gulfpub_hp_201401[1]

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LUBRICATION PRACTICES Increase equipment reliability with better lubrication systems and fluids ®

HydrocarbonProcessing.com | JANUARY 2014

PLANT DESIGN Rethink design margins in major equipment specifications

REFINING DEVELOPMENTS Improve temperature and viscosity control for unit operations

SPECIAL REPORT:

Natural Gas Developments

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JANUARY 2014 | Volume 93 Number 1 HydrocarbonProcessing.com

10

37 SPECIAL REPORT: NATURAL GAS DEVELOPMENTS 37 Consider new designs for offshore LNG regasification terminals A. Bulte

45 Choose the best refrigeration technology for small-scale LNG production T. Kohler, M. Bruentrup, R. D. Key and T. Edvardsson

55 The ethane addiction: How long will the US’ advantage last? J. Wanichko

57 From LNG imports to exports: Process safety and regulatory challenges

DEPARTMENTS

4 10 17 19 93 94 97

2014 Editorial Calendar News News—Trevor Kletz Obituary Innovations People Marketplace Advertiser Index

J. Chosnek and V. H. Edwards

BONUS REPORT: LUBRICATION PRACTICES 61 Update on lubrication systems

COLUMNS 9 Editorial Comment Chemical-grade operations— or not?

H. P. Bloch

65 Control moisture in ‘wetted’ rotating equipment M. Barnes and D. Morgan

23

Reliability Was that a failure or ‘just a repair’?

27

Automation Strategies ISA108 Intelligent Device Management focuses on work processes

29

Boxscore Construction Analysis Russian gas: The end of a monopoly and the beginning of a new era

33

Viewpoint Small-scale GTL to transform gas processing at oil fields

98

Water Management Best practices for RO operations

67 Improve quality of lubricating fluids via filtration K. G. Kroger

PLANT DESIGN 69 Wide design margins do not improve engineering M. Toghraei

REFINING DEVELOPMENTS 73 Decrease tube metal temperature in vacuum heaters S. Roy, E. Bright and V. Ramaseshan

77 Optimize viscosity control in refining operations L. Bellière, P. Burg, D. Chantereau and S. M. Stanton

SAFETY 79 Reliable gauges improve safety and reliability J. Deane

PROCESS OPTIMIZATION 81 HCN distribution in sour water systems R. Weiland, N. Hatcher and C. E. Jones

PROCESS AUTOMATION—SUPPLEMENT P-87 Human-machine interfaces are the future of petrochemical refining C. Foster Cover Image: Qatargas LNG loading at Ras Laffan Industrial City. In Qatar, where Total has had operations since 1936, the company holds equity stakes in the Al Khalij field, the NFB Block in the North field and the Qatargas 1 liquefaction plant. Total also owns 16.7% of Qatargas 2 Train 5, which started production in 2009. Photo Courtesy of Total/Thierry Gonzalez.

2014

EDITORIAL CALENDAR*

MONTH

SPECIAL REPORT

January

Natural Gas Developments

February

Clean Fuels

March

HPI FOCUS

The Green Refinery

Corrosion Control

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PUBLISHER

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EDITORIAL Editor Managing Editor Reliability/Equipment Editor Technical Editor Online Editor Associate Editor Director, Data Division Contributing Editor Contributing Editor Contributing Editor

Stephany Romanow Adrienne Blume Heinz P. Bloch Billy Thinnes Ben DuBose Helen Meche Lee Nichols Loraine A. Huchler William M. Goble ARC Advisory Group

MAGAZINE PRODUCTION Vice President, Production Manager, Editorial Production Artist/Illustrator Graphic Designer Manager, Advertising Production

Sheryl Stone Angela Bathe David Weeks Amanda McLendon-Bass Cheryl Willis

ADVERTISING SALES See Sales Offices, page 97.

CIRCULATION

April

Petrochemical Developments

New vs. De-Bottlenecking

Director, Circulation

Suzanne McGehee +1 (713) 520-4440 [email protected]

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May

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Maintenance and Reliability

June

Process/Plant Optimization

Energy Efficiency

July

Refinery of the Future

Changing Refining Economics

August

Fluid Flow and Rotating Equipment

September

Refining Developments

October

Cyber Security and Process Control

November

Plant Safety and Environment

December

Plant Design, Engineering and Construction

Hydrocarbon Processing is indexed by Applied Science & Technology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index.

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Petrochemical Update

Top Projects in the HPI

*subject to change

4JANUARY 2014 | HydrocarbonProcessing.com

Because Hydrocarbon Processing is edited specifically to be of greatest value to people working in this specialized business, subscriptions are restricted to those engaged in the hydrocarbon processing industry, or service and supply company personnel connected thereto.

Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01.

President/CEO Vice President Vice President, Production Editor-in-Chief Business Finance Manager

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ADRIENNE BLUME, MANAGING EDITOR [email protected]

Innovations

Midstream companies traditionally build a few compressor stations in a year, with periodic upgrades to implement new instrumentation technology, increase compression horsepower or improve control systems. With the boom in the natural gas industry, however, companies now need multiple compressor stations to match increased gas supply. With growing demand for new compressor stations, it is no longer economically feasible to provide an individual design for each new station. Schedules are shorter, and consistent quality sometimes has been sacrificed due to a lack of qualified construction crews. As construction schedules are extended, and as experienced and qualified contractors become busier, the development of complete, high-quality compressor station design packages that are critical for consistent quality compressor station installations have become more difficult to achieve. As a result of these constraints, standardization is becoming the new norm in the midstream industry, and for a good reason: It adds value. Specifically, it creates value in three ways: • Capital expense reduction, mainly due to repeat engineering, volume contracts with preferred suppliers, discounts for material, and services and integration efficiency • Standardization enables project engineers to use proven designs, resulting in reduced front-end engineering design effort requirements, fewer mistakes and increased productivity; this, in turn, results in reduced cycle time, helping accelerate cashflow from operations • Value is created through reduced operating expenses for subsequent projects, mainly due to increased startup efficiency, improved uptime, and commonality of equipment and training (FIG. 1).

Engineers at CDI Corp. have developed a comprehensive standardization package for Access Midstream Partners for natural gas compressor stations in Louisiana, Ohio, Oklahoma, Pennsylvania, Texas, West Virginia and Wyoming. The package is designed to minimize the engineering required for each compressor facility, shorten construction time, ensure consistent project quality and safety, reduce materials costs and improve inventory processes. As with any standardization project, a few key goals were established at the outset: Reduced CAPEX

• Quick preparation of construction bid packages. Process and instrumentation drawings, piping standards, equipment packages, layout drawings, foundation details, control panel hookups, automation and electrical loops, and bill of materials should be prepared and preapproved, resulting in a minimum of preparation time from the initial bid package to the commissioning of the system. • Timely proposal responses from qualified construction companies. Layout and construction schedules Improved operability/ reduced OPEX

Reduced cycle time

3 2 Free cashflow

Standardization aids gas compression

Time

1

Standardized compressor stations One-off compressor stations

FIG. 1. Standardization adds value to gas compression operations.

Patent registered for metal-seated ball valve Extreme operating conditions with temperatures up to 450°C and pressures up to 420 bar require special sealing technology in ball valves. Standard soft-seated ball valves are not optimal to meet these requirements; their plastic seals would fail. Metal-seated ball valves overcome this problem. AS-Schneider has entered the metal seated ball valve arena with its new KM Series. The ball valve features zero leakage, even under extreme operating conditions, with respect to working pressure and temperature, and a smooth operation is provided. These features are possible due to the “Dissolution” ball valve design registered for patent protection. The design offers an optimized distribution of forces and loads, so they are only present where absolutely needed. Select 5 at www.HydrocarbonProcessing.com/RS

Hydrocarbon Processing | JANUARY 201419

Innovations

•

• •

•

should be reviewed, prechecked and approved by qualified construction personnel to take into account the scope of work, schedule, construction sequencing and layout. Consistent construction and installation quality. Standardized materials, complete bill of materials, standardized prepurchase of materials and consistent material stocking by the client will allow the contractor to build a station quickly, with a minimum supply of material. Optimized site layout. This enables ease of accessibility for construction, maintenance and service. Standardization of components throughout the midstream system. This allows the client to duplicate systems, thereby minimizing spare parts inventory. Total yearly component counts. These are provided to optimize component bid package preparation inquiries and purchases for quantity discounts.

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Software enhances project delivery Intergraph’s expanded Global Professional Services Consultancy and Delivery Organization has launched the improved Global Professional Services Methodology (GPSM) to provide consistent and predictable delivery results for projects worldwide. By establishing best practices and processes into a single methodology, GPSM will provide a structured approach for standard reporting and enhanced project execution on a global basis. GPSM is scalable based on delivery complexity, and is also oriented to customer alignment based on schedule and cost

control. There are six phases in GPSM, with decision gates and clear deliverables for better project governance. Quality control is a continuous process throughout GPSM, ensuring accuracy of project documentation and high-quality deliverables. The formal GPSM framework helps streamline project execution and identifies potential risks early, reducing the need for rework and delays. It also provides tools and capabilities for efficient project delivery. Select 2 at www.HydrocarbonProcessing.com/RS

EPA confirms crude vapor pressure test A new method for measuring the true vapor pressure (TVP) of crude oil is spreading quickly in the oil and gas industry. At the request of the American Petroleum Institute (API), the US Environmental Protection Agency (EPA) recently confirmed the use of the ASTM D637710 standard as an alternative test method for the determination of the TVP of highVP crude oils. As defined by the International Maritime Organization, the TVP, or bubblepoint vapor pressure, is the equilibrium vapor pressure of a mixture when the vapor/liquid (V/L) ratio is zero. A V/L = 0 can be achieved if a container is filled to the top with crude oil. This condition is typical for floating roof tanks, where the roof is floating directly on the crude oil. As clear as this definition seems, a correct interpretation of the TVP term always depends on the specification for which it is used. In refining, the term TVP often is used to reflect the specific conditions of storage or transport. For example, if a truck or a ship is filled 95% with crude oil, and only 5% vapor space remains, the vapor pressure at a V/L = 0.053 may be

referred to as TVP. Within US EPA Title 40 regulations, the term TVP is used for a TVP estimate calculated from a D323 Reid vapor pressure (RVP) measurement and the crude oil’s tank stock temperature. In a letter dated May 28, 2013 and published on its website, the EPA acknowledged the broad use of the ASTM D6377-10 standard for VP measurement of crude oils. It confirmed the use of D6377 as an alternative method for TVP measurement of volatile crude oils, as defined under Title 40 Code of Federal Regulations, with the understanding that crude oil samples are delivered pressurized for measurement to prevent the evaporation of light ends, and that the TVP is measured at a V/L = 4. The ASTM D6377 method is versatile. It allows measurement of the TVP at various V/L ratios to reflect different tank filling levels. Sandia National Laboratories has used this bubble point/TVP extrapolation method successfully. From three D6377 measurements at different V/L ratios, the TVP of crude oil at a V/L = 0 is extrapolated. The extrapolation function assumes that crude oil is composed of three components: Very light gas components (e.g., methane or nitrogen), intermediate volatility components (e.g., C2 and higher) and a non-volatile fraction. Select 3 at www.HydrocarbonProcessing.com/RS

Partnership to make synthetic rubber from biomass Axens, IFP Energies nouvelles (IFPEN) and Michelin have announced the launch of a plant chemistry research partnership to develop and bring to market a process for producing bio-sourced butadiene, or bio-butadiene. In response to the need to find sustainable alternative sourcing channels for elastomers, the BioButterfly process (FIG. 2) will make it possible to produce more environmentally friendly synthetic rubber. In addition to developing an innovative bio-butadiene production process, the three partners are committed to laying the groundwork for a future bio-sourced synthetic rubber industry in France. Select 4 at www.HydrocarbonProcessing.com/RS

FIG. 2. The BioButterfly process to produce bio-butadiene.

20JANUARY 2014 | HydrocarbonProcessing.com

Expanded versions of these items can be found online at HydrocarbonProcessing.com.

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We create chemistry that makes natural gas love solutions.

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

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Reliability

HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR [email protected]

Was that a failure or ‘just a repair’?

Picking winning situations. This is an interesting view of

failure; however, it also shows how we can manipulate apparently valid statistics. It is not possible to compare statistics based on narrow definitions against those based on much broader definitions. Sensible MTBF statistics aim for simplicity. Therefore, some reliability engineers or professionals see merit in making comparisons as long as they do not involve the

judgmental ingredient of questioning if and how a particular component defect could have caused the asset to shut down. For years, whenever a component was replaced many organizations have labeled this as a failure event. When first collecting relevant statistics, these companies decided that only two preventive/predictive action steps—data taking and/ or performing scheduled oil changes—would escape being called an equipment failure event. The main aim of the reliability professionals in those organizations was to facilitate comparisons based on facts, not on assumptions or projections. These best-practices organizations wanted to steer clear of speculating if leaving a flawed component in place would have led to an asset shutdown. Counting maintenance interventions. A few years ago, a major oil refinery on the east coast of England emphasized asset outage numbers. Individual process units competed with each other to drive down their respective numbers. They did so by performing lots of preventive actions, which primarily included frequent oil changes. As a result, the refinery’s overall asset outage frequencies declined and bearing failures declined. Some process units looked great, but only on paper. The refinery soon realized that maintenance expenditures in the “good” units were higher than in the “bad” units. From then on, the refinery made it a practice to count “maintenance interventions.” An oil change is a maintenance intervention. Counting maintenance interventions shifted the goals from aiming for favorable statistics to optimized operation. This change in benchmarking shifted more authority and attention to the facility’s key reliability professional, whose job was to look at plantwide bottom-line performance and long-term profitability. When the optimized work processes and procedures

5.0 4.5 4.0 3.5 3.0 2.5 2.0 1.5 1.0 0.5 0.0

60-month MTBR = 2,567 repairs/yr 4,452

34.2

4,128

44.8

46.7 3,297

36.9 3,409

50.3 3,060

53.1

60 50

2,901

40 30 20

MTBR, months

Annual number of pump repairs, thousands

Purists among reliability professionals are sometimes concerned about the accuracy of the measurement of the meantime-between-failure (MTBF) of an asset. There are many ways to conduct this failure frequency rate assessment. FIG. 1 represents a multi-site major refining company. This figure demonstrates that the corporate reliability engineers are making reasonably accurate affiliate-to-affiliate comparisons. However, some petrochemical and refining companies make a distinction between repairs and failures. As one engineer wrote, “I have a philosophical question around the classification of repairs vs. failures when tracking rotating equipment reliability. As I see it, there are basically two structures or philosophies: asset or component.” “In the world of asset philosophy, one views the equipment train as a singularity, and this is how it is being done here, where I work. A motor and pump combination is a single asset. We observe if the asset as a whole continues to perform its intended duty, i.e., pumping product. As long as the asset moves fluid, the asset has not failed. If a particular component fails and needs to be replaced, the asset has not failed. For example, a seal leaks; the action to correct the leaking seal is logged in as a repair. After all, the asset continues to perform its intended function. In this view, all seal leaks are considered repairs. Only if the seal leak causes the asset to shut down (e.g., the seal blows out), then it is classified as an asset failure.” “In the sphere of component philosophy, an asset is seen as a composite unit consisting of multiple and various components, i.e., motor shaft, motor bearings, pump shaft, pump bearings, impeller, wear rings, coupling, throttle bushing, seal, seal pot, etc., and each has its own failure mode. While it is true that a particular component may cease to perform its intended function and not prevent the whole from functioning, i.e., a small seal leaking does not stop the pump from pumping, the asset must still be taken offline to repair the defective component. There will be an asset repair due to a component failure.” “I believe the component philosophy is the superior form of equipment classification as it pertains to rotating equipment reliability. It gives my plant the ability to classify both asset and components in their respective statistics or catalogs. Moreover, it provides the benefit of seeing issues down to the component level. The component strategy is helpful in identifying what particular item(s) are causing all the problems.”

10 2007

2008

2009 Pump repairs per year

2010

2011

Roll 2012

0

Pump MTBR

FIG. 1. Repair frequency and MTBF tracked by a major corporation with over 15,000 process pumps. Hydrocarbon Processing | JANUARY 201423

Reliability to extend intervals between interventions were outlined by the reliability engineer, the organization finally listened. The author’s former employer treated the task of replacing a $3 O-ring the same as a $2,150 impeller replacement. Various plants or process units may have looked for opportunistic repair dates, but, years ago, this company resisted making the “repair vs. failure” distinction. There would have been concern that one person’s seal blow-out was another person’s minor leak. So, the quest was to consistently use simple statistics for comparison purposes. As to the original question raised by the reader, what he called “repairs” was included in MTBF. For some unspecified reasons, certain industry segments keep track of mean-time-between-repairs (MTBRs), as shown in FIG. 1. While this metric could make one’s MTBF look good, the organization may no longer have the ability to compare itself to competitors who lump things together in calculating their MTBFs. Perhaps it does not matter much which calculation method is selected as long as apples are compared to apples.

out on a pallet right outside the shop. That affiliate’s great lowfailure report to corporate remained unaffected; the machine had never entered the shop. It took a while before more realistic heads prevailed. From then on, the managers in charge at corporate headquarters reverted to listing as failures all incidents where components had been replaced. Aiming for failure avoidance. Reliability engineers must make fact-based contributions, which add to the safety, reliability, profitability and future viability of the enterprise. At best-ofclass companies, reliability professionals and subject-matter experts must effectively convey to their managers the exact steps needed to achieve these goals. In many instances, quantification and cost justification are performed; applying and having access to key performance indicators will help. In short, reading, absorbing relevant training and networking among colleagues are needed to make meaningful comparisons. HEINZ P. BLOCH resides in Westminster, Colorado. His professional career commenced in 1962 and included long-term assignments as Exxon Chemical’s regional machinery specialist for the US. He has authored over 550 publications, among them 18 comprehensive books on practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oil-mist lubrication and practical lubrication for industry. He holds BS and MS degrees in mechanical engineering, is an ASME Life Fellow, and maintains registration as a professional engineer in New Jersey and Texas.

Gaming the statistics. Are statistics just a game? Thirty-five

years ago, the affiliate of a multi-national oil company petitioned its corporate head offices that tweaking pump parts was not really a repair. The decision from upper management was to count repairs as a work event requiring equipment to be taken into the shop. “Field work” did not count as an equipment failure. Not long after this decision, work was being performed outside of the shop as “field” cases. The parts were literally spread

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Automation Strategies

PAULA HOLLYWOOD, CONTRIBUTING EDITOR [email protected]

ISA108 Intelligent Device Management focuses on work processes Over the last decade, field instrumentation and analytical chemistry device suppliers have made tremendous progress incorporating value-added functionality into intelligent devices. This includes enhanced visualization and health monitoring functionality to facilitate predictive maintenance (PdM). Despite these technological advancements, many companies are not fully using digital device diagnostics to their best advantage. Consequently, plant operational efficiency has not improved significantly, nor have costs, due to device-related accidents. To address this issue, the International Society of Automation (ISA) has recently formed a new standard committee, ISA108, to characterize intelligent device management in the process industries. The committee will define standard templates for best practices and work processes based on information derived from intelligent field devices, including models and terminology, implementation guidelines and detailed work processes. Plant asset management system landscape. ARC defines

plant asset management (PAM) systems as hardware, software and services that evaluate plant systems and equipment health by monitoring the asset’s condition periodically or in real time to identify potential problems before they can affect the process or escalate to a catastrophic failure. Asset monitoring is one set of applications falling under the asset performance management (APM) umbrella; it also includes enterprise asset management (EAM), mobility, reliability, enterprise resource planning (ERP) systems and other information sources. These include energy management system (EMS), sustainability, and environmental, health and safety (EH&S) system. APM systems provide a compelling case for reducing operational costs while simultaneously improving operational performance. APM leverages the power embedded in various operations and maintenance applications to improve asset availability and utilization within the collective operational constraints of the enterprise. At present, the emphasis has been on monitoring production assets. ARC research indicates that approximately 75% of monitoring investments target production assets. Most production assets involve moving parts that are subject to wear and degradation. Vibration technology is used extensively to monitor these assets. The evidence indicates that automation assets are taking a backseat when it comes to equipment health monitoring. According to Ian Verhappen, co-chair of ISA108, “More than 80% of smart instrument data is not being used or even connected to an online data collection system.” ARC believes that this behavior is counter intuitive given that production asset

monitoring frequently requires additional external equipment, while most automation assets already contain a high degree of embedded intelligence. While the level of digital technology implemented in field devices is evolving, particularly in wireless transmitters, operational enhancements will not be realized if organizations continue to underutilize the available functionality or apply old work practices. ISA108 Intelligence Device Management. Formed in August 2012, the ISA108 committee is charged with defining standard templates of best practices and work processes for the design, development, installation and use of diagnostics and other information provided by intelligent field devices in the process industries. The belief is that, when intelligent devices are properly applied and managed, maintenance personnel can focus on the devices that actually require action when the data indicate attention is necessary. Devices can provide detailed information on problems before a trip to the field is made. This could result in significant reductions or elimination of periodic testing and provide advanced warning of failures thus minimizing the effects on operations. The scope of the committee will include recommended work processes and implementation practices for systems that utilize information from intelligent field devices and the people who use them. Process templates by worker roles (such as maintenance or operations) will be one area of research. The committee will develop best practices for implementation and models for the flow of information from devices through the various systems that use this data. Because no new technology is involved, the primary focus will be on developing new work processes to match device capabilities. This will require a cultural change, which can be the most tasking segment for implementation. The committee will also target alarm management and rationalization for a riskbased approach to alarms to alleviate fatigue. Intelligent device data can make the distinction between operator or maintenance alarms for action by these two groups as required. PAULA HOLLYWOOD, senior analyst at ARC Advisory Group, has been covering field instrumentation and other automation technologies for over 30 years. At present, she focuses on enabling technologies and strategies for industrial asset performance management. Prior to ARC, she held various technical and marketing positions at The Foxboro Company, Krohne America and Kentrol, Inc. Ms. Hollywood has a BS degree from Northeastern University and an MS degree from the University of Massachusetts in Boston.

Hydrocarbon Processing | JANUARY 201427

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Boxscore Construction Analysis

LEE NICHOLS, DIRECTOR, DATA DIVISION [email protected]

Russian gas: The end of a monopoly and the beginning of a new era December 1, 2013 marked the beginning of a new era for Russian gas exports, as it saw the repeal of a 2006 law establishing Gazprom as the sole exporter of Russian gas. Amendments to the gas export law and foreign trade law allow other companies—primarily Novatek and Russian state-owned Rosneft—the ability to sell liquefied natural gas (LNG) for export. Gazprom’s monopoly on gas exports to Europe via pipeline was not touched. The amendments are part of Russia’s plan to double LNG exports by 2020 and grab crucial LNG market share in the Asia-Pacific region. Russia’s overall goal is to produce at least 40 million tons per year (MMtpy) of LNG by 2020. This volume would raise Russia’s global LNG market share from 5% to 11% in just six years. However, Russia is not without stiff competition. Australia has invested over $160 billion (B) on LNG export terminal construction. Forecasts show Australia overtaking Qatar (which holds 31% of the global LNG market share) as the world’s leading exporter of LNG within the next decade. However, spiking labor costs and cost overruns have threatened Australia’s position. Meanwhile, the US is planning the construction of over 210 MMtpy of LNG export capacity. Five LNG export terminals have been approved by the US Department of Energy, as of the time of publication. Almost all LNG exports are targeted for the Asia-Pacific region. Canada is also developing its LNG export portfolio. Multiple LNG export terminals are planned on Canada’s west coast in British Columbia. In the Eastern Mediterranean, Cyprus and Israel will also become LNG exporters. In Africa, major gas discoveries offshore Mozambique have the potential to elevate the country to the world’s third-largest exporter of LNG. Plans are in place to build one of the largest LNG export terminals in

the world. Exports are destined for Asia— primarily India, China and Japan. With the changing dynamics of natural gas exports, Russia must construct LNG export facilities to compete on a global scale. Direct competition from the Middle East—primarily Qatar, Australia, Africa, Canada and the US—are all vying to satisfy Asia’s growing gas demand. Russia’s proximity to Asian markets and large gas reserves can help the country gain a foothold on global competition. Russian gas. Russia holds the world’s largest natural gas reserves. Equaling almost 1,700 trillion cubic feet (Tcf), Russia’s reserves account for nearly one-quarter of the world’s proven reserves. The majority of the gas reserves are located near the Gulf of Ob in upper western Siberia. Known as the Nadym-Pur-Taz region, this area includes some of Russia’s most prolific production areas—the Medvezhye, Urengoy and Yamburg fields. Gazprom is also investing in other regions, such as the Yamal Peninsula, Eastern Siberia, Sakhalin and Shtokman. Russian gas exports head primarily to the Commonwealth of Independent States and the EU via pipeline. Gas is also exported as LNG through Russia’s only LNG terminal, Sakhalin, which is owned by Gazprom. These cargos head mainly to customers in Japan and Korea. Sakhalin contains two LNG processing trains producing a total of 10 MMtpy of LNG. The addition of a third 5-MMtpy train has been proposed, but a final decision has yet to be made. Russia’s LNG export industry has been largely undeveloped, but with the emergence of global LNG trade, Russia is keen to capitalize on its LNG export capacity. Four major LNG terminal projects have been planned: Vladivostok, Yamal, Pechora and Sakhalin. These major projects will help Russia compete for LNG export market share.

Yamal LNG. The $20 B Yamal LNG project is one of the largest industrial ventures to ever take place in the Arctic. The project consists of the development of the South Tambey condensate gas field and the construction of the Yamal LNG export terminal. The project is being developed by Novatek (60%), Total (20%) and China National Petroleum Corp. (CNPC) (20%). Novatek sold a 20% stake in the project to CNPC in September 2013. Per the cooperation agreement, Yamal LNG will provide at least 3 MMtpy of LNG to China, and CNPC will provide active assistance in attracting external funding for the project from Chinese financial institutions. The 16.5-MMtpy LNG terminal will consist of three trains, each with a capacity of 5.5 MMtpy. Construction will be conducted in three phases. Train 1 will be completed in 2016, Train 2 in 2017 and Train 3 in 2018. Major contract awards include: • JGC and Technip: The consortium was awarded the engineering, procurement, construction (EPC), supply and commissioning of the integrated liquefaction facility. • CB&I: Detailed concept design. This includes concept development of the LNG plant (i.e., LNG storage and loading facilities, as well as Arctic shipping and ice-management solutions, a gas transmission pipeline, a central production facility for gas and condensate treatment, and the associated well sites and gas gathering system). The concept development will address the technical, economic and execution feasibility of the remote Arctic project and will provide a project schedule and cost estimate. • CB&I, Chiyoda and Saipem: The companies will provide front-end engineering design (FEED). FEED will lay a basis for the detailed EPC Hydrocarbon Processing | JANUARY 201429

Boxscore Construction Analysis phase, along with the project schedule and cost estimates to secure the final investment decision. CB&I will also be working with the Russian Design Institute, NIPIgazpererabotka, to address local design and authority approval requirements. • BASF: Yamal LNG will utilize BASF’s Oase brand technology for the removal of carbon dioxide from natural gas. • GE Oil & Gas: The company will provide $600 MM in crucial turbomachinery equipment for all three LNG production trains. This equipment includes six Frame 7E gas turbines, 18 centrifugal compressors, six variable-speed drives and six waste heat-recovery units. • Daewoo Shipbuilding & Marine Engineering: The company will construct, launch, equip, complete and deliver up to 16 ARC7 ice-class LNG tankers. These vessels will be used for shipping LNG from the Yamal LNG terminal. Pechora LNG. The Pechora LNG proj-

ect consists of the development of the Kumzhinskoy and Korovinskoye fields, the development of a gas transport infrastructure, and the construction of the Pechora LNG terminal and a gas treatment plant. The LNG plant will be positioned on 220 hectares of land in a non-freezing part of the Barents Sea coast, 230 km from the town of Naryan-Mar. The terminal will receive natural gas via 395 km of pipeline

from the Kumzhinskoy and Korovinskoye gas fields. The $4 B first phase of the complex will process 4 B cubic meters (Bcm) of dry gas per year and produce 2.6 MMtpy of LNG. The project has the capability to be expanded to 8 Bcmy if needed. Total cost could reach $12 B, and completion is scheduled for 4Q 2018. The use of a floating liquefied natural gas (FLNG) vessel has also been considered for Pechora LNG. The FLNG vessel would provide production, processing, liquefaction, storage and shipment without the heavy price tag of an onshore terminal. Vladivostok LNG. The Vladivostok LNG terminal (FIG. 1) is part of Gazprom’s Eastern Gas Program. Eastern Siberia and the Far East cover nearly 60% of the Russian Federation. According to estimates, Eastern Russia contains 52.4 trillion cubic meters (Tcm) of gas onshore and 14.9 Tcm of gas offshore. The Eastern Gas Program’s goal is to develop these fields to supply natural gas domestically and to export markets in Asia. The Vladivostok LNG terminal is crucial to implementing this plan. Vladivostok will be located in Perevoznaya Bay on the Lomonosov Peninsula. This strategic location was selected for its navigable pass that is ice-free during the entire year. Also, the bay is protected from northern and western winds, traffic density is low, no areas are prohibited for navigation, and the site has close proximity to gas transportation facilities. Gazprom will work in cooperation with the Agency for Natural Resources and Energy under the Japanese Ministry

Zemlya Frantsa Iosifa Arctic Ocean

Barents Sea

Severnaya Novaya Zemlya Kara Sea

Laptev Sea

Yamal

Pechora Finland Helsinki Estonia St Petersburg Moscow Kazan Latvia Omsk Novosibirsk Lithuania Belarus Volgograd Ukraine Kazakhstan Modova Aral Sea Romania Rostov Black Sea Bulgaria Istanbul Georgia Tashkent Kyrgyzstan Uzbekistan

Russia

East Siberian Sea

Chukchi Sea Bering Strait

Yakutsk Sea of Okhotsk

Irkutsk

Sakhalin

Mongolia Ulaanbaatar Shenyang

FIG. 1. Major LNG terminal project in Russia.

Arctic Ocean

Novosibirskive Ostrovo

Vladivostok

Bering Sea Aleutian Islands Pacific Ocean

of Economy, Trade and Industry. Both groups conducted a joint feasibility study that was completed in 2011. WorleyParsons was awarded the FEED contract in November 2013. The Vladivostok terminal will receive gas from Russia’s Far East fields. This feedstock will be transported via pipeline to the plant. Development of the new fields and construction of the pipeline are expected to cost $40 B. The terminal will contain three trains of 5 MMtpy each; the first train is expected to come online in 2018. Total capital expenditure was raised from $8 B to $13.5 B in November 2013. The new figure reflects the additional cost of infrastructure, such as a port, gas pipeline and power station, and higher costs for the terminal itself. Sakhalin LNG. ExxonMobil and Rosneft have joined to construct a $15 B LNG export terminal in the Sakhalin region of Russia. The terminal will have an initial capacity of 5 MMtpy, but could be expanded in the future. The plant will receive gas feedstock from Rosneft’s reserves in the Far East and other Sakhalin gas resources. The initial FEED contracts were awarded to CB&I UK and Foster Wheeler in September 2013. The initial FEED phase will finalize details for the LNG plant site, gas liquefaction technology and construction process. Rosneft and ExxonMobil plan to finalize the project design by the end of 2014, including FEED for the LNG plant, associated facilities and gas pipeline, as well as engineering studies and an environmental impact assessment. Completion is scheduled for 2018, the same year as the planned commissioning of Gazprom’s Vladivostok LNG. This would put state agencies in direct competition for market share in China, Japan and South Korea. LEE NICHOLS is director of Gulf Publishing Company’s Data Division. He has five years of experience in the downstream industry and is responsible for market research and trends analysis for the global downstream construction sector.

Detailed and up-to-date information for active construction projects in the refining, gas processing, and petrochemical industries across the globe | ConstructionBoxscore.com

30JANUARY 2014 | HydrocarbonProcessing.com

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COMPLETE ENGINEERED SOLUTIONS

Viewpoint

IAIN BAXTER Business Development Director, CompactGTL, Abingdon, Oxfordshire, UK

Small-scale GTL to transform gas processing at oil fields Iain Baxter is the business development director for CompactGTL, a UKbased company that specializes in smallscale gas-to-liquids (GTL) technology. A natural gas and GTL expert, Mr. Baxter discussed with Hydrocarbon Processing his outlook for GTL worldwide, particularly with regard to small-scale liquids production from associated gas. HP. How does a small-scale GTL unit operate compared with a large-scale, conventional plant?

IAIN BAXTER is a member of the board at CompactGTL, and he joined the company soon after its incorporation in 2006. Before this time, he was business director with Advantica (formerly British Gas), where he ran the Upstream Asset Performance business, including the LNG consultancy, gas processing, rotating machinery and technology licensing areas. Mr. Baxter has 25 years of experience centered on sales and commercial roles in the process and energy sectors, particularly in the Far East and Americas. He has led technology commercialization programs with worldclass companies in Japan and the US, closing contracts to $100 million in 25 countries. Clients include BP, Shell, BG, Saudi Aramco, Eni, Centrica, PDO Oman and Petronas. Mr. Baxter holds a degree in mechanical engineering from Loughborough University in Leicestershire, UK, and has originated six patents and several articles for trade press. He regularly presents at international upstream conferences, and often participates as a GTL expert panelist.

IB. Fundamentally, the technology is predicated on the fact that there are two types of reactors needed for the GTL process: syngas [synthesis gas] production and Fischer-Tropsch [FT] synthesis. We have those two types of reactors, and we have made them about 10% of the size of the conventional reactors in a worldscale plant. These small GTL plant configurations are standard designs from mass production. We have mass production partners in Japan—Sumitomo and Kawasaki Heavy Industries. They have pre-invested in the manufacturing capability to be able to mass produce these units in volume, and that’s where we get some economies of scale, as well as uniformity, in terms of the way in which we’re deploying the technology. HP. In what countries and locations do you see the most promising applications for small-scale GTL?

IB. The scope is absolutely global. There’s a common theme of remoteness of resources. One incredibly interesting region is Australia. Activity is also seen in some Southeast Asian countries, particularly Indonesia, where there have been a lot of discoveries and activity. Other key areas are Russia, the CIS countries, North and West Africa, the US, Canada and some South American countries. CompactGTL has projects in all those territories, at the feasibility and concept development stages. At the beginning

of 2012, Petrobras’ approval of CompactGTL’s technology [as commercially demonstrated at Petrobras’ testing site in Brazil] was critical, because the upstream and midstream industries are rightly conservative, and we wouldn’t be happy putting projects forward unless we had demonstrated the technology at a meaningful scale. HP. What do you see as a realistic timeline for growth in popularity of small-scale GTL?

IB. I think things are going to happen very fast. In North America, you have a “can-do” attitude and a stable environment. It won’t be only GTL; our technology is compelling and has its perks, but this technology is going to attract new technology developments as well. We’re absolutely convinced that there will be other offerings, and that will improve competitiveness, which is good for everybody. It depends on the logistics and the field locations. In the oil fields, the oil and gas companies are really only interested in producing oil. We give them the opportunity to turn the associated gas into synthetic oil. HP. What are the main factors contributing to the success of small-scale GTL technology?

IB. One of the critical factors for CompactGTL’s success to date is the fact that, very early on, we went out into the market and looked for manufacturing partners that have the balance sheets, the reputation and the resources to put a convincing consortium together. We’ve found the most worthy, most capable and most scalable partners with Fluor, Johnson Matthey, Sumitomo and Kawasaki. The investment from those partners in terms of engineering hours, samples, prototypes, and even manufacturing the catalysts and reactors that we needed for the Brazil demonstration, have been absolutely critical for our success. The other critical aspect is the fact that we’ve recruited experience in world-scale Hydrocarbon Processing | JANUARY 201433

Viewpoint GTL, mainly from South Africa, which has given us real operational insight, both from an engineering and operational model, and from an economic perspective.

plays. With the ongoing gas discoveries and the new gas supplies coming online, gas prices are set to be reliably low, while liquids prices are set to be reliably high,

“The market opportunity [for small-scale GTL] is absolutely vast. There’s plenty of room for other companies to come in to try and develop alternatives and enhancements, but it’s a high-stakes game.” Another thing that’s been absolutely critical is the success of the CompactGTL demonstration plant in Brazil. If it wasn’t for Petrobras making the decision to invest in a $45 million [MM] contract with us in 2008, clearly it would’ve been very difficult for us to achieve the level of maturity that we have now. We’re in conversations with nearly all the household names in the industry. The reason we’re in those conversations, and the reason we have these projects at these levels, is because of the robustness and the credibility that’s behind the technology. The market opportunity is absolutely vast. There’s plenty of room for other companies to come in to try and develop alternatives and enhancements, but it’s a high-stakes game. This technology is very difficult to develop, it takes time, and it takes a lot of money. CompactGTL has $200 MM invested to date to get us to this point. Our chairman, Tony Hayward, said earlier in the year that he believes this is an absolute game-changer for the industry. HP. Do you see small-scale GTL as being more applicable to onshore or offshore operations?

IB.The offshore market is an incredibly interesting proposition—although, in terms of volume, the onshore market is a vast market opportunity compared with the offshore. The opportunity for this technology outside of North America is very heavily geared toward processing associated gas and enabling oil field projects to proceed where flaring restrictions are in place. It’s also applicable to remote locations with no gas infrastructure, as well as to places where the costs of installing the infrastructure are prohibitive. However, in North America, the economic drivers are slightly different. There’s a surge of new gas discoveries in the shale 34JANUARY 2014 | HydrocarbonProcessing.com

and this has created a gas monetization opportunity in North America. It’s still most likely to be associated gas, but the economics are not necessarily driven by access to oil, but instead by creating value out of a very low-value gas commodity. In the last two years of development, CompactGTL has been able to bring the costs of its onshore plant offerings down quite substantially. We’ve been able to increase the scale at which it’s viable, which has really lent itself to the North American market. Taking into account the tax regimes among the different states, we’ve got pretty robust project economics that are looking at internal rates of return in the 20%-plus [range], based on realistic gas costs and realistic liquids revenues. So, North America is a really exciting area for this technology. What we’ve done for larger-scale projects is to harness conventional technology to generate the syngas—the first stage of the process. If we replace our modular reforming units with conventional technology, the size is still such that you can usually get the equipment into remote locations, and that drastically reduces the cost of the offering. For example, we’ll take a standard reformer from Lurgi or Haldor Topsøe, or another company that offers syngas technology, and we’ll marry that with our own modular FT units—the second stage of the process. This gives a good combination of the ability to move into remote locations and more reasonable capital costs, and it economically enables the project to stand on its own two feet for gas monetization. HP. What is the maintenance like on these units?

IB. The biggest factor for GTL plants in terms of maintenance is the replacement of the main process catalysts. One

of the unique aspects of CompactGTL’s technology is that we have a two-stage process that allows us to maximize the life of the cobalt-based catalysts inside the reactors. The first step toward minimizing the operational costs and maintenance is to ensure as long of a catalyst life as possible, and our patented technology is directed toward doing that. Our catalysts will last 3–5 years before they need replacement. The replacement strategy is to exchange entire modules. So, you bring spare modules in, because they’re all the same design, and swap them out to keep the plant running. Those modules are reactors that require the catalyst to be changed and then taken away from the site. They’re 40-foot-long, container-sized boxes, so we’ve deliberately constrained the design to make the logistics and transportation by truck viable and easy. The reactors are then returned to a factory environment, where our partners undertake the catalyst replacement process, creating a module that’s then ready to be redeployed either back to the original plant, or to another project somewhere else. The overall operational costs for one of these plants is about US$18 per barrel of liquid product produced, which includes the lifetime cost of replacing the catalysts, so [the economics are] pretty compelling. HP. What trends do you see in the GTL market, as a whole, over the next 5–10 years?

IB.The GTL market, in the broader sense of the word, is the business model adopted by Shell and Sasol, which are looking for large, reliable gas supplies. Usually, [these companies] insist on having ownership in the gas asset before investing in a plant. Peter Voser [CEO of Shell] recently gave an interview where he put a new perspective on what Shell and Sasol see in North America as the opportunity for GTL. CompactGTL’s technology isn’t really GTL in the true sense of the word; instead, it’s dealing with problematic gas and turning it into oil. It’s a different kind of business from what’s going on in large-scale GTL. In time, I think this [small-scale] technology will be bigger than large-scale GTL; there will be many of these small plants distributed everywhere.

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| Special Report NATURAL GAS DEVELOPMENTS The natural gas market is dominated by upstream development in shale gas production, particularly in North America, and by midstream and downstream progress in gas-to-liquids (GTL) and liquefied natural gas (LNG) technologies and projects. Despite Shell’s cancellation of its large-scale GTL project in Louisiana, the high spread between oil and gas prices over the last few years has drastically improved overall economics for GTL. In the US and several other countries, there is increased interest in small-scale and mobile processing technologies, especially for GTL and LNG production. Also, the rapid increase in gas production from shale formations, along with rising prices for natural gas liquids (NGL), are encouraging the construction of additional gas processing facilities in the US. This month’s Special Report features advances in technologies and market developments for gas processing and LNG. Photo: Crosstex Energy Services’ Eunice fractionation plant and processing facility in Louisiana. Photo courtesy of Crosstex.

Special Report

Natural Gas Developments A. BULTE, Foster Wheeler, Houston, Texas

Consider new designs for offshore LNG regasification terminals It is a common belief that the projected growth in gas demand—specifically, where liquefied natural gas (LNG) imports are needed to meet that demand— will require faster execution of LNG regasification terminals. Here, a new design for an LNG regasification terminal is presented that can meet aggressive schedules and be flexible in terms of site selection. The proposed solution for LNG regasification includes the following client objectives: • Develop a terminal that achieves commercial operation in 22–24 months. • Use floating storage units in lieu of LNG tanks to accelerate the startup date. The faster offshore time table helps avoid a protracted permitting process, which is often experienced with onshore terminal projects. • Improve the viability and cost of the project by locating it offshore. Often, potential onshore sites are not physically feasible, or they require large investments, such as extensive dredging, to make the sites acceptable. • Ensure low operating costs. One solution to meet the above objectives is to build a floating storage and regasification unit (FSRU). However, FSRUs tend to be less economic compared to traditional onshore regasificaction terminals, due in part to the high vessel leasing costs. An LNG regasification terminal concept has been developed that features a more competitive execution schedule than those offered by major FSRU providers, along with a significantly lower capital cost. Concept development and design. From a structural point of view, offshore LNG terminals can be fixed [sea island jetty, jacket, gravity-based structure (GBS)]

or floating [floating wharf (i.e., metal buoys fastened to anchor chains) and weathervaning]. The selected “support” technology is important, since it has a large impact on investment and operating costs, flexibility, safety, availability and reliability, time for completion and other factors. Moreover, to select a suitable technology, it is necessary to consider several factors such as location characteristics (climatic conditions, seawater depths, etc.), storage and sendout requirements, and environmental issues. The following options were considered: • FSRUs • GBSs • Floating storage units (FSUs) • Floating regasification units (FRUs). FSRU. This solution consists of a vessel that is new or reconverted from a carrier, equipped with tanks for LNG storage, and with all of the required vaporization process equipment. The FSRU’s main components are:

Compressor

Boiloff

Boilers

Boiloff Boiloff LNG

• LNG transfer system (offloading system) • Storage tanks (in ship) • Boiloff gas (BOG) handling system • LNG pumping system • Vaporization equipment • Delivery facility • Auxiliary systems. In the FSRU, the LNG delivered by carriers is received by the FSRU offloading system, stored in tanks, pumped and regasified into natural gas. The gas is then delivered to consumers through a flexible or rigid riser that is connected to the subsea pipeline, or via high-pressure loading arms fixed on a jetty. Prior to delivery, the natural gas flowrate is measured by an ultrasonic flowmeter, and the gas is odorized. FIG. 1 describes the principal components of an FSRU. The sketch illustrates three possible means of LNG vaporization: 1. Open-loop seawater: Pumping warm seawater across the vaporizer and discharging cooled seawater Power generator

Vapor

BFW Subsea pipeline

Hot water Remaining boiloff

NG

LNG LNG LNG LNG Storage LP pumps Recondenser offloading LNG HP pumps Open loop Valves 1, 2 open Valves 3, 4, 5 close

Metering station 5 LNG

Vaporizers

4

Close loop Hot water: Valves 3, 4 open Valves 1, 2, 5 close Vapor: Valves 4, 5 open Valves 1, 2, 3 close Seawater discharge

3 2 Seawater intake 1

FIG. 1. Process block scheme of an FSRU. Hydrocarbon Processing | JANUARY 201437

Natural Gas Developments TABLE 1. Cost comparison for various regasification alternatives

Initial CAPEX, million USD

Alternative solution

Leased FSRU

Onshore regasification and LNG tank

Onshore regasification with FSU

160 (based on caissons)

70

300

180

173

541 (including FSRU charter rate)

324

194

16 (based on caissons)

18–20 (considering that FSRU must be built)

36

22

Quick schedule

Quick schedule

Long schedule

Long schedule

Low

Low

High

High

High

High

Low

Medium (depending on vaporization system)

Total investment, net present value (10 years), including OPEX Optimum schedule up to mechanical completion, months Permitting Restrictions of applicable standards Potential for standardization

Note: This comparison is based on a storage capacity of 150,000 m3 and a sendout rate of 500 MMscfd.

BAD

Curve of values for client $300 M

$541 M

$180 M

$324 M

$160 M

36 m 22 m

$194 M $173 M

FSRU Onshore + TK Onshore + FSU Alternative solution

18 m-20 m

16 m Unit efficiency

Possibility of standardization

Restrictions of applied standards

Permits

Schedule

(Total investment + financial) present value

Initial CAPEX

GOOD

$70 M

FIG. 2. Value curve for the alternative regasification solution.

FSU plus FRU. This project alternative is based on providing two different vessels, one to function as an LNG storage vessel and the other to serve as the regasification unit. This solution is best suited for calm waters. The overall process is similar to the scheme shown in FIG. 1. GBS LNG terminal. This solution consists of a pre-cast caisson structure developed to receive LNG carriers. The structure includes internal LNG storage tanks, and the required regasification equipment is installed on the caisson superstructure. LNG carriers moor on this structure, as it is equipped with all required nautical equipment (quick-release hooks and a fender system) and unloading/process equipment (unloading arms, vaporizers, etc.). Quick-release hooks are devices intended for the safe mooring of large tankers; they allow for quick release by the control room. Experience shows that a GBS is an expensive solution. Delivery of the structure, including the storage tanks, can be protracted, meaning that this solution cannot meet accelerated schedules. Alternative solution. An innovative so-

FIG. 3. Alternative regasification unit module design.

2. Closed-loop water: Pumping freshwater through a closed circuit, in which the water is warmed in the FSRU boilers and cooled across the LNG vaporizer 38JANUARY 2014 | HydrocarbonProcessing.com

3. Closed-loop steam: Using steam produced in the FSRU boilers to vaporize the LNG and returning the condensate back to the boilers in a closed loop.

lution combines features of the three concepts outlined previously, and is designed to be modular and scalable. The solution consists of a regasification unit that is permanently moored to an LNG ship, which acts as the FSU. A gas pipeline connects to onshore receiving facilities to supply gas to the local pipeline grid. This configuration enables a permanent installation at a competitive price and on a fast schedule. The availability of the plant is higher than the regasification vessel alternatives because there is a lower impact from adverse sea conditions.

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Natural Gas Developments TABLE 2. Range of LNG compositions used in design Component, mol%

LNG heavy

LNG light

C1

87

97.53

C2

8.37

2.16

C3 iC4 + nC4 nC5 N2 Density at –159.8°C, kg/m3

3

0.25

1.2

0.04

0.23

0.01

0.2

0.01

470

429

Molecular weight

18.72

16.44

Higher heating value, megajoule/standard m3

42.87

38.42

FIG. 4. Typical plot plan for the alternative regasification solution.

The offshore facility consists of the following elements: • A conventional LNG carrier modified and classified to function as an FSU. The FSU is moored to a platform that also acts as a jetty. • A jetty/platform with facilities for mooring ships (LNG carriers and the FSU). Ships are moored on opposite sides of the jetty, and LNG transfer is carried out using the unloading arms installed at both sides of the jetty. • Offshore facilities and regasification equipment installed on top of the platform. 40JANUARY 2014 | HydrocarbonProcessing.com

FIG. 2 and TABLE 1 show the added value of this solution. Technical description. The regasification unit (FIG. 3) will be constructed so that all of the equipment and modules are integrated, transported and placed on a piled concrete platform, or on a concrete caisson, at the final destination. A commonly required sendout capacity is 500 million standard cubic feet per day (MMscfd) of gas, with an additional 50% peak capacity. The alternative design is based on three trains, each with a sendout capacity of 275 MMscfd, assembled together on one module. The system is configured as three regasification trains

at 33% operation each. The module contains the required pumps, motors, heat exchangers, instrumentation and control systems, along with interconnecting piping between the trains. Target gas outlet pressure is 33 barg–95 barg at the module’s edge. Turndown capability for each train is 100%–120%. The regasification unit is designed to handle LNG with a wide range of compositions, so it can be used with almost any available gas in the LNG market, as shown in TABLE 2. The plant is designed to comply with International Maritime Organization (IMO) standards and the requirements of classification societies, such as Det Norske Veritas (DNV). The system is designed and manufactured according to DNV guidance for offshore regasification installations. Prior to shipping, final leak and pressure testing is performed at the module yard. This testing must comply with DNV requirements. All components would have already been tested at the manufacturer facilities, according to recognized standards and/or classification society requirements. The plot plan (FIG. 4) is designed to provide: • Safe escape from working areas • Efficient ventilation of hazardous areas • Minimal explosion overpressure, in case of an ignited gas release • Access for firefighting and emergency response • Prevention of serious consequences from dropped objects • Facilitation of good operation and control in normal and emergency situations • Minimal possibility for escalation of fires and other failures or accidents • Safe containment of accidental release of hazardous liquids • Planned simultaneous operation • Easy maintenance access with maintenance cranes to all plant equipment • Loading arms designed to be compatible with the motion envelope of the FSU and the NG carrier • Space minimization to reduce the cost of the platform. Structural design. The loading platform (including the mooring and fendering system) and dolphins will serve to host the shuttle LNG carrier and unload the cargo via arms to the FSU. The FSU

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FIG. 5. Jacketed platform sketch.

FIG. 6. Float-over operation.

FIG. 7. Transport and installation at the site (FSU shown for size reference).

42JANUARY 2014 | HydrocarbonProcessing.com

will be permanently moored on the other side of the platform. Liquid cargo will be transferred from the FSU to the platform top regasification unit via LNG loading/ unloading arms. Over the piles (jackets), steel beams form the supporting structure for the platform (FIG. 5). The locations of the mooring dolphins and fenders take into consideration ship compatibility assessments carried out to guarantee the compatibility between the ship fleet and the proposed platform. Construction approach. Due to the challenges of working offshore, the construction strategy is based on: • Minimizing site work offshore • Minimizing the construction period • Designing for modularization. The plan is to deliver the modular plant (one module) as per the scheme shown in FIG. 6, using a semisubmersible ship (float-over). In summary, the construction process includes: • Construction of the steel/ concrete pile • Manufacturing and precommissioning of the module at the yard • Load-out of the module on top of a semisubmersible vessel (maneuvered via roll-on/roll-off) • Transport of the module from the yard to an offshore location (FIG. 7) • Unloading on top of the pile supports (float-off) • Module hookup • Commissioning and startup. In this option, the dolphins at one side of the platform are installed after the unloading of the module, to permit the maneuver of the ship.

FIG. 8. Cellular reinforced-concrete caissons.

Natural Gas Developments Alternative platform construction method. The compact regasification concept (70 m × 50 m) allows for a more standardized and modular civil infrastructure approach, which is consistent with a fasttrack schedule. Cellular reinforced-concrete caissons, comprising a base slab and vertical walls, can be used (FIG. 8). The delivery period of these components enables a fast-track schedule to be achieved. The regasification unit is placed on the caisson, and they can be transported together, with the caisson functioning similarly to a barge. Once the caissons arrive at the site, they are ballasted down with granular material to ensure stability against metocean actions and operation loads. (This can be done since part of the caisson is still open.) Later, the deck slab is cast in situ. One driver to consider this solution vs. the jacketed solution is that the supporting infrastructure’s main dimensions (beam and freeboard) are conditioned by operation and survival loads— i.e., equipment, berthed vessels and FSUs, metocean actions, seabed conditions, water depth and seabed depth.

There are cases where a caisson is not adequate; typically, this occurs as a result of poor seabed properties that limit bearing capacity, or a water depth greater than 17 m. The supporting infrastructure’s main dimensions may also be limited due to availability of pre-casting yards, or yards with enough capacity to accommodate the required beam or depth. However, since caissons can be towed, yards do not necessarily need to be close to the site area. In this regard, evaluation of metocean conditions for transportation and availability of windows are critical aspects. Limitations due to the size of access channels to the eventual offshore location may be more difficult to overcome. Takeaway. The novel design discussed

here for a fast-track, cost-effective LNG import terminal possesses the following characteristics: • Capacity of 500 MMscfd of natural gas sendout • Proven equipment • Known technology • High availability

• Ability to deal with a wide range of LNG compositions. This solution includes an FSU that allows for a reduction in execution time, compared with the construction of onshore LNG tanks. Civil works, if caissons are used, are not an issue in terms of schedule. Caissons can be designed and constructed in significantly less time than that required for the equipment delivery. Caissons can be towed far away from the pre-cast yard, providing a high level of flexibility in identifying the best yard location. Process skids can also be loaded on top of caissons for transportation. Construction execution is based on proven methods, similar to any other offshore upstream facility. ACKNOWLEDGMENT This article is based on a presentation at LNG 17 in Houston, Texas, on April 18, 2013. AUGUSTO BULTE is based in Foster Wheeler’s Houston, Texas office. He holds a master’s degree in marine engineering from Universidad de Oviedo in Spain, as well as a post-graduate degree in chemical engineering from Universidad Complutense de Madrid. Mr. Bulte has more than 17 years of experience in power and LNG projects.

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Special Report

Natural Gas Developments T. KOHLER and M. BRUENTRUP, Linde Engineering, Pullach, Germany; and R. D. KEY and T. EDVARDSSON, Linde Process Plants Inc., Tulsa, Oklahoma

Choose the best refrigeration technology for small-scale LNG production Low natural gas prices are allowing multiple secondary players in the US market to consider investments in smallscale LNG plants. A frequent question is which refrigeration technology is the best for liquefied natural gas (LNG) production. At first glance, there are numerous process alternatives on the market. However, when taking a closer look, the choice simplifies to either single mixed-refrigerant (SMR) or nitrogen (N2 ) expander technology. These technologies dominate the small-scale plant capacity range between 50,000 gallons per day (gpd) and 500,000 gpd of LNG. Here, a broad range of aspects and guidelines for which technology is best suited for what type of application is covered. Other technologies may be relevant for LNG plants with capacities below and beyond the range indicated, although the observations and conclusions presented here apply only to the aforementioned capacity range. Refrigeration process design. Two processes1 have been se-

lected as representative for the two competing liquefaction technologies. Both processes are based on brazed aluminum platefin heat exchangers (PFHEs) as the main heat exchangers in the liquefaction unit. The processes are a single-cycle, multistage mixed-refrigerant process and a dual N2 expander process. TABLE 1 NG

Refrigerant compressor

compares the primary components of these processes, while FIGS. 1 and 2 present process flows for the two technologies.

The high specific power requirements limit single N2 expander processes as a widely acceptable option. Other dualexpander processes have different detail process topology, use hydrocarbon components mixed with N2 as refrigerant, or are combinations of MR and N2 expander technology. The classic dual N2 expander and the SMR technology used in this model are believed to represent the cornerstones of the modern LNG technology range. Refrigeration process performance. The selection of plant

design parameters, such as ambient design temperature, feed gas pressure and composition, storage tank pressure, flash gas rate, etc., have a significant (± 20%) impact on the specific power requirement of an LNG plant. To make a meaningful performance comparison, it is fundamental to use an equal set of design parameters—or, since different processes are optimum at different conditions, an equal range can be used. For this reason, a range of design parameters has been studied, rather than a single, arbitrarily chosen point. Also, indication of absolute performance numbers has been avoided so as not to present misleading data. Instead, relative differences are provided. NG

LMR

Refrigerant compressor

Main heat exchanger

Main heat exchanger

Warm expander/booster HMR pump Cold expander/booster

HMR LNG

LNG

FIG. 1. Process flow diagram of the dual N2 expander process.

FIG. 2. Process flow diagram of the SMR process. Hydrocarbon Processing | JANUARY 201445

Natural Gas Developments The selection of machinery efficiencies has a significant impact on this process comparison. Some literature sets these efficiency values at 100%, assuming an equal basis of comparison. However, this will lead to a false conclusion: Theoretically, the N2 expander cycle would have up to 15% less power than the SMR. To provide a comparison that matches reality, typical machinery efficiencies have been selected. N2 compressors typically show better efficiencies (82.5%) than MR compressors (80%), while both processes make use of an integrally geared turbocompressor as a cycle compressor, providing optimum compression efficiency. For the expander turbines, 85% efficiency was selected. Sensitivity analysis. Design ambient temperature impacts the process performance, as shown in FIGS. 3 and 4. While FIG. 3 illustrates that power consumption of any refrigeration process increases with rising ambient temperature, FIG. 4 shows how the N2 expander performs relative to the SMR.2 TABLE 1. Main equipment components for the SMR and N2 expander processes

Refrigeration unit

SMR equipment

N2 expander equipment

1 cycle compressor

1 cycle compressor

1 set of HMR pumps

2 expanders/booster compressors (mounted in insulation boxes)

2 air coolers

3 air coolers

3 compressor suction/ receiving drums Liquefaction unit

1 coldbox

1 coldbox

1 PFHE

1 PFHE

1 phase-separator vessel Makeup unit

2 storage drums, including dryers

1 LN2 tank with air-heated vaporizer

1 air-heated vaporizer 1 LN2 tank with air-heated vaporizer

On average, the N2 expander cycle requires approximately 30% more power than the SMR cycle. This power consumption difference is reduced as the ambient temperature increases. FIGS. 5 and 6 show how design feed gas pressure impacts the process performance. FIG. 5 demonstrates that power consumption of any refrigeration process is lower with higher feed gas pressure. FIG. 6 shows how the N2 expander cycle performs relative to the SMR.2 On average, the N2 expander cycle requires around 30% more power than the SMR cycle. This power consumption difference is reduced as the feed gas pressure increases. It can be concluded that the power disadvantage of the N2 expander cycle is lowest for a plant with low design feed gas pressure and high design ambient temperature; a nearly 25% power consumption difference can be reached in this favorable case, whereas up to a 35% power consumption difference may result for the other extreme. Since refrigeration process efficiency is improved by obtaining a close match between the feed gas and refrigerant (Q /T) cooling curves, composition of the feed gas also has an impact. Analysis of this parameter has been performed and appears to have only a moderate effect. The N2 expander cycle tends to perform slightly better on lean feed gases. The improvement may be up to 5% with reference to the aforementioned difference. The background of this observation is that N2 works as a highly efficient refrigerant in cryogenic applications, but shows poor efficiency at higher temperature levels of the liquefaction process. Precooling. Since N2 shows poor efficiency at high liquefaction temperatures, many N2 expander liquefiers include a precooling unit that provides refrigeration duty at higher temperature levels. Fundamentally, three options for precooling exist: • Feed gas • Refrigerant • Feed gas and refrigerant. A variety of precooling technologies presents a wide range of options. Ammonia and propane chilling are still considered the most common options in the simplest case, within a singlecycle, single-stage refrigerant process. Adding more stages will improve efficiency, but it will also increase cost and complexity.

Liquefaction power vs. ambient temperature @ 40 bar/580 psi liquefaction pressure

Specific power, kWh/t

Specific power demand relative to SMR, %

40

25

30

35

40 Temperature, °C

45

FIG. 3. Power vs. ambient design temperature.

46JANUARY 2014 | HydrocarbonProcessing.com

50

55

Specific power demand SMR vs. dual N2 expander @ 40 bar/580 psi feed gas pressure vs. ambient temperature

35

N2 expander

30 25 20 15 10 5 0 25

SMR 30

35

40 Temperature, °C

45

50

FIG. 4. Specific power demand for SMR vs. dual N2 expander.

55

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Natural Gas Developments Based on exemplary calculations for a simple propane chiller, there appears to be improvement potential for the N2 expander cycle of up to 15% compared to the stated values for the uncooled cycle. Feed gas precooling is technically simple, whereas refrigerant precooling is more complex, but also more rewarding. In a best-case scenario, the power disadvantage of a precooled N2 expander cycle may be as low as 10% to 15% above a (non-precooled) SMR cycle. Additional observations. Aside from power consumption, two other parameters with impact on investment cost are significantly different for the two refrigeration processes. Whereas the SMR cycle uses a two-phase refrigerant, the N2 refrigerant in the N2 expander cycle is always in the gas phase. It is not surprising that volumetric flows (and, therefore, pipe diameters) are larger in the N2 expander cycle than in the SMR cycle at any given duty. Also, refrigerant pressures (and, therefore, pipe schedules) typically need to be significantly higher to get to reasonable pipe diameter and process efficiencies. In reference to the given example: • The suction line diameter of the refrigerant compressor is 20 inches (in.) for the SMR cycle and 24 in. for the N2 expander cycle

Specific power, kWh/t

Liquefaction power vs. feed gas pressure @ 40°C/104°F ambient temperature

25

30

35

40

45 50 Feed pressure, bar (a)

55

60

65

FIG. 5. Liquefaction power vs. feed gas pressure.

Specific power demand relative to SMR, %

40

Specific power demand, SMR vs. dual N2 expander vs. feed gas pressure

35 30 25 20 15 10 5 0 25

SMR N2 expander 30°C N2 expander 40°C N2 expander 50°C 35

45 Feed pressure, bar (a)

55

FIG. 6. Specific power demand for SMR vs. dual N2 expander.

48JANUARY 2014 | HydrocarbonProcessing.com

65

• The high-pressure refrigerant operates at approximately 40 bar (600 psi) for the SMR cycle and 70 bar (1,000 psi) for the N2 expander cycle, resulting in Class 300 piping for the SMR cycle and Class 600 piping for the N2 expander cycle. Technical and operational pros and cons. A number of

additional aspects should be considered when comparing both technologies, as a thorough response requires more technical background information. Refrigerant use and makeup system. Both the SMR and N2 expander refrigeration cycles operate in closed loops; i.e., they do not “consume” refrigerant during operation. Typically, the compressors and seal systems used in these refrigeration cycles are not completely leak-tight, and, therefore, leakage must be replaced by “makeup.” A makeup system is required in every case. For the N2 expander cycle, this system may consist of a liquid nitrogen (LN2 ) tank with an evaporator as the simplest solution. Additionally, for the SMR cycle, makeup storage of the hydrocarbon components C2 to C5 is also required. Note: C1 makeup is sourced from the feed gas. Refrigerant makeup rates are typically much higher for N2 expander plants. This higher makeup rate is due to design differences between the SMR cycle and the N2 expander cycle compressor seals: • N2 compressors and expanders/boosters are traditionally a product of the air separation industry, where leakage losses are considered an efficiency loss. Therefore, inexpensive labyrinth seals are a standard solution. Labyrinth seals offer leakage rates of around 3% to 6% of the flow. Alternatively, carbon ring seals offer a reduced leakage rate (around 0.2% of flow) at a slightly higher cost and are, therefore, typically used for N2 refrigerant compressors. • SMR compressors are products of the oil and gas processing industry, where hydrocarbon leakage is considered a hazard and must be minimized. Dry gas seals (DGSs) are the standard design, offering minimal leakage rates (only 1% to 10% of the leakage rate of wet gas seals). They are mostly independent from the compressor throughput. However, dry gas seals feature significantly higher complexity and come at a much higher cost (approximately $250 thousand USD), which is why DGSs are not commonly used for N2 compressors. Note: Hermetically sealed compressors, exhibiting zero refrigerant loss, have also been reviewed to complete the picture. In the analyzed capacity range and at the assumed cost of makeup components, they do not seem to be an economical escape route, either for the mixed refrigerant or the N2 compressor. Alternately, hermetically sealed expanders/boosters appear more attractive, despite only contributing a minor part of the total leakage rate in an N2 expander cycle. Although refrigerant leakages from the cycle are considered unavoidable, it does not automatically mean that those losses must be fully matched by external makeup imports. It is technically feasible to recover major parts of refrigerant losses. The question is whether or not this alternative is the most economical. Whereas large-scale LNG plants usually take the C2 to C5 makeup components from the fractionation process, in most cases, this is not an economical option for small-scale LNG plants, although it is technically feasible and has been success-

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Natural Gas Developments fully demonstrated. Therefore, makeup import from external sources is usually considered, and refrigerant components are limited to C2 and C4. This comes at the expense of a small efficiency loss, which is considered in the efficiency comparison. This small efficiency loss helps to minimize both the investment cost for the makeup system and logistical/procurement efforts for the plant operator. While an inexpensive/high-leak seal design is technically an option for N2 expander cycle machinery, it is an economic question of which setup offers the best lifecycle cost, as will be discussed later. Makeup system operation. In the N2 expander cycle, the operator must monitor the cycle pressure and add N2 when the pressure drops below certain limits. The machinery seal type and resulting leakage rate of the system determine the frequency for adding makeup. This frequency may range from a continuous operation to a weekly occurrence. Operating efforts may be doubled in case a C3 precooling cycle is added to the N2 expander cycle (depending on C3 compressor seal design). For the SMR cycle, leakage and resulting makeup rates are lowered by an order of magnitude. Nonetheless, the operator must monitor the refrigerant composition in addition to the cycle inventory. An online analyzer (i.e., a gas chromatograph) is provided to this end, and biweekly checking of inventory and composition is recommended. (Contrary to statements found in some literature, the authors’ experience TABLE 2. Differences in capital cost for SMR vs. N2 expanders Dual N2 expander CAPEX difference, million USD

SMR

High CAPEX/ low OPEX

Low CAPEX/ high OPEX

0

+0.15

+0.15

Rotating equipment

+0.3

+0.8

0

Static equipment

+0.15

0

0

0

+1.4

+1.4

Static equipment

+0.6

0

0

Bulk materials and labor

+0.7

0

0

+1.75

+2.35

+1.55

Liquefaction unit Refrigeration system

Bulk materials and labor Refrigerant makeup system

Total

TABLE 3. Differences in operating cost for SMR vs. N2 expander Dual N2 expander OPEX difference, million USD per year

SMR

High CAPEX/ low OPEX

Low CAPEX/ high OPEX

0

+0.7

+0.7

+0.15

0

0

Nitrogen (0.1 USD/lb)

+0.07

0

+0.75

Total

+0.22

+0.70

+1.45

Electric power (0.06 USD/kWh) Refrigerant makeup/seal gas MR hydrocarbon components (0.4 USD/lb)

50JANUARY 2014 | HydrocarbonProcessing.com

has shown that SMR cycle efficiency is quite forgiving to offspec MR composition and is sufficient to achieve close to the recommended component mix.) To add makeup components, automated functions can be activated by the operator on the control panel without any need for further field operator intervention. Operator failure to maintain refrigerant composition may result in slowly decreasing process efficiency. Operation at off-design conditions. Liquefaction capacity can be adjusted for both refrigeration technologies. In principal, capacity is influenced by the refrigerant system inventory; i.e., reduced refrigerant system inventory will result in lower pressures, lower refrigerant mass flows and lower LNG production. For the N2 expander cycle, such inventory adjustment is a widely used method to achieve efficient partial-load operation. The operator must only release or add inventory to decrease or increase the plant load. By doing so, the refrigerant compressor antisurge valves can remain closed over a wide load range. In this way, process efficiencies near design can be maintained. To avoid losing released refrigerant, a dedicated buffer drum can be added for temporary storage. This can be quite a large and expensive vessel, depending on the plant capacity, but operation of such a system is relatively simple. The typical N2 expander process can reach a partial load as low as 30%. The SMR technology features the maintenance of a twophase refrigerant of a certain composition. Releasing inventory is more complex and, therefore, is only done occasionally. Dumping of released refrigerant usually is not an option, so temporary storage is required. Without such optional extra equipment, partial-load operation is realized by reducing the compressor throughput (e.g., via inlet guide vanes) and, below a certain load, opening the recycle valves to protect the compressor from surge. Partial-load process efficiency will drop drastically when operating in recycle mode. To maintain correct two-phase flow patterns in the PFHE, partial-load operation is limited to approximately 50% in this setup. In the frequent case where extended partial-load operation is expected—mostly during the initial operating period of an LNG plant—no extra equipment is needed. In that case, operations require the filling of the SMR cycle inventory up to the level corresponding to the desired plant load. This step-by-step procedure allows for highly efficient partial-load operation (as low as 30%) at no additional cost. Additionally, SMR technology gives the option to vary the refrigerant design composition to improve process efficiency at off-design operating conditions (typically, ambient temperatures). This can be realized to a limited extent by modifying the ratio between heavy mixed-refrigerant (HMR) and light mixed-refrigerant (LMR) flow; otherwise, manual adjustment of the composition is required. To avoid loss of refrigerant, such an adjustment should be made in the normal frequency of adding makeup, unless a refrigerant buffer is provided. Therefore, this method is only suitable for longer-term (typically, seasonal) adjustments, rather than daily adjustments, although it may still result in lower annual power consumption. Startup time. Startup from a warm condition to a full load must be performed slowly with the SMR option. This is necessary to keep thermal stress in the PFHE within permissible limits, because liquid refrigerant has a far higher heat-

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Natural Gas Developments transfer coefficient than does gas. With liquid refrigerants, the Economics. Differences in investment and operating cost have PFHE core temperature approaches refrigerant temperature been determined for some examples to ensure that evaluation of faster. Typically, the startup of an N2 expander process can the different technologies is considered on an equal basis. The exbe achieved in about half the time required for the startup of an SMR process. For a cold plant restart (e.g., after a trip where the Having demonstrated only minor PFHE remains cold), there is no difference in startcapital cost differences between the up time between the two refrigeration technologies. Plant maintainability. Compressors are the two refrigeration technologies, it can main focus when assessing plant maintainability. be concluded that a decision is best There are significant differences in rotating equipment quantities and design between refrigeration based on operating cost and operability technologies. For the SMR cycle, there is only one issues. For applications with high annual compressor and, therefore, only one set of capital operating hours near design load, the SMR spare parts to be procured. The N2 expander cycle comprises two additional technology has a strong advantage with expander/booster sets. Therefore, three machines respect to operating cost. require regular maintenance, and three sets of capital spare parts must be procured. The typical seal systems used in this scenario have good operating records, and spare parts are a much lower matter of expense than ample provided is deemed representative. It encompasses a typifor DGSs. Also, the likelihood of unscheduled maintenance cal LNG liquefier (i.e., liquefaction, refrigeration and makeup issues is greater on three pieces of compression equipment vs. units) in a US Gulf Coast location with a capacity of 200,000 gpd. a single piece of compression equipment. For the N2 expander cycle, two options are shown in TABLE 2: One possibility to achieve at least equal maintainability is 1. Process machinery, either seal-less or fitted with refrigto use hermetically sealed expander/booster sets with magerant recovery, resulting in higher investment cost but netic bearings that are more or less maintenance-free, in addilower utility consumption and operating cost tion to their advantage of zero refrigerant leakage. 2. Process machinery fitted with standard seal systems The N2 expander cycle situation is more impacted when a (C-rings on the refrigerant compressor and labyrinths elsewhere), resulting in lower investment cost but higher precooling cycle is added to enhance process efficiency, as this utility consumption and operating cost. configuration adds a fourth compressor. Capital cost. Capital expenditures (CAPEX) include enEnvironmental and process safety. The handling and storgineering, procurement and construction (EPC) and turnkey age of LNG is key when it comes to safety and permits for LNG delivery of the LNG liquefier. In each cost line item, the lowest plants. There is no difference between the two refrigeration option has been set to zero, and the incremental cost of the altechnologies in this regard. The methodology for determining ternatives is indicated. Optional features (e.g., refrigerant bufexclusion zones typically results in similar separation distances fer systems) have not been considered. that are accounted for in a standard plant layout. Risks of exObservations on this comparison include: plosion and jet fires resulting from high-pressure natural gas • SMR compressors are expensive equipment compared piping systems are also comparable, as is the requirement for to the air separation unit machinery of the N2 expander explosion or fire protection. The small advantage an N2 expander plant may have is cancycle • Piping quantities are greater than 100% higher for the N2 celed when C3 precooling or ammonia precooling is added. These considerations drive the novel CO2 precooling system expander cycle compared to the SMR cycle, resulting in to appear on the agenda for floating LNG (FLNG). significantly higher materials and construction cost To achieve the same compact layout at an equal level of safe• Total cost differences between the three alternatives are ty, the SMR plant will only incur additional cost for safety measmall—only about 5% when considering the absolute sures when forced into a congested plant layout by the available cost of the exemplary liquefier system, or 1% when conplot space—e.g., in an FLNG plant. sidering the absolute cost of the exemplary, complete, While some publications suggest that the N2 expander cygreenfield LNG plant. Operating cost. Operating expenditures (OPEX) assessed cle is friendlier to the environment than the SMR due to its use in TABLE 3 account only for power and refrigerant makeup conof N2 as the refrigerant, this is only a partial truth. The refrigerant is operated in a closed cycle, with the compressor seals sumption and are based on 8,000 hours per year. The cost for as the only significant point of leakage. The small seal leakage operating personnel will be identical, whereas cost differences from an SMR cycle compressor will usually be flared, resulting for equipment maintenance are difficult to assess precisely. in CO2 emissions, or it may be recycled. In this case, the N2 Observations on this comparison include: • The SMR cycle shows the expected benefits with respect expander cycle has an environmental benefit, since its seals will to power consumption release only harmless N2 . However, when evaluating energy ef• For the N2 expander cycle, the cost of LN2 makeup ficiency with a corresponding CO2 footprint, this advantage is turned on its head, and the SMR cycle has more benefits. reaches the same order as the cost of power Hydrocarbon Processing | JANUARY 201451

Natural Gas Developments • When considering a 15-year lifecycle cost, the relative OPEX disadvantage of the N2 expander cycle to the SMR reaches the same order of magnitude as the absolute cost of the exemplary liquefier system. Recommendations. Having demonstrated only minor capital cost differences between the two refrigeration technologies, it can be concluded that a decision is best based on operating cost and operability issues. For applications with high annual operating hours near design load, such as baseload or peakshaving LNG plants, the SMR technology has a strong advantage with respect to operating cost. Its disadvantages, including longer startup time and reduced partial-load capability, are less relevant. For applications with low annual operating hours and wide load-profile requirements, such as boiloff gas reliquefaction units, the N2 expander cycle, with a refrigerant buffer system, offers significant advantages with short startup time, as well as wide partial-load capability and efficiency, while low operating hours compensate for higher specific operating cost. Additionally, in remote areas where C2 and C4 makeup component delivery comes at high logistical effort and price, the OPEX gap between the SMR cycle and the N2 expander cycle will be smaller. However, this situation will rarely arise in the US. The extra investment in an N2 expander cycle low-leakage system typically will have an attractive payback time of less than three years.

NOTES The SMR process used in this study is Linde’s proprietary single-cycle, multistage mixed-refrigerant process LIMUM. The N2 expander process is BHP Billiton’s licensed dual-nitrogen expander process. 2 SMR power consumption is used as a reference point for comparison and is, therefore, set to 100% throughout the temperature/pressure range. 1

THORSTEN KOHLER graduated from the University of Erlangen-Nuremberg, Germany in 1997 with a master’s degree in chemical engineering, and he joined Linde Engineering in 1997 as a systems and commissioning engineer for adsorption plants. Mr. Kohler moved to Linde Engineering’s process design group for LNG and natural gas processing plants in 2002. Since 2006, he has been working as lead process engineer on small- to mid-scale LNG projects, including proposal work, contract executions and commissioning. MATTHIAS BRUENTRUP graduated from Munich Technical University in Germany in 1996 with a master’s degree in engineering, and joined Linde Engineering in 2000 as a project manager. He has been working on small- to mid-scale LNG projects since 2005 in various positions, including as proposal manager and senior project manager. Based on this experience, Mr. Bruentrup became a product manager for small- to mid-scale LNG plants in 2012. RON D. KEY graduated from the University of Tulsa in Oklahoma with bachelor’s and master’s degrees in chemical engineering, and joined Linde Engineering in 1988. He holds six process-related patents. Mr. Key is presently serving as the vice president of technology and sales at Linde Process Plants Inc., and he is an experienced business leader in engineering, procurement, fabrication and construction. TINA EDVARDSSON graduated from Chalmers University of Technology in Sweden in 1985 with a master’s degree in chemical engineering, and joined Linde Engineering in 2012. She holds four process-related patents. Ms. Edvardsson is presently serving as the director of business development at Linde Process Plants Inc. She has more than 25 years of experience in developing processing and power plant projects in the domestic and international markets.

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Moving the Gas Industry Forward

The Gastech Young Engineer Foundation (GYEF) is a Gastech initiative that supports the next generation of engineers who are moving the industry forward. Recognising the growing need to attract young talent into the industry to fill the skills gap, the GYEF seeks to recognise and support young energy professionals who will eventually become the industry’s future leaders. The GYEF will bolster the professional development of young engineers, providing successful candidates with a package of educational and networking opportunities. To meet the young engineers of the future, visit Gastech 2014.

For more information about the GYEF please contact: Kate Cheetham, Event Producer, [email protected] +44 (0)203 615 2845

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Special Report

Natural Gas Developments J. WANICHKO, T.A. Cook Consultants, Raleigh, North Carolina

The ethane addiction: How long will the US’ advantage last? The price advantage US petrochemical producers have gained from shale has been well documented, but the wider effect of that advantage on competition between Europe and the US demands equal attention. Here, the increasing use of ethane as a feedstock and its effects on the global petrochemical industry, both in terms of product availability and the market-specific nuances that affect the survival of its key players, are examined. United States of shale. Until 2006, shale

was responsible for almost none of the US’ crude oil demand, of which approximately 10 million barrels per day (MMbpd) of the 16 MMbpd were imported. However, by July 2013, the Bakken and Eagle Ford shale plays in the US were together responsible for just over 1.4 MMbpd, adding steadily to the amount of domestically produced conventional crude. As a result of the changes in supply, the US changed from being a natural gas importer to a nation with a surplus of gas, pushing the industrial price of natural gas to record lows of just over $3 per thousand cubic feet in 2012. According to the American Chemistry Council, the price of ethane produced from gas dropped significantly, from a high of 93 cents per gallon (gal) in 2008 to only 26 cents/gal at the end of 2012. Not surprisingly, the effect of such low ethane prices has been a jump in ethane margins to 25 cents per pound (lb) in mid-2013, showing an advantage against naphtha of almost 30 cents/lb, which has fluctuated around the zero mark. This, in turn, has prompted the announcement of a number of ethylene-specific construction projects based solely on the ethane available from shale. By 2017 alone, over 7.7 million (MM) tons of capacity will come online from firms including ExxonMobil

Chemical and Chevron Phillips (TABLE 1), while additional capacity will be available from the expansion of existing units. According to analysts, this additional ethylene capacity will require 12 MM tons per year (MMtpy) of extra ethane, which could result in an ethane deficit of more than 3.5 MMtpy—even when taking shale development into account—if all of those projects and extensions are completed. The obvious result would be limited supply, increasing prices and decreasing profit margins.

Second, since Europe predominantly built its infrastructure around naphtha cracking, which is tied to the price of crude oil, its petrochemical industry has inevitably suffered from recent oil price highs of $100/bbl. If the dwindling crude reserves in the North Sea—from which European producers have historically gained a lead—are taken into account, then the US’ competitive advantage from shale development puts European producers in a very tough position. Better late than never. This scenario

The European environment. Mean-

while, in Europe, the effects of ethane cracking in the US have been felt keenly, for two key reasons. First, while Western Europe is home to a number of shale formations (799 trillion cubic feet of technically recoverable resources, according to the US Energy Information Administration), shale remains a highly controversial political issue in Europe. The environmental effects of hydraulic fracturing (i.e., fracing) on water tables and greenbelt areas are regularly publicized by lobbies and parties that oppose the development of shale plays. For this reason, politicians are hesitant to publicly endorse fracking. President François Hollande of France has gone so far as to maintain a ban on the use of fracing technology.

has spurred European companies to jump on the ethane bandwagon and arrange contracts with producers in North America to import the chemical. Ineos Europe AG, for example, announced a new agreement to source ethane from Marcus Hook, Pennsylvania, for use in its cracker complexes in Europe, which are due to come online in the first half of 2015. In the short term, similar deals could help improve margins for producers in Europe, but pending legislation in the US designed to limit the amount of ethane permitted for export could hinder Europe’s progress and instead preserve the US’ competitive advantage. Even if European companies sign contracts quickly, those contracts will fail to address the high level of investment needed

TABLE 1. Planned new crackers in the US, based on capacity from shale Company Sasol

Capacity, MMt 1.5

Location

Startup

Lake Charles, Louisiana

2017

OxyChem/Mexichem

0.544

Ingleside, Texas

February 2017

ExxonMobil Chemical

1.5

Baytown, Texas

Late 2016

Chevron Phillips Chemical

1.5

Cedar Bayou, Texas

Mid- to late-2017

Dow Chemical

1.5

Freeport, Texas

2017

Formosa Plastics

1.2

Point Comfort, Texas

2017

Hydrocarbon Processing | JANUARY 201455

Natural Gas Developments to secure European feedstock availability and renew its aging infrastructure over the long term.

tpy. However, according to some analysts, even this extra capacity will not be able to satisfy huge global demand, par-

As more countries develop their shale positions, the scale of change the US’ ethane extraction has started could grow dramatically over the coming years, altering the structure of the worldwide petrochemical industry. Present estimates state that 33% of crackers in Europe will become uneconomical by 2015. For major players, such as Shell, the level of capital required, the high price of construction work, and the significantly higher margins available from exploration and production, have made selling the only option. Furthermore, EU regulations related to fuel quality and emissions add “a heavy and sometimes conflicting burden” on operators in the region, placing the EU at a “major competitive disadvantage,” according to Europia, the European petroleum industry association. Instead, firms in countries such as Saudi Arabia, Brazil and South Korea are investigating building their own crackers on US soil. Propylene panacea. At this stage, the

coproducts formed from naphtha cracking begin to increase in importance. A key effect of the ethane surge on the petrochemical market is the reduction in coproduct volumes that have occurred. Naphtha cracking produces a mixture of coproducts—namely propylene (C3 ) and butadiene (C4 )—and yields approximately 30% ethane. Cracking ethane produces a yield of about 80% ethylene, but hardly any propylene or butadiene. The trend toward building ethylene-only plants, and the decrease in the building of new FCC units, means that traditional sources of propylene production will not be able to keep up with demand, which is estimated to be growing at 5%–6% per year globally. The resulting shortage in propylene supply has increased prices and prompted the announcement of a number of on-purpose propylene projects in North America, which together could pump enough propylene into the market to reduce the demand gap to 750,000 metric 56JANUARY 2014 | HydrocarbonProcessing.com

ticularly from Asia, which, like Europe, traditionally relies on naphtha cracking. This gap between new supply and rising demand could be the panacea that Europe needs to get ahead. Although the margins to be gained from ethane in Europe are somewhat limited due to transportation and security costs, propylene is in short supply, the naphtha needed to make it is still available in Europe and the infrastructure to produce it alredy exists. Maintaining maturity. Europe is a

mature market, and growth is far slower than in Asia and the Middle East. European infrastructure is older and cannot compete with the super-refineries being built abroad. However, that maturity also means that Europe has developed a substantial advantage in terms of knowledge and technology. The petrochemical clusters around Rotterdam and Antwerp, in particular, employ large numbers of highly skilled and experienced staff that have used their know-how to greatly increase plant efficiency. Production sites are well-integrated and serve a domestic market that is easy to reach, keeping logistics costs low. In contrast, huge distances in the US translate into equally large transportation costs. To sustain its low-cost position, Europe’s companies must make vital strategic decisions as to how to survive, whether via consolidation, organic growth or upstream and downstream integration. The best use of technological know-how and product portfolios, aging assets, and the value and source of research and development are all fundamental to staying profitable over the long term. If operators decide not to sell, ongoing investment is required to keep facilities competitive; assets must be kept in

optimal working condition, and employee skills must be leveraged, so that maintenance and safety standards remain high. To remain competitive, it is vital to account for all spending and to carefully examine the effectiveness of expensive processes, such as shutdowns, contracted costs and labor productivity. The great shale play. These market-specific and political nuances mean that it is unlikely that most European operators will switch to lighter feedstock. Instead, they will develop their propylene and butadiene positions to exploit the margins created by the US’ ethane demand. It is, therefore, possible that pockets of specialized production could develop along geographic lines, affected by and involved in global trade, but engaged at the same time in localized niches for a particular product. As more countries develop their shale positions (China alone is estimated to have more than two and a half times the shale reserves of the US), the scale of change that the US’ ethane extraction has started could grow dramatically over the coming years, altering the structure of the worldwide petrochemical industry. Presently, Europe is at the less positive end of the cost curve, but if producers move into higher-value-added products and ensure that they stay ahead in innovation and technology, that is unlikely to remain the case for long. If ethylene is produced on a scale large enough to create a global supply glut, then the margins enjoyed by producers in the US will rapidly decrease. Those desperate to jump onto the ethane bandwagon might do well to focus on the long game, for this play is far from over. JERRY WANICHKO is the director of consulting operations for T.A. Cook Consultants in North America. He has over 25 years of international consulting experience in several industries, with expertise in oil, gas and chemicals. Previously, Mr. Wanichko was the director of operations for Fluor, where he provided routine maintenance, reliability, and planning and scheduling services across 13 different petrochemical sites. Mr. Wanichko provides consulting services to asset-intensive businesses in the refining and petrochemicals industries. His work supports clients with maintenance optimization, turnarounds, outages, shutdown optimization and overall equipment-effectiveness improvement.

Special Report

Natural Gas Developments J. CHOSNEK, KnowledgeOne, Houston, Texas; and V. H. EDWARDS, IHI E&C International Corp., Houston, Texas

From LNG imports to exports: Process safety and regulatory challenges As natural gas becomes more abundant in the US, the demand for liquefied natural gas (LNG) imports is disappearing, while the need to find markets for domestic natural gas is increasing. LNG terminal operators are thus switching from LNG imports, which require regasification, to LNG exports, which require liquefaction, resulting in dramatically changed processing. In liquefaction, new flammable refrigerants have been introduced in large quantities for cryogenic cooling. These compounds can form vapor clouds similar in size to LNG, but the new compounds will reach further and be more reactive than LNG vapors. Additionally, in liquefaction, there is significant processing involving compression and distillation at high pressures and cryogenic temperatures. The natural gas and the LNG itself will be at high pressures, on the order of 600 psig to 1,000 psig, with large process flows and inventories. Also, the incoming high-pressure pipeline gas needs to be conditioned to remove mercury (Hg), hydrogen sulfide (H2S), carbon dioxide (CO2 ), water (H2O) and C2+ hydrocarbons prior to liquefaction. This additional processing presents hazards that have not been previously addressed in LNG import plants. These new hazards must be examined in modeling studies and also considered in facility siting to minimize risk.1 LNG is a heavily regulated commodity, and that poses challenges for producers. The US Federal Energy Regulatory Commission (FERC) regulates LNG through the US Department of Transportation’s (DOT’s) Pipeline Hazardous Materials Safety Administration (PHMSA). The main regulation is 49CFR 193, which is based on National Fire Protection Association (NFPA) regulation 59A.2, 3, 4 These regulations and standards are mainly

consequence-based instead of risk-based, because import problems could be solved with impoundment to comply with the regulations. This has changed significantly with export facilities, and guidance to, and from, government agencies is needed.5, 6 Import characteristics. LNG import

facilities are comparatively simple, as summarized here: • Receive LNG from a ship • Store LNG • Pump to high pressure • Heat to vaporize • Put gas into pipeline. In essence, LNG is received from a ship and pumped to large storage tanks that operate at low pressures. The LNG is then pumped to high pressures, allowing for regasification, and subsequently put into pipelines. Export characteristics. In contrast to LNG imports, LNG exports are more complex. Here are typical steps in the liquefaction of natural gas: • Receive natural gas (primarily methane) from pipeline at high pressure • Clean gas: Remove Hg, H2S, CO2 and carbonyl sulfide • Dry gas • Remove heavies and fuel gas • Liquefy (potentially one or more refrigeration cycles) • Where natural gas supply contains significant nitrogen, strip nitrogen from LNG • Send to storage tank • Pump to ship. Natural gas is received from pipelines at high pressure (typically 1,000 psi). When processing it, first mercury is removed by adsorption. Then H2S and CO2

are removed from the gas by absorption, typically using an aqueous amine solvent. The wet gas is then dried and cooled and heavies are removed and sent to fractionation, where byproduct condensate is sent out for sale. Next, the lean gas is liquefied by refrigeration, and, if it contains significant amounts of nitrogen, it is stripped before sending the LNG to storage. From storage, LNG is pumped to an LNG tanker for export. Process chemicals. TABLE 1 contrasts the process chemicals in LNG regasification and natural gas liquefaction to LNG. Import safety issues. LNG import is not without its challenges. These are the primary sources of process hazards: TABLE 1. Contrasts in process chemicals in LNG regasification and natural gas liquefaction Regasification LNG (predominantly methane) Natural gas Nitrogen Liquefaction LNG (predominantly methane) Methane Nitrogen Carbon dioxide Hydrogen sulfide Water Condensate (C3+ hydrocarbons) Propane, propylene Ethane, ethylene Butanes Mixed refrigerant Amine Hydrocarbon Processing | JANUARY 201457

Natural Gas Developments • LNG handling, transfers and releases • Cryogenic temperatures • Fire • Explosion (low probability due to low congestion and low reactivity) • Asphyxiation. Accidental releases of LNG pose all of the above hazards, but explosion hazards are comparatively low because the simplicity of the process leads to low conges-

tion, and the high concentration of methane keeps reactivity low. Export safety issues. Liquefaction has

all of the challenges of LNG importation, plus quite a few others: • Handling of high-pressure and low-temperature refrigerants • High processing temperatures (natural gas pre-treatment) • Higher-intensity fires

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• Explosion (higher probability, higher congestion and reactivity) • Toxic exposure from H2S present in the incoming natural gas • Training • Facility siting. Because natural gas liquefaction processes typically contain some process streams rich in C2+ hydrocarbons, there is a higher risk of explosion from these more reactive compounds. In addition, the greater process complexity increases congestion, along with more potential leak sites. H2S removed from the natural gas and concentrated during purification poses a toxic exposure hazard in the event of a release. The use of refrigerants or refrigerant mixtures adds to the hazards of handling and storing of these materials. These materials are typically used in closed loops, where large quantities are evaporated and then recompressed to high pressures. These materials have a much higher potential of fire and explosion than methane. The added complexity makes training of personnel more complex, and, at a new site, it represents new hazards for existing or newly occupied buildings. Regulatory agencies. LNG facilities

built within the US must meet the requirements of a number of regulatory agencies (TABLE 2). The most specific requirements are those of FERC and PHMSA, which require that LNG facilities be designed to comply with NFPA 59A and with other applicable industry codes and standards.2, 3, 4 Non-governmental organizations also often actively promote the strict enforcement of existing regulations and the aggressive interpretation of existing law.

operations while saving money.

Import challenges. Current US regu-

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lations focus on LNG import facilities (TABLE 3). FERC is the lead federal agency and, with PHMSA, it regulates domestic LNG facilities through 49 CFR 193. This regulation also draws heavily on NFPA 59A. FERC requires a detailed lifecycle approach to monitor and approve the siting, engineering design, construction and operation of LNG facilities. FERC normally prepares the environmental impact assessment for new LNG facilities. In addition, the US Coast Guard has regulatory authority over waterfront LNG import and export facilities.4 US states also have veto power over LNG facilities through delegated federal

Natural Gas Developments TABLE 2. Agencies regulating LNG in the US US Federal Energy Regulatory Commission (FERC) US Department of Energy (DOE) US Department of Transportation’s (DOT’s) Pipeline and Hazardous Materials Safety Administration (PHMSA) US Department of Homeland Security (Coast Guard) US Environmental Protection Agency (EPA) US Fish and Wildlife Service National Oceanic and Atmospheric Administration (NOAA) State and local health, safety and environment (HSE) bodies and utility agencies

regulations such as the Coastal Zone Management Act, the Clean Water Act and the Clean Air Act. Export challenges. Existing federal regulations mention natural gas liquefaction only briefly, since the primary rulemaking focus was for LNG imports. As previously mentioned, FERC and NFPA 59A are consequence-based (TABLE 4). NFPA 59A requires that a “design spill” does not surpass the limits shown in Table 4 at a property line with only passive mitigations (like dikes, fixed barriers and gravity-flow impoundments). The LNG tanks in the facility are also included in the exclusion zone for radiation and overpressure. FERC recently clarified the conditions for the piping ruptures, providing initiating frequencies for breaks and ruptures based on valve count, pipe lengths and diameters rather than for full-bore breaks for all pipe sizes.5, 6 This more reasonably defined a design spill than the traditional worst case scenario, but left intact the consequence to be avoided and the restriction on using only passive mitigations. A consequence-based approach is very difficult for complex processing operations, where releases cannot be mitigated by passive means. One such example is a high-pressure release at an elevation where there is no liquid pool formation, which means there is no possibility for impoundment of the spill. High complexity. Natural gas lique-

faction and export is a safe and proven technology, and it poses fewer hazards than many other chemical manufacturing processes. However, conversion of LNG import terminals to liquefaction facilities requires more complex processing and involves significant inventories of much

TABLE 3. Principal regulations pertaining to LNG in the US US FERC Federal executive branch: Veto power US DOT (PHMSA) US Department of Homeland Security US Coast Guard’s Waterway Suitability Assessment US EPA States: Veto power Coastal Zone Management Act Clean Water Act Clean Air Act

TABLE 4. Consequence-based FERC regulatory criteria Exclusion zones (at the property line) from a release caused by a “design spill.” This means an LNG pipe break will last 10 minutes and only passive mitigations are allowed. ½ lower flammable limit

When the Going gets HOT… Non-intrusive flow measurement up to 400°C Trouble free operation at f extreme pipe temperatures f No clogging, no pressure losses Installation and maintenance f without process interruption Independent of fluid f or pressure f Hazardous area approved

1,600 Btu/hr-ft2 thermal radiation 1 psi overpressure

Field-Proven at Refineries f Heavy crude Oil

more hazardous compounds. Therefore, the careful application of industry best practices in the conversion of LNG import terminals to LNG export is essential. Better regulations, based on dialog with regulatory agencies and a shift from consequence-based regulations to a process safety risk-based approach would be helpful for future natural gas liquefaction plant projects.1 In addition, improved modeling tools and a better understanding of potential effects on the community are needed.

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LITERATURE CITED Literature cited available at HydrocarbonProcessing.com. FLEXIM AMERICAS Corp. Author biographies can be found online at HydrocarbonProcessing.com.

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| Bonus Report LUBRICATION PRACTICES The reliability of rotating equipment depends on continuously maintaining clean, dirt-free lubricant to all turning/moving parts. The combination of lubricant systems and oils is complex for every facility. Lubricants contaminated with water and particulates are known root causes for equipment failures. Best practices and improved technologies such as oil-mist systems can mitigate problems in plant equipment and prevent equipment failures or repairs. Photo courtesy of Rolls-Royce.

Bonus Report

Lubrication Practices H. P. BLOCH, HP staff, Westminster, Colorado

Update on lubrication systems Several case histories illustrate the pros and cons for maintaining rotating equipment under various plant conditions. Example 1. In late May 2013, a US oil-mist provider in one of the Great Lakes states sent out a note that observed “there is no other single device that yields the reliability improvements obtained with oil-mist lubrication.” This feedback is important to reliability engineers because the provider company is not the average vendor. This particular provider also owns an equipment repair facility specializing in mixer seals; some of these seals have dimensions in the 48-in. (1.2-m) diameter range. By replacing grease-lubricated bearings with oil-mist retrofits in about 50 critical mixers, the provider’s rebuild shop has helped equipment users achieve very significant equipment uptime extensions and reduced repair costs. These developments demonstrate huge progress. Slurry pumps. More specifically, this provider company recorded quantum improvements in bearing and seal reliability at its customers’ installations. By installing a large number of oilmist conversions, both provider and customers have experienced changed expectations regarding rotating equipment reliability. Among the provider’s many unqualified successes were slurry pumps produced by a well-known US pump manufacturer. In this application, the oil-mist provider was able to identify several case histories. Many of these involved serious bearing distress situations. At one site, chronic bearing failures had disrupted operations; many of them resulted in repair obligations deemed “nearly unworkable” prior to applying oil-mist lubrication.

bon processing industry (HPI). Some electric motors at a facility in Texas were commissioned in 1977. Now 36 years later, these motors have yet to experience a bearing failure. The topic of how oil-mist intrusion does not affect motor windings was discussed in several books and numerous articles. Occasional opinions to the contrary are easily refuted by four decades of well-documented and highly favorable experience. Extensive testing of oil-soaked motor windings in a 350°F (177°C) environment was done by Reliance Electric (now Baldor-Reliance) in the early 1970s. The highly favorable results were liberally shared with industry in 1977.1 Oil-mist lubricated motors are a huge step forward over the alternatives. With the exception of oil refineries, oil-mist technology is largely underutilized in the general manufacturing industry. The reasons are often linked to outdated perceptions and an inadequate understanding of how to cost-justify this simple and mature lubrication technology. Valid cost justification calculations by knowledgeable professionals should include electric motor

High-temperature case. In another case, extremely high grease temperatures were documented in the bearing housings of several pumps in high-temperature heat-transfer-fluid service. Escalating maintenance costs soon caused declining profits for the operating company. At first, it was thought that, if failures persisted, the user plant’s survivability may be in question. After converting to an oil-mist system, the provider set up test loops and invited customers to witness bearing temperature declines of as much as 100°F (56°C). With with oil-mist systems, pump failure frequencies dropped to below industry-accepted values. This development was another important step forward in the reliability of lubrication systems. Oil mist on electric motors. As shown in FIG. 1, electric motor

lubrication with pure oil mist is now in its fourth decade of highly successful usage at best-of-class (BOC) plants in the hydrocar-

FIG. 1. Vertical pump lubricated by pure oil mist in a closed-loop mode. Source: Total Lubrication Management, Houston, Texas. Hydrocarbon Processing | JANUARY 201461

Lubrication Practices drivers, the value of fire avoidance and the benefits of using oil mist to protect standby equipment. During 40 years of exceptionally good experience with this simple and yet mature technology, no plant was ever shut down due to a system failure. Past oil-mist system mistakes are easily explained by uncovering (or reading about) installation errors made in the 1960s. There are no moving parts in oil-mist generators. The payback for plantwide systems is now achieved in one to two years. This payback obtained with the single-point oil-mist application devices installed by the oil-mist provider mentioned earlier is often measured in weeks. Oil mist in new plants. Many enlightened design contractors

advise their clients to use plantwide oil mist from the inception of the facility’s design. Of course, not everyone chooses to take this approach. The compelling advantages of preservation by oil mist are sometimes overlooked in new plant construction where open-air storage should mandate equipment protection. An oilmist blanket can serve the storage protection needs better than most other methods, as illustrated in FIG. 2. However, edicts to “save money right now” are passed down the line, and, sometimes, are accepted by uninformed or indifferent support staff. The ultimate outcome is very easy to predict: Large sums of money will either be spent on precautionary equipment examination shortly before equipment commissioning, or on equipment reconditioning during (or soon after) the startup phase. At one site, allocating funds for storage protection would have yielded paybacks conservatively estimated at a ratio of 10:1. The non-allocation of funds for storage protection is always a step backward, and it will prove burdensome to the major refinery that took this position. Updated grease application knowledge. Regarding the more traditional lube application methods, some are largely driven by marketers. Among the older methods that seem to make their comeback in 30-year cycles are numerous different single-point grease applicators. They are often called singlepoint automatic lubricators (SPALs) and function by pushing grease into bearing housings.2 However, the oil and soap constituents of these greases tend to separate when under pressure. All common industrial greases “bleed,” i.e., they release oil from the soap matrix. This soap matrix then acts like a sponge. Grease formulations have different bleed points for various applications. The bleed points needed for electric motors will

FIG. 2. Outdoor storage with an oil-mist blanket is thought to provide a 10:1 payback on average. Source: Total Lubrication Management, Houston, Texas.

62JANUARY 2014 | HydrocarbonProcessing.com

differ from the bleed points needed by the greases used in paper machines. Consider that greases which remain homogenous under pressure are compounded for gear couplings and slowspeed machines. But greases that remain homogenous under pressure are not an ideal choice for electric motors. Premium greases made for high-speed motor applications are less homogenous, and they will separate into soap and oil roughly six times more readily than the more homogenous counterparts. Choosing between the two greases must be governed by an action that is either reliability-focused or repair-focused. Additional staffing is needed to do more frequent maintenance if premium greases are used under pressure. The SPALs filled with premium grease must be replaced before too much of the grease separates. And using SPALs with less-than-ideal greases will simply result in more frequent bearing failures. Operating companies must examine the probable true cost of labor and materials before choosing lubrication systems. At all times, reliability engineers must be familiar with the grease path in grease-lubricated equipment. The double-shielded, grease-lubricated bearing, as shown in FIG. 3, is in a housing equipped with an open-drain pipe. There is no risk of over-pressuring the grease cavity. The spent grease migrates to the opendrain pipe and forms a quasi-plug. This “plug” will be expelled when the grease reservoir is replenished with fresh grease, and a new “plug” will migrate into its place. Oil “bleeds” from the grease reservoir past the annular gap between the shield and the bearing’s inner ring, and enters into the path of the rolling elements by capillary action. A third alternative involves applying grease with a traditional grease gun. Note: Without the open-drain pipe (FIG. 3), pressurizing would occur. It is quite obvious that pressurizing the grease could force the grease shield into contact with the rolling elements. Tests done by Ed Nelson at Amoco’s Texas City, Texas, refinery in 1980 confirmed that a grease gun forcing grease into a non-vented bearing housing could produce a pressure of 26,000 psi. Removing the shield is not the best solution, and it will result in filling 100% of the spaces between rolling elements. However, bearing manufacturers want grease to fill only between 30% and 40% of the free space between rolling elements. The shield should therefore face the grease cavity. Again, applying pressure will cause the shield to get pushed into the rolling elements. Heat will be generated, and the grease will oxidize rapidly. Metal shavings may result from this contact. Commendable efforts to prevent over-greasing are reflected in FIG. 4, where the supplier provided an additional “metering plate” to impede over-lubrication. At present, engineers still argue about how much (actually, how little) grease can flow through a shield when re-lubricating shielded bearings. Remember: The original design intent from the 1950s was to not force even one gram of grease through the annular opening in the time needed to refill the grease reservoir. Grease must stay in the reservoir, and it is expected to slowly bleed miniscule quantities of oil into the path of the bearing’s rolling elements.2, 3 In reviewing FIG. 5, the key element is to understand and to specify the grease path. Many plants may have 50 different motor combinations from 10 or more different manufacturers. The various motors can incorporate 15 different bearing styles and sizes. Some bearings are single shielded with shields facing right; single shielded, with shields facing left; double shielded;

Lubrication Practices sealed (pre-filled but not refillable); open cross-flow; open and same-side flow; same-side reservoir vented; same-side reservoir non-vented; and so forth. Mechanically superior electric motor designs very often have self-relieving passages; these are built-in elements, as illustrated in FIG. 5. All owner-purchasers must obviously specify motor voltage, frame size, power, speed and service factor, but only the BOC companies specify important lubrication details. HPI companies specify the most appropriate means of lubrication for plant equipment and electric motors.

alities. Some maintenance organizations should make very tangible changes or adjustments if their lubrication environment is bogged down in fluff, or if the implementers keep jumping from one trial-and-error attempt to the next one. While there is nothing wrong with engaging competent outsiders, beware of those contractors who have never really solved basic lube problems and lack a full understanding of all underlying causes. They will calculate how many strokes of a grease gun it takes to re-lubricate a such-and-such bearing, but they contribute very little to failure avoidance if they leave critical component details to others.

Basics can solve problems. Fortunately, most motor bearing failures can be cured by simply understanding and applying the basics. Properly applying the basics and properly teaching them requires experienced teachers and willing students. For management, it involves dealing with people. Ask for, and offer, constructive comments and solid explanations. Train your trainers and assess the experience level of plant “lubrication management managers.” They should be able to advise on component details and not just on the usual generLubrication Bearing

FIG. 4. Double-shielded electric motor bearing. This motor manufacturer prudently added a “metering plate” to forestall events where pressurizing the grease cavity would deflect one of the two bearing shields that could then contact the rolling elements. Source: Reliance Electric Co., Cleveland, Ohio, 1960.2, 3

Inner cap Shaft

Bracket

Drain

FIG. 3. Double-shielded, grease-lubricated bearing in a housing equipped with an open-drain pipe. There is no risk of over-pressuring the grease cavity. Oil “bleeds” from the grease and enters into the actual bearing by capillary action.2

FIG. 5. In grease-lubricated bearings, understanding or specifying both the grease path and, in the lower illustration, the built-in grease escape, will add much value to sound lubrication management.2 Hydrocarbon Processing | JANUARY 201463

Lubrication Practices What are the options? Well, one approach would be to use

certain homogenous greases in electric motors and then simply endure the more frequent bearing failures. Remember the old adage: “You can pay me now or pay me later, but pay you will.” Using SPALs with this grease vs. that grease are options 1 and 2. Using a grease gun is option 3, and doing nothing is option 4. Option 4, doing nothing and waiting for random events to hit, will be neither cheap nor safe. Which should bring us back to understanding the merits of oil mist and also the need for intellectual honesty: As professionals, we should resist the urge to pass along distorted opinions about oil mist, rotating machinery, grease lubrication methods, and anything else of value. Voicing an uninformed opinion without labeling it as such is a disservice to all stakeholders. Trial-and-error approaches and allowing opinions to masquerade as facts are steps backward. They represent an even more serious danger in the HPI where many fluids can be toxic, flammable, or a threat to the environment. Speak up. There should be ways to share concerns on lubrica-

tion practices to upper management to prevent colossal blunders. If, as mature reliability professionals, we are confronted with project demands that insist on the lowest as-built cost, let us look at the possible consequences and communicate them to managers in a responsible and quantitative way. Remember: All managers are entitled to hear the facts from reliability professionals. The actual practice of professional ethics

requires pointing out the ultimate effects of taking backward steps on equipment reliability and safety. Reasoned findings must be properly communicated to managers. The plant manager may not be a trained machinery engineer or lubrication expert; however, this manager does need facts to ensure the reliability and safety of the complex. Managers need knowledgebased support. Reliability professionals must take the lead in the information chain. Advice must always be fact based—no opinions. Aerospace decisions are not relying on opinions, and neither should lubrication technology decisions in HPI plants. Apply new knowledge and experiences. In a recent low-

budget case, a user with outstanding experience on nearly 20 plantwide oil-mist systems commissioned an additional large chemical process unit. Money concerns led to the decision to use the old lube application strategies. The irony is that, decades earlier, the same user had found that the old lube application strategies were out of harmony with reliability-focused thinking. Now, contemplate the logistics of teaching, conveying and supervising hundreds of employees. Consider telling these employees that they can continue to perform preventive maintenance on oil-mist lubricated pump sets rarely, if ever. Then, think of trying to impress upon these employees that lubrication issues in the newly constructed unit will have to be handled and approached just as their grandfathers did in the late 1950s. Take courage; oil mist, the best and simplest motor lubrication method, is both well-understood and readily available. The future of oil mist is very bright. Several innovators are gaining momentum on potentially trend-setting new single-point oil-mist application modules. At present, plantwide oil-mist systems serve an estimated 130,000 pumps and motors in the petrochemical and related industries. Just as plantwide systems were quite instrumental in shaping many owner-operators into BOC performers, a future generation of single-point oil-mist application modules will likely make an even larger impact throughout other manufacturing industries. Some choose to link a facility’s future maintenance performance to grease types and grease-flow patterns and grease application skills. Whether they will reach their professed reliability improvement goals and related benchmarks remains to be seen. Chances are they will find rough times ahead. LITERATURE CITED Bloch, H. P., “Dry-sump oil-mist lubrication for electric motors,” Hydrocarbon Processing, March 1977. 2 Bloch, H. P., Practical Lubrication for Industrial Facilities, 2nd Ed., The Fairmont Press, Inc., Lilburn, Georgia, 2009, pp. 259–276. 3 Bloch, H. P. and A. R. Budris, Pump User’s Handbook: Life Extension, 4th Ed., The Fairmont Press, Inc., Lilburn, Georgia, 2012, pp. 289–293. 1

HEINZ P. BLOCH resides in Westminster, Colorado. His professional career commenced in 1962 and included long-term assignments as Exxon Chemical’s regional machinery specialist for the US. He has authored over 500 publications, among them 18 comprehensive books on practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oil-mist lubrication and practical lubrication for industry. Mr. Bloch holds BS and MS degrees in mechanical engineering. He is an ASME Life Fellow and maintains registration as a Professional Engineer in New Jersey and Texas.

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Bonus Report

Lubrication Practices M. BARNES and D. MORGAN, Des-Case Corp., Goodlettsville, Tennessee

Control moisture in ‘wetted’ rotating equipment In turbomachinery, water is one of the most deleterious contaminants. Left unchecked, moisture can severely reduce the service life expectancy of oil-wetted rotating and reciprocating components by as much as 30%–70%, as shown in FIG. 1. Often, water is regarded as an unavoidable consequence: the cost of operating machinery in humid environments or in process equipment that either uses water for cooling, or as steam to power turbines. Several new techniques and maintenance programs can prevent the ingress of water into lubricating oil systems.

well as a particle-removing filter. Where larger systems are in place, a dry gas (instrument air or nitrogen) head-space purge is often more effective at removing airborne humidity. Despite the effectiveness of desiccating breathers, water can still get into the oil through seals and other points of ingress. Any contamination control policy should include the ability to filter water from the oil. While removing particles with mechanical filtration is straightforward, removing water from oil is more complicated. Gravity separation. Perhaps the simplest method is either

cant. With a viscosity about one tenth that of a typical turbine oil at operating temperatures, water-contaminated lubrication oil cannot maintain adequate film thickness to separate moving surfaces under operating loads, speeds and temperatures. But the issue goes way beyond simply the relative viscosity of oil and water. The sudden change in pressure experienced as water passes into the load zone of a plain bearing under hydrodynamic conditions can cause flash vaporization, leading to cavitation damage similar to that seen in hydraulic pumps. In rolling contacts, water prevents the formation of the elasto-hydrodynamic oil film, resulting in increased stress. Such conditions can lead to fatigue failure. In equipment that does not run continuously, such as standby pumps, changes in temperature when the pump cools down can cause the water to come out of solution, resulting in fretting corrosion and other free-water induced failure modes, as shown in FIG. 2.

gravity separation or using coalescing media. Both methods work on the principle that oil and water do not like to 160 140

Journal bearings Rolling-element bearings

120

Relative bearing service life, %

Water is a problem. Put simply, water is not a good lubri-

100 80 60 40 20 0 5,000

2,500

1,000

500 250 Water content in oil, ppm

100

50

FIG. 1. The impact of water content on bearing life.

How much water is too much? Surprisingly, the answer is very little. Most damage is caused by water that is either free or emulsified, as opposed to dissolved in the oil. The solution is to ensure that any water present is equal to or below the saturation point of the oil at all operating temperatures. For turbine oil operating around 120°F, that level is 100 ppm–150 ppm (0.01%–0.015%) or less. For standby equipment, the targets are even lower. Prevention methods. Eliminating water down to these levels can be difficult, but it is achievable. The first place to start is to eliminate all sources of water ingression. These include good seal management, as well as maintaining the integrity of cooling water systems. In addition, one of the main sources of ingression is airborne humidity that can enter through vents and breathers. This can be easily controlled using desiccating breathers. These breather types feature a silica gel-based hygroscopic media that attracts and removes airborne moisture, as

FIG. 2. Bearing corrosion caused by static water. Hydrocarbon Processing | JANUARY 201465

Lubrication Practices mix. However, while they can be effective at removing large amounts of water, they cannot remove water below the oil’s

of oil and water to separate—has changed significantly, with Group II lubricants being less ready to shed water than their older Group I cousins. While vacuum dehydrators have been around for a while, their reputation has been somewhat tarWater mitigation is possible simply by using nished by operational difficulties. However, with the appropriate seal management, applying next-generation vacuum dehydrators, many former deliquescent head space management problems have been resolved, thus making them a very effective and user-friendly way to control water (breathers and headspace purge) and nextdown to very low levels. generation vacuum dehydrator technology. Vacuum dehydration equipment extracts water from lubricating oil by “boiling” or vaporizing that water. The concept is based on vapor pressure in which water “boils” at a lower temperature when exposed to saturation point. Perhaps one of the oldest technologies used vacuum. All vacuum dehydration systems have always worked to remove water down to low levels is the centrifuge. A simple on this principle. These systems have traditionally been someprinciple, based on the difference in specific gravity and polarwhat difficult to operate. The complex technology required to ity of oil and water, centrifuges have been used successfully in create the right conditions to “boil” that water out of the oil is numerous industries for many years. not easily understood. It is often said that a vacuum dehydration system is a complex machine, but that it performs a very New separation methods. A new trend is a move from censimple process—“boiling” water. trifugal separators to vacuum dehydrators. This is due to severThe operation of vacuum dehydrators has improved through al reasons. First, vacuum dehydrators can remove water down automatic controls. Only a few adjustments are done by the opto much lower levels than a centrifuge. In many cases, vacuum erators. This automation has improved operation. On most vacdehydrators can reach less than 10% of the oil’s relative huuum systems built today, the operator only needs to press “start,” midity. Second, as turbine oil formulations have changed with adjust the flowrate, and adjust the vacuum level to dehydrate oil. the introduction of more stable Group II and III basestocks, Next-generation vacuum dehydration equipment is more the demulsibility of fully formulated turbine oils—the ability efficient, with the application of newer, more modern vacuum pumps. One of the most important features of any vacuum dehydrator is the vacuum pump, and the pressure level achievable and maintained by the pump. Newer vacuum pumps are capable of much lower pressure levels with less maintenance, as shown in FIG. 3. These units use a dry-running claw-style pump that achieves pressures as low as 37 torr, or 28.5 in Hg (gauge). Another improvement is the vacuum tower media. Modern vacuum systems use a permanent dispersion media, usually a stainless steel (SS) tower packing material such as saddle rings. Water is effectively removed from oil only when the oil is in a thin layer. The purpose of any dispersion media is to allow for as much surface area as possible to create this thin oil layer. In the FIG. 3. An example of a modern low-maintenance vacuum pump. This past, many systems incorporated dispersion elements made of fipump only requires maintenance once per year and achieves pressure berglass or SS mesh. These dispersion elements would often clog (vacuum) as low as 37 torr (28.5 in Hg by gauge). with debris, requiring the operator to open the vacuum chamber and change out the elements. Systems designed to use permanent dispersion media can eliminate the need to enter the vacuum chamber at all, as this media type will not plug or degrade, and it does not require cleaning or maintenance (FIG. 4). The impact of water on oil-wetted equipment cannot be overstated. Water-free machines can have long service lives. Small amounts of water can result in a very significant rate of early failure. MARK BARNES, vice president of reliability services, has been an active consultant and educator in the area of maintenance and reliability for more than 17 years. He has worked with clients around the world to design and implement lubrication improvement plans.

FIG. 4. An example of permanent dispersion media in a vacuum tower. This material is a SS saddle ring that offers approximately 65 ft2 of surface area for each cubic foot of media and requires no maintenance.

66JANUARY 2014 | HydrocarbonProcessing.com

DENNIS MORGAN, vice president of technical services, has more than 20 years of experience both in management and with industrial equipment. In 2010, he authored the book, Basic Principles of Vacuum Dehydration. His expertise ranges from transformer insulating oil dehydration and degasification to lubricating oil dehydration, oil purification design and strategy and depth filtration technology.

Bonus Report

Lubrication Practices K. G. KROGER, Puradyn Filter Technologies, Boynton Beach, Florida

Improve quality of lubricating fluids via filtration Micro-sized dust particles, along with water, can ruin the best lubricating fluids. Contamination of lubricating fluids can occur due to the byproducts of combustion, metal wear, oxidation and more. To keep rotating equipment operating with higher reliability, more filtration systems and maintenance are proactive practices.

When using bypass oil filtration technology to maintain oil cleanliness in conjunction with oil analysis, operating companies will improve operations and reduce unplanned main-

Bypassing the high cost of oil-related maintenance. Due to the ultra-competitive global marketplace, proper upkeep and maintenance of hydrocarbon processing equipment can mean the difference between profits and losses. This fact is critical for processors to maintain best practices as it relates to the performance and care of their engines. The performance of each engine is based on the type of application, individual age, location, use, load, fuel and modifications to the equipment. One element that is common to all process equipment is the use of oil to lubricate, cool and seal the engine. Just by addressing the lube oil, engine maintenance can be greatly simplified. Bad actors for oils. The source of the contaminant for oil

systems is important; however, the main issue is the loss of lubrication by the oil even with additions. Even over a short time, allowing particle contamination to accumulate can restrict oil flow, thus contributing to increased wear through reduced lubrication. All of these factors increase friction within the engine, causing reduced efficiency and performance. Unavailable process equipment can lead to higher operating costs, which are compounded by associated expenses for unplanned maintenance and engine replacement. Bypass oil filtration technology can allow engine lubricating and hydraulic oil to remain viable for extended periods by diverting a small amount of lube oil out of the engine, cleaning it of impurities and returning it back to the engine. The result is an engine running on continuously clean oil and a safe extension of the oil life. Once a successful bypass filtration program is implemented, most companies find that indirect savings from the program— such as reduced oil-handling logistics, downtime, reduced component repairs, and extension of life to overhaul—significantly outperform the direct savings from the safe extension of oil life. Oil analysis is another vital part of good bypass maintenance protocol. Such programs enable diagnosing the condition of the oil. This is already an important method for most major equipment users. Oil sampling should always be considered a most effective tool to monitor the condition of the oil for many factors, including viscosity, wear metals, additives, contamination and physical properties.

FIG. 1. Installing a bypass oil filter onto the engine.

FIG. 2. Simple installation of the bypass oil filtration system. Hydrocarbon Processing | JANUARY 201467

Lubrication Practices tenance. Instead of having to stop for oil-related maintenance issues, facilities can safely and significantly extend the time be-

tween oil drains and overhauls, and reduce the quantity of new oil purchases by as much as 90%. In assessing bypass filtration products for equipment, the three main reasons that the oil has to be changed should be evaluated. They include 1) the removal of solid contaminant to below 1 micron, 2) the elimination of liquid and gaseous contaminants and 3) the replenishment of base additives (in engine oil) to maintain the oil’s chemical balance. Case study. One natural gas processor has been using bypass oil filtration and oil analysis for 8+ years as a way to increase time to overhaul and greatly reduce the lifecycle cost of the engine. This fleet comprises of 61 natural gas compressors and runs 24/7. At the first overhaul interval after installing a bypass oil filtration system, the engine was torn down and the components inspected. Management was impressed by the cleanliness of the engine to the point that overhaul intervals, on average, have now been extended by 25% or 10,000 hours. Cost savings. The cost for bypass filtration is cost-effective

FIG. 3. Compact size of the filter facilitates installation in many applications.

when compared to the total cost of new oil replacement, downtime, labor and engine overhauls. The average cost of the bypass unit, along with the replacement filter elements, and the oil analysis program for an engine can be covered in approximately two months of operation. Bypass oil filtration technology, when used with oil analysis, provides the ideal synergy for combining engine productivity and economic efficiency.

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Select 157 at www.HydrocarbonProcessing.com/RS 1

13-11-12 16:48

Plant Design M. TOGHRAEI, Engrowth Training, Calgary, Alberta, Canada

Wide design margins do not improve engineering Engineers use design and safety factors in sizing and specifying instrumentation or major process equipment, such as pumps, valves and compressors. Design factors are applied to cover the uncertainty in piping and equipment calculations. Such practices can contribute to “over-design” and can negatively affect performance of the process unit, resulting in higher costs. Several case histories investigate how over-design factors have caused problems in the operations of pumps, heat exchangers and control valves.

DESIGN FACTORS Design factors are generally applied to one or more initial or middle parameters during the front-end engineering design (FEED) stage. Such factors are used in sizing a piece of equipment, instrumentation, a process unit, or even the entire plant. Design factors are not the same as safety factors or the manufacturer’s tolerance values. Safety measures are defined more specifically within parameters outside of the design factor. It is unwise to confuse the differing concepts. The design factor is not necessarily a number between one and two. Such factors can be less than one and, at times, greater than two. The end result is designing a unit item or piece of equipment with extra capacity. In this application, “capacity” does not necessarily refer to flowrate. The extra capacity could be a piece of equipment with the ability to handle a higher flowrate or an instrument with the ability to handle higher temperatures. Therefore, when specifying a design factor, its magnitude, as well as the parameter to which it is applied, must be defined—for example, a design factor of 10% on pressure. In this article, the phrases “more aggressive” or “less aggressive” when referring to design factors will be used in place of “bigger” or “smaller” magnitudes. “Bigger” does not always equate with “more aggressive” within the context of design factors to apply. Parameters affecting the design factor. The main reason for applying design factors is to cover the uncertainty from calculations. This uncertainty is a function of the nature of the phenomena, parameters used and the calculation methodology. However, the magnitude of the design factor—which resulted from the listed parameters—can be limited by the performance sensitivity of the equipment, the economy and the cost sensitivity for equipment. Design factors are defined by the parameters and the phenomenon they relate to. The four well-established parameters are flowrate, level, pressure and temperature. These examples

are associated with lower design factors, rarely exceeding 30%. This factor more closely approaches 10%–25% for flowrates of small, inexpensive equipment, and is usually < 10% for larger units. This number will be even smaller in the cases where the flowrate is controlled, but higher when the flow originates from “not fully understood” sources, such as an oil reservoir in upstream oil extraction plants. Process consideration. For more complicated parameters such as pH in a neutralization process or a corrosion rate or the particle size in a precipitation operation, more aggressive design factors should be considered. As a general rule, the design factors on hydraulic system parameters are less aggressive than those used on petrochemical/chemical applications, and even less aggressive than those of biological systems. For example, in a gravity separator, the falling rate of a particle can be assumed as 50% of the terminal velocity of the particle. In designing a small reactor, the residence time could be presumed to be double that of the reaction time. Calculation methods. The other parameter defining the design factor is the calculation procedure. A design procedure based on a numerical method may need a smaller design factor than a non-numerical method. Hydraulic calculations regarding fluid pressure loss in a pipe, based on implicit friction factors (such as the Colebrook–White equation), may need lessaggressive design factors than a procedure based on explicit friction factors; or hydraulic calculations based on 2K-factors may require less-aggressive design factors due to the “equilibrium length” method. Limiting parameters. Among the items limiting design fac-

tors, the first one is equipment performance sensitivity. If the performance of a hypothetical piece of equipment deteriorates severely with a 7% capacity increase, then selecting a capacity design factor higher than 7% would not be wise. The second limiting item is the economic sensitivity. More aggressive design factors for larger (and expensive) pieces of equipment are difficult to justify. From a purely economical point of view, the resulting extra capacity is useless and wasteful. From a theoretical viewpoint, deciding the magnitude of the design factor requires an economic sensitivity analysis. Where technical criteria ask for a 15% design factor on a specific piece of equipment and it is accepted, then the resulting cost increase up to 15% could be approved by the stakeholdHydrocarbon Processing | JANUARY 201469

Plant Design ers. This approval, however, may be retracted if the extra cost exceeds 50%. Such exponential cost increases could be caused by many factors, including unavailability of required manufacturing shops, transportation limitations or expenses, or the need to purchase field-fabricated items because the size of the equipment exceeds the limits for shop-manufactured items. Likewise, a low/under-design factor can also present plant hazards. This risk—like any other risk—is a function of the frequency of the hazardous event and the consequence of this event occurring. A larger hazard frequency or a more severe potential consequence may force incorporating very aggressive design factors. Sometimes, a large design margin for pressure can be justified. Conversely, an overly aggressive design factor is economically inefficient. Applying design factors. The project engineer should be

aware at the calculation stage when design factors should be applied. For example, it is very popular to apply a design factor of 10% on the flowrate for pumps. Yet, some companies use a 20% design factor on the resulting head. Remember: Head is proportional to the flowrate to the power of 1.85 in turbulent regimes. However, the flaw lies in that not all of the head loss in a flow circuit is caused by friction loss; a portion of the head loss is due to the difference between the head of the liquid at the destination and the source. Custom-made vs. off-the-shelf. Other issues arise when

the design specifies custom-made equipment. Since custommade equipment are not always available in all sizes and capacities, companies can take two different approaches regarding the design factor. First, the design will be completed, and the design factor will come into play (automatically) at the point of specifying the unit, i.e., when a standard size larger than the calculated size should be purchased. In this approach, the capacity of the equipment will be checked to ensure that a sufficient margin for the design factor is available or that a larger standard equipment size should be purchased. The second approach, which is less common, involves applying the design factor before the design process (FEED), and then selecting the next—larger—available size of equipment. This may lead to an unnecessarily large capacity due to the design factor.

System curve

3

Head

2 Selected system point 85% 80%

Real system point

75% 1

Flowrate

FIG. 1. Pump head curves with varying design factors.

70JANUARY 2014 | HydrocarbonProcessing.com

Accumulation. Another important issue regarding the design

factor could be called the “accumulation” of the design factors. During the design of a piece of equipment, it is common for a single design to pass through a series of different disciplines and the vendor; this work process has the potential for multiple applications of design factors, and the individual in charge of the total design must ensure that the design factor is appropriate and not excessive.

CASE HISTORIES Several examples demonstrate how design factors can adversely affect the function of process equipment or the entire facility. Containers. Increasing the size of storage tanks and vessels

will make the tank larger and increase the residence time. The obvious drawback is wasting money due to a tank design with an unnecessarily high capacity, but there also may be some process issues present as well. For example, sometimes sensitive fluids cannot tolerate container oversizing. A famous example of this condition is perishable foods such as milk. The other example is potable water, which cannot be stored in overly large tanks. Long storage of potable water provides an ideal habitat for bacteria, algae and other microorganisms. For non-storage containers, which include unit operation containers and reactors, volume has a vital role. For example, a gravity separator with an excessive design factor will see a much lower flowrate during the actual operation, which may seem desirable since the increased residence time is beneficial for a gravity separation. However, the magnitude of flow also defines the hydraulic behavior inside of the container. Result: The lower internal flow streams will not be what the design anticipated. Even the location of “dead zones” may be altered due to the unexpected change. Pumps. It is very common to size a pump based on a design flowrate of 10% more than the normal (instantaneous) flowrate. Since it is generally expected that centrifugal pumps operate at an efficiency of B 25% to 30% of the best efficiency point (BEP), the pump curve shape may force the designer to use a lower design factor to ensure that the pump is always working within the suitable window. In FIG. 1, Point 1 is the normal operating point on a system (blue curve). This normal operating point shifted to Point 2 by adding an overly conservative design factor to the flowrate and a pump with the “red” system curve bought for this application. During the operation, to transpose the operating point on the pump curve, a control valve may shift the system curve to the blue dashed curve by increasing the system pressure drop, thus decreasing the flowrate. This new operating point, Point 3, does not land necessarily on a favorable point of the pump curve, which is a point with good pump efficiency. A variable speed drive (VSD) cannot help because Point 1 is below the “reach” of the VSD. The decision regarding temperature for the pump calculations is the other issue. The liquid temperature for the head calculation is usually the minimum liquid temperature with no margin, due to the viscosities of the liquids that are at lower temperatures and, therefore, require higher head. For net positive suction head absolute (NPSHa) calculations, the maximum liquid temperature with no margin can be used,

Plant Design since the vapor pressures of the liquids are higher at higher temperatures that lead to more conservative NPSHa calculations. However, the design pressure and temperature for construction material of pumps use with noticable design factors. The consequence of using a less-aggressive design factor could be losing an expensive pump, which is probably a non-tolerable risk. For the last point, the designer should be aware of the consequences of inappropriate design factors on centrifugal pumps vs. positive displacement (PD) pumps. The PD pumps have vertical pump curves, so their efficiency is not affected by changes in flowrate—thus, a larger design factor will not affect the pump’s performance. However, changing/decreasing the flowrate of PD pumps during the operation may require a more complex control system. Control valves. The design process of a control valve starts with the specification of upstream and downstream pressures at three different flowrates: minimum, normal and maximum. Considering overly aggressive design factors for the maximum and minimum flowrates will lead to a control valve with a wide “rangeability.” Published rangeability for control valves depends on the valve type and could range from 10:1 to 50:1 for different control valves.1 Specifying a wide range for a control valve may force the instrumentation and control engineer to implement two parallel control valves in a split-control loop, instead of a simple control valve arrangement. An overly large rangeability may not force the engineer to select two parallel control valves, but this is still not a good practice. Using a high-range control valve in a service with a narrow flow range hinders operation and control loop features. In such cases, a few millimeters travel of control valve stem will change the flowrate through the valve substantially. It is unlikely for such a control valve to show good controllability. Heat exchangers. There are two main factors regarding heat exchangers to ensure good operation. First, heat-transfer duty along with a suitable hydraulic regime is often overlooked. Using less-aggressive design factors on flowrates (and/or stream temperatures) may result in low heat duty of a heat exchanger. Conversely, using more-aggressive design factors could be considered a good investment if the extra cost is not insurmountable. However, unused capacity in a heat exchanger may impact the hydraulic regime of the heat exchanger and, subsequently, the heat duty. Pressure safety valves. For pressure safety valves (PSVs),

two main parameters are used to design the valves—set pressure and release flowrate. The PSV set pressure may be a number as large as the maximum allowable operating pressure (or design pressure) of the container. In a few cases, it can be higher. Selecting any set pressure smaller than the design pressure means there is untapped potential in the capabilities of the container. The release rate is calculated based on the governing scenario to select the orifice size of the PSV. Meanwhile, using less-conservative approaches in the assumptions for the release rate calculations will lead to overly small PSVs that cannot work properly to protect the container. Overly conservative approaches will also move the PSV into unsafe operations, as a

PSV with an overly large orifice could experience chattering (frequent opening and fully closing) and/or fluttering (opening and partial closing) during operation. The PSV, which is sized on a release rate of 40% or more than the actual volume, may be exposed to chattering or fluttering. This unsteady operation will cause fatigue in the PSV disc and internals, and ultimately result in premature breakage.2 Perhaps the only case in which a larger design release rate is acceptable is when a fire is the governing scenario, and the other scenarios generate much lower release rates. During a fire scenario, the concern for chattering, fatigue and premature fractures will be minor compared to other concerns. Applying overly aggressive design factors does not improve performance. They could potentially decrease the quality of equipment or instrumental performance and result in avoidable damage. LITERATURE CITED Altmann, W., “Practical process control for engineers and technicians,” Newnes, 2005, Chapter 3. 2 Hellemans, M., The Safety Relief Valve Handbook: Design and Use of Process Safety Valves to ASME and International Codes and Standards, Butterworth-Heinemann, 2007, p. 212. 1

MOHAMMAD TOGHRAEI is an instructor and consultant with Engrowth Training. He has over 20 years of experience in the field of industrial water treatment. His main expertise is in the treatment of wastewater from oil and petrochemical complexes. He holds a BS degree in chemical engineering and an MS degree in environmental engineering.

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Hydrocarbon Processing | JANUARY 201471

VERONA, ITALY | 24–26 JUNE 2014

Hydrocarbon Processing’s 5th Annual International Refining and Petrochemical Conference We invite you to discover the latest advancements in technology and operations in the refining and petrochemical industries. IRPC 2014 will take place on Verona, Italy on 24 – 26 June 2014 and feature:

Topics to be discussed at IRPC 2014 include:

• More than 40 technical presentations over the two-day, multi-track program offering both a local and global perspective • An opportunity to network with senior executives and engineers from leading operators, refineries, petrochemical plant and gas processing plants from around the world • Access to the exhibition floor

• Clean fuels • Biofuels • Catalyst developments

• An exclusive tour of Eni’s Venice biorefinery — the first refinery in the world to convert from a conventional plant into a biofuels production plant based on Eni’s patented Ecofining technology. (available on a first-come, first-serve basis)

• Plant and refinery sustainability

Register early and take advantage of early bird discounted rates at HPIRPC.com.

• Maintenance and reliability

> Contact Us

• Energy policy • Profitability

For Sponsor and Exhibit Opportunities: Lisa Zadok, Event Sales Manager, +1 (713) 525-4632 or [email protected]

• Effluence management

Speaking Opportunities/General Inquiries: Melissa Smith, Events Director, +1 (713) 520-4475 or [email protected]

• Gas treatment technologies

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• Rotating equipment • Bio-based petrochemicals • Alternative feedstock

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Refining Developments S. ROY, E. BRIGHT and V. RAMASESHAN, Saudi Aramco, Dhahran, Saudi Arabia

Decrease tube metal temperature in vacuum heaters In a Saudi Aramco refinery, a vacuum furnace was found to be operating at a high tube metal temperature (TMT) and was forced to shut down before the normal run length of five years. The coke laydown was also found to be substantial. An evaluation revealed that the furnace outlet temperature and pressure were operating at much higher values, compared to the design values, to maintain the same flash zone conditions at the vacuum tower. This scenario was the result of a change in furnace location, which increased the transfer line length by 200 meters (m). The increase in transfer line length resulted in an additional pressure drop of 120 millimeters (mm) of mercury, which increased the furnace outlet temperature requirement for the same flash zone conditions in the vacuum column. Various options for reducing the TMT of the vacuum heater, such as changing the transfer line size and adding extra surface area in the radiation and convection sections, were examined. The best option generally depends on the limitations under which the heater operates with regard to the process requirements and the downstream equipment limitations and flexibility. Vendor-developed heater models are used to evaluate the various options. System description. FIG. 1 shows the vacuum transfer line arrangement. The existing heater is a horizontal-tube, box-type heater with a convection section. There are four process passes—two on each radiant wall. Process passes from the convection section enter at the top of the radiant section and exit close to the radiant floor. The heaters’ absorbed duty for the design condition is 13.86 million kilocalories per hour (MMkcal/hr), and the fired duty is 17.14 MMkcal/hr (i.e., 100% fuel gas firing). From the outlet, radiant tube sizes are 10-inch (in.), 8-in., 6-in. and 5-in. nominal pipe size (NPS), and all convection section tubes are 5-in. NPS. In the convection section, there are three bare rows and seven studded rows (all 5-in. NPS tubes). The convection section is for process service only. All radiant and convection tubes are 9Cr-1Mo steel material, schedule 40 thickness. Eight upward-firing burners are arranged at the center of the radiant floor. The burners are of the dual-firing type, although they no longer fire fuel oil. The expected TMT under clean conditions is 506°C; for a coke thickness of 3 mm and a corrosion allowance of 3 mm, the design TMT is 621°C. This temperature is based on a rupture pressure of 9.3 kg/cm2 and a corrosion allowance of 3 mm. As per the American Petroleum Institute (API) standard 530, 9Cr-1Mo steel material can withstand temperatures up to 705°C.

The vacuum heater was installed in 2003 to replace the original heater. The transfer line size of the original heater was 36 in. During the replacement of the vacuum heater, the transfer line was changed from 36 in. to 48 in.; however, a nozzle size similar to the transfer line size could not be installed due to construction issues. Consequently, a 48 in.–36 in. reducer was installed, connecting the new and old transfer lines closer to the column. Performance of existing operation. The feed composition

of the reduced crude oil (RCO) feedstock is shown in TABLE 1. The furnace heat release is calculated based on fuel gas pressure and burner capacity (i.e., pressure curves). This calculation has been cross-checked with the fuel gas flowrate. The fired duty was found to be 20 MMkcal/hr, while the average radiant flux, based on absorbed duty, was calculated to be closer to the design duty of 31.5 kW/m2. Taking these calculations into consideration, there is no scope for increasing the firing rate without adding more area in the radiant section. The heater was found to be operating at approximately 108% of the throughput, approximately 112% of the process duty and approximately 116% of the firing rate of the original heater. The higher load was presumed to be the main reason for the higher TMT and the high coking rate. The heater stack damper was found to be operating at 95% of the open position, and the arch draft was 2.5 mm of water (H2O). The excess air was back-calculated from excess oxygen at 3.25% in the flue gas, which was found to be 16.7 vol% (10% for the To vacuum ejector P = 1,030 mmHg 5 in. T = 356°C

5 in. TMT (SOR) design 505°C TMT (SOR) operating Vacuum 588°C furnace 10 in.

16 in.

16 in. 48 in.

Heater outlet operating P = 295 mmHg T = 414°C Heater outlet design P = 176 mmHg T = 407°C 10 in. 36 in.

P = 35 mmHg T = 393°C Vacuum tower bottoms

FIG. 1. Schematic of a vacuum transfer line at a Saudi Aramco refinery. Hydrocarbon Processing | JANUARY 201473

Refining Developments design calculation). Under existing excess air conditions, there is a limited margin for increasing the firing rate without needing to modify the heater stack to satisfy the draft requirement. Improving furnace performance. Several options have been considered to raise the performance of the heater, including increasing the run length, improving the draft and increasing the firing rate without exceeding the radiant flux limit. These options are discussed below. Adding radiant surface area. Adding heat transfer surface area will directly reduce the firebox temperature and the average flux density to the tubes. This, in turn, will reduce the TMT and the coking rate. The firing rate can also be reduced with higher fuel efficiency, due to the increased heating surface. The addition of eight tubes in the section between the convection and radiant sections shows that the TMT can be decreased by 8°C. TABLE 2 provides a comparison of the present operating case and the proposed modification discussed above. Note: The base case has been adjusted to meet 10% excess air (design conditions), while operating with the current load. When additional draft is shown as negative, it implies that the existing stack height is sufficient, while a positive increase in draft translates to increased stack height for the same damper opening. Adding convection surface area. Adding two rows of convection tubes has been studied as a means of shifting part of the process duty from the radiant section to the convection section. TABLE 3 provides a comparison of this option with the base-case scenario. TABLE 1. Boiling point (BP) distribution of reduced crude oil feedstock Recovered mass, %

BP, °F

Recovered mass, %

BP, °F

Since the addition of convection surface area increases the pressure drop on the flue gas side, the required draft is higher. However, the required draft is already limited by the stack height, and the damper opening is close to 95%, so this option was not pursued further. Extending convection surface tubes. The lowest three rows (shield rows) of the 12 tubes in the convection section are bare tubes. The present operating maximum stud temperature is already close to the design temperature. Since adding studs will further increase the temperature, this option was not pursued. Converting natural-draft furnace to forced-draft. Adding a forced-draft fan in the furnace will neither reduce the firing, nor provide more draft. Moreover, this option requires extra ducting and additional plot area. As a result, this option was not investigated in detail. Converting natural-draft furnace to induced-draft. Adding an induced-draft fan in the furnace will provide the necessary draft at the heater and allow for the possibility of more firing, although it will not reduce the TMT. This option requires extra ducting, arrangement of space and arrangement of the steel structure; consequently, this option was not investigated in detail. Converting natural-draft furnace to balanced-draft. Introducing a complete air preheat system has the following consequences: For the same process duty, it will significantly increase the fuel efficiency, therefore reducing fuel gas firing. However, due to the higher combustion air temperature, it will increase the firebox temperature and raise the TMT. Since the furnace is already limited by high skin temperature, and since TABLE 3. Comparison of convection tubes option with base-case scenario Simulated base Addition case (adjusted to of convection present operation) tubes option

Initial BP

577.8

45

1,035.4

5

714.8

50

1,073.6

10

776.2

55

1,115.4

Flowrate to heater, kg/hr

329,000

329,000

15

820

60

1,161.6

Heater inlet/outlet temperature, °C

356/413

356/413

20

857.4

65

1,213.6

Heater inlet/outlet pressure, kg/cm

1.6/0.4

1.6/0.4

25

891.8

70

1,278.6

Total process duty, Gcal/hr

15.6

15.6

30

925.8

75

1,347.4

Calculated maximum TMT, °C

592

589

35

960.6

76.9

40

997.2

–

1,382 –

Property

2

Calculated fuel efficiency, % Extra draft, mm H2O

79.5

81

−3 (less)

+1 (more)

TABLE 4. Comparison of increased transfer line size option with base-case scenario

TABLE 2. Comparison between present and proposed operating cases

Simulated base Increased case (adjusted to transfer line present operation) size option

Simulated base case (adjusted to present operation)

Proposed operating case

Description

Flowrate to heater, kg/hr

32,900

329,000

Flowrate to heater, kg/hr

329,000

329,000

Heater inlet/outlet temperature, °C

356/413

356/413

Heater inlet/outlet temperature, °C

356/413

356/409

Heater inlet/outlet pressure, kg/cm2

1.6/0.4

1.6/0.4

Heater inlet/outlet pressure, kg/cm2

1.6/0.4

1.6/0.25

Total process duty, Gcal/hr

15.6

15.6

Total process duty, Gcal/hr

15.6

15.6

Calculated maximum TMT, °C

592

584

Calculated maximum TMT, °C

592

586

79.5

79.6

Calculated fuel efficiency, %

−3 (less)

−3 (less)

Property

Fuel efficiency, % Extra draft, mm H2O

74JANUARY 2014 | HydrocarbonProcessing.com

Extra draft, mm H2O

79.5

79.5

−3 (less)

−3 (less)

Refining Developments this option requires extra ducting, plot space and arrangement of the steel structure, this method is not recommended. Increasing the transfer line size. Since the pressure and temperature in the flash zone is fixed for a given feed, the enthalpy is also fixed. There is no enthalpy change in the vacuum transfer line; therefore, the enthalpy at the furnace outlet should be the same as in the flash zone. Increasing the transfer line size reduces the pressure drop, which calls for a lower furnace outlet temperature for the same enthalpy. This decrease in bulk temperature lowers the TMT, along with the coking rate. Coking is caused by high temperature and low residence time for a given feed. By increasing the transfer line size and raising the column nozzle size to 60 in., the TMT is expected to be lowered. TABLE 4 provides an overview of the projected results. While the reduction in TMT is approximately 6°C, the heater outlet pressure is expected to be 0.25 kg/cm2, or a reduction of 63 mm, due to the increased transfer line size. This, in turn, reduces the coil outlet temperature by 6°C. In all previous cases, the vapor at the heater outlet was around 9%, and the increase in the transfer line size raised the amount of vapor to 17%. Velocity steam and vacuum tower debottlenecking. Another way to reduce coke formation is to increase the velocity (and, therefore, the residence time) by adding steam. FIG. 2 shows a graph of TMT vs. steam flow. For the purposes of this study, 800kg/hr steam was used. This option depends largely on the availability of additional capacity on the vacuum column overhead steam jet ejectors. Although this will definitely lead to a decrease in TMT, the vapor at the heater outlet will be approximately 14%. It is evident that increased transfer line size, along with extra radiation surface area and coil steam injection, provides the best solution to reduce the TMT and increase vaporization while marginally raising heater efficiency. TABLE 5 summarizes this option as compared to the base-case scenario. With this option, the TMT drops by 18°C, reducing the coke buildup within the heater tubes and extending the unit run length by about nine months. However, with the injection of steam, the pressure at the heater inlet will increase. The maximum design temperature was calculated for the maximum expected pressure of 4 kg/cm2 (i.e., the pressure relief valve set pressure in the vacuum column, plus the transfer line and column pressure drop). The calculated maximum TMT for a 3-mm corrosion allowance, with a pressure of 4 kg/cm2g for convection tubes of schedule 40 thickness, is 675°C. Although the TMT can be stretched from 621°C for a tube life of 100,000 hours during end-of-run conditions, caution is advised, as this circumstance depends on the actual thickness of the tubes. The run length of the heater can be further increased by one year, if allowable TMT is raised from 621°C to 650°C for the same tube life of 100,000 hours. Takeaway. In summary, reduction of TMT can be achieved with several different approaches involving modifications within the heater box, outside of the heater box, or a combination of both. In cases where the transfer length is significant, a change in the transfer line size can have a marked effect on the heater tube TMT. While the best solution in the above case involves a combination of changing the transfer line size, steam injection and the addition of tubes in the radiant zone, a detailed mechanical integrity analysis should be carried out at the vacuum column in-

TABLE 5. Comparison of velocity steam and vacuum tower debottlenecking option with base-case scenario Increased radiant area, plus increased Simulated base transfer line, plus case (adjusted to addition of velocity current operation) steam option

Description Flowrate to heater, kg/hr

329,000

329,000 + 820

Heater inlet/outlet temperature, °C

356/413

356/406

Heater inlet/outlet pressure, kg/cm2

1.6/0.4

4.05/0.25

Total process duty, Gcal/hr

15.6

15.6

Calculated maximum TMT, °C

592

574

Calculated fuel efficiency, % Extra draft, mm H2O

79.5

79.6

−3 (less)

−3 (less)

620 Process peak tube temperature trend last seven radiant tubes (No. 1 is heater outlet)

600 580 560 540 Design-simulated Operation-simulated Operation-with steam

520 500 No. 1

No. 2

No. 3

No. 4

No. 5

No. 6

No. 7

FIG. 2. TMT vs. steam flow.

let nozzle area to confirm the viability of the nozzle size increase from 36 in. to 68 in. Subsequently, as an interim solution, velocity steam can be introduced to the heater, with an increase in radiant heat transfer area, thereby alleviating the TMT issue in the heater. A detailed analysis is being performed to further optimize the system and implement the most techno-economic solution available. SAMIT ROY is an engineering consultant at Saudi Aramco’s downstream process engineering division. A chemical engineering graduate, he has more than 33 years of experience in process engineering and technical services. His experience includes 21 years in Saudi Aramco refining and engineering services and 12 years at Indian refineries. He has worked at most refinery units associated with distillation, hydroprocessing and gas treating. EDWIN BRIGHT has over 17 years of experience in the petroleum refining industry. At the time of authorship of this article, Mr. Bright was the distillation specialist with Saudi Aramco. He is presently working as a distillation technologist with Shell. Mr. Bright has also worked for Reliance Industries, Indian Oil Corp., ATV Petrochemicals and Foster Wheeler India Ltd. He holds a bachelor’s degree in chemical engineering and a master’s degree in petroleum refining and petrochemicals from Anna University in Chennai, India. He also holds a master’s degree in management from the Asian Institute of Management in Manila. VINOD RAMASESHAN has over 19 years of experience in the petroleum refining industry. Before joining Saudi Aramco, he worked with UOP Ltd. and Mangalore Refinery and Petrochemicals Ltd. Mr. Ramaseshan has been involved with commissioning, operating, troubleshooting and optimizing new and revamped hydrocracking and hydrotreating units in Europe, the Middle East and Africa. He holds a master’s degree in chemical engineering from the Indian Institute of Technology in Bombay, India, and is a chartered engineer in the UK. Hydrocarbon Processing | JANUARY 201475

CALL FOR ABSTRACTS NOW OPEN

SEPTEMBER 10–11, 2014 HOUSTON, TEXAS GasProcessingConference.com

Hydrocarbon Processing and Gas Processing are now accepting abstracts for the inaugural Gas Processing Global Technology Conference. Natural gas is changing the energy landscape in North America and throughout the world. Hydrocarbon Processing and Gas Processing are pleased to announce the inaugural Gas Processing Global Technology Conference (GPGTC) will be held on September 10–11, 2014. We invite you to be an integral part of the discussion, and join engineering and operating management from the downstream, midstream and upstream sectors of the oil and gas industry.

SUBMIT AN ABSTRACT Topics to be discussed include but are not limited to: LNG Separation technology NGL GTL Methanol Gas transfer

Stranded gas-treatingdehydration/sour gas removal Field processing Equipment Cryogenic and heatexchanger systems

Treating Metering/custody transfer Environment Compressor/ compressor station/ emissions control/ reliability

For the full list of topics and instructions on how to submit your abstract, please visit: GasProcessingConference.com. The deadline is March 5, 2014.

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CONTACT US For Sponsor and Exhibit Opportunities: Lisa Zadok, Event Sales Manager, +1 (713) 525-4632 or [email protected] Speaking Opportunities/General Inquiries: Melissa Smith, Events Director, +1 (713) 520-4475 or [email protected]

Refining Developments L. BELLIÈRE, P. BURG, D. CHANTEREAU and S. M. STANTON, Sofraser, Villemandeur, France

Optimize viscosity control in refining operations Petroleum is one of the most important hydrocarbons in the global marketplace. It remains the primary source for liquid and transportation fuels, and it is the building block for product manufacturing in the polymerization industry. Viscosity is a crucial fluid characteristic for many reasons. It can be a functional property, or it can be correlated to an exclusive attribute. Viscosity can be related to utilization efficiency. More importantly, viscosity can be one indication of how a fluid is handled—pumped, filtered, stirred, etc. Like most physical properties, viscosity is measured with laboratory analyzers or directly inline (FIG. 1). New insight regarding viscosity can improve downstream petroleum-related operations. Refining. The first step in the refining process is separating

crude oil into distinct streams or products via thermal distillation. The new hydrocarbon streams undergo further processing by other unit operations, such as cracking, reforming, alkylation, polymerization and isomerization. Heavy residual streams [heavy fuel oil (HFO), low added-value products] are blended by mixing or adding solvents. This action improves the value of the heavy residual stream by conversion to lighter products. Viscosity control allows for the precise blending operations for final transportation fuels and liquid products. For example, the marine industry has set requirements for the maximum residue concentration in bunker fuel.

differences between process and reference temperature (e.g., 150°C), the ASTM D341 model is used.2 This method implies that the reference product and its behavior are known. In addition, this technique satisfies basic viscosity measurement requirements and presents several advantages including minimal front-end investment, instantaneous and continuous measurement, and extremely good reliability. Interpolated viscometers. With two interpolated viscometers, viscosity measurement exists at two temperatures; one measurement is before the reference temperature and the other measurement is after. According to the end-user’s reference temperature and identified parameters, a processor continuously calculates the viscosity according to the ASTM D341 model.2 Interpolated viscometers can provide improved reliability with continuous viscosity measurement calculations. Just like a single viscometer, this solution satisfies viscosity standards requirements. Viscosity analyzers. The analyzer method is the best approach for controlling petroleum products’ viscosity is actually measured at the reference temperature. With this viscosity principle, a sample is taken from the process and introduced to the analyzer. The sample is prepared for measurement; the viscosity at reference temperature is recorded, and the sample 10,000

Fuel-product specifications. Petroleum refining consists of 1,000

Kinematic viscosity, cSt

complex procedures that yield consumable goods such as bitumen, lubricants, heating oil, diesel and aviation fuels. Each final product is characterized by specific properties, one of which is the viscosity value. The viscosity index, according to ASTM D2270-04, is a widely used and accepted laboratory measure of viscosity variation due to temperature changes of a petroleum product between 40°C and 100°C.1 A higher viscosity index indicates a smaller decrease in viscosity with an increasing temperature of the lubricant. In refining processes, viscosity can be measured by three ways: with a single viscometer, via interpolated dual viscometers, and with a viscosity analyzer. Viscometers. With a single viscometer, a temperature compensation model is applied. The instrument continuously measures the viscosity at process temperature. The processor calculates the viscosity at the reference temperature (with a variation law). When the difference between the process and reference temperature is reduced to ±20°C, a compensation model is applied. For known petroleum products and increased

100

10

0

0

20

40

60 Temperature, °C

80

100

120

FIG. 1. Viscosity vs. temperature diagram for petroleum products. Hydrocarbon Processing | JANUARY 201477

Refining Developments TABLE 1. Performance increase in burning operations. Yield increase

From 1% to 10%

Consumption increase

From 1% to 10%

Maintenance reduction

Factor of 10

Unburned residues

Divided by 7

Smoke temperature

Reduction from 240°C to 200°C

Combustion parameter stabilization

1%

is returned to the process. This procedure is repeated, and the sample is continuously renewed. The analyzer presents a supreme advantage as the measurement is made at the actual reference temperature, regardless of the product’s behavior. With the analyzer, any effects of varying process temperatures are eliminated. The correlation to the ASTM standard is done directly, and the accuracy is obtained by measuring principle as opposed to calculating an approximation. For singleand dual-viscometer applications, the viscosity will vary with product quality and temperature. For the analyzer at reference temperature, a real viscosity measurement is made at a constant reference temperature, whether higher or lower than the process temperature. According to ASTM D445, inline measurements must be repeatable and simple to use and install. They should require minimum maintenance in both time and cost. The instruments require ex-proof agreement to easily fit in numerous locations with the refinery. Viscosity remains relevant to refining during mixing, blending and separation operations. More important, viscosity is a quality-control parameter, and it can be scrutinized in all phases. Superior quality for petroleum products and all its derivatives is dependent upon viscosity characteristics. Combustion. Many liquid fuels are used in the industry; die-

sel and heavy fuel oil are the most common. Liquid fuels are used in boilers, burners, furnaces or engines to supply heat or mechanical energy. In each case, the burner introduces a spray into the combustion process. From simple to complex combustion formulas, viscosity does control the droplet size. By adjusting a spray’s droplet size to suit the application, a process viscometer in a combustion installation can optimize energy production and reduce fuel consumption. In addition, it reduces the unburned residue and soot accumulation in the combustion chamber, and minimizes corrosion in the chamber. With its reliable and repeatable measure, the process viscometer also provides combustion efficiency. Maintenance, cleaning requirements and atmospheric emissions are reduced. To obtain superior operation in heavy fuel No. 2 burners, the fuel spray must have defined characteristics linked to the fuel oil’s viscosity. Those characteristics are provided by the burner manufacturer, and they are reached while heating the fuel. Efficiency of the burner is optimum when the viscosity of the fluid matches the specifications of the burner. Installing a viscosity-control system ensures that the viscosity value readings are constant and that viscosity control is maintained. The controller interacts on the heater command, and determines the heating energy needed to maintain good HFO viscosity. 78JANUARY 2014 | HydrocarbonProcessing.com

In the past, temperature controls combined with viscosity and temperature charts were used. These systems were simple and were efficient when the HFO had constant characteristics. This is no longer acceptable. The relationship between viscosity and HFO temperature presents higher dispersions due to the diverse origins of the raw oils, different refining methods, and variations among additives. Temperature control alone does not guarantee permanent viscosity stability. There is too much variation between the products and batches. With petroleum products, viscosity is even more crucial, as it is a dedicated, burned energy source. Viscosity control is indispensable in the burning of HFOs in industrial motors, furnaces/heaters and marine engines. Viscosity control inside combustion engines is increasingly realized and measured to improve the power ratio. Refineries, power plants and utility companies use burners, and the manufacturers of burners and engines demand optimal viscosity value to improve performance rates (TABLE 1). Quality control. In petroleum operations, as in many industrial sectors, onsite control is vital for product delivery. Viscosity is also a point of security in distribution tanks. Instruments used for this measure require good repeatability and reliability. By checking viscosity, companies can validate that tanks are supplied with the correct product. By verifying this step, potential mistakes with customers are avoided. Precise measurements. Petroleum-related operations present diverse applications. Viscosity is a key parameter in each phase for production and product quality control. In the petroleum industry, prices and volumes are huge; thus, any viscosity-related improvements have significant benefits. Accordingly, the global petroleum-related industry needs to pursue investments in viscosity measurement. Such projects should focus on instruments that can deliver long-lasting satisfaction for productivity; they should also provide robust and repeatable results, have maintenance-free capabilities, offer continuous measurement, and be resistant to high-pressure and high-temperature environments. Manufacturers are developing more sophisticated instrumentation technology; such developments offer new features and optimized characteristics to comply with the petroleum industry. LITERATURE CITED ASTM D2270-04, Standard Practice for Calculating Viscosity Index from Kinematic Viscosity at 40°C and 100°C. 2 ASTM D341–09, Standard Practice for Viscosity-Temperature Charts for Liquid Petroleum Products. 3 ASTM D445–11a, Standard Test Method for Kinematic Viscosity of Transparent and Opaque Liquids (and Calculation of Dynamic Viscosity). 1

DR. L. SOFRASER is the president of Sofraser, a 40-year-old fluid specialist company. He is the inventor of the vibrating viscometer held at resonance frequency. Patented in 1981, it is now widely considered a reliable viscosity process instrument. (www.sofraser.com.) DR. P. BURGIS the sales manager of Sofraser. D. CHANTEREAU is the marketing manager of Sofraser. S. STANTONIS a sales support associate of Sofraser.

Safety J. DEANE, WIKA Instrument, Lawrenceville, Georgia

Reliable gauges improve safety and reliability Caustic. Flammable. Corrosive. When these adjectives describe the agents that you work with every day, keeping them contained safely is of paramount concern. But what would you say if you knew that the average chemical processing plant has hundreds of connections that are in great and immediate danger of failing and causing spills, accidents and even explosions? To say that we run the risk of seeing a widespread processing plant crisis may not be as alarmist as it sounds. The source of this concern is as ubiquitous as it is simple: the common pressure gauges found all over refineries and chemical processing plants. These simple metal casings with mechanically driven pointer needles that are relied upon millions of times per year for accurate readings could play a role in the next reportable incident. This could either be because a gauge fails to indicate a looming threat or the gauge itself fails so completely that it becomes an actual source of media leakage. Recent events validate the matter’s imminence. Many of the worst modern industrial disasters have been started by relatively simple failures. The Chevron refinery fire in Richmond, California, was caused by a single corroded pipe, and evidence points to a broken pressure gauge as a mitigating factor in the Deepwater Horizon disaster. California is so concerned about refinery safety that it formed the Interagency Refinery Task Force to beef up enforcement of existing laws and to give regulatory agencies more teeth. Problem scope. Imagine that at any given time you were within 20 ft of 7.6 electrical outlets that could fail and give you a jolt; you would probably find that pretty worrisome. An analogous situation plays out every day at many processing plants: The average employee at a petrochemical plant is located within 20 ft of 7.6 gauges that are failing or about to fail. With the

caustic, flammable and corrosive nature of material present at these facilities, the direct safety risk is apparent. Safety lapses located in proximity of employees are especially problematic given how costly accidents that cause personnel injury or death can be. According to the US Occupational Safety and Health Administration (OSHA), a refinery accident that causes a lost work day costs $28,000 directly plus $152,000 in indirect costs. If an occupational death is involved, that cost quickly skyrockets to $910,000 for each affected employee—and that doesn’t even include property damage costs or intangibles like bad publicity and the potential for litigation. When the severity of an accident involves the general public, costs and reputation spiral out of control with lightning speed. Compounding this problem is that almost 25% of all gauges in an average processing plant require corrective action. This can be due to misapplication, damage or complete failure of the gauge. Not only do failing gauges become unreliable as silent alarms to warn of potential threats, but gauges are connection points themselves and as such any failure has leak hazard potential. The thinnest barrier between contained media and the outside world in any petrochemical facility is the Bourdon tube, an internal component present on most gauges. If it fails, the chance of media leakage is almost 100%. The average refinery contains between 300,000 and 400,000 connections, many of which are gauges. Even a pinpoint leak in any of these connections can lead to fugitive emissions, leading to safety incidents and sometimes fires. Further, these types of emissions are highly monitored by the US Environmental Protection Agency (EPA). Fines incurred for failing to contain fugitive emissions can reach millions of dollars for a single incident. According to the American Petroleum

Institute, more than 83% of controllable fugitive emissions originate from only 0.24% of a plant’s piping components. The return on investment (ROI) for ensuring the integrity of these components, including connective gauges, is staggering: A $60 to $100 gauge could literally prevent millions of dollars in losses. Problem sources. Knowledge and technology have improved drastically over the past several years and decades, and, as a result, overall plant safety has improved along with it. Why, then, have losses from refinery and petrochemical safety incidents totaled $1 billion over the past three years, according to the American Petroleum Institute? That averages out to approximately $1.6 million per refinery in the US. The answer is paradoxical. New knowledge and technology have certainly improved safety and productivity, but an unintended cost has come alongside them; the sacrifice of legacy technology and knowledge. Electronic sensors began replacing mechanical gauges as primary sources of information shortly after they were introduced to the market. Plant managers left mechanical gauges in place as a source of frontline information and to provide backup readings during instances of power failures and other electronic disruptions. Over time, electronic equipment proved its worth and proliferated, and mechanical gauges received less and less attention. Many plants have now reached a point where gauge maintenance is no longer formalized. A major issue contributing to the degradation of gauge integrity is industry brain drain. The professionals with the education, years of experience and knowledge necessary to properly maintain mechanical gauges are instrument and control engineers (ICEs). Through a long period of retirements and plant scale-backs, many Hydrocarbon Processing | JANUARY 201479

Safety ICEs have exited the market. This problem will almost definitely accelerate as more than half of all oil and gas professionals are set to retire within the next 10 years. When ICEs retire, it is difficult to transfer knowledge of the gauge population. Therefore, the young replacements have no historical perspective and limited experience to manage mechanical instrumentation. Determine gauge damage. Over time,

gauges fail and, when the failure is noticed, the gauge is replaced. Often, a wellmeaning employee will replace the gauge with another from the storeroom that looks similar, but is not rated to handle the application. The majority of gauge failure incidents are caused by misapplication, often resulting from the simple generalization that a gauge that “looks about right” is a suitable replacement. Aside from misapplication, there are several common environmental causes of gauge failure: • Vibration. A common occurrence on many pieces of equipment used in petrochemical facilities, most gauges are built to withstand a certain level of vibration. However, excessive vibration can lead to gauge failure and may also be indicative of a larger problem with a component. • Pulsation. Rapidly cycling media within a pressure system can cause gauge needles to move erratically, eventually causing internal parts to break down and fail from the constant movement. • Temperature. Petrochemical processing plants often encounter temperature extremes and, over time, this can cause sweating and loosening in metal joints. This eventually causes the metal to crack and creates an opportunity for media leakage to occur. • Overpressure and pressure spikes. When pressure exceeds the highest measurement available on the applied gauge, the pointer pegs at maximum. Frequent pegging causes the pointer to bend against the stop pin, possibly leading to inaccurate measurements. Overpressure also compromises Bourdon tube integrity and can lead to rupture. • Corrosion. Caustic and corrosive media are commonplace in chemical processing and can damage gauges when they come into contact with the 80JANUARY 2014 | HydrocarbonProcessing.com

delicate sensing material that enables the instrument to function properly and provide accurate readings. • Clogging. Many plants use media that contain suspended particles or have viscous or crystallizing properties. This media can clog pressure systems, which makes gauge readings unreliable. • Steam. Vapor and steam are also common at many plants, but certain types of vapor and steam, or their excessive amounts, can damage the internal parts of gauges and compromise the integrity of their readings. • Mishandling and improper use. Any instrument can be damaged if used improperly or abused. Abuse can run the gamut from employees using gauges as footrests while climbing on machinery to striking one in anger. Whatever the cause, abuse can damage gauges and prevent them from functioning properly. Correct the problem. Many plant man-

agers are not aware of just how many failing or about-to-fail gauges exist in their plants, and, of the ones who do, most do not have a plan of action to address the issue. Because of the gauge expert brain drain, the industry has suffered—even facilities that would like to correct the problem do not have the resources available to do so. Many do not have current P&ID documents on file or the experts on staff capable of determining appropriate gauge applications. Their only option in the past has been to continue guessing as to which gauge belongs where or to hire outside consultants to perform plant audits. Equipment manufacturers are starting to own this problem and create solutions to help improve plant safety and reliability. Some manufacturers are offering full instrument audits where any problems are identified and addressed. This is generally done as a value-added service to help keep plants operating at peak productivity levels. During a plant audit, a team of specially trained engineers access a facility where they conduct a full walk through and crossreference each and every gauge with what is indicated on the P&ID. If the P&ID is outdated or does not exist, the team will update it or create a brand new document based on the current equipment. Engineers inspect every gauge and note any instrumentation in need of at-

tention. Any problems found are documented and engineering-based recommendations are provided to ensure the correct solution is applied. Another important component of a plant audit is the storeroom audit. Not only does this portion of the audit streamline the maintenance operations of the plant, but it is also where monetary benefits can be realized immediately. This process involves standardizing inventory in the storeroom. Many storerooms contain inefficient inventory with redundant SKUs, and benefit greatly from identifying which items should be stocked and which are unnecessary, allowing them to be purged from inventory. This serves a dual purpose: It helps minimize inventory while also making sure that suitable replacement gauges are always available. Limiting the diversity of stocked SKUs minimizes confusion, curbing the possibility of selecting the wrong equipment. Plants that audit their storerooms are typically able to reduce inventory by 40%. A skilled audit team will also educate plant staff on the changes that were made and how operations are affected. Maintenance staff are taught how to identify and correct failing instruments with appropriate replacement configurations. They are also shown how to apply each gauge, how to handle them properly, and how to recognize situations that could lead to future failures. The time to conduct a facility audit is now. There is no need to wait for a turnaround period, as full operations do not get in the way of diagnostic and replacement efforts. In fact, it is generally easier to conduct an audit and implement its solutions when the plant is up and running. Every day that a facility waits to audit its instrumentation is a day closer to that instrumentation failing. With more demands than ever being put on processing plants, safety and productivity have become massive concerns. The US is refining more oil than ever before, but the facilities used to process it are aging and operating well beyond the capacities they were originally designed for. While it is natural to invest significant time and resources on the most expensive equipment, it should not be done so at the expense of quality mechanical gauges. JASON DEANE is a senior instrumentation engineer for WIKA Instrument’s audit service team.

Process Optimization R. WEILAND, N. HATCHER and C. E. JONES, Optimized Gas Treating, Buda, Texas

HCN distribution in sour water systems

Cyanides from treating cracked stocks, FCCs and cokers RCN + 2H2O r NH4+ + RCOO– NH4+ + R3N r R3NH+ + NH3 2HCN + O2 + 2H2S + 2R3N r 2R3NH+ + 2SCN– + 2H2O Oxygen incursion, FCCs and vacuum tower offgas 2H2S + 2O2 + 2R3N r 2R3NH+ + S2O3= + H2O SO2 breakthroughs (Claus TGUs) 2H2S + 4SO2 + H2O + 6R3N r 6R3NH+ + 3S2O3=

Cokers

S2O3= + 5⁄2O2 r 2SO4=

FCCs

consistent pattern over time and unit configuration of the relative amount of HSS anions, mainly HCOO– and SCN– produced from various refinery units. Amine systems treating gases from various sources experience different rates of HSS formation. Treating gases and liquids for H2S from delayed cokers have the greatest buildup of amine HSS anions. This is followed by fluid catalytic crackers (FCCs) without gasoil feed hydrotreating, and then by FCCs with feed hydrotreating. Amine systems serving hydrocrackers and hydrotreaters, completely isolated and separate from coking and FCC operations, normally show minimal signs of HSS buildup. This information is shown in FIG. 1. Solvent analyses and investigations at many facilities indicate that HCN is the main contaminant source for producing HSS anions. TABLE 1 shows the mechanisms for the formation of the most common refinery HSS anions. Data from several refineries have shown that: • Beginning to treat oxygen containing streams in an amine system that previously had only HCOO– buildup will show a dramatic increase in the rate of thiocyanate accumulation

TABLE 1. Sources of HSS incursion

Mixed system

Background. Amine data collected over some 20 years show a

• Dumping tail gas unit (TGU) amine contaminated with thiosulfate (S2O32–) into primary amine systems will cause an immediate increase in the amount of SCN buildup. Ammonium polysulfide (APS) is commonly added to wash water systems to aid in the control of cracking and blistering in carbon steel in wet H2S service. Companies that sell and monitor APS confirm the presence of HCN in these systems. HCN is a byproduct of cracking the heavier fractions of crude oil in a refinery (either thermally as in a coker, or catalytically as in a FCC). The gasoil (boiling point 750°F/399°C+) and heavier fractions tend to have greater concentrations of nitrogen than the diesel and lighter fractions. Compared to highpressure hydrotreating and hydrocracking processes, cracking processes that operate at high temperature and low hydrogen partial pressure do not completely convert byproduct molecules like HCN. Thus, HCN occurs quite naturally in refineries and has many sources. Some processes are high producers; others do not seem to produce HCN at all. Once it has been produced, HCN finds

Hydrotreated products only

Hydrogen cyanide (HCN) is commonly present in refinery gases. Because of its low volatility and, to some extent, its acidity, it travels through amine and sour water systems in an unusual and, heretofore, poorly understood way. To shine some light on this subject and perhaps develop a worthy solution, a simulation study has been performed with HCN removal being treated on a mass transfer rate basis. This will help develop an understanding of how HCN distributes in the sour water system and where it might form an internal recycle within a tower. HCN is an insidious contaminant in raw gas from cracked stocks, and has far-reaching effects on amine and sour water system performance and equipment longevity. After hydrocarbon contamination, its presence is probably the primary reason refinery amine and sour water systems suffer from accelerated corrosion and from operability and reliability problems. When HCN enters the amine system, its hydrolysis produces ammonia (NH3) and formate (HCOO–), a heat-stable salt (HSS) anion. Reaction of HCN with oxygen and hydrogen sulfide (H2S) generates another HSSs, thiocyanate (SCN–). Accelerated corrosion from the resulting heat-stable salts leads to faster formation of particulate iron sulfide, filter element plugging, fouled equipment, lower capacity and more stable foams. Most of the HCN, however, travels with blown-down ammonia to the sour water stripper (SWS). In this report, mass transfer rate-based simulation is used to study HCN distribution in SWSs in unprecedented detail.

Increasing HSS buildup rate FIG. 1. Pace of HSS anion formation in refinery amine systems. Hydrocarbon Processing | JANUARY 201481

Process Optimization its way into the amine system with the H2S-containing gases. HCN forms in various processes within a refinery; HSSs form in the amine system. Once in the amine system then, various conditions and the presence of other contaminants allow some of the HCN to be converted into HSS anions. The rest of the HCN either goes overhead to the sulfur plant, or it gets blown down with NH3 and enters the sour water system. HCN in sour water. A recent case study shows a rather surprising distribution of HCN in a SWS—in this case, a packed tower. TABLE 2 shows the composition and flow of this typical refinery sour water stream. FIG. 2 shows the SWS setup, configured to return all overhead vapor condensate to the stripper. The SWS was 5.5 ft in diameter, and we used 33-ft and 48-ft beds of random packing to assess the effect of packed depth on stripped water quality. The overhead pressure was 22 psig, and for this case Outlet-1 8

Condenser

Accumulator

5 10

TABLE 2. Refinery sour water

3

9

Pressure, psig

Flash gas

13

SWS

16,500 (480)

Composition, ppmw Flash

11 Mixer-1

9

Flow, bpd (gpm)

14

Sour water

100

Temperature, °F

Tear

1

study, a reboiler duty of 33 MMBtu/h was selected to achieve 100 ppmw of ammonia in the stripped water. The preheater sent 245°F sour water feed to the top of the column. With the 33-ft deep bed, the stripped water was simulated to have 100.5 ppmw NH3 and 12.5 ppmw HCN, with undetectable H2S. With the 48-ft deep bed, the corresponding performance metrics were 28 ppmw NH3 and 4.5 ppbw HCN. Of course, in condensing water from the stripper overhead, a lot of the gases already stripped (in Stream 3) are reabsorbed into the condensate (73% of the NH3 , 70% of the HCN, and 51% of the H2S) and are returned to the stripper. This is unavoidable if the stripped gas is to be further processed for sulfur recovery without overloading the system with water vapor, but it may be worth noting that a lot of energy is expended to strip and restrip the same contaminants repeatedly. Perhaps the most surprising aspect of HCN in the SWS is its distribution across the column itself. FIG. 3 (left panel) shows how the concentration of HCN in the water phase changes with vertical position within the packed beds of two different depths. FIG. 3 (right panel) shows the corresponding temperature profiles. The lower temperature near the top of the column is not

7

2 6

12

Stripped water 4

CO2

50

H2S

8,000

HCN

300 4,500

NH3 Feed heater

Thiocyanate

FIG. 2. SWS configuration. 0

0 5

10

10

15

15

20

20

Distance from top, ft

Distance from top, ft

Chloride

(a)

5

25 30

9

(b)

25 30 35

35

40

40 33 ft 48 ft

45 50

36

0

500

1,000 HCN in water, ppmw

1,500

FIG. 3. Profiles of HCN in water, and of vapor temperature.

82JANUARY 2014 | HydrocarbonProcessing.com

45 2,000

50 245

33 ft 48 ft 250

255 Vapor temperature, °F

260

265

Process Optimization caused by sour water that is being fed too cold—in fact, the sour water enters the column with the liquid just above its bubble point with 0.3% vapor. The bubble point is a function of the composition of the water with respect to the volatile acid gases and NH3.1 On the other hand, temperature also affects HCN solubility in water. As a result, the temperature profile has a profound effect on the HCN profile in the stripper. HCN that was removed from the water in the reboiler and in the bottom part of the column is partially reabsorbed near the top of the column where the temperature is 14°F to 15°F colder. Although the original sour water in this theoretical study contained only 300 ppmw HCN, water entering the top of the column contained 875 ppmw because of HCN reabsorption into the returned condensate. Peak concentrations in the tower are simulated to be about 1,530 ppmw and 1,580 ppmw HCN

for the 33- and 48-ft beds, respectively. These are some five times the concentration in the original sour water feed. The corresponding HCN level in the vapor is 825 ppmv. These elevated concentrations have a much higher tendency to corrode steel, so this may go some way towards explaining the need for expensive upgraded metallurgy in the SWS overhead system. As can be seen from the figure, HCN stripping is far poorer than one might have expected, even accounting for the higher HCN content of the column feed. In the case of the 33-ft bed, the bulge occupies the top half of the column, rendering half the column ineffective for HCN removal. When the bed depth is increased to 48 ft, the HCN bulge profile and peak value remain virtually identical. Increasing the bed depth by 15 ft has allowed the HCN profile to become what it might have been expected to be without the bulge. Other conditions being the same, HCN 37

250

(a) 1.2 lb steam/gallon 200

35 NH3 stripped water, ppmw

NH3 stripped water, ppmw

(b) 1.4 lb steam/gallon

36

150

100

34 33 32 31

50

30 0

0

100

200 300 HCN in sour water, ppmw

400

29

500

0

100

200 300 HCN in sour water, ppmw

400

500

0

0

5

5

10

10 Distance from top, ft

Distance from top, ft

FIG. 4. Effect of sour water HCN level on residual NH3 in treated water.

15

20 25 50 100 200 300 400 500 Max

25

30

(a) 1.2 lb steam/gallon 35

0

500

1,000 1,500 HCN in sour water, ppmw

2,000

15

20 25 50 100 200 300 400 500 Max

25

30

(b) 1.4 lb steam/gallon 2,500

35

0

500

1,000 HCN in sour water, ppmw

1,500

2,000

FIG. 5. Effect of sour water HCN level on HCN profiles and on the position and size of the composition bulge. Hydrocarbon Processing | JANUARY 201483

Process Optimization can be stripped to very low levels but only by using more bed depth. The reason for the deeper bed requirement is the presence of a very significant bulge and, consequently, a very large, non-functional section of packed bed in the column. Higher HCN levels in the sour water cause higher residual NH3 in the treated water. In FIG. 4, this is shown in the left and right panels, which, respectively, correspond to 1.2 lb and 1.4 lb of 50-psig saturated steam per gallon of water treated. The high-performance random packing was 33.5 ft deep. At the lower steam consumption rate, the effect of HCN is significant, but at the higher, more-typical rate of 1.4 lb/gal, the effect is somewhat more marginal. FIG. 5 shows how the HCN levels in the raw water affect the HCN profiles in the SWS. The size of the peak, of course, increases with the HCN content of the raw water. Furthermore, the peak occurs higher in the stripper, the higher is the HCN content of the original sour water. Higher steam rates push the bulge further up the tower and reduce its size; nevertheless, the bulge still exists even at this higher steam rate, and a sizeable portion of the stripper is completely ineffective in terms of what might have been expected had the existence of the composition bulge not been known. Wrap up. The discovery that HCN accumulates internally within a SWS has been reported here for the first time. The use of mass transfer rate-based simulation has allowed this significant internal recycle of HCN to be quantified in unprec-

84JANUARY 2014 | HydrocarbonProcessing.com

edented detail. The discovery of this recycle may go some way toward explaining observed tower corrosion rates in existing plants and may permit better informed material selection decisions to be made for plants still in the design phase. We speculate that such a distribution of HCN probably always occurs in both amine regenerators and SWSs because the mechanism by which it forms is through the connection between solubility, vapor pressure, and local temperature, and this exists in both types of units. 1

NOTE Bubble point is the temperature at which the vapor pressure over the solution is equal to the system pressure. It is greatly affected by the presence of volatile, dissolved components in the water.

RALPH WEILAND founded Optimized Gas Treating in 1992 and has been active in Canada, Australia and the US in basic and applied research in gas treating since 1965. He also spent 10 years in tray R&D with Koch-Glitsch LP, Dallas, Texas. He has bachelor’s, master’s and Ph.D. degrees in chemical engineering from the University of Toronto. NATE HATCHER is the vice president of technical development for Optimized Gas Treating. He has spent most of his 19-year career in gas treating and sulfur recovery, first in design and startup with Black & Veatch Pritchard, and later in plant troubleshooting and technical support with ConocoPhillips, where he was also involved with developing process simulation tools. CLAY JONES is the principal technical development engineer with Optimized Gas Treating. He has a bachelor of science degree from McNeese State University and a master’s degree from the University of New Mexico. Before starting his current job in 2012, Mr. Jones spent 11 years with ConocoPhillips in sulfur plant and amine unit operations.

Select 158 at www.HydrocarbonProcessing.com/RS

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PROCESS AUTOMATION Human-machine interfaces are the future of petrochemical refining P–87 Automation news in brief P–88 CORPORATE PROFILES ABB Inc—Analytical Measurement P–91

2014

40 Tcf

Discovered gross resources of natural gas in the Eastern Mediterranean region.

19 Tcf

Projected amount of natural gas in the Leviathan field, expected to come online in 2017.

1.1 Bcfd

The expectation for natural gas sales in 2023.

40% OF PRODUCTION Approximate percentage the Israeli government has made available for export.

$50

BILLION

Revenue natural gas exports are projected to bring to Israel over the next 25 years.

Israel—On the Verge of Becoming an Exporter of Natural Gas The State of Natural Gas in Israel

A series of recent discoveries by Noble Energy, the largest operator in the region, has increased the discovered gross resources of natural gas in the area to approximately 40 trillion cubic feet (Tcf). The Tamar natural gas field, first discovered in 2009, came online in March 2013 and is estimated to contain 10 Tcf of natural gas. Deliverability at the field is expected to reach 1.2 billion cubic feet per day (Bcfd) gross by mid-2015, and an additional expansion to 1.5 Bcfd is planned for 2016. The Leviathan field, discovered in December 2010, is the largest in the region, with an estimated recoverable gross mean resource of 19 Tcf of natural gas. Multiple phases of development in the field are being progressed toward sanction, and production is expected to come online in 2017. Additional smaller gas fields have also been discovered, including the Dalit and Tanin fields, and additional exploration is planned. Noble Energy, with partner Delek Group and its subsidiary, Avner Oil and Gas Exploration, are the region’s main operators. Demand for natural gas is strong in Israel and the region, and Israel is exploring its regional and LNG export options. As reported in World Oil’s Eastern Mediterranean regional report in February 2013, Israel consumed 187 Bcf of natural gas in 2010, with 40% of the nation’s electricity generated from natural gas. Natural gas production from new reserves will be increased, and the transmission and distribution systems will be upgraded. Overall, net production is projected to increase to approximately 575 MMcfd in 2018 and then increase over the next five years to 1.1 Bcfd in 2023.

Developing Policy

The Israeli government is actively determining its natural gas policies, as well as evaluating plans to develop the infrastructure needed to process and transport natural gas. The Israeli cabinet (Knesset) approved a plan to reserve 60% of natural gas for domestic use, projected to be around 540 Bcm over the next 25 years. The remaining 40% will be available for export, which is expected to earn $50 billion in the next 25 years. The decision was upheld when Israel’s High Court rejected appeals to the decision to export 40% of the natural gas.

Established Oil Potential in the Region

Significant exploration potential remains in the region. Oil potential is estimated at approximately 3 Bbbl in the

deep Mesozoic play in both Cyprus and Israel and there is 4 Tcf gross of natural gas potential in Cyprus. Exploration drilling is expected to resume in the area in late 2014 or early 2015.

Key Players

Noble Energy, with partners Delek Group and Avner Oil and Gas Exploration, are the main operators responsible for the discovery and development of the Tamar and Leviathan fields. Woodside Energy. Since 2012, Noble Energy and partners have been in negotiation with Woodside Energy on a deal to provide a working interest in the offshore Leviathan licenses to the latter. Woodside Energy is Australia’s largest producer of LNG, with over 25 years of experience. Their expertise in LNG would be an important asset in the development of LNG or FLNG processing facilities in the region. Cyprus. Recent discoveries in Cyprus have made it a pivotal player in the region. Noble Energy and partners are also drilling off Cyprus, where they were responsible for the Cyprus-A discovery, estimated to contain 5 Tcf of natural gas. Cyprus is now positioned to be an energy exporter. Total and eni are also exploring opportunities in the region. The fragile state of the Cypriot economy has created an urgency to monetize its natural gas supply. Many in Cyprus are keen to develop an LNG facility that is estimated to cost $12 billion. Israel’s participation in the project would lessen the financing burden on Cyprus. Such a facility would also open the door for exports to Europe, Asia and beyond. Turkey. A partnership with Turkey remains a possibility, though an unsteady political relationship between the Israeli and Turkish governments decreases the odds. If a partnership were to be formed, existing and potential Turkish pipelines would provide lucrative access to

consumers in the European and Asian markets. Jordan. Jordan has been approved by the Israeli High Court to receive gas exports and was targeted as a potential market by Noble Energy. Egypt. Egypt began exporting gas to Israel in 2008, but the contract was cancelled in 2012. Along with Jordan, Noble Energy listed Egypt a potential market in 2012.

A Recap of Possible Scenarios:

A) LNG plant in Cyprus which utilizes gas from both Israeli and Cyprus fields B) FLNG located in the Eastern Mediterranean sea C) Israeli gas connected to Turkey via pipeline

An Opportunity for Collaboration and Networking at the 2014 Eastern Mediterranean Gas Conference

The Eastern Mediterranean Gas Conference will be held 10–12 March 2014 and will give special focus to the latest market and technology trends related to the exploration, drilling, production, processing and marketing of natural gas offshore Israel and throughout the Eastern Mediterranean. Topics to be discussed include resource potential, leasing/permitting, development plans, infrastructure requirements, regulations and more. Noble Energy will be the lead sponsor for the event and was also lead sponsor of the inaugural Eastern Mediterranean Gas Conference, held in April 2013, where the company’s Chairman and CEO Charles Davidson delivered the keynote address. EMGC 2014 will be held at the Hilton Tel Aviv, Independence Park, Tel Aviv 63405, Israel. For more information, visit http://www.emgasconference.com.

TABLE 1. MAJOR OFFSHORE ISRAEL FIELDS Field

Discovery

Production

Est. size, Bcf

Mari-B

2000

2004

1,000

Tamar

2009

2013

9,700

Dalit

2009

2013

700

Leviathan

2010

2016

19,000

Dolphin

2011

Pending

81

Tanin

2012

Pending

1,200–1,300

PROCESS AUTOMATION

HUMAN-MACHINE INTERFACES ARE THE FUTURE OF PETROCHEMICAL REFINING What specific advances or innovations do you think will be the driving force behind the future of the petrochemical refining industry?

COREY FOSTER represents Valin Corp. in the Northern California automation market. Valin is a technical solutions provider for the technology, energy, life sciences, natural resources and transpor tation industries. The company offers personalized order management, onsite field support, training and applied engineering services utilizing automation, fluid management, precision measurement, process heating, filtration and fluid power products. Mr. Foster, who has 15 years of experience in automation specializing in electromechanical motion control, recently corresponded with the Hydrocarbon Processing editorial team to share his thoughts on automation market innovations and the future of the refining industry.

The future of the petrochemical refining industry will be driven by humanmachine interfaces (HMIs) pushing information to where it is needed. An HMI that pushes production, quality and alarm information to the right level of user or management anywhere in the world has the ability to increase the visibility and reaction time to problems as they arise. This type of innovation will help with plant coordination and troubleshooting recovery. In a refinery using control architecture implemented decades ago, when a sensor’s report back to the controls is out of the ordinary, the controls will throw an alarm. This is typically in a central control room removed from the location of the sensor and the problem. There may or may not be any indication of this alarm at the location of the problem, and if there is, it is probably just a flashing light on an electrical panel or HMI somewhere in the vicinity. If no one is there to see the alarm, then response times to certain problems can be unnecessarily long. A solution currently available that helps shorten these lengthy response times is when that information is “pushed” to wherever the user wants it to go. This includes e-mailing or texting an alert to a specific person. If the first user does not respond in an allotted time, the controls system can automatically “escalate” it to the next person. Then the users can respond to the alarm and appropriately react from wherever they are. This is the kind of modern advancement the industry needs to embrace in order to keep moving forward. There could also be opportunities for dynamic context-sensitive information. What if users could then open a Web browser or app on their smart phones and look at more details about the alarm to see its severity, location and perhaps even a suggested resolution?

What could be possible with dynamic context-sensitive information?

I think the best way to describe what I mean is through an example. Think of a copier machine that is jammed and it gives you information on fixing the problem. Or think of the “help” buttons in programs that give you assistance on a specific topic, depending on what you are doing. Both of those are “context-sensitive,” but they are still static and local to the application. What if these applications could be dynamically updated as solutions are developed for commonly occurring problems? A copier machine that utilizes this dynamic context-sensitive information would be able to display fixes for common problems and potentially warn you before a problem even occurs. Hypothetically, a company that implements these systems all up and down a pipeline can update a PDF or webpage that is linked to all of their other customers’ systems, creating a large network of helpful information for everyone involved. OEM customers would always be sure to have the latest and greatest support information before they even have a problem. FAQs on demand! Any other new innovations you see that will impact refiners?

Other notable new innovations include traceability, authorization and escalation when dealing with HMIs. Many times, problems are caused by operators pushing buttons they shouldn’t be, entering incorrect information, and then not being truthful about what they did. Being able to record their steps would give accountability to the operators, along with traceability on their actions, and thus allow for the gathering of troubleshooting information. This application has tremendous value in every other industry where the same problems exist. This kind of technology will go a long way in improving operator performance. Additionally, most control systems these days provide some sort of security or authorization level capability. These features are especially useful in the phar-

HYDROCARBON PROCESSING | JANUARY 2014 | PROCESS AUTOMATION

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PROCESS AUTOMATION

maceutical industry, which is regulated by the US Food and Drug Administration (FDA) and requires strict security standards (21CRF11). Those same capabilities are also well used in other industries for the same purposes, even if deemed less critical. The innovations that are taking place in newer tools aimed at 21CFR11 compliance allow a user to make certain adjustments only after receiving a manager’s approval, ensuring that the operator isn’t going to make a mistake that a higherlevel user would have detected. Where and how have these innovations already been implemented? What effects have they had?

The idea of “pushing” information to the right place has been used all over the manufacturing industry. HMIs are just one specific way of using this innovation in a pipeline or facility application. Great

visibility means greater production efficiency and throughput, no matter what the industry. The notion of dynamic context-sensitive information is a relatively new idea that requires more thought, planning, programming and updating. Because of this, there are very few applications that I know of using this technology, since most companies prioritize project completion first. Cost efficiency would always be a concern with this application, which, unfortunately, has limited its scope up until now. However, the effects on efficiency and timeliness would be immense if this technology was utilized on a wider scale. What are the biggest obstacles to improving the industry, and how do you overcome them?

The most pressing obstacle when it comes to implementing new technology is the resistance to change. The industry

is inherently conservative and doesn’t always welcome change with open arms. Some good examples of this resistance to change come from my experience in selling valves and filters to the pharmaceutical industry. When I would present process engineers with a new valve and filtration technology that would improve their process control, yields and process times, their first question was always, “Who in the pharmaceutical industry is already using this?” I found that, in each case, the new technology had to be vetted and approved in an intensive small-scale test process in order for it to even be considered. While many industry professionals are resistant to change for safety, financial or regulatory reasons, we in the automation industry try to make them see the potential that technologies such as the ones I’ve described can offer. We have to start in small bites in the industry to get them familiar with what is truly possible.

AUTOMATION NEWS IN BRIEF HONEYWELL SEEKS TO FULLY INTEGRATE TERMINAL OPERATIONS

Honeywell has announced its next generation terminal manager server software, offering full integration of fire and gas, closed-circuit television (CCTV), access control, digital video manager and enterprise building integrator systems. The new terminal manager server software includes the industry’s first configurable workflows for faster setup. “This release marks a major advance in terminal automation for an integrated solution built around a standard platform that also improves safety and security,” said Richard Thompson, general manager of Honeywell Enraf. Incorporating more than six decades of experience providing solutions for terminal operators, Honeywell Enraf ’s terminal manager is a Web-based solution for managing the entire operation in bulk terminals. Built on Microsoft Windows, it is used to monitor and control all critical processes from receipt to dispatch. Interfacing with enterprise resource planning (ERP), access control, loading and unloading, workflow management, inventory management, product reconciliation and documentation systems, it improves control in real time. P–88

“Tighter integration means better control of security, safety, inventory management, reconciliation, order management and workflows,” Mr. Thompson said. “Ultimately, it means operators are more likely to achieve their business goals.” The configurable workflows and a modular approach in the latest release of terminal manager significantly reduce the time needed to build the system by minimizing or eliminating the need for customization to specific operations. It enables users to quickly set up the software to give a broad overview and indepth control of key parameters such as product availability and movement, tank status, alarms, orders, shipments, shifts, loading bay availability, entries and exits. Honeywell Enraf ’s terminal manager is suitable for all bulk terminals and is compliant with the latest Experion PKS SCADA for medium- and large-size terminals, and with Experion HS for smaller terminals. INVENSYS RELEASES CLOUD-HOSTED HISTORIAN

Invensys, a supplier of industrial software, systems and control equipment to the hydrocarbon processing industry, has released a new, cloud-hosted histo-

PROCESS AUTOMATION | JANUARY 2014 | HydrocarbonProcessing.com

rian edition that will enable customers to safely share more plant data with their workers while lowering their IT burden. Building on a base of more than 70,000 licenses for this product, the company’s new online edition can help reduce implementation time, provide universal access and deliver alternative pricing models for expanded industry use. This offering uses a multi-tier historian database architecture, storing data from one or more local plant-level historians onto a cloud-hosted, enterprisewide instance. Data flows only one way—from the local historians to the online historian—and it is protected from cyber intrusion so it can safely be made available to more workers for better troubleshooting, reporting and analytics. The solution leverages Windows cloud services from Microsoft Corp., so there is no software to install or set up, saving on valuable IT resources and reducing capital requirements. This service will be offered as a yearly subscription, based on the number of users accessing the data. Reporting and analytics are delivered to the historian online edition through standard tools, including Invensys’ desktop reporting and analysis client, along with its mobile reporting solution. Sys-

Norris Conference Centers– CityCentre Houston, TX

GTL Advisory Board:

Interested in Presenting at GTL 2014? Call for Abstracts Gulf Publishing Company is pleased to announce that the second annual GTL Technology Forum will be held in Houston, Texas July 30–31, 2014. If you would like to participate as a speaker, we invite you to submit an abstract for consideration by our advisory board.

Arun Basu Institute Engineer

Iain Baxter Business Development Director

Adrienne M. Blume Managing Editor

Suggested topics and areas of interest includes: • GTL- Fischer-Tropsch • GTL- MTG/Methanol • GTL products: fuels, lubes, specialty products, etc. • Economics, properties, performance, etc. • Floating GTL • Financing of GTL projects by owners, equity, banks • Permitting issues (requirements, any thresholds, timing, etc.) • And more. For a full list, visit GTLTechForum.com

Don’t miss this unique opportunity to share your knowledge and expertise with your peers in the industry. Submission Deadline: January 31. Abstracts should be approximately 250 words in length and should include all authors, affiliations, pertinent contact information, and the proposed speaker (person presenting the paper). Please submit via e-mail to [email protected] by January 31. Speaker Inquiries: Please contact Melissa Smith, Events Director, Gulf Publishing Company, at [email protected] or +1 (713) 520-4475. Sponsor/Exhibitor Inquiries: Please contact Lisa Zadok, Events Sales Manager, at [email protected] or +1 (713) 525-4632.

GTLTechForum.com

Carl Hahn Director, Sales and Process Technology

Mark LaCour, P.E. Project Development and Procurement

Syamal Poddar President

Mark Schnell General Manager, Marketing, Strategy and New Business Development

Paul Schubert Chief Operating Officer

Neils Udengaard

Timothy Vail President & CEO

PROCESS AUTOMATION

tem users can view the data via multiple devices, including desktop PCs, laptops, tablets and smart phones. This online historian is the first commercial offering from the Invensys–Windows cloud relationship, whereby the two companies jointly develop manufacturing operations software that can be hosted on the Windows platform. In other company-related news, Invensys shareholders have approved the company’s acquisition by Schneider Electric. At the investor meeting, held back in October in London, a majority of voting shareholders (representing 99.94% by value of those voted shares) voted in favor of the resolution to approve the scheme. At the general meeting of shareholders, 99.95% of the voted shares were in favor of the special resolution to approve the scheme, well above the 75% threshold required. Completion of the transaction remains subject to the satisfaction or waiver of certain other conditions set out in the scheme document. A COST-EFFECTIVE GATEWAY TO VIRTUALIZATION

Rockwell Automation has released an Industrial Data Center product, engineered specifically to help manufacturing and production companies take advantage of the benefits of a fully virtualized environment. This product offering helps reduce costs by decreasing the server footprint, extending application longevity, and improving infrastructure reliability with management and recovery features. “Although there has been a proliferation of virtualized servers on the plant floor in recent years, moving to a virtualized environment can be costly and time consuming for production businesses,” said Matt Fordenwalt, a Rockwell Automation executive. “The Industrial Data Center offering from Rockwell Automation is a cost-effective way for production companies to more quickly take advantage of this growing trend.” The standard, pre-configured infrastructure offering represents a complete turnkey solution that includes hardware, software, factory assembly, onsite configuration, documentation and tech support from Rockwell Automation. The goal for this product is to reduce cost of ownership and help increase realized savings for industrial companies over the P–90

lifetime of assets through virtualization. The Industrial Data Center bundle also incorporates technology from several IT providers and the company’s strategic alliance partners Cisco and Panduit. This packaged solution includes unified computing system (UCS) servers and catalyst switches from Cisco, and is built in accordance with the industrial best practices documented in the Rockwell Automation and Cisco Converged Plantwide Ethernet Architectures. Validation and assembly, led by Panduit, extends convergence to the computing level by combining their expertise in the enterprise and data-center markets with Rockwell Automation industrial expertise. The Industrial Data Center offering is available in two versions. One model is equipped with two UCS servers with the ability to expand from 3 TB to 5 TB of usable storage, standard virtualization software, 24 rack units, and an operating-system license. The other model includes three UCS servers that are expandable from 6 TB to 9 TB of usable storage, 42 rack units and the operatingsystem license. All equipment is shipped pre-assembled, and also includes onsite configuration and a streamlined maintenance program that provides a single phone number to call for support. YOKOGAWA RELEASES NEW PLATFORM FOR DIGITAL MEASUREMENT

Yokogawa Corp. of America has released its new sensors with a communication platform product series for the digital measurement of pH and ORP. This will join an existing lineup of pH/ORP solutions that includes the company’s two-wire pH/ORP-transmitter. The sensors with communication platform initially consists of a module, the pH/ORP sensor, a cable, and specialized PC software. Like its predecessor, the newly released sensor is general purpose and is suitable for a wide range of applications. It can store digital data and be calibrated by using the platform’s software. With these platform products, customers should be able to reduce the amount of maintenance work that needs to be performed onsite, thereby improving efficiency and reducing costs. Liquid analyzers are used in the oil, petrochemical, iron and steel, electric

PROCESS AUTOMATION | JANUARY 2014 | HydrocarbonProcessing.com

power, and water supply and wastewater treatment industries to control the quality of raw materials and products, monitor reactions and manage the wastewater treatment process. The properties of certain solutions may cause damage to or foul the sensors in these analyzers and thus adversely affect measurement accuracy, so sensor calibration is required on a regular basis. However, conditions vary and it is not always safe or convenient to perform the calibration work onsite, which usually requires a converter to store data and the use of standard calibration solutions. There is a need to move this work to a safer location and also reduce measurement downtime. Product features. The new item offers better working conditions and reduced measurement downtime. The pH/ORP sensor is able to process digital signals and store digital information, including calibration data. Using either the PC software or a transmitter, it can do offline calibration of these sensors in a laboratory, where working conditions are optimal. In addition, the ability to swap out the pH/ORP sensor and replace it with a calibrated sensor onsite will significantly reduce measurement downtime. Plus, with the software, it will be possible to simultaneously calibrate up to four sensors, significantly shortening calibration time. The software features an integrated database capable of storing data for up to 100 sensors. This enables predictive maintenance, allowing service staff to identify when sensor maintenance and/ or replacement is required. In addition, there is no longer the need to go onsite to obtain the data stored on a converter. Major target markets. Yokogawa is keen

to have its expertise and products known across the globe. Already, many in the process industries use Yokogawa, including sectors like oil, petrochemicals, iron and steel, electric power, water supply and wastewater treatment. Applications for this new platform include: • Monitor the quality of treated wastewater and neutralized water • Control the concentrations of liquid infusion systems • Use a two-wire system to feed power and transmits signals through a pair of cables, reducing wiring costs.

ABB INC—ANALYTICAL MEASUREMENT

ADDRESSING THE NEEDS OF MODERN OIL AND GAS INDUSTRY—MEASUREMENT MADE EASY ABB Analytical Measurements has the capacity to address the process analytical requirements of the modern Oil and Gas industry. The company counts a large installed base of analytical solutions both upstream and downstream in major production plants, refineries and petrochemical units. Our analytical solutions are used in: Gasoline and Diesel Blending, Distillate Hydrotreating, HF Alkylation, Catalytic Reforming, Hydrocracking, Crude Distillation, Naphtha Steam Cracking and Downstream Petrochemicals. For more than 40 years, ABB designs, manufactures and markets high performance FT-IR and FT-NIR spectrometers as well as turnkey analytical solutions for several applications. The company capabilities encompass one of the largest portfolios for laboratory, at-line and process FT-IR analyzers. They perform real-time analysis of the chemical composition and/or physical properties of a process sample stream. ABB’s advanced solutions combine analyzers, advanced process control, data management, process and application knowledge to improve the operational performance, productivity, capacity and safety of industrial processes for customers. ABB (www.abb.com) is a leader in power and automation technologies that enable utility and industry customers to improve their performance while lowering environmental impact. The ABB Group of companies operates in around 100 countries and employs about 150,000 people.

CONTACT INFORMATION 585, boulevard Charest E., suite 300 Quebec, QC CANADA G1K 9H4 Tel: +1 418 877 2944 Fax :+1 418 877 2834 [email protected] www.abb.com/analytical

Optimize your refinery process and increase profitability. Measurement made easy.

The new FTPA2000-HP260X is a real-time process analyzer offering high-precision and rapid analytical measurements on the full range of hydrocarbon streams helping you achieve efficient and fast Return on Investment. This versatile Ex-area certified 8-channel fibre-optic FT-NIR analyzer is suitable for the measurement of hydrocarbon process stream qualities in a wide variety of refinery process unit optimization applications (CDU, VDU, HCK and FCC units, Lube Base Oil, Gasoline Blending and others). Learn more at www.abb.com/analytical ABB Inc. Analytical Measurements Phone: +1 418-877-2944 1 800 858-3847 (North America) Email: [email protected]

Select 159 at www.HydrocarbonProcessing.com/RS SPONSORED CONTENT

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HPI MARKET DATA 2014 HPI Market Data 2014 Get reliable, accurate information to drive your strategic decisionmaking for 2014 and beyond. Hydrocarbon Processing’s HPI Market Data 2014 is the industry’s most trusted source for forecast spending and market analysis.

The HPI Market Data Report Provides You with Access to: • Capital, maintenance and operating spending broken out by geographical region • Expanded editorial analysis of worldwide economic, social and political trends driving HPI activity across all sectors •A An exploration of the changing markets and demand within the g global HPI, with discussion of growing markets. • A one-of-kind snapshot of how and where spending will take p place in 2014 and beyond. •4 41 tables and 103 figures

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HydrocarbonProcessing.com

BILLY THINNES, TECHNICAL EDITOR [email protected]

People

Melissa Hockstad has joined The American Fuel and Petrochemical Manufacturers (AFPM) as vice president of petrochemicals. Ms. Hockstad comes to AFPM as the association expands its petrochemical division. Ms. Hockstad brings to AFPM 17 years of in-depth industry experience, most recently as vice president of science, technology and regulatory affairs for the Society of the Plastics Industry and the Synthetic Organic Chemical Manufacturers Association, where she served as performance improvement director.

In other AFPM news, the industry trade group has promoted Brendan Williams to senior vice president of advocacy. Mr. Williams joined AFPM in 2007 and has served as vice president of advocacy since December 2011.

Steve Edwards is the new chairman, president and CEO of Black & Veatch, succeeding Len Rodman. In April 2013, Mr. Edwards was named COO of the company and was elevated to the top leadership position following a transition period. Mr. Edwards becomes the seventh person to serve as president in the company’s history. Before becoming COO, Mr. Edwards was an executive vice president of global EPC for Black & Veatch’s energy business.

Dan Hubbard has been named vice president for Willbros Group’s gas processing operations in Tulsa, Oklahoma. With this hire, the company will officially enter the gas processing plant market. Mr. Hubbard has 22 years of experience designing modular cryogenic gas processing plants. He joins Willbros from Hydrocarbon Processing Technology. While with Hydrocarbon Processing Technology, Mr. Hubbard was responsible for overseeing the design, fabrication and installation of gas processing, gas treating and nitrogen rejection plants. Additionally, he provided engineering consultation and design services for gas processing clients. Based in Tulsa, Mr. Hubbard will be responsible for leading the technical development of the company’s gas processing plant offerings.

America’s Natural Gas Alliance (ANGA) has elected Charles B. Stanley to be the organization’s chairman of the board for the 2014–2016 term. Mr. Stanley is president and CEO of QEP Resources. He has more than 26 years of experience in oil and natural gas operations. Previously, he served as a director for Questar Corp. Southwestern Energy’s President Steve Mueller will become vice chairman. Mr. Mueller has led Southwestern since 2009. He has over 30 years of experience in the oil and natural gas industry.

NorTex Midstream Partners has named Ben Moore to lead the company as president and CEO. He joins NorTex with 25 years of experience in business development, operations and engineering in both the upstream and midstream energy sectors. Prior to joining NorTex, Mr. Moore spent 12 years at Enstor, Iberdrola Renewable’s gas storage subsidiary, where he served as vice president of operations and engineering, as well as vice president of business development.

Viega has appointed long-time employee Dalyn Cantrell as the new vice president of sales and marketing. Ms. Cantrell replaced Dave Garlow, who accepted the role as Viega president and CEO. Ms. Cantrell has more than 30 years of experience in the plumbing and heating industry, beginning her career in 1983 in customer service for Vanguard. Throughout her career at Vanguard, Cantrell worked as a customer service representative, customer service manager, assistant to the national sales manager, director of code services, regional manager and, finally, national sales manager. In 2005, when Viega purchased Vanguard, Ms. Cantrell moved into the position of director of field sales, with responsibilities that included directing and managing eight regional managers and all district managers.

Spectra Energy Corp. has appointed Clarence P. Cazalot Jr. to its board of directors. Mr. Cazalot previously served as executive chairman of the board of directors for Marathon Oil Corp., a position he retired from at the end of 2013. “With the addition of the ExpressPlatte crude oil pipeline system into our portfolio, we welcome Clarence’s extensive exploration and production knowledge and history to the board,” said Bill Esrey, Spectra Energy chairman of the board. “His insights will be a valuable addition to the board table, one already filled with a wealth of skills and expertise.” Mr. Cazalot has more than 40 years of industry experience. He worked as president and chief executive officer of Marathon Oil Corp. from 2002–2013.

Jacqueline Lecourtier has agreed to chair and lead the deliberations of DEINOVE’s Scientific Advisory Board (SAB), which meets twice a year. She took her new position at the SAB’s plenary session in December. Ms. Lecourtier is an engineer from the ecole Nationale Superieure des Industries Chimiques (French Higher National Institute of Chemical Engineering), and has devoted 25 years of her career to the Institut Francais du Petrole (IFP). From 2006-2011, she was scientific director of IFPEN: French Institute of Petroleum-New Energies.

Ashland Water Technologies has hired Jeff Fulgham as vice president of marketing. He will be based at company headquarters in Wilmington, Delaware. Mr. Fulgham brings over 30 years of sales and marketing experience, primarily in industrial water treatment, to this role. He most recently served as chief sales and strategy officer for Banyan Water, based in San Francisco, California. He was responsible for sales, service, strategy and marketing for the company, focused on driving water conservation for large commercial and institutional properties. Prior to working for Banyan, Mr. Fulgham spent much of his career with General Electric Co., serving in a variety of sales and marketing roles.

EXCO Resources’ board of directors has appointed Jeffrey D. Benjamin, a long-time investor in EXCO and an independent member of EXCO’s board, to serve as non-executive chairman of the board of directors. Mr. Benjamin has extensive knowledge of EXCO and its business, having served on the board since October 2005 and prior to that from 1998 through 2003. Mr. Benjamin is also a director of Caesars Entertainment Corp. and Chemtura Corp., and is chairman of the board for Spectrum Group International.

Hydrocarbon Processing | JANUARY 201493

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