Hydrocarbon Processing January 2015

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PROJECT MANAGEMENT Poor purchasing practices can lead to expensive project outcomes ®

HydrocarbonProcessing.com | JANUARY 2015

ROTATING EQUIPMENT Dry gas failures are tied to compressor startup problems

RISK MANAGEMENT New construction planning tools can streamline major capital projects

SPECIAL REPORT:

LNG, NGL and Alternative Feedstocks

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OPNOS`Lɉ JPLU[HUKYLSPHISL¶HTH KL[VTLHZ\YLMHJPSP[`[OH[TLL[Z`V\Y goals and challenges. What’s more, we can build a facility of greater capacity than any other manufacturer. The result is unparalleled economies of scale and reduced total cost of ownership.

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JANUARY 2015 | Volume 94 Number 1 HydrocarbonProcessing.com

38

35 SPECIAL REPORT: LNG, NGL AND ALTERNATIVE FEEDSTOCKS 39

Maximize LPG recovery from fuel gas using a dividing wall column M. Bhargava, C. Nelson, J. Gentry and V. Siddamshetti

45

Shale gas drives new opportunities for US downstream A. Maller, D. Dharia, E. Gbordzoe and N. Lambert

51

Optimize amine sweetening with an optical O2 analyzer S. Hammond

PROJECT MANAGEMENT 55 Avoid counterproductive project management practices H. P. Bloch

ROTATING EQUIPMENT 59 Consider technology to reduce compressor vibration and noise problems Z. Liu

63

DEPARTMENTS 4 10 19 83 85 86 88 90

RISK MANAGEMENT 69 Use a schedule confidence tool to manage project risk

21

PROCESS AUTOMATION AND CONTROL 75 DCS migration: Lessons learned

25

H. Dutta Cover Image: Marathon Petroleum completed its $2.2-B, four-year Detroit Heavy Oil Upgrade Project in late 2012. The revamp project increased the Detroit refinery’s heavy oil processing capacity to 100,000 bpd, five times the amount it could process before the project. It is the only refinery operating in the state of Michigan. Photo courtesy of Marathon Petroleum Corp.

Events Marketplace Advertiser Index People

Reliability

Automation Strategies Control on the wire(less)

27

Project Management German refinery successfully modernizes safety system

29

Global State of the US petrochemical/ chemical industry

33

Petrochemicals Global PE demand growth to drive downstream expansions

R. Conley

SAFETY 81 Without reliability, there can be no safety

Innovations

Plan now to deal with stressed equipment later

Fine-tune monitoring of critical compressors J. Loeken

Industry Metrics

Alternative energy?

J. L. Shaw

73

News

COLUMNS 9 Editorial Comment

Achieve successful compressor startup by addressing dry-gas seal failure S. Zardynezhad

Industry Perspectives

35

Boxscore Construction Analysis Malaysia’s ambitious downstream transformation program

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Industry Perspectives

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EDITORIAL

Keystone XL: It is time to move forward, Mr. President In a media call, the American Petroleum Institute (API) president and CEO Jack Gerard emphasized that it is time for the Keystone XL pipeline to move forward, and he requested urgent action by President Obama. In an earlier address, President Obama related the embarrassing situation on the US’ progress in developing infrastructure projects as compared to the activity level achieved by emerging economies, such as China. Yet, the presidential administration has continued to delay approving the Keystone XL pipeline for over six years. Energy security. According to an API report, the Keystone XL project would create $1.1 trillion in private capital investment at no cost to US citizens. From the same study, the pipeline would provide $120 B to the US economy and create $27 B in government revenue. Mr. Gerard emphasized that the Keystone XL pipeline would create 1.1 MM well-paying jobs and assist in closing the income gap. US energy renaissance. The US is experiencing an energy

renaissance due to developments of shale oil and natural gas. But infrastructures such as pipelines are critical and necessary to allow the US to take a leader position in the global energy market. For example, over 60 LNG projects are under development with the same export goals. The US government must take a leadership position on energy to continue the growth of the energy industry. The “delaydelay” attitude on LNG export facility approvals, pipelines and the lifting of the crude oil ban is hobbling forward progress by US energy companies and the nation. The US can be a leader in energy exports of LNG and crude oil, but infrastructure is needed to bring these ideas to fruition, according to Mr. Gerard. Other nations are intensely pursuing the same goals on energy exports. OPEC recently announced a hold on its output quota to maintain its share of the global oil markets. Australia is building LNG export facilities with the goal of exporting to Asian markets. Lack of decision adds risk to investment markets, especially for infrastructure projects.

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

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

MAGAZINE PRODUCTION / +1 (713) 525-4633 Vice President, Production Manager, Editorial Production Artist/Illustrator Senior Graphic Designer Manager, Advertising Production

Sheryl Stone Angela Bathe David Weeks Amanda McLendon-Bass Cheryl Willis

ADVERTISING SALES See Sales Offices, page 88.

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Alice Murrell

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‘Get out of the way.’ The Keystone XL pipeline will eventu-

ally be built, according to Mr. Gerard. The project will fortify energy security for North America. National infrastructure projects, such as Hoover Dam and the Golden Gate Bridge, were physically completed faster than the long, drawn-out approval process for the Keystone XL pipeline. It is time to move forward on this pipeline project. Other news. A new report titled, “The Economic and Budgetary Effects of Producing Oil and Natural Gas From Shale,” from the non-partisan Congressional Budget Office (CBO), confirms that removing export barriers for US crude oil could incentivize higher domestic production, grow the economy, increase federal revenues and put downward pressure on gasoline prices. 4JANUARY 2015 | HydrocarbonProcessing.com

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

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

John Royall Ron Higgins Sheryl Stone Pramod Kulkarni Pamela Harvey

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

Printed in USA

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17–18 March 2015 | Nicosia, Cyprus

Build Business Operations in the Eastern Mediterranean

Keynote Speaker: Charles Davidson Chairman and CEO Noble Energy

A series of recent discoveries by Noble Energy, the largest operator in the region, has increased the estimated gross resources of natural gas awaiting development in the area to 40 trillion cubic feet (Tcf). Industry-leading companies are preparing to increase their regional presence. At EMGC, executives from operators and service and technology companies active in the region will share insight into their experience with this important new resource area. We invite you to join executives and speakers from top operators and regional governments as they discuss key issues and opportunities in the burgeoning Eastern Mediterranean natural gas industry. You’ll be able to use the knowledge you gain, along with the key connections you’ll form at EMGC, to help your company win new business in the region.

Just a few of the Reasons why you Should Attend EMGC 2015: • Get insight on how your company can profit in this emerging region • Network with executives actively involved in the planning and development of the region • Get updates on exploration, drilling, pipeline and gas processing projects • Learn more about what oil and gas operators have planned for offshore Cyprus as well as updates on Israel, Lebanon, Egypt, Jordan, Malta and Greece • Hear from industry experts about the projected global market impact of the region’s resources • Discover what market and technology trends are driving the development of the Eastern Mediterranean’s natural gas industry • Explore critical issues like LNG, FLNG, pipeline, resource potential, leasing/permitting, development plans, infrastructure requirements, governmental plans and regulations, and more

Conference Highlights Include: • Opening night gala dinner featuring a keynote presentation from Charles Davidson, Chairman and CEO, Noble Energy • Breakfast workshop hosted by Deloitte • Exhibition floor with opportunities to network with companies already established in the region

Visit EMGasConference.com to learn more.

2015 Agenda Overview: Tuesday, 17 March 2015 Session One: The state of the Eastern Mediterranean Invited speakers represent: Noble Energy; Avner Oil Exploration/Delek Drilling; Republic of Cyprus; and Ministry of National Infrastructure, Energy & Water Resources, State of Israel Session Two: Regional exploration updates Invited speakers represent: Delek Drilling, Edison International SpA Israel Branch, and representatives from the Governments of Greece and Egypt Session Three: Regional opportunities and infrastructure challenges Invited speakers represent: Petroleum Geo-Services; Ministry of National Infrastructure, Energy & Water Resources, State of Israel; Deloitte; and IFP Session Four: Regional regulatory and legal issues Invited speakers represent: Herzog, Fox and Neeman; Antonis Paschalides & Co LLC; Cyprus Energy Regulatory Authority; and Nasos A. Kyriakides & Partners, LLC Gala dinner Keynote: Charles Davidson, CEO, Noble Energy

Wednesday, 18 March 2015 Breakfast workshop: Hosted by Deloitte Session Five: Gas monetization: Regional economics of development Invited speakers represent: The Cyprus Institute, Hyperion Systems Engineering Group, Methanex, Technimont, Dor Chemicals, and others Session Six: Gas export options: LNG/FLNG/CNG Invited speakers represent: VVT Vasilikos Ltd, GE Oil & Gas, SeaNG, and RSI Session Seven: Global energy trends: Could the Eastern Mediterranean become a regional supplier? Invited speakers represent: Deloitte, European Commission, Union Fenosa Gas, BG Group, Dolphinus Holdings Ltd and more Session Eight: The future: Obstacles and answers Invited speakers represent: Avner Oil Exploration and Noble Energy

Register by 10 February 2015 and SAVE 10% Early Bird (by 10 Feb. 2015)

Regular Admission

Single Attendee

$1,080

$1,200

Team of Two

$1,944

$2,160

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$5,100

Registration Type

Visit EMGasConference.com to learn more. Lead Sponsor:

Gala Dinner Sponsor:

EMGC 2015 Breakfast Workshop Hosted by Deloitte The workshop will cover the challenges that oil and gas companies will be facing in setting up and operating in the Cyprus environment in the areas of direct taxation, indirect taxation (VAT), human capital and other related operational matters. The aim of the presenters, who are all seasoned practitioners with experience in the industry and the local regulatory environment, will be to guide such companies on how to navigate the challenges and optimize their operational efficiency and related tax cost.

Hosted by:

Speaker Opportunities:

Bronze Sponsor:

Contact Melissa Smith, Events Director at +1 (713) 520-4475 or [email protected]

Sponsorship/Exhibit Opportunities: Key Card & Welcome Package Sponsor:

Bottled Water Sponsor:

Contact Lisa Zadok, Events Sales Manager at +1 (713) 525-4632 or [email protected]

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Editorial Comment

STEPHANY ROMANOW, EDITOR [email protected]

Alternative energy?

Change is a constant. Environmental legislation has been a determining factor in future fuel and energy programs. Preserving the environment has initiated replacing fossil fuels with alternatives such as solar, wind and renewables. It has taken time for alternative energy resources to be developed. Progress is materializing. Here are some recent notable developments: • The BioTfueL project is constructing two demonstration facilities at Sofiprotéol in Venette, France, and at a TOTAL site in Dunkirk, France. BioTfueL is a thermoconversion process that converts second-generation biomass into biodiesel and biojet fuel. Partners of BioTfueL include IFP Energies nouvelles (30%), Axens (3%), Sofiprotéol (12%), ThyssenKrupp Industrial Solutions (19%), the CEA (5%) and TOTAL (31%). The partners have committed €180 MM to the project. Almost €110 MM will be invested to construct the TOTAL Dunkirk demonstration unit. • Neste Jacobs and SunPine plan to construct a Tall Oil Rosin facility in Pitea, Sweden. The Tall Oil Rosin process is a second-generation renewable fuel. The facility will

produce raw tall diesel (a feedstock used in renewable diesel), rosin and tall oil pitch (an energy product for the paper industry). The facility is expected to be operational by the second half of 2015. • Gevo Inc. has licensed its renewable isobutanol process to Highlands EnviroFuels LLC. The facility will use a “Brazilian-style” syrup mill to produce 200,000 metric tpy of fermentable sugars for Gevo’s isobutanol process. Other notables. The Institute of Chemical Engineers awarded recognition to various companies for their achievements in chemical engineering. The award categories also included innovations in renewable and bioprocessing methods: BP’s Hummingbird (bio)ethanol-toethylene process received the Bioprocessing Award sponsored by Newcastle University, UK. The process received a highly commended recognition for the Chemical Engineering Project of the Year Award. Johnson Matthey Davey Technologies received the Sustainable Technology Award sponsored by ABB Consulting for its biodiesel-from-waste-oils process. 50 Oil 40 Shares of primary energy, %

Alternative energy is a point-of-reference term. Natural gas is an alternative energy resource for transportation fuels. As more natural gas resources are developed, natural gas is displacing coal as the primary energy source for electrical power generation. As illustrated in FIG. 1, global energy resources are a mix of hydrocarbons, renewables, hydro and nuclear resources. Finding and applying domestic resources for energy is quite logical: Use what is local and supplement through imports to meet national energy needs. These are logical courses to pursue to expand domestic economic growth.

30

20

Coal

NGL and 38 LNG, alternative feedstocks. Maximizing the energy potential from carbon and hydrogen atoms is driving new developments in global energy markets. New natural gas supplies are redefining transportation fuels and petrochemical markets, as well as power generation. This special report focuses on gas processing technology solutions and trends.

55 Project management.

For many years, reliabilityfocused engineers have observed flawed procurement processes for mechanical equipment. Many requirements are supposedly aimed at the lowest possible lifecycle cost. The author outlines best practices in designing and purchasing major and critical rotating equipment for capital projects.

69 Risk management.

In this case history, a new monitoring system was installed on a critical-service hyper compressor for a Middle East ethylene complex. Downtime for this compressor was extremely expensive for the operating company. A monitoring system was effectively used to prevent catastrophic failures and unplanned downtime.

control 75 Process and automation.

Gas

10 Hydro 0 1965

INSIDE THIS ISSUE

Nuclear

Renewables* 2000

*Includes biofuels Source: BP’s Energy Outlook 2035.

FIG. 1. Shares of primary energy by source: 1965 to 2035.

2035

In 2005, TOTAL’s Port Arthur, Texas refinery, like many existing refining and petrochemical facilities, found itself with an obsolete, at-capacity distributed control system (DCS). The refinery primarily used first-generation equipment that no longer had legacy support from the vendor. This case history explains how the Port Arthur refinery planned and executed an upgrade of its DCS network. Hydrocarbon Processing | JANUARY 20159

| News Fuel cells to experience a bright future due to natural gas Rising natural gas production is facilitating growth for both stationary fuel cells that provide power to business and the utility grid, as well as for expanding applications in light-duty fuel cell electric vehicles. According to the US-based Fuel Cell and Hydrogen Energy Association (FCHEA), the convergence of abundant natural gas supplies and breakthroughs in fuel cell technologies are finding great acceptance by top automotive manufacturers, such as Hyundai and Toyota. Advanced fuel cells are highly efficient and generate no emissions—only water and heat. Stationary fuel cell applications will use both natural gas and methanol as fuel. Mega-consumer-goods companies, such as Coca-Cola, Apple, Microsoft and Procter & Gamble, are expanding stationary fuel systems for power generation. At present, 2 MM MWh of electricity is generated by fuel cell technology in the US, according to FCHEA. Photo: The Titan Plant at Methanex’s Trinidad facility. Photo courtesy of Methanex.

HP STAFF / [email protected]

News

How the EU can progress toward an ‘Energy Union’ The EU has made progress in liberalizing energy markets, and its global leadership on climate change is to be commended, according to the International Energy Agency (IEA). However, a new IEA report indicates that there is still room for improvement. Most of the integration of the EU energy market has been confined to northern and western parts of Europe. Until vital interconnections are built across the entire bloc, the EU will not have a truly integrated, single energy network—the basis for an “Energy Union.” Moreover, despite reforms at the wholesale level, markets are increasingly distorted by the persistence of regulated prices and rising green surcharges and levies. In the report, Energy Policies of IEA Countries: European Union—2014, the IEA praised the EU for reducing the region’s carbon intensity and taking the lead in vehicle fuel economy standards. Due to 20-20-20 targets and lower energy intensity, an unprecedented boom in renewable energies was possible. EU leaders agreed in October 2014 to ambitious climate and energy targets for 2030. Now, the legal framework must be put in place, with market rules for a lowcarbon (LC) system. The transition to such an LC system remains challenging, as electricity and transport sectors rely heavily on fossil fuels. This requires the swift reform of the EU Emissions Trading Scheme (EU ETS) and support for investments in LC technologies. EU electricity systems and markets need to accommodate growing shares of variable renewable energy. At the same time, the EU faces the retirement of half its nuclear generating capacity in the next 10 years. Decisions must be made about uprates, upgrades and lifetime extensions. Energy security must be placed at the center of the Energy Union. To reduce dependency on a single supplier, the EU must further diversify gas and oil supplies, and it cannot afford to reduce

its energy options: nuclear, coal and unconventional oil and gas must be part of the mix. Among its key recommended policy actions, the IEA report calls for: • A new commitment to the internal energy market across the EU, with an interconnected energy network and competitive retail markets to ensure: o Electricity—Market integration of variable renewable generation with strong coordination of electricity system operation; generation adequacy; and demand-side response, balancing and intra-day markets across interconnected systems is needed. o Gas—Access to, and efficient use of, gas storage and LNG terminals and unconventional gas sources must be developed. • Timely adoption of market-based and governance rules for an integrated 2030 Climate and Energy Framework with priority to energy efficiency, a strong EU ETS, and support to all low-carbon technologies, by integrating technology, R&D and innovation foresight.

• Enhanced EU-wide cooperation on uprates, safety upgrades and extensions of the lifetimes of existing nuclear power plants to ensure the highest safety standards and regulatory stability needed for the investment decisions in those countries that opt for nuclear energy.

NGVs to displace four times more diesel in China by 2020 A new report by Wood Mackenzie forecasts that natural gas vehicles (NGVs) will be the largest single factor in the substitution of diesel within the Chinese transport sector by 2020. The transition follows similar moves in the industrial and power sectors. Wood Mackenzie estimates that 450 Mbpd of diesel, or 10% of demand, will have been displaced by natural gas before the end of the decade. The influence of NGVs is already being felt in China, with diesel demand weakening through 2014 and a large surplus forecast by 2020. In 2013, there were about 250,000 NGVs in the commercial sector, predomi-

Biorefineries will be part of the EU’s solution for energy security. Photo courtesy of eni. Hydrocarbon Processing | JANUARY 201511

News nantly trucks and buses, in China. This displaced around 110 Mbpd of diesel. By 2020, the number of NGVs will increase to 900,000 in the commercial sector—a four-fold increase on 2013 levels. Despite this level of growth, transportation will remain the smallest component in China’s booming gas sector—accounting for only 8% of demand by 2020 (up from 5% in 2013). In real numbers, however, this results in a trebling of transport-related gas demand to 30 Bcm. Falling oil prices are forecast not to curb gas penetration into the transportation sector, as gas prices in China will similarly soften in line with oil pricing through to 2020, based on the government’s natural gas pricing formula. According to the report, diesel substitution in the industrial and power sectors in China will continue. However, the majority of diesel demand in these sectors has already been substituted, with only limited opportunities remaining. In contrast, NGVs will account for most of the future diesel substitution due to both domestic market and policy incentives. In 2014, China will experience a decline in diesel demand for the first time in more than a decade. Although NGVs played a part in diesel demand contraction, the major driver has been more moderate GDP growth, in particular a slowdown in investments, which sharply reduced the call on freight within the resource sectors. The wider regional impact of gas penetration will slow down China’s demand for diesel. However, continued refinery investments will see China emerge as a large diesel exporter in Asia. The strategic choices of Chinese NOCs, which supply the bulk of both oil and gas to the transport sector, will increasingly come into focus in light of increased gas penetration and the slowing of refinery investments. Asia-Pacific is expected to keep its surplus in diesel/gasoil (GO) at around 520 Mbpd by 2020. Identifying export market opportunities will become challenging for export refiners in Asia, as they will be marginal suppliers of diesel/GO to Europe and will face a stiff competition from US, Middle East and Russia suppliers. Wood Mackenzie asserts that the future pace of diesel substitution will have a material impact on the amount and type of refining capacity required in Asia. NOCs in China and India, which are building new regional refining capacity, Select 151 at www.HydrocarbonProcessing.com/RS

could face an oversupply, especially for diesel, if they fail to balance domestic supply and demand. Therefore, understanding the role NGVs play in driving China’s incremental diesel surplus is vital.

Russia on edge of possible recession due to problems over crude oil pricing Russia may enter its first recession since 2009 as sanctions over the Ukraine conflict combine with plunging oil prices and the weakening ruble. The collective problems are causing domestic economic problems and forcing the government to support banks. Russia’s GDP may shrink 0.8% in 2015, compared with an earlier estimate of 1.2% growth, according to Deputy Economy Minister Alexei Vedev. The government will spend 39.95 B rubles ($760 MM) to support OAO Gazprombank, and is the third lender to secure a capital injection since US and EU sanctions curbed their ability to borrow. The economy is succumbing to penalties imposed over Ukraine as the plummeting ruble stokes inflation and a 30% drop in oil prices erodes export revenue. As economic ties with the EU deteriorate, President Vladimir Putin announced that Russia is scrapping a proposed $45 B Black Sea pipeline to carry gas via Turkey to Europe, thus bypassing Ukraine. Urals, Russia’s chief export oil blend, will probably average $99/bbl in 2014, a downgrade from an earlier forecast for $104/bbl. The price is forecast to drop to an average of $80/bbl in 2015. Russia needs Brent to average about $100/bbl annually to balance its budget, according to Deutsche Bank AG.

EIA launches new tool for crude oil import analysis The Energy Information Agency (EIA) has released the US Crude Oil Import Tracking Tool, which allows policymakers, analysts and the public to more easily track trends in crude oil imports. Users can sort and display crude oil imports by month or year, by crude type (i.e., light, medium, heavy), country source, port of entry, processing company, processing refinery and more. The tool features graphing and mapping capabilities and a built-in help function.

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News Recent and forecast increases in domestic crude production have sparked discussion about how rising crude oil volumes will be absorbed. The primary mechanism for absorbing increased production has been the displacement of imported crude oil, which has fallen from 8.9 MMbpd in 2011 to 7.5 MMbpd in August 2014. The tool sheds light on the adjustments to imports being made in response to growing production of crude oil within the US. It is one part of the EIA’s ongoing effort to assess the effects of a possible relaxation of present limitations on US crude oil exports, which is another avenue to accommodate domestic production growth. The EIA is undertaking further work on this larger question, and expects to issue more analysis reports over the coming months. Launched on the EIA’s beta site to solicit customer feedback, and to incorporate that feedback into the final release, the new tool represents the EIA’s latest step in making energy data more accessible, understandable, relevant and responsive to users’ needs. The US Crude Oil Import Tracking Tool can be found at: http:// www.eia.gov/beta/petroleum/imports/ browser/. Using the tool yielded the following insights regarding recent trends in US crude oil imports: • Volume and quality of US crude oil imports. Crude oil imports have declined since 2010, with nearly the entire decline occurring in light sweet grades. In particular, US light crude imports fell 71% between 2010 and the period of January–August 2014. • Source of US crude oil imports. Imports of light crude from Africa, particularly from Nigeria and Algeria, have declined by 93%. • Light crude oil imports by region. The largest decline in crude

oil imports occurred on the Gulf Coast (PADD 3), down 94%. Light crude oil imports by East Coast (PADD 1) refiners were down 69%, reflecting both their increased use of domestic crudes and modestly lower refinery runs. • Refinery-level trends in light crude imports. Imports by the 10 largest refineries using imported light crude in 2013 accounted for 55% of total US light crude imports, with the remaining 45% scattered among more than 100 other refineries. The largest source for light crude imports among this group of 10 refineries was Canada, followed by Nigeria and Mexico. Of these 10 refineries, three are located on the East Coast, two in the Midwest, three on the Gulf Coast, and two on the West Coast. • Refinery-level trends in imports other than light sweet crude. There is evidence that some refineries have recently reduced imports of medium and heavy grades of crude oil to accommodate increasing light domestic production. Other refiners, which have made changes in processing equipment to accommodate heavier crudes, have increased their imports of such crudes.

UOP to provide deep-conversion technologies for Russia’s oldest operating refinery The 135-year-old Yaroslavl Mendeleyev refinery will be retrofitted to meet Euro V requirements with UOP’s advanced bottom-of-the-barrel technology suite. Russia’s Mendeleev Group selected

2,000 Total shipments of Coriolis flowmeters worldwide, $ MM

1,750 1,500 1,200

1,000 750 500 250 0 2013

2014

2015

FIG. 1. Total global shipments of Coriolis flowmeter, $ MM.

14JANUARY 2015 | HydrocarbonProcessing.com

2016

2017

2018

the UOP refining technologies to fully convert crude oil while maximizing production of high-quality, ultra-low-sulfur diesel (ULSD) to meet growing demand and stricter environmental regulations. UOP, Mendeleev Group and Northwest Production Co. worked together to develop the processing scheme for the new refinery, which will use the most advanced technologies to convert up to 96% of each barrel of oil processed. UOP will provide all of the upgrading and treating process technologies for the new complex, which will process 3 MMtpy (65 Mbpd) of crude oil and is scheduled to start up in 2018. The transportation fuels produced will meet Euro V fuel standards, which limits the sulfur content in transportation fuels. The facility will use Honeywell’s UOP Uniflex process and the UOP/Foster Wheeler Solvent Deasphalting process to convert heavy residue to high-quality distillate products, while minimizing co-products. UOP’s Uniflex processing technology was developed to help refiners processing the bottom of the barrel, the heaviest portions of a barrel of crude (vacuum residue), to higher-value transportation fuels. The refinery will also use UOP’s Unicracking hydrocracking and distillate Unionfining hydrotreating processes to upgrade vacuum gasoil and other feed streams to produce high-quality distillates, such as diesel. Along with basic design services, UOP will supervise the preparation of project engineering documentation in the form of Stadia Proekt, which is required to apply for Russian design and authority approvals.

Growth in large pipe applications drives Coriolis flowmeter market According to a new study from Flow Research, the market for Coriolis flowmeters totaled $1.3 B in 2013, and is projected to grow to almost $2 B by 2018. Growth in the energy markets, especially in oil and gas, is creating greater demand for the accuracy and reliability of Coriolis flowmeters. Coriolis flowmeters remain the most accurate flowmeter made, and both accuracy and reliability are critically important for measuring the flow of crude oil and petroleum liquids. They are espe-

s we celebrate our Platinum Anniversary Year, all of us at the Sabin Metal Group sincerely thank you and others in your organization for your continued confidence and trust. Serving our customers around the world for the past 70 years has been a truly wonderful experience. We look forward to continuing our mutually rewarding relationship with you in the years ahead.”

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News cially suited to downstream applications of petroleum liquids. Another important force driving the market is the development of large-linesize Coriolis flowmeters. For many years, nearly all Coriolis flowmeters were used in pipes with 6-in. diameters or less. In the past five years, four major suppliers have developed Coriolis flowmeters for use with pipe diameters from 8 in. to 16 in. in diameter. While these flowmeters can be quite expensive, they are becoming increasingly popular. Most of these large-line-size Coriolis flowmeters are designed for custody-transfer applications. Companies that have brought out these large-line-size meters include GE Measurement (which acquired Rheonik), Micro Motion (part of Emerson Process Management), Endress+Hauser and KROHNE. Coriolis flowmeters have also benefited from industry approvals that previously worked in favor of differential pressure (DP) and turbine flowmeters. The American Gas Association approved a report on the use of natural gas for cus-

tody-transfer applications in 2003. This report helps explain the growing use of Coriolis flowmeters for natural gas. The American Petroleum Institute (API) has also issued a draft standard for the use of Coriolis flowmeters to measure hydrocarbon fluids. This document was added to the API Library in July 2012. The API also approved a draft standard called “Measurement of Crude Oil by Coriolis Meters.” While Coriolis flowmeters compete with DP and turbine flowmeters for natural gas applications, they also compete with positive displacement (PD) flowmeters for downstream measurement of petroleum liquids. While the use of Coriolis flowmeters is growing rapidly in the oil and gas and refining industries, the chemical industry remains the largest industry for Coriolis flowmeters. Although Coriolis flowmeters are being used more widely to measure both natural gas and industrial gases, liquids still account for more than 75% of the flow applications. Even though measurement of the flow of petroleum liquids is growing at

a faster rate than measurement of nonpetroleum liquids, measurement of nonpetroleum liquids still represents a larger segment of the Coriolis fluid measurement market. Continued growth in the energy markets is a major reason for projected growth in the Coriolis flowmeter market. At the same time, Coriolis suppliers have shown a readiness to bring out new products to meet changing market requirements. This is shown in the development of both straight-tube and large-line-size Coriolis flowmeters. While they remain somewhat expensive, the twin benefits of high accuracy and long-term reliability outweigh the upfront purchase price of Coriolis flowmeters for many flowmeter users. The Coriolis flowmeter market size and forecasts are part of a new research study from Flow Research, The World Market for Flowmeters, 5th Ed. (http://www.flowvolumex.com). An expanded version of the News can be found online at HydrocarbonProcessing.com.

When others can’t,

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COMPLETE SOLUTIONS FOR YOUR REFINERY OPERATIONS Whether you’re dealing with tight oil, more stringent sulfur limits or changing feedstock supplies, CB&I has the answers to help refiners derive maximum value from every molecule. We’re with you through every stage of the process plant life cycle, from feasibility studies through technology selection, full-scope EPC, commissioning and start-up, to plant optimization and upgrades. Our broad portfolio of both refining and petrochemical technologies, combined with our execution expertise, will help you maximize unit flexibility and achieve margin benefits in the widest range of scenarios. PROCESS PLANNING AND DEVELOPMENT LICENSED TECHNOLOGIES AND CATALYSTS FULLSCOPE EPFC SERVICES PROJECT MANAGEMENT AND CONSULTING AFTERMARKET SERVICES

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HP STAFF / [email protected]

Industry Metrics

5

Selected world oil prices, $/bbl

Nov 14

Oct 14

Sept 14

Aug 14

July 14

June 14

May 14

April 14

Feb 14

Jan 14

Nov 14

Oct 14

Sept 14

Aug 14

June 14

July 14

Japan Singapore

May 14

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

US EU 16

April 14

Nov 13

O N D J F M A M J J A S O N D J F M A M J J A S O 2012 2013 2014

70 60 50

Mar 14

1 0

80

Feb 14

2

Jan 14

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

90

Dec 13

3

Global refining utilization rates, 2013–2014* 100 Utilization rates, %

4

Mar 14

0 -5

6 5

Brent, Rotterdam

10

Nov 13

7

Gas prices, $/Mcf

Production, Bcfd

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

Arab Heavy, US Gulf LLS, US Gulf

WTI, US Gulf Dubai, Singapore

15

Dec 13

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

Global refining margins, 2013–2014* 20 Margins, US$/bbl

Recent declines in oil pricing and the associated volatility in future pricing has created a difficult forecasting environment. Other factors are causing deviations, especially with regard to the responsiveness of supply under a lower-price environment. The US EIA has cut price forecasts by $15/bbl and lowered its US oil production outlook for 2015.

US Gulf cracking spread vs. WTI, 2013–2014*

135 40

01 July 08 July 15 July 22 July 29 July 05 Aug 12 Aug 19 Aug 26 Aug 02 Sept 09 Sept 16 Sept 23 Sept 30 Sept 07 Oct 14 Oct 21 Oct 28 Oct 04 Nov 11 Nov 18 Nov 25 Nov 02 Dec

Prem. gasoline unl. 92 Jet/kero

Nov 14

Oct 14

Sept 14

Aug 14

July 14

Nov 14

Oct 14

Sept 14

Aug 14

July 14

June 14

May 14

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

Nov 14

Oct 14

Sept 14

Aug 14

July 14

June 14

May 14

Mar 14

-10 -20

Feb 14

-2 -4

0

Jan 14

0

10

Dec 13

2

20

Nov 13

Dubai Urals

Singapore cracking spread vs. Brent, 2013–2014* 30 Cracking spread, US$/bbl

6

April 14

2015-Q1

Brent Dated vs. sour crudes (Urals and Dubai) spread, 2013–2014* Light sweet/medium sour crude spread, US$/bbl

June 14

-10 -20

Source: EIA Short-Term Energy Outlook, December 2014.

4

May 14

Gasoil, 10 ppm S Fuel oil, 1% S

April 14

2014-Q1

Prem. gasoline unl., 98 Jet/kero

0

Mar 14

-1.0 -1.5

10

Feb 14

-0.5

20

Nov 13

0.0

Cracking spread, US$/bbl

0.5

30

Stock change and balance, MMbpd

Supply and demand, MMbpd

2.0 1.5 1.0

2013-Q1

April 14

Rotterdam cracking spread vs. Dubai, 2013–2014*

World liquid fuel supply and demand, MMbpd Forecast

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

Mar 14

F M A M J J A S O 2014

Prem. gasoline unl. 93 Jet/kero

Jan 14

O N D J F M A M J J A S O N D J 2012 2013

96 Stock change and balance 94 World demand 92 World supply 90 88 86 84 82 80 78 2009-Q1 2010-Q1 2011-Q1 2012-Q1

0

-10

Source: DOE

Dec 13

60 45

10

Feb 14

W. Texas Inter. Brent Blend Dubai Fateh

75

Jan 14

90

30 20

Dec 13

Cracking spread, US$/bbl

105

Nov 13

Oil prices, $/bbl

120

* Material published permission of the OPEC Secretariat; copyright 2014; all rights reserved; OPEC Monthly Oil Market Report, December 2014. Hydrocarbon Processing | JANUARY 201519

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For more information about UOP olefins solutions, visit www.uop.com/olefins. © 2014 Honeywell International Inc. All rights reserved.

Reliability

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

Plan now to deal with stressed equipment later

US refineries have been processing record volumes of oil recently. Refinery inputs hit a record high of 16.8 MMbpd in each of the past two weeks, exceeding the previous record from summer 2005. Refineries in the Midwest and Gulf Coast, in particular, pushed the total US input volume upward, as these refiners’ access to lower-cost crude oil, expansions of refining capacity, and increases in both domestic demand and exports contributed to higher refinery runs. Hydrocarbon Processing believes that record refinery runs will, to some extent, have an impact on machinery reliability. Reliability-focused plant operators would, therefore, like to know what steps they should take to ensure uptime under conditions of more severe loads on fluid machinery. Will equipment fail more often? From our vantage point,

such questions are valid; they certainly merit answers beyond the obvious. Industry has to position itself to anticipate and not just react to such issues. By definition, higher loads or throughputs will reduce the margins of safety for some rotating machinery. Likewise, for machines previously operating below design throughput, increased throughput can actually cause shifts into more favorable operating regions. If the original design margin of safety was 2.0 and, with greater load or throughput, it drops to 1.9, there is no adverse effect on equipment life. Conversely, if the design margin of safety was 1.0, then higher loads or throughputs will have consequences. The consequences can be calculated with long-established rules of thumb, which seek to quantify higher rates of erosion, greater loads on bearings, oil temperature increases leading to reduced oxidation life for mineral oils, and a host of similar considerations. Suppose we tried to anticipate component life reductions associated with a simple load increase of 10% over the base. In using typical rules of thumb for such calculations, we could anticipate component life reductions averaging 35%. Combining turnaround planning and equipment upgrading. We believe that refineries and petrochemical plants

with elevated throughput should incorporate equipment upgrading as part of the turnaround planning. A refinery that already knows that plant equipment has operated beyond the customary norm may consider inspection and

repair activities to coincide with already pre-planned downtime events. Fortunately, a bit of research will uncover aerospace-derived innovation ([email protected]). Giving thought to the adoption of such innovation will open up previously unavailable opportunities for the hydrocarbon processing industry. Inspections and repair opportunities. Depending on the

machines involved, re-thinking inspection and repair downtime would include equipment upgrading. Such upgrading could focus on superbly wear-resistant diffusion-conversion technology used by manufacturing industries, and may include the time and effort needed to accurately define the internal geometry of rotating machines for which no certified manufacturing drawings exist. Fully automated 3D measuring equipment may be needed to do such jobs, and many repair centers have such equipment. Why? Perhaps the original equipment manufacturer (OEM) no longer exists or the equipment was purchased from the preowned or surplus equipment market. In that instance, upgrading may reasonably focus on dynamic compressors. On some machines, the surge margin or turndown ratio could be improved. Older fluid machines often consume more energy, and controlling throughput by simply bypassing or recycling flow is too costly. Discontinuing such bypassing can markedly increase efficiency, as would suitable impeller upgrading and optimization. A good regional repair center should have this type of automated measuring equipment. Higher-performing impellers could be designed and then retrofitted at large regional service centers. Some service centers have full OEM backing or are owned outright by the OEMs. Others have been formed by highly competent individuals or by partnerships, which capitalize on the technical expertise of their respective staff—often exOEM staffers. Strong non-OEM partners often bring together two or more strong competencies in the fluid machinery fields. We have seen cases with know-how and expertise in combining fluid machinery repair with throughput increases or efficiency upgrading. A partnering company may have superior knowledge 18 Gross refinery inputs, MMbpd

The US Energy Information Administration’s (EIA’s) “Today in Energy” brief evaluated how US refineries are processing record amounts of crude oil (FIG. 1), with Midwest and Gulf Coast refineries, in particular, pushing total volumes higher:1

New record set in July 2014: 16.8 MMbpd

17

Previous record set in 2005

2014

16 15

Range and average 2009-13

14 13 0 Jan

Feb

Source: EIA

Mar

April

May

June

July

Aug

Sept

Oct

Nov

Dec

FIG. 1. Weekly US gross refinery inputs, MMbpd.1 Hydrocarbon Processing | JANUARY 201521

Reliability in impeller fabrication and/or a totally superior solution to the problem of wear. These are companies well worth exploring. Roles in operations and reliability. One of the key roles of

reliability professionals is to proactively lay the groundwork for the timely implementation of cost-justified upgrades during equipment downtime and turnaround events. The automated measuring of fluid machinery internal geometry would result in an up-to-date data library. From this library and from field mea-

surements such as flow, differential pressure, gas composition, etc., it is possible to predefine impeller or stage upgrade details. The timing for taking automated 3D measurements varies from plant to plant. Such measuring could be done when an unscheduled unit downtime occurs for reasons unrelated to the fluid machine for which we wish to have accurate geometric mapping in hand. Or, geometric mapping (FIG. 2) could be scheduled as part of the next turnaround and would coincide with planned visual examination or parts replacement on a particular fluid machine. Knowing the machine’s internal geometry and the field-monitored performance would enable a competent machinery upgrader to define, propose, and make detailed plans for revision opportunities. The upgrade components would then be manufactured and on hand for the next scheduled turnaround. 1

LITERATURE CITED EIA, “US petroleum refineries running at record levels,” July 24, 2014, http:// www.eia.gov/todayinenergy/detail.cfm?id=17251. HEINZ P. BLOCH is the Reliability/Equipment editor of HP. The author of 19 textbooks and over 600 papers or articles, he was a senior engineering associate for Exxon Chemicals. He is in his 52nd year as a reliability professional and continues to advise process plants worldwide on reliability improvement, failure avoidance and maintenance cost reduction opportunities. He holds BS and MS degrees in mechanical engineering from the New Jersey Institute of Technology, and he is an ASME Life Fellow.

FIG. 2. Geometric mapping at an upgrade shop.

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Maximum Protection for Your Liquefaction Train

LNG GUARD™ Separation Systems, the latest product innovation from Sulzer Chemtech, utilizes superior quality technologies to meet the high efficiency and reliability needs of the LNG industry while lowering project costs. LNG GUARD™ Systems protects critical downstream compressors, catalysts, pumps, and product stream in fractionation, compression, and treating units. Sulzer Chemtech unites

unequaled cryogenic separations engineering and design experience to deliver what you need: ‡3URGXFWTXDOLW\UHDVVXUDQFH ‡0D[LPXPVHSDUDWLRQHIILFLHQF\ ‡&RVWRSWLPL]HGFROXPQGHVLJQV Rely on Sulzer Chemtech and LNG GUARD™ Systems to protect your equipment, lower your costs, and maximize your performance. Select 88 at www.HydrocarbonProcessing.com/RS

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The computer platform I bought a few years ago is already obsolete. I need technology that will keep pace.

YOU CAN DO THAT DeltaV™ Virtual Studio makes it easier to keep your system current. Keeping your control system up-to-date can be tedious, time-consuming and expensive. With a workflow and feature set that is easy to understand, DeltaV Virtual Studio is uniquely designed for automation engineers. Use pre-built virtual machine templates to easily ensure accurate upgrades with minimum effort. Keep pace with the latest technology – easy. Find out more at: www.DeltaV.com/Virtualization.

The Emerson logo is a trademark and a service mark of Emerson Electric Co. © 2014 Emerson Electric Co.

Automation Strategies

MARK SEN GUPTA Senior Consultant, ARC Advisory Group

Control on the wire(less) Since the industrial revolution, process/industrial control had relied on tightly coupled systems to transmit control signals. Industrial plants have used “modern” control via wired electronic signals for over half a century, making the market ready for a new/innovative technology to disrupt the current methods. Advances in wireless technologies now promise to disrupt that paradigm, and sooner rather than later. Given the ever-increasing rate of development (and the increasing need to connect previously stranded assets), wireless technologies are on the cusp of fulfilling an entirely new range of industrial/process control applications. Wired control. Since its beginning, industrial/process control

has relied mainly on tightly coupled linkages between the field devices and the control mechanisms. In earlier times, this coupling was accomplished mechanically or pneumatically. Recently, industry used wires to convey electrical signals. In fact, most control performed in manufacturing facilities today uses wires to convey signals to and from the field. This generally involves a 4 mA–20 mA signal generated by a measurement device in the field to transmit a process state to the controller, followed by another 4 mA–20 mA signal generated by the controller to convey a desired response to a field actuator. ‘Control on the wire.’ Nearly 20 years ago, Foundation fieldbus technology led the process industries into the concept of “control on the wire.” The concept leverages the higher processing power available in digital (rather than analog) field devices to execute control algorithms and increased speed of digital communications. For example, a digital flow transmitter could execute a PID algorithm based on its own measurement and transmit a control signal to a valve on the same segment. Despite tighter and more robust control and a more reliable setup, only a handful of end users (estimated at less than 5%) have capitalized on this aspect of the technology. Why not wireless? Wireless signals are generally not used for

control because the sample rates are too long and the signal reliability is typically below expectations. PID algorithms expect to sample the field signal at least four times per algorithm execution. When the sample rates are increased on wireless devices, the battery life drops rapidly. This is exacerbated by the generally less-than-ideal reliability of wireless transmission itself. Although wireless mesh technology has improved greatly, applications must still be able to tolerate a loss of signal. Moving by leaps and bounds. The foundations are set. Wireless standards are fairly well agreed upon, with committees working on convergence. This allows suppliers to focus on de-

velopment to a specific standard without the overhead of having to support multiple standards. Energy harvesting currently allows wireless transmitters to use “free” energy from the surrounding environment to augment power to the device. These devices convert vibration, solar or thermal energy into electricity to power wireless devices in locations where line power is not available. In some cases, the wireless device works totally off the energy harvester and uses the battery only for backup. Wireless control. A leading global automation supplier re-

cently announced that it had developed an augmented PID algorithm to handle the longer sample rates and uncertainty in communication associated with wireless process variables. The new algorithm has added signal conditioning to handle this longer sample time. The company donated the patent for the new algorithm to the FieldComm Group. This means that control can be implemented using wireless input signals, and the technology can be licensed from the same organization responsible for Foundation fieldbus. Changing the game. As with many new developments for the industrial world, efforts to extend battery life continue to be propelled by advances initially developed for the consumer market. These advances will enable faster wireless communication between field devices without concern for battery life and associated maintenance. When coupled with increasingly efficient energy harvesting, battery life may cease to be an issue in the near term. When considering the amount of development dollars being invested in wireless vs. wired technologies, end users should expect wireless to quickly become faster, more reliable, more fault tolerant, and more energy efficient. WirelessHART currently claims 99.9% end-to-end reliability. Suppliers that support the ISA 100 wireless standard also report increasing reliability. ARC Advisory Group believes that wireless technology will not only get better, but it will also become easier to implement and use. Is control in the wireless mesh realizable? ARC believes that the answer is “yes.” Although wireless communication reliability is still somewhat questionable, the building blocks are in place to alleviate these concerns. MARK SEN GUPTA is a senior consultant and leads ARC’s coverage of process automation and automation supplier services. He also covers topics in process safety and SCADA. Mr. Gupta has over 24 years of expertise in process control, alarm management, SCADA and IT applications. He holds BS and MS degrees in electrical engineering from Georgia Institute of Technology.

Hydrocarbon Processing | JANUARY 201525

“Beneficial reuse” is defined by the EPA as reusing a material in a manner that makes it a valuable commodity. Spent caustics are generally byproducts of a refinery or chemical process that would ordinarily be treated as wastes. When beneficially reused without reclamation, the spent caustics are exempt from the solid waste definition and are categorized as a product (or valuable commodity) under the EPA regulations.

Merichem’s beneficial reuse of spent caustic, without reclamation, is more environmentally friendly than disposing of the material as a waste. As such, these materials are no longer a part of your waste generation statistics.

At Merichem Company, we bring to the petroleum refining and petrochemical industries more than 50 years of experience in the handling of caustic effluent streams. Our technical expertise allows us to recommend the right caustic treating needs for your specific processes and, if needed, handle most resulting caustic solutions. Our beneficial reuse of caustic streams helps our customers achieve waste minimization goals and eliminates labor intensive waste handling protocols such as manifesting, hazardous waste record keeping, etc. Your spent caustic is used as a substitute for other commercially available products or as a feedstock in manufacturing processes. In either case, Merichem will utilize your spent materials in a non-waste, environmentally responsible manner. Merichem's advanced logistics system allows us to transport caustic solutions to our chemical plants and terminals in a safe, efficient and cost effective manner. Additionally, our adherence to the American Chemistry Council's Responsible Care® program ensures compliance to the highest industry standards. It’s true! Merichem is the partner of choice for non-waste utilization of your secondary materials.

5455 Old Spanish Trail | Houston, Texas 77023 | 713.428.5000 Select 84 at www.HydrocarbonProcessing.com/RS

Project Management

T. ROMAHN, Heide Refinery-Klesch Group, Hemmingstedt, Germany; and M. CISLER, HIMA Paul Hildebrandt GmbH, Brunsbüttel, Germany

German refinery successfully modernizes safety system In September 2014, the Heide refinery in Germany used two weeks of planned downtime at its pyrolysis plant to migrate to new safety systems. The new system emphasized high plant/ equipment availability and investment security, while also guaranteeing a smooth changeover. The refinery. The Heide refinery is an enterprise of the Klesch

Group, and it employs approximately 500 people. The company has a processing capacity of 4.5 MMtpy of crude oil. The refinery was built in 1940, and produces classic mineral oil products, such as automotive gasoline, diesel and jet fuel. In addition, the refinery produces light heating oil along with base materials for the chemical industry. This refinery is Germany’s northernmost facility. The pyrolysis plant is one of the important process areas. As part of an extensive distributed control systems (DCS) replacement project, the Heide refinery also planned replacing the pyrolysis plant’s 20-year-old safety technology with a new system.1 Investment security is a key concern. Plant availability

is especially important to the Heide refinery. In the pyrolysis plant, process changes are undertaken frequently. These changes or conversions need to happen quickly and seamlessly during plant operations, without impairing plant safety. The new safety system is designed for medium- and largesized applications.1 All changes, upgrades, maintenance and proof tests can be executed during normal operation. Due to the system’s high performance, extensions are possible. For example, safety-relevant functions of the propylene drying unit planned for 2015 can also be integrated into the control system. The refinery also wanted a state-of-the-art, safety platform with a long product lifecycle that can be easily extended. Easy integration. In the pyrolysis plant, three redundant

safety systems are used as emergency shutdown (ESD), burnermanagement system (BMS), and fire and gas (F&G) systems in the compressors, the naphtha and ethane furnaces and in other process units. The new process control uses Ethernet functions to safely manage approximately 2,000 signals. Integration of the safety systems involved parts from the previous process control system.2 Various signals from the controllers were required for more complex regulating tasks in the control system (FIG. 1). It was necessary to integrate the safety system with different control systems. The couplings were extensively tested before the installation so that commissioning would run smoothly. For the migration, most of the existing marshaling racks were retained; this measure reduced procurement costs, as well as installation, wiring and test efforts. Because the existing con-

FIG. 1. The new controllers at the Heide refinery serve as ESD, BMS and F&G systems to ensure safety and plant availability. The safety controllers in the pyrolysis plant process manage approximately 2,000 signals.1 Source: Heide refinery.

trol cabinets would be reused, the old CPUs, I/Os and module racks were completely removed from the installed swing frames, and new module racks for the CPU, network, MODBUS and I/O were integrated in the freed space. The terminal blocks in each control cabinet were defined as transfer points. Extensive, up-front tests. The tight timeframe for the con-

version was the main challenge. The installation had to be completed during a 14-day turnaround. Seven existing safety controllers had to be connected to three new safety systems. In recent years, the responsible parties at the Heide refinery had gained experience in other projects. This included checking and testing as much as possible in advance. The vendor was charged with hardware planning and system programming. To ensure that the specifications were correct, safety experts conducted an intensive appraisal on site. Photos of the cabinets and terminals were taken, along with extensive documentation of the project. Heide refinery service engineers supported the installation. Next migration. The safety controllers that process a total of approximately 7,500 I/Os have been in use at the refinery for more than 40 years.3 Due to the positive experiences over many years and the numerous advantages of the systems, the next migration project—the refinery’s power plant—will also be implemented with safety solutions from the same vendor.3 NOTES HIMax systems from HIMA Paul Hildebrandt GmbH. 2 TDC 3000 and the Experion PKS system, both from Honeywell, were implemented via MODBUS RTU and MODBUS TCP/IP. 3 HIMA Paul Hildebrandt GmbH. 1

Hydrocarbon Processing | JANUARY 201527

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THOMAS KEVIN SWIFT

Global

Chief Economist and Managing Director, American Chemistry Council

State of the US petrochemical/chemical industry After a promising start, the global economy faltered in 2014 with heightened geopolitical uncertainty; recessions in Brazil, Japan and many European nations; and slowdowns in China, the Euro Area and other nations. In the US, the economy is in belowpotential growth as high taxes, debt and regulatory burdens still take a toll on both business and consumer confidence. As a result, businesses have been cautious and will slow capital spending in 2015. Furthermore, overseas weakness and a higher dollar dampen US exports. With household deleveraging over, further improvements in the employment situation, lower oil prices fostering discretionary incomes, and asset prices moving higher, consumers are starting to spend again. Manufacturing. During 2014, US

manufacturing growth improved. Leaders included light vehicles, appliances, construction materials and some industries involved with business investment. Elsewhere, however, several manufacturing industries have yet to regain traction (textiles, paper and printing). Forward momentum for these segments depends on demand for consumer goods, which ultimately drives factory output. In addition, the surge in unconventional oil and gas development is creating both demand-side (e.g., pipe mills, oilfield machinery) and supply-side (e.g., chem-

icals, fertilizers and direct iron reduction) opportunities. Despite a slowdown in global manufacturing, US petrochemical and derivatives volume gains have improved. With an improvement in customer industries and eventually in emerging markets, the effects of an enhanced competitive position with regard to feedstock costs will support US production going forward. Inventory. Effective inventory management since the end of the Great Recession has resulted in fairly well-balanced inventories relative to shipments. For chemical manufacturers, inventoriesto-shipments have been well within historical norms. Along the value-chain downstream, businesses are reluctant to add to inventories, and, as a result, levels are low. Downstream customers have been optimizing inventories. Inventories among chemical wholesalers have been mixed in recent months. Basic chemicals. Bulk petrochemicals

and organics, plastic resins, synthetic rubber and man-made fibers, as well as inorganic chemicals, were the hardest hit from the recession in Japan, Brazil, etc., and the economic slowdown in other nations, despite improving demand from important customer markets such as light vehicles and housing. Downstream customers still remain cautious about building invento-

ries, but improvements in final demand could necessitate replenishing. 2015 outlook. The output of US pet-

rochemical and derivatives will improve during 2015 and into the second half of the decade. Production likely moved up 0.3% pace in 2014 and will improve to a 3.7% gain in 2015. Strong growth is expected in bulk petrochemicals and other organic chemistry, plastic resins and synthetic rubber as export markets revive and domestic end-use markets further improve. During the second half of the decade, US growth is expected to expand at a pace (about 6%/yr on average) about double that of the overall US economy. The US is a net exporter of basic chemicals. By this measure, the industry will post a trade surplus of $33 B in 2014. As new investments in the chemical industry come online, basic chemicals export growth will accelerate and its surplus in chemicals trade will grow to $70.9 B by 2019. Access to plentiful and affordable natural gas supplies is allowing the US to capture an increasing share of global chemical industry investment. This trend will continue, as the US has become the location for investment. Looking forward, the expected gains in US production volumes and stable capacity suggest improving operating rates in 2015, and, with strengthening produc-

TABLE 1. US petrochemical production volume outlook Change year–over–year, % 2009

2010

2011

2012

2013

2014

2015

2016

2017

2018

2019

Petrochemicals and derivatives

–14.5

17.9

–2.1

–0.7

1.4

0.3

3.7

4.7

7.1

6.9

5.4

Organic chemicals

–15.1

18.8

–1.2

–1.7

1.4

0.0

3.5

4.9

7.5

7.3

5.6

Plastic resins

–11.0

14.3

–6.1

1.1

0.2

1.0

4.2

4.6

6.8

6.6

5.3

Synthetic rubber

–19.2

14.5

4.6

6.6

7.3

2.9

4.4

3.8

5.2

5.0

3.8

Manufactured fibers

–23.8

33.67

5.2

4.3

5.9

–1.7

0.0

0.5

1.8

1.9

1.3

Trade surplus in basic chemicals, $B

$25.2

$33.2

$34.7

$33.5

$34.0

$32.5

$34.5

$40.4

$49.2

$58.8

$70.9

Hydrocarbon Processing | JANUARY 201529

Global tion volumes, capacity utilization could improve even further in 2016 and beyond. A new capital spending cycle began in 2010 as chemical manufacturers’ access to vast, new supplies of natural gas created an enormous competitive advantage for US petrochemical manufacturers in particular—and the trend in capital investment has rapidly accelerated and changed as significant expansion of existing petrochemical capacity has become the driver.

With high profit margins, a low cost of capital and the opportunities afforded by shale gas, prodigious increases in new plant and equipment investment in the US are forthcoming. The US is being favorably revaluated as an investment location, and petrochemical producers are announcing significant expansions of capacity in the US, reversing a decade-long decline. It is estimated that the gains to basic olefins capacity range

from 35% to 40%. Indeed, over 215 new chemical production projects (valued at over $135 B altogether) have been announced through early December and the dynamics for sustained capital investment are in place. As 2015 begins, the chemical industry is building momentum. Continued recovery in end-use markets, a shift in competitiveness and the eventual return of global economic growth will lift demand for US chemistry over the next several years. Inventories remain balanced, so increasing demand for chemistry will come from new production rather than stock drawdowns. ACC expects to see above-trend growth in US petrochemicals and derivatives over the forecast horizon. Innovation will also continue to drive US petrochemicals and derivatives, with growing investments in research and development in new molecules, new applications, and new more efficient processing techniques. Feedstock advantage. With the devel-

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opment of shale gas and the surge in natural gas liquids supply, the US has moved from being a high-cost producer of key petrochemicals and resins to among the lowest-cost producers globally. This shift in competitiveness is boosting export demand and driving significant flows of new capital investment toward the US. We anticipate that recently announced new capacity for chemicals will significantly expand production when those investments come online beginning in 2015. As a result, employment in the business of chemistry will pick up. The industry is expected to add high-paying jobs through the end of the decade. We will also see US chemical exports grow, and, as external demand becomes more robust, we’ll see the recent pattern of trade deficits shift to one of net surplus. By 2019, the US chemistry industry will post record trade surpluses. All in all, it is a very promising future. DR. THOMAS KEVIN SWIFT is chief economist and managing director for the American Chemistry Council (ACC) in Washington, DC, where he analyzes markets, energy, trade, tax and innovation while monitoring business conditions and identifying emerging business trends.

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BROKEN VS BREAKING NEWS NEWS

Petrochemicals

MARIANNA ASARO Senior principal analyst, IHS Chemical

Global PE demand growth to drive downstream expansions According to IHS Chemical, global demand for polyethylene (PE) is expected to increase by more than 25% during the next five years, from approximately 85 million metric tons (metric MMt) in 2014, to more than 106 metric MMt in 2019. As demand for PE increases, so does demand for linear alpha olefins (LAO). PE, and linear, low-density polyethylene (LLDPE), in particular, is the largest demand segment for these important chemicals. The growth pattern for LAO demand is expected to follow growth in new LLDPE capacity in North America (NA), the Middle East (ME) and China. LAOs are a series of normal alkenes with chain lengths of 4 to 20+ carbon atoms. More than half (54%) of LAO consumption is tied to the production of LLDPE using LAOs of carbon chain lengths 4 (1-butene), 6 (1-hexene) and 8 (1-octene). LAOs of carbon chain length greater than 8 are used in a wide range of other downstream processes, particularly for plasticizer, detergent and lubricant applications. The total global demand for LAOs was 3.5 metric MMt in 2012, and it is expected to grow nearly 6%/yr for the next five years, according to IHS estimates, reaching more than 6 metric MMt by 2019. LLDPE global capacity in 2014 was more than 30 metric MMt, representing approximately 30% of total PE capacity. To meet increasing demand, LLDPE capacity is expected to rise nearly 10 metric MMt, or 32%, during the next five years, exceeding 40 metric MMt by 2019. While demand for PE is growing globally, capacity growth, including that for LLDPE, is increasingly centered in low-cost, natural gas-based regions of the ME and NA, as well as in China, where capacity expansion is based on lowcost coal. In NA, a growing supply of inexpensive, natural gas-based feedstocks is providing producers of ethylene and its derivatives, most notably PE, with an advantageous, lowcost position that offers a strong incentive to add capacity. Overall, according to IHS estimates, North American PE capacity will increase by more than a third during the next five years, exceeding 27 metric MMt by 2019. The total demand figures cover domestic consumption as well as exports for all three major PE types, including high-density polyethylene (HDPE), LLDPE, and low-density polyethylene (LDPE). LDPE represented approximately 35% of total PE capacity in 2014, and will retain its position through 2019. The ME is now positioned as the highest net-exporting region for PE, based on a huge capacity build during the past decade. While the rate of capacity growth is slowing, the region will continue to show growth, adding approximately 5.4 metric MMt of PE capacity during the next five years. By

2019, the region will represent nearly 20% of both total PE and LLDPE global capacities. PE demand growth in China during 2013 to 2018 is expected to account for 40% of total demand growth for PE, or 8.5 metric MMt. As opposed to NA, where shale gas is widely produced to reduce dependence on imports, China continues to invest heavily in new PE capacity, using its vast coal resources and coal-to-olefins technologies. As a result, China is expected to add 10 metric MMt of new PE capacity by 2019. Each leading producer has its own LAO production processes. There are two main categories of technology in use: widerange LAO processes, that produce C4 to C20+ LAO, and on-purpose processes that produce predominantly C4, C6 , or C8 LAO. The selection of wide-range or on-purpose technologies depends on the intended downstream products and markets. Production of LAOs is currently dominated by a few processes, those of Shell, Chevron Phillips, INEOS, Sasol and SABIC. Most of the announced North American capacity additions have been proposed by the first four of these producers. According to a new IHS report on LAO, several other processes for wide-range and on-purpose technologies have been developed to commercial readiness and are finding licensees. In addition, Idemitsu and Mitsui, which have relatively small LAO capacities in Japan, have announced a JV to build a 330,000-metric-ton plant in the US, indicating that the companies plan to take advantage of the region’s low ethylene costs to expand their future presence in global LAO markets. Traditionally, 1-butene has been recovered from refinery and steam-cracking raffinate streams, but the supply of 1-butene has not kept pace with demand. This supply gap is being filled by 1-butene from on-purpose ethylene dimerization and, to a lesser extent, wide-range ethylene oligomerization. Meanwhile, the demands for 1-hexene and 1-octene are each growing faster than that for 1-butene, and the wide-range processes have not kept pace with increasing demand for these olefins. The demand for 1-butene used in LLDPE is decreasing in favor of that for 1-hexene and 1-octene, because the latter olefins impart superior properties to LLDPE. Demand for 1-butene is still expected to grow, albeit slowly, because 1-butene costs less than the C6 and C8 LAO and is also useful as a feedstock to help fill a projected shortfall in butadiene supply. New plants using on-purpose ethylene trimerization and tetramerization processes are now beginning to come online to meet the rising demand for C6 and C8 LAO, respectively. MARIANNA ASARO is a senior principal analyst at IHS Chemical. She can be reached at [email protected]. Hydrocarbon Processing | JANUARY 201533

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Boxscore Construction Analysis

LEE NICHOLS, DIRECTOR, DATA DIVISION [email protected]

Malaysia’s ambitious downstream transformation program

Pengerang. Malaysia’s demand for natural gas sits at around 1.1 Tcf. The country’s eastern region has ample supplies and production to meet existing demand, but the country’s western region suffers from supply shortages, especially in highdemand centers. This scenario has prompted Malaysia to construct its first LNG import terminal at Pengerang. The Pengerang LNG import terminal is part of the much larger Pengerang Integrated Petroleum Complex (PIPC). Once completed, the project will house oil refineries, petrochemical plants, naphtha crackers, and an LNG import terminal and regasification facility (FIG. 1). The PIPC consists of two primary phases. Phase 1 consisted of the development of the Pengerang Independent Deepwater Petroleum Terminal (PIDPT). This project was designed to handle the storage, blending and distribution of crude oil, natural gas and petroleum products. The $1.5-B project was developed by Pengerang Independent Terminals,

a JV between Malaysia’s Dialog Group, Dutch company Royal Vopak and Johor State Secretary Inc. Phase 1 also included the construction of 1.3 MMcm of storage capacity. The terminal received its first cargo in 2Q 2014. Phase 2 of the PIDPT is underway. This development will replicate Phase 1, with the construction of more facilities and an additional 1.3 MMcm of storage capacity. The second primary phase is the construction of the ambitious Refinery and Petrochemical Integrated Development (RAPID) project. RAPID will include a 300-Mbpd refinery, a petrochemical complex with a combined capacity of 7.7 MMtpy of various products, and an LNG regasification terminal. RAPID is estimated to cost $16 B, while the associated facilities will cost more than $11 B. The project has been delayed several times, but Petronas’ board of directors approved the project in April 2014. Major contract awards are listed in TABLE 1. The scheduled startup date is early 2019. Bintulu. Petronas operates one of the largest LNG terminals

in the world. The Petronas LNG complex, located at Bintulu, consists of eight trains with a total processing capacity of nearly 26 MMtpy. The facility is operated by Malaysia LNG Sdn Bhd (MLNG). MLNG was formed in 1978 when Petronas, Shell and Mitsubishi secured a partnership agreement to develop Malaysia’s first LNG project. The consortium completed its first LNG liquefaction plant in mid-1982, with the first cargo departing in January of the following year. The complex is a collection of three LNG processing plant modules: • MLNG Satu—3 trains with 8.4 MMtpy of capacity • MLNG Dua—3 trains with 9.6 MMtpy of capacity • MLNG Tiga—2 trains with 7.7 MMtpy of capacity. To national grid Into PGU

Buffer zone Industrial zone Power Petrochemical plant plants

Residential and commercial areas

Oil refineries LNG regasification plant Crude and LNG imports

Crackers Pipeline Crude and LNG storage

Buff er z one

Malaysia is the third-largest natural gas reserves holder in the Asia-Pacific region and the second-largest oil and natural gas producer in Southeast Asia. Proven natural gas reserves are just under 85 Tcf. According to the US Energy Information Administration (EIA), Malaysia’s dry natural gas production has increased steadily, reaching 2.3 Tcf in 2012. The majority of natural gas production comes from two areas: the Malaysia-Thailand Joint Development Area (MTJDA) and offshore Sarawak. The MTJDA covers 2,800 mi2 in the lower part of the Gulf of Thailand. This area contains proven natural gas reserves of nearly 10 Tcf. Most of Malaysia’s natural gas reserves are located in the eastern region, offshore Sarawak. Burgeoning production offshore Sarawak supports Petronas’ massive, eight-train Bintulu LNG export terminal. Bintulu is the primary reason why Malaysia is the world’s second-largest LNG exporter, behind Qatar. By 2016, however, Malaysia will drop to third place, once Australia’s new LNG terminals are put into operation. Australia plans to add over 61 MMtpy of domestic LNG export capacity by the end of 2016. Malaysia is also developing numerous downstream projects under its Economic Transformation Program (ETP). The ETP’s goal is to turn Malaysia into a developed country by 2020. These goals include increased production at offshore oil and gas fields, as well as the construction of downstream projects in Pengerang, Bintulu and the launch of the world’s first floating LNG (FLNG) vessel. These ambitious goals also have the potential to challenge neighboring Singapore in the race to become Asia’s defining LNG hub.

Preserved environmentally sensitive area

FIG. 1. Layout of the Pengerang Integrated Petroleum Complex. Hydrocarbon Processing | JANUARY 201535

Boxscore Construction Analysis TABLE 1. Major contract awards for Petronas’ RAPID project Company

Contract

Units

CTCI, Chiyoda, Synerlitz (Malaysia) and MIE Industrial

EPCC

Residue fluid catalytic cracking units, LPG treating unit, propylene recovery unit and caustic neutralization units

Sinopec Engineering, Sinopec Engineering Malaysia

EPCC

Crude distillation unit, atmospheric residue desulfurization units and hydrogen collection and distribution units

Tecnicas Reunidas SA, Tecnicas Reunidas Malaysia

EPCC

Kerosine hydrotreating unit, diesel hydrotreating unit, naphtha hydrotreating unit, cracked naphtha hydrotreating unit, and continuous catalytic reformer units

Petrofac (UAE), Petrofac E&C (Malaysia)

EPCC

Amine recovery units, sulfur recovery units, sour water stripping units, liquid sulfur storage unit, and sulfur solidification units

Toyo Engineering, Toyo E&C Malaysia

EPCC

Steam cracker complex

Technip-Fluor

PMC

N/A

Siemens, Siemens Malaysia, MMC Engineering Services

EPCC and long-term Cogeneration plant service agreement

FIG. 2. Keel laying of the PFLNG 1 vessel. Source: Petronas.

To process gas from newly discovered fields in offshore Sarawak, Petronas is planning the construction of a ninth train at Bintulu. The $2-B, 3.6-MMtpy LNG train will have bidirectional capabilities for both liquefaction and regasification processing. JGC Corp. was awarded both the FEED and engineering, procurement, construction and commissioning (EPCC) contracts. JGC will also be responsible for rejuvenation work on Trains 4, 5 and 6 at Bintulu. The rejuvenation project is scheduled for completion in January 2019. Train 9 will include gas receiving facilities, an acid gas removal unit, dehydration and mercury removal units, fractionation and liquefaction units, and associated utilities and facilities. Completion is scheduled for early 2016. Once finished, total liquefaction capacity at Bintulu will reach nearly 30 MMtpy.

FLNG. Petronas is also pioneering the use of FLNG technology. The company is developing two FLNG vessels— PFLNG 1 and PFLNG 2. Once completed in 4Q 2015, PFLNG 1 will be the first FLNG vessel in operation in the world. The vessel will be located in the Kanowit field, 180 km offshore Bintulu, Malaysia. PFLNG 1 will have a design capacity of 1.2 MMtpy and will be able to monetize natural gas from Malaysia’s smaller, remote offshore fields. FEED work, along with engineering, procurement, construction, installation and commissioning (EPCIC), was conducted by Technip Daewoo, a JV between Technip and Daewoo Shipbuilding and Marine Engineering. The vessel is being constructed at Daewoo’s shipyard in Okpo, South Korea. Construction on PFLNG 1 commenced in June 2013. The keel was laid in January 2014 (FIG. 2), and the hull was launched in April 2014. In late January 2014, Petronas approved the construction of PFLNG 2. Once completed, the 1.5-MMtpy vessel will operate at the Rotan gas field. The dual-FEED contract was awarded in 2012 to the Modec, CB&I Nederland BV and Toyo Engineering Corp. consortium, as well as to the JGC, Samsung Heavy Industries Co. (MHI), JGC Malaysia and SHI Malaysia consortium. The EPCIC contract was awarded to the consortium of JGC, JGC Malaysia, SHI and SHI Malaysia. Air Products will provide its proprietary AP-NTM LNG technology for the vessel. PFLNG 2 is scheduled for startup by early 2018. Both FLNG vessels will enable Petronas to unlock gas reserves in Malaysia’s remote and stranded fields, which were once thought to be uneconomical to develop.

Detailed and up-to-date information for active construction projects in the refining, gas processing, and petrochemical industries across the globe | ConstructionBoxscore.com

36JANUARY 2015 | HydrocarbonProcessing.com

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| Special Report LNG, NGL AND ALTERNATIVE FEEDSTOCKS Countries are targeting natural gas as the go-to hydrocarbon for increasing energy security and reducing air emissions from the combustion of oil- and coal-based fuels. Natural gas production from shale plays has expanded rapidly in recent years, which has led to an increase in global natural gas liquids (NGL) output. This month’s special report features advances in gas processing technologies and opportunities now provided by alternative feedstocks for the hydrocarbon processing industry. Photo: Pearl GTL is a world-scale project located in Ras Laffan Industrial City, 80 km north of Doha, Qatar. Pearl GTL is the world’s largest single source of GTL products, capable of producing 140 Mbpd of fuel. Shell and Qatar Petroleum are the owners/ operators of the Pearl GTL complex. Photo courtesy of Shell Global.

Special Report

LNG, NGL and Alternative Feedstocks M. BHARGAVA, C. NELSON, J. GENTRY and V. SIDDAMSHETTI, GTC Technology US LLC, Houston, Texas

Maximize LPG recovery from fuel gas using a dividing wall column Refiners are challenged to recover LPG from mixed fuel gas streams due to the difficulty of separating the lighter components from bulk gas. As a result, many valuable components are lost to a fuel stream or flare. To maintain profitability, it is essential to direct all of the crude oil components to the optimum disposition. This practice is becoming more significant due to increasing LPG demand in some countries and the supply of lighter crudes in countries such as the US. In a refinery, fuel gases are produced from various types of units, including fluid catalytic crackers, catalytic reformers, hydrotreaters, delayed cokers, and crude distillation units. A typical configuration of fuel gas-producing units in a refining complex is shown in FIG. 1. There are many processes available for LPG recovery, either through cryogenic or absorption systems. Some of these systems are licensed from technology suppliers, and others are available in the public domain. These conventional technologies have major challenges to maximize the recovery of LPG-range material beyond 95 wt%, while at the same time being highly energy efficient. To cover this engineering gap, a solution has been developed to maximize LPG recovery and reduce energy consumption. Indepth details of this process solution are provided, with a case study comparing an existing refinery’s LPG recovery scheme with the application of the new design to achieve better process performance and a higher return on investment. A key element of the technology is the use of a dividing wall column (DWC) to overcome the inherent inefficiency associated with the traditional methods of processing fuel gas for LPG recovery. TABLE 1 shows the basic process performance and a simple payback period for an investment using the DWC system. New technology solution. A recently developed process uses

the DWC technology to optimize the overall operation and enhance C3+ recovery. The DWC can separate a multi-component feed into three or more streams within a single column. The deethanizer and depropanizer columns in a traditional LPG recovery system are replaced with one column using a dividing wall to achieve higher C3+ recovery at lower operating temperatures and pressures. As a result, both capital investment and operating costs for grassroots and revamped applications are reduced.

is used here to maximize LPG recovery from refining fuel gas. A simplified flow diagram of the process is shown in FIG. 2. The diagram shows a single column with a dividing wall for deethanizer and depropanizer operation, in the place of two conventional columns. The vertical wall separates the top of the column into two sections, with one side used as an abTABLE 1. Economics of the DWC system Variables

New LPG recovery technology

Overall propane recovery, wt%

97+

LPG recovered, bpd

1,350

Number of columns

1

Material of construction

Carbon steel

Turboexpander and refrigeration system

Not required

Net benefit, $MM

10.1

Total installed cost, $MM

15

Simple payback, months

18 Fuel gas

Gas processing Gas H2 Light straightrun naphtha

Heavy naphtha

Atmospheric crude distillation column

Gas

Hydrotreater

Gas H2

Naphtha hydrotreater

Catalytic reformer

Kerosine

Diesel

H2

the DWC concept through a non-cryogenic absorption system

Reformate Gas H2 Kerosine/ jet fuel

Diesel

Gas H2

Gas

FCC feed treater

FCC unit

Gas H2

FCC naphtha

Hydrotreater

FCC gasoline

FCC fuel oil Gas Delayed coker

Process description. The patented separation process with

Isomerate

Hydrotreating unit

Hydrotreating unit

Desalted Vacuum distillation crude oil column Atmospheric residue

Butanes

H2

C5/C6 isomerization

Gas H2

Gas

LPG

Sweetening unit

Coker gas oil

FIG. 1. Typical fuel-gas-producing units in a refining complex. Hydrocarbon Processing | JANUARY 201539

LNG, NGL and Alternative Feedstocks sorption section and the other side used for fractionation. The process is designed to separate lighter C2– components (noncondensables), intermediate C3 boiling-range components and heavier C4+ material in a single distillation column. The butane-plus material can be further fractionated to produce butanes and C5+ as desired for specific applications. The feed is supplied to the absorption section of the DWC, where non-condensables and water are concentrated in the overhead and passed through a partial condenser. Condensed vapors are collected in the overhead drum for separating out the sour water, and then circulated back to the column as reflux. Non-condensables from the overhead drum are removed as vapor product and routed to the refinery fuel gas header. The section above the feed location acts as an absorption section, where a separate heavy liquid stream is introduced to recover C3 and C4 components from the C1 and C2 components. The liquid, which serves as a solvent for minimizing C3 loss, can simply be the heavier components from the feedstream. In this case, the heavy liquid for absorption is a slip stream from the bottoms material of the DWC.

The other side at the top of the DWC is referred to as the fractionation section, which is concentrated with C3 components. The vapors from the overhead of the fractionation side are condensed in a water-cooled condenser and collected in an overhead receiver. A portion of this liquid is circulated back to the column as reflux, while the remaining liquid is withdrawn as LPG product. The overhead pressure of the column is controlled by a pressure control loop installed on the line to the fuel gas header at the absorption side, while the pressure in the overhead receiver on the fractionation side is controlled by a hot vapor bypass pressure control loop. A single thermosiphon reboiler is provided at the bottom of the column to supply the duty required to distill C3 components. The heat input to the reboiler is regulated by controlling the steam flow cascaded to the column bottom tray temperature controller. A slip stream from the bottom product is pumped to the top of the adsorption section as a solvent or absorbing medium, while the remaining liquid is removed from the system. Application case study. The aforementioned process has

TABLE 2. Fuel gas composition of the feed Liquid

Vol%

Hydrogen

0.05

H2O

0.01

CO2

0.01

H2S

1.23

Methane

0.6

C2

5.12

C3

14.95

C4

28.19

C5

36.06 +

13.81

Total

100

C6

been applied to a real-world case. A new simulation model has been created to review the existing LPG recovery scheme, the process disadvantages, and the application of a DWC to enhance the overall process performance. After an in-depth study and detailed analysis of the simulation results, the key advantages of the advanced DWC process show great improvement in LPG recovery and a dramatic reduction in both capital and operating costs compared to the closest alternative technology. Project scope. The objective of the study was to maximize LPG recovery (> 96 wt%), reduce hydrogen sulfide (H2S) in the product (< 40 ppm) and minimize operational costs (no refrigeration) with a higher energy-efficiency solution from a mixture of fuel gas. The fuel gas to the unit comes from two sources and is mixed in a feed drum at an operating pressure of 160 psig, before being supplied to the LPG recovery scheme. The design basis for the maximum utilization of the existing process scheme includes:

Fuel gas C2-

Fuel gas

Water

Fuel gas

LPG Water

Fuel gas

Deethanizer

Feed

470 psig

Depropanizer

250 psig

C4 and heavies Heavies slip stream for absorption

FIG. 2. Simplified flow diagram for maximizing LPG recovery from fuel gas using a single column.

40JANUARY 2015 | HydrocarbonProcessing.com

C4 and heavies

FIG. 3. Simplified process diagram of the existing process scheme.

LPG

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LNG, NGL and Alternative Feedstocks tion would come at the expense of a high utility requirement, leading to higher operating costs.

1. Feedrate at 10,000 bpd 2. Cooling water to be used for overhead condensation (no refrigeration) 3. Minimize operating pressure 4. Use existing columns for new design; if not feasible, design new columns 5. Minimize H2S in LPG product. The fuel gas feed composition is shown in TABLE 2. Existing process. A simplified flow diagram of the existing

process is shown in FIG. 3. The existing process uses two separate columns, at operating pressures of 250 psig and 470 psig, for separating C3– material and then recovering C2– fuel gas and LPG products. The overall process is able to recover only 55 wt% of the propane and leaves a higher content (180 ppm) of H2S in the LPG product. The primary reasons for the low recovery rate in the existing process are lower operating pressure and a partial condenser used in the first two columns, both of which contribute to propane loss in the overhead gas streams of both columns. A logical solution to counteract the problem and enhance the recovery rate is to increase the operating pressure and use refrigeration to condense the overhead gas. However, this solu-

Study for advanced solution. The existing process was evaluated in detail to determine the root cause of the propane loss. Then, an in-depth study for maximizing the propane recovery at lower energy consumption was carried out in four stages. Process Scheme 1. In the first-stage study (shown in FIG. 4), a new depropranizer and an existing deethanizer column were used at an increased operating pressure of 390 psig (up from 250 psig). The new depropranizer helped recover 92% of the propane, but the existing deethanizer column remained inefficient due to its lower column dimensions and the usage of cooling water for overhead gas condensing. Therefore, the overall C3 recovery achieved was only 76%, with 160 ppm of H2S in the LPG product. The total reboiler heat duty required for this case was 18.1 MMBtu/hr. Process Scheme 2. The second-stage study (shown in FIG. 5) further enhances the recovery by using two new columns for the deethanizer and depropranizer, at a reduced operating pressure of 250 psig. Also, an absorption operation is included at the top of the deethanizer column for minimizing propane loss. Fuel gas

Fuel gas Fuel gas

Water

LPG New deethanizer

Deethanizer To DIB column

Feed

250 psig New depropanizer

250 psig

470 psig

New depropanizer

390 psig

Feed

Water

Heavier hydrocarbons

C4 and heavies

LPG

FIG. 4. New depropanizer at higher pressure, plus existing deethanizer.

FIG. 5. New deethanizer based on absorption, plus new depropanizer.

TABLE 3. Economic advantages of the existing and modified process schemes

Variables

Existing scheme

Process Scheme 1

Process Scheme 2

Process Scheme 3

New depropanizer at higher pressure, plus existing deethanizer

New depropanizer based on reboiled absorption plus existing deethanizer

Enhanced LPG recovery technology

Overall propane recovery, wt%

55

76

97

97

Total duty requirement, MMBtu/hr

22

20

28

20

883

LPG product rate, bpd

1,267

1,445

1,445

LPG benefit/yr, $MM

Existing

7

10.2

10.2

Net benefit/yr, $MM

Existing

4.2

9.2

10.1

Total installed cost, $MM

Existing

17

23

15

Simple payback, months

Existing

48

30

18

42JANUARY 2015 | HydrocarbonProcessing.com

LNG, NGL and Alternative Feedstocks The absorption effect here is achieved with the introduction of a heavier stream consisting of C5 and C6 components at the column top to absorb C3+ material stripped along with C1 and C2 components. This modified process helps achieve higher C3 recovery of 96.9 wt% with just 40 ppm of H2S in the LPG product. However, this comes at the expense of a higher reboiler duty of 28 MMBtu/hr and the addition of two new columns. Part of the duty in the deethanizer is used to build a concentration peak of C3 component in the bottom area of the column, which is remixed with the heavier components. Process Scheme 3. In the final stage, to further reduce energy consumption and minimize capital costs, an advanced process solution using a single top DWC was designed. This DWC solution eliminates the need for a new depropranizer column. A single column is used for both the deethanizer and depropranizer operations. This single-column solution comes at a significantly lower reboiler duty of 20.3 MMBtu/hr, while at the same time maintaining a higher C3 recovery of 97 wt% and 40 ppm of H2S in the LPG product. FIG. 2 shows the simplified process scheme for the enhanced LPG recovery technology. The economic analyses of the various stages of this study in comparison with the existing scheme as the base case are shown in TABLE 3. The product specifications achieved with respect to the design target are shown in TABLE 4. The calculations for the total investment are based on the equipment cost estimated using 2013 US Gulf Coast prices, the equipment

TABLE 4. Target product specifications vs. design for LPG and fuel gas products Component Propane, lv% Ethane, lv% H2S, ppm Butanes and heavier, psig Vapor pressure at 100°F, lv%

Specification target

Achieved design

> 90

99