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LNG AND GAS PROCESSING Technology solutions help optimize plant efficiency ®

HydrocarbonProcessing.com | JANUARY 2013

FLUID FLOW/ HEAT TRANSFER Improve pressure relief systems and steam networks

FUEL TRENDS Asia-Pacific on track to become world’s largest NGV market

Customer:

Challenge:

Result:

Ethylene processor, Texas, USA Compressor load instability caused by variations in suction conditions. Elliott installed Tri-Sen’s TSx compressor controls to keep the compressor load and quench ﬂow in phase.

They turned to Elliott

for better control of their process. The customer turned to Elliott for controls that prevent process instabilities. Elliott’s machinery expertise allied with Tri-Sen’s controls leadership allows operators to focus on managing the process, not the machine. Who will you turn to?

EBARA CORPORATION www.elliott-turbo.com

C O M P R E S S O R S

T U R B I N E S

G L O B A L

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The world turns to Elliott.

JANUARY 2013 | Volume 92 Number 1 HydrocarbonProcessing.com

SPECIAL REPORT: LNG/GAS PROCESSING DEVELOPMENTS

37 Optimize LNG boil-off gas systems for regasification terminals M. Zolfkhani

41 Viability of GTL for the North American gas market E. Salehi, W. Nel and S. Save

51 Molecular sieves in gas processing: Effects and consequences by contaminants A. Terrigeol

59 Improve evaluation of brittle-fracture resistance for vessels J. R. Sims

ROTATING EQUIPMENT

DEPARTMENTS

4 8 11 15 21 86 89

FLUID FLOW

Reliability TAMU Turbo and Pump symposiums still leading

Integration Strategies 3D laser scanning delivers benefits in hydrocarbon processing facilities

J. White, D. Smith and B. Frenk

75 Improve your plantwide steam network R. O. Pelham

CLEAN FUELS

81 Refiners now have a new biofuel option A. Schubert

Innovations Associations Marketplace Advertiser index

69 Evaluate pressure relief system forces in existing installations HEAT TRANSFER DEVELOPMENTS

Brief Impact

COLUMNS

65 Update on wet and gas compressor seals H. P. Bloch

Industry Perspectives

Boxscore Construction Analysis Is the US on the verge of the next construction boom?

Viewpoint LNG: Fueling the future

Water Management Need a package boiler in a hurry?

Cover Image: The Pearl gas-to-liquids (GTL) project in Ras Laffan Industrial City, Qatar was jointly developed by Qatar Petroleum and Shell. It is the largest GTL complex in the world and the largest energy project to be launched in the state of Qatar. KBR, in conjunction with Japan Gas Co., provided project management and EPCM services for Pearl GTL. At full production, the plant will produce 140,000 bpd of high-quality GTL products and 120,000 bpd of oil equivalent of natural gas liquids (NGLs) and ethane.

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Industry Perspectives 2012: Is it over yet? According to a year-end report from the American Chemistry Council (ACC), the global economy is still stumbling three years after the “great recession of 2008.” The Euro area is challenged to move beyond recession conditions. China’s thriving economic expansion slowed in 2012 from the double-digit expansion of earlier years. The final thought on 2012 economic news can be summarized as confidence eroding. Global manufacturing entered a soft period in the 2012 summer; Europe and East Asia were the most affected regions.

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Looking for positive news has been a challenge in 2012. In the US, recovery in the manufacturing industry struggled against waves of uncertainty, such as the results of the fall elections, the failing consensus in the US Congress over raising the debt ceiling, future tax reforms and the looming fiscal cliff discussion during December. Uncertainty throughout 2012 has been unhealthy for the US and global economies. Manufacturing and HPI companies are fearful of possible government regulations. In response, these companies cut back business investments and delayed workforce expansion. What next? Global HPI leaders are divided on how to pre-

pare for the future. The global chemical industry has collectively made an improvement from dismal 2009 numbers. But, this recovery will be uneven beyond 2012. According to ACC, global economic condition will be characterized by a twospeed world: Developed nations (the US, Canada, Western Europe and Japan) will be further challenged by debt, adverse demographic factors and tighter fiscal policies; economic growth will be slow. Conversely, developing nations (India, Brazil, Eastern/Central Europe, Russia, China, East Asia, Africa and the Middle East) will experience more dynamic conditions. All are based on continued industrialization and consumer-driven economics. The Asian-Pacific nations, excluding Japan, will experience strong growth in 2013 and into the future. Global business of chemistry. According to ACC’s find-

ings, the global chemistry business paralleled other manufacturing sections in 2012. Growth was stalled in Europe due to continued uncertainty over debt from several EU member countries and concerns about the value of the euro. China, likewise, experienced a downturn in its chemical industry, as Europe is a major customer of Chinese chemical products and finished goods. The North American market is expected to be flat in 2013. However, new shale gas supplies have kept natural gas prices very low in the US, and this trend is expected to continue. Accordingly, lower-cost feedstock and fuels (energy) will support increased chemical/petrochemical production in the US and Canada. (For more information, visit www. americanchemistry.com.) 4 JANUARY 2013 | HydrocarbonProcessing.com

CIRCULATION Director, Circulation

Suzanne McGehee +1 (713) 520-4440 Circulation@GulfPub.com

SUBSCRIPTIONS Subscription price (includes both print and digital versions): Print—One year $239, two years $419, three years $539. Digital format—One year $239. Airmail rate outside North America $175 additional a year. Single copies $35, prepaid. Because Hydrocarbon Processing is edited specifically to be of greatest value to people working in this specialized business, subscriptions are restricted to those engaged in the hydrocarbon processing industry, or service and supply company personnel connected thereto. 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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| Brief Uncertainty looms in EU economy European chemicals output contracted by 2% in 2012 compared with 2011, according to European chemicals group Cefic. By lowering its forecast released in September, the chemicals trade body downgrade reflects recent data showing a stagnant European economy and a further decline in chemicals output since the first quarter of 2012. Cefic forecasts a slight expansion of 0.5% in 2013. EU automotive and construction segments were a drag on chemicals demand in 2012, offering few encouraging signs. Sluggish demand remains for new cars as governmentbacked incentives to replace vehicles have now run their course. The fallout from overcapacity in the construction market has yet to wind down as the European building sector remains at historically low levels. Once the final numbers are in, EU chemicals production for 2012 will likely remain 8% below its pre-recession level. On the product front, volatile oil and naphtha prices have caused further uncertainty in the petrochemicals sector as customers and producers both attempt to optimize inventory levels. Photo: BASFâ&#x20AC;&#x2122;s butadiene plant in Ludwigshafen, Germany.

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

Brief

A recent survey by the American Automobile Association (AAA) finds a strong likelihood of consumer confusion

and the potential for voided warranties and vehicle damage as a result of the US Environmental Protection Agency’s (EPA’s) recent approval of E15 gasoline. Ninety-five percent of consumers surveyed have not heard of E15, a newly approved gasoline blend that contains up to 15% ethanol. AAA is encouraging regulators and the industry to stop the sale of E15 until more than 5% of the cars on the road (the current number) are approved by automakers to use the fuel. Only about 12 million out of the more than 240 million light-duty vehicles on the road today are approved by manufacturers to use E15 gasoline, based on a survey conducted by AAA of auto manufacturers. AAA automotive engineering experts also have reviewed the available research and believe that sustained use of E15 in both newer and older vehicles could result in significant problems such as accelerated engine wear and failure, fuelsystem damage and false “check engine” lights for any vehicle not approved by its manufacturer to use E15. One employee at Valero’s Memphis, Tennessee, refinery died after a chemical exposure incident, according to

news reports. The accident occurred December 3 when an equipment failure released a hazardous chemical inside the refinery, leading to chemical burns when a small glass window shattered in the alkylation unit. Valero said the incident did not involve an explosion or fire, despite initial reports from local media to the contrary. Operations at the 180,000-bpd refinery were not affected, according to the company. Ecolab has amended its acquisition agreement with Permian Mud Service, the parent company of Champion

Technologies, so that Champion’s downstream process and water solutions business will be spun-off to Permian shareholders prior to the Ecolab acquisition. As such, Ecolab will not be acquiring those specific operations. Sales in 2011 for the downstream business, which primarily serves refineries, were approximately $50 million. Accordingly, the value of the transaction will be reduced to $2.16 billion from $2.2 billion, subject to further adjustment as provided in the acquisition agreement. The Vietnamese government recently announced a roadmap for the blending ratio of biofuel with

traditional fuel. The policy mandates the use of E5 biofuel in seven Vietnamese localities beginning December 1, 2014. From December 1, 2015, the use of E5 will be compulsory for all road vehicles nationwide. E10 biofuel will be used in these localities from December 1, 2016, and E10 use will also become compulsory nationwide from December 1, 2017. Production and supply chain/distribution challenges have resulted in Vietnam’s ethanol production being more expensive than what

could be produced overseas. Vietnamese consumers have also been reluctant to use ethanol because of perceptions about fuel quality and safety. Economic prospects are looking brighter for the heating, ventilation and air conditioning (HVAC) industry in

2013. Potential growth exists in a resurgent housing market and in consumer interest and investment in “green” HVAC equipment, according to a new report from SBI Energy. The report projected the total shipment value of HVAC manufacturing products to reach $14.5 billion by the end of 2012, with that number growing to nearly $17 billion by 2017. “Growth of the industry will begin to accelerate by 2015,” said Darren Bosik, an analyst with SBI, “when the impact of government-funded initiatives is felt in US construction and housing industries, most notably the movement to construct zero-energy buildings (ZEB).” Critical to the growth of HVAC manufacturing is the resurgence of US household remodeling and the recovery of new construction and housing and related industries such as steel. Driving the total HVAC equipment manufacturing growth to 2017 will be heat transfer equipment [4.4% compound annual growth rate (CAGR)] and air source heat pumps (4.9% CAGR). The two categories are characterized by lower unit costs, and demand will increase with an expected boom in construction projects that require replacements of these products. The market for fuel ethanol in the US remains unconcentrated, with 154 firms nationwide either

producing ethanol or likely to be in production in the next 12 to 18 months, according to the US Federal Trade Commission’s (FTC’s) 2012 report on the state of US ethanol production. FTC staff calculated market concentration for ethanol production using different measures. The staff concluded that, as of September 2012, there were 10 fewer ethanol producers in the US than at the time of the FTC’s 2011 report. The largest ethanol producer’s share of capacity decreased slightly to 11.1% of domestic ethanol production capacity, which was below the 11.5% share in 2011. Plains All American Pipeline has agreed to acquire four operating crude oil rail terminals, one terminal

under development and various contractual arrangements from US Development Group for approximately $500 million. The assets to be acquired include three crude oil rail loading terminals located in the Eagle Ford, Bakken and Niobrara producing regions with an aggregate daily loading capacity of approximately 85,000 bpd; a rail unloading terminal at St. James, Louisiana, with a capacity of approximately 140,000 bpd; and a project to construct a crude oil unloading terminal near Bakersfield, California. Hydrocarbon Processing | JANUARY 2013 9

We create chemistry that makes natural gas love solutions.

BASF offers a broad range of technical solutions based on the appropriate absorbent (solvent), adsorbent, and catalyst. Moreover, BASF supports its customers in the design and operation of gas treatment plants by providing process design and engineering support and a range of technical services such as debottlenecking and process optimization, troubleshooting and revamps, analytics, and training. At BASF, we create chemistry for a sustainable future. www.catalysts.basf.com/adsorbents

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

Impact

Increased operating costs in the Asia-Pacific region could derail growth Rising operating costs will be the biggest barrier to oil and gas companies’ growth in Asia-Pacific next year, according to a 2013 outlook for the industry

7,000 6,500 6,000 5,500 Mbpd

The US Energy Information Administration (EIA) reports that US crude oil production (including lease condensate) averaged almost 6.5 million bpd in September 2012, the highest volume in nearly 15 years (FIG. 1). The last time the US produced 6.5 million bpd or more of crude oil was in January 1998. Since September 2011, US production has increased by more than 900,000 bpd. Most of that increase is due to production from oil-bearing rocks with very low permeability through the use of horizontal drilling combined with hydraulic fracturing. The states with the largest increases are Texas and North Dakota. From September 2011 to September 2012, Texas production increased by more than 500,000 bpd, and North Dakota production increased by more than 250,000 bpd. Texas’ increase in production is largely from the Eagle Ford formation in South Texas and the Permian Basin in West Texas. North Dakota’s increase in oil production comes from the Bakken formation in the Williston Basin. Increased production from smaller-volume producing states, such as Oklahoma, New Mexico, Wyoming, Colorado and Utah, is also contributing to the rise in domestic crude oil production. This surge in production does not appear to be a temporary blip. The EIA’s recently released energy outlook projects growth in total US energy production to exceed growth in total US energy consumption through 2040 (FIG. 2). Several of the key findings include: • Crude oil production, especially from tight oil plays, will rise sharply over the next decade, with US domestic oil production rising to 7.5 million bpd in 2019, up from less than 6 million bpd in 2011 • Motor gasoline consumption will be less than previously estimated, with lower gasoline use reflecting the introduction of more stringent corporate average fuel economy (CAFE) standards

creased use of biofuels and lower demand resulting from the adoption of new vehicle fuel efficiency standards and rising energy prices, resulting in the net import share of total US energy consumption falling to 9% in 2040 from 19% in 2011.

• Growth in diesel fuel consumption will be moderated by the increased use of natural gas in heavy-duty vehicles • Because quickly rising natural gas production will outpace domestic consumption, the US will become a net exporter of liquefied natural gas (LNG) in 2016 and a net exporter of total natural gas (including via pipelines) in 2020 • The share of electricity generation from renewables is predicted to increase to 16% in 2040 from 13% in 2011 • Net imports of energy will decline because of increased domestic production of both petroleum and natural gas, in-

5,000 4,500 4,000 = 0 July-1997

July-1999

July-2001

July-2003

July-2005

July-2007

July-2009

July-2011

Source: US Energy Information Administration

FIG. 1. Monthly US crude oil production, July 1997 to September 2012.

History

Projections

2011

MMbpd

US crude production hits 15-year peak

Tight oil

4 Other lower 48 onshore 2 Lower 48 offshore 0 1990

Alaska 2000

2010

2020

2030

2040

Source: US Energy Information Administration, 2013 Annual Energy Outlook

FIG. 2. US domestic crude oil production by source, 1990–2040 (MMbpd). Hydrocarbon Processing | JANUARY 2013 11

Impact by GL Noble Denton. While the sector’s rapid growth is bringing new opportunities to the region, research shows that significant challenges remain. According to initial results from a survey of nearly 400 senior industry professionals, over half of those from the AsiaPacific region (53%) identified rising costs as one of their three biggest concerns for 2013, and a serious threat to the growth of their business. This represents

a substantial increase compared to last year when, in a similar survey, just 39% of respondents from the region forecast increased operating costs as a top three barrier to business growth in 2012. “The mounting cost of operations is largely due to an increase in the complexity of oil and gas projects, a surge in insurance premiums and the acute lack of suitably qualified professionals across the region,” said Richard Bailey, an execu-

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tive vice president for GL Noble Denton. “Add to this a rising tide of supply chain consolidation—a trend that’s making it harder for smaller companies to secure work on large ventures with high capital expenditure, many of which are in Australia. To this end, the game is definitely becoming one that increasingly favors AsiaPacific’s big players. The smaller outfits, which may not have the same track record and process experience, need to fight very hard to stay in the game.” The report takes an overall bullish perspective on growth in the region and predicts substantial industry spending, given the complexity of the projects and the need to improve the operational efficiency of assets.

IHS has released an update to its 2010 report comparing the greenhouse gas (GHG) emissions from fuels made from Canadian oil sands to those from other crude sources. The new analysis found that total emissions from refined products that are wholly derived from oil sands are 4% to 18% higher than the average crude oil processed in the US. This level places oil sands on par with other sources of US crude, including crudes from Venezuela, Nigeria, Iraq and California heavy oil production. When the oil sands products refined in the US are considered (a mixture of oil sands and lower carbon blending components), the GHG emissions are, on average, 9% higher than the average crude processed in the US. This report and its 2010 precursor both analyzed the complete “wells-totailpipe” lifecycle—the extraction, processing, distribution and combustion of the refined fuel—to provide a comprehensive assessment of where oil sands fit in the spectrum of US crude imports. The 2010 report had found that the average for oil sands products refined in the US was 6% higher than the average crude processed in the US, with total emissions from refined products wholly derived from oil sands being 5% to 15% higher than the average barrel. The widening range in emissions estimates compared to the original report is the result of a more detailed estimate for US oil sands imports, as the latest update

Impact accounts for all major sources of oil sands production. However, the majority of the difference was due to increases in the estimate for GHG intensity of some oil sands extraction methods, such as steam assisted gravity drainage dilbit, mining synthetic crude oil and cyclic stream stimulation dilbit. These results do not necessarily indicate an increase in oil sands carbon intensity since 2010 but rather a revision of the results based on new studies that have applied different modeling techniques and data. The latest report is drawn from the results of 12 recent studies from government, academic and industry sources. The new report also includes results measuring Canadian oil sands GHG intensity, accounting for emissions that occur beyond the crude production and refining facilities, such as the production and processing of natural gas used in oil production or emissions from off-site electricity production. When accounting for these “wide boundary” results, the new report found that fuels produced solely from oil sands result in emissions 5% to 23% higher than the average crude processed in the US, with the average for oil sands products refined in the US being 12% higher than the average barrel.

nual sales will still reach only 37,000 by 2019—just over 1% of the world market, which is expected to reach 3.2 million in annual sales in that year. “Sales of NGVs will grow strongly in the next several years in North America, but the market is starting from a very small base of about 16,000 vehicles a year,” said Dave Hurst, a senior research analyst. “The lack of widely available refueling stations, the absence of govern-

ment incentives for purchasers, and low consumer awareness of NGVs will keep the North American market to just a fraction of the total world market.” As in Europe and parts of Asia-Pacific, the growing infrastructure for NGVs in North America remains focused on servicing fleet customers. This will likely limit the growth of NGV passenger cars both in North America and in other markets, according to the report.

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North America lagging, Asia-Pacific surging, in sales of natural gas vehicles The global market for light-duty natural gas vehicles (NGVs), which produce fewer greenhouse gas emissions than conventional gasoline engines and which run on fuel that is cheaper than gasoline, varies significantly depending on the region and country. While many markets in Europe and Latin America continue to struggle with expanding refueling infrastructure quickly enough to meet the needs of both consumers and fleets, the adoption of NGVs is still growing rapidly. According to a recent report from Pike Research, the Asia-Pacific region is rapidly becoming the world’s largest market for NGVs due to strong growth in markets such as Thailand, India and China. North America, however, continues to lag in this sector. Although sales of NGVs in the region will grow at a healthy 10.2% compound annual growth rate from 2012 to 2019, the study found, an-

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

Innovations

FLNG needs offshore know-how More and more developers are considering floating liquefied natural gas (FLNG) as a strong option for monetizing gas resources. The sustained work over the last five years within the sector has enabled FLNG to mature and be better defined. Key considerations must be correctly assessed to ensure the success of an FLNG project. These considerations are unique to FLNG, so addressing the project with an LNG mindset will not necessarily result in the correct decisions being made. One of the most crucial decisions is to select the right FLNG specialists at an early stage. Very few companies know FLNG and have sufficient offshore experience. As an FLNG and offshore specialist, KANFA Aragon has the expertise and experience for successful, simplified and fast execution (FIG. 1). When considering an FLNG development, whether offshore or onshore, there are several key areas to consider, as discussed below. Liquefaction technology selection. The key question is whether to select an adjusted onshore liquefaction technology that is unproven offshore, or a technology developed specifically for offshore that already has been proven. As the offshore oil and gas sector has shown, just because something works onshore does not mean that it is suitable for offshore use. Typically, onshore technologies that are proposed for use offshore utilize flammable, multi-phase refrigerant processes that require very large amounts of space and equipment. Use of such hazardous liquid refrigerants are not ideal for offshore due to performance-impacting vessel motions, limitations on available space offshore, complexity of operation, manpower requirements, and the increased safety demands that operating offshore require. The optimal choice for FLNG developments is to utilize a nitrogen (N2 ) cy-

cle. N2 cycles offer a simple, single-phase process using a nonhazardous refrigerant and are an established offshore technology, as they have already been applied as reliquefaction systems on LNG carriers. For those who understand the offshore world, it is the best option for FLNG. This is why KANFA Aragon developed the patented Optimized Dual Nitrogen Expander Cycle, using N2 specifically for offshore liquefaction. The main argument for hydrocarbon mixed-refrigerant cycles is generated by the traditional onshore LNG focus on efficiency in terms of kW/kg of produced LNG. Mixed-refrigerant cycles are more efficient than N2 cycles. However, for FLNG, developers must look at overall plant efficiency. Often, plants based on mixed-refrigerant technology are not much more efficient than plants using N2 cycles. Complex hydrocarbon-based technologies usually apply a one-train configuration, and they often use steam turbines with low thermal efficiencies as drivers. For N2 cycles, aeroderivative gas turbines with high efficiencies are applied as drivers, resulting in overall high plant efficiency. It is important to guarantee reliable production offshore. As such, simplicity always has an advantage over enhanced efficiency in an offshore environment.

cycles, as it is generally possible to use equipment that already has references from operating offshore. This further reduces risk and enhances stable production. By using established offshore equipment, it also presents a range of possible suppliers, improving price competition and reducing dependency on single sourcing (FIG. 2). Safety. In an offshore environment, the inherent safety level required as part of the plant and process design is much more stringent than in an onshore environment. Large plants that require bulky equipment in confined spaces—together with high numbers of people and significant storage inventories of hazardous and flammable liquids—present a com-

FIG. 2. The LM 6000 aeroderivative gas turbine. Photo courtesy of GE.

Proven equipment. It is also important

that equipment is suitable and proven offshore. This is another strength for N2

FIG. 1. A jetty-moored solution for Samsung Heavy Industries and FLEX LNG. Photo courtesy of Samsung Heavy Industries and FLEX LNG.

FIG. 3. KANFA Aragon’s Sevan Marine FLNG concept with topside and technology. Hydrocarbon Processing | JANUARY 2013 15

Innovations bination that is not ideal for an offshore environment. However, nonhazardous, simple-to-operate processes using proven offshore equipment present a much simpler and safer method of producing LNG offshore. Technology provider. For FLNG, it is crucial to select a technology provider with a proven track record offshore. Hiring experienced staff with high expertise in both gas processes and offshore project execution is critical to successful FLNG development. KANFA Aragon’s most high-profile development to date is for SHI and FLEX LNG. It started with conceptual and generic FEED work; recently, field-specific FEED work was completed for the ElkAntelope Field in Papua New Guinea. For the field-specific FEED, KANFA Aragon established a joint venture with WorleyParsons to further strengthen engineering capability. The project is currently awaiting a final investment decision. With a large amount of development work and FEED done on behalf of SHI

and FLEX LNG, KANFA Aragon possesses experience and capability in FLNG (FIG. 3). Flexible options. As a technology pro-

vider and an EPC company, KANFA Aragon can provide flexible execution options. Whether there is interest only in licensing the liquefaction technology, or preference for a full EPC arrangement (including joint ventures with other EPC companies and/or shipyards), KANFA Aragon is able to meet what is best for development. A proven track record in FPSO topside deliveries, together with experience and expertise in FLNG, means that KANFA Aragon can offer developed, verified solutions alongside optimized project execution. Now that FLNG is maturing and becoming of greater interest, it is more important than ever to ensure that proper considerations are taken and that the right decisions are made. Visit www.kanfagroup.com or contact Tom.Haylock@ kanfagroup.com for more information. Select 1 at www.HydrocarbonProcessing.com/RS

Small-scale GTL to enhance refinery operation A modular, small-scale gas-to-liquids (GTL) plant based on the use of microchannel Fischer-Tropsch (FT) reactors will offer an economical option to expand refinery capacity and make it possible to derive value from smaller accumulations of unconventional gas. The GTL plant was developed by Velocys Inc., the US-based subsidiary of Oxford Catalysts Group, and is now under construction at the Ventech fabrication facility in Pasadena, Texas. In contrast to largescale GTL plants, such as Sasol’s Oryx and Shell’s Pearl plants (both located in Qatar), which are designed to produce over 30,000 barrels per day (bpd) of GTL product, this new, smaller-scale GTL plant has a nominal capacity of 1,000 bpd to 1,500 bpd. The modular GTL plant, which will be composed of standard-sized, 13.5 ft × 12 ft × 40 ft (4.1 m × 3.65 m × 12 m) modules, takes advantage of two technology breakthroughs—modularization and microchannel technology.

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Want hands-on experience? We’ve got it – HANDS DOWN. Even the most seasoned refinery managers may see four to five FCCU revamps throughout their career. AltairStrickland’s managers and craftsmen have performed, on average, four to five FCCU revamps per year since 1976. This experience is the kind of advantage you need to help you manage and execute a successful project. We address constructability issues early on through preplanning, computer imaging, 3-D surveys and AutoCAD® models. Then, unlike most mechanical contractors, we often construct life-size wooden mock-ups of various sections to make sure a human, with tools, can access and work effectively and safely in tightly confined spaces. Our crews, from craft to top management, have worked on so many turnarounds and revamps that they can identify and quickly correct a problem, and work around a snag or lagging schedule. We also don’t choose between quality and safety. We think our clients should have the best of both. Our safety record is amazing. We just completed a 1,317,269-work-hour job for a client with zero BLS/ OSHA recordable injuries. Zero injury is our goal on every project we do. Our quality is evident during start-up. Our level of productivity is evident when you look at the project’s final time/cost. If there’s an FCCU revamp in your future, make the process as pain free as possible by putting the best hands in the business to work for you.

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Innovations

FIG. 4. Velocys Inc.’s microchannel FT reactor enables faster reaction rates and the use of more active FT catalysts.

FIG. 5. Illustration of an FT process unit module. Photo courtesy of Ventech Engineers International LLC.

Modularization is a construction method that involves designing refineries and gas processing facilities as a series of modular process and utility units, that are fabricated in a controlled shop environment, and then shipped and connected together on the project site. Microchannel technology is a developing field of chemical processing that intensifies chemical reactions by reducing the dimensions of the reactor systems. This enables reactions to occur at rates 10 to 1,000 times faster than those in conventional systems, and makes it possible to use more active FT catalysts (FIG. 4). The Velocys reactors take advantage of a highly active FT catalyst developed by Oxford Catalysts to accelerate FT reactions by a factor of 10 to 15 times the speed of conventional reactors. Individual Velocys microchannel FT reactors are designed to produce 125 bpd to 200 bpd of FT product, and desired plant capacity is reached by linking together multiple reactors to scale production to match the available resource. Plants of this type can

also be used as a flexible and economical way to expand capacity at existing petroleum refineries. The first customer for this new plant design is Calumet Specialty Products Partners LP, an independent producer of specialty hydrocarbon products in North America. The Calumet plant will incorporate autothermal reforming (ATR) reactors from Haldor Topsøe to produce the syngas feedstock for the Velocys microchannel FT reactors (FIG. 5). Calumet plans to use the modular GTL plant, which will have a nominal capacity of 1,000 bpd, in the expansion of its specialty products facility in Karns City, Pennsylvania. Fabrication is expected to begin during the first half of 2013. Velocys anticipates that this first modular GTL plant, which is due to come onstream during the second half of 2014, will be the first of many. Select 2 at www.HydrocarbonProcessing.com/RS

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Associations

Cyber security in the oil sector The American Petroleum Institute (API) held its 7th annual cyber security conference over two November days in Houston, Texas. Since cyber attacks on industrial targets have grown in frequency and intensity over the last few years (two recent examples include Saudi Aramco’s victimization and the “Night Dragon” attack that exposed vulnerabilities at multiple energy companies), the conference was well-attended and filled with relevant discussion. Whitelisting. One of the standout sessions from the gathering offered instruction on how to secure industrial control systems with application whitelisting and change detection. As aptly described by the US National Security Agency, application whitelisting “is a proactive security technique where only a limited set of approved programs are allowed to run, while all other programs (including most malware) are blocked from running by default. In contrast, the standard policy enforced by most operating systems allows all users to download and run any program they choose. Application whitelisting enables only the administrators, not the users, to decide which programs are allowed to run.” Gib Sorebo, a vice president at SAIC, spoke about implementing this philosophy within an oil and gas industry sector context. “The first step is using best practices,” he said. “For instance, if I am going to review a PDF, a certain computer should be specified; avoiding overlap is key. This can help avoid some of the problems that exist with and without whitelisting. Acrobat and Flash are problematic programs and you should never have Flash running on control system computers.” Mr. Sorebo’s concern about Adobe Acrobat and Adobe Flash is drawn from substantial data showing that those two programs are particularly susceptible to

tampering and are often gateways that hackers use for eventual deployment of their viruses. Other common software that application whitelisting has identified as being vulnerable includes Microsoft Office documents (especially VBScript and Macros), Windows PowerShell, DLL injection and JavaScript. More and more whitelisting products are emerging, Mr. Sorebo said, but the onus is no longer on individual companies to go into the marketplace and make á la carte selections. Control vendors are now including such products in their program suites. Mr. Sorebo simply advises management to check with their respective control vendors to make sure it is included. “Whitelisting offers highly granular controls that restrict not only installation, but also the execution of [unauthorized] software,” he said. “It also enforces more secure updating methods to protect against supply chain threats and further guards against many improper uses of applications, like spawning a shell.” Mr. Sorebo readily admitted that there are inherent risks in control systems that create unique security challenges. That’s why he was advocating for application whitelisting, as it is an avenue to overcome vulnerabilities and effectively lock down control systems. “When deployed correctly, application whitelisting can operate seamlessly in critical infrastructure with little administrative overhead or help-desk support required,” he said.

Cloud security. During another presen-

API’s Cyber Security Conference took place in November.

Eric Little and Steve Hamby represented Orbis Technologies at the event.

tation at the event, two representatives from Orbis Technologies discussed how cloud-based technologies can improve cyber security. As many petrochemical companies move to massive, shared cloud-based networks, a new security approach is necessary. Orbis’ Eric Little suggested three approaches to make a company’s cloud more secure: infrastructure enhanced security, enhanced threat modeling and semantic security. “The ability to use semantics to model actual threats, like people stealing IP addresses, allows you to capture the type of subject matter expertise that analysts wish to model,” he said. “You can also build security in by creating a lexicon of important terms, with data elements categorized into appropriate classes. This advanced logic allows for reasoning over data sets that can detect new patterns, allowing information to be gained.” Mr. Little also went into detail about the formal ontology of a threat. He said that all threats have three components: intent, capability and opportunity. “Understanding the structure of threat components can allow for improved computational approaches,” he said. During his presentation, Mr. Little also itemized elements that should be included in core technologies for scalable cloud-based semantics. These included: • Information extraction • Natural language processing • Entity extraction • Semantic resolution.

Hydrocarbon Processing | JANUARY 2013 21

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Reliability

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

TAMU Turbo and Pump symposiums still leading Beginning in 1971, the Turbomachinery Laboratory of Texas A&M University (TAMU) organized the first of now 41 consecutive annual turbomachinery symposiums, now known as the TAMU Turbo. In 1984, Texas A&M added an International Pump Users Symposium, now called the TAMU Pump. Almost 30 years ago, both meetings shared three of the TAMU Pump’s founding members—Igor Karassik, Charlie Jackson and Ed Nelson. These professionals stood out as unselfish, modest, informed and highly experienced teachers. They were the tutors to the next-generation engineers and have remained without equals. Both the TAMU Turbo and TAMU Pump symposiums are steered by engineers. As members of the TAMU Turbo and TAMU Pump advisory committees, recognized leaders in the fluid machinery and power generation communities share the task of providing guidance to presenters and attendees. Some leaders are equipment users; others are manufacturers or vendors. Virtually all job functions and user industries are represented at these symposiums. The TAMU Turbo symposium was established as a forum for users and manufacturers of industrial turbomachinery. Because of many overlapping areas of interest, the program continues to focus on commercial turbomachinery users within the oil and gas, petrochemical and utility industries. Both symposiums have very wide scope and content. The decision to co-locate TAMU Pump and TAMU Turbo events has proved to be successful.

Essential elements of TAMU Turbo and TAMU Pump. Because of their relevance, the two symposiums have obviously grown in size and complexity. In 2012, there were 11 short courses (TABLE 1), 19 discussion groups, and, of course, a highly appropriate and valuable product exhibit show. TAMU Pump attendees could choose from six additional lectures, as listed in TABLE 2. This program was focused on pump users. Suitable courses, tutorials and case histories were again part of TAMU Pump. The discussion groups were led by engineers or senior technicians with vast experience; these leaders facilitated discussion from the floor. Attendees from the US and many countries actively participated in the discussion groups. Many attendees used this forum to obtain sound advice from their peers on problems of immediate importance. This author and HP believe that, collectively, the two symposiums are the most valuable events of their genre. Fluid-machinery users should continue to attend both TAMU Turbo and TAMU Pump, especially since they share the same timing and location.

2012: A real success for TAMU. The most recent sym-

Lateral rotordynamics of petrochemical equipment

posiums featured lectures, tutorials, case studies, discussion groups and short courses, as well as exhibits of the latest services and full-sized equipment. As in past years, the two meetings emphasize technology and troubleshooting. Approximately 3,000 attendees registered for the 2012 event. Representatives of Hydrocarbon Processing attended the September 2012 events. The technical sessions (lectures, tutorials, discussion groups and case studies) provided opportunities for attendees to expand their personal and professional needs and interests. Moreover, the exhibits featured products from many key manufacturers. Because exhibiting companies send their “first-team” players to this symposium, attendees were able to “touch base” with executives and even CEOs of companies with stellar credentials. Executives answered questions from first-time attendees and, a scant few minutes later, greeted the occasional octogenarian who wandered through the 300 exhibits. There was knowledge transfer in the exhibit hall, but there was also the occasional commiseration. Some things were different; there was change, and not all changes affected all parties equally.

Compressor controls and anti-surge systems

TABLE 1. 2012 TAMU Turbo short-course topics Vibration problems and solutions in pumps and turbomachinery Utilization of computational ﬂuid dynamics in turbomachinery design and analysis Introduction to centrifugal compressors Advanced centrifugal compressors

Introduction to reciprocating compressor diagnostics and basic pattern interpretation Introductory gas turbines Reliability-centered maintenance FCCU hot gas expander design, operation and troubleshooting Magnetic bearings in turbomachinery

TABLE 2. 2012 TAMU Pump short-course topics Pumps 101 Fundamentals of centrifugal pump and system interaction Pump cavitation physics, prediction, control and troubleshooting Ever-tightening environmental regulations—meet them or shut down Mechanical seals 101 Rolling element bearings Hydrocarbon Processing | JANUARY 2013 25

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Reliability Divergences perceived. Although the two events have considerable synergism, they do differ. The TAMU Turbo advisory committee members are not the same individuals forming the TAMU Pump board. Each of the two committees are made up of what many consider highly knowledgeable members. Unfortunately, TAMU Pump has recently been quick to reject certain presentation offers. For example, one presentation was encouraged by pump users seeking explanations regarding repeat pump failures. Rejecting solid information by acknowledged experts who had documented years of failure-reduction experience is disappointing; more important, members of the TAMU Pump Advisory Committee should be user advocates that are both knowledgeable and impartial. The user’s goal is high equipment reliability and low-failure rates. The manufacturers’ goals are aimed at sales and profits. Finding a balance that serves both parties is a leadership challenge. Participating manufacturers should be encouraged to be more open about their products—good and bad. Formal presentations should supplement the many informal discussion groups. In the late 1980s and early 1990s, advisory committee members had the experience, desire and motivation to work closely with old and young potential presenters. Senior advisory committee members contributed wisdom and maturity; they also insisted on evenhandedness and civility of discourse. The same attributes are needed at a time when the dissemination of solid facts will help a hard-pressed pump user community eliminate dangerous repeat failures. For a pump user symposium to add more value, steps might be taken to elevate the tone of the discourse and to remember how Karassik, Jackson and Nelson communicated respectfully, authoritatively and without bias. We should all try to imitate them. Tentative program for 2013. Although the program for

September 30–October 3, 2013, will not be finalized until March, TAMU Pump has taken steps to emphasize pump failure avoidance topics. For starters, the advisory board is giving consideration to repeating a well-attended tutorial that had received positive reviews in 2012. Put it on your calendar if repeat pump failures are one of your concerns. Both symposiums can be superb training venues for your fluid machinery professionals. As they then return to your facility after attending in 2013, why not ask them to hand in more than the traditional request for travel expenses? Ask them to submit a 200-word summary of what they have learned and what others are doing different from “the way we do it here.” That is one method in which you can get top dollar for your training outlays. HEINZ P. BLOCH resides in Westminster, Colorado. His professional career began in 1962 and included long-term assignments as Exxon Chemical’s regional machinery specialist for the US. He has authored over 520 publications, among them 18 comprehensive books on practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oil-mist lubrication and practical lubrication for industry. Mr. Bloch holds BS and MS degrees in mechanical engineering. He is an ASME Life Fellow and maintains registration as a Professional Engineer in New Jersey and Texas.

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Integration Strategies

RALPH RIO, CONTRIBUTING EDITOR RRio@arcweb.com

3D laser scanning delivers benefits in hydrocarbon processing facilities Present 3D laser scanning (3DLS) technology can be used in many diverse applications; it assists in improving efficiency and quality, and reducing time-to-benefit. For discrete industries, 3DLS can save time and cost in product development and manufacturing applications. In the hydrocarbon processing industry (HPI), utilities and other heavy process businesses, 3DLS benefits can be effectively applied to upgrade projects and ongoing plant-asset management activities. The technology continues to improve with higher scanning speeds (points scanned per second), better ease of use and smoother workflow via software integration with computer-aided design (CAD) systems. Ranges and applications. In 3DLS, a laser beam is used to

accurately gauge the shape of an object’s outer surface. The scanner shoots a pulse of laser light at an object; this pulse accurately measures the direction and distance of a point on its surface. It then calculates the X, Y and Z coordinates for that point. A 3D laser scanner can measure many thousands of points per second along the surface. These points with the X, Y and Z coordinates become a digital representation of the object’s surface, called a “point cloud.” Laser-scanning technology is used for measuring “as-built” conditions in process and utility plants. When done with the proper setup and workflows, the result is accurate within a ¼ in. Process-industry applications. For 3DLS, process-industry

applications span both the design and build segments, along with the operations and maintenance segments of an asset’s lifecycle. In design and build applications for the HPI, 3DLS can be used to: • Create navigation models for construction planning and identifying line and equipment tie-ins • Generate 3D-geometric models and build information management systems (FIG. 1) • Measure as-built conditions, fabricate components offsite and assemble onsite for faster project execution at lower costs. This includes activities such as detecting as-built construction deformations and errors, ensuring precise initial machine installation, and checking for interference with existing construction during upgrades. In plant-asset management applications, 3DLS can be used to: • Create more effective documentation for maintenance, operations and operator training • Generate highly accurate piping and instrumentation diagrams.

FIG. 1. Accurate 3D as-built conditions from a medium-range point-cloud scan. Source: Trimble

growth in both the discrete and process industries. Several factors contribute to the rapid technology adoption across all industries. • 3D movies have “consumerized” the concept of 3D, increasing the awareness among potential prospects. The rapid adoption of Microsoft Kinect (introduced in November 2010) sharply increased awareness of using light to measure and display a 3D virtual environment. With the wide use of Kinect, anyone resisting 3D technology risks being viewed as a laggard. • Scanning equipment continues to improve. Application software provides functions that semi-automatically convert point clouds into CAD objects. The productivity improvements for both hardware equipment and software applications drive increased economic benefits. For brownfield upgrades at process plants, the original design tools and paper-based documentation often predate modern CAD. Without current CAD drawings, extensive mechanical measurement would normally be required to create needed drawings. With laser scanning, the point cloud provides accurate measurements for existing equipment and associated tieins, thus reducing design clashes. Also, with accurate as-built drawings, components can be prefabricated offsite at reduced cost, risk and shutdown time. RALPH RIO is the research director for enterprise software for the ARC Advisory Group. He joined ARC in 2000. His research areas include enterprise-asset management, field service management and 3D laser scanning systems. Mr. Rio holds a BS degree in mechanical engineering and an MS degree in management science from Rensselaer Polytechnic Institute in Troy, New York.

Growing 3DLS technology adoption. Despite the diffi-

cult economic times, 3DLS applications have experienced high Hydrocarbon Processing | JANUARY 2013 29

There’s no way I can get all the I/O change orders done before start-up. But we can’t start-up until the change orders are done.

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Boxscore Construction Analysis

LEE NICHOLS, DIRECTOR, DATA DIVISION Lee.Nichols@GulfPub.com

Is the US on the verge of the next construction boom?

Gas processing trends. Although the Hydrocarbon Processing (HP) Construction Boxscore Database has tracked a global decrease in the total number of ac-

tive gas processing projects within the past 18 months, the US has defied this trend, experiencing a 30% increase in total active gas processing projects, as shown in FIG. 1. This trend began in late 2010 with the construction of more than a dozen cryogenic gas plants near US shale plays, primarily near the Marcellus and Eagle Ford basins. Many of these plants will be completed in 2012, although the construction numbers continue to rise with planned LNG projects along the US Gulf Coast. Due to recent market changes, many previously planned US LNG import terminals have either been canceled or will be converted or expanded into export terminals. At present, there are more than a dozen liquefaction terminals awaiting approval from the US Department of Energy (DOE). US LNG exporting companies must seek approval from the DOE to export LNG to other nations, regardless of whether or not they hold a free trade agreement (FTA) with the US. The most advanced of these projects is Cheniere Energy Inc.’s Sabine Pass Liquefaction Project. This project has been approved by the DOE to export LNG both to countries with and without FTAs. Located in Cameron Parish, Louisiana, the $6 billion (B) project will be

the first LNG export terminal constructed in the US in 50 years. The US’s first export terminal is ConocoPhillips’ Kenai plant, located on the Kenai Peninsula in Nikiski, Alaska. The Sabine Pass Liquefaction Project will include up to four liquefaction trains, each with an average capacity of 4.5 million tpy (MMtpy). Bechtel Corp. has been awarded the engineering, procurement and construction (EPC) contract for Train 1 and Train 2. The company will design, construct and commission each train using ConocoPhillips’ Optimized Cascade Process technology. Completion is scheduled for 2015. Likewise, ExxonMobil and Qatar Petroleum plan to invest $10 B to expand their Golden Pass terminal, located in Sabine Pass, Texas. The proposed project involves the construction of gas liquefaction and export facilities with the capacity to export 15.6 MMtpy of LNG. Since the expansion is planned for an existing import facility, Golden Pass will have the flexibility to both import and export natural gas. This joint venture is the first liquefaction project in which Qatar, the world’s leading exporter of LNG, has invested outside of its own liquefaction complex at Ras Laffan.

300 Total active gas processing projects worldwide

A lingering question for the US, and one that could determine the nation’s energy future, is what to do with the abundance of natural gas from unconventional sources such as domestic shale plays? Revised estimates by the US Energy Information Administration (EIA) list recoverable shale gas reserves at around 542 trillion cubic feet (Tcf), and in its Annual Energy Outlook 2012, the EIA projects that US gas production will jump from 21.6 Tcf in 2010 to 26.1 Tcf–34.1 Tcf in 2035. This development could establish the US as the world’s leading gas producer since overtaking Russia in 2009. The abundance of natural gas has driven the price to a point where it may not be economical to drill additional capacity. What are the options with this abundance of unconventional gas? Halt drilling? Flare it? These are economically and environmentally disastrous options. Conversely, what are the benefits in liquefying excess natural gas for export? This could position the US to become one of the world’s leading exporters of liquefied natural gas (LNG); it could also expand domestic natural gas liquids (NGLs) and the petrochemical industry, with help from cheap ethane feedstocks. However, there is a spoiler alert. The US is moving toward the second option, and it sits on the verge of a new construction boom. Unlike the refinery construction expansion seen after World War II, this new activity will be led by LNG liquefaction and export terminals, along with the construction and expansion of fractionators, ethylene crackers and additional petrochemical infrastructure, primarily along the US Gulf Coast. This month’s column will focus on the US gas processing construction market.

June 2011 December 2012

250 200 150 100 50 0 US

Canada

Latin America

Europe

Middle East

Africa

Asia-Paciﬁc

FIG. 1. Total active gas processing projects worldwide. Hydrocarbon Processing | JANUARY 2013 31

Boxscore Construction Analysis TABLE 1. Major planned US LNG export facilities Project

Owner

Capacity, MMtpy

Cost, $ B

Freeport LNG liquefaction and export

Freeport LNG

13.2

Corpus Christi liquefaction

Cheniere Energy

13.5

Jordan Cove Energy

Veresen (formerly East Chicago Energy)

Trunkline Lake Charles LNG export

Panhandle Energy

Cameron LNG

Cameron LNG (affiliate of Sempra Energy)

Location

Completion date

Freeport, Texas

2017

11.6

Corpus Christi, Texas

2017

7.5

Coos Bay, Oregon

Lake Charles, Louisiana

2018

Hackberry, Louisiana

2016

Dominion Cove Point liquefaction

Dominion Cove Point LNG

Lusby, Maryland

2017

CE FLNG

Cambridge Energy

Plaquemines Parish, Louisiana

2015

Lavaca Bay LNG

Excelerate Energy

1.7

Port Lavaca, Texas

2017

Elba Island export terminal

Southern LNG (subsidiary of El Paso Corp.)

Elba Island, Georgia

2016

Gulf LNG export terminal

Gulf LNG

11.5

Pascagoula, Mississippi

Gulf Coast LNG export terminal

Gulf Coast LNG

2.8 Bcfd

Brownsville, Texas

2018

Oregon LNG export terminal

Oregon LNG

Warrenton, Oregon

2018

South Texas LNG Export

Pangea LNG

Corpus Christi, Texas

2018

These projects are two examples of the many planned facilities that are anticipated to turn the US into a major LNG exporter over the next few years. Other major LNG-exporting facility projects from the HP Construction Boxscore Database are listed in TABLE 1. These projects represent over $40 B in construction investments. Two ambitious projects to note are the Main Pass Energy Hub LNG project and the Alaska LNG project. The Alaska LNG project proposes constructing a pipeline to transport gas from Alaska’s North Slope to a liquefaction plant in south-central Alaska—possibly ConocoPhillips’ Kenai LNG terminal—to export LNG to Asian markets. The $45 B–$65 B megaproject will be an undertaking by ExxonMobil, ConocoPhillips, BP and Canadian pipeline company TransCanada. The 15 MMtpy–18 MMtpy export facility will receive gas from an 800-mile pipeline connected to the Prudhoe Bay and Point Thomson production fields. The new LNG terminal will include a new liquefaction plant and shipping facilities and have the capability to accommodate 15–20 tanker vessels. If approved, the project’s permitting and construction could span up to a decade. Three thousand miles southeast of the Alaska LNG project, the Main Pass Energy Hub (MPEH) LNG project is a $14 B, 32 JANUARY 2013 | HydrocarbonProcessing.com

large-scale liquefaction and storage project located 16 miles offshore of Louisiana. MPEH’s owners, Freeport McMoRan Energy and United LNG, will construct the facility on top of an existing platform that was once used for sulfur mining. In 2007, MPEH was granted authorization to construct an LNG import and regasification facility; however, due to market conditions, it was never built. The concept has now been reversed, and an export facility is planned. It will utilize five interconnected platforms and up to six floating liquefaction storage and offloading (FLSO) vessels, each capable of producing 4 MMtpy. MPEH also has the added bonus of a large salt dome located beneath the structure that could store up to 365 Bcf of gas. The MPEH project was submitted to the DOE for approval to trade with FTA nations in September 2012, and it will seek approval for trade with non-FTA nations in the near future. MPEH estimates LNG exports of 24 MMtpy to Asian-Pacific markets starting in 2017. LNG trade expands around the world. As the US constructs over 190 MMtpy of LNG export capacity over the next several years, it will benefit from a growing global marketplace for LNG. These export facilities and mega-projects will allow the US to become a major LNG exporter to

nations seeking gas to fuel their energy infrastructure. Thanks to high supplies of natural gas, the US can export gas to nations at prices that bring a high return on investment (ROI). The most desired destination is the Asia-Pacific region, where companies can fetch prices as high as $16/MMBtu. Japan, China and South Korea are prime markets for LNG exporters because of their growing demand and high natural gas prices. Both aspects make the LNG business lucrative for companies and nations that can develop LNG-exporting capability and infrastructure quickly to gain a foothold over competitors. Japan, the world’s largest importer of LNG, has a great need for natural gas to fuel its power requirements as the country weans off of nuclear power following the March 2011 earthquake and tsunami and resulting Fukushima nuclear disaster. LNG imports to Japan were forecast to climb above 83 MMtpy in 2012. China is expected to have imported around 16 MMtpy of LNG in 2012, and the nation’s LNG exports are anticipated to double by 2015. To prepare, China has planned 15 new import terminals for completion by 2020. The country’s LNG imports are forecast to equal Japan’s LNG import levels within the next 10 years. However, these predictions could change if China develops its domestic shale gas

Boxscore Construction Analysis reserves. According to the US EIA, China has greater shale gas reserves than does the US, although exploiting them will not be an easy task since extraction is more difficult in Chinese shale plays due to low organic content. Producers will need to drill additional and deeper wells to equal US production levels. India is also emerging as a major LNG importer, with several new LNG-receiving terminals planned along India’s west coast. This new construction will make the nation Asia’s third-largest LNG importer behind Japan and Korea. Another lucrative region for US LNG exports is Latin America, which relies on natural gas for power generation. Argentina, Brazil, Chile and Mexico are the region’s major LNG importers, with Peru being the only LNG exporter. Peru LNG commissioned South America’s first LNG liquefaction plant in 2010. Located in Pampa Melchorita, Peru, the $3.8 B

facility consists of a single-train liquefaction plant with a capacity of 4.4 MMtpy. LNG spot prices can range from $12/ MMBtu in Rio de Janeiro, Brazil, to $12.75/MMBtu in Bahía Blanca, Argentina. The prices are not as lucrative as those in the Asia-Pacific region, but US companies can still make a good ROI by exporting to Latin America. Over the next decade, LNG demand will continue to increase in most parts of the world. The Asia-Pacific region is a high-growth region where LNG exporters can sell cargoes at much higher prices. The future of global LNG trade will be characterized by stiff competition from LNGexporting countries such as Qatar, Indonesia, Papua New Guinea and Australia. With mega-projects such as Gorgon, Prelude, Wheatstone, Ichthys, Queensland Curtis LNG, Gladstone LNG and Australia Pacific LNG, Australia is on track to overtake Qatar as the world’s leading LNG

exporter by the end of the decade. Finally, with the over-abundance of natural gas from domestic shale plays, the US is on the verge of a new construction boom. Planned construction projects call for investments in the tens of billions of dollars that will employ tens of thousands of skilled workers. The US is primed to become a dominant LNG-exporting powerhouse within 10 years. LEE NICHOLS is the Director of Gulf Publishing Company’s Data Division. He has five years of experience in the downstream industry and is responsible for market research and trends analysis for the global downstream construction sector. At present, he manages all data content and sales for Hydrocarbon Processing Construction Boxscore Database as well as all corporate and global site licenses to World Oil and Hydrocarbon Processing.

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Viewpoint

BILL COOPER President, Center for Liquefied Natural Gas

LNG: Fueling the future

BILL COOPER has two decades of experience in various aspects of the energy industry, having served in both the public and private sectors. Prior to serving in his full-time capacity as President of the Center for Liquefied Natural Gas (CLNG), he was a partner at the law office of Hunton & Williams LLP. Mr. Cooper also served as counsel to the US House Energy and Commerce Committee. He was a drafter and lead negotiator for the Pipeline Safety Improvement Act of 2002, and he was also a lead negotiator for the House on several provisions of the national energy policy bills in the 107th and 108th congresses. Earlier in his career, Mr. Cooper served as general counsel for a natural gas utility company. In addition, he is a frequent speaker on energy and natural gas issues. CLNG is an association of LNG producers, shippers, terminal operators, energy trade associations and natural gas consumers. Its goal is to enhance public education and understanding about LNG by serving as a clearinghouse for LNG information.

A few short years ago, the US was a net importer of natural gas. Today, due to the discovery of vast supplies of natural gas and significant technological advancements in unlocking these reserves from shale, the US is poised to become a net exporter of natural gas, which will help grow the nation’s economy, create thousands of jobs and improve the global environment. Despite a sluggish economy, America is faced with a great opportunity. Its wealth of natural gas is so considerable that the US has enough resources to meet its own needs while uniquely positioning itself to sell gas in overseas markets. Concerns that this could adversely impact the US economy have been alleviated with the recent release of a highly anticipated report on liquefied natural gas (LNG) exports commissioned by the US Department of Energy. The report confirms that, if the US allows the export of natural gas, the impact on prices will be minimal and the US will experience net economic benefits.

ral gas processing and pipefitting. The construction and operation of liquefaction facilities would require thousands of design, engineering and construction jobs. Developing LNG will also produce additional natural gas liquids, which are vital feedstocks to the plastics and fertilizer industries. Beyond jobs, selling LNG overseas will contribute millions of dollars in federal, state and local tax revenues to US coffers. These revenues would finance vital public services while defraying public debt. LNG exports would also bolster the US’ geopolitical status, allowing it to provide trading partners with a muchneeded commodity, while also improving the US trade balance. Recent studies conducted by Brookings, Navigant and Deloitte—and, most recently, the US Department of Energy—conclude that the benefits of LNG exports would appreciably surpass any costs. These increased export volumes would be supported by new US natural gas production.

A boon to US industry. Selling a small

Cleaner energy for the world. In addition to economic benefits, LNG exports also provide the world with a cleaner and more reliable energy option. With half the carbon dioxide emissions of coal when burned for electricity, natural gas also has little to no emissions from sulfur dioxide, nitrogen oxides or particulate matter. Exports allow the US to share this valuable resource and reduce worldwide emissions without impeding the US’ ability to use it. Market dynamics change, and so do technologies. However, natural gas is, and continues to remain, an indispensable resource at home and abroad. Clean, reliable natural gas is here today, and the US should do all it can to promote its use at home and abroad to further the country’s economic and environmental objectives. The opportunity is upon us, and if America embraces it, the future of LNG in the US will be bright.

percentage of the US’s natural gas resources to its trading partners will require the construction of LNG liquefaction facilities. These facilities convert ordinary natural gas into a liquefied state by cooling it to −260°F, which enables it to be economically transported by ship. Each facility represents a multibillion-dollar investment back into the US economy. In addition to these investments, exporting LNG will help the US economy in a number of other ways. First, LNG exports will generate tens of thousands of jobs. According to the US International Trade Administration, $1 billion (B) in exports creates 6,000 new jobs. Current estimates project between $13 B and $25 B in LNG exports, creating approximately 150,000 jobs. These jobs would populate a number of industries throughout the supply chain, including manufacturing, natu-

Hydrocarbon Processing | JANUARY 2013 35

| Special Report LNG/GAS PROCESSING DEVELOPMENTS The boom in shale gas production has coincided with an expansion of global liquefied natural gas (LNG) trade. Countries with large natural gas reserves are working to develop their resources for profitable export to consuming nations. Among fossil fuels, natural gas is expected to see the fastest growth through 2030, while oil will see the slowest increase. Due in part to the rise of unconventional gas resources, worldwide gas trade is anticipated to more than double over the next 25 years, with new trade routes and supply patterns emerging. Furthermore, uncertainty surrounding energy security and climate change policies is making natural gas an attractive alternative to high-polluting coal and oil located in politically unstable areas. This monthâ&#x20AC;&#x2122;s special report articles feature technologies for optimizing gas processing and LNG operations and adding value to natural gas-derived products. Photo courtesy of RasGas Co. Ltd.

Special Report

LNG/Gas Processing Developments M. ZOLFKHANI, Ranhill WorleyParsons, Kuala Lumpur, Malaysia

Optimize LNG boil-off gas systems for regasification terminals Boil-off gas (BOG) generation is an inherent part of natural gas liquefaction, transportation and gasification. It varies depending on site temperature, climate condition, integrity of insulation and plant operating mode. Optimization of a BOG system focuses on the optimum operating pressure of the BOG handling system, which affects BOG compressor configuration, process and flare systems design, operating philosophy, startup procedures, line sizes and plant performance. In this examination, different case studies were performed to minimize hydrocarbon loss, flaring and energy consumption. To generalize the results, two extreme compositions (lean and rich) were considered in the case studies. Three scenarios for regasification terminal send-out pressure were considered (40 barg, 70 barg and 100 barg). Two BOG generation scenarios were assumed: 1. Simultaneous gas send-out and liquefied natural gas (LNG) unloading 2. Gas send-out without LNG unloading. These scenarios resulted in maximum and minimum BOG generation, respectively. Operating expenditure (OPEX) increased slightly at higher operating pressures; however, BOG recondensation capacity improved significantly. Depending on LNG composition, nitrogen (N2 ) content and plant operating mode, an operating pressure of 7 barg to

8 barg was found to be the optimum pressure range at which minimum hydrocarbon loss would occur. Introduction. Regasification terminals can receive LNG with different compositions and specifications. A range of hydroCompressed BOG PIC

To BOG compressor

LNG from storage facility

LNG booster pump

FIG. 2. Proposed configuration of BOG recondensation system.

BOG phase envelope

55 50

LNG vaporizer

BOG condenser

LIC

Gas

LNG

LNG to vaporization system

Suction vessel

Trim heater

Lean LNG and minimum BOG generation, 25 mol% N2 in BOG Rich LNG and maximum BOG generation, 5 mol% N2 in BOG

45 40

Vapor propane

Propane vaporizer Seawater Return water to sea

Propane heater Seawater

Return water to sea

Expansion vessel

Pressure, barg

35 30 25 20 15 10 Liquid propane

Propane circulation pump

FIG. 1. Process schematic of a regasification facility (as used in case studies).

5 0 -190

-170

-150

-130 Temperature, °C

-110

-90

-70

FIG. 3. BOG phase envelope charts for two extreme cases. Hydrocarbon Processing | JANUARY 2013 37

LNG/Gas Processing Developments

BOG vapor fraction, outlet stream from recondenser

carbon components, plus N2 , exists in LNG. Due to heat absorption by piping, tanks and equipment, a part of the LNG is continuously turned into vapor. The amount and composition of BOG varies over time. Vaporized LNG is mainly methane (CH4 ) and N2 . The hydrocarbon content of BOG varies between 75 mol% and 95 mol%, depending on the mode of operation and the LNG composition. Therefore, vaporized hydrocarbons should be recovered to minimize hydrocarbon loss and BOG flaring. The amount of BOG generated in terminals depends on the capacity of the plant and can be as high as 100 million 1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0

BOG condensation vs. BOG pressure for HHP case Lean composition max. BOG (10% N2) Lean composition min. BOG (25% N2) Rich composition max. BOG (5% N2) Rich composition min. BOG (15% N2)

BOG vapor fraction, outlet stream from recondenser

LNG receiving terminals around the world. The regasification process on which this study was based uses seawater and a circulating medium (propane) to warm up and vaporize the LNG. FIG. 1 shows a schematic of the system. Regardless of the process applied, the concept of BOG recondensation remains the same. During front-end engineering and design (FEED), a survey was conducted to select the appropriate BOG handling configuration. Using lessons learned from existing plants, a combination of heat exchangers and direct LNG BOG contactors was applied to maximize BOG condensation. FIG. 2 illustrates the details of the system that was designed. case study scenarios, and the Peng-Robinson equation of state was utilized as a base correlation for the fluid package. The rest of the options in the fluid package were maintained at default values.

6 BOG pressure, barg

BOG condensation vs. BOG pressure for HP case Lean composition max. BOG (10% N2) Lean composition min. BOG (25% N2) Rich composition max. BOG (5% N2) Rich composition min. BOG (15% N2)

Case studies. In LNG receiving terminals, generated BOG can be recondensed using high-pressure LNG before being regasified. The dewpoint of BOG is a function of its composition. In turn, the N2 content of BOG has the greatest impact on dewpoint, as N2 is the most volatile component in BOG composition. TABLE 1. OPEX and ﬂaring comparison (for lean LNG and minimum BOG case) BOG pressure Parameters

6 BOG pressure, barg

FIG. 5. High-pressure (LNG pressure of 70 barg) condensation performance for different cases.

BOG condensation vs. BOG pressure for LP case

6 barg

7 barg

8 barg

9 barg

OPEX for BOG compressor absorbed power, USD/day

1,565

1,713

1,848

1,972

OPEX for uncondensed BOG, USD/day

2,356

1,030

Total OPEX, USD/day

3,921

2,743

1,867

1,972

Total ﬂared BOG, MMscfd

1.414

.806

.019

7,500

Lean composition max. BOG (10% N2) Lean composition min. BOG (25% N2) Rich composition max. BOG (5% N2) Rich composition min. BOG (15% N2)

6,500 OPEX, USD/day

BOG vapor fraction, outlet stream from recondenser

1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0

Process scheme. Different process schemes are applied in

Simulation model. A simulation platform was used to run

FIG. 4. High-high pressure (LNG pressure of 100 barg) condensation performance for different cases.

1.0 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0

standard cubic feet per day (MMscfd). Thus, recovery of BOG is a crucial operation in every LNG receiving terminal.

Lean LNG and min. BOG Rich LNG and min. BOG Lean LNG and max. BOG Rich LNG and max. BOG

5,500 4,500 3,500 2,500

6 BOG pressure, barg

FIG. 6. Low-pressure (LNG pressure of 40 barg) condensation performance for different cases.

38 JANUARY 2013 | HydrocarbonProcessing.com

1,500

7 8 BOG pressure, barg

FIG. 7. OPEX comparison for different operating scenarios in high-pressure case.

LNG/Gas Processing Developments The nitrogen mole fraction in BOG is directly related to the N2 content of LNG. The higher the N2 content in the LNG, the more the N2 vaporizes with BOG. In the performed case studies, the N2 mole fraction in BOG is in the range of .05–.25. (LNG N2 mole percentage is a maximum of 2%; most LNG specifications contain less than 2 mol% N2 .) Higher N2 content in BOG shifts the multiphase area to the left in a phase-envelope diagram— i.e., full condensation can be achieved at higher BOG pressures. Keeping this fact in mind, at certain LNG compositions, greater BOG generation will result in a lower concentration of N2 in the vapor phase. It is, therefore, common to see maximum N2 mol% in lean LNG BOG compositions, along with minimum BOG generation in a facility, as can be inferred from FIGS. 4–6. The higher the N2 content, the more energy is required to recondense the BOG. Two phase-envelope diagrams are shown in FIG. 3, wherein the phase-change behaviors of different compositions and BOG generation rates are compared.

From FIG. 7, it can be seen that, during normal operation (no LNG cargo unloading), a pressure range of 7 barg to 8 barg minimizes OPEX. A clearer prospective of the operating scenarios for high-pressure LNG can be derived from TABLE 1. Here, the most credible scenario is shown as a lean composition with minimum BOG generation, and OPEX and BOG flaring results are tabulated. Recommendations. It is advisable to design a BOG handling

system for a maximum operating pressure of 8 barg. At an operating pressure of 7 barg to 8 barg, both BOG flaring and OPEX are kept to a minimum.

Results. Although BOG condensation can start from BOG

Acknowledgment. I would like to take the opportunity to express my thanks to the entire project team at Ranhill WorleyParsons, which supported me during this study—especially Jag Ghantala (project manager) and Viren Vartak (process lead), who reviewed this article and encouraged me to publish the study results.

pressures as low as 3 barg, the majority of the BOG will be turned into liquid only at pressures higher than 6 barg (FIGS. 4–6). Setting BOG operating pressure at the highest possible level will ensure full condensation, but it may not be a cost-effective or energy-efficient option. An OPEX study was performed to discern the optimum operating pressure range. The main items considered in the OPEX calculations were electricity and fuel gas cost (TABLE 1 and FIG. 7).

MAJID ZOLFKHANI holds degrees in chemical engineering from Sharif University of Technology (BSc) and Iran University of Science and Technology (MSc), both in Tehran. Mr. Zolfkhani is a chartered member of the Institution of Chemical Engineers (IChemE), as well as a chartered member of Engineers Australia, with 12 years of process engineering experience. He has worked with Ranhill WorleyParsons since March 2008 as a senior process engineer, accepting technical and leadership roles for a variety of brownfield, greenfield, offshore and onshore projects.

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Special Report

LNG/Gas Processing Developments E. SALEHI, W. NEL and S. SAVE, Hatch Ltd., Calgary, Alberta, Canada

Viability of GTL for the North American gas market New developments in horizontal drilling, in combination with hydraulic fracturing, have greatly expanded producers’ ability to recover natural gas and oil from shale plays in North America. High shale gas activity has increased dry shale gas production in the US by around five times—from 1 trillion cubic feet (Tcf) in 2006 to 4.8 Tcf in 2010—which is over 20% of the dry natural gas production volume in the US.1,2 Considering that there are 750 Tcf of technically recoverable shale gas resources in the Lower 48 states, the shale gas portion of the US’ overall dry gas production is forecast to rise to 40%–50% over the next two decades.1,2,3 Likewise, in Canada, the technically recoverable shale gas total of 355 Tcf provides a promising resource, as it is more than five times the 62 Tcf of proven reserves of conventional natural gas in Canada.4 Projections show that total US and Canadian shale gas production will increase from about 9 billion cubic feet per day (Bcfd) in 2010 to over 25 Bcfd in 2025.5 Shale gas: A game-changer for North America. Shale

gas has caused the Henry Hub spot price to drop from above $12 per thousand standard cubic feet (Mscf) in June 2008 to less than $4/Mscf since January 2012. Gas was traded below $3/Mscf in the first half of 2012. The low gas price is not only a result of cheap production methods developed during the last few years, but also of general oversupply in an isolated North American market.6 Associated gas production from liquids-rich shale plays and the large number of wells drilled in the last several years are major contributors to the present supply and demand situation for gas and, consequently, to the collapse in gas prices.7 However, as expected, price correction has been occurring since early autumn 2012 due to production cutbacks, switches from coalfired to gas-fired power generation, and higher demand during the cold season. Most references claim $3/Mscf to $4/Mscf as the breakeven price for dry shale gas production, which means that a profitable price range of $4/Mscf to $6/Mscf is forecast for natural gas in the foreseeable future.8,9 Gas transport options. The main challenge of monetizing

gas resources is logistical. Natural gas reserves close to gas markets are usually transported via pipeline. Where this is not feasible, the gas can be transported with alternative methods, such as compressed natural gas (CNG), liquefied natural gas (LNG) and gas-to-liquids (GTL), which all address this challenge by densifying gas and reducing transportation costs. The latter option converts natural gas through Fischer-Tropsch (FT)

synthesis into liquid hydrocarbons, such as diesel and naphtha. Therefore, GTL does not need to compete in the limited gas market, unlike CNG and LNG. A significant reduction in gas prices over the last few years and an escalation in oil prices have led to a high spread between oil and gas prices. This has improved economics for GTL and made it the most promising alternative for adding value to natural gas assets in North America. The lower states of the US and the western provinces of Canada (Alberta and British Columbia) have their own drivers to encourage investment in GTL plants. Gas-to-liquids process. The GTL process (FIG. 1) has three

main steps: • Feedstock preparation and gasification • FT synthesis • Product upgrading. Feedstock preparation and syngas generation. The first step, synthesis gas production, is the most expensive of the three processes, accounting for up to 50% of the CAPEX. Therefore, there is significant incentive for developing new technologies to decrease the capital cost of syngas production. Syngas [hydrogen + carbon monoxide (H2 + CO)] is produced through three main commercial technologies: Steam methane reforming (SMR) and autothermal reforming (ATR), which are both catalytic processes; and partial oxidation (POX), which is a non-catalytic process. SMR does not need an air separation unit (ASU), and the H2:CO ratio is about 3, which represents an advantage for SMR in H2 production applications. Sometimes, a combination of two technologies (ATR and SMR, or POX and SMR) is used, depending on the downstream FT technology requirement. The main reactions involved in these processes are shown in TABLE 1.10,11,12 Unlike SMR, in POX, natural gas and oxygen from an ASU produce syngas at an H2:CO ratio of about 1.6:1.9.13 Shell developed POX technology to produce syngas at its two GTL facilities in Malaysia and Qatar. Some drawbacks of POX are the Steam O2 Natural gas from pipeline

FT tail gas Diesel NG preparation and syngas production

FT synthesis

Product upgrading

Naphtha LPG

FIG. 1. The GTL process. Hydrocarbon Processing | JANUARY 2013 41

LNG/Gas Processing Developments Aside from heat-removal considerations, the reactor design is influenced by the FT products desired. There are two versions of FT technology that work at different temperature ranges, depending on the required products: low-temperature FT (LTFT) and high-temperature Heat removal is the main challenge for the FT (HTFT). FT reactor design. Improper design results in LTFT, with an operating temperature of 200°C– 250°C, produces a mixture of gas and liquid hydroan increased catalyst deactivation rate and carbons, with a large fraction of heavy paraffinic waxy decreased selectivity of the preferred products. compounds, that aims to maximize molecules in the diesel range. HTFT operates at temperatures of 300°C–350°C. This produces lower-molecular-weight paraffins and olefins in FT synthesis requires syngas with an H2:CO ratio of about the gaseous phase, which maximizes gasoline production. A low 2, a value higher than that obtained using POX and lower than chain-growth probability (alpha) of around 0.65 is intentionally that achievable with SMR.14 ATR technology uses both POX chosen for HTFT to avoid hydrocarbon deposition on the cataand SMR reactions. Natural gas, steam and oxygen are reacted lysts, whereas this value is 0.9 or higher for LTFT. in a sub-stoichiometric flame (with a steam-to-carbon ratio Both LTFT and HTFT technologies operate at pressures close to 1 and an oxygen-to-carbon ratio of 0.50–0.65), and of 18 bar–45 bar. Since the HTFT product slate is complex, then converted further along the catalytic bed to produce synit requires significant refining to make it suitable for use as gas with an H2:CO ratio of around 2. transportation fuel. HTFT is also more favorable for chemical Fischer-Tropsch synthesis. FT synthesis is the catalytic applications.15 hydrogenation of CO, which is highly exothermic—i.e., 165 kJ per mole of enthalpy change per mole of CO conversion, as HTFT reactors are either fluidized bed or circulating fluidshown in Eq. 1.15 ized bed, whereas LTFT reactors are designed as either multitubular fixed bed or slurry bed. Since the formation of a liquid phase in the fluidized-bed reactors will disable the fluidization, CO + 2 H2 j CH2– + H2O ΔH = –165 kJ/mol (1) no liquid phase is present outside of the catalyst particles in HTFT reactors.16 Eq. 1 shows that not all the energy in the reactants is transBoth slurry-bed and fixed-bed configurations have advanferred to the products; a portion is released as heat, and the retages and disadvantages. Slurry reactors are more efficient in action is exothermic. However, some heat can be recovered to heat transfer compared to multi-tubular fixed-bed reactors. produce medium-pressure steam, and then to generate power. Higher heat transfer in slurry beds leads to improved temperaTABLE 2 illustrates the main reactions of FT synthesis.11,15 ture control, which limits methane production and increases Due to the exothermic nature of FT reactions, heat removal output of heavier hydrocarbons. is the main challenge for the FT reactor design. Improper deIn contrast, fixed-bed reactors are less efficient in heat resign results in an increased catalyst deactivation rate and demoval. A significant task for slurry reactors is removing catalyst creased selectivity of the preferred products. particles from the FT wax.17 Fine particles can be produced as a result of catalyst attrition in the slurry phase, which is not a TABLE 1. Main synthetic gas reactions concern for fixed-bed reactors since the catalyst is stationary. Reactor Process technology Reaction Fixed-bed reactors are easier to scale up, whereas there is more uncertainty in scaling up slurry-bed reactors. Also, fixedSteam methane reforming (SMR) CH4 + H2O } CO + 3H2 SMR bed reactors are more expensive to build than slurry reactors. Water-gas shift (WGS) CO + H2O } CO2 + H2 However, slurry reactors require more catalyst handling and POX Partial oxidation CH4 + 1/2O2 } CO + 2H2 other auxiliary equipment. Partial oxidation CH4 + 3/2O2 } CO + 2H2O To capture the main benefits of slurry reactors (improved heat removal) and fixed-bed reactors (simpler catalyst-hanATR SMR CH4 + H2O } CO + 3H2 dling systems and lower technology risk), extensive work was WGS CO + H2O } CO2 + H2 conducted by emerging technology licensors to enhance both heat and mass transfer in fixed-bed reactors by reducing the TABLE 2. Main FT reactions size of the tubes. This achievement has led to the development of “microchannel” fixed-bed reactors. The microchannel FT Factor Reaction reactors are significantly smaller in diameter and length comParaffin formation nCO + (2n+1)H2 } CnH2n+2 + nH2O pared to traditional fixed-bed reactors, and they can utilize Oleﬁn formation nCO + 2nH2 } CnH2n + nH2O more efficient FT catalysts with a higher heat-release rate and higher productivity. Alcohol formation nCO + 2nH2 } CnH2n+1OH + (n−1)H2O high outlet temperature from the reactor, which leads to soot formation, and the high cost of the reactor materials.

WGS reaction

CO + H2O } CO2 + H2

Boudouard reaction

2CO } C + CO2

Carbon deposition

CO + H2 } C + H2O

42 JANUARY 2013 | HydrocarbonProcessing.com

Upgrading. FT product upgrading applies the same basic

technologies and catalysts as those used in a crude oil refinery. Upgrading unit design depends on the feed to be processed.11

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LNG/Gas Processing Developments For HTFT, the FT products contain considerable amounts of olefins that are removed for chemical applications, whereas the FT products from LTFT lack sufficient olefins content to justify their extraction.16 The FT products, after stabilization, are hydroisomerized/ hydrocracked to produce more distillates at mild conditions. Very severe hydroprocessing improves the weak cold properties of produced distillates (i.e., decreasing diesel cloudpoint), but at the expense of lowering the diesel output and increasing the yield of lighter hydrocarbons. GTL products market. These products are unique; they are clean, sulfur-free, paraffinic hydrocarbons. Although a broad range of specialty products can be obtained through the GTL process, the focus is on three main products: diesel, naphtha and liquefied petroleum gas (LPG). The diesel markets in North America and worldwide are steadily growing. Particularly in Europe, rising demand is driven by the road freight sector and by passenger vehicles switching from gasoline to diesel.15 In the US, the Energy Information Administration (EIA) projects that diesel consumption will reach 4.5 million barrels per day (MMbpd) by 2035—which means an increase of over 40%.18 Likewise, the National En8 7

$/MMbtu

6 5 4 3 2

2011

2015

2019

2023 Year

2027

2031

2035

FIG. 2. Natural gas (Henry Hub) price projection.18 130

120

$/bbl

110

100

2011

2015

2019

2023 Year

FIG. 3. Crude oil (WTI) price projection.18

44 JANUARY 2013 | HydrocarbonProcessing.com

2027

2031

2035

ergy Board of Canada forecasts that domestic diesel consumption will increase by about 50% by 2035.19 FT diesel can be used directly or blended with crude oilderived diesel and burned in existing vehicle engines. FT diesel has zero sulfur, contains low aromatics, and is mostly comprised of linear products with a cetane number above 70, compared to a typical cetane number of 40 for crude oil-derived diesel. Due to these properties, FT diesel has the potential to be sold as a premium diesel blendstock. In addition, FT diesel can be blended with lower-cetane, lower-quality diesels to achieve commercial diesel specifications. Aside from the listed advantages, the lower emissions levels of hydrocarbons, CO, NOx and particulate matter (PM) make FT diesel a more promising fuel vs. conventional diesel.20 FT naphtha is not suitable for gasoline production because of its low octane number and linear paraffinic nature. However, it can be utilized as a bitumen diluent in specific markets, such as the oil sands market in Canada. Canadian producers prefer to export their heavy oil for processing at US refineries, for which diluent is required. To meet pipeline specifications, one third of a barrel of diluent is required for every barrel of bitumen that is to be pumped. The growing oil sands business in Alberta, Canada has resulted in a corresponding growing market for FT naphtha. According to the Canadian Association of Petroleum Producers (CAPP) forecast, total oil sands production will reach 3.7 MMbpd by 2025, representing an increase of more than double the current level.21 The other potential market for FT naphtha is feedstock for steam crackers to produce petrochemicals. FT naphtha’s paraffinic nature makes it is an ideal feedstock for naphtha crackers, and it gives a higher yield of cracker products (ethylene and propylene), compared to crude oil-derived naphtha. Most naphtha steam crackers are located in Japan and South Korea. In North America, steam crackers mainly use gas feedstocks. There are also various industrial uses for LPG, primarily as fuel or as petrochemical feedstock. New in-situ oil sands technologies create an alternative use for LPG, potentially aiding in the extraction of bitumen from oil sands. GTL economics. The oil-to-gas price spread is the main driver affecting the viability of GTL. In fact, GTL products, such as FT diesel and naphtha, will compete directly with crude oil-derived products. The Henry Hub natural gas and West Texas Intermediate (WTI) crude oil price benchmarks are used as the basis for the current study. FIG. 2 and FIG. 3 show the EIA’s 2011–2035 projections for natural gas and crude oil prices, respectively. The average prices for WTI oil and Henry Hub gas in the forseeable future are $110/bbl and $5.60/MMBtu, respectively. This translates into an oil-to-gas price ratio of about 20, compared to a forecast average of less than 10, as estimated in the previous 21 years (FIG. 4). However, the EIA’s 2012 projections show a $20/bbl higher average oil price and a $0.30/MMBtu lower average natural gas price, which leads to a higher spread between crude oil and natural gas prices. A higher spread means increased profitability for GTL. On average, 10 MMBtu of natural gas is required to produce 1 bbl of GTL product, of which about half is consumed to provide the energy needed for GTL processing and for generating

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LNG/Gas Processing Developments some power for export. The differential is the energy content of the liquid product. It means that the average feedstock cost is about $56/bbl, utilizing an average gas price of $5.60/MMBtu for the lifetime of the plant. A significant portion of operating expenditure (OPEX) for a GTL facility (e.g., labor, maintenance and insurance) is size- and location-specific, whereas chemicals, catalysts and utilities are not. A rough OPEX estimate of $15/bbl to $20/ bbl may be used.15, 23 In addition, $3/bbl is assumed for the transportation cost of the products—an assumption that is also location-specific. As with any process in the oil and gas industry, GTL is capital-intensive; therefore, economy of scale is important. Oryx GTL, with $1.2 billion (B) to $1.5 B in capital expenditure (CAPEX) and a capacity of 34,000 bpd, has a specific CAPEX in the range of $35,000 to $44,000 per bpd. Pearl GTL, which is an integrated upstream and downstream project with $20 B in CAPEX and capacities of 140,000 bpd of GTL and 120,000 bpd of NGL, translates to a specific CAPEX of $77,000 per bpd. The higher CAPEX for Pearl GTL is due to the cost escalation of engineering and materials from 2006–2007, when Pearl GTL started construction. Oryx GTL benefited from a lump-sum engineering, procurement and construction (EPC) contract, which had been sealed prior to 2006, hence avoiding this period of cost escalation.20 Sasol of South Africa, which is the technology provider as well as a major stakeholder of the Oryx GTL plant in Qatar, 40

Crude oil to natural gas price ratio

Current ratio

Historical ratio

EIA forecast

Average EIA: 20

10 5 0 1990

1995

2000

2005

2010 Year

2015

2020

2025

FIG. 4. Crude oil (WTI) to natural gas (Henry Hub) price ratio.22

2030

seeks to build GTL facilities in North America. In the US, the cost estimate for Sasol’s proposed, 96,000-bpd GTL plant in Louisiana is $8 B to $9 B (approximately $88,000 per bpd).24 For this analysis, a specific CAPEX of $100,000 per bpd was assumed, which is higher than the Pearl GTL CAPEX and Sasol’s estimated CAPEX for the US Gulf Coast. The $100,000 per bpd translates to an estimated cost of $10/bbl of GTL products for a GTL plant running for 30 years. The breakdown for GTL product cost in FIG. 5 shows that gas feedstock cost is the highest contributing factor to the total cost of 1 bbl of GTL product. However, where the stranded gas alternatives are to leave the gas alone or to flare it, the negotiated gas price has little relationship to the market price. Therefore, stranded-gas GTL economics are primarily driven by product price and CAPEX. The breakeven point for GTL lies between $50/bbl and $100/bbl of the crude oil price, depending mainly on the CAPEX and the natural gas price.25 To evaluate the viability of a generic GTL plant in North America, GTL product prices were forecast based on the EIA’s 2011 projection of the WTI price, utilizing the historical relationships between diesel, naphtha and LPG prices and the price of WTI. The analysis of historical prices shows a relationship between US Gulf Coast ultra-low-sulfur diesel price and WTI price, as seen in FIG. 6. Likewise, FIG. 7 demonstrates the historical LPG price as a function of WTI. The Mont Belvieu, Texas historical propane spot price was assumed for the LPG price, and naphtha was assumed to be sold at the WTI price projected by the EIA. Assuming a GTL plant with the capacity of Oryx GTL, the product slate would be 24,000 bpd of diesel, 9,000 bpd of naphtha and 1,000 bpd of LPG (although Oryx GTL announced an even higher diesel production at the XTL Summit in London in May 2012). The internal rate of return (IRR), which is graphed against CAPEX in FIG. 8, considers the following items: • The assumptions made for gas price projection (FIG. 2) • GTL product price projections (FIGS. 3, 6 and 7) • OPEX • Transportation cost • A plant availability of 93%. As shown in FIG. 8, by increasing CAPEX from $80,000 per bpd to $200,000 per bpd, the IRR will decrease from above 20% to below 10%. FIG. 9 also shows IRR as a function of the 180 US Gulf Coast ultra-low-sulfur diesel price, $/bbl

60 50

$/bbl

40 30 20 10

140 120 100 80 60 40 20 0 50

0 Feedstock

CAPEX

OPEX

FIG. 5. GTL product cost breakdowns.

46 JANUARY 2013 | HydrocarbonProcessing.com

Shipping

y = 1.2198x + 0.249

160

80 90 WTI price, $/bbl

100

110

FIG. 6. Historical price relationship between diesel and WTI.26

120

LNG/Gas Processing Developments

25 20 15 10 5 0

80,000

100,000

CAPEX, $/bpd

150,000

200,000

FIG. 8. Plant IRR vs. CAPEX. 140

140

120

100

80 2

4 6 Average gas price, $/MMBtu CAPEX: $80,000/bpd

120

100

80 2

4 6 Average gas price, $/MMBtu CAPEX: $100,000/bpd

140

90 80 70 60 50 40

Average WTI price, $/bbl

y = 0.589x + 3.6856 Average WTI price, $/bbl

Mont Belvieu, Texas propane spot price (free on board), $/bbl

ery have led to an oversupply of natural gas in an isolated North American market. This has caused an unprecedented disconnect between oil and gas prices. Economic evaluations have shown that the wide spread between oil and gas prices is making GTL viable at a broad range of CAPEX values. GTL installations are

Average WTI price, $/bbl

Shale gas development has significantly changed natural gas pricing in North America and gas trade between Canada and the US. Historically, Canada has been a main gas supplier to the US, which now produces enough gas to be in oversupply. The two main alternatives for monetizing natural gas in both Canada and the US are LNG and GTL. Canada has been planning to install LNG plants in British Columbia, on Canada’s West Coast, to supply Asian markets—particularly Japan. In the US, most planned installations are located along the Gulf Coast and target European markets. Although higher thermal efficiency and proven technology make LNG an attractive alternative, the product is still sold in the limited natural gas market. Furthermore, LNG exports likely will not aid in reducing oil imports, of which 70% are consumed by the transportation sector. GTL, on the other hand, provides clean transportation fuels and also significantly improves US energy security. Western Canada and the US Gulf Coast each have unique advantages and disadvantages for hosting GTL plants. Canada is witnessing higher labor and construction costs (CAPEX and

Takeaway. New technological achievements in shale gas recov-

IRR, %

Potential locations for GTL installation in North America.

OPEX) than the US. Conversely, Canada’s huge gas resources are landlocked, with no readily available market, which will keep the Canadian gas price below the US gas price. The benefit of a lower specific CAPEX in the US is mainly due to accessibility to a lower-cost labor force. The US Gulf Coast, in particular, benefits from proximity to a skilled labor force and access to the coast. The large products market in the US also supports the implementation of larger-scale GTL plants. Canada, with the advantage of a lower gas price and growing naphtha and diesel markets in Alberta, could be a good alternative location, especially for small- to medium-sized GTL plants.

Average WTI price, $/bbl

average natural gas price and the average WTI price for the service life of the plant, at various CAPEXs. As expected, gas and WTI pricings have a significant effect on the total economics of GTL. The economic evaluation shows that, at a gas price of up to $8/MMBtu, assuming a CAPEX of $80,000 per bpd (FIG. 9), GTL could still be economical with an average WTI price of above $120/bbl. However, most scenarios forecast a gas price of $4/MMBtu to $6/MMBtu for the foreseeable future. Conversely, at a CAPEX of $200,000 per bpd, GTL would be viable only at higher crude oil and lower gas prices. Associated gas, as the byproduct of US wet shale plays, could be a good example for low-value, or sometimes zero-value, feedstock. In addition, electricity as the byproduct of a GTL plant could be exported to improve the IRR; however, it is not included in this economic evaluation. Furthermore, production of higher-value byproducts, such as lube oils, paraffins and waxes, has not been considered in this evaluation. Note: this economic evaluation has been conservative regarding the pricing for feedstock and GTL products. Selecting the right location with accessibility to less-expensive gas feedstock significantly improves economics.

120

100

120

100

30 20 10 0

4 6 Average gas price, $/MMBtu CAPEX: $150,000/bpd

80 100 WTI price, $/bbl

120

FIG. 7. Historical price relationship between LPG and WTI.26

140

160

IRR (%):

0%–10% 30%–40%

10%–20% 40%–50%

80 2

4 6 Average gas price, $/MMBtu CAPEX: $200,000/bpd

20%–30%

FIG. 9. IRR vs. average natural gas and WTI prices at various CAPEXs. Hydrocarbon Processing | JANUARY 2013 47

LNG/Gas Processing Developments economically feasible at low natural gas prices and high forecast oil prices, even at lofty CAPEX values of around $200,000/bpd. New developments in FT technology will enable economically viable GTL facilities at a smaller scale, compared to existing industrial facilities. However, one must be careful to understand the various challenges in implementing new FT technology related to gas-loop optimization, total process integration to meet a suitable product slate, catalyst handling, efficient startup, commissioning and operations, and a process design to support a zero-holdup system. A holistic view is required to consider and integrate these factors in a practical manner. An efficient gas-loop design, along with the appropriate level of modularization and an effective project delivery strategy, is known to impact the IRR by 3%–5%. This gives a significant boost to overall project viability. Conversely, negating some of the practical aspects of commercializing technology might lead to schedule and startup delays, thereby having the opposite effect on IRR. LITERATURE CITED “Review of emerging resources: US shale gas and shale oil plays,” US Energy Information Administration, July 2011. 2 Butler, N., “Shale gas and global energy security,” Energy Economist, 2011. 3 “Fueling North America’s energy future,” IHS CERA, 2010. 4 “Country overview: Canada,” US Energy Information Administration, October 16, 2012. 5 “Canada’s shale gas,” Canadian Association of Petroleum Producers, February 5, 2010. 6 “Shale fueling a looming energy credit crunch,” Petroleum Economist, May 10, 2012. 7 “After the gold rush: A perspective on future US natural gas supply and price,” The Oil Drum, February 8, 2012. 1

Brown, D., “What is the cost of shale gas play?” AAPG Explorer, April 2011. “Shell has learned from its Pearl GTL project and costs can be cut: Voser,” Platts, March 7, 2012. 10 Aasberg-Petersen, K., J. H. Bak Hansen, T. S. Christensen and I. Dybkjaer, “Technologies for large-scale gas conversion,” Applied Catalysis A: General, Vol. 221, 2001. 11 Velasco, J. A., “Gas to liquids: A technology for natural gas industrialization in Bolivia,” Journal of Natural Gas Science and Engineering, Vol. 2, 2010. 12 Liu, J. A., “Kinetics, catalysis and mechanism of methane steam reforming,” MSc thesis, Worcester Polytechnic Institute Chemical Engineering Department, 2006. 13 Vosloo, A. C., “Fischer-Tropsch: A futuristic view,” Fuel Processing Technology, Vol. 71, 2001. 14 Wilhelm, D. J., D. R. Simbeck, A. D. Karp and R. L. Dickenson, “Syngas production for gas-to-liquids applications: Technologies, issues and outlook,” Fuel Processing Technology, Vol. 71, 2001. 15 Tijm, P., Gas-to-Liquids, Fischer-Tropsch, Advanced Energy Technology, Future’s Pathway, Bookland Direct, 2010. 16 Steynberg, A. P., “Introduction to Fischer-Tropsch technology,” Studies in Surface Science and Catalysis, Vol. 152, 2004. 17 De Klerk, A., Fischer-Tropsch Refining, Wiley-VCH, 2011. 18 “Annual projections to 2035,” US Energy Information Administration, April 2011. 19 “Canada’s energy future: Energy supply and demand projections to 2035—Energy market assessment,” National Energy Board of Canada, October 17, 2012. 20 Rahmim, I., “Special report: GTL, CTL finding roles in global energy,” Oil & Gas Journal, March 24, 2008. 21 “Crude oil, markets and pipelines,” Canadian Association of Petroleum Producers, June 2011. 22 “Natural gas and crude oil prices in AEO2009,” US Energy Information Administration. 23 “Gas-to-liquids: A reserve ready to be tapped,” IHS CERA, July 14, 2011. 24 “Sasol eyes growth in North America, exit from Iran,” Hydrocarbon Processing, September 10, 2012. 25 McCracken, R., “Prostrate before Pearl,” Energy Economist, July 2011. 26 “Spot prices for crude oil and petroleum products,” US Energy Information Administration. 8

EBRAHIM SALEHI is a process engineer with more than nine years of experience with operating and EPC companies, including four years of PhD research in biofuels and two years of field experience in a petrochemical complex in southern Iran. His industry experience has taken place mainly in natural gas, including conceptual and pre-feasibility studies on GTL in western Canada and study opportunities for developing compressed natural gas (CNG) and adsorbed natural gas (ANG) in Iran. Mr. Salehi’s recent work experience involves the gasification and Fischer-Tropsch areas of a GTL pre-feasibility study with Hatch, and he has developed an in-depth understanding of gasification, Fischer-Tropsch, and upgrading technologies. Mr. Salehi received the Industrial R&D Fellowship (IRDF) award for Hatch from the Natural Sciences and Engineering Research Council (NSERC) of Canada. WESSEL NEL is a senior process engineer at Hatch with more than 14 years of experience. Of these 14 years, 12 were dedicated to Fischer-Tropsch-related projects, including 10 years at Sasol. Mr. Nel has been the lead Fischer-Tropsch engineer on a number of Hatch’s CTL, GTL and biomass-toliquids (BTL) studies in recent years, and the project manager for recent GTL studies. He has developed an extensive understanding of established and upcoming GTL technologies from a broad range of licensors. Mr. Nel’s skills include conceptual to detailed process design, process simulation, flowsheet optimization, economic evaluation, and project and engineering management. SANJIV SAVE is the director of oil and gas (hydrocarbon processing) with Hatch’s oil and gas business unit. He has over 20 years of professional experience with both operating and consulting companies, in the areas of project and business management for multidisciplinary engineering, procurement and construction (EPC) projects in the energy sector. Mr. Save’s specific areas of technical expertise include heavy oil upgrading and non-conventional fossil fuels—namely oil sands, oil shale, gas-toliquids (GTL), coal-to-liquids (CTL), and carbon capture and sequestration. His solid technical qualifications, organizational and management skills, and ability to transcend cultural barriers have led to the successful execution of several projects. Also, his strong research and development background has contributed to the publication of several articles, chapters and patents.

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Special Report

LNG/Gas Processing Developments A. TERRIGEOL, CECA SA, Paris, France

Molecular sieves in gas processing: Effects and consequences by contaminants In the natural gas processing chain, pretreatment typically includes removing acid gas, sulfur and mercury. The moisture specification of the gas depends on the downstream equipment. When cryogenic processes are involved, such as in natural gas liquids (NGLs) recovery or liquefied natural gas (LNG) production, avoiding hydrates requires water dew points that only zeolite-based molecular sieves can achieve. The principles of adsorption on molecular sieves are easy to understand, but practice sometimes reveals traps to avoid. The porous crystalline structure and the large surface area exhibiting a high electronic activity give molecular sieves their outstanding adsorption properties. However, possible side effects should be noted. Contaminants can disturb the adsorption process in several ways: degradation of the structure, partial blocking of the adsorbent bed and side reactions. The compounds involved and the causes are varied, but the consequences are always the same: poor performance, ultimately leading to premature breakthrough, unacceptable pressure drop or adsorbent unloading difficulties.

INDUSTRIAL ADSORPTION ON ZEOLITE MOLECULAR SIEVES Zeolites are crystalline alumino-silicates. There are close to 200 different crystal networks: about 40 are from natural origins, and others, industrially synthesized for different purposes such as catalysis, ion exchange and separation. Two zeolites types are widely used for separation (FIG. 1): zeolite A and X (Faujasite). Their network of repeated crystals forms channels and cavities that exhibit a very large and electronically active surface area (up to 800 m2/g) and attract polar molecules. In the separation applications, the aim is to selectively retain molecules that form low energy bonds with the structure. This exothermic phenomenon is called physisorption and it follows adsorption isotherms. To be efficiently adsorbed, the polar molecules must be small enough to enter the cavities via their windows (pores). The diameter of the pores and cavities depends on the zeolite type and on the cations that are situated around the pores. Zeolites “3A”, “4A” and “5A” show 3, 4 and 5 angstrom (Å) pores, respectively, and allows smaller molecules to enter their cavities. Zeolite X has 7.4 Å pores in its sodium form. Depending on the application and molecules to be separated, one will choose the appropriate type of zeolite. To be used as fixed beds in vessels, the powder of synthetized crystals is compounded with a binding clay to form 0.5-

mm to 5.0-mm beads or extrudates. The resulting material exhibits a complex network of micropores (the crystal windows of the active sites), mesopores (20–50 Å) and macropores (> 50 Å). By changing the adsorption equilibrium conditions (pressure and temperature), the adsorbed molecules can be desorbed from the active sites, and the zeolite recovers most of its original adsorption capacity: it is “regenerated.” Regeneration is key and is described in further detail later. From this, one can understand that the complexity and the activity of the structure may lead to side reactions. Some molecules can form a real chemical bond with the zeolite material (chemisorption) and cannot be desorbed. Others react together, sometimes helped by the zeolite and/or the binder catalytic properties. In the presence of aggressive species and operating conditions, the binder and the crystals themselves can be destroyed, leading to powdering or aggregates. Basics of industrial adsorption. Molecular sieves for natural gas treatment are loaded in adsorbers. The impurities in the treated stream saturate the molecular sieve bed generally within a few hours or days. Therefore, at least two beds have to be used: one in adsorption, while the other is being “regenerated”. To accommodate high flowrates and acceptable diameters, several adsorbers are often used in parallel and are alternatively regenerated (FIG. 2). During adsorption, a molecular sieve bed can be modelized by a three-zone system (FIG. 3). Close to the inlet is the equilibrium zone (EZ), where the adsorbent is in equilibrium with the process fluid (saturated at the partial pressure and temperature conditions). The next area, known as the mass-transfer zone (MTZ), is where the dynamics of adsorption take place.

Zeolite A “LTA”

Zeolite X “FAU”

FIG. 1. Structure of the basic zeolite A and zeolite X crystals. Hydrocarbon Processing | JANUARY 2013 51

LNG/Gas Processing Developments The MTZ shows the impurities concentration decreasing gradient. The MTZ depends mainly on the diffusion kinetics and flow velocity. The larger the accessible surface, the shorter the MTZ. To optimize the surface area and therefore the global bed length, most designs involve smaller particles in the MTZ compared to the EZ. The third area is made of fresh adsorbent that, for a given adsorption time, has not been in contact with the impurities. During the adsorption phase, the EZ extends and the MTZ moves forward. All along its life and repeated cycles, the adsorbent slowly loses its properties (fouling and destruction). Therefore, for the same service (same overall adsorption capacity), the EZ and the MTZ get longer. Some units operate on a “fixed” cycle time: the cycles always have the same duration. At the beginning of the lifetime, when the adsorbent is new, there is still fresh unused molecular sieves in the vessel. For these units, the design is optimized when, at the end of the last adsorption phase of the foreseen product lifetime, the MTZ almost reaches the limit of the bed. Other units operate under “breakthrough” conditions. In that case, the adsorption time decreases slowly all along the product lifetime. There are two main ways to regenerate a molecular sieve bed: Pressure swing adsorption (PSA) and temperature swing adsorption (TSA). In the first case, the change in the adsorption equilibrium is obtained by decreasing the pressure. In the second case, which is more efficient for thorough impurities Adsorption

Vessel A

Adsorption

Vessel B

Reg

Vessel C

Reg 0

Regeneration

Reg

Adsorption

Adsorption 8

Reg 24

Reg

32 40 48 “Carousel operation”

hrs

Cycle time 24 hrs

FIG. 2. Example of a “2+1” system with 16 hours adsorption and eight hours regeneration.

EZ MTZ

EZ EZ MTZ

C1 Fresh

MTZ Fresh Breakthrough

Time = x

Time = y > x

Time = z > y

FIG. 3. Equilibrium zone (EZ) and mass transfer zone (MTZ).

52 JANUARY 2013 | HydrocarbonProcessing.com

COMMON SYMPTOMS DUE TO THE PRESENCE OF CONTAMINANTS For a given lifetime, a good unit design guarantees a specified purity during a given adsorption time, and a maximum pressure drop. The main consequence of poor operation or contaminant effect is premature breakthrough. It is sometimes possible to correct the problem by modifying the operating conditions, but it often requires a change-out of the adsorbents. Another reason for premature adsorbent replacement is when the pressure drop rises to unacceptable levels. The consequences of poor operation that are strictly related to process parameters or too short designs are not detailed here. The information within this article focuses on the effects (expected or not) of the feed components. In the following, we assume that the operating parameters are correct and that they match the design specifications, at least from a theoretical standpoint. Premature breakthrough. When the adsorbent becomes

Adsorption

desorption, a hot gas (180°C–300°C) is passed through the adsorbers. The heating step is critical for several reasons: the gas has to be clean enough not to lead to side effects (exacerbated at high temperature); and it has to carefully address the required regeneration energy duty (temperature, flowrate, duration). After heating, a cooling phase is needed before switching back to adsorption, so that a temperature peak that would significantly disturb the downstream process (especially heat exchangers) most of the time is avoided.

unable to meet the impurities specifications, premature breakthrough happens. Before the expected end of the adsorption time, impurities content at the adsorbers’ outlet increase to a level higher than tolerated. Reasons for premature breakthrough can be: • Competition with other adsorbed species, for which quantity and/or impact were underestimated at the design stage. When the attraction force of these molecules is similar or stronger than the targeted compounds, they can be difficult to displace, or can even stay adsorbed and decrease the remaining capacity allocated to the specific job. • Porosity fouling is detailed here. As explained previously, molecular sieve capacity slowly decreases with time. One of the main reason is that the porosity gets partially fouled with carbonaceous components. These compounds, often referred to as “coke,” are caused by heavy hydrocarbons (HC) present in the feed that sometimes remain in the bed along the cycles. The MTZ is lengthened and the overall porosity is decreased. Normal fouling is taken into account in the unit design, among other “aging” factors. However, under certain circumstances, coking becomes severe, and fouling leads to premature breakthrough. Molecules such as aromatic rings (cyclo-pentadiene to dimethyl-naphthalene) or heavy aliphatic compounds (C8 to C10 and more) have been identified. • Destruction of the adsorbent can result due to chemical attacks by aggressive species. In severe cases, the crystal structure itself suffers and is altered or turned to powder, reducing the quantity of active material. In other cases, liquid reflux at

LNG/Gas Processing Developments (most of the time, a slip stream of the dried gas). When passhigh temperature can destroy and agglomerate large parts of ing through the heater, iron oxides on the steel surfaces (also the beds, especially around the vessel walls. favored by the presence of oxygen) can catalyze the oxidation • Channeling (preferential path) occurs when the flow of the HC at normal regeneration temperatures (250°C to is not well distributed on the cross-section of the bed. If this 300°C). Once initiated, and if oxygen is present, the combushappens during adsorption, the adsorbent is not evenly used. If it occurs during the regeneration phase, the product is not well regenerated: some areas in the bed still show high impurity residuals when switching back to The main consequence of poor operation or adsorption. In both cases, premature breakthrough contaminant effect is premature breakthrough is highly possible. There are several “mechanical” or “process” reasons that can lead to uneven flow distriof the impurities. It is sometimes possible to bution. Here we focus on the causes related to feed correct the problem by modifying the operating composition, which are often the same as the ones responsible for product destruction (leading to dust conditions, but it often requires a change out of and agglomerates that block large parts of the bed).

the adsorbents. Another reason for premature replacement of the adsorbent is when the pressure drop rises to unacceptable levels.

Unacceptable pressure drop. Natural gas treaters experience pressure drop from 0.1 bar to 0.5 bar during start of run (SOR). Along the cycles, pressure drop slowly increases (normal fouling due to HC deposits, light dusting due to thermal stress and attrition). In favorable conditions pressure drop will less than double within 4–5 years of service; while, in difficult conditions, it evolves much faster. In most serious cases, HC condensation, liquid reflux and heavy dusting can lead to a dramatic increase of the bed resistance. Actually, channeling and high pressure drop very often go together as different symptoms for the same causes. At elevated pressure drop, it is no longer possible to process the normal flowrate, and the product must be replaced.

Mitigation. In most cases, solutions exist to minimize or elim-

inate the foregoing described problems. Of course the real issue is to anticipate the troubles before having to cure. It is very important to be aware of all the potential problems as soon as possible in the design process of a unit. Basically, when the cause is due to a real contaminant that was not theoretically expected, the solution typically involves cutting the contamination source or finding the process/product based solutions to live with it. This can be, for instance, a lower regeneration temperature (reactivity limitation), a guard layer (to cope with the species and protect molecular sieves) or the use of resistant grades. When it comes to normal components of the feed that cannot be avoided (like HC or water), the source cannot be cut, and solutions involve not only product and process, but equipment too.

TYPICAL CONTAMINANTS, EFFECTS AND SOLUTIONS Oxygen is not usually part of a typical fossil natural gas. However, the presence of oxygen is sometimes reported (10 ppmV to 50 ppmV and sometimes more). Reasons for the presence of oxygen are not always obvious, and several possible explanations related to process or equipment are available. Oxygen can be present in the feed and/or in the regeneration gas. It has two potential bad effects: • Oxidation reactions (combustion) of HC. In natural gas drying, the regeneration gas often mainly consists of methane

tion reactions continue and propagate in the vessel. Methane and oxygen form CO2 and water, which plays against the desired final specifications. Reactions involving heavier HC are more complex and ultimately form heavy coke deposits. As a result, the MTZ length and the adsorption capacity of the molecular sieves are rapidly affected. In serious cases, pressure drop can rapidly and significantly increase. It has been shown that up to 50% of the oxygen can be converted, and that significant problems start with oxygen concentrations in the feed as low as 15 ppmV to 20 ppmV. • In the presence of sulfur compounds like hydrogen sulfide (H2S), oxygen forms sulfur dioxide and water, and, ultimately, elemental sulfur. This elemental sulfur is deposed in the porous structure, and clusters can even form and partially block the flowrate, leading to channeling, high pressure drop and, eventually, to premature breakthrough. While the second issue is difficult to address, except by minimizing sulfur and oxygen levels, efficient answers exist for the first problem. Taking into account the higher water post-regeneration residual can be done at the design stage, provided one is aware of the potential problem. In any case, the most efficient solution is to dramatically decrease the heating temperature (160°C to 180°C) to eliminate the combustion reactions. Of course, there are several drawbacks, like higher water residual due to low temperature and more regeneration gas requirements. Liquid water. In natural gas treatment, liquid water droplets

are generally carried over onto the molecular sieve bed when the upstream gas/liquid separator experiences an upset in operating conditions, is undersized or not efficient enough. However, liquid water can also come from low points or dead volumes in the piping where vapor condenses during some phases of the process, waiting for the next switch to be entrained on the bed. Of course, the most obvious consequence is that more water must be handled by the molecular sieves, which impacts adsorption time, possibly leading to premature breakthrough. In fact, this is not the main issue. Hydrocarbon Processing | JANUARY 2013 53

LNG/Gas Processing Developments Water droplets strongly react with molecular sieves, both physically (adsorption heat release) and mechanically (hammering the structure). This results in local “hot spots” where the clay binder is damaged and powdered. In severe cases, dusting becomes significant, leading to pressure drop increase, channeling, and premature breakthrough. Several solutions are available to reduce the effects of liquid water. Stopping the upstream carryover is indeed the most efficient, and can be done by implementing a suitable gas/liquid separator, typically a vertical coalescer with a liquid specification of less than 0.1 ppmwt. The case of low points and dead volumes is not always easy to diagnose, and requires a careful review of the piping configuration. But once the problem is identified, some modification or drain pot installation can easily solve it. Hydrothermal damaging. Another destructive effect of liq-

uid water is likely to occur when the heating step is done too fast, and this is often referred to as “hydrothermal damaging.” By heating too fast at high temperatures, water rapidly desorbs from the lower layers, while the bed experiences an important temperature gradient (FIG. 4): its bottom is already hot, but its upper section is still at adsorption temperature. When arriving onto these colder parts of the bed, the regeneration gas gets oversaturated, and water “retro-condenses” on the top layers, especially near the vessel wall. This phenomenon can be seen on the outlet temperature curve of the regeneration gas, which shows a plateau (typical of a physical state change). As the temperature increases, it soon results in boiling the water in the molecular sieve bed. This phenomenon is enhanced by high pressures and low regeneration flowrates. The consequence of water condensation (also known as water reflux) is obviously the weakening of the binder and of the zeolite structure. The binding clay is leached from the molecular sieve structure and disaggregates to dust and Bed temperature proﬁles 300

present in the entrained water. Once they are in the pores, they are not easily removed and remain in the product when water is vaporized. The salts accumulate and build up along the cycles, hindering the access to the pores and damaging the structure (binder and crystals), both physically and chemically. The phenomenon takes place essentially on the top of the bed, causing powdering of the material, participating in agglomerates formation (pressure drop increase) and leading to a drastic decrease of the adsorbents’ performance. Even at very low salts content (< 0.5 ppm), the destruction of more than half the adsorption capacity within a few months has been reported. Again, the best solution (if not the only one) is to avoid liquid water carry over onto the sieves. the entrainment or the formation of liquid HC can be highly damageable to the sieves.

Temperature, °C

150

NaCl. Salts such as sodium chloride (NaCl) can sometimes be

Liquid hydrocarbons. Like liquid water and amines/caustic,

250

200

powder. Eventually, it also rearranges to form agglomerates all around the vessel wall (FIG. 5) under the action of water soluble salts that can ion exchange with the zeolite and cement the structure. In some cases, the agglomerates can take very significant volumes of the bed, causing preferential paths and high pressure drop. All these gas/liquid interactions at high temperature are mechanically damaging. They create attrition and can result in bed movements, which also leads to uneven distribution of the flow and pressure drop increase. Zeolite crystal structure itself is affected by total loss of capacity. Zeolite X crystals can be destroyed, while Zeolite A crystals see a decrease in their kinetics of adsorption. This is due to a “pore closure” effect that concerns mainly the external surface of the crystals (especially in the case of the 3A type). Hydrothermal damaging can be significantly reduced, and sometimes stopped, by using a suitable heating procedure. Typically, a heating ramp of a few degrees per minutes, together with a preliminary heating step around 80°C to 130°C, are usual and efficient implementation. To increase the regeneration gas flowrate (to convey more water out of the bed and heat the upper sections faster), or to lower the regeneration pressure, can also be recommended whenever possible.

100 0.2 1.7

50 3.1 Bed length, m

4.6 22.5 6.0

112.5 67.5 Elapsed time, min.

FIG. 4. Evolution of bed temperature profile with time.

54 JANUARY 2013 | HydrocarbonProcessing.com

FIG. 5. Agglomerated product around the vessel wall.

LNG/Gas Processing Developments

Pressure, atm

Liquid HC can be entrained with the feed gas. Another Acids. All acids are able to alter and destroy the zeolite frameorigin, known as “retrograde condensation” is difficult to diwork by a dealumination process (FIG. 7). This can be detrimenagnose, but is scientifically founded and admitted by many tal for the molecular sieve structure, causing dust and leading authors. FIG. 6 shows for two cases (a lean gas and a heavier one), the corresponding “phase envelope.” It shows that a heavy gas at HC dew point, when operIt may happen that amine foams or caustic ated at high pressure, can be subject to HC condensadroplets are carried over onto the molecular tion when the pressure is decreased. Therefore, one can expect liquids to form due to pressure drop across sieves. Such carryover can be minimized by the bed. Even though it can be computer-simulated, acting on the upstream processes. An efficient it is difficult to accurately estimate how much liquids form and stay in the molecular sieve porosity. gas / liquid separator has to be implemented, As previously discussed, the HC deposit blocks and a protective layer of silica gel can help access to micro-pores, and therefore extends the MTZ, thus decreasing the total adsorption capacsignificantly. However, resistant molecular ity. In addition to that, the heavier HC can crack and sieve products are part of the solution. polymerize during regeneration; it can build up and worsen the problem. Pressure drop increases and channelling may appear. For such gas at the HC dew point, the most efficient soluto a premature pressure drop increase and breakthrough. Howtion is to preheat the inlet stream by 3°C to 5°C. ever, acid attack and the dealumination process mostly occurs during regeneration (high temperature). To avoid related problems, one should use a specific acid-resistant molecular sieve. Liquid amines and caustic carryover. Amine and caustic based processes are widely used to remove acid gases (like H2S and CO2 ) and some mercaptans within upstream molecCOS formation. Carbonyl sulfide (COS) can form according ular sieve units. It may happen that, under upsetting circumto the balanced reaction: stances, amine foams or caustic droplets are carried over onto H2S + CO2 , COS + H2O the molecular sieves. Commonly used amines, due to their chemical structure When sour natural gas enters the adsorbent bed, it is usuand polarity, can adsorb in the material porosity, with two main ally water-saturated. Therefore, it is composed of H2S, CO2 and consequences: water. Usually, COS is absent (or assumed at very low levels). • When heated, they easily decompose and participate in Then, during the adsorption process (and regeneration), coking, to an extent that can be very significant if the carryover molecular sieves tend to favor the formation of COS for several is important and frequent. reasons: • Also, when heated, ammonia can form and further react • Water adsorption shifts the thermodynamic equilibrium with water, leading to ammonium (NH4+), which is able to reto the right place the cation in the structure, leading to a weak structure. 120 Caustic chemically attacks the binder and the zeolite strucAt HC dew point, a slight decrease ture itself, which can be turned to power. in pressure leads to liquid 100 Amine and caustic carryover can be minimized by acting Heavy gas MW 22.2 g/mol on the upstream processes. An efficient gas/liquid separator 80 must be installed, and a protective layer of silica gel can help significantly. However, resistant molecular sieve products are 60 L+G for heavy Lean gas MW 17.4 g/mol part of the solution. Gas G only for lean In the late 1990s, amine and caustic resistance was studied. A 40 Liquid L+G special resistant grade was developed, and successfully tested at 20 the Total plant in Lacq, France. The product formulation, that has been continuously improved since then, exhibits a higher 0 inter-crystal stability and shows some coke minimizing ability. 100 150 200 250 300 350 Temperature, K Laboratory tests have shown that such an improved formulation, compared to a conventional product, drastically deFIG. 6. PT diagram of natural gas; retro-condensation. creases the amount of fines: less 45% to less 90%, depending on the chemical tested. H H Na+ Two patents were granted and today, these formulations O O O O O O (-) O O are used in many LNG trains around the world. + 4H+ + AI3+ + Na+ HH Si Si Si Al Si In the case of the industrial facility, the pressure drop level + (Al2O3) (Na2O) O (H3O ) O O O O O O was reduced from 900 mbar after 1 year down to 500 mbar afO O O O O ter 2.5 years (and the new product’s dynamic capacity remains FIG. 7. Dealumination process by acid attack. 89% of the initial one). Hydrocarbon Processing | JANUARY 2013 55

LNG/Gas Processing Developments • Zeolite and binding clay can catalyze the reaction by coadsorbing CO2 and H2S • During regeneration, temperature increases the reaction kinetics (to a limited extent, as the increase of temperature also limits the adsorption of the formed water). Usually COS has to be avoided or minimized as much as possible, the main concern being if it converts back to H2S in the presence of water in some downstream processes, causing important corrosion problems. Other chemicals. The foregoing list is not exhaustive, but is representative of what can typically happen. Others species that can be entrained in the feed (oils, corrosion inhibitors) could be added. These species stay in the bed and build up as coke, or act like an obstructive film that hinders diffusivity. Some species compete during the adsorption step. At least two very common examples deserve to be cited: • Water and methanol. Methanol is often injected to avoid hydrates formation and is well adsorbed on 4A molecular sieves. Presence of methanol increases the MTZ length, and has to be taken into account at the design stage. • Heavy mercaptans and BTX on X-type molecular sieves. Some other compounds already cited can decompose at medium temperature (methanol) and involve a soft regeneration procedure. Others (heavy sulfurs) are not efficiently removed during regeneration and tend to stay in the bed.

56 JANUARY 2013 | HydrocarbonProcessing.com

Anticipating problems. To anticipate any composition-related problem, especially for new projects and revamps: • Be aware, as soon as possible, of the potential composition-related issues • Do not underestimate the impact of the upstream processes (glycols, amines, caustic, etc.) • Address the related concerns by involving, from the earliest stage of the project, experienced molecular sieve manufacturers who not only sell products, but also bring reliable solutions and added value technical advice. Molecular sieves are very efficient and reliable materials. At the end of the day, the vast majority of the operating units worldwide are doing very well. Even though molecular sieves cannot handle everything, almost all the potential problems mentioned here can be solved with the help and follow-up of your experienced vendor. ACKNOWLEDGMENT This paper is based on a presentation that was given at the annual conference of the Gas Processors Association Europe in Berlin, Germany, on May 24, 2012. ALEXANDRE TERRIGEOL holds a master’s degree in chemical engineering and a master’s degree in chemistry and physics. He joined CECA (Arkema Group) in 2001 and spent five years in the process department, mainly on molecular sieves manufacturing processes. In 2006 and 2007, he moved to the industrial business control department, and since late 2007 he is part of CECA molecular sieves commercial department. Today, Alexandre Terrigeol is technical manager and market manager in charge of oil and gas projects, and is also area manager for Africa.

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Special Report

LNG/Gas Processing Developments J. R. SIMS, Becht Engineering Co. Inc., Liberty Corner, New Jersey

Improve evaluation of brittle-fracture resistance for vessels Process vessels such as towers, drums and heat exchangers can be exposed to low temperatures as part of normal operating conditions or due to a process upset. Carbon and low-alloy steels typically used in process vessels undergo a transition from ductile to brittle behavior as temperature is reduced and are at increased risk of brittle fracture at low temperature. To reduce this risk, the American Society of Mechanical Engineers (ASME) Boiler & Pressure Vessel Code contains requirements for vessels and vessel components with respect to low-temperature operation.1 While these rules are applicable to new construction, API 579-1/ASME FFS-1 Fitness-For-Service uses the rules as the basis to evaluate brittle fracture resistance for existing vessels.2 This article discusses an approach and spreadsheet tool that can be used to provide operating pressure limits as a function of vessel-metal temperatures. These limits can be used as part of a process hazard analysis (PHA) to set operating pressure guidelines for process vessels identified with the potential for low-temperature excursions from auto-refrigeration of light, low-temperature boiling point, liquid hydrocarbons.

DESIGNING FOR FRIGID CONDITIONS The design temperature of process vessels constructed before 1987 used the expected operating temperature plus some margin above that temperature as the design temperature. The code permitted the use of carbon steel (CS) and low-alloy steels to –20°F without requiring impact testing, which provides a measure of a steel’s resistance to brittle fracture. For operating temperatures below –20°F, there were additional material requirements, including impact testing. After 1987, the code was revised with new rules—one of which included eliminating the impact testing exemption to –20°F and requiring the concept of minimum design metal temperature (MDMT). In setting the MDMT, the code now requires that “consideration shall include the lowest operating temperature, operational upsets, auto-refrigeration, atmospheric temperature and any other source of cooling.” For equipment constructed before 1987, where operational upsets or auto-refrigeration may not have been considered, the API 579-1/ASME FFS-1 procedures can be used to assess risks for brittle fracture and to set operating pressure and temperature limits. Assessment levels. The API 579-1/ASME FFS-1 methodol-

ogy provides three assessment levels. Each level progressively requires a more in-depth evaluation and more information:

• Level 1 evaluates equipment meeting the toughness requirements of a recognized code or standard. It usually can be accomplished through a review of equipment records. • Level 2 is divided into three methods (A, B and C). Each method considers not only the materials of construction but also material-heat treatment, design stress, post-weld heat treatment (PWHT), hydrotest pressure and temperature, service environment, and past and future operating conditions. • Level 3 is used for equipment not meeting acceptance criteria for Levels 1 and 2. This level typically involves in-depth analysis using fracture mechanics. The objective of the various levels is to determine the acceptability of the equipment for operational conditions at a given pressure and temperature or within an envelope of pressures and temperatures.

AUTO-REFRIGERATION CASE Auto-refrigeration can occur during the rapid depressurization of a vessel containing light liquid hydrocarbons. The temperature will follow the vapor pressure curve, and the temperature may drop below the MDMT for the vessel if autorefrigeration is not included in the design specifications. The presented case history will consider process vessels constructed before 1987 and the MDMT concept was implemented. API 579-1/ASME FFS-1 defines a material’s minimum allowable temperature (MAT) as the permissible lower metal temperature limit for a given material and thickness based on its resistance to brittle fracture. The MAT may be a single temperature at the maximum allowable working pressure (MAWP) or an envelope of operating temperatures as a function of pressure. To establish the MAT, mechanical design and material specifications for the process vessel information are required. Defining MAT. Fluid vapor pressure data and vessel informa-

tion (drawings, calculations, material specifications and data) are usually readily available. Establishing the MAT is more complex in that API 579-1/ASME FFS-1 has different levels of assessment, along with related charts and equations, that guide the user through the process. In the case of a process vessel, there will be a “limiting” component, e.g., shell, head, skirt, nozzle, flange, tray support, tubesheet, welded attachment, etc. This limiting component will set the MAT for the vessel. For example, a vessel shell fabHydrocarbon Processing | JANUARY 2013 59

LNG/Gas Processing Developments ricated from 1-in.-thick CS plate (SA-516 Grade 70 Normalized) has a MAT of –30°F. However, if an internal tray support ring or some other component welded to the shell is fabricated from ¾-in. plate of the same material but not normalized, then MAT is 15°F. In the case of a vessel, there are many compo-

nents of varying thicknesses and, in many cases, different materials. Such variation of components and materials adds more complexity in establishing the MAT for the vessel. Other key factors such as PWHT, hydrotest temperature and pressure, weld-joint efficiency and impact test data are additional considerations influencing the MAT for a vessel. Determining the MAT for a single vessel using API 579-1/ASME FFS-1 procedures is not a large task. However, establishing the MAT vs. operating pressure for hundreds of vessels as part of a multi-plant PHA is a major undertaking. New MAT tools needed. To efficiently determine the MAT

FIG. 1. Example of process vessel and components used to determine the MAT.

FIG. 2. Data organized to establish MAT for low-temperature operations.

60 JANUARY 2013 | HydrocarbonProcessing.com

for a large number of process vessels of varying types, an Excel spreadsheet tool was developed based on API 579-1/ASME FFS-1. Overall vessel input data include design temperature and pressure (or MAWP), hydrostatic test temperature and pressure, design corrosion allowance, previous metal loss and future corrosion allowance. Data on major vessel components (shell, heads and cones) and all components welded to that component (skirt, nozzles, flanges, lugs, etc.) are input in logical information blocks to facilitate identifying components limiting/setting the total vessel MAT. Dedicated input blocks are provided for heat-exchanger components (tubesheets and girth flanges) and flat components (flat heads and blinds). Vessel component data include nominal thickness, materials of construction, heat treatment, impact test temperature (if available) and joint efficiency, as shown in FIGS. 1 and 2. For example, FIG. 2 lists vessel component information that was used in a typical assessment. Historic operating conditions can be entered and are used in some circumstances to establish the MAT based on past operations at low temperatures. The vapor pressure curves for fluids of interest curves for MAT vs. material specifications and thickness as well as allowable reduction in MAT based on hydrostatic proof testing are preprogramed into the spreadsheet.

FIG. 3. Plot of fluid vapor pressure and the vessels MAT as a function of temperatures.

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LNG/Gas Processing Developments The spreadsheet output, shown in FIG. 3, is a plot of fluid vapor pressure and the vessel’s MAT plotted as a function of pressure. The code rules permit lower metal temperatures as the pressure drops due to reduced stress. The cold metal temperatures experienced during auto-refrigeration are considered with the coincident pressure; they do not

• PWHT can lower a vessel’s MAT by 30°F for certain materials of construction, provided the material thickness is less than or equal to 1.5 in. However, the adjusted MAT cannot be below –55°F. For vessels with no PWHT, it may not be practical to do field PWHT because of vessel size or other limitations. However, local PWHT of a limiting component(s) may be practical and could be accomplished, using the code procedures for local PWHT, in conjunction with supplementary rules in WRC Bulletin 452.3 Process vessels such as towers, drums and • If the material of construction of a vessel comheat exchangers can be exposed to low ponent limits and sets the MAT, it may be possible to upgrade the materials. The code aggregates CS and temperatures as a part of normal operation. low-alloy steels into four groups, A through D, based Typical materials of construction such as on their resistance to brittle fracture (toughness). Group D materials have better resistance to brittle CS and low-alloy steels typically used in fracture than Group A materials. The MAT for a maconstruct process vessels can undergo terial within a group is a function of material thickness, with thicker material having higher MATs. For a transition from ductile to brittle behavior example, a 4-in.-thick tubesheet of a Group B mateas temperatures drop thus increasing rial has a MAT of 31°F if welded to a 1-in. or thinner the risk for brittle fracture. shell. Upgrading the tubesheet to a Group D material would reduce the MAT to –30°F. This solution has been applied for heat exchangers as part of retubing. • Reduction in MAT is permitted for vessels and componeed to be considered in conjunction with the design pressure. nents where there is excess wall thickness above that required There is a greater risk of brittle fracture for any point of temat design pressure and temperature. API 579-1/ASME FFS-1 perature and pressure on the MAT curve above the fluid’s vaporprovides a curve for determining the reduction in MAT. The pressure curve. These points do not meet the code criteria. curve is a function of weld joint efficiency, governing thickIf the points on the MAT curve are below the fluid’s vaporness, and past and future corrosion rates. The simple examples pressure curve, then the pressure is within the envelope of acpresented here did not take credit for excess wall thickness, but ceptable operation. This information can be used as input to the spreadsheet will perform this calculation for cases where a PHA to set the operating pressure guidelines in the event of the joint efficiency is less than 1, the future corrosion allowan auto-refrigeration incident or re-pressurization limits after ance plus previous metal loss is less than the original design an incident. corrosion allowance or if a minimum required thickness as calculated by a pressure vessel design program is entered. AUTO-REFRIGERATION INCIDENTS The spreadsheet considers the hydrotest, PWHT, material If the potential exists for the vessel-metal temperature to group, weld joint efficiency and corrosion allowances in arrivdrop below the MAT during an auto-refrigeration incident, ing at the MAT, and it can be used to study the effect on MAT there are several options that can be considered, either alone of changes in these parameters. or in combination: Recent experience in the evaluation of more than 2,000 ves• Limiting the operating pressure until the vessel is warmed sels has shown such a spreadsheet tool to be an efficient way to the MAT. These limits can be used in conjunction with temto establish the MAT. Although the spreadsheet facilitates the perature and pressure alarms. process, the largest time consumer is extracting data from older • Re-hydrotesting the vessel at a lower temperature or higher drawings, vessel specification sheets, mill reports, etc. In addipressure. API 579/ASME FFS-1 provides for a reduction in MAT tion, the spreadsheet can be used to establish minimum tembased on hydrostatic testing. The allowable reduction is a funcperatures for both shop and field hydrotesting in accordance tion of the ratio of design pressure to hydrotest pressure. For exwith code rules. ample, at a ratio of 2⁄3 (test pressure = 150% of design pressure), the reduction in MAT is 35°F. The hydrotest MAT reduction has LITERATURE CITED a number of qualifiers outlined in API 579-1/ASME FFS-1: 1 ASME Boiler and Pressure Vessel Code, Section VIII, Division 1, Rules for 0 It is limited to materials with an allowable design stress Construction of Pressure Vessels, Part UCS, Paragraph UCS-66, 2010 Ed. 2 of less than, or equal to, 25 ksi. API 579-1/ASME FFS-1, 2007 Ed. 3 WRC Bulletin 452, “Recommended Code Practices for Local Heating of Welds in 0 A maximum primary membrane stress during hyPressure Vessels,” June, 2000. drotest no greater than 90% of the material’s specified minimum yield strength. J. ROBERT SIMS is a senior engineering fellow with Becht Engineering Co., Inc. 0 Actual metal temperature as opposed to water temperHe is a recognized authority in risk-based technologies, high-pressure equipment, mechanical integrity evaluation of existing equipment and fitness-for-service ature is used as the relevant temperature parameter. analysis including brittle-fracture analysis. Mr. Sims is past chairman of the ASME 0 The MAT cannot be less than –155°F after the hyCodes and Standards Board of Directors and is currently a member of the ASME drotest adjustment. Note: There is an increased risk of brittle Board of Governors. Mr. Sims has more than 40 years of experience in design, fracture during hydrotesting. analysis, troubleshooting, design audit and mechanical integrity evaluation. 62 JANUARY 2013 | HydrocarbonProcessing.com

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Rotating Equipment H. P. BLOCH, Reliability/Equipment Editor

Update on wet and gas compressor seals Shaft seals keep compressed gas from leaking out. The need for leak prevention may include process economy, safety and environmental protection. Moreover, the process gas will usually have to be kept away from the compressor bearings. In essence, seals are located between the compressed gas and bearings. A number of different sealing arrangements and configurations are found in industry. FIG. 1 is an overview of four principal seal types—wet-floating ring or bushing seals, trapped-wet-bushing seals, liquid-lubricated mechanical contact seals and dry-gas non-contacting face seals.1 Within each of the four principal types, there are numerous variants: • Wet-face seals, in some cases, incorporate a stationary, a rotating and a floating ring. Others incorporate only a rotating ring clamped to the shaft and a spring-loaded nonrotating face with the springs anchored in a housing assembly. • Dry-gas seals are mechanical face-type seals available as single, double and tandem models. However, dry-gas seals should not be confused with the internal labyrinth seals that separate individual stages inside a compressor casing. For over five decades, centrifugal compressors have benefited from face- and bushing-type mechanical seal technology. The early compressors of the 1950s often struggled with cumbersome labyrinth sealing and gas eductor arrangements. In the 1960s, many labyrinth configurations were rapidly displaced by a variety of liquid-lubricated seals that introduced small amounts of seal oil between either the sealing faces or the small gaps between stationary and floating sealing bushings. American Petroleum Industry Standard 617 has for many years outlined different sealing arrangements, and “generic” dry-gas seals are included in the well-established API-617 compressor standard. User preferences do differ, but each seal type has its application range, as shown in TABLE 1.1 In general, dry-gas seals are favored in new installations. For existing installations, wet (liquid) seals merit replacing only if they are troublesome and if good experience references are available for dry-gas seals in the same service. Case against wet seals. In 2010, a consulting engineer summarized his experience. It apparently favored dry-gas seals in a wide range of applications. For wet seals, the engineer reported:2 1. High seal-oil consumption, even when new; typically about 5 gal/day (gpd) per seal, for a total of 10 gpd per average compressor. After one year in service, this will average about 15 gpd–20 gpd. For combined lube-seal systems (not always possible), the leakage losses are reduced. However, at least 2 gpd of seal oil is lost into the compressor itself on an average-

size machine. (Contaminated lube oil may damage compressor bearings, thus leading to vibration and downtime.) 2. Wet-seal systems require more operator attention (labor) because the system’s sour-seal-oil drainage must be physically inspected and measured on combined systems. There are many active components in the seal-oil system. 3. Incremental energy requirements due to parasitic losses on wet seals are typically about 30 hp on an average-size 10,000hp compressors. Adding seal-oil pump energy (approximately 35 hp) will increase the total energy increment to 65 hp. 4. Hydraulic surges are potential hazards on wet-seal systems, some more so than others. This can lead to seal-face damage and reduced component life. Manufacturers rarely mention this risk and seldom size the oil accumulators properly. Even then, bladder-type accumulators become frequent maintenance items—partly due to internal gas leakage and elastomer failures. Diaphragm-type accumulators are preferred. 5. Wet-seal bushing service life is two to four years. However, some wet-bushing seals reach six years with welldesigned late-generation components. 6. Seal bushings do wear as indicated from microscopic abrasive particles and can accumulate at the bushing seal edge

FIG. 1. Compressor seal overview depicting a floating ring or bushing seal (1), trapped bushing seal (2), liquid-lubricated mechanical contact seal (3) and dry-gas face seal (4).1 Hydrocarbon Processing | JANUARY 2013 65

Rotating Equipment and grind the shaft mechanically. Experience points to the advisability of precautionary repairs on every second seal intervention. At that time, the complete rotor must be removed to repair damaged shaft regions, even though the shaft is hardened. 7. With some wet-seal systems, there are four pumps to inspect and maintain on each compressor lube/seal-oil skid; two are seal-oil pumps and two are lube-oil pumps. 8. Gas-leakage losses to flare from the sour-seal-oil traps can be significant. Unless a flare-gas-recovery unit is available or the gas is re-introduced at the compressor suction, gas losses can be 30 times the equivalent dry-gas seal loss. Losses up to 75 scfm/seal have been reported for a 10,000-hp compressor in average condition. 9. With wet seals, considerable instrumentation complications exist due to the numerous control devices needed. The maintenance cost for instruments can be high. 10. Troubleshooting oil seals requires a highly qualified engineering or senior technical staff. Experience shows that seal-oil system design/installation/maintenance problems are not always resolved. Constant vigilance is required. (Gas seals require lesser skills.)2 11. Contamination of the process gas path, such as heat exchangers and catalyst beds downstream of the compressor, is often experienced. This can become a burdensome cost. On a per-compressor basis, the yearly reduction for heat exchanger efficiency on a propane system can easily incur $50,000 to $100,000 due to resulting cooling losses. TABLE 1. Turbo compressor seal selection guidelines— Experience-based recommendations for compressor seal selection

12. Float traps on seal-oil systems can become a maintenance issue. 13. Faulty level controllers are a risk, leading to worrisome gas leaks to atmosphere. 14. For compressors equipped with bushing-type seals, no backup seal is available in case of power outage (loss of seal oil). As a consequence, emergency power is required for safe operation or an immediate shutdown is required. Dry seals have a safe record in this regard due to the availability of secondary sealing.3 15. The plot plan (“footprint”) needed by wet-seal auxiliary systems is usually large. The compressor skid is physically smaller and less expensive for machines equipped with gas-seal systems. How gas seals function. There are many functional similarities between gas seals and their predecessors. These predecessors include many variants of face, bushing and floating ring seals. Yet, there are also features that differ. For instance, the seal face of the rotating mating ring can be divided into a grooved area at the high-pressure side and a dam area at the low-pressure side, as shown in FIG. 2. The shallow grooves are often laser-etched, spark-eroded or chemically milled. A typical depth is about 0.0003 in. = 8 μ, which is achieved through highly precise machining operations. T-shaped, V-shaped (bidirectional) and L-shaped (unidirectional) grooves have been produced. Each configuration has its advantages and disadvantages. A stationary-sliding ring is pressed axially against the mating ring by both spring forces and sealing pressure. The sealing gap is located between the mating ring and the sliding ring. For proper noncontacting operation, these two rings must be separated by a gas film acting against the closing forces in the sealing gap. The gas film is achieved by the pumping action of the grooves and throttling effect of the sealing dam. Groove geometry is critical for trouble-free operation of the seal.

Application

Service

Inlet pressure, kPa (psia)a

Seal type

Air compressor

Atmospheric air

Any

Labyrinth

Minimizing risks with sealing problems. Dry-gas sealing

Gas compressor

Noncorrosive

Any

Labyrinth

69 to 172c (10 to 20)

Labyrinth with injection and/ or ejection using gas being compressed as motive gas

is obviously coming into prominence, and it deserves consideration. However, specification, review, purchasing and installation of a dry-seal support system cannot be left to chance. A thorough review of the owner’s facility and the particular process unit in which the compressor will be installed is vital to minimizing gas-seal failures. In order of importance, these factors should be considered in examining dry-seal-support systems for centrifugal compressors:

Nonhazardous Nonfouling Low value b

Gas compressor

Noncorrosive or corrosive Nonhazardous or hazardous Nonfouling or fouling

Gas compressor

Noncorrosive Nonhazardous or hazardous

ⱖ 25,000 ⱖ (3,600)

Gas seald Tandem preferred

Anyf

Oil seal, double-gas sealf

Gas composition. Understanding the actual gas composition and true operating condition is essential, but this is often overlooked. For example, it is necessary to understand when

Nonfouling Gas compressor

Corrosivee Nonhazardous or hazardous Fouling

Operating seal pressure range b Where some gas loss or air induction is tolerable c Pressure ranges shown for labyrinth seals are conservative. Manufacturers extend this range upward, resulting in a debit due to power losses d Within state of the art e Hydrogen sulﬁde (H2S) is the most common corrosive f Dry-running gas seals often have pressure limitations below those of oil seals

66 JANUARY 2013 | HydrocarbonProcessing.com

FIG. 2. Mating ring vane-like grooves (left), U-grooves (right). Arrows indicate sense of rotation.4

HPIRPC.com

NEW DELHI, INDIA | 9–11 JULY Hydrocarbon Processing’s fourth annual International Refining and Petrochemical Conference (IRPC) will be held 9–11 July 2013 in New Delhi, India. IRPC is a market-leading technical conference, providing an elite forum within which industry professionals from around the world can network and share ideas relating to the refining and the petrochemical industries. As major restructure forces are reshaping the hydrocarbon processing industry (HPI), managers and engineers are actively seeking information and solutions to make their companies more efficient and profitable.

Supported by:

Conference Lanyard Sponsor:

This is your chance to take part in the discussion and reach key decision-makers as they explore how technological and operating advances can benefit their organization and assets. IRPC emphasizes the industry’s latest technologies and best practices from both a local and global perspective. Topics to be explored at IRPC 2013 will include: plant and refinery sustainability, energy policy, profitability, clean fuels, effluence management, gas treatment technologies, rotating equipment, refining and petrochemical integration, bio-based petrochemicals, maintenance and reliability, and much more.

IRPC 2013 Advisory Board Members:

ANDREA AMOROSO Vice President, Process Technology eni - Reﬁning & Marketing Division

A. K. ARORA Director General Petroleum Federation of India

JOHN BARIC Licensing Technology Manager Shell Global Solutions International B.V.

ANINDYA SUNDAR BASU Managing Director Chennai Petroleum Corporation Ltd

ERIC BENAZZI Marketing Director Axens

GIACOMO FOSSATARO General Manager Walter Tosto S.p.A.

DR. MADHUKAR ONKARNATH GARG Director CSIR-Indian Institute of Petroleum

RAJKUMAR GHOSH Director (Reﬁneries) Indian Oil Corporation Limited (Reﬁneries Division)

GIACOMO RISPOLI Executive Vice President, Research & Development and Projects eni - Reﬁning & Marketing Division

STEPHANY ROMANOW Editor Hydrocarbon Processing

DR. AJIT SAPRE Group President Research and Technology Reliance Technology Group

CHAKRAPANY MANOHARAN Director-Reﬁnery Essar Oil Ltd.

MICHAEL STOCKLE C Eng FlChemE Chief Engineer - Reﬁning Technology Foster Wheeler

B. K. NAMDEO Executive Director, International Trade & Supplies Hindustan Petroleum Corporation Limited

K VENKATRAMAN Chief Executive Ofﬁcer & Managing Director Larsen & Toubro

SYAMAL PODDAR President Poddar & Associates

S VENKATRAMAN Director (Business Development) Gail (India) Limited

CARLOS CABRERA Executive Chairman Ivanhoe Energy

DR. CHARLES CAMERON Head of Technology, Downstream; VP, Formulated Products Technology BP plc

A.K. PURWAHA Chairman & Managing Director Engineers India Limited

Highlights from IRPC 2012 in Milan, Italy: • More than 460 HPI professionals attended the event, representing 26 countries and five continents • 40 technical sessions were given over two days featuring speakers from Indian Oil Corporation, Foster Wheeler, Criterion, Chevron Research, KBR, eni, Indian Institute of Petroleum, Ivanhoe Energy, Chevron Lummus Global and CB&I,and Shell Global Solutions • The sold-out exhibit floor showcased the latest technology from 45 companies • Sponsor organizations included eni, Walter Tosto, ABB, Axens, Curtiss-Wright Flow Control Company, GTC Technology and Merichem • Keynote speakers were Giacomo Rispoli, executive vice president of research and development (R&D) and projects for eni Refining & Marketing, and Michael Lane, secretary general of CONCAWE • 110 attendees took part in an exclusive plant tour of eni’s Sannazzaro de’ Burgondi Refinery EST project • Attendees included project engineers, process engineers and HPI management officials

2013 Sponsorship Opportunities** ❏ Gold Sponsorship

USD 40,000

• Limited to one • Seat on advisory board • Underwriter and sole sponsor of the opening day reception • Opportunity to provide welcoming remarks at reception • Reserved table at lunch on both days (10–11 July) • Recognition in all conference marketing materials, including conference advertisements in Hydrocarbon Processing, promotional brochure, e-mails and web site (sponsor logo and link), and onsite program guide • Opportunity to include 1 full page ad in conference program • Two (2) foam core signs including your corporate logo will viewable throughout entire conference • Opportunity to include a corporate giveaway in conference bag* • Ten (10) delegate passes to the conference • Four (4) passes to work exhibitor booth • 15% discount on all additional seats outside of complimentary passes • 3m x 6m booth space in front of exhibitor hall

❏ Silver Sponsorship

USD $30,000

• Limited to two • Lunch sponsor on day one or two • Reserved table at sponsored lunch • Recognition in all conference marketing materials, including conference advertisements in Hydrocarbon Processing promotional brochure, e-mails and web site (sponsor logo and link), and onsite program guide • One (1) Foam core sign including your corporate logo will be placed at the lunch entrance • Opportunity to include a corporate giveaway in conference bag* • Five (5) delegate passes to the event • Four (4) passes to work exhibitor booth • 10% discount on all additional delegates outside of complimentary passes • 3m x 6m booth space in front of exhibitor hall

❏ Closing Reception Sponsorship

USD $23,575

• Recognition as sponsor of closing reception (11 July) • Recognition in all conference marketing materials, including advertisements in Hydrocarbon Processing, promotional brochure, e-mails and web site (sponsor logo and link), and onsite program guide • One (1) Foam core sign including your corporate logo will be placed at reception entrance • Opportunity to include a corporate giveaway in conference bag* • Three (3) delegate passes to the conference • Two (2) passes to work exhibitor booth • 10% discount on all additional seats outside of complimentary passes • 3m x 3m booth space in exhibitor hall

❏ Conference Delegate Bag Sponsor

USD $17,825

• Sponsorship of a conference refreshment breaks, one each day of the conference • Coffee mugs or tumblers with company logo given to each attendee to keep provided by Gulf Publishing Company • Recognition in all conference marketing materials, including advertisements in Hydrocarbon Processing, promotional brochure, e-mails and web site (sponsor logo and link), and onsite program guide • Foam core sign including your corporate logo will be placed at break entrance on both days • Two (2) delegate passes to conference • Two (2) pass to work exhibitor booth • 10% discount on all additional seats outside of complimentary passes • 3m x 3m booth space in exhibitor hall

❏ Afternoon Refreshment Break Sponsor

USD $16,675

❏ Program Print Sponsorship

USD $13,225

• Folio for each delegate seat with company and conference logo embossed and provided by Gulf Publishing Company • Recognition as the technical conference sponsor in conference onsite program and logo and link on conference website • Company information included in on-site program guide • One (1) foam core sign including your corporate logo will be placed near the registration table next to the programs • Two (2) delegate passes to the conference • Two (2) pass to work exhibitor booth • 10% discount on all additional seats outside of complimentary passes • 3m x 3m booth space in exhibitor hall • Underwriting sponsor of the conference program • Recognition as the program print sponsor in conference program • One (1) foam core sign including your corporate logo will be placed near the registration table • Company information included in on-site program • Opportunity to include a corporate giveaway in conference bag* • Two (2) delegate passes to the conference • Two (2) pass to work the exhibitor booth • USD $100 discount on all additional seats outside of complimentary passes • 3m x 3m booth space in the exhibitor hall

❏ Continental Breakfast Sponsor

USD $10,925/ day

• Sponsorship of a conference continental breakfast • Napkins with your company logo used at the breakfast • Name on signage and pre-event on-line marketing (website and emails) • One (1) foam core sign including your corporate logo will be placed at breakfast entrance • Company information included in on-site program guide • One (1) delegate pass to conference • USD $100 discount on all additional seats outside of complimentary pass

❏ Speaker Gift Sponsor

USD $8,625

• Recognized as underwriting sponsor of gifts given to speakers • Logo on gift or company brochure included with gift • Company information included in on-site program guide • One (1) delegate pass to conference • USD $100 discount on all additional seats outside of complimentary pass

❏ Conference Lanyard Sponsor

Axens

USD 18,665

• Underwriting sponsor of the conference bag to be given to each attendee at registration • Company logo alongside conference logo printed on the conference bag • One (1) foam core sign including your corporate logo will be placed near registration table with the bags • Recognition in online marketing (website / emails) • Company information included in on-site program guide • Opportunity to include a corporate giveaway in conference bag • Two (2) delegate passes to event • Two (2) pass to work exhibitor booth • 10% discount on all additional seats outside of complimentary passes • 3m x 3m booth space in exhibitor hall

❏ Morning Coffee Break Sponsor

❏ Technical Program Sponsorship

USD $17,825

• Sponsorship of a conference refreshment breaks, one each day of the conference • Beverage bottles with your company logo given to each attendee to keep provided by Gulf Publishing Company • Recognition in all conference marketing materials, including advertisements in Hydrocarbon Processing, promotional brochure, e-mails and web site (sponsor logo and link), and onsite program guide • Foam core sign including your corporate logo will be placed at break entrance on both days • Two (2) delegate passes to conference • Two (2) pass to work exhibitor booth • 10% discount on all additional seats outside of complimentary passes • 3m x 3m booth space in exhibitor hall

*Conference bag pursuant to sponsor conﬁrmation; **For pricing in rupees, please contact your Hydrocarbon Processing sales representative; ***Other sponsorships are available. Consult with your salesperson for additional marketing opportunities.

Excellent and easy environment for meeting customers and promoting new opportunities –Area Manager - Business Development, Italy

IRPC was a good oportunity to know people and new technical aspects and advanced chemical and petrochemical technologies. –Chemical Engineer, Brazil

Quite useful both technologically speaking and networking –Director, Brazil

I had a very good personal experience. I had a good interaction with subject matter experts and the exhibitors to get a solution to several practical problems being faced by the industry. –Reﬁnery Specialist, Saudi Arabia

It was really a nice experience, particularly from an information-sharing point of view and global cooperation. Further, the visit to the Sannazzaro Reﬁnery was really excellent. –Deputy General Manager, India

I love it! The event made it possible to share new information in a perfect format without overloading your brain. –Project Manager, Russia

IRPC 2013 Exhibitor Rates:

500

501

502

503

504

505

506

507

508

509

510

• One (1) delegate pass to conference • Two (2) pass to work exhibitor booth

❏ 3m x 6m USD $8,100 + Shell Scheme USD $10,620 • One (1) delegate pass to conference • Three (3) pass to work exhibitor booth

❏ 6m x 6m USD $16,200 + Shell Scheme USD $21,240

215

305

311

104

206

214

304

310

407

103

205

213

303

309

406

102

204

212

302

308

405

101

203

211 301

307

100 Gulftronics

• Two (2) delegate pass to conference • Four (4) pass to work exhibitor booth

202

210

201

209

200

208 Filtrex

404 203

300 Reserved India Oil Corp.

402 306

3 meters

Europe Bret Ronk, Publisher E-mail: Bret.Ronk@GulfPub.com Houston Office 2 Greenway Plaza, Suite 1020 Houston, Texas 77046 USA Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433

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 Bret Ronk Phone: +1 (713) 529-4301, Fax: +1 (713) 520-4433 E-mail: Bret.Ronk@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

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

Other Areas AUSTRALIA—PERTH Brian Arnold Phone: +61 (8) 9332-9839 Fax: +61 (8) 9313-6442 E-mail: Australia@GulfPub.com

408

207

105

❏ 3m x 3m USD $4050 + Shell Scheme USD $5,310

3 meters

6 meters

• Company information included in on-site program guide • USD $100 discount on all additional seats outside of complimentary passes • Shell scheme includes: stand walls, fascia with company name, carpet, table (1 for 3mx3m / 2 for 3mx6m / 3 for 6mx6m), chairs (3 for 3mx3m / 5 for 3mx6m / 6 for 6mx6m), spotlights(3 for 3mx3m / 4 for 3mx6m / 6 for 6mx6m), wastebasket (1 for 3mx3m / 1 for 3mx6m / 2 for 6mx6m) / use of electrical outlet

3 meters

❏ Exhibitor Rates ($450/sq m plus $140/sq m for Shell scheme)

401 400

CHINA—HONG KONG Iris Yuen Phone: +86 13802701367, (China) Phone: +852 69185500, (Hong Kong) E-mail: Iris.Yuen@GulfPub.com INDIA Manav Kanwar Phone: +91-22-2837 7070/71/72 Fax: +91-22-2822 2803 Mobile: +91-98673 67374 E-mail: India@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 JAPAN—TOKYO Yoshinori Ikeda Pacific Business Inc. Phone: +81 (3) 3661-6138 Fax: +81 (3) 3661-6139 E-mail: Japan@GulfPub.com KOREA D. S. Chai Dongmyung Communications, Inc. Phone: +82 (2) 391 4254 Fax: +82 (2) 391 4255 E-mail: Korea@GulfPub.com

Plan to Attend IRPC 2013 NEW DELHI, INDIA | 9–11 JULY

Online: HPIRPC.com General inquiries: Events@GulfPub.com or +1 (713) 520-4402 Exhibit or sponsor: Contact your local HP sales representative.

Rotating Equipment and where phase changes start. Condensed liquids must not be allowed in the sealing gas. Commissioning procedures and control-system design must be thoroughly understood: 1. Is clean and dry buffer gas available at all anticipated compressor speeds? 2. Is the seal protected from bearing oil? 3. How is the compressor pressurized or de-pressurized? 4. How is the machine brought up to operating speed and how will the seal react? 5. Are all operating and maintenance personnel fully familiar with the compressor maintenance and operating manual? 6. Is the full-control system included and adequately described in these write-ups? 7. Are key elements of the system design understood and do they include buffer-gas conditioning, heating, filtration, regulation (flow vs. pressure) and monitoring? Before opting for dry-gas seals in retrofit situations, ask if the apparently flawed liquid seals really represent the best that the vendor can offer. In some cases, these checks lead to the purchase of late-generation liquid-film-face seals instead of gas seals. The areas of safety and reliability must always be given special consideration. Seal safety and reliability. Positive sealing of the compressor during emergencies must always be assessed. In the event that the gas pressure in the compressor casing exceeds that of the seal oil, then shutdown pistons in advanced-face-seal assemblies exert a force proportional to the gas pressure to keep the seal faces closed and to prevent a gas release. Dry-gas seals may or may not provide positive gas sealing if the seal faces are damaged or distorted. The backup seal may show reasonable performance under low pressure but may fail to perform under higher pressure if the primary seal fails. The alarm and shutdown devices of the seal-oil system must have a reasonable range and sensitivity and, likewise, provide reliable alarm and shutdown characteristics. Dry-gas-seal systems often rely on pressure switches for the very low range and high sensitivity. The pressure switches may have a tendency to malfunction or give a false sense of security. Ensure the system will provide a sufficiently high degree of alarm and shutdown performance. Some seal configurations excel at online monitoring. The favored seal must allow easy verification of sound working condition. Beware of seal systems that are hampered by smalldiameter orifices; these orifices are prone to plugging. Avoid sensitive pressure switches that often become inoperable. Drygas-seal failures are not as easy to detect as wet-seal failures. In addition, the user must go through a rigorous cost-justification analysis. In many cases, gas seals are a good choice only if you do not have to purchase the oil-seal console. If this console already exists, it is often difficult to justify gas seals. With hydrocarbon gas prices escalating, it might be prudent to consider gas leakage rates to justify a conversion to gas-lubricated seals. Also, consider advancements in traditional oil-sealing technology for centrifugal compressors. Many world-scale manufacturers are now marketing improved versions of the oil seals that were originally furnished with their compressors. Along these lines, one researcher suggests to study the failure statistics of your oil-type seals. Consider that current esti-

mates of failure rates of gas seals are about 0.175 failures/yr. In other words, we could expect a problem every six years. At least one dry-gas seal manufacturer bases recommended maintenance intervals around gas seals on limits set by the elastomer aging process. This manufacturer suggests this maintenance routine after 60 months of operation: • Replacing all elastomers • Replacing the springs • Replacing all seal faces and seats • Carrying out a static and dynamic test run on a test rig. Making good choices. The final advice to the reader is to make informed choices. Consider gas seals only in conjunction with a clean gas supply. Look for seals that will survive a reasonable amount of compressor surging. Consider dry-gas seals that incorporate features ensuring start-up and acceleration to operating speed without allowing the two faces to make contact. If these seals are not available from your supplier, look beyond the usual sources. Some innovative manufacturers are offering modern dry-gas seals for the original equipment manufacturer, as well as aftermarket applications. At least one manufacturer of advanced sealing devices has the capability to repair and test dry-gas seals made by others.4-5 Investigate the extent to which they can meet all of your reliability requirements, then consider using their dry-gas seals. What we have learned. Sealing technology merits a close re-

view. Insist on references and check with other users on their experiences. Let all comparisons be fair and unbiased. Understand how seals function. Discount anecdotal references and mere sales talk. When using oil seals, ask where the excess oil will end up. Understand oil-consumption requirements. Understand cost! Understand if startup conditions may allow entrained vapors to condense and, thus, ruin the seal. When using dry-gas seals, thoroughly understand gas-purity requirements. Only pure gas can be used. Factor in the cost of servicing auxiliary support equipment. Understand where the motive gas will go and what its operating costs are. Regardless of seal type and style selected, the design of sealsupport systems should be under the compressor vendor’s jurisdiction and the compressor manufacturer’s warranty. Resist the temptation to involve and deal separately with different suppliers. However, seals and seal systems must be serviceable by your own workforces. It would not be prudent to depend entirely on the support of manufacturers and outside vendors. ACKNOWLEDGMENT Article is excerpted from the book, by Bloch, H. P. and F. K. Geitner, Compressors: How to achieve high reliability and availability, McGraw-Hill, New York, New York, 2012. LITERATURE CITED Borsig GmbH, Berlin, Germany, Sales literature, 1987. 2 Mid-East Turbomachinery Consulting Ltd., Dahran, KSA; Personal reviews and professional communications with the co-authors. 3 Bloch, H. P. and F. K. Geitner, An Introduction to Machinery Reliability Assessment, 2nd Ed., Gulf Publishing Company, Houston, pp. 242–247, 1994. 4 Bloch, H. P., “Consider dry-gas seals for centrifugal compressors,” Hydrocarbon Processing, January 2005. 5 Carmody, C., “Dry-gas seal repair and testing,” CompressorTech2, December 2009 1

Hydrocarbon Processing | JANUARY 2013 67

Fluid Flow J. WHITE and D. SMITH, Smith & Burgess LLC, Houston, Texas; and B. FRENK, Frenk Water Technologies LLC, Byron, Illinois

Evaluate pressure relief system forces in existing installations Pressure relief devices control the amount and disposition of material during a process upset while simultaneously protecting process equipment from damage due to overpressure caused by the upset. The devices most commonly used for these purposes are pressure relief valves (PRVs) and pressure safety valves (PSVs). Quite a bit of engineering research, testing and analysis has been performed to improve assessment of relief valve suitability and the ability of associated installations to protect equipment from overpressure. One area that has less prescriptive requirements is analysis of the structural integrity of the relief device installation during the emergency event. These installations are not designed for continuous flow, but rather sporadic flow, often at choked or sonic conditions. This article takes a brief look at the existing evaluation of reaction forces for PRVs. It also performs a detailed baseline analysis of typical installations to develop a screening tool for evaluating an existing facility, and identifies the results when tested against an existing petrochemical facility. The purpose of this study is to limit the number of relief valves that require rigorous engineering calculations to determine the adequacy of the installation. Often, it is assumed that PRV installations are simple and easy to design. However, practical experience has shown that PRVs, particularly devices that discharge to the atmosphere, are the most easily manipulated during the actual construction phase and often are not installed as they were intended. See FIG. 1 for two examples of installations that were likely not installed as designed. Clearly, not all existing relief valve installations meet the specifications recommended by industry practice.

requirements for pressure relief device installations. API 520, Part 2, states that PRV outlet piping should be independently supported and properly aligned. Stresses due to forced directional alignment of PRV piping are also mentioned; however, that topic will not be discussed in this article. The authorsâ&#x20AC;&#x2122; col-

FIG. 1. Examples of PRV installations where little or no engineering piping design was performed or design was not followed.

F A Vent pipe

Reaction force analysis methodology. During an over-

pressure event, the discharge of a PRV imposes a load, referred to as a reaction force, on the collective installation. This force creates a bending moment that is both a function of the quantity and state of the release and the physical layout of the piping installation (i.e., the lever arm created by the installation). The stress caused by the reaction force is propagated into and through the PRV and then into the inlet piping and vessel nozzle, unless the system is properly supported. API reaction force analysis. The American Petroleum Institute (API) provides guidance for determining pressure relief

Relief valve

Support to resist weight and reaction forces

FIG. 2. Recreation of figure from API 520 for a typical relief valve installation. Note: The support should be as close as possible to the centerline of the vent pipe. F = the reaction force, and A = the crosssectional area of discharge pipe. Hydrocarbon Processingâ&#x20AC;&#x201A;|â&#x20AC;&#x201A;JANUARY 2013 69

Fluid Flow lective practical experience has demonstrated that a significant portion of atmospheric relief devices do not have piping supports in place, as described in FIG. 2. API 520, Part 2, provides a basis calculation for the reaction forces in the event of vapor or two-phase releases directly to the atmosphere. There is no discussion in this section of the reaction forces developed during a liquid release. Furthermore, no guidance is presented with respect to applying these results or determining if an installation is acceptable; instead, the burden is placed on the designer to ensure that the installation is appropriate. While this may be reasonable for the design of new facilities, evaluating the adequacy of existing facilities becomes much more complicated. The formulas from API 520, Part 2, are listed below for relief devices discharging to the atmosphere: API 520, Part 2, 4.4.1.1: Customary units for vapor relief reaction forces: kT W F= + AP (1) 366 (k +1)M API 520, Part 2, 4.4.1.2: US customary units for two-phase relief reaction forces: ⎡ x (1− x) ⎤ W2 ⎢ + ⎥ + A(P − P ) F= (2) e a ⎥ 2.898E106 A ⎢⎢ ρ g ρ l ⎥⎦ ⎣ where: F = Reaction force at the point of discharge to the atmosphere, pound force (lbf) k = Ratio of specific heats (CP/CV ) at the outlet conditions W = Flow of any gas or vapor, pound mass (lbm)/hr CP = Specific heat at constant pressure CV = Specific heat at constant volume T = Temperature at the outlet, °R

FIG. 3. Even the smallest modification in piping design can have a significant effect on the resulting reaction forces.

70 JANUARY 2013 | HydrocarbonProcessing.com

M = Molecular weight of the process fluid A = Area of the outlet at the point of discharge, in.2 P = Static pressure within the outlet at the point of discharge, psig x = Weight fraction vapor at exit conditions ρg = Vapor density at exit conditions, lbm/ft3 ρl = Liquid density at exit conditions, lbm/ft3 Pe = Absolute pressure at pipe exit, psia Pa = Absolute ambient pressure, psig. DIERS reaction force analysis. The Design Institute for Emergency Relief Systems (DIERS) provides similar guidance for the consideration of reaction forces and the determination of the acceptability of a relief device installation. Additional recommendations are provided for a suggested piping layout to avoid excessive lever arms, as recreated in FIG. 3. In this illustration, the system on the left has significantly more stress due to the increased lever arm and direction of discharge when compared to the system on the right. Additionally, emphasis is placed on the importance of evaluating the reaction forces for all credible overpressure contingencies, not simply the controlling contingency. This is important because the physical properties are not always the same, and, in some cases, the controlling contingency for sizing may be a vapor stream, while the controlling case for the reaction forces may be a two-phase stream. Reaction force case study analysis. A piping system may respond far differently to a dynamic load than to a static load of the same magnitude. Static loads are those applied slowly enough so that the piping system has time to react and internally distribute the loads, thereby remaining in equilibrium. With dynamic loads—those that change quickly—the piping system may not have time to internally distribute the loads, so forces and movements are not always resolved, resulting in unbalanced and potentially concentrated loads and pipe movement. The typical action of relief valve venting is an impulse load, where the flowrate and associated forces ramp up from nominally zero to some value, remain relatively constant for the duration of the release, and then ramp down to zero again. When the relief valve opens, the discharge fluid creates a jet force that acts on the piping system. This force increases from zero to its full value over a time frame similar to the opening time of the valve. The relief valve remains open until sufficient fluid is vented to relieve the overpressure situation. When the valve closes, the reduction in flow corresponds to the loss of the jet force over the closing time of the valve. Multiple relief valve piping configurations were examined for both static and dynamic conditions, using analysis software. The stresses calculated during the analysis were checked against the allowable stresses per American Society of Mechanical Engineers (ASME) standards. Additionally, the analysis was used to determine if a flange leak was likely. In all cases, the dynamic condition was determined to be the governing condition for the structural integrity of the piping system. The leakage check examined the tendency of the flanges to separate under the applied piping loads. ASME B31.3 does not directly address flange leakage. The purpose of this analysis was to determine piping failure and not flange leaks.

Fluid Flow From extensive tests, “It has been determined that, even under unusually severe bending stresses, flange assemblies did not fail in the flange proper, by fracture of the bolts or by leakage across the joint face. Structural failure occurred almost invariably in the pipe adjacent to the flange, and, in rare instances, across an unusually weak attachment weld. Leakage well in advance of failure was observed only in the case of threaded flanges.”1 These findings, which suggest that the structural integrity of the piping is the major area of concern for any stress analysis and should be considered over flange leakage, serve as the basis for these evaluations. Many different process connections have been observed in field installations: Welding-reducing tees, weld/thread o-lets, and unreinforced “stub-in” connections. Unreinforced stub-in connections result in the highest ratio of calculated to codeallowed stresses, followed by o-lets and then welding-reducing tees for the same relief system-applied piping loads. The model used in the current evaluations has been confined to weldingreducing tees. The allowable code stresses are below the yield and well below the tensile, as indicated in TABLE 1, for commonly used carbon steel materials. The net result is that there is a 19% to 24% safety factor between the code allowable for occasional loading and the yield point where the material begins to fail. The relief valve models were evaluated to establish relief pressures at which the calculated stresses were within 5% of each of the allowable occasional, yield and tensile stresses. Modeling details. The relief valves were modeled as an “open discharge,” with a vertical pipe discharging directly to the atmosphere. As shown in FIG. 4, the process connection is mounted on a pipe header with a welding-reducing tee. This arrangement was chosen to provide a more realistic representation of “typical” installations together with the inherent flexibility of the tee/header connection. The vent pipe is the same diameter as the outlet connection on the valve and is unsupported at the elbow, with a 6-foot-long vertical vent pipe. Another software program was used to determine the physical properties along the vent pipe required to calculate the thrust and momentum forces (FIG. 5): • Average velocity along the vent pipe • Average temperature across the outlet of the vent pipe • Average velocity at the elbow. The relief valve was modeled as an orifice at the end of a converging nozzle. The orifice was set to produce the capacity calculated by a relief valve analysis for the given inlet conditions using the certified orifice size. The following assumptions were made regarding the analysis:

• The process fluid was vapor • The manufacturer’s certified orifice diameters (from the National Board of Boiler and Pressure Vessel Inspectors’ Relief Device Certification NB-18) were used in place of standard API orifice diameters to provide more realistic discharge flow • Valve opening and closing time was 8.0 milliseconds, and venting would last for one second; these numbers are specific to the valve manufacturer, and they appear to be typical throughout the relief valve industry • Wind loadings were not considered • All piping was considered to be schedule 40 carbon steel • Relief valve inlet flanges were specified as required for process considerations • Relief valve outlet flanges were specified to American National Standards Institute (ANSI) RF 150. Screening study and results. The objective of developing

the screening tool was to provide a fairly quick method to identify relief valves that were likely to need either support or more detailed analysis to verify the adequacy of the existing installation. For the purpose of simplification, several assumptions were made, as described below: • All relief valves discharging to a closed disposal system are adequately supported for an individual release

FIG. 4. Sample of the model basis.

TABLE 1. Sample of allowable stresses used in screening study

Material

Allowable stress: B31.3 Table A-1, psi

Allowable Yield stress: Tensile stress: B31.3 stress: Occasional Table A-1, B31.3 Table load, psi psi A-1, psi

A 234 (tee)

23,300

30,990

40,000

70,000

API 5L B (pipe)

20,000

26,600

35,000

60,000

A105 (ﬂange)

21,900

29,130

36,000

70,000

FIG. 5. Sample of the velocity profile output. Hydrocarbon Processing | JANUARY 2013 71

Fluid Flow obvious decision is to flag any installation that falls out of the normal range 0 For the purposes of this study, the standard was defined by the flanged relief valve sizes listed in API 526 and shown in FIG. 6. PRV installations can be characterized as either typical or complex. Since the generic screening methodology was performed using a typical PRV configuOften, it is assumed that PRV installations ration (as seen in FIG. 4), some method of identifying are simple and easy to design. However, configurations with more complex piping had to be identified. For the purposes of this study, any piping practical experience has shown configuration containing more than “change of directhat PRVs often are not installed tion” fitting (elbow, 45° bend, branch tee, etc.) was considered to be complex. FIG. 3 was used as the basis as they were intended. for this assumption. PRVs installed and sized for only the external fire contingency will not require a reaction force evaluation. While this may seem counterintuitive, as external fire is the 0 Due to the complexity of a supported common disposal prevailing overpressure contingency in pressure relief system desystem, these systems are excluded from the scope of this study sign, it is proposed that a PRV installation cannot be deemed ad• All liquid and two-phase relief contingencies require deequate by a reaction force analysis in the event of an external fire. tailed analysis The heating effect on the relief device from a fire is un0 Water hammer is a much bigger concern for liquid and known, and it can be more significant for the relief device two-phase releases than for reaction forces, and is therefore an installation (particularly the outlet piping and the valve body item to be evaluated outside of reaction forces itself) than the stresses caused by the flowrate. It is proposed 0 Additionally, the dynamic effects of flashing flow crethat the failure of a relief valve installation due to reaction forcate far too many variables to include in a simplistic screening es is more likely to be controlled by the reduction in tensile • All nonstandard PRV sizes require detailed analysis strength of the installation due to the heat input, than to be 0 While this statement may not be true for every instalcontrolled by the system design. lation, for the purposes of developing an automated tool to PRVs installed and sized for only the liquid hydraulic expanidentify relief valves that may need detailed engineering, the sion contingency will not require a reaction force evaluation. Liquid hydraulic expansion cases are often nominal rates for TABLE 2. Stepwise results of decision tree of qualitative results to which a small thermal PRV is installed. In many cases, the PRV determine relief devices that require detailed engineering analysis possesses a capacity far greater than the required relief load. Relief valves Relief valves Additionally, the non-steady-state nature of a thermal expanRelief valves requiring not requiring sion event tends to result in the unsustained releases that do Qualitative step remaining analysis analysis not develop typical fluid flow characteristics. Taking these facStarting point 189 0 0 tors into account, it was determined that hydraulic expansion External ﬁre only 186 0 3 scenarios do not require pipe stress screening. Qualitative screening. The screening study was divided Thermal expansion only 168 0 21 into two phases, one being qualitative screening against asDischarge to closed 157 0 32 sumptions, as set forth above, and the other being against the system criteria set forth in the base-case study for each relief valve Nonstandard device sizes 152 5 32 size. The qualitative step was performed stepwise, as a discusLiquid or two-phase relief 112 45 32 sion tree, as represented in TABLE 2. The qualitative screening step identified 32 installations Inlet diameter (in.) × outlet diameter (in.) that are acceptable “as is,” 45 that require more detailed analy1×2 1.5 × 2 1.5 × 2.5 1.5 × 3 2 × 3 2.5 × 4 3 × 4 4 × 6 6 × 8 6 × 10 8 × 10 sis (including the potential review of why two-phase/liquid D t t t E t t t releases are being sent to the atmosphere), and 112 installaF t t t tions that are not covered by this screening. G t t t H The second stage of the screening was developed based on t t J t t t “generic” pressure relief device installations. The intention was K t to draw a line separating PRV installations into three categories: L t t M t • Installations predicted to be acceptable as installed N t • Installations that will require detailed engineering analyP t Q t sis to determine the adequacy of the installation R t t • Installations that are expected to require proper piping T t support if a detailed engineering analysis is performed; the reFIG. 6. Relief valve size configurations evaluated as per API 526. sults of this screening are shown in TABLE 3. API oriﬁce letter

0 Relief valve installations that discharge to a closed system are, by definition, supported by at least the point of discharge, and the purpose of this screening is to identify relief valves that require support—not to evaluate the adequacy of existing supports

72 JANUARY 2013 | HydrocarbonProcessing.com

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Fluid Flow TABLE 3. Quantitative screening results for PRV installations based on complexity of installation Number of installations

Installations requiring detailed analysis

Installations requiring support

Typical

145

Complex

Total

189

Installation type

TABLE 4. Overall results based on reaction force screening Action item

Quantity

Relief devices requiring support

Relief devices requiring engineering analysis

Installations predicted to be adequate with respect to reaction forces

127

Total

189

This screening was performed against all 189 relief device installations rather than the remaining 112 from the qualitative screening, due to the fact that three possible results exist rather than the two previously used. A relief valve installation that was flagged as needing a detailed analysis in the qualitative step may be identified as a device that is predicted to require support irrespective of a detailed analysis. Additionally, a relief device sized only for fire may be identified as an installation requiring support, even before the effects of temperature change can be examined. To perform this screening, the existing PRV installations were divided into typical and complex groups, as described previously. For typical installations, a threshold value of 90% was used when comparing the installation to screening toolgenerated stresses for each relief valve size. This means that relief valves having a relief pressure within 90% of the threshold for occasional loading were flagged as requiring detailed engineering analysis. Similarly, relief pressures exceeding 90% of the threshold for yield stress were flagged as likely requiring support, regardless of the detailed analysis. For complex PRV installations, the threshold value was lowered to 70% of the occasional loading and yield stress limits, respectively. The results of the quantitative screening, shown in TABLE 3, indicate that most of the valves predicted to require support (28 of the 37 identified) fall into the category of those predicted to exceed the yield stress. Therefore, these valves were identified as installations that do not require detailed analysis to determine if support is required. Overall results. The results of both screening studies were combined to create an actionable list of items for ensuring the physical integrity of the PRV installations, as shown in TABLE 4. For the facility studied, the aggregate of the two screenings predicted that 28 pressure relief installations would require support (even if a detailed engineering study was performed), and an additional 34 PRV installations would require a more detailed engineering study to determine the adequacy of the installations. Overall, more than 30% of the relief valves studied were found to require action. 74 JANUARY 2013â&#x20AC;&#x201A;|â&#x20AC;&#x201A;HydrocarbonProcessing.com

A sample was taken from each of the three categories, and detailed analyses were performed to verify these results. Of those samples, all relief device installations predicted to require support did indeed require support to avoid exceeding the yield stress. Likewise, all sampled installations predicted to be adequate were found to be adequate. Of the sampled devices predicted to require detailed engineering analysis, all but one exceeded the yield stress, and that installation did exceed the allowable stress. The purpose of this study was to provide a solid screening tool to prevent the cost of performing a detailed engineering evaluation on every relief device installation, and the end result met this objective. In some cases, it may be more cost-effective to simply support PRV installations for which a detailed study is suggested, rather than to perform the detailed study. Recommendations. Overpressure protection analysis has evolved significantly since the inception of the process safety management (PSM) standard, but the mechanical stress applied to the piping during overpressure events appears to have been, for the most part, overlooked. Criteria for identifying pressure relief device installations that may exceed allowable stress levels were developed from these systems. These criteria were then evaluated against a petrochemical facilityâ&#x20AC;&#x2122;s pressure relief systems and benchmarked for validity as a first-pass tool to identify installations potentially requiring physical supports. For the facility studied, approximately two-thirds of the PRV installations were predicted to be adequate with respect to reaction forces, with the remaining installations being broken into two categories: those requiring support and those requiring further analysis. This proves that, in practice, a significant percentage of PRV installations do not meet the desired structural integrity with regard to reaction forces. This study demonstrates a screening tool that allows plants to focus resources on the relief valve installations most likely to fail due to reaction forces. 1

LITERATURE CITED Peng, L.-C. and T.-L. Peng, Pipe Stress Engineering, ASME, New York, 2009. JASON WHITE, PE, is a senior process engineer with Smith & Burgess LLC, a process safety consulting firm based in Houston, Texas. Mr. White has seven years of experience in PSM compliance, specializing in relief systems design and analysis for the refining, natural gas and petrochemical industries. He received BS and MS degrees in chemical engineering from the University of Missouri, and is a licensed professional engineer in the state of Texas.

DUSTIN SMITH, PE, is the co-founder and principal consultant of Smith & Burgess LLC, a process safety consulting firm based in Houston, Texas. As a consultant, Mr. Smith has extensive experience with helping refineries and petrochemical facilities maintain compliance with the PSM standard. He has more than a decade of experience in relief systems design and PSM compliance. His experience includes both domestic and international projects. Mr. Smith is a chemical engineering graduate of Texas A&M University and a licensed professional engineer in Texas. BILL FRENK is a mechanical engineer and the owner of Frenk Water Technologies LLC, a mechanical engineering consulting firm based in Byron, Illinois. He is also a consultant for Smith & Burgess LLC. Mr. Frenk has extensive experience utilizing Caesar II software in both onshore and offshore applications. He received a BS degree in mechanical engineering from Southern Illinois University.

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Heat Transfer Developments R. O. PELHAM, Merrick & Co., Aurora, Colorado

Improve your plantwide steam network It is a formidable task to optimize a plantwide hydrocarbon processing industry (HPI) steam network. Such systems are complex, and they provide services to multiple processing units. Too often, the system network is revamped in pieces to meet the needs for new processing units without considerations for the whole steam system. When optimizing an existing steam network, design and process engineers need a complete understanding of all aspects of the existing system. Accurate energy and material balances must be established to define the HPI complex’s baseline. Likewise, a current definition of the specific steam-system behavior, in response to shifts in supply and demand, is critical information.

UNDERSTANDING THE TOTAL STEAM SYSTEM Unlike process units, there is no process flow diagram (PFD) for plant-wide steam systems. Likewise, there is neither a total material balance nor a control schematic. Too often, a PFD of the steam system must be constructed in a step-by-step process, and it involves interviewing all of the HPI site’s processing unit employees. Organizationally, the steam system is viewed only in pieces. The biggest single consistent difficulty in optimizing steam systems is that no individual within the HPI complex commands complete full knowledge and understanding of the total steam systems. Too often: • Rarely is there anyone who knows the total steam system from the standpoint of configuration, “normal” steam/water flows and the steam control system • Utilities operators understand only the boiler house (and cogeneration unit, if installed) • Process area operators know the steam system as it impacts their process area only. • Process water (cooling/makeup water and condensate handling) is managed by another group within the utilities area • Rarely does a single group know the location for all of the steam-system control valves and how the system is configured. • Infrequently does a single group know where all of the letdown stations are located. DEFINING THE STEAM SYSTEM ‘BASE CASE’ In 90% of the world’s HPI complexes, the present steam system has evolved over the history of the site. This steam system evolution is influenced by installing new process units, scrapping older equipment, replacing steam-system assets, changes in ownership, economics, etc. The end result is: • System drawings and equipment lists become fragmented

• Firm knowledge of in-service and out-of-service equipment is uncertain • Flowmetering is limited and insufficient to provide good mass balances • Steam-system control valves are scattered across the refinery and are under the control of local process area operators. • Steam flowrate (and actual direction of steam flow) in some lines can become a point of conjecture. Developing the total knowledge for the steam system becomes an investigative problem. For the young utilities engineer, this can prove to be an overwhelming task. To define and understand the complete refinery steam system, TABLE 1 summarizes several beneficial steps. The ease of pulling this information together depends on the quality of prior efforts, and the elapsed years since the subject was last seriously tackled. TABLE 1. Required information to fully define an HPI plantwide steam network. Define all the refinery steam headers by pressure level. Add makeup water system and condensate recovery headers to steam headers Visually trace all steam/network lines. Know the physical locations Develop lists of all steam producers at each pressure level and header, and include: • Steam from a fired boiler • Steam imported across the refinery boundary • Steam from a process “waste-heat” steam generator • Steam exhausting from a back-pressure turbine • Steam let down from a higher pressure through a letdown valve Establish presence of letdown stations by interviewing each process area. Most refineries and petrochemical complexes have more letdown stations than are actually listed or generally known. Carefully clarify the pressure that the controller at the letdown station is sensing and controlling Develop lists of steam users at each pressure level and categorized as: • Driver steam—steam turbines • Heating steam—reboilers and heaters • Process steam—steam “consumed” in the process units (stripping operations) • Letdown and vented steam For condensate systems, establish presence (or not) of condensate flash drums, where steam is flashed to, and where the condensate is sent Establish the system water balance. It should include condensate recovered plus fresh makeup water and steam condensed in the deaerators should equal total steam production, plus blowdown. Define, when possible, all fluid flows. This involves a combination of metered data and calculated rates—column heat balances for a reboiler; HP and water flowrates for turbines, valve sizes and characteristics for letdown stations. Hydrocarbon Processing | JANUARY 2013 75

Heat Transfer Developments The objective of this task is to develop a reasonable “big picture” of the total system, containing three key elements: 1. Physical inventory of the steam system 2. A reasonable material balance 3. System controls and how the system responds to changes in steam supply and demand. To clarify and present the “big picture” of the plantwide steam network, utilities unit engineers should: • Create a large PFD-type drawing • Make a change in the system, and, (by hand) on the PFD follow through the sequence of control and heat balance changes that then occur. Now, we can finally observe how the system will respond from changes in steam supply and demand. What is a refinery steam system PFD? It is a very large drawing, typically developed onsite, and it shows: • Steam headers • At each header, all producers and users of steam • Letdown systems • All vents to atmosphere • Condensate systems • Makeup water system • All flows—thousand lb/hr (Mlb/hr) or tph • Mass balance at each header (in vs. out) • Blowdown rates • Total boiler water demand and total boiler feed supply • Steam header pressure controls at boilers and at letdown stations, in particular, showing the pressure is being sensed/ controlled. FIG. 1 lists the basic elements of such a steam-system PFD. This PFD can become exceedingly too complex and busy; thus, selected equipment groupings may be necessary to organize the steam network. For example, all reboilers using medium-pressure (MP) steam in one particular process area can be grouped together. Waste-heat boilers

Boilers

STEAM SYSTEM BEHAVIOR We will investigate three examples on how a system rebalances in response to a change: 1. Reducing process-steam demand (stripping steam) by 10 Mlb/hr 2. Reducing reboiler demand by 10 Mlb/hr 3. Replacing a back-pressure turbine using 10 Mlb/hr steam with an electric driver. FIGS. 2–4 illustrate these cases. In this particular steam system, the boiler blowdown is 7%, and condensate recovery is 60%. Case 1. In this case, demand for 150-psi process steam is reduced by 10Mlb/hr. Process steam is defined as steam “consumed” in the process units and not recovered as lower-pressure steam or condensate. As shown in FIG. 2, these conditions are present: • Letdown to 150-psi header reduced by 10 Mlb/hr. Assume the boiler output also reduces by 10 Mlb/hr. • Blowdown reduces by 0.7 Mlb/hr, so the deaerator feed to the boilers reduces to 10.7 Mlb/hr. At the first iteration, the boiler makeup water reduces to 10.7 Mlb/hr. • The 10-psi steam is used to preheat cold makeup water for the deaerator. If the deaerator operating temperature is 230°F, then the treated makeup water at 70°F will require 160 Btu/lb. • Assume the steam ΔH is 970 Btu/lb. If the deaerator feed water is reduced by 10.7 Mlb/hr, then the deaerator steam is reduced by 1.8 Mlb/hr. (10.7 ⫻ 160/970). Since the reduced deaerator steam backs up to the boiler, then the boiler output is reduced by 11.8 Mlb/hr. This is not close with the initial assumption of 10 Mlb/hr boiler output reduction. • At the second iteration, assume the boiler output is reduced by 11.8 Mlb/hr. The boiler feed and blowdown are now reduced by 12.7 Mlb/hr and 0.9 Mlb/hr. The makeup water by material balance is reduced—12.7-1.8 = 10.9 Mlb/hr. • Doing the deaerator heat balance, the steam required to heat 10.9 Mlb/hr make water is 1.8 Mlb/hr. The heat and material balances are satisfied. In summary, saving 10 Mlb/hr process steam enabled saving 11.8 Mlb/hr of fired-boiler steam.

HP steam Waste-heat boilers

MP steam Waste-heat boilers

Backpressure turbines

To process Reboiler

To process

Backpressure turbines

Reboiler

LP steam

To process PC

Reboiler

Vent to atm Flash BFW

Deaerator

FIG. 1. Basic elements of an HPI steam system.

76 JANUARY 2013 | HydrocarbonProcessing.com

Condensate recovery system Treated BFW

Case 2. A young engineer has a good idea to recover heat from a waste-heat stream, which will eliminate 10 Mlb/hr of 150-psi reboiler steam. How does the system rebalance? Three factors are in play: 1. Reboiler demand is reduced by 10 Mlb/hr 2. Boiler blowdown loss is reduced by 7% 3. Condensate to 150-psi condensate flash drums is reduced by 10 Mlb/hr, which, in turn, reduces 10-psi flash steam production by 0.8 Mlb/hr. The condensate supply is lowered by 9.2 Mlb/hr. Assume condensate recovery is 60%. FIG. 3 illustrates the actual effect on the system. In sequence, the iterate calculations are: • Reboiler demand is cut by 10 Mlb/hr. Therefore, condensate and 10-psi steam production are reduced by 9.2 Mlb/ hr and 0.8 Mlb/hr, respectively • Assume at closure the boiler output is reduced by 10.5 Mlb/hr • At 7% blowdown, the deaerator feed water to the boiler feed is reduced by 11.3 Mlb/hr.

Heat Transfer Developments • Steam to the deaerator is reduced by 0.5 (reduction in boiler output minus reduction in steam to reboiler) plus 0.8 Mlb/hr (reduction in condensate flash) for a total of 1.3 Mlb/ hr. The reduction in cold makeup water is (11.3 – 1.3 – 5.5) = 4.5 Mlb/hr. • Doing the deaerator heat balance (FIG. 3) steam required is only 0.9 reduction. • Iterating again, closure is obtained at the boiler output of 10.1 Mlb/hr. In summary, in saving 10 Mlb/hr reboiler steam, the firedboiler steam output is reduced by 10.1 Mlb/hr. (In real plant situations, this varies based on actual plant blowdown and condensate recovery levels).

-11.3 Mlb/hr (-10.9) -10.5 Mlb/hr (-10.1)

-10.7 Mlb/hr (-12.7) -10 Mlb/hr (-11.8)

Blowdown 7% -0.7 Mlb/hr (0.9)

Fired boiler

-0.5 Mlb/hr (-0.1) PC

50 psi -10 Mlb/hr

Condensate ﬂash

10 psi -1.3 Mlb/hr (-0.9)

-9.2 Mlb/hr Condensate -3.7 Mlb/hr Loss 40% -5.5 Mlb/hr

-11.3 Mlb/hr (-10.9)

Deaerator

-10 Mlb/hr -10 Mlb/hr Steam stripper

FIG. 3. System effects in a reduction of 10 Mlb/hr of reboiler steam, Case 2.

-1 Mlb/hr

Blowdown

Fired boiler

7% 600 psi

150 psi -10 Mlb/hr

+9 Mlb/hr 50 psi

-1.8 Mlb/hr

50 psi

+9 Mlb/hr

10 psi

-10 Mlb/hr

Condensate -1.8 Mlb/hr

-10.7 Mlb/hr (-12.7)

Makeup water

-4.5 Mlb/hr (-4.5) Deaerator heat balance = (5.5x30 - 4.5X160)/970 = -0.9

Note: Values related to change in mass ﬂowrate. First value is the ﬁrst iteration in the calculation. The second value in parentheses represents the second iteration in the calculation.

150 psi

-10 Mlb/hr -10 Mlb/hr

Steam stripper

-1 Mlb/hr

-1.8 Mlb/hr

150 psi

-0.5 Mlb/hr (-0.1)

600 psi

-10 Mlb/hr (-11.8)

600 psi

-0.5 Mlb/hr (-0.1)

Case 3. In this case, a 150-psi to10-psi back-pressure turbine is

replaced by an electric motor. The turbine steam consumption was 10 Mlb/hr of 150-psi steam, as shown in FIG. 4. Demand for 150-psi steam is reduced by 10 Mlb/hr. However, demand for 10-psi steam has not changed, so the letdown will increase. On a pure material balance basis, the boiler output is unchanged. However, in this situation, relative enthalpies at the deaerator of letdown steam and turbine-exhaust steam must be considered. Most of the steam consumed in the deaerators is for heating cold water. Actual O2 stripping requires much less steam than is consumed. Assuming the 10-psi turbine exhaust is just at saturation, the steam enthalpy will be around 1,160 Btu/lb. Replacing the turbine will require additional 600-psi letdown steam. Since the letdown is at constant enthalpy (adiabatic), and assuming the fired-boiler steam is at 100°F superheat, then

Blowdown 7% -0.8 Mlb/hr (0.8)

Fired boiler

Deaerator

-1 Mlb/hr

Loss 40%

Note: Values related to change in mass ﬂowrate. First value is the ﬁrst iteration in the calculation. The second value in parentheses represents the second iteration in the calculation.

FIG. 2. System effects in a reduction of 10 Mlb/hr of stripping steam, Case 1.

Condensate Loss 40%

Makeup water -10.7 Mlb/hr (-10.9)

10 psi

-11.3 Mlb/hr

Deaerator

Makeup water

Note: Values related to change in mass ﬂowrate.

FIG. 4. System effects in a reduction of 10 Mlb/hr to a back-pressure turbine, Case 3. Hydrocarbon Processing | JANUARY 2013 77

Heat Transfer Developments • Demineralized makeup water • Power cost for electric drivers to operate in place of steam turbines. This applies only when there are steam turbines and electric motor are used spares. Economically, the steam system is optimized when all legitimate process steam and hp demands are met. The sum of these three costs is minimum. Steam-system savings actually occur only when fired fuel is backed out of a boiler. In practice, the total operating cost is only obThe biggest single consistent difficulty in tained from a detailed model of the steam system. It optimizing steam systems is that no person may be a detailed spreadsheet simulation, with multiple cases to determine the lowest cost. The model in the refinery or petrochemical complex can be a linear program (LP) based on an optimizer, knows and understands the total system. which will drive the system to an optimum, i.e., lowest total operating cost. More frequently, specific projects and modifications are based on cost of steam ($/Mlb) and costs to run steam and electric drivers ($/hp-yr). deaerators. In particular, each case is also dependent on the presence of letdown steam between headers. The examples assume there is letdown between headers. In cases where there Local costs for steam. Incentives for some process modifiis excess production of low-pressure (LP) steam, and letdowns cation, change in operating practice, or local project are based are closed, or steam is vented, saving from the first two cases on Δsteam ⫻ steam price, and Δdriver hp ⫻ hp price. Conwill be 5%–10% less. However, savings from a back-pressure sider steam pricing followed by costs for hp: turbine removal can be nearly 10 Mlb/hr as credit. • Price of steam. The price of steam is based on makeup water and produced steam Δ enthalpy, makeup-water cost, boiler efficiency, blowdown rates and cost for “internal” boiler STEAM SYSTEM ECONOMICS plant steam/power consumption for boiler auxiliaries (feed What are the energy costs to operate the steam system? pumps, FD, ID fans, etc.) A “quick and dirty” cost for steam is: Long-term depreciation and system maintenance expenses are excluded in this example. Steam-system economics are not Steam cost, $/Mlb = Fuel price $/MMBtu ⫻ 1.5 fundamentally difficult. However, they can get complicated This cost reflects the equivalence of approximately 1 MMfrom three conditions. First is long-term pricing for fuel vs. Btu vs. 1 Mlb of steam, plus costs for listed factors. The value is electric power. The second factor is the value of LP steam. The within 10% of the rigorous value for most steam systems. Using third is horsepower (hp) cost for steam drivers. $5/MMBtu as the fuel price yields a fired-steam price of approximately $7.50/Mlb. Proper use of these values, however, Fuel-price basis. The largest cost to operate a refinery steam requires more understanding, as discussed here. system is the expenses for fuel to fire steam boilers, which is typi• Steam value at lower pressure levels. As steam drops cally refinery and natural gas. In April 2012, fuel-gas prices were in pressure from the HP systems to lower pressures, its value around $2.50/MMBtu in the US, about $9/MMBtu in Europe becomes an “it depends” factor. Considering a scheme to save and $12/MMBtu–$14/MMBtu in the Asian-Pacific region. 10 Mlb/hr of LP steam, what are the incentives? The benefits The US price is lower than the “normal” price from 20 years will depend on: ago. At present, US natural gas prices are 75% lower than from 0 If the steam supply is let down through a turbine drivtwo years ago. With such variability in cost, what price should er, then the LP steam will have lower enthalpy and, thus, less be used to estimate boiler firing expenses? Present predictions value, since heat has been removed. for long-term US gas pricing are about $5/MMBtu; this will 0 If the letdown occurs across a letdown station (a conbe used as the basis in this example. In real-life situations, users stant enthalpy process), then the LP steam will have the same may scale results up or down to reflect local specific prices. For value as HP steam. similar reasons, 5¢/kWh is used for electric-power costs. 0 If the LP steam is already being vented to atmosphere, and “saving” further steam simply increases the vent rate, then Steam-system total operating cost. The total operating steam saved will have no value. Note: This does not imply that cost for the steam system has three cost components: vented steam has no cost. • Fuel burned to heat water and generate steam So what price should be used? The answer will be derived from knowing the total steam system and pricing steam based TABLE 2. Summary of the three cases in steam networks behavior changes on the system consequences due to the proposed change. the enthalpy will be 1,290 Btu/lb. The fired-boiler output will be reduced by about 10% of 10 Mlb/hr or 1 Mlb/hr. TABLE 2 summarizes these three cases. The exact numbers are dependent on the specific refinery situation, and are sensitive to blowdown rates, condensaterecovery rates and temperature of treated makeup water to the

Savings 10 Mlb/hr steam by eliminating

Reduction in ﬁred-boiler steam output

Process steam

11.8

Reboiler steam

10.1

Steam to back-pressure turbine

78 JANUARY 2013 | HydrocarbonProcessing.com

Prices for driver hp. All HPI pumps, compressors, etc., have

a “driver”—either a steam turbine or an electric driver. For a new installation, how do you select which driver has the lower operating cost? Where there is already a steam-driver spared with an electric driver, how do you choose which one to op-

Heat Transfer Developments erate? In this example, we will only consider driver operating cost. This is typically quoted as $/hp-yr. Other factors that come into play, not considered here, including electric vs. steam supply reliability, individual driver reliability, relative size (hp) of steam and electric spared combination, capacity of electric supply system, and boiler capacity. Electric driver operating cost. To calculate from direct equivalence of electric consumption per hp-yr, we will use the following conversions:

1 hp-hr = 0.7547 kWh Multiplying by 8,760 hr/yr, assuming 92% motor efficiency and electric cost of 5¢/kWh, Electric driver operating cost = $360/hp-yr. Back-pressure turbine operating cost. The cost to run a

back-pressure turbine is very dependent on what happens to the exhaust steam. When there is a valid process use for the exhaust steam, then the hp-yr cost is only related to the energy extracted from the steam in the turbine. At the other extreme, if there is no use for the exhaust steam, and it is simply vented to atmosphere, then the turbine operating costs bear the full expense of generating steam, not simply the energy extracted in the turbine. Consider a 600-psi to 150-psi turbine in two cases. For this example, assume the HP steam is from boiler output, and has 100°F of superheat. Valid process use for exhaust steam. In this case the turbine converts energy (Btu) into work (hp-yr). The steam exhausted simply backs up through the system equivalent steam that would otherwise have had to be let down or generated in parallel to satisfy the need for LP steam. So, turbine operating cost is simply the direct cost for energy extracted by the turbine. From conversion tables, 1 hp-hr = 2,546 Btu and 1 hp-yr = 22.3 MMBtu At $5/MMBtu fuel cost, the theoretical cost is $112/hp-yr. However, this is based on a 100% efficient turbine. The correct turbine efficiency must be used. Turbine efficiencies are largely a function of size. Efficiency can vary from as little as 25% for a small, single-wheel pump turbine up to 80% for large machines. We will assume a range of 50%–80%. For a 50% efficient turbine, annual cost = 112/0.5 = $220/yr For an 80% efficient turbine, annual cost =112/0.8 = $140/yr. Back-pressure turbine operating cost = $140/hp-yr – $220/ hp-yr. Note: The operating cost for a back-pressure turbine, with a valid process use for the exhaust steam, is lower than the cost for an electric driver. This follows from the cogeneration principle. Instead of making steam, producing hp in a turbine, and condensing the steam (losing all the energy), in cogeneration the exhaust steam has full value for application within the HPI process. However, other steam turbines do not compare as well with electric drivers. Excess LP steam and venting exhaust steam. When exhaust steam from a back-pressure turbine is then let down and vented to atmosphere, there is no recovery of the exhaust steam enthalpy. From the Mollier diagram or steam tables at 100% turbine efficiency:

Inlet steam enthalpy = 1,280 Btu/lb Exhaust steam enthalpy = 1,140 Btu/lb ΔH = 140 Btu/lb From conversion tables, 1 hp-hr = 2,546 Btu and 1 hp-yr = 22.3 MMBtu Steam cost/yr = [(22,300,000/140)/1,000] ⫻ 7.50 = $ 1,190/hp-yr. The steam cost of 7.50/Mlb is based on fuel at $5/Mlb. However, this is based on a 100% efficient turbine. For a 50% efficient turbine, annual cost = 1,190/0.5 = $2,380/yr For an 80% efficient turbine, annual cost =1,190/0.8 = $1,490/yr. The hp cost to run a turbine against a back pressure, and then to let the exhaust steam vent to atmosphere is brutally expensive. When turbines are running in a steam system that vents LP steam (possibly in a different location), then there are huge incentives to use electric drivers in place of backpressure turbines. Also, if the turbine can be allowed to vent directly to atmosphere, then efforts should effectively reduce the back pressure from 150 psi to 15 psi. This can halve the steam rate and annual operating costs. Condensing turbine. In a condensing turbine, there is no “valid process use” for the exhaust steam. Exhaust-steam enthalpy is lost in the condensing system. To reduce the loss and improve efficiency, the exhaust is at a minimum pressure obtained by a vacuum system. Assume the exhaust is to a vacuum at 100 mm Hg (from the Mollier diagram or steam tables at 100% turbine efficiency), then:

Inlet steam enthalpy = 1,280 Btu/lb Exhaust steam enthalpy = 910 Btu/lb ΔH = 370 Btu/lb From conversion tables, 1 hp-hr = 2,546 Btu and 1 hp-yr = 22.3 MMBtu Steam cost/yr = [(22,300,000/370)/1,000] ⫻ 7.50 = $450/hp-yr. The steam cost of $7.50/Mlb is based on fuel at $5/Mlb. However, this is based on a 100% efficient turbine. For a 50% efficient turbine, annual cost = 450/0.5 = $900/yr For an 80% efficient turbine, annual cost = 450/0.8 = $560/yr. Condensing turbines are not typically cost-effective compared to electric drivers. Their use in HPI facilities is rare. Next month. A short tutorial investigates how to improve per-

formance of existing plantwide steam networks. ROGER O. PELHAM serves as a senior consultant with The Merrick Consultancy, a Merrick & Co., business sector that further expands the firm’s services within the energy market, specifically refining, bioprocessing and utilities markets. He has more than 40 years of diversified consulting and management experience in the petroleum refining industry. He has served in the capacity of president, vice president and process engineer in various roles supporting the refining industry. Mr. Pelham has authored over 17 technical papers. He received the National Petrochemical and Refining Association Lifetime Service award and is a member of IChemE and AIChE. Mr. Pelham holds a BSc degree in chemical engineering from the University of Birmingham, an MSc degree in chemical engineering from the University of Toronto, and an MBA from the University of Southern California. Hydrocarbon Processing | JANUARY 2013 79

Select 57 at www.HydrocarbonProcessing.com/RS

Clean Fuels A. SCHUBERT, Butamax Advanced Biofuels, Wilmington, Delaware

Refiners now have a new biofuel option The biofuels commercially available to refiners have long been limited to ethanol and biodiesel. These fuels offer the benefits of being readily produced from a variety of commercial feedstocks by well-established technologies. Given growing demand for biofuels, driven by government policy and economics, considerable attention is being paid to commercialize technologies that expand the range of applicable feedstocks to include lignocellulosic materials. This is being done to increase the potential supply and, ultimately, to lower costs. Beyond a certain point, however, expansion of biofuel penetration with existing vehicles and infrastructure requires not only broadening the range of feedstocks, but also commercializing new molecules. Biobutanol, specifically isobutanol produced via fermentation of starches and sugars (such as corn, sugarcane, wheat and lignocellulosic materials), is coming to market as a gasoline blendstock and can be efficiently produced from a range of renewable feedstocks. In addition, biobutanol offers several benefits valued by refiners and consumers. • Biobutanol is compatible with existing vehicles and refueling infrastructure at significantly higher levels than ethanol, overcoming the blendwall and providing a route to fully meet the renewable fuels standard. • Biobutanol delivers 1.3 renewable identification numbers (RINs) per gallon and can be blended at 16-vol% in gasoline. A 16% butanol blend generates the same number of RINs as would be generated by E20, while maintaining compatibility with vehicles and infrastructure designed for E10. Additionally, the 16% butanol blend offers motorists the same fuel economy as E10. • Biobutanol can be produced as a conventional, advanced or cellulosic biofuel, depending upon the feedstock (corn, sugarcane or lignocellulosics). • Biobutanol is estimated to be the only drop-in biofuel that can be readily manufactured at corn-ethanol plants, and it offers the optimum combination of fuel value and production cost of all the biofuel options for these facilities. • Biobutanol offers a high blending value due to its low Reid vapor pressure (Rvp), high octane and favorable distillation properties. • Biobutanol enables more light products to be refined from a barrel of crude oil, enhancing crude flexibility and refining margins. • Biobutanol does not phase separate in the presence of water. Compared to ethanol, it is much less corrosive and is a weaker solvent. These properties enable blending at refineries and transport by pipeline.

Benefits to refiners. Biofuel regulations in the US and Europe require substantial increases in biofuel penetration in the gasoline and diesel pools in the coming years. This presents substantial technical and economic challenges to refiners as they aim to meet their regulatory obligations, produce products meeting market specifications and remain profitable in a generally shrinking market. Biobutanol offers refiners a set of blending properties that, relative to ethanol, facilitate production of blended gasoline meeting industry specifications at a cost generally competitive with ethanol on an energy basis. Some of the key blending properties of isobutanol are summarized in TABLE 1, along with corresponding properties of ethanol and US gasoline specifications. Blending values for the anti-knock index (R+M/2) and Rvp are provided at a 10-vol% blend level for ethanol and a 16-vol% blend level of isobutanol. Octane. As is the case with ethanol, isobutanol offers an octane rating substantially higher than gasoline specifications. While isobutanol’s octane is somewhat lower than that of ethanol, its ability to be blended at 16-vol% (rather than 10-vol% for ethanol) allows an isobutanol blendstock for oxygenated blending (BOB) to be blended at nearly the same octane as that required for an ethanol BOB, while delivering a number of additional advantages. Vapor pressure. While ethanol has a blending vapor pressure significantly higher than gasoline, isobutanol offers a blending vapor pressure that is substantially lower. Much of the US offers 10% ethanol blends a 1-psi relaxation in vapor pressure requirements and this offsets much or all of the Rvp increase attributable to ethanol blending. However, there is no Rvp relief granted in reformulated gasoline (RFG) or California Air Resources Board specifications and in a few other key US markets. For markets outside of the US, Rvp relief is generally not provided. In markets where Rvp relief is not provided to ethanol blends, refiners generally need to remove butane and pentanes from the gasoline pool, often selling these components into markets offering much less than their gasoline blending value. Use of isobutanol allows the refiner to keep these components TABLE 1. Key fuel properties Gasoline

Ethanol

Isobutanol

Anti-knock index

120

102

Blending Rvp, psi

7 to 15

18 to 20

5 to 6

100

–

34.7

21.6

% heating value of gasoline Oxygen, %w/w

Hydrocarbon Processing | JANUARY 2013 81

Clean Fuels in the gasoline pool, where they earn substantially greater value and contribute to increasing the volume of light products that can be yielded from each barrel of crude. Energy content. The increased energy content of isobutanol relative to ethanol offers two direct benefits to refiners. These benefits derive from the fact that the fuel economy achieved in existing vehicles is proportional to the energy content of the fuel.

Fuel specifications are set with consideration of vehicle performance, emissions performance and cost. In the US, performance-related specifications are developed by ASTM International. The standard specification for US gasoline is ASTM D4814. Benefit 1: A gasoline blended with 16-vol% isobutanol will offer a motorist the same fuel economy as a gasoline blended with 10-vol% ethanol while being compatible with existing vehicles and retail infrastructure; a result is that biobutanol usage can grow without requiring disruptive changes in the supply chain. Benefit 2: Renewable fuel regulations in the US and Europe effectively weight the energy content of a renewable fuel in determining a refiner’s regulatory compliance. In the US, this is achieved by granting isobutanol 1.3 RINs per gallon blended (1.3 approximates the ratio of the volumetric energy content of isobutanol to that of ethanol). In Europe, the Renewable Energy Directive states its objectives in terms of the renewable energy content of a refiner’s blended fuel slate. Oxygen content. The US EPA regulates key aspects of fuel composition in terms of the weight percent of oxygen in the finished blend. This structure is derived from the large body of data showing that automotive tailpipe emissions of criteria pollutants—nitrogen oxide (NOx ), volatile organic compounds (VOCs) and carbon monoxide (CO)—are correlated to fuel oxygen content. Gasoline blended with 10-vol% ethanol has an oxygen content of 3.5 wt% to 3.7 wt% (depending on the density of the hydrocarbon portion of the blend); the same oxygen content with an isobutanol blend is achieved with about 16-vol% isobutanol. The EPA recognizes this tailpipe emissions equivalence by permitting 16-vol% isobutanol blends under terms of the Octamix Waiver. Other key properties. The benefits of isobutanol include distillation, low water solubility and low corrosivity. Distillation. Isobutanol has a boiling point near the T50 of gasoline and it does not depress T50. This enables relatively high percentages of isobutanol to be incorporated into gasoline without impacting the ability to meet finished gasoline specifications or adversely impact drivability. Low water solubility. Gasoline blended with isobutanol does not phase separate in the presence of water under the wide range of ambient conditions typically encountered in the gaso82 JANUARY 2013 | HydrocarbonProcessing.com

line distribution system. This enables isobutanol to be blended at the refinery and the resultant blends shipped via pipeline. Low corrosivity. Isobutanol is much less corrosive than ethanol and more highly compatible with the range of elastomers commonly applied in petroleum service. This enables 16% isobutanol blends to be compatible with the wide range of vehicles and distribution infrastructure designed for use with E10. Regulatory considerations. In the US, the Clean Air Act (CAA), as amended over the years, grants the EPA primary responsibility for regulating fuel composition. Under this authority, the EPA has defined the range of fuel formulations which are permitted. In addition, the EPA enforces various specification limits on gasoline to assure the ability of the lightduty vehicle fleet to meet emission standards. More recently, the EPA has been charged with enforcement of the renewable fuels standard (RFS2) as enacted by Congress in 2007. Permissible formulations. The CAA restricts gasoline formulations of the type used for original equipment manufacturer (OEM) certification of 1975-model-year cars or alternative formulations that are “substantially similar.” Over time, EPA interpretation of the SubSim rule has evolved to mean containing no more than 2.7-wt% oxygen. This oxygen content corresponds to about 7.8-vol% ethanol or 11.5vol% isobutanol. The CAA also bestows the EPA the authority to grant waivers to this requirement (known as Section 211(f) (4) waivers) provided: “…the applicant has established that such fuel or fuel additive or a specified concentration thereof, and the emission products of such fuel or fuel additive or specified concentration thereof, will not cause or contribute to a failure of any emission control device or system (over the useful life of the motor vehicle, motor vehicle engine, nonroad engine or nonroad vehicle in which such device or system is used) to achieve compliance by the vehicle or engine with the emission standards with respect to which it has been certified…” The pulled quotation is from this section of US Code: 42 USC 7545(f)(1). The EPA has used this authority on several occasions since the enactment of the CAA. In fact, E10, the most widely used gasoline formulation in the US today, is approved under one such waiver originally put in place in 1978. More recently, the EPA has issued a waiver for the use of E15 in 2001 model year and newer light duty vehicles. In 1988, the EPA issued the Octamix Waiver; this waiver covers a wide range of gasolinealcohol blends containing up to 3.7 wt% oxygen, a range that includes blends of 16-vol% isobutanol. In addition to meeting these formulation requirements, producers of fuels (typically refiners and jobbers) and fuel additives (including functional additives, such as corrosion inhibitors and deposit control additives as well as oxygenates, such as ethanol and isobutanol) must register their formulations with the EPA under Section 211(b) registration, from 42 US 7545(b). The section addresses the range of up to the maximum intended additive content. Such registration requires submission of health effects data to demonstrate no

Clean Fuels significant adverse health impact from the use of the intended formulation. To date, one isobutanol producer has registered isobutanol up to the SubSim limit and a second producer is in the process of registering up to the Octamix Waiver limit. Specification limits. Fuel specifications are set with consideration of vehicle performance, emissions performance and cost. In the US, performance-related specifications are developed by ASTM International, a voluntary consensus organization encompassing the broad range of stakeholders. The standard commercial specification for gasoline in the US is ASTM D4814. Additionally, the EPA uses its CAA authority to regulate properties that can impact emissions of criteria pollutants (SOx , NOx , CO and VOCs) and toxics (such as benzene, 1,3-butadiene, formaldehyde and acetaldehyde). In terms of performance-related specifications controlled by ASTM D4814, isobutanol’s blending properties make it costeffective for refiners to meet D4814 requirements with blends of 16-vol%. Isobutanol’s low blending vapor pressure greatly assists refiners in meeting the EPA’s summer Rvp specifications, particularly in markets where there is no Rvp waiver provided for E10. The ability to utilize isobutanol at levels up to 16-vol% further assists refiners by dilution of sulfur, benzene and other controlled fuel parameters. Renewable fuels standard. RFS2 was enacted by the US Congress as part of the Energy Independence and Security Act of 2007 (EISA 2007) as a mechanism for increasing the renewable content of the US fuel supply. Under RFS2, refiners, blenders and importers are obligated parties required to blend a percentage of renewable fuels each year. This percentage, the renewable volume obligation, or RVO, is set in a rule-making by the EPA each fall. Each year there are actually four RVOs with which a refiner must comply: • Renewable fuels, produced from biomass and achieving, at least, a 20% greenhouse gas (GHG) benefit relative to gasoline • Advanced biofuels, a subset of renewable fuels, that achieve at least a 50% GHG benefit and are not ethanol produced from corn starch • Cellulosic biofuels, a subset of advanced biofuels, that are produced from lignocellulosic feedstocks and achieve at least a 60% GHG benefit • Biomass-based diesel, a subset of advanced biofuels, which is a substitute for petroleum-derived diesel fuel. Corn-based ethanol in the market today qualifies as a renewable fuel, sugarcane ethanol qualifies as an advanced biofuel and biodiesel qualifies as both a biomass-based diesel and as an advanced biofuel. Biobutanol, depending on the feedstock employed and the production process utilized can be produced as a renewable fuel, an advanced biofuel or as a cellulosic biofuel. RVO compliance for renewable fuels, advanced biofuels and cellulosic biofuels is measured in terms of ethanol-equivalent values (one gallon of ethanol earns one RIN. The factor used for translating other biofuels into ethanol equivalents within each classification is the energy content. As a result of its higher energy content, each gallon of isobutanol earns a credit equal to 1.3 gallons of ethanol. Thus, a 16-vol% isobutanol blend earns the refiner credit equivalent to what he would earn with an E20 blend (16vol% isobutanol ⫻ 1.3 RINs/gallon 艑 20-vol% ethanol) while

being compatible with all the vehicles and infrastructure designed for E10 and offering consumers the same fuel economy as E10. Production process. Production of biobutanol is achieved via fermentation of sugars. Fundamentally, those sugars can be derived from existing commercial processes, such as corn and sugarcane. Longer-term, as technology for recovery of fermentable sugars from lignocellulosic (LC) feedstocks becomes commercialized, biobutanol production will be adaptable to an even broader range of feedstocks. Designed with today’s ethanol plants in mind, this technology can be readily retrofitted onto existing ethanol plants. For example, FIG. 1 is a schematic of the corn butanol production pathway. The primary changes from the corn ethanol process are in the two boxes labeled “saccharification/fermentation” and “integrated recovery.” Within the saccharification/fermentation area, the principal change is the substitution of the proprietary isobutanol yeast for the conventional ethanol yeast. As yeast is a consumable for each batch of corn ethanol production, this represents a minor operational change for the plant. The largest capital modifications are in the integrated recovery area; the differences in chemical and physical properties of isobutanol vs. ethanol require that changes be made to isolate a fuel-grade isobutanol product from the fermentation broth. Analogous changes would be required for the retrofit of sugarcane ethanol plants to isobutanol production. CO2

Corn

Corn processing Conversion of corn to a liqueﬁed starch solution

Mash

Sacchariﬁcation/ fermentation Conversion of starch to glucose and glucose to isobutanol

Integrated recovery Proprietary recovery and reﬁning of isobutanol Evaporation/drying Removal of water from unfermented solids

Biobutanol

Dried distillers grains with solubles (DDGS)

FIG. 1. The corn butanol process.

FIG. 2. Highwater Ethanol’s plant is located in Lamberton, Minnesota. Hydrocarbon Processing | JANUARY 2013 83

Clean Fuels As existing ethanol plants can be economically retrofitted to enable commercial isobutanol production, accordingly commercial scale production can be rapidly scaled up to meet the volume and supply reliability requirements of the petroleum refining industry. One such example is Highwater Ethanol’s plant in Lamberton, Minnesota, pictured in FIG. 2. The volumetric output of an ethanol plant after retrofit to isobutanol production decreases if the feedrate is held constant. This can be predicted from the theoretical yields determined by the stoichiometry of the respective processes: Ethanol fermentation: C6H12O6 j 2C2H5OH+2CO2 Theoretically, one kilogram of glucose (C6H12O6 , which may be derived from corn, sugarcane, lignocellulosic matter, etc.) yields 0.511 kg of ethanol. At a density of 0.794 kg/l, this corresponds to 0.644 l. The energy content of ethanol is 21.1 MJ/l, so the ethanol produced has an energy content of 13.6 MJ. Butanol fermentation: C6H12O6 jC4H9 OH + 2CO2 + H2O Theoretically, the same one kilogram of glucose now yields 0.411kg of isobutanol. This corresponds to 0.511 l at a density of 0.804kg/l. As isobutanol has an energy content of 26.6MJ/l, the energy content of the produced isobutanol has an energy content of 13.6 MJ, the same as the ethanol produced from the same quantity of feedstock. Accordingly, retrofit of a notional 100 MM gpy ethanol plant to isobutanol production would, at a constant feedrate,

result in a plant producing approximately 80 MM gpy of isobutanol. That lower volume of isobutanol production would contain the same fuel energy and about the same number of RINs as the ethanol formerly produced at that plant. The new product will offer greater value due to its enhanced compatibility with existing vehicles and infrastructure and its more favorable gasoline blending properties. Closing out. Government regulations (particularly in the US and Europe) continue to be a major factor driving increased biofuel content in motor fuels. In response to this growth in demand, the biofuels industry is responding by developing technology to bring new products to market. While considerable attention gets placed on diversifying the available feedstocks, new fuels are also being designed to better address the refiner’s need to meet increasingly stringent product specifications. Biobutanol, which is isobutanol produced via fermentation, brings a combination of chemical and physical properties that offer substantial benefits for gasoline blending while addressing the challenges of compatibility with existing vehicles and retail infrastructure. ADAM SCHUBERT is the strategy and regulatory affairs manager for Butamax Advanced Biofuels, LLC. Butamax is a joint venture between BP and DuPont. Dr. Schubert is responsible for addressing commercial and regulatory issues required for the commercial introduction of biobutanol. He holds a PhD in chemistry from Michigan State University and an MBA degree from the University of California at Irvine.

Available to VIEW ON DEMAND at HydrocarbonProcessing.com

HEINZ BLOCH: PROCESS GAS COMPRESSOR FAILURE AVOIDANCE

In the Process Gas Compressor Failure Avoidance webcast, Heinz will explain notable compressor issues and map out practical remedies that he has found to have worked in his 50-year professional experience. In essence, Heinz Bloch will provide lessons learned to prevent process compressor failures. His presentation will touch upon centrifugal, rotary positive displacement and reciprocating compressors. It will highlight missed opportunities in getting to the bottom of compressor failures and highlight steps that have been taken by leading performers to operate some machines without shutdown for ﬁve, eight and more years.

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84 JANUARY 2013 | HydrocarbonProcessing.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.

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Page

RS#

Website

Company

Page

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Website

Company

Page

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Gulf Publishing Company Events—EMGC .....................................22–23, 68 Events—IRPC..........................................66a, 85 HP Webcast...................................................84 HPI Market Data 2013 .............................74b–74c Marketplace ............................................ 86–88 Hermetic Pumpen GmbH ................................. 39

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This Index and procedure for securing additional information is provided as a service to Hydrocarbon Processing advertisers and a convenience to our readers. Gulf Publishing Company is not responsible for omissions or errors. SALES OFFICES—EUROPE

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Hydrocarbon Processing | JANUARY 2013 89

Water Management

LORAINE A. HUCHLER, CONTRIBUTING EDITOR Huchler@martechsystems.com

Need a package boiler in a hurry? In a perfect world, acquiring a boiler would be a methodical, well-planned event. In reality, acquiring a package boiler is an unplanned event that requires process engineers to solve this completely unfamiliar problem. To reduce the chaos of replacing package boilers, here are helpful ways to resolve this situation: Purchase, lease and lease-to-own. Purchasing an asset

requires an economic justification (payback or return-on-investment) to gain approval by a budget committee. The hurdle for approving a capital project in the utility department can be difficult because infrastructure projects must compete against process improvement projects that have direct and easily measured profit metrics. Leasing a boiler is an operating expense with a shorter and simpler approval process. Plant personnel should always consider adding the option of lease-to-own in a lease contract. Waiting to negotiate the purchase of the leased boiler during the rental period puts the plant at a tactical disadvantage, possibly resulting in higher purchasing costs. New or used assets. Don’t assume that purchasing or leas-

ing a used unit will reduce the total cost. There are additional tangible and intangible costs. Tangible costs include the expense of a pre-operational cleaning (a standard practice) and a borescope inspection of the highest heat-transfer surfaces to confirm the efficacy of the cleaning process and condition of the boiler tubes. These intangible costs accrue from the other risks. Evaluating the reliability of used assets is difficult without inspection data or historical operating information. There is no standard “certification” process for used boilers. The lead time for a new asset may be too long for a “fast-track” project. A compromise may be necessary: purchase a larger or more complex unit or acquire a used unit with the associated cleaning costs and potential reliability risks. Integration. Plant personnel should thoroughly analyze the integration issues before finalizing the selection of the boiler. This evaluation includes the typical integration issues such as electrical, mechanical and process-control interfaces with the existing infrastructure, as well as the dynamic operational profile and operating protocol. Operating efficiency, emissions, turndown ratio, startup complexity, compliance to safety instrumented system requirements, state licensing regulations, and load management may impact the selection, size and design of the boiler. Commissioning. Most boiler suppliers will provide commissioning services at an additional cost. Purchasing these 90 JANUARY 2013 | HydrocarbonProcessing.com

services is an important risk-management strategy, especially if plant personnel lack specific experience in the startup of newly installed boiler assets. If the facility has installed new transfer piping or auxiliaries, such as boiler feedwater pumps, plant personnel should coordinate pre-operational cleaning and commissioning procedures with the boiler supplier’s activities. Ideally, the supplier will perform the required preoperational cleaning procedures and take responsibility for validating their effectiveness.1 Contract terms. All contract terms are negotiable for a price. Key terms include: technical specifications, scope of services, warranty, milestones for deliverables, and recourse for nonperformance (especially for services delivered by sub-contractors such as boiler cleaning) and conditions for replacement with a failed unit. The over-riding issues are: enforceable warranty terms, an appropriate assignment of risk to each party, and clear milestones to ensure that the plant meets their operational schedule. Other important issues include transfer of liability and/or ownership of the asset and guarding against the consequences of a waterside failure. Plant personnel should require the supplier to transfer ownership and liability for the asset upon delivery onto their property, not upon release from the manufacturing plant. Plant personnel can reduce the risk of waterside failure in used assets by requiring a successful pre-operational cleaning and borescope inspection as a condition of acceptance of the unit. Likewise, the plant should insist on properly documented water quality during startup, commissioning and operation for both new and used boilers. Bottomline. Plant personnel can use a framework of under-

standing and managing risk to guide their decisions and minimize the total cost when obtaining boiler assets. EDITOR’S NOTE HP congratulates Loraine A. Huchler as the recipient of the Society of Women Engineers 2012 Entrepreneur Award. As president of MarTech Systems, Inc., Ms. Huchler was recognized for building a highly regarded consulting business and acknowledged as a leading authority and thinker in risk management for industrial water systems, and inspiring the next generation of entrepreneurs. LORAINE A. HUCHLER is president of MarTech Systems, Inc., a consulting firm that provides technical advisory services to manage risk and optimize energy- and water-related systems including steam, cooling and wastewater in refineries and petrochemical plants. She holds a BS degree in chemical engineering, along with professional engineering licenses in New Jersey and Maryland, and is a certified management consultant.

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