Hydrocarbon Processing May 2015

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REGIONAL REPORT Extensive update of Middle East refining and petrochemical industries ®

HydrocarbonProcessing.com | MAY 2015

ROTATING EQUIPMENT Thorough review explores ways to optimize hydrogen compressor operations

PROCESS ENGINEERING Improve sizing of emergency relief devices for olefins units

SPECIAL REPORT:

Maintenance and Reliability Proper maintenance and inspection programs support safe and reliable plant operations

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MAY 2015 | Volume 94 Number 5 HydrocarbonProcessing.com

65

40 SPECIAL REPORT: MAINTENANCE AND RELIABILITY 41 Reduce maintenance and production losses by benchmarking asset performance M. Naik

45

Consider new labyrinth seals to optimize compressor operations T. Gresh and J. K. Whalen

51

Maximize energy recovery with small steam turbines K. Kaupert, R. Krull and R. Iles

57

DEPARTMENTS 10 19 103 106 108 109 110

News Industry Metrics Innovations Marketplace Advertiser Index Events People

Lubrication update for rotating equipment H. P. Bloch

REGIONAL REPORT 65 The Middle East’s strategic expansion of refined products exports M. Rhodes

ROTATING EQUIPMENT 79 Use new methods to optimize energy efficiency of hydrogen compressors

COLUMNS 9

Change is redefining the petrochemical industry

21

25

27

HP staff

SHOW PREVIEW: IRPC 93 IRPC 2015: Advancing the global HPI by sharing knowledge and best practices HP staff Cover Image: Photo courtesy of Linde Gases.

Project Management Build a better bid, or how to achieve a competitive advantage in capital projects

31

Global Uganda proceeds with new refinery

D. Smith and J. Burgess

TERMINALS AND STORAGE REPORT—SUPPLEMENT T-97 Safety and environmental updates for HPI storage tanks

Automation Strategies Developing the best practices for operator effectiveness in the age of collaboration

F. Sadeghi, S. Sadeghi and U. Sundararaj

PROCESS ENGINEERING 91 Improve relief-device sizing under supercritical conditions

Reliability Reassessing and updating electric motor bearing lubrication

M. Vila Forteza

PROCESS TECHNOLOGY 87 Improve measurement of heavy oil viscosity

Editorial Comment

33

Petrochemicals M&A deals rise as investors push petrochemical leaders to restructure

35

Engineering Case Histories Case 84: Remaining service life of plant equipment can be determined

37

Viewpoint Methanol takes on LNG for future marine fuels

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

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4MAY 2015 | HydrocarbonProcessing.com

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

John Royall Ron Higgins Sheryl Stone Pramod Kulkarni Pamela Harvey

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

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31 May–3 June 2015

Jumeirah at Etihad Towers Abu Dhabi, UAE

Attend the HPI’s Premier Event for Senior-Level Engineering and Management Professionals: IRPC 2015 Keynote Speaker:

Giacomo Rispoli Executive Vice President, Research & Development and Projects eni - Refining & Marketing Division

Hear from top operators including Takreer Research Centre, Abu Dhabi Oil Refining Company; Bharat Petroleum Corporation Limited; Saudi Aramco; EQUATE Petroleum; Kuwait Oil Company; Kuwait Petroleum International and more. Co-host’s, TAKREER, Hydrocarbon Processing, and dmg:events Middle East (organizers of ADIPEC) invite you to join us in Abu Dhabi from 31 May–3 June 2015 for the sixth annual International Refining & Petrochemicals Conference (IRPC) to connect with the global downstream audience in the heart of one of the world’s most active regions for refining and petrochemical projects. The 2015 conference and exhibition will provide a high-level business and technical forum in which key players in the global petrochemical and refinery sector will meet to share knowledge and learn about best practices and the latest advancements in this developing sector of the oil and gas industry.

> www.hpirpc.com

Dr. Mohammad Shamsuzzoha Senior Process Simulation Engineer Takreer Research Centre

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Co-Hosted by:

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4 Days of Discovery, Learning, New Business Opportunities and Networking (View the Full Agenda at www.hpirpc.com) > May 31: Takreer and Borouge Downstream Research & Innovation Workshop and Tour In 2009, TAKREER Research Centre (TRC) started its research activities in the newly built premises located in Sas Al Nakhl, Abu Dhabi. The centre is the first applied research entity within the UAE in the field of oil refining. IRPC attendees will have the unique opportunity to tour the centre which houses several pilot plant units for hydroprocessing, naphtha reforming and TBP distillation. It also has dedicated multi-functional laboratories and other facilities including a computer-based training room and a scientific library. Seats are limited. Reserve your spot today.

> June 1: New for 2015, Business Day Supported by ADIPEC Attendees will hear how businesses are adjusting to the challenges and opportunities of today, and gain key insights into the future direction of the industry and discover opportunities for business growth.

> June 2–3: 2 Day Technical Conference with 3 Tracks and 65 Presentations The technical program provides top-level insight into the latest technology and operating advances in the global HPI. Speakers include top executives and industry experts from: • Takreer Research Centre

• Engineers India Limited

• eni - Refining & Marketing Division

• Bharat Petroleum Corporation Limited

• UOP LLC, a Honeywell Company

• Nalco Champion, an Ecolab Company

• Gail (India) Ltd

• CH2MHILL Srl

• CEPSA

• EQUATE Petrochemical Company

• Saudi Aramco

• GE Water

• Neste Jacobs Oy

• Kuwait Oil Company (KOC)

• Yokogawa Electric International Pte, Ltd

• aTüpras - Turkish Petroleum Refineries Corporation

• Kuwait Petroleum International

• HPCL Mittal Energy, Ltd

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> For Sponsor and Exhibit Opportunities: Americas and Europe: Melissa Smith, Global Events Director, Gulf Publishing Company, +1 (713) 520-4475 or [email protected] Asia Pacific and Middle East: Siham Ammoura, Senior Business Development Manager, DMG Events ME, +00 971 55 7781 360 or [email protected] Italy: Fabio Potesta, Mediapoint & Communications SRL, +39 010 5704948 or [email protected] > For Group Delegate Inquiries: Faheem Chowdhury, Head of Delegates, DMG Events ME, +971 50 600 1173 or [email protected]

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Editorial Comment

STEPHANY ROMANOW, EDITOR [email protected]

Change is redefining the petrochemical industry At a recent downstream conference, a speaker urged attendees to embrace the volatility of the hydrocarbon processing industry (HPI). This is odd advice, considering that most HPI companies labor very hard to minimize volatility from their business plans and plant operations. Another way to view this advice would be: “Expect change (good or bad) and run with it.” The petrochemical industry is embracing more “change” that is largely due to the recent drop in crude oil prices. Bellwether chemical. Global demand

for ethylene is expected to grow slightly above the GDP, according to Steve Lewandowski, global business director at IHS Chemical. On a global annual average, ethylene capacity increases are barely keeping up with demand. Change is a constant. The ethylene

industry is changing, and forecasting the next demand/supply cycle is becoming more complex. “Naphtha remains the No. 1 steam cracker feedstock, accounting for more than 50% of the global demand. Ethane and other NGLs make up about 30%,” said ExxonMobil Chemical Senior Vice President Matt Aguiar at the 2015 IHS World Petrochemical Conference. Changes are unfolding due to abundant supplies of shale oil and gas and associated NGLs. “Rising production of NGLs is driving a global shift toward NGLs as a chemical feedstock,” Aguiar said. “ExxonMobil sees demand for NGL feedstocks rising by about 125% through 2014, compared to 70% for naphtha. We expect NGLs to surpass naphtha as the top feedstock in the chemical sector.”

Investment drivers. New construction activity for North American (NA) petrochemical projects is driven by abundant low-cost natural gas. These investments are focused on ethylene, propylene and methanol-based derivatives.

27 Project management.

How can operating and E&C

companies plan and develop worldscale projects successfully? Too many megaprojects are over

Capitalizing on innovation. Other

changes are unfolding in the production of ethylene. For example, Siluria and Braskem America have successfully launched a large-scale demonstration plant of the first gas-to-ethylene process using the oxidative coupling of methane (OCM) process. This process directly converts natural gas (methane) to ethylene. OCM is not a new technology. For over 30 years, several companies have researched how to efficiently convert methane into ethylene. Siluria has achieved a breakthrough in the OCM process. Siluria is working with the Linde Group to develop ethylene technologies for both world-scale and revamp projects based on the OCM technology. For NA ethylene producers, the OCM process can provide more process flexibility. A commercial unit is planned for 2017– 2018. An expanded version of Editorial Comment can be found online at HydrocarbonProcessing.com.

budget or behind schedule. Ron Beck, director of industry marketing, engineering and construction, AspenTech, explains how better and transparent communication is needed between operating and E&C companies.

37 Viewpoint.

Methanol may be the marine fuel of the

future, according to Gregory Dolan, CEO of the Methanol Institute. New, strict rules on NOx and sulfur emissions for emission control areas require shipowners to use lower-sulfur fuels. Dolan shares how methanol has a viable place in the marine fuel market.

and 40 Maintenance reliability.

Maintenance

and reliability programs create value. In the modern HPI, they should not be viewed as services. HPI facilities constantly investigate new monitoring and conditioning systems, along with preventive maintenance and inspection programs to add value to their organizations.

report: 65 Regional The Middle East. The Middle East is transforming its downstream business to be both vertically integrated across the value

Cost is everything. Feedstocks are as

much as 70% of the manufacturing cost for ethylene. At higher crude oil prices, other feedstocks and ethylene technologies—coal-to-olefins and methanol-toolefins—offer processing advantages.

INSIDE THIS ISSUE

chain and horizontally integrated across diverse geographies. The region is making decisive moves to become a FIG. 1. The OCM demonstration unit at Braskem America’s La Porte, Texas, complex.

manufacturing center for the global downstream industry. Hydrocarbon Processing | MAY 20159

| News Shell to become largest LNG player with €47-B BG Group acquisition Royal Dutch Shell’s agreement to purchase BG Group for approximately €47 B in cash and shares is the oil and gas industry’s biggest deal in at least a decade. Shell saw its 2014 worldwide production drop to the equivalent of 3.08 MMbpd, the lowest in at least 17 years, while BG boosted reserves in six of the past seven years, 78% of which were gas, compared with 47% for Shell. Shell expects the acquisition to accelerate its growth strategy, adding approximately 25% to the company’s proved oil and gas reserves and 20% to production, each on a 2014 basis. The deal will also provide Shell with enhanced positions in competitive new oil and gas projects, particularly in Australia LNG and Brazil deepwater areas. Shell said that the merged company, led by Shell CEO Ben van Beurden, will boast a market value twice the size of BP.

MIKE RHODES, TECHNICAL EDITOR [email protected]

News

Neste Oil’s Porvoo refinery begins massive maintenance turnaround Hailed as the largest refinery maintenance turnaround to date, the Neste Oil Porvoo, Finland, maintenance project will cost nearly €100 MM and involve 4,500 employees and some 3,500 outside contractors. The facility began unit shutdowns in April, and, during the scheduled eightweek turnaround, Neste Oil will sell products from its storage. The Finland refinery’s oil terminal and road transportation of products will continue to operate normally. Investment projects related to refinery development—such as the installation of new furnaces in the crude oil distillation unit, the significant replacement of automation in several areas and the connections to prepare for upcoming projects—will also be completed. Regular maintenance turnarounds every four to five years play an important part in keeping Neste Oil refinery operations safe and running at peak efficiency (FIG. 1). Statutory pressure vessel inspections and maintenance also call for shutdowns at regular intervals. The previous major turnaround at the Porvoo refinery took place in 2010.

ing in International Maritime Organization (IMO) emission control areas (ECAs), MeOH is a solution for complying with S-emissions legislation. MeOH can also be stored in normal, unpressurized tanks: delivery by train, truck and/or ship is already in place in many areas globally, and establishing and expanding the existing MeOH infrastructure is feasible, even for individual ships operating in remote areas. The MAN B&W ME-LGI engine design (FIG. 2) overcomes the challenge of low-cetane-number fuels, such as MeOH,

which has a characteristically poor selfignition quality that utilizes the ME-LGI principle of pilot injection of MGO or HFO. Fuel injection is accomplished by a fuel booster injection valve (FBIV), using 300 bar of hydraulic power to raise the fuel pressure to an injection pressure of approximately 600 bar. To date, MAN Diesel & Turbo has received orders for seven ME-LGI engines—a mixture of 7S50ME-LGI and 6G50ME-LGI variants—from Mitsui OSK Lines, Marinvest and Westfal-Larsen.

FIG. 1. The Neste Oil maintenance project at its Porvoo, Finland, refinery will cost €100 MM.

MAN methanol engine achieves successful demonstration At its diesel research center in Copenhagen, Denmark, MAN Diesel & Turbo successfully demonstrated the ME-LGI (liquid gas injection) concept, expanding the company’s dual-fuel portfolio and enabling the use of more sustainable fuels such as methanol (MeOH), ethanol and LPG. For the purpose of the event, the company rebuilt its 50MX test engine to accommodate an ME-LGI unit. MeOH is viable as a ship fuel because it does not contain sulfur (S) and is liquid in ambient air conditions, which makes it easy to store aboard ships. For ships operat-

FIG. 2. MAN customers and partners take part in the demonstration of its ME-LGI concept. Hydrocarbon Processing | MAY 201511

News The first engine will be produced by Mitsui Engineering & Shipbuilding Co. Ltd. (MES) for a vessel currently under construction by Minaminippon Shipbuilding Co. Ltd. for Mitsui OSK Lines Ltd. MAN has previously stated that it is working toward a Tier 3-compatible ME-LGI version that can meet IMO NOx limits with the aid of secondary measures. More information about this technology can be found in the Viewpoint article on page 37.

Reliance commissions two new plants Reliance Industries Ltd. has successfully put into operation two plants in Dahej, Gujarat, India. The first is a polyethylene terephthalate (PET) resin plant that consists of two lines with a combined manufacturing capacity of 650 metric Mtpy. The plant has been built with Invista technology for con-

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tinuous polymerization and Buhler AG technology for solid-state polymerization. This is one of the largest bottle-grade PET resin capacities at a single location globally. PET resin from the new capacity would find application in packaging for water, carbonated soft drinks, pharmaceuticals, and other food and beverages. Purified terephthalic acid (PTA) and monoethylene glycol (MEG)—the two feedstocks for the new PET plant—are available within the Dahej complex, offering the advantages of lower freight costs and consistent product quality due to inhouse raw material linkages. The second facility is a new PTA plant that provides a capacity of 1.15 MMtpy. With the commissioning of this plant, also built with Invista technology, Reliance’s total PTA capacity will increase to 3.2 MMtpy, and its global capacity share will rise to 4%. Paraxylene, the key feedstock for the PTA plant, is sourced from Reliance’s Jamnagar refinery (FIG. 3). The PTA plant is also forward integrated with the 650-Mtpy PET plant in the same complex, lowering operating costs and capturing full chain margins. Another PTA plant of similar capacity is under construction at the same location, placing Reliant among the top five PTA manufacturers globally. India is the second-largest producer of polyester, with estimated production of 5.4 MMtpy. The Indian polyester market is growing at 8%–10% annually. The Indian market is deficient in PTA by over 1.5 MMtpy.

Mitsubishi unveils $1-B Trinidad methanol project

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Japan’s Mitsubishi Group will build a methanol (MeOH) and dimethyl ether (DME) plant in Trinidad and Tobago at an investment cost of roughly $1 B, project officials have confirmed. The project will be operated by Caribbean Gas Chemical, and will be jointly owned by Mitsubishi Gas Chemical Co. (25.26%),

OIL & GAS SEPARATIONS (936) 788-1000 www.pentairseparations.com FIG. 3. Reliance’s Jamnagar refinery will supply the key feedstock, paraxylene, for the company’s new PTA plant in Dahej, India.

12

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News Mitsubishi Corp. (26.25%), Mitsubishi Heavy Industries (MHI) (17.5%), and Trinidad and Tobago’s state-owned National Gas Co. (NGC) (20.0%) and Trinidadbased Massy Holdings Ltd. (10.0%). The project, scheduled to begin by October 2018 and to be completed by June 2018, would have a capacity of 1 MMtpy of MeOH and 20 Mtpy of DME. The MeOH will be sold worldwide, according to the partners.

The companies will work closely with the government of Trinidad and Tobago to promote the use of DME as a substitute for diesel. The partners said they have already concluded contracts for engineering, procurement and construction (EPC), as well as for gas supply and relevant land leases. Discussions are underway with a syndicate of Japanese banks to finalize the loan agreement. The plant design and construction will be undertaken by MHI.

Amec Foster Wheeler wins Orpic services contract Oman Oil Refineries and Petroleum Industries Co. (Orpic) has awarded a technical services agreement contract for the company’s Mina Al Fahal and Sohar refineries, and its aromatics and polypropylene plants in Oman to Amec Foster Wheeler. Under the contract, Amec Foster Wheeler will provide specialist process and technology engineering support, process safety improvement and maintenance program support for the refineries and chemical plants. This includes a help-desk service to troubleshoot plant processes; optimize production; reduce energy and utilities costs; and improve plant reliability, safety and environmental performance. Amec Foster Wheeler said the contract will be executed using skills from its Reading, UK, hub, along with local expertise in Oman.

Impact of changing US crude export policy Wood Mackenzie is examining the impact a potential policy shift may have on US export crude oil flows and differentials. Ultimately, while eliminating the US export ban would narrow the Brent– WTI differential and raise the wellhead price for US crudes, it would be unlikely to transform the supply outlook, Wood Mackenzie suggests. Wood Mackenzie, which is being acquired by Verisk Analytics, points out that the quality of a US barrel that might be exported is not obvious. The greater narrowing of Brent to Louisiana Light Sweet (LLS) crude oil would depend on US exports of light-sweet crude oil to the growing Asian market, with long-haul large parcels. Asia would also have the greatest appetite for crude oils similar to Mars crude, whereas Europe places a relatively higher value on condensate, but would have a limited appetite for US light barrels because much of its light-sweet crude oil requirements are satisfied by production in the North Sea or Mediterranean regions. Wood Mackenzie’s outlook suggests that the best value for Eagle Ford condensate is to split the barrel locally and sell cuts to a variety of markets. The company suggests that the policy debate needs to move beyond the generic notion of US crude 14

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News exports to a more substantive discussion of potential destinations and types of US crude oil that might be exported.

ABS offers roadmap to regulatory and technical issues ABS, a provider of classification services to the marine and offshore industries, has updated its guidance on LNG bun-

kering in North America (NA) to support the transport sector’s increasingly rapid transition to the use of cleaner fuels. The second edition of ABS’ “Bunkering of Liquefied Natural Gas-Fueled Marine Vessels in North America” report has been released, offering advice to shipowners and operators seeking to develop bunkering infrastructure in response to new emissions regulations and to showcase their environmental stewardship.

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Major updates in the second edition include important lessons learned from first adopters of LNG-fueled vessels and LNG bunkering projects, a “project roadmap” guide of the associated regulatory, stakeholder and technical issues, and an in-depth port directory highlighting ongoing projects and local development processes. ABS has won the classification contracts for the world’s first LNG-fueled containership, NA’s first LNG barge, the world’s first very large ethane carrier, the world’s first compressed natural gas carrier and the first dual-fueled offshore support vessel built in NA.

Motiva creates Louisiana Refining System Motiva Enterprises LLC plans to integrate its two Louisiana refineries, Norco and Convent, to create the Louisiana Refining System. The company said the multi-phased project creates significant operational opportunities, including growing access to advantaged light oil, optimizing inter-plant intermediates and conversion units, increasing distillates yield and reducing operating costs. With an integrated crude capacity of over 500 Mbpd, Motiva’s Louisiana Refining System (FIG. 4) will rank in the top five of North American refineries in capacity. The Maurepas pipeline system, which comprises three pipelines that will be built, owned and operated by affiliates of SemGroup Corp., is the first step in the project. The Maurepas crude pipeline will connect the existing LOCAP terminal in St. James, Louisiana, to the Norco refinery via a 34-mi pipeline, improving access to advantaged domestic crude oil. The Maurepas 35-mi and 34-mi intermediates pipelines will directly connect the Norco and Convent refineries, supporting optimization of both plants’ conversion units while improving logistics efficiency, alleviating dock congestion and allowing additional product exports.

FIG. 4. Motiva, owned equally by Shell and Saudi Aramco (through subsidiaries), owns three refineries located in Convent and Norco, Louisiana, and Port Arthur, Texas.

News When the pipelines are complete, Motiva plans to idle the fluid catalytic cracker (FCC) at its Convent refinery and to reconfigure the existing hydrocracker unit at its Norco refinery to process 30 Mbpd of additional gasoil into high-quality diesel. On a combined basis, the Louisiana Refining System is expected to drive incremental annual benefits of $350 MM of EBITDA.

Pentair valve facility expands Korean operations Pentair Valves & Controls’ Anseong manufacturing facility in South Korea will now also produce trunnion-mounted ball valves under Pentair’s FCT brand, helping to satisfy the demand for Korean-manufactured products. The expanded facility enables Pentair to supply ball valves for local projects, offering Korean EPC customers high-quality products, shorter lead times and cost savings. Operations at the plant include valve manufacturing, assembling and testing for critical applications in the on- and offshore oil and gas, marine and LNG industries. The plant will produce forged carbonsteel and FCT-branded stainless-steel ball valves, certified to API 6D and API 607, in sizes up to 24 in. Design features, such as an anti-blowout stem shouldered inside the body and a three-barrier stem sealing, ensure complete fire safety and fugitive emission control for maximum protection and reliability. In addition, the valve’s true double-block-and-bleed control at full rating with high trim resistance helps to provide a longer service life in critical process application, such as water hammer. The Anseong facility expansion builds on Pentair’s FCT valve technology and expertise from its FCT flagship plant in Saint Juery, France, and from its other plants in Rescaldina, Italy; Sharjah, UAE; and Chengdu, China.

Elliott Group supplying compressor string for refinery Phillips 66 has selected Elliott Group to supply a compressor string for a major project at its Sweeny refinery in Old Ocean, Texas. The project will enable the refinery to meet the requirements set forth by the US EPA’s Tier 3 clean fuels standards. Jacobs Engineering Group is the engineering

procurement contractor for the project. Elliott will provide a recycle compressor designed to increase clean product yield. The equipment string includes a 25 MB motor-driven compressor similar to the unit shown in FIG. 5. The contract also includes a master service agreement between Elliott and Phillips 66. The unit will be built and tested in Elliott’s Jeannette, Pennsylvania factory, with delivery scheduled for early 2016.

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Industry Metrics

5

130 Cracking spread, US$/bbl

Mar. 15

Feb. 15

Jan. 15

Nov. 14

Oct. 14

Sept. 14

July 14

June 14

May 14

Aug. 14

Mar. 15

Feb. 15

Jan. 15

Dec. 14

Mar. 15

Feb. 15

Jan. 15

Dec. 14

Nov. 14

Oct. 14

Sept. 14

Aug. 14

Mar. 14

Global new project announcements, April. 2014–Mar. 2015

Mar. 15

Feb. 15

-20

2016-Q1

Jan. 15

2015-Q1

Dec. 14

2014-Q1

Nov. 14

2013-Q1

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

Oct. 14

2012-Q1

Gasoil, 10 ppm S Fuel oil, 1% S

-10 Mar. 14

2011-Q1

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

Sept. 14

-0.5 -1.0

0

Aug. 14

0.0

10

July 14

0.5

June 14

1.0

20

May 14

2.0 1.5

April 14

Forecast

Rotterdam cracking spread vs. Brent, 2014–2015* 30 Cracking spread, US$/bbl

2.5

Stock change and balance, MMbpd

Singapore cracking spread vs. Dubai, 2014–2015*

50

Source: Hydrocarbon Processing Construction Boxscore Database

Mar. 15

Feb. 15

Jan. 15

Dec. 14

Nov. 14

April- May- June- July- Aug.- Sept.- Oct.- Nov.- Dec.- Jan.- Feb.- Mar.14 14 14 14 14 14 14 14 14 15 15 15

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

Oct. 14

0

Prem. gasoline unl. 92 Jet/kero

Sept. 14

10

0

-10 -20 Aug. 14

20

10

July 14

30

20

June 14

40

Mar. 14

Cracking spread, US$/bbl

30

May. 14

Supply and demand, MMbpd

World liquid fuel supply and demand, MMbpd Stock change and balance World demand World supply

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

-10

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

96 94 92 90 88 86 84 82 80 78 2010-Q1

Prem. gasoline unl. 93 Jet/kero

0 July 14

Source: DOE

10

June 14

W. Texas Inter. Brent Blend Dubai Fateh

70

30 20

May 14

85

April 14

100

April 14

Oil prices, $/bbl

40

40

New projects

Japan Singapore

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

115

55

Nov. 14

Selected world oil prices, $/bbl

US EU 16

Oct. 14

Mar. 14

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

70 60 50

Sept. 14

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

80

Aug. 14

1 0

90

July 14

2

June 14

3 Monthly price (Henry Hub) 12-month price avg. 12-month price avg. Production

Global refining utilization rates, 2014–2015*

May 14

4

Brent, Rotterdam

100 Utilization rates, %

5

April 14

6

Arab Heavy, US Gulf LLS, US Gulf

WTI, US Gulf Dubai, Singapore

Dec. 14

0 -5

Mar. 14

7

80 70 60 50 40 30 20 10 0

Gas prices, $/Mcf

Production, Bcfd

US gas production (Bcfd) and prices ($/Mcf)

15 10

April 14

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

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

Global product markets and refinery margins, particularly in the US, have seen steady improvement since January. Worldwide gasoline demand has soared in recent months in both OECD and non-OECD regions. New refinery capacity coming onstream in the Middle East could lead to increased competition in the global gasoil market.

* Material published permission of the OPEC Secretariat; copyright 2015; all rights reserved; OPEC Monthly Oil Market Report, April 2015. Hydrocarbon Processing | MAY 201519

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Reliability

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

Reassessing and updating electric motor bearing lubrication Over the past 25 years, this column has often dealt with electric motor lubrication. As listed in the recommended reading list, this subject is often asked and, of course, there are updates to the recommendations. Many of the updates commingle with important new technologies. Case 1. Not long ago, the author was contacted by a major US

oil refinery. The author had visited this site in late 2012 or early 2013 to address electric motor lubrication matters. At this refinery, the electrical department was in charge of everything regarding motor maintenance. The leaders at that location had taken the position that oil mist was unsuitable for electric motors—an incorrect notion, which is solidly refuted by 27,000 electric motors lubricated and operating elsewhere. Some of the “elsewhere” locations include both horizontal and vertical electric motors in countries around the world. At a competitor’s ethylene plant in Texas, oil-mist-lubricated motors range from 1.5 hp to 500 hp. On many of the 107 vertically oriented oil-mist-lubricated motors in the Texas facility, no motor bearings needed to be replaced over a 37-year period from 1977 to 2014. One problem at a major oil refinery located in a northern US state was that, when solving technical issues, solutions were often based on opinions instead of on solid facts. These opinions were then passed down to younger staff members, who, without input or mentoring from more experienced individuals, had no incentive to replace anecdotes with facts. The corporate engineering group claimed that oil mist could not be cost-justified. Corporate had neglected to factor in the remarkable labor savings and total life extension of oil-mist-lubricated electric motors. As a consequence, the refinery specified and purchased grease-lubricated electric motors. They also stipulated voltage, speed, service factor, hp, insulation grade and other parameters. Yet, nobody at this refinery showed any interest in specifying the bearing style and grease path that are considered equally important by reliability-focused competitors.

asserting that their motors could not be lubricated by oil mist. Two of the four bidders explained that oil mist would get past the internal seals located between bearings and motor internals. Note: “V-ring” seals will leak after two years of operation; this has been known for five decades. Also, motors from all four vendors included styles or models of vertical motors at a location in the same area. These vertical motors had been successfully lubricated with oil mist for many decades. An informed user quite obviously knows more than suppliers that choose to remain uninformed. In some cases, the suppliers decline to sell long-life equipment for a host of different reasons. Due to the position taken by the four motor vendors, grease and liquid oil would be allowed for the 2014–2015 Texas project. However, the grease had to be dispensed differently for the different bearing housings and grease paths. Some users try to push grease into the reservoir, as shown in FIG. 1, without first removing the drain plug. Consequently, the rolling elements will scrape on the (pressure-deflected) shield. When the shield is moved to the other side, re-greasing will over-fill the bearing. Remember: Bearings should have only about one-third of the void space between rolling elements filled with grease.

1. Lubrication entry 4. Bearing 5. Inner cap

3. Shaft Single-shield motor bearing with shield facing the grease cavity

No wisdom without knowledge. Certainly, the project de-

partment at this particular refinery did not insist on an expanded specification. Why engage in a career-limiting battle with entrenched non-readers when all that truly counts are initial costs and commissioning schedules? The cost-estimating basis for electric motors at this refinery reflected only the least initial cost, and each motor supplier wanted to be the lowest bidder. Case 2. During a 2014–2015 project for a large petrochemical

plant in Texas, four out of four motor vendors provided letters

6. Bracket

2. Drain

FIG. 1. During re-greasing, the expulsion port (Item 2) must be open. Failure to remove the plug can quickly ruin a bearing. On singleshielded bearings, the shield must be located as shown here. Hydrocarbon Processing | MAY 201521

Reliability

Recommended reading list for oil-mist lubrication applications 1. Bloch, H. P., “Dry sump oil mist lubrication for electric motors,” Hydrocarbon Processing, March 1977. 2. Bloch, H. P., “Oil mist lubrication: Is it cost-justified?,” Hydrocarbon Processing, October 1990. 3. Bloch, H. P., “When to use lifetime lubricated ball bearings,” Hydrocarbon Processing, July 1991. 4. Bloch, H. P., “Storage preservation of machinery,” Hydrocarbon Processing, August 1991. 5. Bloch, H. P., “Oil mist proven for electric motor lubrication,” Hydrocarbon Processing, August 1994. 6. Bloch, H. P., “Implementing modifications on pumps and motors,” Hydrocarbon Processing, September 1994. 7. Bloch, H. P., “Identifying electric motor bearings,” Hydrocarbon Processing, November 1995. 8. Bloch, H. P., “Lubrication—not an afterthought,” Hydrocarbon Processing, February 1997. 9. Bloch, H. P., “Select better bearings,” Hydrocarbon Processing, June 1995. 10. Bloch, H. P. and A. R. Budris, Pump User’s Handbook— Life Extension, 4th Ed., The Fairmont Press, Lilburn, Georgia, 2013. Again, purchasers with proper lube specifications will avoid calamity, whereas others will invite distress. An alert reader of technical texts and information sources will outperform any non-reader. A company with no budget for technical information, books or training will have more repeat failures than a company that invests in the knowledge of its maintenance staff and engineers. Several decades of observation support these disturbing facts, but talking about the situation could prove career-limiting for some. Sealed bearings and smart greases. Assume a refinery

entrusts motor lubrication to individuals who do not exactly know bearing configurations and grease paths, although motor nameplates do contain that information. In their misguided desire to save time by not removing the drain plug, workers often curtail bearing service life. Flawed motor lubrication negatively impacts refinery safety and reliability. Many refineries may be much better off installing sealed bearings throughout plant electric motor population. These sealed bearings would benefit from a perfluoropolyether (PFPE) synthetic grease, which, according to FIG. 2, has an L-10 life at least 10 times that of mineral-oil-based electric motor greases. Of course, it may be the best course for the Case 1 refinery to closely observe its competition. This refinery could extend its existing oil-mist systems at minimal incremental cost to cover not only pumps but also electric motors. If that is impossible because management prefers to act on outdated opinions rather than on well-established facts, then the refinery may consider reverting to a sensible backup strategy. 22MAY 2015 | HydrocarbonProcessing.com

Bearings failed, %

Bench bearing lift test – ROF+ Krytox lubricant AUT 2E45 Weibull probability plot – included lives: L10 L50 – conf. interval: 90% two sided 6204 bearing, 10,000 rpm at 177°C

99 95 90 80 70 60 50 40 30 20

AUT 2E45 Polyurea #1 Polyurea #2

10 5 2 1

2

3 4 5

102

2 3 4 5 103 Bearings grease life, hr

2

3 4 5

104

FIG. 2. Weibull life comparisons for different greases. Source: DuPont.

Such a strategy might involve teaming up with companies maintaining application engineering ties to DuPont. Application engineering leader Boulden Co. or DuPont’s lube marketers can introduce users to Krytox PFPE synthetic grease as a “lube for life” solution in both (small) pumps and (mid-size) electric motors. A document available from both companies shows standard test results of Krytox vs. synthetic hydrocarbons where Krytox lasts 50–60 times longer. This author believes that Krytox can serve as a lube-for-life solution in electric motors and pumps with shafts up to 3 in. in diameter operating up to 3,600 rpm on a continuous basis (DN of about 400,000). Service life considerations. It is likely that grease life with sealed bearings in these applications will approach 10 years of continuous service. PFPE-base oil cannot oxidize, and no solids or varnishes are formed. Because electric motor and pump bearings run at far lower than the evaporation temperature of the base oil, the lubricant will last the service life of an average bearing. There is a high probability that bearings with Krytox sealed in offer oil-mist averse plants significant benefits in eliminating routine maintenance and potential failure modes associated with over-greasing bearings, using the wrong grease, or having grease oxidize/solidify due to excessively long re-greasing intervals. Subject to the concurrence of Texas A&M’s International Pump User Symposium (TAMU) advisory board, I am planning to elaborate on pump lubrication matters at TAMU’s 31st International Pump Users Symposium in Houston, Sept. 14-17, 2015. As part of a newly developed tutorial, I will update pump and motor bearing lubricant application matters. A different and highly experience-based ranking will be offered 30 years after a more generalized ranking was published by a bearing manufacturer in 1985. HEINZ P. BLOCH is the reliability/equipment editor of HP. The author of 19 textbooks and over 600 papers or articles, he was a senior engineering associate for Exxon Chemicals. He is in his 53rd year as a reliability professional and continues to advise process plants worldwide on reliability improvement, failure avoidance and maintenance cost reduction opportunities. He holds BSME and MSME degrees from the New Jersey Institute of Technology and is an ASME Life Fellow.

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Automation Strategies

PAUL MILLER, SENIOR EDITOR/ANALYST ARC Advisory Group

Developing the best practices for operator effectiveness in the age of collaboration Multiple converging trends make operator effectiveness even more important today than ever before. These include: loss of expertise in industrial plants and the transition to a new workforce, business imperatives to “do more with less,” increasing regulatory compliance pressures, and new information technology (IT)-based enabling technologies moving into the operational technology (OT) space. Today’s plant operators must collaborate effectively with other operators and operations supervisors within their own plants; with plant maintenance staffs and engineering and IT groups; and with business planners and supply-chain professionals at the corporate level. These converging trends and associated business imperatives make it critical for owner/operators across a broad range of industrial sectors to identify best practices for operator effectiveness and to support benchmarking, knowledge transfer, onboarding and continuous performance improvement initiatives. Owner/operators searching for answers. Based on discussions with a large number of technology end-user clients across a variety of upstream and downstream process industries, ARC Advisory Group acknowledges that owner/operators are struggling to identify best practices for how their operations staffs can best interact with the production process to improve performance. Operators must also be able to take advantage of the tremendous amount of data and information now available from control systems, asset-management systems, alarm-management systems and historians to make better decisions. Increasingly, plant operations staffs must collaborate with others inside and outside the plant—and become more attuned to the total business. While ARC’s ongoing research into collaborative process automation systems (CPAS) and related industry initiatives such as the Industrial Internet of Things (IIoT), Industrie 4.0 and Smart Manufacturing provides some guidance, TABLE 1 summarizes questions about some basic issues. New IT-based collaboration tools offer potential. Effec-

tive collaboration requires a high degree of situational awareness, including operational window compliance and a good overview of the status of procedural automation, process control and any abnormal situations. New collaboration tools—many based on Internet Protocol (IP) and concepts of the emerging IIoT—offer significant potential to improve operator effectiveness through increased access to sensor-based data, new cloud-based data analysis tools and better collaboration, both within plants and across multi-plant enterprises. However, many of these tools remain unproven in

TABLE 1. Common issues regarding operator effectiveness and best practices What are the most important collaboration points for plant operations staffs? What data are most important for field and control room operations staff, and what is the best way to present this information? How do you prevent overloading operators with too much data? What factors create the most effective work environment for operators?

demanding industrial environments in which downtime is unacceptable and occasional “glitches” can have serious repercussions. Many end users in the heavy process industries still also have serious concerns about hosting critical data and applications in the cloud due to the persistent threat of cyber security intrusions. Information overload is another concern. Present control systems already provide operators with more raw data and information than they often know what to do with. The newer information and collaboration tools can only exacerbate the situation. Rather than more data and information, it is important for operators to quickly and easily access the right information, in the right context, and in a time frame that makes it useful for real-time decision support. The operators themselves are often in the best position to determine this. Help identify best practices. Clearly, new IT-based technologies and IIoT concepts offer significant future potential to improve operator effectiveness and collaboration. However, many of these technologies and concepts remain unproven in industrial environments, driving owner/operators to wonder what their peer organizations are doing in this area. To help identify best practices, ARC Advisory Group has launched a confidential web survey on this topic.1 Qualified survey participants will receive a detailed summary. ARC will also update HP readers in a future column. 1

EDITOR’S NOTE For more information, visit www.arcweb.com. PAUL MILLER is a senior editor/analyst at ARC Advisory Group and has 30 years of experience in the industrial automation industry. He continues to follow the increasing adoption of IT in the OT area and its various ramifications for industrial organizations.

Hydrocarbon Processing | MAY 201525

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Project Management

RON BECK Director of Industry Marketing Engineering & Construction, AspenTech

Build a better bid, or how to achieve a competitive advantage in capital projects As backlogs and revenues continue to be strong and on an upward path for most global engineering and construction (E&C) firms, competition for the best projects has increased. The energy industry’s turbulence and new sense of urgency have imposed aggressive schedules in the bidding phase. Result: E&C companies are responding with more aggressive bids, which, in turn, create more uncertainty over cost estimates and project scopes. Resource shortages and other factors have played a major role in elevating project costs, and owners have responded by pushing E&C companies to provide lump-sum bids. In addition, owners have compressed the front-end engineering and design (FEED) stage of projects, which has led to more midcourse corrections in the project scope, thus taxing the project execution fluidity. To achieve a competitive advantage under this environment, leading E&C companies are applying new powerful and versatile software technologies that empower organizations during the bidding, contracting and project execution stages. In addition to the increasing number of capital projects worldwide, the size and complexity of these projects have significantly expanded. While a number of global E&C companies have responded by increasing the size of their workforces through acquisitions and organic growth, some companies are concerned that this approach may not be the best solution. According to Chiyoda Corp.’s executive, Takashi Kubota, speaking at Rice University in September 2014, “We need the size, but does bigger mean better? We are not sure.” To remain agile as the size of projects increases, companies need to adapt software that provides the ability for lead estimators and project managers to have superior visibility over the details and complexity of the project. Result: E&C enterprises will have better oppor-

tunities to navigate through the necessary environment of risk and uncertainty. The SADARA petrochemical complex, the world’s largest grassroots petrochemical engineering project, was successful in cost estimations and project planning by applying leading-edge technology.1 Additionally, a number of smaller and agile, boutique engineering companies have emerged to fill the needs of industry for specialized engineering to manage small- to mid-sized projects. These emerging companies, often innovative in their organizational style and business processes, have been able to take particular advantage of new software approaches to project development, thus enabling them to compete successfully in the E&C business. Transparency in the estimate. Experienced estimators are among the scarcest resources in the downstream industry. When time is not a critical factor, bruteforce estimating man-hours can be substituted for experience, but this usually only masks the importance and value of an experienced workforce. At the bidding and very early engineering phases, time is a gating factor. Additionally, the judgment and ability to consider contingencies by an experienced estimator are crucial. For companies lacking experienced estimators, one solution has been to integrate proper software systems with the process, which can be critical in engendering success. The temptation of an estimating group, when under pressure, is to enumerate quantities by developing very large “supercharged spreadsheets.” Many of the project assumptions are hidden in formulas within the spreadsheet, and the overwhelming size of such spreadsheets keeps increasing. The difficulties with this enumeration approach are that the full project scope is not transparent. There is a challenge in separating the important cost determinators from

the less important details. Result: The flexibility to explore scope and process alternatives is lost. A more sophisticated and effective approach focuses on providing the correct project scope and aligning this scope with the process definition, rather than focusing on enumerating details. Now, E&C companies can concentrate on getting major equipment items and metallurgy correct from the processing point of view. Bulk details, attained through statistical and experienced-based engineering approaches, can be built into the estimating software. This approach has been demonstrated to improve the overall predictability and variance of estimates, and it greatly reduces the required estimating manpower, while improving the transparency of the project estimate in communications between the estimators, the executive team and the proposal manager.2 Aligning with the owner. A recent Ernest & Young (EY) survey investigated 365 oil and gas megaprojects, where 64% were identified as running over budget, and 73% as behind schedule. While there were 15 key factors responsible for these problems, during the project development phase, aggressive estimates and inadequate planning contributed largely to the overly aggressive forecasts. By utilizing the proper software systems, E&C organizations can attack these problems. A strong front-end-design collaboration system can make a true and accurate process flow diagram (PFD) and key equipment lists available to the proposal team and owner. Such information is provided in a platform for clear and transparent communication and discussion of project scope. It ensures that bids and estimates are prepared with the same realistic basis that the owner is requesting and expecting. This also creates the basis for the owner and E&C company to confront arHydrocarbon Processing | MAY 201527

Project Management eas of uncertainty and risk in the proposed project, required resources, and realism in the execution plan to make the appropriate decisions early enough in the project planning and development process. Breaking down barriers. As global work sharing and the size and scope of projects have increased, managers have become resistant to changing the highly structured business processes. To meaningfully address both the bidding and project execution challenges and risks, these business processes are now being evaluated and upgraded. The powerful capabilities of underlying systems, together with wholesale changes in the engineering workforce, present opportunities for conceiving, developing and executing projects in new ways. Specifically, during the bidding process, the opportunity to tie together process modeling systems, software to rate major equipment items, front-end deliverable collaboration solutions, and estimating and formal risk analyses will lead to a competitive advantage and bet-

ter company and project performance for those organizations that embrace it. Standardized and modular design. Another key trend being driven by the energy industry is the standardization and reuse of designs. These one-of-a-kind engineering approaches, which have been used for decades, are increasingly viewed as a problem in a marketplace where spiraling capital project costs can create significant friction. Energy firms are looking for E&C companies to lead the way in proposing standardized rather than “goldplated” designs. The same integrated solutions can be applied, in contrast to the traditional workflow, to capture standard repeatable (or modular) design components as building blocks for projects that can be designed and engineered much more efficiently and with higher quality. E&C companies that adopt integrated project modeling techniques and flexibility into their risk management or project changes will help energy companies. This can provide enormous value, and will support large-scale

projects more effectively. When an E&C firm reduces the cycle time of a project by a significant amount (i.e., 10%–30%), it can help the client deliver results more quickly. Additionally, by using the same software between the owner-operator and E&C company, especially when applied with a transparent software system, the scope and resource requirements are clearly communicated. The owner uses this to evaluate bids on a “like for like” basis and ensure that all requested scopes are included. Owners such as ConocoPhillips have demonstrated improvements in project timetables, capital predictability and E&C oversight through the transparent use of the same model-based software system. Effective decision-making. The E&C industry is rapidly changing. Customer demands are increasing. Being able to adapt strategy and equip engineering expertise with a cutting-edge economic evaluation software platform throughout the engineering cycle will help to capitalize on project opportunities. By providing cost estimators and project managers with the right tools, project uncertainty and risk can be reduced, thus enhancing the capability for effective decision-making to control capital costs. In the quest for bid-to-win contracts, better and faster designs mean better value for customers, which underpins a successful strategy for E&Cs to survive and thrive in a rapidly developing market. NOTES The SADARA petrochemical complex’s cost estimations and project planning was aided by applying the Aspen Capital Cost Estimator estimating system. 2 Estimating groups, including S&B Engineers, Linde Engineering, Technip USA and Suncor’s engineering organization, have reported a 3:1 to 5:1 estimator productivity gain. 1

RON BECK is director of industry marketing at AspenTech. During six years at the company, he has been responsible for engineering product marketing, including Aspen Economic Evaluation and Aspen Basic Engineering product families. He has over 20 years of experience in providing software solutions to the process industries and 10 years of experience in chemical engineering technology commercialization. Mr. Beck has authored papers on key industry topics and presented at several public industry events, and is a graduate of Princeton University.

28

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Global

SHEM OIRERE Guest columnist

Uganda proceeds with new refinery Uganda is proceeding with the construction of a $2.5-B, 60-Mbpd crude oil refinery with approvals from analysts for this landlocked country’s downstream plans. The engineering, procurement and construction (EPC) contract has been awarded to RT Global Resources of Russia. Uganda’s neighbor and East Africa’s largest economy, Kenya, has confirmed the acquisition of a 2.5% stake in the new downstream complex at an estimated cost of $60.9 MM. “The construction of the refinery is the first step in monetizing the oil reserves of Uganda,” says Chris Bredenhann, PwC Africa oil and gas advisory leader of the crude processing plant located in the Hoima district of the Albertine Basin. Project parties. RT Global Resources, a subsidiary of Rus-

sia’s defense giant, Rostec, is leading a consortium that includes other Russian firms such as Tatneft and VTB Capital, the investment arm of Russian bank VTB, along with South Korea’s GS and Telconet Capital Ltd. Partnership. The Russian-firm-led consortium edged out SK Engineering and Construction Co. to attain the deal. However, the Ugandan government has retained the Korean firm as an alternate preferred bidder after fears emerged due to sanctions levied by the US and EU against Russian companies and close allies of Russian President Vladimir Putin. The new refinery project marks the end to a prolonged tug-of-war between the Ugandan government and international oil companies over a controversial tax regime and delayed regulatory requirements to govern the exploration and production contracts for the country’s estimated commercial reserves of 3.5 Bbbl. Originally, the government had proposed a 120-Mbpd refinery. “The primary concerns of the oil companies (in Uganda) today are receiving approvals on their development plans so that work can go forward, leading to actual production of crude oil,” says Matthew Tallarovic, director of tax services for Deloitte East Africa. “These approvals for developing the fields are necessary before an export pipeline or refinery can actually be viable.” The UK’s Tullow Oil, France’s Total SA and China National Offshore Oil Corp. (CNOOC) are developing the oil fields in Uganda’s Albertine Basin. Commercial production of hydrocarbons is expected in 2018 and will coincide with the completion of the first phase of the new refinery, which will process 30 Mbpd. “Concerns that the falling global oil prices could constrain downstream projects, such as the Ugandan refinery, may not necessarily be founded. As for Uganda, the refinery will only be the middle man in the picture,” says Tallarovic. “As long as there is demand and an available supply, the refinery works off

the margins in between, and so it is somewhat insulated from the price fluctuations.” Refining in Africa. Uganda’s new refinery is being developed at a time when many refineries in Africa are characterized by low utilization rates, underfunding, inability to modernize and political uncertainties. All of these challenges could easily be circumvented in favor of a new refinery in Uganda. “It is true that African refineries suffer technical and operational challenges,” says Bredenhann. “But it must be recognized that many of the African refineries are old, and, as a result, they are not able to operate at the efficiency levels that we see in other parts of the world where investments have been made in newer technologies. However, with the right approach to partnering and skills development, it could provide a unique and wonderful opportunity for Uganda.” Growing demand. Uganda, with an estimated petroleum product consumption of 27 Mbpd, could also take advantage of the growing demands for cleaner fuels, which many of the older African refineries cannot produce. East African countries consume an estimated 200 Mbpd of refined products with an annual demand increase of 7%. Kenya Petroleum Refineries Ltd. met this demand until shutting down in the last quarter of 2014 after Essar Energy Overseas Ltd., a wholly owned subsidiary of India’s Essar Energy, pulled out of a 50-50 partnership with the government of Kenya. The Kenyan government has since approved a $5-MM acquisition of the Essar stake in the Mombasa refinery. The 35-Mbpd refinery is designed to process Murban heavy crude from Abu Dhabi and other Middle East heavy crude grades. “In East Africa, refining capacity is completely inadequate to meet the liquid fuel demand, resulting in the entrance of large traders in the region,” says Bredenhann. “Even with the construction of the Ugandan refinery, there will still be a need for imports.” The refinery project will also include crude oil and product storage facilities onsite, along with a 205-km oil pipeline to a terminal at Buloba, 15 km from the capital Kampala. SHEM OIRERE has reported widely on the business beat for Kenyan newspapers The Daily Nation, Kenya Times and The People. He also freelances, reporting extensively on Africa’s energy, construction and chemical industries for various international publications. He graduated from journalism school in London.

Hydrocarbon Processing | MAY 201531

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Petrochemicals

SHEENA MARTIN Contributing Editor

M&A deals rise as investors push petrochemical leaders to restructure Oil and petrochemical companies are seeking strategies to remain competitive as their cash flows continue to take direct hits due to depressed oil prices. This is resulting in significant restructuring and simplifying of balance sheets to curb the negative impacts of market turbulence, and that, in turn, creates a ripe environment for mergers and acquisitions (M&A). A. T. Kearney, a leading global management consulting firm, predicts that the global chemicals industry will witness increased M&A during 2015, according to the firm’s Chemicals Executive M&A Review. About 60% of executives surveyed see rising M&A activity in 2015, with deal values in the chemical industry having spiked 13% since 2013. Rise of shareholder activism. Man-

agement, however, has not been the primary driving force behind this company restructuring. Instead, shareholders are giving their voice, pushing for more attractive, simplified corporate structures that are agreeable for M&A. “Activist investors are putting pressure on the management of some of the most prominent chemical majors to streamline their business portfolio,” said A. T. Kearney partner Joachim von Hoyningen-Huene. Activists are primarily facing off with North American companies at the moment, but increasing fund sizes and a scarcity of underperforming assets in the region have also led A. T. Kearney to forecast stronger shareholder activism in Europe and Asia. Targeted companies. In the US, activists have already targeted upstream companies such as Chesapeake Energy, SandRidge Energy, QEP Resources and Hess. In the downstream chemical sector, activist investors have recently taken aim at Dow Chemical (FIG. 1) and DuPont.

Richard Forrest, co-author of the A. T. Kearney study, said the “window of opportunity” for M&A may be short, and “companies with strong cash flow and healthy balance sheets will be able to leverage opportunities.” This is the road on which activist investors are trying to push companies forward. Much of shareholder demand consists of companies de-leveraging underperforming business sectors and simplifying complex business structures for a more finetuned composition. Dow Chemical began implementing divestitures of lower-return operations to the tune of $5 B, to help it improve profitability and streamline processes. However, activist shareholder Dan Loeb of Third Point LLC is pushing for more. Loeb has requested Dow management to separate its commodity petrochemical and specialty chemicals businesses to maximize shareholder value. However, as of the time of publication, Dow has rejected this course of action. Third Point has acquired $1.3 B worth of shares in Dow since late 2014. After Loeb announced his investment, stock prices increased by approximately 14%, as of the end of March. For the foreseeable future, A. T. Kearney believes that strategic investors will drive M&A activity in the chemical industry. Strategic deals streamlining portfolios could lead to a resurgence of the US chemical industry, with help from low-cost feedstock and high-level fragmentation of Asian chemical markets. Activist investor Nelson Peltz is similarly challenging DuPont, initially targeting the replacement of four of the company’s directors. Peltz’s radical approach also calls for the company’s breakup. This aggressive push, however, could cause corporate America to draw a line on how much power to give to investors.

Successful history. Peltz is not necessar-

ily out of line with his demands. Air Products & Chemicals bent to the will of William Ackman in 2013, a credit to the power that an activist approach can have in swaying a company’s leadership and direction. Ackman’s investment group, Pershing Square Capital Management—which holds a 9.8% share in Air Products & Chemicals—dislodged the company of its former CEO, John McGlade. In 2014, board members agreed to enter discussions to hear out Ackman’s views on enhancing the company’s performance by changing its corporate culture and improving investment decisions. As of late March, the company’s shares have increased 40% since Ackman’s involvement. DuPont, however, is better positioned to challenge Peltz’s hedge fund, Trian Fund Management. The hedge fund has an approximately 2.7% stake in DuPont, which makes it the fifth-largest company shareholder. Ultimately, what all activists have in common is the goal to strengthen each company’s balance sheet and limit exposure to poorly performing assets—especially in light of changing breakeven oil prices. A. T. Kearney’s study believes those factors will put independent oil companies in prime positions to find success in the upcoming M&A wave.

FIG. 1. Dow Chemical is one of many chemical companies for which activist investors are seeking change. Hydrocarbon Processing | MAY 201533

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Engineering Case Histories

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

Case 84: Remaining service life of plant equipment can be determined For new plant machines and equipment, the life expectancy is determined by the original equipment manufacturer (OEM). Yet, different analysis techniques are often required in a failure analysis. In a processing facility, the reliability or project engineer may be asked if damaged equipment can be safely operated until a controlled shutdown is possible. This requested time is usually days, not months. In the real world, careers are not enhanced by mandating immediate equipment or unit shutdowns without supporting data. Solutions. Engineers have the analytical tools available to make decisions based on an educated and thorough analysis. Here are some examples:1 Bearings. The service life of new ball and roller bearings can be determined by the loads, speeds, lubrication method, cleanliness and other factors. The number of cycles that the bearings will endure before evidence of metal fatigue occurs determines the length of service (life). For new designs, the engineer will consider the L10 life or the life that 90% of the bearings will exceed before failure. Exceeding the L10 life will usually not result in a failure. For a failure analysis, engineers should be interested in knowing under what conditions failures are most likely to occur. A 90% chance of a failure occurs at about 14 times the L10 life.2 Shafts, rotors, pressure vessels and structures. With the various loads and stresses, material properties, surface finishes and stress concentrations known, the fatigue life in axial, bending, shear and torsion can be determined in cycles. Using certain techniques (e.g., the Palmgren-Miner linear damage rule), the life reduction due to excessive periodic loading can also be determined. A metal “remembers” when it has been overstressed, as its remaining service life will have been permanently reduced. The damage rule will approximate how much. Steel parts with cracks. When cracks are present, traditional fatigue calculation methods may not be applicable. This is because 90% of the fatigue life of a part is exhausted by the time a crack develops. Other techniques, such as fracture mechanics, must be applied. When the crack size is known along with the material type and the stresses opening and closing the crack, the growth rate can be determined. A life assessment can then be done by assuming that a very small crack is present and then determining how fast it will grow, or if it will grow at all. When the part is a brittle material, meaning certain low-ductility materials, the crack growth can be fast (such as 7,000 ft/sec). This crack should never be allowed to materialize! Growth of such cracks is dangerous, and it is difficult to monitor as these cracks are unstable.

Use this rule with brittle materials: In critical equipment constructed of old brittle material that has cracks, shut it down and repair it or assess by using fracture mechanics techniques. Even if the equipment has run successfully over the years, one major upset or shock loading could cause cracks to grow rapidly. Part wear. Wear equations make it possible to determine the wear rate of two materials sliding together dry or with lubrication between them. The wear of gear teeth, extruder barrels/ screws or the wear of a rotating shaft in a bore are examples in which service life calculations in cycles are possible. Gear life due to pitting, bending, wear and scoring failures. Load calculations will allow service life assessments on new gears with different lubricants, loads, speeds and tooth profiles. Service life will be in cycles or the probability of failure. Pitted gears will not provide useful life assessments, but a sensitivity analysis may show the root cause for the pitting. Creep life. The service life of furnace tubes and other components under high temperature can exhibit creep—an elongation due to failure under a constant stress. The stress could be in a pressurized tube in a high-temperature environment. The furnace tube material can thin out and rupture at any given time. This service time can be calculated and estimated in hours. Best advice. All service life calculations are approximations

since the data are scattered, and probabilities are used. Users must understand that the equipment service life could be longer or shorter. However, if the life calculations indicate that a threeyear life is remaining and that only a day run is required, then this is valuable data to use in the decision-making process. NOTE Case 83 was published in HP in March. For past cases, please visit HydrocarbonProcessing.com. LITERATURE CITED Sofronas, A., Analytical troubleshooting of process machinery and pressure vessels, John Wiley & Sons, 2006. 2 Palmgren, A., Ball and roller bearing engineering, Burbank and Co., pg. 74, 1959. 1

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 | MAY 201535

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Viewpoint

GREGORY DOLAN, CEO Methanol Institute, Washington, DC

Methanol takes on LNG for future marine fuels

EU programs. From 2010–2014, two European programs—Efficient Shipping with Low Emissions (EffShip), and Alcohol (Spirits) and Ethers as Marine Fuel (SPIRETH)—identified MeOH as an alternative fuel that could reduce emissions and improve the environmen-

tal performance of marine transport. The technology development work from these programs contributed to the IMO’s draft IGF code (International Code of Safety for Ships using Gases or other Low-Flashpoint Fuels), which governs the safe handling of LNG and MeOH fuels onboard ships. New MeOH-powered ships ordered. In December 2013, Methanex Corp., the world’s largest MeOH producer and distributor, announced an agreement with Mitsui OSK Lines (MOL) to build seven new 50,000-dead-weight-ton ships with MAN Diesel & Turbo’s ME-LGI flex-fuel engines running on MeOH, fuel oil, MDO or MGO. The ships are being built for delivery next year by Japan’s Minaminippon Shipbuilding Co. and South Korea’s Hyundai Mipo Dockyards Ltd. The ships have been chartered by Canada’s Waterfront Shipping Co., a subsidiary of Methanex. In January, Lloyd’s Register announced plans to design a whole new generation of cruise ships and RoPax ferries powered by MeOH, ushering in a low-emission, fuel-efficient revolution in today’s marine fleet. Partnering in the project are German shipyard Meyer Werft, German shipbuilder Flensburger-Schiffbau-Gesellschaft and German MeOH distributor HELM AG. Funded by the German government, designs for

4.5 World

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On Jan. 1, a major change occurred as ships entering within 200 miles of US, Canadian, Caribbean and northern European waters began to face a 0.1% sulfur (S)-fuel limit (FIG. 1). National and regional environmental agencies in these areas have established emission control areas (ECAs) under pollution rules adopted by the International Maritime Organization (IMO), an agency of the United Nations. Shipowners can comply by shifting to low-S marine gasoil (MGO) or marine diesel oil (MDO), but can expect a 50% increase in fuel costs.

METHANOL AS A MARINE FUEL Let’s look at the global efforts to demonstrate MeOH as a marine engine fuel:

Marine fuel sulfur limits, %

GREGORY A. DOLAN has held a variety of senior management positions with the Methanol Institute (MI) over the past 17 years. He is CEO of the global methanol industry trade association. Mr. Dolan manages MI’s offices in Washington, DC, and in Singapore and Brussels, while directing international governmental relations, media relations, public education and outreach efforts. Mr. Dolan came to MI after spending a decade in a variety of public information positions in New York State, including the Department of Environmental Conservation, the Department of Transportation, and the Energy Research and Development Authority. Mr. Dolan holds a BA degree in political science from Boston University, and did extensive postgraduate work in political communication at the State University of New York-Albany.

They can also install onboard emissionsscrubbing equipment and continue to use heavy fuel oil (HFO). However, these technologies are complicated, costly and unproven. Complicating the situation even further, new vessels built after Jan. 1, 2016, will also have to meet stringent nitrogen oxide (NOx ) emission regulations if they want to enter or operate in the North American ECA. Simply taking the S out of fuel oil will not allow shippers to comply with these NOx emissions regulations. For the existing fleet of some 100,000 commercial vessels plying the world’s oceans, and the 2,000 new keels laid each year, the option of adding dual-fuel capability for diesel-liquefied natural gas (LNG) or diesel-methanol (MeOH) is increasingly seen as the smart course. While there are already some 50–60 ships using LNG as a bunker fuel, interest in using MeOH fuel is quickly gaining speed.

FIG. 1. New sulfur limits for marine fuels, 2008–2020. Hydrocarbon Processing | MAY 201537

Viewpoint the new MeOH-powered ships will be developed over the next three years. On March 27, Swedish ferry operator Stena Line relaunched the Stena Germanica, featuring the world’s first dualfuel MeOH propulsion system. The 240-m-long, 1,500-passenger RoPax ferry features four Wärtsilä engines, with one of the engines converted to MeOH operation while in dry dock in Poland’s Remontowa shipyard in January. Once the owner is satisfied, the other three engines will be converted one by one while the vessel is in service. Running on MeOH, SOx emissions are expected to be cut by 99%, NOx by 60%, particulates by 95% and carbon dioxide (CO2 ) by 25%. Funding of €11.2 MM for the work was provided under the EU’s Trans-European Transport Networks (TEN-T) program. Conversion developments. The ef-

fort by Wärtsilä is particularly significant, as it is converting existing engines

by adding a new fuel rail and injector system, while changing nothing inside the ship’s engine (FIGS. 2 and 3). The ship operator simply presses a button on the bridge, and the fuel delivery system switches over from diesel to MeOH operation in seconds. Existing ballast tanks on the Stena Line ferry are being used to store MeOH fuel, with the addition of nitrogen blanketing to inert the MeOH. The cost of conversion is estimated to be €300/kW of engine capacity. These costs are comparable to adding a scrubber system. The addition of LNG dualfuel capability is expected to be more than €1,000/kW, with the need to install special storage facilities for the cryogenic fuel. These storage facilites are expected to be expensive and impinge on cargo or passenger space.

MeOH AS A FUEL OFFERS ADVANTAGES In a broader viewpoint, MeOH’s cost advantage over LNG is not limited

FIG. 2. Wärtsilä’s MeOH-diesel retrofit solution-engine piping.

FIG. 3. Stena Line will relaunch the Stena Germanica, featuring the world’s first dual-fuel MeOH propulsion system.

38MAY 2015 | HydrocarbonProcessing.com

to the shipping industry. MeOH is one of the most widely shipped commodity chemicals in the world, with present global MeOH demand at approximately 65 metric MMtpy. Much of this MeOH supply is shipped from one continent to another, with the world’s major shipping hubs handling hundreds of thousands of tons of MeOH each year, and smaller ports handling thousands of tons. Since MeOH can be stored in mild steel tanks and is already present at just about every chemical port/terminal, it would be very simple to make the infrastructure adjustments to offer MeOH as a bunker fuel. By comparison, LNG projects will be much more capital intensive, complicated and challenging from a safety perspective. LNG also has a tendency to allow MeOH to boil off, creating a potential carbon footprint concern. As a bonus, MeOH is readily biodegradable and soluble in water, making it an environmentally friendly alternative to oilbased fuels. On the supply side, global MeOH production capacity exceeds 100 MMton, which provides an overhang of 20 MMton to 40 MMton to meet marine fuel demand. While most MeOH is made from the steam reformation of natural gas, MeOH can be produced from a wide range of feedstocks, including coal, biomass and even CO2. MeOH is a unique molecule that offers wide pathways to renewability that are not open to LNG. As the lifecycle economics of using MeOH compared with other emission compliance options become more evident, we will see the tide rising on the use of MeOH as a marine engine fuel.

FIG. 4. Stena Line will operate MeOH powered ferries to reduce emissions.

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| Special Report MAINTENANCE AND RELIABILITY The service life of an HPI facility is approximately 30 years. During this time, operating companies use maintenance programs to protect their capital investments. In 2015, the HPI will spend over $95.2 B globally on various maintenance projects. Since equipment failures can result in expensive unit and plant shutdowns, as well as in environmental and/or safety incidents, best-of-class companies maintain the mindset that spending to improve reliability and equipment conditioning is a great benefit to the organization. HPI facilities constantly investigate new monitoring and conditioning systems, along with preventive maintenance and inspection programs. In the modern HPI, maintenance and reliability staff should not be viewed as services, but rather as equal partners of operations in the creation of business value. The May special report explores innovative methods and programs to keep HPI facilities operating as designed.

Special Report

Maintenance and Reliability M. NAIK, Meridium, Roanoke, Virginia

Reduce maintenance and production losses by benchmarking asset performance In the production-intensive manufacturing world, the most evident asset failures are those that significantly impact maintenance costs and cause lost production. While it is important to focus efforts on preventing such events from occurring, it is equally important to focus on seemingly low-impact, but high-frequency, failures—i.e., chronic failures. Chronic failures typically consume many worker hours, although they may not cost significant cumulative maintenance dollars. Also, due to their repeated occurrence, they might give a false appearance of being normal or part of required maintenance. In light of these masked losses, benchmarking can help identify assets with chronic failures, and it can drive failure elimination efforts to improve reliability and availability and to reduce costs. Assets having chronic failures can be identified by combining insights from benchmarking with the “bad actor” list. Benchmarking also provides tools to help organizations understand the nature of failures and direct the use of root cause analysis (RCA) to eliminate failures. In this case study, an investment of $200,000 eliminated chronic failures at a major chemical manufacturing facility. It also increased availability, saving $250,000/yr in maintenance costs and another $400,000/yr in production losses.1 For one particular asset, the mean time between failures (MTBF) was measured in days. Over a period of 10 years, outages had cost the company millions of dollars in maintenance and lost opportunities. However, the expenditures did not come from a large-impact item event; rather, a succession of chronic failures was responsible. Establishing asset performance benchmarking. Benchmarking of assets

can help identify a specific type of equipment that is having chronic failures. It also can identify the “bad actor” assets of the equipment type that may be experiencing chronic failures, as well as identify the most common failure mode for these chronic issues. Finally, asset performance benchmarking can help build the case for a failure elimination program. The key ingredient of any useful endeavor to determine the remaining life of machinery is often hidden within the client plant’s own past failure history. Where such history exists and where the root causes of failures have been analyzed, au-

thoritative answers on remaining life are possible. Conversely, where these data are lacking, applicable comparison data from others may need to be substituted. On stationary equipment and piping, corrosion data should be available from coupons or from non-destructive testing records. In the case of rotating machinery—in particular, process pumps—the equipment owner would submit to the asset management service provider both failure history and past repair or maintenance data. Lube application strategies often have considerable impact on overall compari-

FIG. 1. Benchmarking asset performance using the MTBF metric.

FIG. 2. Benchmarking performance by equipment taxonomy—MTBF of vessels. Hydrocarbon Processing | MAY 201541

Maintenance and Reliability

Benchmarking’s baseline benefits: • Benchmarking similar asset types and identifying uncharacteristically low-performing assets can determine operating conditions • Benchmarking identifies assets having chronic failures in a quick and simple way by combining software analysis with a bad-actor list • Asset performance management tools can be used to understand the nature of failures, and root cause analysis can be used to eliminate failures • Benchmarking drives the need for failure elimination, showing that constant reactive maintenance without proactive strategies can lead to significant maintenance costs and production losses

FIG. 3. MTBF for pressurized vessels.

FIG. 4. A bad-actor list identifies the specific assets affected by chronic failures.

sons, as do the extension of oil replacement intervals made possible by better lubricants and superior bearing housing protection measures—i.e., advanced bearing housing protector seals. Mechanical seal life must be assessed and compared against best available sealing technology. This may require that the client demands a seal alliance partner’s active cooperation and the divulgence of what some “partners in name only” claim to be proprietary information. For instance, the extent to which superior 42MAY 2015 | HydrocarbonProcessing.com

dual-sealing technology from smaller seal manufacturers is used elsewhere by bestof-class competitors must be explored by the asset management service provider. Who needs to be a part of the benchmarking effort? First, engineering personnel should be involved because they are responsible for equipment selection and design. They must also monitor equipment performance. Second, operations personnel must have an active role, as they are responsible for monitoring and controlling production losses. Final-

ly, maintenance personnel have a vested interest in both maintenance costs and asset reliability. One chemical manufacturing company implemented asset-level benchmarking in February 2013. It started by comparing its operational experience against that of other specialty and commodity chemical companies. The company gained several important insights: • It experienced twice as many failures as its peers, with an MTBF of 93 months for all types of assets for the 2011–2012 period (FIG. 1) • If the company could increase its MTBF to the peer average of 220 months, it could save approximately $26 MM/yr in maintenance costs alone, due to the reduction in failures • Analyzing the asset performance by equipment taxonomy, it was found that the equipment class of “vessel” in the fixed equipment category has the maximum opportunity for cost savings (FIG. 2) • The company’s vessels fail almost six times more often than those of its industry peers, with an MTBF of 18 months • Reducing failures and increasing the MTBF of vessels to the peer value of 113 months would enable the company to save $6 MM/yr in maintenance costs (FIG. 2) • Adding another level of detail to the equipment taxonomy, of the type “pressurized vessels,” showed an MTBF of two months, compared to a peer MTBF of 13 months, offering an opportunity to save $2 MM/yr (FIG. 3). Tackling failure reduction. With comparative failure information in hand, the company now knew that pressurized vessels were a prime target for failure reduction. To best determine how to minimize those failures, it needed to identify the specific assets that were affected by chronic failures. To accomplish this task, a badactor list was generated, as shown in FIG. 4. The specific asset identified in the badactor list was coalescer pressure vessel 17PV-1. This asset is used in the finishing process of manufacturing synthetic resins. It uses a mechanical filter element to separate the emulsion into its components. Through the combination of benchmarking and bad-actor evaluation, the engi-

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Maintenance and Reliability neering team identified this asset as critical to operation, since failures and downtime here result in severe production losses. The coalescer pressure vessel experienced 116 failures between 2011 and 2012, which cost $500,000 in maintenance expenses to replace plugging filter elements. An operations review also showed that no proactive strategies, such as condition monitoring, inspections or preventive maintenance, have been applied to this asset. However, the work order descriptions for the asset show a chronic failure mode of plugged filter elements (FIG. 5). Issue resolution and operational change. A reliability growth analysis was

conducted using proprietary asset performance management software for the failures encountered since the installation of the equipment in January 2004. The MTBF trend shows a peak in mid-2006 due to a unit turnaround, during which time the asset was not in operation. Excluding this turnaround, it was observed that, since its installation in 2004, the MTBF of the asset has remained the same, with a frequency of 3–5 days. This scenario had led the company to believe that filter replacement at this frequency was normal, and simply a part of required maintenance. However, with the help of proprietary software analysis, it became clear that the failure rate was too high, justifying investment in a failure elimination program. A root cause failure analysis (RCFA) was undertaken using a decision-making model. The main reason behind the frequent filter plugs was identified as the accumulation of emulsion on the filter surface. Engineering, operations and maintenance found that the emulsion hardens over time and completely restricts the pores on the steel-knit mesh filter element. This caused plugs, which, in turn, triggered the high differential pressure alarm. After the root cause was fully understood, a high-pressure backwash system was installed in March 2013 to remove the residue remaining on the filter after the coalescence operation. A highpressure stream of hot water was run every hour during the low-demand period of the asset, and the residue was collected from an outlet at the bottom of the vessel. opportunity. After the improvement was implemented, an as-

Asset

FIG. 5. Work order list for coalescer pressure vessel 17-PV-1.

FIG. 6. Reliability growth analysis for coalescer pressure vessel 17-PV-1.

FIG. 7. Asset opportunity for asset 17-PV-1.

set opportunity (FIG. 7) was created to monitor and track the maintenance costs for the asset. Based on historical work orders between 2011 and 2012, the program automatically calculated that the company spends an average of $20,000/month on maintenance and $32,000/month

on lost production. After installing the filter backwash system, the predicted maintenance cost will go down to $500/ month, with no production losses. 1

NOTE The proprietary software program used to pinpoint and resolve chronic failures in this case study is Meridium’s Asset Answers. Hydrocarbon Processing | MAY 201543

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Special Report

Maintenance and Reliability T. GRESH, Flexware Inc., Grapeville, Pennsylvania; and J. K. WHALEN, John Crane Engineered Bearings, Houston, Texas

Consider new labyrinth seals to optimize compressor operations The pressure ratio is approximately 1.12, so the pressure following the first wheel is 224 psia (15.4 bara). Assume that the

FIG. 1. Damaged labyrinth seal.

Head

Degradation of labyrinth seals in centrifugal impellers can have a significant impact on not only compressor power consumption but also on plant production rate. Upgrading to rubtolerant seals can be beneficial in not only making improvements to the present efficiency and capacity, but, even more importantly, maintaining new operating levels. With damaged labyrinth seals, the head and efficiency are reduced. The performance curve is shifted down and to the left, and the capacity of the compressor is reduced, thus limiting plant output. As shown in FIG. 1, such damage can occur in an instant as the compressor goes through the critical speed on startup. This then results in the remaining run of the compressor (two to four or more years) with increased clearances and resulting efficiency losses. With rub-tolerant seals installed, the shaft may deflect during a vibration excursion, such as passing through a critical speed, and contacting the seal. The seal teeth deflect and then return back to as-installed when the vibration level settles back to normal levels. Seal clearances remain at design clearances, thus maintaining compressor performance. For a closed impeller with a labyrinth seal at the impeller eye, the leakage through the impeller eye seal is recirculated through the impeller. This leakage is recompressed, and the compressor efficiency is affected in proportion to the amount of flow being recycled. The same is true for the impeller shaft labyrinth and the balance piston labyrinth.

1 3

HBase

Example. Assume the compressor is designed with four impel-

lers. The compressor main inlet pressure is 200 psia (13.8 bara), and the discharge pressure is 315 psia (21.7 bara). For simplicity, the pressure ratio for each impeller is the same: or: Rp = (P2 /P1 )1/x where: Rp = Pressure ratio across each compressor stage. X = Number of impellers P1 = Inlet pressure P2 = Discharge pressure For this example: Rp = (315/200)1/4 Rp = 1.12

2

1

Efficiency

Rpx = P2 /P1

ΔH

3 Base (clean) Damaged labyrinth seals

2 Flow

FIG. 2. Compressor performance with new and damaged labyrinth seals. Hydrocarbon Processing | MAY 201545

Maintenance and Reliability pressure development through the impeller is approximately 60% of the stage pressure rise (the rest of the pressure rise is in the diffuser, as shown in FIG. 5), thus, a pressure of 214.4 psig (14.8 bara) is possible at the impeller tip and at the impeller eye seal area. Design condition. FIG. 2 shows the operating conditions for a clean compressor with the labyrinth seals per design specs. With damaged labyrinth seals, the head and efficiency are reduced. The performance curve shifts down and to the left. Result: The capacity of the compressor is reduced, thus limiting plant output. Rub-tolerant seals can be installed with clearances that are smaller than the original aluminum labyrinths, as shown in FIG. 3. Both the head (pressure rise), efficiency (power) and compressor through flow will be improved over the original equipment. The shaft may deflect during a vibration excursion, such as passing through a critical speed, and rub the seal. Since the seal material is flexible, the angled seal teeth deflect and then return back to normal when the vibration level settles back to normal levels, as shown in FIG. 3. Efficiency issues. Leakage through the impeller eye seal, Q L , is recirculated through the impeller. The compressor efficiency

is affected in proportion to the amount of flow leaking through the impeller eye labyrinth seal, Q L , relative to the main gas flow, Q i . The same is true for the impeller shaft labyrinth and the balance piston labyrinth. For a closed centrifugal impeller, the efficiency loss for the increased eye labyrinth seal clearances is about one percentage point for each percent increase in Q i (as a result of Q L increasing and the inlet flow to the compressor constant). For closed centrifugal impellers with labyrinth seals at the eye, the following rule of thumb may be used: %Δη α – %ΔQ i where: Q i = Impeller flow Using a software program based on the Adolf Egli procedure (free download), the seal leakage for the impeller eye seal for the standard seal and proposed rub-tolerant seal can be calculated. Clearance issues. From the original equipment manufacturer (OEM) manual, the radial seal clearance for the first-stage impeller and the eye seal diameter can be found. This information and the gas analysis can be entered into the labyrinth seal leakage program. The approximate value for the radial seal clearance for the new rub-tolerant seals is:

CLRT = CLbrg + DEye /8,000 Deflected shaft 30° typical

Centerline

Shaft

G.E.B.

FIG. 3. Rub-tolerant seal cross-sectional view.

where: CLRT = Radial clearance for the new rub-tolerant seals, in. CLbrg = Radial clearance for the compressor journal bearings, in. DEye = Impeller eye diameter at the eye seal, in. For this example: CLRT = 0.0025 in. + 14/8,000 CLRT = 0.004 in. A rule of thumb used by one OEM is that approximately 60% of the pressure is developed in the impeller. The rest of the pressure rise for a stage is developed in the diffuser, as noted previously. This is a crude rule of thumb, and it is not a precise calculation. This value can vary depending on the stage design and operating conditions. Accurate values can be obtained from software prediction programs that model the compressor in detail. Pressure

Cl

V Diffuser

Impeller

P V

Qi Inlet

QL FIG. 4. Closed impeller with labyrinth seal at impeller eye.

46MAY 2015 | HydrocarbonProcessing.com

Velocity FIG. 5. Velocity/pressure development through a centrifugal compressor stage.

P

Maintenance and Reliability If the compressor through flow is 2,500 lb/min, then the efficiency improvement is: (48–11)/2,500 = > 1.5% if the impeller eye seals are changed out to rub-tolerant seals. Note: This is relative to aluminum seals in the as-new condition. Often, aluminum seals may be worn out, and they may be more than two or three times the normal spec clearances.

Monitoring the compressor before and after changeout of the labyrinth seals can demonstrate the improvement in compressor performance (FIGS. 7 and 8). With the changeout, a 5%

More improvements. Changing out the impeller shaft seals

and balance piston seals will result in even greater improvement. For an accurate assessment, use a software program that properly models the compressor aerodynamically to confirm both the efficiency and power improvements and the capacity enhancement. Use a software program to continuously monitor the compressor before and after the changeout of the labyrinth seals to demonstrate improvements in compressor performance. FIG. 6 shows that the leakage rate for the first-stage impeller with standard aluminum labyrinth seals is 48 lb/min, as calculated based on the Egli procedure. Assume that the other three stages are similar. Recalculating the leakage rate for the firststage impeller with rub-tolerant labyrinth seals gives 11 lb/min. If you assume that the aluminum labyrinth seals will eventually open to two times the normal clearance (leakage = 71 lb/min), then the efficiency improvement for the changeout to rub-tolerant seals will be: (71–11)/2,500 = > 2.5%. This calculation is based on the changeout of all of the impeller eye seals. Changing out the impeller shaft seals and balance piston seals will result in even greater efficiency improvement, as shown in FIG. 7.

FIG. 6. The calculated leakage rate for the first-stage impeller with standard aluminum labyrinth seals is 48 lb/min. The leakage rate for the first-stage impeller with rub-tolerant seals (0.004 in. clearance) gives 11 lb/min.

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Hydrocarbon Processing | MAY 201547

Maintenance and Reliability or more improvement in capacity can be achieved depending on the slope of the head curve, where the machine is operating on the curve and how the compressor chokes. Changing out the impeller shaft seals and balance piston seals will result in even more capacity (plant output).

66 65

Efficiency

64 63 Change out to rub-tolerant seals

62 61 60

Time

FIG. 7. Plot of compressor efficiency vs. time.

Rub-tolerant seals

H

BIBLIOGRAPHY Gresh, M. T., Compressor Performance: Aerodynamics for the User, Flexware, 2011. Whalen, J. K., et al., “Polymer seal use in centrifugal compressors-Two users’ experiences over 15 years,” Proceedings of the Second Middle East Turbomachinery Symposium, 2013, Doha, Qatar. TED GRESH is president of Flexware Inc. in Grapeville, Pennsylvania. He has been involved in the design of highefficiency centrifugal compressor staging, field-testing of compressors and steam turbines, and troubleshooting field performance problems for over 40 years. While most of this time was with Elliott Co., he is presently with Flexware Inc., a company focused on turbomachinery engineering consulting services, training seminars and software for turbomachinery performance analysis. Mr. Gresh received a BS degree in aerospace engineering from the University of Pittsburgh. He has published a book on compressor performance, and holds several patents related to turbomachinery. He is a registered professional engineer in the state of Pennsylvania. JOHN K. WHALEN, PE, is the chief engineer for John Crane. He is a member of STLE, ASME and the Vibration Institute. Mr. Whalen is also a member of the Turbomachinery Symposium Advisory Committee and is a registered professional engineer in the state of Texas. He holds a BS degree in mechanical engineering from the Rochester Institute of Technology. He worked for Dresser Rand, where he was involved in large turbine engineering and rotordynamics. Mr. Whalen joined Centritech Corp. in 1988 and helped form Turbo Components and Engineering in 1991.

Original OEM aluminum seals

Q FIG. 8. Compressor efficiency improvement.

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Tower Technical Bulletin 3-Pass Trays: Profitable niche designs Introduction Over approximately 60 years of supplying trays to the industry, Sulzer has found that only 0.5% of those trays have been 3-Pass trays. However, in light of several articles on the topic, there has been a renewed interest in 3-Pass trays.(1,2) 3-Pass trays have an economic advantage over 2 and 4-pass trays because they employ only a single tray layout in any given column section, where 2 and 4-Pass trays have a totally different tray design for the odd and even numbered trays in a tower. Also, 3-pass trays can handle more liquid than 2-Pass trays because of their longer weir length. There is an optimum diameter range for the use of 3-Pass trays. This is between 7’ (2.1m) and 12’ (3.6m) ID. In this range, 3-Pass trays can have sufficient flow path length to allow placement of tray manways on the tray deck where 4-Pass trays cannot.

3-Pass tray application In 2012, Sulzer provided a set of 3-Pass trays into a 102” (2.6m) ID Refinery Debutanizer Tower. The tray decks employed the UFMTM valve, our latest development in High Capacity/ High Turndown tray technology. The plant has been operating successfully with excellent tray efficiency and capacity for 2 years now. As with all multi-pass designs, once you take the necessary measures to balance the vapor and liquid flows, the number of passes becomes a non-issue. For those in-between applications where weir loads are too high for a 2-Pass tray and the column diameter is too small for a 4-Pass tray, 3-Pass trays can be a reliable and profitable option.

(1) D.R. Summers, “Three Pass Trays – Friend or Foe?”, Paper 21a AIChE Annual Meeting, Nashville, TN, Nov, 2009 (2) H.Z. Kister and M. Olsson, “Understanding Maldistribution in 3-Pass Trays”, Distillation and Absorption 2010, Eindhoven, Netherlands, September 2010

Design Considerations: Balance is the Key Knowledge of the column thermodynamic and hydraulic functions is the key starting point. Any problem that develops that does not allow the vapor and liquid to contact each other in the manner for which the device was designed, or keeps the vapor and liquid from separating after contact, will adversely affect column performance. For example, the packing shown below will not provide good flow or vapor/liquid contacting efficiency because some of the packing is blocked off by fouling.

The Sulzer Applications Group Sulzer has over 150 years of in-house operating and design experience in process applications. We understand your process and your economic drivers. Sulzer has the know-how and the technology to design internals with reliable, high performance.

Sulzer Chemtech, USA, Inc. 8505 E. North Belt Drive | Humble, TX 77396 Phone: (281) 604-4100 | Fax: (281) 540-2777 Email: [email protected] www.sulzer.com

Select 89 at www.HydrocarbonProcessing.com/RS Legal Notice: The information contained in this publication is believed to be accurate and reliable, but is not to be construed as implying any warranty or guarantee of performance. Sulzer Chemtech waives any liability and indemnity for effects resulting from its application.

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Special Report

Maintenance and Reliability K. KAUPERT, R. KRULL and R. ILES, Energent Corp., Santa Ana, California

Maximize energy recovery with small steam turbines Steam systems are common in the hydrocarbon processing industry (HPI). In the past, system design was on large steam turbines. However, using smaller turbines (50 kW to 300 kW) can also increase system efficiency and help conserve energy. This article investigates examples in which the application of smaller steam turbines provided return on investment within two years. Introduction. Steam systems are an integral part of large hydrocarbon processing facilities. Such systems are used with large steam turbines that, in turn, drive other plant equipment. Steam systems are also used to provide heat for chemical processes and building environments. Furthermore, steam may also be required in the chemical refining process, such as in steam cracking facilities where vast quantities of steam are used.1 For steam systems in HPI plants, the cost of steam generated by the boilers is significant; thus, these systems must be optimized. Typically, steam systems have pressure reduction valves (PRVs) installed in some line locations to reduce the steam pressure. While the PRVs do perform the function of dropping the steam pressure in a steam line, PRVs also waste available energy by dissipating steam pressure. Installing small efficient steam turbines in the power range of 50 kW to 300 kW can recover some of the wasted letdown energy.

plant, approximately 5.2 MMtpy of steam is required in addition to the 100 MW of steam power used for the steam turbines. As an example, FIG. 1 is a general process diagram for the ethylene cracking process that is greatly simplified. Ethylene production is used as an example here, as it is a common petrochemical. Ethylene itself has no direct use, but it is a building block for a wide variety of petrochemical products such as polyethylene, ethylene oxide, ethylene dichloride and ethylbenzene (styrene). With regard to the turbomachinery technology, the requirements for steam turbine power are estimated at 100 MW for a large ethylene plant with a capacity of 1 MMtpy. In the past, the focus of turbine technology has appropriately fallen on the engineering of large steam turbines. However, in present steamcracking plants, opportunities exist to economically optimize the steam network using smaller steam turbines (50 kW to 300 kW). Such smaller turbines are installed where PRVs are located on steam lines, thus effectively recovering wasted energy to generate additional electricity. Small turbines in steam pressure letdown (replacing PRVs). The operating principal of pressure letdown turbines

is simple. Available energy, which is otherwise dissipated dur-

Naphtha

Steam in HPI facilities. Steam systems are used in a wide variety of HPI processes. For example, large steam systems drive turbines in steam-cracking ethylene plants to power process gas compressors, refrigerant compressors, pumps and electric generators.2, 3 In a large ethylene plant, a rough estimate of turbine power requirements is 1 MWh/t of ethylene product.4 For a 1-MMtpy ethylene plant, this means that approximately 100 MW of steam power is needed from the steam turbines. In addition to the steam supply used by steam turbines, it is also used within the steam-cracking process. Steam is mixed with the hydrocarbon feedstock (e.g., naphtha); the feedstock and steam are heated in the furnace to a temperature where hydrocarbon molecules thermally decompose to produce lighter hydrocarbons. The final product obtained from the cracking process depends primarily on the feedstock composition, steam-to-hydrocarbon ratio, cracking temperature and residence time in the furnace. Steam-to-hydrocarbon ratios typically range from 0.3:1 to 1:1.5 Reports from several large ethylene plants indicate that the average amount of steam used for cracking is 5.2 ton of steam/ton of ethylene product with a steam-to-hydrocarbon ratio of 0.6.4 For a 1-MMtpy ethylene

HP steam for cracking

To fractionation for C6, C5, C4, C3, C2, C1, H, ethylene Condensate flash

Heat exchanger Cracked products

Water Deaerator

Superheater

Boiler

Pump

Process steam consumption

PRVs

Pyrolysis furnace

HP steam

Steam turbines drive • Process gas compressor • Ethylene compressors • Propylene compressors

Process steam consumption

Condenser

FIG. 1. A simplified flow diagram for the stream system in an ethylene plant illustrating the many locations where steam is used. Hydrocarbon Processing | MAY 201551

Maintenance and Reliability ing the pressure letdown of steam in a PRV is instead used to drive a small efficient turbine and generate electricity. The power range of 50 kWe to 300 kWe is commonly possible. Electric power grid Turbine inlet Turbine outlet

Such pressure-letdown turbines are installed in parallel to existing PRVs so that, during maintenance, the PRVs can be used instead of the turbine on a temporary basis. When started, the small turbine automatically takes over the steam flow control from the PRV. When taken offline, the PRV automatically resumes control of the steam flow. FIG. 2 shows an installation. Since the available energy was previously wasted in the PRV, the electricity is essentially generated at a low operating cost. However, the capital cost of the turbine and economic feasibility studies must be reviewed to determine the viability of installing a small steam turbine. Design of pressure-letdown turbines. When designing

Small steam turbine Steam inlet

Steam outlet PRV

PRV

FIG. 2. Schematic to generate 275 kWe from an existing steam line that uses a double PRV arrangement.

T2

T3

T4

T5

T6

Pressure

T1

1 2

Wet vapor region 3 Enthalpy

FIG. 3.The steam expansion on the P vs. h state diagram shows that the steam flow is entering into the wet vapor region.

FIG. 4. A sectional view of the radial outflow steam turbine used to expand the wet steam.

52MAY 2015 | HydrocarbonProcessing.com

pressure-letdown turbines for steam, the low-pressure (LP) steam flow at the turbine outlet is wet. Conventional turbine technology for small steam turbines tends to use radial inflow or even small axial flow turbines, which cannot efficiently expand into the wet-gas regime of a steam flow. For example, FIG. 3 shows the P vs. h expansion of steam into the wet-gas region. The expansion proceeds from Location 1 at the turbine inlet, which is dry steam. The flow then passes into the turbine stationary nozzles, as seen in the cross-sectional sketch of FIG. 4. As the flow passes through the stationary nozzles, the pressure decreases and the flow velocity increases as a large tangential velocity is imparted to the steam flow. However, the steam becomes wet at Location 2 (FIG. 3). At Location 2, the flow enters the turbine impeller (rotor). The impeller begins to extract the angular momentum from the flow, which results in torque on the turbine impeller, as torque is the rate of change of angular momentum. The flow then leaves the turbine impeller at Location 3 and passes through a diffuser (draft tube) for pressure recovery and eventually leaves the turbine outlet. At Location 2, the steam flow inside the vapor dome is wet. If a conventional radial inflow-style steam turbine were used for this duty, then the centrifugal field in the turbine would

FIG. 5. A radial outflow turbine impeller.

Maintenance and Reliability

Small steam turbine performance envelope. The per-

formance envelope for a small steam turbine used to replace a PRV is shown in FIG. 6. The electric power output produced is given as a function of steam flowrate and inlet to outlet pressure (pressure ratio). FIG. 7 shows the influence of the pressure ratio (Pin /Pout ) on the isentropic efficiency of the turbine. Note: For pressure ratios above the optimum of 2.5, the efficiency decreases gradually, while, for pressure ratios below the optimum of 2.5, the efficiency drops off more rapidly. This has implications for off-design performance

and the general design of such turbines. The figure shows that engineers should never design turbines conservatively for lower pressure ratios. Better to over-design the turbine for higher pressure ratios and accept any deviations in the steam process conditions. FIG. 8 shows an example of measured performance for a pressure-letdown steam turbine with varying flowrate. The inlet and outlet pressure were near 8 barg and 3 barg, respectively, although these pressures did vary by ± 25% during test300

6b arg :2

ba rg

250

n /P ou t

=1

200 150

Pi

Power, kWe

trap the heavy wet liquid drops at the larger radius and only pass the lighter gas, acting somewhat like a centrifuge for the liquid. This heavy liquid would be trapped in the machine, causing efficiency losses and even damage to the turbine due to liquid impacting the turbine impeller blades at the inlet.6 For this reason, the turbine style needed to expand wet steam is a radial-outflow turbine; due to such a geometry, any heavy liquid drops will move in the direction of the centrifugal field, which is in the downstream radial outward direction and will eliminate possible blade damage. FIG. 5 shows a photo of a radial outflow turbine wheel made of titanium. Radial-outflow turbines are slightly less efficient than conventional radial-inflow turbines for single-phase flows, 7 but are needed for additional reliability when expanding a wet steam flow to ensure that the centrifugal field created in the turbine impeller moves the heavy liquid drops downstream and out of the turbine.

100

g bar

g: 4 bar

g bar

6 =1 arg P out g: 4 b 10 bar = P in/P out rg ba :6 arg b = 16 g: 6 barg P out P in/P out = 10 bar P in/

= 10

t

P ou P in/

g: 2 bar

/ P in

50 0 2,000

3,000

4,000

6,000 5,000 Steam flowrate, kg/hr

7,000

8,000

FIG. 6. A performance map example of a small steam turbine used in pressure letdown energy recovery.

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Maintenance and Reliability 1.0 0.9 0.8

Efficiency, %

0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0 0.0

0.5

1.0

1.5

2.0 2.5 3.0 Pressure ratio

3.5

4.0

4.5

5.0

FIG. 7. An example of measured isentropic efficiency for a small steam turbine used in pressure letdown energy recovery as a function of the pressure ratio = Pin /Pout. 250

1.0 Power Isentropic efficiency

FIG. 9. A typical small steam turbine will operate in parallel with a PRV to generate electricity. The installed small steam turbine package at an industrial facility includes the controls cabinet to the right and the small 275-kW steam turbine to the left.

0.9

200

0.8

0.6

150

0.5 0.4

100

Efficiency, %

Power, kWe

0.7

0.3 0.2

50

0.1 0 1,000

1,500

2,000

2,500 3,000 Steam flowrate, kg/h

3,500

4,000

0.0 4,500

FIG. 8. The measured performance of a small steam turbine showing the electric output power and efficiency vs. flowrate.

ing, as evidenced by the scatter in the data. Due to the high velocity found in the steam flow, the formation of two-phase flow and the potential for foreign debris in the steam, the small steam turbine needs to be erosion resistant. As such, Ti-6Al-4V impellers are used in the construction. FIG. 9 Shows a 275-kW steam turbine in parallel service with a PRV. The turbine, gearbox and generator are of a vertical orientation in this configuration. Small steam turbine economics. Typically, small steam turbines that replace PRVs have a return on investment within two to four years to pay for the capital expenditure and operating costs. For example, if the steam flowrate is 6,000 kg/hr and the pressure drop is from 10 barg to 2 barg, then such a turbine will generate 275 kWe of electricity. Using an electricity cost of €0.07/kWh and running for 8,000 hr/yr provides €154,000/ yr worth of electric power that otherwise would have been wasted. However, the cooling effect as the steam flow passes 54MAY 2015 | HydrocarbonProcessing.com

through the turbine is also heat loss to the steam system that must be compensated. This heat loss is steam-system dependent, and is based on experience. It is estimated as €44,000/yr. This results in a net benefit of €110,000/yr for such a turbine. Overall, such economic assessments need to be made for each HPI plant, with a clear view of the economic optimization for the plant operating costs and benefits. LITERATURE CITED Moulijn, J. A., M. Makkee and A. E. van Diepen, Chemical Process Technology, Wiley Publications, 2nd Ed., 2013. 2 Lee, J. J., et al., “Reduce revamp costs by optimizing design and operations,” Hydrocarbon Processing, April 2007, pp. 77–81. 3 Li, Z., L. Zhao, W. Du and F. Qian, “Modeling and Optimization of the Steam Turbine Network of an Ethylene Plant,” Chinese Journal of Chemical Engineering, Vol. 21, No. 5, pp. 520–528, 2013. 4 Verde, L., R. Riccardi, D. Pedretti and A. Nava, “Energy Conservation, Ethylene Plants,” Encyclopedia of Chemical Processing Design, Marcel Dekker Publishing, Vol. 18, pp. 171–180, 1983. 5 Matar, S. and L. F. Hatch, Chemistry of Petrochemical Processes, Gulf Publishing Company, 2nd Ed., 2001. 6 Wilson, D. G., The Design of High Efficiency Turbomachinery and Gas Turbine, 1st Ed., MIT Press, 1984. 7 Aungier, R., Turbine Aerodynamics: Axial-Flow and Radial-Flow Turbine Design and Analysis, ASME Publishing, 2006. 1

KEVIN KAUPERT has 25 years of detailed turbomachinery design experience for the aerospace sector and the oil and gas industry. At Energent, he is responsible for two-phase turbomachinery design involving wet gas and flashing liquid flow. Dr. Kaupert holds a doctorate from the ETH Zurich Turbomachinery Laboratory. ROBERT ILES has 30 years of high-speed turbine machinery experience, 15 of which have been in the field of steam turbines. At present, he is Energent’s field service manager. RIK KRULL directs the sales and marketing activities for steam turbines at Energent. He is the former president of Mafi-Trench Turboexpanders. Mr. Krull has also held several executive management positions with BOC, Mafi-Trench, Cryogenic Industries and Energent.

Process Insight:

Air Emissions Modeling Advances for Oil and Gas Production Facilities

A perfect storm has dramatically changed the way oil and gas production facilities are designed and permitted for air quality compliance. Air quality regulations have been strengthened due to rule changes in the Clean Air Act (40 CFR 60, Subpart OOOO), drastically reducing the allowed emissions of VOCs from well sites. These changes were made along with new regulations of Green House Gas emissions (40 CFR 98, Subpart W). Due to the more stringent and complex permitting regime, it is now important to accurately predict VOC emissions rates from oil and condensate tanks. More FRPSOH[ZHOOVLWHGHVLJQVZKLFKRIWHQLQFOXGHÀDUHVYDSRU recovery towers, and vapor recovery compressors are now commonplace. This calls for design-class process simulation tools. Along with more stringent rules, the shale revolution has caused the number of wells drilled in the US to skyrocket. Each of these new wells requires a permit with emissions estimates, dramatically increasing the work load for compliance. Along with the calculation requirements for permits, annual inventory reports are also required for a variety of emissions sources and contaminants. Examples include Greenhouse Gas Emissions, Flashing Losses, as well as Working, Breathing, and Loading Losses from VWRUDJHWDQNV1HZDQGÀH[LEOHVLPXODWLRQSURJUDPVDUH therefore necessary to keep up with changes to calculation requirements.

Figure 1

Another result of this more rigorous air permitting environment is closer coordination between well site facility design, air permitting, and air quality compliance personnel. Air quality parameters are considered in early design phases and now typically drive the design process. The resulting process simulation is then used by air permitting and compliance functions throughout the life of the well. Use of a design-class process simulation tool helps bring the work of these two groups together in seamless fashion.

Well Site Air Emissions – a Brief History Until recently, well head or compressor station VHSDUDWRUVDWVLJQL¿FDQWSUHVVXUH SURGXFHGDJDVSURGXFW WKDWÀRZHGWRDVDOHVJDVOLQHDQGDOLTXLGSURGXFWWKDWZDV ÀDVKHGWRDQDWPRVSKHULFSUHVVXUHWDQN7KH92&ULFKJDVHV WKDWHYROYHGIURPÀDVKLQJGRZQWRDWPRVSKHULFSUHVVXUH were typically vented to the atmosphere. (See Figure 1) With the new regulations, a comparable well is now equipped with additional features designed to mitigate, recover, or convert VOC’s in gases that were previously vented. Designs similar to Figure 2, in conjunction with a ÀDUHRURWKHUFRQWUROGHYLFHDUHFDSDEOHRIQHDU]HUR92& emissions. To achieve such designs, a high-quality process simulator like ProMax is necessary for evaluating and RSWLPL]LQJWKHYDULRXVVFKHPHV

Figure 2

ProMax brings these new and necessary capabilities to the design, permitting, and compliance teams. Additionally, an EPA AP-42 Working, Breathing, and Loading Loss calculation tool has been added to ProMax so that all FDOFXODWLRQVFDQEHSHUIRUPHGLQDVLQJOHPRGHO¿OH3UR0D[ enables compliance teams to run hundreds- even thousandsof well site inventory calculations in a fraction of the time and with greater accuracy than was ever possible before! Select64 at www.HydrocarbonProcessing.com/RS

For more information about this study, see the full article at www.bre.com/support/technicalarticles ProMax® process simulation software by Bryan Research & Engineering, Inc. Engineering Solutions for the Oil, Gas, Refining & Chemical Industries

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Special Report

Maintenance and Reliability H. P. BLOCH, Professional Engineer, Westminster, Colorado

Lubrication update for rotating equipment API-610 is the most widely used pump standard in the petrochemical and refining industries. It includes experience-based recommendations for lubricant applications and one of those recommendations relates to oil-mist systems. The API standard asks for oil mist to be routed through the bearings, as shown in FIG. 1, instead of past the bearings (FIG. 2). Although intended for pumps, this same recommendation will work equally well for electric motor rolling element bearings. The resulting diagonal through-flow route guarantees adequate lubrication; however, oil mist entering and exiting on the same side may allow some of the mist to leave without first wetting the rolling elements. Through-flow is one of the keys to a successful installation. Background. Major electric motor manufacturers, includ-

ing the former Reliance Electric Co. of Cleveland, Ohio, were fully aware of this fact. Representing “best technology,” their mid-1970s bearing housings were configured for through-flow. Moreover, a very wide oil-mist suitability range is documented for electric motors. Another industrial giant published technical bulletins discussing pure oil mist as a superior technique for electric motors ranging in size from 18 kW to 3,000 kW. Bearing size constraints and synthetic lubricants. De-

cades of experience confirm the success of oil mist for rolling element bearings in the operating speed and size ranges used in motors for process pumps. Since 1960, empirical data have been applied to screen the applicability of oil mist. The influences of bearing size, speed and load have been recognized and are part of a rule-of-thumb oil-mist applicability formula. The limiting

FIG. 1. Oil mist routed through electric motor bearings.

parameter, DNL, is defined as D = bearing bore in mm, N = inner ring in rpm and L = load in lb, with values ranging to 1 trillion (1T or 109). An 80-mm electric motor bearing, operating at 3,600 rpm with a load of 600 lb, would have a calculated DNL of 172 MM—less than 18% of the allowable threshold value. As of 2014, approximately 26,000 oil-mist-lubricated electric motors are operating flawlessly in reliability-focused plants. Capitalizing on this favorable experience, the procurement specifications for both new projects and replacement motors (with rolling element bearings) at many of these plants require oil-mist lubrication in sizes 15 kW and larger. Although it was well known that synthetic lubes reduce friction, little quantitative work has been done before 1980. Morrison, Zielinski and James quantified how diester fluids reduce the frictional power losses of industrial equipment; their findings are summarized in TABLES 1 and 2.1 The potential cost savings through power loss reductions are quite substantial. It has been estimated that industrial machines consume 31% of the total energy in the US.2 As much as 5% of the mechanical losses of these machines could be avoided through a combination of improved equipment design and lubricant optimization. Motor sealing. Motor sealing and mist drainage are well understood. Although oil mist will neither attack nor degrade the epoxy insulation on electric motor windings manufactured

FIG. 2. Oil mist applied to the center of a bearing housing is not providing optimal lubrication. Much of the mist is simply flowing from the entry to the drain. Hydrocarbon Processing | MAY 201557

Maintenance and Reliability since the mid-1960s, mist entry and related sealing issues merit inclusion in this overview. Regardless of motor type, i.e., totally enclosed, fan cooled (TEFC), X-Proof or weather-protected (WP) ll, cable terminations in junction boxes should not be made with conventional electrician’s tape. The adhesive in this tape will last a few days and then become tacky and unravel. Inferior products are replaced by superior materials that are often Teflon-based. For termination leads (T-leads), competent motor manufacturers use an irradiation cross-linked polymeric TABLE 1. Overview of power loss with different oils and application methods1 Power loss per bearing, kW L = 8.9 KN (2,000 lbf)

Oil sump

Oil mist

MIN 68

0.271

0.192

SYN 32

0.254

0.169

TABLE 2. Overview of power loss and loss reduction percentages with different oils and application methods1

Δ Power loss Change

insulation system that is highly resistant to oil mist. At present, irradiation cross-linked polymeric insulation systems have consistently outperformed the many “almost equivalent” systems. Most important, oil mist is neither a flammable nor an explosive mixture. It would be unsightly to allow a visible plume of mist to escape from the junction box cover. The wire passage from the motor interior to the junction box should be sealed with a high-quality two-part epoxy potting compound. Sealing will prevent oil mist from entering the junction box. Finally, it is always good practice to verify that all electric motors have a small (3-mm) weep hole and that XP-motor drains are given closer attention. The latter are furnished with either an explosion-proof-rated vent or a suitably routed weep-hole passage at the bottom of the motor casing or lower edge of the motor end cover. Intended to drain accumulated moisture condensation, the vent or weep-hole passage will allow coalesced or atomized oil mist to escape. Note: Explosion-proof motors are still “explosion-proof ” with this passage. A motor with its interior slightly pressurized by non-explosive oil mist cannot ingest any explosive vapors from the surrounding atmosphere. The suitability of oil mist for Class 1, Groups C and D locations was specifically reaffirmed by Reliance Electric in July 2004.

per bearing

Total reduction, %

Sump: MIN 68 to SYN 32

0.017

6

Mist: MIN 68 to SYN 32

0.022

8

TEFC vs. WP ll construction. For TEFC motors, there are

Sump MIN 68 to Mist MIN 68

0.080

29

Sump SYN 32 to Mist SYN 32

0.085

31

Sump MIN 68 to Mist SYN 32

0.11

38

documented events of liquid oil filling the motor housing to the level of almost contacting the spinning rotor. TEFC motors are suitable for oil-mist lubrication by simply routing the oil mist

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58MAY 2015 | HydrocarbonProcessing.com

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Maintenance and Reliability through the bearing, as has been explained in a comprehensive text on lubrication. There are numerous other references, including API-610. No special internal sealing provisions are needed with pure oil mist filling a TEFC motor as long as the pressurized mist prevents dirty atmospheric air from entering the system. On WP ll motors, merely adding oil mist has often been done, and it has generally worked surprisingly well. In this instance, however, it was important to lead the oil-mist vent tubing away from regions influenced by the motor fan. Still, WP ll electric motors do receive additional attention from reliabilityfocused users and knowledgeable motor manufacturers. Air is constantly being forced through the windings, and an oil film deposited on the windings could facilitate dirt accumulation. To reduce the risk of dirt accumulation, suitable sealing means should be provided between the motor bearings and interior. Since V-rings and other elastomeric contact seals are subject to wear, low-friction face seals are considered technically superior. The axial closing force on these seals could be provided either by springs or small permanent magnets.3 Also, many modern motors use advanced rotating labyrinth seals with closure O-rings that travel axially.4, 5 Note: The author does not advocate rotating labyrinth seals with O-rings that could potentially make contact with the sharp-edged grooves. The user must make intelligent choices. Some low-friction axial seals (face seals) may require machining of the motor end caps. But long motor life and the avoidance of maintenance costs will make up for the added expense. Double V-rings using Nitrile or Viton elastomeric material are sometimes used because they are considerably less expensive than face seals. Sealing to avoid stray mist stressing the environment. Even when still allowed under prevailing regulatory environmen-

Average temperature rise, K

70 60

MIN 68 SYN 32

Converting from grease-lubricated electric motors. When converting operating motors from grease to oil-mist lubrication systems, consider these additional measures: 1. Perform a complete vibration analysis. The analysis will confirm or rule out preexisting bearing distress. It will indicate if such work as realignment or base-plate stiffening is needed to avert incipient bearing failure.

50 40 30 Oil sump

tal regulations (e.g., OSHA or EPA), air quality and environmental concerns reinforce minimizing stray oil-mist emissions. It is helpful to recall that state-of-the-art oil-mist systems are fully closed, i.e., they are configured to permit any and all mist not to escape. The various bearing housings are sealed with the magnetic seals incorporated in the motor end bells, as shown in FIG. 1. Alternatively, advanced rotating labyrinth seals can be installed.4, 5 For many decades, combining effective seals and a closed oil-mist lubrication system has represented a well-proven solution. The combination not only eliminates virtually all stray mist and oil leakage, but it facilities nearly 97% recovery of oil for purification and reuse. These recovery rates enable using more expensive, superior quality synthetic lubricants. For many years, polyalpha olefins (PAO) and diester-based “synthetic” lubricants embodied most of the properties needed to extend bearing life and provide the greatest operating efficiency. These oils excel in the areas of bearing temperature and friction energy reduction. Synthetic lubricants in closed systems and reusing filtrated lubricant can offer economic benefits.3 Closed systems and oil-mist-lubricated electric motors can offer reliability-focused users several important advantages: • Compliance with actual and future environmental regulations • Extended bearing life and reduced electric motor maintenance budgets • Technical and economic justifications to apply highperformance synthetic oils in plant operations. PAO and diester-based “synthetic” lubricants provide benefits to extend the service life of bearings. As shown in FIG. 3, synthetic lubricants can reduce bearing temperature and greatly extend bearing service life. As shown in FIG. 4, these oils excel in reducing friction. FIG. 5 is a composite plot of different changes and power reduction percentages. This figure illustrates the quick return on investment (ROI).

Oil mist

40

FIG. 3. Average temperature rise plot for the ball bearing test.1

35

0.300

0.250

30 Total reduction, %

Power loss per bearing, kW

MIN 68 SYN 32

25 20 15 10

0.200

5 0

0.150 Oil sump

Oil mist

FIG. 4. Power loss plot for the ball bearing test. Two different oils are used at two different viscosities.1

60MAY 2015 | HydrocarbonProcessing.com

Sump: MIN 68 to SYN 32

Mist: MIN 68 to SYN 32

Sump: MIN 68 to mist MIN 68

Sump: SYN 32 to mist SYN 32

Sump: MIN 68 to mist SYN 32

FIG. 5. Plot of different changes and power reduction percentages that resulted.1

Maintenance and Reliability 2. Measure the actual efficiency of the motor. If the motor is inefficient, consider replacing it with a modern highefficiency motor, using oil-mist lubrication in line with the mentioned recommendations. This will allow capturing all benefits, and it will yield a greatly enhanced ROI. 3. Evaluate if the capacity of the motor is the most suitable for the application. “Most suitable” typically implies driven loads that represent 75% to 95% of nominal motor capacity. Result: Operation conditions are at the best efficiency. Note: Converting an overloaded, hot-running electric motor to an oil-mist lubrication system will only provide marginal improvement at best. Oil-mist systems. The required volume of oil mist is often expressed in bearing-inches (BIs). A BI is the volume of oil mist needed to satisfy the demand of a row of rolling elements in a 1-in. (25-mm) bore diameter bearing. One BI assumes a rate of mist containing 0.01 fl oz, or 0.3 ml, of oil per hour. Other factors must be considered to determine the necessary oil-mist flow, and these are known to oil-mist system providers and bearing manufacturers. The various factors are also extensively documented in several references; they are readily summarized as: • Type of bearing. The different internal geometries include different types of contact (point contact at ball bearings and linear contacts at roller bearings), amount of sliding contacts (between rolling elements

• • •

• •

and raceways, cages, flanges or guide rings), angle of contact between rolling elements and raceways, and prevailing load on rolling elements. The most common bearing types in electrical motors are deep-groove ball bearings, cylindrical roller bearings and angular contact ball bearings. Number of rows of rolling elements. Multiple row bearing or paired bearing arrangements require a simple multiplier to quantify the volume of mist flow. Size of the bearings. It is related to the shaft diameter and is inherently expressed in Bls. Rotating speed. The influence of the rotating speed should not be considered as a linear function. It can be linear for a certain intermediate speed range, but, at lower and higher speeds, the oil requirements in the contact regions may differ from straight linearity. Bearing load conditions. It includes the preload, minimum or even less-than-minimum load, heavy axial loads and more. Cage design. Different cage designs may affect mist flow in different ways. It has been reasoned that stamped (pressed) metal cages, polyamide cages or machined metal cages can create different degrees of turbulence. While different rates of turbulence may cause varying amounts of oil to “plate out” on the various bearing components, the concern vanishes when oil mist is applied in the through-flow mode.

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Hydrocarbon Processing | MAY 201561

Maintenance and Reliability Using the right bearing and proper installation methods. Very significant increases in bearing life and overall electric motor reliability have been documented. Oil mist cannot eliminate basic bearing problems. However, it can provide a reliable means of lubricant application. Bearings must be: • Adequate for the application, i.e., deep-groove ball bearings for coupled drives, cylindrical roller bearings to support high radial loads in certain belt drives or angular contact ball bearings to support the axial (constant) loads in vertical motor applications • Incorporating the correct bearing-internal clearances • Mounted with correct shaft and housing fits • Installed carefully and handled correctly, using the proper tools to avoid damaging the bearings • Correctly assembled and fitted to the motor caps, thus carefully avoiding misalignment or skewing • Part of a correctly installed motor, avoiding shaft misalignment and soft foot, or bearing damage incurred while mounting either the coupling or drive pulley • Subjected to a vibration spectrum analysis. This will indicate the lubrication condition (lubricating film), bearing condition (possible bearing damage) and general equipment condition, including misalignment, lack of support (soft foot), unbalance and more. Sealing to avoid stray mist releases to the environment.

Closed systems and oil-mist-lubricated electric motors give

62MAY 2015 | HydrocarbonProcessing.com

reliability-focused users several important advantages: • Compliance with environmental regulations • Proof that oil-mist lubrication will benefit electric motors and the maintenance budget • Technical and economic justifications to use highperformance synthetic oils. Modern additives technology has further strengthened wear protection. They offer reduced energy consumption with other synthetic base oils. All are worthy considerations. LITERATURE CITED Morrison, F. R., J. Zielinsky and R. James, “Effects of synthetic fluids on ball bearing performance,” Transactions of the ASME, Journal of Energy Resource, Technology, Vol. 104, pp. 174–181, 1982. 2 Pinkus, O., O. Decker and D. F. Wilcock, “How to save 5% of our energy,” Mechanical Engineering, September 1997. 3 Bloch, H. P., Practical Lubrication for Industrial Facilities, 2nd Ed., The Fairmont Press, Lilburn, Georgia, 2009. 4 Bloch, H. P., “Statistics to think about,” Hydrocarbon Processing, July 2006, pg. 9. 5 Bloch, H. P., Pump Wisdom: Problem Solving for Operators and Specialists, John Wiley & Sons, Hoboken, New Jersey, 2011. 1

HEINZ P. BLOCH resides in Westminster, Colorado. His professional career began in 1962 and included long-term 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 and is an ASME Life Fellow.

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SUSTAINABLE? Tier 3 gasoline standard of 10 ppm becomes effective January 1, 2017 and the EPA implemented a credit averaging, banking and trading (ABT) program for transition purposes from Tier 2. Are these options secure and sustainable for your refinery? It is not too early to develop a solution to Tier 3 using Merichem’s patented non-dispersive caustic treating technologies. Merichem Company optimized several caustic treating technologies to support Tier 3 gasoline production. These technologies have been chosen for multiple Tier 3 projects since 2013. Merichem’s technologies, THIOLEX™ and REGEN®, were chosen to extract mercaptans from various refinery streams. Merichem’s REGEN® platform is a key component of the final processing solution that allows treating options to bring product sulfur levels down to 2 PPMW. Merichem has licensed over 350 THIOLEX and REGEN units worldwide. To learn more about how these technologies can benefit you ahead of the Tier 3 transition visit

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Merichem’s REGEN® Platform • Remove product sulfur down to 2 PPMW • Maintain Octane • Reduce Hydrotreater Demand • Reduced CAPEX / OPEX • Proven FIBER FILM® Technology Copyright © 2015 Merichem Company • www.merichem.com

When you think resources, think beyond equipment. From safety/operator training and equipment management technologies, to custom solutions engineered to meet specialized job requirements, United Rentals offers much more than just the world’s largest rental fleet. We’re here to help. 3 Calculate your pump needs online at UnitedRentals.com/PumpCalc

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© 2015 United Rentals, Inc. Select 60 at www.HydrocarbonProcessing.com/RS

Regional Report

M. RHODES, Technical Editor

The Middle East’s strategic expansion of refined products exports Already a leader in crude oil exports, the Middle East (ME) is making a deliberate move to increase its participation in the refined and petrochemical products markets. It is likely that the ME will continue to add downstream projects. Refining capacity will center on domestic demand and export opportunities to Asia-Pacific (AP) and Europe. The ME refining industry varies greatly from other regions, as exemplified by its average utilization rates, which generally run at maximum and regularly exceed 90%. Since 87% of the approximately 8 MMbpd of existing refining capacity is owned by national oil companies (NOCs), refining margins do not play a significant role in operations. These NOCs process their own crude oil and condensate, and they operate to meet growing domestic demand and strategic objectives to expand refined product exports. The region’s overall refining capacity is forecast to increase by nearly 2 MMbpd through 2020, exceeding 10 MMbpd, despite potential delays in the commissioning of several projects.1 Incremental products output from new refinery capacity is expected to outpace demand growth in the region, resulting in higher net product exports. Some products are expected to be absorbed domestically as the region moves into compliance with tighter environmental fuel regulations, such as the Euro 4 and Euro 5 quality standards. Traditionally, ME refineries have had simple configurations and high fuel oil yields, partly due to strong power generation

requirements. This condition is changing; a new generation of highly complex plants, combined with upgrades at existing refineries, is radically altering the product mix. New unit configurations include hydrocracking, catalytic cracking and hydrotreating capacities designed to minimize fuel oil output and maximize middle distillate, diesel and gasoline production. Refinery integration. The ME is transforming its down-

stream business to be both vertically integrated across the value chain and horizontally integrated across suitable geographies. The goal is to add greater value to hydrocarbon supplies while building a more robust and resilient portfolio to withstand market turbulence. Top-tier refining companies are investing significantly to secure the region’s position as the hub of the global downstream industry (FIG. 1). World and ME oil demand. In 2014, world oil demand grew

by just under 1 MMbpd to average 91.2 MMbpd. World oil demand in 2015 is anticipated to rise by 1.17 MMbpd to average 92.37 MMbpd. Correspondingly, oil demand growth for the ME in 2014 was 250 Mbpd, while 2015 oil demand is proOngoing construction at the 3-MMtpy Sadara complex (left), winner of HP’s Top HPI Projects of 2014, Petrochemical. (Photo courtesy of Sadara Chemical Co.) The Qatofin project in Qatar (right) includes one of the world’s largest ethane crackers. (Photo courtesy of TOTAL Petrochemicals France.) Hydrocarbon Processing | MAY 201565

Regional Report

FIG. 1. HPI facilities in Saudi Arabia, including refineries, petrochemical complexes, and ports and terminals.

jected to increase by 280 Mbpd over 2014 levels. Most of this growth shown in FIG. 2 is expected to come from Saudi Arabia, with a forecast increase of 150 Mbpd, or more than half of the region’s expected growth.1

SAUDI ARABIA Saudi Arabia holds 16% of the world’s proved oil reserves, more than half of which are contained in eight fields. The giant Ghawar field, with an estimated remaining reserve of 75 Bbbl, has more proved oil reserves than all but seven other countries, according to the US Energy Information Administration.3 Saudi Arabia is the largest exporter of total petroleum liquids in the world—and the second-largest petroleum exporter to the US— and it maintains the world’s largest crude oil production capacity. Of Saudi Arabia’s total crude oil production capacity, more than 70% is considered light gravity, which is generally produced onshore, with the remaining crude considered to be medium or heavy gravity, mainly from offshore fields. The country is moving to reduce its share of the latter two grades. Most Saudi oil production, except for extra-light and super-light crude oil, is considered sour, as it contains relatively high levels of sulfur (S). The region’s petrochemical capacity is expected to rise from 127 MMtpy in 2012 to over 145 MMtpy by 2018.2 However, 66MAY 2015 | HydrocarbonProcessing.com

natural gas feedstock restraints will propose hurdles to capacity expansion plans. Saudi Arabia has the world’s fifth-largest natural gas reserves, but most natural gas fields in Saudi Arabia are associated with petroleum deposits, and increases in gas production remain linked to oil production increases. To minimize the use of crude oil for power generation, gas supplies remain reserved for domestic use. The petrochemical industry, among others that use gas-fired power generation, is contributing to a looming regional gas shortage by 2016. This is especially vital because the country plans to increase its electricity generating capacity to 120 GW by 2032 to meet demand. However, natural gas production remains limited, as the costs of natural gas production, exploration, processing and distribution have squeezed supply.3 Expanding the gas, refining, petrochemicals and power industries. To comply with mandatory S specifications for gas-

oline and diesel between 2013 and 2016, Saudi Arabia is constructing multiple clean-fuel projects aimed at reducing the S content in diesel and gasoline to 10 ppm and lowering the benzene content in gasoline to 1%. NOC Saudi Aramco has invested in excess of $100 B in the last decade to support long-term sustainability of oil demand.2

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Regional Report In the near term, Saudi Aramco will operate 8 MMbpd–10 MMbpd of refining capacity, much of which will be directed to high-demand and growth markets of AP, Europe and the ME. The NOC is upgrading the country’s domestic refineries to produce lower-S transportation fuels, and several projects have been designed to produce near-zero-S fuels by 2016: • Yanbu Aramco Sinopec Refining Co. (YASREF), a JV between Saudi Aramco (62.5%) and Sinopec (37.5%), began export operations at its 400-Mbpd Yanbu Industrial City refinery in January 2015. The refinery has been designed to process heavy and medium crude oils and maximize gasoil (GO) and gasoline production. It includes process units for the separation and conversion of the feed crude into finished products; utility and offsite systems to support the refinery 400 300 200 100 0 Saudi Arabia

-100 1Q12

2Q12

3Q12

Iran, I.R. 4Q12

Kuwait

1Q13

2Q13

UAE 3Q13

Others 4Q13

1Q14

2Q14

3Q14

FIG. 2. Oil demand growth in the ME, year-on-year, 2012–2014.

4Q14

operation; and associated feed, intermediate and product storage facilities. • Dow Chemical (35%) and Saudi Aramco (65%) are constructing a fully integrated refining complex under the JV Sadara Chemical Co. The 3-MMtpy facility will consist of 26 chemical manufacturing units and produce 1.5 MMtpy of ethylene and 400 Mtpy of propylene. The complex will also produce a variety of chemicals, such as ethylene, propylene oxide, propylene, benzene, toluene, polyethylene, propylene glycol, polyolefin elastomers and more.4 The Sadara complex will use ethane and naphtha as feedstock, which will be supplied from Saudi Aramco Total Refining and Petrochemical Co.’s (SATORP’s) refinery. Full operations are expected to begin in 2016. • Rabigh 2 is an expansion of the existing PetroRabigh refining and petrochemicals complex, which produces 18 MMtpy of refined products and 2.4 MMtpy of petrochemical products. Phase 2 will add 15 MMtpy of refined products and 5 MMtpy of petrochemicals, and is expected to begin operations in the first half of 2016. Rabigh 2’s development will include the expansion of PetroRabigh’s existing ethane cracker, the construction of a new aromatics complex and an expanded facility to process 30 MMcfd of ethane and approximately 3 MMtpy of naphtha as feedstock. The total project investment is projected to reach approximately $8.5 B (an increase from the original $7 B).4

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68MAY 2015 | HydrocarbonProcessing.com

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Regional Report KUWAIT Despite its relative size (18 Mkm2), Kuwait has the thirdlargest refining capacity in the ME and consumes only a small portion of its total crude production. The national oil company, Kuwait National Petroleum Co. (KNPC), is investing more than $31 B in projects—the Clean Fuels Project (CFP) and the New Refinery Project (NRP)—to overhaul the country’s refining sector and diversify its oil-heavy economy. The country’s petroleum export revenues account for nearly 60% of its GDP and approximately 94% of export revenues, which were estimated at $92 B in 2013, according to EIA data.5 Once completed, these ambitious modernization/expansion projects will place the country as the third-largest exporter

FIG. 3. Night view of the Mina Al-Ahmadi refinery in Kuwait. Photo courtesy of Kuwait National Petroleum Corp.

of liquids among OPEC producers, behind Saudi Arabia and Iran, and as one of the top 10 oil exporters worldwide.2 Clean fuels project. The $17-B CFP is designed to upgrade and integrate the Mina Abdulla and Mina Al-Ahmadi (FIG. 3) refineries, while the Shuaiba complex will be shut down. The Mina Al-Ahmadi refinery’s capacity will decrease from 466 Mbpd to 346 Mbpd, and Mina Abdullah’s throughput will increase from 270 Mbpd to 454 Mbpd (TABLE 1). The newly integrated refineries will act as a single merchant refining complex, boosting their domestic capacity from 736 Mbpd to 800 Mbpd.4 New refinery project. KNPC’s clean fuels initiative also includes the construction of what will be the ME’s largest refinery—Al Zour (615 Mbpd). The $14.5-B project will produce high-quality petroleum products for export, supply power generation plants in Kuwait with environmentally friendly fuel, and provide alternatives to gas imports and heavy fuel use. Startup of the Al-Zour refinery is scheduled for early 2018. KNPC received EPC proposals for all packages (1, 2, 3 and 4), but the bids for package 4, which includes the construction of oil tanks and pipelines, have been higher than expected. This package and package 5, which includes an export terminal and other marine facilities, are estimated to cost approximately $1.1 B. KNPC has announced that it may re-tender packages 4 and 5; if it does, this process will delay the project by up to six months. As of March, the project is still ongoing.4

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Control. Manage. Optimize. The NEW Research Control® SRD positioner does everything you expect any valve positioner to do, plus more. The SRD’s comp comprehensive diagnostics tool continuously monitors for ffugitive emissions, delivers real-time performance statistics, stati and facilitates both proactive and reactive process proc management. Available with integrated network communications, co the SRD is ccompatible ompatible with Research Control C valves and most other pneumatically-actuated pneu euma m tically-actuated val valves. V sit www.badgermeter.com/Smart-Valve-Positioners Vi www. w ba badgermeter.co Visit or c lll 877-243-1010 ca 877-243-10 010 for more information today. call

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Regional Report The CFP and NRP projects will produce high-quality, low-S fuels for export to various markets around the globe, and they are part of Kuwait’s goal to increase its total domestic refining capacity to 1.4 MMbpd of refined fuels by 2020.2 Expanding olefins cracking capability. Petrochemical Industries Corp. (PIC), a subsidiary of Kuwait Petroleum Co., is developing the country’s third olefins cracker, Olefins 3. The first olefins cracker began operations in the Al-Shuaiba Industrial Area in 1997 as part of a petrochemical complex owned and operated by PIC’s joint venture, Equate. In 2009, it was joined by a second cracker, owned by the Kuwait Olefin Company (TKOC) and operated by Equate. PIC is looking to place the cracker at the new Al-Zour refinery, which would lower costs as it would potentially utilize the refinery’s feedstock. The project will contain a 1.4-MMtpy TABLE 1. Kuwaiti refineries’ current capacities and future expansion plans Present capacity, Mbpd

Planned capacity, Mbpd

Mina Abdullah

270

454

Mina Al-Ahmadi

466

346

Shuaiba

200

–

Al-Zour

–

615

936

1,415

Facility

Total installed capacity

cracker and produce ethylene derivatives like 1 MMtpy of polyethylene and 400 Mtpy–600 Mtpy of polypropylene. Initial feasibility studies conducted in 2010 put the total cost of the project at nearly $5 B; with changing market conditions, that price has ballooned to $7 B–$9 B. The project remains in the early planning stages, and will likely push back the initial completion date of 2018. The feedstock source is still being analyzed, but it will include ethane, offgases, propane and combinations of LPG, naphtha and condensate.

OTHER ME NATIONS Iraq. To alleviate shortfalls in refined fuels and to meet increas-

ing domestic demand, Iraq has laid plans to double its refining capacity to 1.5 MMbpd by 2017. The plan includes $20 B in investments to construct several new refineries with a total capacity of 740 Mbpd. Due to fighting with ISIS and continued economic and political instability, the majority of these projects, except for the Karbala refinery that is presently under construction, have been delayed indefinitely. The Kirkuk refinery plan was revived in late 2014 after continuous delays, and the Iraq oil ministry announced it will rebid the Nassiriya refinery contract in 2015. Shell’s $11-B petrochemical complex in the southern oil hub of Basra is being called Nibras, Arabic for “beacon of light,” and it envisions an ethane cracking unit that would produce ethylene to make plastics. The project is expected to be completed in 2020 or 2021.

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Monitor

Equip

Regional Report Shell is developing the huge Majnoon oil field near Basra that is pumping approximately 200 Mbpd. Shell also signed a $17.2-B deal last year to collect natural gas from Iraq’s southern oil field production. The gas has traditionally been flared, and Iraq has long had ambitions to collect and use the gas to meet domestic energy demand. Qatar. While several large projects have been canceled recently, Qatar is still investing in its refining and petrochemical sectors.

FIG. 4. A Qatar Petroleum-led JV is constructing Laffan Refinery 2 (LR2), a $1.5-B refinery that will process untreated condensate produced from Qatar’s North field.

74MAY 2015 | HydrocarbonProcessing.com

Qatar Petroleum has entered into a JV agreement with Total, Idemitsu, Cosmo, Marubeni and Mitsui, to build Laffan Refinery 2 (LR2), a $1.5-B condensate refinery in Ras Laffan Industrial City (FIG. 4). Qatar Petroleum will hold an 84% interest in the project, while Total will hold 10%, Idemitsu and Cosmo will each hold 2%, and Marubeni and Mitsui will each own 1%. The plant will be operated by Qatargas Operating Co. and developed similarly to Laffan Refinery 1(LR1). The LR2 facility will process untreated condensate produced from the country’s North field, and it will have a processing capacity of 146 Mbpd and a daily production capacity of 60 Mbpd of naphtha, 53 Mbpd of jet fuel, 24 Mbpd of GO and 9 Mbpd of liquid petroleum gas. Additionally, LR2 will include a diesel hydrotreater unit that will be able to process all light GO from LR1 and LR2. A Chiyoda and CTCI JV has been contracted for the engineering, procurement, supply, construction and commissioning (EPSCC). The project is expected to be commissioned in 2016. United Arab Emirates. The Abu Dhabi National Oil Company (ADNOC) will expand its existing Ruwais refinery (400 Mbpd) with an adjoining 417-Mbpd capacity refinery.4 The complex produces LPG, premium unleaded gasoline (98 octane) and special unleaded gasoline (95 octane), as well as naphtha, Jet-A1, kerosine, GO and granulated S. The latest expansion comes on the heels of ADNOC’s other capital intensive projects in Ruwais—such as the Borouge expansion projects (Borouge 2 and 3) as shown in FIG. 5—and will include the addition of crude

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Regional Report distillation and sulfur recovery units, a residue fluidized catalytic cracker (RFCC) and a carbon black delayed coker (CBDC) unit, which will have a production capacity of 40 Mtpy of carbon black and 30 Mbpd of crude. It will consist of two trains with a designed processing capacity of 700 Mt of anode green petroleum coke. The $10-B project is expected to be completed in 2015. Iran. Despite being hampered by economic sanctions, approxi-

mately 360 Mbpd of new condensate splitting capacity is expected to come onstream in three phases, starting at the end of 2015 or early 2016. This project is likely to transform the country from a gasoline importer to an exporter.2 A signed 2013 agreement to begin exporting natural gas to neighboring Iraq has been delayed due to security concerns and fighting between Islamic State militants and Iraqi troops. Completion of the pipeline would initially allow delivery of 4 MMcmd of gas to feed three power plants in Baghdad and Diyala. That volume could rise to 35 MMcmd. Iran has huge gas reserves and exports small quantities to Turkey, but it has been unable to increase production fast enough to meet its own demand. Northern Iran relies heavily on gas imports from Turkmenistan, especially for winter heating.

The Liwa Plastics project is being built to enhance both fuel and plastics production in Oman, and it includes the construction of a gas extraction plant in Fahud. Total costs for the complex, extraction plant, infrastructure and other facilities could top $5 B. Plastics production will increase from 200 Mtpy to 1.4 MMtpy from 2013–2018, while fuels production will grow from 7.3 MMtpy to 11.3 MMtpy from 2013–2018.4 The project will be constructed in tandem with the Sohar refinery expansion and upgrade project. Global engineering firms are eyeing the mega-refinery scheme at the Duqm Refinery and Petrochemical Integrated

Oman. As part of a program to reduce its reliance on the export of

crude oil and natural gas in developing its downstream industry, Oman Oil Refineries and Petroleum Co. (Orpic) plans to construct a greenfield petrochemical complex near the Sohar refinery.

FIG. 5. ADNOC is expanding its existing Ruwais refinery following previous projects at Borouge 2 and 3.

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Hydrocarbon Processing | MAY 201575

Regional Report Complex on Oman’s Al-Wusta coast. Duqm Refinery and Petrochemical Industries Co. LLC (DRPIC), an equal JV of Oman Oil Co. (OOC) and International Petroleum Investment Co. (IPIC), respectively the energy investment arms of the Sultanate of Oman and the UAE Emirate of Abu Dhabi, is jointly developing the refinery project with an investment of approximately $6 B. Plans for an associated petrochemical complex in the second phase could add a further $9 B to the total project cost. One of the project’s main goals is to facilitate the export and import of hydrocarbon products in a region still underdeveloped compared with the north of the country. The project

also holds strategic importance, as imports and exports will not have to travel through the Strait of Hormuz. Turkey. The planned Socar Turkey Aegean Refinery (STAR)

will be integrated at the Petkim petrochemicals site on the Aegean coast. It will process medium-sour crudes (Azeri light, Kerkuk and Urals oil) into low-S transportation fuels, meeting Euro 5 specs. The products will be mainly sold to the domestic market and will provide feedstock for the Petkim Petrochemical complex, part of Socar’s downstream activities and its most important production unit outside Azerbaijan. The $5-B project, which is expected to be commissioned in 2018, is a JV between Azerbaijan state oil firm SOCAR and Turkey Enerji AS.

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Bahrain. The $5-B expansion of Bahrain Petroleum Co.’s (BAPCO’s) Sitra refinery will increase processing capacity by 35% to 360 Mbpd.4 The project includes a $360-MM expansion, from 120 Mbpd– 350 Mbpd, of a pipeline that supplies the refinery with light crude from Saudi Arabia. The refinery imports approximately 85% of its crude oil from Saudi Arabia and is connected by a 54-km pipeline for pumping the feedstock. BAPCO sells 8% of the refinery production to the domestic market and exports the remaining 92% to India, the ME, the Far East and to Africa. National Oil & Gas Authority (NOGA) is planning to install an LNG floating storage unit (FSU) that will have an initial capacity of 400 MMcfd and be expandable to 800 MMcfd. The project will consist of a floating storage unit connected to a regasification unit on an island jetty. The $600-MM terminal will combat the trend of domestic demand outpacing supplies. Looking forward. The ME is witnessing a unique combination of consistently high local demand growth, secure feedstock supplies, dominant NOC investors and a shift from crude oil to refined product exports. These trends suggest that the ME will remain detached from the economic woes overshadowing the international refining business for the foreseeable future. 1

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5

LITERATURE CITED Organization of the Petroleum Exporting Countries, “Monthly Oil Market Report,” March 2015. Nichols., L. and S. Romanow, Hydrocarbon Processing’s HPI Market Data 2015, “Global Construction and Investment” and “Refining.” US EIA, “Saudi Arabia Analysis Brief,” September 10, 2014. Hydrocarbon Processing’s Construction Boxscore Database, April 2015. US EIA, “Kuwait Analysis Brief,” October 24, 2014.

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Learning opportunities abound at ILTA’s 2015 conference and trade show!

Join ILTA in Celebrating 35 Years in Houston!

ILTA Conference

RECEPTION

ILTA 2015 Trade Show

Monday, June 1 – Tuesday, June 2 Focused sessions will feature more than 30 industry experts who will share the latest in improving terminal operations, enhancing business performance, and achieving regulatory compliance.

Tuesday, June 2 | 6:00 p.m. to 8:00 p.m. George R. Brown Convention Center | Exhibit Hall E

Don’t miss this great opportunity to network with terminal industry colleagues! This reception is open to all ILTA attendees and exhibitors. Enjoy live jazz or take a picture in our 80s-themed photo booth and capture your 2015 memories.

Exhibitor Presentations Series Tuesday, June 2 | 2:30 p.m. to 5:30 p.m. Short presentations provide trade show attendees with the opportunity to hear directly from vendors about some of the products and services available at ILTA’s trade show.

Corrosion Technologies Forum Wednesday, June 3 | 9:30 a.m. to 11:30 a.m.

PLUS!

Panelists will discuss common causes for corrosion and present different strategies for prevention and mitigation. This session is open to all trade show attendees.

Five additional educational sessions will be offered as part of ILTA’s Post-Conference Training.

JUNE 1-3

2015

35TH ANNUAL IN T ER N ATIO N A L O P E RATI NG CONFERENCE & TRADE SHOW

H OU STON , TE XAS

R E G I STER TO DAY

GEORGE R. BROWN CONVENTION CENTER

AT

WWW. I LTA .OR G

Rotating Equipment M. VILA FORTEZA, Repsol SA, Petronor, Spain

Use new methods to optimize energy efficiency of hydrogen compressors Hydrogen (H2 ) is a key to efficient operation of refinery desulfurization units (DSUs). Process H2 , both pure and recycled from DSUs, must be compressed to pressures up to 85 kg/cm2. Centrifugal compressors and reciprocating compressors are used depending on the flow and pressure requirements of the process. Reciprocating compressors are often used for low to medium flow conditions under a wide range of pressure rates. Leak mitigation and efficiency. Several elements can be analyzed to reduce leaks and energy consumption for reciprocating compressors. FIG. 1 shows an energy balance for a typical reciprocating compressor and ways to maximize energy savings. Oil refineries must also implement carbon dioxide (CO2 ) emissions programs while improving energy efficiency. This article will provide guidelines to help reliability and process engineers make better decisions on the operation of reciprocating compressors. This analysis is from the user’s viewpoint and will address three different topics: control of process and machine operating parameters; capacity control; and energy-efficient design of valves and packings, as well as piston rings and bands.

COMPRESSOR OPERATING DATA It is not difficult to find reciprocating compressors that are in good mechanical condition but not working efficiently due to excessive wear, off-design operating conditions or other external issues. In these cases, new investment or upgrades/revamps of the machine are not necessary to increase efficiency or operating performance. With thorough machinery knowledge, experience and improved technologies, engineers can detect inefficiencies in these compressors. Some common operational issues and process parameters are identified to help optimize energy performance of reciprocating compressors.

Conversely, modern monitoring systems have great potential in planning predictive/preventive maintenance of the machine, as well as to detect energy inefficiencies. Leakage and internal recirculations or inefficiencies can be determined by analyzing the PV diagram and other related performance parameters, such as valve temperatures and packing (FIG. 2). Periodic inspection, by qualified technicians, on parameters that are sensitive to energy consumption can justify maintenance work based on energy savings obtained from the repair. Inefficiencies that can be diagnosed with monitoring systems are: valve leakages (suction or discharge), leaking packings and internal recirculations due to wear of piston rings. Also, some monitoring systems include useful tools to calculate the approximate economic impact due to these inefficiencies. The savings achieved with predictive maintenance repairs will depend on the installed capacity of the machine, as well as on the magnitude of the leak or gas recirculation detected. Compressor design and process conditions. Compres-

sors operating away from design conditions can cause serious inefficiencies.2 Although it is not obvious, assessing the state and process conditions of reciprocating compressors can be opportunities to optimize operations. The compression efficiency of a reciprocating compressor depends on many factors, including valve efficiency, compression ratio, gas composition, machine size and internal clearances. These factors can be divided into groups that depend on process conditions and those related to inappropriate designs. Conversely, mechanical efficiency is a function of size and mechanical design of the machine. Several interesting aspects to consider when assessing the energy efficiency of a reciprocating compressor are: Friction losses

pressor manufacturers and specialized companies have developed sophisticated software for continuous monitoring of reciprocating compressors. The related analyses are obtained in real time and can be overlapped to do more complex studies when required. Newer monitoring systems can survey more online parameters that allow the engineers the ability to assess the compressor’s status and successfully anticipate failures that formerly could not be detected. The primary justification to install a monitoring system is based on early fault detection and protection of the machine against breakdowns. Without such systems, it would be very difficult to detect a catastrophic or high-cost failure.

Energy used by the compressor

Continuous monitoring systems. In recent years, both com-

2%–7%

Valve Leaks from piston losses rings and packings Packing friction losses

3%–10%

0.5%–1%

1%–3%

Bypass energy losses

12%–50%

Indicated compression energy Energy balance for a typical (1 MW–4 MW) reciprocating compressor operating in a refinery. Sources: C. Bouché and K. Wintterline, Kolbenverdichter, Springer Verlag.

FIG. 1. Energy balance for a typical refinery reciprocating compressor. Hydrocarbon Processing | MAY 201579

Rotating Equipment Gas composition. The PV diagram will vary according to the process gas composition—thus, the energy used in the compression cycle will also vary. It is essential to know the gas composition when assessing energy efficiency to achieve consistent conclusions and formulate effective actions. Suction temperature. The hotter the gas entering the cylinder, the hotter the discharged gas after compression. The cooling system may become ineffective and not qualified for actual working conditions. Also, the colder the gas entering the compression chamber, the denser the gas will become, and more pumped mass per volume unit is achieved, thus increasing compressor capacity. Valve design. When the process conditions differ considerably from the original design, the performance of the valves could decrease significantly. It is easy to install new valves to meet new process conditions or to modify the existing ones. The efficiency and performance of the compressor can be improved. Cylinder, packing and frame lubrication. It is important to control the oil viscosity, pressures, temperature and other oil properties because they do affect the mechanical efficiency of the machine. Clearance volume. In a reciprocating compressor, the clearance volume is a residual space at the end of the stroke between the head end or crank end when the piston is located at TDC or BDC, plus other remaining spaces inside the compression chamber. Clearance volume typically ranges between 4% and 16% of the swept volume, and it can essentially decrease or increase flow capacity. A higher clearance volume can result in lower volumetric efficiency and lower compressor capacity. It is very important to understand the impact of clearance volume on the capacity of the machine. Compressor capacity can be modified by changing the uncompressed volume of gas inside the cylinder. Fitting the machine capacity to the flow required by the process will allow minimizing the quantity of gas through the recirculation valves and energy consumption. Compression ratio. Depending on the original process conditions, the compressor is designed to work efficiently over a specified range of temperatures and pressures. When varying Safety analysis Vibration

Wear monitoring Data Safety acquisition protection

Performance optimization

Temperature

Lubrication monitoring

Other

Process data analyses

VISU

Component tracking

FIG. 2. (a) Analysis capabilities of VISU NT, PROGNOST Systems. Source: PREDITEC-PROGNOST Systems. Suction valves Crank end

Head end 1

Gas recirculation. The process conditions impact the flow of compressed gas that is recycled to the compressor suction or sent through the process unit even when this gas it is not necessary to be processed. Both conditions can lead to significant energy consumption because excess gas is compressed without any process benefits. It is possible to achieve savings in both the energy used to compress the gas and in the energy required in the furnaces, coolers and other heat-transfer equipment. Reciprocating compressors, even older machines, usually have unloaders on the intake valves and clearance pocket valves on/off in the cylinder head to achieve some flow regulation. This regulation is usually controlled manually. With this capacity control feature, some gas recirculations/bypasses can be minimized by just adjusting the compressor capacity when the bypass valve is open to recirculate the gas. Periodically checking the required flow by the process vs. the loading in which the compressor is operating can yield significant savings in both the power consumed by the compressor driver and the energy required for other plant equipment.

Early failure detection

Displacement Pressure

pressures, the machine may work with excessive compression ratios at any of its stages. Apart from mechanical problems, this operating method will involve excessive heating of the gas and sometimes a decrease in compression efficiency. It is important to check the operating pressures of each cylinder, so that all stages work without high discharge temperatures or excessive mechanical stresses. Gas cleanliness. Particles and dirt in the gas can lead to accelerated wear of the bands and segments. Result: It materializes as inefficient operation of the valves and other problems. Clean gas will help achieve better performance of the compressor and optimize the reliability of those elements that impact energy consumption of the machine. Minimizing excessive wear will improve the compressor’s efficiency and reliability. Any modifications to the machine should be done under strict adherence to the design specifications and verified by the original equipment manufacturer (OEM) or authorized component manufacturer. The goal is to ensure safe design and desired results.

2

Discharge valves 100% capacity

1

2

50% capacity (suction valves held open crank end)

1

2

0 capacity (suction valves held open both ends)

FIG. 3. Example of valve unloading in a cylinder with three load steps.3

80MAY 2015 | HydrocarbonProcessing.com

Cylinder cooling. Another important energy efficiency issue is cooling the cylinders and gas being compressed. In those cases, where the cylinder is partially loaded, fresh gas flow is reduced, so the cooling system must be checked and controlled. The fundamental advantages obtained from good cooling of the cylinders include:3 1. Dissipating heat due to friction and caused by the piston rings 2. Improving the cooling system of the cylinder to prevent excessive temperature rises in those parts subject to friction in the compression chamber 3. Improving the cooling system will maintain the oil viscosity in the cylinder at appropriate values, thus reducing friction and wear. Likewise, while good cooling is important, excessive cooling of the process gas may cause condensation and lead to other problems, including corrosion and wear on pistons, bands and rings. The effects from cylinder cooling efficiency during the compression cycle are usually studied from the temperature-

Rotating Equipment entropy (TS) diagram of the cycle. Good heat transfer through the cylinder walls is important, as the polytropic exponent (actual parameter compression process) is reduced. This effect involves a lower ratio of the polytropic work and isothermal compression and, therefore, a greater compression efficiency.4 API 618 has good information and recommendations on the design of cooling systems. Other valuable literature references are listed at the end of this article.

CAPACITY CONTROL In reciprocating compressors, the major energy inefficiency source is the capacity control of the machine. Flow control of the pumped gas according to the specific needs of the process has been broadly developed as the cost of energy and CO2 emissions have increased. There are different capacity-control methods used for reciprocating compressors. Some have been used for years, and the control range is very limited. More modern technologies have been developed that offer higher flexibility and, therefore, significant energy savings. The range of working loads and the compression ratio will often determine the control system selected. All working cases and loadings of the machine must be verified by the OEM to obtain the optimal capacity control in terms of energy savings and reliability. Several typical capacity control systems in reciprocating compressors are described here: Gas recirculation to the suction line. The simplest method to control gas flow to the process is the recirculation of excess

compressed gas to the compressor suction. Through an automatic valve, normally commanded by the suction pressure set point, excess gas is recirculated to the suction line. Although a simple method, recirculation of compressed gas is very inefficient, because a certain amount of gas that has been compressed is expanded again when it returns to the compressor inlet pipe to be recompressed. Depending on other factors, the compressed gas must be cooled before going back to the machine; sometimes additional coolers may be necessary. The gas recirculation valve to the inlet pipe is usually installed on compressors, regardless if it is used as a primary capacity control system. This method helps other flow-control systems to ensure finer control, or it can be used for emergency flow recirculation if the main control system fails. Throttling of suction gas valve. Another simple technique to control reciprocating compressor capacity is to use pressure reduction at the inlet pipe through a manual or controlled valve. This method will reduce the volumetric efficiency by lowering the gas density, thus the mass of compressed gas (capacity) decreases. The major disadvantage of this method is that a significant decrease in suction pressure is necessary to achieve effective flow control of the machine. Also, due to the suction pressure reduction, the compression ratio increases, and the discharge gas temperature can substantially increase as well as the rod loadings. In some cases, it may not be a noticeable decrease in

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Rotating Equipment power consumption due to the higher compression ratio and discharge temperature. Unloaders on suction valves. This method is the most widely used to control the load on double-acting reciprocating compressors (FIG. 3). Load control is achieved by loading or unloading the suction valves with pneumatic actuators, which are usually operated manually, depending on the required capacity. The unloaded valves are open during the compression cycle, so that the gas moves in and out of the compression chamber through the suction valve. This flow is not sent downstream, thus reducing the capacity of the machine and energy consumption proportionally to the amount of gas that is not compressed. This system does not permit a fine control of the load, and the quantity of load steps that can be achieved depends on the

FIG. 4. Clearance pocket valves, handwheel operated and hydraulic. Source: Dresser-Rand. Pocket control valve

}

Control gas connection Fixed volume pocket

number of cylinders and compression stages, along with the number of valves installed on each cylinder end. Typically, load stages with which the machine is designed are 0%–25%–50%– 75%–100%. As these are fixed steps of load, a certain quantity of excess gas should be recirculated to the compressor suction to deliver only the required flow to the process. The efficiency of this method is good because the adiabatic power is reduced proportionally to the flow reduction. However, the gas recirculation through the open valves leads to some power losses, which may be important. Variable clearance pocket. As pointed out earlier, the clear-

ance volume present in the cylinders of a reciprocating compressor will change the volumetric efficiency. Any change in the clearance volume of the cylinder will affect the maximum load capacity of the compressor. Previously, compressors were designed with “clearance pockets” that provided one or two additional steps of loading on each cylinder, depending on its location (crank end, head end or both). Later, with the development of electronics, some manufacturers have designed hydraulic control systems that enable automatic clearance volume with continuous fine adjustments during the compression cycle (stepless-capacity control systems) at rates from 50% to 100%. FIG. 4 shows a manually actuated valve that allows one additional load step in the head end of the cylinder, along with another valve that is hydraulically actuated to permit stepless-capacity control. FIG. 5 shows a new control system in which the hydraulic unit is not needed because the capacity control is achieved due to a reference gas, typically the process gas compressed by the machine. The clearance pocket can be mounted in both cylinder ends, and it is possible to achieve a regulation range from 70% to 100%. This system works with a standard valve, and is easy to install and maintain. P

Dr

A

P

D

Compressor cylinder

Dr

A

Energy savings compared to recycle valve control

Cr

B

Cr C V

B

TDC

BDC

TDC

FIG. 5. Clearance pocket—gas-controlled stepless pocket (GSP). Source: Dresser-Rand.

D

C

V

BDC 6

FIG. 7. Capacity regulation reverse flow. Source: HOERBIGER. A–A

a

Piston ring

Cylinder A

Piston b

A

C

ba

FIG. 6. HYDROCOM control system.6 Source: HOERBIGER.

82MAY 2015 | HydrocarbonProcessing.com

FIG. 8. Gas recirculation areas through piston rings.8

Gap

Rotating Equipment Reverse flow capacity control systems. Capacity-control systems based on a reverse flow effect present an interesting evolution. While using the traditional unloaders on the cylinder effect where the valve works is unloaded during the whole cycle, the reverse-flow systems allow the valve to work only during a part of the compression cycle, thus obtaining a stepless-capacity-control system. This system was developed in the 1990s; it has evolved and is considered very reliable (FIGS. 6 and 7). Several manufacturers have developed their own capacity-regulation system based on the same principle. They all offer good energy savings because the capacity control ranges from 20% to 100% capacity.

MODERN DESIGNS OF COMPRESSOR COMPONENTS Other improvements in compressor design include: Rider bands and piston rings. From FIG. 1, between 2% to 7% of the energy used in a reciprocating compressor is due to friction losses, and 0.5% to 1% of energy loss is attributed to gas recirculation through piston rings and packings. The losses derived from internal recirculations have an influence on the volumetric efficiency (between 0.5% and 3%), thus affecting the flow capacity of the cylinder.7 Using quality rider bands and piston rings not only influences reliability, but also affects total energy consumption and the pumping capacity of the compressor. Great advances in plastic materials for the manufacturing of rider bands and piston rings have increased the service life of these elements, thus reducing wear and maintenance costs due to the high-wear. Likewise, internal recirculation through the piston elements are minimized due to the limited wear, even the nonlubricated, which tend to wear faster. Rider band and piston ring materials are usually of a combination of PTFE with graphite or other elements, depending on process gas conditions. New piston designs allow installing the rider bands with an appropriate distribution, which minimizes losses and friction between the liner and piston rings (FIG. 9). For example, distributing the sealing segments in the central part of the piston will lead to a higher service life, because the elements work at a lower differential pressure, which is distributed across the piston rings. Internal recirculations are minimized due to new design. Using this configuration, rider bands are grooved to keep them from acting as seal elements. Sealing should be done by the piston rings. The efficiency of the sealing elements of the piston is strongly influenced by gas cleanliness and good cylinder lubrication (on machines where it is required).

Valves. Both suction and discharge valves have traditionally been a huge reliability problem for reciprocating compressors. One of the most renowned field studies suggests that 36% of faults due to unscheduled reciprocating compressor shutdowns are linked to valve problems.9 The study was done in 1996, and valve design has evolved. New data shows that a longer service life is now possible with improved valve design and new construction materials. When a reasonable lifetime of compressor valves is obtained, manufacturers’ efforts are directed to reducing losses by friction. Valve manufacturers have achieved performance improvements with energy consumption savings up to 2% over conventional valves. Simulation tools, such as computational fluid dynamics (CFD), have enabled redesigning conventional valves to obtain substantial improvements in energy efficiency (FIG. 10). It is possible to reduce the gas velocity passing through the valve and the formation of vortexes; both have a great impact on the efficiency of valve, which can be calculated based on the effective flow area (EFA).10 It refers to the throat area for an ideal discharge nozzle that can be calculated (for non-viscous in subcritical flow) from the ratio, Ks : %

m

Ks  GFA

P01

2 RT01 

1

PS2 P01

2

PS2 P01

1

FIG. 9. Piston rings installed in a central position reduce internal recirculations, as the differential pressure between them is lower than in other designs. Source: GE Oil & Gas. Select 170 at www.HydrocarbonProcessing.com/RS

83

Rotating Equipment Once Ks is calculated, the valve efficiency can be calculated: EFA = GFA × Ks with: GFA = OP × Lift where: Ks = Flow coefficient Lift = Stroke from the closed to the open position ṁ = Measured mass flowrate P01 = Total pressure upstream of the valve Ps2 = Static pressure downstream T = Total temperature upstream γ = Ratio of heat capacities Δp = Pressure drop across the valve Φ = Valve diameter EFA = Effective flow area GFA = Geometric flow area OP = Opening periphery

7 6 5 4 3 2 1 0

Conventional tangential/radial ring BCD ring

Energy savings

10

20

30 40 50 Supply pressure, bar

60

70

FIG. 11. a) Power savings on BCD packings; (b) BCD ring. Source: HOERBIGER. 0.9 0.8 0.7 0.6 0.5 0.4 0.3 0.2 0.1 0.0

Packings. About 3% to 10% of the energy used by reciprocating compressors is generated by friction losses in the packings. Another 0.5% to 1% of energy loss is due to leaks in the packings and piston rings. The packings also have a high influence on reliability, as they are subjected to significant wear. Preventing leaks to the environment and flares has been addressed by new designs developed by OEMs in energy efficiency and reliability. Packing does influence energy consumption for compressors. It is estimated that each standard ring set tangential/radial may represent an average energy consumption of about 5 kW. This power value multiplied by all the rings installed on the machine is not negligible. Manufacturers have developed new designs to minimize friction between rings and the piston rod. A new design (FIG. 11) uses a single-ring design with a pressure balancing groove that reduces friction losses up to 40% over standard packings.a Packings are responsible for most gas leaks, and have environmental and economic impacts (FIG. 12). To dilute and minimize leakage of process gas, low-emission packings have been installed

Energy loss, %

Loss by friction, kW

FIG. 10. Simulation CFD of a valve. Typical discharge valve arrangement.10 Source: GE Oil & Gas.

ID = Inner diameter OD = External diameter. The efficiency of the valve increases by increasing the EFA parameter, so it can be deduced from the listed equations that valve efficiency will improve by increasing within certain limits one or more of these parameters: Opening periphery (OP) is the length of the perimeter of the gas passage on the seat. It can be calculated for a ring valve as the sum of the OD and ID of all rings inside the valve. Lift is the maximum stroke from the closing to opening positions of the rings or plate inside the valve. Ks is the ratio between the ideal nozzle throat area (EFA) and the GFA.

Packing leakage erratic and elevated due to changes in cup pressure distribution

BCD ring RT ring

FIG. 13. Packing with nitrogen as buffer gas.11 Source: HOERBIGER.

Specially designed oil seals poil pressurized oil

Average leakage Average leakage

Service life (Set of one radial cut ring and one tangential cut ring)

FIG. 12. Comparison of average leakage BCD ring vs. radial/tangent ring design.11 Source: HOERBIGER.

84MAY 2015 | HydrocarbonProcessing.com

pgas poil > pgas

FIG. 14. XPerSeal packing.12 Source: HOERBIGER.

Rotating Equipment equipped with inert gas injection (usually nitrogen). This design is well-proven and validated by the successive revisions of the API 618 about reciprocating compressors. FIG. 13 shows a packing system equipped with nitrogen injection. Another advanced design aims to achieve zero leakage and minimize friction losses, as shown in FIG. 14.b In this case, pressurized oil is injected into the packing at a pressure slightly higher than the gas pressure, so the leak is avoided. Oil consumption is minimal, and, due to oil flow friction losses, the temperatures reached in piston rod and packing rings are lower than those that are obtained in other designs.

CONCLUSIONS There is an important improvement margin in terms of energy efficiency related to reciprocating compressors. Some modifications and best practices can be implemented easily and with very little investment. Some improvements can be obtained simply by adjusting the loading of the compressor to the real needs of the process, thus avoiding unwanted gas recirculation. The daily work of checking process conditions and machine capacity is critical to improving compressor efficiency and performance. The reliability engineer must be aware of new developments to take advantage of solutions and practices that are efficient in terms of energy and to minimize gas leakages and recirculations. NOTES A new design with reduced friction is the Balanced Cup Design (BCD) made by HOERBIGER. b XPerSeal, developed by HOERBIGER. a

LITERATURE CITED Dimoplon, W., “What Process Engineers Need to Know About Compressors,” Compressor Handbook for the Hydrocarbon Industries, Gulf Publishing Company, 1979. 2 Vila Forteza, M., “Eficiencia energética y actualización tecnológica de compresores centrífugos en la actual coyuntura económica, Revista Mantenimiento, No. 267, September 2013. 3 Bloch, H. P. and J. J. Hoefner, Reciprocating Compressors Operation and Maintenance of Reciprocating Compressors, Gulf Publishing Company, 1996. 4 EFRC Website, http://www.recip.org/173.0.html. 5 Faulkner, H. B., “An investigation of instantaneous heat transfer during compression and expansion in reciprocating gas handling equipment,” Massachussets Institute of Technology, 1983. 6 Stachel, K. and M. Wenisch, “Improved control concepts for reciprocating compressors in refining processes,” ERTC 18th Annual Meeting, November 2013, Budapest, Hungary. 7 Hanlon, P. C., Ed., Compressor Handbook, McGraw Hill, 2001. 8 Liu, Y. and Y. Yongzhang, “Prediction for the Sealing Characteristics of Piston Rings of a Reciprocating Compressor,” International Compressor Engineering Conference, 1986. 9 Leonard, S. M., “Increasing the Reliability of Reciprocating Compressors on Hydrogen Services,” NPRA Maintenance Conference, May 20–23, 1997. 10 Kosla, A. and A. Babbini, “Fluid dynamic design of a new generation of reciprocating compressor valves,” GE Technology insights, 2013. 11 Lindner-Silwester, T., and C. Hold, “The BCD packing ring—a new high performance design HOERBIGER Ventilwerke GmbH & Co KG.” 7th Conference of the EFRC, October 2010, Florence, Italy. 12 XPerSeal Customer Presentation 2013, HOERBIGER. 13 Machu, E. H., “Valve Throttling, Its Influence on Compressor Efficiency and Gas Temperatures,” International Compressor Engineering Conference, Paper 805, 1992. 1

MARC VILA FORTEZA is responsible for the rotating machinery/reliability department at Repsol S.A.’s Petronor refinery at Muskiz, Spain, since 2009. He holds an MSc degree in mechanical Engineering and a BSc degree in naval engineering from the Polytechnic University of Catalonia (UPC), Barcelona, Spain. He has published technical articles on reliability, hydrogen compressors and lubrication management.

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Process Technology F. SADEGHI, S. SADEGHI and U. SUNDARARAJ, University of Calgary, Canada

Improve measurement of heavy oil viscosity This work will study the viscosity behavior of bitumen and its blends with diluent at different temperatures, as well as evaluating simulations for prediction of viscosity of the blend. A blend of bitumen and diluent was prepared, and the viscosities of the bitumen and blend were measured by a viscometer at three different temperatures and compared to simulation results. The effect the diluent (kerosine) addition into the bitumen had on the viscosity of the blend was also studied by experiment and simulation. It was found that the addition of 10 wt% diluent resulted in a viscosity reduction equivalent to increasing the temperature from 30°C to 50°C. The viscosity at low temperatures (such as 30°C) showed a shear-thinning behavior, indicating viscoelasticity; whereas, at a higher temperature (such as 50°C), a Newtonian behavior was observed over the range of shear rates studied (0.01–100 s–1). The results showed a structural phase transition at a temperature between 40°C–50°C for both the neat bitumen and the bitumen-diluent blend. Viscosities at three temperatures (30°C, 50°C and 80°C) were measured, and the results were compared with simulation results obtained by a process simulation and optimization tool used for viscosity evaluation that has the ability to model all processes into one simulation environment. There was a significant deviation between the simulation tool and the experimental data for the viscosity of bitumen and its blend with the diluent. The tool’s simulations were greatly influenced by bitumen characteristic inputs. It was observed that if only the distillation curve of oil (i.e., composition) is loaded in the simulation tool’s oil manager, the predicted viscosity would be very different from the experimental value. A much better match was obtained when bulk properties, such as density and viscosity at two temperatures, were also loaded into the simulation tool. Characteristics of bitumen. Bitumen is considered an ex-

tra-heavy oil that does not flow unless heated or diluted with a light crude oil or natural gas condensate. It has a high viscosity (10,000 cP) under reservoir conditions. Extraction of bitumen as a source of crude oil has recently received more attention because of high oil prices and the introduction of new profitable technologies for extraction and processing. Production, transportation and refining of crude oils, in general, are significantly dependent on the viscosity. Viscosity is a significant factor for designing separation processes. For example, oil, water and gas are separated in a three-phase separator. Separation of water from oil is highly

dependent on oil viscosity. Separation occurs based on Stokes’ law (Eq. 1) in low regime:1 Vt = (1,000 × g × Dp2) × (ρ1 – ρ2) / (18μ)

(1)

The terminal velocity, Vt , or settling velocity, of water droplets is inversely proportional to viscosity, μ, and proportional to the gravitational constant g. Here, Dp is the droplet diameter, ρ1 , is the water density and ρ2 is the oil density. Decreasing the viscosity tenfold could improve (i.e., decrease) the settling velocity tenfold and result in much lower residence time and, consequently, smaller separator size. Oil viscosity also affects sizing of pipelines because pressure loss in pipelines depends directly on fluid viscosity. For example, hydraulic calculations show that an increase in viscosity from 1 mPa.s to 10 mPa.s will increase the pressure drop by 10%–50% (depending on roughness/friction factor) in turbulent flow,2 resulting in significant costs for pumping equipment and energy/power to operate. The same increase in viscosity could reduce the terminal velocity for a water droplet size in a separator by 10 times (Stokes’ law), which would be reflected in a much longer separation vessel. To facilitate transportation, the viscosity of bitumen can be reduced either by heating to a higher temperature or by adding a diluent, or both. Generally, a diluent is added at regular distances along pipelines carrying heavy crude to reduce the viscosity, thus facilitating the flow. This diluted bitumen is called dilbit, and the method is considered an effective way to transport highly viscous oil. Naphtha or gas condensates are the usual diluents in dilbit. The viscosity of bitumen is reduced to meet the pipeline specifications of 19°API and 350 cSt at minimum temperature (i.e., 8°C within the pipeline).2 One study examined the dilution of bitumen using methyl tert-butyl ether (MTBE) inhibited asphaltene deposition, which can occur when paraffinic hydrocarbon is used as diluent.3 A liquid viscosity model was used to calculate viscosity of components as a function of temperature, and then used the mixing rule to determine blend viscosity as a function of composition. A distillation test was also performed to assess separation of diluents from bitumen, and it was found that the bulk of diluents could be removed without difficulty. Another article studied different mixing rules for heavy and light oils.4 It was found that prediction using pure mixing rules yielded a viscosity with high error. Their analysis showed that the accuracy of the model in predicting viscosity diminished as the API decreased. The effect of viscosity and water droplet size in water/oil emulsion systems was also investigated.5 They Hydrocarbon Processing | MAY 201587

Process Technology showed that asphaltenes play an important role in stabilizing water droplets in the mixture. As a result, a smaller average particle size and higher viscosity were reported with increasing asphaltene content in the emulsion. An article developed a correlation for predicting the viscosity of heavy oil/diluent systems.6 They proposed a model that showed good agreement with experiments, especially for mixtures with higher viscosity ratios (ratio of 20 or above). The required input for their model was density and viscosity of the heavy and light components. They used a modified version of the Arrhenius equation and reported a good agreement between the predicted and experimental data. However, some limitations were noted for the proposed model, i.e., it was valid only for mixtures with high-viscosity ratios and should be used

with caution for low-viscosity ratio systems. Additionally, the effect of temperature was not verified. The viscosity of mixtures of bitumen with toluene was studied.7 It introduced a temperature-dependent viscous interaction parameter, Bij , into the formula to improve the viscosity prediction. Toluene was chosen as the diluent because paraffin-based solvents might lead to asphaltene precipitating out of the solution; it was observed that aromatic solvents such as toluene and benzene would dissolve bitumen in all proportions. Viscosity reduction could be achieved using a liquid diluent at any pressure, including ambient pressure.8 A model for prediction of the viscosity of bitumen/diluent mixtures was presented.9 However, the model was not in good agreement with experimental results for diesel/bitumen mixtures and a large error was reported.

TABLE 1. Distillation curves for bitumen and diluent Bitumen TBP distillation curve: SIMDIS, ASTM D7169 Mass wt%

TBP, °C

0

209.8

10

192

5

323.2

20

200

10

358.9

30

204

Vol. wt%

15

387.2

40

207

412.5

50

209

25

434.5

60

213

30

458.8

70

218

35

483.8

80

226

40

509.7

90

239

45

537.6 567.3

55

597.1

60

626.5

was carried out in a modified gas chromatograph with methodology based on ASTM D7169. The properties of the bitumen and diluent used in this study are listed in TABLES 1 and 2. Viscosity measurements were conducted using oscillatory and rotational rheometers. Measurements were performed using Couette geometry (inner cylinder diameter = 27 mm; gap = 2 mm) at an elevated temperature and cone-plate geometry for heavy oil at low temperature (disk diameter = 25 mm; gap = 47 micron; angle = 1°). The blend was prepared by adding 10 wt% kerosine to bitumen.

TBP, °C

20

50

The distillation curve for bitumen. A simulated distillation

Diluent (kerosine) distillation curve: ASTM D86

Results and discussion. The viscosity measurements for bitumen were performed using parallel-plate geometry at room temperature due to high-normal forces exerted on the measuring system upon lowering the inner cylinder into the outer cylinder. Viscosities of the samples at other conditions TABLE 2. Bulk properties of bitumen and diluent Bitumen

65

652.9

70

676.4

Density at 15°C

75

694.8

80

711.4

Diluent (kerosine)

998 kg/m3

Density at 15°C

756 kg/m3

Viscosity at 30°C

510 Pa.s

Viscosity at 30°C

0.00161 Pa.s

Viscosity at 80°C

2.09 Pa.s

3.0

600

A) 30°C

Bitumen

500

B) 80°C

2.5

Bitumen 2.0 ␩*, Pa.s

␩*, Pa.s

400 300

1.5

200

1.0

100

0.5

Blend 0 0.01

Blend 0.1

1

Shear rate, 1/s

10

100

1,000

0.0 0.01

FIG. 1. Effect of diluent addition on viscosity of bitumen: a) at 30°C and b) at 80°C.

88MAY 2015 | HydrocarbonProcessing.com

0.1

1

Shear rate, 1/s

10

100

1,000

Process Technology tioned distinctive microstructures, which are highly dependent on thermo-mechanical conditions, are responsible for the linear and nonlinear rheological behavior of heavy oil materials. The results obtained from viscometry are compared to simulation results in TABLES 3–5. In TABLE 3, the simulation results based on inputting only the distillation curve of the heavy oil into the simulation software are presented. There is a significant difference between these simulation results and the viscometry results in TABLE 3. Changing the thermodynamic property package did not improve the simulation results. In fact, for both thermodynamic packages, the simulation tool greatly underestimated the viscosity for bitumen and for the blend. In another simulation, the density of oil and its distillation curve were loaded into the simulation software, and the results are shown in TABLE 4. It is observed that viscosity prediction slightly increases in this case, but there is still a considerable discrepancy between the simulation and experimental values. Therefore, it is concluded that including density in the simulation does not significantly improve the prediction of viscosity. In another attempt, the density and viscosities of heavy oil at two temperatures (30°C and 80°C), along with the distillation curve, were loaded into the software and simulation results were compared to experimental measurements in TABLE 5. 600

Bitumen, 30°C

500

␩*, Pa.s

400 300 200 100

Blend

Bitumen, 50°C

0 0.01

0.1

1

Shear rate, 1/s

10

100

1,000

FIG. 2. Effect of viscosity reduction of bitumen by increasing temperature from 30°C to 50°C compared to adding 10% diluent.

100

Modulus, Pa

were measured using Couette geometry at three temperatures (30°C, 50°C and 80°C). The results for the heavy oil and blend of heavy oil with 10 wt% diluent at two temperatures (30°C and 80°C) are shown in FIG. 1. The rheological behavior of bitumen is different near room temperature than at higher temperatures. At 30°C, bitumen shows a viscosity plateau at a lower shear rate and shear-thinning behavior at a higher shear rate. Such behavior has been reported for heavy oil at low temperatures.10 This is likely related to fraction of high-molecular-weight hydrocarbon molecules in heavy oil that exhibit shear-thinning behavior, like polymer molecules. Viscosity drops by about 35% from low to high shear rate range for heavy oil at room temperature. However, it is observed that an addition of 10 wt% kerosine diluent has a more significant effect. Viscosity decreases by more than 10 times and no significant shear-thinning behavior is observed. The results in FIG. 1B show that the effect of increasing temperature (30°C to 80°C) on the reduction of bitumen viscosity is much more significant than the addition of 10% diluent. The effect of diluent addition on viscosity reduction of bitumen is also different at 30°C and 80°C. Adding 10% diluent reduced the viscosity of bitumen about 10 times at room temperature. However, at a higher temperature (80°C), this reduction was only about four times. It is important to notice that no shear-thinning behavior is observed for bitumen upon either adding diluent or increasing temperature (for shear rates below 10 s–1). The effect of diluent vs. the effect of increasing temperature on viscosity reduction was investigated (FIG. 2). It is observed that the effect of adding 10% diluent is similar to increasing temperature from 30°C to 50°C. The viscoelastic behavior of bitumen and its blend were analyzed further by performing a temperature sweep test with the rheometer. FIG. 3 depicts elastic modulus and loss modulus vs. temperature at a cooling rate of 1°C/min. The experiment was conducted at a constant frequency of ω = 1 rad/sec, a constant amplitude of γ = 1%, and zero normal force using parallel-plate geometry. Considering the multi-phase arrangements proposed for colloidal microstructure of heavy oils and bituminous materials, it is possible to infer the existence of a structural phase transition in the temperature range below 50°C for both the bitumen and the blend.11, 12 The observed phase transition was signaled by the intensification of elastic response, while viscous behavior is still dominant for temperatures as low as 30°C. It should be noted that the increase in elastic modulus was less significant for the blend. These results are correlated with asphaltene micelles aggregation. Interpretations were proposed using small-angle X-ray scattering (SAXS) and small-angle neutron scattering (SANS) experiments.13 The aggregation process originated from Brownian motion by the so-called “reaction-limited cluster aggregation.”14 By utilizing characterization techniques like scanning electron microscopy (SEM) and atomic force microscopy (AFM), a variety of multi-phase microstructures were observed that were highly composition- and temperature-dependent.15, 16 Micron-scale heterogeneities were also detected by confocal laser-scanning microscopy (CLSM) in heavy oil and bituminous samples.17 Interestingly, the observed morphologies were comparable in shape and size with those of paraffin crystals.18 The above-men-

1

0.01

0.0001 20

Bitumen, G' Blend, G' Bitumen, G" Blend, G" 30

40

50 60 Temperature, °C

70

80

90

FIG. 3. Elastic modulus (G’) and loss modulus (G”) of bitumen and the blend. Hydrocarbon Processing | MAY 201589

Process Technology TABLE 3. Viscosity of the components and the blend (without loading bulk properties of heavy oil in simulation tool) Rheology μ, Pa.s Kerosine

30°C

50°C

Simulation tool 80°C

30°C

0.00164 0.00118 0.00081 0.00156

50°C

80°C

0.0014 0.00072

Heavy oil

510

34.96

2.09

2.307

0.4

0.076

Blend 10%

39

4.5

0.5

0.3738

0.11

0.032

TABLE 4. Viscosity of the components and the blend (using density of heavy oil in simulation tool) Rheology μ, Pa.s Kerosine

30°C

50°C

Simulation tool 80°C

30°C

50°C

80°C

0.00164 0.00118 0.00081 0.00156 0.00114 0.00072

Heavy oil

510

34.96

2.09

3.374

0.5256

0.088

Blend 10%

39

4.5

0.5

0.5135

0.1379

0.037

TABLE 5. Viscosity of the components and the blend [with loading density and viscosities at two temperatures (30°C and 80°C) of heavy oil in simulation tool] Rheology μ, Pa.s Kerosine

30°C

50°C

Simulation tool 80°C

30°C

50°C

80°C

0.00164 0.00118 0.00081 0.00156 0.00114 0.00072

Heavy oil

510

34.96

2.09

510

33

2.1

Blend 10%

39

4.5

0.5

10.28

1.73

0.2773

Although the predicted results for heavy oil are very close to the experimental values in this case, the values for the blend are still quite different, as the simulation tool underestimates the viscosity values by at least 50%. One study 2 examined the viscosity of bitumen blend with diluents and showed that Cragoe’s equation provided the best prediction of the blend viscosity compared to other methods such as mixing rule, API and Mehrotra’s methods.8 Cragoe’s equation is shown here (Eq. 2): 1 x x  D O +D + +m ln ln O ln c c c

(2)

Here, µ m , µ D and µ O are the viscosities of mixture, diluent and oil, respectively; and xD and xO are the mass fractions of diluent and oil, respectively. The viscosities obtained from Cragoe’s equation at 30°C, 50°C and 80°C are 14.3, 2.4 and 0.51 Pa.s, respectively, and this prediction is better than that seen from the simulation tool. The effect on reducing viscosity. Viscosities of bitumen

and 10 wt% blends with kerosine were measured and the results were compared with the empirical simulation data. The effect on reducing viscosity by adding 10 wt% of kerosine as a diluent into bitumen was equal to the effect obtained upon increasing temperature from 30°C to 50°C. Bitumen viscosity at lower temperatures (such as 30°C) exhibited shear-thinning behavior. At higher temperatures (such as 50°C and 80°C) or for blends containing 10% diluent, viscosity was almost Newtonian, i.e., independent of shear rate. Temperature sweep tests revealed the existence of a structural phase 90MAY 2015 | HydrocarbonProcessing.com

transition in the temperature range of 40°C–50°C for both the bitumen and the blend. Viscosities were measured at three temperatures and the results were compared with simulation viscosity results obtained by the simulation tool and viscosity from Cragoe’s model. A significant deviation between the simulation software and experimental data was observed, as the software always underestimated the viscosity of the blend by at least 50%. The simulations were improved by inputting more bitumen characteristics. If only the distillation curve is used in the simulation tool, the predicted viscosity is much lower than the experimental value. However, if other bulk properties such as density and viscosity at two temperatures are provided, in addition to distillation curve, this resulted in improved simulation predictions. LITERATURE CITED Arnold, K. E. and J. P. Koszola, “Droplet-settling vs. retention-time theories for sizing oil/water separator,” SPE, 1990, pp. 59–64. 2 Ha, H. Z. and P. Koppel, “Accurately predict viscosity of syncrude blends: An evaluation for mixing rules uncovers potential errors in fluid transportation of bitumenbased feeds,” Hydrocarbon Processing, July 2008, pp. 87–92. 3 Anhorn, J. L. and A. Badakhshan, “Heavy oil-oxygenate blends and viscosity models,” Fuel, 1994. 4 Centeno, G., G. Sanchez-Reyna, J. Ancheyta, J. A. D. Muoz and N. Cardona, “Testing various mixing rules for calculation of viscosity of petroleum blends,” Fuel, 2011. 5 Maia Filho, D. C., J. B. V. S. Ramalho, L. S. Spinelli and E. F. Lucas, “Aging of waterin-crude oil emulsions: Effect on water content, droplet size distribution, dynamic viscosity and stability,” Colloids and Surfaces A: Physicochemical Engineering Aspects, 2012, pp. 208–212. 6 Shu, W. R., R. Mobil and D. Corp, “A viscosity correlation for mixtures of heavy oil, bitumen and petroleum fractions,” SPE, 1984, pp. 277–282. 7 Mehrotra, A. K., “Development of mixing rules for predicting the viscosity of bitumen and its fractions blended with toluene,” The Canadian Journal of Chemical Engineering, 1990, pp. 839–848. 8 Mehrotra, A. K., “Modeling temperature and composition dependence for the viscosity of diluted bitumens,” Journal of Petroleum Science and Engineering, 1991, pp. 261–272. 9 Miadonye, A., N. L. Doyle, A. Britten, N. Latour and V. R. Puttagunta, “Modeling viscosity and mass fraction of bitumen-diluent mixtures,” Journal of Canadian Petroleum Technology, 2001, pp. 52–57. 10 Hasan, S. W., M. T. Ghannam and N. Esmail, “Heavy crude oil viscosity reduction and rheology for pipeline transportation,” Fuel, 2010. 11 Dwiggins, C. W., “A small-angle X-ray scattering study of the colloidal nature of petroleum,” The Journal of Physical Chemistry, 1965, pp. 3500–3506. 12 Mason, T. G. and M. Y. Lin, “Asphaltene nanoparticle aggregation in mixtures of incompatible crude oils,” Phys. Rev., E 67:1–4 050401, 2003. 13 Roux, J. N., D. Broseta and B. Demésans, “Study of asphaltene aggregation: concentration and solvent quality effects,” Langmuir, 2001, 17, pp. 5085–5092. 14 Mullins, O. C. and E. Y. Sheu, Structures and dynamics of asphaltenes, Springer, New York, 1998. 15 Masson, J. F., V. Leblond, J. Margeson and S. Bundalo-Perc, “Low-temperature bitumen stiffness and viscous paraffinic nano- and micro-domains by cryogenic AFM and PDM,” Journal of Microscopy, 2007, 227, pp. 191–202. 16 Loeber, L., O. Sutton, J. Morel, J. M. Valleton and G. Muller, “New direct observations of asphalts and asphalt binders by scanning electron microscopy and atomic force microscopy,” Journal of Microscopy, 1996, 182, pp. 32–39. 17 Bearsley, S., A. Forbes and R. G. Haverkamp, “Direct observation of the asphaltene structure in paving-grade bitumen using confocal laser-scanning microscopy,” Journal of Microscopy, 2004, 215, pp. 149–155. 18 Lu, X., M. Langton, P. Olofsson and P. Redelius, “Wax morphology in bitumen,” Journal of Materials Science, 2005, 40, pp. 1893–1900. 1

FARHAD SADEGHI, PhD, P.Eng, is a senior process engineer with Fjords Processing (formerly AkerSolutions) in Calgary, Alberta, Canada. SOHEIL SADEGHI is a PhD student at the department of chemical and petroleum engineering, University of Calgary, Alberta, Canada. UTTANDARAMAN SUNDARARAJ, PhD, P.Eng, FEC, is a professor at the department of chemical and petroleum engineering, University of Calgary, Alberta, Canada.

Process Engineering D. SMITH AND J. BURGESS, Smith & Burgess, Houston, Texas

Improve relief-device sizing under supercritical conditions

Details of sizing equations. Per API 520, if the compress-

ibility factor of the fluid is greater than 0.8, then the ideal gas ratio of specific heats may be used to determine the expansion coefficient. If the compressibility factor is less than 0.8, then the expansion coefficient should be based on the isentropic expansion coefficient. This article shows that the listed guidance can over-predict the capacity of the relief device near the critical point for light gases. The authors suggest that, when the fluid critical volume is 2 or lower, a direct integration method is required to accurately estimate relief-device capacities. If the critical volume is greater than 2 and the compressibility factor is less than 0.8, then using the nozzle equation with the isentropic expansion factor is acceptable.

Background. The accurate sizing of relief devices is very important. Operating facilities processing such fluids near the critical locus want to ensure that plant equipment is adequately protected from overpressure and that relief devices are not oversized. In general, the potential consequence for undersizing relief devices is severe, and is the focus of relevant industry codes and standards.1, 2 Relief-device sizing equations are based on a modified nozzle flow equation (e.g., Eqs. 2–7 in API 520, Part 1) and assume that the expansion of the fluid/ gas (the nozzle capacity) can be predicted by Eq. 1 (for US customary units):1 C  520 k

2 k 1

k 1 k 1

(1)

v P

P v

CP T CV

Methodology. The direct integration method (Eq. 3) to size relief devices provides the most accurate estimates of relief device capacities: 2

G 

2

P P1 vt2

v dP



 t

2

P dP P1

max

(3) max

To evaluate the effect of different relief-device capacity estimation methods, four light hydrocarbon gases were sized using the direct integration method (Eq. 3). The method is based on the nozzle equation, using both the ratio of ideal gas specific heats and the isentropic expansion coefficient to determine C (Eq. 1). The predicted capacity of a representative relief device (a 2×J×3) was then estimated for a wide range of relief temperatures (50°F–350°F) and pressures (250 psig and 2,500 psig) for relief fluids of pure ethane, ethylene and propane. In addition, mixtures having molecular weights ranging from 28–43 were also analyzed. In all cases, the fluid was a superheated vapor at the inlet to the device. 50 40

Integration Δ, % Ideal k Δ, % Isentropic Δ, %

30 20 10 0

-10

Per API 520, K is the ratio of ideal specific heats, CP /CV , if the compressibility factor, Z, of the relief fluid is greater than 0.8. If not, C should be based on the isentropic expansion factor instead (Eq. 2), API 520, Part 1 §5.6.1):1 n

However, near the critical loci, the very assumption that Eq. 1 correctly describes the expansion of the gas is potentially incorrect, and may result in invalid relief-device capacity estimates. The remaining sections of this article show an alternative method for determining if a modified nozzle equation is valid when estimating the capacity of a relief device near the critical loci.

Deviation calculated capacity vs. z, %

Properly sized relief devices under supercritical conditions are vital to processing natural gas and gas condensates into olefins. These processes operate near the critical locus of the process gases used. Relief-device sizing equations that are based on the nozzle flow equation in API 520 or ASME B&PVC Section I or VIII use the expansion of an ideal gas or a real gas.1, 2

(2)

-20 -30

-40 -50 0.40

0.50

0.60

0.70

0.80

0.90

1.00

FIG. 1. Percent deviation from direct integration in calculated capacity vs. z. Hydrocarbon Processing | MAY 201591

Process Engineering Since equations of state have known issues with predicting the physical properties needed to size relief devices near the critical loci of the fluid, all physical properties in this evaluation were calculated using the National Institute of Standards and Technology’s REFPROP property package, version 9.1. Results. The results of all the relief-device sizing estimates are shown in FIG. 1 as a function of the compressibility factor. What is noted for these light hydrocarbon gases is that using the modified nozzle equation with the expansion factor based 50 Integration Δ, %

40

Deviation vs. reduced volume, %

30 20 10 0 -10 -20 -30 -40 -50 0

2

4

6

8

10

12

FIG. 2. Percent deviation in calculated capacity vs. reduced volume.

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14

on an ideal gas (CP /CV ) or the isentropic expansion factor Eq. 2 does not accurately predict capacity. FIG. 1 shows that near a compressibility factor, Z, of 0.5, there are cases where the nozzle equation can over-predict, under-predict and accurately predict the relief-device capacity as compared to a direct integration method as predicted by Eq. 3. When the isentropic expansion factor is used in the nozzle equation, the capacity tends to either accurately predict capacity or overpredict it. When the ideal gas, K, is used in the nozzle equation, the capacity tends to either accurately predict capacity or under-predict it. If the capacity estimates are replotted vs. reduced volume, as shown in FIG. 2, a usable pattern is indicated. The capacity of relief devices with contained fluids with compressibility less than 0.8 and a reduced volume greater than 2 can be accurately predicted based on the recommendations in API 520. When the reduced volume of a fluid is below 2, the only accurate means to predict relief-device capacity is to use a direct integration method. The use of Eqs. 2–7 in API 520, Part 1 will tend to under-predict the capacity of relief devices for light gases in the fluid-condition ranges studied for this article. Charts similar to FIGS. 1 and 2 were also reviewed for reduced temperature and reduced pressure, and the resulting correlations were similar to that of compressibility (FIG. 1). Observations. The results of all the relief-device sizing estimates for the four light hydrocarbon gases show that the guidance given in API 520 may over-predict relief-device capacity. When sizing relief devices, these points should be considered: 1. At reduced volumes greater than 2, the advice in API 520 is sufficient. 2. At reduced volumes less than 2, the direct integration method should be used to size relief devices. Further guidance in API 520 is to ensure that the equations presented are applicable to the system being reviewed. To ensure the most appropriate sizing results, users should establish the limits of applicability for their own systems.1 However, from the authors’ experience, this caveat is often, if not universally, overlooked. The analysis presented here was also done for octane and pentane, starting at each fluid’s critical loci with pressure and temperature increase, and the results were identical to those for light gases. LITERATURE CITED API STD 520 Sizing, Selection and Installation of Pressuring-relieving Devices in Refineries, Part 1—Sizing and Selection, 8th Ed., December 2008. 2 American Society of Mechanical Engineers, “2007 ASME Boiler and Pressure Vessel Code,” Section VIII Division I, Appendix II. 1

AFTER

DUSTIN SMITH, PE, is the co-founder and principal consultant of Smith & Burgess LLC, a process safety consulting firm based in Houston, Texas. His experience includes both domestic and international projects. Mr. Smith is a chemical engineering graduate of Texas A&M University and a licensed professional engineer in Texas.

281-339-9993 curranintl.com • [email protected] LOCATIONS: GULF COAST US, CANADA, EUROPE, SINGAPORE AND INDIA

92

Select 172 at www.HydrocarbonProcessing.com/RS

JOHN BURGESS, PE, is the co-founder and principal consultant of Smith & Burgess LLC, a process safety consulting firm based in Houston, Texas. Mr. Burgess has BS and MS degrees in chemical engineering from both Texas Tech University and the University of Missouri. He is a licensed professional engineer in Texas.

Show Preview

IRPC HP Staff

IRPC 2015: Advancing the global HPI by sharing knowledge and best practices May 31–June 3, 2015 Jumeirah at Etihad Towers, Abu Dhabi, UAE • The sixth annual IRPC features a four-day forum focused on the downstream industry • Day 1—Full-day workshop presented by Takreer Research Centre and Borouge • Day 2—Business agenda, with keynote presentations and panel discussions on present day and future issues influencing the global and regional refining industry • Days 3 and 4—Technical agenda with over 65 technical presentations by high-level executives, technical experts and academics on the concerns impacting the operation and business planning of refineries, petrochemical plants, and gas processing and LNG facilities • Four days of networking opportunities • Organized by Gulf Publishing Company and dmg::events Middle East, the organizers of ADIPEC • Cohosted by TAKREER • Sponsors include Sandvik, Axens, KBR and Al Mazroui Group

HPIRPC.com

Leading hydrocarbon processing industry (HPI) executives and technical experts will come together May 31–June 3 in Abu Dhabi, UAE, to share ideas, innovation and vision for the global downstream industry at Hydrocarbon Processing’s sixth annual International Refining and Petrochemical Conference (IRPC). Leaders and innovation converge.

IRPC 2015 will provide a broader forum than in the past, and it is organized by Gulf Publishing Company and dmg::events Middle East, the organizers of ADIPEC, and cohosted by Abu Dhabi Oil Refining Company (TAKREER). Two additional programs have been added to the four-day IRPC 2015. First, the event begins with a full-day downstream research and innovation workshop sponsored by Takreer Research Centre and Borouge. The workshop will also include a tour of the Takreer Research Centre. Also new to the IRPC program is the business-day program developed by dmg::events. The business day includes several keynote presentations and panels addressing the pressing needs of the global petrochemical and refining industries and discussions on downstream innovations and technology developments. Representatives from the Organization of Arab Petroleum Exporting Countries (OAPEC), Equate, KBR and others will focus on industry issues that include profitability, risk aversion, workforce problems, and the integration of petrochemical and refining complexes. The technical agenda is a two-day event with over 65 technical presentations by company leaders, managers, engineers and other professionals. Continuing in 2015, the forum will feature three

technical tracks to cover the broad spectrum of HPI topics and disciplines. The tracks are refining/biofuels, petrochemicals and gas processing/LNG. The refining track will address the processing of heavy oil into clean transportation and marine fuels. Presentations will address new technologies to handle present-day crudes and improved flexibility methods in refining operations. The petrochemicals track will focus on olefins and aromatic operations and on future product and feedstock trends. The gas processing track will include presentations on gas treating, LNG commercialization and more. Other technical sessions are dedicated to energy efficiency, process optimization, corrosion mitigation/prevention methods, safety, petrochemical/refinery integration, environmental performance, advanced catalytic technologies, licensed

FIG. 1. IRPC 2015 comes to the Middle East and will be held at the Jumeirah at Etihad Towers in Abu Dhabi, UAE. Hydrocarbon Processing | MAY 201593

Show Preview: IRPC technologies for refining and petrochemicals, water management, process control, process modeling/simulation, maintenance and planning techniques, reliability programs, plant management and more. The conference will feature several keynote presentations. Giacomo Rispoli,

A truly international event

executive vice president of research and development and projects of Eni SpA, will discuss developments of Eni’s heavy oil conversion technology-EST and the future of the downstream industry. Top HPI project award luncheon. Winners of the 2014 top HPI projects, as selected by HP readers through an online survey, will be honored during a special awards luncheon. Top HPI 2014 project winners are Sadara Chemical, a JV between Saudi Aramco and Dow Chemical

IRPC is an international downstream event that is held globally to bring together industry stakeholders for discussions on high-priority topics.

IRPC CONFERENCES: Rome, Italy Singapore Milan, Italy New Delhi, India Verona, Italy Abu Dhabi, UAE TBA, Europe

2010 2011 2012 2013 2014 2015 2016

FIG. 2. HPI expansion continues in the Middle East. Photo shows ongoing construction at the Sadara Chemical Co. Photo courtesy of Sadara Chemical Co.

for top petrochemical project; Saudi Aramco and Total Refining and Petrochemical (SATORP) Co. for top refining project; and Sasol North America’s GTL project in Lake Charles, Louisiana, for top LNG/gas processing project. The engineering, procurement and construction companies for these projects will also receive awards for their participation. The SATORP, Sadara Chemical and Sasol GTL projects were selected from 12 HPI projects by an online survey conducted by HP. These projects were identified by HP readers as having the highest impact on the global and regional downstream industry. The industry’s leading edge. The HPI is a global industry; success hinges on companies and their staff finding accurate and vital information in real time to make informed and profitable decisions. At IRPC 2015, HPI professionals will have the opportunity to network and brainstorm with executives and leaders that are charting the course of the global HPI. The meeting place for the global downstream. Companies involved in

the following areas will benefit from attending IRPC: refining, natural gas processing, technology and equipment manufacturing, consulting, construction and engineering, chemicals and petrochemicals, and oil and gas services and supplies. Individuals and company officials active in the following role types will also benefit from attending IRPC: operations and supply management, business development, engineering, research and development, project management, construction and design, and more. For more information about the 2015 International Refining and Petrochemical Conference—organized by Gulf Publishing Company and dmg::events Middle East, the organizers of ADIPEC—please visit HPIRPC.com.

FIG. 3. Night view of Sohar refinery. Photo courtesy of Oman Oil Refineries and Petroleum Industries Co.

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TERMINALS AND STORAGE REPORT

SAFETY AND ENVIRONMENTAL UPDATES FOR HPI STORAGE TANKS Storage tanks are common in any hydrocarbon processing industry (HPI) facility or receiving/shipping terminal. Crude oil, refined products and petrochemicals are safely stored in aboveground tanks to facilitate daily operations of HPI facilities. These tanks hold flammable materials for processing and product distribution. The oversight and maintenance of storage tanks remains a high priority for HPI companies.

tank failures. Such events are a threat to employees, the public and property. There are a number of techniques available in the marketplace to qualitatively identify leaks. Tank entry has often been seen as the only real choice. Unfortunately, it is very difficult to detect leaks from a tank bottom in the early phase. How to effectively detect a leaking tank bottom. Leak detec-

LEAK DETECTION IN STORAGE TANKS

Storage tanks are a key part of any HPI distribution operation, according to Li-Chuan Liu of the Logistical Engineering University, China. Notably, tank-bottom plates are very vulnerable to corrosion, which compromises the integrity of the tank wall and bottom. Result: Leaks and even complete failure of the tank are linked to corrosion attacks. “Leaks and containment failures are high-risk events that impact plant safety and the environment,” said Liu. “Such events result in a direct loss of revenue. Contamination of soil and water can potentially lead to punitive action from federal and state environmental agencies.” Fires and explosions due to the accidental release of flammable materials are the main catastrophic events from storage

tion methods range from simple visual inspection to automated electronic-data gathering systems. Most continuous monitoring systems include automatic alarm capabilities. Other methods are conducted as part of regularly scheduled maintenance programs and rely on daily visual inspections. Electronic level gauges or transducers, along with temperature probes, can be used as part of a monitoring system. Other leak-detection systems rely on a wide variety of parameters, from sampling and testing the soil for hydrocarbon vapors to acoustic emissions monitoring. These technologies are performed non-invasively and have a reliable track record. Non-invasive leak detection technologies include liquid sensing cables, soil monitoring or acoustic-emissions testing. These systems can be programmed to continuously monitor a

© leungchopan—Shutterstock.com HYDROCARBON PROCESSING | MAY 2015 | TERMINALS AND STORAGE REPORT

T–97

TERMINALS AND STORAGE REPORT

© huyangshu—Shutterstock.com

TABLE 1. Key API standards that govern AST management. Std. 620: Design and construction of large, welded, low-pressure storage tanks

sults of the experiments on both models and actual tanks show that the leakage from tank bottom could be detected in time by testing and monitoring vapor in the tank foundation.”

Std. 625: Tank systems for refrigerated liquefied gas storage

API TANK STANDARDS UPDATES

Std. 650: Welded tanks for oil storage

The American Petroleum Institute (API), through its various committees, has developed standards and best practices to help downstream companies safely operate their facilities and pipelines. API standards are reviewed on a regular basis. API standards for aboveground storage tanks (ASTs) are Standards 620, 625, 650 and 653 (TABLE 1), and are developed using API procedures and standards development. The AST standards are reviewed on an 18-month basis. Changes in several AST standards took effect in 2014: API 650 was issued in September 2014 with participant in the API Monogram Program; the final release was in March 2015. For API Standards 653, 625 and 620, the revisions were issued in November 2014.

Std. 653: Tank inspection, repair, alteration and reconstruction

tank or can be part of the regularly scheduled tank testing and maintenance programs. No silver-bullet methods. There is no single leak-detection

system that is best for all sites. Each leak-detection method has unique characteristics. For example, vapor-detection devices work rapidly and are most effective in porous soils, while liquid detectors are only appropriate. Identifying the best leak-detection system depends on many factors including cost, facility configuration, groundwater depth, soil type and other variables. Although there are many methods for detecting oil leaks from storage tanks, it may not be easy to discover the leak. With the increasing capacity and size of storage tanks, the level changes from a very slow leak may be too small and not measurable by automatic or manual gauging until a substantial volume of product has been released, said Liu. Very small level changes due to oil leaking from large storage tanks can occur at an extremely low rate, thus, the leak may not be detected by gauging alone. A photo ionization detector (PID) can be used to test oil vapor concentration in a tank foundation, the sensitivity to ppm levels, which is “fine” leak detection, according to Liu. “The re-

T–98

TERMINALS AND STORAGE REPORT | MAY 2015 | HydrocarbonProcessing.com

2015 API TANKS, VALVES AND PIPING CONFERENCE & EXPO

The 2015 API Tanks, Valves and Piping Conference and Expo will be held October 12-15, 2015, at the Aria Hotel in Las Vegas, Nevada. This event will give attendees an opportunity to learn about new and existing industry codes and standards, and to hear about emerging trends from industry experts. The two-day conference offers over 65 sessions in three conference tracks, addressing the needs of individuals involved in production systems, pipelines, terminals, refining and chemical manufacturing, and storage facilities. Each day focuses on presentations relevant to upstream, midstream and downstream. For more information, visit http://www.api.org/tvp.

TERMINALS AND STORAGE REPORT

TERMINALS AND STORAGE NEWS/PRODUCTS/EVENTS CB&I TO BUILD REFINERY STORAGE TANKS FOR KUWAIT CLEAN FUELS PROJECT

CB&I has been awarded a contract valued at approximately $60 MM by JGSK, a JV between JGC Corp., GS E&C and SK E&C. The project scope includes the engineering, procurement, fabrication and construction of 39 storage tanks and two spheres for the Clean Fuel Project (CFP), a major initiative of Kuwait National Petroleum Co. (KNPC) to upgrade and expand two existing KNPC refineries. “This award underlines the confidence our clients have in CB&I’s commitment to safety, reliability and on-time solutions for complex projects,” said Luke Scorsone, president of CB&I’s fabrication services operating group. “CB&I has a long history of experience for new construction and reconstruction work in Kuwait, and our infrastructure and capabilities in the Middle East will allow us to execute the scope of work outlined for the CFP at the highest quality.” WIRELESS TECHNOLOGY ENABLES SAFER AND MORE EFFICIENT TERMINAL OPERATIONS

Honeywell’s OneWireless Terminal Solution combines a portfolio of wireless-enabled products, services and productivity tools tailored for terminal operators. The new system enables operators of oil and gas terminals to increase their productivity while also complying with stringent health, safety and environment regulations, all at significantly lower cost than wired technology. Unique in the industry, the OneWireless Terminal Solution includes Wireless ISA100 Honeywell Enraf SmartRadar FlexLine (FIG. 1), the highest-precision wireless radar gauge available. Requiring no external wireless module, the FlexLine’s integrated radio sends tank level measurements securely and wirelessly to the central control room. The FlexLine is also used as a data concentrator, collecting data from local tank instruments and sending the data wirelessly through the same ISA100 Wireless network. The OneWireless Terminal Solution includes additional applications such as Honeywell’s mobile productivity tools (Field Advisor, Mobile Station and Experion Mobile Access), aiding with the adoption of operator driven reliability (ODR) programs and enabling operators to complete activities more efficiently and safely. Other applications include wireless fixed and portable gas detectors and wireless video, including Honeywell’s Digital Video Manager to enhance plant security. For a mid-size petrochemical facility, ODR and these wireless applications can generate more than $1 MM in annual cost savings. Honeywell’s OneWireless Network enables all of these applications, which can be tailored to offer either ISA100 Wireless-only coverage or ISA100 Wireless and Wi-Fi coverage. SOFTWARE ADDRESSES API STANDARDS FOR STORAGE TANKS

Intergraph’s TANK is a comprehensive, easy-to-use software package for the design, analysis and evaluation of oil stor-

age tanks. It provides quick and accurate designs for new tanks and evaluation of existing tanks. Data collection. The menu-driven interface of TANK allows for the quick definition of input and functions for the accurate analysis of oil storage tanks to API standards. Increased flexibility allows combination of data for analyses or to desired reports. In addition, unit files are completely user-definable, so engineers are not bound by program default settings. Analysis options and codes. TANK performs calculations in accordance with the latest API Standards 650 and 653. Analysis can also take into account wind, seismic and settlement conditions, plus calculate air venting requirements to API 2000 Section 4.3. Output and reports. After completing an analysis, you can view the results in a tabular report or as a graphic diagram with associated data. For convenience in verifying the results, the output reports reference code sections used where applicable. Material databases. TANK has many databases integral to the package, which make it easy to select standard data for accurate analysis. A number of US and international structural steel databases are provided. API materials are available. EVENTS

International Liquid Terminals Association (ILTA) 35th Annual International Operating Conference and Trade Show, Jun. 1–3, George R. Brown Convention Center, Houston, Texas Phone: +1 (703) 875-2011, [email protected], www.ilta.org Active Communications International (ACI) Europe’s European Bulk Liquid Storage 2015 Conference, Sept. 9–10, Antwerp, Belgium, Phone: 44 (0) 203 141 0623, [email protected], www.acius.net

FIG. 1. Honeywell FlexLine Radar Gauge ISA100 Wireless, the latest and most technically advanced tank gauging system, custody transfer approved.

HYDROCARBON PROCESSING | MAY 2015 | TERMINALS AND STORAGE REPORT

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STORAGE SOLUTIONS YOU CAN COUNT ON As the world’s most experienced tank builder, CB&I supplies complete storage solutions to meet the needs of leading energy companies around the globe. We execute many of our storage tank projects on a lump-sum, turnkey basis, performing every phase of the project with our in-house resources and providing a single point of contact for our customers. This true EPC approach is possible because we have a vast global network of engineering, procurement, fabrication and construction resources that allow us to quickly mobilize people, material and equipment wherever they are needed. Our integrated business model translates into shorter project schedules, lower costs, improved quality control and reduced risk for the customer—allowing them to focus on their core business operations. Contact CB&I for your next storage project. ATMOSPHERIC STORAGE TANKS PRESSURE SPHERES LOW TEMPERATURE AND CRYOGENIC TANKS BULK LIQUID TERMINALS LOW TEMPERATURE AND CRYOGENIC SYSTEMS

A World of Solutions Visit www.CBI.com

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CB&I

CB&I PROVIDES SMART SOLUTIONS IN TANK CONSTRUCTION AROUND THE WORLD CB&I is the most complete energy infrastructure focused company in the world and a major provider of government services. With more than 125 years of experience and the expertise of approximately 54,000 employees, CB&I provides reliable solutions while maintaining a relentless focus on safety and an uncompromising standard of quality. CB&I combines proven process technology with global capabilities in engineering, procurement and construction to deliver comprehensive solutions to customers in the energy and natural resource industries. With premier process technology, proven EPC expertise, and unrivaled storage tank experience, CB&I executes projects from concept to completion. With over 46,000 tanks built in more than 100 countries, CB&I has accumulated more storage design and construction experience than any other organization in the world. In addition to being a leader in engineering, procurement, fabrication and construction of storage tanks, we have also designed and built more than 100 storage terminals. We have the capability to design and install pipelines for these facilities, as well as other ancillary equipment. Many customers draw upon this knowledge and extensive construction experience early in a project’s development, enabling us to provide project-specific solutions that deliver maximum long-term value, lower up-front costs, and shorter schedules. Safety is a core value at CB&I and we are proud to have one of the best safety records in the industry. As the 2014 recipient of the National Safety Council’s Green Cross for Safety® medal, every employee world-

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wide is committed to safe work practices. Our programs promote a culture of involvement and dedication with a goal of zero incidents for everyone involved in our projects.

CONTACT INFORMATION 2103 Research Forest Drive The Woodlands, TX 77380 USA Tel: +1 832 513 1000 Fax: +1 832 513 1005 [email protected] www.CBI.com

HYDROCARBON PROCESSING | MAY 2015 | TERMINALS AND STORAGE REPORT

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2015 WOMEN’S

Save the Date October 27–28, 2015 Hyatt Regency Houston Houston, Texas

Make plans to attend the 12th Women’s Global Leadership Conference in Energy (WGLC) As one of the largest women’s events in the industry, and the only one that focuses on discussing key environmental, economic and professional development issues in oil and gas, this is the perfect forum to network with your peers and exchange valuable ideas and experiences. Targeted specifically to matters of female leadership, WGLC strives to provide meaningful discussion on all aspects of responsible stewardship ranging from energy security and geopolitics to personal career development. We hope you’ll join us at WGLC 2015 and discover how you can further develop your career in the oil and gas industry.

Visit WGLConference.com for more information

Facebook/WGLNetwork

Join Women’s Global Leadership Network on LinkedIn

Follow us on Twitter @WGLNetwork #WGLC

ADRIENNE BLUME, MANAGING EDITOR [email protected]

Innovations Coatings line wins innovation award

Explosion-proof light features dimmer

Hempel’s HEMPADUR AvantGuard range of products won the 2014 European Frost & Sullivan Award for the category of new product innovation. To be presented on May 14 in London, the award recognizes the products’ ability to provide anti-corrosive protection for iron and steel structures in harsh environments (FIG. 1). The AvantGuard activated zinc primers include patented technology to provide better anti-corrosion protection. The technology uses hollow glass spheres and a proprietary activator to activate more zinc and enhance the anti-corrosive properties of the coating. The coatings can be applied with standard application techniques, and they show high tolerance to dry film thicknesses and different application conditions. The coatings have been developed to protect industrial structures and equipment in C4 and C5 corrosive conditions, where saltwater and high humidity corrode unprotected steel. They can be used in a range of industries and applications, from offshore oil and gas platforms to power plants and wind turbines. The award recognizes the products’ ability to offer reduced corrosion, improved performance in extreme temperatures and greater mechanical strength. The increased protection and durability of the AvantGuard coatings have been proven in salt spray tests (ISO 12944, part 6), cyclic corrosion tests (ISO 20340 and NORSOK M-501, Rev. 6) and thermal cycling resistance tests (NACE cracking test and Hempel’s welding test). The HEMPADUR AvantGuard series includes three zinc primers (AvantGuard 550, AvantGuard 750 and AvantGuard 770). Hempel is developing more AvantGuard technology-enabled products, including products that can be applied on components offsite and then transported for onsite installation.

Larson Electronics has released an explosion-proof, two-lamp fluorescent light fixture that is equipped with a dimmable ballast (FIG. 2). The EPL-48-2L-T8-D light is designed for areas where flammable petrochemical vapors and pulverized dust exist. The 4-ft-long fixture has a T6 temperature rating and comes standard with two T8 fluorescent lamps. The lamps are protected by heat-resistant and impact-resistant Pyrex tubes, and the fixture is constructed of copper-free aluminum alloy. The lamp reflectors are corrosion-resistant, heavy-gauge aluminum and coated with a high-gloss reflective finish. The fixture is capable of handling multiple voltages and is equipped with an Advance Mark 7 dimming ballast. The light is shipped with surface mount brackets, unless otherwise specified. Each bracket is cinched to the bracket mounting peg on each side of the light. The angle of the bracket is set by tightening two cap screws on either side of the bracket. The cap screws act as set screws.

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The bracket itself is mounted with a single bolt hole at the top of the bracket. Once the brackets are mounted to a surface, the light can be removed from the brackets by loosening the cap screws that hold the bracket to the mounting peg. The fixture provides operators in hazardous locations with a reliable lighting solution that gives explosion-proof protection without sacrificing light quality or fixture durability. Select 2 at www.HydrocarbonProcessing.com/RS

Calibrator simplifies process control A new, handheld pressure calibrator that delivers deadweight tester accuracy in an onsite instrument (FIG. 3) is offered by Crystal Engineering, a unit of AMETEK Test & Calibration Instruments. The HPC40 series calibrator is designed for process control applications, such as verification or calibration of pressure gauges, transducers, transmitters, pressure switches and safety valves. It is suitable for pressures ranging from

FIG. 1. AvantGuard coatings protect steel industrial structures and equipment from saltwater and high humidity.

FIG. 2. The explosion-proof fluorescent light fixture is equipped with a dimmable ballast.

FIG. 3. The HPC40 handheld pressure calibrator is designed for process control equipment, such as gauges, transducers, transmitters, switches and valves. Hydrocarbon Processing | MAY 2015103

Innovations vacuum to 15,000 psi, with accuracy of 0.035% of reading for all ranges. The calibrator is said to be the first mA loop calibrator that is fully temperature compensated from 20°C–50°C. This temperature compensation enables the device to deliver the same accuracy whether measuring pressure, current, voltage or temperature.

FIG. 4. The North Force hard hat has 24% more back-of-head coverage than standard Type I hard hats.

Applications for the calibrator include: • Laboratory • Power generation • Nuclear power • Automotive, and others. A single HPC40 device can typically replace several gauges or calibrators. The calibrator also features a full-color display and a single-layer user interface with no

FIG. 5. The SOLA II flare system is designed for the EPA’s new source performance standards.

UPCOMING WEBCAST: May 13, 2015

deep menu structure, allowing tasks to be performed quickly. The calibrator can be used as an individual calibrator, or it can be combined with AMETEK pressuregenerating products to make a complete calibration system. Select 3 at www.HydrocarbonProcessing.com/RS

New hard hat protects back of head Honeywell introduced the industry’s first hard hat with 24% more back-ofhead coverage (FIG. 4) than standard Type I hard hats to protect workers from potentially catastrophic head injuries due to slips and falls. The patented shell design of the North Force hard hat provides increased rearhead coverage without restricting range of motion, while a rear-impact attenuator absorbs force to minimize injuries. The hard hat is ideally suited for upstream oil workers, miners or workers in other industries where slippery or icy conditions exist. The hat is constructed of a lightweight shell material that offers high-impact re-

9 a.m. ET/ 8 a.m. CT/ 1 p.m. UTC

Challenges in Refinery Control & Optimization – User Perspective Once a plant is commissioned and stabilized, the challenge is to continuously operate the plant reliably at it’s true economic optimum. However, the economic optimum point continuously shifts due to changes in feed quality, feed prices, product specification, product value, marketing constraint and disturbances in upstream and downstream units, feed, intermediates and product storage limitations, as well as with day and night ambient changes. This requires that the operation and technical staff are as agile as possible to take advantage of any opportunity and avoid repetitive postmortem studies and retro analysis. This webinar focuses on Reliance’s approach to resolving these problems effectively.

Speaker: Fareed Khan, Vice-President, APC/RTO, Reliance As Vice-President(APC/RTO), Mr. Fareed Khan is in-charge of APCs and RTOs in all of the Refinery and Petrochemical sites of Reliance, more than 60 plants located at 6 different sites. He has been working for about 17 years in imbibing Advanced process controls (APC) and Real time Optimisation (RTO) systems in the company with the result that all APC and RTO projects today are implemented in-house for last more than 10 years. Mr. Khan has a Masters in Chemical Engineering from IIT, Kanpur and a Bachelors in Chemical Engineering from Osmania University, Hyderabad. He joined UHDE India consultancy in 1986, as process engineer doing basic and detailed engineering for petrochemicals and caustic-chlorine plants. He joined Reliance in 1992 as senior technical support engineer to new projects, after commissioning those plants in 1997, he shifted to RTOs and APCs implementations and continued working in this area till date.

Moderator: Stephany Romanow Editor Hydrocarbon Processing 104MAY 2015 | HydrocarbonProcessing.com

Register at: HydrocarbonProcessing.com/Webcasts

Innovations sistance and accommodates extreme temperature changes from –30°F to 120°F. Its patented, six-point suspension system with five adjustment areas, combined with an adjustable chin strap, allows for a customized fit. An ergonomically designed ratchet allows for quick adjustment, even while wearing gloves. The hat meets ANSI and CSA Type I Class E requirements.

tions. The system also achieves rapid recovery time, allowing it to respond within minutes to changing sulfur concentrations that occur during flare events. All flares affected by NSPS must be in compliance on or before November 17, 2015. Total sulfur measurement is a required part of NSPS compliance. Select 5 at www.HydrocarbonProcessing.com/RS

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Flare analysis for NSPS compliance Thermo Fisher Scientific has released the SOLA II flare system (FIG. 5), an online sulfur analyzer for refineries. The flare analyzer is specifically designed for the US EPA’s new source performance standards (NSPS), under subpart Ja, which apply to all flares that commence construction, modification or reconstruction after June 24, 2008. The SOLA II system is based on pulsed ultraviolet fluorescence (PUVF) technology. The technology allows the system to measure a wide range of sulfur concentra-

Measure acidic and polluted gases Pitot tubes are suitable for measuring exhaust and flue gases, since they are resistant to dirt and condensates. The choice of materials for measuring probes to monitor the combustion of chemical residues is often a difficult one. As soon as the exhaust gas falls below the dewpoint, halogens may turn surprisingly acidic. For example, a mixture of sulfuric acid, hydrochloric acid and hydrofluoric acid will soon corrode most metals and make any subsequent measurements impossible. Only a few metal alloys can be safely used under these conditions, since the

material price of these alloys hardly differs from that of precious metals, and since processing them to obtain probe components is often time-consuming and expensive. A solution developed by Systec Controls for such applications makes use of synthetic dynamic pressure probes (FIG. 6). Systec manufactures Teflon probes with reduced surface resistance for use in extremely corrosive conditions. After dosing the material with carbon, static charging (which could have fatal consequences in explosive atmospheres) can be safely avoided. Select 6 at www.HydrocarbonProcessing.com/RS

FIG. 6. The pitot tube is designed for use with explosive and acidic gases.

Introducing the US GAS PROCESSING PLANT DIRECTORY

US GAS PROCESSING

PLANT DIRECTORY

500+ Plants with Information about Name, Capacity, Plant Scope and Detail, and Owner/Operator Information. Hydrocarbon Processing and Gas Processing’s first annual US Gas Processing Plant Directory is now available. The directory provides detailed information for more than 500 gas processing plants, including natural gas processing, cryogenic and fractionation. The fully searchable directory will allow users to gain detailed information on hundreds of plants across the US. The directory will also have a detailed prologue on major trends in the US gas processing, production and construction industries. Gain the market knowledge to grow your business and inform your decisions in the booming United States gas market. Order the directory to: Benefit your planning and strategy / Locate new opportunities / Gain a competitive advantage. $1,195 per edition. Searchable, digital format. Group rates and site licenses are available.

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].

Hydrocarbon Processing | MAY 2015105

MARKETPLACE / [email protected] / +1 (972) 816-3534

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