HP_2012_12

PLANT DESIGN AND ENGINEERING

速

HydrocarbonProcessing.com | DECEMBER 2012

New techniques facilitate design of grassroots complexes and modernization efforts for existing facilities

PETROCHEMICALS REVIEW Innovations and developing markets are redefining this industry

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DECEMBER 2012 | Volume 91 Number 12 HydrocarbonProcessing.com

38

43 SPECIAL REPORT: PLANT DESIGN AND ENGINEERING

39 How do innovations and best practices transform process engineering?

V. Dhole and R. Beck

43 Intelligent indexing is key to 3D CAD plant modeling S. Saha and A. Nair

47 Consider coal gasification for liquid fuels production B. Anantharaman, D. Chatterjee, S. Ariyapadi and R. Gualy

55 Consider ‘lean’ engineering to fast-track mega projects S. Bennett

DEPARTMENTS

4 8 11 15

2013 Editorial Calendar

21 25 27 30

Innovations Associations Construction Construction Boxscore Update Marketplace Advertiser index

PETROCHEMICALS REVIEW

57 South America: Argentina, Brazil, Venezuela 63 Europe: Germany, United Kingdom 67 Asia: China, India, Japan MAINTENANCE

86 88

HPI Market Data 2013 Executive Summary

COLUMNS

33

Reliability Upgrade the design of vertical, multistage centrifugal pumps in low-temperature services

35

Control What’s new with FOUNDATION Fieldbus—Part 2 Editorial The last word

75 Reliability and maintenance: The path to world-class performance A. Poling

REFINING DEVELOPMENTS

Brief Impact

79 Improve integration opportunities for aromatics units—Part 2 J. Zhou, S. Vaidyanathan and S. Kapur

90

Cover Image: This petroleum refinery image shows the YPF Complex of Ensenada at the Bay Complex Unit in Argentina. The image was developed with several Intergraph Process, Power & Marine solutions, including SmartPlant 3D, SmartPlant Instrumentation and SmartPlant Review. Photo is courtesy of Intergraph Corp.

2013

EDITORIAL CALENDAR*

MONTH

SPECIAL REPORT

January

Natural Gas Developments

February

Clean Fuels

March

Corrosion Control

HPI FOCUS

The Green Refinery

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CIRCULATION Director, Circulation

April

May

Petrochemical Developments

New vs.

De-Bottlenecking

Maintenance and Reliability

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June

Process/Plant Optimization

Energy Efficiency

July

Refinery of the Future

Changing Refining Economics

August

Fluid Flow and Rotating Equipment

September

Refining Developments

October

Cyber Security and Process Control

November

Plant Safety and Environment

December

Plant Design, Engineering and Construction

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Petrochemical Update

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Top 5 Projects in the HPI

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

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| Brief Gulf Coast hydrogen pipeline unveiled Air Products recently completed its 600-mile Gulf Coast Connection Pipeline (GCCP) project and also started up operations at a dynamic customer service center.

The pipeline stretches from the Houston Ship Channel in Texas to New Orleans, Louisiana. In August, it began supplying over 1.2 billion cubic feet of hydrogen per day to refinery and petrochemical customers. Air Products had operated two hydrogen pipeline systems in Texas and Louisiana before joining them with a new 180-mile segment.

Completion of the GCCP project required overcoming several challenges. These included: • Securing 1,085 permanent landowner right-of-ways and over 300 temporary agreements • Obtaining numerous environmental permits and hundreds of non-environmental permits • Maneuvering the pipeline through three US Army Corps of Engineers flood-protection levees within the Atchafalaya Basin swamp • Installing more than 24,000 pipe sections that were each 40 feet in length.

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

Brief Dow Chemical plans to close 20 plants and cut 2,400 jobs as part of a global cost-cutting program over the

next two years. The 2,400 layoffs amount to 5% of Dow’s global workforce. With the moves, Dow expects to save $500 million in annual operating costs by the end of 2014. Dow says it also plans to further reduce capital spending and investments for certain unspecified growth programs. Those measures are expected to save the company an additional $500 million in cash. Plants to be shut down include a high-density polyethylene (HDPE) facility in Tessenderlo, Belgium, and a sodium borhidrate plant in Delfzijl, The Netherlands.

Moreover, a number of performance materials manufacturing facilities will be closed, including an automotive systems diesel particulate filters manufacturing facility in the US (Midland, Michigan); formulated systems manufacturing facilities in Spain (Ribaforada), the UK (Birch Vale) and the US (Solon, Ohio); and an epoxy resins facility in Japan (Kina Ura).

Gunvor Group has signed a one-year contract with Rosneft to export approximately 6 MM tons of oil

products from Russia. Gunvor won the contract to export products from Rosneft’s three refineries in Russia’s Samara region, following a tender. Gunvor will export the products via its Ust-Luga terminal on the Baltic Sea and its 50%-owned Novorossiysk terminal on the Black Sea. The US Environmental Protection Agency (EPA) has exercised its authority under the Clean Air Act to

temporarily waive certain federal clean gasoline requirements for gasoline sold and distributed in Tennessee, North Carolina, South Carolina, Mississippi, Georgia, Alabama, the District of Columbia, New York, Maryland, Connecticut, Delaware, Massachusetts, New Jersey, Pennsylvania, Virginia, New Hampshire and Rhode Island. The waiver was granted by the EPA in coordination with the US Department of Energy (DOE). The EPA determined that, as a result of the effects of Hurricane Sandy, extreme and unusual supply circumstances exist, which may result in a temporary shortage of gasoline compliant with federal regulations. The federal waiver will help ensure an adequate supply of fuels in the impacted states.

The waiver allows the sale and distribution of conventional gasoline in a number of eastern states that are required to use reformulated gasoline, and allows a number of additional states to mix reformulated gasoline and conventional gasoline to remove potential barriers to the supply of gasoline to the region.

The relatively recent and intense exploitation of US natural gas reserves is resulting in an increased

dependence on butadiene imports, according to a report from business intelligence group GBI Research. The study predicts that the disparity between butadiene production and demand

will climb in the near future as the US moves away from crude oil and naphtha to increasingly cheap natural gas. The percentage of C4 hydrocarbons required for the production of butadiene is very low in natural gas compared to crude oil or naphtha.

As a result, growing demand will necessarily require a boost in imports. US butadiene demand last year stood at 1.9 MM tons, compared to the 1.6 MM tons the country produced. GBI Research predicts demand will hit 2.4 MM tons by 2020, while butadiene yield will climb at a slower rate, reaching 1.9 MM tons by the end of the decade.

Shell has awarded Fluor a five-year enterprise framework agreement for engineering and project

management services for downstream and potentially upstream onshore projects in Europe, Africa and the Middle East. Under the terms of the agreement, Fluor will provide design, project and construction management and site-based engineering services. Fluor is currently working on Shell projects in Malaysia, the Philippines and Canada. Fluor also provides services at Shell sites in Australia, Qatar, Russia and The Netherlands.

Air Liquide has a new licensing agreement with Petrobras in conjunction with its recently awarded

contract to Foster Wheeler for a world-scale, grassroots, gasto-chemicals complex in Linhares, Espirito Santo, Brazil. The complex is to be called Complexo Gás-Químico UFN-IV. Air Liquide is the licensor for the integrated unit, which will produce syngas, methanol, ammonia, power and steam. Air Liquide will also furnish fully integrated basic engineering design (BED) and engineering services during the execution of the front-end engineering design (FEED), along with technical assistance during the engineering, procurement and construction phase through startup of the complex. The BED/FEED phase is scheduled for completion at the end of 2013. The complex is expected to produce in excess of 1 MM tpy of ammonia and urea fertilizers, methanol, acetic acid, formic acid and melamine.

Renewable Energy Group (REG) has acquired a 15-MM gpy biorefinery located in New Boston, Texas. With the

acquisition, REG’s nameplate biodiesel production capacity is expected to increase to more than 225 MM gpy. REG paid $300,000 in cash and issued 900,000 shares of its common stock to North Texas Bio Energy for the multi-feedstock biorefinery, located about 22 miles west of Texarkana. It is REG’s second Texas biodiesel production facility, following the 2008 acquisition of its Houston-area plant. The New Boston facility began production in June 2008 and has been idled for approximately four years. Brad Albin, REG vice president of manufacturing, said the plant will undergo some construction and minor upgrades prior to the facility’s startup, which is expected in the first quarter of 2013.

Hydrocarbon Processing | DECEMBER 2012 9

Results

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

Impact

Production of biofuels made from algae poses sustainability concerns Scaling up the production of biofuels made from algae to meet at least 5% (approximately 39 billion liters) of US transportation fuel needs would place unsustainable demands on energy, water and nutrients, said a new report from the National Research Council. However, these concerns are not a definitive barrier for future production, and innovations that would require research and development could help realize algal biofuels’ full potential.

Biofuels derived from algae and cyanobacteria are possible alternatives to petroleum-based fuels and could help the US meet its energy security needs and reduce greenhouse gas (GHG) emissions, such as carbon dioxide (CO2 ).

Algal biofuels offer potential advantages over biofuels made from land plants, including algae’s ability to grow on noncroplands in cultivation ponds (FIG. 1) of freshwater, saltwater or wastewater. The number of companies developing algal biofuels has been increasing, and several oil companies are investing in them. Given these and other interests, the National Research Council was asked to identify sustainability issues associated with large-scale development of algal biofuels.

The committee that wrote the report said that concerns related to large-scale algal biofuel development differ depending on the pathways used to produce the fuels. Producing fuels from algae can be done in many ways, including cultivating freshwater or saltwater algae, growing algae in closed photobioreactors or openpond systems, processing the oils produced by microalgae, or refining all parts of macroalgae. The committee’s sustainability analysis focused on pathways that, to date, have received active attention.

Most of the current development involves growing selected strains of algae in open ponds or closed photobioreactors, using various water sources, collecting

and extracting the oil from algae or collecting fuel precursors secreted by algae, and then processing the oil into fuel.

The committee pointed out several high-level concerns for large-scale development of algal biofuel, including the relatively large quantity of water required for algae cultivation; magnitude of nutrients, such as nitrogen, phosphorus and CO2 , needed for cultivation; amount of land area necessary to contain the ponds that grow the algae; and uncertainties in GHG emissions over the production life cycle. Moreover, the algal biofuel energy return on investment would have to be high, meaning that more energy would have to be produced from the biofuels than what is required to cultivate algae and convert it into fuels.

The committee found that to produce the amount of algal biofuel equivalent to 1 liter of gasoline, between 3.15 liters and 3,650 liters of freshwater is required, depending on the production pathway. Replenishing water lost from evaporation in growing systems is a key driver for use of freshwater in production, the committee said. In addition, water use could be a serious concern in an algal biofuel production system that uses freshwater without recycling the “harvest” water.

To produce 39 billion liters of algal biofuels, 6 MM to 15 MM metric tons of nitrogen and 1 MM to 2 MM metric tons of phosphorus would be needed each year if the nutrients are not recycled, the report said. These requirements represent 44% to 107% of the total nitrogen use and 20% to 51% of the total phosphorus use in the US. However, recycling nutrients or utilizing wastewater from agricultural or municipal sources could reduce nutrient and energy use, the committee said.

Another resource that could limit the amount of algal biofuels produced is land area and the number of suitable and available sites for algae to grow. Appropriate topography, climate, proximity to water supplies—whether freshwater, inland saline water, marine water, or wastewa-

ter—and proximity to nutrient supplies would have to be matched carefully to ensure successful and sustainable fuel production and avoid costs and energy consumption for transporting those resources to cultivation facilities. If the suitable sites for growing algae are near urban or suburban centers or coastal recreation areas, the price of those lands could be prohibitive. A national assessment of land requirements for algae cultivation that takes into account various concerns is needed to inform the potential amount of algal biofuels that could be produced economically in the US. Emissions. One of the primary motiva-

tions for using alternative fuels for transportation is reducing GHG emissions.

However, estimates of greenhouse gas emissions over the life cycle of algal biofuel production span a wide range; some studies suggest that algal biofuel production generates less GHG emissions than petroleum-based fuels, while other studies suggest the opposite. These emissions depend on many factors in the production process, including the amount of energy needed to dewater and harvest algae and the electricity sources used.

The committee emphasized that the crucial aspects to sustainable development are positioning algal-growth ponds close to water and nutrient resources and recycling essential resources. With proper management and good engineering designs, other environmental effects could be avoided, the committee said. Examples

FIG. 1. Cultivation ponds offer a controlled environment for algae production.

Hydrocarbon Processing | DECEMBER 2012 11

Impact include releasing harvest water in other bodies of water and creating algal blooms and allowing harvest water to seep into ground water.

For algal biofuels to contribute a significant amount of fuels for transportation in the future, the committee said, research and development would be needed to improve algal strains, test additional strains for desired characteristics, advance the materials and methods for

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growing and processing algae into fuels, and reduce the energy requirements for multiple stages of production. To aid the US Department of Energy in its decisionmaking process regarding sustainable algal biofuel development, the committee proposed a framework that includes an assessment of sustainability throughout the supply chain, a cumulative impact analysis of resource use or environmental effects, and cost-benefit analyses.

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US energy independence vs. energy security The Deloitte Center for Energy Solutions recently released a report, “Energy independence and security: A reality check,” which examines whether or not energy independence is necessary to achieve energy security. Deloitte contends that the answer is “probably no.”

The report reviews present and developing national energy policies and discusses US strategies for oil imports and use. A key conclusion is that, “while US energy independence may be unattainable in the foreseeable future, energy security is a realistic and achievable goal.

“The real issue is not independence from all foreign oil,” the report said, “but reducing oil imports from unfriendly nations, diversifying our supply of energy sources and ensuring that no nation can effectively manipulate markets against our national interests...Understanding how to reach [energy security], however, requires us to know more about our sources and uses of energy—and the realities of energy supply and demand.”

One section of the report breaks down the US’ primary energy sources and sectors. Petroleum provides the US with 36% of its energy (FIG. 2); 71% of all petroleum available is used in the transportation sector, while 23% of it goes to the industrial sector.

FIG. 2 explains how the rest of the US’ energy sources are used.

The report also acknowledges that, “for most energy-consuming sectors of our economy, our supply is predominately domestic, with only transportation remaining more heavily dependent on imports. Thus, the US already has significant ‘energy independence,’ at least in terms of exclusive reliance on domestic production, for much of its economy.”

“The remaining question,” Deloitte contends, “is how to make the transportation sector more independent of sharp disruptions and unfriendly sources [of energy].”

Scottish distillers jump on natural gas bandwagon The excitement about natural gas as a useful industrial tool has spread to the Scottish countryside. A collection of whisky distillers in the Speyside area of Scotland plans to invest £7.6 MM to install a

Impact 16-mile gas pipeline that will link four of these distilleries to the main gas network. Diageo, Chivas Brothers and Angus Dundee said the pipeline will end their reliance upon fuel oil and will cut their energy costs by around 30%. The new pipeline will connect distilleries at The Glenlivet, Tormore, Cragganmore and Tomintoul with Scotland’s main gas network. Work on the underground pipeline began in November and is expected to be completed within 18 months.

The conversion to natural gas is expected to reduce distillery carbon emissions by a quarter and will remove the need for tanker deliveries on rural roads often affected by severe winter weather.

A joint statement from the three distillery companies said: “These distilleries were founded before the advent of gas as an energy source and their distant locations were often chosen for a bounteous supply of fresh spring water above all else.

It is a very positive move to bring them online with the main gas network, which will bring environmental and economic benefits to all distillers concerned.”

Sources

Sectors 71%

Petroleum(a) 36%

3% 4%

23% 1% 5% 3% 33% Natural gas(b) 25%

40% Industrial(e) 41% 21% 8% 11% Residential and 17% 76% 1% commercial(f) 11% 6% 20% 1%

32%

<1% Coal(c) 20%

31% 8% 91%

13% Renewable energy(d) 9% Nuclear electric power 8%

Transportation 28%

93%

46%

25% 7% 55% 100%

Electric power(g) 41%

12% 21%

Notes: (a) Does not include biofuels that have been blended with petroleum—biofuels are included in “Renewable Energy.” (b) Excludes supplemental gaseous fuels. (c) Includes less than 0.1 quadrillion Btu of coal coke net exports. (d) Conventional hydroelectric power, geothermal, solar/PV, wind and biomass. (e) Includes industrial combined-heat-and-power (CHP) and industrial electricity-only plants. (f) Includes commercial (CHP) and commercial electricity-only plants. (g) Electricity-only and (CHP) plants whose primary business is to sell electricity, or electricity and heat, to the public.

Includes 0.1 quadrillion Btu of electricity net imports not shown under “Source.”

Primary energy in the form that it is first accounted for in a statistical energy balance, before any transformation to secondary or tertiary forms of energy (for example, coal is used to generate electricity). *Sum of components may not equal total due to independent rounding.

FIG. 2. US primary energy consumption by source and sector, 2011 (% of total energy use).

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Hydrocarbon Processing | DECEMBER 2012 13

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Forecast HPI Market Data 2013 Executive Summary ENERGY TIME: CHARTING A COURSE FOR THE FUTURE The hydrocarbon processing industry (HPI) is a global business with a 100-year history. Much has changed since the early days when crude oil was stripped to recover kerosine for lighting purposes. The HPI has been the vehicle by which nations have advanced economic growth and created wealth. The HPI includes crude oil refineries, petrochemical facilities and gas processing/liquefied natural gas (LNG) installations. The petrochemical industry grew out of developments from the early natural gas and petroleum refining industries. LNG and natural gas are key parts of the electrical power generation industry. The HPI is well ingrained in the global economy and in the gross domestic product of all nations.

The world order for the global HPI is changing. Developing nations such as China, India and Brazil are the new demand centers for HPI products. Accordingly, new grassroots HPI facilities will be located in these nations. In addition, areas with abundant hydrocarbon resources, such as the Middle East, will continue processing and manufacturing capacity expansions through grassroots HPI projects and revamps of existing facilities, as shown in TABLES 1 and 2.

Energy time is very different. HPI facilities are constructed for a service of 30-plus years. Many economic cycles will occur during the service life of an HPI complex. In fact, many HPI facilities in operation today were commissioned 60 years ago. Maintenance and optimization programs keep older complexes operating safely and efficiently. Investment in major equipment, catalysts and processing technologies enable established HPI facilities to remain profitable.

TOTAL SPENDING In 2013, the HPI’s total spending on capital, maintenance and operating budgets is expected to exceed $230 billion (B), as summarized in TABLES 3 and 4. Capital spending includes

investments for grassroots projects under development and construction, in addition to modernization and optimization projects for existing HPI facilities. In 2013, capital spending is forecast to exceed $57 B. Global maintenance spending is forecast to reach $69 B; operating spending is estimated to hit almost $104 B, as summarized in TABLE 4.

From TABLES 1 and 3, it can be seen that petrochemical and refining projects are the major centers for spending in all categories. More importantly, project activity is very global, as demonstrated in TABLE 2. Since 2008, HPI companies have reigned in spending to weather the uncertainty following the financial collapse. At present, many HPI companies have cash reserves set aside for the future.

TABLE 2. Worldwide HPI construction projects by region, June 2009 to June 2012 Jun-09

Jul-11

Jun-12

US

714

716

421

485

Canada

212

209

155

168

Latin America

530

607

469

480

Europe

1,261

1,283

956

920

Africa

215

231

179

241

Middle East

990

1,057

822

795

Asia-Pacific

1,551

1,629

1,277

1,157

5,473

5,732

4,329

4,246

Total

TABLE 3. 2013 Worldwide HPI total spending Sector, millions $

US

OUS

Worldwide

Petrochemical/chemical

31,200

83,200

114,400

Refining

21,100

68,700

89,800

Gas processing

5,600

16,700

22,300

4,000

4,000

172,600

230,500

Synfuels Totals

TABLE 1. Worldwide HPI construction projects

Jun-10

57,900

Jun-09

Jun-10

Jul-11

Jun-12

Petrochem/chem

1,837

1,889

1,246

1,237

Refining

1,692

1,751

1,427

1,550

Gas processing

1,196

1,266

939

901

98

108

78

76

Maintenace Operating

31,500

72,400

103,900

Total

57,900

172,600

230,500

Synfuels All others Total

650

718

639

482

5,473

5,732

4,329

4,246

TABLE 4. Worldwide HPI spending by budget, 2013 Type, millions $ Capital

US

OUS

Worldwide

9,700

47,900

57,600

16,700

52,300

69,000

Hydrocarbon Processing | DECEMBER 2012 15

Forecast REFINING In looking ahead to 2013, the HPI will still be managing problems that began during the 2008 recession. Developed markets, such as the Organization for Economic Co-operation and Development (OECD) nations, will experience reduced consumption of transportation fuels going forward, as summarized in TABLE 5. Refined products demand from developed nations, such as the US, Japan and some Western European countries, has already peaked. Fuel efficiency mandates for light-duty trucks and passenger cars are further reducing future demand for gasoline and diesel. Increasing usage of renewable fuels continues to displace crude oil-based transportation fuels in the market. Additionally, the automobile population of OECD nations is leveling off, thus tempering new demand for transportation fuels.

Developing nations are driving new demand for transportation fuels, as indicated by TABLE 5. China and India continue to invest in refining capacity to meet present demand for transportation fuels. FIG. 1 shows that demand for refined products will be largely driven by middle distillates—diesel and jet fuel.

In 2013 and beyond, a number of factors will influence the operation and ownership of refining assets: • Scale. Larger refineries can more efficiently distribute significant fixed costs across each barrel of product that is refined. Typical major refineries have 300,000 bpd to 600,000 bpd of throughput capacity. In the past, refineries with 100,000 bpd of capacity were considered viable—but not today.

• Ability to process high-sulfur crude oils. Refineries now require significant capital investment and higher complexity to process high-sulfur crudes and heavy oils into “cleaner” transportation fuels.

• Flexibility. More importantly, successful refining operations apply processing “flexibility” to adapt to changing market

conditions. This includes the ability to produce high-quality distillates—clean diesel and jet fuel. Such capabilities do require investments in hydrocracking, catalytic cracking and decoking/coking capacity.

• Access to reliable crude oil supplies. Refiners need strategies to ensure some protection from shortages and price volatility.

• Processing capability for specialty products. Other profit opportunities include capabilities to produce specialty products such as solvents, lubrication oils, waxes, etc.

• Integration with petrochemical facilities. Refineries with “over-the-fence” petrochemical facilities benefit from trading and supplying intermediate products to both operations, especially for olefins and aromatics. Today, fluid catalytic cracking units produce more propylene for petrochemical applications than do traditional ethane steam crackers.

• Access to other refineries locally. Again, opportunities to optimize trading and exchanging intermediate product streams between proximate refineries enable the optimization of processing capability for both groups.

• Access to low-cost natural gas. Refineries are major users of natural gas to provide energy for thermal processes and utility operations (steam production). Lower-cost natural gas dramatically reduces operating costs.

• Age and operating efficiency. Newer refineries are more energy efficient and have lower manufacturing costs per barrel of crude refined. Also, larger-scale refineries contribute to more efficient operations and, therefore, lower operating costs per unit.

• Environmental compliance costs. European and US refiners incur higher costs per gallon due to environmental spending. In 2010, US refiners spent 5¢/gal of crude oil processed on environmental compliance. On a per-barrel-of0.4 0.2 0.0

0.8 0.6 0.4 0.2 0.0 -0.2 -0.4 -0.6 North America

Fuel oil Distillate = Diesel + Kerosine/jet Gasoline Naphtha

FSU

0.4 0.2 0.0 -0.2 -0.4 -0.6

1.6 1.2 0.8 0.4 0.0

Europe

China

0.4

0.6 0.2 -0.2

-0.6 0.3 0.0

2.0

Middle East

0.8 0.0 -0.6

Global demand 2010 2020

FIG. 1. Worldwide incremental refined product demand, 2010–2020.

16 DECEMBER 2012 | HydrocarbonProcessing.com

0.0

0.2 -0.2

-0.4 India

Japan

0.8 0.4

0.4 Latin America

0.6

0.0 Other Asia-Pacific Africa MMbpdoe 88.2 99.8

Unit: MMbpdoe Source: Axens estimates

Forecast

NATURAL GAS AND LNG The boom in shale gas production has coincided with an expansion of global liquefied natural gas (LNG) trade. Countries with large natural gas reserves are working to develop their resources for profitable export to consuming nations via pipelines, liquid petroleum gas (LPG) transport, LNG cryogenic tankers and gas-to-liquids (GTL) projects.

Due in part to the rise of unconventional gas resources, worldwide gas trade is anticipated to more than double over the next 25 years, with new trade routes and supply patterns emerging. Presently, LNG makes up 32.3% of gas shipments worldwide. FIG. 2 shows the division of the global LNG export market in 2011.

The US remained the world’s largest gas producer in 2011, with output rising 7.7% from 2010. The country maintained its focus on unconventional gas production, despite lackluster North American natural gas prices. Russia followed close behind with a 3.1% increase on the year.

Conversely, the EU’s gas output plummeted 11.4% on weak regional demand and field maturation and maintenance, marking the largest annual decline on record. The biggest contributors to growth in global natural gas supply through 2030 are expected to be the Middle East and the former Soviet Union. Incremental supplies will come from the US, Australia and China.

Among fossil fuels, natural gas is expected to see the fastest growth through 2030, while oil will see the slowest increase.

Gas is anticipated to meet 31% of the projected growth in global energy consumption by that year. Also, global gas growth from 2010–2030 will be highest in the power and industry sectors, which is consistent with historical growth trends.

Non-OECD regions will collectively account for 80% of global growth in demand for natural gas, with an average increase of 2.9%/yr through 2030.

In 2011, total global gas demand expanded just 2.2% vs. the 7.4% growth seen in 2010. Demand growth was below average in all regions except North America, where weak gas prices supported consumption. Outside of North America, the highest demand growth levels were recorded in China (21.5%), Saudi Arabia (13.2%) and Japan (11.6%). Conversely, the EU recorded its largest-ever decline in gas consumption during 2011. The 9.9% decrease was spurred by economic turmoil, mild winter weather, high gas prices, and increased generation of renewable Algeria 5%

Other* 28%

Australia 8% Indonesia 9%

PETROCHEMICALS Outlooks for the global petrochemical industry remain largely tied to the accessibility of a given location to natural gas.

For regions such as North America, an abundance of shale has helped keep natural gas prices low, allowing the ethane-based petrochemical industry to thrive.

On the other hand, naphtha-based regions are struggling to make the economics work. This is particularly the case in Western Europe (FIG. 3), where sinking demand and stringent environmental regulations against shale drilling are forcing the region to import increasing amounts of product from elsewhere, such as the US, Russia and several Middle Eastern and Asian countries.

10 2010 2011

8

2012 2013

Malaysia 10%

*Trinidad and Tobago, Russia, Oman, Yemen, Egypt, Brunei, Equatorial Guinea, Peru, Abu Dhabi, Norway and US (Alaska)

4 2 0 -2 NAFTA

Other Americas

Western Europe

Emerging Mideast- Sub-Saharan Japan Europe N. Africa Africa

Other AsiaPacific

Source: IHS Chemical

FIG. 3. Economic conditions and trends by region, 2010–2020.

TABLE 5. World oil demand by region, 2005–2011, MMbpd Consumption US North America Latin America Brazil

2005

2008

2010

2011

Average

20.8

19.5

19.18

18.84

19.58

25.06

23.84

23.49

23.16

23.8875

5.11

5.79

6.79

6.24

2.07

2.4

2.63

2.65

Europe

20.1

20

19.04

18.92

Middle East

6.37

7.27

7.89

8.08

Asia-Pacific China

2.86

3.15

3.38

3.34

25.72

27.56

28.3

26.5025

6.94

7.94

9.25

9.76

8.4725

2.57

3.07

3.33

3.47

Total

83.93

85.77

87.44

88.34

OCED nations

49.95

48.02

46.52

45.92

Non-OCED nations

33.98

37.75

40.92

42.11

3.75

3.98

3.89

4.11

15.03

14.69

13.86

13.48

Former Soviet Union

19.515

24.43

India

European Union FIG. 2. Division of global LNG export market, 2011.

2014-20

6

Africa Qatar 32%

Nigeria 8%

electricity. By volume, the US, Russia and Canada remained the world’s three biggest users of natural gas.

Gas processing and liquefaction capacity expansions are forecast for all major LNG-importing and LNG-exporting regions, which will also require the addition of LNG carriers to transport the fuel. Investments reflect ongoing efforts to retrofit existing plants to meet growing demand for energy and natural gas products, to improve processing flexibility, and to comply with environmental and safety regulations.

Real GDP, annual percent change

crude-oil-processed basis, US refiners spent $2/bbl, which significantly impacted margins.

86.37

Source: BP Statistical Review of World Energy 2012

Hydrocarbon Processing | DECEMBER 2012 17

Forecast Technology developments. Shale technology has evolved

rapidly and continues to improve, led by horizontal wells, lower rig cycle times, multiple fractures and multi-well pads.

The technology is also scalable and transferable to numerous shale plays. Combine that with the substantial amount of new reserves that are rich in natural gas liquids (NGLs), and there suddenly appears to be a feedstock haven for petrochemicals.

In addition, the crack spread for natural gas continues to widen relative to crude. That will give midstream producers all the incentive they need to continue drilling in shale plays.

Shale oil regions, such as the Bakken in North Dakota, are of the utmost importance for downstream sectors.

North America leads the way. Those developments are heading a petrochemical revival in areas that only two years ago were considered old news. While capacity continues to come onstream in Asia, led by growing Chinese demand, the cheap feedstock advantage and high margins that once were exclusive to the Middle East are now available in places like the US and Canada (FIG. 4), where there is also political stability.

Some producers believe the ethane advantage is here to stay in the US. For those companies, building new facilities is optimal because they can best tailor their units to handle modern feedstock slates. However, others believe the North American revival is only temporary, considering that economic trends remain largely stagnant in the developed world. Those companies believe they are best suited to debottleneck existing units, since doing so requires less capital investment.

Middle East, Asia closer to demand. Despite those factors, Middle Eastern and Asian producers still have one advantage over North American manufacturers based on proximity to de25

353

20

265

15

220

10

132

176

Dollars per ton

Cents per pound

309

US wtd. avg. contract cash margin

88

5 0 2008

2009

2010

2011

2012

2013

2014

2015

44 0

mand (FIG. 5). While North American producers have cheap feedstock access, post-recession demand is not growing quickly enough to consume the potential supply.

As a result, producers must have domestic or export access to locations such as China, India and other developing Asian-Pacific countries, where demand continues to surge.

The International Energy Agency (IEA) projects roughly 7% economic growth for the region in 2013, giving incentive to producers to keep operating rates high.

Construction and spending. These factors are leading petrochemical spending to a projected total of $112.2 B worldwide in 2013—a $4.3 B increase over 2012. Higher maintenance spending is anticipated as petrochemical producers maintain existing assets during uneven economic conditions. Higher frequency of planned shutdowns also facilitates more maintenance activity, with organizations reviewing their operating budgets.

New plant construction and project announcements top out at 1,237 active petrochemical projects, virtually flat with projects in the year 2011. Companies are retrofitting and upgrading existing facilities with improved equipment, materials and technologies. Considerations for security at petrochemical sites are an ongoing priority. However, not all projects will be completed; some cancellations are anticipated due to market and financial risks. Several projects have announced delayed startup times amid the continued struggle in some global economies.

The Asia-Pacific remains the global growth leader, based on burgeoning economic strength in China and India. North America may challenge the Middle East in new projects over the next decade, based on recent shale discoveries and export opportunities. Companies continue to debate the best strategy for new capacity to efficiently take advantage of feedstock availability.

Naphtha olefins crackers remain at a disadvantage. However, producers will seek ways to maximize olefins production from available resources such as natural gas condensate and coal-to-liquids. On the ethane side, the trend toward increased cracking reduces volumes for co-products, such as benzene, butadiene and propylene (FIG. 6). Overall, petrochemical companies throughout the world are restructuring, consolidating and implementing domestic and global strategies to improve profitability and contend with forecast economic changes. The year 2013 could well be a tipping point.

3.5

Million metric tons

12

Forecast

8 4 0

-4 -8 ’90

’92

’94

’96

’98

’00

North America Total Asia Others

’02

’04

’06

’08

’10

’12

’14

’16

Middle East West Europe Annual demand increase

Source: IHS Chemical

FIG. 5. Global ethylene capacity compared with demand, 1990–2016.

18 DECEMBER 2012 | HydrocarbonProcessing.com

Production yield for world-scale, 1-MMt cracker

FIG. 4. Margin outlook for US ethylene.

3.0 2.5

Other Benzene Butadiene Propylene Ethylene

2.0 1.5 1.0 0.5 0.0 Ethane

Naphtha

Source: IHS Chemical

FIG. 6. Reduced co-product volumes when cracking ethane.

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Anticipating that hydrogen needs along the Gulf Coast of North America will increase in the years ahead, Air Products expanded its hydrogen supply network. By building a 180-mile (290-km)-long pipeline that connects our existing Texas and Louisiana systems, we’ve united 22 hydrogen plants and 600 miles (965 km) of pipeline, with a total system capacity of over one billion SCFD (1.3 million Nm3/hr). So if an event disrupts operations on one side of the Gulf, hydrogen can keep flowing from the other, giving our refinery and petrochemical customers the reliable, uninterrupted supply they need. With this record-breaking network, Air Products continues to break new ground in hydrogen supply. For videos and detailed information, visit our website.

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Reliability has no quitting time

ITT offers a full range of API/ANSI/ISO Goulds Pumps that have been tested in rough oil and gas facility conditions around the world. Plus valves, actuators, switches, regulators, high-temperature interconnectors, energy absorption and vibration isolation systems—and the aftermarket services to keep it all going. After all, in the 24/7/365 refinery business, the last thing you want is a piece of equipment that fails. With ITT, your processes stay up—and your total cost of ownership stays down. For more information, and to receive our Oil and Gas catalog, visit www.ittoilgas.com or call 1-800-734-7867.

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ADRIENNE BLUME, PROCESS EDITOR Adrienne.Blume@HydrocarbonProcessing.com

Innovations Invensys acquires Spiral Software Invensys Operations Management has acquired Spiral Software, a privately held company headquartered in Cambridge, UK. Spiral Software provides integrated solutions ranging from crude assay management to refinery supplychain optimization, enabling clients to make educated choices in trading and refining crude oil.

Spiral’s crude oil knowledge-management tools help companies track the quality of feedstocks and predict their refining behavior. Fully integrated refinery planning and scheduling help optimize production plans based on real-time crude demand and market pricing, as well as on the refinery’s own capacity and supply-chain constraints.

Ravi Gopinath, president of Invensys’ software business, commented, “Spiral Software provides the only integrated refining industry solution designed from the ground up, bringing together feedstock data management, planning and scheduling. This means that our SimSciEsscor offerings will now fully support and optimize the entire refining value chain, from crude trading to supplychain distribution, including lifecycle modeling from design to startup to performance optimization.”

Spiral Software’s crude oil knowledgemanagement tools provide oil information across an enterprise, from ranking crude oils in trading to optimizing refinery processes and maximizing reliability.

Spiral Software’s planning and scheduling solution provides a collaborative, multiuser environment for sharing common data and models across all supply-chain work processes.

In parallel, Spiral Software’s integrated risk-analysis feature enables users to look across many different planning and scheduling scenarios, helping refiners understand their exposure to changes in feedstock costs, product demand and refinery operations.

The business will continue to be managed by Spiral Software’s existing executive team, adding employees to Invensys operations in the UK and North America.

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Flowmeters resist corrosion in offshore applications

Endress+Hauser’s Proline Promass 83O (FIG. 1) and 84O Coriolis flowmeters are ideal for use in corrosive, highpressure and high-temperature environments in the oil and gas industry. All materials that can come into contact with gases and fluids are manufactured from super duplex stainless steel, which offers protection against saline seawater, H2S, chloride, CO2 and other corrosive materials found in crude oil and natural gas.

The Promass 83O and 84O flowmeters simultaneously measure mass flow, fluid density and temperature. They are highly immune to external disturbances such as pipeline vibration, and they are stable under changing process conditions such as pressure, density, temperature and viscosity.

The stainless steel sensing tubes fulfill all requirements in accordance with NORSOK M-630 and NACE MR175/ MR103, as well as corresponding pressure equipment directives like PED Category 3, ASME, CRN and AD2000. This makes the 83O and 84O flowmeters suitable for use on offshore drilling platforms; floating, production, storage and offloading (FPSO) facilities; onshore well fields; custody transfer systems; and refineries.

The flowmeters handle pressures up to 3,742 psi (258 bar) and process temperatures of –40°F to 392°F (–40°C to 200°C).

Both instruments are available in line sizes of 3-in., 4-in. and 6-in. diameters. Every flowmeter is subjected to rigorous testing on accredited (ISO/IEC 17025) and fully traceable calibration facilities.

Promass 83O flowmeter output configuration options include digital communications, supporting FOUNDATION fieldbus, PROFIBUS PA or DP, EtherNet/IP or Modbus RS485 installations.

Promass 84O analog outputs for 0 kHz– 10 kHz phase-shifted pulse/frequency are also available when custody-transferproving requirements are mandated.

When using the 4 mA–20 mA signal output with HART, intrinsically safe applications for Class 1, Division 1 and other hazardous locations can be satisfied. Promass O has been submitted for a SIL-2 rating for critical applications, and the line complies with NE43 (NAMUR) safety standards, including operating down to 3.6 mA in a fail-safe condition.

The 83O and 84O flowmeters have built-in diagnostics, and they display clear English text errors and root causes on local displays in case of a fault. The flowmeters also can be commissioned and diagnosed with Endress+Hauser’s FieldCare software. If servicing is needed, FieldCare’s DAT function automatic data backup ensures automatic reconfiguration of a repaired or new meter without the need for recalibration.

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FIG. 1. The Promass 83O flowmeter is ideal for use in harsh and corrosive environments.

Hydrocarbon Processing | DECEMBER 2012 21

Innovations Low-maintenance detector protects against CO2 leaks General Monitors’ IR700 Infrared Carbon Dioxide Point Detector (FIG. 2) requires no routine calibration and provides complete control room status and control capability for monitoring at the ppm level.

The IR700 detector has a precision infrared (IR) point-sensing element that

protects against the hazards of CO2 gas leaks. It also features a fail-safe design for dependable gas detection performance, heated optics to eliminate condensation, and a dirty optics indicator to let the user know when the device must be cleaned, thereby reducing downtime.

The IR700 detector includes microprocessor-based technology to continuously monitor CO2 at a range of 0 ppm–5,000 ppm. Its detection principle

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With an extended range of hydraulic coverage and rugged construction, the Process Maxum Series is ideal for Industrial Process applications. Manufactured in 35 sizes, standard materials include WCB, WCB/316SS, 316SS and CD4MCu, with others available upon request. A variety of options include various types of mechanical seals and bearing lubrication/cooling arrangements, auxiliary protection devices and certified performance testing.

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is based on measuring the absorption of IR radiation passing through a volume of gas using a dual-beam, single-detector method. The detector measures the intensity of two specific wavelengths, one at an absorption wavelength and another outside of the absorption wavelength.

Gas concentration is determined by comparing these two values.

All of the detector’s electronics are contained within a rugged, explosionproof housing so that information can be processed at the point of detection.

It features multiple communication outputs, a 4-milliampere (mA) to 20-mA signal proportional to 0%–100% fullscale Modbus and HART. The IR700 detector is also available with relays for warnings, alarms and faults. Additionally, the detector can be connected to an IR4000S CO2 transmitter to provide local display and control.

The IR700 detector is factory calibrated and requires no routine field calibration. Periodic window cleaning and re-zeroing are necessary to ensure performance. The detector is able to discriminate between true fault and cleaning requirements, and it stores fault, gas check and alarm event history. It operates at a wide temperature range of –40°F to 122°F (–40°C to 50°C) and a humidity range of 10% to 95% relative humidity, noncondensing.

The IR700 detector is available in either an aluminum or a stainless steel housing, and is designed for use in Class I; Divisions 1 and 2; Groups B, C and D; Zone 1 areas for North America; and Zones 1 and 21 internationally.

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Creating Value.

Carver Pump Company 2415 Park Avenue Muscatine, IA 52761 563.263.3410 Fax: 563.262.0510 www.carverpump.com FIG. 2. The IR700 detector gives control capability for CO2 monitoring at the ppm level.

22

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Innovations Emerson expands AMS Suite support Emerson Process Management recently announced expanded asset support in the AMS Suite predictive maintenance software application, providing users with a more comprehensive asset-management application.

Connectivity was established to PROFIBUS PA devices, which expands the list of assets that users can integrate into AMS Suite to enable a consistent maintenance approach. Additionally, AMS Suite now supports both electronic device description language (EDDL) and field device tool/ device type manager (FDT/DTM) to provide users with a single application to support the full capabilities of all their devices.

The addition of PROFIBUS PA provides a complete PROFIBUS solution with the DeltaV control system, corresponding to capability already available for PROFIBUS DP devices in DeltaV. PROFIBUS DP and PA support on thirdparty hosts is also available via the Softing FG PROFIBUS family of interfaces.

Users are able to launch HART and FOUNDATION fieldbus DTMs via the DTM Launcher application, which is provided as a standard part of AMS Device Manager. Also, expanded asset support gives users the ability to choose devices based on the best fit for their application, regardless of the manufacturer or communication protocol.

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Clariant features heattransfer fluids at Chillventa

Swiss specialty chemicals group Clariant presented its Antifrogen line of heattransfer fluids at the Chillventa tradeshow in Nuremberg, Germany, from October 9–11. Antifrogen products are versatile heat-transfer fluids based on glycols (Antifrogen N, Antifrogen L and Antifrogen SOL HT) and/or potassium formate (Antifrogen KF).

All fluid types offer freezing protection and reliably protect cooling and heating systems against corrosion. Clariant’s comprehensive package includes performance checks, sample analysis at no charge, and technical consulting as part of the service provided.

The trade show presented a first-time opportunity for Clariant to unveil its new corporate branding to the heating, venti-

lation and air-conditioning (HVAC) industry. The new branding reflects Clariant’s stress on the values of performance, people and planet.

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Eralytics offers portable FTIR oil analysis

Eralytics’ ERASPEC OIL analyzer (FIG. 3) uses the economic infrared analysis test

method to deliver specific information about the chemical condition of lubricating oil. Compact and rugged, the analyzer weighs 8 kg/17.6 lb and is fully encased in aluminum housing. The analyzer brings lab-quality results to the field and provides immediate feedback on in-service oil quality even at remote sites, where avoiding equipment breakdown is critical.

With its patented, reinforced, mid-Fourier transform infrared (FTIR) spectrometer, the ERASPEC OIL analyzer is the first truly portable, standalone analyzer that offers the advantages of the latest FTIR technology for lubricant oil condition monitoring in full compliance with ASTM, DIN and JOAP methods directly onsite.

The ERASPEC OIL analyzer offers a built-in industry PC and a large, full-color touchscreen that allow the direct display of the oil spectra as a graphic chart. The spectra are immediately analyzed and compared with other spectra, as several thousand spectra can be saved in the internal instrument memory.

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FIG. 3. The ERASPEC OIL analyzer can provide feedback on lubricant oil quality at remote sites.

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23

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

Associations Aside from North American exports, owes to cheap coal exports from the Gastech examines natural Mr. Muraki believes the other issues that US, which is turning to gas for its power gas potential for all sectors For four days in October, Hydrocarbon Processing was on call at the Gastech Conference and Exhibition in London. The magazine’s editorial staff was selected to produce the official show daily newspaper for the event. All four days of the newspapers can be found at hydrocarbonprocessing.com; presented here are a two brief items excerpted from the complete show daily coverage.

Japan looks to secure North American LNG exports. The long-term fate of

Japan’s LNG market will largely depend on whether the nation can secure deals to import LNG from North America, an executive with Tokyo Gas said. Shigeru Muraki, CEO of the Energy Solution Division of Tokyo Gas, believes LNG prices will determine the balance between gas and coal usage in industries, such as power.

The International Energy Agency (IEA) forecasts that, by 2020, gas prices will be $5.40/MMBtu in the US, $10.50/ MMBtu in Europe and $12.40/MMBtu in Japan. However, if shale gas in North America is exported to Asia, the price is expected to drop to between $9 and $11, Mr. Muraki said.

“If those pricing levels are achieved, LNG [import] demand in 2020 will increase to 90-to-100 MM tons per year (tpy). If current pricing levels continue, the demand will continue at 70-to-80 MMtpy.

In Asia, it comes down to the pricing.”

Mr. Muraki spoke at a Gastech Executive Leadership Panel session on whether the gas industry has entered a “golden age.”

Tokyo Gas, already one of the world’s largest LNG buyers, has significantly increased its deals following the 2011 earthquake disaster. In 2010, the year before the earthquake, Japan imported 70 MMtpy of LNG. However, the import quantity increased after the earthquake, due to the shutdown of nuclear power plants, reaching 80 MMtpy in 2011 and from 85-to-87 MMtpy in 2012.

will dictate Japan’s LNG market going forward are government policies on nuclear energy.

“A government committee has announced a plan to decrease dependence on nuclear energy to zero by the 2030s,” he said. “However, this plan has not been adopted as policy. Discussions are still ongoing and not finalized.”

European gas sector needs policy intervention. European gas demand is

flat-to-declining and will likely remain that way without government regulations to support gas fired power generation, said Norbert Kint, head of trading for Austriabased EconGas. Mr. Kent was a featured speaker at the conference’s trading session on gas markets, prices and risk.

“Overall, in Europe, we’ve seen very strongly decreasing demand,” said Mr. Kint. “That’s the main impact of what you’ve seen the last few years and will probably see in the years to come.”

The reasons for the switch vary by specific country. In the UK, gas demand dipped 16% in 2011 and is expected to shed another 7% in 2012. That decline

needs, due to low domestic costs.

“The US is now exporting roughly 25% more coal in the direction of Europe,” said Mr. Kint. “It’s mostly landing in the power production sector in the UK. Gas demands are dropping off substantially.”

He said the lone positive for the UK’s gas sector is that nuclear development does not appear to be going as expected.

In Germany, the biggest driver is governmental incentives for renewable production. “The forecast calls for renewables to continue to eat into gas consumption,” said Mr. Kint.

The German gas sector saw demand drop 17% in 2011 and is expected to remain largely flat in 2012 and 2013, possibly with slight increases of under 5%.

Another problematic issue for Europe is that LNG supply is decreasing, due to Asian demand. Qatar accounted for nearly half of Europe’s LNG imports in 2011, but that nation is increasingly sending more production to Asia.

Overall, Mr. Kint describes the European regulatory picture as “uncertain,” and further clarity is needed to determine where the industry is headed.

Gastech brought together upstream and downstream natural gas professionals.

Hydrocarbon Processing | DECEMBER 2012 25

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

Construction North America Westlake Chemical Corp. will perform planned maintenance and an expansion of the Petro 2 ethylene unit at its complex in Lake Charles, Louisiana, in the first quarter of 2013. This expansion will increase ethane-based ethylene capacity by approximately 230 million lb/yr–240 million lb/yr in support of the company’s ethylene integration strategy. The unit is expected to be down approximately 50 days for the work to be completed.

Evonik Industries is undertaking an engineering study for a new multimilliondollar methyl methacrylate (MMA) plant at its site in Mobile, Alabama. “The Evonik executive board authorized the basic engineering study to evaluate the site’s feasibility for a 120,000-tpy facility last month,” said Gregor Hetzke, head of Evonik’s Performance Polymers Business Unit.

If approved by the Evonik executive board, the new facility is expected to start up in mid 2015.

The Lubrizol Corp. intends to build a resin and compounding manufacturing facility in Deer Park, Texas. The new plant will require a total investment of approximately $125 million over a three-year period.

Lubrizol evaluated several options for the plan’s first phase and determined that the most efficient and effective next step is to build a new plant located adjacent to its existing Deer Park additives facility, leveraging current Lubrizol infrastructure and expertise. Additional site benefits include its close proximity to the Gulf of Mexico shipping channel and direct access to pipeline chlorine. The world-class facility is expected to be operational by the fourth quarter of 2014, and is designed to complement the company’s existing chlorinated polyvinyl chloride (CPVC) manufacturing facilities.

South America

ICA Fluor, the industrial engineering partnership of Fluor and Empresas ICA,

is part of the joint venture ( JV) that was awarded a multibillion-dollar engineering, procurement and construction contract by Braskem Idesa. The JV company, which includes Odebrecht, Technip and ICA Fluor, will design and build the new Etileno XXI petrochemical complex in Veracruz, Mexico.

The new petrochemical complex will include a 1 million-tpy ethylene cracker and two high-density polyethylene plants.

The JV project team will use several operating centers around the world to execute the project.

ICA Fluor was part of the team that performed the front-end engineering for the offsites and facilities in 2011.

Toyo Engineering Corp. (TOYO) has a urea synthesis and granulation technologies supply contract with a capacity of 2,100 tpd for Yacimientos Petrolíferos Fiscales Bolivianos (YPFB), in Carrasco, Cochabamba, Bolivia.

The scope of the contract includes grant of license, development of basic design and supply of a set of proprietary equipment. The plant is scheduled to start up in 2015. Samsung Engineering Co. Ltd. (SECL) has been awarded the engineering, procurement and construction (EPC) contract for the ammonia and urea project, and TOYO will provide its proprietary urea technologies to YPFB through SECL. The Bolivian government plans to monetize its country’s vast natural-gas resources, and this is the first project in its plans to target the urea import substitute and export market.

Europe

Alfa Laval has won an order for compact heat exchangers from a refinery in Russia. The order, valued at approximately SEK 70 million, was booked late September 2012, and delivery is scheduled for 2013.

The Alfa Laval compact heat exchangers will be used in the vacuum section of the crude-oil distillation, where they will preheat the feed stream reusing heat from

other parts of the process, thereby resulting in an energy-efficient process solution.

Uhde Inventa-Fischer will build a 432,000-tpy polyethylene terephthalate (PET) plant for JBF Industries Ltd. in Geel, Belgium. The plant will produce high-quality PET for bottling and packaging applications. BP Chembel N.V. will produce and supply feedstock terephthalic acid on the same site.

JBF Industries Ltd. will produce topquality PET pellets based on Uhde Inventa-Fischer’s state-of-the-art, energyefficient, patented Melt-To-Resin (MTR) technology. Integration of a 54,000-tpy Flakes-To-Resin (FTR) recycling line will also allow 25% of the purified terephthalic acid (PTA) to be replaced with recycling material.

Uhde Inventa-Fischer’s scope of supplies includes the know-how license for the MTR and FTR technologies, the basic and detail engineering, supply of all plant components, and supervision of the construction and commissioning activities. The operating personnel will also be trained by Uhde Inventa-Fischer’s experienced specialists. The detail engineering for the project will be carried out by Uhde Inventa-Fischer and Uhde India Private Ltd. TREND 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 | DECEMBER 2012 27

Construction Mitsubishi Gas Chemical Co., Inc. (MGC) and JGC Corp. have announced that performance testing has been successfully completed and commercial operation has started at a licensed dimethyl ether (DME) production plant commissioned by Grillo A.G., using a process owned jointly by MGC and JGC. The plant is located in an industrial park in Frankfurt, Germany.

This process uses high-performance catalysts developed by MGC, and the process has been optimized to ensure high-purity DME product with minimal impurities. Furthermore, it has been established that the process can be used to manufacture DME on a scale as large as 1 million tpy, making DME feasible for use as fuel, and contributing to the expanding potential for the global use of DME.

Middle East

Subsidiaries of Foster Wheeler AG’s Global Engineering and Construction Group have been awarded an engineering and procurement contract by Sadara Chemical Co. for a packaging center

at Jubail Industrial City, Kingdom of Saudi Arabia.

The packaging center contract has been awarded as an extension to the frontend engineering and design (FEED) contract awarded to Foster Wheeler in 2008.

The packaging center, expected to be completed in the second half of 2014, will serve as a logistics handling hub for Sadara’s chemical complex. The facility will handle packaging, storage and loading of high-value-added chemical products and performance plastics.

Saudi Aramco has completed the contractor selection process for the engineering, procurement and construction (EPC) phases of the Jazan refinery and terminal, in the southwest part of the Kingdom of Saudi Arabia.

After completion of front-end engineering and design (FEED) work in April 2012, competitive bidding for the EPC contracts took place, and it has concluded with the selection of Saudi Arabian and international contractors to implement the mega project. The following

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companies are among the selected contractors: Petrofac Saudi Arabia Ltd., Hyundai Arabia Co. Ltd. , Hanwha Engineering and Construction Corp. , SK Engineering & Construction Co. Ltd., Tecnicas Reunidas, JGC Corp., and Hitachi Plant Technologies, Ltd. Scheduled for completion in late 2016, Saudi Aramco’s Jazan refinery and terminal mega project are expected to play a significant role in the supply of feedstock and fuels to support the growth of major industries in Jazan Economic City. The project is expected to create numerous economic benefits, including business opportunities for local enterprises and new job opportunities.

Asia-Pacific

KBR was awarded a license and process-design package contract for a new olefins-recovery unit in Yulin, Shaanxi Province, China.

The client owns an existing commercial plant of coal-to-olefins, which was put into production in 2011, and, is said to be the first and largest coal-to-

Construction olefin project in the world. It uses coal as the feedstock to produce polyethylene and polypropylene by coal gasification to methanol, then methanol to olefin (MTO), and then olefin polymerization.

This is the second MTO plant for the client with the capacity of 600 kiloton/ yr of olefins (ethylene plus propylene).

It is planned to be put into production in 2014.

Davy Process Technology (Davy), a wholly owned Johnson Matthey subsidiary, and Johnson Matthey have successfully started up a new substitute natural gas (SNG) plant owned and operated

by Datang Energy Chemical Co. Ltd. (Datang) in Keshiketeng County, Inner Mongolia Autonomous Region, China.

The plant uses Davy’s SNG process technology in conjunction with Johnson Matthey’s purification and methanation catalysts to convert coal-derived synthesis gas into SNG, essentially methane, which will be transported via a new gas pipeline to Beijing. The plant capacity is 4 million Nm3/day, and it is one of three plants Datang is building at Keshiketeng, giving an overall site capacity of 12 million Nm3/day. The second plant is in the detailed engineering phase, and the third plant is in the final stages of approval.

The plant is one of six SNG plants that Davy and Johnson Matthey have licensed in China, and it is the first to start up and produce gas. Another Davy/Johnson Matthey SNG plant is expected to start up in 2012, with two further plants coming onstream in 2013.

and construction management (EPCm) contract from LANXESS Butyl Pte. Ltd. for a new neodymium polybutadiene (Nd-PBR) rubber plant to be built on Jurong Island, Singapore. This award follows Foster Wheeler’s successful completion of this project’s front-end engineering and design earlier this year. Foster Wheeler’s scope of work is expected to be completed in 2014.

The new facility, which LANXESS states is expected to be the largest of its kind in the world, will produce 140,000 tpy of Nd-PBR, and will include process and finishing buildings, a central control room, a substation and a tank farm. It will be built alongside LANXESS’ 100,000tpy synthetic butyl-rubber plant, the largest facility of its type in Asia, due to start up in 2013, and for which Foster Wheeler is also the EPCm contractor.

CB&I has a contract from Huating Coal Group Co., Ltd., for the license, basic engineering and related services for a polypropylene plant at Huating Industrial Development Area, Gansu, China.

The plant will use the Novolen advanced gas-phase polymerization technology to produce the full scope of polypropylene homopolymers, random copolymers and impact copolymers.

The plant will be part of an integrated 600,000-metric-tpy coal-to-methanol project, which started production at the end of 2010. The 200,000-metric-tpy polypropylene plant is expected to start up in 2014.

Versalis, Eni’s chemical subsidiary, and Honam Petrochemical Corp. have signed an agreement for the development of an elastomeric production plant at its Honam facilities in Yeosu, South Korea.

The new site will use Versalis’ proprietary technologies and will have an elastomers production capacity of about 200,000 tpy. Startup is planned by the end of 2015. Versalis will provide its engineering services, commercial development skills and technical assistance, while Honam will provide the primary raw materials, operative sites and existing structures.

KBR has a license and process-design package contract from Jiutai Energy Group for its methanol-to-olefins (MTO) recovery project in Dalu New Area, Zhungeer Banner, Ordos, Inner Mongolia, China.

KBR’s MTO technology will be used in the recovery process for Jiutai’s 600-kiloton/yr ethylene and propylene unit.

The recovery process will take 1,800 kiloton/yr of methanol to the MTO reactor and convert it. The effluent from the MTO reactor will then enter KBR MTO recovery to separate 600 kiloton/yr of polymer-grade ethylene product and propylene product.

A subsidiary of Foster Wheeler AG’s Global Engineering and Construction Group has an engineering, procurement

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

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CONSTRUCTION BOXSCORE UPDATE / ConstructionBoxscore.com COMPANY

CITY

PROJECT

EX CAPACITY UNIT

Egyptian Refining Co Kenya Petroleum Refineries

Cairo, Mostorod Mombasa

Amine Unit Refinery

RE

Huating Zhongxu Coal Chem Datang Energy Chemical BPCL / LG Chemicals HPCL Sinopec Petronas Petrovietnam

Gansu Keshiketeng Kochi Rajasthan, Barmer Batam Island Johor Bahru, Pengerang Nghi Son EZ

Polypropylene Coal to SNG Plant (3) Refinery Refinery Storage, Oil Refinery Refinery

BP Porner Eni SpA KazMunaiGas Expl & Prod Polskie LNG

Hull Bitterfield Venice Pavlodar Swinoujscie

Ethanol Bisphenol Biorefinery Refinery LNG Terminal

Cochabamba Coatzacoalcos Veracruz

Urea Petrochemical Complex Ethylene Cracker

Bahrain City Doha Jubail Yanbu Fujairah Ruwais Ruwais Bahrain City

Refinery EX Acid Gas Removal Polyacetals Refinery RE Refinery Cracker, FCC-Resid Sulphur Handling Terminal Cracker, FCC TO

Highlands County Louisville Toledo Tulsa Freeport

Cellulosic Ethanol Dehydrogenation Processing, Heavy Oil Coker, Delayed Ethylene

COST STATUS YR CMPL LICENSOR

ENGINEERING

CONSTRUCTOR

AFRICA Egypt Kenya

90 m3/hr None

120000

E P

2014 2016

E E U S U U U

2014 2013 2015 2016 2015 2016 2016

C U P F U

2012 2014 2013 2015 2014

E U E

2015 2015 2015

E E P E F F H P

2017 2013 2015 2015 2016 2014 2013 2017

A U P E F

2013 2015 2013 2017

Tecnimont

ASIA/PACIFIC China China India India Indonesia Malaysia Vietnam

200 12 120 9 2.6 300 200

EX EX

m-t MMNm3/d bpd MMtpy MMm3 Mbpd Mbpd

2800 850 1670 6200

CB&I Davy Process

CB&I Davy Process CB&I Technip / Jacobs FW

Versalis SpA Technip

EUROPE England Germany Italy Kazakhstan Poland

110 MMgpy None None 17.5 Mtpy 5 BNm3/y

EX

50 130

EDL Saipem / Techint

Technip Techint / Saipem

LATIN AMERICA Bolivia Mexico Mexico

Yacimientos Petr Fiscales Braskem / IDESA JV Braskem SA

2100 tpd 2700 None 1 MMtpy

2.7

Toyo Engineering Corp.

Technip / Odebrecht / ICA Fluor Technip / Odebrecht / ICA Fluor

MIDDLE EAST Bahrain Qatar Saudi Arabia Saudi Arabia United Arab Emirates United Arab Emirates United Arab Emirates Bahrain

BAPCO Qatargas Celanese Corporation / SABIC LUBREF IPIC Takreer GASCO BAPCO

400 bpd 10 m-tpy None 710 tpy 200 bpd 127 bpd 22000 tpd 40 Mbpd

6000 871 3000

FW Technip / Chiyoda

Axens / Shaw S&W

Samsung Eng Shaw S&W / Stone & Webster Bechtel / Fluor / Jacobs / FW Techint Shaw S&W

FW

FW Al Jaber / Techint

UNITED STATES Florida Kentucky Ohio Oklahoma Texas

BP Clariant BP Husky Holly Corp Dow Chemical

36 MMgpy None 170 Mbpd 30 Mbpd 1.5 MMtpy

EX TO

2500 400

CB&I FW

FW Technip

Ecopetrol / FW

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.

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Reliability

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

Upgrade the design of vertical, multistage centrifugal pumps in low-temperature services The overall mechanical design of most API-style vertical-column pumps (FIG. 1) comes close to meeting the expectations of modern pump users. Such pumps are often equipped with self oil-lubricated bearing thrust assemblies in contrast to older designs that depended on motorthrust bearings only. Some older vertical pumps deserve to be closely reviewed.

Based on failure history and criticality of service, older vertical-column pumps are candidates for upgrading at the next routine repair or maintenance opportunity.

The adequacy for large vertical pumps should include these 10 factors: 1) The dn value of the bearings (shaft rpm multiplied by the mean bearing diameter, in mm). It should not exceed the experience-based limit of 500,000.

2) Disclosure of mechanical seal pv values (pv = pressure x velocity). Also seal component materials and seal balance ratios are needed. Working with a respected manufacturer, reliability-focused users should verify the pv values against prior experience. In case of unusually high pv values, the locations and names of contact persons may be needed.

3) The line bearings or column bushings used for shaft stabilization (FIG. 2) should be made from high-performance polymer materials. Many high-quality bushings contain carbon-graphite fibers.

The typical diametral clearance should be [(0.001) (shaft diameter, in.) + 0.002 in.] For a nominal shaft diameter of 1.6875 in., the bushing bore should be 1.6912 in. +/–0.0005 in. Three or four axial grooves should be provided in the bushing bore to counteract fretting risk during occasional, but potentially severe, rubbing contact.

4) A nominal diametral clearance of 0.010 in. is recommended for the bore of labyrinth bushings not serving as bearings.

5) If vibration probes are used, the probes should monitor both high-fre-

FIG. 1. Typical vertical-pump inlet bowl and mixed-flow impeller.

quency acceleration and low-frequency velocity. Gradually developing bearing defects will show up in the acceleration spectrum before there are velocity excursions. During shop testing, the pump manufacturer should verify the absence of resonant vibration. This is especially important in variable-speed vertical pumps; resonant vibration must be absent at all anticipated operating speeds.

6) Hand-fitting of keys and bottomradiusing of keyways should be considered, and roll-pins should not be used for key fixation. Improved shop practices will increase the shaft factors of safety.

7) Monitor proper assembly procedures. Bearing manufacturers have long insisted on either supporting the bearing inner ring while pushing on a shaft or, alternatively, while pushing the bearing inner ring on the shaft.

8) O-ring selection varies with the fluid being pumped. Teflon wrap over nitrile rubber or Viton cores should be considered for olefin services. The final selection should be approved by an Oring or mechanical-seal manufacturer.

9) In cryogenic temperature environ-

FIG. 2. Column bearing sandwiched between two column flanges. A two-piece split tapered bushing secures two keyed shaft ends in place; a single-piece tapered sleeve fits over the twopiece split tapered component.

ments and where dual seals are used, low pour-point synthetic lubricants will be advantageous as a barrier fluid.

10) There is universal agreement among bearing manufacturers that an oil spray introduced into the bearing cage (ball separator) is the most desirable lubricant application method. An oil spray greatly reduces the risk of overheating, which is a primary concern in pump geometries where several rolling element bearings are assembled as a stack of two or more bearings.

HEINZ P. BLOCH resides in Westminster, Colorado. His professional career began in 1962 and included longterm assignments as Exxon Chemical’s Regional Machinery Specialist for the US. He has authored over 520 publications, among them 18 comprehensive books on practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oilmist lubrication and practical lubrication for industry. Mr. Bloch holds BS and MS degrees in mechanical engineering. He is an ASME Life Fellow and maintains registration as a Professional Engineer in New Jersey and Texas.

Hydrocarbon Processing | DECEMBER 2012 33

Process Insight:

Selecting the Best Solvent for Gas Treating

Selecting the best amine/solvent for gas treating is not a trivial task. There are a number of amines available to remove contaminants such as CO2, H2S and organic sulfur compounds from sour gas streams. The most commonly used amines are monoethanolamine (MEA), diethanolamine (DEA), and methyldiethanolamine (MDEA). Other amines include diglycolamine® (DGA), diisopropanolamine (DIPA), and triethanolamine (TEA). Mixtures of amines can also be used to customize or optimize the acid gas recovery. Temperature, pressure, sour gas composition, and purity requirements for the treated gas must all be considered when choosing the most appropriate amine for a given application.

Primary Amines

Mixed Solvents

dŚĞ ƉƌŝŵĂƌLJ ĂŵŝŶĞ D ƌĞŵŽǀĞƐ ďŽƚŚ KϮ ĂŶĚ ,Ϯ^ ĨƌŽŵ ƐŽƵƌ ŐĂƐ ĂŶĚ ŝƐ ĞīĞĐƟǀĞ Ăƚ ůŽǁ ƉƌĞƐƐƵƌĞ͘ ĞƉĞŶĚŝŶŐ ŽŶ ƚŚĞ ĐŽŶĚŝƟŽŶƐ͕ D ĐĂŶ ƌĞŵŽǀĞ ,Ϯ^ ƚŽ ůĞƐƐ ƚŚĂŶ ϰ ƉƉŵǀ ǁŚŝůĞ ƌĞŵŽǀŝŶŐ KϮ ƚŽ ůĞƐƐ ƚŚĂŶ ϭϬϬ ƉƉŵǀ͘ D ƐLJƐƚĞŵƐ ŐĞŶĞƌĂůůLJ ƌĞƋƵŝƌĞ Ă ƌĞĐůĂŝŵĞƌ ƚŽ ƌĞŵŽǀĞ ĚĞŐƌĂĚĞĚ ƉƌŽĚƵĐƚƐ ĨƌŽŵ ĐŝƌĐƵůĂƟŽŶ͘ dLJƉŝĐĂů ƐŽůƵƟŽŶ ƐƚƌĞŶŐƚŚ ƌĂŶŐĞƐ ĨƌŽŵ ϭϬ ƚŽ ϮϬ ǁĞŝŐŚƚ й ǁŝƚŚ Ă ŵĂdžŝŵƵŵ ƌŝĐŚ ůŽĂĚŝŶŐ ŽĨ Ϭ͘ϯϱ ŵŽůĞ ĂĐŝĚ ŐĂƐͬŵŽůĞ D ͘ ' Π ŝƐ ĂŶŽƚŚĞƌ ƉƌŝŵĂƌLJ ĂŵŝŶĞ ƚŚĂƚ ƌĞŵŽǀĞƐ KϮ͕ ,Ϯ^͕ K^͕ ĂŶĚ ŵĞƌĐĂƉƚĂŶƐ͘ dLJƉŝĐĂů ƐŽůƵƟŽŶ ƐƚƌĞŶŐƚŚƐ ĂƌĞ ϱϬͲϲϬ ǁĞŝŐŚƚ й͕ ǁŚŝĐŚ ƌĞƐƵůƚ ŝŶ ůŽǁĞƌ ĐŝƌĐƵůĂƟŽŶ ƌĂƚĞƐ ĂŶĚ ůĞƐƐ ĞŶĞƌŐLJ ƌĞƋƵŝƌĞĚ ĨŽƌ ƐƚƌŝƉƉŝŶŐ ĂƐ ĐŽŵƉĂƌĞĚ ǁŝƚŚ D ͘ ' ĂůƐŽ ƌĞƋƵŝƌĞƐ ƌĞĐůĂŝŵŝŶŐ ƚŽ ƌĞŵŽǀĞ ƚŚĞ ĚĞŐƌĂĚĂƟŽŶ ƉƌŽĚƵĐƚƐ͘

Secondary Amines

/Ŷ ĐĞƌƚĂŝŶ ƐŝƚƵĂƟŽŶƐ͕ ƚŚĞ ƐŽůǀĞŶƚ ĐĂŶ ďĞ ͞ĐƵƐƚŽŵŝnjĞĚ͟ ƚŽ ŽƉƟŵŝnjĞ ƚŚĞ ƐǁĞĞƚĞŶŝŶŐ ƉƌŽĐĞƐƐ͘ &Žƌ ĞdžĂŵƉůĞ͕ ĂĚĚŝŶŐ Ă ƉƌŝŵĂƌLJ Žƌ ƐĞĐŽŶĚĂƌLJ ĂŵŝŶĞ ƚŽ D ĐĂŶ ŝŶĐƌĞĂƐĞ ƚŚĞ ƌĂƚĞ ŽĨ KϮ ĂďƐŽƌƉƟŽŶ ǁŝƚŚŽƵƚ ĐŽŵƉƌŽŵŝƐŝŶŐ ƚŚĞ ĂĚǀĂŶƚĂŐĞƐ ŽĨ D ͘ DŽƌĞ ĐŽŵŵŽŶ ŝŶ ƚŽĚĂLJ͛Ɛ ŵĂƌŬĞƚ ŝƐ ƚŚĞ ĂĚĚŝƟŽŶ ŽĨ ƉŝƉĞƌĂnjŝŶĞ ƚŽ D ƐŽůƵƟŽŶƐ ĨŽƌ KϮ ƌĞŵŽǀĂů Žƌ ƉŽƐƐŝďůLJ ĂŶ ĂĐŝĚ ƚŽ ĂŝĚ ŝŶ ƌĞŐĞŶĞƌĂƚŽƌ ƉĞƌĨŽƌŵĂŶĐĞ ĨŽƌ ƚŚĞ ůĞĂŶ ƐŽůǀĞŶƚ͘ DĂŶLJ ƉůĂŶƚƐ ƵƟůŝnjĞ Ă ŵŝdžƚƵƌĞ ŽĨ ĂŵŝŶĞ ǁŝƚŚ ƉŚLJƐŝĐĂů ƐŽůǀĞŶƚƐ͘ ^h>&/EK> ŝƐ Ă ůŝĐĞŶƐĞĚ ƉƌŽĚƵĐƚ ĨƌŽŵ ^ŚĞůů Kŝů WƌŽĚƵĐƚƐ ƚŚĂƚ ĐŽŵďŝŶĞƐ ĂŶ ĂŵŝŶĞ ǁŝƚŚ Ă ƉŚLJƐŝĐĂů ƐŽůǀĞŶƚ͘ ĚǀĂŶƚĂŐĞƐ ŽĨ ƚŚŝƐ ƐŽůǀĞŶƚ ĂƌĞ ŝŶĐƌĞĂƐĞĚ ŵĞƌĐĂƉƚĂŶ ƉŝĐŬƵƉ͕ ůŽǁĞƌ ƌĞŐĞŶĞƌĂƟŽŶ ĞŶĞƌŐLJ͕ ĂŶĚ ƐĞůĞĐƟǀŝƚLJ ƚŽ ,Ϯ^͘

Choosing the Best Alternative

dŚĞ ƐĞĐŽŶĚĂƌLJ ĂŵŝŶĞ ƌĞŵŽǀĞƐ ďŽƚŚ KϮ ĂŶĚ ,Ϯ^ ďƵƚ ŐĞŶĞƌĂůůLJ ƌĞƋƵŝƌĞƐ ŚŝŐŚĞƌ ƉƌĞƐƐƵƌĞ ƚŚĂŶ D ƚŽ ŵĞĞƚ ŽǀĞƌŚĞĂĚ ƐƉĞĐŝĮĐĂƟŽŶƐ͘ ĞĐĂƵƐĞ ŝƐ Ă ǁĞĂŬĞƌ ĂŵŝŶĞ ƚŚĂŶ D ͕ ŝƚ ƌĞƋƵŝƌĞƐ ůĞƐƐ ĞŶĞƌŐLJ ĨŽƌ ƐƚƌŝƉƉŝŶŐ͘ dLJƉŝĐĂů ƐŽůƵƟŽŶ ƐƚƌĞŶŐƚŚ ƌĂŶŐĞƐ ĨƌŽŵ Ϯϱ ƚŽ ϯϱ ǁĞŝŐŚƚ й ǁŝƚŚ Ă ŵĂdžŝŵƵŵ ƌŝĐŚ ůŽĂĚŝŶŐ ŽĨ Ϭ͘ϯϱ ŵŽůĞͬŵŽůĞ͘ /W ŝƐ Ă ƐĞĐŽŶĚĂƌLJ ĂŵŝŶĞ ƚŚĂƚ ĞdžŚŝďŝƚƐ ƐŽŵĞ ƐĞůĞĐƟǀŝƚLJ ĨŽƌ ,Ϯ^ ĂůƚŚŽƵŐŚ ŝƚ ŝƐ ŶŽƚ ĂƐ ƉƌŽŶŽƵŶĐĞĚ ĂƐ ĨŽƌ ƚĞƌƟĂƌLJ ĂŵŝŶĞƐ͘ /W ĂůƐŽ ƌĞŵŽǀĞƐ K^͘ ^ŽůƵƟŽŶƐ ĂƌĞ ůŽǁ ŝŶ ĐŽƌƌŽƐŝŽŶ ĂŶĚ ƌĞƋƵŝƌĞ ƌĞůĂƟǀĞůLJ ůŽǁ ĞŶĞƌŐLJ ĨŽƌ ƌĞŐĞŶĞƌĂƟŽŶ͘ dŚĞ ŵŽƐƚ ĐŽŵŵŽŶ ĂƉƉůŝĐĂƟŽŶƐ ĨŽƌ /W ĂƌĞ ŝŶ ƚŚĞ /WΠ ĂŶĚ ^h>&/EK>Π ƉƌŽĐĞƐƐĞƐ͘

Tertiary Amines ƚĞƌƟĂƌLJ ĂŵŝŶĞ ƐƵĐŚ ĂƐ D ŝƐ ŽŌĞŶ ƵƐĞĚ ƚŽ ƐĞůĞĐƟǀĞůLJ ƌĞŵŽǀĞ ,Ϯ^͕ ĞƐƉĞĐŝĂůůLJ ĨŽƌ ĐĂƐĞƐ ǁŝƚŚ Ă ŚŝŐŚ KϮ ƚŽ ,Ϯ^ ƌĂƟŽ ŝŶ ƚŚĞ ƐŽƵƌ ŐĂƐ͘ KŶĞ ďĞŶĞĮƚ ŽĨ ƐĞůĞĐƟǀĞ ĂďƐŽƌƉƟŽŶ ŽĨ ,Ϯ^ ŝƐ Ă ůĂƵƐ ĨĞĞĚ ƌŝĐŚ ŝŶ ,Ϯ^͘ D ĐĂŶ ƌĞŵŽǀĞ ,Ϯ^ ƚŽ ϰ ƉƉŵ ǁŚŝůĞ ŵĂŝŶƚĂŝŶŝŶŐ Ϯй Žƌ ůĞƐƐ KϮ ŝŶ ƚŚĞ ƚƌĞĂƚĞĚ ŐĂƐ͕ ƚŚƵƐ ƵƐŝŶŐ ƌĞůĂƟǀĞůLJ ůĞƐƐ ĞŶĞƌŐLJ ĨŽƌ ƌĞŐĞŶĞƌĂƟŽŶ ƚŚĂŶ ƚŚĂƚ ĨŽƌ ͘ ,ŝŐŚĞƌ ǁĞŝŐŚƚ ƉĞƌĐĞŶƚ ĂŵŝŶĞ ĂŶĚ ůĞƐƐ KϮ ĂďƐŽƌďĞĚ ƌĞƐƵůƚƐ ŝŶ ůŽǁĞƌ ĐŝƌĐƵůĂƟŽŶ ƌĂƚĞƐ ĂƐ ǁĞůů͘ dLJƉŝĐĂů ƐŽůƵƟŽŶ ƐƚƌĞŶŐƚŚƐ ĂƌĞ ϰϬͲϱϬ ǁĞŝŐŚƚ й ǁŝƚŚ Ă ŵĂdžŝŵƵŵ ƌŝĐŚ ůŽĂĚŝŶŐ ŽĨ Ϭ͘ϱϱ ŵŽůĞͬŵŽůĞ͘ ĞĐĂƵƐĞ D ŝƐ ŶŽƚ ƉƌŽŶĞ ƚŽ ĚĞŐƌĂĚĂƟŽŶ͕ ĐŽƌƌŽƐŝŽŶ ŝƐ ůŽǁ ĂŶĚ Ă ƌĞĐůĂŝŵĞƌ ŝƐ ƵŶŶĞĐĞƐƐĂƌLJ͘ KƉĞƌĂƟŶŐ ƉƌĞƐƐƵƌĞ ĐĂŶ ƌĂŶŐĞ ĨƌŽŵ ĂƚŵŽƐƉŚĞƌŝĐ͕ ƚLJƉŝĐĂů ŽĨ ƚĂŝů ŐĂƐ ƚƌĞĂƟŶŐ ƵŶŝƚƐ͕ ƚŽ ŽǀĞƌ ϭ͕ϬϬϬ ƉƐŝĂ͘

'ŝǀĞŶ ƚŚĞ ǁŝĚĞ ǀĂƌŝĞƚLJ ŽĨ ŐĂƐ ƚƌĞĂƟŶŐ ŽƉƟŽŶƐ͕ Ă ƉƌŽĐĞƐƐ ƐŝŵƵůĂƚŽƌ ƚŚĂƚ ĐĂŶ ĂĐĐƵƌĂƚĞůLJ ƉƌĞĚŝĐƚ ƐǁĞĞƚĞŶŝŶŐ ƌĞƐƵůƚƐ ŝƐ Ă ŶĞĐĞƐƐŝƚLJ ǁŚĞŶ ĂƩĞŵƉƟŶŐ ƚŽ ĚĞƚĞƌŵŝŶĞ ƚŚĞ ďĞƐƚ ŽƉƟŽŶ͘ WƌŽDĂdžΠ ŚĂƐ ďĞĞŶ ƉƌŽǀĞŶ ƚŽ ĂĐĐƵƌĂƚĞůLJ ƉƌĞĚŝĐƚ ƌĞƐƵůƚƐ ĨŽƌ ŶƵŵĞƌŽƵƐ ƉƌŽĐĞƐƐ ƐĐŚĞŵĞƐ͘ ĚĚŝƟŽŶĂůůLJ͕ WƌŽDĂdž ĐĂŶ ƵƟůŝnjĞ Ă ƐĐĞŶĂƌŝŽ ƚŽŽů ƚŽ ƉĞƌĨŽƌŵ ĨĞĂƐŝďŝůŝƚLJ ƐƚƵĚŝĞƐ͘ dŚĞ ƐĐĞŶĂƌŝŽ ƚŽŽů ŵĂLJ ďĞ ƵƐĞĚ ƚŽ ƐLJƐƚĞŵĂƟĐĂůůLJ ǀĂƌLJ ƐĞůĞĐƚĞĚ ƉĂƌĂŵĞƚĞƌƐ ŝŶ ĂŶ ĞīŽƌƚ ƚŽ ĚĞƚĞƌŵŝŶĞ ƚŚĞ ŽƉƟŵƵŵ ŽƉĞƌĂƟŶŐ ĐŽŶĚŝƟŽŶƐ ĂŶĚ ƚŚĞ ĂƉƉƌŽƉƌŝĂƚĞ ƐŽůǀĞŶƚ͘ dŚĞƐĞ ƐƚƵĚŝĞƐ ĐĂŶ ĚĞƚĞƌŵŝŶĞ ƌŝĐŚ ůŽĂĚŝŶŐ͕ ƌĞďŽŝůĞƌ ĚƵƚLJ͕ ĂĐŝĚ ŐĂƐ ĐŽŶƚĞŶƚ ŽĨ ƚŚĞ ƐǁĞĞƚ ŐĂƐ͕ ĂŵŝŶĞ ůŽƐƐĞƐ͕ ƌĞƋƵŝƌĞĚ ĐŝƌĐƵůĂƟŽŶ ƌĂƚĞ͕ ƚLJƉĞ ŽĨ ĂŵŝŶĞ Žƌ ƉŚLJƐŝĐĂů ƐŽůǀĞŶƚ͕ ǁĞŝŐŚƚ ƉĞƌĐĞŶƚ ŽĨ ĂŵŝŶĞ͕ ĂŶĚ ŽƚŚĞƌ ƉĂƌĂŵĞƚĞƌƐ͘ WƌŽDĂdž ĐĂŶ ŵŽĚĞů ǀŝƌƚƵĂůůLJ ĂŶLJ ŇŽǁ ƉƌŽĐĞƐƐ Žƌ ĐŽŶĮŐƵƌĂƟŽŶ ŝŶĐůƵĚŝŶŐ ŵƵůƟƉůĞ ĐŽůƵŵŶƐ͕ ůŝƋƵŝĚ ŚLJĚƌŽĐĂƌďŽŶ ƚƌĞĂƟŶŐ͕ ĂŶĚ ƐƉůŝƚ ŇŽǁ ƉƌŽĐĞƐƐĞƐ͘ /Ŷ ĂĚĚŝƟŽŶ͕ WƌŽDĂdž ĐĂŶ ĂĐĐƵƌĂƚĞůLJ ŵŽĚĞů ĐĂƵƐƟĐ ƚƌĞĂƟŶŐ ĂƉƉůŝĐĂƟŽŶƐ ĂƐ ǁĞůů ĂƐ ƉŚLJƐŝĐĂů ƐŽůǀĞŶƚ ƐǁĞĞƚĞŶŝŶŐ ǁŝƚŚ ƐŽůǀĞŶƚƐ ƐƵĐŚ ĂƐ ŽĂƐƚĂů 'ZΠ͕ ŵĞƚŚĂŶŽů͕ ĂŶĚ EDW͘ &Žƌ ŵŽƌĞ ŝŶĨŽƌŵĂƟŽŶ ĂďŽƵƚ WƌŽDĂdž ĂŶĚ ŝƚƐ ĂďŝůŝƚLJ ƚŽ ĚĞƚĞƌŵŝŶĞ ƚŚĞ ĂƉƉƌŽƉƌŝĂƚĞ ƐŽůǀĞŶƚ ĨŽƌ Ă ŐŝǀĞŶ ƐĞƚ ŽĨ ĐŽŶĚŝƟŽŶƐ͕ ĐŽŶƚĂĐƚ ƌLJĂŶ ZĞƐĞĂƌĐŚ Θ ŶŐŝŶĞĞƌŝŶŐ͘

WƌŽDĂdžΠ ƉƌŽĐĞƐƐ ƐŝŵƵůĂƟŽŶ ƐŽŌǁĂƌĞ ďLJ ƌLJĂŶ ZĞƐĞĂƌĐŚ Θ ŶŐŝŶĞĞƌŝŶŐ͕ /ŶĐ͘ ŶŐŝŶĞĞƌŝŶŐ ^ŽůƵƟŽŶƐ ĨŽƌ ƚŚĞ Kŝů͕ 'ĂƐ͕ ZĞĮŶŝŶŐ Θ ŚĞŵŝĐĂů /ŶĚƵƐƚƌŝĞƐ͘ ƐĂůĞƐΛďƌĞ͘ĐŽŵ ǁǁǁ͘ďƌĞ͘ĐŽŵ ϵϳϵ ϳϳϲͲϱϮϮϬ h^ ϴϬϬ ϳϳϲͲϱϮϮϬ Select 71 at www.HydrocarbonProcessing.com/RS

Control

LARRY O’BRIEN, CONTRIBUTING EDITOR Larry.Obrien@fieldbus.org

What’s new with FOUNDATION Fieldbus—Part 2 Remote operations management (ROM)—management of automation assets and resources that are geographically dispersed—is one of the fastest growing segments of the process automation business (FIG. 1). At present, the ROM segment is plagued with a high degree of customization, solutions that are not easily configurable, and a “break-and-fix” mentality when it comes to asset management. Beginning in 2007, the Fieldbus Foundation began a new project that would extend the functionality and infrastructure of FOUNDATION fieldbus to remote applications through remote I/O and wired HART technologies. The project was expanded to include leading industrial wireless networks such as ISA 100.11a and WirelessHART. The overall FOUNDATION ROM specification is nearly complete, and ready to extend capabilities to manage data from a limitless range of devices in some of the most unforgiving applications.

New technology development: FOUNDATION for ROM. FOUNDATION for ROM allows users to implement a true predictive and proactive maintenance strategy for remote assets that could not be previously supported. Data from devices on multiple networks, both wired and wireless, can be brought into the FOUNDATION fieldbus infrastructure. The infrastructure provides a single environment to manage diagnostic data, alarms and alerts, data quality, control in the field capability, and object-oriented block structure.

FOUNDATION for ROM has the potential to address many upstream applications, such as oil fields, offshore-platform automation, oil and gas pipelines, water-treatment centers and distribution networks, and even original equipment manufacturer skid-mounted applications. The upstream oil and gas and water-treatment industries are the two fastest growing industries in process automation, and FOUNDATION for ROM is clearly targeted at these applications.

The Fieldbus Foundation is planning the first round of field demonstrations of ROM technology. The ROM demo team has over 20 sponsors, and the first live demo will be at Petrobras’ CENPES research facility outside of Rio de Janeiro, Brazil, in April 2013. Several more demos are planned in Europe, the Middle East, India and Japan.

FOUNDATION for SIF. Products incorporating FOUNDA-

TION fieldbus safety instrument were successfully demonstrated in 2008 (FIG. 2). It has taken some time for products to be submitted to the Foundation for testing and registration.

However, there are two pilot projects underway at two different end-user sites. TÜV granted protocol type approval for the Fieldbus Foundation Safety Instrumented Systems specifications in 2006. No changes were made to the fundamental

H1 protocol for implementation in safety instrumented systems (SISs), but additional device diagnostic functions and fault detection capabilities were required.

The specifications outlined by the Fieldbus Foundation comply with the IEC 61508 standard for functional safety of electrical/electronic/programmable safety-related systems requirements up to, and including, safety integrity level 3 (SIL 3). TÜV protocol type approval extends FOUNDATION technology to provide a comprehensive solution for SISs in a wide range of industrial plant applications. The specifications enable suppliers to build FOUNDATION devices in compliance with IEC 61508, and these devices can be certified for use in SISs. What are the benefits of fieldbus at the safety system layer? Over 90% of the causes for a process safety system failure are due to the failure of field devices. A safety system should address total safety needs by checking the health of the I/O, field devices and valves. The system should also incorporate components, such as sensor validation, environmental condition monitoring for conditions that can cause sensor degradation and impulse-line blockage monitoring.

FOUNDATION for ROM device

FOUNDATION infrastructure for data management and diagnostic information Transducer blocks

Transducer blocks

Transducer blocks

Transducer blocks

Diagnostic and instrument data

Diagnostic and I/O data

Diagnostic and instrument data

Diagnostic and instrument data

Diagnostic and instrument data

H1

Conventional I/O

HART I/O

WirelessHART

ISA100.11a

FIG. 1. Devices and communication systems with ROM.

PFDavg distribution over 8,917 SIFs 65.43% final element 8.52% logic solver 26.05% sensor

FIG. 2. Probability of failure for safety instrumented function (SIF) in the field.

Hydrocarbon Processing | DECEMBER 2012 35

Control Common-cause failures of electronic components are frequently due to environmental conditions. Many electronic device failures are sourced to elevated humidity and temperature, which should be monitored closely. Sensor calibration is also becoming an integral part of safety systems. FOUNDATION Fieldbus allows for remote monitoring, diagnostics and validation.

Development Services Provider program. The Fieldbus

Foundation launched the FOUNDATION Development Services Provider (DSP) program to assist automation equipment suppliers preparing to design and manufacture products incorporating FOUNDATION Fieldbus technology (FIG. 3).

The DSP program is intended to provide access to qualified development services providers with the expertise to make fieldbus solutions a reality. Qualified DSP participants must

FIG. 3. Logo of FOUNDATION Development Services Providers.

ensure that they have the tools, training and experience necessary to support a wide range of FOUNDATION fieldbus development projects. Services that can be qualified in the FOUNDATION DSP program include H1 and high-speed ethernet (HSE) fieldbus device development services, as well as host system services.

The DSP program is a resource for all companies wishing to design, develop, manufacture or sell FOUNDATION Fieldbus devices. A FOUNDATION DSP is a company or individual that has met the Fieldbus Foundation’s standards for tools, training and experience to provide services for the development and registration of Foundation products. These individuals or companies provide extraordinary services and solutions to their customers and have earned the distinct honor of being a DSP. The DSP program was created in response to a need recognized by the Fieldbus Foundation within the global automation industry to provide a list of competent service vendors that can help get Foundation products to market quickly. The foundation, which is directed by its membership, receives many questions regarding qualified third-party services to help with the development of Foundation devices. Because of this demand, the FOUNDATION DSP Program was created.

AG 181 System Engineering Guide. Perhaps the “best kept secret” is the AG 181 System Engineering Guide, revision 3.2.

The latest version of the AG 181 guide can be downloaded. It contains the distilled wisdom of many of the world’s leading experts from the engineering and construction world to end users, systems integrators, educators and suppliers. AG 181 offers many good pointers on how to do a fieldbus project right the first time. It is an essential part of the toolbox of any FOUNDATION Fieldbus professional. If you already have an older version, this new version will look more streamlined, and it contains several new sections, along with rewrites of old sections.

You can download AG 181 from the website at www.fieldbus. org under End User Resources/Technical References.

Further resources. Aside from the FCTP certified training partner and AG 181, the Foundation also offers free end-user seminars throughout the world every year. You can also check out the LinkedIn Discussion area, Blog and YouTube channel.

The Foundation has recently uploaded some new videos on best practices for fieldbus wiring and cable installation. The Foundation’s goal in the coming year is to make things easier for end users and to get the right information in the hands of people that need it.

End of series. Part 1, November 2012.

LARRY O’BRIEN joined the Fieldbus Foundation as Global Marketing Manager in April 2011. Prior to his job at the Foundation, he was research director for process automation at ARC Advisory Group, where he began work in 1993. As an industry analyst and market researcher, he covered the topics of process fieldbus, distributed-control systems, process safety, automation services business and intelligent field instruments. Mr. O’Brien has authored or co-authored numerous market forecast reports, strategic-level advisory reports and white papers for ARC and its clients, including all the major process automation suppliers.

He holds a BA degree from the University of Massachusetts at Lowell.

36

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| Special Report PLANT DESIGN AND ENGINEERING In the high-priced, fast-paced capital project environment, failure is costly, while zero-defect work processes are highly valued. By understanding and applying best practices, companies can achieve billion-dollar advantages in project cost and quality. This monthâ&#x20AC;&#x2122;s special report articles focus on new tools and resources that can be successfully applied to major capital projects.

The laser scan of a process facility was created with Leica Geosystems hardware and software plus Intergraph Process, Power & Marineâ&#x20AC;&#x2122;s SmartPlant Review. Leica Geosytems and Intergraph are part of Hexagon.

Special Report

Plant Design and Engineering V. DHOLE and R. BECK, Aspen Technology Inc., Burlington, Massachusetts

How do innovations and best practices transform process engineering?

Chemical process simulators were first introduced to the market in the late 1970s and early 1980s. Beginning with that original modeling breakthrough, process engineering has undergone significant transformation over the years, catalyzed by advances and innovation in software, both within individual disciplines and also in the integration across the workflow. This continuous evolution has created tremendous value for many companies, resulting in capital and energy savings, increased safety and reliability, and optimized designs with dramatic improvements in engineering quality and productivity.

This article outlines specific innovations and best practices, highlights examples of recent successes in the industry, and examines new approaches that are presenting additional opportunities for change in process engineering practice. The examples offered here span the asset-creation lifecycle, including R&D, early feasibility studies, conceptual engineering, basic engineering, equipment design, economic evaluation, energy management, debottlenecking and continuous improvement, and engineering support to manufacturing and planning.

A common aspect of all these examples is the huge impact that cross-discipline integration of modeling and analysis tools have on the selection of the best design options, the overall quality of the designs, and the safe and profitable operation of process plants. The ability to achieve superior energy and environmental performance while, at the same time, saving both capital and operating expense would not be possible without the capability of the models to rapidly analyze many alternative solutions and present design and cost tradeoffs to decision-makers. This is critical, as companies across the globe are facing an increasingly interconnected and highly competitive environment.

The process optimization opportunity. Process engineer-

ing plays a critical role across the entire asset lifecycle—development, design, construction, debottlenecking and operations.

At the front end, process engineering decisions determine and constrain the ultimate economics of a facility (FIG. 1). In operations, process engineering decisions solve throughput, yield, regulatory and performance issues.

Given their highly varied role, process engineers benefit from interactions with other engineering and operational functions and disciplines on a daily basis. The exchange of ideas, recommendations, designs, analyses, plant data and process models of various kinds support optimizing increasingly complex designs and operations. By considering a broader range

of ideas, companies are able to achieve improved asset performance, reduced costs, and increased safety and reliability.

Unfortunately, within many organizations, communication between engineering disciplines and with other functions is manual, sequential and inefficient. Understanding of the current state of the asset and opportunities for improvement are not consistently shared and executed across the groups. Organizational “silos” hold the expertise and data of each group and discipline largely within the group; this expertise is shared with other groups only after a design is “released,” or on a case-bycase basis, when it is important. This leads to significant loss of opportunitiesm, since ideas developed in one group are not fully exploited by other groups. Furthermore, the sequential nature of the interactions between engineering groups limits the screening of multiple alternatives during design and manufacturing, leading to suboptimal choices.

This sequential workflow results in a significant loss of opportunity in capital, energy and operating costs, and a missed chance to improve safety and reliability, which amounts to hundreds of billions of dollars per year in lost value. Improving this information-sharing and workflow presents a compelling opportunity to help asset owners and engineering companies to actualize the lost opportunities through a clear understanding of current asset performance and identification of optimum improvement opportunities that can be consistently executed across the lifecycle.

What follows is an examination of the journey of process engineering over the last three decades and the exciting innovations driving its evolution.

Traditional front-end loading challenge Ability to influence cost

Cashflow

Integrated conceptual engineering Total cost established Startup Feasibility, concept and basic design

Procurement Permitting Design and construction

Commissioning

Enhanced documentation, commission and qualification

FIG. 1. Impact of integrated economics on capital projects.

Hydrocarbon Processing | DECEMBER 2012 39

Plant Design and Engineering Impact of the desktop revolution. Following the introduc-

tion of process simulators (first on mainframes and mini-computers), personal computer (PC) price/performance was the next major breakthrough.

This had a dramatic impact on process engineering practice in the 1980s and 1990s. It lowered the barrier-to-entry to automate engineering calculations and democratized the ability to model and analyze an asset through process simulation and modeling.

Process engineers play a key part in the conceptual engineering workflow.

Their ability to model and optimize processes is at the core of value creation from the entire integrated workflow throughout the asset lifecycle—from conceptual design to operations.

The steady increase of PC power to solve bigger simulation models quickly moved the simulators from mainframes to each engineer’s PC. The evolving Microsoft Windows user environment spurred an evolution in ease of use of the models with graphical user interfaces, making them more accessible to a broader range of chemical engineers.

This accessibility has enabled process engineers working on plant problems to quickly establish an understanding of the current asset performance and rapidly consider improvement opportunities through the modeling of “what-if ” scenarios. Expanded access to plant data and to manufacturing and planning tools helps process engineers translate improvement ideas into real benefits for the asset owners.

In parallel, desktop environments also made engineering design, cost estimation and analysis tools widely available and easier to adopt, enabling greater opportunities for idea creation and collaboration across disciplines. Desktop environments ultimately helped improve performance and increase productivity.

Estimated size 280

$36 million

Stages

5% error in VLE $18 million wasted

140

$18 million

5% error

Accurate VLE Relative volatility

FIG. 2. Importance of accurate physical properties: Estimating the cost of a close-boiling distillation column.

40 DECEMBER 2012 | HydrocarbonProcessing.com

However, the authors have observed that, despite all of these democratizing trends, there is still a huge opportunity for all organizations to take advantage of these powerful modeling capabilities. To break through this barrier, we have conducted extensive usability studies and introduced radically new user interface concepts into several modeling tools, and we are continuing to do so across the gamut of engineering optimization products. Of this breakthrough user environment, BP Chemicals’ Dr. Godwin Tongo reports, “The new paradigm has provided us with a big leap in flexibility and ease of use, to enhance and optimize our engineering productivity.” 1 Evolution of user interface and workflow paradigms has continued to accelerate, catalyzed by new innovations in software, hardware and mobile environments.

Convergence of modeling approaches. Another related area of improvement involves the convergence of steady-state modeling with dynamic modeling tools and the integration of sequential modeling with equation-oriented solution approaches. This has great significance, with the timeconsuming efforts to build dynamic models and equation-oriented models for a complex process being overcome through building models, first in the steady-state mode and then reusing and building on them.

The ability to model processes dynamically is required to address the increasing complexity of safety, startup and quality challenges in highly optimized, large and integrated process plants, as well as for effective modeling of sequential batch units within process plants.

A recent example that demonstrates the power of this approach is the use of dynamic modeling together with relief system analysis tools for more accurate relief load and flare system analysis. This results in significant savings in capital costs related to flare capacity.2 Physical properties as innovation in process optimization.

Web and software evolutions have enabled several areas of core chemical engineering innovation that provide the foundation for process modeling and optimization. Such innovations have been an integral part of achieving optimization benefits.

Today, a large and expanding set of highly accurate thermophysical properties is accessible to modelers. The example of a close-boiling distillation column (FIG. 2) provides a clear picture of the value of better thermophysical property characterization. A 5% error in vapor-liquid equilibrium (VLE) predictions can result in 100% error in capital cost estimation for the distillation column, which is a major capital item. Therefore, accurate physical properties are a key input parameter for reducing project capital and technical risk.

Availability of physical properties data has always been a challenge in developing a new process or equipment design.

Innovations in this area continue to accelerate engineering efficiency while improving the accuracy and reliability of model predictions and equipment sizing.

New optimization algorithms have continued to expand the scope and impact of process optimization. Improved analysis

Plant Design and Engineering and visualization tools help engineers understand complex phenomena, enabling the development of more efficient processes. Continued focus on these innovations will be critical for value creation through process optimization.

Using this innovation, Huntsman Chemical reported a reduction of 25% in energy intensity5; Honam Petrochemicals saw energy savings of 17.5% with the integrated conceptual engineering approach6; and S-Oil reported savings of $39 MM with payback of less than one year.7

Optimizing engineering through collaboration. In addition to innovations in process engineering, another aspect critOptimizing support to manufacturing and planning. A ical for value creation is collaboration among groups and dissignificant part of process engineering at operating companies ciplines to consider cost and energy parameters in the designs. involves supporting manufacturing and supply chain activities The traditional workflow for conceptual engineering today to troubleshoot and optimize assets. One of the key challenges is sequential. During conceptual engineering, the main objecis that engineering, manufacturing and supply chain teams do tive is to screen multiple design alternatives to ensure that an not share a common understanding of the current state of the optimum design has been selected. A process engineer typically asset and opportunities for improvements. As a result, initiadevelops these alternatives using a process simulation tool. The tives to improve performance are often developed in silos and, most promising alternatives are then passed on to equipment in some cases, they compete with each other. (e.g., heat exchanger) specialists to size and design the equipThe process engineer’s focus is on understanding the proment. The equipment specialist develops preliminary equipcess and predicting its performance. However, this is not shared ment designs and passes these to cost estimators. This sequence effectively with the stakeholders in the manufacturing and supof tasks may take several days or even weeks to complete. ply chain. Communication tends to be ad hoc through a variety The sequential nature of the workflow slows down the of mechanisms including emails, Excel spreadsheets, models, overall process and limits the number of design alternatives drawings and face-to-face meetings, among others. This prethat can be evaluated in the short window of opportunity vents complete alignment across the key disciplines and, more available for conceptual engineering. One consequence is importantly, results in lost opportunities for the asset owners. that economics and adequate equipment options are not conToday, one may reuse a process model of the asset for what-if sidered early enough. The result is suboptimal designs and analysis, decision support and optimization of the asset. A prolost opportunities. cess model encapsulates knowledge of the asset and provides the ability to reliably predict asset behavior. One approach to FIG. 3 shows the integrated conceptual engineering workenable plant personnel to access the models is to use an Excelflow that is now possible today. The integrated approach probased or real-time interface to shield model complexity. vides access to equipment modeling, sizing and economic Another opportunity involves reuse of process modeling analysis capabilities inside the simulation environment simulinformation in production planning. This ensures that the protaneously, in a manner that a process engineer can use without duction plan is based on accurate information of the current being a specialist in design and estimating. state of the operation and can correctly predict the optimiThis integrated approach allows the process engineer to zation potential. Another area of innovation is the provision rapidly screen multiple alternatives in a matter of hours inof real-time data for viewing and analysis within the process stead of days or weeks. This saves 10%–30% capital and energy model itself. This provides a “one-stop shop” for troubleshootcompared to the traditional approach, since multiple alternaing operational issues. tives can be rapidly screened and designs can be optimized Saudi Aramco has been using a combination of process early. BASF believes that its net benefits from the broad use of models and production planning models—referred to as the process simulation and conceptual engineering, in a comprehensive way, have been between 10% and 30% of installed capital cost of projects.3 Additionally, Dow Chemical reported savings of $65 million (MM) using integrated simulation and equipment modeling. The approach enabled identification of a debottlenecking opportunity in a chemical process while diagnosing and fixing a specific operational problem.4 Another newly accessible integrated workflow enables activated energy analysis directly from within the simulation model, so that promising conceptual options for energy savings can be identified during process design. Activated energy analysis, with equipment and cost analysis, enables process engineers to quickly identify the most promising options within their familiar process simulation FIG. 3. Today’s integrated conceptual engineering workflow. user environment.

Hydrocarbon Processing | DECEMBER 2012 41

Plant Design and Engineering

Support manufacturing and supply chain

Reuse process models for operations decision

Reuse process models for planning decision

R&D and conceptual engineering

Safety and controllability analysis

Process modeling and analysis

Analyze economic performance

Basic engineering

Develop detailed equipment designs

Develop basic design package

Analyze detailed costs

Detailed engineering

Develop detailed plant design

FIG. 4. An overview of today’s integrated process engineering workflow.

Integrated Oil and Gas Model—to optimize exploration and production assets. This model is used for daily optimization and for planning purposes. Saudi Aramco has reported benefits of a 3%–8% increase in production, a 3%–5% reduction in energy usage, and a 50%–70% decrease in planning time.8 New learning paradigms. A large number of new engineers

are joining the process industry. This generation of engineers is rapidly changing the composition of the process industry workforce. There are considerable challenges in transferring an organization’s intellectual property and knowledge, which are tied up in sophisticated models, to this new wave of engineers.

Discussions with key users have highlighted that, beyond the use of software, learning is also integrally tied to becoming experienced in discipline practices, such as developing conceptual design, flare systems analysis, and capital project estimating (among others); as well as in effectively training organizations to use the integrated workflows correctly. The software industry has responded to this need by introducing effective search tools and online training for engineering tools.

The prize for process optimization. An overview of the

integrated process engineering workflow achievable today is shown in FIG. 4. The overall benefits of adopting a wellintegrated process engineering workflow are a 10%–30% capital and operating cost savings due to inherently better designs, a 10%–20% improvement in engineering quality, and a 10%–20% improvement in engineering efficiency. The integrated workflow enables process optimization and complements innovations in process engineering.

Process engineers play a key part in this workflow because of their understanding of the process. Their ability to model and optimize processes is at the core of value creation from the entire integrated workflow throughout the asset lifecycle— from conceptual design to operations.

Considering the opportunities ahead. What are the key opportunities for process engineering? New innovations will continue to broaden the scope for process optimization through new, more accurate models for physical properties 42 DECEMBER 2012 | HydrocarbonProcessing.com

and process equipment, and through new optimization innovations. Further integration will enable process modelers to have better vision in optimizing process schemas against more parameters, including economics and sustainable operations.

Standalone design and analysis, such as equipment sizing and detailed equipment design, can be expected to play a more prominent role in the simulation modeling world.

Advanced collaboration within engineering tools, combined with advances in engineering databases, will provide opportunities to better integrate global teams.

This journey is already beginning with the introduction of new process modeling search tools. IT innovations such as social networking, mobile and cloud computing platforms, and search technologies will transform process engineering once again.

Breakthroughs here can be expected to increase access to process modeling tools, reduce the learning barrier, and make optimization choices more visual and transparent. Web and cloud innovations will integrate people in addition to facilitating the integration of software applications. Process engineers will play an even more important role in this transformation due to their focus on understanding, modeling and optimizing processes.

LITERATURE CITED Press release, AspenTech, March 6, 2012.

2 Feliu, J. A., “Assessing Safer Blow-Down Options Using Dynamic Process Simulation,” Inprocess Technology and Consulting Group, February 7, 2012.

3 Polt, A., “Collaborative Conceptual Engineering at BASF,” AspenWorld 2004, Orlando, October 2004.

4 Kolesar, D., “Aspen EDR Helps Troubleshoot Thermosyphon Problems,” AspenTech Global Conference, Boston, May 2010.

5 Smith, B., “Huntsman Saves Millions of Dollars with Energy Efficiency Overhaul at Port Neches, TX,” Chemical Week, April 23, 2010.

6 Park, J.-S., “Site Energy Assessment and Total Site Study,” OPTIMIZE 2011 AspenTech Global Conference, Washington, D.C., May 2011.

7 Kim, J. J., “S-Oil Refinery Energy-Saving Project,” OPTIMIZE 2011 AspenTech Global Conference, Washington D.C., May 2011.

8 Jones, G., J. Savla and D. French, “Integrated Oil & Gas Model,” AspenTech User Conference, Houston, May 2009.

1

DR. VIKAS DHOLE joined Aspen Technology in 1997 and serves as vice president of engineering product management.

His responsibilities include strategy, direction and business performance of the aspenONE Process Engineering suite.

Dr. Dhole previously held a variety of leadership positions in product management, technology development and consulting services. Prior to joining Aspen Technology, Dr. Dhole was technology manager with Linnhoff March Ltd. UK (now part of KBC Ltd.) and a lecturer at the Department of Process Integration at the University of Manchester, UK. Throughout his career, Dr. Dhole has championed innovative technology and software solutions in the areas of conceptual design, energy management and process engineering optimization. He has authored several publications on these topics. Dr. Dhole has a BTech degree in chemical engineering from the Indian Institute of Technology (IIT), Mumbai, India, and a PhD in process integration from the University of Manchester, UK. RON BECK is engineering product marketing manager at Aspen Technology. He has been with Aspen Technology for five years and is the marketing manager for the aspenONE Process Engineering suite. Mr. Beck spent 10 years in an R&D organization that commercialized fluidized bed technologies, enhanced oil recovery methods and environmental technology.

He has 20 years of experience in the development, adoption and marketing of software solutions for engineering and plant management.

He has also been involved with the development of integrated solutions for several global chemical enterprises, as well as Aspen Technology’s economic evaluation products. Mr. Beck is a graduate of Princeton University.

Special Report

Plant Design and Engineering S. SAHA and A. NAIR, Reliance Ports and Terminals Ltd., Reliance Refinery, Jamnagar, India

Intelligent indexing is key to 3D CAD plant modeling Modeling a plant in a three-dimensional (3D) computeraided design (CAD) environment and digitizing of the existing setup are becoming trends due to the immense benefits these features provide to owners and plant operators. They not only bring visualization, but they also provide ample opportunities to all contributors to the project to take preventive actions through model reviews and data analysis.

Indexing is a key activity in CAD modeling. Arbitrary indexing of the models invariably leads to problems, as discussed in this article.

Introduction. CAD supports the entire workflow of all functional groups. Historically, it has benefited the engineering and construction contractor. The benefits come from improved accuracy and constructability, fewer engineering work-hours, lower material surpluses and shorter schedules.1 The utility of the CAD plant is not limited to engineering and construction. Its benefits can be extended to other functional groups like operations, inspection, etc. This article attempts to create awareness of plant indexing methods and explore opportunities for contribution by all functional groups to improve the utility of plant digitization.

The digitization of today’s plant is not limited to assigning location coordinates to graphical components of the plant (FIG. 1). Various developments occur when linking the databases of other functional groups, which eventually increases the utility index of the digital plant.

Improvement in the utility index is not only evident in the project phase, but it is also visible in the entire lifecycle of the plant—such as commissioning, post-commissioning, day-today operation, planned and unplanned shutdowns, maintenance, inspection and revamps.

Organize with indexing. Indexing is the process of organizing the physical area or components of the plant into logical parts. These logics are developed during the initial stages of CAD. Model boundaries are finalized based on process systems and the mobilization of modelers. These boundaries—referred to as CAD areas—are discussed with piping, structural

FIG. 2. Sample CAD index in a typical ISBL unit.

FIG. 1. CAD plant model.

FIG. 3. Refined CAD index with rack in R-series.

Hydrocarbon Processing | DECEMBER 2012 43

Plant Design and Engineering and electrical design groups, as every discipline must follow the same model boundaries.

In a complex containing many plants, it is common to find rack areas with different CAD names beginning with the letters D, H, J, etc. (FIG. 2). However, there are benefits in standardizing the rack CAD areas of all plants to begin with the letter “R” (FIG. 3). In this way, a project manager can focus on these areas to prioritize engineering and procurement efforts and to clarify the design for the construction team. A construction manager can easily identify the rack isometrics from the lot for prompt distribution.

Importance of the indexing method. Once the CAD area is

finalized and deliverables commence, it is not practical to make changes to the CAD area, as this could result in undesirable revisions to deliverables. Therefore, the optimization process for the CAD area must be carried out well in advance. Instead of finalizing CAD area classification based on process systems and mobilized modelers, it is prudent to consider this classification’s influence on all functional groups at various lifecycle stages of the plant.

Plant design and layout are conceptualized and developed in the CAD development stage (FIG. 4). Job division and mobilization of skilled modelers for design development activities are considered major factors for CAD area classification. A small number of CAD areas may result in model allocation difficulties, thus limiting CAD modeler mobilization and ultimately affecting progress. A large number of CAD areas may result in increased

FIG. 4. Number of CAD model files in CAD areas of a typical inside-battery-limits unit.

FIG. 5. Concept of construction work area (CWA).

44 DECEMBER 2012 | HydrocarbonProcessing.com

clashes and interfaces, as well as in design-check instances requiring relevant management tools. Optimization on the number of CAD areas is necessary for efficient CAD development activity.

In the procurement stage, cost benefits are realized from discounts for bulk purchases. Materials are grouped irrespective of their CAD areas to attain maximum discounts. The ideal situation is to begin procurement after engineering completion; however, this is not a practical approach most of the time. The project team must prioritize engineering activities and optimize procurement actions to provide a relevant construction front and make planned progress. A well-thought-out CAD area classification can help the project team set priorities and envisage the construction front.

In the construction stage, the work front depends on the availability of drawings and materials. The available work front is generally divided into various construction work areas (CWAs).

These areas require different types of skilled labor (e.g., rack, compressor, pump, column and reactor area). A carefully developed CAD area classification that takes CWAs into consideration avoids the need to split isometrics into two or three parts.

This can save substantial construction efforts and prevent compilation problems.

Consider a case where piping modeled in a single CAD area is to be constructed from a column overhead to the receiver over the rack (FIG. 5). In such cases, the construction team typically splits the drawings to respective CWAs and distributes them to various contractors.

Such situations end in responsibility distribution problems, especially during hydrotesting or mechanical completion of the system. Commercial justification is needed when the single drawing is billed by more than one contractor. However, a carefully developed CAD area that takes these issues into account will avoid such situations and allow construction managers to focus on priority activities.

Improper indexing can cause a number of difficulties. Cases of arbitrary indexing include the following: • A large number of CAD areas without proper model boundaries. Process logics are usually difficult to memorize, and this results in confusion and drawing splits for construction.2 • CAD areas in multiple physical locations, usually observed in outside-battery-limits racks, with multiple bridges to process units. In such cases, the identification of physical location becomes difficult. Continuation drawing numbers must be reviewed to find the exact location.

FIG. 6. Rack area with CAD indexing issues.

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Plant Design and Engineering • Drawings modeled in different CAD areas. This happens due to a modeling error or overlapping CAD areas, as model boundaries are not always “straight lines.”2 Such cases are usually seen in the incoming and outgoing lines of the rack.

CAD index case study. In one case study, the plant inspection group called for a database structure for tagging the inspection history of lines as a way of developing a future inspection strategy. The plant was experiencing problems with the existing CAD index due to CAD area overlaps and the same area in multiple locations (FIG. 6).

A breakthrough was achieved by restructuring the indexing of the racks with unique index names (UINs). Negative effects on existing deliverables were avoided by mapping the new UINs with the existing CAD index. This approach not only resolved the problem, but it also opened avenues for other functional groups to link their databases to the digital plant.

The entire lifecycle of the plant—i.e., commissioning, maintenance and revamp—are affected by CAD area classification.

A refined CAD area classification can simplify data tagging of all functional groups in the digital plant map. This process may lead to new data interpretation approaches, which may help in structured work plans and controlled job distribution to thirdparty experts. Safety and value-addition initiatives can be easily incorporated at all plants, and information exchange across functional groups creates opportunities to dissolve barriers between them.

Takeaway. Indexing the digital plant is critical for all contribu-

tors to the project, and it has substantial influence on the entire lifecycle of the plant. The active participation of all stakeholders during the process is encouraged to improve the utility indexing of the digital plant. Utility indexing by all functional groups in the lifecycle of the plant indicates that pivotal information exchanges are taking place, thus helping to avoid the side effects of departmentalization.

Proper indexing not only improves the ability to respond to opportunities and challenges, but it also provides the possibility of exploring untapped areas of improvement to achieve accuracy and encourage competitiveness.

LITERATURE CITED Bausbacher, E. and R. Hunt, Process Plant Layout and Piping Design, Prentice Hall, Upper Saddle River, 1994.

2 Beale, R. J., P. Bowers and P. Smith, The Planning Guide to Piping Design, Gulf Publishing Company, Houston, 2010.

1

DR. SUBRATA SAHA is head of the engineering division of Reliance Ports and Terminals Ltd., which is the engineering wing of the Reliance Refinery at Jamnagar, India. He has a wide range of experience in engineering design in the power and hydrocarbon industries. Dr. Saha holds a BTech degree in mechanical engineering from the Indian Institute of Technology in Kharagpur, India, and a PhD from the Indian Institute of Technology in Kanpur, India.

AJAY NAIR is the lead piping engineer at the engineering division of Reliance Ports and Terminals Ltd. at the Reliance Refinery in Jamnagar, India. He has 15 years of industry experience, particularly in refinery and petrochemical CAD environments. Mr. Nair holds a mechanical engineering degree from the L.D. College of Engineering in Gujarat, India.

Predictive solid-liquid, vaporsolid, and vapor-liquid-solid equilibrium calculations.

Good thinking.

Feedback from our users is what inspires us to keep making CHEMCAD better. Many features, like this one, were added to the software as a direct response to user need. That’s why we consider every CHEMCAD user part of our development team.

CAD EM

Engineering advanced

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© 2012 Chemstations, Inc. All rights reserved. | CMS-1789 11/12

Select 158 at www.HydrocarbonProcessing.com/RS

46 DECEMBER 2012 | HydrocarbonProcessing.com

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Get the whole story behind this user-inspired feature and learn more about how CHEMCAD advances engineering at chemstations.com/UserInspired.

Special Report

Plant Design and Engineering B. ANANTHARAMAN, D. CHATTERJEE, S. ARIYAPADI and R. GUALY, KBR, Houston, Texas

Consider coal gasification for liquid fuels production Recent high prices for crude oil and natural gas (outside the US) are spurring increased interest in other conversion technologies, such as coal gasification, to process lower-value hydrocarbon feedstocks into higher value end products.1 FIG. 1 compares the projected prices of crude oil, natural gas and lowrank coals.1,2 Liquid fuels, including gasoline, diesel, naphtha and jet fuel, are usually processed by refining crude oil. Due to the direct distillation, crude oil is the most suited raw material for liquid fuel production. However, with rising crude oil prices and depleting reserves, gas-to-liquids (GTLs) and coal-to-liquids (CTLs) processes are alternative routes used for liquids production.

Natural gas and coal are converted to syngas first, and then the well-proven Fischer-Tropsch (FT) technology is used to convert the syngas to a raw product, which is further upgraded to produce primarily premium diesel, naphtha and jet fuel.

Commercial GTL plants have been operating successfully for many years at various parts of the world, as shown in TABLE 1.

However, the scarcity and premium prices of natural gas at certain geographical locations make coal gasification an economically viable alternative route. Due to faster depleting natural gas reserves and more abundant coal reserves, coal gasification and CTL are solutions to produce liquid fuels over the long term.

FIG. 2 compares the proven reserves of crude oil, coal and gas worldwide.3 It has been estimated that there are over 847 billion tons of proven coal reserves. Accordingly, there are enough coal supplies to last nearly 118 years at present production rates. In contrast, proven oil and gas reserves are equivalent to around 46 to 59 years at present production levels.

Coal reserves are available in almost every country worldwide, with recoverable reserves in 70 countries. The largest reserves are in the US, Russia, China and India. With faster depleting reserves of oil and gas, coal presents an attractive alternative option for making liquid fuels. A new proprietary coal gasification technology uses an advanced design gasifier.a This article integrates technology for coal gasification with FT synthesis and product upgrading units.

Maturity of FT technology. FT technology is a well-proven, mature process, and it is used to convert syngas into clean, high-quality liquid fuels, including ultra-clean diesel and jet fuels. Depending on coal quality and process technology, the CTL process can also yield quantities of naphtha and ammonia as byproducts. The FT process produces superior quality diesel that has virtually no sulfur (< 5 ppm), is very low in aromatic content (< 1%) with a high cetane number (> 70) and good cold-flow characteristics (< 5°C–10°C).4 The FT-derived diesel can be used as blendstock against high-aromatic, low-cetane No. 2 heating oil at a ratio of 1/1 TABLE 1. FT technology in commercial plants Plant name

Capacity, bpd

Plant owner

Secunda CTL

160,000

Sasol

Sasol 2—1980 Sasol 3—1984

Oryx GTL

34,000

Qatar Petroleum—51% Sasol—49%

2007

Escravos GTL

34,000

Chevron Nigeria Limited—75% Nigerian National Petroleum Co.—25%

2013 (forecast)

Ordos, China

24,000

Shenhua Sasol

December 2008

Pearl GTL

140,000

Qatar Petroleum Shell

2011 1993

20

Forecast prices, $/MMBtu

16 12 Crude oil Natural gas Low-rank coal

8 4 0 2005

2010

2015

Year

2020

2025

FIG. 1. Projected price comparisons for crude oil, natural gas and low-rank coal.

2030

Start of production

Bintulu GTL

15,000

Shell

Mossgas, Mossel Bay, SA

47,000

PetroSA—37.5% Statoil—37.5% Lurgi—25%

Jincheng, China

2,500

Jinmei

Operation

Changzhi, China

4,000

Lu’an

Construction

Ordos, China

4,000

Yitai

Operation

Hydrocarbon Processing | DECEMBER 2012 47

Plant Design and Engineering to make onroad diesel. The produced naphtha is highly paraffinic with very low-sulfur, naphthenic and aromatic content; it is suitable as a quality feedstock for conversion into other fuels or cracked to produce ethylene for the polymer industry. FIG. 3 shows the FT process, which has three main processing steps, all of which are commercially proven.5 TABLE 1 lists successful applications of FT technologies in existing commercial CTL and GTL plants.

Variety of liquid products from coal. In addition to syn-

thetic oil and diesel fuels, numerous additional products can be derived from coal, as listed in FIG. 4.6 The CTL process can provide several key benefits, such as: • Yielding ultra-clean, sulfur-free and low-particulates products • Processing at low levels of oxides and nitrogen 300 Gas Coal Oil

250 200 150 100 50 0

Geographical regions worldwide for CTL. There are nu-

merous CTL projects worldwide, and FIG. 6 provides a broad overview of these various CTL projects. Blue-coded locations denote CTL plants in operation, and green-coded units are projects underway. From FIG. 6, it is noted that the majority of CTL projects are concentrated in Asia-Pacific with a significant presence in China, India and Indonesia. There are five operating CTL plants in China (Yitai, Lu’An and JMG are semi-commercial) and two plants in South Africa. There are three CTL projects in India, five in Australasia (Australia and New Zealand), and one in Canada.

Global liquids production. FIG. 7 shows the projection from

South North America America

EU

Former USSR

Middle East

Africa

India

China Asia-Pacific

FIG. 2. Global proven reserves of crude oil, coal and natural gas.

Gaseous products

FT reactor

Coal Biomass

Solids gasification

Step 3. Hydrocracking Methane, alcohols and diesel

Step 1. Syngas generation

Kerosine Product upgrading

Methane Steam/oxygen

Natural gas reforming

Waxy hydrocarbon production

Diesel

Step 2. FT conversion

FIG. 3. Main processing steps of FT process.

Fuels

Diesel fuel

Chemicals Detergents

LPG

Kerosine

Plastics

FischerTropsch Waxes

Steam

Lube oils

Specialty waxes

Electricity

FIG. 4. Variety of liquid products from coal gasification.

48 DECEMBER 2012 | HydrocarbonProcessing.com

C, %

H, %

N, %

S, %

O, %

Cl, %

45

41.6

2.3

1.1

0.3

9.7

0.0

F, %

HHV, kJ/kg

0.0 16,200

TABLE 3. CTL plant production (products and byproducts) and consumption

Slurry phase

Synthesis gas (H2 and CO)

Moisture + Ash, %

Naphtha

Steam generation

Syngas

2009 to 2035 in liquids supply and demand by region.1 From FIG. 7, the Organization for Economic Cooperation and Development (OECD) includes developed nations, while non-OECD includes developing countries. Total use of liquids is similar in the reference, high-oil-price and low-oil-price cases, ranging from 108 million bpd (MM bpd) to 115 MM bpd in 2035, respectively. Although total gross domestic product (GDP) TABLE 2. Coal composition and heating value for low-rank coal

Bio-renewables

Coal

• Reducing carbon dioxide (CO2) emissions through carbon capture and storage (CCS) • Yielding a coal-derived diesel that can be used as clean transportation fuels • Using low-cost coal that is available domestically in appropriate geographical regions.

FIG. 5 illustrates the CO2 emission reductions with CTL diesel through CCS. CO2 emissions are reduced by 5%–12% for CTL diesel with CCS when compared to diesel produced from crude oil.

Fuel cell fuel

Synthetic Synthetic fibers rubbers

FT diesel

14,700 bpd

Cetane number, min: 74–78 Cloud point, max: –10°C to 1°C

Naphtha

5,300 bpd

Octane, RON: 40–45 Reid Vapor Pressure: 8 psi

Power generation

240 MW

Onsite STGs

Compressed CO2

12,700 tpd

> 96 vol%, P = 155 bara, T = 60°C

Gasifier ash

3,700 tpd Plant consumption figures

Raw coal

14,400 tpd

HP oxygen

6,000 tpd

> 99.5 vol%, P = 46 bara, T = 24°C

HP nitrogen

2,900 tpd

> 95 vol%, P = 46 bara, T = 24°C

LP nitrogen

125 tpd

> 95 vol%, P = 9 bara, T = 24°C

Purchased power

100 MW

Imported from OSBL

Natural gas

37 GJ/h LHV

Raw water

Normally no flow

Plant Design and Engineering price case is supported by CTL and GTL technologies becoming more economical. Production levels from unconventional sources such as CTL and GTL are driven largely by price level and the need to compensate for restrictions on economic access to conventional liquid resources in other nations. FIG. 9 shows the projected unconventional liquids production by fuel type.10 From FIG. 9, the projections in unconventional liquids produced from coal tremendously increase from 2008 to 2035. FIG. 10 shows FT liquid fuels production 1990 (historic) to 2030 (projected).11 At high oil prices, CTL looks particularly attractive in countries possessing abundant coal reserves, large energy requirements and inadequate reserves of crude oil and natural gas. From FIG. 10, it is expected that CTL liquid fuels production will be preferred over GTL.

900

120

800

World liquids supply and demand by region, MMbpd

Well-to-wheels emissions, grams of CO2 equivalent per mile

growth is assumed to be the same in all three cases, non-OECD GDP growth is lower in the low-oil-price case and higher in the high-oil-price case, thus changing the shares of global liquids consumed by OECD and non-OECD countries among the three cases. In the reference case, OECD liquids consumption grows to 47.9 MM bpd, while non-OECD liquids use grows to 62.9 MM bpd, in 2035. FIG. 8 shows the projection in unconventional liquids as a share of the total global liquids projection.1 Global 2009 production of liquid fuels from unconventional resources was 4.1 MM bpd, or about 5% of the total liquids production. Production from unconventional sources grows to 10%, 12% and 17% of total world liquids production for the low-oil-price, reference and high-oil-price cases, respectively.

The increased unconventional production in the high-oil-

+63-100%

700

-5-12%

600

-4% Reference: Conventional diesel

500 400 300 -46%

200

-30%

100 0 Diesel from crude oil

CTL diesel w/o CCS

CTL diesel with CCS

CTL diesel with 30% biomass

CTL diesel CCS and 30% biomass

CTL diesel CCS and 15% biomass

Supply

Demand

Non-OECD

80 Non-OPEC 40 Other OPEC OPEC Middle East

OECD

0 2009

Low oil price

Source: Idaho National Laboratory (2007) and US DOE (2009)

FIG. 5. Well-to-wheels emissions of CO2 from diesel.

High oil price

Reference 2035

FIG. 7. Global liquids supply and demand by region.

Baotou 4.3 Mm3/d

600,000 tpy

Great Plains, ND 20,000 bpd Fox Creek, Alberta

Ordos

Irkutsk

Leuna

4,000 bpd

Yitai

Serafimovskiy Mongolia

Lu’An

4,000 bpd

Posco

Assam

JAMG Tata Sasol

3,000 bpd

Geleximco

Jindal Philippines Bumi & Sasol

Waterberg CTL

Mmamabula

SNG

Sasolburg

Projects

Arckaringa Secunda 160,000 bpd

Spitfire Oil

Clinton

Monash Latrobe

Operations L&M Lignite Source: 14th European Round Table on Coal–May 31, 2011, World CTL

FIG. 6. CTL plants and projects worldwide.

Hydrocarbon Processing | DECEMBER 2012 49

Plant Design and Engineering Most of the announced, commercial-scale CTL projects are in China, as shown in FIG. 11.11 With completion of these announced projects, China will be the world CTL leader within the next decade. Many projects are designed to coproduce chemicals, including ammonia. The longer-term development of a global CTL industry may depend on advancements in CO2 sequestration that allow projects to produce fuels with a lower carbon footprint.

20

15

Oil shale GTL CTL Biofuel Extra-heavy oil Bitumen

10

5

0

Low oil price

2009

Reference

High oil price

FT liquid-fuels production, 1,000 bpd

Unconventional resources as a share of total world liquids production, %

CTL process. FIG. 12 is a block-flow diagram of an advanced CTL process. It uses a proprietary gasifier that is integrated with typical FT synthesis and upgrading units.a The gasifier is compatible with a wide range of feedstocks, particularly low-rank coals with high moisture and ash content. This CTL process is briefly summarized here: Coal preparation. Dried, pulverized coal is fed to the pressurized gasifier unit through a system of lock hoppers. The coal feed fluidizes as it enters the gasifier.

Air separation unit. The proprietary CTL process uses oxygen (O2 ) provided by a cryogenic air separation unit (ASU) as the O2 in the gasifier.

Coal gasification. Dried, pulverized coal, oxygen and steam are fed to the proprietary gasifier; coal gasification reactions occur in the resulting fluidized bed in the high-velocity “transport regime.” Steam is added to the gasifier, both as a reactant and as a moderator to control the reaction temperature at about 980°C. Gasifier ash removal system. A proprietary continuous coarse ash depressurization (CCAD) system withdraws the coarse ash from the gasifier and maintains the solids level within the desired range. The ash withdrawn is cooled with boiler feedwater (BFW), depressurized continuously through a number of stages of pressure-letdown devices and routed to an ash silo.

Syngas cooling. The hot syngas exiting the gasifier is cooled in the primary syngas cooler with BFW to produce high-pressure superheated steam.

Particulate control device (PCD). The warm syngas containing fine ash from the syngas cooler flows into the PCD, which is a barrier-filter system to remove particulates. The produced syngas is particulate-free, thus eliminating dirty-water or gray-water systems.

Sour shift. Part of the syngas from the PCD is sent to a saturation column, where the syngas is contacted with recycled condensate (water) to generate steam. This mixture of steam and syngas is sent to the sour-shift reactors. The fraction of total gas that is shifted is set by the desired H2:CO ratio at the inlet of the FT synthesis unit.

COS hydrolysis. The remaining (unshifted) syngas stream is sent through the catalytic carbonyl sulfide (COS) hydrolysis reactor to convert COS to hydrogen sulfide (H2S). The sourshift reactor catalyst also promotes hydrolysis of COS to H2S from the syngas, which eliminates the need for a separate COS

2035

FIG. 8. Unconventional liquids as percentage of total world liquids.

Oil sands/bitumen

Biofuels

CTL

1,000 800

GTL CTL

600 400 200 0 1990

1995

2000

2005

2010 Years

2015

2020

2025

2030

2010 Years

2015

2020

2025

2030

2008

Extra-heavy oil

2035

GTL

Shale oil 0

1 2 3 4 Unconventional liquids production by fuel type, MMbpd

Source: International Energy Outlook 2011

FIG. 9. Projected unconventional liquids production by fuel type.

50 DECEMBER 2012 | HydrocarbonProcessing.com

5

FT liquid fuels production via CTL, 1,000 bpd

FIG. 10. FT liquid-fuels production.

700 600 500

Asia-Pacific Africa

400 300 200 100 0 1990

1995

2000

2005

FIG. 11. FT liquid-fuels production from CTL process.

AD: www.graficadueprint.com Š 2010 Costacurta S.p.A.-VICO

SINCE 1921...

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Within the wide range of Costacurta products you will also find some, described below, that are used specifically in the oil, petrochemical and chemical industries: - RADIAL FLOW AND DOWN FLOW REACTOR INTERNALS; - GAS-LIQUID AND LIQUID-LIQUID SEPARATORS; - ARMOURING OF REFRACTORY, ANTI-ABRASIVE AND ANTI-CORROSIVE LININGS. For more information visit our website or contact the division 'C' components for the oil, petrochemical and chemical industries at tcsc@costacurta.it.

Gas-liquid and liquid-liquid separators

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Plant Design and Engineering

Mercury

hydrolysis reactor for the portion of synTo battery gas that is being shifted.

CO2 COS limit ASU compressor hydrolysis Water recovery. Syngas streams leaving the sour-shift reactor and the COS reCoal O2 blown Syngas Water Sour shift AGRU PCD actor are individually cooled to condense preparation gasifier cooling recovery water from the sour syngas. The water dissolves almost all of the nitrogenous Liquid Gas cleanup Ash H2 prod.

FT FT compounds, chlorides and fluorides pressynthesis upgrading ent along with lesser amounts of CO2 , carGasification/syngas bon monoxide (CO), H2S and COS. This H2 generation Offgas aqueous mixture is removed from the syntreatment gas and recycled to the saturator system.

Mercury removal. The unshifted FT and product syngas stream from the COS reactor is upgrading cooled and combined with the shifted syngas and sent to the mercury removal FIG. 12. Block-flow diagram of CTL process. unit. Elemental and any organic mercury present in the gas are adsorbed by the sulfur-impregnated actiCAPEX +/- 25% vated carbon beds.

Acid-gas removal unit. Syngas leaving the mercury removCoal price +/- 50% al unit enters the acid-gas removal unit (AGRU). The AGR for the CTL plant is required for: Availability +/- 5% • Removing H2S and CO2 from the FT feed syngas from the gasifiers Corporate tax rate +/-10% • Removing CO2 from the reformed FT waste (offgas) -40% -30% -20% -10% 0% 10% 20% 30% 40% • Removing CO2 from reformed and shifted FT waste (offgas).

Change in FT diesel cost, $/bbl CO2 compressor. The combined acid-gas stream recovered FIG. 13. Sensitivity analysis of change in FT diesel cost of production. from the AGRU at a low pressure and slightly above ambient temperature is routed through one or more CO2 compression trains to provide a dense-phase CO2 at about 155 bara. The compressed CO2 is expected to have a purity of > 96 mol% CO2 CTL plant performance data. TABLE 2 summarizes the typical and about 0.5 mol% H2S. coal composition and high heating value for a low-ranked coal used in gasification. TABLE 3 lists production products and conFT synthesis and upgrading. Clean, sulfur-free syngas is sent to the FT reactors to produce hydrocarbon liquid products and sumption for a typical 20,000-bpd CTL plant. reaction water. The light hydrocarbon liquids (condensate), along with liquid hydrocarbon wax removed from the FT reactor, are CTL plant financial data. These assumptions are made in sent to the product-upgrading unit for further processing. The the economic analysis of a CTL plant: product-upgrading unit separately treats the hydrocarbon con• Liquids production capacity = 20,000 bpd densate and hydrocarbon waxy liquid. The hydrocarbon condeno FT diesel = 14,000 bpd sate is mildly hydrotreated to eliminate olefins and oxygenates. o Naphtha = 5,300 bpd The waxy liquid is sent to an isomerization/dewaxing unit to con• Compressed CO2 = 12,700 tpd vert the paraffins into premium-quality distillates. The FT pro• Coal cost = $20/ton = $1.8/MMBtu cess converts the clean syngas into finished products, including • Electricity cost = $100/MWh FT-based diesel, naphtha, kerosine and liquefied petroleum gas.

• Oxygen cost is included in the CAPEX of ASU Offgas treatment. The offgas from FT synthesis contain• Operations and maintenance = 3.5% of CAPEX ing valuable light hydrocarbons and unreacted H2 and CO is • Administration = 0.5% of CAPEX • Feedstock/product escalation = 5%/yr hydrotreated, shifted and sent to a steam-methane reformer to • Capital structure: Debt-to-equity ratio = 60%:40% recover the syngas/hydrogen value. After CO2 removal, the re• Cost of financing = 8% formed gas is sent to a pressure swing absorption (PSA) unit to • Corporate tax rate = 25% recover pure H2 , which is compressed and mixed with the treat• Plant availability = 330 days per year, 90% ed synthesis gas entering the FT synthesis section providing • Internal rate of return (IRR) = 20%. the desired H2:CO ratio. This significantly reduces the amount FT diesel and naphtha pricing. FT diesel has superior of shifting required for the gasifier outlet gas. Waste gas from qualities with no/very-low-sulfur and low-aromatics content, the PSA unit is fully utilized as fuel for the reformer furnace. high-cetane and good cold-flow characteristics; thus, its price The CO2 recovered in the reformed-gas AGRU is completely is comparable to ultra-low-sulfur diesel (ULSD) prices.11 For sulfur free. It can be compressed and exported for enhanced-oil recovery (EOR) and/or sequestration. This sulfur-free CO2 can this economic analysis, a 5% premium on present ULSD pricing is assumed to estimate the FT diesel price. The present sellalso be sold as food grade or sent to urea plants after appropriate ing prices of ULSD and naphtha in Singapore, Europe, US Gulf treatment steps.

Hydrocarbon Processing | DECEMBER 2012 51

Plant Design and Engineering Coast and Mediterranean are listed in TABLE 4.11 Based on the ULSD density of 876 kg/m3 and naphtha density of 740 kg/ m3, the selling prices of ULSD and naphtha in Europe are calculated.12,13 Adding a 5% premium to the ULSD prices yielded the FT diesel prices, as summarized in TABLE 4.

FT diesel cost of production. TABLE 5 lists the FT diesel production costs in Asia and the US. The assumed selling prices for compressed CO2 and the IRR are also listed in TABLE 5. The compressed CO2 at pressures of 155 bara are suitable for either EOR and/or storage. The plant-gate selling prices of compressed CO2 ranging between $25/ton to $35/ton are reported in literature.14 Best market for CTL is Asia-Pacific. TABLE 6 shows the profitability of CTL projects in Asia-Pacific and the US. The capital cost (CAPEX) for the CTL project in Asia-Pacific is only 70% of that for the US Gulf Coast. Thus, a CTL project can be extremely profitable in Asian markets such as India, China and Indonesia, where the cheap, low-rank coals are abundantly available and natural gas and crude oil reserves are scarce and/or priced at a premium.

The US market is less attractive than Asia, since the CAPEX for CTL is extremely high and abundant, lower-cost natural gas resources make the GTL process more suitable. At an IRR of 15%, the CTL is economically viable in the US. The European market is also not very attractive for CTL due to high CAPEX. The Middle East/Arab Gulf market is also not attractive for CTL due to extremely abundant resources of crude oil, making refining the best option for liquids, and a significant amount of natural gas, making GTL the second best option.

TABLE 4. Present selling prices of ULSD, naphtha and FT diesel Prices, $/bbl Country/Region

ULSD

Naphtha

FT diesel

Singapore (Asia-Pacific)

130

107

136

Europe

134

114

141

US Gulf Coast

125

131

Mediterranean

135

113

142

TABLE 5. FT diesel cost of production

Region Asia-Pacific

Compressed Naphtha CO2 price, $/ton price, $/bbl

Assumed IRR, %

FT diesel production cost, $/bbl

0

107

20

80

Asia-Pacific

25–35

107

20

65

US

25–35

107

15

92

US

25–35

107

20

123

Assumed IRR,%

Profit margin, $ MM/yr 344

TABLE 6. Profitability of CTL Region Asia-Pacific

Selling price, Production $/bbl cost, $/bbl 136

65

20

US

131

123

20

39

US

131

92

15

189

52 DECEMBER 2012 | HydrocarbonProcessing.com

Sensitivity analysis of CTL production in Asia-Pacific.

Since the estimated cost of production of liquid fuels depends on assumptions, it is important to identify the sensitivities of these factors on the liquid-fuel production cost. FIG. 13 shows such a sensitivity analysis. The blue lines in FIG. 13 indicate the effect of an increase in each factor on FT diesel production cost, while yellow lines indicate the effect of a decrease in the factor.

As illustrated in FIG. 13, the FT diesel production cost is most sensitive to CAPEX. Increasing the CAPEX by 25% increases the FT diesel production cost by 31%, while decreasing the CAPEX by 25% decreases the FT diesel production cost by 31%. Typically, the CAPEX in India and China are 70% of the CAPEX on the US Gulf Coast. The cost of coal has the second highest impact on the FT diesel production cost. Increasing the coal cost to $30/ton ($2.7/MMBtu) increases the production cost by 13%, while decreasing the coal cost to $10/ton ($0.9/MMBtu) decreases the production cost by 13%. Oxygen is also a raw material in addition to coal; the oxygen cost is already included in the CAPEX as part of the ASU. It is not explicitly used as a variable for sensitivity analysis. Plant availability and corporate tax rates have the least impact on the production cost. Present inflation rates in the US, China and India are 3.6%, 5% and 9%, respectively.7–9 The inflation rates are varied in the economic analysis to cover various geographical regions.

What price of crude oil makes CTL more attractive?

CTL is estimated to be economically more attractive than refining when the selling price for crude oil is between $55/bbl and $65/bbl (US 2007 dollars) using a WTI benchmark.15 These prices include the costs of capturing about 90% of CO2 emissions from the CTL plant, but do not assume any income or outlays associated with sequestering that CO2 . The FT diesel can be produced at $1.7/gal to $2/gal ( January 2007 dollars), directly comparable to refinery gate prices of ULSD, which is $2.41/gal.16 At world crude oil prices of between $60/bbl and $100/bbl (2007 dollars), direct economic profits are more likely.15 Lower world oil prices will likely be the result of any increase in liquid-fuel production, either domestically or abroad, from unconventional resources. Based on examining a broad range of potential responses by the Organization of the Petroleum Exporting Countries (OPEC), it is anticipated that world oil prices will drop by between 0.6% and 1.6% for each million barrels of unconventional fuel production that would not otherwise be on the market. Further, this price decrease should be close to linear for unconventional-fuel additions of up to 10 MMbpd. Looking only at coal-derived liquids, it is possible that total world production could reach about 6 MMbpd by 2030.15 Future. Coal-gasification technology for liquid-fuel plants offers an economically attractive option for manufacturing liquid fuels, especially in Asian countries with large coal reserves and limited or high-cost crude oil and natural gas deposits, such as China, India and Indonesia. The prospect for developing an economically viable CTL in the US looks promising, although important uncertainties in future crude oil prices and the environmental policies on greenhouse-gas emissions exist. Coal gasification technology for liquid fuel plants will ease the pressures due to increasing global demand of liquid fuels and various

Plant Design and Engineering derivatives. Coal-gasification technology will find increasingly greater use due to a wide range of coal feedstocks, particularly the low-rank coals, which are cheap and abundant.

LITERATURE CITED USEIA, Annual Energy Outlook 2011, With Projections to 2035, April 2011.

2 IHS Cambridge Energy Research Associates (CERA), August 2011.

3 http://www.worldcoal.org/coal/where-is-coal-found/, World Coal Association.

4 Berg, D. R., B. Oakley, S. Parik and A. Paterson, â&#x20AC;&#x153;The Business Case for Coal Gasification with Co-Production,â&#x20AC;? Scully Capital, December 2007.

5 FT Solutions LLC, http://www.nma.org/pdf/liquid_coal_fuels_100505.pdf.

6 http://www.aidea.org/pdf%20files/belugactloverview9-20-06.pdf.

7 US Bureau of Labor Statistics, July 15, 2011.

8 CIA, The World Fact Book, August 2011.

9 Monthly Review of Indian Economy, Economic Affairs and Research Division, FICCI, April 2011.

10 USEIA, International Energy Outlook 2011, September 2011.

11 Purvin and Gertz Inc., Global Petroleum Market Outlook: Petroleum Balances, Vol. 1, March 2011.

12 http://www.usor.com/files/pdf/5/ULSDspec.pdf.

13 http://www.icis.com/StaticPages/Naphtha_Solvent.htm.

14 DOE/NETL, Storing CO2 with Enhanced Oil Recovery, February 2008.

15 J. T. Bartis, F. Camm, D. S. Ortiz, Producing Liquid Fuels from Coal: Prospects and Policy Issues.

16 USEIA, Annual Energy Outlook 2008: With Projections to 2030, June 2008.

1

NOTES a CTL process uses KBRâ&#x20AC;&#x2122;s proprietary Transport Reactor Integrated Gasifier (TRIG).

DR. BHARTHWAJ ANANTHARAMAN is a principal process engineer in the ammonia and syngas technology at Kellogg, Brown and Root (KBR) in Houston, Texas. Dr. Anantharaman has authored papers in industry magazines, presented

talks at industrial conferences and published a book entitled, Catalytic Partial Oxidation Reaction Mechanisms: Commercial Application to Industrial Ethylene Epoxidation. His work focuses on both the technical and financial aspects of chemical technologies with practical applications. Dr. Anantharaman holds a BTech degree in chemical engineering from Indian Institute of Technology, Madras, a PhD in chemical engineering from the Massachusetts Institute of Technology (MIT), and a certificate in financial technology from the Sloan School of Management of MIT. RON GUALY is vice president technology, coal monetization with KBR in the US. He is working in the technology business unit with responsibilities to manage and to grow the gasification business line. He is responsible for managing the execution of the projects, coordinating with sales, and defining a technology strategy that supports the present offering and technology improvements. Prior to this assignment, he was vice president technology acquisitions within the KBRâ&#x20AC;&#x2122;s technology business unit. Mr. Gauly is a chemical engineer graduated from Texas A&M University with more than 28 years of experience in the industry and extensive worldwide business exposure. He has over sixteen years of experience in technology management and licensing activities, and growing and managing a business line. In his previous experience, he has participated in several new technology development and commercialization programs.

DEBASREE CHATTERJEE is working as process engineer in coal monetization team in KBR Technology, Delhi. She has worked in the field of coal gasification for more than five years with different technology licensors. She holds a MS degree in chemical Engineering from Indian Institute Of Technology, Kanpur and BS degree from Jadavpur University, Kolkata.

SIVA ARIYAPADI is technology manager, coal monetization, for KBR (Houston).

In his current role, he supports KBRâ&#x20AC;&#x2122;s coal gasification product line with worldwide technology licensing, business development and marketing efforts related to the Transport Gasification Technology (TRIG). He has 15 years of industry experience in the energy and chemicals business sectorâ&#x20AC;&#x201C;including heavy-oil upgrading, LNG process technology, gas monetization, synthesis gas, coal gasification and carbon capture technologies. He holds a PhD degree in chemical engineering from the University of Western Ontario, Canada.

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Special Report

Plant Design and Engineering S. BENNETT, AVEVA, Cambridge, UK

Consider ‘lean’ engineering to fast-track mega projects Go to any large capital expenditure construction site the world over, and discuss issues of inefficiency, and then expect to be inundated with information about the processes being applied to manage this issue. The highest priority for the constructor is maximizing profit and meeting deadlines. Pressure to deliver the construction project on time can sometimes create apparently unavoidable inefficiencies.

Efforts to maximize efficiency, increase productivity and reduce waste are executed inline with agreed processes. However, onsite subcontractors may not share the same ideals, or even be motivated to do so only due to terms of their work agreements. This collectively results in an uncoordinated approach to improving site efficiency.

Moreover, no singular vision or philosophy for managing and reducing waste and maximizing efficiency is applied to the whole project. Local solutions are applied but are not bound by any guiding philosophy or framework, which extends outside of each team to include the whole project ecosystem. Result: This fragmented approach can only ever provide a modicum of success. All of these issues existed in the automobile industry at the end of the 19th century, where craft manufacturing (producing one-offs) was the only route for vehicle production.

GUIDING PHILOSOPHY The move to mass production was a fundamental change for the automobile industry as Henry Ford pioneered techniques such as conveyors to control output, and gauge standardization for mass part production as part of the drive to produce huge volumes of cars. The 1950s saw the dawn of a new philosophy for manufacturing introduced by Eiji Toyoda, then owner of Toyota Motor Cars. This new approach, dubbed “lean production,” focuses on doing more with less.

The aim was to double production using half the resources.

This lean philosophy is founded on three key principles: 1. Respect people. Briefly stated, empowerment should be at all levels of the organization from senior management all the way to the workers on the shop floor. Employess are accountable for their work and being empowered to improve the efficiency of the working practices. Unified adoption of this philosophy is essential to its success 2. Eliminate non-value-add activity—remove waste.

Adopting a zero tolerance to waste, whether it is material, waiting for material in transit or material in storage, means having a minimum or no inventory of parts with no stockpiling.

3. Maximize the efficiency of value-add activity. Use continual improvement for the efficiency of producing parts.

Value-add activity is defined as work, which is done on a part, such as bending a pipe or cutting sheet steel.

All of the values for lean production are aspirations for engineering, procurement and construction (EPC) projects that yield more efficiency, more accuracy, better quality and profitable delivery ahead of schedule. So why not adopt this approach?

LEAN-PLANT DESIGN ADOPTION— THE CHALLENGES Significant pressures are applied to EPC companies to complete the project under extremely short timescale, with high levels of scrutiny, compliance to standards on ever larger and more complex engineering problems to solve. The EPC business is presented with some distinct challenges in adopting the lean-production philosophy: No environment for a unified adoption of the philosophy.

These large-scale projects are made up of a diverse multicultural management team with distinct methods of working— developed to give them competitiveness—and a diverse set of business models.

Fragmentation of the stakeholders provides a significant hurdle to adopting a unified vision and philosophy for the project execution. Each contractor is paid based on timely delivery of information, materials or other measurable milestones to the next internal customer. Conversely, each contractor is often penalized for late delivery. This reinforces behavior where each contractor assumes a single-minded focus on providing deliverables for the next internal customer only.

One-off projects. Each project has different requirements.

They are met with different technologies and engineering, and are located in different parts of the world and delivered by diverse teams of engineers. Most projects exhibit a degree of uniqueness, which would best suit a craft production model, although not entirely. These projects offer very little opportunity for repeatable construction processes to occur. Plant business has to manage much longer cycle times, where the design, fabrication and construction of any part of the final asset can take many months to complete. This provides very little opportunity for the continual improvement on fabrication, assembly and installation at the site.

Hydrocarbon Processing | DECEMBER 2012 55

Plant Design and Engineering FUTURE OF PLANT DESIGN With the introduction of affordable laser scanning and mobile and cloud computing, there is significant disruption to the market; it will prove to be the kick-start for a new era under lean construction adoption.

The availability of up-to-date design information to these construction personnel will help them to make more informed decisions and also assist them to validate information received in drawing about the construction. Information can quickly become outdated during a rapid project execution phase. In return, these devices will also provide a method for the construction team to share information with the fabrication teams and, ultimately, take it back to the Better coordination of engineering skills and design team. Constructors will be able to provide management processes can respond faster status updates for the items on site, and to also share laser data with the design team. to how systems are designed and supported

for grassroots and revamp projects.

Plant-design software will play a vital role in delivering new levels of efficiency, collaboration and compliance management to drive competitiveness and sustainability.

Laser data everywhere. The market is enjoying a greater degree of affordable laser scanning for large-scale construction sites. Laser data capture is often used to record the as-built environments for brownfield projects. But, more frequently now, it is used for collecting construction information during greenfield projects. It has never been easier to justify the use of laser data capture for both brownfield and greenfield projects. But, laser scanning should become a routine activity for the fabricators and constructors. By recording the real geometry of the fabricated part or the spool or construction details, and the sending this information back to the design office, it provides a platform for more rapid rework of the designs.

Mobile access. It is widely claimed that as much as 30% of

construction workers’ time is wasted waiting for information and decisions to be made. This is often a consequence of the serial nature of requests, changes and clarifications from the prime contractor and the client. Lack of availability of key staff and a less-than-optimal process can be the main cause of delays.

A typical project execution phase Design Detail Fabricate Construct

Lean projects Design Fabricate Construct

Man hours

Construction starts Construction starts Lean EPC Traditional EPC

Time FIG. 1. Vision for plant design based on traditional and lean construction methods.

56 DECEMBER 2012 | HydrocarbonProcessing.com

Automatic pipe and steel fabrication drawings.

Designs created within 3D models are sent to the fabricator who, in turn, repeats a great deal of this work by creating non-intelligent 2D drafts of the 3D model and then detailed fabrication drawings for the design. This introduces unnecessary wastage into the process and an opportunity for errors to be introduced. The opportunity to streamline the process between layout design and detailed design, with a view to providing accurate fabrication drawings straight from the model reduces waste and wasted time. With the recent acquisition of new CAD software, the production of accurate fabrication drawings directly from the 3D design model is as easy as the click of a button.

LOOKING FORWARD The move to “lean” is unquestionably a significant challenge, but is it one with huge benefits. A lean construction approach can add a greater degree of competitiveness to the EPC business, increasing its profitability, improving its delivery success rate and, consequently its brand image (FIG. 1).

Adopting this approach requires wholesale support from the senior management team to the fabrication shop floor through to the site constructor to be successful. As we move toward the future of plant design, new plant design product will provide key capabilities to encourage and enable the adoption of a lean approach to the project execution. Allowing each internal customer in the project the ability to share up-to-date information and provide feedback to their previous internal customer will help to accelerate the collaboration required for successful concurrent design, fabrication and construction.

As laser scanning, mobile computing and cloud computing become more accessible and affordable to EPC companies we will see a new rate of adoption of these techniques to improve the project execution efficiency. Owners can help to accelerate the adoption of lean approaches to construction if they are able to present a contracting environment that is conducive to a unified philosophy of shared benefits, efficiency improvements and culture.

SIMON BENNETT is a senior product business manager with AVEVA. With a background in civil engineering, he has over 12 years of experience as a software product manager, having worked for a number of commercial off-the-shelf and enterprise software companies. Mr. Benett has managed product software to serve customers in the financial, airline, power, law enforcement and military sectors. He joined AVEVA in 2008, where his product management experience allowed him to play an important role in organizing the Enterprise product portfolio’s marketing and strategy. More recently, he has driven the launch strategy and marketing for AVEVA’s new generation of plant design, AVEVA E3D.

2012 PETROCHEMICALS REVIEW

SOUTH AMERICA ARGENTINA ALFREDO FRIEDLANDER, Consultant, Instituto Petroquímico Argentino (IPA), Buenos Aires, Argentina

For nine consecutive years (2003–2011), the Argentinean gross domestic product (GDP) continued to increase at an impressive annual rate of 7% to 8%. However, this trend was expected to change in 2012 with the domestic GDP only increasing at 3% to 4%. The world economic crisis will affect the Argentinean economy, but it will not be the sole reason for the sharp decrease.

A severe drought is affecting the harvest of main export products (soybean and corn), and a reduction in the commodities international prices is expected to reduce the balance of payments.

The government is limiting imports to improve the balance, but these measures are raising fears among local producers.

The local industry is strongly dependent on imported supplies, and the new regime of nonautomatic imports may jeopardize some strategic sectors such as the automotive and electronic industries. The petrochemical sector may also be affected, since many intermediate chemicals are not produced locally and are required for the manufacture of final products.

TABLE 1 shows domestic petrochemical production over the last 20 years. A peak of about 7 million tons was reached in 2006. Since then, annual production has declined by 1 million tons each year. The main reason for this trend has been the lower availability of oil and, especially, natural gas, which is the main raw material for Argentina’s petrochemical industry.

FIG. 1 shows the location of Argentina’s main petrochemical sites. Bahía Blanca (south of Buenos Aires) is the largest complex for basic petrochemicals (ethylene and ammonia) and polymers (HDPE, LDPE, LLDPE, PVC and urea) products.

The largest refinery is located at Ensenada (La Plata); this site has the largest benzene, toluene and xylene (BTX) capacity. A third important location is San Lorenzo (Santa Fe province, north of Buenos Aires); this complex has aromatics capacity, as well as styrene monomer (SM) and styrene-butadiene rubber (SBR) capacity. Polypropylene (PP) is produced by two sites (Ensenada, Luján de Cuyo) close to the two largest refineries, which are fluid catalytic cracking units supplying propylene.

TABLE 2 shows the fluctuations of the Argentinean petrochemical trade balance since 1990. For most years, it has been negative. Only in 2002 did the petrochemical balance become positive. This was possibly due to new capacity that came onstream in the Bahía Blanca area. Since then, no new capacity additions have occurred.

The increasing trade balance deficit over the last few years is the result of two combined factors. From the demand side, there is the already-mentioned increase in GDP and, consequently, of petrochemicals consumption. The other factor results from lower utilization rates of local capacity due to raw materials restrictions and, thus, less local product is available, as shown in TABLE 1.

In 2010, imports increased to their highest level ever in volume, surpassing $3 billion and creating a –$1.9 billion trade imbalance for Argentina. TABLES 3 and 4, respectively, list the “top 10” 2010 exports and imports. Several products, mainly thermoplastics (PE, PVC, PP and PET), appear in both tables. This reflects the fact that, thanks to Mercosur, there is fluent commerce between Argentina and Brazil, with no import tariffs. TABLE 4 TABLE 1. Petrochemical production, thousand tons (Mton) Year

Basic, Mton

Intermediate, Mton

Final, Mton

Total, Mton

1990

949

802

798

2,549

1995

1,117

811

1,041

2,969

2000

1,405

839

1,427

3,671

2005

2,915

1,039

2,907

6,861

2006

2,951

997

3,184

7,132

2007

2,657

947

2,635

6,239

2008

2,540

914

2,455

5,909

2009

2,540

845

2,752

6,137

2010

2,427

887

2,589

5,903

Source: IPA

TABLE 2. International trade data for Argentina’s petrochemical industry Year

Exports, Mton

Exports, $ million

Imports, Mton

Imports, $ million

Balance, $ million

1990

582

335

405

317

18

1995

470

423

1,437

838

–415

2000

783

549

2,402

1,188

–639

2002

1,753

791

1,647

701

70

2005

2,008

1,401

2,389

1,790

–389

2006

1,922

1,495

2,665

1,922

–427

2007

1,313

1,407

3,338

2,705

–1,298

2008

1,180

1,397

2,834

3,235

–1,838

2009

1,412

1,117

2,019

1,771

–654

2010

954

1,124

3,507

3,029

–1,905

Source: IPA

Hydrocarbon Processing | DECEMBER 2012 57

2012 Petrochemicals Review Sucre

Pacific Ocean

TABLE 4. Top 10 petrochemical imports in 2010

Bolivia

Brazil

Volume, Mton

Sales, $ million

MAP

607.9

298.5

DAP

277.4

135.1

Urea

437.5

143.5

PTA

170.3

155.8

HDPE

121.3

189.8

Paraguay Asunción

Chile

San Lorenzo (Santa Fe) Uruguay

Luján de Cuyo Santiago (Mendoza)

Rosario Buenos Aires Ensenada (Buenos Aires)

Argentina

Bahía Blanca (Buenos Aires)

PP Atlantic Ocean

LDPE

105.0

182.9

92.7

164.5

LLDPE

96.6

157.1

PET

90.6

123.8

PVC

67.1

74.3

3,507

3,029

Total (125 products) Source: IPA

Refinery Petrochemical complex

FIG. 1. Location of Argentina’s major petrochemical and refining complexes.

TABLE 3. Top 10 petrochemical exports in 2010 Volume, Mton

Sales, $ million

LLDPE

109.2

158.7

HDPE

95.0

128.4

PVC

101.0

114.5

57.0

90.8

PP PET

25.4

34.3

Nylon 66

28.9

82.0

SBR

22.2

50.1

Urea

122.9

44.4

Oxo alcohols

24.7

40.1

SM

37.2

46.3

Total (125 products)

957

1,123

Source: IPA

BRAZIL OTÁVIO CARVALHO, MaxiQuim Assessoria De Mercado, Porto Alegre, Brazil www.maxiquim.com.br

Brazil’s economic improvement was remarkable over the past decade, following many years of slow growth. On average, the Brazilian gross output of goods and services increased at an annual average of 3.6% from 2000 to 2010, despite the global fi58 DECEMBER 2012 | HydrocarbonProcessing.com

also shows that the other main imports are fertilizers not produced locally (MAP and DAP) and urea, since their producing units are not operating at full capacity due to raw material shortages. The first 10 products represent around 60% to 70% of the total volumes and sales for both imports and exports.

Natural gas reserves continue to decrease. In 2002, natural gas reserves represented 17 years of production—now, this figure is reduced to 7.5 years. Oil availability is more stable and has not changed significantly over the last 10 years, with present reserves representing 10 years of production.

However, since most of the Argentinean petrochemical industry is based on natural gas, no new plants or significant expansion of existing units is immediately foreseen. All indicators show that the petrochemical trade deficit may increase. The main risk may be new government-imposed import restrictions.

This could strongly affect the petrochemical industry, as well as other strategic sectors of the economy. But there is one hope in the middle term, as Argentina looks to become a country with very large shale gas reserves. Shale gas exploitation will require significant investment. For such resource development, it is imperative that clear signs are given by local authorities to attract domestic and foreign capital.

NOMENCLATURE Complete nomenclature available at HydrocarbonProcessing.com.

nancial crisis. From the long-term perspective, this rate means a great achievement from years past. During the 1980s, Brazil’s gross domestic production (GDP) expanded at 1.6%/yr, while, in the 1990s, it accelerated to a mere 2.5%/yr, as shown in FIG. 1.

According to analysts’ estimates, the Brazilian GDP may have expanded by 2.7% in 2011, and it could accelerate over the next five years. This growth is linked to the anticipated new infrastructure investments needed to host two major sports events: the World Cup of Soccer in 2012 and the Olympic Games in 2016.

Political and social briefing. Mr. Luiz Inácio Lula da Silva was the country’s president from 2003 to 2010. His main achievement was keeping economic fundamentals unchanged

2012 Petrochemicals Review do Sul, where the company has several polymer units. Dow has announced a memorandum of understanding with Mitsui to study construction of an integrated sugarcane-ethanolethylene-PE unit in the state of Minas Gerais. This unit would have an estimated 350 Mtpy of PE capacity and should come onstream in 2014.

In the conventional feedstock scenario, Petrobras has made several significant discoveries in offshore Brazil, which is known as the pre-salt oil layer. At remote locations (200 miles from the coastline) and in ultra-deep (20,000-ft) waters, these large reserves now define Brazil as a significant energy producer. The new oil reserves are a future feedstock resource for the petrochemical and chemical industries.

Petrobras is also building four large refineries over the next five years; they will increase the country’s refined product output from 1.8 million bpd to 3.2 million bpd in 2020. Two of the refineries—Comperj, in the Rio de Janeiro area, and RNEST, in Suape, Pernambuco—are in advanced construction and equipment-purchase stages. Both refineries should come online in the next two years. The other two refineries—Premium I, in the state of Maranhão, and Premium II, in the state of Ceará—may see project construction accelerate over the next few years, and they are expected to come onstream later this decade.

2

7.8 7.5

7.5 5.9

5.4

4.9 3.5

3.2

-6

4.3

3.4

0.8

0.0 -0.1

3.2

2.7

1.0

0.3

1.3

5.2

4.0 2.7

1.1 -0.3

-0.5

-2 -4

5.7 4.2 2.2

0

6.1

-2.9 -4.3

-4.3

’81

’83

’85

’87

’89

’91

** MaxiQuim estimates Source: IBGE

’93

’95 ’97 Year

’99

’01

’03

’05

’07

’09 ’11*

FIG. 1. Brazil’s historical GDP trends: 1981–2011.

12

60 Imports/total % Imports Production

10

50

8

40

6

30

4

20

2

10

0

2002

2003

2004

2005

2006

2007

2008

2009

2010

2011

Naphtha imports, % of total

widely based on naphthas, which are supplied by the state-controlled oil company, Petrobras, or via imports, as shown in FIG. 2. The country is a net importer of naphthas and condensates. In 2006, the first ethane-based cracker came onstream in Rio de Janeiro. The company, Rio Polimeros, is now part of the petrochemical giant Braskem.

Naphtha prices in the domestic market, supplied by Petrobras, are settled on a monthly basis and are pegged to the average benchmark price for Antwerp, Rotterdam and Amsterdam (ARA) naphtha. In our view, the chances for a formula based on benchmark prices are slim over the medium term, since the country will remain a net importer. Due to strong transportation fuel demand, local naphtha production allocated to petrochemical applications has been falling; the gap between demand and supply is covered by naphtha imports, which accounted for more than half of the country’s needs in 2011.

Renewable feedstock alternatives. Due to Brazilian expertise in the ethanol business, companies, such as Braskem and Dow are advanced in using bioethanol as feedstock for polyethylene (PE) production. Braskem has been operating its 200,000-tpy (200-Mtpy) ethanol-to-ethylene unit since 2010 in Triunfo, in the state of Rio Grande

Brazil’s naphtha supply, million tons

Feedstock. Brazil’s petrochemical industry is

GDP change, %

(such as the floating currency and inflation-target monetary policy), while reducing inequality through comprehensive social programs. Over the past five years, roughly 45 million citizens were able to climb from poverty into the middle class, which created new demand for automotive, construction, electronics, cosmetics, chemicals and other products.

Mrs. Dilma Rousseff, after serving as Minister of Energy and Chief of Staff of Lula’s government, was appointed the candidate of the central-left-wing Workers’ Party, and she beat the Brazilian Social Democracy Party’s candidate, Jóse Serra, in a runoff election in late 2010. On Jan. 1, 2011, Mrs. Rousseff officially assumed the presidency of Brazil, with the task of accelerating the nation’s progress through better management of the government’s investments, while expanding social programs and reducing inequality. Her first year was marked by a reduced tolerance to corruption among ministers and their assistants. She also promoted the acceleration of several infrastructure projects in partnership with the private sector in many areas.

Unlike developed countries, tight fiscal policies and healthy government revenues led to improved ratings by global agencies such as S&P, Fitch and Moody’s to Brazilian sovereign debt and local companies. Combined with healthy trade surpluses and historical highs on foreign direct investments into Brazil, such ratings led to significant amounts of hard currency 10 entering the country, which has been strengthening the Brazilian real. The downside from this 8 situation is that the strong currency is taking its 6 toll on the industrial sector, especially those more exposed to foreign competition, such as chemical 4 and petrochemical producers.

0

Source: MIDIC and ANP

FIG. 2. Naphtha supply and demand: 2002–2011.

Hydrocarbon Processing | DECEMBER 2012 59

2012 Petrochemicals Review TABLE 1. Brazilian petrochemical expansion projects, 2011–2015 Product

Company

Location

Additional capacity, thousand tpy

Start Up

Status

Ethylene

Comperj

Itaborai, RJ

TBD

2017

Under evaluation

Ethylene

Solvay Indupa

Santo André, SP

60

NA

Standby

Ethylene

Dow / Mitsui

Santa Vitória, MG

350

2015

Under evaluation

Propylene

Comperj

Itaborai, RJ

TBD

2017

Approved

Propylene

Petrobras

Betim, MG

150

NA

Standby

Green propylene

Braskem

NA

30

2013

Under evaluation

Butadiene

Comperj

Itaborai, RJ

TBD

2017

Under evaluation

Benzene

Comperj

Itaborai, RJ

TBD

2017

Under evaluation

Styrene

Innova

Triunfo, RS

250

NA

Under evaluation

Comperj

Itaborai, RJ

TBD

2017

Under evaluation

Ethylbenzene Styrene

Comperj

Itaborai, RJ

TBD

2017

Under evaluation

Paraxylene

Comperj

Itaborai, RJ

TBD

2017

Under evaluation

HDPE/LLDPE

Dow / Mitsui

Santa Vitória, MG

350

2015

Under evaluation

HDPE/LLDPE

COMPERJ

Itaborai, RJ

TBD

2017

Under evaluation

PP

COMPERJ

Itaborai, RJ

TBD

2017

Under evaluation

PVC

Solvay Indupa

Santo André, SP

60

2012

Standby

PVC

Braskem

Marechal Deodoro, AL

200

2012

Underway

PTA

Petroquímica Suape

Ipojuca-Suape, PE

700

2012

Underway

POY

Petroquímica Suape

Ipojuca-Suape, PE

170

2012

Underway

PET

Petroquímica Suape

Ipojuca-Suape, PE

450

2012

Underway

PTA

Comperj

Itaborai, RJ

TBD

2017

Under evaluation

MEG

Comperj

Itaborai, RJ

TBD

2017

Under evaluation

PET

Comperj

Itaborai, RJ

TBD

2017

Under evaluation

ABS

Videolar

Manaus, AM

50

2013

Under evaluation

ABS

Unigel

Guarujá, SP

90

2013

Under evaluation

Braskem

Triunfo, RS

100

2012

Underway

BASF

Camacari, BA

NA

2014

Approved

Butadiene Acrylic acid

Shareholders

Voting capital, %

Total capital, %

Odebrecht Petrobras

50.1 47

38.1 35.9

BNDES

0.0

5.5

Others

2.9

20.1

Source: Braskem

1.28 million tpy of ethylene (Camaçari/BA) Feedstock: Naphtha 520,000 tpy of ethylene (Rio de Janeiro/RJ) Feedstock: Ethane/propane 700,000 tpy of ethylene (Maua/SP) Feedstock: Naphtha and refinery gas 1.43 million tpy of ethylene (Triunfo/RS) Feedstock: Naphtha and ethanol

FIG. 3. Location of domestic crackers, with capacities and ownership structure, as of 2011.

60 DECEMBER 2012 | HydrocarbonProcessing.com

FIG. 3 shows the locations of the main petrochemical sites and product capacities within Brazil. Until 2002, there were several small and nonintegrated companies.

The large petrochemical company Braskem was created through the merger of seven companies that year. During the next four years, Braskem was the nation’s only integrated petrochemical company, combining the production of monomers and resins at its Camacari site in the state of Bahia. In 2006, the Rio Polimeros complex became the nation’s only integrated, gas-based petrochemical unit in Rio de Janeiro.

In March 2007, another significant event changed the picture of the Brazilian petrochemical industry. A consortium of companies formed

by Petrobras, Braskem and Ultra, announced the acquisition of Group Ipiranga, which, at that time, was a partner of Braskem in Copesul, the naphtha-based cracker in Triunfo. That move turned Braskem into the only owner of the petro-

State of the industry.

2012 Petrochemicals Review 6 Commodity resin demand, million tons

chemical complex of Triunfo, thus consolidating its leadership position in the region. In August 2007, Petrobras announced the acquisition of Suzano PetroquÍmica, which was one of Brazil’s major PP producers. This move made possible the merger of all petrochemical assets of the Suzano Group (those acquired by Petrobras) and Unipar Group into one large and integrated petrochemical company later known as Quattor.

In 2010, after months of negotiations, Braskem and Petrobras reached an agreement to acquire Quattor’s shares from Unipar Group.

This movement led to the ultimate consolidation in Brazil, which now has one producer of polyolefins. It also increased Petrobras’ stake in the Brazilian leading petrochemical group to 47%, while Odebrecht holds 51% of the voting shares.

5 4

PVC PS

PP HDPE

LLDPE LDPE

3.7

4.6

4.3

4

5.3

5.2

2010

2011*

4.4

3 2 1 0

2005

2006

2007

2008

2009

*MaxiQuim Estimates Sources: ABIQUIM and MaxiQuim

FIG. 4. Commodity resin demand: 2005–2011.

Demand growth. Overall, domestic demand

Outlook. Many previously announced petrochemical proj-

ects came online on schedule, such as Braskem’s ethanol-to-

ethylene unit in Triunfo, the refinery-gas-based ethylene unit and LLDPE/HDPE plant in Sáo Paulo, and some new propylene units at Petrobras’ refineries. Others are still in development, including the new butadiene unit at Braskem’s Triunfo site, the new purified terephthalic acid (PTA)/PE terephthalate (PET) unit of PetroquÍmica Suape in the state of Pernambuco, and the PVC unit of Braskem in the state of Alagoas.

Two other important projects have been reformulated: 1) the Comperj project in Rio de Janeiro, for which a new configuration will be announced by Petrobras and Braskem, and 2) the Mitsui/Dow integrated sugarcane-to-polyethylene complex in the state of Minas Gerais. TABLE 1 summarizes the progress of announced petrochemical projects.

VENEZUELA www.intellichem.net

illustrates the annual gross domestic product (GDP) and inflation from 2006 to 2011 for Venezuela. High crude oil prices have helped domestic GDP growth, suggesting a healthy economy.

Despite the economic shocks that have rocked the global GDP since 2008, Latin America’s economic growth has remained above the world average. However, 2012 could be challenging in terms of growth. Inflation and stronger currencies in Latin America could slow economic expansion in the region.

Most Latin American countries will experience the effects of higher energy prices and the likely recession in Western Europe, as well as the recovering-but-weak US economy.

Venezuela’s petrochemical industry has not grown significantly over the last few years. Since 2009, Venezuela has become more dependent on imported petrochemicals, inFIG. 1

35

10

30

8 GDP, % change

DR. R. QUIJADA, CEO, IntelliChem Inc., Houston, Texas

12

25

6

20

4

15

2

10

0 -2 -4

GDP, % change Inflation, % change 2006

2007

2008

Inflation, % change

for resins—LDPE, LLDPE, HDPE, PP, PS and PVC—showed healthy growth, as illustrated in FIG. 4. However, during 2009, with the global financial crisis, industrial activity slowed and demand for resins decreased. During 2011, another soft patch for resin demand was partially explained by destocking, especially in the second half of the year.

However, over the last six years, domestic demand for thermoplastic resins grew nearly 6%/yr. In particular, LLDPE demand, which grew 13%/yr, was fostered by the substitution of LDPE in film applications. Another fast-growing resin was PVC, which was boosted by strong expansion in construction markets.

5 2009

2010

2006

0

Source: Central Bank of Venezuela

FIG. 1. GPD and inflation rates for Venezuela, 2006–2011.

cluding both basic petrochemicals (ethylene) and derivatives (polyethylenes).

Several expansion programs announced between 2005 and 2009 have been delayed or canceled. Meanwhile, the government, through PetroquÍmica de Venezuela (Pequiven), continues to develop a methane-based industry, and is increasing capacity for fertilizers and methanol production.

Hydrocarbon Processing | DECEMBER 2012 61

2012 Petrochemicals Review Russia Iran Qatar Turkmenistan Saudi Arabia US United Arab Venezuela Nigeria Algeria Iraq Indonesia Australia China Malaysia Egypt Norway Kazakhstan Kuwait Canada

1,581 1,046 894

0

Venezuela, 8th place worldwide in proven reserves.

Some additional 248 Tcf in probable and possible reserves are estimated.

600

Source: BC

15

14

13

Trinidad and Tobago

Peru

Argentina

Brazil

800 1,000 1,200 Natural reserves, tcf

13

1,400

FIG. 2. Global natural gas reserves, 2010.

Paraguana refinery CIAMCA

Installed capacity at CIAMCA and Jose (thousand tpy)

Methanol 1,530 Ammonia 1,300 1,450 Jose Urea CIAMCA-Polinter/Propilven Pralca 636 Ethylene glycol 68 Ethylene 260 Ethylene oxide 16 Propylene Clor alkali 130/147 EDC-MVC 130 PVC 120 Ammonia 300 Urea 360 HDPE (includes swing) 410 LDPE 85 LLDPE-swing 190 144 Source: Intellichem, Inc. PP-propilven Pralça

Morón

El Palito

FIG. 3. Locations of major refineries and petrochemical complexes, along with output and production capacities in Venezuela.

Political highlights. Since assuming the presidency in 1999, Hugo Chavez has survived a coup, an oil strike and protest movements against him. Of late, his most important battle has not been with the opposition party but with health issues.

Venezuela held presidential elections in October and reelected Chavez. New investments in the oil, energy and petrochemical industries continue to depend on the outcome of elections, thus underscoring the importance of Venezuela’s political environment on the domestic petrochemical industry.

Natural gas. Among the region’s major economies, Venezuela

holds the largest natural gas reserves, as shown in FIG. 2. However, the lack of private investment has crippled the supply and growth of petrochemicals, primarily on the west coast of Venezuela. Planned expansion of ethane-based capacity at Jose, on the eastern coast of Venezuela, is all but canceled. Braskem and Pequiven were working on the Jose project from 2007 to 2010, 62 DECEMBER 2012 | HydrocarbonProcessing.com

Chile

18

Mexico

26 Bolivia

Latin America

Petrochemical industry. Venezuela uses gas, associated with crude oil production, to produce ethane as a feedstock for petrochemical production.

Lower crude oil production means reduced gas and ethane availability at El Tablazo (now called Campo Industrial Ana Mariá Campos or CIAMCA), where supply is now limited. Olefin plants at CIAMCA 4 2 continue to operate at reduced rates due to inadequate ethane supply. Large capital investments and strong government support will be necessary to increase gas supplies.

Venezuela has four production sites for pet1,600 1,800 rochemicals, as shown in FIG. 3. The largest petrochemical site is CIAMCA, located on the west coast. The Jose petrochemical site on the east coast of Venezuela will continue to produce methane derivatives such as ammonia, urea and methanol.

The El Palito refinery is equipped with a reformer that feeds on condensates and produces benzene, toluene and xylene for local markets. The Morón facility is mainly for fertilizer production to supply local demand. It has important ammonia- and urea-producing units and produces other fertilizers, such as ammonium sulfate. FIG. 3 lists Venezuela’s present petrochemicals capacity for various base petrochemicals.

Pequiven is revamping the Moron petrochemical site to increase fertilizer production. There are also plans to increase feedstock availability at the CIAMCA petrochemical site.

Pequiven is building a new ammonia plant to produce fertilizers at its petrochemical site in Morón, Carabobo State (21 km from Puerto Cabello). The new ammonia plant is part of Pequiven’s strategy to double its fertilizer production; Pequiven has just over 2 million tpy of ammonia capacity at the CIAMCA site and the FertiNitro plant in Jose.

Major changes in feedstock supplies are under evaluation at Pequiven. Venezuela could expand olefins and derivatives production through naphtha cracking or by tapping into refineryrich streams from the Paraguaná refinery. Meanwhile, Pequiven is working to revamp existing facilities at CIAMCA and Morón.

Brazilian petrochemicals producers Braskem continues to evaluate Venezuela’s feedstock situation, looking to expand production capacity. Propilsur, the joint venture created by Pequiven and Braskem to produce polypropylene (PP) in Venezuela, is evaluating a propane dehydrogenation unit near the Paraguaná refinery where, Profalca, a local producer of polymergrade propylene (PGP) has a splitter to upgrade refinery-grade propylene for PGP production. Meanwhile, Polinter is considering the construction of a naphtha cracker to increase ethylene and polyethylene capacity in Venezuela. Other basic petrochemicals, like aromatics and heavy olefins, will be exported from this site when the project is completed. This project would redirect naphthas currently exported as feedstock to supply a new, 800,000-tpy olefins cracker. New grassroot or large units are not anticipated to come onstream sooner than 2017. These units, when built, will be efficient, world-class facilities that will help supply olefins and polyolefins to this region.

Colombia

195

Venezuela

284 283 273 213 195 187 159 112 108 103 99 85 78 72 65 63 61 200 400

but both companies are now looking into alternative feedstocks to support additional polyolefin capacity growth in Venezuela.

2012 PETROCHEMICALS REVIEW

EUROPE GERMANY DR. HENRIK MEINCKE, Chief Economist, Association of the German Chemical Industry (VCI), Frankfurt, Germany www.vci.de

The German chemical industry has an outstanding position inside Europe. Nearly 25% of chemical product sales in the European Union (EU) are by German chemical companies. Ranking behind China, the US and Japan, Germany is the fourth largest chemical manufacturer worldwide. Also, the chemical industry holds an eminent position within Germany’s overall economy. With more than 184 billion Euros, the share of manufacturing industry sales by chemical companies was well over 10%; thus, the German chemical industry is ranked third among all manufacturing sectors, behind automobile and machinery.

In recent years, German chemical companies successfully increased their competitiveness with restructuring and costcutting programs, as well as with innovative products and technologies. This explains the strong rebound after the 2008 economic crisis. The long-term prospects for the industry are favorable. Economic growth in all modern societies has always been strongly connected to advances in chemistry and the development of the chemical industry. The top challenges for humanity—e.g., renewable energies and raw materials, growing population and clean water—require new solutions, many of which can only be implemented through new materials, substances and technologies provided by the chemical industry. It is a true enabling industry and will keep this role in the future.

Business situation. The German chemical industry can look

back on a successful 2011 financial year overall. Production increased by 2.2%, prices rose by 5.2% and the turnover for the sector as a whole rose by 7.7% to 184.2 billion Euros. These improvements also had a knock-on effect on the labor market. The German chemical industry employed around 12,000 additional people, which is a 3% increase for labor.

However, these figures cannot hide the fact that the recovery has run out of steam, even in Germany. The sovereign debt crisis in the US and Europe came to a head in the summer of 2011.

The US came close to insolvency because the debt ceiling had been reached and the political maneuvering of both political parties initially prevented it from being raised.

In Europe, it became clear that the measures already in place were not enough to save Greece and other countries with high debt levels from insolvency. In the second half of 2011, economic growth continued to slow down. Research institutes and international organizations, such as the International Monetary Fund and the Organization for Economic Co-operation and Development (OECD), reduced their growth forecasts. There were renewed fears of recession. Citizens and companies alike were plunged into uncertainty. The economic setbacks were felt early on by the chemical industry. In Germany, chemical production dropped from one quarter to the next. Even the Q4th of 2011 failed to bring the anticipated trend reversal.

Prices. Higher raw material costs in 2011 forced many com-

panies to raise the prices of their products. But there has been a slight drop in raw material costs in the course of the present year. With a slower demand, the upward trend of prices ended in the Q4th. The average prices of chemicals and pharmaceuticals were 5.2% higher than they had been one year ago. Price increases were recorded in almost all sectors. Only pharmaceutical prices declined.

Sales and international trade. In 2011, total sales of the

German chemical industry increased by 7.7% to 184.2 billion euros. Business with customers abroad developed somewhat more dynamically than domestic business. Foreign sales of German chemical companies rose by 8.8% to €108.9 billion. Domestic sales improved by 6% to €75.3 billion.

Exports—comprising foreign sales by German chemical companies, re-exports and additionally chemical exports by other industries—rose by 5.8% to €150.6 billion. Such trends make Germany once again the world champion in chemical export activities. Strongest growth rates were achieved in business with Asia and South America. In addition, customers in neighboring European countries increased their orders with German chemical companies. As the business situation of German industry stabilized, imports of chemical products went up too: they totaled €108.7 billion and were 7% higher than last year. With almost €42 billion, German chemical companies once more significantly contributed to the export surplus of our country in 2011.

Employment. The good position of the chemical industry in

2011 positively impacted the labor market as well. Following a period of not filling labor vacancies during the economic crisis, German companies returned to hiring new staff. New hiring is also be motivated by concern over the growing shortage of qualified personnel. As a result, the number of jobs in the German chemical industry rose by 3%. In total, the German chemical industry had 427,000 staff in 2011.

Hydrocarbon Processing | DECEMBER 2012 63

2012 Petrochemicals Review Production

2.2

Prices

5.2

Sales

7.7

Exports*

5.8

Imports*

7

Employment*

3 Source: Statistical Office Germany, VCI * estimations

FIG. 1. 2011 Growth indicators for the German chemical industries, %.

Investment and R&D spending. With the fast recovery of the

German chemical business, and especially with high capacity utilization and the good earnings situation, companies decided to forgo their reserved investment attitude, a trend that continued in 2011. Since 2010, the chemical industry invested some €5.8 billion in buildings and plants; for 2011, we estimate investments to total roughly €6.4 billion. This corresponds to a 10% increase.

But 2012 investment plans are more cautious. In view of a less favorable economic environment situation and the threatening energy costs, investment decisions are currently being reconsidered.

According to VCI estimates, 2011 research spending for the chemical-pharmaceutical industry increased by 6.5% against 2010 to well over €8.8 billion. Out of this total, more than €5 billion were spent by the pharmaceutical sector. This high R&D spending pays off, as it keeps strengthening the international competitiveness and the success of German chemical companies.

UNITED KINGDOM ALAN EASTWOOD, Economic Advisor, Chemical Industries Association (CIA), London, UK www.cia.org.uk

The United Kingdom (UK) is Europe’s fourth largest chemical economy, after Germany, France and Italy. It accounts for 8% of the European Union’s (EU’s) $900 billion overall chemical production and 12% of extra-EU chemical export sales.1 In world terms, the UK is ranked tenth (with China, the US and Japan holding the top three places), and is the source of about 2% of global chemical production.

Domestically, the chemical sector is one of the most important segments of the UK manufacturing industry, accounting in 2010 for 14% of the nation’s manufacturing gross value added and 1.3% of the total UK gross domestic product (GDP).

In 2010, the country had chemical sales of $73 billion (excluding merchanted goods), with significant contributions from practically all industry sectors. The recent global recession has left its mark, however. Over the decade to 2010, the only sector to have recorded a positive growth rate was pharmaceuti64 DECEMBER 2012 | HydrocarbonProcessing.com

Outlook. Since December 2011, conditions have been improving for the German chemical industry. Confidence is gradually returning. The financial situation appeared brighter, and the economic prospects are now positive again. The trough appears to have been reached in Q4 of 2011. In the coming months, a renewed sense of buoyancy can be expected, although only time will tell whether this confidence is justified. The economy is still in a critical condition, and prudence is needed. The chemical companies must, therefore, proceed with caution as there could still be further setbacks ahead.

We are confident and expect to see a further slight increase in production and turnover in 2012 compared to the previous quarter. However, in comparison to the very good start to the year in 2011, it is likely that we will experience a substantial loss initially. Only as the year continues will the growth rates move back into the black.

Our forecast for 2012 has to be set against this background.

German chemical production will remain at the level of the previous year. We are not expecting to see any appreciable growth this year. The price increases are slowing. This year, chemicals and pharmaceuticals are likely to show price rises of 1%. The turnover of the sector as a whole is, therefore, also expected to increase by 1% to a total of €186 billion.

After two years of substantial upsurge, the German chemical industry will experience a pause in growth.

The industry must cope with this condition. The prospects for 2013 appear to be more positive: Experts expect to see a return to significant growth both in the GDP and in industrial production. The chemical industry should be able to benefit from this. As things currently stand, we can expect to see a 3% growth in German chemical production.

cals, and even this sector has seen a reversal in the last two years (to the end of 2011) with sharp falls in local production. Detergents and cosmetics have held their own, and have bucked the general trend with strong growth in 2011. Commodity chemicals—petrochemicals, plastics and basic inorganics—did well until 2008, and these chemical sectors have severely suffered since then. Dyes and fibers have long felt the contraction of European textiles markets, while fertilizer output has also declined as domestic markets have shrunk. Pharmaceuticals accounted for 45% of the UK industry’s gross value added in 2010.

International trade. The UK’s primary chemical trading partners are in Western Europe, with the rest of the EU-27 accounting for 55% of exports in 2010. Total export sales in 2010 to the EU were $43 billion, balanced almost exactly by imports from those countries. By comparison, exports to North America were $13.5 billion, and imports from there were $7 billion.

Overall, the UK enjoys a healthy trade surplus from chemical activities, with global exports of about $78 billion and imports of $66 billion generating a positive trade balance of $12 billion in 2010, as shown in TABLE 1.

Production volumes showed steady growth in the 1990s, rising by an average 3.2%/yr from 1990 to 2000, but slowed to 2%/yr from 2000 to 2008. Output has fallen sharply over the past three years. Growth was entirely the result of surging

2012 Petrochemicals Review exports, which increased at over 6%/yr in real terms in the 1990s, and averaged over 5%/yr from 2000 to 2010. Imports, however, grew even faster during the 1990s, at around 7%/yr, and at a similar rate to exports of just over 5% in the latter 10 years. It is difficult to reconcile the strong export volumes with the weak production volume statistics since 2008. Moreover, at a detailed sector level, official data note that exports, in some cases are exceeding the value of local production, even in cases where it is improbable that it would make sense for imports to be re-exported.

The UK’s undoubted success in international markets is due in part to the country’s ability to contain production costs.

Over 5, 10 or 15 years to 2007, UK chemical output prices fell in real terms, as they also did in Continental Europe; whereas, in the US, this was not the case. The sharp oil price increase saw a marked increase in real prices in 2008, and depreciation of the sterling caused further real-term increases in 2009, but normal service was resumed in 2010. Expressing prices in current dollars, fluctuating exchange rates saw the UK at its most competitive within Europe in the mid-1990s, and at its least competitive around 2000. Against the US, however, it enjoyed its greatest advantage around 2000, and once again in 2010 as depreciation played its part.

The successful containment of production costs can be attributed to substantial and consistent improvements in productivity. Over the 10 years to 2007, chemical industry output grew by 28%, while output per employee grew by 71%, an average improvement of 5.5%/yr. Production increases were achieved with fewer employees, thus reflecting improvements in technology and automation. Since the output peak in 2007/2008, despite falling output, labor productivity has still edged ahead. In 2010, the UK industry employed approximately 150,000 workers at manufacturing sites—a third fewer than a decade earlier.

Current trends and forecasts. Any current discussion of the present state of the industry and its short-term outlook is inevitably clouded by major uncertainties over the course of the global economy, not least in the neighboring eurozone, as well as energy prices both in the world as a whole (oil) and in the UK specifically (gas and electricity, including the effect of various extra costs imposed as a consequence of an aggressive unilateral climate-change policy). The fall in North Sea hydrocarbon output has tipped the UK from a net gas exporter to a net gas importer. Both spot and forward prices have, in recent years, regularly reflected nervousness over security of supply, although recent expansion of LNG import capacity has eased the position.

Output of chemicals, excluding pharmaceuticals, has had a difficult time since 2007, with current UK output levels still almost 20% below the peak levels achieved in early 2008. The current year began with many clouds hanging over the European continent, the UK’s main market. Apart from problems of sovereign debt, there are worries over consumer debt, high unemployment and consequent weak final demand. Coupled with banks’ inability or reluctance to lend, and stabilizing commodity and oil prices (which removes any incentive to buy in advance of immediate need) there has been pressure along supply chains to free cash by reducing inventories. This, in turn, has resulted in falling production across Europe at the end of 2011.

TABLE 1. Key 2010 statistics of the United Kingdom’s chemical industry Sales (total turnover including merchanted goods)

$82 billion

Exports

$78 billion

Imports

$66 billion

Trade balance

$12 billion

Employees at manufacturing sites

147,000

R&D spending (2009): Pharmaceuticals

$6.9 billion

Chemicals excl. pharmaceuticals

$1.0 billion

Output growth, %/yr 2000–2010 2011 2012 forecast

0.5 –3.4 0

In 2012, very low year-on-year growth is the best that can be expected, both in the UK and in the EU at large. As mentioned earlier, UK pharmaceuticals production, for many years a growth driver, has also wilted within the last two years. Some major pharmaceutical companies are facing loss of patent protection on major drugs and now are forced to look for manufacturing economies and to possibly outsource part of their production. New UK “Patent Box” legislation promises, however, to give tax advantages to companies exploiting their intellectual property within the UK, and it is hoped that this will help to counteract the lure of both low Irish tax rates and cheap Asian production locations.

Domestic transition. The UK continues its quest to improve performance in manufacturing efficiency and innovation for new products. Expansions in bulk and commodity chemical production are mainly occurring in locations where feedstocks and energy are cheap, such as in the Middle East, or close to centers of demand growth, principally Asia. Major UK sites are seeing investment such as waste-to-energy plants, like Ineos chlorvinyls’ £400 million project at Runcorn. The £200 million world-scale low-density polyethylene unit at Wilton, Teesside, begun by Huntsman and now owned by SABIC, is in full operation. Wilton has seen closure of an ethylene oxide (EO) unit and of nylon fiber production, but it will gain a new 200,000-tpy PET plant—as well as more waste-to-energy developments.

The UK government is actively assisting industry to develop new technologies. The Chemistry Innovation Knowledge Transfer Network, for which the government provided initial support, is now well established.

In 2009, UK R&D investment for the chemicals industry totaled over £5 billion, of which pharmaceuticals accounted for over £4.4 billion. For chemicals excluding pharmaceuticals, the figure was equivalent to around 1.8% of sales—which nevertheless compares well with the most recent figures quoted by CEFIC (European Chemical Industry Council), which puts the EU average at about 1.5% in 2008—although the US ticked up to 2.1%, and Japan is at 4.1%.

1

EU-25 plus Switzerland and Norway, 2010. Estimated sales of own production, i.e., excluding goods resold without further processing.

Hydrocarbon Processing | DECEMBER 2012 65

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2012 PETROCHEMICALS REVIEW

ASIA CHINA A. LIN, PetroChina Ltd. Co.; X. FU, X. LI and L. ZHANG, Petrochemical Research Institute, PetroChina, China

The International Monetary Fund (IMF) announced in its January 2012 “World Economic Outlook” that the global GDP growth rate was 3.8% in 2011. However, Asian-Pacific nations bucked this trend. In 2011, China’s GDP was 9.2% and India’s GDP reached 7.4%. The IMF estimates that global 2012 GDP will grow by 3.3%; China’s GDP will grow by 8.2%, and India’s GDP will increase by 7%. The global economy is threatened by intensifying strains in the euro area. Financial conditions have deteriorated, and growth prospects are dimming. Lower demand for Asian exports is dragging growth. However, Asian economies continue to remain buoyed by continuing strong domestic demand.

In 2012, worldwide refining capacity is estimated to reach 88.05 million bpd (MMbpd). The Asian-Pacific region has 24.92 MMbpd of refining capacity, accounting for approximately 28.3% of global refining capacity. Members of the top 10 refining nations include four Asian countries: • China, with 10.8 MMbpd in refining capacity, is ranked second in the world • Japan, with 4.73 MMbpd, is ranked fourth • India, with 4.04 MMbpd, is ranked fifth • South Korea, with 2.7 6MMbpd, is ranked sixth.

Asia has 164 operating refineries; North America has 148 refineries; and Western Europe has 99 refineries. The refining capacity share by region is 28.3%, 24.1% and 16.4%, respectively. A new reconfiguration of the global refining industry has formed. At present, Asia is now the major refining sector; North America is second, and Western Europe is third.

Worldwide ethylene capacity reached 138 MMtpy in 2010.

Ethylene capacity in Asia increased to 42.63 MMtpy, exceeding North America. China has 15.22 MMtpy of ethylene capacity; Japan has 7.26 MMtpy; South Korea has 5.63 MMtpy; and India is operating 3.31 MMtpy of ethylene capacity. The AsianPacific region accounts for 30.8% of total worldwide ethylene capacity and has the highest operating capacity.

Refining. In 2011, China’s refining industry had 150 refineries,

of which 21 refineries have a site operating capacity exceeding 0.2 MMbpd.

In China, three large, government-owned refining enterprises dominate the domestic refining industry. Sinopec is the largest

state-owned hydrocarbon processing company, with a refining capacity of 4.44 MMbpd. The second-largest governmentowned refiner is China National Petroleum Corp. (CNPC)— the parent company of PetroChina. CNPC operates 3.44 MMbpd of refining capacity. China National Offshore Oil Corp.

(CNOOC) is the third-largest state-owned refining company, with 0.6 MMbpd of production capacity. In addition, small local refineries (referred to as “teapot” refineries) are in operation, with a combined refining capacity exceeding 2 MMbpd.

China has 15.7 MMtpy of total ethylene operating capacity and is ranked second in the world after the US. Six ethylene plants have a production capacity exceeding 1 MMtpy. Sinopec and CNPC are the main ethylene producers.

According to China’s 2011–2015 petrochemical plan, by 2015, three to four refining bases (with 0.4 MMbpd of capacity) and three ethylene bases (with 2 MMtpy of capacity) will be in operation. The average capacity for Chinese refineries will exceed 0.12 MMbpd, and ethylene production capacity will exceed 0.7 MMtpy. Total crude oil processing capacity will reach 12 MMbpd. Ethylene capacity is expected to reach 2.7 MMtpy.

India is becoming a major refining power. In 2011, India’s

total crude processing capacity reached 4.04 MMbpd; nearly 64% of the country’s refining capacity is controlled by publicsector refineries. Aggregate demand of refined products for the domestic market will reach 4 MMbpd in 2015. New refineries and expansion plans will continue, thus increasing India’s refining capacity to 5.04 MMbpd by 2015. As a major petrochemical producer and consumer, India has seven ethylene complexes with a total capacity of 2.51 MMtpy, and is ranked 15th in the world. In 2006, the Indian government established the Petroleum, Chemicals and Petrochemicals Investment Regions (PCPIRs) to promote petrochemical industry investment. The PCPIRs will help boost India’s ethylene capacity to nearly 8 MMtpy by 2014.

Future challenges. While the Asian refining industry is booming, it also faces new challenges: Tight oil supply and growing dependence on imports.

Asia’s proven crude oil reserves are smaller than those in the Middle East and the Americas. Consequently, Asia is not selfsufficient. China is the second-largest oil-importing country after the US. In 2011, Chinese crude oil imports increased to 254 MMt, with imports supplying 55.1% of crude oil demand. India is the fourth-largest oil-importing country; over 80% of its daily crude demand is met through imports. India imported 163.51 MMt of crude oil in 2011.

Rising refinery over-capacity. The global recession’s stifling impact on demand is manifesting itself at a time when Asia-Pacific’s refining capacity is surging. This scenario is driving down Hydrocarbon Processing | DECEMBER 2012 67

2012 Petrochemicals Review signs of recovery. Refining profits are low; the threat of excessive production is still a problem. Accordingly, some measures are being taken to achieve sustainable development.

Expanding energy sources and diversification. Despite steady domestic petroleum output, Asia is expanding its energy resources from the Middle East, Russia, Africa, South America and other countries. Diversity is needed to ensure security of energy supplies and safety. The rapid development of alternative fuels including coal, natural gas, biomass and others is being explored. Biofuels, gas-to-liquids and coal-to-liquids are supplementing the oil-based fuel market. Refineries are striving to process more diverse materials.

Optimizing crude processes and increasing fuel yields.

Since Asia-Pacific is poor in oil reserves, it is very important to fully utilize all resources. Such efforts include optimizing refining processes and maximizing yields of transportation fuels. For example, light oil yields are less than 75% in China—much less than the 82.7% at North American refineries. Some solutions are needed to increase the economic benefits and competitiveness of refining companies in Asia-Pacific. Such actions include increasing complexity, upgrading heavy-oil processing, increasing light oil yields and optimizing refining operations.

For example, PetroChina is researching technologies to handle Venezuelan extra-heavy oil. Its proprietary hydrogendonated thermal cracking (HDTC) process can produce marine oil and bitumen from Venezuelan extra-heavy oil.

Three commercial units using the HDTC technology are in operation. The HDTC process provides good performance for viscosity reduction of extra-heavy oils. Commercial-scale experiments on delayed coking technology to process 100% Venezuelan extra-heavy-oil vacuum residue were successfully completed by PetroChina.

refining margins and utilization rates. Oil demand in the US and Europe continues to decline. In contrast, Asian-Pacific refiners continue to rely on exports to manage excess supplies. Japan and South Korea are greatly impacted by the global recession and demand downturn. Both nations’ economic growth is centered on external demand. In addition, India, Singapore, Indonesia, Malaysia and the Philippines have reduced loading rates to adapt to the new market. At present, China’s crude oil processing capacity is 10.8 MMbpd, and the total crude oil volume processed was 8.96 MMbpd in 2011, with an 83% utilization rate. It is forecast that refinery over-capacity will increase and utilization rates will further decline.

Emerging CO2 emissions-reduction requirements. High energy consumption is accompanied by higher carbon dioxide (CO2 ) emissions by the refining industry. Energy conservation is occurring in response to climate change and sustainable development issues, but it is a long-term task. Emerging Asian economies, especially China, will be under greater pressure to limit CO2 emissions. As China’s carbon emissions are ranked first in the world, saving energy and reducing greenhouse gas emissions are closely related to economic and social development. The Chinese government has incorporated climate change and CO2 emissions into national economic and social development plans by comprehensive legal, economic, scientific and technological measures. Under the Copenhagen Accord, China promised to reduce CO2 emissions per unit of GDP by 40% to 45% in 2020.

In the future, Chinese and Indian petrochemical companies will bear more pressure to reduce CO2 emissions.

Strategies for sustainable development. Since 2008, the

Asian-Pacific refining and petrochemical industries have suffered from the international financial crisis. At present, the Asian-Pacific refining and petrochemical industries are showing

Reducing CO2 . CO2 emission reductions are ac-

Daqing Karamay Jilin Dushanzi Urumqi Yanshan Yumen

Panjin Jinzhou Tianjin Dagang

Renqiu

Yinchuan

Zibo Lanzhou Changqin Luoyang Pengzhou

Wuhan

Fushun Liaoyang Dalian

Qingdao

Changling Jiujiang Ningbo Quanzhou Guangzhou Huizhou Nanning

Main refineries Total refining capacity reached: 10.8 MMbpd Main ethylene complexes Total ethylene capacity reached: 15.7 MMtpy

Maoming Hainan

FIG. 1. China’s refining and ethylene production facilities.

68 DECEMBER 2012 | HydrocarbonProcessing.com

Enhancing technology innovation. Asia-Pacific

Nanjing Anqing

tively initiated in response to climate change. Energy conservation and minimizing fossil fuels usage are the most important and direct measures. Possible detailed measures are phasing out older, less-efficient refineries; installing energy-saving equipment and sophisticated technologies; improving energy utilization efficiency; and reducing fossil fuel consumption in production processes. Other options include adjusting the energy structure and developing biofuels to reduce CO2 source emissions.

Shanghai

countries, especially China and India with their enormous market potential, are attracting many foreign investors for the refining and petrochemical industries. However, Asian-Pacific refining and petrochemical technology development remains low.

Asian-Pacific countries need to change economic growth modes; strengthen their technology absorption and re-innovation; improve their integrated innovation abilities; and focus on clean-fuel production, deep processing of heavy oils, and energysaving and CO2 emissions-reduction technologies.

An expanded version of this item can be found online at HydrocarbonProcessing.com.

2012 Petrochemicals Review

INDIA S. MITRA and M. GEORGE, Indian Oil Corp. Ltd., New Delhi, India

PP demand in India is around 3.7 MMtons and is estimated to grow at an annual rate of approximately 13% over the next five years. PP has the greatest demand share, and it accounts for over 40% of the total polyolefins market. There is strong intrinsic growth in the biaxially oriented PP film; several new units are being commissioned. Along with raffia segments and coupled with new capacities, PP is performing strongly in India. This nation exports 0.6 MMtpy of PP. LDPE demand in India is estimated at 0.2 MMtpy. Around 75% of LDPE demand is for film and sheet applications such as packaging and plastic bags; the remainder is directed to raffia lamination. LDPE continues to be substituted by LLDPE. Accordingly, LDPE demand is expected to grow at 2%/yr to 3%/ yr over the next five years, and then plateau.

LLDPE demand is estimated at 1.4 MMtpy, with 70% of the demand used for film and sheet applications. LLDPE is also the most commonly used polymer for roto-molding of water tanks and intermediate bulk carriers. Domestic demand for

(Net Import)/Net export, million bpd

The Indian economy has come a long way since the 1991 economic reforms. A decade and a half of economic reform and globalization is yielding returns that cut across all income groups. The domestic economic expansion has also accelerated growth within the industrial and services sectors.

India is forecast to emerge as one of the top five economies by 2025. This nation’s rapid economic growth has spurred demand for a wide range of petrochemicals. Consumption of key petrochemicals, such as polymers, is projected to show double-digit increases due to strong support by India’s growing middle class.

The after-effects from the global recession did 2.0 not significantly impact India due to strong internal fundamentals. Yet, currency exchange rate probLPG lems are a reality. If India is to sustain this rapid 1.5 Naphtha growth rate, then certain development areas of the Gasoline nation and its people will need more attention.

Kero/jet 1.0 The polyolefin industry plays a vital role in ecoGasoil nomic development. This industry is one of the Fuel oil 0.5 fastest-growing sectors within the Indian economy.

Plastics have not only supplemented, but are also 0.0 substituted for conventional materials in many applications. Energy efficiency, competitive packag-0.5 ing alternatives, consumer durable and nondurable applications, advanced materials in high-tech ap-1.0 plications, etc. are some of the drivers for substi1998 2002 2004 2006 2008 2012 tution. Plastics have penetrated all sectors and are Year Source: Purvin & Gertz essential to daily life.

Yet, the per-capita consumption of polymers FIG. 1. Indian refined product balance, 1998–2015. in India languishes at 6.5 kg/yr compared to the global average of 24 kg/yr. In developed nations, the per-capita consumption of polymers exceeds 80 kg/yr. There are significant growth opportunities in India’s polyolefins industry.

HMEL—2012 GAIL PP—450 Mtpy India is a net exporter of petroleum-based prodHDPE/LLDPE—500 Mtpy PE—450 Mtpy, 2014 ucts, as shown in FIG. 1. This nation has the po- IOCL Mtpy tential to export 1.5 MMbpd of these products by HDPE/LLDPE—650 PP—600 Mtpy 2015. Benefiting from greater availability of naphtha from recent refinery capacity additions, several major petrochemical producers have announced OPaL—2014 new polymer plants, as shown in FIG. 2.

PE—1,100 Mtpy PP—350 Mtpy

Polymer supplies are set to boom. The key to

sustainable growth is facilitating the increased usage of plastics while taking care of environmental concerns through initiatives for collection, disposal and waste recycling.

Polyolefins. FIG. 3 shows the supply/demand scenar-

io for polyolefins in India. While PE is more balanced in supply and demand requirements, PP will see an exportable surplus over the short term (FIG. 3).

RIL PE—1,200 Mtpy PP—2,700 Mtpy LDPE/LLDPE—400 Mtpy, 2014

MRPL—2015 PP—450 Mtpy

2015

BPCL—2014 PE—220 Mtpy PP—60 Mtpy

HPCL HDPE/LLDPE—700 Mtpy PP—340 Mtpy

Blue—existing Red—new/proposed

Source: IOCL Analysis

FIG. 2. Polyolefin production capacities and operating companies.

Hydrocarbon Processing | DECEMBER 2012 69

2012 Petrochemicals Review 5,000

6,000

4,000

5,000 4,000

PP supply and demand, Mtpy

PE supply and demand, Mtpy

younger than the southern population, as 50% of the population growth in India will be in the northern states over the next decade.

3,000 3,000 Accordingly, the northern region will witness a 2,000 2,000 demand explosion for polymers, provided that sup1,000 1,000 plies are available. IOCL’s polymer plant at Panipat 0 0 has proven to be a catalyst for new growth in northern 2011 2012 2013 2014 2015 2011 2012 2013 2014 2015 India. The new polymer plant, which came online in Supply, Mtpy Supply, Mtpy 2,800 2,800 2,910 4,075 4,710 3,810 4,140 4,390 4,980 4,980 Demand, Mtpy Demand, Mtyp 3,119 3,425 3,763 4,144 4,558 3,380 3,765 4,175 4,613 5,063 Bhatinda, will support further growth in this region.

Polyethylene Polypropylene Initiatives by the Indian and Pakistani governAAGR – PE-9.2% and PP-12.8% ments to stimulate and enhance cross-border trade Regular imports in PE (~850 Mtons) and PP (~250 Mtons) via the land route between their countries will add a new dimension to petrochemical markets. PakiFIG. 3. Polymer supply-demand trends for the Indian sub-continent, stan is the fifth most-populated nation in the world, 2011–2015. and the northern Indian plants are within 400 km from Lahore, Pakistan’s major consumption center.

IOCL is already exporting significant volumes—up to 8,000 LLDPE is expected to increase by 12.5%/yr due to growth in metric tons/month of PP and ethylene oxide (EO) to Pakithe film and sheet sector, combined with equally strong destan. The new producer from Bhatinda, HMEL, is certain to mand growth in applications such as water tanks, automobile follow suit with PP. components and toys.

HDPE demand is estimated at 2 MMtpy. The market is varied, with 23% of the demand for film and sheet, whereas injecGovernment intervention. As a sector, the Indian plastics intion and blow-molding applications each account for 19%. Rafdustry has received little attention from policy-makers. It is time fia is also a significant application for HDPE in India. HDPE that this industry is recognized for its role and contributions to pipes, although accounting for only 12% of the market, are domestic growth and development. slated for huge expansion through the agriculture/irrigation Government focus areas should be facilitate the creation and construction sectors. HDPE demand is also forecast to of a world-class infrastructure through policy initiatives such grow 10%/yr. India is a net importer of HDPE. The mentioned as PCPIRs, adapting a cluster approach and developing and projections will result in an investment potential of $8 billion promoting plastic parks and petrochemical export processing in upstream cracker complexes and polymer plants, and about zones. Likewise, programs must focus on investing in R&D and $6 billion in the downstream plastics sector. human resource development, modernization and technology upgrading, adopting new-generation technologies, improving operational efficiencies, facilitating environmentally friendly Supply-driven market. The Indian polymer market is supply and recycling technologies, and removing structural constraints driven. The major consumption states are Maharashtra, Gujarat, for the sustained growth of the domestic industry.

Daman, West Bengal and Uttar Pradesh. One of the common The Indian petrochemical industry is poised for a supplythreads binding these states is the proximate polymer plant. driven demand boom, given India’s key drivers in demographNandan Nilekani, co-chairman of Infosys, explains the exics (trained labor force, a large working-age population and inistence of a “double hump” in India’s demographics. The first trinsic population growth) and per-capita income growth. hump came from southern India and resulted in economic An expanded version of this item can be found online at growth in that region. He believes that the second hump will HydrocarbonProcessing.com. come from the northern states. The northern population will be

JAPAN M. YONEYAMA, IHS Chemicals, Tokyo, Japan

The Japanese economy showed steady recovery for 2003– 2007. However, due to the global recession in late 2008, Japan’s GDP growth decreased to –1% in 2008 and to –5.5% in 2009. Due to the counter-effect from the low growth rates in 2009 and 2010, the GDP growth rate showed high recovery of 4.4% in 2010. In 2011, the earthquake on March 11 damaged some manufacturing plants in the Tohoku and Kanto Districts. The damage to part producers in Tohoku District disrupted the “supply chain” to user industries, especially the 70 DECEMBER 2012 | HydrocarbonProcessing.com

automobile industry. As a result, 2011 automobile production in Japan decreased by 13% from 2010 levels.

TABLE 1 summarizes Japan’s ethylene production and ethylene-equivalent consumption and trade. The ethylene-equivalent demand increased during 2002–2007. However, it decreased in 2008 and 2009 because of the global recession. In 2010, ethyleneequivalent consumption recovered, but it decreased again in the following year. In 2011, the exports of ethylene-equivalent chemicals decreased and imports increased.

TABLE 2 shows the correlation between the growth of ethylene-equivalent demand and GDP growth. The table shows that domestic ethylene-equivalent demand strongly correlated with economic conditions. Although the growth rate of domestic demand has the same tendency as the GDP growth rate,

Production and consumption: Ethylene.

2012 Petrochemicals Review ethylene-equivalent consumption is less than that for GDP. A possible explanation is that petrochemical-consumer companies have been shifting their manufacturing base from Japan to other Asian-Pacific countries and increasing imports of finished goods, such as electrical appliances, toys and plastic bags.

FIG. 1 shows that the volatility of ethylene-equivalent demand is higher than the volatility of GDP. This can be explained by the inventory cycle. Production cannot be modified as quickly as inventory during recession times. Consequently, these conditions cause overshooting or undershooting of ethylene-equivalent demand against GDP changes. FIG. 2 shows domestic monthly ethylene production rates for 2010 and 2011.

The March 11 earthquake damaged chemical plants and refineries in Tohoku and Kanto Districts. Four ethylene crackers were shut down; these crackers have a total ethylene production capacity of 1.8 MMtons and account for 23% of Japan’s ethylene capacity. Among these four crackers, two crackers were started up less than one month after the earthquake. The other two ethylene plants were started up in May and June of 2011. Due to the shutdowns, ethylene production was lower in 2011, as shown in TABLE 1. However, Japan’s ethylene production was affected more by the global economic slowdown triggered by the euro crisis.

FIG. 3 shows the monthly ethylene-equivalent consumption and net exports in Japan. Please note that the monthly statistics include a time lag between calculated and actual consumption because of inventory changes. Ethylene-equivalent consumption was affected by the March 11 earthquake. Consumption sustained a relatively high level from April to August of 2011 because of the recovery and reconstruction. However, consumption began decreasing in September 2011 due to the global slowdown.

TABLE 2 summarizes aromatics production from 2000–2011. Like ethylene, the aromatics production also increased during 2003–2007; however, it dropped by 9% in 2008 and by 4% in 2009. In particular, benzene decreased by 13% in 2008 and further decreased by 7% in 2009 due to low styrene monomer (SM) production. Conversely, xylene production

Aromatics.

TABLE 1. Ethylene-equivalent production, 2000–2011

Trade. As shown in TABLE 1, Japanese ethylene-equivalent exports increased during 2001–2007 in response to the steady growth of the world economy, especially in Asian-Pacific counTABLE 2. Japan’s aromatics production, 2000–2011 Year

Benzene, Toluene, Xylene, Total, thousand tons thousand tons thousand tons thousand tons

2000

4,425

1,489

4,681

10,595

2001

4,261

1,423

4,798

10,482

2002

4,313

1,548

4,916

10,777

2003

4,551

1,584

5,213

11,348

2004

4,758

1,634

5,395

11,787

2005

4,981

1,676

5,570

12,227

2006

4,874

1,633

5,727

12,234

2007

5,246

1,637

6,006

12,889

2008

4,580

1,437

5,698

11,715

2009

4,259

1,415

5,628

11,302

2010

4,764

1,393

5,935

12,092

2011

4,413

1,340

5,753

11,506

Source: METI

Production, Apparent Exports, Imports, Net trade, thousand consumption, thousand thousand thousand tons thousand tons tons tons tons

2000

7,614

5,887

2,138

411

1,727

2001

7,361

5,727

2,051

417

1,634

2002

7,152

5,388

2,157

393

1,764

2003

7,367

5,548

2,238

420

1,818

2004

7,570

5,752

2,206

388

1,818

2005

7,618

5,771

2,270

422

1,848

2006

7,522

5,717

2,294

489

1,805

2007

7,739

5,742

2,391

394

1,997

2008

6,882

5,595

1,829

541

1,288

2009

6,913

4,380

2,940

407

2,533

2010

7,018

5,117

2,435

535

1,900

2011

6,689

5,205

2,193

709

1,484

GDP growth and ethylene-equivalent demand, %

Year

did not decrease so much due to steady demand for paraxylene (PX) and purified terephthalic acid (PTA). Toluene production is linked to the operating rate of disproportionation and dealkylation units. Aromatics production recovered in 2010 but decreased in 2011.

TABLE 3 shows production and consumption (trade) of aromatics in 2010 and 2011. As shown in TABLE 3, benzene production and consumption decreased in 2011 due to low SM production and declining exports. Toluene production also decreased due to declining exports. However, toluene consumption increased by 9% because of strong demand for disproportionation units and gasoline blending components. Xylene production decreased as several production facilities were damaged by the earthquake. Demand remained low until summer 2011, but recovered in Q4 in response to growing demand by other Asian-Pacific countries.

20 15

Ethylene-equivalent demand, % GDP growth, %

10 5 0 -5 -10 -15 -20 -25

2000 01’ 02’ 03’ 04’ 05’ 06’ 07’ 08’ 09’ 10’ 2011 Source: METI

FIG. 1. Ethylene demand and GDP growth, 2000–2011.

Source: METI

Hydrocarbon Processing | DECEMBER 2012 71

2012 Petrochemicals Review tries. However, in 2008, exports decreased by 24% due to the global recession. In 2009, exports increased and sustained high levels through 2010, fueled by growing petrochemical demand in other Asian-Pacific countries. However, exports decreased in 2011 mainly due to earthquake damage to petrochemical production facilities. The economic slowdown in late 2011 also adversely affected exports.

5 0

700

-5 600 -10 500

400

-15

2010 2011 Percent change, 2011/2010 Jan Feb Mar April May June July Aug Sept Oct Nov Dec

Percent change, 2011/2010

Monthly ethylene production, thousand tons

800

-20

Source: METI

Ethylene-equivalent imports in 2011 increased by 33% to make up for production shortages caused by the March 11 earthquake. A strong yen also stimulated imports.

From FIG. 4, it can be seen that ethylene-equivalent net exports decreased, especially from April to July 2011, due to production facility damage. After the summer, net exports recovered as the facilities again began operating. However, with slower economic conditions in late 2011, ethylene-equivalent exports decreased in November and December. A strong yen also affected the situation, with decreases in exports and increases in imports.

Profits. TABLE 4 summarizes sales and profit for the petrochemical segment of 11 Japanese chemical companies operating ethylene crackers. The profit of the petrochemical segment showed cyclicality in the past. Since the trough of 2001, profits and sales increased due to a tight supply-and-demand situation until 2007. However, a loss was recorded from late 2008 to March 2009. The financial loss continued in fiscal 2009, but it recovered in 2010. It was estimated that fiscal 2011 would be a difficult year for the petrochemical industry. Effects from the earthquake and declining export levels along with low petroTABLE 3. Aromatics balance—products, imports, consumption and exports, 2010–2011

FIG. 2. Monthly ethylene production.

Benzene 40 35 30 25 20 15 10 5 0 -5 -10 -15 -20

Percent change, 2011/2010

Ethylene-equivalent consumption, thousand tons

800 700 600 500 400 300 200 100 0 -100 -200 -300 -400

2010 2011 Percent change, 2011/2010 Jan Feb Mar April May June July Aug Sept Oct Nov Dec Source: METI

2010 2011

-20 -30

100 2010 2011 Percent change, 2011/2010

50 0

Jan Feb Mar April May June July Aug Sept Oct Nov Dec Source: METI

FIG. 4. Ethylene-equivalent net exports.

-40 -50 -60

Percent change, 2011/2010

Ethylene-equivalent net exports, thousand tons

-10

150

Imports, thousand tons

2010 2011

54

86

59%

32

63

97%

1

41

Exports, thousand tons

326

241 –26% 309

% –3% 4,000%

Consumption, 4,507 4,250 –6% 1,126 1,223 9% 4,986 4,986 thousand tons 187 –39% 945 833

0% –12%

Source: The Japan Aromatics Industry Association

TABLE 4. Profitability of the petrochemical segment of Japanese chemical companies, 1997–2010

FY1997

2,506

49

FY1998

2,094

34

2

FY1999

2,297

91

4

FY2000

2,588

91

4

FY2001

2,398

8

0

FY2002

2,595

43

2

2

FY2003

2,748

65

2

FY2004

3,420

213

6

FY2005

3,963

175

4

FY2006

4,537

273

6

FY2007

5,274

211

4

FY2008

4,470

–183

–4

FY2009

3,469

–9

0

FY2010

3,922

75

2

Source: METI

72 DECEMBER 2012 | HydrocarbonProcessing.com

Xylene %

Sales, billion yen Profit, billion yen Profit on sales, %

0

200

2010 2011

Production, 4,764 4,417 –7% 1,393 1,340 –4% 5,935 5,758 thousand tons

FIG. 3. Ethylene-equivalent consumption.

250

Toluene %

2012 Petrochemicals Review chemical demand—especially in the automobile, electrical and electronics industries—still remain.

Investment. Japanese petrochemical companies actively invest

in both domestic and overseas markets. The companies prefer commodity chemicals for overseas investment projects, and they focus on high-performance chemicals and feedstock ventures in Japan.

In commodity chemicals, almost all investments are made in countries with abundant raw materials, such as the Middle East, or nations with growing consumer markets, such as other Asian-Pacific countries. Sumitomo Chemical started up its ethylene complex in Rabigh, Saudi Arabia with Aramco in March 2009. Mitsubishi Group companies have invested in a cracker project in SHARQ, Saudi Arabia. Mitsui Chemical announced its alliance with SABIC in the urethane business in February 2012. Mitsui will license its toluene diisocyanate and methylene diphenyl diisocyanate process to SABIC. In China, several projects are in progress. In 2009, Mitsui Chemicals started up a bisphenol A (BPA) plant, and it plans to start up a phenol and acetone plant in 2014. Mitsubishi Chemical started up a PTA plant in 2006, a polytetramethylene ether glycol plant in 2009, and BPA plant and polycarbonate plants during 2010–2011. Mitsui Chemical also has been expanding its production capacities in Indonesia, Thailand and Singapore, while Mitsubishi Chemical is expanding its petrochemical production capacity in India.

In domestic investment, petrochemical companies focus on propylene and aromatics rather than ethylene. US-based, lowcost shale gas is changing the competitiveness of North American gas crackers. For propylene, in addition to metathesis plants from Mitsui Chemical and JX Nippon Oil & Energy Corp., Mitsubishi Chemical started up a metathesis plant in Kashima.

Furthermore, many companies are now developing technology for on-purpose butadiene production, including Mitsubishi Chemicals and Asahi Kasei Chemicals.

In addition to large-volume petrochemicals, Japanese petrochemical companies are expanding their businesses into valueadded products, both in Japan and in other Asian countries, such as performance materials for IT and electronics industries. Engineering plastics are good examples of high-performance products. Japanese companies have invested in specialty engineering plastics projects located in Japan and commodity engineering plastics outside of Japan. Mitsubishi Rayon acquired Lucite International Group Ltd., a leading methyl methacrylate (MMA) producer. Mitsubishi Rayon is expanding MMA capacity in the US, Korea and Saudi Arabia, along with poly methyl methacrylate capacity in Thailand, Korea and Saudi Arabia. Polyplastics, Toray and Sumitomo Chemical have expanded liquid crystal polymer capacities in Japan. Toray, Tosoh and DIC have expanded domestic polyphenylene sulfide capacities. Conversely, Polyplastics plans to start up a propylene oxide/SM plant in Malaysia.

An expanded version of this item can be found online at HydrocarbonProcessing.com.

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Maintenance A. POLING, HSB Solomon Associates, LLC, Dallas, Texas

Reliability and maintenance: The path to world-class performance

TRADITIONAL VIEWPOINT The focus in a traditional manufacturing environment has been on driving maintenance costs down. Rather than eliminating the root cause of these costs, traditionalists focus on optimizing their reactive environment, as shown in FIG. 1.

Companies operating in this mode are plagued by perpetual equipment failures, and constantly changing priorities and maintenance schedules. Although there is a focus on driving down maintenance expenses, these costs are primarily determined by the volume of maintenance work, which is largely uncontrollable.

Best performers in this environment have maintenance costs that approach 2% of the plant replacement value (PRV). While this figure was quoted for decades as world class, at best, it is average performance in the present global environment.

Traditional maintenance cultures suffer from frequent production interruptions, subsequent production limitations, excessive offspec product generation, and, ultimately, unsustainable margins that can quickly turn into operating losses. Result: Capital replacement costs are considerably higher, thus further eroding company profits.

‘Penny wise and pound foolish’ traditionalist. The conse-

quences of continuing to operate in a traditional maintenance environment are many. A larger maintenance organization must

deal with excessive equipment repairs and replacements that come with a larger workforce and higher number of failures.

Total direct costs in the form of craft labor and repair materials are significantly higher in this environment. The loss of valuable production capacity is often overlooked in the traditional maintenance culture, where all eyes are focused on maintenance costs.

The old adage “penny wise and pound foolish” is applicable here. While trying to minimize maintenance costs (penny wise), untold profits are lost (pound foolish) due to maintenance-related downtime. Additionally, traditional maintenance organizations lack discipline relative to controlling

Maintenance costs

Total

Reactive Proactive Maintenance costs

100%

FIG. 1. RAM optimization with corresponding maintenance costs.

98 Effectiveness of mechanical availability, %

Reliability and maintenance (RAM) are being leveraged worldwide as competitive advantages in the hydrocarbon processing industry (HPI). Yet, most manufacturing operations continue to struggle with unreliability and subsequently high maintenance costs. The change in the global business environment has driven RAM performance to new levels, surpassing benchmarks that have been quoted for decades.

A leading performance improvement company for the global energy industry has collected and analyzed more than 30 years of performance data through its International Study of Plant Reliability and Maintenance Effectiveness (RAM Study).1 The data shows that there are two distinct cultures in the RAM community—traditional and progressive.

The traditional culture believes that failures are inevitable.

Companies operating in a traditional culture view equipment failure as normal, and they behave passively as if they have no influence over the outcome. In contrast, companies operating in a progressive culture strive for failure-free operations; everyone is focused on defect elimination and uninterrupted operation.

Industry leaders 97

Sustainable High mechanical availability and low cost

96

Low mechanical availability and high cost Not sustainable

95 94

Facility 2 Maintenance cost per PRV, %

>6

FIG. 2. Pathway to improving maintenance and reliability at HPI facilities.

Hydrocarbon Processing | DECEMBER 2012 75

Maintenance turnaround scope. Everything imaginable gets loaded into the turnaround, so their durations are longer even though they occur more frequently.

PROGRESSIVE VIEWPOINT The focus in the progressive manufacturing environment is on driving up reliability. Progressives recognize that the root cause of maintenance cost is equipment failure; consequently, these companies focus on defect elimination.

SURVIVAL IN NATURE “It is not the strongest of the species that survives, nor the most intelligent that survives. It is the one that is the most adaptable to change.”

—Charles Darwin

The best performers have maintenance costs approaching 1% of PRV. And mechanical availability in progressive maintenance environments is 97% or higher, with the best performers approaching 99%, which includes annualized downtime for turnarounds, as shown in FIG. 2.

Minimal downtime for the progressives. The most significant benefit of a progressive culture is the reduction in maintenance-related downtime caused largely by corrective maintenance due to unplanned equipment failures. Total maintenance downtime is also influenced by planned downtime, such as turnarounds, as shown in FIG. 3.

Progressive maintenance organizations have reduced the frequency of turnarounds to an average of five to seven years, in comparison to traditional maintenance organizations that do so every year. Progressive organizations have also controlled the duration of their turnarounds by limiting the turnaround scope to work that can only be done during a turnaround.

REACTIVE VS. PROACTIVE MAINTENANCE The type of maintenance work performed by “It is not the strongest of the species that traditional organizations is reactive in nature; somesurvives, nor the most intelligent. It is the one thing is broken, and it must be repaired or replaced. that is the most adaptable to change. Reliability By contrast, the majority of work in a progressive environment is proactive, continuously monitoring and maintenance are tools in the manufacturing the condition of critical equipment so problems can survival tool kit.” be resolved prior to failure. If you viewed the entire —Al Poling, RAM Study Project Manager, spectrum of maintenance behaviors from totally reactive to totally proactive, you would find a bellHSB Solomon Associates, LLC shaped curve with a long tail on the right side, representing the large number of traditional maintenance organizations in transition, as shown in FIG. 4. On the Although these companies also streamline maintenance left side of FIG. 4, the curve is rather steep, as there is a limit work processes to optimize efficiency, they are not distracted as to how good you can be. Every manufacturing site is someby continuous equipment failures. Such groups know that each where on that continuum, with most moving incrementally in 1% increase in mechanical availability results in a 10% reducthe proactive direction. Those at the far end of the reactive side tion in maintenance cost. of the curve continue to shut down, as their operation is no longer competitive, and it cannot be sustained.

SURVIVAL IN A GLOBAL MARKETPLACE

7

6

Downtime, %

5

Risk averse vs. Risk minimization. Traditional mainte-

Turnaround Unplanned operations Planned operations Unplanned routine maintenance Planned routine maintenance

nance organizations are largely risk averse; fear of change drives their behavior. Progressive maintenance organizations are constantly working to improve, and do not accept the status quo. As a result, progressive maintenance organizations continue to improve, while traditional maintenance organizations fall further behind. Manufacturing organizations are most vulnerable when shutting down or starting up equipment. Being able to operate in steady-state conditions within a progressive maintenance culture enables companies to minimize exposure and subsequent risk.

4 3 2 1 0 Best performers

Poor performers

FIG. 3. Best performers vs. others in planned and unplanned maintenance activities as recorded downtime (equipment unavailability).

76 DECEMBER 2012 | HydrocarbonProcessing.com

PATH TO WORLD-CLASS PERFORMANCE World-class manufacturers achieve high reliability at lower cost. These companies recognize the value of reliable operations and focus on failure elimination. These best performers build reliability into their corporate strategy and compete effectively in the global marketplace.

From an operational perspective, a progressive maintenance culture offers numerous advantages. The reduction in downtime achieved through the increase in equipment reliability provides additional (spare) capacity. Companies with this advantage enjoy greater margins on their products as maintenance costs are distributed across greater production.

In addition, superior product quality can be achieved and sustained through uninterrupted operations, leading to a net result of increased revenue and greater profitability. The detrimental effects of operating in a traditional maintenance culture can make the difference between staying in business and being forced out. Because the majority of the competition continues to suffer from reactive maintenance, progressive organizations can afford to ship their products anywhere in the world and undercut local producers.

However, the world is changing and becoming more dynamic. While initial indications revealed that progressive organizations were more likely found in developing regions, established manufacturers are beginning to embrace reliability.

Soon, no one will be immune to global pressures. It takes years to transition from a traditional maintenance environment to a progressive one. Every day you delay puts your operation more at risk. The path to world-class RAM performance begins with the first step. What are you waiting for?

NOTES Solomon Associates is the leading performance improvement company for the global energy industry and the author of this study.

Number of sites or units

Maintenance

Maintenance cost per PRV

FIG. 4. RAM performance distribution.

AL POLING is a project manager with Solomon Associates, where he works with clients to identify performance improvement opportunities through participation in The International Study of Plant Reliability and Maintenance Effectiveness. He started his technical career as a maintenance and reliability engineer, and has held plant and corporate leadership roles in maintenance and reliability with several companies. Mr. Poling is a certified maintenance and reliability professional (CMRP). He served as the technical director for the Society for Maintenance and Reliability Professionals (SMRP) from 2008 to 2010. Mr. Poling has presented at numerous reliability and maintenance conferences nationally and internationally. Additionally, he has published several white papers and articles on reliability, maintenance and related topics.

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HPIRPC.com

NEW DELHI, INDIA | 9–11 JULY

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Hydrocarbon Processing’s fourth annual International Refining and Petrochemical Conference (IRPC) will be held 9–11 July 2013, in New Delhi, India. IRPC is a market-leading technical conference, providing an elite forum within which industry professionals from around the world can network and share ideas relating to the refining and the petrochemical industries.

The call for papers for IRPC 2013 will open 19 November 2012 and will close 19 February 2013. Please visit HPIRPC.com for a full list of this year’s conference topics and to view instructions for how to submit your abstract for consideration.

As major restructure forces are reshaping the hydrocarbon processing industry (HPI), managers and engineers are actively seeking information and solutions to make their companies more efficient and profitable.

This is your chance to take part in the discussion and learn from key industry players while exploring the latest technological and operating advances in the areas of: plant and refinery sustainability, energy policy, clean fuels, gas treatment, rotating equipment, refining and petrochemical integration, maintenance and reliability, and more.

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Exhibit or Sponsor Limited sponsorship opportunities and exhibitor spaces are available. Contact your local Hydrocarbon Processing sales representative, or Bret Ronk, Publisher, at Bret.Ronk@GulfPub.com or +1 (713) 520-4421.

Refining Developments J. ZHOU and S. VAIDYANATHAN, Fluor Enterprises, Inc. Sugar Land, Texas, and S. KAPUR, Apex PetroConsultants, Houston, Texas

Improve integration opportunities for aromatics units—Part 2 Reformed petroleum naphtha (reformate) is the largest source for aromatics. Integrating refineries and petrochemical plants can provide feedstock synergies and operating flexibility for both facilities. The following case histories further illustrate the benefits possible with such arrangements.

wt%) for the EB unit, while minimizing toluene production.

Toluene and heavier aromatics, if necessary, will be converted TABLE 2. Feedstock qualities of refinery naphtha Feedrate

CASE STUDY 1 A grassroots petrochemical project is developed to produce olefins and styrene monomer (SM) from light liquids derived from local crude oil refining and natural gas condensate production. To optimize upgrading liquid feedstocks to commercial products, this project relies on an integrated process configuration with steam cracking to produce olefins for the polymer units and an aromatics complex to produce benzene for SM production.

Design feedstocks. The aromatics complex will use refinery naphtha (TABLE 1) plus byproduct pygas (TABLE 2) from the steam cracker as the feedstock.

Processing objective. The aromatics complex is designed to produce 590 metric Mtpy of benzene (minimum 99.9

447

Mercaptan sulfur, ppmw

50

Composition C4s

bpcd

65,860

wt%

Properties

Paraffins (P)

85.4

Specific gravity, 15°C

0.651

Naphthenes (N)

10.9

Total sulfur, ppmw

65

Aromatics (A)

3.7

Total nitrogen, ppmw

0

Total

100

Mercaptan sulfur, ppmw

120

ASTM D86 distillation curve Volume %

°C

IBP

28

30%

49

50%

59

70%

78

FBP

141

TABLE 3. BTX production in reforming

wt% 0.1

2,410

Composition

TABLE 1. Feedstock qualities from the olefin’s raw pygas Feedrate, metric Mtpy

metric Mtpy

HN to reformer

Reformate

1,291

893

P, wt%

74

13

N, wt%

19

2

A, wt%

7

85

N+2A

32

–

RONc

–

99.7

Total, metric Mtpy

C5s*

67.1

C6 NA (nonaromatics)

12.2

Benzene

13.1

C7 NA

1.1

Toluene

4.0

C8 NA

0.1

Styrene

1.1

C8 aromatics

0.5

Benzene

C9 aromatics

0.7

Toluene

2.6

32.9

C8 aromatics

2.4

24.0

C9+ aromatics

1.0

11.7

Total *Includes C5 recycles.

100

wt%

Composition 0.6

16.1

Hydrocarbon Processing | DECEMBER 2012 79

Refining Developments into benzene. Excess MXs will be sold. C9+ heavy aromatics will be returned to refinery storage for disposition in the gasoline pool.

Aromatics complex-1. Based on the listed project premise,

the goal is to develop an integrated aromatics complex for maximum benzene production with a configuration similar to FIG. 1.

Naphtha cutpoint. The naphtha feeds to a prefractionator where light ends are removed and routed to the steam cracker furnaces. In addition to full recovery of benzene precursors, TABLE 4. Pygas C6+ to reformate splitter Composition

wt%

C6 NA

36.8

Benzene

40.4

C7 NA

3.5

Toluene

12.3

C8 NA

0.2

EB+MXs

4.5

C9+ aromatics

2.3

Total

100

Flow, metric Mtpy

143

the cutpoint is adjusted to ensure adequate recovery of nC6, while limiting the iC6 paraffins. Also, nC6 can be converted to benzene through reforming, whereas iC6 will have negligible ability for such conversion. Due to the limited benzene amount in the pygas, nC6 is recovered to boost production. The heavy naphtha (HN) feeds the naphtha hydrotreater (NHT) before entering the CCR reforming unit. The HN is highly paraffinic in nature with N+2A= 32, as shown in TABLE 3.

Pygas hydrotreating. Pygas is high in aromatics and is usually not processed in a reforming unit. Raw pygas feeds the pygas hydrotreater (two-stage HT) to remove diolefins and styrene in a first-step selective hydrogenation, followed by olefins hydrogenation and sulfur removal in a second stage.

Alternatively, the pygas hydrotreater can be a first-step HT only for the removal of diolefins and styrene (FIG. 6). A partially treated pygas C5s stream is sent to the steam cracker. The C6+ can be mixed with the HN for olefins hydrogenation and sulfur removal in a common NHT. The effect of this configuratio is a 10% increase for the CCR reformer capacity.

Aromatics in reformate and pygas. Since the benzene production target is high (590 metric Mtpy), with the CCR reformate and pygas’ benzene content of 201 metric Mtpy (sum of 143 and 58, see TABLES 3 and 4), it is necessary to produce additional benzene, 389 metric Mtpy, as shown in TABLE 5, by the hydrodealkylation (HDA) of toluene and heavier arTABLE 6. HDA conversionsa, b

TABLE 5. Aromatics targets vs. sources, metric Mtpy Sources Aromatics

Demand

C7H8 + H2 j C6H6 + CH4

Units

Targets Reformate

Pygas

Excess

Benzene, 99.9 wt%

590

143

58

Toluene

0

294

18

312

214

6

(Note)

A8 (MXs and EB)

Toluene Benzene

Short kg-mole

389

104

3

C 5s

2-stage HT

Raw pygas

1-stage HT

A8

Benzene

1

1

1

kg / kg-mole

92

78

120

78

106

78

metric Mtpy

–312

+265

–14

+9

–170

+125

For simplification purpose, side reactions have been neglected.

Product yields approach stoichiometric for the thermal hydrodealkylation process.

“–” means consumption and “+” means production.

Raffinate C 5s

Raw pygas

2-stage HT

C5s DeC5

Benzene

1

Note: Benzene target to be achieved by converting all of the toluene and some heavier aromatics via HDA

Raw pygas

A9

1

b

(Note)

C8H10 + 2x H2 j C6H6 + 2x CH4

1

a

A9, A10

C9H12 + 3x H2 j C6H6 + 3x CH4

BT extraction DeC5

DeC5

Benzene

Benzene Toluene column column

HA column

Reformate splitter Heavies

HDA To reformate splitter LN

Reforming

Naphtha

LN

NHT

Naphtha

Reforming

NHT C6+

FIG. 6. Pygas hydrotreating options.

80 DECEMBER 2012 | HydrocarbonProcessing.com

MXs

C8+

LN

Reformate splitter

Naphtha

Reforming Xylene column NHT C 9+

FIG. 7. Configuration of aromatics complex-1.

Refining Developments omatics in an HDA unit. Preferentially, all of the toluene and as much of the low-value C9+ aromatics as possible are used to produce the additional benzene. The more valuable MX stream can supplement benzene production in HDA unit. The remaining MXs are sold.

HDA conversions. The reactions take place in the thermal

HDA reactor to produce 389 metric Mtpy (“Demand” in TABLE 5) of additional benzene:

Toluene + H2 → Benzene + Methane, and (C8+ Aromatics) + H2 → Toluene + Methane All of the toluene from the toluene-column overhead and the low-value C9 /C10 aromatics from the HA column overhead are recycled to HDA reactor to produce benzene, with MXs as supplementary feed to the HDA for additional benzene requirement. A stoichiometric amount, 399 metric Mtpy in total benzene is produced, as shown in TABLE 6. This is slightly higher than the required benzene amount, 389 metric Mtpy (TABLE 5) to account for the losses during separation.

FIG. 7 shows the overall aromatics complex configuration.

CASE STUDY 2 This case study is based on a fully integrated grassroots refining and petrochemical complex. The petrochemical facility consists of an aromatics complex, steam cracker and derivative units to produce polyethylene, polypropylene and polystyrene. The aromatics production targets are PX producTABLE 7. Feedstock qualities for Case 2 aromatics complex Crude naphtha

Condensate naphtha

HC naphtha

Feedrate, bpcd

17,100

40,320

3,190

Feedrate, metric Mtpy

1,030

1,715

102

Specific gravity, 15°C

0.723

0.731

0.741

Properties Total paraffins, wt%

66

61

49

Total naphthenes, wt%

23

25

40

tion at 600 metric Mtpy; benzene at a minimum of 330 metric Mtpy required for downstream styrene production; and fuelgrade toluene at 150 metric Mtpy for mogas blending. There is no upper limit on benzene export, assuming a favorable benzene market.

Design feedstocks. The aromatics complex will use refinery SR-heavy naphtha and hydrocracker (HC) heavy naphtha plus treated pygas C6 from the steam cracker as feedstock, as summarized in TABLES 7 and 8.

Processing objective. The design objective of this aromatics complex is to produce 600 metric Mtpy of PX for sale.

Benzene production will be maximized with 330 metric Mtpy for EB unit (EBU) and the balance to be sold. Toluene production is to be 150 metric Mtpy for mogas blending. Excess toluene and C9+ heavier aromatics, if necessary, will be converted into benzene and xylenes. Any excess of C9 and C10 heavy aromatics will be returned to refinery storage for disposition in the mogas and diesel pools, respectively.

Aromatics complex-2. Based on the listed project premises,

the goal is to develop an integrated aromatics complex for maximum benzene and PX production with a configuration similar to FIG. 2.

Naphtha cutpoint. The SR-run naphtha/kerosine cutpoint

are established by balancing the kerosine needs and highly discounted prices for the sale of petrochemical naphtha. Initial cutpoints ensure recovery of all of the benzene and benzene TABLE 8. Qualities of treated pygas C6 cut Total sulfur, ppmw

1

Total nitrogen, ppmw

1 metric Mtpy

wt%

C6 NA

29

17.2

Benzene

138

82.8

Total

167

100

Components

Total aromatics, wt%

11

14

11

N+2A, wt%

45

53

62

HN to reformer

Reformate

Total sulfur, ppmw

400

2,000

< 0.5

P, wt%

61

21

Total nitrogen, ppmw

125

550

< 0.5

N, wt%

26

1

A, wt%

13

78

IBP

71

65

100

N + 2A

52

–

10%

83

80

101

RONC

–

104

50%

99

99

110

FBP

155

151

128

1,810

1,564

ASTM D86, vol%, °C

Total, metric Mtpy Composition, wt%

Composition, wt% Benzene

TABLE 9. BTX production in reformer

1.2

3.7

1.8

Benzene

3.6

11.7

5.0

29.6

Toluene

3.1

4.9

5.9

Toluene

EB

0.9

0.6

0.4

EB

0.6

5.2

MXs

3.2

4.1

2.6

MXs

4.0

24.6

0.2

6.7

C9+ aromatics

2.2

0.2

0

+

C9 aromatics

Hydrocarbon Processing | DECEMBER 2012 81

Refining Developments TABLE 10. Aromatics targets vs. sources, metric Mtpy Targets Aromatics

a b c

Chemical grade, min 99.9 wt%

Sources

Fuel grade, approximately 95 wt%

138

0

150

463

0

Xylenes

600 (PX)

–

385

0

EB

0

–

82

0

82b

A9+

–

–

105

0

105a

Short >8

313a 233c

Can be converted to benzene and xylenes in TDP unit Dealkylated to benzene in isomerization unit PX recovery is assumed to be 97 wt%

TABLE 13. Feedstock qualities of treated naphtha

Transalkylation

Disproportionation

C7H8 + C9H12 j 2 x C8H10

2 x C7H8 j C8H10 + C6H6

kg-mole

Xylenes Toluene Xylenes Benzene j

1

1

2

2

1

1

kg/kg-mole

92

120

106

92

106

78

metric Mtpy

–30

–40

+70

–283

+163

+120

For simplification purpose, side reactions are neglected “–” means consumption and “+” production.

TABLE 12. EB conversiona, b

EB j Benzene + C2H4

Units

Feedrate, bpcd Feedrate, metric Mtpy

37,500 1,564

Properties Total sulfur, ppmw

< 0.5

Total nitrogen, ppmw

< 0.5

Total paraffins, wt%

44

Total naphthenes, wt%

44

Total aromatics, wt%

12

N+2A, wt%

68

Distillation curve, °C

EB dealkylation

b

184

Excess

Toluene

Toluene + A9 j

a

Pygas C6 (TABLE 8)

> 330

Units

b

Reformate (TABLE 9)

Benzene

TABLE 11. TDP—toluene and A9 conversion a, b

a

Demand

D86

IBP

45

C8H10

C6H6

10%

90

kg-mole

1

1

50%

113

kg/kg-mole

106

78

FBP

175

metric Mtpy

–82

+60

Side reactions are neglected “–” means consumption and “+” means production

precursors. An optimal end cutpoint of 145°C (293°F) for the naphtha ensures recovering enough xylene precursors to hit production targets.

Pygas cutpoint. Hydrotreated heavy pygas C6+ has a sig-

nificant octane value, and it contains important fractions of aromatics. For Case 2, toluene is in excess, while the mogas pool needs high-octane blendstocks. The optimal pygas cut strategy is to separate the benzene-fraction C6 from the hydrotreated heavy pygas to supplement reformate for benzene production. The pygas C7+ is routed to mogas blending. If the C7 fraction is retained in the pygas feed stream to aromatics, more fuel-grade toluene (exceeding the 150 metric Mtpy target) must be produced from the aromatics complex. It will increase both capital investment and operating costs of downstream aromatics facilities. Additionally, the high proportion 82 DECEMBER 2012 | HydrocarbonProcessing.com

of EB in the C8 mixture is less desirable for PX production.

It is difficult to separate EB from MXs due to similar boiling points. The high proportion of EB from pygas could also be a bottleneck for the PX loop.

Naphtha feedstock selection. The depentanized naphtha

cut from the crude or condensate feed can either be an aromatics or steam-cracker feedstock. A feedstock PNA comparison is shown in TABLE 7. The N+2A of the condensate HN is higher than that of the crude; so, it will be a better feedstock for the BTX production. Additionally, based on the composition breakdown, the condensate is a better feedstock for benzene production due to its significantly higher native benzene and benzene precursor contents.

Within the selected cutpoint range of C6–145°C (293°F), the condensate naphtha is a better feedstock for reforming and can match the overall production of toluene and xylenes due to higher total content of naphthenic (N7 –N9) and aromatic (A7–A9) species. In summary, based on both N+2A and BTX

Refining Developments potential, the condensate HN is a higher priority feedstock than the crude HN for the reformate production.

As shown in TABLE 7, the HCU HN has the highest N+2A and the most components in either toluene or xylenes precursors. However, the HCU HN contains the least amount of benzene precursors. The highest benzene making capability of condensate HN boosts the benzene production rate to match downstream EBU requirements. The condensate HN is, thus, the highest priority feed, and the HCU HN is chosen as a supplemental feed for reforming to achieve the aromatics production targets. The depentanized crude HN is the lowest priority feed. The total feedstock volumes are varied based upon the desired aromatics production and by manipulating reforming operating severities. The highest priority feed will be completely consumed, whereas the supplemental feed and the lowest priority feed are varied on an as-needed basis to meet processing objectives. Any excess naphtha is sent to the steam cracker for the olefins production.

BTX operation of reformer. With the high BTX potential of the condensate HN and HCU HN (TABLE 9), this aromatics complex sets the CCR reforming unit operating at an optimal severity, producing reformate with a RONc of nearly 104 to achieve the BTX production targets. The alternative choices would be to run the CCR reformer at a lower octane severity but with more throughput and still produce the 600 metric Mtpy of PX or run the CCR reformer at a higher severity and reduce the amount of xylenes recycled in the PX loop. However, more throughput at lower severity requires a larger CCR reformer. Conversely, running the CCR reformer at a higher octane severity would decrease reformate yield, if constant reactor pressure and feed N+2A are maintained.

Toluene and heavier aromatics conversion.

Raffinate

Benzene Toluene to mogas

BT extraction

Benzene column

C7–

PX separation. For Case 2, adsorption technology is chosen over crystallization. The principal advantage is the ability of adsorption to produce 99.9 wt% pure PX with nearly 97 wt% recovery per pass.

Reformate splitter options. As an aromatics production

target, 150 metric Mtpy of fuel-grade toluene is needed for mogas blending. This could be achieved by adjusting extracted toluene draw at the top of the toluene column and sending high-purity toluene to mogas blending (FIG. 8). However, a more cost-effective scheme is adding a reformate splitter sidecut to draw 150 metric Mtpy of unextracted toluene (about 95 wt% purity) for mogas blending. This design strategy allows reductions in downstream capital and operating costs associated with the separation of high-purity benzene and toluene from the combined light reformate and hydrotreated pygas benzene fraction. The reformate splitter with side-cut is a Raffinate Treated pygas C6 C7– Reformate splitter Reformate C5+

BT extraction

Benzene Benzene column

Toluene column

Toluene (95%) to mogas

TABLE 10

shows a comparison of BTX production targets vs. the sources from reformate and pygas feedstocks. This aromatics complex is configured with the licensed process combining conventional disproportionation and transalkylation (with a high degree of feed flexibility between toluene and A9 along with some A10 ). In this configuration, 150 metric Mtpy of net toluene is withdrawn and the remaining toluene is recycled to the TDP reactor to maximize benzene production. A9s recycle to the TDP unit is manipulated for a PX production of 600 metric Mtpy (TABLE 11).

Treated pygas C6

EB dealkylation over EB isomerization. For this case study, optimal economics is achieved by using an EB dealkylation catalyst. This catalyst system minimizes the size and investment of the xylene concentration loop (less EB circulation). The EB dealkylation catalyst selection is also consistent with maximizing benzene production, as shown in TABLE 12.

C8+ to C7 to TDP xylene column

TDP effluent Divided wall column

C 8+ Xylene column

FIG. 9. Reformate splitter option—divided-wall column.

Raffinate Treated pygas C6

Reformate splitter Reforming

Toluene column

BT extraction

Benzene column

Benzene (99.9%) Toluene column

HA column

Toluene (95%) to mogas A10+

TDP PX (99.9%)

NHT

LEs Reformate C5+

Condensate HN HCU HN

Reformate splitter TDP effluent

C8+ to C7 to TDP xylene column

PX separation Xylene column

Isomerization

DeC7

C8+ to xylene column

FIG. 8. Reformate splitter option—conventional column.

FIG. 10. Configuration of aromatics complex-2.

Hydrocarbon Processing | DECEMBER 2012 83

Refining Developments divided-wall column (DWC), as shown in FIG. 9. The middleboiling components of fraction C7 distribute to the top of the partition wall together with the low-boiling components of fraction C6–, as well as to the bottom of the partition wall, but

CASE STUDY 3 A grassroots petrochemical project is developed to produce benzene and purified terephthalic acid (PTA) from light reformate and HN derived from local refinery operations. To optimize upgrading liquid feedstocks to commercial products, this project relies upon an aromatics complex to produce PX for the PTA unit and benzene for sale.

Design feedstocks. The aromatics complex will use the refinery naphtha plus light reformate from the existing refinery reformer as feedstock. The naphtha, as shown in TABLE 13, is hydrotreated SR-naphtha blended with HCU naphtha. To reduce the gasoline-pool benzene content, a reformate splitter is installed in the existing reformer unit to produce a benzenerich stream, as shown in TABLE 14, for benzene extraction in the aromatics complex.

Processing objective. For Case 3, the objective of the aromatics complex is to produce 780 metric Mtpy of PX with 99.9 wt% purity for PTA production. Benzene production is maximized to at least 400 metric Mtpy for sale options. The benzene product purity is 99.9 wt%. All of the toluene and C9+ heavier aromatics, if necessary, will be converted into benzene and xylenes. Any excess heavy aromatics will be returned to refinery storage for disposition in the diesel pool.

TABLE 14. Refinery light reformate Components

wt %

Benzene

39.0

Toluene

2.2

Nonaromatics

58.8

Total

100.0

Flow, metric Mtpy

316

TABLE 15. BTX Production in CCR HN to CCR

Reformate

P, wt%

44

15

N, wt%

44

0

A, wt%

12

85

N+2A

68

-

RONC

-

106

Total, metric Mtpy

1,564

1,361

Benzene

1.3

9.3

Toluene

4.5

24.8

EB

0.7

4.9

MXs

3.6

23.1

C9 aromatics

1.9

19.1

C10 aromatics

0.2

3.9

C11 aromatics

0.2

0.3

along with the high-boiling components of fraction C8+. This concept avoids the contamination of middle-boiling fraction C7 with lighter or heavier fractions. FIG. 10 shows the aromatics complex configuration.

Composition, wt%

Naphtha cutpoint. For this project, the SR naphtha is pre-

fractionated to retain the benzene precursors in the aromatics complex feed and thus maximize benzene production from the complex. The end point of the naphtha is 175°C (347°F), as shown in TABLE 13, which recovers all of the xylene precursors and maximizes the amount of C9 aromatics precursors in the feed. With a transalkylation process incorporated into the aromatics complex, C9 aromatics become valuable sources of additional xylenes and benzene.

TABLE 16. Aromatics targets vs. sources, metric Mtpy

Raffinate Refinery light reformate

Benzene column

BT extraction

Benzene (99.9%) Toluene column

Aromatics

HA column

Targets

Sources

Demand

Refinery light min. 99.9 Reformate reformate wt% (TABLE 15) (TABLE 14)

Reformate splitter Reforming

Benzene

> 400

126

123

Excess

Short

–

> 151

A10+

TDP Treated HN

a

Toluene

–

337

7

344

–

Xylenes

780 (PX)

314

0

–

490c

EB

0

67

0

67b

–

A9

–

260

0

260a

–

PX (99.9%) LEs PX separation Xylene column

Isomerization

DeC7

a

FIG. 11. Configuration of aromatics complex-3.

84 DECEMBER 2012 | HydrocarbonProcessing.com

b c

a

A10

–

53

0

53

–

A11

–

4

0

–

–

Converted to benzene and xylenes in TDP unit EB isomerized to xylenes in Isomerization unit PX recovery is assumed to be 97 wt%

Refining Developments TABLE 17. TDP—Toluene and A9+ conversiona, b

Units

Transalkylation

Disproportionation

C7H8 + C9H12 j 2 x C8H10

2 x C7H8 j C8H10 + C6H6

Toluene +

A9 j

Xylenes

Toluene j

Xylenes

kg-mol

1

1

2

2

1

kg/kg-mole

92

120

106

92

106

metric Mtpy

–80

–104

+185

–414

+239

Benzene 1 78 +176

Dealkylation Units

a b

C9H12 + H2 j C7H8 + C2H6

C10H14 + H2 j C7H8 + C3H8

A9 j

Toluene

A10 j

Toluene

kg-mol

1

1

1

1

kg/kg-mole

120

92

134

92

metric Mtpy

–155

+119

–45

+31

For simplification purpose, side reactions are neglected “-” means consumption and “+” production

Aromatics complex-3. Based on the listed project premise, the

goal is to develop an integrated aromatics complex for maximum benzene and PX production with a configuration similar to FIG. 2.

BTX operation of reformer. With the available naphtha (TABLE 15), the CCR reforming unit is set to operate at a high severity, producing reformate with a RONc of nearly 106 and to achieve the BTX production targets.

Toluene and heavier aromatics conversion.

o Xylene isomerization with EB dealkylation or EB isomerization o PX separation—Adsorption and crystallization.

End of series. November 2012.

TABLE 16

shows a comparison of BTX production targets vs. the sources from reformate feedstocks. As shown in TABLE 17, all of the toluene is recycled to the TDP reactor to maximize benzene production. A9 along with A10 recycle to the TDP unit is manipulated as PX production of 780 metric Mtpy.

Choice of EB isomerization over dealkylation. The EB

isomerization catalyst is chosen since the primary goal is to boost production of PX for the PTA unit from a fixed amount of feedstock.

PX separation. Adsorption technology is chosen over crystal-

lization for Case 3 due to its ability of adsorption to produce 99.9 wt% of pure PX with nearly 97 wt% recovery per pass. FIG. 11 shows the aromatics complex overall configuration.

AROMATIC PRODUCTION STRATEGIES The three presented cases demonstrate the different approaches to configure aromatics complexes to maximize benzene and/or PX production. The aromatics complexes in Case 1 and Case 2 have synergies with both the refineries and the steam cracking for the optimum routing of naphthas. The main tools for optimizing the aromatic complex configuration include: • Feedstock selection and routing • Operating parameters of CCR reformer • Technologies for product optimization: o Toluene conversion—TDP, transalkylation, HDA

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Hydrocarbon Processing | DECEMBER 2012 85

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Select 207 at www.HydrocarbonProcessing.com/RS Hydrocarbon Processing | DECEMBER 2012 87

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

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RS#

Website

(77) (159)

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Air Products & Chemicals Inc. ............................19

(67)

www.info.hotims.com/41435-67

AMACS .............................................................31

(65)

Colfax Americas .............................................. 32 Costacurta SpA Vico .......................................50A Cudd Energy Services ...................................... 53

(86)

ARC’s Collaborative MFG .................................. 74

(57)

www.info.hotims.com/41435-57

Axens ............................................................. 92

(53)

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BASF Corporation ............................................ 24

(96)

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BCCK ..............................................................89

(91)

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(156) (71)

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Carver Pump Company .................................... 22

(153)

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(93) (61)

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Gulf Publishing Company Construction Boxscore.................................... 85 GPC Events—EMGC ..........................................91 GPC Events—IRPC .......................................... 78 Marketplace ............................................ 86–87 Hydro, Inc..................................................... 6–7

(158)

Michell Instruments US .................................... 28

(155)

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(154)

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(152)

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Scott Safety ..................................................50B (72) (88) (160) (78)

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(101)

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(162) (82)

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(85)

(74)

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Toyo Engineering Corporation .......................... 37

(55)

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Trachte USA .................................................... 36

(157)

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(68)

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www.info.hotims.com/41435-85

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Linde AG ......................................................... 26

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LA Turbine ...................................................... 73

Bryan Research & Engineering ......................... 34

(161)

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ITT Industries ..................................................20

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(65)

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RS#

www.info.hotims.com/41435-86

www.info.hotims.com/41435-77

Borsig GmbH .................................................. 29

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AE Solutions .................................................50A Aggreko .........................................................30

Company

(73)

www.info.hotims.com/41435-73

Worley Parsons ................................................12

(151)

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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.

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88 DECEMBER 2012 | HydrocarbonProcessing.com

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Editorial

STEPHANY ROMANOW, EDITOR Stephany.Romanow@HydrocarbonProcessing.com

The last word Throughout this year, Hydrocarbon Processing (HP) has investigated the last 90 years of the hydrocarbon processing industry (HPI) through its monthly editorial, Insight. The HPI has a rich history; this industry is completely ingrained into our daily lives. This month, we will publish the final Insight editorial for this series. Before we leave this project, there are a few final observations that may provide value to HP readers over the next 10 years as we prepare to celebrate HP’s centennial milestone in 2022.

Survival in the HPI requires flexibility. It may be consid-

ered a Darwinian idea, but longevity in the HPI belongs not to the strongest or the most intellectual organizations. Instead, survival hinges on flexibility and long-term planning. Through the years, we have witnessed numerous mega-companies defeated due to unintended consequences stemming from behemoth organizational structures and protocols, and the inability to quickly adapt to market and industrial changes. Change is a constant for the energy industry. Too often, the sources of these changes are beyond the control of HPI organizations.

Politics of energy. The energy industry has always had a contentious relationship with government at all levels. From the beginning, the HPI has protested taxes levied on oil, natural gas and refined products. In looking ahead, the politics of hydrocarbons will continue and, in some cases, become a bitter contest on sustaining jobs vs. environmental agendas. No nation is immune from this debate; even developing nations must address energy policies in constructing their emerging energy infrastructure. Unfortunately for the HPI, elected politicians operate on “political” time while the HPI functions under energy time. Depending on the office and nation, political time can be as little as a two-year office cycle. Energy time is the service life of the HPI facility (60 to 80 years) and is much longer than political time.

Politics can disrupt the energy market. In several developed nations, politics have villianized coal and crude oil as energy resources. Coal is an excellent resource for power generation; yet, permitting barriers are driving power companies to natural gas to avoid the bureaucratic “red tape” on coal-fired facilities. In addition, reactionary politics nearly banned nuclear energy after the 2011 Fukushima nuclear event.

Far-left environmental groups continue to impede drilling efforts and pipeline developments around the world. Such politics ignore the well-paying jobs from drilling, pipelines and, ultimately, the downstream business that are made possible with the exploration and development of all hydrocarbon resources. The pettiness of politics regarding energy sources hobbles economic growth for many nations.

90 DECEMBER 2012 | HydrocarbonProcessing.com

Same problems, different discomfort levels. Interrup-

tions of crude oil sources or refined product supplies pose both concerns and opportunities, depending on the condition and position of the HPI facility. Transportation costs have decreased for crude oil and its refined products. Crude oil and clean transportation fuels are commodity products. This condition will not change much over the next 10 years.

How HPI companies view their business opportunities will evolve. More HPI companies are leaving the refining and marketing/distribution businesses. New independent, nonintegrated refiners own and operate a greater share of refineries.

Many of the new owners are financial groups; this is a major change for the refining industry.

These new entrepreneurs must handle the same problems as the previous owner/operating company. The difference now will be the ability to leverage different assets by the new owner.

Over the past 90 years, there have been periods in which small and agile groups trump large, integrated organizations. Also, mergers of great companies have failed to overcome the tests and hardships generated by the global economy. Such mergers again divide in hopes that the surviving parts will prevail.

Innovation will continue. Developments will focus on conserving energy and producing desired refined products and petrochemicals. Over the next 10 years, the HPI will continue to rely on new equipment, catalysts and so forth to increase production, eliminate waste, reduce emissions, and increase the safety and reliability of facilities.

Communication continues to impact the modern HPI. Communication/automation/monitoring systems are the latest round of innovative advancements creating economic opportunities. Information from the processing unit is captured, recorded and presented to stakeholders, who can then make informed business decisions. Likewise, the Internet and social media now quickly relay news about fires, releases and other negative events. The HPI is interconnected to the global economy, no matter its location or size.

The HPI has adapted to the numerous changes from its past. Likewise, this industry continues to introduce changes that improve the quality of life for all nations. It will be interesting to see what the next years will hold for the HPI and the global economy.

The final word. HP itself is making changes for the new year.

Beginning in January 2013, HP will launch a daily newsletter entitled Newsbrief. Knowledge is power. With the interconnectivity of the global HPI, events across the world have a ripple effect on other economies. The availability of energy supplies is a critical reality.

Hilton Cyprus Nicosia EMGasConference.com

Gulf Publishing Company is Proud to Announce Hyperion Systems Engineering as the Gold Sponsor of the Eastern Mediterranean Gas Conference Hydrocarbon Processing and Gulf Publishing Company are proud to announce Hyperion’s participation as the gold sponsor at the inaugural Eastern Mediterranean Gas Conference (EMGC) to be held spring 2013 in Nicosia, Cyprus. Hyperion Systems Engineering will be one of many market-leading companies participating in this cutting-edge conference dedicated to exploring the planning and development of the natural gas industry in this important new resource region. Noble Energy, Inc. will be the event’s host sponsor.

With a short-list of international operators currently negotiating for the rights to offshore Cyprus blocks 2, 3, 9 and 11 in the Eastern Mediterranean, now is the time for you and your company to get in on the ground floor of the planning and development of the area’s natural gas industry. This important region is home to an estimated 35 trillion cubic feet of recoverable resources, and Cyprus is poised to be the next European LNG hub.

EMGC 2013 will give special focus to the latest market and technology trends related to the exploration, drilling, production, processing and marketing of natural gas in the area. The conference will cover such critical issues as resource potential, leasing/permitting, development plans, infrastructure requirements, government plans and regulations, and more.

Q&A with Adrienne Blume, Process Editor, Hydrocarbon Processing How will the Eastern Mediterranean impact the international gas market?

“Current activity in the area indicates that Cyprus will be the seat of natural gas resource development in the Eastern Mediterranean region. At this time, natural gas pipelines and supply to European Union (EU) member countries are, for the most part, controlled by non-EU nations. Development and production measures in Cyprus, an EU member, and the Eastern Mediterranean will contribute to efforts to establish secure natural gas resources and energy corridors for the EU and beyond. Once Cyprus is able to establish successful operations in the region, such progress is expected to spark additional oil and gas exploration and production across the Eastern Mediterranean.”

Who will be impacted by production gains in the Eastern Mediterranean?

“With such large amounts of resource expected to come online in the next few years, the natural gas supply landscape in Europe will undoubtedly change. In addition to Cyprus, Israel, Egypt, Lebanon and Turkey, the area poised to benefit most from natural gas production in the Eastern Mediterranean is the EU. With 27 member countries representing an estimated population of 503 million, the EU stands to gain increased natural gas resource security through Eastern Mediterranean production gains. Pipelines and liquefaction terminals originating in the Eastern Mediterranean have the potential to serve many EU countries, while future export capabilities could serve buyers around the world, including those across Asia.”

For more information visit EMGasConference.com For more information about conference sponsorships, contact Melissa Smith, Events Director, Gulf Publishing Company at +1 (713) 520-4475 or Melissa.Smith@GulfPub.com.

Hyperion Systems Engineering is a globally operating, independent provider of consulting & advisory services, systems engineering solutions and professional implementation services and support to process manufacturers. With 20 years of experience in the Upstream Oil & Gas, Petroleum Refining & Petrochemicals, Chemical, Power, Water and Metals industries, Hyperion helps its customers reduce operating and supply chain costs, improve safety and increase their overall profitability, always cognisant of environmental impact. For more information visit hyperionsystems.net.

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