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FLUID FLOW AND ROTATING EQUIPMENT

Maintenance focus on improving performance of compressors, pumps, piping and more

LNG DEVELOPMENTS HYDROCARBONPROCESSING.COM | AUGUST 2012

Advanced engineering and design enhance project construction on a global basis

GASTECH PREVIEW Update on premier event for the international natural gas industry


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AUGUST 2012 | Volume 91 Number 8 HydrocarbonProcessing.com

38

31

8 SPECIAL REPORT: FLUID FLOW AND ROTATING EQUIPMENT

39 Modernize your compressor lube- and seal-oil systems H. P. Bloch

45 Utility piping: Why over-engineering is inefficient G. Wilkerson

51 Consider new developments for variable-speed electric motors A. Almasi

57 Improve performance monitoring of your turbomachinery

DEPARTMENTS

8 11 15 21 27 31 32

U. Bhachu and J. Francis

61 Case history: Improve refrigeration compressor performance N. Ghaisas

98 101

Brief Insight Impact Innovations Construction Construction Profile Construction Boxscore Update Marketplace Advertiser index

65 Apply new guidelines when selecting low-temperature service compressors S. Mubarak

COLUMNS

35

Reliability Consider best-of-class lubrication practices

37

Integration Strategies Reliability solutions offer unique value propositions

SAFETY, SECURITY AND THE ENVIRONMENT—SUPPLEMENT

S-69 Fire incident at Jaipur was a wakeup call S-71

H. Dutta Safety news

BONUS REPORT: LNG DEVELOPMENTS

81 Use dynamic simulation for advanced LNG plant design A. M. Fantolini, L. Pedone, L. D’Orazi, R. Prodan, A. Sood, G. Bhattad, D. Stavrakas and V. Harismiadis

102

Control Automation: The path to reliability

89 PERU LNG: Executing Peru’s largest industrial project S. Sharma, D. Hill, P. Rano, G. Humphrey and M. Mayer

SHOW PREVIEW: GASTECH

93 The premier event for the global natural gas industry B. Thinnes Cover Image: The liquefied natural gas (LNG) regasification plant Gate terminal, located in Rotterdam, The Netherlands, was named “LNG Project of the Year” by the European Gas Conference in 2011 and “Project of the Year” by the European Construction Institute in 2012. Gate terminal was managed by SENER as part of the TS LNG joint venture. SENER was in charge of the engineering, procurement, construction and startup of the facility. This regasification terminal is one of the largest LNG terminals in Europe. It has an initial throughput capacity of 12 billion m3/yr and three 180,000-m3 storage tanks. The terminal has two jetties able to simultaneously unload two ships of the Q-Max type (the world’s largest LNG carriers). The full story is on page 31. Source: Techint E&C and SENER.


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ARTICLE REPRINTS

EDITORIAL Editor Reliability/Equipment Editor Process Editor Technical Editor Online Editor Associate Editor Contributing Editor Contributing Editor Contributing Editor

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

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

Sheryl Stone Angela Bathe David Weeks Amanda McLendon-Bass Cheryl Willis

SALES MANAGER

Bill Wageneck Bill.Wageneck@GulfPub.com

ADVERTISING SALES See Sales Offices page 100.

CIRCULATION Director, Circulation

Hydrocarbon Processing is indexed by Applied Science & Technology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index.

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Hydrocarbon Processing (ISSN 0018-8190) is published monthly by Gulf Publishing Company, 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252. Copyright © 2012 by Gulf Publishing Company. All rights reserved. Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01.

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President/CEO Vice President Vice President, Production Business Finance Manager

John Royall Ron Higgins Sheryl Stone Pamela Harvey

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

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| Brief Production of oil, other liquids, to increase in US The US Energy Information Administration (EIA) recently released its 2012 annual energy outlook. The EIA projects US domestic production of petroleum and other liquids to grow by 3.1 million bpd from 2010 to 2035. Total production should grow rapidly until 2020, as production of crude oil and natural gas liquid (NGL) from tight oil formations (including shale plays) increases sharply. After 2020, total US production will grow more slowly, to 12.7 million bpd in 2035, as tight oil production levels off even with continued increases in crude oil prices. As production of other liquid fuels increases, the crude oil share of total domestic petroleum and other liquids production is expected to decline from 56% in 2010 to 47% in 2035. NGL production is slated to increase by more than 900,000 bpd, to 3 million bpd in 2035, mainly as a result of strong growth in the production of both tight oil and shale gas, which contain significant volumes of NGLs.


BILLY THINNES, TECHNICAL EDITOR / Billy.Thinnes@HydrocarbonProcessing.com

Brief

The US Environmental Protection Agency (EPA) will not revise greenhouse gas (GHG) permitting thresholds

under the Clean Air Act. The final rule affirms that new facilities with GHG emissions of at least 100,000 tpy of carbon dioxide equivalent (CO2e) must continue to obtain prevention of significant deterioration (PSD) permits. Existing facilities that emit 100,000 tpy of CO2e, and that make changes increasing their GHG emissions by at least 75,000 tpy of CO2e, must also obtain PSD permits. Facilities that must obtain a PSD permit, to include other regulated pollutants, must also address GHG emissions increases of 75,000 tpy or more of CO2e. New and existing sources with GHG emissions above 100,000 tpy of CO2e also must obtain operating permits. The GHG tailoring rule will continue to address a group of six greenhouse gases: carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons and sulfur hexafluoride. The EPA is also finalizing a provision that allows companies to set plant-wide emissions limits for GHGs, which should streamline the permitting process. GE has signed a commercial alliance agreement with Norway-based Sargas to provide a gas turbine for

one of the world’s first gas-fired plants with integrated carbon capture for enhanced oil recovery (EOR). The Sargas plant will combine a configuration of GE’s existing aeroderivative gas turbine package with Sargas’ combustion and carboncapture technology, enabling low-emissions power generation, the companies said. Sargas says its technology captures CO 2 at pressure, which requires lower capital investment costs and can be built quickly with existing or slightly modified subsystems and equipment. In combination, the new configuration of the gas turbine in the Sargas plant can capture CO2 for oil recovery with high efficiency and low parasitic load. Intergraph is teaming up with Bayer Technology Services to lobby for a standardized piping environment

in the German chemical process industry, the companies have announced. The standardized environment would include all piping disciplines, the firms said, aiming to provide consistent piping data on the basis of PAS and EN codes by using a professional management system. Such a move would ensure crucial time savings and improved safety for all partners, the companies said. Many well-known companies active in the respective industries have shown interest in the project, and some of them have already agreed to the conditions in principle, Intergraph said. “With new EN codes and improved, powerful 3D systems on the market, we feel that this agreement comes exactly at the right time,” said Gunter Mauss, vice president of Intergraph Process, Power & Marine. “By creating this level of

standardization, we are able to provide an environment that offers substantial benefits for all parties involved.” CONCAWE recently released a report on gasoline ether oxygenates (GEOs), which are added to certain fuel

formulations to improve combustion efficiency and increase octane rating. The report presents data on the production capacities and use of GEOs in 30 European countries. CONCAWE reveals that there are about 55 facilities with GEO production capacity in the EU, with 50% of that capacity located in Germany, France and the Netherlands. Europe’s total GEO production capacity grew from 4,108 KT in 2002 to 6,049 KT per year in 2010. The report also notes how the use of GEOs has evolved from methyl tertiary butyl ether to ethyl tertiary butyl ether in some countries. In certain markets, there is also a trend afoot to phase out GEOs almost entirely, in favor of direct ethanol blending. BP and JBF Petrochemicals have signed an agreement for licensing of BP’s latest-generation purified terephthalic

acid (PTA) technology. JBF intends to build a 1.25 milliontpy unit at the Special Economic Zone in Mangalore, India, to produce PTA, the primary feedstock for polyesters used in textiles and packaging. JBF expects the Mangalore plant to come onstream at the end of 2014. The PTA market has continued to grow at a high rate over the years, with over 80% of the demand currently in Asia (with about 50% in China alone), according to BP. “The market is now of such a scale (greater than 50 million tpy) and continuing to grow, at close to 7%, that three or four new world-scale plants per year will be needed,” said Nick Elmslie, CEO of BP’s global petrochemicals business. With China’s natural gas consumption set to almost triple over the next eight years, the Asian giant will

draw from all available sources to keep up with demand, according to a new report from the energy industry analysis firm GlobalData. According to the company’s latest research, China’s natural gas consumption was 131.7 billion cubic meters (bcm) in 2011, already a steep rise from the 2000 figure of 24.5 bcm. Consumption levels are predicted to soar even higher to reach 375 bcm by 2020, thanks to the country’s desire to increase the share of natural gas in its energy mix, the analysts said. In 2011, China consumed approximately 131.7 bcm of natural gas, although it only produced 100.9 bcm— a disparity that will only grow in the future. Accordingly, major Chinese national oil companies, such as China Petrochemical Corp. and its subsidiary, China Petroleum & Chemical Corp. (Sinopec); China National Petroleum Corp. (CNPC) and its subsidiary, PetroChina Co. Ltd. (PetroChina); and China National Offshore Oil Corp. (CNOOC), are actively involved in the partial or full acquisition of overseas assets in an attempt to guarantee long-term national gas security. Hydrocarbon Processing | AUGUST 20129


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STEPHANY ROMANOW, EDITOR / Stephany.Romanow@HydrocarbonProcessing.com

Insight

How long is an economic cycle for the HPI? As summer takes hold in the Northern Hemisphere, demand for energy in various forms increases. In looking back over the past 90 years, energy demand and pricing cycle through high and low points. In 2008, many economists commented that the global slowdown reflected the same conditions as the early 1980s. However, the waves of change continue to “roll through” due to numerous interconnected events. In this month’s Insight, economic downturns appear to follow a 10-year cycle, judging from the headlines. Closure of refining and petrochemical capacity is not a new development. Headlines regarding plant shutdowns or “mothballing” occurred more often than we typically recall. Remembering and learning from the past will support better decision-making going forward.

Headlines from Hydrocarbon Processing, August 2002: Central Asia emerging as a potential global energy supplier. This region’s energy resources are concentrated in countries surrounding the Caspian Sea. Kazakhstan and Azerbaijan together account for 92% of the region’s total oil reserves. Although Central Asia accounts for only 2% of the world’s proven resources, this region has a great potential for natural gas reserves. It will be some time before long-distance pipelines will bring Central Asia’s gas exports to China. Accordingly, Central Asia’s nearest target for energy exports will be Eastern Europe and Russia.

Workers are putting finishing touches to the new fluid catalytic cracking (FCC) unit and gas recovery facility at Gulf Oil Corp.’s Port Arthur, Texas, refinery. The M. W. Kellogg Co. designed and constructed the 70,000-bpd FCC unit. Petroleum Refiner 1951.

EU chemical industry fighting back. The European Union’s (EU’s) chemical industry is experiencing a slow recovery following a difficult year in 2001. The regional industry sees a mixed picture. Japan shows no sign of economic recovery. In the US, the chemical industry should increase in 2003. For the EU, the chemical industry should increase 2% in 2002 and 3% in 2003. The polyolefins industry will have a better year as compared to other chemicals. Oil industry and IT: Lessons learned. The US stock market has been hit by a triple whammy. The first shock was the abrupt and shocking meltdown in the technology sector. The second is the global recession, followed by the third blow, financial finagling at many firms—all reducing investor confidence in the markets. According to analysts, the tech “boom” is remarkably similar to the oil “boom and bust” from the 1970s and 1980s. Over the past two decades, enormous resources—time, money and manpower—have been absorbed by technology and “financial engineering” segments of the global economy. Fluctuating oil prices have created waves due to highly volatile business conditions. In the end, it will be a battle of business designs (or models), and there will be three major survivors— vertically integrated full-service providers, low-cost producers and specialty firms that feed the value chain.

Workers are ready to ignite a tank containing 100,000 gallons of kerosine as part of tests conducted at the Olean Refinery of SoconyVacuum Oil Co., Inc. Petroleum Refiner 1952. Hydrocarbon Processing | AUGUST 201211


Insight Headlines from Hydrocarbon Processing, August 1992: European energy outlook. Nominal crude oil prices will probably reach $32.20/bbl by 2000 and $62.70/bbl in 2010 in a report by DRI, London, UK. This report also forecasts that gasoline demand will expand slightly. DRI notes that diesel demand by freight transport and the expanding population of dieselpowered automobiles will also increase over the next 10 years. Clunker trade-in program aims to cut air pollution. The US Office of Technology Assessment (OTA) has reviewed a new program offered by the Environmental Protection Agency (EPA) to reduce air pollution and gasoline consumption. The new method focuses on paying owners of 1971 and earlier cars to “scrap” the autos for cash. A pilot program operated by Unocal in the Los Angeles, California, area was successful in removing older vehicles. However, OTA concedes that such a program should be treated as an experimental option and carefully monitored. Olefin demand to increase. Higher olefin demand will grow 5.8%/yr from 1990–2000 according to a new report by Chem Systems. On a global basis, about 41% of the alphaolefins are consumed by polymers, largely for linear-low-density polyethylene production and detergents. Global consumption of alphaolefins was 1.5 million metric tons in 1990.

Headlines from Hydrocarbon Processing, August 1982: Refinery ‘mothballing’ may have peaked. HP editors believe no more significant refining capacity in the US or Europe will be shutdown. Even with the shutdowns, US distillation capacity increased 2.5% in 1982, with 20 refinery projects adding 455,000 bpd to the distillation capacity of 18.3 million bpd, according to the API. Meanwhile, existing capacity is operating at 70% utilization rates.

Row of high-pressure compressors used at Carbide and Carbon Chemicals Co.’s South Charleston, West Virginia polyethylene plant. Petroleum Refiner, March 1955.

12AUGUST 2012 | HydrocarbonProcessing.com

Long-term outlook by economist. According to Merrill Lynch Economics Inc.’s 1982 to 1992 forecast, change is expected: • The large overhang of excess OPEC capacity, combined with non-OPEC production, will limit crude oil prices. Over the next 10 years, oil prices should only increase about 6% to 7%. • Natural gas prices are expected to be decontrolled by 1985. Wellhead prices should increase about 25% to $4.25/MMBtu. • Free-world petroleum demand is projected to increase 1%/ yr, with US demand growing 0.5%/yr. • Demand for electricity will increase 2.7%/yr through 1992. Coal and nuclear energy will be used to meet future power demand.

Headlines from Hydrocarbon Processing, August 1972: Don’t use natural gas to produce electricity is the advice from the Gas Appliance Manufacturers Association. About 16% to 28% of the electricity generated in the US is provided by naturalgas fired steam boilers. With a gas shortage, the association recommends directing natural gas to higher-form applications. Coal-gas plant involves 11 HPI companies. Cities Services Gas, Peabody Coal, and Transcontinental Gas Pipe Line are among the 11 companies to participate with the Conoco Methanation Co. in constructing the world’s first commercial-scale methanation of the “coal-gas” process. Conoco will design and construct the facilities. The methanation plant will be built at the Scottish Gas Board’s Westfield coal field, and it is estimated to be operational by the summer of 1973. US LNG imports will reach 250 billion cubic feet (cf) per year by 1975, according to the Institute of Gas Technology. By 1980, LNG imports are forecast to increase to 1 trillion cf (tcf) and 1.6 tcf by 1985.

To see more headlines from 1962 to 1923, visit HydrocarbonProcessing.com.

Construction continues for the fractionating tower, crude-oil furnaces and control room at Vacuum Oil Co. Pty. Ltd.’s 1,200-bpd refinery at Altona, near Melbourne, Australia. Petroleum Refiner 1956.


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BILLY THINNES, TECHNICAL EDITOR / Billy.Thinnes@HydrocarbonProcessing.com

Impact Comparing land use impacts for petroleum and biofuels The biofuels industry claims its fuel is unfairly singled out by potential regulatory policies that focus on greenhouse gas (GHG) emissions associated with land use change. It argues that petroleum also causes land use change impacts and should be similarly judged in any such regulatory scheme. In an effort to contribute to the scientific analysis of this debate, an international research team, led by University of California–Davis research engineer Sonia Yeh, has published one of the first estimates of land use change GHG emissions from petroleum production. The team’s findings conclude that emissions released from land disturbed by certain fossil fuel extraction methods can be comparable to, or are higher than, emissions from land disturbed by farming crop-based biofuels (when measured as tons of carbon emitted per unit of land disturbed). However, when measured per unit of energy produced, the land impacts of even the most high-impact fossil fuels are a tiny fraction of those of biofuels. “We started this because of the current policy debates,” said Ms. Yeh, who acknowledged that regulators and researchers believed the land use impacts of petroleum production were minimal when compared to biofuels. She and her team, under contract with the California Air Resources Board, set out to test this belief. “It turns out that, while many researchers have looked at land use impacts of biofuels, few have looked at the land use impacts associated with oil.” The research team focused on the land use impacts of heavy crude oil extracted in California and in Alberta’s Canadian oil sands (Fig. 1). The study examined conventional extraction methods, such as drilling, which occurs in California and Alberta, and nonconventional extraction methods in Alberta. Nonconventional extraction methods include surface strip mining of the bitumen soil and in-situ re-

covery, where steam is injected into a deep well. The researchers first estimated the amount of land impacted by the different processes, and then calculated the GHG emissions from the land disturbances. To estimate the amount of land affected by conventional processes (about half of Alberta’s output is conventional), they applied a custom software program to Google Earth images of the land disturbances, such as well pads, pipelines, access roads and seismic surveys. They found that the land use impacts of conventional oil extraction methods are limited, compared to nonconventional oil sands processes. Land disturbance. To estimate the land

use impacts of oil sands processes, the study relies on the earlier findings of coauthors Sarah Jordaan and David Keith from the University of Calgary. Land disturbance for in-situ recovery includes central processing facilities and networks of seismic lines, roads, pipelines, well pads, and upstream land use disturbance for natural gas production (a key fuel used in the in-situ production process). In surface mining, a large area is cleared of all vegetation and then excavated. The total land disturbance includes a mine site, overburden storage, and “tailings” ponds, which not only cover large areas of land but are also high in chemical wastes and toxic substances. The team found that the impacts of the oil sands processes can be significant for three reasons. First, the surface mining process disturbs enormous amounts of land rich in carbon deposits. Second, only 12% of the total oil sands surface mining area in

Alberta is reported as reclaimed, which means the land impact is prolonged. Third, the use of tailings ponds makes the land unavailable for reclamation and carbon sequestration. Improved restoration practices could significantly reduce GHG emissions and, therefore, the land and GHG impact, said Ms. Yeh. Companies can reduce emissions from tailings ponds by employing strategies to facilitate sedimentation, reduce tailings size, and more quickly return the land to its natural state.

The modern world of steel

The World Steel Association recently published the 2012 edition of “World Steel in Figures.” This study provides essential facts and statistics about the global steel industry, including information on crude steel production, apparent steel use, pig iron production, the steel trade, iron ore production and trade, and scrap trade. Steel plays an important role at an oil refinery. Within a hydrocarbon processing facility, important trays, piping, tub-

FIG. 1. Oil sands operation in Athabasca, Alberta, Canada. Photo courtesy of NASA’s Earth Observatory.

TABLE 1. Major steel producing countries, million tons 2011

2010

1. China

683.9

1. China

637.4

2. Japan

107.6

2. Japan

109.6

3. US

86.4

3. US

80.5

4. India

71.3

4. India

68.3

5. Russia

68.9

5. Russia

66.9

Hydrocarbon Processing | AUGUST 201215


Impact ing, boilers, exchangers and the like are all reliant on steel. The refinery of today is especially interested in high-alloy, corrosion-resistant steels, especially stainless steels, to process crudes all across the corrosive spectrum. The World Steel Association’s study provides data to clarify where the steel is coming from that is being used in new projects like Borouge in Ruwais, UAE, and CNOOC’s refinery in Huizhou, Chi-

na. The top five steel-producing countries of 2011 can be found in Table 1, and they should not come as a surprise. China, Japan, the US, India and Russia have all been steel-producing powerhouses for some time. Table 2 provides the crucial data indicating the world’s top steel-producing companies. ArchelorMittal is by far the globe’s leader in steel, producing 97.2 million tons in 2011. The company’s next-closest com-

Lead times of 7 days available

petitor, Hebei Group, was a distant second, at 44.4 million tons produced. Providing a distillation of data that can then be used as a springboard to other economic analysis, Table 3 breaks down the top 10 countries with the highest apparent steel use per capita. Of particular interest are the high rankings achieved by the Czech Republic (3rd) and BelgiumLuxembourg (10th). When parsing these statistics, be aware that apparent steel use comprises the deliveries of steel to the marketplace from the domestic steel producers together with imports. This differs from real steel use, which takes into account steel delivered to or drawn from inventories. For more information on this study, visit www.worldsteel.org.

EU chemicals sector output down in 2011

European Union (EU) chemicals production recorded a 1.9% decrease in the first four months of 2012 compared with TABLE 2. Top steel-producing companies, million tons 2011

Improved Wellpad Automation, Shipped Quickly VEGA’s guided wave and through-air radar sensors are ideal for measuring total level and/or interface in storage tanks. A truly redundant system is developed when used with VEGA’s vibration switch for overfill protection. VEGA measurement instruments supply the following benefits: ϶ Removes issues associated with mechanical float style measurements ϶ Easy setup and use saves time —no recalibration is necessary after initial configuration

1. ArcelorMittal

97.2

2. Hebei Group

44.4

3. Baosteel Group

43.3

4. POSCO

39.1

5. Wuhan Group

37.7

6. Nippon Steel

33.4

7. Shagang Group

31.9

8. Shougang Group

30.0

9. JFE

29.9

10. Ansteel Group

29.8

TABLE 3. Countries with the highest apparent steel use, kg per capita 2011 1. South Korea

1,156.6

2. Taiwan

784.4

3. Czech Republic

595.7

4. Japan

506.7

5. Germany

479.6

6. Austria 866-VEGA-NOW (834-2669) americas@vega.com www.vega-americas.com

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473.1

7. China

459.8

8. Italy

459.5

9. Sweden

424.5

10. Belgium-Luxembourg

422.5


Refinery Wash Water Injector Constructed of Inconel® 625, this injector is 6 ft. (1.8 m) long, weighs 2600 lbs. (1179 kg) and has a class 1500 flange.

SUPERIOR SPRAY. SERIOUS RESULTS. Using a quill or injector for water wash or chemical injection? We can help improve performance. Here's how: UÊÊNozzle selection assistance. There are dozens of options and a wrong choice can result in wall wetting, corrosion and unscheduled downtime. Using a quill? Consider a change. A slot in a pipe doesn’t provide the same precise flow and drop size control as an injector U Analyze process conditions to determine spray direction – co- or counter-current. Spray direction affects drop size, wall contact, evaporation rate and more – it’s essential to get it right UÊÊDesign validation using Computational Fluid Dynamics (CFD) and our proprietary drop size data. We simulate your environment to verify spray performance, determine injector placement and ensure the materials of construction can withstand thermal stresses, heat transfer, vortex shedding and more We are uniquely qualified to optimize injector performance: spray expertise, manufacturing capabilities for B31.1 and B31.3 code compliance and a proven track record with customers like Jacobs Engineering, Shaw Group, Bechtel, Shell, Conoco Phillips and dozens more.

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Impact the same period in 2011, according to the latest Cefic Chemicals Trends Report. Monthly data for April 2012 showed a 1.9% decline compared with the previous April. April 2012 data show that the EU chemicals production level remains 5.2% below the peak in 2007. Prices for chemicals in the EU continued to climb on a year-on-year basis in April, up 3.2% during the month against the comparable month in 2011. The

price increase was led yet again by the overall price increase in basic inorganics. The latest data show the EU chemicals net trade surplus improved through the first quarter of 2012 by €2.4 billion, compared with the same period last year, reaching €12.5 billion. According to the latest EU Commission survey from May 30, 2012, confidence in the EU chemicals industry declined in May, based mainly on a strong deterioration in man-

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18

agers’ expectations for the months ahead. Consumer chemicals was the only subsector to avoid a drop in the April EU chemicals production index, up 1.6% in April 2012 compared with April 2011. Specialty chemicals and basic inorganics production decreased in April by 4.2% and 3.8%, respectively, on a year-on-year basis. Polymers production declined in April 2012 by 2.7% against the comparable period the year prior. Petrochemicals experienced no change in the same period. Monthly data for April 2012 showed a 1.9% decline for the EU chemicals industry compared, with April of the previous year. The EU trade surplus improved by €2.4 billion through the first quarter of 2012, and March 2012 trade data indicated a €12.5 billion overall EU chemicals net trade surplus. An EU net trade surplus with the NAFTA region contributed significantly to the additional surplus generated from January to March, reaching €3.3 billion, up €1.3 billion compared with the period from January to March 2011. The EU net trade surplus with the rest of Europe was €3.4 billion in the first quarter of 2012, up €0.5 billion compared with the first quarter of 2011. A €1.5 billion surplus occurred with Asia, excluding Japan, and China, which fell €0.5 billion when compared with the first quarter of 2011.

®

®

March 2012 were 1.4% lower compared with March 2011. The overall sales level continues to surpass the pre-crisis peak reached at the beginning of 2008. Compared to full-year sales levels in 2008, the total value of sales through the first three months of 2012 was 6.1% higher. As previously mentioned, the latest EU Commission report revealed confidence in the EU chemicals industry deteriorating markedly (–5.4) in May 2012, based mainly on a strong deterioration in managers’ expectations for the months ahead (–8.5). Moreover, managers’ assessment of their companies’ current level of order books deteriorated sharply (–4.2). Also, the assessment of the adequacy of the current level of stocks of finished products worsened. Managers’ assessments of their companies’ past production and current level of export order books also declined. Employment plans were further revised down. At the same time, selling price expectations decreased modestly.


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ADRIENNE BLUME, PROCESS EDITOR Adrienne.Blume@HydrocarbonProcessing.com

Innovations

PCHEs boost power from waste heat Heatric recently supplied Echogen Power Systems Inc. with Printed Circuit Heat Exchangers (PCHEs) for Echogen’s Supercritical CO2 (ScCO2) power generation cycle. The power generation system converts industrial waste heat into electricity, using supercritical CO2 as the working fluid and without creating new emissions. Heatric’s PCHEs help transfer more of the waste heat into electricity than would be possible with non-supercritical fluids. In the Echogen system, liquid CO2 is pumped to supercritical pressure, where it accepts internally recycled heat at the recuperator, followed by waste heat from the hot flue gas supply (FIG. 1). High-energy ScCO2 is then expanded through a turbine, which drives a generator to produce electrical power to customer specifications. The expanded ScCO2 is cooled at the recuperator and condensed to a liquid at the condenser. Then the cycle begins again. Heatric PCHEs are used for recuperating and condensing heat transfer services at pressures over 200 times atmospheric pressure. They allow greater heat recovery and process efficiency than other heat exchangers, with the resulting electricity produced at a lower cost per unit. If widely utilized, such systems could significantly reduce the demand that heavy power consumers place on the grid. Also, the compact size of Heatric’s PCHEs allows systems to be retrofitted more easily to existing industrial facilities.

To obtain SIL certification, the products were assessed by FM Approvals per the requirements of IEC 61508 parts 1, 2 and 3. When implementing Safety Instrumented Systems (SIS) in process plant environments such as power plants, offshore oil platforms, refineries and chemical plants, the SIL certification helps mitigate risk at the process instrument level. The SOR line of pressure switches and level switches are rugged, field-mounted instruments. Nearly every SOR product can be designed to meet the demands of specific processes and custom-built to suit exact specifications. Select 2 at www.HydrocarbonProcessing.com/RS

Cooler design raises efficiency by 25% GEA Heat Exchangers’ Groovy Fin Cooling industrial cooler design improves efficiency by 25%. The process technology supplier featured its air coolers at the ACHEMA 2012 conference in Frankfurt, Germany from June 18–22. The Groovy Fin Cooling design features a patented fin shaping that reduces the “slipstream,” or dead space, behind the finned tubes. This allows for smaller coolers with reduced space require-

ments and less power consumption by fans—i.e., reduced investment and operating costs. The central idea of using air instead of water as the coolant saves water resources and prevents the warming of bodies of water—and it is the technology preferably used in regions where water is scarce. Air coolers comprise finned-tube bundles and fans that generate airflow to cool the gas or liquid inside the tubes. When the air flows across the finned tubes, it cannot reach the area located immediately behind the tubes because a dead space is formed on the side not facing the airflow. Until now, a part of the fins was not used as a cooling surface. “Groovy Fin Cooling” means that the fins are grooved to guide the airflow behind the tube. The efficiency of the air cooler is increased by up to 25%, and the environmental footprint (in this case, the space requirement and the energy consumption) is also significantly reduced. If the customer uses the improved efficiency for higher cooling performance while retaining the same heat exchanger size, then performance can be improved by up to 20%. Cleaning of the grooved finned tubes is the same as in conventional finned tubes, and the mechanical stabil-

Cooled flue gas

Heat engine skid Recuperator Pump Waste heat exchanger

Select 1 at www.HydrocarbonProcessing.com/RS

Power electronics

Switch line receives SIL certification SOR Inc.’s line of pressure, differential pressure, temperature, vacuum and level switches has been certified fit for use in Safety Integrity Level (SIL) environments. SOR is one of only a few manufacturers in the industry to offer its entire range of switches certified to the IEC 61508 safety standard.

Condenser

Generator Cooling water supply

Cooling water return

Gear

Turbine

Flue gas supply

Net power

FIG. 1. Echogen’s power generation system converts industrial waste into electricity using Heatric’s heat exchange technology. Hydrocarbon Processing | AUGUST 201221


Innovations ity of the patented design is even higher. GEA offers a variant with special protection for applications in aggressive ambient air conditions, e.g. in LNG terminals. Select 3 at www.HydrocarbonProcessing.com/RS

Third-generation valve diagnostics enhance flexibility

The new Metso Valve Manager (FIG. 2) represents state-of-the-art, third-generation valve diagnostics that are capable of processing collected diagnostics information to visualize the condition of a valve with five different indices: control performance, valve condition, actuator condition, positioner condition and environmental conditions.

FIG. 2. The Metso Valve Manager is capable of processing collected diagnostics information to visualize the condition of a valve.

FIG. 3. Honeywell’s MeterSuite solution helps oil and gas operations reduce costs, improve control performance and meet requirements for CO2 emissions.

22AUGUST 2012 | HydrocarbonProcessing.com

With processed and visualized diagnostics information, maintenance engineers and process operators are capable of making educated decisions concerning control valve maintenance, without deep valve know-how. Unexpected shutdowns can be avoided, and the control valve performance can be maintained at an optimum level by continuously monitoring the condition of the installed base at the plant or mill and by taking necessary preventive actions based on available diagnostics information. Also, with the help of diagnostics, the available maintenance resources can be more efficiently allocated during shutdowns. When a preventive or schedule-based maintenance strategy is followed, valves are often needlessly maintained during shutdowns. By focusing the maintenance actions on the valves actually needing maintenance, significant maintenance cost savings can be achieved through reduced spare-part purchases and reduced need for maintenance resources. Valve Manager is available for the Neles ND9000 series of intelligent valve controllers. Select 4 at www.HydrocarbonProcessing.com/RS

PDH catalyst delivers significant savings

Süd-Chemie AG recently announced that its breakthrough in the CATOFIN propane dehydrogenation (PDH) catalyst has been successful in delivering a significant increase in propylene selectivity, while simultaneously reducing energy consumption. Since the new catalyst was introduced a little over a year ago, commercial operations employing the improved catalyst have delivered a 2%–3% selectivity boost, as well as energy savings of between 5% and 10%, both of which have a significant positive impact on plant economics by enabling an increase in production without additional operating costs. For a grassroots facility, this performance improvement can translate into a profit improvement of up to $30 million, when compared to using conventional catalysts. The CATOFIN PDH process can also be used to produce isobutylenes from isobutane. It operates at optimum reactor pressure and temperature to maximize conversion of propane (or iso-

butane), with low investment and operating costs. Süd-Chemie produces the CATOFIN catalyst, and Lummus Technology has exclusive worldwide licensing rights to the technology. CATOFIN technology has been selected by 20 licensees worldwide and is in operation in 14 units. Select 5 at www.HydrocarbonProcessing.com/RS

ExxonMobil launches online lubricant selector

ExxonMobil Lubricants & Specialties recently introduced Looble, a user-friendly, online industrial lubricant selector designed to help maintenance professionals make informed lubricant decisions for optimizing equipment performance and minimizing unplanned downtime. Looble simplifies the lubricant selection process by providing targeted Mobil-branded product recommendations with performance ratings based upon users’ specific industries, applications and equipment. Looble enables users to access lubricant recommendations and application guidance based on their specific applications and operating conditions for a wide range of industries. It also provides Original Equipment Manufacturers’ recommended lubricants and schematics for numerous types of equipment makes and models, along with detailed descriptions and performance ratings for each recommended lubricant. For more information about Looble, visit Looble.com. Select 6 at www.HydrocarbonProcessing.com/RS

Metering solution cuts costs, improves control performance

Honeywell Process Solutions’ MeterSuite fiscal metering solution (FIG. 3) recently received European Measuring Instrument Directive (MID) and International Organization of Legal Metrology (OIML) R117 certification. MeterSuite is available globally and is now a fully MIDand OIML-approved product. MeterSuite is an advanced, configurable and integrated fiscal flow measurement solution offered by Honeywell in partnership with Swinton Technology. It integrates with Honeywell’s Experion Process Knowledge System (PKS) architecture to provide oil and gas flow calculation for greater cost efficiency, ex-


Innovations tended lifecycle support and improved control. MeterSuite is available in all Experion software revisions, from R201 to R400.2. The system also integrates with all common meter types and supports ISO, AGA and API standards. MeterSuite helps oil and gas operations meet regulatory requirements for fiscal reporting of CO2 emissions; simplifies the integration of raw meter data in accounting and reporting systems; and offers enhanced control features for liquid, loading and proving systems where control and sequencing tasks are critical. Users benefit from the incorporation of Experion capabilities, including flexible reporting, web-based access, and integration with wireless and fieldbus transmitters in the metering function. With the MeterSuite offering, Honeywell remains the only distributed control system (DCS) vendor that can provide a fully-integrated metering solution on a DCS control platform.

mizing chemical composition design, specific melting, and casting developments. Stronger and more ductile than its predecessor, Paralloy H39WM+ features enhanced creep strength and carburization resistance, with extensive research performed to meet the most stringent criteria for modern steam-reforming furnaces and pyrolysis cracking coils. The properties of Paralloy H39WM+ allow for tubes with thinner walls, which

reduce thermal gradient and, therefore, thermal stresses within the wall on startup and shutdown. Thinner walls also provide energy savings and improvement in the rate of heat transfer. Select 8 at www.HydrocarbonProcessing.com/RS

Flowmeter reduces LNG costs

With its unique self-conditioning flow technology, the versatile V-Cone

Altra Couplings. Ultra Precision. Offering the widest range of couplings for critical turbomachinery.

Select 7 at www.HydrocarbonProcessing.com/RS

Ameridrives Couplings, formerly

High-performance microalloy raises plant efficiency

In response to the petrochemical industry’s need to improve plant performance, Doncasters Paralloy launched a new microalloy, Paralloy H39WM+. This alloy fulfills those requirements by providing superior material properties, enabling customers to improve plant operation and generate long-term savings. Paralloy H39WM+ is built on the success of the classic and highly respected Paralloy H39WM. It is the result of opti-

the Mechanical Drives Division of Zurn Industries, is the leading global supplier of high performance couplings for gas turbine generator drives and API-671 applications in the hydrocarbon processing market. In 2011, Altra Couplings proudly announced shipping the 10,000th Ameriflex multiple convoluted diaphragm coupling. Ameriflex® by Ameridrives

Ameridisc® by Ameridrives

Turboflex HP by Bibby Turboflex

FIG. 4. McCrometer’s V-Cone Flow Meter is installed in a wide variety of LNG applications, including gas measurement in liquefaction trains and storage tanks, and specialized cryogenic applications.

The Ameridisc coupling’s advanced technology offers an optimized scalloped disc profile based on FEA and strain gage verification. Features include lightweight reduced moment designs for sensitive turbocompressor applications along with fail-safe co-planar designs, proprietary disc coating and optional disc materials often required by end users. The first flexible “dry” coupling supplied on turbomachinery, Bibby’s Turboflex disc coupling, is well known globally for its competitive design and 50 year reference list. The polygon profiled disc and larger fasteners result in the most power dense disc coupling available to the market. Please visit us at www.AltraGlobalCouplings.com

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23


Innovations Flow Meter (FIG. 4) from McCrometer offers a lowest-installed-cost, low-maintenance and highly reliable measurement solution for challenging and hazardous applications in liquefied natural gas (LNG) processing, transportation, storage and distribution. The natural gas liquefaction process requires accurate flow measurement, as the gas is first cooled to −260°F (−162.2°C), which condenses the fluid into the liquefied state. Flow is then measured again several times during transportation, storage, regasification and distribution through pipelines. With its self-conditioning, no-moving-parts differential pressure (dP) sensing technology, the V-Cone Flow Meter is now installed in a wide variety of LNG applications all over the world. Hundreds of V-Cone Flow Meters have been installed to measure gas as it flows into liquefaction trains and then from the trains into storage tanks. It has even been used in specialized cryogenic applications where flow was never before measured. The V-Cone Flow Meter offers significant installed and operational cost savings in LNG facilities with complex or crowded equipment layouts, where the options for upstream and downstream piping are limited. This meter requires only 0–3 straight pipe diameters upstream and only 0–1 straight pipe diameters downstream for accurate flow measurement, using up to 70% less pipe than other dP flowmeters. Beyond the initial cost savings by installing much shorter pipe runs, there is an additional energy cost savings that accrues from maintaining the extreme cryogenic temperatures necessary over a much shorter distance. The need for costly pipe insulation is also reduced. With its rugged design, the V-Cone Flow Meter requires little maintenance; its life is typically 25 years of service. The flowmeter is inherently more accurate than traditional dP instruments because the flow conditioning function is built directly into its sensor design. A centrally located cone interacts with the fluid steam, reshaping the velocity profile to provide a stable signal that increases measurement accuracy. The pressure difference exhibited between the static line pressure and the low pressure created downstream of the cone 24AUGUST 2012 | HydrocarbonProcessing.com

is measured via two pressure-sensing taps, one placed slightly upstream of the cone and the other located in the downstream face of the cone itself. The pressure difference is then incorporated into a derivation of the Bernoulli equation to determine the fluid flow rate. The V-Cone Flow Meter is available in line sizes from 0.5 in. to greater than 120 in., with flanges compatible with any application. It operates over a wide flow range of 10:1, is accurate to ±0.5%, and offers repeatability to ±0.1%. Select 9 at www.HydrocarbonProcessing.com/RS

pH sensors monitor sour water in refineries

Electro-Chemical Devices’ sulfideresistant Models S10 and S17 Analytical pH Sensors (FIG. 5) provide a flexible, cost-effective solution to monitoring sour water containing hydrogen sulfide (H2S) compounds in oil and gas refineries. To meet regulatory limits, refiners must monitor and treat naturally occurring H2S that contaminates water in their operations. Removing H2S from water is accomplished through air stripping, which eliminates the sulfur or oxidation reactions that convert the sulfides to sulfates. Once the water has been stripped of the sulfides, it can be used in other refinery operations or further treated as wastewater. Stripping is essential due to both the toxic environmental and corrosive effects on equipment of sulfides, which are also a common sensor poison. The S10 and S17 pH sensor product family monitors pH in water-based solutions. The S10 and S17 Model 20005130 replaceable cartridge electrode features a pH range of 0 to 14 at temperatures from −5°C to 130°C, and it survives pressures up to 300 psi at 25°C. It has been tested to sulfide ion concentrations of up to 25 ppm. The S10 and S17 product line consists of two unique sensor designs and replaceable electrode cartridges. The S10 sensor is an immersion- or insertion-style sensor, and the S17 is a valve-retractable sensor. They are fully rebuildable, and they both feature a 316 stainless steel body that incorporates the sensing cartridge, a temperature module and a signal conditioner with cabling. These cartridges provide specific solutions for the measurement of pH, ORP, specific ion (pION), dis-

solved oxygen, conductivity and resistivity in a wide range of industrial process applications. The pH and ORP cartridges are available with either Radel (PES) or PEEK construction configurations with fullcrown-, double-tine- or single-tine-style pH bulb protection. The pION cartridges with solid-state, glass- or PVC-sensing membranes are suitable for continuous online measurement. The DO electrode is a galvanic cell with a lead anode, a silver cathode and a Teflon membrane. The conductivity and resistivity electrodes are designed in both contacting and toroidal sensor configurations for application flexibility. Select 10 at www.HydrocarbonProcessing.com/RS

Software enables RTD display for simulation Aspen Technology Inc.’s new release of aspenONE software allows process engineers to compare simulation results to historical and real-time data (RTD) on the simulation flowsheet for the first time. This unique functionality makes it easier for Aspen Plus and Aspen HYSYS users to optimize and troubleshoot their manufacturing assets. Aspen Plus and Aspen HYSYS can now find plant data based on characteristics, including tag types and tag attributes. Searching delivers the right information faster, with results organized by relevance and previews available for all historical attributes. Users can search by feature, component, reaction, unit operation type and other specifications. The new search functionality in Aspen Plus and Aspen HYSYS is available immediately. Select 11 at www.HydrocarbonProcessing.com/RS

FIG. 5. Electro-Chemical Devices’ sulfideresistant Analytical pH Sensors provide a cost-effective solution to monitoring refinery sour water containing H2S compounds.


KNOW-HOW DELIVERED We put proven hydroprocessing solutions to work in your world. Technology, equipment and services to improve operating flexibility, capital efficiency and environmental performance. So you can take advantage of heavy, high-sulfur and acidic opportunity crudes. KBR Technology delivers for greenfield and existing refineries of virtually every type and size. See HOW we can help you meet mission-critical goals.

REFINING

© 2012 KBR K12105 All Rights Reserved 08/12

h y d r o p r o c e s s i n g . k b r. c o m Select 59 at www.HydrocarbonProcessing.com/RS


The world’s largest hydrogen pipeline network delivers... The world’s most reliable hydrogen supply.

How does Air Products, the global leader in hydrogen supply, make the best hydrogen supply systems on the Gulf Coast even better? We connect them. With the opening of a 180-mile-long pipeline that connects our existing Texas and Louisiana systems, we’ve united 22 hydrogen plants and 600 miles of pipeline, to create a total system capacity of over one billion SCFD. So if an event disrupts operations on one side of the Gulf, hydrogen can keep flowing from the other, giving our refinery and petrochemical customers the reliable, uninterrupted supply they need. For videos and detailed information, visit our website.

tell me more airproducts.com/H2pipeline

©2012 Air Products and Chemicals, Inc.

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HELEN MECHE, ASSOCIATE EDITOR Helen.Meche@HydrocarbonProcessing.com

Construction North America

TWD Technologies has been selected by Great Lakes Biodiesel to build what is said to be Canada’s largest biodiesel plant. It is scheduled to be operational by the autumn of 2012. TWD is providing full engineering, procurement and construction management for the plant, which is to be located in Welland, Ontario. The new Great Lakes Biodiesel plant will produce ASTM 6751-quality biodiesel made primarily from Canadian vegetable oils, such as canola and soybean. When completed, the plant will have the capacity to produce 170 million liters/yr of biodiesel. ExxonMobil Research and Engineering Co. (EMRE) has a licensing agreement with Sundrop Fuels Inc. for EMRE’s methanol to gasoline (MTG) technology. Sundrop Fuels will apply the technology at its planned biomass fuels plant near Alexandria, Louisiana. The biomass complex will gasify forest waste, supplemented with hydrogen produced from natural gas, to make synthesis gas. The syngas then will be converted to methanol and fed into the MTG process producing 3,500 bpcd of renewable gasoline. The MTG process converts crude methanol directly into low-sulfur, lowbenzene gasoline. Although the original application of the MTG technology processed methanol from natural gas, the same technology can be used for methanol from other sources, such as coal, petcoke and biomass. Petroplex International, LLC, has launched the front-end engineering and design (FEED) study of a state-of-the-art bulk liquids terminal facility in St. James Parish, Louisiana. Petroplex, which is backed by a consortium including Macquarie Group, through its Macquarie Capital division, Quanta Services Inc. and individual investor Mr. Harley Franco, CEO and founder of Harley Marine Services Inc.,

announced that QPS Engineering, LLC, a division of Quanta Services, will lead the project’s design and engineering work, and Verwater B.V. will provide specialist engineering advice on the storage tanks. The storage and distribution terminal will include a unit-train facility, barge and ship dock, truck racks and pipeline, and will be designed and tailored to client specifications. The project’s major construction work is expected to begin after the close of construction financing in the first half of 2013. Commercial operations are scheduled during 2014.

Latin America

Shanghai-based Wison Offshore & Marine Ltd., a subsidiary of the Wison Group, has a contract from Exmar Group for engineering, procurement, construction, installation and commissioning (EPCIC) of what is said to be the world’s first floating liquefaction, regasification and storage unit (FLRSU). The facility will be used by Exmar under a build, own and operate contract with Pacific Rubiales Energy Corp., and it will be located on the Caribbean coast offshore Colombia. Commercial operations are planned to commence from the fourth quarter of 2014. The FLRSU consists of a non-propelled barge equipped to convert 69.5 million scfd of natural gas into liquefied natural gas (LNG) (+/– 500,000 tpy of LNG) that will be temporarily stored in onboard tanks with a total capacity of 14,000 m3 and subsequently offloaded either to a permanently moored floating storage unit or shuttle tankers. The facility will be moored to a jetty and supplied with gas by pipeline. Wison Offshore & Marine will design and engineer the unit from its Shanghai operational center. Construction will be performed at Wison’s wholly owned fabrication facility located in Nantong, China, with further support supplied by the company’s subsidiary in Houston, Texas, in the US. Black & Veatch will engineer and

procure the topside liquefaction equipment and packages using its patented PRICO LNG technology, and provide onsite commissioning and startup services. Alpek S.A.B. de C.V., through its subsidiary Grupo Petrotemex, S.A. de C.V., has awarded a turnkey contract to a consortium led by SENER Mexico to construct a cogeneration power plant in Cosoleacaque, Veracruz, Mexico. This plant, which will have a capacity of over 85 MW, will boost the competitiveness of Alpek’s operations. The new facility will have two gas turbines, two heat-recovery steam generators and a back-pressure steam turbine. SENER will carry out the basic and detailed engineering, and will also coordinate the project. The timeframe for completing construction will be 23 months, meaning that the plant is slated for completion in February 2014. Ecopetrol has started the modernization of its Barrancabermeja refinery (PMRB project) in Santander, Colombia. As part of this reconfiguration, Ecopetrol has selected Axens’ technologies for its hydrocracking and coker naphtha-hydrotreating units. The 80,000-bpd hydrocracker will process a blend of straight-run vacuum gasoil and cracked gasoil to produce high-qualTREND ANALYSIS FORECASTING Hydrocarbon Processing maintains an extensive database of historical HPI project information. The Construction Boxscore Database is a 45-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc. Many companies use the historical data for trending or sales forecasting. The historical information is available in commadelimited or Excel® and can be custom sorted to suit your needs. The cost depends on the size and complexity of the sort requested. You can focus on a narrow request, such as the history of a particular type of project, or you can obtain the entire 45-year Boxscore database or portions thereof. Simply send a clear description of the data needed and receive a prompt cost quotation. Contact Lee Nichols at 713-525-4626 or Lee.Nichols@GulfPub.com

Hydrocarbon Processing | AUGUST 201227


Construction ity middle-distillates and to improve the FCC feed quality. The 14,000-bpd coker naphtha hydrotreater will produce feedstock suitable for petrochemicals. The refinery is already equipped with Axens’ Prime-G+ and Prime-D hydrotreating technologies for low-sulfur gasoline and ultra-low-sulfur diesel production. Braskem’s new butadiene plant, located in the Triunfo Petrochemical Complex in the state of Rio Grande do Sul, has entered the pre-operational phase, which marks the startup of plant operations 50 days ahead of schedule. With a 103-kiloton/yr production capacity, the new plant is starting its operations 14 months after construction began. Total project investment was R$300 million. Wison Engineering Ltd. has an engineering, procurement and construction (EPC) contract from PDVSA Petroleo, S.A. for PDVSA’s refinery in Puerto la Cruz, Venezuela. Hyundai Engineering & Construction Co. Ltd. and Hyundai Engineering Co., Ltd., are jointly participating in the project as Consortium Hyundai-Wison. The total contract value amounts to approximately $2.993 billion, of which Wison Engineering will receive a share of approximately $927.8 million. Consortium Hyundai-Wison will carry out EPC and startup assistance of the environmental and auxiliary units, and will also revamp the deep-conversion project’s atmospheric distillation units at the Puerto la Cruz refinery. The project will upgrade refinery facilities to process heavy crude oil, with a capacity of 210,000 bpd. In addition, the contract also includes expansion of gasoline, diesel and aviation kerosine units and other facilities. The project is expected to be completed within 42 months from its commencement.

Europe

Haldor Topsøe has selected UOP LLC, a Honeywell company, to provide technology to purify hydrogen from a steam-reforming unit to be installed at the Antipinsky refinery in Tyumen, Russia. Honeywell’s UOP Polybed Pressure Swing Adsorption (PSA) system will recover and purify hydrogen to help the refinery meet the increasing need for clean transportation fuels such as diesel and gasoline. The new hydrogen unit, which is schedSelect 155 at www.HydrocarbonProcessing.com/RS

uled to start up in 2013, is part of the refinery’s plan to increase its capacity of crudeoil processing by as much as 7 million tpy. It will also enable production of fuel products that meet the European Union’s Euro5 emission standards aimed at reducing emissions from light-duty vehicles. Axens has been selected to supply a technology license for a new Prime-G+ unit to desulfurize FCC gasoline at Lukoil’s Kstovo refinery in the Nizhny Novgorod region of Russia. The unit, which has been designed to treat more than 1.1 million tpy of cracked gasoline, will produce a high-octane stream, resulting in refinery gasoline pool sulfur levels as low as 10 ppm. The Linde Group has an engineering contract from SIBUR LLC for the licensing and front-end engineering and design (FEED) of what is reported to be one of the world’s largest ethylene plants in Tobolsk, Western Siberia, Russia. The ethylene plant is to be built at the petrochemical complex ZapSibNeftekhim in Tobolsk, which is being planned by the company ZapSibNeftekhim, a SIBUR subsidiary. Once finished, the new plant will produce around 1.5 million tpy of ethylene, 500,000 tpy of propylene and 100,000 tpy of butadiene from the feedstocks ethane, propane and n-butane. Linde’s FEED services will provide a foundation for the detailed engineering and construction phase. The services also include a cost estimate, which will be used by SIBUR to inform the final investment decision. Linde is constructing a 500,000-tpy polypropylene plant at SIBUR’S Tobolsk site, which is set to go onstream next year. This project is said to be one of the key investments in Russia’s petrochemical industry. CB&I has been awarded a $40 millionplus contract by Nizhnekamskneftekhim OAO (NKNK) to provide front-end engineering and design (FEED) services for a new ethylene plant. The work is scheduled for completion in 2013. CB&I’s project scope includes FEED for a 1 million-tpy ethylene plant, a related butadiene-extraction unit and a pyrotol unit, including offsites and utilities. Technip has been awarded two frontend engineering and design (FEED)


Construction contracts by ZapSibNeftekhim, an affiliate of SIBUR LLC. The plants will be located in Tobolsk, Russia. The first contract concerns a linearlow-/high-density gas-phase polyethylene plant; the second is for a high-density slurry-phase polyethylene plant. Each plant will consist of two parallel production trains with a total capacity of 1.5 million tpy of polyethylene. Both will be developed using INEOS Technologies’ licenses. Technip’s operating centers in Lyon, France, and St. Petersburg, Russia, will execute the contracts, which are scheduled to be completed in the first half of 2013.

Africa Naftec SpA, a subsidiary of Sonatrach, is reported to be nearing mechanical completion of a new paraxylene production plant in Skikda, Algeria. Anticipated to be fully operational later this year, the new facility will help to meet a global increase in paraxylene demand. The new facility will incorporate CrystPX technology licensed by GTC Technology to recover paraxylene from reformate feedstock, and GT-IsomPX, a process using ISOXYL catalyst from SüdChemie AG, a subsidiary of Clariant, to isomerize the C8 aromatics into additional paraxylene. GTC has been the only licensor in recent years to provide crystallization technology for equilibrium and concentrated-PX feed streams. Sasol Petroleum International has inaugurated its expanded central-processing facility (CPF) in Temane, Mozambique. The capacity of the CPF was increased to 183 megajoules per year (MJ/ yr) of natural gas, from its initial design capacity of 120 MJ/yr. Sasol’s partners in the CPF are Companhia Moçambicana de Hidrocarbonetos S.A. (CMH), representing the Mozambican government, and the International Finance Corp. (IFC). The expansion project, at an investment cost of $220 million, came in under budget while achieving excellent safety statistics. Honeywell has a $2.4-million project to deliver a full automation solution for Petrocity’s Greenfield Konza terminal storage facility located 60 km southeast of Nairobi, Kenya. The project includes comprehensive solutions for the pipeline receipt system, tank farm, truck-loading

system and terminal automation, through the Experion Process Knowledge System (PKS). It also includes all industrial security, emergency shutdown (ESD) and fire and gas (F&G) systems. The new terminal facility is situated on the Nairobi-Mombasa highway, and will have a capacity to handle 120 million liters of gasoline, diesel and kerosine—enough stock to fuel Nairobi for up to two months. It will also provide infrastructure for product receipt, storage and distribution. Honeywell Process Solutions will deliver all services associated with the project, from the initial hazard and operability (HAZOP) study, front-end and detailed engineering, to onsite commissioning and support services with a resident engineer.

Middle East Jacobs Engineering Group Inc. has a design contract from Saudi Kayan Petrochemical Co., an affiliate of Saudi Basic Industries Corp. (SABIC), to develop a process design package (PDP) and front-end engineering and design (FEED) package for an ultra-high-molecular-weight polyethylene (UHMWPE) plant in Jubail Industrial City in the Kingdom of Saudi Arabia. The UHMWPE plant is to produce 35,000 tpy, using ethylene sourced from Saudi Kayan’s existing olefins plant, and is reportedly of significant strategic importance, as SABIC is to use its own technology. Sadara Chemical Co., a joint venture between Saudi Aramco and The Dow Chemical Co., has awarded Jacobs Engineering Group Inc. an in-Kingdom engineering, procurement and construction management (EPCM) contract for three polyethylene trains. This award is part of a world-scale, fully integrated chemicals complex now being built by Sadara in Jubail Industrial City in Saudi Arabia. Comprising 26 manufacturing units, the complex will reportedly be one of the world’s largest integrated chemical facilities, and the largest ever built in a single phase. First production units are expected to come online in the second half of 2015, with all units up and running in 2016.

Asia Pacific Alfa Laval has an order from a Technip Samsung Consortium (TSC) to

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Construction supply equipment to Shell’s Prelude floating liquefied natural gas (FLNG) facility. The Alfa Laval equipment consists of desalination units, heat exchangers and filters. The desalination units will convert seawater into freshwater to be used for steam generation, process water and potable water. The heat exchangers will use seawater in the vital cooling applications in the gas liquefaction process.

When the Going gets HOT… Non-intrusive flow measurement up to 400°C Trouble free operation at f extreme pipe temperatures f No clogging, no pressure losses Installation and maintenance f without process interruption Independent of fluid f or pressure f Hazardous area approved

Field-Proven at Refineries f Heavy crude Oil f Atmospheric Distillation f Vacuum Distillation f Coker & Visbreaker Feed

A new ethylene dimerization unit, using Axens’ AlphaButol technology will be installed at the petrochemical complex of GAIL (India) Ltd., in Pata, India. The unit will produce 20,000 tpy of highpurity 1-butene. Based on homogeneous catalysis and associated with a low investment cost, the AlphaButol technology ensures a flexible and reliable source of high-quality comonomer 1-butene for downstream polyolefins applications. UOP LLC, a Honeywell company, has opened a manufacturing and operations center in Penang, Malaysia, that will produce natural gas membrane elements to support the growing natural gas market. Honeywell’s UOP Separex membrane systems remove impurities from natural gas streams. Removing impurities is necessary before the gas can be used as fuel, as a source for petrochemicals, or distributed by pipeline. Indian Oil Corp., Ltd. (IOCL), has chosen Axens’ AlphaButol technology to produce high-purity 1-butene by ethylene dimerization. An AlphaButol unit of 20,000-tpy capacity will be incorporated in IOCL’s Panipat naphtha-cracker complex situated in the state of Haryana. Panipat is the location of IOCL’s most state-of-the-art refinery and India’s largest naphtha steam cracker.

f Fluidized Catalytic Cracker f Bitumen

www.flexim.com

FLEXIM AMERICAS Corp. Toll free: 1 888 852 74 73 Select 157 at www.HydrocarbonProcessing.com/RS

KBR will provide an integrated technology, engineering, procurement and construction (EPC) support solution for Uz-Kor Gas Chemical’s flexible-feed, 400,000-metric-tpy ethylene plant in the Ustyurt region of Uzbekistan. The plant will reportedly be the first ethylene plant based on KBR’s license in Uzbekistan and will utilize KBR’s proprietary Selective Cracking and Optimum Recovery (SCORE) technology. KBR will deliver the basic engineer-

ing package, SCORE technology license, operator training, startup services and in-country construction assistance. KBR will also provide detailed engineering and design for the ethylene plant’s furnace section and supply equipment related to the ethylene furnace. GS Engineering and Construction Corp. will supply additional EPC for the project, which will further strengthen KBR’s working relationship with GS Engineering and Construction as providers of competitive lump-sum EPC solutions to potential customers. GTC Technology US, LLC, has a memorandum of understanding (MOU) with Beijing Sanju Environmental Protection and New Material Co., Ltd., for cooperation in sulfur-removal technologies. The MOU expands GTC’s platform of acid-gas-removal technology, which currently includes GT-CO2, a process technology for CO2 removal; GT-SSR, a Claus process for sulfur recovery with over 60 licenses; Crystasulf, a liquidphase Claus process technology for sulfur recovery; GT-DOS, an innovative directoxidation technology; and GT-SPOC, a key advancement in the Claus process. The MOU allows GTC to expand its offerings to applications of less than 1 tpd of sulfur removal. Davy Process Technology Ltd. (DPT), a Johnson Matthey company, and The Dow Chemical Co.’s Oxygenated Solvents business announced that Shaanxi Yanchang Petroleum Yan’an Energy and Chemical Co., Ltd., a project entity invested in by Shaanxi Yanchang Petroleum (Group) Co., Ltd., has selected LP Oxo technology using Dow’s proprietary NORMAX Catalyst to co-produce 2-propylheptanol, n-butanol and isobutanol in a single integrated plant in Fu County, Shaanxi Province, China. With this license, Yan’an Energy will build a LP Oxo plant, as part of Yanchang Petroleum Yan’an Coal-Gas-Oil Resources Integration Complex, with 80 kiloton/ yr of 2-propylheptanol, 206 kiloton/yr of n-butanol and 7 kiloton/yr of isobutanol. The new plant adopts what is said to be an industry-first design based on DPT’s and Dow’s state-of-the-art LP Oxo technology, which specializes in the production of 2-propylheptanol and butanols within one combined facility.


STEPHANY ROMANOW, EDITOR Stephany.Romanow@HydrocarbonProcessing.com

Construction Profile

Rotterdam LNG facility wins More importantly, the construction entire project and site management, phase was completed with one of the together with the supervision of con‘project of the year’ award The liquefied natural gas (LNG) regasification plant Gate terminal, located in Maasvlakte (Rotterdam) has been named “project of the year” by the European Construction Institute (ECI) and is featured as the cover of HP’s August issue. The award was announced by the Institute during the 23rd Annual ECI conference in Düsseldorf, Germany. ECI is Europe’s only transnational learning and improvement network covering the entire project cycle for engineering construction. The Gate terminal megaproject is one of the largest LNG terminals in Europe, with an initial throughput capacity of 12 billion m3/yr and three 180,000-m3 storage tanks. The terminal has two jetties and is able to unload simultaneously two vessels of the Q-Max type (the world’s largest LNG carriers). The high-scale Gate terminal is able to fulfill the natural gas needs for The Netherlands and part of Europe. Total project cost is estimated at 800 million euros. This project is a success story. TS LNG—a joint venture of TechintSENER and TSEV (Techint-SENEREntrepose-Vinci), the main contractor of the plant—delivered the facility to the client on September 1, 2011, as planned, complying successfully with the EPC contract. The project began in June 2008; special attention was consistently applied to safety, protecting the environment, operational availability and versatility. This plant is environmentally friendly, and it was designed for the “unthinkable.” For example, it has a safe shutdown earthquake element with a return period of 5,000 years. The Gate terminal was designed to manage rising sea levels linked to global warming and to comply with the latest safety and security standards, such as SEVESO, HAZOP, HAZID, ISPS, SVA, etc. Along with the plant’s design, onsite safety was a high priority for the main contractors and the TSEV consortium.

highest levels of safety ever recorded for works implemented in Rotterdam’s Europort (boasting more than 2.5 million work hours without accidents). The TS LNG joint venture was in charge of managing the engineering, procurement, construction and start-up of the LNG plant. Techint E&C was the leader for the building consortium TSEV, and the company was also assigned the

struction works. SENER participated in project management, procurement and construction works. Also, SENER was responsible for managing the plant’s implementation, commissioning and startup, as well as for the engineering activities. In addition, the Gate terminal was also named “LNG Project of the Year” in January 2012 by the European Gas Conference Awards.

FIG. 1. Aerial view of Gate terminal at Rotterdam.

FIG. 2. Workers finish insulating pipework at the Gate terminal LNG facility. Hydrocarbon Processing | AUGUST 201231


CONSTRUCTION BOXSCORE UPDATE / ConstructionBoxscore.com COMPANY

CITY

PROJECT

EX CAPACITY UNIT

Egyptian Refining Co

Cairo, Mostorod

Refinery

Shell Royal Dutch HMEL ONGC Mangalore Petrochemicals HPCL Pertamina Petronas PARCO

Offshore, West Australia Bhatinda Mangalore Visakhapatnam, Visakh Refinery Cilacap Melaka Multan

LNG Floating (FLNG) Refinery Paraxylene Hydrotreater, Diesel Refinery LNG Regasification Bitumen

Bayer MaterialScience AG KazMunaiGas Expl & Prod SABIC Europe Sibur Uz-Kor Gas Chemical LLC

Dormagen Atyrau Geleen Tobolsk Ustryat, Akchalak

Toluene Diisocyanate (TDI) Refinery EX Olefins EX Polypropylene (4) Ethylene

Cosoleacaque Guarico

Cogeneration Preflash

Qeshm Island Duqm Sohar Jubail Yanbu Taweelah, Khalifa Port Ind Zone

Refinery, Heavy Ends Petrochemical Complex Sulfur Recovery Unit (3) Acrylonitrile Benzene Melamine

Geismar Gallup Baytown Baytown Freeport Mont Belvieu Old Ocean Port Arthur Port Arthur

Olefins, Alpha Coal Gasification Ethane Cracker Ethylene Propylene (2) NGL Fractionation Polyethylene (2) Cogeneration Treater, Tail Gas

COST STATUS YR CMPL LICENSOR

ENGINEERING

CONSTRUCTOR

3700

E

2016

GS E&C | Mitsui

GS E&C

Mm-tpy 12.6 MMtpy 189 Mm-tpy 1200 MMtpy 89 Mbpd Mtpy 3000 bbl

P C U U E C C

2016 2012 2013 2012 2014 2012 2012

Technip | Samsung H EIL Toyo India Technip FW

Alfa Laval EIL Toyo India Toyo India

Porner

PARCO

U U E E E

2014 2015 2013 2013 2015

U E

2014 2013

P P P U E E

2013 2017 2015 2014 2013 2015

P P P U U E F C C

2013 2014 2016 2013 2018 2013 2017 2012 2012

AFRICA Egypt

100 bpd

Technip | Axens KTI | ConocoPhillips Co.

ASIA/PACIFIC Australia India India India Indonesia Malaysia Pakistan

TO RE

3.6 9 900 2.2 340 3.8

UOP Technip Porner

EUROPE Germany Kazakhstan Netherlands Russian Federation Uzbekistan

300 Mtpy 629 Mtpy None 1.5 MMtpy 387 kty

206 1700 609

Bayer MaterialScience AG FW | Axens FW Jacobs INEOS Technip KBR GS E&C | KBR

Marubeni | SEI

LATIN AMERICA Mexico Venezuela

Alpek Intevep

RE

85 MW 40 tpy

Sener Viscolube

MIDDLE EAST Iran Oman Oman Saudi Arabia Saudi Arabia UAE

Iranian Oil Rfg OOC/IPIC Oman Refinery Co LLC SABIC SABIC Chemaweyaat

30 230 155 140 EX

Mbpd bpd t/a Mtpy None 80 Mtpy

1500 400 20000

Jacobs Nederland BV Tecnicas Reunidas Wison Group Neste Jacobs

UNITED STATES Louisiana New Mexico Texas Texas Texas Texas Texas Texas Texas

Shell Chemical First American Internaional ExxonMobil Chevron Phillips Chemical Dow Chemical Anadarko Chevron Phillips Chemical Motiva Enterprises LLC Motiva Enterprises LLC

EX

BY

535 800 1.5 1.5 900 102 500 146 525

MMlb/y t/a Mtpy Mtpy tpy Mbpd Mm-t MW t/a

50 1700

Shell

Bechtel

Becon | Ecopetrol

Shaw

Shaw

Shaw

Enterprise Products Jacobs Burns and Roe Burns and Roe Black & Veatch|Shell Global S&B

Bechtel\Jacobs JV Bechtel\Jacobs JV

The above projects represent only a fraction of data updated monthly in the Construction Boxscore Database. For more information please go to www.ConstructionBoxscore.com or contact Lee Nichols at 713-525-4626 or Lee.Nichols@GulfPub.com.

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

• Track trend analysis • Decide future budget planning

NOW, WE’VE MADE OUR BEST PRODUCT EVEN BETTER! ENHANCEMENTS INCLUDE:

FOR A FREE 2-WEEK TRIAL, contact Lee Nichols at +1 (713) 525-4626 or Lee.Nichols@GulfPub.com.

www.ConstructionBoxscore.com 32AUGUST 2012 | HydrocarbonProcessing.com

• Exporting your search results to Excel so you can compile your research • Delivering the latest updated projects directly to your inbox each week • Designing customized construction reports for your company using our 50 years of archived projects • Detailed information for key contacts at planned and ongoing construction projects


Zyme-Flow® tough. From routine decontamination to heavy oil.

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Call 888.478.6996 for more information COLFAX is a registered trademark of Colfax Corporation, and TOTAL LUBRICATION MANAGEMENT, COT-PURITECH and LSC are service marks of Total Lubrication Management Company. ©2012 Total Lubrication Management Company. All rights reserved.

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Reliability

HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR Heinz.Bloch@HydrocarbonProcessing.com

Consider best-of-class lubrication practices Last month’s column explained that all hydrocarbon processing (HP) facilities use machinery, and these machines require lubrication. Periodically auditing one’s lubrication practices is part of a thoughtful reliability assessment routine. Such reviews may uncover near-zero cost improvement opportunities that can have paybacks measured in days. More important, such improvements can rapidly move the plant to best-of-class performance level. Example audit. An audit conducted by the authors at a USbased worldscale, state-of-the-art, petrochemical plant proved rather revealing conditions. This particular facility deserved commendations for selecting appropriate lubricants for their critical-operation equipment. While the origin of several plastic drums of synthetic lube was clearly spelled out (FIG. 1), there were deficiencies that needed to be rectified. Plant management and the reliability group had thoughtfully specified a high-quality lubricant to contain less-than-traditional amounts of water for use at the facility. Also, an oil analysis laboratory was on the facility’s list of consultants, and all should have been aware of the merits of sound lubrication management. Missed communication and flawed practices. But instructions and implementation strategies had not trickled down to the field workforce. Indoor storage was sporatic; lube transfer from five-gallon buckets (FIG. 2) to smaller, more manageable transfer containers was cumbersome and risky. This deficiency was later addressed by upgrading to the storage system, as shown in FIG. 3. It was evident that important lube-management rules had been bypassed or possibly neglected at this facility. Storage drums should be located and positioned so that water accumulation (FIG. 1) is mitigated. The July issue’s Reliability column

FIG. 1. Water accumulation on a drum can jeopardizes 65 gallons of a superior lubricant. There is an even greater consequential damage risk to rotating equipment at plants that allow this type of outdoor storage. Source: Royal Purple Inc., Porter, Texas.

illustrated how changes in ambient temperature can cause rainwater laying on top of a storage drum to be drawn into the drum by capillary action. In the case of FIG. 1, an aggregate supply of lubrication oil worth about $4,000 could have been rendered unserviceable. So, while outdoor storage is feasible, the drums should never stand upright. Spills and more. Contamination and spillage control of bulk storage containers are alluded to in FIGS. 2 and 3. In addition, plants utilizing best lube practices should use both filters and desiccant breathers to eliminate both airborne particulates and atmospheric moisture intrusion in drums. There are instances where installing only a vent cap is no longer deemed acceptable by reliability-focused plants. Best-of-class actions. Not applying best available lubrication management practices can be expensive. Good lubrication practices are described in experience-based texts that recommend periodic audits.1 1

LITERATURE CITED Bloch, H. P., Pump Wisdom, John Wiley & Sons, Hoboken, New Jersey, 2011.

FIG. 2. Indoor storage in five-gallon buckets makes spill-proof transfer to smaller transfer containers difficult. Source: TRICO Mfg. Co., Pewaukee, Wisconsin.

HEINZ BLOCH* teamed up with Raymond L. Thibault (rlthibault@msn.com) for this audit. Mr. Thibault has BS and MS degrees in chemistry. In 2001, he retired from a premier multi-national lube manufacturer after 31 years of developing lube programs and providing technical support for numerous major HPI and other industrial clients. He is considered the most knowledgeable independent consultant in the field of lube reliability improvement and teaches the subject worldwide.

FIG. 3. A modern indoor oil dispensing layout. Source: TRICO Mfg. Co., Pewaukee, Wisconsin. Hydrocarbon Processing | AUGUST 201235


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Integration Strategies

PAULA HOLLYWOOD, CONTRIBUTING EDITOR PHollywood@arcweb.com

Reliability solutions offer unique value propositions Globally, the process industries lose the equivalent of 5% of production annually because of unscheduled downtime and poor product quality. ARC Advisory Group estimates that almost 80% of these losses are preventable. As the longest phases in any asset’s life cycle, operation and maintenance (O&M) expenses account for the highest costs. Any improvements that a manufacturer can make in these life-cycle phases can significantly impact the bottom line. A perfect storm. A number of factors have converged to

drive present interest in reliability software and services. Increases in the amount and complexity of plant assets applied are the primary factor, as the lines between work management and information technology (IT) are blurred. Greater emphasis on safety, energy consumption and environmental control compound the need for more data. Enterprises now place greater emphasis on risk management to limit exposure to adverse events. With the growing shortage of skilled technicians capable of operating and maintaining such assets, a “perfect storm” is materializing. For owner-operators, asset reliability requires the convergence of process control with work management to form the basis for a more robust approach to sustainable business performance improvement. This convergence resolves weaknesses in one methodology, while being additive for both. For example, process control solutions cannot identify asset criticality, but reliability solutions can. Manufacturers can improve efficiency and productivity with standardized workflows based on best practices. Reliability solutions transform data into instantly accessible, context-appropriate information for those who need it. Proactive maintenance as a strategy. As maintenance activities migrate from reactive to proactive, new solutions are emerging that are designed to leverage the now available rich information to manage critical issues better within the confines of operational constraints. In terms of enterprise software for the manufacturing industries, asset reliability software is a new entry to the marketplace. ARC believes the real value of enterprise-level reliability software lies in its analytical capabilities. Operational risk management. Managing risk is an essen-

tial component of a reliability program. Decision-makers must understand the uncertainties of costs vs. risks to make informed decisions about the benefits of a given strategy and their possible impact on safety. Identifying critical equipment; failure modes; failure effects on equipment, personnel and the environment; and critical spares on hand enables decision-makers to leverage the right risks, while maintaining the appropriate controls to en-

sure effective and efficient operations. Visualization capabilities in risk-management modeling tools provide individuals with information in the context of their responsibilities and level of authority. Displays of real-time information and historical trends at the management level enable actions based on facts to minimize costs and losses associated with a business interruption. Reliability goes mobile. Technicians frequently perform

work that takes them out of range of wireless networks or handheld cradles for data transmission. As a result, reliability solutions have migrated into handheld devices and tablets for the bidirectional exchange of data. This enables operators to take a more proactive role in initiating corrective actions for degrading equipment. Taking reliability to the next level. At present, reliability is generally an afterthought, with little input in the concept and design phase of the asset life cycle. To take reliability to the next level, it must be built into the asset. Reliability expectations should be defined in the concept phase and used to drive performance into the design phase of the product development cycle. Early testing can identify important failure modes that should be resolved in the final design. Unresolved failure modes, such as normal wear of items, should be tagged in diagnostic guides for condition monitoring and PAM solutions to drive appropriate maintenance strategies. A reliable-by-design approach provides a clear understanding of the risks before products are introduced and enables end users to better address issues later, if necessary. Historically, in the hierarchy of an enterprise, maintenance has been viewed as the ugly stepchild. It carries negative connotations—connotations that something is broken and will cost a lot to fix. In challenging economic times, the maintenance organization is frequently the first to experience cuts in an attempt to improve profitability. Enterprises have come to the collective realization that this attitude can be self-destructive. As a tool in the asset-performance management toolbox, reliability solutions enable enterprises to optimize asset availability and utilization while mitigating exposure to risk. PAULA HOLLYWOOD, senior analyst at ARC Advisory Group, has been covering field instrumentation and other automation technologies for over 30 years. At present, she focuses on enabling technologies and strategies for industrial asset performance management. Prior to ARC, she held various technical and marketing positions at The Foxboro Company, Krohne America and Kentrol, Inc. Ms. Hollywood has a BS degree from Northeastern University and an MS degree from the University of Massachusetts in Boston.

Hydrocarbon Processing | AUGUST 201237


| Special Report FLUID FLOW AND ROTATING EQUIPMENT The hydrocarbon processing industry (HPI) is a vast steel and metallurgical network involved in the receiving, moving, reacting, separating, heating, cooling and storing of hydrocarbon feedstocks, byproducts and finished products. For all purposes, an HPI facility is really a closed system; it is designed to keep the product streams “in” and the external compounds and elements “out”. HPI operating and storage facilities are fluid systems designed to function safely and reliably. Fluid-flow systems are comprised of pumps, compressors, valves, turbines, motors, piping and flowmeters. In August, the special report articles investigate the numerous issues regarding the design, installation, maintenance and operations of fluid-flow systems to ensure maximum uptime and to mitigate leaks or emissions.


Fluid Flow and Rotating Equipment

Special Report

H. P. BLOCH, Reliability/Equipment Editor

Modernize your compressor lube- and seal-oil systems terest that Note 1 (see FIG. 1) also alerts purchasers to locate the suction piping away from reservoir low points where dirt can easily accumulate. A reliability-focused user will take a very active part in the selection and design process for these compressor-support systems. An infinite number of component combinations are possible, and user preferences will be discussed in this article. Guidance can be found in various API specification documents. However, the instrument nomenclature chosen by vendors and manufacturers often differs. TABLE 1 is one of many hundreds of feasible listings of instruments typically found on lube- and seal-oil systems. The owner-purchaser’s engineer must understand the purpose and functionality of each of these elements.

Auxiliaries are responsible for more downtime events than the main components of a compressor. To improve unit reliability, auxiliaries deserve closer scrutiny; unfortunately, they are often upgraded from the traditional vendor’s standard configuration. Compliance with an applicable American Petroleum Institute standard (API-614) is helpful. However, engineers should remember that various API standards are intended to explain the minimum requirements. Minimum requirements are not to be confused with best available technology. As of 2012, only a small percentage of the many thousands of centrifugal compressors operating in modern industry were equipped with magnetically suspended or gas-lubricated bearings. The overwhelming majority of compressors continues to use oil lubrication for bearings that either support the compressor shaft (radial bearings) or limit shaft axial movement (thrust bearings). This article deals with these lubrication systems only. It will emphasize factors that are commonly overlooked.

Low-pressure alarm

TSH

High-oil temperature alarm and shutdown

TCV

D

D TIC

PDI

PD SH

Driver

TCV

TIC

Low-pressure shutdown

Optional

Alarm

D TI

TI

TI

FG

FG

V V

V V

FG

Cooler

Cooler

PCV D D Main pump running alarm

D D TI

PSH PI

D

FO PSV

Standby pump

EXAMINING UPGRADE OPTIONS Oil reservoirs must include valve and space provisions for temporarily or permanently connecting oil purifiers to the low-point drain. In addition to removing water contamination, modern oil purifiers will also remove undesirable gases from the seal oil. If both drivers are electric motors, different feeder connections are recommended by API-614. It should be of in-

Start standby pump

V

V

D

PS LL

PI PSL PSL

TSL TI

Compressor and gear unit

TS HL

Filter

migration from the pressurized compressor interior volume (the compression space) toward the bearings. These seals are available in a variety of configurations, and most seals require oil as a coolant and lubricant. The auxiliary systems that feed oil to the bearings and seals are often combined, in which case, they are aptly called lube- and seal-oil systems. Separate systems are more common and are required if the seal oil is contaminated by entrained “sour” gases, such as hydrogen sulfide. FIG. 1 shows a simplified schematic of a plain lube-oil system. Several of the most common system instruments are also listed in FIG. 1.

Filter

Seal purpose. Seals are used to prevent

LAYOUT GUIDANCE All systems must be properly laid out, and supply piping sized for maximum velocities that do not exceed 7 fps (ap-

Mist eliminator Fill connection Manhole

PSV

PI Main pump

Maximum operating level Minimum operating level TI

LG Suction loss level

See Note 1

Baffle when required

LSL Alarm

ES TC

Electric heater

Steam coil optional

1½-in. minimum blind-flanged drain connection

FIG. 1. The simplified, but typical, compressor lube-oil system includes many auxiliary components in addition to the compressor. The multi-unit systems require provisions to separate (to valve-off) one system from another. In the combined lube- and seal-oil systems with turbine drivers, the compressor’s outer seal-oil drain must be separate from the lube-oil drain. Hydrocarbon Processing | AUGUST 201239


Fluid Flow and Rotating Equipment proximately 2 m/s). Stainless steel (SS) is used for all piping, both upstream and downstream of the filters. SS is also needed for vessels, housings, tanks and their respective tops. Only certain valves and a few instruments are (possibly) exempted from this requirement. With high reliability being the first and foremost goal, all supervisory and control instrumentation elements should include stainless steels. Cost-cutting has made inroads here, although some “savings” are false economy that will often cost more later. To avoid unavailability, here are some of the key areas to address: • Access to major hardware and instruments should be easy. • Filter housings must be vented to a safe location. After replacing a filter, air must be vented to ensure that the standby TABLE 1. Typical instrumentation found on lube- and seal-oil systems AS

Air supply

FI

Flow indicator

FO

Flow orifice

FSH

Flow switch high

FSHH

Flow switch high high

FY

Solenoid valve

HCV

Hand-control valve

LCV

Level-control valve

LG

Level glass

LSL

Level switch low

LSH

Level switch high

LSHH

Level switch high high

PDCV

Pressure differential control valve

PDI

Pressure differential indicator

PDIC

Pressure differential indicator controller

PDT

Pressure differential transmitter

PDSH

Pressure differential switch high

PDSL

Pressure differential switch low

FIG. 2. In this accessible skid-mounted lube-oil system, the filters are in the right foreground; the coolers are horizontally arranged on the left.1

40AUGUST 2012 | HydrocarbonProcessing.com

filter housing is ready for operation. Venting back to the oil reservoir is allowed. • With the possible exception of valves, all oil-wetted parts of the lube-oil system (but not the pumps) should be made of SS. The top lid of the oil reservoir must be made of SS; moisture condensation can accumulate on this cover. • The switch-over valve directing oil through either the “A” or the “B” filter-cooler set must incorporate provisions to lift its plug off the valve seal before the plug can be rotated in the desired direction. • If the top lid is made of plain steel, the resulting rust (on the inside) will reduce equipment reliability or require increased preventive maintenance. A nitrogen “blanket” to fill the space between the liquid oil and top lid will not be a fully effective method to prevent rust on plain steel top lids. • The top lid is slightly inclined to allow rainwater and spilled oil to drain. Pipe connections and access ports (manways) are flanged with top openings raised at least 1 in. above the reservoir top, and no tapped holes are allowed anywhere on the reservoir. • All fill openings must be provided with removable strainers. • Integral internal relief valves are permitted on rotary positive displacement pumps. However, only external relief valves are permitted on pressure vessels. A small- to mid-sized lube skid is shown in FIG. 2. The photo depicts two horizontally arranged rotary positive displacement lube pumps, which have been sized for oil requirements that include unusual upset conditions. When both pumps are motor-driven, different feeders or a DC supply source are generally specified. The direct-current source must last as long as it takes to secure the main compressor and manipulate all associated valves. Note how the principal components are readily accessible, as shown in FIG. 2. The suction pipes must be arranged to provide positive suction head for these horizontal pumps, with the line sloped down from the reservoir to the pump. While this recommendation is sometimes contested by pump manufacturers, it will allow gas to be vented back to the reservoir. To rule out unexpected surprises and the occasional fingerpointing, the compressor manufacturer must be directly responsible for the design, although the manufacturer often asks third parties to fabricate and test the entire skid.

EXAMINE WHAT OFTEN GOES WRONG Reliability-focused users specify lube- and seal-oil systems that comply with the applicable standards of the American Petroleum Institute (API-614). These standards constitute a detailed and enhanced bill of materials, as well as a description of the redundancies required to ensure years of uninterrupted uptime to such systems. Appropriate instrumentation must be provided. An experienced compressor operator should be involved in selecting these instruments and determining their operator-friendly, optimum mounting locations. Ease of maintenance and accessibility compete with the desire to keep things compact. A measure of judgment must be exercised by both the purchaser and vendor. With few exceptions, systems that do not comply with API standards will require more frequent maintenance. Regardless of the standards applied, the purchaser should review several pertinent details, as listed here:


Fluid Flow and Rotating Equipment Main vs. standby pump. Pumps must be centrifugal or rotary positive displacement. Driving off the main driver or compressor shaft is rarely acceptable, because pump failure would mandate equipment shutdown. If two or three pumps are used, at least one is usually driven by a small steam turbine. Pumps must have carbon-steel casings, and cast-iron casings are allowed only inside the reservoir. Exposed cast-iron pumps would be brittle and more prone to failure when involved, directly or indirectly, in a fire event. A decision must be made as to which pump is normally on standby (although the turbine-driven pump is usually selected for standby duty). Still, someone must define how quickly the turbine will come up to speed and reestablishes the required oil pressure. The correct electrical classification must be selected for motor drivers. Suitable electronic governors should be chosen even for small steam turbines. If the steam turbine driven pump is in standby mode, it should be kept warm and “slow-rolled.” But slow-rolling consumes energy. Some bearings will not allow slow rolling at speeds below 100 rpm. Pumps being slow-rolled should have a return line with a restriction orifice back to suction, and dewatering of piping and steam turbine casing must be accomplished by using the right steam trap type and model. Standby equipment deserves more attention than it usually seems to receive. Pumps and their respective driver shafts must be easy to align.2 Couplings should be designed with a service factor of two or more, and they must be virtually maintenance-free. The start switch or actuator component for the auxiliary pump must have a manual reset provision. A steam condensate exhaust hood will be needed for steam exhaust lines vented to atmosphere. Without it, operators risk being showered with scalding water whenever the auxiliary steam turbine-driven pump kicks in.

overhead rundown tank should be provided to gravity-feed the turbomachinery bearings. A pressurized overhead tank is shown in FIG. 3, but nonpressurized (atmospheric pressure) tanks are quite often used as well. An atmospheric breather valve or vent must be used with nonpressurized models, and the user-purchaser must address issues of airborne dirt and birds trying to build nests in or near such vents. A drilled check valve is then used between the lube supply header and atmospheric pressure overhead rundown tank. Regardless of the type of rundown tank selected, elevations should be such that the static head is less than the equipment lube-oil trip pressure. API-614 gives guidance on these and other important matters dealing with lubrication, shaft sealing and control oil systems for special purpose applications. The anticipated time needed for the machine to coast to a stop is 8 minutes, with 15 minutes used as a more conservative limit. This rundown tank should be vented, and the vent oriented and configured to prevent entry of birds and debris. Does the overhead rundown tank need to be heated or insulated for operation in cold weather? Are suitable auto-start facilities provided? Designers should verify that proper dewatering facilities are provided at all points of the steam piping and at the turbine casing. In installations with two electric motor-driven pumps, the power should come from different feeders or substations. Temporary power dips during the pump switch-over are bridged by using a hydraulic accumulator in the lube supply line. The bladder of the accumulator is usually filled with nitrogen, and the configurations and functionalities of such acCharge gas

Slow-roll precautions. For some steam turbine models, slowrolling below 150 rpm will not allow establishing an oil film between the journal and bearing bore. Also, consideration must be given to an emergency oil source to be fed to the turbocompressor train during an occasional power failure event. If there is even a remote possibility of neither oil pump being available, an

PI

Bladder

Float-type check valve FG LI

Accumulator tank

Shut-off device Drain to reservoir

Oil out Lube-oil supply

To equipment

Vent

Oil in

To reservoir or drain header

FIG. 3. Pressurized overhead rundown tank for centrifugal compressors lists the instrumentation.3

FIG. 4. Bladder-type accumulator (left) and a rod-equipped “surveillable” diaphragm-type accumulator (right).5 Hydrocarbon Processing | AUGUST 201241


Fluid Flow and Rotating Equipment cumulators are well known. Yet, although widely used, typical bladder-type accumulators (FIG. 4, left side) risk premature failure from the rubbing action of the neoprene or buna-rubScrew plug Seal ring

Diaphragm Steel shell Shut-off button

ber bladder against the accumulator walls. This failure risk is further amplified when dirt particles are carried in the oil.4 Diaphragm-style accumulators (FIG. 4, right side) were used in reliability-focused user companies after 1975 to facilitate condition monitoring and to avoid rubbing-induced failures. Note: The standard diaphragm-type accumulator (FIG. 4, right) is fitted with a vertical indicator rod and a transparent dome at the top. Reliability-focused plants modify the standard diaphragm accumulator, as shown in FIG. 5, by removing the seal ring and screw plug and tightly fitting a tall transparent high-strength plastic dome at the top of the accumulator. A tapped hole is machined into the center of the shut-off button and a long “gauge rod” is threaded into this tapped hole. The gauge rod extends through the opening created by removing the screw plug. The tip of the gauge rod is seen by the operators making their surveillance rounds. The integrity of the flexible diaphragm and its properly proportioned nitrogen vs. oil fill volumes are visually ascertained, as shown in FIG. 6, which shows a large field installation. The wire-mesh screens are installed to guard against a careless overhead hook or a maintenance tool accidentally hitting the polycarbonate sight-glass dome. If bladder-type accumulators are deemed acceptable, be sure that they have a 10-second or greater capacity and are equipped with fill valves and isolation valves that permit monitoring of bladder condition. Bladderless accumulators will require highlevel alarm, low-level alarm and low-level cut-off provisions.

FIG. 5. Cross-view of the diaphragm-type accumulator.6

System reservoirs. An armored sight glass must be sup-

FIG. 6. Diaphragm accumulators installed at a best-of-class facility.

42AUGUST 2012 | HydrocarbonProcessing.com

plied for the reservoir. Because the reservoir should be constructed from stainless steel, its interior should not be coated or painted. Minimum standard practice calls for oil reservoirs to be sized for at least 2.6 minutes of maximum flow. A lubeoil system with pumps supplying 100 gpm would be sized for an operating volume of 260 gallons (1,000 l) or more. A more conservative high-reliability practice defines the system operating range as 2.6 times gpm, to which the greater of 40 gallons or one week’s oil leakage rate is being added. Other rules-ofthumb are noteworthy; one calls for an oil-free surface in the reservoir of at least 0.25 ft2/gpm to promote air disengagement from the oil. Oil reservoirs are typically rectangular and are provided with a sloped bottom, sometimes called a “false bottom.” The volume below the sloped false bottom is filled with a heattransfer fluid for pre-startup heating or for maintaining a controlled temperature. The volume above the false bottom is, of course, the actual working volume of the oil reservoir. Convention calls for a reservoir vent to be one pipe size larger than the sum of the areas of all seal drains. In installations where steam is available, a thermal fluid with high-temperature capability and low volatility should fill the space below the sloped bottom. If no steam is available, electric heaters sized not to exceed 15 watts/in.2 (the “watt density”) can be used to heat the thermal fluid. Electric temperature control switches should be provided if electric heat is selected. A high-capacity vent is needed to accommodate thermal expansion of the heat-transfer fluid below the sloped bottom of an oil reservoir. A side-mounted gauge glass or dipstick is required to verify or to monitor the height of thermal


Fluid Flow and Rotating Equipment fluid under the false reservoir bottom. If a steam coil is used for heating, there should be suitable steam traps. Heating requirements. In some climates, heating will be

needed only at startup or in low-temperature ambient conditions. Heaters are generally sized to effect heating from the lowest average ambient to a minimum allowable oil temperature—73°F (20°C), for the very typical ISO VG 32 lubricant—in four hours. It is possible to pre-heat the lubricant by simply admitting steam into the water upstream of the coolers. However, temperature indicators should be installed, and a responsible operator must be assigned the task of emergency heating operation. For cold-temperature regions or in situations where large ambient temperature swings are common, the reservoir may require external insulation. Such insulation has the associated benefit of reducing condensation of water vapors in the reservoir. The return oil from the turbocompressor may be at sufficiently elevated temperature to flow freely without further heating. The drain valve at the low point of the working volume serves also as a connection for an onstream lube-oil purifier. Such purifiers are normally sized to handle the entire system’s working volume in 24 hours. They must be provided with a piping leg that prevents emptying the reservoir. Some will also require a condensate-removal line. All reservoirs must be fitted with internal baffles or stilling tubes that allow for contaminants to settle out. Oil returning

from the turbocompressor bearings or bypassed from the pressurizing pumps should not fall into the reservoir; this would risk static electricity buildup. The vents from filter housings and other points in the installation should feed back into the reservoir. Filters and coolers. Suitable instrumentation is also need-

ed on the filters and coolers. The layout should permit the system to operate while maintenance personnel are safely performing routine service on nonoperating redundant elements. Except for the transfer valve (main switching valve) and the structural parts of the mounting skid, stainless steel is the required material of construction. Block valves and check valves are needed, and the user-purchaser must devote time and effort to review the piping and instrumentation diagram for functional completeness. Kickback valves that route excess oil back to the reservoir must be located upstream of the filters and coolers. They should be sized to pass excess capacity of one pump plus the full capacity of the standby pump. Dual valves may be needed to obtain proper valve coefficients in certain seal systems. It is usually considered a good move to involve plant operators in the selection process before specifying and purchasing filters and coolers for an existing facility. Blotter paper-style filter cartridges are not acceptable. Allow the operators to ask if they are satisfied with the instrumentation package as shown on the schematics, or on a mockup of the system. Obtaining buy-in from operations staff at this stage will provide great value.

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Fluid Flow and Rotating Equipment TABLE 2. Material selection for heat exchangers used on compressor lube skids Channels and covers Shell Carbon steel

Tube sheets

Tubes

Materials

Specification

Materials

Specification

Materials

Specification

Acid-resisting bronze or aluminum bronze

ASTM B 143 Alloy 2 A

Naval brass

ASTM B111 ASTM Alloy 464

Inhibited

ASTM B111 Types 443, 444 or 445

ASTM B169 Alloy 614

Normally, coolers are bought in compliance with TEMA Class C shell requirements and have removable bundles. Experienced users will not permit tubes with less than 5⁄8-in. OD 18 BWG, but will allow double pipe fin-tube exchangers for small systems. It is usually best to make an experience check and to ask questions. Unlike pumps, coolers are pressure vessels that must be designed and manufactured in accordance with applicable codes. Water should be on the tube side, oil on the shell side. The oil pressure must exceed cooling water pressure to prevent—or at least reduce—leakage of water into the oil system in the event of tube failure. The oil-side design pressure should be equal to, or greater than, the pump relief valve setting with PD pumps and shutoff pressure with centrifugal pumps. TABLE 2 summarizes the material selection guidelines. Each cooler must have an oil fill line, a drain and a highpoint vent—all suitably valved and generously sloped. Cooling water flow enters at the bottom and exits at the top. Drain piping is typically sized for a maximum velocity of 1 fps (approximately 0.3 m/s). High-pressure gas piping should be seal welded, and all piping should be configured to allow for thermal expansion. Remember: The piping may have to be removed for cleaning prior to compressor commissioning. Flanges and special locations (such as near bearings and seals) are required to insert temporary strainers. Flexible expansion joints are not allowed in the piping due to the danger of fatigue failure. Flexible joints and hoses are also not allowed because they tend to be the first stationary elements to fail during a fire. To facilitate oil drainage back to reservoirs in gravity systems, each compressor bearing housing typically requires a 1-in. minimum vent. Gear boxes and couplings are generally equipped with 2-in. vents. Coupling guards may require special air exchange provisions to prevent trapped air from overheating the coupling components. Centrifugal compressor lube/seal reservoir hazards. The static electric charge generation mechanism was investigated by prominent users in the mid-1970s. Static charge buildup in filters was determined to be the root cause; it was confirmed by careful measurements. Several systems that had experienced explosions were equipped with pressurecontrolled recycle lines downstream of the seal-oil (or lube/ seal-oil) filters. In obvious contrast, systems with recycle lines originating upstream of the filters and with line lengths that allowed relaxation of charges remained trouble-free. Safe designs allow 30 or more seconds for the oil to travel from the filter outlet to the reservoir inlet. Because undesirable agitation of the oil surface must be avoided, the return line should enter the reservoir below the oil level. Pressurized return lines should not be vented inside the reservoir. 44AUGUST 2012 | HydrocarbonProcessing.com

Admiralty

Seal-oil system gas reference lines should be provided with a drilled check valve to prevent disruption of overhead accumulator level control during compressor surge. There is also a need for provisions that allow introduction of a simulated gas signal (sometimes called a “false buffer gas”) during startup when running a compressor on air, or with a suction pressure below design. These provisions may require control systems that can fully accommodate prevailing running-in conditions.

WHAT WE HAVE LEARNED Lube- and seal-oil systems must be carefully and conservatively designed. A review of the system design and limitations must begin at the proposal stage. The ownerpurchaser must thoroughly understand each design element. Each pipe or control line should be traced back to its origin, the design intent must be well understood, and all of the owner-purchaser’s questions must be answered by the vendor-manufacturer. Reliability-focused owner-purchasers go beyond the minimum requirements of API-614 in their efforts to impart the ultimate in maintainability and surveillability to these very important systems. Special diaphragm-style accumulators are one of many examples where reliability-focused thinking is translated into component selection. They represent best available technology and have been used by best-of-class companies for many decades. ACKNOWLEDGMENT This article is based on the book entitled, Compressors: How to Achieve High Reliability and Availability, authored by Heinz Bloch and Fred Geitner. The book was released by McGraw-Hill. LITERATURE CITED IMO-Demag-DeLaval, Trenton, New Jersey, Commercial Literature, 1991. 2 Bloch, H. P., Pump Wisdom: Problem Solving for Operators and Specialists, John Wiley & Sons, Hoboken, New Jersey, 2011. 3 American Petroleum Institute, “API Standard 614.” 4 D’Innocenzio, M., “Oil Systems—Design for Reliability,” First Texas A&M University (TAMU) Turbomachinery Symposium, College Station, Texas, 1971. 5 Bloch, H. P., “Making machinery surveillable—Part 2,” Hydrocarbon Processing, July 1993, p. 23. 6 Doddannavar, R. and A. Barnard, Practical Hydraulic Systems, Elsevier Publishing, Burlington, Massachusetts, 2005. 1

HEINZ P. BLOCH is a consulting engineer residing in Westminster, Colorado. He has held machinery-oriented staff and line positions with Exxon affiliates in the US, Europe and Japan prior to retirement as Exxon Chemical’s regional machinery specialist for the US. Mr. Bloch is the author of 18 comprehensive texts and close to 500 other publications on machinery reliability improvement. He is also the reliability and equipment editor for Hydrocarbon Processing. He is an ASME Life Fellow and maintains registration as a professional engineer in Texas and New Jersey.


Special Report

Fluid Flow and Rotating Equipment G. WILKERSON, Victaulic, Easton, Pennsylvania

Utility piping: Why over-engineering is inefficient Refineries built in the 1950s to 1970s used all welded piping for both process and utility services. The specifications used during that time are often applied to retrofits, expansions and turnaround projects. But this reliance on the traditional specifications does have a downside. Scheduling, safety and constructability are three major factors in turnarounds. They are also the impacting factors that affect welding activities. However, alternatives, such as grooved mechanical piping, have been slow to gain acceptance due to the perception that the joining method won’t work and a reluctance to use a gasketed joint. This article will compare the primary pipe-joining methods—welding, flanging, threading and grooved—and discuss the advantages and disadvantages of each method as used in the hydrocarbon processing industry (HPI). The misconceptions over grooved piping will be explained and corrected, and how this method can speed project completion, and improve constructability and safety, making it an ideal pipe-joining method for plant utility services.

HISTORY OF HPI PIPE JOINING During the wave of refinery construction in the 1950s to 1970s, over 99% of the HPI facilities elected to weld all piping. Everything was based on process piping. Even utility piping systems were designed to the same material class as process piping. Many engineers didn’t differentiate between piping classes. Nonprocess piping was over-engineered and overconstructed for perceived safety reasons. At present, during retrofits, expansions and turnarounds, the specifications of the mid-20th century are still used. There is a mindset of “if it ain’t broke, don’t fix it.” Welding is certainly not broken. But when it comes to utility piping, it may not be the best choice, given this method’s shortcomings as it relates to construction, maintenance and safety. Reliability and maintainability needs. Several factors that are important during construction projects typical of existing refineries and chemical plants include: • Schedule • Safety • Constructability, reliability and maintainability of equipment and systems. Whereas welding is typically very reliable when performed by an experienced and highly skilled welder, the method does not promote quick project completion. It lacks in the constructability and maintainability of piping systems, and is inherently unsafe, particularly in the presence of volatile, toxic

and explosive chemicals. It’s also simply unnecessary for lowrisk, nonprocess oriented utility services such as domestic water, plant water, plant air and compressed air. Other major pipe-joining methods also have their challenges.

PIPE-JOINING PLAYERS Other methods equally have their pros and cons in plant piping systems: Welding. This pipe-joining method produces a high-strength,

permanent joint, which is usually very reliable. With the ability to use the joining method on just about any piping service, welding has become the standard by which all other methods are compared. The strength and reliability of welded joints are essential for critical high-temperature, high-pressure process piping. However, for utility services, welding’s disadvantages outweigh the advantages. Safety. First, safety concerns are considerable during welding activities. Welding by its very nature is dangerous. It is one of the most dangerous industrial activities. When welding is done in a potentially volatile environment, the risks become even greater. Welding produces flames, sparks and fumes; all introduce the risk of fire or explosion. Welding requires a fire watch during and following the work, which can slow the construction schedule. Furthermore, welding exposes workers to noxious fumes and particulate matter, as well as potential burns and eye damage. Time-consuming activity. Second, welding is a timeconsuming process. Welders must cut, bevel and prepare the pipe lengths; align and clamp the joint; and then undertake two, three or more passes using the selected welding method at each joint. A single 4-in. carbon steel pipe joint can take up to 2.25 hours to weld; a 12-in. joint can take 4 hours or longer, based on values found in the Mechanical Contractors Association of America’s Labor Estimating Manual (Rev. 2/98). Once the weld is complete, an X-ray may be required for quality inspection. In the case of a failed X-ray inspection, the re-work increases facility downtime. The challenges, time and risk associated with welding galvanized pipe are even greater. Complex method. Third, the maintenance of a welded system is difficult. Welded systems convert individual pipe sections into a single unit, making it much harder to access a specific point within the system. If not accessing a welded system at a flange, the pipe would have to be cut in place to provide access. Skill shortage. Finally, the quality of welding is declining. Many of the highly skilled welders with years of experience are reaching retirement age. The need for welding is unlikely Hydrocarbon Processing | AUGUST 201245


Fluid Flow and Rotating Equipment to drop as quickly as the number of skilled welders available to do the work. Result: A shortage of skilled labor is quite possible, which could affect the quality of work. Allocating skilled labor to critical process systems and using alternative joining methods for noncritical utility systems are strategies to mitigate this challenge. Flanging. This pipe-joining method is a mechanical method that uses a series of bolts and nuts to compress a gasket between two flat-faced, flanged pipe ends. Flanging also produces a strong and reliable joint. Unlike welding, it provides a means for system access, but requires more maintenance to support joint integrity. Union maintenance. The bolts and nuts of a flanged union and gasket absorb and compensate for system forces. Over time, the bolts and nuts can relax due to surges, system working pressure, vibration and expansion and contraction. When the bolts lose tension, the gasket can “slip,” which can result in a leak. Flange gaskets can take on compression over time, also resulting in leakage. To prevent or stop leaks, routine bolt and nut tightening is required. Galvanization. Joint integrity may also be affected by the galvanization process. Under normal process conditions, galvanization may result in a zinc buildup on the flange, thus producing a flange face that is no longer flush. Such conditions can cause the flange to be more prone to leaks. Although flanges provide system access, performing maintenance can be a time-consuming process because each of the

bolts needs to be loosened and removed. In some cases, the gasket needs to be scraped off the flange and then replaced. The same bolt-tightening sequence required upon initial installation is also required upon reconnection of the flanges. Welding issues. Finally, because flanges are typically welded onto the pipe ends, this method carries the same issues associated with welding, including safety risks and lengthy installation time. Threading. In threading, a process that is typically used to join small-diameter pipe involves cutting conical spiraling male or female channels into the inside or outside of pipe or mating components. The joint is quick and simple to assemble. However, it is the least reliable compared to the other pipe-joining methods. Threaded joints are notorious for leaks, which can result from improper initial installation and ongoing plant operations that weaken the threaded seal. System vibration can compromise the thread tape or sealant, resulting in a leak. Poor thread cuts can also cause leaks. In a threaded system, the leak is usually “fixed” by tightening the joint. The problem with this solution is that tightening one end of the threaded joint ultimately loosens an adjacent joint, so fixing one leak may lead to a new one. Threading joints can present alignment issues with branches and elbows. In addition, the joints are difficult to repair. Over time, the joint may become fused, making system access more challenging. Many refineries have experienced problems with threaded small-diameter galvanized piping. They are replacing these systems with stainless steel (SS) systems. The final method is the grooved mechanical piping. It is widely known and highly regarded in the upstream oil and gas industry. However, grooved mechanical piping is relatively unknown and, in some cases, misunderstood on the downstream side.

ANATOMY OF A GROOVED JOINT A grooved mechanical joint is formed with grooved-end pipes, fittings or valves, and a coupling, as shown in FIG. 1. The coupling comprises three elements: gasket, housings, and nuts and bolts.

FIG. 1. A grooved mechanical joint is formed with grooved-end pipes, fittings or valves and a coupling.

FIG. 2. A small portion of the pipe wall is displaced to form the groove around the outer diameter of the pipe.

46AUGUST 2012 | HydrocarbonProcessing.com

Grooved pipe. Grooved mechanical piping does not require special pipe. Standard, off-the-shelf pipe is fabricated by coldforming or machining a groove into the pipe ends. There are two types of grooving: roll and cut grooving. Roll grooving is far more common, and is the preferred method for most utility services. To form a roll groove, the pipe end is placed between the roll set of a grooving machine. As the roll set closes, the pipe is compressed and rotated, which radially displaces a small portion of the pipe wall to form a groove around the outer diameter of the pipe that is recessed on the outside and indented on the inner pipe wall, as shown in FIG. 2. Unlike threading, roll grooving does not remove any material from the pipe. A fast and clean technique, roll grooving is used on a variety of pipe sizes and wall thicknesses, from Schedule 5 through ANSI standard wall thickness carbon steel (CS) and SS, copper and aluminum pipe. Roll-grooved systems range in diameter from ¾ in. up to 60 in.


Fluid Flow and Rotating Equipment Gaskets. To seal the joint, a resilient, pressure-responsive

elastomer gasket seals around two abutted grooved pipe ends. The nitrile gasket, which is common in most water with oil vapor applications, is injection-molded to precise tolerances and is resistant to aging, heat and oxidation.

to similar cold-forming manufacturing operations. Any potential increase in pipe hardness, reduction in tensile strength, or reduction in elongation due to the roll-grooving process has no effect on the pressure capability of the joint. The pressure rating of a grooved system—established after extensive performance barometers including ultimate pressure, bending moment and cyclic loading tests—is based on the components of the joints. Grooved pipe has no rating without the corresponding coupling, and coupling pressure ratings vary based on the pipe material and wall thickness. The published maximum rated pressures for couplings are based on test data and field experience. Any effect that roll grooving has on the pipe material has been accounted for in coupling pressure ratings.

Housings, bolts and nuts. The coupling housings fully enclose the gasket, and the key sections of the housings engage the grooves. The housings are typically constructed from ductile iron (painted or with engineered coatings), SS or aluminum. While the housings are exposed to the external environment, they are insulated from the system media by the coupling gasket that contains the fluid within the interior of the pipe. The bolts and nuts, which hold the housings together, are tightened with a socket wrench or an impact wrench. The critical factors that impact In the installed state, the coupling housings enconstruction projects for existing case the gasket and engage the groove around the circumference of the pipe to create a leak-tight seal refineries and petrochemical plants are: in a self-restrained pipe joint. With the availability of schedules, safety concerns and practices, rigid and flexible couplings, a grooved joint can be completely rigid, like a welded joint, or offer flexibiland the constructability, reliability and ity to accommodate thermal expansion and contracmaintainability of equipment and systems. tion, deflection, seismic movement and vibration. The housings of a rigid coupling positively clamp the pipe to create a rigid joint, resulting in system behavior characteristics similar to other rigid systems. Performance codes. Component performance requireThe piping remains strictly aligned and is not subject to axial ments for many piping applications are dictated by standard movement or angular deflection during operation. For this reacodes relevant to the service. To comply with the code reson, systems installed with rigid couplings utilize support techquirements, the piping materials must be able to maintain niques identical to those of welded systems when designed and published performance capabilities while in service. Based installed according to the hanger spacing requirements as noted on their proven performance capabilities, use of couplings on in the ASME B31.1 Power Piping Code, ASME B31.3 Process Pipgrooved pipe meets the requirements of ASME B31.1, B31.3 ing Code, ASME B31.9 Building Services Piping Code and NFPA and B31.9, as well as NFPA 13. 13 Sprinkler Systems Code. The suitability of grooved pipe for use in piping systems is Flexible couplings provide controlled linear and angular recognized in such standards as ASTM F1476, Performance of movement that may be used to accommodate linear moveGasketed Mechanical Couplings for Use in Piping Applications, ment due to thermal changes. It may be used at system changes and ANSI/AWWA C606, Grooved and Shouldered Joints. These in direction to provide stress-free offsets, or it may be used on pipe standards have been established in recognition of the traditional expansion loops, resulting in loops one-half to onewidespread use of grooved piping in air- and water-conveying third the size of a loop of welded construction. systems, and the subsequent need for sufficient clarity in the Couplings localize vibration within the pipeline, dampenperformance and dimensional requirements of grooved joints. ing the vibration of the system. Grooved piping systems do not Grooved pipe joining has been proven through research, require rubber bellows or a braided flexible hose, which can testing and extensive evaluation. Provided the coupling is wear out and require replacement. correctly installed—a process that is substantially easier than most other pipe-joining methods—the joint will not leak or fail as long as the working pressure of the system is within the MISCONCEPTIONS OF GROOVED PIPING coupling’s pressure rating for the type and thickness of the Unlike other industries that have readily accepted grooved pipe. With couplings currently rated up to 4,000 psi, grooved piping, HPI facilities have been hampered by a perception that pipe joining can be used on almost all utility services. the joining method won’t work and reluctance to use a gasketed joint. Fears exist that the coupling will leak or even fail, and that the grooving process weakens the pipe. These ideas have BENEFITS FOR UTILITY SERVICES arisen due to limited exposure to grooved piping systems. The There are multiple reasons why grooved mechanical piping concerns can be easily rectified by reviewing strength and presis an ideal choice for plant utility services. The three key benesure performance capabilities. fits are also factors that drive equipment and material decisions With regard to pipe end preparation, roll grooving does not in refinery expansions and turnarounds: compromise the integrity of the pipe joint. The inward radial • Ability to ease construction and maintenance displacement that occurs at the groove during the roll-groov• Speed project completion ing process causes pipe material property changes comparable • Improve safety. Hydrocarbon Processing | AUGUST 201247


Fluid Flow and Rotating Equipment

Press-to-connect systems Many plants utilize Schedule 40 or Schedule 80 threaded galvanized pipe for small-diameter systems such as compressed air lines. But like any utility service using threaded pipe, the systems are prone to leakage. In compressed-air applications, leaks can lead to problems such as inconsistent equipment performance due to fluctuating system pressure, increased energy and maintenance costs, reduced service life of the compressors due to excess load, and corrosion of the piping caused by moisture within the system. In addition to grooved piping, an alternative to threaded small-diameter pipe is a joining method known as press-to-connect piping. The press-to-connect systems join standard plain-end pipe by compressing a fitting onto the pipe ends, as shown in FIG. 4. The fitting, which con-

tains O-ring seals, is compressed onto the pipe, fitting or valve using a hand-held pressing tool, resulting in a permanent seal. Like grooved systems, it is a cold-forming process that does not require heat or flame. Press-to-connect systems also require very little pipe-end preparation, resulting in an extremely fast joint that meets ANSI Class 150 standards. When installed correctly, the elastomeric seal of a press joint dramatically reduces the likelihood of leaks compared to threaded systems. Press-to-connect systems can be used with off-theshelf Schedule 10S SS pipe up to 2 in. in diameter. Systems larger than 2 in. can benefit from the same constructability, schedule and safety features as larger systems by using grooved piping.

Number of employees onsite

Welded peak manpower Shift maximum manpower line

Peak manpower

Meet or beat project schedule

Mechanical construction weeks

FIG. 3. Grooved-joint piping can provide benefits in construction and turnaround projects.

Constructability. Ease of installation and maintenance

is one of the most appealing aspects of grooved piping. To assemble a grooved joint, two grooved pipe ends are abutted, the gasket is positioned over the joint, the housings are placed over the gasket, and finally, the bolts and nuts are tightened to secure the housings together. Welding and special tools are not required. Grooved systems offer 360° of rotational allowance for field flexibility, meaning alignment of the pipe by the bolt-hole index, as would be required with flanging, is unnecessary. Unlike other pipe-joining methods, visual inspection can confirm correct installation of most grooved systems. Metalto-metal bolt-pad contact confirms that the assembled joint is properly and securely installed, and no re-work is necessary. Couplings decrease maintenance time because, unlike flanges, they do not require regular retightening. A coupling holds the gasket in precise compression from the outside of the pipe joint. While the bolts and nuts of the coupling hold the housings together, the coupling itself is what holds the pipe together. Over the service life of the system, the nuts and bolts do not require regular maintenance and will not relax. 48AUGUST 2012 | HydrocarbonProcessing.com

FIG. 4. Press-to-connect systems join standard plain-end pipe by compressing a fitting onto the pipe ends.

Should access to the piping system be required for maintenance, expansion, alteration or equipment/component replacement, the coupling can be removed quickly, and with no special tools. Following completion of the work, the coupling can be reassembled just as quickly on the joint. Maintenance of grooved systems is far simpler than maintenance of welded, threaded and flanged systems. The ease of access allows piping systems to quickly adapt to changes in plant operations. Grooved is also beneficial for specialty applications such as lined pipe and galvanized pipe. Typical specifications do not allow torch cutting or welding lined pipe because it can compromise the integrity of the internal linings. As grooved systems are cold-formed, they meet the requirements of most piping specifications. Grooving the pipe does not have an effect on the internal coating. Furthermore, gaskets with a central leg that acts as a pipe stop protect the pipe ends from installation damage that can cause a holiday in the coating. As a result, grooved piping maintains the integrity of internal pipe


Fluid Flow and Rotating Equipment coatings. In fact, grooved is the only pipe-joining method that can ensure a holiday-free system. Grooved piping eliminates the disadvantages associated with welding and flanging galvanized pipe. Because welding is not required, no toxic fumes are created. Furthermore, there is no increased risk of leaks, as there would be with flanged due to leak paths created by zinc buildup. The fabrication and assembly of a grooved galvanized system are much quicker than other joining methods. Schedule. Another key factor during plant expansions, retrofits and turnarounds is the schedule. It is quite obvious that the shorter the downtime, the sooner the plant is online and producing revenue-generating products. Installation of grooved piping is up to 10 times faster than welding and up to 6 times faster than flanging. Although installation time will vary by installer, conservative estimates require approximately 15 minutes to assemble a 4-in. grooved joint and 45 minutes to assemble a 12-in. joint, a vast difference compared to the 2.25 hours and 4 hours required to weld joints of the same size. As shown in FIG. 3, the ease and speed of installation can reduce onsite manhours by up to 45% compared to welding. Safety. In the volatile environment of a refinery, any pro-

cedure that can reduce risk is worth exploring. In terms of pipe joining and maintenance, grooved is among the safest methods due to the elimination of hot work. Most injuries on

job sites occur via material handling, but the most significant risks are caused by fire and fume hazards. Because the assembly of a grooved pipe joint does not require welding, flame or heat of any kind, it can be installed by almost anyone. It does not require time-consuming X-rays of joints, purge gases, fire watches, hot-work permits, cutting/ grinding of weld bevels, tacking, slag cleaning or dealing with weld fumes, weld splatter and sparks, and welding cable trip hazards. No-flame grooved systems pose no fire or respiratory risk, do not necessitate increased ventilation, and often reduce or eliminate system cleaning and flushing. Better methods. The primary obstacles in the use of grooved piping are lack of knowledge and fear. As demonstrated, concerns regarding the strength of the system are unfounded, and awareness of the grooved system’s array of benefits can undoubtedly outweigh the reliance on traditional, inefficient joining methods. Grooved mechanical piping can offer improved constructability, speedy expansion, retrofit and turnaround completion, and also reduce safety risks. It is a quality pipe-joining method for utility services in any HPI facility. GRADY WILKERSON is vice president of oil, gas and chemical sales with Victaulic, a producer of mechanical pipe joining systems. He began his career with Victaulic in 1980 as a member of the West Texas Oil Metro Group in Odessa, Texas. Mr. Wilkerson holds a BBA degree from Texas A&M University.

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Special Report

Fluid Flow and Rotating Equipment A. ALMASI, WorleyParsons Services Pty. Ltd., Brisbane, Queensland, Australia

Consider new developments for variable-speed electric motors The major oil, gas and petrochemical operators use variable-speed electric motor drivers to drive process compressor trains, as shown in FIG. 1. A large electric synchronous motor is used for high-power applications. Because of the total shaft-line length of these large electric motors, dynamic issues and lateral vibrations are difficult problems. Resonance must be eliminated, and the lateral and dynamic exciting forces generated by the electric motor should also be minimized. The number of motor poles in a high-power large electric motor driver is usually selected based on the rotational speed. When the speed approaches 3,000 rpm, a two-pole design is applied. However, a higher pole count may be considered for various reasons. This choice is narrowed between a two-pole and a four-pole design. New challenges, recent developments, the latest mechanical issues and the main reliability factors for large variable-speed electric motor drivers in hydrocarbon processing plants are presented in this article.

DESIGN NOTES FOR LARGE ELECTRIC MOTORS A solid-steel round (cylindrical) rotor design is the most suitable technology for a large electric motor operating at high power and speed. High-alloy steel forging is used for the motor shaft, which contains milled axial slots for the field windings and damper bars. The design of the electric motor (rotor, stator, bearing, frame and cooling system) depends on the rating and speed range. The rotor volume is nearly the same for both the two-pole and four-pole options. Conversely, the longer and thinner shape of the two-pole rotor may

be less suitable for transferring a large torque and meeting the lateral dynamic performance requirements. The twopole rotor exhibits worse lateral vibration behavior compared to the four-pole rotor because of its design and frequency vibration component. The four-pole solution offers more stiffness and robustness demanded for transferring the entire string torque. Size issues. Large electrical motors are

typically two-pole synchronous motors with brushless excitation. The second option is a four-pole synchronous motor. The choice depends also on the converter technology. The four-pole rotor design choice implies a supply frequency of around 100 Hz for common compressor services.

This frequency level would be challenged with load commuted inverter (LCI) technology, due to the turn-off and inverse blocking capability of power thyristors. Although applications of 120 Hz are reported in the literature regarding LCI technologies, practical issues remain. Other concerns include possible thermal issues from increased magnetic losses inside the stator core. Conversely, a 100-Hz supply frequency can be easily and reliably obtained using pulse-width modulation (PWM) voltage source inverter (VSI) technology. Coil design. In small- and medium-

sized electric motors, the stator winding consists of formed coils, made of either round wire or flat turns. Each coil comprises multiple series-connected turns.

FIG. 1. Example of a large variable-speed electric motor. Hydrocarbon Processing | AUGUST 201251


Fluid Flow and Rotating Equipment As the rated phase current of the electric motor increases, the current flowing through each turn increases. Above certain power levels, the turn cross-section is so large that only one turn per coil should be used. Accordingly, formed coil-winding technology should be abandoned and Roebel bars used. The manufacture and assembly of Roebel bars (commonly used for large generators) require expensive/complex methods. Whenever possible, engineers should avoid Roebel bars and retain multi-turn coil windings due to economic and technological reasons. Adopting a high-phase-order winding design is beneficial. Generally, a winding can be split into two or more systems to maintain an allowable current value for each winding unit. In an application for an electric motor with 50 MW, 7 kV would yield a current higher than 3 kA if a single threephase design is used. Because of the high current level, a Roebel bar construction would be required. Conversely, splitting the winding into several independent stator sets (using four independent PWM-VSI converters in a four-pole motor) reduces the phase to one-fourth in a four-pole motor. Now the design is compatible with a coil-winding technology. This design also shortens the stator core length and reduces the coil axial dimension; all benefit the assembly and impregnation processes.

Malfunctions. In designing electric mo-

tors, all possible malfunctions and upset situations should be considered. Shortcircuit capability is important in electric motors. For example, electric motors should be designed to accommodate the short-circuit current caused by the commutation of the output bridge in which one machine winding is short-circuited. In large electric motors, these design considerations are critical: • The centrifugal forces acting on motor components • The mechanical strength of the rotating and static parts • The material selection for various parts. Special attention is required for complex systems and complicated components, such as the excitation system of a synchronous motor, under mechanical and dynamic loads. Load issues. Several factors limit the

power, load and speed ratings of large electric motors. They include: • Circumferential speed of the motor, particularly for synchronous electric motors with field windings and exciter machines • Rotor-dynamic considerations, such as the flexing of the long rotor and its bearing span • Maximum output power of the power electronic components.

FIG. 2. Example of a compressor driven by an electric motor via a gear unit.

52AUGUST 2012 | HydrocarbonProcessing.com

Internal part accessibility, e.g., borescope (boroscope) hole, is a new requirement for motors, and it has considerable effects on maintenance.

MECHANICAL ISSUES Sleeve bearings are commonly used in large electric machines. To meet the mechanical and dynamic requirements, two different bearing designs are used. Application depends on the power rating and operational speed range of: • Flange bearing • Pedestal bearing. Pedestal bearing designs are used for very large power ratings, e.g., long and heavy rotors at medium speed. The flange bearing design is used for smaller rotors operating at higher speeds. For a higher speed range, the flange bearing design is closed on top to form a solid block. It provides greater structural integrity and higher stiffness, but it also has disadvantages with accessibility of the individual electric machine parts. The next decision is selecting a twobearing or three-bearing design. The two-bearing design offers the advantage of a shorter shaft length, but the overhung masses (such as the coupling) on the drive end (DE) and the exciter on the non-drive-end (NDE) can impose restrictions on the second critical speed. Two-bearing designs require larger shaft diameters and larger bearing sizes. A three-bearing design results in a longer shaft length, but it allows the critical speeds of each rotor section to be adjusted individually. There is no general best choice. The decision should be made based on the optimized solution for each individual application. Jacking oil provisions may be required for a special speed range (for typical turn operations in the 200 rpm–1,000 rpm range). Some typical electric motor designs for various powerspeed ranges are: • Medium-sized motors—below 20 MW, with an operating speed range of 5,000 rpm–7,000 rpm. A block design is usually preferred. This design often uses three mid-flange bearings with a flanged exciter-rotor (usually with the exciter housing mounted to an NDE-bearing-shield). A three-bearing design maintains lateral natural frequencies at high levels, which is very useful for high-speed machines. • Large-sized motors—between 20 MW–50 MW with an operating speed


Fluid Flow and Rotating Equipment range of 3,000 rpm –4,000 rpm. An integrated base-frame design is preferred. It uses two mid-flange bearings and an overhung exciter—often an exciter stator mounted on a bracket. • Very large-sized motors—above 50 MW with an operating speed range of 2,000 rpm–4,000 rpm. A rigid baseframe is commonly specified. This design uses two bearings with bearing pedestals and an overhung exciter rotor (an exciterstator mounted on the base-frame). The listed examples are only typical designs. Because large electric motors are custom-made, some exceptions can be expected. An active magnetic bearing is an advanced bearing option. It could be used in special applications to improve reliability, to eliminate lubrication oil requirements, and to provide superior rotor-dynamic behavior. Cooling systems. The motor cooling system greatly impacts design. Selfcooled rotors with shaft-mounted fans increase the bearing span, which has a decisive impact on the lateral critical speeds of the rotor. For applications with wide speed ranges and certain torque characteristics, shaft-mounted fans cannot adequately cool the machine, especially in the lower part of the speed range. In large variable-speed electric motors, a forced cooling system is required. The cooling system is usually a totally enclosed water to air cooled (TEWAC) unit. The cooling system model and requirements (IC81, IC611, etc.) should be selected carefully and address the numerous details, such as ambient conditions and operating points. Large electric motors are typically horizontal TEWAC design in protection class E Ex(p), pressurized for operation in Zone 1 or Class 1 Div. 1 environments. When an electric motor is connected to the power system via a frequency converter, it performs very different from a line-connected condition. There are usually no motor inrush currents, no severe starting toque pulsations, no out-of-step pulling with overloading, and no acceleration problems. The behavior of a converter-fed electric motor becomes much like that of a DC motor (or a steamturbine driver). However, VSD systems present new challenges such as harmonic issues, different electrical-mechanical interactions and various issues associated with VSD auxiliaries.

MOTOR ROTOR DYNAMICS AND VIBRATION Optimizing the design of an electrical machine involves various engineering disciplines. The main focus is the electrical design of the machine, which directly impacts functionality and performance. Yet, with increases in the power, size and speed of the electric machine, the mechanical design becomes more important with regard to mitigating noise and vibration. When considering the motor rotor dynamics and vibration, these limits are usually specified: • Bearing housing vibration limits of 1.8 mm/s in all directions • Shaft vibrations. A 50-μm unfiltered displacement vibration peak-to-peak (pp). Sometimes, vibrations above 50 μ may be accepted for very large electric machines based on site-specific conditions. In special cases, 70-μm vibrations may not be considered excessive for some large electric machines when the source and reason for the vibration are addressed. • Run-out values (combined) pass the acceptance criterion of about 12 μm –15 μm, based on IEC standard. Vibration-related items. When concentrating on the vibration-related items of the machine design, there are two major mechanisms of lateral vibration excitation: • Mechanical unbalance of the rotor, including thermal unbalance • Electromagnetic forces. The mechanical unbalance is a l× excitation generated by unbalanced centrifugal forces in the rotating system. However, electromagnetic l×-forces can also be generated from an eccentricity in the rotor body due to the bearing axis. All other electromagnetic exciting forces are mainly of the 2× type, such as ovalization forces in the air gap, and stator eccentricity in relation to the rotor axis. There is also a slight excitation from the nonuniform cross-section of the rotor body due to unequally spaced winding slots. Early design considerations. In the early design phase, there is usually a lack of dynamic information. For example, the foundation has not been designed, and the coupling selection has not been finalized. For the electrical machine itself, some data of the nonrotating parts are interpolated or extrapolated from built ma-

chines or from experience. Preliminary analyses and parametric studies should be used. The vibration limits and study scope must be fixed before ordering the machine. Several recommended calculations should be done to verify the rotordynamic behavior of an electric motor; they include: • The static deflection curve of the shaft and load distribution on bearings, considering the effects from the supports, motor frame and machine base. • The natural frequencies and mode shapes, including separation from critical forward modes and more or less uncritical backward modes • Bearing temperature variations and bearing clearance variations • Unbalance response calculations (in-phase and out-of phase) for the main machine, exciter and coupling • Critical speed map (variation in natural modes with speed) to verify the speed range and separation margins • Foundation stiffness variation map, which gives only a rough estimate of the sensitivity against modal foundation stiffness. Tighter acceptance criteria with larger separation margins and tighter damping values are encouraged. In the early design phase, the examination of the rotor dynamics mainly concentrates on the l× criteria. Rotor natural modes are usually checked for the 2× range only to avoid resonance. Some design criteria for a good vibration design are: • Speed range (1× and 2×), including a separation margin, preferably free of resonance • Sufficient damping (particularly oil-film damping) for all modes between zero and upper limit of the 2× range • Separate rotor critical speeds from other structural and assembly resonances • Insensitive design for unbalance at various rotating parts, particularly coupling • Optimized number and axial locations of balancing planes to allow modal balancing. Detail-design criteria. In the detaileddesign phase, the rotor-dynamic model should be extended to the structural (nonrotating) parts, such as all possible components including the foundation and soil. Accurate nonsymmetric stiffness models for all of the nonsymmetHydrocarbon Processing | AUGUST 201253


Fluid Flow and Rotating Equipment ric components, particularly bearings, are necessary to obtain the proper analytical values as close as possible to the test results. Only a few commercially available finite element (FE) programs facilitate such accurate modeling and simulations. Tilt-pad bearings are always recommended for rotating machines and electrical motors operating above a speed of around 1,200 rpm–1,500 rpm. These are mandatory for high-speed ranges and can offer stable operation. For tilt-pad bearings, the non-diagonal elements are small, and more accurate natural frequencies and mode shapes can be obtained as compared to other bearing types.

Nonrotating parts issues. For largesize electric machines, it is usually difficult to obtain the operating speed region of the l× and 2× range completely free of resonance. Normally, the resonances of a rotor can be easily identified. This is more complicated for the nonrotating parts. For example, sheet-metal construction has numerous modes, and it is not easy to filter out the various vibration harmonics. An important indication of the relevant modes is the modal mass. Only modes with a sufficiently high modal mass are considered for structural vibration purposes. To identify all of the possible critical modes, an accurate vibration study that includes a detailed forced vibration

Large variable-speed electric motor drivers (50 MW to 150 MW and beyond), are required in modern large process compressor trains. The design of large variable-speed electric motor drivers should include new simulation procedures to mitigate vibration and increase reliability.

Allowances in FE models. The FE dynamic model normally reacts in a slightly stiffer manner than the real machine. This is because of the idealistically modeled joints, mounting points and other simplifications. Therefore, more attention should be paid to the separation margins between the natural frequencies and the next operating frequency or excitation frequency below the natural frequencies. The actual natural frequencies are usually lower than the calculated values. However, any inaccuracy could result in a considerable deviation of the analytical behavior from the actual vibration behavior. For example, the natural frequency of a large 60-MW electric motor, related to second-order resonance amplification in the stator structure, was calculated to be around 108 Hz (6,480 rpm). This mode was measured at a frequency of 121 Hz (around 12% higher) during a performance test. The difference was due to inaccurate assumptions for the core and winding stiffness. Simplifications in modeling can cause missed resonances and vibration problems. 54AUGUST 2012 | HydrocarbonProcessing.com

analysis is normally required. The most sensitive factor for this calculation is the assumption of modal damping factors for the individual modes. A comparison of the calculated and measured response values leads to modal damping factors of 1% to 3% for metallic structural systems, depending on the participation of the bolted connections or other damping elements for the mode shapes. For modes involving bearing-oil damping effects, soil-damping effects (foundation) and nonmetallic-elastic components (elastic flexible couplings), much higher damping effects (more than 10%) can be expected. For detailed electric motor dynamics calculations, sufficient accurate knowledge of the foundation is necessary. Many civil engineers provide only static stiffness values, which are not valid for use in supercritical foundation design. Usually, a frequency dependent modal stiffness should be provided. Civil engineers sometimes reduce the electrical machine to a lumped mass, and to some excitations with rotating forces located at the center of gravity of the machine. This may be more accurate than static

values. However, two significant items cannot be covered: • The structural part of the electrical machine is not a rigid body. The frame, combined with the supporting foundation structure, leads to individual stiffness values at each fixed point. • This assumption does not provide sufficiently accurate results (or even a correct indication) for the combined modes related to higher critical speeds excited by an out-of-phase unbalance. Stiffness calculation. Any simplified type of modal stiffness calculation can only be an approximation, due to the many parts of the structure or machine assembly that are extremely simplified, e.g., to a rigid body. Normally, the forced vibration from unbalance or from electrically excited forces without a resonance condition will stay within the specified limits. However, problems can occur when the foundation (or structure) has a significant impact on the natural modes of the foundation-machine system, or, in the worst case, when combined resonance conditions occur for the machine and supporting foundation (or structure). The most accurate way to do a vibration-performance calculation on the final foundation is to merge the FE models of the motor and foundation and then to calculate the combined dynamic response of the system. In practice, merging the FE models is difficult. The sharing of models and data is a common practice for vibration analyses of critical machine sets, such as large power-generation trains. Without the combined models, it is not possible for large electric machines to reach safe and convenient vibration levels. A good idea is to discuss this requirement with the vendor before ordering. This combined, final, dynamic analysis (including the machine, structure and foundation) could be included in the vendor scope, based on accurate foundation/structural data and complete machine details (“as built” data) as soon as the foundation design is completed. This combined dynamic simulation is actually the second detailed vibration simulation. It is used for the final verification. The first dynamic analysis should be done during the machine detail design phase, before the design of the foundation is available, to finalize/freeze the machine design.


Fluid Flow and Rotating Equipment TORSIONAL ISSUES IN ELECTRIC LCI-VSD DRIVEN TRAINS Always avoid the resonance condition of integer harmonics with relevant torsional natural frequencies within the operating speed range. For the non-integer excitation frequencies, intersections cannot usually be eliminated. In a typical VSD synchronous motor-driven train, disturbances are transmitted from the electric motor to the line side and vice versa. The air-gap torque is the product of the air-gap flux and stator current. This flux is mainly given by a constant quantity in the rotating coordinate system. Thus, the air-gap torque is composed of the same frequencies as the stator current. Based on experience, usually only the subsynchronous first mode of the train can be excited (via the electric motor). The fundamental torsional natural frequency is normally of primary importance. During resonance, this vibration mode is capable of facilitating large amplifications of the dynamic torque, which may result in the catastrophic failure of one or more train components. High-order harmonics may not be sources of train torsional excitation. From a Fourier analysis, the envelope of the Fourier coefficient magnitudes decreases as the inverse of the frequency. Thus, the biggest magnitudes for the torque are expected to be of a low order. The amplification of the higher-order natural frequencies is lower. Nonetheless, torsional higher harmonic order effects should also be considered in dynamic simulations and torsional study reports. The inter-harmonics may equal the resonance frequency of the first train shaft mode. The excitation magnitude of the steady-state harmonics is usually determined by the manufacturer of the converter. An excitation profile vs. driver speed can be expected for the integer harmonics. The non-integer harmonics are usually expected to have a relatively constant magnitude. For 6( fCM – fSL ) and 12( fCM – fSL ), approximately 2% and 1% of the motor’s rated torque, respectively, are commonly used as the expected excitation magnitudes for torsional studies. Sometimes, despite the fact that the inter-harmonic excitation torque of the 12× inter-harmonics is lower than that of the 6× inter-harmonics, both excitation

torque magnitudes may be assumed to be 1.5% of the motor’s rated torque. The 18( fCM – fSL ) and 24( fCM – fSL ) excitation magnitudes are usually less than 1%. Torsional study. A torsional modal damping of 1%–2% is usually used, based on experience (a torsional damping of around 1% for trains with metallic coupling and 2% for trains with flexible coupling using elastic elements). The effect of the modal damping should be analyzed in the sensitivity study. These steps are recommended for a torsional study: • Torque-transmitting elements are specified based on the static torque, torque ripples and transient torques. • The harmonic excitation generated in the air gap is transferred across the motor-rotor mass into the train. The dynamic response of the torque transmitting element is a function of the excitation torque and the amplification factor (AF). The AF is defined as the ratio of the response torque to the excitation torque. The amplification factor (for a torsional natural frequency) multiplied

by the torque amplitude of the corresponding excitation frequency from the VSD system can produce the maximum steady-state oscillating torques within the train element. • A Campbell diagram should be drawn. The torsional natural frequencies are shown as horizontal lines. Excitation lines (integer and non-integer harmonics) are also drawn. The intersections of the natural frequencies with the excitation lines within the operating speed range should be investigated. Coupling issues. Flexible coupling using nonmetallic elastic elements may present a change in the coupling’s torsional stiffness of more than 30% as a result of load variation, degradation and other nonlinear effects. This coupling requires an extensive sensitivity analysis to assess the torsional stiffness variation effects on natural frequencies, resonances and dynamic stresses. These variations could easily result in new resonances, unexpected dynamic behavior and fatigue cases.

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55


Fluid Flow and Rotating Equipment High-torsional-stiffness and metallicflexible couplings provide a more stable operation. Yet, even for these couplings, coupling torsional-stiffness variations in the range of 10%–20% have been reported. For larger and longer couplings, greater variations should often be expected. A torsional study should be completed, based on the minimum coupling stiffness. Even for metallic high-torsionalstiffness couplings (such as the multiple diaphragm type or multiple disc type), a 5%–8% variation (usually an increase) in the torsional natural frequencies could be expected as a result of coupling stiffness variation and its nonlinear effects. For higher-order harmonics, the deviations (natural frequency variations as a result of coupling stiffness changes) are usually lower. In various case studies, above the fourth harmonic, deviations of less than 2% have been calculated, resulting from the coupling stiffness variation, because the high-order harmonics are not sensitive to coupling stiffness. They are a function of the distributed system stiffness characteristics.

CASE STUDY The design of a large compressor-train electric motor driver with a rated power of approximately 70 MW and a speed range of around 2,500 rpm to 3,800 rpm is reviewed in this case study. A two-bearing tilt-pad pedestal-type design was chosen for this large, electric synchronous motor driver. The location of the first critical speed was designed to be 1,810 rpm (with a margin of around 28%) with a modal damping of approximately 1.4%. The second critical speed is located above the maximum operating speed at around 5,130 rpm (a margin of around 26%). The excited stator contracts laterally as a result of electromagnetic ovalization forces from the air-gap field. The 2× dynamic deformations of the stator assembly are transmitted through the electric motor base frame to the pedestal bearings and lead to high axial bearing housing velocities. Based on earlier dynamic simulations with a very simplified model of the foundation (using an approximate static stiffness), the vibration is slightly above the limit (around 1.9 mm/s). These high

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vibrations are related to a second-order resonance amplification of the stator system. Even a heavy base-frame design could not prevent these high vibrations. The shaft radial vibrations do not influence the motor rotor, because it is affected by resonance with the second natural frequency of the stator system. Accurate modeling of the foundation and a combined simulation of the electric motor and final foundation show a decrease in the axial vibration amplitudes stemming from increased stiffness of the combined motor and foundation frame (compared to the initial dynamic model). The final vibration values remain slightly lower than the limit (lower than 1.8 mm/s). The electric motor shows a satisfactory vibration performance in the combined motor/foundation simulation. Another commonly used action to prevent forced vibration transmission through such heavy-frame structures is the decoupling of the stator assembly from the frame structure. Designs for elastic stator support, which give adequate vibration isolation with sufficient stability of the positioning and force transmission, may be the only acceptable solution for some large electric motor designs. This solution will be required for future large electric motors (> 80 MW). LCI NDE DE fSL fCM AF 1× 2× FE pp VSI n VSD

NOMENCLATURE Load commutated inverter Non-drive end Drive end System line frequency Supply frequency from converter to motor Amplification factor Operating speed Two times the operating speed Finite element Peak to peak Voltage source inverter Number of modes to balance Variable speed drive

AMIN ALMASI is the lead rotating equipment engineer for Worley Parsons Services in Brisbane, Australia. He previously worked for Technicas Reunidas (Madrid, Spain) and Fluor (various offices). He holds a chartered professional engineer license from Engineers Australia (MIEAust CPEng– mechanical) and a chartered engineer certificate from IMechE (CEng MIMechE). He is also a registered professional engineer in Queensland and holds MS and BS degrees in mechanical engineering. He specializes in rotating machines, including centrifugal, screw and reciprocating compressors, gas and steam turbines, pumps, condition monitoring and reliability. He has authored more than 60 papers and articles dealing with rotating machines.


Special Report

Fluid Flow and Rotating Equipment U. BHACHU and J. FRANCIS, Canadian Natural Resources Ltd., Calgary, Alberta, Canada

Improve performance monitoring of your turbomachinery

4,100

T = 800

P = 0.5

P=1

P=2

P=5

P = 20

4,200

GENERAL TURBINE DATA In this case history, the equipment focus is a 2,000-kW back-pressure steam P = 10

application tool used widely in many industries to gather and analyze static and dynamic plant process data.

T = 750

4,000 T = 700 P = 0.2

3,900 T = 650

3,800

T = 600

3,700

P = 0.1

T = 550

3,600

T = 500

3,500

T = 450

3,400 3,300

P = 0.05

T = 400

3,200 Specific enthalpy, kJ/kg

Performance measurements of critical turbomachinery are very important to ensure reliable plant operations. Downtime related to unavailable critical equipment can cost the facility millions of dollars in lost production and maintenance. Steam turbines are one group of the most important prime turbomachines used commonly within hydrocarbon processing facilities. Overhauling of steam turbines is normally done during major planned outages and generally warrants including the original equipment manufacturer’s (OEM’s) expertise. Accordingly, online performance monitoring and establishing performance indices (PIs) for steam turbines are crucial when optimizing equipment reliability and plant availability. Performance of a steam turbine deteriorates due to various reasons such as deposition on steam-path components, erosion and damage to blades, leakage, etc. The American Society of Mechanical Engineers (ASME) performance test code (PTC 6) stipulates detail procedures when testing steam turbines. However, PTC 6 is not a cost-effective method for continuous monitoring. Online-monitoring systems can be an efficient and costeffective way to evaluate machinery performance. A PI process book capability to create data sets (DSs) and a built-in steam function library can provide an economical tool when implementing complex thermodynamic calculations and defining additional performance variables for continuous monitoring. This case study documents the performance variables to consider and apply when monitoring and tracking the efficiency deterioration for a steam turbine using DSs in a PI process book. The PI process book is a powerful online process

T = 350

Point A: P = 4.2 kPa (a), T = 352 °C

3,100

P = 0.02

T = 300

3,000

T = 250 P = 0.01

2,900

T = 200 T = 150

2,800

Point B: P = 0.5 kPa (a), T = 163.4 °C

2,700

P = 0.004

T = 100 T = 50 Saturation line

2,600 2,500

Point C: (Isentropic) P = 0.5 kPa at S = 6.67 kgkJ

2,400

P = 0.001 X = 1.0

P = 0.000612 X = 0.95

2,300 X = 0.90 2,200

Triple point pressure = 0.000612 Mpa (0.018 ºC) X = 0.85

2,100 2,000

Enthalpy-entropy diagram for steam Liquid at 0 °C and saturation pressure: s = 0 kJ/K*kg and H = 0 kJ/kg T = Temperature, °C P = Pressure, MPa

X = 0.80

1,900 X = 0.75 1,800 1,700 5.5

6.0

X = 0.70 6.5

7.0 7.5 Specific entropy, kJ/kg K

8.0

8.5

9.0

Produced by I. Aartun, NTNU 2001. Based on the program Allprops, Center for Applied Thermodynamic Studies, University of Idaho.

FIG. 1. Enthalpy/entropy (H-s) steam table showing the three points of P, T, H and s. Hydrocarbon Processing | AUGUST 201257


Fluid Flow and Rotating Equipment

FIG. 2. PI screen shot of various “s” parameters for the entire compressor/turbine system.

turbine. It drives a barrel-type centrifugal compressor at 10,000 rpm. This turbine is a multistage unit with an inlet steam pressure of approximately 4,248 KPa at a temperature of 355°C and an outlet pressure of 365 KPa and a temperature of 155°C. Thermodynamic and performance indicators. From the first law of thermo-

dynamics and steady flow energy equation: U 1 + P1V1 + P2V2 + H1 +

v12

2g

v12 + Z1 + Q = U 2 + 2g

v 22 + Z 2 +Ws 2g

(1)

+ Z1 + Q = H 2 +

v 22 + Z 2 +Ws 2g

Z1 ≈ Z 2

ΔH =

1 2 (v2 − v12 ) 2g

Turbine performance indices. Some critical parameters can be monitored when the turbine is online. These parameters can provide an accurate picture of the state of the running machine: Isentropic efficiency. The internal efficiency of a turbine is a key indicator of turbine performance and is termed as an enthalpy drop in the PTC code 6. This is the simplest and the most accurate test. The requirements are stipulated in the code.

Isentropic efficiency =

Where enthalpy (H), velocity (v) and head (Z) are used. For the steam nozzle Q = Ws = 0

H1 − H 2 =

For the turbine (Q = 0). Since the turbine casing is insulated, the flow process can be assumed adiabatic (Q = 0) (Q  0) Z 1  Z2 v1  v2 H1 – H2 = Ws ⌬H = Ws

(2)

1 2 (v2 − v12 ) 2g

In the case of the nozzle fouling, the enthalpy drop, ⌬H, decreases and reduces the nozzle exit velocity, v2. Result: The turbine slows down. The turbine responds to this condition by increasing the steam flowrate to keep the speed isochronous. 58AUGUST 2012 | HydrocarbonProcessing.com

η=

H1(P1,T 1) − H 2(P 2,T 2) H1(P1,T 1) − HS(P 2s−T 2s )

(3)

Steam mass flowrate. The mass flowrate is inversely proportional to the internal efficiency of the turbine. Exhaust temperature. The loss in efficiency increases entropy and, also, higher exhaust temperature occurs. Turbine shaft position. Fouling increases the wheel chamber pressure, and it subsequently develops an axial thrust on the rotor. Turbine active thrust bearing temperature. The thrust bearing temperature shows an increasing trend when the wheel chamber pressure increases.

PROBLEM CASE AND SOLUTION Canadian Natural Resources Ltd. (CNRL) plant operations expressed concerns regarding the efficiency of the steam turbine over issues related to poor steam quality. The solution entailed either to have the turbine vendor present onsite and use dedicated instruments to measure and record steam turbine performance, or to address the issue in-house with locally available software. CNRL plant reliability engineering was assigned the task of monitoring and tracking turbine efficiency and the subsequent evaluation of machinery performance. The enthalpy drop method from PTC code section 6 was used to calculate the efficiency drop across the turbine. This involved determining the isentropic enthalpy drop and the actual enthalpy drop, and then using their ratio to determine the stage group (operating) efficiency of the turbine. Manual method. Manual calculations, as summarized in TABLE 1, were initially done using the steam table, as shown in FIG. 1, to determine the operating overall turbine efficiency. Gauge readings from the PI online system (FIG. 2) were taken for the inlet and outlet conditions. The pressures were converted to absolute for the case history calculations. The stage group efficiency, approximated as per the calculations, was determined to be around 70%. PI data set. The PI was used to model

and track the turbine efficiency in accordance with the PTC procedures. This information was then used to trend and monitor the efficiency of the turbine on a real-time basis within the PI process book. The PI has a builtin steam table that can be called out functionally by the use of PI data sets. This provides a powerful and excellent feature to track and monitor efficiency trends over long periods without using sophisticated software. The DS provided a valuable tool in programming equations and other logic to monitor key machinery parameters. Various other process parameters such as turbine inlet and outlet pressure conditions, temperatures, flowrates, etc., can also be simultaneously plotted along with the efficiency to form an inclusive view of the turbine. Performance measurement and analysis can provide valuable insight into the health status of a given machine. It is


Fluid Flow and Rotating Equipment important to ensure data reliability and accuracy prior to performing any analysis to prevent incorrect conclusions and misguided decisions. The steam flow, turbine efficiency and steam-outlet temperature were trended from the process book. It is evident from the enthalpy drop (Eq. 3) that an increase in the steam-outlet temperature, T2, will cause an increase in the outlet enthalpy of the steam, consequently dropping the efficiency. This efficiency drop only holds true when the inlet temperature, T1 , and pressure, P1 , are held constant. The constant inlet pressure and temperature conditions are required for most operating steam turbines to ensure reliable process and machinery operation. Pressure drop (over design specifications) will occur across the nozzle (for impulse type) or across the turbine blades (for reaction type) due to steam path fouling issues such as deposit build up across the nozzles or turbine blades (FIGS. 3 and 4). This condition must be compensated by an increasing steam flow, which is achieved by an increased opening of the governor valve to maintain constant turbine speed. In this case, it was observed that the steam-flow input to the turbine had increased over time to maintain constant speed and that a gradual decrease of efficiency was observed due to steampath fouling issues. After the governor valve opens to 100%, a fully open condition, then the speed of the turbine begins to decrease. Result: The turbine is unable to meet the required compressor demand. Eq. 4 shows the general flow–pressure relationship for all turbine stages: w = (3,600)(C q )( An )× (2× g )(

γ ) γ −1

2 γ +1 ⎤ ⎡ P1 ⎢⎢⎛⎜ P2 ⎞⎟γ ⎛⎜ P2 ⎞⎟ γ ⎥⎥ ( ) ⎢⎜ ⎟⎟ − ⎜ ⎟⎟ ⎥ ⎜⎝ P1 ⎟⎠ v1 ⎢⎜⎝ P1 ⎟⎠ ⎥ ⎦ ⎣

Where: w = Flowrate, lbm /hr Cq = Flow coefficient An = Nozzle flow area, ft2 (stationary–blade flow area) γ = Ratio of specific heats P1 = Stage inlet pressure, psia P2 = Pressure between rotating and stationary blade rows, psia g = Acceleration due to gravity, ft/sec2

(4)

FIG. 3. A decrease in the isentropic efficiency causes an increase in the exhaust temperature (entropy).

FIG. 4. An increase in the steam mass flowrate is followed by a decrease in the turbine isentropic efficiency.

v1 = Specific volume at stage inlet, ft3/lbm . As per Eq. 4, most stages, including the first and last stage, operate with a constant pressure ratio under the changing governor valve setting, throttle flow, throttle steam conditions and condenser pressure (for condensing type turbines). However, when the governor is fully open (w at its maximum), there is a reduction in the nozzle area, An , as a result of steam fouling. The pressure ratio, P2 / P1 , begins to change, and this is indicative of a loss of turbine power to maintain the required load demand. Trending the

pressure ratios of the input and output steam could also provide valuable information on the turbine status. Evaluation results. It was determined, based on the data and analysis mentioned previously, that the steam turbine was experiencing fouling due to steam quality issues. These results initiated a follow-up investigation on steam quality and, subsequently, control. The online performance analysis coupled with trending of the governor position, provided a good measure of the turbine’s health. Reasonable predicHydrocarbon Processing | AUGUST 201259


Fluid Flow and Rotating Equipment TABLE 1. Calculations to approximate turbine efficiency in the running condition Location

Pressure, kPa

Temperature, °C

Enthalpy, kJ/kg

Entropy, kJ/kg K

Turbine inlet

(Point A)

4246.40

352.12

3,175

6.67

Turbine exhaust

(Point B)

486.99

163.42

2,800

7.35

(Point C)

486.99

2,645

6.67

Isentropic enthalpy drop

530

Actual enthalpy drop

375

Approximate stage group efficiency, %

tions were possible on the reliability of the turbine. It is important to ensure that proper instrumentation signaling is maintained into the distributed control system to acquire reliable data for such analysis and subsequent decision making. Plant reliability personnel can use similar strategies coupled with the functionality of their online monitoring system to determine the condition of critical turbomachines during plant operation. Accurate data monitoring, understanding and avoiding complacency during the decision-making process can help save the plant millions of dollars and affect the bottom line in a positive manner.

70.75 BIBLIOGRAPHY American Society of Mechanical Engineers, ASME PTC 6S Report, Procedure for Routine Performance Tests of Steam Turbines, New York, New York, 1988. UMEET BHACHU, PE, is a registered engineer in the province of Alberta and is working as a reliability engineer for the Canadian Natural Resource Ltd. (CNRL) Refinery in Fort McMurray, Canada. His work with CNRL involves reliability simulations and technical assessment of rotating machinery. He earned a Diploma in mechanical engineering from the British Columbia Institute of Technology and then graduated with a BS degree in chemical engineering from the University of British Columbia in 2005. Prior to CNRL, he was employed with Flowserve Canada where he was extensively involved with centrifugal pump and mechanical seal

design and commissioning. He holds ISO CAT II vibration analyst certification. JOY FRANCIS, PE, is a registered engineer in the province of Ontario and is working as a reliability engineer for the Canadian Natural Resource Ltd. (CNRL) Refinery in Fort McMurray, Canada. He has more than 23 years of experience in the field of rotating equipment in petrochemical, refinery and nuclear facilities. His major area of interest is in equipment condition/monitoring, rotor dynamics and reliability analysis. He is a graduate in mechanical engineering from University of Kerala, India, and his previous experience includes working with EQUATE Petrochemical Co., Kuwait, and Bhaba Atomic Research Centre (BARC), India. He holds Cat-IV Advanced Vibration Analyst certification from Vibration Institute and Six Sigma certification from Dow Chemical Co.

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Special Report

Fluid Flow and Rotating Equipment N. GHAISAS, Fluor Canada Ltd., Calgary, Alberta, Canada

Case history: Improve refrigeration compressor performance

First signs of failure. However, the first signs of deviation

from normal operating conditions became obvious when a step rise in the compressor’s vibrations was observed (changing from 21 microns peak-to-peak to 26 microns peak-topeak) with dominant peaks occurring at 1x and 2x, together with a cluster of sub-synchronous frequencies of 0.3x, 0.5x, 0.8x, 1.5x and 2.5x at the discharge end of the radial bearing. After analyzing the vibration spectrum, these frequencies were attributed to unbalance and mechanical looseness in the rotor. The alignment of the train had been checked during a recent out4,000 (157.48-in.)

4,500 (177.17-in.)

24 in. discharge

driven by a 5,000-hp rated electric motor through a speed increasing gear. The compressed refrigerant gas exiting the compressor is condensed by an overhead air cooler. The condensed refrigerant enters a receiver and is then sent to a flash drum. Vapors from the flash drum are directed to the second-stage suction of the compressor through a side-load nozzle. The liquid refrigerant in the chiller (evaporator) exchanges heat with the circulating water. The chiller is located within five feet of the compressor suction. Its vapor section is connected to the compressor’s firststage inlet flange with a short, straight-run pipe. The inlet throttle valve is a butterfly type. FIG. 1 shows details of the simplified compressor loop schematic. Similarly, the arrangement of the compressor train is illustrated in FIG. 2. The cooling load for this compressor fluctuates with the petrochemical plant’s production rate. For continuous refrigeration capability, vapor in the condenser must be condensed at the same rate as liquid refrigerant is vaporized by the evaporator. Because the condensing temperature of the air cooler depends on the ambient temperatures, the refrigeration capacity of the condenser changes with increasing and/or decreasing

Sideload 12 in.

History. The compressor is a three-stage centrifugal machine

condensing temperatures. When the cooling water flowrate through the evaporator increases in conjunction with hot summer days, the compressor operates at peak load. The machine is critical equipment and without a spare; thus this refrigeration compressor train is included as part of the periodic vibration analysis program conducted by the plant’s condition monitoring and asset reliability unit. Since the first start-up, this machine has operated normally, as evident from steady-state vibrations, bearing temperatures, thrust positions and the other measured process parameters.

30-in. inlet

The presented case history discusses the analysis and investigation regarding the mechanical distress and performance deterioration of a critical refrigeration compressor installed in a world-class petrochemicals complex.

Condenser

Receiver Flash cooler 10,000 (393.7-in.)

Cooling water in

LT LT

Cooling water out

Internal balance line Speed increaser gear

Chiller Driver motor

Balance piston Compressor

FIG. 1. Compressor-loop scheme.

Equipment Compressor Gear Motor Baseplate (include piping and auxiliaries) Subtotal weight

Mass of equipment lb kg 165,347 75,000 28,660 13,000 44,093 20,000 44,093 20,000 282,193

128,000

FIG. 2. Compressor train arrangement. Hydrocarbon Processing | AUGUST 201261


Fluid Flow and Rotating Equipment age of the chiller circuit, and it was within specified tolerance. As such, angular and/or parallel misalignment was not considered to be a contributing factor for increased vibration. After experiencing signs of rotordynamic malfunction, vibrations and thrust position of the compressor were closely monitored. During this GRP SPEC QUAD 4 CH SPECT AVG

Microns

RPM 9,825 19:33:48 40

VW 80 DB D G x2

CH ABCD FR 2KHZ WTG H

Drive end, ‘x’

20

A

Microns

0 40 Taken @ 9,825 rpm

‘y’

20

B

Microns

0 40 Free end, ‘x’

20

C

Microns

0 40 ‘y’

20

D

0 0 165.00 HZ

NORM A:

LNX1

F 5.000 HZ 31 microns

FIG. 3. Amplitude vs. frequency plot before shutdown.

2000.0 SPEC EXP N 2

period, the axial position of the compressor rotor had changed in the active direction only by a small amount—0.002 in. More analysis. In parallel to the vibration analysis, compres-

sor performance calculations were also done using data collected from the plant’s distributed control system (DCS). The results were compared with performance curves supplied by the manufacturer. It was soon revealed that the calculated head and efficiency were much higher than the values at the rated point. Secondly, the flowrate associated with calculated values was far to the right on the head (H)-flowrate (Q) curve. This circumstantial evidence indicated that the compressor’s impellers were operating in choke. In addition, there was a possibility that liquid was present in the suction gas because the gas exiting the evaporator had no superheat. In addition, the motor current was also recorded, which confirmed that the compressor train was operating in overload condition. Inspection. The unit was shut down after four days due to

increasing amplitude, reaching 31 microns peak-to-peak. The steady-state vibration level of the compressor in the preceding months was 21 microns peak-to-peak, maximum. The compressor was decoupled, and alignment readings were recorded. The compressor was disassembled for inspection, followed by rotor removal. A thorough examination of the rotor showed that two vanes in the third-stage impeller were partially detached from the cover at the weld joint. This condition explained the presence of unbalance and mechanical looseness related to peaks in the vibration spectrum. Rotor damage. Minor circumferential abrasion scratches were noticed on thrust bearing pads and both radial bearing surfaces, a condition often caused by dirt or debris passing through the oil film. To eliminate further abrasion damage, the duplex oil filters were replaced after flushing the entire oil system. Lubricating oil was reused, as it was determined that it had not degraded. Evaporator. Inspection of the evaporator showed no damage to the internals. However the evaporator’s liquid-level controlGRP SPEC QUAD 4 CH SPECT AVG

Microns

RPM 9,825 07:40:41 40

VW 80 DB D G x2

CH ABCD FR 2KHZ WTG H

Drive end, ‘x’

20

A

Microns

0 40 Taken @ 9,825 rpm

‘y’

20

B

Microns

0 40 Free end, ‘x’

20

C

Microns

0 40 ‘‘y’’

20

D

0 0 165.00 HZ

NORM A:

LNX1

F 5.000 HZ 19 microns

FIG. 4. Amplitude vs. frequency plot after repairs.

62

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2000.0 SPEC EXP N 2


Fluid Flow and Rotating Equipment ler was found to be defective following a calibration check. This controller was not able to maintain the set point, thus reporting incorrect information to the plant DCS. Result: Some liquid refrigerant remained entrained in the gas leaving the evaporator. As this liquid absorbed the heat of compression and evaporated, volume flow through the compressor increased, thus overloading the last stage (third stage) of the compressor. Sustained operating of the third stage at higher than the design pressure gradient contributed to material fatigue and initiated weld cracks. After replacing the rotor and completing other maintenance activities, the compressor was assembled. Calibration checks of instruments in the compression loop were conducted, and the defective level controller was repaired. Start-up of the compressor was normal. The compressor now operates at normal vibration levels—19 microns peak-to-peak maximum since the inspection/repair. FIGS. 3 and 4, respectively, show the amplitude vs. frequency plots in X -Y directions for each radial bearing before shutdown and after repairs. Overview. In summary, the elevated vibration amplitude of the

compressor was an after-effect of distress in the third-stage impeller. The level-controller malfunction and wrong information collected by the plant DCS resulted in a double-jeopardy situation. In addition, the presence of liquids affected the density of the refrigerant gas, compression ratio, volume flow and motor load. Entrained liquid in the gas lowered the compressor discharge temperature and, therefore, the calculated polytrophic

efficiency was higher (five points higher than that corresponding to the rated point). Note: The discharge temperature of a refrigeration compressor is not the same as the condensing temperature. The condensing temperature is governed by the temperature of the condensing medium. Unbalance and looseness in the third-stage impeller showed the prominent effect on the vibration level on the closest radial bearing (discharge end bearing). As mentioned earlier in this article, the rate of vaporization in the evaporator must match the rate of condensation to provide a continuous refrigeration effect. The higher the cooling load, the greater the flow velocity in the evaporator and the higher the potential for liquid to be entrained in the gas. It was recommended to plant operations that the vapors entering the compressor suction should have a minimum of 5° superheat. On start-up after the repairs, between 5° and 7° suction superheat was being maintained by the unit operators by adjusting the liquid refrigerant level in the chiller (evaporator) for a given cooling load. NEETIN GHAISAS is a technical fellow and director of design engineering in Fluor Canada’s Calgary office. He holds an MS degree in mechanical engineering and is a registered practicing professional engineer in the province of Alberta, Canada. Mr. Ghaisas has more than 30 years of significant experience in the specification, selection, application and troubleshooting of rotating equipment. He is a subject matter expert for Fluor Corp.’s compressors and steam turbines. In Fluor’s Calgary office, he serves as a group leader of rotating equipment engineers. He is a member of API subcommittee on mechanical equipment and a member of the machinery function team in Process Industry Practices.

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Special Report

Fluid Flow and Rotating Equipment S. MUBARAK, Bharat Pumps and Compressors, Ltd., New Delhi, India

Apply new guidelines when selecting low-temperature service compressors Liquefied gases are transported by tankers and ships and are stored in specially designed tanks. However, when the temperature of liquefied gases—ammonia, ethylene, propylene and liquefied natural gas (LNG), etc.—is considerably low, the vaporization occurs very quickly due to ambient temperatures. As the liquid vaporizes, the pressure inside the tank, likewise, increases. The rising pressure must not exceed the design pressure of the tanker/storage tank. To control pressure, the re-liquefaction process was adopted, in which reciprocating compressors are an indispensable part of the whole system. When the temperature of the liquid gas and its vapor is quite low (–160°C for LNG and –100°C for liquefied ethylene and propylene gases), the compressor to handle low-temperature gas has some special features. Accordingly, when selecting reciprocating compressors for low-temperature services, several criteria must be considered: • Effects of gas temperature on compressor size • Construction materials of components in contact with the cold gas • Cylinder cooling systems.

GAS TEMPERATURE The size of a compressor depends mainly on two factors: • Gas flow and volume at the inlet to the compressor • Power required to compress the gas to desired pressures. For a given suction pressure, the suction gas capacity also depends on the temperature of the gas at the cylinder inlet manifold. In low-temperature applications, the actual temperature of the gas entering the cylinder during the suction

stroke is always higher than the gas in the storage tank. Therefore, while calculating the required compressor BKW (brake power in kilowatts) and size of the cylinders, determining the cylinder inlet gas temperature is very important. Cylinder inlet gas temperature is affected by: • Distance between the storage tank and compressor • Ambient temperature • Insulation of piping and vessels. Ulta-low-temperature (ULT) gas systems will experience greater delta temperature rises. In other words, the temperature rise will be more in the case of LNG, at –162°C, as compared to the gas service involving liquefied ethylene at –100°C. In addition, design engineers should address these system conditions to manage increases in the suction-gas temperature: Compression ratio. In low-temperature

applications, the intercooling of the gas does not occur. Therefore, the secondstage inlet gas temperature depends on the first-stage gas discharge temperature. If the overall compression ratio (CR) of the compressor is low, then the CR of the first stage will also be low. Consequently, the discharge gas temperature will be considerably lower. But, in such a case, the second-stage inlet gas temperature will be considerably higher than the first-stage discharge gas temperature. To understand this processing condition, consider the case of ethylene boiloff (BO) service, in which the suction pressure is 1.02 kg/cm2 A and the suction temperature is –102°C. If the discharge pressure of the compressor is 8 kg/cm2 A, then the first-stage CR is around 3, and the discharge temperature will be approximately –40°C, which is a con-

siderably low temperature. Therefore, at the second-stage cylinder, the inlet gas temperature will be considerably higher than –40°C. However, in case when the compressor discharge pressure is higher (approaching 20 kg/cm2 A), then the CR for the first stage is also higher (approximately 5) and the resulting first-stage discharge temperature is also higher. Result: The gas heating effect is not as much for the second-stage inlet gas. Therefore, with high CR conditions, the average temperature of the gas inside the cylinder will be higher, and the volumetric efficiency of the cylinder will be lower. Frictional heat. For ULT services, e.g.,

LNG (–160°C), the effect of frictional heat, developed inside the cylinder, is more pronounced for the first-stage cylinder, as this cylinder is cooled by the gas itself. The heating of suction gas is related to higher operating pressures, where more frictional heat is generated. Capacity control. At partial loading,

the flow of cold gas is reduced while the frictional heat is almost the same. Therefore, heating of the gas is greater during partial load operations. Moreover, in the case of capacity control by suction-valve unloading, the gas temperature in the suction pulsation dampener increases due to the pressure drop in the unloaded valves during suction and discharge strokes. The net result is higher gas-suction temperatures at the loaded end of the cylinder. Clearance volume. With a higher clearance provided inside the cylinder, more hot gas will be present inside the cylinder. Again, the gas temperature will increase further during the suction stroke. Hydrocarbon Processing | AUGUST 201265


Fluid Flow and Rotating Equipment Cylinder size. With a larger cylinder

bore, less heating of the gas will occur. The capacity of the gas handled by a cylinder increases as the bore size increases. However, the surface area of the cylinder exposed to the atmosphere (heat source) does not increase in the same proportion.

characteristics of the material at low temperatures and type of loading of the components. Based on past experience, these suggestions may be considered: • For ULT service, e.g., LNG, the material of the first-stage cylinder should be ASTM A351 CF8 or an equivalent.

Extra precautions are needed in the design and sizing of reciprocating compressors for low- and ultra-low-temperature services, such as LNG and refrigerant applications. For the same reason, if the bore of the cylinder is smaller, then the temperature of the gas will increase due to absorption of more heat by a lesser amount of gas. Number of compressors. When gas piping is designed for two or more compressors running in parallel, and not all of the compressors are operating, then the gas temperature at the inlet side will be higher. Cooling occurs as the gas flows through the piping. Consequently, heating of the gas is related to ambient temperatures and the quantity of gas flowing through the system. The overall effects from the listed process and equipment factors are that the gas temperature at the compressor inlet will increase, and, in turn, gas flow will decrease. Therefore, unless we know the actual temperature of the gas entering the cylinder, then sizing the compressor and its driver is very difficult. Considering all of the previously mentioned factors, here are several key points that are highly suggested to consider when sizing the compressor cylinders: • When the discharge temperature of first stage is around –35°C and greater, consider the effect of gas heating only for the first-stage inlet gas; for the second stage inlet gas, it can be ignored. • When the first-stage discharge gas temperature is below –35°C, consider using higher suction temperatures for both stages.

SELECTION OF MATERIALS The selection of material for various components in contact with lowtemperature gas is done considering the 66AUGUST 2012 | HydrocarbonProcessing.com

• In ULT service, since the cylinder’s distance pieces are covered with ice, the construction materials must be from cast iron ASTM A571 D2M or an equivalent. • When suction-valve unloaders are to be provided and the unloader length (the distance between the valve and the actuator) cannot be increased sufficiently, then the valve unloader body should also be constructed from ASTM 571 D2M cast iron. • Although the piston-rod working temperature is considerably higher than the gas temperature, construction material of the first-stage piston rod should be A522 (9% Ni) stainless steel. • Low-temperature service is more severe than the service involving moisture-free gases. Therefore, special care should be taken while selecting the materials for the piston rings and rider rings. For such services, special materials are available to provide satisfactory performance.

CYLINDER COOLING SYSTEM While designing the cooling system of the cylinder jackets, ensure that the selected coolant freezing temperature should be sufficiently lower than the average temperature of the gas inside the cylinder. The cooling of cylinders when handling low-temperature gases is done normally by isobutyl alcohol (freezing temperature –120°C). Likewise, here are several other considerations for the cylinder cooling system: • In the case of LNG service, the discharge gas temperature for the first stage at 100% load is always below 0°C. The whole cylinder will remain covered in ice.

Therefore, cooling by an external source of the first-stage cylinder is not carried out. Similarly, cooling of the cylinder packing is also not done as it is cooled by the cylinder itself. • Operating at partial loading over a long period, even with the assistance of a bypass valve is not desirable. However, if it is necessary to run the machine at partial loading, some arrangements can be made for cooling the first-stage cylinder. • In LNG service, at 100% load, the average gas temperature inside the first-stage cylinder is normally lower than the coolant freezing temperature (–120°C). If the first-stage cylinder is also equipped with cooling by an external source, then a fail-safe arrangement should be provided so that the coolant is drained out before freezing occurs inside the cylinder jacket. • When intercooling is done in a flash vessel and the compressor is shutdown, the gas temperature at the second-stage inlet will also be quite low. Therefore, design engineers should consider the temperature inside the secondstage cylinder when designing the cylinder cooling system. Design and process engineers should take extra precautions when selecting and sizing reciprocating compressors in lowtemperature gas service. To incorporate all of the required features within the design of such machines, customers should also specify all the necessary information and data including ambient condition, plant layout, type of service (intermittent or continuous,) capacity control requirements and number of working compressors. All of this information will impact the final design and selection of compressor along with auxiliaries to achieve a long, uninterrupted service. SYED MUBARAK is the regional manager of Bharat Pumps and Compressors Ltd., New Delhi, India. He joined Bharat Pumps and Compressors Ltd., Naini, Allahabad, India, a government-owned enterprise, engaged in the manufacturing of rotating equipment-compressors and pumps along with welded/seamless gas cylinders. He has over 33 years of experiences and has held various positions of responsibility with Bharat Pumps and Compressors Ltd. He was a compressor application engineer for more than 25 years in the design and engineering department. Before his appointment as regional manager in 2007, he was the deputy general manager of the design and engineering department at the Allahabad office. Mr. Mubarak holds a BS degree in mechanical engineering from the Z. H. College of Engineering and Technology at A. M. University in Aligarh, India.


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HOUSTON HOUSTON

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O c t o b e r 3 0 – 3 1 , 2 0 1 2 • H y a t t R e g e n c y D o w n t o w n • H o u s t o n , Te x a s U S A The Women’s Global Leadership Conference in Energy and Technology (WGLC) is one of the largest women’s events in the industry, and the only one that focuses on discussing key environmental, economic and professional development issues in oil and gas. The 2012 event will take place October 30–31 at the Hyatt Regency Hotel Downtown in Houston, Texas. This year, conference content will focus on the global impact of recent technological advances in exploration and production. Executives from leading oil and gas companies will share the latest information on topics like regulatory changes, sustainability, refining, international operations, IOC/NOC relationships and global upstream trends. Also slated for discussion is the recent North American revolution in shale energy, oil sands and natural gas, and the wider implications on transportation and infrastructure. A key component of these innovations is the increased influence of women in engineering, technical and strategic management roles on a global scale. Noble Energy’s Vice President of Exploration, Susan Cunningham, will be the WGLC 2012 keynote speaker, and she will share her insight into these topics, as well as the knowledge she has gained through her own professional and personal development. Register by August 31 to attend the 2012 WGLC and save 15 percent.

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SAFETY, SECURITY AND THE ENVIRONMENT 2012 Fire incident at Jaipur was a wakeup call [S–69] Safety news [S–71] CORPORATE PROFILES ONIS [S–73] Scott Safety [S–75] COVER PHOTO

Detector Electronics Corporation [S–76]

Firefighters perform an inspection at a refinery to ensure safety.

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Be a Marketing Champion September 5, 2012 Omni Houston Galleria Hotel Houston, Texas

Learn the tactics and strategies to develop a cost-effective, integrated marketing mix that maximizes impact and return on your dollar. More than ever, marketing is a collaborative task, involving both internal and external stakeholders. With an overload of information and influencers of all kinds, it often takes a team approach to provide savvy customers with everything they require. In today’s oil and gas industry, marketers must know how to champion ideas internally, engage with influencers and justify their marketing spending to senior management. Join us on September 5, 2012, to see how marketing fundamentals can be applied to traditional and emerging marketing channels. You’ll also be able to gather inspiration and ideas from other industries that can be effectively applied to the oilfield, and how to create medal-worthy marketing campaigns.

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SAFETY, SECURITY AND THE ENVIRONMENT

FIRE INCIDENT AT JAIPUR WAS A WAKEUP CALL New safety standards developed to avoid future tragedies H. DUTTA, Oil Industry Safety Directorate, New Delhi, India

The 2009 fire incident at Indian Oil’s Jaipur petroleum oil lubricants (POL ) terminal happened while reversing the hammer blind during transfer of POL to the pipelines. Unfortunately, while this reversal was taking place, the tank body’s motor operated valve (MOV) was open. The oil spillage and vapor cloud formation that followed resulted in a devastating fire and loss of property and human life. As per normal practice, the MOV should not have been kept open while reversing the hammer blind. The episode led to the loss of 11 lives and a property loss of around $60 million. The root cause of the incident revealed that plant personnel did not follow standard operating procedures. This terrible tragedy was a wake-up call for the industry.

REFINERY VS. MARKETING OPERATIONS Marketing locations are spread across the nooks and crannies of India; in order to be in the vicinity of the customer base. With more than 660 marketing installations and 22 refineries in the country, the geographical spreads of marketing locations are enormous. Refinery operations are complex, with high temperature, high pressure operations taking place constantly. Marketing operations, in contrast, are not so complex, with practically no source of ignition. Refinery operations are uninterrupted seven days a week, whereas marketing operations in most of these locations are two shift operations. Marketing locations do not have their own full-fledged fire-fighting crews at their disposal, nor do they have a training center attached to the location. Furthermore, many of them are located in highly congested and densely populated locations. Given these scenarios and constraints, it seems that marketing is perhaps more shambolic compared to refining in terms of infrastructure and environment. However, this poses a great challenge to the oil marketers in India.

PRIMARY AND SECONDARY FACTORS To mitigate unsafe situations, oil companies’ approach to safety management must be systemic, encompassing both primary and secondary factors (FIG. 1). Primary safety management factors include risk analysis, hazard and operability (HAZOP) study and risk assessment. Safety measures should also be built in at the design stage, incorporating safety in instrumentation (including safety interlocks), while following best engineering practices like API and ASME codes. In addition, walk-throughs of the plant—using 3D modeling and other techniques, overseen by multi-disciplinary teams with engineers from chemical, mechanical, instrumentation, electrical backgrounds—are also helpful. Operating manuals should not only cover normal startup, shutdown and emergency procedures, but also include disaster preparedness issues so that employees are prepared to manage smooth and safe operations under any conditions.

Secondary safety factors include fire-fighting infrastructure and facilities to address any development once an incident or accident happens due to a failure of the primary safety systems, as outlined previously. The Oil Industry Safety Directorate has developed a number of safety standards (112) to be implemented by the oil industry in India. The directorate undertakes audits at regular intervals, including surprise safety checks, to oversee the implementation of the safety standards and to point out gaps that may exist in a particular company’s approach. Accidents are investigated and root cause analysis is shared with the industry, not for the sake of fault finding, but rather to learn from the mistakes and avoid recurrence. Thanks to this approach, the number of accidents in India has been reduced over the last three years. A close analysis of the accidents that took place in the last three years shows that a majority of the incidents have taken place due to: • Not following the standard operating procedures • Poor upkeep of equipment and assets • Knowledge gaps. To meet the objective of no incidents in the oil industry, the leaders of the industry recognized the need for a paradigm shift in safety management approaches. Foremost is the belief that accidents can be prevented. The second is a renewed focus on learning, unlearning and re-learning (applicable not only to full-time employees but also to the large number of contract laborers that work in oil installations), coupled with strict adherence to standard operating procedures. The third important factor is that of asset integrity management.

EMPHASIS ON LEARNING The successful absorption of any technology or process depends on how it has been assimilated by the plant personnel. Accidents take place due to: • Incorrect operations • Not properly maintaining the equipment or facilities

Safety management systems

Primary (systemic)

Secondary (reactive)

Technology related Systems and procedures Best practices

Fire protection and mitigation system

FIG. 1. Safety management systems in the hydrocarbon processing sector.

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SAFETY, SECURITY AND THE ENVIRONMENT

• Not following procedures • Knowledge gaps. Thus, it is evident that the success of any improvement effort, namely managing safety or improving productivity or gross refining margin, depends upon the employees. In India, it is mandatory that all new entrants to oil installations must successfully complete fire and safety training. The training encompasses both classroom inputs and onsite drills. Refresher programs are conducted at all the installations. The training materials are critically reviewed, radar charts are developed for each operating crew, and needs-based training sessions are included. Training for all contract employees has also been made mandatory. Identification of critical workers like riggers, welders, electricians, crane operators, and drivers selected by outsourced agencies includes periodically monitoring and assessing their competencies. The directorate demanded that industry identify and give a critical task analysis of high-risk jobs. It encouraged periodic observation of the critical tasks by a supervisor, followed by a discussion with the operating personnel. Mock drills have become a regular feature of safety preparedness training for employees, as the outcome of each drill is critiqued for lessons learned, and then action items are discussed, corrected and completed in a timely manner. Another aspect of the renewed focus on quality assurance and preventive maintenance programs examines: pressure vessels and storage tanks; piping systems, including valves; relief and vent system devices; emergency shutdown systems; monitoring devices; sensors, alarms and interlocks; inspection techniques; and pumps and compressors.

STANDARD OPERATING PROCEDURES Each element of standard operating procedures (SOPs) is now discussed with the plant operators and technicians to provide clarity for all participants. It is vital to have SOPs that are properly understood by the personnel who are responsible for following and implementing them. The SOPs should be regularly updated and displayed at a location near critical equipment. The concept of equipment ownership and “know your equipment” (KYE) was brought in. This is aimed at improving ownership and accountability. More emphasis on visual management and its display at appropriate locations to eliminate operational mistakes has been put into practice.

ASSET INTEGRITY MANAGEMENT Employees and supervisors should constantly be concerned about proper facilities maintenance. While it is easy to build facilities, it is

Safety triangle People

Process safety Process

Technology

FIG. 2. The safety triangle illustrates that when people, process and technology work in tandem, there is always a significant reduction in surprises. S-70

SAFETY, SECURITY AND THE ENVIRONMENT 2012 HydrocarbonProcessing.com

more challenging to maintain them in a “like new” condition. Unless asset reliability is monitored consistently, the various safety devices associated with the plant may not work. The remote operated device that was supposed to shut off the MOV at Jaipur did not function properly. A similar thing happened at the Buncefield, UK, terminal, where the high-level tank indicator did not work appropriately. If it had, it could have prevented such a huge loss of life and property. Oil companies today are putting more emphasis on safety through intense reliability testing, properly scheduled maintenance of rotary equipment and inspection of static and rotary equipment. Storage tank maintenance and inspection schedules are followed and not unnecessarily delayed. Pipelines are receiving periodic health checks and troublesome equipment replaced wherever necessary. This shows that the the emphasis is on maintaining assets in a “fit-for-use” condition all of the time. The significant aspect of asset integrity involves people and their development. Unless the human assets are equipped with adequate knowledge and skills, motivation and a climate for fostering innovation, it is impossible to achieve the desired results.

POST-JAIPUR: OTHER SAFETY MEASURES Reversing a hammer blind is always problematic, as there are chances for accidental spillage. To eliminate hammer blind reversal as a potential hazard, India decided post-Jaipur that all hammer blinds throughout the oil industry would be replaced by double block and bleeder valves or plug valves. At many locations, this has already been implemented. Another post-Jaipur safety decision was to replace the tank MOV with remote operated shut-off valves (ROSOVs), which can be operated from the control room (with the cable leading to the control room being fireproof). ROSOVs also have the additional benefit of operating the same from the field through a switch located outside the tank dike. This changeover from tank MOV to ROSOVs is underway across the country. To prevent tank overflow, a separate hardwired independent switch with a high-high level alarm in the control room has been proposed to bolster the normal high level alarm from the radar gauge. The additional high-high level alarm from the independent switch would actuate an emergency shutdown switch to shut off the ROSOV. These additional layers of protection, which are under various stages of implementation, are aimed at further enhancing the safety of oil installations.

VISIBLE CHANGE A visible change has taken place in the attitude of top management. The attitude toward safety has changed from being reactive to being proactive, following philosophical shift from preventive to predictive. Routine training programs have been expanded to increase learning opportunities for employees, and top leadership is now accepting dissent views as a valuable resource. The focus is as it should be, on people, process and technology. Industry management should recognize that when people, process and technology work in cohesion, surprises can be eliminated, safety can be improved and profitability can be increased.

Hirak Dutta has a bachelor’s degree in chemical engineering from Jadavpur University in Kolkata, India. He is currently executive director of India’s Oil Industry Safety Directorate. Mr. Dutta has over three decades of experience in the oil industry, including operations, process engineering, troubleshooting, project management and human resources management.


SAFETY, SECURITY AND THE ENVIRONMENT

SAFETY NEWS SAFETY AWARDS PRESENTED AT ILTA The International Liquid Terminals Association (ILTA) held its 32nd Annual International Operating Conference and Trade Show from May 21–23, in Houston, Texas. More than 650 people attended the conference, which focused on a variety of operational and business topics, along with environmental, health, safety and security issues. A total of 14 terminal companies were recognized during the safety awards breakfast. Two companies demonstrating exemplary safety cultures were awarded the 2012 Platinum Safety Award. Citgo Petroleum received the large terminal company award, and Motiva Enterprises’ New Jersey complex received the small terminal company award. The 2012 Safety Excellence Award was presented to 11 terminal companies that achieved a safety record of less than one injury per 100 workers in 2011 (FIG. 3). The companies were: Asphalt Operating Services LLC, Buckeye Terminals LLC, Enterprise Products Partners LP, Flint Hills Resources, Hess Corp., Marathon Petroleum Co., Murphy Oil Corp., NuStar Energy LP, Petro-Diamond Terminal Co. Inc., Sunoco Logistics Partners LP and US Venture Inc. In addition, TransMontaigne Product Services Inc. received a Safety Improvement Award for demonstrating significant improvement in its safety record over the past four years. During the awards ceremony, seven terminal companies received special recognition for participating in ILTA’s annual safety survey each year since inception of the program in 2003. The companies were: Colonial Terminals Inc., Hess Corp., Houston Fuel Oil Terminal Co., Intercontinental Terminals Co., International-Matex Tank Terminals, LBC Houston LP and Odfjell Terminals (Houston) Inc.

API TRADE GROUP ADOPTS PIPELINE SAFETY PRINCIPLES The pipeline subcommittee of the American Petroleum Institute (API) trade group adopted eight pipeline safety principles at meetings this week with industry operators and the Association of Oil Pipe Lines. The principles, which evolved from operator experiences and API’s pipeline performance tracking system program, will help focus and improve industry safety programs and performance, the group said. “The principles are evidence of our commitment to continuous safety improvement,” said Harry Pefanis, president of Plains All American Pipeline and chairman of API’s pipeline committee. “Industry’s adoption of these principles demonstrates our commitment and strengthens our ongoing efforts to improve our safety record.” API says the eight liquid pipeline safety principles are zero incidents, organization-wide commitment, a culture of safety, continuous improvement, learning from experience, systems for success, employing technology and communicating with stakeholders. “Our members have worked hard to measure their performance and identify ways to improve,” said Peter Lidiak, pipeline director for API. “While we’ve seen great improvement, more is needed to move us toward a goal of zero incidents. Adoption of these principles sends a clear message to the entire industry and the public that safety will continue to be of paramount importance.”

BP PROBES BLAST AT COLORADO GAS COMPRESSOR PLANT In late June, a contract worker was killed and two others injured after an explosion at BP’s gas compressor station in Durango, Colorado.

“The site has been safely shut down and secured, and everyone has been accounted for,” BP said in a statement. “We are working closely with the local emergency crews that responded to the incident.” Eleven workers were at the Pinon Compression Station at the time of the explosion, most of whom were performing pipeline maintenance work. The Pinon station gathers natural gas produced in the San Juan basin and handles about 30 million cubic feet/day of gas. BP said that it continues to investigate the cause of the explosion. “It is too early to speculate on the cause of the accident,” BP said. “We are deeply saddened that one individual was fatally injured. Two others are receiving medical treatment.” BP said impacts from the explosion were still being assessed, and it remains unclear how long the facility will be offline. The La Plata County Sheriff’s Office said it was not a flammable explosion, but one involving a pressurized device. “There was pressure being put into a device, and that device failed,” the office said.

EXXONMOBIL CHEMICAL RECEIVES SAFETY AWARD FROM ACC ExxonMobil Chemical was named the Responsible Care company of the year at the 2012 American Chemistry Council (ACC) annual meeting in Colorado Springs, Colorado. The prize is ACC’s top award for exemplary achievement in safety, health, environmental performance and communication with stakeholders. An independent panel selects the recipient based on performance, programs and projects sustained over time. Responsible Care is the global chemical industry’s premier program for achieving and sustaining operational excellence. ExxonMobil Chemical said it implements Responsible Care through its operations integrity management system (OIMS), which establishes company-wide expectations for addressing operational risks. Through OIMS, ExxonMobil monitors and improves its performance. Over the past 10 years, ExxonMobil Chemical has reduced the injury rate in its worldwide operations by 60%, while at the same time improving the sustainability of its operations and products, the ACC said. For example, ExxonMobil Chemical’s advances in polyethylene used to make heavy-duty shipping bags have reduced the thickness of the bags by 50% over the last 20 years, decreasing packaging weight, shipping costs, energy consumption, emissions and waste.

FIG. 3. ILTA’s Safety Excellence Award was presented to 11 terminal companies that achieved a safety record of less than one injury per 100 workers in 2011.

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36” 150# Onis Line Blind; Full-bore to blinded in 5 minutes

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ABOUT PICTURE TO THE LEFT This is a 36” 150# Onis Line Blind used in HCN Gas. Before using the Onis Blind the operating company unbolted all the bolts, scraped spiral wound gaskets, used a crane to lower a 36” slip blind , and then re-bolt. This process took 8 hours under full PPE. This Onis Line Blind was installed in 2000 and now takes the company 5 minutes to blind. Gaskets can be inspected or changed, before operation, without being in contact with the HCN gas.

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Onis Line Blind with double gaskets for Api-607 Fire Safe standards.

ONIS SPECIFICS Onis Blinds physically spread the pipe. There are only 4 gaskets on the slide and zero internal (backseat) gaskets or moving parts that are hard to change in the field. The advantage of this feature is that all gaskets can be inspected, and changed if needed, without opening the line. For example, a few days before operators need to blind a line, anyone can easily inspect the gaskets, and if they need replacing, the gaskets can be removed and replaced while the production line is still in operation. For Dangerous mediums there is no need to use additional PPE while replacing gaskets. When the line is blinded, the full-bore gaskets are accessible and available to easily change and provide a new seat when the line is returned to service. All Onis moving parts are outside of the process, and there is no reduction of flow from the pipe and no place for product build-up. Additionally, all Onis Blinds have slide covers, grease fittings (to ensure bushing longevity), and lock-out/ tag-out latches. The bodies of Onis blinds are made from solid forgings and are not welded flanges. Onis blinds can be built for hydrotesting additional when specified by the customer. Onis offers manufacturers one year warranty (additional upon request). Installation support and on-site training for operators and maintenance personnel are available. Thank you for considering Onis Line Blinds.

WHERE ONIS BLINDS ARE USED Onis Blinds are currently used in refineries, chemical plants, pipelines, and compression stations. The Onis Blind can be used in any service (i.e. H2S, Nitrogen, Decoke/Feed lines, diesel, natural gas, benzine, chlorine, HCN, and more). Onis Blinds can be used to isolate reactors, heaters, pumps, compressors, and furnaces. Onis Blinds are used in offshore applications and their minimal operation time offermany advantages.

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DIRECTOR OF INNOVATION

For 80 years you’ve inspired some of our best products. Every innovation. Every solution. We’ve made them better with your help. By listening to your feedback and using it to innovate what’s next. The Air-Pak 75i is a perfect example. Thanks for all the good ideas.

you’re the expert. let’s talk innovation. join us on facebook. © 2012 Scott Safety. SCOTT, the SCOTT SAFETY Logo and Scott Health and Safety are registered and/or unregistered marks of Scott Technologies, Inc. or its affiliates.

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| Bonus Report LNG DEVELOPMENTS Liquefied natural gas (LNG) is becoming an increasingly important component of the global and regional energy mixes. Utilities around the world are looking to natural gas as a low-emissions and relatively low-cost source of energy. In its liquid form, the fuel can be exported across long distances via pipeline or tanker ship, making it a flexible and valuable resource. Developments in the engineering, design and construction of LNG plants are enhancing the availability and attractiveness of liquefaction technology, as discussed in this month’s Bonus Report.


Bonus Report

LNG Developments A. M. FANTOLINI, L. PEDONE, L. D’ORAZI and R. PRODAN, Saipem SpA, Milan, Italy; A. SOOD and G. BHATTAD, Hyperion Systems Engineering, Pune, India; D. STAVRAKAS and V. HARISMIADIS, Hyperion Systems Engineering, Athens, Greece

Use dynamic simulation for advanced LNG plant design Performing engineering studies with dynamic simulation is becoming a critical requirement for new liquefied natural gas (LNG) plants. Typically, the major target for such a study is the investigation and review of critical plant design elements, such as compressors, flares and boiler systems. Dynamic engineering studies can identify design changes that will significantly improve plant performance and the safety and reliability of plant operations. Furthermore, if such design changes are identified early, they can be implemented at a low cost and provide significant savings during a plant’s lifetime.1–3 LNG plant design is based on steady-state process simulation. This approach typically does not take into account rotating equipment characteristics, holdups or actual pressure drops. However, the use of a dynamic process simulator is required to understand actual plant transients and dynamics, to examine and verify control schemes, and to review plant procedures. The dynamic model allows for the calculation of process variables as a function of time (i.e., as a movie instead of a series of snapshots). Moreover, it is possible to examine process upsets, including process startups and shutdowns—a critical functionality not offered by the steady-state simulator. This article presents experiences obtained from a detailed engineering study for Sonatrach’s GNL3Z project, a grassroots baseload LNG production plant in Algeria. A brief description of the LNG production process is provided, along with a number of test cases demonstrating the design challenges faced and their resolutions. Lessons learned during this study with regard to project execution and project management are offered, and the benefits obtained through engineering studies are described. Systems examined and simulation test cases. All compressor systems in the GNL3Z plant have been examined, and a series of simulations has been performed to verify the process design. In this section, the approach used in engineering studies and in the overall liquefaction process is described. Next, details are provided on the compressor systems and on the test cases reviewed. Engineering study approach. A dynamic engineering study involves a number of steps before delivery of the final results and recommendations, as outlined below: • Exact scope definition, which includes the modeling boundaries and the test cases to be examined • Careful data collection and reduction to a form usable by the simulator; these data should be easily accessible, reusable

and verifiable, which, in practice, means maintaining specific project folders and spreadsheets and ensuring version control • Calculation of pipework volume and resistance to flow through analysis of isometric drawings • Model building as per piping and instrumentation diagrams (P&IDs) and agreed scope, incorporating plant logic (e.g., cause-and-effect charts) and isometrics; elements typically included are: a. Compressor system (gas/steam turbines, electric motors, heat exchangers, vessels, etc.) b. Compressor control, including the anti-surge, hotgas/cold-gas bypass and bleed valves c. Regulatory control, emergency shutdown logic and related valves d. Startup and normal shutdown procedures. • Integration of sub-models and preparation of the final model, aligned at the agreed heat and material balance (H&MB) • A first report to the final user clarifying data and general approaches used, comparing the model with the agreed H&MB, and supporting the model review • Model update, which can include client comments, incorporation and review of data, preparation of repeatable scenarios for test runs, defining test run duration and specific integration time steps, etc. • Execution of the test run, which involves collecting data, graphically reviewing the results (i.e., process variable as a function of time) for easy analysis, and discussing first results with the client • Delivery of the individual test run and reporting of observations, conclusions and possible recommendations • Delivery of the final report, including all individual run reports and final recommendations. LNG production process description. Natural gas is first compressed in a feed gas compressor and then sent to the mercury-removal unit. The gas is further treated in an acid gas absorber to remove CO2 and H2S, if present. The sweet gas is dried in molecular sieve beds and further processed in the natural gas liquids (NGL) recovery unit to remove the C2+ compounds. The chilling requirement for the treatment is supplied by auxiliary propane (C3 ) refrigeration.4–6 The treated natural gas is then compressed in a residue gas compressor and cooled by C3 chillers. Afterward, it is fed to the Hydrocarbon Processing | AUGUST 201281


LNG Developments bottom of the main cryogenic heat exchanger (MCHE), where it is liquefied by mixed refrigerant (MR). This is the typical liquefaction technology used in projects based on a propane/MR process. The LNG produced is sent to the helium recovery and nitrogen-stripping sections. The nitrogen- and helium-free LNG is then sent to the storage tanks. The boil-off gas (BOG) from storage is recompressed and sent to fuel gas. The gas coming from the helium-recovery and nitrogen-stripping units is compressed in the end-flash gas compressors and sent to the fuel gas header. The following compressor systems are considered in the current dynamic simulation scope: • Feed gas compressor • Residue gas compressor and turboexpander • Auxiliary propane compressor • Refrigerant (C3/MR) compressors • End-flash gas compressors • Boil-off gas compressors. Several test cases are reviewed in the following sections. Feed gas compressor startup. The natural gas is fed to the feed gas compressor suction knockout drum to remove any entrained or condensed liquids. The overhead vapor is directed ASC XV HG BV

Treatment Mercury removal

Acid gas scrubber

Molecular sieve drier

NGL recovery unit

Residue gas

PIC

Feed gas compressor

Feed gas

Knockout drum

FIG. 1. Feed gas compressor system simplified process flow diagram.

to the feed gas compressor. The compressed gas is cooled and then directed to other LNG plant units for further treatment. A simplified process diagram is shown in FIG. 1. During startup, the feed gas compressor pressurizes other downstream units to the residue gas compressor. The volume of the downstream system is very large (about 3,000 m3 ). Thus, during a typical startup, when the downstream pressure is low, our simulations show that the compressor would operate in the stonewall region until the downstream system is pressurized, as shown in FIG. 2 (red line). To avoid operating at high compressor flows, it was decided to isolate the compressor from the downstream system during startup. A valve bypassing the discharge on/off valve and controlling the downstream pressure was used to smoothly pressurize the downstream system. Results are shown in FIG. 2 (blue line). In this case, the anti-surge controller was allowed to control pressure while increasing the compressor speed from minimum to operating speed. A further refinement to the procedure was implemented to allow the anti-surge system to control when the compressor reached the minimum speed. Results are shown in FIG. 2 (green line). The compressor startup procedure was optimized, achieving smooth system pressurization while the compressor was protected from surge. End-flash gas system: Motor trip case. Nearly 85% of the fuel gas is made by the end-flash gas coming from the heliumrecovery drum overheads and the nitrogen-stripping column overheads. Before combining together, both streams pass through the end-flash gas exchanger for heat recovery. The combined stream is then compressed to about 32 bara. There are two compressor trains with three stages each. A simplified process diagram is shown in FIG. 3. The performance of the anti-surge system during motor trip was studied extensively. It has been observed that the firststage compressor was surging upon trip (FIG. 4, blue line). To solve this problem, two options were examined to improve the system design: 1. Use a check valve at suction (FIG. 4, green line) 2. Use a hot-gas bypass (HGB) valve (FIG. 4, cyan line).

Head

Compressor curves (min. and max. speed) and surge line Startup with discharge isolation valve open Startup with discharge bypass valve pressure controlled and discharge on/off valve closed Startup with discharge bypass valve pressure controlled and antisurge controller released early

Residue gas

Compressor train 2 End-flash cold box

Check valve at suction suggested based on run results

ASC

LNG

ASC

ASC

Stripping gas

Heliumrecovery drum

Volumetric flow

FIG. 2. Compressor maps for the feed gas compressor system, with the movements of the operating point during compressor startup.

82AUGUST 2012 | HydrocarbonProcessing.com

Nitrogenstripping column

HG BV

HG BV

HG BV

Compressed fuel gas

Compressor train 1

FIG. 3. End-flash gas compressor simplified process flow diagram.


LNG Developments

Head

with a starting pressure increase to 1.5–2.5 bara. The case of defrost gas is shown in FIG. 6. To start the compressor with different compositions (C3 , N2 and defrost gas), a semi-automated approach was developed, based on the aforementioned results. The plant operator knows the current operation case (e.g., startup with defrost or propane gas) and presses the appropriate button on the distributed control system. The operator action ensures passing the necessary information to the compressor control system. The compressor control then adjusts the value of the first-stage C3 compressor anti-surge valve maximum opening/ CV through a software clamp, and it also defines the startup pressures and permissives required.

The compressor curves at the highest and lowest speed and surge line 1st stage: LP C3 antisurge valve CV = 1,600 Startup with a CV suitable for standard operations 1st stage: LP C3 antisurge valve CV = 2,600 Startup with a high CV Volumetric flow

FIG. 5. First-stage C3 compressor map during startup with propane (Liquefaction Case 1). The pink line shows the compressor curves at the highest and lowest speed and the surge line.

Head

Head

Both options appear valid. However, the results demonstrate that, if an HGB valve is used, high temperatures occur at the compressor discharge. This can be detrimental to the compressor seals. Based on these findings, it was recommended to modify the design and to use a check valve at the compressor suction. Liquefaction section: Refrigeration compressor cases. Refrigeration for this process is provided by two major systems: the C3 system and the MR system, containing nitrogen, methane, ethane and propane. The low-pressure MR is compressed in three stages of MR compressors. The high-pressure vapor from the discharge of the compression train is cooled and partially condensed by four C3 chillers in series. The partially condensed MR is fed to a high-pressure separator, where heavy MR and light MR are separated before entering the MCHE. The C3 refrigeration system utilizes C3 evaporating at four pressure levels to supply refrigeration to the natural gas feed and to the MR circuit. The chilled natural gas feed enters the MCHE, where it is liquefied. Case 1: Verification of compressor valve size. One of the objectives of the simulations performed was to verify the sizing of the compressor anti-surge valve. For the majority of the runs performed, it was noted that, for the low-pressure C3 compressor anti-surge valve, a valve size (calculated as CV) of 1,600 was adequate to protect from the risk of damage due to surge. However, while performing startup of the C3 system, the valve size proved to be insufficient. Results of the test cases examined are presented in the following figures. FIG. 5 shows a map of the C3 low-pressure (first-stage) compressor with anti-surge valve CVs of 1,600 (red line) and 2,600 (blue line), while starting up the system with propane. Using a CV of 1,600, the operating point appears to be in the surge region for a significant part of its path. The higher CV (2,600) is needed to start the compressor safely, with normal composition and pressure of 1.5 bara. However, when starting up the C3 system with defrost gas or N2 , the low-pressure C3 anti-surge control valve requires an even higher CV to protect from surge. A CV of 3,000 is needed to start the compressor safely with N2 or defrost gas, together

Compressor curves at the highest and lowest speed and surge line Base system design, using neither an NRV nor a hot-gas bypass Using a non-return valve at the suction of the system discharge Using a hot-gas bypass valve Volumetric flow

FIG. 4. First-stage fuel gas compressor map during motor trip.

Compressor curve at the nominal speed and surge line LP ASV CV = 1,600 LP ASV CV = 2,600 LP ASV CV = 3,000 Volumetric flow

FIG. 6. First-stage C3 compressor map during startup with defrost gas (Liquefaction Case 1). The pink line shows the compressor curve at the nominal speed and the surge line. The blue, green and pink lines demonstrate the operating point using different CVs. A high CV is required for safe operation when defrost gas is used. Compare with FIG. 5. Hydrocarbon Processing | AUGUST 201283


LNG Developments The different approaches used in valve design by vendors are worth mentioning. The typical valve design is based on a number of distinct/discreet operation cases at steady-state conditions. Each case may be based on different gas conditions at the suction and discharge of the valve (e.g., gas temperature, pressure, density, etc.). With dynamic simulation, it is possible to explore a continuous set of plant conditions. For example, during a simulated compressor startup, all plant conditions from the settle out/trip to the final steady-state conditions are visited. These include intermediate conditions with increasing compressor speed, varying suction/discharge compressor temperatures, ΔP across the anti-surge valve, etc. In brief, using dynamic simulation, the engineering study team was able to evaluate design modifications and to capture cases where the original valve design was not satisfactory for startup.

Head

Compressor curves (min. and max. speed) and surge line Case (a) HGB valve with CV = 1,000, opening in 1 sec., and bleed valve opening in 20 sec. Case (b) HGB valve with CV = 500, opening in 1 sec., and bleed valve opening in 20 sec. Case (c) no HGB valve, and bleed valve opening in 1 sec. Final design; HGB valve with CV = 700, opening in 3 sec., and bleed valve opening in 1 sec.

Volumetric flow

Head

FIG. 7. Low-pressure MR compressor map upon MR compressor trip (Liquefaction Case 2). The pink line shows the compressor curves at the highest and lowest inlet guide vane positions and the surge line.

Compressor curves (min. and max. speed) and surge line Base design case, with the MR anti-surge valves responding to the disturbance in the propane system Proactive opening of the MR anti-surge valves based on a feed-forward signal

Volumetric flow

FIG. 8. Low-pressure MR compressor map on C3 compressor trip (Liquefaction Case 3).

84AUGUST 2012 | HydrocarbonProcessing.com

Case 2: MR compressor HGB valve design. Another objective of this dynamic simulation study for the low-pressure MR compressor was to confirm the requirement for an HGB valve and its stroking time. Note that the low-pressure MR compressor is provided with a bleed valve and a discharge pressure control valve to flare. A number of sensitivity test runs were conducted. It was determined that the bleed valve opening time could be reduced to 1 sec. Furthermore, it was shown that, by opening the bleed valve quickly and the discharge valve to flare relatively slowly, the HGB valve size could be reduced, or the valve itself could be removed. Results are demonstrated in FIG. 7. To compensate for any uncertainties, it was decided to maintain the original design (i.e., maintain the HGB valve with a small size). Case 3: Valve opening on compressor trip. As soon as the C3/HP MR compressor driver was tripped, the compressor speed decreased, as expected. However, the simulation run showed a pronounced effect on the MR compressors. The first stage of MR compressor was entering the surge region upon C3 compressor trip. A series of simulation test cases revealed that, to protect the MR compressor from surge upon C3 compressor trip, both the low- and medium-pressure MR compressor anti-surge valves must open shortly after the C3 trip, following a feed-forward signal. The performance map of the low-pressure MR compressor with the aforementioned feed-forward signal to the lowpressure MR anti-surge valve can be seen in FIG. 8. Lessons learned and execution methodology. It is chal-

lenging to perform a meaningful dynamic simulation study. To ensure useful results, some principles must be understood and basic guidelines must be followed: • An engineering study is a dynamic process. It requires continuous interaction between the EPC contractor, the dynamic simulation provider, the equipment vendors and the client at all levels (managerial, technical, etc.). Excellent cooperation must be achieved to turn the study into important findings and appropriate process design changes. • Small teams of engineers with good process understanding and the ability to cooperate will drive the project to success. The team should remain the same throughout the project execution. • The plant data used for the study must be accurate and consistent. After some point, data changes should be minimized to have consistent and comparable results, while avoiding a series of costly sensitivity-simulation runs. • For all test cases, detailed procedures are required and should be communicated in writing. This step ensures common understanding, targets and methodology. • The simulation models must be of high fidelity. Special attention should be devoted to all critical parameters that could possibly invalidate the study results (isometrics, valve sizes and timings, compressor and driver inertia, compressor curves, etc.). • Models should be approved before proceeding to results generation. The following should be reviewed and accepted: a. Model topology and match with P&IDs b. Main data used c. Match with heat and mass balance d. Isometrics e. Compressor curves and inertia values used.


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• After the simulation models are prepared, it is critical to debug the models by running a series of test cases. These can reveal model weaknesses. At the same time, early findings can be communicated so that the direction of investigation can be set. From a project management point of view, a dynamic simulation study follows a relatively standard schedule that can be changed according to project-specific needs and requirements. The main elements are: • The kickoff meeting is where the study’s targets are confirmed and data are provided. • When the model is prepared, a report describing the match of the models to the data and the heat and mass balance is delivered. The model validation test follows. The delivered models and associated reports are examined to ensure the match with the actual plant design. This model review can be an offline activity. However, face-to-face meetings are advisable to improve the communication of findings. Such meetings present ideal settings to finalize the procedure for every simulation test case. • After the model review meeting(s) are conducted, the dynamic models are updated and retested, the individual cases are examined, and the individual run reports are delivered. Early findings are communicated, and the direction of investigation is discussed. • A number of review meetings should be arranged to closely monitor the project execution and to discuss important findings or challenges that must be addressed to avoid delays and project risks. • The dynamic study completion is accompanied by the appropriate deliverables, including the final project report. This report includes:

a. b. c. d. e.

An executive summary The study objectives Model scope and description Stream comparison Individual studies and results.

Benefits. The work performed for the GNL3Z project il-

lustrates that dynamic simulation can be an excellent tool for the support and verification of process design during the engineering, procurement and plant construction (EPC) stages. The advantages of dynamic simulation are becoming more important and valuable, as evidenced by the fact that dynamic simulation is increasingly included as a fundamental engineering step. Experience has revealed several attractive attributes of dynamic simulation: • A dynamic simulation study is a useful tool for process verification and optimization of operating procedures, along with control and protection systems. Through critical results analysis and comparison with project constraints, it is possible to improve the quality of process design. In turn, the early implementation of improved solutions reduces total project cost. • Dynamic simulation can reproduce the behavior of a real plant and offer process insight that cannot be obtained with traditional steady-state simulators. Using dynamic models and studies through all of the engineering phases improves knowledge of process dynamics. This understanding is fundamental during plant startup and for the identification and resolution of process bottlenecks. • The evaluation of sequences and procedures involving rotating equipment and important packages during the engineering stage increases process controllability and reliability. Hydrocarbon Processing | AUGUST 201285


LNG Developments Furthermore, the machine/package vendor can verify and implement suggested improvements in control functionality. • By maintaining the dynamic model (i.e., ensuring that it tracks the adjustments applied onsite during the commissioning and startup phases), it is possible to extend the life and value of the simulation well beyond the engineering stage. Any update/improvement of the control schemes, the creation of “what-if ” scenarios, etc., can be easily implemented using the simulation study model. In the current project, the use of dynamic simulation delivered significant estimated value: around 1% of capital expenditure ($30–$60 million) at plant commissioning, taking into account the minimization of reworks and the avoidance of prolonged commissioning activities. Increased process reliability is estimated to yield around $10 million per year. To capture these benefits and boost confidence in the plant design, it is critical to have an appropriate project execution strategy that includes: • A recognized and validated modeling tool • An experienced project team with a significant track record • An accurately defined scope of work and a flexible project execution plan • Maturity of design and availability of actual equipment data during the early construction stage, which allows for the timely implementation of study findings into the actual plant. Failing to take into account the aforementioned measures significantly increases the risk that potential benefits will not be realized.

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LITERATURE CITED Psarrou, S., Y. Bessiris, I. Phillips and V. I. Harismiadis, “Dynamic simulation useful for reviewing plant control, design,” Oil & Gas Journal, Vol. 105 (30), August 13, 2007. 2 Al-Dossary, A., M. Al-Juaid, C. Brusamolino, R. Meloni, V. Mertzanis and V. I. Harismiadis, “Optimize Plant Performance Using Dynamic Simulation,” Hydrocarbon Processing, June 2009. 3 Panigrahy, P., J. Balmer, M. A. Alos, M. Brodkorb, B. Marshall, “Dynamics break the bottleneck,” Hydrocarbon Engineering, Vol. 16 (9), September 2011. 4 Price, B. C., “Small-scale LNG facility development,” Hydrocarbon Processing, January 2003. 5 Foglietta, J. H., “Consider dual independent expander refrigeration for LNG production,” Hydrocarbon Processing, January 2004. 6 Harrold, D., “Design a turnkey floating LNG facility,” Hydrocarbon Processing, July 2004. 1

ANTON MARCO FANTOLINI is the LNG technology manager at Saipem. He holds a degree in chemical engineering and has 14 years of experience in the oil and gas industry, with concentrations in LNG plant design and development during the conceptual, FEED and EPC phases. LUIGI PEDONE is a lead control engineer with Saipem’s automation and control department. He holds a degree in chemical engineering and has 12 years of experience in the oil and gas industry. His areas of focus include dynamic and operator training simulators, management information systems, and advanced process control.

LUCA D’ORAZI is a process engineer with Saipem. He holds a degree in chemical engineering and has six years of experience in the oil and gas industry, with a concentration in plant simulation.

RAMONA PRODAN is a technical engineer specializing in control systems and automation. She has more than five years of professional experience in the oil and gas industry. She holds a BS degree in chemical engineering from the Petroleum Gas University of Ploiesti, Romania.

ANKUSH SOOD is a team leader with Hyperion Systems Engineering in Pune, India. He has seven years of experience in the oil and gas industry, including five years of delivering engineering studies for centrifugal compressors and developing high-fidelity operator training simulators. He holds a BSc degree in chemical engineering from Punjab Technical University.

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GIRISH BHATTAD is a team leader with Hyperion Systems Engineering in Pune, India. He has eight years of experience in the oil and gas industry, including four years of developing highfidelity operator training simulators and delivering engineering studies. He holds an MTech degree in process engineering and design from The Indian Institute of Technology Delhi.

DIONYSIOS STAVRAKAS is a senior engineer at Hyperion Systems Engineering in Athens, Greece. He has five years of experience in delivering high-fidelity engineering studies and developing operator training simulators. He holds an MSc degree in chemical engineering and energy production and management from The National Technical University of Athens.

VASSILIS HARISMIADIS is the real-time optimization and training simulation manager at Hyperion Systems Engineering. He has 12 years of experience in the oil and gas industry, with a focus on using dynamic process modeling to improve plant efficiency. Dr. Harismiadis holds a PhD in thermodynamic modeling of complex systems from NTU Athens.


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Bonus Report

LNG Developments S. SHARMA, Hunt Oil Co., Peru; D. HILL, P. RANO, G. HUMPHREY and M. MAYER, CB&I, Peru

PERU LNG: Executing Peru’s largest industrial project PERU LNG is Latin America’s first liquefied natural gas (LNG) export project. It was developed by a consortium of Hunt Oil Co. (50%), SK Energy (20%), Repsol YPF (20%) and Marubeni Corp. (10%). The PERU LNG project includes a liquefaction plant, marine export facilities with an island breakwater, and a 408-km pipeline that connects to an existing pipeline in the Ayacucho mountains. Hunt Oil Co. is the operator of the PERU LNG liquefaction plant and LNG loading terminal, and Stream—a joint venture of Repsol YPF and Gas Natural—has exclusive rights to market the 4.5 million metric tons (metric MMt) of LNG produced each year. Total investment for the project was US$3.8 billion (B). Included in this amount were the liquefaction plant ($1.5 B), which was awarded as a lump-sum turnkey EPC contract; marine and pipeline facilities; and development and financing costs. Of the $3.8 B investment, over $1 B was targeted for investment within Peru for goods and services in the Pampa Melchorita region. The project is expected to boost Peru’s GDP by an average of 0.5%/yr and generate approximately $1.3 B of hard currency export revenues annually, while increasing the country’s exports by an estimated 4.2%.1

In addition, there were several criteria specific to Peru that needed to be addressed: • Site elevation of at least 20 m required to mitigate the effects of tsunamis • Stable soils to prevent damage from Peru’s high level of seismic activity; i.e., no potential for soil liquefaction from earthquakes and no nearby identified fault systems or seismically unstable soils • No archeological impact. Initially, 17 sites were evaluated. From this selection, three sites were shortlisted: Pampa Clarita, Punta Corriente and Pampa Melchorita. A more detailed assessment was applied to these sites, including environmental studies; onshore and offshore studies; and geotechnical, archaeological and socioeconomic assessments. Pampa Clarita, located 154 km south of Lima, was initially the preferred site since engineering studies revealed Chosica Callao

Antioquia

Lima

Safety focus. Safety was a core value for all who worked on

the project. All onsite activities were executed in a manner to ensure the health and safety of every person working on the project. The commitment to safety is clearly demonstrated by the safety record of the PERU LNG project. Over the duration of the project, the main contractor and subcontractors expended more than 29 million work-hours with a recordable incident rate of 0.10 and a lost-time incident rate of 0.01. Site selection. The selection of a suitable site for the location of the LNG facility was one of the first steps in the planning phase. Typical site selection criteria were evaluated: • Environmental sensitivity, e.g. protected flora and fauna, and sensitive ecosystems • Potential social impact and proximity to populated areas • Marine suitability—i.e., sea conditions, such as currents, wave heights, and water depth sufficiency for LNG carrier berthing and loading operations • Initial dredging and maintenance dredging requirements • Land availability for facility (and potential future expansion) • Soil conditions • Proximity to labor and raw materials • Logistics of transporting equipment and materials.

Mala

Quilmana Imperial

Peru LNG

Chincha Alta

Pisco Parakas Ica Santiago

Tinque

FIG. 1. The location of the PERU LNG site along the South Pan American Highway. Hydrocarbon Processing | AUGUST 201289


LNG Developments that the site offered the most technically favorable conditions. However, an archaeological site evaluation led to the discovery of the mummified remains of a two-year-old boy that had been buried under Pampa Clarita for an estimated 500 years. To avoid disruption of the area’s cultural heritage, Pampa Clarita was dismissed as a possible site. The Punta Corriente site also was eliminated due to its limited land space in an already heavily developed area. The evaluation eventually led to the selection of Pampa Melchorita as the best option, based on a suite of environmental, technical and economic considerations.2 Pampa Melchorita (FIG. 1) initially was considered the third-likeliest site for the project because of its elevated location—140 m above sea level—and its requirement for a significant investment in road access to the beach. However, the location was ultimately chosen as the site for the LNG facility since it satisfied the following key criteria: • Sufficient land space available (for the current project and potential future expansions) • Area of minimal environmental impact (FIG. 2) • Low population density • Site elevation significantly higher than the 20 m above mean sea level required to mitigate tsunami effects • Potential for soil liquefaction, soil instability and seismic impacts were as low as could reasonably be expected in Peru • Intensive dredging not required

• Reasonable sea conditions suitable for reliable tanker berthing operations • Relatively close to commercial centers that could provide raw materials and labor. Process facilities. The LNG plant has a number of unusual

features and design challenges due to the nature of the feed gas (FIG. 3). The natural gas feed delivered to the plant is the residue product gas from a natural gas liquids (NGLs) extraction plant located at Malvinas. The majority of the hydrocarbons heavier than ethane have already been removed from this feed. As a result, the feed gas is very lean, consisting predominantly of methane and ethane with a small quantity of inerts and a nominal concentration of propane. As a result of the upstream liquids recovery, there is no requirement for LPG or condensate removal within the plant, either to satisfy LNG product specifications or to prevent freezing of these components in the cryogenic sections of the plant. Unfortunately, this also means there is no ability to extract the necessary refrigerants required for the liquefaction process, and so refrigerants must be imported. Feed gas treatment. In terms of feed gas treatment, the

PERU LNG facility has a fairly straightforward set of processes. Acid gas contaminants, principally carbon dioxide (CO2 ), are removed using an activated methyl diethanolamine (MDEA) process. After acid gas removal, the water-saturated gas is cooled to condense about half of the water. The gas is then passed through molecular sieve beds to remove the remaining water to less than 1 ppmv, to prevent freezing and plugging in the cryogenic liquefaction unit. There is no known mercury in the feed gas; however, as a precaution, a guard bed using activated carbon has been included upstream of the main heat exchanger. Liquefaction. The liquefaction process is based on a propane-

FIG. 2. The PERU LNG facility is located on a strip of uninhabited desert 140 m above sea level.

F/G Natural gas Inlet, metering and knockout

ATM

Acid gas removal Liquids

F/G

LNG storage Main cryogenic heat exchanger

PR loop 4

5

6

MR loop 1

2

FIG. 3. PERU LNG process flow diagram.

90AUGUST 2012 | HydrocarbonProcessing.com

3

precooled, mixed-component refrigerant process. The feed gas is first precooled using propane refrigerant at four descending pressure levels and corresponding temperature levels. After being cooled by the propane refrigerant, the feed gas directly enters the main cryoF/G Dehydration genic heat exchanger (MCHE); no scrub column is provided. In the MCHE, the feed gas is further cooled and totally condensed by the mixed refrigerant (MR). The pressure of Water the subcooled LNG leaving the MCHE is reduced across a control valve and sent to the LNG storage tanks. The proMercury cess uses four refrigeration compressors. removal The propane compressor and the highpressure MR compressor are driven by 4 1 a single Frame 7 gas turbine and helper 5 2 motor. The low- and medium-pressure 6 3 MR compressors are driven by a second Frame 7 gas turbine and helper motor. Methane LNG rundown from the MCHE is N2 Ethylene stored in two single-containment LNG storage tanks; each has a capacity of 130,000 m3. It has been possible to use


LNG Developments single-containment tanks, as there is sufficient space available to accommodate a secondary containment area, and to satisfy all of the necessary regulatory and safety criteria. The facilities are self-sufficient in utilities. A desalination plant provides process and potable water. Nitrogen and instrument air are produced onsite, and power is generated by aeroderivative gas turbine generators, which provide good overall thermal efficiency for the facility. Mixed refrigerant. The MR consists of nitrogen, methane,

ethane, ethylene and propane. The composition of the MR has been modified to include both ethane and ethylene, due to the unusual nature of the feed gas. Nitrogen is generated onsite, and methane and ethane makeup is supplied from the feed gas. However, the ratio of ethane to methane in the feed gas is much lower than the ethane-to-methane ratio desired in the MR. Ethylene is added to the MR to enable optimum performance. Ethylene provides similar process performance to ethane, but it must be obtained from remote sources. While propane is locally available, for sufficient quantities, it must also be imported. Environmental challenges. The project faced a number of

environmental and design challenges, several of which are described below. Soil conditions. One of the unusual challenges of the Pampa Melchorita site involves soil conditions (FIG. 4). The soil has a high salt content, between 15% and 20%, which impacted the design and engineering in a number of unexpected ways: • All of the foundations were constructed using sulfur-resistant concrete, to prevent corrosion due to the saline nature of the soil • The site is located in a coastal desert environment with low annual rainfall; however, a wastewater collection system was still needed, since water used in the event of a fire could wash out the soil around the foundations if not captured and collected. Seismic conditions. The project site is located in one of the most seismically active regions in the world, where the Pacific plate meets the South American plate. The movement of the plates is predictable—approximately 10 cm/yr, with the Pacific plate moving underneath the South American plate. However, the plates do not move smoothly past each other, which leads to increasing stress and stored strain. This process continues until the strain rises to a point that enables the sliding of the plates to continue. When this occurs, there is a sudden release of energy that is experienced as an earthquake. The LNG plant has been designed to withstand two seismic levels as defined in the Operating Basis Earthquake (OBE), the Safe Shutdown Earthquake (SSE) and the NFPA 59A (Production, Storage and Handling of Liquefied Natural Gas) guidelines (FIG. 5). The OBE guideline, which describes earthquake activity to which a facility can be subjected during its design life, is defined as ground motion having a 10% probability of being exceeded within a 50-year period. The philosophy of the OBE is that the plant is expected to withstand such an earthquake without substantial damage or significant interruption of plant operations (i.e., no major repairs). The SSE guideline details the maximum considered earthquake ground motion as having a 2% probability of being ex-

ceeded in a 50-year period. The main purpose of the SSE design guideline is to safeguard against uncontrolled failure, collapse, and loss of containment, which could otherwise lead to catastrophic consequences and loss of life. In essence, this means that pressure containment integrity is maintained; however, the equipment may be subjected to substantial damage, to the extent that it may not be reusable. The PERU LNG plant has been designed for peak horizontal accelerations during an earthquake of 0.875 g and 1.6 g for OBE and SSE compliance, respectively. For comparative purposes, in areas of low seismic activity, such as the UK, peak horizontal accelerations for similar return periods would be in the order of 0.05 g. Although the Richter magnitude scale is not a metric normally used in the design of structures, the SSE seismic maximum is approximately equivalent to 8.4 on the Richter scale. Piping design. The high seismic loading also required special consideration in the piping design. The design required a balance between the need to provide flexibility for the thermal expansion and contraction of the lines, and the need for the lines to be rigid and heavily anchored for seismic resistance. The piping support and pipe reinforcement designs were reevaluated and compared to an LNG plant with low seismic design criteria. Another consequence of the seismic design was the impact of the calculated piping loads on the design of the pipe support structures. As an example, the loads generated by an 8-in. line at the PERU LNG facility are equivalent to those generated by a 24-in. line at a similar plant with low seismic criteria. The high seismic loading also imposed height restrictions on equipment design. For example, the LNG storage tanks have an outer shell diameter of 78 m and an outer tank height of 35 m. Air cooler racks were reduced in height, and additional nozzle stress calculations were performed on vessels and compressors—particularly the refrigerant compressors—to reduce nozzle loads. Structural considerations. As a consequence of the increased loads calculated for the piping, the steel members and beams of the pipe support structures (and, consequently, their foundations) are significantly larger and stronger than those found in a typical plant, with specifications approaching nuclear industry requirements. State-of-the-art methods were used in the design

FIG. 4. Early PERU LNG site preparation in the Pampa Melchorita region.

FIG. 5. LNG tanks are supported on a double-slab foundation incorporating seismic isolators. Hydrocarbon Processing | AUGUST 201291


LNG Developments

FIG. 6. The developed PERU LNG site.

of the structures to enable ductile movement of the frames, which encourages collapse of the beams but not the columns. Site elevation. The site, including the LNG tanks, is 140 m above sea level. This elevation difference led to several complex engineering issues related to the potential surge loads on the LNG loading lines, which run more than 2 km from the LNG tank to the shoreline and then along the jetty. Detailed surge analysis simulations were carried out to predict the surge loads and their implications for the piping and surge-relief design. Meeting the surge loads required the use of an atypical piping configuration with independently initiated protection systems, elevating design pressures, rapid-open valves and a surge drum.

Startup and initial operations. CB&I and PERU LNG formed a joint team to start up and operate the plant (FIG. 6). The initial drying/defrosting of the LNG train started in April 2010, just 39 months after the EPC contract was awarded. The first refrigerant was introduced into the propane circuit in May 2010, and the first LNG was produced six days later. Following purging, cooldown and loading, a cargo ship departed with the first LNG cargo on June 23, 2010—41 months after the EPC contract was awarded. After a performance test, facility acceptance was granted in October 2010. At that time, custody and control of the facility passed from CB&I to PERU LNG. Under CB&I’s control, the PERU LNG facility produced almost 2 MM m3 of LNG and loaded 11 LNG ships in the four-and-a-half months after the first drop of LNG was produced. The initial start of the system dryout to the completion of the cooldown took only 40 days—26 days for dryout and 14 days for cooldown, which compares favorably with the most successful LNG plant startups. Summarizing the impact of PERU LNG, Hunt Oil Co. stated that the culmination of this project positions Peru as a leader in the South American LNG industry, and the income it generates will provide further development and growth for the country and its people for decades to come. LITERATURE CITED Complete literature cited available online at HydrocarbonProcessing.com.

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Show Preview

Gastech

B. THINNES, Technical Editor AUTHOR NAME, company, location XXX

The premier event for the global natural gas industry Oct. 8–11, 2012 ExCeL Center London, UK Gastech Exhibition: • 10,000 industry professionals expected to attend • 300 international exhibitors confirmed • 50 top recruiting companies and organizations

Gastech Conference: • Features more than 120 prominent speakers and representatives • Four days of ministerial keynotes, commercial and technical and presentations, question and answer sessions and panel debates

Gastech Show Daily Newspaper: • Four days of coverage to be published by Hydrocarbon Processing • For information on submitting editorial or advertising, please contact Billy Thinnes at Billy.Thinnes@gulfpub.com

www.gastech.co.uk

Gastech is the global meeting place for energy professionals working in the natural gas industry. Operating on an 18 month cycle to ensure issues remain topical, the 26th edition of Gastech will take place at the ExCeL Conference and Exhibition Center in London’s Docklands, October 8–11, 2012. Originally set up to bring together the technical decision-makers involved in LNG and LPG shipping, Gastech now attracts the major technical and commercial players from around the world to meet, discuss and exchange ideas affecting the upstream, midstream, downstream and power generation sectors of the industry. Gas is proving to be an increasingly popular choice for power generation, industry and transport, as the cleanest fossil fuel available, while nuclear energy comes under intense scrutiny and renewable energy sources remain unreliable. Gastech exists to nourish and build relationships in the global energy community to ensure that gas remains at the forefront of the international energy mix. A landmark gathering. This year, Gastech reaches a landmark 40th birthday and

it has been a long, interesting journey that brings the gathering back to London for the first time since 1973. Back then, a gathering of engineers working in LNG and LPG shipping came together to discuss the technical challenges facing the industry. Gastech has grown substantially since then, and it now attracts not only industry engineers but also key global government figures and international executives. It has been a turbulent and eventful year for the global gas community, with increased demand for LNG in Asia spurred on by the region’s economic growth and a post-Fukushima landscape that has seen a move away from nuclear power. China’s choices in natural gas will be followed closely: Will it choose to develop more LNG import facilities or exploit its own vast, unconventional natural gas resources? Within a few years, Australia could become an even larger producer of LNG than Qatar, while LNG exports will be making their way out of North America and on to new markets. But what will become of major international project investment and development in these economic times? What will the Eurozone crisis mean for infrastructure investments? And how can gas be better monetized as low prices in North America continue to drive the renaissance for alternative uses of gas within the chemical industry? What remains clear is that the current “dash for gas” is likely to be sustained and rapid. Gastech exists as a solid forum to address the issues that matter to the decision-makers, investors, stakeholders and engineering contractors delivering gas to the world’s markets.

Conference. The Gastech conference brings the world’s professional gas community together, to understand the issues impacting the business today and in the future. An important meeting place, Gastech offers delegates face-to-face networking at the very highest level. The conference features more than 120 of the industry’s most prominent speakers and representatives, and is comprised of ministerial keynotes, company addresses, technical presentations, question and answer sessions and panel debates. Two of the panel discussions really stand out on the first day of the conference. The Executive Leadership panel will examine the question, “Have we entered the Hydrocarbon Processing | AUGUST 201293


Gastech Preview golden age for gas?” Heavy hitters on that panel include Bill Dudley, president and CEO of Bechtel; Helge Lund, president and CEO of Statoil; Shigeru Muraki, executive vice president and energy chief executive of Tokyo Gas Co.; and Hamad Rashid Al-Mohannadi, vice-chairman of Qatar Petroleum. The second noteworthy panel on Monday is the Regional Executive Leadership panel. These folks will discuss, “Europe: Security of supply vs. liberalization.” Notable panel members include Sergi Shmatko, Russia’s minister of energy; Chris Finlayson, executive director for BG Group; and Jean-Claude Depail, president for Gas Infrastructure Europe.

Tuesday and Wednesday of the conference feature two tracks of programming: commercial and technical. Subject matter includes natural gas and LNG projects; floating LNG; unconventional gas; gas technology; and gas monetization. Exhibition. Running alongside the conference, the exhibition will present a major showcase of the latest gas industry products, services, innovations and technologies, playing host to more than 300 exhibiting companies. Exhibitors hail from the downstream, midstream and upstream sectors of the gas supply chain, providing a valuable meeting place to network, conduct business and build strategic partnerships. Visitors to the exhibition constitute a cross-section of the gas industry comprising company representatives actively involved in sourcing suppliers, developing partnerships and making decisions that lead to the purchase of gas-related products and services. What follows is but a brief list of some of the companies exhibiting at Gastech. For a complete A-Z exhibitor list please visit, www.gastech.co.uk/exhibition. • ABS • Air Products • Anadarko Petroleum Corporation • BG Group • Black & Veatch • Bechtel • CB&I • Chevron Global Gas • E.ON Ruhrgas • ExxonMobil • Fluor • Hamworthy • Hanjin Heavy Industries • Iberdrola • Lloyd’s Register • Mustang • Samsung Heavy Industries • Shell • Sonatrach • Technip • Total • Wood Mackenzie • Worley Parsons • Yokogawa ignite! Co-located with Gastech, ignite!

offers a unique exhibition focusing on recruitment and personal and workforce development. The energy industry has reached a critical juncture regarding its dwindling talent pool, making recruitment as crucial as ever. ignite! aims to facilitate the task of finding the right qualified individuals to fill vacant positions. Supported by the Energy Institute, OPI-

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Gastech Preview TO, Telegraph Media Group, Euromoney Training, OilCareers.com and Saudi Aramco, the ignite! conference streams will be dedicated to the discussion of personal and workforce development issues, as well as an stream allowing exhibiting companies to reveal their developing projects and new recruitment opportunities. ignite! will provide a platform to meet over 3,000 active professionals seeking new employment in the natural gas industry. It removes the lengthy process of trying to source new talent, by putting exhibitors face to face with qualified individuals, without costly recruitment agency fees. Exhibitors including Saudi Aramco, Fluor, Worley Parsons and SBM will be utilizing this service to secure their recruit-

ment pipeline with experienced individuals looking to take that next step. Other companies are more than welcome to join them. For more information about ignite! please visit www.igniteyourcareer.co.uk. CoTEs. The Gastech Centers of Technical Excellence (CoTEs) are free to attend educational theaters located on the exhibition show floor. They are dedicated to delivering knowledge, education and awareness of technological innovations in the

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Gastech Preview gas industry. Gastech is working with many of the world’s mostrespected industry associations and organizations to bring together high-level speakers who will provide significant insights and updates about the latest developments in gas technology. The 12 CoTE streams for 2012 are: • Gas processing • Unconventional gas • Floating LNG • Cryogenics • Offshore and subsea technology • Carbon capture and storage • Power generation • Health, safety and environment • Engineering project delivery

• Pipelines and transmission • UK innovation • LNG shipping as fuel For more information about the CoTEs, please visit www. gastech.co.uk/CoTEs. Accommodation and travel. Congrex Travel AG is the of-

ficial booking agent for Gastech 2012 and has secured a number of hotel rooms to suit various budgets across London, offering Gastech attendees savings in money, time and hassle for both individual and group bookings. For more information or to book accommodations please visit www.gastech.co.uk/travel. As far as getting to Gastech, here are a few recommendations. If you are traveling by rail or subway, the Jubilee Line is recom-

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Gastech Preview mended as the quickest route to ExCeL from central London. Gastech attendees are advised to alight at Canning Town and change onto the Docklands Light Railway (DLR) bound for Beckton (DLR trains traveling toward ExCeL normally depart from Platform 3) and alight at the Prince Regent stop for Gastech. If you are traveling by road to Gastech, you should follow signs for Royal Docks, City Airport and ExCeL. There is easy access from the M25, M11, A406 and A13. If you are flying, ExCeL is easily accessible from London’s five main airports (London City, Heathrow, Gatwick, Stanstad and Luton) via the DLR, underground and mainline rail services. Attendees flying into London City airport, the closest of the five airports, can arrive at ExCeL in approximately five minutes by car or taxi. CONFERENCE PROGRAM AT A GLANCE Day One—Monday, October 8, 2012 Morning Session Opening Ministerial Speech Senior Representative of Her Majesty’s Government of the United Kingdom (name to be confirmed) Welcome and Keynote Speech Sir Frank Chapman, Chief Executive, BG Group The Executive Leadership Panel Discussion Exploring the theme of “A Golden Age for Gas?” Inspirational Guest Speaker Professor Brian Cox MBE, Research Fellow, Author, Broadcaster, CERN Project and BBC Television The VIP Opening of the Gastech Exhibition Floor Afternoon Session The Regional Executive Leadership Panel Discussions Europe—“Security of Supply versus Liberalization” The Americas—“From Demand Sink to Supplier” Asia-Pacific—“Meeting Demand Growth” Day Two—Tuesday, October 9, 2012 Commercial Streams Market Outlook (morning) Natural Gas and LNG Projects (afternoon) Technical Streams Gas Shipping and Storage (morning) Floating LNG (afternoon) Extra Streams Gas Trading, Origination and Regulation—with the European Federation of Energy Traders The Russian Seminar—with the support of RESTEC The Gastech Student Program Day Three—Wednesday, October 10, 2012 Commercial Streams Unconventional Gas (morning) Gas Monetization (afternoon) Technical Streams Advances in Gas Technology (morning) LNG for Transport (afternoon) Extra Stream Financing Gas Supply and Infrastructure Day Four—Thursday, October 11, 2012 (Morning Only)

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SALES OFFICES—NORTH AMERICA IL, LA, MO, OK, TX Josh Mayer Phone: +1 (972) 816-6745, Fax: +1 (972) 767-4442 E-mail: Josh.Mayer@GulfPub.com

AK, AL, AR, AZ, CA, CO, FL, GA, HI, IA, ID, IN, KS, KY, MI, MN, MS, MT, ND, NE, NM, NV, OR, SD, TN, TX, UT, WA, WI, WY, WESTERN CANADA Laura Kane Phone: +1 (713) 520-4449, Fax: +1 (713) 520-4459 Mobile: +1 (713) 412-2389 E-mail: Laura.Kane@GulfPub.com

CT, DC, DE, MA, MD, ME, NC, NH, NJ, NY, OH, PA, RI, SC, VA, VT, WV, EASTERN CANADA Merrie Lynch Phone: +1 (617) 357-8190, Fax: +1 (617) 357-8194 Mobile: +1 (617) 594-4943 E-mail: Merrie.Lynch@GulfPub.com

CLASSIFIED SALES Gerry Mayer Phone: +1 (972) 816-3534, Fax: +1 (972) 767-4442 E-mail: Gerry.Mayer@GulfPub.com

DATA PRODUCTS Lee Nichols Phone: +1 (713) 525-4626, Fax: +1 (713) 520-4433 E-mail: Lee.Nichols@GulfPub.com

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FRANCE, GREECE, NORTH AFRICA, MIDDLE EAST, SPAIN, PORTUGAL, SOUTHERN BELGIUM, LUXEMBOURG, SWITZERLAND, GERMANY, AUSTRIA, TURKEY Catherine Watkins Tél.: +33 (0)1 30 47 92 51 Fax: +33 (0)1 30 47 92 40 E-mail: Watkins@GulfPub.com

Alfred Bilyk Phone/Fax: 11 23 37 42 40 Mobile: 11 85 86 52 59 E-mail: Brazil@GulfPub.com

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ITALY, EASTERN EUROPE Fabio Potestá Mediapoint & Communications SRL Phone: +39 (010) 570-4948 Fax: +39 (010) 553-0088 E-mail: Fabio.Potesta@GulfPub.com

INDONESIA, MALAYSIA, SINGAPORE, THAILAND Peggy Thay Publicitas Singapore Pte Ltd Phone: +65 6836-2272 Fax: +65 6634-5231 E-mail: Singapore@GulfPub.com

RUSSIA/FSU Lilia Fedotova Anik International & Co. Ltd. Phone: +7 (495) 628-10-333 E-mail: Lilia.Fedotova@GulfPub.com

JAPAN—Tokyo Yoshinori Ikeda Pacific Business Inc. Phone: +81 (3) 3661-6138 Fax: +81 (3) 3661-6139 E-mail: Japan@GulfPub.com

UNITED KINGDOM/SCANDINAVIA, NORTHERN BELGIUM, THE NETHERLANDS Michael Brown Phone: +44 161 440 0854 Mobile: +44 79866 34646 E-mail: Michael.Brown@GulfPub.com

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ADVERTISERS INDEX / HydrocarbonProcessing.com The first number after the company name is the page on which an advertisement appears. The second number, appearing in parentheses, after the company name, is the Reader Service Number. There are two ways readers can obtain product and service information: 1. Go to www.HydrocarbonProcessing.com/RS. Follow the instructions on the screen, and your request will be forwarded for immediate action. 2. Go online to the advertiser's Website listed below.

Company

Page

RS#

Website

Air Products & Chemicals Inc. ..............26

Company

Page

RS#

Website

(56)

www.info.hotims.com/41431-56

Gas & Air Systems...............................88

(76)

(62)

Gastech .............................................79

www.info.hotims.com/41431-62

Axens .............................................. 104

(53)

(70)

www.info.hotims.com/41431-70

General Electric Company ...................10

Bently Pressurized Bearing Co .............62 (163) www.info.hotims.com/41431-163

Grace GmbH & Co. Kg......................... 94

(85)

(64)

(77)

www.info.hotims.com/41431-77

Paratherm Corporation ....................... 18

Gulf Publishing Company

(84)

www.info.hotims.com/41431-84

ONIS, Inc.........................................S-72 (171)

(58)

www.info.hotims.com/41431-58

Merichem Company.......................... 103

www.info.hotims.com/41431-171

(161)

Linde Process Plants ........................ 66A

Merichem Company............................36

www.info.hotims.com/41431-64

www.info.hotims.com/41431-53

BIC Alliance........................................56

GE Oil & Gas .......................................50

RS#

www.info.hotims.com/41431-85

www.info.hotims.com/41431-154

Aramco Overseas Company B.V............87

Page

Website

www.info.hotims.com/41431-76

Altra .................................................23 (154)

Company

(153)

www.info.hotims.com/41431-153

www.info.hotims.com/41431-161

Borsig GmbH .....................................29 (156) (55)

Quest Integrity Group LLC....................55 (160)

Events—EMGC ...............................S-78

www.info.hotims.com/41431-160

www.info.hotims.com/41431-55

Colfax Americas .................................34

(86)

Compressor Controls ..........................97

Events—MITO ............................... S-68

Rentech Boiler System ......................... 2

Events—WGLC ................................. 66

www.info.hotims.com/41431-86

(174) (68)

Scott Safety ....................................S-74

Marketplace ...............................98–99 Hermetic Pumpen GmbH ................... 60 (162)

Cudd Energy Services .........................43 (158)

(83)

www.info.hotims.com/41431-73

www.info.hotims.com/41431-159

Spraying Systems Co .......................... 17

www.info.hotims.com/41431-83

www.info.hotims.com/41431-158

(73)

SO.CA.P. SRL ...................................... 49 (159)

www.info.hotims.com/41431-162

www.info.hotims.com/41431-68

Hydro, Inc........................................6–7

(52)

www.info.hotims.com/41431-52

www.info.hotims.com/41431-174

Costacurta SpA Vico ......................... 66A

(61)

www.info.hotims.com/41431-61

Event—HPI China............................100

www.info.hotims.com/41431-156

Cameron ...........................................20

PARCOL SpA ....................................... 19

Boxscore .........................................32

(66)

www.info.hotims.com/41431-66

Detector Electronics.........................S-76 (166) www.info.hotims.com/41431-166

Dresser-Rand..................................... 13

Trachte USA .......................................63 (165)

www.info.hotims.com/41431-168

(60)

www.info.hotims.com/41431-60

Inpro/Seal Company...........................92 (170)

www.info.hotims.com/41431-169

(157)

www.info.hotims.com/41431-165

Vega Americas, Inc. ............................ 16 (152)

www.info.hotims.com/41431-170

Dresser-Rand.....................................86 (169) Flexim Americas Corp. ........................30

HyTorc ...............................................85 (168)

ITW Polymer Technologies/ Chockfast........................................63 (164)

www.info.hotims.com/41431-152

Weir Minerals Lewis Pumps ................. 14

(94)

www.info.hotims.com/41431-94

www.info.hotims.com/41431-164

www.info.hotims.com/41431-157

Flexitallic LP ....................................... 5

(93)

www.info.hotims.com/41431-93

Fluid Components International ..........28 (155)

www.info.hotims.com/41431-151

(59)

Koch-Glitsch ......................................95

(151)

LA Turbine ........................................ 96 www.info.hotims.com/41431-173

Winsted Corporation .......................S-77 (167) www.info.hotims.com/41431-167

www.info.hotims.com/41431-59

(172)

www.info.hotims.com/41431-172

www.info.hotims.com/41431-155

FourQuest Energy................................ 4

KBR...................................................25

Wood Group Mustang ........................ 64

(98)

www.info.hotims.com/41431-98

(173)

ZymeFlow Decon Technology ..............33

(92)

www.info.hotims.com/41431-92

This Index and procedure for securing additional information is provided as a service to World Oil advertisers and a convenience to our readers. Gulf Publishing Company is not responsible for omissions or errors. Hydrocarbon Processing | AUGUST 2012101


Control

ALLAN KERN, GUEST COLUMNIST Allan.Kern@APCperformance.com

Automation: The path to reliability Consider the view looking back from 2020. Will the current decade be the decade of process automation? This may seem a puzzling way to frame the question. We have been automating for several decades. To understand the question, we must define the distinctions between modernization, automation and optimization. In investigating the net effects in how the process industry does business and operates facilities today, one conclusion is that the process-control business has been involved primarily in modernization, to some degree optimization, and least of all automation. That is surprising, since automation was the initial goal. What came first? Modernization and its prodigious offspring,

information, have been several fold. Control-system success has often meant just keeping pace with technological change—completely separate from automation and optimization. Control systems have evolved from pneumatic to analog, digital, distributed and, now, open systems. Safety systems and field devices have undergone similar evolutions. Business pressures compel adopting each successive technology. Most people are only too familiar with the pace and demands of modernization. It would be nice if, like information, automation sprang naturally from modernization. But that is not at all the case. It is quite possible to keep pace through multiple modernization cycles without ever making headway in automation. Indeed, this is the present condition for many companies. Processing plants are more modernized, but the difficult challenges of sustaining reliable operation still remain.

matic distributed-control system (DCS), safety instrumented system (SIS) and other base-layer functions. Optimization. Let’s define optimization as activities that take

place in the business domain. They have the objective of arriving at optimal operating targets, or making optimal business decisions that are implemented across the organization. Optimization has been sustained by constant improvement on information flows. Many resources participate in this task across an organization. In many ways, the entire business is “plugged into” this mission; the automation domain is just one aspect. However financially winning optimization can be, plant reliability is not one of its usual consequences. Little such carefree collaboration characterizes the automation domain, where equipment and procedures often defy automation solutions; implementation is laborious; mistakes are painful; and critical skills are scarce. This is one hurdle to automation. The control domain is not a very hospitable environment. Modernization vs. automation. With these definitions in hand, it becomes clear that continued modernization and greater automation are the challenges before us. Modernization will continue to bring reliability and efficiency gains, such as centralized monitoring, remote control, lower cost and less nuisance trips, if not exactly automation. Greater automation, while harder to come by, can ultimately be expected to bring the same transformational improvements in safety, reliability and quality as in many manufacturing industries. Next decade. The single biggest challenge facing process

What is ‘modern’ control? For example, modern control sys-

tems are digital and not pneumatic. However, are there fewer operators in the field, fewer process upsets, and fewer equipment trips? Are more valves in automatic mode, with less frequent reliance on manual mode? Are board operators less alarm-driven and more procedure-driven? Are more procedures and sequential operations automated? While the answer to these questions may be a tentative “yes,” in most cases, the improvement has been incremental and stems from modernization, not automation. The answer that we wish to see is that process industries have achieved the same transformational level of automation as many manufacturing industries. Automation. Let’s define automation as automatic control that takes place in the control system domain. This fits the traditional concept of automation involving direct control of equipment or machinery. This includes, most notably, advanced regulatory control (ARC), multivariable control (MPC) and sequential control. But it really includes all auto102AUGUST 2012 | HydrocarbonProcessing.com

plants today is reliability. And automation is the single best answer. Will this decade become the automation decade? The situation is unfolding slowly, with manufacturers still engaged in modernization, broadly tackling the optimization puzzle and, when it comes to automation, still focused primarily on MPC, which is only one piece of automation. Perhaps, the 2020s will eventually unfold as the decade of automation. Those companies who start the automation process early may find themselves leading the industry over the next decade. ALLAN KERN has 30 years of process control experience and has authored numerous papers on advanced process control with emphasis on operation and practical process control effectiveness. Mr. Kern is a professional engineer, a senior member of ISA, and a graduate of the University of Wyoming.


Sweet Solutions.速

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HP_2012_08