HP_2012_07

90TH ANNIVERSARY ISSUE

HYDROCARBON PROCESSING 速

HydrocarbonProcessing.com | JULY 2012

A look at the rich history of the HPI

TIMELINE Remembering the innovations, companies and people that built the global HPI

DOWNSTREAM INNOVATIONS HPI major events and trends, 1920s to present TH

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JULY 2012 | Volume 91 Number 7 HydrocarbonProcessing.com

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D-119

SPECIAL REPORT: 90 YEARS OF PROGRESS IN THE HPI

39 Catalyst developments: The last 90 years 47 55 65 71 83 87 93

R. Heinen LNG and GTL drive 50 years of technology evolution in the gas industry J. Castel, D. Gadelle, P. Hagyard and M. Ould-Bamba A portrait of process safety: From its start to present day M. S. Mannan, A. Y. Chowdhury and O. J. Reyes-Valdes Impact of advanced engineering and design software on the HPI D. Wheeldon Process control in the HPI: A not-so-sentimental journey P. Miller, D. Hill and D. Woll Benchmark oil, gas prices poised for divorce B. DuBose The psychology of energy pricing: A look at market behavior during oil shocks A. Blume The military and the hydrocarbon: A love affair of over 100 years B. Thinnes

TOP HPI CONSTRUCTION PROJECT REVIEW

99 Qatar LNG: Mega-trains and major ambitions 103 105

DEPARTMENTS

8 13 19 23 32 156 160

Brief Impact Associations Construction Construction Boxscore Update Marketplace Advertiser index

COLUMNS

35

Reliability Rethink your auditing of lubrication practices

37

Engineering Case Histories Case 69: Heat-up rate and rubs on a steam turbine

162

Water Management Avoid failures in water projects: Part 2

A. Blume Largest ethane cracker: Borouge’s Ruwais manufacturing complex S. Romanow Largest hydrocracker in China S. Romanow

DOWNSTREAM INNOVATIONS—SUPPLEMENT

D-111 HPI major events and trends, 1920s to present TIMELINE

148 A closer look at the HPI: 1901 to present Cover Image: Borouge, a joint venture between Abu Dhabi National Oil Co. and Borealis, operates the world’s largest ethane cracker, with 1.5 million tpy of ethylene capacity, at its petrochemical production complex in Ruwais, United Arab Emirates. The original ethylene cracker and downstream polyethylene units came online in 2001. In 2010, Borouge expanded olefins processing capacity at this site with its second ethane cracker (EU2).

Construction of the third expansion project, Borouge 3, is 60% complete as of March 2012. Borouge 3 includes a third, 1.5-million-tpy ethane cracker, EU3, which is designed by The Linde Group.

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EDITORIAL Editor Reliability/Equipment Editor Process Editor Technical Editor Online Editor Associate Editor Contributing Editor Contributing Editor Contributing Editor

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

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President/CEO Vice President Vice President, Production Business Finance Manager

John Royall Ron Higgins Sheryl Stone 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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past – 1924

present – 2012 refinement redefined

clean fuel, turning “bottom of the barrel” into “top of the line.”

of other residue-upgrading technologies, turning the “bottom of the barrel” into more proven technology that processes low-quality residue streams like vacuum residue into

from every barrel.

For more information, visit www.uop.com/uniflex. © 2012 Honeywell International, Inc. All rights reserved.

| Brief Air Liquide starts up SMR in La Porte, Texas Air Liquide recently celebrated the formal startup of a new steam methane reformer (SMR) in La Porte, Texas. The 120 million scfd of gaseous hydrogen (H2 ) produced by the SMR will feed into the company’s pipeline system along the Texas Gulf Coast, including the recently built, 85-mile pipeline expansion to supply refineries in Port Arthur, Texas. The H2 will be used to convert heavy crude oil into clean-burning transportation fuels and petrochemical feedstocks.

In addition to the benefits of H2 in manufacturing cleaner gasoline, the gas increasingly is being used with fuel cells for transit buses and forklift trucks for materials handling. In April, Air Liquide announced a demonstration project for an H2 -powered fuel-cell transit bus in Birmingham, Alabama. In January 2012, the company began supplying H2 to a fleet of 37 H2 -powered fuel-cell forklifts at a leading soft drink maker’s bottling and distribution facility in California.

BILLY THINNES, TECHNICAL EDITOR / Billy.Thinnes@HydrocarbonProcessing.com

Brief Gunvor has signed a purchase agreement to acquire Petroplus’ refinery in Ingolstadt, Germany, and related

marketing activities. Gunvor said it intends to restart operations as soon as possible. That follows the refinery’s closure in early February as a result of Petroplus’ ongoing financial woes. The company said the Ingolstadt refinery has a “strong regional footprint” in Germany’s prosperous Bavaria region. It has a processing capacity of approximately 100,000 bpd. Gunvor said it is committed to operating the refinery on a long-term basis, and the more than 400 existing employees will be retained. Earlier this year, Gunvor also acquired the Petroplus refinery in Antwerp, Belgium.

Honeywell’s UOP has been selected by Haldor Topsøe to provide technology to purify hydrogen from a steam

reforming unit to be installed at the Antipinsky refinery in Tyumen, Russia. The UOP pressure swing adsorption system will recover and purify hydrogen to help the refinery meet increasing demand for clean transportation fuels, such as diesel and gasoline, the companies said. The new hydrogen unit, which is scheduled to startup in 2013, is part of the refinery’s plan to increase its capacity for crude oil processing by as much as 7 MM tpy. It will also enable the production of fuel products that meet the European Union’s Euro-5 emissions standards aimed at reducing emissions from light-duty vehicles.

Shell has confirmed that refining operations at its 79,000bpd Clyde refinery in Australia will cease on September

30. This follows an announcement in July 2011 that the refinery would be converted into a dedicated fuel terminal. According to Shell Australia Downstream Vice President Andrew Smith, “The initial decision to close and convert Clyde, taken in July last year, was consistent with Shell’s strategy to focus its refining portfolio on larger assets and to build a profitable downstream business here in Australia. Since the decision was taken, the refinery has continued to struggle against sustained poor industry margins and intense competition from mega-refineries in Asia.”

A ceremony was recently held at the Motiva refinery in Port Arthur, Texas, to celebrate the completion of a

five-year expansion project that more than doubled crude processing capacity to 600,000 bpd, making the Motiva refinery the largest in the US. With more than 14,000 employees working on the project at peak construction and more than 300 new permanent jobs, the expansion bolstered Motiva’s position as an employer and as a leading revenue source for the city, county and local public schools, the company said. The regional economic impact of the project has been estimated in excess of $17 billion.

The expanded refinery can process a wide variety of crude oils, ranging from relatively light to heavy. It also has the flexibility to switch between producing primarily gasoline and diesel to adapt to varying market conditions.

The US Environmental Protection Agency (EPA) has issued standards informed by input from stakeholders,

including industry, for new flares and process heaters at petroleum refineries. The final rule, which responds to petitions requesting the agency to reconsider standards issued in 2008, provides industry with greater compliance flexibility than did earlier standards, and it ensures that companies can make routine operational changes without triggering new requirements. These updates are expected to save the refining industry approximately $80 million per year. These reductions will also provide up to $610 million in annual health benefits. The standards will reduce emissions of sulfur dioxide, nitrogen oxides and volatile organic compounds (VOCs). VOCs react in the air to form fine particle pollution and ground-level ozone. While the revised standards do not address greenhouse gas emissions, they will reduce carbon dioxide emissions by as much as 2 million tpy as a co-benefit.

ExxonMobil said that it will expand the size of its campus under construction in Houston to accommodate

additional employees from the immediate area and from company locations in Fairfax, Virginia, and Akron, Ohio. The affected units include ExxonMobil Refining and Supply in Fairfax, which had played host to the business unit for some time. Mobil was based in Fairfax prior to its 1999 merger with Exxon. Other companies involved are ExxonMobil Research and Engineering; ExxonMobil Fuels, Lubricants and Specialties Marketing; the Akron-based employees of ExxonMobil Chemical; and select positions from ExxonMobil Research and Engineering and ExxonMobil Chemical now located at the Baytown, Texas, refinery complex.

The new campus is located on a 385-acre wooded site on company-owned land north of Houston. It will accommodate approximately 10,000 employees. Construction began in 2011, and full occupancy for employees is expected by 2015.

Neste Oil’s refinery in Naantali, Finland, is back to normal operation following the completion of a scheduled major

maintenance turnaround. The turnaround began in April and lasted about six weeks. During the turnaround, approximately 2,000 pieces of equipment were overhauled, and replacements were made for various process furnaces and other equipment.

The cost of the turnaround and related investment projects amounted to €60 million. Approximately 1,000 people took part in the turnaround, 700 of which were contracted employees.

Brenntag has acquired Petrolube, the exclusive distributor of Infineum specialty fuel and oil additives based in

Milan, Italy. For financial year 2012, the Italian company expects an EBITDA of about €800,000. The acquisition follows Brenntag’s November 2011 purchase of Multisol Group, a specialist in the distribution of lubricant additives and base oils in Europe and Africa.

Hydrocarbon Processing | JULY 2012 9

CRI’s Nickel Catalysts KL6564, KL6565, KL6515, KL6516

AROMATIC SATURATION CATALYSTS AT A GLANCE CUSTOMER DRIVERS High sulfur uptake, high activity, low hydrocarbon cracking, easy activation

SOLUTION Advanced catalysts with maximum nickel dispersion on novel carriers

History of Proven Performance In 1997, CRI acquired the catalyst manufacturing and technical expertise of KataLeuna Catalysts. With this purchase came Leuna’s extensive knowledge of nickel catalysts, which dates back to the early 1930’s. In 2001, CRI launched KL6564, an impregnated nickel catalyst. Over thirty-five catalyst charges have since been sold and operated. Today, KL6564 remains a preferred industry catalyst. In 2002, CRI launched the bulk nickel catalyst, KL6515. Over twenty charges have been installed and have exhibited superior performance.

VALUE DELIVERED Efficient use of nickel, extended cycle length, low pressure drop, reduced and passivated products

PROOF POINT Strong history of high performance nickel catalyst products in multiple aromatics saturation applications

Introduction Multiple chemical/petroleum applications require complete hydrogenation (saturation) of aromatics in the product. The catalyst of choice depends on the feed properties (sulfur concentration, poison levels, etc.), the type of aromatics (mono, di, tri, poly), the degree of saturation targeted, and the unit operating constraints. CRI offers a broad range of nickel catalysts, allowing customers to select a product which best fits their individual needs. The majority of applications make use of either an impregnated or bulk nickel catalyst in an extruded form.

Figure 1: KL6565-TL1.2 CRI’s track record of continuous catalyst improvement carries on with the development of CRI’s latest generation of impregnated nickel catalyst, KL6565 and a new high-capacity bulk nickel catalyst, KL6516.

CRI’s Nickel Catalysts KL6564, KL6565, KL6515, KL6516

AROMATIC SATURATION CATALYSTS Impregnated Nickel Catalyst

Catalyst Activation

CRI impregnated catalysts maximize nickel surface area through optimal metal dispersion as demonstrated with CRI’s KL6564.

This exemplary catalyst achieves high aromatic saturation activity with 28 wt% nickel content. The catalyst has also proven to give low hydrocarbon cracking characteristics, a desirable property, especially for lighter feeds. The new KL6565 catalyst delivers higher aromatic saturation activity with the same nickel content.

In some applications, KL6565 has demonstrated an activity gain of >50% compared to KL6564.

CRI’s nickel catalysts are offered in a reduced and passivated form, allowing for low temperature activation. In addition, the catalysts are air passivated, dramatically reducing the risk of high temperature methanation reactions during the activation process.

Bulk Nickel Catalyst Bulk nickel catalysts are designed for high activity with maximum tolerance to poisons. The most common poison in these applications is sulfur. CRI’s KL6515 exhibits up to 40% higher sulfur tolerance versus the impregnated KL6564. Since market introduction in 2002, the higher poison tolerance of KL6515 has been proven commercially in numerous applications.

Aromatic Saturation Applications Aromatic saturation applications are highly diverse, and include areas such as resin hydrogenation, benzene removal, solvent purification, and white oil production. These catalysts operate under a broad range of conditions with temperatures ranging from 100 to 300°C, and pressures from 10 to 110 bar, as well as operating in trickle phase or gas phase systems. CRI delivers aromatic saturation catalysts designed to work under this wide range of conditions.

PROOF POINT In 2002, KL6515 displaced a competitive nickel product in a high-poison application. The previous catalyst cycle was 6 to 9 months. The first charge of KL6515 lasted over two years, and subsequent charges have repeated this stellar performance. The site has been able to reduce the number of catalyst changes by > 65%

Full Line of Aromatics Catalyst Products

Figure 2: Relative Sulfur Capacities CRI’s newest bulk nickel catalyst KL6516 represents a step-out in performance by dramatically increasing poison tolerance. As shown in Figure 2, KL6516 displays a sulfur tolerance over 100% greater than KL6564.

Contact Us E-mail at: cricatalystsales@cri-criterion.com

CRI offers specialized aromatic saturation catalysts, including nickel catalysts for the production of chemical-grade cyclohexane, and precious metal catalysts for high-sulfur feeds.

In addition, CRI can offer custom catalyst solutions for customer-specific aromatic saturation goals.

Contact CRI, “Delivering Innovation” and solving your process needs.

HOW CAN CRI’S NICKEL CATALYSTS WORK FOR YOU? UÊ >À}iÊV ViÊ vÊV>Ì> ÞÃÌÃÊÌÕ i`ÊÌ ÊëiV v VÊ ii`à UÊ } ÊÃÕ vÕÀÊV>«>V ÌÞÊ> `ÊiÝÌi `i`ÊÀÕ Ê i }Ì Ã UÊ } Ê Þ`À }i >Ì Ê>VÌ Û ÌÞ

Select 65 at www.HydrocarbonProcessing.com/RS CRI Catalyst Company LP (CRICC) is a wholly owned affiliate of CRI/Criterion Inc. and an affiliate of the Shell Global Solutions network of companies. CRICC and its affiliates are dedicated to providing a broad customer base with effective and cost-efficient catalysts and technologies available in focus areas which include hydrogenation, oxidation, dehydrogenation, and environmental catalysts and systems.

The information contained in this material is intended to be general in nature and must not be relied on as specific advice in connection with any decisions you may make. CRICC is not liable for any action you may take as a result of you relying on such material or for any loss or damage suffered by you as a result of you taking this action. Furthermore, these materials do not in any way constitute an offer to provide specific products or services. Some products or services may not be available in certain countries or political subdivisions thereof.

Leaking chemicals and gases are harmful to health and the environment. I need to control fugitive emissions with a reliable control valve solution.

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The easy-e control valve uses the Fisher ENVIRO-SEAL packing system to provide the measure of emission control security that you require. Testing across a broad range of conditions demonstrates compliance with environmental standards. The easy-e valve combined with ENVIRO-SEAL packing technology controls fugitive emissions to below 100 ppmv, protecting your health and the environment. For more information visit Fisher.com/Control. ®

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The Emerson logo is a trademark and service mark of Emerson Electric Co. ©2012 Fisher Controls International LLC. D352075X012 MY73 (H:)

BILLY THINNES, TECHNICAL EDITOR / Billy.Thinnes@HydrocarbonProcessing.com

Impact A new era of energy conservation A new era of energy frugality is taking hold in the US, even as the economy slowly recovers, according to a survey from the Deloitte Center for Energy Solutions.

Businesses are forging the way by targeting average reductions in energy consumption of nearly 25% over a three- to four-year period. Consumers are also doubling down on efficiency; 83% report that they took extra steps to reduce their electric bill over the past year and 93% say they will use the same amount of electricity or less in the future.

“The recession is profoundly changing energy habits for both businesses and consumers,” said Greg Aliff, one of the survey’s authors and a vice chairman in the energy and resources sector at Deloitte. “Using less may be the new normal, from boardroom tables to the kitchen tables.”

The annual survey, “reSources 2012,” found that nine out of 10 companies have set goals regarding electricity usage and energy management practices, with 66% identifying cost-cutting as their primary motivation.

Moreover, the survey indicates that 85% of businesses view reducing electricity costs as essential to staying financially competitive, a 9% jump from 2011. In addition, 81% view reducing electricity costs as essential to their image, 11 percentage points over last year.

Marlene Motyka, a US alternative energy leader at Deloitte, says new energy goals are not just corporate window dressing; they are linked to the bottom line. “Companies are making significant energy-efficiency progress, reporting that they have achieved about 60% of their targets for energy savings when it comes to electricity, natural gas, carbon footprint and transport fleets,” she said.

It is going to get tougher, though, noted Ms. Motyka. “Well over half [62%] of companies report that their energy management goals were somewhat difficult

to achieve. Moreover, 21% say their energy management goals were very or extremely difficult to achieve compared to 13% in the 2011 survey. The low-hanging fruit may have already been picked when it comes to energy efficiency.”

Seeking energy reduction. Nearly 61% of consumers believe that going through the recession has ultimately been good because it makes them more efficient and reminds them what is important. In contrast, last year, only 49% of respondents felt that way.

Here are some additional interesting findings from the survey: • Consumers see turning off the lights (cited by 56% of respondents), shutting down electronics when they are not in use (48%), and adjusting thermostats by a few degrees (41%) as among the top five most important actions they could do to save electricity in the future • 35% of respondents saw replacing old appliances with new, more energy efficient ones as among the top five actions they could take • 20% cited using a “smart” power strip that senses when appliances are off and cuts “phantom” energy use.

New technologies are helping businesses and individuals make smarter choices, according to Dr. Joseph Stanislaw, an independent senior advisor to Deloitte LLP. “Now they can proactively manage their energy consumption and carbon footprints with smart meters, smart appliances and demand management programs,” Stanislaw said.

E15 ethanol fuel can damage auto engines

Auto repair costs for consumers could rise due to adverse effects of fuel containing 15% ethanol blends (E15), according to new results from a two-year study on engine durability.

The study was conducted by FEV, a longtime consultant to the US Environmental Protection Agency, on behalf of the Coordinating Research Council (CRC).

The CRC study showed adverse results from E15 use in certain popular, high-volume models of cars (TABLE 1), its authors said.

Problems included damaged valves and valve seats, which can lead to loss of compression and power; diminished vehicle performance; misfires; engine damage; poor fuel economy and increased emissions.

“Clearly, many vehicles on the road today are at risk of harm from E15. The unknowns concern us greatly, since only a fraction of vehicles have been tested to determine their tolerance to E15,” said Mitch Bainwol, CEO of the Auto Alliance trade group.

“Automakers did not build these vehicles to handle the more corrosive E15 fuel. That’s why we urged EPA to wait for the results of further testing.”

The potential costs to consumers are significant, the study says. The most likely repair would be cylinder head replacement, which costs from $2,000-$4,000 for single cylinder head engines and twice as much for V-type engines.

“Our goal is to ensure that new alternative fuels are not placed into retail TABLE 1. Vehicles and designs selected for E15 ethanol fuel study.

1996

Toyota Camry 2.2L

1998

Honda Accord 3.0L V6

2000

Jeep Grand Cherokee 4.0L

2001

Chevrolet Cavalier 2.2L

2001

Toyota Tacoma 2.4L

2002

Mitsubishi Galant 2.4L

2002

Toyota Camry 2.4L

2003

Hyundai Elantra 2.0L

2003

Nissan Maxima 3.5L

2004

Ford Focus 2.0L

2004

Ford Focus 2.3L PZEV

2004

Ford Ranger 3.0L

2005

Dodge Neon 2.0L

2007

Nissan Altima 2.5L (non-PZEV)

2009

Honda Accord 2.4L Hydrocarbon Processing | JULY 2012 13

Impact until it has been proven they are safe and do not cause harm to vehicles, consumers or the environment,” said Mike Stanton, CEO of the Global Automakers trade group. “The EPA should have waited until all the studies on the potential impacts of E15 on the current fleet were completed.”

“Automakers believe that renewable fuels are an important component of our national energy security, but it is not in

the longer term interest of the government, vehicle manufacturers, fuel distributors or the ethanol industry itself to find out after the fact that equipment or performance problems are occurring from rushing a new fuel into the national marketplace,” added Bainwol.

Growth Energy, an ethanol industry trade group, petitioned the EPA in March 2009 to raise the limit on ethanol in gasoline from 10% to 15%.

In June 2008, EPA outlined testing needed for the agency to approve a waiver, and EPA requirements were consistent with test plans developed by the auto and oil industries.

The CRC, composed of engineers from the auto and oil industries, was working with EPA and US Department of Energy (DOE) on a multi-year suite of tests on the effects of higher blends of ethanol, according to the trade groups.

This testing included more than $14.5 million of research sponsored by the auto and oil industries, and $40 million of testing sponsored by the federal government.

Before those tests were completed—in October 2010 and January 2011—the EPA granted “partial” waivers to allow the introduction of E15 into the marketplace for use in model year 2001 and later vehicles.

EPA’s decision was based largely on a DOE study of the effects of E15 on durability of catalytic converters, the primary pollution control system in a vehicle EPA did not undertake or wait to consider the results of this engine durability test, or for other E15 related research still underway, the groups allege.

The CRC study took duplicates of eight different vehicle model engines spanning the 2001–2009 model years. All 16 vehicles were tested over a 500-hour durability cycle corresponding to about 100,000 miles of vehicle usage, the authors said.

A range of engine operating parameters was monitored during the test, including cylinder compression, valve wear, valve leakage, emissions and emissions control system diagnostics.

Two of the engines tested on E15 were said to have mechanical damage. Another engine showed increased tailpipe emissions beyond the allowable limit.

Interventions avert pipeline shutdowns, enhance safety T.D. Williamson (TDW) recently performed its first pipeline interventions in Belgium. The interventions made it possible for two nitrogen pipelines located in the Albert I Canal in Antwerp to be relocated without shutting them down. This meant that product was able to flow without disruption.

TDW carried out the operations for a company on behalf of the Flemish Government in conjunction with its Antwerp 14

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Impact Masterplan, a major initiative designed to ease traffic congestion on the Antwerp Ring Road. To achieve this, part of its strategy is to divert container traffic from the roads to a central container terminal in Limburg on the Albert I Canal. There, container traffic will board transport ships and travel on the canal, alleviating road congestion. To address the traffic jams on the Ring Road and the bottlenecks on the canal, work has begun on the first of 57 new bridges that offer higher clearance for passing ships. By installing new bridges, ships will be allowed four stories of storage and, therefore, much greater capacity.

To prepare for installing the new bridges, all pipelines located in close proximity to the existing bridges must be relocated. TDW was retained to provide train intervention services to ensure that product flow would continue through two industrial gas pipelines near the Bridge Geel-Oevel and the Bridge Grobbendonk while they were relocated.

The plugging system relies upon plugging technology to temporarily block sections of active piping systems. It links two plugging heads to form a “train” that provides a double block and bleed function.

Traditionally, other methods have been used to achieve double block and bleed, including the use of two separate valves with a bleed port between them. This system is a double-block and bleed design that makes it possible to insert two plugging heads through a single fitting. The method allows a technician to install two barrier surfaces (FIG. 1), including a bleed port for pressure and product evacuation, between work (such as welding or pipe cutting) being performed downstream of the line’s pressurized contents.

With support from the company’s facility in Herentals, Belgium, TDW

technicians carried out the intervention operations on the two pipelines near the Bridge Geel-Oevel and the Bridge Grobbendonk. Technicians used a standard 660 tapping machine to hot tap the line, and one six-inch single position doubleblock and bleed plugging system to plug the lines. Each line was isolated, creating a secure environment for relocation of the pipeline, as required for installation of the new bridges. The operations were execut-

ed by two teams of two technicians, and were carried out simultaneously over the course of five working days. At no time was service interrupted.

Over time, this system has been used successfully for customers seeking to carry out routine maintenance and emergency repair work on pressurized piping systems located subsea, in remote onshore environments and in refineries and processing plants.

BORSIG 1837-2012 175 Years of Leading Technology for a Changing World -

Waste Heat Recovery Systems and Transfer Line Exchangers

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Reciprocating and Centrifugal Compressors

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Membrane Technology

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Fired Boilers (up to 420 t/h) and Power Plant Engineering

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Services

BORSIG GmbH FIG. 1. The technicians from T.D. Williamson, hard at work on a pipeline intervention in Antwerp, Belgium.

Egellsstr. 21, 13507 Berlin, Germany Phone: +49 (0)30 / 4301-01, Fax: +49 (0)30 / 4301-2236 E-Mail: info@borsig.de

www.borsig.de

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Impact The way we were: Impact in 1974 Hydrocarbon Processing has covered refining events large and small in its storied

16 JULY 2012 | HydrocarbonProcessing.com

history. To provide an illustration of “the more things change, the more they stay the same,” have a look at the HPImpact section from November 1974. Back in 1974, people were talking about oil shale.

Liquefied natural gas pipelines were being discussed. Controversy raged about offshore drilling. Fuel oil deliveries were declining in Europe. Kind of sounds like the news of today, doesn’t it?

Impact

Hydrocarbon Processing | JULY 2012 17

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BEN DuBOSE, ONLINE EDITOR Ben.DuBose@HydrocarbonProcessing.com

Associations

HPI mulls technical innovations at IRPC in Milan, Italy The third annual International Refining and Petrochemical Conference (IRPC) opened its doors in mid-June, bringing record crowds to Milan, Italy, as leading downstream players shared and debated new hydrocarbon processing industry (HPI) technologies.

The event attracted more than 500 attendees, 40 presentations, and at least 40 sponsors and exhibitors—setting a new high in all three categories.

“It went very well,” said John Royall, CEO of Gulf Publishing Company, which organized the conference alongside Italian host eni (FIG. 1).

“We launched this event two years ago in Rome [before moving to Singapore in 2011],” Mr. Royall added. “The idea was that we would put together the number one technical forum in the world for professionals in the downstream industry.

“This year’s program was the best we’ve ever put together, and with that we drew teams from around the world,” (FIG. 2).

FIG. 1. Italian energy major eni hosted IRPC and had a busy booth on the exhibit floor.

Eni refinery project opens for tour.

IRPC events began with a June 12 tour of eni’s nearby Sannazzaro de’ Burgondi refinery, where the company’s EST (eni slurry technology) project is near completion.

“I think the cherry on the cake was the first day when we visited eni,” said Dr. Raushan G. Telyashev, general director at Russia’s LUKOIL. “That was impressive.”

The proprietary EST technology allows for the conversion of heavy oil residues in fine products, gasoline and gasoil.

The process converts waste oil, heavy crude and tar sands into high-quality and performance fuels.

“That was very, very well received because it is a groundbreaking technology that creates a lot of efficiencies and costsavings for refiners,” said Mr. Royall.

“A lot of these refiners around the world found it to be a very exciting day seeing this new technology put into place by eni.”

FIG. 2. Conference attendees mingled at IRPC’s opening reception on Wednesday, June 13.

FIG. 3. Italy’s Walter Tosto was among many with popular exhibition booths.

Hydrocarbon Processing | JULY 2012 19

Associations

FIG. 4. Dr. Giacomo Rispoli, an executive vice president with eni, delivered IRPC’s keynote address on Wednesday, June 13.

Heavy oil talk leads presentations.

The conference moved to the Mico – Milano Congressi, the largest convention center in Europe, for two days of presentations and exhibits (FIG. 3) on June 13 and 14.

Roughly half of IRPC presentations were focused on heavy oil conversion, with industry heavyweights such as eni vice president Dr. Giacomo Rispoli (FIG. 4) imploring slurry technology innovations from European refiners.

“Refining is considered a technologically mature sector,” said Dr. Rispoli.

“The last significant development was in the 1960s with modern hydrocracking.

The industry desperately needs a technology breakthrough.”

Meanwhile, other talks centered on issues like distillate yields.

Buoyed by rising transportation fuels demand, Indian Oil executive director A.S. Basu said multiple upgrader projects will allow his company to raise distillate yields to 79 percent by 2016 and 84 percent within a few more years, up from 72 percent in 2005 and 76 percent in 2012.

Other relevant subjects discussed included hydrogen management, environment and safety issues, energy efficiency, and European economic concerns.

“We really liked the event,” said Dr. Telyashev, who traveled with several LUKOIL officials. “It was very well planned.

“The presentations were very useful,” he continued. “We liked that there were a wide variety of reports and companies— some who were licensing technologies and others who run the refineries.

Site of

production

“It was very good knowledge of new technologies in detail, not just observations.”

Companies represented among the speakers and exhibitors included eni, Indian Oil, Foster Wheeler, Criterion, Chevron Research, KBR, Walter Tosto, Ivanhoe Energy, Chevron Lummus Global, CB&I, Shell Global Solutions, ABB, Saudi Aramco and many others.

Delegates, meanwhile, were registered from locations including Libya, Saudi Arabia, Abu Dhabi, Russia, India, Europe and the US. Future of IRPC. The 2013 version of IRPC will be held in New Delhi, India, event organizers confirmed following the Milan conference.

Specific site and host details have yet to be finalized, according to Mr. Royall.

However, the event is certain to head to India for the first time, he said.

For more coverage of IRPC 2012, visit the HPInformer blog at www.hydrocarbonprocessing.com/HPInformer.

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www.careers.total.com More than 600 job openings are now on line!

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action loves reaction Chemical reactions require chemical catalysts. As the global leader in chemical catalysts, BASF acts through continuous product and process innovations in collaborative partnerships with our customers. The result is a broad chemical catalyst portfolio backed by dedicated customer and technical service and enabled through the strength of BASF - The Chemical Company.

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Adsorbents Fine Chemical Catalysts Environmental Catalysts Catalysts for Fuel Cells Catalysts for Oleochemicals & Other Biorenewables Oxidation & Dehydrogenation Catalysts Petrochemical Catalysts Polyolefin Catalysts Refining Catalysts Syngas Catalysts Custom Catalysts

See our Downstream Innovations proďŹ le on page D-138 of this issue.

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HELEN MECHE, ASSOCIATE EDITOR Helen.Meche@HydrocarbonProcessing.com

Construction North America Air Liquide Large Industries U.S. LP has started up a new steam methane reformer (SMR) in La Porte, Texas, just east of Houston. The 120 million scfd of gaseous hydrogen produced by the SMR will feed into the company’s pipeline system along the Texas Gulf Coast, including the recently built 85-mile pipeline expansion to supply refineries in Port Arthur, Texas. Hydrogen is used in the oil refining process to convert heavy crude oil into clean-burning transportation fuels and petrochemical feedstocks.

GDF SUEZ has signed a commercial development agreement with Cameron LNG, a unit of Sempra Energy, regarding the natural gas liquefaction project of Cameron LNG. This facility will be located at the site of its existing import terminal in Hackberry, Louisiana. Through this commercial development agreement, GDF SUEZ and Sempra will negotiate a 20-year liquefaction service contract for 4 million tpy of liquefied natural gas (LNG).

The LNG plant will have three liquefaction trains with a production and export capacity of 12 million tpy and will be operated by Cameron LNG. The plant is expected to start full operations in late 2016.

Shell, Korea Gas Corp. (KOGAS), Mitsubishi Corp. and PetroChina Co., Ltd. are developing a proposed liquefied natural gas (LNG) export facility, near Kitimat, British Columbia, Canada.

Shell holds a 40% interest in the LNG Canada project, with KOGAS, Mitsubishi and PetroChina each holding a 20% interest. The proposed project includes the design, construction and operation of a gas liquefaction plant and facilities for the storage and export of LNG, including marine off-loading facilities and shipping.

LNG Canada will initially have two LNG processing units, or “trains,” each with the capacity to produce 6 million tpy of LNG, with an option to expand the project in the future.

The partners will decide whether to move ahead with the project’s development after conducting engineering work and environmental assessments, as well as consultations with local communities and other stakeholders. Startup could come around the end of the decade, assuming all necessary regulatory approvals and investment decisions.

The Shaw Group Inc. has an agreement with Chevron Phillips Chemical Co. LP to proceed with front-end engineering design (FEED) for a 1.5 million metric-tpy (3.3 billion lb/yr) grassroots ethylene plant. The scope of work, which will be released in phases, follows Shaw’s previous award of a contract to license its proprietary technology and provide a process design package for the project. The plant will be located at Chevron Phillips Chemical’s Cedar Bayou Plant in Baytown, Texas.

Nalco, an Ecolab company, plans to construct a dry polymer production facility at the company’s complex in Garyville, Louisiana. The 300,000 sq-ft facility will produce dry polymer products for use in removing contaminants from wastewater.

When completed late this year, the dry polymer plant will increase facility space at the Garyville complex to 1 million sq ft and add 22 full-time positions to the company’s current Garyville workforce of 235 employees.

In addition to the 22 full-time positions necessary to operate the new dry polymer facility, it will take approximately 350,000 man-hours to complete the project, the equivalent of 167 full-time construction jobs. Construction of the facility is expected to be completed in December 2012.

Eastman Chemical Co. has completed the retrofit and startup of its non-phthalate plasticizer manufacturing facility in Texas City, Texas. Eastman purchased the former Sterling Chemicals, Inc. plant in mid-2011. The facil-

ity, which will primarily produce Eastman 168 non-phthalate plasticizer, will increase the overall capacity of Eastman 168 by approximately 60%. Further capacity increases are possible with minimal investment at the Texas City site as demand for non-phthalate plasticizers continues to grow.

The Shaw Group Inc. has been awarded a contract to provide its proprietary technology and engineering services for a new Ultra Selective Conversion (USC) furnace for Eastman Chemical Co.’s ethylene plant in Longview, Texas. Shaw will procure the equipment for the furnace.

Excelerate Energy L.P. is developing what is said to be the first floating liquefaction facility in the US, using its Floating Liquefaction Storage Offloading (FLSO) vessel technology. The Lavaca Bay LNG project will be located in Port Lavaca, situated between Galveston and Corpus Christi on the Texas Gulf Coast, and will be designed to export liquefied natural gas (LNG) to markets worldwide by 2017.

Excelerate Energy’s FLSO vessel comprises 3 million tpy of production capacity, 250,000 m3 of LNG storage, and a fully integrated gas-processing plant. With this gas-processing capability, the FLSO vesTREND ANALYSIS FORECASTING Hydrocarbon Processing maintains an extensive database of historical HPI project information.

The Construction Boxscore Database is a 45-year compilation of projects by type, operating company, licensor, engineering/constructor, location, etc. Many companies use the historical data for trending or sales forecasting. The historical information is available in commadelimited or Excel® and can be custom sorted to suit your needs. The cost depends on the size and complexity of the sort requested. You can focus on a narrow request, such as the history of a particular type of project, or you can obtain the entire 45-year Boxscore database or portions thereof. Simply send a clear description of the data needed and receive a prompt cost quotation.

Contact Lee Nichols at 713-525-4626 or Lee.Nichols@GulfPub.com

Hydrocarbon Processing | JULY 2012 23

Construction sel can accommodate a wide range of gas compositions at its inlet, making it well suited for virtually any application near shore or offshore. For those situations where gas processing is not required due to the presence of existing processing facilities or where pipeline-quality gas is used as the feedstock, the processing equipment can be removed and liquefaction capacity increased to 4 million tpy.

Front-end engineering and design (FEED) is in an advanced phase and Excelerate is now entering into discussions with potential off takers and natural gas suppliers, as well as investors and potential sources of finance to take the project forward. Excelerate Energy expects FEED to last until the end of 2012, and, following its completion and successful permitting, project delivery will take approximately 44 months from final investment decision.

In its initial phase, the Lavaca Bay LNG project will consist of one permanently moored FLSO vessel with multiple connections to the onshore natural gas grid in South Texas. The project will

be designed with the potential for expansion and the addition of a second FLSO vessel over time for a total production capacity of up to 8 million tpy. Excelerate Energy expects to begin the export authorization and Federal Energy Regulatory Commission (FERC) permitting immediately, and is in the process of completing its site-specific final FEED effort.

Two polyethylene facilities, planned as part of the Chevron Phillips Chemical Co. LP’s US Gulf Coast (USGC) Petrochemicals Project, will be located on a site near the Chevron Phillips Chemical Sweeny facility in Old Ocean, Texas.

The two new polyethylene facilities will each have a capacity of 500,000 metric tpy and will use Chevron Phillips Chemical’s proprietary Loop Slurry Technology.

The company has also executed a frontend engineering and design (FEED) agreement with Jacobs Engineering Group, Inc., to design the polyethylene facilities. Additionally, the company has also executed a FEED agreement with Shaw Energy & Chemicals to design the

previously announced 1.5 million-metric tpy ethane cracker that would be located at Chevron Phillips Chemical’s existing Cedar Bayou facility in Baytown, Texas.

The estimated completion date for the USGC Petrochemicals Project is 2017.

Middle East

Alfa Laval has won an order from a Korean engineering company to supply heat exchangers for a natural gas project in Saudi Arabia. The order value is approximately SEK 80 million, and delivery is scheduled for 2013.

The Alfa Laval heat exchangers will be used in a new major gas-processing facility in Saudi Arabia, where they will be recovering energy in the gas-cleaning process, bringing down power consumption and CO2 emissions.

Siemens has taken the next step toward a massive expansion of its activities in Saudi Arabia, breaking ground on a landmark manufacturing facility for gas turbines and compressors. Planned for completion in late 2013, the center will

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Imagine no crude oil demulsifiers or corrosion inhibitors.

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Notable Baker Hughes Industry Firsts

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In 1914 William S. Barnickel patented our industry’s first crude oil demulsifier. In the decades since, other Baker Hughes chemists and scientists continued to © 2012 Baker Hughes Incorporated. All Rights Reserved. 36257

develop new solutions—enabling refiners to process any crude feedstock. We were also the first to use chemical

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See our Downstream Innovations profile on page D-140 of this issue.

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Construction create job opportunities for young Saudis, serving as a knowledge transfer hub for new Siemens technology and supporting the country’s industrialization drive.

The power equipment manufactured at the plant will be supplied to the local Saudi market, where energy requirements are strongly increasing. Siemens and its local partner, E.A. Juffali & Brothers, will jointly invest a US dollar figure in the hundreds of millions in the facility, which

will be constructed on a 220,000-m2 site in Dammam in the Kingdom’s Eastern Region. The manufacturing facility is reportedly the first of its kind for Siemens in the Middle East.

EQUATE Petrochemical Co. and Schmidt + Clemens Group (S+C) have signed a strategic cooperation agreement relevant to enhancing and optimizing production performance of ethylene crackers.

EQUATE’s procurement leader, Ahmad Al-Saleh, said, “As EQUATE owned and managed ethylene production capacities reach 1.8 million metric tpy, this strategic accord leverages a decade-long business relationship with S+C to implement solutions, best practices and latest technologies in operational and life-cycle optimization of ethylene crackers radiant coils.”

Established in 1995, EQUATE is an international joint venture between Petrochemical Industries Co., The Dow Chemical Co., Boubyan Petrochemical Co. and Qurain Petrochemical Industries Co. Commencing production in 1997, EQUATE is the single operator of a fully integrated world-scale manufacturing facility producing over 5 million tpy of high-quality petrochemical products that are marketed throughout the Middle East, Asia, Africa and Europe.

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Because each project is unique and highest quality design is paramount to success we offer a unique portfolio of proprietary gas treatment technologies licensed by Prosernat. Backed by our strong investment and partnerships in R&D, with IFP Energies nouvelles and Total, we are proud to bring to the market the most advanced technologies in the following areas: Natural Gas Sweetening, Natural Gas Dehydration, Sulfur Recovery, Hydrocarbon Dewpointing, Separation and CO2 Capture from Flue Gases.

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A groundbreaking ceremony has taken place for Evonik’s new hydrogen peroxide (H2O2 ) plant in China. The plant is scheduled to go online, with a production capacity of 230,000 metric tpy, at the end of 2013.

Evonik Industries founded Evonik Specialty Chemicals (Jilin) Co., Ltd. (ESCJ) to run the new production facility. Evonik will supply its H2O2 from Jilin directly to the adjacent propylene oxide plant run by Jishen Chemical Industry Co., Ltd., via a pipeline that will link the two facilities. A long-term supply agreement is in place between these companies.

Jishen will use the so-called HPPO process to make propylene oxide from the hydrogen peroxide. Propylene oxide is used chiefly in the manufacturing of polyurethane intermediates. The HPPO process was developed by Evonik in collaboration with ThyssenKrupp Uhde GmbH. Malaysia’s largest refinery and petrochemical venture, the PETRONAS Refinery And Petrochemical Integrated Development (RAPID) project, has been launched. It reportedly has the potential of turning Southern Johor into the country’s new petroleum and petrochemical hub.

With a capacity to refine 300,000 bpd of imported crude oil, RAPID’s proposed refinery will act as the backbone of the project, which will supply feedstock for the petrochemical complex. It will also produce a host of refined petro-

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Construction leum products, including gasoline and diesel that meet the Euro 4 and Euro 5 fuel specifications.

To support RAPID’s development, PETRONAS is also assessing the feasibility of developing a new liquefied natural gas (LNG) receiving and re-gasification terminal, as well as a co-generation power plant.

RAPID’s project implementation is expected to commence by mid 2013, after PETRONAS reaches its final investment decision.

AEG Power Solutions’ Chinese subsidiary has signed a contract with SINOPEC Luoyang Petrochemical Engineering Co. (LPEC) to provide all power supply equipment for the Atyrau refinery they are building in Kazakhstan.

AEG PS will provide the backup system, integrating 44 new modular UPS Protect 8 systems, as well as Protect RCS industrial chargers.

The Protect 8 series, which represents the main part of this contract, includes heavy-duty, double-conversion, singlephase and three-phase AC output, indus-

trial UPS system and stand-alone singlephase and three-phase DC/AC inverters as standard issue.

UOP LLC, a Honeywell company, has been selected by Sinochem to provide technology to purify hydrogen at a new refinery in China.

Sinochem Quanzhou Petrochemical Co. Ltd. will use two Honeywell UOP Polybed Pressure Swing Adsorption (PSA) systems to produce highpurity hydrogen at its new refinery. The hydrogen will be used to produce clean transportation fuels, including diesel, gasoline and jet fuel, in the new 12 million-tpy refinery.

Two Polybed PSA systems will process hydrogen from different streams throughout the facility. The system processing feed from a steam reformer will produce 140,000 Nm3/h of hydrogen, and the system processing refinery offgas will produce 110,000 Nm3/h of hydrogen. The facility, located in Quanzhou City, Fujian Province, China, is expected to start up in 2013.

Shareholders of Refining NZ have voted for a $365 million expansion of gasoline-making facilities at the Marsden Point refinery in New Zealand. The vote at the company’s annual meeting—required because the total cost of the investment was more than half the company’s market value—saw 64.5% of shareholders vote in favor of the proposed CCR Project. “Refining NZ is a world-class refinery with a clear vision and a talented group of people to ensure this expansion goes to plan and is up and running by 2015,” said Ken Rivers, Refining NZ chief executive.

Fluor Corp. has been selected by Reliance Industries Ltd. (RIL) to perform project management services for its projects to be executed at its world-scale Jamnagar Refining and Petrochemical Complex in Gujarat, India. In addition to assisting RIL in project management, Fluor will also perform engineering and procurement services for the pet-coke gasification project.

RIL’s investment in the expansion of energy and petrochemicals projects is

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Construction said to represent one of the largest such investments globally. The proposed coke gasification facility is also among the largest such projects ever built.

The scope of the project management services to be provided by Fluor includes several world-scale units including petroleum coke gasification units, refinery offgas cracker and downstream petrochemical plants, a captive power plant, as well as associated utilities and offsites.

The completed gasification project will gasify petroleum coke to produce fuel and hydrogen for the expanded refinery and petrochemical complexes and captive power plant, as well as feedstock for future chemicals production.

Petronet LNG Ltd. (PLL) and Gangavaram Port Ltd. (GPL) have signed a firm and binding term sheet for developing a land-based liquefied natural gas (LNG) terminal at Gangavaram Port, Andhra Pradesh, India, with a capacity of 5 million metric tpy.

The LNG terminal will include facilities for receiving, storage and regasifica-

30 JULY 2012 | HydrocarbonProcessing.com

tion of LNG, and will be developed with an approximate investment of Rs 4500 Crores. This will be PLL’s third LNG terminal, the other two being an operational 10 million-metric tpy terminal at Dahej, Gujarat, and a 5 million-metric tpy terminal at Kochi, Kerela, which is expected to be operational in the next six months. The terminal at Gangavaram Port will have the provision for further expansion similar to PLL’s flagship Dahej LNG terminal.

Construction work on the terminal is expected to start within a year, and it will be ready to commence operations by 2016.

Woodside is now producing liquefied natural gas (LNG) from its Pluto LNG Project near Karratha in Western Australia, and will soon be loading its first cargo aboard the Woodside Donaldson LNG tanker.

The initial phase of the project comprises an offshore platform in 85 m of water, connected to five subsea wells on the Pluto gas field. Gas is piped through a 180-km trunkline to the onshore facilities that include an LNG processing train

Select 158 at www.HydrocarbonProcessing.com/RS

with a forecasted production capacity of 4.3 million tpy.

Pluto LNG Project joint-venture participants are Woodside Burrup Pty Ltd. (90% and operator), Tokyo Gas Pluto Pty Ltd. (5%) and Kansai Electric Power Australia Pty Ltd. (5%).

Jacobs Engineering Group Inc. has been awarded a contract from Evonik Industries AG to provide basic engineering services for an investment in a grassroots polyamide 12 production facility in Asia.

Jacobs has been working closely with Evonik’s project team in Marl, Germany, to develop the conceptual design for the new plant, which is based on Evonik’s existing plants in Germany. Members of the integrated project team are operating from Jacobs’ office in Leiden, The Netherlands, to undertake the front-end engineering design work, supported by Jacobs’ office in Mumbai, India.

Under a separate framework contract, Jacobs is providing engineering services as the Owner’s Engineer on Evonik’s process industry projects worldwide.

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CONSTRUCTION BOXSCORE UPDATE / ConstructionBoxscore.com COMPANY

CITY

PROJECT

EX CAPACITY UNIT

Naftec Spa PetroSA PetroSA

Skikda Coega Port Elizabeth

BTX Refinery Refinery

RE

Chevron Australia Pty Ltd Inpex/Total E&P JV Shandong Chambroad Petrochemical Evonik Industries AG FSRC Risun Chemical Co Nagarjuna Oil Corp Ltd Reliance Industries Ltd New Zealand Rfg Co ExxonMobil

Ashburton Darwin Binzhou Jilin Ningbo Tangshan Cuddalore Jamnagar Whangarei Napa Napa

LNG (2) LNG Isobutylene Polyamide Butyl Rubber, Halo Epichlorohydrin Refinery Refinery (1) CCR LNG

UPM Lanxess Dow Chemical SNAM Rete Gas KPI Karachaganak Petroleum

Lappeenranta Krefeld-Uerdingen Stade Sulmona Atyrau Karachaganak

Biorefinery Formalin Cogeneration Gas Compression Dehydrogenation, Propane Gas Processing (3)

COST STATUS YR CMPL LICENSOR

ENGINEERING

CONSTRUCTOR

AFRICA Algeria Repub S Africa Repub S Africa

None 400 Mbpd 400 Mbpd

10500 11000

C F F

2012 2016 2015

15 Mm-tpy 29 8 MMtpy 3400 87 m-t None 100000 Mtpy 430 100000 m-tpy 15 MMmtpy 258 None 1000 None 346 9 Tcf 9500

U U U F E U U P U U

2016 2015 2014 2014 2013 2016 2014 2015 2014

E C U E P F

2014 2012 2013 2015 2014 2022

S P

2015 2018

F U P F

2013 2015

GTC, Inc

GTC, Inc KBR | SEI KBR | KBC | SEI

ASIA/PACIFIC Australia Australia China China China China India India New Zealand Papua New Guinea

BY EX EX

Conser Conser UOP

Bechtel Wood Group Chiyoda | JGC Corp | KBR UOP Jacobs CTCI CTCI Hualu Hualu Fluor WorleyParsons InterOil | Bechtel|JGC Chiyoda | Daewoo E&C

Bechtel | Conoco Phillips Co Chiyoda Petr

EUROPE Finland Germany Germany Italy Kazakhstan Kazakhstan

100 150 150 2280 500 5

t/a Mtpy MW MMcfd Mtpy Bcmy

24 115

Dow APS Eng Co Roma LyondellBasell

Poyry Porner FW APS Eng Co Roma Petrofac|CER

MIDDLE EAST Bahrain Kuwait

Bahrain LNG KNPC

Bahrain City Al-Zour

LNG Terminal Refinery

None 615 Mbpd

Kuwait Saudi Arabia UAE UAE

KNPC Sadara Chemical Co. Mubadala Dev, Co/Int. Pet. Inv. Co. Takreer

Mina Al Ahmadi Ras Tanura Fujairah Ruwais

Sulfur Recovery (2) Petrochemical Complex LNG Terminal Aromatics Complex

200 t/a 400 Mbpd None 3 MMtpy

Hackberry St James Toledo Hood Co

LNG Liquefaction Plant Terminal, Petroleum Hydrotreater, Resid Gas Processing

12 10 42 200

600 14.5 20000 1000

Haldor Topsøe CLG | Shell Global Jacobs Nederland BV Dow

2015

GS E&C|JGC

JGC|GS E&C

Jacobs Jacobs |KBR WorleyParsons

ThyssenKrupp ABB | KBR | Jacobs KOGAS FW

FW

GDF SUEZ

UNITED STATES Louisiana Louisiana Ohio Texas

Sempra Energy Petroplex International BP Crosstex Energy

MMtpy Mbpd Mbpd MMcfd

600 80

E U U H

2016 2014 2013

KBR

KBR

The above projects represent only a fraction of data updated monthly in the Construction Boxscore Database. For more information please go to www.ConstructionBoxscore.com or contact Lee Nichols at 713-525-4626 or Lee.Nichols@GulfPub.com.

THE DEFINITIVE SOURCE FOR TRACKING GLOBAL HPI CONSTRUCTION ACTIVITY For more than 50 years, Hydrocarbon Processing magazine remains the only source that collects and maintains data specifically for the HPI community, publishing up-to-the-minute construction projects from around the globe with our online product, Boxscore Database.

Updated daily, our database helps engineers, contractors and marketing personnel identify active HPI construction projects around the world to: • Generate leads • Market research

• Track trend analysis • Decide future budget planning

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FOR A FREE 2-WEEK TRIAL, contact Lee Nichols at +1 (713) 525-4626 or Lee.Nichols@GulfPub.com.

www.ConstructionBoxscore.com 32 JULY 2012 | HydrocarbonProcessing.com

• Exporting your search results to Excel so you can compile your research • Delivering the latest updated projects directly to your inbox each week • Designing customized construction reports for your company using our 50 years of archived projects • Detailed information for key contacts at planned and ongoing construction projects

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Reliability

HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR Heinz.Bloch@HydrocarbonProcessing.com

Rethink your auditing of lubrication practices All hydrocarbon processing industry (HPI) facilities use machinery, and every one of these machines requires lubrication of some type. Modern, profitability-minded plants thoughtfully manage their lubrication practices and reap substantial benefits from the resulting enhanced equipment reliability.

However, not all lubrication practices are cost and valueoptimized. A one-day audit of your lube management practices may uncover near-zero-cost improvement opportunities that, if implemented, have paybacks measured in days and may quickly move the plant into the best-of-class grouping.

Best practices. Suffice it to say that being unaware of bestavailable lubrication practices can be expensive. Deviations from best lubrication practices may incur significant, yet readily avoidable maintenance and downtime expenses. Periodic lubrication audits are recommended. Experience shows that lubrication audits can be extremely cost-effective and almost always pointing to areas of improvement.

Next month. The discussion continues regarding oil lubrica-

tion practices and areas for improvement.

The audit. During an audit conducted by the authors at a

world-scale, state-of-the-art petrochemical plant in the US, the lube program was generally judged to be well managed. The plant had selected a competent supplier of both mineral oils and synthesized hydrocarbon (synthetic) lubricants. Management and the reliability group had engaged an experienced oil analysis laboratory and were certainly aware of the merits of sound lubrication management. Still, they had to be encouraged to make changes and improvements. A few illustrations will serve as examples here and convey part of the story.

Storage and transfer. Examples of questionable transfer and storage practices are shown in FIGS. 1 and 2. Many lube audits uncover unsatisfactory lubricant dispensing practices; little oversights can have serious negative consequences. For example, it is important to minimize contamination on lube carts.

Galvanized steel dispensing containers are frequently attacked by certain lube-oil additives; therefore, good practices mandate the use of plastic dispensing containers. Leaving transfer containers open is simply not acceptable, as shown in FIG. 1A. Storage drums should be located and positioned so that water accumulation is ruled out, as shown in FIG. 1B. Changes in ambient temperature can cause rainwater on top of the storage drum (see FIG. 2) to be drawn into the drum via capillary action. Under these conditions, a drum containing valuable lubricant is, thereby, rendered unserviceable.

Audit findings and recommendations frequently deal with lubricant contamination. Also, the effective labeling of pointsto-be-lubricated is often found wanting.

Pitfalls of standardizing. Finally, we still find plants that are

somewhat arbitrarily “standardizing” on less-than-optimum grease formulations. These facilities are applying incorrect regreasing practices on thousands of electric motors. We have seen superior plants experience as few as 14 motor bearing replacements per 1,000 motors/yr; the average plant bearing replacement is 156 motor bearing replacements per 1,000 motors/yr. We will spare the reader the statistics of less-than-average plants.

FIG. 1A. Leaving a transfer container uncovered invites lube contamination and machinery distress. 1B. Outdoor storage drums are notorious for collecting rainwater.

Rain

Cool Clean oil as delivered

Chime Air space Air space reduced

Water

Warm Oil and air expand when warm. Some air above the oil escapes.

Air escapes

Powerful suction created

Water

Cool Water is drawn-in when oil and air in the drum cool and thus contract

Water

FIG. 2. Ambient temperature cycling explains the mechanism for water entering into oil drums stored outdoors in the upright position.

HEINZ P. BLOCH teamed up with Raymond L. Thibault (rlthibault@msn.com). Mr. Thibault holds BS and MS degrees in chemistry. In 2001, he retired from ExxonMobil as a territory manager after 31 years of developing lube programs and providing technical support for numerous major HPI and other industrial clients. Mr. Thibault is considered the most knowledgeable independent consultant in the field of lube reliability improvement, and he teaches the subject worldwide.

Hydrocarbon Processing | JULY 2012 35

THANK YOU! Dear Hydrocarbon Processing community: As we celebrate our 90th anniversary, we want to acknowledge the authors, readers and advertisers who have made Hydrocarbon Processing the leading provider of technical information to the global hydrocarbon processing industry (HPI). The industry has evolved over the years—and so have we—but one thing that has stayed the same is our collective spirit and passion for making the HPI an innovative, sustaining, exciting and safe industry of which we can all be proud to be a part. As we move forward, we aim to continue striving to do our best in serving the global HPI and driving technical excellence and innovation to make our industry more competitive, efficient, and safer.

Let’s continue to accomplish great things together!

Sincerely,

John Royall President & CEO Gulf Publishing Company

Engineering Case Histories

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

Case 69: Heat-up rate and rubs on a steam turbine This column has suggested using simple analytical models to troubleshoot equipment. However, in some cases, a more detailed solution may be required. The following case histories examine the heat up of a steam turbine and the thermal growth of the rotor assembly and stationary case. The finite element analysis (FEA) is used here to identify root causes for failure events.

Y axis

The model. This axis-symmetric model contains steam tem-

peratures and film coefficients; it can then calculate the thermal displacements of the machine as it heats up from the cold condition.1 This condition is called a “transient coupled heattransfer-stress problem” because the nodal temperatures are determined from startup, and they are automatically inputted into the stress model to calculate displacements at any time.

Previous articles have illustrated the benefits of simplified FE models when an in-house answer to a problem is required quickly. It should be done by an engineer who also understands the equipment’s operation.2–4 This analysis determines if the growth difference between the rotor and case at the rub point, meaning (b-a), as shown in FIG. 1, exceeds the cold-assembly clearance. If it does, then there will be a potential interference and rub incidence. Since a rub never occurred when the insulation was in place, the same rub-point displacements will be compared with the insulation on and off.

Analysis results. The analysis indicated that, although the case was cooler without the insulation, so was the rotor assembly, and the growth difference (b-a) was essentially the same.

This is not unreasonable since the gas temperature at each stage stays about the same as it warms up the rotor and case.

The rub problem was attributed to other causes. However, the

Shaft centerline

Insulated case

Turbine example. The outline of a simplified model for a

four-stage steam turbine is shown in FIG. 1. It is an axis-symmetric model, which means that if you rotate the area about the Y axis, it will be a solid three- dimensional model. This greatly simplifies the FE modeling, and this information is all that is needed for this problem. The results are easily explained to management.

In this case, a rotor disk had rubbed against a case diaphragm. The investigation team developed a list of possible root causes. One of the many potential sources for the incident was that, since the insulation was left off the machine, the rotor shaft expanded more than in the cold case. Under these conditions, the rotor would make contact with the diaphragm for an instant. Management requested an analysis to confirm that the “touching” event was possible.

Exhaust side T5 °F a b

Shaft

T1 °F

T ambient °F

Disk

Case

Diaphragm X axis

Rotation axis

Steam inlet side T1 °F

FIG. 1. Axis-symmetric view of a steam turbine.

insulation was reinstalled for safety and efficiency reasons.

Case 2. An analysis was also done on a 12-stage 40,000-hp steam turbine with similar results.

Lessons learned. The presented examples with FE show that an analysis can be useful in determining what isn’t the cause, as well as what is the true cause. By eliminating a possible cause, the investigation can proceed in reviewing other potential concern areas.

LITERATURE CITED Lawrence, K. L., ANSYS Tutorial Release 10, SDC Publications, 2006.

2 Sofronas, A., “Case 44: Cracking due to sudden temperature changes in piping,” Hydrocarbon Processing, May 2008, p. 135.

3 Sofronas, A., “Case 46: Rotary screw compressor failure,” Hydrocarbon Processing, September 2008, p. 168.

4 Sofronas, A., “Case 61: Pressure loss in a reactor,” Hydrocarbon Processing, March 2010, p. 83.

1

DR. TONY SOFRONAS, 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. Early in his career, he worked for General Electric and Bendix and has extensive knowledge of design and failure analysis for various types of equipment.

Hydrocarbon Processing | JULY 2012 37

| Special Report 90 YEARS OF PROGRESS IN THE HPI Hydrocarbon Processing (HP) is celebrating its 90th anniversary as a publication for professionals involved in the global hydrocarbon processing industry (HPI). Much has changed since the first edition of The Refiner and Natural Gasoline Manufacture—the forerunner of present-day HP—in September 1922; yet, so many factors remain the same. In July, HP will look back and share from its archives many of the major breakthroughs in processing technologies, catalysts, equipment, instrumentation, analytical methods and automation developments that have revolutionized the global HPI.

Special Report

90 Years of Progress in the HPI R. HEINEN, IHS Chemical, The Woodlands, Texas

Catalyst developments: The last 90 years Prior to 1922, the development of three important German catalytic processes had shown the potential impact that catalysis could have on the process industry. One was the so-called contact process for producing sulfuric acid catalytically from the sulfur dioxide generated by smelting operations. Another was the catalytic method for synthetic production of the valuable dyestuff indigo. The third was the catalytic combination of nitrogen and hydrogen for the production of ammonia—the Haber-Bosch process for nitrogen fixation.

Present day value. The impact of catalysis is substantial with over 90% of all industrial chemicals produced aided by catalysts. Annually speaking, process catalysts have become a $13 billion business worldwide. The value-added products dependent on process catalysts include petroleum-based products, chemicals, pharmaceuticals, synthetic rubber, plastics and many others. The annual value of catalyst-aid products is estimated at $500–600 billion.

The definition of a catalyst that was coined in the 19th century is still used today: a substance that alters the velocity of a chemical reaction without itself being consumed. Although that is theoretically true, in practice, catalysts decrease in activity with use and suffer losses in material handling, thus requiring periodic replacement. These factors, together with economic growth and discoveries of new applications contribute to the continued growth of the catalyst business.

The other side of the picture is the drive to find moreefficient, long service life, more active and selective catalyst systems. Economic and practical considerations provide incentives to develop new catalysts, along with a greater understanding of catalysis systems in general. Development is further driven by the need for new sources of energy and chemicals, concern over environmental pollution, desire and demand for new products, and the cost and potential restrictions on the availability of the noble metals used in many catalysts.

CATALYSTS TAKE OFF The rapid growth of catalysis began around the time of World War II (WWII) with the development of catalytic cracking of crude oil. The process enabled the breaking of large hydrocarbon molecules into smaller compounds needed to process transportation fuels and petrochemicals. An important process breakthrough was the Houdry process that coupled the endothermic cracking reaction with the exothermic reaction (heat is released) of catalyst regeneration in a cyclic, continuous operation. The wartime need for toluene feedstock for trinitrotoluene (TNT) production supported the devel-

opment of catalytic reforming processes—the dehydrogenation, cyclization and isomerization of aliphatic hydrocarbons obtained from crude oil to form aromatic compounds. Owing chiefly to this process, toluene production increased tenfold from 1940 to 1944, to 1 billion liters.

Significant developments since the 1940s have made catalytic processes even more important to the modern petroleum refining and petrochemical/chemical processing industries.

These have included the emerging metallocene and other single-site catalysts (SSCs) for the polymerization of olefins, the Ziegler-Natta titanium (Ti) halide–aluminum alkyl catalysts, zeolite catalysts for petroleum refining and petrochemicals production, catalysts for the oxo reaction to convert olefins to aldehydes and catalysts for the reaction of diisocyanates with polyols to produce polyurethanes.

Refining industry. Petroleum refining, for example, is the

source for the largest share of industrial products. Upgrading crude oil technology consists almost entirely of catalytic processes. In 2009, catalysts for the refining market were a $3.2 billion business worldwide. The largest catalyst segment in terms of value is catalytic cracking, while the largest-volume products are alkylation catalysts. Other major refinery catalyst market sectors, in terms of value, include hydrotreating, reforming and hydrocracking.

Worldwide environmental regulations now mandate the production of cleaner fuels. Consequently, refiners are expe-

FIG. 1. New UOP catalytic cracking unit installed at the Rock Island Refinery. Petroleum Refiner, October 1949.

Hydrocarbon Processing | JULY 2012 39

90 Years of Progress in the HPI • Polymers with closely controlled molecular-weight distributions allow greater control over properties and facilitate new product applications.

Metallocenes, the initial class of SSCs developed, are very expensive. Less complicated ligands are used in metallocene catalysts for PE than for PP, facilitating PE catalyst development. Technical improvements have reduced the cost of metallocene-produced polymers to levels that are more competitive with those produced with conventional Ziegler-Natta polymerization catalysts. Polymers based on SSCs have unique properties and are creating new markets. Even in the existing market, some metallocene-based polymers can be competitive with conventional polymers, which has added a new dynamic to some applications.

Advanced Ziegler-Natta catalysts have been develWithout the catalytic processes that have oped; these catalyst systems can produce polyolefins with properties similar to those produced by metallocenes. We been developed since the 1940’s, many of expect that Ziegler-Natta catalysts will remain the domithe fuels and materials we use on nating technology due to cost benefits.

We will summarize some of the major developments a daily basis would not exist. in catalysis that have occurred over the last 90 years.

While the list of advances and the implications of these developments on the process industry are too numerous to list, they represent some of the most noteworthy. sign, as modifications and/or new technologies are required to facilitate compliance with the regulations, while still allowing the hydrocarbon processing industry to economically provide PETROLEUM REFINING CATALYSTS hydrocarbon-based products without interruption and meet The major processes involved in petroleum refining are disthe increasing needs of the growing global population. tillation, catalytic hydrotreating, catalytic reforming, isomerization, catalytic cracking, catalytic hydrocracking, alkylation and thermal operations. Only distillation and thermal operaPolymerization catalysts. Polymerization catalyst sales in tions involve no catalysts. The utilization of each refining pro2009 were estimated at $4.3 billion. Major market segments cess depends on the quality of the crude oil and the demand include polyethylene (PE), polypropylene (PP), polyethylene for the various product streams and products. Many of the terephthalate (PET), polyvinyl chloride (PVC) and polystyadvances in refining process technology were possible due to rene (PS). Polyolefin catalysts are the largest single market catalyst developments. Much of this work was driven by the sector, with about a 50%–60% market share of the total polyneed to increase production of the refined products needed to merization market, equivalent to about $2.2–2.6 billion. Sigsupport the war efforts in the mid-1900s. These developments nificant new technical developments that were introduced provided the basis for many processes that are common procommercially since the 1990s are: cessing practices in the present-day refining industry.

• SSCs for polymerization offer tremendous opportunities for polyolefins development Catalytic cracking. The first full-scale commercial catalytic cracker for the selective conversion of crude petroleum to gasoline went on stream at the Marcus Hook refinery in 1937.

Pioneered by Eugene Jules Houdry (1892–1962), the catalytic cracking of petroleum revolutionized the industry. The Houdry process conserved crude oil by doubling the amount of gasoline produced by other processes. It also greatly improved the gasoline octane rating, making possible today’s efficient, high-compression automobile engines. During WWII, the high-octane fuel shipped from Houdry plants played a critical role in the Allied victory.

The most dramatic benefit of the earliest Houdry units was in the production of 100-octane aviation gasoline, just before the outbreak of WWII. The Houdry plants provided a better gasoline for blending with scarce high-octane components, as well as byproducts that could be converted by other processes FIG. 2. The arrival of a 96-ton cat-cracker reactor is part of an expansion at the Anglo-Iranian Oil Co.’s Grangemouth, Scotland, refinery. to make more high-octane fractions. The increased perforOn the left is the topping unit; the catalytic cracker is under construcmance gave Allied planes some advantage over the Axis. In the tion, as shown on the right of the photo. Petroleum Refiner, May 1952. first six months of 1940, at the time of the Battle of Britain, riencing severe pressures from market forces that demand a change in the product mix, aside from quality. On the regulatory side, stringent product specifications limit sulfur content along with changes in gasoline and diesel composition. Major technological challenges to refining operations include achieving “zero” or heavily reduced sulfur content in all fuel for almost all countries around the world. The phase-out of methyl tertiary butyl ether (MTBE) in reformulated gasoline in the US and other nations has forced operating changes for reformer operations to achieve the required high-octane number of gasoline-blending components. Environmental pressures have become the major driving forces in catalysis and process de-

40 JULY 2012 | HydrocarbonProcessing.com

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90 Years of Progress in the HPI 1.1 million bbl/month of 100-octane aviation gasoline was shipped to the Allies. Houdry plants produced 90% of this catalytically cracked gasoline during the first two years of the war.

The original fixed-bed Houdry process units have been outmoded by engineering advances that transformed the fixedbed to more economical fluidized-bed systems, and introTABLE 1. Milestones in catalysis developments Year

Process

Catalysts

1957

Polymerization

Ziegler-Natta catalysts

1962

Steam reforming

NiK2Al2O3

1964

Catalytic cracking with faujasite zeolites

x and y zeolites

1967

Bimetallic reforming

Pt-Re; Pt-Ir

1968

Selectoforming (shape selectivity)

Erionite

1972

Low-pressure CH3OH

Cu-Zn-Al2O3

1974

Acetic acid via carbonylation RhI

1976

Auto emission control for HC and CO

Pt-Al2O3

1980

Gasoline from methane

ZSM-5 zeolite

1982

NOx control

Pt-Rh for autos; V2O5-TiO2 stack gas

1988

Selective oxidation

TiSiO2

1988

Chiral catalysts

Zeolites or SO2 cinchonidine on supported Pt

1991

Polymerization

Metallocenes

FIG. 3. View of the new catalytic cracking and thermal refining unit for West Germany’s newest refinery constructed by Esso A.G., a German affiliate of Standard Oil Co. (New Jersey). The $12 million expansion is located in Hamburg, Germany, and replaces the older refinery destroyed during WWII; it is the most modern refinery in Europe.

Petroleum Refiner, May 1954.

42 JULY 2012 | HydrocarbonProcessing.com

duced the use of crystalline aluminosilicate catalysts to provide higher gasoline yields. Yet, it is remarkable that, 70 years after Houdry’s discovery, the same fundamental principles are still the primary platform for manufacturing gasoline worldwide.

Donald Campbell, Homer Martin, Eger Murphree and Charles Tyson were known for their development of a process still used today to produce more than half of the world’s gasoline. These “four horsemen” were part of the Exxon Research Co. They began thinking of a design that would allow for a moving catalyst to ensure a steady and continuous cracking operation. The four ultimately invented a fluidized-solids reactor bed and a pipe-transfer system between the reactor and regenerator unit in which the catalyst is processed for re-use.

The fluid catalytic cracking (FCC) process revolutionized the petroleum industry by more efficiently transforming heavier oil fractions into lighter, usable products. Catalysts for this process have evolved significantly over the past 30 years from the original amorphous silica/alumina products. Essentially all commercial gasoline refining processes now use zeolite catalysts, and FCC is the largest market for zeolites.

Catalytic hydroprocessing. Reactions involving catalytic hydrogenation of organic substances were known prior to 1897.

The property of finely divided nickel to catalyze the fixation of hydrogen on hydrocarbon (ethylene and benzene) double bonds was discovered by the French chemist Paul Sabatier who found that unsaturated hydrocarbons in the vapor phase could be converted into saturated hydrocarbons by using hydrogen and a catalytic metal. His work was the foundation of the modern catalytic hydrogenation process.

Soon after Sabatier’s work, a German chemist, Wilhelm Normann, found that catalytic hydrogenation could be used to convert unsaturated fatty acids or glycerides in the liquid phase into saturated ones. He was awarded a patent in Germany in 1902 and in Britain in 1903, which was the beginning of what is now a worldwide industry.

In the mid-1950s, the first noble metal catalytic reforming process (UOP’s Platformer Process) was commercialized. At the same time, the catalytic hydrodesulfurization (HDS) of the naphtha feed to such reformers was also commercialized. In the decades that followed, various proprietary catalytic HDS processes have been commercialized. Most refineries have one or more HDS units.

Catalytic hydrocracking. Hydrocracking was first developed in Germany as early as 1915 to provide coal-based liquid fuels from domestic coal deposits. The first plant that might be considered as a commercial hydrocracking unit began operation in Leuna, Germany, in 1927. Similar efforts to convert coal to liquid fuels took place in Great Britain, France and other countries. Between 1925 and 1930, Standard Oil of New Jersey collaborated with I.G. Farbenindustrie of Germany to develop a hydrocracking technology capable of converting heavy petroleum oils into fuels. Such processes required pressures of 200 bar—300 bar and temperatures of over 375°C, and they were very expensive.

In 1939, Imperial Chemical Industries (ICI) of Great Britain developed a two-stage hydrocracking process. During WWII, this two-stage hydrocracking process helped refiners in Ger-

90 Years of Progress in the HPI many, Great Britain and the US to supply the needed volumes of aviation gasoline. After WWII, hydrocracking technology became less important, as increased availability of petroleum crude oil from the Middle East removed the motivation and the economics to convert coal into liquid fuels. Newly developed FCC processes were more economical than hydrocracking to convert high-boiling petroleum oils to fuels.

In the early 1960s, hydrocracking become economical in part due to the introduction of zeolite-based catalysts, during the period from about 1964 to 1966. Zeolite-based catalysts performed much better than the earlier catalysts, and these catalysts permitted operation at lower pressures. The combination of higher performance and lower operating pressures significantly reduced the cost of building and operating hydrocrackers.

Alkylation. The alkylation process started with an observation that puzzled Herman Pines in 1930 when he was working in the lab of Universal Oil Products (UOP). While vigorously shaking petroleum fractions with concentrated sulfuric acid in a calibrated glass cylinder to determine how much of the oil dissolved in the aqueous acid phase, Pines observed that, after a few hours, the phase boundary between oil and acid had shifted again.

Apparently, paraffins had formed from the olefins. Pines concluded that this process required the simultaneous formation of a highly unsaturated coproduct, which remained dissolved in the aqueous phase in a process called “conjunct polymerization”.

Alkylation was commercialized in 1938, and experienced tremendous growth during the 1940s stemming from demand for high-octane aviation fuel during WWII. After the war, refiners’ interests shifted from producing aviation fuels to using alkylate as a blending component in gasoline motor fuels. Alkylation capacity remained relatively flat through the 1960s due to the lower cost of other blending components. When the US Environmental Protection Agency’s lead phase-down program began in the 1970s and completed in the 1980s, alkylate demand sharply increased. Alkylate was sought as a blending component to compensate for lead removal from gasoline. As additional environmental regulations were imposed worldwide, the importance of alkylate as a blending component for motor fuel increased.

discovered that it is possible to catalyze one type of chemical reaction in preference to others that are thermodynamically favorable. He showed that bimetallic catalysts could be used to effectively reduce undesirable competing reactions. This made possible the economic conversion of low-octane-number molecules to high-octane number molecules.

Many versions of this process have been developed by the major oil companies and other organizations. In 1971, UOP commercialized a fully regenerative reforming process called continuous catalysis regeneration (CCR). The Institut Français du Pétrol (IFP) also offers a CCR process. This process stacks the reactors so that the catalyst may be withdrawn from the bottom reactor, regenerated and fed back to the top reactor without interrupting operations. The process uses lower operating pressures, thereby increasing the yield of hydrogen and aromatics and improving the octane rating.

PETROCHEMICAL PROCESSING CATALYSTS Ziegler-Natta catalysts. German Karl Ziegler, for his dis-

covery of the first titanium-based catalysts, and Italian Giulio Natta, for using them to prepare stereo-regular polymers from propylene, were awarded the Nobel Prize in Chemistry in 1963. Ziegler discovered the basic catalyst systems for polymerizing ethylene to linear high polymers. Ziegler’s research had started with propylene but was unsuccessful, and he then shifted his focus to ethylene. Natta was a professor at the Institute of Industrial Chemistry at Milan Polytechnic and was a consultant for Montecatini. Natta learned of Ziegler’s success with ethylene polymerization and pursued propylene polymerization, thus determining the crystal structure in 1954 for which Ziegler and Natta were awarded the Nobel Prize in Chemistry.

In the early 1950s, workers at Phillips Petroleum discovered that chromium (Cr) catalysts are highly effective for the low-temperature polymerization of ethylene. A few years later, Ziegler discovered that a combination of TiCl4 and Al(C2H5 )2Cl gave comparable activities for PE production. Natta used crys-

Catalytic reforming. In the 1940s, Vladimir Haensel, while

working for UOP, developed a platinum-based catalytic reforming process for producing a high-octane gasoline from low-octane naphthas known as the UOP Platforming process.

Haensel’s process was commercialized by UOP in 1949 when the first Platforming unit was built by the Old Dutch Refining Co. in Muskegon, Michigan.

Dr. Sinfelt, at Standard Oil Co., was researching alternate petroleum conversion chemistries and developed the application of novel, highly active and selective bimetallic-cluster catalyst systems to produce high-octane motor gasoline without lead additives. Earlier work on metal alloys had demonstrated the relation between catalytic performance of a metal and its electron band structure. However, the possibility of using this to catalytically influencing the selectivity of chemical transformations (product selectivities) had not been considered.

Dr. Sinfelt, through in-depth studies on bimetallic catalysts, discovered how to influence chemical reaction selectivity. He

FIG. 4. Catalytic cracking unit No. 3—the largest cat cracker in Amoco Oil’s Texas City refinery—will be among the units modified to process high-sulfur crude oils. Hydrocarbon Processing, October 1973.

Hydrocarbon Processing | JULY 2012 43

90 Years of Progress in the HPI talline α-TiCl3 in combination with Al(C2H5 )3 to first produce isotactic PP, which decreased the atacticity, and it was key to PP market development. Usually, Ziegler catalysts refer to Tibased systems for conversions of ethylene, and Ziegler-Natta catalysts refer to systems for conversions of propylene. In the 1970s, magnesium chloride (MgCl2 ) was discovered to greatly enhance the activity of the Ti-based catalysts. These catalysts were so active that the small amount of residual Ti was no longer removed from the product. They enabled commercialization of linear-low-density PE (LLDPE) resins and it allowed the development of noncrystalline copolymers.

Ziegler-Natta catalysts have been used in the commercial manufacture of various polyolefins since 1956. In 2010, the total volume of plastics, elastomers and rubbers produced from alkenes with these and related catalysts worldwide exceeded 100 million metric tons. Together, these polymers represent the largest-volume commodity plastics, as well as the largestvolume commodity petrochemicals in the world.

Metallocenes. One of the most exciting developments in

chemical-process catalysts is the new class of SSCs—metallocene and nometallocene. Polymers based on SSCs have unique properties and are creating new markets. Even in the current market, some metallocene-based polymers, especially LLDPE, are replacing conventional polymers.

Metallocene catalysts are just as old as the Ziegler-Natta systems, but the first systems using them were found to have

FIG. 5. Qatofin’s Ras Laffan, Qatar, complex is one of the latest world scale olefins and polyethylene manufacturing sites. Hydrocarbon Processing, April 2011.

44 JULY 2012 | HydrocarbonProcessing.com

low activity. It wasn’t until 1980, when metallocene catalysts were put together with a methyl aluminoxane cocatalyst, that their full potential was realized. Their big advantage over the Ziegler-Natta systems is that these systems catalyze the reaction of olefins through only one reactive site. Due to this “single-site” reaction, the polymerization continues in a far more controllable fashion, leading to polymers with narrow molecular weight ranges and, more importantly, predictable and desirable properties. Also, it has been found that changing the ligands (functional groups attached to the metal) within the metallocene molecule can controllably affect the properties of the polymer. This is very attractive to petrochemical companies trying to keep up with the demand for engineered plastics.

Research and development. Following the lead of the phar-

maceutical industry, oil, petrochemical and catalyst companies are turning to high-throughput screening (HTS), including combinatorial chemistry, to accelerate catalyst development as short as two years, and, therefore, shortening the time-tomarket of new products. For example, UOP is developing HTS expertise to develop new catalysts and adsorbents, which it considers to be at the basis of its competitive advantage. Other companies developing their own HTS capabilities include BASF and Johnson Matthey. Research using these methods, as well as banks of microreactors, continues at the R&D centers of the major energy and chemical companies.

In the last two decades, catalyst development has been transitioning from an art form into a science based on advances in physical and chemical instrumentation plus computer-based modeling tools. New initiatives in catalytic processes are focused on reducing cycle time for catalyst discovery and process development from five to ten years down to three to five years. New approaches are designed to integrate and validate catalyst design methodologies along with HTS techniques and process modeling.

Combinatorial chemistry is speeding up innovation and accelerating availability of improved catalytic materials for the chemical industry. HTE refers to high-throughput experimentation. The term combinatorial catalysis is really a misnomer because, although this concept may be used to visualize libraries of catalysts to be tested, it is actually the HTE techniques that are the key to decreasing catalyst development time. The application of HTE to catalyst research requires developing new methods for catalyst preparation, reactors and instrumentation, along with new methods for rapid analysis and information systems capable of handling the large quantities of generated data.

THE FUTURE The rapidly growing field of biotechnology brings with it opportunities in the field of enzyme-catalyzed reactions. The role of genetically engineered microorganisms in synthesizing rare and valuable peptides used in human therapeutics is now well established. The same techniques of molecular biology can also be used to enhance the properties of enzymes as catalysts for industrial processes.

This approach can potentially revolutionize the applications of biological systems in catalysis. Enzymes and other biological systems work well in dilute aqueous solutions at moderate temperature, pressure and pH. The reactions catalyzed

90 Years of Progress in the HPI by these systems are typically environmentally friendly in that few byproducts or waste products are generated. The reactions are typically selective with extremely high yields. Enzymes can be used to catalyze a whole sequence of reactions in a single reactor, resulting in vastly improved overall yields with high positional specificity and 100% chiral synthesis in most cases.

The improved use of enzyme-based catalyst technology with whole-cell catalysis, reactions catalyzed by single enzymes, and mixed enzymatic and chemical syntheses are all important for fostering new catalyst technology.

Whole cells of various microorganisms are being used more frequently in the catalytic synthesis of complex molecules from simple starting materials. The use of whole microbial cells as biosynthetic catalysts takes advantage of one of the unique properties of enzymes: They were designed by nature to function together in complex synthetic or degradative pathways. Because of this property, whole cells and microorganisms can be used as catalytic entities that carry out multiple reactions for the complete synthesis of complex chiral molecules. A number of specialty chemicals with complex synthetic schemes can be produced most efficiently by intact microorganisms utilizing a series of enzyme-catalyzed reactions designed by nature to work together.

The biotechnology field has a growing number of examples of reactions of industrial significance catalyzed by isolated enzymes. The enzymatic conversion of acrylonitrile to acrylamide was recently commercialized in Japan. Japanese com-

panies and researchers have been very diligent in developing enzymatic processes for the synthesis of fine chemicals. The stereospecificity of enzyme-catalyzed reactions has been used to advantage in polymer synthesis, as well. Workers at ICI have developed a combined enzymatic and chemical process for the synthesis of polyphenylene from benzene. These are only a few of the developments that demonstrate the potential for the process industry to utilize breakthroughs in other areas to improve the range of products that can be produced economically. While catalysis has made great advances over the last 90 years, the application of new technologies developed in other areas offers great promise for future breakthroughs.

RUSSELL HEINEN is the director of technology services for IHS Chemical and manages the Process Economics Program (PEP), and the Carbon Footprint Initiative. He has 30 years of experience in energy and chemical consulting. He joined IHS in 2010 when SRI Consulting (SRIC) whom he had been with for more than 13 years was aquired by IHS. Based in The Woodlands, Texas, his specific expertise covers natural gas, refining, and chemicals market analysis and technology evaluations. This experience has recently been focused on helping clients to identify new opportunities in the downstream chemical markets and assisting companies with technology evaluations and selections. In addition to these studies, he also is responsible for the Carbon Footprint Initiative, which helps companies understand and manage their strategy related to carbon emissions. Mr. Heinen holds a BS degree in engineering from Rice University in Houston, and received an MBA from the Jesse H. Jones Graduate School of Administration at Rice University in 1982. He is a registered engineer in the state of Texas, and is a member of the American Institute of Chemical Engineers.

Select 159 at www.HydrocarbonProcessing.com/RS

Hydrocarbon Processing | JULY 2012 45

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Special Report

90 Years of Progress in the HPI J. CASTEL, D. GADELLE, P. HAGYARD and M. OULD-BAMBA, Technip, Paris, France

LNG and GTL drive 50 years of technology evolution in the gas industry meet environmental regulations, to avoid corrosion, to maximize revenue, and to comply with product specifications.

Gas treatment generally involves a number of steps, as shown in FIG. 3 and listed below: • Separation of liquids (hydrocarbons and free water) • Acid gas removal (CO2 and/or H2S, when present) • Removal of other sulfur compounds (e.g., carbonyl sulfide and mercaptans) • Final dehydration for the removal of water to sub-ppm level, which makes the gas acceptable for the downstream cryogenic unit or for export requirements • Mercury (Hg) is removed to protect aluminum-based equipment often present in cryogenic units, such as cryogenic 350 300 Consumption, Bcfd

While humankind has been aware of the existence of natural gas since ancient times, its industrial use is relatively recent, with the first natural gas wells drilled in North America in the 19th century. The first “true” natural gas processing plants began operating in Canada at the beginning of the 20th century, but they produced gas mainly for local heating and lighting.

Natural gas has become increasingly popular since the 1940s, and its consumption has grown steadily. FIG. 1 shows increasing gas consumption over the 45 years to 2010. Natural gas is, and will remain, a vital component of the global energy supply, helped by its environmental advantage over other fossil fuels and by growing demand from developing countries. Numerous factors have contributed to the evolution of the natural gas industry over time: • The need to handle increasingly difficult resources—e.g., high-contaminants-content reserves, stranded reserves, resources in harsh geographical locations or climates, and subsea reserves • Energy-efficiency improvements with regard to economic constraints and environmental regulations • Plant capacity increases to limit project costs, requiring equipment scale-up • Development of new technologies and processes reaching maturity • Tighter oil and gas industry health, safety and environment (HSE) standards and regulations • Economic and political developments.

250 200 150 100 50 0 1965

1970

1975

1980

1985

1990

1995

2000

2005

2010

Source: BP Statistical Review of World Energy 2011

FIG. 1. Global natural gas consumption, 1965–2010.

The gas value chain. Natural gas is a valuable resource, not

only as a clean fuel for power and heat generation, but also as a key raw material for the petrochemical and chemical industries. Once cleaned of its impurities, natural gas can be separated into its major components—methane, ethane and liquefied petroleum gas (LPG)—and used as pipeline gas, liquefied for export or converted to liquid fuels or synthesis gas (syngas) for the fertilizer industry, as illustrated in FIG. 2.

Natural gas also is a major source of ethane and LPG for the production of olefins via steam cracking.

In this article, we discuss the evolution of gas processing plants to satisfy ever-growing demand, with a focus on liquefaction and GTL plants.

Natural gas processing. The first step at the majority of the

world’s gas processing plants is to eliminate impurities and to recover components heavier than methane. This is done to

Oil field facilities including shale oil Coalbed methane

Natural gas pipeline

Offshore liquefaction

Associated gas Gas processing Non-associated gas

Methane (C1)

CO2 Sulfur Water

Gas field facilities including shale oil

LPG Gasoline

Ethane (C2)

Condensate

Onshore liquefaction

Steam cracker (ethylene)

GTL

Petrochemicals đƫ ))+*% ĥ1.! đƫ 5 .+#!* đƫ +(5!0$5(!*! đƫ +(52%*5(ƫ $(+.% !

FIG. 2. The natural gas value chain.

Hydrocarbon Processing | JULY 2012 47

90 Years of Progress in the HPI Flue gas to stack

Total CO2 removal may not be required. Design for selective H2S removed in some cases.

Separation unit

Sulfur recovery unit

Sulfur Acid gas (H2S+CO2)

Acid gas removal unit

Dehydration (mercaptans and mercury removal)

NGL recovery unit

Sales gas

Hydrocarbons, C2+ Condensate stabilization unit Sour gas from field

Stabilized hydrocarbons, C5+

NGL

C5+

FIG. 3. Process flow of a typical natural gas processing plant.

FIG. 4. Cakerawala gas treatment platform with CO2 removal on membranes, Malaysia/Thailand joint development area.

heat exchangers; it also may be removed for HSE considerations when the feed gas Hg level is high • Heavy hydrocarbons (including benzene) are often separated from the gas since they tend to freeze at the low temperatures encountered in cryogenic sections • Natural gas liquids (NGLs), such as ethane and/or LPG, might be extracted to meet product gas specifications (heating value), or because of their inherent economic value.

Over the last 100 years, natural gas processing has steadily evolved due to continual scientific and technical advances in related fields: • Process design tools and simulation software incorporating more accurate thermodynamic models • Research work conducted by chemists to develop new solvents, adsorbents and catalysts, in view of improving natural gas purification performance and economics • Development of membrane separation technologies to provide economical and compact designs for high-CO2-content gases (FIG. 4) • Developments in the technology and manufacturing of high-efficiency and compact heat exchangers, mass transfer internals, compressors and pumps, etc.

• Computer-assisted design (CAD) and advances in automation and control facilities.

Gas/liquids separation has benefited from more efficient internals and mass transfer devices that have been developed with the aid of computational fluid dynamics. The incentive to produce compact equipment to reduce platform costs in the North Sea’s hostile environment, starting in the 1970s, has provided the gas industry with solutions enabling single-train sizes of up to 1,350 million standard cubic feet per day (MMscfd).

Today, CO2 and H2S are commonly removed with one of the formulated amines that have largely replaced hot carbonate, 48 JULY 2012 | HydrocarbonProcessing.com

MEA and caustic soda, which were once standard solutions.

Formulated MDEAs, possibly mixed with a physical solvent, enable decreased energy consumption, improved performance and reduced corrosion through lower output of heat-stable salts.

MDEAs also increase the amount of gas that can be treated in a single column by allowing higher acid gas loading in the solvent.

Sulfur recovery continues to rely on the Claus process, although the application of modern acid gas enrichment and tail gas treating processes means that recovery rates above 99% can be attained even with the most challenging feed gases. Additionally, the dehydration of gas upstream of the cryogenic units is presently done using zeolites—molecular sieve material that has efficiently replaced silica gel and the glycol systems that were first implemented.

Finally, modern, highly optimized cryogenic fractionation processes using turboexpanders and compact heat exchangers allow for the recovery of NGLs, such as ethane and LPG, and the simultaneous removal of heavy hydrocarbons, including benzene.

The gas processing industry has developed a number of improved processes that offer reduced equipment count, improved efficiency and/or reduced operating cost, therefore making it possible to produce gas from challenging reservoirs. Such reservoirs include sour gas fields containing high levels of acid components, such as those encountered in Russia, Kazakhstan, the Middle East (H2S and CO2 ) or the Far East (CO2 ); deepwater fields (as found offshore Brazil, Norway, Russia, Australia, the Middle East, Africa, etc.); and fields located in the Arctic.

With the unequal distribution of natural gas reserves around the world, the monetization of some of these resources via pipeline distribution grids or power generation plants can be limited or even impossible. This opens the door for the liquefaction of methane for export as liquefied natural gas (LNG), or for shipment to plants that convert natural gas into syngas for methanol, ammonia and urea synthesis. More recently, the conversion of natural gas into synthetic liquid fuels (synfuels) in gas-to-liquid (GTL) plants has been industrialized at a large scale.

Rapid growth in LNG. Natural gas liquefaction dates back to the late 19th century at an experimental level. LNG technology was developed alongside helium recovery from natural gas in the early 1920s, but it took until 1941 before a commercial peakshaving plant started producing LNG in Cleveland, Ohio for storage in atmospheric tanks.

The possibility of shipping large quantities of LNG to distant consumers was demonstrated for the first time in 1959 by the world’s first LNG carrier, the Methane Pioneer. This event demonstrated that large quantities of LNG could be transported safely across the ocean, creating a market opportunity for the large gas reserves discovered in North Africa’s Hassi R’Mel field and in the Cook Inlet area of Alaska.

The LNG industry is considered to be a young industry since the first baseload export plants were put into operation only in the mid-1960s. The world’s first baseload LNG export plant was the Camel plant in Arzew, Algeria.1 It started up in September 1964, liquefying natural gas from the Hassi R’Mel gas field using a propane-ethylene-methane cascade-refrigeration process. The train capacity was 400,000 tons per year (tpy) of LNG, with production exported primarily to France and the UK.

90 Years of Progress in the HPI TABLE 1. LNG plant startup dates and key specifications Plant

Startup date

Refrigerant compressor drivers

Cooling medium

Camel

1964

Steam turbine

Seawater

Kenai

1968

Gas turbine, Frame 5

Cooling tower

Libya

1970

Steam turbine

Seawater

Skikda

1972

Steam turbine

Seawater

Brunei

1972

Steam turbine

Cooling tower

Das Island

1977

Steam turbine

Seawater

Bontang

1977

Steam turbine

Seawater

Arzew

1978

Steam turbine

Seawater

Arun

1978

Gas turbine, Frame 5

Seawater

Bintulu I

1983

Steam turbine

Seawater

Northwest Shelf

1989

Gas turbine, Frame 5

Air cooling

Bintulu II

1995

Gas turbine, Frame 6 + 7 [electric motors (EM)]

Seawater

Qatargas

1996

Gas turbine, Frame 5 (EM)

Seawater

RasGas I

1999

Gas turbine, Frame 7 + 7 (EM)

Seawater/freshwater

Nigeria

1999

Gas turbine, Frame 6 +7 (EM)

Cooling tower

Trinidad

1999

Gas turbine, Frame 5

Air cooling

Oman

2000

Gas turbine, Frame 6 +7 (EM)

Seawater

RasGas II

2004

Gas turbine, Frame 7 + 7 (EM)

Seawater/freshwater

Northwest Shelf IV

2004

Gas turbine, Frame 7 + 7 (EM)

Air cooling

Segas

2005

Gas turbine, Frame 7 + 7 (EM)

Air cooling

Snøhvit

2007

EM

Seawater

Qatargas/RasGas APX

2009/2010

Gas turbine, 3 ⫻ Frame 9 (EM)

Seawater/freshwater

Yemen

2009

Gas turbine, 2 ⫻ Frame 7

Seawater

-7 -7 s 6 tr 4 sGa as Ra atarg Q

Steam turbines + water cooling Gas turbines + water cooling Gas turbines + air cooling

7,000 6,000

.

Exp elf Sh

a eri Nig

e Sh

2 s 1sGa H Ra adak B

NW

2,000

lf 1 n Aru

B

1-3

1970

kA

0 1960

n

3,000

e Yem

s Plu ad 2 1 nid 1- s Tri geria targa Ni Qa

4,000

1,000

as

Seg NW

5,000

da Ba

LNG production capacity, thousand tpy/train

8,000

a1 kd Ski nai Ke el Cam

The opening of the Camel plant marked the beginning of the commercial LNG industry. This facility was followed in 1968 by the startup of the Kenai LNG plant in Alaska, which exported product to Japan. It was also based on pure-component cascade technology, although it used gas turbines for the compressor drivers.

Motivated by the industry’s need for larger production scales and lower equipment count, mixed-refrigerant (MR) processes soon dominated the LNG sector. The Single Mixed Refrigerant (SMR) process was adopted by Esso for the Marsa El Brega plant in Libya in 1970, and the Tealarc double mixedrefrigerant process was developed. Meanwhile, Sonatrach adopted the Dual Pressure SMR Tealarc process for its LNG plant in Skikda, Algeria in 1972, and the Propane Precooled MR (C3MR) process was first licensed by Shell Brunei in 1972.

The LNG industry has grown relentlessly since 1964, undergoing considerable changes. The most prominent of these changes is the increase in single-train capacity, as illustrated in FIG. 5. Individual LNG train capacity was multiplied by a factor of nearly 20 with the 2009 startup of the LNG mega-trains at Ras Laffan, Qatar. These mega-trains—used for Qatargas Trains 4, 5, 6 and 7 and RasGas Trains 6 and 7—each produce 7.8 million tons per year (MMtpy) of LNG. The continual increase in LNG single-train capacity has been driven by strong demand, and by the industry’s efforts to reduce specific investment and operating costs and to take

1980

1990 Year

2000

2010

2020

FIG. 5. The evolution of baseload LNG train capacity over time.

advantage of larger equipment sizes and improvements in efficiency and technology, including: • New refrigerant cycles • Larger, more efficient refrigerant compressor drivers • Cooling systems that strike a balance of efficiency, cost, reliability and environmental impact • Integration of heat and power systems.

TABLE 1 depicts key features of baseload LNG plants developed over the last 50 years. In the early years of baseload LNG export plants, steam turbines were the drivers of choice for Hydrocarbon Processing | JULY 2012 49

90 Years of Progress in the HPI refrigerant compressors, since large turbines were previously developed for the power generation industry and were already widely used in the HPI. A major breakthrough was achieved in the 1980s with the adaptation of the large, heavy-duty gas turbines used in power generation for mechanical drive, a change that introduced new opportunities for the LNG industry. These heavy-duty gas turbines allowed for high power output, better overall efficiency and reduced capital cost by avoiding excessive water use for steam condensation. At the same time, the use of air cooling for heat rejection appeared as a viable and lower-capital-intensive solution for plants with difficult or no access to seawater cooling, such as the North West Shelf plant in Australia. This trend was maintained in the 1990s and afterward with the use of more powerful gas turbines, which has been a key factor in boosting individual LNG train capacity.

The first decade of the new millennium saw the introduction of large electrical motors—a driver solution with high reliability and good efficiency when power generation is based on a combined cycle. Even though the capital expenditure for such a system can appear quite high, it reflects an industrial vision increasingly focused on reliability and the monitoring of atmospheric emissions. This configuration for large-capacity plants has been applied once, in the Snøhvit LNG plant in Norway.

FIG. 6. Amine absorber shell for Qatargas II Trains 4 and 5.

100

Of course, the evolution of compressor driver technology is not the sole focus point of the LNG industry’s remarkable progress. The sector also has benefited from continual technology improvements in a number of other areas: • Optimization of process configuration and energy integration, which reduces overall cost while improving efficiency • Developments in gas processing technologies applicable to the LNG industry, such as high-performance sour gas sweetening solvents, and zeolites and adsorbents for gas contaminant removal to trace levels; these technologies make compliance with stringent product specifications and environmental regulations possible • Improvements in the capacity and efficiency of refrigerant compressors • Progress in metallurgy and the ability to manufacture, transport and install heavy pieces of equipment, such as the amine absorbers in Qatargas Trains 4 and 5; each absorber weighs 1,450 tons, is 7.4 m in diameter, and rises 46 m high (FIG. 6) • Improvements in heat exchanger technology—including large spool-wound exchangers; high-pressure aluminum platefin exchangers of large capacity; and high-flux heat exchangers involving special tube design, such as the enhanced tubes, which allow for very low temperature approaches4 • Progress in CAD (process and thermal design simulation software, dynamic simulation tools, 3D modeling, etc.) allows designers to optimize and check solutions for process configuration, pipe routing and equipment layout.

To conclude this overview of the evolution of LNG baseload plants, it is worth noting that, while energy efficiency has made significant progress over the past 50 years, this can be mainly attributed to the better integration of power and heat facilities. Improvements in equipment and process configuration represent only 30%, as illustrated in FIG. 7.

Another interesting feature of LNG baseload plants is that most of the project costs are dictated by site-related parameters (e.g., quality of feed gas, climatic conditions, site topography, extent of marine works, local construction environment, accessibility and availability of infrastructure, economic and political conditions, environmental constraints, etc.). The technical design has no influence on these parameters and can only adapt to them. Although technology selection does not have the weight in the total project cost that might be expected, it remains a key parameter for the operation and efficiency of the plant.

90 80

Percentage

70

Power and heat integration

60 50 40 30 20 10 0

Improved equipment

Process configuration

FIG. 7. Contributions to energy efficiency improvements.

50 JULY 2012 | HydrocarbonProcessing.com

Same-capacity LNG trains, separated 50 years. Nearly five decades lie between the 1964 construction of the Camel LNG plant in Algeria and the 2012 startup of the Ningxia Hanas mid-scale LNG plant in China. Both plants have approximately 400,000-tpy individual train capacities (FIG. 8).2 Despite the industry’s tendency to design and build individual liquefaction trains of ever-increasing capacity to improve plant economics, there is a renewed interest in small-scale LNG (SSLNG) plants for monetizing small gas reserves and for supplying isolated communities or areas where the installation of a natural gas distribution grid is too costly. China, India and Brazil have implemented or are planning to install SSLNG plants like the one developed at Ningxia Hanas.

While the Camel plant was designed to process raw natural gas from a field and is dedicated to overseas LNG export via

90 Years of Progress in the HPI tanker, the Ningxia Hanas plant processes pipeline gas that is already pretreated for contaminants and NGL recovery. The facility’s feed gas requires compression prior to liquefaction, and production is delivered via road tanker. Thus, besides the similarity in capacity, the processing schemes and plant features of the Camel and Ningxia Hanas LNG trains have little in common, as illustrated in TABLE 2.

This comparison reflects the way the LNG industry has evolved, driven by the need to minimize equipment count and processing steps to reduce capital investment while at the same time obtaining the highest possible efficiency to preserve resources.

A giant leap from Skikda to Qatargas II. An interesting

comparison also can be made between the Skikda and Qatargas II LNG projects (FIG. 9). Each one was a pioneering development in its time, but the plants were built and commissioned 36 years apart. TABLE 3 shows a comparison of the two facilities, which were built in 1972 and 2009, respectively.

Between the first trains of the Skikda plant and the megatrains of Qatargas II, the individual LNG throughput per train has multiplied by a factor of close to 8, and the overall plant capacity by a factor of 5, leading to a proportional increase in terms of construction quantities. However, fuel gas consumption has been multiplied by only 2.8, reflecting the significant increase in energy efficiency achieved over the period.

The overall duration of the construction and commissioning phases also has been reduced despite the increased workload, the number of simultaneous construction projects in the Ras Laffan area, and the more complex configuration of the Qatargas units due to the presence of H2S and organic sulfur components in the feed gas. The excellent overall efficiency of Qatargas II is due to the use of gas turbines and the deep integration of heat and power systems that recover heat enTABLE 2. Comparison of Camel and Ningxia Hanas LNG plants Camel

Ningxia Hanas

Startup date

1964

2012

Capacity, trains ⫻ tpy

3 ⫻ 400,000

2 ⫻ 400,000

Location

Seaside

Inland

Primary feedstock source Natural gas field

The industry’s next challenge: FLNG. In recent years, progress in exploration and subsea production technologies has enabled the development of LNG projects that monetize gas reserves located in difficult-to-reach offshore and deepwater locations. An FPSO can be used when oil is discovered, but the associated gas usually must be reinjected because export by pipeline is not economical.

The concept of floating liquefied natural gas (FLNG) is now seen as a leading solution to monetize these types of gas TABLE 3. Comparison of Skikda and Qatargas II LNG plants Skikda

Qatargas II

Startup date

1972

2009

Capacity, trains ⫻ MMtpy

3 ⫻ 1.0

2 ⫻ 7.8

Liquefaction process

Tealarc APX (three cycles— (one MR cycle propane, MR, nitrogen) at two pressures)

Nitrogen removal

Yes

Yes

Sulfur recovery units

No

Yes (2 ⫻ 600 tpd)

Refrigerant compressors and drivers

Axial; steam turbines

Centrifugal; Frame 9 gas turbines and EM helpers

Cooling medium

Seawater

Cooling water loop/ seawater

Rated power refrigerant compressor drivers, MW

240

1,050

Fuel gas consumption, MMtpy

0.45

1.25

Energy auto-consumption 15%

8%

Concrete, m3

40,000

215,000

Peak workforce (direct)

2,000

13,500

Execution phase duration (first LNG cargo)

48 months

42 months

Pipeline gas

LNG export

LNG tankers

Liquefaction technology

Cascade, three cycles SMR

Acid gas removal

MEA

Refrigerant compressors 1 propane and drivers 1 ethylene 2 methane Steam turbines

ergy from gas turbine exhaust and also use excess compressor driver output for electric power generation.

Trucks

Formulated MDEA 1 MR

FIG. 8. The Camel plant (left) and the Ningxia Hanas SSLNG plant (right).

EM

Exchangers

Kettles/coil-wound heat exchanger (CWHE)

CWHE

Tank

38,000 m3 (in-ground)

50,000 m3 (full containment)

Power generation within battery limits

Yes

No (external grid)

Cooling medium

Seawater

Air cooling

FIG. 9. The Skikda plant (left) and Qatargas II Trains 4 and 5 during construction (right).

Hydrocarbon Processing | JULY 2012 51

90 Years of Progress in the HPI resources. Shell was the first company to invest in FLNG, for the development of its Prelude field offshore Australia. Today, practically all major oil and gas companies have launched FLNG programs. The development of FLNG technology has built on the combination of expertise gained from large oil FPSOs, the latest developments in liquefaction processes, experience with production on floating platforms and LNG storage, and innovation in new offloading technologies. Challenges to LNG development in a marine setting include: • LNG tank sloshing • Offloading LNG between two vessels in the open sea . 0% ƍ %. (!

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FIG. 10. FLNG project regions and incentives.

• Importing large quantities of high-pressure feed gas through a swivel.

The adaptation of large gas processing facilities to marine environments includes: • Compact designs • Development of equipment for motion—a challenge for large columns and separation equipment • Stringent environmental regulations • High reliability and reduced maintenance • High flexibility and turndown.

Several FLNG projects are at conceptual or advanced FEED stages for various locations around the world (FIG. 10). Shell’s Prelude FLNG (FIG. 11), one of the first FLNG projects, will be operating 200 km offshore Australia.3 Prelude is designed to produce 3.6 MMtpy of LNG from sulfur-free natural gas, along with LPGs and C5+ condensate.

Gas-to-liquids. The Fischer-Tropsch (FT) conversion process

is a technology for the production of long-chain paraffins from a syngas mainly composed of H2 and CO. The liquid products from FT conversion can be processed into high-value liquid fuels, lube oils and specialty waxes. The syngas feeding the FT conversion unit can be sourced from any carbon-containing primary feed, such as solid feeds (coal, coke, biomass, etc.), heavy hydrocarbon liquid residues from oil refineries or natural gas.

While the conversion of coal to motor fuels—or coal-toliquids (CTL) production—was the focus of original FT technology developments around 80 years ago, the main interest is now directed toward gas-to-liquids (GTL)—i.e., the conversion of abundant natural gas resources to competitively priced, high-quality liquid products. FIG. 12 depicts the production process for GTL. It is only in the last 15 years that industry attention has seriously focused on this monetization route. LNG and GTL are complementary industries. The interest of major oil and gas companies in GTL is supported by multiple incentives, as listed below. • GTL can be an alternative solution to crude oil market tensions when oil prices are high worldwide, driven by increasing demand for transportation fuels in developing economies.

Gas is more abundant and, depending on location, prices are low relative to oil. In particular, the shale gas revolution in North America promises a durably low-cost feedstock.

FIG. 11. Shell Prelude FLNG 3D model.

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90 Years of Progress in the HPI • Demand for low-sulfur diesel is increasing, and there is interest in GTL-based kerosine for aviation use. GTL products are valuable blending components for the diesel and jet fuel pools, enabling refiners to meet the most stringent requirements.

• Zero-flaring policies are in force in many countries.

• GTL can provide a solution for monetizing stranded gas reserves.

• Infrastructure for the transport and distribution of liquid fuels is already in place and can be used to market GTL products.

GTL has benefited from general developments in gas processing technology that have been driven, to some extent, by the LNG sector. Specific GTL developments that have contributed to the technology’s strong position include innovation in reactor and catalyst designs by Sasol and Shell, and the development of large air separation units and methane reformers for syngas production.

Proven commercial technologies for the generation of FT syngas from natural gas are available from applications in the fertilizer and refining industries: • Steam methane reforming for a high H2:CO ratio in syngas • Autothermal reforming for an intermediate H2:CO ratio • Partial oxidation for a low H2:CO ratio.

The optimum solution must be determined on a case-bycase basis, but the industry’s interest is focused on autothermal reforming and partial oxidation configurations, with the potential combined use of gas-heated reformer technology.

GTL technology developments have centered on different FT reactor concepts (fixed bed, fluidized bed or slurry) and catalysts (iron or cobalt based). Although several technologies are at the demonstration-plant stage, only two commercially and technically proven technologies are in use at largecapacity plants.

Sasol has strong experience in FT from coal gasification in South Africa, and it operates two GTL plants: the 23,000-bpd Mossel Bay GTL refinery in South Africa and the 34,000-bpd Oryx GTL plant (FIG. 13). Oryx GTL, a joint venture with Qatar Petroleum, was the first GTL plant in Ras Laffan, Qatar. It was commissioned in 2006.2 This plant processes treated gas produced from neighboring gas plants in Ras Laffan. Meanwhile, Shell technology has been applied at the 14,700-bpd Bintulu GTL plant in Malaysia and also at the 140,000-bpd Pearl GTL plant in Ras Laffan, Qatar. The Pearl GTL facility, which opened in 2011, is the largest in the world.

A positive outlook for gas. The use of natural gas on a large

scale appeared relatively late in the 90-year period since Hydrocarbon Processing was first published.

With high and rapidly increasing proven gas reserves worldwide, we anticipate that the natural gas industry will continue to grow and to diversify into markets where usage is still developing. Gas will represent a larger share of the energy mix in fast-growing economies such as India and China, and a significantly bigger share of the transportation fuel market worldwide, either as LNG or as synthetic liquid fuel.

The technologies needed to shape this transformation exist and have been proven on a large scale. New innovations that drive down costs and increase efficiency, while at the same time adapting to the challenges of harsh offshore and arctic environments are needed.

Naphtha Natural gas Oxygen

Natural gas reforming

Fischer-Tropsch conversion

Product upgrading

Diesel Kerosine

FIG. 12. GTL production process flow diagram.

FIG. 13. Oryx GTL plant, Qatar.

ACKNOWLEDGMENT Technip has a longstanding involvement in this gas value chain and has been a partner in many first-of-a-kind developments in gas production and processing.

Projects include oil and gas field development; gas treatment; natural gas liquids recovery; liquefied natural gas production (both in onshore and offshore locations); gas-to-liquids production; and applications for ammonia/urea, hydrogen, ethylene and petrochemical derivatives. Technip, founded in 1958, has a history that follows a period of gas industry globalization and intense growth to which the company contributed many landmark projects.

NOTES Designed and built by Technip 2 Built by Technip 3 Technip, in collaboration with Samsung is executing the first FLNG project 4 Technip/Wieland enhanced tubes

1

JOËLLE CASTEL is the chief process engineer and technology officer for gas and sulfur technologies at Technip in Paris, France. She has more than 35 years of experience in the oil and gas industry, either as a process manager or as a technical advisor. Ms. Castel holds degrees in chemical engineering from Ecole Nationale Supérieure des Mines, France and IFP School, France.

DOMINIQUE GADELLE is the deputy vice president of the process and technologies division at Technip in Paris, France. He has more than 15 years of experience in the oil and gas industry, and he was previously in charge of the LNG process engineering department at Technip in France. He is a member of the Gas Processors Association and the author of several papers and presentations. Mr. Gadelle received a BS in chemical engineering from Université de Technologie de Compiègne in France.

PHILIP HAGYARD is the senior vice president of Technip’s LNG/GTL product business unit. Mr. Haygard joined Technip in 1982 and has been working in the LNG sector for most of his career. He was the manager of gas and LNG process engineering at Technip in France during Nigeria LNG, Yemen LNG and the Qatargas projects. In his current role, he has helped position Technip for recent awards in LNG, FLNG and mid-scale LNG. Mr. Haygard is a chartered chemical engineer in the UK. MOHAMED OULD-BAMBA has served as the vice president of Technip’s LNG/ GTL product business unit since 2007. He has spent most of his career in process engineering, covering all aspects of process design, conceptual studies and detailed design of the gas value chain. He also has experience in site activities for gas treatment plants, and he served as the process manager for Technip’s EPC contract for Qatargas II. Mr. Ould-Bamba is a member of the Gas Processors Association Europe management committee and is the author of several papers and presentations. He holds degrees in chemical engineering from Ecole Nationale Supérieure des Industries Chimique, France and IFP School, France.

Hydrocarbon Processing | JULY 2012 53

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Special Report

90 Years of Progress in the HPI M. S. MANNAN, A. Y. CHOWDHURY and O. J. REYES-VALDES, Mary Kay O’Connor Process Safety Center, Artie McFerrin Department of Chemical Engineering, Texas A&M University System, College Station, Texas

A portrait of process safety: From its start to present day

Process safety: An ongoing phenomenon. The driving

force for process safety has been primarily based on catastrophic events. With an increasing number of tragic incidents, the process industry and governments started taking initiatives to minimize loss of life and property, as well as to protect the environment. In the US, safety regulations started back in 1899 when the US government issued the River Harbor Act to avoid excess dumping in waterways. At the beginning of the 19th century, especially in the mines, thousands of innocent lives were lost because of the hostile environment. The year 1910 was reported as the worst, with 1,775 deaths in mines.2 These tragedies forced governments and local establishments to initiate regulatory regimes. In order to understand the growth of process safety, we have divided the significant initiatives and incidents into three broad sections. This categorization is based on the changes that took place between years 1930–1970, 1970–2000 and 2000–2012. This is shown in FIG. 1.

From 1930–1970. This period was mostly about establishing regulations. The Walsh-Healy Public Contracts Act in 1936 in US restricted working hours and employing child labor.1 This

TABLE 1. Other regulations between 1936–19691 Year

Regulation

1952

Coal Mine Safety Act

1966

Metal and Nonmetallic Mine Safety Act

1969

Construction Safety Act

1969

Coal Mine Health and Safety Act

All about regulations

Learning from accidents

2000–2012

trial revolution. Each technical progression has brought with it a certain amount of threat and hazardous activity. Chemical process safety was not a major public concern prior to almost the end of the 18th century. However, safety concerns were always there from the beginning of industrialization but not necessarily as we know or call it today. The primitive instinct of human beings to stay alive and protect themselves is probably the most visceral driver for the growth of process safety initiatives.1

1970–2000

Background. The 19th century is known as the era of indus-

act also was concerned with occupational diseases, a basis of many present safety regulations. The 1947 presidential conference on industrial safety was another noteworthy step forward.

Some other regulations were established in the years 1936–1969 (see TABLE 1). Individually, these acts did not have major impact in ensuring industrial safety but they played an imperative role for process safety to reach the position that it has achieved.

Congress passed the Occupational Safety and Health Act in 1970, which is a landmark legislation that put into motion programs that continue to evolve. Under this act, the Department of Health established the Occupational Safety and Health Administration (OSHA) with wide-ranging authority to enforce safety and health standards to ensure a safer workplace.1 Also, the US Department of Health and Human Services instituted the National Institute for Occupational Safety and Health (NIOSH) which had the responsibility to conduct research, provide recommendations to OSHA and train professionals for increasing awareness.1 In addition, the US Environmental Protection Agency (EPA) was established in 1970 to address environmental issues.

From 1970–2000. In the 1970s and 1980s, some of the world’s most shocking and tragic industrial accidents took place. Consequently, industries and government bodies everywhere were forced to rethink about the technology and management systems in industries from the safety point of view. FIG. 2 offers a timeline of the catastrophes during this time period.

1930–1970

By looking at the history of process safety and the improvements that each decade has brought in terms of regulations and techniques, industry can invariably make itself safer. Determining how major incidents such as Bhopal, Flixborough, Chernobyl, Piper Alpha and others have influenced the industry, academia, government and subsequent regulations can offer a firm foundation for future endeavors. There is still research needed in the near future to further cement the foundation, and researchers and process safety experts need to pay attention to what incidents of this millennium are telling us about what is still needed in order to make process safety second nature.

Process safety in the new millennium

FIG. 1. Broad classification of process safety development based on time period.

Hydrocarbon Processing | JULY 2012 55

90 Years of Progress in the HPI The Flixborough explosion in 1974 was by far the most severe disaster in the UK chemical industries and proved to be a major driver for process safety issues in the UK. As a result of these initiatives, at the end of 1974, the Advisory Committee on Major Hazards (ACMH) was implemented. The impact of Flixborough was reinforced by that of the Seveso tragedy in 1976.3 However, the unforgettable Bhopal gas disaster in India on December 3, 1984, which resulted in varying estimates of 3,000 to upward of 20,000 fatalities and injuries to another 500,000, was a wake-up call for the chemical process industry.

Both the industry and the public became aware of the potential hazard of chemical facilities.2 This piloted the intensification of efforts within industry to ensure the safety of major hazard plants. Process safety finally gained absolute recognition as a standard practice. After the Bhopal tragedy, many regulatory initiatives were taken worldwide. In India, the Environment Protection Act (1986), the Air Act (1987), the Hazardous Waste (Management and Handling) Rules (1989), the Public Liability Insurance Act (1991) and the Environmental Protection (Second Amendment) Rules (1992) were promulgated.3 In 1984, the Mexico City disaster represented the largest series of boiling liquid expanding vapor explosions (BLEVEs) in history that killed almost 500 people.3 The nuclear disaster which took place on April 28, 1986, in Chernobyl, Ukraine, killed 56 people and caused the development of cancer and radiation sickness in many.3 The Piper Alpha accident on July 6, 1988, resulted in 167 deaths. The Piper Alpha Inquiry has been of crucial importance in the development of the offTABLE 2. Significant initiatives in the US4 Year

Initiative

1985

Center for Chemical Process Safety (CCPS) established under AIChE5

1986

Superfund Amendments and Reauthorization Act (SARA) signed

1987

Emergency Planning and Community Right-to-Know Act (EPCRA) signed as final rule for hazardous-chemical reporting that introduced the material safety data sheet (MSDS)6

1990

The Clean Air Act Amendments (CAAA)7

1992

OSHA promulgated the process safety management (PSM) standard under 29 CFR 1910.1198

1996

US EPA promulgated the Risk Management Program (RMP)9

1998

US Chemical Safety and Hazard Investigation Board (CSB) established10

shore safety regime in the UK sector of the North Sea. On October 23, 1989, in the Phillips 66 plant in Pasadena, Texas, a massive gas explosion caused the death of 23 people and more than 300 injuries. 3 These incidents made it even more evident that implementation of safety legislation was indispensably necessary. TABLE 2 and TABLE 3 show the significant legislative and regulatory steps taken in the US and Europe.

Process safety in the new millennium. Process safety has

certainly made remarkable progress. However, it is still impossible to adequately answer a simple question, “Are we safe enough?” The incidents that occurred in this millennium are a reminder that process safety has a long way to go.

The Columbia disaster on February 1, 2003, caused the death of all seven astronauts onboard and scattered shuttle debris over 2,000 square miles of Texas.11 This tragic incident can be traced back to flaws in decision making at NASA. The Columbia explosion was an important lesson for crisis communication professionals, as well. In fact, the NASA lessons can be mapped to many other catastrophes, such as the Piper Alpha or the Flixborough incidents, that reveal a sense of vulnerability, establish an imperative for safety, and reinforce the need for valid on-time risk assessments.11 The Macondo blowout in the Gulf of Mexico (GoM) on April 20, 2010, killed 11 employees and led to an uncontrolled oil spill lasting 87 days.12 This blowout was the most significant offshore incident in the US, and it had a profound impact on safety regulations in the GoM. The Drilling Safety Rule regarding well-bore reliability and well-control equipment was implemented on October 14, 2010. The Modified Workplace Safety Rule was put into place on October 15, 2010, based on the lessons learned from the Macondo blowout.

Finally, there was the Fukushima Daiichi nuclear plant incident in March 2011 that drew the attention of the global process and power industries, encouraging them to incorporate natural disaster risks in a hazard analysis study.12 Technical achievements pre-1970. Techniques to identify and evaluate hazards, calculate consequences and quantified event probabilities and risk (such as What-If, Checklist, HAZOP, Fault- and Event-Tree analyses) were developed in the middle of the 20th century. These developments occurred in some cases years or even decades before the well-known major incidents in the 1970s and 1980s. However, these catastrophic incidents reflected the need for more understanding and research regarding the underlying issues about process

TABLE 3. Significant initiatives in Europe4 Year

Initiative

1974

Flixborough incident report introduced consequence modeling and risk assessment

1981

Second Canvey Report included additional hazard models and injury relationships (HSE, 1981)

1984

Control of Industrial Major Accident Hazards (CIMAH) Regulations established, which implemented the European Union Seveso Directive

1996

The Seveso Directive was replaced by the Seveso II Directive

1999

The Control of Major Accident Hazards (COMAH) Regulations (HSE, 1999) was established

56 JULY 2012 | HydrocarbonProcessing.com

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90 Years of Progress in the HPI safety incidents. For example, the HAZard and OPerability (HAZOP) study, was developed by ICI in 1963, when a team was looking for ways to design a plant for phenol production with the minimum capital cost, but was considering possible deficiencies in the design.13 The Flixborough and Seveso incidents clearly showed the importance of identified hazards before fatal incidents occur, and HAZOP gained extensive popularity within operating and design companies. In the case of the Flixborough disaster, more than 40 tons of cyclohexane were released due to the rupture of a temporary bypass line. The temporary pipe was designed by a person who did not know how to design large pipes operating at high temperatures. After this incident, companies started to include procedures for management of change (MOC). Fault tree analysis (FTA) was developed in the early 1960s, and its use as a safety system and reliability technique quickly gained widespread interest, especially in nuclear and power installations. Since the development of FTAs, great efforts and advances (analytic methodologies, computer programs, computer codes) have occurred in the quantitative evaluation of fault trees.14 Technical achievements: 1970s and 1980s. In the US and Europe, models for pool formation, releases, evaporation and fire and explosions were refined in the late 1970s and the early 1980s.15 In these two decades, a series of fatal incidents (FIG. 3), reinforced the importance of these models and were one of the principal motivations for further research and improvements.

Bhopal increased substantially the interest and activity of the research and academic communities in a wide range of areas related with process safety,2 principally in reactivity hazards (employees did not have knowledge of the reactivity of MIC mixed with water16), inherent safety and chemical reTABLE 4. Research needed based on recent incidents Year

Incident

Area(s) of research needed

2003

Columbia

Safety culture Risk assessment

2005

BP Texas City

Facility siting Fatigue

2005

Buncefield

Vapor cloud explosion Tank farm consequence models Pool fires

2007

T2 laboratories

Reactive chemicals

2008

Imperial Sugar

Dust explosion

2011

Fukushima

Nuclear safety

1974

1976

1984

1986

1988

1989

Flixborough

Seveso

Bhopal

Chernobyl

Piper Alpha

Phillips

HAZOP MOC

Mexico City Reactive chemicals releases Inherent safety

Chemical releases VCE BLEVEs

Fires Explosions Offshore QRA

Safety culture

FIG. 3. Research motivated by major disasters in the 1980s.

58 JULY 2012 | HydrocarbonProcessing.com

Management systems VCE Flammability

leases. The 500 deaths involved in Mexico City clearly demonstrated the importance and hazards involved in BLEVEs.3 Piper Alpha focused attention on jet fires, pool fires, carbon monoxide fires (initial CO poisoning caused most of the deaths) and explosions in modules with turbulence generation.17 This incident, and the sinking of the Alexander L. Kielland in 1980, were the most important events in the history of offshore operations in Europe, and together made a great impact in the use of quantitative risk assessment (QRA) techniques to assess offshore facilities.18 The aftermath of the Chernobyl disaster gave birth to the safety culture concept.19 According to the Phillips report,20 the cause of the incident was a modification in a routine maintenance procedure. This reinforced to the process industry the importance of incorporating management systems, such as MOC procedures. The 1970s and 1980s were decades of major incidents and great losses, but there is no doubt that these two decades made a great impact on what today we call “process safety.”

Technical achievements: 1990s to present day. During the 1990s, in response to new regulations and regulatory initiatives, collection of incident history data started at a rudimentary level. Advances in technology and the research conducted by different centers, such as the Mary Kay O’Connor Process Safety Center (which was established in 1995), allowed for the development and availability of increasingly reliable incident databases.21 In the late 1990s, the Chemical Safety Board (CSB), in its MOC safety bulletin, highlighted the importance of having a systematic method for MOC, and how this is an essential ingredient for safe chemical process operations.

In the 1990s and early 2000s, the development of engineered nano-materials increased considerably. This development introduced a new area of research to process safety, an area where researchers are trying to understand the workplace exposure and environmental aspect of nanotechnologies.

Research needed in the near future. There is no doubt that the field of process safety has made great advances in terms of regulation and techniques in the last 40 years, but industry changes every day, and more sophisticated and complex processes are developed. This, combined with factors such as human errors (which will be always present), and challenges in creating and maintaining organizational memory, among others, is the reason why incidents continue to occur. Fatal incidents in this new millennium highlighted some of the areas of process safety where research is still needed (TABLE 4).

Dust explosion. Dust explosion research has been conducted on and off for more than 100 years.22 However, events such as the Imperial Sugar Co. incident in Georgia (14 deaths, 14 life-threatening burns, 38 total injures23) demonstrate the need for further research, awareness and management systems.

In order to prevent these kinds of incidents, it is imperative to perform experimental and theoretical work to understand the chemistry and physics of dust cloud generation and combustion, flame propagation and potential ignition sources. It is also important to understand and develop models for fire and explosion of nano-materials.

Reactive chemicals. Reactive chemistry incidents continue to occur in the chemical processing industry, and in other

DIRECTOR OF INNOVATION

For 80 years you’ve inspired some of our best products.

Every innovation. Every solution. We’ve made them better with your help. By listening to your feedback and using it to innovate what’s next. The Air-Pak 75i is a perfect example. Thanks for all the good ideas.

you’re the expert. let’s talk innovation. join us on facebook. © 2012 Scott Safety. SCOTT, the SCOTT SAFETY Logo and Scott Health and Safety are registered and/or unregistered marks of Scott Technologies, Inc. or its affiliates.

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90 Years of Progress in the HPI industries which handle chemicals in their manufacturing processes. A CSB study, released in 2002, identified 167 reactive incidents that occurred between 1980 and 2001, which caused 108 deaths.24 More experimental and theoretical research is necessary to fully understand the kinetics and thermal behavior of industrial chemical reactions.4

Safety culture. The tragic Columbia shuttle incident showed the possible fatal consequences of bad industrial communication. It is important that research and safety professionals understand and evaluate good safety culture that enables the sharing of information and improvement of safety within the industries, taking into account different specialties and environments.

Top 10 worst process safety incidents in history This article discusses what the Mary Kay O’Connor Process Safety Center at Texas A&M University in College Station, Texas, consider the top 10 process safety incidents in history. The incidents were ranked based on the cumulative impact on loss of lives and economic losses, and the resulting impact on the development of what today we know as process safety.

1. Bhopal. On the early morning of December 3, 1984, at the Union Carbide plant in India, a storage tank containing methyl isocyanate (MIC) was contaminated with water leading to a runaway reaction causing the release of more than 40 tons of toxic MIC gas through a relief valve. The incident killed more than 3,000 people and injured hundreds of thousands more. This was arguably the worst chemical industry incident in terms of people affected, however; it was just after this fatal tragedy that the chemical process industry became really conscientious of the importance of process safety and it gained complete acceptance as a standard practice.1 As a direct response to Bhopal, many regulatory initiatives were implemented worldwide. In India, this event led to the Environment Protection Act (1986), the Air Act (1987), the Hazardous Waste (Management and Handling) Rules (1989), the Public Liability Insurance Act (1991) and the Environmental Protection (Second Amendment) Rules (1992). In the US, the Emergency Planning and Community Right-to-Know Act (EPCRA) was promulgated in 1986,2 and the Clean Air Act Amendments (CAAA) were signed into law in 1990.1 2. Chernobyl. On April 28, 1986, in a power plant in Chernobyl, Ukraine, an experiment performed in order to verify the emergency power supply of a reactor resulted in unfortunate consequences. The core of the reactor was blown out by two violent explosions causing a series of fires and the release of tons of radioactive materials. It is considered to be the worst nuclear disaster in history. The incident directly killed 56 people and influenced the development of cancer and radiation sickness of hundreds in the subsequent years.3 Before the incident, there were no written rules for the test that led to the catastrophic consequences. This fact has made the adherence to safety-related instructions as the most highlighted lesson learned regarding to process safety.4 3. Piper Alpha. Piper Alpha was a North Sea oil production platform. On July 6, 1988, the backup condensate pump pressure safety valve was removed for routine maintenance.

60 JULY 2012 | HydrocarbonProcessing.com

However, since the maintenance could not be completed within the shift, it was decided to complete the remaining work the next day. As a temporary measure, the condensate pipe was sealed with a blind flange. Communication gaps between different shifts resulted in a catastrophe when the night shift crew unknowingly started the backup condensate pump after the failure of the primary pump. In just 22 minutes, fire broke out everywhere and the event escalated further because of design and operational flaws resulting in 167 deaths. The Piper Alpha incident was a wakeup call for the offshore industries. Significant changes in safety practice include development and implementation of safety case regulations in UK, adherence to a permit-to-work system and realistic training for emergency response.4 4. The Macondo blowout. The Macondo exploration well located in the Gulf of Mexico (GoM) was drilled by a deep water horizontal semi-submersible rig. On April 20, 2010, a blowout caused a fire and explosion on the rig that killed 11 employees and caused a major oil spill that continued uncontrolled for 87 days. A series of mechanical failures, lack of human judgment, faulty engineering design and improper team interaction came together to result in the largest oil spill known to mankind. The blowout was the biggest offshore incident in the US and it had a profound impact on safety regulations in the GoM. As a direct outcome of the Macondo incident, the Drilling Safety Rule regarding wellbore reliability and well control equipment was implemented on October 14, 2010. The Modified Workplace Safety Rule was also implemented on October 15, 2010, based on the lessons learned from the Macondo blowout.5–6 5. BP Texas City. On March 23, 2005, during the startup of an isomerization unit, the safety relief valves of a distillation tower opened due to overfilling, allowing hydrocarbon liquids to flow into a disposal blowdown drum with a stack, which were also overfilled, resulting in a liquid release. The evaporation of the hydrocarbons produced a flammable vapor cloud that ignited and led to a series of fires and explosions. Fifteen workers died and about 180 were injured.7 This incident led to major investigations including the milestone Baker panel report headed by former US Secretary of State James Baker III. This incident also resulted in significantly more interest in and attention to issues such as facility siting, atmospheric venting, leading and lagging indicators and safety culture.

90 Years of Progress in the HPI 6. The Flixborough disaster. On June 1, 1974, in a caprolactam production plant, a temporary bypass line ruptured, resulting in the leak of almost 40 tons of cyclohexane that caused a huge vapor-cloud explosion. The tragic disaster killed 28 people including all the employees working in the control room. There was the alarming possibility of killing more than 500 employees if it were a normal working day instead of weekend. Also, widespread damage to property within a 6-mile radius around the plant was another major consequence. The Flixborough explosion was a critical driver in moving process safety issues forward in the UK. As a result of the Flixborough incident, at the end of 1974, the Advisory Committee on Major Hazards (ACMH) was formed. The lessons learned from this disaster highlight the importance of HAZOP analysis, blast resistant control rooms and thorough studies prior to any modification in process plants.4 7. Mexico City. On November 19, 1984, in an LPG installation in Mexico City, the failure of the safety valve of an LPG storage tank caused an overpressure inside the tank and a pipe rupture, leading to a leakage of LPG followed by an ignition and violent explosions. Approximately 500 people were killed and more than 700 were injured.9 This incident represents the largest series of boiling liquid expanding vapor explosions (BLEVEs) in history.4 Mexico City clearly demonstrated the risk of BLEVEs in process facilities and lessons learned from this event have significantly impacted standards for design and operation.

8. Phillips. On October 23, 1989, in the Phillips 66 plant in Pasadena, Texas, the rupture of a seal on a polyethylene reactor caused the release of highly flammable ethylene and isobutene gas, forming a gas cloud and leading to a massive explosion in less than two minutes. Twenty-three people were killed and more than 300 injured. The day before the incident, a maintenance procedure had been performed by contractor personnel. This incident underscored the importance of rigid adherence to operating procedures and the implementation of an appropriate management system for contract workers. In response to this incident and other incidents that occurred before in the 1980s (including Bhopal, Shell Norco, Arco Channelview and Exxon Baton Rouge), the US Department of Labor, Occupational Safety and Health Administration developed the Process Safety Management (PSM) regulation.10 9. Columbia disaster. The physical cause of the Colum-

bia shuttle disaster was separation of insulation foam that then hit the carbon–carbon reinforced panel of the left wing, thus damaging the thermal protection system. Aerodynamic pressure caused by superheated air destroyed the wing when the shuttle was reentering earth’s atmosphere at about 10,000 mph on February 1, 2003. The tragic incident caused the death of all seven astronauts and resulted in shuttle debris being scattered over 2,000 square miles in Texas. However, the underlying causes for the disaster

can be traced back to flaws in decision making at NASA. The Columbia incident also provided important lessons for crisis communication professionals, as well. In fact, the lessons learned from the Columbia incident can be mapped to many other catastrophes such as the Piper Alpha or the Flixborough incident, covering issues such as sense of vulnerability, establishing an imperative for safety and valid ontime risk assessment.11 10. Fukushima Daiichi nuclear incident. On March 11,

2011, this incident drew the attention of the process and power industries around the world, encouraging them to incorporate natural disaster risk in any hazard analysis study.

When a powerful earthquake hit the plant, the reactors shut down automatically. However, because of the earthquake and the following tsunami, a power blackout ensued, leading to the loss of cooling, which, in turn, led to overheating of the reactors (creating serious radiation hazards). Fortunately, no one was killed because of the radiation, but there may be long-term consequences to the workers and to the neighboring communities who were exposed to radiation.

Conclusions. These tragic events and the consequences

of these events have provided us with numerous lessons that help our understanding of the hazards and risks of the modern process industry and, more importantly, how design, technology, equipment, management systems, human factors and safety culture can be used to improve the safety performance of the industry. Understanding the root causes of incidents and learning from mistakes within the company, as well as other organizations, is vital. These lessons need to be implemented both in the engineering and the management sectors.

LITERATURE CITED Mannan, M. S., et al., “The legacy of Bhopal: The impact over the last 20 years and future direction,” Journal of Loss Prevention in the Process Industries, 2005.

18(4–6): pp. 218–224.

2 Mannan, M. S., J. Makris and H. J. Overman, Process Safety and Risk Management Regulations: Impact on Process Industry, Encyclopedia of Chemical Processing and Design, ed. R. G. Anthony, Vol. 69, Supplement 1, pp. 168–193, Marcel Dekker, Inc., New York, 2002.

3 Dara, S. I. and J. C. Farmer, “Preparedness Lessons from Modern Disasters and Wars,” Critical Care Clinics, 2009. 25(1): pp. 47–65.

4 Mannan, M. S., Lees’ Loss Prevention in the Process Industries, 3rd Edition, Elsevier, 2005.

5 McAndrews, K. L., “Consequences of Macondo: A Summary of Recently Proposed and Enacted Changes to US Offshore Drilling Safety and Environmental Regulation,” Society of Petroleum Engineers Americas E&P Health, Safety, Security and Environmental Conference, Houston 2011.

Available online: http://www.jsg.utexas.edu/news/files/mcandrews_ spe_143718-pp.pdf, accessed on March 16, 2012.

7 Kaszniak, M. and D. Holmstrom, “Trailer siting issues: BP Texas City,” Journal of Hazardous Materials, 2008. 159(1): pp. 105-111.

8 Snorre, S., “Comparison of some selected methods for incident investigation,” Journal of Hazardous Materials, 2004. 111(1–3): pp. 29–37.

9 C.M, P., “Analysis of the LPG-disaster in Mexico City,” Journal of Hazardous Materials, 1988. 20(0): pp. 85-107.

10 Guidelines for Vapor Cloud Explosion, Pressure Vessel Burst, BLEVE, and Flash Fire Hazards, 2nd Edition, August 2010, Process Safety Progress, 2011. 30(2): p. 187.

11 American Institute of Chemical Engineers (AIChE), Lessons from the Columbia Disaster-Safety and Organizational Culture, Center for Chemical Process Safety, 2005.

1

Hydrocarbon Processing | JULY 2012 61

90 Years of Progress in the HPI Nuclear safety. The Fukushima incident definitely changed the risk perception of nuclear power plants. Managers and researchers have a long journey in both risk communication and risk assessment models of nuclear power plants.

Make safety second nature. Although “process safety” was

not recognized as a practice or discipline before the mid-1980s, concern about the health, safety and environment is intrinsic in human beings and as old as civilization. Great advances in safety regulations and techniques have occurred during the last century. But as industry grows and changes every day, processes present new challenges. Managers, operators and researchers must continue working together to improve their overall safety knowledge in order to make safety second nature.

LITERATURE CITED Mannan, M. S., J. Makris and H. J. Overman, “Process Safety and Risk Management Regulations: Impact on Process Industry,” Encyclopedia of Chemical Processing and Design, ed. R. G. Anthony, Vol. 69, Supplement 1, Marcel Dekker, Inc., New York, 2002.

2 Mannan, M.S., et al, “The legacy of Bhopal: The impact over the last 20 years and future direction,” Journal of Loss Prevention in the Process Industries, 2005.

3 Mannan, M.S., editor, Lees’ Loss Prevention in the Process Industries, Volumes 1–3 (3rd Edition), Elsevier, 2005.

4 Qi, R., et al., “Challenges and needs for process safety in the new millennium,” Process Safety and Environmental Protection, 2012.

5 Berger, S., History of AIChE’s Center for Chemical Process Safety, Process Safety Progress, 2009.

6 US Environmental Protection Agency, The Emergency Planning and Community Right-to-Know Act (EPCRA) Enforcement,EPA 550-F-00-004, March 2000,

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available at: www.epa.gov/osweroe1/docs/chem/epcra.pdf, accessed on: March 15, 2012.

US Environmental Protection Agency, The Clean Air Act (1990), available online at: www.epa.gov/air/caa/, accessed on: March 15, 2012.

8 US Occupational Safety and Health Administration, ProcessSafety Management (PSM) 2010, available online at: www.osha.gov/Publications/osha3132.pdf, accessed on: March 15, 2012.

9 US Environmental Protection Agency, Risk Management Plan (RMP) Rule (updated 2009), available online at: www.epa.gov/osweroe1/guidance.htm#rmp, accessed on March 16, 2012.

10 Willey, R.J., D.A. Crowl and W. Lepkowski, “The Bhopal tragedy: Its influence on the process and community safety as practiced in the United States,” Journal of Loss Prevention in the Process Industries, 2005.

11 American Institute of Chemical Engineers (AIChE), “Lessons from the Columbia Disaster—Safety and Organizational Culture,” Center for Chemical Process Safety 2005.

12 McAndrews, K.L., “Consequences of Macondo: A Summary of Recently Proposed and Enacted Changes to US Offshore Drilling Safety and Environmental Regulation,” Society of Petroleum Engineers, Americas E&P Health, Safety, Security and Environmental Conference, Houston 2011. Available online at: www.jsg.utexas.edu/news/files/mcandrews_spe_143718-pp.pdf, accessed on March 16, 2012.

13 Kletz, T.A., Hazop—past and future. Reliability Engineering; System Safety, 1997.

14 Lee, W.S., et. al., Fault Tree Analysis, Methods, and Applications—A Review, IEEE Transactions on Reliability, 1985.

15 Pasman, H. J., et. al., “Is risk analysis a useful tool for improving process safety?”

Journal of Loss Prevention in the Process Industries, 2009.

16 Center for Chemical Process Safety (CCPS), Guidelines for Investigating Chemical Process Incidents (2nd Edition), Center for Chemical Process Safety/AIChE 2003. Available online at www.knovel.com/web/portal/browse/display?_EXT_ KNOVEL_DISPLAY_bookid=931&VerticalID=0, accessed on March 16, 2012.

17 Crawley, F.K., “The Change in Safety Management for Offshore Oil and Gas Production Systems,” Process Safety and Environmental Protection, 1999.

18 Turney, R. and R. Pitblado, Risk assessment in the process industries, Institution of Chemical Engineers.

19 Pidgeon, N.F., “Safety Culture and Risk Management in Organizations,” Journal of Cross-Cultural Psychology, 1991.

20 Company, P.P., A Report on the Houston Chemical Complex Accident, Bartlesville, Oklahoma, 1990.

21 Mannan, M. S., T. M. O’Connor and H. H. West, “Accident history database: An opportunity,” Environmental Progress, 1999.

22 Eckhoff, R.K., “Current status and expected future trends in dust explosion research,” Journal of Loss Prevention in the Process Industries, 2005.

23 US Chemical Safety and Hazard Investigation Board (US CSB), “Investigation Report on Sugar Dust Explosion and Fire,” Report No.2008-050I-GA, 2009.

Available online at www.csb.gov/assets/document/Imperial_Sugar_Report_ Final_updated.pdf, accessed on March 15, 2012.

24 US Chemical Safety and Hazard Investigation Board (US CSB), “Improving Reactive Hazard Management,” Report No. 2001-01-H, 2002. Available online at: www.csb.gov/assets/document/ReactiveHazardInvestigationReport.pdf, accessed on March 15, 2012.

7

M. SAM MANNAN, PhD, PE, CSP, is a chemical engineering professor and director of the Mary Kay O’Connor Process Safety Center at Texas A&M University. He is an internationally recognized expert on process safety and risk assessment. His research interests include hazard assessment and risk analysis, flammable and toxic gas cloud dispersion modeling, inherently safer design, reactive chemicals and run-away reactions, aerosols and abnormal situation management.

AMIRA Y. CHOWDHURY, BS, is a PhD student in materials science and engineering, and a research assistant at the Mary Kay O’Connor Process Safety Center at Texas A&M University.

She is a chemical engineer from the Bangladesh University of Engineering and Technology. Her research interests include hazard assessment and dust explosions.

OLGA J. REYES-VALDES, BS, is a materials science and engineering PhD student at Texas A&M University and research assistant of the Mary Kay O’Connor Process Safety Center. She is a chemical engineer from Universidad Industrial de Santander, Colombia. Her research interests include reactive chemicals and run-away reactions, dust explosion, hazard assessment and risk analysis.

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Special Report

90 Years of Progress in the HPI D. WHEELDON, AVEVA, Cambridge, UK

Impact of advanced engineering and design software on the HPI Anniversaries are always a good opportunity to pause and reflect on the past and to dream about the future. Technology advancements continue to reshape the hydrocarbon processing industry (HPI). The nature of great technological advances seems to be that they begin as interesting curiosities until a key insight releases a cascade of innovation. In the case of the HPI, the great insight was, arguably, the development of the distillation process. In the engineering and design discipline, it was the ability to use computing technology to design and manipulate three-dimensional (3D) models. Here are a few of the keen innovation milestones that shifted project and process design to the next level: Milestone 1: Practical 3D design. Three-dimensional de-

sign has been truly transformational and a dramatic enabler that facilitated the expansion of the global HPI. Today, projects are executed and operated at levels of size and complexity that are only feasible through the use of advanced 3D modeling and powerful information management technologies.

Early computer-aided design (CAD) tools simply sought to computerize the drawing board. CAD methods created digital drawings that, at least, enabled a degree of design reuse. The drawings were still only 2D pictures of the designed object. They did nothing to solve the problem of creating very complex plant designs. This problem had to be addressed by building accurate scale models.

3D design requires a certain minimum level of processing power to be usable. In the 1960s, a tipping point was reached when increased processing power and affordability combined with inspiration in computer science to make 3D a realizable objective. This period of rapid innovation gave rise to two different approaches to 3D: surface modeling and object modeling. Both approaches survive today because they are optimal for different tasks.

Defining a 3D object by describing its surface shape still seems to be the “obvious” approach. This approach is the way that we experience the physical world and the way we manufacture everyday objects. But it quickly became apparent that this is an extremely inefficient way of describing a complex unit.

For example, consider a refinery; it physically consists of many geometric solids such as tubes, spheres, girders and so on. The great insight lay in recognizing the importance of the object itself as a distinct entity. For example, a pump is an object that has many associated attributes. One of these is its 3D form, which can be adequately described by aggregating geometric

solids. This is a very efficient way to use processing power, and it is one key enabler of complex plant design, as shown in FIG. 1.

Milestone 2: Effective clash detection. From an engineering design perspective, arguably the most important advantage of 3D modeling is ease of clash detection (FIG. 2). Discovering during construction that a pipe has to magically pass through a wall, or that pieces of the plant are trying to occupy the same space is expensive, both in the direct rework costs and in construction delays. If one is limited to designing in 2D, avoiding clashes between pipe runs becomes difficult at very low levels of complexity, and is usually impossible in most practical situations. The ability to avoid this from the outset, as the design evolves through the collaborative efforts of many individual designers, is perhaps the greatest single enabler of massive HPI projects. A benefit of 3D technology is the ability to deliver 100% clash-free designs.

Less obvious, but almost as valuable, is the ability to define exclusion zones (known as obstruction volumes) around objects and have these also subject to clash detection. This enables plant designers to accommodate accessibility and safety requirements. Such examples are ensuring that a valve handle can be reached and operated safely, or that access is provided

FIG. 1. The early days of plant design and 3D engineering design today.

Hydrocarbon Processing | JULY 2012 65

90 Years of Progress in the HPI for maintenance tasks such as extracting a heat exchanger bundle. The value of this is harder to quantify, but, critically, it is delivered throughout the plant’s entire service life.

Milestone 3: Merging the 2D and 3D worlds. Return-

ing to the ubiquitous pump, its 3D form is only one among its many attributes. Most important is its relationship as part of a system; what other objects is it connected to?

Process system design is schematic in nature. An engineer designs the system by selecting suitable symbols for items of equipment—pumps, valves, columns, filters and so on—and connecting them together diagrammatically with various specifications of pipe. The result is known as a process (or piping) and instrumentation diagram, or P&ID. Initially, this was a drafting process; the P&ID was just a collection of lines and symbols. But technology quickly enabled the P&ID to be “in-

telligent” by capturing the connectivity between objects. Rules could be applied to limit object selection according to context, or to alert the designer to errors.

But even the most intelligent P&ID still lived in the 2D world. So, for a long time, there existed a disconnection with its embodiment in 3D. Eliminating this has undoubtedly been an important breakthrough. Today, it is possible for a P&ID to be created in, or imported into, the same project model that contains the 3D description. Object-centric data structures ensure that the pump object can be associated with its position in the P&ID, as well its position in 3D space.

This close integration enables automatic verification that the 3D layout correctly corresponds to the P&ID. Indeed, it is now possible to import the P&ID “model” straight into the 3D layout as a connected system of objects, ready for the 3D designer to position and to route the pipes appropriately.

Linking the P&ID and the 3D model is also valuable in plant operations, as anyone who has ever tried to locate a piece of equipment in a plant just by using a P&ID will appreciate.

Linking 2D and 3D is proving to be a powerful familiarization tool, as instruments, valves and equipment items can be identified on a 2D schematic and immediately displayed in a 3D view, as shown in FIG. 3. This can save a lot of wasted time spent crawling around a live plant in search of elusive items.

Milestone 4: Integrated engineering. This 2D-3D inte-

FIG. 2. A 3D model view showing obstruction zones around equipment items. Such models enable clash detection against spaces provided for access or maintenance.

FIG. 3. Current plant design processes are highly concurrent.

Integrating the various types of information enables consistency and efficiency as the design evolves.

66 JULY 2012 | HydrocarbonProcessing.com

gration was an early step along an important, and continuing, evolutionary process to fully integrated engineering information. The previous decades of rapid technology development have given rise to many powerful but mutually incompatible engineering and design applications. We have now reached a point where the limitations imposed by the incompatibilities nullify many of the benefits provided by the applications’ various functions. Overcoming this has been a challenge, and we are not out of the woods yet. But increasing adoption of effective, neutral interoperability standards such as ISO15926, championed by leading vendors and authoritative industry forums such as FIATECH and the POSC Caesar Association, has brought us to another tipping point.

Taking a design from initial concept through to fully detailed and validated completion is an iterative, multi-disciplinary process of progressive refinement. It relies on two key capabilities: robust change control and the integration of all the different types of project information—P&IDs, line lists, electrical and instrumentation (E&I) data, 3D plant layout, 3D equipment models, and so on. But, equally important, this information integration must support wide freedom of choice in selecting individual applications and solutions, rather than being arbitrarily restricted by each individual client’s specific needs, as shown in FIG. 4.

Many great strides have been made in this direction and it continues to be an important area of development because integrated engineering and design (IE&D) offers the plant industries substantial gains, both in capability and efficiency. I believe also that the HPI may come to recognize another important related milestone in the integration of the software tools used for plant and ship design. At present, the full potential of this integration has yet to be widely achieved, but industry developments, such as floating liquefied natural gas

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90 Years of Progress in the HPI (FLNG), point to increasing demand for complex floating projects. The boundaries between plant and marine engineering are rapidly blurring.

Improving productivity in the creation of new assets is important. However, the economic value of such projects is tiny compared to the lifecycle value of all the existing plants in operation, globally speaking. Technology is enabling huge productivity gains. The next two milestones involve different aspects of asset operations.

Milestone 5: Laser technology. Particularly in the HPI, assets require regular upgrading and modification throughout their service lives. This might be to accommodate changes in the product stream, to debottleneck a process, or to comply with new regulatory requirements. But revamp projects pose severe challenges: • Cost of downtime • Onsite hazards • Poor quality as-built data.

The first two challenges demand that fitting new equipment be a simple bolt-in, right-first-time exercise, but achieving this is inevitably compromised by the third.

One cannot assume that design drawings or 3D models accurately represent the as-operating plant. Thus, detailed site surveys are essential. But traditional methods using theodolites and measuring tapes proved inadequate years ago, and photogrammetry has its own limitations. Now the great enabler is 3D laser surveying, which has transformed the modification of as-operating assets so that, here too, accurate clashfree designs are routine.

Laser scanning equipment has advanced rapidly in a few years and so too has the technology to exploit the data collected via laser systems. Early success was achieved by using the scanned “point cloud” model as a 3D template in a 3D modeling application. This enabled a new design to be created, to fit accurately against existing installation, and to identify destruct items such as redundant pipe runs to be removed or re-routed.

Today, this technology foundation supports a growing range of tools for asset management. Increased scan resolution creates near-photographic-quality 3D surveys, enabling a user

FIG. 4. The integration of the different types of engineering and design information is the key to efficient projects.

to quickly check dimensions in 3D. Recent advances now enable reverse-engineering of scanned objects into their equivalents as native, intelligent 3D objects in a 3D plant design application, as shown in FIG. 5. But there are also exciting new developments in using laser survey data in asset management, which lends us to the final milestone.

Milestone 6: Information management. Just as 3D trans-

formed the way in which we create assets, information management (IM) technology is transforming the way we operate them. So far-reaching is IM that here are just a few highlights in which IM is making an impact.

Operating even the smallest plant requires procedures, workflows and record-keeping. But as plant size and complexity have increased over time, the tools used for these functions have lagged behind. As with engineering and design, individual applications have been created to handle specific requirements, but, generally, these have not been integrated to create seamless, enterprise-wide management systems (FIG. 6).

FIG. 5. 3D laser surveying is transforming many aspects of asset management.

FIG. 6. Just as 3D transformed the way in which we create assets, IM technology is transforming the way we operate and manage them.

Hydrocarbon Processing | JULY 2012 67

90 Years of Progress in the HPI This is now changing through the availability of integrated enterprise-asset management (EAM) solutions, the advent of a new generation of “data-agnostic” IM technology, and growing awareness of both the nature of the problem and the tools that can now address it.

EAM solutions exist, and they can manage almost every aspect of plant operations, from work-order processing to recertification of equipment. These can significantly increase efficiency by controlling workflows and ensuring that the right information is available at the right time. Much scope for human error can be eliminated, and better use can be made of valuable skills and costly downtime.

However, even the most powerful EAM solutions encounter limitations if information is not accessible to them. This is a common situation; over time, different applications have led to asset information existing in isolated “silos” created by incompatible data formats. Worse, in many cases, important engineering information remains in paper documents, which are hard to access or cross-reference and are often of doubtful integrity. This represents a massively under-exploited business asset that advanced IM technology can now unlock.

A new philosophy reinforces that, for every physical asset, there should exist a digital counterpart. The efficiency of managing the physical asset is directly related to the completeness, accuracy and accessibility of its digital counterpart. To support this, a new concept—the digital information hub— acts as a central, widely accessible, enterprise-level asset. It integrates, validates and enables users to navigate all information. It enables creating an information counterpart of a physical plant—a “digital plant.” As one can readily walk around the physical plant, now a user can readily navigate the digital plant, moving from the 3D model view to a P&ID, to an equipment maintenance log, to a spares list, and so on.

It is now possible to aggregate all forms of data, whether model views, diagrams, scanned documents, real-time process

FIG. 7. Present-day powerful plant design tools enable efficient execution of solar energy projects, where minimizing both project and lifecycle costs is at a premium. Images courtesy of Iberese.

68 JULY 2012 | HydrocarbonProcessing.com

data or the latest laser scan surveys, into meaningful presentations for almost any purpose. This greatly extends the reach of asset management. This technology is delivering substantial benefits in areas such as project handover, or in “reverse engineering” a digital plant to facilitate more efficient management and regulatory compliance.

Looking ahead. Forecasting in the highly innovative technology industry is always asking to be proved wrong. So what is plausible in the immediately foreseeable future?

More integration of tools and information. Certainly, we will see further advances in integration, both between software tools and information itself. Better applications will always be created, but as much for better interoperability as for sheer productivity. Laser scanning technology will continue to advance, but the real breakthroughs will come in the use of survey data. This trend is clearly visible, with recent innovations adding intelligence to 3D surveys.

Hardware/software access improvements. Engineering applications necessarily lag behind the absolute leading edge of technology development, but the increasing portability of powerful hardware is creating opportunities for more effective ways of accessing and exploiting asset information. For example, one can easily envisage a shift-handover log in the form of a custom report on a tablet computer, instead of a handwritten entry in a log book. But, even here, the big benefit lies less in hardware portability as in the ability for the software to immediately associate the information entered with the objects in the digital plant model. This makes information immediately available to be reviewed, analyzed and acted upon in the full context of the plant’s operational and maintenance records.

Energy resource development. Engineering’s big challenge, of course, is meeting the world’s growing energy demand. There are many uncertainties in this, but it is safe to say that the HPI and oil and gas industry have catalyzed the development of many of the technologies that will be used to meet this demand. These technologies have long been used in thermal- and nuclear-power generation and they are now also being used for impressive projects in stranded gas and renewable energy. The likely rapid growth in FLNG vindicates our strategy of integrating plant and marine design technologies, which I believe will prove an important enabler in this sector.

And it is particularly pleasing to see how advancing products’ features, such as powerful piping design tools, are being put to good use in solar energy projects, in which minimizing both project and lifecycle costs is at a premium (FIG. 7).

DAVE WHEELDON is chief technology officer (CTO) and head of Engineering and Design Systems for AVEVA. His responsibilities encompass all aspects of product strategy, product development and delivery of AVEVA’s integrated engineering and design systems. As group CTO, he directs technology choice and technical direction, together with consistent software engineering processes, and the continuous development of AVEVA’s integrated engineering IT solutions. Mr. Wheeldon joined AVEVA (then known as the CADCentre) in 1981, initially developing process simulation and fluid network modeling applications. He managed the AVEVA PDMS development team during the transition from mainframe to distributed computing, and led the development of automated drawing production and 3D visualization. He also held positions in marketing, IT and product management. He was appointed to the board of AVEVA Solutions in 2003. This year AVEVA celebrates its 45 year anniversary.

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Special Report

90 Years of Progress in the HPI P. MILLER, D. HILL and D. WOLL, ARC Advisory Group, Dedham, Massachusetts

Process control in the HPI: A not-so-sentimental journey As long as there have been hydrocarbon processing industry (HPI) facilities to process crude oil and intermediates, there have been instruments in place to assist plant operators in measuring, recording and controling pressures, flows, levels, temperatures and other process variables. Initially, these were (by today’s standards, at least) crude “Rube Goldberg-like” instruments utilizing ingenious mechanical and/or pneumatic mechanisms.

In the early petroleum refineries and petrochemical plants, many of the control concepts conceived during the Industrial Revolution of the 18th and 19th centuries were further developed, refined and proven. It would be exceedingly difficult, if not impossible, to operate a typical present-day refinery or petrochemical plant without good, closed-loop process control. The continuous, generally steady-state nature of processing liquid petroleum feedstocks and intermediates lends itself to closed-loop feedback control, using a standard set of measurement, control and final control/actuation instruments.

However, with so many process variables, interactions and nonlinearities involved, the process can overwhelm the human mind. Additional challenges include more complex processes and plants, less uniform feedstocks, increasing use of unconventional feedstocks, variable energy costs, and an increasingly difficult regulatory environment. These further increase the reliance on automation and help explain the universal acceptance of sophisticated process control and automation systems in today’s plants.

Anatomy of ‘control.’ While it hasn’t always been the case,

process control is—for the most part—an exacting science made possible by continuous advancements in control theory, processing technologies and process-control instrumentation and systems. These developments enable not just individual control loops, but entire units, plants, and even integrated petrochemical complexes to be operated in a close-to-optimum manner (with “optimum” determined by product cost, quality, yields, throughput and so on). Rather than those quaint, if ingenious, mechanical and pneumatic instruments utilizing basic feedback control, current process measurement and control in HPI plants are performed by networked field instrumentation with more onboard intelligence than early mainframe computers and computer-based process automation systems that are many times more powerful and capable than the NASA control centers that sent the first men to the moon. This article will briefly trace how we got from “point A” to “point B.”

The early years. Modern process control instrumentation

evolved from the basic instruments and devices developed to control prime movers, such as James Watt’s steam engine, during the Industrial Revolution. In the 1850s, following the revelation that crude oil could be refined via distillation into kerosine for lighting purposes, which ended the whale-oil industry, the first petroleum refineries were constructed in Europe and the US. Sensing the opportunity, a handful of instrumentation companies (Honeywell, Fisher, Foxboro, Bailey, Bristol, Taylor, Brown, etc.) began to adapt their temperature, level and pressure gauges, and pen-based, mechanical circular chart recorders to meet the basic measurement and control needs of the early refineries. During this industrial period, control was purely manual, with field operators monitoring the gauges, taking notes and making any needed process adjustments by manually opening or throttling valves. Often, this meant the operator had to move around quite a bit, including climbing up to places that are restricted under current OSHA rules.

In the late 1890s and early 1900s, refineries began to implement automated feedback control using a combination of direct-connected, pneumatically operated instrumentation utilizing ingenious combinations of nozzles, flapper valves, bellows, springs and other mechanisms—all powered by compressed air.

This provided a reasonable degree of on-off control. Separate indicators and chart recorders were often used to provide the human interface and record-keeping functionalities. By combining basic mechanical pressure, level, flow and temperature measurement instrumentation with field-mounted pneumatic controllers and actuator-driven valves, closed-loop feedback control became possible. Fisher Controls (now part of Emerson

FIG. 1A. Indicating/recording pressure gauge circa 1908. Photo courtesy of Invensys Operations Management. 1B. Fisher introduced its field-mounted Wizard 1 pneumatic controller in 1930. Photo courtesy of Emerson Process Management.

Hydrocarbon Processing | JULY 2012 71

90 Years of Progress in the HPI Process Management) introduced its field-mounted Wizard pneumatic controller in 1930, as shown in FIG. 1A. More sophisticated, large-case field-mounted pneumatic instruments incorporating control, indicating and recording functions began to appear on the scene around 1915. Initially, these just provided on/off and/or proportional control capabilities. Foxboro (now part of Invensys Operations Management) introduced the Model 40, the first proportional-plusintegral controller, in 1934–1935. In 1941, Taylor Instruments (now part of ABB) introduced the Fulscope 100, the first controller to provide full proportional/integral/derivative (PID) control capability in a single unit. At present, PID methods remain the workhorse of process control in refineries, petrochemical plants and other process plants around the world.

To avoid tampering by operators who were worried about keeping their jobs in the face of all this “automation,” instrument suppliers had to start putting locks on the cases to keep employees out. While this practice certainly helped secure the

FIG. 2. Large-case pneumatic instruments in a control room at Gulf Oil Co.’s Port Arthur, Texas, refinery. Photo courtesy of Petroleum Refiner, March 1949.

FIG. 3. View of the graphic instrumentation board of Rock Island Refining Co.’s FCC unit. Photo courtesy of Petroleum Refiner, March 1953.

72 JULY 2012 | HydrocarbonProcessing.com

instrument’s integrity, it created many problems when the instrument had to be adjusted or repaired, especially when no one could find the key!

While relatively primitive compared to today’s digital controllers, these early mechanical/pneumatic instruments did a surprisingly good job of controlling process variables. They were so reliable that a number of them are still operating in some older refineries and petrochemical plants.

Move from stand-alone instrumentation to control rooms.

A major breakthrough in process control occurred around 1938 with the introduction of pneumatic transmitters and large-case instruments modified to accept pneumatically transmitted signals from field-mounted transmitters and then sending pneumatic control signals back to valve actuators. For the first time, this made it possible to physically separate the process-measurement instrumentation from the recording/indicating/controlling instrumentation. This led to the appearance of local control rooms in refineries and other process plants, as shown in FIG. 2.

In some cases, these local control rooms were located up to several hundred feet away from the processing units (but no further, due to the distance limitations of the pneumatic signals). With this instrumentation, control room operators could remotely monitor process variables, setpoints and valve outputs, and switch between automatic and manual control.

To ensure that different suppliers’ instrumentation would function properly together, the industry soon established the 3-psi to 15-psi standard signal range for pneumatic transmission, which remains in effect today.

Since control room space in HPI plants is usually limited and always expensive to build, following World War II (WWII), instrumentation suppliers focused on reducing the size of the instruments mounted in the control room. The resulting “miniaturized” controllers typically measured approximately 6-in. by 6-in. on the front faceplate, complete with a built-in indicator. With these smaller instruments, it now became practical to embed the indicators, controllers and recorders in appropriate locations on wall-sized graphical diagrams, as shown in FIG. 3.

These diagrams illustrated the process unit, providing operators with a more intuitive sense of how the instrumentation related to the process. While these graphic panels helped reduce training requirements and enabled operators to monitor process operations more effectively, they still required fairly large control rooms. This led to the development of “semi-graphic” panels. These graphic displays used less space and still provided much of the intuitiveness of full graphic panels.

On the sensor side, suppliers began introducing a number of measurement products during the invigorating post-WWII years that would see wide applicability in the HPI. These included the first pneumatic-differential pressure transmitter, introduced by Foxboro in 1948. In conjunction with a simple flange-mounted orifice plate, this provided a practical and low-cost method to obtain accurate and repeatable fluid flow measurements. In 1956, Beckman Instruments introduced the first gas chromatograph for chemical analysis based on earlier research by A. T. James and A. J. P. Martin.

At around this same time, we started seeing more analog electronic instruments appearing in refinery control rooms.

They were often interfaced to existing pneumatic instruments

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90 Years of Progress in the HPI using current-to-pressure (I/P) and pressure-to-current (P/I) converters. In 1951, the Swartwout Co. introduced its AutroniC, the first electronic controller to use vacuum tubes. At the 1958 Instrument Society of America (ISA) show in Philadelphia, Pennsylvania, Foxboro, Taylor Instruments, Honeywell, and Leeds & Northrup (now part of Honeywell) all demonstrated electronic controllers. In 1959, Bailey Controls (now part of ABB) introduced the first fully solid-state electronic controller, followed shortly by several other instrumentation suppliers. During these years, we also began to see the shift from single-loop to multi-loop electronic controllers. In 1952, several engineers at Shell Development also presented the feasibility of direct digital control (DDC) in the Transactions of ASME (American Society of Mechanical Engineers).

Direct digital control and the dawn of CIM. Exciting

news came in March 1959, with the announcement that—following almost two and a half years of effort—Texaco and the Thompson Ramo Wooldridge (TRW) Co. installed the first direct digital control computer online in a refinery, as shown in FIG. 4. This heralded what would later become known as the computer-integrated manufacturing (CIM) era for the HPI. An excellent article entitled, “Texaco closes the loop,” which appeared in Business Week, April 4, 1959, chronicled the drama: “Shortly before 11 a.m. on March. 12, a veteran Texas Co. process operator named Marvin Voight flipped the switch …

FIG. 4. The Thompson Ramo Wooldridge (TWR) RW-300 direct digital control process control computer was installed at Texaco Inc.’s new No. 1 poly unit at the Port Arthur, Texas, refinery. Photo courtesy of Motiva Enterprises.

FIG. 5. IBM process computer installed in the control room at American Oil Co.’s Whiting, Indiana, refinery. Photo courtesy of Hydrocarbon Processing and Petroleum Refiner, 1965.

74 JULY 2012 | HydrocarbonProcessing.com

The action closed the loop in the first fully automatic, computer-controlled industrial process. Moments later, the most vital parts of the 1,800-bpd polymerization unit at Texaco’s Port Arthur (Texas) refinery were under the unblinking eye and almost instantaneous control of a Thompson Ramo Wooldridge Corp. RW-300, a desk-size digital computer designed for just such control jobs as this. Texaco hopes the computer will raise the plant’s efficiency by a healthy 6% to 10%.”

In addition to TRW, which contributed the computer, the Bristol Co. (now part of Emerson Process Management) redesigned its recording controllers to interface with the computer.

Leeds & Northrup supplied onstream analyzers to chart the chemical content of the raw material and product streams.

The description of the computer’s function provided by Charles Richker, Texaco’s chief process engineer at the time, doesn’t sound all that different than that for a present-day optimization project. The computer … gets an analysis of incoming gas and outgoing gas; it senses and measures pressure, flows and temperatures; it calculates catalyst activity; then it weighs all these together and decides what the processing unit should do to get the most product for the least cost. Finally, it sets the controls and rechecks its figuring.

According to Business Week, the computer cost was $98,000 (in 1959 dollars); the custom I/O required to convert analog measurement signals to digital language cost $36,000; and— not surprisingly—the expense for engineering and extra instrumentation was more than double that of the capital cost for the computer and I/O hardware. So how did Texaco cost-justify this major (for 1959) $300,000 science project? To begin with, apparently, the company would have spent at least one-third of that on new instrumentation for the polymerization plant anyway.

In hard terms, the company anticipated that the new computer would boost conversion efficiency from the 85%–87% considered the maximum for the most skilled operators using automatic controllers to 93%, while saving up to $75,000/yr by prolonging catalyst life. Based on this information, Texaco expected “an early payout” on its investment. In soft terms, according to a Texaco executive, the company also expected to gain invaluable knowledge and experience from full-scale operation.

Not surprisingly, the familiar question of whether all this automation would make the human operator obsolete frequently came up during the project. But, obviously, that’s not the case.

While the computer “does the dull repetitive work of reading, calculating and resetting,” if something should go amiss, it would sound an alarm to which a human operator would have to respond to handle the situation.

Following this initial direct digital control implementation at Texaco’s Port Arthur refinery, TRW installed an RW-300 DDC computer at Monsanto’s new Chocolate Bayou, Texas, petrochemical plant in 1960. During the same approximate time period, IBM installed its first special-purpose computer for process control, the IBM 1700, at an American Oil refinery in Indiana, as shown in FIG. 5, and at a Standard Oil of California refinery, and (in 1962) at a DuPont chemical plant. In 1961, IBM announced its first standard computer for process control, the 1710 model. In the 1960’s, Foxboro introduced several digital systems, including the M9700 process computer and its Digital Equipment Corp. (DEC) PCP-88-based DDC system, which was installed at the Esso Aruba Refinery. The PCP-88 incorporated dual DEC PDP-8s with a shared disk drive.

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90 Years of Progress in the HPI While much of the supplier activity during this time focused on process control computers, automation suppliers also had to figure out how to interface the installed base of largely pneumatic field transmitters and actuators with their new-fangled electronic controllers. In 1959, Honeywell introduced the 4-mA to 20-mA analog signal, which, in conjunction with P/I converters mounted in the control room, provided the interface between the company’s pneumatic field instrumentation and electronic controllers. Ultimately, 4 mA to 20 mA won out over Foxboro’s proposed 10 mA to 50 mA signal as an industry standard (ISA SP-50) for analog field communications.

In 1965, DEC introduced its first minicomputer, the PDP8. Eventually, the company supplanted this with the PDP-11, which was used widely for real-time process control applications. In 1968–1969, Honeywell introduced the Series 16 DDC, with a modular hardware/software package. In the 1970s, Bailey Controls and Taylor Instruments introduced their own DDC systems. Rather than trying to build the computers themselves, these early process control systems were based on DEC, MODCOMP, Data General, and other companies’ minicomputers using purpose-built software and I/O. In 1971, Foxboro introduced its Fox 1, the first in a popular series of

FIG. 6. Analog electronic instrumentation installed in the main process control center at Marathon Oil Co.’s Garyville, Louisiana, refinery. Photo courtesy of Hydrocarbon Processing.

FIG. 7. DCS-equipped control room with CRTs and projected display.

Photo courtesy of ABB.

76 JULY 2012 | HydrocarbonProcessing.com

process control computers and, in 1972, its SPEC 200 split-architecture analog electronic controllers and INTERSPEC digital data highway. Also in 1972, Fisher Controls introduced its Series 1000 split-architecture system, with separate controllers and faceplates. In 1973, Taylor introduced real-time programming to the control industry with the company’s process-oriented language (POL), an adaptation of BASIC programming, first used on the Taylor 1010 and MOD 3000 control systems.

Also, in this appropriate time frame, process control engineers starting experimenting with reusable control-block structures, which arguably formed the basis for today’s ubiquitous objectoriented programming techniques.

The DCS era. Thanks to continuing improvements in solid-

state microprocessors and digital communications, automation suppliers were able to squeeze ever-more-powerful functionality into their electronic devices and systems. This led to the development of the distributed control system (DCS).

While some might challenge this point, it’s generally accepted that Honeywell coined the phrase and introduced the first DCS, the total distributed control (TDC) system, in 1975. At just about the same time, Yokogawa introduced the company’s CENTUM DCS. Despite their high cost, TDC 2000 and CENTUM received strong acceptance within the HPI, particularly in North America and Japan. Within the next several years, several other companies, including Bailey Controls, Fisher Controls, Fischer & Porter (now part of ABB), Taylor Instruments, and Foxboro introduced their own DCSs. The Foxboro SPECTRUM DCS, began to show up in refineries and petrochemical plants around the world, providing strong competition for Honeywell and Yokogawa. Yamatake, which shared some intellectual property with Honeywell and manufactured many of the TDC 2000 components, also marketed the system in Japan.

Unlike the monolithic DDC systems which it replaced, the DCS “distributes” much of the functionality across multiple processors, helping to minimize the impact of failures on the ability of the plant to produce product. In theory, at least, the DCS architecture also moved some of the control functionality closer to the process to minimize latencies. The microprocessor-based, multi-loop controllers were connected to supervisory computers, floppy disk drives, CRT-based operator displays and push-button-equipped workstations, and line printers, now often located in a central (rather than local) control room via a proprietary data highway. In practice, however, the harsh environmental conditions in HPI facilities required that both the process controllers and I/O had to be mounted in air-conditioned rack rooms, often located fairly close to, if not immediately adjacent to, the central control room.

While DCSs offered far more control and real-time information handling capabilities and other functionalities than previously available, they were not without their obvious flaws.

For example, while the CRT-based operator displays provided control-room operators with a remote view of one or more process units while seated in front of a workstation in the control room, the computer displays lacked the intuitiveness of the full- and semi-graphic panel boards that they supplanted. This increased training requirements and often led to the operator switching from automatic to manual control because they just

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didn’t trust the computer. Also, as operators in process plants know all too well, since it’s relatively easy and inexpensive to configure process alarms in software-based DCSs (compared to hard-wired annunciators), there was also a tendency to configure unnecessary and often confusing alarms, leading to often-terrifying “alarm storms.”

In 1977, Honeywell introduced the first redundancy scheme for a process controller, and, in the early 1980s, following several years of development and an investment of approximately $80 million, Honeywell introduced the company’s second-generation DCS, the TDC 3000. This system offered more powerful controllers, new workstations, enhanced information management and other important features. According to some sources, Esso installed the first TDC 3000 system at the company’s Cold Lake Refinery in Alberta, Canada. Throughout the 1980s, all DCS suppliers continued to enhance their systems with new control and information management capabilities, making the DCS the de facto platform for process control.

Honeywell introduced the first “smart” pressure transmitter, the ST3000, in 1983, followed shortly by Foxboro, Yokogawa, Rosemount and others. When combined with the respective suppliers’ proprietary digital field communications scheme, these smart pressure, temperature and flow transmitters improved performance over analog transmitters by transmitting the process variable(s) and often secondary measurements (such as ambient temperature, which is vital in colder climates) in a precise digital format; allowed the transmitters to be re-ranged remotely; and enabled operators and maintenance technicians remote (if relatively crude) access to transmitter status and diagnostics. This eliminated many unnecessary trips to the field.

In 1989, 30 years after the first DDC computer went online at Texaco’s Port Arthur refinery, the Purdue Reference Model for Computer Integrated Manufacturing was published. This evolved into today’s ISA 95 architectural model and schema for plant-to-enterprise integration.

APC pushes the boundaries of economics. The im-

proved visibility into the process and robust PID and advanced regulatory control capabilities provided by many DDC and DCS platforms helped operators and control engineers in HPI plants to stabilize control loops to a considerable degree and also solve other problems. Recognizing the opportunity that advanced regulatory control offered to help stabilize some of their trickier, more interactive control loops, process control engineers began to take greater advantage of these embedded capabilities, often experimenting on their own to further expand the envelope.

Model predictive control (MPC) was pioneered largely by dedicated groups of control engineers at Shell (including both Charlie Cutler and Steve Treiber) and other energy companies beginning in the early 1970s. In the late 1980s, Shell Research engineers in France developed the Shell Multivariable Optimizing Controller (SMOC), a significant advancement.

A handful of small specialist companies, such as DMCC, Setpoint and Treiber Controls (all three subsequently acquired by AspenTech), plus Predictive Control in the UK and Profimatics also began to develop, refine and license MPC technology.

Not to be outdone, control gurus at the major DCS suppliers (Honeywell, Foxboro, Yokogawa, etc.) also either began to develop their own MPC solutions or the companies acquired and further developed licensed technology from third parties.

Hydrocarbon Processing | JULY 2012 77

90 Years of Progress in the HPI The resulting breakthroughs in MPC helped solve the previously daunting multivariable constraint problems encountered in many HPI processes. Advanced process control (APC) software systems such as these, which typically ran in separate supervisory computers, provided the DCS controllers with the precise setpoints needed to further stabilize the process, reduce variability, and safely operate processes closer to physical constraints. Assuming that the plant process control operators trusted the APC enough to keep it turned on (which was not always the case), this typically provided owner-operators with significant economic benefit.

Open control and real-time information systems.

While they represented a step change in process control technology over the all-in-one DDC systems and stand-alone analog electronic controllers, DCSs were handicapped by their closed, proprietary nature. This tended to speed obsolescence and make it difficult and costly to integrate the DCSs with other plant- or enterprise-level systems. Seeking to gain every possible competitive advantage, DCS suppliers were loath to share their proprietary communication technologies with other suppliers, or to even open up their software codes to their customers. This was particularly troublesome in HPI enterprises, where lots of data and information need to flow back and forth between the plant-level systems used to produce products (DCS) and the enterprise-level planning and scheduling systems.

However, during the 1980s, IBM, DEC, Microsoft, AT&T, and other high-technology companies were investing huge sums of money and dedicating their impressive brain trusts to advancing and reducing the cost of the general-purpose information technology (IT). This laid the foundation for the Internet-enabled Information Age. These technologies included open, standards-based operating systems (such as UNIX) and graphical user interfaces, Ethernet networking, TCP/IP communication protocols, object-based programming approaches,

FIG. 8. Recently renovated central control room in a refinery at Major Global Energy Co. Photo courtesy of Emerson Process Management.

78 JULY 2012 | HydrocarbonProcessing.com

and many others that we take for granted today. Unlike the DCS, these technologies were based on open standards and many were available commercially, almost literally right “off the shelf.”

Initially, at least, automation suppliers either ignored, or tried their best to ignore, these goings on, convincing themselves that their industrial customers would never accept using commercial off-the-shelf (COTS) technologies in their plants.

Foxboro, with the introduction of its I/A Series system in 1987, was the first mainstream automation supplier to incorporate UNIX, Ethernet and other commercial-type technologies into a system designed to manage and control mission-critical industrial processes. Foxboro also spent millions of dollars developing the world’s first real-time object manager. Since there were still performance and availability concerns about Ethernet at the time, Foxboro developed a redundant/fault-tolerant scheme for its Ethernet-based process control network, which the company intentionally referred to as a “serial backplane,” rather than a “network,” because company officials were concerned that industrial users wouldn’t be able to get their heads around the idea of an Ethernet-based system.

Unfortunately for Foxboro, serious software and manufacturing issues with the I/A Series system, which took several years to fully resolve, prevented the company from capitalizing on this innovative technology, with more conventional and field-proven systems, such as Honeywell’s TDC 2000/3000 and Yokogawa’s CENTUM DCSs continuing to gain market share in the HPI plants in North America and Japan, respectively. In Europe, ABB began to make inroads into the HPI with its MOD 300 DCS. The development of the DCS over the past 30 years has closely mirrored that of the overall process automation business, moving from proprietary technologies and closed systems to COTS components, industry-standard field networks, and Microsoft Windows operating systems. Today, the DCS has moved from a system-centric architecture to one that is more focused on supporting collaborative business processes and helping owneroperators achieve operational excellence in their process plants.

The drive toward openness in the 1980s gained momentum through the 1990s with the increased adoption of COTS components and IT standards. Probably the biggest transition undertaken during this time was the move from the UNIX operating system to the Windows environment, particularly for human-machine interface (HMI) and data analysis and presentation applications.

The invasion of Microsoft at the desktop and server layers resulted in the development of technologies such as OLE for process control (OPC), which is now a de facto industry connectivity standard. Internet-based technology also began to make its mark in industrial automation and the DCS world.

The impact of COTS was most pronounced at the hardware layer. Standard computer components from manufacturers such as Intel, Motorola, IBM, Sun Microsystems and Cisco Systems made it cost prohibitive for DCS suppliers to continue making many of their own servers, workstations and networking hardware (although most DCS suppliers still assemble their own process controllers and I/O modules, albeit using many COTS components). COTS not only resulted in lower manufacturing costs for the supplier, but also in steadily decreasing prices for the end users, who were also becoming increasingly vocal over what they perceived to be unduly high

90 Years of Progress in the HPI

Ziegler and Nichols develop a method for tuning closed-loop controller response While certainly functional, the only way those early pneumatic controllers could be tuned to provide the desired control response was through tedious and wasteful trial and error, which didn’t always work either. During WWII, two engineers at Taylor Instruments, John Ziegler and Nathaniel Nichols, spent a lot of time tinkering around with PID simulations on the company’s Fulscope 100 controller until they came up with a satisfactory solution. In 1942, they published their now-famous paper, “Optimum settings for automatic hardware costs. Some suppliers that were previously stronger in the programmable logic control (PLC) business, such as Rockwell Automation and Siemens, have been able to leverage their expertise in manufacturing control hardware to enter the DCS marketplace with competitive offerings.

The current state of most process automation system offerings available on the market today relies heavily on the incorporation of international standards, a common control and configuration environment, a common hardware platform, and a common information infrastructure that is designed to accommodate a wide range of applications from multiple suppliers. Although the DCS of today has come a long way from the almost totally proprietary world of the ’80s, there is still considerable progress to be made in the quest for full standards adoption.

In ARC’s latest global DCS market outlook study, published in 2011, Honeywell retained its dominant position in the global refining market, followed by Yokogawa, Invensys, Emerson Process Management, ABB and Siemens. In chemicals, Yokogawa has the leading position globally, followed by Siemens, Honeywell, ABB, Emerson Process Management, Invensys and Yamatake.

What goes around, comes around. While the HPI may be

very conservative in some respects, traditionally, this industry has been quick to accept new technologies that offered clear potential to help companies operate and maintain their complex assets better and more efficiently. Process computers, direct digital control systems, DCS systems, APC, simulation and plantwide historians, are just a few examples of the new technology adopted by the HPI. This has also been the case for fieldbus, the technology that provides a digital link between intelligent, microprocessor-based field instrumentation and the host DCS. Unlike the 4-mA to 20-mA analog electronic standard for communications between field instruments and the control system (and the 3-psi to 15-psi pneumatic standard that preceded it), which required point-to-point wiring (or pneumatic hoses) for each device, digital fieldbus technology enables multiple field devices to communicate with the host system on the same wire. While fieldbus segment sizing, topology, and hazardous area-related decisions can add engineering complexity and cost compared to point-to-point analog field wiring, the wiring savings alone can reduce fieldbus installation costs to a significant degree.

controllers.” This established clear rules for tuning PID controllers in refineries, petrochemical facilities and other process plants. This came in very handy during the ensuing war years, when now-well-tuned controllers helped chemical plants produce synthetic rubber for tires and other wartime necessities, helped refineries produce massive quantities of gasoline and diesel to fuel jeeps, trucks, tanks and heavy equipment; and produce newly developed, high-octane aviation fuel for fighter planes, strategic bombers and other aircraft.

More importantly, fieldbus provides bidirectional digital communications between the field devices and the host system. Thus, in addition to communicating one or more process variable measurements for monitoring and/or control, the field devices can communicate secondary measurements and important device status and asset management-related information to the host system. This eliminates the tedious and time-consuming effort previously required to “ring out” and verify potentially thousands of different field terminations during system commissioning; reduces ongoing maintenance costs and effort by eliminating unnecessary trips to the field; and – in conjunction with appropriate software—enables HPI plants to implement highly effective condition-based plant asset management strategies to help improve equipment availability, while minimizing unnecessary maintenance. (As many owner-operators have learned, too much work during planned turnarounds is done based on habit, rather than on actual need; while needed work sometimes goes unattended.)

That is the good news. As automation users in HPI plants know all too well, due to the snail-like pace of standardization efforts and significant politicking among national standards bodies and automation suppliers, it’s taken far too long for fieldbus standards and technology to arrive at its current state.

Initially, DCS suppliers offered proprietary digital communications that provided many of the benefits of today’s standard fieldbus technology, albeit in a single-vendor environment.

In other words, each supplier’s smart transmitters could only communicate digitally with its own control system. Not an optimum situation, particularly for end users.

Pressed by their customers, national standards bodies in Europe and North America, working in conjunction with automation suppliers, initiated a number of different, competing fieldbus standardization efforts. In 1999, in a creative, if not terribly helpful, attempt to break the stalemate and end these “fieldbus wars,” the International Electrotechnical Commission (IEC) came up with a compromise “standard,” IEC 61158, that recognized eight different fieldbus approaches (including FOUNDATION fieldbus, ControlNet/Ethernet IP, PROFIBUS, WorldFIP and INTERBUS), grouping these into different “types,” but creating common physical, data link and applications layers.

While waiting for these “fieldbus wars” to sort themselves out, many users simply avoided the issue altogether by installHydrocarbon Processing | JULY 2012 79

90 Years of Progress in the HPI from the controller back to the final control device in the field.

While a study commissioned by the Fieldbus Foundation revealed that this can help improve performance, particularly in fast-acting control loops, owner-operators have been slow to accept fieldbus-enabled control in the field to date.

ARC believes that this is probably because users are already very comfortable and generally satisfied, with their DCS controllers, and because control in the field doesn’t add value for the types of interactive control loops found in many HPI processes.

FIG. 9. “Collaboration wall” decision support for a hypothetical integrated downstream energy enterprise. Photo courtesy of Invensys Operations Management.

ing transmitters with HART communications capability. While HART-enabled transmitters don’t offer multi-drop capability and still commonly communicate the process control variable in analog, 4 mA to 20 mA (rather than the available digital) format, they do offer the potential to access transmitter status diagnostics and interact with the field device remotely from the control room, maintenance shop or plant reliability center. In the past, many users found this particularly useful when commissioning the instruments; far fewer used this capability for ongoing asset management. However, this situation appears to be changing as automation and other suppliers have introduced plant asset management toolkits that fully exploit the potential of HART. Ultimately, in Europe, PROFIBUS emerged as an industry fieldbus standard for both process and discrete applications, gaining wide acceptance among suppliers and users alike on that continent. In North America, FOUNDATION fieldbus emerged as the digital fieldbus for process plants.

Not surprisingly, Shell and other leading HPI companies were among the first to experiment with and implement FOUNDATION fieldbus. They did so cautiously at first, with the initial implementations in pilot plants and for other smaller-scale projects, and ultimately, in virtually all their new plants and/or major expansion projects.

FOUNDATION fieldbus-enabled control valves and transmitters include standard process control blocks, so that— once again—for simple process control loops, at least, both measurement and control can be performed in the field—just like in the early days of process control! What’s more, as with the early single-loop controllers, this can help limit the negative impact of instrument or other faults compared to DCS controllers, which handle dozens, or even hundreds, of control loops (albeit, normally in redundant configurations designed to enhance fault tolerance).

Since DCS process controllers are often physically located at a significant distance from the process, fieldbus-enabled control in the field can sometimes reduce the time latencies involved when a measurement signal has to be transmitted from the field devices to a DCS controller and the control signal transmitted 80 JULY 2012 | HydrocarbonProcessing.com

What’s ahead? While the state-of-the-art in process automation systems has only advanced incrementally in recent years, ARC believes that we’ll soon see some major advancements emerge in industrial automation, and—if the past is any lesson—owner-operators in the HPI will likely to be among the first to implement many of these advancements. Some of these advancements include: • Even smarter field devices that are capable of conveying their health in absolute terms • Automation systems with increased functional distribution • Platform-independent, software-based function blocks supporting intelligent autonomous agents • Increased use of cloud computing to serve data to authorized users, anywhere, at any time • Increased use of wireless field devices, including wireless measurements for process monitoring and control • Increased use of tablets, smartphones and other mobility devices by plant operators, maintenance technicians, engineers and others • Increased use of advanced analytics for real-time decision support, fueled by the “big data” currently buried in many plant historians.

ARC analysts will aim to keep HP readers informed about these and other trends in our monthly “Integration Strategies” columns.

PAUL MILLER is a senior editor/analyst at ARC Advisory Group and has 25 years of experience in the industrial automation industry. He has published numerous articles in industry trade publications. Mr. Miller follows both the terminal automation and water/wastewater sectors for ARC.

DICK HILL is vice president of ARC Advisory Group, Dedham, Massachusetts, responsible for developing the strategic direction for ARC products, services and geographical expansion. He is responsible for covering advanced software business worldwide. In addition, he provides leadership for support of ARC’s automation team and clients. Mr. Hill has over 30 years of experience in manufacturing and automation. He has broad international experience with The Foxboro Co. Prior to Foxboro, Mr. Hill was a senior process control engineer with BP Oil, developing and implementing advanced process control applications. Prior to joining ARC, he was the US general manager of Walsh Automation, a major engineering consulting firm and supplier of CIM solutions to the pulp and paper, petrochemicals, pharmaceutical, and other process and manufacturing industries. He is a graduate of the Lowell Technological Institute with a BS degree in chemical engineering.

DAVE WOLL is vice president of the consulting services at ARC Advisory Group where he provides high-level consulting services for ARC clients. He has been with ARC since 1997 and has been defining and applying process automation for over 35 years. This includes the marketing and application of control, safety, SCADA, measurement systems and business Integration. Prior to ARC, Mr. Woll held numerous positions at both The Foxboro Co. and Bristol Babcock.

He holds a BS degree in electrical engineering from the University of Connecticut.

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Special Report

90 Years of Progress in the HPI B. DuBOSE, Online Editor

Benchmark oil, gas prices poised for divorce The trickle-down effect of baseline oil and gas prices has an enormous impact on the hydrocarbon processing industry (HPI). The economically-advantaged feedstocks of a given era are among the primary factors to decide which sectors thrive and which feel the pain.

In today’s HPI, the ability to crack gas-derived ethane makes all the difference—especially in the US. Shale gas discoveries have nudged natural gas prices as low as $2/MMBtu by virtue of making supply abundant (FIG. 1).

This, in turn, makes ethane-based petrochemical projects an economic boon for HPI companies.

Meanwhile, rising political tensions in the Middle East have pushed global oil prices above $100/bbl for much of the past year. This makes economics more difficult for many plants that run on crude-based naphtha, such as most in Europe and several in Asia (FIG. 2).

Over the past 90 years of the HPI, there has often been at least some relationship between the leading oil and gas benchmarks. So what changed to set up today’s decoupling dynamic?

Here’s a look at where we’ve been and where things may be going.

Where the ratio was. A barrel of oil has approximately six times the energy content of an MMBtu of natural gas. Thus, if oil and gas were perfect substitutes, the price of oil would tend to be about six times that of natural gas.

Of course, the reality is that using oil for gasoline production is easier for a producer. Thus, oil is slightly more valuable and historically trades between six and 12 times the price of gas.

That’s the way things were for much of the past 90 years. There were shortterm deviations based on exogenous factors such as storage levels, weather and the quantity of production shut in due to

hurricanes, but the two markets always found their way back in line.

It was especially easy for that to be the case prior to the 1970s and early 1980s, when the US natural gas market was regulated and subject to federal controls.

The eventual deregulation did bring

about a freer market in the 1980s and 1990s, with competitive forces largely allowed to determine prices. But even then, natural gas prices remained linked to oil since natural gas was usually sold via long-term negotiated contracts at prices indexed to the price of oil.

FIG. 1. Shale gas drilling has rapidly increased in many US locations, such as this one in Wyoming.

FIG. 2. The integrated petrochemical composite at Nanjing, China, is a joint venture between BASF and Sinopec. The facility uses crude-based naphtha as feedstock.

Hydrocarbon Processing | JULY 2012 83

90 Years of Progress in the HPI 2009, the US Potential Gas Committee— led by Dr. John B. Curtis of the Colorado School of Mines—noted numerous new resources in its reevaluation of potential shale plays (FIG. 4).

The committee found that, in 2009, the US possessed a total resource base of 1,836 trillion cubic feet (Tcf), the highest resource evaluation in the committee’s 44-year history and up 45 percent from just two years earlier in 2007. Most of the increase came from reevaluations of shale-gas plays in the Appalachian basin and in the Mid-Continent, Gulf Coast and Rocky Mountain areas.

That newfound supply, coupled with still-low demand from the recession, sent gas prices tumbling in spot markets.

Free of regulation, more HPI companies turned to the spot market for their natural gas needs, given the ability to quickly take advantage of low rates.

Those trends have continued and increased even more in the years since 2009. While demand recovered in years following the recession, supply was enough to still exert downward pressure.

Henry Hub natural gas prices sank from above $13/MMBtu in mid-2008 to below $2/MMBtu in early 2012.

While gas prices are higher in other parts of the world, they may not last. Multiple US natural gas export projects are scheduled for startup by the latter half of this decade, allowing global access to cheap US supply and likely placing downward pressure on competitors’ prices.

Now, flash forward to today. In 2012, a single barrel of West Texas Intermediate (WTI) crude oil (FIG. 3) has been worth about 35 MMBtu of natural gas. What happened, and what does it mean?

2009 changes the gas game. The mood of the HPI was grim following the global economic downturn of 2008. Demand was devastated, particularly in developed regions such as the US and Europe.

There were signs of life in the developing worlds of China and India, but the traditional producing regions that largely dictate oil and gas pricing had little ability to access those locations. Economics were conducive to shutting down more capacity, not finding new sources.

But researchers in the US were discovering that much more gas existed than was ever thought. In a report released June 18,

FIG. 3. Oil drilling remains quite profitable due to high crude values.

Montana Thrust Belt Williston Basin

Cody

Gammon Michigan Basin

Greater Green River Basin

Antrim

Hilliard Baxter Mancos Forest City Basin

Uinta Basin

Mancos Hermosa

Pierre

Woodford

Paradox Basin

Lewis

Permian Basin Marfa Basin

Cherokee Platform

Fayetteville

Anadarko San Juan Raton Basin Basin Basin Bend Ardmore Basin Palo Duro Basin

BarnettWoodford

Illinois Basin

Excello-Mulky

Piceance Basin

New Albany

Barnett

Woodford-Caney

Haynesville

Devonian (Ohio) Marcellus Utica

Chattanooga

Black Warrior Basin Arkoma Basin

Ft. Worth Basin

Appalachian Basin

Texas-LouisianaMississippi Salt Basin

Conasauga Valley and Ridge Province Floyd-Neal

Miles

Maverick-Sub-Basin Shale Gas Plays Stacked Plays Shallowest/Youngest Deepest/Oldest

Basins

Pearsall-Eagle Ford

0

Eagle Ford

Rio Grande Embayment

Source: Energy Information Administration based on data from various published studies Updated: May 28, 2009

FIG. 4. A look at many popular US shale plays.

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100 200 300 400

90 Years of Progress in the HPI Oil doesn’t follow. On the other hand,

oil has not gone with the same trend. Oil had a similar mid-2008 run-up, when WTI and Brent crude prices reached alltime highs near $145/bbl.

But after briefly tumbling in the peak recession months of late 2008 and early 2009, crude quickly regained its upward bias. Rising transportation fuels demand from growing populations in China and India started the momentum, and recovering major economies in the US and Europe sustained it.

Moreover, political tensions near key oil production regions in countries such as Libya, Iran and Egypt posed a significant threat to supply. That sent prices to around $120/bbl for Brent and $100/bbl for WTI for much of 2012.

Those figures are not as high as 2008 levels, but things look much closer than for the natural gas counterparts.

Going forward. Barring an unforeseen dynamic in oil supply, the oil-to-gas price relationship seems forever changed.

The US is the leader in shale development today, but it is not the only player.

Significant shale reserves are also present in regions such as Europe, Asia and South America (FIG. 5). Though infrastructure is not as developed in those places as in the US, it likely will be in coming years—further enhancing the trend for lower gas prices.

Shale producers are, of course, targeting liquids areas when possible. In the US, the Bakken shale play in North Dakota is rapidly expanding in popularity because of the presence of shale oil. However, shale-oil estimates are not nearly significant enough to put a dent in crude prices—at least not to the extent that shale gas estimates have lowered natural gas rates. In addition, Middle East controversies are ongoing and OPEC continues to tightly evaluate any proposed oil-production increases.

For the HPI, this puts a premium on petrochemical and refining facilities that can crack ethane. That has led many downstream companies—such as Shell and Dow Chemical—to announce plans for new US projects with quick access to ethane feedstock. Others, including LyondellBasell, are embarking on debottlenecking projects at existing US sites to quickly raise capacity.

The flip side is that the ethane boom makes older, crude-based naphtha crack-

Legend Assessed basins with resource estimate Assessed basins without resource estimate Countries within scope of report Countries outside scope of report Source: EIA, June 2011

FIG. 5. Assessment of shale gas resources around the world.

ers uneconomical. Those are particularly prominent in Europe and Asia.

It remains to be seen whether the majority of reliable HPI operating companies will spend on new capacity investments just as their older, established units are struggling. It’s an especially difficult deci-

sion, considering the infancy of the cheap gas trend and the fact that the prominent supply location (US) isn’t in close proximity to the most quickly growing sources for energy demand (China, India, Brazil).

That debate could well define the next 90 years of the HPI.

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Special Report

90 Years of Progress in the HPI A. BLUME, Process Editor

The psychology of energy pricing: A look at market behavior during oil shocks Oil prices respond to a wide range of fundamental and technical factors. These factors include, but are not limited to, energy supply and demand; inventory levels; geopolitics; economics; weather events and natural disasters; shutdowns and startups at refineries, pipelines and oil rigs; and speculative trading. To understand how and why these factors are responsible for influencing the direction of energy prices, it is useful to examine how changes in market sentiment are driven by human responses to these factors.

Energy markets are, at their cores, made up of people—producers, traders, suppliers, investors, consumers, etc. This means that markets are not only vulnerable to human emotional reactions such as anxiety, confidence and fear, but that they are also shaped by humans’ limited ability to predict what will happen in the future. This article explores how psychological reactions influence pricing in the oil market, and also how fluctuations in pricing are informed by market behavior and speculation. A review of the energy crises and price shocks of the 1970s and the 2000s provides a historical perspective on market and consumer reactions to planned and unplanned events.

Triple-digit oil and psychological price points. The impact of geopolitical factors has been seen recently in the price response to market worries about a potential disruption to oil supplies as a result of tensions between the West and Iran over Iran’s nuclear program. A European Union (EU) embargo on Iranian oil—agreed upon in January 2012 and scheduled to go into effect on July 1, 2012—pushed Iran to announce on February 19, 2012 that it would halt exports of oil to the UK and France. This retaliatory announcement, in turn, caused the price of US West Texas Intermediate (WTI) benchmark crude oil on the New York Mercantile Exchange (NYMEX) to spike to a 10-month high of over $125/bbl on February 24, 2012— just two weeks after oil had reached $100/bbl for the first time in 2012. Oil prices have hovered around $90/bbl to $100/bbl since that time, and they are expected to remain near those levels for the rest of the year.

The first time oil prices breached the psychologically important level of $100/bbl was on January 2, 2008—the first trading day of that year—as unrest in major oil producer Nigeria, weather-related closures at Mexican oil export ports, and worries over future OPEC supply briefly sent oil prices on the NYMEX above the triple-digit mark.1 Speculators were largely blamed for the run-up to $100/bbl, as trading volume on that day was only 50% of normal due to the New Year’s holiday.

Oil first closed above $100/bbl on the NYMEX in February 2008. The major influencing factors at that time were Venezuelan President Hugo Chávez’s threat to cut off oil supplies to the US over a stakeholdings dispute with ExxonMobil; ongoing tensions in the Middle East; and oil price speculation.

President Chávez eventually toned down his threats, but then a sudden explosion at Alon USA’s refinery in Big Spring, Texas sent prices for both crude oil and refined fuels surging.

Although the Big Spring refinery is relatively small and US fuel inventories were considered sufficient at the time, oil traders and hedge fund managers interpreted the refinery outage as a buying signal—likely because a record number of similar refinery shutdowns in the US during the summer of 2007 resulted in gasoline shortages, price hikes and panic buying. The 2007 refining capacity shortage pushed up oil prices by 23% between January and late July of that year, while gasoline prices surged upward by 35% in the same time period.2 In this instance, recent history influenced the oil market’s thinking and sent traders into panic mode. Although the likelihood of previous events recurring was unknown, the possibility of such served to elevate traders’ anxieties. As energy trader Michael Rose explained in a February 20, 2008 interview with the New York Times, “With this credit crisis going on, everyone is on edge and the slightest disruption in crude oil or its products takes prices right up.”3 Consumer sentiment vs. market sentiment. According to IHS Global Insight, a 10% rise in the price of gasoline relative to the overall price level decreases US consumer confidence by 1.4%–1.5%; likewise, a 10% drop in the price of gasoline increases consumer confidence by the same amount. When rising gasoline costs approach round-dollar values—e.g., $3/gal or $4/ gal—consumer confidence plummets by a sharp 3.79%, while consumer sentiment slips 1.4%, as the threshold price-point is neared. However, when decreasing gasoline prices fall below a round-dollar amount, no significant increases in either consumer confidence or sentiment are observed. This suggests that consumers tend to place more emphasis on (that is, be more emotionally responsive to) rising fuel prices than to falling fuel costs.

The same appears to be true of energy traders and analysts with regard to oil pricing. According to some market watchers, the excitement and apprehension of surpassing the psychologically important $100/bbl mark may have influenced oil’s 2007–2008 climb. Daniel Yergin, oil historian and Cambridge Energy Research Associates (CERA) chairman, remarked in Hydrocarbon Processing | JULY 2012 87

90 Years of Progress in the HPI November 2007, “Today’s markets feel like the crowds standing up in the final minutes of a football game shouting: ‘Go! Go! Go!’ People seem almost more relaxed about [reaching] $100 [per bbl oil] than they were about $60 or $70 oil.”4 Stock market analysis has shown that psychological resistance and support levels tend to be round and/or even numbers. Also, the prospect of oil hitting triple digits was, until 2007, an unthinkable scenario, as oil had traded around $15–$25/bbl from the mid-1980s to September 2003. New York Times journalist Louise Story wrote in May 2008, “In the 1990s, oil research was a sleepy area at banks. Many analysts assumed oil prices would hover near $15–$20/bbl forever. If prices rose much above those levels, they figured consumers would start conserving, suppliers would raise production, or both, causing prices to decline.”

Prices began moving upward in the fourth quarter of 2003, breaching $30/bbl. They moved into the $40/bbl range in 2004 as declining US petroleum reserves and worries about peak oil stirred market anxieties. By August 2005, prices had climbed to $60/bbl. During that month, Hurricane Katrina’s landfall in the southern US destroyed 30 Gulf of Mexico oil platforms, closed nine refineries and sent prices soaring to over $70/bbl by late August.

Price shocks unsettle energy, consumer markets. The

rapid run-up in oil prices in late 2007 and early 2008 is often viewed as the third energy price shock of this generation. The 120 Annual GDP growth Average IEA oil import price in real 2011 dollars * Black columns indicate recession years in OECD countries

6

90

4

60

2

30

0

0

-2 1970

1980

1990 Year

2000

2010

Average IEA oil import price in real 2011 dollars

World GDP growth (2011 dollars, market exchange rate), %

8

-30

Source: IEA

FIG. 1. Oil price hikes have preceded every global recession since the early 1970s.

Inflation-adjusted annual average crude oil price Nominal annual average crude oil price

1946 1948 1950 1952 1954 1956 1958 1960 1962 1964 1966 1968 1970 1972 1974 1976 1978 1980 1982 1984 1986 1988 1990 1992 1994 1996 1998 2000 2002 2004 2006 2008 2010

Price, $/bbl

110 100 90 80 70 60 50 40 30 20 10 0

Year

FIG. 2. Nominal and inflation-adjusted average WTI crude oil prices on the NYMEX, 1946–2011.

88 JULY 2012 | HydrocarbonProcessing.com

price shocks of the 1970s and 1980s stirred fears at the energy market, consumer market, and government levels of lasting supply shortages and sustained fuel price hikes, and also the economic damage that could result from these scenarios. As FIG. 1 shows, hikes in oil prices have preceded every global recession since the early 1970s.

The 1978 Iranian oil worker strike and the 1979 Iranian Revolution—which collectively resulted in a near-shutdown of Iran’s oil production—spurred panic fuel buying in the US, as the Organization of Arab Petroleum Exporting Countries (OAPEC) oil embargo of October 1973 to March 1974 was still fresh in consumers’ minds. This scenario is similar to that seen in February 2008, when US refinery outages echoing those of the previous summer pushed consumers to the pump en masse.

However, supply fears during the energy crises of the 1970s were calmed within months, after political relationships stabilized, oil operations recommenced and supply flows resumed.

However, unlike the energy crises of the 1970s and 1980s, which resulted from cut-offs in Middle Eastern oil supplies to the West, the current price shock is due to surging economic expansion—and, thus, rapid increases in fuel demand—in developing countries. In that sense, it is the first demand-led energy price shock the world has witnessed, noted economist Lawrence Goldstein with the Energy Policy Research Foundation of Washington, D.C., in November 2007.4 Most analysts believe that today’s energy price shock will have wider-ranging and longer-lasting implications. China’s and India’s growing middle classes are demanding more and more fuel, and although the average Chinese consumer currently uses less than half the amount of energy than does the average US citizen, China is expected to consume 70% more energy than the US in the future. Aggressive expansions in other developing and nonWestern economies, such as Brazil and Russia, are contributing to the demand-led energy shock. Another factor is continuously rising fuel consumption in the US and other Western nations.

Bold forecasts propel oil price frenzy. Nominal and infla-

tion-adjusted annual average prices for WTI crude oil on the NYMEX over the 65 years through 2011 are shown in FIG. 2.

Marked fluctuations from the 1970s onward demonstrate the effects of energy crises on oil pricing. These sharp fluctuations suggest that energy costs have become more closely tied to the market’s reaction to fundamentals in the last 40 years than they were in the middle part of the 20th century.

During the 2007–2008 price escalation, oil price forecasts varied widely due to market uncertainty and, perhaps, also because the number of political, economic and energy supply variables involved made it more difficult for analysts and market players to predict where prices would go. Some market watchers expected prices to fall back to around $70/bbl, while others projected that oil would rise to $120/bbl within months. The International Energy Agency’s chief economist, Fatih Birol, warned in November 2007 as WTI prices approached $100/bbl, “These prices are too high and will end up hurting everybody—producers and consumers alike.”4 Goldman Sachs economist Arjun N. Murti issued a bold prediction in May 2008, at the height of the price mania, that oil could hit a “super spike” of $150–$200/bbl within the next 6–24 months, due to robust demand growth and slow supply

90 Years of Progress in the HPI Unlike the utilities, industrial consumers, governments and growth. Nauman Barakat, senior vice president for global enenergy companies that physically buy and sell crude oil and ergy futures at Macquarie Futures USA, commented on the fuel supplies, noncommercial market speculators do not parforce of this forecast: “Even if you disagree with their views, ticipate in energy markets for end-use purposes. These entithe problem is that Goldman [Sachs] does carry so much ties—which include investment banks, hedge funds and other credibility. There are a lot of traders who are going to buy based on their reports.”5 Famed oil tycoon T. Boone Pickens joined the frenzy with his forecast of $150/bbl oil by the end of 2008, Unlike the energy crises of the 1970s while then-OPEC President Chakib Khelil predicted and 1980s, which resulted from that prices would rise to $150–$170/bbl over the summer of 2008. Meanwhile, Gazprom CEO Alexey Miller cut-offs in Middle Eastern oil supplies forecast that oil prices would hit $250/bbl in 2009. to the West, the current price shock is Bloomberg later reported that over 3,000 options contracts were purchased giving holders the right to purdue to surging economic expansion in chase oil at $250/bbl in December 2008, demonstratdeveloping countries. In that sense, ing the strong effect of these forecasts on the market.

The bullish predictions sent ripples of uncertainty it is the first demand-led energy price and fear through the oil market, which further drove shock the world has witnessed. up prices as speculators attempted to forecast how high prices would rise, while OPEC members raised production quotas in an effort to calm prices. Oil prices eventually spiked at an all-time high of $147.30/bbl in July large financial institutions—buy and sell futures contracts as 2008. On average, the cost of oil rose 23% per year between bets on forward price direction, based on calculated risk and 2003 and 2008 (as measured in real dollars),6 which resulted on forecasts issued by their analysts and economists. These forecasts are normally derived from a combination of fundain erroneous finger-pointing at market speculators. mental and technical factors, in addition to analysts’ gauge of market sentiment. Speculation by commercial traders—such Global recession reverses price hike. The onset of the as oil producers, refiners, airlines and other energy buyers— global recession of 2008–2009 calmed energy demand and, serves as a way for commercial players to hedge against sharp consequently, dampened the market frenzy over $100-plus/ fluctuations in prices, and is not focused on here. bbl oil. Prices plummeted to $32/bbl by December 2008. This Much of the daily fluctuation in oil prices can be attribwas an unprecedented movement, given the July clamor over uted to noncommercial speculation. The practice is a legal near-$150/bbl oil, which was more highly publicized than the (and many claim essential) factor in market functioning, as December drop. This speaks to the theory that consumers and it provides the market with needed liquidity. However, many market players alike are more emotionally responsive to rising analysts and market watchers insist that the movement of excosts than to falling prices. cessive amounts of speculative money into and out of the oil Saudi Arabian Oil Minister Ali al-Naimi cautioned in March market has helped accelerate price spikes and drops over the 2009, “I have often described unsustainably low oil prices as past five years. These price hikes have hit consumers the hardcarrying the seeds of future spikes and volatility. In a low-price est, as energy firms have been forced to pass down increased environment, the trend is often to focus on survival instead of feedstock costs during times of high prices. Excessive speculaexpansion. If we place a low priority on preparing for the fution is undesirable from a consumer point of view, as it freture, that lack of action can come back to haunt us through supquently results in higher retail fuel prices and is not required ply shortages and another round of high prices.”7 for oil futures and spot markets to function.8 The present state of the market appears to confirm Mr. Al-Naimi’s warning. Oil prices stabilized briefly between The US Commodity Futures Trading Commission late 2009 and the middle of 2010, to around $60–$80/bbl; (CFTC) and the UK Financial Services Authority (FSA) however, in early 2011, costs climbed back above $90/bbl jointly investigated market speculation on the NYMEX and on political upheaval in Libya and other African and Middle IntercontinentalExchange (ICE) trading platforms in 2008, Eastern oil-producing nations. By early 2012, anxiety over the at the height of the oil price frenzy, to determine if illegal continuing conflict between Iran and the West sent WTI oil price manipulation was taking place. The CFTC’s and FSA’s prices back above $100/bbl and pushed up European Brent Interagency Task Force concluded in July 2008 that rapidly oil futures to nearly $130/bbl in March—levels that Mr. Alexpanding fuel demand as a result of the economic boom in Naimi deemed “too high.” developing countries was largely to blame for the rapid run-up in prices, and not market speculation alone.

In an effort to protect consumers, however, the CFTC Speculation’s role in the oil market. The most publicized drafted the Dodd-Frank Wall Street Reform and Consumer and visible impacts on oil prices since late 2007 have been Protection Act, which went into effect in July 2010. The act stormy geopolitics and political unrest, supply/demand uncercalls for financial regulatory reform for capital investments by tainty, and a handful of uncontrollable weather events. Howevbanks and insurance firms, and imposes regulatory restraints er, a fourth factor that has influenced price direction (albeit to on hedge funds and private equity funds. a debatable degree) is speculation by noncommercial traders.

Hydrocarbon Processing | JULY 2012 89

90 Years of Progress in the HPI 160 140 Price, $/bbl

120

WTI crude oil futures WTI crude oil spot

100 80 60

5/1/03 8/1/03 11/1/03 2/1/04 5/1/04 8/1/04 11/1/04 2/1/05 5/1/05 8/1/05 11/1/05 2/1/06 5/1/06 8/1/06 11/1/06 2/1/07 5/1/07 8/1/07 11/1/07 2/1/08 5/1/08 8/1/08 11/1/08 2/1/09 5/1/09 8/1/09 11/1/09 2/1/10 5/1/10 8/1/10 11/1/10 2/1/11 5/1/11 8/1/11 11/1/11 2/1/12 5/1/12

40 20 Date

FIG. 3. Co-movement of WTI crude oil futures and spot prices on the NYMEX, May 2003–May 2012.

Research downplays speculation’s impact on market. A March 2012 study by the Oxford Institute for Energy Studies (OIES) and the University of Michigan’s Department of Economics reached similar conclusions to the Interagency Task Force on oil market speculation. “We find that the existing evidence is not supportive of an important role of speculation in driving the spot price of oil after 2003,” the authors wrote. “Instead, there is strong evidence that the co-movement between spot and futures prices reflects common economic fundamentals rather than the financialization of oil futures markets.”8 This is because, as the authors explain, changes in open interest on the futures market are primarily driven by forecasts of higher economic activity, which stimulate hedging demand and, therefore, help predict fluctuations in futures and spot prices for oil.

FIG. 3 illustrates the co-movement of WTI crude oil futures and spot prices on the NYMEX from May 2003 to May 2012.

Blake Clayton, a fellow for energy and national security at the US Council on Foreign Relations, also links speculation’s role in the oil market to the difficulty inherent in predicting market direction. In an April 9, 2012 article, he wrote, “In light of such a complex environment, it should come as no surprise that oil prices have been wildly volatile as market participants struggle to anticipate what is around the bend. Discerning the future path of supply and demand is hardly straightforward when the market is calm, let alone when economic and geopolitical uncertainty are magnifying the risk of otherwise unlikely events. The opaqueness of the world oil market, which is plagued by partial and contradictory data, only compounds the perils of prophecy.

But there is no reason to believe that prices would better reflect fair value, or that the economy and consumers would be better served, if speculation in the oil market were severely curtailed.”9 Mr. Clayton went on to explain how today’s trading market is “far superior” to other pricing methods that have been used since the 1940s. The 1950s and 1960s saw benchmark prices set by executives at large, integrated oil firms amid aggressive open-market trading. OPEC then commandeered oil pricing from the early 1970s through the late 1980s, after which market trading took over as the primary method for pricing oil. “Wall Street speculators had nowhere near the presence in the oil market during those two earlier eras that they do today, and yet few would choose to return to those defunct arrangements,” Mr. Clayton asserted.9 Yet another study, released in January 2012 by Bates White Economic Consulting, examined a range of political, economic, financial and environmental factors affecting the oil market between 2006 and 2009. The authors reached a similar conclu90 JULY 2012 | HydrocarbonProcessing.com

sion to the OIES study and Mr. Clayton’s analysis. They stated, “During the part of the 2007–2008 period in which prices increased the most quickly and about which the most concern was expressed … we are unable to find statistical support for causation … of oil prices by financial traders or speculators.”

Instead, the authors claim that fundamental factors (including OPEC production decisions and surprise changes in inventory levels of major consuming nations) as well as political events (particularly violent ones) were the driving factors in the runup in oil prices from late 2007 through July 2008. The onset of the recession in the second half of 2008 dominated fluctuations in prices during that time period.6 The majority of the analyses and studies that have been conducted on speculation over the last five years by government, financial, consulting and other institutions have reached the same conclusion: speculation plays a role in price fluctuations, but it does not dictate price direction. It is one of a myriad of factors that impact the market, and speculation generally has a shorter-term effect on market movement than do fundamentals with wider-reaching and longer-lasting implications, such as demand booms, supply shortages and political and economic turmoil. However, the temporary run-ups in prices that are partially caused by speculative activity can be burdensome to consumers, as these price increases are filtered down to the retail level.

Fundamentals, price trends key to market analysis.

An examination of the energy price shocks of the 1970s and 2000s demonstrates the range and extent to which fundamental and technical factors influence oil market sentiment and, therefore, price direction. It also shows how these factors may change over time as new patterns emerge in the fundamentals “kaleidoscope”—e.g., the supply-driven price shocks of the 1970s giving way to the demand-focused price hikes of the last decade.

At the heart of these price fluctuations are reactions by traders, producers, suppliers, consumers and other energy market participants. Both consumers and traders tend to be more emotionally responsive during times of increasing and high prices than they are during times of decreasing and low prices. This is supported by the bigger market and media reactions to the 2007–2008 runup in oil prices compared with the subsequent plunge in prices in the latter half of 2008. Studies of consumer sentiment during gasoline price increases and decreases also support this theory.

Furthermore, noncommercial speculation in the oil market (specifically during the price run-ups of recent years) has been found to play a role in short-term oil price fluctuations, but it does not determine the direction of the market over the longer term. Fundamental factors including geopolitics, supply and demand, economics, weather and others have a significantly greater influence on oil price direction, according to recent studies.

Price forecasts and estimates of future supply and demand do inform general market sentiment as well as speculative trading, although such forecasts are still shaped by humans’ limited ability to predict what will happen in the future. For this reason, traders and analysts often look to market trends and lessons learned from past energy crises when evaluating present and future market direction and sentiment.

LITERATURE CITED Literature cited available online at HydrocarbonProcessing.com.

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Special Report

90 Years of Progress in the HPI B. THINNES, Technical Editor

The military and the hydrocarbon: A love affair of over 100 years The relationship between the military and the petroleum industry dates back to the years before World War I (WWI), when the US and British navies started to switch from coal to oil as a fuel source.

Military dependence on oil only increased as WWI progressed, since the military innovations of the time (airplane, tank, submarine) all needed oil to run. By World War II (WWII), militaries around the world were hooked on the hydrocarbon.

The intertwined relationship between oil and military is not just a story of gasoline and jet fuel, though. Other uses of the hydrocarbon molecule were parsed by military men in the 20th century, leading to rapid innovation in chemicals, explosives and rubber.

Militaries in the modern era are still vast consumers of oil and a variety of refined products, although there has been increased military investment and interest in the possibilities of biofuels and alternative fuel sources like wind, solar and tidal power.

Consumption. An example of a military

with a thirst for fuel is the US’ defense forces. The US Department of Defense (DOD) consumes upward of 1% of the petroleum products refined in the US annually. The majority of the DOD’s bulk fuel purchases are for jet fuel, which averages about 100 million bpy.

The DOD’s top four fuel suppliers operate a combined 31 refineries in the US, representing 6 million bpd of refining capacity. The Defense Energy Support Center (DESC) purchases fuel for all DOD services and agencies, using fixed-price contracts with economic price adjustments. DESC typically awards fuel contracts based on the lowest cost to the point of delivery, typically for lengths of one year. DESC’s fuel procurement cat-

egories include bulk petroleum products, ship bunker fuel, into-plane (refueling at commercial airports) and post camp and station. Although DOD may represent the largest US consumer of refined products, its primary fuels are Jet Propellant 8 ( JP-8), Jet Propellant 5 ( JP-5) and diesel.

History. Oil became important for mili-

taries in the years before WWI, as many of the leading navies of the time began switching from coal to oil to power their ships. During WWI and pretty much ever since, having access to large amounts of oil resources was a key indicator of a country’s and a military’s power.

Once again, WWI offered a key indicator, in that Britain and France could depend on oil supplies from the Middle East and North America, while Germany was solely reliant on Romania. This caused the Germans to suffer oil shortages at inopportune moments during the war, and these shortages should certainly be considered contributing factors to their eventual surrender.

The end of WWI did not cause Germany to stop obsessing over oil. When Adolf Hitler took control of the country in the 1930s, he was keen to develop a domestic synthetic fuel industry. When WWII started, synfuels refined from coal were a significant contributor to Germany’s energy needs. The one problem with this was that getting oil from coal requires a complicated, expensive and labor-intensive process. The process also needed large steel structures, which then made these synfuel refineries susceptible to air raids.

Hitler was undeterred, though. Under an agreement in 1939, Germany began receiving big shipments of oil from Russia. This wasn’t enough for the German industry’s (military and otherwise) thirst

for oil, so Hitler had to look to exotic lands (like the Caucasus) to get his oil fix.

Once Hitler found out about the vast oil reserves in the Caucasus, he decided to show what a swell guy he was, and commenced with an invasion of Russia in 1941, a mere two years after the Russians began generously allocating oil to him.

Post WWII, one of the often overlooked reasons for the Soviet Union’s lack of saber rattling and belligerence was the simple fact that it did not have access to enough oil to fight another war. The US worked hard to keep the Soviet Union out of the Middle East, and, for the most part, the scheme worked. Not only did this allow the US and its allies access to the oil reserves of countries like Saudi Arabia (thus preventing the Soviets from doing so), but it also gave the US and the West a strategic boost in global positioning, should another conflict break out.

FIG. 1. US Chief of Naval Operations Ernest King uttered a succinct order that became a rallying cry for the Allies.

Hydrocarbon Processing | JULY 2012 93

90 Years of Progress in the HPI Wartime innovations. During WWII, US Chief of Naval Operations Ernest King uttered a succinct order that became a rallying cry for the Allies. “Oil is ammunition,” Admiral King said. The propaganda arm of the US military ended up using this statement for promotional posters as you can see in FIGS. 1 AND 2.

One way that ammunition was distributed was via an explosive chemical compound by the name of trinitrotoluene (TNT).

TNT. Invented by a German in 1863, TNT was used by Germany and other militaries starting in the early 1900s. The breakthrough in source material for the explosive in the US did not happen, though, until 1933. That’s when the researchers at Standard Oil Development (the company that later became Esso and then Exxon) told the US Army about the detection of toluene in product streams from thermal reforming experiments on a petroleum-based naphtha. This first discovery later led to a significant new source of pure toluene, something that would help the Allies immensely when they were looking to blow things up.

These samples did not come up to the nitration-grade requirements, but Esso continued the research. Eventually, the scientists decided to give catalytic reforming a try. This process gave much improved results over the thermal route, and a pilot plant was built in 1938. Ultimately, a 99+% toluene stream was produced that could be nitrated.

FIG. 2. A US military promotional poster from WWII.

94 JULY 2012 | HydrocarbonProcessing.com

“With war pending, the Army’s interest in toluene became grave and they ordered a first batch amounting to 20,000 gallons,” said G. T. Westbrook, an expert on the subject of petroleum refining during the WWII time period. “A logistics nightmare existed at that time, as seen in the steps taken to fill this contract. The naphtha feedstocks were refined in Texas.

They were then shipped to New Jersey for reforming. This reformate stream was returned to Texas in 22 tank cars for aromatics recovery. Next, the aromatics (benzene, toluene and xylene) were shipped to Louisiana for recovery and purification of toluene. Finally, the toluene was shipped to Maryland for nitration.”

Such a far-flung production network meant that Esso did not make not make any money on its 1940 contract with the US military. Business did improve dramatically after that, and Humble Oil ended up building the Baytown Ordinance Works, a plant that, during WWII, produced more than half of the total toluene supply extracted from oil.

Aviation gasoline. The Allies’ aviation gasoline (AGN) program was tasked with producing a rather complex mix of fuels.

AGN is a high-octane, controlled-vaporpressure fuel for propeller-based planes.

In 1939, with motor gasoline at about 75 octane, AGN requirements would range from as low as 87 for a simple reconnaissance plane to 100 octane for high performance fighters and bombers.

According to Mr. Westbrook, in 1939 the US AGN capacity was about 17,000 bpd. Early in 1941, forecasts were at 35,000 bpd, but, after Pearl Harbor, those jumped to 190,000 bpd. AGN capacity finally crested at over 600,000 bpd in 1945.

To produce the right fuel at the right octane for military planes, it was decided that a major refining construction initiative would be accompanied by tweaking existing refineries. Over 300 refineries were targeted for this effort, which consisted of implementing blending policy and operational changes.

As Mr. Westbrook was keen to point out, operational changes included searching refineries for high-octane, straightrun blendstocks; coordinating interplant blendstock moves; maximizing cracked gasoline output for an AGN base, and allocating more feedstock to alkylation units for more alkylate output.

SBR. Along with fuel, WWII created a vast demand for styrene-butadiene rubber (SBR). When the natural rubber supply from Southeast Asia was cut off at the beginning of WWII, the US and its allies faced the loss of a strategic material. With US government sponsorship, a consortium of companies involved in rubber research and production united to produce a general purpose SBR on a commercial scale.

These companies, in collaboration with a network of researchers in government, academic and industrial laboratories, developed and manufactured, in record time, enough synthetic rubber to meet the needs of the US and its allies during WWII. Rubber was a commodity of great military importance. The construction of a military airplane used half a ton of rubber; a tank needed about one ton. Each person in the military required 32 pounds of rubber. Tires were needed for all kinds of vehicles and aircraft.

By the late 1930s, the US rubber industry became the largest and most technologically advanced in the world. During this time, the industry was using half the world’s supply of natural rubber, most of it coming from Southeast Asia.

Shortages of natural rubber caused by the advent of WWII led the US government to embark on a program to produce a substitute for this essential material quickly and on a very large scale. There was a real danger the war would be lost unless US scientists could replace almost a million tons of natural rubber with a synthetic substitute within 18 months.

To work this industrial and scientific miracle, the US government joined forces with rubber companies, the young petrochemicals industry and university research laboratories. The resulting synthetic rubber program was a remarkable scientific and engineering achievement.

The partnership expanded the US synthetic rubber industry from an output of 231 tpy in 1941 to an output of 70,000 tons per month in 1945.

Onto the future. While the relationship between the military and the hydrocarbon has been a good one, there are some military folks out there advocating for dialing down the military’s reliance on oil. A group of retired US generals recently put out a report (issued by CNA Analysis and Solutions) in which they advocated for a 30% reduction in the US’ use of petroleum.

90 Years of Progress in the HPI “A 30% reduction in our use of petroleum would significantly improve our national security,” the report said. “We chose our reduction target based on a specific military challenge. CNA analysis shows that if America used 30% less oil, our economy would have enough resilience to sustain the effects of a complete

shutdown of the Strait of Hormuz, or any other major shipping choke point, with little effect.”

The report argues that if the US achieves this 30% reduction, any terrorist attack or action by a rogue nation that would significantly disrupt the global flow of oil would cause little, if any, first

order economic impact to the US. The US spends billions of dollars each year on military operations in the Persian Gulf region. In a 2010 CNA report, the organization noted that the average estimate for the annual military cost of protecting oil traffic in the Arabian Gulf was $74 billion.

TABLE 1. Summary of alternatives to oil, with positives and negatives noted.

Algae-based biofuels

Cellulose-based biofuels

Compressed natural gas

Electric vehicles

Fischer-Tropsch derived fuels

Economic security

Diversification of fuel supply reduces price volatility and vulnerability to shocks. Domestic production would create jobs and new industry.

Diversification of fuel supply reduces price volatility and vulnerability to shocks.

Domestic production would create jobs and new industry.

Diversification of fuel supply reduces price volatility and vulnerability to shocks. Domestic production would create jobs.

Diversification of fuel supply reduces price volatility and vulnerability to shocks.

Domestic production would create jobs, depending on competitiveness of US automakers.

Diversification of fuel supply reduces price volatility and vulnerability to shocks. Domestic production would create jobs.

Geopolitcal security

Fuels can be produced in nonagricultural areas, diversifying supplies.

Rising demand for phosphorus could complicate pricing, supplies.

Benefits accrue to US and other grain producers. Production from indigenous biomass sources can diversify and stabilize global supplies.

Global gas reserves are plentiful, including within the US. Gas reserves tend to occur alongside oil reserves, so many oil producers would benefit.

Current advanced batteries require lithium and some rare earth minerals, the supplies of which could become constrained due to market or political forces. Some substitutes available.

Coal and gas reserves are relatively plentiful around the world.

Environmental security

Relatively low GHG emissions. Total GHG impact depends on type and means of algae cultivation.

Could require intense use of phosphates, CO2 and water.

Relatively low vehicle GHG emissions.

Cultivation requires fewer inputs than food crops (could be waste). Grasses, crop residues affect land values less than food crops.

Burns cleaner than oil, but releases much more GHG than ethanol. Large scale gas extraction has environmental hazards similar to oil drilling.

EVs emit no greenhouse gases.

Total impact would depend on source of energy.

Requires CO2 sequestration, or another means of reducing or storing CO2 to keep GHG emissions at acceptable levels.

Coal-burning F-T plants require large volumes of water.

Military implications

Sound for permanent installations in the continental US (CONUS).

Good potential for expeditionary use.

Sound for permanent installations in the CONUS. Good potential for expeditionary use.

Sound for permanent installations in the CONUS. For expeditionary use, volatility is a challenge.

Sound for permanent installations in the CONUS. Poor for expeditionary use because of limited, unreliable electric capacity at front lines.

Sound for permanent installations in the CONUS. Good potential for expeditionary use.

Technological or economic challenges

Technology unproven at commercial scale.

Costs uncertain.

Could be mixed into gasoline, or dropped in as alternative without major engine alteration.

High initial facility costs. Uncertainty about optimal source materials. Requires modified delivery and storage systems.

Can be mixed into gasoline, or dropoped in as alternative without major engine alteration.

Best for fleets with central refueling points. Wider delivery systems require special compression systems. High potential as source material for further refinement into fuel via F-T process or into methanol. Lower GHG than gasoline.

Already commercially available, but cost of vehicles high. Designing smaller, more powerful, affordable batteries is the key challenge. Recharging at massive scale could increase pressure on US energy grid.

Technology proven and commercially operative in other countries outside of US. Costs of new F-T plants are extremely high, though lower if source material is natural gas instead of coal.

**0–5 years for wide commercial availability

**0–5 years for wide commercial availability

**5–10 years to commercial availability

**0–5 years to commercial availability

= good

= Area of concern

**0–8 years for wide commercial availability

= Area of higher risk Table courtesy CNA Analysis and Solutions

Hydrocarbon Processing | JULY 2012 95

90 Years of Progress in the HPI “It is our view that there are several other strategically important reasons for maintaining a significant military presence in the Middle East beyond protecting oil routes,” the report said.

“However, it is clear that by reducing US demand for oil, and thereby reducing US economic vulnerability to supply and

price shocks, the US would increase its options in military presence, operations and costs in that region.”

The retired generals believe that making the US less sensitive to interruptions from overseas oil supplies also reduces the potential urgency of a military response to closures of critical ocean chokepoints.

For example, projections indicate that, in the next 15 years, China and India will be increasingly reliant on oil imports, including imports from the Persian Gulf region.

“If we begin to act now to make the US economy less sensitive to turbulent oil prices, our leverage will increase when asking other countries to supplement, or

TABLE 1. Summary of alternatives to oil, with positives and negatives noted (cont.)

Food crop-based biofuels

Traditional gasoline

Hydrogen fuel cells

Methanol

Propane

Economic security

Diversification of fuel supply reduces price volatility and vulnerability to shocks.

Domestic production would create jobs.

Reliance on gasoline contributes to trade deficit. Subsidies to oil and gas include military protection of supply chain, limited taxes, emergency funds for oil spills and use of public lands.

Diversification of fuel supply reduces price volatility and vulnerability to shocks. Domestic production would create jobs and new technologies could have spillover effects for new industries.

Diversification of fuel supply reduces price volatility and vulnerability to shocks.

Domestic production would create jobs.

Energy density is half that of gasoline, meaning more refuelings would be necessary.

Diversification of fuel supply reduces price volatility and vulnerability to shocks. Domestic production would create jobs.

Geopolitcal security

Benefits accrue to US and other grain producers, mostly stable democracies. Food vs. fuel tradeoff for grains could cause global political rift. Rising demand for phosphorus could complicate pricing and supplies.

Reliance on gasoline restricts foreign policy, underpins enduring military engagement in Middle East and profits countries who oppose the US.

Offer prospects for abundant transportation fuels. Enormous startup costs may limit technology to wealthy countries.

Methanol is relatively easy to produce from gas, coal or nuclear power and blends with traditional gasoline.

Production possible around the world, which would diversify global energy supplies.

Global gas reserves are plentiful, including within the US. Gas reserves tend to occur alongside oil reserves, so many oil producers would benefit.

Environmental security

Relatively low vehicle GHG emissions. Rising cropland values can lead to deforestation.

Cultivation can require intense use of energy, phosphates and water, increasing “well-towheel” GHG impact.

Burning gasoline from oil using internal combustion engines emits significantly more GHGs than any alternative fuel produced from natural gas or biomass or from gas powered electricity plants.

Offer cleanest known technology, with no emissions.

Total impact would depend on need for electricity and its source.

Diversification of fuel supply reduces price volatility and vulnerability to shocks.

Domestic production would create jobs and new technologies could have spillover effects for new industries.

Propane burns cleaner than oil but releases much more GHG than ethanol.

Military implications

Sound for permanent installations in the CONUS. Good potential for expeditionary use.

Optimal power per weight, but costs for delivery in expeditionary use can be very high.

Volatility a challenge.

Additional weight and size for fuel tank unsuitable for expeditionary use.

Sound for permanent installations in the CONUS. Good potential for expeditionary use, but twice as many fuel convoys.

Volatility a challenge.

Additional weight and size for fuel tank unsuitable for expeditionary use.

Technological or economic challenges

Technology established.

Less efficient than biofuels from cellulose.

As stand-alone fuel requires modified delivery and storage.

Can be mixed into gasoline, or dropped in as alternative without major engine alteration.

Technology established. High price volatility controlled by cartel.

Mostly imported.

Poses significant national security vulnerability. High GHG content.

Commercially available, but in small numbers and at high cost.

Weight and size of fuel tanks presents design challenges.

Would require new hydrogen delivery infrastructure.

Techology is established from natural gas and coal, under development from biomass.

High startup costs for new plants. Can be mixed into gasoline, or dropped in as alternative without major engine alteration.

Less efficient per volune than gasoline, requiring frequent fuel tank replenishment. Most efficient for specialized fleets of small vehicles. Requires compressed storage and delivery.

High GHG content.

**5–15 years for wide commercial availability

**0–5 years for wide commercial availability

**Widely available now

**0–5 years for wide commercial availability

= good

= Area of concern

**Widely available now

= Area of higher risk Table courtesy CNA Analysis and Solutions

96 JULY 2012 | HydrocarbonProcessing.com

90 Years of Progress in the HPI cooperate with, US forces in assuring the flow of oil through the region,” the report said. “The US will, in our view, be relieved of some of the military and economic burden of protecting those sea lanes, and be able to focus resources elsewhere.”

So if the US’ economy and military are to reduce reliance on oil, how will they do it? The answer could be biofuels.

Biofuels. Ethanol and biodiesel have, for years, been produced and consumed around the world as fuel additives and, less often, as stand-alone fuels. In the US today, most light duty vehicles are burning gasoline blended with up to 10% ethanol.

At present, the US and Brazil lead the world in the manufacture and use of ethanol. France, Sweden and Germany are major producers of biodiesel. These technologies continue to advance in efficiency, raising the possibility of future mass production of fuel from cellulose (like grasses, wood and sawdust), algae, manure and municipal or industrial waste.

In 2008, biofuels accounted for less than 2% of the world’s transportation fu-

els, but their use is growing dramatically.

Part of their attractiveness is that the processes of their conversion into portable forms of energy generally emit much lower levels of CO2 and other greenhouse gases than result from the conversion of gasoline. The other key aspect in the growing use of biofuels is government mandates and subsidies.

Under the US Energy Independence and Security Act of 2007, the US government has defined a Renewable Fuel Standard (RFS) that mandates, out to 2022, the increasing use of renewable fuels as gasoline additives in the US. The trend in these standards is to keep the volumes of corn-based ethanol and biodiesel roughly constant, while increasing the level of cellulosic ethanol and, more slowly, advanced non-cellulosic ethanol.

Complicating factors. There are many variables to consider when advocating one alternative fuel over another. Are there economic or geopolitical security issues to consider? Are there unforeseen consequences to the environment? What are the military implications? Even if a re-

THURSDAY, JULY 12, 2012 10 a.m. CT, 11 a.m. ET

HEINZ BLOCH:

placement fuel is found that addresses all of these concerns in a satisfactory manner, technical or economic challenges to the full ramp up of the fuel source must be considered. TABLE 1 presents the pluses and minuses of an assortment of alternative fuels.

Finishing strong. Crude oil and the refined products derived from it has been a key cog in military operations from the years before WWI all the way to present day. Finding, defending and maintaining access to oil supplies has also been a key military activity during the last 100 years and one that promises to continue.

However, there is the possibility of change on the horizon, as arguments are growing in volume that such reliance on the hydrocarbon is unhealthy and unsustainable. A variety of biofuels exist in all forms of development, but it remains unclear if any of them have the staying power or the energy dependability to replace the hydrocarbon and take militaries and the globe on which they reside into the next century.

LIVE WEBCAST

2012

HOW MAINTENANCE PERFORMANCE UPGRADING AVOIDS FAILURES

When a selective preventive maintenance program is developed and managed correctly, it is the most effective type of maintenance plan available.

The proof of success can be monitored and demonstrated in several ways: • Improved plant availability • Higher equipment reliability • Better system performance or reduced operating and maintenance costs • Improved safety A plant staff’s immediate maintenance concern is to respond to equipment and system functional failures as quickly and safely as possible.

Every maintenance event must be viewed as an opportunity to upgrade so as to avoid repeat failure. This italicized sentence is the key to superior maintenance. Even good maintenance refers to relatively frequently scheduled work.

In stark contrast, systematic upgrading will designout maintenance and extend allowable intervals between shutdowns.

Heinz Bloch will draw on 50 years of experience. His presentation will give solid field examples instead of what he calls “consultant-conceived generalities.”

Watch live on July 12, 2012 and take part in a 15 minute live Q&A that takes place after Heinz’s presentation. View on demand after July 13.

Sponsored by:

Register at HydrocarbonProcessing.com

Hydrocarbon Processing | JULY 2012 97

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Top HPI construction project review A. BLUME, Process Editor

Qatar LNG: Mega-trains and major ambitions

LNG evolution. Qatargas commenced LNG exports to Japan and Spain in January 1997 with the startup of the Qatargas I project in Ras Laffan Industrial City. The first phase encompassed three trains with an initial collective capacity of 6 million tons per year (MMtpy); total capacity was lifted to 9.6 MMtpy after the completion of a debottlenecking project in 2005. The capacity gain from the debottlenecking also helped Qatar overtake Indonesia in 2006 as the world’s largest LNG exporter. Qatargas I stakeholders include Qatar Petroleum (65%), ExxonMobil (10%), Total (10%), Mitsui (7.5%) and Marubeni (7.5%).

The site’s second phase, Qatargas II, was the world’s first fully integrated value-chain LNG venture when it debuted in April 2009. It has two LNG mega-trains (FIG. 2), each with a capacity of 7.8 MMtpy, along with five 145,000-m3 LNG storage tanks. The project is tied to Europe’s largest LNG receiving terminal, South Hook LNG, which is located at Milford Haven in Pembrokeshire, Wales. The UK sources 20% of its natural gas demand through this terminal. Some LNG from Qatargas II is sent elsewhere in Europe and also Asia and the US. Train 4 is a joint venture between Qatar Petroleum (70%) and ExxonMobil (30%), while ownership of Train 5 is divided among Qatar Petroleum (65%), ExxonMobil (18.3%) and Total (16.7%).

Qatargas II won several environmental and project development awards in 2007 and 2008. Environmental sensitivity,

as demonstrated by offshore workers’ careful relocation of more than 4,500 coral colonies from the sea floor to specially prepared ecoreefs, played an important role in the project.

Other environmental precautions include the development of a common volatile organic compound (VOC) control system to reduce smog at the Ras Laffan port; smokeless flaring at the LNG facility; the rescuing and releasing of sea snakes from cooling seawater pipes; and an extensive recycling program.

The project’s efficient and safe development also was praised. Qatargas II’s 30 wells were completed 27 rig-months ahead of schedule, and the project saw the fastest well drilling in the North Field—14,500 ft of rock in only 33 days. Also, 12 10 Total capacity, Bcfd

Qatargas, the company behind what is presently the world’s largest liquefied natural gas (LNG) production facility, put down roots in 1984 and is headquartered in Doha, Qatar. It was the first company to start up LNG operations in Qatar, and it remains the largest. RasGas, the world’s second-biggest producer of LNG and the only other producer in Qatar, came on the scene in 2001 and now has seven trains to rival those of Qatargas. The two companies boast a combined production capacity of 77 MMtpy, with Qatargas accounting for 42 MMtpy of the total. FIG. 1 shows the robust growth in Qatar’s LNG production capacity from 1996–2011.

Qatargas’ seven LNG trains are fed by Qatar’s North Field, which is part of the South Pars/North Dome natural gas and condensate field shared by Qatar and Iraq—the largest nonassociated gas field in the world. According to the US International Energy Agency, the field holds an estimated 1,800 trillion ft3 (51 trillion m3) of in-situ natural gas and around 50 billion bbl (7.9 billion m3) of gas condensate.

8 6 4 2 0 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 Source: Reuters

FIG. 1. Qatar’s LNG capacity has expanded from just over 1 Bcfd in 1996 to more than 10 Bcfd in 2011.

FIG. 2. Qatargas’ LNG mega-trains 4 and 5. Photo courtesy of Technip.

Hydrocarbon Processing | JULY 2012 99

Top HPI construction project review Qatargas recorded 108 days without a single medical treatment or injury in 2008, which James Adams, former CEO of Qatargas II, likened to an average family of five going 200 years without needing to see a doctor.

LNG production expanded in November 2010 with the startup of Qatargas III, which included the construction of another 7.8-MMtpy LNG mega-train and two subsea pipelines, and the drilling of 33 wells. The pipelines and wells are shared with Qatargas IV, as the third and fourth phases were designed by a joint asset development team to capitalize on synergies between the two projects. Qatargas III’s Train 6 exports LNG to the US, Asia and Europe, and is owned by Qatar Petroleum (68.5%), ConocoPhillips (30%) and Mitsui (1.5%).

The fourth and final Qatargas LNG expansion project, Qatargas IV, commenced production of 7.8 MMtpy of LNG at its single mega-train in January 2011. Qatargas II, III and IV utilize Air Products’ proprietary APX processing technology, which generates economies of scale and achieves integration previously unseen in the LNG industry. Exports from Qatargas IV—a joint venture of Qatar Petroleum (70%) and Royal Dutch Shell (30%)—are sent to North America, the Middle East and Asia.

Other Qatargas developments at the Ras Laffan site include the 146,000-bpd Laffan condensate refinery, which came onstream in September 2009 and which processes North Field condensate produced by both Qatargas and RasGas. The refinery has production capacities of 61,000 bpsd

of naphtha, 52,000 bpsd of kerosine/jet fuel, 24,000 bpsd of gasoil and 9,000 bpsd of liquefied petroleum gas (LPG).

A second, 146,000-bpd condensate refinery is slated to start up in early 2016. Laffan I refinery shareholders include Qatar Petroleum (51%), ExxonMobil (10%), Total (10%), Idemitsu Kosan (10%), Cosmo Oil (10%), Mitsui (4.5%) and Marubeni (4.5%).

Vision for the future. Qatargas aims to become the world’s premier LNG producer by 2015 through innovation, operating excellence, corporate citizenship and environmental responsibility. At the Flame 2012 conference in Amsterdam in mid-April 2012, Qatargas CEO Alaa Abu Jbara noted, “One of the key achievements of Qatargas has been our ability to maintain reliability in our operations. Thus, our history of project execution is a key factor in our continued future success.”

Looking to the future, Mr. Abu Jbara believes that Qatar’s prominence as an LNG exporter will prevail, despite predictions that the US (which is rich in shale gas) or Australia (which is constructing multiple LNG projects) could overtake Qatar as the world’s largest LNG exporter in the next six to eight years.

Mr. Abu Jbara asserted, “In a world of competition for long-term energy supplies, access to LNG produced in Qatar is considered by many as a strategically important component of a diversified LNG supply portfolio, offering unparalleled security of supply.”

Marketing, Inside Out Marketing in the Oilfield 2012 will provide you with the tools necessary to maximize your marketing efforts in the oil and gas industry. Expert speakers in an array of topic-focused sessions will offer you guidance and insight that will enable you to effectively plan your marketing strategy for 2012 and beyond.

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Top HPI construction project review S. ROMANOW, Editor

Largest ethane cracker: Borouge’s Ruwais manufacturing complex Ethylene is the bell-weather petrochemical and the feedstock for many petrochemicals and polymers. The size of ethylene facilities has increased since the first ethane crackers were constructed in the 1950s. With advances in “cracking” technology, larger ethylene complexes were possible, now reaching over 1 million tpy (1 MMtpy) of ethylene capacity.

Where is, and who operates, the largest ethylene complex? Answer: Borouge, a joint venture between Abu Dhabi National Oil Co. (ADNOC) and Borealis, operates the largest ethane cracker with 1.5 MMtpy of ethylene capacity.

Central to Borouge’s operations is the petrochemical production complex in Ruwais, about 250 km west of Abu Dhabi City in the United Arab Emirates (UAE). Borouge invested US$1.2 billion to build the first petrochemical facility in the Middle East. In 2001, Borouge started production with a total manufacturing capacity of only 450,000 tpy (450 Mtpy) of polyethylene (PE). By 2005, the complex consisted of an ethylene cracker (EU1) built by the alliance of Bechtel and Linde. Additionally, two Borstar bimodal PE units were constructed by Tecnimont (PE1/PE2), each capable of producing 300 Mtpy of bimodal PE. In 2010, under the project name of Borouge 2, Borouge tripled the polyolefins manufacturing capacity of this complex.

The approximately $5 billion investment enabled Borouge to produce a total of 2 MMtpy of Borstar polyolefins. This project included an additional ethane cracker (EU2), a third PE unit, an olefins conversion unit for the conversion of ethylene to propylene, and two new polypropylene (PP) units, spearheading the company’s entrance into PP production.

The 1.5-MMtpy ethane cracker (EU2) was built by the Linde Group at a cost of $1.3 billion, and it is considered to be the largest in the world, as shown in FIG. 1. With the first and second ethane crackers put into production, Borouge can now produce 2.1 MMtpy of ethylene.

Borouge is expanding its petrochemical plant at Ruwais by 2.5 MMtpy to a total annual capacity of 4.5 MMton by the end of 2013 and the new cracker will be operational by mid-2014.

The expansion project, entitled Borouge 3, is progressing safely as planned with approximately 60% of its construction completed as of March 2012.

The project includes an ethane cracker (EU3), two PE units and two PP units, as well as a low-density PE (LDPE) unit.

Bechtel is providing management support for this construc-

tion project. The project’s new (and third for Borouge) ethane cracker will produce 1.5 MMtpy of ethylene and is being built by the Linde Group at a contract value of $1.075 billion.

The unique Borstar technology that Borouge uses in its production enables the company to provide a differentiated range of PE and PP innovative plastics solutions for infrastructure applications (including pipe systems, and power and communication cables), automotive components and advanced packaging.

Borouge is a leading provider of innovative, value creating plastics solutions; it is a groundbreaking international partnership at the forefront of the next generation of plastics innovation. With its base in the UAE and its Marketing & Sales head office in Singapore, Borouge employs approximately 1,700 people representing more than 40 nationalities and serving customers in more than 50 countries across the Middle East, Asia-Pacific, Indian sub-continent and Africa.

Borouge is also investing in plants and logistics hubs in Asia and in an Innovation Centre in Abu Dhabi. Focused on its company mission, Value Creation through Innovation, Borouge ensures that its customers throughout the value chain, around the world, can always rely on superior products and security of supply. Borouge is committed to the principles of Responsible Care, and, together with Borealis, it proactively contributes toward addressing the world’s water and sanitation challenges through its “Water for the World” initiative.

FIG. 1. Night view of Borouge 2, the world’s largest ethane cracker.

Hydrocarbon Processing | JULY 2012 103

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Top HPI construction project review S. ROMANOW, Editor

Largest hydrocracker in China Hydrocracking is not a new process. The first hydrocracker was constructed at the Leuna, Germany, industrial complex to convert lignite coal into liquid fuels. Hydrocracking evolved as a method to convert the “bottom of the barrel” into lighter, highervalue products than that achieved through delayed coking operations. These operations often focus on the deeper conversion of vacuum gasoil and heavy-coker gasoil. As refinery feedstocks become higher in sulfur content and lower in API, refiners are seeking process changes to facilitate production of middle distillates.

Hydrocracking has always been considered an expensive processing option due to operating costs for hydrogen consumption and capital costs for high-pressure reactors. As the global market continues to shift to diesel and lower sulfur fuels, investment in hydrocracking capabilities will increase.

China is now the No. 1 nation in energy consumption. Chinese demand for energy, especially transportation fuels, is growing as a new middle class exercises more purchasing power to own consumer goods such as automobiles, along with the transportation fuels to power them. China’s refining industry, with 10.8 million bpd in refining capacity, is seeking opportunities to meet growing demand for transportation fuels.

China’s largest hydrocracker. China National Offshore Oil

Corp.’s (CNOOC’s) grassroots Huizhou refinery tackled part of the fuels dilemma with the construction of a 240,000-bpd grassroots refinery in 2009. This project included constructing an 80,000-bpd (4-metric tpy) hydrocracker. The Huizhou hydrocracker, licensed and engineered by Shell Global Solutions BV, is the largest hydrocracker operating in China. This hydrocracker presented several design challenges. In addition to being the largest hydrocracker in operation, the Huizhou refinery would be processing a very difficult-to-process feed—100% heavy, high-acid Peng Lai crude oil. In the design, much consideration was directed at handling the high naphthenic feed to ensure middle distillate products would meet all specifications for jet fuel and ultra-low-sulfur diesel.

Working with Shell Global Solutions and Criterion Catalyst and Technologies, a tailored hydrocracking catalyst system was developed as part of the design of the grassroots hydrocracker.

This hydrocracker has two parallel reactor trains, each with one reactor and a common separation and fractionation section.

The reactors use multiple catalyst beds for demetallization, pretreating and cracking catalysts.

The Huizhou hydrocracker produces kerosine as jet fuel and ultra-low-sulfur (10 ppm maximum) diesel with a cetane

FIG. 1. CNOOC’s hydrocracker provides middle distillate streams and hydrowax for an adjacent ethylene facility.

number of 65. More important, the new hydrocracker was designed with flexibility to meet future specifications for cleaner fuels. In addition, the hydrocracker also produces a high-quality feedstock for the new ethylene cracker operated by the Nanhai petrochemical complex.

The $3 billion (€1.94 billion) refinery uses leading-edge technology to produce “clean” middle distillates such as diesel, jet fuel and kerosine. The consultancy group, The Catalyst Group, forecasts that global hydrocracking capacity exceeded 5.8 million bpd in 2010, and it will increase 40% by 2013. According to Süleyman Özmen, vice president of refining and chemical licensing for Shell Global Solutions International BV, more hydrocracking capacity will be planned in China and Far East to meet growing demand in low-sulfur transportation fuels. Refiners are leveraging hydrocracking to respond to the momentum in global dieselization, especially as crude prices force refiners to process distressed crudes and difficult feedstocks.

The general trend is for more hydrocrackers to be constructed as part of refinery upgrades or grassroots projects. Much of this construction will be in the Middle East and Asia. The impact of these changes on refiners, who are already contending with the changing feedstock slate and increasingly stringent environmental standards, has been severe.

Editor’s note. CNOOC is planning a second-phase project that is estimated at $7.5 million.

BIBLIOGRAPHY Complete bibliography available online at HydrocarbonProcessing.com.

Hydrocarbon Processing | JULY 2012 105

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Special Supplement to

DOWNSTREAM I N N O VAT I O N S 1922 TO PRESENT

HPI major events and trends, 1920s to present [D–111] CORPORATE PROFILES ABB [D–121] Axens [D–123] CB&I [D–125] Imperial Crane [D–127] Linde AG [D–129] Curtiss-Wright Flow Control [D–131] T.D. Williamson [D–133] Wood Group Mustang [D–135] BASF [D–138] Yokogawa [D–139] Baker Hughes [D–140] Carver Pump Company [D–142] Chevron Lummus Global [D–143] Elliott Group [D–144] Saint-Gobain NorPro [D–145] COVER PHOTO

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BENZOUT

Converts benzene contained in the refinery’s gasoline blend-stock into high octane alkyl-aromatics by reacting benzene with light olefins.

2010

2000 SELECTIVE LUBE DEWAXING (MSDW)

ExxonMobil’s new generation of MSDW technology continues to lead the industry.

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MTG converts methanol to sulfur free gasoline, including first commercial CTL application.

1970 DISCOVERY OF ZSM-5 ZEOLITE

1960 Hydrofinishing Catalyst POWERFORMING

1950

The discovery of ZSM-5 revolutionized many catalytic processes in refining and petrochemical industry.

FLUID CATALYTIC CRACKING FCC unit in 1942 would become the industry standard for production of gasoline.

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For more information about this study, see the full article at www.bre.com/support/technical-articles/ gas-treating.aspx

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HPI MAJOR EVENTS AND TRENDS, 1920s TO PRESENT 1920s: THE FORMATION OF THE MODERN HPI During this period, a new industry was evolving focused on the refining of crude oil into fuels and other products. New demand for crude oil-based products, such as kerosine for lighting purposes and gasoline for transportation, spurred the advancement of the early hydrocarbon processing industry (HPI). While still in their infancy, startup refining groups discovered new methods throughout the 1920s to efficiently transform crude oil into refined products.

The early refining industry struggled to move crude oil and refined products to consumer markets. High government taxes and railroad freight rates complicated the profitability of this industry. Safety was another pressing issue when processing hydrocarbons. Fires were a constant threat as the industry labored to find best practices and better designs to minimize risks. Overall, the 1920s was a decade of early research and construction to process motor fuels in the US and Europe.

World War I (WWI) had mobilized the US, and the same trend was emerging in Europe.

1930s: TECHNOLOGY ADVANCEMENT AMID FINANCIAL CRISIS If one were to rank the decades of the 20th century on a qualityof-life basis, the 1930s would not fare very well. The decade began in the fierce grip of the Great Depression and concluded with World War II (WWII). As a time period best known for economic devastation and war-mongering, the 1930s require more than a cursory glance to discover their redeeming qualities. However, such qualities are present under close examination, especially with regard to the HPI. Important industry innovations and discoveries were made during these years of global upheaval. Some of the most significant follow below.

Polyethylene. In 1933, two organic chemists working for the Imperial Chemical Industries Research Laboratory in England were testing various chemicals. The researchers set off a reaction between ethylene and benzaldehyde, which caused their testing container to spring a leak and lose all pressure. All that remained in the container after the reaction was a white, waxy substance resembling plastic. Upon carefully repeating and analyzing the experiment, the scientists discovered that the loss of pressure was only partially due to the leak. The major reason

for the pressure loss was that the polymerization process they witnessed had left behind a substance that would be named polyethylene (PE).

The first patents for PE were registered in 1936 by Imperial Chemical Industries. A year later, the first practical use for the material, as a film, was discovered.

During WWII, PE played a crucial role in the development of radar, as it became the standard insulation used in British radar cables due to its high electrical resistivity. PE was later used for less serious applications, as it became a key component in hula hoops and Tupperware.

Alkylation. Alkylation, first commercialized in 1938, experienced tremendous growth during the 1940s as a result of demand for high-octane aviation fuel during WWII. During the mid-1950s, refinersâ&#x20AC;&#x2122; interest in alkylation shifted from the production of aviation fuel to the use of alkylate as a blending component in automotive motor fuel. A decision by the US Environmental Protection Agency (EPA) in the 1970s to eliminate lead in gasoline further increased demand for alkylate as a blending component for motor fuel.

Fischer-Tropsch process. Franz Fischer and Hans Tropsch invented the Fischer-Tropsch process while working at the Kaiser Wilhelm Institute in Germany during the 1920s. It was commercialized in Germany in 1936. The Fischer-Tropsch (FT) process involves the conversion of synthesis gas (syngas) into liquid fuels. Syngas can be produced from coal, natural gas or biomass either by incomplete burning of the fuel or through gasification. Germany used the FT process during WWII for aviation and automobile fuel. This was a particularly useful innovation for the Germans, since the country had ample coal within its borders but limited access to hydrocarbons.

The FT process is once again a hot topic of conversation, as interest in biofuels and the desire to limit carbon emissions are at the forefront of global energy discussions.

Catalytic cracking. French scientist Eugene Houdry introduced catalytic cracking in 1936. By using silica-based and alumina-based catalysts, he demonstrated that more gasoline can be produced from oil without the use of high pressure. As an added benefit, gasoline derived via

FIG. 1. Lion Oil & Refining Co. facility in Oklahoma, 1923.

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catalytic cracking has a higher octane rating and burns more efficiently compared to other processes.

Mr. Houdry originally focused on lignite as a feedstock, but switched to heavy liquid tars after moving to the US in 1930. Although others had experimented with catalysts for this purpose, they were stymied by the fact that the catalyst ceased to work after a time. Mr. Houdry diagnosed the nature of the problem and developed a method to regenerate the catalyst. The first Houdry unit was built at Sun Oil’s Marcus Hook, Pennsylvania refinery in 1937. Many more units were built by the 1940s. As a whole, catalytic cracking was seen as a significant contributor to the Allies’ eventual victory in WWII, by supplying the high-octane gasoline needed by the air forces of Great Britain and the US.

Butyl rubber. Polyisobutylene was first developed by the BASF unit of IG Farben in 1931 and sold under the trade name Oppanol B. It was developed into butyl rubber in 1937 by researchers at Standard Oil’s laboratory in Linden, New Jersey. Today, the majority of the global supply of butyl rubber is produced by ExxonMobil, the successor to Standard Oil; and LANXESS, a spinoff of Bayer. The first major application of butyl rubber was tire inner tubes. It is now also used in adhesives, caulks and sealants, agricultural chemicals, electrical fluids, fiber-optic compounds, ball bladders, lubricants, personal care products and as a fuel additive.

Saran. In 1933, a Dow Chemical lab worker accidentally discovered polyvinylidene chloride. Dow researchers took the initial discovery

and turned it into a greasy, dark green film, which the company called “Saran.” The military started using it, spraying Saran on fighter planes to guard against salty sea spray, while automakers used it in upholstery.

Dow later eliminated Saran’s green color and unpleasant odor. This led to it being released on the consumer market as Saran Wrap, ensuring that leftovers from dinners could be preserved for another day.

Polyurethanes. In 1937, Otto Bayer and his co-workers discovered and patented the chemistry of polyurethanes. These flexible foams are used in a wide variety of consumer products, including upholstery and mattresses. They also are an important part of chemical-resistant coatings, specialty adhesives and packaging. On the industrial side, polyurethanes help insulate buildings, water heaters and all manner of refrigeration devices.

Teflon. Springtime in New Jersey during 1938 meant one thing: the discovery of polytetrafluoroethylene (PTFE). Dr. Roy Plunkett and his colleagues at the DuPont laboratory in Jackson, New Jersey, were working with gases related to Freon refrigerants. During their experiments, a frozen, compressed sample of tetrafluoroethylene was discovered to have polymerized spontaneously into a white, waxy solid, which they named PTFE. The product was first marketed under the DuPont Teflon trademark in 1945. The molecular weight of Teflon can exceed 30 million atomic mass units, making it one of the largest molecules known to man.

Teflon was first used by the US military in artillery shell fuses and in the production of nuclear material for the Manhattan Project. It is now a major reason that washing dishes after cooking a big meal is a relative breeze, since Teflon’s slippery, non-stick properties are applied to most pots and pans in kitchens today.

1940s: GLOBAL WAR SPURS INNOVATION The 1940s was truly the period that transformed the modern refining industry. Germany had been conquering European nations in the late 1930s, and it set its sights on the UK. The US sustained a laissez-faire attitude on the outside world as it pulled itself out of the Great Depression. However, on Sunday, December 7, 1941, everything changed as Japan attacked US troops in Hawaii. After the assault on Pearl Harbor, the US officially entered WWII. This war would be fought on several continents and require new transportation and aviation fuels to power advanced war machines for the Allied and Axis armies. Meeting new demands for transportation and logistics set the course for global refining and petrochemical operations.

Fueling the war. In WWII, new military planes were designed to operate on 100-octane fuels. Previous jets used 75-octane fuel. However, with the advanced airplane engines of the 1940s, aviation fuels needed to be more efficient and able to facilitate carrying larger cargos over longer distances. The cost to produce 100-octane fuel was estimated at $25/gal. The 1940s-era modern refinery used several processing methods including crude distillation, visbreaking, gasoil cracking and catalytic alkylation to yield refined transportation products. However, not all refineries were configured in a similar manner. Transporting armies and supplies became the driving factor for investment in heavy industry and energy.

FIG. 2. Advertisements in the 1940s promoted new technology, such as Phillips Petroleum’s technology suite for the production of 100-octane aviation gasoline.

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Defense efforts push oil to record levels during 1941. Demand for petroleum products in 1941 was the greatest in the oil industry’s then-80year history—nearly 1.6 billion bbl, or 10% above 1940 levels. To meet US national defense emergencies, the petroleum industry spent hundreds of thousands of dollars in 1941 for new refining equipment, new pipe-

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lines and tanker ships, along with regular capital investment. Yet, massive reconfigurations and capacity expansions were still necessary to provide sufficient transportation fuels to support US military actions. Secretary of the Interior Harold L. Ickes was appointed Petroleum Coordinator for National Defense (which was later changed to Petroleum Coordinator for War). Ickes had the task of mobilizing the US refining industry and resources to produce gasoline, diesel, synthetic rubber (SR) and other compounds to support US troops.

Although US petroleum demand for domestic use and export rose sharply in 1941 to a new record high, demand for transportation fuels and petrochemicals, such as SR and toluene, would be substantially greater in 1942 as the country proceeded with unprecedented civilian activity and worldwide military action. Fuel oils assumed greater importance as war efforts by the Navy, Army, merchant ships, railroads, electric power plants, mines, smelters and factories boosted fuel oil demand.

Lead had been used in jet fuel, but new blendstocks from alkylation units provided even higher octane values.

The program involved the construction of catalytic cracking capacity along with new alkylation and isomerization units. The core of the program was the construction of 94 plants to support the blending of 100-octane aviation gasoline. The cost for the US government-sponsored construction program exceeded $900 million. With the completion of the program, 60 refineries were equipped with FCC units in the latter half of the 1940s. Key to the accelerated design and construction of the new refining units were agreements by licensors of the catalytic cracking technology to reduce royalties until WWII had ended.

While the US focused on petroleum to power its war machines, Germany focused on hydrogenating coal into heavy oils, which were then converted into aviation fuels, diesel and SR. It was the more expensive fuel production route. Germany lacked substantial domestic crude oil reserves and was cut off from imports. Coal conversion was an established process; German companies were licensing this technology before the start of WWII.

Beginning of the modern petrochemical age. Besides quality fuels, Decade of cooperation. The US government, in cooperation with domestic refining companies, embarked on a massive construction program in the 1940s to expand processing capability. The new capacity would provide much-needed gasoline and diesel along with higheroctane aviation fuels for the military. Also, the Petroleum Industry Council for National Defense was organized as a consortium between the US federal government and the domestic refining industry.

New refining technologies were required to produce 100-octane fuel for the gasoline blending pool. Many refiners were researching and commercializing new refining processes that achieved higher octane and better quality levels for gasoline, aviation fuels and naphtha. However, a new process, fluid catalytic cracking (FCC), was soon identified as the technology foundation to meet quantity and fuel-specification goals. Several licensing companies joined in the effort. Refining technology leaders participating in the 100-octane program included M. W. Kellogg (now KBR), Universal Oil Products (UOP, a division of Honeywell), Standard Oil Co. of Indiana, Texas Co., Royal Dutch Shell and Anglo-Iranian Oil Co. The push was to produce aviation-grade alkylate.

FIG. 3. In addition to gasoline and diesel, the refining and chemical industry focused on other petrochemical products to replace natural rubber. Processing capability to extract valuable C4s and C5s from FCC streams were needed to supply SBR facilities. Pictured is a column lift at the Neches Butane facility in Port Arthur, Texas.

other materials were in short supply, such as natural rubber needed for tires. The new catalytic cracker units under construction yielded butane-butylene raw materials. Butylenes could be used as feed for alkylation units, and, more importantly, butylenes could be converted to butadieneâ&#x20AC;&#x201D;a building block for styrene-butadiene rubber (SBR) or SR. Again, cooperation on royalties for SBR processes by licensors was requested by the US government to push forward the construction and operation of the much-needed SBR capacity.

With the cooperation of the refining industry to provide raw materials, 700,000 tons of SBR production was constructed and put into operation by the end of 1943. Twenty-two companies were involved

FIG. 4. Isoprene columns being hoisted at the Neches Butane facility in Port Arthur, Texas.

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in this project—11 petroleum companies, seven chemical companies and four rubber manufacturers including Firestone Tire & Rubber Co., B. F. Goodrich Co., Goodyear Tire & Rubber Co. and US Rubber Co. Aromatics such as toluene, benzene and xylene were also used in the war effort. Research and development (R&D) work focused on new separation methods to increase yields of toluene—a precursor to the explosive TNT. Newly built planes and trucks required tires. Finding sufficient supplies of styrene fostered advanced dehydrogenation of ethylbenzene to styrene monomer. By the end of the 1940s, R&D efforts had made significant contributions to downstream petrochemicals production. By the end of the decade, US refining capacity had increased from 4.9 million bpd (MMbpd) to 6.55 MMbpd.

1950s: ERA OF REBUILDING Refining capacity in countries outside of the US increased by 150% between 1945 and 1952, from 2.02 MMbpd to 5.04 MMbpd. Much of the new construction was supported by US investments to build and

rebuild refining capacity in areas of Europe that were destroyed by bombing during WWII. The UK, France, Germany and Italy were the countries receiving aid to rebuild; the UK added 409,000 barrels per day (Mbpd) of new refining capacity, France gained 330 Mbpd, Italy built 296 Mbpd and Germany added 113 Mbpd. Fourteen refineries were modernized, expanded or constructed in Western Europe with the aid of Marshall Plan financing during the 1950s. The estimated cost of the projects totaled $234 MM. Likewise, construction continued in the US to provide transportation fuels for the private sector. In 1952, approximately 475 Mbpd of new refining capacity was approved. The overhanging challenge from the past decade was limited availability of construction materials, such as steel. In the early 1950s, the US government still allocated construction materials.

By the end of 1959, the US would have 291 operating refineries, down from 361 in 1947. Refining capacity throughput increased from 5.3 MMbpd to 9.5 MMbpd in 1959. Likewise, plant size increased.

Over the same period, HPI employment decreased 7%. With a smaller workforce, production output increased 105%, and total salaries and wages increased 76%.

Petrochemicals. By the end of the 1940s, R&D efforts had made signifi-

FIG. 5. Construction of FCC units supported efforts to provide 100-octane aviation gasoline and were sponsored by the US government. Shown is the dedication ceremony for Texas Co.’s FCC unit in Port Arthur, Texas, on February 29, 1944. By the end of 1945, this refinery had a processing capacity of 1 MMbpd of aviation gasoline.

FIG. 6. Over 75% of the total production of butadiene for the US government’s synthetic rubber program was based on Union Carbide and Carbon Corp.’s alcohol process. Pictured is the butadiene unit in Institute, West Virginia, which was built for Defense Plant Corp. and operated by Rubber Reserve Co. D-114

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cant contributions to downstream petrochemicals production. Many early petrochemicals, such as low-density polyethylene (LDPE), polyurethane (PU), polyethylene (PE) terephthalate, nylon, SBR and many more, were discovered in the 1930s. With the need to provide materials for the war effort, R&D efforts focused on commercializing and installing capacity for the new petrochemical products. At the conclusion of WWII, a wave of new polymers and other petrochemicals shifted from military products to consumer goods.

Efforts continued to improve processing technology with new catalysts, equipment and methods to decrease costs and provide more consumer applications. In 1953, Karl Ziegler found a process to produce PE at atmospheric conditions, using a special alumina catalyst.

This discovery reduced PE manufacturing costs and yielded a more crystalline high-density PE (HDPE) resin that could be molded, casted and extruded. Polypropylene was discovered as a side product of PE research during the 1950s.

PE continues to be commonly referred to as plastic. The world fell in love with plastic due to its versatility and almost endless range of colorful consumer products. Meanwhile, PU helped fast-track designs to manufacture refrigerators for homes as industry converted from military supplies

FIG. 7. Installation of a new distillation unit at BP’s Lavera refinery near Marseilles, France.

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to consumer goods. Output of the major polymers—resins, plastics, SR and synthetic fibers—increased during the 1950s. By 1959, production of plastics and resin materials reached 6 billion lb. PE, with an output of about 1.4 billion lb, was the leading resin, followed by vinyl resins.

Polystyrene resins became the third type of plastic topping, at 1 billion lb/yr of output.

1960s: US PRODUCTION LEADS ENERGY INDUSTRY The 1960s marked a transition for the HPI as the US took center stage, particularly in oil production and consumption. The hallmark event to kick off the decade was the formation of the Organization of the Petroleum Exporting Countries (OPEC). OPEC was formed in 1960 by Iran, Iraq, Kuwait, Saudi Arabia and Venezuela. At that time, the petroleum industry in those regions was controlled by oil companies in the US and Europe. Companies in those countries paid the host governments income taxes and royalties based on the posted crude oil price on the global market. In 1959 and 1960, however, global oil production greatly exceeded demand. The surplus that was created prompted several major companies to cut the posted price and reduce their payments to host governments. OPEC became a reality in response to that price cut.

In the US, however, the population continued to grow at a very fast rate. As such, US crude oil production spiked throughout the decade, reaching an all-time high as the calendar turned to 1970. Domestic crude production and imports soared from about 7 MMbpd at the start of the decade to approximately 9.5 MMbpd in December 1969—an increase of roughly 35%. The impact of all the available oil on the global marketplace quickly trickled downstream.

Refiners widen scope. The increasing sources of crude oil meant that refiners had to expand on techniques to process a wider variety of oils into high-quality products. From a demand standpoint, the burgeoning aviation industry brought the need for more jet fuels and lubricating oils.

Thermal reforming was replaced by the catalytic reforming of naphtha, which became the leading process for upgrading octane number to meet the specifications of higher-compression engines. Hydrocracking, a cracking process conducted in the presence of hydrogen, was developed in 1960 as a manufacturing process to increase the product yields of either gasoline or jet fuels. Hydrocracking also brought about the side benefits of reduced sulfur content and alkylation feedstocks as byproducts.

Petrochemical boom. The available crude oil and increasingly sophisticated cracking processes also led to the dawn of the modern petrochemical industry. Petrochemical companies, which, as plastics producers, have long had their success directly tied to the prosperity of the average person, saw the perfect storm emerge. Rising demand and economic prosperity in the aftermath of WWII were coupled with a greater supply of feedstocks.

As a proportion of organic chemicals, the petrochemical stake surged from 50% in 1950 to 88% in 1960, to 94% in 1965 and to 96% in 1971, according to figures from BP. Between 1960 and 1973, the global petrochemical sector grew at rates between 10%/yr and 17%/ yr—more than doubling the total OECD industrial production average of about 5.5%/yr in that same period. By product, olefins and aromatics dominated the demand picture, with butadiene growing by 10%/yr, benzene by 13%/yr, propylene by 16.5%/yr and ethylene by 17%/yr.

This led to a rapid increase in production facilities and capacity, particularly in the US. One of the most modern petrochemical projects of the time was the Chocolate Bayou plant, located just outside of Houston, Texas. Built by Bechtel, the plant—one of the world’s largest at the time—

featured online digital computer controls. Detailed engineering began in November 1960; ground was broken in 1961; and all units were turned over to the customer, Monsanto, in September 1962. Likewise, in nearby Louisiana, several projects in the Baton Rouge area from producers such as Exxon caused the city to expand away from the Mississippi River and threatened to strand its historic downtown area. In the West Texas area of Odessa, El Paso Natural Gas and Rexall Chemical Co. announced plans in 1960 to build a $71 MM petrochemical complex.

It started up in 1964 and saw thriving business activity.

The same trend held true on a global level. In Japan, a 1962 forecast projected that ethylene capacity would reach 4 billion lb/yr by 1970—in turn, requiring more naphtha cracking capacity. Propylene capacity was pegged to climb to 2.8 billion lb/yr, which was supported by offgas from refineries and byproducts from naphtha cracking. Stone & Webster, a leading engineering company at the time, reportedly designed 22 petrochemical plants in Japan alone from 1950 to 1970.

This publication, once titled Petroleum Refiner, changed its name to Hydrocarbon Processing and Petroleum Refiner in 1961 and to simply Hydrocarbon Processing in 1966, reflecting the expansion of the petrochemical industry in that timeframe and its integration with refining.

Natural gas shortage. The boom in oil and petrochemical production contributed to struggles in the natural gas market. The US in 1954 set artificially low price ceilings for natural gas that were well below the market value. The effects were seen beginning in the 1960s, as there was little incentive for natural gas producers to devote the money required to explore for, and produce, new natural gas reserves.

Conversely, the aforementioned advances in crude-based naphtha cracking meant that downstream industries were not as tied to gas

FIG. 8. The new catalytic polymerization unit at Gulf Oil’s Philadelphia, Pennsylvania refinery is part of a $50 MM expansion program and will produce 2,800 bpd of high-octane components for motor fuels.

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processing. As a result, only those downstream companies that were exclusive to gas processing truly felt the pinch. For the most part, the global HPI thrived so much from an oil-based standpoint that it took until the 1970s (and events such as the 1973 OPEC oil embargo) for the effects of the natural gas shortage to be fully felt.

As the 1960s turned to the 1970s, petrochemicals and plastics activity began to slow as US refining capacity caught up with customer demand and declined accordingly. The domestic oil production peak of the 1960s has not been threatened since, as the rise of OPEC contributed to an increase in global oil supply. Meanwhile, years of neglecting the natural gas market were about to result in consequences.

1970s: ENVIRONMENTAL REGULATIONS AND MIDDLE EAST UNREST The 1970s are remembered as a time of bushy sideburns, bellbottom jeans and disco music. These cultural affectations were merely window dressing, though, for serious geopolitical developments and regulatory decisions that took place during the decade. This was a decade that started with the world’s first Earth Day in 1970 and concluded with the Iranian revolution that led to lingering difficulties between the West and the Middle East, culminating in the Iranian hostage crisis of 1979.

FIG. 9. Global panic over political events in the Middle East led to long lines at gasoline stations several times in the 1970s.

FIG. 10. The average vehicle in the 1970s consumed 2–3 l/hour of gasoline while idling, leading to an estimated 150,000 bpd of oil wasted daily in the US. D-116

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The overriding themes of the 1970s in relation to oil were the advent of stricter environmental regulations and continual squabbles between the West and OPEC nations over oil supply and gasoline pricing.

Environment. 1970’s Earth Day can be considered the commencement of the modern-day environmental movement. The idea was started by a US senator from Wisconsin, and it resulted in millions of Americans participating in rallies across the nation. The event achieved a rare political alignment, in that it was supported by Republicans and Democrats.

A direct result of this event was the creation later that year of the US EPA and, subsequently, the passage of the Clean Air and Clean Water acts.

The Clean Air Act instructed automobile manufacturers in 1974 to introduce new engines equipped with catalytic converters. It further mandated that unleaded gasoline would be sold across the US. The phase-out of leaded gasoline began in 1975. Then, in 1976, another major piece of environmental legislation passed when the Toxic Substances Control Act gave the EPA regulatory power over toxic chemicals.

Arab oil embargo. In the oil markets, 1973 and 1974 were particularly tumultuous years. In October 1973, members of the Organization of Arab Petroleum Exporting Countries (OAPEC), which consisted of the Arab members of OPEC, plus Egypt, Syria and Tunisia, declared an oil embargo. The stated reason for the embargo was the US’s support of Israel during the Yom Kippur war. The embargo lasted until March 1974, when the promise of a negotiated settlement between Israel and Syria convinced Arab oil producers that the embargo should be lifted. A direct result of the oil embargo was the historic oil price shock of 1973 and major volatility in global stock markets from 1973 to 1974.

Auto industry. The auto industry was severely affected by the 1973 oil crisis. This time period also saw the debut of fuel efficiency standards that are still in the news today. Under the Energy Policy and Conservation Act, the US federal government initiated corporate average fuel economy (CAFE) standards in 1975. The first CAFE standards instructed automakers to create cars that averaged 18 miles per gallon (mpg). This mandate increased to 27.5 mpg by 1985.

While trying to adapt to new fuel efficiency standards, automakers were also suffering from self-inflicted wounds. The most high-profile incident was Ford’s rollout of the Pinto, which was soon revealed to have a gas tank vulnerable to exploding when hit from behind. This and other design miscues, against a backdrop of highly volatile oil markets and changing consumer tastes, made the 1970s a decade to forget for automakers.

FIG. 11. The 1970s oil embargo created shortages during which retailers in the US were completely sold out due to no available gasoline stocks.

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Global panic over these events, in conjunction with US President Jimmy Carter’s decision to deregulate domestic oil price controls, once again led to long lines at gasoline stations, eerily reminiscent of 1973. These queues to obtain gasoline only further contributed to the problem. The average vehicle at the time consumed 2–3 l/hour of gasoline while idling, leading to an estimated 150,000 bpd of oil wasted daily in the US as its consumers waited in line at gas stations.

There was a positive development in the US to the roiling oil markets. When the price of West Texas Intermediate crude oil increased by 250% between 1978 and 1980, the oil-producing areas of Texas, Oklahoma, Louisiana, Wyoming and Colorado began experiencing an economic boom and population inflows.

1980s AND 1990s: LNG TAKES OFF AS US REFINING DOWNSIZES With the establishment of the Natural Gas Policy Act (NGPA) in 1978, price ceilings on both old and new gas wells were abolished between 1979 and 1987, under Title I. By the time Title V went into effect, the Federal Energy Regulatory Commission (FERC) had assumed authority over nearly all interstate and intrastate gas production. Likewise, following an April 1979 executive order from President Jimmy Carter and a free-market petition from the National Petrochemical and Refiners Association (NPRA)—now known as the American Fuel and Petrochemical Manufactures (AFPM)—President Ronald Reagan signed legislation on January 29, 1981 that deregulated prices for crude oil and oil products.

Gas and oil price collapse. Contract prices for natural gas jumped immediately following the passage of the NGPA, although, by 1982, prices had begun to ease as gas demand declined and as oil prices started to slide after their 1980 peak of over $35/bbl. After price ceilings on gas from most new wells were removed on January 1, 1985, abundant US gas supplies contributed to the downward price movement for gas.

Oil prices collapsed in 1986, dropping more than 50% between January and March to less than $10/bbl, as a result of falling demand following the 1978–1980 oil crisis and a glut of non-OPEC oil production. OPEC had reduced its production quotas several times between 1980 and 1986 in an effort to sustain high prices; however, its output was surpassed by non-OPEC nations and slipped to less than one third of the global market by 1985. Production cuts by top OPEC producer Saudi Arabia were especially heavy during this time. However, amid OPEC member debate on how to address the cartel’s declining influence, Saudi Arabia bumped up its output in September of 1985, causing a rift in cartel relations.

The 1986 oil price collapse also encouraged the shut-in of a number of high-cost wells, which subsequently led to a reversal of the upward trend in US oil output. US oil firms began moving exploration and production (E&P) investment overseas, where project costs were cheaper and resources were abundant.

LNG developments. The growth of liquefied natural gas (LNG) in the 1980s and early 1990s was driven by increasing power needs, specifically the use of combined-cycle gas turbines for electricity generation.

The 1990s and early 2000s saw the expansion of LNG trade around the world, particularly in Asia-Pacific, as LNG transitioned from a niche fuel to a mainstream gas application. The number of LNG exporting countries grew from eight in 1996 to 19 in 2012. As of 2012, there were 16 countries with LNG importing terminals.

The 2000s and the beginning of the current decade saw the arrival of the shale gas “revolution” in North America, which has further altered LNG supply/demand dynamics and trading patterns. Australia’s gaining prominence as an LNG exporter will come into play later in the current decade, as the country is expected to overtake Qatar as the world’s largest LNG exporter by 2018.

LNG in the US. In 1980, the US adopted comprehensive LNG safety regulations after the conclusion of experiments by the US government and Shell Research on the dispersion and combustion of LNG spills. Also in that year, the falling natural gas prices in the US and an LNG price dispute with Algerian exporters resulted in a shutdown of the Cove Point, Maryland and Elba Island, Georgia terminals, which had commenced operation only two years earlier. The Cove Point terminal was reopened in 1995 as a natural gas storage facility, while the Elba Island location was reopened in 2001. In 2003, Cove Point was reactivated as an LNG facility after securing permission from the FERC in 2001.

These restarts were motivated by rising natural gas demand in the US and the opening of Trinidad and Tobago’s liquefaction plant in 1999— the first LNG export facility in the Atlantic Basin. The twin-island nation remained a primary supplier of LNG to the US for the next decade, until the huge shale gas reserves being developed in the US began to displace the need for LNG from Trinidad and Tobago.

LNG in Asia-Pacific. Across the Pacific Ocean, Japan became a major buyer of LNG in 1984, purchasing 72% of the world’s product.

Of the purchase volume, 75% was used for power generation. South Korea joined the ranks of LNG importers in 1986, receiving a cargo from Indonesia. Meanwhile, the US saw no imports of LNG in 1986, although the country resumed purchases from Algeria in 1989 with the reopening of the Lake Charles, Louisiana terminal. The terminal, which began receiving deliveries in 1982, had suspended imports in 1983 due to the high cost of LNG. The 1990s was an exciting decade for LNG trade, which became more competitive and market-driven, especially in the Asia-Pacific region.

Taiwan received its first LNG shipment from Indonesia at the beginning of the decade, while the first deliveries of LNG from Australia’s North West Shelf arrived in Japan and South Korea in 1991.

Japanese purchases dropped from the mid-1980s level, with the country accounting for 66% of the world’s LNG deliveries in 1999. However, the March 2011 earthquake and tsunami that destroyed several of the country’s nuclear plants led to a substantial rise in demand for LNG for power generation, altering global LNG trading patterns over the following year and possibly over the long term.

Safety and environment in the 1980s. The 1980s saw new developments in safety and environmental programs in the US. Fuel initiatives. The US EPA proposed an aggressive ban on leaded gasoline in 1982, which resulted in a gradual phase-out of the fuel. In 1990, a total ban was initiated in the US on the sale of new engines operating on leaded gasoline, and the sale of leaded gasoline was banned in January 1996 with the introduction of the new Clean Air Act. Furthermore, August 1989 saw the introduction, by ARCO Products Co., of the first reformulated gasoline designed to reduce emissions. By

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1991, ARCO’s EC-1 gasoline had been credited with displacing over 100 million pounds of air pollutants in southern California.1 Later, the passage of the US Alternative Motor Fuels Act on October 14, 1988 required government fleets to use alternative fuels such as ethanol and methanol. The environmental benefits of using alternative and renewable fuels have been heavily debated and promoted since that time, with new legislation emerging in the US and Europe in the 2000s, as discussed later in this article.

Elsewhere in the world, moves to ban the use of lead in gasoline followed the US’s initiative. However, it has been only recently that lessdeveloped economies have been able to eliminate lead in motor fuel.

Historically, lead phase-outs in gasoline have been motivated by two factors: the changeover to catalytic converters in vehicles (as seen in the US) and public health concerns (as seen in Sweden, the Slovak Republic, Brazil and Thailand).

The ability to accommodate lead-free fuel initiatives has varied among nations. Phasing out lead in gasoline requires refineries with the capacity and technology to produce high-octane gasoline components.

Such technologies include alkylation, oxygenation and polymerization processes. While these technologies are found in most modern conversion refineries, less-advanced hydroskimming refineries—many of which are located in less-developed nations with smaller refining capacities— have fewer technology options available to produce these components.

These options consist of adding octane-enhancing additives or utilizing high-severity reforming.

Many refinery modernization investments of the 1980s and 1990s focused on removing lead and producing cleaner fuels, motivated by government policies. In 1998, the World Bank estimated the cost to most refiners of phasing out lead in gasoline at US$0.01–0.02/l of gasoline.

Chemical safety. In 1985, Canada became the first country to introduce the Responsible Care program in response to public worries about safety in the manufacture and use of chemicals. Concerns were sparked when a massive leak of methyl isocyanate from the Union Carbide plant in Bhopal, India on December 3, 1984 caused thousands of deaths and injuries to local residents.

The Responsible Care program, which is a voluntary, global initiative that has been established in 60 countries accounting for over 90% of the world’s chemical output, is the chemical industry’s effort to improve occupational safety and health, plant safety and security, environmental performance and product management, and to also generate new business opportunities.

The US American Chemistry Council (ACC) launched its own version of the Responsible Care program in 1986. According to the ACC, companies participating in the program have reduced process safety incidents by 48% since the mid-1990s. Also, since 1988, these companies have lowered hazardous emissions to the air, water and land by more than 75%. Going back even further, the US chemical industry as a whole has boosted its energy efficiency by 56% since 1974, partly as a result of the Responsible Care program.

zations, environmental groups, automakers and other government agencies to establish principles for the reformulated gasoline (RFG) program.

Agreement on RFG standards was reached in August 1991, and subsequent industry and government studies confirmed that substantial emissions benefits were achievable and cost-effective with the RFG program, which was initially mandated in nine US cities with smog problems and later expanded to include other high-pollution cities and areas. In 2000, new emissions standards for the RFG program went beyond the regulations established in the Clean Air Act. Other fuel regulations throughout the 1990s included alternative fuels use, as specified in the 1992 Energy Policy Act; an 80% sulfur reduction in diesel to 500 ppm (October 1993); the EPA’s introduction of Tier II emissions standards for vehicles (March 1998); and the development of the Tier II sulfur rule (December 1999–February 2000), which required a reduction in gasoline sulfur content to 30 ppm.

Rationalization of US refining industry. In the first half of the 1980s, 123 of the US’s refineries were shut down, despite an average return on investment of 8.8% and an average industry profit of 2.5 cents per gallon.2 Oil price deregulation in 1981 contributed to the wave of refinery closures, which left the US with 192 operating plants in 1986. In the second half of the decade, increasing demand for light products resulted in greater downstream processing and conversion capacity, although rationalization of crude oil distillation capacity persisted.

The US National Petroleum Council (NPC) cautioned in an August 1993 report, “The first half of the 1990s poses financial difficulty for the US refining industry because of the large projected capital expenditures for regulatory compliance coupled with declines in refinery utilization.

Some shutdown of capacity, including entire refineries, has occurred and is likely to continue.”2 As the NPC predicted, US refineries continued to close during the 1990s as domestic production costs increased, which stimulated demand for cheaper foreign imports. New environmental regulations required refiners to produce cleaner fuels with lower sulfur contents, which forced some refiners to upgrade and revamp their plants to meet the specifications. Other refiners opted to shut down operations rather than make the expensive upgrades.

The NPC forecasted that US refiners would need to invest US$37 billion (in 1990 dollars) between 1991 and 2000 to meet regulatory and environmental requirements and to produce reformulated gasoline and ultra-low-sulfur diesel. “Ultimately, the cost of meeting regulatory requirements will be reflected in the marketplace,” the NPC predicted.

Such costs piled up heavily between the mid-1990s and the mid-2000s, contributing substantially to the rationalization of US refining capacity.

Worldwide, the 1980s saw a general accumulation of refining capacity that was rationalized in the early 1990s through plant shutdowns and refiner consolidations.3 However, global refining capacity generally expanded from 1995 to 2011 due to booming demand for refined products, particularly transportation fuels. Refinery operating rates averaged 83% over the time period.

Fuel regulations and the environment in the 1990s. The US Pollution Prevention Act, which was passed on November 5, 1990, outlined greater action to control pollutants at their sources. The Office of Pollution Prevention was also founded in that year. The Clean Air Act Amendments, which specified more actions to improve air quality, were signed into law on November 15, 1990.

As part of the US government’s efforts to improve air quality, the EPA granted a waiver on February 11, 1991 allowing an increase in oxygenate blending (up to 2 wt%). Over the next few months, the EPA negotiated with the petroleum industry, the oxygenate industry, state and local organiD-118

DOWNSTREAM INNOVATIONS: 1922 TO PRESENT HydrocarbonProcessing.com

2000 AND BEYOND: OUT WITH THE OLD, IN WITH THE NEW The HPI has seen its traditional demand centers shift since the calendar turned to the 21st century. During the 2000s, the UK, Norway and Mexico slipped into long-term oil production declines, according to data from BP. They joined the US, Indonesia and Venezuela as three of the world’s 21 largest producer nations—the 1 MMbpd club—that are likely past their production peaks and have either flat or declining output. Collectively, these six countries saw a drop of more than 4 MMbpd of production in the 2000s.

DOWNSTREAM INNOVATIONS

However, output increases from several non-OPEC countries more than offset that decline. The nations comprising the former Soviet Union saw a recovery of 5 MMbpd compared with the prior decade. Other non-OPEC nations saw improvements of around 3 MMbpd, most notably Brazil, China and Canada. On the whole, those countries helped world oil production grow from 74.8 MMbpd in January 2000 to 87.4 MMbpd at year-end 2010—an increase of just under 17%.

These oil production trends were mirrored within the broader energy industry and the world’s population. While developed areas such as the US and Europe largely saw flat to declining outlooks, demand exploded alongside the rising population in areas such as China, India and Brazil. That trend held even during the global recession of late 2008 and 2009, which devastated demand in the developed world but only slightly curbed growth in the new hubs.

Refiners plagued by production costs. In the downstream segment, crude

FIG. 12. Total introduced a new distillate hydrotreater in 2011 to produce ULSD, which is a more environmentally friendly fuel.

oil refiners likely struggled the most with the changing energy dynamics of the 2000s and beyond. Crude oil prices, which held at around $50–$60/bbl through 2005, rose as high as $145/bbl in mid-2008.

Although prices dipped temporarily during the recession, the ensuing economic recovery and political turmoil in areas such as the Middle East quickly pushed prices close to $120/bbl in 2012.

Those prices have caused the total cost of production to more than triple since the turn of the century, squeezing margins for many oil-based refiners.

In areas such as China and the Middle East, surging domestic demand is enough for refiners to stay viable. Conversely, many older, high-cost facilities in developed areas such as Europe have had to shut down.

Shale interest drives gas market. The dominant trend of the post-2000 natural gas market has been rapidly growing interest in shale plays.

The majority of the development has occurred in the US, where shale production increased from 1% of total gas production in 1990 to 23% by 2010. By 2035, shale gas is projected to jump to 49% of total gas production, according to the US Energy Information Administration (EIA).

Largely due to shale gas discoveries, the US estimate for natural gas reserves was 35% higher in 2008 than in 2006. Some have speculated that there may be up to a 100-year supply of natural gas in the US. As a result, a nation that was increasingly becoming an importer has become self-sufficient in recent years. Supply is ample enough that US prices have dipped from roughly $9/MMBtu in 2005 to below $3/ MMBtu in 2012.

The largely successful story of shale in the US has, in turn, led to rapid development in Canada and exploration in Europe, Asia and Australia.

New applications of hydraulic fracturing technology and horizontal drilling make shale production easier than ever, and its share in the global energy mix increases daily.

Petrochemical industry sees ethane-based boom. In the modern petrochemical world, success largely depends on whether a cracker is ethane-based or naphtha-based. Ethane, extracted from natural gas, has become progressively cheaper because of the aforementioned shale gas scenario. As many as seven new crackers are being discussed in the US for the next decade amid increasingly favorable economics. Likewise, a wave of new ethylene capacity came onstream in the Middle East in the late 2000s because of that region’s proximity to Saudi Arabian ethane.

Conversely, crude-based naphtha—prevalent in Europe and other areas—has become more and more unprofitable for use in petrochemicals. When the calendar turned to 2000, ethane traded at approximately 40 cents/gal, while naphtha prices were around 60 cents/ gal—a difference of about 50%. During the oil price shock of 2008,

FIG. 13. The Total refinery complex in Port Arthur, Texas is one of the largest in the US in 2012 following a $2.2 billion expansion. naphtha briefly touched 250 cents/gal, while ethane hovered near 100 cents/gal—a difference of around 150%.

More recently, ethane has held in a band of roughly 50–70 cents/ gal, with a price ceiling due to the abundant natural gas liquids (NGLs) supply in the US. That trend should become progressively more global as shale developments advance.

Deepwater Horizon tragedy leads to increased focus on safety.

Safety concerns have become paramount for the industry in the 21st century, particularly in the aftermath of the April 2010 Deepwater Horizon rig explosion in the Gulf of Mexico. The resulting oil spill was the largest in US Gulf history, and it led to a wave of tightening regulations on unconventional energy sources, both in the US and abroad.

BP, which operated the ill-fated rig, says it has developed numerous new safeguards in the two years following that incident. Other companies and industry watchdogs have made similar claims. However, global environmental groups have used the incident to ratchet up pressure on politicians to further regulate energy companies. As such, even with implemented safety improvements, the development of unconventional energy production will largely depend on legislative direction.

As with most aspects of the HPI, things come down to supply and demand. On the demand side, post-2000 growth has mostly occurred in Asia-Pacific and Latin America. On the supply side, shale discoveries have dramatically changed the North American landscape. As a result, these three regions are leading the way in the HPI and are poised to do so for the foreseeable future. HP LITERATURE CITED Complete literature cited available online at HydrocarbonProcessing.com

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HP260X. A versatile multi-channel FT-NIR analyzer to optimize refinery process unit operation and increase profitability.

The new FTPA2000-HP260X is a versatile Ex-area certified 8-channel fibre-optic FT-NIR analyzer. It is suitable for the measurement of hydrocarbon process stream qualities in a wide variety of refinery process unit optimization applications (CDU, VDU, HCK and FCC units, Lube Base Oil and Gasoline Blending).This fully integrated compact unit is easy to install and to commission. This real-time process analyzer offers high-precision and rapid analytical measurements on streams helping you achieve efficient and fast Return on Investment. www.abb.com/analytical

ABB Inc. Analytical Measurements Phone: +1 418-877-2944 1 800 858-3847 (North America) Email: ftir@ca.abb.com Select 69 at www.HydrocarbonProcessing.com/RS

ABB

ABB ANALYTICAL MEASUREMENTS FT-IR TO IMPROVE PRODUCTIVITY OUR HISTORY Founded in 1973 as Bomem Inc, ABB Analytical Measurements enables scientists around the world to perform through excellence in infrared spectroscopy. ABB is a market leader in Fourier Transform Infrared (FT-IR) and Fourier Transform Near Infrared (FT-NIR) in terms of reliability and reproducibility.

COMPREHENSIVE PORTW ABB designs, manufactures and markets high performance FT-IR and FT-NIR spectrometers as well as turnkey analytical solutions for several applications. The company capabilities encompass one of the largest portfolios for laboratory, at-line and process FT-IR analyzers.

They perform real-time analysis of the chemical composition and/ or physical properties of a process sample stream. ABB’s advanced solutions combine analyzers, advanced process control, data management, process and application knowledge to improve the operational performance, productivity, capacity and safety of industrial processes for customers.

OUR MARKETS • • • •

Oil & Gas Life Sciences Chemical Academic

• • • •

Semiconductor Metallurgy Remote Sensing OEM

knowledge to improve process performance, productivity, and safety.

For all laboratory or process needs ABB can be your partner and single source provider.

ABB (www.abb.com) is a leader in power and automation technologies that enable utility and industry customers to improve their performance while lowering environmental impact. The ABB Group of companies operates in around 100 countries and employs about 130,000 people.

ADDRESSING THE NEEDS OF MODERN OIL & GAS INDUSTRY ABB Analytical Measurements has the capacity to address the process analytical requirements of the modern Oil & Gas industry. The company counts a large installed base of analytical solutions both upstream & downstream in major production plants, refineries and petrochemical units. Our analytical solutions are used in: Gasoline & Diesel Blending, Distillate Hydrotreating ,HF Alkylation, Catalytic Reforming, Hydrocracking, Crude Distillation, Naphtha Steam Cracking and Downstream Petrochemicals.

SINGLE SOURCE SOLUTIONS Our customers come to us with technical challenges, and our dedicated team offers simple, dependable, solutions with reliable instruments to create greater value for our customers. Our advanced solutions combine state-of-the-art FT-NIR analyzers with process and application

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CONTACT INFORMATION ABB Inc. Analytical Measurement 585, boulevard Charest E., suite 300 Quebec, QC CANADA G1K 9H4 Tel: +1 418 877 2944 ftir@ca.abb.com www.abb.com/analytical

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The winning catalyst combination for your hydrocracker )3, )%, ):, TFSJFT UIF FYQFSU USJP UP NBYJNJ[F DZDMF MFOHUI BDUJWJUZ BOE NJEEMF EJTUJMMBUFT TFMFDUJWJUZ 4JOHMF TPVSDF *40 t *40 t 0)4"4 www.axens.net Select 53 at www.HydrocarbonProcessing.com/RS

AXENS

CATALYZING SUSTAINABLE GROWTH IN A WORLD OF CHANGES The geographical shift in demand for refined and petrochemical products towards regions with growing economies combined with the decrease in demand in the OECD countries will durably reshape the hydrocarbon processing industry landscape.

Over the next 20 years, world demand for oil products or their equivalents is likely to increase at an average rate of just under 1% per year up to 2030 when it will exceed 100 million barrels per day of oil equivalent (Mbdoe).

However, this growth will not be distributed evenly around the world.

In OECD countries, reduction in car engine fuel consumption will lead to a drop in oil demand of an average of 0.8% per year, generating refining overcapacity. In addition, the adoption of legislation that will impose the incorporation of increasing quantities of renewable fuels, such as those derived from lignocellulosic biomass will also contribute to reduce the demand for refined products.

The situation is completely different in countries with growing economies where GDP is increasing rapidly and where populations aspire to greater mobility. In these countries, demand for oil products will rise at the rate of 1.6% per year over the coming years and could represent 65% of world demand by 2030.

These global trends present challenges and offer opportunities for development: • Ever cleaner fuels will be increasingly required. Tightening fuel quality specifications worldwide will call for additional hydrotreating capacities and even higherperforming catalysts. o Axens is engaged in a sustained clean fuels program both in hydrotreating technology and in catalysts. This long term effort has been rewarded in the gasoline and middle distillates hydrotreating area with innovative technologies that are recognized by the market, such as: Prime-G+, Prime-D, EquiFlow internals and HR Series catalysts.

• Changes in the mix of fuel consumption; growth in on road diesel, currently at 1.8 % per year, will continue at a higher rate than that of gasoline (0.8%/yr) for which new demand will be mainly located in growing economy regions. This trend will drive the thirst for hydrocracking technology and catalysts that maximize middle distillate yields.

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o A full range of catalysts has been developed to meet the objectives of high conversion hydrocracking units. Optimized combinations of HRK, HDK, HYK catalyst Series makes it possible to squeeze more middle distillates from heavy ends while reaching high conversion levels.

• Squeezing the most from the bottom of the barrel will be necessary to take advantage of lower priced heavy crudes and maximize motor fuel and petrochemicals yields. This will become all the more important as demand for heavy oil products is forecast to decline. o Axens has developed various solutions in this field: a scheme such as a vacuum residue (VR) hydrotreater (Hyvahl) upstream of a residue fluid catalytic cracker (RFCC) and a vacuum gas-oil (VGO) hydrocracker addresses the demand for a more balanced production of gasoline and diesel. If middle distillates are in the highest demand, integrating a VGO-hydrocracking unit with an ebullated-bed VR hydrocracker (H-OilRC) offers a very attractive solution.

• Integration between refining and petrochemicals will allow the recovery of valuable products such as propylene from low value heavy feeds. o High Propylene FCC, HS-FCC and Resid to Propylene technologies enable the production of propylene with a yield ranging from 8 to 20 wt. % from atmospheric or vacuum residue. To further increase propylene production, C4 and C5 olefins issued from the catalytic crackers or cokers can be recovered to be oligomerized then selectively cracked into propylene via dedicated technology (Olicrack) or integrated technology using FCC units (FlexEne). o Integrated solutions between refinery and aromatic complexes (ParamaX) participate in increasing paraxylene production to meet the ever growing demand in polyester for bottles and textiles in growth economies.

• In mature markets such as Europe, increasing flexibility through revamping of existing units to reduce the gasoline/diesel imbalance will be a key to recovering profitability. o For instance, the olefins contained in light FCC cuts can be transformed via HYDROCARBON PROCESSING

oligomerization PolyFuel technology into good quality blending stock for the diesel or jet fuel pool.

• Actively preparing for the future, Axens is developing its offer in the field of alternative fuel technologies: vegetable oils to diesel and jet fuel, high-quality distillates from direct coal liquefaction and liquid products through the conversion of synthesis gas from various feedstocks (natural gas, biomass and coal).

With the continuous renewal and improvement of its portfolio of processes, catalysts and adsorbents, the recent acquisitions of Criterion’s reforming catalyst business and Rio Tinto Alcan’s activated alumina business, and the development of new services, Axens strives to provide its customers and partners with the best tools to respond to market changes and maximize profitability.

Jean Sentenac, Chairman & CEO Axens

CONTACT INFORMATION 89, bd Franklin Roosevelt - BP 50802 92508 Rueil-Malmaison—France Phone: +33 1 47 14 25 00 Email: information@axens.net www.axens.net

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CB&I

CB&I COVERS THE ENTIRE PROJECT LIFECYCLE, CONCEPT TO COMPLETION From humble beginnings nearly 125 years ago, CB&I has continually expanded its capabilities to serve the energy and natural resource industries. Today, CB&I engineers and constructs some of the world’s largest energy infrastructure projects. With premier process technology, proven EPC expertise and unrivaled storage tank experience, CB&I executes projects from concept to completion.

We offer a comprehensive range of capabilities that span the entire project lifecycle: CB&I’s Project Engineering and Construction business sector builds upstream and downstream oil and gas projects, LNG production and regasification terminals, and a wide range of other energy related projects.

CB&I’s Steel Plate Structures business sector designs, fabricates and constructs storage tanks and containment vessels and their associated systems for the oil and gas, water and wastewater, mining and nuclear industries.

CB&I’s Lummus Technology business sector provides proprietary process technologies, catalysts and specialty equipment to petrochemical facilities, oil refineries and gas processing plants.

Safety is a core value at CB&I and we are proud to have one of the best safety records in the industry. Throughout our organization, every employee worldwide is committed to safe work practices. Our awardwinning safety program promotes a culture of involvement and dedication with a goal of zero incidents for everyone involved in our projects.

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CONTACT INFORMATION CB&I 2103 Research Forest Drive The Woodlands, TX 77380 USA Tel: +1 832 513 1000 Fax: +1 832 513 1005 info@cbi.com www.CBI.com

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Imperial’s 600-ton LTM 1500-8.1 Liebherr

Safety, Service, Quality Imperial Crane Services has been specializing in crane rental and sales for over 40 years. Headquartered in the Chicagoland area, we have four locations throughout the United States. Our focus is on daily rentals and long-term, heavy-lift projects while being dealers in Tadano rough terrains, Elliott boom trucks, Sany crawler cranes, STROS personnel and construction hoists, and Barko material handlers.

Imperial has extensive experience in refinery turnarounds and maintenance work. Our staff is skilled at managing multiple large scale projects with the ability to offer over 250 pieces of equipment, operator training, project management, cost estimation and lift coordination.

UÊ Þ`À>Õ VÊ/ÀÕV Ê À> ià 35 ton to 600 ton UÊ Ûi Ì > Ê/ÀÕV Ê À> ià up to 300 ton UÊ À>Ü iÀÊ À> ià up to 352 ton UÊ, Õ} Ê/iÀÀ> Ê À> ià 15 ton to 120 ton UÊ Ê/ÀÕV à 10-50 tons with boom reach over 200’ UÊ `ÕÃÌÀ > Ê iÛ>Ì ÀÃÉ ÃÌÀÕVÌ Ê ÃÌÃ

www.imperialcrane.com

OVER $50 MILLION IN INSURANCE - MORE THAN 10 TIMES THE INDUSTRY STANDARD 2 Million Man Hours Without a Lost Time Accident (.61 EMR) Bridgeview, IL: 708-598-2300

Griffith, IN: 219-924-2900

Port Lavaca, TX: 1-888-HOIST IT

Dealers in:

Select 99 at www.HydrocarbonProcessing.com/RS

St. Louis, MO: 1-888-HOIST IT

IMPERIAL CRANE SERVICES

IMPERIAL CRANE SERVICES HOLDS ON TO VALUES OF SAFETY, SERVICE AND QUALITY Imperial Crane Services, headquartered in the Chicagoland area, is a full-service crane rental and sales company. Our focus is on daily rentals and long-term, heavy-lift projects, with a growing number of large, long-term projects throughout the United States. In addition to Imperial’s rental services we are dealers in Tadano rough terrains, Elliott boom trucks, Sany crawler cranes, STROS personnel and construction hoists, and Barko material handlers.

More than 40 years ago our founder, John Bohne, started Imperial with a single crane. By setting high expectations in daily rentals and identifying opportunities in refinery work, Bohne quickly grew the business into the largest locally owned crane company in the Midwest.

Today, we have expanded to four locations throughout the United States, at times employing over 500 employees and offering over 400 pieces of equipment.

We believe our success is attributed to our long-standing commitment to excellence. In the highly competitive world of crane rental we stand apart from the competition by delivering the highest standards of safety, service and quality in every application. Our dedication to these standards has allowed our customers to focus on their businesses, assured we are holding ourselves accountable for our high expectations of work.

SAFETY As of November 13, 2011 we have reached a significant milestone, over 4 Years and Two Million Man Hours without a Lost Time Accident.

Our entire organization’s commitment to our “Talk Safety, Live Safety” culture can be attributed to strong leadership and full support from ownership. Our team of full-time safety professionals works with and encourages all supervisors and employees within Imperial to apply prevention and protection to every aspect of their daily tasks.

In order to enhance our on-site training programs and maintain our OSHA compliance requirements, we have constructed a 30-person training office to house our safety staff and to educate all of our employees with seminars and packaged trainings. By creating a proactive safety curriculum we have created an incident and injury free work environment that has resulted in a record low EMR of .61.

In addition to our safety program, we protect our clients and employees by carrying over 50 million dollars in insurance, over ten times the industry standard.

Imperial has extensive experience in refinery turnarounds and maintenance work.

QUALITY Our fleet is recently purchased, with an average unit age of five years, and equipped with the most up-to-date technology in the industry.

It is well maintained by our onsite mechanics. With daily inspections by our operators, frequent detailed inspections by our maintenance department, and yearly third party inspections for every one of our cranes, our fleet is updated regularly.

EQUIPMENT Hydraulic Truck Cranes—5 to 600 tons Conventional Truck Cranes—up to 300 tons Crawler Cranes—up to 352 tons Rough Terrain Cranes—15 to 120 tons Boom Trucks—10 to 50 tons with boom reach over 200 feet Industrial Elevator/Construction Hoists

SERVICE We build long-term client relationships by providing superior customer service. The same dedication and professionalism is applied to all projects, large and small.

Our knowledgeable sales staff is available on a 24-hour basis to assist customers with accurate and timely information.

In-house estimators use the latest programs to provide prompt crane sizing, quotes and permit expediting. They are always available to offer alternative lifting methods and equipment, along with cost cutting suggestions.

Field estimators will make jobsite visits, prepare site layouts and meet with a project team. They are available to consult field staff in order to provide the appropriate equipment needed for any project.

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CONTACT INFORMATION Imperial Crane Headquarters 7500 W. Imperial Dr. Bridgeview, IL 60455 Phone: 708-598-2300 Fax: 708-598-2313 info@imperialcrane.com www.imperialcrane.com imperialcrane.wordpress.com

HYDROCARBON PROCESSING

Additional Branches: Griffith, Indiana 219-924-2900 St. Louis, MO 1-888-HOIST IT Borger, Texas 1-888-HOIST IT

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LINDE AG

LINDE IN THE UNITED STATES The Linde Group is a leading gases and engineering company with approximately 50,500 employees working in more than 100 countries worldwide. In the 2011 financial year, it achieved sales of EUR 13.787 billion.

THE MISSED ANNIVERSARY Linde has been active in the USA for more than one hundred years.

However, the development of the business was not without setbacks.

During the First World War, Linde had to abandon its US branch and it was not until 1953 that Linde was able to regain ground in the USA with the delivery of at that time the world’s largest air separation plant.

It was not until effective January 1, 1999 that the North American group companies were once again permitted to use the name “Linde.”

The Linde Group now once again owns the global rights to the “Linde” name and trademark.

FOLLOWING THE PATH OF BEER As early as the 1890s, Linde was known in the USA as a licensor and supplier of brewery refrigeration machines. But it was the demand for industrial gases which first made the setting up of Linde’s own production location in the USA attractive. In 1907, Carl von Linde founded the new company in Cleveland under the name Linde Air Products. With high-profile jobs such as the incredibly fast dismantling of the collapsed Québec Bridge over the Saint Lawrence River, or the removal of steam generators from the battleship Kentucky using Linde welding and cutting technology—in only nine days instead of ten months as the competitors—the company developed a rapidly expanding sales market for oxygen, nitrogen, and acetylene.

Partial Condensation Cold Box in Clearlake, Texas With the acquisition of two gases companies AGA (2000) and BOC (2006), The Linde Group had finally paved the way to become a leader in the global gases market. Linde had already concentrated its activities in 2004 by combining its US companies AGA Gas, Holox and Linde Gas enabling its entire range of production and services to be offered from a single source.

WIDE SPECTRUM, BROAD CUSTOMER BASIS Today, Linde is one of the most important suppliers of industrial and medical gases, and engineering products and services in the USA. Around 4000 employees in 400 sales and production locations serve more than 100,000 customers. In 2011 Linde earned more than USD 2 billion in the USA and together with its customers is looking forward to an optimistic future.

PASSING THE PARENT Between the First and Second World Wars, the now independent subsidiary outperformed the parent company, both technologically and economically. Linde Air Products became the world’s largest supplier of gases but after the Second World War, European gases companies— including BOC and Linde—were able to compensate their shortfalls and to re-establish themselves as global leaders.

RESTART IN BIG APPLE A new beginning as plant constructor in the USA involved the founding of the LOTEPRO subsidiary (Low Temperature Processing and Equipment) in New York. With the relocation of the head office to Tulsa, Oklahoma, and the acquisition of the Pro-Quip-Corporation, the US market leader in the construction of hydrogen plants, it operates today under the name Linde Process Plants (LPP).

With further important acquisitions including the UCC patents for wastewater treatment (UNOX) in 1980 and the industrial furnace manufacturer Selas Fluid Processing Corporation in 1985, Linde had already laid the foundations for expanded activity in the US market.

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CONTACT INFORMATION Linde AG Engineering Division Dr.-Carl-von-Linde-Str. 6-14 82049 Pullach Germany Phone: +49.89.7445-0 Fax: +49.89.7445-4908 Email: info@linde-le.com Website: www.linde-engineering.com

HYDROCARBON PROCESSING

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Engineering transformation.

That’s how we meet our customers’ toughest challenges.

DeltaGuard Building on our rich technology legacy,

Pop-A-Plug®

iPRSM®

drum unheading devices. Farris Engineer-

thought was possible, this is what drives

we embrace the toughest challenges

ing, creator of pressure relief valve designs

us. We offer solutions to our customers’

with our passion to explore the limits

that are now industry standards, has led

toughest challenges and help transform

of our innovation and creativity. Today,

the way in pressure relief system manage-

the way their business is done.

we’re breaking new ground in industries

ment with the patented iPRSM software.

beyond our aviation roots. Our DeltaValve

And EST Group’s Pop-A-Plug makes the

business unit forever changed coke drum

process of sealing leaking heat exchanger

unheading — saving lives and improving

and condenser tubes faster, safer and

reliability — with its fully automated coke

damage-free. Pushing past what others

©2012 Curtiss-Wright Flow Control Corporation

Learn about innovations past and present at http://cwfc.com

Select 89 at www.HydrocarbonProcessing.com/RS

CURTISS-WRIGHT FLOW CONTROL

INNOVATION RUNS DEEP AT CURTISS-WRIGHT Eighty-three years ago, Curtiss-Wright was formed from the merger of companies founded by Glenn Curtiss and Orville and Wilbur Wright— pioneers who soared to new heights of human achievement that ushered in the era of aviation. When we created wings for ourselves, we expanded our horizons and transformed forever our vision of what’s possible. For generations since then, Curtiss-Wright Flow Control Company has led and still leads through innovation. Innovation isn’t just a new product or technology or process, it’s essential to how we conduct and grow our business.

In the oil and gas industry, a key focus for Curtiss-Wright Flow Control is the development of transformational new technologies to improve both safety and reliability in traditionally hazardous operating environments.

Refiners in established and emerging markets turn to Curtiss-Wright Flow Control for solutions that include specialized valves, pumps, controls and process systems.

Innovations in oil and gas technologies have come from many of our business units, including DeltaValve, Farris Engineering, EST Group and Benshaw.

LEGACY OF INNOVATION CONTINUES At DeltaValve, innovation runs in their blood. From its early days, DeltaValve has been developing innovative valve designs for severe service applications in many major industries. To its credit are several valve technologies, the best known of which is the revolutionary DeltaGuard coke drum unheading valve.

DeltaValve’s innovative vision was to design a valve to work continually in one of the most severe and aggressive environments in oil and gas refining—a feat never thought possible. The valve was designed to fully enclose the coke drum unheading process from the top of the coke drum to the coke chute, eliminating exposure to operators and equipment from coke drum fallout and redefining safety for a traditionally hazardous process.

Today, the coke drum unheading valve invented by DeltaValve is used by nearly every major oil company in the world. It has set a global standard for remotely operated, fully automated, safe, and reliable coke-drum unheading.

Farris Engineering has an impressive history in the development of pressure relief solutions. Introduced in the 1950s, the balanced bellow design developed by Victor Farris mitigated the effects of back pressure and chemical erosion on internal valve components. This Farris innovation is now a standard feature used in pressure relief valves (PRVs) around the world.

In 1981, Farris developed SizeMaster, a software package which automated and simplified the complex process of sizing and selecting PRVs. SizeMaster remains the preferred PRV sizing program used in industry today, and became the precursor for the patented, web-based iPRSM® technology developed in 2002. iPRSM is an innovative engineering software tool which helps engineers intelligently design, audit and document safety compliance of new and existing pressure relief systems. Using iPRSM’s technology ensures a safer plant, protecting people, equipment, communities and the environment.

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Since 1968, EST Group has been providing innovative heat exchanger tube plugging systems to power generation, refineries and chemical plants worldwide. Its Pop-A-Plug® heat exchanger tube plugging system does the job without the traditional use of welding or explosives. It uses one-of-a-kind serrated rings designed to maintain a leak-tight seal under extreme thermal and pressure cycling. This increases working speed, reduces downtime, and won’t damage tubes, tube joints or tube sheets.

Founded in 1983, Benshaw has grown to achieve leadership in the design, development and manufacture of mission-critical motor controls and drives. Benshaw is known for its breakthrough products featuring advanced motor control and protection functionality, easy-to-use interfaces, exceptional input/output flexibility and connectivity across all major communications protocols. In 2006, Benshaw developed, installed and commissioned one of the world’s largest solid-state starters to energize a 13.8kV, 22,000 horsepower motor for the main air blower in a fluid catalytic converter unit. And soon it will be releasing a medium voltage variable frequency drive with newly patented technology, which will be available up to 3,000 hp.

A FUTURE OF INNOVATION Though Curtiss-Wright has an impressive history as an industry leader in developing transformational technology across multiple industries, we are not content to sit back and rely on previous successes.

We continue to drive forward and push the envelope with new and inventive ideas. DeltaValve recently developed the world’s first centerfeed injection nozzle for delayed coking applications. This unique technology greatly reduces coke drum fatigue experienced from side feed entry, minimizes internal hot spots in the coke bed and reduces the possibility of coke drum blowouts.

Inspired daily by the extraordinary talent and capabilities of Glenn Curtiss and the Wright brothers, Curtiss-Wright Flow Control will continue to design, engineer and develop transformational technologies, processes and solutions that meet the most critical challenges our customers face day in and day out. This engineering transformation offers profound, differentiating value to our customers, and helps them to change forever the way they do business.

CONTACT INFORMATION Sharon L. Dey Address: 2941 Fairview Park Drive, Suite 850, Falls Church, VA 22042 Phone: 703-286-2011 Fax: 703-286-2035 Email: sdey@curtisswright.com Website: www.cwfc.com

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Performance Under Pressure STOPPLE STOP ST OPPL OP PPLE PLE PL E ® Train Tra raiin in d double oubl ou ble e bl bloc block ockk an and a d bl blee bleed eed d te tech technology chno nollogy nolo l ogy ffrom rom ro m TD TDW TDW. W. W.

Advanced patent pending technology for incredible performance in high-pressure applications.

Provides double block and bleed features at pressures up to 1,480 psi.

Reduces safety concerns associated with pressurized piping systems.

Helps reduce fitting costs and welding time.

To learn more about STOPPLE® Train technology, contact your nearest TDW sales representative or visit www.tdwilliamson.com.

NORTH & SOUTH AMERICA: 918-447-5500 EUROPE/AFRICA/MIDDLE EAST: 32-67-28-36-11 ASIA/PACIFIC: 65-6364-8520 OFFSHORE SERVICES: 832-448-7200

® Registered trademark of T.D. Williamson, Inc. in the United States and in other countries. ™ Trademark of T.D. Williamson, Inc. in the United States and in other countries. © Copyright 2012 All rights reserved. T.D. Williamson, Inc.

Select 80 at www.HydrocarbonProcessing.com/RS

T.D. WILLIAMSON

DOUBLE BLOCK AND BLEED TECHNOLOGY CONTINUES TDW TRADITION OF INNOVATION For more than 90 years, T.D. Williamson (TDW) has been an innovative provider of equipment and services for pressurized pipelines and piping systems worldwide. From the earliest pipeline pigs and tapping machines to the latest in inline inspection technology, TDW has consistently provided customers with the best possible solutions to optimize throughput, ensure integrity and extend the service life of their assets.

TDW innovates in direct response to industry and customer needs.

Operators of pressurized piping systems encounter challenges; TDW finds ways to meet those challenges, and, in so doing, often advances the science of line intervention.

A great example is the patented STOPPLE® Train plugging system, which was developed by TDW engineers to address the rising need for a simple method of achieving double block and bleed capability. As a way to increase safety, particularly in high consequence areas such as refineries, operators often look for ways to install two barriers—a double block—between the pressurized contents inside an active line and any work (such as pipe cutting or welding) being performed downstream. In many cases, there is also a need for a bleed port to enable the evacuation of pressure and product between the two barriers.

Historically speaking, achieving double block and bleed has never been simple. Two separate valves with a bleed port between them can work, as can a combination of a valve and a plugging head with a port between them. Some operators have turned to a plugging head and an isolation plug separated by a port, though many have just resorted to two separate plugging heads and a bleed port. All of these methods offer dual barriers, but they also typically require more than one hot tap and fitting.

SIMPLIFIED SAFETY Currently available in 4-, 6-, 8-, 10-, 12-, 14-, 16-, 20-, 24- and 30-inch sizes, the STOPPLE® Train plugging system simplifies things considerably. It does so by linking two plugging heads—each with its own sealing element—to form a “train” that can be inserted into a line through a single tapped opening. One hot tap and one fitting can thus provide the additional assurance of a double block. Adding a bleed port between the primary and secondary plugging head makes it possible to bleed the void between them, creating a zone of zero energy.

This same port also makes it possible to verify and monitor the integrity of the primary seal.

Based on proven STOPPLE® plugging technology pioneered by TDW in the 1950s, the STOPPLE® Train system has quickly gained market acceptance, in no small part because the system is capable of handling both low and high pressure environments. At low pressures, compression between the sealing elements and the inside diameter of the pipe creates an excellent barrier, so much so that the seals need not even be energized. At 0.5 psi to 5 psi, the compression fit alone is enough.

At the opposite end of the pressure spectrum, both of the plugging heads in a STOPPLE® Train system are rated to 1,480 psi (102 bar) at 180°F (82°C). At these elevated pressures, the sealing elements are energized. And once energized, the seals function until there is disruption by an external force, typically the retraction of the plugging heads when work is complete. The plugging heads have been successfully pressure tested, with a safety factor, both in tandem and separately.

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The STOPPLE® Train plugging system links two plugging heads— each with its own sealing element—to form a “train” that can be inserted into a line through a single tapped opening.

LESS IS MORE Any piping system intervention naturally leaves behind artifacts—such as tapped openings and their associated potential leak paths—which the operator must live with for the next 20 or 30 years, if not longer.

Fewer artifacts are obviously better from a safety perspective, and the STOPPLE® Train plugging system helps in that regard. Because the system requires just one hot tap and a standard fitting, fewer potential leak paths remain behind, typically half as many when compared with other methods for achieving double block isolation.

Fewer fittings also conserves space and reduces cost. Additional savings come with less excavation, less equipment and less welding.

In fact, job times overall can be reduced, meaning less exposure to potential hazards for on-site personnel. Less scaffolding and fewer cranes are needed for site support. Fewer permits and inspections are typically required.

The STOPPLE® Train plugging system was introduced in 2008. An initial wave of five plugging head sizes (4- through 12-inch) were specifically designed to cover about 80 percent of hydrocarbon processing industry applications. In response to requests from pipeline operators who also sought the value of double block and bleed, a second wave of sizes (including 16- and 24-inch) has been tailored to cover about 80 percent of pipeline market needs. To date, more than 100 piping and pipeline isolation projects have been performed using the system.

CONTACT INFORMATION 6801 S. 65th W. Ave., Tulsa, OK 74131-2444 Phone: +1 918-447-5000 E-mail: contact@tdwilliamson.com www.tdwilliamson.com

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Solutions Outside of the Box THE COMPLETE PACKAGE

People Oriented... Project Driven速 www.mustangeng.com Select 98 at www.HydrocarbonProcessing.com/RS

WOOD GROUP MUSTANG

WOOD GROUP MUSTANG PROVIDES OUT-OF-THE-BOX PROCESS SOLUTIONS Wood Group Mustang is the new brand for a company with a long established presence in the process industries. Comprised of several companies that previously operated either under the Wood Group or Mustang banner, we are now combined into a single entity to add geographic expertise and extensive resources to deliver added value to our clients. Each of the component parts has already established a notable track record that has made them a leader with a broad range of services in the process markets they serve and has garnered a reputation for out-of-the-box thinking in all phases of the project. We are known for executing technically complex projects safely, on-time and within budget. Our capabilities extend throughout the project, from concept through completion and every phase in between. With more than 6,000 employees, we operate in locations within eight countries and have completed more than 11,000 projects for over 300 clients.

We operate as a division of Wood Group, an international energy services company.

DOWNSTREAM Wood Group Mustang’s project engineers have worked together for more than 30 years and our process engineers average more than 20 years in the refining, petrochemical, polymers and chemical industries. They stand out when it comes to project execution, with an emphasis on safety and predictable results. Using extensive front-end planning and the latest in 3D modeling techniques, including laser scanning, we help our clients streamline their projects and reduce costs. We provide sound scope definition with the support of leading edge software systems, technical resources and accumulated knowledge from myriad projects.

We deliver a spectrum of projects from small revamps, modernizations and debottlenecking to large, multi-year billion dollar grassroots facilities. All are cost and schedule-driven to improve HSE and efficiency. Our team has experience with most of the industry’s proprietary technologies. As such, we can offer solid licensor support while remaining technology neutral. Our goal is to provide the best solution possible.

ties design expertise, Wood Group Mustang’s LNG team can apply its knowledge to floating LNG projects from concept studies through operations for projects from 0.5 to 2.5 MTPA production.

GAS PROCESSING Our capabilities extend in many directions and into a wide variety of configurations and processes involving synthetic gas (syngas). We have focused on the conversion of natural gas, coal, petroleum coke and biomass into a range of high value products through gasification and other processing. We have built relationships with suppliers of multiple technologies, gasification systems and applications.

ECOSOLUTIONS Clients who are facing resource and energy challenges are increasingly exploring renewable fuels and resource management. Wood Group Mustang provided design services for, Masdar, the world’s largest carbon capture initiative. In addition, we have provided concept studies, process packages and engineering assistance for biofuels projects.

AUTOMATION AND CONTROL

PROFESSIONAL SERVICES

Wood Group Mustang’s team of automation and control experts uses a vendor-neutral approach to our projects. This assures clients that the most appropriate hardware and software solutions are employed to maximize efficiency, reliability and productivity. We have both the industry and the engineering expertise to act as the project’s Main Automation Contractor (MAC) and as a single-source services provider.

Within the process industries, we address many challenges our clients face with extensive regulatory reporting, complex operations and the integration of accurate data into enterprise systems. We have a qualified team to improve air emissions compliance through a range of services extending to reporting, data integration, work process optimization and instrumentation analysis.

The process industry continually experiences a demand for qualified personnel of all descriptions and disciplines to provide necessary staff at a facility. Wood Group Mustang’s Professional Services offers the solutions, from single professionals to entire project teams, for assignments ranging from short term to multi-year. We tailor your staffing needs to evolving requirements anywhere in the world.

CONTACT INFORMATION LNG Throughout the LNG value chain, Wood Group Mustang provides experience in executing onshore LNG facilities for liquefaction or regasification. With unique topsides and modular production faciliSPONSORED CONTENT

16001 Park Ten Place Houston, Texas 77084 USA Phone: +1 713 215 8000 www.mustangeng.com

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worldwide expertise on demand

Coldest. Hottest. Deepest. Farthest.

That’s where Zeeco people and products work today. Our dedicated team of worldwide experts understand the complexities of combustion across the globe. We have the real-world experience to engineer proven combustion solutions for the global refinery and petrochemical industries.

Trust Zeeco burners, flares and thermal oxidisers.

Experience matters.

burners

flares

thermal oxidisers

aftermarket products & services

Zeeco, Inc. 22151 E 91st St., Broken Arrow, OK 74014 USA +1-918-258-8551 sales@zeeco.com zeeco.com

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©Zeeco, Inc. 2012

ZEECO

BUILT FOR TODAY’S HYDROCARBON PROCESSING CHALLENGES: ZEECO’S LEGACY OF INNOVATION Zeeco, Inc., started out in 1979 as a small operation based on the big idea that better results come from a clear focus on expertise, reliability and innovation. The company’s founder, a recognized combustion engineering expert, was responsible for inventions that led to more than 35 patents for burners, flares, incinerators, and related combustion equipment including the flame-front generator for flare ignition, steam-assisted flares for smokeless flaring, and energy-efficient burners for reduced plant operating costs. Built from the ground up as a lean, responsive company with innovation in its blood, Zeeco engineers tackled industry challenges and delivered products that changed the hydrocarbon processing world.

Thirty-three years and nine expansions later, Zeeco now employs over 450 people in its Broken Arrow, Oklahoma, USA corporate headquarters alone and has offices and staff in 11 other countries. International manufacturing capabilities and local experts make Zeeco a trusted name by customers worldwide. Still privately owned, the company remains focused solely on the combustion business. Driven by the simple philosophy of better by design, Zeeco experts look at product development from an inside-out perspective instead of just looking for incremental improvements in existing concepts. Continuing a legacy that pioneered the development of permeate gas incinerator technology for the natural gas processing industry, Zeeco continues to design innovative, industrychanging products like the patented GLSF Free-Jet Burner. “Zeeco’s strength has always been the talent of its people and the industry knowledge they bring to every challenge or project,” says Zeeco’s Dan Caho, Director of Business Development.

Zeeco burners, flares and incinerators serve the hydrocarbon processing industry worldwide, meeting the strictest emissions requirements and surviving some of the harshest operating conditions on the planet, including the world’s hottest and coldest climates and the North Sea’s deepest drilling operation. In addition, Zeeco designed the world’s largest demountable flare and the world’s largest SRU thermal oxidizer.

With its continuing focus on innovative products, Zeeco serves today’s refining, petrochemical, production, power and pharmaceutical industries through new ideas and new approaches like using the waste heat from thermal oxidizers in gas processing plants to reduce plant fuel costs and boost bottom line gas sales. A rich history of working hand-in-hand with industry leaders and understanding their challenges gives Zeeco an edge. Those relationships led to the development of technology for liquid flaring that reduced liquid carryover by more than 99% and HighPressure Air Assist flaring. Zeeco’s HPAAS technology allows plants to quickly and economically achieve efficient and smokeless flaring in new and existing applications.

Keeping the talented engineers and experts at Zeeco motivated to look for better ways to do things means keeping things in perspective from the top down. “We appreciate the importance of balancing the interests of our customers, employees and our communities,” says Caho.

The kind of people who have always thrived at Zeeco are the ones who enjoy a good challenge and who believe in hard work, integrity and reliability. Those qualities, present from day one in the Zeeco team, are what positions Zeeco to shape the combustion industry’s future. As the industry embraces development in tight oil, oil sands, shale gas, more remote fields, and stricter emissions requirements, Zeeco designs SPONSORED CONTENT

Zeeco has grown tremendously over the past two decades in response to customer demand and market conditions. Our debtfree headquarters complex includes 73,000 sq. ft. of manufacturing space and one of the industry’s largest combustion testing and research facilities. will continue to make the process more efficient and reliable. Beyond innovative products, Zeeco tackles the processes involved, too. The Zeeco Rapid Response Team took apart the repair and replacement part process and rebuilt it with the customer in mind. Now housed in a separate facility with its own manufacturing equipment and workflow, the RRT can replace flare tips in days.

Zeeco corporate headquarters is located on a 250 acre modern, debt-free campus that includes offices, manufacturing and fabrication space, and one of the industry’s largest combustion research and testing facilities. Continued expansion of both the core facility and the testing facility is planned over the next few years as Zeeco looks for ways to meet the industry challenges of tomorrow.

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BASF

BASF—SERVING THE HYDROCARBON PROCESSING INDUSTRY FOR OVER 120 YEARS From our invention of the contact process for sulfuric acid production in 1888 to the industrial catalytic process for ammonia in 1913 to commercialization of the three-way catalytic converter in 1974, BASF has played a vital role in shaping the history of industrial catalysis. As the global leader in this field, we continue to revolutionize the hydrocarbon processing industry and advance chemical applications of all kinds, helping drive our customers’ success.

“As a catalyst company, BASF can only be successful by working with strong partners. We provide a comprehensive and cost-competitive portfolio of leading catalytic technologies, which is constantly improved through innovation. We use highly efficient platform technologies and highthroughput catalyst-screening methods. This, in combination with dedicated R&D projects in all regions, enables us to develop innovations quickly, in close collaboration with our customers,” says Hans-Peter Neumann, BASF Senior Vice President, Process Catalysts & Technologies.

At BASF, we understand that the total value of our solutions must extend beyond the product itself to include commercial and technical support, global supply chain management and responsive customer service. We’ve built a

First definition of catalysis by Jöns Jakob Berzelius

Phinesse™ introduced as part of the REAL program offering lower rare earth

BASF develops the “contact process” for producing sulphuric acid

Alwin Mittasch (BASF) finds the industrial catalyst for production of ammonia by systematic tests of several thousand catalyst formulations

Rare Earth Alternative (REAL) Solutions introduced to cope with high rare earth oxide price environment

Fritz Haber, Carl Bosch, and Alwin Mittasch implement the industrial scale ammonia process

BASF and Dow announced the world’s largest commercial-scale propylene oxide (PO) plant and the first based on the innovative hydrogen peroxide to propylene oxide (HPPO) technology

Adsorbents Chemical Catalysts ■ Custom Catalysts ■ Environmental Catalysts ■ Polyolefin Catalysts ■ Precious Metal Services ■ Refinery Catalysts ■ ■

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commercial and technical team that has more than 300 years of combined experience in the development and application of catalyst technologies across the entire range of chemical processes. This expertise is further strengthened by a global team of customer service providers, global centers of manufacturing excellence, and the capability of the global BASF supply chain.

“BASF is committed to partnering with its customers to understand the challenges faced by the global hydrocarbon processing community and we are proud to continue our proven tradition of introducing sustainable solutions to the market,” Neumann added.

The result is a broad catalyst portfolio backed by dedicated customer and technical service and enabled through the strength of BASF—The Chemical Company. At BASF, we create chemistry for a sustainable future.

DOWNSTREAM INNOVATIONS: 1922 TO PRESENT HydrocarbonProcessing.com

Franz Fischer and Hans Tropsch develop the catalytic hydrogenation of carbon monoxide to liquid hydrocarbons (gasoline)

BASF received Frost & Sullivan Award for Technology Leadership in recognition of Distributed Matrix Structures (DMS) and NaphthaMax® FCC catalyst innovation

Eugene Houdry develops fluid catalytic cracking (FCC)

The three-way catalytic converter for removing pollutants from gasoline engine exhaust is commercialized by BASF

1st refining catalyst application (Platinum reforming catalyst for Sinclair Oil Catforming process)

1st FCC Catalyst produced

Contact Us Americas catalysts-americas@basf.com Asia Pacific catalysts-asia@basf.com Europe, Middle East & Africa catalysts-europe@basf.com www.catalysts.basf.com

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YOKOGAWA

THE CLEAR PATH TO OPERATIONAL EXCELLENCE Since Yokogawa’s founding in 1915, it has been helping customer’s improve their quality, optimize throughput, reduce energy costs and increase plant safety. Yokogawa’s global business spans 54 countries and generates over $3 Billion annually. Our cutting-edge research and innovation, resulting in 7,200 patents and registrations have helped our customer’s continual drive to improve their processes. These innovations include the world’s first digital sensors for flow and pressure measurement introduced in 1998. Since the 1975 introduction of Yokogawa’s Centum System, we have supplied over 23,000 Distributed Control Systems worldwide providing our customers with the lowest lifecycle costs and highest reliability (seven 9s) system in the industry. Industrial Automation, Measurement, Control and Business System Integration are the foundation of Yokogawa’s global business.

OUR PRODUCTS Systems • Integrated Process Control System • Safety Instrumented Systems • SCADA Systems • Network Control Systems including intelligent RTU systems

INDUSTRY BASED SOLUTIONS

Solution Packages • Alarm Management Solutions • Device Asset Management Solutions • Historians and SER Solutions • Transaction Management Solutions • Real-time Production Organization and Production Management • Integration and Interface Solutions • Simulation • Advanced Process Control and Optimization

Upstream • AGA Flow Metering • Well Head and Lift Plunger Applications • Platform and FPSO Applications • Pipeline Control and Monitoring Downstream • Modular Procedural Automation including Batch Automation • On-site and Off-site Automation • CombustionOne Fired Heater Optimization

Pressure, Temp and Flow • Coriolis, Vortex and Magnetic Flowmeters • Pressure and Temperature Transmitters Analytical • Gas Density Analyzer and Detector • Zirconia Oxygen Analyzers and Detectors • Process Gas Chromatograph • Tunable Diode Laser Spectroscopy Analyzer • Liquid Analyzers and Sensors Data Acquisition • Data Acquisition and Display Station • Single Loop Controllers • Wireless DAQ Recorders Services • System and Process Optimization • Lifecycle Effectiveness Services • Alarm Analysis • Cybersecurity • Training SPONSORED CONTENT

CONTACT INFORMATION Yokogawa World Headquarters Phone: (81)-422-52-5535

Yokogawa America do Sul Ltda.

Phone: (55) 11-5681-2400

Yokogawa Corporation of America Phone: (1)-800-888-6400

Yokogawa Engineering Asia Pte Ltd. Phone: (65) 6241-9933

Yokogawa Europe B.V. Phone: (31)-88-4641000

Yokogawa Middle East B.S.C.(c) Phone: (973)17358100

Yokogawa Electric CIS Ltd. Phone: (7) 495-737-7868

Yokogawa China Co., Ltd. Phone: (86) 21-6239-6262

www.yokogawa.com HYDROCARBON PROCESSING

DOWNSTREAM INNOVATIONS: 1922 TO PRESENT

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BAKER HUGHES

CHEMICAL INVENTIONS THAT REVOLUTIONIZED THE HYDROCARBON PROCESSING INDUSTRY For almost a century, innovation has been part of our DNA in the Baker Hughes Downstream Chemicals product line. In 1914, William S. Barnickel was awarded a patent for the first crude oil demulsifier. Melvin DeGroote’s inventions of chemical demulsifiers contributed to the development of the modern oil industry by making more types of crude suitable for refining. At retirement in 1960, DeGroote had earned over 900 U.S. patents, making him the most prolific inventor of his era, second only to Thomas Edison. Scientist Charles M. Blair looked more closely at problems associated with crude oil refining.

In the early 1930s, crude units would have to be shut down for cleaning every few weeks.

Blair combined the use of chemical demulsifiers with settling vessels, and then extended that to electrical desalters. Blair also developed a salt-in-crude analytical method, published in Industrial Engineering Chemistry, Analytical Edition in 1938, which became the basis for future industry standards. In 1949, Blair received a patent for the use of imidazolines as corrosion inhibitors both in the oilfield and the refinery—a technology “first.” Before Blair, the idea of protecting equipment with chemical inhibitors was unprecedented.

Since those earliest advancements, Baker Hughes has never stopped searching for solu-

tions to challenges in the refining industry, and today has more than 3,000 patents companywide. Key technological breakthroughs include the first patented naphthenic acid corrosion inhibitor, SMARTGUARD™ inhibitors, which help refiners process high TAN crudes; EXCALIBUR™ contaminant removal programs enable refiners to process crudes high in metals and other contaminants that cause unit reliability and product quality issues; and XERIC™ heavy oil demulsifiers help refiners process Canadian crude.

Baker Hughes continues to invest in research and development to meet the next frontier.

Refiners processing shale oil are now looking to Baker Hughes for solutions. The blending of light, paraffinic crudes with asphaltenic crudes is known to destabilize asphaltenes, causing them to precipitate, which leads to desalter operational issues and increased fouling in the hot preheat train. Using our new Field ASIT services™ tool, refiners are able to determine the stability of crude oils and crude oil blends on-site, providing an early-warning mechanism for potential processing issues. Our crude pretreatment and compatibility aids help to increase the stability of the blends and minimize process impacts.

Today, Baker Hughes experts continue the tradition of technological innovation and services, helping our customers achieve the reliable performance they need to efficiently process hydrocarbons.

NOTABLE BAKER HUGHES TECHNOLOGICAL ADVANCEMENTS

Baker Hughes Scientists: Top: William S Barnickel (left), Melvin de Groote. Bottom: Dr Larry Kremer (left), Dr Jerry Weers.

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1914—First patent for a crude oil demulsifier.

1936—Installs a desalter at a refinery in Kentucky.

1946—First corrosion inhibitor at a gasoline plant in Illinois.

1949—First corrosion inhibitor at an Illinois refinery.

1949—First patent for ethoxylated demulsifier.

1949—First patent for the use of imidazolines as corrosion inhibitors.

1955—First dispersant fouling inhibitor at an Illinois refinery.

1960—Patent for anti-oxidant fuel stability additive for #2 fuel and diesel.

1963—First inhibitor dispersant in a naphtha HDS heat exchanger.

1988—First successful crude oil pretreatment program—Crude Oil Management™ program

DOWNSTREAM INNOVATIONS: 1922 TO PRESENT HydrocarbonProcessing.com

1990—First chemical patent for inhibiting high-temperature corrosion caused by naphthenic acids.

1990—First patent for reactor bed antifoulant.

1991—First patent for a H2S scavenger.

1996—First chemical ser vice company to license and apply Shell Ionic Model technology to refinery overhead corrosion problems—TOPGUARD™ program.

1996—VisTec™ visbreaker technology to control fouling and optimize conversion in visbreakers.

2002—Asphaltene Stability Index Test™ (ASIT™)—a laboratory test to determine crude oil compatibility and to predict the potential for asphaltene instability.

2002—First use of hydrogen flux monitoring for naphthenic acid corrosion in a refinery— SMARTGUARD™ naphthenic acid corrosion control program.

2003—Patent for crude oil contaminant removal technology—EXCALIBUR™ program.

2006—MILESTONE™ program for hightemperature fouling control.

2007—TOPGUARD™ corrosion inhibitors and neutralizers specifically for controlling overhead corrosion when processing opportunity crudes.

2008—Patent for higher viscosity silicone antifoam–Baker Petrolite FOAMSTOP™ low catalyst impact antifoam program.

2008—XERIC™ heavy oil demulsifiers.

2009—Field ASIT Services™ technology.

2010—Introduction of technology to control fouling and optimize conversion in ebullated bed resid hydrocracker process.

2011—LIFESPAN™ program for heat exchanger fouling control.

ASIT, Asphaltene Stability Index Test, Baker Petrolite FOAMSTOP, Crude Oil Management, EXCALIBUR, Field ASIT Services, LIFESPAN, MILESTONE, SMARTGUARD, TOPGUARD, VisTec, XERIC are trademarks of Baker Hughes Incorporated.

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CARVER PUMP COMPANY

CARVER PUMP COMPANY— CREATING VALUE FOR OVER 70 YEARS After 70 years Carver Pump Company continues to supply pumps for some of the toughest Industrial and Military applications! During this time a reputation for creating value has been

attained by building premium quality pumps used by the Automotive, Chemical Processing, Mining, Refining, Power Generation, General Manufacturing and Pulp/Paper markets.

1955 Chevy 150/210

Do you have flows up to 1,400 US GPM (320 m3/hr), heads up to 3,400 feet (1,000 m), pressures up to 1,500 psig (100 bar), temperatures from 20˚F to 300˚F (-30˚C to 149˚C), and speeds up to 3,500 RPM? Then you need Carver Pump RS Series muscle!

RS Series

Designed for moderate to high pressure pumping applications, the RS is available in five basic sizes with overall performance to 1,000HP. As a standard, with a product lubricated radial sleeve bearing and two matched angular contact ball bearings for thrust, it only takes a mechanical seal on the low pressure, suction side to seal the pump. Optional features include ball bearings on both ends with an outboard mechanical seal, various seal flushing arrangements and bearing frame cooling. These features make the RS ideally suited for Industrial and Process applications including Pressure Boost Systems, Boiler Feed, Reverse Osmosis, Desalination and Mine Dewatering. Whatever your application, let us build the muscle you need!

Boasting a rugged product line that offers horizontal and vertical end suction pumps, multistage, axial split case self-priming and API, our pumps are used in land-based, mobile and shipboard installations. Specifically designed to meet the needs of the Hydrocarbon Processing Industry, we now offer the API Maxum Series. Fully compliant with latest edition API 610 specifications, this unit is designed for optimum reliability.

The API Maxum Series is available in 35 sizes to handle flows exceeding 9,000 GPM and 720 feet of head. Standard materials include S-4, S-6, C-6 and D-1. Capable of operating up to 400°F without external cooling and 600°F with cooling makes this pump ideal for mid-high temperature applications. Standard features include renewable wear rings, seal chamber designed for 682 mechanical seals, heavy duty carbon steel/finned bearing housing equipped with labyrinth type oil seals, fan cooling and more!

As with all our other pumps, the API Maxum offers the reliability, low total life cost, and lasting value that has made Carver Pump Company one of the most trusted names in pumps Let us build the muscle you need!

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Creating Value.

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Select 165 at www.HydrocarbonProcessing.com/RS D-142

DOWNSTREAM INNOVATIONS: 1922 TO PRESENT HydrocarbonProcessing.com

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As a market leader in licensing world-class units, CLG relies heavily on state-of-the-art, high-performance catalysts to process the most difficult feeds into the cleanest products possible. We offer complete engineering services from conceptual studies to fullengineering design packages. CLG has a complete line of hydroprocessing technologies and catalysts covering the full hydrocarbon boiling spectrum: • ISOCRACKING • Lube base oil ISODEWAXING and ISOFINISHING • Residuum hydrocracking—LC-FINING and LC-MAX • Residuum hydrotreating—RDS, VRDS, OCR, and UFR • Distillate and VGO hydrotreating • State-of-the-art reactor internals—ISOMIX®-e As the most completely integrated source for hydroprocessing technologies and services, CLG provides efficiencies at every step in your project. We bring planning skills to your project that we’ve honed from designing thousands of projects in over 70 countries balanced by the practical know-how that comes from hands-on, day-to-day operating experience. This experience, unmatched in the industry, is available to you as a complete package or as individual services tailored to meet your specific needs.

CLG is an operating company just like you. We know the value of Operational Excellence; we know how to extract maximum value from complex hydroprocessing units; and we know how to employ safe operating practices. Combining our own first-hand operating expertise with our rich history of catalyst developments allows us to provide you with unparalleled technology and customer support.

1977 VRDS Hydrotreating

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DOWNSTREAM INNOVATIONS: 1922 TO PRESENT

D-143

ELLIOTT GROUP

ELLIOTT GROUP: 100 YEARS OF TURBOMACHINERY EXCELLENCE Companies around the world turn to Elliott Group to design, manufacture and service their critical turbomachinery. For more than 100 years, Elliott has been synonymous with innovative engineering, highly reliable products and unwavering commitment to customer satisfaction.

Since 2000, Elliott Group has encompassed the global turbomachinery operations of its corporate parent, Ebara Corporation, headquartered in Tokyo, Japan.

Elliott’s engineering and manufacturing centers in Sodegaura, Chiba, Japan and Jeannette, Pennsylvania produce efficient and reliable rotating equipment, including steam turbines, power recovery expanders and centrifugal and axial compressors. Elliott’s global network of full-service repair centers, field service teams, and sales and support offices extend throughout North and South America, Europe, the Middle East and Asia.

All of Elliott’s 2,400 employees worldwide recognize the critical importance of each customer’s requirements, and have the technical expertise and competencies to deliver high-value solutions. Elliott is known for its integration and coordination of its global service operations and processes so that customers have the same satisfying experience each time they interact with us, everywhere in the world.

MARKETS AND APPLICATIONS Elliott Group supplies and services turbomachinery for the industries that are the foundation of the global economy. We have delivered hundreds of compressors to oil and gas producers that offer the superior performance, flexibility, availability and reliability they demand. Our API-compliant compressors are critical in applications such as well head/booster stations, enhanced oil recovery, gas gathering, gas/oil separation, and gas treatment and processing.

Elliott was a pioneer in supplying refrigeration compressors for baseload LNG plants. Today, Elliott is a key a partner in several of the world’s largest LNG projects in the Middle East, Russia, Asia and the United States. Elliott’s LNG experience includes more than 100 compressors producing over 70 million tons per annum of LNG capacity.

Building upon its 50-year history in refrigeration compression technology, Elliott equipment operates in many of the world’s largest ethylene plants with capacity of one million tons per annum or greater.

Elliott designs efficient, reliable compressors for volumetric flow rates up to 320,000 icfm. As petrochemical production plants grow ever larger, custom-engineered cracked gas, propylene and ethylene compression trains from Elliott continue to meet the demand for increased throughput and reliability.

Elliott’s compressors have been used in critical refining processes for more than 70 years. As the refining industry has grown and evolved, so have Elliott’s compressors and steam turbine drivers. Elliott compressor and steam turbine drivers are used worldwide in refinery applications such as hydroprocessing, catalytic cracking and reforming, coking, and alkylation.

Companies turn to Elliott steam turbine generator (STG) sets for efficient reliable power. Elliott’s STGs provide 50kW to 50MW of renewable, cost-effective power from existing steam systems or alternative fuels such as biomass in completely integrated packages. Packages include the steam turbine, speed reducing gear, generator, lube

D-144

DOWNSTREAM INNOVATIONS: 1922 TO PRESENT HydrocarbonProcessing.com

system, controls, base plates, commissioning services, and operator and maintenance training.

Elliott STGs support many industrial applications including: power, geothermal, chemical processing, food and beverage, industrial manufacturing, refining, oil and gas processing, pulp and paper, pharmaceuticals, alternative fuels, municipal waste-to-energy, steel and sugar.

GLOBAL SERVICE With more than a century of turbomachinery experience, Elliott Group offers comprehensive service and support for all types of rotating equipment. We know what it takes to keep equipment performance high and maintenance costs low regardless of the original manufacturer. Elliott’s Global Service operations are LRQA certified to Quality Management System Standard ISO 9001:2008 for design, manufacture, modification and repair of turbomachinery and associated components and equipment, as well as turbomachinery installation, field maintenance and overhaul. Elliott is accredited by the American Society of Mechanical Engineers, with both U and R boiler and pressure vessel certifications. We adhere to the principals of the American Society of Nondestructive Testing.

Elliott’s global network of two dozen full-service repair centers provide a complete range of service for Elliott and non-Elliott rotating equipment.

Our service teams include experienced, dedicated engineers, metallurgists, technicians, welders, machinists and mechanics. Elliott’s field service team is recognized throughout the world for technical expertise and hands-on experience with all types of turbomachinery.

As technology, materials and plant capacity evolve, companies seek to maximize the performance of their critical rotating machinery. Elliott Engineered Solutions is dedicated to helping customers enhance the value of their turbomachinery. Rerating or upgrading existing apparatus to meet new production requirements can be a more cost-effective solution with shorter lead time than investing in new equipment. Elliott Engineered Solutions extends the life of centrifugal compressors, steam turbines and power recovery systems from any manufacturer quickly and affordably regardless of the manufacturer.

At Elliott Group, we are committed to providing each customer with the best possible solution to the challenges they face.

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Saint-Gobain NorPro has been servicing the industry for well over 100 years ... an evolving company that started as United States Stoneware Company in 1859, producing chemical stoneware in the design and fabrication of random packing used in chemical processing reactors. Norton Company acquired United States Stoneware in 1966, and from there, the company was named Norton Chemical Process Products and grew to include not only ceramic random packing for heat and mass transfer applications, but custom catalyst carriers and catalyst support media for refining, gas processing and petrochemical applications.

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HYDROCARBON PROCESSING

DOWNSTREAM INNOVATIONS: 1922 TO PRESENT

D-145

Originally published in The Refiner, February 1928; see current ad on page 81.

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Timeline

JANUARY 10, 1901

1900

Major oil discovery in Texas; Spindletop well.

A CLOSER LOOK AT THE HPI 1901 to present

JANUARY 1, 1902

JUNE 17, 1902 Formation of the National Petroleum Association (NPA).

Linde builds world’s first air separation unit to produce oxygen.

1905

1920

GASOLINE HAS 40–60 OCTANE VALUES 1920

MARCH 25, 1905

JULY–AUGUST 1914

US government breaks up the Standard Oil trust and creates the forerunners of the major US refining companies.

World War I (WWI) begins in Europe.

1921

JUNE 1, 1915

Thomas Midgley Jr. discovers tetraethyl lead as an effective antiknock agent for gasoline.

German scientist develops the first hydrocracking process to convert coal into liquid fuels.

1922

OCTOBER 1908 Henry Ford introduces the Model T; cost $850.

FEBRUARY 17, 1911 First electric starter installed on a Cadillac; Charles Kettering invents the electric ignition system.

NOVEMBER 1912 The Western Petroleum Refiners Association (WPRA) is founded.

JANUARY 7, 1913 William M. Burton receives a patent for his cracking process to produce gasoline from crude oil; Standard Oil of Indiana builds the first commercial thermal cracking unit.

DECEMBER 17, 1917

THE US ENTERS WWI First US pipeline transports gasoline through a 3-in. pipe over 40 miles from Salt Creek, Wyoming, to Casper, Wyoming.

1918 NPA and WPRA open an office in Washington, D.C.

NOVEMBER 18, 1918

WWI ENDS

WPRA merges with the Texas Petroleum Association.

Dow introduces ethylene dibromide for use in ethyl gasoline.

SEPTEMBER 1922 The first issue of The Refiner and Natural Gasoline Manufacturer is published. It is the forerunner of the present-day refining/petrochemical/ technical publication Hydrocarbon Processing.

1923 Almer McDuffie McAfee, a US chemist, develops the first commercially viable catalytic cracking process that doubles gasoline yield over standard distillation methods. The process uses an expensive catalyst—anhydrous aluminum chloride.

FEBRUARY 2, 1923

1919

Leaded gasoline is introduced to the US market.

UOP commercializes the Dubb’s thermal cracking process.

The American Petroleum Institute (API) is founded.

Firestone Tire and Rubber Co. begins production of balloon tires for commercial use.

148 JULY 2012 | HydrocarbonProcessing.com

APRIL 1, 1923

1930

1930

Standard Oil of New Jersey (Exxon) collaborates with I.G. Farbenindustrie of Germany to develop a hydrocracking technology capable of converting heavy petroleum oils into fuels at 200 to 350 barg.

Discovery of the East Texas Oil Field.

BASF scientists develop a commercial way to manufacture polystyrene.

First hydrorefining unit is installed at Standard Oil Co. of Louisiana’s Baton Rouge refinery.

JUNE 1931 Texas Co. and Humble Oil Refining Co. join Standard Oil in drastic price slashing on mid-continent

oils; Linde builds the first plant to recover ethylene via low-temperature rectification.

Eugene Houndry, working with Sun Oil, patents the Houndry catalytic cracking (HCC) process to produce higher-octane gasoline.

JANUARY 1, 1933 Reginald Gibson and Eric Fawcett with Imperial Chemical Industries (ICI) discover polyethylene. UOP introduces a catalytic polymerization process to blend gasoline.

First jet engine is built.

1936

Pneumatic transmitters and pneumatic-controlled instruments are introduced.

1938 Roy Plunkett, a chemist with DuPont, discovers Teflon by accident.

US, British and German companies produce polymethyl methacrylateacrylic. The transparent material is sold as a glass replacement.

1939 Germany invades Poland; beginning of World War II (WWII).

1937 Friedrich Bayer & Co. of Germany discovers polyurethane.

ICI develops a two-stage hydrocracking process.

1940

1940 1927 First commercial hydrocracker is constructed at Leuna, Germany. It converts lignite into liquid fuels.

Charles Lindbergh makes first solo transatlantic flight from New York to Paris.

MAY 24, 1927 Thomas Edison receives a patent for a method to produce chlorinated rubber.

1928 Thomas Midgley Jr. and Charles Kettering invent the nontoxic, nonflammable refrigerant called Freon.

Styrene and Saran are developed.

Standard Oil Co. is offered membership in NPA.

1929 German scientists discover process for synthetic rubber called Buna—an emulsion-based process with butadiene and styrene. Standard Oil of Indiana (now BP) commercializes the Burton Process for delayed coking along with the Buna S polymer. The rubber process yields a rubber polymer more durable than natural rubber.

OCTOBER 29, 1929

STOCK MARKET CRASHES; BEGINNING OF THE GREAT DEPRESSION

B. F. Goodrich scientists copolymerize butadiene with methyl methacrylate to create rubber, called Ameripol, for tire applications. Phillips Petroluem develops the HF alkylation process.

1941 Two English chemists, Rex Whinfield and James Dickson, develop polyethylene terephthalate (PET) and the base for synthetic fibers, such as polyester, Dacron and terylene.

DECEMBER 7, 1941

JAPAN BOMBS PEARL HARBOR; US ENTERS WWII JANUARY 1, 1942 US government begins massive construction projects to produce jet fuel, synthetic rubber, toluene and other materials to support WWII effort.

APRIL 26, 1942 Firestone produces the first bale of synthetic rubber.

JUNE 4, 1941

SYNTHETIC RUBBER TIRE IS UNVEILED AUGUST 1942 The Refiner and Natural Gasoline Manufacturer is retitled Petroleum Refiner; the name change reflects the significant advancements and broader scope of petroleum processing.

1944 The French Government establishes the Institut Français du Pétrole (IFP) to implement and develop petroleum technology.

Hydrocarbon Processing | JULY 2012 149

Germany surrenders, ending WWII in Europe.

Michigan builds the world’s first catalytic reformer based on UOP’s Platforming process.

Luxembourg are the first nations to establish this union.

AUGUST 1945

1951

Following atomic bombings of Hiroshima and Nagasaki, Japan surrenders, ending WWII in Asia Pacific.

Paul Hogan and Robert Banks with Phillips Petroleum of The Netherlands are official inventors of crystalline polypropylene.

Dow introduces Saran wrap for household use.

MAY 7, 1945

1945

1947

Linde builds the first RECTISOL plant for gas purification.

The transistor is invented.

MAY 11, 1947

UNIVAC, the first commercially practical computer, is developed.

B. F. Goodrich Co. develops the tubeless tire.

APRIL 1951

1948 The US enacts First Water Pollution Control Act.

1949 Old Dutch Refining in Muskegon,

1955

The European Union is formed to quell competition and to foster cooperation in the coal and steel industries. Germany, France, Italy, The Netherlands, Belgium and

1955

1958

US Congress adopts the Mandatory Oil Import Program to control imports of lower-priced foreign oil.

NASA launches its first space rocket carrying the Explorer satellite.

1957

APRIL 1959

Soviet Union launches Sputnik I and II.

Texaco installs the first computer-control system on its polymerization unit.

First shipment of LNG from Louisiana to the UK proves the safety of importing LNG to replace coal for electrical power generation.

1960 Technologies developed for lead removal from gasoline.

Karl Ziegler discovers a catalyst to produce polyethylene without high pressure and temperature.

NOVEMBER 1953 The first Petrochemical Process Handbook is published in the Petroleum Refiner. It features descriptions of emerging petrochemical processes.

1954 Guilio Natta develops catalytic process for polypropylene.

1960

First modern hydrocracking unit is constructed by Standard Oil Co. of California.

Standard Oil Co. of California (now Chevron) introduces catalytic hydrocracking.

SEPTEMBER 1960

JULY 1, 1961

Formation of the Organization of the Petroleum Exporting Countries (OPEC).

NPA and WPRA merge to create the National Petroleum Refiners Association (NPRA).

APRIL 1961

JUNE 1, 1962

Soviet Union astronaut Yuri Gagarin is the first man in space.

IFP licenses its first catalytic reforming unit.

MAY 1961

JANUARY 1963

The Petroleum Refiner is retitled Hydrocarbon Processing and Petroleum Refiner. This change further demonstrates the expansion of the petrochemical industry.

CONCAWE is established by a small group of leading oil companies to carry out research on environmental issues relevant to the oil industry.

150 JULY 2012 | HydrocarbonProcessing.com

1953

1964 Charles J. Plank and Edward J. Rosinski, with Mobil Oil Co., invent the first zeolite catalyst used in the petroleum industry for catalytic cracking of petroleum into lighter products such as gasoline.

JANUARY 1964 The British Gas Council begins importing LNG from Algeria; the UK is the world’s first LNG importer, and Algeria is the first LNG exporting nation.

1965 Digital Equipment Co. introduces the first mini-computer.

JANUARY 1, 1965

1965

LINDE BUILDS THE FIRST COMMERCIAL, LARGE-SCALE ETHYLENE PLANT WITH CRACKING FURNACES JUNE 1, 1965

JUNE 1966

1969

Ziegler and Natta are awarded the Nobel Prize for their discoveries in the science and technology of polymers.

Hydrocarbon Processing and Petroleum Refiner is retitled Hydrocarbon Processing, thus marking the integration of the refining and petrochemical industries.

Dr. Robert W. Gore invents a new form of polytetrafluoroethylene widely known as GORE-TEX—a chemically inert material used on wires and cables.

1968

Japan imports LNG from Alaska, a project developed

by Philips Petroleum.

1966 Stephanie Kwolek receives a patent for the synthetic material Kevlar.

As a research chemist for DuPont, Kwolek discovers the noncorroding, high-strength material used in bulletproof vests, brake linings and more.

1970

Bedford Associates develops the first progammable logic control (PLC) to replace hardwired relays.

The first controller is called model 084 by Modicon.

NOVEMBER 1969

GREENPEACE IS FOUNDED

CLEAN AIR ACT (CAA) OF 1970 IS PASSED; IT USHERS IN WIDESPREAD PROVISIONS TO IMPROVE AIR QUALITY APRIL 22, 1970

1972

First Earth Day.

Mobil invents ZSM-5, a shapeselective catalyst used in FCC, catalytic dewaxing and other processes.

DECEMBER 1970 The Environmental Protection Agency (EPA) is created to set national standards for clean air, water and land.

Allen Bradley develops the first computer terminal for programming.

DECEMBER 29, 1970 US President Richard Nixon signs the Occupational Safety and Health Act of 1970. The law creates three organizations, including the Occupational Safety and Health Administration (OSHA).

1973 Arab Oil Embargo triggers oil price rise; EPA issues rules to phase out lead in gasoline.

1974 Automobile manufacturers introduce new engines equipped with catalytic converters.

Dr. Federico Faggio invents new memory chips now used in automobiles, medical devices and computers.

JUNE 1, 1974 A temporary bypass line ruptures at a caprolactum plant in Flixborough, UK, releasing 40 tons of cyclohexane that results in a vapor cloud explosion. This event triggers enactment of new safety rules in the UK.

1975 Honeywell releases the first distributed control system with the TDC 2000.

1975

1975

Oil prices reach $10.72/bbl, up from $1.30/bbl in 1970. Phase-out of leaded gasoline begins. NPRA hosts the first petrochemical annual meeting, which is held independently of the refining annual meeting.

Saudi Arabia plans construction of two industrial cities—Al-Jubail and Yanbu. Saudi Basic Industries Corp.

(SABIC) is created.

Hydrocarbon Processing | JULY 2012 151

1976

1976

JANUARY 1985

An accident at a pesticide/herbicide facility in Seveso, Italy releases a dense vapor cloud of dioxin into the community. Over 2,000 residents of Seveso are treated for dioxin poisoning.

Canada launches the first Responsible Care program responding to public concerns about the manufacture and use of chemicals.

1985

The Toxic Substances Control Act (TSCA) enables the US EPA to control toxic chemicals.

1978 The Iranian Revolution triggers a second oil price crisis; crude oil prices rise from $13/bbl to $34/bbl.

Establishment of the Natural Gas Policy Act in the US abolishes price ceilings on old and new gas wells.

1979 Data highway/network communications for instrumentation and data monitoring are developed.

1980

JUNE 1985 PETROKEMYA and YANPET start up worldscale polyethylene units in Al-Jubail, Saudi Arabia. Saudi Arabia bumps up OPEC quota to support oil prices, causing a rift in cartel relations.

1986 Oil prices collapse, dropping 50% in the first three months of the year to less than $10/bbl; the oil industry bottoms out.

By the end of the first half of the 1980s, 123 of the US’ refineries have shut down.

The American Chemistry Council launches its version of the Responsible Care program.

1980

APRIL 28, 1986

Elf Aquitaine, Total and IFP form a joint heavy oil upgrading group; three processes are developed—Asvahl, Solvahl and Hyvahl.

In Chernobyl, Ukraine, failure of an experiment in the nuclear power plant causes the blowout of the reactor and radioactive material. It is deemed the worst nuclear disaster.

Oil prices exceed $35/bbl. Also, US adopts comprehensive LNG safety regulations.

High-tech companies develop improved information technology (IT) and the foundation for the Internetenabled information age.

JANUARY 29, 1981 US President Reagan signs legislation that de-controls the price of oil and its products.

1982 US EPA proposes an aggressive ban on lead in gasoline.

AUGUST 1982 Council Directive 82/501/EEC on major accident hazards of certain industrial activities is adopted by the EU in response to the dioxin release at Seveso, Italy. It is also known as the Seveso Directive.

1984 Japan becomes a major buyer of LNG, purchasing 72% of the world’s product.

NOVEMBER 19, 1984 In Mexico City, Mexico, an explosion at an LPG storage tank kills 500 residents and injures more than 700.

DECEMBER 3, 1984 Massive leak of methyl isocyanate from the Union Carbide plant in Bhopal, India causes thousands of deaths and injuries to local residents.

152 JULY 2012 | HydrocarbonProcessing.com

1987 ISO 9000 is published, outlining a family of standards promoting quality management systems for manufacturing companies.

JULY 6, 1988 Piper Alpha, a North Sea oil production platform, experiences a fire caused by missed steps in maintenance. The event results in 167 deaths and remains one of the worst offshore events in history.

OCTOBER 14, 1988 The Alternative Motor Fuels Act is passed, requiring government vehicle fleets to use alternative fuels such as methanol and ethanol.

AUGUST 1989 In California, ARCO Products Co. introduces EC-1—the first reformulated gasoline designed to reduce emissions from motor fuels.

OCTOBER 23, 1989 At the Phillips 66 plant in Pasadena, Texas, a ruptured seal on a polyethylene reactor releases ethylene and isobutene gas. The gas cloud leads to a massive explosion, killing 23 employees and injuring more than 300 workers.

Process Safety Management regulations grew from this event.

1995

JANUARY 1, 1995

DECEMBER 9, 1996

Reformulated gasoline is required for the nine US nonattainment areas.

Council Directive 96/82/EC on the control of major accidents and hazards (Seveso II Directive) requires EU member states to enforce safety management systems, emergency planning and land-use planning rules. Seveso II now has broader scope following major accidents at Toulouse, Baia Marte and Enscheda.

JANUARY 1, 1995 JANUARY 1996

LEADED GASOLINE IS PROHIBITED FOR HIGHWAY USE AS PER THE NEW CLEAN AIR ACT

IFP acquires HRI, adding H-Oil and other heavy oil processes to its licensing group.

1996 ISO 14000, a family of standards related to environmental management, helps organizations minimize how their operations can affect the environment.

JUNE 1996 California begins statewide CARB program.

1990

DECEMBER 1997 The Kyoto Protocol, an international agreement linked to the United Nations Framework Convention on Climate Change (UNFCCC or FCCC), aims to fight global warming. The treaty has the goal of stabilizing greenhouse gas concentrations to prevent climate change.

TOTAL BAN INITIATED IN THE US ON THE SALE OF NEW ENGINES THAT OPERATE ON LEADED GASOLINE

NOVEMBER 5, 1990

DECEMBER 1991

NOVEMBER 1992

The Pollution Prevention Act is passed in the US. This law specifies greater action to control pollutants at their source.

The US Office of Pollution Prevention is also founded.

The Soviet Union disintegrates into 15 separate countries, thus officially ending the Cold War.

Regulations set minimum oxygen content in winter gasoline for 39 US cities that exceeded the CO levels for national ambient air quality.

NOVEMBER 15, 1990 US President Bush signs the Clean Air Act Amendments of 1990, specifying more actions to improve air quality.

JANUARY 1, 1991 The first deliveries of LNG from Australia’s North West Shelf arrive in Japan and South Korea.

FEBRUARY 11, 1991 The US EPA grants a waiver to increase oxygenate blending in gasoline (up to 2 wt%).

AUGUST 1991

1992 The 1992 Energy Policy Act is passed in the US, which requires the purchase of cars, trucks and vans powered by electricity and other alternative fuels.

JANUARY 1992 Ethernet capabilities for process instrumentation and control become available.

MARCH 1992 Arabian Petroleum enters a joint venture with Fina for two Texas-based refineries, marking the first time a Saudi Arabian company will process and market crude outside of the Kingdom.

1993 Shell starts operations at the first gas-toliquids (GTL) facility in Bintulu, Maylaysia.

It is a joint venture with Shell, Mitsubishi, Petronas and Sarawak State, and it uses Shell technology.

OCTOBER 1993 New standard reduces sulfur concentration in diesel by 80% to 500 ppm.

During Reg-Neg, refiners and regulators negotiate principles for the RFG program.

Hydrocarbon Processing | JULY 2012 153

1998

NPRA CHANGES ITS NAME TO THE NATIONAL PETROCHEMICAL AND REFINERS ASSOCIATION MARCH 20, 1998

JANUARY 1999

SEPTEMBER 1999

EPA proposes Tier II emissions standards for vehicles and requires lower sulfur concentration in gasoline.

First LNG export facility in the Atlantic Basin opens in Trinidad and Tobago.

SUMMER 1998

Euro officially introduced to the financial markets of EU.

French refining company TotalFina merges with Elf to create the combined company Total FinaElf. It is now known as Total.

JANUARY 1, 1999

Downturn in Southeast Asia initiates global economic slowdown; oil prices soften.

APRIL 1, 1999 BP Amoco acquires ARCO for $26.8 billion.

DECEMBER 1998 NPRA becomes a Responsible Care Partner Association.

JULY 1999

BP and Amoco merge to create a supermajor oil company.

2000

US EPA begins investigation on groundwater contamination by MTBE from leaking underground storage tanks.

2000

NOVEMBER 2001

Lead is banned in gasoline sold in Europe.

Conoco and Phillips merge to create the third-largest US oil company, ConocoPhillips.

JANUARY 1, 2000 SEPTEMBER 11, 2001 TERRORISTS USE JET PLANES TO ATTACK WORLD TRADE CENTER AND OTHER US TARGETS

US RFG Phase II begins.

DECEMBER 11, 2001

FEBRUARY 2000

China becomes a member of the World Trade Organization.

US EPA publishes Tier II sulfur rule, which mandates the reduction of sulfur in gasoline to 30 ppm.

MID-2000 The EU bans leaded gasoline; the European Commission issues Auto Oil II, which sets a timetable for low-sulfur gasoline and ultra-low-sulfur diesel.

JUNE 2000 The US EPA proposes a rule to reduce sulfur concentration for onroad diesel to 15 ppm.

OCTOBER 16, 2000 Chevron Corp. purchases Texaco Inc. for $36 billion. The new company’s name is ChevronTexaco.

154 JULY 2012 | HydrocarbonProcessing.com

NOVEMBER 30, 1999 Exxon and Mobil merge to form a supermajor integrated refining and petrochemical company.

2002 BP and ExxonMobil phase out MTBE and switch to ethanol for reformulated gasoline blending.

MARCH 2002 Edinburgh becomes the world’s first city to offer both sulfur-free unleaded gasoline and sulfur-free diesel. Both transportation fuels are produced

by BP’s Grangemouth refinery in eastern Scotland.

2005 FEBRUARY 2005

KYOTO PROTOCOL OFFICIALLY TAKES EFFECT

MARCH 23, 2005

MAY 2006

At BP’s refinery in Texas City, Texas, failure of a safety relief valve on an isomerization unit releases hydrocarbons, causing a flammable vapor cloud explosion. Over 180 are injured, and 15 deaths are attributed to the blast.

MTBE is banned from use in reformulated fuels.

MAY 2005 ChevronTexaco shortens its company name to Chevron, with Texaco remaining a brand under Chevron Corp.

AUGUST 2005 Chevron acquires Unocal Corp. and enters the geothermal business.

JUNE 2007 The European Commission passes a regulation on chemicals and their usage, EC 1907/2006. It addresses the registration, evaluation, authorization and restriction of chemical substances (REACH).

JULY 2008 Crude oil prices exceed $150/bbl; financial practices of major banks cause nearcollapse of global financial systems.

2006

JANUARY 2009

The Responsible Care Global Charter is launched at the UN-led International Conference on Chemicals Management in Dubai.

Crude prices drop to under $20/bbl in response to diminished demand from the global recession.

MAY 2010

2010

EXPLOSION ON DEEPWATER HORIZON RIG IN THE GULF OF MEXICO CAUSES THE RELEASE OF MILLIONS OF BARRELS OF OIL AND A HALT TO DRILLING IN THE REGION FOR OVER A YEAR 2011

2012

Unrest in North Africa and the Middle East sets off political protests and disposes of dictators in Tunisia, Egypt and Libya.

Continued economic unrest weakens the economies of several European nations and sustains the recession in Europe. Greece is one of the most vulnerable nations and is the center of much controversy.

US shale gas development holds 25% of the natural gas supply. Hydraulic fracturing technology developed by George Mitchell drives shale gas developments.

Neste Oil starts up the largest renewable diesel refinery in Europe. The Rotterdam renewable diesel refinery will annually process 1 billion litres of clean biofuels.

MARCH 2011 Major earthquake and tsunami cripple the Fukushima Daiichi nuclear power plant in Japan. The event sets off bans and closures of nuclear power facilities in other nations, while demand for LNG increases overnight.

JANUARY 2012 NPRA changes its name to the American Fuels and Petrochemical Manufacturers (AFPM), further reflecting the business focus of member companies.

APRIL 2012 ConocoPhillips separates into two companies. Phillips 66 is the refining/downstream company and ConocoPhilllips remains the upstream company.

Hydrocarbon Processing | JULY 2012 155

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Select 206 at www.HydrocarbonProcessing.com/RS Hydrocarbon Processing | JULY 2012 157

BRAZIL—São Paulo

SALES OFFICES—EUROPE

Bill Wageneck, Sales Manager Phone: +1 (713) 529-4301 Fax: +1 (713) 520-4433 E-mail: Bill.Wageneck@GulfPub.com www.HydrocarbonProcessing.com

SALES OFFICES—NORTH AMERICA

FRANCE, GREECE, NORTH AFRICA, MIDDLE EAST, SPAIN, PORTUGAL, SOUTHERN BELGIUM, LUXEMBOURG, SWITZERLAND, GERMANY, AUSTRIA, TURKEY Catherine Watkins Tél.: +33 (0)1 30 47 92 51 Fax: +33 (0)1 30 47 92 40 E-mail: Watkins@GulfPub.com

ITALY, EASTERN EUROPE Fabio Potestá Mediapoint & Communications SRL Phone: +39 (010) 570-4948 Fax: +39 (010) 553-0088 E-mail: Fabio.Potesta@GulfPub.com

IL, LA, MO, OK, TX Josh Mayer Phone: +1 (972) 816-6745, Fax: +1 (972) 767-4442 E-mail: Josh.Mayer@GulfPub.com

AK, AL, AR, AZ, CA, CO, FL, GA, HI, IA, ID, IN, KS, KY, MI, MN, MS, MT, ND, NE, NM, NV, OR, SD, TN, TX, UT, WA, WI, WY, WESTERN CANADA Laura Kane Phone: +1 (713) 520-4449, Fax: +1 (713) 520-4459 Mobile: +1 (713) 412-2389 E-mail: Laura.Kane@GulfPub.com

RUSSIA/FSU Lilia Fedotova Anik International & Co. Ltd. Phone: +7 (495) 628-10-333 E-mail: Lilia.Fedotova@GulfPub.com

UNITED KINGDOM/SCANDINAVIA, NORTHERN BELGIUM, THE NETHERLANDS Michael Brown Phone: +44 161 440 0854 Mobile: +44 79866 34646 E-mail: Michael.Brown@GulfPub.com

CT, DC, DE, MA, MD, ME, NC, NH, NJ, NY, OH, PA, RI, SC, VA, VT, WV, EASTERN CANADA Merrie Lynch Phone: +1 (617) 357-8190, Fax: +1 (617) 357-8194 Mobile: +1 (617) 594-4943 E-mail: Merrie.Lynch@GulfPub.com

SALES OFFICES—OTHER AREAS AUSTRALIA—Perth Brian Arnold Phone: +61 (8) 9332-9839 Fax: +61 (8) 9313-6442 E-mail: Australia@GulfPub.com

CLASSIFIED SALES Gerry Mayer Phone: +1 (972) 816-3534, Fax: +1 (972) 767-4442 E-mail: Gerry.Mayer@GulfPub.com

CHINA—Hong Kong

DATA PRODUCTS Lee Nichols Phone: +1 (713) 525-4626, Fax: +1 (713) 520-4433 E-mail: Lee.Nichols@GulfPub.com

Iris Yuen Phone: +86 13802701367, (China) Phone: +852 69185500, (Hong Kong) E-mail: Iris.Yuen@GulfPub.com

Alfred Bilyk Phone/Fax: 11 23 37 42 40 Mobile: 11 85 86 52 59 E-mail: Brazil@GulfPub.com

INDIA Manav Kanwar Phone: +91-22-2837 7070/71/72 Fax: +91-22-2822 2803 Mobile: +91-98673 67374 E-mail: India@GulfPub.com

INDONESIA, MALAYSIA, SINGAPORE, THAILAND Peggy Thay Publicitas Singapore Pte Ltd Phone: +65 6836-2272 Fax: +65 6634-5231 E-mail: Singapore@GulfPub.com

JAPAN—Tokyo Yoshinori Ikeda Pacific Business Inc. Phone: +81 (3) 3661-6138 Fax: +81 (3) 3661-6139 E-mail: Japan@GulfPub.com

KOREA D. S. Chai Dongmyung Communications, Inc. Phone: +82 (2) 391 4254 Fax: +82 (2) 391 4255 E-mail: Korea@GulfPub.com

PAKISTAN—Karachi S. E. Ahmed Intermedia Communications Phone: +92 (21) 663-4795 Fax: +92 (21) 663-4795

REPRINTS Rhona Brown, Foster Printing Service Phone: +1 (866) 879-9144 ext. 194 E-mail: RhondaB@FosterPrinting.com

LIVE WEBCAST presents . . .

Tuesday, July 10, 2012 | 11am ET, 10am CT

Suction-specific speed: The hidden costs of pumping’s least understood measure Speakers: John Bailey, Oil & Gas Global Product Marketing Manager for ITT Goulds Pumps Simon Bradshaw, Director of API Product Development & Technology for ITT Goulds Pumps Moderator: Stephany Romanow, Editor, Hydrocarbon Processing When purchasing API pumps, everyone knows that suction-specific speed (“Nss” or “S”), is one of the most critical specifications to consider.

Think again, say the experts on pump design and hydraulics at ITT Goulds Pumps. Twenty-five years ago, suction-specific speed was considered a singularly critical specification for predicting pump reliability. Today, modern pump designs and construction materials make this an outdated measure. Yet most purchasers continue to rely on the same old spec—which has become a drain on capital budgets, frequently driving purchasers to get the wrong design or more pump than they need.

In this webcast, leaders from ITT Goulds Pumps will explain suctionspecific speed and its proper role in modern oil-and-gas pump assessment.

158 JULY 2012 | HydrocarbonProcessing.com

Attendees will learn: • History of suction-specific speed and the science behind the spec • Using suction-specific speed to evaluate a pump’s design before purchase • How computational fluid dynamics (CFD) has rewritten the role of suction-specific speed—and the questions you should ask your pump vendor about CFD simulations • How suction-specific speed can be used with other specs and features to make smarter pump purchases This webcast will demystify one of the commonly mentioned yet least understood terms in oil and gas pumping. It will benefit anyone involved in system design and pump selection—including engineers, managers and purchasers at refineries and engineering contractors.

The live webcast takes place July 10, 2012 at 11am ET, 10am CT. An interactive question-and-answer session will follow the presentation. The event will be available to view on demand after July 11, 2012.

Register at HydrocarbonProcessing.com

The companies below offer a wide variety of services and equipment to the US Gulf Coast refining, petrochemical and gas processing markets. You will find their complete listings in the 2012 Gulf Coast Turnaround & Maintenance Services Directory, published by Hydrocarbon Processing.

2012

You can contact these companies by going to www.HydrocarbonProcessing. com/RS, following the instructions on the screen and using the Reader Service numbers below. You can also access the full directory at www.HydrocarbonProcessing.com on the left-hand navigation bar.

24 Hr Safety

CURTISS WRIGHT Flow Control Company,

OnQuest, Inc.

Reader Service 304

Farris Engineering

Reader Service 302

Reader Service 316 Safway Services, Inc.

Access Plug Flange, Inc. Reader Service 305

Diamond Refractory Services

Reader Service 324

Reader Service 312 Sentinel

Altair Strickland Reader Service 306

Reader Service 325 Ecodyne Heat Exchangers Reader Service 313 Summit Industrial

Aquilex SRO

Reader Service 326 Reader Service 307

FabEnCo, Inc. Reader Service 315 T.F. Hudgins, Inc.

Babbit Steam Specialty Co. Reader Service 308

Reader Service 327 Flare Ignitors Pipeline & Refinery, LLC Reader Service 317

Brand Energy & Infrastructure Services

Team Industrial Services, Inc. Reader Service 328

Reader Service 301 G.S.D. Global Scrap & Dismantling Reader Service 318 Central Maintenance and Welding Inc.

Tiger Tower Services Reader Service 329

Reader Service 309 Gulftronic Reader Service 319 Certified Safety

TPS, LLC Reader Service 330

Reader Service 310 Hason-Steel Products, Inc. Reader Service 303

Turnaround Welding Services Reader Service 331

CURTISS WRIGHT Flow Control CompanyI Reader Service 323 Hunter Buildings

Unifrax Reader Service 320 CURTISS WRIGHT Flow Control Company,

Reader Service 332

DeltaValve Reader Service 311

Industrial Insulation Group

USA Industries

Reader Service 321

Reader Service 333

EST Group

Mach Industrial Group

Voith Turbo GmbH & Co Kg

Reader Service 314

Reader Service 322

Reader Service 334

CURTISS WRIGHT Flow Control Company,

www.HydrocarbonProcessing.com/RS

ADVERTISER INDEX / HydrocarbonProcessing.com The first number after the company name is the page on which an advertisement appears. The second number, appearing in parentheses, after the company name, is the Reader Service Number. There are two ways readers can obtain product and service information: 1. Go to www.HydrocarbonProcessing.com/RS. Follow the instructions on the screen, and your request will be forwarded for immediate action.

2. Go online to the advertiser's Website listed below.

Company

Page

RS#

Website

ABB Inc......................................... 120–121

(69) (76)

www.info.hotims.com/41430-76

ASCO Valve Inc. ................................... 102

(64) (53) (101)

BASF Ag.............................................. 163 (100) (77) (163) (94)

www.info.hotims.com/41430-94

(153)

www.info.hotims.com/41430-153

Bryan Research & Engineering ..............110

(71)

www.info.hotims.com/41430-71

Cameron ............................................106

(55)

www.info.hotims.com/41430-55

Carver Pump Company ........................ 142

(165)

www.info.hotims.com/41430-165

Cashco Vci.............................................24

(155)

www.info.hotims.com/41430-155

CB&I .............................................124–124

(54)

www.info.hotims.com/41430-54

Chevron Lummus Global ................. 92, 143

(91)

www.info.hotims.com/41430-91

Colfax Americas ....................................34

(86)

www.info.hotims.com/41430-86

Compressor Controls .............................. 4

(65)

(103)

(159)

(157) (61)

(58)

MSA .....................................................63 Paharpur Cooling Towers, Ltd. ................33 Prosernat .............................................26

(84) (79) (102) (156) (52)

www.info.hotims.com/41430-52

Saint-Gobain NorPro ...................... 18, 145

(57)

www.info.hotims.com/41430-57

Scott Safety ..........................................59

(73)

www.info.hotims.com/41430-73

Siemens Ag ..........................................29

(62)

www.info.hotims.com/41430-62

Sulzer Chemtech, USA Inc.......................57

(74)

www.info.hotims.com/41430-74

T.D. Williamson ............................. 132–133

(80)

www.info.hotims.com/41430-80

Team Industrial Services ........................27

(95)

www.info.hotims.com/41430-95

Total ................................................... 20 (56) (152)

(161)

(70)

www.info.hotims.com/41430-70

Trachte USA ..........................................52 (63)

(154)

www.info.hotims.com/41430-154

Total Safety ......................................... 70

(160)

www.info.hotims.com/41430-160

UOP LLC ..............................................6–7 URS Corp ............................................. 30

(158)

www.info.hotims.com/41430-158

(99)

www.info.hotims.com/41430-99

www.info.hotims.com/41430-59

Merichem Company...............................82

Rentech Boiler System ............................ 2 (164)

www.info.hotims.com/41430-161

KBR..................................................... 98

(162)

www.info.hotims.com/41430-156

URS Washington Division.....................104

(81)

www.info.hotims.com/41430-81

(88)

Wood Group Mustang ....................134–135

(98)

www.info.hotims.com/41430-98

(60)

Yokogawa .....................................54, 139

(67)

www.info.hotims.com/41430-67

(82)

www.info.hotims.com/41430-82

www.info.hotims.com/41430-58

Maxon Corporation............................... 84

www.info.hotims.com/41430-102

www.info.hotims.com/41430-63

KBC Advanced Technologies Inc..............75

(85)

www.info.hotims.com/41430-79

www.info.hotims.com/41430-152

Johnson Screens (Australia) Pty Ltd. ....... 31

(78)

www.info.hotims.com/41430-78

www.info.hotims.com/41430-84

www.info.hotims.com/41430-60

www.info.hotims.com/41430-159

Elliott Group ..................................69, 144

(93)

www.info.hotims.com/41430-88

(89)

(83)

www.info.hotims.com/41430-83

www.info.hotims.com/41430-162

www.info.hotims.com/41430-56

ITT Industries ................................. 81, 146

www.info.hotims.com/41430-89

Dixon Valve ..........................................45

Gulf Publishing Company Circulation ....................................... 66B Construction Boxscore..........................32 Events - MITO ....................................100 Events - WGLC ....................................141 GPC Books......................................... 147 Gulf Coast Turnaround Showcase ........ 159 HP Webcast.................................. 97, 158 HPI Market Data Book ..........................62 HPI Marketplace ..........................156–157 Hydrocarbon Processing ......................36 Haldor Topsøe A/S................................ 64

Imperial Crane ..............................126–127 (66)

www.info.hotims.com/41430-66

Curtiss Wright Flow Control Company........................ 130–131

(97)

www.info.hotims.com/41430-164

HYTORC ................................................77

www.info.hotims.com/41430-65

Curtiss Wright Flow Control Company .... 86

Grabner Instruments Messtechnik GmbH ............................141

Heurtey Petrochem .............................. 46 (68)

www.info.hotims.com/41430-68

CRI Catalyst ..................................... 10–11

Fugro ................................................... 21

HTRI .....................................................14 (151)

www.info.hotims.com/41430-151

Costacurta SpA Vico ............................ 66A

FourQuest Energy..................................28

Kobe Steel Ltd......................................101

www.info.hotims.com/41430-85

www.info.hotims.com/41430-61

www.info.hotims.com/41430-163

Borsig GmbH ........................................ 15

Foster Wheeler .................................... 46

RS#

Linde Process Plants ........................... 66A

www.info.hotims.com/41430-157

www.info.hotims.com/41430-77

Bonney Forge .......................................91

www.info.hotims.com/41430-72

Flexitallic LP .......................................... 5

Page

Linde Ag .......................................128–129 (72)

www.info.hotims.com/41430-103

www.info.hotims.com/41430-100

BIC Alliance...........................................85

(75)

www.info.hotims.com/41430-75

ExxonMobil Research & Engineering .............................. 108–109

Company Website

www.info.hotims.com/41430-93

www.info.hotims.com/41430-101

BASF Corporation ........................... 22, 138

RS#

www.info.hotims.com/41430-97

www.info.hotims.com/41430-53

Baker Hughes ...............................25, 140

Emerson Process Management (Fisher Controls) ................................ 12 ENI SpA ................................................41

www.info.hotims.com/41430-64

Axens .................................... 122–123, 164

Page

Website

www.info.hotims.com/41430-69

AFPM ................................................. 162

Company

Zeeco ...........................................136–137

(87)

www.info.hotims.com/41430-87

(59)

Zyme-Flow Decon Technology ...............73

(92)

www.info.hotims.com/41430-92

This Index and procedure for securing additional information is provided as a service to Hydrocarbon Processing advertisers and a convenience to our readers. Gulf Publishing Company is not responsible for omissions or errors.

160 JULY 2012 | HydrocarbonProcessing.com

PROVIDING SOLUTIONS

THE 2012 AFPM (NPRA) Q&A AND TECHNOLOGY FORUM Grand America Hotel Salt Lake City, UT October 1-3, 2012

afpm.org

AFPM’s Q&A and Technology Forum is the industry’s most comprehensive meeting on refinery operations and process technology. This event assembles representatives from throughout the industry – including refiners, petrochemical producers, catalyst and chemicals suppliers, plant automation specialists and engineering firms – and gives them the opportunity to address real problems refiners face today.

Attendees will gain from the chance to discuss their challenges and find solutions from the expert Q&A panelists and other attendees.

Today’s competitive refining environment requires attention to plant safety, superior technology, innovation and excellence in operations. Benefit from the shared knowledge of experts throughout the industry – the Q&A and Technology Forum will keep you moving in the right direction as you optimize your plant’s operation.

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Water Management

LORAINE A. HUCHLER, CONTRIBUTING EDITOR Huchler@martechsystems.com

Avoid failures in water projects: Part 2 Last month, we discussed the need for project engineers to talk to process engineers about the water systems as a capital project takes shape. This month’s column discusses additional ways to bridge the communication gap between these two groups.

Assess suitability for service. Some industrial plants, such

as refineries, have stringent engineering guidelines and sourcing for components and materials of construction. In the absence of clear guidance from the customer, the engineering design firm will follow its own internal design guidelines. A major constraint is a cost-competitive procurement process for equipment that selects lower cost materials, lower quality components and, sometimes, violates good design guidelines.

Consider the plant owner who agreed with the engineering firm’s recommendation to select a demineralizer system design sized for 150% of the maximum service flowrate because it reduced the capital cost in the competitive bid. The industry standard is 200% of the maximum service flowrate. After several years of operation, the plant replaced one unit with a larger-sized unit, resulting in a miss-matched set of demineralizer trains that have a common regeneration system program— making it is impossible to optimize the regeneration sequence.

Assess operability and maintainability issues. Process engineers are experts on this subject and are responsible for solving the daily issues of operating and maintaining plant equipment.

Some design issues involve proper specification of online monitoring equipment and water storage tanks with sufficiently large working volumes to accommodate the dynamic treated-water demand profile. Project engineers should consult process engineers regarding location of sample points, chemical feed points and online analyzers. Process engineers know the application guidelines and the reliability and maintainability of these instruments.

Other problems are design issues. For example, the absence of a variable-speed drive on the recirculation pump on a reverse osmosis (RO) cleaning skid, compromises cleaning procedure for a multi-stage RO unit.

than the conventional multi-media filtration systems. But this incremental cost for new technology is a very small percentage of the total capital cost of the project. Conversely, specifying this technology in retrofit projects to replace conventional filtration is impossible because the hurdle for return-on-investment is too high.

Other site-specific limitations. The most common site-

specific limitations are environmental and plot-plan issues.

These operating issues may be forgotten or dismissed as unimportant. For example, a Canadian plant considered replacing its aging demineralizers with RO units until experiencing a rare shutdown of the entire plant on a cold winter’s day. I asked the question, “Are we going to size the RO unit to operate on a “cold start” or are we going to install a supplemental bootstrap boiler to supply steam to heat the water and resize the RO for 25°C?” The simpler, cheaper and more reliable option is demineralizers that are not so sensitive to water temperatures.

Identify the negotiable cost components. There is al-

ways a risk of cuts in project budgets. Discussion of the negotiable issues by process engineers during the project design is an excellent idea. A good example is the installation of a cleaning skid for RO units that uses flexible transfer hoses instead of permanently installed connections and, even worse, lacks quick-disconnect flanges. This configuration makes the cleaning process an onerous and time-consuming task. Consequently, the operators are unlikely to clean the RO at the right frequency—not a good choice to cut costs.

Open discussion. Project engineers must manage a huge

number of technical issues for capital projects. Process engineers can add significant value to the design process by providing insights to operability and maintainability of various process designs and water treatment technologies. To have a successful plant project, both sets of engineers must talk to each other.

End of series. Part 1, June 2012.

New technology. There is a tension when choosing new

technologies. Process engineers “vote no” because they are unfamiliar with the operability and reliability of the new technologies and the cost is higher than conventional technologies.

Conversely, project engineers will “vote yes” because the higher capital cost is amortized over the service life of the plant. The right way to evaluate new technology is suitability for service. For example, membrane filtration is a perfect pretreatment strategy to ensure reliable operation of RO units and packed-bed demineralizers. However, the capital cost is several time higher 162 JULY 2012 | HydrocarbonProcessing.com

LORAINE A. HUCHLER is president of MarTech Systems, Inc., a consulting firm that provides technical advisory services to manage risk and optimize energy- and water-related systems including steam, cooling and wastewater in refineries and petrochemical plants. She holds a BS degree in chemical engineering, along with professional engineering licenses in New Jersey and Maryland, and is a certified management consultant.

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