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JANUARY 2011
HPIMPACT
SPECIALREPORT
2011FORECAST
Refinery construction costs on the rise
GAS PROCESSING DEVELOPMENTS
HPI MARKETDATA 2011
Shale gas could affect Middle East LNG
Improved technologies treat sour gas
Summary reviews spending and trends shaping the global HPI
www.HydrocarbonProcessing.com
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JANUARY 2011 • VOL. 90 NO. 1 www.HydrocarbonProcessing.com
SPECIAL REPORT: GAS PROCESSING DEVELOPMENTS
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Consider different alternatives for enriching lean acid gases New developments improve operation of Claus sulfur recovery units B. ZareNezhad
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Avoid condensation-induced transient pressure waves
Cover The PERU LNG production complex in Pampa Melchorita, Peru, was officially inaugurated in June 2010. With a nominal capacity of 4.4 million tons of LNG per annum, it is South cutline for fig 00 America’s first baseload liquefaction plant and represents one of the largest industrial projects ever undertaken in Peru. Photo courtesy of CB&I.
Case studies give an indication as to probable causes for water hammer G. Mani
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When is CO2 more hazardous than H2S Data shows potential harmful effects to workers due to acid gas exposure
HPIMPACT 17
K. Tyndall, K. McIntush, J. Lundeen, K. Fisher and C. Beitler
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Use online analyzers for successful monitoring Improved analytics measure moisture and dew points for natural gas components A. Benton and C. Valiz
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Refinery and petrochemical construction costs continue measured rise
00 cutline for fig
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Moving beyond the meltdown in the Gulf
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Global energy outlook to 2035
Advanced chemical process for treating sour gas Technology avoids huge capital investments while speeding up results C. A. Ortega Peralta and M. J. Ortega Casteln
HPI 2011 FORECAST
PLANT SAFETY Safe detection of small to large gas releases
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Look at these advantages in using ultrasonic leak detectors E. Naranjo, S. Baliga, G. A. Neethling and C. D. Plummer
Considerations for blast-resistant electrical equipment centers Guidelines explore protecting critical systems from disaster D. Cole and D. Austin
ENVIRONMENT What are the strategies for sustainable chemical production?
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New options recover waste gas energy as steam and electricity for plant use B. Carbonetto and P. Pecchi
ENGINEERING CASE HISTORIES Case 60: Socket-weld failures
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HPI Market Data 2011 Executive Summary:
This summary reviews spending for the global HPI. Will 2011 be a better year for the refining, petrochemical and natural gas industries? Cutline for fig. 00 What lies ahead for the energy industry?
New environmental challenges require a new way of thinking by the hydrocarbon processing industry M. P. Sukumaran Nair
ROTATING EQUIPMENT Going ‘green’ with FCC expander technology
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A risk analysis can determine which critical welds to repair T. Sofronas
COLUMNS 9
HPIN RELIABILITY HPIMPACT Packing not best for firewater XX practice Dewitt petrochemicalpumps conference out look
11 EUROPE XX HPIN Six strategic business European consumers technologies to watch mull their options as XX oil Australia making companies quit crucial GTL decisions the market
7 HPIN BRIEF • 27 HPINNOVATIONS • 31 HPIN CONSTRUCTION
XX HPINTEGRATION IEA assesses energy poli13 cies of U.S. STRATEGIES vs. ARC—Not XX MPC Creating more value an in ‘either/or’ decision capital projects
35 HPI CONSTRUCTION BOXSCORE UPDATE
90
DEPARTMENTS
86 HPI MARKETPLACE • 89 ADVERTISER INDEX
HPIN CONTROL Process control practice renewal— select CVs
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[email protected]. 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 © 2011 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 BILLY THINNES, NEWS EDITOR
[email protected]
Sunoco, Inc., will sell its 170,000-bpd refinery in Toledo, Ohio, to Toledo Refining Co., a subsidiary of PBF Holding Co., for approximately $400 million (consisting of $200 million in cash and a $200 million two-year note). In addition, the purchase agreement includes a participation payment of up to $125 million based on the future profitability of the refinery. The buyer will also purchase the crude oil and refined product inventory attributable to the refinery, which will be valued at market prices at closing. The transaction is expected to be completed early in the first quarter of 2011.
The Alliance for Climate Protection and the Center for American Progress released a joint report that calls on the US to take the lead on international climate finance—even under the current difficult political and economic conditions. The report says that it is in the US’ best interest to help developing nations reduce greenhouse-gas emissions and build clean-energy economies. It calls on the US to lead a global partnership to mobilize new investments in developing countries between now and 2015, and urges the country to explore new ways to help developing countries pursue clean-energy growth. The report suggests the US can finance investments through public budget resources, carbon markets, development bank lending and private financing.
ABB will acquire Baldor Electric in an all-cash transaction valued at approximately $4.2 billion, including $1.1 billion of net debt. The transaction closes a gap in ABB’s automation portfolio in North America by adding Baldor’s NEMA motors product line. Baldor also adds a mechanical power transmission business to ABB’s portfolio. The US market for high-efficiency motors is expected to grow 10% to 15% in 2011 on the back of new regulations, effective in December this year. Similar regulations in Canada, Mexico and in the European Union are expected in 2011.
The chairman of the US Chemical Safety Board (CSB) applauded the National Fire Protection Association (NFPA) for its recent decision to establish a new technical committee to develop a comprehensive standard for gas processing safety, including the cleaning of fuel gas piping systems. The NFPA acted in response to an urgent recommendation issued by the CSB following a catastrophic natural gas explosion at Kleen Energy, a power plant under construction in Middletown, Connecticut, on February 7, 2010. In that incident, workers were conducting a “gas blow,” a procedure that forced natural gas at high volume and pressure through newly installed piping to remove debris. The gas was vented to the atmosphere, where it accumulated and exploded, killing six contract workers and injuring many others.
Early December marked a major milestone for the US’ transition to ultra-low-sulfur diesel (ULSD) fuel, as all highway diesel fuel in the US now complies with the 15-ppm sulfur standard. This represents a 97% reduction in sulfur content from diesel’s 2006 levels. The December 1, 2010, deadline was mandated by the US Environmental Protection Agency (EPA). However, according to the EPA’s pump survey, the highway transition to ULSD was actually completed a few weeks ahead of schedule.
BASF and PETRONAS are studying the possibility of producing specialty chemicals in Malaysia, a move that would extend the two parties’ existing business collaboration in the country. The partners are considering a potential joint investment sum of approximately €1 billion, along with operating facilities for the production of specialty chemicals including non-ionic surfactants, methanesulfonic acid, iso-nonanol as well as other C4-based specialty chemical products. A decision is expected in 2011. HP
■ Improved outlook for US chemicals The outlook for the US chemicals manufacturing sector is improving gradually and global production is set to increase in the coming year, thanks in part to dramatic growth in export markets for the products of chemistry, according to a report from the American Chemistry Council (ACC). For 2010, US chemistry exports will be up by 17%, shifting the trade balance for the industry from a $0.1 billion deficit to a $3.7 billion surplus, its best performance in 10 years. The growth in export markets also has partially offset soft domestic demand for chemical products. Domestically, chemical production volumes have increased across all regions of the US in 2010 following steep declines in 2008 and 2009. The largest gains have occurred in the Gulf Coast and Ohio Valley regions, boosted by export demand for basic chemicals and plastics. Output is expected to grow moderately in all regions in 2011 and continue to improve through 2012. Growth in export markets is driven by several factors, including favorable energy costs, resulting from developments in extracting natural gas from shale; and growth in emerging markets, where recovery, and now expansion, has been strongest. US natural gas markets have seen a dynamic shift over the past five years as a result of increased capacity to extract natural gas from organic shale deposits. Reserves have risen by one-third, resulting in lower prices and greater availability of ethane, a feedstock material derived from natural gas that is the basis for hundreds of manufactured products. This low price for natural gas compared to oil has enabled US chemicals manufacturers to become more competitive than producers in much of the rest of the world. Growth in emerging markets, most notably in China, India and Brazil, is increasing demand for chemistry feedstock materials. Production of chemistry products in emerging economies increased by 12.2% in 2010, and further gains are expected. HP HYDROCARBON PROCESSING JANUARY 2011
I7
Two months ago, we had a process redesign. Last month? The I/O schedule changed…again. Today, skids showed up and didn’t match spec. And yet, our start-up isn’t changing.
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HPIN RELIABILITY HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR
[email protected]
Packing not best practice for firewater pumps Statistics show that for every 1,000 pump failures in hydrocarbon processing plants, there will be a fire. Fig. 1 shows a typical visible outcome, and the final bill for remedying such disastrous results can amount to hundreds of millions of dollars. Since roughly 60% of pump fires involve mechanical seal failures, it has been assumed that the majority of mechanical seals are somehow flawed. However, this conclusion is quite incorrect. Many pumps have been in service for years without seal failures. The entire experience points to the need to carefully select the right mechanical seal designs and to follow up by adhering to appropriate work processes and installation procedures. Braided packing or mechanical seals? There is still
the occasional assumption that critically important pumps will benefit from braided packing. Firewater pumps are mentioned in this context since they are expected to be available at all times and because, with water, a small amount of leakage is deemed tolerable. It might surprise some readers that, even here, packing is not the first choice of experienced professionals. Best practice in modern firewater pumps has been (since about 1968) to use single-spring mechanical seals. As was mentioned in the July 2010 HPIn Reliability column, these mechanical seals are to be backed up by a floating throttle bushing and a deflector guard. Reliability professionals interested in “designing out” maintenance always check into the feasibility of systematically upgrading their equipment. In fact, the very best HP companies mandate viewing every maintenance event as an opportunity to upgrade. For process pumps, one of the many cost-effective upgrade measures involves replacing the plain deflector guards that had been introduced in the 1950s. It is of more than historical interest to review what led to the recommendation and to use single-spring mechanical seals instead of packing. In the 1960s, accurate statistics were kept (for insurance purposes) by a major multinational oil company. The statistics for firewater pumps showed that leaking packing tended to ruin bearings. Well-designed mechanical seals were then selected because they generally leak much less than packing and are considerably less likely to allow water spray to enter the adjacent bearing housing. Of course, we know that brittle mechanical seal faces might shatter when abused. However, seals that are properly designed, selected and installed are highly unlikely to shatter. Moreover, floating throttle bushings represent a “second line of defense” in firewater pumps. Testing your firewater pumps. Proper operating and maintenance best practices require periodic testing of all standby equipment. Periodic testing is mandatory, and testing once every two weeks is not unreasonable. Each firewater pump would then be allowed to run for about an hour. Different rules may pertain to process pumps in other services.
FIG. 1
Scene of a refinery pump fire (Source: Release No. 200408-I-NM; US Chemical Safety Board; http://www.csb.gov).
For process pumps, the question is often asked differently. Some facilities believe that switching the “A” and “B” pumps and running each for a given time (months) is best. Another group believes that simply turning on the standby pump once a month and then running it for 4–6 hours is a better alternative. Which of the two is preferred? When people argued—many decades ago—that plants might get away with testing pumps as infrequently as twice a year, responsible reliability professionals took the position that testing only twice a year would not be acceptable and monthly testing was needed. Depending on lubricant selection and lube application method, switching “A” and “B” every two months is considered best practice. This then keeps the bearings lubricated, prevents the rolling elements from sitting in exactly the same position and prevents seal faces from sticking. Back to the issue of firewater pump sealing practices. Knowledgeable engineers do not advocate using packing in modern firewater pumps. The reasons are technical and were described above, but the reasons are also workforce and experience-related. Consider the difficulty of grooming and retaining top-notch maintenance personnel in some plants. Taken together, decades of experience and an examination of present-day workforce availabilities support the contention that packing no longer represents best practice at the most advanced companies. HP The author is Hydrocarbon Processing’s Reliability/Equipment Editor. The author of 18 textbooks and over 490 papers or articles, he advises process plants worldwide on reliability improvement and maintenance cost reduction opportunities. For more details, see his “Practical Lubrication for Industrial Facilities,” ISBN 0-88173-579-5.
HYDROCARBON PROCESSING JANUARY 2011
I9
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HPIN EUROPE TIM LLOYD WRIGHT, EUROPEAN EDITOR
[email protected]
European consumers mull their options as oil companies quit the market Although I’ve watched it coming, it still feels like a historic moment to see the oil industry pack up its things and leave. If you sell catalysts, pumps, inspection services, display ads or antistatic additives, then that low rumble is the ground moving—your market is changing under your feet. New supplier on the horizon. People who buy fuel are
waking up to a different logo on the tank truck and another voice on the telephone. Some are realizing too late that they’ll be losing a supplier with a certain standing, a reputation to preen and a level of expertise that they’ve come to count on. And if you’re not supplying, but manning a refinery or a marketing operation in Europe, then it isn’t just you. It’s happening all over. You’re not the only one seeing a new set of suits wandering through your workplace measuring you up. “We’ve had a room in the center of the main floor set up as a data room all summer,” one oil major executive told me on a recent visit. “People have had their teams coming in and running our numbers for months. The whole business is up for sale.” The international oil companies are bidding their farewells, and a new breed of nontraditional suppliers is doing its due diligence. For example, in the UK, half of the retail stations could change hands in the next few years, the Financial Times reckoned recently. France’s Total is selling its 780 stations in the country; Murphy Oil is selling its 480 stations. The Chevron Texaco business in the UK and Ireland is up for sale. It operates 1,300 stations under the Texaco brand. Exxon Mobil wants to supply, but no longer own and operate its Scottish forecourts. The sale or closure of numerous European refineries by Shell, Total, Chevron Texaco, ConocoPhillips and Petroplus is no longer a consultant’s projection, but an emerging reality. ‘New’ oil company. At a recent meeting of fuel buyers in the global aviation industry, one of the companies investing now to assume major oil market share was exuding confidence. Ian Taylor is CEO of Vitol, one of the world’s largest trading groups, a company that has come to be known to the airlines as one of the new “nontraditional” suppliers. He effectively thanked BP and Shell for their service and told the audience his company would take over from here. He went on to restate Vitol’s ongoing plans to take over Shell Aviation businesses all over Africa. Days later, Trafigura, another very substantial trading group, announced it would take over from BP in a number of southern African states. Chevron Corp. has sold its Caribbean and Central American fuels and aviation businesses recently to Rubis, a French midstream group. And it’s not just around the equator and in the southern hemisphere that the nontraditional suppliers are moving in. Morgan Stanley, the bank, is aggressively pursuing aviation custom in European markets, having traded fuels for many years. One of
its executives shared a stage at the aviation conference with the managing director of the newly launched Vitol Aviation. In the UK, Greenergy, the company I’ve followed since it was a half-dozen desks gathered around an oversized “Scalextric” toy car track, is bidding to buy up hundreds of service stations. It has already built one of the UK’s largest private businesses out of taking over clean fuels niches and later marketing functions, from major companies. Today, it delivers some 140 million liters (37 million US gallons) of fuel a week, but, like Vitol and Trafigura, it all started with oil trading. The oil companies aren’t getting out of supply roles across the board. Shell is at pains to point out that it intends to grow in some aviation markets as it leaves others. But the trend is unmistakable. “Look at an average major,” a bank researcher friend told me. “They may have 100,000 people, of which 70,000 work downstream. Yet 80% of their profits are coming from the upstream. They’re running the numbers and concluding, ‘why bother?’ John Digby, an independent consultant and former boss at Chevron Texaco, says that in the first half of 2010, upstream income accounted for some $48.6 billion at six leading major oil companies, while downstream income accounted for just $9.6 billion—a ratio of five to one. But it’s more than nostalgia that has some oil market end users flustered at the changes. The chair of an International Air Transport Association technical meeting wanted to know recently where were the expert representatives from the new suppliers in his working groups as they try to understand the salt contamination issue that recently led to a near disaster aboard a Cathay Pacific flight leaving Indonesia. “We’ll buy in expertise from the majors,” one of the trading groups told me. “We can’t afford to have any quality issues at all,” he added. That’s no doubt true, but one has to wonder what will be left of the quality assurance and long-term research and development function in the fuels supply industry. Admittedly, the oil companies themselves shrank technical and research facilities like Thornton and Sunbury very significantly during the 1990s, but will their research and technical facilities in the region now fade to nothing? And there’s another thing. As the international oil companies head off to spend the remaining decades of the oil age in more rewarding upstream pastures, the oil products markets are being handed to traders and banks. Granted, there’ll be new competition among the new suppliers with a nose for sourcing cost-effective streams of product. But end users may well be wary of what they see as a change from dealing with expert producers, to expert “middle-men.” HP The author is HP’s European Editor and also a specialist in European distillate markets. He 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 JANUARY 2011
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HPINTEGRATION STRATEGIES DICK HILL, CONTRIBUTING EDITOR
[email protected]
MPC vs. ARC—Not an ‘either/or’ decision Overview. In the 35 years since they introduced distributed control systems (DCSs), automation system suppliers have provided the hydrocarbon processing industry (HPI) and other customers with far more than the ubiquitous piping and instrumentation diagram (PID) control-function block in their suite of available function blocks. Many of the additional DCS function blocks originated back in the days before multivariable or modelpredictive control (MPC) was commercially available. We now refer to putting together functions such as lead-lag, dead time or selectors to formulate advanced control as advanced regulatory control (ARC). ARC and MPC are both types of advanced process control (APC). While DCSs provide advanced control capabilities in the many useful function blocks available, some end users in the HPI and other heavy process plants moved away from function blocks in favor of developing MPC models for APC. Getting the foundation right. Before MPC, if the process required advanced-control techniques, the process control practitioners had to assemble the correct control functions to achieve the required results. These evolved into what we now call ARC. Modern process control assumes that the regulatory control provided by the process control system is solid, with well-tuned loops and controllers operating in the correct mode. Without good basic regulatory control, APC will not perform well. But what about ARC? Now that MPC is so widely accepted and used, are control engineers and other practitioners still taking advantage of the ARC capabilities built into most DCSs? MPC isn’t the only tool in the toolbox. An entire
culture has evolved around the use of MPC. MPC has earned widespread respect and acceptance due to its often-spectacular payback. Despite the considerable implementation cost often involved, users have cited MPC projects that have delivered return on investment in 18 months or less. As a result, the “culture of MPC” might unduly influence some companies to implement MPC, when, in some cases, ARC implemented right in the DCS control blocks might actually provide the best solution. Not highlighted as much is the fact that MPC requires a continued investment. The models are built based on the set of process conditions, feedstocks, ambient conditions, variable interactions and business objectives that exist at that point in time. However, any or all of these may change, requiring the model to be modified or rebuilt for the MPC to continue driving value. Balancing ARC and MPC. So here’s a good question: If all the process needs to perform better is feedforward, do you really need to build (and maintain) a model to accomplish this? In many instances, advanced control could be accomplished
by configuring function blocks and tuning each to remove loop interaction and to provide feedforward action and other advanced regulatory control techniques. If so, could this possibly be a better approach than MPC? More to the point, how’s a plant to decide? There is no substitute for knowing your process and the skills of your control personnel. The process control culture in any plant or company has evolved over many years with deep roots in “how we’ve always done it.” All plants must continuously maintain basic regulatory control to provide the stable, well-tuned base layer. However, above this foundation, plants have options for performing APC functions. It’s important to note here that the choice of which technology to use for APC—whether MPC or ARC—is not an “either/ or” decision, but rather a matter of understanding which tool, or combination of tools, is best for each application. But how do you know if you have the right balance? The decision to implement an advanced-control application using MPC, ARC or some combination is more than a technology decision. Both tool sets can perform well for a variety of applications. Users must take support for the implemented application into consideration. If the staff at the site is not trained in maintaining MPC models, then ARC could be a better choice. If uniformity across the enterprise is important, it is important that the company considers how it will support remote locations, regardless of whether it chooses MPC or ARC. In the end, both MPC and ARC may be the right decision. Some applications will lend themselves to using DCS function blocks, while others are best solved using model predictive controllers. If you question whether you’re using the right combination, benchmarking can help you at least determine if you are alone or with the majority. End users in process plants may find it worthwhile to participate in ARC Advisory Group’s Benchmarking Consortium, which addresses MPC performance and other key issues. For more information, HP readers can visit http://www. arcweb.com/Benchmarking. HP
The author is vice president of ARC Advisory Group, Dedham, Massachusetts, responsible for developing the strategic direction for ARC products, services and geographical expansion. He is responsible for covering advanced software business worldwide. In addition, he provides leadership for support of ARC's automation team and clients. Mr. Hill has over 30 years of experience in manufacturing and automation. He has broad international experience with The Foxboro Company. Prior to Foxboro, Mr. Hill was a senior process control engineer with BP Oil, developing and implementing advanced process control applications. Prior to joining ARC, he was the US general manager of Walsh Automation, a major engineering consulting firm and supplier of CIM solutions to the pulp and paper, petrochemicals, pharmaceutical, and other process and manufacturing industries. He is a graduate from Lowell Technological Institute with a BS degree in chemical engineering. HYDROCARBON PROCESSING JANUARY 2011
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Süd-Chemie Defining the Future V Conference May 23-25, 2011 – Beijing, China Industry executives, technical experts and analysts will be discussing the latest innovations and breakthroughs in catalysis, process engineering, battery materials and water treatment technologies applied in these fields at the “Defining the Future V Conference.” Through open exchange and in-depth discussion, it is our goal to offer valuable insight into opportunities and challenges the industries are facing, and to support the formulation of strategies that can be developed to address them. This conference will be comprised of parallel sessions on:
• Refining Industries • Chemical Industries • Petrochemical Industries & Polyolefin Plants • Coal-To-Chemicals (Methanol & Derivatives) • Environmental Technologies • Battery Materials • Water Treatment Technologies Please mark your calendar and join us in Beijing!
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HPIMPACT BILLY THINNES, NEWS EDITOR
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Refinery and petrochemical construction costs continue measured rise The costs for designing and constructing downstream refining and petrochemical projects rose 3% from Q1 2010 to Q3 2010, according to the latest edition of the IHS CERA Downstream Capital Costs Index (DCCI). It was the third straight increase for the index since prices bottomed out at 9% below peak 2008 levels. Costs are now just 4% below their 2008 peak. The IHS CERA DCCI is a proprietary measure of project cost inflation similar in concept to the Consumer Price Index (CPI). It provides a benchmark for comparing costs around the world and draws upon proprietary IHS and IHS CERA databases and analytical tools. The current DCCI rose from 175 to 180 over the past six months. The values are indexed to the year 2000, meaning that a project that cost $100 in 2000 would cost $180 today. Higher commodity prices and a weakening US dollar continued to be the driving force behind the steady rise of costs in the downstream sector. “The momentum in the rise of costs back to prerecession levels is really a ‘slowmentum’ [sic] reflective of the broader global economic recovery,” said IHS CERA Chairman Daniel Yergin. “Activity is increasing and prices are rising, albeit with a healthy dose of caution.” Commodities prices were driven by the global economy’s recovery and increased construction activity as the impact of the fiscal stimuli was felt by the wider economy. Steel prices continued to show high degrees of volatility as iron ore producers switched from adjusting prices annually to adjusting them every quarter, reflecting market-based demand-supply fundamentals. The continued weakening of the US dollar also contributed to the rise of commodity prices while also driving up costs of equipment, labor and engineering and project management costs. The dollar’s fall was driven by the US Federal Reserve’s second round of quantitative easing to reinvigorate the US economy—the Fed recently announced a $600 billion plan to purchase treasury bonds over the next eight months. Robust downstream construction activity in China, India and the Middle East continues unabated, according to the index. Record refining and ethylene capacity additions came online in 2009 and more projects are in various stages of engineering and construction. This trend is expected to continue until 2015. Government policies encourage investment in the downstream sector in anticipation of increasing demand for transportation fuels, plastics and fibers. China plans to increase refining capacity by 50% in the next five years. Similarly, the Middle East is emerging as a major hub for petrochemicals with advantageous feedstock and government policies that incentivize diversification into other industries supported by petrochemicals. Large complex refineries with integrated petrochemicals are emerging as the “new standard” to position the downstream sector for profitability. The capacity additions in Asia will continue to put downward pressure on margins as excess capacity emerges in the face of
tepid consumer demand. Refiners and petrochemical companies in Organization for Economic Cooperation and Development (OECD) countries—which have been rationalizing refining capacity—will continue to face rising pressure to shut down older and less efficient plants with poor economics. “The economic outlook ahead appears to be mixed with rising prospects that the recent momentum will give way to an impending slowdown,” said Farooq Sheikh, lead researcher for the IHS CERA Capital Costs Analysis Forum for Downstream. “China also appears to be slowing down as the government increasingly restrains the fiscal stimulus and has recently increased interest rates by a quarter percent in fear of a real-estate bubble.” Developing countries are showing increasing concerns about capital flows into their markets creating an asset bubble. Capital controls and higher interest rates are being employed to temper unbridled growth. As a result, the IHS CERA DCCI concludes that another modest increase is expected in downstream capital costs in the near term as recovering construction activity and further increases in raw materials prices push costs closer to their pre-recession highs.
Moving beyond the meltdown in the Gulf According to Deloitte Center for Energy Solutions’ recent study, the Gulf of Mexico deepwater drilling remains vital to the US economy and is vital for future growth. For the record, “easy oil” is gone; oil companies must venture to more challenging regions to explore and produce (E&P) crude oil. Such projects will require billions of dollars of investment in new technologies to produce crude oil and natural gas at depths greater than 5,000 feet under water. For the Western Hemisphere, the Gulf remains a “hot bed” of E&P activity. This region’s crude oil reserves can provide a significant and secure source of domestic energy to the US. At present, 30% of the US’ oil supplies come from the Gulf of Mexico, and this region provides an economic engine to the US by creating over thousands of jobs and more than $11 billion a year in royalties and taxes. One event. For years, E&P companies have safety operated in the Gulf without incident; but everything change with the Deepwater Horizon tragedy. In response to this drilling rig accident, the US Department of Interior (DOI) immediately set in place a six-month moratorium on new shallow and deepwater drilling. The moratorium is affecting E&P operations in the Gulf. Delays in new oil supplies have contributed to the increase in oil prices during the Q4 of 2010 and the tightening in US crude supplies. The American Petroleum Institute estimates that a production loss of 80,000 bpd to 130,000 bpd of crude oil could be felt in the US market by 2015. The International Energy Agency estimates that between 100,000 bbls to 800,000 bbls of new oil supply could be deferred under the new rules, making it more difficult to supply US demand. More imports will be required to cover the gap between supply and demand. New realities. In addition to the stay on new drilling, the DOI is imposing more rules to promote safe and reliable operations on drilling operations. The regulations set guidelines over new operations and procedures, certifications, backup control systems, new HYDROCARBON PROCESSING JANUARY 2011
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HPIMPACT rig (equipment) and materials, and demonstrations of available unprecedented uncertainty. The 2008–2009 global economic backup blowout containment resources. Permitting delays are crisis threw the energy markets into severe turmoil. The pace of anticipated due to the extended regulatory reviews now in place. the global economic recovery holds the key to energy prospects Price of risk. Following the Deepwater Horizon event, E&P for the next several years, but it will be governments’ responses companies must evaluate their potential risk exposure at $30 bilto the twin challenges of climate change and energy security that lion when operating in the Gulf, up considerably from $75 milwill shape the future of energy in the longer term. The worst of lion. In a recent Deloitte survey of approximately 300 companies the global economic crisis appears to be over. But it will be a hard operating in the Gulf, only 10 international and national oil comfight to return to pre-2008 energy levels. In looking ahead, IEA panies have capitalization and a balance sheet that could withstand forecasts some changes in the global energy market: this level of liability. In addition, 40% of the companies working • Global primary energy demand will increase by 36% in the Gulf have a market capitalization of $5 billion or less—well between 2008 and 2035, or 1.2%/yr on average. This combelow the new level of risk exposure. Tolerance to risk is changing the environment within the Gulf. Some companies will continue to pursue projects; other companies will go to less risk areas. A mass exodus of oil and gas companies from the Gulf will have a negative impact on the US economy. The Deepwater Horizon accident was a tragedy that will be felt for many years. More important, many lessons have been learned through this experience by government and industry that will be most beneficial for future operations. Government and industry must find a common ground to move forward and to keep the Gulf open for business. Update. In a reversal, the Obama administration said on Dec. 1 that it will not pursue offshore drilling off the East Coast of the US and the eastern Gulf of Mexico. Because of the BP oil spill, the Interior Department will not propose any ,QQDWXUDOJDVSURGXFWLRQWUDQVPLVVLRQ new oil drilling in waters off the East Coast for at least the next seven years. VWRUDJHDQGFRQGLWLRQLQJ President Barack Obama’s earlier plan— announced in March, three weeks before 'LVFRYHUPRUH±YLVLWZZZPLFKHOOFRPXV the April BP spill—would have authorized officials to explore the potential for drilling from Delaware to central Florida, plus the northern waters of Alaska. The new plan allows potential drilling in Alaska, but officials said they will move cautiously before approving any leases. A spokeswoman for the US Chamber of Commerce said the decision represents a major step backward for the nation’s energy future. “The decision comes on top of the de facto moratorium the administration has imposed on production in both deep and shallow waters in the Gulf and Alaska, which is already causing significant harm to our economy and our energy security,” said Karen Harbert, president and CEO of the Chamber’s Institute for 21st Century Energy.
100 ppmv)
High
200–500
Changes in respiratory tissue (200–400 ppmv per laboratory animals) Rapid respiratory distress and failure (acute exposure at > 500 ppmv for 1 to 4 hours)2
Very high
> 2,000
Coma and death after single breath4 Known as “knockdown effect” with immediate immobilization and unconsciousness, possibly from disruption of oxidative metabolism in the brain HYDROCARBON PROCESSING JANUARY 2011
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SPECIALREPORT
GAS PROCESSING DEVELOPMENTS
nerve cell function, putting certain nerves to sleep, including olfactory (as discussed previously) and the ones necessary for breathing. Table 1 shows the typical exposure symptoms of H2S. It is important to note that while most chemicals are toxic, exposure has to occur (at a level that is considered toxic) before adverse health effects are observed. Most, if not all, of the irreversible health outcomes including death have occurred due to overexposure to H2S in confined areas.
Texas), as far as the oxygen partial pressure is concerned. Most people who are acclimated to sea level would have no trouble going to 3,000 ft in elevation. In summary, mixing 10 parts CO2 with 90 parts air can possibly cause a person breathing the mixture to die if exposed long enough. In contrast, mixing 10% N2 with air probably has little effect on a person. Clearly, it is very important to recognize that CO2 is not the same simple asphyxiant as N2.
Toxicity of CO2. Carbon dioxide is a slightly toxic, odorless
Occupational exposure limits for H2S and CO2. Table 3 provides a summary of occupational exposure limits for H2S and CO2. Occupational exposure limits are typically designed to protect health and to provide for the safety of employees for up to a 40-hour work week, over a working lifetime. The threshold limit value (TLV) was developed by the American Conference of Governmental Industrial Hygienists (ACGIH) while the permissible exposure limit (PEL) is an enforceable standard developed by the Occupational Safety and Health Administration (OSHA). The short-term exposure limit (STEL) was developed by ACGIH and represents a 15-minute timeweighted average exposure that should not be exceeded at any time during the workday. The IDLH value was developed by the National Institute for Occupational Safety and Health (NIOSH) to provide a level at which a worker could escape without injury or irreversible health effects. IDLH values are conservatively established by NIOSH to give a worker approximately 30 minutes to evacuate an area. The IDLH for both H2S and CO2 are purposefully established below levels at which adverse and irreversible health effects would be seen following 30 minutes of exposure. The IDLH for H2S was developed based on human data (and supplemented with information from laboratory animals) that showed that between 170 ppmv and 300 ppmv, a person can be exposed for one hour without serious health effects and that 400 ppmv to 700 ppmv can be dangerous if exposure is greater than 30 minutes. A person can be exposed to H2S at 800 ppmv for approximately 5 minutes before unconsciousness occurs, while exposure at 1,000 ppmv or greater can cause immediate respiratory arrest, unconsciousness and possibly death. For CO 2, a person can sustain exposure to the IDLH of 40,000 ppmv for 30 minutes with minimal signs of intoxication (e.g., changes in breathing rate, headache and fatigue). At 30 minutes of exposure to 50,000 ppmv CO2, signs of intoxication become more pronounced. A person can sustain exposure to 70,000 ppmv to 100,000 ppmv CO2 for about 5 minutes and signs of intoxication become intense with very labored breathing, visual impairment, headache, ringing in the ears and potentially impaired judgment. Air containing CO2 at a concentration
and colorless gas. It is typically found in air at around 360 ppmv (0.036 vol%) while exhaled air may contain as much as 40,000 ppmv (4 vol%). Table 2 shows the general affects of CO2 over different ranges of exposure. At lower concentrations, CO2 affects the respiratory system and central nervous system. Too much CO2 also acts as a simple asphyxiant by reducing the amount of oxygen available for respiration.6 At higher concentrations, too, the ability to eliminate CO2 decreases and it can accumulate in the body. In this way, CO2 differs from some other asphyxiants, such as nitrogen (N2). Unlike CO2, N2 does not get distributed throughout the body to cause an adverse health effect; rather, N2 acts simply by displacing oxygen from the air and, thereby, decreasing the amount of oxygen available for respiration. Result: CO2 is dangerous at a much lower level than some other asphyxiants, such as N2. Nitrogen is discussed here because it is a common potential asphyxiant in industrial settings. The following example illustrates the differences between CO2 and N2. Consider a hypothetical example where 90 parts of atmospheric air (normally 21% O2 and 79% N2) are mixed with 10 parts of either pure CO2 or N2. The resulting mixture compositions are shown in Fig. 1. As shown in Fig. 1, the resulting mixture with CO2 addition contains 18.9% O2, 71.1% N2, and 10% CO2. As discussed previously, such a mixture could potentially kill a person. Conversely, the mixture with N2 contains 18.9% O2 and 81.1% N2; while this mixture is lower in oxygen than normal air and below the recommended O2 % for workers, it is not likely to cause irreversible health effects. The effect of going from a 21% oxygen atmosphere to an 18.9% oxygen atmosphere is similar to going from sea level to about 3,000 ft in elevation (roughly the elevation of Midland, TABLE 2. Symptoms from low to high concentrations of CO2 Exposure level
Concentration, ppmv
Symptom
Low
20,000 to 30,000
Shortness of breath, deep breathing
Medium
50,000 75,000
Breathing becomes heavy, sweating, pulse quickens Headaches, dizziness, restlessness, breathlessness, increased heart rate and blood pressure, visual distortion
High Very high
100,000 300,000
CO2 addition 10
Impaired hearing, nausea, vomiting, loss of consciousness Coma, convulsions, death5
TLV and PEL, ppmv
STEL, ppmv
10
15
100
CO2
5,000
30,000
40,000
46
I JANUARY 2011 HYDROCARBON PROCESSING
% O2
% N2 71.1
H2S
18.9
18.9 % O2
TABLE 3. Exposure limits for H2S and CO27 Compound
N2 addition
% CO2
% N2 81.1
IDLH, ppmv FIG. 1
Mixture compositions with 90 parts air and 10 parts CO2 or N2.
GAS PROCESSING DEVELOPMENTS greater than 100,000 ppmv (i.e., 10 vol%) can produce extreme discomfort and, as indicated above, can be life-threatening. Table 4 shows an example of how a gas stream containing initial concentrations of H2S of 2,000 ppmv and of CO2 of 98 vol% would change assuming a uniform dispersion in air for both compounds. As shown in the table, when the IDLH of H2S (100 ppmv) is reached, the CO2 content is still above the IDLH level of 40,000 ppmv. Even more dramatic are the 5-minute exposure levels; when the H2S exposure level is at the 5-minute limit of 800 ppmv, the CO2 concentration is at 392,000 ppmv, which is far above the level a person can survive for 5 minutes. Thus, given the much higher percentage of the CO2 in this gas stream, the danger from CO2 is higher than the danger posed by H2S.
SPECIALREPORT
would be in a low-lying area or depression. This is currently an issue for CO2 pipelines in which harmful levels of CO2 can accumulate in these areas, regardless of the presence of H2S. The presence of H2S increases concerns due to its more insidious toxicity (i.e., it can render a person incapable of escape at sufficiently high concentrations). However, levels above the IDLH could occur in a confined space or depression for either compound. As indicated earlier, the presence of H2S may provide a warning that a release has occurred and prevent a person from entering the area where potentially dangerous levels of CO2 or H2S may be present. Note: The use of direct reading gas detection instrumentation and other protective measures should be required before entering confined spaces such as manholes, tanks, pits and vessels that could contain a buildup of these gases.
Potential exposure scenarios to H 2S and CO2. In
actuality, it is difficult to determine the likelihood of a release and the potential concentration a person may encounter following a release. A release could occur at any point in the processing unit or transfer pipeline depending on the source of the stream (see Fig. 2). Atmospheric conditions, such as the wind or physical location of the release (low lying area), can greatly affect the dispersion rate and exposure concentrations of the two compounds. Some potential exposure scenarios are discussed here. If there is wind, a small release (i.e., not a catastrophic event) would most likely disperse relatively quickly. Under this scenario, a person downwind (unless they were within close proximity to the release) would probably not be exposed to a harmful concentration of either compound. In fact, the presence of H2S (which has an odor at very low concentrations) may actually provide an early indicator of a CO2 release that would otherwise go undetected. Although H2S may provide an early indicator of a release in certain situations, this should not be relied upon because H2S deadens the sense of smell at higher concentrations. Exposure should be kept to a minimum by applying sufficient engineering controls and safe work practices. Appropriate monitoring and personal protective equipment should always be used. Because both compounds are heavier than air (the specific gravity for H2S and CO2 is 1.192 and 1.52, respectively), the most likely place to encounter harmful levels of either compound
Potential synergistic effects of concurrent exposure.
Since the mechanisms of action for CO2 and H2S are very different, it is unlikely that exposure to both compounds will be worse than exposure to only one compound. Most occupational exposure limits are based on exposure to single compounds, even though it is recognized that multiple compounds may be encountered, and Environmental Protection Agency only considers compounds additive if they affect the same target organ or act by the same mechanism. Moreover, industries such as swine production, where both CO2 and H2S are measured in the air, do not adjust occupational exposure limits for added worker safety nor have synergist effects (i.e., effects that are worse when in combination than when exposure is to a single compound) been noted for industries where exposure to both compounds occur.8
TABLE 4. Occupational limits example (high-purity CO2 gas with low H2S) CO2, ppmv
H2S, ppmv
Initial concentration, %
Dispersion
980,000
2,000
Occupational exposure limit
10
882,000
1,800
20
784,000
1,600
30
686,000
1,400
40
588,000
1,200
50
490,000
1,000
60
392,000
800
70
294,000
600
80
196,000
400
90
98,000
200
5-minute CO2 exposure (100,000 to 70,000 ppmv)
95
49,000
100
H2S IDLH (100 ppmv)
95.9
40,000
82
CO2 IDLH (40,000 ppmv)
100
0
0
FIG. 2A Example sources of high-purity CO2 and low H2S streams— CO2 dehydration unit.
5-minute H2S exposure (800 ppmv)
FIG. 2B Example sources of high-purity CO2 and low H2S streams— CO2 piping. HYDROCARBON PROCESSING JANUARY 2011
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SPECIALREPORT
GAS PROCESSING DEVELOPMENTS
Evaluation of risk. Based on the general qualitative analysis of exposure to both H2S and CO2 discussed here, it appears that there is no increased risk from the presence of H2S at low levels (e.g., up to perhaps 2,000 ppmv or higher) in high-purity CO2 gas. In fact, in these types of gas streams, the potential exposure to high CO2 concentrations during a release event could be as dangerous, or more dangerous, than exposure to lower concentrations of the more toxic H2S. At high concentrations, CO2 may accumulate in the body, which is different than some other asphyxiants (i.e., N2). It is most important to recognize the difference between CO2 and other common asphyxiants. In some cases, the H2S in the gas may serve as a warning for the more hazardous CO2 environment. Dispersion modeling for specific release scenarios should be conducted to better understand possible exposure limits and impacts on human health for both compounds. Appropriate safety precautions should be implemented including monitoring (both fixed and personal detection systems) and training on chemical hazards, personal protection equipment and safety rescue procedures. HP 1
2
3
4 5
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LITERATURE CITED US Environmental Protection Agency, Integrated Risk Information System (IRIS), Profile for Hydrogen Sulfide (CASRN 7783-06-4). Online database, http://www.epa.gov/iris/subst/0061.htm, August 2010. “Hydrogen Sulfide Fact Sheet,” August 2004, SafetyDirectory.com; http:// www.safetydirectory.com/hazardous_substances/hydrogen_sulfide/fact_sheet. htm Agency for Toxic Substances and Disease Registry (ATSDR), Draft Toxicological Profiles for Hydrogen Sulfide, US Department of Health and Human Services. Public Health Service, September 2004. Gossel, T. A. and J. D. Bricker, Principles of Clinical Toxicology, Third Edition, Raven Press, New York, New York, 1994. Goodman Gilman, A., L.S. Goodman, T.W. Rall and R. Murad, The Pharmacological Basis of Therapeutics, Seventh Edition, MacMillan Publishing Co., New York, New York, 1985. Klaassen, C. D., Cassarett and Doull’s Toxicology—The Basic Science of Poisons, Seventh Edition, McGraw-Hill Publishing Co., New York, New York, 2008. National Institute for Occupational Safety and Health, NIOSH Pocket Guide to Chemical Hazards, US Department of Health and Human Services. Public Health Service. Centers for Disease Control and Prevention. February 2004. Lemay, S., L. Chenard and R. MacDonald, “Indoor Air Quality in Pig Buildings: Why Is It Important And How Is It Managed?,” London Swine Conference—Conquering the Challenges, April 11–12, 2004.
Kirby Tyndall, PhD, DABT, is a senior consulting toxicologist with Pastor, Behling, & Wheeler, LLC. She is a board certified toxicologist with over 19 years of experience in the fields of toxicology, risk assessment and risk management. Dr. Tyndall has worked in both the environmental consulting and government sectors, and has significant experience evaluating potential human health and ecological risks associated with exposure to contaminants in environmental media (air, water, soil, sediment and biota including fish, etc.).
Ken McIntush, PE is a practicing chemical engineer and president of Trimeric Corp., a small company based in Buda, Texas, that is focused on chemical/process engineering. He has about 21 years of varied process engineering experience, serving clients in oil refining, oil and gas processing, silicon refining and several other industries. Mr. McIntush performs troubleshooting, debottlenecking and other projects for the company. He holds a BS degree in chemical engineering from Texas A&M University, College Station.
Joe Lundeen is a principal engineer at Trimeric Corp. in Buda, Texas. He has 21 years of experience in process engineering, process troubleshooting, and facility installation for oil and gas production and CO2 processing clients. His recent experience has been focused on dehydration, contaminant removal, and transport of super-critical CO2. He holds BS and MS degrees in chemical engineering from the University of Missouri, Rolla.
Kevin Fisher, PE is a principal engineer at Trimeric Corp. in Buda, Texas. He has over 20 years of experience in process engineering, research and development, and troubleshooting for oil and gas production and oil refining clients, as well as for private and government-sponsored research programs. He holds an MS degree in chemical engineering from the University of Texas, and BS degrees in chemical engineering and chemistry from Texas A&M and Sam Houston State University, respectively.
Carrie Beitler is a senior engineer at Trimeric Corp. in Buda, Texas. She has over 15 years of experience in process engineering, process modeling and optimization of unit operations in the natural gas, petroleum refining and CO2 processing areas. She also specializes in the development of process design packages for the fabrication of open-art technology such as caustic scrubbers, acid-gas injection units, glycol dehydrators and amine treaters. She graduated with a BS degree in chemical engineering from Purdue University.
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I JANUARY 2011 HYDROCARBON PROCESSING
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GAS PROCESSING DEVELOPMENTS
SPECIALREPORT
Use online analyzers for successful monitoring Improved analytics measure moisture and dew points for natural gas components A. BENTON, Michell Instruments Ltd., Ely, Cambridgeshire, United Kingdom; and C. VALIZ, PDVSA, Jose Complex, Venezuela
U
sing advanced online water and hydrocarbon dew-point analysis techniques is critical to the efficient and reliable operation of natural gas liquid-extraction processes, producing valuable light alkane liquids while the remaining gas is suitable for sales distribution. At its San Joaquin facility, Petróleos de Venezuela, S.A. (PDVSA) initially processed raw wellhead natural gas by separating residual hydrocarbon (HC) condensates, followed by glycol dehydration to reduce the water dew point. Reduced temperature separation was used to decrease the HC dew point prior to molecular sieve dehydration. This provided feed gas with moisture controlled to trace levels into the primary liquid-extraction process. Maintaining moisture concentrations to less than 0.1 parts per million (ppm) by volume is essential for reliably operating turbo expanders. The turboexpanders’ function is to use the depressurization of natural gas to achieve deep cooling of the process flow to –80°C. Avoiding ice formation within the separation process—particularly the turboexpander—is critically important for continuous plant operations and to prevent astronomical maintenance costs. Online measurement of dew point temperature within the feed gas, containing water precipitate and hydrocarbon condensate, enabled PDVSA process operators to extend the lifetime of the desiccant beds while protecting the turboexpanders from risk of damage. The San Joaquin plant (Fig. 1) started operation in 1985 and currently provides a third of the total Venezuelan production of natural gas liquids, roughly 43,000 barrels per day, transferred
FIG. 1
PDVSA San Joaquin extraction plant.
via pipeline to the PDVSA Jose Complex, near Barcelona. The Jose fractionation plant extracts butane, iso-butane and other individual alkanes. Residual gas production at 1,000 million standard cubic feet per day (MMf 3d) enters the Venezuelan market network. The extraction process. The production train at the San Joaquin process plant is shown in Fig. 2, while Fig. 3 illustrates a schematic of an individual train. Unprocessed wellhead natural gas (two-phase gas flow with entrained hydrocarbon liquids and water) enters the San Joaquin facility. It is initially processed using separation vessels to collect the bulk-entrained natural gas liquids that flow in the feed pipeline. The gas at this point is highly corrosive and saturated with moisture, and is prone to hydrate formation. Hydrate formation is crystalline solids that form from condensed liquid water in combination with methane under pressurized conditions, even at temperatures above freezing. Initial dehydration is carried out at the earliest stage by a glycol contactor where liquid triethylene glycol (TEG) is spray injected as a desiccant into the gas flow rising through a process column contactor (Fig. 4). Moisture-laden TEG is collected from the contactor for heat regeneration greater than 200°C, so boiling off the adsorbed moisture is done in a continuous circulation process. At this stage, the gas is dry—the water dew-point temperature is lower than 0°C, below the process temperature conditions at
FIG. 2
Production train at San Joaquin.
HYDROCARBON PROCESSING JANUARY 2011
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GAS PROCESSING DEVELOPMENTS
Expansion
1
2
Wellhead natural gas
Separator J-T outlet
12
Residual gas to national distribution system 69 barg
55 bar -33ºC 17 bar -79ºC
34
Separator T-E inlet
Seperator J-T inlet
Silica gel x 2
Compression
Turbo-expander
Joule-Thomson valve 58 bar 66 bar 11ºC 18ºC
Glycol (TEG) dehydration contactor
Separator T-E outlet
SPECIALREPORT
Glycol regeneration system Natural gas liquids
Liquid stabilizer
Molecular sieve columns x 4
Deethanizer Natural gas liquids
FIG. 3
Process train schematic.
140
Process pressure, bar
120 100
Hydrocarbon dew-point reduction at process stages Residual gas Outlet J-T seperator Gas entering plant
80 60 40 20 0 -100
FIG. 5
FIG. 4
Glycol contactor tower.
the prevailing process pressure. Therefore, while not entrained with liquid water, the gas is still heavily laden with HC liquids as a potential two-phase flow. The liquid content of the gas is suppressed through two stages of separation, before and after a Joule-Thomson (J-T) expansion valve that generates moderate 50
I JANUARY 2011 HYDROCARBON PROCESSING
-80
-60 -40 -20 0 20 40 Hydrocarbon dew-point temperature, °C
60
80
Phase envelop (HC dew point curves) at stages throughout the liquid extraction process.
cooling of the gas by approximately 7 Kelvin through partial pressure reduction at 8 bars. This yields part of the natural gas liquid production while reducing the HC dew-point gas temperature. The effect of this separation process is illustrated in Fig. 5. Reducing the HC dew point is important for the next stage of the process—dehydration to trace moisture concentration through molecular sieve columns (Fig. 6). Reduction in the liquid loading of the gas is critical to the molecular sieves’ drying efficiency. If liquids are present, it adversely affects the moisture adsorption properties of the materials’ lattice structure and the overall operation lifetime of the sieves. Reduction in the water dew point below –80°C (at process pressure equating to a moisture concentration of less than 0.1 ppmV) is critically important for operating the turboexpanders. Turboexpanders, (Fig. 7) or expansion turbines, recover useful work from the expansion of a gas stream while lowering the process temperature, resulting in partial liquefaction of the bulk stream. As the expansion nears isentropic, the turboexpander reduces the process gas temperature significantly more than
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Corporate Headquarters:1BOUJHP1MBDF 4VJUFt&BTU)BNQUPO /:t5FMFQIPOFt'BY Main Plant/Sales Office:8IFBUMBOE$FOUFS3PBEt4DPUUTWJMMF /:t5FMFQIPOFt'BY 8FCXXXTBCJONFUBMDPNt&NBJMTBMFT!TBCJONFUBMDPN Additional Facilities:8JMMJTUPO /%t$PCBMU 0OUBSJP $BOBEBt-BUJO"NFSJDBt.FYJDPt&VSPQFt"TJB1BDJGJD 72 Select Select65 64at atwww.HydrocarbonProcessing.com/RS www.HydrocarbonProcessing.com/RS
SPECIALREPORT
FIG. 6
GAS PROCESSING DEVELOPMENTS
Molecular sieve dehydration columns.
FIG. 8
FIG. 7
Turboexpander and a deethanizer column.
expansion across a J-T valve for the same 38-bar pressure drop. The consequences of higher moisture concentrations within the process gas can be catastrophic, as the lowest temperatures in the liquid extraction process approaches –79°C. If the gas water dew point rises above that temperature, then rapid ice formation will bring a high risk of physical damage to the rotating blades on the turboexpander. The deep cooled natural gas goes through multiple stages of liquid separation as the temperature cascades downward into a deethanization column. The result is a lean natural gas with only C1 and C2 hydrocarbons and some residual CO2 (Fig. 5). Compression of this remaining gas into the national distribution system is carried out by a centrifugal compressor linked to the shaft of the turboexpander, therefore capturing useful work from the gas expansion. A rich blend of propane, butane and heavier hydrocarbons forms the natural gas liquids transferred by pipeline to the fractionation plant. Online dew-point analysis. Close monitoring of the dew-
point levels at critical points across the San Joaquin extraction facility requires 12 combined hydrocarbon and water dew-point analyzers (Fig. 8). PDVSA installed two analyzers on the glycol dehydration contactors and five on each production train. Each train had four individual molecular sieve columns that needed to be monitored continuously along with the common header outlet feed to the turboexpander plant. Dew point is the temperature where a vapor or the combination of vapors condense to form a liquid, seen as dew drops, when the gas is cooled. When the dew-point temperature is below freezing, ice crystals form. HC 52
I JANUARY 2011 HYDROCARBON PROCESSING
Hydrocarbon and water dew-point analyzer with a sampling system.
dew point is the condensation temperature of the heaviest HC components. Often, molecules with greater than 10 carbon atoms, present in ppm and sub-ppm concentrations, will condense to form HC condensates. The analyzer (Fig. 7) will simultaneously measure HCs and water dew point using two discrete sensor cells applying dedicated sensor technologies (Fig. 9). A direct fundamental principle adapted from the optical cooled mirror technique is applied for the HC dew-point measurement. An abraded optical surface with a conical depression profile has been developed specifically for the detection of the low surface tension films that are characteristic of the precipitation that occurs at the HC dew point. A visible red spectrum source directed onto the abraded surface scatters the light. A photo detector is positioned so that it captures the scattered light. It diminishes rapidly as the condensate film forms on the surface, cooling down to the temperature region of the HC dew point by a heat pump under the automatic control of the analyzer firmware. As the condensate film forms, a ring of light develops as the surface within the conical depression becomes more reflective. However, it is the secondary effect of reduction in scattered light intensity that enables the analyzer to detect the HC dew point to a sensitivity of 5 mg/m3 condensate mass per volume of gas. Unlike the HC dew point, an optical condensation technique cannot be applied to the water dew point measurement in this application. The water dew point temperature is significantly lower than the HC dew-point, such that any cooled surface would be flooded with condensate at a temperature far higher than the water dew point. For such measurements, a ceramic moisture sensor is used. Working on a moisture adsorption principle, the sensor adsorbs moisture into a micron-thin hygroscopic metal film in equilibrium with the flowing gas stream. The sensor exhibits an impedance change in proportion to the partial pressure of moisture vapor, the most elementary hygrometric unit. This is directly related to dew-point temperature, the measure-
GAS PROCESSING DEVELOPMENTS ment unit where each sensor is calibrated. These sensors have an extremely wide sensitivity range, being calibrated traceable to national metrology standards from –100°C to +20°C dew point. They also have the capability to measure directly at process pressure conditions representing greater than 20,000 ppmV moisture content at full scale compared to less than 0.01 ppmV at the low end—this is important for measuring the turbo expander feed gas. In-situ measurement verification.
Although the sensors performing the online water dew point measurement are factory-calibrated traceable to national metrology standards, the critical nature of the water dew-point measurement for the turboexpander feed gas demands that PDVSA site personnel carry out periodic verification of the online analyzers during field operation. This is done in-situ using a portable dew point analyzer. Given the extremely low level of water dew point within the process (< –80°C dew point) and the process pressure of 60 barg, equating to less than 0.1 ppmV, it is advantageous to carry out the verification measurement by installing a reference dew-point sensor within the online analyzer on a temporary basis. This enables both online and reference sensors to be in total equilibrium with the process gas sample under the same conditions over the duration of some hours. Through this method, PDVSA was able to maintain the highest level of confidence in the measurements.
SPECIALREPORT
Permeable gold film Hygroscopic mono-layer Base electrode Ceramic substrate Moisture molecules
FIG. 9
Schematic diagrams of ceramic impedance moisture (left) and HC dew-point detection technique (right).
FIG. 10
Traces from molecular sieve capacity tests. Note: the Y-axis is scaled in °F dew-point temperature.
Process plant proving field trials. During June and July
of 2009, PDVSA carried out trials to determine the operational status of the molecular sieve desiccant within the four drying columns on Train B at the San Joaquin facility. During normal plant operation, the columns were operated in an overlapping sequence for 36 hr before going offline for regeneration by heating to 300°C and back-flushing during an 8-hr period. At least three of the columns were in process operation in parallel at one time. During the plant-proving trials, the total adsorption capacity of each column was assessed through continuous operation until moisture breakthrough was detected by the online monitoring of dew point analyzers. After three years of use for the current molecular sieve material and an expected operational lifetime prediction of 3½ yrs, the purpose of the test was to determine the capacity of each bed and the urgency of scheduling when to replace each desiccant. Furthermore, the regeneration cycle times were reassessed to optimize the sequence throughout the remaining lifetime of the existing bed material. Fig. 10 illustrates the moisture breakthrough on two individual desiccant beds occurring after 30 hr and 32 hr of continuous adsorption. The red trace shows the increase in the gas’ dew point in the common header resulting from these high moisture excursions. Given similar findings on the other two desiccant beds, PDVSA
reduced the operational adsorption period for each column to 27 hr, with a 9-hr regeneration sequence, to extend the useful life of the molecular sieve material through the intended replacement date of February 2010. The proving trials served to reaffirm to the PDVSA plant operations and laboratory staff. It was shown that the performance of the analyzers after the first 18 months of successfully monitoring the dew-point conditions was critical to the continuous process operation and the reliability of key plant equipment. HP
Andy Benton joined Michell Instruments Ltd in 1983, initially in the R&D section. Throughout his career he has specialized in devising innovative solutions to applications for online process gas and liquid analysis. Most particularly for the natural gas industry, Mr. Benton has advised best practice for water and hydrocarbon dew-point control and measurement to producers, pipeline operators and large scale end users covering six continents.
Carlos Valiz joined PDVSA Gas 15 years ago as senior chemist specializing in laboratory analysis. His current position is quality control supervisor for the complete Eastern Venezuela division of PDVSA Gas.
HYDROCARBON PROCESSING JANUARY 2011
I 53
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GAS PROCESSING DEVELOPMENTS
SPECIALREPORT
Advanced chemical process for treating sour gas Technology avoids huge capital investments while speeding up results C. A. ORTEGA PERALTA and M. J. ORTEGA CASTELÁN, NEUGA SA, Argentina
C
urrent gas-sweetening technology requires plants to treat at least 1 million standard cubic meters per day (MMm3/d) of gas to be economically feasible. This article presents a versatile technology that can be profitably applied to any gas flow from 10 thousand standard cubic meters per day (Mm3/d) up to several million with the benefit of reducing setup periods. This technology (Fig. 1) has been proven over five years in a gas-compression plant where sulfur and mercaptans (RSH) contamination unexpectedly rose from 150 ppm to 1,000 ppm. This allowed the company to comply with an existing commercial agreement for 100 Mm3/d. The problem. In the proven installation, gas-flow production
is collected along 50 km in an 8-in.-diameter pipeline. Gas-flow temperature is generally around 60°F, and pressure is as low as 3 kg/cm2. The contaminants to be scavenged are hydrogen sulfide (H2S), RSH and carbon dioxide (CO2). Plant process is completed by a set of alternative compressors, a distillation plant and dew-point adjustment for high pressure. Afterward, sweetened natural gas is dispatched through a transport pipeline injection (95%) and liquefied petroleum gas (LPG) to trucks (5%). The original sweetening processing plant was designed through seven towers containing a solid chemical scavengerbased in OxFey. Over time, H2S and CO2 levels strongly rose, and mercaptans appeared as contaminants. Scavenger products used were specific for H2S acid treatments, since contamination was prevalent in the beginning. However, the scenario changed to have lower yields, requiring using different liquid chemical injections downstream to obtain the required output specification. Operating costs increased to a point where the alternative to interrupt supply needed to be evaluated, despite the reputation impact in the market. Due to this problem, it was proposed to test the chemical process, changing the “chemical scavenger,” in a pilot plant. Amine technology was quickly discarded since the gas standard flow being treated was heavy in contamination, implying an expensive installation and high operative costs. As a consequence, testing began on a process using a strong alkali that reacts with weak acid contaminants forming a buffer solution, which means the possibility of obtaining a controlled pH in the effluents. Moreover, it is possible to add commercial value to all the salts obtained in the reaction. The design. Plant capacity defined what to consider in the
• Caustic recuperation and recycling • Byproducts concentration • Both, depending on the commercial alternatives. A specific study must include a gas-contaminant assessment to define the technical application in function of the treatments to byproducts. In the opposite extreme, it is possible to simply install modular plants just near well-outs. An important advantage is the protection of pipeline transporting only sweet gas. New process chemistry. Case with H2S (plus or without
RSH), as contaminant: H2S + H2O > SH– + (H3O)+ Ka = 4 x 10–7 + + RSH + Na > SHNa + R S HNa + (OH)– + (H3O)+ + H2O SH– + 3 H2O + Na+ pH = 7.1 (buffer), pH control is required according to Henderson-Hasselbach to monitor log ((SH–)/(H2 S)). Such control is related to the tower and packed design, drain and make-up of the scavenger, with continual checking of pH values. The solubility of H2S in water is important in industrial practice, especially in these environmental-awareness times. The fate of such an unfriendly component such as H2S is important to track. H2S is highly toxic, has a noxious odor and can form harmful-reaction products [such as sulfur dioxide (SOx)]. The treatment for the solubility in strong bases is the same as that in acids, but the effect is dramatically different. As with Sweet gas Strong alkyl solution
Sour gas H2S, CO2, RSH contaminants
Byproducts chemical treatments and recycling Byproducts alkaline salts
FIG. 1
The technology and conceptual design.
selected process and included: HYDROCARBON PROCESSING JANUARY 2011
I 55
SPECIALREPORT
GAS PROCESSING DEVELOPMENTS
TABLE 1. Flow and variables controlled Flow, m3/d 100.000
Dp, kg/cm2
H2S, ppm
SHR, ppm
CO2, ppm
Inerts, N2 + CO2 %
Byproducts and pH
0.1
700 in < 2 out
400 in < 2 out
4,500 in 2,000 out
2 in 1.8 out
SHNa SNa2 CO3Na2 10.5
Scavenger recirculation, m3/hr
Scavenger makeup, m3/hr
2
0.25
TABLE 2. New scavenger advantages Plant size
Low mass transference coefficient and high solution reactivity, allows high spacial gas velocity and small tower diameter. Plant size could be defined modular, in the area of well production. Plant size could be defined integrally, allow catching full well production up stream of plant compression.
Tower type
High contact areas require the use of “packed towers,” the “mass transfer rings” type, offering: Very low pressure loss Minimal maintenance High chemical resistance No water absorption Low investment cost Simple and easy charge of the package
Effluents of process
The process has no gaseous effluents. Liquid effluents have important industrial uses as byproducts. CO3Na2, CO3HNa, SNa2 and SHNa, are key raw materials in various industries. This process can be classified as “No contaminants to the environment.”
Sweet and sour gases mixed
Sweet gas
Well Fresh solution
8-in. Well Well Slug-trap Packed towers
Na2CO3 + 2 H2O H2CO3 + 2Na+ + 2 (OH)– buffer pH = 11/13 CO2 is a gas easily soluble in water and the solubility equilibrium is maintained in agreement with Raoult Law. Part of dissolved CO2 is converted to carbonic acid, which reacts as weak acid forming buffer salts. Both salts obtained have important industrial uses. On the other hand, the sodium carbonate can react, giving back the caustic alkali in agreement with the following: Na2CO3 + CaO > CaCO3 + NaOH Case with H2S and CO2, as the contaminant. In cases
To clients
Byproducts
FIG. 2
Concentrator
Recycling process
The solution.
the case of strong acids, the amount of the molecular species is dictated by the partial pressure. However, in this case, the reactions are shifted to the right producing more of the ionic sulfide species, thus dramatically increasing the total H2S concentration.
where both contaminants are present, plant design must consider that an H2S acid in spite of having similar Ka as H3CO2, is more powerful as a reducer. Thus, H2S is the first priority as a reactive in the presence of a strong caustic like the scavenger. When the designer defines basic engineering, spacial velocity of sour gas and scavenger flow are dependent on the quantities of acid to be neutralized. In the case presented in Table 1, the tower design has the capability of neutralizing, at first, 30% of the H2S being present. Afterward, it neutralizes up to 70% of H2S and 60% of the total CO2 present in the original sour gas. Designers can define the capability of the strong caustic, while waste solution pH will vary with the byproduct salts present in the overall solution. HP
Carlos Alberto Ortega Peralta is the executive president at NEUGA SA. He has over 42 years of experience in process design and plant processes. Mr. Ortega Peralta invented the Titular Process.
Case with CO2, as the contaminant.
CO2 + H2O > H2CO3 H2CO3 + H2O H– CO3+ (H3O)+ Ka = 6 x 10–7 NaCO3H + H2O H2CO3 + Na+ + (OH)– buffer pH = 9/10 56
I JANUARY 2011 HYDROCARBON PROCESSING
Maria Jose Ortega Castelán is a manager NEUGA SA and has 10 years of experience in project management. She received a degree in industrial engineering and an MBA. Ms. Ortega Castelán is CFA certified.
PLANT SAFETY
Safe detection of small to large gas releases Look at these advantages in using ultrasonic leak detectors E. NARANJO and S. BALIGA, General Monitors, Lake Forest, California; G. A. NEETHLING, Gassonic, Ballerup, Denmark; and C. D. PLUMMER, Safety Consulting and Process Engineering Analysis, Stoke on Trent, United Kingdom
I
t is clear in the oil and gas industry that large combustible gas releases can have catastrophic consequences. To prevent this, fire and gas safety professionals select and analyze a diverse set of representative release scenarios, considering such factors as duration, orientation and type of gas.1 Understanding the hazard potential is a vital step in selecting sensors that are most suited for gas detection. Despite such efforts in the original safety assessment, the capacity of an instrument to detect significant leaks is often inferred from its performance with small ones. As such, the instrument’s behavior under probable release scenarios is not well understood and generally leads to poor equipment selection. Similarly, oil and gas workers may place undue emphasis on selecting detection instruments that reduce personal injury but fail to consider the sensor’s capacity to mitigate the consequences of major incidents.2 Ultrasonic gas leak detectors, non-concentration-based detectors used to detect leaks from high-pressure systems, are found to be suitable for detecting gas releases with mass flow rates ranging from a fraction of a gram per second to over 0.1 kg/s. The detection range scales with a sound pressure level (SPL) produced by these leaks, from a well-known isentropic flow relation that assumes choked flow at the leak source. Simulations with inert gases and a mathematical model suggest ultrasonic gas leak detectors can safeguard personnel and plant assets from significant leaks.
Introduction. Ultrasonic gas leak detection usage has increased for detecting combustible and toxic gases in the oil and gas industry. Rather than relying on the gas reaching the sensor element, ultrasonic gas leak detectors detect a leak through the ultrasound produced by the escaping gas. These sensors have been shown to perform well under harsh environments and their advantages for detecting leaks in open, ventilated areas are well known.3–6 One of the principal advantages of ultrasonic gas leak detectors is that leaks can be simulated, providing a method for system verification that is uncommon among other types of gas sensors. Using an inert gas as a proxy, a technician can produce leaks at a controlled leak rate or through an orifice of known size and shape. Simulation is particularly useful for determining adequate coverage for minor leaks, when the hazard can be prevented from escalating into a more severe incident. Naturally, what constitutes a minor gas leak depends on the application. The Health and Safety
Executive (HSE) Offshore Safety Division, for example, defines such leaks as “a gas release of mass release rate of less than 0.1 kg/s and duration of less than 2 min.” 7,8 Such leaks, if ignited, would not be expected to cause significant escalation or multiple fatalities, but may result in injuries or a fatality in the leak’s vicinity. A second but often overlooked advantage of ultrasonic gas leak detectors is that they lend themselves well for modeling large leaks. Performance in the event of significant or major leaks is difficult to simulate in the field. At rates of 0.1 kg/s or more, gas leaks cannot be sustained but for short bursts; otherwise, the inert gas is quickly consumed. In some instances, the pressure required to produce a large leak can lead the jetting material to become a liquid, rendering it more difficult to gain a full understanding of the potential for ultrasonic noise generation by such leaks. Some simple calculations enable engineers to estimate the detection range or the amount of ultrasound produced by significant leaks if the SPL for minor leaks is known. Such calculations are useful for allocating detectors in open fields where the only hazards of interest are significant leaks. This article looks at formulas that were developed for determining detection coverage when the minimum leak to be detected is large (≥ 0.1 kg/s). The results suggest that the relation between SPLs at different mass flowrates is a good predictor of detector range for significant combustible gas releases, but that they overestimate coverage when the jetting substance is a liquid and gas mixture. SPL values obtained from the logarithm of a direct field term produce values that are much greater than those measured in the laboratory, suggesting a dampening effect on sound by grass, trees and other structures surrounding the sound source during the experiment. Sound pressure level. Ultrasonic gas leak detectors operate on the principle that the escape of gas from a high-pressure pipeline or vessel produces ultrasound. This ultrasound is measured as SPL, which can . be calculated from knowledge of the sound source’s power, Ws , the distance of the sensor to the leak, r, and the ambient room constant, S:9 Ws 4 1 + 10 log SPL = 10 log 12 + (1) 2r 2 S 10
Applying the ideal gas equation, the sound source’s power can be expressed as: HYDROCARBON PROCESSING JANUARY 2011
I 57
PLANT SAFETY RT m (2) W s = M where is an efficiency constant (0 ≤ ≤ 1), R is the gas constant, . M is the molecular weight, T is the absolute temperature, and m is the mass flowrate. Substituting Eq. 2 in Eq. 1 results in: RTm 1 4 (3) SPL = 120 + 10 log +
2 S M 2r Eq. 3 is useful for calculating the SPL of a leak if the mass flowrate for said leak and the SPL and corresponding leak for a second leak are known. Consider a second equation using Eq. 3: RT2 m2 4 1 SPL2 = 120 + 10 log + (3a) M2 2 r22 S
Assuming that the distance to the sound source is constant, and subtracting Eq. 3a from Eq. 3 yields the relation
M T m SPL2 = SPL1 + 10 log 1 2 2 M 2T1 m 1 which can be simplified to:
(4)
m (5) SPL2 = SPL1 + 10 log 2 m1 when the molecular weight and absolute gas temperature for both leaks remain unchanged. Similarly, Eq. 3 can be used to estimate detection coverage, assuming the mass flow rate is constant. In this instance, subtracting Eq. 3 gives: (r r )2 S + 8r 2 1 (6) SPL2 = SPL1 + 10 log 1 2 S + 8r12 Assuming that the direct field term in Eq. 3 at a given location in the room is much larger than the reverberant field term; that is, (10 log (1/2πr 2) >> 10 log (4/S)), Eq. 6 becomes:
FIG. 1
58
Experimental setup for leak simulation.
I JANUARY 2011 HYDROCARBON PROCESSING
r (7) SPL2 SPL1 + 20 log 1 r2 Eq. 5 is a useful tool for calculating the detection radius of ultrasonic gas leak detectors, provided that the SPL for a given mass flowrate is known. In instances when a change in background noise is expected (for example, by the removal of machinery) Eq. 6 or 7 can provide a working estimate of the range (assuming the minimum mass flowrate to be detected remains the same). Experimental procedure. To verify the usefulness of Eqs. 5 and 7 in estimating detection range, SPLs were measured for minor and significant leaks and compared to predicted values. SPL measurements were taken with an ultrasonic gas leak detector mounted on a tripod at approximately 3 m from the ground (Fig. 1). To simulate the gas leaks, a rubber hydraulic hose with a 2-cm inner diameter and 4 m length was used. Both ends of the hose were fitted with high-pressure locks. On one end, an oil-filled pressure gauge was attached. On the other end a ball valve and a nozzle were attached. The nozzles had circular openings with nominal diameters of 1, 2 and 4 mm, as shown in Fig. 2, and were manufactured to specifications. All gases tested were supplied in standard 44H-sized cylinders (service pressure = 3,500 psi) and used as found. Experimental results. Per HSE’s definition, significant gas
releases have the potential to cause an event severe enough to be considered a major “accident” or to be of a size leading to significant escalation within the immediate area or module.7, 8 Fig. 3 shows SPL measurements for significant methane leaks as a function of distance and an SPL curve derived from Eq. 5. The dashed curve in Fig. 3 is a second-order polynomial fit to the predicted values and is presented to guide the eye. The . estimated values for SPL were extrapolated from leak rates of m = 0.01 kg/s. As illustrated in Fig. 3, the predicted values agree, with an average percent difference between measured and predicted values of 2%. Other matches between predicted and experimental results are obtained for inert gases like nitrogen (Fig. 4). Substances that are liquid when pressurized in gas cylinders generate less ultrasonic noise than predicted by Eq. 3. Fig. 5 shows SPL curves for CO2 and ethylene, two gases that are liquids at room temperature under moderate pressure. For both gases, the model overestimates the sound pressure level by an average of 13% at 10 m or more from the sound source. If the SPL at a particular distance from the sound source is known, one can approximate the detection radius provided that
FIG. 2
Stainless-steel nozzles for high-pressure leaks.
PLANT SAFETY the mass flow rate is kept constant. From Eq. 6, the sound pressure level decreases with distance as log (1/r). Fig. 6 illustrates the SPL readings of the ultrasonic gas leak detector for a methane . leak of m = 0.01 kg/s and the corresponding estimate from Eq. 7. The initial SPL was taken as 96 dB at r = 2 m. As evident from the graph, SPL decreases with distance at a much faster rate than predicted by the direct field term alone. Accounting for the value of S could result in a better match to experimental data. Conclusion. With ultrasonic gas leak detection, a relation
between SPL and mass flowrate can be effectively used to estimate detection radii for significant leaks. A similar relation that relies
on the direct field term [10 log (1/2πr 2)] as the dominant factor underestimates the rate of SPL decrease over distance, suggesting that surrounding structures may have a dampening effect on the ultrasound. This may have been particularly the case with the experiments reported in this article, as they were performed outdoors. By fitting the experimental curve in Fig. 4, we find SPL in such experiment decreases at almost twice the predicted rate [37 log (1/r)] vs. [20 log (1/r)]. One important limitation of these equations is that they apply only to gas releases. Gas-liquid mixtures, which may be produced as a result of high pressures, invariably attenuate SPL. As shown above, when CO2 was pressurized above its critical pressure at 120
120 110
110
Extrapolated from 0.01 kg/s using Eq. 5 Measured at 0.1 kg/s
100
100 90 SPL, dB
SPL, dB
90 80 70
80 70
60
60
50
50 40
40 0
5
10 15 Distance from source, m
20
25
Measured and predicted values for methane leaks at 0.1 kg/s. Measurement error = ± 3 dB.
)R FR P ) UD Z DQD SUH 5(( ED O\ V OVW VLV VH RQ J GD ÀOW RW LU HU R VF RP FD
FIG. 3
ZZ
Extrapolated from 0.01 kg/s using Eq. 5 Measured at 0.1 kg/s
0 FIG. 4
5
10 15 Distance from source, m
20
25
Measured and predicted values for nitrogen gas leaks at 0.1 kg/s. Measurement error = ± 3 dB.
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HYDROCARBON PROCESSING JANUARY 2011
I 59
PLANT SAFETY room temperature to achieve a mass flowrate of 0.1 kg/s, the predicted SPL curve was higher than the one produced from experimental readings. Besides the practical value of the equations, the test results demonstrate that ultrasonic gas leak detectors are well suited for detecting significant leaks. During the experiments, the test instrument never produced a false positive nor failed to respond to a gas leak. Further work is needed to understand the scope of application of ultrasonic gas leak detectors to significant or even major incidents. As next steps, we plan to further characterize sensor behavior for combustible gas releases with mass flowrates larger than 0.1 kg/s. This study would throw light on the response for catastrophic incidents, where a potential detonation could lead to structural damage to surrounding areas or multiple fatalities. A topic that also deserves further consideration is sensor response to mixed-phase gas releases. Although the HSE has produced an excellent report on the subject, little work has been carried out on the sound characteristics of high-pressure jets produced by petroleum-gas mixtures.10 Given the broad application to which ultrasonic gas leak detectors have been found suitable so far, these are areas of investigation well worth exploring. HP ACKNOWLEDGEMENTS The authors are indebted to Toke Eng, Mads Kornbech, and Martin Olesen at Gassonic A/S on preparing the article. Special credit also goes to Kamyar Babaielivari for setting up the leak simulation equipment and for his assistance in conducting the experiments.
120 Carbon dioxide and Ethylene, extrapolated from 0.01 kg/s using Eq. 5 Carbon dioxide and Ethylene, measured at 0.1 kg/s
110 100 SPL, dB
90 80
Shankar Baliga is a manager for research and development
50 40 0
FIG. 5
5
10 15 Distance from source, m
20
25
Measured and predicted values for carbon dioxide and ethylene leaks at 0.1 kg/s. Measurement error = ± 3 dB.
Extrapolated from SPL at r = 2 m using Eq. 7 Measured at 0.1 kg/s
110 100
at General Monitors in Lake Forest, California. He is responsible for the development of new optical, acoustic and chemical sensing technologies for gas and flame detection. Recent examples of Dr. Baliga’s research interests include flame detection with neural networks and open path gas detection for ppm levels. He is a senior member of ISA and IEEE and a voting member on the ISA 12.13 committee for combustible gas detection instruments. Dr. Baliga received a PhD in physics from Ohio State University.
Gregory A. Neethling is the technology manager for Gassonic A/S, a General Monitors company. Mr. Neethling has over 10 years experience in ultrasonic gas leak detection, with an electrical engineering background. He started his career at Innova Air Tech Instruments in Copenhagen, Denmark as a research and development engineer. Mr. Neethling’s knowledge of industrial gas detection stems from the development and deployment of ultrasonic gas leak detection devices over the last decade. He has published several papers on fire and gas detection implementation with emphasis on ultrasonic instruments.
120
90 SPL, dB
Edward Naranjo is a product manager for General Monitors. He has been with GMI for six years and contributes to product innovation and new product development, including initiatives on wireless-enabled fire and gas sensing, gas imaging, and ultrasonic gas leak detection. Dr. Naranjo has over 12 years of product development experience in the industrial instrumentation, healthcare and consumer packaged goods industries. He received a BS degree in chemical engineering from Caltech and a PhD in the same discipline from the University of California, Santa Barbara. He also earned an MBA from the University of Chicago. Dr. Naranjo is the chapters’ regional director, western region, of the Product Development and Management Association and a certified new product development professional.
70 60
80 70 60 50 40 0
FIG. 6
60
LITERATURE CITED Health and Safety Executive, Fire and Explosion Strategy, Issue 1, Hazardous Installations Directorate, Offshore Division, 2004. 2 Leistad, G. H. and A. R. Bradley, “Is the focus too low on issues that have a potential to lead to a major incident?” Proceedings of the SPE Offshore Europe Conference and Exhibition, Aberdeen, UK, 2009. 3 Naranjo, E. and S. Baliga, “Expanding the use of ultrasonic gas leak detectors: A review of gas release characteristics for adequate detection, International Gases and Instrumentation, Vol. 3, pp. 24–29, 2009. 4 Naranjo, E. and G. Neethling, “Safety in Diversity: The advantages of technology diversification in gas monitoring safety,” Hydrocarbon Engineering, Vol. 13, pp. 102–108, 2008. 5 Naranjo, E., “Selection and use of ultrasonic gas leak detectors,” Proceedings of the 54th IIS 474 pp. 287–296, Pensacola, Beach, Florida, 2008. 6 Hazardous Installations Directorate Semi-Permanent Circular, Acoustic Leak Detection, SPC/TECH/OSD/05, 2007. 7 Health and Safety Executive Offshore Technology Report 2001/055, OSD hydrocarbon release reduction campaign: Report on the hydrocarbon release incident investigation project – 1/4/2000 to 3/31/2001, HSE Books, Colegate, England, 2001. http://www.hse.gov.uk/research/otohtm/2001/ index.htm. 8 HID Statistics Report HSR 2002 002, Offshore Hydrocarbon Releases Statistics and Analysis, 2002, 2003. http://www.hse.gov.uk/offshore/statistics/ hsr2002/index.htm. 9 Raichel, D. R., The Science and Applications of Acoustics, Second Edition, Springer, New York, 2006. 10 Royle, M., D. Willoughby, E. Brueck and J. Patel, Measurement of Acoustic Spectra from Liquid Leaks, Research Report RR568, HSE Books, Colegate, England, 2007. 1
5
10 15 Distance from source, m
20
25
Measured and predicted values for methane leaks at 0.01 kg/s. Measurement error = ± 3 dB.
I JANUARY 2011 HYDROCARBON PROCESSING
Chris D. Plummer is a retired process safety consultant with Safety Consulting and Process Engineering Analysis in Stoke on Trent, UK. He received an undergraduate degree in chemical engineering from the University College in London. Mr. Plummer’s experience spans over 30 years in health safety and environment (HSE) management, especially the use of safety devices in the oil and gas industry. He was chief HSE engineer at W.S. Atkins and has held a variety of positions in industrial safety and operations. Mr. Plummer is a chartered engineer, certified safety professional and fellow of the Institution of Chemical Engineers.
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PLANT SAFETY
Considerations for blast-resistant electrical equipment centers Guidelines explore protecting critical systems from disaster D. COLE and D. AUSTIN, Lectrus Corp., Chattanooga, Tennessee
I
t is no secret that many of the process technologies within the hydrocarbon processing industry (HPI) carry their own set of challenges and risks. Inherent in the HPI is the continual concern for worker and operations protection in the event of an explosion and fire. The ongoing history of refining is replete with accounts of disasters arising from simple and complex causes. Pipe corrosion was determined to be the prime cause of a May 2009 explosion and fire at the ethylene unit of Sunoco’s Marcus Hook refinery, located in Delaware. Superheated feedstock leaked out of a rusty pipe and ignited. The result was a vapor-cloud explosion (VCE). Even though the refining industry has experienced advances in process and safety technologies, the risk of a blast event can still occur—thus underscoring the need for greater emphasis on worker safety and equipment protection. The design, development and deployment of blast-resistant structures to protect workers, power and process controls has been ongoing within the HPI and chemical manufacturing. In more recent years, the demand for these types of buildings has created a new industry that can provide benefits physically and financially to the HPI and other chemical processing plants.
Background. Although blast-resistant shelters are being used at land-based chemical processing plants, their origins can be traced to applications for externally reinforced, steel intermodal shipping containers in offshore safety applications. Freight containers have been in plentiful supply since their inception, and their structural strength makes them natural candidates for personnel protection from low-level blasts. Converted containers are resistant to blast loads in the 1 psi to 2 psi range. However, much higher loads are experienced during refinery blast events; given the distance and other variables affecting the force of a VCE, stronger structures are necessary. This imperative led to the design and fabrication of the first, custom-designed blast-resistant modules (BRMs), and the industry has been evolving ever since. The industry response to ensuring personnel and plant safety reached a high degree of intensity after March 23, 2005. On that day, a series of explosions ripped through BP’s Texas City, Texas, refinery during the restarting of process equipment at the refinery’s isomerization unit, killing 15 workers and injuring 180 others (Fig. 2). A tremendous loss of manpower and equipment damage resulted from the accident; the unit did not come back online for another two years. Since this incident, demand has increased significantly for blast-resistant, steel-fabricated buildings to provide more protec-
tion at HPI facilities. Industry guidelines have been established to facilitate the design, construction and optimal location of BRMs for personnel protection, as well as blast-resistant electrical equipment centers (BRECs) to protect critical electrical process functions of the facilities (Fig. 1). Addressing safety concerns at HPI and other hazardous manufacturing facilities began largely in the 1990s, resulting in publication of the Occupational Safety & Health Administration’s (OSHA) Process Safety Management (PSM) standards. In response to the OSHA publication, a joint effort was initiated by the American Petroleum Institute (API) and the Chemical Manufacturers Association to establish a set of guidelines directly addressing OSHA’s concerns in the PSM standards. This response is contained in API Recommended Practice 752, Management of Hazards Associated with Location of Process Plant Buildings. Government, industry and market response. Follow-
ing the conclusions reached in the wake of events at Texas City, OSHA initiated a series of National Emphasis Program Audits at US refineries, during which OSHA inspectors began issuing citations to companies for failure to adequately protect essential or critical equipment at their facilities. This has added momentum to an already growing movement on the part of HPI firms to provide strong, ductile, affordable protective shelters. Advances in
FIG. 1
Blast-resistant electrical equipment center loaded for shipment at off-site manufacturing plant. HYDROCARBON PROCESSING JANUARY 2011
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PLANT SAFETY the design, testing and manufacture of such structures has served to further ensure market viability for them.
process-related automatic shutoff valves and other critical power equipment, as well as water pumps for fire protection.
Protecting personnel vs. equipment. The primary function of blast-resistant shelters has been to protect personnel at facilities where at risk for accidental explosions exists. At the same time, risk managers, engineers and company owners also realize that the risk of exposure to overpressure or blast wave extends to critical and essential power and control systems of their facilities as well. Outside of protecting personnel during a blast event, nothing is more critical than sustaining the proper function of
Personnel protection. The manufacturing industry for BRMs offers a wide range of sizes and blast ratings, conforming to International Building Code (IBC) design and construction practices. BRMs are most often used as a substitute for unrated construction trailers but may be configured into multiple sections. Multi-sectional systems may be large single-story buildings or stacked to create a multistory configuration. Examples include offices, cafeterias and even sleeping quarters.
FIG. 2
Aftermath of the BP Texas City March 2005 blast.
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FIG. 3
Side view of a blast-resistant electrical equipment center.
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PLANT SAFETY Protecting equipment. As mentioned earlier, the IBC defines essential facilities as those whose processes must remain in operation or return to operation with minimal interruption during or after a catastrophic event. Essential equipment is defined as equipment used in the power and control systems that must remain online during an event to maintain the minimum necessary process functionality at the site. Critical equipment is that which is used in those systems and must be returned to functional status in minimal time, with minimal cost and effort. While massive attention and effort have been given to provide blast-resistant shelters for personnel protection in areas with potential for overpressure at HPI facilities, a commensurate effort is being directed at protecting critical and essential power and control systems (Fig. 3). Concerning such processes and the associated critical equipment, OSHA’s PSM standard specifically lists equipment that the employer deems critical to process safety, “…because of its potential for significant impact on the safety of a process involving highly hazardous chemicals if it did not maintain its mechanical integrity.” The standard goes on to name equipment types including, but not limited to: • Relief and vent systems and devices • Pumps • Emergency shutdown systems • Controls (including monitoring devices and sensors, alarms and interlocks). The logical and most effective solution for protecting critical processes and associated equipment is a BREC rated to handle pressures of the type experienced at Texas City in 2005. Current building standards. Blast-resistant buildings are
not currently defined by a governing industry standard. Therefore, engineering analyses and testing are used to certify individual components and system designs. This responsibility falls primarily
on the shoulders of engineers, designers and manufacturing firms that produce blast-resistant modules. Since the purpose of BRMs is to protect people, they must meet architectural and life-safety codes. However, these requirements do not extend to equipment centers. Typically the size of an office trailer, a BRM may be installed in a multitude of varying configurations (including multilevel) and floor plans. The buildings may be similar in design and construction to their first-generation cousins, steel shipping containers, but modern BRMs are larger, considerably stronger and specially designed for placement in hazardous areas. Most of the standard features of shipping containers, i.e., all-welded steel construction, crimped plate walls, steel-tube framing and reinforced plate roofs, also apply to blast-resistant equipment shelters. Modern BRMs are constructed with specially designed, heavy framed doors, windows and HVAC. Any external system or accessory must be designed and constructed to withstand the forces of the rated blast pressures. Most of these construction features are also attributable to BRECs. The BRM exterior will respond during an overpressure event by deflecting, whereby some structural components may permanently deform. At the same time, the walls and roof are designed to remain intact, absorb the blast forces and protect the occupants. Functional differences between BRMs and BRECs.
Whereas BRMs have the option of being installed as either permanent or temporary structures, BRECs are sited within refineries as permanent structures. The most desirable location for an electrical equipment center at a refinery is as close to the processing operation and maintenance personnel as possible. The owner has far more flexibility in siting BRECs than is available for siting BRMs. Siting decisions are based upon economics when the incident risk is immediate, and the costs of additional cabling and other delays from increased standoff distances are high.
TABLE 1. Functional differences between personnel and equipment shelters Design consideration
Personnel
Equipment
Protection
People
Equipment
Allowable response
Walls and roof may deform but must not generate heavy internal debris. Allowable deformations typically follow ASCE guidance
Walls and roof may deform but must not impact equipment. Connections must have adequate protection to withstand relative movement. Some equipment may also be shock sensitive, requiring flexible mountings.
Construction
Seam welded crimp plate, wood framing and sheetrock
All steel SWCP or interlocking panel. Typically no interior “finish out” is required
Access
IBC/ADA
OSHA
Foundation type
Slab-on-grade
Elevated
Doors
Opened frequently
Open infrequently for equipment check
TABLE 2. Design specifications for various BREC construction types Construction type Product design feature Description Panel width, mm Panel connection type Exterior wall/roof thickness, mm
Type I
Type II
Type III
Medium-gage G90 steel; interlocking panels
Heavy-gage G90 steel; interlocking panels
Seal-welded crimped heavy steel plate
400
300
n/a
Interlocking
Interlocking
Continuously welded
75
100
100
Wall deflection space, mm
0–140
38–100
64–178
Total wall thickness, mm
75–270
100–280
100–355 HYDROCARBON PROCESSING JANUARY 2011
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PLANT SAFETY Typical types I, II and III structure construction.
Unlike commercial-grade, pre-engineered metal buildings, today’s BRECs use heavy structural members and either crimped plate or interlocking heavy-gauge wall panels. Base members consist of C-channels, wide-flange structural beams, and wall panels are supported with tube steel. Up to 12 mm- (1/2-in.) thick metal plate is continuously welded to the base to form the floor. Floor cutouts are made for all electrical equipment located within the shelter. Wall and roof construction details depend upon the maximum blast loadings. Table 1 shows the functional differences between blast-resistant modules used for personnel vs. equipment protection. Table 2 lists the design specifications for various BREC construction types. It is also notable that the older, 14x40-foot size limitation for BRECs is no longer a factor, since any of the three unit types can be constructed with custom dimensions and loadings in mind. HP BIBLIOGRAPHY Chase, R., Associated Press, “Pipe corrosion led to Delaware refinery explosion,” Sept. 8, 2009. Cole, D., R. H. Bennett and D. Austin, “Protecting Essential Refining Operations Using Blast-Resistant Electrical Equipment Shelters,” IEEEPCIC-AN-22, 2008. Design of Blast Resistant Buildings in Petrochemical Facilities, American Society of Civil Engineers, Task Committee on Blast Resistant Design, New York, New York, 1997. Fatal Accident Investigation Report: Isomerization Unit Explosion—Final Report, Texas City, Texas, incident date: March 23, 2005, report date: Dec. 9, 2005. Gehring, G. and P. Summers, “Constructing and designing blast-resistant buildings,” Hydrocarbon Processing, November 2005, pp. 55–61. International Building Code, Section 1602, Washington, DC, 2006.
Management of Hazards Associated with Location of Process Plant Portable Buildings, API RP 753, First Edition, American Petroleum Institute, Washington, DC, June 2007. Petroleum Refinery Process Safety Management National Emphasis Program, CPL 03-00-004, US Department of Labor, Occupational Safety and Health Standards, Washington, DC, 2007. Process Safety Management of Highly Hazardous Chemicals, 29 CFR 1910.119, US Department of Labor, Occupational Safety and Health Standards, Washington, DC, Subpart H, 1992. Samara, M., ASCE Abstract, Nonstructural Considerations in Design of BlastResistant Buildings, Vol. 3, Issue 4, November 1998, pp. 172–175.
David Cole is the vice president of corporate engineering for Lectrus Corp. His current responsibilities include product design, research and development, and code compliance for the company’s complete line of custom, walk-in metal electrical equipment enclosures. Mr. Cole also represents Lectrus on various technical and industry associations, including IEEE. He graduated from North Carolina State University with a BS degree in mechanical engineering in 1985, and from University of Phoenix with an MBA in 1995. He has had a diverse career in medical R&D, computerperipheral manufacturing, and electrical control and enclosure design.
Deron Austin is the vice president of marketing for Lectrus Corp. Mr. Austin has over 20 years of experience in sales and marketing of engineered products and is a licensed professional engineer in the State of Tennessee. Prior to joining Lectrus in June 2008, he was employed by Propex, where he helped increase the global demand for the company’s civil engineering products. As vice president of marketing for Lectrus, he is responsible for the company’s strategic marketing initiatives, marketing communications tactics lead development, branding and new market, channel, product and service commercialization efforts. He is a member of the Institute of Electrical and Electronics Engineers, and holds a BS degree in civil engineering from Bucknell University.
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I JANUARY 2011 HYDROCARBON PROCESSING
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PROCESS INSIGHT Selecting the Best Solvent for Gas Treating Selecting the best amine/solvent for gas treating is not a trivial task. There are a number of amines available to remove contaminants such as CO2, H2S and organic sulfur compounds from sour gas streams. The most commonly used amines are methanolamine (MEA), diethanolamine (DEA), and methyldiethanolamine (MDEA). Other amines include diglycolamine® (DGA), diisopropanolamine (DIPA), and triethanolamine (TEA). Mixtures of amines can also be used to customize or optimize the acid gas recovery. Temperature, pressure, sour gas composition, and purity requirements for the treated gas must all be considered when choosing the most appropriate amine for a given application.
Tertiary Amines A tertiary amine such as MDEA is often used to selectively remove H2S, especially for cases with a high CO2 to H2S ratio in the sour gas. One benefit of selective absorption of H2S is a Claus feed rich in H2S. MDEA can remove H2S to 4 ppm while maintaining 2% or less CO2 in the treated gas using relatively less energy for regeneration than that for DEA. Higher weight percent amine and less CO2 absorbed results in lower circulation rates as well. Typical solution strengths are 40-50 weight % with a maximum rich loading of 0.55 mole/mole. Because MDEA is not prone to degradation, corrosion is low and a reclaimer is unnecessary. Operating pressure can range from atmospheric, typical of tail gas treating units, to over 1,000 psia.
Mixed Solvents In certain situations, the solvent can be “customized” to optimize the sweetening process. For example, adding a primary or secondary amine to MDEA can increase the rate of CO2 absorption without compromising the advantages of MDEA. Another less obvious application is adding MDEA to an existing DEA unit to increase the effective weight % amine to absorb more acid gas without increasing circulation rate or reboiler duty. Many plants utilize a mixture of amine with physical solvents. SULFINOL® is a licensed product from Shell Oil Products that combines an amine with a physical solvent. Advantages of this solvent are increased mercaptan pickup, lower regeneration energy, and selectivity to H2S.
Primary Amines The primary amine MEA removes both CO2 and H2S from sour gas and is effective at low pressure. Depending on the conditions, MEA can remove H2S to less than 4 ppmv while removing CO2 to less than 100 ppmv. MEA systems generally require a reclaimer to remove degraded products from circulation. Typical solution strength ranges from 10 to 20 weight % with a maximum rich loading of 0.35 mole acid gas/mole MEA. DGA® is another primary amine that removes CO2, H2S, COS, and mercaptans. Typical solution strengths are 50-60 weight %, which result in lower circulation rates and less energy required for stripping as compared with MEA. DGA also requires reclaiming to remove the degradation products.
Secondary Amines The secondary amine DEA removes both CO2 and H2S but generally requires higher pressure than MEA to meet overhead specifications. Because DEA is a weaker amine than MEA, it requires less energy for stripping. Typical solution strength ranges from 25 to 35 weight % with a maximum rich loading of 0.35 mole/mole. DIPA is a secondary amine that exhibits some selectivity for H2S although it is not as pronounced as for tertiary amines. DIPA also removes COS. Solutions are low in corrosion and require relatively low energy for regeneration. The most common applications for DIPA are in the ADIP® and SULFINOL® processes.
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ENVIRONMENT
What are the strategies for sustainable chemical production? New environmental challenges require a new way of thinking by the hydrocarbon processing industry M. P. SUKUMARAN NAIR, Special Secretary to Government of Kerala, and Chairman, Chemical Engineering Division Board of the Institution of Engineers, India
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lobally speaking, there is an exalted awareness of environmental degradation caused by industrial activities including the hydrocarbon processing industry (HPI). Scientists and environmental groups are linking industrial activity as the potential source for greenhouse gas (GHG) emissions, stratospheric ozone depletion, acid rain and acidification, eutrophication, soil degradation, technological hazards, chemical mists and fog. Some climate experts and other scientists believe that these conditions may pose potential damage to human beings. Indeed, this potential effect is the topic of many discussions at both national and international forums. Environmental considerations assume significant importance in chemical and petrochemical processing, which contribute effluents and emissions capable of degrading the environment. Accordingly, HPI operators are challenged. They must solve how to increase manufacturing of high-demand goods and services, and to maintain the profitability of their parent organizations while effectively tackling consequential environmental issues to the environment and general public. Effective environmental management assumes paramount importance in addressing the numerous issues over pollution and emissions control, while simultaneously maintaining safety and sustainability of the industry. Clean initiatives in the HPI are a major development.
Challenges for industry. The growth
of the HPI has been guided mostly by the necessity to increase production at lower costs, and it has contributed in some degree to degradation of water resources, soil and air around the processing plants. Worldwide, the focus of pollution control
has shifted from end-of-pipe treatment to source reduction, thus lowering emission generation and applying clean technology and sustainable development. It has become imperative that environmental considerations will play a substantive role in the future development of the HPI, especially at a time when more industrial activities are expanding in developing countries. In recent years, several studies in different parts of the world focused on this issue. Key objectives of the studies are to identify issues in environmental protection within different industrial processes; to assess the extent that national and international guidelines regarding pollution control and environmental management can and are being implemented; to understand the problems encountered in environmental management; and to explore the reasons for noncompliance. Suggestions were also made on the basis of the listed studies to develop guidelines for environmental policy and to adopt cleaner technologies that will foster industrial development with least degradation impact on the environment. Environmental management. At present, most HPI processing units in developed or developing countries have specific environmental policies over site emissions, effluents and waste disposal; these operations are guided by rules and programs set by regulatory authorities. New plants under development include modern technologies that were part of the design inception stage; pollution prevention is a part of the design process and is not an afterthought for modern HPI facilities. Older process units are now operated with add-on state-of-the-art pollution-control equipment and technologies.
Environmental control departments attached to the plants usually exhibit meticulous care to see that the company’s environmental goals and agendas are achieved. Thus, effective emission control facilities exist in most HPI facilities, and they are operated with due diligence. The stipulations of pollution-control and environmental protection agencies are also within the achievable limits of the available technology. Excursions, at times, still occur—often during abnormal operating events such as startup, shutdown or during accidental situations. Several national and the international standards covering a wide range of parameters have been developed to specify the emissions and effluents from the HPI. These include pH, ammoniacal nitrogen, nitrates, fluorides, phosphates, total suspended solids (TSSs), oils and fats, and chemical and biological oxygen demands in the effluent streams, particulate matter, nitrogen oxides (NOx), sulfur oxides and carbon monoxide (CO) in exhaust streams. Radioactivity, toxicity, presence of heavy metals, organics, biological pollutants, pathogens, etc., are also monitored in specific cases. Clean technologies. Current devel-
opments in environmental chemistry and chemical engineering have helped plant operators reduce effluent generation at the source and thus eliminate treatment and disposal of waste and byproducts. Very often, treatment from industrial operations is linked to the processing technologies adopted in the plants. Over the years, the specific consumption of raw material and energy for manufactured products has registered a continuously declining trend accomplished with the adoption of efficient technologies and best operating HYDROCARBON PROCESSING JANUARY 2011
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ENVIRONMENT practices at the plant level. This invariably contributes to achieving better environmental standards through reduced emissions, effluents and solid waste per ton of product manufactured. Further improvements toward better environmental quality may require major design changes involving additional investment or going for a newly proven and commercialized process. This is a costly option and efforts in this direction are limited unless they bring economic incentives
such as increased productivity, lower energy consumption, etc. In the case of products having high-water intensity, there is an economic benefit in reusing treated effluents to conserve water. The startup and shutdown of plants are situations that can potentially increase emissions generation as compared to normal operations. Most plants are equipped with specific provisions to control such situations. Most pollution-prevention methods implemented in the HPI follow prescrip-
tive approaches that adhere to standardized procedures built around questionnaires and checklists. The new approach is to adopt a more descriptive approach in which process operators are challenged to attack pollution problems and devise new and innovative ways for solving them. New management approaches are undertaking substantial efforts to develop “green belts” and maintaining greenery around process plants to reduce the impact of GHGs. This is an important step in the direction of sustainable environmental control. ISO programs for the environment. Establishment of ISO 14000
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Environment Management Systems and a corporate environmental agenda for regular monitoring and control is another major step in environmental protection. These systems are intended for continuous improvement of existing operations from the environmental angle. Certain industries have adopted a zero-effluent approach incorporating total recycle and reuse of effluents back to process. Zero effluents still remains more of a concept than its effective implementation to a reasonable degree of reliability. European process plant operators use the best available techniques (BATs) in their plants for environmental control. Both effluent specific standards and product specific standards are available. In India and in many other developing countries, systems are applied for controlling and reducing pollution from plants with in the limits set by the statutory authorities, i.e., the Pollution Control Boards (PCB). Some operating units do not put in further efforts to reduce the pollution effects beyond the limits prescribed by the PCBs. This is primarily due to the lack of incentives to encourage additional investment toward improved technology aiding better environmental quality. Most HPI operations emit large quantities of carbon dioxide (CO2), which is a major GHG to the atmosphere. There are no emission standards for CO2 as prescribed by the statutory bodies. Attempts to reduce GHG emissions globally to tackle climate change may bring in specific limits for CO2 emissions or calls for effective measures for sequestration in future. Every processing unit imposes certain environmental burdens to the local environment, and its impact categories are acidity, global warming, human health effects, ozone depletion, photochemical smog, aquatic oxygen demand and eco-toxicity to aquatic life, etc. A parametric assess-
ENVIRONMENT ment of the contribution of each of these components can be used to compare yearly performances of plants. The necessity of maintaining a safe work environment for employees and the neighboring community is well recognized. For this purpose, extensive hazard and risk analysis using techniques such as hazard operability (HAZOP) studies and quantitative risk assessment (QRA) are conducted based on which safe systems, work practices and risk-reduction measure are now adopted. The environment management plans (EMPs) of the production units are capable of mitigating risk from most expected crisis situations barring those from nightmare incidents such as earthquakes, sabotage, etc. Public information. Information to the public regarding the environmental consequences of these plants is very important. The communities associated with these units have a right to know the environmental risk that they are subjected to. In most countries, it is now mandatory that an environment impact assessment (EIA) be done prior to implementation of a project having large-scale environmental consequences. A proper EMP is also to be in place before the unit startup. Environmental challenges. Climate change across the world, depletion of ozone layer in the outer atmosphere, loss of biodiversity elements such as migratory species and important genetic resources; widespread degradation of land, urban air, forests and natural waters and marine ecosystems; and accumulation of persistent organic pollutants in nature are major global environmental concerns. These issues have an impact that transcendent national boundaries and require global solutions. We have over 200 international legislations governing environmental issues and together with currently available technology and adopting best practices mitigation for further degradation are possible. India, for example, has adopted a national action plan for climate change and has framed a comprehensive auto fuel policy that consider among other things, availability and security of supplies, vehicle technology, cost-effective emission reduction, fiscal measures and institutional means to bring about progressive improvements by reducing vehicular emissions on ambient air. The fuel cell as a power source is becoming a viable alternative to internal combustion engines with least environmental impacts. Thus, concerted efforts
are required both at the national and international levels to stop further degradation and reverse trends. Stress on environmental health.
National environmental policies should foster efforts for sustaining environmental health of the public and to call for a discrete assessment of pollutants entering the natural environment from human interventions in terms of their toxicity, persistence, mobility, bioaccumulation and methods available for source reduction and control mechanisms. Shift toward alternatives. More industries are switching over to environment-friendly raw materials and energy resources to improve sustainability. Several examples are available: • Use natural gas, predominantly methane (CH4), as a relatively benign raw material and energy source than other petroleum feedstocks including naphtha, fuel oil and coal to produce ammonia, which is the basic building block of the nitrogenous fertilizer industry. Natural gas as feedstock would reduce pollution generation. This route would offer lower CO2 emissions, reduce waste generation and decrease energy intensity for the final product. • Replace organic solvents with water. Replacing volatile organic compounds (VOCs) as reaction medium in organic synthesis is another important innovation. Using ethylene dichloride (EDC) for extraction of food items has been replaced by n-hexane. • Manufacturing sulfuric acid from pyrite roasting has a lesser impact than using elemental sulfur. Recycling of metals, recovery of metals from spent catalysts, sludge from metallurgical operations, etc., could reduce the impact of large-scale mining of metals and minerals. • Begasse from sugar industry is used as a raw material for paper industry in place of wood pulp. Treated softwood, coir and bamboo composites are extensively used in place of hardwood for furniture. Several oxidation reactions involving air are being replaced with gaseous oxygen to mitigate toxic NOx generation. Application of next-generation polymers and plastics in place of metal in highly corrosive applications, are intended to reduce the environmental burden arising out of products manufactured and lead to sustainability. • Construction industry is being increasingly encouraged to use locally available materials to replace steel, glass, wood and cement.
• Replace fossil fuels with hydrogen in engines is in an advanced research stage. Once it becomes technically and economically feasible, fuel cells can offer an environment friendly option for transportation. • Natural zeolites are finding extensive applications in place of alkyl benzene sulfonates (ABSs) as detergents. • Power generation using vacuum residue from crude refining operations is a sustainable option to dispose of the unmarketable end products. These bottoms, after improved crude utilization processes such as hydrocracking, are highly viscous, heavy and difficult to handle and, as such, are not marketable. The quantity of residue from refineries varies from 20% to 40% of the throughput depending on the crude characteristics and secondary process applied. Refiners are seeking alternative residue utilization strategies to produce lighter highvalue products and to increase competitive positions in a market where light-oil product(s) demand is steadily increasing. • Biofuels are being used in the automotive industry. Ethanol and biodiesel have emerged as reasonable alternatives to the conventional petroleum fuels. These are based on agricultural feedstocks and they can be easily blended with hydrocarbon fuels unto 50% blends and can be used in existing vehicles without any modifications. Biofuels are renewable resources that are nontoxic, and biodegradable. They have reduced inflammability, and their performance is also superior. Ethanol-blended gasoline has become a commonplace fuel in many countries. Ethanol, largely available as a byproduct of the sugar industry, is nontoxic and is considered environment friendly, causing no harm to soil, water bodies and public health. Being an oxygenated fuel, ethanol enhances the combustion of gasoline and effectively lowers emission rates from engines. • Natural fibers, such as coir, jute, etc., lessen the burden on the environment through product substitution for similar applications such as nylon, polyester, polyethylene, etc. Coir geotextiles find extensive application in preventing soil erosion and landslides. • Biotechnology (BT) products can reduce the intensity of normal cropping in terms of input, such as fertilizer and water, and they have better resistance to adversities to pest infection, and crop losses while increasing productivity. Several BT products help to reduce environmental footprints. • Recycling of paper and replacing plastic with natural polymers can provide greener options. At present, 150 million tons HYDROCARBON PROCESSING JANUARY 2011
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ENVIRONMENT Addressing challenges: National environmental policy
The important problems encountered in environmental management in the HPI are the lack of: 1. Incentives for continuous improvement in the direction of pollution reduction beyond the compliance limits of the PCBs 2. Integration of environmental concerns into the core of the business strategy. 3. Sufficient transparency with regard to environmental information To effectively address the listed problems and foster development of an apexlevel environmental policy, incorporating clean-development strategies with these elements will be required: 1. Role of top management. The first and foremost guiding principle of an environmental policy facilitating industry growth is to ensure the unstinted commitment, involvement and actionoriented approach by top management of the organization in achieving the set environmental goals. 2. Environmental policy statement. Top management should codify its environmental commitment, values and perceptions in a documented policy. This policy should be relevant to organization activities, product and services, and taking into account its implications on the different stakeholders. Attempts for improving energy efficiency, resource productivity of plastics are produced a year from fossil fuels globally. Plastic products have gained universal usage not only in food, clothing and shelter, but also in transportation, construction, medical, entertainment, etc. There is a growing demand for biodegradable plastics as a solution to global environmental and waste management problems. Research on biodegradable plastics and polymers has been carried out worldwide with the aim of achieving a balance between human activities and the natural environments. Ideal biodegradable plastics are defined as materials that are completely degraded to CO2 and water (H2O) by the action of microorganisms. Resources of biodegradable plastics and polymers are mainly classified into biosynthetic polymers such as poly hydroxyalkanoic acid, plant polysaccharides such as cellulose, starch, and xanthan, and chemical synthetic polymers such as polylactic acid, poly -caprolactone and polyaspartic acid. Biodegradable plastics are expected to 72
I JANUARY 2011 HYDROCARBON PROCESSING
and use of renewable energy sources and raw materials need special mention within the policy. 3. Environment, health, safety (EHS) vision statement. Every unit shall have an EHS vision statement. The statements will depend on the nature and scale of organization’s operation and will specifying its current thinking and aspirations for the future. These vision statements should adopt a national pollution-prevention policy that encourages source reduction and environmentally sound recycling as a first option. Also, the statements recognize safe treatment, storage and disposal practices as important components of the overall environment protection strategy. 4. Environmental targets. The environmental targets, i.e., the qualitative and quantitative changes attainable to more environment friendliness in the industry and acceptance to the community, must be clearly defined. Steps that are envisaged for minimizing environmental impacts, reducing emissions of toxic gases and those causing global warming and improving employee health, safety and pollution prevention must be specified. The target must also address achieving zero accidents at workplaces, reducing incidents of work-related diseases, and replace plastics derived from petroleum products in natural environment such as agricultural and fisheries, civil engineering and construction materials, toys where recovery and reuse are difficult, composting of organic waste is effective such as food packaging, hygienic products on account of its specific features, such as slow release, water retention, medical use, low oxygen permeability and low melting temperatures. Green manufacturing. Green manufacturing (GM) aims to prevent pollution and save material and energy through innovation and development of new knowledge that reduces or eliminates environmental damages right from the design, manufacture and application of products or processes. Apart from using benign materials, changing process technologies also adds to the environment friendliness of manufacturing industries. Existing processes are also undergoing tremendous changes to become environmentally friendly. Thus,
reducing risk exposure to the employees as well as to the surrounding community. It focuses on achieving sustainable development and eco-efficiency as a new business perspective through production and innovation integrated environmental protection, responsible product stewardship and total quality improvements. It is desirable that the environmental friendliness of the HPI industry should be through implementing a guided approach achieved and action plan. For this purpose, existing environmental burden imposed must be quantified by considering suitable indices for every environmental aspect. 5. Control strategies. This policy shall provide for the use of legal, financial and social instruments, which influence the behavior of companies, citizens, public bodies and authorities for achieving the objectives. Existing and innovative control mechanisms, such as statutory provisions and stipulations of the various regulatory bodies may be used. Industry may be asked to apply current BATs for pollution abatement. During the interim phase, strategy of monitoring in comparison with set standards and penal action, wherever required, should continue. HPI plants should be operated to standards that will comply with the requirements of appropriate national and international GM requires rethinking of the manufacturing systems by pursuing environmentally related goals and objectives, nontraditional manufacturing processes, new marketing strategies and product design based on a life-cycle approach. Improved catalysts increase conversion and yields, reduce recirculation and increase outputs. The best illustration is the development of ruthenium catalyst in place of conventional iron catalyst for the ammonia reaction. It helped improve conversion threefold, reduce size of plant equipment and rendered higher plant capacities viable. In-situ generation and consumption of hazardous and toxic intermediates and thus avoiding storage and transport, is another option. An example is the manufacture of methyl iso-cyanate and its immediate conversion to pesticides without going for storages; a lesson we have learned form Bhopal. Other sustainable improvements in reaction engineering include carbonylation
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ENVIRONMENT Addressing challenges: National environmental policy (cont.)
legislation and codes of practice. The government shall formulate country specific BATs to facilitate continuous improvement in environmental management. Technically and economically feasible regulatory measures, as well as nonregulatory measures are also suggested to improve environmental management in chemical processing operations. Fiscal incentives may be provided to encourage early adoption of technologies that reduce pollution. 6. Risk management. It is necessary that management will ensure that potential health, safety and environmental risks associated with the activities are assessed early to minimize and manage adverse effects and to identify opportunities for improvement. A workable Disaster Preparedness and Emergency Management Plan (DPEMP) should be kept ready to mitigate any such situations in the unlikely event of its occurrence. 7. Staff training. Necessary and stateof-the-art training may be given to the concerned people responsible for environmental management. This should include keeping them abreast of the new developments, technologies and practical tools, accident investigations, environmental impact predictions, selecting appropriate protective equipment, implementing emergency response plans as and when using dimethyl carbonate instead of phosgene or CO; using solid catalysts to minimize waste; manufacturing petrochemicals from renewable sources; produce alpha olefins from fatty acids rather than petroleum products; avoiding the use of toxic acids, catalysts and solvents in all applications; and going for photo-catalyzed reactions using natural dyes as catalysts instead of heavy metals, etc. Use of low analysis fertilizers with nutrient content sufficient only to meet the demand of the plants during the cropping season minimizes leaching to the environment. Develop membrane cell process for caustic soda in place of mercury cells. This has helped the industry to ward off mercury contamination, and the byproduct hydrogen can be used for food-grade applications. Membrane processes and pressure swing adsorption have come of age for physical separation of gases in place of chemical absorption and regeneration. 74
I JANUARY 2011 HYDROCARBON PROCESSING
necessary, and so on. They may be trained to learn from previous incidents and similar experiences. They must be made conversant in the corporate environmental management systems and the proposed action plans for its implementation. In short, necessary capabilities must be available in-house with all organizations to tackle probable emergency situations that are likely to arise. 8. Monitoring. The policy should call for regular and meticulous environmental performance monitoring to keep track of the environmental burden imposed by the company and watch the direction of its progressing trends. Quantitative, as well as qualitative approaches, may be used for this purpose. Emissions, waste streams, hazardous waste, disturbance, resource depletion, etc., should be addressed accordingly. Commitments towards targets for Responsible Care and social responsibility may also have to be assessed. Present operations should regularly and systematically assess the purpose for identifying and correcting any element that may put human beings, real property or the natural environment at risk of nuisance or damage and of establishing a basis of safety-related improvements of processes and products. Any new process and product, as well as any new infor-
mation of existing processes and products, should be thoroughly analyzed with regard of HES implications. Concerned authorities must be kept well informed of the operations and of HES implications. Any incident entailing a risk of environmental disturbances or of conflict with existing regulations should be promptly reported to proper authorities. 9. Public information. Necessary provision must be for sharing information on HES with the public and incorporated in the policy. The “community right to know” acts or the “right to information” acts in several states are intended for this. The policy should provide for involvement of the community and working with active environmental groups in the region in bettering the environmental situation and thereby enhancing public perception of the industry. 10. Annual reports. The policy shall call for Annual Environmental Status Reports (AESR), along with the financial performance reports. Such reports are now available from many HPI operators around the world. The feedback on these reports from concerned stakeholders may be used for continued improvement of existing systems. The policy document shall be integrated with the national environmental plan of the country.
The harshness of chemical reaction as depicted by elevated temperature, increased concentration, high pressures, large reactor volumes, corrosion tendencies, flammability characteristics, etc., are being considerably reduced through technological innovation. Today, several reactions are being carried out under lower temperatures, pressure and concentration with improved catalytic efficiencies. The best example is again from the fertilizer industry where ammonia used to be synthesized at 350 atmospheres pressure two decades ago, has been lowered down to operate at as low as 80 atmospheres. The potential for recycling and reusing within are being exploited considerably, and modern plants are built with such integrated facilities. Promote integrated complexes. Refineries, fertilizer, power and petrochemicals sites are themselves major investment and high-technology decisions, and, very often, these units are managed by different agencies and function as independent compa-
nies. Technology brings in a lot of scope for exploiting the synergy within these units and could play a major role in improving the bottom line of these units. Integration of refineries, fertilizer and petrochemical plants and power generation units at the planning phase will help to drastically reduce emissions and other pollutants; thus ensuring optimized operation. Review existing control limits for pollutants. Present standards regarding effluent discharges from industrial units are technological limits attainable through application of available technologies for abatement and control available at the time the limits were mandated. These norms are not based on long-term health effects. Revised standards based on health impacts of each listed pollutant may be developed incorporating the advancements in control and detection technologies. While doing so, care is needed so that the prescribed limits are technologically achievable and are within the means and reach of the HPI.
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ENVIRONMENT In HPI plants, normally systems are used to control and reduce emissions and discharges within the limits set by regulatory authorities. The units do not put in further efforts for reducing the pollution effects beyond prescribed limits by the PCB in the interest of public health. This is primarily due to a lack of incentives encouraging additional investment toward improved technology. HPI operators should be encouraged to go beyond compliance and become more environmentlly friendly. Harness environmental biotechnology. Environmental biotechnology uses living organisms—flora and fauna-engineered—to exhibit specific traits to identify, control or prevent pollution. This technology has been applied to cleaning up hazardous waste sites more efficiently than conventional methods, thereby reducing the need for incineration or extractionbased methodologies. Bioremediation has been applied to the cleanup of many different pollutants, including heavy metals, persistent organic pollutants, explosives, sewage and industrial waste. Because of the prevalence of tropical climate, biological processes for pollution control have an edge over chemical processes and are more
efficient. Modern developments, such as recombinant and genetically engineered organisms, find extensive application in biological processes for pollution control and bioremediation. Reduce GHG emissions. Encouragement through adequate financial incentives should be made available to those companies intending for voluntary reduction of GHGs and other climate-change promoters. The extension of natural gas pipelines, harnessing clean-coal technologies, gasification of biomass and development of hydel and nuclear sources for power generation should be encouraged. Reduce water intensity. The HPI is a highly water-intensive industry. The availability of good quality water for the community and industry will become a major problem in coming years. To address the availability of adequate water for industries, recycling and reusing process water is a potential option to pursue. Recycling and water reuse program can benefit through advanced membrane technologies, which have come of age and are now cost-effective options. Develop pollution inventory database. The policy should strive to develop a national level pollution inventory data-
base. It could ensure that pollutant levels are reduced over time during the development process. Changing role of the regulator. Environmental regulatory authorities in developing countries must be encouraged to become solution providers to the industry rather than being mere policing agents. Disposal of hazardous waste. Management of hazardous waste materials is a major concern for HPI plant operators from the environmental angle. Hazardous waste can be solid, semi-solid or nonaqueous liquids. Because of its quantity, concentration or characteristics in terms of physical, chemical, infectious quality capable of significantly contributes to an increase in mortality or an irreversible damage. Left uncared or improperly treated, stored, transported and disposed wastes, they are capable of posing a potential hazard to human health and the neighboring environment. A waste material is classified as hazardous if it exhibits, whether alone or in contact with other wastes or substances, any characteristics such as corrosivity, reactivity, ignitability, toxicity, acute toxicity or infectious property. These substances are either created as byproducts of the HPI or as residues of processes. Toxic byproducts or products are capable of causing irreversible damages to the environment. Most industries have identified such materials coming under the review of hazardous wastes from their operations and are subsequently classified. Hazardous waste is generated in-house as a result of several industrial operations, and there are imports too for recovery of valuable metals hydrocarbons, etc. Determined efforts of local governments to federal levels describe the necessity for chemical hazardous treatment and disposal facilities (CHTDF). Emergency planning for disaster mitigation. Local level emergency planning for disaster preparedness in case of natural calamities and man-made disasters is important. Effective mechanisms for mitigating hazards should be developed under the district administration. The program may be coordinated on the lines of the Awareness and Preparedness for Emergencies at Local Level (APELL) project of the United Nations Environment Programme (UNEP). Key issues. The key issues in environ-
mental management in the HPI are identified as pollution from solid waste resulting in contamination of land space; liquid effluSelect 164 at www.HydrocarbonProcessing.com/RS 76
ENVIRONMENT ents endangering water streams and groundwater resources; and gaseous emissions degrading the quality of atmospheric air. It is a risk to life from operational incidents to people and property in the industry and adjacent neighborhoods due to the storage, handling, transport and use of large quantities of inflammable and hazardous chemicals and hydrocarbons; large-scale depletion of natural resources, raw materials, energy resources and water; and contribution to global warming due to GHG emissions. Studies also reveal that the units have been successful in controlling emissions from their operations to the prescribed levels by the statutory authorities and as required by law. The best available technology (BAT) for pollution control and environmental management is being used, and it compares well with such practices being adopted internationally. Generally, there is substantial compliance by all units to the standards prescribed for effluent discharges. Often, units are committed to attaining norms for various parameters as stipulated by PCBs. HPI companies will go beyond compliance if there are sufficient economic incentives to make additional investments. In other situations, no attempt is made to achieve better control of pollution and to meet the standards. HP BIBLIOGRAPHY For complete bibliography, visit HydrocarbonProcessing.com.
Dr. MP Sukumaran Nair is currently the Special Secretary to Government of Kerala and Chairman, Chemical Engineering Division Board of the Institution of Engineers (India). He was formerly managing director of the state-owned chlor-alkali major Travancore-Cochin Chemicals (TCC) Ltd., Cochin. He has over three decades of experience in the chemical processing industry at the M/s Fertilizers and Chemical Travancore (FACT), India’s pioneer fertilizer and chemical manufacturing, engineering design and consultancy organization (FEDO) and at TCC Ltd. He holds BS degrees in chemistry and chemical engineering and is a postgraduate in ecology and environment. Dr. Nair also has an MBA and a PhD in management. He has published more than 90 technical and management papers at various national and international forums and workshops and journals. He is well experienced in process plant operation, process design, troubleshooting and management, in the HPI. Dr. Nair is a Fellow of the Institution of Engineers (India), was chairman of its Cochin center and a member of the American Institute of Chemical Engineers and European Federation of Chemical Engineers. He is also associated with various professional bodies and institutions and serves on several expert advisory committees to the Central and State Governments. A recipient of the Outstanding Chemical Engineer award from IIChE, he is listed in the Marquis, Who’s Who in the World and by the International Biographical Centre, Cambridge, England. He can be reached at
[email protected].
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ROTATING EQUIPMENT
Going ‘green’ with FCC expander technology New options recover waste gas energy as steam and electricity for plant use B. CARBONETTO and P. PECCHI, GE Oil & Gas, Florence, Itlay
O
various levels. The process allows desirable petroleum-oil refinery products to be separated out.1,2 The final portion of the FCC process is the regenerator. The used (spent) catalyst from the reactor is sent to the regenerator to be stripped of carbon and recycled back to the reactor. Compressed air is pumped into the regenerator to mix with the used catalyst in a combustion process. Also taking place in the regenerator is the separation of particles from the flue gas. There are generally two stages of cyclones in the regenerator that strip the exhaust gas of its catalyst. The flue gas exiting the top of the regenerator will typically pass through an additional vessel called a third-stage separator (TSS) to further reduce the catalyst amount in the flue gas. The flue gas from the FCC process exiting the regenerator has significant pressure, temperature and volume, and it is a source of useful energy that represents an energy cost-saving opportunity to a refinery. One method of harvesting the potential of the flue gas is a heat recovery steam generator (HRSG). The HRSG uses the heat from the flue gas to create steam. However, this method ignores the pressure component, a potential energy source that can be converted to mechanical work. A second method is to use an expander to recover energy from the flue gas. This energy can then be used to drive the compressor that provides air to the regenerator (the main air blower) or an electric generator.
ver the years, petroleum refineries around the world have researched and invested in ways to reduce the amount of waste energy and pollutants produced and released into the environment from their processing operations. The diverse processes used to produce crude oil based products usually require large amounts of electricity to run the various compressors and pumps. Many oil refineries have projects to recapture the energy as part of their cost savings plan and are driven by environmental concerns to reduce pollutants generated by process units. The hot gas expander is a single-stage power turbine capable of converting the potential energy of flue (waste) gas into mechanical work. This article describes how refineries can “go green” by implementing fluid catalytic cracking (FCC) hot gas expanders.
Highlighting the FCC process. The FCC process is widely used for manufacturing of gasoline and petrochemical feedstock. The process uses three main process vessels: the reactor, fractionator and regenerator. As shown in Fig. 1, feedstock (crude oil) enters the FCC reactor; here, a catalyst strips carbon molecules from the larger hydrocarbon chains in the feed oil. This reaction breaks the hydrocarbons down into smaller, more useful hydrocarbon products. The hydrocarbon mixture is sent to the fractionator where it is vaporized and cooled under controlled conditions to
Electricity Steam Fuel gas
Power recovery
Air FIG. 1
Raw oil: VGO, resid, etc. Flow diagram of FCC unit.
Fractionator
Regenerated catalyst
LPG Reactor (920°F-1,050°F)
Spent catalyst
Regenerator (1,300°F-1,400°F)
Flue gas
Gasoline HCN (gasoline)
LCO (diesel)
Clarified oil (fuel oil) FIG. 1A Hot gas FCC expander—side view.
HYDROCARBON PROCESSING JANUARY 2011
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ROTATING EQUIPMENT In this case, the FCC process is the existing (and primary) process and it can be useful to think of the power recovery system as a secondary process (see Figs. 1 and 2). The refinery operator is primarily interested in the FCC process. It is the FCC process that generates the refinery primary products (gasoline, propane, fuels, etc.) and, thus, it yields revenues for the refinery. The power recovery process increases energy efficiency for the overall plant and therefore, it increases profitability. Hot gas expanders can be used to drive the compressor that provides air to the regenerator—the power recovery train (PRT). Alternatively, it can be used as the driver for standalone expander-generator sets. Fig. 3 shows a main air blower PRT; Fig. 4 illustrates an expander-generator set. In both cases, the expander maximizes recovery of available energy from the flue gas.
entire power production to generate electricity for the refinery. In general, the expander–generator set stands to benefit the customer the most. The key benefits include:3 • Easily added to existing FCC installations • Small footprint • Installed remote from the FCC unit or main air blower train • Does not need to match the air blower operating conditions—speed • No modifications to the air blower equipment • Installed during FCC operation and tied in at a scheduled turnaround • Taken on- or off-line at any time without affecting FCC unit operation • Has a high efficiency due to equipment optimization. FCC expanders: Description and operation. Fig. 5
Main air blower train. A main air blower PRT consists of a
steam turbine, compressor, motor/generator and expander. The expander in the PRT is used to drive the compressor, and often supplies additional power for the generation of electricity. In this case, the expander cannot provide all of the power needed to drive the compressor; motor/generator will operate in motor mode. A steam turbine is used for startup. Electric power generation train. Expanders in an
expander-generator application drive a generator, thus using the
FIG. 2
Expander generator power recovery system for an FCC Plant.
FIG. 3
Main air blower power recovery train.
represents an FCC hot gas expander; it shows the path of the hot flue gas flow passing through it. Major components can be seen assembled in Fig. 6. The FCC hot gas expander is a single-stage axial-flow turbine. The pressurized, high-temperature flue (exhaust) gas coming from the FCC process enters the inlet opening of the expander and is accelerated through the stationary and rotating blades. In the expander, the pressure and temperature are reduced, and energy is extracted and converted into mechanical work. Although the flue gas has been processed through multiple separation stages, a significant amount of catalyst particles will
FIG. 4
Expander generator set.
FIG. 5
Cross-sectional view of the FCC hot gas expander (flue gas flow path). HYDROCARBON PROCESSING JANUARY 2011
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ROTATING EQUIPMENT remain in the flue gas. The catalyst particles pass through the expander and can potentially cause erosion. The expander flow path’s stationary and rotating components are optimized to efficiently extract the pressure energy from the flue gas and to minimize catalyst erosion.4 Rotor disc cooling and seals are used to increase the service life. The latest developments in material alloys and coatings can be used to mitigate damaging effects from handling catalyst-laden flue gas. All components are designed for reliability, including casings, bearings and supports. All of these factors allow the expanders to regularly withstand four to five years of continuous operating cycles. Based on process conditions (pressure, temperature and flow), a customized flow path has to be selected to meet the process requirements. Selecting the right expander frame size is
FIG. 6
3.5
Cross-sectional view of the FCC hot gas expander (major components).
22 TBD
FEX-81 FEX-97
3.0
Pressure ratio
40 TBD
55 TBD FEX-107
75 TBD FEX-125
2.5
2.0
very important, and standardized frames that can cover a large range of pressures and flows have been developed, as shown in Fig. 7.
History of expanders for FCC applications. Initial expander development took place between the late 1950s and the mid-1970s. In all, hundreds of units were installed, each with unique designs for specific installations. Second-generation expanders were developed from the mid-1970s through the mid1980s, and this era experienced significant expander production. Hot gas expanders became available with increasing frame size options. However, there were also increased industry concerns regarding equipment reliability as well as the desire to increase the time between shutdowns. Some of the initial problems/issues faced during the development of expanders over the decades included:2 • Lack of proper catalyst separation mechanism. The expander flow path components would wear quickly due to the catalyst content in the flue gas. The introduction of an additional catalyst separator (external to the regenerator) commonly called the TSS was crucial to extending the life of expander components. • Lower refinery throughput factors such as lower pressures and temperatures meant lower power recovery opportunities for refineries • Difficulties of designing customized expanders for every FCC application. As every refinery designs and operates their FCC unit differently, each expander needed to be customized. Only a few expander manufacturers had the capabilities to design custom solutions. To overcome this issue, pre-standardized frames were developed to cover refineries’ production needs (see Fig. 7 for sample chart). • Validation of investment cost vs. benefits over the years. Initially, during the earlier developmental years (1960s and 1970s), it was not essential to install an expander since pollution-control measures were not given as much priority as they are today. As more government laws have targeted pollution control and green initiatives, more refineries are investing in ways to reduce their power consumption.1 Over the last 20 years, design programs have been developed to address the user industry’s increased emphasis on expander reliability and extended time between shutdowns. These programs focused on material upgrades, CFD-designed flow 110 TBD paths, more efficient catalyst removal and robust control systems. Modern FCCU FEX-142 hot gas expanders are designed to run for four to five years to coincide with FCC unit maintenance intervals and have demonstrated this capability in many applications. Economic benefits of power recovery. Energy costs are a major part of
1.5 Refinery capacity: TBD = thousands barrels per day 1.0 0
FIG. 7
82
50
100
150 200 250 Flue gas flowrate, lbs/sec
Frame selection chart.
I JANUARY 2011 HYDROCARBON PROCESSING
300
350
400
the total costs of operating an oil refinery, and electricity usage is a large part of these energy costs (steam is an alternate energy source), with energy requirements ranging from 50 MW to 180 MW. FCC expanders can help reduce these costs even if the temperature drop that is experienced through
ROTATING EQUIPMENT the FCC expander will result in decreased steam production for the refinery. Due to the variability of refinery steam requirements and HRSGs, the reduction in steam temperature and production is not easily quantified. Additionally, a loss in the quantity or temperature of the steam does not easily translate into a monetary figure. These values must be evaluated based on the specifics of the application. However, a very rough approximation can be made based on actual cases. The expander reduces the flue gas temperature entering the HRSG by approximately 300°F. For a typical HRSG, the exit flue-gas temperature will be the same with or without an expander. Thus, the flue-gas temperature reduction through the HRSG will be 300°F. To maintain superheated steam production, the amount of steam produced will be less when an expander is used. Table 1 shows the estimated savings in electricity per year attributable to a power recovery unit installation. The notable savings due to higher power recovery are evident in comparing current process conditions (2007) to those of the 1960s. Factors taken into consideration for Table 1 values include: • Steam generation losses (flow and temperature) may be experienced and must be debited • Installed cost is approximately $30–$55 million • Typical payback is less than three years.
TABLE 1. Potential recovered power and savings Year Design conditions
1962
2007
Inlet temperature–Basis: the assumption of a 25 degree drop from the regenerator, °F
1,100
1,400
13
50
Inlet pressure–Basis: the assumption of a 4 psi drop from the regenerator, psig Discharge pressure, psig Flow, lbm/hr Delivered power, kW Electricity savings–Basis: average electricity cost of 6 cents/kW-hr
1.5
13
200,000
1,750,000
6,340
52,944
$3,332,304
$27,873,366
ronment, more innovative ways will be pursued to deliver more benefits to customers. FCC hot gas expander technology has grown significantly from the 1960s to the present, and it now offers state of the art machinery that can be incorporated into the refinery process without impacting plant reliability or efficiency. The huge economic and environmental benefit of this energy recovery solution proves that FCC hot gas expanders are a significant contribution in the drive for “green” applications in the oil and gas industry. HP
Environmental benefits of power recovery. In a power
recovery system installation, there are environmental benefits associated with the economic benefits to the refinery. The positive impact on the environment comes from the fact that the need to install sources of electricity to run machinery is reduced, with the consequent elimination of the emission of carbon dioxide (CO2), nitrogen oxides (NOx) and other pollutants associated with the combustion of fossils fuels. Often, the energy usage and efficiency of a refinery is measured through the Energy Intensity Index (EII). The installation of a power recovery system can reduce a refinery’s EII by 7%–10%, thus helping them to reduce their environmental impact and to comply with specific regulations. A few numbers can give a better understanding of the huge benefits of this solution. For example, if we consider the total installed fleet of one leading manufacturer’s FCC hot gas expanders, the estimate is that it produces around 500 mega watts (500 MW) of power, which corresponds to 4.3 billion kWh (4.3 TWh) of electricity saved per year. Using the US Environmental Protection Agency (US-EPA) Emissions Calculator, 4.3 TWh of electricity saved per year translates into approximately 3.1 million metric tons of CO2 emissions avoided per year.5 In simpler terms, this is equivalent to: • Annual greenhouse gas emissions from 565,000 passenger vehicles • CO2 emissions from 350 million gallons of gasoline consumed • CO2 emissions from the electricity used by 428,000 homes in one year • Carbon sequestered annually by 702,000 acres of pine or fir forests. As can be seen, the installation of FCC expanders in refineries has a noticeable environmental impact. Outlook. As the petroleum refining industry continues to strive for more ways to save energy, reduce costs and improve the envi-
1
2 3
4
5
LITERATURE CITED US Environmental Protection Agency Executive Summary, 2008 Sector Strategies Performance Report, Executive summary, http://www.epa.gov/ispd/ pdf/2008/executive_summary.pdf Bloch, H. and C. Soares, Turboexpanders and process applications, First Ed., Gulf Publishing Company, 2001, ISBN 0-88415-509-9. Conroy, C.F and D. H. Linden, “Successful Application of Stand-alone FCCU Expander / Generator Sets,” International Symposium on Turbomachinery, combined-Cycle Technologies and Cogeneration – IGTI-Vol.1. Greenhouse Gas. Carbonetto, B. and G. L. Hoch, “Advances in Erosion Prediction of Axial Flow Expanders,” Proceedings of the 28th Turbo machinery Symposium, Turbomachinery Laboratory, Texas A&M University, College Station, Texas, pp. 1–7, 1999. Equivalencies Calculator, 2009. US Environmental Protection Agency, (http://www.epa.gov/cleanenergy/energy-resources/calculator.html).
Ben Carbonetto is hot gas expander product leader, GE Oil & Gas. His career spans 15 years in the design and operation of turbomachinery, starting in 1995 as an axial compressor / hot gas expander design engineer. In 2001, he was promoted to Sr. (lead) design engineer, a role which expanded to include responsibility for orders, engineering and execution as expander product supervisor/manager. Mr. Carbonetto has also served as engineering manager (2005) and North America services engineering manager (2007). He holds a BS degree in mechanical engineering and mechanics from Drexel University and is a member of ASME.
Paolo Pecchi joined GE Oil & Gas in 1996 as a fluid dynamics engineer with the R&D team. In 1998, he joined the technical leadership program (TLP) covering different technical assignments in the gas turbine department, following LM2500+ HSPT product introduction and field installation. Upon TLP graduation, he held the role of project/system engineer in the new product Introduction organization, and in 2004, he was appointed NPI-NTI programs management leader, being responsible for the management of the company’s technical development programs. In 2008, he relocated to Bethlehem, Pennsylvania, as manager of the engineering team. Mr. Pecchi is now the global technical fleet support manager—turbomachinery. Mr. Pecchi graduated with a degree in mechanical engineering in 1995 from the University of Florence, Italy. HYDROCARBON PROCESSING JANUARY 2011
I 83
GE Oil & Gas
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ENGINEERING CASE HISTORIES
Case 60: Socket-weld failures A risk analysis can determine which critical welds to repair T. SOFRONAS, Consulting Engineer, Houston, Texas
A
new plant was constructed; it contained over 10,000 socket welds. Socket welding (Figs. 1 and 2) is one of a number of methods used for making piping connections; they are plain-fillet welds arranged for greater ease of alignment and welding. Used for nominal pipe sizes (NPSs) 4-in. and smaller, they are favored for new projects that make use of prefabricated piping. However, there are some downside issues with socket welds. Having only about ⅓ the strength of a full butt weld in bending and even less in fatigue, they are not considered high-strength welds. Moreover, socket welds are subject to vibration cracking in the root and toe regions and are susceptible to crevice corrosion, if used in the wrong services. Assessment of the weld. X-ray examination indicated that some socket welds lacked adequate weld penetration of the fillet weld. Also, some of the pipes had bottomed out in the socket body, which was due to poor workmanship when assembling the pieces for welding. When welding these assemblies, there is an ASME Code requirement for a gap. Such a gap, usually 1⁄16 in., ensures that the weld is not stressed due to the pipe axially expanding. Without a gap, there is the possibility of a weld crack developing in the root. It would have been extremely cost prohibitive and, in some cases, impossible to inspect, grind and reweld all the joints due to the confined nature of the piping after installation. There was simply no room for the needed access. The project team, therefore, proceeded with a risk analysis approach. This meant that noncritical, nonhazardous joints that weren’t safety issues would be considered low risk and would be checked for leaks during normal pipe inspection intervals after startup. Higher risk joints that could pull apart were either rewelded or braced, depending on the assessed risk. This reduced to a manageable number of joints subjected to repair; after 10 years, there have been no major leaks. With no gap during welding, strain will be induced in the weld root. Weld-root behavior and what happens to stresses as the weld cools would be complicated and was not considered. But many of these types of no-gap welds were checked after welding, and no cracks were present.
not affect the life in non-vibratory services due to bending. Concerns with no gap were not considered further in the risk analysis. Best preventive measures. While this article is for edu-
cational purposes only, it does show the importance of using various methods to solve problems in a cost-effective manner. A high level of experience allowed the project team to quickly examine the various joints on piping drawings and to make key decisions. The resulting savings in time and expense were well worth the effort. HP
Fillet weld toe
Pipe
Root
Gap Body
FIG. 1
Socket-weld nomenclature.
FIG. 2
Dye-leak trace of a 2-in. socket-weld connection.
Problems in normal operations. Another potential
problem is no gap during normal operation. The problem then becomes how much the weld is stressed due to a temperature difference between the socket body and pipe. Any additional stress would reduce the load capability of the weld. This would be important to know for the screening procedure. This was analyzed with a coupled thermal stress finite-element analysis for a 400°F product flowing through the pipe and with no end gap. Weld stresses were less than 5,000 lb/in.2 and should
Dr. Anthony (Tony) Sofronas, P.E., was worldwide lead mechanical engineer for ExxonMobil before his retirement. Information on his books, seminars and consulting, as well as comments to this article, are available at http://mechanicalengineeringhelp.com.
HYDROCARBON PROCESSING JANUARY 2011
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FREE Product and Service Information—JANUARY 2011 HOW TO USE THE INDEX: The FIRST NUMBER after the company name is the page on which an advertisement appears. The SECOND NUMBER, appearing in parentheses, after the company name, is the READER SERVICE NUMBER. There are several ways readers can obtain information: 1. The quickest way to request information from an advertiser or about an editorial item is to go to www. HydrocarbonProcessing.com/RS. If you follow the instructions on the screen your request will be forwarded for immediate action. 2. Go online to the advertiser's Website listed below. 3. Circle the Reader Service Number below and fax this page to +1 (416) 620-9790. Include your name, company, complete address, phone number, fax number and e-mail address, and check the box on the right for your division of industry and job title. Name ________________________________________________________
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ACS Industries Inc. . . . . . . . . . . . 38 (157) www.info.hotims.com/35899/-157
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Sabin Metals Corporation . . . . . . 51
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154
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Merichem Company . . . . . . . . . . 73
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Hoerbiger . . . . . . . . . . . . . . . 28–29
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Honeywell Analytics. . . . . . . . . . . 20
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Elliott Company. . . . . . . . . . . . . . 16
Emerson Process Management (Fisher Controls) . . . . . . . . . . . . 30
Gulf Publishing Company
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CB&I . . . . . . . . . . . . . . . . . . . . . . 67
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GE Power & Water . . . . . . . . . . . . 12
Bently Pressurized Bearing Co . . . 76 (164)
Cameron . . . . . . . . . . . . . . . . . . . . 2
Emerson Process Management (Delta V) . . . . . . . . . . . . . . . . . . 19
GE Oil & Gas . . . . . . . . . . . . . . . . 84
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RS#
Foster Wheeler . . . . . . . . . . . . . . 61
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BASF Catalysts Llc . . . . . . . . . . . . 78
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Flexitallic LP . . . . . . . . . . . . . . . . . 5 (59)
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Axens . . . . . . . . . . . . . . . . . . . . . 92
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HPIN CONTROL PIERRE R. LATOUR, GUEST COLUMNIST
[email protected]
Process control practice renewal—select CVs I followed my April 2010 call for renewal of process control and IT practice with editorials on purpose in August, performance in October and consequences in December. Now I turn to selection of controlled variables (CVs). How do we select CVs? Well, just how do we go about select-
ing operating conditions to be controlled about setpoints by manipulating valves? Why we do select particular flows, levels, pressures, temperatures, compositions, efficiencies, capacities and yields for measurement and stabilization about desired setpoints near limits? How do we determine the production, inventory, product quality, utility consumption and equipment limit setpoints? From the host of candidate refinery operating conditions, what is the underlying basis for selecting a relatively few for control to operate the HPI? We know how to measure CVs. We know how the manipulated valves affect them. We know about instruments, control algorithms, models, optimizers and displays. Somehow, we determine what is important, what we care about and what counts. Since we know how much equipment costs to procure, install and maintain, we proceed to engineer and use instruments, control systems, computers and IT to operate about predetermined CV setpoints. But why? What is wrong with this picture? What is missing? Why is it so hard to rigorously quantify the financial value of improved HPI operation? Why do we have so much trouble justifying maintenance? How do we figure out the merit of control and information system components and solutions? Pause a moment to think about how we know and quantify values. We determine what is important, what we care about, what counts. What we mean is that the average of a candidate CV affects profit rate. Profit is sensitive, and errors can be costly. There is great potential from quantifying the steady-state profit rate increase as the mean is moved to a limit, determining the precise location value for that limit, and the financial consequences for exceeding that limit. Establishing this tent-shaped tradeoff is critical for selecting CVs at the outset and controlling them. If the sensitivity is low and the profit tent shallow, the CV is not important. If sensitivity is high and the profit tent steep, the CV is important. We select CVs/key performance indicators (KPIs) because they have interesting and significant trade offs. Significance. Often, there is a severe cliff at the limit, encountered when a machine, safety, government or customer penalty is incurred. CVs that encounter high cliffs are critical. Knowing the location, slope and height of those cliffs is central to the business of HPI operation. So, one should determine and maintain the steady-state profit rate cliff function of CVs as a first order of business for operating properly and selecting the appropriate CVs for doing so. If you do not know CV/KPI cliff limits, you do not know your operating business. 90
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This function can be combined with the CV distribution to determine the actual expected value profit hill to find the best setpoint to optimize each risky tradeoff. This is the profit meter for every CV/KPI. If there ever was an activity that needs to pay close attention to identifying, capturing and sustaining financial values by locating and re-optimizing risky tradeoffs, it is the HPI. Once the best practice of process control is driven as the standard method for operating HPI plants, the determination of the value of control components becomes routine and we know the value of our work. We know the information that we need to make best decisions, and we can make them faithfully on the best information available because we know what we are doing with that information. Now we have a complete method for selecting CVs and KPIs. We know how to pick them and why. Distillation dual temperature control? Kern,1 Fried-
man, Shinsky and I agree that tightly controlling top and bottom temperatures or dual-ended compositions is not a good idea. Beyond their technical arguments, my additional reasons stem from HPI separation business economics. For separations like distillation, absorption and extraction, one key component is invariably more valuable than the other, providing the incentive for their separation. There will be a maximum specification for the less valuable component in the valuable stream and an optimum recovery vs. utilities for the valuable key in the less valuable stream. One end invariably has an important customer-quality specification, while the other has a smooth recovery vs. utility financial tradeoff. The former hard target is best controlled by material balance split; the latter soft target by utility reoptimization when feed composition, feedrate, component value or utility costs change. The economic incentive for tight soft-target control for a nearly flat profit hilltop can be quite small. This situation is true for olefin plant cold-side recovery, aromatics recovery, refinery saturates and unsaturates gas plants, crude-oil distillers and natural gas plants. So, first, ask why control temperatures at both ends simultaneously? What is the financial merit? How should their setpoints be determined to align the column operating conditions to its economics? Avoid working on control systems that don’t make much money. HP 1
LITERATURE CITED Kern, A., “Weighing in on dual-temperature control,” Hydrocarbon Processing, Vol. 89, No. 11, November 2010, p. 15.
The author, president of CLIFFTENT Inc., is an independent consulting chemical engineer specializing in identifying, capturing and sustaining measurable financial value from HPI dynamic process control, IT and CIM solutions (CLIFFTENT) using performance-based shared risk–shared reward (SR2) technology licensing.
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