Gulfpub Hp 201503

HARNESS THE POWER

OF MANUFACTURING INNOVATION

RENTECH engineers build unmatched power and performance into every boiler we deliver. Our 80-acre manufacturing facility—the industry’s most technologically advanced—includes heavy bay and light bay areas with direct access to rail, cross-country trucking routes and shipping facilities. We master every detail to deliver elemental power for clients worldwide. Take an expanded tour of our facilities today at www.rentechboilers.com/facilities HARNESS THE POWER WITH RENTECH.

HEAT RECOVERY STEAM GENERATORS WASTE HEAT BOILERS FIRED PACKAGED WATERTUBE BOILERS SPECIALTY BOILERS

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ROTATING EQUIPMENT New API guidelines improve design of compressor seals ®

HydrocarbonProcessing.com | MARCH 2015

REFINING DEVELOPMENTS Better modeling optimizes shale oil processing

PLANT DESIGN

SPECIAL REPORT:

Corrosion Control New duplex stainless steels reduce failure events and increase plant profitability

Rethinking secondary reformer temperature enhances ammonia production

HARNESS THE POWER

OF MANUFACTURING INNOVATION

RENTECH engineers build unmatched power and performance into every boiler we deliver. Our 80-acre manufacturing facility—the industry’s most technologically advanced—includes heavy bay and light bay areas with direct access to rail, cross-country trucking routes and shipping facilities. We master every detail to deliver elemental power for clients worldwide. Take an expanded tour of our facilities today at www.rentechboilers.com/facilities HARNESS THE POWER WITH RENTECH.

HEAT RECOVERY STEAM GENERATORS WASTE HEAT BOILERS FIRED PACKAGED WATERTUBE BOILERS SPECIALTY BOILERS

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MARCH 2015 | Volume 94 Number 3 HydrocarbonProcessing.com

34

10 SPECIAL REPORT: CORROSION CONTROL 35 How caustic stress leads to failures of incinerator caustic spray nozzles E. Al-Zahrani, A. Al-Meshari and M. Maity

41

Extend heat exchanger lifecycle with hyper-duplex stainless steel E. Perea

47

Evaluate the reliability of a reformer heater convection tube H. Yoon, J. Nam and S. Kim

PLANT DESIGN 53 Determine the design metal temperature for a secondary reformer B. K. Sharma

HEAT TRANSFER 55 Improve the operation of fired heaters K. Malhotra

REFINING DEVELOPMENTS 61 Shale oil characterization optimizes refining process S. Sayles

67

DEPARTMENTS 4 10 17 103 106 108 109 110

PROCESS CONTROL 73 Optimize online monitoring of base oil H. Kim and G. Fannin

ROTATING EQUIPMENT 77 Contain ‘normal’ leakage from primary seals

HP staff Cover Image: Austrian OMV installed a SNOX plant, a fuel gas desulfurization process licensed by Haldor Topsøe, to remove SO2 and NOx from the flue gases of the power and steam generation facilities at its Schwechat refinery near Vienna, Austria. The facilities are fired primarily with high-sulfur heavy residual oil. Photo courtesy of OMV.

Industry Metrics Innovations Marketplace Advertiser Index Events People

Downstream has good news for 2015

19

Reliability Consider oil-resistant cable terminations to increase electric motor reliability

21

Project Management Energy efficiency: Getting in early pays off exponentially

23

Global Latin America’s refinery product demand is decelerating

27

Petrochemicals Fatal DuPont leak shows need for improved chemical safety systems

29

Engineering Case Histories Case 83: What are useful questions to ask before starting a vibration analysis?

R. Smith and S. Shaw

WHAT’S NEW IN CATALYSTS—SUPPLEMENT C-84 2015 catalyst developments: Innovation and value creation

News

COLUMNS 9 Editorial Comment

Update on the catalytic cracking process and standpipes—Part 1 P. K. Niccum

Industry Perspectives

31

Boxscore Construction Analysis How low oil prices are affecting new project announcements

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Industry Perspectives

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EDITORIAL

Notables from BP’s Energy Outlook 2035 In mid-February, BP released its outlook for the next 20 years. As reminded by BP’s new chief economist, Spencer Dale, the outlook is a projection of what is most likely to occur based on the influences of technology, global and regional economics, and political policy. So, what can the energy industry expect over the next 20 years? • The global GDP will double by 2035, largely driven by growing populations and increased productivity in developing nations. GDP growth will be supported by a 37% increase in energy consumption. • After 2015, there will be a clustering of hydrocarbon energy resources. Crude oil, coal and natural gas will make up similar percentages (26% to 28%) of the energy supply over the next decade as natural gas gradually replaces coal in the power sector (FIG. 1). • Consumption of liquid fuels (oil, biofuels and other liquids) will rise by 11 Mbpd over the next 20 years, driven by non-OECD nations’ transport and industry demands. • Looking ahead, new energy sources, such as renewable fuels, shale gas, tight oil and oil sands, will account for 8% of total energy consumption (FIG. 2). The energy industry is a long-term business. The full report can be found online at www.bp.com/energyoutlook.

Shares of primary energy, %

50 Oil Coal Gas

40

Hydro Nuclear Renewables*

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

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30 20 10 0 1965

1975

1985

1995

2005

2015

2025

2035

Source: BP’s Energy Outlook 2035

For more information about article reprints, call Rhonda Brown with Foster Printing Company at +1 (866) 879-9144 ext. 194 or e-mail [email protected]. Hydrocarbon Processing (ISSN 0018-8190) is published monthly by Gulf Publishing Company, 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252.

*Includes biofuels

FIG. 1. Shares of primary energy, 1965–2035

Copyright © 2015 by Gulf Publishing Company. All rights reserved.

3

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.

Renewables in power Shale gas Tight oil, oil sands and biofuels Production, Btoe

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

2

1

0 1990

2005

2020

Source: BP’s Energy Outlook 2035

FIG. 2. New sources of energy supply, 1990–2035.

2035

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

Part of Euromoney Institutional Investor PLC. Other energy group titles include: World Oil and Petroleum Economist. Publication Agreement Number 40034765

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Preliminary Agenda Announced for the Sixth International Refining & Petrochemical Conference Register Now to Take Advantage of Best Savings with Super Early Bird Rates Hydrocarbon Processing’s International Refining and Petrochemical Conference (IRPC) will be held 1–3 June 2015 in Abu Dhabi, United Arab Emirates in conjunction with DMG Global Energy, organizers of ADIPEC. We invite you to join us for this high-level business and technical forum and exhibition. You’ll hear from key players in the global petrochemical and refinery sectors regarding best practices and the latest industry advancements, plus have numerous opportunities to network with top operators and technology leaders from across the global hydrocarbon processing industry (HPI).

New for 2015, IRPC will benefit from a one-day, high-level refining and petrochemical business conference addressing the strategic direction of the industry. Put together by an esteemed advisory board, the 2015 technical conference program features presentations from leading HPI companies. Sessions include: • Multi-purpose clean fuel DME from methanol: Catalysis and Kinetics, Bharat Petroleum Corporation, Ltd • Success factors related to plant revamp and modification projects—cost, schedule and quality are not enough, EQUATE Petrochemical Company

• Strategic investments in Middle East refining and its new process technology configurations, Kuwait Petroleum International • SAF 2304: Cost effective solution for refinery heat exchangers, Sandvik Materials Technology

• Natural gas processing operational experience, Gail (India), Ltd

• Consider new designs for sour water strippers, Saudi Aramco

• MS maximization by innovative modification of FCC Naphtha splitter operation (zero investment), HPCL Mittal Energy, Ltd

• Bio-jet production and testing for demonstration flight at Abu Dhabi, Takreer Research Center, Abu Dhabi Oil Refining Company

• Role of safety instrumented system in flare reduction, Kuwait Oil Company (KOC)

• An efficiency assessment of a fired heater in diesel hydroprocessing unit by detailed heat loss analysis, aTüpras – Turkish Petroleum Refineries Corporation

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• and others

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Editorial Comment

STEPHANY ROMANOW, EDITOR [email protected]

Downstream has good news for 2015 The outlook is optimistic for downstream companies. Independent refiners are positive on present and future demand for transportation fuels. Investments by US independent. Valero Energy Corp. continues to strategically invest in its refining and logistics assets. New projects are focused on increasing the company’s ability to process greater volumes of light shale oil. Valero is building two crude topping units at its Corpus Christi, Texas and Houston, Texas refineries. When completed, the new units are expected to reduce feedstock costs at both refineries and add 160 Mbpd of total processing capacity for 50 °API crudes. Distillate expansions. Valero is also expanding hydrocracking capacity within its network. The Meraux, Louisiana hydrocracker project was completed in the fourth quarter of 2014. Other expansion projects are underway at the St. Charles, Louisiana and Port Arthur, Texas refineries. Both hydrocracker projects will add 30 Mbpd of capacity and are expected to start up in the second half of 2015.

Focus on light domestic crude. Simi-

lar to Valero, Marathon Petroleum is increasing light sweet crude and condensate processing capacity. The company recently finished building a 25-Mbpd condensate splitter at its Canton, Ohio refinery. A 35-Mbpd splitter is slated for completion by the second quarter of 2015 at the Cattesburg, Kentucky refinery. Both refineries are near the Utica shale play. Also, a 30-Mbpd revamp is planned at the Robinson, Illinois refinery to improve the processing of light crudes; project completion is expected in 2016. In December 2014, Flint Hills Resources began construction at the Corpus Christi West refinery. The project, named Project Eagle Ford, is expected to cost approximately $600 million. Construction will take 36 months. After the project is complete, the West refinery will have the capability to process 100% domestic crude. The West refinery is a 230-Mbpd refinery and is located near the Eagle Ford play. Projects are moving forward in the US to handle greater volumes of domestic crudes and incorporate more flexibility and efficiency.

INSIDE THIS ISSUE

23 Global.

Latin America had been a growing market for transportation fuels and petrochemicals. This region was on a super-cycle for products and energy. Things have changed for this region, according to John Galante with ESAI. What is the future demand for energy and HPI products for this region?

34 Corrosion control.

In the HPI, corrosion is an ongoing and dynamic issue for processing facilities and equipment. It is often the root cause for equipment failure, leaks and accidents. Several case studies by SK Innovation Co., Sandvik Materials and SABIC Technology Center investigate leaking and cracking equipment events, and the use of new steels to extend equipment service life.

55 Heat transfer.

Fired heaters are huge energy consuming units and widely used in HPI facilities. The safe and reliable operation of fired heaters is critical. Several case histories demonstrate better methods to design and operate fired heaters.

61 Refining developments.

The abundance of shale oils has redefined the crude slate in North America. These new crudes have different characteristics from conventional oils. Better crude evaluation methods will help refiners process these new oils with minimal impact on operating conditions.

77 Rotating equipment. FIG. 1. Valero’s Corpus Christi petroleum refinery was commissioned in 1983. It is one of the world’s most complex refineries.

New advances, such as dry containment seal technology, can limit fugitive emissions, especially in refinery environments. These seals can also provide a lower-cost solution to liquid dual-seal systems. Hydrocarbon Processing | MARCH 20159

| News Labor union strike affecting US refining industry There is no end in sight to the United Steelworkers Union (USW) strike affecting several US refineries. The USW has filed unfair labor practices charges against nine refineries operated by BP-Husky, LyondellBasell Industries NV, Marathon Petroleum Corp. and Tesoro Corp., and is seeking wage increases, health benefits, tougher worker fatigue prevention measures, and an end to non-union contract workers performing refinery maintenance. Royal Dutch Shell is bargaining on behalf of employers. The USW says a fair agreement is impossible until the companies “show respect for the union workers who have made them and their shareholders very wealthy,” while Tesoro claims its plants can run for a “very long period” during the walkout. The middle ground seems smaller than ever. Photo: The Anacortes refinery in Washington State, with a capacity of 120 Mbpd, is one of three Tesoro facilities affected by the USW strike.

MIKE RHODES, TECHNICAL EDITOR [email protected]

News

Halder Topsøe brings Sweden demonstration biogas plant onstream Swedish energy company Göteborg Energi announced that GoBiGas, the world’s first large-scale demonstration plant for the production of biogas through the gasification of biofuels and residues from forestry, is now in operation supplying gas to the country’s natural gas grid. GoBiGas is an abbreviation of Gothenburg Biomass Gasification Project and represents a large investment for Göteborg Energi. The project has received funding from the Swedish Energy Agency and consists of two primary phases: Phase 1 has focused on establishing the demonstration plant now in operation, while Phase 2 is to expand to a full-scale commercial plant. Haldor Topsøe A/S provided licensing, catalyst and engineering for the gas cleaning, and the methanation section for the project, enabling the plant to produce substitute natural gas (SNG) by thermal gasification of forest residues such as branches, roots and tops. The biomass is converted to gas with a methane content of over 95%. The plant has a capacity of 20 MW of SNG. Until now, all running industrial references related to SNG in Haldor Topsøe have been based on coal gasification or coke oven gas. With the successful startup of GoBiGas, Haldor Topsøe has demonstrated that catalytic solutions and process technology also make it possible to efficiently carry out biomass to SNG conversion (FIG. 1).

the study says, as both residential and nonresidential construction spending increase at double-digit growth rates, rebounding from the declines recorded during the 2008–2013 period. Utilities construction will also recover, bolstering the large associated valve market. Process manufacturing will remain the largest end-use market for valves, and gains here will be supported by growth in manufacturing output, particularly in the chemical industry. Demand for automatic valves is forecast to outpace increases in standard valve sales as a result of consumer efforts to improve operational efficiencies. The positive outlook for most valve-using industries will lead companies to opt for

automatic products in applications where they may have purchased standard valves in weaker economies. Automatic regulator valves will post the strongest gains of any product, as a result of their widespread use in petrochemical/chemical, oil and gas, and utility applications (TABLE 1).

Second-generation biofuels market expected to reach $23.9 B According to a new report by Allied Market Research, the global second-generation biofuels (advanced biofuels) market will reach almost $24 B by 2020, registering a compound annual growth rate (CAGR) of 49.4% during 2014–2020.

FIG. 1. The GoBiGas plant in Sweden produces biogas through the gasification of biofuels and residues from forestry.

TABLE 1. US industrial valve demand in millions of dollars

Industry performance increases industrial valves demand in US The need for industrial valves in the US is forecast to increase 4.9%/yr to $19.8 B in 2018, according to a new study from Cleveland, Ohio-based industry market research firm The Freedonia Group Inc. The construction market will post the strongest increases in valve demand,

Annual growth, % Item

2008

2013

2018

2008–2013

2013–2018

Industrial valve demand

14,184

15,600

19,800

1.9

4.9

Process manufacturing industries

5,150

5,875

6,885

2.7

3.2

Public utilities

4,432

4,775

6,065

1.5

4.9

Resource industries

2,476

2,990

3,960

3.8

5.8

Construction

1,594

1,445

2,250

-1.9

9.3

532

515

640

-0.6

4.4

Other Source: The Freedonia Group Inc.

Hydrocarbon Processing | MARCH 201511

News Second-generation biofuels are developed to overcome the limitations associated with traditional biofuels, such as biodiversity and food vs. fuel issues. Financial incentives and supportive regulations in the US and Europe are instrumental in driving the commercial production and adoption of advanced biofuels—the Renewable Fuel Standard in the US is one such initiative. However, complexities associated with the production process, high initial capital investment and the availability of land (for plant setup) in the vicinity of the source of feedstock are factors impeding the growth of the market. TABLE 2. Recent filtration and valve company acquisitions Air filtration acquisitions Acquiring company

Acquired company

Eastman Chemical

Knowlton

Neenah Paper

Crane Technical Materials

Lydall

Andrew Filtration

Mann + Hummel

Vokes

Clarcor

GE–BHA

Filtration Group

Porex

SWM

DelStar

PGI

Fiberweb Valve company acquisitions

Acquiring company

Acquired company

IMI

Bopp & Reuther

MAT Holdings

Dorot

SPX (divesting)

Flow Control

Graco

Alco Valves; High Pressure Equipment

Siemens

Dresser Rand

AVK

Premier Valves Group

Dover

WellMark

Curtiss Wright

Engelmasa (Brazilian valve division)

Rotork

Xylem (UK solenoid valve division); Young Tech; G. T. Attuatori; Renfro Assoc.

Admiral Valve

CPV

Krones

EvoGuard

KITZ

Micro Pneumatics

Klinger

Westad

Samson Group

Ringo Válvulas

Emerson

Virgo; Enardo

COOPER Valves

Accuseal

Cameron

Douglas Chero

12MARCH 2015 | HydrocarbonProcessing.com

Biodiesel is the highest produced second-generation biofuel, but the more commercially viable cellulosic ethanol will soon surpass biodiesel and eventually lead the market by 2020 (FIG. 2). North America (NA) generated the largest revenue with over 50% of the globally installed capacity base. The cellulosic ethanol market is forecast to grow at a CAGR of 52.2% during 2014–2020 due to the rapid growth in technologies for mass production. At present, NA accounts for approximately 82% of the global market share, chiefly due to the supportive regulatory environment. Recently, Procter & Gamble announced a collaboration with DuPont to use cellulosic ethanol, replacing cornbased ethanol in its Tide detergent in NA. Other major players that have recently begun production of cellulosic ethanol in NA are INEOS New Planet BioEnergy, Poet-DSM Advanced Biofuels LLC, Canergy LLC, Abengoa Bioenergy, Amyris and Enerkem, among others. Many companies are setting up production plants for second-generation biofuels. Some of the key players operating in different market segments include Algenol Biofuels, Abengoa Bioenergy, GranBio, INEOS Bio, Inbicon, Clariant, ZeaChem and DuPont Industrial Biosciences. POET-DSM Advanced Biofuels LLC has recently opened its first-commercial scale cellulosic ethanol plant with a production capacity of 20 MMgal/yr.

Composites institute provides Dow with collaborative platform The Dow Chemical Company, in partnership with its JV, DowAksa, and a consortium of composites-related businesses, academic leaders and government organi-

zations, has been selected by the Obama Administration to establish the Institute for Advanced Composites Manufacturing Innovation (IACMI). IACMI will help advance the state of knowledge and commercialization of carbon fiber composites technology in response to market demands for strong, lightweight materials. It will create a platform to overcome technological and cost barriers to the wide-scale adoption of carbon fiber composites in a variety of industrial sectors including pressure vessel, infrastructure and wind, and automotive. DowAksa, a 50/50 JV between Dow and Aksa Akrilik Kimya Sanayii A.Ş., one of the world’s largest acrylic fiber manufacturers, has become a leader in the production of carbon fiber, carbon fiber intermediates and high-quality composite materials, which are valuable for downstream high-tech manufacturing.

Mergers abound in the gas and liquids flow, control and treatment market The last two years have seen hundreds of acquisitions in the $400-B market that treats and controls air, gas, water and other liquids. The largest segment is industrial valves, while one of the smaller segments is air filtration. Recent acquisitions in these two segments are listed in TABLE 2. There are a variety of motivations involved in acquisitions, including expansion of the technology and product base. Lydall makes filter media for HVAC, but not for dust collection. Andrew Filtration makes media for dust collectors, so Lydall has more than doubled the filter media sales potential with the acquisition. Clarcor took a similar course, but one step down the supply chain. Clarcor fur-

FIG. 2. Global second-generation biofuels (advanced biofuels) market, segmentation and forecast (2013–2020).

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News nishs HVAC filters, so, with the purchase of BHA from GE, the company is now the leading dust collector bag company. Another motivation is to gain access to a geographical market, as witnessed by Curtiss Wrights’ Brazilian valve acquisition. A third reason is vertical integration. An earlier acquisition by Clarcor moves it into the media business for face masks and HVAC. Another impetus is to streamline companies and make them more profitable. The SPX decision to separate its flow control from other businesses is a case in point. Xylem is still in

FIG. 3. GE will supply its LDPE Hyper compressor technology for Sasol North America’s LDPE plant in Lake Charles, Louisiana.

FIG. 4. The opening of the BASF polymer dispersions plant in Malaysia.

a repositioning mode several years after it was separated from ITT.

Sasol picks GE for compression trains on Louisiana PE project GE Oil & Gas has been awarded a contract from Sasol North America for the provision of the main compression trains required for its new low-density polyethylene (LDPE) plant being developed in Lake Charles, Louisiana. The LDPE plant is a central element of Sasol’s proposed $8.9-B petrochemical complex, which will include world-scale ethylene and ethylene derivative plants. GE’s LDPE Hyper compressor, a unique, 20-cylinder, two-stage compressor with discharge pressures of 45,000 psi, will sit at the heart of the plant. The complex will produce 1.5 MMtpy of ethylene, with approximately 90% of ethylene output converted into a diverse slate of commodity and specialty chemicals (FIG. 3).

BASF opens Malaysia polymer dispersions plant ESC signed by Steelhead LNG, WorleyParsons BASF is further strengthening its footprint in Asia-Pacific with the startup of its first production plant for polymer dispersions in Malaysia (FIG. 4). The plant has been built at the existing BASF production site in the Pasir Gudang Industrial Park of the Johor Free Trade Zone, and is the company’s third polymer dispersions plant in the Association of Southeast Asian Nations (ASEAN),

FIG. 5. The proposed site for the Vancouver Island LNG project.

14MARCH 2015 | HydrocarbonProcessing.com

complementing the existing Jakarta and Merak, Indonesia facilities. The new plant, which will benefit from close proximity to raw materials like the acrylic monomer complex at BASF Petronas Chemicals in Kuantan, will focus on the production of a variety of acrylic base polymer dispersions for the decorative coatings, construction and adhesive industries. Commercial production began in early 2015. By 2020, BASF aims for local production of approximately 75% of the products it sells in the Asia-Pacific region. To achieve this, BASF is investing €10 B with its partners to further develop its local production footprint to 2020. The Dispersions and Pigments division of BASF develops, produces and markets a range of high-quality pigments, resins, additives and polymer dispersions worldwide. These raw materials are used in formulations for coatings and paints, printing and packaging products, construction chemicals, adhesives, fiber bonding, plastics and paper, as well as for electronic applications.

In Canada, Huu-ay-aht First Nations and Steelhead LNG signed a contract with WorleyParsons for the provision of environmental, engineering, geotechnical and regulatory services at their proposed LNG Project at Sarita Bay on Vancouver Island (FIG. 5). The 24-MMtpy land‐based facility is one of the largest proposed LNG projects in British Columbia. The new contract, which could be worth in excess of $30 MM, will encompass environmental impact assessments, preliminary front-end engineering and design (pre-FEED) studies, geotechnical investigations and permitting approvals support. The new contract is an extension of the strategic relationship that already exists between WorleyParsons, Steelhead LNG and Huu-ay-aht First Nations. WorleyParsons played a key role in the recently completed preliminary assessment and screening stage of the proposed project. Over the past 25 years, WorleyParsons has also worked with numerous First Nations groups across BC and has provided specialized services for some of the largest projects in the province. The contracted activities will begin immediately.

A Better IEEE 841 High strength cast iron frame, endplates, conduit box and fan cover are designed to reduce vibration and assure accurate mounting dimensions

Super-E® windings meet or exceed NEMA Premium® efficiency standards

All internal rotor, stator and shaft surfaces are epoxy coated to prevent corrosion

Oversize bearings on each end for long life

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Inpro/Seal™ VBXX Bearing Isolators at both ends assure protection from contamination

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MIKE RHODES, TECHNICAL EDITOR [email protected]

Industry Metrics

5

Selected world oil prices, $/bbl

Jan 15

Dec 14

Nov 14

Oct 14

Sept 14

Aug 14

July 14

June 14

May 14

April 14

Jan 15

Dec 14

Nov 14

Oct 14

Aug 14

Sept 14

Japan Singapore

July 14

Production equals US marketed production, wet gas. Source: EIA.

US EU 16

June 14

Jan 14

J F M A M J J A S O N D J F M A M J J A S O N D J 2013 2014 2015

70 60 50

May 14

1 0

80

April 14

2

Mar 14

Monthly price (Henry Hub) 12-month price avg. 12-month Productionprice avg.

90

Feb 14

3

Mar 14

Global refining utilization rates, 2014–2015* 100 Utilization rates, %

4

Brent, Rotterdam

0 -5

6 5

Arab Heavy, US Gulf LLS, US Gulf

10

Jan 14

7

Gas prices, $/Mcf

Production, Bcfd

US gas production (Bcfd) and prices ($/Mcf) 80 70 60 50 40 30 20 10 0

WTI, US Gulf Dubai, Singapore

15

Feb 14

An expanded version of Industry Metrics can be found online at HydrocarbonProcessing.com.

Global refining margins, 2014–2015* 20 Margins, US$/bbl

The global market is experiencing a potential temporary recovery from a prolonged decline, possibly followed by the continuation of the downtrend. This is reflected in continued growth in the US tight oil production and strong global supply amid weaker global oil demand growth, contributing to rising global oil inventories.

US Gulf cracking spread vs. WTI, 2014–2015*

130 40 Cracking spread, US$/bbl

100 85 W. Texas Inter. Brent Blend Dubai Fateh

-0.5

01 Sept 08 Sept 15 Sept 22 Sept 29 Sept 06 Oct 13 Oct 20 Oct 27 Oct 03 Nov 10 Nov 17 Nov 24 Nov 01 Dec 08 Dec 15 Dec 22 Dec 29 Dec 05 Jan 12 Jan 19 Jan 26 Jan 02 Feb

0

Prem. gasoline unl. 92 Jet/kero

Jan 15

Dec 14

Nov 14

Oct 14

Sept 14

Aug 14

July 14

June 14

Jan 15

Dec 14

Nov 14

Oct 14

Sept 14

Aug 14

July 14

Gasoil, 50 ppm S Fuel oil, 180 cSt, 2% S

Jan 15

Dec 14

Nov 14

Oct 14

Sept 14

Aug 14

July 14

-10 -20 June 14

0

-2 -4

10

Mar 14

2

20

Feb 14

Dubai Urals

30 Cracking spread, US$/bbl

6

Singapore cracking spread vs. Brent, 2014–2015*

Jan 14

Brent Dated vs. sour crudes (Urals and Dubai) spread, 2014–2015*

June 14

Source: EIA Short-Term Energy Outlook, February 2015.

Light sweet/medium sour crude spread, US$/bbl

May 14

-20 May 14

2016-Q1

Gasoil, 10 ppm S Fuel oil, 1% S

-10 Jan 14

2015-Q1

-1.0

Prem. gasoline unl. 98, 10 ppm S Jet/kero

0

May 14

0.0

10

April 14

0.5

20

April 14

1.0

Cracking spread, US$/bbl

2.0 1.5

Stock change and balance, MMbpd

Supply and demand, MMbpd

30

2.5

2014-Q1

April 14

Rotterdam cracking spread vs. Dubai, 2014–2015*

World liquid fuel supply and demand, MMbpd

Forecast

Mar 14

Jan 14

J F M A M J J A S O N D J F M A M J J A S O N D J 2013 2014 2015

4

Gasoil/diesel, 0.05% S Fuel oil, 180c

-10

Source: DOE

40

96 Stock change and balance 94 World supply 92 World demand 90 88 86 84 82 80 78 2010-Q1 2011-Q1 2012-Q1 2013-Q1

Prem. gasoline unl. 93 Jet/kero

0

Mar 14

55

10

Feb 14

70

30 20

Feb 14

Oil prices, $/bbl

115

* Material published permission of the OPEC Secretariat; copyright 2015; all rights reserved; OPEC Monthly Oil Market Report, February 2015. Hydrocarbon Processing | MARCH 201517

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Reliability

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

Consider oil-resistant cable terminations to increase electric motor reliability Most engineers are familiar with adhesive-coated insulating tape used by electricians in the field and maintenance shop. If we use this tape in the engine compartment of an automobile, it will soon become gummy and will unravel. Although a common product will suffice in most applications, “standard” stretchable insulating tape will not serve well as an oil-resistant cable termination. Oil resistance is an important consideration, especially regarding terminal boxes of oil-mist-lubricated electric motors. However, excessive swelling can occur near the stator windings, thus impeding motor cooling effectiveness, as shown in FIG. 1.

Insufficient heat transfer can drastically reduce the service life of the winding. What is the maintenance cost due to poor cooling of the motor’s winding? Assume that the average motor, operating in a plant with 1,008 electric motors, has a service life of 12 years with non-swelling terminal leads vs. 6 years of operation when cooling is impaired due to swelling. In this case, the yearly repair and replacement frequencies are 84 and 168 motors, respectively. Spend wisely. Assume that the cost of purchasing and install-

ing an electric motor is $6,000. The possible recoverable funds of avoiding 84 events/yr could exceed $500,000. Conversely, the outlay for a superior T-lead material has an almost negligent incremental cost when compared to the calculated benefit-to-cost ratio of doing things right the first time. True reliability focus includes selecting superior materials whenever the cost can be justified. Compliance with applicable standards is needed. Many standards are associated with the Underwriter Laboratories, and address properties such as temperature and voltage ratings, abrasion resistance, hardness, allowable bend-radius-to-diameter ratio, tensile strength, elongation, flame-test compliance, oil resistance, chemical resistance and dielectric strength. Oil resistance is often linked to a maximum temperature; the standards define the test duration and percentage of original tensile and elongation retained. Hazards. Another document describes the restriction of hazardous substances (RoHS) compliance requirements as set forth by the EU. It represents the directive to establish environmental guidelines and legislation to reduce the presence of six materials that are listed as hazardous to the environment. To comply, products entering the EU must not have a homogeneous presence of these materials according to the weight percentages: • Lead (Pb) < 0.1% • Mercury (Hg) < 0.1% • Cadmium (Cd) < 0.01% • Hexavalent chromium (CrVI) < 0.1%

FIG. 1. Swelling cable terminations can impede motor cooling effectiveness and drastically shorten winding life.

• Polybrominated biphenyls (PBB) < 0.1% • Polybrominated diphenyl esters (PBDE) < 0.1%. Venders’ role. Top venders recognize their responsibility as

suppliers of coaxial connectors, cable assemblies and components used within products that are targeted for RoHS compliance. Likewise, reliability-focused user companies must make sound choices. These companies may elect to work with responsible and trustworthy electric motor manufacturers who make it their goal to fully understand their customer’s priorities. By disclosing the range of capabilities of their products and components, the vendor/manufacturer becomes the purchaser’s technology resource. Alternatively, a reliability-focused userpurchaser will groom subject matter experts whose tasks include the development of rigorous motor specifications. These specifications should ensure that motors incorporate only irradiation cross-linked polymeric insulation. Reliability engineering includes hundreds of details similar to the ones highlighted here. HEINZ P. BLOCH resides in Westminster, Colorado. His professional career began in 1962 and included longterm assignments as Exxon Chemical’s regional machinery specialist for the US. He has authored over 600 publications, among them 19 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 a professional engineer. Hydrocarbon Processing | MARCH 201519

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Project Management

ALAN ROSSITER, PRESIDENT Rossiter & Associates

Energy efficiency: Getting in early pays off exponentially There are many situations and circumstances when it makes good sense to pursue energy efficiency for industrial processes. But when is the best time for such action? Better operating practices. In existing facilities, improved operating disciplines and procedures often lead to significant energy savings without capital investment. Identifying realtime key performance indicators and optimizers can increase savings. Making data more accessible to operators and engineers through energy “dashboards” can reinforce better operating conditions and make them more sustainable. Dedicated maintenance and energy “housekeeping” have a demonstrated track record of energy savings. Key areas to focus on include fixing steam leaks and monitoring steam traps, as well as repairing insulation and cleaning heat exchangers. Revamps. Often, revamp projects are undertaken to increase

energy efficiency through improved heat integration, steam/ power system balancing, equipment upgrades, and, sometimes, fundamental process changes. However, even though the economics can be attractive, these projects are inherently difficult to justify and to implement because they require working within the confines of existing process unit and equipment. Furthermore, when replacing a piece of equipment with an “upgrade,” you typically pay full price for the new item while only gaining the incremental benefit between it and the old equipment. Optimized energy efficiency. The best economics for energy-efficient processes and equipment occur in new plant designs and major plant expansions. There are many different areas where energy efficiency can be “baked in” during various design stages of new facilities. Basic technology selection. Early in design, the key issue is technology selection. Often, there are several competing technologies that can be used to achieve the required process objectives, such as material transformations and separations. Many factors must be considered. Due to the multi-dimensional nature of the selection parameters, the most energy-efficient option may not always be the top choice. Energy should always be a serious consideration in the selection procedure. Beyond basic technology selection, there are many additional design decisions that affect the energy performance, such as: Heat integration. It is often possible to recover additional energy from “waste-heat” sources without fundamentally changing the underlying process technology. Pinch analysis is a good technique used to identify such opportunities.

Equipment selection. Pumps, compressors, turbines, motors and other mechanical equipment can vary greatly in efficiency. It is often beneficial to invest a little more in high-efficiency machines to lower energy costs. Process and utility interfaces. Individual process designs are very well optimized by contractors. However, material and energy are transferred between process units and utility systems, and the interconnections can vary. There are invariably opportunities to fine-tune the design. For example, this can include incorporating options for hot and/or cold transfer of materials from one process to another, adding steam turbines, generating steam from surplus heat, and changing steam header pressures. Control. A great deal of energy is consumed in process control—for example, in throttling or recycling the discharge flow from pumps. Alternative control options, including variable frequency drive control, should be considered during design. In addition, excess air control of boilers and furnaces using stack gas oxygen and carbon monoxide measurements should be incorporated in new designs where appropriate. These measures can greatly improve overall equipment efficiencies and minimize environmental impact. Maintenance facilities. Various maintenance activities are important for sustaining energy efficiency over the service life of a project. Examples include provision of bypass piping and valves to allow onstream cleaning of key heat exchangers, along with washing facilities for turbines and compressors, and cleaning facilities for boilers and furnaces. Process design is a complex combination of science and art. Energy efficiency must never be handled in isolation from other design considerations. However, when properly managed, an energy efficiency assessment of the design for a new facility or for major expansions can lead to significant energy savings over the service life of the project and, consequently, provide an excellent return on investment. EDITOR’S NOTE Editorial is based on Dr. Rossiter’s book, Energy Management and Efficiency for the Process Industry, published by AIChE/Wiley partnership, April 2015. ALAN P. ROSSITER, PhD, PE, is president of Rossiter & Associates, a consulting company based in Bellaire, Texas, which provides consulting services on energy efficiency for the oil refining and chemical industries. Dr. Rossiter holds BA and MEng degrees as well as a PhD in chemical engineering, from the University of Cambridge. He has more than 30 years of experience in process engineering and management. Dr. Rossiter is a chartered engineer (UK) and a registered professional engineer in the state of Texas. He is a past chair of the South Texas Section of AIChE. Hydrocarbon Processing | MARCH 201521

Select 59 at www.HydrocarbonProcessing.com/RS

Global

JOHN GALANTE, LEAD ANALYST FOR LATIN AMERICA ESAI Energy

Latin America’s refinery product demand is decelerating

Super-cycle growth. During the past decade through 2013,

demand for refined products in Latin America and the Caribbean grew precipitously. The so-called super-cycle in global commodities markets and an expansion of the middle class and consumer credit led regional oil demand to rise by 2.6%/ yr or 2.1 MMbpd, despite a global recession. At the same time, throughput fell by 300 Mbpd. A number of refineries in the Caribbean closed, while utilization rates dropped in some of the region’s oldest refining sectors. The net result was the emergence of a roughly 1.5-MMbpd shortfall of primary refined petroleum products (not including a fuel oil surplus), according to ESAI Energy estimates. Because of this deficit, Latin America and the Caribbean emerged as a key region in determining trade and pricing dynamics in the Atlantic Basin. The region also became a vital outlet for refined-product exporters, especially from the US Gulf Coast, but also from Europe and Asia. The jump in product spreads following the late-2012 fire at Venezuela’s Amuay refinery was a potent illustration of the dependence of product margins and flows on the region’s balances. Deceleration of growth. In 2014, these conditions began to unravel. The region’s total oil demand growth continued to decelerate, to around 100 Mbpd from a peak of 400 Mbpd in 2007. Yet, this slowdown in demand was met by a 110-Mbpd decline in refinery throughput last year. Refineries in Ecuador, Mexico and Trinidad and Tobago saw heavy maintenance shutdowns, and Ecopetrol shuttered its aging 80-Mbpd plant at Cartagena, Colombia, in March 2014. Result: The gasoline deficit in Latin America and the Caribbean increased by 50 Mbpd to 710 Mbpd last year. ESAI Energy estimates that, while the diesel shortfall climbed 70 Mbpd to 690 Mbpd, jet fuel and LPG deficits each grew by 20 Mbpd. From 2015 to 2020, the trajectory of these deficits will change. Conditions will vary considerably across countries and

across products.1 Broadly speaking, however, a less-robust demand outlook, combined with upcoming additions to throughput, means that product deficits will level off in many cases, and even narrow in some markets, through the end of the decade.1 Capacity additions. Year-on-year changes in product supply are set to turn positive as downstream investment produces throughput gains of 900 Mbpd between 2014 and 2020. Crude processing will grow despite a host of greenfield projects being delayed indefinitely. Petrobras’ 230-Mbpd RNEST refinery at Abreu e Lima should be fully operational by year’s end, while Ecopetrol’s new and highly sophisticated 165-Mbpd Reficar plant in Cartagena should launch by mid2015. Petroecuador will complete its year-long revamp of the 110-Mbpd Esmeraldas refinery around the same time, while Mexican and Trinidadian throughput will not see the same maintenance-related yearly declines this year. Further out, the 165-Mbpd first phase of Petrobras’ Comperj refinery in Rio de Janeiro should be completed by 2019. In a number of refining sectors around Latin America and the Caribbean, operators are investing in expansion, revamp and upgrading projects in place of new greenfield refinery construction. Investments are planned or underway at Pemex’s Salamanca and Tula refineries, Petroperu’s Talara refinery, Ecopetrol’s Barrancabermeja refinery and Bridas Corp’s Campana refinery, among others. In some cases, these upgrades will also incorporate adjustments in diesel and gasoline sulfur specifications in their respective countries. “Tipping the scale” includes balances divided by sulfur specifications. At the same time that some long-delayed downstream investments in Latin America and the Caribbean will finally produce results, total oil demand growth should be more 2.1 1.9 Refined product deficits, %

The trajectory of refined product balances in Latin America and the Caribbean is changing. With demand growth slowing and throughput expected to rise by 2020, the region’s combined deficits for primary petroleum products, led by gasoline and diesel, will not continue to expand in the same manner as in the past decade. This matters not only for economies in the region that are dependent on refined product imports, but also for market fundamentals and prices in the Americas, the Atlantic Basin and beyond. ESAI Energy’s recent study, “Tipping the Scale,” investigates the country-level and region-wide forecast of regional product balances through 2020.1

39.7

39.4

40

36.8

34.9

31.6

1.7 1.5 1.3 1.1

0.9 0.7 0.5 2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

2020

FIG. 1. Refined product demand in Latin America and the Caribbean: 2010–2020. Products include diesel, gasoline, jet fuel, LPG and naphtha. Hydrocarbon Processing | MARCH 201523

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Global 100 80 Total diesel deficit, %

moderate through 2020, ESAI Energy believes. Growth should recover from the 1% posted in 2014, but it will only average 1.9% in the second half of the decade. Macroeconomic imbalances in a number of the region’s major economies will be difficult to resolve, especially as global commodity markets fail to return to recent rates of growth. There will, of course, be significant variation among countries. Forecast. The outlook for product balances will similarly

vary, but deficits should moderate or narrow, especially in the near term with the completion of announced new plants and upgrading projects. Among products, the greatest changes will occur in the diesel market because new refineries and deepconversion units will favor additional output of middle distillates. Among sub-regions, the Pacific coast of South America will add the least refining capacity, and deficits will increase. The combination of these trends is visible in FIG. 2, which illustrates how the “Pacific South America” region should increase its share of the entire region’s diesel shortfall to 40% in 2020 from 26% last year. The refined product shortfalls in Latin America and the Caribbean are not disappearing. Instead, they are changing and not growing as they have in recent years. Trade flows and benchmark product margins will have to adjust to a new reality in this market that has absorbed much of the excess products in the Atlantic Basin during the past decade—and so will product exporters, who have come to rely on these deficits.

16 26

60 40 20

34 25

19

13

35

40

22

25

24

22

0 2014 2015 Caribbean Basin

2016 2017 Atlantic South America

2018 2019 Pacific South America

2020 Mexico

Caribbean Basin: Caribbean Islands, Central America, Colombia and Venezuela Atlantic South America: Argentina, Brazil, Paraguay and Uruguay Pacific South America: Bolivia, Chile, Ecuador and Peru

FIG. 2. Sub-region percentages of total diesel deficit, 2014–2020.

1

NOTE ESAI Energy’s recent study, “Tipping the Scale,” provides a detailed, country-level and region-wide forecast of regional product balances through 2020.

Select 151 at www.HydrocarbonProcessing.com/RS

JOHN GALANTE is ESAI Energy’s lead analyst for Latin America and the Caribbean and for the global gasoline market. He manages ESAI Energy’s data collection and forecasting for Latin America and the Caribbean, and publishes the firm’s monthly Latin America Watch publication. He also forecasts US demand for gasoline and leads ESAI Energy’s global analysis for that market. Mr. Galante previously worked as a markets reporter at Energy Intelligence Group.

Hydrocarbon Processing | MARCH 201525

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Petrochemicals

BEN DUBOSE, ONLINE EDITOR [email protected]

Fatal DuPont leak shows need for improved chemical safety systems The November 15 chemical leak at DuPont’s plant in La Porte, Texas was the company’s third fatal US accident in five years and the deadliest of them all. The blast took the lives of four workers, including two brothers. According to US Chemical Safety Board (CSB) investigators probing the case, it appears to have been preventable. “We have found that not only DuPont, but the industry as a whole, must do much better,” said Rafael Moure-Eraso, chairperson of the CSB. “Complex process-related accidents with tragic results are taking place across the country at companies of all sizes,” he said. “This problem includes major corporations such as DuPont, not just smaller companies that some refer to as ‘outliers.’ It is clear that the current process safety regulatory system is in need of reform, and that companies themselves must do more.” The La Porte case follows two other fatal accidents in 2010 at DuPont facilities in Belle, West Virginia and Buffalo, New York. “The frequency of these incidents is a concern for the Board as well as for DuPont, its workers, [their] family members and the communities nearby,” Moure-Eraso said. Investigation findings. In the most recent case, the board

found that a ventilation system at the La Porte plant (FIG. 1) had been broken, allowing methyl mercaptan to build up undetected. When the chemical mixed with the air, it became a toxic gas. Four workers were killed during the release of what DuPont estimates to be more than 23,000 pounds of methyl mercaptan. Investigators have already identified four design issues. First, the process included several interconnections between the methyl mercaptan supply line and a chemical ventilation system, which allowed a toxic leak to occur in an unexpected location where workers were exposed. Second, the chemical vent system, which was intended to safely remove harmful vapor from process vessels, had a design shortcoming that allowed liquid to accumulate. This liquid buildup regularly caused pressure buildups in the vent. The liquid needed to be manually drained by operators to prevent safety issues from interconnected equipment, such as reactors. Third, the vent drain that operators were required to use was open to the atmosphere, meaning that workers were exposed to any chemicals drained from the vent system. Fourth, the building was designed in such a way that, even if ventilation fans had been working on the day of the accident, they likely would not have effectively protected workers from chemical exposure. “We found that those ventilation fans were not, in fact, working at the time of the accident,” Moure-Eraso said.

DuPont stresses safety commitment. DuPont said in a

statement that safety has been a value of the company and a constant priority since its founding. “We first implemented safety rules in 1811, and we have been engaged in a continuous process to improve ever since,” the company said. “We are responding to this tragedy in a way that reinforces our absolute focus on safety and enables us to learn from it. We have an expert team leading an intensive effort to understand exactly what happened, and how we can ensure that it never happens again.” DuPont added that it remains committed to working with the CSB and the Occupational Health and Safety Administration, in their investigations, noting that the results from those reviews will guide actions going forward. CSB representatives visited the La Porte plant, which opened in 1956, in early February and commended the company for its attitude. “I was encouraged by DuPont’s commitment, which was restated to me, to thoroughly investigate this tragedy, to learn from it and to make all needed changes,” Moure-Eraso said. The CSB says it has conducted about 50 interviews and has spent hundreds of hours reviewing documents and evaluating the incident scene. The field phase of the investigation is roughly 50% complete, with further testing of field equipment and verification of critical instrumentation planned in coming months. Conclusions for industry. Nonetheless, from what it knows thus far, the CSB believes the La Porte case is neither an outlier nor a DuPont-specific problem. Rather, it is a symptom of a larger industry issue that must soon be corrected. “This accident, like many investigated by the CSB, demonstrates that regulators and companies should place greater emphasis on making designs as safe and possible and updating them on a constant basis,” Moure-Eraso said. “I believe that there will be many important and valuable lessons learned that will benefit local citizens, regulators, and the chemical community.”

FIG. 1. The CSB is investigating DuPont’s plant in La Porte, Texas. Hydrocarbon Processing | MARCH 201527

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Engineering Case Histories

A. SOFRONAS, CONSULTING ENGINEER http://mechanicalengineeringhelp.com

Case 83: What are useful questions to ask before starting a vibration analysis? Periodically, this author receives questions from readers throughout the world addressing what performance issues could be wrong with a centrifugal compressor that is vibrating. Note: It is impossible to accurately diagnose problems remotely from the compression system; a specialist doing an onsite review is highly recommended. For newer industry equipment engineers, here are some useful guidelines to follow when preparing for an onsite investigation:1 1. Are you sure that the machine vibration is excessive? How do you know (quantify) what is excessive for this compressor? Baseline data on what is normal vibration for the machine is always a useful tool. Do not use vibration limits tighter than the industry standards. Also, verify that the monitoring instrumentation in use is functioning correctly. 2. Was there always a problem with the machine before the downtime? If it was present since installation, then it may be a basic system problem such as a resonance issue, poor balance, an installation problem or selection of the wrong equipment for the present processing service. 3. Did the problem start after a downtime, and, if so, what was done to the machine during the downtime? For example, was a new rotor element installed? You can eliminate some possibilities if the original system was running well. Also, investigate if the vibration monitoring equipment was modified or if this machine was realigned. These could be root causes for the new vibration issues. 4. Was there some process event that could have caused the vibration problems? Events such as power outages, operational

changes and prolonged surging in centrifugal and axial compressors can result in rotor or seal problems, gear damage and bearing distress. 5. Were process/operating conditions changed such as gas properties, power, speeds, temperatures or pressures? Note: Compressors could be operating in a region where surges or other phenomena are possible and are outside the original design scope. 6. Has the system been modified? Were new piping or vessels added or removed from the system? New equipment can add thermal pipe strain and misalignment; both could increase the vibration of the machine. For example, a case was investigated in which system flow resistance was unexpectedly added; it brought the compressor into an unstable surging range on the operating curve. In another system, dry-gas seals were installed in a centrifugal compressor to replace the oil seals. The rotor developed vibration issues because of the loss of extra oil damping provided by the original seals. 7. With gearbox unit vibration problems, have all the gear mesh frequencies been calculated so they can be compared to the spectrum analysis? For compact high-hp planetary gear or multi-shaft units, this can be complicated. Bearing defect calculations depend on the shaft speed and must be known. Comparing the spectrum analysis data with the mesh frequencies may not always produce the correct answer unless the time domain is also reviewed. Note:

Know your limitations and use consultants who are specialized and knowledgeable with these machine problems. 8. Get training on the vibration monitoring device that you are using. Some new handheld units can provide more information than older instrumentation. However, if you do not understand what the device is telling you or how to use it, then you may be losing key data. Early intervention will usually pay for itself, especially when a failure can be predicted and a unit teardown is avoided. 9. Document everything! Similar vibration problems tend to reappear. They usually are not identical, but they are close enough so that historical data are useful. 10. Be familiar with the machinery operating in your facility. Physically monitor critical equipment daily. Unusual noises can be early signs of serious problems. Talk often with the experienced operators on the unit; they will notice abnormalities before you do. NOTE Case 82 was published in HP in December 2014. For past cases, please visit HydrocarbonProcessing.com. 1

LITERATURE CITED Sofronas, A., Case Histories in Vibration Analysis and Metal Fatigue, pp. 12,152, John Wiley & Sons, 2012.

TONY SOFRONAS, D. Eng, P.E., was worldwide lead mechanical engineer for ExxonMobil Chemicals before retiring. He now owns Engineered Products, which provides consulting and engineering seminars on machinery and pressure vessels. Dr. Sofronas has authored two engineering books and numerous technical articles on analytical methods. Hydrocarbon Processing | MARCH 201529

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Boxscore Construction Analysis

LEE NICHOLS, DIRECTOR, DATA DIVISION [email protected]

How low oil prices are affecting new project announcements

180 160 140 120 100 80 60 40 20 0

120 WTI Brent

100 80 60 40 20 0 July-14

August-14 September-14 October-14 November-14 December-14 January-15

FIG. 2. WTI and Brent crude oil prices, July 2014–January 2015.

Jan-15 2012 2013 2014

Africa

Asia-Pacific

Global new project announcements, July 2014–January 2015

Total new project announcements by region, 2012–2014

Recent project growth. The US was not the only region experiencing tremendous growth over the past three years. All regions have announced major expansions, upgrades, plant restarts and new grassroots facilities. These announcements included new clean fuels projects in countries such as Saudi Arabia, South Africa and Russia; dozens of LNG projects in Africa, Asia-Pacific (AP) and North America (NA); and a surge in new petrochemical investments in China, the Middle East and the US Gulf Coast. The US petrochemical sector is in the midst of one of the largest industry expansions to occur in NA. Total capital investments have climbed to well over $100 B. These investments include a sharp increase in the construction of ethylene cracking and derivatives capacity, methanol and ammonia-urea plants, and propane dehydrogenation (PDH) units. However, beginning in July 2014, the world began to witness a widespread fall in crude oil prices. By the end of January 2015, both West Texas Intermediate (WTI) and Brent crude oil prices had fallen from around $106/bbl to $45/ bbl and $47/bbl, respectively (FIG. 2). With the decrease in global crude oil prices, what has this meant for new project announcements in the downstream sector?

Mega-investments in US and AP. Since July 2014, new project announcements have averaged nearly 25/month globally. As shown in FIG. 3, new project announcements spiked in October 2014 and gradually decreased through the end of January 2015. The US continued to dominate new project market share over the past six months (FIG. 4). The US shale gas boom has continued to add capital investments in the gas processing and petrochemical sectors. These investments include projects such as cryogenic gas processing plants, nitrogen fertilizer complexes and methanol production units. The US also increased new project market share from 31% in July 2014 to 38% at the end of January. The only other region with significant new project market share growth is AP. Announced projects include new petrochemical capacity in China; continued developments in the LNG sectors of Australia, India, Malaysia and Singapore; possible large investments in Indonesia’s refining sector; and multiple refining and petrochemical projects in Vietnam that WTI and Brent crude oil prices, July 2014–January 2015

In Hydrocarbon Processing’s December 2014 Boxscore Construction Analysis article, “2014 global construction year in review,” it was stated that new project announcements climbed to over 500 in 2014. This number represented a 72% increase in new project announcements over the previous year. FIG. 1 shows a Boxscore Database trends analysis on new project announcements from 2012–2014. The US showed significant growth, mainly due to the shale boom that has brought about a surge in new project investments along the downstream construction train.

Canada

Europe Latin America Middle East

US

Dec-14 Nov-14 Oct-14 Sep-14 Aug-14 Jul-14 0

FIG. 1. Total new project announcements by region, 2012–2014. Note: European project totals include projects in Russia and the CIS.

5

10

15

20

25

30

35

40

45

FIG. 3. Global new project announcements, July 2014–January 2015. Hydrocarbon Processing | MARCH 201531

Boxscore Construction Analysis could potentially transform the country into a net exporter of refined fuels. Looking forward. What do low oil prices mean for the future

of downstream projects? Which areas might see success in 2015 and beyond? There are multiple answers to both questions, to be explored in detail in upcoming Boxscore Construction Analysis articles. Refiners saw large revenues during the global crude oil price drop, as pump prices fell much more slowly than the 5%

22%

38%

7%

8%

Africa Asia-Pacific Canada Europe Latin America Middle East United States

14% 6%

FIG. 4. New project market share by region, July 2014–January 2015. Note: European market share includes projects in Russia and the CIS.

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price of oil. For integrated companies, downstream refining operations provided somewhat of a cushion to offset hits to upstream revenues. Global refiners should see lower margins through the first half of 2015 with stabilizing crude oil prices, lower oil demand growth, high inventories and refining capacity additions. However, low fuel prices tend to encourage higher consumption, which some nations hope will eat up excess supplies. Low oil prices will likely have a negative effect on the US LNG export industry. LNG export markets are tied to oil indexing, and, with crude oil prices decreasing by 50% over the past few months, the US Henry Hub market is losing its price advantage. This not only minimizes projected LNG export revenues, but it also makes financing capital-intensive LNG facilities more difficult. The projects that can secure, or that have already secured, supply contracts are more likely to move forward, including projects up for final investment decisions (FIDs) in 2015, such as Cheniere’s Corpus Christi LNG project. The US also has to contend with additional LNG supplies coming online from Australia. Multiple Australian LNG terminals are scheduled to begin exports in 2015. Additional LNG projects are moving ahead. These projects include multiple Asian LNG projects in countries such as China, India, Malaysia, Indonesia, Singapore and the Philippines. ExxonMobil recently announced the addition of a third LNG train at its PNG LNG facility in Papua New Guinea. However, India may be the brightest spot for future Asian LNG demand, since the country’s natural gas demand is expected to triple by 2018. Demand from gas-consuming industries, such as power and fertilizer, is rising steadily. India is expanding domestic LNG import capacity at a rapid rate. Other factors could hamper Asian LNG demand by 2020. These factors include the construction of Russian natural gas pipelines to supply a portion of Chinese natural gas demand, China’s potential development of its shale gas reserves, and the restart of some of Japan’s nuclear reactors. Europe will see France’s Dunkirk LNG and Poland’s Swinoujscie LNG import terminals come online this year. The region has also announced multiple LNG import terminal projects to reduce its dependency on Russian gas supplies. Canada is working to become a major LNG exporter as well, but hurdles stand in the way. Petronas delayed an FID on its Pacific NorthWest LNG project, but the terminal has a high likelihood of being greenlighted. Meanwhile, Chevron found a new partner in Woodside for its Kitimat LNG project. Chevron has delayed a FID until at least 2016, but will continue FEED work. Additional project information on the global refining, petrochemical and gas processing/LNG industries will be detailed in upcoming segments. Each region and sector is responding differently to the drop in oil prices; some responses are positive and some are negative. At present, Hydrocarbon Processing’s Boxscore Construction Database shows that active downstream projects have surged over the past few years. Whether these projects will come to fruition, and what regions are doing to react to the global downfall in crude oil prices, will be a constant theme in the downstream market.

This water wash injector uses an offset flange and a WhirlJet® hollow cone nozzle. A CFD study determined that this design provides the best coverage without heavy wall impingement.

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| Special Report CORROSION CONTROL Corrosion-related damage of steel plant equipment is accelerated by several factors, such as high temperatures, erosive fluids, acidic/caustic conditions and others. All of these conditions are found in HPI facilities. Aging process equipment is vulnerable to corrosion attacks unless preventive and maintenance measures are applied on a regular basis. This month’s special report investigates methods to mitigate corrosion attacks on process equipment and infrastructure. The centrifugal compressor rotor is coated with Elliott’s Pos-e-Coat Plus, a premium coating that provides anti-fouling and corrosion resistance in hydrocarbon processing and gas processing applications. Photo courtesy of Elliott Group.

Special Report

Corrosion Control E. AL-ZAHRANI, A. AL-MESHARI and M. MAITY, SABIC Technology Center, Jubail, Saudi Arabia

How caustic stress leads to failures of incinerator caustic spray nozzles the microstructure of the sample in the etched condition (FIG. 7). X-ray fluorescence (XRF) and carbon sulfur (C/S) analyses were conducted to confirm the composition of the damaged samples. The results show that the nozzle samples match the typical composition of austenitic SS grade 310 (TABLE 1).

The primary function of incinerators is to burn hazardous materials, such as contaminated products, out of specification products and wastes. In this case study, a detailed investigation was conducted into frequent, premature failures of spent caustic [i.e., sodium hydroxide (NaOH)] spray nozzles in an incinerator. The operating temperature of the spent caustic incinerator is approximately 980°C. The incinerator is downfired, internally refractory lined and externally water jacketed. The wastes (mainly caustic) are atomized and sprayed from the incinerator upper cone through nozzles fabricated from austenitic stainless steel (SS) grade 310 (FIG. 1). Frequent failures of the waste spray nozzles resulted in accelerated degradation of the refractory lining, requiring unscheduled shutdowns for repairs (FIG. 1). This study was carried out to identify the factors that contributed to the nozzle failure and to prevent the reoccurrence of similar failures in the future. The two nozzle samples investigated are referred to as Nozzle A and Nozzle B.

The samples were then etched by oxalic acid to reveal the nozzle material microstructure. Grain growth at the nozzle external surface was observed in the etched microstructure. This growth may indicate that the nozzle was exposed to excessive heating (FIG. 6). Furthermore, transgranular cracks were observed in

Investigation. A visual examination of

FIG. 1. Schematic of the spray nozzle assembly (left) and deteriorated refractory lining around the spray nozzle (right).

the failed nozzles revealed a network of cracks and ruptures (FIG. 2). The nozzles were covered with a whitish deposit. Nozzle A showed more cracks as compared to Nozzle B. The nozzle with less damage (Nozzle B) was selected for the investigation, as it could reveal more evidence concerning the original damage mechanism (FIGS. 3 and 4). An optical microscope examination of prepared metallographic cross-sections showed the presence of branched, transgranular cracks that appear to have initiated from the nozzle external surfaces (FIG. 5).

TABLE 1. Chemical composition of damaged nozzle and typical austenitic SS, as per ASTM A240 type SS 310 Element

C

Al

Si

P

S

V

Cr

Mn

Ni

Nb

Measured content, wt%

0.04

0.01

0.71

0.06

0.01

0.12

24.18

1.15

19.37

0.02

Typical content, wt%

0.08 max.

24–26 2 max.

19–22

1.50 0.045 0.030 max. max. max.

FIG. 2. Damaged nozzles. Hydrocarbon Processing | MARCH 201535

Corrosion Control A scanning electron microscope (SEM), equipped with energy-dispersive X-ray spectroscopy (EDS), was used to further study the cracking mechanism (FIG. 8). The presence of corrosive species, such as NA and S, inside the cracks was confirmed by EDS (TABLE 2). Discussion. The failed nozzles were es-

sentially used to spray spent caustic in the incinerator combustion chamber. Air was also introduced inside the nozzles to atomize the caustic and to help cool the nozzles. The nozzle temperature was supposed to be kept below 150°C during caustic injection. However, during idle conditions (i.e., when the caustic was not being sprayed into the combustion chamber, but the burner was on), the flow of air was kept to control the nozzle temperature at approximately 200°C.

Generally, the burned spent caustic solution contained caustic concentration within the range of 5 wt%–8 wt%, in addition to suspended and dissolved solids. The size of the solids varied, and some were large enough to cause blockage in the nozzles. As a consequence, the caustic/air mixture would not be permitted to pass through the nozzle and be constantly sprayed, which could result in a significantly lower heat transfer rate and overheating of the nozzle. The metallographic examination showed that there was noticeable grain growth at the nozzle’s external surface, which indicated that the nozzle was exposed to temperatures as high as 1,100°C (FIG. 6). Since the overall operating temperature of the incinerator is approximately 980°C, the temperature of the conical area in the combustion chamber—where

TABLE 2. Corrosive elements in scales found in the cracks Element Content in A1 area shown in Fig. 8, wt%

C

O

Na

Si

S

Cr

Mn

Fe

Ni

22.35

32.46

1.93

0.22

0.85

12.23

0.74

23.46

5.48

the caustic spray nozzles are placed— would be slightly higher, as it is close to the burner flame. Practically speaking, the expected temperature of the conical area is in the range of 1,100°C–1,150°C. Therefore, it is anticipated that the nozzles would be exposed to high temperature (1,100°C) whenever the cooling system is not working effectively. Handling spent caustic soda solutions should not result in a catastrophic failure, as long as adequate materials are selected.1 For instance, when the caustic concentration is as high as 50% and the temperature does not exceed 90°C, low-carbon steel is the most suitable material for handling caustic solutions in many industrial applications, mainly due to its low cost and resistance to corrosion.2, 3 However, austenitic SS and/or high-nickel (Ni) alloys are the preferred materials for caustic-containing environments when the caustic temperature reaches moderate levels at concentrations of 50% or less.3, 4 The corrosion resistance of austenitic SS in a caustic-containing environment is relatively dependent on the Ni content. Due to the higher Ni percentage in SS type 310 (TABLE 1), it is the preferred

FIG. 4. Locations of cross-section samples prepared from Nozzle B.2 FIG. 3. Nozzle B after cutting.

FIG. 5. Micrographs showing crack morphology in polished condition.

36MARCH 2015 | HydrocarbonProcessing.com

FIG. 6. Grain growth at the nozzle’s external surface, etched by oxalic acid.

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Corrosion Control austenitic SS grade for handling caustic solutions.1 However, austenitic SS is not completely immune to caustic stress corrosion cracking (SCC), particularly when exposed to high caustic concentration at high temperature. In this case, austenitic SS 310 is a suitable material for such caustic concentrations (5 wt%–8 wt%) and temperature (200°C). In contrast, as soon as the nozzle temperature exceeds a temperature (approximately 210°C) with the same caustic concentration, austenitic SS becomes susceptible to caustic SCC (FIG. 9). The morphology of the cracks investigated resembled caustic-induced cracks, which are generally transgranular in austenitic SS. However, indication of intergranular caustic-induced cracking in austenitic SS has also been reported in literature. Therefore, identifying the mecha-

nism of intergranular cracking that occurs in environments bearing both chlorides and caustic would be difficult, as chloride SCC has a similar appearance.3 Transgranular, branching cracking observed by metallography and high Na concentrations detected at the cracks on the spent caustic nozzle indicated the occurrence of caustic SCC. It is believed that the nozzle temperature increased as a result of interrupted caustic/air flow. This temperature increase, in turn, led to the onset of the caustic cracking. The caustic/air flow could be interrupted due to blockage of the nozzle or a malfunction in the air supply. Takeaway. The failure of the spent caus-

tic nozzle is attributed to caustic stress corrosion cracking. The cracking was accelerated by overheating caused by caustic/air flow interruption. Effective cooling of the caustic nozzles must be ensured to maintain the temperature well below the caustic SCC region. LITERATURE CITED A. J. Sedricks, Corrosion of Stainless Steels, WileyInterscience, Hoboken, New Jersey, 1996. 2 B. Craig and D. Anderson, Handbook of Corrosion Data, ASM International, 2nd Ed., Novelty, Ohio, 1995. 3 D. R. McIntyre and C. P. Dillon, Guidelines for preventing stress corrosion cracking in the chemical process industries, Materials Technology Institute (MTI), Publication No. 15, St. Louis, Missouri, 1985. 4 M. J. Esmacher, “Stress corrosion cracking of stainless steel components in steam service,” NACE International, March 11–16, 2001. 1

FIG. 7. Photomicrograph indicating transgranular cracking, etched by oxalic acid.

EISSA AL-ZAHRANI is a mechanical engineer who graduated from King Khalid University in 2008. He worked for Saudi Basic Industries Corp. (SABIC) as a failure analysis engineer in the materials and corrosion section for nearly six years. He published and presented several papers at international journals and conferences on failure analysis, corrosion and refractories. At present, he works for Saudi Aramco’s consulting services department as a materials engineer. ABDULAZIZ AL-MESHARI has worked with SABIC since 1999. He runs and supervises failure analysis, life assessment and corrosion control investigations. He has published and presented several papers at regional and international conferences on corrosion, mechanical failure and related topics. Dr. Al-Meshari received his PhD in materials science and metallurgy from the University of Cambridge in the UK in 2008, his MSc degree in corrosion science and engineering from the University of Manchester Institute of Science and Technology in the UK in 2002, and his BSc degree in mechanical engineering from King Fahd University of Petroleum and Minerals in Saudi Arabia in 1999. MANABENDRA MAITY works as a refractory consultant at SABIC’s Manufacturing Center of Excellence. He holds a BTech degree in ceramic engineering from Calcutta University in India, and an MTech degree in ceramic engineering from the Indian Institute of Technology in Varanasi, India. He has more than 20 years of experience in refractory lining design, engineering, installation, quality control, failure analysis and troubleshooting for furnaces and vessels. He started his career in 1994 as a refractories and non-metallics engineer at Engineers India Ltd. (EIL). Following his leave from EIL in 2007, he spent two years at the Ciria division of Thermal Ceramics.

315 Stress cracking zone boundary 260

A

Temperature, °C

204 200

Stress cracking zone

Atmospheric boiling point 149

93

38 Melting point 0

FIG. 8. SEM/EDX analysis of scales found inside cracks, wt%.

38MARCH 2015 | HydrocarbonProcessing.com

0

10

20

40

NaOH, wt%

60

80

FIG. 9. Cracking resistance of austenitic SS in a NaOH solution.3 Note: “A” is an approximate value of 10 wt% NaOH and 200°C, whereas the actual value is 5 wt%–8 wt% NaOH and 200°C.

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Special Report

Corrosion Control E. PEREA, Sandvik Materials Technology, Singapore

Extend heat exchanger lifecycle with hyper-duplex stainless steel As much as 50% of scheduled or unscheduled shutdowns in process plants is attributed to unavoidable repairs necessitated by corrosion damage in tubes, pipes and associated equipment. Although certain material problems can be ascribed to other factors, the effects of corrosion remain a substantial concern for refineries around the world and cause significant increases in operational and maintenance costs. Intensifying performance demands. High demands are

being placed on tubes in heat exchanger equipment that is used to recover heat from hot gas streams and transfer it to water or oils in refinery processes. Since such processes are dependent on the efficient transfer of heat from one medium to another, heat exchangers are at the forefront of refineries’ economical and environmentally compliant processes. It is established1 that duplex stainless steel (SS) has been traditionally regarded as the most reliable material in heat exchangers. Use of duplex SS is shown to distinctly reduce the types of equipment failure caused by corrosion that are otherwise evident in a range of materials, such as copper-based alloys and different types of austenitic SS, while also proving cost effective. Nevertheless, intensifying performance demands in refineries, coupled with the ongoing decline in crude oil quality, require a new and improved duplex SS grade to withstand increasingly tough operating conditions. This need has led to the development of hyper-duplex stainless steels (HDSS). Contaminants in crude oil. To address the greater demands

several common steel grades. Special attention must also be given to the capabilities of materials to withstand corrosion at elevated temperatures of up to 300°C (572°F). Aside from these factors, the main cause of corrosion in refinery applications is the presence of contaminants in highsulfur crude oils. This is an especially pertinent issue, given the wider issues surrounding the decline in crude oil quality. These crude oils contain carbon dioxide (CO2 ); hydrogen sulfide (H2S); sulfur compounds; nitrogen (N) compounds; and inorganic chlorides like sodium chloride (NaCl), magnesium chloride (MgCl2 ) or calcium chloride (CaCl2 ), which affect the corrosion resistance of steels. These non-hydrocarbon compounds and additives build up within process streams and can be the root cause of extensive corrosion problems. Innovations in construction materials. Carbon steel (CS) is the traditional material choice in refinery applications; yet, it is extremely vulnerable to general corrosion, pitting and underdeposit corrosion. FIG. 1 illustrates general pitting and crevice corrosion phenomena, the effects of which have also caused premature equipment failure in austenitic SS. As a replacement for CS and austenitic SS grades, duplex SS materials have exhibited high yield strength properties that are twice those of standard ASTM 316L. With good thermal expansion, weldability and fabrication properties, duplex SS is suited for both new installations and as replacement tubing in CS and austenitic SS. The second generation of N-containing duplex SS, some of which are called super-duplex SS (SDSS), have low C content but high amounts of molybdenum (Mo) and N, and ferrite content H2O + O2 —> OH-

being placed on materials for heat exchangers, a key approach is to select materials that enable equipment to run for longer periods of time, thereby helping refineries achieve major reductions in plant costs. Process flow An in-depth understanding of the reaCorrosion products ClClsons for corrosion on the process side of H O + O —> OHH2O + O2 —> OH2 2 refineries is essential to identify the most effective replacement material suited for Passive layer these higher operating demands. H2O + O2 —> OHe2 Cl Fe + Corrosion phenomena in plants are e + generally caused by different aggressive Fe2+ Cl- H mixtures of chemicals and hydrolysis H+ Fe2+ Cl(the separation of chemical bonds) of H+ organic chlorides. Such processes lead to the formation of hydrochloric acid, FIG. 1. General pitting and crevice corrosion phenomena. which induces corrosion problems for

e-

Cl-

H+ Fe2+ Fe2+ Cl- H+ Cl- Fe2+ H+ Cl-

Cl-

e-

Passive layer Passive layer

Hydrocarbon Processing | MARCH 201541

Corrosion Control that is about 50% or slightly lower. SDSS has been used extensively in chloride-containing environments for more than 30 years.

As much as 50% of shutdowns in process plants is attributed to corrosion damage. Chemical composition of HDSS. Further to these innovations, the chemical composition of HDSS is informed by experiences with duplex grades. The nickel (Ni) content of HDSS can be kept as low as 7% due to the grade’s nominal 0.4% N content, which also stabilizes the austenitic structure. Levels of chromium (Cr), Mo and N are particularly important in HDSS. Combined, these elements reinforce the material’s superior pitting and crevice corrosion resistance in a chloridecontaminated environment. Extensive tests have also shown that HDSS extends material performance beyond existing SDSS grades and traditional 6Mo (i.e., 6% Mo) austenitic SS. Mechanical properties. A combination of high strength and

workability in tubes maintained over long periods of time is crucial to ensure that heat exchangers can exhibit increased lifecycles. This helps refineries to achieve enhanced productivity levels, minimal maintenance disruptions and major reductions in plant costs. Whereas high-strength properties affect the workability of SS, HDSS is designed to maintain high ductility. This propDSS CS AISI 316L 0

5

10

(x10-6)

15

FIG. 2. Typical expansion behavior in duplex SS alongside CS and standard grade AISI 316L.

erty is also greatly beneficial to fabrication procedures, such as bending and expansion, and it aids in more efficient and cost-effective installations. The thermal expansion properties of SS and duplex SS are shown alongside CS and the standard austenitic grade AISI 316L in FIG. 2. The yield strength of HDSS is about 3.5 times higher than 316L. Higher-strength properties also enable substantial reductions in tube wall thickness. This is advantageous given that the typical values in heat exchanger tubes are yield strength Rp0.2 700 MPa and tensile strength 920-1,100 MPa, and this elongation value is above 25% in the quenched annealed condition. Resistance to general corrosion. General corrosion is particularly detrimental to equipment service lifecycles, and it affects standard steel components that are in contact with process solutions. Organic acids—such as formic acids (HCOOH), the reactive group that is the most common type of organic acid—are present in such processes and are often responsible for corrosion attacks characterized by slightly reducing conditions of the acids. FIGS. 3 and 4 show that HDSS is highly resistant to corrosion by organic acids. Therefore, the material maintains resistance in contaminated acid. Pitting and crevice corrosion. Pitting corrosion happens

when corrosion attacks are localized to small areas on the steel surface. These create pitting and, eventually, holes in the metal. Pitting corrosion can be more detrimental to SS components than general corrosion. The phenomenon often remains undetected until severe damage has been caused. The pitting resistant equivalent (PRE) number (PRE = %Cr + 3.3 × %Mo + 16 × %N) is a measurement for ranking the resistance of SS to pitting corrosion. Exact testing procedures are specified in the ASTM G48 standard, which is one of the most severe pitting and crevice corrosion tests applied to SS. The test exposes test specimens to 6% iron(II) chloride (FeCl) solution, also known as ferrous chloride, with and without crevices. Exact testing procedures specified to the ASTM G48 standard have been used to ascertain the resistance of HDSS to corrosion threats and its suitability in given applications. 120

120

Boiling point curve HDSS

100

Temperature, °C

Temperature, °C

Boiling point curve

80

60

0

20

40

HCOOH, wt%

60

80

100

FIG. 3. Isocorrosion diagram in naturally aerated formic acid. The curve represents a corrosion rate of 0.1 mm/yr (4 mpy) in a stagnant test solution.

42MARCH 2015 | HydrocarbonProcessing.com

100

80

60

0

20

40

CH3COOH, wt%

60

80

100

FIG. 4. Isocorrosion diagram in naturally aerated acetic acid. The curve represents a corrosion rate of 0.1 mm/yr (4 mpy) in a stagnant test solution.

Corrosion Control In a modified version of the standard test, ASTM G48A, HDSS was exposed to a 6% FeCl3 solution, while the temperature was increased stepwise by 2.5°C (36.5°F) over a 24-hour period until a corrosion attack was observed. The resulting data, shown in FIG. 5, defines the critical pitting temperature (CPT) of HDSS as 97.5°C (207.5°F). This threshold is a significant improvement on the corresponding 80°C (176°F) CPT of SDSS materials. The corrosion resistance of the HDSS in oxidizing chloride solutions is illustrated by CPT, determined in a “green death” solution (1% FeCl3 + 1% CuCl2 + 11% H2SO4 + 1.2% HCl). The crevice corrosion test was performed in a 6% FeCl3 solution with a crevice specified in the MTI-2 procedure, where an artificial crevice is mounted on the sample with a torque of 0.28 Nm. The values obtained, and a comparison with an SDSS, are given in FIG. 5. All test results show significantly higher values for HDSS than for the SDSS. The chemical balance of HDSS equips the grade with better mechanical and physical properties, along with a minimum pitting resistance equivalent (PRE) value of 48. These characteristics are compared alongside other steel grades in FIG. 6. Extensive tests have shown that, on its introduction, HDSS extended the material performance levels beyond existing SDSS grades and also typical grades like ASTM 316L and ASTM 317L.

low chloride levels in standard austenitic SS, whereas HDSS can overcome this problem with excellent resistance to chloride corrosion and temperatures, as shown in FIG. 7. Laboratory conditions tested HDSS for a period of six weeks with fresh NaCl solution pumped through the chamber throughout the test period. The results illustrated in FIG. 7 confirm that there were no signs of SCC up to 1,000 ppm Cl–/300°C and 10,000 ppm Cl–/250°C, and demonstrate that HDSS offers good resistance to chloride SCC in critical heat exchanger applications in the process industry.

Stress corrosion. As one of the most serious types of corro-

FIG. 5. Critical pitting temperature measured in the modified G48A and “green death” test solutions. The critical crevice corrosion temperature was obtained in testing with a crevice specified in the MTI-2 procedure.

sion in industrial processes, stress corrosion cracking (SCC) can lead to rapid material failure. It usually occurs at relatively

120

Temperature, °C

100

SDSS HDSS

80 60 40 20 0 CPT G48C

CCT MTI-2

CPT green death

EFFICIENCY MATTERS.

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Hydrocarbon Processing | MARCH 201543

Corrosion Control 350,000

50

300,000

Cost savings achieved with HDSS after four years, $

60

PRE value

40 30 20 10 0 Lean duplex SS

Duplex SS

SDSS

HDSS

Temperature, °C

• Autoclave • 100 bar • 8 ppm O2 • Load = proof strength • NaCI solution • 1,000 hr (6 weeks)

150,000 100,000 50,000

-50,000

CS cost

HDSS

Material cost Fabrication Fabrication Fabrication Total cost difference cost CS cost HDSS saving saving

FIG. 8. Cost savings achieved with HDSS after four years.

200

100

0 0.00001

200,000

0

FIG. 6. Comparison of the PRE value of HDSS alongside other grades.

300

250,000

Duplex SS HDSS Austenitic SS Lean duplex SS SDSS AISI 304 and 316 0.001

Cl– concentration, %

0.1

10

FIG. 7. SCC phenomena in HDSS and other SS grades.

as the replacement material due to its pitting and crevice corrosion resistance properties, which are demonstrably superior to SDSS grades. The original heat exchanger in the CS tube was completely revamped with HDSS tubes and then inspected after six months of service. The inspection revealed slight erosion corrosion on the upper tubes, to approximately 10% of the tube wall thickness. No failures were detected. The bundle was cleaned, eddy current and hydro tested, and then the heat exchanger was closed and left to run for four more years. An inspection four years later showed no further erosion corrosion in the HDSS tubes, and they were again cleaned, eddy current and hydro tested, with no failures detected. This result was very positive with regard to corrosion resistance properties, and it also met the German refinery’s target. Cost advantages. HDSS is shown to be successful in helping

Tube installation. With good resistance to chloride-induced

SCC and minimal thermal expansion, HDSS is easier to install and is also very compatible with other alloys during fabrication, bending and expansion. The grade’s low thermal expansion offers significant design and cost advantages in refineries, not only for new equipment but also for the retubing of existing heat exchangers. Case study. An oil refinery in Germany was experiencing

persistent corrosion problems in its heat exchangers, specifically in the overhead condenser unit of its crude distillation column. The existing CS tube was prone to failure after 5–7 months of service and required weekly monitoring due to unexpected shutdowns. Also, twice per year, all processes needed to be shut down to replace the CS tube bundle, which was creating significant production losses, lost revenues and extra costs. An examination of the damage to the existing tube revealed that pitting and under-deposit corrosion were the main causes for the short heat exchanger tube lifetime. The refinery, therefore, required a replacement tube material that could exhibit extended lifecycles, both to solve these issues and to meet the refinery’s standard quadrennial shutdown. HDSS was chosen 44MARCH 2015 | HydrocarbonProcessing.com

achieve major reductions in plant costs, by contributing more consistent and longer-term performance in refinery operating conditions. In the case of the German refinery, inspections found that the replacement HDSS tube bundle had reduced the number of plant shutdowns from eight to one over a four-year period. This equated to cost savings totaling €255,000 ($321,932), as shown in FIG. 8. The findings and analysis herein confirm that HDSS can extend material performance levels beyond existing SDSS grades, thereby reducing maintenance requirements and unplanned shutdowns for more productive and cost-effective operations. 1

LITERATURE CITED E. Perea, “Mitigate heat exchanger corrosion with better construction materials,” Hydrocarbon Processing, December 2013.

EDUARDO PEREA is a metallurgist engineer who graduated in 2004 and started his career at Sandvik as a trainee. After graduation, he took on the role of technical marketer for Sandvik’s tube business in Brazil. He has built his knowledge on customer applications and support for tube material recommendations. In 2008, Mr. Perea moved to Sweden to work as a global technical marketer, and then moved to Singapore in 2011 to work as a regional sales manager for Southeast Asia.

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/LQGH(QJLQHHULQJ1RUWK$PHULFD,QF 3HWURFKHPLFDO%XVLQHVV8QLW :6DP+RXVWRQ3NZ\6RXWK6XLWH+RXVWRQ7;86$3KRQH /(1$VDOHV#OLQGHOHFRPZZZOLQGHXVHQJLQHHULQJFRP Select 90 at www.HydrocarbonProcessing.com/RS

Special Report

Corrosion Control H. YOON, J. NAM and S. KIM, SK Innovation Co. Ltd., Seoul, South Korea

Evaluate the reliability of a reformer heater convection tube Within 30 days of the startup of a catalytic reformer heater, which comprises four radiant cells with one steamgeneration convection section, water leakage was detected from a convection tube. A subsequent investigation led to the shutdown of the fired heater and the opening of the convection section, which revealed a leak in a 3-in.-diameter finned tube in the first-pass coil of the convection tube bundle (FIG. 1). Two damaged areas were visually observed, one at the finned tube and another at the U-bend vertical section (FIG. 2). An elliptical-shaped, 40 mm × 30 mm puncture was noticed on the finned tube at the 4 o’clock position (near the convection side wall), and a similar-size hole was observed near the convection end wall at the U-bend tube. Much debate has arisen about which puncture is the root cause of this failure, since it took place within a very short time. A hydrostatic test and other necessary inspections were carried out during turnaround. Given this scenario, it is uncertain why the particular tube was severely damaged over a short time, while damage on other tubes was barely noticeable. The root cause analysis of the steamgeneration convection tube failure is described here. Such studies are necessary to prevent catastrophic incidents in refineries that could result in significant monetary loss. Also discussed are corrosion assessments and countermeasures, such as a fired heater design guide that includes recommendations from industrial practices, to share lessons learned from the incident. Morphology of damage. Inside the tube, the localized loss in thickness in the form of pits, grooves and horizontal valleys was observed all along the tube. The

loss from corrosion increased in severity closer to the puncture. A slight expansion was measured in the U-bend tube diameter, which is a direct sign of overheating. Also, a severe thermal oxidization of fins near the puncture was observed (FIG. 3). Note: The length of the damaged finned tube is approximately 1.5 m. Probable reasons for failure. The failure of the convection tube may have occurred due to one or a combination of the following reasons: • Incorrect construction material • Mineral content in water • Upsets in operation • Design.

Material of construction. Since the failure occurred at the second-row tube of the first pass in a concentrated spot, the possibility of incorrect construction material was considered: • Metallurgical analysis of the failed tube conformed with ASTM specifications [3-in.-diameter (thickness of 5.49 mm) A106 Grade B steel pipe, as summarized in TABLE 1]. • Mechanical properties, including thickness and hardness, were within specification. • The microstructure of the failed tube cross-section was examined and found to be consistent with anticipated phases, namely ferrite

TABLE 1. Chemical composition of tube material C (max.) A106 Grade B pipe

P S Si Cr Cu Mo Ni V Mn (max.) (max.) (min.) (max.) (max.) (max.) (max.) (max.)

0.30 0.29–1.06 0.035 0.035

0.1

0.4

0.4

0.15

0.018

0.01

Old tube

0.19

0.978

0.014 0.007

0.178 0.034

New tube

0.2

1.011

0.016 0.007

0.199 0.047 0.022

0.4

0.08

0.02 0.003

0.013 0.022 0.003 Side view Intermediate tubesheet

End view Steam

Steam generation section

Boiler feedwater

1

2 Failure spot

Failed tube

FIG. 1. Failed tube location and fired heater configuration. Hydrocarbon Processing | MARCH 201547

Corrosion Control and pearlite. ASTM grain size was in the range of 7–8. As no abnormality was noticed in the finned tube metallurgy and specification, a failure due to incorrect construction material was ruled out. Mineral content in water. Even very small amounts of dissolved minerals in the boiler feedwater (BFW) accumulate to significant solids deposits during operation. The solids should, therefore, be regularly flushed out of the boiler by blowdown. However, depending on the mineral content of the water, these deposits would

FIG. 2. Punctures on the tube.

form hard scales on the water wall tubes, which is sufficient to raise the tube metal temperature beyond safe limits. Liquid stagnation marks were noticed at the bottom of the corrugated tube. Based on a water analysis review of the operating procedures, it was concluded that the chemistry of the feedwater was within the specification, and also that the frequency and interval of blowdown was done in accordance with standard practice. Since there were no problems in the plant’s power boilers and waste heat boilers, which are similar in design to the BFW network, water chemistry as a cause of tube failure was ruled out. Upsets in operation. During startup, it is likely that the intermittent unstable operation could be inevitable prior to the attainment of normal operating conditions. The following operating parameters were investigated to see if they could have led to the tube failure:

FIG. 3. Localized metal loss inside of failed tube.

FIG. 4. Cross-section view and microstructure of failed tube at different sections.

48MARCH 2015 | HydrocarbonProcessing.com

• In the first days of startup, the flowrate of the BFW was kept at approximately one-third of the design flowrate • Simultaneously, the excess oxygen (O2 ) and the draft were kept at 3.5% and high, respectively; no draft records exist for the arch elevation level • The flue gas temperature at stack was kept 20°C higher than the design temperature. Design. The design of fired heaters is complex and also requires good engineering practices. Every heater is custom designed to fulfill the customer’s requirements and specifications. Since codes, such as API standards, normally specify basic requirements, there are significant differences in the detailed designs of each vendor, such as tube layout, structural shape, refractory design and so on. Particular design features were examined to ascertain if they could have led to the convection tube failure: • Tube layout. To achieve better heat transfer, only the finned tube sections are in the convection box, and the bare U-bend tubes are separately contained in the header box. The header box is necessary for better flue gas distribution and allows for more efficient, safer maintenance. There were no header boxes at either side of the end wall; the whole convection tube bundle was contained within the convection box. • Presence of corbels. The corbels are projections of refractory, a type of baffle that reflects a portion of the flue gas over the convection tubes. The corbels are normally required for efficient convective heat transfer. No corbels were present along the convection side wall. Failure analysis. A careful examination of the failed tube section revealed that the failure was the result of rapid acceleration in the tube wall temperature. A step-bystep approach to determine the origin of failure and factors that will prevent the incident from happening again are discussed. First of all, a visual examination of the failed part, as well as hardness testing and a metallurgical examination, were carried out. The 15-m-long failed tube was cut at every 3 m. • The thickness reduction began at the fifth cut section (there was no

Corrosion Control

Heat flux, Btu/hr-ft2

Flowrate, m3/hr

where the convective heat flux is highest. the pressure drop was much lower than in reduction in thickness in sections The reason is that the bare U-bend tubes the finned tube. Without any proper heat 1–4), and puncture holes were found at sections 6 and 8 • Local metal loss was evident in the internal bottom The design of fired heaters is complex and also portions (from the 3 o’clock requires good engineering practices. Every heater position to the 9 o’clock position) is custom designed to fulfill the customer’s • Bulging resulted in an requirements and specifications. approximate 1% increase in tube diameter; this bulging worsened near section 8 • The fins at section 6 were thermally are located in the convection box, and, transfer through the finned tube, the flue therefore, the flue gas flows better through gas temperature at the stack is 20°C higher oxidized bare tubes vs. densely finned tubes. In ad- than in the normal condition. • The microstructure at sections dition to the uneven flue gas distribution, 1–4 is normal A106 Grade B steel What was the metal temperature at there was high draft operation with 3.5% the failed tube? On the basis of micropipe (carbon content of 0.19%); excess O2. In spite of the 10% decrease structural analysis, there is a dramatic meanwhile, there is a dramatic transformation from lamellar pearlite in fired duty, the opening of an induced transformation from lamellar pearlite to to spherodized carbides from draft fan was kept at the same level. Due spherodized carbides from sections 5–8. sections 5–8, as described in FIG. 4. to this excess air operation, more flue gas From the small-volume fraction of the Several key questions needed to be flowed through the bare tube area, where carbides, the metal temperature could be answered to identify the root cause of 3.0 the failure: 2.5 • Why and how was the tube heatdamaged? 2.0 • Why did only the No. 1 pass tube 1.5 Fluid flow vel. XYZ, m/sec fail, while the other tubes remained +1.03489e+000 1.0 0.1% +9.48651e+001 in good condition? 0.8% +8.62401e+001 0.5 7.0% • Why did the second row fail, +7.76169e+001 11.1% 0.0 +6.89928e+001 while the other rows of tubes 9.8% 0 No. 1 No. 6 No. 11 No. 16 +6.03687e+001 9.6% +5.17446e+001 remained in good condition? 9.3% +4.31205e+001 9.4% The BFW system is designed as a +3.44964e+001 9.6% +2.58723e+001 manifold. In a 14-in.-diameter manifold, 9.9% +1.72482e+001 10.0% +8.62410e+002 there are 32 branches (two rows of 16 13.3% +0.00000e+000 branches) of 3-in. tubes that collect at the 18-in. manifold. In evaluating a computational fluid dynamics (CFD) model (FIG. 5), there is a 40% flow difference between a No. 6 tube and a No. 16 tube, es- FIG. 5. Flow distribution at manifold branch, CFD analysis. pecially when the flowrate is low. 106 Since the No. 1 pass tube has a miniNatural convection Nucleate boiling Partial film boiling Film boiling mum flowrate, it should be the most vulnerable to heat damage. The less flow the tube has, the more heat-damaged it should DNB be by the high-temperature flue gas pass105 ing through the convection section. Since the first row consists of bare tubes, their surface area is about one-sixth that of the finned tube. Although the first-row tube is located at the highest heat-temperature104 exposed zone, the second-row tube is Excessive more heat-damaged because it has a larger overheating surface area. This scenario brings up a new set of questions. 103 Why are the punctured holes adja10 100 1,000 10,000 1 cent to the convection side wall? The Temperature difference, °F punctured holes are adjacent to the convection side wall and end wall, respectively, FIG. 6. Excessive overheating; the temperature difference between metal and bulk fluid. Hydrocarbon Processing | MARCH 201549

Corrosion Control TABLE 2. Summary of recommendations Recommendations Operation

The flowrate of the BFW should be kept above the normal operating condition. The excess O2 and draft should be kept at 2% and –0.1 in. wc at minimum and at the arch, respectively.

Design

U-bend tubes should be located at the separated header box. A corbel should be installed along the convection side wall.

Intermediate tubesheet Steam

Steam generation section

BFW Header box

Corbel

FIG. 7. Recommended design improvement showing corbel and header box.

estimated at approximately 650°C from the iron-carbon phase diagram. The buildup of deposits inside the tube will increase when the velocity inside the tube decreases, as not enough deposits will be washed away due to the poor flowrate of the BFW. Once the inside of the tube— which contains mostly feedwater corrosion products—is fouled, the possibility of underdeposit corrosion will increase. The concentrations of corrosive solutions occur at the heat transfer surface as the result of fouling by porous deposits, such as iron oxides. These deposits are typically formed from particles suspended in BFW. Once the corrosive concentration mechanism is started, the additional corrosion products are generated from porous deposits. The steam bubbles grow from the deposits, and the concentration of sodium hydroxide in BFW increases at the tube surface. Sodium hydroxide concentrates at the base of the deposit and leads to the dissolution of the protective oxide layer. This is called “caustic gauging,” and it accelerates at high temperature. Why is the corrosion rate so high (about 5 mm/month)? When the flow of BFW decreases, the bubbles cannot escape as quickly from the heat transfer surface. As the temperature continues to in50MARCH 2015 | HydrocarbonProcessing.com

crease, more bubbles are formed than can be efficiently carried away. The bubbles grow and group together, covering small areas of the heat transfer surface with a film of steam that insulates the surface, making heat transfer more difficult. As the area of the heat transfer surface covered with steam increases and partial film boiling begins, the temperature of the surface increases dramatically. Despite the radiation heat transfer from the metal surface to the liquid through the vapor film, there is no convective heat transfer at the steam film area. Therefore, the temperature of the metal becomes significant at approximately 650°C (see FIG. 6, where the X axis shows the temperature difference between the metal temperature and the bulk fluid temperature), which is almost comparable to the temperature of the flue gas. Caustic gauging accelerates at high temperature. Recommendations. The flowrate of the

BFW should be kept above the normal operating condition. Often, heater operators focus on keeping the outlet temperature of the process at the required conditions, but will sacrifice other parameters, such as steam generation, draft, excess air and fuel firing rate.

During startup, when process conditions tend to fluctuate, the cooling medium should be serviced often enough to protect the tube from overheating. For safety reasons, it is important to first ensure that the heater is operating under negative pressure. However, if there is too much negative pressure, the flue gas will exit directly to the stack without properly transferring heat through the convection tubes. If the heater radiant arch draft is kept at a minimum of –0.1 inch water column (in. wc), then all other sections of the heater should be operating under negative pressure. The U-bend tubes should be located at the separated header box (FIG. 7). The header box is the internally insulated structural compartment, separated from the flue gas stream. If the bare U-bend tubes are inside the convection section, rather than inside the header box, then uneven flue gas distribution will occur. The flue gas will exit through the bare tube zone more easily than it would through the densely finned tube zone. A corbel (FIG. 7) should be installed along the convection side wall. To have proper heat transfer in convective heat, the convection tubes are designed in a staggered layout. A corbel is required at the convection side wall to act as a staggered layout dummy tube, which enables proper convective heat transfer to the convection tubes adjacent to the convection side wall (TABLE 2). HYUNJIN YOON is a master engineer of fired equipment at SK Innovation. He received an MS degree in material science and engineering from Stanford University in Palo Alto, California. He has over 27 years of petrochemical industry experience, including wide experience in fired heater design, troubleshooting, reliability assessment and maintenance. Mr. Yoon is credited with major roles and involvement in the development of specifications and various maintenance procedures for stationary equipment. JINGAK NAM is a senior corrosion engineer at SK Innovation. He earned his PhD in corrosion engineering from Florida Atlantic University in Boca Raton, Florida. Since receiving his degree, Dr. Nam has worked in the refinery and petrochemical business as a corrosion engineer and metallurgist. SUNIL KIM is a senior mechanical engineer at SK Innovation. He has been working with combustion equipment in refinery and petrochemical applications for 14 years.

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Plant Design B. K. SHARMA, Fluor Daniel India, Haryana, India

Determine the design metal temperature for a secondary reformer In a recent case study, a secondary reformer (FIG. 1) at an ammonia plant using an air-burning facility was registering an inside temperature of 1,373°C, which is on the high side. An air-burning system should be designed so that there is no maintenance required between scheduled shutdowns every two years. To achieve this, a metal temperature study should be carried out for the design of the pressure parts and for the refractory design. Secondary reformers play an important role in the production of ammonia. The goal of reforming is to prepare as pure as possible a gas mixture of nitrogen (N) and hydrogen in a 3:1 stoichiometric ratio from the raw materials of water, air and natural gas. Secondary reformers reduce methane slip to a very low level and, in ammonia plants, provide feedpoint for the N required for ammonia synthesis. They also generate heat for the waste heat boiler. Choosing the proper design temperature for the pressure equipment inside the reformer is also critical for the mechanical design of the unit. The main material used in construction is carbon steel (CS). The secondary reformer is internally lined with dense castable refractory, and it is water jacketed on the outside to maintain the uniform design temperature at the surface of the pressure parts. Outlined here is an approach used to determine and verify the design metal temperature used for designing the pressure parts of a secondary reformer, under the maximum allowable continuous operating gas temperature. Basic assumptions for the study include: • A calculation has been performed to assess the heat transfer from

a multilayer cylindrical wall through conduction, as well as the convection from the CS surface to water through the water jacket. • Water temperature is kept constant throughout the water jacket, at 110°C, by circulating the water with adequate velocity. • The thermal conductivity of CS is taken from ASME Section 2, Part D, while the thermal conductivity of refractory material is confirmed by the refractory vendor. The convective film coefficient of the water has been assumed.

The refractory vendor ensures the value of thermal conductivity for the refractory (i.e., high-alumina castable), which is used to determine the metal temperature. The temperature should not go beyond the value used in the calculation. The value of thermal conductivity for the refractory has been restricted to determine the desired design metal temperature. When conducting heat through a composite cylindrical wall for a steady-state condition, the heat flow through each layer is the same and can be described by the following set of equations:

Key design features. A design metal

temperature determination study has been performed to verify the desired design metal temperature for the secondary reformer, as per the process conditions generally found in an ammonia plant.

FIG. 1. Diagram of a secondary reformer. Image courtesy of RHI AG.

FIG. 2. Cross-sectional view of secondary reformer section. Image courtesy of SaintGobain SA. Hydrocarbon Processing | MARCH 201553

Plant Design

t1 t2 570-mm ID

(t 2 – t 3 ) (2) log e (r3 ÷ r2 )

Heat transfer through convection, from CS to water inside the water jacket, is shown in Eqs. 5–6:

design metal temperature determination, as shown in FIGS. 2 and 3. By adding Eqs. 3, 4 and 6, the following calculations can be made: ⎧ log e (r2 ÷ r1 ) ⎫ + ⎪ ⎪ K1 ⎪ ⎪ Q ⎪ log e (r3 ÷ r2 ) ⎪ (t1 – t 4 ) = + ⎬ (7) ⎨ K2 2π L ⎪ ⎪ ⎪ 1 ⎪ ⎪ ⎪ ⎩ r3 × h ⎭

Q = h × A × (t3 – t4)

Q=

Q = 2 × π × K2 × L ×

Or: (t1 – t 2 ) =

Q log e (r2 ÷ r1 ) 2 × π × K1 × L

(3)

(t 2 – t 3 ) =

Q log e (r3 ÷ r2 ) 2 × π × K2 × L

(4)

(5)

where: A = 2 × π × r3 × L Q = h × (2 π r3 L) × (t3 – t4)

t3

2,624 mm

t4

1,270-mm OD

(t1 – t 2 ) (1) log e (r2 ÷ r1 )

2,550-mm ID

Q = 2 × π × K1 × L ×

Or: Q (t 3 – t 4 ) = (2 × π × r3 × L) × h

(6)

Secondary reformer examination. A FIG. 3. Dimensions of secondary reformer section.

section with an ID of 1,170 mm, a length of 2,624 mm, and a thickness of 50 mm is examined in a secondary reformer for

=

( t1 – t 4 ) 2 × π × L ⎫ ⎧ log e (r2 ÷ r1 ) + ⎪ ⎪ K1 ⎪ ⎪ ⎬ ⎨ ⎪ log e (r3 ÷ r2 ) + 1 ⎪ ⎪⎩ K2 r3 × h ⎪⎭

(8)

( 1,373 − 110) × 2 × 2.624 × π ⎧ log e (0.585 ÷ 0.285) ⎫ +⎪ ⎪ 34 ⎪ ⎪ ⎪ log e (0.635 ÷ 0.585) ⎪ +⎬ ⎨ 53.38 ⎪ ⎪ ⎪ ⎪ 1 ⎪ 0.635 × 5,000 ⎪ ⎩ ⎭

(9)

Q = 831,302.22 W

DUNN HEAT EXCHANGERS, INC. Dunn’s specialized facility offers complete services for shell and tube type heat exchangers and related process equipment.

24 hours a day. 7 days a week.

The value of Q can then be substituted to determine temperature, t2: (t1 – t 2 ) =

Q log e (r2 ÷ r1 ) 2 × π × K1 × L

(10)

831,302.22 log e (.585 8 .285) (1,373°C – t 2 ) = 31 2.624 2

(1,373°C – t2) = 1,169.65162 t2 = 203.35°C Takeway. The determined metal tem-

REPAIR/RETUBING

CLEANING/BAKE-OUT

NOMENCLATURE Complete nomenclature available online at HydrocarbonProcessing.com.

SAFE TRANSPORT

www.dunnheat.com   s  

54

perature is used as the design temperature for designing the pressure parts in the secondary reformer, under maximum continuous operating gas temperature. It is also used to determine the design pressure and all combined loadings (such as wind and seismic activity).

Select 154 at www.HydrocarbonProcessing.com/RS

BRIJESH KUMAR SHARMA is a mechanical engineer at Fluor Daniel India Pvt. Ltd. He holds a BEng degree from the Sant Longowal Institute of Engineering and Technology in Punjab, India.

Heat Transfer K. MALHOTRA, S&B Engineers and Constructors Ltd., Houston, Texas

Improve the operation of fired heaters

Background. Fired heaters consist of radiant, convection and stack sections. There may be preheating systems (air or other), steam sections for additional heat recovery to increase the efficiency of the heaters, and selective catalytic reduction units or other catalysts for emission reduction. Fans are added to get adequate draft by utilizing an induced draft (ID) fan or pushing air to the burners via a forced draft (FD) fan. Additional ducts are incorporated depending on the application. Refractory installed on the walls and ducts of the heater control heat losses. Radiant section. Primary heat transfer occurs in the radiant section, where the heat is mainly transferred by radiation. About 60% to 70% of the heat energy is recovered in this section. The remaining heat energy is recovered by convection or the combination of both the convection and heat-recovery systems. Practically 90% to 91% efficiency can be achieved from a fired heater, due to stack temperatures reaching close to the sulfur dew point. A minimum approach of 100°F is recommended. FIG. 1 shows the estimated heater efficiency as a function of stack temperature and excess oxygen (O2 ). Horizontal and vertical radiant tube layouts are the most common. Other typical radiant tube layouts include helical and arbor coil layouts. Convection tubes are placed horizontally. Horizontal radiant tube layouts offer self-draining tubes but require a larger footprint (space). Box layouts (horizontal or vertical tubes) are an obvious choice when process duties are large. Vertical cylindrical layouts are preferred when space is an issue and lower heater cost is required. The selection of tube size is typically a function of the process type, process flow and pressure drop available. Selection of tube material and thickness is a function of process type, process conditions, oxi-

dation, corrosion and deposition mechanisms. Process tubes are designed for 100,000-hour life, per API-530 guidelines. Flow imbalance in the process passes should be minimized. This leads to tubes overheating, increased coke formation and heat flux imbalance in the heater. Installing flow transmitters, individual pass-flow controllers on the process inlet passes and temperature transmitters at the outlet passes are required to make necessary flow adjustments to avoid heat flux imbalances. Low flow alarms and trips should be configured. Tube-skins provide valuable information on tube conditions. Main burners. The burners are considered the “heart” of the

fired heaters and where combustion happens. For burner combustion to be complete, more than stoichiometric air is allowed in the burners since perfect mixing between fuel and air is not possible. Excess air (typically about 15% excess air for gas fuels) compensates for the mal-distribution and aids in complete combustion. Excess air also provides a buffer to the changing fuel gas composition and process needs. Some FD burners use 10% design excess air. It is not recommended to operate burners with less than 10% excess air. Increased carbon dioxide (CO2 ) or combustibles in the box are signs of incomplete combustion. For a properly designed heater and burner, the combustion process should complete well before the radiant arch (also referred to as the bridgewall). With the increased demand of lower NOx emissions, use of low or ultra-low NOx burners is increasing. The estimated flame length is about 1.5 ft/MMBtu to 2 ft/MMBtu, and the flame diameter is about 1.5 to 2 times the burner throat diameter (depending on the burner design and spacing utilized). Tight burner spacing promotes flame to flame 1,400 Efficiency 90% Efficiency 85% Efficiency 80%

1,200

Efficiency 75% Efficiency 70% Efficiency 65%

1,000

Stack temperature, °F

Fired heaters or “process furnaces” are used extensively by the refining and petrochemical industries. These heat transfer units generate the much needed process energy through the combustion of fuels, which is transferred to process fluids. The hydrocarbon processing industry (HPI) uses fired heaters in a wide variety of applications with different manufacturing goals. For large process duties, higher process outlet temperatures and specialized processes, fired heaters are the preferred heat transfer equipment. Operating heaters safely is even more important due to the combustion and explosion risks involved. As large consumers of energy, operating heaters efficiently can result in major savings for the plant. Maintaining adequate draft and excess oxygen are high priorities.

800 600 400 200

1

2

3

4

5

6 7 Excess O2 dry, %

8

9

10

11

FIG. 1. Estimated heater efficiency as a function of stack temperature and excess O2. Hydrocarbon Processing | MARCH 201555

Heat Transfer coalescing and increases flame lengths/dimensions in the field and correspondingly results in higher NOx emissions. Burners can be either natural or forced draft. A natural draft burner uses the draft at the heater floor to draw in ambient air through the burner opening. FD burners utilize the extra pressure generated by the fan to force air through the burner. The key advantage of an FD burner is that a smaller burner can be installed to deliver the same amount of duty (and air) as that of a natural draft burner. FD burners use the extra energy created by the air, which aids the combustion profile, thus, a smaller flame can be obtained. Burner flames are typically monitored through a flame scanner. A burner management system is installed to manage the flame-out. Pilot burners. Pilots are an integral part of the burner. These are typically premix burners (with an internal or external mixer). The key objective of the pilot is to light up the burner and re-light it if the main flame goes off. Pilot flames are typically monitored by flame rod. An ignition rod or manual torch is used to light the pilot. Pilots are supposed to be “on” at all times. However, if the main flame fuel gas pressure is very low or if the burner tips are plugged, then the pilot will not be able to light the main burner. Flame scanners or high/low pressure trips are used as safeguards. Guidelines to consider for the main fuel gas and pilot gas are: • Gas pressures should be monitored. The system should have high/low pressure trips based on burner curves. • Gas lines should have an independent trip (typically two) and control valves. A pressure regulator is used for pilot operating pressures. • Strainers upstream of the trip valves will ensure that the trip valves have a tight seal when the heater is shut down. • Coalescers should be considered if there is a possibility of liquid carryover to the burners. Knockout drums should be designed to capture the liquid slugs. Remember: The heater must be free of any combustibles before lighting the pilot or burner. The heater should be purged per startup procedures. Precautions must be taken on startup. Accidents during startup of fired heaters have been linked to not following proper procedures or to leaking valves.

Stack

Stack effect in stack Damper Convection, stack damper, losses

Convection

Typical operating draft at radiant arch design: -0.1 in. wc

Radiant arch heater controlling point Radiant ht = H ft

Radiant draft gain approximate -0.01 in. wc x H ft Negative pressure (in. wc)

Positive pressure (in. wc)

FIG. 2. Typical draft profile in a natural draft heater.

56MARCH 2015 | HydrocarbonProcessing.com

Radiant

Case Study 1. Due to a tight schedule, the burners were shipped to the field without tips. The tips were modified per the new requirements and shipped later. Installation work was done in the field. When the heater was started up, the burner flame shapes were very unpredictable, and the flames were hitting the tubes. Later, it was determined that, during field assembly, the secondary gas tips were not oriented to the burner tile. Reorientation of the gas tips with alignment dots was done to rectify the problem. Case Study 2. It was reported that the burners were not performing in the field per the burner curves provided. A field visit confirmed that, when the heater was started up, the burners were hit by a liquid slug (accumulated in the low spots of piping upstream of the burners), thereby plugging most of the burner tips. Recommendations were made to install fuel gas coalescers. The tips were cleaned to restore heater operation. Case Study 3. A pilot was found to be unreliable and often un-operational. Field testing showed that the pilot was provided with air doors. The pilot air door setting was changed, thus altering the air-to-fuel ratio mix and creating an unstable pilot. The pilot air doors were readjusted to solve the problem. Draft. Draft is created due to the differential densities between the cold air and rising hot flue gases. Eq. 1 provides a correlation for the differential pressure.

Dp = 0.0179 Pa (29/Ta – MW/Tg ) (Z2 – Z1)

(1)

where: Dp = Differential pressure, in. wc Pa = Atmospheric pressure, psia Ta = Temperature of ambient air, R Tg = Temperature of flue gas, R MW = Molecular weight of flue gas Z1 = Elevation at Point 1, ft Z2 = Elevation at Point 2, ft. Using Eq. 1 for typical bridgewall temperatures, an approximation of 0.01 in. wc draft gain can be made for every 1 ft in radiant height increase. Typical design pressure for all heaters at bridgewall is about –0.1 in. wc. In practical operation, the bridgewall pressure will vary in the range of –0.1 in. wc to –0.15 in. wc. In cases when there are multiple fireboxes connected to a common stack or a common ID fan, every firebox should have an independent draft measurement at the bridgewall to ensure that the minimum draft conditions are always maintained for all boxes. A typical draft profile for a natural draft heater is shown in FIG. 2. Positive pressure. Positive pressure conditions at radiant bridgewall should never be allowed: • Such conditions may result in O2-deficient environment in the box. • Hot flue gases will exit the heater and damage the structural support. • Exiting flue gases can also cause injuries to personnel standing on platforms near the bridgewall or if anyone accidently opens up the peep doors. Air leakage. Ideally, all excess air measured should come through the burners. In real applications, there is always air leakage occurring. Several precautions can be taken to reduce the air leakages and include:

Heat Transfer • Use glass-sealed peep doors with self-closing hinged metal doors. The glass material should be a good thermally resistant material. If the glass material is not shock resistant, cracking may occur due to the thermal shock between the firebox temperature and cooling effect from outside rain. Glass on the peep doors also provides protection against injuries if the heater was running positive. • Caulk radiant and convection sections (header boxes, explosion doors and heater seams). Caulking will crack after several years of service, and it should be inspected and re-caulked every turnaround. • Install boot seals on all process tube penetrations and tube guides. • Ensure that if a burner is not being used, the air registers for that burner are closed. If a few of the burners are not operating, then conditions can be a major air leak and result in a sub-stoic burner operation or fuel-rich box. • Do not run excessive negative pressure in the bridgewall. A typical bridgewall pressure of a fired heater is about –0.1 in. wc; running higher negative pressure can lead to increased air incursions in the box. Air leakage from the tube penetrations also results in increased oxidation and higher thermal stresses at the tube penetrations. The convection air leakage (O2 leakage through header boxes and tube penetrations) can be estimated through the difference between the radiant bridgewall O2 (provided an accurate radiant box reading is possible) and the stack O2. Note: As a good design practice, the stack exit should be sized to ensure a minimum of 10 ft/sec velocity at heater turndowns to avoid inversion, as inversion results in draft instability. Typically, the design stack exit velocities are about 25 ft/sec. For heaters with lower turndowns, adequate design exit velocities should be considered. A stack cone is generally added to achieve increased velocities. Flue gas-side instrumentation. As a minimum, the follow-

ing flue gas-side instrumentation is recommended: • O2 , temperature and draft transmitter at the radiant bridgewall (API-560 provides guidance of one O2 analyzer for every 30 ft of the radiant length or diameter) • O2 and temperature transmitter in the stack (last flue gas exit) • Temperature transmitters are recommended upstream and downstream of heat recovery equipment with a differential pressure transmitter (dPT) to monitor the pressure drop. • Temperature transmitters are recommended upstream of the emission reduction unit with a dPT to monitor the pressure drop • When considering an air preheater (APH), an O2 transmitter should be installed both upstream and downstream of the APH to monitor air leakage in the flue gas. The air temperature at the outlet of the APH going to the burners should be monitored. • Emissions-monitoring equipment should be installed per requirements. The instrument transmitters should be wired with control room indication. Draft measurement reliability. Draft is a key parameter; it provides vital information about the safe operation of a fired

heater. Differential draft transmitters are often used to meet the needs of sensitivity for draft measurement. Often, these draft transmitters are installed wrong in the field, which leads to faulty or unreliable readings. Several guidelines can be followed to ensure proper installation of a differential draft transmitter: • The draft transmitter should be located above the draft tapping. • The tubing (minimum ½ in.) between the flue gas tapping and the draft transmitter should be as short as possible, and it should have a minimum slope of about ½ in. per ft to allow free draining back to the heater. • The atmospheric reference line should be provided with a bug-shield. • The atmospheric reference line should be shielded from wind and rain effects. Case Study 4. A heater was reported to have draft issues. It was suspected that the ID fan was not delivering the required draft. A field walk-through showed that the operator was using a differential draft transmitter with the atmospheric reference line horizontally laid out and exposed to the environment with no bug-shield. Rain water had entered the atmospheric reference line, and the high winds were resulting in erroneous draft data. The solution was to modify the atmospheric reference line with a bug-shield and to protect it from wind and rain effects. Case study 5. A heater was experiencing draft problems, and operations did not rely on the draft data from the instrument. A field inspection showed that the draft transmitter was located at the grade for access by maintenance. The impulse line was filled with condensation, and zero suppression was added to the transmitter calibration. A consistent and accurate measurement was not obtainable with this installation. The solution was to relocate the draft transmitter above the draft tapping to the nearest platform. It was recommended to have a draft and O2 reading display (preferably electronic) at grade level (for the manual stack dampers) near the damper operating station, so that an operator will know the heater conditions before operating the stack damper. Otherwise, communication with the control room is required before making any changes. O2 measurement reliability. The most important parameter is the O2 measurement. It provides key data about the safety of the combustion occurring inside the radiant box. The O2 analyzer placed at the radiant arch (bridgewall or below the shock section tubes) indicates the excess air available in the radiant box. This location is chosen because all combustion inside the box is complete, and it is the last exit point (from radiant). This point provides reliable information on the excess air (or O2) provided to the burners. This enables operators to either reduce or increase the excess air supply to the burners, thus ensuring optimum combustion (or running heaters efficiently and safely). The O2 analyzer reports the numbers as percentages of excess O2. The excess O2 can be reported on either a dry or wet basis. FIG. 3 shows the relation between excess air and flue gas O2 for a typical refinery fuel gas. Point-source analyzers. Most commonly used O2 analyzers are point source ZrO2 oxygen analyzers. API-556 states that Hydrocarbon Processing | MARCH 201557

Heat Transfer these are “net O2” sensors, which are heated and use a platinum electrode with catalytic properties. Since the sensors are heated and are a potential source of ignition, flame arrestors, disconnecting power sensors or reverse flow of close-couple extractive systems are considered. One of the important parameters to a reliable reading for a point-source O2 measurement utilizing point-source analyzers is the location in the radiant box, especially for long cabin or box heaters. In some instances, cabin or box heaters have been known to provide unreliable or high O2 data in the radiant section than in the stack. This is related to either bad installation, incorrect location (long boxes with stagnating locations) or incomplete combustion. Although API-556 states that one O2 analyzer is required for every 30 ft of the radiant box, choosing those locations is critical to achieve a reliable reading. Guidelines include: • The location to the center of the heater is preferred. Placing O2 analyzers past the convection offtake ducts centerline close to end walls is not recommended. End walls are not preferred locations for making measurements. • If an O2 analyzer is placed in direct sight over a burner (e.g., in a hip section with a burner underneath), depending on the radiant box’s height and flame dimensions (especially shorter boxes with long flames), the burner air profile may influence the O2 analyzer reading. • The O2 transport tube (typically 310 SS) should project a minimum of 12 in. past the tubes or 18 in. past the refractory. • The O2 analyzer needs to be calibrated and maintained on a timely schedule. Tunable diode lasers (TDLs). An alternative to single-point source O2 analyzers are the TDLs. These analyzers are typically placed at radiant arch end-walls, and the laser beam shoots across the whole length of the radiant bridgewall area to provide an average of the O2 measurement. The advantages from TDLs include: • Fast response with low maintenance • Not an ignition source; can be reliably used during heater startups. Several guidelines should be followed when installing TDLs: • Shooting (typically 4 in.) and receiving end (typically 4 in.) nozzles must be reinforced to ensure that they can take about 40 lb to 50 lb hanging weight. Repad should be provided around the nozzle area, and angle support steel should be welded to the nozzle and the heater structural steel for additional strength. • The laser beam shooting and receiving ends are 12

Excess O2, %

10 8

Dry O2

6

Wet O2

4 2 0

1

20

40

Excess air, %

60

80

FIG. 3. Excess air vs. flue gas O2 for a typical refinery fuel gas.

58MARCH 2015 | HydrocarbonProcessing.com

100

nitrogen purged to keep them clean, cool and free of any particulate accumulation. • An isolation valve should be installed between the TDL and the heater nozzle for isolation purposes, when TDL maintenance is required. • Accurate bridgewall temperature readings are required. This is typically achieved by installing a shielded velocity thermocouple. Case Study 6. An O2 TDL was installed at the radiant arch section of a 50-ft-long box. However, when the testing was done, the TDL did not respond correctly. It was discovered that the nozzles on the receiving end were not laser aligned during installation. Due to this slight offset, the receiving end was not getting the laser signal. Case Study 7. An operating company reported an issue with

the TDL. A field inspection showed that the TDL was not adequately supported; the gussets were not enough to hold the weight. Also, the heater skin had sagged due to the additional TDL weight, thereby causing an offset to the TDL receiving unit. The nozzles were realigned and reinforced by welding an angle steel to the nozzle and heater structural steel. Bridgewall temperature thermocouple reliability. Bridge-

wall temperature measurements using convectional thermocouples sometimes have an error of as much as 150°F to 200°F. The key reasons include the location and re-radiation from the cold surfaces around. Shielded-velocity thermocouples should be considered in the radiant bridgewall sections for accurate temperature measurement. A shielded velocity thermocouple is basically a shielded SS tube (1 in.), which shields the thermocouple from cold surfaces. Velocity thermocouple has an air connection, which creates a vacuum to induce an actual flue gas sample, and the sample is measured through the thermocouple. Tube-skin thermocouple reliability. The tube-metal tem-

peratures are monitored through the tube-skin thermocouples. These provide vital information about the heater tube safety. A minimum of two tube-skins are recommended per heater pass. These are located on the hottest sections of the tubes, which typically is the radiant outlet tube and the first row of the shock section. Monitoring of tube-skin temperatures provides information on whether the tubes are exceeding their maximum allowable temperatures, which can result in tube ruptures if no corrective action is taken. Higher tube-skin temperatures are also indications of increased fouling or possible flame impingement. IR scans and visual screening on a periodic basis can provide valuable information about the hot spots and overall condition of the tubes. From industry experience, several actions can be taken to increase the reliability of the tube-skin thermocouple: • Proper routing of sheath. The sheath should preferably have a 180° wrap (thermocouple facing the burners), and the expansion coils should be on the cooling side of the heater. The sheath should exit the heater from the cooler side of the tube; clips can be used to hold the sheath in place. The sheath should exit the heater with the least exposure to flame and radiation.

Heat Transfer • Recommended minimum sheath metallurgy is either Inconel 600 or Hastelloy X. A heavier wall is preferred. • Expansion loops. Insufficient expansion loops or restricted expansion of the sheath will result in failure of the tube-skin thermocouple. The heater tube metallurgy and the hottest temperature the tube to be encountered (maintenance operations) should be considered when designing the expansion loops. • Proper design of clips is essential. If the clip fails or cannot hold the sheath in place, then the sheath can have a premature failure due to the exposure to high temperatures. Minimum 310 SS metallurgy is recommended. • Installation. In field jobs, the tube-skin installation should only be done by an experienced tube-skin installer or supervised by the tube-skin OEM supplier during installation. Case Study 8. A new set of tube-skins were installed in the field.

When the heater was fired, the tube-skins were reporting low temperatures. A field check indicated that the thermocouples were facing the tube side rather than the flame side (hot side). Stack damper reliability. The stack damper is used to control the draft in natural draft heaters. However, dampers are also utilized in the flue gas and air ducts, and fan dampers control the FD and ID fans. API 560 states that a minimum of one

blade is required for every 13 ft2 of the internal cross-section area for butterfly dampers. Stack damper reliability is a major issue in some installations. Several guidelines can be considered to increase reliability: • Selection of the bearing should be per the operating temperature range (low and hot ends). Some bearings can gum up at the lower operating temperature range. If the flue gas temperatures are very high, then a damper design modification will be required to lower the bearing temperatures within the recommended range. • Shaft surface finish and hardness must meet the required specifications of the bearing manufacturer guidelines. • Shaft OD and bearing ID clearances must be adequately considered. Inadequate clearance will result in seized bearings. • Adequate damper blade and refractory clearance, should be based on the damper design, metallurgy and design temperatures. • Damper linkages should be evaluated for reduced friction factor. • A minimum of 10% open adjustable mechanical stop should be considered (for control dampers). Higher adjustable mechanical stop can be considered for flexibility. The mechanical stop provides the blades an expansion area and prevents contact with the refractory. This is especially important; as the heater ages,

worldheavyoilcongress.com

March 24-26

THE KNOWLEDGE. THE EXPERTISE. THE RELATIONSHIPS. No event gets you better connected with the heavy oil community. business conference | technical conference | short courses | exhibition | social events | poster sessions

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Hydrocarbon Processing | MARCH 201559

Heat Transfer adjustment is made, depending on the heater size. FIG. 4 shows a typical draft and O2 adjustment for fired heaters.

Done OK

OK

Check O2

Case Study 10. A new burner retro-fit installation was completed on a vertical cylindrical heater. When the heater was operated, the operator reported unbalanced flue gas currents and that the NOx emissions were slightly higher than the guaranteed. A field visit showed that the heater was operating with about 5% to 6% excess O2. All of the burner air registers were opened at different damper settings and one non-operating burner had the air register completely open. The heater was tuned to operate at 3% excess O2 ; all burners were made operational, and the burner air damper settings were adjusted equally. The heater flue gas cleared up and the NOx emissions were under the guarantee. FIG. 5 illustrates the annual operating cost of fired heaters and the savings that can be realized by operating efficiently, based on a $4/MMBtu natural gas cost. Duties represent heater absorbed duties.

Check draft

Not OK

Not OK

Adjust burner registers or FD fan

Adjust stack damper or ID fan

Annual operating fuel cost MM, ($4/MMBtu)

FIG.4. Typical draft and O2 adjustment for fired heaters. 18 16 14 12

Visual observations. Visual confirmation inside the heater

10 8 6 4 2 0

63

68

73 10 MMBtu/hr 25 MMBtu/hr 50 MMBtu/hr

78 Heat efficiency, % 100 MMBtu/hr 150 MMBtu/hr 200 MMBtu/hr

83

88 250 MMBtu/hr 300 MMBtu/hr

FIG. 5. Annual operating fuel cost vs. heater efficiency.

is always required to check for combustion adequacy, flame or heater conditions. Peep doors provide a visual of the flame patterns or possible flame impingement on the tubes. When observing inside vertical cylindrical heaters, a floor view port should be considered for a clear view of the flame and tube areas. Hazy or smoky environments, lazy and pulsating flames, hot spots on tubes, damaged refractory, broken tube hangers and sagging tubes can provide visuals to the potential problems in the heater. Outside visual information can show missing tube seals, obvious signs of air leakage, corroded or buckled heater skins, and more. Recommendations. Much can be saved by optimizing the

the refractory may bulge in certain areas, thus increasing the chances of sticking dampers. • Dampers operated regularly. It has been observed from the field that if the dampers are not operated regularly, they get stuck. A direct-actuator mounted-stack damper is more likely to be operated from the control room than a manual stack damper. This is important for large stack dampers (greater than 5 ft in diameter). Slacking cables and large forces required to move large dampers usually result in manual stack dampers not being operated. Dampers should be provided with a pointer (painted with a bright color) to provide a visual on the indication of the stack damper position from grade. Case Study 9. A few dampers used to stick when they were in a hot position. When the heater was shut down, both the actuator and damper vendors stroked their equipment, and no issues were identified. However, in the hot position, the problem reappeared. It was identified that the inadequate clearance between the bearing and shaft resulted in sticking dampers in the hot condition. Adjusting the bearing clearance solved the problem. Heater tuning. It is important to get the optimum performance

from the fired heater. Heater instruments have lag times, and the settling times for the combustion parameters should be considered. Typically, after an adjustment is made, the heater should be allowed to settle a minimum of 5–10 minutes before the second 60MARCH 2015 | HydrocarbonProcessing.com

heaters. However, reliable operating instruments will ensure safe working conditions inside the box: • Follow proper heater startup procedures. Heaters should be purged before lighting the pilot or the main flame. • A draft and O2 transmitters at radiant arch are the single most important instruments required for combustion safety monitoring. • Keep the heater tuned in to get the most optimum heater performance with reduced emissions. Do not operate burners below 10% excess air. • Keep a visual of the heater from inside and outside for potential problems in the furnace. • Have a maintenance schedule set up for the heater maintenance. Tube conditions should be monitored to estimate discard thickness. NOTE All case studies presented here have been developed solely for the purpose of illustrating typical problems and their solutions. Their resemblance to any installation may be coincidental. KAPIL MALHOTRA is a heat transfer engineer at S&B Engineers and Constructors Ltd. in Houston, Texas. He has more than 10 years of experience in the design, engineering and troubleshooting of fired heaters, combustion systems and thermal equipment. He holds an MS degree in mechanical engineering from Oklahoma State University. Mr. Malhotra is a registered professional engineer in the state of Texas, and has authored several papers on heat transfer.

Refining Developments S. SAYLES, KBC Advanced Technologies, Houston, Texas

Shale oil characterization optimizes refining process The abundance of shale oils is an unexpected gift for US refiners. These new crude oils have different characteristics from conventional oils that will affect refining processes and the operation of process equipment. Better crude evaluation methods will help refiners plan how to introduce shale oils as part of the refinery feedslate, with minimal disruption to operating conditions.

BACKGROUND The production method for the Eagle Ford and Bakken shale plays is via fracturing of the tight or shale formations; both shale plays are in two different regions of North America (NA). Crude produced via fracturing production method is termed light tight oil (LTO). The LTO crudes from the two different formations, likewise, have very different properties or characteristics. Asia-Pacific (AP) crudes are produced using conventional methods, and the qualities of these crude oils also vary by production location. Crudes from both NA and the Pacific Rim are low in sulfur (S), nitrogen (N) and metals, and are good candidates for refinery operations. New source. LTO formations are provid-

ing a new oil source to NA and possibly the global market.1 The economic advantages of processing LTO crudes are the historically low cost relative to the global market and high quality.2, 3 The production of LTO crudes is relatively new in NA. However, AP conventional crudes with similar crude quality have been in production for a long time. A comparison of crude quality between the two crude sources presents a possible way to provide operating insight and product quality. A comparison between NA LTOs (Bakken and Eagle Ford) and AP conventional crudes (Bach Ho, Gippsland, Cossack and Kutubu) with similar physical properties is presented here.

CRUDE EVALUATION METHODOLOGY

advanced analytical testing of the crude is required to determine the many chemicals that may be present.4

Crude evaluation methodology varies, and it is changing as the upstream production methods progress. For example,

Data source for comparison. The data

tables presented were developed by us-

TABLE 1. Recommended methodology to evaluate new crude oils Review the crude assay provided by the supplier. • Determine the actual sample source (single well and pilot testing) • Request information on method of production (e.g., chemical additions, hydraulic fracturing or other possibilities) Data reconciliation between the cut testing and the whole crude is required. At a minimum, include balances on mass, volume, S, N and CCR with a closure between 99% and 101% for all results. Determine deficiencies and corrective action(s). For example: • Mass balance errors • Missing data (S speciation, sediment, trace metals and more) • Focus on areas that the data indicate are possible causes for concern: high TAN, low kerosine yield and more • Request additional data from the supplier Using the reconciled data, enter this information into a modeling tool to prepare an assay file of whole crude from the cut data.a Comparison of the assay may indicate deviations that require additional corrective action, such as poor matching of the cut N contents. Using a heat and material balanced model of the refinery, evaluate the processing potential for running the crude in the refinery.a This allows prediction of the potential value to the refinery for the new crude. Provide runs with multiple crude blends to determine flexibility to process the crude and establish a concentration ceiling at unit constraints. Using realistic crude blends, determine the crude compatibility and requirements for tankage or processing requirements.4 Determine an estimate of the incremental variable operating costs for the new crude: • Use a heat and material balanced tool that allows accurate prediction of the energy consumption changes for the new crude.a • Use a kinetic model to produce projections of hydrotreater catalyst life or FCC catalyst addition requirements.a • Review the literature and inquire from chemical vendors and other industry sources for possible additional information on the crude. Update the refinery LP for nonlinear items. Run the LP to verify the performance criteria. Use updated crude evaluation data from the supplier to update the simulations. Conduct a preliminary MOC: • Highlight crude qualities that are outside the current crude types being processed. • Evaluate the potential impact on unit performance using model output.a • Conduct metallurgical assessments for increases to TAN, S, N and other constituents. Prepare a high-level corrective action list of mechanical and process modifications required to meet the new crude’s specific processing needs. Using a model, the high-level review can include major equipment sizing and tray performance, for example. Update the variable operating costs and prepare a fixed or capital cost summary.a If the crude is still of interest, then request a representative sample for independent confirmation of the quality. Hydrocarbon Processing | MARCH 201561

Refining Developments ing a commercially available simulation model.a The crude assay data are a combination of several crude data bases.b The Eagle Ford assay is an estimate.a, 5 The reported Eagle Ford crude properties vary significantly depending on the production well, and a typical assay is not published. The Eagle Ford assay estimate assumes qualities similar to crudes having similar API gravities and properties as reported.5–8 Although not shown in the tables, the individual test methods are the typical ASTM type for each reported quality. Refinery crude evaluation procedure. Changing crude source may trigger a

management of change (MOC) process; thus, the hazards from new crude oils must be carefully considered.9 A stepwise process is recommended that assists in meeting the standards of the MOC. TABLE 1 summarizes the procedure. The economic evaluation of the new crude requires accurate market pricing data that is often not available. The best initial estimate is determined by understanding the crude’s value to the refinery and backcalculating a breakeven cost for processing. A critical component of the business case is an accurate estimate of both the operating and capital costs associated with the new crude. It is possible to develop a rank5–7, 11–14

TABLE 2. Common observations for LTO and Pacific crudes

Refinery gasoline + distillate increases compared to conventional crudes. Wax formation in the cold crude and distillate hydrotreater preheat exchangers causes fouling, which reduces heat transfer and increases pressure drop, requiring cleaning at shortened intervals. Difficulties in desalting due to the formation of emulsions and other factors: • High filterable solids add to the desalter load and reduce efficiency. • High API gravity improves desalting by creating a greater density difference between crude and water, increasing the Stokes settling velocity. H2S and odors are higher, and the use of H2S scavengers creates amine salts and corrosion products in the crude unit. Distillate cetane is excellent, while waxes tend to create cold-flow (CFPP and PP) issues, leading to modifications of the process, additives or jet fuel downgrading to meet specifications Crude quality is variable between cargoes, leading to unpredictable operational changes. High VGO paraffin content allows high conversion, low coke yields and low naphtha octanes: • Catalyst circulation becomes limiting due to the coke yield. • Gasoline selectivity increases. • C3 /C4 olefin yields increase. • Slurry rate decreases with a corresponding increase in API gravity: ° Distillate blendstock requirements are reduced. ° Diesel production increases. • Existing units require evaluation of the main fractionators and vapor recovery unit to accommodate the changes in yields. Compatibility is poor with asphaltic crudes, leading to sedimentation and asphaltene precipitation. Residue yield is low, decreasing the vacuum and coker charge rates. LPG and naphtha yields on crude increases requiring more lift, either as a preflash or in the atmospheric tower: • Produced LPGs may require modifications to the saturate gas plant. • Naphtha-splitter upgrades are also a consideration. The NHT, reforming and isomerization unit rates increase, requiring evaluation for performance or expansion Hydrogen requirements are reduced due to lower hydrotreating severity at the low feedstock S and N concentrations. Distillate production is generally higher due to the FCC selectivity improvements, and has about the same distillate yield on crude. Naphtha paraffin content is higher: • CCR units have higher coke, lower yields and poorer activity. • Semi-regen units have lower yields and octane. FCC increased olefin production tends to increase: • Alkylation iC4 requirements • Isomerization of nC4 to meet alkylation requirements • Higher utilization of polyunit to react the C3= • Potential for refinery-grade C3= production Lower S levels decrease the amine and SRU loading.

62MARCH 2015 | HydrocarbonProcessing.com

ing of crudes specific to a given refinery’s configuration and operation.

LTO CRUDE QUALITY LTO crude indicates the formation from which the oil is derived but not necessarily the oil’s quality (TABLE 2). The common link between different formations is the production chemicals used in the fracturing process. LTO crudes tend to be low in S and high in N, and the bottoms concentration is low. The low-cost, favorable quality aspects and quantity of the crude can make it a very attractive choice for the refineries. LTO general observations. Common observations about LTO crudes are that they produce high-value, low-S products. But, these crude oils require changes to the operation due to the differences in quality. Some general observations are: Salt composition. Salt composition is higher in the concentration of calcium (Ca) and magnesium (Mg) salts (70 wt%–90 wt%) vs. typical crudes, which are sodium based (70 wt%–80 wt%).6, 10 The impact of the shift to Ca and Mg salts is the potential for hydrolysis in the atmospheric tower fired heater. Hydrolysis is the conversion or decomposition of a salt to the ion and HCl. Sodium salts do not hydrolyze, while Mg and Ca will hydrolyze. Result: At constant total salt concentration, the expectation is higher chloride levels in the atmospheric tower overhead, thus leading to the potential for higher corrosion. Phosphorus. The phosphorus (P) content is another difference among typical crudes. P tends to accumulate in the upper section of the atmospheric tower, causing tray fouling. The P source is an ongoing investigation. However, data from several atmospheric towers indicated fouling caused by P when processing Eagle Ford, Bakken and/or WTI.10, 11 Common observations. TABLE 2 summarizes some common observations for LTO and Pacific crude.5–7, 11–14 The following sections describe some of the yield and quality shifts between Pacific Rim and LTO crudes.

CRUDE YIELDS Bakken crude production is located in the northern US and southern Canada, and Eagle Ford production is in southern Texas. The AP crudes range from Vietnam to Australia, and these crude oils have been

Refining Developments in production for many years. Bach Ho crude was used as the reference crude and has had very successful refinery operation experience. The incremental yields were calculated using proprietary simulation models, and are shown with Bach Ho as the base crude.a, 5, 15 In general, the yields are similar with the exception for light-end yields, which are higher than Bach Ho. The Cossack, Gippsland and Kubutu crudes have higher light naphtha yield, while Bakken crude has more light naphtha yield. The Eagle Ford crude has less light naphtha yield as compared to Bach Ho. Bakken crude yields less heavy naphtha than Bach Ho (TABLE 3). In contrast, Eagle Ford crude produces more heavy naphtha compared to Bach Ho. The Cossack, Gippsland and Kubutu crudes yield more heavy naphtha yield than the Bach Ho crude. The distillate yields are about the same. For all crudes, the light vacuum gasoil (LVGO), heavy VGO (HVGO) and vacuum resid (VR) yields are less than the Bach Ho crude, but are about the same when compared to the other yields within this group. In general, the light yield structure is an advantage, and it provides high-value products. The heavy naphtha plus yields offer the greatest value. However, the high lightends yield (C1 to C6 ) from the LTO crudes is creating a potential surplus in the US market.1 The market is reacting, and present pricing on a Btu basis places ethane below natural gas (NG). This trend provides advantages to ethane crackers producing ethylene and to refiners by reducing fuel costs. Recovery of C3 as LPG offers benefits, while the C4 to C5 boiling range is at a disadvantage due to gasoline volatility.

CRUDE QUALITY TABLE 4 summarizes the crude qualities for several shale oil plays.13, 16, 17 The Bakken and Eagle Ford crudes have higher pour points (PPs), while the other qualities are about the same. The crude qualities for API gravities, PP and N vary by location. While 1,000°F+ S, aromatics, paraffin and viscosity are comparable. High iron (Fe) content is typical for paraffinic crudes. The high-Fe concentration causes catalyst deactivation in downstream units and other operating problems. PRODUCT QUALITY Paraffinic crude cut qualities generally have high API gravity and wax content. The

low S and N levels are observed for all of the cuts. The PP is generally higher for all LTOs, with the exception of Bakken crude. The high PP leads to storage challenges requiring either heated systems or storage as blends for intermediate feeds. The quality

of the light ends and light naphtha is about the same for all of the LTOs, although the yields do vary by location. The light naphtha is a particular challenge. The base gasoline volatility is reduced due to ethanol added in the final blending.

TABLE 3. Crude incremental yields Bach Ho

Bakken Eagle Ford

Cossack Gippsland

Kubutu

Vietnam

US/ Canada

Papua New Australia Guinea

US

Australia

Light ends, vol%

Base

2%

4%

5%

5%

6%

Light naphtha, vol%

Base

5%

–4%

18%

28%

13%

Heavy naphtha, vol%

Base

10%

14%

7%

3%

9%

Kerosine, vol%

Base

0%

–1%

1%

–3%

0%

Diesel, vol%

Base

–2%

3%

–2%

–3%

–1%

LVGO, vol%

Base

–4%

–4%

–8%

–7%

–6%

HVGO, vol%

Base

–5%

–6%

–13%

–14%

–12%

VR, vol%

Base

–5%

–7%

–9%

–10%

–8%

Cossack Gippsland

Kubutu

TABLE 4. Crude incremental quality comparison Bach Ho

Bakken Eagle Ford

Vietnam

US/ Canada

US

Australia

Australia

Papua New Guinea

API

Base

0.4

3.6

7.8

13.4

14.6

S, wt%

Base

0.1

0.1

0.0

0.0

0.0

N, wppm

Base

265

–338

–27

–263

–275

PP, °F

Base

–52

–92

–72

–59

–47

Paraffins, vol%

Base

–17

NA

–2

11

6

Aromatics, vol%

Base

13

NA

0

–1

–2

Iron, wppm

Base

3

–1

0

–1

–1

Cossack Gippsland

Kubutu

TABLE 5. Heavy naphtha incremental quality Bach Ho

Bakken Eagle Ford

Vietnam

US/ Canada

US

Australia

Australia

Papua New Guinea

API

Base

1

4

–2

–2

0

S, wppm

Base

19

53

10

294

114

N, wppm

Base

0

0

0

0

0

Paraffins, vol%

Base

–24

8

–10

–2

–11

Naphthene, vol%

Base

–9

–6

6

–5

3

Aromatics, vol%

Base

33

–2

4

7

7

TABLE 6. Lubricity test methods Test description

Abbreviation

Method

Limit

High-frequency reciprocating rig

HFRR

ASTM D6079

< 460 micron

Ball-on-cylinder

BOCLE

ASTM D5001

< 0.85 mm

Scuffing load ball-on-cylinder

SL-BOCLE

ASTM D6078

3,000 gms

Low-lubricity fluid endurance

LLFE

SAE ARP 1797

Performance

Hydrocarbon Processing | MARCH 201563

Refining Developments Heavy naphtha quality. As summa-

rized in TABLE 5, the heavy naphtha fractionation of LTOs have low S levels, but will still require hydrotreating before being sent to the catalytic reforming unit. 5, 15 The heavy naphtha is similar in qual-

ity to Bach Ho crude for all of the LTOs except Bakken crude, which has a higher aromatic and lower naphthenic concentrations, and it is an excellent reformer feed. The low aromatic and naphthenic concentrations for the other crude

TABLE 7. Kerosine incremental quality Bach Ho

Bakken Eagle Ford

Cossack Gippsland

Vietnam

US/ Canada

US

Australia

Australia

Kubutu Papua New Guinea

API

Base

–5

–4

–4

–5

–5

S, wppm

Base

109

32

32

610

506

N, wppm

Base

4

0

0

0

–1

Paraffins, vol%

Base

–19

–10

–10

–9

–14

Naphthene, vol%

Base

12

3

3

0

5

Aromatics, vol%

Base

7

7

7

10

10

Freeze, °F

Base

–27

–23

–23

–7

–6

Cetane index

Base

–9

–9

–9

–11

–9

Smoke point, mm

Base

–4.7

–1.0

–4.7

–5.8

–5.7

Cossack Gippsland

Kubutu

TABLE 8. Diesel incremental quality Bach Ho

Bakken Eagle Ford

Vietnam

US/ Canada

Papua New Australia Guinea

US

Australia

API

Base

–6

–6

–5

–4

–9

S, wppm

Base

247

247

1,015

660

294

N, wppm

Base

12

12

–25

–28

50

Paraffins, vol%

Base

–13

–13

–2

–11

–21

Naphthene, vol%

Base

3

3

–8

2

5

Aromatics, vol%

Base

10

10

11

10

16

Cloud, °F

Base

–21

–21

–1

–3

–11

PP, °F

Base

–22

–22

–5

–4

–14

Cetane index

Base

–11

–11

–8

–7

–14

Name mechanism

Growth agglomeration

Nucleation wax appearance temp. (WAT)

Extension molecular alignment

Liquid state random motion

Molecular type

fusi on

Iso-paraffin

Hea t of

Heat of fusion

n-Paraffin

Cyclo-paraffin (Naphthene)

Cloud flow depressant Reduces the rate of agglomeration

FIG. 1. Crystallization mechanisms.

64MARCH 2015 | HydrocarbonProcessing.com

Temperature

Cloud point depressant Reduces the rate of wax nucleation

sources make the heavy naphtha a marginal reformer feed. Distillate quality. Distillates have high cetane and poor cold-flow (CF) properties. High straight-chain paraffinic concentration and yields make these crudes great for diesel production. Straightchain paraffin properties are prone to wax production, thus creating flocculation, which is seen as high cloud points. Also, they crystallize due to high PPs, as illustrated in FIG. 1. CF-depressant (CFD) additive chemistry consists of polymers that modify the initial wax formation from large to small wax crystals and then inhibit the agglomeration. Wax formation starts with a nucleation point for small crystals to collect (cloud point). As the crystal grows, the larger crystals combine or agglomerate into larger collected masses until the fuel begins to gel (PP or CFPP). The thermodynamics are such that the heat of fusion can be measured by the differential temperature of the mixture. As a result, CF properties must be improved, usually through chemical additives (CFDs), isomerization or blending with other streams. Another potential issue requiring monitoring is lubricity. Four tests are available to measure lubricity (TABLE 6). The general agreement is that the HFRR test is the most reproducible and is recommended as the standard. However, the specifications are typically BOCLE (TABLE 6). Recent changes to jet fuel specifications allow additives to address lubricity.14 The Defense Standard gives a list of approved lubricity additive packages, suppliers and acceptable blending limits in the relevant section of Annex A.18 Kerosine quality. The kerosine incre-

mental quality compared to Bach Ho as simulated is summarized in TABLE 7.15 Kerosine appears to need undercutting, blending, hydrocracking or dewaxing to meet freeze-point specifications. Virgin kerosine-jet blends potentially would require clay treating or mild hydrotreating. Recent changes in specifications allow additives to improve lubricity.18 Diesel quality. Diesel quality is accept-

able for cetane numbers with higher CF and S reductions than ULSD specifications. TABLE 8 shows the incremental

Refining Developments diesel quality as fractionated by the model.a, 15 High paraffin levels have the potential for water containment resulting in hazy final products. Hydrotreating, dewaxing or jet downgrading are options to be considered in producing ULSD.19, 20

TABLE 9. VGO incremental quality comparison LVGO

Bach Ho

Bakken

Eagle Ford

Cossack

Gippsland

Kubutu

API

Base

–9

–6

–6

–2

–1

S, wppm

Base

1,984

590

590

1,361

742

N, wppm

Base

0

0

0

0

0

VGO quality. The VGO has low aromat-

Aromatics, wppm

Base

466

240

240

1

–52

ic content and cracks well. TABLE 9 lists the incremental VGO qualities as fractionated by the model and compared to Bach-Ho.15 The low Conradson carbon residue (CCR) and high paraffin levels allow high conversion and low coke make. Fluid catalytic cracking unit (FCCU) catalyst circulation will reach limitations due to low coke. Resid is potentially the best feed for the FCCU.

PP, °F

Base

18

12

12

10

7

CCR, wt%

Base

–45

–31

–31

–17

–11

HVGO

Base

API

Base

0

0

0

0

0

S, wppm

Base

–9

–7

–7

–3

0

N, wppm

Base

2,515

1,094

1,094

2,244

1,229

summarizes the atmospheric tower bottoms (ATB). The ATB has moderate CCR and low metals content. It is a good choice as feed to the FCCU. Processing the full-range ATB produces a higher-S gasoline than is allowed by US Tier III and would require additional post-treating. Hydrotreating full-range ATB is possible with an existing GO hydrotreater, and it would provide an alternative to produce ULSG.

ATB quality.

TABLE 10

Options. Crudes from the AP rim are

similar to the Bakken and Eagle Ford production. The similarities allow more flexibility to process LTOs, using knowledge gained in modeling. NOTES The data tables presented in the article were developed using the KBC Petro-SIM simulation model. PetroSIM is a trademark of KBC Advanced Technologies plc, and it is registered in various territories. b The crude assay data are a combination of either the H/CAMS Haverly Systems Inc. crude data base15 or as modified by KBC. a

LITERATURE CITED Kuhl, et al., “Capitalizing on shale gas in the downstream energy sector,” AFPM Annual Meeting, March 2013. 2 Sayles, S., “Upgrading technology selection,” 2007 Oil Sands and Heavy Oil Technology Conference, Calgary, Alberta, Canada, July 2007. 3 Sayles, S., “Shale or tight oil processing,” AFPM Q&A, October 2012. 4 Sayles, S., et al., “Unconventional crude oil selection and compatibility,” NPRA Annual Meeting, March 2011. 5 Huovie, et al., “Solutions for FCC refiners in the shale oil era,” AFPM Annual Meeting, March 2013. 6 Lordo, S., et al., “Shale and tight oil new frontier,” 3rd Opportunity Crude Conference, March 2012. 7 Lordo, S., et al., Opportunity Crude Conference 2008. 8 Sandu, C., et al., “Innovative solutions for processing shale oils,” Hydrocarbon Processing, July 2013. 1

Aromatics, wppm

Base

0

0

0

0

0

PP, °F

Base

946

1,110

1,110

29

–229

CCR, wt%

Base

19

13

13

10

4

Metals

Base

–35

–24

–24

–7

–6

Fe, wppm

Base

1

0

0

1

0

Cossack

Gippsland

Kubutu

TABLE 10. Atmospheric tower bottoms incremental quality ATB

Bach Ho

Bakken

Eagle Ford

API

Base

–5

–5

–1

0

–8

S, wppm

Base

931

931

2,150

1,790

765

N, wppm

Base

803

803

–272

–362

744

Aromatics, wppm

Base

13

13

10

7

20

PP, °F

Base

–33

–33

–22

–17

–28

CCR, wt%

Base

0

0

0

0

1

Metals

Base

0

0

0

0

0

Fe, wppm

Base

7

7

–2

–1

–2

Ni, wppm

Base

2

2

–1

–1

0

V, wppm

Base

–1

–1

–1

–1

–1

9

OSHA regulations, 29CFR 1910.119 Process Safety Management of Highly Hazardous Chemicals, state that any time a critical component in an oil or chemical plant changes, a formal MOC program is required to ensure that the proposed change is made safely. 10 Ohmes, R., et al., “Characterizing and tracking trace contaminants in opportunity crudes,” AFPM Annual Meeting, San Antonio, Texas, March 2013. 11 Sayles, S., “Unconventional crude processing Part 1: Metals,” Crude Oil Quality Association, October 2008. 12 Sayles, S., “Unconventional crude processing—Part 2: Heteroatoms,” Crude Oil Quality Association, October 2010. 13 Sayles, S., “LTO heat transfer loss,” Unpublished. 14 Kramer, “Using proven technology to optimize profits when processing opportunity crudes,” 3rd Opportunity Crude Conference, March 2012. 15 H/CAMS Haverly Systems Inc. 16 Saleh, et al., “Blending effects of fouling on four crudes,” ECI Symposium Series, Vol. RP2: Proceedings 5th International Conference on Heat Exchanger Fouling and Cleaning, June 5–10, 2005. 17 http://crudemarketing.chevron.com/crude/far_ eastern/duri.aspx.

18

Defense Standard 91-91 Issue 7, Amendment 2, March 2013. 19 Sayles, S., et al., “Solutions to common problems in scoping, designing, implementing and operating ULSD units,” NPRA Annual Meeting, March 2006. 20 Ohmes, R., et al., “Analyzing and addressing the clean fuels and expansion challenge,” NPRA Annual Meeting, March 2007. SCOTT SAYLES is a principal consultant for KBC Advanced Technologies Inc., Houston, with more than 35 years of refinery and petrochemical experience, ranging from refinery plant manager to research engineer. His technical areas of expertise include operation and design, ebullated-bed residual hydrocracking, hydrotreating, FCCU, and practical understanding of most processes. Mr. Sayles is a member of the American Fuel and Petrochemical Manufacturers. He holds a BS degree in chemical engineering from Michigan Technological University, and an MS degree in chemical engineering from Lamar University. Hydrocarbon Processing | MARCH 201565

CASE STUDY SUCCESSES 2015 AFPM Reliability & Maintenance Conference and Exhibition Austin Convention Center Austin, Texas May 19 – 22, 2015 Register at www.afpm.org 202.457.0480

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Refining Developments P. K. NICCUM, KBR, Inc., Houston, Texas

Update on the catalytic cracking process and standpipes—Part 1 The fluid catalytic cracking (FCC) process is a well-established technology used by complex refineries. It is a key profit center, as the FCC unit (FCCU) has the flexibility to produce transportation fuels and high-value petrochemicals. One of the prime challenges in the operation of an FCCU is keeping the catalyst circulating. Compared to the other problems, the correction of erratic catalyst standpipe operation tops the list. Fundamental equations and practical lessons learned can remove much of the mystery surrounding fluidized particle flow through standpipes. Part 1 reviews FCC standpipe history and fundamental process equations are developed along with a general discussion of standpipe design and operation. In Part 2, theoretical aeration requirements, the effectiveness of different aeration mediums, catalyst properties, troubleshooting tools and lessons from commercial standpipe performance issues will be provided. Background. FCCU performance and reliability are the prima-

ry drivers of petroleum refinery economics. In the years leading up to the commercialization of the world’s first FCCU in 1942, a key breakthrough was the discovery that powdered catalyst can exert static head when flowing downward in a pipe.1 The discovery, now known as the standpipe, as indicated in FIG. 1, allowed the elimination of screw feeders designed to move the powdered catalyst between pressurized reaction and regeneration zones. The reduced mechanical complexity improved the reliability of FCCUs. The advantage came at a cost; the introduction of standpipes conscripted future generations with weeks and months of frustrating work to combat problems with pressure buildup through the standpipes. FIG. 2 shows the configuration of the world’s first commercial FCCU.2

pressure buildup of more than 35 lb/ft3, and also while operating on different catalysts within a broad spectrum of physical properties, then the standpipe could be called a good, well-behaved standpipe. Conversely, a “bad standpipe” could be characterized as one that exhibits low or erratic pressure buildup and over-sensitivity to changes in FCCU operating conditions or catalyst physical properties. In the author’s experience, most FCCU standpipe performance issues can be categorized into four areas that are often interrelated: • Standpipe inlet design • Standpipe geometry issues • Standpipe aeration • Catalyst-related issues. Recognizing a problem with standpipe performance. Not all limitations to FCCU catalyst circulation are related to inadequate standpipe performance. Some of the more common impediments to catalyst circulation, aside from standpipe performance, include:

44 in.

32 in.

Venturi 6 in.

Stripper

20 in.

Framing the problem. In an ideal world, FCCU operations

would be: 1. Standpipes are fed with well-aerated catalyst. 2. The standpipe routing and diameter changes, if any, do not trap pockets of gas or accelerate defluidization. 3. Aeration systems provide gas if needed to fluidize the catalyst and makeup for compression of gas as the solids and gas move downward. 4. Catalyst properties support the catalyst’s ability to pass through the system without losing its fluidized condition. FIG. 3 shows a typical standpipe.3 This figure depicts the desired pressure profile through a standpipe with pressure steadily increasing from top to bottom. If a standpipe can circulate the desired rates of catalyst while maintaining a steady

88 ft-6 in.

Regenerator

16 in. 20 ft

Reactor

3 in.

Steam

30 ft

4 in. Air

Oil

Drawing (June 21, 1940) of new “standpipe system” for installation at PECLa. There was also a circuit for catalyst flow from the 32-in. hopper to a catalyst cooler and into the bottom of the regenerator.

FIG. 1. Early record of standpipe disclosure. Hydrocarbon Processing | MARCH 201567

Refining Developments • Riser pressure drop is high • Reactor-regenerator pressure differential is limiting • Required catalyst circulation rate has increased due to increasing reactor heat loads or a reduction in regenerator-reactor temperature differential. When pressure buildup through the standpipe is low or erratic, catalyst circulation capability will suffer, and these circumstances are the subject of this article. Actual vs. apparent density. To discuss standpipe operating characteristics, it is sometimes useful to draw a distinction between the actual density of the flowing emulsion of catalyst and gas in the standpipe and what is termed apparent density. Actual density is the true flowing emulsion density that can be measured with techniques such as gamma ray scans through the standpipe. Apparent density is simply the change in pressure

Second cyclone

Second cyclone First cyclone

First cyclone

Regenerated catalyst hopper Venturi Regenerator

Regeneration coolers

Reactor

Fresh feed Fractionation

FIG. 2. First commercial scale standpipe application. Bed “level”

Importance of the standpipe inlet. Good fluidization of the catalyst before it enters the standpipe is of prime importance. Inadequate fluidization at the standpipe inlet is very difficult to overcome with attempts to re-fluidize the catalyst after it enters the standpipe. Many different design configurations of standpipe inlets have been practiced over the years, ranging from a simple hole in the bottom cone of a fluid bed, to internal standpipe inlet hoppers, to externally fluidized side-draw hoppers. Many successful examples exist for each of these configurations, but, at the same time, not-so-successful examples are plentiful. Where does the aeration go? The gas in a standpipe al-

ways flows upward relative to the downward flow of catalyst, but the net flow of gas can be upward or downward depending on the bubble-rise velocity and the velocity of the downward flowing catalyst. In most modern FCCUs, vertical standpipes are designed with a high enough catalyst velocity so that the 50

Standpipe lnlet

Normal presssure increase

Minimum fluidization density

Spent catalyst hopper

between two points in the standpipe divided by the elevation difference between the points, i.e., ∆P/∆L. It is common in casual conversations to just refer to ∆P/∆L as simply standpipe density, but, in some instances, we need to be careful not to confuse actual and apparent densities in the standpipe. What is the difference between actual and apparent density? The difference is the frictional force exerted between the flowing catalyst and the walls of the standpipe. FIG. 4, published in 1976, shows data from an 8-in.-diameter standpipe flowing at catalyst fluxes between 160 lb/ft2-sec and 250 lb/ft2-sec.4 It also shows the calculated standpipe friction loss vs. the true density of the flowing emulsion based on gamma ray scans. Based on the line drawn through the data, the maximum ∆P/∆L occurred at an actual (radiation) density in the range of about 40 lb/ft3 to 45 lb/ft3 with a 5 lb/ft3 to 10 lb/ft3 friction loss, i.e., an apparent density of about 35 lb/ft3. Note: As the actual density increases to higher levels, the frictional forces increase enough that apparent density will become lower. Awareness of this concept can reveal some of the mysteries of standpipe operation.

40

Increasing depth

Friction loss, lb/ft3

30

20

10

0 Standpipe diameter: 8 in. circulation rate: 160-250 lb/ft2 sec Slide valve

Increasing pressure

FIG. 3. Simplified standpipe depiction.

68MARCH 2015 | HydrocarbonProcessing.com

-10 25

30

35

40 45 Radiation density, lb/ft3

50

FIG. 4. Gamma ray determination of solids friction loss.

55

60

Refining Developments

Modeling of gas and catalyst flow through the standpipe. As shown in FIG. 5, the standpipe model refers to the no-slip model where a mixture of discrete bubbles flow at the same velocity as the catalyst/gas emulsion within a standpipe. The emulsion phase is defined as a phase having a density corresponding to that at the catalyst’s minimum fluidization velocity, ρo. The modeling neglects friction between the catalyst and standpipe, so the terms density and apparent density become TABLE 1. Phase properties without gas—solids slip Mixed phase

Bubble phase

Emulsion phase

Phase density

ρ

0

ρo

Phase voidage

1 – ρ/ρs

1

1 – ρo /ρs

Phase fraction

1

1 – ρ/ρo

ρ/ρo

Phase velocity

w/ρ

w/ρ

w/ρ

TABLE 2. Phase properties with gas—solids slip Bubble phase

Emulsion phase

Phase fraction

1 – ρ/ρo

ρ/ρo

Phase velocity

w/ρ + Ub

w/ρ

(w/ρ + Ub ) (1 – ρ/ρo )

w (1/ρo – 1/ρs ) + Uo ρ/ρo

Gas contribution to SVV Ut (Total SVV)

synonymous. The sketch on the left is a mixed-phase representation. For purposes of visualizing a mathematical model, the sketch on the right partitions the bubble phase and emulsion phase into separate envelopes within the standpipe, with both phases traveling at the same velocity. Based on this model and the assumption that bubble-phase (gas) density is zero, TABLE 1 shows the phase density, voidage, cross-sectional area fraction and phase velocity in the separate partitions. The terms ρs and w represent the skeletal density of the catalyst and catalyst mass flux through the standpipe, respectively. With the case representing no slip between the gas and the catalyst established, terms for bubble-rise velocity, Ub , and Mixed phase (density = ␳)

Separate phases (density = ␳)

Emulsion phase

Bubble phase (density = 0) Bubble phase

net flow of gas, along with the bubble direction, is downward. If the catalyst velocity in the standpipe is low enough, the direction of the bubble flow and even the total gas flow in the standpipe will be in the upward direction and, therefore, must vent through the standpipe inlet. Inclined standpipes are special cases where significant quantities of gas travel in the form of bubbles along the top side of the standpipe counter-current to the flow of catalyst. At the same time, aeration may need to be added along the bottom of the inclined standpipe to keep the catalyst fluidized as it slides down the standpipe beneath the up-flowing bubble phase. The counter-current flow of bubbles along the top of the standpipe can be easily detected, once suspected. An effective way to visualize this phenomenon is to mostly fill a clear plastic tube with FCC catalyst, cork the ends, and then turn it over a few times to fluidize it; then incline the tube, and tap it to see the bubbles emerge and flow up the top side of the inclined tube. Not surprisingly, coldflow models show the phenomenon graphically. The author has not seen CFD modeling applied to this situation, but, hopefully, it would also mimic the bubble traffic along the top of the pipe. From these simple descriptions of standpipe behavior, opportunities for malfunction are apparent: • If a standpipe operates with a catalyst velocity in an intermediate range where the gas velocity approaches zero, the gas will tend to accumulate in the standpipe and reduce the catalyst head. • If a long slanted standpipe has a bend to the vertical direction near its top, the bubbles traveling up the standpipe may get trapped at the top of the slanted section by the downward flow of catalyst in the upper, vertical section of the line.

Emulsion phase (density = ␳o)

FIG. 5. Standpipe gas/solids flow model.

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w (1/ρ – 1/ρs ) + Ub (1 – ρ/ρo ) + Uo ρ/ρo Hydrocarbon Processing | MARCH 201569

Refining Developments minimum fluidization velocity, Uo , are added in TABLE 2. The velocity of the bubble phase relative to that of the solid phase is captured in the term bubble-rise velocity. The derivation of the equation for total gas superficial vapor velocity (Total SVV) through the standpipe is now described. The key to deriving the equation is recognizing that, to maintain the same overall density as in the no-slip case, the phase area fractions must remain the same as those in the no-slip case after the bubble-rise velocity and minimum fluidization velocity terms are added. The velocity of the bubble phase is set equal to the emulsion-phase velocity plus the bubble-rise velocity. Then, the SVV of the gas in the bubble phase (across the entire stand50 Ub = 1.0 Ub = 2.0 Ub = 3.0 Ub = 4.0

Density, pcf

45

40

35 0.0

0.2

0.4

0.6 0.8 1.0 Superficial vapor velocity, fps

1.2

1.4

pipe area) becomes just the bubble-phase velocity times the bubble-phase fraction. Similarly, the SVV of the gas carried in the emulsion-phase (across the entire standpipe area) is the estimated gas velocity in the emulsion (neglecting slip) plus minimum fluidization velocity, all multiplied by the emulsion phase fraction. Finally, the Total SVV of gas through the standpipe is provided by summing the SVV contributions from the bubble and emulsion phases. The equation for Total SVV can also be rearranged into a second-order polynomial and solved for density as a function of the other variables. Exercise of the equations in TABLE 2 shows that selected bubble-rise velocity plays a major role in the estimation of the Total SVV and density in the standpipe, while minimum fluidization velocity is a very minor term. Matsen disclosed that a bubble-rise velocity of 1.05 ft/sec was determined from independent catalyst bed density measurements at bed SVVs from 0.5 ft/sec to 3.5 ft/sec.5 FIG. 6 shows estimated fluid bed densities as a function of Total SVV and assumes bubble-rise velocities based the emulsion phase being stationary. A comparison of the estimates with available fluidization curves for FCC catalyst shows that the curves at bubble-rise velocities of 3 fps or 4 fps appear more in line with the data over the range of interest in FCC standpipe operations, i.e., 35 lb/ft3 to 45 lb/ ft3. Therefore, a bubble-rise velocity of 3.5 fps is selected for use in the following examples. 2.00

FIG. 6. Application of model to static fluid bed.

Emulsion-phase velocity, fps

2.00 0.00

1.00 Ub = 3.5 fps w = 0 lb/ft2s w = 40 lb/ft2s w = 80 lb/ft2s w = 120 lb/ft2s

Gas SVV from emulsion-phase, fps

4.00

w = 160 lb/ft2s w = 200 lb/ft2s w = 240 lb/ft2s

0.00

-1.00

-2.00

-2.00

-3.00

-4.00

-6.00 -8.00 30

Ub = 3.5 fps w = 0 lb/ft2s w = 40 lb/ft2s w = 80 lb/ft2s

-4.00 -5.00

32

34

36

38

40 42 Density, pcf

44

46

48

30

32

34

w = 120 lb/ft2s w = 160 lb/ft2s w = 200 lb/ft2s 36

38

50

w = 240 lb/ft2s

40 42 Density, pcf

44

46

48

50

FIG. 9. Emulsion-phase contribution to total SVV.

FIG. 7. Emulsion-phase velocity. 2.00

4.00

1.00 Gas SVV from bubble-phase, fps

Bubble-phase velocity, fps

2.00

0.00

0.00

-1.00

-2.00

-2.00

-4.00

Ub = 3.5 fps w = 0 lb/ft2s w = 40 lb/ft2s w = 80 lb/ft2s w = 120 lb/ft2s

-6.00 -8.00 30

32

34

36

38

40 42 Density, pcf

FIG. 8. Bubble-phase velocity.

70MARCH 2015 | HydrocarbonProcessing.com

44

-3.00

w = 160 lb/ft2s w = 200 lb/ft2s w = 240 lb/ft2s

46

48

Ub = 3.5 fps w = 0 lb/ft2s w = 40 lb/ft2s w = 80 lb/ft2s w = 120 lb/ft2s

-4.00

50

-5.00

30

32

34

36

38

40 42 Density, pcf

FIG. 10. Bubble-phase contribution to total SVV.

44

w = 160 lb/ft2s w = 200 lb/ft2s w = 240 lb/ft2s 46

48

50

Refining Developments

LITERATURE CITED 1 Squires, A. M., “The Story of Fluid Catalytic Cracking,” First International Conference on Circulating Fluid Beds, Technical University of Nova Scotia,

Halifax, Nov. 18–20, 1985. Reichle, A. D., “Fluid Cat Cracking—Fifty Years Ago and Today,” NPRA Annual Meeting, New Orleans, Louisiana, March 22–24, 1992. 3 Mott, R. “Troubleshooting Standpipe Flow Problems,” Catalagram 83, W. R. Grace & Co, 1992. 4 Matsen, J. M., “Some Characteristics of Large Solids Circulation Systems,” Fluidization Technology, D. L. Keairns, Ed., Hemisphere Publishing Corp., Washington, D.C., 1976, Vol. 2, pp. 135–149. 5 Matsen, J. M., “Flow of Fluidized Solids and Bubbles in Standpipes and Risers,” Powder Technology, 1973, pp. 93–96. 2

2.00 1.00 0.00 Total SVV , fps

and 8 show the emulsion-phase and bubble-phase velocities as a function of standpipe density and mass flux assuming a bubble-rise velocity of 3.5 fps. The emulsion phase velocity is always in the downward direction when circulating catalyst, but the direction of the bubble phase can be up or down depending on the mass flux and assumed density. FIGS. 9 and 10 show the contributions of the emulsion-phase and bubble-phase gases to the Total SVV. The contribution of the emulsion-phase gas to the Total SVV velocity is always in the downward direction when circulating catalyst, but the direction of the bubble-phase gas contribution to the Total SVV can be up or down depending on the mass flux and assumed density. At higher densities, the bubble-phase gas contributes less to the Total SVV because the bubble-phase fraction is relatively small. FIG. 11 shows the estimated Total SVV, which is the sum of the contributions from the two previous figures. When bubble-rise velocity is included in the model, the challenge of low-flux standpipe operation becomes apparent. As the absolute velocity of the gas in the standpipe approaches zero, the gas will tend to accumulate in the standpipe and very little aeration can be tolerated. The charts explain why the conventional wisdom is to avoid operating vertical FCCU standpipes in the lower-flux regions. FIGS. 7

-1.00

-2.00 -3.00

-4.00 -5.00

30

32

34

36

Ub = 3.5 fps w = 0 lb/ft2s w = 40 lb/ft2s w = 80 lb/ft2s

38

40 42 Density, pcf w = 120 lb/ft2s w = 160 lb/ft2s

44

46

48

50

w = 200 lb/ft2s w = 240 lb/ft2s

FIG. 11. Total gas SVV through the standpipe.

UPCOMING WEBCAST: March 18, 2015

10 a.m. CDT / 11 a.m. EDT

Ensuring Operations Effectiveness through Operator Training Simulators Operators struggle today with increasingly complex plants with fewer people responsible for even more tasks. Control room and field operators require extensive DCS and process training and have limited to no experience. Under this premise, companies must be able to easily test control applications and complex control strategies, reduce start-up time, and establish long-term training strategies. One of the best indicators of the efficiency and success of any organization is the level and depth of its personnel training. As operators and personnel switch jobs and/or migrate between various operations, technology holds the key to engaging the next generation of operators. Simulation & Training solutions from SimSci enable continuous sustainment of simulation and training for your assets and operators. This provides: • Improved plant safety & operational excellence

• Reduced capital expenditure

• Faster commissioning

• Increased profitability

Speaker: Steven Sendelbach, Principal Consultant, Optimal Process Solutions

Moderator: Stephany Romanow, Editor, Hydrocarbon Processing

Steven Sendelbach has more than thirty years industry experience including approximately twenty-five years in both dynamic simulation applications and operations effectiveness. Much of his technical work has been performed for ABB Simcon, Invensys (now Schneider-Electric) and since 2011 as founder of Optimal Process Solutions. Hydrocarbon Processing | MARCH 201571

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Portable Ultrasonic Flow Meters Select 72 at www.HydrocarbonProcessing.com/RS

Process Control H. KIM, SK Innovation, Ulsan, South Korea; and G. FANNIN, Bartec Benke GmbH, Reinbek/ Hamburg, Germany

Optimize online monitoring of base oil Latter-model vehicles and new automotive engine designs Online monitoring methods. There are many different types now require higher-quality lubrication oils, such as Groups II and of online/inline viscometers that can be applied. However, it can III. Demand for Group II/III base oils is increasing. To capitalize be proven that systems in compliance with ASTM D445 provide on the greater demand for lubricating oils, refiners are ramping up capacity to yield LBO plant more paraffinic base oils. Quality control to UCO Lube base VGO monitor base oils includes online viscosity HCU IDW HDF oil measurements. This case history investigates how a South Korean refinery installed a new online viscosity measurement sysHydrotreating tem to improve quality control for base oils. Demetallization (HDM)

–

–

–

–

–

=

–

=

–

–

–

–

=

–

–

–

–

=

–

–

–

=

FIG. 1. Overview of LBO process—Part 1.

LBO plant VGO

HCU

UCO

IDW

Isomerization • Improve cold properties (reduce P/P) • VI and low pp lube oil

Lube base oil

HDF

Aromatic saturation • Saturate PNA • Improve color and stability

CH3–C–(CH2)x–CH3

C–C Benzene

C + 3H2

ជ

C

C–C

C + Heat C–C Cyclohexane

–

C=C

–

CH3

C

–

C

=

C

–

C

–

CH3–CH2–(CH2)x–CH3

–

[C–C–C3 –C–C3–C–C2]2

=

ply has been dominated by US refiners. As growth in vehicle sales in China and India surges, Group II/III base oil production is expected to replace Group I facilities to meet new market requirements. Also, Group I oil plants will be upgraded to produce Group II oils. Refiners are already taking steps to increase production, with a number of new Group II/III base oil plants recently started up or under construction. Consequently, the marketplace has become more pricecompetitive, with refiners looking for opportunities to improve efficiencies in lube oil processes. One method to optimize base oil production is through using accurate and reliable online analysis techniques. Improved process monitoring reduces product giveaway and increases the yield of higher-value products.

=

Supply base. The paraffinic base oil sup-

–

industrial output in Asia, combined with changes in automotive engine designs to comply with tightening environmental regulations, has created new demand for Group II/III base oils. In the US, government mandates will increase the corporate average fuel economy for gasoline engines by over 50%, beginning with 2016 models. In the EU, late-model vehicles must decrease carbon dioxide emissions by over 25%.

Fe-naphthanate + H2S + H2 FeS + hydrocarbon + H2O + Heat ជ Hydrocracking Olefin saturation -C = C - H2 - H2 -C- C- + Heat ជParaffin Olefin C–C C–C Desulfurization (HDS) C – C + 6H2 C 4H10 + C7H16 + Heat -C - S -S - C - + 3H2 -C-H + 2H2S + -C - H - Heat C7H15 – C ជ C – C C + Ciso ជ H/C C C=C C iso C7 Disulfide H/C CH3 4 C–C Denitrification (HDN) MCH CH3 C–C C C + 3H2 -C4-H8 + NH3+ Heat ជ N Pyrrolic Butane Aromatic saturation (HDA) C=C C–C C C + 3H2 C ជ C – C C + Heat C–C Cyclohexane Benzene

–

Base oil outlook. Dramatic growth in

CH3

FIG. 2. Overview of LBO process—Part 2. Hydrocarbon Processing | MARCH 201573

Process Control more precise control of lube oil processes. Better control increases revenue. For example, a 1% error in product viscosity can cause a blend adjustment; such “fixes” can increase product cost by €0.01/gal. For a large lubricant manufacturer, such errors can result in annual revenue losses of €900,000.

(CDWU) and some facilities for utilities and offsites, as shown in FIGS. 1 and 2. The unconverted oil (UCO) feed from the HCU is introduced to the vacuum tower, and then separated to distillates and transferred to intermediate tanks. The distillate from the intermediate tank is sent to the CDWU and converted to LBO, which is sent to the product tank.

Overview of LBO process. The lube base oil (LBO) plant

produces a range of Group III base oils with feed from the hydrocracking unit (HCU). The feed consists of streams from the vacuum distillation unit (VDU), catalytic dewaxing unit VDU • Feed: UCO • Vacuum distillation by viscosity of UCO VDU

CDWU • Isomerization reactor Improvement of low temp. pp • Stell reactor Improvement of color and light stability Ism

HDF Vacuum column

UCO

Why use online ASTM D445 viscosity analyzers? SK Innovation was seeking a kinematic viscosity analyzer instead of an absolute viscosity analyzer. Specifications for the new analyzer included higher accuracy and repeatability to increase product yield of higher-value components for the complex’s new LBO plant. The selected ASTM D445 process viscosity analyzer is capable of measuring kinematic and absolute viscosity, as shown in FIG. 3. The unique feature of this viscosity analyzer is that the capillary temperature is controlled to +/– 0.02 K according to ASTM D445.1 The temperature control is the single most important TABLE 1. Types of API lube base oil

Base oil Kinematic viscosity analyzers distillates

Kinematic viscosity analyzer products

FIG. 3. Locations of viscosity analyzers in SK lubricants at the Ulsan complex.

Base oil category

Sulfur, %

Saturated, % Viscosity index

Group I

> 0.03

and/or

< 90

80 to 120

Group II

≤ 0.03

and

≥ 90

80 to 120

Group III

≤ 0.03

and

≥ 90

≥ 120

Group IV

All polyalphaolefins (PAOs)

Group V

All others not included in Group I, II, II or IV

TABLE 2. Kinematic viscosity readings at 100°C for different grades of LBOs over a 12-hr test run Lube base oil grades

109.2 109.0 108.8 108.6 108.4 108.2 108.0 107.8 107.6 107.4 107.2 107.0 106.8 39.8

6.612

< 0.0073

0.004

Grade 150D, with wax, cSt

7.03

< 0.008

0.004

Grade 100D, with wax, cSt

4.19

< 0.005

0.003

Grade 100N, wax free, cSt

4.226

< 0.005

0.003

Viscosity temperature relation due to ± 0.1 K at 40°C According to ASTM D repeatability base oils, (max. 0.11%) 0.0011 x 108 cSt at 40°C max. allowed deviation, ± 0.119 cSt => green lines Due to temp. inaccuracy of ± 0.1 K deviation: ± 0.56 cSt (± 0.52% => red lines

Base oil Group II

39.9

40 Temperature, °C

40.1

40.2

FIG. 5. Kinematic viscosity/temperature variation due to +/– 0.1 K at 40°C.

74MARCH 2015 | HydrocarbonProcessing.com

Repeatability Repeatability according to results of viscosity ASTM D445 analyzer readings

Grade 150N, wax free, cSt

Kinematic viscosity, cSt

Kinematic viscosity, cSt

FIG. 4. Kinematic viscosity readings at 100°C for 150N grade of lube base oil over a 12-hr test run.

Average reading of viscosity analyzer

12.27 12.26 12.25 12.24 12.23 12.22 12.21 12.20 12.19 12.18 12.17 12.16 12.15 12.14 12.13 99.8

Viscosity temperature relation due to ± 0.1 K at 100 °C According to ASTM D repeatability base oils, (max. 0.11%) 0.0011 x 12.20 cSt at 100°C max. allowed deviation, ± 0.134 cSt => green lines Due to temp. inaccuracy of ± 0.1 K deviation: ± 0.03 cSt (± 0.26 % => red lines

Base oil Group II

99.9

100 Temperature, °C

100.1

FIG. 6. Kinematic viscosity/temperature variation due to +/– 0.1 K at 100°C.

Process Control parameter for obtaining accurate and precise kinematic viscosity measurements. This is especially true for petroleum products, as the rate of viscosity per unit temperature is significantly greater than with other products. Thus, a slight variation in temperature can have a very large effect on the viscosity of the fluid. The viscosity analyzer, with its precise temperature control design, has provided readings that show that the analyzer meets and exceeds the requirements of ASTM D445 (see TABLE 1 and FIG. 1). From TABLE 2 and FIG. 2, a 0.1K variation in temperature

will cause the kinematic viscosity to change by 0.56 cSt, which represents a 0.52% deviation at the measured value of 108 cSt at 40°C. Since ASTM D445 allows for a maximum deviation of 0.11%, a +/–0.1 K temperature control of any sensor or measuring device is not acceptable. With the new inline viscosity analyzer, payback was possible within two months. LITERATURE CITED Complete literature cited available online at HydrocarbonProcessing.com.

TABLE 3. Deviation of kinematic viscosity and index by temperature accuracy of ± 0.1 K Medium

Kin. visc. at 40°C, cSt

Kin. visc. at 100°C, cSt

Visc. index

108

12.

103

Kin. visc. at 39.9°C, cSt

Kin. visc. at 99.9°C, cSt

108.56

12.23

Kin. visc. at 40.1°C, cSt

Kin. visc. at 100.1°C, cSt

107.44

12.17

Kin. visc. at 39.9°C, cSt

Kin. visc. at 100.1°C, cSt

Visc. index

108.56

12.17

102.03

Deviation in cSt by 0.1 °C

0.56

0.03

not applicable

Deviation in % by 0.1 °C

0.52

0.25

0.94

ASTM D445 requirements max. deviation, %

Max. 0.11

Max. 0.11

**

Viscosity analyzer repeatability for base oils, %

0.06–0.11

0.06–0.11

Max. 0.20

Base Oil Group II

Base Oil Group II calculated—ASTM D341

Base Oil Group II calculated—ASTM D341

Base Oil Group II calculated—ASTM D341

**Note: According to ASTM D22702—If the viscosity index calculated for a given sample using kinematic viscosity measurements from different test methods are in disagreement, the values calculated from Test-Method D445 measurements shall be accepted.

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Hydrocarbon Processing | MARCH 201575

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Rotating Equipment R. SMITH and S. SHAW, Aesseal Plc, Rotherham, UK

Contain ‘normal’ leakage from primary seals Dry containment seals have gained popularity over the last few decades and provided reliable service. The refinery sector has used this sealing technology to limit fugitive emissions in a cost-effective manner by not incurring the cost of liquid dualseal systems. Little has been written about monitoring the condition of dry containment seals during operation, or how they behave in the event of high levels of leakage from a primary seal. These issues, and comparisons with other sealing options, are discussed here. Secondary dry containment seals. The purpose and underlying principles of secondary dry containment seals are easy to grasp. A secondary seal is used on process pumps to prevent normal primary seal leakage from escaping to the ambient atmosphere. Instead, this leakage is diverted to a liquid collection or vapor recovery system. The American Petroleum Institute (API) 682 standard requires secondary containment seals to contain pump process fluid for eight hours in the event of a primary seal failure. The containment seals fitted in the 1990s are often used in conjunction with simple piping arrangements, which give little to no indication of seal condition. API 682 provided for improved piping plans in 2002. The 4th edition of the standard, published in May 2014, further improves seal effectiveness by stipulating the mandatory use of transmitters, providing users with a better indication of the condition of the inner seal. However, this transmitter deployment does not provide an indication of the integrity of the containment seal. In the event of high leakage from a primary seal, the operator will not know if the containment seal is effective. In such a fault condition, the levels of leakage from containment seals are not commonly understood by many operators. Static manual testing is the only way to test the integrity of containment seals, but this process has not been universally adopted by the industry. At present, the API requires the containment seal to withstand full chamber conditions for a period of eight hours. By comparison, it is possible to simultaneously monitor the condition1 of both inner and outer seal face pairs in dual-wet seals. If the seals are well designed, loss of containment will not occur, even with high levels of leakage from either the primary or secondary seal. Dry containment seals were originally selected by owner/ operators because of their perceived lower installation and operating costs. However, as containment plans have developed to become safer, the seals’ competitive cost advantage has been eroded, and the safer technology of dual-wet seals now represents the lowest overall cost solution.

Seal history. In the late 1980s and early 1990s, users of pump mechanical seals in the oil and gas industries became increasingly concerned with the levels of emissions from single mechanical seals. There was also concern regarding containment of pump fluid in the event of the single seal (FIG. 1) failing in service. Leakage from a failed single seal could be controlled to some extent with a bushing, but leakage rates would be significant. Dual seals were developed to overcome these two issues. Early dual seals were typically organized in a tandem arrangement with a buffer or barrier liquid between the interspace. The barrier/buffer would be circulated around a reservoir; the reservoir level required monitoring and occasional replenishing. Dry containment seals were conceived in an attempt to simplify dual seals (FIG. 2). With no barrier/buffer fluid to replenish, operational savings were realized. The associated pipe work was also perceived to be simpler to install at a lower cost. There were no formal piping plans for use with containment seals, and, as a result, it was left for design engineers to configure. The

FIG. 1. Typical traditional single seal.

FIG. 2. Typical legacy containment seal. Hydrocarbon Processing | MARCH 201577

Rotating Equipment normal practice was to connect the leakage port to a contained drain system or, sometimes, to a vapor recovery system. A piping system similar to that in API’s Plan 65 was implemented (FIG. 3), where an orifice is used on the drain connection. In the event of high leakage from the primary seal, alarms would typically trigger at 1 bar (14.5 psi). A relatively high flowrate from the primary seal is required to activate the alarm. Assuming a 3.2-mm orifice plate API minimum size was used, a leakage flowrate of approximately 4.5 l/min. would be required to activate the alarm. Some operators might use a pressure alarm, while others might use a small vessel with a level switch, which is almost identical to a Plan 65 solution. The key difference is that a Plan 65 solution is intended for use with a single seal with a bushing, not a secondary containment seal. One of the operational problems with Plan 65 and its variant is that the orifice is potentially blocked, particularly on waxy or contaminated surfaces, causing false alarms. Incorporation into API standards. In 2002, dry containment seals were recognized in the 2nd edition of API 682. A series of piping plans offered to take leakage to a safe collection point. Plan 75 is used for pumped fluids where normal leakage would be condensing or mixed-phase fluid at ambient conditions. Plan 76 is used where the normal pump fluid leakage would vaporize in amTo vent (not always applied) PS

Seal

Typical pressure switch set to trip at 1 bar rising

Orifice plate calculation Pressure drop for a given flowrate P1 – P2 = rho × 0.5 × (Q/(C × A))2 Density 835 kg/m3 mm Area on m3 Orifice diameter 3.2 8.04E–06 0.62 C (Orifice coefficient) l/min m3/sec Flow 4.6 7.67E–05 bar pa Pressure drop (P1–P2) 0.99 98699.02

Brent crude has an API gravity of approximately 38.06 To open/closed and a specific gravity of approximately 0.835 drains

FIG. 3. Historic and current practice: Typical early piping arrangement (Plan 65) with pressure switch.

bient conditions. Additionally, Plan 72 N2 quench can be used to assist by sweeping the normal leakage to the collection location. In Plan 75 (FIG. 4), leakage escape from the inner seal is restricted by the containment seal and routed to the drain line. The collector accumulates any liquid, while vapor passes into the vapor collection system.1 Assuming that the leakage is predominantly condensing (FIG. 5), a visual level indicator on the collector is used to determine when the collector must be drained. If the user specifies the option for a level transmitter, the inner seal liquid leakage rate can be monitored remotely. As the leakage collects, the collection system will require draindown.2 Trending time intervals between draindown interventions provides the user with another clear indication of the condition of the inner seal. If the leakage is predominantly vaporizing, an orifice in the outlet line1 of the collector restricts flow so that high leakage of the inner seal will cause a pressure increase, triggering the pressure switch or transmitter to alarm at a gauge pressure of 0.7 bar (10 psi). The block valve in the outlet upstream of the orifice isolates the collector for maintenance. It may also be used to test the inner seal by closing while the pump is in operation, with respect to the time/pressure buildup relationship in the collector. Plan 76 description and limitations. The Plan 76 system (FIG. 6) is intended for services where no condensation of the inner seal leakage or from the collection system will occur. Should liquid accumulate in the containment seal chamber, excessive heat could be generated, leading to hydrocarbon coking, blistering of the seal face and possible seal failure. In Plan 76, leakage from the inner seal is restricted from escape by the containment seal and goes out via the containment seal vent. An orifice in the outlet line of the collector restricts flow so that high leakage of the inner seal will cause a pressure increase and trigger the pressure transmitter to alarm at a gauge pressure of 0.7 bar. The application of Plan 76 is dependent on temperatures and actual atmospheric pressure. A review of vapor pressure curves would indicate that, in higher altitudes, Plan 74 is limited to light hydrocarbons. In tropical climates, Plan 76 has a broader application group. FIG. 5 provides the application areas for Plans 76 and 75, based on the minimum flare backpressure and minimum ambient temperatures. Vapor pressure curves

100

Vapor pressure, bara

1 0.1

Typical flare back pressure

Carbon dioxide 10

Propane

Ethylene up

n atio

Cyclohexane

gro

plic

p

6a n7

Pla

Plan 75 application group

0.01 Min. ambient Pentane Butane temperature 0.001 -150 -130 -110 -90 -70 -60 -10 -10 10 30 50 Temperature, °C

FIG. 4. Distributed control system (DCS) with Plan 75.

78MARCH 2015 | HydrocarbonProcessing.com

FIG. 5. Vapor pressure curves.

70

90 110 130 150 170

Rotating Equipment Containment seal integrity monitoring. In the event of a primary seal failure, the integrity of a containment seal is crucial to prevent process fluid escape. At present, no dynamic method for the condition monitoring of containment seals exists. A periodic static pressure test method was proposed by Bowden and Fone.3 Both Plan 76 and Plan 75 have test connections available for statically pressurizing the containment chamber and for measuring pressure decay over time. With the containment chamber isolated, the proposed method suggests an acceptable pressure decay of 0.14 bar over 5 min. Containment seal integrity is on the frequency of this test. Bowden/Fone3 suggest that a weekly check will ensure confidence in the containment system. Periodic testing within the industry appears to be done on an ad hoc basis, or not at all. Weekly testing is impractical and may create other risks in the form of exposure to personnel carrying out the test in production areas.

ing arrangement. The choice between the two technologies is a trade-off between their features, as summarized in TABLE 1. Plan 72 description. This plan is used with dry containment seals (FIG. 8). An inert buffer gas (N2) is injected through a port adjacent to the outer dry containment seal. The main purpose of Plan 72 is to “sweep” any leakage that comes across the primary seal away from the secondary (outboard) seal. Any “sweep gas,” together with process fluid leakage, would go to a designated location, either a designated vent (Plan 76) or a liquid collection system (Plan 75). Some operators have experienced problems where the N2 flow from a number of Plan 72 systems affects the flare system. Comparison with other dual-seal designs. Plan 52 (FIG. 9) is a wet containment seal where a buffer fluid (liquid) fills the interspace between the primary containment seal and the secondary containment seal. This plan is intended to be connected

Two types of containment seals. Contacting and non-contacting (sometimes referred to as gas lift) technologies are accepted within the API 682. The standard does not differentiate between the two technologies, giving them the same coding. Dry contacting technologies use seal face geometries and materials that allow a rubbing contact mechanical seal face pair. Dry non-contacting technologies are designs where the mating faces have microface features to intentionally create fluid dynamic (usually gas) separating forces to sustain a specific separation gap. Significant performance differences are evident between the two technologies. The API 682 4th edition does provide some details on the expected leakage rates from containment seals in Annex F. FIG. 7 illustrates that the containment performance of a non-contacting design during a primary seal failure will be little better than a single seal with a segmented floating bushTABLE 1. Containment seal technology comparison Contacting containment type Advantages

Limitations

High levels of containment in the event of primary seal failure

Will wear (> 25,000 hr min. API requirement)

Low levels of emission (normal operation)

Speed and/or size restricted Not tolerant of flare upset (overpressurizing)* rubbing friction causing temperature rise and high wear

Non-contacting (gas lift) containment type Advantages

Limitations

Virtually no wear

Limited containment in the event of primary seal failure

Can be used at higher speeds and larger shaft diameters

Higher levels of emissions in normal operation; emissions meet API 682 requirements of < 1000 ppm**

Tolerant of flare upset (over-pressurizing)

Face features vulnerable to clogging in some environments, congealing or abrasive leakage**

* If seriously abused (containment chamber blocked in), Bowden-Fone claim potential ignition source ** Can be minimized by use of Plan 72 N2 quench

FIG. 6. DCS with Plan 76.

Contacting containment 0.1 seal Non-contact containment (gas lift) seal

45

Segmented floating bushing (single seal)

160 0

20

40

60

80 100 Leakage, cc/min

120

140

160

180

FIG. 7. Generalized comparison of leakage rates for 50-mm size, 3,000 rpm and with water at 2.75 barg. Hydrocarbon Processing | MARCH 201579

Rotating Equipment to a flare system. The 4th edition of API 682 specifies transmitters for both pressure and level. Plan 52 offers a simultaneous means of condition monitoring of the primary and secondary containment seals. A rise in liquid level in the tank, or an increase in pressure above the flare, would indicate high leakage from the primary seal. A reduction in liquid level would indicate high leakage from the secondary containment seal. The limits of Plan 52 are described in the 3rd edition of API 682, in a tutorial in Annex A: Plan 52 works best with clean, non-polymerizing, pure products that have a vapor pressure higher than the buffer system pressure. Leakage of higher-vapor-pressure process liquids into the buffer system will flash in the seal pot, and the vapor can escape to the vent system. Inner seal process liquid leakage will normally mix with the buffer fluid and contaminate the buffer liquid over time. Maintenance associated with seal repairs, filling, draining and flushing a contaminated buffer system can be considerable.2

FIG. 8. DCS with Plan 72.

FIG. 9. Wet containment seal with buffer fluid, per Plan 52.

80MARCH 2015 | HydrocarbonProcessing.com

Fundamentally, if operated and designed correctly, Plan 52 is limited to the same application group as Plan 76 and is unsuited for process fluids, which condense at ambient conditions. Pressurized dual seals are becoming increasingly common within the industry. The cost of the supporting systems has become more comparable with unpressurized containment seals, especially when considering the cost of utility connections. The principal difference is that, with a pressurized dual-sealing system, both primary and secondary seals will be sealing a clean, nonhazardous barrier fluid, as opposed to an unpressurized containment seal where the system is managing the hazardous (and/or contaminated) leakage from the primary seal. The barrier fluid of a pressurized dual seal can be noncompressible liquid (typically Plan 53A, B or C) or compressible gas (Plan 74). Another safety feature of pressurized dual seals is that, in the event of a pump being accidently dry run (not an uncommon occurrence in tank farm product transfer or offloading), both seals are lubricated by an external barrier fluid and will survive. Liquid pressurized dual seals may run warmer, but survive the event. Plan 53B description. Quickly becoming the most popular solution (FIG. 10), Plan 53B is favored by many users and operators because it does not require connections to any external utilities if an air-cooled system is adopted. The barrier fluid is pressurized in a bladder accumulator with an N2 precharge. The bladder accumulator directs the barrier fluid to the seal cooling circuit, where the barrier fluid is pumped around the cooling circuit via an integral pumping ring within the seal assembly. During normal operation, controlled leakage of barrier fluid will enter the process fluid across the primary seal and to the atmosphere across the secondary seal. Pressure is monitored, and, as the pressure decays over time, barrier fluid will be recharged either manually or by an automated top-up system. The required top-up frequency provides owners/operators with a clear indication of seal condition. In-

FIG. 10. Dual seal with popular and cost-effective Plan 53B.

Rotating Equipment creasing refill frequency would provide an early warning of seal condition deterioration. With a properly designed dual seal, in the event of major leakage from either the inner or outer seal, the process will be contained. With excessive leakage from the primary seal, the barrier fluid circuit pressure would become equal to the seal chamber pressure. The pressure would signal an alarm, but if the alarm was ignored for an extended period of time, then the outer seal would remain intact and act as a backup seal for a while. If the alarm was further ignored, the barrier fluid cooling circuit would become contaminated with process fluid over time. In the event of excessive leakage from the secondary containment seal, provided the inner seal is hydraulically double balanced, the inner seal will contain the process fluid. Plan 53B is perhaps the safest of all the dual-seal plans, with the highest degree of fault tolerance. Plan 74 description. Plan 74 requires a constant flow of N2 , and the overall condition of both inner and outer seals can be continuously monitored by observing the N2 flowrate. In the event of either a primary or secondary seal having excessive levels of leakage and the available N2 flow being unable to maintain pressure, some loss of containment will occur, as the seal faces are not designed to run on liquid.

System cost comparisons. Typical containment seals are

compared against other popular dual-seal arrangements in Various scenarios are presented with relevant alarm strategies and the effect of the condition. A traffic light color coding red-amber-green (RAG) illustrates areas of concern. In particular, TABLE 2 focuses on a major event where the seal leakage is high. The nature of this event is not relevant, but could be caused by normal wear, abnormal wear due to abrasives, component failure, seal hangup, etc. FIG. 11 compares the installation costs of different dual-seal systems and is offered as a guideline, as costs vary considerably with the level of specification. If only seal system hardware costs are considered, pressurized dual-seal systems would be considered more expensive; however, this is an industry-wide misconception, as the true cost of installation includes the cost of utilities hookup. When utilities connection costs are considered, containment seals do not fare as favorably, and Plan 75 may be one of the most expensive. Pressurized dual-seal Plan 53B costs can vary considerably, but they compare very favorably because utilities connections are not required. One view is that containment seals do not incur high operating costs. This may be true if no testing of containment seals is undertaken; however, this is a potentially unsafe working practice. If best practices are adopted and containment seals TABLE 2.

TABLE 2. Fault tolerances dual-seal comparison RAG chart Scenario Condition monitoring leakage detection API plan

Technology

Current historic practice

Contacting containment

Current historic practice

VOC emissions

Catastrophic failure consequence No liquid in seal chamber

Primary seal

Secondary seal

Primary seal

Secondary seal

Good

Leakage would need to exceed 4.5 gal/min to alarm

Manual air test (pump offlinee)

Pressure alarm.a Process leakage to atmos > 0.1 cc/minf

No way of detecting failure

Inner seal fails potentially catastrophically

Non-contacting gas lift

Acceptableb

Leakage would need to exceed 4.5 gal/min to alarm

Manual air test (pump offlinee)

Pressure alarm.a Process leakage to atmos > 45 cc/minf

No way of detecting failure

Inner seal fails potentially catastrophically

Contacting

Good

Leakage detectionc visual unless optional Level Transmitter API 682 4th ed. is specified

Manual air test (pump offlinee)

Level alarm.a Process leakage to atmos > 0.1 cc/minf

No way of detecting failure

Inner seal fails potentially catastrophically

Non-contacting gas lift

Acceptableb

Leakage detectionc visual unless optional Level Transmitter API 682 4th ed. is specified

Manual air test (pump offlinee)

Level alarm.a Process leakage to atmos > 45 cc/minf

No way of detecting failure

Inner seal fails potentially catastrophically

53B

Pressurized dual wet 53B

Zero

Pressure transmitterd

Pressure transmitterd

Pressure alarm. Process fluid will contaminate barrier fluid over time

Pressure alarm. Inner seal will contain the processg

Seal faces lubricated by barrier liquid fluid—Barrier fluid temperature will increase

74

Pressurized dual gas 74

Zero

N2 flow transmitterd

N2 flow transmitterd

High flow alarm. High flow alarm. Seal faces If insufficient N2 flow Inner seal will not lubricated by available, process fluid contain process gas barrier fluid will not be contained by the outer seal

75

75

a Assumes containment seal will contain; many operators do not perform regular period static tests of the containment system b Can be improved by use of plan 72 c Assumes API 682 4th ed. philosophy and use of transmitter; 3rd ed. would rely on trending frequency of the level switch d Assumes fluid is primary condensing (> C5 ) level transmitter optional (API 682 4th ed.)—a switch is optional in earlier editions of API 682 e Most operators do not do this—no reference to this in API 682 or in recommended procedure f  Assumes 50-mm seal/seal chamber pressure of 2.75 bar g Assumes inner seal has reverse pressure capability

Hydrocarbon Processing | MARCH 201581

Rotating Equipment are tested on a regular basis, then the cost of regular testing will be potentially higher than that of maintaining a Plan 53 or Plan 52 configuration. Periodic containment seal testing requires the pump to be static. Plan 53 and Plan 52 systems are normally configured for fluid replenishment while the pump is in operation. Plan 74 potentially offers the most cost-effective option with respect to maintenance costs, as no manual interventions are required. Takeaway. If containment seal costs, including periodic static

LITERATURE CITED American Petroleum Institute, API 682, 2nd Ed., 2002. 2 American Petroleum Institute, API 682, 3rd Ed., 2004. 3 Bowden, P. E. and Fone, C. J. “Containment seals for API 682 ISO 21049,” Proceedings of the 19th International Pump Users Symposium, Turbomachinery Laboratory, 2002. 4 American Petroleum Institute, API 682, 4th Ed., 2014. 1

52 equipment N2 connection

54 equipment

53C equipment

53B equipment

N2 connection 53A equipment

Flare connection 72/76 equipment

Flare connection and drain 72/75 equipment

52 equipment

Flare connection

pressure testing, are considered, then they do not offer a cost advantage over dual-pressurized sealing systems. They also do

not offer the ability to dynamically monitor the condition of the primary and secondary seals. Users and operators should always consider the entire cost and not just the capital cost of the containment seal when making purchasing decisions. Failure to consider a dual-pressurized seal option can result in greater overall operation costs and reduced reliability. Safety issues are paramount, and dualseal systems offer the highest levels of safe operation.

RICHARD SMITH has worked in sealing technology for the last 28 years, the past 24 years of which have been with Aesseal Plc. Now a director of the company, Mr. Smith is actively involved with the company’s developments in the oil, natural gas and petrochemical industries. He has had a number of papers published, predominantly on the practical application of sealing technology, in international conference journals. STEPHEN SHAW is a chartered engineer and a fellow of the Institution of Mechanical Engineers, as well as a chartered safety and health practitioner. Since 2008, he has been the chairman of Aesseal Plc. He was also appointed group engineering director of AES Engineering Ltd. in 2011.

FIG. 11. Auxiliary system comparative costs/utilities connections.

Order online at GulfPub.com/HPI2015 or call +1 (713) 520-4426. To be published October 2014.

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More Data Than Ever Before. HPI Market Data 2015 is the hydrocarbon processing industry’s most trusted forecast of capital, maintenance and operating expenditures for the petrochemical, refining and natural gas/LNG industries. Produced annually by the editors of Hydrocarbon Processing and featuring data provided by governments and private organizations, this comprehensive resource gives critical insight into HPI market trends, spending and activity.

Obtain HPI Market Data 2015 to: • Plan strategically for 2015 and beyond • Locate new global growth opportunities • Discover how spending trends by sector will impact your company 82MARCH 2015 | HydrocarbonProcessing.com

WHAT’S NEW IN CATALYSTS 2015 Special Supplement to

2015 catalyst developments: Innovation and value creation C–84

CORPORATE PROFILES Advanced Refining Technologies C–89 Axens C–91 BASF C–93 CRI Catalyst Company C–95 Criterion C–97 Grace Catalysts Technologies C–99 Sabin Metal Corp. C–101

COVER PHOTO

© alex.pin—Fotolia.com

WHAT’S NEW IN CATALYSTS

2015 CATALYST DEVELOPMENTS: INNOVATION AND VALUE CREATION Hydrocarbon Processing invited major catalyst companies and industry consultants to share their insights regarding innovations and trends for new catalytic technologies. Challenges to be solved. “As challenging as things currently appear in Europe, things in North America are markedly more encouraging; the US is better positioned, with the boon of ‘shale oil and gas,’ although it is consuming more time than anticipated to monetize,” said John Murphy, president of The Catalyst Group Resources (TCGR). “This is due to the compositional differences between shale gas, NGLs and tight oil, and the unprepared infrastructure (plants and pipelines) to deal with the phenomena. The logistical challenges are significant (along with the opportunities). For example, with 15+ new crackers announced for construction in the 2015–2018 period, there is not enough EPC capacity for them to all be built within this timeframe.” A number of refinery, petrochemical and commodity chemical plant closures have occurred, and multinational companies are shifting their investments regionally. These trends are likely to continue. Naphtha feedstock cost disadvantages, relative to inexpensive gas, will force moves to specialty chemicals and value-added enterprises to remain competitive, but this will require the rejuvenation and reinvestment in innovation to be sustainable. Brittany McGinley, president of The Catalyst Group (TCG), added that it is clear the industry is at a crucial influx: the rapid and substantial changes that catalyst users and manufacturers have experienced in the last 15 years in both feedstock development and end-product manufacturing location have required successful competitors to have an extremely sophisticated understanding of the entire value chain and to be highly flexible and to continually reposition their product offering to meet market needs. This highly changeable environment has also influenced how market players have developed their near- and medium-term growth strategies. From an organic perspective, catalyst manufacturers and users alike are following two major trends: 2013

2016 28%

35%

25% 40%

6% 13%

14%

$25.3 B

$30.2 B Refining Petrochemicals Polymers

24%

41%

17 %

16%

17%

6%

2019

5%

13%

$33.5 B

Fine chemicals and intermediates Environmental

FIG. 1. Global catalyst value, 2013–2019. Source: TCGR’s “Intelligence Report: Business Shifts in the Global Catalytic Process Industries, 2013–2019.” C–84

WHAT’S NEW IN CATALYSTS | MARCH 2015 | HydrocarbonProcessing.com

• Enhancing and influencing market pull by investigating or developing technology licensing to allow better control of catalyst revenues or by influencing end customer needs by developing catalysts that create unique (and brand-able) product properties • Developing customer intimacy by better understanding end-user (either the product formulator or end consumer) needs and with the offering of highly desirable custom or tolling catalyst business. From an inorganic perspective, consolidations via mergers and acquisitions are expected to continue through 2015, coupled with investments in adjacent and synergistic markets. This will allow market participants to typically focus on three areas: • Enhancing regional presence to allow faster regional product delivery or better local market penetration, such as with increased interest in greater ASEAN • Enhancing product margins by back-integrating into key raw materials such as zeolites and organometallics • Adding new business models such as technology licensing businesses or technical services. According to TCGR’s recently completed biannual industry report titled “Intelligence Report: Business Shifts in the Global Catalytic Process Industries, 2013–2019,” the global merchant catalyst market is forecast to grow from $25.3 B/yr in 2013 to $33.5 B/yr by 2019, with an AAGR of 5.4%/yr, higher than global GDP. The two largest sectors after environmental, which include mobile and stationary sources, are refining, at over $7 B, and petrochemicals, at nearly $5 B, as illustrated in FIG. 1. New developments for the refining industry. “Catalyst and process developments over the last several years have focused on the processing of light tight oil (LTO), increasing distillate selectivity and quality, converting higher amounts of residual oil, and enhancing petrochemical feedstock,” said Murphy. “Dewaxing technology is now receiving more attention, due primarily to LTO processing.” Specific developments include: • All three western FCC manufacturers (Albemarle, BASF and Grace) are promoting LTO catalysts designed to handle these paraffinic feeds and to counteract contaminant metals. • Sinopec China has continued to maintain a minor FCC catalyst presence in the global marketplace, despite no longer having a pricing advantage due to the return of rare-earth prices to near baseline levels. • New reforming catalyst grades from Axens and UOP have been developed to provide additional reformate yield and hydrogen, as well as greater aromatics for petrochemical feed. • With lower-cost hydrogen available in North America, vendors are promoting new high-activity hydrotreating catalysts to maximize saturation and volume swell.

WHAT’S NEW IN CATALYSTS • For low-pressure ULSD units, higher hydrodesulfurization (HDS) activity or more cost-effective catalysts have been introduced. New specialty hydrotreating guardbed catalysts have been brought to market to handle contaminants such as arsenic, iron and silicon. Other refining developments. Grace has developed solutions

to help refiners lower slurry yield, take advantage of distillate crack spreads and to address the trend toward increased residue and opportunity crude processing. Rosann Schiller, director of marketing for Grace Catalysts Technologies, said, “Processing opportunity crudes, along with upgrading the bottom of the barrel into light cycle oil (LCO) and lighter products, are some of the challenges facing refiners looking to maximize the value from their FCCUs. Grace is now expanding its portfolio of catalysts under the ACHIEVE series to address market challenges.” According to Schiller, the ACHIEVE series (100, 200, 300, 400, 800) comprises state-of-the-art catalyst technologies designed to maximize refiners’ profitability. In response to the tight-oil revolution in the US, Grace successfully launched the ACHIEVE 400 FCC catalyst to address the octane debits that were being encountered by refiners. During this research and development (R&D) program, five key catalytic functionalities were developed: • Higher-diffusivity matrices • Dual zeolite technology • Flexible hydrogen transfer • Advanced metals tolerance • Higher activity. Meeting new challenges. Designing the best catalyst systems from these functionalities encompasses the Grace approach to FCC catalyst design. The ACHIEVE formula contains high-diffusivity matrices for deep conversion of the bottom of the barrel and resistance to poisoning from unconventional metals. The latest generation of integral metals traps are used to protect active components from deactivation while preserving coke selectivity and minimizing dry gas production. Additionally, the dual-zeolite feature delivers increased naphtha octane, higher LPG olefins yield, as well as ultra-high activity to help maintain unit heat balance. “The ACHIEVE series was developed as a tailor-made solution and optimized to meet specific refinery opportunities while not exceeding the refinery’s constraints,” said Schiller. “We are proud of our close customer partnerships and a broad product portfolio built on talent, technology and trust. We are ready to work with refiners to select the catalysts with the right balance of operational flexibility, product capability and overall value to meet their requirements.”

THE AUTHORS RIVE TECHNOLOGY, INC DAVID C. ALDOUS joined Rive Technology, Inc., as CEO in 2012. He brings over 30 years of diverse experience in the refining, chemicals and catalyst industries, including over 20 years at Royal Dutch Shell, where he was executive vice president of strategy and portfolio. Mr. Aldous also served as president of Shell Canada Products. He brings deep experience in the catalyst industry from his six years as president and CEO at CRI/Criterion. Prior to joining Rive, he was CEO of Range Fuels. Mr. Aldous holds a BS degree in fuels engineering from the University of Utah and an MBA with distinction from Northwestern University.

CRITERION CATALYSTS AND TECHNOLOGIES SAFA GEORGE is vice president of catalysts technology for Shell and CRI/Criterion. In 1980, he joined Shell Canada’s research group and was appointed section head of refining projects in Shell Canada’s Montreal East refinery. In 1990, Dr. George joined Criterion Catalyst as the technical service coordinator and he became vice president of technical services in 2000. Dr. George was appointed vice president of catalyst technology for Shell and CRI/Criterion in 2009. He holds a BS degree and PhD both in chemical engineering from Imperial College of the University of London, and McGill University, Canada, respectively.

THE CATALYST GROUP BRITTANY MCGINLEY is president of The Catalyst Group (TCG), with over 12 years consulting experience, and currently managing TCG’s operations, strategic initiatives and relationships for its consulting division. Prior to her appointment to vice president in June 2011, she served TCG in the role of project manager, providing project oversight, analyses and key deliverables for client confidential projects as well as multi-client studies. She has been a member of TCG consulting team since October 2008. Ms. McGinley holds a BS degree in business administration from Babson College.

THE CATALYST GROUP RESOURCES JOHN J. MURPHY is the president of The Catalyst Group Resources (TCGR), the information services component of The Catalyst Group (TCG). TCGR monitors and analyzes technical and commercial developments in catalysis as applied to global refining, petrochemical, polymer, fine/specialty and environmental industries. Mr. Murphy develops, manages and contributes to member-directed programs and multi-client studies. He graduated from Bowdion College with an AB degree in chemistry and has an MBA from Lehigh University.

GRACE CATALYSTS TECHNOLOGIES

Advances in hydroprocessing. Criterion Catalysts and Tech-

nologies is launching a series of new hydroprocessing catalysts based on its ASCENT technology platform. The results of an extensive high-throughput experimental program indicate that refiners can expect a 10%–20% increase in activity. Significantly, the gains come without compromising other key features of the catalysts: notably, their limited hydrogen consumption, good physical properties, lower density and ease of regeneration—all of which make ASCENT technology an outstanding

ROSANN SCHILLER is marketing director for Grace Catalysts Technologies, based in Columbia, Maryland. She has been with Grace for 16 years, and has held a variety of roles in FCC technical service, sales, product management and marketing. Ms. Schiller holds an MSE degree in chemical engineering.

HYDROCARBON PROCESSING | MARCH 2015 | WHAT’S NEW IN CATALYSTS

C–85

WHAT’S NEW IN CATALYSTS system for many distillate hydrotreating and cracker feed pretreatment applications. “Although highly active Type II catalysts have taken center stage recently, with Criterion’s class-leading CENTERA technology being a prime example, mixed Type I/II catalysts still have much to offer in terms of all-around performance,” said Safa George, Criterion’s vice president for catalyst R&D. “There are refiners with low- to medium-pressure units or that are short of hydrogen, and they are just as keen to raise conversion, extend run lengths and process tougher feeds. This is why ASCENT has remained a key part of our portfolio for 10 years.” The new catalysts represent third-generation technology. “We started by optimizing the support’s pore structure and then turned to the balance between the metallic [cobalt (Co) and nickel (Ni)] and non-metallic promoters and the molybdenum (Mo) in the catalysts,” said George. “This latest advance is linked to improved dispersion of the active sites on the support and has borrowed from manufacturing techniques used to make CENTERA catalysts. Over time, we have continually enhanced what ASCENT technology has to offer. These latest products border on the activity normally associated with pure Type II catalysts.” The first catalysts offered to customers include CoMo (DC2535) and NiMo (DN-3532) for distillate hydrotreating. The latter is intended for tougher feeds. In a range of tests, NiMo (DN-3532) has shown a sharp increase of about 20% in relative volume desulfurization activity over its predecessor. Criterion is also introducing a new hydrocracker feed pretreatment catalyst, NiMo (DN-3552); it has at least 20% higher desulfurization and denitrogenation activity than the previous benchmark product and does not consume any more hydrogen. “Hydroprocessing is a complex business: no two units are the same, and refiners’ business drivers also vary widely,” said George. “We have to maintain a strong portfolio of catalysts to add value to individual applications.” Newcomer to catalyst development. Rive Technology, a developer of innovative materials-based solutions for catalytic and separations processes in the petroleum refining and chemicals industries, is commercializing the molecular highway zeolite technology for FCC in collaboration with Grace Catalysts Technologies. The molecular highway technology improves the mass transfer into and within the zeolite crystals of catalysts and adsorbents through a series of larger mesopores within the zeolite. In FCCUs, the mesopores, or molecular highways, significantly improve diffusion into and out of the zeolite crystals of the FCC catalyst, leading to improved coke selectivity, enhanced bottoms upgrading, decreased dry gas production, and enhanced C3= and C4= yields. Rive Technology is also working with Zeolyst and Criterion to develop and commercialize hydrocracking catalysts incorporating molecular highway technology. Initial work for middle distillate applications has shown significantly enhanced diesel selectivity. The companies anticipate product availability in 2016. Additionally, Rive continues to work with several leading oil and chemical companies, as well as technology providers to those industries, on additional high-value applications of molecular highway technology. “Rive continues to demonstrate value to refiners through application of molecular highway technology in FCC,” said C–86

WHAT’S NEW IN CATALYSTS | MARCH 2015 | HydrocarbonProcessing.com

David Aldous, CEO of Rive Technology. “With the recent debottlenecking of our supply chain, we expect to see accelerated commercial adoption of our technology within the industry in 2015.” More refining news. Dewaxing technology that favors

isomerization over cracking to preserve diesel stream volume is available from catalyst/process providers such as Haldor Topsøe, Shell/Criterion and UOP/ExxonMobil. Clariant is also a supplier of dewaxing catalysts. All hydrocracking catalyst companies have focused on distillate selective grades for jet/kerosine and diesel. With the recent agreement between Advanced Refining Technologies (ART) and Chevron Lummus Global (CLG), all competitors have catalyst and process connections either inhouse or via agreements and alliances. Slurry hydrocracking using “nano” catalysts offers a step change upward in resid conversion; in particular, the Eni Slurry Technology (EST) process is operating at an industrial level at this time. Use of refinery-type processes based on FCC and hydrotreating technology to produce second-generation biofuels remains a niche application. The continuing global shift from gasoline to distillates and petrochemicals will encourage new products for all catalytic processes. Expansion of hydraulic fracturing will result in the application of LTO catalysts and also to process improvements in regions outside the US. WHAT IS NEW IN PETROCHEMICALS?

According to TCGR’s John Murphy, a number of new process developments have been announced, including: • Aromatics. The main thrust has been to develop new catalysts, adsorbents and process schemes aimed at improving the economics and energy efficiencies of producing primarily p-xylene. Gevo is developing a route to renewable p-xylene. • Organic syntheses. The most significant development in this area is a new BP process to produce acetic acid from syngas that eliminates methanol as an intermediate and avoids the need for corrosive iodides. A novel business/technology development is the production of ethanol from acetic acid, commercialized in China by Celanese, and intended to essentially produce fuel ethanol from coal. • Oxidation. There have been several developments in this category, dealing with productions that are made via oxidation but with processes utilizing different routes. A startup company, Novomer, is developing a route to react carbon monoxide (CO) with ethylene oxide to produce acrylic acid; it is in the early stage of work. Eastman Chemical Co. and Johnson Matthey Davy Technologies have announced a process to produce ethylene glycol from syngas (but not passing through oxalates as an intermediate, as is being practiced in China), starting from coal. • Syngas and derivatives. Haldor-Topsøe A/S has announced several improvements in reforming and low-temperature shift catalysts. For methanol, the news is the resurgence of methanol production in North America, thanks to low-cost shale gas methane,

WHAT’S NEW IN CATALYSTS with plants being moved by Methanex from South America, “mothballed” plants being started up, and new plants being constructed. • Hydrogenation. There have been noteworthy developments in higher-efficiency catalysts for acetylene hydrogenation and the hydrogenation of edible oils and fatty acids. • Dehydrogenation and olefins. Several technologies are now under development in Japan and China to dehydrogenate butenes to butadiene. A novel development by INVISTA and LanzaTech, in New Zealand, is intended to produce butadiene from waste CO via 2,3-butandiol. In ethylene, Braskem, is supporting a demonstration plant by the startup company Siluria, which has announced the development of methane-coupling technology to produce ethylene. Also, ExxonMobil has announced that its new ethylene plant in Singapore can crack crude oil, thus eliminating the need to first produce naphtha for feedstock purposes. • Chemicals from biomass. Many developments are occurring in the area of chemical process technology based on sugars and other biomass feedstocks. The most important developments involve current or planned production plants for bio-ethylene, bio-butadiene, biobutanol and bio-1,3-butanediol: o Bio-ethylene is being produced by at least two organizations—one based on glycerin, a renewable

feedstock; and the other, a Chinese technology based on corn as a feedstock. o Several technologies are being developed, with plants announced to produce bio-butadiene—one via bio-butanol by Cobalt Technologies, and several involving Genomatica via bio-butanediol. o In bio-butanol, two organizations are developing technology to produce isobutanol—Gevo, with an operating plant that was converted from ethanol production; and Butamax, a JV between BP and DuPont, with a similar technology and business plan. o Several projects are under development, utilizing licenses of Genomatica’s one-step process to convert sugars to bio-1,3-butanediol, with BASF and Novamont both building plants. Other organizations including Myriant and BioAmber, are developing routes to biobutanediol, based on converting renewable feedstocks to succinic acid, which is then hydrogenated using Davy Process Technology, which also produce co-products tetrahydrofuran (THF) and gamma butyrolactone (GBL). “In 2015, it is important to focus on market and value creation,” said McGinley. “This will require new products, new geographic markets and new processes/technology using costadvantaged feedstocks. This is not for the faint-hearted; it requires creativity and risk, as well as investment. But some positive signs are finally emerging that justify these changes.”

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Order online at GulfPub.com/GPPD or call + 1 (713) 525-4626. For more information, including sample data, contact Lee Nichols, Director of Data, at Gulf Publishing Company at +1 (713) 525-4626 or [email protected].

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Global leader in hydroprocessing catalysts offering the complete range of catalysts and services

Advanced Refining Technologies 7500 Grace Drive Columbia, MD 21044 USA +1.410.531.4000

www.artcatalysts.com Select 65 at www.HydrocarbonProcessing.com/RS

ADVANCED REFINING TECHNOLOGIES

THE LEADER IN HYDROPROCESSING Advanced Refining Technologies (ART) is the global leader in hydroprocessing catalysts offering a complete range of catalysts and services to the petroleum refining industry. ART’s broad portfolio of catalysts allows us to customize catalyst systems to provide refiners with solutions to their hydroprocessing challenges.

A HISTORY OF PARTNERSHIP Chevron and Grace joined together in 2001 to form Advanced Refining Technologies (ART), with shared goals based on technology expertise, world-class research and development, global manufacturing, and a shared vision to offer a complete portfolio of hydroprocessing catalysts. ART combined Grace’s material science, manufacturing, marketing and sales strength with Chevron’s extensive experience operating its own refineries and leadership in technology, design and process licensing. Starting from a strong base of resid hydrotreating catalysts for Chevron Lummus Global (CLG)-designed units, ART’s portfolio also included ebullating bed resid hydrocracking and distillate hydrotreating catalysts. The joint venture acquired the Orient Catalyst Company’s hydroprocessing technologies and its HOP catalyst product line, and has become the largest shareholder in Kuwait Catalyst Company. ART resid and distillate hydrotreating catalysts are now used in both CLG licensed/designed units as well as units designed by other licensors. Early in 2013 ART fulfilled its vision of offering a complete portfolio of hydroprocessing catalysts when it signed an agreement with CLG giving ART the exclusive right to sell CLG’s hydrocracking and lubes hydroprocessing catalysts to both CLG’s licensees and any other refiners for existing unit refills, regardless of design or licensor. The agreement streamlines hydroprocessing catalyst supply and improves technical service for refining customers by establishing ART as the single point of contact for all their hydroprocessing catalyst needs. CLG’s depth of technical expertise remains available for the refiner who requires process technology and design services.

IMPROVING THE OPERATION AND YIELDS OF REFINERS THROUGH INNOVATIVE CATALYST DESIGN Keeping in step with the ever increasing demand for refiners to produce cleaner and higher quality products, ART continues a strong R&D program to develop cutting edge catalysts. Recent new product launches in the hydrocracking pretreat segment include ICR 513 and ICR 1000 for high HDN activity and improved aromatics saturation. ART also recently introduced several hydrocracking catalysts to meet refiners’ complex needs: ICR 257 noble metal catalyst for naphtha-jet, ICR 214 and ICR 215 for naphtha-jet, ICR 188 for maximum distillate, and ICR 191 which was designed to provide premium performance for distillate or naphtha-jet production. These new catalysts were developed working together with refiners around the world to meet today’s challenging feeds and operating severities all while achieving long, stable operating cycles. ART continues to innovate in the resid segment. ICR 173 was recently introduced for fixed bed resid hydrotreating units, and was designed for deep MCR and sulfur conversion. For ebullating bed resid hydrocracking units, ART recently introduced several technology platforms that can be used in dual catalyst systems to help refiners achieve optimum profitability. The HCRC™ platform combined with the HSLS™ platform in a dual SPONSORED CONTENT

catalyst system allows refiners to attain high resid conversion activity at identical operating conditions while achieving good sediment control. The increased resid conversion, combined with higher contaminant removal, gives higher yields of better quality products and allows for options to maximize conversion at constant operating temperature. For distillate hydrotreating, ART’s SmART® Catalyst System for ultra low sulfur diesel production continues to evolve with the successful introduction of 545DX for higher HDS and aromatics saturation activity over previous generations of NiMo catalysts. For lower pressure applications, a SmART system using 425DX offers higher HDS activity and better stability compared to previous generations of CoMo catalysts. ART also recently introduced 586DX, a new catalyst for the FCC pretreat segment, designed for improved HDS and HDN activity over standard catalysts. ART continues to upgrade its plants to produce these new catalysts and future ones that are currently under development. These products are being designed to help refiners meet the challenges of the expected growth in demand for diesel and other low-sulfur fuels, while continuing to further upgrade the bottom of the barrel. Today and into the future ART is committed to maintaining its leadership position in hydroprocessing.

CONTACT INFORMATION 7500 Grace Drive Columbia, MD 21044 USA (410) 531–4000 www.artcatalysts.com HYDROCARBON PROCESSING | MARCH 2015 | WHAT’S NEW IN CATALYSTS

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Stimulate the heart of your hydroprocessing unit ImpulseTM, the catalyst technology that combines the stability you recognize with the activity you need 4JOHMF
TPVSDF
*40

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 www.axens.net Select 51 at www.HydrocarbonProcessing.com/RS

AXENS

OPTIMIZE YOUR PERFORMANCE WITH AXENS CATALYST TECHNOLOGY Axens is recognized as a worldwide technology benchmark for clean fuels production, conversion solutions, aromatics and olefins production and purification. The combination of the technology and services with the catalyst and adsorbent manufacturing and supply business constitutes an efficient structure that handles market needs as a single source. Currently, Axens offers a complete product range of hydrotreating and hydroconversion catalysts for naphtha, gas oil, vacuum gas oil and residue applications and continues to launch new catalysts to meet high conversion and mild hydrocracking objectives and to produce ultra-low sulfur diesel (ULSD) while maximizing refinery profits.

IMPULSE CATALYST TECHNOLOGY With the worldwide tightening of fuel specifications and increased demand for middle distillates, hydrotreating catalyst technology has become crucial to the refining industr y. As a consequence, Axens has launched a new catalyst technology called Impulse™. Impulse is a complete, high performance family of hydrotreating catalysts which combine stability with high levels of activity. Impulse catalysts allow for even more difficult feedstock to be processed without cycle penalty. They feature higher flexibility, maximum throughput with higher end boiling point and longer cycles. Impulse achieves increased activity by maximizing the amount of the catalytically most active mixed Mo (Ni)/Co sites. Worldwide, 50 orders have been received and 30 refineries are already producing ULSD using impulse. The superior performances obtained have led customers, including many majors, to award Axens with repeat orders.

HRK, HDK AND HYK SERIES HYDROCRACKING CATALYSTS Axens’ hydrocracking solution upgrades a wide range of heavy feedstock to produce the desired slate of products while meeting ultimate quality targets. It relies on catalysts from the pretreating HRK series and the hydrocracking HDK and HYK series which are combined to achieve operator conversion targets. The combination of HRK, HDK and HYK Series squeezes more middle distillates from heavy ends while reaching high conversion levels and excellent products quality.

SYMPHONY REFORMING CATALYSTS Symphony™ is the next generation family of reforming catalysts combining the best in catalyst support and multimetal formulation technologies. Compelling results are achieved for virtually all reforming services: from fixed bed to CCR, low to high density loading, lean to rich naphtha feed and high to low octane severity. Contrasted with prior-generation best-in-class reforming catalysts, Symphony catalysts (PS 100, PR 150, PR 156 and P 152) show step-out improvement in yield, selectivity, coke stability and hydrothermal stability without sacrificing activity, leading to a remarkable increase in unit profitability. After switching to Symphony, even well before end-oflife of the incumbent catalyst, customers have reported payback times of less than 4 months. 20 refineries in the world have selected those high performance products.

SULFUR RECOVERY CATALYST During the last 30 years, Axens’ continuous R&D efforts have contributed to a drastic improvement in the way in which Sulfur is recovered. Axens has, for instance, pioneered the use of titanium dioxide catalysts to boost the efficiency of the Claus unit and has revolutionized the design of Claus tail gas treatment units by introducing low temperature catalysts. Axens provides essential support to its customers and offers a large family of innovative products in the field of sulfur recovery. These range from regular Claus alumina (CR), boosted alumina for COS hydrolysis (CR-3S), pure titanium dioxide catalysts (CRS 31, CRS 31 TL) and BTX management catalysts (CSM 31) to Claus tail gas treatment (TGT) catalysts. Our TGT Co-Mo catalysts, TG 107 and TG 136, have been designed for low temperature processes. While maintaining ideal TGT unit performances, the lowered operating temperature entails significant energy savings and improves the cycle length of the catalyst.

CONTACT INFORMATION 89, bd Franklin Roosevelt - BP 50802 92508 Rueil-Malmaison – France [email protected] www.axens.net

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We create chemistry that lets individual needs love global innovation.

As the global leader in catalysis, BASF draws on the talent and expertise of more than 1,100 researchers working in close partnership with our customers. This collaboration results in innovations that drive new levels of performance and achievement, today and over the long term. When global catalyst innovations help our customers become more successful, it’s because at BASF, we create chemistry. www.catalysts.basf.com Select 79 at www.HydrocarbonProcessing.com/RS

BASF

BASF—THE GLOBAL LEADER IN CATALYSIS Connecting people and ideas to create chemistry for a sustainable future for 150 years

BASF’s Catalysts division is the global market leader in catalysis. The division develops and produces mobile emissions catalysts as well as process catalysts and technologies for a broad range of customers worldwide. The division also provides precious metals procurement, sales and related services. BASF’s Catalysts division expands its leading role in catalyst technology through continuous process and product innovation. Innovation in catalysis is crucial for all our product groups. For mobile emissions catalysts, the focus is on improved products to meet new exhaust gas standards, especially for diesel. For process catalysts and technologies, priority is given to developing new and improved products. For battery materials, the focus is on delivering solutions that can improve energy density and power.

MOBILE EMISSIONS CATALYSTS BASF’s emissions abatement catalysts enable cost-effective regulatory compliance, providing technologies that control emissions from gasoline and diesel-powered passenger cars, trucks, buses, motorcycles and off-road vehicles.

PROCESS CATALYSTS AND TECHNOLOGIES BASF is the leading global manufacturer of catalysts for the chemical industry, with solutions across the chemical value chain as well as intermediates for pharmaceuticals. The business provides oil refining technology catalysts including fluid catalytic cracking (FCC) catalysts, co-catalysts and additives. It also provides polyolefin catalysts and adsorbents, which offer guard bed and catalyst intermediate technologies for purification, moisture control and sulfur recovery.

HOW CAN YOU MAKE TOMORROW BETTER THAN TODAY? 150 years of BASF: Co-create and celebrate. Visit www.creatorspace.basf.com and collaborate with industry experts toward tangible solutions to key economic, environmental and societal challenges.

BATTERY MATERIALS Formed in 2012, the Battery Materials global BASF business unit offers advanced cathode materials to allow higher energy density and increased efficiency by enabling more discharge/ charge battery cycles. It also offers high-purity customized electrolyte formulations that are ideal for automotive battery applications. BASF is the global leader in nickel-metal hydride (NiMH) technology development and licensing. Additionally, it conducts future-generation battery materials research, working alongside BASF’s global R&D network and select third-party development partners.

PRECIOUS AND BASE METAL SERVICES The precious and base metal services global business unit supports BASF’s Catalysts business and its customers with services related to precious and base metals sourcing and management. It purchases, sells and distributes these metals and provides storage and transportation services. It also provides a variety of pricing and delivery arrangements to meet the logistical, financial and price-risk management requirements of BASF, its customers and suppliers. In addition, the business produces precious metal salts and solutions and is a global leader in precious metals recycling and refining.

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CONTACT INFORMATION Americas [email protected] Asia Pacific [email protected] Europe, Middle East & Africa [email protected] www.catalysts.basf.com

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choose wisely. At CRI, we provide catalyst and process solutions tailored for the petrochemical and refining industry. Our technology is an integral part in helping achieve success in a customer's application. Our strengths in R&D, catalyst manufacturing and technical service allow CRI to progress quickly from lab scale to production to customer results. We pride ourselves on developing lasting relationships with our customers through collaboration and successful implementation of catalytic solutions. It is all part of our commitment to delivering innovation.

cricatalyst.com Select 74 at www.HydrocarbonProcessing.com/RS

CRI CATALYST COMPANY

CRI CATALYST COMPANY—YOUR PARTNER FOR OPTIMAL CATALYST SOLUTIONS In an environment with stricter specifications, higher selectivity requirements and challenging economic demands, how can CRI partner with you to deliver higher value? CRI Hydrogenation and Specialty Catalysts, formerly KataLeuna, is a division of CRI which develops and markets hydrogenation and specialty catalysts. With more than 90 years of catalyst development and manufacturing capability in Leuna, Germany, CRI has a wealth of experience in developing and delivering valuable catalyst solutions to the industry. By listening to our customers and partnering with them, CRI has combined the knowledge of its deeply experienced staff, state-of-the art testing facilities and world class manufacturing facilities to develop solutions for the customer’s selective and full hydrogenation needs. The solutions provided include high performance catalyst products designed to address our customer’s specific concerns, such as stability, activity, selectivity, robustness towards operational swings, pressure drop and/or cycle length. In addition, specific tools such as detailed kinetic modeling enable CRI to quickly assess customer’s hydrogenation challenges, and provide optimal solutions.

SELECTIVE HYDROGENATION CATALYSTS CRI offers catalyst for the selective hydrogenation of acetylene, for both front-end and tail-end applications. In front-end applications, CRI acetylene hydrogenation catalysts have proven performance in numerous process designs, including C2 minus, C3 minus, and Raw Gas, in both adiabatic and isothermal reaction systems. The catalysts are characterized by exceptional stability in terms of both selectivity and activity. For C3 streams, CRI offers a portfolio of catalysts for the removal of methyl acetylene and propylene diene (MAPD) for both gas and liquid phase applications. For selective hydrogenation (and isomerization) of C4s in alkylation pretreat streams, the portfolio uniquely includes both palladium and nickel catalyst products for this application. Again, CRI has proven commercial experience for all the various reaction systems designs, including up-flow, down-flow, liquid and gas phase. For the hydrogenation of Pyrolysis Gasoline (Pygas) streams, CRI combines its catalyst knowledge and expertise with operating experience (from Shell in-house Pygas units), process design experience (from Shell Global Solutions’ licensing division) and world-class modeling abilities to become a recognized leader in providing Pygas solutions. A full portfolio of 1st and 2nd stage Pygas catalysts are available to address typical challenges in Pygas unit operations, such as balancing 1st and 2nd stage reactions, pressure drop mitigation, activity optimization, and minimization of aromatic saturation.

FULL HYDROGENATION CATALYSTS A portfolio of catalysts is available for the full hydrogenation of hydrocarbon streams. These catalysts are designed to have high poison tolerance while minimizing the potential for any side cracking reactions. Applications served include C4/C5 streams, benzene saturation and aromatic hydrogenation in light oils to heavy solvents. A full array of catalysts is available, giving customers options for treating a wide range of feed streams. SPONSORED CONTENT

SPECIALIZED HYDROGENATION CATALYSTS CRI offers a wide range of specialized hydrogenation catalysts for use in specific chemical applications, including phenol hydrogenation, alcohol polishing, nitriles to their corresponding amines, poly-alpha olefins and phenyl acetylene to styrene.

PARTNERS CRI brings decades of catalyst experience to its customers with standard or specialized needs. Together with our global technical support group, we look forward to work with our customers, providing tailored solutions, application knowledge, operational and start-up assistance, routine performance monitoring, and/or additional technical services as needed to help get the most out of the customer’s application. At CRI, by “Delivering Innovation”, we are committed to improving your processes. Contact us today to discuss your specific needs.

CONTACT INFORMATION Kaspar Vogt, CRI Catalyst Company +1 (713) 241-1877 [email protected] www.cricatalyst.com HYDROCARBON PROCESSING | MARCH 2015 | WHAT’S NEW IN CATALYSTS

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ADVANCE

to the

Next Generation

Our scientists surpass the norm to create catalysts that set the standard. The next generation ASCENT™ catalyst is leading the industry in multi-cycle economics and maximizing hydrodesulphurization, even in constrained hydrogen environments. ASCENT™ DN-3532 and DC-2535 create extended ULSD value. ASCENT™ DN-3552 provides maximum hydrogenation and stability under constrained hydrogen environments. In combination with the latest SENTRY™ MaxTrap products, ASCENT™ DN-3532 provides superior value to treat coker naphtha feeds.

Leading minds. Advanced technologies.

www.CRITERIONCatalysts.com Select 69 at www.HydrocarbonProcessing.com/RS

CRITERION

OPTIMIZING LOADING PROFILE TO EFFECTIVELY UTILIZE EXISTING NAPHTHA HYDROTREATERS A US refinery asked Criterion to help reduce the frequency of catalyst change outs and reduce overall cost without sacrificing unit throughput on their two naphtha hydrotreating units (NHT). The unit cleans up coker naphtha feed for the reforming unit so the ability to stretch the catalyst cycle life beyond the current 8 months per reactor has a direct impact on profitability. As the incumbent catalyst supplier for the unit, Criterion focused on quickly reviewing the operating data and current set up. Each hydrotreating unit has two single-bed reactors in series. The unit configuration provides the flexibility to change which reactor is in the lead position, leaving the alternate reactor as the lag. This flexibility also allows the unit to isolate a reactor while the other remains in service as needed. The primary method of deactivation for these reactors is Si poisoning, which is very common in this service. The loading profile (as shown in FIG. 1), prior to Criterion’s optimization, was to load each reactor in series with Silica trap catalyst (SENTRY™ MaxTrap [Si] in this case) followed by an active de-nitrification catalyst to balance activity with poison control, thus setting the cycle life. After ~ 8 months, the lead reactor would be deactivated from poisoning. The operators would then exchange lead-lag positions of the reactors to facilitate a reload of the spent reactor. Operation would continue in this same manner until the reactor deactivated on poisoning cycling lead/lag reactor positions again, completing a full reload in a 16-month time frame. Although this scenario provided quality naphtha feed, the duration was such that the expense was not falling into the capital spend 100% of the time. Additionally, the operating scheme created a percentage of unit operation loss that categorized the unit out of the top quartile bracket. Criterion evaluated several catalyst loading options and concluded that obtaining the maximum cycle life required the two reactors to be operated in series with an optimized loading scheme to facilitate longer cycles and fewer changes. Configuration changes created the lead reactor with a primary function of poison control, leaving the lag reactor as the activity reactor for de-nitrification. Compared to current loading scheme, the new loading scheme provided substantially more poison control catalyst SPONSORED CONTENT

Lead Reactor

Lag Rreactor

Trap Si– MaxTrap [Si]

Trap Si– MaxTrap [Si]

Si removal/ HDS/HDN HDS/HDN

Si removal/ HDS/HDN

Lead Reactor

Lag Rreactor

Si removal/ HDS/HDN Trap Si and protect activity

HDS/HDN

HDS/HDN

FIG. 1.

FIG. 2.

in the lead reactor. With the unit run length controlled by feed Si poisoning, using Criterion’s SENTRY™ MaxTrap[Si] catalyst extended the cycle life beyond 12 months. While the SENTRY™ MaxTrap[Si] lead reactor is changed out, the configuration allows the lag reactor to remain in service. Once reloaded, the SENTRY™ MaxTrap[Si] reactor repositions itself in the lead and operation continues. In this new scenario, the lag reactor does not reach maximum capacity on Si poison for several lead cycles. The timing is synchronized to allow both reactors to be shut down in sequence and the lag reactor catalyst is changed along with the lead on the third or fourth change, depending on poison levels in the feed slate. When this occurs, the scheme provides again for uninterrupted operation while both reactors are reloaded. The lead reactor containing SENTRY™ MaxTrap[Si] is unloaded first and reloaded as the lag reactor. This configuration consists of Criterion DN-140 catalyst followed with Criterion’s ASCENT™ DN-3531 catalyst while the current lag reactor remains in service (as shown in FIG. 2). Once the lead reactor is reloaded, it is then switched into service while the lag reactor is reloaded as the lead reactor with SENTRY™ MaxTrap[Si] catalyst. When completed, this new lead reactor is put into service to restart the cycle scheme. This loading methodology ensures flow to the unit is not interrupted and product quality is not compromised. Utilizing the new loading scheme, the refiner benefits by achieving less frequent catalyst change-outs enjoying lower fills costs on each reactor. The lead reactor is expected to

achieve a cycle length of 12 months, while the lag is expected to achieve a cycle length of 36 months. The majority of the catalyst purchased and loaded is SENTRY™ MaxTrap[Si] in the lead reactor, which has saved in fill cost while protecting higher activity catalysts and prolonging the life of the lag reactor. When amortizing the catalyst change-out frequency and cost over a 10 year period, this loading methodology has resulted in ~ 16 % reduction in catalyst costs and ~11% reduction in catalyst change-out frequency. For the refiner described in this paper, this strategy specifically resulted in approximately $400,000 USD savings in catalyst cost per year and one less catalyst change-out every 5 years. This also moved all of the catalysts costs away from operating expense to a more favourable capital expense. Daniel Shiosaki, a Technical Service Engineer at Criterion, says “We work with many customers every year providing not only top tier catalysts but innovative solutions like the one highlighted here that yield real saving as well as additional profitablility for the refinery. It’s what I love about my job.”

CONTACT INFORMATION Diane Chamberlain 910 Louisiana Street, 29th Floor Houston, TX 77002 (713) 241-4568 www.criterioncatalysts.com

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Choose Grace Catalysts Technologies, the global leader in specialty inorganic catalysts. Talent that spans the globe with operations in over 40 countries, knowledgeable R&D teams and industry leading tech service service.

grace.com

Technology leadership #1 in FCC catalysts #1 in resid hydroprocessing catalysts (ART) #1 in independent polyethylene catalysts #1 in independent polypropylene catalysts Leading supplier of hydrocracking catalysts and polypropylene technology licensing

Select 54 at www.HydrocarbonProcessing.com/RS

Trust built through long term partnerships over a 150 year history.

GRACE CATALYSTS TECHNOLOGIES

BUILT ON TALENT, TECHNOLOGY AND TRUST Grace Catalysts Technologies is the global leader in developing and manufacturing process catalysts and related technologies used in refining, petrochemical and other chemical manufacturing applications. Refining Technologies, Specialty Catalysts and the Advanced Refining Technologies joint venture are managed in this segment, as is the UNIPOL® Polypropylene Licensing and Catalysts business.

INNOVATIVE REFINING CATALYSTS AND ADDITIVES FROM THE INDUSTRY’S BROADEST PORTFOLIO Manufacturing excellence and industry leading technical service have made Grace the world’s leading supplier of FCC catalyst and additives. Grace is dedicated to helping refiners achieve success with innovative catalytic solutions. Refineries stay competitive with Grace Fluid Catalytic Cracking (FCC) technology because they can maximize the yield of the most valuable products through use of the optimal catalyst for their crude slate. Understanding feed impacts earlier allows the refiner to optimize operating parameters and catalyst management strategies for a more stable and profitable operation. Grace developed the ACHIEVE® FCC catalyst technology specifically to meet the challenges of opportunity feeds. Grace is now expanding its portfolio of catalysts under the ACHIEVE® series to address current market challenges. Processing opportunity crudes as well as upgrading the bottom of the barrel into light cycle oil (LCO) and lighter products are some of the challenges facing refiners looking to maximize the value from their FCC units. Grace’s current portfolio of FCC additives allows refiners to reduce SOX, NOX, and CO emissions from their FCC units, as well as lower sulfur content in gasoline. The portfolio includes ZSM-5 additives, OlefinsMax®, OlefinsUltra®, and OlefinsUltra®HZ, which provide three levels of activity for LPG olefin maximization. Super DESOX® OCI, a low-rare-earth catalytic SOX reduction additive was first introduced during the rare-earth crisis. Since that time, Super DESOX® OCI has become a preferred product because it delivers equivalent performance at lower cost to the refiner. Grace’s patented GSR® (FCC gasoline sulfur reduction) technologies create a variety of opportunities and options for refiners to drive profitability during routine maintenance and unit upsets, whilst maintaining regulatory compliance. Refiners around the world have demonstrated that use of GSR® catalysts and additives is a cost-effective component of their clean fuels strategy to meet 10 ppmw gasoline sulfur specifications. We are the leader in hydroprocessing catalysts through Advanced Refining Technologies (ART). Chevron and Grace joined together in 2001 to form ART, with goals based on the values of its parents: technology expertise, world-class research and development, global manufac-

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turing footprint, and a complete portfolio of hydroprocessing catalysts designed to meet the challenges of today’s refiners. ART combines Grace’s material science, manufacturing, marketing and sales strength with Chevron’s extensive experience operating its own refineries and leadership in technology, design and process licensing.

CATALYSTS FOR POLYOLEFIN PRODUCTION AND MARKET LEADING PROCESS TECHNOLOGY Grace provides catalyst systems and supports for polyethylene and polypropylene process technologies. Grace has a unique position as the only company currently supplying a complete portfolio of polyolefin catalyst systems including, silica and magnesium based support systems, metallocene components, key raw materials and intermediates, and finished Chromium, Ziegler Natta and SSC catalysts for essentially all polypropylene and polyethylene process platforms and applications. In December 2013, Grace acquired UNIPOL® PP Licensing & Catalysts, a proprietary gas phase polypropylene process technology for the production of a broad range of polypropylene products, from the Dow Chemical Company. The UNIPOL® licensing and catalysts systems business offers the industry-leading UNIPOL® PP Process Technology, which includes the advanced process control UNIPOL UNIPPAC® Process Control software, SHAC® Catalysts Systems, and 6th Generation nonphthalate CONSISTA® Catalysts Systems. The major trends expected in the refining industry, include a growing demand for low-sulfur diesel, tightening environmental regulations, and increasing use of heavy crudes, which are causing major shifts in our customers’ businesses. Over the years, catalysts have evolved to be more active, to be more selective, and to drive the right conversion to meet the changing market demands. Grace Catalysts Technologies will continue to deliver value to the refining, petrochemical, and chemical industries with our process catalysts through customer focus and innovation.

CONTACT INFORMATION 7500 Grace Drive Columbia, MD 21044, USA +1 (410) 531-4000 [email protected] www.grace.com

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Elements of Success

Precious metal refining with response and responsibility

Learn more about the art and science of sampling at Sabin Metal, one of many Elements Of Success we’ve provided to catalyst users around the world for over six decades.

www.sabinmetal.com Select 68 at www.HydrocarbonProcessing.com/RS

SABIN METAL CORP.

PRECIOUS METALS RECOVERY AND REFINING FOR GLOBAL INDUSTRY Sabin Metal Corp., East Hampton NY has added a second electric arc furnace (EAF) and baghouse at its Williston ND precious metals recovery and refining processing plant (Sabin Metal West Corp.). The addition of the second EAF doubles the company’s capacity to process spent precious metal-bearing hydrocarbon/petrochemical catalysts. The new EAF uses Sabin’s exclusive Pyro-Re™ technology to recover maximum possible remaining precious metals from spent process catalysts, including rhenium, another high value precious metal. The baghouse incorporates sophisticated, state-of-the-art filtration systems that enable the company to recover particulates of precious metals that would otherwise be lost in the atmosphere, while also assuring compliance with appropriate pollution abatement standards. Sabin Metal recovers and refines precious metals including platinum, palladium, ruthenium, rhodium, rhenium, gold, silver, and others from spent hydrocarbon, chemical, and petrochemical processing catalysts with zeolite, soluble and insoluble alumina, and carbon supports. The Sabin Metal Group, headquartered in East Hampton, New York, is composed of five independent organizations including Sabin Metal Corp., Scottsville, New York, considered the most sophisticated facility of its kind for safely processing precious metal-bearing materials; Sabin Metal West, a specially equipped facility for sampling large lots of precious metal-bearing spent hydrocarbon processing catalysts. This refinery employs electric arc furnace (EAF) technology which helps maximize recovery of precious metals, and also incorporates a unique “low dust” continuous sampling

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system for accurate sample derivation and total environmental safety and compliance. Sabin Metal Europe B.V., a technical service division based in Rotterdam, works with hydrocarbon, chemical, petrochemical, and nitric acid processors in Europe, Africa, and the Middle East, to recover and refine precious metals from spent catalysts and nitric acid production equipment and facilities. Sabin International Logistics Corp. (SILC), is a licensed hazardous waste, hazardous materials, and general commodities transporter providing global transportation and logistics for spent precious metal-bearing catalysts and other materials. The company operates its own fleet of trucks, and is also a Permitted and Licensed Freight Broker. SILC’s SA-BIN® secure storage/shipping containers represent a unique method for quickly, conveniently, and safely transporting spent catalyst materials from Sabin’s customers to its processing facilities. SMC (Canada) Ltd., the McAlpine Mill in Cobalt, Ontario, Canada, offers capabilities and processing technologies to extract highest possible metal values from residual materials generated in refining, smelting, and milling operations. The Sabin Metal group of companies is the largest domestically owned, independent precious metals refining organization in North America. The company’s recovery/refining facilities and sales/service offices are located in strategic countries around the world. Sabin’s gold, silver, platinum, and palladium are accepted on the Chicago Mercantile Exchange (NYMEX/COMEX); Sabin’s platinum and palladium are also accepted for delivery on the

Dual electric arc furnaces double pyrometallurgical processing throughput at Sabin Metal West to help assure maximum recovery of remaining PGMs in spent catalysts—including rhenium. London/Zurich market by the London Platinum and Palladium market (LPPM). The organization is now entering its eighth decade of working with a worldwide customer base by providing added value services along with the peace of mind that comes from working with an environmentally responsible precious metals refiner.

CONTACT INFORMATION Bradford M. Cook (832) 707-1338 [email protected] sabinmetal.com

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Innovations

Corrosion prevention for high-TAN refining For petroleum refiners, improving profitability by processing high-total-acidnumber (high-TAN) crude oils requires an investment in high-temperature corrosion protection. Investing in metallurgy delays profit improvement, and return on capital is uncertain. Conventional chemical inhibitors require high phosphorus treat rates, which introduce fouling and operating risks that have deterred the acceptance of chemical solutions. In response, specialty chemical company Dorf Ketal Chemicals LLC introduced TANSCIENT, a chemical inhibitor solution offering more effective passivation and ongoing protection. The TANSCIENT solution reportedly contains up to 80% less phosphorus than competing companies. The inhibitor was previewed at the CORCON 2014 Conference and Expo in Mumbai, India and will be launched at NACE CORROSION 2015, which takes place March 16–19 in Dallas, Texas. According to Dorf, the TANSCIENT solution is effective at concentrations below the Canadian Association of Petroleum Producers (CAPP) recommended phosphorus specification of 0.5 ppm. High phosphorus treat rates with traditional phosphate ester programs have been shown to impair the downstream unit catalyst, requiring more fresh catalyst addition. While traditional programs may foul the hydrotreater, decreasing the run length of the unit, the TANSCIENT inhibitor does not, the company says. The TANSCIENT solution is said to offer an improved level of safety, reliability, efficiency, and cleanliness in corrosion protection, thereby allowing refiners to take greater advantage of high-TAN crudes. Select 1 at www.HydrocarbonProcessing.com/RS

Chlorine analyzer reduces monitoring costs The new panel-mount Model FC80 free chlorine analyzer (FIG. 1) from Elec-

tro-Chemical Devices (ECD) reportedly simplifies water monitoring and treatment processes while installing easily and requiring less maintenance, thereby lowering total cost of ownership. The analyzer monitors free chlorine in cooling water, drinking water, rinse water or other freshwater samples from 0.05 ppm–20 ppm of chlorine as the standard range, or from 0.01 ppm–5 ppm with the low-range sensor. The analyzer is compliant with EPA method 334.0 for measuring drinking water. The FC80 analyzer can be installed directly out of the box. An advanced panel mount design includes built-in flow control, which eliminates the need for complex pressure regulators and rotometers. Built-in automatic pH compensation also eliminates the need for expensive reagents, thereby reducing maintenance and lifecycle costs. The analyzer’s panel-mount design incorporates a constant head flow control device, a pH sensor, a chlorine sensor and ECD’s T80 analyzer/transmitter mounted on a PVC panel. Calibration is accomplished by DPD chemistry (N, N-diethylp-phenylenediamine) comparison. Free chlorine exists in solution as a pH-dependent ratio of hypochlorous acid (approximately 100% at pH 5) and hypochlorite ion (approximately 100% at pH 10). The T80 free chlorine sensor measures only the hypochlorous acid component of the free chlorine, and the analyzer calculates the balance using either the measured pH or a user-defined, fixed value. The use of the pH sensor provides accurate compensation for samples between pH 6 and pH 9, eliminating the need for expensive sample conditioning systems to control the pH of the solution. The FC80 analyzer is available with either 110-240 VAC or 24 VDC power. Parameters can be graphically displayed with user-defined line, bar or gauge-style graphs. The standard configuration has two 4-20 mA outputs, three alarm relays and a Modbus remote terminal unit.

The analyzer is available with an autoclean option that includes a solenoid actuated spray cleaner using either 30-psi process water or air. An adjustable timer controls the period and duration of the cleaning cycle. Select 2 at www.HydrocarbonProcessing.com/RS

Ceramics extend heat exchanger life Shell-and-tube heat exchanger technology has been in existence for more than a century. However, the technology has been characterized by limitations— mainly operating temperatures and construction materials. Even high-grade metals limit the maximum-use temperature to 1,400°F or less. These materials can also be difficult to select, due to the various conditions to which they are exposed. For example, a metal that has great creep strength at elevated temperatures may be poor at resisting attacks by certain acids. Another metal that has good resistance to acid may not perform in an erosive environment. Often, compromises are made and the heat exchanger is accepted as an expendable commodity. Heat Transfer International (HTI) has introduced new ceramic materials that have the ability to dramatically extend the life of thermal transfer devices. Attempts to adapt various ceramics into shell-and-tube heat exchangers have been

FIG. 1. The FC80 chlorine analyzer simplifies water monitoring and treatment processes. Hydrocarbon Processing | MARCH 2015103

Innovations made in the past, but the mechanical challenges of using ceramics—which are completely different than those of metals—have proven too great. HTI says it has overcome these challenges and has applied for numerous patents on the design and development of both low- and high-pressure ceramic heat exchanger applications. It also claims the ability to achieve near-zero leakage at extreme temperatures of over 2,000°F. The company has fully developed and tested its materials, seals and compensation systems at real-world operating temperatures and pressures (FIG. 2). HTI’s test stand can simulate operating temperatures in excess of 2,400°F and differential pressures of greater than 150 psia. Ceramics have many benefits as heat exchanger construction material. Ceramics are: • Capable of performing at much higher operating temperatures than metals

• Impervious to most corrosive and erosive environments • Extremely hard; compared to other industrial materials, they are second only to diamond • Adept at transferring thermal energy • Very resistant to thermal shock • Creep resistant, which is virtually unaffected by temperature • Available in multiple grades of tubing to suit varying process requirements. In partnership with a leading turbine manufacturer, HTI also developed the first biomass-fired, ceramic-heatexchanger-driven turbine-generator system. The turbine was driven solely with hot air from the heat exchanger, which operated at 2,000°F and transferred 9 MMBtu/hr from a poultry waste gasification process. The system was commissioned, operated, and certified to produce power and connected to the grid. Select 3 at www.HydrocarbonProcessing.com/RS

Low-emissions refrigerant in mass production

FIG. 2. A ceramic heat exchanger operating at 1,900°F.

FIG. 3. The TRITAN 365 UV leak detection lamp pinpoints fluid leaks in a range of industrial systems.

104MARCH 2015 | HydrocarbonProcessing.com

Honeywell has started full-scale commercial production of a low-global-warming-potential (GWP) material that can be used as an aerosol propellant, an insulating agent and a refrigerant. The material, known by the industry designation HFO-1234ze and marketed by Honeywell under its Solstice line of low-global-warming materials, is being produced at the Honeywell Fluorine Products facility in Baton Rouge, Louisiana. In September 2014, at an event sponsored by the Obama administration, Honeywell announced that it will increase production of its low-GWP refrigerants, insulation materials, aerosols and solvents. Furthermore, up to 2020, Honeywell plans to drive a 50% reduction in its annual production of high-GWP hydrofluorocarbons (HFCs) on a CO2-equivalent basis. The company projects that use of its low-GWP Solstice materials to replace HFCs will eliminate more than 350 metric MMt in CO2 equivalents by 2025, which is akin to removing 70 MM cars from the road for 1 yr. HFO-1234ze is a next-generation material that is non-ozone-depleting and non-flammable (per ASTM E681 and

ISO 10156:2010 testing), and that has a low GWP of less than 1. It is also not a volatile organic compound, as determined by the US Environmental Protection Agency (EPA) and the California Air Resources Board. HFO-1234ze is said to be a preferred replacement for both HFC-134a (which has a GWP of 1,300) and HFC-152a (which is flammable and has a GWP of 138) in aerosol applications and thermal insulating foams, including extruded polystyrene board and polyurethane foams. The material is also being considered to replace HFC-134a for large stationary and commercial refrigeration applications. Honeywell’s line of Solstice hydrofluoro-olefin (HFO) products have low GWPs that are either equal to or less than CO2. The Solstice HFOs are alternatives to high-GWP HFCs and are energy efficient, safe to use and nonozone-depleting. They also have a minimal global warming profile. Honeywell’s Solstice line of HFOs includes Solstice yf Refrigerant (R-1234 yf) for automobile air conditioning, Solstice Propellant for aerosol applications, Solstice Liquid Blowing Agent and Gas Blowing Agent for foam applications, and Solstice Performance Fluid for use as an industrial solvent. Each of these products has been approved under the EPA’s Significant New Alternatives Policy (SNAP) program. In addition to its line of low-GWP HFOs, Honeywell’s Fluorine Products business manufactures and supplies non-ozone-depleting refrigerants used by air-conditioning and refrigeration manufacturers worldwide, blowing agents for energy-efficient foam insulation, hydrofluoric acid used in gasoline and steel manufacturing, and precursors for nuclear fuel. Select 4 at www.HydrocarbonProcessing.com/RS

UV lamp sheds light on leak detection The Spectroline TRITAN 365 multiLED, broad-beam ultraviolet (UV) leak detection lamp (FIG. 3) pinpoints fluid leaks in a wide range of industrial systems, such as hydraulic equipment, compressors, engines, gearboxes, fuel systems and more. It is designed for use with Spectroline’s fluorescent dyes.

Innovations The TRITAN 365 lamp features three ultra-hi-flux UV LEDs for fluorescent leak detection, along with a white-light LED for general component inspection in dimly lit areas. The lamp’s broad-beam profile provides extra-wide area coverage—a 45-in. (114-cm) diameter at a 20ft (6.1-m) distance—allowing for quick leak checking over large surface areas. The UV lamp weighs 16 oz. (454 g), and its compact head can investigate cramped areas that larger lamps cannot reach. A three-way rocker switch allows for easy control of the light sources. A lightweight, angled lamp body helps streamline inspections. Also, instant-on operation allows the lamp to reach full intensity immediately. The lamp provides twice the output of conventional 150-watt lamps and has a 100,000-hr LED service life. Also available is the TRITAN 365M portable, battery-operated AC/DC lamp kit. Along with the TRITAN 365 UV lamp, the kit includes a rechargeable nickel-metal hybrid battery pack, AC and DC cord sets, a smart AC charger and UV-

absorbing glasses. All components are packed in a carrying case for portability. Select 5 at www.HydrocarbonProcessing.com/RS

Irish firm develops sustainable waste treatment Irish environmental firm SCFI has been awarded nearly €1 MM in EU funding to develop commercial opportunities for its sustainable waste treatment technology, AquaCritox. SCFI developed AquaCritox to provide a sustainable solution for the treatment of a variety of industrial, municipal and sewage wastes. Awarded under the EU’s eco-innovation initiative, the grant will fund a new project that aims to position the pioneering technology at the forefront of the global waste treatment industry. The project will demonstrate the commercial feasibility of the technology, establishing a viable route to market for a range of applications. The eco-innovation project will first see the design, manufacture and installation of an AquaCritox demonstrator

in Cork, Ireland. This unit will carry out comprehensive testing of the technology’s treatment of municipal and industrial sludges, with an operating capacity of 15,000 metric tpy. It will then be shipped to a working commercial facility in the Middle East, where it will undergo further trials, including processing oil and gas waste. AquaCritox uses a patented hydrothermal oxidation (HTO) process. By subjecting wet waste to a high pressure and temperature and adding an oxygen supply, a rapid and complete oxidation reaction takes place. This reaction reduces waste volume by 97% and produces a treated effluent that is safe for disposal. A single-step, sustainable and cost-effective process, AquaCritox mitigates the social, political and environmental concerns over traditional methods of waste destruction and disposal (e.g., landfill, incineration and land spreading). It also generates renewable energy and allows for the recovery of resources like phosphorus and carbon dioxide. Select 6 at www.HydrocarbonProcessing.com/RS

Keynote Speaker:

J. Keith Elliott Senior Vice President Eastern Mediterranean Region Noble Energy

17–18 March 2015 | Nicosia, Cyprus

Explore Opportunities for Regional and International Collaboration in the Eastern Mediterranean Join us for the third annual Eastern Mediterranean Gas Conference (EMGC) and hear from key industry experts and governments officials regarding the latest trends and developments in natural gas exploration, exportation, monetization and collaboration opportunities for the region to become an international trade hub.

2015 EMGC Discussions Include: • The state of the Eastern Mediterranean • Regional exploration updates • Regional opportunities and infrastructure challenges • Regulatory stability and legal issues • Gas Monetization (pathways, markets, pricing, alternatives)

• Global energy trends and the effects on gas export options • The Eastern Mediterranean: Gas and the Levant Trade Corridor: Opportunities for regional and international collaboration • The future: Obstacles and answers

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Why Should You Filter Your Water?

Bexar Energy Holdings, Inc. Phone 210-342-7106 s Fax 210-223-0018 www.bexarenergy.com s Email: [email protected] Select 201 at www.HydrocarbonProcessing.com/RS

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