HP_2011_05

MAY 2011

HPIMPACT

SPECIALREPORT

TECHNOLOGY

HPI recovery underway

MAINTENANCE AND RELIABILITY

Design exchangers for ‘dirty’ service

Advanced materials and programs protect critical assets

Improve design of closed-drain drums

Biodegradable polymers CAFE could boost US auto profits

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MAY 2011 • VOL. 90 NO. 5 www.HydrocarbonProcessing.com

SPECIAL REPORT: MAINTENANCE AND RELIABILITY

41

Consider new developments in antifouling coatings for rotating equipment Innovative materials and applications protect critical centrifugal compressors and steam turbines from erosion and corrosion P. Dowson

45 49 55

Deferred maintenance causes upsurge in pump failures Not addressing the root cause of a failure puts resources and employees at risk H. P. Bloch

Avoid costly engineering faults, missteps and miscalculations Experience does count, especially in achieving success in capital and revamp projects K. Sanghavi

Nickel recycle: Extending service life for reformer tubes Case studies investigate methods to conserve high-nickel tubes for fertilizer facilities S. B. Kunte

61

Consider new materials for ethylene furnace applications

65

Testing and repair options for critical dry-gas seal: Updates

71

How to justify root-cause failure analysis for pumps

75

Spiral heat exchanger in desalter service solves fouling issues

79

Optimize reordering of critical raw materials and parts

An innovative metallurgy solves maintenance issues G. Verdier and F. Carpentier Do your research when sending compressor seals out for renovations C. Carmody New method uses annualized risk to determine RCFA analysis levels R. X. Perez Technology offers problem-free operation along with considerable maintenance savings C. Wajciechowski New models evaluate the ‘total’ costs in receiving and storing materials for a refinery A. Goti, N. Zabaleta, A. Garcia, M. Ortega and J. Uradnicek

HEAT TRANSFER

83

Cover Tray-Tec, Inc. craftsmen installing a random packing holddown grid in a 46’ diameter Vacuum tower for a major refining company in the Texas City area. Also in this Vacuum tower Tray-Tec installed new internals, including 13,000 cuft of random packing, grid packing and performed variousvessel repairs, including weld metal build-up in thinned areas and replaced the bottom boot section. During this turnaround Tray-Tec also performed repairs and maintenance on numerous towers, reactors and drums including a 21’ diameter Atmospheric tower. Tray-Tec, Inc. is based in Humble, Texas, and performs vessel mechanical services for the refining, chemical, and gas industries across the United States. Photo courtesy of Tray-Tec, Inc.

HPIMPACT 17

HPI recovery underway despite uncertainty

17

Small-scale chemistry could improve biodegradable polymers

19

US auto industry could boost profits with higher mileage standards

Update on designing for high-fouling liquids A critical analysis of shell and tube exchanger systems looks at ‘clean and dirty’ service performance J. M. Nesta and C. A. Coutinho

GAS PROCESSING

87

Is your antifoam compatible with the amine system?

Several options help minimize operation costs and mitigate unscheduled shutdowns A. Atash Jameh, A. Z. Gharaghoosh, S. Mokhatab and A. G. Shazadeh

COLUMNS

SULFUR 2011—SUPPLEMENT

95

Sulfur 2011

9

HPIN RELIABILITY Consider ‘water washing’ for steam turbines

11

HPIN EUROPE Biofuels audience warms to advocate for third industrial revolution

13

HPIN ASSOCIATIONS The era of the integrated oil company has passed

Innovation will play a key role in managing sulfur compounds

LOSS PREVENTION

107

Review unit-wide impacts on closed-drain drums API 521 standard helps decipher the correct operating pressure for this system R. Mukhopadhyay, Consultant, Bangkok, Thailand

PROCESS DESIGN

113

Design an efficient exchanger network Advanced heat integration and pinch technology reduces energy consumption F. Rikhtehgar

ENGINEERING CASE HISTORIES

117

Case 62: Useful shaft stress equations to remember Committing several equations to memory can be useful T. Sofronas

DEPARTMENTS 7 HPIN BRIEF • 25 HPINNOVATIONS • 31 HPIN CONSTRUCTION 38 HPI CONSTRUCTION BOXSCORE UPDATE 118 HPI MARKETPLACE • 121 ADVERTISER INDEX

122 HPIN WATER MANAGEMENT Legionella—to test or not to test?

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Dow Global Technologies (DGT) has announced the invention and development of a new, high-molecular-weight brominated polymeric flame retardant (PFR). The PFR is expected to be the “next-generation industry-standard” flame retardant for use in both extruded polystyrene (XPS) and expanded polystyrene (EPS) foaminsulation applications globally. The development of the new PFR is the result of Dow’s continuing search for more sustainable products and, in this case, for a flame retardant that can replace hexabromocyclododecane (HBCD).

DGT also announced its first license agreement with Chemtura Corp. This first license agreement makes it possible for Great Lakes Solutions, a Chemtura business, to produce and sell the newly developed PFR for use in XPS and EPS foam.

A poll released in April shows that 90% of Americans believe the nation’s petroleum refineries and petrochemical manufacturing plants are among America’s “most important” or “important” industries. NPRA, the National Petrochemical & Refiners Association, announced results of the poll conducted by Opinion Research.

A total of 44% of Americans believe the refining and petrochemical sectors are “among the country’s most important industries,” while 46% consider the sector “among the country’s important industries,” the poll found. Only 5% of those surveyed said the refining and petrochemical sectors were “not among the country’s important industries” and the remaining 5% said they did not know.

The board of directors of the Export-Import Bank of the US has voted to grant preliminary approval for a $2.84 billion direct loan/loan guarantee to Colombia’s Refinería de Cartagena S.A. (Reficar). The financing, when finally approved, will support the purchases of equipment and services from over 150 large and small US engineering/design, equipment supply, contracting and process license firms, including Chicago Bridge & Iron, Foster Wheeler, ExxonMobil and UOP. This is part of a $5.18 billion refinery and upgrade project in Cartagena, Colombia, supplying petroleum products to the domestic and export markets.

The US Environmental Protection Agency (EPA) will require electronic submissions for new chemical notices under the Toxic Substances Control Act (TSCA).

Beginning last month, companies can no longer submit their new chemical notices and support documents on paper for the EPA’s review.

On April 6, 2010, the EPA issued a final rule that put in place a two-year phaseout of paper and optical-disc reporting for new chemical notices to the agency. The rule included a one-year phaseout of paper reporting and a two-year phaseout of optical-disc reporting. Under TSCA, companies are required to submit new chemical notices, including pre-manufacture notices (PMNs), to the EPA at least 90 days (in the case of PMNs) prior to the manufacture or import of the chemical. The EPA reviews the notice and can set conditions to be placed on the use of a new chemical before it enters into commerce.

Marking the one year anniversary of the tragic accident at the Tesoro refinery in Anacortes, Washington, the US Chemical Safety Board (CSB) released a video safety message in which Chairperson Rafael Moure-Eraso urged refinery companies to “make the investments necessary to ensure safe operations.”

The video highlighted the CSB’s ongoing investigation into the April 2, 2010, accident that killed seven workers. At the time of the incident, a heat exchanger was being brought online when the nearly 40-year-old piece of equipment catastrophically failed, spewing highly flammable hydrogen and naphtha that ignited and exploded.

Tesoro disputes the findings of the CSB. Company spokesperson Mike Marcy said in a statement that, “We disagree with the chairman’s characterization of Tesoro’s operations at Anacortes. The heat exchanger was maintained and inspected in accordance with regulations and industry standards. We continue to cooperate with the CSB.” HP

■ BASF foam insulating LNG pipes in Korea BASF’s specialty foam Basotect is now, for the first time, being used to insulate pipes in a liquefied natural gas (LNG) tank terminal in Gwangyang, Korea. The pipe cover with Basotect provides energy-efficient thermal insulation, easy handling and flame retardancy. LNG is natural gas that is temporarily liquefied at very low temperatures, in order to transport or store it more easily. As the temperature of LNG must be kept below –162°C, efficient insulation for the pipes is necessary.

According to SKI Insulation, the system supplier of the removable insulation cover, the pipe cover made from Basotect is more energy-efficient as it is 20% thinner than conventional foam insulation.

“Basotect shows a high degree of stability at low temperatures. In laboratory tests even at temperatures of around –200°C the material retains its properties. The high degree of elasticity and the thermal insulation capacity of the foam remain unaffected, in contrast to conventional foam insulation, which becomes brittle when exposed to such extreme cold,” said Dr. Peter Wolf, head of Global Business Management Basotect at BASF. SKI Insulation discovered that the system material with the lightweight and flexible BASF foam can be easily removed for regular inspection of pipe integrity and later reused, unlike rigid conventional foams that are hard to replace. This translates into reduced maintenance costs.

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Consider ‘water washing’ for steam turbines Occasions may arise when deposits form on the internal parts of steam turbines. The accumulation of these deposits may be indicated by a gradual increase in stage pressures over time with no evidence of vibration, rubbing or other distress. Such deposits have a marked detrimental effect on turbine efficiency and capacity. When deposits cause extensive plugging, thrust-bearing failure, wheel rubbing and other serious problems can result.

Boiler stop valve Boiler

Water washing. Turbine washing at full speed (onstream

cleaning) can be and has been successfully used on many mechanical-drive steam turbines. Considerable hazards are possible with water-washing methods, and full-speed washing is more hazardous than washing at reduced speed. But this can be accomplished, provided great care and judgment are exercised. While we know of no steam turbine manufacturer who would guarantee the safety of turbines for any washing cycle, capable manufacturers recognize that deposits do occur. They will, therefore, help operators as much as possible in dealing with such problems until effective prevention is established.

Saturated steam washing by water injection is the conventional and well-tried method of removing water-soluble deposits from turbines. The amount and rate of superheat to be removed and the steam flow required for operation determine the waterinjection rate. Injecting large quantities of liquid (such as may be required on process drivers) creates potential problems.

The nature of a typical impulse turbine lends itself to fullspeed water washing. Axial clearances between first-stage buckets and nozzles and between moving buckets and diaphragms will range from 0.050 in. to 0.090 in. The typical NiResist labyrinth packing radial clearance when the unit is cold will be approximately 0.007 in. The labyrinth will seal on the shaft only; the moving blades will not require seals. With impulse turbines, these

Governor valves Turbine

Water-steam mixer

Deposit types. Deposits are classified as water insoluble and

water soluble. The characteristics of these deposits should be determined by analyzing samples, and corrective measures should be taken to eliminate such deposits during future operation.

When it has been determined that deposits have formed on the internal parts of the turbine, three methods may be applied to remove the deposits: 1. Turbine shutdown, casing opened and deposits removed manually 2. Turbine shutdown and allowed to cool; the deposits crack off due to temperature changes 3. Online water washing (while running), essentially removing water-soluble deposits.

Plant operating conditions will dictate which method is best in restoring the turbine to optimum performance. In a generatordrive service, shutting down the unit or water washing at low speed and reduced load may create minimum plant upset.

T&T Recording valve thermometer

Feedwater

Driven machine

Exhaust steam to drain

Turbine speed held at approximate 500 rpm by adjusting steam and water flow with these valves

FIG. 1

Flow diagram of low-speed water-wash system.

liberal clearances help minimize hazards associated with water washing. Nevertheless, numerous reaction turbines have also been successfully water washed.

Water injection is accomplished by a piping arrangement for atomization and injecting water into the steam supply , thus ensuring a gradual and uniform reduction in temperature of the turbine-inlet steam until it reaches 10°F to 15°F superheat. It is probably a safe rule that the temperature should not be reduced faster than 25°F in 15 minutes or 100°F/h. Fig. 1 shows suggested piping arrangements for admission of water and steam, and a simple assembly of fabricated pipes to form a desuperheater can be found in the text reference.

Failure of water injection pumps presents a great hazard, especially at maximum injection rates. To guard against pump failure, untreated boiler feedwater is used since these pumps are usually the most reliable. If plant operating conditions allow, the vacuum on a condensing turbine should be reduced to 5 mmHg to 10 mmHg. For non-condensing turbines, the exhaust pressure should be reduced to atmospheric pressure. Note: On any non-condensing unit requiring full-speed washing, the manufacturer should be consulted about minimum allowable exhaust pressures. Extraction turbines should be operated with the extraction line shutoff.

A steam gauge and thermometer should be installed between the trip-throttle valve and governor-controlled valves. The thermometer should be a recording type and be very responsive to small changes in temperature. Low-speed wash (see Fig. 1) represents a well-understood method for deposit removal. HP The author is Hydrocarbon Processing’s Reliability/Equipment Editor. A practicing consulting engineer with close to 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance cost-avoidance topics. This excerpt is taken from Bloch, H. P. and Dr. M. P. Singh, Steam Turbines: Design, Applications and Re-Rating, 2nd Ed., 2009, McGraw-Hill, New York. The original material was contributed by Dresser-Rand Co.

HYDROCARBON PROCESSING MAY 2011

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

Biofuels audience warms to advocate for third industrial revolution Here is a thesis on energy that’s being expounded at the heart of European policy-making these days: Thirty years after peak oil per capita and at the apex of peak globalization, the machines and infrastructure of the oil age are on life support. Oil prices will not edge over $150/bbl without turning off the engine of global growth, as they did in 2008. But, there is an alternative—a third industrial revolution.

So says the US author and polemicist, Jeremy Rifkin, who is something of a controversial figure back home in the US. He’s been outspoken long, and loudly, enough to have his detractors.

I might hesitate to give space to him in this editorial here if his ideas weren’t influential in reshaping European policy making.

A new herald. Rifkin, the president of a Washington, DC,

think tank, and a fellow and lecturer at the Wharton School of the University of Pennsylvania, spoke at the World Biofuels Markets conference in Rotterdam. He is a natural choice for this event.

Rifkin professes optimism grounded in pessimism, one might say. According to Rifkin, oil has peaked; the atmosphere is in big trouble; and nuclear is finished. No surprise then that a speech with those premises would pep up the European biofuels industry. For added impact, the delivery is that of a big-screen prosecutor pressing home his case in a courtroom drama.

But starched collars and deftly handled statistics aside, Rifkin’s talk of an energy revolution has been influential.

Indeed, a version officially adopted by the European Parliament has been formative in policies that are even now powering the biofuels industry, and a raft of other sustainability initiatives across Europe.

It is striking that, at this well-attended event, there were more engineers, operators and vendors than attend Europe’s largest oil refining conference. And they pay slightly more to do so as well. After the plenary, during coffee, members of this industry actually seem pepped up. Two years ago, the biofuels industry was being blamed for food riots in Mexico and was seeing credit evaporate during the financial rash. A year ago, biodiesel plants were by some accounts being driven out of business by US “splash and dash” exports of 99% biodiesel blends.

But the big reason that they’re in a more buoyant and conference-going mood this year is because European policy-making on renewables is really taking hold! When a recent initiative to introduce a 10% blend of bio-ethanol into gasoline was bungled in Germany this winter, it wasn’t just a blow to ethanol producers. The oil companies distributing transportation fuels in Germany could face two or three hundred million euros in fines if they’re found short of their blending obligations by the year end. They can be fined 62 eurocents for each mandated liter that goes unburned (US $3.33/US gal) in German vehicles this year.

Crisis in the making. Rifkin begins his keynote speech by outlining two crises. The first problem is peak oil per capita.

We’re in an end game, he tells delegates, because our energy reserves have not been measured against the benchmark of massive population growth.

“When China and India made a bid at a 8%–10% growth rate,” he says, “raking one third of the human race into the game in 10 years, the aggregate output and demand against reserves pushed the price up and the global economy collapsed at $150/bbl.” Our first major problem, he claims, is that our oil-driven engine of economic growth won’t work at prices above that threshold.

The second problem is what he calls the entropy bill for the first two industrial revolutions: “This is not a metaphor…it’s spent energy. We’ve exhumed too much carbon and we’re not getting enough sunlight off the planet. So we’ve hit peak globalization with $147/bbl, and we’re now paying an entropy bill for 200 years of the industrial revolution and we’re also facing a mass extinction event because of global warming in this century, so what do we do?”

Policy. Rifkin is credited with helping to form the European energy strategy that he goes on to describe. One point is that renewable energy will provide a third of European electricity production (20% of energy) by 2020. Approximately 191 million buildings will be partially repurposed to generate power, and a supergrid technology learned from distributive computing will provide a nervous system to the new infrastructure. It will, in time, displace what he calls elite, centralized technologies like oil, gas and nuclear. He names €8 billion of investment into energy storage, largely using hydrogen, to provide base-load generation, when the wind isn’t blowing and the sun isn’t shining.

Preparing for change. And as a young generation turns to distributed and collaborative ways of solving energy problems, Rifkin draws parallels between the fossil fuel industry and other 20th century ones, which will need to adapt or end. “The music companies just didn’t understand file sharing,” he says. “When millions of kids started file sharing music, they laughed. They tried to legislate against it; then they went out of business, within five years. Encyclopedia Britannica didn’t understand Wikipedia, now Wikipedia rules.” HP

The author is HP’s European Editor and is 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 MAY 2011

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HPIN ASSOCIATIONS BILLY THINNES, TECHNICAL EDITOR

BT@HydrocarbonProcessing.com

The era of the integrated oil company has passed The National Petrochemical and Refiners Association (NPRA) gathered in San Antonio, Texas, for its 109th annual meeting in March. Key points of conversation included the ongoing battle with the US Environmental Protection Agency (EPA) over greenhouse gas emissions (GHGs), possible discriminatory tax treatment toward downstream oil companies from the US federal government and the status of energy policy in the US. Keynote speakers included former US Senator Alan Simpson (R-WY), journalist Robert Bryce, PBF Energy Chairman Tom O’Malley and television personalities Joe Scarborough and Mika Brzezinski.

be drilled the future. He wonders why Brazil is drilling deep wells now but the US has stopped drilling completely.

Mr. Klesse also expressed concern about the EPA’s regulation of GHGs under the Clean Air Act. The way it appears the agency would go about such regulation would mean that in order for Valero to expand a refinery, it would take 18–24 months just to get a permit. He thinks that would have a crippling effect on the US economy, on output of refined products domestically and most importantly, on energy prices for the US consumer.

EPA and GHGs. The NPRA supports the Upton-Inhofe legislation which says the EPA does not have the authority to regulate greenhouse gases (GHGs) under the Clean Air Act. Another bill that is in Congress, penned by Senator Rockefeller (D-WV) would delay implementation of EPA’s GHG regulation for two years.

While Mr. Drevna thinks two years is better than immediately, he wonders what happens two years from now? He thinks the GHG and climate change debate won’t change much two years from now and that using the Rockefeller bill is more like a stay of execution than an actual solution.

Strategic petroleum reserve.

US energy policy. The US’ current

The future. Mr. Klesse looked to the

With the price of oil on the rise recently, some politicians and pundits have called

energy policy, or lack thereof, has been a hot topic of conversation in Washington among both industry types and environmentalists. Bill Klesse, of Valero, who is serving as the NPRA’s board chairman, and NPRA President Charlie Drevna spoke about this and other subjects in a press conference with reporters at the meeting.

“We have an energy policy that is no policy at all,” Mr. Drevna said. “The government manages from crisis to crisis rather than having a crisis management program. For instance, a town or city doesn’t wait until there is a fire to organize the fire department. We shouldn’t wait until the next crisis to develop a real energy program.”

While Mr. Drevna is keen for the US to develop and implement a rational and fair energy policy based on sound science and pragmatic perspectives, he does not see that happening anytime soon.

“Long term, I don’t see any grand energy policy coming out of this Congress, at least during the first session,” Mr. Drevna said. “We do need an energy policy that makes sense but it is going to be very difficult to get anything through this Congress. Not because we have a Republican House and a Democratic Senate, but because the deficit debate is going on and resolving that is front and center.”

future, taking the position that the world is going to use more energy as the standard of living in places like India and China continues to go up. He further acknowledged that, while the Macondo well explosion in the Gulf of Mexico was a tragedy, it should be remembered that the oil industry had drilled 14,000 wells before that without incident.

This line of thought led Mr. Klesse to comment that President Obama visited Brazil, a place where deepwater drilling is occurring and more deepwater wells will

Tom O’Malley meets with reporters after his speech at the industry leadership breakfast.

The NPRA’s 109th annual meeting took place in San Antonio, Texas.

HYDROCARBON PROCESSING MAY 2011

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HPIN ASSOCIATIONS for tapping into the US’ strategic petroleum reserve (SPR). The NPRA’s position has always been that it should only be tapped into when there is a supply shortage, which is not the case today.

Using the SPR as a price control mechanism is not good public policy and it is something the NPRA does not support. Mr. Drevna pointed out that even President Obama is against tapping into the SPR. Over capacity. On the subject of the

long term need to reduce overall refining capacity in the US and the world, Mr. Klesse offered a distinctive perspective.

“I believe there is still excess refining capacity in Japan [despite the recent disaster], North America and Western Europe,” he said. “You can tell by looking at operating rates. In the world, refining capacity is going to continue to be built and oil demand is going to continue to increase. In 2020, this is going to be a 95–100 million bpd business.”

As an aside to Mr. Klesse’s remarks, it should be noted that EIA reported that 72.2 million bpd was produced in 2009.

On the subject of refining margins and refinery closures, Mr. Klesse noted that Valero had shuttered a refinery recently and sold it to another company. He pointed out that refineries have been shut down in the US, Canada and Europe.

“When you look at the distribution in these markets, you see refineries that over time cannot compete in this environment,” he said. “Rationalization will continue to occur. However, with a cold winter and refinery upsets in many markets, margins have been better in regional markets. But not all refineries are benefitting in this environment.”

Integrated oil companies. During

an industry breakfast at the event, PBF Energy Chairman Tom O’Malley shared his belief that the era of the integrated oil company has passed.

Mr. O’Malley first entered the industry in 1984 when he purchased Hill Petroleum for $3 million. He noted that, in 1984, the refining industry was dominated by integrated companies both upstream and downstream. For instance, in 1984, integrated companies controlled about 84% of the refining capacity. What is shocking about how much the industry has changed is that, by the end of 2010, 14

I MAY 2011 HydrocarbonProcessing.com

integrated companies controlled only 41% of capacity.

“This is an incredible drop,” Mr. O’Malley said. “But it is clear the era of integration has passed. Integration was developed when you couldn’t sell all your crude. It came out of an era pre-1973 when crude was $2 a barrel and oil companies needed to find a home for their production.”

Mr. O’Malley expects the trend of integrated companies exiting the refining business to continue.

“To some extent, refining has been a lousy business,” Mr. O’Malley said.

“This trend will continue and we will be below 25% integrated companies soon, as merchant refining will gravitate to non-integrated companies. This shift in manufacturing is just specialization; we’ve seen it in every other industry, so why not ours?”

Retail business. Mr. O’Malley said that integrated companies are also leaving the retail business. Is refining and marketing within one company a good business strategy? When he was at Tosco, the company acquired Circle K and ran about 2,500 retail sites and 2,500 branded sites.

“The business at Circle K wasn’t about selling gasoline, it was about convenience,” he said. “The best stores were not operated by oil companies but rather by retailers. The retailers saw gasoline as a necessary part of business, but not their reason for existence.”

The central message is that specialization is the way to go. Mr. O’Malley advises that if a company is in refining it should not go into retail and vice versa.

“We’ve morphed over the past few years from an integrated model to the disintegrated model,” he said. “Specialization is the buy word for the future.”

Rate of return. Investment banks have

tried to calculate rate of return on the HPI for many years, Mr. O’Malley said. His research has revealed that the common rate is 2% per year over the last 20 years, which is not a reasonable investment.

Underscoring the difficulty of being a refiner in this era of razor thin margins, Mr. O’Malley said, “If you buy at the right price and manage your business correctly, you can make money on some, but not all, of the assets in the marketplace. For instance, the Northeast system

[two refineries] we bought from Valero is a heavy system and we believe that the heavy/sour barrel discount is going to work out for us. The synergies between these two plants should allow us to work very well.”

What’s going to happen? According to Mr. O’Malley, the best summary from an analytical point of view was a study by Turner Mason released at the beginning of 2011. In the next 15 years, the study said the world is going to consume another 20 million bpd of oil products. It further clarified that Europe and the US are not a part of the growth factor. There will be a tightening of capacity between now and 2020. It should also be noted that these projections were preJapan earthquake/tsunami, which will certainly enhance oil product consumption worldwide.

Petrochemical Conference. The

week following its annual meeting, the NPRA hosted another conference in San Antonio. The International Petrochemical Conference (IPC) was attended by nearly 2,800 people working in the petrochemical sector from over 45 nations.

“In the United States, prospects for growth and development are strengthened by the potential additional supply of tremendous natural resources right in our own back yard,” Mr. Drevna said in a statement from the IPC. “The natural gas reserves of the Marcellus Shale formation in the northeastern US, the Texas Eagle Ford reserves and the Rocky Mountain formations could sustain and grow not just the petrochemical industry, but manufacturing in general and the American economy as a whole—if they’re developed properly.”

NPRA Petrochemical Committee Chairman Jeff Ramsey, who is senior vice president for refining and chemicals marketing at Flint Hills Resources, also spoke at the opening session. Honn Tudor, senior manager commercial at Total Petrochemicals, presided over the conference.

Outside speakers at the IPC included: Brian Habacivch, senior vice president of Fellon-McCord, an energy consulting and management company; and Fox Business anchor John Stossel. The IPC featured discussions of key governmental, economic and environmental issues affecting petrochemical manufacturing. HP

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HPI recovery underway despite uncertainty Purvin & Gertz recently released its global petroleum market outlook for 2011.

The study provides an analysis of global and regional markets for crude oil and refined products within a framework of world energy demand and economic activity through 2030. The conclusion of the report is that a global economic recovery is well underway, but there are new areas of uncertainty to consider. Political turmoil in the Middle East and North Africa has appeared in the first few months of 2011 and has caused some oil supply disruptions.

A massive earthquake and tsunami devastated northeastern Japan, inflicting painful loss of life and serious damage to nuclear power capacity and other energy infrastructure such as refineries and LNG receiving terminals. These negative factors are counterbalanced somewhat by the return of economic growth in many of the world’s economies and by accelerating crude oil supply in countries outside of OPEC. Key conclusions of this year’s analysis include: • Refined product demand increased by 2 million bpd in 2010 as most economies emerged from the 2009 recession. Demand growth was strongest in Asia, the Middle East and parts of Latin America. The company’s long-term forecast for refined product-demand growth has been updated to reflect the impact of higher long-term crude oil prices and more stringent conservation efforts. The challenge to supply energy to a growing global population of expanding financial means is huge.

• Product demand in non-OECD countries will grow rapidly from the current level of 37.3 million bpd in 2010 to 59.6 million bpd in 2030. Of the expected 22.3 million-bpd increase, China alone is expected to account for 43% of this increase. The combination of Brazil, India, Russia and the broader Middle East will account for almost 30% of the increase.

• Diesel fuel will increase its share of total demand as demand for other fuels grows at a slower pace. Gasoline’s share of demand has been relatively stable for the last 20 years, but is expected to drop in the

OECD countries as higher vehicle efficiency standards propagate through the fleet. However, gasoline demand will still continue to grow in many developing countries.

• Residual fuel oil’s share of demand will decline over the next 10 years as competition with natural gas intensifies in some regions and bunker fuel specifications favor a shift to marine diesel by 2015.

• Despite the large refined product demand increase seen in 2010, a significant oversupply situation currently exists. The requirement to blend increasing volumes of ethanol and biodiesel into products is further adding to the product oversupply situation in the Atlantic Basin. A few weaker refineries have already shut down and more closures are expected. However, the survivors in some markets will have to operate at significantly lower rates until after 2015 unless further capacity rationalization corrects the capacity imbalance.

• Light/heavy price differentials and returns on capital investment declined rapidly in early 2009 as the global economy slowed. A modest recovery in conversion returns was experienced in 2010, but conversion returns are expected to weaken because new capacity will continue to come online in the next few years.

• Worldwide refinery investments to 2020 are expected to cost approximately $275 billion which represents 18% of 2010 replacement costs. Additional investments in the range of $145 billion are expected through 2030.

Small-scale chemistry could improve biodegradable polymers Using a small block of aluminum with a tiny groove carved in it (Fig. 1), a team of researchers from the National Institute of Standards and Technology (NIST) and the Polytechnic Institute of New York University is developing an improved “green chemistry” method for making biodegradable polymers. Their recently published work is a prime example of the value of microfluidics, a technology more commonly associated with inkjet printers and medical diagnostics, to process modeling and development for industrial chemistry.

“We basically developed a microreactor that lets us monitor continuous polymerization using enzymes,” explained Kathryn Beers, a NIST materials scientist. “These enzymes are an alternate green technology for making these types of polymers.

We looked at a polyester, but the processes aren’t really industrially competitive yet.”

Data from the microreactor, a sort of zig-zag channel about a millimeter deep crammed with hundreds of tiny beads, shows how the process could be made much more efficient. The team believes it to be the first example of the observation of polymerization with a solid-supported enzyme in a microreactor.

The group studied the synthesis of PCL, a biodegradable polyester used in applications ranging from medical devices to disposable tableware. PCL, Ms. Beers said, is most commonly synthesized using an organic tin-based catalyst to stitch the base chemical rings together into the long polymer chains. The catalyst is highly toxic, however, and has to be disposed of.

Modern biochemistry has found a more environmentally friendly substitute in an enzyme produced by the yeast strain Candida antartica, Ms. Beers said, but standard batch processes—in which the raw material is dumped into a vat, along with tiny beads that carry the enzyme, and stirred—is too inefficient to be commercially competitive. It also has problems with enzyme residue contaminating and degrading the product.

By contrast, Ms. Beers said, the microreactor is a continuous flow process. The feedstock chemical flows through the narrow channel, around the enzyme-coated beads, and polymerized out the other end.

The arrangement allows precise control

FIG. 1

Typical NIST microreactor plate for studying enzyme-catalyzed polymerization. Photo courtesy of Kundu, NIST.

HYDROCARBON PROCESSING MAY 2011

I 17

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HPIMPACT of temperature and reaction time, so that detailed data on the chemical kinetics of the process can be recorded to develop an accurate model to scale the process.

“The small-scale flow reactor allows us to monitor polymerization and look at the performance recyclability and recovery of these enzymes,” Ms. Beers said. “With this process-engineering approach, we’ve

shown that continuous flow really benefits these reactors. Not only does it dramatically accelerate the rate of reaction, but it improves your ability to recover the enzyme and reduce contamination of the product.”

A forthcoming follow-up paper will present a full kinetic model of the reaction that could serve as the basis for designing an industrial scale process.

US auto industry could boost profits with higher mileage standards

7

Marginal cost per $/gallon saved

While this study focused on a specific type of enzyme-assisted polymer reactions, the authors observe, “it is evident that similar microreactor-based platforms can readily be extended to other systems; for example, high-throughput screening of new enzymes and to processes where continuous flow mode is preferred.”

6 5 4 3 2

2020 CAFE target at 6% annual reduction in greenhouse gas emissions.

1 0 25

30

35

40

45 50 55 CAFE fuel economy, mpg

60

65

70

Source: Meszler Engineering Services

FIG. 2

Marginal fuel economy cost in 2020 by CAFE level.

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As the US ramps up vehicle fuel efficiency standards, new reports from Citi Investment Research, Ceres and longtime independent industry experts conclude that US automakers will be more profitable at a fleet-wide 42 miles per gallon (mpg) average in 2020 (the strictest standard now proposed for that year and one seen as eminently achievable) and that by 2015 more than one in 20 cars sold in the US will be hybrid, plug-in or full electric vehicles (EVs).

The two new reports were produced

by Citi and Ceres’ Investor Network on Climate Risk in conjunction with the University of Michigan Transportation

HYDROCARBON PROCESSING MAY 2011

I 19

HPIMPACT Research Institute, Baum and Associates and Meszler Engineering Services.

Fuel economy. The fuel economy

analysis evaluates the potential impact that changes to the US Corporate Average Fuel Economy (CAFE) and greenhouse gas (GHG) emissions standards may have on the auto industry in 2020. Federal and California state agencies tasked with developing these standards are expected to

send their recommendations to the White House as early as this month.

Stronger mileage and GHG standards will boost variable profits and sales in 2020 for the auto industry worldwide, with the Detroit 3 (General Motors, Ford and Chrysler) seeing the biggest financial benefits. The Detroit 3’s variable profit gains would garner more than half of all increased profits.

The US electric vehicle industry is already robust and viable, and will grow

further under strong standards and other government policies that will boost demand for electric and plug-in electric cars.

The 42-mpg standard by 2020 is consistent with a 6% annual mileage improvement, starting in 2017, that would boost fleet mileage to 62 mpg by 2025 (Fig. 2).

In addition to increasing profits, these goals are eminently achievable technologically and cost-effective.

“Our research indicates that increasing industry average fuel economy to 42 miles per gallon by 2020 could raise industry variable profit by $9.1 billion, or 8%,” said Walter McManus, an economist at the University of Michigan Transportation Research Institute and director of the Automotive Analysis Group.

Savings. Dan Meszler of Meszler Engi-

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neering Services provided estimates of vehicle technology costs and fuel economy impacts for the CAFE study.

“Technology exists to address a number of continuing inefficiencies associated with internal combustion engines,” Mr. Meszler said. “Between now and 2020, much of this technology is expected to mature, so that a 2020 CAFE requirement of 42 mpg should produce consumer savings starting at gas prices of $2 per gallon. Since current and expected future gasoline prices far exceed that price, these technology-driven fuel savings are extremely cost effective and indicate that a 42-mpg CAFE program will not only reduce petroleum imports, but save consumers money.”

In May 2010, President Obama directed the US Environmental Protection Agency and the National Highway Transportation Safety Administration to work with California to develop the next phase of the nationwide CAFE mileage standards and GHG emissions limits for model years 2017–2025. The agencies are considering a range of standards representing an annual decrease in carbon-dioxide (CO2) emissions of 3%–6%, which translates to a range of 47 mpg to 62 mpg in 2025. The agencies’ recommendation appear headed for the White House sometime this month.

Tougher fuel economy standards will have positive implications for sales units and variable profits for the auto industry in general, especially US automakers. The report assumes an industry-wide standard in 2020 of 42 mpg (a 6% improvement per year). Under this scenario, the Detroit 3 could see variable profits jumping 8% globally in 2020 globally. HP

Global Industry Global

Issues Global Leaders

The Place, The Time...

IRPC–ASIA: The Conference Refining and On 19–21 July 2011 Hydrocarbon Processing will host the 2nd Annual International Refining & Petrochemical Conference–Asia. Strategically located in the heart of Southeast Asia’s refining and petrochemical industry, and with easy access from all major refining and petrochemical centers, Singapore is home to IRPC for 2011.

IRPC–Asia will bring together many of the world’s leading experts in refining and petrochemical technologies. Like Hydrocarbon Processing, the two-day, two-track conference and exhibition will focus on presenting leading-edge technology, best practices and solutions for the global hydrocarbon processing industry.

PRELIMINARY PROGRAM (Subject to change) WEDNESDAY, 20 JULY 2011 8:15 – 8:30 OPENING REMARKS: John Royall, President & CEO, Gulf Publishing Company 8:30 – 9:30 KEYNOTE PRESENTATION (TO BE ANNOUNCED) 9:30 – 10:00 REFRESHMENT BREAK 10:00 – 11:30

SESSION 1: SAFETY AND PLANT INTEGRITY

SESSION 2: REFINING PROCESS / PRODUCT DEVELOPMENT

ExxonMobil Transient Hazop Operations Process (TOH)– ExxonMobil

Advanced Trends in Meeting Refinery Hydrogen Needs–Asian focus–Technip

Critical Proactive Considerations for Enhanced Safety of the Next Generation of Refineries and Gas Processing Complexes– Fluor Corporation

Innovative Energy Efficient Way to Debottleneck Vacuum Units with Improved VGO Yield–Indian Oil Corporation

Flare Structure Revamp: A Case History– Reliance Industries Limited

LCO processing solutions / Bottom of the Barrel Conversion Strategies–Axens

11:30 – 13:00 LUNCH, KEYNOTE: REFINERY–PETROCHEMICAL INTEGRATION–Jacobs Consultancy 13:00 – 14:30

SESSION 3: PETROCHEMICAL PROCESSES / PRODUCTS DEVELOPMENTS

SESSION 4: INFORMATION & ASSET MANAGEMENT

Diversification of Feedstock Options for Petrochemicals: Future Road Map– Birla Institute of Technology and Sciences

Process and Mechanical Design Optimization of Heat Exchangers using a CFD Technique: Two Reference Cases– Walter Tosto Spa

Design of Divided Wall Distillation Column– Engineers India Limited

Key Drivers and Trends for Retrofit of High Temperature Reaction Furnaces and Fired Heaters–KTI Corporation

Solutions for Purification of Refinery Sourced C3s Utilized as Feedstock to Petrochemical Processes– UOP, LLC, A Honeywell Company

Utilizing Advanced Simulation Software for Revamping Steam Reformers for Hydrogen Production– Chem Development, Inc. / PFR Engineering System, Inc.

14:30 – 15:00 REFRESHMENT BREAK 15:00 – 16:30

SESSION 5: MARKET TRENDS Renewable Hydrocarbons–Indian Institute of Petroleum, Dehradun Refining Outlook: Capacity Expansion and Rationalization–Muse Stancil (Asia) Challenges and Opportunities in the Growing Asia Pacific Oils Market–Wood MacKenzie 16:30 TECHNICAL CONFERENCE DAY ONE RECEPTION

for the Global Petrochemical Industry Learn About New Technology and Proven Solutions; Meet Global Experts Networking functions will facilitate exchange of ideas, and an environment for meeting peers from around the globe.

Lunches, receptions and coffee breaks will take place at the exhibition. IRPC is a high-level technical and operations focused conference. The structure of the event makes for a productive and enjoyable two days with peers from around the world.

THURSDAY, 21 JULY 2011 8:30 – 8:45 WELCOMING REMARKS: Stephany Romanow, Editor, Hydrocarbon Processing 8:45 – 9:45

SESSION 6: REFINING / PETROCHEMICAL INTEGRATION Refining / Petrochemical Integration–A New Paradigm–GTC Technology Refining / Petrochemical Integration–Panipat Complex of M/s Indian Oil Corporation Ltd.–Indian Oil Corporation Limited 9:45 – 10:15 REFRESHMENT BREAK 10:15 – 11:45

SESSION 7: ENVIRONMENT AND ENERGY EFFICIENCY

SESSION 8: CATALYST TECHNOLOGY: REFINING / PETROCHEMICAL

Impact of Carbon Capture on Oil Sands Development Projects– Worley Parsons, Canada

Jatropha Oil Hydroconversion Kinetics Over Co-Mo / Al2O3 Catalyst–Indian Institute of Petroleum

Comprehensive Energy Optimization in Low Budget Era– Neste Jacobs Oy

Exceed your Hydrocracker Potential using the latest generation Max Diesel Flexible Catalysts–Shell Global Solutions

Adding a third eye towards energy efficiency in Process Industries–Yokogawa Electric International Pte Ltd

Advances in Rare Earth Free Catalysts Provide Cost Savings for Refiners–Grace Davison Refining Technologies

11:45 – 12:45 LUNCH 12:45 – 13:45

SESSION 9: ENVIRONMENT AND ENERGY EFFICIENCY Improving equipment efficiencies in operating plants– Chevron & Rotating Machinery Consultant Achieving Competitive Advantage from Refinery-Wide Business Performance Optimization / Optimizing Refinery Hydrogen Supply, Distribution, Consumption in Real Time–Invensys

SESSION 10: CATALYST TECHNOLOGY: REFINING / PETROCHEMICAL A Case Study in FCC Gasoline Sulfur Reduction for Enhanced Operating Flexibility and a Cleaner Environment– CNOOC, Huizhou Refinery Economic conversion of Natural Oils–Grace Davidson

13:45 – 14:15 REFRESHMENT BREAK 14:15 – 15:15

SESSION 11: INFORMATION & ASSET MANAGEMENT

SESSION 12: REFINING / PETROCHEMICAL INTEGRATION

Sweating the Plant Assets– Jubail United Petrochemical Company, KSA

Refining and Petrochemical Integration Opportunities and Challenges–KBR

Intelligent severity optimization pays off in two months– Sinopec Yangzi Petrochemical Co. Limited

Refining and Petrochemical Integration–Axens

15:15 – 16:15 CONFERENCE KEYNOTE SPEAKER (TO BE ANNOUNCED)

2011 IRPC ADVISORY BOARD: John Baric Licensing Technology Manager Shell Global Solutions International B.V.

Eric Benazzi Marketing Director Axens

Carlos Cabrera President & CEO NICE

Dr. Charles Cameron Head of Research & Technology BP plc

Antonio Di Pasquale Vice President, Refining Product Line Technip

Giacomo Fossataro Technical and Operation Manager Walter Tosto S.p.A.

Dr. Madhukar O. Garg Director Indian Institute of Petroleum in Dehradun

Andrea Gragnani

For registration and lodging information, contact: Gwen Hood, Events Manager for Gulf Publishing Company at +1 (713) 520-4402 / Gwen.Hood@GulfPub.com.

Director, Refining Product Line Technip

James Richardson Director of Southeast Asia Süd Chemie

To register and find out more information, visit www.GulfPub.com/IRPC

Giacomo Rispoli Senior Vice President, Research & Development eni–Refining & Marketing Division

Stephany Romanow Editor Hydrocarbon Processing

Michael Stockle Chief Engineer–Refining Technology Foster Wheeler

For sponsorship and exhibit information, contact: Bill Wageneck, Publisher Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433 E-mail: Bill.Wageneck@GulfPub.com www.HydrocarbonProcessing.com SALES OFFICES—ASIA-PACIFIC

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HPINNOVATIONS SELECTED BY HYDROCARBON PROCESSING EDITORS editorial@gulfpub.com

EYESIM Virtual Reality now available on iPhone and iPad Following the successful launch of the innovative Virtual Reality training system EYESIM, Invensys Operations Management, a global provider of technology systems, software solutions and consulting services to the process and manufacturing industries, takes the next step in further developing this technology. The launch of the iPhone and iPad apps adds true mobility to the EYESIM system, allowing “in the field” access to first-principle simulation and augmented reality. The iPhone and iPad apps were demonstrated publicly for the first time in Europe at the Gastech Conference and Exhibition in Amsterdam this past March.

EYESIM Immersive Virtual Reality is a comprehensive solution linking control room operators to field operators, maintenance operators and other critical team members in their process by means of a high-fidelity process simulation coupled with a virtual walkthrough plant environment. EYESIM provides a complete plant crew training system, capturing best practices, rarely used procedures and other operations, and makes them systems of record for continuous use and refinement.

The introduction of mobile EYESIM extends the usability of the system to iPhone or iPad users, allowing these mobile users to “virtually” be trained on systems, operational procedures and plant environments. The apps are particularly suited to the gas exploration and production industry, where remote and unsafe locations are increasingly the norm.

EYESIM addresses the real-life challenges that face operators and maintenance staff daily, and it is of particular value in the area of safety. EYESIM can be used to rehearse safety procedures with standardized, documented processes; for operator initiation training; updating health and ensure appropriate responses occur to infrequent but safety-critical events; and gaining consistency across operations corporate-wide.

EYESIM captures the inherent value in customer’s worker’s knowledge base, integrating into a comprehensive training program that grows with their needs. Adopting

this model to mobile devices allows “untethered” access to procedures, processes and operational statement of work’s without having to be sitting at a terminal.

Mobile EYESIM is used for classroom training simulating plant experiences. By using mobile EYESIM, instructors and supervisors can monitor dynamically, and in real time, a trainee’s position and behavior in the virtual plant environment through a client application running on an iPhone or iPad. All “touch” facilities are available for a complete user experience. Mobile EYESIM allows workers to more fully experience “real-life” situations through an iPad or iPhone interface, on the plant floor, away from the classroom.

EYESIM Virtual Reality Training enables engineers and operators to navigate the plant in a highly realistic and safe training environment on their iPhone or iPad screens. This application provides a combination of virtual-reality technologies with high-fidelity process and control simulation, computer-based maintenance and documentation management. Maurizio Rovaglio, head of Innovation and Emerging Technologies at Invensys Operations Management, describes the iPhone and iPad application as a mobile station that can be used in conjunction with the main application, enabling younger operators and engineers to connect to the server and enjoy the same training experience as on the main system.

Instructors and supervisors can monitor, in real time the positions and behaviors of trainees within the plant environment through a client application running on an iPhone or iPad being connected to an EYESIM iPhone or iPad server. Instructors and supervisors can interact with virtual reality gas plant operations by opening or closing valves, changing weather conditions or introducing malfunctions, by using the “touch-screen” commands.

Mr. Rovaglio says that, “it is designed to provide complete plant crew training to improve skills that are safety-critical by enabling operators to perform tasks in a simulated environment, allowing them to react quickly and correctly, facilitating reactions in high-stress conditions, and instilling standards for team training and communications.” He went on to explain,

“it can be used to train operators on new systems, as well as train new or younger operators and engineers in a real-time, immersive environment, helping processors and manufacturers retain and replenish the specialized knowledge they need to improve their operations.”

John Gilmore, director of Global Industry Solutions Upstream Oil and Gas at Invensys Operations Management says, “It is extremely costly to put a person into the plant for the purpose of training principally because of the plant size or location. If we could do 80–90% of this training in a virtual environment, we can significantly cut down on cost and risk, avoiding the risk of injury and making mistakes, such as spills and the like due to inexperience.” He also highlighted the significance of such training in hazardous or extreme environments.

The risk to an untrained or a partially trained person in environments such as the Arctic or a sour gas plant, where conditions are extreme due to high pressures and temperatures, can be great; EYESIM provides an ideal solution in these cases.

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XOS installs 1,000th analyzer XOS announced the installation of its 1,000th SINDIE 7039 sulfur analyzer. This analyzer was installed at the Yanshan refinery of the China Petroleum and Chemical Corp. (the Sinopec Corp.). With this milestone, SINDIE analyzers have been sold to hundreds of customers in 33 countries and throughout the US. This announcement builds on XOS’s steady growth in the energy sector.

“From the time that we launched production of the first-generation SINDIE As HP editors, we hear about new products, patents, software, processes, services, etc., that are true industry innovations—a cut above the typical product offerings. This section enables us to highlight these significant developments. For more information from these companies, please go to our website at www.HydrocarbonProcessing.com/rs and select the reader service number.

HYDROCARBON PROCESSING MAY 2011

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HPINNOVATIONS analyzer to the shipment of this 1,000th unit, the SINDIE product line has earned a reputation as an indispensable analytical instrument for today’s energy companies,” said Berry Beumer, vice president of sales and marketing at XOS. “This latest milestone affirms XOS’s commitment to leading-edge technology solutions that address analytical challenges that support the success and productivity of the global energy sector.” SINDIE analyzers help XOS’s customers accurately monitor sulfur content within such diverse fuels as crude, biofuels, gasoline and ultra-low-sulfur diesel (ULSD).

SINDIE offers a measurement technique based on monochromatic wavelength dispersive X-ray fluorescence (MWDXRF).

The practical application of this technology in the SINDIE product line enables energy and transportation companies to meet clean-air mandates enforced by global regulators. In turn, this reduces sulfur-oxide exhaust emissions that are responsible for producing acid rain and causing adverse health and environmental conditions.

Sinopec received recognition of this milestone at its refinery in Yanshan,

China. Sinopec executives responded to the milestone by issuing the following statement: “We are very proud of becoming the 1,000th user of the monochromatic wavelength x-ray fluorescence sulfur analyzer made by XOS. The analyzer has demonstrated significant performance advantages over other commonly used methods, such as coulometry, UV fluorescence, and conventional x-ray fluorescence. These advantages include high detection precision, high analysis speed, ease-of-use, high stability, and low maintenance. The analyzer has received wide acclaim from operators and technical staff during the course of operation. In particular, the refinery division of Sinopec Yanhua Co. recently received high-octane fuel components, that required high-analysis precision and speed. The XOS sulfur analyzer demonstrated excellent performance during the analysis process, and it made a heroic contribution in successfully completing the factory quality assurance analysis. Please let us thank XOS and its distributor in China, Phase Analytical Solutions, for providing us with an analyzer of outstanding performance.”

In a related development, Phase Analytical Solutions was given XOS’s Asia Distributor of the Year Award in recognition of Phase’s outstanding customer and technical support in the China market.

Other features of XOS’s SINDIE product line that make this milestone significant include: • It serves diverse market segments such as petroleum production, refining, and distribution; petrochemicals; biofuels; enforcement; independent testing; and power generation.

• End-users include refinery labs, pipeline and marine terminal operators, enforcement authorities, and third-party test labs.

• XOS spearheaded the ASTM D-7039 standard development covering the SINDIE measurement method, and the company maintains the task group chair for measuring sulfur in fuels.

• Regulators worldwide recognized D-7039 for the purpose of certifying sulfur in fuels.

• A portable version of the SINDIE benchtop analyzer—SINDIE On-The-Go (OTG)—received Instrument Business

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R&D contract provides protection against excavations Magal Security Systems, Ltd., received a contract from a research organization, associated with a large US gas utility, to enhance the capabilities of its PipeGuard system–a sophisticated system (Fig. 1), developed by Magal, that warns and protects against excavations.

The research organization has evaluated various technologies for mitigating and proactively alerting personnel when excavations are occurring in the vicinity of buried gas pipes, to enable effective and early response for prevention of potentially hazardous and catastrophic events. The rigorous testing included the ability to distinguish between various types of excavation equipment in the proximity of pipelines, particularly in noisy environments such as busy highways.

The PipeGuard system has so far shown to be the most promising technology; with the contracted improvements it should pro-

vide a cost-effective solution for the proactive monitoring of pipelines to prevent third-party damage.

Hagai Katz, senior vice president of marketing and business development, Magal S3, commented: “Historically, this system was designed to protect long-distance pipelines against terrorist and criminal activity. Contractors all over the world are inadvertently digging or drilling into gas pipes, disrupting service, risking lives and also cause environmental catastrophes.

“Our distributed-system layout covers dispersed risk areas and is the perfect solution for this challenge. This financed development agreement is an excellent opportunity to develop the product for this important application and make it the preferred choice. This is an important step in our corporate strategy to supply sophisticated sensors and solutions beyond our traditional security market; in this case, it is to preserve outdoor safety and green ecology.”

PipeGuard is a sophisticated, patentpending sub-surface intrusion detection system for underground asset protection. Based on state-of-the-art geophone

technology, PipeGuard offers a unique solution for the protection of pipelines, communication lines, prisons and even bank vaults, from terrorism, theft and inadvertent third party-damage. Multiple PipeGuard sensor units are typically interconnected through a wireless or cellular mesh network and alarms are displayed on a geospatial map.

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FIG. 1

Magal S3 Pipe Guard system.

The new CP valve for small pocket, high speed compression.

Outlook’s 2009 Industrial Design Award for portable instruments.

HYDROCARBON PROCESSING MAY 2011

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HPINNOVATIONS Flowmeter offers small foot print and reduced installation costs Process engineers responsible for crude oil production from wells that employ gas lift systems to increase oil production will find that the rugged, highly accurate V-Cone flowmeter (Fig. 2) from McCrometer features a wide turndown, a small footprint and virtually no maintenance, reducing total installed costs and operating life cycle costs while improving crude oil production efficiency.

Gas lift systems employed for enhanced oil recovery (EOR) increase crude oil production by injecting gas into the well bore casing, reducing the oil density being produced. The injected gas mixes with the oil in the casing and the low reservoir pressure in the formation is then sufficient to allow production without the need for pumps.

Some oil wells produce natural gas that is separated from the oil stream once it reaches the surface. The well operator then re-injects a portion of this byproduct gas, thus maximizing production from the well.

Carbon dioxide, nitrogen or engineered chemical solutions can also be employed in gas-lift wells.

McCrometer’s V-Cone flowmeters feature accuracy of ±0.5% of rate and repeatability of ±0.1%, ensuring accurate measurement and control of the injected media.

With its no-moving parts design, the V-Cone flowmeter is proven to remain accurate in installations for 25 years or more in the toughest of applications, all but eliminating the need to shut down production for calibrations, inspections, or regular replacement of the primary element, saving not only through production up-time, but also in parts and labor.

FIG. 2

28

Gas-lift well.

I MAY 2011 HydrocarbonProcessing.com

McCrometer’s differential-pressure V-Cone flowmeter provides built-in flow conditioning, which nearly eliminates the upstream and downstream straight pipe runs required by other flowmeter technologies, reducing typical straight pipe run by 70% or more requiring only 0–3 straight pipe diameters upstream and 0–1 downstream for precise operation.

Engineers in the oil/gas industry rely on the versatility of McCrometer’s V-Cone flowmeter available in line sizes from 0.5 in. to greater than 120 in. in materials and flanges compatible with any application.

The flowmeter operates over a wide flow range of 10:1, which typically covers the entire flow range required for injection in gas-lift applications.

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CO2 removal technology reduces compression cost The Japanese companies JGC Corporation and INPEX Corporation, jointly with BASF SE, have successfully completed tests of a new technology for the removal of carbon dioxide (CO2) from natural gas under high pressure. The performance of this new gas treatment technology enables a reduction of 25% to 35% in the cost of CO2 recovery and compression.

The so-called “High Pressure Acidgas Capture Technology” (HiPACT) was developed by JGC and BASF. The tests of the technology commenced in August 2010, at INPEX’s Koshijihara natural gas plant in Nagaoka, Japan. “We greatly appreciate the involvement of INPEX, allowing us to test the new technology in a commercial natural gas plant. Targeting demand in the market, we successfully demonstrated an excellent energy saving performance,” said Mr. Yasuda, executive officer and senior general manager of the research and development Division at JGC. “INPEX strives to reduce energy consumption as much as possible. This new technology offers a great opportunity to improve energy conservation. It also reduces our carbon footprint and helps curb greenhouse gas emissions,” added Mr. Yamamoto, executive officer and vice president of the technical division.

“This test was a critical milestone in the commercialization of a new technology for which the market has been looking for some time,” said Dr. Northemann, head of the Gas Treatment Solutions business unit within BASF’s Intermediates division.

Saving energy in the removal of CO2.

Natural gas, an increasingly important source of energy, often contains CO2 when it is extracted from the well. Most of this CO2 is usually removed directly at the natural-gas source. The removal is achieved by means of an amine-based solvent developed by BASF. The solvent temporarily absorbs the CO2 from the high-pressure natural gas-stream. The solvent is then regenerated at low pressure and fed back to the process, but this regeneration requires energy. Traditionally the CO2 released in the regeneration process has been emitted to the environment.

Alternatively, the CO2 can be injected underground for storage after separation from the natural gas. To do that the CO2 must first be compressed above its high pressure. This has, to date, required an additional high energy input, which the new process can reduce significantly. The process uses a solvent that is not affected by high pressure levels and elevated temperatures during regeneration, so it remains stable and intact during the capture process. Thus, the new technology can be operated at a higher pressure. This reduces the cost of compressing the CO2 for underground re-injection. Moreover, the solvent, which has an excellent CO2 absorption capability compared to the existing solvents, enables reduction of the solvent regeneration energy.

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New alliance in process analyzer industry Metrohm, trusted for laboratory analysis systems, and Applikon, revered for accurate and dependable process analyzers, have joined forces to bring the best of both brands to the process analytical industry.

This Metrohm-Applikon alliance unites process technology with the precision of laboratory instrumentation to offer rugged systems that meet the demands of modern process plants. At-line and online analyzers feature automated sample preparation and continuous monitoring technology — which are integrated seamlessly into any process setup. In addition, each analyzer is customized to meet the exact needs of its environment. Metrohm-Applikon also complement each other’s support offering, and their alliance now brings full application and product support to both the laboratory and process floor.

Select 6 at www.HydrocarbonProcessing.com/RS

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EBARA CORPORATION

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HPIN CONSTRUCTION HELEN MECHE, ASSOCIATE EDITOR HM@HydrocarbonProcessing.com

North America Chevron Phillips Chemical Co., LP, is advancing a feasibility study to construct a world-scale ethane cracker and ethylene derivatives at one of its existing facilities in the US Gulf Coast region. The new facility would use the advantaged feed sources expected from development of shale-gas reserves. According to Tim Taylor, COO for Chevron Phillips Chemical, the company is finalizing its evaluation of potential sites and advancing discussions with engineering, procurement and construction contractors. The feasibility study is expected to be complete by the end of 2011.

Valero Energy Corp. plans to expand crude-unit capacity at its McKee, Texas, refinery by 25,000 bpd. The refinery will process West Texas Intermediate crude oil from Midland, Texas, to feed the increased charge rate. The expansion project, which will take place over the next three years, will increase the amount of crude oil available to be processed at the McKee refinery to 195,000 bpd.

The expansion plans follow the previously announced Panhandle crude-gathering system expansion project, which is nearing completion. That project involves looping an existing pipeline from Valero’s storage facility in Perryton, Texas, as well as building additional pump stations and storage facilities to bring more locally produced crude to the McKee refinery.

Merichem Co. has entered into a licensing and equipment-supply agreement with a leading midstream energy-services provider to install a LO-CAT hydrogen sulfide (H2S) treatment system at its shale gas-treating facility in Louisiana. The 6.93-metric-tpd LO-CAT unit, provided through the Merichem Gas Technologies business unit, will be integrated into the overall processing facility, with a proposed startup date during the fourth quarter of 2011.

The LO-CAT unit will be treating 34.6 million scfd of amine acid gas with an H2S removal efficiency of 99.9%, far exceeding current environmental standards. This will be the second LO-CAT system to be installed in the Haynesville Shale play for this client, and the third LO-CAT unit to be

installed in the Haynesville play. LO-CAT is becoming recognized as the sulfur recovery system of choice for the shale gas industry.

CB&I has been awarded a contract by Imperial Oil Resources for engineering, procurement and construction (EPC) work on the Kearl oil sands project in Alberta, Canada. The value of CB&I’s work scope is in excess of $900 million. This includes $500 million of incremental work releases booked prior to 2011. CB&I will be responsible for the EPC execution of the bitumen extraction plant and tank farms, as well as the design, supply and construction of additional storage vessels. Completion is expected in the third quarter of 2012.

Due to the hydrotreater’s large capacity, the project will include two trains with four hydrotreating reactors in total. They will produce ultra-low-sulfur diesel containing less than 10 wt ppm of sulfur.

The diesel hydrotreater is part of an optimization project in PDVSA’s largest refining complex in Paraguana, Falcon State.

Haldor Topsøe will supply an engineering design package for the hydrotreaters. The scope of supply includes design of the reactors, basic engineering and catalysts, and detailed design of the proprietary reactor internals. Erection of the unit is expected to commence in 2014, and PDVSA expects to begin production by the end of 2015.

Europe South America Braskem-Idesa, the joint venture between Braskem and Idesa, has taken another important step in developing its Ethylene XXI project in Mexico. The JV has chosen Technip as the technology provider for its 1,050-kiloton/yr ethylene cracker based on ethane. This is part of the petrochemical complex to be built in Coatzacoalcos/Nanchital region, in the Mexican state of Veracruz, and it is planned to be ready for startup by the end of 2014. The complex will also include one low-density polyethylene plant and two high-density polyethylene plants.

Braskem-Idesa has also selected Technip as contractor for the front-end engineering design (FEED) of the cracker and high-density polyethylene plants. Technip’s operating centers in Rome, Italy, and in Claremont, California, will execute the ethylene plant’s FEED activities, while the activities related to the FEED for the high-density polyethylene units will be executed by Technip’s office in Lyon, France. The overall FEED activities are scheduled to be completed at the end of 2011.

Petróleos de Venezuela, S.A. (PDVSA) and Haldor Topsøe have signed a contract for the Centro de Refinación Paraguaná project. The contract includes an 85,000-bpsd hydrotreating unit. This will reportedly be the biggest ever designed by Haldor Topsøe, and the capacity will correspond to about half of Denmark’s daily consumption of oil.

Uhde has begun construction of what is said to be its first-ever skid-mounted chlor-alkali electrolysis plant in Leuna, Germany. Leuna-Harze GmbH, one of Europe’s leading producers of epoxy resin, awarded Uhde the contract to build a turnkey membrane electrolysis plant with a production capacity of 15,000 tpy of chlorine.

Commissioning is planned for mid-2012.

Uhde’s scope of services includes the process licence, design and engineering, procurement, construction work and commissioning support. This, reportedly the world’s first skid-mounted chlor-alkali electrolysis plant, is to be successfully implemented for the first time in Ger-

Trend analysis forecasting Hydrocarbon Processing maintains an extensive database of historical HPI project information. The Boxscore Database is a 35-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc. Many companies use the historical data for trending or sales forecasting.

The historical information is available in comma-delimited or Excel® and can be custom sorted to suit your needs. The cost depends on the size and complexity of the sort requested.

You can focus on a narrow request, such as the history of a particular type of project, or you can obtain the entire 35-year Boxscore database or portions thereof. Simply send a clear description of the data needed and receive a prompt cost quotation.

Contact: Drew Combs P.O. Box 2608, Houston, Texas, 77252-2608 713-520-4409 • Drew.Combs@GulfPub.com HYDROCARBON PROCESSING MAY 2011

I 31

HPIN CONSTRUCTION Neste Oil celebrates the grand opening of its ISCC-certified renewable diesel plant in Singapore Neste Oil with Singapore’s Deputy Prime Minister and Minister for Defence, Mr. Teo Chee Hean; Finnish Minister for Ownership Steering, Mr. Jyri Häkämies; and some 200 guests celebrated the grand opening of its renewable diesel plant in Singapore on March 8, 2011 (Fig. 1). The startup of the Singapore plant took place in November 2010, and production at the world’s largest renewable diesel plant has run smoothly ever since. Neste Oil’s Singapore plant was completed on schedule and on budget, and marks a major step forward in Neste Oil’s cleaner traffic strategy. The plant produces premium-quality NExBTL renewable diesel, which is the most advanced and cleanest diesel fuel on the market today.

FIG. 1

32

Opening ceremony in which (from left) Managing Director of Neste Oil Singapore Pte Ltd., Mr. Petri Jokinen; Finnish Minister for Ownership Steering, Mr. Jyri Häkämies; Singapore’s Deputy Prime Minister and Minister for Defence, Mr. Teo Chee Hean; as well as Neste Oil’s President and CEO Mr. Matti Lievonen cut the ribbon together.

I MAY 2011 HydrocarbonProcessing.com

“Only two years ago, we were here to lay the cornerstone of our renewable diesel plan. The rather empty piece of land has since been turned into the world’s biggest renewable diesel plant.

As a location, Singapore has fulfilled all our expectations. It is the world’s third-largest center of oil refining, and occupies a central location in terms of product and feedstock flows, as well as logistics. Talent pool in Singapore is absolutely first-class.

The government of Singapore has played an important role in promoting Neste Oil’s investment, and the Singapore Economic Development Board has assisted Neste Oil at every stage of the project,” said Matti Lievonen, president and CEO of Neste Oil. The plant has a capacity of 800,000 metric tpy, and cost around €550 million to build. It uses a variety of renewable feedstocks to produce NExBTL, including palm oil and sidestream products of palm-oil production from Indonesia and Malaysia, as well as waste animal fat from Australia and New Zealand. The plant employs approximately 120 people, the majority of which are from Singapore and the nearby countries. The construction project has required close to 14 million man-hours of work from employees and contractors from 13 countries. At peak times, the number of workers at the construction site reached almost 5,000. Before any work aboveground started, over 300 km of piles were put into the ground to prepare the site for heavy structures. Later on, more than 90 km of pipe work was installed. Furthermore, as calculated from the start of the project, the total recordable injury frequency per million hours worked was less than one, clearly below the global safety averages of the industry.

Neste Oil has a similar-sized facility under construction in Rotterdam, The Netherlands, which is due to be commissioned in mid-2011. The company already operates two renewable diesel plants that came onstream at Porvoo in Finland in 2007

HPIN CONSTRUCTION and 2009 with a combined capacity of 380,000 metric tpy. After the startup of Rotterdam plant, the production capacity of Neste Oil’s renewable diesel plants totals approximately 2 million metric tons annually. The main markets for NExBTL diesel are Europe and North America.

Singapore refinery to receive ISCC certification.

At the end of January 2011, Neste Oil’s Singapore refinery was International Sustainability and Carbon Certification (ISCC) certified. More specifically, the certificate confirms that NExBTL renewable diesel produced at the Singapore refinery from certified raw materials, such as from ISCC certified palm oil, meets the strict sustainability criteria based on the EU’s renewable energy directive (RED) and is suitable for meeting biocontent mandates on the German market. The ISCC system, specific to the German market, is approved by the German Federal Office of Agriculture and Food (BLE). Neste Oil’s Porvoo refinery in Finland has already been ISCC certified in November 2010.

“Although the ISCC certification is specific to the German market, it reinforces Neste Oil’s sustainability commitment and offers third-party verification for the sustainability of our production chain and our NExBTL renewable diesel,” Lievonen added.

Singapore plant—the world’s largest and most advanced renewable diesel facility Neste Oil’s Singapore renewable diesel plant facility marks a major step forward for the company’s clean-traffic-fuel strategy.

Renewable fuels business is an important part of Neste Oil’s strategy; with the startup of the Singapore plant, Neste Oil is regarded as the world’s leading producer of renewable diesel.

With its premium-quality product and increasing production capacity, Neste Oil, as an industry pioneer, aims at meeting the world’s growing energy needs and demand for cleaner, bio-based fuels.

Highlights of the Singapore NExBTL project

• World’s largest renewable diesel plant; Neste Oil’s third NExBTL renewable diesel plant • Based on Neste Oil’s own proprietary NExBTL technology • Located in an industrial area of Tuas, in the south-western part of Singapore, approximately 40 km from the city center • Annual production capacity of 800,000 metric tons (or 1 billion liters) of NExBTL renewable diesel. This annual volume is enough for 10 million cars to run continuously with a 10% NExBTL blend.

• Operational since November 2010; completed on budget and on schedule at a cost of approximately €550 million • Employs approximately 120 persons; approximately 90% of employees are from Singapore or neighboring countries.

• All feedstock used at the plant are fully sustainable and traceable: palm oil, stearin and palm fatty acid distillate (PFAD) from Southeast Asia, as well as animal fat from Australia and New Zealand • The main markets for NExBTL diesel are Europe and North America, later possibly also Asia.

• Singapore refinery received ISCC certification on Jan. 20, 2011. The certificate confirms that NExBTL diesel produced from certified raw materials is suitable for use in meeting mandated bio-content on the German market. The ISCC system, specific to the German market, is the first standard for sustainability based on the EU’s new renewable energy directive (RED). It is approved by the German Federal Office of Agriculture and Food (BLE). Also, Neste Oil’s Porvoo refinery has been ISCC certified.

• Led by Managing Director Petri Jokinen. In addition to the NExBTL plant, Neste Oil also has a commercial office in central Singapore.

• Neste Oil has a similar-sized facility under construction in Rotterdam, which is due to be commissioned in mid-2011.

The company already operates two renewable diesel plants that came onstream at Porvoo, Finland, in 2007 and 2009, with a combined capacity of 380,000 metric tpy. HP

HYDROCARBON PROCESSING MAY 2011

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HPIN CONSTRUCTION many. The concept was developed by AkzoNobel, UHDENORA and Uhde.

CB&I has been selected by Yamal LNG LLC to provide front-end engineering and design (FEED) services for the Yamal LNG project. The work is scheduled for completion in the first quarter of 2012. The Yamal LNG project consists of the production, treatment, transportation, liquefaction and shipping of natural gas and natural

gas liquids (NGL) from the South Tambey field on the Yamal Peninsula in Northern Siberia, Russia.

CB&I’s project scope includes FEED development for the 16.5 million-tpy LNG liquefaction plant, including LNG storage and loading facilities. CB&I’s FEED execution plan is based on engaging its international partners—Chiyoda and Saipem, as well as collaboration with the Russian Design Institute, NIPIgazpererabotka, to

address local design and authority approval requirements. The FEED will provide a firm basis for the detailed engineering, procurement and construction phase, as well as project schedule and cost estimates to enable Yamal LNG to secure the final investment decision. The value of the contract was not disclosed.

Foster Wheeler AG’s Global Engineering and Construction Group has been awarded a contract by JSC NovoUfimsky Refinery, a subsidiary of Russian oil company Bashneft, for the engineering and material supply of a new Terrace Wall steam reformer heater and air preheating system for the Ufa refinery in the Republic of Bashkortostan, Russia. The steam reformer will be part of the 420-tpd hydrogen production unit being built by the JSC Novo-Ufimsky refinery and will reportedly be one of the largest steam Terrace Wall reformers for hydrogen ever built

by Foster Wheeler.

The plant is based on Foster Wheeler’s hydrogen technology and process-design package. Foster Wheeler’s scope of work is scheduled to be completed in mid-2012.

The balance of the hydrogen plant engineering and construction will be undertaken directly by the client.

Middle East

This bench top analyzer tops all others in its price range for features and performance. It’s equipped with an intuitive user interface, full-color touch screen and on-board Windows XP computer. Ethernet electronics that permit remote access for calibration, diagnostics or service support. Plus, the Phoenix II has a large sample compartment that accommodates spinners and special holders yet requires little or no sample preparation.

It all adds up to the lowest cost of ownership, backed by AMETEK’s reputation for reliability and world class customer support. Visit: ametekpi.com

Neste Oil and Abu Dhabi National Oil Co. (ADNOC) have a partnership concerning very high-viscosity index (VHVI) base oils. Along with the cooperation, 600,000 metric tpy of NEXBASE base oil is expected to be brought onto the market at the end of 2013. Takreer, a subsidiary of ADNOC, will supply the feedstock, as well as operate and maintain the plant, while Neste Oil will be responsible for the sales and marketing of the base oil on behalf of ADNOC. There will be no investment costs for Neste Oil related to this activity.

The plant is based on ExxonMobil Research and Engineering’s hydroisomerization technology and Neste Jacobs’ distillation technology. It will have a capacity of 500,000 metric tpy of Group III base oil to be used in blending top-tier lubricants, as well as 100,000 metric tons of Group II base oil. Commercial production is expected to start at the end of 2013.

KBR has been awarded a contract by Saudi Aramco Lubricating Oil Refining Co. (Luberef ) to implement KBR’s propri-

34

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www.costacurta.it

HPIN CONSTRUCTION etary solvent deasphalting (SDA) technology, ROSE, for Luberef ’s Yanbu Refinery Expansion Project in Saudi Arabia. Under the contract, KBR will provide technology licensing and basic engineering services to revamp and almost double the capacity of Luberef ’s existing propane-deasphalting (PDA) unit. The existing PDA unit, which is based on conventional SDA technology, will be converted to KBR’s ROSE technology. In addition to increasing production volumes, the PDA revamp will allow Luberef to increase brightstock and byproduct production.

A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group, along with the subsidiary’s consortium partners comprising A. Al-Saihati, A. Fattani and O. Al-Othman Consulting Engineering Co. (SOFCON) and Saudi Consolidated Engineering Co.–Khatib & Alami (SCEC K&A) have signed a contract with Saudi Aramco for the provision of services associated with Saudi Aramco’s GES+ initiative for a duration of five years, with options available for extensions.

Under contract terms, Foster Wheeler and its consortium partners will perform engineering and project-management services including pre-front-end engineering design (pre-FEED), FEED, detailed design and procurement services for onshore/offshore oil and gas, refining, petrochemicals and associated infrastructure projects in Saudi Arabia. The work will be executed from the consortium’s offices located in the city of Al-Khobar in the Kingdom of Saudi Arabia.

Jacobs Engineering Group Inc. has received an award from the Jubail Chemical Industrial Co., Ltd. (JANA) to provide technical and project-management services for its existing epichlorohydrin plant expansion and a new epichlorohydrin plant at the Jubail, Saudi Arabia, site.

JANA is a wholly owned subsidiary of NAMA Chemicals.

Under the agreement, Jacobs is providing technical and project-management services for both inside battery limits (ISBL) and outside battery limits (OSBL). The ISBL services involve debottlenecking of their existing epichlorohydrin plant to increase capacity, and the OSBL services cover all utilities and the tankage area.

Jacobs’ scope also includes cost-estimate preparation and project-management support for JANA’s new epichlorohydrin 36

I MAY 2011 HydrocarbonProcessing.com

plant, to be built at the same site in Jubail.

This expansion is intended to increase the Jubail site’s epoxy resins production capacity to 240 kiloton/yr.

Qatar Petroleum (QP) and Shell have announced the first flow of dedicated offshore gas into the Pearl gas-to-liquids (GTL) plant located in Ras Laffan Industrial City in the State of Qatar. Shell, the operator of the Pearl GTL plant, developed under a production and sharing agreement with QP, has opened natural gas wells offshore, allowing the first sour gas to flow through a subsea pipeline into the giant GTL plant onshore. Sections of the Pearl GTL plant will be started up progressively over the coming months.

Once fully operational, Pearl will produce 1.6 Bcfd of gas from the North Field, which will be processed to generate 120,000 bpd of condensate and natural gas liquids and 140,000 bpd of GTL products.

Egypt Japan Petrochemical Corp.

S.A.E. (EJPC) and Davy Process Technology Ltd., a wholly owned subsidiary of Johnson Matthey Plc (JM), have signed a methanol operating license agreement.

EJPC is developing a world-scale combined methanol and ammonia project comprising a 6,000-metric-tpd methanol plant that will use Davy’s technology, and a 2,000-metric-tpd ammonia plant (the Project).

The methanol plant, which will use steam reforming of natural gas in conjunction with the advanced methanol synthesis process developed and licensed by Davy and JM, will reportedly be the largest methanol plant in the world. The hydrogen-rich purge gas from the methanol loop will be used in the integrated ammonia plant. This project is a key component in the development of Carbon Holdings’ petrochemicals business, with construction scheduled to commence in 2012.

Alfa Laval has received an order for delivery of Alfa Laval Packinox heat exchangers to a refinery in Saudi Arabia.

The order value is about SEK 75 million and delivery is scheduled for 2012. The Packinox heat exchangers will be used in a catalytic reforming unit for producing gasoline. Last year, half of Alfa Laval’s big orders came from refineries and the vast majority of these included Alfa Laval Packinox heat exchangers.

Asia-Pacific Fluor Offshore Solutions, a unit of Fluor Corp., has been awarded a front-end engineering and design (FEED) contract by Woodside for the Browse liquefied natural gas (LNG) development. The Browse fields are located in the Browse Basin about 425 km north of Broome off the western coast of Australia. Fluor will be responsible for the offshore central gas-processing facility’s FEED services including the steel jackets, a compression platform and a utilities accommodation platform. Fluor has teamed with McDermott International, Inc., to design the steel jackets and floatover installation.

Fluor will staff the FEED with more than 150 offshore experts from its Perth, Houston and Manila offices, and the FEED is expected to be completed in late 2011.

The Browse joint venture is scheduled to take a final investment in mid-2012.

INVISTA plans to construct a manufacturing facility at the Shanghai Chemical Industry Park in China to meet the region’s demand for nylon 6,6 intermediates and polymer. The company is engaged in project engineering, which will include an environmental impact assessment to be completed by the end of 2011.

INVISTA expects to begin plant construction in 2012 and commence production in phases beginning in 2014. When the new plant is complete, it will reportedly be the most energy-efficient and technologically advanced nylon intermediates plant in the world. Using INVISTA’s latest advances in its proprietary butadienebased technology, the state-of-the-art plant will produce hexamethylene diamine (HMD) and adiponitrile (ADN), along with various specialty chemicals and nylon 6,6 polymer.

Bayer MaterialScience has inaugurated a manufacturing facility for polyisocyanates at Ankleshwar, in the state of Gujarat, India. With the investment of approximately €20 million, the company wants to expand its business in India and to participate in the strong growth of this local market for coatings and adhesives.

The plant will produce Desmodur N grades based on aliphatic hexamethylene diisocyanate (HDI). The initial capacity amounts to 15,000 tpy. It will be increased in stages in the coming years in accordance with the predicted growth for polyurethane coatings and adhesives.

HPIN CONSTRUCTION KBR has been awarded a contract

by Inner Mongolia Connell Chemical Industry Co., Ltd. (Connell) to provide licensing, basic engineering and related training and field services for its grassroots aniline plant in TongLiao, Inner Mongolia Province, China.

The aniline technology is offered by KBR through a licensing alliance with DuPont. KBR will license the leading process for Connell’s 360,000-metric-tpy aniline plant. This follows an award of the aniline technology to KBR earlier in 2010 by Connell for its 150,000-metric-tpy plant in Jilin City, China.

Basic engineering of the unit, which will include the UOP Pacol, UOP DeFine and UOP Detergent Alkylation processes, is underway, and the project is expected to come onstream in the second quarter of 2012.

Foster Wheeler AG’s Global Engineering and Construction Group has received a contract from Huntsman (Europe) BVBA to undertake the front-end engi-

neering design (FEED) for the expansion of Huntsman’s Isocyanates facility at Caojing, in Shanghai, People’s Republic of China.

Foster Wheeler’s scope will include frontend engineering, technology licensor management and development of the project schedule and cost estimates. The project’s FEED phase is scheduled for completion in the third quarter of 2011, with the overall project scheduled for mechanical completion by the fourth quarter of 2013. HP

BASF and PETRONAS will commence a feasibility study for a new plant for superabsorbent polymers. The companies are also looking into the expansion of the existing production capacities of their joint venture BASF PETRONAS Chemicals Sdn Bhd. The new investment will be part of BASF PETRONAS Chemicals Sdn Bhd, founded by BASF and PETRONAS in 1997. The company operates an integrated complex situated at the Gebeng Industrial Zone, Pahang. The company’s share of capital is 60% held by BASF and 40% by PETRONAS with a total investment of about RM3.4 billion for production facilities for acrylic monomers, oxo products and butanediol.

Siemens Energy has received an order for the supply of up to 10 compressor trains to Australia Pacific LNG (APLNG) in Queensland, Australia. APLNG is a joint venture between Origin Energy and ConocoPhillips. The APLNG project will involve developing coal-seam gas fields in south-central Queensland over a 30-year period and includes construction of upstream gas-gathering and processing facilities, together with a 450-km main transmission pipeline from the gas fields to the liquefied natural gas (LNG) facility being built on Curtis Island near Gladstone.

The technology of UOP LLC, a Honeywell company, has been selected by Great Orient Chemical for a new petrochemicals complex in China that will produce key ingredient for biodegradable household laundry detergents. Great Orient Chemical expects the new complex to produce up to 100,000 metric tpy of linear alkylbenzene (LAB).

Select 156 at www.HydrocarbonProcessing.com/RS

37

HPI CONSTRUCTION BOXSCORE UPDATE Company

City

Plant Site

Project

Capacity Unit Cost Status Yr Cmpl Licensor

Sonatrach Egyptian Methanex SAMIR Qatar Petroleum

Tiaret Damietta Mohammedia Skhira

Tiaret Damietta Mohammedia Skhira

Refinery Methanol Treater, Kerosine Refinery

Chang Zhou Cheml Co UPC Technology Corp Risun Chemical Co UPC Technology Corp Nagarjuna Oil Corp Ltd Mangalore Rfg & Petrochemicals Lotte Daesan Petrochemical BASF Petronas Chemicals Samsung Eng CPC Corp

Chongqing Liaoyang Tangshan Zhuhai Cuddalore Mangalore Banten Kuantan Yeosu Talin

Chongqing Liaoyang Tangshan Zhuhai Cuddalore Mangalore Baten Kuantan Yeosu Talin

MDI Butanediol Epichlorohydrin Malic Acid Sulfur Recovery Unit Treater, Tail Gas (1) Petrochemical Complex Polymers BTX Cracker, FCC-Resid

Neste Oil Hellenic Petroleum SA AGIP KCO Neste Oil Yamal LNG LLC Petronor

Naantali Elefsina Kashagan Rotterdam Yamal Muskiz

Naantali Elefsina Kashagan Field Rotterdam Yamal Muskiz

Maintenance Turnaround Hydrocracker, LP Sulfur Recovery (1) Renewable Diesel LNG Storage Sulfur (2)

La Plata Minatitlan Paraguana

La Plata Minatitlan Paraguana

Desalter, Crude Sulfur Recovery (4) Hydrotreater, Diesel

Sitra Baghdad Mesaieed Yanbu Ruwais

Sitra Baghdad Al Shaheen Yanbu Ruwais

VHVI (Very High Viscosity Index) Crude oil pumping station RE Scrubber Refinery Polyethylene, LD

400 kty 2.5 Mtpy None 400 Mbpd 350 Mtpy

Bakersfield Durango Pascagoula Gallup Mandan Toledo Tulsa Houston Logansport

Kern Refinery Durango Pascagoula Gallup Mandan Toledo Tulsa Houston Logansport

Refinery Amine Unit Desalter, Crude Scrubber Refinery Refinery Benzene Reduction Chlorine Cryogenic Gas Plant

120 50 11 78 170 25 250 120

Engineering

Constructor

Techint Tecnicas Reunidas

Technip|CB&I|Saipem|Chiyoda|Sinopec Techint Tecnicas Reunidas

AFRICA Algeria Egypt Morocco Tunisia

300 6000 600 150

bpd m-tpd t/a bbl

6000 F 2014 P 2012 Davy Process|JM E 2012 UOP 6300 A

ASIA/PACIFIC China China China China India India Indonesia Malaysia South Korea Taiwan

TO BY RE

EX

400 40 100000 30 60 185

Mm-tpy 1212 P 2014 Mtpy 30 P 2013 m-tpy E 2012 Conser Mtpy 15 U 2011 t/a U 2012 Lurgi t/a U 2012 Siirtec Nigi None 5000 S 2017 None S 10 MMtpy 90 E 2013 80 Mbpsd 1219 U 2012 Shaw S&W

BASF Hualu

Hualu

Siirtec Nigi

CTCI

CTCI

EUROPE Finland Greece Kazakhstan Netherlands Russian Federation Spain

None 14 bpsd 3800 m-tpd 800 kty None 110 m-tpd

P U U 945 U F 1081 U

2012 2011 2012 2011 2012 2011

KTI WorleyParsons Neste Oil CB&I Centry

Tecnicas Reunidas Petrofac|Siirtec Nigi|Black & Veatch Technip Technip Sener

LATIN AMERICA Argentina Mexico Venezuela

Repsol YPF Pemex PDVSA

RE EX

5840 MMm2/y 150 tpd 85 bpd

U 2011 Petreco U 2011 Lurgi P 2015

Tecnicas Reunidas Haldor Topsøe

Constr N. Odebrecht|Rio San Juan

MIDDLE EAST Bahrain Iraq Qatar Saudi Arabia UAE

Neste Oil SCOP Qatar Petroleum Saudi Aramco\ConocoPhillips Borouge III

430 U E H 1300 E 722 E

2011 2012 2012 Belco 2014 KBR 2013 Tecnimont

APS Eng Co Roma Aramco Services Co|KBR Samsung Eng

UNITED STATES California Colorado Mississippi New Mexico North Dakota Ohio Oklahoma Texas West Virginia

Alon/Fina Oil & Chemical Red Cedar Gathering Chevron Chemical Co Western Refining Tesoro Corp Sunoco Inc Holly Corp Samsung Eng MarkWest Hydrocarbon PL

RE RE EX

None MMscfd Mbpd Mbpd bpd bpd Mbpd MMtpy MMscfd

F 18 U E A 35 U 400 C E 816 E 16 U

2011 2012 Petreco |Cameron Belco 2012 2011 2011 GTC, Inc 2013 2011

BOXSCORE DATABASE

FW Thomas Russell Co. Bechtel Belco

Cameron

KP Engineering, LP

KP Engineering, LP

Thomas Russell Co.

Thomas Russell Co.

ONLINE

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

Now, we’ve made our best product even better!

Enhancements include: • Exporting your search results to Excel so you can compile your research • Delivering the latest updated projects directly to your inbox each week • Designing customized construction reports for your company using our 50 years of archived projects.

For a Free 2 -Week Trial, contact Lee Nichols at +1 (713) 525-4626, Lee.Nichols@GulfPub.com, or visit www.ConstructionBoxscore.com

38

I MAY 2011 HYDROCARBON PROCESSING

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Effluent Wa Water Quality

Before

After

solve processing problems with heavy crudes. we’ll share our experience.

Joe Nguyen, Research Scientist

Solving problems when you process heavy crudes means having a partner with the right knowledge.

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When an upgrader processing 100% heavy crudes had a significant amount of desalter oil carryunder, we had the solution—Baker Petrolite

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Select 67 at www.HydrocarbonProcessing.com/RS

can improve your heavy crudes processing performance.

HPI VIEWPOINT Consider new developments in antifouling coatings for rotating equipment Innovative materials and applications protect critical centrifugal compressors and steam turbines from erosion and corrosion

Over the past fifteen years, a great deal of progress has been made with respect to materials science and related processes applied to various components of centrifugal compressors and industrial steam turbines. Due to the very competitive market, material selection has moved beyond simply finding the material with the most ideal properties. Material cost and delivery has become one of the most important factors in the overall cost of the component.

Most original equipment manufacturers (OEMs) are continuously reviewing new ways, whether by material or process changes, to reduce cost or delivery to remain competitive. Also, as energy costs increase, the importance of process and equipment efficiency increases. To be more competitive, OEMs are looking for new ways to enhance the components to perform more efficiently. At the same time, process environments are increasing in severity, leading to the need for more specialized materials. Since specialized materials can be more costly and generally have long lead times, other materials such as coatings that are resistant to aggressive environments, are being developed. In some cases, coatings can even enhance equipment performance.

Coating technology. Coatings can be applied to rotating

and stationary components of centrifugal compressors and steam turbines to enhance performance in several areas, including: • Increase resistance to corrosive environments • Minimize the rate of solid particle erosion • Minimize the rate of liquid droplet erosion • Improve the foulant releaseability of the component • Prevent/minimize fretting between two components.

A number of improved coatings and application processes for enhancing the performance of turbomachinery components in aggressive environments have been developed. One of the major developments has been the application of an anti-foulant type coating, in which amorphous nickel (Ni) is applied to complete assembled centrifugal compressor and steam turbine rotors. These

coatings have superior anti-foulant characteristics for resistance in aggressive environments. Also, multi-component—polytetrafluoroethylene [PTFE (also referred to as teflon)]—sprayed coatings have been designed for foulant and corrosion resistance.

Fouling issue. Fouling is a common problem in compressors

and, to some extent, steam turbines. Fouling refers to the buildup of solids, usually polymeric materials, on the internal aerodynamic surfaces of the machine. While it does not usually lead to a catastrophic failure, it does gradually reduce the efficiency of the machine by increasing the mass of the rotor, thus altering the aerodynamics and blocking flow paths. If left unchecked, fouling can block the flow path to the extent that production is stopped or it can cause imbalances that can damage the machine.

Depending on the service, fouling substances may come from outside of the machine or can be generated internally. External foulants may come from airborne salt, submicron dirt, and organic or inorganic pollutants in the process gas. A well-maintained filtration system usually minimizes this external fouling.

In petrochemical compressors, the situation is much more complicated, as the foulants can be generated internally. For example, in ethylene cracked-gas compression, fouling results from the polymerization reactions intrinsic to the compression process.

Fouling imposes significant costs on petrochemical production.

Solutions on fouling. To resist fouling, the material or coat-

ing must have excellent release properties. Materials with a combination of a low coefficient of friction and chemical inertness are usually used in aggressive environments. A common and widely known coating material for centrifugal compressors is PTFE

100 80 Foulant remaining, %

Phillip Dowson is the general manager, materials engineering, for Elliott Group in Jeannette, Pennsylvania. He has 40 years of experience in the turbomachinery industry.

Mr. Dowson is responsible for the metallurgical and welding engineering for the various Elliott rotating equipment lines. He is the author/coauthor of a number of technical articles, related to topics such as abradable seals, high temperature corrosion, fracture mechanics, and welding/ brazing of impellers. Mr. Dowson graduated from Newcastle Polytechnic, now Northumbria University, with a degree in metallurgy and did his postgraduate work (MS degree) in welding engineering. He is a member of ASM, NACE, ASTM and TWI.

Bare steel Proprietary Cr-TiN

60 40 20 0 0

FIG. 1

250

500

750

1,000 1,250 1,500 1,750 2,000 Scrub cycles

Comparison of foulant release performance of bare steel against proprietary coating and Cr-TiN coated samples.

HYDROCARBON PROCESSING MAY 2011

I 41

HPI VIEWPOINT 80 Uncoated Coated

75

Stress, ksi

70 65 60 55 FIG. 2

Centrifugal compressor rotor coated with a PTFE-type coating.

50 1e5

25

FIG. 4 Cr-TiN Bare AISI 403 SS Proprietary

Mass loss, mg

20 15 10 5 0 0 FIG. 3

1

2

3

4 5 6 Scrub cycles

7

8

9

10

Comparison of bare AISI 403 stainless steel against proprietary and Cr-TiN coated samples after 10 hours of modified ASTM G32 testing.

(Teflon). PTFE coatings are multi-component, sprayed coatings designed for fouling and corrosion resistance. A dramatic decrease in time required to release an applied foulant on samples coated with two PTFE type coatings vs. bare steel samples was observed and shown in Fig. 1.1 Fig. 2 shows an example of a compressor rotor with PTFE coated impellers.

Unfortunately, PTFE coatings can be removed by erosive liquids (i.e., water washing) or solids. Electroless nickel (EN) has also been shown by Dowson (2007) to exhibit excellent release properties, while remaining adherent in erosive conditions. In fact, the release properties are as good as or better than results from PTFE. EN is applied by submerging the component into a Ni and phosphorus (P) containing solution where an autocatalytic process plates the part with a well bonded, amorphous Ni-P alloy. The P in the alloy is believed to be responsible for the release properties, while the amorphous nature of the coating aids in corrosion resistance.

Corrosion issues. Fouling and corrosion can also be a problem in steam turbines, not only causing material damage but also reducing turbine efficiency over time. Industrial turbines, whether condensing or noncondensing, can encounter problems with deposit buildup on the turbine airfoils. In a turbine, hydroscopic salts, such as sodium hydroxide (NaOH), can absorb moisture when superheated steam becomes saturated and condenses in the latter stages of the turbine/Wilson line. Wet NaOH has a tendency to adhere to turbine metal surfaces and can entrap other impurities such as silica, metal oxides and phosphates. Once these 42

I MAY 2011 HydrocarbonProcessing.com

1e6

1e7 Cycles to failure

1e8

1e9

Results of R. R. Moore fatigue testing.

deposits have formed, they can be difficult to remove. Buildup of these deposits may be a root cause for a decrease in efficiency and possibly an increase in vibration. A smooth clean steam path will not collect deposits so easily as a dirty, previously contaminated surface. Consequently, a previously contaminated turbine will accumulate deposits more rapidly than a clean one. Therefore, it is desirable to prevent further deposit buildup and to remove the problems associated with deposits by cleaning the turbine.

Water washing of steam turbines (Watson, et al., 1995) can be an effective way to remove deposits. The effectiveness of waterremoval procedures mainly depends on the adherence of the deposits to the substrate.

A second route is to coat the surface with a material that has superior antifouling or anti-stick/corrosion characteristics. This, in turn, is beneficial to the turbine blades by reducing the tendency for contaminants to stick to the blades and increasing the effectiveness of the water washing. Titanium nitride coatings with a chromium undercoat (Cr-TiN) have also been used by steam turbine OEMs to coat turbine blades.

Cr-TiN coatings provide corrosion protection and can be used on all stages of a steam turbine rotor. However, Cr-TiN coatings provide limited anti-foulant benefits. A recently developed, proprietary corrosion resistant, anti-foulant coating designed for the later stages of the turbine rotor where the deposit buildup is most severe, provides significant improvement in foulant releaseability, as well as excellent corrosion and erosion protection—passes over 1,000 hours of ASTM B117 corrosion testing under a 5% salt solution, (Fig. 3)— while having little effect on the fatigue properties of the blades (Fig.4). HP 1

LITERATURE CITED Wang, W., P. Dowson and A. Baha, “Development of antifouling and corrosion resistant coatings for petrochemical compressors,” Proceedings of the 32 Turbomachinery Symposium, Turbomachinery Laboratory, Texas A&M University, College Station, Texas, pp. 91–97, 2003.

BIBLIOGRAPHY Guinee, M. J. and E. W. Lamza, “Cost-effective methods to maintain gas production by the reduction of fouling in centrifugal compressors,” SPE30400, pp. 341–350, 1995.

Meher-Homji, C. B., A. B. Focke and M. B. Wooldridge, “Fouling of axial flow compressors—causes, effects, detection, and control,” Proceedings of the 18th Turbomachinery Symposium, Turbomachinery Laboratory, Texas A&M University, College Station, Texas, pp. 55–76, 1989.

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MAINTENANCE AND RELIABILITY

SPECIALREPORT

Deferred maintenance causes upsurge in pump failures Not addressing the root cause of a failure puts resources and employees at risk H. P. Bloch, HP Staff

Operating unsuitable pumps in parallel. Worried about unexpected pump outages, some facilities decide to operate two or more BFW pumps in parallel. However, for reasons of gaining power efficiency, the performance curves for many of these pumps were originally designed to be relatively flat at flows

40 NPSH 800

Head vs Flow

EFF.

BEP

100

20

90

0

80

750

70

700

60

650

50

600

40

550

Efficiency, %

Why bearings go first. Interestingly, and of late, fewer bearings seem to be reaching their design life. Also, and in spite of using better lubricants and installing bearing protector seals, pump bearings tend to be the parts that fail first. Seeking to avert bearing distress, many facilities place greater emphasis on vibration monitoring programs, and these pursuits allow their owner-operators to initiate pump shutdown a short time before disaster would strike. Having shut down just in time, people then congratulate themselves for accomplishing what management has decreed, i.e., repairs were deferred until absolutely necessary and only the glaringly defective parts are getting replaced.

Deferring a full repair does not address the real root cause, and repeat failures put both physical and human resources at risk. While the failed part is the weakest link in the component chain and needs to be replaced, something else is pushing the weakest link toward premature failure. It should also be realized that repeat failures are the precursor to far more serious events. More failed pumps per time period thus reduces the mean-times-between repairs (MTBR). This is most noteworthy because statistics that indicate a serious fire occurs for every 1,000 pump failures.1

approaching shutoff. The resulting pressure rise from operating point to shutoff is then either insufficient or non-existent (Fig. 1).

As one or more pumps are operating too close to shutoff, shafts deflect and bearings are overloaded. The oil film that must separate bearing rolling elements from stationary elements becomes both too thin and too hot—a vicious cycle. High load, a thin oil film and high metal temperature combine and bearings fail prematurely. Depending on bearing cage type, these failures range from gradual and detectable to sudden, difficult-to-detect-inadvance, and plain catastrophic.

Deferring repairs or limiting repairs only to the parts that are labeled broken (i.e., the bearings) overlooks the fact that impeller erosion and loss of internal clearances will have occurred as well.

Fear of failure often goads operating departments into parallel operation of more pumps than necessary. Running fewer pumps in parallel would result in each pump operating closer to its best efficiency point (BEP).

In contrast, operating too many pumps often causes one or more of them to operate in the prohibited low-flow range, especially if their respective H/Q curves are not identical. Internal recirculation and progressive wear increase the difficulty of suc-

Total head, feet

I

f your facility has recently seen an upsurge in bearing failures on boiler feedwater (BFW) pumps in the 200 kW–2,000 kW range, it will not be the only one with this costly experience. Failure causes are elusive, which is why plants have so many unresolved repeat failures. As we take note of them, we realize that these frequent failures are very often related to economic downturns. During economic downturns, maintenance outlays and, of course, training funds are among the first to be curtailed.

Maintenance managers then decide to authorize only those repairs that they deem absolutely necessary. In effect, these decisions often encourage treating the symptoms and discourage looking for the true root causes of failures. Ultimately, higher maintenance expenditures and more outage events are incurred. This article explains how the underlying causes of these and other process pump failures must be addressed and avoided.

1,750 Flow at BEP

500 Horsepower

0 Shutoff FIG. 1

400

800 1,200 1,600 Gallons per minute

2,000

2,400

Typical “flat” pump performance curve with undesirable low-flow characteristics.

HYDROCARBON PROCESSING MAY 2011

I 45

SPECIALREPORT

MAINTENANCE AND RELIABILITY

cessfully operating pumps in parallel. Mechanical parts distress and seemingly small deviations from the least-risk geometry of best available designs now converge, and the BFW pump will become involved in a string of seemingly random failures.

Pump operators and reliability professionals need to stand back and understand every one of the various risk factors. Pump owners must accept that, as several risk factors are added, one single additional and in itself seemingly small deviation could bring down the entire plant. Therefore, it should be a priority to examine all probable causes and factors that have recently combined or contributed to costly repeat failures of BFW pumps at a number of facilities in the US. Simply put, operating in the low-flow range forces BFW pumps to run in the flat portion of the head vs. flow (H/Q) curve. By the time pressure sensors signal a small pressure difference in the flat portion of the curve (Fig. 1) and control action is initiated, large differences in throughput will have occurred.

Flow control and load sharing are difficult in the flat portion of a pump-performance curve and long-term satisfactory pump operation is simply not possible in the forbidden low-flow range.

Rebuilding and upgrading are urgently needed. One of several important points of this discussion is that an inflexible edict to “fix only what is broken” is likely to lead to repeat failures. Internal wear and operation at low flow cause cavitation. The impeller geometries and wear-ring leakage flow in regions subjected to a given pressure will vary with progressive wear. Prevailing pressures multiplied by effective impeller areas will, of course, generate a thrust force. An increase in this thrust force can greatly contribute to bearing failures since bearing life varies inversely and exponentially with load. Moreover, on BFW pumps with sleeve bearings and associated shaft-driven worm-gear lube supply pumps, excessive thrust often leads to worm wheel damage and loss of lubrication.

As mentioned previously, bearing distress is generally a symptom and rarely the root cause of pump problems. The root cause of the BFW failure incidents described here is the decision, made by a person, to operate unsuitable pumps in parallel. The best possible remedial action is to rebuild and upgrade all BFW pumps and to then use controls—automated or manual and operatortraining related—that ensure pump operation in the steep region, or close to BEP. Such rebuilding affords an opportunity to upgrade older BFW pumps by using a high-performance polymer as the

FIG. 2

46

Comparing a new slinger ring (left) with an abraded version (right).

I MAY 2011 HydrocarbonProcessing.com

wear ring and throat-bushing material. Rebuilding all pumps to original equipment manufacturers (OEM) specifications can be entrusted to either the OEM or a competent pump rebuilder.

As is so often the case, there are pump rebuilders whose entire focus is on keeping cost low. These parties are often unable to provide the engineered solutions needed for best efficiency and longest equipment life. Performing both an up-to-date competency and experience check, together with a thorough life-cycle cost analysis, will steer the owner-operator to a rebuilder who can prove a solid combination of planning and work execution expertise. The “rebuilder of choice” must perform and report to the owner-operator a large number of critical measurements. Also, the rebuilder must have a proven track record, and the owneroperator of the BFW must spend the time and effort necessary to establish the list of deliverables, the adequacy of the rebuilder’s detailed procedures, and whether or not the rebuilder has just lost four of its five most qualified workers.

Lubrication compromises must be addressed. Many

process pumps are supplied with slinger rings supplying oil to the bearings. To perform well, these oil rings (slinger rings) must be concentric within 0.002 in. (0.05 mm) and have a bore finish reasonably close to 32 RMS.2 Oil rings will not survive long if the shaft system is not truly horizontal, or if the depth of immersion in the oil is either too much or too little. While an ISO grade 32 lubricant is required on pumps equipped with sleeve bearings, mineral oils with this viscosity grade are seldom satisfactory for BFW pumps with rolling element bearings. In theory, rolling element bearings will benefit from ISO grade 68 mineral oils. This thicker ISO grade is required for rolling element bearings and major bearing suppliers recommend ISO grade 68 mineral oils up to 176°F.3 Yet, using the thicker ISO grade 68 mineral oil will slow down the oil slinger rings and will, furthermore, risk depriving sleeve bearings of the oil wedge on which the shaft must ride.

Special issues and potential problems will arise if, in any pump, both sleeve type and rolling element bearings share the same bearing housing. In essence, viscosity is of greatest importance, and each bearing type fails if there is prolonged metal-to-metal contact. To prevent this contact, the oil film has to be thicker than the asperities (the surface roughness) in the bearing and journal surfaces. The oil film must also be thicker than an occasional dirt particle traveling in the oil. Most importantly, the oil needs to be properly applied and must form a suitable film on the surfaces where such a film is most needed. To make a long story short, a lubricant with all required performance attributes, including film strength and film thickness, must, at the same time, allow slinger rings to function properly.

Only well-proven synthetic ISO grade 32 lubricants will satisfy all of these requirements. A preferred supplier usually formulates such lubricants from a PAO/dibasic ester synthetic base oil to which an ionic bonding agent has been added. The oil will have to be viscosity grade 32 and the particular synthetic ISO grade 32 formulation must give users the protection and film thickness/film strength properties of ISO grade 68 mineral oils. While these properties may not be needed elsewhere in one’s facility, they will make lots of technical sense in many BFW pumps that have recently and unexpectedly proven so vulnerable and repair-intensive.

While troubleshooting lubrication issues on existing pumps, one will often find sludge in pump-bearing housings. It should be realized that water acts as a catalyst that promotes sludge formation. Sludge is often the result of water and atmospheric dirt, in addition to oil ring (slinger ring) debris. Exposure to airborne

MAINTENANCE AND RELIABILITY particulates is unavoidable in some environments, and water intrusion is possible in other environments. Another possible source of water is from cracked water jackets. There is some irony in that observation, since—on rolling element bearings—cooling water may not be needed in the first place.

Also, the troubleshooter should become familiar with the inadvisability of mixing two “virtually identical” oils from different suppliers. There is ample evidence that, to keep costs low, some oil suppliers skimp on the amount and/or quality of additives. The lowest-cost-supplier games played by a supplier are often encouraged by users. It stands to reason that engaging in these ill-advised procurement practices will lead to not attracting, grooming and/ or retaining top talent. If the user plays along with the low-price strategy, suppliers are encouraged to provide a “commodity product” and commodity lubrication products may not serve those of us who go beyond paying lip service to the term “reliability.”

Systematic component upgrades recommended.

During a recent plant visit to a facility in the Southern US, an oil-slinger ring that had been removed from a BFW after one more pump failure was measured. Instead of staying within the allowable eccentricity of 0.002 in., this ring was about 0.06 in. eccentric—30 times the allowable value. The ring was abraded on one side; it also showed very serious discoloration—similar to Fig. 2 (taken from Ref. 4). If one must use slinger rings, they should never be the cheap ones. Good ones will have gone through an annealing step before finish-machining. Again, be certain to subject slinger rings to rigorous specifications and quality control.

On pumps furnished with rolling element bearings, the purchaser may be able to avoid slinger rings by insisting on bearing housings configured to accept solid flinger discs. If nothing else, specifying a lube application method other than slinger rings will start a discourse with the pump manufacturer. It should also be realized that slinger rings can become dislodged as the equipment is transported from a factory or shop to an installation site. These slinger rings are later found caught between the shaft and ring locator pin or some other housing component.

The point of the story is that truly reliability-focused purchasers have highly justified concerns with certain traditional and all too often failure-prone means of lube delivery. Pump manufacturers must be shown the vulnerabilities of certain pump

SPECIALREPORT

designs. Pump users must use rigorous checklists that lead to better installation procedures, verification of adequacy before startup, and adequacy while running and while doing root cause failure analysis. Thousands of repeat failures occur in industry every day.

They are irrefutable testimony to the fact that things are far from acceptable and that striving for improvement is a shared obligation that cannot be disregarded by any of the parties.

Systematic upgrading is practiced by best-of-class companies on every pump that enters their repair shops. The causes of “black oil” are then traced to one of only two causes: overheated oil or contaminated oil. The source or sources of either of these root causes is not difficult to find and upgrade as well as failure avoidance measures are outlined in many relevant texts.1 Retrofitting process pumps with only the very best constant level lubricators is part of these efforts. Reliability-driven facilities would use pressure-balanced models that typically cost $30–$50 more than the traditional nonbalanced models one still finds on the majority of process pumps.1,4 In essence, the intrinsic value of systematically upgrading important utility and process pumps can be envisioned by somewhat arbitrarily assuming that each deviation from best practice reduces pump mean-time-between-failures (MTBF) by approximately 10%. Once five seemingly minor deviations combine, pump MTBF will be cut in half. If the negative impact of operating pumps in the flat region of the performance curve is factored in, as well, one has all the data needed to explain the very significant differences in pump reliability among different pump owner-operators. HP 1 2 3 4

LITERATURE CITED Bloch, H. P., and A. Budris, Pump User’s Handbook: Life Extension, 3rd Edition, Fairmont Press, Lilburn, Georgia, 2010.

Wilcock and Booser, Bearing Design and Application, McGraw-Hill, New York, New York, 1957.

Bearings in Centrifugal Pumps, SKF Publication 100–955, pp. 20; also Ref. 1 Bloch, H. P., Practical Lubrication for Industrial Facilities, 2nd Edition, Fairmont Press, Lilburn, Georgia, 2009.

Heinz P. Bloch is Hydrocarbon Processing’s Reliability/Equipment Editor. A practicing consulting engineer with close to 50 years of applicable experience, he advises process plants worldwide on failure analysis, reliability improvement and maintenance costavoidance topics.

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MAINTENANCE AND RELIABILITY

SPECIALREPORT

Avoid costly engineering faults, missteps and miscalculations Experience does count, especially in achieving success in capital and revamp projects K. SANGHAVI, Alon USA, Big Spring, Texas

I

n the past two decades, technical manpower and average experience levels within the oil industry and its affiliated engineering, contractors and technology companies declined as the need for lower operating costs drove most decisions. Senior experienced staff members took early retirement or were displaced with younger professionals. Supported by new state-of-the-art technological tools, but lacking adequate training and mentoring, these younger workers are expected to deliver more and faster. At times, designers and engineers are working under rush deadlines and lean supervision, which can lead to frequent accidental engineering missteps, faults and miscalculations. This article illuminates the current industry situation and the need for proper training and mentoring, and a broader and deeper experience base. Several examples illustrate poor design and engineering encountered during a recent refinery project.

Case history. The following examples illuminate the present

hydrogen heater provides primary preheat for the feed to reactor No. 2. The reactors, the heart of a hydrotreater operation, can directly impact plant profitability through any compromised design or reliability. A semi-regenerative reformer is the refinery’s sole hydrogen source.

New thinking for design. In this project, new thinking

changed old, established reactor design practices for increased operational flexibility and economic advantage. A common industry practice is to design the unit’s reactor and heat transfer equipment, including the heater(s), based on: a) Both reactors being at the start-of-run (SOR) and/or both reactors being at the end-of-run (EOR), in tandem, based on a four-year run length and b) Average hydrogen purity, a value of 80.2% for BSR. But, for enhanced operational flexibility, the RPC asked that other scenarios be taken into the design of the equipment to cover a) staggered reactor operation, with reactor No. 1 being

condition with the energy industry. These incidents were encountered during outside engineering work on just a single project at Alon’s Big Spring Refinery (BSR). Fortunately for BSR, the refinery’s core project team of three members—a project/mechanical engineer, PC Liquid phase a refinery process consultant (RPC) and Feed Heat up flow exchange a process control/electrical engineer—all reactor No. 1 supervising this project are experienced and versatile enough to quickly catch and correct all the problems. The RPC also interjected new thinking, and the refinery’s team was able to achieve a very successful project outcome.

Hydrogen Compressor heater Fig. 1 shows an overview of the recent Hot hydrotreater project at BSR. The unit hydrogen feedrate was being increased by more than Purge 25%, while product specifications were Vapor phase stringently tighter. The new equipment Production Heat Effluent down flow separator exchange cooler included a liquid-phase upflow reactor No. reactor No. 2 1, a splitter, stripper product pumps and associated new heat exchange train and pipNew Revamp equipment equipment ing. Additionally, the existing vapor-phase downflow reactor, compressor, hydrogen FIG. 1 Project overview for new hydrotreater at BSR. heater, stripper reboiler, and airfin coolers and piping were being revamped. The

Product

Splitter

Makeup H2 Amine contactor

Offgas Stripper Pumps Reboiler Product

HYDROCARBON PROCESSING MAY 2011

I 49

SPECIALREPORT

MAINTENANCE AND RELIABILITY

prematurely at SOR while reactor No. 2 continues to run its course and vice versa, and b) the expected 74%–88.6% range for hydrogen purity.

The revised basis increased the sizes of a reactor and heat exchange equipment, as well as the sizes of the hydrogen heater and reactor effluent air fin condenser, as listed in Table 1.

Also, the RPC further enhanced operational reliability by insisting that a layer of macroporous trap/media layer be added above the planned catalyst grading system to capture particulates TABLE 1. Unit equipment size with various operating scenarios

and iron sulfide that can cause increased reactor pressure drop and thereby shorten the run length. The RPC and the refinery technical service engineer requested use of wedges and pins, instead of traditional nuts and bolts, to facilitate handling of the reactor internals and reduce reactor downtime.

The post-startup audit has revealed that this unit will not constrain refinery operations, and it will be in a position to provide the refinery economic advantage and leverage. Also, an outside review has revealed that this unit has the best performance amongst other similar functional units in the industry.

Experience and practical knowledge results in savings.

Using practical knowledge, the BSR team found opportunities to reduce and increase plant reliability: Tower trays. After initial work and consultation with tray Makeup H2 purity, % 80.2 74.0 88.6 vendors, the detailed engineering contractor (EC) recommended: Recycle gas, MW 8.4 10.56 3.07 • 20 new trays for an existing amine contactor when the RPC Reciprocating compressor, acfm 1,320 1,320 had expected only minor tray changes H2 flow, lb/hr 17,758 22,257 6,678 • 30 new trays for the stripper when the RPC had expected Reactor No. 2 volume, ft3 1,173 1,675 no change at all.

So, the RPC worked directly with the tray vendors with correct Reactor No. 1 steam preheater, ft2 260 603 information and, as a result, it helped eliminate the need for new Reactor No. 2 air cooler, MMBtu/hr 22 42.3 trays in both towers and determined that the amine contactor H2 heater, MMBtu/hr 10.7 13.34 required only a change-out of bolted outlet weirs. This resulted in considerable cost savings and less mechanical work during downtime.

Misdirected fractionation tower feed distributor. Due to increased loads, the stripper tower feed distributor hole area needed to be increased from 18 in.2 to 30 in.2. The tower has single pass trays, and the discharge from the existing feed distribuTray tor impinges on a downcomer’s “sacrificial wear plate.” The EC 45° 45° 45° erosion Wear plate designer decided to retain the existing six slots “as is” and install Feed tray a second row of slots on the opposite end of the distributor, as shown in Fig. 2.

With such an arrangement, depending on the new slot’s angle, the feed stream from the newer slots could impinge on the tray deck below, discharge into the downcomer or impinge on the tower shell. All these scenarios are unacceptable. This design Existing EC Plan would have led to poor operations and product loss. Typically, FIG. 2 Before and after designs on the fractionation tower feed sacrificial wear plates and feed diffuser plates are typically installed distributor. to break stream momentum. The RPC simply requested that the width of the existing slots be increased from 0.75 in. to 1.25 in., to provide the required Horiz. ells 2-45° additional area; the feed would continue to 18-in. x impinge on existing downcomer wear plate.

16-in.

Control valve. An inexperienced pro18-in. x 15-in.

14 ft 18-in. x 14-in. cess engineer would size control valves 18-in.

17 ft 18-in. x 18-in. just for a single case of design rate. In real18-in.

14-in. ity, truly seasoned engineers know that a 45° Reb 18-in.

Reb oile H oile detailed study based on hydraulic mod18-in. x r r 14-in.

E-0 18-in. els of the piping circuits and associated 12-in. <45° Min. 21 12-in. P E-0 pump or compressor curves is required to 12-in.

21 establish control-valve conditions, at not 18-in. 12-in. only the design rate, but also at a maximum flow, say at 110% design rate and at 12-in.

12-in. a minimum flow say, at 40% design rate.

Total fittings = 14 Total fittings = 10 Then the control valve would have differTotal length = 127 ft Total length = 78 ft ent pressure drops at these three flows, as Before After opposed to original data sheets prepared FIG. 3 Before and after view of design of the reboilers circulation unit. by the EC, which showed constant pressure drops.

T-001

18-in.

22 ft

50

I MAY 2011 HydrocarbonProcessing.com

Low

Alternative cases – High

T-001

Base case average

Purity case

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Tower Technical Bulletin 4 Simple Ways to Convert Turnarounds Into Profitable Tower Upgrade Opportunities

Background With planned outages commonly occurring at intervals of 2-5 years, a refinery turnaround is a prime opportunity to replace column and separator internals with the newest available technology. Planning for an outage with a “replacement-in-kind” strategy will address lost performance from refinery equipment due to normal wear and tear. However, most column internals can be upgraded for higher capacity, more flexibility, or greater efficiency at close to the same cost as an in-kind equipment replacement. #1 – Upgrade Performance of Existing Packing or Trays Adding column capacity to debottleneck existing operations or to create “room” for future capacity creep can often be accomplished with a simple modification to the existing design. High performance tray decks, like Sulzer MVGTM trays, can achieve up to a 15% capacity increase in entrainment-limited applications. MVG trays can fit within existing column weld-ins and ring supports for a similar cost to replacement-in-kind moveable valve trays. If increased liquid handling is required, the use of Z-bars can adapt the existing weld-ins for larger downcomers without the need for costly welding to the vessel wall.

Similarly, standard structured packing can easily be replaced with high performance packings such as MellapakPlusTM and MellagridTM, providing capacity increases of up to 40% at a cost that is comparable to the existing equipment without requiring other column modifications.

efficiency of 25% or less. By making a simple change to the design – reducing the open area on the lower trays appropriate to the predicted vapor rate, the refiner can see a large impact on stripping efficiency or can take advantage of the improved stripping by reducing energy / steam usage. #3 – Upgrade Separator Internals Separators, accumulators, receivers, and knockouts are often the forgotten vessels that can consume downstream capacity when operating with poor performance. Since entrainment generation is typically exponential, a small shortfall in separator capacity can result in a very large increase in liquid losses. Upgrading an existing standard mesh or demister pad with a higher capacity Sulzer KnitMesh™ Mist Eliminator or Mellachevron™ can reduce carryover of liquid or free water to downstream processes from existing separators that are forced to operate with a higher superficial velocity. #4 – Improve Tray Fouling Resistance Adding anti-fouling features to a replacement tray can be a simple fix to increase run length between cleanings or turnarounds in heavy fouling services. Adjusting downcomer design and incorporating push valves on the active decks can improve the washing effect of the tray liquid traffic to prevent fouling buildup. These features can typically be incorporated into the trays without the need to weld on the column wall.

Other Considerations Making tower and vessel upgrades rather than in-kind replacements takes some extra planning and strategy but the payout is often extremely high. You have to start early so you have time to evaluate, not only the tower internals in question, but also the feeds, draws, nozzles, and auxiliary equipment as well. Sulzer’s process applications team can help evaluate all your possible options.

#2 – Optimize Stripping Tray Open Area Column bottom, side column, or Hydrotreater Product stripping trays are often of a single design in order to simplify equipment layout and production. In operation, however, the bottom tray has a far lower vapor rate than the top tray due to the stripping effect. Since the design will have to accommodate the highest loads, the bottom trays’ performance will likely suffer due to weeping. Because of this, stripping trays can often have an

The Sulzer Chemtech Applications Group Sulzer Chemtech has over 50 years of providing equipment and services for optimal turnarounds. Our goal is to meet your requirements and challenges while providing the most cost effective solutions with the least amount of downtime, in any situation.

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Legal Notice: The information contained in this publication is believed to be accurate and reliable, but is not to be construed as implying any warranty or guarantee of performance.

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Select 68 at www.HydrocarbonProcessing.com/RS

SPECIALREPORT

MAINTENANCE AND RELIABILITY

Multiple improper pipe routings.

Pipes are the arteries in a process unit and 8-in. must be properly designed for trouble-free 8-in.

8-in. operation. Process piping that can experience slug flow and/or have pockets and traps are in a class of critical piping that 10-in.

10-in. can cause serious operational and reliability 2.5 ft.

Existing 8-in.

Existing 8-in.

1.6 ft. (pocket) problems and must be properly designed.

10-in.

Slug flow creates unstable operation and/ or destructively damaged fittings and vessel 10-in. x 8-in.

8-in.

10-in. x 8-in. inlets and walls from a hammering effect.

Slug-flow potential can be managed by: 8-in. x 6-in. 8-in.

8-in. x 6-in.

1) Using a pipe with a smaller diameter, Reboiler Reboiler 8-in. x 6-in.

8-in. x 6-in. pumps pumps if possible New 8-in., L = 60 ft.

New 8-in., L = 53 ft.

2) Providing dual risers that can be Before After turned off or on, depending on the flowrates FIG. 4 Before and after view new product pump layout.

3) Installing an impingement tee at the end of the risers, where possible.

In low-pressure drop piping, pockets can 1) cause flow restrictions and thus loss of capacity, especially in pump suction piping, and 2) induce slug flow in two phase flow 12 in.

12 ft pipe ~ 9 ft Splitter piping. Streamlined piping with shorter pipe runs and fewer fit8 ft pipe ~ 483 ft 12 in. tings, and piping that has strictly downturns past the first starting 45° El 3 ft HCR 8-in. point riser can reduce operational risk substantially.

197 ft 15 ft Traps Examples from three key piping categories are quoted here 8 ft 12 ft x 8 ft Two phase to illustrate the critical importance of piping and equipment flow 3 ft El 4 ft 3 ft 188 ft reviews to guard against problems from slug flows and pockets No. of 8-in. that can affect plant reliability. In each case, initial CAD drawings 3 ft fittings = 7 incorporated improper piping routings and/or convoluted heart El 8 ft x 6 ft Reactor 113 ft stopping designs.

8 ft x 6 ft No. 1 Overly complex reboiler circulation. Initially, a very convoSplitter feed line–before luted arrangement was proposed as shown in Fig.3-Before view.

12-in.

This arrangement would have resulted in a very poor reboiler 12 ft pipe ~ 11 ft Splitter 12-in.

8 ft pipe ~ 431 ft El operation, potentially leading to upsets and downtime for repairs.

1 ft El 122 ft The RPC improved reliability of operation by streamlining pip197 ft No traps 3 ft ing layout, minimizing slug flow potential and, at the same time, 12 ft x 8 ft reduced large bore piping length from 127 ft. to 76 ft. and fittings El 8-in.

Two phase 45° vert. from 14 to 10 as shown in Fig. 3-After view.

188 ft 3 ft flow No. of Restriction in pump suction piping. The project required 8-in. fittings = 2 3 ft the addition of two new stripper-product pumps next to the El existing reboiler circulation pumps with the extension of the 125 ft El Reactor 103 ft existing reboiler pump suction header. New piping is shown No. 1 Splitter feed line–after with solid lines and existing piping is shown with dashed lines in Fig. 4.

Initially, the proposed arrangement simply violated the good FIG. 5 Before and after design of tower feed piping. engineering practice by introducing a vapor pocket in the new suction line shown in the “before” view. The “after” view illusAccordingly, the RPC reworked all control-valve data sheets trates the design subsequently drawn up by the RPC to improve using proper hydraulic models and found that, out of the 39 operational reliability while reducing the new piping length from control valves that were sized, approximately 16 were undersized 60 ft to 53 ft. (of which six were grossly undersized) and 10 were oversized (of Problematic tower feed piping. Fig. 5 shows the initial which two were grossly oversized). Such improper sizing would arrangement proposed by EC and also the final arrangement rechave led to control problems and/or would have reduced unit ommended by the RPC for improved reliability for a two-phase capacity. In the past, the RPC has also seen that an improperly flow service and also lower costs. These benefits were achieved specified control valve can experience severe valve-body erosion, through streamlining piping with fewer fittings downstream of especially for those control valves experiencing cavitation, resulta pressure control valve, eliminating “liquid traps” and reducing ing in unplanned plant downtimes. total pipe length from 472 ft to 442 ft.

Stripper

Stripper

16-ft

13 ft

28 ft

94 ft 8-in.

14-ft

2-ft

Product pumps

Product pumps

10-in.

8-in.

Technological tools. Computer aided designs (CADs) are most effective only if backed with proper training and field experience.

52

I MAY 2011 HydrocarbonProcessing.com

Flexible view on the design issue. Flexible eyes for both

the big picture and smaller details help identify missteps and opportunities for greater reliability. Missteps to watch for are:

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SPECIALREPORT

MAINTENANCE AND RELIABILITY

4 in. 175 lb steam 200 ft 21

4 in

4 in

. co

. co

Demister

nde

nse

r2

Vortex Brkr.

ft

Demister

19

E-0

D-021

Vortex Brkr.

D-018 8-in.

4-in.

Before

00

nde nse r2 00 ft

4-in. condenser

8-in.

E-0

Demister

4-in.

D-020

D-021

2-in.

3-in.

1½-in.

4-in.

After FIG. 6

8-in.

2-in. condenser

¾-in.

2-in.

Before and after design for condensate handling, routing and flash drum.

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Incorrect condensate handling, routing and placement.

The initial proposal, as shown in Fig. 6-before view, demonstrates multiple engineering missteps: 1) Incorrect design of condensate pots and inlet piping 2) Poor layout of critical condensate piping downstream of the pot level control valves, as this piping can be subject to slug flow and 3) Wrong placement of the final condensate flash drum, D-02.

Condensate pots require bottom inlets and do not require demister pads or anti-vortex baffles.

If the pot design and piping installations had been built per initial proposal, it would have affected unit throughput and reliability. The arrangement then proposed by the RPC is shown in Fig. 6-after view. The RPC also captured the opportunity to place the final flash drum in the corner of the pipe rack leaving the units and thus saved BSR the cost of a total of 400 ft on insulated-traced pipes.

Wrap-up. Fortunately, the early faulty designs introduced in this project by some inexperienced outside engineers were corrected in time to avoid costly rework and unscheduled plant downtimes. There were a number of other equally troublesome missteps in other categories, such as splitter design, heat exchangers and pumps, that were fixed by the RPC. Although only process examples are quoted in this article, the other two members of the refinery’s project team supporting the mechanical side and instrument, and electrical had similar experiences requiring corrective actions.

All of the cited examples illuminate current concerns for the oil industry leaders and provide warning signs. A frustrated past colleague who now works for another major US refiner recently said, “I have seen some engineering lately that I think a smart 8th grader could do better.” In these times, the industry will need to protect itself against such design and engineering faults, missteps and miscalculations that could curtail production, cause unscheduled downtimes and/or escalate project cost into overruns.

The writer went out to speak to three outside engineering directors for feedback on this article. Their input and perspectives and recommendations have been incorporated in the article and its conclusion: • The largest single safeguard for the oil industry and affiliated engineering and technology companies is the retention of a talented team of experienced and versatile in-house engineers who are capable of managing daunting challenges in major projects while capable of new thinking and willing to make appropriate changes to any of the outdated design methods and practices.

• Decisions made strictly on the basis of pricing can turn out to be costlier over the longer term, and due diligence is warranted to achieve a proper balance.

• Experienced, multi-talented refinery engineers would need to reside and work together with younger staff members and engineering contractors in a truly joint- team fashion and thus successfully meet the project’s goals for quality, cost and timeliness and to ultimately capture a savings of 15%–30% on engineering costs by eliminating reworks. HP Kirit Sanghavi is a senior refinery process engineering consultant at Alon USA’s Big Spring Refinery. He has been with BSR for the past 18 years, responsible for the largest capital projects at the refinery. Previously, he worked at Esso Chemical and Imperial Oil in Canada for 15 years. Mr. Sanghavi has also worked for four international engineering companies in the US, the UK and Canada during his career. He earned a bachelor’s degree in chemical engineering from London University.

MAINTENANCE AND RELIABILITY

SPECIALREPORT

Nickel recycle: Extending service life for reformer tubes Case studies investigate methods to conserve high-nickel tubes for fertilizer facilities S. B . KUNTE, Rashtriya Chemicals & Fertilizers Ltd., Chembur, Mumbai, India

T

his case study deals with the conservation of centrifugally cast reformer tubes in the fertilizer industry. A fertilizer plant investigated how to extend the service life of reformer tubes beyond design limits. The study describes two cases: one case focused on HK-40 tubes and the other with HP micro-alloyed tubes. In both cases, reworking the tubes proved to lengthen the service life for the reformer tubes. The recovery and reinstallation procedures were successful. Such actions not only resulted in huge savings on the reformer-tube inventories but also in conserving expensive raw materials, such as nickel.

Metal shortages. There is a fear that the rising demand for

nickel (Ni) will cause shortages and increase the price for this metal.

Industry must find ways to conserve Ni and recycle this metal.

Reformer tubes used in the fertilizer and petrochemical industries are an area in which large quantities of Ni are applied. This article details the advantages gained in recycling used reformer tubes.

Changes in materials of construction. The fertilizer

industry has seen the material of reformer tubes change from HK40 to IN519 and now to HP-micro alloyed. The wall thickness of the reformer tubes reduced from about 17 mm to about 10 mm without losing strength and other high-temperature properties. This is a major advantage with respect to heat transfer, increase in volume and also with respect to the total weight of the tubes’ which provides more benefits.

But, in the process, Ni consumption has increased from 20% in the old HK40 tubes to 35% in the present HP- micro alloyed tubes. Table 1 shows the nominal chemical composition of HK40, IN519 and HP micro-alloyed tubes, with the corresponding sound-wall thickness used. Note: There is a substantial increase in the Ni content.

This table reflects the situation for reformer tubes. But in general, the demand for Ni is increasing globally. With the current rate of consumption, we may run out of Ni by the end of this century.

Design life of reformer tubes. Reformer tubes are nor-

mally designed for a service life of 100,000 operating hours under ideal conditions. The service life is generally limited by creep failures. In practice, there are several factors contributing to the loss of creep properties, thus making it difficult to run the tubes up to the full design life of 100,000 hours. These factors are:

• Thermal shocks due to reformer tripping • Localized overheating from damaged catalyst • High-thermal gradient along the length of the tubes • Non-uniform firing of the burners • Restrictions in the free expansion and contraction of the tubes • Bowing of the tubes • Inadequate induced draft in the furnace.

Since accidental failure of a reformer tube is a very expensive affair in terms of fire hazard and production loss, the reformer tubes are normally replaced after extracting 90% of the design life, depending on the maintenance practices being followed. This again means a hike in Ni demand beyond projection.

Manufacture and service conditions. As per the exist-

ing global norms, reformer tubes are constructed from fresh raw materials and no scrap material is allowed. The author, being a metallurgical engineer, had initial hands-on experience in quality control and assurance steps in the manufacture of centrifugally cast reformer tubes and other heat-resistant castings in a major foundry. The work involved planning and executing qualitycontrol steps followed by quality-assurance steps for each tube.

This included testing from spectrographic analysis of molten charge ready for pouring to the hydraulic-pressure test of the finished reformer tubes, and assembly to the complete satisfaction of the third-party inspection agency as per specified concerned international standards.

This initial experience of the quality aspects for centrifugal castings has been of great help. His present responsibility, spanning a period of about 30 years of monitoring the plant health in Rashtriya Chemicals & Fertilizers Ltd. (RCF), which is a huge fertilizer manufacturing complex, where hundreds of reformer tubes are in service. The responsibility of plant health service includes, TABLE 1. Nominal composition of reformer tube alloys Common name

C, %

Cr, %

Ni, %

Nb, %

Mn, %

HK40

0.4

25

20

–

IN519

0.4

25

25

1

1.5

HP Microalloyed

0.4

25

35

1

1

Si, %

2 Max 2 Max 1.5

Tube wall Other thickness, mm – –

1.4 Micro alloy additions Ti, Zr, W, Cs

17 15 10

I

HYDROCARBON PROCESSING MAY 2011 55

SPECIALREPORT

MAINTENANCE AND RELIABILITY

among others, monitoring the behavior/performance of reformer tubes and analyzing their routine and unusual challenging failures over the entire service life of the tubes.

The author had the opportunity to conduct an entire thirdparty inspection activity for 90 HP micro alloyed reformer tubes being manufactured for RCF in a well reputed foundry. The author witnessed the gradual transition of reformer tubes metallurgy from HK40 through IN 519 to the present HP-micro alloyed, which occurred gradually over the last three decades.

The reaction in the reformer tubes is endothermic. The reformer furnaces in RCF are side fired. The reaction peaks in the top portion, and it slows down toward the bottom side of the tubes. The tubes remain cooler at the top and become hotter toward the bottom. If the tubes are designed to operate at the tube skin temperature (TST) of 870°C and if the bottom portion of any given tube is at 890°C, the top portion of the same tube could be at 820°C or 830°C or even less. Under ideal conditions, the thermal gradient from top to bottom of the tubes should be at minimum level. But in practice, reformers are operated sometimes with this gradient as 100°C or even more. For all practical purposes, a gradient of 20°C to 30°C can be considered as very good.

Common failure pattern and its assessment. Due

to continuous high TST, the reformer tubes are more prone to failure in the bottom one-third portion. Over the last 30 years at RCF, more than 90% of the reformer tube failures were recorded in the bottom one-third portion only. Very rarely were

tube failures recorded above the bottom one-third region due to localized overheating. Not a single failure was recorded in the top one-third portion.

As the tubes get older, they start losing their high-temperature strength; the rate loss depends mainly upon their skin temperature. Only the outer surface of the tubes is available for carrying out all non-destructive testing (NDT) like microstructure, ultrasonic flaw detection, dye penetrant, magnetic permeability, OD measurement, radiography, soap-bubble test, etc.

Out of these methods, the tests that tell the true inside story are mainly done on the weld seams. The general feeling is that the weld seam is the weakest portion, and cracks in the tubes originate from welds. However, many times it has been observed that the tubes crack in the parent metal away from the weld. So, the weld seam does not need to be treated as a part of the tube susceptible for cracking. Besides, reformer tubes with only one joint and those without using filler wire are already in use within the industry.

It is not a very common practice to do radiography testing on reformer tubes to assess the health condition and residual life.

Even if radiography is done, it is only applied to the weld seams.

Ultrasonic-flaw detection and magnetic permeability tests are very commonly carried out for the entire length of the tubes. It is very tricky and difficult to co-relate the results of these tests with the residual life of the tubes.

The microstructure is studied only on the outer surface of the tubes, and it cannot tell the story on the inside surface. It may not be advisable to correlate the deterioration observed in the micro structure on the outer surface of the tubes with the residual life of the tubes as it may not be leading to sudden failure. The dye penetrant test is done only on the weld seams, and it tells about the damage that has already occurred. The soap-bubble test can be done for the entire tube but it also tells about the defects that already exist.

TABLE 2. Summary of measurement for OD in 90 reformer tubes in a methanol reformer Initial OD, in Min. and max Min. and max Min. and max mm 1997 OD, 2005, mm OD, 2006, mm OD, 2007, mm 129.4 to 130.2

56

FIG. 1

Tubes are being tested for straightness.

FIG. 2

Welding in progress.

I MAY 2011 HydrocarbonProcessing.com

FIG. 3

130.5 and 132.2

131 and 134.6

Dye-penetrating testing tubes.

131 and 134.6

Remarks Tubes with more than 133 mm OD were replaced

Not Mozart, Yet a Classical Genius

MAINTENANCE AND RELIABILITY Gradual aging of the tubes and its monitoring. The inside surface of the tubes has a machined finish, but the outer surface of the cast tubes has a rough shiny granular finish. As the tubes grow older, the outer surface of the tubes becomes smooth and gradually loses its shine. Anyone closely associated with the reformer tubes for a long time can tell the approximate age of the tubes just by examining their surface finish.

The present generation of reformer tubes has a good resistance to creep, but with aging, as they start yielding and gradually bulging, the surface finish starts changing. The tubes estimated as young as five years can be taken out of service if they exhibit bulging during this period. This largely depends on the operating conditions.

The TST of the tubes has the maximum impact on their aging process. The design of the present reformer furnaces is generally spacious, and the possibility of the tubes receiving undesired heat flux from the neighboring tubes and from the furnace walls is minimized. Some tubes that run below the design TST exhibit very less increase in the outer diameter even at the end of their life, whereas some tubes running at higher TST show excessive sudden bulging even at a young age. For a particular design operating pressure and temperature, the manufacturer of the reformer tubes specifies the maximum allowable bulging and advises not to use the tubes beyond this bulging, which is normally 2% for the HP- micro alloyed tubes.

So, the warning on the tubes could be best realized before 100,000 running hours or 2% bulging, whichever is earlier. As the reformer tubes run hottest in the bottom one-third portion, the bulging of the tubes occurs predominately in this region, and so do are the failures. The bulging of each individual tube is monitored during every possible opportunity. Experience shows that the bulging of the tubes in top one-third portions is insignificant. For assessing the residual life, the bulging of the tubes in the bottom one-third portion needs to be monitored very closely. Table 2 is a summary of measurements for the OD in the bottom one third portion in methanol reformer at RCF. Replacement and repurpose strategies. The tubes

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showing sudden excessive bulging are more likely to fail than the tubes bulged to the same value steadily over a long period. The tubes will bulge steadily to the maximum allowable limit over a prolonged period, which is substantially less than the design life.

Similarly, the tubes, which have bulged less than 1% but have almost lived their designed life can also give more service. In the case of the methanol reformer at RCF, a service life of 110,000 running hours has been extracted from few HK40 tubes, as their bulging was less than 1% throughout their life.

In reality, no one wants to take any chances on reformer tubes.

They are replaced in time. Slightly unhealthy and failed tubes are replaced immediately, and when life of majority of the tubes comes to an end, all the tubes are replaced together. No one prefers to run the reformer with a combination of fresh and old tubes.

Everything ultimately leads greater demand for Ni.

We supply the instruments, you be the conductor.

Case No. 1: Repurpose of used HK40 tubes. More than

15 years ago, the reformer in the methanol plant at RCF had 90 tubes made from HK40 tubes. The reformer used an old design, and all the outlet pigtails and headers were inside the furnace.

During a shutdown, about 35 aged tubes were replaced with new HK40 tubes as part of the planned activity. Due to such unavoidable partial replacements, the reformer always ran with

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SPECIALREPORT

MAINTENANCE AND RELIABILITY

a combination of some very old tubes and some fresh tubes. The removed 35 tubes had only a scrap value, and procurement of new tubes was not planned immediately.

The failed/aged/scrapped 35 tubes were inspected thoroughly.

Bulging measurements and micro-structure analysis were done on each tube. The bottom half portion of all these tubes was discarded, regardless of its condition. The top one-third portion and about a meter extra (depending on the position of the first weld seam) of the discarded tubes was found useful from a metallurgical point of view. The good portions of the scrapped tubes were salvaged, and 10 new tubes were fabricated from these portions in-house. The bottom reducers and grid plates were salvaged from the discarded tubes only.

These tubes were put into service, and they worked satisfactorily for almost 30,000 hours (four years) until all the 90 HK 40 tubes were replaced with HP-micro alloyed tubes. This has resulted in considerable cost savings and better utilization of the reformer tube inventory kept in stores.

Significance of Case No. 1. This activity, never attempted before in the reformer tube application industry, was initially felt only as a salvaging operation for emergency use. The importance associated with the Ni crisis and all other expensive natural resources was not seriously considered those days as they are today.

Case No. 2: Recovery of used HP- micro alloyed tubes. By 2007 in the same reformer, many of the same HP-

micro alloyed tubes had almost reached the end of their design

Select 161 at www.HydrocarbonProcessing.com/RS 58

life. There had been accidental failures of the reformer tubes, and the reformer was operated with a combination of old and new tubes. During April 2007 turnaround, 25 damaged tubes were replaced with new ones. The reformer ran for a long time with the undesired combination of some old tubes and some fresh tubes.

It was decided to replace the entire reformer, with the project to be completed by October 2009. Until then, the reformer was to be operated with many old tubes, which were installed in 1997, because it is very difficult and expensive to buy reformer tubes in smaller quantities.

All of the scrapped 25 tubes were, therefore, inspected thoroughly. Eight tubes that had developed cracks and operated in blanked condition for some time were discarded. The bottom half of the remaining 17 tubes along with pigtails were discarded without any testing. It was planned to fabricate at least four good tubes from the 17 top halves of the scrapped tubes. Eight good reducers and grid plates were salvaged from the scrapped tubes.

The 17 top halves were subjected to these tests: 1. Straightness and dimensions. The lengths were matched in such a way that the coldest end, i.e., the topmost portion of the tubes becomes the bottom most portion of the new tube.

2. Bulging throughout the length 3. Microstructure study of the tubes selected at random 4. Tensile strength testing of random samples 5. Macro structure study of sample rings selected at random.

The excessively bent portions and most portions of the tubes below the first weld seam were discarded. The macro structure did not reveal the original proportion of equiaxed and dendritic columnar grains. Some failed tubes exhibited a good amount of

FIG. 4

Final tubes are ready for hydrotesting.

FIG. 5

Old tubes being cut down in sizes.

MAINTENANCE AND RELIABILITY equiaxed grains, but the older tubes mostly showed columnar grains. No macro fissures were observed. The microstructure analysis and tensile strength values did not show any abnormal deterioration and, accordingly, the bulging of these portions was within 0.6%.

Desired lengths were measured and marked for making four tubes. The inspection and testing norms were set just like making new tubes. The machined surface was checked with dye penetrant testing before welding, and no porosity was tolerated. Welding of the selected pieces was done with the same WPS used for making fresh tubes. Root-dye penetrant test, final-pass dye penetrant test and 100% radiography were carried out. There was not much rejection in carrying out welding of the old used tubes, and the weldability of the material was found well within acceptable limits. Brand new pigtails were welded to the reducers, and four new tubes were made ready for hydrotesting. The hydrotest was done at the same pressure for new tubes. The pressure was held for a much longer time than the time specified for new tubes. There was no leakage observed.

All the fabrication, inspection, testing and witnessing were done in-house as seen in Figs 1â&#x20AC;&#x201C;5. Making tubes this way does not mean recycling Ni. All the four tubes reborn from scrap were put into service. They were subjected to real acid tests as they are installed in the corners where the tubes receive maximum heat from side walls. The tubes remained in service at 920°C for 14 months, i.e., about 10,000 hours until April 2010 when the entire reformer was replaced as a part of project activity. The tubes have contributed about 2,400 tons of methanol production worth approximately Rs. 4 crores, i.e. about $ 900,000 during their second life.

Comments. Ni does not die in the reformer. More service life is still left in the cold end of the reformer tubes. The cold end, i.e., the top portion of the tubes, does not get exposed to high temperatures as does the bottom portion, and thus, it retains its original properties to a considerable extent. The cost for making one good tube from three used tubes is less than 10% of the cost of new tube, and the service life expected from this tube could be 30,000 to 40,000 operating hours or four years to five years.

The extravagant usage of Ni (or, for that matter, all resources) may deprive our future generations of fresh Ni too early. Salvaging reformer tubes may postpone fresh Ni stock outages, and we may escape abuses and curses from our own grandchildren and great-grandchildren for our extravagancy. HP ACKNOWLEDGMENTS The author is highly thankful to the RCF management for giving freedom to carry out the unique exercise of salvaging used reformer tubes and putting them back into service, which was never attempted before in the reformer tube industry.

The author is also thankful to Dr. Ellaya Perumal, Corrosion and Metallurgical Consultancy, Bangalore, for his valuable input to this technical article.

Satish B. Kunte is the chief engineer in the technical services department for Rashtriya Chemicals & Fertilizers Ltd., Chembur, Mumbai, India. He began his career with Nitin Castings at Thane and was employed by JAMS Engineering from 1979 to 1980. Mr. Kunte joined RCF in 1980 as a corrosion and inspection engineer and has held many responsible positions. He holds a BE degree in metallurgy from the College of Engineering in Pune and is a research council member for the Central Electrochemical Research Institute at Karaikudi, India.

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59

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MAINTENANCE AND RELIABILITY

SPECIALREPORT

Consider new materials for ethylene furnace applications An innovative metallurgy solves maintenance issues G. Verdier and F. Carpentier, Manoir Industries, Pitres, France

E

thylene furnaces, cracking liquid or gas hydrocarbon molecules in the presence of steam, operate at high temperatures. While the cracking operation induces coke formation that deposit alongside the radiant coils tube walls, the tubeskin temperatures increase up to what is the material operating limit, or until the pressure drop due to the constriction of surface is too small. Then the furnace is shut down and a mix of steam and air is sent through the coils for decoking purposes.

Coil suppliers have researched on finding construction materials for ethylene furnaces that can withstand higher operating conditions. Several years ago, a family of alloys was developed that can successfully operate under the extreme environment of an ethylene furnace. This article describes new achievements in the metallurgy of ethylene furnace applications.

and thermal shock resistance properties, are altered to the point that the tube material becomes very brittle. The tube can fail at the first thermal shock.

Because of the mentioned issues, radiant coil outlet materials have evolved from what was originally a 25Cr/35Ni material to a higher Cr-content alloy, typically 35Cr/45Ni material.

Background. As mentioned before, high

temperatures and pressures are used to â&#x20AC;&#x153;crackâ&#x20AC;? liquid hydrocarbons and natural gas into olefins. Several processing conditions challenge furnace design and construction materials for the furnace.

Operating temperatures. Ethylene furnaces usually consist of a multi-pass configuration-type coils. Because of the cracking reaction, and coke deposit that takes place as the feedstock is processed through the coils, the outlet tubes of the radiant coils operate under a higher temperature. Coke acts as a thermal barrier. It imposes on the furnace operator and increases the tube skin temperature. This allows the cracking temperature inside the tube to remain the same despite the coke thickness.

Carburization resistance. Because the carbon diffusion is thermally activated, carbon from the coke, with high temperatures, diffuses into the metal of the tubes. The mechanical properties, mostly the creep

New developments. To enhance

carburization resistance of tube materials, new alloys now contain aluminum (Al), in a limited enough quantities to prevent the formation of low-melting point compounds. However, in a sufficient amount, it also decreases creep resistance properties. To restore those creep properties back to where they were originally, tantalum (Ta) is added as carbide former, as shown in Table 2.

Mechanical properties. It is always

TABLE 1. Alloy material resistance in ethylene operations

difficult to balance material properties.

When some developments are achieved on one hand, some drawbacks unfortunately occur on the other hand. While a 25/35 material has superior creep properties, its carburization resistance is affected due to its lower Cr content as compared to 35/45.

Carburization resistance

Creep resistance

Cr25/Ni35 alloy1

Average

Very good

Cr35/Ni45 alloy2

Very good

Average

TABLE 2. Make-up of new alloy for ethylene tubes Element

C

Ni

Cr

Mn

Al

Ta

Ti

Si

% mini

0.35

38.0

28.0

0.5

â&#x20AC;&#x201C;

â&#x20AC;&#x201C;

add

0.53

% maxi

0.6

42.0

32.0

1.50

3.0

add

add

2.004

t $S /J HK40

HP t "EE $S UP JODSFBTF DBSCVSJ[BUJPO SFTJTUBODF t "EE NJDSP BEEJUJPOT UP JODSFBTF DSFFQ SFTJTUBODF GVSUIFS t $S /J /C NJDSP BMMPZT t "EE "M UP JODSFBTF DBSCVSJ[BUJPO SFTJTUBODF t "EE 5B UP SFTUPSF DSFFQ QSPQFSUJFT

FIG. 1

$S /J /C

t "EE /JDLFM UP JODSFBTF DSFFQ QSPQFSUJFT t $S /J

t "EE /C UP GPSN /C DBSCJEFT BOE JODSFBTF DSFFQ SFTJTUBODF )1 /C t $S /J /C

$S /J .JDSP

t "EE NJDSP BEEJUJPOT UP JODSFBTF DSFFQ SFTJTUBODF GVSUIFS HP t $S /J /C NJDSP BMMPZT NJDSP

$S /J "M5B

HP .JDSP "M 5B

t "EE "M UP JODSFBTF DBSCVSJ[BUJPO SFTJTUBODF t "EE 5B UP SFTUPSF DSFFQ QSPQFSUJFT $S /J "M 5B

Historical summary with features.

HYDROCARBON PROCESSING MAY 2011

I 61

SPECIALREPORT

MAINTENANCE AND RELIABILITY

In Europe, a specific pressure vessels directive called PED is required. For a specific material such as a heat-resisting alloy to be “qualified” and recognized for its use in a pressure vessel, the manufacturer of the alloy must obtain a particular material appraisal (PMA). The PMA is provided by a notified body upon review of the raw data regarding mechanical properties supplied by the manufacturer.

For the new Al-based alloy, the Dutch Stoomwezen was selected as the notified body to provide the PMA. Stoomwezen rule requires creep data reaching 1/3 of the design life, in this case 33,000 hours of creep tests or more. Users in Europe who have therefore positively decided to select this alloy had their case backed up with approximately four years of creep tests.

New alloy in service. The Al-based

alloy has now been installed in service for over six years. Besides the material related features such as carburization resistance and creep properties, application of this material in service showed a lower coking rate compared to other alloys when natural gas is used as the feedstock.

Indeed, Al plays an inerting role of the

surface and delays formation of the catalytic coke inherent to gas cracking. The furnace run lengths are longer.

Examples. The new generation of alloy can help both maintenance (carburization resistance, extended tube life) and process (longer run lengths). The section criteria for alloy materials for ethylene tubes highly depends on the problem to be solved at the furnace level.

Case 1. Sabic NL is a major user of the Al-based alloy; six complete furnaces have been converted to the new MzAl tubes, with the oldest furnace operating six years.

This furnace has not shown signs of carburization or creep elongation. Decision criteria for the new installation were driven by maintenance.

Case 2. This European-based ethylene operator has three complete furnaces using the Al-based alloy tube material. The oldest installation has been operating for four years. Only two tubes were recently removed from the furnace of investigation and in-depth study for the Al-diffusion pattern. Tubing adjacent to the Al-based material, after four years, were easily weldable, thus proving the new alloy’s resis-

Asset Longevity Plant & Pipeline Performance

tance to carburization. Additional process benefits occur with tube metal temperatures having been modified to take full advantage of the alloy in comparison with 35Cr-45Ni-type material.

Case 3. An ethylene operator in Asia opted to change out 35/45 material to the Al-based alloy in two full furnaces at two different gas crackers. After several decoking cycles, the run lengths of the two furnaces increased by 20%. The alloy manufacturer is monitoring furnace operations on a permanent basis for this ethylene producer.

Case 4. Another European ethylene producer is in the process of converting one complete ethane cracker. Both process and maintenance benefits are anticipated to occur.

Case 5. Two complete naphtha cracking furnaces were purchased by an European ethylene producer. The alloy selection was to overcome excessive creeping of 35/45 material and address creep elongation and tube life.

Case 6. This North American producer operates gas crackers in furnaces using very small diameter tubes, which are sourced as the problems for run length issues. A full Ta-based alloy furnace was delivered and is in the process of being installed to assess process benefits and lower coking rates.

Options in tube materials. In six

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NOMENCLATURE Aluminum C Chromium Mn Nickel Si Tantalum Ti

Carbon Magnesium Silicon Titanium

NOTES 1

Manaurite XM 2 Manaurite XTM 3 Manaurite XO 4 Manaurite 40XO Gilles Verdier is the director of Metallurgy, and Frederic Carpentier is a senior Metallurgist.

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years, new alloy materials for ethylene tubes have been developed and are being installed by ethylene producers globally. While maintenance related issues such as extensive creeping, or heavy carburization leading to tube change are overcome to extend tube life by approximately two years, the process benefits alone with gas cracking users make this alloy the optimum selection. HP

Together they have 55 years of experience in metallurgy in general, and half of this in heat-resisting alloys. Both hold PhDs in their discipline. Manoir Industries is one of the leaders in supplying high-temperature alloys for the petrochemical industry. Manoir Industries operates four plants in its petrochemical division serving the global industry.

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The Domain provide expertise and consultative services to manufacturing sites scattered worldwide to improve and sustain reliability of Rotating Equipment.

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t $BSSZ PVU FOHJOFFSJOH BOBMZTJT BOE UFTUJOH PG SPUBUJOH BOE TUBUJPOBSZ TUSVDUVSFT t %FWFMPQ '& NPEFM UFTUJOH NFUIPEPMPHZ UP ESBX DPNQBSBCMF SFTVMUT GPS JNQFMMFST CMBEFT EJTDT UVSCP FMFDUSJD NBDIJOFSZ SPUPST HFBST DPVQMJOH TIBGU FYIBVTU DBTF QFEFTUBMT CBTF QMBUFT GPVOEBUJPO QJQJOH FUD t 1SFQBSF UFTU QMBOT BDRVJSF EBUB BOBMZ[F UFTU SFTVMUT XSJUF TVNNBSZ SFQPSUT NFNPT BOE QSFTFOUBUJPOT PG CPUI BOBMZUJDBM BOE QSBDUJDBM QSPHSBNT t %FUFSNJOF NPEBM QSPQFSUJFT OBUVSBM GSFRVFODZ NPEF TIBQF BOE EBNQJOH BOE EZOBNJD DPNQMJBODF TUJGGOFTT PG TUSVDUVSFT t 3FDPNNFOE TUSVDUVSBM EZOBNJDT NPEJmDBUJPOT t %FWFMPQ JNQSPWF JO IPVTF CFTU QSBDUJDFT UP NBYJNJ[F FRVJQNFOU VUJMJ[BUJPO t 1SPWJEF UFDIOJDBM TVQQPSU UP 4"#*$ QFUSPDIFNJDBM NBOVGBDUVSJOH GBDJMJUJFT XPSMEXJEF t 8FMM WFSTFE XJUI /"453"/ ."5-"# BOE PUIFS mOJUF FMFNFOU DPNQVUFS DPEFT t 1SPmDJFOU XJUI DPNNFSDJBMMZ BWBJMBCMF TUSVDUVSBM EZOBNJD EBUB BDRVJTJUJPO TZTUFNT F H 4UBS .PEFM PS TJNJMBS

t .BDIJOFSZ 0&. FYQFSJFODF XJMM CF QMVT

MACHINERY DIAGNOSTICS ENGINEERS

JRE29883

For all the above positions, candidates should have BS/ MS Degree with minimum of 10 years proven experience with strong professional credentials.

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XXX KWH NFEJB DPN

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t .BDIJOFSZ 0&.T TIPQ UFTU TUBOE FYQFSJFODF XJMM CF QMVT

MAINTENANCE AND RELIABILITY

SPECIALREPORT

Testing and repair options for critical dry-gas seal: Updates Do your research when sending compressor seals out for renovations C. CARMODY, AESSEAL plc, Rotherham, UK

U

pgrading from traditional compressor seals to advanced dry-gas seals (DGSs) is entirely feasible and has been pursued for approximately two decades. Over the last five years, DGS production for new compressors has increased as well as well-planned implementation of dry-seal retrofit options. However, primary emphasis on the manufacture of new DGSs has resulted in service issues related to product engineering. As with all industries where demand for new products outstrips capacity to support existing products, both pricing structure and lead time for component repairs have come under scrutiny. This author discusses the issues related to the repair and testing of DGSs.

Advanced seal designs. Utilization of centrifugal compressors for gas transportation has increased over the past decades. In these presumed “clean gas” services, most modern gas movers are now fitted with DGSs in preference over much older conventional wet and labyrinth seal configurations. Simply put, DGSs operate by creating and maintaining a very thin fluid film (< 5 μm) between two mating surfaces. Maintaining this fluid film under all operating conditions is essential to ensure reliable seal operation. The fluid film is so small that the most efficient method of demonstrating its existence is to perform a dynamic test. For this reason, all DGSs are dynamically tested at the time of manufacture and after repair.

Fig. 1 shows a schematic representing such a seal and its associated controls.

DGSs contribute to significantly improved overall machine reliability. Advanced seal designs reduce overall maintenance requirements; they also save power and gas consumption and thus contribute to sizeable operating cost savings in gas transmission services.

Test facilities are key to repairs.

The first phase of providing a global DGS repair service required upgrading the customary repair and inspection facilities to unparalleled standards of excellence.

Since the repair and testing program of a UK manufacturer was aimed at any type, configuration or specification of DGS, the new facility had to be devised with utmost versatility in mind.

To accommodate the repair of largediameter and high-speed seals, it was first necessary to provide a suitable power supply for dynamic test purposes. In the autumn of 2005, the seal manufacturer commissioned a new electrical substation dedicated to reliably supplying power to the company’s Rotherham (UK) DGS Test Facility. This 500 kVA substation is now able to serve both of the two DGS test rig motors as well as the other services necessary to conduct dynamic tests on these seals.

Each of the two test rigs contains a state-of-the-art inverter drive enabling precise speed control of the 106 kW-rated motors up to a maximum speed of 7,000 rpm. Each motor provides the input to a planetary gearbox with three output modules that can be interchanged to provide output speeds up to 45,000 rpm. The power and speed capacity of each test cell will allow the dynamic testing of largediameter, high-speed seals under full operational conditions.

Testing is feasible with either 350 bar (5,000 psi) air or 230 bar (3,300 psi) nitrogen. Air is supplied by a 45 kW multistage reciprocating compressor that delivers 130 m3/hr at a 350 bar capability. Irrespective of the gas type used in testing, it is passed through a coalescing filtration system that removes particles above two microns in size. To enable testing a wider range of DGS operating conditions, it was also necessary to provide additional heat-

Process gas supply Inert buffer gas supply

Seal leakage monitoring FIG. 1

A typical DGS arrangement with a control system.

HYDROCARBON PROCESSING MAY 2011

I 65

SPECIALREPORT

MAINTENANCE AND RELIABILITY

ing or cooling. Cooling of the gas and test equipment is achieved via a 76 kW capacity chiller, whereas additional heating can be introduced via a 60 kW heat exchanger.

Control of test activities is achieved through specially designed test panels and software. The test panels control all gas flow in and out of the test cell and are designed to enable any part of seals under test to be individually pressurized or vented, as appropriate. Test speed and temperature are controlled from an integrated software program. This software also controls the data logging or capture of speed, pressure, gas consumption and temperature taken from critical locations around the seal and test cell throughout the dynamic test.

DGS repair process. The ability to test

DGSs to high standards is only one aspect of a full-repair service. The seal manufacturer has drawn upon many years of experience in the conventional seal industry and transferred the same service-based culture into a first-class DGS repair program.

66

The first element of the repair process is usually an initial price quotation that can also be based upon electronically transferred images or historical repair knowledge of the seal’s condition. This allows the seal manufacturer/repair group to quickly respond to customer demands for reasonable estimates of cost and time-to-repair.

The estimate may well leave the office before a defective seal arrives at the testing/ repair UK facility.

Once a seal arrives at the DGS service facility, it is disassembled and mapped for damage assessment. The damage is then documented in a concise examination report that provides the full scope of work needed to restore the seal to its original asdesigned condition. Firm price and delivery are rapidly offered together with details of the dynamic test protocol, one normally conducted in accordance with API 617.

Already, at this stage of the repair initial design work is conducted. This design work typically covers equipment and fixtures— such as spin test and balance mandrels— needed later in the repair process. Because the facility is geared toward different seal and compressor designs, fixtures must purpose designed for a particular repair. They will later be needed to verify the integrity of rotating face materials and, if required, to effect dynamic balancing to ISO Standard 1940.

A complete material assessment is done, whereby all materials of construction are fully certified. Providing both rapid repair response and all requisite documentation is facilitated by close links to premium suppliers of raw materials. The seal manufacturer/repair group has made it a practice to

FIG. 2

One of the seal manufacturer/ repair group’s two dynamic test rigs.

FIG. 3

A typical graph relating to the logged data taken during a typical DGS dynamic test where pressure and speed are varied to suit future operating conditions.

I MAY 2011 HydrocarbonProcessing.com

order materials beyond those needed for a particular repair. The resulting buildup of DGS parts stock will unquestionably advance the speed of responding to future repair requests.

Replacement and rebuilding.

Replacement of damaged faces is an important facet of the repair process. Premiumgrade corrosion-resistant tungsten carbide, reaction bonded and sintered silicon carbide and silicon nitride seat replacements are offered. Stationary faces can be supplied in blister-resistant carbons and diamondlike carbon (DLC) coated silicon carbide where additional PTFE (Teflon) coatings are also applied to seal faces. Steel components can be repaired and recoated as required and where replacement parts are necessary, full material certification requirements can be met.

In all repairs offered by the seal manufacturer/repair group, replacing consumable items is standard. Such replacement includes all springs and fasteners; also included are secondary seals, where all O-rings fitted to DGS repairs are explosive decompression-resistant grades. Whenever polymer upgrading is feasible, the original selections are replaced with spring-energized PTFE-equivalent sealing devices.

Since most DGSs are supplied with external barrier devices, these components can also be repaired along with the seals.

Labyrinth components and both contacting and non-contacting segmented seals are often supplied as part of the repair program.

Once all of the replacement parts have been produced, re-assembly and testing can proceed. A full-spin test is conducted at 23% over the maximum speed rating of the seal. The component itself is subjected to twice its normal rotational stress.

Also, whenever applicable, full dynamic balancing is done on all rotating assemblies. Similarly, all stationary assemblies are subjected to force-displacement tests that exercise the face assembly and serve to identify seal hang-up. Only then are the various assemblies finally fitted into the test equipment, as shown in Fig. 2.

Customers are invited to observe DGS testing at the company’s main facility. Even if unable to attend, customers can still participate anywhere in the world and view the test progress in real time via a WebEx Internet link. A second remote surveillance option involves a 3G mobile phone link, whereby the test is being filmed with a 3G camera.

This option is available in the form of live video streaming to any mobile phone with

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MAINTENANCE suitable 3G features. Irrespective of whether customers choose to witness the tests, each test is fully recorded and a CD of the full test event is produced for each individual seal. The CD is normally supplied with the information pack that is placed inside the shipping cartons for the repaired seals.

Although tests are normally conducted in accordance with API 617, the seal manufacturer/repair group often accepts and carries out additional customer testing requirements. Dynamically testing each seal typically takes three or four hours, which includes second-by-second data logging (Fig. 3). Once the dynamic test is complete, the seal is dismantled, inspected and subjected to a further static pressure test following re-assembly.

The company provides an information packet for each repaired seal; the data packet normally includes the pre-repair inspection report, a post-test condition inspection report, full details of the dynamic test itself, a full set of tabulated dynamic test results, a graph of the data logging results, and a full set of installation details. It includes a spin test certificate, a balance test certificate, a dynamic test certificate, plus full certificates of conformity for any materials used.

The repaired seal is shipped in a heavy-duty airfreight case, which incorporates carrying handles and a locking mechanism. In addition to the actual seal repairs, an assembly tool replacement service is offered. This is particularly useful when seal assemblies were produced at locations remote from the compressor factory, but the compressors were shipped without the best available DGS assembly tools.

Clearly, compressor owner-operators now have unprecedented and solidly verifiable options. They can decide to continue working with the OEM, or can trust the demonstrated capabilities of a company whose expertise in seal design is firmly anchored in a totally modern and highly accessible testing facility. Most importantly, the customer is now at liberty to investigate the full extent of this company’s commitment to timely repairs and superbly executed testing of any compressor DGS in use today. HP

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MAINTENANCE AND RELIABILITY

SPECIALREPORT

How to justify root-cause failure analysis for pumps New method uses annualized risk to determine RCFA analysis levels R. X. PEREZ, Pumpcalcs, San Antonio, Texas

W

e have all read about and acknowledged the merits of root-cause failure-analysis methods. But not everyone agrees on when and how these methods should be used.

In times past, the author worked for a while within an organization so enamored with failure analyses that the formal reports were to be written by a machinery engineer for each and every plant machinery failure. This seemed unusual and even a bit extreme.

Yet, the issue begs an important question: When is formal failure analysis justified? Before answering and explaining, we need to briefly agree on the customary definition of a root cause failure analysis. A root-cause failure analysis (RCFA) is a formal analysis of an equipment or system failure with the intent of uncovering all latent causal factor(s) and contributing factors, so that similar future failures may be prevented.

Latent causal factors are unseen or hidden causes hiding

just below the surface of the wreckage. Whenever a repeat failure occurs, we must realize that the hidden causes are still at play and that future failures are likely. It certainly makes it imperative that during the failure-analysis process, the analyst (or analysts) will look beyond the physical evidence and uncover the true latent causes for the failure. Here are a few quick examples of latent causal factors in process pumps: • Parallel operation of pumps drives a pump off its allowable flow range, which then causes internal recirculation and high bearing loads • Low-flow pump operation due to process changes results in frequent seal failures • Oil supply is inconsistent because of inherent issues with an inexpensive oil delivery choices (oil ring degradation) • Design weaknesses in certain bearing protector seals can result in oil contamination • Oil contamination is caused by poor lubricant storage practices • Oil consolidation efforts often lead to unwise oil replacement choices, and ultimately causes bearing failures • Bearings selected in accordance with the generalized recommendations of prominent industry standards are not always the best choice.

Root-cause failure analysis: A case history. A petrochemical plant and oil refinery was experiencing recurring failures of a cylindrical roller bearing in a critical centrifugal pump (Fig. 1). Transition from belt-drive to direct-drive configuration of the pump led to unexplained bearing failures and costly downtime.

The bearing manufacturer investigated the application conditions and the failed cylindrical roller bearings. Changing from a belt-drive to a direct-drive arrangement had drastically reduced the radial load on the existing bearing. In turn, this had led to rollers slipping on the inner raceway. The solution was simple: the original bearing was readily replaced by a deep-groove ball bearing.

In essence, the bearing manufacturer determined that a light load on the cylindrical roller bearing was the cause of bearing distress. The latent root cause was the transition from belt-drive system to a direct-drive arrangement. The solution to this issue was to select the proper bearing for the new load conditions.

Time is money. The RCFA method is one of the most pow-

erful tools of a reliability program, but it is also one of the most time-consuming and, thus, costly endeavors. Since time is money, RCFAs must be administered judiciously.

Like all decisions made in a competitive environment, the decision of when to conduct an RCFA must be based on economics.

Since not all failures are created equal, not all failures warrant the same level of analysis. The decision to conduct an RCFA should be based on the answers to two questions: 1. What is the consequence of the failure? Obviously as the failure consequence rises, the need for analysis becomes more critical.

2. What is the failure frequency? The higher the failure rate the more attention the piece of equipment should get.

FIG. 1

Recurring failure of cylindrical roller bearing in critical centrifugal pump. Photo credit: NSK Bearings Europe.

HYDROCARBON PROCESSING MAY 2011

I 71

SPECIALREPORT

MAINTENANCE AND RELIABILITY

Consequence per event

TABLE 1. Consequence vs. failure frequency 0.1

10

100

$10,000,000

$100,000

$1,000,000

$10,000,000

$100,000,000

$1,000,000,000

$1,000,000

$10,000

$100,000

$1,000,000

$10,000,000

$100,000,000

$100,000

$1,000

$10,000

$100,000

$1,000,000

$10,000,000

$10,000

$100

$1,000

$10,000

$100,000

$1,000,000

$1,000

$10

$100

$1,000

$10,000

$100,000

$100

$1

$10

$100

$1,000

$10,000

$10

$0

$1

$10

$100

$1,000

TABLE 2. Typical risk matrix High consequence

A

A

A

Medium consequence

B

B

A

Low consequence

Annual failure frequency 1

0.01

C

C

B

Low failure frequency

Medium failure frequency

High failure frequency

If we denote the consequence as C and the rate of failure, F, we can define the risk, R, of failure as the product of consequence and the failure rate: Risk (R) = C ⫻ F So, if a pump that costs $20,000 to repair fails four times a year, this represents an annualized risk of $80,000/yr, i.e., $20,000 ⫻ 4. Next, we will construct a risk matrix based on a broad range of consequences and failure frequencies (see Table 1).

Notice as risk levels (i.e., consequence times frequency) exceed $1 million/yr, they are highlighted in a rose color. Risk levels of $100,000/yr are highlighted in yellow, and risk levels of $10,000/ yr are highlighted in green. Risk levels of $1,000 and below are shown in gray. They are assumed to warrant little or no concern.

In general, we can say that high-risk issues are in the upper righthand corner of risk maps and low-risk issues are in the lower lefthand corner of risk maps (Table 1).

One can consider these annualized risk levels to be potential revenue that can be recovered if the root cause of an issue falling in one of these cells is found, and the required remedial steps are implemented. With that being said, we should view all RCFA pursuits as potential projects—and, as on any projects, we must assess their cost-to-benefit ratio.

Suppose we have an event that is occurring 10 times a year with a consequence of $10,000. This represents an annualized

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MAINTENANCE AND RELIABILITY risk of $100,000. If the total cost of remedial action and RCFA is $20,000, the project will have a payback of about 73 days. On the other hand, if there is a $100,000 consequence that occurs once every 100 years, this only represents a risk of $1,000/yr. It would not make much sense to assign a multi-disciplinary analysis team to investigate this failure.

The take-away here is that annualized risk is a better means of determining the level of analysis justified—not the consequence level. However, it is possible to also set a maximum allowable loss trigger for a failure investigation. For example, a site may choose to investigate all events resulting in losses of $1 million or more, regardless of their frequency. Together, the risk map and the maximum allowable loss methods can provide clear RCFA guidance.

Most production companies take this basic risk-based approach and develop their own risk matrix, as shown in Table 2.

Each organization must define what high-, medium- and low-consequence events are, along with low-, medium- and high-failure frequencies. For example, a company might choose to define high-, medium- and low-consequence events as those resulting in losses of more than $250,000, $100,000 to $249,999, $25,000 to $99,999 respectively. High-, mediumand low-failure frequencies could be defined as more than two failures/yr, more than one failure every two years, or less than one failure every two years, respectively. So, a $150,000 failure occurring every year would fall in the “B” risk level category, but a $150,000 failure occurring twice or more a year would fall in the “A” risk level category.

Non-monetary events, such as environmental releases and safety events, may also be included in a risk matrix. An example of a high-attention environmental event could be a release of 10 barrels or more of any hazardous fluid from the process. A highrisk safety event could be any lost time accident.

Notice in the risk map (Table 2) that even high-consequence events occurring at lower frequencies are considered “A” risk levels. This is because this risk map incorporates a maximum allowable loss trigger regardless of event frequency for high-consequence events. It serves as management’s way of conveying that all major events are unacceptable regardless of frequency.

SPECIALREPORT

Level C issues. Failure events falling in the “C” region of

the risk matrix can be considered “bread and butter” investigations. Even though they are termed low-consequence events, they typically represent the largest number of RCFAs. Based on their sheer numbers, they can represent the greatest cost-saving potential for a plant. Level C RCFAs are often conducted by mechanics using the “5 Why” or similar methods. A systematic use of Level C RCFAs can lead to a dramatic and rapid reduction of repeat failures.

Proceeding to analyze. The root cause failure analysis effort should be considered one of the main pillars of machinery reliability. We have all seen formal failure investigations solve the most perplexing and costly problems. But to ensure success, participants must be given the proper training and the time to uncover latent-root causes.

The payoff is well worth the price. Consistent administration of these methods can empower an organization to whittle down early and frequent machinery failures until only predictable endof-life failures are experienced. HP

Robert Perez is the author of Operator’s Guide to Centrifugal Pumps and co-creator and editor of the PumpCalcs.com website.

He has more than 30 years of rotating equipment experience in the petrochemical industry and has numerous machinery reliability articles to his credit. Mr. Perez holds a BS degree in mechanical engineering from Texas A&M University at College Station and an MS degree in mechanical engineering from the University of Texas at Austin. Mr. Perez holds a Texas PE license. He can be reached at rxperez@pumpcalcs.com.

RCFA levels. Having defined A, B and C risk level events, we need to determine the extent to which analysis is warranted at each of these levels. Here are some general guidelines as to when and whom to assign to the analysis of A, B and C level events: Level A issues. Failure events falling in the “A” region of the risk matrix justify the highest level of analysis. This usually means that a multidisciplinary team should be used to mine the data and procure the physical evidence in order to determine the most probable cause or causes of the failure. Typically, this requires a team consisting of three to five technical specialists—often composed of a machinery engineer or technician, vibration tech, process engineer, operators, etc.—should be formed to leave no stone unturned during the investigation. The team may take a few days or weeks to finalize their findings and recommendations.

Level B issues. Failure events falling in the “B” region of the

risk matrix are considered costly but do not justify a “full-blown” team approach. Level B analyses are typically conducted by an engineer or highly skilled machinery technician working with process support. This type of analysis rarely takes more than one week for an individual to finalize.

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MAINTENANCE AND RELIABILITY

SPECIALREPORT

Spiral heat exchanger in desalter service solves fouling issues Technology offers problem-free operation along with considerable maintenance savings C. WAJCIECHOWSKI, Alfa Laval, Richmond, Virginia

A

major US refinery was experiencing severe fouling and plugging problems in two shell-and-tube (S&T) heat exchangers installed to cool desalter effluent using cooling water.

In 2008, the refinery replaced the two S&Ts with a fouling-resistant spiral heat exchanger (SHE). The SHE gives continuous problem-free operation, higher process reliability and more consistent wastewater treatment temperatures than the S&Ts. Best of all, there has been no plugging and, based on savings in maintenance and cleaning costs alone, the payback time was less than 18 months.

In the desalting process, crude oil is contacted with hot water to remove impurities such as chloride salts and particulate matter before continuing through the crude preheat train into the refinery.

The solids and salts collect in the process and must be flushed out with the effluent water. In a process called “mudwashing,” solids are mixed with the effluent water and removed. The effluent water—now contaminated with oil, suspended solids and dissolved solids—needs to be cooled before traveling downstream to wastewater treatment.

As shown in Fig. 1, Refineries typically use two stages of cooling before wastewater treatment: 1) effluent cooling by preheating feed water, and 2) effluent cooling with cooling water. The first application is a heat recovery service; so maximizing the efficiency of this heat exchanger is important. The second heat exchanger is a trim cooler and is designed to protect the wastewater treatment plant from excessively hot effluent. Unfortunately, due to severe fouling in both applications, refiners will bypass the heat-recovery service and foul the cooling-water exchanger

so rapidly that it damages the wastewater treatment system. The consequences of the damage include unplanned downtime and environmental penalties for noncompliance. Fortunately, there is a solution to this widespread problem of desalter effluent fouling with the SHE. These facts are very evident in a specific US refinery that has operated a SHE in desalter service since 2008.

The process of cooling the effluent water has caused fouling headaches in refineries for years, as was the case with the major refinery covered in this article. Due to continuous, costly fouling and plugging problems, it was necessary to shut down the S&Ts cooling the desalter effluent water once a month on average. The unplanned downtime caused problems for the wastewater treatment plant, since the effluent temperature was poorly regulated and frequently out of specification.

Problem-free operation. Shortly after the SHE startup, the refinery had satisfactorily noticed that the pressure drop through the unit remained stable. Increasing pressure drop had frequently been one of the reasons the refinery needed to shut the S&Ts down for cleaning. The SHE continued to provide trouble-free operation and, over an extended period, only a moderate reduction in thermal performance was measured.

SHE recommended. SHEs have a

Cleaned once since startup. In June

well-proven technology for fouling applications. Its single-channel design resists

2009, after 14 months of operation, the refinery opened the SHE for the first time

Crude oil START

Feed water

plugging while the fully counter-current flow paths allow for effective heat recovery in a compact space.1 SHE is the only technology that copes easily with the solids in the stream and can handle process upsets with high solid concentrations. Due to the design efficiency, it was possible to install just one SHE. This only had 50% of the surface area of the S&Ts, yet it still outperformed them in the long term.

Desalted crude oil

Desalter Desalted water Feed water Cooling water

Desalted water to treatment

Cooling water FIG. 1

Simplified desalter system configuration.

HYDROCARBON PROCESSING MAY 2011

I 75

SPECIALREPORT

MAINTENANCE AND RELIABILITY TABLE 1. Cost savings when using SHE Unit

Service

Cleaning frequency (amount/year)

Cost per cleaning*

Total cleaning costs/year

2 shell-and-tubes

Desalter effluent cooling

12

$6,000

$72,000

1 spiral heat exchanger

Desalter effluent cooling

0.86

$3,250

$2,786

* S and T cleaning costs calulated as $2,500 (disassembly/assembly tube side, two units) and $2,500 (cleaning rig: day one and $1,000 cleaning rig: day two). Spiral cleaning costs calculated as $1,250 (disassembly/assembly one unit) and $2,000 (cleaning rig: 5.5 hrs).

ing water side. With the S&T exchangers, they witnessed many plugged tubes after only one month. The spiral was mechanically hydroblasted and placed back in service the next day. By December 2010, it was noted that the SHE had only been cleaned once since startup and was still operating efficiently. An onsite engineer stated that it’s doing well and there have been no complaints.

FIG. 2

Single-channel geometry resists plugging while counter current flow efficiently recovers heat.

to check for fouling—an operation made easy by the option of integral davits on each cover. To their surprise, the engineers found only a thin greasy coating on the effluent side and minor scale on the cool-

Savings. The cost to clean the tube side of the two S&T exchangers was estimated by the refinery in Table 1. Given the frequency of cleaning, the investment cost for the SHE was returned in less than 1.5 years on savings in maintenance alone (Table 1).

Summary. The SHE technology includes

these benefits:

MICROTHERM SlimFlex

• Fouling problems in refinery desalter effluent services can be greatly reduced or eliminated.

• The single-channel design and robust construction make the spiral an ideal product for this challenging refinery service (Fig. 2).

• Often, the capital cost of the spiral equipment can be justified with the savings in maintenance/cleaning costs alone, not to mention the added reliability of the process and more consistent wastewater treatment temperatures. HP 1

LITERATURE CITED Anderson, E., “Minimizing refinery costs using spiral heat exchangers, PTQ Q2 2008.

Chris Wajciechowski is currently a business development manager in the process technology division of Alfa Laval. Mr. Wajciechowski is a graduate of Virginia Tech with a BS degree in chemical engineering. Prior to his current role, he held several positions in the refining and petrochemical industry for Alfa Laval. Mr. Wajciechowski has been with Alfa Laval for 12 years.

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MAINTENANCE AND RELIABILITY

SPECIALREPORT

Optimize reordering of critical raw materials and parts New models evaluate the ‘total’ costs in receiving and storing materials for a refinery A. GOTI and N. ZABALETA, University of Mondragon, Spain; A. GARCIA and M. ORTEGA, Polytechnic University of Madrid, Spain; J. URADNICEK, Slovak University of Technology, Bratislava, Slovakia

O

ptimizing the reordering of raw materials and maintenance spare parts is a problem extensively studied in the academic field, but poorly solved. This project focuses on the problem of reordering points and batch sizes via a commercial discrete-event simulation software. A product for reordering points was developed and tested. It was successfully used to optimize the reordering points and batch sizes of several critical spare parts for a refinery. The satisfactory results enabled reducing the total ordering, storage and backorder costs.

Inventory management principles. Most companies

The problem. The optimization problem studied here considers several input variables, constant variables, assumptions and output objectives. Fig. 1 shows the overall context of the problem. The inventory problem deals with two input variables: • Reordering point when a new purchasing order, RP, is launched • Maximum amount of elements that the warehouse already has ordered and is en route to the warehouse, Qmax .

In the case of Petronor, each time we are below the reordering point, a purchasing order is sent to fill the space of the reference up to Q max . Thus, the reordering quantity of any instant in time, Qi(t), will have to take into account how much is Qmax ; how many units are in the warehouse at that moment, Q(t), and if any previous order sent—Qi-1(t), Qi-2(t), etc.—have not arrived yet; and how many units are on their way to the warehouse.

The behavior of the remaining elements of the tool developed is equal to what was defined by Goti,3 and is summarized here.

Concerning the constant values and assumptions to be modeled, it is assumed that: • The logistic lead-time, LT, the time taken from when a purchase order is submitted to the arrival of the products related

are implementing lean production principles. These are related to minimize waste from unneeded and inefficient operations, such as excessive buffering operations to serve the client or backorders.1 These two inefficiency types can be resolved by defining a proper reordering point—as too low reordering points may worsen service rates, whereas excessively high reordering points increase storage costs. An adequate definition of batch size to reorder can improve total purchasing efforts plus management costs for products to be stored. Additionally, it is a parameter that definitively influences overall storing plus backorder costs for the facility.

Several authors and companies offer their safety stock and/or reordering point Input data Input data calculators.2,3 Nevertheless, literature information is very scarce when dealing with Ordering cost €250.00 No. orders 2 Reordering point 20 Holding cost €233.62 Average stock x time 20 Lot size 50 joint optimization of reordering points and Back order cost €410.00 Non-met demand 41 Lead time 2.56 batch sizes. Considering this background Total cost €893.62 Demand D 12 and context conditions, this research projSupplier Reception and production of Wroclaw plant ect is based on the work presented by Goti3 the received purchased orders where a reordering point optimizer tool 0 was developed and tested along with a joint Input reordering point plus batch size optimizer. buffer The tool has been successfully applied to 0 30 0 several critical spare parts for Petroleos del Truck Norte S.A. (Petronor) refinery at Muskiz, Reference Spain. The results were obtained through Q, LT An order is launched if available stock is lower than the reordering point simulations using the tool presented, and they coincide with what the purchasing FIG. 1 Graphical description of the problem to be solved. department wanted, and significant savings were obtained.

HYDROCARBON PROCESSING MAY 2011

I 79

SPECIALREPORT

MAINTENANCE AND RELIABILITY

to that order, is a variable but known. Historical data is available so that information can be fitted to a known distribution.

• Customer demand rate of client, TT, is the speed in which the client consumes buffered products; it is known. Historical data is available, so that information can be fitted to a known distribution.

• The buffer containing the arriving products has an infinite capacity.

• Each batch of products jointly bought has a fixed purchasing order cost, Ce. • Each product has a fixed cost per unit of time for being stored in a buffer, Cs. • A fixed backorder cost, Cb, is assigned each time a client needs a product from the buffer and does not find any products in inventory.

Finally, the outcomes to be optimized may consider the joint optimization of these costs: • Minimizing the total cost spent on submitting purchase orders and intake at the warehouse, Cet .

• Minimizing the total holding cost for elements in the buffer, Cst .

• Minimizing the total cost of not serving the client because the buffer is empty, Cbt .

Each one of these costs will be calculated by multiplying the times an event related to the listed costs happens. So, being ne and nb, respectively, the amount of purchasing orders submitted and the amount of non-served products in the studied period, Cbt and Cet are calculated as:

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Cbt = nb Cb

(1)

Cet = ne Ce (2) While calculating for Cst is performed taking into account Cs and the amount of time each of the m products is stored in the buffer, ts , as it is shown in Eq. 3: (3) Scope of the problem. Optimizing for Qmax and RP vari-

ables while considering Cbt , Cst and Cet criteria, can be formulated as a single-objective problem (SOP) or a multi-objective optimization problem (MOP). A SOP could be presented by summing all purchasing, buffering and backorder costs, while MOP would be formulated to optimize a vector of functions: f = (f1, f2, ..., fn )

(4)

where f represents functions that depend on the decision variables, Q and RP. The optimization proposed here considers the total costs as described in Eq. 5 as a SOP problem: f (Qmax, RP) = Cst Cet Cbt

(5)

Modeling and optimization techniques. The discrete event simulation (DES) was used as a modeling technique for this problem. The main advantages of DES are two:5–7 • Standard DES-based tools provide capabilities of modeling or modifying complex system models.

• DES is closely related to stochastic systems, so they are appropriate when simulating real-world phenomena, since there are few situations where the actions within the system can be completely predicted in advance.

To generate stochastic events, simulation packages generate pseudo-random numbers to select a particular value for a given distribution. Thus, using pseudo-random numbers, it is possible to implement the stochastic nature of actual spare part and consumable consumption in DES models.

Specifically, the development of the model was done using an educational version of commercial software. This was collaboration between the authors and Petronor. Both parties could experience the potential benefits of a DES approach for addressing realworld situations, which are quite different from those that can be Results of the optimization process

Total cost, €

120,000 80,000 12

40,000

10 Reorder point, 8 units

0 0 15 Qmax, units

FIG. 2 Select 168 at www.HydrocarbonProcessing.com/RS 80

Optimization results

20

25

6

MAINTENANCE AND RELIABILITY found in text books. The study focused on some references using the data available at that time. Indeed, Petronor was very satisfied with the proposed approach and stated that values obtained from the study were very reliable and would be implemented.

The authors are very confident that Petronor will rely in the future on DES approaches for both this type of analysis and for others. As to reordering point studies, they may consider acquiring some software to recalculate values (as data change overtime).

SPECIALREPORT

TABLE 1. Economic data of the optimization case Reference

Consumption, units/month

LT, days, normal distr.

1 2 3 4 5 6 7 8 9 10 11 12 Oxygen bottle 4 5 1 2 1 3 1 0 1 2

0 1

Average

Deviation

75

1

TABLE 2. Logistic data of the optimization case Parameter

Unit

Optimization algorithms and brute force. Depend-

Ce

$/order

7

ing on the complexity and the characteristics of the optimization problem, different techniques can be used. For instance, if the problem is faced as a MOP, a multi-objective evolutionary algorithm (MOEA)—i.e. the non-dominated sorting genetic algorithm NSGA-II9—can be used. In case a SOP (minimizing total cost as the unique objective) is presented, single objective optimization algorithms may be enough to solve the problem. In this case, the scatter search utility of an optimization set of tools was used to develop the optimization tool.10 This software was chosen due to two main reasons. First, in terms of its usability, it provided a convenient environment that allows the user to easily tune the optimum seeking procedure.10 Second, in terms of efficiency and effectiveness, it performed very satisfactorily for this study, and the authors highly recommend its use.10

Cs

$/(product.year)

37.5

Cb

$/(unit not served in time.hour)

180

Implementation case. As it was previously stated, the set of modeling plus optimization techniques was applied to optimize the reordering points of several references for Petronor’s Muskiz refinery. To have an idea of the size of this refinery, it can be mentioned that spending for parts exceeds €42,000 (Fig. 2).

In this case, there were some special interest elements to be optimized because they have generated several backorders in the past. One of these elements, an almost pure oxygen bottle, is used in the laboratory for testing samples of petroleum-derived products that reach the refinery. It is worth remarking that although it is not very expensive, a backorder for this bottle may stop the laboratory tests needed to homologate the material samples analyzed. To avoid this hugely expensive circumstance, these samples are urgently sent to other laboratories located all over Spain when this backorder occurs. Thus, the backorder cost represented in this case comprises the cost of having to send samples to other laboratories. Data shown in Tables 1 and 2 reflect the economic and logistic data for this problem, respectively.

It is worth noting that the client plant work is scheduled on three shifts. The optimization problem, as shown in Eq. 6 will be faced, where RP can acquire any positive integer value. Finally, the warmup period and simulation period values are five and 229 days respectively, and have been calculated considering the suggestions provided by the theory of the simulation, compiled by Goti.11 Results. The results obtained after the optimization process using the previously shown values are ranked in Fig. 2.

The optimization software indicated that the RP and Qmax values corresponded respectively to 10 and 14, when the values used before were respectively 8 and 16. Thus, it is worth remarking two aspects: • For this case, the optimization results proposed a roughly equal average stock level of the reference within the plant.

• But using the new reordering policy (with a higher reordering point but with a more tense logistic flux), the overall logistic cost achieves a significantly lower value. HP

Value or distribution

ACKNOWLEDGMENTS The authors thank the collaboration of Jose Luis Arredondo, Javier Lucas Fernandez and Iñaki Orbe from the purchasing department of Petronor, along with the help and support provided by Lanner, developer of Witness, and OptTek, developer of OptQuest. This project has been funded by the following funding programs: Demagile Tools: Development of decision-making tools for the implementation of principles related to the ‘Leagile production’. Project funded by the Basque Government (Basic and Applied Research Project, PI2009-24 code).

Servistock: Development of a tool for the joint optimization of logistic safety stock levels and transportation types (European transnational project MANUNET-2008-BC-001).

Availafacturing: Development of a tool for the management of technical assistance service networks for the availability maximization of manufacturing equipment and/or products (European transnational project MANUNET2009-BC-006).

LITERATURE CITED Complete literature cited is available online at HydrocarbonProcessing.com.

Aitor Goti Elordi, PhD., is a member of the Spanish reliability committee, focuses his research activities are the areas of optimization and simulation in maintenance, production and logistics.

Álvaro García is a profesor at the Univesidad Politécnica de Madrid and mainly focuses his research activities within the field of optimization and simulation in production and logistics.

Dr. Miguel Ortega teaches at the Universidad Politécnica de Madrid and researches and works with companies in optimization and simulation fields.

Noemi Zabaleta received her PhD in industrial engineering from Mondragon University, Basque Country (Nothern Spain). Her research is focused on technology transfer and project management.

Juraj Úradníček received his PhD in mechanical engineering from Slovak University of Technology in Bratislava. He has published papers in the field of mathematical modeling of mechanical systems, simulation and optimization.

HYDROCARBON PROCESSING MAY 2011

I 81

Oil Refinery | Marcelo Senatore | Technical Marketing | Germany

If eight shutdowns could be reduced to one, what would that do for your productivity?

When a German oil reďŹ nery experienced corrosion problems in its crude oil

distillation column, it turned to Sandvik for the solution. Since pitting and under deposit corrosion were the reasons behind the short heat exchanger lifetime, Sandvik suggested replacing the previously used carbon steel tubes with next generation duplex stainless steel grade Sandvik SAF 2707 HDÂŽ.

The new tube material was installed in 2006. Inspection after 4 years showed only slight erosion corrosion. After cleaning, eddy current testing and hydro testing, the bundle was reinstalled to run for another 4 years.

Reducing the number of shutdowns from 8 to 1 over a 4 year period has increased plant safety and resulted in big savings in terms of material replacement, manpower and lost production.

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w w w. s m t . s a n d v i k . c o m / o i l re fi n e r y

HEAT TRANSFER

Update on designing for high-fouling liquids A critical analysis of shell and tube exchanger systems looks at ‘clean and dirty’ service performance J. M. NESTA, Fluor Canada Ltd., Calgary, Alberta, Canada; and C. A. COUTINHO, Heat Transfer Research, Inc., College Station, Texas

H

eat exchanger design for high-fouling liquid hydrocarbons requires careful consideration to minimize the frequency of costly shutdowns. In an earlier article, an alternative methodology was presented that aimed at achieving a critical velocity made possible by a reduced amount of excess surface area.1 This was recommended in lieu of typical fouling resistances that result in large excess surface areas with lower velocities for the same pressure drop. Here we discuss: • Importance of shear stress by controlling the fluid velocity • Role of allowable pressure drop • Fouled performance of “low-foul” designs compared to conventional designs.

Note: The designs outlined involve the development of a “low-foul” ’ exchanger (as opposed to no-foul). This avoids the perception that fouling can be completely eliminated using high-shear stress methods.

Rather, it is advisable to provide an overdesign should fouling occur or accommodate future increases in capacity.

Role of shear stress. Wall shear has now been established as an important parameter to gauge the fouling propensity of a fluid. Calculating the shear stress at the inner surface of a tube with fully developed single-phase flow is straightforward.

However, the determination of shear stress on the shell side is more uncertain. The flow direction with conventional baffles varies from cross flow to axial flow, including a transition region between the two.

At high Reynolds numbers, some of the crossflow pressure drop does not result from shear stress but from drag. For these reasons, shear-stress calculations in the past were cumbersome, and fluid velocity

was regularly used as a proxy. Recent versions of the design software produced by Heat Transfer Research, Inc. (HTRI) can provide shear stress as an output value for both tube-side and shell-side flow. This enables engineers to establish an appropriate relationship between the shear stress and fouling tendency of particular fluids. The shell-side shear stress estimation has more uncertainty than the tube-side method. However, it still provides reasonable results for baffle cuts of 20%–25% and baffle spacings of 30%–60% of the shell diameter.2 In the absence of prior testing or field evaluation, the critical shear stress value that mitigates fouling is unknown. Towards this end, an appropriate rule of thumb for crude oil exchangers is a shear stress of 15 Pa–20 Pa on both the shell side and tube side. This cutoff value has been chosen from experience. Engineers may want to use the higher value for the most severe services, such as the hot end of crude preheat trains. For shell-side evaluation, only the crossflow shear stress is used. It is recognized that shear stress for axial flow over the baffle tips will be low, and some fouling can be expected in this region. Note: Tube-side value of density times velocity squared for both liquids and gases should not exceed 8,928 Pa (␳v2 ≤ 8,928 Pa) to prevent erosion at the tube ends unless ferrules are used.3 In all designs discussed in this article, the value of ␳v2 was maintained below 8,928 Pa. There is no limit on maximum shear for the shell side.

flash points and other parameters that serve to optimize operating and pumping costs. However, it must be recognized that severe fouling operations require a critical single-phase shear stress to provide adequate performance. Thus, implicit expenses for maintenance and loss of performance (for example, increased fired-heater fuel cost) must be included in the evaluation for the optimum allowable pressure drop.

These added maintenance expenses, due to poor designs that allow low pressure drops, may completely overwhelm the theoretical savings that can be attained with reduced pumping costs.

When designing shell-and-tube heat exchangers for heavy fouling services, it is the fouled pressure drop that must be considered. While the pressure drop for the clean case is easily computed, the fouled pressure drop is often a guess. One way of tackling this problem is to use a high-shear stress design that minimizes the difference between clean and fouled performance.

This reduces the margin of error of the pressure drop fouling allowance. Examples show that fouled pressure drop can be 2 to 3 times higher than clean pressure drop for conventional designs. Thus, the task of estimating a proper allowance with conventional designs for high-fouling services is quite difficult. The examples also discredit a popular misconception that lowfoul designs require more pressure drop than conventional designs. As shown in Table 1, low-foul designs typically have a lower pressure drop than fouled conventional designs.

Role of allowable pressure drop.

Plant designers have reference tables to calculate the allowable pressure drop across a preheat train based on liquid viscosity,

Different design performance.

In general, the fouled performance of different designs may be simulated if 1) HYDROCARBON PROCESSING MAY 2011

I 83

HEAT TRANSFER TABLE 1. Comparison of low–foul and conventional designs for clean and fouled cases Low–foul based on 15 Pa shear

Evaluation parameter

Clean case

808

811

1,286

1,427

$1,000,000

$1,000,000

$1,359,000

$1,474,000

Tube side

⌬P, kPa

Shell side

Tube side

19

19

61

66

240

175

149

126

v, m/s

0.87

0.60

0.47

0.40

␶, Pa

15–17

13–14

9–10

8

⌬P, kPa

199

171

146

127

v, m/s

2.43

2.24

1.80

1.61

␶, Pa

15–17

13–14

9–10

8

+3

–30

–33

–40

% Excess (±) area for fouling ⌬P, kPa

240

287

388

412

v, m/s

0.87

0.82

0.84

0.83

␶, Pa

15–17

14–15

14–16

14–16

⌬P, kPa

239

241

299

311

v, m/s

2.55

2.55

2.51

2.49

␶, Pa

20

20

20

19–21

TABLE 2. Geometry specifications of conventional and low-foul designs Low-foul based Low-foul based on 15 Pa shear on velocity flow

Area, m2 Number of shells, par × series

Conventional

Conventional with 10% over design

808

811

1,286

1,427

2×4

2×4

2×4

2×4

650/660*

760

840

880

TEMA type

BES

BET

BET

BET

Tube length, m

5.2

4.9

6.1

6.1

Tubes/shell

251/255*

274

341

379

Tube passes

2

2

2

2

Tube pitch, mm

31.75

31.75

31.75

31.75

Tube angle, deg

90

45

45

45

190/210/235/235*

200

210

219

Shell diameter, mm

Baffle spacing, mm

*A variable baffle spacing, shell size and tube count were used for Design 1 (from hot shell to cold shell).

Clean Shear based low-foul design

Fouled

v = 2.4 m/s ␶ = 16 Pa

v = 2.6 m/s ␶ = 20 Pa

t = 0.3 mm

Rf = 0.0004 m2 °C W-1 Conventional design with 1.1 safety factor

v = 2.5 m/s ␶ = 20 Pa

v = 1.6 m/s ␶ = 8 Pa

t = 2.1 mm

Rf = 0.0030 m2 °C W-1

FIG. 1

Tube side parameters for designs 1 and 4.

the fouling is assumed to be asymptotic or nearly asymptotic and 2) each design achieves approximately the same shear stress at asymptotic conditions. Thus, the fouled performance of various exchangers can be simulated using new software by 84

Conventional with 10% overdesign

Area, m2

Shell side

Evaluation parameter

Conventional

Cost, US$ % Excess (±) area for fouling

Fouled case

Low–foul based on velocity flow

I MAY 2011 HydrocarbonProcessing.com

assuming an asymptotic shear stress and fouling layer thermal conductivity value. A design is checked for fouled performance by specifying the fouling layer thickness by trial and error until the asymptotic shear rate is achieved. The intent is not to pre-

dict fouled performance with any sort of accuracy, but rather to investigate the relative performance of different designs for a given set of assumptions. While the fouling layer is not likely to evenly coat the tubes, the assumption is adequate for a relative comparison of fouled performance. The four designs evaluated include: • Design 1: A low-foul design based on a critical shear stress of 15 Pa • Design 2: A low-foul design based on velocity • Design 3: A conventional design based on fouling factors and typical allowable pressure drop • Design 4: A conventional design as per Design 3, plus a 1.1 multiplier on flow and duty.

The geometries of all designs are available in Table 2. Design 2 (low-foul based on velocity) is an actual exchanger in service and is the low-foul example for the original article.1 Anecdotal reports indicate that this exchanger has a run time of three to four months between cleaning. This is a significant improvement in comparison to a conventional design in similar service, which required cleaning every three to four weeks! When clean, this design has a shear stress of 7 Pa–12 Pa on the shell side and 13 Pa–14 Pa on the tube side. Because the field reports suggest that these shear stresses fall short of that required to eliminate cleaning, it is assumed that this design had an asymptotic shear stress of 15 Pa on the tube side and 20 Pa on the shell side. A higher rate was used on the tube side to be directionally consistent with the conventional foul-

HEAT TRANSFER ing factor which is higher on the tube side.

Because the conventional design geometry is unavailable, two hypothetical designs are developed for evaluation purposes.

One design (Design 3) uses conventional fouling factors and an allowable pressure drop of 150 kPa for each side. The other conventional design (Design 4) contains a 10% overdesign. In all simulations, the smooth-tube friction factor was used for the clean-design pressure drop, and the commercial tube friction factor was used for the fouled-pressure drop. The fouling layer thermal conductivity was assumed to be that of asphalt on the hot shell side.

On the cold side, a slightly higher thermal conductivity was used to account for a coking type chemical reaction that generally occurs at the base of the fouling layer. Table 3 summarizes all relevant process data.

Note: Even though the shear stress is increased from Design 1 to Design 2, the surface area is nominally similar. This can be attributed to a change in tube pitch from 45° to 90°. The 90-degree layout helped to increase the shear stress but simultaneously decreased the heat transfer coefficient for a viscous fluid. This anomaly occurs in viscous flow where the shear stress and heat transfer coefficient diverge for different pitch angles and it will be the subject of future investigation.

Table 1 lists a comparison of the designs. It is interesting to note that the fouled performance is inversely proportional to surface area and equipment cost.

The fouled heat transfer and pressure drop worsen as the surface area increases. Conventional designs with extra surface area do not provide additional safety, but are worse than the low-foul designs in terms of heat transfer and cleaning intervals. Merely increasing the size of an exchanger, without also increasing the allowable pressure drop will lower the starting shear stress, and consequently, increase the fouling layer thickness at the fouled end of run. This is illustrated in Fig. 1, which compares designs 1 and 4. Thus, the surface area dedicated to a fouling and/or safety margin tends to create a fouling resistance that can render a design inadequate for the fouled case.

Extra surface area hinders a good design if the excess area comes at the expense of a reasonable shear rate.

These examples point to the allowable pressure drop as a vital parameter for good design in high-fouling applications.

Although the pressure drop for low-foul designs may be higher than typical values previously used in the industry, the sce-

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HEAT TRANSFER narios shown demonstrate that the design consideration should be the fouled pressure drop and not the clean design pressure drop. As shown in Table 1, the fouled pressure drop in conventional designs increases rapidly due to fouling, thereby resulting in premature cleaning and loss of duty.

Fouling. Ultimately, fouling can account for over 60% of the thermal resistance in conventional designs. While the

low-foul Design 2 is only marginally better than the conventional design with respect to duty, there is a greater discrepancy in pressure drop from the start-to-end of service. This comparison also illustrates that even though the right critical shear stress (as in Design 2) is unknown, a low-foul design based on high-shear stress will likely outperform a conventional exchanger designed for a low-shear stress. Because fouling is a

TABLE 3. Process data sheet Inlet Density, kg/m3 Thermal conductivity, W/m °C

Shell side Outlet

Inlet

Tube side Outlet

859

911

834

810

0.064

0.071

0.072

0.068

Specific heat, kJ/kg °C

2.783

2.495

2.491

2.599

Viscosity, cP

2.996

10.797

2.5

1.704

Surface tension, dyne/cm

18.5

24.1

18.4

16

Operating temperature, °C

363

269

235

268

Fluid Total flow, kg/h Operating pressure, kPa Velocity, m/s *Fouling resistance, m2 °C /W Film coefficient, W/m2 °C

RHC residue stripper bottoms

Preflashed bitumen

210,636

615,636

2,800

2,500

0.6

2.2

0.00052

0.00120

629

1,241

*Designed with no fouling factors and additional ~22% extra surface area.

self-fulfilling prophecy, it is advisable to design exchangers for the pressure drop that inevitably arises during fouling services.

Lastly, problematic fouling services have a dynamic fouling resistance that strongly depends on the starting shear stress. One must design for service-specific shear stresses with a general safety factor to account for accuracy of heat transfer correlations and physical properties. For nonproblematic fouling services, heat exchangers are typically designed using additive fouling resistances from a table published

by TEMA. Caution: When using TEMA fouling factors, these values have remained unchanged since their first publication in 1941. Work is currently underway through HTRI’s Exchanger Design Margin Task Force to produce a practical supplement to the TEMA fouling factors known as the “resistance factor method.” This method aims to combine fluid design based margins with good design practice.4 It is intended to be an ever improving source of information, regularly adjusted to garner the knowledge and methods available. HP

1

2

3 4

LITERATURE CITED Nesta, J. M. and C. A. Bennett, “Reduce fouling in shell-and-tube heat exchangers, Hydrocarbon Processing, July 2004, pp. 77–82.

Bennett, C. A., Tubeside and shellside shear stress for single-phase flow, F-17, Heat Transfer Research, Inc., College Station, Texas, 2008.

Standards of the Tubular Exchanger Manufacturers Association, 9th Ed., TEMA, New York, 2007.

Kistler, R. S. and R. L. Shilling, Heat Transfer Research Incorporated, correspondence with authors, June 7, 2010.

NOMENCLATURE Variable Description

Fluid density, kg/m3 v Velocity, m/s

Shear stress, Pa ΔP Pressure drop, Pa Rf Fouling resistance, m2 °C W–1 t Fouling layer thickness, mm

John M. Nesta is a technical director specializing in heat transfer equipment at Fluor Canada, Ltd. He holds a BS degree in chemical engineering from the University of Southern California. His practical experience includes over 30 years of designing, evaluating and procuring heat exchangers used in the process industries. Mr. Nesta is a member of the American Petroleum Institute committees for heat transfer equipment: Standards 660, 661 and 662.

Cecil A. Coutinho is the fouling researcher at Heat Transfer Research, Inc. He earned his BS degree in chemical engineering from the University of NebraskaLincoln and a PhD in chemical engineering from the University of South Florida. His research focuses on crude oil fouling and mitigation. He is a member of the American Institute of Chemical Engineers and the Materials Research Society.

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GAS PROCESSING

Is your antifoam compatible with the amine system?

Several options help minimize operation costs and mitigate unscheduled shutdowns A. ATASH JAMEH, A. Z. GHARAGHOOSH, S. MOKHATAB and A. G. SHAZADEH, Sarkhoon and Qeshm Gas Treating Company, Bandar Abbas, Iran

T

he specific behavior of antifoam use was studied in a particular plant. The goal was to find a solution for applying the new antifoam for the best compatibility with amine systems.

A gas sweetening unit was installed to remove hydrogen sulfide (H2S) contained in a high-pressure (HP) natural gas stream. The solvent used for the H2S removal from the gaseous stream was a 34 wt% diethanolamine (DEA) solution, and the designed plant treating capacity was 250 million standard cubic feet per day (MMscfd) of HP sour gas. Due to bad filtration and an improper antifoam selection, an upset occurred that created foaming at the contactor tower. Six months after the unit startup, the deferential pressure of the lean/rich (L/R) exchanger was increased to 4 bar (allowed limitation was 0.7 bar). An unplanned shutdown of the sweetening plant occurred since cleaning was needed for the L/R amine heat exchangers. It took maintenance 12 hours to do the turnaround.

The study indicated that the high amount of incompatible antifoam injection to the system created this problem. Also, a reaction between the antifoam and sour gas produced a solidlike agglomeration particle. At lower amine flowrates, the heat exchanger incurred particular sedimentation formed in the heat exchanger, which caused resistance in the amine flow, thus increasing the deferential pressure. A glycolic antifoam was substituted for a silicon-based antifoam and the antifoam injection concentration was reduced from 80 wt% to 10 wt%. This solved the sedimentation issue. The amount of antifoam inhibitor remained about 5 ppm in the amine-solution cycle, saving the plant $100,000.

Foaming a major problem. Foaming is caused by changes in surface chemistry. Chemical contaminants that lower treating solution surface tensions enhance foaming tendency and aerosol formation. When the surface tension is low, the solution can create a very thin film that is elastic in nature and capable of encapsulating a gas bubble or forming tiny liquid droplets (aerosols).

When the surface tension is high, the solution cannot form a thin film and will not readily encapsulate a gas bubble or form an aerosol (Figs. 1 and 2). Antifoams are chemicals designed to prevent foam formation. The antifoam chosen for a gas plant is generally done during the engineering-phase. A basic understanding of gas composition and solvent type to remove acid gas is needed.

It is obvious if the selected antifoam is not compatible with the solvent in applications with a sour-gas treating plant. Typically, there will be some unscheduled shutdowns due to an unsuitable selection.

The antifoam injected, chosen with a particular amine solvent, is dependent on the solvent type, sour-gas composition and hydrocarbon condensate level that will be contained in the plant feed.

In normal gas-treating plants recirculation solution circuits, antifoaming additives are intended to act as both antifoams and defoamers. Antifoam may be added to the solution prior to foaming symptoms, but an inspection will need to determine the response.

The injected antifoam eventually disburses throughout the plant’s solution inventory to prevent foam generation since the solution becomes agitated in the stripping and absorber columns.

Fine particulates, such as iron sulfide, play a different role.

Iron sulfide tends to form a quasi-polymeric layer in the film around a bubble. This increases surface viscosity and prevents Plastic film breaks

Low surface viscosity Gravity

Capillary tension FIG. 1

Unstable foam in uncontaminated liquids.1

Elastic film encapsulates

High surface viscosity

Gelatinous layers

{ FIG. 2

Coulombic forces Stable foam in contaminated liquids.1

HYDROCARBON PROCESSING MAY 2011

I 87

GAS PROCESSING liquid migration from the bubble wall into the intersection of the bubbles. In short, iron sulfide simply retards drainage and thus stabilizes the foam. A clean amine solution will not form stable foam. Contaminants in the feed gas, amine-degradation products, fine particulates, and chemical additives that reduce surface tension and raise surface viscosity can dramatically enhance foaming tendency and foam stability.

Anything that has destabilizing effects on foam is antifoam.

Efficiency is dependent upon the bulk-solution chemistry, operating conditions and surface active agents (surfactants) creating the foam. The most productive antifoams have traditionally been

synergistic mixtures of hydrophobic liquids and solids. Examples classified by major constituents include: • Nonpolar oils—minerals and silicones • Polar oils, such as fatty alcohols, fatty acids, alkyl amines and alkyl amides • Hydrophobic solids—treated silica, aluminum oxide and polypropylene.

These compounds usually contain additional surfactants to enhance other properties required in the finished blend, surface wetting, emulsification, particle dispersion or detergency.

A confusing aspect of surfactant applications is that a chemical compound may have antifoaming properties in one application but may be used as an emulsion breaker in another.

Complex chemistry problem. The vast formulation library

Silicone antifoam.

GJP4.5e11

FIG. 3

reflects the complexity of interfacial physical chemistry, and widespread need to control foams. Antifoam “recipes” are normally proprietary and are seldom published in detail. Even if the recipes were published, it’s extremely difficult, given the state of the art, to distinguish which components were actually causing the antifoaming action at any given time in any particular application.

Result: A trial-and-error application is required.

In many ways, the art of breaking or preventing foam is as complex as its formation. Certainly, it is a subject that has been undergoing intense study. There are no hard and fast rules governing the efficiency of a given antifoam formulation in any particular application. Each application is based on empirical data, usually bench-level trials. However, there are some physical and chemical factors consistent among observations made while studying antifoams, along with their functionalities under different conditions. Factors that affect antifoam performance include: • Solubility. Most antifoams exhibit extremely low solubility in aqueous solutions. For instance, antifoam based on glycolic acid was provided from another gas plant to replace the current antifoam. Since the antifoam must be heated before injection, it was not being dispersed in the amine solvent since there was no heating system. This resulted in changing the antifoam type.

• Droplet size. The entry force required to allow the antifoam droplet to enter the bubble wall generally increases as antifoam droplets become smaller.

• Presence of hydrophobic solids. Liquid/solid mixtures are usually more effective than either component used alone.

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FIG. 4

Polar antifoam.

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T R A I N I N G

GAS PROCESSING • Environmental shear. Some antifoams are inactivated by too much shear. This is usually due to solid/liquid separation and antifoam droplets being too small to bridge the bubble lamellae.

Shear also plays a major role in the differences between dynamic and equilibrium surface tensions. If the interfacial area increases faster than the surfactant molecules can occupy it, the dynamic surface tension is higher. Equilibrium surface tension represents the fully saturated surfactant film along the interfacial area. The same dynamic affects apply to the antifoaming surfactant’s ability to occupy the interfacial area.

FIG. 5

Excess antifoam absorbs iron sulfides formed as a result of increasing HSS, which consequently precipitates on an L/R amine exchanger.

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• Repeated exposure to foaming. Repeated exposure to foaming eventually exhausts the antifoam’s ability to inhibit formation.

This is probably due to the separation of hydrophobic solids and/ or reduced droplet size. Multiple-shake test experiments have shown that some antifoams gradually lose their antifoaming ability.

• Competing chemical constituents. Other surface-active chemical constituents have been found to occupy interfacial areas and to reduce the effects of antifoams. This is one reason why some antifoams work better in high-shear environments where gas-to-liquid interfaces are constantly being formed, and not so well when added to exiting foams. Antifoam co-surfactant presence may also cause inhibition.

• Surfactant concentration. Higher surfactant concentrations tend to reduce antifoam effectiveness by increasing the entry force necessary to bridge the interfacial film.

• Dissolved salt species and concentration. The presence of high-valance metal ions reduces antifoam effectiveness. Counterions surround the polar ends of the surfactant molecules, reducing their electrostatic interaction with other surfactant molecules in the film.

Two antifoam types recommended by gas processing plant personnel are: silicones, which are mixtures of nonpolar siloxane oils and hydrophobic silica solids; and glycols or high-molecular weight alcohols, which are mixtures of polar oils and other highmolecular-weight surfactants.

Silicone antifoams and excess injection. The most prevalent antifoams in the gas-processing industry are silicones.

The majority of these antifoams are composed of siloxane oils mixed with silica particles in varying concentrations; although some do not contain silica. Chemically, siloxane oils have long, hydrophobic R-hydrocarbon groups attached to silicon atoms that render them insoluble in aqueous solutions. Most silicone antifoams contain silica particles that are treated to become hydrocarbons so they remain suspended, preferentially, in silicone oils.

The photomicrograph in Fig. 3 shows a silicone-oil droplet with suspended silica particles. The droplet appears granular.2 The synergism between the silicone oil and the hydrophobic silica particles is described as acting like “pins,” breaking the surfactant film surface and subsequently reducing the antifoam droplet’s entry force requirement.

While the silicone antifoam family has unquestionable antifoaming ability, there have been serious concerns with their use in gas-processing systems. These concerns include tendencies to exhaust in service and their potential impact on heat transfer and corrosion inhibitor function due to their surface wetting or coating tendencies. Premature fouling of mechanical filters and activated carbon due to surface coating and insolubility have long been associated with silicone usage in antifoams. Most recently, mass transfer inhibition has proven to be a concern as well. Silicone antifoams will exhaust in service when the silica particles separate from the oil fraction. Interestingly, simply adding more siloxane oil revives the antifoaming ability, and it is not more costly than simply adding new antifoam.

Overdosing silicone antifoam has gained the reputation of creating foam. But, in fact, studies show that these antifoams reach a critical concentration where foaming is not caused; but rather, they simply fail to inhibit it. At elevated concentrations, the antifoam gets tied up in micelle structures in the bulk solution. Once tied up in micelles, it can no longer spread on the interface, form lenses and be incorporated in the foam’s structure.

GAS PROCESSING Polar oil antifoams. The polar oil family of antifoams combines electrochemically neutral hydrophilic moieties with long hydrophobic hydrocarbon groups. These antifoams are formulated from, and usually named some variant of polyglycol copolymer, polypropylene or ethylene block polymer, polyoxyethylene/ oxypropylene esters of C8â&#x20AC;&#x201C;C30 fatty acids, oxy/ethoxyprpylene alcohols, and other non-ionic surfactants. As with silicone oil formulations, insolubility in aqueous solutions is the key property of these antifoams. They are most effective above their cloud points. Below their cloud points, some non-ionic surfactants have caused surfactant films, becoming thicker and more stable due to long-range electrostatic repulsion between the monomers. Above their cloud points, they produce insoluble droplets that are incorporated into the interfacial films similar to other insoluble oils.

Non-ionic surfactants offer several other properties not found in silicone antifoams; the most obvious is the lack of a synergistic solid component. In Fig. 4, the micrograph shows droplets of polyglycol antifoam in an MDEA solution and the lack of droplet granularity.

This solid fraction eliminates in-situ exhaustion due to separation.

Case study. Amine foaming is a complex problem caused by a combination of chemical contaminants, stabilized by fine particulates, and dependent on physical parameters and process conditions. To prevent foaming from disrupting gas-plant operations, the causes and the symptoms must be known. Questions to ask include: What role does computer simulation play in solving the problem? What role should additives, antifoamants, corrosion inhibitors and formulated solvents play? How does the selection and operation of filtration equipment promote or reduce foaming?

A parameter that causes foam is an amine degradation product.

Acidic amine degradation products can be very troublesome. They

are formed when the amine reacts with oxygen in the feed gas.

The reaction proceeds at varying rates, depending on concentration, temperature and pressure. Primary and secondary amines are easily oxidized. It takes less organic acid to cause problems in a tertiary amine solution because tertiary amines have inherently lower surface tension.

Organic acids also reduce the effective acid-gas absorption capacity of the treating solution by forming heat-stable salts (HSSs). These salts are soluble reaction products of organic acids and functional amine. A buildup of HSS may lead to problems.

If left unchecked, the same organic acids that form HSS with the amine solvent can polymerize and form longer-chain organic acids that cause foaming. Since hydrocarbons are present in feed gas, operators injected more antifoam. Over time, the antifoam accumulates in the amine solvent. The excess antifoam is altered to an adhesive polymer that contributes to clogging the L/R amine exchanger (Fig. 5).

Fig. 6 shows the antifoam absorbing suspended iron sulfide particles and foaming large agglomerates in an amine solution that was sampled from the gas plant. This clearly shows how antifoam droplets can prematurely plug activated carbon beds and the mechanical filter even if the droplets can pass through without being absorbed.

Since the applied antifoam was not a compatible solution with plant operation and to overcome a foaming upset, operators injected more than the expected amount of antifoam. Data in Table 1 illustrates how much antifoam was accumulated in the cycle since

TABLE 1. Effect of glycolic antifoam on foaming of amine contactors Number of foaming occurrences

Total injection, liters

2004

382

4,015

2005

250

2,912

2006

95

450 FIG. 7

Accumulated gelatin formation if incorrect antifoam is used.

14

Foaming tendency, ml

250 Foam tendency, ml Foam stability, s

200

12 10

150

8

100

6 4

50

2

0

0 0.00

FIG. 6

Excess antifoam in the amine solvent created an adhesive gel.

FIG. 8

Foaming stability, s

Year

1.05

1.22

3.46 4.66 HSS, wt %

4.95

5.20

HSS vs. foaming tendency and stability.

HYDROCARBON PROCESSING MAY 2011

I 91

GAS PROCESSING the plant’s commissioning in 2003. Foam formation could have been avoided along with the promotion of foam formation in the contactor. As a consequence, buildup of glycolic antifoam in the cycle caused a reaction with oxygen (sometimes accompanied with deionized water). It was necessary to inject the amine solution to control the concentration; thus, a fatic acid formation occurred.

This increased the HSS amount also causing the number of foaming occurrences to increase. Unknown impurities such as gelatins can also form due to improper antifoam injection selection (Fig. 7).

As HSS concentration increases, more iron sulfides are produced that cause amine foaming. Data collection from the plant justified this claim, as illustrated in Fig. 8. HSS that causes foaming when the HSS and amino acids enter with the gas or are produced. Amino acids are well known in making complex compounds with iron. The complexes are formed by the reaction:

Fe (H 2 O) 6 + 2 + n (anion) Fe (anion) n (2 - n) + (6 - n) H2 O where n = 1 to 6.

The reaction shifts toward complexation by increasing the anion concentration or by increasing the hexaquo-iron ion in solution. Anions such as thiocyanate, formate and acetate—common amines in HSS anions—readily form iron complexes. These complexes cause the dissolution of iron sulfide to shift to the right, providing more irons for complexation.

Iron carbonate and iron sulfide are more soluble on the lean side. HSS and/or degradation products will cause iron carbonate and iron sulfide to become soluble in the lean side of the system.

When the amine is circulated back to the contactor and picks up carbon dioxide (CO2) and H2S, the iron carbonate and iron sulfide will precipitate, leaving the HSS and/or degradation product free. This free-complex former is circulated back to the lean side where it picks up more iron. This cycle can repeat over and may cause severe corrosion on the lean side of the amine treating system. The precipitated iron carbonate and iron sulfide can plug trays in the contactor, or form on the plate and frame of the heat exchanger, impacting operation as shown in Fig. 9.

Foaming effects in an amine contactor. Chemical additives, such as antifoamers and corrosion inhibitors, have a place in amine plant operation, but they should only be used with a thorough understanding of the applied chemistry. Most antifoams are either silicone-based or long-chain alcohols. Corrosion inhibitors can be either inorganic metals or film-forming organic compounds. Formulated solvents are based on combinations of amines or amines with the addition of corrosion inhibitors and/ or antifoaming agents. A system already full of silicone from lube oil or an amine formulation usually does not respond well to additional silicone.

The antifoam injected into the gas plant’s amine solvent was a glycolic-base, a common antifoam that is a long-chain alcohol.

Extreme caution should be exercised with its use. As a result, incompatibility with the process occurred and operators had to inject more antifoam than expected to eliminate the foam symptoms in the contactor. The antifoam readily undergoes oxidation to form a long-chain fatty acid. A feed gas containing oxygen can provide the reactant to oxidize it to a fatty acid. Long-chain alcohols should be avoided when oxygen is present. Parts per million (ppm) levels of oxygen can react with the amine to form carboxylic acids.

Carboxylic acids react with functional amine and basic amine degradation products to form very soluble long-chain organic acids

TABLE 2. Foaming test on glycolic types Antifoam type

Dissolved oxygen in demineralized water

16

TK-301

14

T-101

1.6 1.4

12

1.2

10

1.0

8

0.8

6

0.6

4

0.4

2

0.2

0

0.0

Foam stability, S at 69°C

Type A glycolic antifoam

80

2

Type B glycolic antifoam

330

12

Lean amine DEA as a blank

180

8

Dissolved oxygen in amine solution, ppm

Iron sulfide buildup in a heat exchanger caused by excess antifoam.

22.05.06 04.6.06 04.6.06 08.6.06 09.6.06 11.6.06 17.6.06 23.6.06 30.6.06 07.7.06 16.7.06 21.7.06 28.7.06 04.8.06 11.8.06 18.8.06 26.8.06 01.9.06 10.9.06 31.10.06 1.11.06 2.11.06 3.11.06 4.11.06 5.11.06 6.11.06

Dissolved oxygen in deionized water, ppm

FIG. 9

Foam tendency, ml at 69°C

Date FIG. 10

92

Dissolved oxygen in amine (T-101) and deionized water (TK-301).

I MAY 2011 HYDROCARBON PROCESSING

FIG. 11

Foaming tendency and foam stability test.

GAS PROCESSING

Solvent

Foaming height, ml

Foaming stability, s

Amine solution at plant

573

15

Injection of Type A glycolic antifoam to amine solution

250

11

Injection of Type B glycolic antifoam to amine solution

490

> 60

Injection of silicon antifoam to amine solution

180

10

Different antifoam with different effect

1.2

No. of foaming occurrence each day Antifoam injection(cc/hr)

1.0 0.8 0.6 0.4 0.2 0.0

Antifoam alcoholic Antifoam alcoholic Type A Type B

FIG. 12

500 450 400 350 300 250 200 150 100 50 0

Antifoam injection, cc/hr

TABLE 3. Laboratory test of different types of antifoams

not reveal composition, thereby making it virtually impossible to make informed decisions regarding supplemental additives. Even mixed amines can be a problem. If the mixture contains MEA and DEA, and the feed gas containing oxygen and organic acids will form readily. If the bulk of the formulation is MDEA, which is sensitive to small concentrations of organic acids, the solution will likely have a severe foaming problem.

Lost-treating capacity is often the net effect of foaming in the contactor. The height of the foam increases and the void volume inside the vessel decreases. Reduced void volume increases pressure drop in the system. As the vapor liquid contact area is reduced (filled with foam), the effective mass-transfer zone is reduced and

No. of occurring foaming in contactor

or fatty acids. Fatty acids increase liquid hydrocarbon solubility in amine solution and also cause severe foaming problems.

During this study, different tests were carried out for measuring the amount of dissolved oxygen in an amine. Treated water was used to dilute the amine solution. The results show that the source of oxygen reacted with the amine, and that the antifoam was water deionized at about 20 ppm dissolved oxygen based on ASTM measurements (Fig. 10). This was also used to wash the treated gas in the contactor. The oxygen level contained in the feed gas was not measured.

Corrosion inhibits for the most part and is created by organic film-forming chemicals. As such, they are surface active and are readily removed by activated carbon until the carbon becomes saturated. When this happens, the carbon begins to unload and can rapidly increase the concentration, causing a foaming problem.

Formulated solvents pose a new challenge for the gas-plant operator. The formulations are typically proprietary. Suppliers do

Antifoam silicon base

Characteristics of different antifoams on contactor operations.

polimeri europa eni.com Select 173 at www.HydrocarbonProcessing.com/RS M_0495_180x125_Hydrocarbon_Polimeri_Ing.indd 1

I

HYDROCARBON PROCESSING MAY 201110:36 93 24/03/11

GAS PROCESSING 14 No of foaming in contactor per day

No of occurring foaming 12 Injection of antifoam glycolic type B

10 8 Injection of antifoam glycolic type A

6 4

Injection of antifoam silicon base

2

21.12.04 22.12.04 23.12.04 24.12.04 25.12.04 26.12.04 27.12.04 28.12.04 25.01.05 26.01.05 27.01.05 28.01.05 29.01.05 30.01.05 21.01.05 01.02.05 03.02.05 04.02.05 05.02.05 06.02.05 07.02.05 08.02.05 09.02.05 10.02.05 11.02.05 12.02.05 13.02.05 14.02.05 15.02.05 16.02.05 17.02.05

0

Date FIG. 13

Trend showing decrease in foam that occurred in the contactor.

TABLE 4. Different types of antifoams field tests

Test

Number of foaming occurrences

Injection at each step, cc

Time for overcoming foaming, min

Run 1 Run 2

12 10

400 30

15 13

Glycolic base, Type B

Run 1 Run 2

8 5

200 200

11 10

Silicon base

Run 1 Run 2 Run 3

1 3 2

300 650 600

5 8 7

Antifoam type Glycolic base, Type A

During this step, a sample solution of the amine cycle was taken and the effects of three antifoams on foaming symptoms were evaluated. The parameters, such as foaming stability and foaming tendency, were recorded and the results are shown in Table 4. Silicon-based antifoam has a higher efficiency than glycolic types. The laboratory test confirmed that a silicon-type antifoam is more appropriate for an amine solution; the decision was to apply it into solvent at the plant. Data gathered from the plant proved that, since a silicon base was applied, numbers of foam occurrences were drastically reduced, as shown in Tables 3 and 4 and Fig. 13.

Using a silicon-based antifoam not only had a higher performance over a glycolic antifoam, but it also could provide the same efficiency with little injection into solution.

The study indicated that a high amount of antifoam injection into the system created process problems like clogging the L/R amine exchanger, increasing the number of foaming occurrences in the contactor, gas-treating instabilities and increased unscheduled plant shutdowns. It was shown that the reaction between antifoam and sour gas, preferentially with oxygen of deionized water, produced a particle solid-like agglomeration. If the heat exchanger had a decrease in the amine flowrate due to particular sedimentation, an increase in deferential pressure also occurred. With a decrease in the concentration of antifoam injection from 80 wt% to 10 wt%, this problem along with the amount of antifoam inhibitor remained about 5 ppm in the amine solution cycle. Selecting a new antifoam must encompass a deep study for compatibility.

Choosing the right antifoam saved the plant about $100,000. HP ACKNOWLEDGMENT The authors thank Mr. Saifi and Mr. Nori in their cooperation with field and laboratory testing.

1

less acid gas is absorbed. When foaming occurs in the flash tank, it reduces the surface area from which the gas evolves. Reduced surface area prevents the solution from achieving the desired semi-rich loading. Foam prevents gas from immigrating out of the solution. If the reboiler is at full rate, it may not be possible to achieve specification.

Tests and methodology. For this study, a determination

of foaming tendency and resultant foam stability of pure liquid and mixtures was used in the following procedure. Air is sparged through a measured amount of solution at a specified rate for a specific period (Fig. 11). The difference between initial and final foam height is measured. When the air stopped, the time required for the foam to collapse was recorded.

For measuring the HSS, two methods were used. The first one used titration, which is a traditional method and would be efficient to judge the amine behavior. The second method was using ion chromatographic, an application that should be taken.

Appropriate antifoaming effects on amine solvent.

Since injecting more glycolic didn’t have a suitable effect on the foaming upset, another glycolic antifoam was applied. This antifoam, unfortunately cannot completely disperse in solution. As shown in Fig. 9, when a Type B glycolic antifoam was used, it inhibited foaming. However, it needs more time to overcome the foaming symptoms as compared to the Type A glycolic antifoam that was applied and mostly agglomerated, as shown in Table 2 and Fig. 12.

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2

LITERATURE CITED Paul, C. R., “Gas Conditioning—Face the Facts about Amine Foaming,” Chemical Engineering Progress, July 1991. von Phul, S. A. and L. Stern, “Antifoam: What is it? How does it work? Why do they say to limit its use?” Laurence Reid Gas Conditioning Conference, Norman, Oklahoma, 2001.

Abolfazl Atash Jameh is the head of process engineering, a division of engineering and technical services, at the Sarkhoon and Qeshm Gas Treating Company in Iran. He joined the National Iranian Gas Company (NIGC) in 1999 and has 10 years of experience in process engineering, modeling and optimization, as well as troubleshooting gas processing units. Mr. Atash Jameh received an MS degree in chemical engineering from the Sharif University of Technology in 1998 and a BS degree in chemical engineering from the Petroleum University of Technology in 1995. He has authored and coauthored more than seven papers in national and international conferences.

Ahmad Zamani Gharaghoosh is the head of technical inspection department at the Sarkhoon & Qeshm Gas Treating Company (SQGC). He joined National Iranian Gas Company ( NIGC) In 1997.Mr. Zamani Gharaghoosh has more than 11 years of experience in gas refinery processes, static equipment inspection, and risk-based inspection, and is a corrosion specialist at the gas refinery.

Saeid Mokhatab is an internationally recognized expert in the field of natural gas engineering with a particular emphasis on gas transmission, LNG and processing. He has been involved as a technical consultant in several international gas-engineering projects and published over 150 academic and industry-oriented papers. Mr. Mokhatab is a member of the editorial board for most professional oil and gas engineering journals, and serves on various SPE and ASME technical committees.

Special Supplement to

SULFUR 2011

CONTENTS

The ultimate path to H2S-free gas C–97

Corporate Profiles Silcotek C–99 Ametek Process Instruments C–101 Foster Wheeler C–103 WorleyParsons C–105

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Select 77 at www.HydrocarbonProcessing.com/RS

SULFUR 2011

The ultimate path to H2S-free gas Z. LIU, GTC Technology US, LLC, Houston, Texas; and B. CHIA, GTC Technology, Singapore Advanced technologies offer competitive advantages over traditional methods With the desire to maintain a clean environment, there is an increasing pressure by worldwide environmental regulatory agencies, as well as petrochemical and refining industries to continue meeting more stringent standards for sulfur emissions from processing facilities. It is important to understand the various sulfur-recovery (SR) methods available and to implement advanced, reliable and cost-effective technologies for SR to ensure continuous and smooth plant operation. Following are highlights of some of the advanced technologies for SR as well as their competitive advantages over traditional methods.

Traditional SR units. In the refinery processes, sulfur is converted to hydrogen sulfide (H2S), which is recovered primarily in amine absorbers to minimize sulfur emissions to the atmosphere. The rich amine solution is regenerated in an amine regeneration unit, producing a H2S-rich gas stream that is then fed to the SR unit (SRU)—the Claus process—where the H2S is converted to elemental sulfur.

The Claus reaction is reversible, with sulfur vapor and water vapor always present. This prevents H2S conversion from reaching 100%, and thus the byproducts—carbon disulfide (CS2) and carbonyl sulfide (COS)—cannot be 100% hydrolyzed. From a thermodynamic standpoint, lower temperature is more favorable to equilibrium conversion. However, this is restrained by the dew point of sulfur vapors. Due to the limitation of chemical equilibrium and reaction temperature, the highest SR in a Claus unit is lower than 98%. Without further treatment, the remaining H2S in the feed is combusted and emitted to the atmosphere as sulfur dioxide (SO2). This was the case until 1970, when the first commercial unit was built to treat Claus tail gas (TG).

Since then, a number of different TG cleanup processes have been developed to overcome the thermodynamic equilibrium of the Claus reaction and thus, increase the overall SR. Environmental emission regulations are becoming tighter and there is increasing demand to achieve even higher sulfur removal and recovery.

Integrated Claus and TG treating.

In view of this need, an optimized and integrated flow scheme combining Claus and tail-gas treating (TGT) has been introduced. This new SR process offers lower capital and operating costs, higher reliability and operability, and a 99.9+% SR efficiency.1

Sour gas from either rich amine regeneration or sour water stripping, or both, is sent to the sulfurproducing burner after entrained liquid removal. In this burner, based on required oxygen for the reaction, the air quantity supplied by a blower is strictly controlled.

After burning, all of the organics in the acid gas are oxidized. About 65% of H2S from the feed is transformed into sulfur through a thermal Claus reaction.

About one-third of the remaining H2S is transformed into SO2 to meet the stoichiometric amount of SO2 required in the Claus reaction. A small portion of hightemperature process gas from the sulfur-producing burner is used to adjust the inlet temperature of the 1st stage converter via a high-temperature mixing valve. The majority of high-temperature process gas line caption is sent to a waste-heat boilerTwo to produce 1.1 MPaG, 250°C superheated steam. The temperature of the process gas is decreased to 350°C and then cooled to 160°C in the first-stage condenser. Liquid sulfur is separated from the process gas and sent to the sulfur drum.

Process gas from the first-stage condenser is then reheated to 258°C by high-temperature process gas and sent to the first-stage converter to undergo catalytic Claus reaction. Due to exothermic reaction heat, process gas from the first-stage converter increases to 308°C and is used to heat up low-temperature process gas from an outlet of the second-stage condenser. Process gas is further cooled to 160°C and liquid sulfur is separated and sent to a sulfur drum. Process gas from the second-stage condenser is heated up to 220°C and sent to the second-stage converter. Process gas from the second-stage converter is sent to the thirdstage condenser. Liquid sulfur is separated and sent to the sulfur drum. The Claus tail-gas is sent to a tail gas treating section after entrained liquid knockout.

Waste heat from the first, second, and third-stage condensers is recovered to generate 0.4 MPaG saturated steam. Liquid sulfur from the sulfur drum flows to a liquid sulfur pool. After quinoline and nitrogen

injection, entrained gas in the liquid sulfur is removed through a degassing pump and then sent to the offgas incinerator. Liquid sulfur, after gas removal, is sent to a sulfur shaping machine by a liquid sulfur transfer pump, and then sent to autopacking and to a stacking machine for weighing and packing. Specifications of solid sulfur obtainable in the new SR process are shown in Table 1.

The Claus tail gas is heated by flue gas from the offgas incinerator to 300°C and sent to the hydrogenation reactor after mixing with hydrogen. SO2, S2, COS and CS2 are converted to H2S by reduction and hydrolysis reaction. The process gas from the hydrogenation reaction is sent to a steam generator to generate 0.4 MPaG steam. The temperature of the tail gas is decreased to 170°C and sent to a quench column. The tail gas interacts with quench water and is cooled to 40°C. The sour water generated is sent to the sour water stripper.

The cooled tail gas is sent to the amine absorber.

Lean amine solvent is sent to the top of the amine absorber to reduce H2S, and rich solvent is sent to the solvent stripper for solvent recovery. Offgas from the top of the amine absorber is sent to the offgas incinerator. Flue gas is vented at 296°C after superheating the inside battery limits (ISBL) generated steam and preheating the Claus tail-gas feed before hydrogenation. Acid gas stripped off from the rich solvent is recycled to the sulfur manufacturing burner.

TABLE 1. Solid sulfur specification Property

Unit

Specification

Purity As Ash Acidity (as of H2SO4) Water Organics Fe

wt % wt % wt % wt % wt % wt % wt %

≥ 99.9 (on dry basis) ≤ 0.01 ≤ 0.03 ≤ 0.003 ≤ 2.0 ≤ 0.03 ≤ 0.005

Hydrogen Saturated steam

Superheated steam

Sour gas from amine regeneration and/or sour water stripper Boiler-feed water

Tail-gas treating

Claus

Sulfur

H2S-free gas

Sour gas recycle

FIG. 1. Block flow diagram for new SR process.

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• Turndown in normal operation may be as low as 15% • Hydrogen source flexibility within most refineries and petrochemical complexes.

10% 5% Hig hC O

H4S concentration

2

1%

Amine/Claus/TGT

an

du

5,000 ppm

nc

on

10 0t pd ven

Non-aqueous solution (all applications)

1,000 ppm

100 ppm

Scavenging

1,000

tpd

su

5,000 10,000

1t lfu

r

pd

na lg 25

500 ppm

0.1

tio

5t

su lfu

r

pd

as

lfu

r

ap p

t pd

su lfu

50,000 100,000 Gas flowrate, m3/hr

su

lic ati on s su lfu r

r

1,000,000

FIG. 2. Application range of non-aqueous technology.

Sweet gas Lean solution Absorber

Sour gas

Flash gas Slurry tank

Flash vessel

Heated surge tank

SO2

SR application. SR from high-pressure sour natural gas streams with medium amounts of sulfur has historically been a challenge for the industry.

Conventional treatment using the amine/Claus/TGT methods is capital intensive and mostly favored for large units. Other systems, on the other hand, were primarily developed for low-pressure applications.

A non-aqueous process has been developed specifically for the treatment of high-pressure sour natural gas in medium-sized sulfur applications, with produced sulfur in the range of 0.1 tpd to 30 tpd.2 Fig. 2 indicates the application range of this non-aqueous technology.

The non-aqueous solution has a high solubility for elemental sulfur. Because the elemental sulfur stays dissolved in the solution, there are no solids in the liquid circulated to the absorber. By design, the solution avoids the problems that make the aqueous sulfur recovery systems unsuitable for direct treatment of high-pressure gas.

With this process, H2S is removed from the sour gas in a conventional absorber tower. The H2S reacts with dissolved SO2 to produce elemental sulfur, which remains in solution. HP Extended version avaiable online at Hydrocarbon Processing.com.

Sulfur filter system

NOTES 1

Scraped surface crystallizer

Sulfur

FIG. 3. Non-aqueous solution technology flow scheme.

In the new SR process, there is only the sulfur manufacturing burner and offgas incinerator consuming fuel gas. The inline burner to generate reducing gas for Claus tail-gas hydrogenation is eliminated. This results in less equipment and fewer controlling loops than those of similar processes. The process not only maintains a high SR rate, but also avoids high costs for energy consumption, investment and operation. The amount of emission vent gas is also reduced. Some similar processes use steam or electricity to heat up process gas as a means to reduce emissions. However, outside battery limits (OSBL) cost on steam and electricity generation cannot be omitted by doing this.

Through flow scheme optimization and inside battery limits (ISBL) heat integration, this process consumes the least energy compared with similar processes, thus making it the most environmentally friendly method.

In terms of equipment, it utilizes a high-temperature mixing valve, which is critical to this process. At temperatures above 1,200°C and in a strong reducing environment, any metal will be corroded by sulfur S-98

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species. The internal-cooling mixing valve controls the surface temperature under the critical temperature of corrosion. This equipment has been used for more than six years of continuous operations, demonstrating proven reliability for long-term operation.

The sulfur manufacturing combustion chamber is another key piece of equipment in this process. It is constructed with corundum-mullite bricks, which have been used in continuous operation for more than 10 years without major maintenance. For catalysts, the process uses a self-developed high-performance catalysts for both catalytic Claus and tail-gas hydrogenation applications. In addition, the process has demonstrated the several competitive advantages over the similarities: • H2S concentration in acid-gas feed may range from 30% to 97% • Ammonia over H2S ratio in feed gas may vary up to 0.42 • Single-train capability from 4 tons to 340 tons of sulfur

GTC Technology in alliance with Shandong Sunway—Sulfur Recovery Technology 2 GTC Technology, in alliance with CrystaTech— CrystaSulf technology

Zhepeng Liu is project manager in the technology department at GTC Technology US, LLC, in Houston, Texas. He has over 15 years’ experience in the refining and petrochemical industry and is a specialist in aromatics and derivatives production processes. Mr. Liu’s background covers the fields of catalyst/process development, process engineering design, commissioning/startup, operation/optimization, technical services and project management.

Before joining GTC in 2004, he worked for Sinopec SRIPT, UOP and Shanghai SECCO.

Beitian “Shermaine” Chia

is a technical sales engineer at GTC Technology’s Singapore office.

She joined GTC in June 2008 and is actively involved in commercial activities involving licensing support and proposal preparation. Ms. Chia graduated from the Nanyang Technological University with a BS degree in engineering (chemical and biomolecular engineering).

CORPORATE PROFILE: SILCOTEK SULFUR 2011

SilcoTek coatings improve system performance SilcoTekâ&#x20AC;&#x2122;s coating technology allows customers to improve the performance of process instrumentation, and the plant bottom line, by enabling reliable, accurate sulfur and H2S sampling. For nearly 25 years the Scientists, Engineers and Technicians at SilcoTek have been offering innovative coating solutions to petrochemical, refinery, oil and gas customers. SilcoTekâ&#x20AC;&#x2122;s CVD technology bonds an inert silicon layer into the surface of stainless steel and other alloys, preventing active compounds like H2S, mercaptan, ammonia, sulfur and mercury species from interacting with fluid pathways or components. SilcoTekâ&#x20AC;&#x2122;s inert coatings have revolutionized sulfur transport and analysis by eliminating adsorptive effects of stainless steel; allowing transport, storage and detection of ppb level active compounds while maintaining accurate, reliable analytical results.

SilcoTekâ&#x20AC;&#x2122;s patented coating technologies include:

Our newest coating! A tough, durable, inert and corrosion resistant coating designed for harsh environments found in oil and gas exploration, transport and processing.

The ultimate inert coating technology. A required coating when analyzing low levels of organo-sulfur compounds, such as H2S.

A corrosion resistant coating that increases the lifetime of system components by improving corrosion resistance by 10x or more.

A non-stick coating designed to reduce the onset of carbon coking and fouling on stainless steel by 8x.

A high purity coating designed to improve the performance of instrument and vacuum systems.

SilcoTek is dedicated to offering upstream and downstream oil and gas customers new, advanced coatings to maximize material performance; making the impossible, possible.

Contact information SilcoTek Corporation 112 Benner Circle, Bellefonte, PA 16823 Phone: (814) 353-1778, Fax: (814) 353-1697 Email: Silcod@SilcoTek.com Website: www.SilcoTek.com

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HYDROCARBON PROCESSING SULFUR 2011

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UV/Vis and NIR SPECTROP HOTOMET ERS WANTED F OR PROCESS ENGINEER ING.

Plant/proc ess engine er seeks high -performan ce spectropho tometer fo r long-term employme nt.

Must be co mpact, rug ge and measu re multiple d componen ts simultan eously.

Put AMETEK’s new IPS-4 on the job.

High performance, low maintenance and now available in Infrared!

Put next-generation technology to work to verify the quality of your feedstocks, intermediates, final products and more. The new IPS-4 spectrophotometer detects and quantifies thousands of chemical species — up to eight at once. With an IP-65-compliant housing and a 2-year-life lamp, the IPS-4 needs no annual maintenance. So it’s perfect for outdoors, next to inaccessible areas along your process.

Just 31 inches wide, the IPS-4 is packed with features including 22-key keypad, analog signal output, 3 digital signal ports, high-speed Ethernet port, plug-and-play/web-based queries, alarm contacts, RS232 and RS485 ports. Plus, its multilingual interface includes English, French, German, Russian and Spanish. The IPS-4 is available in UV/Vis and NIR versions with fully integrated sampling systems.

AMETEK’s entire family of spectrophotometer-based analyzers is proven in applications from chemicals and petrochemicals to pharmaceuticals, food and metals processing.

To learn more call 412-828-9040 or visit our web site.

www.ametekpi.com Select 56 at www.HydrocarbonProcessing.com/RS

CORPORATE PROFILE: AMETEK PROCESS INSTRUMENTS SULFUR 2011

AMETEK offers extended capabilities for sulfur measurement and analysis For decades AMETEK has provided hydrocarbon processors and sulfur recovery operators with a broad line of instruments specifically designed for process measurement and analysis. The recent addition of Asoma Instruments to its Process Instruments group has extended the company’s capabilities even further, especially in the realm of helping processors meet emerging ultra-low sulfur content regulations. AMETEK’s line now includes instruments for: • feed gas process control • residual H2S measurement • continuous SO2 emissions monitoring • tail gas and pit gas measurement and analysis • tail gas treating unit analysis • H2S, H2 and HC in natural gas • ultra-low-S measurement in fuels • S and Cl in diesel, gasoline, crude oil, bunker fuel, other petroleum distillates • S in high-temperature, high-pressure, viscous fluids like residual and crude oils.

Single- and Multi-Gas Analyzers. AMETEK makes a range of gas analyzers capable of measuring SO2, H2S, and other species with high accuracy. The Model 880-NSL tail gas analyzer has become an industry standard for online analysis of tail gas in SRUs. The robust Model 920 allows multi-range SO2 analysis, with virtually no H2O or CO2 interference, while the Model 932 multigas H2S analyzer uses a sophisticated UV-VIS photometer to measure up to five gas species in applications ranging from feed gas analysis and reaction rate monitoring to impurity detection and quality assurance monitoring.

Benchtop ED-XRF Analyzer. The Phoenix II, a polarized Energy Dispersive-X-Ray Fluorescent (ED-XRF) benchtop analyzer, offers extreme simplicity of operation in a low-cost, compact design. Ideal for elemental analysis of liquids, solids, pastes, slurries and powders, this ED-XRF spectrometer can operate in the rugged production process environment or the laboratory with equal ease. A simple, intuitive touch-screen display makes analysis easy for non-technical operators, yet it’s advanced enough for even the most experienced user, with a “Low S” version capable of detecting less than 1 ppm sulfur in fuels. Predefined, factory-calibrated application packages conform to industry, national and international standards; no need for time-consuming onsite method creation and calibration.

682T-HP. The Model 682T-HP is designed for analysis of sulfur in highly viscous hydrocarbons such as residual and crude oils. This highly sensitive unit easily handles high-sample pressures and situations where fouling of flow-cell windows with paraffin or similar substances can occur.

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Designed to measure viscous hydrocarbon in crude lines, pipelines, terminals, and blending operations, the Asoma 682T-HP can help meet emerging lower-sulfurcontent regulations. It’s faster, more sensitive and more compact than previous models, and it provides continuous, reliable detection of sulfur at pressures up to 800 psig. It can operate as a stand-alone analyzer or be tied to plant-wide automation systems to provide real-time strategic measurements. Analysis range for sulfur is 0.04%–6.0%.

Experience Makes the Difference. An installed base of more than 2,000 analyzers and 45 years of quality performance make AMETEK the first choice for hydrocarbon processing and sulfur recovery professionals. Serving the industry with solutions that last…that’s AMETEK Process Instruments.

Ask us about operator training, too.

Contact information Phone: 412/828-9040 E-mail: sales.info@ametek.com Web-site: www.ametekpi.com

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Foster Wheeler Acquires Sulfur Recovery Technology This addition to our technology portfolio enhances our ability to help you reach peak operating and environmental performance.

Find out more at www.fwc.com/sru Select 75 at www.HydrocarbonProcessing.com/RS

CORPORATE PROFILE: FOSTER WHEELER SULFUR 2011

Peak operating, environmental performance with Sulfur Recovery Technology Sulfur Recovery Technology Foster Wheeler’s newly acquired sulfur recovery technology brings clear advantages to our refinery customers. The technology provides a smaller footprint, as well as cost-effective designs with enhanced operability features. Included in the proprietary technology is a Claus unit burner that is capable of destroying ammonia up to 25 mole % in the SRU feed, and providing low level oxygen enrichment up to 28 mole %. The units typically deliver overall sulfur recovery efficiencies ranging from 96% to 99.95% and higher, whereas efficiencies of other sulfur removal technology, for Claus type units, trend a bit lower.

Our Expertise Our personnel employed at the new Foster Wheeler Salt Lake City office are knowledgeable in the design of SRU units, including Claus units, tail gas treating units and tail gas incinerators. Our sulfur expertise also includes sulfur storage, sulfur degassing, sulfur pit vent disposition, sour liquid or gas amine absorbers, amine regenerators, sour water strippers, sulfur condensers, and waste heat boilers. Other areas of proficiency include hazardous waste incineration, natural gas processing, and general refinery units.

3 Catalytic Reactor Beds 200LTPD Sulfur Recovery Unit

Our Scope of Work Coupled with the small footprint, our design offers reduced piping runs that are completely free draining. Lower corrosion and reduced pressure drop are clear benefits from the reduced pipe routing, which also results in lower Capex and enhanced operability and maintenance.

Furthermore, all sulfur condenser passes–except the final pass–are typically routed through a single shell, based on unit capacity. We have also successfully designed units in which the thermal reactor waste heat boiler was also included with the sulfur condenser, in a single shell. The mechanical expertise required for reliable and safe design of the waste heat boiler and sulfur condenser tubesheets, as well as the partitioning of the condenser passes in the boiler plenums, has been developed through many years of experience. Steam pressures ranging from 50 psig to 600 psig are available, and each plant is designed to be self-sustaining in steam usage during normal operation. These proven, innovative designs help to set our technology apart from the rest.

Tail Gas Catalytic Reactor 200LTPD Tail Gas Treating Unit

Global Reach Our sulfur technology is currently operating all over the world, including North America, South America, Europe, and Asia. Currently, we are performing basic engineering of sulfur recovery units for four refineries in South America, each with an MDEA amine tail gas treating unit followed by tail gas incineration.

In addition to our sulfur recovery technology, Foster Wheeler also has heavy oil conversion technologies including delayed coking, and full EPC capabilities. We are also known in the chemicals, petrochemicals and polymers market. From consultancy and small process unit revamps to large integrated grass root complexes, we deliver comprehensive solutions that meet your requirements.

We are truly a global engineering and construction contractor, and power equipment supplier adding value with technically advanced services, reliable facilities and equipment.

Reach your peak operating and environmental performance with Foster Wheeler Sulfur Recovery Technology!

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Contact information Foster Wheeler USA 10876 S River Front Parkway, Suite 250 South Jordan, UT 84095 Phone: 801 382 6900 Fax: 801 382 6901 Email: dean_bybee@fwhou.fwc.com www.fwc.com 585 N. Dairy Ashford Houston, Texas 77079 Phone: (713) 929-5500 Fax: (713) 929-5170 Email: info@fwc.com www.fwc.com

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Worldâ&#x20AC;&#x2122;s Leader in Sulphur Technologies & Gas Processing With Advanced Sulphur Management We are committed to creating value for our customers. With over 60 years of experience in advanced technolgies, we can provide cost effective solutions through all phases of a project.

Sulphur Technologies Conventional Claus Ammonia & Contaminant Destruction Claus Selectox/Recycle Selectox Lean Acid Gases Oxygen Enrichment Technology Sulphur Degassing Internal & External Technologies Sub Dew Point Process - Up to 99.5% Recovery Beavon Sulphur Removal (BSR) New Technologies

Services t Concept Development t Feasibility Studies t Front-End Engineering t Site Selection t Detailed Design t Engineering t Procurement t Program Management

100+ tail gas treaters

For more information, contact sulphurtechnology@worleyparsons.com www.worleyparsons.com

t Construction t Construction Management t Start-up t Training t Operations Support t Optimization & Maintenance

500

sulphur recovery units

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gas plants with 250 BSCFD of gas processed

CORPORATE PROFILE: WORLEYPARSONS SULFUR 2011

Unrivalled experience in total sulphur management WorleyParsons is a leading global provider of professional services to the resources & energy sectors and complex process industries. Our services cover the full asset spectrum both in size and life cycle—from the creation of new assets to services that sustain and enhance operation assets.

Across our comprehensive global network of 32,900 employees in over 41 countries, our four customer sector groups—Hydrocarbons, Power, Mineral & Metals, Infrastructure and Environment—use their extensive expertise to deliver small studies through to mega-projects.

Total Sulphur Management. WorleyParsons has the unrivalled ability to address all sulphur removal and handling issues across all industry sectors.

In whichever industry sector you operate–oil, gas, upstream, downstream, minerals and metals or power generation—and whatever your sulphur related problem— environmental protection, sulphur removal, smelter offgas cleaning, sulphuric acid production, safe sulphur handling and storage—WorleyParsons has the answer.

Sulphur removal and management have long been core services in which WorleyParsons is recognized as a world leader, servicing the resources and energy sectors on large and small projects. Our expertise has been built up over many years and covers all major aspects of sulphur management, providing a unique total sulphur management capability. In the early stages of development, our Select team assists asset owners to identify the critical steps and decision points that maximize the value of their sulphur management project.

WorleyParsons understands what it takes to create and implement a successful development and our team of global sulphur experts provide quality expertise in environmental assessment, technology selection, infrastructure requirements, and safety considerations. Total Sulphur Management project opportunities can be developed using EcoNomics™, which assists our customers in adopting a broader view of the impacts of their operations and incorporates financial, social and environmental risk into their project decisions to deliver optimized and profitable solutions. This initiative delivers projects that are future-proofed with improved risk management for our customers.

Sulphur Recovery Technology. WorleyParsons is a world leader in sulphur recovery technology, with a track record extending over 60 years. We have designed and built more than 550 sulphur plants, more than 120 BSR tail gas units, and more than 66 sulphur plants to oxygen enrichment accounting for more than 60% of the world sulphur production. Our sulphur recovery experience includes projects from the North Slope of Alaska, Asia, Africa, the Americas, and deserts of the Middle East. We have also designed and constructed over 400 gas processing plants throughout the world that correspond to a total capacity of over 300 billion SCFD. We offer unrivalled experience in the design, engineering, commissioning and support of sulphur recovery plants. WorleyParsons currently offers more than ten sulphur recovery processes itself and in conjunction with its partners, such as Linde/ BOC. These technologies include standard and oxygen-enriched Claus technology, tail gas treating technology, and sulphur degassing and are able to meet the most stringent environmental standards. WorleyParsons’ expertise has been maintained and developed by building plants throughout the world using our leading-edge designs and know how.

Advanced New Technologies and Greenhouse Gases • Greenhouse Gases and Sulphur Technology RSR® (Rameshni SO2 Production): Reduction of the gas stream containing sulphur dioxide to elemental SPONSORED CONTENT

Consolidated sulphur terminal at Vancouver Wharves. Receiving, storage and ship loading (160,000 tonne storage).

sulphur is carried out by reacting a reducing gas with recycled sulphur to produce a stream containing hydrogen sulfide that may be reacted with the gas stream that contains sulphur dioxide. Gas streams with a molar concentration of sulphur dioxide from 1% to 100% may be processed to achieve nearly 100% recovery efficiency, and at a significantly reduced operating cost.

• RCTI® (Rameshni Catalytic Tail Gas Incineration): RCTI® is a new Claus Tail gas process that replaces conventional BSR/amine type (patent pending, Feb. 2008). It uses TGU low temperature catalyst and a selective direct oxidation catalyst. The gas leaving RCTI® can go to the incinerator or other units for processing SO2. This process eliminates NG consumption from conventional RGG by using an indirect heater and reducing fuel gas consumption in the incinerator.

• RSC-D® (Rameshni Sulphur Collection-Degassing): RSC-D® is a method for collection of liquid sulphur by using a liquid jet pump or eductor and by pumping the sulphur to a storage vessel and using a portion of liquid sulphur as a jet or eductor motive fluid compromising the new invention. The new invention eliminates the gravity flow constrains and plugging problems. In addition, the new invention provides entrainment and enough agitation in the liquid sulphur where simultaneously degassing occurs in the new method of sulphur collection system.

• Ammonia Burning in Tail Gas Treating Unit RAC® (Rameshni Ammonia Combustion): The RAC® process consists of ammonia destruction in a Claus Tail gas treating unit, providing less demand on selling ammonia and limited capacity to burn in sulphur plants. This has been developed to process additional ammonia beyond sulphur capability and replace natural gas consumption in the Claus Tail Gas Treating Unit to support GHGs and reduce CO2 emission.

Contact information Mahin Rameshni Vice President and Global Manager, Sulphur Technology and Gas Processing Phone: +1 626-803-9058 Mahin.Rameshni@WorleyParsons.com www.worleyparsons.com HYDROCARBON PROCESSING SULFUR 2011

I S-105

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LOSS PREVENTION

Review unit-wide impacts on closed-drain drums API 521 standard helps decipher the correct operating pressure for this system R. MUKHOPADHYAY, Consultant, Bangkok, Thailand

C

losed-drain drums are generally intended to receive hydrocarbondrained liquids from various upstream sources. These drains may be maintenance drains, continuous-process drains and open-hazardous drains from drip pans. The vent line of this vessel type is normally routed to the low-pressure (LP) cold vent header—ultimately culminating into a LP cold vent tip. Liquid from the drum is removed periodically. The drum inbreathes during pumping out and out breathes during liquid inflow through the vent line on top.

Design pressure. The question is what

should the design pressure be without any liquid seal at the vapor outlet to prevent air ingress? To a process designer, a simple design is very straight forward. The process designer will consider gas blowby scenarios from upstream contributory inlet streams and design the vent line of the closed-drain drum, sufficiently large to cater for the largest inflow rate either from non-continuous maintenance drains or the liquid rate from continuous drains coming through restriction orifices (provided for preventing blow-by scenarios). This would prevent the overpressure generation by allowing adequate out breathing facility in case of large inlet flow to the drum. Based on this simplistic concept, the design pressure of an open-to-atmosphere drum system is set at 3.5 barg = 50 psig, as per standard practice.

However, most process designers may not be able to explain why a 50-psig design pressure was chosen. Why not another number? To find an answer to why 50 psig was chosen, you have to remember that, apart from inlet streams coming from upstream and creating overpressure pos-

sibility in the drum, there may be another source of over-pressure as well.

Since these drums handle hydrocarbon liquid/vapor mixture and are operating at pressure slightly above atmosphere, there is a chance of air ingress to the drum in some circumstances (shutdown or other instances of inbreathing/pump-out, etc.), potentially inducing an explosion inside the drum. Vessels need to be strong enough to withstand such overpressure from the internal explosion. Note, in many cases, the LP vent header is not generally purged to prevent air ingress. Reasons are to minimize waste of hydrocarbon/nitrogen and green house gas emissions. Hence, the designer may need to rethink the vessel’s design pressure. The explosion overpressure from such a potential internal explosion (deflagration) becomes a key point in correctly assigning the design pressure of such drums.

In the past, simulations of explosion scenarios using sophisticated software for limited volume (30-m cloud) had been done (Fig. 1). These calculations used unconfined-explosion models. Maximum over-pressure generated in unconfined explosions is 2.5–3.0 barg or 40 psi.

This result is extended to arrive at the extent of over-pressure, suitable for the lower bound of the entire range. Instead of using any arbitrary number in the hydrocarbon processing industry, the number tends to fit the minimum design pressure of such low-pressure atmospheric vessels (non-purged, non-sealed on vapor side) at a minimum 3.5 barg. This is based on the results predicted from mathematical modeling/simulation from an explosion scenario. Following are specific company standard requirements regarding design pressure of closed-drain drums:

TOTAL’S GS-EP-SAF-228 (liquid drainage) states: “The design pressure of the closed-drain drum shall be 3.5 barg or more, in line with API RP 521, to provide minimum resistance to an internal explosion. All facilities connected to a closed drain drum shall be designed at no less than the design pressure of the closed-drain drum.” This is an open-ended statement, stating 3.5 barg or more. How much more pressure is not concluded. What is the method used to arrive at this pressure?

Shell’s DEP 80.45.10.10 (pressure relief, flare and vent system design), Section - 4.1.3.2 states: “The knockout drum shall be designed as an ASME pressure vessel with a design pressure of at least 3.5 bar (ga) (50 psig). If no seal vessel is used, the design pressure shall be at least 7 bar (ga) (100 psig). The minimum design pressure of 7 bar (ga) (100 psig) is specified for flare knockout vessels so that the vessel will safely withstand the overpressures from an internal deflagration (i.e., flashback).”

BP RP-44-1 also mentions a minimum

design pressure of 7 barg.

API-521, Section 7.3.2.4, states:

“Most knockout drums and seal drums are operating at relatively low pressures.

To ensure sound construction, a minimum design gauge pressure of 345 kPa (50 psi) is suggested for knockout drums in subsonic flare or other low-pressure applications. A vessel with a design gauge pressure of 345 kPa (50 psi) should not rupture if a deflagration occurs. Stoichiometric hydrocarbon-air mixtures can produce peak explosion pressures on the order of seven to eight times the absolute operating pressure. Most subsonic-flare seal drums HYDROCARBON PROCESSING MAY 2011

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LOSS PREVENTION operate in the range of gauge pressure from 0 kPa to 34 kPa (0 psi to 50 psi).

Seven to eight times the absolute working pressure gives the range of explosion overpressure in such drums as: (0+14.7)* 7 psi to (5+14.7) *7; i.e., 102.9 psi – 137.9 psi or 7 barg – 9.5 barg for most of the subsonic flare seal drums/vent knock-out drums (KODs)—unpurged/unsealed atmospheric closed drain drums. Analyzing the API 521 standard, starting from a minimum 50 psi design gauge pressure, it states

that the vessel would not rupture under deflagrations. However, based on the drum operating pressure, the explosion overpressure can go up to 137.9 psi (9.5 barg) in commonly known cases. Hence, you can’t always stick to a single design pressure value of 50 psig (3.5 barg) for all atmospheric drums. Along with a design pressure arrived at based on purely process considerations, an internal explosion overpressure might become significant if the possibility of such deflagration exists.

Select 174 at www.HydrocarbonProcessing.com/RS 108

These higher design pressure range values can be justified by the API 521 interpretation, from a mechanical design point of view of carbon steel, which is the most commonly used material for such vessels.

Let’s look at API 69 (latest edition) clauses to find a relationship. NFPA 69 has taken it a step further to define two different acceptability criteria with respect to vessel deformation/failure that is: 1) Design pressure for a scenario where explosion causes vessel deformation, but no rupture occurs and 2) Design pressure for a scenario where explosion causes no vessel deformation.

Obviously, vessels designed for the second scenario will require higher design pressure (may be higher plate thickness).

Some clients prefer design 1, but others prefer design 2. Once the design criteria is established and in line with the NFPA— the design matches harmoniously with the API-521 interpretation of two design pressure ranges: minimum 3.5 barg and the higher side up to 9.5 bar. This depends on the drum’s observed operating pressure.

ASME has a method of calculating deflagration containment design pressure for vessels as per Section VIII, Division 1, of the Boiler and Pressure Vessel Code.

ASME Boiler and Pressure Vessel Code defines two terms to explain the previously mentioned “no rupture” and “no deformation” concepts. It defines the ratio of “ultimate stress” and “enclosure material allowable stress” as a dimensionless entity symbolized by Fu. It also defines the ratio of “yield stress” and “enclosure material allowable stress” as another dimensionless entity symbolized by Fy . Fu corresponds to the “no rupture but deformation” concept, whereas Fy corresponds to the “no deformation” concept.

Fu = 60,000/20,000 = 3.00; carbon steel plate; SA-516 60 K02100; Temperature < 150°F Fy = 32,000/20,000 = 1.6; carbon steel p; SA-516 60 K02100; Temperature < 150°F The following excerpt illustrated in Table 1 from ASME Section II, Part D, to justify the values mentioned previously.

Line 22 values from Table 1 are relevant for this case of Fu and Fy (60,000, 32,000 and 20,000). Using the concepts of NFPA 69’s standing and following mentioned clauses, the intended range of deflagration design pressures of 3.5 barg to 9.5 barg can be established and verified. Relevant clauses from NFPA 69 are defined: 13.3.4* Given an initial pressure and dimensionless pressure ratio for the poten-

LOSS PREVENTION TABLE 1. Allowable stress (ksi), ASME Section II, Part D, USC Units Alloy Min. tensile Min. yield External Max. Line Nominal Product Spec. Type/ design/Units P- Group strength, strength, pressure use no. composition form No. grade No. No. No. ksi ksi chart No. temp. Notes < 100°F < 150°F < 200°F < 250°F Plate

SA-515

60

K02401

1

1

60

32

CS-2

1,000

G13,T3

21.3

22

Carbon steel

Plate

SA-516

60

K02100

1

1

60

32

CS-2

1,000

G13,T3

23

Carbon steel

Plate

SA-283

D

K02702

1

1

60

33

CS-2

700

4.0

0.40

3.5

0.35

3.0 2.5 2.0 1.5 1.0 0.5 0.0

FIG. 1

Explosion overpressure, MPa

tial deflagration, Pmawp shall be selected based on the following conditions as defined by Eqs. 1 and 2: Permanent deformation, but not rupture, of the enclosure can be accepted.

Pmawp ≥ [R(Pi =14.7)-14.7]/(2⁄3 Fu ) (1) Permanent deformation of the enclosure cannot be accepted.

Pmawp ≥ [R(Pi =14.7) -14.7]/(2⁄3 Fy ) (2) where: Pmawp = enclosure design pressure (psig) according to ASME Boiler and Pressure Vessel Code R = dimensionless pressure ratio Pi = maximum initial pressure at which combustible atmosphere exists (psig) Fu = ratio of ultimate stress of the enclosure to the allowable stress of the enclosure according to ASME Boiler and Pressure Vessel Code.

Fy = ratio of the yield stress of the enclosure to the allowable stress of the materials of construction of the enclosure according to ASME Boiler and Pressure Vessel Code.

13.3.4.1* The dimensionless ratio, R, is the ratio of the maximum deflagration pressure, in absolute pressure units, to the maximum initial pressure, in consistent absolute pressure units.

13.3.4.2 For use as a practical design basis (since optimum conditions seldom exist in industrial equipment), the value of R is: • For most gas and air mixtures, the value of R shall be 9 • For St-1 and St-2 dust–air mixtures, the value of R shall be 11 • For St-3 dust–air mixtures, the value of R shall be 13 13.3.4.3 A value for R other than the values specified in 13.3.4.2 shall be permitted to be used if such value can be substantiated by test data or calculations.

13.3.4.4 For operating temperatures below 25°C (77°F), the value of R˙ shall be calculated for use in Eqs. 1 and 2: R˙ = R [298 / (273+Ti )] (3) where: R˙ = deflagration ratio adjusted for operating temperature R = maximum deflagration ratio for the mixture measured at 25°C (77°F) Ti = operating temperature (°C)

20

19.5

19.2

21.3

20

19.5

19.2

22.0

20.7

20.2

19.8

50

0.30

30-m cloud–CFD Simulation A 30-m cloud–CFD Simulation B Design pressure–time curve No. 3

0.25

40

0.20

30

0.15

20

0.10 0.5 0.00 0.00

10 0.10

0.20

0.30

0.40 0.50 0.60 Time, seconds

0.70

0.80

0.90

Explosion overpressure, psi

Carbon steel

Explosion overpressure, bar

21

0 1.00

345-kPa (50-psig) design pressure-time curve and typical model calculations.

13.3.5 The presence of any pressure relief device on the system shall not cause the design pressure calculated by the methods of 13.3.4 to be reduced.

13.3.6* The maximum initial pressure for positive pressure systems shall be as follows: • For positive pressure systems that handle gases and liquids, the maximum initial pressure, Pi, shall be the maximum initial pressure at which a combustible atmosphere is able to exist, but a pressure not higher than the setting of the pressure relief device plus its accumulation.

• For positive pressure systems that handle dusts, the maximum initial pressure shall be the greater of the following two pressure values: • Maximum possible discharge pressure of the compressor or blower that is suspending or transporting the material • Setting of the pressure-relief device on the vessel being protected plus its accumulation • For gravity discharge of dusts, the maximum initial pressure shall be the atmospheric gauge pressure (0.0 bar or 0.0 psi).

13.3.7 For systems operating under vacuum, the maximum initial pressure shall not be less than atmospheric gauge pressure (0.0 bar or 0.0 psi).

13.3.8 Auxiliary equipment such as vent systems, man ways, fittings and other openings into the enclosure, which could also experience deflagration pressures, shall be designed to ensure integrity of the total system and shall be inspected periodically.

Using the previously stated concepts of “permanent deformation acceptable” and “permanent deformation not acceptable” and the concepts of ultimate tensile stress, yield stress and allowable stress of the material of construction (usually carbon steel material) with the proper number crunching, the following calculation support is: • Permanent deformation acceptable.

R = 9 per NFPA 69 for most gas and air mixtures Pi = 0.0 psig (Assuming Atmospheric conditions) Fu = 60,000/20,000 = 3.00 for carbon steel plate SA-516 60 K02100 temperature < 150°F Pmawp ≥ [9 * (14.7 + 0.0) – 14.7] / [(2/3) * (60,000/20,000)] Pmawp ≥ 58.8 psig for vessel operating @ 0.0 psig (59.25 for 0.1 psig) Matches perfectly with NIOSH’s design pressure vs. time curve (Fig. 1).

Pmawp ≥ 283.8 psig for vessel operating @ 50 psig Pmawp ≥ 81.3 psig for vessel operating @ 5 psig.

The hydrocarbon processing industry appears to have accepted 50 psig as the design pressure for vessels operating at or near atmospheric pressure. The case valid for permanent deformation accepted but no rupture, in case of internal explosion. “R = 9” given in NFPA for HC. A value of R = 7.8 would give Pmawp= 50 psig. The value of R = 7.8 is in perfect agreement with the statement in API 521 that stoichiometric HYDROCARBON PROCESSING MAY 2011

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LOSS PREVENTION

in Process Unit Decontamination

New Directions

hydrocarbon-air mixture can produce peak explosion overpressure on the order of seven to eight times the absolute operating pressure.

• Permanent deformation not acceptable (preferred by some clients): R = 9 per NFPA 69 for most gas and air mixtures Pi = 0.0 psig (assuming atmospheric conditions) Fy = 32,000/20,000 = 1.6 for carbon steel plate SA-516 60 K02100 temperature

< 150°F Pmawp ≥ [9 * (14.7+0.1) – 14.7] / [(2/3) * (32,000/20,000)] Pmawp ≥ 110.25 psig for vessel operating @ 0.0 psig (111.1 for 0.1 psig) Pmawp ≥ 532.13 psig for vessel operating @ 50 psig Pmawp ≥ 153.4 psig (10.6 barg) for vessel operating @ 5.0 psig; R = 9.0 Pmawp ≥ 131.4 psig (9.0 barg) for vessel operating @ 5.0 psig; R = 7.8 Conclusion: This is an unusual case, if

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permanent deformation cannot be accepted in case of internal explosion.

Usually, after an event like an internal explosion, the vessel integrity would be in question and calls for replacement. However, some clients prefer to have design pressure like this. Hence, for the design concept of the “permanent deformation not acceptable” case, the design pressure of closed-drain drum can be in the range of 9-9.5 barg, in line with the API 521 7.3.2.4 (h) clause and the values mentioned in Shell DEP, TOTAL’s GS-EP, BP-RP and other reputed company standards.

Mechanical design view point. A

vessel designed for DP = 100 psig will show permanent deformation, but no rupture up to 300 psig (simple ratio of design. Stress vs. rupture stress or UTS).

A vessel designed for DP = 100 psig will not show permanent deformation up to 160 psig (simple ratio of design stress vs. yield stress).

A carbon-steel vessel designed for MAOP= 50 psig and a thickness of 1⁄4 in. can be as big as 12 ft diameter. So, do not bother till the vessel diameter exceeds 12 ft. If the diameter exceeds 12 ft, consider increasing the length, keeping the diameter at 12 ft.

Design pressure of atmospheric vessels like closed drain drums (not purged), considering internal explosion case: Min. 50 psig (would not rupture as per API 521 Max. = in the range of 131–153.4 psi (9–10.6 barg), considering a variation of R from 7.0–9.0.

It is established with calculation supports and references that 50 psig–153.4 psig is the range of design pressure of the closeddrain drum type atmospheric low-pressure vessels, handling hydrocarbon vapor/liquid, with no liquid seal for the LP vent from the vessel; the usual operating pressure of the vessel varies from 0–5 psig. This is on the basis of deflagration (internal explosion) over-pressure, mentioned in many operating company standards and API 521. HP Rajib Mukhopadhyay earned a BTech degree in chemical technology and a BSc degree in chemistry from the University of Calcutta. He has more than 17 years of professional experience in oil and gas sector, specializing in the process safety and loss prevention field. Mr. Mukhopadhyay has extensive hands-on experience in operation, commissioning and trouble-shooting process operations. He has worked for numerous engineering and production organizations.

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Your Company + KBC Produces NextGen Performancen We collaborate with our clients to create unique solutions to their speciďŹ c challenges. Some of these challenges may include: Strategic Challenges

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U Increasing Return on Capital Investment U Rationalising/Optimising Environmental Compliance Capital Expenditures U Reducing Capital Risk

Operating Challenges U Improving Yield U Increasing Availability U Reducing Maintenance Costs U Improving Safety Performance U Implementing/Improving U Managing Operational Risk Behaviour-based Reliability U Improving Supply Chain Performance

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For more information on how KBC can help you achieve NextGen Performance, contact us at: AMERICAS +1 281 293 8200 EMEA +44 (0)1932 242424 ASIA +65 6735 5488 answers@kbcat.com U www.kbcat.com

PROCESS INSIGHT Optimizing CO2 Capture, Dehydration and Compression Facilities The removal of CO2 by liquid absorbents is widely implemented in the field of gas processing, chemical production, and coal gasification.

Many power plants are looking at post-combustion CO2 recovery to meet environmental regulations and to produce CO2 for enhanced oil recovery applications. The figure below illustrates actual data of fuel consumption in 2005 and an estimate of energy demand for various fuels from 2010 to 2030.

The world energy demand will likely increase at rates of 10–15% every 10 years. This increase could raise the CO2 emissions by about 50% by 2030 as compared with the current level of CO2 emissions. The industrial countries (North America, Western Europe and OECD Pacific) contribute to this jump in emissions by 70% compared to the rest of the world, and more than 60% of these emissions will come from power generation and industrial sectors.

formulated solvent without implementing any split flow configurations. This is much less than the reported steam usage for the MEA solvent.

The design of a facility to capture 90% of the CO2 from the flue gas of a coal fired power plant is based on the specified flue gas conditions, CO2 product specifications, and constraints. Using the ProMax® process simulation software from Bryan Research & Engineering, CO2 capture units can be designed and optimized for the required CO2 recovery using a variety of amine solvents. The following figure represents a simplified process flow diagram for the proposed CO2 Capture Plant.

Despite the strong recommendations from certain governments, there are very few actual investments in CO2 capture facilities geared toward reducing greenhouse gas emissions mainly because of the high cost of CO2 recovery from flue gas. CO2 capture costs can be minimized, however, by designing an energy efficient gas absorption process. Based on the findings of recent conceptual engineering studies, HTC Purenergy estimated the production cost to be US$ 49/ton CO2 (US$ 54/ tonne CO2) for 90% CO2 recovery of 4 mole% CO2 content in the flue gas of NGCC power plants. A separate study showed the cost for 90% CO2 recovery of 12 mole% CO2 from a coal fired power plant to be US$ 30/ton CO2 (US$ 33/tonne CO2). The cost of CO2 recovery from coal power plant flue gas is substantially less than that of NGCC power plant flue gas due to the higher CO2 content in the feed.

The energy efficiency of a CO2 capture plant depends primarily on the performance of the solvent and optimization of the plant. In traditional flue gas plant designs, MEA was the primary solvent and was limited to 20 wt% to minimize equipment corrosion. Recent developments in controlling corrosion and degradation has allowed an increase in the solvent concentration to about 30 wt% thus decreasing the required circulation and subsequent steam demand. A recent DOE study shows the steam consumption for an existing CO2 plant using 18 wt% MEA (Kerr McGee Process) is 3.45 lb of steam per lb of CO2 for amine regeneration. A modern process that uses 30 wt% MEA is expected to use 1.67 lb of steam per lb of CO2 for amine regeneration. The HTC formulated solvent is a proprietary blend of amines and has a lower steam usage than the conventional MEA solvent. Based on the material and energy balances for the plant designed in the recent study, the reboiler steam consumption is estimated at about 1.47 lb steam/lb CO2 using the proposed

The table below presents the main findings for CO2 capture from the coal fired power plant and the NGCC power plant, each designed to produce about 3307 ton per day (3,000 TPD metric). To produce the same capacity of CO2, only one train with smaller column diameters is required in the case of the coal power plant and two trains with larger column diameters are required in the NGCC Power Plant case. This is mainly due to processing a larger flue gas with lower CO2 content in the NGCC power plant. Consequently, a substantial reduction in the capital and production cost was reported for the coal fired power plant CO2 recovery facility.

For more information about this study, see the full article at www.bre.com/support/technical-articles/gas-treating.aspx.

Bryan Research & Engineering, Inc. P.O. Box 4747 • Bryan, Texas USA • 77805 979-776-5220 • www.bre.com • sales@bre.com Select 113 at www.HydrocarbonProcessing.com/RS

PROCESS DESIGN

Design an efficient exchanger network Advanced heat integration and pinch technology reduces energy consumption F. RIKHTEHGAR, KBS Co., Tehran, Iran

TABLE 1. Stream data Stream no.

1

⌬H, KW

CP, W/ºC

80

2,000

20

Stream Supply temp., Target temp., type ºC ºC Hot

180

2

Hot

130

40

3,600

40

3

Cold

60

100

3,200

80

4

Cold

30

120

3,240

36

(HENs)–generating savings in processes and total sites. Wherever heating and cooling process materials take place, there is a potential opportunity to save energy.

Composite curve. HEN analysis first identifies hot and cold

stream sources (source and sink) from the material and energy balance. For instance, the current typical flowsheet of a specialty chemical process is considered (Fig. 1). For heat exchange, there are only three streams (reactor feed, reactor product and column product). The supply and target temperature and enthalpy change of four streams are given in Table 1.

180 Temperature, °C

E

nergy use in chemical plants, such as refineries and petrochemical facilities is complex and interrelated. Identifying where and how energy use can be improved is best pursed using a system approach that inherently takes these complexities and interactions into account. This article will demonstrate the basic principles and capabilities of pinch technology; how its energy targeting capability is used to determine the scope for reducing energy consumption and costs; and the design methods used to improve heat-recovery networks and process-utility systems for olefin plants. The intent is to illustrate the potential for energy recovery in each chemical process, how much heating/ cooling is actually required for the process, and how we can design a process that achieves the energy target.

The term pinch technology was introduced by Linnhoff to represent a thermodynamically based methodology that guarantees minimum energy levels in the design of heat exchanger networks

150

Hot composite curve

100 ΔTmin = 10°C

50

H FIG. 2

Current case composite curve.

60°

QHmin = 960

ΔH 3,200 heat

Condenser

ΔH 3,240 heat

120°

R1

72° Reboiler

R2 130°

180°

FIG. 1

Flowsheet of a case study.

ΔH 2,000 cool

ΔH 40° 3,600 cool

Temperature, °C

200

100° 30°

Cold composite curve

150 100 ΔTmin = 10°C

50

80°

QCmin = 120 H FIG. 3

Composite curve of targeting case.

HYDROCARBON PROCESSING MAY 2011

I 113

PROCESS DESIGN QHmin

Energy

Temperature

Cost

Total

Fig. 2 shows ΔTmin = 10°C, and, for this flowsheet, the hot and cold utility recovery is 960 and 120 units respectively.

The importance of ΔTmin is that it sets the relative location of the hot and cold streams, and therefore the heat recovery amount (Fig. 4).

The heat-recovery pinch. To achieve

a small ΔTmin, the types of heat exchanger and fluid regime are important. We consider counter-current flow for that and operating with a ΔT min less than 10°C should be avoided. In Table 2, minimum approach temperature for some industries has been shown. The correct setting of composite curves is defined by an economic trade-off between energy and capital cost, according to selecting ΔTmin. Fig. 4 illusTinterval trates the total system cost as the relative QHmin position of composite curves is changed over a range of ΔTmin. There is a trade-off between energy and capital cost and an eco␣ nomic amount of energy recovery, thus this trade-off can be carried out using energy and capital cost targets.

Pinch principles include: • Do not recover process heat across QCmin pinch H Grand composite • Do not use cold utility above pinch • Do not use hot utility below pinch • CP rule: CPOUT >= CPIN for feasibility.

During pinch analysis, threshold problems may occur when the composite curves are closer together. In this case, one of the hot/cold utilities will be zero while the utility consumption is constant. Finally, the cost graph will be shown according to this constraint. A better method to calculate the energy targets is the problem table algorithm. By shifting the composite curves (CCs), ΔTmin /2, you can do the heat balance across the shifted CC and shifted temperature intervals. In each shifted temperature interval, the calculated energy balance is: ΔTmin

Capital QCmin ΔTmin

FIG. 4

H

Balanced composite curve.

␣

Tinterval

Temperature

QHmin

QCmin H Composite curves

FIG. 5

H Shifted composites

Grand composite curve of a case study.

7

Temperature

6 5

ΔHi = [ ∑ CPC-∑CPH ] ΔTi

4 3 2 1

(

7 qstream 1 ––– ∑ ––– Network area: Amin = ∑ DT H LM interval

)

H FIG. 7

Area integrity of HEN.

Consider steam at 200°C and cooling water (CW) at 20°C for heating and cooling utilities. It is preferable to try to recover the heat between process streams. The scope for heat recovery can be determined by plotting all streams on T-H diagram (Fig. 2).

114

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I MAY 2011 HydrocarbonProcessing.com

Utility selection. Part of heat recovery is calculated by using external utilities. The remaining maximum heat recovery of HEN should be calculated with utilities after the heat recovery of process-process heat exchangers. The common hot utility is steam in several levels; flue gas or hot oil are designated as high-temperature utilities. Cooling water, air cooling, air preheater and some steam generation are designated as cold utilities. In pinch analysis, the grand composite curve (GCC) is an appropriate tool to show the interface between the process and utility system (Fig. 5).

With the GCC method, the premise is to use the specified utility at the appropriate levels. For hot utility, use at the lowest temperature and generate at the highest temperature. For a cold utility, use at the highest temperature and generate at the lowest temperature.

Grid diagram. The energy recovery analysis considers two

separated regions as below and above the pinch to achieve energy

PROCESS DESIGN targets during the HEN design. For instance, if there is a chemical plant flowsheet, it is complicated to show the pinch point, streams and the overall required diagram. Thus, another tool to represent pinch design is needed. The grid diagram is used when the designer focuses on streams that need heating/cooling and removal of all unit operations except heat exchangers, heaters and coolers. In the grid diagram, all the hot/cold streams are clear and the related heat-exchange region should be clarified (Fig. 6—Editor’s note: Fig. 6 is available online at HydrocarbonProcessing. com).

this study, the cracking furnace and super-heater were excluded due to acceptable heat integration and the reaction that was done.

A ΔTmin value of 10°C was chosen to mention future potential savings. The extracted stream data is shown in Table 3 (Editor’s

Poor economics Good economics

Don’t discard existing area

Heat-exchanger area target. It is possible to predict the Ideal scenario Area

required area for the entire problem by using the vertical enthalpy intervals; the area calculated with this model is only minimal when all the stream heat-transfer coefficients are equal. For each enthalpy interval, we can predict the area requirement from the composite curves. The duty and heat-transfer coefficient are obtained from the stream data, and the log-mean temperature difference (ΔTLM) is derived from the composite curves (Fig. 7).

Existing network

‘Grassroots’ optimum

Grassroots trade-off curve Infeasible

Retrofiting exchanger networks. Most industry own-

Olefin plant pinch analysis. For a

more detailed study, in this step consider a case study of pinch analysis on an olefin plant, located south of Iran (BIPC). The plant’s capacity is 411,000 metric tons/yr of ethylene product. Process data was taken from the design process flow diagrams and discussions with operating engineers. The olefins unit was separated for the pinch analysis into cold and hot sections. This is due to the significant differences in temperatures and operation economics. During

Temperature, C

Temperature, C

ers are interested to do it by considering the minimum required Energy energy consumption. Revamping the heat-exchanger network will be the key factor within these projects. Pinch studies for FIG. 8 Area/Energy trade-off. revamp projects are more common. The technique used in this technology is retrofit. The need to retrofit might arise from a desire to reduce the 900 utility consumption of the existing netHot composite 800 work. If the need to increase throughput Cold composite is required, modify the feed to the process 700 or apply a modification to the product 600 specification.

Naphtha furnace 500 A typical capital/energy trade-off durproduct ing a revamp project is explained using the 400 Ethane furnace product grassroots trade-off curve as a basis, (Fig. 8).

300 Any existing design or revamped design will Dilution steam Quench oil 200 lie above the grassroots curve. The shaded Quench water heat recovery area is infeasible for any revamp design.

100 Column reboilers However, in a revamp situation, the Liquid feed 0 objective is to make the best use of the 0 100 200 300 400 500 600 700 Enthalpy, GJ/h existing area. In an ideal scenario, one FIG. 9 Composite curves for ethylene hot section. would like to proceed horizontally, as shown (maintaining the same area but reducing energy). A realistic revamp project will follow a curve that represents increased 900 area requirements and reduced energy Process GCC 800 requirements (Fig. 8). A curve with better Utility GCC Naphtha furnace product economics is closer to the grassroots curve.

700 600

Ethane furnace product

500 400 U: HP steam (gen)

300 200

U: PS steam

100

Dilution steam

0 0 FIG. 10

U: MP steam Pygas rec cooler Quench water heat recovery Liquid feed U: cooling water

100

200 Enthalpy, GJ/h

300

400

GCC for ethylene hot section.

HYDROCARBON PROCESSING MAY 2011

I 115

PROCESS DESIGN TABLE 2. Industrial recommended ⌬Tmin Industrial sector

Experience ⌬Tmin value, °C

Oil refineries

20–40

Petrochemicals

10-20

Chemical plants

10–20

Low temperature processes

3–5

TABLE 4. Energy targets and gaps Heating

Target, Gj/hr

Now, Gj/hr

To save, Gj/hr

MPS

68.2

133.9

65.7

PS

19.1

50.8

31.7

Total hot

87.3

184.7

97.4

Cooling

Target, Gj/hr

Now, Gj/hr

To save, Gj/hr

PS (Gen)

0

62.1

62.1

CW

114.2

321.1

206.9

HPS (Gen)

148.7

135.1

–13.6

Sea Water

151.5

0

–151.5

C3, 20°C

6.46

0

–6.46

Total cold

420.9

518.3

97.4

Total energy

508.2

703

194.8

note: Table 3 is available online at HydrocarbonProcessing.com).

Fig. 9 illustrates the composite curves for the process.

The energy targets and the pinch temperatures obtained by the pinch analysis are shown in the Table 4.

Table 4 illustrates that the total potential savings is 194.8 GJ/hr.

The majority of the savings should be achieved through reducing steam use and increasing high-pressure steam generation. Fig. 10 shows the grand composite curve for the utility data.

According to GCC, it recommends that MPS should be used to increase high-pressure steam generation since it is a higher level and more beneficial for the plant. The other case is using a cross pinch, but it causes some energy penalties within the HEN and using the retrofit project can optimize these problems for energy targeting.

Conclusion. The best design for an energy-efficient HEN results in a trade-off between the equipment and operating cost.

This is dependent on the choice of the ΔTmin for the process.

Pinch technology can help guide the choice of process modification. It can be applied to generate financial savings by improving heat recovery and reducing utility loads. Pinch analysis begins with the heat and material balance, and certain parameters should be chosen. It is very important to extract the required data for taking into account when a new design or a retrofit study is prepared.

It consists of the key targeting steps: heat recovery improvement, utility selection and process changes. HP LITERATURE CITED Complete literature cited is available online at HydrocarbonProcessing.com.

Farbod Rikhtehgar is a process engineer at KBS Co., specializing in modeling and simulation studies of refineries and petrochemical plants. He has a BS degree in chemical engineering from Iran University of Science and Technology and an MS degree, specializing in energy from Tehran University.

Buzau - ROMANIA phone: +40 238 725 500 www.betabuzau.ro

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ENGINEERING CASE HISTORIES

Case 62: Useful shaft stress equations to remember Committing several equations to memory can be useful T. SOFRONAS, Consulting Engineer, Houston, Texas

R

emembering complex equations is not required for reasonable on-thespot answers. Neither are sophisticated computer studies when a quick screening study will be satisfactory. This case history shows simple equations1 that have been useful for making quick decisions.

Failed solid circular shafts. Too much shaft torque can cause failures; so it’s good to remember this torque equation: Torque due to horsepower (HP): T = 63,000 HP / rpm in-lb Torsional shear stress failure solid circular shaft is: Ss = 16 K Tin-lb/ (π Din

3)

lb/in2

K is the stress magnifier caused by sharp corners such as keyways and steps (shoulders). K = 2 can be used for both torsion and bending.

Assuming no material data were available for more accurate decisions, calculations showing stress Ss greater than 25,000 lb/in2 for mild steels would be cause for concern.

Bending failure solid circular shaft.

There is usually a bending moment M (inlb) acting on the shaft.

Sb = 32K Min-lb / (π Din3 ) lb/in2 Calculating Sb greater than 50,000 lb/ in2 would be a concern for mild steels without materials data.

Fatigue failures shafting. Cyclic torque or bending on shafting can result in fatigue cracking at stresses much lower than the yield strength.

When fluctuating loads are calculated using the above equations, they need to be compared to the endurance limit of the steel. The uncorrected endurance limit is approximately half the ultimate strength of the steel. “Uncorrected” means a perfectly smooth shaft with no imperfections. Cor-

rosion, poor surface finish and other irregularities could reduce this value by 50% or more. In the case of a welded shaft the cyclic stresses at even a good weld should be less than approximately 2,000 lb/in2 to avoid risking fatigue type failures.

Combined stresses. When shear stresses (S s ) and bending stresses (S b) are both present at the same section of the shaft at the same time, the two combine into an equivalent stress Se , which should then be compared to the yield stress:

Motor

M

Failure

Se = ( Sb2 + 3Ss2 ) ⁄ lb/in2 1

2

Equations on a vertical centrifugal pump. Consider a 1-in. broken shaft, as shown in Fig. 1. This is a 75-hp pump operating at 3,560 prm. The shaft broke near a steady bushing and the moment at that point was M. Using the previous equations: FIG. 1

T = 1,327 in-lb and Ss = 13,520 lb/in2 is much less than the 25,000 lb/in2 yield.

The shaft should not have failed in torsion unless the material yield properties were lower or there was a torque 2 times or more above design. Lower material properties might be possible due to corrosion or a material substitution made at a repair.

Since M is unknown, so is Sb ; we will thus determine what M would have to be to cause the shaft to fail at the location observed: 50,000 =[{ 32 2 M / (π 3 13,5202 ] ⁄ 1

13)}2

+

2

M = 2,170 in-lbf This is a significant bending moment for a shaft that should not have such a moment at this location. Yet, there was a failure.

It would be logical to now request a metallurgical examination of the fracture surface, and the outcome of such an examination will be valuable. A bending-torsion failure might suggest misalignment. A pure

Vertical pump shaft failure.

torsional failure might suggest binding.

Fatigue might suggest cavitation, or vibratory activity due to misalignment or unbalance. Low-material strength properties due to corrosion damage or inadequate material selection may have led to failure because low-strength materials simply cannot carry the imposed load. HP 1

LITERATURE CITED Sofronas, A., Analytical Troubleshooting of Process Machinery and Pressure Vessels: Including Real-World Case Studies, John Wiley & Sons, p. 6.

Dr. Tony Sofronas , PE, 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://mechanical engineeringhelp.com.

HYDROCARBON PROCESSING MAY 2011

I 117

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Flowserve Pumps . . . . . . . . . . . . . . . 63

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Bently Pressurized Bearing Co . . . . . . 86 (170)

CB&I . . . . . . . . . . . . . . . . . . . . . . . . . 18

Flottweg AG . . . . . . . . . . . . . . . . . . . 19 (152)

GE Power and Water . . . . . . . . . . . . . . 8

www.info.hotims.com/35903-67

Baldor Electric Company . . . . . . . . . . 74

(93)

(64)

www.info.hotims.com/35903-53

Baker Hughes Inc . . . . . . . . . . . . . . . 40

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

Company Website

www.info.hotims.com/35903-98

GEA Wiegand GmbH . . . . . . . . . . . . . 88 (171)

www.info.hotims.com/35903-64

Axens . . . . . . . . . . . . . . . . . . . . . . . 124

Eralytics GmbH . . . . . . . . . . . . . . . . . 58 (161)

(76)

www.info.hotims.com/35903-76

Asco Valve Inc. . . . . . . . . . . . . . . . . . 77

RS#

www.info.hotims.com/35903-93

www.info.hotims.com/35903-159

Ariel Corporation. . . . . . . . . . . . . . . . . 6

Page

www.info.hotims.com/35903-161

www.info.hotims.com/35903-156

Altair Strickland. . . . . . . . . . . . . . . . . 60

Company Website

(96)

www.info.hotims.com/35903-168

Weir Minerals - Lewis Pumps . . . . . . . 70

(92)

www.info.hotims.com/35903-92

Wood Group Surface Pumps . . . . . . . 47 (158) www.info.hotims.com/35903-158

Zyme-Flow . . . . . . . . . . . . . . . . . . . . 78

(71)

www.info.hotims.com/35903-71

Zyme-Flow . . . . . . . . . . . . . . . . . . . 110 (175) www.info.hotims.com/35903-175

For information about subscribing to HYDROCARBON PROCESSING, please visit www.HydrocarbonProcessing.com HYDROCARBON PROCESSING MAY 2011

I 121

HPIN WATER MANAGEMENT LORAINE A. HUCHLER, CONTRIBUTING EDITOR Huchler@martechsystems.com

Legionella—to test or not to test?

Legionella pneumophila (“legionella”) bacteria cause Legionellosis, a pneumonialike illness that infects persons with compromised immune systems and can be fatal. These bacteria are common in natural waters and thrive in warm waters found in cooling towers. Cooling towers that have high concentrations of water droplets (aerosols) entrained in the vapor plume can broadcast aerosols several miles before the droplets reach the ground. If water from these cooling towers has high populations of legionella bacteria, vulnerable persons who inhale the aerosols have a high risk for potential infection.

Designing the optimal strategy to minimize the risk of legionella infections in populations downwind of the cooling tower requires a combination of mechanical, chemical and operational solutions.

One of the most controversial aspects of managing the risk of Legionellosis from cooling towers is the bacteria test protocol and the decision to test or not to test for legionella bacteria.

Most European countries have legal requirements to conduct routine testing for legionella bacteria in cooling towers.1 There are no legal or regulatory requirements to conduct legionella testing in the US. However, the Cooling Technology Institute (CTI) is creating a standard2 for cooling towers that requires legionella testing (culture method) for validation of the bacteria control program and bacteria testing for control.

Validation methods. Validation

requires that the cooling tower owner conduct successive legionella tests during a specified time period and obtain nondetectable legionella bacteria for all test results. The validation process assumes that the bacteria control program will be effective in controlling the population of legionella bacteria for the remainder of the validation period.

At present, the draft standard requires the legionella culture test—a test that requires a certified laboratory to conduct the approximate 10-day test. The draft stan122

I MAY 2011 HydrocarbonProcessing.com

dard does not currently provide any options for alternative legionella test methods.

However, there are technologies available: polymer-chain reaction (PCR) and immunoassay. The qualitative PCR method, Q-PCR, amplifies a synthetic DNA primer molecule known as a probe labeled with a fluorescent dye that binds to the Legionella pneumophila bacteria3 with sensitivity similar to the standard culture method.

The KWR study showed that three Q-PCR methods detected the same number of positive results as the standard culture method. The immunoassay method showed a positive correlation to the culture method.

The immunoassay test uses antibodies to detect the legionella bacteria. One of the commercially available immunoassay tests is the Fastpath.4 Q-PCR tests are available within 24 hours while immunoassay results are available in less than an hour.

Bacteria testing. Industry has documented that the likelihood of detecting legionella bacteria in cooling water increases as the aerobic bacteria population increases. The preferred control method is to monitor aerobic bacteria population.

The most common test for aerobic bacteria is a culture method on an agar media.

Operators examine the test results on a daily basis and use the preliminary results to adjust the biocide feedrate.

Alternatively, operators may use other tests as a control method: adenosine triphosphate (ATP) or biological activity reaction test (BART). ATP methods use bio-luminescence to measure the relative amount of live cells that may or may not correlate to the results of the culture method, depending on the species of bacteria and accuracy of the test method. The BART methods use a nutrient media that is specific to a category of bacteria (e.g., heterotrophic aerobic, slime-forming, fluorescent Psuedomonads, etc.)

Conclusions. The legionella culture method is the definitive measure of the bacteria, but the delay in obtaining results makes this method inappropriate as a rou-

FIG. 1

Legionella pneumophila bacteria.

tine control method. Newer technologies for legionella testing, such as Q-PCR and immunoassay-lack sufficient correlation to the culture method and/or sensitivity to be accepted as a standard method at this time.

The most common control method is a culture of aerobic bacteria. However, many plants are using supplemental methods such as ATP or BART. All microbiological methods have limitations in the nonculturable species of bacteria and/or in the correlation to population of legionella bacteria. Plant personnel should carefully consider the role of validation and controls protocols in managing the risk of legionella in their cooling towers. HP 1 2

3

4

LITERATURE CITED Spain, United Kingdom, Holland, Singapore: Quarterly testing as a minimum.

Draft Standard: CTI STD-159: “Legionellosis Related Practices for Evaporative Cooling Water Systems,” Cooling Technology Institute.

Oesterholt, F., D. van der Linde, B. Wullings, and H. Veenendaal, “A new method of screening cooling water and process water for Legionella pneumophila,” KWR ©2008.

Fastpath—trademark of Nalco Co., www.nalco.com.

The author is president of MarTech Systems, Inc., an engineering consulting firm that provides technical services to optimize water-related utility systems in refineries and petrochemical plants. She holds a BS degree in chemical engineering and is a licensed professional engineer in New Jersey and Maryland.

She can be reached at: huchler@martechsystems.com.

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