HP_2009_07 by androsov.info

HYDROCARBON PROCESSING

JULY 2009

JULY 2009 LIQUEFIED NATURAL GAS DEVELOPMENTS

HPIMPACT

SPECIALREPORT

TECHNOLOGY

LNG outlook by regions

LIQUEFIED NATURAL GAS DEVELOPMENTS

A CI process that really works

Focused strategies for the upturn

Technologies handle extreme temperatures

Estimate water hammer in steam piping

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SPECIAL REPORT: LIQUEFIED NATURAL GAS DEVELOPMENTS

Are floating LNG facilities viable options?

Consider new approach for floating LNG units

Here’s how to evaluate technological and commercial issues of these units A. J. Finn

Combined technical expertise for onshore and offshore LNG facilities reduces risks and capital costs for new installations C. Caswell, C. Durr, E. Rost and M. Kilcran

Minimize risks from cryogenic exposure on LNG facilities

Consider investing in a standard-compliant process analyzer

A rational approach investigates methods to protect equipment and infrastructure from liquefied natural gas releases M. Livingston, R. Gustafson, P. Guy, L. J. Padilla, C. Bloom, K. Shah and V. H. Edwards

High profits are realized with accurate vapor pressure testing O. Sauer and H. Pichler

PIPING/RELIABILITY

Cover ConocoPhillips’ Darwin LNG plant, located at Wickham Point, Darwin, Australia employs the company’s proprietary natural gas liquefaction technology, the ConocoPhillips Optimized Cascade Process. The plant was the first to use highly efficient, low emission aeroderivative gas turbines for compressor drivers.

Estimate water hammer loads in steam piping The problem is more complicated because of the two-phase flow S. Saha and P. Darji

HPIMPACT 17 LNG outlook: spare global capacity and weak demand 19 Prepare for the upturn: be lean, prioritize, focus on strategic intent

GAS PROCESSING DEVELOPMENTS

Do you have hard-to-handle gases? Consider using this second-generation hybrid solvent for treating D. L. Nikolic, R. Wijntje and P. P. Hanamant Rao

MANAGEMENT GUIDELINES

A continual improvement process that really works Taking care of these basics can enable businesses to move out of bureaucratic quagmire onto a path of measurable results D. M. Woodruff

GAS PROCESSES 2009

Selection of gas processing technologies used by modern facilities that treat and purify natural gas For the complete listing, please visit www.HydrocarbonProcessing.com.

ENGINEERING CASE HISTORIES

Case 51: Phantom failures Why some are very elusive T. Sofronas

DEPARTMENTS 7 HPIN BRIEF • 17 HPIMPACT • 21 HPINNOVATIONS • 25 HPIN CONSTRUCTION • 29 HPI CONSTRUCTION BOXSCORE UPDATE • 86 HPI MARKETPLACE • 89 ADVERTISER INDEX

COLUMNS 9 HPIN RELIABILITY Why continuing education gets dropped first 11 HPIN EUROPE Glut of stored distillate infers betting on EU’s diesel 13 HPIN CONTROL APC designs for minimum maintenance—Part 2 15 HPIN ASSOCIATIONS Debating America’s energy future 90 HPIN AUTOMATION SAFETY Safety culture for operations and maintenance

www.HydrocarbonProcessing.com Houston Office: 2 Greenway Plaza, Suite 1020, Houston, Texas, 77046 USA Mailing Address: P. O. Box 2608, Houston, Texas 77252-2608, USA Phone: +1 (713) 529-4301, Fax: +1 (713) 520-4433 E-mail: editorial@HydrocarbonProcessing.com www.HydrocarbonProcessing.com Publisher Mark Peters mark.peters@gulfpub.com EDITORIAL Editor Les A. Kane Senior Process Editor Stephany Romanow Managing Editor Wendy Weirauch Process Editor Tricia Crossey Reliability/Equipment Editor Heinz P. Bloch News Editor Billy Thinnes European Editor Tim Lloyd Wright Contributing Editor Loraine A. Huchler Contributing Editor William M. Goble Contributing Editor Y. Zak Friedman Contributing Editor ARC Advisory Group (various) MAGAZINE PRODUCTION Director—Editorial Production Sheryl Stone Manager—Editorial Production Chris Valdez Artist/Illustrator David Weeks Manager—Advertising Production Cheryl Willis ADVERTISING SALES See Sales Offices page 89. CIRCULATION +1 (713) 520-4440 Director—Circulation Suzanne McGehee E-mail: circulation@gulfpub.com SUBSCRIPTIONS

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If you would like to have a recent article reprinted for an upcoming conference or for use as a marketing tool, contact us for a price quote. Articles are reprinted on quality stock with advertisements removed; options are available for covers and turnaround times. Our minimum order is a quantity of 100. For more information about article reprints, call Cheryl Willis at +1 (713) 525-4633 or e-mail EditorialReprints@gulfpub.com HYDROCARBON PROCESSING (ISSN 0018-8190) is published monthly by Gulf Publishing Co., 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252. Copyright © 2009 by Gulf Publishing Co. All rights reserved. Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01. www.HydrocarbonProcessing.com

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HPIN BRIEF WENDY WEIRAUCH, MANAGING EDITOR

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Effects of pool fires on LNG tank systems. With the increasing trade in LNG in recent years—a fleet of more than 300 LNG carriers is transporting the fuel worldwide—possible major hazards are a focus of public concern. Previous studies have been conducted to assess the consequences and risks of LNG spills as a result of marine accidents. At the 2009 GASTECH conference in Abu Dhabi, Dr. Gerd-Michael Würsig, from the classification society and technical assurance and consulting company Germanischer Lloyd, presented a study on major hazard scenarios of an LNG containment system under fire. “The evaluations include a finite element buckling analysis of the tank cover, an extensive computational fluid dynamics simulation of the insulation system and tank supports, as well as an overall thermodynamic analysis,” according to Dr. Würsig. For more on this study, go to www.gastech.co.uk.

■ NOCs forge ahead with investments The world’s largest national oil companies (NOCs) and super majors are planning on delivering over $375 billion of ambitious investments through the down cycle, despite ongoing concerns about the oil demand outlook, according to a new analysis from Ernst & Young (www.ey.com).

Downstream capital costs decline 9% in past six months, according to a recently compiled index from IHS CERA (www.ihs.com). After years of steady escalation, the effects of the global economic slowdown and falling commodity prices have halted rising costs for designing and constructing downstream refining and petrochemical projects. The drop returns costs back to levels last observed in late 2007. “The downward pressures that began to materialize at the end of third quarter 2008 have now taken hold on the cost of construction materials,” says Daniel Yergin, chairman of IHS Cambridge Energy Research Associates. The decrease was driven by a sharp decline in steel costs (down over 25% in the past six months) and low oil prices.

As oil prices recover, numerous projects move forward. Holly Corp.’s $65-million deal to acquire Sunoco’s West Tulsa, Oklahoma, refinery is part of the buyer’s $215-million plan that upgrades the 96-yr-old facility to meet stricter environmental standards, according to a new market analysis by the McIlvaine Company. Pakistan’s oil refineries will require $1.5 billion for upgrading to achieve desulfurization and isomerization to meet Euro II specifications. Mexico’s state-owned Pemex has launched a $12.2-billion plan to add new refining capacity to deal with the country’s growing dependence on imported fuels. The present oil price level has slowed down oil-shale activity, but there are still projects going ahead. “Canadian production of synthetic crude from oil sands is expected to reach 3.3 million barrels/day (MMbpd) in 2020 up from 1.2 MMbpd in 2007,” according to this research. Europe’s consumers pay ‘startling differences’ for energy. Depending on where an electricity or gas customer lives in Europe, the price for electricity can be around 300% that of another country, according to a new monthly price index for that region (www.vaasaett.com). The data reveal that both for electricity and gas, end-user prices have decreased constantly across EU15 member states since January 2009. Electricity customers in Copenhagen pay by far the highest prices within the capital cities of the EU15, around a third higher than Berlin, the next most expensive city. Customers in Helsinki and Athens get to outlay the least. For gas, Stockholm customers pay the highest prices—over 50% higher than in the next most expensive cities: Copenhagen, Berlin and Rome. Gas customers in London pay less than in any other capital city.

Quantifying the value in maintaining sustainable and successful business practices during the global economic crisis, a new report describes the strategies pursued and programs implemented by the Bayer Group. Using a “Climate Check,” the company plans to analyze 100 production facilities worldwide by the end of this year with the goal of identifying additional CO2 reduction potential. Analysis of more than half of its facilities so far has confirmed Bayer’s original assumption that there is an emissions reduction potential of between 5% and 10% to be identified. The report can be found at www. sustainability.bayer.com. HP

The report calculates that the largest NOCs are on course to invest over $275 billion in developing their businesses at home and abroad in 2009. Almost 70% of total investment is forecast to come from NOCs in Asia and South America. “Companies are wary of finding themselves in a position where they have to play catch-up on investment when the upturn materializes,” says Andy Brogan, author of the report. The economic slowdown, a dramatic fall in oil prices and investors’ flight from risk have left many reserve-rich state-owned oil and gas companies less able to finance projects with surplus cash flows. The capital expenditure of NOCs in Africa, CIS and the Middle East is a fraction of that of their Asian and South American counterparts. The report calculated that the NOCs of Africa announced $21 billion of investment this year, compared to $36 billion for the CIS and $29 billion for the Middle East. When the NOCs had easy access to capital, they were in a position to dictate terms with their international oil company (IOC) partners. “IOCs with sufficient liquidity will be able to offer potential partners not only technological and operational expertise but also access to much needed capital,” according to Mr. Brogan. However, he notes that any renewed appetite from NOCs for IOC participation will be short-lived. “And, therefore, opportunities available now should not be wasted.” HP HYDROCARBON PROCESSING JULY 2009

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

Why continuing education gets dropped first

Pump MTBF, months

Yearly cost of pump maintenance and repairs at a reﬁnery (per installed pump and driver set)

for pumps increase. Best-practices professionals, the ones we wish Fact: An oil refinery in the Western US achieves a pump meanto commend, will use these statistics to make a powerful case for time-between-failure (MTBF) of over nine years. The facility has continuing education and will do so as a matter of routine. It is 1,200 pumps and, in a given year, repairs 130 of them. Fact: An in their role statements to groom successors and to understand oil refinery “elsewhere” has about the same number of pumps where the reliability performance of their plant is ranked relative installed and does 260 repairs each year; its MTBF is roughly 4.5 to industry competition. These are the professionals that will years. Including overhead expenses, the average pump repair costs obtain funding for continuing education a US refinery $13,000. Each year, the because they have proof that their plant refinery “elsewhere” spends $1.7 million would suffer avoidable repeat failures more for pump repairs than the refinery ■ Best-practices professionals, without such education. As responsible in the West. If one would teach the “elsewhere” the ones we wish to commend, professionals they know failure statistics oil refinery to safely extend run time and will use these statistics to make and will have informed their managers if, for instance, pump MTBFs did not increase pump MTBF to 5.5 years, this measure up to best-of-class. facility would save $600,000 per year. a powerful case for continuing The same dedication to excellence If this achievement required sending should motivate key institutions of indus20 employees to a local college campus education and will do so as a trial learning to assist local industry trainwhere they would attend a two-day ing coordinators (LITCOs) by nudging continuing education course costing matter of routine. below-average performers toward better $12,000, the “elsewhere” refinery would uptime and improved reliability achievements. Regrettably, not every recover its investment 50 times in one single year. The state of the institution of industrial learning is doing its part; not all are willing economy has absolutely nothing to do with it. to lead. A few see themselves as the representatives of a LITCO orgaWhy, then, is continuing education often the first budget item nization made up of volunteers who decide whether or not they can to be deferred or dropped in an economic downturn? Here’s the afford to pay for training (even local). They merely view themselves short answer: Management will not support what it deems of little as facilitators seeking to accommodate the wishes of the LITCOs. value. But why would continuing education in equipment reliability When most of the LITCOs take the position that there are no funds improvement or failure avoidance be deemed of little value? The answer involves us, the reliability professionals. I will try to spell out to send people to training, some institutions of industrial learning the answer, knowing full well that it risks alienating a few readers. accept the fictitious claim that local industry would go under if its The below-average performance of one plant is plotted in Fig. 1. employees were to attend a solid continuing education course. Note how its MTBF decays, even as the plant’s repair expenditures In essence, we unreservedly applaud the many reliability professionals whose objective it is to continuously improve. They also quantify and report, in support of management, the value of 20,000 targeted and tangible improvement. Those who don’t have these 45 objectives are encouraged to make changes. Above all, we urge 18,000 the occasional misguided faculty member of an institution for 40 industrial learning to consider his or her role. Some might really 16,000 add value by spreading the word about the effectiveness of true 14,000 learning. In some refineries and on a per-attendee basis, the cost 35 would be a pittance. For some, the benefit-to-cost ratio of imple12,000 menting lessons learned from experts would be huge. Whatever 30 10,000 good continuing education manages to put into the gray matter between the ears of a willing worker can never be taken away. It MTBF 8,000 might even help the economy. HP Yearly cost of pump maintenance 25 and repairs at a reﬁnery (per installed pump)

6,000 4,000 0

FIG. 1

8 10 12 Calendar months

20 18

MTBF decays even as the plant’s repair expenditures for pumps increase.

The author is HP’s Reliability/Equipment Editor. A practicing engineer and ASME life fellow with close to 50 years of industrial experience, he advises process plants on maintenance cost-reduction and reliability upgrade issues. His 16th and 17th textbooks on reliability improvement subjects were published in 2006 and 2009. An excerpt was taken from Bloch-Geitner, Maximizing Machinery Uptime, pp. 201–228 (Gulf Publishing, ISBN 10:0-7506-7725-2). HYDROCARBON PROCESSING JULY 2009

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HPIN EUROPE TIM LLOYD WRIGHT, EUROPEAN EDITOR tim.wright@gulfpub.com

Glut of stored distillate infers betting on EU’s diesel Just outside the archipelago here, the Danish shipping operator, Maersk, has applied for permission to conduct ship-to-ship transfers to and from large crude carriers at anchor. There’s a lot more of this going on as large vessels are increasingly used not only for transporting crude, but for storing it. But staggeringly, just a day or two ago I learned that five to six very large crude carriers are being pressed into service to store heating oil in Europe and West Africa. That’s in addition to perhaps 10 long-range tankers here, each carrying 60,000–80,000 metric tons of distillate. Now, you don’t put distillate in a 290,000 metric ton (2.2 million bbl) supertanker lightly. With terminals full of products right now, the logistics just to empty the vessel are quite a headache. “It would cost you about a million dollars to do that,” said one oil trader. “No port or terminal can discharge that load. You’d need five to six offshore ship-to-ship transfers.” Speculators’ storage program. And since supertankers are used to freight dirty oil, the traders in this play must find newly commissioned crude tankers on their maiden charter. Underlying this spectacular hoarding of distillates in Europe is a so-called “supercontago,” a phrase coined by the analysts at Goldman Sachs who in May last year came up with “superspike” to describe the potential onslaught of $150–$200/bbl crude. Refinery planners and traders have never seen anything in their careers like the current contango. For the uninitiated, it means that the market is lousy now, but is looking real good the further out into the future you go. For example, on Jan. 3, 2008 heating oil “now” (the front futures contract) was $34 more expensive than gasoil contracted for delivery six months later in June that year. Today, buying the June contract costs $55.25, but the price for delivery in December this year is $66.25 higher. In gross profit terms, you can fill one of these boats for $161 million and discharge it for $180.2 million. It will cost you about $1 million a month to keep it afloat and a further million to discharge. The question then becomes, why is the market rewarding people for doing something so apparently extreme? The answer is that the market has faith in the prospects for oil generally and, particularly, for diesel in Europe. Tales of events to come. Some interesting views came up on

the subject at the Global Refining Summit in Rotterdam in May. The Oil Price Information Service, for whom I write a daily jet fuel and gasoil report, had suggested I accept an offer to chair, and I took up the supercontango in my opening comments. First out among the speakers was an economist, Ogur Ocal, from the International Energy Agency (IEA). Global oil exploration and production budgets are set to fall by $100 billion or 21%, he said, previewing an IEA paper, which was later presented to G8 Energy Ministers under the title, The Impact of the Financial and

Economic Crisis on Global Energy Investment. Seven refining projects have been delayed since September 2008, and two cancelled, representing a total of 1.6 million bpd, the IEA also reported. The Saudi Oil Minister, Ali al-Naimi, later said that lack of investment could precipitate another oil shock “similar or worse to what we saw in 2008,” causing headlines about $150 oil. With the summer of 2008 described by Total’s chief economist, Pierre Sigonney, as the third oil shock, news that the fourth might be around the corner, is music to the ears of a re-emerging group of global investors taking a serious punt on oil. Speculators may be focused on the oil as a whole, but what about distillates in Europe? On that point, Wood Mackenzie, made an interesting observation. Europe might be very long distillate now, but structurally it has a massive deficit, which will re-emerge along with economic and industrial activity. The company’s head of downstream oil consulting, Mike Wilcox, told delegates that in the mid-term the European diesel shortage may leave Europe’s refiners in better shape than their US counterparts. Both regions, he said, face declining demand growth in the future, as global warming legislation, including new CAFE standards, begin to bite. Both will struggle with an oversupply of gasoline. But in that context, it’s a boon to the European refiners that they have their diesel deficit to get stuck into. “Since their principal product is going to be a profitable business, they can afford to sell the bi-product, gasoline, to the US market at levels, which will undercut US producers,” he said. While some who have invested in major diesel projects, like Neste, which is currently starting up a 1 million tpy-residue hydrocracker at Porvoo, Finland, it may be a testing time. Margins are down, and there is product everywhere. But, they can take some consolation that the global market is betting on them. PS. We just had elections for the European Parliament. Centerright parties scored highest on economic woes, the Greens did well from climate change worries (gaining ten seats for their bloc), and some extreme right politicians were elected by those concerned about immigration. The highlight of the whole campaign was hearing challenges racist parties are having in organizing themselves into an effective international political group at the Parliament. It turns out that racists from, say, France are a little suspicious of their Romanian racist colleagues. Anti-immigration racists from the UK, meanwhile, are not that enthusiastic about collaborating with racists from Poland. I guess they’ll have to learn to co-operate with foreigners if they want to effectively promote xenophobia within the EU! HP The author is HP’s European Editor and has been active as a reporter and conference chair in the European downstream industry since 1997, before which he was a feature writer and reporter for the UK broadsheet press and BBC radio. Mr. Wright lives in Sweden and is the founder of a local climate and sustainability initiative. HYDROCARBON PROCESSING JULY 2009

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HPIN CONTROL Y. ZAK FRIEDMAN, CONTRIBUTING EDITOR Zak@petrocontrol.com

APC designs for minimum maintenance—Part 2 My last month’s editorial proposed that since our advanced process control (APC) applications are by and large under-maintained, these applications should be designed in the simplest possible way. The design rule discussed was: Do not clutter the control matrix. Associate each control variable, CV, preferably with one, hopefully no more than two, manipulated variables (MVs). That was accompanied by a distillation column example (Fig. 1), which this editorial will continue to use proposing additional rules. Design rule 2. Avoid nearly redundant CVs. Our example last month showed a 3 MV by 3 CV design as follows: • Tray six temperature, MV1 • Reboiler steam, MV2 • Column pressure, MV3 • Top product inference, CV1 • Reflux valve position, CV2 • Reboil ratio, CV3. But such a design with only one inferential model goes almost against the grain in our industry. Many APC practitioners would consider several additional CVs for our distillation example: • Pressure-compensated top temperature, CV4 • Pressure-compensated tray 25 temperature, CV5 • Pressure-compensated bottom temperature, CV6 • Bottom purity inference, CV 7. The rationale for these CVs has to do with lack of trust in the inference models, and setting up redundant simple inferences to protect the application from failure of the main inference model. That is the same kind of fear that would drive the operator to set a tray six temperature, MV1, limit, except redundant CVs damage the APC performance more than MV limiting. A degree of freedom

MV3 PC TI

analysis reveals that at most two inference CV targets can be met on this column, one related to the top product and the other to the bottom product purity. But the multivariable predictive controller (MVPC) has no such knowledge; it works by inverting the dynamic response matrix, and since there are always small differences among models, the MVPC can be misled into finding a “solution” that would meet three inferential model targets. Because of the almost colineal CVs, instead of a real set of conditions, ill-conditioned MVPCs tend to push the unit to extremes, for example minimum pressure and maximum reflux, or vice versa. The column in Fig. 1 does not normally flood and hence, no flooding detection CV is specified, but the erroneous solution might drive the column into flooding. Now the operator has another reason to limit MVs—to avoid a minimum-pressure–maximum-reflux solution. To reiterate, when an APC application is operated correctly, redundant inferences would have wide ranges and would not usually come into play. But in an unsupervised application, due to operator lack of confidence, the redundant inference CV ranges could be narrowed enough to bring about strange infeasible MVPC solutions. At that point the operator would lose the remaining confidence and turn off the application indefinitely. Design rule 3. Restructure necessary near colineal CVs to avoid ill-conditioning. In the distillation example

it actually is feasible to control both top and bottom purities. Can we avoid near colineal CVs in that case? Our design rule 2 above simplified the problem by setting a reboil ratio, CV3, considering that if the top product is on specification, reasonable loading of the stripping section ensures that bottom product purity is also acceptable. That would be my preferred solution for dealing with inadequate APC engineering attention. Although there is another solution: Set up an inference CV3 called fractionation using a combination of top and bottom inferences as follows: CV3 = fractionation = top impurity + bottom impurity

LC LC

MV1

PI LC TI

FIG. 1

We have thus created a CV3 that is not parallel but rather orthogonal to CV1 by using process engineering knowledge. Associate CV3 with reboiler steam, MV2, and tune it to move only very slowly. Note that we have associated MV2 also with reflux valve position, CV 2. If the operator demands more fractionation than this column can deliver the MVPC should be configured to ignore CV3. HP

Tray 6

Tray 25

Tray 30

A distillation column candidate for APC.

MV2 FC

The author is a principal consultant in advanced process control and online Steam

optimization with Petrocontrol. He specializes in the use of first-principles models for inferential process control and has developed a number of distillation and reactor models. Dr. Friedman’s experience spans over 30 years in the hydrocarbon industry, working with Exxon Research and Engineering, KBC Advanced Technology and since 1992 with Petrocontrol. He holds a BS degree from the Israel Institute of Technology (Technion) and a PhD degree from Purdue University.

HYDROCARBON PROCESSING JULY 2009

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THE COL D, HARD FACTS Pro t e ct in g C o m p a n i e s and Their People Worldwide Our insulation systems are performance proven for use in below-ambient and cryogenic applications. But, we also provide peace of mind for you and your company. Be assured that, in addition to saving energy dollars, using FOAMGLAS® insulation provides the precise process control you require. Because it is 100% glass, it will not burn, and it is impermeable to moisture in liquid and vapor forms, thereby ensuring constant thermal efficiency for LNG applications. Contact our technical experts today to learn how FOAMGLAS® insulation can be the solution for your projects.

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HPIN ASSOCIATIONS BILLY THINNES, NEWS EDITOR

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Debating America’s energy future In the weeks and months ahead, Congress and the administration will be making decisions that could shape the US’ energy future for decades to come. The American Petroleum Institute’s Partnership for America’s Energy Security is working to inform people about the US energy situation and to help them communicate their views to members of Congress and other policymakers. Improved com- This viewpoint editorial munication about was written by Jack Gerard, the president energy is vital because of the American many Americans still Petroleum Institute lack a basic knowledge of the country’s energy challenges. The Partnership is trying to change this by creating a robust public dialogue. The more transparent the debate, the more likely good public policy will be achieved. The oil and natural gas industry supports President Obama’s commitment to strengthen US energy security and get the nation on the road to economic recovery. The industry agrees on the need for a comprehensive approach that includes increased reliance on renewable energy and improved energy efficiency. But the approach must also include oil and natural gas, which the US Energy Information Administration (EIA) projects will continue to meet more than half of the nation’s energy consumption in 2030. EIA also estimates that renewable energy (including ethanol, hydropower and biomass) supplied just 7% of the nation’s energy needs in 2007, with its share projected to rise to 13% by 2030. Thus, even if the US were to double its reliance on renewable energy (as the president has advocated), the country would still rely on oil and natural gas as its leading energy sources in 2030. The US oil and natural gas industry has the expertise and technology to produce the energy America needs to fuel economic growth, create jobs, generate significant

revenues for local, state and federal governments and bolster national security. However, companies cannot do so if held back by harmful, counterproductive taxes while being restricted from access to domestic oil and natural gas resources. The administration’s budget proposals include more than $400 billion in taxes and fees over the next 10 years, including revenues that would be raised from a carbon cap-and-trade system. We believe these proposals would depress investment in new domestic oil and natural gas projects, weaken the US’ energy security, and make it all the more difficult to put the economy back on the tracks. The administration does not appear to be listening to the majority of Americans who want to strengthen the economy by developing more of the country’s oil and natural gas resources. Two-thirds of Americans in exit polls in last November’s election said they supported increased offshore drilling. Unfortunately, the administration has been following a pattern of delay when it comes to increasing domestic oil and gas development. Our industry should be allowed to develop these resources that belong to the American people. For information about the Partnership for America’s Energy Security and assistance in communicating your views, please visit www.partnershipforenergy.com. HP

The Women’s Global Leadership Conference held a well-attended satellite event in Dubai, UAE, in late May. The one day conference brought together women in the energy industry from all over the world. Topics discussed included the growing opportunities for women in the Arab region, cultural differences, international business etiquette and how the energy industry impacts the global economy.

Hydraulic Institute issues lifetime achievement award Dave McKinstry, vice president of business development and special projects for Colfax Corp., recently received the Hydraulic Institute’s (HI) lifetime achievement award. HI’s board of directors presents the award to a deserving professional who has done significant work to promote pump technology during the course of his career. “Dave has made significant contributions to both Colfax and the pumping industry over the past 50 years, so we’re very proud the Hydraulic Institute has honored him,” said John A. Young, president and CEO of Colfax. McKinstry has served HI in a variety of capacities, including his current leadership roles on the HI board of directors as vice president of technical affairs and as chairman of the International Organization for Standardization’s (ISO) ISO/TC 115 SC-3 subcommittee for pump application standards. McKinstry is also chairman of HI’s Positive Displacement e-Learning project, which compiled an authoritative positive displacement pump training document with 400 pages of slides and 1,600 illustrations. Engineers who complete the course and demonstrate their knowledge of its contents can earn professional development hour credits required by their states’ licensing authorities. “Dave is an international ambassador for HI, working with Europump and ISO,” said Robert Asdal, executive director of HI. “He is widely regarded and respected for his domestic and international knowledge of pump companies, the pump industry and their associated standards. He bridges the gap between standards development, technical/business strategy and executive leadership.” McKinstry entered the pumping industry in 1957 and has held many senior-level positions in sales, marketing and corporate development. He earned a bachelor’s degree in engineering from the University of Missouri, Rolla, and is a licensed professional engineer. HP HYDROCARBON PROCESSING JULY 2009

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Gold or Coal? Why ‘or’? The rising demand for energy has contributed to the comeback of coal – which has a golden future. Global reserves are vast. The task now is to make the most of it. Lurgi has a decisive edge in coal technology owing to its decades of experience in this ﬁeld. We command reliable processes for generating syngas from coal. This gas can be converted into synthetic fuels using the Fischer-Tropsch technology or via the intermediate product methanol. Such fuels contain substantially less hazardous substances than oil-derived fuels. Besides fuels, Lurgi can also convert these gases into valuable petrochemical products. In future, also the environment will be protected more than ever before in coal gasiﬁcation. Lurgi’s state-of-the-art technologies as well as its innovative CO2 management will shape the future. As you can see, coal is the new black gold.

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LNG players are living in a time of falling gas demand, plunging prices and a world awash with LNG. In 2008, global LNG trade reached 171.1 million metric tons (MMton), which represented a 0.4% (or 0.7 MMton) decline compared with 2007. Although in 2008, LNG imports in Asia and Europe were stronger than 2007 by approximately 4.5%, LNG imports in the Americas posted a massive decrease (40.5% or 7.6 MMton). This was driven by a substantial decline in the US. European buyers showed the highest growth in LNG imports in 2008, followed by Asia, whereas the significant drop in US imports counterbalanced the LNG trade (Fig. 1). These and other findings are assessed in a recent report from FACTS Global Energy, headquartered in Singapore.

• Healthy growth in gas demand for residential and commercial sectors. China imported 0.4 MMton of additional LNG in 2008 compared to 2007, which represents a nearly 14.5% year-overyear hike. The country increased its spot purchases, particularly in the second and third quarters to cover peak demand from the Olympic Games. Indian imports declined by 2.3%, primarily due to a switch by many end-users to naphtha toward the end of 2008. This was when oil prices plunged faster than LNG, making naphtha a cheaper fuel for fertilizer production and power generation than LNG. The country was very active on the spot LNG market, receiving over 46 cargoes in 2008, according to this analysis. Europe. Overall in 2008, European LNG

demand grew by 1.9 MMton, chiefly underpinned by robust demand in Spain. That nation represented more than half of all 2008 European LNG imports and was the main reason that Europe was the fastest-growing regional market last year. Spain was the world’s fastest-growing LNG importer last year in terms of volumes with an increase of 13.9% or 2.6 MMton, entirely due to the strong growth in the power generation sector. With this increase, it consolidated its position as the world’s third-largest importer after Japan and South Korea. Belgium and Greece are the other European countries where imports increased, according to FACTS’ analysis.

Americas. LNG demand in the Ameri-

cas dropped by 40.5% in 2008. US LNG imports plunged in 2008 by nearly 55%, accounting for only 7.2 MMton in 2008, against 15.8 MMton a year ago mainly as a result of a strong hike in domestic natural gas production, stemming from unconventional sources. The massive drop in US imports was slightly countered by the increase in Mexican imports at the Altamira terminal and the commissioning of the Costa Azul terminal in second quarter 2008. Argentina started importing LNG in the third quarter of 2008. The country faced gas supply shortages during the 2008 summer peak consumption period and turned towards LNG imports to meet the demand gap. The country imported 0.4 MMton of LNG in 2008. LNG supply. The only supply growth originated from the Atlantic basin in 2008, while production from the Pacific basin and Middle East dropped by nearly 1.5% and 0.1%, respectively. As a result, a substantial number of Atlantic basin cargoes were diverted to Asia, for a total of 14.1 MMton—approximately 12% of the region’s LNG supply, according to FACTS’ estimates (www.FGEnergy.com). Nameplate global liquefaction capacity is slated to grow to about 240 MMton by the end of 2009. This forecast represents a significant increase from its 2008 level of about 197 MMton. The majority of new LNG export capacity expected for 2009 startup is in the Middle East.

Million metric tons

Asia-Pacific. Despite the global economic recession, LNG imports into Asia increased 5.1 MMton. Demand was particularly strong for the first three quarters of 2008 and then began to wane as decreased economic activity in importing countries led to lower gas demand. In 2008, Asia-Pacific’s main LNG supply sources were the Pacific basin and the Middle East. These two regions represented 56% and 32%, respectively, of total LNG supply to Asia-Pacific markets. The region also increased its reliance on supplies diverted from 140 10 4.5% the Atlantic basin. Imports from 4.6% 5 2007 120 the Atlantic basin accounted for 0 2008 112 117.1 Change, % 12% of total 2008 Pacific Rim –5 100 LNG purchases. –10 80 –15 Japan, the world’s largest –20 LNG market, showed a 3.7% 60 –25 average annual growth rate in its 40 –30 2008 imports compared to 2007 40.9 42.8 -40.5% –35 levels due to several issues: 20 –40 • Unexpected nuclear power 18.9 11.2 –45 0 plant shutdowns Asia-Paciﬁc Europe Americas • Attractive LNG prices Source: FACTS Global Energy compared to oil prices for the FIG. 1 LNG demand growth shows regional disparities between industry sector in the first half 2007 and 2008. of the year

Percentage

LNG outlook: spare global capacity and weak demand

Path forward. Asian LNG demand, which only a year ago needed a steady stream of Atlantic basin LNG to satisfy its appetite, now looks decidedly sluggish. Consequently, the likelihood of Asian cargoes seeking markets west of Suez this year is strong. However, the problem is compounded by soft energy demand in markets west of Suez, not to mention a slew of new LNG supply coming onto nearly-saturated global markets before year-end.

HYDROCARBON PROCESSING JULY 2009

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HPIMPACT Demand. According to the Asian Development Bank, Asia’s economic growth will be at its weakest since the 1998 financial crisis as the global recession hurts exports. As a result, FACTS believes that AsiaPacific LNG demand will drop back by just under 5% to 112 MMton in 2009 compared with the previous year. The fall will be chiefly led by a significant decline in Japanese imports. There is no shortage of LNG import capacity to accommodate increased LNG imports. In addition to the 68 MMton of existing import capacity, North America this year will commission at least three new facilities with a combined import capacity of over 33 MMton/yr. More capacity will follow in 2010. US receiving terminals will therefore be greatly under-utilized this year, even if imports were to double from their 2008 level. But the somewhat scant amount of additional LNG supply coming online over the next few years should quell any speculation that the pendulum is swinging from a seller’s to a buyer’s market again. While FACTS’ analysts do not assume any further delays in new projects under construction and expected online in the 2009–2012 period, there could be a drop-off in new capacity additions for the 2012–2013 period.

Prepare for the upturn: be lean, prioritize, focus on strategic intent The need in a downturn is an actionable plan with strong leadership and a commitment to carry it out. So said Paul Newman, global manager for service and implementation with Shell Global Solutions. Speaking recently in Barcelona, Spain, at the first of the company’s three annual regional symposiums, he shared his perspective on survival tactics for the present economic slowdown. Mr. Newman, who began his career in the oil and gas industry as a refinery process engineer, observed that “as operational folk, we’re players, not victims.” He revealed Shell’s key business concepts and a few ideas about “what’s important”: • Stay focused on health, safety and environment. It’s a “table stake,” he noted. “We can have some focused asset integrity around critical items. And if we do that, then we have to put some controls around it, and those controls would be around a risk assessment framework.”

• Don’t concentrate entirely on fixed costs. This stops you from doing the right thing. • Examine work processes, speed and acceleration. Look at internal processes that do not go fast enough to generate the reactivity that is needed, especially in a constrained economy.

in 2012. “Maybe you’ve got enough confidence to defer and you can convince yourself, because you’re doing it in a conscious, calculated, quantifiable way and pushing those costs out toward a time when you can afford to do it,” Mr. Newman suggested. Navigating the storm. Karl Rose, chief

Cost leadership. The central tactics

in achieving cost leadership, according to Mr. Newman, have become a Shell mantra: eliminate, simplify, standardize and automate. If you can simplify the entire contracts and procurement process, then you’re able to standardize the methodologies. Complexity costs a company a lot of money, thus avoid it. Simplicity can equate to cost-effectiveness. Then, when you’ve standardized, you can start to automate some of those work processes. By automating, you can free up people to do more value-adding work. Reliability and plant peak performance are vital for process plants to succeed. It might not feel like that’s an issue now because some of our plants are underloaded in the refinery world. They could be at only 70% utilization. However, the plants have to be ready to run when the upturn comes. In addition, “the CO2 debate will not go away. There will be carbon credits and carbon capping; there will be regulation,” he noted. So in the downturn, if you can start to manage your energy costs and reduce your CO2, then you’re ready for the upturn in terms of carbon emissions. Maintenance plan. So what are the

hardware fixes and what are the process fixes that refiners need to put in now to ensure that they’ve got the right level of activity ready for the upturn? You can’t do everything, you can’t have an expensive preventive maintenance plan for all your assets; you have to really select those critical equipment items, according to Mr. Newman. To prioritize systems, he advised processors to feed in their corrosion allowances, look at the remnant life of the asset—how long is it going to run—and put in some confidence rating based on historic data. These inputs give you an inspection interval. “And perhaps you can start to increase those inspection intervals,” he said. Perhaps you can take an expensive piece of equipment outside of a turnaround or shutdown, and schedule it for the next one

strategist with Shell International, was another presenter at the company’s seminar. He echoed the importance of analyzing the best ways for dealing with volatility and uncertainty. When formulating a sound business plan, Shell uses scenario planning as its main strategic tool. He forecast that the world will see a step change in energy use due to emerging markets hungry for products. Supplying “easy” oil and gas will struggle to keep pace. Increasingly, energy use is expected to be based on coal. Mr. Rose projected that 70% to 80% of the expected energy demand increase will be satisfied by coal. This is going to put a tremendous stress on global CO2 emissions. In the short term, there are impacts on the industry’s ability to invest. “Shell expects to keep investment levels constant for 2009,” according to Mr. Rose. This is running about $30 billion to $32 billion, a level unchanged from the corporation’s plans before the financial crisis. Monitors. One of Shell’s important indicators is the investment level taken by OPEC in spare capacity. A key question is whether those producers are going to be able to maintain their production and increase it when recovery comes. Also interesting will be to see how costs are going to develop during this recession. “This is one of the areas where the industry will see opportunity and not only a threat within this downturn,” Mr. Rose noted. “We do believe that fundamentally the energy industry has got a very, very good future ahead of itself. The world will need a lot of energy, maybe twice as much, but at half of the carbon dioxide,” according to Mr. Rose. Companies must be strategizing now to compete and win in such a carbonconstrained environment. HP Coming next month Look for the August issue of Hydrocarbon Processing, which features a Special Report on Fluid Flow and Rotating Equipment. HYDROCARBON PROCESSING JULY 2009

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Safe, quick method to remove coked refractory from risers The risks involved to workers using traditional methods for removing coked refractory in confined spaces can be avoided by using a new system. Claimed to be a world’s first, Sydney-based Silver Raven Pty. Ltd. has developed a remotely controlled water blasting tool for removing the coked refractory from reactor risers. The new technology not only replaces high-risk manual jack hammering methods in confined spaces, but also preserves the integrity of the vessels being refurbished. During late 2008, the company carried out a series of tests with the assistance of Andreco Hurll Refractory Services Pty. Ltd., which provided sample blocks and panels. The tests were designed to determine whether ultra-high water pressure could be used to break up super-hard reinforced refractory. Positive results were obtained after a number of attempts. This led to turnaround management company Transfield Services Pty. Ltd. becoming involved. This company assisted by obtaining a section of redundant reactor riser lined with refractory-filled hex mesh impregnated with coke. When the new technology, called the Silver Sonic Mk. 1, sparked a great deal of interest, the company arranged a comprehensive trial using the redundant riser (Fig. 1).Refinery industry personnel who attended were impressed by the effectiveness of the new system. In particular, the visitors were able to assess the potential benefits: • Safety. It is no longer necessary to have personnel inside a confined space using high-risk jack hammer methods to break out coked refractory. • Speed. The Silver Sonic Mk 1. is claimed to be quicker than jack hammers. • No vessel damage. Hex mesh, anchors and the vessel remain intact and undamaged. Following the successful trial demonstration, Silver Raven Pty. Ltd. provided its services to remove coked refractory from a reactor riser onsite during a refinery shutdown. Space inside the reactor was limited, so the unit was reconstructed in a modular articulated format to allow ease of handling and setup.

FIG. 1

Water blasting tool removes coke from reactor riser’s hex mesh.

Access to the top of the riser was difficult and the Silver Sonic equipment had to pass through a 600-mm-diameter manway before it could be effectively deployed. The team then had to operate the system under confined space conditions inside the reactor dome. Following the removal process, inspectors reported that 99% of 34.5 sq m of hex-mesh refractory—along with 4.5 sq m of reinforced castable material within the 1,100-mm-diameter vessel—was removed after a single pass. The total 39 sq m were removed in 72 hours. Select 1 at www.HydrocarbonProcessing.com/RS

Plastic LPG pipe eliminates corrosion risk KPS, a petrol pipe manufacturer, has launched what is claimed to be the firstever plastic pipe for liquefied petroleum gas (LPG). The company has applied its ATEX-compliant pipe technology to the As HP editors, we hear about new products, patents, software, processes, services, etc., that are true industry innovations—a cut above the typical product offerings. This section enables us to highlight these significant developments. For more information from these companies, please go to our website at www.HydrocarbonProcessing.com/rs and select the reader service number.

LPG fuel market. The LPG pipe offers the same conductive properties as the company’s petrol pipes. “The pipes presently used for LPG fuel are either made entirely from steel or steel with a plastic coating,” according to Fredrik Hellner, the company’s sales and marketing director. “Corrosion, both external and internal, is a big problem and poses significant risks for leakage and damage to cars and dispensers. Our pipes are corrosion-free, offering considerable advantages in terms of safety, durability and cost efficiency.” KPS’s LPG pipe is 100% plastic with a permeation liner and conductive inner layer. The semiflexible pipes are claimed to be easily rolled out onsite, end-to-end with no welding needed. “At a recent installation in France, the LPG pipe installation took less than one day, which also included pressure testing,” Mr. Hellner says. Due to LPG’s green fuel properties, the market for LPG is growing at a rate of approximately 8% to 10%/yr. It is a commonly used green fuel in Italy, Poland and Turkey, and is on the rise in France, Germany and the UK, according to KPS. Select 2 at www.HydrocarbonProcessing.com/RS

Climate-friendly biofuels pilot plant goes onstream Süd-Chemie AG and The Linde Group are producing climate-friendly biofuels based on lignocellulosic biomass. A pilot plant was officially opened at Süd-Chemie’s research center in Munich-Obersendling in April 2009. This pilot plant uses cereal straw to manufacture up to 2 ton/yr of bioethanol fuel. The new process developed by the two companies allows biofuels, such as ethanol, to be extracted from plant matter containing cellulose (wheat straw or maize straw) with the aid of enzymes. The new pilot plant represents a scaled-down version of the entire integrated manufacturing process or biorefinery required to convert straw into bioethanol. Compared with the first-generation biofuels already in use—such as biodiesel made from rapeseed oil—second-generation biofuels are claimed to offer a signifiHYDROCARBON PROCESSING JULY 2009

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Learn to apply these tools and others, as well as best practices in our Applied Maintenance Management seminar. Looking for Reliability Engineering training? We offer that too! For a list of course dates and locations go to www.jmcampbell.com/HCP For a FREE subscription to the Campbell Tip of the Month go to www.jmcampbell.com/TIP2

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cant improvement in terms of climate and energy balances, including higher potential to reduce carbon dioxide emissions. In addition, second-generation biofuels do not compete with cultivation of either food or animal feed. New legislation to implement the European Commission’s climate and energy policy specifically promotes secondgeneration biofuels.

tural fiber and convert it to sugars, which are fermented and distilled into ethanol. The new deal continues the collaboration announced in November 2007 to investigate other biofuels, researching new enzymes to convert biomass directly into components similar to gasoline and diesel. Codexis will expand research in the US and at a new research center in Budapest, Hungary.

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Cryogenic swivel with active sealing system

Improved sulfur oxide reduction technology

Framo Engineering AS has developed a cryogenic swivel that is claimed to keep bending of flexible pipes to a minimum. The swivels are used at the A-frame base for each line and also as a hang-off point for all the flexible pipes at the top of the A-frame. The cryogenic swivel has been qualified to the following requirements: • Operation between 30°C and –190°C up to a pressure of 16 bar • Five years without seal change-out and 25-yr design life without need to replace other mechanical components • Capable of operating in rain and sea spray without needing external insulation • N2 over-pressurization system between dynamic seals to prevent water ingress or gas leakage from the swivel • Self-lubricating seals and bearings • Three seals/double barrier between LNG and external environment. The design is based on Framo Engineering’s extensive record of swivel stacks in continuous operation since a first installation in 1997.

Albemarle has released a sulfur oxide (SOx ) reduction additive called SOxMASTER; it is claimed to provide unique features that are not available from conventional additives: • Superior stability under commercial fluid catalytic cracking (FCC) conditions • Improved regenerability • Lower sensitivity to the availability of O2 in the regenerator (resulting in better performance in partial-burn units). The product is formulated to meet the most difficult challenges of SOx reduction and a potential solution for tough applications. It is also suited for reactor-to-regenerator FCC applications, which run with partial burn in the first regenerator and often at very high temperatures in the second regenerator. Other benefits of the technology are that it contributes to E-cat activity and unit conversion—thus consumption of FCC catalyst can be reduced—and it has a lower CO promotion activity. Using conventional additives in deep partial-burn regenerators can upset the CO 2/CO balance. This leads to higher regenerator temperature and conversion loss due to the promotion ability of the additive. SOxMASTER has a much smaller effect on regenerator operation in deep partial burn. Commercial data are claimed to demonstrate the product’s superior stability. Conventional additives lose half of their initial activity within days. The new technology enables lower SOx emissions to continue for several weeks even after the additive is stopped. In addition, Albemarle has developed a new proprietary SOx model that explains the commercial performance of additives in all FCC unit designs. This model, based on commercial experiences from FCC units globally, considers the activity of fresh SOx additives, various effects of the FCCU operating conditions, and deactivation and regeneration of these additives.

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Collaboration speeds arrival of next-generation biofuel Royal Dutch Shell plc and Codexis, Inc. expanded their agreement to develop better enzymes that could accelerate commercialization of next-generation biofuels. Shell also increased its equity stake in Codexis. As part of the agreement, Codexis will work closely with Shell and Iogen Energy Corp. to enhance the efficiency of enzymes used in Iogen’s cellulosic-ethanol process. The Iogen demonstration plant in Ottawa, Canada, produces hundreds of thousands of liters of cellulosic ethanol from agricultural residue, such as wheat straw. The research program with Codexis aims to enhance the Iogen process and shorten the timeline to full-scale commercial deployment. In the Iogen technology, enzymes break down cellulose in agricul-

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North America Mu s t a n g h a s a c o n t r a c t w i t h ConocoPhillips for a distributed control system (DCS) modernization project at ConocoPhillips’ San Francisco refinery in Rodeo, California. The project scope includes the re-instrumentation and upgrade of existing control systems for crude and coker units and the supply of a coke drum interlock system. Mustang is also responsible for the integration and fabrication of two remote instrument enclosures to house the control system equipment. Mustang’s process plants business unit also has a contract with D-Cok for the front-end loading (FEL) engineering services to study the addition of coke drum bottom unheading devices at the refinery. D-Cok is providing project management services to develop a scope and cost estimate for the delayed coker upgrade project. The proposed upgrade includes automating the coke drum unheading process. The upgrade would also have the benefit of reducing cycle time-related operating costs. Mustang has executed numerous automation projects at this refinery, including the last three DCS modernization projects and two projects for new grassroot units. Pemex Gas y Petroquímica Básica has awarded a project to a consortium of ICA Fluor and Linde Process Plants for the construction of a cryogenic plant at the Poza Rica gas processing complex in the state of Veracruz, Mexico. Fluor will book its share of the approximate $268 million project award value in the company’s second quarter. ICA Fluor, together with Linde, will be responsible for the engineering, procurement, construction, testing and startup. The project is scheduled to be executed over a two-year term starting in August 2009 and, when complete, the facility will process 200 million cfd of natural gas. Linde has a new long term contract with PdV Midwest Refining LLC to supply hydrogen to the company’s CITGO oil refinery in Lemont, Illinois. The hydrogen will be produced by a new plant that Linde is building for CITGO’s production of ultra-low-sulfur diesel fuel. The

plant, which is expected to begin operating in 2010, is being engineered, built and installed by Linde Process Plants. Site construction has already commenced for the 45-mmscfd hydrogen plant, which Linde will own and operate under a long-term supply contract. BASF is building a new plant for the production of methylamines at its integrated Verbund site in Geismar, Louisiana. Operation is scheduled to start in 2011. The methylamines will serve as raw materials for some 20 different specialty amines produced by BASF at existing facilities in Geismar.

South America Refineria del Pacifico-CEM plans to build a $10 billion refinery in Ecuador’s coastal Manabi province. Construction will begin in 2010 and the refinery is expected to begin operations in 2013, processing 300,000 bpd of crude oil. KBC Advanced Technologies PLC has already concluded a market analysis and technical assessment study on the project. TREND ANALYSIS FORECASTING Hydrocarbon Processing maintains an extensive database of historical HPI project information. Current project activity is published three times a year in the HPI Construction Boxscore. When a project is completed, it is removed from current listings and retained in a database. The database is a 35-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc. Many companies use the historical data for trending or sales forecasting. The historical information is available in comma-delimited or Excel® and can be custom sorted to suit your needs. The cost of the sort depends on the size and complexity of the sort you request and whether a customized program must be written. You can focus on a narrow request such as the history of a particular type of project or you can obtain the entire 35-year Boxscore database, or portions thereof. Simply send a clear description of the data you need and you will receive a prompt cost quotation. Contact: Lee Nichols P. O. Box 2608 Houston, Texas, 77252-2608 Fax: 713-525-4626 e-mail: Lee.Nichols@gulfpub.com.

Middle East ExxonMobil Chemical Technology Licensing, LLC has an agreement with Saudi International Petrochemical Co. (Sipchem) to license ExxonMobil’s tubular high-pressure low-density polyethylene (HPPE) process technology for Sipchem’s new ethylene vinyl acetate (EVA) plant. The 200,000-metric tpy plant will be built at Sipchem’s site in Jubail Industrial City, Saudi Arabia, as part of Sipchem’s third phase projects. The plant will be operational by the end of 2013. The design of the Sipchem plant will be based on current reactors operated by ExxonMobil Chemical to manufacture EVA and low-density polyethylene (LDPE) products, allowing Sipchem to produce a wide range of both EVAs and LDPE grades. In addition to Sipchem, ExxonMobil has eight licensees of its proprietary HPPE process technology around the world. Qatar Kentz WLL has a multimillion dollar contract with Qatargas Operating Co. Ltd. The project includes the electrical, instrumentation and telecommunications work on the new Phase 6 liquefied natural gas storage and loading facility in Ras Laffan Industrial City, Qatar. Kentz’s work will commence immediately, with the construction phase of the project scheduled for completion in December 2009.

Asia-Pacific Mustang has entered a joint venture with Petronas and MISC Berhad to develop integrated floating LNG liquefaction, storage and offloading solutions, using Mustang’s LNG liquefaction technologies. The joint venture’s first project-related activity will be the development of the front-end engineering design (FEED) for a floating LNG vessel to be located offshore Malaysia. The project is expected to achieve first gas from a floating LNG FPSO facility in 2013. The group’s approach is for a long-term commitment to assist gas owners with full project development of gas reserves in Malaysia and other countries worldwide, using cost-effective floating LNG FPSO solutions. It will also focus on the adaptation, enhancement and development of floating LNG technologies and project HYDROCARBON PROCESSING JULY 2009

I 25

HPIN CONSTRUCTION implementation with the goal of being the provider of choice for LNG FPSO services. Foster Wheeler Energy Ltd. and Foster Wheeler (G.B.) Ltd. have contracts with CTCI Corp. for the supply of a carbon monoxide boiler for CPC Corp.’s new residue fluidized catalytic cracker (RFCC) at CPC’s Talin refinery in Kaohsiung, Taiwan. CTCI is the prime contractor for the engineering, procurement and construction of CPC’s RFCC

project. Foster Wheeler’s scope includes a proprietary Foster Wheeler-designed incinerator to destroy carbon monoxide in the waste gas stream from the RFCC, a boiler section to recover heat from the resulting flue gas and a selective catalytic reduction flue gas treating system to minimize emissions of nitrogen oxides to the atmosphere. Japan Butyl Co. Ltd. will increase its butyl rubber production capacity by 18,000

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I JULY 2009 HYDROCARBON PROCESSING

tpy at its plant in Kawasaki, Japan. This expansion will rely on ExxonMobil Yugen Kaisha process technology and will increase capacity to 98,000 tpy when the project is completed in late 2010. One of ExxonMobil’s new process technologies to be used is a proprietary advancement that reduces the butyl polymerization reaction temperature from -95°C to -75°C. This advancement should provide energy and capital investment savings. Market testing is expected to commence in 2010. ExxonMobil Chemical recently broke ground on a technology center in Shanghai, China. The new 27,000-square meter facility will be built and operated by ExxonMobil Asia Pacific Research and Development Co. Ltd. The initial investment in the technology center and related equipment is $70 million. The center will house laboratories and product demonstration facilities, providing technical services and a range of application development capabilities for ExxonMobil’s polymer products and plasticizers. Initial employment will be approximately 200 people. The facility is expected to be operational in 2010. Brahmaputra Cracker and Polymer Ltd. (BCPL) has awarded contracts for the license and basic engineering of two new chemical plants to Lummus Technology. BCPL’s ethylene plant, which has a design capacity of 220,000 metric tpy, will utilize Lummus Technology’s proprietary ethylene technology. The downstream polypropylene plant, which has a design capacity of 60,000 mtpy, will use Lummus Technology’s gas-phase polypropylene technology. The two plants will be built in Lepetkata, Assam, India. Fujian Refining and Petrochemical Co. Ltd. (FREP) recently announced that the 8 million tpy crude vacuum distillation unit in its new integrated refining and petrochemical complex has begun startup. The complex is located in Quanzhou, Fujian Province, China. Other major units are expected to come online during a phased startup over the next several months. FREP’s refining and petrochemical complex is expected to be in full operation in the second half of this year. FREP is expanding an existing refinery from 80,000 bpd to 240,000 bpd. The upgraded refinery will refine primarily sour Arabian crude. HP

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Select 79 at www.HydrocarbonProcessing.com/RS

HPI CONSTRUCTION BOXSCORE UPDATE Company

Plant Site

Project

Capacity Est. Cost Status Licensor

Engineering

Constructor

UNITED STATES California

ConocoPhillips

San Francisco

Controls, Coker

None

Poza Rica Marcona Marcona Marcona Marcona Marcona

Cryogenic Gas Plant Ammonia Nitrogen Fertilizer Complex Offsites Urea Granulation Utilities

Syzran Syzran Syzran Syzran Bratislava Cartagena Huelva La Coruna Muskiz Muskiz Muskiz Muskiz Muskiz Muskiz Kremenchug Kremenchug Kremenchug Kremenchug Hatfield Colliery

Gas Compression (1) Gas Compression (2) Gas Compression (3) Gas Compression (4) Polyethylene, LD LNG Terminal (4) EX LNG Terminal (3) EX LNG Terminal (2) EX Butadiene Cogeneration Coker Coker, Naphtha Merox Sulfur Deisopentanizer TO Hydrodesulf (HDS) TO Naphtha HDT TO Technology Consultancy Services TO Treater, Adsorption

Shell\Gladstone Ports Corp JV EnCana Corp Nexus Energy WEPEC Giuzhou Jinchi CNOOC Oil & Petrochem Hulunbeier New Gold Shaanxi Carbonification Bei Yuan Chemical Shijiazhuang Chem & Fbr PetroChina Tianjin Kaiwei Group Brahmaputra Cracker and Polymer Gujarat Narmada Valley Fertilizer Krishak Bharati Coop Ltd Krishak Bharati Coop Ltd Krishak Bharati Coop Ltd Krishak Bharati Coop Ltd Chennai Petroleum (CPCL) Mangalore Rfg & Petrochemicals Mangalore Rfg & Petrochemicals NOCL Hyundai Oilbank Co., Ltd. SK Energy Doosan Hyundai Oilbank Co., Ltd. PolyMirae Chinese Petroleum Corp CPC Corp CPC Corp

Gladstone Latrobe Valley Melbourne Dalian Guizhou Huizhou Hulunbeier Shaanxi Shenmu Shijiazhuang Sichuan Tianjin Lepetkata Bharuch Hazira Hazira Hazira Hazira Manali Mangalore Mangalore Undisclosed Daesan Incheon Undisclosed Undisclosed Yeosu Kaohsiung Talin Refinery Kaohsiung

LNG Gasifier FPSO Scrubber, FCC Urea Lube Hydroprocessing Ammonia Methanol Polyvinyl Chloride (PVC) Ammonia Hydrotreat, Resid Lube Hydroprocessing Cracker, FCC-Flexickr Ethyl Acetate Ammonia (5) Ammonia (6) Urea (1) Urea (7) Hydrocracker Distillation, Crude Distillation, VDU Scrubber, FCC Hydrotreat, Resid Hydrocracker IGCC Scrubber, FCC Polypropylene Hydrocracker CO Boiler Lubricants

Sonatrach Sonatrach EHC Suez Oil Processing Co NNPC

El Merk Facility El Merk Facility Suez Suez Warri

Processing, Oil Storage, NGL Ammonium Nitrate Ammonium Nitrate Alkylation, HF

98 600 1.06 85 RE 341

Karbala Al-Zour Mesaieed Ras Laffan Ras Laffan Undisclosed Ras Laffan Al Jubail Yanbu Khursaniyah Khalifa Port Ind Zone Ruwais Undisclosed

Refinery Utilities Methanol Gas Processing (1) Gas Processing (2) Gas Compression (1) Controls, LNG ABS Propylene Utilities (2) Complex Scrubber, FCC Gas Processing, Sour

140 Mbpd None 3000 m-tpd 850 MMscfd 850 MMscfd 25 MW None 200 kty 650 kty EX None 10 MMtpy None 60 MMscfd

Mustang

E 2011 Linde F F F F F

ICA Fluor|Linde Technip Technip Technip Technip Technip

E E E E F U U E E E E E E E P P P P P

Burckhardt Compression Burckhardt Compression Burckhardt Compression Burckhardt Compression Tecnimont

LATIN AMERICA Mexico Peru Peru Peru Peru Peru

Pemex Gas CF Industries Inc CF Industries Inc CF Industries Inc CF Industries Inc CF Industries Inc

200 MMcfd 2.6 Mtpy None None 3850 tpy None

268

EUROPE Russian Federation Russian Federation Russian Federation Russian Federation Slovakia Spain Spain Spain Spain Spain Spain Spain Spain Spain Ukraine Ukraine Ukraine Ukraine United Kingdom

Syzran Oil Refinery Syzran Oil Refinery Syzran Oil Refinery Syzran Oil Refinery Slovnaft as Enagas Enagas REGANOSA Petronor Petronor Petronor Petronor Petronor Petronor Ukrtatnafta JSC Ukrtatnafta JSC Ukrtatnafta JSC Ukrtatnafta JSC Powerfuel Plc

220

5 42 2115 28 2115 110 88 610 380

None None None None Mtpy None None None m-tpd MW m-tpd m-tpd m-tpd m-tpd None Mm-tpy Mm-tpy None None

1081

2010 2010 2010 2010 2012 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2011 2013

FW FW Axens FW Axens UOP Centry Axens Axens Axens UOP

FW Intecsa-Uhde|FW Sener FW Intecsa-Uhde|FW FW|Intecsa-Uhde Sener Ukrneftekhimproekt Ukrneftekhimproekt Ukrneftekhimproekt Ukrneftekhimproekt

ASIA/PACIFIC Australia Australia Australia China China China China China China China China China India India India India India India India India India India South Korea South Korea South Korea South Korea South Korea Taiwan Taiwan Taiwan

EX EX EX

RE RE RE RE RE

None 500 MW None 52 None 1750 m-tpd 9 Mbpd 1632 m-tpd 2000 m-tpd 50 Mtpy 700 m-tpd 48 Mbpd 2 Mbpd 280 Mtpy 150 tpd 1890 m-tpd 1890 m-tpd 3325 m-tpd 3325 m-tpd 46 Mbpd None None None 66 Mbpd 40 Mbpd None 52 Mbpd None 12 Mbpd Scfd 4 Mbpsd

1140

100 100

5200

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

2013 Siemens 2011 2009 2010 2010 2010 2010 2010 2013 2012 2011 2010

Belco UCSA CLG ACSA MCSA Chisso ACSA CLG CLG

2011 2011 2012 2014 2011

Belco CLG CLG

KBK Chem KBR KBR 2012 Saipem 2012 Saipem 2013 CLG

Belco LyondellBasell CLG

Siemens SBM UCSA CLG ACSA MCSA

UCSA

ACSA CLG CLG CB&I Lummus KBK Chem KBR KBR PDIL|Saipem PDIL|Saipem CLG Jacobs Jacobs

ACSA

CLG CLG FW

ACSA MCSA

SKEC

CLG CTCI|FW

U 2009

AFRICA Algeria Algeria Egypt Egypt Nigeria

Mbpd MMscfd Mm-tpd Mm-tpy m-tpd

E 2012 E 2012 F Carbon Holdings C P Exelus

Petrofac Petrofac KBR IE-SA

MIDDLE EAST Iraq Kuwait Qatar Qatar Qatar Qatar Qatar Saudi Arabia Saudi Arabia Saudi Arabia United Arab Emirates United Arab Emirates United Arab Emirates

SCOP KNPC Qatar Fuel Additives ExxonMobil ExxonMobil not disclosed Qatargas Arabian Petrochemical SABIC lbn Rushd Saudi Aramco Abu Dhabi Natl Chem Co Takreer Undisclosed

F P S F F P U F E E

MCSA Chiyoda Chiyoda

See http://www.HydrocarbonProcessing.com/bxsymbols for licensor, engineering and construction companiesâ&#x20AC;&#x2122; abbreviations, along with the complete update of the HPI Construction Boxscore. HYDROCARBON PROCESSING JULY 2009

I 29

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LIQUEFIED NATURAL GAS DEVELOPMENTS

SPECIALREPORT

Are floating LNG facilities viable options? Here’s how to evaluate technological and commercial issues of these units A. J. FINN, Costain Oil, Gas & Process Ltd., Manchester, United Kingdom

echnology developments in offshore liquefied natural gas (LNG) storage and transfer have made offshore LNG production commercially viable, even at plant capacities of 1 million tpy (Mtpy) to 2 Mtpy. Due to rising costs for onshore LNG facilities, floating LNG (FLNG) is cost competitive. Floating plants will use liquefaction processes based on turboexpanders to generate the refrigeration. This technology has been used onshore for small-scale LNG production and offers important advantages including: • Inherent process safety • Simple design • Ease of operation • Smaller footprint • Low topsides weight. The overall project cost and schedule to first LNG production can be competitive with base-load onshore production. FLNG plants will be much larger than the existing LNG plants that use turbo-expanders and this introduces significant new technical, engineering and safety considerations. The refrigerant compression system configurations and the associated compressor drivers is particularly a key area. The need for marinization and topsides interfacing with the hull are also novel aspects of liquefaction plant design. Techno-commercial issues associated with floating LNG and how they are resolved will be discussed.

Floating LNG potential. The difficulties with onshore LNG projects have renewed interest in offshore LNG production. Studies over the last 30 years have identified the main technology developments necessary to make offshore LNG production feasible.2 As well as process technology and plant design issues, advances in offshore LNG transfer and storage have been essential to the viability of offshore LNG. Developments in LNG transfer at sea have advanced to where several suppliers have commercial systems available. A decade ago, only one LNG storage system was proven for partially full operation at sea (i.e., robust enough to stand sloshing when partially full). Today, several LNG storage systems are certified and LNG shipbuilders can provide approved designs. There are several hundred “stranded” natural gas fields in the world of sufficient reserves (over 0.5 tcf ) to support a 1.0 Mtpy LNG plant for up to 10 years or more. FLNG facilities can be moved to a new gas field if production declines, which may extend the service life 30 to 40 years. Liquefaction of associated gas from oil production is also attractive, as it would otherwise be reinjected or flared. In all, about 100 prospects for FLNG plants producing < 1.0 Mtpy have been identified.3 Floating production, storage and offloading (FPSO) is conventional for development of “stranded” oil reserves, with well over 100 FPSOs now in operation. Several vessel lease and LNG shipping companies have the capability and know-how to consider LNG FPSO projects. Engineering firms have also developed the skills to see offshore projects to completion and successful operation.

Shortages from conventional sources. Increasing

demand for LNG has led to the upgrading of existing import terminals and new regasification facilities in the US, Western Europe, India and China. In parallel, deliveries of new LNG carriers are at record high levels. Several new LNG plants will start up in 2009, but many proposed LNG production capacities will not materialize, creating a shortfall in worldwide LNG production of up to 150 Mtpy by 2012. Lack of investment in new LNG production has been partly due to a shortage of sufficiently large gas fields near shore and lack of suitable plant sites. Some leading LNG producing nations have recently declared moratoria to maintain their indigenous gas reserves for domestic use. Final investment decisions on projects have been postponed because of escalating plant costs (due to shortages in raw materials and limited human resources in engineering and construction firms). It is unlikely that the many delayed or postponed LNG projects will be implemented soon.1

Cost and schedule advantages. Technology developments

and engineering studies have shown that cost estimates for LNG FPSOs at $700 tpy can be achieved. Virtually no onshore LNG projects meet this investment cost. Offshore LNG production is commercially viable now because LNG vessel costs are relatively low compared to the major infrastructure costs needed for onshore production including gas pipeline, jetty, LNG storage tanks, site preparation and construction facilities. FLNG projects usually demonstrate shorter time to commercial production compared to onshore projects, providing a more flexible solution to realizing LNG offtaking and sales opportunities. Floating LNG production has emerged from being prospective or “near future” technology to provide a competitive option to onshore LNG production and a solution to future LNG shortages. Liquefaction process evaluation and selection. For

many years, LNG plant licensors and engineering firms tried applyHYDROCARBON PROCESSING JULY 2009

I 31

SPECIALREPORT

LIQUEFIED NATURAL GAS DEVELOPMENTS

ing onshore technology and plant design concepts to prospective offshore projects—with little success. Offshore processing presents different engineering, project management and installation challenges compared to an onshore plant. These issues must be addressed to determine the optimal process technology and plant design. For offshore LNG to be commercialized, it is essential to gain the confidence of potential investors. Onshore LNG production is mature with well-established design concepts, engineering procedures and hazard mitigation practices. This experience is important for FLNG production but must be aligned with the unique requirements of an FPSO. Fundamental to ensuring the viability and acceptance of LNG FPSOs is selecting the best process technology. Criteria for evaluating process technology. A study completed for the United Kingdom Department of Energy indicated that expander-based process technology, proven on small-scale “peak-shaving” LNG facilities, had considerable merit for offshore LNG production.4 This conclusion counteracted “accepted wisdom” that considered offshore LNG plants should use similar liquefaction technology as large onshore plants (multicomponent hydrocarbon refrigerant or “mixed refrigerant”). Turbo-expander refrigeration cycles work by compressing and work-expanding a suitable fluid, typically nitrogen, to generate refrigeration at high isentropic efficiency (Fig. 1). The cycle gas is boosted in pressure by the expander’s brake-end. The first offshore LNG production studies included feed gas chilling by mechanical refrigeration to improve overall process efficiency, thus, increased LNG production.4 Expander technology was proposed for offshore LNG due to: • Inherent safety by avoiding liquid hydrocarbon refrigerants (and their storage), and potential fire and explosion hazards • Insensitivity to vessel motion as the refrigerant is gaseous and refrigerant distribution in the liquefaction heat exchangers is constant • Flexibility to changes in feed gas conditions and ease of operation due to process simplicity • Rapid startup and shutdown in a safe and controlled manner • A small number of equipment items with consequently a relatively small plant footprint and relatively low topsides weight. The capital cost of the processing and liquefaction facilities is only a fraction of the total investment cost for offshore facilities. Expander technology minimizes overall project cost, and represents the safest possible design. Subsequent engineering studies demonstrated three further important advantages for expander technology: Pre-treated natural gas feed

• Ease of modularization and construction due to process simplicity and low equipment count • Use of conventional well-proven cryogenic equipment maximizes competition among equipment suppliers and minimizes plant cost and project schedule • Turbo-expanders are very reliable with minimal maintenance requirements. Nitrogen expander process development. In the late 1980s, a dual turbo-expander flowsheet based on nitrogen refrigerant, was advocated for the Pandora field, offshore Papua New Guinea (see Fig. 2). The process is widely used for cryogenic liquefaction of industrial gas.5 The second, colder turbo-expander improves process efficiency by reducing the temperature difference for LNG subcooling (Fig. 3). Subsequently, a dual nitrogen expander process was developed for the proposed Bayu-Undan development.6 The European Union Azure Project concluded that this process is optimal for offshore LNG production of 1 Mtpy to 2 Mtpy.7,8 In proposing nitrogen refrigerant for the dual-expander flowsheet, methane refrigerant was also evaluated. Methane can reduce the specific power for liquefaction by several percent but this advantage is outweighed by the safety implications of using hydrocarbon refrigerant rather than inert nitrogen. This is due to an increase in equipment spacing, which decreases the Pre-treated natural gas feed

LNG product

Booster compressor

Warm expander

Cycle compressor

Booster compressor

FIG. 2

Cold expander

Dual turbo-expander flowsheet for gas liquefaction.

Temperature

LNG product

Cycle compressor

Booster compressor

Expander Heat duty

FIG. 1

Turbo-expander cycle for gas liquefaction.

I JULY 2009 HYDROCARBON PROCESSING

FIG. 3

Typical cooling curves for dual turbo-expander liquefaction.

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6/03/09

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SPECIALREPORT

LIQUEFIED NATURAL GAS DEVELOPMENTS

propensity of jet fires and blast pressures. Reducing the overall plant footprint is crucial offshore and dictates plant design and engineering decisions. A specific power consumption of less than 0.50 kWh/kg of LNG is typical for a dual-expander plant with efficient cycle compressors and turbo-expanders with optimized chilling from mechanical refrigeration.9,10 For high-pressure feed gas, specific power consumption can be less than 0.40 kWh/kg. Usually, the need for pressure let-down to remove (“scrub”) heavier hydrocarbons and high freezing point aromatics from the feed gas indicates this figure is only realistic for very lean feed gas (e.g., liquefied petroleum gas (LPG) is extracted upstream). Mixed refrigerant. The vast majority of base-load LNG

plants use a process wherein propane is used for natural gas cooling and a mixed-refrigerant is used for condensing and sub-cooling. This, and other mixed-refrigerant technology, including single mixed refrigerant and dual mixed refrigerant processes, have been assessed for offshore liquefaction. Mixed-refrigerant plants have a significant inventory of highly flammable hydrocarbon refrigerant including storage (to make-up refrigerant losses). The refrigerant should be ethane (or ethylene), propane and butane, extracted from natural gas feed or supplied from shore. This requires extra gas processing and fractionation or methods for safe unloading and loading of volatile, flammable hydrocarbons offshore. The complexity increases deck space and mitigation of fundamental safety concerns, which are major hurdles for implementation of mixed refrigerant technology offshore. Dual mixed-refrigerant technology has lower hydrocarbon inventories and gives lower flaring rates in the event of refrigerant compressor trip and refrigerant blow-off. It may be the most appropriate mixed-refrigerant technology available but no onshore liquefaction plant has implemented this technology yet.11 As well as safety concerns, liquid refrigerants rely on good distribution in the liquefaction heat exchangers, which is difficult to achieve with a moving vessel. Mixed-refrigerant plants also suffer if feed gas conditions vary and can take hours to stabilize after startup because precise blending of the refrigerant mixture is needed. Offshore, where startups and shutdowns may be relatively frequent, this may lead to loss in production. LNG FPSO plant design. Offshore LNG production can

use conventional process technology and equipment, see Fig. 4, for gas reception (including slugcatcher and filtration) and the pre-treatment section, consisting of acid gas removal, molecular sieve dehydration and mercury removal (for protection of the aluminum plate-fin heat exchangers in the liquefaction section). If the feed gas is rich in heavier hydrocarbons, they may need to be removed as condensate. Aromatics, particularly benzene, must be removed to avoid freeze-up. Compared to an onshore LNG plant, there is greater incentive to minimize upstream processing so lean natural gas, with low CO2 content is preferred. Plant capacity. Significant reduction in LNG production costs

is achieved with large LNG train capacities, typically up to 5 Mtpy. However, such plant capacities are infeasible with the deck space of a conventional LNG vessel hull and less than half this capacity is more realistic. Early engineering studies indicated that a single liquefaction train using dual nitrogen expander technology could have a capacity of about 0.75 Mtpy.12,13 A two-train liquefaction plant of approxi34

I JULY 2009 HYDROCARBON PROCESSING

Dehydration mercury removal

Liquefaction Fuel gas compressor

Acid-gas removal Inlet gas

Gas reception Condensate stabilization

LNG product

Fuel gas compressor Dehydration mercury removal

Liquefaction

Gas turbine generator

Waste-heat recovery

Gas turbine generator Gas turbine generator

FIG. 4

Waste-heat recovery

Simplified LNG plant diagram (electrical power generation for nitrogen cycle compressor drives).

mately 1.5 Mtpy capacity can be accommodated within the available deck space of a conventional hull (~145,000 m3 LNG). Using two independent LNG production trains, minimal equipment, reliable aero-derivative gas turbines, sparing of critical equipment and formalized preventive maintenance will increase the availability of the LNG plants to produce more than a single train onshore plant—over 98.5% based on scheduled shutdowns. So, equipment sizes are generally within the limits of industry experience, ensuring multiple potential suppliers and competitive costs. It also enables the plant to be laid out symmetrically to optimize topsides weight distribution and to simplify module design. A single train is viable for the feed gas pre-treatment upstream of liquefaction. A plant capacity of approximately 1.5 Mtpy with this overall offshore concept, has now emerged as the primary option for the majority of LNG FPSO projects being considered. OFFSHORE ENGINEERING

Engineering of an LNG FPSO brings together established methods from onshore LNG plants and oil FPSOs. It also includes several unique elements due to the complexity of the liquefaction system, the cryogenic equipment, large utility consumption (notably cooling water and possibly the electrical supply system) and the hazards of handling LNG in a relatively confined space. Design. Design of an LNG FPSO requires naval architects to coordinate LNG plant design and FPSO design practice to ensure optimal integration of the topsides (the processing plant and major utilities) with the hull and vessel systems (utilities, control and support). Work is ongoing with shipbuilders to optimize the design of their particular LNG storage systems and hull structures with the topsides layout to reduce overall weight and cost. On any FPSO, space is restricted since process facilities must be located away from the flare, helideck and buildings. An integrated approach between topsides designer and vessel designer helps establish appropriate and optimal plant design and layout strategies. An important concern with an FLNG is vessel response to wave motions and the plant and equipment design requirements to mitigate motion effects. Clearly, the first plants will be located in

LIQUEFIED NATURAL GAS DEVELOPMENTS relatively calm benign seas. By designing the vessel to weathervane to the wind, as is conventional for FPSOs, any tendency to roll will be virtually eliminated. Several specialist companies can accurately determine the effect of wave motions on vessel movement as a basis for engineering and design. Dual-expander technology is the most robust possible LNG technology with respect to vessel movement (and the easiest to restart if vessel motions become so excessive that operation must be stopped). There needs to be an understanding how the vessel movement influences the effective equipment weight and vessel deck flexing. Experience in designing cryogenic plants provides capability in pipework stress analysis and allowance for pipework contraction. Piping design for the liquefaction section (and including hull flexing) is an important activity in generating an optimized plant layout. Equipment. Process equipment influenced by vessel movement

due to wave motion should be located on the vessel centerline. All separators and columns on vapor/liquid service are potentially a concern. The most significant are the acid gas removal unit (AGRU) contactor and the amine regeneration column as maloperation can lead to CO2 freezing in the liquefaction section. Satisfactory performance, to maintain the treated gas CO2 level to 50 ppmv, requires multiple beds of structured packing and regular liquid redistribution to keep the downflowing liquid from tending to the column wall. Computational fluid dynamics are valuable in confirming the column internals design and avoiding excessive design margins on the column height. If, during operation, the treated gas CO2 content is excessive, the molecular sieve dehydration system may be overloaded if this was not considered in the design. The sensitivity dehydration system sensitivity should be evaluated for high CO2 to ensure a robust and optimal design. Engineering specifications and classification. Engi-

neering specifications and standards used for onshore LNG plants apply to topsides design, but all offshore facilities must be approved by a classification society such as Lloyds Register, Det Norske Veritas and the American Bureau of Shipping. Amongst the classification society activities and responsibilities are: • Combine best practice from oil and gas carriers • Use existing standards as far as feasible • Add specific LNG and leakage considerations • Formally qualify novel technology • Use risk assessment for novel hazards. The classification society has a key role in producing the coarse safety assessment at an early stage of engineering to identify hazards and risk mitigation measures and procedures. At this juncture the plant design, plant layout and environmental and safety studies should be detailed enough to proceed to permitting. The classification society acts as a formal design authority and produces the formal safety assessment for detailed engineering. A key focus of recent engineering and technical development is how the classification society requirements differ from conventional engineering standards for LNG plants and ensures that the proposed equipment and plant are compliant. Classification society verification, auditing and approval of design methods and materials needs close cooperation between suppliers, classification society and the engineering team. Plant standardization. Engineering of a floating liquefaction

plant is a quite a different logistical and scheduling challenge com-

SPECIALREPORT

pared to an onshore plant. An offshore LNG plant is designed as modules for installation ease and for minimal “hook-up” of pipework, instrumentation and services to minimize the schedule to first LNG. Strict fabrication and construction timescales must be met in a shipyard or the construction of several ships may be delayed. The whole process concept, flowsheet, plant design and all aspects of engineering must be aligned with minimizing weight, ensuring good weight distribution and supporting the overall modularization strategy. Offshore LNG requires a “construction-led” approach to engineering using standard systems and module designs. In previous work, a feed-gas composition suitable for a large majority of prospective projects (particularly offshore Australia and West Africa) was used as a design basis.9,10 Standard plant design handles CO2 levels in the feed-gas up to 4 mol%. The design has an upstream condensate removal system with space allocated on deck for further equipment to remove greater levels of feed-gas CO2 and sulfur compounds. If necessary, the feed-gas pressure can be increased to over 40 bars. For specific feed-gas conditions, the performance and LNG production capacity of a standard plant is calculated by process simulation. Equipment changes or additions can be made for specific feed-gas conditions, but the LNG plant design should be standardized as much as possible. The standard plant approach minimizes engineering time, reduces changes to equipment and topsides design, and enables the overall delivery schedule to be reduced by many months compared to a customized plant design. This overall approach is also consistent with relocating a production facility with minimal equipment changes in the future. LIQUEFACTION SYSTEM

A two-train liquefaction plant of 1.5 Mtpy capacity requires up to 90 MW for nitrogen cycle compression. Onshore LNG plants use refrigerant compressors driven by industrial heavy-duty gas turbines, but these are not practicable offshore. Aero-derivative gas turbines. These have long been proposed for offshore LNG and have a number of important advantages over their industrial counterparts that include:4 • Smaller footprint and much lower weight—around half of an industrial unit with comparable power output. These factors are especially important offshore. • High availability and reliability (with a lower duration for planned maintenance and less than 0.5% unscheduled downtime). Engine sections are modular and light and can be replaced in less than 24 hours without specialist technical support • Higher thermal efficiency – over 40% compared to 30% for an industrial unit saving on fuel and reducing carbon emissions. However, aero-derivative gas turbines have not been used often, even onshore. Large process compressor drivers raise concerns over reliable start up and operation, and offer similar availability to the Frame 5 and Frame 6 industrial heavy-duty gas turbines used on most onshore LNG plants. Concerns with direct drive of cycle compressors led to most studies being based on electrical power generation by gas turbines (Fig. 5) and motor-driven cycle compressors. However, electric motors of 40 MW to 45 MW are outside the experience of both the LNG business and most suppliers. Therefore, neither direct drive nor motor drive can be considered conventional. Choice of motor drive or direct drive depends on several factors, including: • Availability HYDROCARBON PROCESSING JULY 2009

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LIQUEFIED NATURAL GAS DEVELOPMENTS

• Equipment size and weight • Efficiency • Operational experience. Using aero-derivative gas turbines as direct compressor drives means that a gas turbine trip would require shutdown of an LNG train. A power-generation system could continue in the event of a single gas turbine trip, as an additional spare gas turbine would be included (N+1 principle where N is the number of items needed for operation). So, overall plant availability requires detailed assessment. In summary, the high reliability of aero-derivative gas turbines indicates that the justification for motor drives is not highly as anticipated by earlier studies, particularly since the electrical system is relatively complex. Electrical power generation. This requires considerable equipment and space, especially if variable-frequency drives were needed for efficient capacity control of LNG production. From the perspectives of equipment size, weight, structural steel and associated capital cost, aero-derivative gas turbines as direct compressor drives have an advantage over large-scale power generation and motor drives. Overall fuel gas consumption is higher for the electric motor drive option as up to about 8% of shaft power is lost through the electrical generator, transformer, harmonic filter and motor. Onshore LNG plant licensors, engineering firms and operators have reappraised the use of aero-derivative gas turbines in recent years, primarily due to their high thermal efficiency and low emissions and as they became more popular for electrical generation. Recent evaluations have considered efficient plant start-up and control. Centrifugal compressors of about 40 MW are within the capability of the major compressor suppliers. A number of motor suppliers offer designs or are close to developing them for this duty based on synchronous machines with a wide speed range and high efficiency. Motor-driven compressors may be more responsive and afford better process control than a gas turbine driver, but this may not be significant if an LNG plant operates at a relatively constant feed-gas flow. Turbo-expanders. The application of turbo-expanders with nitrogen at required process conditions, pressure ratio and capacities is conventional. Since frame sizes are at the higher end of the manufacturer’s range, efficiency is high. Expander isentropic efficiencies approach 90% while compressor (brake-end) polytropic efficiencies approaching 85% can be expected.14 Active magnetic bearings on radial inflow turbo-expanders were introduced in the early 1990s and are now a conventional technology (Fig. 6). Compared to oil-lubricated machines, they reduce footprint and weight, simplify operation and ensure that the nitrogen cannot be contaminated with lube oil. Process simulations, assessments and sensitivity studies have identified how to optimize nitrogen cycle pressures for a range of feed gas conditions to ensure high expander and compressor efficiency. Mechanical refrigeration. As previously discussed, a benefit of the dual nitrogen expander cycle is that no refrigeration system or refrigerant storage is necessary. However, chilling the inlet air to the gas turbine can increase power generation by as much as 30%. As LNG production capacity is based on utilizing available power, this increase can lead to a similar increase in LNG production if liquefaction equipment is suitably sized. Clearly, the extra cost, weight and footprint of a refrigeration system, refrigerant storage system and inlet air chillers must be 36

I JULY 2009 HYDROCARBON PROCESSING

FIG. 5

Power generation package.

FIG. 6

Turbo-expander with AMB (courtesy of Mafi-Trench Co.).

justified by the additional LNG production capacity. However, the chilling system can also be employed on feed gas and cooling water to reduce the temperature of the high-pressure nitrogen downstream of the cycle compressor coolers.6,9,10 Feed-gas chilling improves process efficiency and can reduce molecular sieve dehydration duty significantly. Chilling the plant cooling water can increase LNG production by several percent. The selected refrigerant should be non-flammable (excluding propane) and have both limited ozone depletion and greenhouse potential. Liquefaction heat exchangers and cold boxes. Alu-

minum plate-fin heat exchangers, conventional in cryogenic natural gas processing onshore, are ideal for floating liquefaction by virtue of being light, compact and highly efficient for multistream duties. Extensive experience with high-pressure exchangers on hydrocarbon service has enabled some companies to optimize exchanger design and heat transfer fin selection (in terms of the Chilton-Colburn j factor and the Fanning f factor) in parallel with optimizing nitrogen cycle operating pressures and performance to maximize LNG production against cold-box footprint and weight.15 The plate-fin heat exchangers are located in a cold box and completely insulated and weatherproofed. Cold box designs can accommodate several exchanger blocks (“cores”) so one cold box is suitable for approximately 0.75 Mtpy of LNG production. The internal piping arrangement is simple and there are no unusual mechanical design or exchanger support issues. Large-bore pipe-

LIQUEFIED NATURAL GAS DEVELOPMENTS work outside the cold box presents some technical challenges in resolving transitions from aluminum to stainless steel and in ensuring suitability for the forces imposed by vessel movement. Utility systems. Air-cooling would

require a prohibitive amount of deck space and cannot be justified. Seawater cooling is conventional in offshore hydrocarbon processing but the cooling duty on an LNG FPSO is much greater compared to oil processing and associated gas compression. A 1.5 Mtpy LNG FPSO requires about 15,000 cubic m3/h of cooling water based on a 10°C rise in water temperature (including pre-treatment). The cooling system has an important influence on the required deck space. The cooling system can be either an openloop or a closed-loop system. In the openloop system, seawater is drawn in, filtered, treated to avoid fouling and pumped through the nitrogen cycle compressor intercoolers and aftercoolers before discharged back to sea. All heat exchangers and pipework must use non-corrosive materials, typically titanium. In the closed-loop system, process grade cooling water is pumped around a closed loop, with heat of compression being removed and then rejected to seawater in cooling water/ seawater heat exchangers. Exchangers and pipework on process-grade cooling water service can be carbon steel. The open-loop system operates at seawater temperature whereas the closed-loop system must operate at a higher temperature to provide a reasonable temperature driving force between the cooling water and the seawater used to cool it. Based on a 10°C temperature difference, the closedloop system reduces process efficiency by about 6%, with an equivalent reduction in LNG production. Most studies, therefore, used open-loop cooling, even though the need for expensive metallurgy represented a large investment. More detailed engineering studies have questioned the use of open-loop cooling. Compact heat exchangers can provide efficient nitrogen cycle cooling at very small temperature driving forces and occupy a fraction of the space of a conventional shell-and-tube exchanger at a fraction of the weight. The reduction in topsides weight can more than compensate for the higher process efficiency of the open-loop system. As previously mentioned, mechanical refrigeration introduces a chilled-water circuit with the refrigeration system being cooled by the main cooling water system.

Process heating. Process heating is needed for the molecular sieve pretreatment and acid-gas removal systems, and condensate stabilization. The amount of waste heat available from the gas turbines exceeds process requirements, so most evaluations have concluded that this is the most cost-effective and thermally efficient solution for process heating. Hot oil is normally preferred to steam-based for higher thermal efficiency, fewer equipment items and ease of operation. Steam could potentially drive a turbine for power generation and increase overall thermal efficiency by using a greater amount of the available waste heat. If high-pressure steam or condensate is available from the vessel this could be advantageous and is a consideration for optimized LNG FPSO designs. Plant design, environment and safety. Since the nitrogen refrigerant has

a constant composition and the refrigeration system is simple, it is relatively easy to assess how to change refrigeration cycle parameters to optimize performance and maximize LNG production. Experience from operation of smaller-scale cryogenic liquefiers and LNG plants is very relevant. The environmental impact of offshore LNG production is less than onshore production simply because there are no onshore construction activities. Environmental impact assessments are not the potential bottleneck they can be onshore. Assessment of treatment options should use a “best available technique” approach to ensure minimal delay to permitting being sanctioned. The major emissions are: • CO2 . The AGRU produces a CO2 effluent with minor amounts of hydrocarbons, which is vented to atmosphere at a safe height. Dispersion studies can determine the minimum height for safe venting. • Gas turbine exhaust. The turbine exhaust gas is predominantly nitrogen, CO2 and water with small amounts of CO and trace levels of NOx and SOx. The high thermal efficiency of aero-derivative gas turbines compared to industrial heavy-duty gas turbines means that although liquefaction process efficiency is lower than most onshore LNG plants, fuel consumption and total exhaust emissions are similar. Dry low emissions technology is well developed on aero-derivative gas turbines. NOx emissions below 25 ppm are achievable today and it is likely that lower figures will be achieved in the future. • Flaring. There is zero hydrocarbon flaring under normal operating condi-

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Select 154 at www.HydrocarbonProcessing.com/RS

LIQUEFIED NATURAL GAS DEVELOPMENTS tions, other than a nominal purge flow. A high integrity pressure protection system (HIPPs) can be employed at the plant inlet as with all gas plants that utilize a feed-gas let-down valve. This avoids a “full flow relief case” and has a direct effect on reducing flare load, the impact due to flaring and flare tower height.

■ Onshore LNG production

plants have enjoyed an excellent safety record. Offshore LNG production introduces more stringent requirements due to the congested nature of the plant, storage and personnel areas. It is essential that experience from design and operation of onshore LNG plants is utilized. Plant layout. Safety considerations are paramount to plant layout. Layout criteria for an FPSO are more stringent than onshore due to the limited footprint (only 8,000 m2 to 10,000 m2 typically), the need for good weight distribution and the need for personnel refuge and escape routes. Hazard mitigation and blast overpressure are critical elements for layout and the benefits of nitrogen refrigerant become apparent in setting safety distances and minimum spacing for equipment. Design reviews must focus on minimizing piping runs of large-bore pipework, including cooling water and cryogenic nitrogen cycle pipework that is heavily insulated. The effect of pipework weight on the extent and weight of structural steel can be significant. Minimizing pipework weight by layout optimization has been essential in minimizing topsides weight and confirming the overall feasibility of the 1.5 Mtpy LNG FPSO. SAFETY

Onshore LNG production plants have enjoyed an excellent safety record. Offshore LNG production introduces more stringent requirements due to the congested nature of the plant, storage and personnel areas. It is essential that experiSelect 155 at www.HydrocarbonProcessing.com/RS

ence from design and operation of onshore LNG plants is utilized. The primary safety concern is the inventory of hazardous, flammable gas and LNG and the consequence of any loss of containment. Major accident hazard reviews are essential to: • Ensure the integrity of all methods of primary containment • Inhibit the potential formation of flammable vapor which could cause fire or explosion • Identify mitigation measures. Using a nitrogen refrigerant greatly minimizes the hydrocarbon inventory and plant design simplicity and should ensure that the layout is relatively uncongested, with acceptable blast overpressures. Quantitative risk assessment (QRA). QRA shows lower risk than many

onshore LNG plants. Of course, accommodation location, control building, helideck, flare and safety refuge areas are critical to personnel risk and firewalls are necessary to meet segregation requirements. The usual safety, health and environmental requirements for an onshore LNG plant are applicable and integral to the QRA. Safety philosophies are needed for prevention of incidents (e.g., avoidance of LNG leakage and ignition) and hazard mitigation including active and passive fire detection, gas detection and emergency shutdown. Safety studies and technical assessments should include determination of fire areas, gas dispersion modeling and personnel escape/evacuation, design accidental loads for all facility aspects and the effect of LNG on vessel structural steel. Risk based assessments must show that risks are as low as reasonably practicable. Conventional engineering and safety assessments, including Hazard Identification and Hazard and Operability studies, focus on “safety by design.” The simplicity of the dual nitrogen turbo-expander plant lends itself to FPSO custom and practice but the plant operations team should be experienced LNG plant operators. Regulatory issues. Classification soci-

ety requirements have addressed statutory and regulatory issues for fundamental plant safety.6,7,9 The classification societies have developed requirements for LNG FPSOs from existing rules and guidelines for LNG carriers and have completed coarse safety assessments of LNG FPSOs. For detailed engineering, a classification society will act as a “design authority” and is responsible for

LIQUEFIED NATURAL GAS DEVELOPMENTS the Formal Safety Assessment, developed with the engineering team that determines the fundamental safety criteria, philosophies and procedures. Work to date is clear that there are no obstacles designing safe LNGs plant using nitrogen refrigerant. Modularization. A significant advantage of turbo-expander technology for offshore LNG is that the plant can be designed as modules more easily than with other liquefaction technologies. Therefore, it can be built away from the shipyard and this provides opportunities for capital cost savings and high-quality fabrication with established module suppliers. Module limits are based on what can be fabricated (either local to the shipyard or locally to a port for transporting to the shipyard). A nominal limit of 2,000 tons is pragmatic to ensure crane availability. Cold boxes and rotating equipment packages are provided to the module fabricator fully piped, wired and tested. This philosophy is extended through all major equipment as far as practicable to simplify installation and hook-up of utilities, instrumentation and other services. Since vessel fabrication and topsides modules can be performed in parallel, the time to vessel delivery and full LNG production can be reduced by many months compared with a similar-capacity plant onshore. Overview. With uncertain gas prices and funding for major projects becoming more difficult, the commercial case for floating LNG becomes even better due to the smaller capacity of floating LNG projects, lower cost and reduced time to first production. Evaluating critera that influence commercial acceptance of floating LNG production—safety, overall cost, performance, availability and delivery schedule—have led to selection of the dual nitrogen expander liquefaction process. This proven process has now been evaluated in detail for offshore conditions and plant capacities in terms of technical risk, equipment design and availability, topsides design, ease of modularization, plant performance and operation, delivery schedule, and safety and environmental impact. These engineering studies have further reiterated that this liquefaction technology is an outstanding candidate for offshore LNG projects. HP ACKNOWLEDGEMENT The author thanks Terry Tomlinson, Grant Johnson and Simon Cathery at Costain for their assistance with the article. Revised and updated from an earlier

presentation from the GPA conference, March 9–11, 2008, San Antonio, Texas. LITERATURE CITED Phalen, T., “Will LNG liquefaction project development prosper?,” Hydrocarbon Processing, Vol. 87, No. 7, p. 15, July 2008. 2 Mokhateb, S., A. J. Finn and K. Shah, “Offshore LNG industry developments,” Petroleum Technology Quarterly, p. 105, Q4 2008. 3 Fjeld, P. E., “Analyzing the market potential for FLNG and adopting a flexible and creative approach,” IBC FLNG 2008 Conference, London, February 20–21, 2008. 4 Kennett, A. J., D. I. Limb and B. A. Czarnecki, “Offshore Liquefaction of Associated Gas—A Suitable Process for the North Sea,” 13th Annual Offshore Technology Conference, Houston, May 1981. 5 Vink, K. J. and R. K. Nagelvoort, “Comparison of Baseload Liquefaction Processes,” Paper 3.6, LNG12, Perth, Australia, May 4–7, 1998. 6 Dubar, C., T. Force, V. Humphreys and H. Schmidt, “A Competitive Offshore LNG Scheme Utilizing a Gravity Base Structure and Improved Nitrogen Cycle Process,” Paper 2.4, LNG12, Perth, Australia, May 4–7, 1998. 7 Sheffield, J. A. and M. Mayer, “The Challenge of Floating LNG Facilities,” European GPA Spring Meeting, Norwich, UK, May 16–18, 2001. 8 True, W. R., “Study says floating liquefaction plants are viable,” Oil & Gas Journal, p. 62, April 9, 2001. 9 Finn, A. J., “Effective LNG Production Offshore,” 81st Annual GPA Convention, Dallas, Texas, March 10–13, 2002. 10 Finn, A. J., “New FPSO design produces LNG from offshore sources,” Oil & Gas Journal, p. 56, August 26, 2002. 11 Sheffield, J. A., “Offshore LNG Production: How to make it happen,” GPA European Annual Conference, Warsaw, September 21–23, 2005. 12 Finn, A. J., G. L. Johnson and T. R. Tomlinson, “Developments in natural gas liquefaction,” Hydrocarbon Processing, Vol. 78, No. 4, p. 47, April 1999. 13 Johnson, G. L., A. J. Finn and T. R. Tomlinson, “Offshore and Smaller-Scale Liquefiers,” LNG Journal, p. 19, July/August 1999. 14 Lillard, J. K. and R. Dirlam, “Use of TurboExpanders in LNG Facilities,” 83rd Annual GPA Convention, New Orleans, Louisiana, March 14–17, 2004. 15 Taylor, M. A. (editor), “Plate-Fin Heat Exchangers: Guide to Their Specification and Use,” First Edition, HTFS, Harwell, UK, 1987. 1

Adrian Finn is technology development manager with Costain Oil, Gas & Process, Manchester, UK with responsibility over technology development and commercialization, intellectual property, process studies and basic engineering projects. He has 26 years with Costain, mainly on cryogenic gas processing projects and recently focusing on floating LNG. Mr. Finn is a Fellow of the Institution of Chemical Engineers and a Chartered Engineer in the UK. He is also a member of the Gas Processors Association Europe. He holds a BSc Tech degree in chemical engineering and fuel technology from the University of Sheffield and an MSc degree in integrated plant design from the University of Leeds. Select 156 at www.HydrocarbonProcessing.com/RS

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LIQUEFIED NATURAL GAS DEVELOPMENTS

SPECIALREPORT

Consider new approach for floating LNG units Combined technical expertise for onshore and offshore LNG facilities reduces risks and capital costs for new installations C. CASWELL and C. DURR, KBR, Houston, Texas; E. ROST and M. KILCRAN, KBR, Leatherhead, UK

n an era where technological advances are a continuous, evolutionary dynamic, the liquefied natural gas (LNG) industry is primed for the implementation phase of offshore liquefaction, or floating LNG (FLNG), based on the important lessons learned from the progression of floating, production, storage and offloading (FPSO) and onshore LNG projects.

once the first FLNG is towed to its destination, then the project becomes an LNG plant. Onshore LNG recent history. Since 2005, the cost of

upstream oil and gas projects has risen dramatically. From 2000 to 2008, upstream capital costs increased nearly 100%.1 Factors influencing capital costs include: FLNG is not a new idea. It is an idea whose time may well • Raw material price inflation have come. The successful implementation of FLNG requires • Complex projects in challenging locations applying lessons learned while identifying what makes FLNG • Coincidental industrial projects unique. When the technical and execution risks are properly • Finite contractor and material supplier capacity. identified during a high-quality front-end engineering and design In the past, LNG projects were once compact gas plants in (FEED), FLNG prospects have the opportunity to be commerindustrial-friendly locations subject to favorable marine and shipcially and technically successful. ping conditions. Over the past 20 years, large gas fields have become more difficult to find and potential site locations are FLNG risks. There are many opinions on why FLNG has not becoming more challenging (e.g., Sakhalin, Snøhvit, Tangguh, been commercialized. These opinions commonly involve perGorgon, etc.) In addition, new issues facing onshore LNG develceived risks that are large enough to stall the opments are: project in the appraisal phase. Some risks ■ There is no magic pill, • Complex marine infrastructure (jetty, include: material offloading facility, etc.) • Technical risk. FLNG may not be fea- potion or formula for • Greater distance of reservoir to shore sible. • Substandard soil conditions quickly and successfully • Commercial risk. FLNG does not pro• Arctic and arid environments vide adequate rate of return. • High acid gas content/carbon dioxide implementing FLNG. • Execution risk. FLNG is too complex to (CO2) sequestration put together in the present market. • Heavy hydrocarbon inventories. Each set of risks are valid causes for concern, but technical, As a result, onshore LNG projects have transformed from liquecommercial and execution risks are present in all large industrial faction-centric gas plants to complex infrastructure-centric projects projects. The key to successful project implementation is mitiwith a certain liquefaction capacity. In some cases, the estimated gating risks that are achieved by a proper project execution plan. LNG train cost is 30% or less than the overall project cost. Execution planning anticipates risks by applying the appropriate The once useful comparative metric of US$/annual ton of lessons learned to new concepts and situations. production is now meaningless. Comparing one LNG project FLNG press releases often cite the familiar liquefaction process vs. another is difficult without using a common basis that contechnology aspect of these projects. Liquefaction technologies are tains the effect of infrastructure costs as a function of the overall technically vetted entities that create natural divisions among conplant capacity.2 One of the goals for FLNG is to minimize these cepts and owner/operator companies. For example, liquefaction infrastructure costs to a level necessary for reliable plant operation technologies can separate concepts by plant capacity, refrigerant in a marine environment. At a minimum, it is clear that FLNG sources and equipment selection. However, developing a new combines gas treatment, liquefaction, storage and offloading in a industry such as FLNG requires a focus on the less familiar aspects singular piece of infrastructure. of a project to mitigate true risks. A recent strategy to develop onshore LNG projects used It is the lessons learned from FPSOs that will be familiar design competitions with two or more contracting entities. The when implementing the first baseload FLNG projects. However, design competition is a different approach for encouraging execuHYDROCARBON PROCESSING JULY 2009

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LIQUEFIED NATURAL GAS DEVELOPMENTS

tion innovation, guaranteeing multiple EPC bids and reducing CAPEX or life-cycle cost for well-established industries such as onshore LNG. A successful design competition is based on a full definition of the project requirements and principles along with a fair set of rules in which to compete.3 Conversely, a competition allows limited flexibility for scope changes or significant technical changes. Result: Design competitions are not best suited for developing industries or first-of-a-kind projects. Perceived FLNG state-of-the-art. The perceived state-ofthe-art of FLNG varies depending on the information source. With many companies and consortia all vying to be first (or even second) to commercialize FLNG, a limited amount of public information leads to a distorted perception on the development of publicized projects and schemes. However, many separate entities are proposing technical and commercial solutions to the FLNG puzzle. There is no doubt that every formidable international oil and gas company has considered FLNG as a potential alternative to conventional onshore liquefaction. A first step in evaluating FLNG is to conduct conceptual studies to review concepts and compare capital cost estimates of defined accuracy. While these studies are technical in nature, a primary deliverable is the capital cost estimate. Often, conceptual FLNG studies are based on onshore LNG technical know-how combined with varying levels of information on hull and fabrication issues. Since estimate accuracy is a function of engineering detail (certainty of quantities, work hours, subcontracts and schedules), the publicly stated cost of an FLNG project can have wide variation. In addition, comparing FLNG cost estimates using onshore LNG metrics of US$/ton is irrelevant unless a comparable onshore option and estimate are technically developed for that exact NG asset. Among the myriad of players in FLNG, there are definitive camps that pursue similar development paths. Some of these groups include: • Large-scale providers (high-capacity FLNG) • Alliance-based solutions • Customized solutions • Niche solutions. Large-scale providers follow a path of bringing state-of-theart onshore LNG to a marine environment. This philosophy uses the concept of maximum liquefaction capacity, via perceived economy of scale, by using sensible practices from onshore LNG

and challenging the limits of current FPSO size and topsides weight. Large capacities will provide the highest annual revenues with the challenge of building the largest FPSOs. A recent study indicates that a 5 million tons per year (MMtpy) FLNG unit will require a hull size larger than any FPSO that has been built (see Table 2 for FPSO dimensions). Alliance-based solutions rely on a consortium of companies to provide parts of the total FLNG solution. For example, an FPSO owner/operator could align with a liquefaction technology provider and/or a shipbuilder or module fabricator. The net technical capability of the consortium is high, while the experience in developing a full-field LNG FPSO solution does not reside in a single part of the alliance. Consequently, the alliance is viewed stronger by public opinion. Customized solutions developers have the greatest degree of freedom in applying technology and experience to FLNG. This freedom is further enhanced if the developer has extensive LNG and offshore experience. Conversely, technical freedom results in a challenging series of decisions to face during appraisal and selection stages. The road to a customized solution could be an optimal path if the journey is forged by a developer with the technical know-how, finances and perseverance to complete the quest. There are no shortcuts to a customized solution. Therefore, the developer is faced with a significant challenge to find the right concept and execution strategy before fully committing to FLNG. Niche solutions cover unique methods to penetrate the FLNG market. In some instances, the actual “first mover” in FLNG may be a niche solution. This area covers a wide spectrum of solutions, including smaller LNG capacities, conventional LNG carrierbased solutions, unconventional hull designs and shapes, and unique liquefaction technologies. Many players in FLNG face a challenge of how to move their project forward. As of this writing, very few opportunities are developed to the degree of estimating and execution certainty needed to fully sanction the project. The execution risks of a multibillion-dollar industrial project lie in the technical and commercial details. Many FLNG concepts have not addressed these details because of the colloquial concept of “You don’t know what you don’t know.” There has not yet been an FLNG FEED project based on a fully vetted proven concept, so there is a strong need to execute a highquality FEED to reduce technical risk and commercial uncertainty. As a result, all developers should plan how to structure a highquality FEED while learning from the history of FPSOs and LNG projects to further commercialize their solution. FPSO—history and present. The move to designing the first

FIG. 1

The Belanak LPG FPSO—A precursor to FLNG.

I JULY 2009 HYDROCARBON PROCESSING

oil and gas FPSOs in the 1970s is similar to current opportunities facing the LNG industry. New hydrocarbon assets (crude oil and associated NG) that were once found onshore and in convenient locations are more difficult to find. To augment existing oil production and supplement reserves, companies must look offshore—first to platform-based solutions in shallow water locations and then to deepwater reservoirs. As attractive hydrocarbon reserves are found farther offshore, the FPSO concept was developed to monetize these assets by crude oil transport to shore via shuttle carriers. On many occasions, some topsides processing was involved. These first FPSOs were ideal for locations such as the North Sea, Brazil and Western Africa. There was either a local demand for crude oil products or an economic benefit for export.

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The beginnings of the FPSO industry and present development path of FLNG are quite similar. As NG assets (including associated gas assets) are found further offshore, conventional onshore gas processing is becoming increasingly challenging and more costly. With the experience of a large fleet of LNG carriers in service, applying the historical lessons of FPSOs is a natural fit for FLNG. The first FPSO projects were uniquely challenging in merging traditional oil and gas recovery with the experience gained from designing shallow water offshore structures. Movement to deeper water was a historical step change in the hydrocarbon industry. Deepwater, as a new business, had few established rules and needed exceptional technical experience, execution leadership and the passion for this new enterprise. These mega-projects have a common “first-of-a-kind” nature where technical risk is tempered by sound execution and risk management. As the FPSO industry matured, so did the opportunities to push the limits of vessel size and volumetric capacity. One of the world’s largest FPSOs is the Kizomba A (operated by ExxonMobil) located in 1,200 m of water and 150 mi offshore Angola. The vessel has a capacity of 2.2 MMbbls (equivalent to 350,000 m3 of liquid storage) and has hull dimensions of 285 m long, 63 m wide and 32 m high. The development of the modern FPSO and associated technologies is the result of innovative teams overcoming great technical challenges. The initial efforts were necessary to monetize offshore oil and gas reserves in deep water and were often subject to considerably challenging marine conditions. The need to augment global NG reserves along with the demand for LNG is clear. The question of FLNG is not “if ” but “how.” Evolution of onshore LNG to FLNG. One logical path to FLNG involves the transiting of known onshore concepts to a new marine environment. This evolution is in progress even without a current LNG FPSO in fabrication. In fact, the real road to FLNG began as early as 30 years ago. The familiar evolution to FLNG takes a very logical path:

Onshore LNG Modular LNG Offshore LNG Less complex project More complex project

Baseload onshore LNG projects, still quite commercially viable, have a history going back to the Camel project in Algeria from 1964. Onshore LNG facilities, based on the degree of infrastructure required, are still commercially viable today. However, in areas where labor or infrastructure costs are high, some developments have considered modularization construction techniques. The popularity of modular construction increased in popularity in the 1970s.5 Modular construction was often used for areas with challenging weather patterns such as for oil and gas fields along the North Slope of Alaska. With regard to LNG, this philosophy was applied for projects such as Snøhvit LNG in Norway. In more temperate climates, modularization allowed the prefabrication of Train V of the Northwest Shelf LNG facility to take advantage of modular construction productivity and efficiency. Result: Modular design is proposed for future LNG projects such as Gorgon LNG, Inpex LNG and many other projects. Such modules will be based on the design fundamentals and expertise gained from offshore oil and gas projects, including FPSOs. The next extension of onshore LNG modularization is designing LNG-related equipment for offshore operation. LNG projects are often associated with large-scale power systems, piping and equipment that provide a unique challenge over simpler technolo44

I JULY 2009 HYDROCARBON PROCESSING

TABLE 1. Dimensions of LNG carriers Typical LNG carrier dimensions Storage volume, m3

Length, m

Width, m

Depth, m

165,000

286

26.2

175,000

286

45.6

26.6

215,000

302

265,000

332

53.8

TABLE 2. Hull dimensions of operating FPSOs Vessel name

Sample FPSO dimensional characteristics Topsides weight, ton Length, m

Width, m

Terra Nova

10,000

291

White Rose

13,500

258

Girassol

20,000

300

59.6

Greater Plutonio

23,000

310

Belanak

24,000

285

Bonga

34,000

295

Agbami

35,000

320

58.4

Dalia

37,000

300

Akpo

40,000

310

45.5

Kizomba A

Not available

285

Kizomba B

Not available

285

gies. In addition, offshore modules must be designed for both operational and transportation loads when operating in a transient environment. Historical oil and gas projects in challenging locations have helped develop the potential for FLNG. How FLNG differs from traditional FPSOs. Although

there are many familiar themes in the development of both FPSOs and FLNG, there are several differences that make FLNG unique. These differences are primarily categorized in the areas of overall size/ scale and process technologies. Successful development of FLNG projects is based on identifying risks associated with these differences and allowing for successful project execution. The most noticeable difference in developing FLNG is with the size of the vessel necessary to make an impact on the LNG market. For FLNG providers previously discussed, LNG capacity ranges from 1 MMtpy to 8 MMtpy. The global LNG trade for 2008 was 174 MMtpy.6 At the lower end of this range, the LNG traded is about 0.5% of the world capacity. Accordingly, the volume could be traded on either a long-term or speculative basis to fill small gaps in worldwide trade volumes. In terms of hull dimensions, the vessel size is comparable to that of a medium-sized LNG carrier. Table 1 is a sample list of LNG carrier dimensions. At the higher end of the FLNG capacity range, the project would fulfill incremental energy demands in dedicated markets via using traditional long-term LNG contracts. However, with increased liquefaction capacity, the length of purpose-built barges could grow in excess of 500 m. The greater length is attributed to both the topsides area and liquids storage volume required based on selected shipping logistics. To some extent, the size of a large FPSO is similar in scale to a modest capacity FLNG. Accordingly, a large-capacity FLNG will push the current boundaries of FPSO size and scale. A sample list of FPSO hull dimensions is provided in Table 2. Looking at this data, there are manufacturing and commercial bar-

LIQUEFIED NATURAL GAS DEVELOPMENTS

SPECIALREPORT

riers that limit the dimensions of these hulls. For example, the width nology, integration of upstream processing units for an entire of an FPSO is limited by the dry-dock capabilities of the largest FLNG solution must not be ignored. In a gross oversimplification, capacity shipyards. These drydocks cannot “expand” in width for an FLNG is similar to an FPSO with a “refinery” added to the one specific project. From Table 2, the maximum width for FLNG topsides processing scope. The lessons learned from the design to fit the current manufacturing experience is 63 m; however, there of offshore equipment, module and hull interfaces, and project have been several crude oil carriers delivered with dimensions of 380 execution risks will be applicable for FLNG, but they do not m x 68 m.4 These dimensions are within the tolerance for the largest answer all potential questions. capacity LNG carriers, delivered in 2008, shown in Table 1. As of April 2008, there were 121 FPSOs in operation with 53 In addition to vessel width, the vessel length can be affected by units on order. Of these vessels, 70 were new builds and 104 were shipyard limitations. Comparing Tables 1 and 2, the current upper converted hulls.7 Since FPSOs target oil and gas recovery, the hulls range of vessel length is 330 m, with minimal experience of one can be converted from existing crude oil carriers. Due to the demands shipyard at 380 m. This maximum dimension allows for efficient of LNG topsides and to develop a safe and reliable industry, it is manufacturing of multiple carriers and/or FPSOs within a given expected that all of the first FLNG vessels will be new builds. shipyard. Extending the length of the FLNG, based on additional LNG capacity, module complexity, turret location, safety separation What is a high-quality FLNG FEED? Since a full-scale distances or additional liquids storage will create execution challenges FLNG still does not exist, what is the proper FLNG FEED to for shipyards accustomed to building oil and gas FPSOs, LNG carlimit exposure to cost and schedule risk? What is required in terms riers, crude-oil carriers, containerships, bulk carriers and naval ships. of work hours and duration? Answers to these questions lie in the However, if the market for high-value transportation vessels becomes lessons from the past; but which history should we follow: 40 less attractive than for the potential future for FLNG, the opportuyears of onshore LNG or 30 years of operating FPSOs? nity to build longer floating vessels will become possible. Onshore LNG project execution has greatly evolved over the Another difference between FLNG and an FPSO is the amount past 40 years. Substantial growth in LNG production since the of topsides processing that is required to produce the valued cargo. 1990s has led to technical and commercial innovations to increase For an FPSO, the cargo is crude oil and, for FLNG, it is on-spec LNG product. The TABLE 3. Range of FEED metrics for onshore LNG projects amount of topsides processing required to FEED produce LNG is significantly greater than FEED schedule, Project type work hours months Project characteristics that for FPSOs. The goal of a traditional FPSO is to Small-scale LNG Low to medium 6–12 Proven technology and modest or peak-shaving produce a certain capacity of stabilized crude capacity, industrial location, easy access to feed gas, labor and material oil and to provide enough storage to support a predetermined number of offloading Medium-scale LNG Medium 9–14 Proven technology and capacity range, predictable feed gas, familiar logistics, medium infrastructure tankers. This crude oil is a high-value commodity that requires further processing Large-scale or High 12–18 Advanced technology, challenging LNG enhanced onshore. As a result, the minimum amount challenging LNG capacity, challenging feed gas conditions, heavy infrastructure, environmental challenges, multiple of offshore processing is included to guarancontracting partners tee a suitable end product. This processing includes oil treatment (separation, dehydration, desalting and stabilization) plus the TABLE 4. Elements of a high-quality FLNG FEED treatment of separated water and NG that Impact to FLNG FEED are characteristic of the reservoir. Water and Sample activities for FPSO FEED NG are often re-injected to enhance-oil Basic hull dimensions frozen Storage / hull dims for transportation scenarios recovery, while any exported NG is treated Motions and accelerations defined Marinization for AGRU and LNG equipment for its water dew point and sometimes for Identification of turret vendor and interfaces Design for severe weather conditions (e.g., cyclone) hydrogen sulfide (H2S). Topsides PFDs and main system P&IDs frozen More systems to develop (AGRU, DEHY, NGL, etc.) The goal of FLNG is to export a valuSelection of proven versus prototype equipment able commodity that has a stricter product Main equipment items frozen Topsides weight and space frozen More equipment and interfaces specification that requires no further processing onshore. The actual liquefaction of Main interfaces defined Mitigate for additional modules and scope NG requires a highly purified feedstock as Construction methodology Hull, equipment and module supplier(s) logistics compared to that required for oil extraction Power generation philosophy Sparing philosophy for extended power block or even oil refining. NG suitable for liquefacControl system methodology Adaptive for multiple suppliers/manufacturers tion must be treated for CO2 (< 50 ppm), Supply and maintenance of large seawater system water (< 1 ppm), H2S (< 4 ppm) and the Process heating and cooling system New risks associated with FLNG removal of all C5+ (< 0.1%) components that Preliminary safety and risk analysis can freeze during refrigeration. Location of safety equipment New risks associated with FLNG To make LNG, one must also store lique- Escape routes and accessways defined New risks associated with FLNG fied petroleum gas (LPG) and condensate, Mechanical handling defined LNG equipment sparing philosophies which are natural end products from liqueLiquid loading defined Liquid(s) loading system defined faction. While most discussion of FLNG Commissioning plan Multi-fabrication center commissioning plan revolves around liquefaction process techHYDROCARBON PROCESSING JULY 2009

I 45

SPECIALREPORT

LIQUEFIED NATURAL GAS DEVELOPMENTS

LNG train capacity in some of the most challenging locations of the world. FEED metrics are familiar among the companies involved in the design of LNG projects. Table 3 summarizes a range of these metrics. A high-quality FLNG FEED should incorporate the successes and lessons learned from these two well-established industries. FLNG is a new and emerging business. The focus should not be overly dominated by either LNG or offshore thinking. However, we naturally tend to gravitate to what we know, as opposed to the unknown. Some FLNG opportunities have been led by experienced shipping companies but more are led by LNG producers targeting stranded reserves and traditional markets. Often, FLNG is thought of as an extension of either LNG know-how or FPSO know-how, with a less intensive regard to the “other side.” Objectively, the goal of the FLNG FEED is to study and define the project to obtain the technical and estimating certainty necessary in advance of the final investment decision (FID). Based on the challenges faced by future onshore LNG and FPSO projects, do we know all of the answers to the questions posed for marinization of an LNG train or multiple trains? Reviewing Table 4, one immediately raises questions about the feasibility of design, operability, size and scale of a floating liquefaction plant. All of the challenges of working offshore are difficult enough. FLNG considers a world-class arrangement of gas processing, power plant and refrigeration equipment that must operate with a high degree of availability and safety. The path toward executing a high-quality FEED is well within sight for LNG producers that have reviewed potential markets and technologies. But do the work hour and schedule metrics from onshore LNG apply when considering the scope of this high-quality FEED? As mentioned for both onshore LNG and FPSO projects, a primary goal during FEED is to improve confidence in the design for operation, execution strategy to assure schedule, and cost estimating that affects competition and the best use of capital. In structuring a high-quality FEED, would the activities from Table 4 require more or less definition than historical projects? One of the biggest changes in mindset in planning an offshore FEED is the level of engineering necessary to support a ±10% cost estimate. Onshore LNG projects have a long history of correlating engineering activities to support an estimate. Capable contractors wield this expertise based on this known set of activities adapted to site-specific requirements. Thus, the technical and estimating assumptions for onshore LNG projects are based on decades of experience along with a keen sense of current material and labor markets. FLNG projects often claim to be simple and quicker to construct based on eliminating remote onshore construction labor and infrastructure such as temporary facilities, marine systems and LNG storage. However, moving the fabrication of an LNG plant to an efficient industrial shipyard ignores the design certainty necessary for the actual LNG plant to be supported by a floating hull. An offshore estimate is based not only on the equipment defined by the process and captured on P&IDs, but, also on its total weight. For onshore LNG projects, foundation calculations are not a critical path item. But the topsides weight estimate, as well as the management of that weight during EPC, is critical to the structural support and stability of the hull. If design changes allow equipment or systems to increase in weight, the entire project is affected. For example, the deliverables for an FPSO FEED include pipe routing definition that would not be part of the onshore LNG FEED scope. The engineering detail is much greater for offshore projects to ensure certainty of topsides weight. 46

I JULY 2009 HYDROCARBON PROCESSING

■ Mitigating risk is achieved with the

sensible investment in a set of highquality technologies, with a group of high-quality contractors, who execute a high-quality FEED to deliver a highquality cost estimate. The challenge in FLNG projects remains in identifying and addressing “what you don’t know” during FEED to address these issues and interfaces prior to the EPC or EPCm phase. A high-quality FLNG FEED must define installed equipment to a greater detail than for onshore plants. For example, an onshore plant may require a pump of a certain size and type. In contrast, the offshore plant will estimate the pump size, model number, weight and support criteria to design the support module. Consequently, equipment selection has a cascading effect on the entire system design, which determines the primary structural steel weight necessary for each module. While an onshore LNG estimate can be factored from items such as equipment count and labor cost, offshore LNG estimates are factored by equipment and bulk-material weights critical to the module design, fabrication schedule, labor cost and hull size. The extra effort needed to define the weight of equipment and systems bulk materials results in work hours not commonly considered during FEED (but common for FPSOs). In comparison to onshore LNG, a high-quality offshore FEED would contain 30% of what was scheduled as detailed engineering for an onshore project. This engineering is necessary to prevent weight escalation, which is proportional to cost escalation and schedule creep—possibly resulting in the project not meeting milestones or expectations. The total system weight includes piping design down to a line size needed to instill confidence in the module sizes and weights. For example, it is suggested to model all piping down to at least 10 in. during FEED. At this level, this process enables over 70% of the piping weight to be extracted directly from the 3D model. Where lines are stress or interface critical, piping sizes down to 4 in. are modeled. In addition to weight implications, the packing density of modules (equipment, piping and structural steel) is yet to be determined, which, if proven, can be detrimental and may require re-engineering of layouts. One implication of a high-quality FLNG FEED is the misconception of cost competitiveness for the project. However, reduced scope development or a reduction in FEED workhours will add unneeded contingency to the cost estimates from all engaged parties. High levels of contingency and uncertainty will result in a lack of competition for the EPC phase for all but reimbursable projects. How are we to interpret the press releases over the last few years stating that FLNG will significantly reduce the time to deliver the first cargoes of LNG vs. an onshore LNG plant? First, due to the varying scope of all large complex projects, it is difficult to compare one LNG project to another as “not all plants are created equal.”3 Some LNG projects are train expansions, have complex infrastructure or have varying process and utility scope that significantly affect cost and schedule.

LIQUEFIED NATURAL GAS DEVELOPMENTS Similar to FPSOs and onshore LNG, FLNG concepts will vary widely, and no two projects will be similar. FLNG projects will vary in capacity, using different technologies and will be based on different hull concepts with different containment and loading systems. In addition, these FLNG concepts will be subject to the feed-gas composition variation that separates all LNG projects in scope. The true success of FLNG will depend on the path to FID: taking either the high-quality FEED or the minimalist path that yields different outcomes with regard to project cost and implementation schedule. Reduction in scope can also occur during pre-FEED or conceptual development. As mentioned in the section “What is a typical FEED?”, the investment in scope definition will be rewarded during later stages of execution. As a result, isn’t it imperative to perform a high-quality (if not exhaustive) FLNG FEED to provide the certainty of design and capital cost that is warranted for a first-of-akind project of this magnitude? Ignorance of the critical design issues by ignoring the 800lb gorilla in the room illustrates the concept of “You don’t know what you don’t know.”

Acid-gas disposal

Feed gas reception system

Acidgas removal

Dehydration and mercury removal

Condensate storage and loading FIG. 2

SPECIALREPORT LNG storage and loading

Refrigeration systems Precooling

Liquefaction

Fractionation and storage

Nitrogen rejection

LNG storage

Fuel gas system

Basic block diagram for pre-cooled gas liquefaction plant.

We a prese re nt at Offsh o 08-11 re Europe Sep Aberd tember een

FLNG technical issues. Another integral part involves resolving design issues for topsides process technologies, equipment and module design. Although traditional FPSOs can have sizeable gas-processing facilities (e.g., up to 500 MMscfd), baseload liquefaction is a major extension from offshore oil and gas processing. A “standard” feed-gas flowrate of 500 MMscfd would produce approximately 3 MMtpy of LNG. This production rate is less than the production capacity of nearly every LNG train under construction in 2009 (4 MMtpy to 7.8 MMtpy). For larger LNG processing capacities, the expected topsides weight of FLNG will exceed that of the large FPSOs (see Table 2). Successful conceptual design leading to a high-quality FEED requires acknowledging the issues and difficulties of offshore gas processing and liquefaction and not avoiding the issues with conceptual photos. Since most definition occurs during FEED, a proper conceptual study (or pre-FEED) will formulate a design to capture these issues that require more intensive study. After reviewing a handful of technical issues across multiple concepts, one may question if any company or joint venture has actually attempted a quality FLNG FEED. As shown in Fig. 2, a liquefaction plant with a one or two-stage refrigeration system has many interfacing units. In addition, nearly all stranded gas fields will require three Select 157 at www.HydrocarbonProcessing.com/RS

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LIQUEFIED NATURAL GAS DEVELOPMENTS

types of product storage: LNG, LPG and condensate. Thus, the total scope for an LNG plant, which occupies well over 100 ac onshore and hundreds of pieces of equipment, will be a challenging task. Ironically, instead of addressing the execution challenges of large complex projects, most public discussion of FLNG revolves around liquefaction process technology.

Currently, the AGRU design to meet tight CO2 specifications is based on known feed-gas compositions and amine circulation rates. The variable design factors include unknown compositions, consistent fluctuations or educated guesses on processing parameters. Design for wide AGRU operational flexibility is not standard for onshore LNG units and will become a unique challenge for the offshore arena.

Role of process technology. Many liquefaction process

technologies are suitable for FLNG. These technologies can be categorized as: • Inert refrigerant expander technologies, e.g., nitrogen (N2) processes • Dual-expander technologies (e.g., N2 and methane) • Single-mixed refrigerant (SMR) technologies • Dual-mixed refrigerant (DMR) technologies • Traditional baseload technologies (C3-MR and cascade). Each subset of liquefaction technologies are different based on total process efficiency, refrigerant composition, number of refrigerant cycles and the critical equipment used within the process. Familiar metrics for onshore LNG plant efficiency (e.g., 35 MW per MMtpy of LNG) are based on cascade and MR technologies, while other processes provide additional design flexibility at a lower process efficiency. With the number of processes available, what is the best solution for FLNG? Objectively, all available technologies could be applied for FLNG. Each technology, along with its refrigerant and equipment basis, could be appropriate within the agreed principles of availability, operability, efficiency and safety for use offshore. However, the weighted evaluation criteria used during the liquefaction process selection study will determine the best processing solution for a specific project. Regardless of the preferred liquefaction process technology, the important issues for FLNG lie with the equipment and interfaces of the flowsheet. Although FLNG is an additional step beyond LPG processing, it is imperative to discover the technical risks for baseload offshore LNG. Role of equipment. One of the challenges in executing FPSO projects is the potential growth in topsides weight during the EPC phase. The key to mitigating growth in topsides weight is to thoroughly define the amount of processing and refrigeration equipment during FEED while conforming to the expectations of process efficiency, availability, operations and maintenance. Similar to a traditional value engineering exercise, the resolution of equipment count revolves around defining essential vs. nonessential equipment. Certain items or spares may not be essential to the actual process under normal operation, but may be essential for higher availability targets desired for FLNG. Result: FLNG design competitions could yield in minimally based facilities to limit topsides weight and capital cost as only the competition evaluation criteria is used to measure success. Consequently, since the design of FLNG is neither commonplace nor consistent among companies, design competitions or competitive FEEDs may not provide the intended value to the owner and operator of the facility. AGRU and dehydration equipment. An FLNG process

unit that will be sensitive to motion is the acid gas removal unit (AGRU), which is required to remove CO2 and would freeze in the liquefaction train. The AGRU contains one of the largest and heaviest vessels in an LNG facility—the AGRU absorber. An additional consideration for the AGRU is variation of feed-gas composition either during operation or for future relocation of the FLNG. 48

I JULY 2009 HYDROCARBON PROCESSING

Liquefaction equipment. One often debated design challenge for FLNG is the liquefaction module. Specific equipment within the liquefaction module is a function of the process technology and train size. The list of equipment in this module would include most of the following: refrigerant compressors, refrigerant companders (compressor and expander), compressor drivers (turbines or motors), main cryogenic heat exchanger, pumps, intercoolers, drums, hydraulic turbines, and/or JT valves. The most widely discussed equipment is the main cryogenic heat exchanger (MCHE). Many papers have been written about the design and operational benefits for both types of MCHE onshore, but there are currently two divided camps on this issue for FLNG. The optimal choice of MCHE is still under debate. Train size. For all but the smallest FLNG concepts, the topsides

design must address LNG train size to meet target LNG production rates while establishing plans for module size and layout. Similar to the MCHE, train size is a function of the liquefaction process technology, although the scalability of each technology has its practical limits. Liquid storage and loading. Although LNG carriers have been safely transporting LNG for over 40 years, these carriers operate in either an empty or a full condition. FLNG will naturally have variation in day-to-day storage volume as a function of production rate and logistics of shipping LNG to multiple markets. In addition to the traditional storage for LNG carriers, FLNG projects must store all liquids produced onboard, including LNG, LPG and condensate. Hull and marine systems. The design of the hull, turret,

risers and mooring system is a significant challenge regardless of the specifics of topsides processing. In review of the components for FLNG, it is certain that the hull will be either similar or larger than the existing LNG carrier fleet. Role of safety. One of the impending unknowns for FLNG

is the effect of process and operational safety over facility design. At an absolute minimum, FLNG must carry the safety principles, philosophies and practices developed from the FPSO industry. To advance FLNG installations, safety cannot be compromised by prototype designs, poor analysis, cost-cutting initiatives, lack of operational experience or the ignorance of the true risks of LNG production offshore. Safety is a sensitive subject; there are not any existing LNG production vessels offshore. Safety will impact the application of liquefaction process technologies, along with the handling of refrigerants, development of piping and equipment layouts, all of which drive the topsides facilities. Similar to FPSOs, there isn’t a definitive set of rules or criteria that can be applied to ensure that a facility is safe. Accordingly, the project must demonstrate that all reasonable measures are to eliminate safety risks and that residual risks are at acceptable levels for interested parties. The interested

LIQUEFIED NATURAL GAS DEVELOPMENTS parties would typically include the asset owner and operator, financier, operational jurisdiction and possibly a classification society. Project execution issues. In the mid-1990s, various busi-

ness drivers—such as the cost growth of jacket-based topside solutions, technical advances in subsea riser systems, and shorter life of offshore fields—raised the popularity of FPSO solutions. The FPSO became the industry innovation to make smaller and more remote offshore assets commercially viable. The initial perception innovation was that the FPSO solution was simple and easily fabricated because the solution was based on the existing topsides designs for oil platforms. In many cases, FEED was limited to a quick concept definition to define equipment lists, generate layouts and develop a factored cost estimate and schedule. Project cost and schedule were estimated on shipping and fixed-platform experience and cost. Schedule validation was less of an issue because contractors were offering extensive production and schedule guarantees based on a lump-sum turnkey (LSTK) pricing. This initial perception resulted in underestimating the technical complexity of an FPSO, along with overly optimistic schedules. Many changes were required to ensure that the total system would work and that the interfaces would match. Different regulations for shipping and topsides design further complicated integration. The two most common symptoms resulting in execution problems were the carry-over work from shipyard to topside/integration yard and the weight growth of the topside facility. Engineering teams for FLNG will be facing similar first-of-akind challenges and are susceptible to learning lessons the hard way—by executing the first few FLNG projects to see if these projects can be commercially successful for all stakeholders. Through conceptual studies and pre-FEEDs, it is evident that LNG and offshore regulations and design practices are quite different. Establishing consensus on a set of merged FLNG design practices will take time and effort. The FEED for the first few FLNG facilities requires focused attention on identifying and mitigating technical and execution risks to minimize the inevitable changes during project execution. All projects have a unique evolution from conceptual design to operation, but technical or commercial show-stoppers could prevent the development of this new gas monetization business. An FLNG project execution team must have a strong focus on identification, planning and solving the physical and technical interface issues between the hull and topsides, because the interfaces will be different than for current FPSOs. For a “first of a kind” project, there is very little historical data to benchmark the weight and cost estimates for the FLNG topsides. The ability to benchmark estimates against historical data from recent similar projects provides further means to ensure confidence in forecasted cost and schedules for FLNG. The lack of directly relevant benchmark data, against which the project forecasts can be compared, surely makes the argument that a high-quality FEED is necessary; deriving representative estimate input data are even more compelling than having reliable benchmarks. Several project teams have started the journey of learning and solving these challenges. But this journey will be longer than commonly advertised. Studies based on existing LNG know-how or generic field-based solutions will form the building blocks for future FLNG design manual, but they cannot prepare capable contractors and shipbuilders to accurately estimate the first FLNG. However,

SPECIALREPORT

actual projects based on specific locations and gas compositions will enable innovative developers to implement FLNG. HP LITERATURE CITED “Oil & Gas Construction Costs Reach New High; IHS/CERA Upstream Capital Costs Index Up 11% in 6 Months to 198 Points,” www.CERA.com, Nov. 7, 2007. 2 Durr, C., D. Hill, and P.J Shah, “LNG Project Design Competition—A Contractor’s Viewpoint,” LNG 14, March 21–24, 2004. 3 Kotzot, H., C. Durr, D. Coyle, and C. Caswell, “LNG Liquefaction—Not All Plants Are Created Equal,” LNG 15, April 24–27, 2007. 4 FPSO ad LNG Carrier dimensional information courtesy of promotional material from: Samsung Heavy Industries Performance Record, DSME Performance Record, Hanjin Heavy Industries Performance Record, and www.offshore-technology.com. 5 Meissner, R. E., III, Meissner Engineering Co., “Choosing The Right Path: Modular Versus Conventional Construction: By Systematically Evaluating A Host Of Factors Using The Methodology Described Here, You Can Determine If Prefabrication, Preassembly, Modularization And Offsite Fabrication [PPMOF] Are Warranted For A Given Project,” Chemical Engineering, September 2003. 6 “Global LNG Trade Rises Just 0.3% In 2008,” LNG in World Markets, Poten and Partners, March 2009. 7 Llewely, D., “FPSOs—Key Regional Differences and Trends,” FPSO Houston by IBC, April 2008. 8 Hertz, D., “Capital Project Execution and Analysis,” Perry’s Chemical Engineering Handbook, Section 9: Process Economics, 8th Ed., 2008. 9 Peace, D., Commercial Considerations (Session 2.1), for FPSO Houston by IBC, April 2008. 10 Katz, T., G. Modes, and V. Giesen, “Seasick? How Many Times Can You Afford to Clean Up, the Cold Box,” GPA Europe Offshore Processing and Knowledge Session, Feb. 19, 2009. 11 Moorfield, D., P. R. Smith and B. P. Fitzgerald, “Temporary Safe Refuge Assessment,” Offshore Safety: Protection of Life and the Environment, Marine Management Holdings, May 20–21, 1992. 1

Christopher Caswell is a technology manager with KBR. He joined KBR in 1991 and has worked exclusively in LNG since 2000. His current role includes responsibilities for LNG liquefaction, receiving terminals, offshore LNG and technology development. His experience at KBR also includes equipment design, field services and project engineering. Mr. Caswell holds a BS degree in mechanical engineering from Cornell University and is a registered Professional Engineer in the State of Texas.

Charles Durr has worked on dozens of liquefaction facilities, receiving terminals and world-scale gas processing plants during his 39-year career with KBR. He has presented over 50 papers, holds eight patents and is a registered professional engineer. Mr. Durr graduated from Manhattan College in 1969 with an MS degree in chemical engineering. Ernst Rost is a project director for KBR at the Leatherhead, UK office. He has been involved in the engineering, construction and installation of onshore and offshore oil and gas facilities since 1988. He started his career in the offshore installation engineering and management services in The Netherlands. In 1994, he joined Bluewater and was involved in various leadership roles for three FPSO developments for the North Sea. In 2000, he joined KBR and was involved as project manager in various large offshore and onshore projects. In 2005, he held a leadership role in the mega GTL project in Qatar. Since 2008, he is focusing on business and technical development of Floating LNG and oversight of various other offshore projects. Mr. Rost is currently the project director and is designated to lead KBR’s first Floating LNG project.

Mark Kilcran is a senior project manager in KBR’s Leatherhead, UK office. He has been involved in the engineering, construction and installation of offshore facilities since 1990. Mr. Kilcran joined KBR from Saipem in 1997 and is a chartered structural engineer with an MSc degree from Imperial College, London. Since 2006, he has specialized in the execution of projects involving extensive modularization of onshore LNG plants and the application of offshore /FPSO technologies to develop offshore and floating LNG facilities designs. HYDROCARBON PROCESSING JULY 2009

I 49

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LIQUEFIED NATURAL GAS DEVELOPMENTS

SPECIALREPORT

Minimize risks from cryogenic exposure on LNG facilities A rational approach investigates methods to protect equipment and infrastructure from liquefied natural gas releases M. LIVINGSTON and R. GUSTAFSON, WS Atkins, Houston, Texas; P. GUY and L. J. PADILLA, AMG Engineering Inc., Houston, Texas; C. BLOOM, K. SHAH and V. H. EDWARDS, Aker Solutions US, Inc., Houston, Texas

Facility siting issues. For the most part, onshore LNG facilities have generous spacing between equipment; so significant cost savings in fire and cryogenic protection can be achieved without compromising safety. Generous spacing helps by locating some potential LNG leak sources away from process equipment and LNG storage tanks. In addition, relocating personnel to safe areas is usually not an issue. The decision to provide thermal protection becomes an asset protection/capital investment question for onshore facilities. Offshore LNG facilities have close spacing due to the high cost of building offshore. Accordingly, fire and cryogenic protection must be applied to a much higher proportion of equipment and structural steel. Egress and relocation to safe refuge areas are also significant factors. If the structure of the offshore platform is compromised, it would have to be abandoned using egress chutes, davit boats, freefall boats, life rafts, etc. Two philosophies can be applied to fire and cryogenic protection. One is to protect all structural steel and equipment that could be exposed to fire and/or cryogenic temperatures. A second philosophy only protects structural steel and equipment where failure could escalate the incident. Hazards of cryogenic exposure. Exposure of personnel

to LNG and cold gas can cause severe cryogenic burns, similar to frost bite or thermal burns. Contact with non-insulated and even insulated parts of equipment or vessels containing cryogenic fluids can also result in frost bite. Unprotected skin may stick to lowtemperature surfaces and flesh may be torn upon removal. These hazards should be controlled by separation, guarding, insulation

and personal protective equipment such as gloves, safety glasses and face shields. Inhaling cold vapor can damage lungs and may trigger an asthma attack in susceptible individuals. Asphyxiation is a serious hazard because vaporized LNG is usually odorless. Air contains 21% oxygen (O2). If the O2 content falls below 18%, adverse effects such as loss of mental alertness and performance may result. At 6% to 10% O2 or less, exertion is impossible; collapse and unconsciousness occurs. At 6% O2 or below death would occur in six to eight minutes. Personnel working in the vicinity of an LNG release can quickly be enveloped by cold hydrocarbon vapors resulting in 120 AISI 321 stainless steel 5052 aluminum 100 Impact value, ft-lb (Charpy V-Notch test)

he cryogenic nature of liquefied natural gas (LNG) facilities poses a potential risk to low-temperature exposure of personnel, structural steel, equipment, and instrumentation, control and power cabling. The probability of cryogenic exposure from containment loss of LNG is inherently greater than the probability of a fire. Many precautions are taken to eliminate ignition sources in LNG facilities. Cryogenic hazards. The hazards of cryogenic and fire exposure to personnel and facilities will be investigated using consequence modeling for pool and jet releases. Practical measures to eliminate or mitigate risks from cryogenic and fire exposure will be explored for both onshore and offshore LNG facilities.

67-33 yellow brass

80 Be-Cu

60 AISI 4130 steel

40 Brittle transition temperature range for most carbon steels 20 50 Pb-50 Sn soft solder 0 100

200 Boiling point of LNG

FIG. 1

400 300 Temperature, 째R

500

Low-temperature impact strength of metals.1

HYDROCARBON PROCESSING JULY 2009

I 51

SPECIALREPORT

LIQUEFIED NATURAL GAS DEVELOPMENTS Average rate of heating steel plates exposed to open gasoline ﬁre on one side

FIG. 2

Damage to deck of carrier casued by LNG spill.

O2-deficient zones. The expansion ratio of LNG is approximately 600:1. Therefore, the release of 1 m3 of LNG will produce 600 m3 of 100% NG in a short period of time. Hazards to structures and equipment. Carbon steel (CS), which is widely used in process plant structures and in the hulls of LNG carriers, loses its ductility and becomes brittle when exposed to LNG or cold NG. Fig. 1 shows that AISI 4130 steel loses half of its impact resistance at –60°F.1 Other CSs become brittle at temperatures of –20°F. LNG has a boiling point of –260°F (200°R). Since the beginning of LNG tanker trade in 1969, there have been eight marine LNG incidents resulting in spillage with some hull damage due to cold fracture. However, no cargo fires have occurred. Fig. 2 shows a 2-m crack in the deck of an LNG carrier exposed to a 30-l LNG spill. Direct contact of LNG with structural steel can rapidly cool the steel to below embrittlement temperature. Experiments have demonstrated that immersion of 12.7 mm (1/2 in.) and 25.4 mm (1 in.) pieces of painted steel in LNG can completely cool the steel to LNG temperatures in less than two minutes. When combined with suggested failure criteria for structural steel sections due to embrittlement, these high heat transfer fluxes predict steel section failure in as little as one to five seconds. Vapor heat transfer due to contact with cold NG velocities is predicted to be much slower. The cooling rate of structural steel depends on the amount of LNG available for chilling the steel per surface area, i.e., the LNG liquid flux in the jet. The LNG liquid flux is controlled by the flowrate and the location of the steel relative to the LNG release origin. Because cooling rates are so rapid, early leak detection, system isolation and shutdown have little effect on managing cryogenic LNG hazards in the immediate release area. By the time the detection and shutdown system has activated, the cryogenic damage is complete within the LNG exposure hazard envelope. Thus, cryogenic protection requires changing position, changing materials of construction, or adding protection such as cryogenic insulation or shielding. Rapid detection and process isolation will serve to limit the total volume of LNG released and mitigate the potential for LNG to spread over an even greater area, thereby exposing even more equipment and structures to cryogenic conditions. Polymeric materials, such as plastics and elastomers, are also subject to rapid brittle fracture on exposure to LNG, thus compromising some equipment components and electrical insulation. 52

I JULY 2009 HYDROCARBON PROCESSING

Plate temperature averaged over 2.3 m3 (24 ft2) °C (°F)

871 (1,600)

3 4

760 (1,400)

649 (1,200) 538 (1,000) 427 (800) 316 (600) 204 (400) Key 1 Plate 3.2 mm (1⁄8 in.) thick as computed 2 Plate 3.2 mm (1⁄8 in.) thick observed 3 Plate 12.7 mm (½ in.) thick as computed 4 Plate 25.4 (1 in.) thick as computed

93 (200)

0 FIG. 3

8 12 16 20 Time after start of the ﬁre, min.

Temperature-time profiles from API Standard 521 (2007).4

In the US, NFPA 59A is one of the key design documents for the design of LNG facilities.2 In Europe, EN 1473 is normally used.3 Both NFPA 59A and EN 1473 require that equipment, controls and structures whose failure would result in incident escalation must be protected from cryogenic embrittlement.2,3 Hazards of fire exposure. In contrast to cryogenic hazards,

fire hazards associated with vaporization of LNG releases can be substantially reduced by rapid detection of releases, followed by shutdown and isolation of equipment. Experience has shown that fire impinging upon structural steel takes a few minutes of exposure to threaten the steel’s integrity. Fig. 3 illustrates the rate of temperature rise of steel plates exposed to a gasoline pool fire.4 Heating rate would be more rapid for direct impingement of jet fires. The heat flux associated with large pool fires would be approximately 120 kW/m2 for fires larger than the object exposed and approximately 85 kW/m2 for pool fires comparable in size to the exposed object. The heat flux associated with jet fires would be approximately 250 kW/m2 maximum.5 Due to the rapid detection and shutdown system, large jet fires are limited to the high-pressure pumps, vaporizers and export gas pipeline sections of an LNG receiving, storage and regasification terminal. Low-pressure LNG releases from isolated lower pressure sections of the terminal are expected to cause local pool-fire hazards if ignited. Pool fires can be controlled with sloping, curbing and trenching. LNG releases that discharge at a pressure less than 4 barg are assumed to form liquid pools rather than jets. Modeling consequences of LNG containment loss. To

design necessary thermal protection measures for an LNG facility, it is necessary to predict the consequences from LNG and NG leaks. This can be done using commercially available correlation models or with computational fluid dynamics (CFD) models. The work illustrated here used a process hazard analysis software in which models leak rates for various scenarios, atmospheric dispersion and rainout

Select 99 at www.HydrocarbonProcessing.com/RS

SPECIALREPORT

LIQUEFIED NATURAL GAS DEVELOPMENTS

of releases and identifying potential effects from resulting fires and/ or explosions. This consequence modeling predicts which portions of the LNG facility require thermal protection from cryogenic and external fire exposure. Identifying credible scenarios. The first step in consequence modeling is defining credible leak scenarios to be modeled. Each LNG facility has its own isolation criterion. For the onshore LNG facility illustrated here, two minutes should be enough time to detect, isolate and shut down the facility in the event of an unplanned release or leak. Each isolated segment of the facility then contains an inventory of LNG, NG or a mixture of the two phases. The segment that has the leak will then empty at a rate that is dependent on variables such as the initial inventory, pressure and temperature of the segment and the size, as well as the location and orientation of the hole. Failure rates and hole size distributions for LNG service are not readily available. The Gas Research Institute prepared a report that collected failure rates and types of failure for LNG service equipment.9 But the report did not provide specifics on the size or distribution of holes. The report indicated that most major leaks were a result of either vaporizer tube ruptures or pump failures and that most major fires involved vaporizers.9 In current work, modeled hole sizes for onshore facilities include 0.12 in. (3 mm), 0.5 in. (12.7 mm), 0.75 in. (19 mm), 2 in. (50 mm) and 4 in. (100 mm). The 0.12 in. (3 mm) release was selected to represent small leaks such as a leaking seal. The 0.5 in. (12.7 mm) and 0.75 in. (19 mm) leaks were modeled to represent flange leaks and small-bore fitting ruptures such as instrument connections and drains. The 2 in. (50 mm) and 4 in. (100 mm) holes were modeled to represent fatigue, dropped objects, severe localized corrosion and large-bore holes. However, for the onshore facility illustrated here, scenarios leading to 2-in. and 4-in. holes and larger are not considered credible for thermal protection. In this situation, the scenarios are not credible because: • Cleanliness of LNG service • Most piping containing LNG is welded rather than flanged • Most instrument connections are ½-in. and ¾-in. taps • All piping and flanged connections to equipment containing LNG will be protected with insulation, jacketing and stainless steel straps

SAFE WAY TO TRANSPORT ENERGY

LNG is a safe and practical way to transport natural gas (NG) by sea from remote locations to user distribution systems. LNG is also an effective means for storing natural gas at peak-shaving plants during low-demand periods. As with any hydrocarbon processing facility, fire prevention and protection are important considerations in LNG facilities. Because of its cryogenic nature (atmospheric boiling point approximately –260°F), LNG also poses exposure to employees, facility structure and equipment. The design and operation of LNG terminals minimize ignition sources; thus, cryogenic exposure is more likely than a fire incident. This is particularly true in the high-pressure processing areas where the fluid inventory is lower but where the higher pressure creates greater potential for cryogenic exposure. Cryogenic exposure can cause freeze burns to employees and embrittlement to carbon steel, thus possibly resulting in structural failure. Protection from cryogenic exposure, as well as from fire exposure, is needed. Protective measures should be chosen that are effective for both fire and cryogenic exposure. Remember: Protective measures add cost, and should only be applied to those parts of facilities where the possibility of harm exists. Consequence modeling can be used to predict the extent of potential fire and cryogenic exposure so that protection can be applied where necessary. • A guillotine-type full-diameter rupture of welded piping is not considered a credible scenario • A complete loss of a gasket in a flange for a large-diameter LNG pipe is not considered credible. Isolatable segments and jet fire potential. Table

1 summarizes typical isolatable segments for an onshore LNG receiving, storage and regasification facility. Note: Not all of these segments will produce a jet fire with a duration long enough (five minutes) to cause failure of uninsulated structural steel, as shown by Table 2. Even including two minutes duration before isolation and shutdown is achieved, the duration of the leaks is less than five minutes for many of the credible scenarios. The duration of a leak is the two-minute shutdown and isolation time plus the

TABLE 1. Typical isolatable segments for an onshore LNG receiving, storage and regasification facility Section

Description

Assumed initial state

Pressure, psig

Temp, °F

Vol., ft3

Unloading arm

Subcooled LNG with a bubble point of 2.9 psig

–256.9

572

Unloading arm header to shore station ESDV

Subcooled LNG with a bubble point of 2.9 psig

–256.9

10,798

In-tank pumps discharge line to HP pumps ESDV

Subcooled LNG with a bubble point of 2.9 psig

140

–254.6

1,043

LNG inlet piping from ESDV in tank inlet manifold to tank

Subcooled LNG with a bubble point of 2.9 psig

–256.9

4,700

Upstream vaporizer piping (LNG)

Saturated LNG at 1,500 psig

1,480

–246.5

238

Downstream vaporizer piping (gas)

Methane gas at the specified temperature and pressure

1,400

42.4

7,177

7, 9

LNG surge drum, BOG condenser and recirculation line

Subcooled LNG with a bubble point of 2.9 psig

100

–254.3

5,847

ESDV upstream of HP pumps to ESDV upstream of vaporizers

Subcooled LNG with a bubble point of 2.9 psig

1,480

–246.5

2,280

LNG tanks unloading line header

Subcooled LNG with a bubble point of 2.9 psig

–256.9

3,488

Note: LNG modeled as methane

I JULY 2009 HYDROCARBON PROCESSING

LIQUEFIED NATURAL GAS DEVELOPMENTS TABLE 2. Duration of leak required for contents to reach atmospheric pressure in a typical onshore LNG receiving, storage and regasification facility Section 1

Description Unloading arm

7, 9

0.12 (3)

4.2

0.12 (3)

0.5 (12.7)

2.1

Section

Hole diameter, Pressure, in. (mm) psi @ 5 min.

Flame length, ft. @ 5 min.

Comment

2.9

N/A

Pressure < 58 psig

0.12 (3)

N/A

Pressure < 58 psig

2.1

0.12 (3)

N/A

Pressure < 58 psig

0.12 (3)

N/A

Pressure < 58 psig

to shore station ESDV

0.5 (12.7)

4.2

0.12 (3)

1,480

0.75 (19.05)

0.5 (12.7)

1,480

In-tank pumps discharge line

LNG inlet piping from ESDV

Upstream vaporizer piping (LNG)

Downstream vaporizer piping (gas)

LNG surge drum, BOG condenser

ESDV upstream of HP pumps to ESDV upstream of vaporizers

Duration, min

0.12 (3)

and recirculation line 8

Hole size, in. (mm)

0.75 (19.05)

in-tank inlet manifold to tank 5

TABLE 3. Jet fire hazard summary @ five minutes for a typical onshore LNG receiving, storage and regasification terminal

Unloading arm header

to HP pumps ESDV 4

SPECIALREPORT

LNG tanks unloading line header

0.12 (3)

8.5

0.75 (19.05)

1,480

140

0.5 (12.7)

2.4

2 (50)

2.9

N/A

0.75 (19.05)

2.2

0.12 (3)

696

15.4

0.12 (3)

0.5 (12.7)

696

0.5 (12.7)

2.8

0.75 (19.05)

672

0.75 (19.05)

2.3

2 (50)

435

146

0.12 (3)

120

7/9

0.12 (3)

84.

0.5 (12.7)

10.2

0.12 (3)

1,317

0.75 (19.05)

4.9

0.12 (3)

N/A

0.12 (3)

> 7,900

0.5 (12.7)

> 430

0.75 (19.05)

> 200

0.12 (3)

0.5 (12.7)

3.7

0.75 (19.05)

2.8

0.12 (3)

0.5 (12.7)

4.9

0.75 (19.05)

3.3

0.12 (3)

0.5 (12.7)

2.7

0.75 (19.05)

2.3

Note: These durations do not account for elevation differences within a segment

time required for the pressure to fall to atmospheric pressure in the isolated and leaking segment. Because LNG is relatively incompressible, because most segments have a vapor pressure of less than 3 psig, and because the segments will be insulated, leakage rate will drop fairly soon after isolation. Note: Autorefrigeration will occur during the initial leakage, partial vaporization and depressurization, thus rapidly bringing the LNG saturation pressure to atmospheric pressure. Once depressurization is complete, the leak rate will be due primarily to drainage and very slow vaporization caused by ambient heating of the insulated segment. Ignited releases were assumed to be a credible jet fire hazard if they existed beyond five minutes at a source pressure greater than 4 barg (58 psig). Table 3 summarizes the jet fire hazards. LNG releases that discharge at a pressure of less than 4 barg (58 psig) are assumed to form liquid pools. As the pressure continues to drop, wind and rainout become factors and active fire-fighting measures can effectively control the magnitude and exposure of the event. Consequence modeling software can be applied to predict when pool formation is expected and suitable precautions can be taken to protect structural elements and equipment. Prediction of cryogenic exposure. Ordinary structural

steel can fail rapidly when exposed to LNG. In this work, com-

FIG. 4

Duration < 5 min.

Pressure < 58 psig

LNG receiving, storage and regasification facility under construction at Cameron, Louisiana.

mercially available consequence modeling software was used to predict the range and liquid content of unignited jets of vaporizing LNG. These predictions provide a basis for identifying those structural members requiring thermal protection (see Table 4). Whereas, in Table 3, thermal protection from jet fires was not required in segments 1, 2, 3, 4 and 10, Table 4 shows that thermal protection from cryogenic exposure is required in all segments. This is because cryogenic exposure can lead to failure before the time needed to stop a leak. Risk-based protection of onshore facilities. There are

dozens of onshore LNG facilities around the world. Fig. 4 shows the new LNG terminal under construction for Sempra Energy at Cameron, Louisiana. Because most onshore LNG facilities are comparatively open and equipment is not congested, risk to life is low. In those cases, risk management becomes primarily a matter of asset protection. One risk-based philosophy that minimizes initial capital cost is to protect all assets that could be exposed to cryogenic fluids or fire, whose failure could lead to escalation of the incident. Because of wide spacing, and because many assets can fail without causing escalation, only some assets will require protection. HYDROCARBON PROCESSING JULY 2009

I 55

SPECIALREPORT

LIQUEFIED NATURAL GAS DEVELOPMENTS

MORE INFORMATION

Reference these sources for more information on fire protection: API RP 14G, API 2218,6 API 2510A,7 NFPA 59A,2 EN 14733 and API 2FB.8 Of course, loss of even a part of a facility can cause extended lost production with a major impact on the overall costs of the facility. The choice is a business decision. Coatings and insulation. Fire-approved insulation with a cementitious insulation can also provides economical protection of structural steel against short-term cryogenic exposure. Unfortunately, not all potential insulation products have been tested for their ability to withstand cryogenic exposure as well as fire exposure. Industry testing has been conducted on intumescent and subliming fireproofing coatings. These materials in conjunction with a cryogenic insulating coating can provide good protection from both cryogenic and jet-fire exposure. But these fireproofing materials are more expensive to apply than most cementitious systems. There are no current industry standard tests for the performance of the coating materials to resist the effects of LNG cryogenic exposure and then a subsequent fire. Current testing data available is generally the result of manufacturersâ&#x20AC;&#x2122; independent research, and ongoing construction project testing. One of the primary difficulties in designing for LNG release scenarios is that, depending on the specific scenario, there could be a release resulting in a cryogenic exposure, a fire exposure (jet, pool or spray) or a combination of events.

TABLE 4. Cryogenic hazard summary for a typical LNG receiving, storage and regasification terminal Section 1

Description Unloading arm

Unloading arm header to shore station ESDV

In-tank pumps discharge line to HP pumps ESDV

LNG inlet piping from ESDV in-tank inlet manifold to tank

7/9

Upstream vaporizer piping (LNG)

Downstream vaporizer piping (gas)

LNG surge drum, BOG condenser and recirculation line

ESDV upstream of HP pumps to ESDV upstream of vaporizers

K6EDG EG:HHJG: EGD8:HH 6C6ANO:G B>C>K6E DC"A>C: KE d[ <Vhda^cZ! 8gjYZ D^a VcY AE< 6HIB 9*&.&! *&--! +(,,! +(,-! +-.,! :C &(%&+"& '! >E(.)! )%.! )-& =^\]Zhi 6XXjgVXn Vaadlh WZhi edhh^WaZ 7aZcY^c\ id D[[^X^Va A^b^ih Je id ' HVbeaZ HigZVbh 6jidbVi^X 8Va^WgVi^dc ;Vhi :Vhn BV^ciZcVcXZ

Select 160 at www.HydrocarbonProcessing.com/RS 56

LNG tanks unloading line header

Hole diameter, in., (mm)

Jet hazard length, ft

0.12 (3)

4.2

0.5 (12.7)

18.8

0.75 (19.05)

0.12 (3)

4.9

0.5 (12.7)

18.8

0.75 (19.05)

0.12 (3)

5.3

0.5 (12.7)

19.8

0.75 (19.05)

27.7

0.12 (3)

5.7

0.5 (12.7)

18.8

0.75 (19.05)

25.6

0.12 (3)

5.2

0.5 (12.7)

0.75 (19.05)

0.12 (3)

0.79

0.5 (12.7)

3.7

0.75 (19.05)

5.8

0.12 (3)

6.2

0.5 (12.7)

20.6

0.75 (19.05)

27.3

0.12 (3)

5.7

0.5 (12.7)

23.1

0.75 (19.05)

0.12 (3)

4.8

0.5 (12.7)

18.8

0.75 (19.05)

27.2

LNG pools. If pooled LNG does not ignite, then the bases of columns and equipment supports could be exposed and then fail. A spill containment system consisting of curbing, sloped paving and troughs should be provided under all LNG lines and equipment in the plant. These containment systems limit the area that can be affected by an LNG spill and the exposure duration. Limiting exposure duration keeps insulation requirements from becoming too thick and impractical. The containment area layout should consider the potential exposure areas that could result from a pressurized LNG release. When designing the LNG spill containment system, consider the Leiden frost effect which leads to higher liquid velocities from creating a vapor film between the solid-spill containment system and boiling LNG. These higher liquid velocities, when compared to flowing water, could cause splashing around obstructions and overshoot the sloped trough at turns and changes in elevation. Where structural steel and/or critical equipment supports are within the curbing and/or drainage paths, they should be supported on a suitable concrete base that prevents exposure of the steel to the pooling, splashing or draining liquid. Protection of instrument and electrical cabling is normally not done because these systems are designed to be fail-safe. However, specific review of the potential exposure to the shutdown and blowdown system controls should be conducted. Direct exposure from cryogenic spray to shutdown/blowdown valves or

LIQUEFIED NATURAL GAS DEVELOPMENTS

FIG. 5

Tow out of the Adriatic LNG facility from Spain in September 2008.

actuators could result in the failure to isolate or deinventory the process. In general, the probability of the cryogenic spray impinging on the specific equipment should be considered for the overall probability of the equipmentâ&#x20AC;&#x2122;s failure on demand to evaluate the need for additional protective measures. Protective measuresâ&#x20AC;&#x201D;offshore facilities. Although less common and more expensive than onshore LNG facilities, LNG facilities can be located offshore when there are no suitable onshore sites. The first gravity-based offshore LNG receiving, storage and regasification facility for installation in the Adriatic

Sea to serve the Italian natural gas network is shown in Fig. 5. Offshore, because of close spacing, protection of all assets that could be damaged by exposure to cryogenic fluids or fire is recommended. Because of weight restrictions, a lightweight ablative layering system can provides both fire and cryogenic protection. Insulation suitable for offshore structural steel, decking and equipment must be resistant to salt water as well as to cryogenic and fire exposure. An epoxy-based system can provide both cryogenic and jet fire protection; it can also serve as a coating to inhibit corrosion effects. When compared with onshore LNG facilities, the significantly smaller areas associated with an offshore facility increase the potential for LNG release incidents to impair occupant evacuation and can escalate damage to the facilities. One method to reduce the potential exposures (both cryogenic and pressurized fire) is to provide flange guards on specific flange connections. Such flange guards serve to reduce the potential spray area, and to prevent well-formed jets from occurring. Valves. Cryogenic spray exposure on shutdown and blowdown valves can cause failure of the actuators prior to the valves moving to the safe position. This is acknowledged as a low probability event since it would require direct spraying onto an actuator to induce failure. However, the probability and consequence of the event should be reviewed for critical valves, and protection provided if necessary. In general, fire exposures to such valves is less likely to prevent the valve from moving to the safe position because the embrittlement effects from the cryogenic LNG spray can induce a more rapid failure. Cloud effect. When LNG vaporizes it creates a condensation cloud in the air around the NG cloud. This cloud is often mis-

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HYDROCARBON PROCESSING JULY 2009

I 57

SPECIALREPORT

LIQUEFIED NATURAL GAS DEVELOPMENTS

taken for NG itself, but is merely condensed water vapor resulting from the cryogenic release. Creating large fog clouds during LNG releases can impair the employees’ visual abilities. They may not be able to see the pooled LNG on the deck if it is obscured by a condensation-fog cloud. Based on this, all portions of the process unit should be reviewed to assure that the employees have access to more than one evacuation route to the temporary refuge no matter where an incident may occur. In addition, the emergency response team members should be specifically trained on LNG release characteristics so that they are properly prepared to respond. HP ACKNOWLEDGMENT An upgraded and revised presentation from the 8th Conference on Natural Gas Utilization, Spring National Meeting of the American Institute of Chemical Engineers, Tampa, Florida, April 26–30, 2009. BIBLIOGRAPHY 33 CFR Part 127-Waterfront Facilities Handling Liquefied Natural Gas and Liquefied Hazardous Gas, US Code of Federal Regulations, Washington, DC, 2009. 49 CFR Part 193-Liquefied Natural Gas Facilities: Federal Safety Standards, US Code of Federal Regulations, Washington, DC, 2009. Center for Chemical Process Safety, Guidelines for Fire Protection in Chemical, Petrochemical, and Hydrocarbon Processing Facilities, American Institute of Chemical Engineers, New York, 2003. 1 2

LITERATURE CITED Flynn, T. M., Cryogenic Engineering, 2nd Edition, CRC Press, Taylor and Francis Group, Boca Raton, Florida, 2005. “Standard for the Production, Storage, and Handling of Liquefied Natural Gas (LNG), NFPA 59A, 2009 Edition, National Fire Protection Association, Quincy, Massachusetts. EN 1473, “Installation and Equipment for Liquefied Natural Gas – Design of Onshore Installations,” European Committee for Standardization, Brussels, Belgium, 2007 “Pressure-relieving and Depressuring Systems,” ANSI/API Standard 521, 5th

5 6

Edition, American Petroleum Institute, Washington, DC, January 2007. DiNenno, Ph. J., Ed., The SFPE Handbook of Fire Protection Engineering, 3rd Edition, National Fire Protection Association, Quincy, Massachusetts, 2002. “Fireproofing Practices in Petroleum and Petrochemical Processing Plants,” API Publication 2218, Second Edition, American Petroleum Institute, Washington, DC, August 1999. “Fire-Protection Considerations for the Design and Operation of Liquefied Petroleum Gas (LPG) Storage Facilities,” API Publication 2510A, Second Edition, American Petroleum Institute, Washington, DC, December 1996. “Recommended Practice for the Design of Offshore Facilities Against Fire and Blast Loading,” API Recommended Practice 2FB, American Petroleum Institute, Washington, DC, 2006. “Reduction of LNG Operator Error and Equipment Failure Rates,” GRI 90/0008, Gas Research Institute, Chicago, April 20, 1990.

Michael C. Livingston, PE is a chief engineer and the HSE and reliability group manager for the Houston oil & gas division of WS Atkins, Inc. He is a registered professional engineer in the states of Oklahoma, Texas, Alaska and Mississippi and is responsible for managing and executing risk, safety and fire protection services provided to the oil and gas industry. Mr. Livingston serves on the Texas A&M Process Safety Center’s Steering Committee and Technical Advisory Committee. He holds a BS degree in chemical engineering and an MS degree in environmental engineering from the University of Arkansas. He has contributed to six engineering publications and one risk management book. He is a member of ASSE, NFPA and SPE-Gulf Coast Section.

Richard Gustafson, PE, CSP, is a principal engineer for the Houston oil & gas division of WS Atkins, Inc. He is a registered professional engineer in the state of Texas. Mr. Gustafson’s responsibilities include developing LNG cryogenic and fire quantitative risk analysis methodologies and tools. He holds a BS degree in biological science from the University of Connecticut, and BS and MS degrees in chemical engineering from Villanova University. Mr. Gustafson has contributed to four engineering publications and is a coeditor of four books on risk assessment. He is listed as a significant contributor to the API 4628, “A Guidance Manual for Modeling of Accidental Releases to the Atmosphere.” W. Phillip Guy is the founder and president of AMG Engineering in Houston, Texas. He earned his degree in fire protection engineering from the University of Maryland in 1990. He is a registered professional engineer in the state of Texas. Mr. Guy has extensive experience in fire protection engineering and loss prevention for a wide variety of industrial and commercial projects. Luis J. Padilla, PE is a senior consulting engineer for AMG Engineering Inc. He has over nines years of experience in fire protection engineering and loss prevention on a wide variety of industrial and commercial projects. His oil and gas experience includes both onshore and offshore facilities as well as LNG terminals and oil and gas production facilities. He holds an MS degree in fire protection engineering from Worcester Polytechnic Institute and a BS degree in mechanical engineering from the Polytechnic University of Puerto Rico. Mr. Padilla is a registered professional fire protection engineer in Puerto Rico and the state of Texas. Craig W. Bloom is a senior manager of health, safety and environment for Aker Solutions US, Inc., Houston, Texas. He has over 28 years of experience in the petrochemical, refining, gas processing and offshore production industries. Mr. Bloom has over 17 years of experience in developing and implementing process safety programs for a variety of offshore and onshore oil & gas projects and LNG grassroots facilities. He holds a BS degree in chemical engineering from The Pennsylvania State University. Kamal Shah, PE is a technical vice president with Aker Solutions US Inc, Houston, Texas. He has been working with the company for 22 years and is involved in the process design, management and technology development for many oil and gas processing and energy projects. Prior to joining Aker Solutions, he was chief process engineer at Key Engineering, Inc. He holds BS and MS degrees in chemical engineering from Michigan State University and is a registered professional engineer in the state of Texas.

Victor H. Edwards PhD is the director of process safety for Aker Solutions US, Inc., Houston, Texas. He received five DuPont awards for safety and environmental engineering excellence during his 25 years of experience with Aker Solutions. Dr. Edwards has contributed more than 60 technical publications. He chairs the Technical Advisory Committee of the Process Safety Center at Texas A & M University. Dr. Edward holds a BA degree from Rice University and earned his PhD from the University of California at Berkeley both degrees in chemical engineering. He is a registered professional engineer in the state of Texas, AIChE fellow, and a member of ACS, AAAS, NFPA, NSPE and the New York Academy of Sciences. Select 158 at www.HydrocarbonProcessing.com/RS 58

LIQUEFIED NATURAL GAS DEVELOPMENTS

SPECIALREPORT

Consider investing in a standard-compliant process analyzer High profits are realized with accurate vapor pressure testing O. SAUER and H. PICHLER, Grabner Instruments Messtechnik GmbH, Vienna, Austria

apor pressure is an important physical property of volatile liquids especially gasoline, gasoline-oxygenate blends, crude oil and liquefied petroleum gas (LPG). The reasons to invest in standard-compliant vapor pressure process analyzers are of crucial interest for refineries, pipelines, terminals and offshore plants will be explained.

Compliance with governmental regulations. Vapor

pressure provides an indication of fuel performance under different operating conditions—whether a fuel will cause vapor locks at high ambient temperatures or high altitudes, or will provide easy starting at low ambient temperatures. Petroleum product specifications are regulated by various governmental agencies and maximum vapor pressure limits for crude oil and gasoline are legally mandated in many areas as a measure of environmental pollution control. Official vapor pressure limits for spark-engine fuels are dependent on ambient conditions, commonly referred to as summer-graded or winter-graded fuel. In many countries, it is obligatory to blend gasoline with biofuels, which in turn affects the fuel’s vapor pressure. Maximum vapor pressure limits are controlled according to various ASTM, EN and IP standards. Safety for transportation and storage. Pipeline operators, offshore platforms, terminals, fuel depots or oil tankers detect vapor pressure before transporting crude oil or other petrochemical products such as gasoline or LPG for subsequent processing. It is absolutely necessary to know the vapor pressure of the transported substance to prevent costly damage done to the transportation system. Damage prevention is not just limited to the supplier. Customers require their supplier to guarantee a maximum vapor pressure before accepting fuel delivery. Examples that indicate typical applications that require vapor pressure testing are: • Offshore platforms determine the vapor pressure of crude oil to determine the bubble point, before transporting the crude via pipeline or tanker to a distribution terminal/platform. Excess gas is burned to prevent damage done to the transportation medium. If the vapor pressure of the crude case is too high, pump cavitation during transfer operations may happen. It is advisable for a platform operator to have the platform equipped with a vapor pressure analyzer. Thus, the operator is able to provide evidence

that the released crude is delivered according to specifications— and to prevent costly damage. • Liquid terminals are used for storage or as a buffer, before petroleum products are transferred or shipped for further processing or delivery. Fuel depots are used whenever petroleum products from different oil production sources are transported to a central storage area. Vapor pressure is an important property to determine product quality delivered from different sources. Safety for the facility and its personnel are key concerns with regard to both floating and fixed-roof tanks surrounding storage. With fixed-roof tanks, vapor pressure limits are in place for explosion protection. When gasoline or crude oil is released, the volume has to be replaced by gases. This is controlled by testing the vapor pressure. In floating-roof tanks, too high vapor pressure will create bubbles under the roof that may lead to a roof overturn. Apart from the costs that a failure may cause, environmental regulations limit maximum vapor pressure in floating-roof tankers to prevent air pollution control by the outgassing of petroleum products. Profit optimization in refineries and pipelines. In refineries, crude oil is processed to gasoline with different quality (octane numbers). Naphtha is blended with oxygenates, butane and octane boosters to conform to governmental and environmental regulations, to ensure better fuel performance and reduce production costs. To maintain a certain quality level of the refined product, refineries have to watch vapor pressure closely during the entire refining process. Industries that obtain large profits by using precise vapor pressure testing are: • Refineries. By blending C4-compounds into gasoline, profit margins can be optimized, while the heat of combustion remains unchanged. C4-like butane is far cheaper than crude oil, but also raises vapor pressure. Refined gasoline must adhere to maximum vapor pressure limits, specified by standards. Thus, the highest profit is made when blending as close as possible to official limits. In turn, this requires an analyzer capable of testing the vapor pressure standard-compliant along with being precise. • Pipeline operators, plants and transportation. Usually, suppliers and customers agree over maximum vapor pressure limits of crude oil or gasoline delivered to a plant or terminal. This is necessary to ensure safety for transportation and storage, and to guarantee that the customer receives a specific fuel quality. HYDROCARBON PROCESSING JULY 2009

I 59

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LIQUEFIED NATURAL GAS DEVELOPMENTS A prominent application for vapor pressure testing is C4-blending. Crude price valuation can be increased significantly when butane or propane is blended into the crude. The addition of these hydrocarbons is limited by the maximum Reid vapor pressure (RVP). Depending on the RVP prior to blending, typically ratios of 1% to 5% of hydrocarbons are blended into the crude. Thus, even a small plant handling 20,000m3 per month can expect an increase of up to $100,000 through C4-blending. So, accurate blending of cheap butane into crude oil—while monitoring standard-compliance and product quality via vapor pressure detection—can significantly improve the plant’s profit and pay down the vapor pressure analyzer equipment costs in the short-term.

SPECIALREPORT

intermittently every five to seven minutes with the accuracy of modern lab equipment. Triple expansion method measuring principle. The

stream product is conditioned in the sample conditioning system that allows the measuring system to operate. Pressures up to 70 bar in the stream are brought down between 0 bar and 7 bar, filling pressure adjustable by a pressure regulator depending on the applied sample (sample conditioning). The filling pressure must be higher than the sample’s vapor pressure to receive proper system filling on one side and not allowing for the escape of high volatiles on the other side. The sample conditioning system guarantees a representative sample in the measuring unit like in the stream line. Accurately measuring vapor pressure in process. High Fig. 1 illustrates the steps involved with a process analyzer meaaccuracy can be achieved when vapor pressure is measured directly, suring cell. The sample is introduced through the Luer sample inlet instead of assessing it with re-adjustable, unreliable or unproven (1) and the sample inlet valve (2) into the measuring chamber. The correlation models. One method to be standards-compliant and to automatic sample introduction and volume adjustment are accomobtain highly accurate measurements is to test with a process anaplished by a piston with an integrated pressure transducer (3). lyzer. This utilizes the same principle The measuring chamber (4), with a as highly precise laboratory instru- ■ ... accurate blending of cheap 5 mL total volume is rinsed with 3 x ments. With a measurement method 2.5 mL and filled with the approprithat fully complies with the strictest butane into crude oil—while ate sample amount. After closing the ASTM, EN and IP standards as well monitoring standard-compliance and valve (2), single or triple expansion to as US Environmental Protection 5 mL (a vacuum is created by piston Agency (EPA) regulations for vapor product quality via vapor pressure withdrawal) is obtained by additional pressure testing of crude oil, gasoline strokes. The measuring cell detection—can significantly improve piston and LPG. No further testing in the temperature is controlled by a highlaboratory needs to be done to certify the plant’s profit ... power thermoelectric module (5) and measurement accuracy. measured with a precision resistance As an effective example, the triple expansion method for detertemperature detector (RTD) sensor (6). Preferably, the analyzer mining vapor pressure is mentioned. The method is simple and should handle more than one sample stream simultaneously, incorsmart, based on the premise that liquid vapor pressure remains porates an explosion-proof Class I housing, is ATEX and UL certiconstant and that all components, like dissolved air, follow the ideal fied and data is output via a standard MODBUS digital signal or gas equation. An expansion is performed in three steps at a constant a standard 4-20mA analog signal. temperature. Three total pressure values are determined. From these values, the partial pressure of the air, liquid solubility factor and the Triple expansion method’s analytical performance. liquid’s absolute vapor pressure are calculated. Results are available The excellent performance of the triple expansion method has been proven in various round robins in refineries and independent laboratories. Fig. 2 illustrates online gasoline measurement results compared to lab analyzer measurements. Triple expansion method accuracy. Per standard ASTM

D5191, the sample’s cooling and air saturation are required prior to the vapor pressure measurement. Since this makes sample 3

Lab analyzer

80 y = 0.9776x + 1.9249 R2 = 0.9997

75 70 65 60 65

FIG. 1

A process analyzer measuring cell—triple expansion method.

FIG. 2

75 80 Process analyzer

Process analyzer vs. lab analyzer, various samples using ASTM D6378 method. HYDROCARBON PROCESSING JULY 2009

I 61

LNG DEVELOPMENTS

P (kPa)

Italian design A masterpiece

69.6 69.4 69.2 69.0 68.8 68.6 68.4 68.2 68.0 67.8 67.6

DVPE ASTM D6378 process analyzer DVPE ASTM D5191 Time

FIG. 3

Creativity is the art we apply to achieve superior design and developments in technology. For over 70 years we have designed and supplied cost-effective technology, process plants and equipment for the oil & gas industry around the world. With our expertise we provide tailor-made solutions from studies and revamps to skid-mounted units and complete turnkey plants. Our own technologies are complemented by alliances with renowned licensors such as BOC, BP Amoco, IUT, WorleyParsons and UOP to provide state-of-the-art answers to design issues. Oil & gas production facilities: separation, filtration, NGL and LPG recovery, stabilisation Gas & liquids treatment: amines, physical solvents, molecular sieves, iron oxide, glycol, silica gel, Merox™, sour water stripping Sulphur recovery: Claus, ammonia Claus, oxygen-enriched Claus, tail gas clean-up, Thiopaq™, redox, sulphur degassing, sulphur forming, advanced process controls Flue gas treatment: De-SOx, De-NOx & De-Dioxin, ammonia production Gas manufacture: low pressure gasification Special process equipment

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Dry vapor pressure equivalent (DVPE) of gasoline—ASTM D6378 process analyzer vs. ASTM D5191. The jump in the D5191 line indicates that the sample’s chilling and air saturation had been performed as per standard requirements.

conditioning tedious when testing vapor pressure in process, the triple expansion method offers a smart solution for fast and highly precise tests, eliminating conditioning bias and errors, commonly associated with vapor pressure tests. While standard compliance is a must to conform to governmental and environmental pollution control regulations, a “precision-exceeding standard” is necessary to tap the full profit potential through vapor pressure measurement. Fig. 3 shows typical sample behavior when testing using the ASTM D5191 standard against measurements using the ASTM D6378 standard by an online analyzer. Lessons learned. When considering using a vapor pressure

process analyzer in refineries, two questions should be asked to support a professional purchasing decision. How good is the instrument’s precision? Finding out which analyzer has a proven record of the highest accuracy is critial for profit optimization over time. Direct vapor pressure testing probably is the best choice, because permanent correlations or corrections of measured results are obsolete. Does the instrument conform to standards? Most online vapor pressure analyzers do not test according to industry standards. Thus, frequent additional sample checks and result verifications have to be done in the laboratory. Consequently, having process analyzers conforming to industry standards are not a “nice to have” feature. With refineries forced to reduce costs and optimize the operation process, it is imperative for modern process engineering to reach out for new and better technology to reduce workload. HP

Dr. Oliver Sauer is the director of marketing and sales with Grabner Instruments. He has 10 years’ field experience in technically related marketing and sales positions. Dr. Sauer holds a PhD in physical chemistry and an MSc degree in engineering management. His interest includes marketing of technically challenging solutions to a various range of industry professionals.

Hannes Pichler, is a product marketing manager with Grabner Instruments. He earned his MSc degree in natural sciences from the University of Vienna. Mr. Pichler has been working in the field of analytical, laboratory and quality control instrumentation for several years, focusing on economic payoff and improvement of efficiency for customers worldwide.

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)DEAS FOR GROWTH )DEAS FOR SUSTAINABILITY

!MMONIA &ERTILIZER s 3YNGAS s (YDROGEN s 2ElNING

/RGANIC #HEMICALS s /LElNS s #OAL 'ASIlCATION s #ARBON #APTURE 3TORAGE

KBR Technology specializes in developing and licensing process technologies worldwide. From refining to ammonia, from chemicals to coal gasification, from olefins to syngas, KBR Technology helps you accelerate profitability and sustain growth. For more information, visit www.kbr.com/technology or email technology@kbr.com © 2009 KBR All Rights Reserved K09062 05/09

Select 89 at www.HydrocarbonProcessing.com/RS

PIPING/RELIABILITY

Estimate water hammer loads in steam piping The problem is more complicated because of the two-phase flow S. SAHA and P. DARJI, Reliance Refinery, Jamnagar, India

ost of us are aware of the disastrous effects of water hammer (e.g., pipe rupture, dislocation from support, support and equipment damage, etc.). The term “water hammer” refers to shocks sounding like hammer blows produced by a rapid change of fluid flow in a closed pipeline. The common occurrence of the phenomenon is in liquid pumping systems. It is caused by flow disturbance or transients. A typical example is the sudden closure or opening of the valve in a cooling water network. Rapid valve closure causes the fluid to stop suddenly as a result of which the kinetic energy of the moving fluid is converted into pressure energy. This produces pressure surges causing a series of shock waves in the piping. An abundance of literature1–3 is available on water hammer and the surge analysis and design of the hydraulic piping for single-phase systems (e.g., fluid is water or any liquid). However, for steam systems the phenomenon is quite complicated due to the two–phase effect. The detailed analytical treatment of the surge analysis is quite complex which involves the biphase mass and momentum equations and interaction between phases. Still, there is a lot of scope of development and it is a topic of research. In this article we briefly explain the phenomenon in simple terms while presenting some approximate methods of estimating the loads on the piping that should be of interest to piping designers. Steam line water hammer. As per the extensive research

conducted by reputed institutes, there are seven basic mechanisms that initiate water hammer in steam lines.4 One of them, the mechanism of a steam-propelled slug, is very common.3 This is also referred to as “condensate-induced water hammer” or the active mechanism hammer. The active mechanism happens when there is condensate build-up and water slugs in live steam piping. If steam condensation is allowed to accumulate at low points in steam piping, at one stage it tends to restrict steam flow. Water slugs are lifted off the condensate and propelled by the steam at high speeds. Their movement suddenly stops on meeting an obstruction such as a bend or a valve. This results in the conversion of their kinetic energy into pressure. The higher the mass and velocity of the water slug the higher the pressure and its impact on piping. The impact may have mild to severe effects on piping. This impact may displace the line from its original position if the line is not properly restrained by supports. In a severe impact, supports may also get broken. Hence, it is important to consider the hammering effect while designing supports to take care of this impact load. However, another mechanism known as passive water hammer4,5 is also very important. We shall describe the phenomenon in some

Hot steam source

Hot liquid

Subcooled liquid

Initially closed valve FIG. 1

Configuration for passive water hammer.

detail. Consider a case (Fig. 1) when there is hot steam upstream of the valve followed by a subcooled liquid due to cooling up to the valve. The line pressure downstream of the valve is lower than the saturation pressure. When the valve is quickly opened there is flow of the subcooled liquid followed by the hot steam. At the valve throat there could be choking of the steam. This causes a change in steam velocity that gives rise to steam pressure as per Joukowsky’s equation.2 Approximate estimation of hammer load. The magnitude of the pressure rise, ΔP, is given by Joukowsky’s formula,2

P = mC m v

(1)

where Δv is the change in fluid velocity (i.e., cold flow to hot flow). The steady-state velocity of the hot fluid passing through the valve may be obtained from Moody’s diagram.6 ␳m and Cm are mixture density and acoustic speed, respectively. The mixture density is given in terms of the void fraction, x, as: m = x s + (1 x ) w (2) ␳s and ␳w are the steam and water densities at the saturation temperature. For single-phase flow x is either 0 or 1. Mixture acoustic speed is:2

C m = (K eq / m ) / [1+ (K eq / E )(D / t )]

(3)

where D and t are the pipe mean diameter and thickness, respectively. E is the pipe material modulus of elasticity which is normally steel for metallic pipes. Keq is the equivalent bulk modulus of the fluid. For single-phase flow its value is either of water, Kw , or steam, Ks . For water its value is 2.2 GPa and for steam it depends on the specific heats, Cp , Cv , and the state.7 The equation that gives the equivalent bulk modulus of the water–steam mixture is: HYDROCARBON PROCESSING JULY 2009

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PIPING/RELIABILITY

Axial stop

FIG. 3 FIG. 2

Axial stop failure.

Piping configuration.

that the safety factor was inadequate in this case. A new support design was performed using the revised loads. 1/K eq = (x /K s ) + (1 x ) /K w

(4)

It is seen that the bulk modulus of water can be substantially lowered by steam entrained in the water. This means that the mixture acoustic velocity is much less than that of pure water. This is of vital importance in estimating hammer forces. The forces obtained by considering the single-phase properties are in general highly overestimated because of the inaccurate value of the acoustic speed. After obtaining the acoustic speed the dynamic forces in the piping may be obtained using Joukowsky’s equation (Eq. 1): Fdyn = DLF ( PA)

(5)

where A is the pipe flow area and DLF is the dynamic load factor generally considered as 1.8 to 2.0 for an equivalent static analysis.

Conclusion. The right approach toward mitigation of the problem would be to avoid any condensate build-up and proper operational procedure. But this seldom happens in practice. There could be several reasons such as steam trap malfunction, faulty operation or lack of proper design, construction and system maintenance. From the viewpoint of initial design it would be prudent to have some realistic estimate of the hammer loads. A single-phase calculation could produce unrealistic forces that could not be feasible for support system design. In fact, it could be about 2,500 kN or more. However, with a better understanding of the phenomenon it would be possible to simplistically quantify realistic loads without resorting to tedious calculations. This will help in making the system design more reliable, thereby increasing the plant life. Our study is a step in that direction. HP

Case study. An axial stop failure was observed in a utility steam

line. The line was 16 in. NB, standard wt. schedule and carrying low-pressure steam (5.1 kg/cm2g, 177°C). The line was axially displaced by about 100 mm from its original position and was close to touching the adjacent lines. Fig. 2 shows the line configuration and Fig. 3 shows the axial stop condition after failure.

1 2 3 4

Problem analysis. Initially a thermal analysis was carried out.

The results showed no abnormality and all the design parameters were well within limits. The nature of the failure indicated a large impact load on the pipe caused the failure. But the problem could not be explained by the normal water hammer phenomenon that occurs on valve closure. The failure was observed on opening the valve during startup. Hence, this made us consider a passive water hammer. The first step was to estimate the acoustic speed for which the void fraction is required. Assuming the valve opening as adiabatic, the enthalpy balance (643.3 kJ/kg) at saturation gives us the void fraction, x, to be around 0.1. This results in the acoustic speed of 91m/sec and a pressure surge of 8.6 bar. The resulting force (Eq. 5) in the pipe segment is 192 kN. From the support failure the force may be also calculated. The value turns out to be 230 kN, which is somewhat close to the estimated value. This also provides some confidence in the method. The actual design maximum load was 90 kN, which was much lower than both values. This proved 66

I JULY 2009 HYDROCARBON PROCESSING

6 7

LITERATURE CITED Antaki, G. A., Piping and pipe line engineering, Marcel Dekker, 2003. Streeter, V. L., Fluid Mechanics in Systems, Prentice Hall. McKetta, J. J., Piping Design Handbook, Marcel Dekker, 1992. Van Duyne, et. al, “Water Hammer Events Under Two-Phase Flow Conditions,” International Multiphase Fluid Transient Symposium, FED Vol. 87, ASME Winter Meeting, California, USA, 1989. Arastu, et. al., “Computer Models for the analysis of severe water hammer initiating mechanisms,” International Mechanical Engineering Congress, ASME, Chicago, USA, 1994. Moody, J. F., Introduction to Unsteady Thermo-Fluid Mechanics, John Wiley & Sons, New York, USA, 1990. Spalding, D. B. and E. H. Cole, Engineering Thermodynamics, Edward Arnold, London, UK, 1967.

S. Saha works in the Engineering Centre of Reliance Refinery at Jamnagar (India) as a chief of stress analysis. Dr. Saha holds a B.Tech. (Hons.) degree in mechanical engineering from the Indian Institute of Technology (Kharagpur, India) and a Ph.D from the Indian Institute of Technology (Kanpur, India).

Pradeep Darji is a senior pipe stress analyst in the Engineering Centre at the Reliance Refinery, Jamnagar, India. He has been involved in troubleshooting plant problems in the complex. Mr. Darji holds a post-graduate degree in mechanical engineering from the University of Pune.

GAS PROCESSING DEVELOPMENTS

Do you have hard-to-handle gases? Consider using this second-generation hybrid solvent for treating D. L. NIKOLIC, R. WIJNTJE and P. P. HANAMANT RAO, Shell Global Solutions International B.V., Amsterdam, The Netherlands

as development projects face growing challenges—increasingly contaminated Dehydration/ HC, H2S, CO2 AGRU HC, RSH mercaptan HC resources, tightening sales specifications and RSH, COS absorber removal stricter environmental emission standards. CO2, H2S, H2O, carbonyl sulfide (COS), mercaptans H2S, CO2, COS, HC HC (RSH) and organic sulfides are generally removed H2O HC, RSH, COS from the gas prior to sale or liquefaction. This may result in complicated treating process line-ups, CO2 H2S, CO2, S recovery AGRU Regen. gas Regen. gas RSH, often requiring multiple process units. TechnolRSH, or S regenerator absorber regenerator COS, HC COS, HC reinjection ogy development or smart integration of different process steps offer many opportunities for line-up H2S, CO2, COS, HC simplification. A key unit in these line-ups is the acid-gas removal unit (AGRU), which traditionally Top panel relies on amine-based solvent absorption. Based on proven design practices with hybrid HC, H2S, CO2 AGRU HC Dehydration HC RSH, COS absorber and accelerated solvents, as well as long-term operational experience, a second-generation hybrid H2O H2S, CO2, COS, RSH, HC solvent (SX) that is ideally suited for hard-toS recovery CO2 handle gases is discussed. Several case studies are AGRU or H2S, CO2, RSH, COS, HC regenerator presented showing the benefits of SX technology, S reinjection both for solvent swaps in existing plants along Bottom panel with new plant design. FIG. 1 The top panel shows a typical line-up for treating contaminated natural gas Benefits include: while the bottom panel shows a simplified line-up using SX. • Increased capacity • Energy consumption reduction sulfides are typically present in parts per million (ppm) ranges, • Lower chemical consumption and waste disposal but are difficult to remove.1 Since exploitation of more dif• Tighter CO2, H2S and COS specifications ficult gases has increased in recent years, requiring the diffi• Simplified process line-ups. cult removal of many sulfur species as well as CO2 and H2O, For new plants, it has been shown that simplicity and reliabilthe gas-treating step in development projects has significantly ity are achieved by using SX, while significantly reducing capital increased in complexity. This often requires a combination of expenditure (CAPEX) when compared to traditional accelerated process steps and process units. This is further complicated by methyldiethanolamine (MDEA) line-ups for highly contaminated the tightening of product specifications both for sales gas and gases. Commercial facilities currently utilizing SX indicate anticiliquefied natural gas (LNG), as well as stricter environmental pated advantages and lasting stability. emission standards.2 A typical process line-up involving several treating steps is Background. The production, processing and natural gas use shown in the top panel in Fig. 1. Typically, H2S, CO2 and some have been well established for several decades, providing a clean, COS are removed in the AGRU, along with RSH and H2O in the reliable, safe and secure energy source. Gas development projects molecular sieve unit following the AGRU. COS and other organic have evolved from relatively simple exploitation of sweet gas sulfides are dealt with further downstream in separate unit(s). A reserves that were directly routed into domestic and industrial process line-up of this complexity presents numerous opportunisupply networks to exploitation of contaminated and remote gas ties for simplification, both through technology development and deposits through liquefaction, marine transport and regasification. smart integration of different process steps. In addition, the well-established infrastructure of oil product Application of SX technology and the resulting simplification markets can be used for additional value generation through gasis illustrated in the bottom panel in Fig. 1. H2S, CO2, RSH, COS to-liquids technology applications. and organic sulfides are removed in the AGRU, while the molecuMajor contaminants in natural gas are typically CO2, H2S lar sieve unit is only needed for dehydration. For this case, there and H2O. Other contaminants, such as RSH, COS and organic is no need for a regen gas absorber or regenerator. HYDROCARBON PROCESSING JULY 2009

I 67

GAS PROCESSING DEVELOPMENTS Focus on AGRU. Typically, the AGRU is employed for H2S and CO2 removal. The AGRU consists of an absorption step, where acid gases are absorbed in the treating solvent and a regeneration step where the absorbed components are stripped from the solvent. Acid-gas stream from the regenerator is then further processed (i.e., sulfur recovery or acid-gas reinjection) and the regenerated solvent is returned back to the absorber. Optimal AGRU design and solvent choice is driven by the contaminant removal requirements.3 Aqueous amines—MDEA, diisopropanolamine (DIPA), diglycolamine (DGA), etc.—are the most widely used solvents for H2S and CO2 removal from natural gas. By using the standard acid-base chemistry, these amines allow for a straightforward removal of H2S and CO2. If other contaminants, like weak acids are present, standard aqueous amines have a marginal impact on their removal. On the other hand, physical solvents, which rely purely on physical interactions between the solvent and the gas, are efficient in removing these trace components from the gas.4 However, due to the high loss of hydrocarbon components through co-absorption and the relatively high capital costs, pure physical solvents are rarely applied in natural gas treating. Thus, chemical solvent blending with a physical solvent, in the so-called “hybrid solvent” presents a solution that can combine the efficient removal of all present contaminants in one AGRU.

main reactant, and piperazine as the accelerator), sulfolane and water, thus leveraging the advantages of well-proven and established technologies in a single acid-gas removal process. The advantages of SX are summarized in Table 1. Smaller absorber size. In the presence of piperazine, the CO2

removal capacity is increased due to the enhanced reaction kinetics. This has been demonstrated in pilot plant experiments. A 6.5-indiameter absorber column was used to directly compare SX and the first-generation DIPA-based hybrid solvent (FG) at varied gas to solvent ratios as well as at different levels of CO2 contamination in the feed gas. Therefore, a smaller absorber column is required when using SX as opposed to FG. Alternatively, for debottlenecking cases, higher gas throughput can be achieved with SX for existing columns. In addition, the extensive pilot plant testing allowed for the development of a sophisticated model that can accurately describe SX performance under wide-ranging conditions. Improved trace sulfur removal rates. Similarly to

SX solvents. Hybrid solvents have been on the market for a few decades, and typically combine an amine (such as DIPA) and sulfolane as the physical component along with water.1 The drive for reliability, robustness and simplification in gas processing operations, resulted in SX development. In this case, piperazine is added to the hybrid solvent to enhance CO2 reaction kinetics and COS hydrolysis. Piperazine has various advantages over other activators, making it the accelerator of choice for many companies and it has been used in gas treating for over two decades. With this in mind, SX employs two amines (MDEA, as the

CO2, in the presence of piperazine, the COS removal capacity is increased due to the enhanced reaction kinetics. This has been demonstrated in pilot plant experiments (see Table 2). In these experiments, FG and SX were compared. Under these conditions, even at a 40% lower circulation rate, SX has superior COS removal performance. Additionally, FG formulation typically used in the past to remove COS contains more sulfolane than SX, resulting in reduced hydrocarbon co-absorption when SX is used. With respect to RSH removal, FG and SX have comparable performance that is determined by the sulfolane concentration and solvent circulation rate. When compared to the accelerated MDEA process, SX removes RSH in a continuous manner, simplifying the downstream Claus unit operation. Whereas the cyclical operation of the molecular sieve unit is used in combination with an accelerated MDEA solvent to remove RSH.

TABLE 1. Advantages of SX when compared to FG

Significantly reduced energy consumption. The energy

Parameter

First-generation DIPA-based hybrid solvent (FG)

Second-generation MDEA-based hybrid solvent (SX)

Chemical composition

DIPA, sulfolane water

MDEA, piperazine, sulfolane, water

CO2 removal

Lower CO2 removal rate

Higher CO2 removal rate due to enhanced reaction kinetics

COS removal

Lower COS removal rate

Higher COS removal rate due to enhanced reaction kinetics

Loading capacity and solvent circulation

Lower loading capacity (especially for high CO2containing gases), resulting in higher solvent circulation rate

Higher loading capacity (especially for high CO2 containing gases), resulting in lower solvent circulation rate

Steam requirement

Higher steam requirement, due to higher solvent circulation rate and higher heat of reaction

Lower steam requirement, due to lower solvent circulation rate and lower heat of reaction

Hydrocarbon co-absorption

Higher hydrocarbon co-absorption if the design is governed by the removal requirement of COS, CO2 or H2S

Lower hydrocarbon co-absorption if the design is governed by the removal requirement of COS, CO2 or H2S

Solvent degradation 68

Oxazolidone formation

I JULY 2009 HYDROCARBON PROCESSING

No oxazolidone formation

consumption is to a large extent influenced by two factors: the solvent circulation rate and the desorption energy of CO2/H2S. SX has a significantly higher loading capacity than FG as MDEA reacts 1:1 with CO2 while DIPA reacts 2:1. The molarity of SX is also about 20% higher than FG. Therefore, SX requires a lower solvent rate to remove the same CO2 amount in comparison to FG. The sensible heat requirement for SX is significantly lower than for FG, and the heat of reaction for CO2 absorption is lower for MDEA than for DIPA. Even though the heat of reaction of piperazine is higher compared to other amines, the overall heat of reaction of SX is lower than that of FG. Piperazine is used as an accelerator constituting only a minor fraction of the solvent formulation. For H2S, the heat of reaction is similar for MDEA TABLE 2. Pilot plant comparison of FG and SX performance regarding COS breakthrough as a function of solvent circulation rates. Feed gas contains 23 mol% of acid gas (CO2 and H2S) and 1,000 ppmv COS at 40 bara Solvent circulation rate (relative)

COS breakthrough in treated gas (ppmv)

100%

3.1

100%

No breakthrough

80%

No breakthrough

60%

1.2

Hybrid solvent

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GAS PROCESSING DEVELOPMENTS and DIPA. Accordingly, SX requires a lower reboiler duty to strip the same CO2 amount in the regenerator. Combining both effects results in significantly lower SX energy consumption compared to FG and similar to that of accelerated MDEA solvents. Reduced hydrocarbon co-absorption. Since SX has a

higher loading capacity than FG, when the design solvent circulation rate is governed by the removal requirement of CO2, H2S or COS, SX requires a lower solvent circulation rate and therefore has significantly lower hydrocarbon co-absorption. Keep in mind that the hydrocarbon co-absorption is directly governed by the sulfolane amount in the solvent. If comparing at the same sulfolane concentration and solvent circulation rate, both FG and SX have a comparable degree of hydrocarbon co-absorption. No reclaiming required. DIPA forms oxazolidones, heat stable salts, when reacting with CO2, with the formation rate depending strongly on the CO2 partial pressure.5 At high oxazolidone formation rates, a reclaiming unit may be required to keep oxazolidone in the amine solution at acceptable levels. On the other hand, MDEA, sulfolane and piperazine have been used extensively in the industry and are known to be stable in CO2 presence with regard to formation of oxazolidone-like species. Therefore, no dedicated reclaimer needs to be installed for SX. Recent project experience. Several SX technology eval-

ion s

Sinc e

1942

uationsâ&#x20AC;&#x201D;both for revamps (solvent swaps) in existing plants to increase gas throughput capacity and for the design of new plantsâ&#x20AC;&#x201D;were performed.

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Solvent swap to SX. In solvent swap cases, the focus is typically on increasing throughput while minimizing changes in the installed equipment. A study for a plant in North America investigated a potential swap from FG to SX. The requirements for the swap were that no equipment changes and no additional impact on the planned maintenance shutdown needed to be made. The feed gas contains significant amounts of CO2 and COS, which were the determining factors in the original design. Due to the higher CO2-loading capacity of SX and the enhanced COS reaction kinetics, a â&#x2026;&#x201C; higher gas throughput can be sent through the AGRU with the same solvent circulation rate and the same reboiler duty while meeting the same specification of the treated gas (< 1 ppmv H2S, < 16 ppmv total S and < 250 ppmv CO2). Therefore, solvent swaps to SX could be interesting for operating companies looking for the benefits previously discussed. Green field design with SX. For an LNG project in the

Middle East (processing about 630 MMscfd), a third party performed a process comparison between an accelerated MDEA line-up (see Fig. 1, top panel) and SX (see Fig. 1, bottom panel) for a gas containing H2S, CO2, COS and RSH. With SX, RSH is removed in the AGRU, thus, resulting in a smaller molecular sieve unit. In addition, a separate regeneration gas-treating unit is not needed as the regeneration gas stream contains only a minor RSH amount and can be recycled back to the AGRUâ&#x20AC;&#x2122;s main absorber. Comparing the two process line-ups substantiates that the use of SX technology results in a much simpler process arrangement. The comparison between the two process options shows significant CAPEX savings. When considering only the AGRU running on SX, slightly higher energy consumption compared to an accelerated MDEA unit would be required. However, if the overall treating lineup is considered, the energy consumption of both schemes is comparable. Since the study was done for a constrained plot space location, the benefit with respect to reduced plot size, reduced complexity and overall process performance of SX, resulted in the third party recommending SX as the preferred solution.

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SX solvent implementation. There are

two facilities that have already benefited from using SX. Both implemented the solvent swap â&#x20AC;&#x153;on the flyâ&#x20AC;? (no shutdowns). In addition, it is anticipated, a third facility, currently under construction in the Middle East, will be using SX. First plant. Two AGRUs were used to treat a 190 MMscfd natural gas plant. Both units removed CO2 and H2S upstream of a cryogenic LPG recovery facility and an ethane/propane recovery unit. The feed gas exiting the slug catcher passes through a vertical demister knockout vessel with the potential for hydrocarbon entrainment in the AGRU. The feed gas to the absorber has about 4 mol% CO2 and 450 H2S ppm, while the treated gas specification is < 50 CO2 ppm and < 4 H2S ppm. The plant was originally designed for and operated with FG. In 2005, the plant experienced significant foaming issues, which were

GAS PROCESSING DEVELOPMENTS causing costly capacity reductions. The foaming was due to the significant liquid hydrocarbon build-up and the operation with low solvent inventory. MDEA and piperazine were added to the solvent as an immediate remedial measure, resulting in a partial swap to the SX solvent. This helped resolve the foaming problems, and provided significantly increased gas processing capacity as an additional benefit.

1 2

3 4

Second plant. Having a capacity to process 760 tons of gas per day,

this AGRU services a hydrogen manufacturing unit that was originally designed for FG. The feed gas contains around 20 mol% CO2, while the treated gas specification is < 0.1 mol%. To enhance the CO2 removal capacity, the solvent was swapped to an aqueous-accelerated MDEA solvent by adding MDEA and piperazine. During the swap, the plant operated with SX. The plant operation was stable and the performance and capacity increase were in line with the predictions. Overview. As the exploitation of contaminated gas keeps increasing, the efficient and simple removal of CO2, H2O, H2S, RSH, COS and organic sulfides is crucially important. Current removal of these components requires complex treating process line-ups using a combination of processes. Development based on the enduring design and operational experience with both traditional FG and accelerated MDEA solvents, SX is a technology ideally suited for removal of H2S, CO2, RSH, COS and organic sulfides in one process unit. This can be applied both in new designs as well as in the revamping of existing plants to increase capacity, reduce energy consumption, lower chemical consumption/waste disposal, and achieve tighter CO2, H2S and COS specifications. HP

LITERATURE CITED Kohl, A. and R. Nielsen, Gas Purification, Fifth Edition, Gulf Publishing Company, Houston, Texas, 1997. Coyle, D. F., F. De La Vega, C. Durr and F. L. Del Nogal, “Impact of LNG specification on liquefaction and import plants,” AIChE Spring National Meeting, Conference Proceedings, 2008. Johnson, J. E., “Trace components: GTU solvent selection,” Hydrocarbon Engineering, pp. 43–46, February 2007. Burr, B. and L. Lyddon, “Which physical solvent is best for acid gas removal?” Hydrocarbon Processing, pp. 43–50, January 2009. Kim, C. J., “Degradation of alkanolamines in gas-treating solutions: Kinetics of di-2-propanolamine degradation in aqueous solutions containing carbon dioxide,” Industrial and Engineering Chemistry Research, Vol. 7, pp. 1–3, 1988.

Djordje L. Nikolic is a researcher in the gas treating and sulfur processes division of Shell Global Solutions International BV, in Amsterdam, The Netherlands, and has been in his current role since 2006. He obtained a BSE degree in chemical engineering from Tulane University, New Orleans, Louisiana, and a PhD in chemical engineering from Princeton University, Princeton, New Jersery. Renze Wijntje is a researcher in the gas treating and sulfur processes division of Shell Global Solutions International BV, in Amsterdam, The Netherlands, and has been in his current role since 2007. He obtained an MSc degree and PhD in chemical engineering from the University of Twente, Enschede, The Netherlands. Prashant Patil Hanamant Rao is a technologist in the gas treating and sulfur processes division of Shell Global Solutions International BV, in Amsterdam, The Netherlands, and has been in his current role since 2007. He obtained an MSc degree in chemical engineering from the Indian Institute of Technology, Madras, India, and a PhD in chemical engineering from the University of Manchester (formerly UMIST), Manchester, UK.

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HYDROCARBON PROCESSING JULY 2009

I 71

MANAGEMENT GUIDELINES

A continual improvement process that really works Taking care of these basics can enable businesses to move out of bureaucratic quagmire onto a path of measurable results D. M. WOODRUFF, Management Methods, Inc., Decatur, Alabama

ontinual improvement (CI) can be defined as making changes in processes or systems to improve the ability to fulfill stated requirements. An effective CI process is simply an organized approach to upgrading processes and reaping the rewards. In many businesses today, the leadership team is saying or thinking, “This quality system (ISO 9001, Lean, Six Sigma, et al.) stuff just hasn’t yielded the results we expected.” With the present economic environment, it is critical that those of us in the HPI make significant continual improvements in our processes. Yet, many are concerned that process and quality improvement efforts have become bogged down in bureaucracy. The challenge is to define, implement and sustain a simple CI process that enables your company to become the low-cost, highquality leader in your industry. As with any other enterprise-wide process or business system, the support and involvement of top management is critical. This requires more than “lip service.” How does top management show their involvement? They must: 1) articulate the vision and expectations for CI; 2) provide the resources; 3) ensure that obstacles are removed; 4) participate in the process. Top management must be visible participants and ask the right questions. Staying in an office and avoiding process areas is not an option for an effective CI process. Visibility of top management is a key to success. A simple plan for CI that builds on effective quality management principles and philosophy should not “re-invent the wheel!” Here are the five components of a simple and effective CI process: 1. Take care of the basics 2. Focus on the processes 3. Eliminate waste 4. Get it done with teams 5. Measure the results.

TAKE CARE OF THE BASICS

In the everyday affairs of business, it is easy to overlook the basics. Too often, businesses (or top management) become enamored with the “latest and greatest” fad instead of focusing on the fundamentals. The story is told that the great coach Vince Lombardi began practice each year with professional football players by showing them a football! Well, if someone like Coach Lombardi needed to be that basic with professional—and some hall of fame caliber—players, then, in the HPI, we need to be just as diligent in understanding the basics. Effective CI requires a focus on basics because sustainable improvements are usually 72

I JULY 2009 HYDROCARBON PROCESSING

made at a fundamental level in the processes. The basics for any organization include: 1. Leadership 2. Employee development 3. Processes and equipment 4. Resource utilization 5. Fact-based decision-making (i.e., statistical process control) 6. Documentation that makes sense for your business. Leadership. The fundamental top management responsibility

is to provide leadership. We manage things and lead people. Let’s review the essentials of leadership that must be applied if your CI process is to be effective. Here are nine timeless principles: honesty/integrity, trust, sincerity, fairness, attention to detail, expectations defined and communicated (be sure people know what is expected), competence, keeping commitments and following up to let people know you care. A survey of over 500 people in leadership positions a few years ago showed that the number one characteristic of a good leader is honesty. In today’s high-tech workplace, it is vital that we be honest with employees, customers and all people and that we provide employees with honest feedback. A simple thank-you for a job well done can sometimes do more to improve productivity than can a sophisticated software package. As John Naisbitt portrayed in his book, Megatrends, the hightech world requires a “high-touch” approach to dealing with people. This simply means that we pay attention to needs, communicate openly and readily, say thank-you, discipline when necessary and—above all—be honest. Employee development. Employee development is critical for successful CI. Every company needs a long-term employee development and training plan. A system that works well involves identifying the competencies required for each job (ISO 9001, clause 6.2); breaking them into fundamental, intermediate, advanced and specialized skills; developing training modules; establishing a long-term (3 yr to 5 yr) employee development plan; and implementing the process. Table 1 is an example of a competency matrix for a small transport company in the HPI. Using this matrix, a training plan can be easily prepared for each position and person in the organization. Fig. 1 is an example of a complete training process that really works.

MANAGEMENT GUIDELINES TABLE 1. Example competency matrix Director of operations

Dispatcher

Drivers

Adm. support

Company operations

Load rack operations

Product knowledge

Word processing and computer skills

Computer system

ISO QMS

General loading

ISO awareness

Customer requirements

General safety requirements

DOT requirements

Customer service

ISO QMS (all documentation)

Basic computer skills

ISO awareness

Regulatory requirements

Customer requirements

Must maintain commercial driver’s license (CDL)

Basic computer skills

Customer locations and tanks

Truck loading standard operating procedures (SOP)

Safety

Truck unloading SOP

DOT requirements/updates

DOT requirements

PM SOP

Dispatching process

Inventory management system

Safety SOP

HAZMAT

Dispatching process

Customer relations

HAZMAT

Employee list Org. chart Job descriptions

Identify employees who affect quality

Matrix of competencies for each position

Required competencies identiﬁed

Records and needs reviewed by the executive team; management reviews.

Provide training as needed

QMS procedures and other documents; OJT; Videos; Books; Online; seminars; continuing Ed classes; etc. Training records

Evaluate effectiveness

Reviews

Goals and objectives met On-time deliveries Customer satisfaction Management review CAPA records

Competent and trained employees

Process monitoring and measurement: 1. Objectives met; CAPA records 2. Training timeliness and effectiveness 3. Internal audits 4. Management review of training needs and results FIG. 1

Example of a training process that works.

Remember the old question: “Could he or she do that job if his or her life depended on it?” If the answer is “No,” we have a training problem. While it generally isn’t life or death, it is impera-

tive that workers be properly trained to do their job. To be successful training should be needs-based and delivered “just in time.” Mass training usually doesn’t work too well because frequently someone in the organization simply “decrees” that all employees will receive training in “XYZ” subject matter with no immediate application of the principles learned. In other scenarios, organizations may focus training primarily in one area, such as safety. While that may be good, it doesn’t address all of the required competencies needed by the organization. Processes and equipment. Processes

and equipment represent the critical path to satisfying customer needs. Without reliable processes and having equipment available when needed, customer needs will not be met on time. Thus, organizations that are getting the most benefit from their CI processes will be focused on improving or streamlining all processes including maintenance and operations. Up-to-date and understandable operating and maintenance instructions and plans are essential in any industry, but especially in the HPI. These two sets of instructions can provide the basis for process and equipment reviews. Procedures and work instructions should be legible, available, easy to use, properly approved and under a document control system (ISO 9001, clause 4.2.3). With the just-in-time (JIT) and lean systems of today, a company must use a systematic predictive/preventive maintenance process because process upsets and equipment failure can lead to an immediate disruption in supply for a customer. The days of the “run it ’til it breaks” philosophy of equipment maintenance are gone! An unexpected shutdown can be devastating to you and your customer. Effective process documentation packages should include startup, routine operations, abnormal conditions, troubleshooting guides, emergency and shutdown instructions. Procedures can be effectively presented in a flow chart, checklist or outline form instead of wordy documents. Pictures may be the optimum approach in many cases. The simpler the instructions are presented, the better. A usual byproduct of simplified process instructions is reduced variability, because people on all shifts are “doing the work alike.” Maintenance instructions and plans should include (at a minimum) preventive maintenance details, operating hours between “PM,” a checklist for routine and breakdown maintenance, and a follow-up reporting mechanism after each major repair. Records are a key part of the maintenance process and will ultimately help reduce operating costs when used appropriately. If the repairs are the result of a system or equipment failure, then corrective action is needed to be sure that the problem was resolved and that repetitive issues are clearly identified and understood. Resource utilization. Effective utilization of all resources is critical to being the low-cost, high-quality leader in your industry. For example, utility and energy management processes can save money and improve the environment. Understanding the entire value stream of your business operations will help focus CI efforts on cost savings. HYDROCARBON PROCESSING JULY 2009

I 73

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ucl cl

Frequency

Temperature, °F

Total yield is another critical measure in PM ﬂash utilizing resources. In some businesses, yield 160 is still defined as “output/input,” when in X-bar reality it is “usable or good output/input.” 158 One of our clients was making a product 156 and simply looked at yield as barrels pro154 duced/barrels of input to the process. This 6 Range may be a measure of process efficiency, but 4 is not a true measure of resource utilization. It doesn’t consider inherent process waste, 2 abnormal waste or quality issues that lead 0 to scrap or waste. Date: 11/15/06 11/15/0612/27/06 1/17/07 2/7/07 2/28/07 3/21/07 4/11/07 5/2/07 X-bar cl: 156.913 ucl: 158.983 Icl: 154.843 A more effective measure would be Range: cl: 2.30435 ucl: 5.25826 Icl: 0 saleable or prime barrels output/barrels of input. Then CI efforts could be focused on FIG. 2 Example of a process control chart. identifying the top categories of waste and making process improvements to address these. When the client only looked at output/input in the original data, it was not possible to see the waste because of several reasons: 80 1) the theoretical or maximum possible yield was not known 70 because the inherent waste factor was unknown; 2) equipment 60 issues that led to certain types of waste were not documented; 3) routine or unusual quality concerns were not given proper atten50 tion because that was not considered in the yield calculations. 40 You get the idea. Fact-based decision-making. Another basic is fact-based decision-making using the tools of statistical process control (SPC). In some companies, engineers and statisticians have become enamored with complex statistical techniques and mathematical models while minimizing the use of basic tools such as control charts, histograms, run charts, flow charts, Pareto charts and cause-effect diagrams. Often a simple graph of process metrics can yield information to guide CI efforts and to help establish cause-and-effect relationships that can lead to CI. For example, process yield or process waste when graphed and monitored daily, weekly or monthly can show trends and help drive improvements. Other metrics to consider could be on-time deliveries, preventable customer complaints, equipment up-time, productivity (good output only), maintenance time per work order, cycle times, inventory turns, catalyst life, etc. Identify those five to seven key indicators for your business and focus on them. Make them visible for employees and get more people involved in understanding the data. Process control charts (SPC) are effective and simple tools for fact-based decision-making. Effectively using these tools will provide information about the type and amount of variation in your processes. Unexpected and/or too much variation are enemies of CI. Without using control charts, one does not really know the type nor amount of variation present. While this is not a course in SPC, let me quickly point out that control charts show process performance over time, indicate the expected system variation and clearly show when processes experience special causes of variation. Process control charts are based on the random variation in a process over time and provide limits of expected “behavior” for your processes. They are based on process statistics such as averages and ranges of sample variation over time. Fig. 2 is an example of a typical control chart. From this chart, one would expect the process to behave between about 155 and 159. In fact, statistically, one would expect this about 99.73% of the time based on the random variation in

Icl ucl cl Icl 5/23/07 6/13/07 7/4/07 7/25/07 8/15/07 9/5/07

Subgrp size 4 Rule violation

Frequency

30 20 10 0 Color

FIG. 3

Mold Dimensional Clips problems don’t ﬁt Nonconformity

Voids

Other

Pareto chart example.

this process. From the lower half of the chart, or the range chart, one would expect the process to vary <~5 within the sample subgroup. One can readily see when the variation is too high and when the actual process result is not within expected levels of performance. Another simple tool is the Pareto chart, which is really just a bar graph arranged in order of importance or occurrence. These are based on the Pareto principle, or the 80/20 rule which tells us that 80% of our problems come from 20% (or less) of the reasons or causes. Fig. 3 is an example of a Pareto chart. While at times it may be necessary to use more sophisticated techniques, the simple tools, when properly used, yield an abundance of information about most processes. Employees and managers should be trained in appropriate methods and encouraged to use simple statistical tools for CI. While this is not intended to be a course in statistics or problem solving, one can easily find many useful references on the Internet and in books that are readily available and written in understandable formats. Documentation. Complete documentation is an important consideration with the continuing emphasis on quality management systems such as ISO 9001 (i.e., clause 4.2.3), TS 16949, ISO 13485, AS 9100, ISO 17025, etc. Proper documentation is nothing new for an effective total quality system. Fig. 4 is an example of a simple procedure using a flow chart approach. HYDROCARBON PROCESSING JULY 2009

I 75

MANAGEMENT GUIDELINES Purchasing

SOP 740P001 Effective date: May 15, 2008

Scope XYZ Industries operations that require product quality-related purchased items. Purpose To define the policies governing purchases of supplies, materials and services that are related to product quality. Reason for revision May 15, 2008, reviewed and flow chart added. May 25 , 2004, added to procedure for verification of purchased material. Procedure The process and procedure are as follows:

Need identiﬁed

What? • A tool to aid in analyzing processes • Looks for inputs and outputs and linkages or “hand-offs” • Focuses on how the work is to be done in a given process • Prevents missing key information about a process When? • Use to study a process or nonconformities within a process • A tool for continual process improvement and with PDCA

Purchasing process SOP 740P001 Parts and items affecting quality Approved suppliers based on quality, price, delivery and history. Price is not the deciding factor.

TABLE 2. Process analysis for understanding

• Helps identify effective process improvements

Parts, packaging, preventive maint., calibration, etc.

How? 1. Identify the process 2. List inputs and outputs 3. Identify the steps (hint: develop a flow chart)

Approved supplier list or off-the-shelf or catalog item; approvals required by Board for capital Items.

No good

PO issued

Items received and veriﬁed

Purchasing information speciﬁed. Orders may be place via e-mail Verify against PO to ensure we got what we ordered.

Good Return to vendor

4. Determine how the work is being done and managed 5. Identify how the process performance is being measured 6. Identify the linkages between processes (i.e., hand-off from previous and to the next process in the sequence of processes) 7. Identify how this process is measured or monitored 8. Evaluate and document how the work can be done better 9. Implement the improvements

Inventory

Benefits 1. Provides an orderly approach for process improvement

Process monitoring and measurement: 1. Supplier performance 2. Onsite surveys if required 3. On-time deliveries

2. Helps in simplifying processes 3. Focuses efforts on continuous improvement 4. Can be used on any process.

Notes: 1) in emergencies, purchases may be made from a supplier not on the ASL, but it should be clearly documented and approved; 2) Suppliers are re-evaluated periodically; 3) Management review administers the process.

1. At this time, there are no requirements for onsite veriﬁcation at subcontractor or vendor premises. Should the need arise, it will be added to the SOP. 2. Records of vendor performance are reviewed at least annually during management review. This includes price, delivery, quality concerns and general satisfaction with the vendor. 3. Vendors may be removed from the approved vendor list at management’s discretion. Approval ––––––––––––––––– Executive director FIG. 4

–––––––––––––– Date

Example procedure for purchasing.

Complete documentation includes an up-to-date quality manual, product traceability, training plan, training records, operating procedures/instructions for product or service realization, relevant safety and environmental information, corrective actions, preventive actions and process descriptions. The documentation should tell us “how to do the work,” describe the “work to be done” and record “how the work was done.” This documentation must be a part of the CI process. When the “way we do the work” is clear to all employees, then it is a rather straightforward task to review the documentation with all shifts and areas that are affected to identify system improvements that can be made or best practices that can be transferred to other areas of the business or even to other facilities within the organization. And, please remember that documentation for the sake of documentation is an exercise in futility—this is not CI. 76

I JULY 2009 HYDROCARBON PROCESSING

FOCUS ON THE PROCESSES

In many companies, CI processes began by using data to monitor key product variables. A customer’s desire to determine process capability for certain product parameters may have led to a product focus instead of a process focus. If no corrective and/or preventive actions are taken immediately, nothing is different from the traditional inspection approach to quality or CI. To understand your processes more in depth, begin by identifying the core processes and then flow charting the overall system of processes at a high level. Next, each process should be flow charted at a more detailed level. This can be readily accomplished by utilizing a team of knowledgeable personnel with the assignment to flow chart all business processes. Be sure to include information flow and process monitoring and measurement. Since readers of Hydrocarbon Processing are familiar with flow charts, this should be a relatively simple yet powerful exercise and a foundational building block for your continual improvement process. Process focus. Shifting to a process focus encourages work on problem prevention and maybe even quantum-leap process improvements. A simple first step is what I call “process analysis for understanding.” Here is an approach that has proved to be effective in many situations. Table 2 is an outline of the technique. Fig. 5 is a worksheet that gives you a tool for gathering and using the information. Using process analysis information. After the basic analysis is done, cause-effect relationships among process variables

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MANAGEMENT GUIDELINES Process analysis worksheet Process: _____________ 1) Inputs (List)

Managing variability

Date: _____________

1) What is the work to be done? (Develop simple ﬂow chart)

2) How is the work being done? (Process steps, problem areas, procedures)

Outputs (List)

3) How is the work being managed? (Responsibility, accountability, expectations, goals)

The path to continual improvement is the path of managing and reducing variability Variability FIG. 7

4) How well is the work being done? 5) How can we do the work better? (Cost, cycle time, quality issues; key (Continual improvement plans or steps) indicators)

Process analysis team:_________________________ Date:________________ FIG. 5

A simple tool for analyzing processes.

CI project: reduce measurement variation in chemical analysis People Instrument

Environment

Sample in

Result out

Calibration

Reagents/materials

Procedure FIG. 6

Example of a cause-effect diagram.

and product characteristics could be identified. A team that is knowledgeable of the process can work together to identify the top three to five process variables that impact the final product. Using the Plan-Do-Check-Act (PDCA) cycle along with appropriate statistical methods, this team can begin to reduce variation in the process. Fig. 6 is an example of a cause-effect diagram developed by a team of knowledgeable people who used the information to prioritize, define and implement continual improvement actions on a measurement process. Reducing variation is the goal. Variability in a process

can be defined as “the difference in things that should be alike.” Remember, management is responsible for the system. Processes that “behave” with a predictable degree of uniformity are results 78

I JULY 2009 HYDROCARBON PROCESSING

Improvement

Reducing system variation is the long-term goal.

of eliminating sources of variation over time. Process control charts (SPC) are the only tools that will let you know if you have special causes of variation present or only system variation, also known as common cause variation. These charts will show long-term trends as well as short-term “spikes” in processes and provide the information to really improve the processes and measure the results. Control charts give signals when processes don’t behave as expected. They are simple, yet very powerful tools to use in reducing variation. Working on the system encourages long-term changes aimed at reducing variation and yields effective continual process improvement. The shift to process thinking from traditional product thinking is a major step in getting CI efforts on the path to effectiveness (Fig. 7). Establishing process monitoring and measurement criteria along with specific goals or targets is a key to success with process improvement and CI (and is required in ISO 9001, clause 8.2.3). This transition enables management and employees to make long-term changes to improve the consistency of processes and simplify the “work to be done.” ELIMINATE WASTE

An often missed opportunity for continual improvement is eliminating waste. Waste can be defined as anything that is nonvalue-added. When the entire value stream is considered, waste can really mount up in terms of dollars, time, resources, re-work, etc. Waste can involve process scrap, re-worked products, re-done reports, waiting on parts, etc. With this broad definition, it’s easy to understand the importance of eliminating waste. Categories of waste. Most organizations have at least seven major categories of waste: 1. Measurable scrap, including process waste and product scrap, etc. 2. Waiting on materials, people, parts, decisions 3. Performance barriers such as procedures that were developed in a front office with insufficient (i.e., “NO”) understanding of the impact on the work being done 4. Dissatisfied customers, so measure customer satisfaction 5. Dissatisfied employees who are not being productive— usually traced to issues in leadership 6. Damaging goods, facilities, equipment either accidentally or, heaven forbid, on purpose, but most likely inadvertently— such as running equipment without proper preventive maintenance 7. Doing things over because they weren’t done right the first time. Too often, this is a result of communications issues when requirements were not clearly understood.

MANAGEMENT GUIDELINES TABLE 3. How the team gets results: the team Top 10

TABLE 4. Plan-Do-Check-Act worksheet

1. Focus on the process

Plan

2. Use an organized approach to understand the process

List the steps in the action plan to implement specific corrective actions or problem solutions based on root causes. Be sure to include specific steps, timetables, responsibilities, measurement.

Implement the corrective action plan and be sure that all documentation needing changes are updated. Don’t forget the forms! Follow-up on the implementation according to specified responsibilities.

Check

Act

The specific items to measure, check or verify should be specified in the PLAN. Check these items and record the results. Look for differences in what you expect and what you actually experience.

As a result of measurements (checks), take the appropriate actions and repeat the process. This may be the most important step to having effective corrective actions.

3. Use the tools of SPC to make fact-based decisions 4. Understand and simplify the procedures or other documentation 5. Identify the sources of waste 6. Communicate closely with management and employees 7. Take it easy, go slow, digest what you learn in “small bites” 8. Document the team’s function. 9. Document results/implement changes. 10. Follow-up to hold the gains.

Identify, eliminate the sources. Now it is time to identify

the major sources of waste. These can be categorized as costs, time, occurrences or other categories meaningful to your business. Use the tools we’ve been discussing. Control charts can show you when variation is the culprit that requires a concerted CI effort. Pareto charts are powerful tools to identify the top problems. The tough question becomes, “How can we do the work better?” Cause-effect diagrams and flow charts make it possible to focus on eliminating the waste that’s been identified. Root cause analysis techniques can be applied to eliminating waste, which will make a significant impact in most businesses.

■ Select the measures that make

sense for your business, but avoid the temptation to make it complex or cumbersome. A unique approach that a client used to identify waste and make it visible was to actually “build” a Pareto chart of scrap outside the employee entrance to the plant. They took the scrap for one week and created “piles of waste” by each category of nonconforming parts. This visible reminder highlighted the need to eliminate waste and provided essential information about what areas to attack first in their CI improvement process. While this approach is unusual and in many cases can’t be done due to all sorts of reasons, the idea of visibility of waste is important to any organization. Another client used very large Pareto charts of waste posted at the entrance to the employee lunch room: the same idea with a different approach, but very effective. Management must provide leadership in the waste reduction (elimination) efforts. The gains made by eliminating waste translate directly into reduced costs, increased productivity and profits.

should be able to make decisions, inform the proper people and implement improvement actions (Table 3). MEASURE THE RESULTS

Without tracking results, it is impossible to measure the benefits of your CI process. Use a simple tracking mechanism such as an Excel file or easy-to-use database that will enable you to quickly summarize projects and results. As in most things, the most significant measure may be in $$$; however, other measures such as reduced change-over times, improved catalyst life, pounds of waste eliminated, cycle time improvements, reduction in customer issues, etc., may also be effective. Select the measures that make sense for your business, but avoid the temptation to make it complex or cumbersome! Remember, the goal is to continually improve processes without increasing bureaucracy. The Plan-Do-Check-Act (PDCA), or Deming Cycle, is a simple way to monitor and measure results. Table 4 is an easy-touse tool to help you use the PDCA approach more effectively. We used to say, “If you always do what you always did, you always get what you always got.” The new reality is: “If you always do what you always did, you will fall behind the competition!” HP BIBLIOGRAPHY Grant, E. and R. Leavenworth, Statistical Process Control, McGraw-Hill, 1996. D. Woodruff, Taking Care of the Basics, 101 Success Factors for Managers, August 2005. www.daviswoodruff.com, “From Required Competencies to Effective Training,” free article download.

GET IT DONE WITH TEAMS

The fourth part of the CI plan is Get It Done. This is where the work really takes place! How do we “get it done?” With teams. Small teams (five to seven people) of experienced and knowledgeable employees who are trained in the team process and empowered to make decisions can focus the organization on CI. Too often, groups are put together randomly—with no training in the team process or the tools of CI—and expected to come up with revolutionary improvement. That’s a prescription for frustration and failure. CI teams should be cross-functional, knowledgeable, trained and have some clout within the organization. They

Davis M. Woodruff is the founder and president of Management Methods, Inc., a management consulting firm based in Decatur, Alabama. A consultant, speaker and author, Mr. Woodruff is a recognized expert in showing companies how to be the low-cost, high-quality environmentally responsible leader in their industry. Since 1984, he has served clients in 35 states and on three continents. He is the author of a full-length book, Taking Care of the Basics: 101 Success Factors for Managers, and dozens of articles, including articles for Hydrocarbon Processing and the Encyclopedia of Chemical Engineering. Mr. Woodruff is a chemical engineering graduate of Auburn University, a certified management consultant and a licensed professional engineer in Alabama. HYDROCARBON PROCESSING JULY 2009

I 79

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Gas Processes 2009 • • • •

Application Process descriptions Flow diagrams Economics

Published in July 2009 Copyright © 2009 Gulf Publishing Company. All rights reserved. Printed in USA. For a complete listing, the Gas Processes 2009 Handbook is available on our website for paid subscribers. www.HydrocarbonProcessing.com Photo: Copano Energy’s gas processing plant in Sheridan, Texas.