hp_2009_12

DECEMBER 2009

HPIMPACT

SPECIALREPORT

TECHNOLOGY

European refiners facing a tough slog

PLANT DESIGN AND ENGINEERING

Oil price roller coaster continues

Novel approaches for project construction

Think power pumps are self priming?

Think again

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Select 52 51 at www.HydrocarbonProcessing.com/RS

DECEMBER 2009 • VOL. 88 NO. 12 www.HydrocarbonProcessing.com

SPECIAL REPORT: PLANT DESIGN AND ENGINEERING

27

What are the 10 secrets of successful leaders?

31

Maintain a competitive edge in the liquefied natural gas industry

Leadership is about relationships; consider applying these strategies to improve your organization D. M. Woodruff

Use this integrated approach to optimize construction and operation costs J. Colpo

39

Advanced hydrocracking technology upgrades extra heavy oil New hydrogen-addition process yields middle distillates while zeroing fuel oil and coke production from vacuum residue G. Rispoli, D. Sanfilippo and A. Amoroso

47

Executing a standard plant design using the 4X model

55

Case history: Benchmarks achieved in a residue upgrading project

Cover Today, the physical and virtual worlds of hydrocarbon processing facilities are coming together. Innovative technologies that mirror the as-built state of assets with intelligent, 3D virtual models are driving a new class of asset related solutions for plant personnel.

Illustration courtesy of INOVx.

Case study: A low-sulfur gasoline project on four identical process units J. T. O’Connor, V. P. Damiano, Jr., R. Kulkarni and P. Clark

This energy company aggressively implemented a mega-project safely and under budget with a new approach S. H. Kwon, B. H. Sohn, Y. M. Jeon, S. J. Kim, Y. W. Shin and Y. S. Ok

HPIMPACT 15 New regulatory pressures mean a tough slog for the EU’s refining industry 15 The roller coaster shows no signs of slowing down

PUMPS/RELIABILITY

61

Think power pumps are self-priming? Think again!

Follow these guidelines to avoid damage T. Henshaw

17 Successful strategies in the current market conditions 19 Small technologies can deliver big punches

PROCESS ANALYZERS

65

Fine tune accuracy in analytic measurement—Part 3 Follow these steps to avoid compromising a sample D. Nordstrom and T. Waters

PLANT SAFETY AND ENVIRONMENT

70

Requirement engineering and management— Part 2—performance standards development Use these guidelines to determine the safety-critical elements and tasks.

Free software modules are available at http://www.adepp.com/demo F.-F. Salimi

75

Ensuring site-wide consistency in relief system analyses Follow these protocols when evaluating common-cause failure scenarios for flares and headers R. Brendel

DEPARTMENTS 7 HPIN BRIEF • 15 HPIMPACT • 21 HPIN CONSTRUCTION • 25 HPI CONSTRUCTION BOXSCORE UPDATE • 79 HPI MARKETPLACE • 81 ADVERTISER INDEX

COLUMNS 9 HPIN RELIABILITY Understanding periodic pump switching and parallel operation 11 HPIN EUROPE Forecast for Europe: Bankers get richer as old refiners fade away 13 HPINTEGRATION STRATEGIES Laser scanning for HPI plant operations and maintenance 82 HPIN CONTROL More on APC designs for minimum maintenance

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www.HydrocarbonProcessing.com Houston Office: 2 Greenway Plaza, Suite 1020, Houston, Texas, 77046 USA Mailing Address: P. O. Box 2608, Houston, Texas 77252-2608, USA Phone: +1 (713) 529-4301, Fax: +1 (713) 520-4433 E-mail: editorial@HydrocarbonProcessing.com www.HydrocarbonProcessing.com Publisher Bill Wageneck bill.wageneck@gulfpub.com EDITORIAL Editor Les A. Kane Senior Process Editor Stephany Romanow Process Editor Tricia Crossey Reliability/Equipment Editor Heinz P. Bloch News Editor Billy Thinnes European Editor Tim Lloyd Wright Contributing Editor Loraine A. Huchler Contributing Editor William M. Goble Contributing Editor Y. Zak Friedman Contributing Editor ARC Advisory Group (various) MAGAZINE PRODUCTION Director—Editorial Production Sheryl Stone Manager—Editorial Production Chris Valdez Artist/Illustrator David Weeks Manager—Advertising Production Cheryl Willis ADVERTISING SALES See Sales Offices page 81.

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HPIN BRIEF BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

Süd-Chemie AG has an agreement with BASF SE for the acquisition of a production site for syngas catalysts in Nanjing, China. The site has approximately 400 employees and is independent from BASF‘s main production facility in Nanjing.

Süd-Chemie already produces catalysts in Panjin, China. The syngas catalysts produced in Nanjing are primarily used for the production of methanol, which is gaining importance in China as a transportation fuel. Syngas catalysts are also used in the production of hydrogen or in the conversion of coal, natural gas and biomass into liquid mineral oil products, such as diesel. Süd-Chemie AG is based in Munich, Germany, while BASF SE operates out of Ludwigshafen.

Fluor Corp. has renewed its global alliance agreement with Intergraph for the next five years. This agreement covers the various Intergraph software suites. Fluor uses Intergraph enterprise engineering solutions on a significant number of its contracts across multiple industry sectors, including oil and gas. Of particular note is Intergraph’s life cycle data management software that allows owner/operators to manage, maintain, refurbish or modify plants. The ARC Advisory Group ranked Intergraph the top overall engineering design 3D software and process engineering tools (PET) provider worldwide in its PET Worldwide Outlook Market Analysis and Forecast through 2013.

In recent remarks, the president of Sinopec said he expects the company's petroleum refining capacity to increase approximately 12 million to 15 million metric tpy in the next three years. Helping to supply this thirst for expanded refining output are two Saudi companies, Saudi Aramco and Saudi Basic Industries Corp.(SABIC). Sinopec plans to purchase over 1 million bpd of oil from Saudi Aramco in 2010, while SABIC will supply 210,000 bpd to Sinopec's refinery in Tianjin, China. In other Sinopec and SABIC news, the two companies’ 1 million metric tpy ethylene joint venture project recently commenced operations in Tianjin.

Shell Global Solutions US Inc. and Merichem Co. have formed an alliance to allow Shell Global Solutions to market and license Merichem’s technologies for treating hydrocarbon streams in combination with its own technologies to customers worldwide. The Merichem technologies are designed to remove mercaptans, carbonyl sulfide and other contaminants from hydrocarbon streams.

Iran and Turkey have an agreement to work together and promote several oil and gas projects. The details of the pact include the development of an oil refinery in northern Iran, the transport of gas from Iran to Europe via Turkey and an Iranian vow to allow Turkish interests to participate in Iran's future petrochemical efforts. The two countries have committed to a shared investment of $2 billion for the construction of the northern Iran refinery. They also intend to form a company to transfer up to 35 billion cubic meters of gas per year from Iran to Turkey. The gas feed will be used to meet demand in Turkey and in Europe.

A group looking to advance the cause of biorefining has parceled out a contract for the design of a biorefining technology center in North Lincolnshire, UK. The economic development group known as Yorkshire Forward is working with Grimley Smith Associates Consultant Process Engineers to create a location that will be able to process a wide range of bio-feedstocks through biorefining and extraction. The center plans to give companies and academic institutions an opportunity to test products and process technology for the conversion of feedstocks and waste streams into renewable transport fuels and energy. It also hopes to enable companies to build knowledge and understanding of the economies of scale and feedstock requirements for particular process units and technologies. HP

■ The lowdown on industrial drives The worldwide industrial drives market was estimated to be worth approximately $16.5 billion in 2008, with more than 20 million drive units shipped during the year. According to the latest statistics published by IMS Research, revenue growth was substantial in 2008, with market revenues increasing by 12.6% over 2007 levels. In contrast, the market is expected to decline by 10.4% in 2009 as a result of the global economic downturn. The total industrial drives market comprises seven product types – compact AC, standard AC, premium AC, DC, medium voltage, servo and stepper drives. Of these products, premium drives and medium voltage drives had the greatest growth in 2008, increasing by more than 20% over 2007 levels. This performance is linked to rapid growth of the major industry sectors that utilize these drives, including renewable energy and oil and gas.

This growth is also attributed to the shift in focus from low-end to high-performance products, specifically by ABB and Siemens. These premium product categories are also expected to outperform the total industrial drives market during the global recession. Conversely, the servio drives market is predicted to see contracted revenues of nearly 20% in 2009, while the stepper drives market should see an 8% decline.

The Europe, Middle East and Africa (EMEA) region continues to be the leading consumer of industrial drives. Total drive revenues for EMEA were approximately $7.2 billion in 2008, accounting for more than 43% of the worldwide market. The region represents the largest geographic market for all seven industrial drive types, but has a significantly greater proportion of sales into the higher-end product categories, accounting for more than 58% of 2008 global premium drive revenues. HP

HYDROCARBON PROCESSING DECEMBER 2009

I7

Where do You Want to be on the Performance Curve?

P = People M= Methodologies T = Technologies

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

Operating Challenges

U Effective Business Strategy/Decisions U Increased Return on Investments U Enhanced Returns on Acquisitions/Divestitures U Reduced Risk (Strategic, Capital, Other)

U Improved Organisational Effectiveness U Reduced Maintenance Costs U Improved Energy EfďŹ ciency U Behaviour-based Reliability/Performance U Improved Safety Performance U Operational Risk Management

Market Challenges U Enhanced Yields U Effective Responses to Crude/Feedstock and Product Markets U Improved Financial Performance U Market Risk Management

Environmental Challenges U Reduced Emissions U Enhanced Compliance

For 30 years, KBC consultants have provided independent advice and expertise to enable leading companies in the global energy business and other processing industries manage risk and achieve dramatic performance improvements.

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 Select 82 at www.HydrocarbonProcessing.com/RS

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

Understanding periodic pump switching and parallel operation Many process plants have “identical” centrifugal pumps installed in a given service. Most of these were probably intended as spare equipment. They would be started up in the event the primary pump had to be serviced or repaired. In best-practices plants, the two pumps are switched monthly. Switching is very important because it extends the bearing life of most pumps. For one, the lubricant is thus redistributed and corrosion damage is less likely.

Additionally, the extent of bearing damage due to vibration transmitted from an adjacent operating pump is cut in half. Operating each pump for about a month goes a long way to ensure that the rolling elements in the nonrunning pump do not remain in the same location for too long. More specifically, this reduces the severity and rate of a failure mode incident called ball indentation damage or “false brinelling.” (The occasional concern that both pumps will wear out at the same time is best refuted by considering twin children. By definition, they were born on the same day, but the probability of their dying of natural causes on the same day is rather remote.)

As plants increase their throughput capacity, they often run both pumps simultaneously. Likewise, when pumping requirements are known to vary greatly it may be desirable to use several small pumps and stop one or more pumps when the throughput demand drops. The remaining pumps then operate closer to their respective best-efficiency points (BEPs).In new installations, it is worth keeping in mind that, given a definite flowrate and head, several small pumps operating in parallel may allow purchasing and installing higher-speed pumps. When compared to the cost of lower speed pumps, higher-speed pumps often cost less.

Pump curves and their importance. Trouble-free parallel

operation is possible only if the head vs. flow curves (sometimes called H/Q curves) in Fig. 1 are relatively steep. A good rule-ofthumb would call for the head rise from operating point to shutoff of each pump to be 10% or more of the total head at BEP. New impellers are often available for existing pump casings and this upgrading may be easy to cost-justify.1 The characteristic curve of a system is often called a system curve. It actually represents the system head requirements as related to the flowrate. In Fig. 1, and with two pumps running in parallel, the system curve intersects the head vs. flow curve at about 120 ft and a flow of 470 gpm. Stopping one pump would instantly cause the one remaining operating pump to jump to the intersection of the system curve with the “single pump” head vs. flow curve. It would develop about 100 ft of head and a flow of 350 gpm.

Numerous references attest to the fact there is no such thing as two truly identical pumps.2 Each pump has its own H/Q performance curve because of its own unique internal roughness and wear or corrosion-affected clearances. There have been many instances of two pumps operating satisfactorily in parallel for

350

300

Two pumps in series

Total head, ft

250

200 Two pumps in parallel

150

Single pump 100 System curve 50

0 0

FIG. 1

100

400 200 300 Capacity, gal/min.

500

600

Centrifugal pump parallel and series operation.

years. Problems occur suddenly after one pump has been overhauled or a new impeller has been installed. A thorough analysis of alternative solutions is always appropriate. These may include system modifications and the use of a single, new and moreefficient pump instead of continuing to tolerate using two old, fundamentally weak pumps.

However, when operating two or more pumps in parallel, be certain that each operates at adequate flow to stay away from the forbidden low-flow regime. Also, always look at true life cycle cost. HP 1 2

LITERATURE CITED Bloch, Heinz P., and Alan Budris, Pump User’s Handbook, (2006) 2nd edition, Fairmont Publishing Company, Lilburn, Georgia, ISBN 0-88173-517-5.

Dufour, John W. and Ed Nelson, Centrifugal Pump Sourcebook, (1992) McGraw-Hill Publishing Company, New York, New York, ISBN 0-07018033-4.

The author is HP’s Reliability/Equipment editor. A practicing engineer and ASME Life Fellow with close to five decades of industrial experience, he advises process plants on maintenance cost-reduction and failure avoidance. His 17 texts on reliability improvement have been used for course presentations on all six continents and the 2nd edition of, Practical Lubrication for Industrial Facilities, was released in May 2009 (ISBN 0-88173-579-5).

HYDROCARBON PROCESSING DECEMBER 2009

I9

In troubled times fierce global competition for premium crudes means that refinery units must have the flexibility to handle heavy, viscous, dirty crudes that increasingly threaten to dominate markets. And flexibility must extend to products as well as crudes, for refinery product demand has become more and more subject to violent economic and political swings. Thus refiners must have the greatest flexibility in determining yields of naphtha, jet fuel, diesel and vacuum gas oil products.

Why Do Many Crude/Vacuum Units Perform Poorly?

Rather than a single point process model, the crude/vacuum unit design must provide continuous flexibility to operate reliably over long periods of time. Simply meeting the process guarantee 90 days after start-up is very different than having a unit still operating well after 5 years. Sadly few refiners actually achieve this—no matter all the slick presentations by engineers in business suits!

modeling. Refinery hands-on experience teaches that fouling, corrosion, asphaltene precipitation, crude variability, and crude thermal instability, and many other non-ideals are the reality.

Theoretical outputs of process or equipment models are not. In this era of slick colorful PowerPoint® presentations by well-spoken engineers in Saville Row suits, it’s no wonder that units don’t work. Shouldn’t engineers wearing Nomex® coveralls who have worked with operators and taken field measurements be accorded greater credibility?

In many cases it’s because the original design was based more on virtual than actual reality.

There is no question: computer simulations have a key role to play but it’s equally true that process design needs to be based on what works in the field and not on the ideals of the process simulator. Nor should the designer simply base the equipment selection on vendor-stated performance. The design engineer needs to have actual refinery process engineering experience, not just expertise in office-based

Today more than ever before this is important. Gone are the days when a refiner could rely on uninterrupted supplies of light, sweet, easy-to-process crudes.

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

Forecast for Europe: Bankers get richer as old refiners fade away It may have been the banking industry that paved the way into the present global downturn. But it is European refineries that will be shutting up shop, and there’s no government rescue waiting in the wings for them. How bad is it? For perhaps one in five of the refiners attending this year’s European Refining Technology Conference in Berlin, the quest for optimizing operations has been replaced on with the question of how we (the refining industry) will survive these turbulent times.

already very active, JP Morgan has signaled its intention to play the contango or carry market via floating storage. It’s staffing up in the US market, what’s already been a feature of the Northwest European market for more than a year.

Essentially underwritten by taxpayers, and with almost free credit from the central banks, bank oil traders are in a privileged position to take on exposure with the oil market. As prices of crude and heating oil rise, the cost to finance a contango position becomes more significant. If you can reduce risk and gain access to very cheap borrowing, then playing this oil market starts to look like easy money. But it’s less easy on the European refining industry.

Running on empty. Credit Suisse’s European refining margin at a few pennies over $4/bbl, not only suggests that refining’s golden age is a pre-credit crunch memory, but that many sites are running on empty. Their revenue streams are shallow, while Victims of this game. According to a veteran oil company traders are sitting on stocks of oil products at substantial levels. trader, “once you’ve established the contango, it takes a long time In October, the Oil Price Information Service estimated that to get out of it. Because the product overhang has a dampening approximately 60–75 million bbls (MMbbls) of diesel and jet fuel effect on prompt prices, it’s rather self-reinforcing.” Production were being stored onboard ships. must grind almost to a halt so that the available demand has a Earlier this year, it seemed audacious when traders started hiring chance to take on the huge stockpiles. newly constructed Very Large Crude Carriers (VLCCs) to store It’s a turn in the market that has hefty impliheating oil in European waters. But in October, cations. At a recent oil economics meeting, JBC Shell scrubbed out used supertankers for the same Energy told attendees that 2.8 MMbpd of refining purpose. Vitol, the trader with the biggest stake in ■ How about a capacity needs to close by 2020. In the run-up the oil storage game, reportedly fixed an Ultra Large of the most recent refining Golden Age (2004– Crude Carrier to store crude oil. A smaller VLCC trillion € for the 2007), the analysts often spoke about a geopolitihas a capacity of nearly 2 MMbbl. Vitol’s fixture cal fear premium in oil. Something dangerous was may be for storing crude oil. Why? We don’t know. european refining about to happen, which the market was forced However, there’s a huge amount of oil and refined industry? to price to spot prices. Now, they say, it’s a hope products in storage. premium. Recovery is around the corner and that’s where the premium should be. But as the world Where’s the profit? Storing crude and refined moves beyond OECD peak demand in 2005, the problem is products can be a profitable game for the traders, who’ve made a that Europe’s “hope” could well turn out to be more a matter of high-stakes game out of a market that’s more or less stuck in conEastern promise. tango. In other words, forward prices will be higher than today’s “When the rebound comes in demand growth,” says David spot market prices.

Martin of the International Energy Agency, “it will be in China, Traders buy at spot prices distressed by high inventory levels India and the Middle East where they are all building new capacand then sell on the forward curve. With storage costs in some ity. So the drop in Europe is unlikely to be temporary.” What is contracted supertankers hovering around $4.50/ton per month, the advice for refiners? “Margins are going to be bleak. Just try some tidy profits have been realized for companies using the and sit it out.” HP futures market to lock in forward sales at prices up to $14/ton per month higher than spot prices.

It’s not only independent traders that are involved. Some oil companies have separate ventures spun off the main corporation to create specific “contango companies.” These business groups can take on large exposure to the volatile crude market without compromising the entire corporation.

The author is HP’s European Editor. He has been active as a reporter and confer-

Greed in many forms. And let’s not forget about the bankers.

Banks are staffing up to profit from the carry market that is decimating refining margins. With companies like Morgan Stanley

ence 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 DECEMBER 2009

I 11

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HPINTEGRATION STRATEGIES RALPH RIO, CONTRIBUTING EDITOR rrio@arcweb.com

Laser scanning for HPI plant operations and maintenance Is your plant’s CAD model current? Do you even have an electronic model? “As-built” models provide the information required for both plant upgrades and maintenance management. To create these models, you start with 3D laser scanning (3DLS) of the existing plant (Fig. 1). The models can help reduce costs for plant upgrades, maintenance engineers use the software for designing upgrades and operating personnel use it for managing maintenance.

Documenting the “as-built” plant. Often, plant owner/

operators do not have up-to-date CAD design files for their facilities. This occurs for a variety of reasons including: • An old plant with hard-copy drawings prior to modern CAD • Dysfunctional documentation hand-off from the EPC, with the needs of the EPC being different than the owner/operator • Current as-built varies from as-designed because CAD files were not updated over time with construction modifications, upgrades and refurbishments • Some items are field-run and not depicted in the design.

A 3D laser scan provides a point cloud that is a set of X, Y and Z points that digitally represent the surfaces within an existing facility.

This resulting point cloud is an effective source of measurement data for creating the needed documentation of the as-built conditions.

D&B of plant upgrades or refurbishments. Applying point cloud data from laser scanning can solve a couple of design and build (D&B)-specific issues. For example, the design of an upgrade must fit into the existing structure. Interference with remaining equipment and structural elements must be anticipated and avoided. Also, tie-ins must match between the old and the new, and the clearances and construction sequences must allow

FIG. 1

3D model with spatial information derived from a point cloud. Source: INOVx Solutions Inc.

for the old to be removed and the new to be installed. Also, to minimize the financial impact of an upgrade-related shutdown, expensive and time-consuming on-site construction can be reduced by prefabricating as much material as practical. Accurate dimensional data ensures that the parts will fit together.

The 3DLS methodology is critical for obtaining engineering-level precision. To obtain points on all the surfaces around the equipment, the laser scanner is relocated for multiple scans. The multiple-point clouds are combined for the full 3D rendering. Here, it’s imperative to accurately register the point clouds relative to each other.

Ultimately, these laser scan points should be tied to surveyed known plant coordinate reference points. As-built plant documentation requires shared registration points (targets placed within the field-ofview of the scanner). When hiring a contractor to perform the laser scanning, carefully review its methods to assure the resulting point clouds will have the required dimensional accuracy.

Plant operations and maintenance. The requirements for operating and maintaining (O&M) a plant are much different than for D&B. Here, laser scanning can be used to create an intelligent, object-based model. The resulting geospatial information can be applied to O&M to support asset information management, inspection rounds, maintenance activities and incident response.

HPI plants are complex, which often makes it difficult to find the needed information. Look-up is usually in a hard-copy file or a software application with obtuse reference identifiers. The library numbering system (including tag names) probably made sense when the plant was built, but can become difficult to understand for operations. An intuitive approach is to mimic the way humans see the world. A 3D model provides a visual reference for navigating to the asset of interest. Software objects with parameters make asset information easily accessible by operating personnel.

The typical flat 2D piping and instrumentation diagram (P&ID) does not provide the spatial information and distances among the items needing inspection. A 3D model derived from a point cloud can provide the needed geospatial information for optimizing inspections rounds for both distance and combining multiple rounds.

Geospatial data, combined with the asset information management, are used to support a query with various parameters.

A query allows the dispatcher to combine work orders when a technician goes to a particular area. For example, work orders for similar equipment in the same area can be combined into one maintenance activity, allowing for improved productivity. HP The author has been with ARC since 2000. Prior to joining ARC, he was with GE Fanuc Automation as its manager of marketing for its CIMPLICITY software and services. Prior to that, Mr. Rio was Intellution’s marketing manager for all HMI software products. Mr. Rio holds a BS degree in mechanical engineering and an MS degree in management science from Rensselaer Polytechnic Institute, Troy, New York.

HYDROCARBON PROCESSING DECEMBER 2009

I 13

PROCESS INSIGHT Selecting the Best Solvent for Gas Treating Selecting the best amine/solvent for gas treating is not a trivial task. There are a number of amines available to remove contaminants such as CO2, H2S and organic sulfur compounds from sour gas streams. The most commonly used amines are methanolamine (MEA), diethanolamine (DEA), and methyldiethanolamine (MDEA). Other amines include diglycolamine® (DGA), diisopropanolamine (DIPA), and triethanolamine (TEA). Mixtures of amines can also be used to customize or optimize the acid gas recovery. Temperature, pressure, sour gas composition, and purity requirements for the treated gas must all be considered when choosing the most appropriate amine for a given application.

Tertiary Amines A tertiary amine such as MDEA is often used to selectively remove H2S, especially for cases with a high CO2 to H2S ratio in the sour gas. One benefit of selective absorption of H2S is a Claus feed rich in H2S. MDEA can remove H2S to 4 ppm while maintaining 2% or less CO2 in the treated gas using relatively less energy for regeneration than that for DEA. Higher weight percent amine and less CO2 absorbed results in lower circulation rates as well. Typical solution strengths are 40-50 weight % with a maximum rich loading of 0.55 mole/mole. Because MDEA is not prone to degradation, corrosion is low and a reclaimer is unnecessary. Operating pressure can range from atmospheric, typical of tail gas treating units, to over 1,000 psia.

Mixed Solvents In certain situations, the solvent can be “customized” to optimize the sweetening process. For example, adding a primary or secondary amine to MDEA can increase the rate of CO2 absorption without compromising the advantages of MDEA. Another less obvious application is adding MDEA to an existing DEA unit to increase the effective weight % amine to absorb more acid gas without increasing circulation rate or reboiler duty. Many plants utilize a mixture of amine with physical solvents. SULFINOL® is a licensed product from Shell Oil Products that combines an amine with a physical solvent. Advantages of this solvent are increased mercaptan pickup, lower regeneration energy, and selectivity to H2S.

Primary Amines The primary amine MEA removes both CO2 and H2S from sour gas and is effective at low pressure. Depending on the conditions, MEA can remove H2S to less than 4 ppmv while removing CO2 to less than 100 ppmv. MEA systems generally require a reclaimer to remove degraded products from circulation. Typical solution strength ranges from 10 to 20 weight % with a maximum rich loading of 0.35 mole acid gas/mole MEA. DGA® is another primary amine that removes CO2, H2S, COS, and mercaptans. Typical solution strengths are 50-60 weight %, which result in lower circulation rates and less energy required for stripping as compared with MEA. DGA also requires reclaiming to remove the degradation products.

Secondary Amines The secondary amine DEA removes both CO2 and H2S but generally requires higher pressure than MEA to meet overhead specifications. Because DEA is a weaker amine than MEA, it requires less energy for stripping. Typical solution strength ranges from 25 to 35 weight % with a maximum rich loading of 0.35 mole/mole. DIPA is a secondary amine that exhibits some selectivity for H2S although it is not as pronounced as for tertiary amines. DIPA also removes COS. Solutions are low in corrosion and require relatively low energy for regeneration.

The most common applications for DIPA are in the ADIP® and SULFINOL® processes.

BR&E

Choosing the Best Alternative Given the wide variety of gas treating options, a process simulator that can accurately predict sweetening results is a necessity when attempting to determine the best option.

ProMax® has been proven to accurately predict results for numerous process schemes. Additionally, ProMax can utilize a scenario tool to perform feasibility studies. The scenario tool may be used to systematically vary selected parameters in an effort to determine the optimum operating conditions and the appropriate solvent. These studies can determine rich loading, reboiler duty, acid gas content of the sweet gas, amine losses, required circulation rate, type of amine or physical solvent, weight percent of amine, and other parameters. ProMax can model virtually any flow process or configuration including multiple columns, liquid hydrocarbon treating, and split flow processes. In addition, ProMax can accurately model caustic treating applications as well as physical solvent sweetening with solvents such as Coastal AGR®, methanol, and NMP. For more information about ProMax and its ability to determine the appropriate solvent for a given set of conditions, contact Bryan Research & Engineering.

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

HPIMPACT BILLY THINNES, NEWS EDITOR

BT@HydrocarbonProcessing.com

Berlin was the spot for a sober gathering of HPI professionals who used the ERTC annual meeting as a platform to discuss current economic and regulatory problems facing the industry. The mid-November gathering of the European refining industry focused on facts, statistics and new technologies, using such data and ideas to assess problems and seek out solutions. Sifting through all the chatter and the numbers, Hydrocarbon Processing is pleased to provide you with some of the highlights of the conference.

New regulatory pressures mean a tough slog for the EU’s refining industry The EU refining industry faces a tough slog as market conditions, new regulatory fervor and biofuels all conspire against hydrocarbon processors in Europe. Martin Suenson, an executive officer for EUROPIA, came to the ERTC to discuss how all of these issues are related.

General message. Mr. Suenson said

that the European refining industry is a key sector in the EU framework, but is facing major challenges. These include supply/ demand imbalances, flat demand, expected low margins and competition from other regions. Plus, environmental legislation could increase these challenges and some of the regulation is unique to the EU, so it

is not a balanced challenge when compared to the rest of the world.

“Europe faces a major supply/demand imbalance, as it is importing 27 million tons of middle distillates from Russia and exporting 31 million tons of gas to the US,” Mr. Suenson said. “Let us not forget that refining is a vital part of the supply chain to meet EU consumer needs.”

Demand is down. Europe has been

most impacted by falling demand in 2009 and 2010. Even by 2015, demand growth is not expected to catch up with capacity additions. Mr. Suenson sees 2010 as the bottom of the demand drop and projects that things will not catch up until 2015.

In short, refinery utilization rates are down and are not forecast to recover quickly. Mr. Suenson said Wood Mackenzie predicts margins to be around break even, with utilization rates below 2007 levels and any capacity rationalization will be insufficient to balance a growing gas surplus.

Offering a summary of the market situation, Mr. Suenson said there is a product slate mismatch and falling demand, utilization rate and margins. He also noted that biofuels will depress oil product demand further, with all of these factors putting increased pressure on profitability.

Regulatory questions. The acronym-

laden alphabet soup that European refiners are facing include: Corporate Average Fuel

Alois Virag, OMV, Martin Suenson, EUROPIA, and Charles Cameron, BP, prepare to address delegates at the ERTC annual meeting in Berlin.

Economy (CAFE), National Emission Ceilings (NEC), the Intergovernmental Panel on Climate Change (IPCC), Pollutant Release and Transfer Registers (PRTRs), the Large Combustion Plants (LCP) Directive and the Fuels Quality Directive (FCD).

“The world in which we are living, from a regulatory viewpoint, is very, very complex,” Mr. Suenson said.

The EU Emissions Trading System (ETS) Phase 3 will start in 2013 and have an impact on EU refining. The refining industry has been assessed as an Energy Intensive Industry (EII) and labeled as being “exposed to significant risk of carbon leakage.”

“The EU ETS will create a competitive challenge to EU refineries without similar constraints elsewhere in the world,” Mr. Suenson said.

He concluded his remarks by saying that for the refining industry to achieve the EU’s environmental ambitions and still remain competitive, what is required is environmental policies that: give a longer-term predictable legislative framework, are cost effective, and recognize and mitigate the competitive impact of unilateral legislation.

The roller coaster shows no signs of slowing down Oil prices have been on a roller coaster since West Texas Intermediate hit a peak of $147 in the summer of 2008 and then plunged to as low as $37 earlier this year.

During the afternoon technical sessions, attendees were rapt with attention.

HYDROCARBON PROCESSING DECEMBER 2009

I 15

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HPIMPACT

Andrea Amoroso, ENI, Olivier Raevel, Koch Supply & Trading, Roberto Ulivieri, Purvin & Gertz, and Koenraad Herrebout, Total, respond to audience questions during a panel discussion.

Hans Keuken, HE Blends BV, and Anders Roj, Volvo, were featured panelists during the ERTC annual meeting.

While oil prices have recovered since that dramatic drop, refiners still find themselves in a market of enormous volatility. Trevor Morgan of the International Energy Agency (IEA) took this landscape and drilled beneath it to find meaning and offer advice as the HPI looks into the future. His remarks were an outgrowth of the statistics and information contained within the recently released IEA World Energy Outlook.

There is a strong correlation between oil markets and financial markets in recent months, Mr. Morgan said. To emphasize his point, he displayed a slide showing the price of WTI and the valuation of the S&P 500 in the US virtually mirroring each other from January 2008 to July 2009.

Mr. Morgan also sees a strong correlation between the US dollar and oil prices over the same time period.

Global demand has taken a big hit, Mr. Morgan said, with global oil product demand now projected to average 84.6 million bpd in 2009, down from 86.3 million bpd in 2008. While OPEC is taking the brunt of this weak demand, it is showing

Trevor Morgan, an economist with IEA, confers with Simo Honkanen of Neste Oil before presenting his keynote address.

some signs of turning around. In September, OPEC’s output rose 120,000 bpd to a total of 28.93 million bpd.

The single most important determinant for the near-term market outlook is the shape and pace of economic recovery, Mr. Morgan said. At the moment, the IMF is expecting a fairly rapid return to reasonably strong growth. If this is so, the question must be considered: Has oil demand been forever destroyed or is this merely a temporary suppression?

Demand outlook to 2014. After a

heavy fall in demand in 2009, the IEA expects steady recovery until 2014, with the increase coming from non-OECD countries (30% from China alone), mainly in the transport sector. Mr. Morgan sees a 1.5% to 1.6% increase in demand over that period. However, if economic recovery is weaker than projected, demand could easily be 4.1 million bpd lower in 2014 versus the IEA’s optimistic view.

capacity in place will decline as a result of the decline in existing fields. The result is that fields that are already past production peaks will see an average rate of decline rising from 6.7% in 2007 to 8.6% in 2030.

This is because production is expected to shift to smaller fields that have heightened decline rates.

Peak oil. So is peak oil in sight? Oil will, of course, eventually run out since it is a finite resource, but not just yet, Mr. Morgan said. His research indicates proven reserves are equal to roughly 40 years of production at current rates. However, it is worth noting that half of the worlds’ ultimately recoverable conventional resources will have been depleted by 2030. Mr. Morgan also said that demand-side factors are just as important to the timing of peak oil; pricing will ultimately balance supply and demand. The cost of the marginal barrel is set to rise as E&P moves to frontier provinces, and under this scenario he can see oil prices rising to $115.

Oil refining. Mr. Morgan said that 7.6

million bpd of distillation capacity is still expected to be added in 2009–2014, with approximately 6.5 million bpd in upgrading capacity. As far as refining capacity utilization, he said that “something’s got to give.”

An overhang of spare capacity and weaker utilization means that commercially sensitive operators in the US, Europe and Japan could bear the brunt of the run cuts.

Long-term outlook for oil demand.

Projecting out to 2030, Mr. Morgan sees most of the demand growth coming from developing Asia and the Middle East, with demand falling in OECD countries.

However, as far as supply goes, a lot of the

Successful strategies in the current market conditions The global recession was abrupt and has hit very deep. By the end of 2009, the world will have seen two consecutive years of oil demand decline, the first time it has happened since the 1980s. Within this context, Roberto Ulivieri of Purvin & Gertz shared his perspective on how refiners can weather the storm and still maintain profitability.

OPEC has cut production by over 3 million bpd to shore up prices, Mr. Ulivieri said, and OPEC production cuts tend to remove heavy crude from the market.

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HPIMPACT These cuts played a key role in narrowing along with human resources, gain imporlight-heavy differentials. According to Mr. tance in this market, he said.

Ulivieri, OPEC will have to keep some production shut until demand recovers.

Small technologies can There is a very clear difference between this recession and the recession of the 1980s, deliver big punches he said. In the 1980s, refiners lost demand, Charles Cameron, the head of research but it was mainly demand for heavy prod- and technology in refining and marketing ucts. This recession is a loss of demand for for BP in London, is a firm believer in small light products, an important difference. technologies that can deliver big punches.

Mr. Ulivieri said he is used to low growth “I am here today as the lead cheerleader in Europe, but not in North America. This to help us get out of this latest down cycle,” recession has quenched demand growth in Mr. Cameron said to a roomful of delegates North America and, as a consequence, he at the ERTC. “BP believes we need technolpredicts a continued fall in demand through ogy more than ever—we are in a commod2015. Even more concerning, he said that ity industry, but to make that commodity the decline of gas demand could accelerate there is an awful lot of technology needed. after 2015, with diesel demand for passen- The industry must continue to invest, but ger cars stagnating or slightly declining and invest wisely, in technology.” no growth in the transport sector.

Mr. Cameron moved on to discuss some What this means for European refin- bleak numbers from BP’s 2009 3rd quarter. eries is that business models will have to He displayed a slide that showed refining change. Historically, the US has been the margins trending significantly downward preferred market for excess production, but over a one-year period, with margins slidthe development of ethanol and the peak in ing from $7/bbl in the 3rd quarter of 2008 overall demand will reduce opportunities to to below $4/bbl in the 3rd quarter 2009. export gasoline to the US. Mr. Ulivieri said “What is evident is that some of the US that he is certain that the peak of gasoline and European operations are operating at demand has already happened within the low margins. The margin conditions are last two years. excessively poor in the US and inventories Four factors are keeping light-heavy dif- are very high and won’t go down for the ferentials and conversion margins down: next few weeks,” Mr. Cameron said. “It will reduced supply of heavy crude; lower take one or two quarters more before things demand, primarily for light products; at begin to significantly improve.” lower levels of utilization the marginal Mr. Cameron spoke about BP’s capital capacity is more complex; and a high level of expenditures (CAPEX), noting that the project completion in the next few years. company’s uptick in spending is due to the Mr. Ulivieri said the speed of margin Whiting, Indiana, refinery upgrade project. recovery is likely to be related to overall This bump in CAPEX spending will be suseconomic recovery. Margins will eventu- tained until the revitalized Whiting comes ally come back up, and projected refinery online in 2012. Whiting, one of oldest utilization rates are currently at levels that refineries in the world, was built in 1890. are bound to spark some rationalization. He predicts there will be some closures in Europe to restore acceptable operating rates and margins.

In a summary of his remarks, Mr. Ulivieri said that refining has swung to a “back to the basics” business environment.

Plant operators are going to have to reassess the question of what makes a refinery competitive. In the current situation, a profitable refinery selects its crudes wisely while embracing optimization, efficiency and cost controls.

Strong performance at all levels DV Clean Technologies hosted a hospitality suite. and wise investment strategies,

Martin Turk, Invensys, discussed virtual reality plant simulation during a technical session.

It made sense to upgrade this aging refinery, Mr. Cameron said, because it harbors a location advantage, with more extra-heavy crude flows coming from Canada and heading to the Gulf. BP is repositioning Whiting to process advantaged feedstocks at scale and intends to capture the appropriate light/heavy spread. Once online, the refinery should run over 340,000 bpd of extra-heavy crude.

Within the OECD countries, Mr. Cameron sees flat or falling demand for core refined products, compared to strong growth in Asia (he based his assessment on IEA numbers). There could be some local needs for diesel until 2020, in Europe in particular, but beyond 2020 it will fall off, he said.

BP is currently a strong advocate for low-capital projects with high technology content. Deploying wireless instrumentation and control loop monitoring requires a small initial investment and then these technologies should pay for themselves many times over as the years progress.

Using such technology is key for predicting when equipment needs to be changed out. Since 2006, BP has been working on predictive analytics, using wireless monitoring. The company has implemented just under 1,000 wireless instruments across nine refineries. Mr. Cameron projects that there is a savings value of $3,000 to $6,500 per instrument deployed.

BP is also using predictive analytics to detect deviations from normal equipment behavior, probing differences in temperature and vibrations, so that problems can be caught before equipment gets damaged. HP HYDROCARBON PROCESSING DECEMBER 2009

I 19

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HPIN CONSTRUCTION BILLY THINNES, NEWS EDITOR BT@HydrocarbonProcessing.com

North America CB&I has a contract in excess of US$100 million with UGI LNG, Inc. to engineer, procure and construct the expansion of the Temple liquefied natural gas (LNG) peak shaving facility near Reading, Pennsylvania. CB&I’s work scope includes the addition of a new 50,000 cubic meter LNG storage tank and related processing facilities designed to provide 150 million scfd of natural gas during peak demand periods. The Temple LNG expansion will connect directly into the Texas Eastern pipeline to provide gas supplies for the Mid-Atlantic and Northeast markets.

Air Products was awarded a long-term supply contract with Monsanto Co. to build a new world-scale hydrogen production plant to be located at Monsanto’s Luling, Louisiana, facility. The new hydrogen plant is scheduled to be onstream in January 2012. Air Products will build a steam methane reformer (SMR) producing over 100 million scfd of hydrogen.

The SMR will be connected to Air Products’ East Gulf Coast pipeline network, which supplies refineries with hydrogen needed to make cleaner-burning transportation fuels, in addition to meeting the hydrogen needs of the local petrochemical industry. This facility will produce additional hydrogen via clean-up of a hydrogen-rich offgas feed from Monsanto. Also, Monsanto will use steam from Air Products’ SMR process to benefit its production plant.

Air Products’ hydrogen facility in Luling will be built through the global alliance between Air Products and Technip. Technip provides the design and construction expertise for SMR while Air Products provides gas separation technology.

Port Dolphin was recently awarded a license to construct a deepwater port 28 miles off Tampa Bay, Florida. The port will allow specially designed liquefied natural gas (LNG) vessels to deliver natural gas through an undersea pipeline to connect with the state’s pipeline system four miles inland. The LNG will be regasified onboard the vessels and fed into the pipeline to serve customers across Florida.

Port Dolphin’s deepwater port will have peak send-out capacity of up to 1.2 Bcfd—

enough to power more than one million homes. When fully operational, Port Dolphin will supply enough natural gas to meet 15% of Florida’s needs. Construction is set to begin in 2012 with completion in 2013.

Jacobs Engineering Group Inc. has been awarded a contract by Suncor Energy to provide planning, pre-work, procurement and field services for execution of a portion of the 2010 turnaround at Suncor’s Upgrader 2 unit located 30 km north of Fort McMurray, Alberta, Canada. The work will be developed in two phases. The planning and preparation phase is presently underway and will be followed by the execution phase. The outage is scheduled to begin in the second quarter of 2010.

INEOS Bio recently announced another step in the commercialization of its thirdgeneration bioethanol technology process to serve the global renewable transport fuels market and the renewable energy market. The company has selected KBR as its engineering contractor to develop the TREND ANALYSIS FORECASTING Hydrocarbon Processing maintains an extensive database of historical HPI project information. Current project activity is published three times a year in the HPI Construction Boxscore. When a project is completed, it is removed from current listings and retained in a database. The database is a 35-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc.

Many companies use the historical data for trending or sales forecasting.

The historical information is available in comma-delimited or Excel® and can be custom sorted to suit your needs. The cost of the sort depends on the size and complexity of the sort you request and whether a customized program must be written. You can focus on a narrow request such as the history of a particular type of project or you can obtain the entire 35-year Boxscore database, or portions thereof.

Simply send a clear description of the data you need and you will receive a prompt cost quotation. Contact: Lee Nichols P. O. Box 2608 Houston, Texas, 77252-2608 Fax: 713-525-4626 e-mail: Lee.Nichols@gulfpub.com.

front-end engineering and design (FEED) for the first of its bio-energy plants that is to be completed by the end of 2011. This plant is scheduled to be located in Illinois.

Work on the commercial design began in the third quarter of 2008 and is already well advanced. The FEED work is scheduled to be completed in the first quarter of 2010, with first commercial production expected by the end of 2011.

Air Products plans to build a new world-scale air separation unit (ASU) at its La Porte, Texas, industrial gases facility. The energy-efficient ASU will replace older assets at the site and provide benefits to customers through higher-reliability pipeline oxygen and nitrogen supplies, and enhanced production of merchant and electronics products including argon and xenon. The new ASU is scheduled to be onstream in October 2011.

South America Petroperú (Petroleos del Perú) and Axens have signed a contract for the modernization of Talara, Petroperú’s largest refinery in Peru. The main objectives are expansion of the refinery and implementation of new process units for higher-quality products. Axens will supply several major process technologies for the refinery: a 13,300-bpd naphtha hydrotreater; a 9,500-bpd semiregenerative reformer; a 9,500-bpd PrimeG+ FCC gasoline desulfurization unit; and a 8,000 bpd Sulfrex unit to treat unsaturated liquefied petroleum gas.

Europe Gazprom and Srbijagas have agreed to set up joint ventures for the South Stream and Banatski Dvor UGS facility in northern Serbia.The agreement defines procedures, terms and conditions of incorporation, as well as the operating mechanisms for the joint venture to be responsible for the construction and operation of an underground storage area with an active capacity of 450 million cubic meters.

GAZPROM Komplektatsiya LLC has launched an investment program to increase the octane number of existing gasoline production and also the profitability HYDROCARBON PROCESSING DECEMBER 2009

I 21

HPIN CONSTRUCTION of its refinery located in Astrakhan, Russia, on the coast of the Caspian Sea. The refinery was first put in service in 1985.

The contract was signed with MAVEG Industrieausrüstungen GmbH. Lurgi GmbH and MAVEG were selected to supply engineering and procurement services for this project and will handle a naphtha hydrotreater and a C5/C6 isomerization unit to be integrated within the refinery.

Startup is scheduled for 2012.

INEOS Bio has started a feasibility study for a facility to convert locally generated biodegradable household and commercial wastes into carbon-neutral transport fuels and clean electricity, using the INEOS Bio technology process. The £3.5 million feasibility study includes detailed engineering for a plant at the company’s Seal Sands site in the Tees Valley, UK. It is being supported by a £2.2 million grant from the Regional Development Agency One Northeast

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and the UK’s Department for Energy and Climate Change. When completed, the feasibility study will inform an investment decision in 2010 for a commercial INEOS Bio bio-ethanol and bio-energy plant.

The Shaw Group Inc. has a contract with Petkim Petrochemical Holding AS to provide engineering and procurement services and additional study work for an ethylene capacity expansion in Aliaga, Turkey. Shaw built the original 300,000tpy plant in 1986 and did basic engineering for the previous capacity revamp to 520,000 tpy in 1999. The new expansion will increase ethylene production capacity by approximately 10%.

Agri-food Chemicals and Petroleum Environment Facilities and Operations Maintenance Industrial and Manufacturing Infrastructure Mining and Metallurgy Pharmaceuticals Power Telecommunications

Middle East Al-Waha Petrochemical Co. has successfully started up its new complex in AlJubail Industrial City, Saudi Arabia. The complex includes a 450,000-tpy polypropylene plant based on LyondellBasell’s process technology. Al-Waha was formed in 2006 and is a joint venture between Sahara Petrochemicals Co. and LyondellBasell.

Qatar Petroleum recently launched the testing phase of the Pearl gas-to-liquids (GTL) project by inaugurating the massive plant’s central control room. Shell is assisting Qatar Petroleum with this project.

While testing begins on the many thousands of pieces of equipment that have already been installed in the plant, construction continues and is expected to be complete by the end of 2010. Production ramp-up will then take around 12 months.

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Latin America

Europe

Africa

Eurasia

Asia

Middle East

Select 153 at www.HydrocarbonProcessing.com/RS 22

Oceania

Alfa Laval has received an order from PetroVietnam Group. The order value is about SEK 100 million and includes equipment and engineering solutions for an ethanol production plant in central Vietnam.

Delivery is scheduled for 2010. Alfa Laval’s heat exchangers, decanters and tank-cleaning equipment will be used in the starchbased fermentation, distillation and dehydration processes of the ethanol plant. The facility will produce about 330,000 lpd of fuel ethanol from cassava chips.

Air Products has an agreement with Technip to supply process technology and equipment for two liquefaction trains, each producing 400,000 tpy of LNG for Ningxia Hanas Natural Gas Co., Ltd., in Yinchuan, China.The units are targeted to be completed in the second half of 2011. HP

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HPI CONSTRUCTION BOXSCORE UPDATE Company

Plant Site

Project

Capacity Est. Cost Status Licensor

Engineering

Constructor

UNITED STATES Pennsylvania Texas Texas

UGI LNG Eastman Chemical Air Products

Reading Beaumont La Porte

LNG Storage Coal Gasification Air Separation Unit

50 Mm3 None None

PetroquimicaSuape Pemex Pemex Pemex Pemex Pemex Pemex Pemex Pemex Stingray Copper Petroleos del Peru Petroleos del Peru Petroleos del Peru Petroleos del Peru PDVSA

Ipojuca Hector Sosa Refinery Hector Sosa Refinery Hector Sosa Refinery Hector Sosa Refinery Madero Refinery Madero Refinery Madero Refinery Madero Refinery Sonora Talara Talara Talara Talara San Juan de los Morros

Polyester Polycondensation None Amine Regeneration Unit None Desulfurization, Catalytic Gasoline (2) 42.5 Mbpd Flare System None Utilities None Amine Regeneration Unit None Desulfurization, Catalytic Gasoline (2) 20 Mbpd Flare System None Utilities None Sulfuric Acid 750 MMtpy FCC Gasoline Desulfurization 9.5 Mbpd Hydrotreater, Naphtha 13.3 Mbpd LPG Sweetening 8 Mbpd Reformer, Cont Regen 9.5 Mbpd Lube Re-Refiner 40 Mtpy

TAQA Energy BV Esso Nederland BV Galp Energia TAIF NK Ukrtatnafta JSC Ukrtatnafta JSC INEOS Bio

Haarlem Rotterdam Sines TAIF-NK Refinery Kremenchug Kremenchug Seal Sands

Storage, Gas Hydrogen Sulfur Recovery Unit Complex Hydrotreater, Diesel Hydrotreater, Diesel (2) Bio-ethanol

PetroChina Dushanzi Petrochem PetroChina Dushanzi Petrochem Air Products Petronas Methanol Petronas Methanol

Dushanzi Dushanzi Nanjing Labuan Labuan

Distillation, Crude Ethylene Amine Air Separation Unit Methanol

SAMIR SAMIR SAMIR

Mohammedia Mohammedia Mohammedia

Bitumen Storage, Tank (1) Storage, Tank (2)

100 1.5

E 2010 E 2013 P 2011

CB&I Air Products

LATIN AMERICA Brazil Mexico Mexico Mexico Mexico Mexico Mexico Mexico Mexico Mexico Peru Peru Peru Peru Venezuela

638 638 638 638 638 638 638 638

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

2011 2012 2012 2012 2012 2012 2012 2012 2012 2011 2013 2013 2013 2013 2011

Lurgi Zimmer ICA Fluor CDTECH

E P E F E E S

2013 2011 2011 2014 2010 2010 2010

C C C C C

2009 2009 Linde 2009 Air Products 2009 2009 Lurgi

CDTECH Aker Chemetics Axens Axens Axens Axens Axens|Viscolube

ICA Fluor ICA Fluor ICA Fluor ICA Fluor ICA Fluor ICA Fluor ICA Fluor ICA Fluor Aker Chemetics

EUROPE Netherlands Netherlands Portugal Russian Federation Ukraine Ukraine United Kingdom

None None 170 tpd TO 9.1 MMtpy RE None RE None None

2200

5.2

Air Products Siirtec Nigi Lurgi Criterion|Shell Global Criterion|Shell Global

Fluor Air Products Siirtec Nigi

ASIA/PACIFIC China China China Malaysia Malaysia

10 Mtpy 1 MMtpy None None 5 Mtpd

AMEC|HQCEC|Linde

PetroChina Dushanzi

Air Liquide|Lurgi Air Liquide

AFRICA Morocco Morocco Morocco

270 Mtpy 5.5 Mm3 5.5 Mm3

P 2011 Porner P 2011 Porner P 2011 Porner

Porner Porner Porner

See http://www.HydrocarbonProcessing.com/bxsymbols for licensor, engineering and construction companies’ abbreviations, along with the complete update of the HPI Construction Boxscore.

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25

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PLANT DESIGN AND ENGINEERING

SPECIALREPORT

What are the 10 secrets of successful leaders?

Leadership is about relationships; consider applying these strategies to improve your organization D. M. WOODRUFF, Management Methods, Inc., Decatur, Alabama

L

eadership is about people, while management is more about processes and tasks. According to President (and General) Dwight Eisenhower, leadership is “getting other people to do what you want done because they want to do it.” Ultimately, leadership is about building relationships with people. These 10 secrets will help you be more effective in dealing with people and building these all important relationships.

A person in a management role in the hydrocarbon processing industry (HPI) is also in a leadership role because people are involved. Many times, engineers, maintenance or other technical people are in leadership roles by virtue of being in a project management role or they act as liaisons with contractors even though they may not be in an officially recognized management position within their company.

Supervisors and managers Peers

Policies, rules and laws

You

Employees Customers

Relationships

Suppliers

Finances

FIG. 1

Honesty and integrity

A leadership model for the present workplace.

Best attributes of a leader. The critical foundations of

leadership are honesty and integrity. In a survey that our firm conducted of over 500 leaders and managers in the workplace, we found honesty to be the No. 1 characteristic. Effective leaders know the importance of trust and building relationships. Work gets done because of relationships more than because of position.

As leaders, we are bound by certain external factors that include policies, rules, laws and finances, but the emphasis of leadership must be on building relationships based on honesty and integrity.

With the foundations of honesty and integrity, successful leaders know and apply the 10 secrets that help them get the work of the organization done by people who want to get the work done right and on time. These 10 leadership secrets will help you work more effectively with those above you, on your level and under your supervision in the organization, as well as with customers and suppliers, as shown in Fig. 1. It really is all about relationships. So, here are the 10 secrets that successful leaders follow:

Secret No. 2: Define expectations for each employee.

Every employee has a need and a right to know what their boss expects.

Managers (leaders) have a responsibility to define and communicate expectations for each employee. Failure to do so leads to frustration and poor performance. If you want to reduce stress and frustration, then make this secret work for you and your organization.

The essential expectations for each employee are those five or six key requirements that must be met for a person to be successful at his or her job. This is not a job description of detailed tasks, but rather the major requirements for success on the job. Simply take out a sheet of paper and write each employee’s name in one column and then write in your expectations for each person. Next comes the hard part: communicate your expectations one on one with the employee. This is absolutely basic to leadership success and is one of the most overlooked secrets by leaders at all levels in organizations today.

Secret No. 1: Treat people right. Successful leaders work

to earn the respect of the people who report to them and of the people with whom they interact. This means supervisors, employees, co-workers, customers and suppliers. The attitudes that employees develop toward their bosses are based upon the qualities and actions of the person in charge. Employee attitudes are critical to the leader’s success, as well as to the productivity in the workplace. The “top secret” is to treat all people with dignity and regard them as individuals. Really, just treat others like you would want to be treated, to paraphrase the “Golden Rule.”

Secret No. 3: Have a clear vision and articulate it. Vision is simply looking ahead and seeing the things others don’t see, and providing a long-term sense of direction for the organization. Spend time to look beyond today. Look ahead 5 or 10 years and make your best estimate of what needs to happen in your business unit, operating unit or overall business to continue being successful.

Vision sets the overall direction for the organization. It gives the people something to “hitch their wagon to” and should be relevant and practical, yet challenging for the organization to really HYDROCARBON PROCESSING DECEMBER 2009

I 27

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

embrace it. Clearly articulating the vision will help your people stay the course in difficult times.

TABLE 1. 10 secrets for successful leaders Secret No. 1: Treat people right

Secret No. 4: Delegate effectively. Delegation is making

Secret No. 2: Define expectations for each employee.

effective work assignments based on the competencies of your people. Many managers today are overloaded with work, and yet they fail to realize the importance of effective delegation. Successful managers or leaders know what can and should be delegated. They make the assignments and then leave their people alone to get the job done. Ineffective leaders will take care of many tasks themselves, stay busy and then fail to fulfill their role as a manager.

Many times, those in charge just give direction without getting input or checking for understanding. When delegating a task it is essential to know that the employee understands what is to be done. It is difficult to delegate a job, because with delegation comes the right to make a mistake and the person in charge is still responsible for all that happens in his or her work group. Yet, it is impossible to be effective in leading a work group when one is trying to do all the work themselves.

Secret No. 3: Have a clear vision for the organization and articulate it.

Secret No. 5: Pay attention to details. The details that

we are talking about are little things but they make the difference between success and failure.* The effective leader is careful to take care of the details, especially where employees and/or customers are concerned. Managers must be involved in the details, especially on the large projects.

It is a myth that the people in charge can avoid getting involved with the details of the work to be done. The challenge is to avoid getting so deeply involved into details that you bother your people or fail to manage the overall operation or organization. For example, in a large HPI project, safety is always a top consideration.

However, there are many other details that must also not be overlooked. Perhaps details as simple as how the contractor materials will be unloaded at the site could become an issue if not properly addressed in the planning stages. This is just a simple illustration, but you get the idea.

The big issues in the workplace will be resolved. Usually, it’s the little things that are harder to focus on every day. Remember: When you’ve got a little rock in your shoe, nothing’s right!

Secret No. 6: Evaluate alternatives. Alternatives are

the different potential courses of action to resolve a problem, a workplace situation or to achieve an objective. Failure often comes from a single-minded approach to problems. Being “boxed in” without understanding alternative recourses can lead to even more trouble in some situations.

Focus is important. But managers need to practice developing alternatives when faced with problems or situations in the workplace. Developing reasonable alternatives enables us to identify multiple approaches to a specific issue or situation. Practicing the discipline of developing alternatives will make you a better problem-solver for your organization.

In most situations faced by a manager, there are multiple possible solutions or actions. The effective manager will develop alternatives that will enable him or her to approach problems more objectively as opposed to being “fixed” on one solution or course of action. Encouraging those who report to you to bring several alternatives when discussing problem situations will build * Success Factor #17 from Taking Care of the Basics: 101 Success Factors for Managers, by Davis Woodruff.

28

I DECEMBER 2009 HYDROCARBON PROCESSING

Secret No. 4: Delegate effectively.

Secret No. 5: Pay attention to details.

Secret No. 6: Evaluate alternatives.

Secret No. 7: Ask the right questions.

Secret No. 8: Know when to make exceptions.

Secret No. 9: Be decisive.

Secret No. 10: Follow up to let people know you care.

a more competent workforce for your organization. This practice will help you develop your people.

Secret No. 7: Ask the right questions. Sometimes

simply knowing the right questions to ask can make a person much more successful as a leader. Of course, the simple “why?”, when asked about five times, can help us get to the root cause of many problems. Generally, we arrive at the root cause about the third or fourth time we ask “why.” Here are other questions to consider: 1. How are your overall business results as compared to your goals for the year?

2. Is your safety performance for the year on target, or are you having too many first-aid cases, accidents or lost-time injuries?

3. Is there an established process to evaluate your compliance to regulatory requirements that affect your organization (i.e., IRS, EEOC, OSHA, EPA, ADA, FDA, DOT and a myriad of other federal, state and local regulations and/or agencies)? Have you conducted and documented compliance reviews? Are corrective actions effective?

4. Are you meeting your customers’ expectations? Is it time to assess customer satisfaction?

An action step for leaders is to take time to develop a list of key questions about your business, operating unit, work group or team that will help you assess quickly the “health” of the organization. The four questions listed above are simply idea starters for you. Make your own list of 4–7 key questions and focus on them.

Revise the list as conditions change. This is an ongoing exercise in leadership that will enable you to more clearly understand the situations you face in your business.

Secret No. 8: Know when to make exceptions. An exception is when a policy, work rule or procedure is knowingly violated in the interest of an employee, customer or business need.

While it’s important to follow work rules and procedures, there are times in the real world when work rules or procedures may restrict a manager from acting in the best interest of an employee, a customer or a business.

Wisdom dictates that managers realize these unusual situations for what they are and make rare exceptions. Whenever exceptions are made to work rules or procedures, a legitimate justification should be readily recognizable. The problem, of course, is for the manager to recognize the situation and be willing to take a calculated risk. When an exception is made, the situation should be carefully documented and clearly communicated to all interested parties. Before you get too carried away here, this is not condoning compromising a safety

Select 79 at www.HydrocarbonProcessing.com/RS

PLANT DESIGN AND ENGINEERING rule. We are talking about policies that sometimes just do not fit every conceivable situation, or perhaps the “game has changed” significantly and the policy was never updated.

Exceptions that are not legitimate or that are not clearly communicated generally lead to misunderstandings, setting undesirable precedents or charges of favoritism. Thus, clear communications are essential. Also, if procedures or rules need to be changed, document the changes and update the procedures.

Secret No. 9: Be decisive. General George Patton said,

“When in command, command.” In the business world, the workforce is looking for leaders who will make decisions based on the facts of the situation and not just “what someone will accept.”

So when you are the leader, lead!

It’s a disgrace and a waste when the workforce is waiting for those in charge to stop procrastinating and make decisions. Too often, the top people in an organization delay progress or, even worse, let a situation force the decision by not making a decision.

Workers don’t respect indecisive leaders.

Learn and use a systematic process for making decisions.

Make effective decisions in a timely manner. For example, define the problem or situation, get the facts, look at the options, get input where appropriate, evaluate the consequences and make a decision.

Secret No. 10: Follow up to let people know you care. Follow-up is just letting people know that you care by

seeing that work assignments are performed properly. Effective follow-up is not “looking over the shoulder” of an employee, but rather asking how the work is progressing or observing results. It lets the employee know that the work is important and you care.

When the boss doesn’t care enough to follow up, why should anyone else care?

Leading for the future. Leadership is a challenging job and it gets more challenging with each passing year. Resource limitations, regulatory compliance, economics and many other external factors go into making the leader’s role more demanding.

The HPI is fortunate to have many effective leaders at all levels of organizations within the industry. However, it is important to be preparing the next generation of leaders as well as learning new techniques that will enhance your career. Applying these 10 secrets of leadership will go a long way toward helping you succeed in your leadership role. HP BIBLIOGRAPHY Woodruff, D., Taking Care of the Basics: 101 Success Factors for Managers (available at amazon.com).

Davis M. Woodruff is the founder and president of Manage-

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I DECEMBER 2009 HYDROCARBON PROCESSING

ment Methods, Inc., a management consulting firm based in Decatur, Alabama. A consultant, speaker and author, Mr. Woodruff is a recognized expert in showing companies how to be the low-cost, high-quality environmentally responsible leader in their industry.

Since 1984, he has served clients in 35 states and on three continents. He is the author of the book, Taking Care of the Basics: 101 Success Factors for Managers, and dozens of articles, including articles for Hydrocarbon Processing and the Encyclopedia of Chemical Engineering. Mr. Woodruff is a chemical engineering graduate of Auburn University, a certified management consultant and a licensed professional engineer in Alabama. (www.DavisWoodruff.com)

PLANT DESIGN AND ENGINEERING

SPECIALREPORT

Maintain a competitive edge in the liquefied natural gas industry Use this integrated approach to optimize construction and operation costs J. COLPO, Honeywell Process Solutions, Burnie, Tasmania, Australia

L

iquefied natural gas (LNG) is experiencing a healthy longterm growth rate but faces resource constraints and growing competitive pressures. To maintain competitiveness and profitability, the LNG industry needs to reduce project timelines and costs. The LNG industry also needs to design assets for minimal staffing and inventory, energy efficiency and minimal carbon footprint, along with improving plant flexibility to exploit spot trade opportunities. Although automation represents only 2% to 6% of project spending, its impact on operations over time is 15% to 30%. Accordingly, automation represents a great opportunity to improve an LNG plant’s business effectiveness. Unfortunately, the traditional Main Automation Contractor (MAC) approach focuses on integrating the automation segment of projects, but only up to the startup phase and it does not address the complexities of today’s LNG projects.

A new approach called Integrated Main Automation Contractor (I-MAC), see Fig. 1, provides major improvements by addressing interactions between people, systems and processes over the complete LNG asset life cycle. Automation providers can fill a consultative role in the early stages and conduct collaborative workshops with operations representatives to define requirements for human factors design, operational and business systems integration and life cycle sustainability. Early involvement in projects by automation suppliers can help ensure that decisions made in the early phases support smooth, efficient startup such as dynamic simulation, alarm system design processes and plant optimization. Training operators earlier, modeling the process in parallel with construction and testing advanced process control designs in simulation mode, all contribute to reducing time to market and reduce project risk.

the oil prices that LNG contracts are typically tied to are close to 2004–2005 levels. As a result, pressures are high for new projects to be brought online as quickly and cost-efficiently as possible and accelerated through the ramp-up phase to full earning capacity. The industry is also striving to preserve its enviable safety and security record despite increasing risks and operation complexity.

For most of its history, the LNG trade has had a very conservative approach to business development and operations. This is primarily due to multi-decade take-or-pay contracts that were and are still needed to guarantee the relatively high capital costs as compared to conventional oil and gas plays. Twenty-year contracts were signed up to 95% of the working capacity of LNG liquefaction plants, leaving little opportunity for lucrative spot trades.

However, developments in the past decade have made trade in LNG more flexible and introduced more competition into the market. An increasing number of LNG terminals can blend or spike the imported LNG to desired heating values so that LNG from multiple sources can be imported. Many countries that have sufficient existing natural gas sources are building LNG terminals

Project focus (cost, schedule, risk)

Challenges despite steady growth. The global LNG

industry has seen dramatic growth since the late 1990s. According to BP, global LNG trade increased from 113 million tons per year (MMtpy) in 2000 to 154 MMtpy in 2006. The same source expects LNG trade to reach 225 MMtpy by 2010 and 524 MMtpy by 2030. In 2008, a combined liquefaction capacity of 207.01 MMtpy is provided by 31 terminals in 17 countries supplying LNG to 59 regasification terminals with a combined capacity of 402.15 MMtpy in 19 countries. But, the growth in LNG capacity has helped to drive a dramatic increase in capital expenditures and operating costs that is threatening the industry’s health.

Project capital costs doubled between 2005 and 2008, and plant operations costs doubled between 2004 and 2008 while

I-MAC Operational and business readiness (flawless startup, first year operations)

FIG. 1

Lifecycle focus (safety, reliability, efficiency)

Three phases of holistic automation regime - I-MAC.

HYDROCARBON PROCESSING DECEMBER 2009

I 31

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KTI Corporation 1990 Post Oak Blvd., Suite 1000, Houston, TX 77056 Tel: (281) 249-2400 Fax: (281) 249-2328 E-mail: sales@kticorp.com KTI - KOREA #612, Kolon Science Valley II, 811, Guro-dong, Guro-gu, Seoul, 152-050, Korea Tel: 82-2-850-7800 Fax: 82-2-850-7828 E-mail: BSKim@kti-korea.com Select 96 at www.HydrocarbonProcessing.com/RS

PLANT DESIGN AND ENGINEERING

or process providers. Integrated products mean an integrated approach from process automation systems to enterprise systems and IT, all of which must be wrapped in a secure environment.

The I-MAC philosophy also includes automating and managing work processes. I-MAC delivers a holistic approach to the entire life of plant assets in addition to managing costs and reducing risk during project execution.

100

60

40

Low

20 0 0

ing nn Pla

Ability to influence cost

80

I-MAC strategic procurement

Co st

High

The value of early involvement. LNG asset owners have the greatest ability to influence project costs in the early stages, even though most project costs accrue during the latter phases.

Automation philosophies have a large contribution to the smooth efficient startup and enable lowest cost of ownership of the facility’s operational life. Decisions made early in projects around automation technology selection—such as dynamic simulation, alarm system design processes, production management systems or plant optimization—all have major impacts on the ongoing operation of the facility (Fig. 3). I-MAC providers fill a consultative role in the early stages of a project and conduct collaborative workshops with operations representatives to define requirements for human factors design, operational and business system integration and full life sustainability.

t cep Con

for energy security. These are not base-load plants and they serve to increase the amount of spot trade in LNG. Many new gas reserves are smaller than the 10 Tcf of proved reserves typical of earlier large-scale base-load plants. LNG liquefaction solutions are being developed that can monetize stranded reserves down to even 0.1 Tcf by using such solutions as floating LNG plants or LNG floating production storage operations.

Until now, a conservative approach has also dominated the construction on LNG plants and its processes and automation systems. Engineering, procurement and construction (EPC) contractors have shifted some of the risk and complexity to automation vendors. The MAC method was designed to provide a single point of responsibility for all automation-related aspects of a project, including the integration of automation with plant equipment and management systems, up to the startup phase. However, MAC was designed to simplify only one dimension of the asset construction and does not address the majority of the LNG’s asset life cycle. It should be noted that the LNG asset has three distinct phases in its life: the construction project phase, which may take two to five years; the asset readiness phase, beginning at plant startup and persisting until the asset reaches operational and business readiness at sustained working capacity, which can take two years; and the operating life cycle, which can be from 25 to 50 years or longer.

I-MAC is the improved method for achieving sustained benefits across all three phases of the LNG asset life. The “I” in I-MAC indicates integration with the LNG company’s overall business objectives of a new LNG asset, including people, products and processes. I-MAC addresses not only the short-term objectives of the capital project phase, but also the operational and business readiness that is required for startup. Fig. 2 illustrates an improvement of I-MAC over MAC. The I-MAC approach focuses on the LNG company’s business objectives through automation at the plant’s process, operational and business layers. An integrated approach to reliability management is also important. Integrated people means having an integrated project team consisting of a client, the PMC/ EPCs, MAC, and other parties involved in the project. It also means integrating the expertise of partners and large equipment

SPECIALREPORT

en d

iture

Engineering phase Commodity procurement phase

ROI impact

Im ple me nta tion Definitive estimate and proposal

20

p ex

40

Construction phase Clos

60

e-out 80

100

Percent FIG. 3

I-MAC influences return of investment in early stages.

afety and sec ted s urit gra Enterprise e y t In and resource

Control–DCS, SIS, PLC compressor controls, RMs, PCT

Production

planning

Production management, supply chain Advanced control and optimization–operator training, asset manage ment

Lost revenue

Without operational readiness

Field devices–control valv e, pressure, temp, level, analyzers, local indicators

Time FIG. 2

Improvement of I-MAC over MAC.

FIG. 4

Any delay in operational readiness results in significant lost revenue.

HYDROCARBON PROCESSING DECEMBER 2009

I 33

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

Early involvement is also crucial to the success systems at supporting the reliability or maintenance department. Look for an I-MAC provider with strong credentials in front end engineering and design and consulting capability. Projects built in a virtual silo will likely not meet requirements in many areas and will struggle during commission and handover. The I-MAC approach enables the various stakeholders to influence the plant design, resulting in smoother and faster startup and handover to operations.

Although the MAC or I-MAC provider takes responsibility for all design, engineering and construction activities for automation, the team is tightly integrated with the overall EPC team, often sharing the same or compatible computerized tools.

Choosing automation providers with substantial prior experience in LNG and strong project execution capability will accelerate and stabilize the capital project compared to other choices.

APC, already used in most oil refineries and large gas plants, is also gaining popularity in LNG. Analogous to an autopilot, APC typically removes the reactive actions required by a process operator to allow more time to be spent on optimizing production. For example, massive cryogenic and ambient air-cooled heat exchangers operate at differing capacities during cool evenings compared to the afternoon heat. This is only one of many opportunities that can be automatically exploited by APC to increase throughput and decrease energy consumption and emissions.

Layered safety and security. Safety needs to be approached from a plant-wide perspective, incorporating layers of safety, such

Achieving operational readiness.

I-MAC introduces a broader view and delivery of operational readiness than previous techniques. Operational readiness is the state when a new LNG plant is operating for an extended period at the desired production rate, within designed operating costs (see Fig. 4). The engineering, sourcing and construction of the physical asset have been completed and all tests made to verify compliance with the capital project scope. Operational readiness includes readiness of operations personnel (people assets) as well as the plant and physical assets, as illustrated in Fig. 5. The cost of financing a multi-billion dollar LNG plant makes delays very expensive. Also, any delays in achieving operational readiness can be incredibly expensive. Startup is the first time that all the new systems in an LNG asset are operated together. Validating that all systems work together correctly from the process automation layer to the operational and business automation layers prior to startup is a core component of I-MAC. Training, or people readiness, is perhaps the most important aspect to the success of operational readiness. Only when properly trained can the LNG plant operators run the plant to optimum efficiency levels.

Keeping operators well trained to handle infrequent process upsets is critical. An operator training simulator (OTS) enables operators to continually develop skills to handle process upsets in a safe simulated environment. Startup and operating procedures can be developed and validated using the OTS along with the process control system design to reduce startup time. Simulators can be used during testing phases to aid in pre-commissioning automation systems.

Advanced process control (APC) can also be step-tested on simulators.

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I DECEMBER 2009 HYDROCARBON PROCESSING

FIG. 5

Operational readiness in an LNG plant.

FIG. 6

Layered approach to security.

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KTI - KOREA #612, Kolon Science Valley II, 811, Guro-dong, Guro-gu, Seoul, 152-050, Korea Tel: 82-2-850-7800 Fax: 82-2-850-7828 E-mail: BSKim@kti-korea.com

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SPECIALREPORT

PLANT DESIGN AND ENGINEERING as a secure process design, abnormal situation management and physical security (Fig. 6). The safety system should be operationally integrated with the control system to align the LNG plant’s goals for safety and reliability with a proven solution that combines process safety data, system diagnostics and critical control strategies.

Additionally, the I-MAC vendor provides a tightly integrated suite of robust applications for physical protection, providing significant life cycle cost of ownership benefits based on a common automation and security systems model. With such design and implementation, security technology can equal that at sensitive military, governmental and private facilities around the world. Ideally, the security and control consoles should use the same solution platform and the same alarming and access structures as the process control system to optimize sharing information throughout the LNG facility.

FIG. 7

Multiple software models of the LNG supply chain.

Measurement

Control

Sustaining performance throughout the plant lifecycle. The LNG enterprise is expected

to operate for many decades at the plant’s original working capacity. Typically, most LNG capacity is sold on 20-year contracts and most contracts are renewed for a further 20 years. Accordingly, it is important to keep the plant operating reliably, with Reliability Centered Maintenance (RCM) being the current best practice. Automation vendors can deliver solutions that monitor the condition of large equipment while digital I/O solutions can monitor the condition of automation equipment.

The automation vendor can provide long-term support agreements to keep instrumentation and control systems at peak working order. Recent advances extend the automation maintenance regime to remote calibration of control loops and APC via “scouts.” For the LNG plant, it is critical to reverse the typical degradation of production capacity, efficiency and reliability that usually occurs in the mid-life of the plant. Automation providers offer solutions in mid-life that can step up performance, sometimes to better than new.

Maximizing business opportunity. The increasing num-

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ber and size of LNG trains, storage tanks and carrier vessels, have made traditional approaches to managing logistics scheduling obsolete. Although software models may be used to predict voyages and future LNG inventory, these tool-like models are not integrated and require manual workflows to communicate schedules and activities. Personal spreadsheets, still frequently used to coordinate multibillion dollar LNG enterprises, are prone to error and miscommunication.

Solving the complex LNG logistics problem requires producers to master the entire production chain from gas wells to the final sales terminal. This means having a transparent overview of gas pipelines, liquefaction, intermediate storage, ship scheduling, berth scheduling and harbor management. The challenge is to constantly and accurately match the delivery contracts with the LNG production, the available storage capacity, the harbor con-

PLANT DESIGN AND ENGINEERING straints and the ongoing production rates, including byproducts and the shipping logistics. Any disconnects will result in significant financial losses or penalties due to loss of capacity/throughput, non-timely delivery, ship idle time (demurrage), and so on.

LNG delivery commitments are normally defined in terms of an annual delivery plan (ADP). The ADP globally matches the expected LNG output with the long-term contracts in place and any possible spot cargoes. To plan effectively, the production planning, ship scheduling and berth scheduling functions all need to communicate with each other in essentially real time (Fig. 7).

■ Solving the complex LNG logistics

SPECIALREPORT

Conclusion. The LNG industry must continue to develop

new practices to manage increasing competition with other fuel sources, competition within the LNG industry and pricing volatility. Automation can provide significant economic and holistic benefits across the entire LNG plant life cycle. I-MAC builds on the MAC concept of providing the EPC and end user with one-stop responsibility for automation scope. I-MAC goes on to include operational and business readiness solutions as well as integrated security and safety systems. Early involvement strategies enable I-MAC to improve capital project success and reduce project costs. Full LNG plant life-cycle maintenance services and solutions will prevent deterioration of LNG plant and subsystems. HP

problem requires producers to master the entire production chain from gas wells to the final sales terminal.

John Colpo is the leader for Honeywell Process Solutions Mar-

The I-MAC approach delivers common interfaces across product and business enterprises, reducing engineering and design work and enabling a higher level of collaboration. Tight integration of point solutions around a central inventory management database can deliver effective supply chain management for a liquefaction facility. This approach can cope with the breadth of the supply chain problem, even when the large numbers of trains and tankers are involved.

keting and Strategy for oil and gas. He handles strategic and some tactical marketing activities ranging from market planning, product roadmap planning, management advisory, solutions partners and alliances, market planning, sales training development, sales collateral development, acquisitions, and marketing communications. Mr. Colpo has over 20 years of experience in automation and software applications in the oil and gas industry.

He has worked at Honeywell since 1986 in a wide variety of roles from automation systems engineering, software development, operations manager of advanced solutions, head of oil and gas software COE, research and development analyst, research and development manager and marketing manager. Mr. Colpo received a BE degree in mechanical and electrical engineering from University of Tasmania.

H y d r o c a r b o n P r o c e s s i n g . c o m

WEBCAST Now Available On-Demand

Heinz Bloch—Maintenance and Reliability Trends in the Refining, Petrochemical, Gas Processing and LNG industries Watch as Hydrocarbon Processing’s Reliability/Equipment Editor Heinz Bloch is interviewed by Editor Les Kane, in his first webcast on maintenance and reliability trends in the refining, petrochemical, gas processing and LNG industries.

In these tough days of narrow refining margins, refiners have to do more with less and create greater efficiency with a smaller pool of capital expenditures. This is not impossible, but it is challenging. Heinz Bloch addresses these issues head on in this timely and informative webcast. Heinz advises participants on his belief system for effective reliability engineering, pulling no punches as he describes his view that adding value requires effort and doing the right thing is very seldom the easy thing.

Heinz, as an editor for Hydrocarbon Processing for 10 years, has built a dedicated following worldwide in his area of responsibility.

He holds six U.S. patents and has authored over 460 technical papers and 17 books on machinery. He was an Exxon Chemical Co. machinery specialist and held positions worldwide before retiring after 24 years with Exxon. He has a deep personal and technical understanding in the area of maintenance and reliability and current trends.

To view this exciting, one-of-a-kind event for the HPI, visit www.hydrocarbonprocessing.com/blochwebcast0909 to register for the on-demand webcast that was held on September 10, 2009.

For questions about future Hydrocarbon Processing Webcasts, contact Bill.Wageneck@Gulfpub.com.

Sponsored by |

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HYDROCARBON PROCESSING DECEMBER 2009

I 37

Quality Time

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PLANT DESIGN AND ENGINEERING

SPECIALREPORT

Advanced hydrocracking technology upgrades extra heavy oil New hydrogen-addition process yields middle distillates while zeroing fuel oil and coke production from vacuum residue G. RISPOLI, D. SANFILIPPO and A. AMOROSO, Eni Refining & Marketing Division, Milanese, Italy

ingly, conversion processes are classified as carbon rejection in which excess carbon is removed by thermal and/or catalytic treatment and as hydrogen addition processes operating in the presence of suitable catalysts.

Coking, the most typical carbon-rejection technology, offers high feedstock flexibility and can process the heaviest, high carbon residue and highly heteroatomic feedstocks. Drawbacks with coking are loss of liquid yields, production of large amounts (around 30% wt) of coke and poorer quality of distillates, which require severe upgrading to meet market specifications. At present, about 100 million (MMtons) tons of petroleum coke are produced annually worldwide.4 Of course, coke production increases processing of particularly unconventional extra-heavy oils. Petcoke has low value; it is tough to market and poses potential serious logistic issues—all of which are aggravated by the often remote locations of oil resources.

Gasification also allows utilization of the bottom-of-thebarrel. This method converts low-value heavy streams and coke into syngas—a mixture of hydrogen (H2) and carbon monoxide (CO)—and the syngas is used in integrated gasification combined cycle (IGCC) power generation. Cogeneration of electricity from syngas has become attractive because of deregulation especially

Fuel oil supply and demand, million bpd

C

onstruction of the first advanced slurry-phase hydrocracking process unit is in progress at Eni’s Sannazzaro refinery. This plant is designed to convert 23,000 bpsd of vacuum residue into high-quality diesel (<10 ppm sulfur) and other valuable refinery streams—liquefied petrolem gas (LPG), naphtha, jet fuel and catfeed.

Development to a commercial scale of the proprietary slurryphase hydrocracking process may be the answer to a crucial need for the oil industry in both upstream and downstream sectors over upgrading the “bottom of the barrel.” In the upstream industry, the production of heavy crude oils is forecast to continue to grow over the coming decades.1 Large reserves of unconventional extra-heavy crude and bitumen exist in several geographic areas including Canada and Venezuela. Therefore, heavy oils are expected to increase their role in supplying worldwide oil derivatives.

High-boiling point, high specific gravity (less than 10 API), lowhydrogen content and high carbon residue make heavy oils a harsh feedstock. They also contain large amounts of asphaltenes, sulfur, nitrogen and metals. As reserves of conventional crude oil continue to decline, these unconventional feedstocks become an increasingly larger share of feedslate to refiners. More important, these crude oils require effective technologies for deep upgrading and meeting the growing demand for light and middle distillate fuels.

Conversely, the refining industry must address the market evolution to improving the quality of ground, air and maritime transportation fuels, and the declining demand for fuel oil by industry and power generation.2 The new International Marine Organization proposal for marine bunker fuel quality will drop to <1% sulfur would further impact residual fuel oil surplus. The increasing supply of higher sulfur and gravity crude oils and the increasingly more stringent environmental regulations worsen an imbalance between residues availability and market demand.

Therefore, cost-effective refinery modifications that can achieve higher residue conversion are required to transform surplus poorquality oil residues into cleaner fuels.

2.0 1.5 1.0 0.5 0.0 -0.5 -1.0 -1.5 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020

Net fuel oil FSU East

New upgrading technologies. Several technologies for

converting vacuum residues to lighter products are commercially available. Petroleum vacuum residues, and especially those produced from extra-heavy crudes, have a high carbon-to-hydrogen atomic ratio as compared to the desired fuel products. Accord-

North America Africa

Latin America Middle East

Europe Asia-Pacific

Source: Eni R&M on Parpinelli data

FIG. 1

Fuel oil supply and demand balances.3

HYDROCARBON PROCESSING DECEMBER 2009

I 39

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

in the US and Europe. Any type of heavybottom residue, including visbroken tar, deasphalter pitch, high-sulfur coke and hazardous refinery wastes, can be used as feedstocks for gasification. The final product, in this case, is not a transportation fuel but electricity. Disadvantages for this approach include large capital costs and the need for valueless or negatively valued feedstocks.

• Delayed coking 1 in its Gela refinery: 4,600 tpd • Delayed coking 2 in its Gela refinery: 3,300 tpd • Gasification of visbroken (VB) tar in its Sannazzaro Refinery: 400,000 tpy with 200 Mwe generation.

Beyond economic benefits, all of these approaches demonstrate some limitations in minimizing production of low-value, low-demand co-products—zero fuel oil/ zero coke—or increasing distillates output at the same crude distillation unit (CDU) capacity. A better deep-conversion technology was needed.

Hydrogen-addition methods. Resid conversion processes through hydrogen addition operate in the presence of heterogeneous catalysts, mainly based on transition metals such as molybdenum (Mo), nickel (Ni) FIG. 2 High-resolution transmission and cobalt (Co) supported on aluminas. The electron microscopy of nanodesired reactions cleave sulfur, nitrogen and New approach. In the early 1990s, devellamellae of slurry-phase metals from the oil substrate and saturate opment began a new concept to achieve full hydrocracking catalyst. polynuclear aromatic (PNA) rings under high conversion and upgrading the bottom of temperature with the presence of hydrogen. the barrel. This effort has developed a proprietary hydrocracking Hydroprocessing reactors can be either fixed-bed, moving technology that allows almost complete conversion to distillates bed, ebullating-bed, or a combination. Most fixed-bed catalytic from the heaviest refinery bottoms as well as high upgrading by processes accept rather low-metal containing feedstocks. Due to removing heteroatoms or reducing them to a level that is managethe buildup of metals and coke on the hydroprocessing catalyst, able in conventional refinery operations. The successful operaoperation cycles have limited run lengths. Ebullating bed catalytic tion of a semi-scale commercial demonstration plant demonprocesses are able to process high-metal feedstocks due to continustrated the technical viability and reliability of a new slurry-phase ous fresh catalyst addition and withdrawal of spent catalyst. hydrocracking process. Following this achievement, it was decided to build the first full-scale slurry-phase hydrocracking process unit Cons. The main drawback of all current hydroprocessing technoloin Eni’s Sannazzaro refinery, with startup scheduled in 4Q2012. gies is the loss of residue stability at high conversion levels, which The Sannazzaro unit will also be the first industrial-scale one based limits the maximum conversion achievable. During the reaction, on a slurry-phase hydroprocessing technology. A study for a second the heaviest components of the feedstock become insoluble in the unit with a processing capacity of 14,000 bpsd for the Taranto lighter fractions. High temperatures or high asphaltene contents refinery by revamping existing refinery equipment is in advanced promote polymerization and condensation reactions between aroexecution stages. Applying the slurry-phase hydrocracking techmatic clusters. When the difference between the solubility paramnology eliminates the production and handling of petcoke. As an eters of the two pseudo-components (asphaltenes and maltenes) hydrogen-addition technology, it increases production of synthetic approaches the critical value, asphaltene precipitation and coke crude oil (SCO) by more than 20%.8 formation can occur. Because of limited conversion, fuel oil remains a fatal product. Additionally, devaluation of the hydrocarbons is still Advanced slurry-phase hydrocracking technology. present in the residue; the need for lighter oil fractions as fluxant, From the technological point of view, slurry-phase hydrocracking contributes to the fuel-oil diseconomies. World fuel oil production, is a hydrocracking process based on the unique features of a nanowhich peaked in 2004, has been declining. Refiners are looking to dispersed (slurry) non-aging catalyst and a special homogeneous upgrade their plants with catalytic crackers, hydrocrackers or cokers isothermal reactor synergistically working in a novel processing to reduce fuel-oil production and to increase output of light cleaner scheme that allows an almost total (> 98%) feedstock conversion transportation fuels. Actually, over 9 MMbpd of fuel oil (over 10% into distillates as well as high upgrading performance.9,10 5 of the world oil production) are produced now.

Some pacing technologies, based on the slurry-reactor concept Catalyst. The active phase of the process is a catalyst—unsupfor hydrocracking heavy residues, have been announced, but they ported molybdenite (MoS2) in the form of nano-lamellae generhave not yet reached the commercial level.6,7 The main limitations ated in-situ from oil-soluble precursors. of these new dispersed catalyst processes are the high-severity Electron microscopy (high resolution transmission electron operating conditions required to attain higher conversion goals microscopy) observations reveal excellent dispersion of the catadue to the low activity of the catalysts that must be kept at low lyst. Most of the MoS2 is present as single isolated layers (Fig. 2). concentrations due to once-through processing.

The stacking phenomena (2–3 layers particles) involve only a minor part of the catalyst.

Experienced refiner. As a refiner, Eni S.p.A., has a great Since metals precipitate as sulfides forming separated phases experience with residue conversion through its downstream refinwithout interfering with the naked active centers of MoS2, the ing systems: catalyst remains practically unchanged during the whole operation, • Fixed-bed resid hydroconversion unit in its Taranto refinery: thus eliminating aging. It avoids catalyst substitutions (and relevant 25,000 bpsd plant turndowns) typical of all catalytic hydrotreating processes.

• Ebullating bed hydroconversion in its Milazzo refinery: Contrary to the conventional supported catalysts used in 25,000 bpsd fixed-bed and ebullating-bed reactors, the new slurry-phase 40

I DECEMBER 2009 HYDROCARBON PROCESSING

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SPECIALREPORT

PLANT DESIGN AND ENGINEERING

hydrocracking catalyst does not suffer ■ Development of a heavy ends to achieve total feedstock confrom plugging problems due to metals version and to avoid fuel-oil production. and coke deposits within the pores of the commercial scale proprietary Process flow. Fig. 3 shows the simplisupports. fied reaction section scheme of the new slurry-phase hydrocracking The lower effect of coke, high surface slurry-phase hydrocracking process. area and absence of mass transfer diffusion process may be the answer The heart of the process is a slurry resistances aid the catalyst to being more to a crucial need for the oil reactor in which the heavy feed is hydroactive than supported ones. The very high cracked into lighter products in the presspecific activity allows the catalyst con- industry over upgrading the ence of the slurry Mo-based catalyst. The centration to be kept at a level of a few “bottom of the barrel.” upgraded oil moves from the reactor to a thousand ppm. Temperature control with separation system to recover gas, naphtha, a dispersed catalyst is uniform, whereas supported catalyst can be middle distillates and catfeed. The gas phase, after separation of subjected to hot spots. Applying unsupported slurry catalysts is lighter products, goes to the amine-wash section, and clean gas, particularly useful in the case of feedstocks containing a high conafter recompression and hydrogen makeup, is recycled to the centration of contaminants, particularly metals and asphaltenes. reaction section. Distillates are recovered from the liquid phase.

Conversion of heavy products into distillate initiates thermally Unconverted bottom materials, together with the dispersed catathrough the breaking of C-C bonds and the generation of free lyst, are recycled back to the reactor. radicals. Hydrogen uptake reactions quickly quench and avoid Depending upon the feedstock, process severity (reaction time the chain reaction mechanism via beta scission of free radicals and temperature) is optimized to generate a residue well within and their recombination that leads to coke formation. The disthe stability limits and it avoids asphaltene precipitation that can tance between the MoS2 lamellae in the slurry phase is several generate coke and foul process equipment. The recycling and orders of magnitude closer than any supported catalyst to the oil blending of the partially converted residue with the fresh feed, molecular size. This reduces the time elapsed between radical formaintains stability of the recycle stream so that it can be repromation and hydrogenation on the catalyst, thus mitigating coke cessed to almost complete conversion. After repeated cycles, the formation. The Mo-catalyzed hydrogen uptake allows aromatic system reaches a steady-state so that the net result is the total ring hydrogenation, CCR reduction and heteroatoms removal— conversion of the feed into valuable products. hydrodesulfurization (HDS), hydrodemetallation (HDM) and A small purge (< 3%) is necessary to limit buildup of metals hydrodenitrification (HDN)—via the hydrogenolysis of C-hetero (Ni and V) from the heavy feed. The purge is processed to recover atom bonds. residual hydrocarbons and metals, including Mo. Accordingly, the Reactor. Another important feature of this hydrocracking slurry-phase hydrocracking process can handle heavy feedstock process is the use of a tailored-designed bubble-column reactor without generating byproducts, such as coke or heavy fuel oil. operating in the slurry phase. The reactor behaves homogeneously Path to development. The original idea of developing a due to the small size of the catalyst particles and isothermally due hydrotreating process based on micronic catalyst began in the late to the high degree of back mixing fluid—dynamically controlled 1980s. After an intensive R&D activity carried out at a laborain the slurry phase, thus ensuring almost flat axial and radial temtory level during the 1990s, all of the new processing steps were perature profiles. It contributes to making the reactor intrinsically integrated in a 0.3 bpd-pilot plant that was constructed and opersafe against temperature runaway. ated in 2000–2003. Pilot-plant operation, mockup studies with The synergetic combination of catalyst and reactor developmimic fluids, and the development of suitable models provided all ments enables the new slurry-phase hydrocracking technology to necessary information required for designing and constructing a adopt a process configuration based the on recycle of unconverted semi-scale 1,200 bpd-commercial demonstration plant (CDP).

The CDP was located inside the battery limits of Eni’s refinGas ery at Taranto, Italy. Since startup at the end of 2005, more than 230,000 bbl of black feed were processed successfully by the CDP H2 recycle unit (Table 1).

Reaction products Refined products Slurry reactor

TBP cut, °C (SCO) Fractionation system

H2 Cat prec.

Feed FIG. 3

42

Catalyst and residue recycle Slurry-phase hydrocracking concept.

I DECEMBER 2009 HYDROCARBON PROCESSING

TABLE 1. Feedstock tested in the CDP runs

Purge

API gravity H/C

Ural VR

Athabasca bitumen

Basrah VR

VB tar, PV = 1.1

500+

450+

500+

410+

9

5

5.6

0.1

1.49

1.47

1.45

1.33

S, wt%

2.9

5.4

4.9

5.9

N, wt%

0.53

0.38

0.39

0.49

Ni, ppm

90

86

35

68

V, ppm

253

230

119

125

Asphaltene, wt%

12.6

19.9

13.9

22.5

18

17

20

27

CCR, wt%

PLANT DESIGN AND ENGINEERING TABLE 2. Experimental yields from CDP Experimental yields from CDP

wt% on fresh feed

H2 consumption

2.9–3.3

H2S + NH3

3–5

C1–C4

6–9

Naphtha

6–20

AGO

35–55

Catfeed

12–55

Purge before PTU

2–3

The CDP operation enabled strengthening the know-how for this technology and confirmed expected process performance as obtained at the pilot scale. The CDP enabled an in-house fluid dynamics assessment of slurry-bubble-column reactors and internals.11,12 The process configuration was simplified to eliminate the solvent deasphalting section that was included in the original design. With the new design, it is possible to optimize operating conditions; heavy fractions are completely converted in the same reactor into higher-value distillates.

One of the main characteristics of the slurry-phase hydrocracking process is the excellent feedstock flexibility. The CDP operation validated the technical and economical viability of this methodology through safe and steady runs, even with a feed close to instability— Pvalue of 1.1 of a VB tar.

With all of the feedstocks used in the CDP, the new hydrocracking process demonstrated the possibility to attain total conversion of resi-

SPECIALREPORT

due into light, medium and heavy distillates with minimum purge.

Table 2 shows the experimental yields from the CDP obtained over a wide range of operating conditions—mainly temperature, fresh-feed residence time, recycle ratio and catalyst concentration.

Also, Table 2 notes that selecting the proper operating conditions can optimize conversion of heavier or lighter feed slate according to the refinery configuration. Process performances have been confirmed with several extra-heavy oils similar to Athabasca bitumen, Cerro Negro, Zuata, Congo tar sands and Tempa Rossa vacuum residues. All have been successfully processed.

In all cases, the process assures complete metal removal, excellent CCR and sulfur reduction and a fairly good denitrogenation.

Another peculiar characteristic of the slurry-phase hydrocracking process is the production of high-quality diesel oil and catfeed with a low sulfur and aromatic content that can be further converted into transportation fuels (diesel and/or gasoline) via hydrocracking (HDC) or fluid catalytic cracking (FCC).

Typical overall performances achieved in the reaction system, by recycling unconverted bottoms, include: • Metal removal (HDM) > 99% • Conradson Carbon Residue reduction (HDCCR) > 97% • Sulfur reduction (HDS) > 85% • Nitrogen reduction (HDN) > 40%.

In terms of economic evaluation, it is important to underline that the volume yield of the products is over 110% of the fresh feed.

The CDP runs have been crucial for development and scale-up to a full-scale commercial plant. Additionally, the CDP experience enabled:

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E-mail: Lee.Nichols@GulfPub.com HYDROCARBON PROCESSING DECEMBER 2009

I 43

PLANT DESIGN AND ENGINEERING LPG

Cat reform

44

I DECEMBER 2009 HYDROCARBON PROCESSING

HDS

Kerosine Gasoil

HDS Alky

MTBE

FCC

Hydro

FO and bitumen

HDC

Unit at Sannazzaro refinery. Applying the positive

results obtained from the CDP unit, the decision was made to build the first full-scale industrial unit of the new slurry-phase hydrocracking at Eni’s Sannazzaro de’ Burgondi Refinery at Pavia, Italy. The Sannazzaro refinery has a balanced refining capacity of 170,000 bpsd with one of the highest conversion indexes in Italy (52% hydroskimming conversion index, and 85% effective conversion). This refinery was constructed in 1963 with a processing capacity of 5 million tpy (MMtpy). The refinery’s output was doubled in 1975; again revamped between 1988 and 1992; and upgraded with improved technology over the last few years.

Today, this refinery holds one of the highest complex levels and conversion capacities in Europe.

Technology and efficiency, with the advantageous logistic position and flexibility to meet demands for the market and environment, make the Sannazzaro refinery a core business of Eni’s Refining and Marketing Division. Located in the Po Valley, the Sannazzaro refinery supplies refined products primarily to markets in northwestern Italy and Switzerland. The high degree of flexibility allows this refinery to process a wide range of feedstocks. From a logistical standpoint, this refinery is located along the Central Europe Pipeline, which links the Genoa terminal with Switzerland.

This refinery contains two primary distillation lines and relevant facilities, including three desulfurization units to achieve 10 ppm-S diesel for Euro V spec and an FCC gasoline post-treatment unit for 10 ppm S. High conversion is obtained through a 45,000 bpsd-FCC unit and two hydrocrackers with a total processing capacity of 70,000 bpsd. (One of the hydrocrackers is a 30,000 bpsd high-pressure total conversion unit that started up in July 2009.)

The “bottom of the barrel” is minimized since the heavy residue from visbreaking (tar) is used to produce high-purity hydrogen and syngas to feed the nearby EniPower power plant (Fig. 4).

Based on these conditions, the Sannazzaro complex is a highconversion, technology state-of-the-art refinery that does not require additional implementation. Nevertheless, installing the new slurry-phase hydrocracking unit will provide this refinery with extraordinarily profitable options. Some unique features of this refinery are: • Strategic and logistical issues; the refinery is in a key position for the European diesel market and is the knot of an efficient network of pipeline for oil supply and product distribution.

• The new slurry-phase hydrocracking unit will allow a synergic integration with present facilities and an existing unit refinery, mainly due to the high-capacity conversion units able to process less valuable products produced from the slurry-phase hydrocracking process, i.e., heavy gasoil.

Gasoline

ISOM

Blending

• Tailoring the technology with different feedstocks • Developing and fine-tuning process simulation models • Organizing operating procedures for startup, steady-state operation and emergency conditions for the new hydrocracking process • Training operation maintenance personnel and process engineers • Evaluating performance of selected construction materials against corrosion in harsh environment • Assessing the performance of various types of instrumentation that are exposed to heavy, fouling fluids.

The CDP is still in operation to demonstrate useful scale information, update process schemes and optimize proper operating conditions for any new feedstock.

Topping

SPECIALREPORT

H2 to refinery

Vacuum VSB

SDA IG

EST

FIG. 4

NP

CC Syngas Enipower

Sannazzaro refinery configuration.

Sulfur plant

Steam reforming

Sulfur

FG LPG

Vacuum residue

Reaction section

Utilities and offsites FIG. 5

Fractionation

Upgrading section

PTU

7-9, wt% Naphtha 6.5-7.6, wt% 38-50, Jet fuel wt% HQ diesel 30-45, Cat feed wt% Metals to reclaim

Block flow diagram of the slurry-phase hydrocracking complex at the Sannazzaro refinery.

• The refinery will be able to process 100% of extra-heavy crude with high sulfur content and produce high-quality middle distillates, in particular diesel. It should be considered that AR from sweet crude feeds FCC may become a limitation in that the crude slate is becoming increasingly heavier.

• Increase conversion by reducing fuel oil yield to zero (a minimum amount of asphalt as per market request will be assured) • Increase up to 10% of the present refinery throughput without increasing environmental impact.

The chosen slurry-phase hydrocracking process configuration incorporates all of the operating experience and innovation demonstrated in the Taranto CDP, thus mitigating technological risk. Reactors of maximum size, in terms of internal diameter and weight, will be installed to establish a sound reference for enhancing major industrial initiatives. The new unit has a design capacity of 23,000 bpsd of vacuum residue. Fig. 5 shows the unit layout and major equipment: • Reaction • Fractionation

PLANT DESIGN AND ENGINEERING

SPECIALREPORT

TABLE 3. Characteristics of feedstock Design feed Ural VR type 350–500°C, wt%

5

5

500+, wt%

95

95

15

15.6

1,004

1,039

Asphaltenes C5, wt% Sp. gravity,

kg/m3

Sp. gravity, °API

FIG. 6

Slurry reactor slice at GE yard, Massa, Italy.

• Products upgrading • Purge treatment unit.

Additionally, the slurry-phase hydrocracking complex includes: • A steam-reforming unit—Capacity at 100,000 Nm3/h of H2 • Sulfur plant (two lines)—Capacity at 80 tpd for each line • Utilities and offsite infrastructure.

The slurry-phase hydrocracking has been designed to treat the Ural vacuum residue (VR)—lower S, higher N and metals—and, as alternative feed, the Basrah VR—higher S, lower H/C ratio, as shown in Table 3. Table 4 lists the expected hydrogen consumption and product slate wt% of fresh feed. Noticeably due to the hydrogenation reaction, the liquid-products volumn is about 15% higher than the feed volume.

Alternative feed Basrah VR type

9.4

4.7

Viscosity, cst

982@100°C

1,126@80°C

Viscosity, cst

159@135°C

436@100°C

Pour point, °C

51

51

Sulfur, wt%

3

6

Nitrogen, wt%

0.7

0.4

Ni, ppm wt

68

46

V, ppm wt

214

164

CCR, wt%

20.2

18.5

H/C ratio

1.41

1.37

• 700 km of instrumentation wiring.

The Sannazzaro project requires a total investment, including ancillaries and offsites, of approximately 1 billion €. A second industrial project for a 14,000 bpsd-slurry-phase hydrocracking unit in the Taranto refinery, via revamping part of existing equipment is in advanced study stages.

The Sannazzaro EPC project. The Sannazzaro slurry-phase hydrocracking project is on a fast track. It is already in the engineering/procurement/construction (EPC) phase, and onsite work is already in progress. The front-end engineering design has been completed. The Environmental Impact Study and Environmental Impact Evaluation Application have been completed.

Site works have already started. Assembling of high-pressure reactors (Figs. 6 and 7) is already in progress at the site since October 2009 and will continue through March 2011. Construction and commissioning activities will last about 32 months, and startup of the facilities is scheduled for 4Q 2012.

This complex covers an area of 220,000 m2 (+190,000 m2 during construction). The Sannazzaro refinery is a very crowded area; thus, it has been necessary to enlarge the fence incorporating a neighboring pad field where the slurry-phase hydrocracking will be located. This has involved a significant impact on the project execution, site preparation and interconnecting/utilities costs.

Additionally to the process packages and usual offsites, ancillaries include a new sour-water stripper (SWS) unit, amine regeneration unit (ARU), blowdown and flare. Some additional information provides an idea of the scope for this project: • About 1.3 million engineering man-hours • 3,000 man-months for supervision • 32 months of yard duration • About 7.5 million construction hours • 36,000 tons of bulk material and piping • 17,000 tons of equipment Select 160 at www.HydrocarbonProcessing.com/RS 45

SPECIALREPORT

PLANT DESIGN AND ENGINEERING HDC HDCCR HDM HDN HDS FCC IGCC IMO SCO VB tar VR

= = = = = = = = = = =

Hydrocracking Hydroconversion of concarbon residue Hydrodemetallation Hydrodenitrification Hydrodesulfurization Fluid catalytic cracking Integrated gasification combined cycle International Maritime Organization Synthetic crude oil Visbroken tar Vacuum residue

LITERATURE CITED Radler, M., “Oil, Gas reserves inch up, Production Steady in 2007,” Oil & Gas Journal, Dec. 24, 2007, p. 22.

2 Eagles, L. (Ed.), Medium-Term Oil Market Report, International Energy Agency, July 2007, www.oilmarketreport.org.

3 Eni R&M on Parpinelli Tecnon data, 2008.

4 Platt, J., “Petcoke and low-rank coal/lignite supply outlook for IGCC evaluations,” Rep. No. 1013038—Electric Power Research Institute Final Report, February 2006.

5 Poten & Partners, Inc., “Synopsis of World Fuel Oil Production & Consumption in 2007,” Fuel Oil in World Markets, November 2007.

6 Butler, G., R. Spencer, B. Cook, Z. Ring, A. Sheiffer and M. Rupp, “Maximize liquid yield from extra heavy oil,” Hydrocarbon Processing, September 2009, pp. 51–55.

7 Stratiev, D., and K. Petkov, “Residue upgrading: Challenges and perspectives,” Hydrocarbon Processing, September 2009, pp. 93–97.

8 Delbianco, A., A., Faggella, R., Montanari, L., Petti, D., Sanfilippo and A., Amoroso, “Process Selection for Upgrading Extra-Heavy Oils, Venezuela Perspective,” World Heavy Oil Conference, Puerto la Cruz, November 2009, Paper No. 407.

9 Panariti N., A. Delbianco, G. Del Piero and M. Marchionna, “Petroleum Residue Upgrading with Dispersed Catalysts. Part 1. Catalysts activity and selectivity,” Applied Catalyst, A, 204, 2000, pp. 203–213.

10 Panariti N., A. Delbianco, G. Del Piero and M. Marchionna and P. Carniti, “Petroleum Residue Upgrading with Dispersed Catalysts. Part 2: Effect of Operating Conditions,” Applied Catalyst, A, 204, 2000, pp. 215–222.

11 Rispoli G., N. Panariti, A. Delbianco, and S. Meli, “Upgrading Unconventional Oil Resources with the EST Process,” 20th World Energy Congress, Rome, 2007.

12 Rispoli G., “Heavy Oil Upgrading,” GE Oil & Gas Annual Meeting, Florence (Italy), Jan. 26–27, 2009.

1

FIG. 7

Slurry reactor under construction at GE yard, Massa, Italy.

TABLE 4. Hydrogen consumption and product slate/ quality as wt% of fresh feed Hydrogen consumption H2 tot, wt% on FF

4.5–5

H2 slurry, wt% on FF

3–3.4

Products

S, ppm

N, ppm

3.2–4

–

–

7–9

–

–

Naphtha (C5 –170°C), wt%

6.5–7.5

<10

–

700

Kero + AGO, wt%

38–50

<10

–

840

Catfeed (350–500°C), wt%

30–45

<400

<700

920

Purge before PTU, wt%

2.5–3.8

H2S+NH3 , wt% C1–C4 , wt%

Sp. gr.

540 (LPG)

Outlook. True technology breakthroughs are necessary to enable the oil industry to resolve crucial problems in the upstream and downstream sectors. The new proprietary slurry-phase hydrocracking process allows valorization to fuels with mandated higher quality from unconventional crude oils, bitumen, and increasing and worsening refinery bottoms. It provides refiners some rigidity of supply and variability of refined product demand.

The new hydrocracking applies an H-addition process through a special homogeneous isothermal intrinsically safe reactor, and of a nano-dispersed non-aging catalyst. The process converts more than 98% of any residue type to about 110% volume of lighter products and distillates or extra heavy oils into high-quality bottomless SCO. As typical performances, HDS is >85%; HDM is >99% and HDCCR is >97%. This new methodology for upgrading the bottom-of-the-barrel can achieve the target of “zero fuel oil—zero coke goals. HP ACKNOWLEDGMENTS Revised and updated from an earlier presentation at the 3rd World Heavy Oil Congress, Nov. 3–5, 2009, Puerto La Cruz, Venezuela.

Development of the slurry-phase hydrocracking process from the lab to the first industrial unit has involved several skills in a number of disciplines and roles.

Many colleagues of Eni Refining & Marketing Division, Exploration & Production Division; Snamprogetti/Saipem with roles in the R&D, Engineering and project execution departments; and from the Taranto and Sannazzaro refineries have significantly contributed with their professional and personal commitment.

CCR CDU EPC EPCM 46

= = = =

NOMENCLATURE Conradson carbon (concarbon) residue Crude distillation unit Engineering procurement and construction Engineering procurement and construction management

I DECEMBER 2009 HYDROCARBON PROCESSING

Giacomo Rispoli is Senior Vice President and Director of R&D at Eni Refining & Marketing Division. In this position, he is responsible for managing development and application of Eni’s innovative technologies for refining and natural gas processing.

Previously, he was President and CEO of Eni’s Gela Refinery (Sicily), and Managing Director of Eni’s Venice Refinery. Dr. Rispoli joined Eni in 1986 and holds a degree in Chemical Engineering from the University of Rome.

Domenico Sanfilippo earned his Doctorate in Industrial Chemistry from the University of Catania in 1969 and is the Chief Scientist at the Eni Refining & Marketing Division. Since 2008, he is the Manager of Eni slurry technology (EST) technology in the industrialization projects. He joined Eni Group in 1970, spending most of his career in Snamprogetti S.p.A., Italy, where until 2008 he was the director of onshore technologies with the responsibility of licensing out and EPC contracting all proprietary technologies. He is a professor of scale-up of chemical plants at the University of Genoa.

Andrea Amoroso is Process Technology Vice President at Eni Refining & Marketing. He started his carrier in 1987 as process engineer for an Italian Engineering Company (CTIP) and joined Eni in 1992 as senior technologist. Since 1997 to 2005, he has been technology manager at Eni’s Sannazzaro Refinery. In 2005, he moved to Eni’s headquarters in Rome as technology manager. Mr. Amoroso holds a degree in chemical engineering.

PLANT DESIGN AND ENGINEERING

SPECIALREPORT

Executing a standard plant design using the 4X model Case study: A low-sulfur gasoline project on four identical process units J. T. O’CONNOR, University of Texas at Austin; V. P. DAMIANO, JR., Sunoco, Philadelphia, Pennsylvania; R. KULKARNI, ARK Project Management Solutions, Philadelphia, Pennsylvania; and P. CLARK, Fluor, Sunninghill, South Africa

W

hy don’t we all have custommade cars and clothes? A good reason is because it would be incredibly expensive. So, why hasn’t the industry been more successful in applying that lesson to capital projects? In fact, many organizations have attempted to build duplicate plants, striving to achieve significant cost and schedule savings by building from existing drawings. But, for many reasons, it never seems to work. If we just tweak this process variable, we’ll better match some feedstock variable; the equipment we bought four years ago has been upgraded and the vendor data has changed; the client has upgraded its specifications and standards and they “must” be applied; if we widen the pipe rack we’ll have better maintenance access, etc. There are many reasons that seem valid at the time; however, a truly standardized design never comes to fruition. The projects described in this case study are the exception.

Background. The Sunoco low-sulfur gasoline (LSG) project included four identical 65,000 barrels per day (bpd) gasoline desulfurization hydrotreater process units with a single design above ground. These units are located in four Sunoco refineries located in Pennsylvania, New Jersey and Ohio. After front-end design and planning was completed in Houston, the design contractor commenced detailed engineering for these units in Calgary and New Delhi in September 2003. The work in all four locations was targeted for completion to meet Environmental Protection Agency (EPA) Tier II regulations by January 1, 2006. This accomplishment would not have been possible without the 4X quadruple strategy, which allowed the project team to challenge several industry benchmarks.

The project scope initially included three identical gasoline desulfurization units in Sunoco’s refineries in Pennsylvania and Ohio.

Sunoco purchased a refinery in New Jersey in January 2004 and the 3X project became a 4X project. A “crash” front-end development program ensued for this additional plant and was assimilated into the design process starting in March 2004, approximately six months after the first three locations. Specific project features included: • Cost-reimbursable front-end loading (FEL) contractor • One engineering/procurement contractor via cost-reimbursable contract with incentives • Use of valve engineering center (VEC) in India with 50% of ISBL engineered by VEC • Highly modularized design: 105 pipe rack modules and 81 equipment modules • Two construction contractors that

worked at two sites, predominantly via cost reimbursable contracts with a fixed fee • Slightly staggered construction schedules • Emphasis on experience sharing from site to site • Core owner team that led the commissioning at all four sites.

In addition, the projects embraced a variety of value-improving practices, including value engineering, reliability modeling analysis, 3-D design, and constructability reviews. But the 4X standard plant design strategy presented a golden opportunity to challenge industry cost performance benchmarks. The four process units are identical above ground, with one process unit design, one plot plan and one set of ISBL drawings. The foundations are different due to differing soil conditions, and the utility and offsite facilities outside the process units are location-specific due

Sunoco, Inc. Low sulfur gasoline project project milestone schedule Description

2003

2004

2005

1 Engineering 2 Procurement 3 Construction Philadelphia Toledo Marcus Hook Eagle Point 4 Commission and startup

FIG. 1

4X LSG project milestone schedule.

HYDROCARBON PROCESSING DECEMBER 2009

I 47

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

to different refinery configurations. For the gasoline desulfurization process unit, there was only one 3-D model and one set of engineering deliverables. The equipment, modules, and bulk material specifications and fabrication were also identical for all four locations.

This unique opportunity started out as a client executive-level directive, along with a “just in time” project schedule to engender client corporate cash flow benefits. This strength of purpose helped fend off nearly all challenges for location-specific optimization within the process units.

The significance of this executive-level commitment, focus and support cannot be stressed enough. Without this level of commitment, the identical design would have fallen apart during the early stages of front-end development. Fig. 1 illustrates how the four projects were sequenced relative to each other.

There were a few 4X exceptions and deviations that could not be avoided. However, they were very limited in number and well controlled via a 4X deviation list and the project’s stringent management of change process. Deviation examples include: • ISBL drawing North arrow orientations • Building code-driven structural design details in New Jersey following the fourth site’s late addition • Compressor gearbox speeds to meet process requirements for different plant feedstock • Different control valve trim to meet process requirements for increased plant turndown for the fourth unit • Modified stripper column trays in the fourth plant for reduced normal throughput • Different maintenance power receptacles to suit existing refinery tools.

As the gasoline desulfurization process unit ISBL areas above ground were the only portion of the projects that were identical, it was important to distinguish work zones and to have a naming convention to differentiate the ISBL scope from the surrounding areas. This was achieved by labeling the sections of the project as follows: • ISBL–gasoline desulfurization process unit • Greater low-sulfur gasoline (GLSG)–area surrounding the ISBL unit and within the road perimeter containing local racks and utility systems • Outside battery limits (OSBL)– interconnecting racks and offsites facilities outside the GLSG road perimeter.

48

I DECEMBER 2009 HYDROCARBON PROCESSING

FIG. 2

Example of 4X LSG area definition (Eagle Point).

FIG. 3

LSG standard site development plot plan.

Engineering. With only one design

for all four process units, the design was completed by a single task force sized for a single unit design. This was only possible due to a single ISBL model and only one set of engineering deliverables for fabrication and construction. The engineering and procurement work was controlled with a work breakdown structure and corresponding work packages. In this case, the refinery location was part of the work breakdown string, as illustrated in Fig. 4.

Fig. 4 also shows how the work was further broken down by plant design area and discipline account (civil, piping etc.) and also module versus non-module. For the 4X ISBL scopes that were identical, this breakdown was still needed to send materials to each appropriate site loca-

tion, module yard and fabrication shop for quadruple fabrication. As only one set of drawings were produced for the 4X ISBL facilities, material control (in materials management) handled the 4X multiplication of all applicable 4X material. Single plant quantities were issued by engineering.

The project also pushed the envelope in work-share execution, with an engineering office in New Delhi, India that performed many new activities that were never done there before, such as a final piping isometric issue for the entire project. The New Delhi staff generally did the detailed design for the new facilities, including the identical 4X ISBL LSG units and the surrounding GLSG areas, that were different for each refinery. The

12760500 Low sulfur gasoline project

Sunoco STD 0010

1 12 4 LSG unit (including 3X) OSBL 1 00 6 Interconnecting pipe racks, sewers, equipment and buildings.

Inst./control sys. tankage, utilities, and flare modifications.

FIG. 4

2 09 5 LSG unit (including 3X) OSBL 2 00 6 Interconnecting pipe racks, sewers, equipment and buildings.

Inst./control sys. tankage, utilities, and flare modifications.

8 51 1 LSG unit (including 3X) OSBL 8 00 6 Interconnecting pipe racks, sewers, equipment and buildings.

Inst./control sys. tankage, utilities, and flare modifications.

Description

Unit no.

Area Unit Refinery location

Description

Unit no.

Plant no.

Area Unit Refinery location

Description

Philadelphia Refinery location 9

Plant no.

Eagle Point Refinery location 8

Unit no.

Area Unit Plant no.

Description

Unit no.

Plant no.

Refinery location

Area Unit

Toledo Refinery location 2

Refinery location

Marcus Hook Refinery location 1

9 87 0 LSG unit (including 3X) OSBL 9 00 6 Interconnecting pipe racks, sewers, equipment and buildings.

Inst./control sys. tankage, utilities, and flare modifications.

4X LSG partial work breakdown structure.

TABLE 1. Analysis of engineering and design cost savings Actual ISBL eng. cost with 4X ISBL strategy

Estimated ISBL eng. cost with conventional strategy

No.

Unit

0

4X ISBL

1

Philadelphia (3X)

$14.6 MM

2

Marcus Hook (3X)

$13.3 MM

3

Toledo (3X)

$13.3 MM

4

Eagle Point (4X)

$13.5 MM

Total

Estimated cost savings

$15.6 MM

$15.6 MM

New Delhi staff also did some OSBL design for new OSBL pipe racks.

Late release of 4X, Eagle Point.

Sunoco purchased the Eagle Point refinery in Westville, New Jersey, in January 2004.

The gasoline production at the Eagle Point refinery is approximately 50% of the 3X LSG plant capacities; therefore, the LSG hydrotreater unit for the Eagle Point refinery needed to operate consistently at 50% turndown in all conditions.

A process screening study was completed by an engineering company for Sunoco in fall 2003. This was done before acquiring the refinery to determine alternative solutions for the Eagle Point operating case with minimum deviations from the current 3X ISBL gasoline desulfurization unit design.

The following options were evaluated for the Eagle Point LSG unit: • Optimize the plant size entirely based

$54.7 MM

$39.1 MM

on the same layout as the 3X units, resizing for the different footprint • Keep the unit layout, spacing and structures the same as the 3X units; reduce the equipment and line sizes for the reduced capacity hydraulics • Preserve the 3X design and only modify the design for the plant to work at the reduced capacity. Treat this design as if the 3X units were already built.

The last option was selected as the goforward design basis, and front-end development commenced in January 2004 to define the required 4X LSG deviations and develop the GLSG/OSBL design. The goal was to add this plant to the 3X design concept and achieve a 4X design with minimal impact. This extended the previous value improving opportunity and minimizing scheduling to meet the January 2006 EPA Tier II deadline at Eagle Point.

Detailed engineering and procurement for Eagle Point commenced in March

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PLANT DESIGN AND ENGINEERING

FIG. 5

July 2004, Philadelphia.

FIG. 7

November 2004, Philadelphia.

FIG. 9

Module construction at Philadelphia.

FIG. 6

July 2004, Toledo, Ohio.

FIG. 8

November 2004, Toledo, Ohio.

FIG. 10

Same module construction for Eagle Point.

2004, approximately six months after the first three locations. The most significant physical impact of introducing the fourth unit was the change in seismic design criteria for structural steel. The fourth location introduced different state requirements for New Jersey where the local seismic criteria under the International Building Code became the governing design criteria. This impact was handled by modifying and reinforcing structural steel moment connections in the ISBL process unit for all four locations, still preserving a single steel design right through fabrication. This was achieved with very little impact to the 3X schedule and with the changes being marked on the steel fabrication drawings during the squad check cycle. In fact, the cost impact of modifying and reinforcing structural steel connections was an insignificant cost compared to the cost and schedule benefits from preserving the standard 4X design.

The addition of a third state also required the Calgary-based engineers-of-record to obtain registration as professional engineers in New Jersey. This posed a challenge for one lead designer, resulting in some delay from the required registration process.

Sizing of in-line instruments and administration of all instruments were also 50

I DECEMBER 2009 HYDROCARBON PROCESSING

challenges for the original 3X and then 4X deviations. With slightly different stream data between the various sites, the internals of some instruments had to vary to achieve specific plant process conditions. A single instrument database was also maintained during the detailed design of the 4X process units.

Procurement. Individual process unit

tag numbers for equipment, instruments and tagged piping specialty items were loaded into a material manager automated tool and individually tracked through the full procurement cycle through delivery to the appropriate module yard or site.

Bulks were also identified singularly in downloads from engineering and replicated by material control. Destinations and schedule-driven delivery sequences for all materials were controlled according to the work packages established by engineering.

The 4X LSG process units were extensively modularized, including pipe-rack modules, equipment modules and dressed vessels. The module orders were split into two packages—equipment modules and pipe-rack modules—to avoid overloading any one shop and as a risk-mitigation strategy. The original orders included all ISBL,

GLSG and OSBL modules for the original three sites only. Supplemental orders for the 4X scope were made to the same module yards for the same modules.

Due to the location of Toledo and the Great Lakes and local river system freezing up, it was necessary to prioritize the barge loads into Toledo first. All other materials were prioritized by plant completion date, Philadelphia being first. Figs. 9 and 10 show module fabrication progress at different sites, photographed the same day.

Construction. During front-end devel-

opment, the generic LSG path of construction was established and the sequence of design was adjusted to support that path.

This sequence was later confirmed by the two construction companies hired by Sunoco.

However, as construction commenced, site conditions (e.g., restraints due to pipe rack around the Philadelphia LSG site), contractor planning efforts and different capabilities of the constructors led to different field sequences, as shown in Figs. 5–8.

Cost optimization and savings.

The 4X strategy in the LSG project execution resulted in cost optimization and cost

PLANT DESIGN AND ENGINEERING

SPECIALREPORT

savings in several different areas, as further described. Contractorâ&#x20AC;&#x2122;s engineering and project management was based on the tabulated cost data in Tables 1 and 2. It is estimated that, through standardized plant design, the ISBL 4X strategy optimized the cost by approximately $39.1 MM in engineering and design and $7.2 MM in project services. Project service efficiencies resulted from more proficient approaches to project management, project controls, procurement, QA/QC and IT. For example, training development, startup procedures and process simulators were duplicates associated with manpower savings. Together, these two cost savings resulted in an overall estimated savings of $46.3 MM. Equipment and material procurement. Since the majority of 3X equip-

ment and materials were purchased via competitive bidding, vendors quoted their best prices for 3X equipment inclusive of any cost savings due to volume discounts, fabrication learning curve effects and risk reduction. As indicated in Table 3, the procurement savings realized on the 3X projects is conservatively estimated at 5%

FIG. 11

Final construction for Philadelphia.

of the total equipment and materials cost, amounting to $5.78 MM. However, the equipment and materials for the fourth X (Eagle Point) was ordered about eight to 10 months after the 3X purchases. During that period, the industrial

sector experienced a steep cost escalation of approximately 8%. Also, since procurement of the 4X equipment and materials was from the same vendors selected for the 3X, there was less competitive pressure on them to further optimize their cost. The end result

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HYDROCARBON PROCESSING DECEMBER 2009

I 51

SPECIALREPORT

PLANT DESIGN AND ENGINEERING TABLE 5. Analysis of overall cost savings

TABLE 2. Analysis of project services cost savings Actual ISBL eng. cost with 4X ISBL strategy

Estimated ISBL eng. cost with conventional strategy

No.

Unit

1

Philadelphia (3X)

$4.7 MM

$6.8 MM

2

Marcus Hook (3X)

$4.7 MM

$6.5 MM

3

Toledo (3X)

$4.4 MM

$6.2 MM

4

Eagle Point (4X)

$4.1 MM

$5.7 MM

Total

$18.0 MM

$25.2 MM

Estimated cost savings

$7.2 MM

TABLE 3. Analysis of equipment and material cost savings No.

Unit equip. and mat. cost

Optimization effects

% savings

Savings

1

PHL/MH/TOL (3X) $115.6 MM ($38.53 per site)

Volume discounts, fabrication learning curve, risk reduction

5

$5.78MM

2

Eagle Point (4X) $41.2 MM

Fabrication learning curve, risk reduction

2

Total

$156.8 MM

$0.82MM $6.6 MM

was that the material and equipment cost savings for the Eagle Point site was reduced to approximately 2% or $0.82 MM. Owner’s oversight and program management. It is estimated that a

As detailed in Table 4, after the Philadelphia project, for each of the three subsequent sites, 11 days–or 36.7%–of startup duration and effort were saved. In all, 33 days of team effort in startup were saved with the 4X strategy. It is estimated that this saved a total of 58 person-months. During the startup period the plant operated on a 24-hour basis, so the estimated cost savings from this reduced effort is estimated to be $1.3 MM.

No.

Item

1

Engineering and design

$39.1

2

Project services

$7.2

3

Equipment/materials

$6.6

4

Owner’s oversight program

$2.2

5

Startup and commissioning

$1.3

Total savings

$56.4

Overall cost optimization. The conservative estimate of the overall savings in the 4X execution strategy is listed in Table 5.

Thus, from these five sources, the total cost savings amounted to $56.4 MM. Spread over the three subsequent projects, this amounted to approximately 12.7% of the total installed cost when compared to applying the conventional approach for the three subsequent sites. The estimate is considered to be conservative as it only includes an allowance for savings from equipment, fabricated components, module assembly and large-bore pipe fabrication. These savings were substantial, but difficult to track due to the lump-sum nature of the contracts.

A quantitative benchmarking was performed and the competitiveness of this project was also assessed.1 Fig. 12 illustrates how cost effective by the 4X LSG project installed its ISBL scope compared to peer projects.

$2.2 MM (or 128 person-months) effort was saved in reducing the owner’s oversight costs from a more efficient approach in managing the ISBL engineering and construction efforts for the 4X project. In the current business climate, with shortages of experienced project TABLE 4. Analysis of startup time and effort savings professionals, this type of savings Pre-startup Startup Total Days can be a key benefit from plant No. Refinery days days days saved design standardization.

1

Philadelphia (3X)

18

12

30

0

2

Startup schedule benefits. The Philadelphia LSG 3

Marcus Hook (3X)

7

12

19

11

Toledo (3X)

7

12

19

11

unit was started first and, after mechanical completion, a period of 18 days was spent in prestartup of the unit in commissioning instrumentation and the control system. The actual unit startup was subsequently done in 12 days. The lessons learned in commissioning and startup of instrumentation and the control system were transferred to the Toledo, Marcus Hook and Eagle Point sites. Since the startup of Philadelphia and Toledo overlapped, two independent teams were required. However, a common commissioning team traveled to the startups of the Marcus Hook and Eagle Point facilities.

Eagle Point (4X)

7

12

19

11

52

4

80% 50%

25% of projects lower

75% of projects lower

10% of projects lower

90% of projects lower Actual cost Philadelphia, Toledo, Marcus Hook, Eagle Point

Costs 2006 USD FIG. 12

I DECEMBER 2009 HYDROCARBON PROCESSING

Amount ($ MM)

Industry benchmark

4X LSG cost effectiveness relative to industry benchmarks.

Other benefits: Lessons learned. Lessons learned were

shared with each of the sites on a regular basis via conference calls and/or by exchanging regular visits by key construction supervision staff.

The following activities benefitted substantially from the experienced-based learnings from the Philadelphia LSG unit and included: • Module transportation and erection sequence • Underground piping • System testing and handover • Testing of instrumentation and control system.

The following activities benefited from lessons that were learned in Philadelphia and reapplied at Marcus Hook: • Underground piping and sewer system • Rigging planning for heavy lifts and modules

PLANT DESIGN AND ENGINEERING • Scaffolding planning • Piping erection sequence.

Since the labor force in Eagle Point was totally different than that of Philadelphia, Marcus Hook and Toledo, the Eagle Point lessons-learned were limited to construction, planning and management issues, such as underground piping and sewer systems, and rigging planning for heavy lifts and modules.

value management processes, design effectiveness, Industrial piping processes, and job-site organizations.

He is a University of Texas instructor for graduate and undergraduate level students. Mr. O’Connor has given instruction on more than 170 industry short courses on a wide variety of project-related topics. He has received numerous honors including the CII Outstanding Researcher Award, 2005; ASHTO/FHWA National Quality Initiative Award, 1999; AASHTO/FHWA National Value Engineering Award, 1997; ASCE Thomas Fitch Rowland Prize, 1995 and 1987; Best Paper, International Symposium on Automation and Robotics in Construction, 1993; and Ervin S. Perry Young Engineer of the Year, TSPE, Travis Chapter, 1990.

■ Effective strategy

implementation requires a discipline for which perhaps few organizations are prepared to adhere to.

Conclusion. Applying the standard plant design engineering strategy with subsequent replication of construction at several sites can contribute substantially to a project team’s ability to achieve the owner’s targeted project value objectives. The capital projects industry should view the strategy as a major opportunity for replicating the magnitude of productivity gains experienced by the manufacturing sector over the last 30 years.

Yet, effective strategy implementation will require a discipline for which perhaps few organizations are prepared to adhere to.

Thus, as discussed in this case study, the owner’s commitment to the strategy is of paramount significance. HP 1

LITERATURE CITED Sonnhalter, K. and A. Aschman, A Closeout of the Low Sulfur Gasoline Program, Independent Project Analysis, Inc., Report SNC-6011-CLO, Reston, Virginia, August 2006.

James T. O’Connor has industry experience with the US Army Corps of Engineers, Jewell Planning and Construction, and Murray Jones Murray, Inc. He has had more than 45 consulting and contract claims/expert witness engagements.

Mr. O’Connor has authored or co-author more than 25 monographs/course manuals, 140 refereed journal and conference articles, and 110 technical reports. He’s been the principal investigator on more than 50 funded studies totaling nearly $14 million. Mr. O’Connor is Construction Industry Institute’s (CII’s) principal investigator in the areas of constructability, planning for startup,

Phil Clark is vice president of project management in Fluor Corporation’s Energy & Chemicals business line. Mr. Clark has nearly 30 years industry experience in various oil refineries and petrochemical plants around the globe. His project management experience includes both grassroots and revamp projects, domestic and international mega-projects and managing integrated and joint-venture project teams. Mr. Clark’s projects have been extensively modularized and more recent projects have involved a high percentage of workshare with Fluor’s Global Execution Center in New Delhi. He received bachelor and graduate degrees in mechanical engineering from the University of Birmingham, UK. Mr. Clark is a member of the Association of Professional Engineers, Geologists and Geophysicists of Alberta and the Project Management Institute.

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Ravi Kulkarni is the principal consultant for ARK Project Management Solutions, Inc, US, with over 30 years of experience with EPC contractors as well as owners in the execution of capital projects for refineries and petrochemical plants. Mr. Kulkarni specializes in developing contracting strategies and commercial evaluations, risk assessments, project overviews, project controls, estimate developments and reviews, procurement and training. He has overseen projects in Korea, Egypt and Abu Dhabi, as well as in various locations in the US. Mr. Kulkarni is based in New Jersey, US, but operates worldwide.

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Case history: Benchmarks achieved in a residue upgrading project This energy company aggressively implemented a mega-project safely and under budget with a new approach S. H. KWON, B. H. SOHN, Y. M. JEON, S. J. KIM, Y. W. SHIN and Y. S. OK, SK Energy Co., Ltd., Ulsan, Korea

Background. SK Energy (SK)is the largest petroleum refining company in Korea, and it has a combined crude oil throughput of 1.115 million bpsd. SK had several reasons to install the No. 2 FCC Project at the Ulsan refinery to: • Meet environmental regulations and to enhance price competitiveness in the global fuels market • Decrease surplus bunker-C production as global demand for fuel declines over even more stricter environmental regulations • Increased gasoline output to meet growing demand through 2010 • Increase the complexity ratio of this refinery, which is lower than the other Korean refineries.

The main onsite support units include the hydrogen plant (which supplies highpurity hydrogen to the RHDS), amineregeneration units, sour-water-treating units, sulfur-recovery units (SRU), utilities and offsite facilities. While self-sufficient, all of the processing units are integrated within the existing refinery, thus increasing the total reliability of this facility.

SK selected the atmospheric Residue Hydrodesulfurizer (RHDS) + Residue Fluid Catalytic Cracker (RFCC) combination to add flexibility to the overall refinery thus allowing the new facilities to process heavier sour crudes. The No. 2 FCC project would ensure SK’s competitive standing within the petroleum business by increasing

Initial project goals. The overall project goals were identified during a feasibility study and the project planning phase. The project goals emphasized schedule, quality, cost and safety: • Schedule. The project was planned for 35 months, from FEED until sustained on-spec production by all units. The scheduled targeted completion was June 2008, with commercial startup by the end of September 2008.

• Quality. The goals mandated a startup with onstream factor for the main Units: thousand bpd Sulfur (510 tpd)

SRP (620 tpd)

H2S C3 (15.1)

Fuel gas (2) Propylene (11.8)

PRU (972 tpd)

Propane (3.2)

C4 (8) Fuel gas (0.3)

Isomerization (13)

AR

The No. 2 FCC project. As shown in

Fig. 1, the No. 2 FCC project will upgrade atmospheric residue by first desulfurizing the feed to less than 0.5% sulfur via the residue hydrodesulfurization (RHDS) unit.

The lower-sulfur bottoms stream is sent to the residue fluid catalytic cracker (RFCC).

Cracked products from the RFCC are further treated and/or processed by downstream units to produce low-sulfur FCC gasoline, sweeten refinery fuel gas, polymergrade propylene, LPG, alkylate, light-cycle oil (LCO) and heavy fuel-oil components.

the production of high-octane gasoline and other products that meet environmentally driven specifications.

(80) H2

C3/C4 (0.6)

C4= (14.5)

Naph (2.2)

SHP (14.5)

No. 2 RHDS DSL (16.8) (80) L/S B-C (60)

Gasoline (22)

Alkylation (18)

nC4 (13) Alkylate (17.5)

Sulfuric acid SAR (180 tpd) GDS (30)

T-gasoline (22)

HCN (7.4)

HP (110 MSCFD)

LCO (2.9) B-C (3.6)

FIG. 1

No. 2 RFCC (60)

S

K Energy’s residual fluid catalytic cracking (FCC) project was a $2 billion-capital project that was successfully implemented in less than 31 months— from front-end engineering design (FEED) through on-specification product operations. This case history identifies the key factors that were applied to achieve this historical project on schedule and without exceeding the allocated budget.

SLO (5)

Process flow diagram of the No. 2 FCC project.

HYDROCARBON PROCESSING DECEMBER 2009

I 55

SPECIALREPORT

PLANT DESIGN AND ENGINEERING is challenging, but the goals are achievable through the willingness of all project members to engage openly in developing new working concepts and ideas through brainstorming and team buy-in.

Project champion

Project director

Startup director

PT-1

PT-2

PT-3

PCT

LEC-1

LEC-3

LEC-2

LEC-4

PET

ST-1

ST-2

ST-3

Tech team

Support team (Existing)

MT

n PT - Project Team, PCT - Project Control and Procurement Team n ST - Startup Team, MT - Maintenance Team n PET - Process Engineering Team FIG. 2

Project management team for the No. 2 FCC.

TABLE 1. Work breakdown structure (WBS) for No. 2 FCC project Process section

FEED

Detailed engineering

RHDS, Hydrogen

FEC

LEC-1

FEC

LEC-1

Construction LEC-1

PRU2

FEC

LEC-2

FEC

LEC-2

LEC-2

Sulfur, alkylation, isomerization

FEC

LEC-3

FEC

LEC-3

LEC-3

LEC-4

LEC-4

—

LEC-4

LEC-4

RFCC,

GDS1,

Procurement Critical Non-critical

Utilities and offsites • • • • •

FEC - Front-end engineering contractor LEC-1 - Local engineering contractor-1 LEC-2 - Local engineering contractor-2* LEC-3 - Local engineering contractor-3 LEC-4 - Local engineering contractor-4*

Operation structure. In considering

* LEC-2 and LEC-4 are the same company 1 Gasoline desulfurization 2 Propylene recovery unit

process units (RHDS and RFCC) greater than 0.95. (Onstream factor = Actual treated quantities for 90 days after initial startup divided by design capacity.)

• Cost. The project had to be completed under $2 billion.

• Safety. The aim was to have no serious injury during the project.

SK’s managerial operating philosophy, “Super excellent methods (SUPEX)”, was introduced at the project planning stage to accomplish the specified goals. SUPEX

(Left) Under construction May, 2007. (Right) Under construction September, 2007.

56

I DECEMBER 2009 HYDROCARBON PROCESSING

Project execution strategies. Based on the strengths, weaknesses, opportunities, and threats (SWOT) analysis and considering the project environment, such as the oil and petrochemical engineering industry, material and equipment market, and SK’s experience in mega-scale projects, SK elected to execute the project under these strategies: • Establish a strong owner-management team with single responsibility for EPC and initial startup • Early on, select the single front-end engineering (FEC) contractor, with the technical expertise, for basic engineering and critical equipment procurement services • Select early multiple local engineering contractors (LECs) to perform detailed engineering and procurement services except for critical equipment and construction services • Procure equipment and materials early • Promote teamwork among all partners—SK, technology licensors, FEC, LECs and vendors.

• Reinforced quality management driven by SK.

the project schedule and limited engineering resources of local engineering contractors, SK divided the process area into four sections, as shown in Table 1.

Implementing project strategies.

One of the key factors to achieve challenging project goals is timely and correct deci-

PLANT DESIGN AND ENGINEERING TABLE 2. Project master schedule, Description

2005

Plan 2006

Actual 2007

2008

Feasibility study by SK Process design by licensors Basic FEC design Detailed Design by LECs Procurement for critical equipment Procurement for all other equipment Site preparation Construction Pre-commissioning & commissioning Commercial operation

Remarks (actual) 4.2004–4.2005 5.2005–7.2006 11.2005–4.2007 6.2006–9.2007 7.2005–2.2008 2.2006–2.2008 6.2006–12.2006 12.2006–3.2008 4.2008–6.2008 6.2008–

execution. SK selected the FEC before the licensor design was Description Plan Actual Remarks completed and the Schedule, months 35 31 From FEED to commercial operation LECs before completion of the FEED Quality 0.95 0.99 Onstream factor package to enable Cost, $ billion 2 1.95 parallel work of licenSafety No serious injury No serious injury sor design, FEED, procurement and sion making by management. SK estab- construction, as shown in Table 2. SK used lished a single responsibility organization, in-house data for the FEC and LECs selection which is well aligned with the project’s work since materials for the ITB was not available break down structure (WBS) as shown in at the time of choosing contractors.

Fig. 2. To enable quick decisions, the projSingle front-end engineering conect champion had total responsibility over tractor. Basic engineering was done in decision makings for the EPC execution Cambridge, Massachusetts, and Houston, and initial startup. The assigned team man- Texas, by the FEC. To maintain design agers had ample experience in similar proj- consistency among multiple processes, SK ects. In addition, SK eliminated the project selected one FEC to provide FEED packmanagement consultant (PMC) function, ages, which included: which could be a bottleneck in the quick • Review of licensor process design decision-making process. (However, SK • Coordination of licensor process added that function into the management design work team’s duties.)

• Process design of non-licensed process Early selection of FEC and LECs for facilities parallel project execution. To achieve this • Basic engineering of all process facilities unprecedented fast-track project schedule, SK • Procurement services for critical had no choice but to adopt a parallel-project equipment such as preparing RFQ, evaluatexecution approach instead of phase-by-phase ing proposals and reviewing vendor prints.

TABLE 3. Initial goals vs. achievements

SPECIALREPORT

Multiple LECs. Considering the project scale and limited resources of the LECs, SK selected four local engineering contractors to perform detailed engineering, procurement, construction and precommissioning. Early selection of LECs enabled them to be familiar with the FEED and to commence detailed design in parallel with FEED work. This parallel execution of basic engineering and detailed design contributed significantly to achieving the project’s 31-month duration. With four LECs, it was necessary to designate a lead LEC who was responsible for ensuring consistency in four LECs’ detailed engineering works among the processes in applying design criteria, specifications, materials, etc.

Early procurement of equipment.

The tight seller market forced SK to adopt these approaches in procuring equipment and materials: • Classify and identify “critical” and “non-critical” equipment based on the procurement cycles using in-house data.

• Prepare and issue RFQs for “critical” equipment using licensor information and finalizing the purchase order amount during bid clarification phase or later. For example, SK purchased RHDS reactors and separators using in-house data before completion of licensor design with the condition to change the purchase order amount inline with the actual design and to secure the manufacturer’s shop space.

• Introduce an incentive program to the FEC for early issuing of equipment datasheets to support early procurement.

Teamwork among all partners. With eight licensors, one FEC and four LECs, it was essential to have good teamwork for a successful project. Teamwork involved: • Shared project goals with the FEC and the LECs.

(Left) After mechanical completion March, 2008. (Right) After startup, June 2008.

HYDROCARBON PROCESSING DECEMBER 2009

I 57

SPECIALREPORT

PLANT DESIGN AND ENGINEERING

• Project managers of LECs participated in the monthly review meetings with the FEC • Project managers and construction managers of the LECs participated in the monthly review meetings with other LECs. • Team-building workshops were conducted.

Reinforced quality management driven by SK. The Quality Management Plan (QMP) provided a road map to ensure that the plant had a once-through startup.

The QMP contains programs for qualityassurance activities required during all phases of the project, i.e., basic engineering, detailed engineering, procurement and construction. The No. 2 FCC QMP contained these details: • Quality management organization • How to check the requirements from licensors, codes and specifications • Optimum sizing/operability/maintainability/reliability specs • Inspection plan at the manufacturers’ shop • Checklist to inspect materials on their arrival at the site • Checklist to inspect workability during construction

TABLE 4. On-specifications of main process units Units

Main products

Main properties

Product specification

Actual operation

RHDS

Treated AR

Total sulfur, wt%

Max. 0.5

< 0.5

HP

Hydrogen

Purity, vol.%

Min. 99.9

> 99.9

RFCC

LCN

RON

Min. 91

> 91

PRU1

Propylene

Purity, vol.%

Min. 99.65

> 99.65

Alkylation GDS2 1 2

Alkylate

RON

Min. 95

> 95

Treated LCN

Total sulfur, wppm

Max. 10

< 10

Propylene recovery unit Gasoline desulfurization

• Quality patrol plan at the site to ensure the check points were inspected • Lessons learned from operation, maintenance and troubleshooting of existing facilities.

Performance of FCC project. SK achieved project goals in every aspect as shown in Table 3. It took 90 days from mechanical completion to get final on-specification for all units of SK’s existing No. 1 FCC plant. For the No. 2 FCC plant, it just took 72 days to achieve on-spec product requirements. The dates of major activities that SK achieved after mechanical completion included:

• Mechanical completion of all units— March 31, 2008 • On-specification of hydrogen unit— May 8, 2008 • On-specification of RHDS unit— May 31, 2008 • On-specification of RFCC/GDS units—June 11, 2008 • On-specification of alkylation unit— June 12, 2008.

SK achieved each design capacity for its main units on June 25, 2008. Also, SK achieved all product specifications, as shown in Table 4.

The plant has been operating without a shutdown since the initial startup on June 12,

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I DECEMBER 2009 HYDROCARBON PROCESSING

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PLANT DESIGN AND ENGINEERING 2008. SK tried to maximize the capacity of its No. 2 FCC plant using design margins. The company achieved this goal as shown here: • Achieved capacity of RHDS unit: 86,000 bpsd (design capacity: 80,000 bpsd) • Achieved capacity of RFCC unit: 73,000 bpsd (design capacity: 60,000 bpsd) Outlook. When SK began the No. 2 FCC

project in the second quarter of 2005, the engineering and construction industry in Korea was at a peak. Not only was the E&C business very busy, but fabricatedequipment industry was in an even higher demand. In addition, raw material prices were higher than in previous years. Much of the higher costs were driven by various similar projects in China. Also, other major competing projects were being designed and constructed in Korea at the same time and included: • SKC—HPPO project • Samsung Total Petrochemicals Co. Ltd.—Styrene revamp project • LG Chem. Ltd.—Styrene revamp project • GS Caltex Corporation—No. 2 HOU Project.

To overcome these challenges, SK implemented these practices: • SK had a strong project management team with single responsibility • Early awards of long-lead fabricated equipment were assigned to vendors, FEC, LECs and licensors • Planned an early engagement of FEC and LECs • Teamwork with SK, the FEC and the LECs was promoted • Quality management driven and reinforced by SK • SK gave accurate information based on requests to meet the needs of other groups involved with the project.

The decisions made by the SK project team were able to meet and even beat all requirements for safety, cost, schedule and quality. Although the initial goals were very aggressive, SK was able to shorten the project schedule by four months without exceeding the budget and with simultaneously achieving all other project objectives. HP ACKNOWLEDGMENT The authors believe that one of the key success factors of this project was due to strong leadership of Mr. Sang-Il Lee, project champion, and much devoted

TABLE 5. Key project people in addition to authors Company

Name

Title

SK Energy Co.

Sang-Il Lee

Project champion

SK Energy Co.

Kwoan-Ho Choi

Senior planning director

SK Energy Co.

Nam-Kyu Choi

Planning director

SK Energy Co.

Jeong-Sik Kim

Start-up director

SK Energy Co.

Yong-Won Nam

Process engineering team manager

SK Energy Co.

Jae-Youn Kim

Maintenance team manager

SK Energy Co.

Dong-Ho Kim

Start-up team No. 1 manager

SK Energy Co.

Man-Kyu Song

Start-up team No. 2 manager

SK Energy Co.

Jeong-Don Seo

Start-up team No. 3 manager

SK Energy Co.

Choo-Jei Kim

Technical support team manager

FEC

Mel. Barnett

Project director, FEC

LEC-1

Hyung-Taek Park

Project director, LEC-1

LEC-1

Young-Chul Kang

Project manager, LEC-1

LEC-1

Heon-Jae Lim

Construction manager, LEC-1

LEC-2

Myung-Soo Lee

Project manager, LEC-2

LEC-2

Jong-Hwa Lim

Construction manager, LEC-2

LEC-3

Yoon-Taek Oh

Project director, LEC-3

LEC-3

Dong-Chul Cha

Project manager, LEC-3

LEC-3

Young-Ki Kim

Construction manager, LEC-3

LEC-4

Ho-Jeong Kim

Project manager, LEC-4

LEC-4

Won-Ki Lee

Construction manager, LEC-4

LEC-2 & 4

Jai-June Kang

Project director, LEC-2 & 4

LEC-2 & 4

Moon-Soo Park

Construction director, LEC-2 & 4

SPECIALREPORT

cooperation from inside and outside of SK Energy.

For the No. 2 FCC project, these key persons were involved in addition to project organization are listed in Table 5.

Sook-Hyung (Sam) Kwon was a vice president and project director of the No. 2 FCC project at SK Energy Co. He holds an MS degree in chemical engineering from Yonsei University in Korea. He is a member of the Korean Professional Engineers Association, ISO Technical Committee-185 and API Standard Committee on Refinery Equipment. Mr. Kwon has 27 years of experience in petroleum refining and chemical process industries.

Byung-Heon Sohn was a project team No. 1 Manager of the No. 2 FCC project at SK Energy Co. He holds a BS degree in mechanical engineering and design from Seoul National University in Korea. He has 26 years of experience in project management and procurement for the petroleum refining and chemical process industries.

Yang-Myung Jeon was a project control and procurement team manager of the No. 2 FCC project at SK Energy Co. He holds a BS degree in mechanical engineering from Busan National University in Korea. He has 23 years of experience in project engineering and plant maintenance for the petroleum refining and chemical process industries.

Sung-Joo Kim was a project team No. 2 manager of the No. 2 FCC project at SK Energy Co. He holds a BS degree in chemical engineering from Yonsei University in Korea. He has 22 years of experience in project management for the petroleum refining and chemical process industries.

Young-Wook Shin was a project team No. 3 manager of the No. 2 FCC project. He holds an MS degree in chemical engineering from Korea University in Korea. He has 27 years of experience in project and construction management in the field of petroleum refining, heavy-oil upgrading, utilities and offsite facilities.

Young-Seok Ok was a senior project engineer of the No .2 FCC project at SK Energy Co. He holds a BS degree in chemical engineering from Hanyang University in Korea. He has worked as a project and maintenance engineer in the petroleum refining and chemical process industries for 21 years.

HYDROCARBON PROCESSING DECEMBER 2009

I 59

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PUMPS/RELIABILITY

Think power pumps are self-priming? Think again!

Follow these guidelines to avoid damage T. HENSHAW, Consulting Engineer, Magnolia, Texas

T

he age-old myth: I’ve recently read, again, that power pumps are self-priming. At best, they just tend to be self-priming. Under the right conditions, they may self-prime. The article also said that power pumps can successfully pass quantities of gas. That, also, is not true.

I used to think that power pumps were self-priming. That’s what I read. I learned better.

They are poor compressors. These types of pumps typically

have a clearance volume that is 3 to 5 times the plunger displacement (Fig. 1) so they are poor compressors. When the pumping chamber is full of air, they are capable of producing only about 6 psig of pressure (with 15 psia of inlet pressure). That’s not enough to overcome the system discharge pressure.

Each pumping chamber of a reciprocating pump is an independent pumping entity, operating in parallel with each other chamber. A triplex pump has three chambers, a quintuplex—five.

It is possible for only one of these chambers to be primed, while all others remain vapor-locked. I’ve witnessed both triplex and quintuplex pumps in operation with only one pumping chamber primed. The results were reduced capacity, noisy (pounding) operation, high vibration and wildly swinging gage readings.

A pump will normally be full of air after maintenance, and

some chambers may gain air that leaks through the packing when the pump is idle. Often, upon startup, gas is drawn into the pump from the suction line. For these reasons, it is necessary that the discharge pressure be kept low (near suction pressure) during the first half-minute or so of operation. This gives each pumping chamber an opportunity to clear itself of gas and be operating fully primed when exposed to system discharge pressure. With most systems, it is possible to keep discharge pressure low only by having a by-pass line. This line should not connect to the pump suction, because the gases would again be ingested by the pump.

Fig. 2 shows the desired features of a power-pump system.

One of the features is a by-pass line connected back to the suction vessel.

Other benefits of starting unloaded. Other benefits

accrue from starting a power pump against negligible discharge pressure. The break-away torque will be only about 25% of full-load torque, allowing the use of a motor with normal starting torque, and reducing the time of inrush current. Drive components, such as couplings, gears and chains will not be overloaded. Also, the power end of the pump has an opportunity to establish full lubricating films on all sliding surfaces, and the plungers have an opportunity to become wetted by a lubricant and/or the pumpage.

Minimum liquid level Feed in Weir plate Vortex breaker

Line velocity 5–15 ft/sec Suction stabilizer

Long-radius elbow Full-opening valve

Clearance (C) Displacement (D)

FIG. 1

Power pumps are poor compressors.

Suction line velocity 1–3 ft/sec.

Eccentric reducer w/flat side up

FIG. 2

Relief valve w/ 10 percent max. pressure accumulation

Startup and capacitycontrol valve Pulsation dampener

Line velocity 3–10 ft/sec

Pump fluid Ample cylinder Minimum number of turns NPSHA good piping support

Properly designed reciprocating pump system.

HYDROCARBON PROCESSING DECEMBER 2009

I 61

PUMPS/RELIABILITY Gas symptoms. If during normal operation, the pump suddenly begins to run roughly, or the capacity drops suddenly, it is probable that gas has been ingested by one or more pumping chambers. With the previously suggested system, it is necessary only to open the by-pass valve until the pump clears itself.

Field experience. I was changing packing on some 5-in.-stroke triplex power pumps when an operator in another unit requested my presence. He said that his 3-in.-stroke quintuplex was pumping much less than its rated capacity. When I heard the pump run, it sounded like a six-cylinder engine with five spark plugs disconnected. It was pumping on just one plunger! The other four chambers were not primed! They were full of air—may have been that way since the packing was last changed. The system discharge pressure was holding the four discharge valves closed, preventing the air from being discharged. The capacity was only 20% of rated.

I told the operator to open the valve in the by-pass line so the pump could prime itself. By-pass line? The system didn’t have one. We found a gage connection between the pump discharge connection and the system check valve, opened it, and started and stopped the pump numerous times. As the pump coasted to a stop, it would occasionally spit out some air. It finally reestablished prime, was put on line, and pumped at rated flow.

On another occasion, I completed installation of new-design stuffing boxes on a 5-in.-stroke triplex in a “charging” service. I asked the operator to place the pump in service. It started to roll, quickly priming one pumping chamber, but the other two chambers did not prime. The discharge pressure gage began swinging from about 30 psig to 2,300 psig. The pump was shaking. The discharge pipe was vibrating severely. I quickly told the operator to shut it down and open the valve in the by-pass line. There was none!

We disconnected a discharge pressure gage and alternately opened and closed valves in the suction line and gage line. The 30-psig suction pressure allowed us to compress the air in the two air-locked chambers, then bleed the pressure off through the gage connection.

Finally, all the air was bled from the pump, and it was started (against system discharge pressure!). The pump operated satisfactorily.

The operator told me that normal starting procedure was to let the pump hammer and pound until it somehow managed to dispel the air. He said that it could take days to become fully primed.

A plant in Florida reported its triplex charging pump was running fine, then just quit pumping. A plant in New York reported that its quintuplex was running fine, then the capacity dropped 40%. The operators and engineers failed to recognize the symptom of these pumps ingesting gas. They thought that the pumps would compress the gas to discharge pressure and push it through the discharge valves.

The slamming and pounding caused by partially primed pumping chambers shortened the valve and packing lives, and led to the fracture of some of the forged stainless-steel pump fluid cylinders.

For months the cause of this “vapor-locking” was a mystery, until a sharp-eyed engineer, pouring over system drawings, noticed that the suction vessel contained spray nozzles! The entering pumpage was sprayed through a hydrogen blanket, forcing the pumpage to become saturated, or super-saturated with hydrogen. (A suction vessel should be designed to remove gas—not add it!)

We learned that the hydrogen was injected into the pumpage to absorb any free oxygen in the system. We also learned that original plans called for a compressor to inject the hydrogen on the discharge side of the pump, but system designers concluded that the reciprocating pump was capable of compressing the hydrogen, and the compressor was not needed. That was a costly mistake.

62

I DECEMBER 2009 HYDROCARBON PROCESSING

A plant in Tennessee was experiencing similar problems with its charging pumps. The problem was assigned to one of its top engineers. After a few telephone conversations with this author, he recognized the problem and set about to minimize the impact of the hydrogen on system operations. He learned that the pressure on the suction vessel would sometimes be dropped quickly, allowing the hydrogen dissolved in the pumpage in the suction line to flash out of solution. He likened it to popping the cork on a bottle of champagne. He changed the operating procedure to reduce the rate at which the pressure would be changed. In a desperation move, to keep the pumps operating when they would ingest quantities of hydrogen, he drilled a small hole through each discharge valve, deliberately creating a leaking valve. When a slug of hydrogen would “lock” a pumping chamber, pumpage under discharge pressure would leak from the discharge manifold, through the valve, and into the pumping chamber, compressing the hydrogen and allowing the chamber to reprime itself. (Pulsations must have been severe during repriming.)

A designer/builder of gas processing plants once told me that, to prime a new power pump before operation, he would partially disassemble the liquid end and fill each pumping chamber with liquid. He was glad to learn that this laborious procedure could be replaced by a by-pass line.

Summary. Are power pumps self-priming? Only during startup

if the discharge pressure approximates suction pressure.

Does this apply to all power pumps? No. High-speed units require extra-strong springs on the valves for smooth operation, resulting in high cracking pressures, resulting in more difficult priming. The suction pressure may need to exceed discharge pressure to fully prime the pump, but high-speed pumps typically have booster pumps (to provide the necessary NPSH) that can be used to help prime the power pump.

Recommendations.

• Don’t believe the myth that power pumps are self-priming.

• Don’t believe the myth that power pumps can readily ingest quantities of gas.

• Do design your systems with by-pass lines.

• Do design your suction vessels to separate all free gas.

• Do establish startup procedures that assure that power pumps are fully primed prior to exposure to the system pressure.

Failure to follow these rules has resulted in very expensive operating and maintenance problems in numerous systems. HP Terry Henshaw is a consulting engineer. He designs centrifugal and reciprocating pumps (and related high-pressure equipment), consults for companies that build and use pumps, and conducts seminars on pumps. For 30 years Mr. Henshaw was employed by Ingersoll Rand and Union Pump in New York, Houston and Battle Creek Michigan; serving in the positions of sales engineer, reciprocating pump division manager, and research and development manager. He designed the original line of ultra-high-pressure water-jetting equipment for the NLB Corp. Mr. Henshaw served in various positions of the Hydraulic Institute, including chairman of the Reciprocating Pump Section, chairman of the Metrication Subcommittee, and as a member of various general and centrifugal pump subcommittees. He also served as a member of ANSI Subcommittee B73.2 that wrote the standard on in-line centrifugal pumps, as chairman of the API 674 manufacturers’ subcommittee which wrote the standard on reciprocating pumps and as a member of the ASME Performance Test Code Committee PTC 7.2. Mr. Henshaw authored a book on reciprocating pumps, a technical paper, several magazine articles on pumps and systems and the sections on pumps in the 11th edition of Marks’ Handbook. He has been awarded six patents. He is a licensed professional engineer in Texas and Michigan, is a life fellow of the ASME and holds engineering degrees from Rice University and the University of Houston.

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PROCESS ANALYZERS

Fine tune accuracy in analytic measurement—Part 3 Follow these steps to avoid compromising a sample D. NORDSTROM and T. WATERS, Swagelok Company, Solon, Ohio

The objective of an analytical instrumentation (AI) system is to provide a timely analytical result that represents the fluid in the process line at the time the sample was taken. If the AI system alters the sample so the analytical result is changed from what it would have been, then the sample is no longer representative and the outcome is no longer meaningful or useful. Assuming the sample is properly taken at the tap, it may still become unrepresentative under any of the following conditions: • Deadlegs or dead spaces are introduced at inappropriate locations in the AI system, resulting in a “static leak,” which may cause bleeding or leaking from the old sample into the new sample.

• The sample is altered through contamination, permeation or adsorption.

• The balance of chemicals is upset due to a partial change in phase; • The sample undergoes a chemical reaction.

The following information will review the major issues leading to an unrepresentative sample and provide recommendations on how to avoid a compromised sample. Discussion will cover in detail the following items: deadlegs and dead spaces; component design and placement; adsorption and permeation; internal and external leaks; cross-contamination in stream selection; and phase preservation.

Deadlegs and dead spaces. It’s important to understand

the difference between mixing volumes and deadlegs. They are not quite the same. A mixing volume is a reservoir with a separate inlet and an outlet, such as a filter or knock-out pot. Fluid flows through a mixing volume slowly. A deadleg is typically a tee formation with a block at the end so there is no through-flow (Fig. 1). Examples of deadlegs are pressure gauges, transducers, lab sampling valves, or relief valves. You can calculate the rate at which a mixing volume

Old sample New sample

FIG. 1

In this deadleg configuration, old sample trapped in the tee formation leaks into the main fluid stream, contaminating the new sample.

will flush an old sample, but the same is not true of a deadleg. A deadleg holds the old sample, allowing a small portion of it to mix with the new sample, contaminating it. Deadlegs may eventually clean up or may not. They do not behave in a predictable manner.

Generally, deadlegs become more problematic as the ratio of length to diameter increases. In addition, lower flow in the analytical line increases the degree of the deadleg’s effect. A pressure gauge with a deadleg volume of 10 cm3 may not have much effect in high flow, but in low flow (e.g., 30 cm3/min) it could—if located in the wrong place—compromise the whole application. Here are some general guidelines concerning deadlegs: 1. Use high flow rates whenever possible.

2. Select a component design that minimizes or eliminates deadlegs.

3. When installing the component, ensure that the end connection minimizes the length of the deadleg.

4. Remove deadlegs to a bypass loop, so that only the minimal number of deadleg components are in a direct line with the active flow to the analyzer.

5. Replace a tee and two-way ball valves with three-way ball valves.

In most systems, deadleg components can be positioned so most are not in a direct line with the active flow to the analyzer.

They may be placed on a bypass loop and will still serve their intended purpose. A bypass loop or a fast loop is a configuration that enables relatively fast flow in a loop, with a return to the process line or to a flare or drain. At one point in the loop, a part of the flow is diverted to the analyzer. Fig. 2 illustrates a system with five deadlegs, whereas Fig. 3 illustrates a variation of this configuration with the following improvements: • Two pressure gauges are removed to a bypass loop.

• One pressure gauge is removed without a replacement.

• The calibration gas inlet is moved to the stream selection system.

• The lab sample take-off is moved to a flow loop that originates at a filter.

When multiple fluid streams are running to the same analyzer by way of a stream selection system, components with deadlegs should, if at all possible, be placed before the stream selection system in a bypass or return line to minimize the potential for cross-stream contamination. The same is true of components with “memory,” i.e., components with a lot of surface area (filters) or with permeable materials, like elastomers (e.g., some regulators). For example, rather than locating one filter after the stream selection system, it is better to purchase multiple filters and HYDROCARBON PROCESSING DECEMBER 2009

I 65

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PROCESS ANALYZERS

Sample #3

Fast loop Quick-connect for lab sample port

Sample #2

Sample #1

PI

PI

PI

FI

Bypass loop

Analyzer Bypass loop

FI

FI

Steam selection system

Filter

Calibration gas inlet

Analyzer

Lab sample FIG. 2

Five deadlegs in this configuration pose the risk of contaminating the sample.

FIG. 4 Samples # 2 #3

Calibration gas inlet

Sample #1 Bypass loop FI

Switch streams

FI

Analyzer

PI PI

Bypass loop FI Lab sample

FIG. 3

A variation of Fig. 2, this configuration introduces design improvements that eliminate the deadlegs or move them to locations where they will not have an effect on the analyzer reading.

locate them before the stream selector system, one in each of the multiple lines. Similarly, it is not advisable to locate a lab sample port, with a tee and quick-connect, after the stream selection system because the tee configuration is a deadleg that may cause cross-stream contamination.

The ideal configuration (Fig. 4) would locate the lab sample port on a bypass loop—a separate bypass loop for each sample line—before the stream selection system. The lab sample port, gauges and other deadlegs can be located on the bypass loop, downstream of the point where flow is diverted to the analyzer.

An additional advantage to this configuration is that, while one stream is running to the analyzer, the other streams continue to flow through their respective bypass loops, keeping the sample current. Components with limited memory, those that can be safely located after the stream selection system, include some highquality regulators, shut-off valves, check valves and flow meters.

In the case of liquid samples, when there is minimal pressure drop through the analyzer, deadleg components, like gauges, may be located after the analyzer.

A less subtle point about component placement is concerned with using the double block-and-bleed (DBB) configuration. This configuration, which consists of two block valves and, in between them, a bleed valve running to a vent, is a well-established stan-

Quick-connect lab sample ports are located on bypass loops before the stream selection system. Deadlegs are not created on a line shared by sample streams.

dard in the industry—and for good reason: It guards against contamination between fluid streams. It should be employed whenever there is an intended block between two fluid streams that must remain separate. The basic premise is that two blocks— shut-off valves—are better than one. DBB is the basis of all stream selector systems. It should also be used when calibration fluid is introduced into a system.

Beyond component placement, there is component selection.

Components vary in the amount of dead space they contain. It behooves the system designer to review cutaway drawings and to look for dead space; for example, in a ball valve, around the ball and its packing. The flow path through a valve or through an assembly of components should be smooth, without sharp changes in direction, which cause pressure drop. Purgeability data demonstrate in quantifiable terms that similar components or systems take longer or shorter periods of time to flush out.

In Fig. 5, three fluid systems were filled with nitrogen. Then, a second gas was introduced and the period of time required to flush the nitrogen from the components was recorded along the horizontal axis. Note that Geometry 3 does not clean up even after 30 sec.—a long period of time in the context of an AI system, when the industry standard for an analytical response is 1 min.

Geometry 1 performs the best, with all nitrogen flushed from the system in less than 5 sec.

Leaks and permeation. All fluid system components leak because no seal is perfect and all materials are subject to permeation, even stainless steel. In many cases, the leak rate is too slow to be significant in an analytical instrumentation system, but in other cases, it is not. The engineer and technician should be educated about leak rates and whether they are significant. Quality fluid system components, including valves, are rated to certain temperatures and pressures, and these ratings are published and available. Valves are rated not only for leaks across the seat (internal leaks) but also for shell leaks (external leaks), which are leaks from the inside out. Valves should be able to handle a system’s worst-case conditions repeatedly.

Leaks and permeation occur in the direction of lower partial pressure. To determine whether leaks or permeation will be an HYDROCARBON PROCESSING DECEMBER 2009

I 67

PROCESS ANALYZERS

1,000,000

100% Nitrogen concentration

N2 concentration, ppm

100,000

10%

10,000

1%

1,000

0.1%

100

100

10

10 ppm

1

1 ppm Geometry 1 outlet Geometry 2 outlet Geometry 3 outlet

0.1 0.01 0.001 0

FIG. 5

5

10

15 Time, sec

20

25

100 ppm 10 ppb 1 ppb 30

This experiment was conducted using computational fluid dynamics (CFD). Three different fluid system configurations were filled with nitrogen; then a second gas was introduced. The amount of time required to flush out the nitrogen was recorded along the horizontal axis.

FIG. 6

In this double block and bleed valve, double seals and a vented air gap guard against the possibility of actuation air leaking into the fluid stream.

issue for a system, identify the sample composition and its absolute pressure, and do the same for the atmosphere outside the system. From there, determine partial pressure. For example, if the system media is 100% nitrogen at 100 psia, then the partial gases,” stick to solid surfaces but are easily knocked off. Other pressure of nitrogen is 100 psia. And if, for simplicity’s sake, the molecules, like water and hydrogen sulfide, stick to tubing and atmosphere is 80% nitrogen and 20% oxygen at 15 psia, then hold tight. If one of these sticky molecules is in the sample, it will the partial pressures of nitrogen and oxygen are 12 psia and 3 stick to the inside surface of the tubing and will not show up in psia respectively. Given these conditions, oxygen will leak into the analytical reading for some time. For example, pure nitrogen the system and nitrogen will leak out. Even if the system pressure is running through the tubing but then, after a while, it’s switched were increased to 200 psia, 1,000 psia or higher, oxygen from the to a sample with a low level of hydrogen sulfide. The hydrogen atmosphere would still leak in because the partial pressure for sulfide will line the insides of the tubing and, as a result, the oxygen is greater outside the system than inside the system. analytical reading may show no hydrogen sulfide molecules at Permeation is not always an issue. A small amount of oxygen all. However, once the insides of the tubing have been saturated, leaking into the sample may not matter, depending on the applihydrogen sulfide will begin to show up in the analytical reading. cation. When permeation is a potential Some operators may believe that once issue, the system designer should avoid ■ Some operators may the insides of the tubing have been satuo-rings, elastomers and polytetrafluororated, the problem of adsorption has gone ethylene (PTFE). Instead, employ stain- believe that once the insides away, but this is not true. Let’s assume less steel and metal-to-metal seals wherthat after the hydrogen sulfide sample, ever possible. Another possibility is to of the tubing have been pure nitrogen is now used. The hydrogen enclose the sampling conditioning system sulfide on the insides of the tubing will saturated, the problem of or other parts of the system in a nitrogenbegin to jump off so, even though the purged box. new sample is pure nitrogen, the analytiadsorption has gone away, Some pneumatic valves have design cal reading will show the presence of some configurations that allow for leaks or but this is not true. hydrogen sulfide molecules. Or, to take permeation between the sample and the another example, suppose the temperaactuation air. A valve’s actuator may be integral to the valve design, ture of the tubing increases, as a result of daily changes in the sun’s as in miniature modular valves. In other words, the valve body intensity. Higher temperatures give molecules more energy so they and the actuator are contained in the same block, and they may leave the tubing walls, causing changes in the analytical reading. be separated by only a single seal, such as an o-ring. If this single If the molecules being measured make up more than 100 seal were to fail, molecules from the pneumatic air could leak into ppm in the sample, adsorption will probably not matter a great the sample, or molecules from the sample may escape into the deal. However, if the molecules being measured make up less actuation air. Such leaks may lead to a bad analytical reading or, than this amount, then the adsorption must be addressed. An worse, they could cause a fire or an explosion. When employing electropolished surface on the inside of the tubing—or, another actuators integral to the valve design, look for valves with double solution, PTFE lining—will provide marginal improvements in seals as well as safety provisions, such as vented air gaps, which the adsorption rate. Or, another option is silica glass-lined tuballow air or process leaks to safely escape (Fig. 6). ing. Manufacturers of this product deposit a very thin coating of glass on the inside of the tubing. Glass is smooth and fills up the Adsorption. Adsorption refers to the tendency of some molirregularities in the steel. While the product is expensive, the rate ecules to stick to solid surfaces, including the insides of tubing. of improvement is dramatic. The tubing is still flexible with the Some molecules, like nitrogen, oxygen and other “permanent glass lining, although the minimum bending radius is increased.

68

I DECEMBER 2009 HYDROCARBON PROCESSING

PROCESS ANALYZERS

Supercritical fluid

Vapor

Pressure

Pressure

Liquid

Liquid Mixed phase

Solid Vapor Bubble point (IBP)

Temperature FIG. 7

The phase change chart shows the points where water changes between a solid, liquid and a gas.

Phase preservation. To maintain a representative sample,

one must avoid a partial phase change in the sample. Molecules assume different phases—solids, liquids or gases, or a mixture of these—depending on the temperature and pressure in the system.

The point at which the phases begin to change for each molecule is different, as represented in phase charts with temperature along one axis and pressure along the other (e.g., Fig. 7, a phase chart for water). Solid lines show the interfaces between the phases.

An analytical sample usually consists of more than one type of molecule. The objective is to determine the sample’s composition, i.e., what percent consists of molecule A, what percent consists of molecule B, etc. As long as the sample remains all liquid or all gas, the composition will remain the same. However, if a partial phase change of the sample is allowed, the composition will change. Fig. 8 illustrates a phase chart for a mixture of molecules.

The purple line is the bubble-point temperature for the mixture, and the red line is the vapor’s dewpoint temperature, or the final boiling point. At any point between these two lines, there will be a two-phase combination of vapor and liquid, and the vapor and liquid will have different compositions. In other words, the sample has fractionated into two different compositions and the analyzer can no longer determine what the original composition was.

The challenge for the analyzer engineer and technician is to maintain pressure and temperature in zones that will preserve the entire sample in one phase throughout the analytical system. For a gas sample, the simplest solution is to install a regulator, which will lower the pressure. In addition, if necessary, the sample lines can be heated and maintained at the high temperature with insulated, bundled tubing. Both regulators and bundled tubing are fairly easy components to install and maintain.

For liquid samples, the challenges are somewhat greater. A pump can raise the pressure and, if necessary, chillers may be installed.

Unfortunately, neither pumps nor chillers are especially easy components to install and maintain, although they may be necessary.

Conclusion. Maintaining a representative sample is tricky.

There is no alarm that goes off in an analytical system announcing that the sample is unrepresentative. The only way to uncover the problem is to be familiar with the usual tripping-up points.

Fortunately, all of them are avoidable or correctable. Most corrective actions come down to:

FIG. 8

Dewpoint (FBP) Temperature

In this phase change chart for a mixture of molecules, the purple line is the bubble point temperature and the red line is the dewpoint temperature of the vapor or the final boiling point. At any point between these two lines the mixture will be in a two-phase combination of vapor and liquid, and the vapor and the liquid will have different compositions.

• Knowing the component design and its limitations (deadlegs, dead spaces, leaking of actuation air, etc.)

• Asking the right questions of the fluid system provider (e.g., valve pressure ratings, cutaway drawings, purgeability data, etc.)

• Placing components in the right location in the system (e.g., in the bypass loop, on one side or the other of the stream selection system) • Determining/calculating whether leaks, permeation or adsorption will happen or matter (based on partial pressure) • Knowing which materials or designs will prevent leaks, permeation, adsorption, etc.

• Calculating and maintaining the proper pressure and temperature for phase preservation, based on phase charts. HP End of series:

Part 1. October 2009, Part 2. November 2009.

Doug Nordstrom is the marketing manager for analytical instrumentation at Swagelok Company, focusing his efforts on advancing the company’s involvement in sample-handling systems.

He previously worked in new product development for Swagelok and earned a number of Swagelok patents in products including the SSV and MPC. Mr. Nordstrom graduated with a BS degree in mechanical engineering from Case Western Reserve University and with an MS degree in business administration from Kent State University.

Tony Waters has 45 years of experience with process analyzers and their sampling systems. He has worked in engineering and marketing roles for an analyzer manufacturer, an end user and a systems integrator. Mr. Waters founded three companies that provide specialized analyzer services to the process industries and he is also an expert in the application of process analyzers in refineries and chemical plants. He is particularly well known for presenting process analyzer training courses in Asia, Europe and the Middle East, as well as in North and South America.

HYDROCARBON PROCESSING DECEMBER 2009

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PLANT SAFETY AND ENVIRONMENT

Requirement engineering and management—Part 2— performance standards development Use these guidelines to determine the safety-critical elements and tasks.

Free software modules are available at http://www.adepp.com/demo F.-F. SALIMI, ADEPP Academy, France

W

hen a project is susceptible to the risk of major accident hazards, modern industrial regulations call for a rigorous approach to determine the safety-critical systems (SCSs), subsystems, elements and related tasks.

The requirements for the SCSs, subsystems, elements and tasks shall be engineered and managed during the project life cycle.

Defining the exact expectations of project management toward the numerous contractors and subcontractors that are located at the physically remote locations is one of the most challenging tasks of modern project managers. Any miscommunication or missing information/requirement could cause high costs and significant project delays.

Part 1 of this article explains explained how the prescriptive approaches like API 14C and API 581 can be used in combination with risk-based approaches such as the safety integrity level (SIL) assessment described in IEC61508 and IEC61511 to determine the safety-critical elements (SCEs) and tasks.

Part 2 of this article describes how SCSs and their performance standards can be managed by available online tools such as the ADEPP monitor.

The ADEPP monitor is an online secure tool and offers a robust, efficient and user-friendly tool to engineer and manage performance standards of the SCSs, subsystems, elements and tasks.

This approach has been applied by the author and her collaborators since 1996 for various major oil and gas projects.1,2

Performance standards. The requirements for the SCEs

are “engineered” in the form of “textual rationales.” A typical performance standard covers the following: • Goal—What the system does.

• Scope—The boundary limits to which the performance standard applies.

• Functionality—What the system must do and the criteria it must achieve.

• Availability/reliability—How often it will work when required.

• Survivability—The extent it is required to function after a hazardous event has occurred.

• Dependency/interactions—Affected by or effects on other critical systems.

• Constructability—Which measures must to be considered during construction.

• Accessibility—Which measures should be considered to ease accessibility if inspection and maintenance are required.

UR: User requirement SR: System requirement TR: Textual rationale ASS: Assumption DK: Domain knowledge

UR2 TR1: Xxxxx

TR2: Yyyy

SR7

Introduction. Part 1 of this article explained how the safety

critical systems, subsystems and elements are identified.

A combination of event tree and fault tree analysis is called bow-tie analysis. It is one of the most effective approaches for both quantitative and quantitative identification of the safety critical systems, subsystems and elements.

The brainstorming sessions involves all the relevant parties and disciplines leader in determining safety critical elements.

ADEPP risk models offer the tools for combining the event and fault trees.

The ADEPP monitor provides an online platform for requirement engineering and managing the performance standards during the project life cycle.

70

I DECEMBER 2009 HYDROCARBON PROCESSING

Or

And SR1

SR2

SR6

And SR3

ASS1

TR3: Zzzz And

SR4 SR8

FIG. 9

SR5

Multilayer rich traceability.

DK2

DK1

PLANT SAFETY AND ENVIRONMENT • Maintainability—Which types of TABLE 2. Checklist approach maintenance routines, procedures and perCompliance mit to work are required Requirement Yes No Justifications/remarks/comments • Operability—How operations are X Refer to paragraph (n) of the design ESD philosophy, performed (manually, remote control, auto- Has a process hazard analysis been conducted to determine the fail-safe Doc. No. (P-003) matically, etc.) and which procedures are position of control valves during a critical specific or total utility outage • Procurement criticality ratings and (electrical power, instrumentation options—What are the safety, operational air, etc.)? and financial consequences if the system Have “deadman” (spring-to-close) X Action: To be considered by process to modify the under study fails? What are the specific design sampling valves been installed in highisolation and sampling philosophy, Doc. No (P-125). factors and manufacturing complexity? pressure, flammable, or lethal systems For each section of the performance stan- to prevent continued material flow if dard the following are clearly explained: the operator becomes incapacitated?

• How these items will be assured (written examination scheme) TABLE 3. Rational for setting the performance standard for survivability • What means are to be adopted for verirequirements at compression area fying the compliance of the SCE with the standards set for its performance (verifica- Step Source Type Statement tion scheme).

1 Contract UR1 Project HSEMS shall be in compliance with company HSE plan Ideally, a simple traceability model in doc. (Client-001) the form of a checklist is established. The 2 Company HSE plan, User TR1 The safety barriers shall be designed to limit the probability of checklist questions are answered by a clear doc. (Client-001) an accident in fire and explosion hazard areas to expand to the and ambiguous answer of “yes or no.” installation as a whole.

The criterion is that the frequency of immediate loss of the These types of performance standards are safety barrier protecting persons or safety systems shall not be easy to verify and manage. An example of more than 1/10,000 year. this approach is shown in Table 2.

Design HSE plan, Designer Requirement from hazard and effect management process: If the requirement is more complex and 3 doc. (design-HSE-001) TR1 Fire and explosion study (doc. design-HSE-003) shall be depends on more than just one assumption, performed to identify the foreseeable scenarios and quantify fact, study result and practice code in more their frequency and consequences. than one document then the simple and 4 Design HSE philosophy, SR1 The impairment criteria of API 2218 for fire impairment shall straightforward checklist “textual rationale” is doc. (design-HSE-002) be applied. not sufficient to express all the rationale behind Design HSE philosophy, ASS1 The safety barriers will be designed for one fire at the time. the requirement in a traceable and auditable 5 doc. (design-HSE-002) manner. The management of change of this API 2218 DK1 Impairment criterion: type of requirement is complex and difficult. 6 • Exposure to 8 kW/m2 thermal radiation from jet or pool fires.

To achieve this difficulty, a multilayer API 2218 DK2 If unprotected equipment is exposed to the jet fire (300 kW/m2) traceability model should be applied (Fig. 9). 7 it will fail with five minutes.

In the multilayer traceability model, three 8 Fire and explosion study, DK3 Duration of medium jet fires at compressor pipework is about types of inputs are distinguished: doc. (design-HSE-003) 25 minutes. This fire could impinge the compressor scrubbers.

• Systems requirements from the code, Performance standard standards, guidelines and project documents 9 for the passive fire like philosophies and specifications protection (PFP) at • Assumptions compression area.

• Domain knowledge from the specific Section: survivability project knowledge, studies or experiments doc. (design-HSE-PS-001) and lessons learned from other projects.

9.1 Option 1 SR2 The equipment and associated compression area pipework “Textual rationales” are derived from a shall be passively protected to resist a jet fire impingement combination of these inputs to satisfy the and/or thermal radiation for at least 30 minutes. requirements of the client (end user) that 9.2 Option 2 SR3 The welded pipeworks shall be used at the compression area are described in the contract. and the number of flanges and instrumentation shall be To understand the multilayer rich traceminimized. ability concept consider the performance stanFlange guards should be applied where safe direction jet fire is dard for the survivability requirement at the practical. compression area as an example. Table 3 sum- Note: (UR = user requirement, TR = textual rationale, SR = system requirement, ASS = assumption, DK = domain knowledge) marizes the rationale behind this requirement and Fig. 10 illustrates this rationale in a user-friendly pictorial way. out compromising the plant safety integrity level. The project If, for example, the project meets difficulties in the budget may attract the attention of the client on the fact that the impairto provide the required passive fire protection then refer to the ment criteria suggested by API 2218 are very tight. requirement multilayer traceability model to find which part of If enough space is available you can suggest increasing the the rationale can be reworked and asserted with the client withimpairment criterion from 8 to 10 kW/m2 and manage the risk HYDROCARBON PROCESSING DECEMBER 2009

I 71

PLANT SAFETY AND ENVIRONMENT Functional

User requirement (UR1) User textual rationale (TR1)

Technical

Verification

Contract compliance

Designer textual rationale TR1) Or

Interface links Performance standard options

SR2

SR3

(a) Vertical linkage FIG. 11

And

SR1

Design codes, studies, know-how

DK3

And

DK1 FIG. 10

ASS1

UR: User requirement SR: System requirement TR: Textual rationale ASS: Assumption DK: Domain knowledge

DK2

Multilayer rich traceability for the survivability requirement example at the compression area.

of jet fire impingement and thermal radiation with a better layout and longer safety distances without jeopardizing the safety and asset integrity levels. If the new option is approved then the content of Table 3 and traceability model configuration will be changed accordingly.

Tree-to-tree correspondence (b) Horizontal linkage

Cross-reference in the documents.

The traceability model serves as the mirror of the requirements.

Any rationale behind change and decision should be reversible and could be corrected at any time. An efficient traceability model provides an objective platform for: • Knowing what is a current requirement • Knowing why a requirement was changed • Documentation to form the basis of testing • Understanding where requirements have been built into the system • Forming the basis for ongoing system documentation.

With a clear traceability model the audit activities get much easier and lead to better communication and effective decision-making.

Action-tracking and follow-up. During the project development, the requirements and assumptions in performance standards are evolved and could be changed. It is important to identify when and how the requirements and assumptions are changed.

For example, if the project changes the specifications of an SCE from “A” to “B,” the project should be fully able to respond to the following questions that may be raised by management or the verification party: • Have the relevant responsible parties been informed about this change?

• Have the relevant documents been updated for cross-referencing (e.g., tagging, numbering, etc.)?

Errors in updating the documents could create great confusion between the project team members and subcontractors.

For example, the project can be penalised with high correction action cost and delays if, for example, the supplier is not aware about the possible changes in the specifications and starts to fabricate the materials according to the invalid specifications found in an obsolete version of the specification.

Fig. 11 illustrates how a change in a document could affect the other documents vertically or horizontally.

Management of change is one of the essential elements of the project HSE management system.

The changes in the performance standards should be fully accessible to the relevant contractors, procurement, construction, operation leaders and verification bodies on time to avoid any confusion and conflict between the different disciplines, departments and project phases.

ADEPP, a tool for a traceable and auditable HSEMS.

The HSEMS is implemented to demonstrate that the project is designed and specified such that: • All SCEs necessary for system safe operation are included.

• All SCEs are suitable for their intended purpose.

Select 165 at www.HydrocarbonProcessing.com/RS 72

PLANT SAFETY AND ENVIRONMENT Leadership and commitment

Policy and strategic objectives

Audit and SCORE assessment by ADEPP

Organization and resources

Evaluation and risk management

Supervisory corrective action

Management corrective action

Planning, standards and procedures

Implementation

and

FIG. 13

Task interface with ADEPP monitor.

FIG. 14

Activity log interface with ADEPP monitor.

ADEPP monitor

Management review Continuous improvement

FIG. 12

SCORE assessment by the ADEPP monitor and the HSEMS model.

• All activities necessary for integrity assurance can be carried out.

Today, different independent tools and software packages are used to support each element of the HSEMS. Creating a consistent linkage and interaction between these tools and software is a very difficult task, if not impossible.

The ADEPP monitor is an innovative tool designed to provide an efficient, secure online supervisory corrective action tool for the project. It can federate all the elements of the HSEMS on a sole platform.

Fig. 12 shows how the SCORE assessment by the ADEPP monitor is coupled with the project HSEMS model.

The ADEPP monitor provides a list of generic SCEs and the basis for their performance standards. The industry code, standards, guidelines and proven good engineering practices are used to engineer the requirements of these generic performance standards and will save a considerable amount of time and effort at the early stage of the project.

The SCE list can be updated online by the designers, operator and verification parties for review and comments.

The ADEPP monitor provides the secure open-source database interfaces for company, contractors and verification bodies. They can participate in evolving and improving the performance standards by giving their inputs in the form of comments or attached files. These files could provide the guidelines, evidences, rationales and outcomes of the discussions and meetings, and ease the management of change and follow-up on the assigned tasks.

The main features of the ADEPP monitor are: 1. Secure online access to the safety critical tasks, written schemes and the performance standards.

2. The possibility to add, delete or modify the identification list and any requirement or task at any time (Figs. 13 and 14).

3. The possibility to keep the activity log and monitor the progress of each activity or task (Fig. 14). This could also be served as the project HSE concern register.

4. The possibility of allocating the critical tasks and schedule to any requirement of the performance standard without any limits (Fig. 18). All revisions of a given task are accessible immediately.

5. The possibility of linking the other relevant project databases like HAZID, FIREPRAN, etc., to the SCE identification worksheets.

6. The possibility of linking the results (curves, tables, texts and images) of important supporting documents such as the fire and explosion study and dynamic simulation to each requirement.

7. Dynamic project information and knowledge management including: • The evidence from the results (curves, tables, texts and images) of important supporting documents such as the fire and explosion study and dynamic simulation • The documents, procedures and technical guidelines available in any electronic form on the project intranet • The documents, procedures and technical guidelines available in any electronic form on the public-Internet system.

8. Efficient management of change. The discipline leaders will be informed automatically about the changes and the required tasks for updating the relevant documents or activities.

All actions, action revisions and responses are stored and can be revisited at any time.

9. Traceable and auditable “textual rationale” in the form of: • The checklist for simple requirements • Multilayer traceability model for more complex requirements.

10. Combined event-tree and fault-tree analyses for determining SCEs and assessment of the possible options.

11. Cost-effective solution for communication between people involved in the project.

The ADEPP monitor can be applied for any hazardous plant including upstream onshore and/or offshore installations, pipelines, hydrocarbon processing, chemical, power and nuclear plants, railway and aeronautics.

The ADEPP monitor could also be applied to monitor all the HSE-related subjects such as HAZID, HAZOP, SIL and bow-tie, and produce an online HSE case for the project.

HYDROCARBON PROCESSING DECEMBER 2009

I 73

PLANT SAFETY AND ENVIRONMENT To evaluate the prototype of the ADEPP monitor, please enter as a guest at the following Website: http://www.adepp.webexone.com.

“Click on request an invitation.” Also, The ADEPP demos (15min each) are available in http://www.adepp.com/demo.html. HP ACKNOWLEDGMENT The author thanks the valuable comments of Mr Frederic Salimi on this article and developing the ADEPP monitor. Mr Frederic Salimi obtained his MSc in dependability from “Ecole Centrale Paris” and has been the HSE leader for various major oil and gas projects.

ADEPP ALARP CSU ESD HSEMS ICSS PAHH PFD PSD PSV SCE SCS SIS SIL SOV 1

ACRONYMS Analysis and dynamic evaluation of project Processes As low as reasonably practicable Critical Safety Unavailability Emergency shut down Health, safety and environmental management system Integrated control and safety system Pressure trip alarm high-high Probability of Failure on Demand Process shut down Pressure safety valve Safety-critical element Safety-critical system Safety instrumented system Safety integrity level Solenoid valve

LITERATURE CITED Roger, M. C., Bamforth, P., Salimi, A., Thomas, E. J., “Determination of safety critical equipment, safety critical procedures and softwares utilising quantitative risk assessment data,” Offshore structures hazards & integrity management, International conference of ERA Technology, London/UK, 4-5 December 1996.

2

3 4 5

6 7

8 9

Dr. Salimi Fabienne-Fariba, Mutiplan R&F, France and Martin C. Rogers, Kvaerner Oil & Gas, UK, Use of Quantified Risk Assessment for the determination of Safety Integrity Levels (SIL) utilised in the design of offshore oil and gas installation, ERA Technology, Dec. 1999.

SINTEF REPORT No STF38 A04419, Safety barriers to prevent release of hydrocarbons during production of oil and gas, 2004 ISO 10418, Analysis, design, installation and testing of basic surface safety systems for offshore production platforms. (Replaces API RP14 C).

ISO 13702, Petroleum and natural gas industries—Control and mitigation of fires and explosions on offshore production installations—Requirements and guidelines.

IEC 61508, Functional Safety of Electrical/Programmable Electronic Safety Related System, (all parts) IEC-61511-3, Functional safety—Safety instrumented systems for the process industry sector—Part 3: Guidance for the determination of the required safety integrity levels, 2003.

Stevens, Richard and James Martin, “What is requirement management,” Quality System and Software Ltd. Jan. 1995.

Fitch, John, Requirement management workshop, Systems Process Inc., Feb 1995.

Fabienne F. Salimi is a senior HSE consultant and has more than 20 years of experience in process safety engineering in the chemical and oil and gas industries, both onshore and offshore.

She has a particular expertise in risk-base design and identifying safety-critical systems and developing their performance standards for the life cycle of the major hazardous projects. Since March 1994, Dr. Fabienne has been the project manager of Multiplan R&F in France and later the ADEPP Academy in the UK. She is also the codeveloper and project manager for developing the ADEPP monitor, an online innovative tool for identifying safety-critical equipment and management of their performance standards. Dr. Salimi obtained her PhD in chemical engineering from “Ecole Centrale Paris” in 1996. Her main qualifications were obtained in Iran and France and she is a member of the American Institute of Chemical Engineers (AICHE) and the International Society for Instrumentation (ISA).

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PLANT SAFETY AND ENVIRONMENT

Ensuring site-wide consistency in relief system analyses Follow these protocols when evaluating common-cause failure scenarios for flares and headers R. BRENDEL, Jacobs Consultancy, Chicago, Illinois

W

hen the capacity and capabilities of a site’s existing pressure relief system are to be evaluated, engineers often start by gathering current documentation for the relief valves (RVs). Typically, the site staff keep up-to-date documents on required loads and RV orifice areas for individual RVs that discharge into the system under various failure scenarios. The American Petroleum Institute (API) created a guideline for these documents so that the owner can demonstrate that each vessel and system is adequately protected by an RV for all credible overpressure scenarios.

Once the information is gathered for each RV that discharges into the flare system, usually the engineer’s intent is to use the required relief loads shown there to analyze the headers and flare system for various scenarios. Although there are good reasons to approach the flare system review in this sequence, there are also potential pitfalls to avoid that can give a false view of the collection system.

The following will discuss several situations in which careful analysis and accounting are required to ensure that the scenario used as a basis for analyzing the overall relief system reflects the plant configuration and that the scenario is self-consistent.

Introduction. System-wide analyses of relief systems are often

based on relief loads determined when sizing individual RVs that discharge into the system because: • Much of the technical work required for the system-wide analysis is the same as that done for the individual valves.

• The overall system basis is usually consistent with the bases used for the individual components.

However, there are differences in the analyses necessary for evaluating the relief protection required for a single service as compared to those required for designing or analyzing a relief collection system—the header system, liquid knock-out vessels, and the flare stack and tip. These differences often make it inadvisable or impossible to use the required relief loads for individual services when determining the governing cases for the collection system. The considerations pointed out here arise more frequently in complex relief systems, e.g., where there are several different flare systems that can interact; or in facilities that have site-wide collection and/ or distribution headers that interact with the relief system.

Potential pitfalls are discussed here when evaluating a site-wide relief system from the starting point of data on individual RVs. A proper system-wide analysis will have the following characteristics: • It is self-consistent, so no significant stream is doublecounted and no mutually exclusive loads are included.

• It captures the most likely scenario outcomes under consideration.

• It meets API-recommended practices and standards.

• It is reasonably conservative in that all assumptions that can be demonstrated to give estimates of flows into the relief system that are no less than those expected for the actual event under consideration.

Effects of instrumentation responses. When sizing an individual RV for a given service, per API guidelines, the analysis must not consider the normal response of any instrumentation that would tend to reduce the required relief load for that RV. Consider the distillation column shown in Fig. 1. The overhead pressure controller is an example of a beneficial instrumentation response. If a failure occurs and the column pressure starts to rise, the normal controller response would be to open the vent valve, which tends to reduce the required flow of excess gas that must exit the RV. Since this response is beneficial to the RV, the RV sizing analysis would consider that the pressure controller will fail to respond to increasing pressure, and the vent valve position would be considered unchanged from its normal position.

Similarly, the individual RV analysis must consider the normal response of any instrumentation that would tend to increase the relief load. The reboiler steam flow controller in Fig. 1 is an example of this type. As the relief event develops and the column pressure increases, the process temperature at the reboiler will likely increase. This reduces the driving force for heat transfer across the reboiler tubes, thus decreasing the rate of steam condensation. The normal action of the steam flow controller would be to open the steam control valve, increasing the steam-side temperature in the reboiler by reducing pressure drop across the valve and increasing steam pressure in the tubes, restoring the driving force and increasing the heat transfer rate back toward its normal value. Thus, the individual column analysis must consider that the steam flow controller will respond normally to restore the reboiler temperature driving force during the event.

These rules are required by the API for individual RV analyses to assure that there is sufficient relief protection for each piece of equipment. In the analysis of the entire flare system, however, assumptions that lead to maximum possible individual relief loads do not necessarily lead to maximum possible overall system loads, or to situations that are most demanding of the header system.

This is recognized by the API, which, in Standard 521, gives this guidance on a similar, but not identical, situation: HYDROCARBON PROCESSING DECEMBER 2009

I 75

PLANT SAFETY AND ENVIRONMENT To flare

To flare No. 1 PC

To flare No. 1

PC

Cooling water Condenser Distillation column

To vapor recovery Accumulator

Accumulator Other units

Vapor product

To flare No. 1 PC

PC

Light liquid product

Column feed Feedbottoms exchanger

Knock-out drum Accumulator

Overhead pump

To flare No. 2 To vapor recovery

FC

Steam Heavy liquid product FIG. 1

Reboiler

M

Condensate

Distillation column.

FIG. 2

“It is important to recognize that systems with pressure-control valves and/or depressuring valves, can maintain the pressure below the opening pressure of a pressure-relief device. In such cases, it is not necessary to include the load from the pressure-relief device in the flare load in addition to that from the pressure-control valves and/or depressuring valves. Note that, in these cases, the resulting disposal-system load from the pressure-control valve or the emergency depressuring valve can be larger than the calculated load for the pressure-relief device.”1 Fig. 2 illustrates vapor products from several distillation columns within one unit that are collected and routed on backpressure control to a vapor recovery header, where they join vapors from other units. RVs on the local columns discharge to the nearest flare, named Flare No. 1. The vapor recovery compressor is located far from the unit in consideration. Vapor collection header pressure is limited by a back-pressure controller at the compressor suction, such that, on detected high header pressure, excess gas will spill to Flare No. 2, which is the flare nearest to the compressor. There is no direct connection between the headers for Flare No. 1 and Flare No. 2.

When analyzing the required relief loads from the distillation colums for a power failure scenario to size the RVs, API guidelines state that the beneficial controller responses may not be taken into consideration, as previously discussed. Note, however, that, although the normal response of any column pressure controller is beneficial for the column itself, its action is not beneficial for either the knock-out drum in the unit or for the potential load to Flare No. 2. If the power failure scenario takes place as assumed in the RV study for the columns, Flare No. 2 will see a relatively small load since the spill valves into the header are not considered to have responded to increasing pressure in the columns. The calculated load to Flare No. 2 from the suction of the motor-driven compressor, which will stop upon power failure, would be the compressor’s normal flow since only normal rates of column off-gas flows were considered for the individual streams into the header.

There is a potential pitfall in this approach in that the load to Flare No. 2 will actually be much greater than the normal compressor flow if the column back-pressure controllers respond 76

I DECEMBER 2009 HYDROCARBON PROCESSING

Columns spill gas to a vapor recovery header.

in their intended fashion, by opening to vent excess vapors from the column into the header. The total flow into the header will be much greater than the normal off-gas flows, increasing the flow to Flare No. 2 through the header spill valve as a result of the compressor failure. In analyzing the power failure load to Flare No. 2, if these normal responses of the column pressure controllers are not considered, the estimated spill rate to the No. 2 flare header will be less than the most likely flow, such that the hydraulics may be too optimistic and potential problems in the Flare No. 2 system may be missed.

Thus, if the process engineer bases the loads to the flares for power failure by simply cataloging the power failure loads from the RV scenario sheets, and considering the spill rate to Flare No. 2 to be the sum of the vented gases shown in the calculations for the column RVs, the engineer will under-estimate the potential total flow to Flare No. 2. In fact, since the column back-pressure controllers normally operate in automatic mode, they most likely will open in response to the event, increasing gas flow to the header, and result in a higher flow to Flare No. 2 from the header spill. The true picture for Flare No. 2, then, is actually worse than that developed by the engineer depending on only the RV sizing calculations for determining flare loads.

Balances on utility headers and flows between process units. Site-wide header systems such as the vapor

collection header recently discussed, can be difficult to handle in relief system analyses, largely because the flows into and out of the headers during the relief scenario may be markedly different than those during normal operations. Determining the header flows is often an important part of the overall relief system analysis, making it critical that the hard work is done to define the system.

Consider the process unit illustrated in Fig. 3, specifically, the interactions with the fuel gas system, which is fitted with an RV that discharges to the flare (fuel gas RV not shown). During a power failure scenario, both the feed pump and the recycle gas compressor will stop since they are motor-driven. As a result, fuel

PLANT SAFETY AND ENVIRONMENT gas flow to the furnace will be halted on loss of flow through the In situations such as these, it may be that both controller process tubes as a protective measure for the furnace. response cases need to be considered in the flare system analyIf steam header pressure is maintained during the event, heat sis since determining which controller status is a worst-case sceflow to the column reboiler will continue for at least some time nario may not be straightforward. Experience shows that as long after the event starts. The loss of reflux to the column will lead to as RV discharge tailpipes were designed for the full valve capacity increasing pressure in the column, and the flow of gas into the fuel as required by the API, it is generally more difficult to dispose of header will increase if the column pressure controller responds. the same material through an RV set at a lower pressure than it is to The fuel gas system is now out of balance. Flow out of the relieve through one set at a higher pressure. This is due to the allowsystem has been decreased by the shutdown of the reactor furnace, able back-pressure being lower for the lower set pressure—less presand flow into the system has increased by the actions of the back sure driving force is available to push the material out the RV and pressure controller opening in response to increasing pressure in through the header system to the flare. In this case, if the fuel gas the column. In this example, the required flow to flare from the RV is set lower than that for the column, it will probably be a worse fuel gas system RV will be the sum of these two changes, not simply scenario for the relief system overall if the column controller acts the increased inflow through the column pressure control valve. as normally expected. That is, the excess gas from the column will Note that the true power failure load to the flare will not be the be easier to dispose of to the flare if it exits in the column RV. Most sum of the individual required loads for this scenario from the collikely, however, much of it will be let down to the fuel-gas system umn RV and the fuel system RV. The reaand eventually routed to the flare through son is that the same gas has been counted ■ Determining the header the fuel gas RV set at a lower pressure. twice—the assumptions are mutually This is the typical situation in units exclusive in the column RV analysis and flows is often an important where gas is let down to a lower pressure that done for the fuelgas system. The col- part of the overall relief system on back-pressure control. Gas is umn pressure controller did not respond often let down to the system with the in the column analysis but it did respond system analysis, making it lowest set pressure, where it will be the normally in the fuel system analysis. If the critical that the hard work is most difficult to route to the flare. This is total flare load for the scenario is deteramong the reasons to perform a thorough mined by summing the required loads for done to define the system. balance on utility headers for the scenario power failure from these two RV calculain question, taking care to avoid doubletions, the result will be that for a physically impossible situation: counting any sources that may appear in summaries of required the controller cannot both respond and fail to respond. flows from individual RVs. In this example, double-counting some material is also possible The situation is similar when considering flows between process due to the interaction within the unit between the separator RV units. This can arise for a site that has multiple hydroprocessing and the column. The relief calculation for the power failure scenario units operating at widely varying pressures. Optimizing the hydrofrom the separator will likely consider condensation loss in the prodgen utilization site-wide may lead to a scheme in which off-gas uct coolers, with the required relief load estimated to be the vapor from a high-pressure unit acts as makeup gas for a lower-pressure amount not condensed that normally would be. For the column RV, unit. Here again, the same gas may appear in the required loads the analysis may consider that the liquid level in the separator had for several RVs in the different process units based on mutuallybeen lost due to the combined effects of loss of liquid feed to the unit exclusive assumptions about the actions of the controllers manipuand at least partial loss of condensation. If the separator level conlating the flow among the units. Overall flare system evaluation troller fails to respond to the decreasing liquid level, a vapor blowmust involve determining which of several mutually exclusive through scenario will develop such that high-pressure gas can flow instrument actions is more severe for the system. from the reactor section into the low-pressure column; this excess gas Finally, there is another level of complication possible when will be included in the required flow from the column RV. headers spill on back-pressure control not directly to the relief If the vapor blow-through situation arose, hydraulic analysis may show that the separaTo flare To flare Relief valve tor’s RV will not be required to lift as the excess PC gas—and possibly more—is being vented into Recycle gas the column. Thus, the required relief loads from Cooling compressor Condenser the power failure scenario as listed on the RV water Separator M data sheets for the separator and the column Cooling Fuel Air cooler water cannot both occur as they depend on mutually gas LC exclusive events. For the separator RV to open, Trim cooler the level controller must respond as it normally Accumulator Furnace would upon loss of incoming liquid. But, for M the full required load to develop in the column, that same level controller must fail to respond FC Feed/ effluent to the liquid level loss in the separator, resultSteam Fuel LC Charge exchanger Reactor gas ing in vapor blow-through to the column. The pump T Condensate level controller cannot both respond and fail to respond, so at least a portion of the calculated FIG. 3 Reactor and separation example. required relief loads from the two individual RVs is actually the same material counted twice.

HYDROCARBON PROCESSING DECEMBER 2009

I 77

PLANT SAFETY AND ENVIRONMENT system, but down to other lower-pressure headers, which in turn may spill to the flare.

The chances for counting the same material multiple times will increase since the level of complexity can get quite large in such a site.

Discharge of non required RVs.

Pset: 100 psig

Distillation column To flare

To flare

PC

Condenser

Cooling water Vapor product

To fuel

Pset: Note that there are many RVs associated 100 psig Accumulator with the column in Fig. 4, and they all have Light liquid the same set pressure: 100 psig in this examproduct ple. The RVs associated with the exchangOverhead Column feed pump ers were installed due to the presence of the FeedTo flare To flare To flare block valves around the exchangers which Pset: bottoms Pset: allows one to be taken out of service for 100 psig exchanger Pset: 100 psig cleaning or repair while the column con100 psig tinues to operate. Often, the only credible FC Heavy liquid product Steam overpressure scenarios for such exchangers are the external fire and blocked-in with Reboilers Condensate heat cases. Since none of these exchanger RVs can be guaranteed to be on line during a relief event, the individual relief analysis FIG. 4 Distillation column showing instrumentation and relief valves. for the column will consider only the RV on the column overhead to be in service, and thus it must have sufficient orifice area available to protect the entire column system from overpressure. consistent, the engineer should take the following steps: In this case, the process engineer’s documentation survey for all • Go through the relief system unit by unit or section by secRVs associated with this column will likely show that there is only tion and develop a consistent material balance for the scenario a single flow required to flare for the power failure scenario: vapor under consideration, keeping in mind that the flows may not sum from the column overhead RV. to zero as the plant will not be in a steady state.

During an actual column overpressure event, any exchanger • Do a full accounting for feed, product and internal streams in the reboiler, bottoms or feed service will reach a given pressure to avoid double-counting any material. before the column overhead. Due to the system’s hydraulics, the • Include flows to and from header systems that are consistent pressure is a little higher at the bottom of the column than it is at with assumptions made within the process units—furnaces may the top. Thus, the RVs protecting the equipment at the column be key in many cases. bottoms will open before the RV on the column overhead line. As • Consider how normal instrumentation responses may move a result, the relief disposal system (a flare header, in this example) some material from a high-pressure area to a low-pressure area— will likely see significant amounts of hot and flashing liquid with from which will generally be more difficult to direct into the properties quite different from the column overhead vapor. Thus, relief header. when the goal is analysis of the relief discharge system, the pos• Consider any mutually exclusive scenarios where the worst sibility must be considered that the exchanger RVs will lift and case is not readily identifiable, or where the cases tax different discharge into the system for many scenarios, even though they’re sections of the relief system differently. not required to lift according to the individual RV analysis guideOnly after completing the steps above can the engineer be lines. A relief system study that relies solely on the individual RV assured that he or she has a full and complete picture of the analyses will miss this potentially important detail. required flows into the relief system for the scenario in question.

The system hydraulics and other constraints can then be analyzed Overview. The engineer must recognize the differences in with confidence that the results will be representative of how the approach required for sizing an individual RV vs. analyzing the actual plant will respond to the event. HP relief system as a whole. In the examples considered, it was shown LITERATURE CITED that although all individual RVs are properly sized, the interaction 1 “Pressure relieving and depressuring systems,” ANSI/API Standard 521, Fifth of multiple RVs and control valves discharging to different relief Edition, January 2007. headers can lead to an expected load to the flare that is actually larger than the sum of individual required RV loads for the scenario in consideration. On the other hand, eliminating doublecounting of required relief rates for various RVs may show that the total flow to the relief system is actually less than the sum of all the required flows from the individual RVs. In conclusion, the process engineer’s work is not done once Rob Brendel is a senior consultant in the Oil, Chemicals and he or she has collected the required loads for a given scenario, as Energy practice of Jacobs Consultancy. He has 20 years of expeshown on the individual RV documentation. To ensure that the rience in the refining and petrochemicals industry working for engineer has analyzed the entire system for how the scenario will Jacobs, UOP and Mobil Technology Company. Mr. Brendel’s areas of expertise include safety and relief systems, and energy efficiency. most likely evolve, and to ensure that the overall analysis is self78

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81

HPIN CONTROL ALLAN KERN, GUEST COLUMNIST kernag@yahoo.com

More on APC designs for minimum maintenance Perhaps Zak Friedman struck the perfect balance in his series of editorials,1 because while Dr. Latour thinks Zak went too far in his suggestions to prune multivariable control (MPC) matrices,2 I would say he didn’t go far enough. For many MPCs, I would go a step further and consider abandoning the MPC altogether in favor of well-designed DCS-level regulatory controls. This will often result in improved economic and control performance.

This may sound like strong medicine to the MPC generation, but in my opinion, the practical limitations of MPC over the past 20 years have gone greatly under-reported. In recent years, concerns are finding voice regarding “maintenance” and “sustainability” issues, but a closer look will reveal that many MPC applications have underperformed since day one, not withstanding the great tradition of “successful” project completion rituals.

Fig.1 shows typical distillation column regulatory controls.

MPC, whether minimalist as Dr. Friedman recommends, or more “maximalist” as has been the industry habit, has little more to contribute, except expense and operational complexity. Some of the common breakages between the conventional wisdom and actual practice of MPC-based distillation control are as follows: • Column pressure is rarely a suitable MV. It is best kept steady to preserve the composition profile on which overall operation depends.

At most, pressure can “float” on the condenser to capture the benefits of minimized pressure or to gracefully handle a cooling limitation.

This behavior is inherent in the controls depicted in Fig. 1.

• MPC typically includes feed rate as a disturbance variable.

This is inherent in heat-to-feed ratio control and this feedforward can be applied to the reflux, too, if desired.

• Inferentials, while commonly perceived as a value-added component of MPC, are easily incorporated into regulatory controls without MPC. For example, an inferential-based top composition controller can be cascaded to, or simply replace, the top temperature controller.

• The controls in Fig. 1 respond naturally in the correct manner to saturated reflux, pressure or steam valves, something MPC practitioners often suggest is value-added.

• Many MPCs are configured for dual top and bottom temperature control, but few if any succeed. In my experience, they behave in the same unstable manner as regulatory controls configured this way and are quickly defeated by clamping either the reflux or reboiler MV. This discussion uses the example of distillation columns, but a closer look at other common MPC applications leads to similar conclusions. Most handles, overrides and feedforwards reflected in MPC matrices, while impressive and promising on paper, prove impractical or unwanted in operation. In most cases, they are soon “defeated” by adjusting MV and controlled variable (CV ) limits, resulting in the well-known condition of high service factor, but low utilization. The small number of remaining “active” models, in most cases, could be much more easily captured with basic 82

I DECEMBER 2009 HYDROCARBON PROCESSING

Pres. ovrd.

PI 120

TC 110

Feed FI 101

Stm./ feed ratio

PC 120A

FRC 102

FY 102

FC 111

Distillation column

Reflux drum

LC 112

FC 113

Distillate TI 152 LC 150

FC 151

FC 102

Bottoms

Steam FIG. 1

Typical distillation column controls.

DCS-level controls, sans all the MPC hoopla.

While MPC remains a sound and often tantalizing technology in principle, its practical applicability and success rate are not nearly what popular wisdom might have you believe. I would hazard a guess that less than 15% of installed MPCs are earning money by doing something regulatory controls can’t do better. That means there’s a whole lot of unnecessary MPC activity going on. HP Dr. Friedman’s response.

Mr. Kern has a valid point about the balance between APC complexity, maintainability and potential versus real benefits. The quest to simplify APC should also consider what can be done by advanced regulatory control.

When the application dynamics and constraints are simple, advanced regulatory control can deliver benefits. Do remember, however, that when an application has multiple constraints and complex dynamics, implementing it in the DCS does not make it simple and maintainable. Simplify the problem definition first, and then choose the appropriate application platform.

1 2

LITERATURE CITED Friedman, Y. Z., HP In Control Parts 1–3, Hydrocarbon Processing, June– August 2009.

Latour, P. R., HP In Control Part 1, Hydrocarbon Processing, October 2009.

The author has 30 years of process control experience, including over a decade as MPC group leader at a major Middle East refinery, and has authored numerous articles on process control effectiveness. He is a professional engineer (inactive), a graduate of the University of Wyoming and a senior member of ISA.

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