of a fourth train could cost as much as $20 B due to the intricate subsurface prepara-tion required for additional pipelines and compression facilities. For this reason, analysts believe that project completion could be pushed ahead to 2016.

Nevertheless, Gorgon LNG has an ad-vantage in that it is at an advanced stage of development and is scheduled to begin exporting LNG to Asian markets before other major LNG projects in the region. As of October 2013, approximately 65% of the project’s forecast 15.6 MMtpy of LNG output has been contracted under long-term sales agreements. Gorgon LNG will deliver contracted volumes to Osaka To-kyo Gas, Chubu Electric Power, GS Caltex, Nippon Oil Corp. and Kyushu Electric.

SASOL MOVES AHEAD ON MASSIVE

US ETHANE CRACKER, GTL

PROPOSALSB. DuBose

Many petrochemical companies are looking to take advantage of the US shale boom and the availability of cheap

feedstocks. However, even by those stan-dards, Sasol’s proposed investments near its existing facilities in Westlake, Louisi-ana, stand out as among the industry’s most ambitious (FIG. 2).

With project costs estimated at be-tween $5 B and $7 B, the ethane cracker will be one of the world’s largest, designed to produce 1.5 MMtpy of ethylene.

Meanwhile, Sasol is also evaluating an innovative gas-to-liquids (GTL) com-plex at the site that would be the first of its kind in the US. It is scheduled to produce 4 MMtpy, or 96 Mbpd, of high-quality transportation fuels, including GTL diesel and other value-added chem-ical products.

Total investment in the GTL plant would be near $15 B, roughly three times the cost of a traditional refinery (FIG. 3).

Project goals. “The ethylene produced in the chemical facility will be used to produce a range of high-value derivatives in world-scale plants,” said André de Ruyter, senior group executive for global chemicals and North American opera-tions at Sasol.

“This forms part of Sasol’s strategy of building globally competitive down-stream facilities and adding value to the already low cost of ethylene production opportunity in North America,” he added.

Mark Schnell, general manager of marketing, strategy and new business development for Sasol, spoke about the GTL side of the equation.

“The availability of affordable natural gas is unprecedented on the global stage,” Schnell said. “It’s on us to step up as a business and provide solutions.”

“GTL products are unique, with higher quality than conventional equiva-lents,” Schnell noted. “The challenge is how to best position these products to capture that value.”

One strategy could be to target the domestic and global diesel markets. Die-sel produced through the GTL process is cleaner than conventional diesel, Schnell explained, particularly given that it is zero-sulfur.

“Globally, diesel remains the work-horse for economic growth,” Schnell said. “Diesel growth is consistently outstrip-ping other petroleum grades, and our expectation is that trend will continue. In addition, it is becoming more difficult for conventional refining to meet the re-quired product mix, not to mention the increasing requirements for stricter fuel quality standards.”

The question is whether the market will ultimately prioritize clean diesel, thus giving GTL companies like Sasol the economic incentive to produce it in higher quantities. Factors that may spur development, according to Schnell, in-clude tighter emissions policy measures, an increasing desire for domestic energy security, and the need to move away from crude oil-based feedstocks.

For both the ethane cracker and GTL proposals, Sasol began feasibility studies in late 2011 and launched the front-end

FIG. 2. The new plants will be located near Sasol’s existing facilities in Westlake, Louisiana.

FIG. 3. Louisiana Governor Bobby Jindal spoke at Sasol’s project announcement for the ethane cracker and GTL plans.


Top HPI Projects

engineering and design (FEED) phase in December 2012.

Engineering and technology pro-viders. In July 2013, Sasol progressed further on the ethane cracker side by an-nouncing all engineering and technology provider appointments.

Fluor is the main FEED contractor for the ethane cracker and derivatives proj-ect, while individual engineering services agreements for the development of ba-sic packages were concluded with Toyo Engineering for the linear low-density polyethylene (LLDPE) plant, Mitsui En-gineering & Shipbuilding for the low-density polyethylene (LDPE) plant, and Samsung Engineering for the ethylene oxide (EO) and monoethylene glycol (MEG) units.

Meanwhile, the technologies of Tech-nip Stone & Webster Process Technol-ogy, ExxonMobil Chemical, Univation Technologies and Scientific Design Company were selected for the ethane cracker, LDPE, LLDPE and EO/MEG processes, respectively. Sasol also plans to use its own proprietary technologies for the Tetramerization, Ziegler alcohol and Guerbet alcohol units.

Emerson Process Management was named as the main automation contrac-tor for the project, while Worley Parsons was contracted to support Sasol’s own project execution team as part of an in-tegrated project management team. In that role, Worley Parsons systems, tools and local expertise will be used to en-hance the Sasol team that is overseeing the project.

“The selected companies are leaders in their respective fields and have the tech-nologies, systems and expertise to help us deliver the project on schedule, optimiz-ing our return on investment,” said Johan du Preez, executive vice president for US mega-projects at Sasol.

The ethane cracker project was also advanced in April 2013 with the place-ment of a purchase order for the main ethylene compressor trains from MHI Compressor International.

From the GTL perspective, Sasol in August 2013 unveiled an alliance with Technip for front-end engineering servic-es on future Sasol GTL projects. That al-liance also allows for Technip’s participa-tion during the execution stage of those GTL projects.

Timeline. Sasol expects to make a final investment decision on the proposals in 2014, after the engineering and design reviews are finished.

Beneficial operation from the eth-ane cracker is expected to be achieved in 2017. Meanwhile, the GTL plant’s two phases would start operations in 2019 and 2020, making it the first facility in the US to produce GTL transportation fuels and other products.

GEM OF INDIA’S DOWNSTREAM:

INDIAN OIL CORP.’S PANIPAT

REFINERY, PANIPAT, INDIA

S. Romanow

The Indian Oil Corp Ltd. (IOCL) group of companies owns and operates 10 of India’s 21 refineries, with a com-bined refining capacity of 65.7 metric MMtpy, or 1.3 MMbpd. One of this re-finer’s rising-star facilities is the Panipat refinery and naphtha complex. Located in northern India, this refinery operates on a sprawling, 4,225-acre spot about 100 km from New Delhi. The refinery is one of the largest integrated refining and petrochemical complexes in India and Southeast Asia.

The early days. Originally, the Panipat refinery was approved for construction as the Karnal refinery, located near Ba-holi in the Karnal district in 1984 with a proposed startup in 1989. The USSR, through a trade organization, showed a keen interest in developing this refinery with IOCL and signed an interest agree-ment. However, in late 1988, it was appar-ent that Soviet assistance would not ma-terialize. Accordingly, IOCL proceeded in developing this refinery project alone.

In the 1980s, the northwest region of India had a huge deficit of petroleum products. The new refinery was intended to alleviate some of the supply shortage. At that time, a new district, Panipat, was formed, and the Karnal refinery was re-named Panipat during its construction.

The Panipat refinery is IOCL’s sev-enth refinery. The original refinery was commissioned in July 1998, with a dis-tillation capacity of 6 metric MMtpy. The complex configuration included a catalytic reforming unit, a hydrocracker, a fluid catalytic cracking (FCC) unit and a visbreaker.

As demand for refined petroleum products continued to rise in Northern India, the plans developed to expand the Panipat refinery from 6 metric MMtpy to 12 metric MMtpy in 2006. This expan-sion would also increase the complexity of the refinery by adding more second-ary processing capabilities. The new pro-cessing units included a full-conversion hydrocracker, delayed coking, diesel hy-drotreating, hydrogen generation unit and sulfur-recovery unit, as well as associ-ated auxiliary services and infrastructure to support the additional refining needs.

Environmental regulations. To meet sustainability and environmental stan-dards, the Indian refineries were required to produce Euro 3- and Euro 4-quality fuels and motor spirits (MS) under the Motor Spirits Quality (MSQ ) Project. To meet the new guidelines for lower-sulfur MS as part of the MSQ project, the Panipat refinery was upgraded with new processing units. The expansion and revamp included a new, 400 metric Mtpy isomerization unit, a 410-metric Mtpy naphtha hydrotreater, a 470-metric Mtpy reformate splitter and a 370-metric Mtpy FCC gasoline desulfurization unit. These new processing units were completed and commissioned in November 2009. With this expansion, the Panipat refinery was IOCL’s first refinery to produce Euro 3 and Euro 4 MS.

Next wave. In November 2010, the throughput capacity of the Panipat re-finery was again expanded to meet rising regional demand for MS from 12 metric MMtpy to 15 metric MMtpy. This proj-ect was different; it focused on adding more flexibility to the site to process high-sulfur crude oils now available. This expansion included provisions to pro-duce Euro 3 and Euro 4 high-speed diesel (HSD) products, and included:

• Increasing the capacity of the crude and vacuum distillation unit (CDU/VCU) from 6 metric MMtpy to 7.5 metric MMtpy


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Refi nery Middle East Yanbu Saudi Arabia Saudi Aramco\Sinopec 2.5 MMtpy 1200

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Top HPI Projects

• Increasing the once-through hydro-cracker capacity from 1.7 metric MMtpy to 1.9 metric MMtpy

• Raising the delayed coking capacity from 2.4 metric MMtpy to 3 metric MMtpy.

Other updates involved second-stage reactors for the diesel hydrotreaters, new sour water strippers, a sulfur-recovery unit and a tail gas treating unit.

Today, the Panipat refinery is an effi-cient and automated refinery. It is a zero-discharge refinery. The additional upgrad-ing efforts minimize waste. This refinery is surrounded by a greenbelt of trees and vegetation to sustain the local environ-ment. The Panipat refinery received the prestigious Golden Peacock Environ-ment Management Award in 2012 in the oil and gas category. In 2012, this facility received the Greentech Platinum Safety Award from the Greentech Foundation for the implementation of exemplary fire and safety management systems.

Integration. The Panipat refinery is ad-jacent to a world-class naphtha cracking complex (FIG. 4). This olefin unit is the larg-est naphtha cracker in India, with a name-plate capacity of 800 Mtpy of ethylene and 650 Mtpy of propylene to support several downstream polymer units. The naphtha cracker uses the CB&I Lummus olefins technology. It also provides benzene and other blending products for the refinery.

This naphtha cracker was commis-sioned in March 2010. The ethylene is the feedstock for several polymer units including linear low-density polyethyl-ene, high-density polyethylene, poly-propylene and other petrochemicals including monoethylene glycol, dieth-ylene glycol and benzene (FIG. 5). The complex also features paraxylene and purified terephthalic acid units; these processes strengthen the facility’s ability to manufacture polyesters and polyeth-ylene terephthalate (PET) plastic bottle-grade resins. Benzene is used to produce various consumer products such as paints and varnishes, pesticides, adhesives, and more. IOCL plans to provide 20% of do-mestic polymer demand with the Panipat ethylene/petrochemical complex.

The Panipat naphtha complex involved participation of 17 large national and in-ternational contractors, five process tech-nology licensors, two project management companies, plus a strong team from IOCL. During peak construction, over 28,000 workers were involved at the construction site, including more than 5,000 engineers from India, Korea, Japan, Singapore, Ger-many, Italy, Canada and the US.

The petrochemical complex used new construction methods that involved pipe diameters up to 108 in. in diameter. The Panipat Naphtha Cracker Project won the PETROTECH 2011 award for proj-ect management.

Expansion of petrochemicals. The Panipat refinery complex has emerged as a modern, thoroughly integrated, syn-ergistic manufacturing complex. Stream sharing and exchange of process streams and utilities have positioned this complex as a major petrochemical hub. To con-tinue the downstream integration and improve the hydrocarbon value chain, a new, 120-Mtpy styrene butadiene rub-ber (SBR) plant is under planning at the site. It will use available butadiene from the naphtha cracker to produce SBR used in many consumer goods, especially tires, shoes, and automobile belts and hoses.

WILLIAMS TAKES LEAD IN ALTERNATIVE PROPYLENE

TECHNOLOGIESB. DuBose

The global trend toward increased ethane cracking is known and largely viewed as positive. However, it has one major supply downside in the form of

FIG. 4. Lifting of the propylene fractionator no. 2 of the naphtha cracker plant. This column weighed nearly 1,305 metric tons with an 8.2-m internal diameter and is the heaviest column of olefin complex. It was fabricated in three parts, assembled and erected on site.

FIG. 5. Construction of the recovery section and loop reactor for the polypropylene unit train 1. The two-loop reactor and support structure weighed about 432 metric tons.


Top HPI Projects

fewer coproduct volumes. Ethane crack-ing produces much smaller amounts of propylene, benzene and butadiene, and, in turn, fewer product derivatives.

One way to address this issue is through niche catalytic processes, such as on-purpose technologies. That is ex-actly what Williams is planning to do in Canada’s Alberta province, where it will build Canada’s first propane dehydro-genation (PDH) plant to produce poly-mer-grade propylene (PGP) (FIG. 6).

Location and capacity. Earlier this year, Williams granted formal approval to begin construction of the PDH facility, which will be in close proximity to its ex-isting Redwater fractionation plant near Edmonton, Alberta.

The PDH facility will have the capac-ity to initially produce up to 1.1 billion lb/year (500 Mtpy) of PGP, with the op-portunity to double capacity with a fu-ture expansion. This will allow Williams to significantly increase its production of PGP from its operations in Canada, where it is the only domestic company producing the chemical.

“We’re thrilled to be moving full-speed ahead on Canada’s first and only PDH facility,” said David Chappell, pres-ident of Williams Energy Canada.

“The project fits strategically within Williams’ operations in Alberta, lever-ages our expertise in propylene and adds further value to a byproduct of oil sands upgraders,” he added. “Once operational, this new facility will expand market op-portunities in Canada, feed the demands of North America’s growing petrochemi-cal industry and allow for the creation of a new value chain in Alberta.”

Process technology critical. Wil-liams has selected Honeywell UOP as the licensed technology provider for the olefin dehydrogenation process. The technology uses a platinum-based cata-lyst system, as well as less energy and wa-ter than several other PDH technologies.

Williams plans to primarily use propane recovered from its expanding oil sands off-gas processing operations, along with local propane purchases, as feedstock for the new PDH facility. Williams is the world’s only processor of oil sands upgrader off-gas, giving it a unique market position.

When producers convert the Cana-dian oil sands into usable oil, the pro-cess produces an offgas byproduct that includes a rich mixture of natural gas, NGLs and olefins. Williams pioneered the process of extracting the mixture from the offgas at its liquids extraction plant in Fort McMurray, Alberta.

After it extracts the offgas mixture, Wil-liams returns the clean-burning natural gas to the third-party oil sands producer for its operations. It then transports the remain-ing NGL/olefins mixture, via Williams’ Boreal Pipeline, to its Redwater fraction-ation facility for further separation.

Williams’ offgas processing reduces emissions of CO2 in Alberta by approxi-mately 200 Mtpy and cuts emissions of sulfur dioxide (SO2) by an average of 1.7 Mtpy, the company says. The new offgas expansions will further limit both CO2 and SO2 emissions.

In turn, the recovered propane will feed the PDH project. Williams will convert the propane into higher-value propylene that will be transported to the US Gulf Coast and sold to petrochemical producers. Meanwhile, the associated hy-drogen byproduct will be sold in Alberta.

Investment details and proposed timeline. Williams, which operates the only olefins/NGL fractionators in west-ern Canada and has a 90-year history in the country, estimates total capital ex-penditures on the project to be near $900 MM. Expenses will be funded with ex-pected cash flow from the company’s Ca-nadian operations, as well as from interna-tional operations.

Pending appropriate permitting ap-provals, the PDH facility is scheduled to go into service in the second quarter of 2016.

Alan Armstrong, CEO of Williams, said, “We expect the PDH facility to de-

liver a very attractive return on invest-ment, as well as provide a long-term natural hedge of the propane volumes we control in our Canadian offgas processing business. Our planned PDH facility will enable Williams to capture the full value between natural gas and polymer-grade propylene, rather than just the value be-tween natural gas and propane.”

When complete, Williams expects the new facility to execute one of the lowest-cost propylene production processes in North America.

COLOMBIA’S CARTAGENA REFINERY IS DOUBLING CAPACITY, CUTTING

SULFUR LEVELSB. Thinnes

Ecopetrol’s Reficar Cartagena refinery is located within an industrial zone in the Mamonal Port on the banks of Cartagena Bay. The bay is on Colombia’s northern coast. This refinery is strategically situ-ated, allowing it access to the US Gulf Coast and Caribbean markets by way of the Atlantic Ocean. Refined products also flow out of the refinery to serve Colom-bia’s domestic market via a pipeline net-work and by ship on the Canal del Dique, a 118-km canal connecting Cartagena Bay to the Magdalena River.

The Cartagena refinery was built in 1956 by the International Petroleum Co. (Intercol). In 1974, Ecopetrol acquired the refinery from Intercol.

Cartagena has seen several upgrades and expansions in its lifespan, in the years 1964, 1983 and 1995. The present expansion and revamp taking place at the facility is by far the most substantial in its history. When completed in 2015, it will take the refinery’s capacity from 80 Mbpd to 165 Mbpd. This expansion will help Ecopetrol reach its targeted re-fining capacity across all facilities to 650 Mbpd (the largest refinery in Ecopetrol’s network is Barrancabermeja, with a 250-Mbpd output capacity).

FIG. 6. The new PDH plant will be located close to Williams’ existing Redwater fractionation plant near Edmonton, Alberta.


Top HPI Projects

Total investment in the expansion is expected to be $6.5 B (FIG. 7). To finance the project, Ecopetrol looked to a consor-tium of export credit agencies and com-mercial banks. The coalition of deals has been structured under a project finance template. In essence, this structure pro-vides for the long-term financing of in-frastructure and industrial projects based upon the projected cash flows of the proj-ect rather than the balance sheets of its sponsors. According to data from 2012, $3.5 B out of the $6.5 B revamp total will emerge from the project finance ar-rangement. The key point here is that six months after the conclusion date for the project, the repayment clock starts tick-ing. All involved parties agreed to a repay-ment schedule of no greater than 14 years.

The key players in the project finance deal were:

• The US Export-Import Bank• Servizi Assicurativi del Commercio

Estero (Italy’s export credit agency)• Exportkreditnämnden (Sweden’s

National Export Credits Guarantee Board)

• Sumitomo Mitsui Banking Corp.• Banco Bilbao Vizcaya Argentaria SA• HSBC Bank USA, National

Association• The Bank of Tokyo-Mitsubishi

UFJ Ltd.The majority of the loan money is

from the US Export-Import Bank ($2.8 B). The terms of the loan stipulate that the money must be spent on goods and services from the loan originator’s coun-try. Therefore, the financing from the US Export-Import Bank will help support the purchases of equipment and services from over 150 US engineering, design, equipment supply, contracting and pro-cess license firms.

Among the US companies playing an instrumental role in the Cartagena re-vamp, CB&I is the lead EPC contractor on the project. Merichem is involved in licensing for the facility’s LPG, kerosine and naphtha treatment units. KBR has two contracts to provide technology li-censing and related services to upgrade the FCC unit. Foster Wheeler has been on board as a project management consul-tant. KBC Advanced Technologies is pro-viding technical services for the revamp, and UOP is sharing its licensing expertise.

The revamp and expansion will allow Reficar to process heavier, sourer crudes

into clean, ultra-low-sulfur gasoline and diesel (FIG. 8). The resulting products are expected to be distributed within Co-lombia and sent off to international mar-kets, especially those in the Caribbean and the US.

According to a statement from Eco-petrol, the project will encompass im-provements in all of Reficar’s refined products. Sulfur content in gasoline will be reduced from 1,000 ppm to 300 ppm for domestic consumption, and to 30 ppm for export. Sulfur in diesel produced at Cartagena will drop from 4,500 ppm to 500 ppm for domestic consumption and 30 ppm for export. The company believes that these improvements will al-low the refinery to increase white prod-uct (gasoline, LPG and medium oils) yields to competitive levels and allow for

increased volumetric expansion, generat-ing additional volumes close to $2/bbl. The $2/bbl number is based on present refining margins.

Revamp and expansion projects of this magnitude rarely go according to plan, and Reficar has encountered some delays and complications in achieving its goal. In September, construction work-ers in Cartagena went on strike, protest-ing their wages. The work stoppage was the first in Colombia’s oil sector in nine years. Thankfully, negotiations between labor and management were swift, and the strike was concluded after three days. The deal to bring the workers back re-quired lead EPC contractor CB&I to increase wages by 40%–100% for all seg-ments of the domestic laborers contrib-uting to the project.

FIG. 8. The revamp at Reficar will drop sulfur content in gasoline produced at the refinery from 1,000 ppm to 300 ppm for domestic consumption, and to 30 ppm for export.

FIG. 7. Total investment in the expansion is estimated to be $6.5 B.

2 0 1 3 W O M E N ’ S

HO

US

TO

N

A Recap of the 2013 Women’s Global Leadership Conference in Energy & Technology (WGLC)The tenth Women’s Global Leadership Conference in Energy & Technology was held October 29–30 in Houston and focused on “Changing the Global Dynamics—America’s Renaissance.” One of the largest women’s events in the industry, this year’s WGLC was host to 685 industry professionals. The event featured three outstanding keynote speakers, 14 presentations and panel discussions covering shale and unconventional resources in North America and women’s professional development issues, and included an exhibition area full of supporting organizations.

The conference opened on Tuesday with a keynote speech by Amity Shlaes, Director 4% Growth Project, George W. Bush Institute and New York Times best-selling author. In her keynote address, Ms. Shlaes noted that innovation is key to keeping the energy sector at the forefront of U.S. economic growth, and more of this innovation must come from women. “The message to women today is to rise to the top to walk in the halls of power, speak up, and improve your company as you do it,” Ms. Shlaes said.

Jo Miller, CEO of Women’s Leadership Coaching, began day two with a workshop titled “Becoming a Person of Infl uence.” In her workshop, Miller taught attendees how to create their own 30-second commercial and advised that the fundamental truth of becoming a person of infl uence at their organization was that “our behavior teaches others how to treat us.” Miller then went on to address the six types of infl uence people can exert in the professional world and the ways in which oil and gas professionals can expand their infl uence at any career stage.

Following lunch on day two, track and fi eld record holder Jackie Joyner-Kersee spoke to attendees about using their God-given gifts and blessings to get the most out of themselves and shared her message of hope, faith, perseverance and hard work to a rapt audience who gave her a standing ovation.

In keeping with the 2013 theme, other presentations and panel discussions focused on U.S. shale and unconventional resources, exports, America’s energy future and developing the future generation of leaders in the oil and gas industry. In the conference’s fi rst panel discussion, panelists from Baker Hughes Incorporated, XTO Energy, Statoil and Tudor, Pickering, Holt & Company discussed how shale and unconventional resources are reshaping how we do business and the lessons to be learned in this characteristically low–margin space. Later, Charles T. Drevna, President, American Fuel & Petrochemical Manufacturers, warned that U.S. fuel and petrochemical companies must shake off past inclinations toward energy protectionism if they are to fully take advantage of the shale revolution.

Throughout the conference, panelists and speakers stressed the importance of getting the next generation, and women in particular, involved in STEM studies and excited about the oil and gas industry. Shelly Cory, Strategic Integration Project Manager, Baker Hughes Incorporated, shared the initial results of their STEM initiative, and Tyra Metoyer, Energy Nation Consultant, American Petroleum Institute, spoke about employment opportunities for minorities in the industry. Additional panel discussions focused on the “Great Crew Change” and recruitment and training.

The next WGLC is scheduled for November 4–5, 2014 at the Hyatt Regency Houston.

Participate in the 2014 Women’s Global Leadership in Energy & Technology…Speaker Inquiries: Melissa Smith, Events Director, [email protected], +1 (713) 520-4475.

Exhibit or Sponsorship Inquiries: Lisa Zadok, Events Sales Manager, [email protected], +1 (713) 525-4632

Plan to Attend: WGLConference.com

Amity ShlaesDirector 4% Growth ProjectGeorge W. Bush Institute

Jo MillerChief Executive Offi cerWomen’s Leadership

Coaching, Inc.

Jackie Joyner-KerseeTrack and FieldRecord Holder


SafetyR. MODI, professional engineer, Abu Dhabi, UAE

Rethink the hazards in your process

In designing process safety systems, “more” is not neces-sarily better. Advanced technology has created a mindset to over-install hardware to prevent or to reduce the risk of failure in hydrocarbon processing facilities. Several international stan-dards set guidelines on equipment/instrumentation life cycle systems. There are better approaches in developing a safety in-strument system (SIS) that can achieve a balanced safety func-tion system and still meet all mandatory requirements.

Managing process hazards safely. Major plants contain hazardous processes. Therefore, adequate precautions are re-quired for process safety. It is essential to apply different tech-niques to reduce processing risk to the acceptable limits. Dur-ing the design and selection of the process configuration and technologies, attention is directed at mitigating risk from the process as well.

Various methods can be applied to prevent or to mitigate possible unsafe events and operating conditions to further re-duce risk to acceptable or tolerable levels and still efficiently operate the facility. Options include:

• Modifying the process design• Improving mechanical integrity• Installing SIS and mitigating equipment• Improving basic process control systems (BPCS)• Developing training and operational procedures, etc.It is essential to apply significant efforts to all demanded

safety functions while designing any safety system to achieve tolerable risk. However, eliminating risk and still operating the facility in absolute safety is not practically possible.

Safety life cycle. According to the prominent international standards, i.e., IEC 61508 and 61511, the safety life cycle has three phases: analysis, realization and operation. Out of the three phases, the analysis and realization phases play a vital role in the total performance of the SIS in most applicable pro-cess conditions.

A growing trend by many safety-system designers/users is to consider incorporating more hardware to improve design and reliability. Many designers hold the position that “more is better” in designing safety/process control systems. This is a conflict with the main aspect to balance system design between safety and availability by applying suitable architecture that meets specific process conditions. Consequently, engineers get trapped into overdesigning the system. A study of different leading organizations reported the approximate value of over- and under-design falls in the range of 35%–50% and 4%–6% of total safety loops, respectively.

During the review process, many questions will surface regarding compliance with international standards, evolving technologies and contemporary market trends, realization of cost-to-benefit, and suitability of selected architecture for spe-cific process applications. Therefore, proper care at the design stage is very significant to achieve continuous operation and flawless function to prevent intolerable incidents during the operation phase.

FIG. 1 illustrates the major steps required to comply with IEC 61511 for SIS design. The safety instrumented function (SIF) is identified during hazard and operation (HAZOP) studies, i.e., the process hazards analysis (PHA). “Risk assessment” determines the required safety instrumented level (SIL) to re-duce the risk up to the “target frequency.” So, the SIS should be designed and implemented to fulfill the function of bringing the process to a safe state in the event of an unacceptable devia-tion or failure of any subsystem/component of the SIS.

Basis of SIS design. The SIS comprises different subsystems (physical components). The subsystems used to implement the SIS are:

• Input elements such as sensors, push buttons and switches• Logic solvers such as the emergency shutdown (ESD), pro-

grammable logic controller (PLC) or relay based devices• Output elements such as the final elements—valves, so-

lenoids and circuit breakers. FIG. 2 illustrates the basic connectivity of the subsystems.

Typically, the SIS performs several functions such as detect-ing process demands, executing the predefined logical func-tions and actuating output elements to bring the plant/process to a safe state. The subsystem components are assessed for their complexity, inherent properties and behavioral uncertainty.

SIL validation SIS designSIL assessment

SIL verifications HAZOP

SIF identification

FIG. 1. Major steps in the design of SIS systems.

I/p O/pLogic solverInitiator Actuator

ESD with 10 command PS modules

Sensors forsignal input

Final elementsfor action

FIG. 2. Simple diagram of SIS subsystem.


Safety

Therefore, they are classified as type A or B subsystems. A Type A subsystem is a simple design, whereas the microprocessor-based complex design is considered as a Type B system.

In simple terms, the effectiveness of an SIS can be described by the term, PFDavg , as the probability of failure to perform the desired safety function when demanded. It is a statisti-cal representation in the bands of numerical values. The high PFDavg indicates—low SIL and low PFDavg indicates—high SIL. A SIS is used to implement one or more SIF(s) accord-ing to the desired SIL(s). So, the SIS design should meet the required value of PFDavg for the specific process applications. According to the SIS design, the selected ESD/logic solver should be with the highest SIL among all of the SIF(s) to be incorporated in that SIS. Normally, process automation indus-tries operate in the “low-demand” mode up to SIL3.

Contributing factors for SIS voting. For SIS design, the usual understanding is to determine the SIL and several key factors such as hardware fault tolerance (HFT), safe failure fraction (SFF), diagnosis coverage (DC), acceptable spuri-ous trip rate (STR), test interval, types of subsystem (A or B), common cause of failure (CCF), redundancy (identical or diverse), mean time between failure (MTBF), mean time to restore (MTTR), etc.

Are these sufficient decisive factors to derive voting/archi-tecture for each SIF to incorporate in the SIS? The answer is not so simple. It is essential to design a SIS that balances both safety and availability for the specific process conditions and applications where it is to be implemented; the design must be suitable, balanced, and yet, reliable. Several examples are:

Processhookup

Process safetytime

Processtechnology

DC(diagnosticcoverage)

STR(spurious trip

rate)CCF (common

cause offailure)

SFF (safefailure

function)

HFT (HWfault

tolerance)Function

test interval

MTBFand MTTR

Subsystemtype: A or B

Systemarchitecture

MooN

Systemconfiguration

Prooftestingfacility

Redundancyidentical/

diverse

Bypassarrangement

Maintainability

Environmentalcondition

Turnaroundspan

PFDavg = SIL

Licensorrecommendation

Variableto be

measuredProcesstype andcondition

Contributingfactors for

SISvoting

FIG. 3. Contributing factors in SIS designs.

TABLE 1. General factors to consider in designing the SIS to achieve the desired functions

Evaluate and consider all the possible failure modes and their implications on the SIS

Design simple and robust SIS by applying proven technology and a well-proven track record in similar operating profi les and physical environments

Keep PFDavg value of each SIF superior or greater than the targeted value

Consider fault-tolerant, redundant architecture wherever demanded by process condition, type of variable, selected fi eld instruments, SIL, etc., to get better reliability and availability

Consider all SIS subsystems as independent from other systems to avoid dependent failures

Use programmable smart-fi eld devices with higher DC to improve reliability and to trim down the CAPEX as it reduces the requirement of HFT, i.e., two SIL2 transmitters can meet the SIL3 levels in lieu of three SIL1

Select appropriate type and material for fi eld instruments, i.e., sensors, valves, etc., as they are exposed to the actual process condition such as a harsh/sour environment. Improper selection may result into corrosion, temperature and pressure extremes, freezing/plugging due to polymerization, suspended solids, measurement errors due to dry/wet-leg, erosion/deposition on valve trim, etc.

If essential, implement online/offl ine periodic function/proof test facility to reveal covert faults

Evaluate and take necessary measures to minimize CCF and CMF, especially for power supply, process tapping, fi eld instruments, etc.

Use prior-tested, error-free and modular-based application program with enough comments.

Software should be able to verify input to output thoroughly and detect all faults.

TABLE 2. Factors to consider in designing long-term stability in the SIS

Proper evaluation of sources of process demand and event initiators for each SIF

Information on process safety time (PST) and required speed of response to return to a safe state

Process description, trip value, logical relation between I/Os, output action and manual intervention like overrides/inhibits/bypasses and resetting for each SIF

Appropriate installation care against grounding, EMI/RFI, shock/vibration, electrostatic discharge, hazardous area classifi cation, lightning, and other related factors

Protection against the access of process-related parameters/settings by means of physical and logical protection, e.g., jumper, password, etc., from an unauthorized person

TABLE 3. Systems to improve effi ciency for the whole life cycle

Well-established procedures/guidelines for startup, restart and actions to achieve or maintain a safe state for the alarms/detected fault(s) by the SIS

Procedure, facility and security to force parameters without taking the SIS out of service. Facility to announce forced condition/updates to the operator

Proper guidelines/procedures for management of changes (MOC)

Application of sequence of events recorder, alarm system and communication of SISs with other control systems

Availability of critical spares and/or service contracts to minimize the MTTR; generally, eight hours are considered as repair time for a detected failure


Safety

• 1oo1, 1oo2 or 1oo3 architecture may provide better safe-ty, but it increases the chance of spurious trips due to mal-functions of any subsystem.

• Whereas, 2oo2 or 3oo3 architecture may pro-vide better availability, but it increases chances of dangerous situation such as any subsystem that does not respond to the demand due to ab-normal process condition.

One can say that the listed architectures are meet-ing all criteria stated in the standard. However, they are almost at two extremes—the highest safety and highest availability levels.

Other factors. Apart from the listed criteria, other factors such as configuration, licensor’s recommen-dations, process type, process conditions, variables to be measured, past failure records, types of field in-struments, diversity demand, installation hookup, se-lected technology, environment, competency level for operation, security, maintainability, bypasses arrangement and electromagnetic interference (EMI)/radio-frequency interfer-ence (RFI), are also significant factors to consider while deriv-ing the voting for the system architecture. When considering all such aspects, the total SIS design is somewhat that “the whole is more than the sum of its parts.”

It should not be pursued that SIL3 means 2oo3 voting or that only this voting can provide an excellent reliability to the safety requirement, although 1oo2D architecture with quadrant processors configuration can also provide almost equal reliabil-ity and HFT to balance the criteria of optimum design for the major applications. Consequently, one channel from the field device to the system hardware can be saved by using two chan-nels with improved diagnostic features in 1oo2D architecture to achieve the same SIL, which was only possible by 2oo3 in earlier days. 2oo3D can be configured for two HFT failures, but it is reserved for special applications.

In conjunction with the progression of the latest technology, attention is equally being paid to the capability of intelligent software, together with the robustness of the hardware. This has improved the total reliability of the devices through embedded software intelligence. The latest smart microprocessor-based devices are capable of identifying detectable problems, an-nouncing them, and taking corrective action via DC.

Detected failures are revealed by online diagnostics, where-as undetected failures are only revealed during periodic prooftesting—and still a few remain undetected. Dangerous unde-tected (λdu) failures are the most vulnerable. Smart program-mable devices with high DC are used to lower the value of λdu. This has improved SFF and reduced the requirements of HFT.

Therefore, “good” is not just “enough” as both architectures are having similar decisive factors. Although, to accomplish 2oo3 voting with 1oo2D configuration to meet specific process conditions, the appropriate software algorithm of applicate pro-gram can be used to connect three separate field instruments to three different input cards installed in different racks. This will reduce capital and operating costs.

Effective factors to design an SIS. The general factors to consider when designing an SIS are listed in TABLE 1. In most

cases, due to unavailability of important data/information/his-tory, the safety system is designed with a positive margin and added hardware to meet the unexpected events that may turn

it into an oversized design. Whereas overlooking standards’ clauses, efforts to reduce the capital cost, ignoring the imposed restrictions/safety guidelines on the selected architecture, ab-sence of authenticated data, improper selection of sensing or final elements, ignorance of process and human factor, etc., may lead to an undersize system design.

Other measures for SIS life cycle design. The guidelines to help design engineers to select systems to provide long-term sta-bility are summarized in TABLE 2. TABLE 3 lists measures to operate and maintain the system efficiently through its whole life cycle.

Thus, “the optimum” is the best design. Excess hardware or oversized design can cause problems related to safety, complex-ity, installation cost, maintenance, etc. Likewise, less hardware or undersized design invites problems such as reduced reliability, spurious trips and profit loss. Unless process demands, avoid us-ing additional hardware and software to achieve required safety functions and integrity levels. Apart from standards’ require-ments, the selection of architectures and field devices are exclu-sively reliant on process conditions and applications. Therefore, SIS subsystems should be sufficiently robust with proven use for the specific process to do the desired safety functions through-out its life cycle.

BIBLIOGRAPHYIEC 6i508 Functional safety of electrical/electronic/programmable electronic safety-

related systems.IEC 61511 Functional safety—Safety instrumented systems for the process industry

sector.Goble, W. and H. Cheddie, Safety Instrumented System Verification.Riess, C., presentation on Siemens Safety System Seminar, TUV SUD, Munich,

Germany.Exida, CFSP/CFSE TUV certification course.

RAJESHKUMAR MODI is an electronics and communication engineer and has over 29 years of experience in the design, engineering, maintenance and construction of instrumentation and control systems for various industries including chemical, petrochemical, oil and gas and fertilizer plants/projects with client and EPC based organizations. At present, he is working as a discipline manager—instrumentation in EPC organization-UAE.

He holds TÜV-FSE and is TÜV certified as a functional safety engineer. He is a chartered engineer. Mr. Modi has authored technical papers on SIS in technical publications and international symposium.

In designing process safety systems, “more” is

not necessarily better. Advanced software and

hardware developments have created a mindset

to over-install with the intent to prevent or

to mitigate the risk of failure and accidents

in hydrocarbon processing facilities. Better

balanced safety and instrumentation designs

address both safety and operational needs.

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the newest information platforms from Gulf Publishing Company, publisher of Hydrocarbon Processing and World Oil. Gas Processing covers the latest in process technologies, equipment, operations and maintenance, and environment and regulations pertaining to Natural Gas Liquids (NGLs), Liquefi ed Natural Gas (LNG), Gas-to-Liquids (GTLs) and Liquefi ed Petroleum Gas (LPG). GasProcessingNews.com provides breaking news, market insight, in-depth articles covering the latest developments and advancements in the gas processing industry, project data and more.

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Refining DevelopmentsA. W. SLOLEY, CH2M HILL, Bellingham, Washington

Mitigate fouling in crude unit overhead—Part 3

CASE STUDYThe basis for this case study is shown in FIG. 18; it is a crude

unit with overhead heat integration. This is a one-drum over-head system with heat integration and no water wash. In an at-tempt to avoid corrosion, the unit configuration takes diesel through heavy naphtha as a single overhead product. The oper-ating conditions are for a mid-run on 21.6°API (0.9241) mixed-crude blend (FIG. 18).

The unit was originally constructed as a light-crude topping unit (atmospheric section only). Later additions added a vacuum column and a preflash column. The unit was expanded at the same time the vacuum column was added. All the additional preheat available from the vacuum column was used in a parallel crude preheat train. Train 1 refers to the preheat driven by atmospheric tower heat. Train 2 refers to the preheat driven by vacuum tower heat. When adding the atmospheric preflash section, the only preheat added was in using naphtha product to preheat the crude in Train 1. Due to the modification history, the heat-exchanger

layouts in the atmospheric crude overhead-to-crude exchangers are not symmetrical. TABLE 1 summarizes the exchanger areas in the overall unit. Only Train 1 exchanger areas are shown in detail.

The base operation has an overhead temperature of 587°F (308°C). This provides ample driving force for crude heating. The crude preheat from the overhead is split between the cold train (upstream of the desalters) and the hot train (downstream of the desalters). Few atmospheric tower overheads provide heat to the hot train.

The hot-train exchangers do not have significant operating problems. The NH3 concentrations are low, and solid salt depos-its do not form. In contrast, the cold-train overhead-crude ex-changers suffer from severe corrosion and fouling. The unit has been shut down due to overhead leaks.

Adding a water wash. In addition to chemical treatment, a water wash will be added to control overhead corrosion and fouling. Adding water wash requires, at a minimum, water-wash

212438

224398

701 574 479 229

E113(pf)

E112(ht)

E103AB(ct)

E503

587

E110AB (ct)

300 453587

231226Water Water

361325

252

Atm OVHD (T101) 479

481439

449

410574285381 425

445

E110AB

E212AB

Asphalt(P203AB)E213

E211

507

504

520

524

701

574

513418 662

E113

AGO prod+PA (P102AB)

HVGO(P102AB)

E112

E111AB

E111AB (ht)

192

179

166

265

E103AB 472

172

E503

224

94

212212

E501

50E110AB (ct)E102

E505(ct)

Crude

Naphtha prodE111AB

(ht)

DesalterD101

Desaltertoo cold

drops 24°FNew

Train 1 cold

Train 1 hot

Train 2

Preflashpreheat train

Vacuum towerheat recovery

E100AB (ct)

E101AB (ct)Severe corrosion

and foulingE502AB

CW E50112090Offgas to flare

D102

212

P104ABP101AB

E213513662

P203AB

P103AB

SteamQuench

Vacuumheater

Vacuumheater

Crudeheater

E212AB(pf)

BFW Asphalt

E214

E506370 300

Steam

Wash waterNew

To water treatingDistillate productCold AGO product

AGOPA

P102AB

Hot AGO product

Atmosphericcrude tower

T101Atmos preflashNo heat recovery

FIG. 18. Water wash added to crude unit—desalter is too cold.


Refining Developments

438 380

398 347

701 574 479 229

E113(pf)

E112(ht)

E103AB(ct)

E503

587

E110AB (ct)

321 462587

232227Water Water

380347

276

Atm OVHD (T101) 479

488439

449

410574308398 438

454

E110AB

E212AB

Asphalt(P203AB)E213

E211

507

504

520

524

496

574

513418 662

E113


HVGO(P102AB)

E112

E111AB

E111AB (ht)

229

209

209

292

E103AB

Desalter

479

209

E503

193

94

193193

E501

50E110AB (ct)

E101C

E101CE102

E505(ct)

Crude

Naphtha prodE101AB

(ht)

D101NewNew

NewLarge arearequired

Train 1 cold

Train 1 hot

Train 2



E100AB (ct)

E101AB (ct) E101C(ct)

E100C(ct)

E502ABCW E50112090Offgas to flare

D102

193

193

193232

227

P104ABP101AB

E213513662

P203ABVRC

P103AB

SteamQuench

Vacuumheater

Vacuumheater

Crudeheater

E212AB(pf)

BFW Asphalt

E214

E506370 300

Steam

Wash waterTo water treatingDistillate productCold AGO product

AGOPA

P102AB

Hot AGO product



FIG. 19. Brute-force configuration; more condenser area is added. Drawback is that larger footprint is required for more exchangers.

212232427

224226394

701 574 473 270 177

E113(pf)

E112(ht)

New(ct)

E103AB(ct)

E503

587

E110AB (ct)

304 455587

232226Water Water

365329

256

Atm OVHD (T101) 473

482440

451

410574289384 427

447

E110AB

E212AB

Asphalt(P203AB)E213

E211

507

504

520

524

701

574

513418 662

E113


HVGO(P102AB)

E112

E111AB

E111AB (ht)

177

179270

270

166

E103AB

172

E503

224

94

212212

E501

50E110AB (ct)E102

E505(ct)

Crude

Naphtha prodE111AB

(ht)

D101Desaltertoo cold

drops 20°F

DesalterNew New

New

Train 1 cold

Train 1 hot

Train 2



E100AB (ct)

E101AB (ct)E502AB


D102

212

P104ABP101AB

E213513662

P203AB

P103AB

SteamQuench

Vacuumheater

Vacuumheater

Crudeheater

E212AB(pf)

BFW Asphalt

E214

E506370 300

Steam


AGOPA

P102AB

Hot AGOproduct



FIG. 20. Improved heat integration with injection water system—insufficient benefits achieved.



TABLE 1. Exchanger areas

Name Hot Cold Exchanger area, ft2 Service Area, ft2

Base

Train 1 cold

E102 Naphtha product Crude 563

E100AB Crude overhead Crude 4,480

E101AB Crude overhead Crude 4,597

E103AB AGO PA Crude 5,428

Subtotal Crude overhead Crude 9,077

Train 1 hot

E110B Crude overhead Crude 2,488

E110A Crude overhead Crude 1,773

E111B Crude overhead Crude 2,488

E111A Crude overhead Crude 1,710

Subtotal Crude overhead Crude 8,459

E112 AGO PA Crude 999

Summary

Train 1 cold 15,068

Train 1 hot 9,458

Train 2 cold 9,376

Train 2 hot 7,944

Prefl ash 8,086

Steam generation 8,702

Total 58,334

Brute-force area

E100AB removed Crude overhead Crude –4,480

E101AB removed Crude overhead Crude –4,597

E100ABC added Crude overhead Crude 15,199 to 17,537

E101ABC added Crude overhead Crude 15, 199 to 17,537

Total removed –9,071

Total added 30,398 to 35,074

AGO added

New AGO PA Crude 2,751

Steam heater

New Steam Crude 2,732

Asphalt rundown

New Asphalt Crude 6,086

pumps, a new overhead drum and injection piping. The total temperature to preflash column drops by 4°F (2°C). While not a major problem, this will require a modest investment in the atmospheric preflash as well. Some overhead duty shifted from the heat-integration exchangers into the air fin (E501) and cooling water (E502) exchangers.

Most important is the Train 1 desalter temperature. It drops from 276°F (136°C) to 252°F (122°C). For a heavy-crude feed, the 276°F (136°C) is already marginal. Even higher temperatures would be preferred. The unit’s desired operating point is 290°F (143°C). The immediate response to

resolve the desalter issue was to move half of the exchanger services E110 and E111 in front of the desalter. This achieves the desired desalter temperature, and maintains an average crude temperature of 292°F (144°C) between the exchangers.

The difficulty is that the temperatures reported are for mid-run, fouled conditions on a specific crude. Start-of-run (SOR) and end-of-run (EOR) present problems as well. At SOR, the duty has to be shifted further back in the train. At EOR, the duty must be shifted further forward in the train. Just moving the exchangers does not accommodate the oper-ating needs for the entire run.



212232427

224226394

701 574 479 193

E113(pf)

E112(ht)

E103AB(ct)

E503

587

E110AB (ct)

321 462587

232226Water Water

380348

256

Atm OVHD (T101) 479

488443

458

410574289398 438

454

E110AB

E212AB

Asphalt(P203AB)E213

E211

507

504

520

524

701

496

574

513418 662

E113


HVGO(P102AB)

E112

E111AB

E111AB (ht)

193268

179

290

166

E103AB

172

E503

225

94

212212

E501

50E110AB (ct)E102

E505(ct)

Crude

Naphtha prodE111AB

(ht)


drops 20°F

DesalterNew New

New

Steam

Train 1 cold

Train 1 hot

Train 2



E100AB (ct)

E101AB (ct)E502AB


D102

212

P104ABP101AB

E213513662

P203AB

P103AB

SteamQuench

VRC

Vacuumheater

Vacuumheater

Crudeheater

E212AB(pf)

BFW Asphalt

E214

E506370 300

Steam


AGOPA

P102AB

Hot AGOproduct



FIG. 21. Steam-heating configuration.

212231438 380

224226398 348

701 574 479 192

E113(pf)

E112(ht)

E103AB(ct)

E503

587

E110AB (ct)

321 462587

231226Water Water

380348

256

Atm OVHD (T101) 479

488

443

Quench

458

410574308398 438

454

E110AB

E212ABE213

Asphalt(P203AB)

E211

507

504

520

524

701

496

574

513418 662

E113


HVGO(P102AB)

E112

E111AB

E111AB (ht)

193266

179

292302E506

370

166

E103AB

172

E503

224

94

212212

E501

50E110AB (ct)E102

E505(ct)

Crude

Naphtha prodE111AB

(ht)


drops 20°F

DesalterNew New

New

New

Train 1 cold

Train 1 hot

Train 2



E100AB (ct)

E101AB (ct)E502AB


D102

212

P104ABP101AB

E213513662

P203AB

P103AB

SteamQuench

VRC

Vacuumheater

Vacuumheater

Crudeheater

Steamgen

E212AB(pf)

BFW

Asphalt

E214

E506

370

302300

Steam


AGOPA

P102AB

Hot AGOproduct


T101

AtmospreflashNo heatrecovery

FIG. 22. Improved heat integration with process modifications with asphalt rundown applied—final configuration.



Piping up the exchangers E110B and E111A to swing be-tween upstream and downstream of the desalters was consid-ered as a Base Case. The exchangers could be moved, either together or one at a time. If economically justified, other alter-nates would be accepted.

Brute force. Potentially a brute-force approach of adding area to the existing E100AB and E101AB services could solve the corrosion problem. FIG. 19 shows the performance with new shells. Six new shells (E100A-C and E101A-C) would be required. They could fit in the structure with enough modifi-cations. However, significant structural and foundation work would be required.

The existing E100AB and E101AB exchangers must be re-moved to provide space. The removed area is 9,071 ft2. The new exchangers have 30,398 ft2 to 35,074 ft2 of area. The varia-tion depends upon the allowances for fouling, EOR vs. SOR, and variation in crude types to be considered. Brute force re-quires more equipment, and it carries significant installation costs. This approach is not feasible.

Improved heat integration—Process. Improving the heat integration from the process streams requires finding a stream with the right temperature levels. The present unit configu-ration allows the crude column to run at reduced rates with out-of-service vacuum column. Keeping this configuration re-quires using only the atmospheric column heat in Train 1. The only significant stream available with the right temperature level is the atmospheric GO (AGO) PA.

Adding a new exchanger on the AGO PA raises the desalter temperature by 4°F (2.2°C). Even a large exchanger can only do so much. The total cost for the duty gained is much lower than for the overhead. The new exchanger can be placed at grade with minimum piping modifications. The new exchang-er will never reach the objective of getting the desalter to a minimum of 276°F (136°C).

Improved heat integration—Desalter water. The only other heat source within the atmospheric unit is improved heat recovery from the desalter dilution water. FIG. 20 shows this operating condition. Details are not shown. The benefit is roughly the same as for improved AGO heat recovery, but at a higher cost. The exchanger requires more expensive metal-lurgy due to corrosion problems.

Steam heating. Another brute-force approach uses steam to heat the crude upstream of the desalter. Many units have taken this approach. FIG. 21 shows the result of adding a steam heater. Within the constraints of the steam pressure and exchanger area, any desired temperature can be achieved. Desalter op-erating temperature reaches the desired minimum 276°F (136°C). The exchanger area required is 2,732 ft2.

This exchanger will meet all process requirements at a rea-sonable cost. The refinery has excess steam, so energy costs are insignificant. A local exchanger pair, E213–E214, can generate steam within the crude unit. This is a reasonable so-lution. The difficulty with this proposal is from the refinery steam system. The steam provided by E213–E214 meets the demands for local users. The total refinery system does not

have sufficient capacity to supply all users. Therefore, this op-tion was discarded.

Asphalt heating. At this point, the refinery needed to accept the shifting exchanger configuration, or to relax other con-straints. The relaxed constraint was keeping the atmospheric heat integration completely separate from the vacuum heat. FIG. 22 shows using the asphalt production (vacuum-reduced crude) to storage to provide heat to the desalter. The duty is a nearly perfect match. The asphalt product is split between di-rect feed to other units and net product to storage. Review of heat demand vs. product rate for a specific operation showed that, 96% of the time, sufficient asphalt would be available. While the exchanger surface area required was higher than the steam heater (TABLE 1), the asphalt heat recovery main-tained operating flexibility and offered a reasonable energy recovery incentive.

Overview. Crude units commonly use atmospheric tower overhead to preheat crude. These overhead systems have sig-nificant maintenance costs and operating problems. One of the most effective ways to reduce corrosion and fouling prob-lems is to use an overhead water wash. Using the water wash drops overhead temperatures, reducing the benefit of the ex-changes for crude preheat. New units should avoid overhead heat integration.

However, modifying existing units is very expensive. Opti-mizing chemical use, operating conditions, material upgrades and configuration changes makes the best of the existing asset. The major issue covered was using water wash. General fac-tors to be considered with water include product splits, over-head drum systems, and the location of the first point of water condensation. Different water-wash programs (continuous vs. intermittent) and configurations are possible. Choices will de-pend upon the unit and the plant.

End of series. Part 1, September 2013 and Part 2, November 2013.

ACKNOWLEDGMENTThis is an updated and revised version from an earlier presentation at the

AICHE Spring National Meeting, April 28–May 2, 2013, San Antonio, Texas.

NOTES A Imperial and metric units are listed. Metric conversions are not exact due to

rounding off of significant figures. Where the differences may create confusion, the Imperial units (°F, etc.) should be considered as taking priority.

B In figures, ct = cold train, duty recovery upstream of the crude unit desalter. C In figures, ht = hot train, duty recovery downstream of the crude unit desalter.

LITERATURE CITED 9 NACE publication 34101, “Refinery Injection and Process Mixing Points.”

ANDREW W. SLOLEY is a principal process engineer at CH2M Hill. He has worked in process technology development and unit revamps at Exxon, Glitsch and consulting firms. His background includes major work on refinery black oil units including crude, vacuum, FCC, hydrocracking, delayed coking and visbreaking as well as light-end units. His focus areas are distillation, product recovery, and heat-integration. Mr. Sloley has authored over

200 papers on these areas. He is a graduate of the University of Tulsa and is a registered professional engineer in the State of Texas.


D. L. N. CYPRIANO, G. B. COSTA and

M. J. NORONHA, Petrobras, Rio de Janeiro-RJ, Brazil

Safety/Loss Prevention

Consider process-based failure analysis

methods for piping and equipment

Avoiding incident (or accident) recurrences at industrial systems is a long-standing problem, and it involves process safety strategies (PSSs). Incurring zero incidents is the ulti-mate goal for any structured failure analysis. When applied to pipes and equipment, this investigation usually involves studying the damage mechanisms. Sometimes it requires deep and complex laboratory testing. Often, it is just based on team experience, visual inspection, design, codes, and process and maintenance information.

However, the physical approach to failure analysis, which identifies the type of corrosion, metallurgical alteration or mechanical damage, is not conclusive or sufficient enough to avoid future failures. A practical method to transform all detected process anomalies into a continuous reliability im-provement—based on the plan, do, study, act (PDSA) cy-cle—is suggested.

A case study involving a boiler feedwater (BFW) pipe is discussed. Some leaks observed in this pipe were attributed to thinning by impingement corrosion, caused by an inadequate inspection plan, a deficient process parameters study and low-quality maintenance procedures. As a consequence of this multifunctional analysis, an effective action plan was devel-oped. Statistical data for the last three years shows an increas-ing trend of anomalies recorded and treated, coinciding with a decrease in hydrocarbon production losses, during shutdowns or slowdowns, caused by pipes or static equipment failures.

BACKGROUNDFailure analysis represents an important source of continu-

ous learning for any organization—from a little incident at home, with low consequences, to a major catastrophe of an industrial facility. To transform these undesirable events into process improvements, the study should apply basic concepts of reliability, such as failure mode and effects, fault-tree (FT) methods, flowcharts, applicable standards and/or historical statistical data to quality control. Additionally, this should involve deep knowledge of mapped processes and associated tasks, design and operating details of the involved equipment and system, critical process parameters, equipment integrity, damage mechanisms that contribute to failure modes, appli-cable regulations, and a direct relationship to some structured method benchmarking for continuous improvement.

Classes of root causes. There are three general classes of failure causes or roots—physical, human and latent roots.1 Un-til the investigators can understand each of these classes and their inevitable interaction, they will not be able to truly under-stand how and why the failure occurred, and they will not have the tools to prevent another event. At present, literature pres-ents many important studies about metal failure analysis. Many articles and books are focused on understanding the specific damage mechanisms. A case study of failure analysis shows how to begin the investigation with the physical phenomenon approach. Further, a method is proposed to transform process management anomalies, which actually lead to failure, into a continuous reliability improvement program, based on the PDSA cycle introduced by Deming.2

APPLYING PDSA CYCLE TO FAILURE ANALYSISIn general, equipment failures are caused by anomalies in

the integrity management process. These processes occur at different stages of industrial development, including basic de-sign, project detailing, mounting, efficient operation according to the procedural and parameter ranges, periodic inspections and high-quality maintenance.

A process is defined as a set of actions ordered and integrated for a particular productive goal, which will generate products, services and/or information.3 Processes are results of systems in action, represented by flows of activities or events. Then, each company department has to conduct, and periodically re-view, a mapping of its processes, and order the planning, imple-mentation and study for the critical analysis. These processes can be divided into two groups: 1) processes that support dis-cipline and operational performance of the company, the way it was planned and designed, and 2) processes that provide team development through the technological frontier references.

As shown in FIG. 1, the word “study” in the PDSA cycle refers to the building of new knowledge.2, 4 When this is ap-plied to research and development, or to advanced process improvement, new technologies are generated or a change in procedures and standards is proposed. From the team dis-coveries, new competencies, abilities and/or qualifications are developed. Conversely, when applied to failure analysis, this will give directions for developing effective action plans. When a failure occurs by a series of typical operational events



that interact with each other (for example, incorrect operating procedures that differ from design conditions, along with in-complete periodic inspection and low-quality maintenance), attention should be given to processes that underpin discipline and company performance at the operational level. Then, the failure analysis should consider some basic questions, but it is not restricted by them. Example questions are:

• What are the possible failure modes and effects for the equipment/system?

• What are the damage mechanisms observed at the failed component/equipment?

• Which are the mapped processes for the company safety management?

• Were these processes unfolded by a sequence of tasks to its operationalization?

• Which are the standards and/or procedures that orient these tasks?

• Did the planning of these tasks consider the applicable procedures/checklists?

• Which are the tasks and processes that presented some anomalies?

• Why did these anomalies occur?Any failure analysis involves a multifunctional group of

specialists, all of them with the same goals, based on each department’s mapped processes. In these moments, coopera-tion, not competition, is vital for a successful investigation. In-stead of looking for culprits or other department (“not mine”) fragilities, there should be cooperation to solve problems of common interest.

As pointed out by Deming, cooperation for process im-provement will be greater innovation, applied science, tech-nology, expansion of market, greater service, and material re-ward for everyone.2 It is a high probability that those who were responsible for the mistakes are the same group that will enact the solutions, not repeat similar anomalies in the future.

Improving quality. Literature presents many tools for im-proving quality. It is mandatory that industrial designs contain some important reports and definitions based on process haz-ard analysis (PHA), many of them arising from quality con-trol concepts. Even during a long reliable operating time, these concepts can be applicable for improvement, as a search for all possible failure causes, such as what is done with failure mode and effect analysis (FMEA). The main objective of FMEA is to identify potential failure modes, evaluate the causes and ef-fects of the different component failure modes, and determine what could eliminate or reduce the chance of failure.5 For a predictive or corrective approach, FT methods provide suit-able directions to team brainstorming and final conclusions. The question “why” is repeated, until the team reaches the roots of the issues, and, only then, the resultant study can gen-erate effective and in-depth action plans.

PROPOSED METHOD FOR FAILURE ANALYSISThe first approach for a failure analysis is focused on physi-

cal mechanisms. We can divide the equipment or pipe damage mechanisms into three groups: corrosion, metallurgical altera-tion and mechanical damages. This is the starting point. Re-gardless of damage type, failure analysis is a multidisciplinary

activity. A single analyst may not be fully acquainted with a range of vital disciplines, such as metallurgy, materials science, structural mechanics, corrosion engineering, propulsion en-gineering and aerodynamics. Failure analysis methodology should comprise some or all of these related items:6

1. Background information 2. Location of the failed component 3. Specimen collection 4. Preliminary examination 5. Microscopic examination 6. Chemical analysis 7. Mechanical properties 8. Nondestructive evaluation 9. Simulation studies 10. Analysis of data 11. Preparation of the report.Further, mapped processes and associated tasks have to be

visited, according to the possible effects of the incident, look-ing for all the points where some stage of planning or imple-mentation failed. The main activities related to equipment integrity management are: project engineering, operation, process engineering, inspection, maintenance and industrial safety. Then, all of the effort is applied to studying the pro-cesses, standards and procedures that orient these employees’ tasks. It is important that each department has previously done a process mapping. These maps represent essential protection layers for any failure. They form a basis for their planning ac-tivities and, consequently, let the company meet its unified aims. This approach is important as a link to concepts applied on a layer of protection analysis (LOPA), a semi-quantitative methodology that can be used to identify safeguards that meet the independent protection layers (IPLs). Some cited exam-ples of IPLs are:7

1. Standard operating procedures 2. Basic process control systems 3. Alarms (defined operator response) 4. Safety instrumented systems (SISs) 5. Pressure relief devices

PDSA–Phases to failure analysis

ActPlan

Study Do

FIG. 1. PDSA cycle: a) build new knowledge, and b) define phases to failure analysis.4

Decision-making(Logic solver, relay,mechanical device,

human)

Sensor(Instrument, mechanical,

human)

Sensor(Control element logic

solver, relay, mechanicaldevice, human)

FIG. 2. Simple model of a protective layer.8



6. Blast walls and dikes 7. Fire and gas systems 8. Deluge systems.Protection layers generally include a sensor (or a means of

detection), decision making, and a way to take action to deflect the undesired consequence, as shown in FIG. 2.8

This study will not deepen this specific theme, but the hu-man factor will always be the biggest concern for process safety managers who work to train, develop and evaluate their teams, while focused on achieving, in a balanced manner, the interests of the stakeholders. Then, the company work method directs decisions in all levels, from the operational to strategic ones, ac-companied by ethics and other corporative principles. This is oriented by a structured, unified and sustainable process man-agement. This will be the basis for a management system that is capable of analyzing all detected process anomalies, in any com-pany department, for any real or potential consequence level.

The proposed methods for failure analysis unify these con-cepts in a logical sequence, based on stage “A” of the PDSA

cycle, which is applied for team investigation studies, and it is recommended to every discontinuity, defect, incident (poten-tial) or real failure, as shown in FIG. 3.

CASE STUDY—BACKGROUND INFORMATION AND FIELD DATA

A BFW pipe presented some failures, whose analysis will illustrate the method described earlier. Water leaks were de-tected in two regions, both positioned at curves, as shown in FIG. 4. The main characteristics are:

• Material: Carbon steel (curves: API 5L Gr.B; pipe: ASTM A 284 Gr.WPB)

• Diameter: 2 in.• Operating pressure: 5.9 MPa• Temperature: 120°C.This BFW pipe had been in operation since the 1970s and

in service for nearly 40 years. The pipe transported water, which corresponds to the lowest risk classification. More im-portantly, this pipe is a critical source for the refinery’s util-ity systems. External visual inspection led to the conclusion that the first leakage occurred at the third curve of the pipe loop, the biggest hole, followed by the second one, at the sixth curve, as shown in FIG. 4. Initially, it would be expected to be a corrosion-erosion process on the curves, especially due to impurities found in the water.

For example, some remaining resin from the water polish-ing process could have been present. This fact was confirmed by historical inspection data of the ion-exchange drums, when some resin losses, caused by mounting problems on an internal distributor, were reported. However, the holes were not detect-ed in the outer radius of both curves, even where local thinning due to corrosion-erosion was observed. FIG. 4b shows the pipe surface affected by this damage mechanism, with shallow shafts at flux direction, justified by intermittent removal of the protec-tion film, imposed by the impacting particles.

For the operating temperature of 120°C, only at low pres-sure (< .1 MPa) would it be expected to be a biphasic flow—water/steam. But the operating pressure was 5.9 MPa, much higher than that. Even in curves, where turbulence flow was found, no vaporization was expected under normal operat-ing conditions. However, many transient conditions occurred during the service life of this pipe, such as planned or un-planned shutdowns, when a biphasic flow occurred.

The investigation led to a detailed visual inspection of the internal surface of the failed curves. FIG. 5 shows the pitting as-pect of the damaged metal surface, where the average diameter of the corroded region was greater than, or comparable to, the depth. This morphology, together with background informa-tion and field data, justified the conclusion that cavitation had occurred. This damage mechanism occurred due to a near-wall gas bubble collapse in a liquid-vapor phase.9 It was concluded that, over the 40 years of this pipe’s operating life, transients induced the biphasic flux, water-vapor, as many times as neces-sary to the internal localized thinning process observed.

Operating data reported at least three other leakage incidents with this 2-in. pipe, whose length is about 700 m. These holes were always observed in curves, which were promptly replaced. No detailed failure analysis for these incidents was found. The leak/repair events appeared after the year 2000, approximately

Recommendations(Action plan)Fault-tree analysis (FTA)

(“Why” questions)Process analysis andimprovement(Tasks related to failure)Data analysis

(Damage mechanism)

Background/information field data

FIG. 3. Method/sequence for a failure investigation study.

FIG. 4. Schematic drawing of the BFW pipe loop, where two failures occurred: a) external detail of the leak at the bottom of the third curve of the loop; b) details of failure at the sixth curve of the loop, seen from the inner side; and c) internal detail of failure at the third curve.



30 years after the system operation started. No thickness mea-surement had been done. Even the straight sections suffered with impingement corrosion processes, especially near curves. However, such processes could not be detected before, because a structured failure analysis had not been conducted. Then, re-ports about this pipe damage mechanism were insufficient to prevent repeat failures.

Data analysis—Physical mechanism. It is observed that all previous information obtained by the analysis team led to a con-clusion about the physical characteristics of these pipe failures. The visual inspection was sufficient to understand the involved damage mechanism, because a previous study on operating conditions and historical data was done. Then, it was not nec-essary to do any laboratory analysis to study the metal failure. Any inspection team must consider that all the incidents, or ac-cidents, generated by equipment or pipes have to be studied. These exercises should be conducted to:

• Understand and report the damage mechanisms• Define disposal actions, so that the system will be able

to return to the normal operational conditions• Define corrective actions, so that the system will not

fail again• Set comprehensive actions, so that other similar systems

will not fail either.In this event, the failures were caused by impingement

corrosion, during transients of temperature and/or pressure, which allowed formation of a biphasic flux water-vapor into the pipe. The damage was intensified by the interaction with erosion, caused by impurities present in the water inside the pipe—resin from the water polishing process.

Process analysis and improvement. A simplified descrip-tion of the processes comprising a safety and environmental management system (SEMS) is shown in FIG. 6. These pro-cesses must be clearly unfolded, with active participation of stakeholders, by a sequence of tasks to its operationalization. In the processes description, the responsible team for each set of tasks is identified. Actually, there are many other tasks with this aim, but they are not within the scope of this article.

For this case study, the project engineering activity was not the focus. First, the pipe has been 100% available for 30 years since operation started, that is, much longer than the 20 years defined at the project phase, based on the predicted thickness for corrosion. Moreover, the conditions were not expecting a biphasic flux for the operating condition of the system.

Operation and process engineering teams had to visit their internal processes, looking for parameters and tolerance ranges controlled during normal operating conditions, and different ones for transients. During the investigation, it was found that the residual percentage of O2 (O2%) at BFW was not controlled. Modification of the corrosive medium, by reducing O2%, is one of the most important tasks for reducing impingement corro-sion. Only good control of the process parameters can increase equipment service life, according to what it was designed.

There is a direct relationship between the historic data of process parameters and the expected thinning of equipment and pipes.10 This is valid for all corrosion processes. This knowledge will always increase with proper studies of process parameter

reports, provided that research and development are exhorted; advanced processes are faithfully improved, new technologies are generated; and the changing of procedures and standards are proposed—all of this oriented by PDSA cycles.

Inspection plays an important role in process safety, and it should act with autonomy, always based on qualified stan-dards/procedures, oriented by its mapped processes. As de-scribed earlier, all incidents (or accidents) generated by equip-ment or pipes must be studied and registered by the inspection team. This was a repeated failure, in the same pipe, with un-known damage mechanism for that type of operating condi-tion. Then, the inspection plan was not suitable for what would be an expected deterioration.

Maintenance took place on the analysis, when the investi-gation team was looking for possible causes for erosion. From the sequence of “why” questions, it was found that low-quality services, on mounting the internal distributor of ion-exchange

FIG. 5. Alveolar aspect of metal surface at the failure region (an average diameter of the corroded region greater than, or comparable to, the depth).

Projectengineering

To design andimplementnew system/equipment forstakeholderneeds.

Processengineering

To define,monitor andstudy processparameters/toleranceranges.

Operation

To operate intoparameterranges andtreat eventualanomalies.

Inspection

To performinspection plan,adherent toexpecteddamagemechanisms.

Maintenance

To manage safety and environmental systemSMES

To implementinspection-recommendedservices withassured quality.

FIG. 6. Simplified description of processes comprising an SEMS.



drums, caused inventory losses of resin. This should generate an in-depth study about maintenance management systems for quality assurance.

A SEMS is the basis of any strategic planning, implementa-tion, study and act method for a productive process. Because of the risks associated with industrial activities, every depart-ment is involved and responsible for that. However, similar to inspection, an autonomic SEMS team has to visit and contin-uously improve their mapped processes, like the releases for industrial services and strategies to combat emergencies. The control mechanisms inside organizations, by means of several accident investigations, were examined.11 The accidents ana-lyzed were considered, without exception, to be the result of one or more uncontrolled organizational processes. Addition-ally, they asserted that it is inherent to real life that not all situ-ations happening in daily operation are fully preplanned, so they lead to undesirable events. All the incidents, accidents, or any process anomaly or disruption (even before leading to a failure) can provide crucial information to strengthen protec-

tion layers. Applied to a SEMS, this concept justifies an un-flagging search for new ways to minimize risks associated to industry activities by lowering potential consequences.

Fault-tree analysis—’Why’ questions. After studying pro-cess anomalies in each involved department, added up by their interactions, a fault-tree analysis (FTA) was conducted. FIG. 7 shows a condensed FT, just to illustrate how this method led to the main failure causes. This is just a summary of possible FTs that could be developed by the team.

Recommendations—Action plan. The first objective of es-tablishing recommendations is to return the system to a secure and normal operating condition. Then, all of the related com-ponents of this analysis were substituted by new ones. The main objective for the recommendations is to avoid the same or similar system conditions to be repeated. When a process anomaly or disruption is detected, even without a failure oc-currence, recommendations are essential to ensure the safety culture. As long as these disruptions are controlled either by preventive or active methods, it is impossible for any of the disruption to escalate and to initiate a serious accident.11

Some recommendations from the failure analysis are pre-sented here. In this example, the recommendations include:

• Reclassify inspection pipe systems of BFW, steam and steam condensate of high-failure consequence, as pointed out by a FMEA

• Promote a structured study/review on inspection plans based on the expected damages, applied for equipment and pipes

• Implement inspection recommendations, according to the defined deadlines and qualified maintenance procedures

• Review procedures and implemented routines of process parameter analysis, based on the expected damages for equipment and pipes

• Audit and define corrective actions for maintenance qual-ity control, to assure the correct application of standards, procedures and checklists.

Improved reliability through integrity management. From the continuous learning of the company’s safety guide-lines, action plans and improved process management, better operational performance was observed at the refinery. Statis-tical data of hydrocarbon production losses caused by static equipment and pipes, expressed in the refinery capacity per-centage (C%), indicate a sustainable decrease of 13%, from 2008 to 2012 levels. The improvement occurred in the main processes—crude unit, fluid catalytic cracker, coker unit and hydrotreater—and corresponds to an increased availability, proportional to 3.5 days of processing in all these units. When these data are segregated for losses whose roots included in-spection processes, the decrease is around 55%. FIG. 8 shows this trend, which coincides with an increasing number of anomalies recorded and treated. Process mapping and the PDSA cycle were the basis for the development of work pro-cedures and unfolded tasks in this area. The goal has always been to look for anomalies before failures. Other management initiatives, not described here, were important for this result. Some profit will always be found when a pragmatic view of

Failure of a BFW pipe Connector “or”Legend:

Connector “and”Discarded hypothesisFailure cause

Mechanicaldamage

Corrosiondamage

Metallurgicalalteration

Thinningby externalcorrosion

Corrosion underinsulation

Inspection planinadequate for

damage mechanism

Deficient processparameters study

Impuritiesdetected on

BFW

Low-qualitymaintenanceprocedures

Impingementcorrosion

Carbonic acidcorrosion

Corrosion-erosion

Thinningby internalcorrosion

FIG. 7. Condensed FTA of case study—failure of a BFW pipe by impingement corrosion.

2008

0.11

12

Losse

s ins

pecti

on

Anom

alies

regis

tered

0.00

0.04

0.08

0.12

0.16

0

20

40

60

80

2009

0.14

21

2010

Losses–inspectionAnomalies registered

Losses and anomalies registered by inspection

0.04

69

20110.00

70

2012

0.05

70

FIG. 8. Trend of decrease in losses where roots included inspection, coincident with an increasing number of anomalies registered and treated by the inspection team.



real problems is applied, as to discussion of solutions (action plans), leading to consistent process management, stimulat-ing anomalies registration and increasing multifunctional team integration.

Action plan. Although a physical approach is present with every failure analysis, it is not common to find complete mul-tifunctional studies proving how to avoid the recurrence of the event. Industry’s goal is to operate with total safety and/or zero accidents. All technicians and engineers should be involved in a productive environment and look at any process anomaly as a reliability improvement opportunity—analyzing them by an adequate methodology, and registering the results for continu-ous learning. There are many known damage mechanisms. It is possible to identify what kind of corrosion, metallurgical al-teration or mechanical damage occurred. This analysis will not be conclusive or sufficient to avoid future failures.

Finally, recommendations should also be generated on how to return the system to a secure and normal operating condi-tion following an event. Many management and human factors, which should be part of an internal investigation, are not ad-dressed in this article and influence the decision making. The best way to avoid undesired anomalies and their consequences is to have a trained and developed team. Periodical evaluations should be conducted. The goal is to establish a forum so that employees are disciplined and cooperative, and meetings are accompanied by dialogue, feedback, ethics and other corpora-tive principles, oriented by PDSA practices. If team members or departments are not prepared and focused on avoiding new failures, then a potential anomaly will happen.

ACKNOWLEDGMENTSThe authors acknowledge Petrobras, and all the people that work there, direct or

indirectly, to sustain its successful strategies, that will keep this team to be among the largest integrated energy companies in the world and preferred by the stakeholders. The authors especially thank Alessandra S. Lopes and Hervandil M. Santanna, who provided language assistance and schematic drawing of pipe loops, respectively. They also thank Hermano C. M. Jambo, always present, as a technical consultant, teacher and friend.

LITERATURE CITED 1 Sachs, N. W., Practical Plant Failure Analysis—A Guide to Understanding Machinery

Deterioration and Improving Equipment Reliability, Boca Raton, Florida, AA Taylor & Francis Group Publication, 2007.

2 Deming, W. E., The New Economics—For Industry, Government, Education, Cambridge, MIT Press, 1994.

3 Barbará, S. O., “Process Management—Fundamentals, Techniques and Implementation Models,” Rio de Janeiro, Qualitymark Ed Ltda., 2006.

4 Langley, G. J., et al., The Improvement Guide—A Practical Approach to Enhancing Organizational Performance, San Francisco, Jossey-Bass, Wiley Imprint, 2009.

5 Liu, H. C., L. Liu and N. Liu, “Risk Evaluation Approaches in Failure Mode and Effects Analysis: A Literature Review,” Expert Systems with Applications, 2013, Vol. 40, pp. 828–838.

6 Ramachandran, V., et al., Failure Analysis of Engineering Structures—Methodology and Case Histories, Materials Park, Ohio, ASM International, 2005.

7 Summers, A. E., “Introduction to Layers of Protection Analysis,” Journal of Hazardous Materials, 2003, Vol. 104, pp. 163–168.

8 Myers, P. M., “Layer of Protection Analysis—Quantifying Human Performance in Initiating Events and Independent Protection Layers,” Journal of Loss Prevention in the Process Industries, 2013, Vol. 26, pp. 534–546

9 Schmitt, G. and M. Bakalli, “Advanced Models for Erosion Corrosion and its Mitigation,” Materials and Corrosion, February 2008, Vol. 59, pp. 181–192.

10 Cypriano, D. L. N., et al., “Improving pH control mitigates corrosion in crude units,” Hydrocarbon Processing, March 2011, pp. 49–54.

11 Sonnemansa, P. J. M. and P. M. W. Körversb, “Accidents in the Chemical Industry: Are They Foreseeable?,” Journal of Loss Prevention in the Process Industries, 2006, Vol. 19, pp. 1–12.

DANIEL CYPRIANO graduated in metallurgical engineering from Federal University of Rio de Janeiro (UFRJ), Brazil, with a PhD in metallurgical and materials engineering from COPPE/UFRJ and an MBA in business management from Getúlio Vargas Foundation, Rio de Janeiro, Brazil. He joined Petrobras in 2001, initially in the inspection team of Duque de Caxias refinery. He is the coordinator of inspection technology for Petrobras

Downstream, with large experience on inspection practices and management. Dr. Cypriano also has experience with industrial property, steel plants and training courses for inspectors and undergraduate engineering courses, in disciplines related to metallurgy and materials, inspection, reliability, strategy and failure analysis.

GILSON COSTA holds a technical degree in electrical engineering from Federal Center of Technological Education, Rio de Janeiro, Brazil. He joined Petrobras in 2002 and is a senior inspection technician for equipment and industrial installations, at Duque de Caxias refinery, specializing in corrosion control, evaluation of structural integrity and failure analysis for crude units, paraffin and lubricant plants,

hydrocracking, fluid catalytic cracking units, boilers, storage tanks and pipelines. He has 10 years of experience in the inspection area, with qualification to perform many nondestructive testing, liquid penetrant, magnetic particle, ultrasonic thickness and alternating current field measurement.

MAURICIO NORONHA graduated in metallurgical engineering from Federal University of Rio de Janeiro, Brazil, with an MS degree in metallurgical and materials engineering from COPPE/UFRJ. He joined Petrobras in 2006 and is an equipment engineer with the inspection team for the Duque de Caxias refinery, performing structural integrity analysis, corrosion and damage mechanisms control of static equipment and pipes. He

has seven years of experience in the inspection area, especially in inspection planning for paraffin and lubricant plants, hydrocracking and fluid catalytic cracking units. He developed research about the integrity of austenitic stainless steels used in the furnaces for hydrogen generation.

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Engineering Case Histories

A. SOFRONAS, CONSULTING ENGINEER

http://mechanicalengineeringhelp.com

Case 76: Simple troubleshooting analysis tips are useful

Analyzing failed parts or poor opera-tion requires the proper skills and equip-ment. Sometimes these investigations are not always very difficult. Often, trouble-shooting a failure just requires a logical ap-proach and applying some common sense.

Case History 1. In this example, as shown in FIG. 1, a lip seal was installed on a 1-in. drive that rotates at 1,000 rpm. Unfortu-nately, in this case, this seal was leaking. If you pressed on this seal’s rubber lip, it felt much harder/stiffer than a new seal. The radial crack that caused this leak was most likely a secondary failure due to the aged and brittle rubber. Plant records estimated that this seal had been installed on the engine for over 25 years, and it had never been replaced during an overhaul. A new seal was installed with no further investi-gation needed.

Case History 2. In this event, as shown in FIG. 2, the failure was a broken coupling shaft that was driving a multiple carbon-blade vacuum pump. The fractured shaft

(FIG. 2) was a special plastic material. The cone-like failure pattern was recognizable to a trained reliability professional as a torsional failure. The carbon pump vanes were worn and past their replacement life; unfortunately, the pump vanes had broken and suddenly jammed. Result: In this case, the pump shaft failure happened instanta-neously. A new pump was installed as the root cause for this failure was obvious.

Case History 3. The final example is il-lustrated in FIG. 3, and it involved a motor-pump set. This failure was encountered by the column’s author early during his career when he had little practical experience with this pump type.

A large pump used to circulate a hot fluid was vibrating excessively after sev-eral hours of operation. The author went with an experienced machinist to inves-tigate this pump. The first question the machinist asked the operator was, “Did it (the pump) vibrate when you did a cold start?” The operator said, “No.” The ma-chinist then said, “They forgot to ‘hot’ align the pump!” Now, I (the reliability engineer) understood that the machinist’s own experience was the basis for his com-ment. As for the machinist and his quick response, I am almost certain that he had made the same error himself when align-ing the pump many years earlier. When I asked him if this was so, he just smiled and would not admit to anything. We all have to learn from our failures and mistakes.

This pump was base mounted. Thus, the pump would expand as the unit tem-perature increased from pumping the higher-temperature fluids. If alignment was done on a cold unit with no thermal

corrections, the pump would vibrate due to misalignment when pumping the hot fluids or operating in the “hot” mode. A rough operation when cold and a smooth-er operation when hot would indicate that a hot alignment was probably done. This is not as much of a problem when a pump is center-mounted, since it grows evenly in both directions, and, theoretically, it would not thermally change the centerline.1

In the author’s experience, about 90% of all of the troubleshooting of machin-ery has been done via observation and repair. It is the 10% high-risk failures that required detailed troubleshooting. Deter-mining what is a high-risk event is a dif-ficult task, and it requires experience. For example, if the hardened cracked seal had blown out and sprayed oil under pressure, a fire could have developed. That event is viewed as a higher risk, much more severe failure than a slight leak. So, if this pump was on an aircraft or located in a hazardous environment, it might have been classified as a high risk, and, if it was sealing ambient water, it might have been a lower risk.

The lesson learned is that a simple di-agnosis and a quick repair should always be well thought out or reviewed by oth-ers to eliminate any other hidden failure modes.

LITERATURE CITED 1 Sofronas, A., Case Histories in Vibration Analysis

and Metal Fatigue for the Practicing Engineer, Wiley, p. 102, 2012.

TONY SOFRONAS, P.E., was worldwide lead mechanical engineer for ExxonMobil Chemicals before retiring. He now owns Engineered Products, which provides consulting and engineering seminars on machinery and pressure vessels. Dr. Sofronas has authored two engineering books

and numerous technical articles on analytical methods. Early in his career, he worked for General Electric and Bendix, and has extensive knowledge of design and failure analysis for various types of equipment.

FIG. 1. Example of a failed lip seal.

FIG. 2. Example of a failed coupling shaft.

Pump cold

Motor

Pump hotδ

FIG. 3. Block diagram of the hot pump alignment.

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