H P 2011 01.pdf

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www.HydrocarbonProcessing.com JANUARY 2011

HPIMPACT

SPECIALREPORT

2011FORECAST

GAS PROCESSING

DEVELOPMENTS

Improved technologies

treat sour gas

Refinery construction

costs on the rise

Shale gas could affect

Middle East LNG

HPI MARKETDATA 2011

Summary reviews

spending and trends

shaping the global HPI

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XX Dewitt petrochemical-conference out look XX Six strategic business

technologies to watch XX Australia making

crucial GTL decisions XX IEA assesses energy

poli-cies of U.S.

XX Creating more value in capital projects

HPIMPACT

Cutline for fig.

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cutline for fig

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cutline for fig

00 www.HydrocarbonProcessing.com

JANUARY 2011 • VOL. 90 NO. 1

SPECIAL REPORT: GAS PROCESSING DEVELOPMENTS

37

Consider different alternatives for enriching lean acid gases

New developments improve operation of Claus sulfur recovery units

B. ZareNezhad

41

Avoid condensation-induced transient pressure waves Case studies give an indication as to probable causes for water hammer

G. Mani

45

When is CO₂ more hazardous than H₂S

Data shows potential harmful effects to workers due to acid gas exposure

K. Tyndall, K. McIntush, J. Lundeen, K. Fisher and C. Beitler

49

Use online analyzers for successful monitoring

Improved analytics measure moisture and dew points for natural gas components

A. Benton and C. Valiz

55

Advanced chemical process for treating sour gas Technology avoids huge capital investments while speeding up results

C. A. Ortega Peralta and M. J. Ortega Casteln

Cover The PERU LNG production complex in Pampa Melchorita, Peru, was officially inaugurated in June 2010. With a nominal capacity of 4.4 million tons of LNG per annum, it is South America’s first baseload liquefaction plant and represents one of the largest industrial projects ever undertaken in Peru. Photo courtesy of CB&I.

HPIMPACT

17 Refinery and

petro-chemical construction costs continue measured rise 17 Moving beyond the

meltdown in the Gulf 20 Global energy

outlook to 2035

COLUMNS

9 HPIN RELIABILITY

Packing not best practice for firewater pumps

11 HPIN EUROPE

European consumers mull their options as oil companies quit the market 13 HPINTEGRATION STRATEGIES MPC vs. ARC—Not an ‘either/or’ decision 90 HPIN CONTROL Process control practice renewal— select CVs PLANT SAFETY

57

Safe detection of small to large gas releases Look at these advantages in using ultrasonic leak detectors

E. Naranjo, S. Baliga, G. A. Neethling and C. D. Plummer

63

Considerations for blast-resistant

electrical equipment centers

Guidelines explore protecting critical systems from disaster

D. Cole and D. Austin

ENVIRONMENT

69

What are the strategies for sustainable chemical production? New environmental challenges require a new way of thinking

by the hydrocarbon processing industry

M. P. Sukumaran Nair

ROTATING EQUIPMENT

79

Going ‘green’ with FCC expander technology New options recover waste gas energy as steam and electricity for plant use

B. Carbonetto and P. Pecchi

ENGINEERING CASE HISTORIES

85

Case 60: Socket-weld failures

A risk analysis can determine which critical welds to repair

T. Sofronas

DEPARTMENTS

7 HPIN BRIEF • 27 HPINNOVATIONS • 31 HPIN CONSTRUCTION 35 HPI CONSTRUCTION BOXSCORE UPDATE

86 HPI MARKETPLACE • 89 ADVERTISER INDEX

HPI 2011

FORECAST

21 HPI Market Data 2011

Executive Summary: This summary reviews spending for the global HPI. Will 2011 be a better year for the refining, petrochemical and natural gas industries? What lies ahead for the energy industry?

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4 EDITORIAL

Executive Editor Stephany Romanow Process Editor Tricia Crossey

Reliability/Equipment Editor Heinz P. Bloch News Editor Billy Thinnes

Associate Editor Helen Meche

European Editor Tim Lloyd Wright Contributing Editor Loraine A. Huchler Contributing Editor William M. Goble Contributing Editor Y. Zak Friedman Contributing Editor ARC Advisory Group (various)

MAGAZINE PRODUCTION

Director—Editorial Production Sheryl Stone Manager— Editorial Production Angela Bathe Artist/Illustrator David Weeks

Manager—Advertising Production Cheryl Willis

ADVERTISING SALES See Sales Offices page 88.

CIRCULATION +1 (713) 520-4440 Director—Circulation Suzanne McGehee E-mail: [email protected]

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Because Hydrocarbon Processing is edited spe-cifically to be of greatest value to people work-ing in this specialized business, subscriptions are restricted to those engaged in the hydro-carbon processing industry, or service and sup-ply company personnel connected thereto. Hydrocarbon Processing is indexed by Applied Science & Tech nology Index, by Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon Processing is also available in electronic versions of the Business Periodicals Index.

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HYDROCARBON PROCESSING (ISSN 0018-8190) is published monthly by Gulf Publishing Co., 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals postage paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252.

Copyright © 2011 by Gulf Publishing Co. All rights reserved. Permission is granted by the copyright owner to libraries and others regis-tered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohib-ited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01.

www.HydrocarbonProcessing.com

GULF PUBLISHING COMPANY John Royall, President/CEO Ron Higgins, Vice President Pamela Harvey, Business Finance Manager

Part of Euromoney Institutional Investor PLC. Other energy group titles include:

World Oil® Petroleum Economist

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E-mail: [email protected] www.HydrocarbonProcessing.com

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www.HydrocarbonProcessing.com

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The outlook for the US chemicals manufacturing sector is improving gradually and global production is set to increase in the coming year, thanks in part to dramatic growth in export markets for the products of chemis-try, according to a report from the American Chemistry Council (ACC).

For 2010, US chemistry exports will be up by 17%, shifting the trade balance for the industry from a $0.1 billion deficit to a $3.7 billion surplus, its best performance in 10 years. The growth in export markets also has partially offset soft domestic demand for chemical products.

Domestically, chemical production volumes have increased across all regions of the US in 2010 following steep declines in 2008 and 2009. The largest gains have occurred in the Gulf Coast and Ohio Valley regions, boosted by export demand for basic chemicals and plastics. Output is expected to grow moderately in all regions in 2011 and continue to improve through 2012.

Growth in export markets is driven by several factors, including favorable energy costs, resulting from develop-ments in extracting natural gas from shale; and growth in emerging mar-kets, where recovery, and now expan-sion, has been strongest.

US natural gas markets have seen a dynamic shift over the past five years as a result of increased capacity to extract natural gas from organic shale deposits. Reserves have risen by one-third, resulting in lower prices and greater availability of ethane, a feedstock material derived from natu-ral gas that is the basis for hundreds of manufactured products. This low price for natural gas compared to oil has enabled US chemicals manufac-turers to become more competitive than producers in much of the rest of the world.

Growth in emerging markets, most notably in China, India and Brazil, is increasing demand for chemistry feed-stock materials. Production of chemis-try products in emerging economies increased by 12.2% in 2010, and fur-ther gains are expected. HP

[email protected]

BILLY THINNES, NEWS EDITOR

HPIN BRIEF

Sunoco, Inc., will sell its 170,000-bpd refinery in Toledo, Ohio,

to Toledo Refining Co., a subsidiary of PBF Holding Co., for approximately $400 million (consisting of $200 million in cash and a $200 million two-year note). In addition, the purchase agreement includes a participation payment of up to $125 million based on the future profitability of the refinery. The buyer will also purchase the crude oil and refined product inventory attributable to the refinery, which will be valued at market prices at closing. The transaction is expected to be completed early in the first quarter of 2011.

The Alliance for Climate Protection and the Center for American

Progress released a joint report that calls on the US to take the lead on international climate finance—even under the current difficult political and economic condi-tions. The report says that it is in the US’ best interest to help developing nations reduce greenhouse-gas emissions and build clean-energy economies. It calls on the US to lead a global partnership to mobilize new investments in developing countries between now and 2015, and urges the country to explore new ways to help develop-ing countries pursue clean-energy growth. The report suggests the US can finance investments through public budget resources, carbon markets, development bank lending and private financing.

ABB will acquire Baldor Electric in an all-cash transaction valued

at approximately $4.2 billion, including $1.1 billion of net debt. The transaction closes a gap in ABB’s automation portfolio in North America by adding Baldor’s NEMA motors product line. Baldor also adds a mechanical power transmission business to ABB’s portfolio. The US market for high-efficiency motors is expected to grow 10% to 15% in 2011 on the back of new regulations, effective in December this year. Similar regulations in Canada, Mexico and in the European Union are expected in 2011.

The chairman of the US Chemical Safety Board (CSB) applauded

the National Fire Protection Association (NFPA) for its recent decision to establish a new technical committee to develop a comprehensive standard for gas processing safety, including the cleaning of fuel gas piping systems. The NFPA acted in response to an urgent recommendation issued by the CSB following a catastrophic natural gas explo-sion at Kleen Energy, a power plant under construction in Middletown, Connecticut, on February 7, 2010. In that incident, workers were conducting a “gas blow,” a procedure that forced natural gas at high volume and pressure through newly installed piping to remove debris. The gas was vented to the atmosphere, where it accumulated and explod-ed, killing six contract workers and injuring many others.

Early December marked a major milestone for the US’ transition

to ultra-low-sulfur diesel (ULSD) fuel, as all highway diesel fuel in the US now complies with the 15-ppm sulfur standard. This represents a 97% reduction in sulfur content from diesel’s 2006 levels. The December 1, 2010, deadline was mandated by the US Environmental Protection Agency (EPA). However, according to the EPA’s pump survey, the highway transition to ULSD was actually completed a few weeks ahead of schedule.

BASF and PETRONAS are studying the possibility of producing

specialty chemicals in Malaysia, a move that would extend the two parties’ existing business collaboration in the country. The partners are considering a potential joint investment sum of approximately €1 billion, along with operating facilities for the production of specialty chemicals including non-ionic surfactants, methanesulfonic acid, iso-nonanol as well as other C4-based specialty chemical products. A decision is expected in 2011. HP

■

Improved outlook

for US chemicals

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HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR

HPI

N RELIABILITY

I

Statistics show that for every 1,000 pump failures in hydrocar-bon processing plants, there will be a fire. Fig. 1 shows a typical visible outcome, and the final bill for remedying such disastrous results can amount to hundreds of millions of dollars.

Since roughly 60% of pump fires involve mechanical seal failures, it has been assumed that the majority of mechanical seals are somehow flawed. However, this conclusion is quite incorrect. Many pumps have been in service for years without seal fail-ures. The entire experience points to the need to carefully select the right mechanical seal designs and to follow up by adhering to

appropriate work processes and installation procedures.

Braided packing or mechanical seals? There is still the occasional assumption that critically important pumps will benefit from braided packing. Firewater pumps are mentioned in this context since they are expected to be available at all times and because, with water, a small amount of leakage is deemed tolerable. It might surprise some readers that, even here, packing is not the first choice of experienced professionals. Best practice in modern firewater pumps has been (since about 1968) to use single-spring mechanical seals. As was mentioned in the July 2010

HPIn Reliability column, these mechanical seals are to be backed

up by a floating throttle bushing and a deflector guard.

Reliability professionals interested in “designing out” mainte-nance always check into the feasibility of systematically upgrading their equipment. In fact, the very best HP companies mandate viewing every maintenance event as an opportunity to upgrade. For process pumps, one of the many cost-effective upgrade mea-sures involves replacing the plain deflector guards that had been introduced in the 1950s. It is of more than historical interest to review what led to the recommendation and to use single-spring mechanical seals instead of packing.

In the 1960s, accurate statistics were kept (for insurance pur-poses) by a major multinational oil company. The statistics for firewater pumps showed that leaking packing tended to ruin bear-ings. Well-designed mechanical seals were then selected because they generally leak much less than packing and are considerably less likely to allow water spray to enter the adjacent bearing hous-ing. Of course, we know that brittle mechanical seal faces might shatter when abused. However, seals that are properly designed, selected and installed are highly unlikely to shatter. Moreover, floating throttle bushings represent a “second line of defense” in firewater pumps.

Testing your firewater pumps. Proper operating and maintenance best practices require periodic testing of all standby equipment. Periodic testing is mandatory, and testing once every two weeks is not unreasonable. Each firewater pump would then be allowed to run for about an hour. Different rules may pertain to process pumps in other services.

For process pumps, the question is often asked differently. Some facilities believe that switching the “A” and “B” pumps and running each for a given time (months) is best. Another group believes that simply turning on the standby pump once a month and then running it for 4–6 hours is a better alternative. Which of the two is preferred?

When people argued—many decades ago—that plants might get away with testing pumps as infrequently as twice a year, responsible reliability professionals took the position that testing only twice a year would not be acceptable and monthly testing was needed. Depending on lubricant selection and lube application method, switching “A” and “B” every two months is considered best practice. This then keeps the bearings lubricated, prevents the rolling elements from sitting in exactly the same position and prevents seal faces from sticking.

Back to the issue of firewater pump sealing practices. Knowl-edgeable engineers do not advocate using packing in modern firewater pumps. The reasons are technical and were described above, but the reasons are also workforce and experience-related. Consider the difficulty of grooming and retaining top-notch maintenance personnel in some plants. Taken together, decades of experience and an examination of present-day workforce avail-abilities support the contention that packing no longer represents best practice at the most advanced companies. HP

Packing not best practice for firewater pumps

The author is Hydrocarbon Processing’s Reliability/Equipment Editor. The author of 18 textbooks and over 490 papers or articles, he advises process plants worldwide on reliability improvement and maintenance cost reduction opportuni-ties. For more details, see his “Practical Lubrication for Industrial Facilities,” ISBN 0-88173-579-5.

Scene of a refinery pump fire (Source: Release No. 2004-08-I-NM; US Chemical Safety Board; http://www.csb.gov). FIG. 1

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TIM LLOYD WRIGHT, EUROPEAN EDITOR

HPI

N EUROPE

Although I’ve watched it coming, it still feels like a historic moment to see the oil industry pack up its things and leave. If you sell catalysts, pumps, inspection services, display ads or anti-static additives, then that low rumble is the ground moving—your market is changing under your feet.

New supplier on the horizon. People who buy fuel are waking up to a different logo on the tank truck and another voice on the telephone. Some are realizing too late that they’ll be los-ing a supplier with a certain standlos-ing, a reputation to preen and a level of expertise that they’ve come to count on. And if you’re not supplying, but manning a refinery or a marketing operation in Europe, then it isn’t just you. It’s happening all over. You’re not the only one seeing a new set of suits wandering through your workplace measuring you up.

“We’ve had a room in the center of the main floor set up as a data room all summer,” one oil major executive told me on a recent visit. “People have had their teams coming in and running our numbers for months. The whole business is up for sale.”

The international oil companies are bidding their farewells, and a new breed of nontraditional suppliers is doing its due dili-gence. For example, in the UK, half of the retail stations could change hands in the next few years, the Financial Times reckoned

recently. France’s Total is selling its 780 stations in the country; Murphy Oil is selling its 480 stations. The Chevron Texaco busi-ness in the UK and Ireland is up for sale. It operates 1,300 stations under the Texaco brand. Exxon Mobil wants to supply, but no longer own and operate its Scottish forecourts. The sale or closure of numerous European refineries by Shell, Total, Chevron Texaco, ConocoPhillips and Petroplus is no longer a consultant’s projec-tion, but an emerging reality.

‘New’ oil company. At a recent meeting of fuel buyers in the global aviation industry, one of the companies investing now to assume major oil market share was exuding confidence.

Ian Taylor is CEO of Vitol, one of the world’s largest trading groups, a company that has come to be known to the airlines as one of the new “nontraditional” suppliers. He effectively thanked BP and Shell for their service and told the audience his company would take over from here. He went on to restate Vitol’s ongoing plans to take over Shell Aviation businesses all over Africa. Days later, Trafigura, another very substantial trading group, announced it would take over from BP in a number of southern African states. Chevron Corp. has sold its Caribbean and Central American fuels and aviation busi-nesses recently to Rubis, a French midstream group.

And it’s not just around the equator and in the southern hemi-sphere that the nontraditional suppliers are moving in. Morgan Stanley, the bank, is aggressively pursuing aviation custom in European markets, having traded fuels for many years. One of

its executives shared a stage at the aviation conference with the managing director of the newly launched Vitol Aviation.

In the UK, Greenergy, the company I’ve followed since it was a half-dozen desks gathered around an oversized “Scalextric” toy car track, is bidding to buy up hundreds of service stations. It has already built one of the UK’s largest private businesses out of taking over clean fuels niches and later marketing functions, from major companies. Today, it delivers some 140 million liters (37 million US gallons) of fuel a week, but, like Vitol and Trafigura, it all started with oil trading.

The oil companies aren’t getting out of supply roles across the board. Shell is at pains to point out that it intends to grow in some aviation markets as it leaves others. But the trend is unmistakable. “Look at an average major,” a bank researcher friend told me. “They may have 100,000 people, of which 70,000 work down-stream. Yet 80% of their profits are coming from the updown-stream. They’re running the numbers and concluding, ‘why bother?’

John Digby, an independent consultant and former boss at Chevron Texaco, says that in the first half of 2010, upstream income accounted for some $48.6 billion at six leading major oil companies, while downstream income accounted for just $9.6 billion—a ratio of five to one. But it’s more than nostalgia that has some oil market end users flustered at the changes.

The chair of an International Air Transport Association techni-cal meeting wanted to know recently where were the expert rep-resentatives from the new suppliers in his working groups as they try to understand the salt contamination issue that recently led to a near disaster aboard a Cathay Pacific flight leaving Indonesia.

“We’ll buy in expertise from the majors,” one of the trading groups told me. “We can’t afford to have any quality issues at all,” he added. That’s no doubt true, but one has to wonder what will be left of the quality assurance and long-term research and development function in the fuels supply industry. Admittedly, the oil companies themselves shrank technical and research facilities like Thornton and Sunbury very significantly during the 1990s, but will their research and technical facilities in the region now fade to nothing?

And there’s another thing. As the international oil companies head off to spend the remaining decades of the oil age in more rewarding upstream pastures, the oil products markets are being handed to trad-ers and banks. Granted, there’ll be new competition among the new suppliers with a nose for sourcing cost-effective streams of product. But end users may well be wary of what they see as a change from dealing with expert producers, to expert “middle-men.” HP

The author is HP’s European Editor and also a specialist in European distillate markets. He has been active as a reporter and conference chair in the European downstream industry since 1997, before which he was a feature writer and reporter for the UK broadsheet press and BBC radio. Mr. Wright lives in Sweden and is the founder of a local climate and sustainability initiative.

European consumers mull their options as

oil companies quit the market

(13)

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DICK HILL, CONTRIBUTING EDITOR

HPI

NTEGRATION STRATEGIES

I

Overview. In the 35 years since they introduced distributed

control systems (DCSs), automation system suppliers have pro-vided the hydrocarbon processing industry (HPI) and other customers with far more than the ubiquitous piping and instru-mentation diagram (PID) control-function block in their suite of available function blocks. Many of the additional DCS function blocks originated back in the days before multivariable or model-predictive control (MPC) was commercially available. We now refer to putting together functions such as lead-lag, dead time or selectors to formulate advanced control as advanced regula-tory control (ARC). ARC and MPC are both types of advanced process control (APC).

While DCSs provide advanced control capabilities in the many useful function blocks available, some end users in the HPI and other heavy process plants moved away from function blocks in favor of developing MPC models for APC.

Getting the foundation right. Before MPC, if the pro-cess required advanced-control techniques, the propro-cess control practitioners had to assemble the correct control functions to achieve the required results. These evolved into what we now call ARC. Modern process control assumes that the regulatory control provided by the process control system is solid, with well-tuned loops and controllers operating in the correct mode. Without good basic regulatory control, APC will not perform well. But what about ARC? Now that MPC is so widely accepted and used, are control engineers and other practitioners still taking advantage of the ARC capabilities built into most DCSs?

MPC isn’t the only tool in the toolbox. An entire culture has evolved around the use of MPC. MPC has earned widespread respect and acceptance due to its often-spectacular payback. Despite the considerable implementation cost often involved, users have cited MPC projects that have delivered return on investment in 18 months or less. As a result, the “culture of MPC” might unduly influence some companies to implement MPC, when, in some cases, ARC implemented right in the DCS control blocks might actually provide the best solution.

Not highlighted as much is the fact that MPC requires a continued investment. The models are built based on the set of process conditions, feedstocks, ambient conditions, variable interactions and business objectives that exist at that point in time. However, any or all of these may change, requiring the model to be modified or rebuilt for the MPC to continue driv-ing value.

Balancing ARC and MPC. So here’s a good question: If all the process needs to perform better is feedforward, do you really need to build (and maintain) a model to accomplish this? In many instances, advanced control could be accomplished

by configuring function blocks and tuning each to remove loop interaction and to provide feedforward action and other advanced regulatory control techniques. If so, could this pos-sibly be a better approach than MPC? More to the point, how’s a plant to decide?

There is no substitute for knowing your process and the skills of your control personnel. The process control culture in any plant or company has evolved over many years with deep roots in “how we’ve always done it.” All plants must continuously maintain basic regulatory control to provide the stable, well-tuned base layer. However, above this foundation, plants have options for performing APC functions.

It’s important to note here that the choice of which technol-ogy to use for APC—whether MPC or ARC—is not an “either/ or” decision, but rather a matter of understanding which tool, or combination of tools, is best for each application. But how do you

know if you have the right balance?

The decision to implement an advanced-control application using MPC, ARC or some combination is more than a technol-ogy decision. Both tool sets can perform well for a variety of applications. Users must take support for the implemented appli-cation into consideration. If the staff at the site is not trained in maintaining MPC models, then ARC could be a better choice. If uniformity across the enterprise is important, it is important that the company considers how it will support remote locations, regardless of whether it chooses MPC or ARC.

In the end, both MPC and ARC may be the right decision. Some applications will lend themselves to using DCS function blocks, while others are best solved using model predictive controllers.

If you question whether you’re using the right combination, benchmarking can help you at least determine if you are alone or with the majority. End users in process plants may find it worth-while to participate in ARC Advisory Group’s Benchmarking Consortium, which addresses MPC performance and other key

issues. For more information, HP readers can visit http://www.

arcweb.com/Benchmarking. HP

MPC vs. ARC—Not an ‘either/or’ decision

The author 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 Company. Prior to Foxboro, Mr. Hill was a senior process control engineer with BP Oil, develop-ing and implementdevelop-ing advanced process control applications. Prior to joindevelop-ing ARC, he was the US general manager of Walsh Automation, a major engineering con-sulting firm and supplier of CIM solutions to the pulp and paper, petrochemicals, pharmaceutical, and other process and manufacturing industries. He is a graduate from Lowell Technological Institute with a BS degree in chemical engineering.

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SÜD-CHEMIE

[email protected] www.sud-chemie.com

Industry executives, technical experts and analysts will be discussing the latest innovations and breakthroughs in catalysis, process engineering, battery materials and water treatment technologies applied in these ﬁ elds at the “Deﬁ ning the Future V Conference.” Through open exchange and in-depth discussion, it is our goal to offer valuable insight into opportunities and challenges the industries are facing, and to support the formulation of strategies that can be developed to address them. This conference will be comprised of parallel sessions on:

• Reﬁ ning Industries • Chemical Industries

• Petrochemical Industries & Polyoleﬁ n Plants • Coal-To-Chemicals (Methanol & Derivatives) • Environmental Technologies

• Battery Materials

• Water Treatment Technologies

Please mark your calendar and join us in Beijing!

Süd-Chemie Deﬁ ning the Future

V Conference

May 23-25, 2011 – Beijing, China

SC_DTF_V_Anz_210x280_f01.indd 1 27.10.2010 16:00:32 Uhr

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I

HPI

MPACT

Refinery and petrochemical construction

costs continue measured rise

The costs for designing and constructing downstream refining and petrochemical projects rose 3% from Q1 2010 to Q3 2010, according to the latest edition of the IHS CERA Downstream Capital Costs Index (DCCI). It was the third straight increase for the index since prices bottomed out at 9% below peak 2008 levels. Costs are now just 4% below their 2008 peak.

The IHS CERA DCCI is a proprietary measure of project cost inflation similar in concept to the Consumer Price Index (CPI). It provides a benchmark for comparing costs around the world and draws upon proprietary IHS and IHS CERA databases and analytical tools. The current DCCI rose from 175 to 180 over the past six months. The values are indexed to the year 2000, mean-ing that a project that cost $100 in 2000 would cost $180 today. Higher commodity prices and a weakening US dollar contin-ued to be the driving force behind the steady rise of costs in the downstream sector.

“The momentum in the rise of costs back to prerecession lev-els is really a ‘slowmentum’ [sic] reflective of the broader global economic recovery,” said IHS CERA Chairman Daniel Yergin. “Activity is increasing and prices are rising, albeit with a healthy dose of caution.”

Commodities prices were driven by the global economy’s recovery and increased construction activity as the impact of the fiscal stimuli was felt by the wider economy. Steel prices continued to show high degrees of volatility as iron ore producers switched from adjusting prices annually to adjusting them every quarter, reflecting market-based demand-supply fundamentals.

The continued weakening of the US dollar also contributed to the rise of commodity prices while also driving up costs of equip-ment, labor and engineering and project management costs. The dollar’s fall was driven by the US Federal Reserve’s second round of quantitative easing to reinvigorate the US economy—the Fed recently announced a $600 billion plan to purchase treasury bonds over the next eight months.

Robust downstream construction activity in China, India and the Middle East continues unabated, according to the index. Record refining and ethylene capacity additions came online in 2009 and more projects are in various stages of engineering and construction. This trend is expected to continue until 2015. Government policies encourage investment in the downstream sector in anticipation of increasing demand for transportation fuels, plastics and fibers.

China plans to increase refining capacity by 50% in the next five years. Similarly, the Middle East is emerging as a major hub for petrochemicals with advantageous feedstock and government policies that incentivize diversification into other industries sup-ported by petrochemicals. Large complex refineries with integrated petrochemicals are emerging as the “new standard” to position the downstream sector for profitability.

The capacity additions in Asia will continue to put downward pressure on margins as excess capacity emerges in the face of

tepid consumer demand. Refiners and petrochemical companies in Organization for Economic Cooperation and Development (OECD) countries—which have been rationalizing refining capacity—will continue to face rising pressure to shut down older and less efficient plants with poor economics.

“The economic outlook ahead appears to be mixed with rising prospects that the recent momentum will give way to an impend-ing slowdown,” said Farooq Sheikh, lead researcher for the IHS CERA Capital Costs Analysis Forum for Downstream. “China also appears to be slowing down as the government increasingly restrains the fiscal stimulus and has recently increased interest rates by a quarter percent in fear of a real-estate bubble.”

Developing countries are showing increasing concerns about capital flows into their markets creating an asset bubble. Capital controls and higher interest rates are being employed to temper unbridled growth.

As a result, the IHS CERA DCCI concludes that another mod-est increase is expected in downstream capital costs in the near term as recovering construction activity and further increases in raw materials prices push costs closer to their pre-recession highs.

Moving beyond the meltdown in the Gulf

According to Deloitte Center for Energy Solutions’ recent study, the Gulf of Mexico deepwater drilling remains vital to the US economy and is vital for future growth. For the record, “easy oil” is gone; oil companies must venture to more challenging regions to explore and produce (E&P) crude oil. Such projects will require bil-lions of dollars of investment in new technologies to produce crude oil and natural gas at depths greater than 5,000 feet under water. For the Western Hemisphere, the Gulf remains a “hot bed” of E&P activity. This region’s crude oil reserves can provide a significant and secure source of domestic energy to the US. At present, 30% of the US’ oil supplies come from the Gulf of Mexico, and this region provides an economic engine to the US by creating over thousands of jobs and more than $11 billion a year in royalties and taxes.

One event. For years, E&P companies have safety operated in

the Gulf without incident; but everything change with the

Deep-water Horizon tragedy. In response to this drilling rig accident,

the US Department of Interior (DOI) immediately set in place a six-month moratorium on new shallow and deepwater drilling. The moratorium is affecting E&P operations in the Gulf. Delays in new oil supplies have contributed to the increase in oil prices during the Q4 of 2010 and the tightening in US crude supplies. The American Petroleum Institute estimates that a production loss of 80,000 bpd to 130,000 bpd of crude oil could be felt in the US market by 2015. The International Energy Agency estimates that between 100,000 bbls to 800,000 bbls of new oil supply could be deferred under the new rules, making it more difficult to sup-ply US demand. More imports will be required to cover the gap between supply and demand.

New realities. In addition to the stay on new drilling, the DOI

is imposing more rules to promote safe and reliable operations on drilling operations. The regulations set guidelines over new opera-tions and procedures, certificaopera-tions, backup control systems, new

BILLY THINNES, NEWS EDITOR

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HPI

MPACT

rig (equipment) and materials, and demonstrations of available backup blowout containment resources. Permitting delays are anticipated due to the extended regulatory reviews now in place.

Price of risk. Following the Deepwater Horizon event, E&P

companies must evaluate their potential risk exposure at $30 bil-lion when operating in the Gulf, up considerably from $75 mil-lion. In a recent Deloitte survey of approximately 300 companies operating in the Gulf, only 10 international and national oil com-panies have capitalization and a balance sheet that could withstand this level of liability. In addition, 40% of the companies working in the Gulf have a market capitalization of $5 billion or less—well below the new level of risk exposure.

Toler-ance to risk is changing the environment within the Gulf. Some companies will con-tinue to pursue projects; other companies will go to less risk areas. A mass exodus of oil and gas companies from the Gulf will have a negative impact on the US economy.

The Deepwater Horizon accident was a

tragedy that will be felt for many years. More important, many lessons have been learned through this experience by government and industry that will be most beneficial for future operations. Government and industry must find a common ground to move for-ward and to keep the Gulf open for business.

Update. In a reversal, the Obama

administration said on Dec. 1 that it will not pursue offshore drilling off the East Coast of the US and the eastern Gulf of Mexico. Because of the BP oil spill, the Interior Department will not propose any new oil drilling in waters off the East Coast for at least the next seven years.

President Barack Obama’s earlier plan— announced in March, three weeks before the April BP spill—would have authorized officials to explore the potential for drilling from Delaware to central Florida, plus the northern waters of Alaska. The new plan allows potential drilling in Alaska, but offi-cials said they will move cautiously before approving any leases.

A spokeswoman for the US Chamber of Commerce said the decision represents a major step backward for the nation’s energy future. “The decision comes on top of the de facto moratorium the administration has imposed on production in both deep and shallow waters in the Gulf and Alaska, which is already causing significant harm to our economy and our energy security,” said Karen Harbert, president and CEO of the Chamber’s Institute for 21st Century Energy.

Global energy

outlook to 2035

According to the International Energy Agency’s (IEA’s) World Energy Outlook 2010, the energy world market faces

unprecedented uncertainty. The 2008–2009 global economic crisis threw the energy markets into severe turmoil. The pace of the global economic recovery holds the key to energy prospects for the next several years, but it will be governments’ responses to the twin challenges of climate change and energy security that will shape the future of energy in the longer term. The worst of the global economic crisis appears to be over. But it will be a hard fight to return to pre-2008 energy levels. In looking ahead, IEA forecasts some changes in the global energy market:

• Global primary energy demand will increase by 36%

between 2008 and 2035, or 1.2%/yr on average. This

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'LVFRYHUPRUH±YLVLWZZZPLFKHOOFRPXV $EW0OINTƔ(UMIDITYƔ/XYGEN 0LFKHOO,QVWUXPHQWV,QF 1HZEXU\SRUW7XUQSLNH 6XLWH 5RZOH\0$ 7 XVLQIR#PLFKHOOFRP Select 152 at www.HydrocarbonProcessing.com/RS

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18

I

JANUARY 2011 HYDROCARBON PROCESSING

HPI

MPACT

pares with 2%/yr predicted from the previous 27-year study. Slower growth is due to national pledges to reduce greenhouse-gas (GHG) emissions and plans to phase out fossil-fuel subsidies. • Non-OECD countries account for 93% of the projected

increase in global energy demand. China, where demand has

surged over the past decade, will contribute 36% to the projected growth in global energy use; its demand is rising by 75% between 2008 and 2035 (Fig. 1). China overtook the US in 2009 to become the world’s largest energy user. Aggregate energy demand in OECD countries is forecast to rise very slowly.

• Global demand for fossil fuels will account for over 50%

of the increase in total primary energy demand. Rising

fossil-fuel prices for end users, resulting from upward price pressures in international markets and, increasingly, carbon penalties in many countries, will encourage energy savings and switching to low-car-bon energy sources, to restrain demand growth for all three fuels. • Oil remains the dominant fuel in the energy mix. Oil’s share of the primary fuel mix diminishes as higher oil prices and government measures to promote fuel efficiency support fuel switching. Demand for coal rises through 2020 and starts to decline. The share of nuclear power increases from 6% in 2008 to 8% in 2035. Use of modern renewable energy—including hydro,

wind, solar, geothermal, modern biomass and marine energy— triples between 2008 and 2035. Its share in total energy demand increase from 7% to 14%.

• Natural gas will play a central role in meeting the world’s

energy needs. Global natural gas demand, which fell in 2009, is

set to resume its long-term upward trajectory from 2010. Demand will increase by 44% between 2008 and 2035—at an average of 1.4%/yr. Demand growth for gas far surpasses that for the other fossil fuels due to its more favorable environmental and practical attributes, and constraints on how quickly low-carbon energy technologies can be deployed. China’s gas demand will grow the fastest, accounting for more than one-fifth of the increase in global demand to 2035. The Middle East leads in expansion of natural gas production; its output is estimated to double by 2035.

What will shape the future of oil? The global outlook for oil remains highly sensitive to policy action to curb rising demand and emissions. Primary oil use will increases in absolute terms between 2009 and 2035, driven by population and economic growth, but demand is forecast to decline in response to radical policy action to curb fossil-fuel use. Other trends are:

• The oil price needed to balance oil markets is set to rise, reflecting the growing insensitivity of both demand and supply to price. The growing concentration of oil use in transport and a shift of demand toward markets where subsidies are most prevalent are limiting the scope for higher prices to choke off demand and discouraging fuel switching. Constraints on investment mean that higher prices lead to only modest increases in production. In the New Policies Scenario, the average IEA crude oil price reaches $113/ bbl (2009 dollars) in 2035—up from just over $60/bbl in 2009.

• Oil demand (excluding biofuels) continues to grow

steadily reaching about 99 million bpd (MMbpd) by 2035.

Non-OECD nations are responsible for the net growth—almost half from China alone. Demand by OECD nations falls by over 6 MMbpd. Global oil production reaches 96 MMbpd, the balance of 3 MMbpd coming from processing gains. Crude oil output reaches an undulating plateau of around 68–69 MMbpd by 2020, but never regains its all-time peak of 70 MMbpd reached in 2006, while production of natural gas liquids (NGLs) and unconven-tional oil grows strongly (Fig. 2). Total OPEC production rises continually through to 2035; its share of global output increasing from 41% to 52%.

• The eventual peak in oil demand will be determined by

several factors affecting both demand and supply. Production

in total does not peak before 2035, although it comes close to doing so. Oil prices are much lower as a result. If governments act more vigorously than currently planned to encourage more efficient use of oil and development of alternatives, then demand for oil may ease. Result: We might see a fairly early peak in oil production, which would help prolong the world’s oil reserves.

• Unconventional oil is set to play an increasingly

impor-tant role in the world oil supply through to 2035, regardless

of what governments’ actions to curb demand. Unconventional oil will meet about 10% of world oil demand compared with less than 3% today. Canadian oil sands and Venezuelan extra-heavy oil dominate the mix, but coal-to-liquids, gas-to-liquids and, to a lesser extent, oil shale also makes a growing contribution in the second half of the outlook period. HP

Expanded versions of these items can be found online at HydrocarbonProcessing.com. Gas Oil Coal OECD China Rest of world -600 -300 0 300 600 900 1,200 1,500 Other renewables Hydro Nuclear Million toe

Energy demand by region, 2008–2035. FIG. 1

Crude oil ﬁelds yet to be developed or found Unconventional oil Natural gas liquids

Crude oil—currently producing ﬁelds Total crude oil 60 80 100 mb/d 0 20 40 60 1990 1995 2000 2005 2010 2015 2020 2025 2030 2035

World oil production by type, 1990–2035. FIG. 2

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Tim Lloyd Wright is HP’s European Editor and has been active as a reporter and conference chair in the European downstream industry since 1997, before which he was a feature writer and reporter for the UK broadsheet press and BBC radio. Mr. Wright lives in Sweden and is founder of a local climate and sustainability initiative.

www.GulfPub.com/2011HPI

HP EDITORIAL

HPI

2011 FORECAST

HPI Market Data 2011 Executive Summary

BACK FROM THE EDGE OF DESPAIR

Hydrocarbon Processing’s HPI Market Data 2011 report offers

a detailed forecast for the direction that the hydrocarbon process-ing industry (HPI) is headprocess-ing in 2011. The executive summary is reproduced here for your reading pleasure. Should you wish to purchase the whole report, please visit www.gulfpub.com.

Depending on the markets, HPI segment and processing facil-ity location, refiners and petrochemical producers can expect their business prospects to improve, tread water or take a turn for the worse. The report emphasizes that a new environment has arrived this year, and it will take courage and stamina by HPI companies to successfully navigate this constantly evolving economic and regulatory terrain.

The 2011 economic outlook for HPI companies is:

Improving. Half-way through 2010, it is the developing or non-Organization of Economic Co-operation and Development (non-OECD) nations that are pulling the rest of the world out of this downturn. As shown in Fig. 1, non-OECD nations are steadily increasing their consumption of crude oil. In contrast, OECD nations’ demand for crude oil peaked in 2006 at 49.5 million bpd (MM bpd) and has declined to an estimated 45.5 MM bpd in 2010. Yet, the total demand for crude oil has fluxed around 86 MM bpd over this same period, with a five-year average of 85.74 MM bpd.

In particular, it is China’s strong gross domestic product (GDP) and manufacturing powers that have remained positive during this downturn. As shown in Fig. 2, China is the major non-OECD

energy-consuming nation. In 2011, China will be responsible for about one-third of new crude-oil demand growth. In 2010, Chinese oil demand is forecast to rise 9.2%. Much of this rising demand is linking to a growing middle class in China.

Several economists predicted that significant changes would evolve due in part to the sharp decline in the global economy; such changes would move centers of influence as well. In mid-2010, China emerged as the No. 1 energy-consuming nation, sur-passing the US and Japan. This shift in leading energy-consuming nations was predicted to happen in 2015. However, the steep decline in energy consumption by the US and the steady, increas-ing expansion of the Chinese economy shifted China to the No. 1 energy-consuming nation five years sooner than forecast. With a strong economy, China has surpassed Japan as the second largest economy. Japan’s economy struggled before the 2008 downturn and, since then, has contracted even more, as shown in Fig. 2.

Treading water. The US economy still struggles to find for-ward momentum. The combination of high unemployment and a jobless recovery continues to stifle economic activity. Lower crude oil prices and natural gas prices eased processing and feed-stock costs. But consumers remain chilled on spending what incomes they still have. Housing starts remain mired, which hinders the petrochemical industry.

Taking a turn for the worse. Western Europe is experienc-ing new economic woes in 2010. High unemployment still chal-lenges the European Union (EU). In 2010, several EU nations

Total oil demand for OECD and non-OECD nations, 2006–2010. FIG. 1 49.5 49.2 _47.6 45.5 45.5 35.6 37.2 38.4 39.3 40.9 85.1 86.4 86 84.8 86.4 0 10 20 30 40 50 60 70 80 90 100 2006 2007 2008 5-yr. avg. 85.74 2009 2010

Global oil demand, 2006–2010

Global oil demand, million bpd

OECD Non-OECD Total

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HPI

2011 FORECAST

22

I

JANUARY 2011 HYDROCARBON PROCESSING

encountered more financial difficulties over deficit spending that unfortunately spilled over to neighboring nations. Just as in the US, EU consumer spending nearly evaporated in 2009, and the EU demand for petrochemicals declined 13.9%. The EU petro-chemical industry report a 9% increase over 2009 levels in 2010. But recovery to pre-2008 levels will take much longer, perhaps five years. In addition, a stronger US dollar against the euro created even more stress for this region. Several EU nations are tightening their financial belts to weather through this economic storm, thus adding more pressure to this region.

Beyond 2011. The global HPI is bruised from recent events. However, the HPI is intertwined in the daily lives of the aver-age consumer. Activity and consumption of HPI products will increase in non-OECD nations due in part to a growing middle class in China and India and increasing populations in developing nations. The “stampede to the East” will continue as more HPI complexes will be located in growing consumer markets as well as in locations with lower cost feedstocks and operating costs.

TOTAL SPENDING

HPI companies manage their spending habits via three bud-gets—capital, maintenance and operating. In 2011, we believe that global improvements from 2010 will continue into the next year. While new project activity is stalled from the all-time high in 2007, the total active project count remains at record levels. The global GDP stagnated in 2010; some regions fared better than others. The developed nations (OECD nations) still struggle to get back on track, economically speaking. Demand for transporta-tion fuels and petrochemical consumer products is rising slowly, but not at rates desired by most governments. The meltdown of the banking and credit systems tightened access to capital and is still impacting the entire HPI community. More scrutiny is

applied by financial institutions to minimize their risk on major capital projects.

Greenshoots of economic stability began appearing in late 2009 and early 2010. However, recovery to pre-2008 levels will take more time, perhaps until 2015 by some forecasters. Yet, there is some good news; notably, energy costs have declined. This is a benefit for manufacturers and consumers. Dramatic reductions in natural gas and crude oil prices are easing operating spending. However, the near collapse in product demand and trade has created a surplus situation for various HPI products. It is taking longer for industry to work down excess inventories.

Looking forward, 2011 will continue to improve for the HPI. New project announcements declined in 2010 but did not evapo-rate. However, we should expect a more disciplined spending approach by major companies to trim costs across the entire value chain of their products and manufacturing centers. The bonus from the downturn has been a decline in construction, material and equipment costs.

HPI construction activity remains resilient, and new project additions still occurred even at the bottom point of the recession in early 2009. Investment in existing facilities will focus on improv-ing reliability and maintainimprov-ing more onstream time while findimprov-ing more production capacity through “creep” expansion projects. Growing demand for HPI products will be met by new grassroots installations in developing nations, particularly China and India.

In 2011, the HPI’s capital, maintenance, and operating budgets are expected to total $219.8 billion (Table 1). Capital spending is projected at $56.4 billion; maintenance spending should reach $63.9 billion, a $1.1 billion increase over 2010 spending; and operating spending is projected to be $99.5 billion. HPI companies are more cost conscious during tight credit times.

Capital spending exceeds $56 billion. HPI capital spend-ing is forecast to be more than $56 billion worldwide in 2011. As shown in Table 2, the 2011 capital spending total includes $25.1 billion in the refining sector, $16.6 billion in the petrochemical segment, approximately $10.5 billion in the gas processing sector and $4.3 billion in the synfuels sector. More than $28 billion of the capital budget will be spent on equipment and materials.

HPI companies are strengthening their balance sheets and are seeking opportunities to maximize their market shares through strategic capital investment. Caution is still applied in major projects and capital spending.

Companies in maturing HPI consuming regions, such as the US and EU, are implementing capacity additions through process modifications and retrofits. The need to maintain the reliability of existing assets and to increase energy efficiency are major goals in many revamp projects. Other energy-conservation and envi-ronmental improvements from innovative equipment and new processing technologies are also part of this investment strategy. The availability of new and improved equipment and construction

TABLE 1. 2011 Worldwide HPI total spending by budget, millions

Type US Outside US Worldwide

Capital 9,660 46,770 56,430

Maintenance 15,333 48,542 63,875 Operating 30,386 69,090 99,476

Total 55,379 164,402 219,781

TABLE 2. 2011 Worldwide HPI capital spending by sector, millions

Sector US Outside US Worldwide

Petrochemical/chemical 2,300 14,300 16,600

Refi ning 4,400 20,700 25,100

Gas processing 2,960 7,460 10,420

Synfuels – 4,310 4,310

Total 9,660 46,770 56,430

Oil demand changes in Asia-Pacific for OECD and non-OECD nations, 2007–2010, FIG. 2 -600 -400 -200 0 200 400 600 800 2007 2008 2009 2010 OECD Paciﬁc

Change in oil demand, million bpd

Non-OECD Paciﬁc China