Hydrocarbon Processing July 2015.pdf

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REFINERY OF THE FUTURE Advanced project management and technology solutions facilitate revamps to meet environmental regulations

CHINA REPORT An “energy revolution” meets expanding industrial infrastructure, demand growth

LNG REPORT Changing market conditions spur LNG developers to reassess project economics

PROJECT MANAGEMENT Successful project execution requires managing different types of risk

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JULY 2015 | Volume 94 Number 7 HydrocarbonProcessing.com

59

56 SPECIAL REPORT: REFINERY OF THE FUTURE 33

European refiner revamps delayed coker to meet Euro 5 specifications C. Bolohan, L. Manafu and J. D. Ward

39

Use advanced automation and project management to simplify refinery construction E. Spiropoulos

43

Turning a Tier 3 profit J. Esteban and M. Hartman

49

DEPARTMENTS 10 17 84 86 88 89 90

News Industry Metrics Innovations Marketplace Advertiser Index Events People

How to cost-effectively adapt to a tight oil world D. Lindsay, M. Griffiths, A. Sabitov, D. Sioui and B. Glover

BONUS REPORT: LNG 57 US liquefaction projects to drive global expansion of LNG trade A. Slaughter

REGIONAL REPORT 59 China’s ‘energy revolution’ strives for sustainable growth M. Rhodes

PROJECT MANAGEMENT 69 Better risk-management methods ensure project success C. Rentschler and G. Shahani

GAS TREATING 73 Improve LPG treating via advanced amine-solvent recovery technologies

COLUMNS 9

Courage amid challenge and change

19

21

T. Meek Cover Image: Klesch Group’s Heide refinery, located north of Hamburg, Germany, is a distillates-focused plant. It produces mainly diesel, heating oil, jet fuel and some gasoline and petrochemicals. While servicing the inland markets, the refinery is well integrated with the local industrial community of Brunsbüttel, with access to road and rail networks and local pipelines. Photo courtesy of Photo Raffinerie Heide.

Automation Strategies Safety lifecycle management challenges in hydrocarbon processing plants

23

Global Investment in Egypt’s downstream on the rise

25

Petrochemicals Higher international sales boost 2015 earnings above forecast for many chemical leaders

27

Engineering Case Histories Case 85: Learnings on hydraulically fitted hubs

B. Glasscock

PROCESS AUTOMATION 82 Automate environmental monitoring at petrochemical plants with LIMS

Reliability Trends from the 2015 AFPM Maintenance and Reliability Conference

D. Engel, H. Burns and B. Spooner

MANAGEMENT 79 A data-driven, experience-based approach to workforce optimization

Editorial Comment

29

Viewpoint Advice for the downstream: Keep the faith

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Two Events, One Location September 9–11, 2015 Hyatt Regency Houston | Houston, Texas

AMERICAS LNGAmericasConference.com

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Get the latest natural gas and LNG industry outlooks, infrastructure updates, technology developments and more The second annual GasPro Americas will be held September 9-11, 2015 in Houston, Texas at the Hyatt Regency Houston. This year’s conference will be held in conjunction with LNG Americas, and together, these events provide a timely gathering for the gas processing industry to meet and discuss the latest challenges and developments; learn about the current economic outlook; share best practices; explore solutions to help improve production and efficiency; network with peers and more.

Agenda at a Glance: September 9: Combined Business Day / September 10–11: Dual-track Technical Program The GasPro Americas track focuses on broader gas processing topics and the LNG Americas track is devoted to LNG. Attendees will be able to jump back and forth between BOTH conferences. Attend the sessions that interest you the most!

Technical Sessions Include: • Separation/dehydration/acid gas removal

• Policy in the Americas

• Rejection: Ethane/methane/nitrogen • NGL recovery

• Regional opportunities for the Americas: Pacific Northwest, Canada

• Gas sweetening/fractionation

• Bunkering

• Syngas production and utilization

• LNG supply chain

• Flaring and emissions

• Liquefaction and regasification

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Business Day Agenda: Wednesday, September 9 7:30–8:55 a.m. Registration and continental breakfast

Session One: The future of natural gas in America 8:55–9 a.m. Opening Remarks: John Royall, President and Chief Executive Officer, Gulf Publishing Company 9–9:35 a.m. EIA: Annual Report 2015: Vishakh Mantri, PhD, PE, PMP, Office of Petroleum, Natural Gas and Biofuels Analysis – Biofuels and Emerging Technologies Team, US Energy Information Administration 9:35–10 a.m. Domestic energy infrastructure update: Lee Nichols, Data Director, Gulf Publishing Company 10–10:30 a.m. Coffee break

Session Two: NGL in America 10:30–10:55 a.m. NGL Outlook: Anne Keller, Manager, NGL Research, Wood Mackenzie 10:55–11:20 a.m. Production of gas liquids – Eagle For and Marcellus/Utica: Ajey Chandra, Managing Director, Muse, Stancil & Co 11:20–11:45 a.m. Gathering, processing and take away efficiencies: Crestwood Midstream Partners (invited) 11:45 a.m.–12:45 p.m. Lunch

Session Three: The future of LNG—Are we still a competitive option for the global market 12:45–1:15 p.m. Global LNG: Will new demand and new supply mean new pricing: Dale Nijoka, Global Oil and Gas Leader, EY (invited) 1:15–1:40 p.m. LNG Finance in World Markets: Jason Feer, Global Manager, Poten & Partners 1:40–2:10 p.m. Coffee break 2:10–2:35 p.m. Methane emissions and solutions in natural gas: Matthew Kelly, Analyst¸ICF International (invited) 2:35–3:45 p.m. Panel Discussion: Reducing emissions – Operator response Moderator: Ken Chow, Senior Partner, Muse, Stancil & Co Invited panelists from: Enlink Midstream; Enterprise Products Partners, LP; Williams Partners; Energy Transfer Partners; Noble Energy; Chesapeake Energy; and Questar Pipeline Company. 3:45 p.m. Closing Remarks: John Royall, President and Chief Executive Officer, Gulf Publishing Company *Visit GasProcessingConference.com for the complete technical program and agenda updates.

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Editorial Comment

STEPHANY ROMANOW, EDITOR [email protected]

Courage amid challenge and change Working in the downstream requires tremendous courage. Why courage? It does not mean HPI staff have no fear. Actually, it is quite the contrary. The downstream industry must manage risk at many levels that can be interpreted as almost fearful. Why try? Why work in an industry that

is constantly challenged by governments and regulatory agencies? For many, it is rewarding to overcome obstacles and to create products that have, and continue to, revolutionize society. Today’s society was created through the development of transportation fuels and combustion engines. With both advancements, goods and people became more mobile, thus further developing commerce domestically and internationally. Room for all. Some critics hold the thought that oil and natural gas-based fuels and products have outlived their usefulness, and that society should switch to renewable fuels and plastics. Open-minded thinking supports the argument that there is room for all products. Research and development is warranted to identify and investigate alternative products as part of sustainable development for the long term. What is undermining, if not destructive, is the support of regulations that mandate conversion to alternative fuels before such products have been thoroughly developed and can compete in the marketplace without subsidies and penalizing regulations. In the US, the battle to oust crude oilbased transportation fuels continues. For many years, critics of big oil have waged a war against transportation fuels under the guise of saving the planet and the people. This is a harsh viewpoint. Over the past two decades, transportation fuels have been over-regulated under the premise of protecting the public and ensuring energy security.

‘When the going gets tough...’ Such

conditions require courage by members of downstream companies to knowingly face these challenges and continue to develop viable solutions. What if Thomas Edison had quit working to find the proper filament for the light bulb after the first few failures? For the most part, society would have remained in the dark, thus hindering the beginning of the industrial revolution. In the US, outdated laws such as the Renewable Fuel Standard (RFS) keep the refining business in the dark. Over the years, HP has commented on environmental and safety issues for transportation fuels and petrochemical products through the Insight and Editorial columns. As a member of the HP editorial team for over 23 years, it has been my responsibility to develop these columns to comment on pressing issues for the downstream industry. A quick review of my past editorials yields a unique trend: Without fail, the downstream rallies to overcome numerous obstacles presented by changing economic cycles, regulations and technological developments. There is no single solution to the topic of clean transportation fuels. Energy supplies are a political and social issue in addition to being a profitability concern. Many parties are involved, thus further complicating viable solutions to meet the demands of all stakeholders. Change requires courage. Many chal-

lenges remain to be solved by the talented individuals working in this industry. It has been my great pleasure to share updates and present new ideas through past editorials. More importantly, it has been an honor to serve as an editor on the HP staff for the past 23 years. As with other downstream companies, HP is also undergoing a crew change as I retire from the HP team. I thank the numerous readers and members of the downstream community for their support of HP over the past two decades, and wish great success to all.

INSIDE THIS ISSUE

32 Refinery of the future.

Process automation in oil refineries is undergoing major changes, driven by the need for faster and more comprehensive advances from automation OEMs. Yokogawa and ExxonMobil explain how advanced automation hardware technologies, when used in conjunction with new project management techniques, make refinery construction and upgrades simpler, easier and faster.

56 Bonus report: LNG.

The global LNG environment is changing alongside fluctuating energy prices and trading patterns, particularly in Asia. The executive director of the Deloitte Center for Energy Solutions explains how LNG developers will consider project economics on an individual basis, despite variable market conditions, and which countries will shape LNG trade flows over the next five years.

59 Regional report: China.

China’s energy demand is rapidly increasing to keep pace with its expanding industrial and transportation infrastructure. The country’s government has called for a “revolution in energy” amid pressure to reduce air pollution levels and secure long-term, sustainable growth.

69 Project management.

Management of project risk is a challenge; tight schedules and insufficient resources are at the heart of the problems surrounding capital projects. Linde Engineering discusses how to use risk management as a key ingredient in project execution, and presents alternative strategies for successfully managing risk. Hydrocarbon Processing | JULY 20159

| News TOYO Engineering will use project execution solutions to deliver Malaysia cracker TOYO Engineering has purchased two leading Intergraph project execution solutions, which are being used to deliver a large-scale steam cracker complex in Malaysia. The project is part of the Refinery and Petrochemicals Integrated Development (RAPID) megaproject. When completed, it will consist of a 300-Mbpd refinery and petrochemical complex with a combined capacity of producing 7.7 MMtpy of various grades of products, including differentiated and specialty chemical products, such as synthetic rubbers and high-grade polymers. The first solution is the Intergraph Smart 3D, which leverages real-time concurrent design, rules, relationships and automation specific to the plant industry. TOYO also selected SmartPlant Materials, which offers a total materials management and subcontract management solution for chemical plants and projects.

MIKE RHODES, TECHNICAL EDITOR [email protected]

News Oman to build multi-faceted facilities in Indonesia Oman will invest $7 B to build oil storage facilities, a petrochemical plant and a refinery in Indonesia. The refinery would be built in Indonesia’s Riau province, with the oil products being purchased by state-owned oil and gas company Pertamina. An agreement was also signed for the supply of crude oil to the former OPEC member. The project is now in the process of issuing permits and groundbreaking is expected to begin in 2016. Indonesia’s fuel output has suffered from a lack of investment in its refining sector since the construction of its last refinery was completed in 1994. Pertamina has 1 MMbpd in refining capacity, which it plans to raise to 2.3 MMbpd through upgrades and additional plants.

Neste, Total to develop biosolvents, technical fluids for downstream Neste Oil and Total Fluides, a producer of high-purity hydrocarbon fluids, have signed a collaborative agreement for the supply of Neste’s NEXBTL renewable isoalkane used by Total Fluides as feedstock to produce and develop innovative bio-based solvents and technical fluids. NEXBTL renewable products have a comparable position to that of their fossil equivalents and can be transformed into materials with unique properties. Neste produces NEXBTL products intended for chemical industry use at its renewable products refineries in the Netherlands, Singapore and Finland (FIG. 1). Total Fluides will market a new line of renewable fluids for numerous applications such as paints and coatings, drilling fluids, solvents for emulsion polymerization, printing ink fluids, and emollients for cosmetics, among others. The biobased fluids will be produced at the company’s plant in France.

Haverhill to shutter Ohio phenol/acetone plant An unexpected withdrawal of financial support has halted production and resulted in a cessation of operations at Haverhill Chemicals’ phenol/acetone complex in Ohio. Haverhill acquired the complex from Sunoco in late 2011. The site has a production capacity of 300 Mtpy of phenol and 173 Mtpy of acetone. Shipments to customers will continue until inventory is exhausted. The process is expected to be completed in July.

First Dragon-class vessel to transport US ethane to Europe The first in a series of 27,500-cbm Dragon-class vessels ordered by Evergas, an owner and operator of seaborne petrochemical and liquid gas transport vessels, has been delivered from the Sinopacific Offshore & Engineering (SOE) shipyard in China. The vessel features a comprehensive Wärtsilä solutions package, including two Wärtsilä 50DF dual-fuel en-

gines, propulsion equipment (including the gearbox), two 20DF auxiliary generating sets, a liquefied natural gas (LNG) fuel system and a cargo handling system. The Dragon-class ships (FIG. 2) will be chartered by INEOS Europe for the transportation of ethane to Europe from the Mariner East project in the US. While the carriers are purpose built for the transportation of ethane, they can also carry a wide range of petrochemical gases and liquefied petroleum gas (LPG). The various individual Wärtsilä solutions are integrated to form a fully optimized package. By engineering and supplying the complete cargo plant, along with the gas fuel supply system and the propulsion plant, optimal energy consumption efficiency for the entire vessel can be achieved. For example, the LNG supply system is integrated with the cargo handling system so it can be used to cool the cargo. The Dragon-class vessels (FIG. 2) are 180 m long and 26.6 m wide with a draft of approximately 9 m, and they represent the largest ethane carriers in their class in the world.

FIG. 1. NESTE produces NEXBTL products at its renewable products refinery in Porvoo, Finland. Hydrocarbon Processing | JULY 201511

News Chevron sells New Zealand downstream operations to Z Energy Z Energy has agreed to buy Chevron Corp.’s downstream operations in New Zealand for $558 MM, ensuring its place as the nation’s biggest gasoline retailer. The company will add Chevron’s 146 Caltex retail outlets to its existing 210 sites, which were acquired in 2010 when the company took over assets from Royal Dutch Shell. It also will grow its share of supply to commercial operators and its role in distribution. Chevron, which sold a 50% stake in Caltex Australia in March, has also divested an 11% stake in New Zealand Refining Co.

Emerson acquires software group ESI

UOP wins Egypt oil refinery expansion contract

Emerson Process Management has acquired Energy Solutions International Holdings Inc. (ESI), expanding its capability to provide complete solutions for automation and operations management throughout the oil and gas transportation industry. ESI’s integrated suite of operational management applications for pipeline modeling, leak detection and scheduling is recognized for improving both operational efficiency and profitability. ESI will join Emerson’s Remote Automation Solutions group, which provides oil and gas supervisory control and data acquisition (SCADA) and fiscal measurement solutions.

UOP LLC, a Honeywell company, has signed two contracts worth a combined $1.4 B for the expansion of an oil refinery in the Amreya free zone of Alexandria, Egypt. As part of the agreement with state-owned Middle East Oil Refinery (MIDOR), UOP will provide engineering designs and licensing. The project aims to increase the refinery’s production capacity by 60%, from 100 Mbpd to 160 Mbpd. When the expansion is completed, the annual production capacity of the refinery will reach up to 245 Mtpy of butane gas, 1.3 MMtpy of gasoline, 3.2 MMtpy of diesel oil, 570 Mtpy tons of coal and 135 Mtpy of sulfur (S).

CB&I awards Shintech ethane cracker furnace coil contract to Manoir

FIG. 2. Evergas has taken delivery of a Dragon-class vessel powered by a Wärtsilä propulsion solution.

International metal processing group Manoir Industries has been awarded the complete furnace coils contract by CB&I for the Shintech ethane cracker project in Plaquemine, Louisiana. The furnace components are based on Manoir’s Manaurite high-alloy technology and are manufactured in its production center in Yantai, China, with the coordination and support of technology and project teams in Pîtres, France. Manoir develops alloys and manufactures highperformance metal components molded and forged for the petrochemical, nuclear, oil and gas, civil engineering, energy, defense and construction markets. The teams work under an international production scheme that guarantees consistent manufacturing and quality control processes across all plants in France, the UK, India and China.

Bechtel to quadruple Queensland LNG production this year

FIG. 3. Bechtel construction at Australia’s Curtis Island LNG complex.

12JULY 2015 | HydrocarbonProcessing.com

Bechtel is on track to complete the construction of an additional three LNG production trains on Curtis Island by the end of 2015, quadrupling Queensland’s LNG production. The company is constructing the state’s first three LNG plants, the first in the world to convert commercial quantities of coal seam gas into a liquid form

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News ready for export. At full capacity, the three Curtis Island projects will produce a combined 25 metric MMtpy of LNG. When complete, the operators of the plants—Queensland Curtis LNG (BG Group), GLNG Plant Project (Santos, Petronas, Total and KOGAS) and Australia Pacific LNG (ConocoPhillips)— will produce the commodity for export to their global customers. Six production trains (FIG. 3) will be operational when

Bechtel hands over the LNG plants to the owner teams for long-term operation. Queensland Curtis LNG Train 1 has been producing LNG since December 2014, and Bechtel is now working on delivering the second train for that project. Concurrently, Bechtel teams on the GLNG and Australia Pacific LNG plants recently introduced gas into their systems and began producing their own power as part of commissioning the first of two production

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trains on each site. The second production trains on each of these projects are expected to be operational in early 2016.

US approves non-FTA LNG exports from Alaska project The US Department of Energy (DOE) has sanctioned the export of LNG from a plant on the Kenai Peninsula to countries that do not have a free trade agreement (FTA) with the US. The agreement calls for the export of up to 2.55 Bcfd of gas for 30 years, or over 3% of US gas supply, opening up stranded natural gas on Alaska’s North Slope to global markets following a growing list of other projects already making moves in that direction. The project, estimated to cost $45 B–$65 B, would include an 800-mi pipeline to transport gas from Alaska’s northern reaches to Nikiski on the Kenai Peninsula, where it would be liquefied for shipment overseas, likely to markets in Asia. Alaska LNG is being developed by a consortium including affiliates of ExxonMobil, ConocoPhillips and BP. It is expected to take years to build, and must still undergo an environmental review and a final investment decision.

Jacobs awarded contract for Singapore VAE emulsions production plant Jacobs Engineering Group Inc. has been awarded an engineering, procurement and construction management (EPCM) contract from Celanese Corp. for the construction of a vinyl acetate ethylene (VAE) emulsions production plant at Jurong Island, Singapore. With the plant, Celanese will broaden its capabilities throughout the Asia-Pacific region, primarily in the higher-end applications of architectural coatings, building and construction, carpets and paper industries. Under the terms of the contract, Jacobs is responsible for the detailed engineering and design of the project, including procurement of major equipment and management of construction services. Construction is expected to begin by mid-2015, and the unit is expected to begin production by the second half of 2016.

News NOVATEK signs long-term LNG contract with Shell

KBR, Exelus to license catalyst technology

Novatek Gas & Power, a wholly owned trading subsidiary of OAO NOVATEK, has signed a long-term contract with Shell International Trading Middle East for the supply of LNG from the Yamal LNG project (FIG. 4). The contract stipulates annual supply of approximately 0.9 MMtpy of LNG for more than 20 years from the volumes that Novatek Gas & Power will purchase from Yamal LNG. OAO NOVATEK, Russia’s largest independent gas producer and the secondlargest natural gas producer, is engaged in the exploration, production, processing and marketing of natural gas and liquid hydrocarbons.

KBR has signed an agreement with Exelus to allow KBR to exclusively license Exelus’ solid-acid catalyst (ExSact) for KBR’s solid-acid alkylation technology (K-SAAT). Global demand for motor fuels continues to rise, while stricter environmental standards and oxygenate blend re-

quirements for gasoline place a premium on clean-burning fuels, such as alkylate. The key to the K-SAAT technology is ExSact, a solid-acid catalyst engineered to overcome rapid deactivation limitations of solid-acid catalysts and provide superior alkylation performance. The K-SAAT process is adaptive, safe and environmentally benign compared with conventional liquid-acid catalyst process technologies. 19

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Shell acquires land for ethane cracker Shell Chemical is in the midst of a multi-year site review that includes environmental analysis, engineering design studies, evaluation of ethane supply and economic viability. If built, the facility would include an ethane cracker with a nameplate capacity of 1.5 MMtpy of ethylene; three polyethylene units with a combined production of 1.6 MMtpy; and utilities. The proposed complex would be the first major US project of its type to be built outside of the US Gulf Coast region in 20 years. Shell says locating the facility close to both supply and markets would reduce economic and environmental transportation costs and provide regional plastic manufacturers with more flexibility, shorter supply chains and enhanced supply dependability. Shell plans to source ethane feedstock for the complex from the nearby Marcellus and Utica shale plays.

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MIKE RHODES, TECHNICAL EDITOR [email protected]

Industry Metrics

World liquid fuel supply and demand, MMbpd Cracking spread, US$/bbl

May 15

April 15

Mar. 15

Feb. 15

Jan. 15

Dec. 14

Nov. 14

Oct. 14

May 15

April 15

Mar. 15

Feb. 15

Jan. 15

Dec. 14

Nov. 14

Oct. 14

May 15

April 15

Mar. 15

Feb. 15

Jan. 15

Dec. 14

Nov. 14

Oct. 14

Sept. 14

10 0

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

Gasoil, 10 ppm S Fuel oil, 1% S

-10

Global new project announcements, June 2014–May 2015

May 15

April 15

Mar. 15

Feb. 15

Jan. 15

Dec. 14

Nov. 14

Oct. 14

Sept. 14

-20

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

40 35 30 25 20 15 10 5 0

20

Aug. 14

2016-Q1

Rotterdam cracking spread vs. Brent, 2014–2015*

July 14

2015-Q1

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

30

June 14

2014-Q1

6 5 4 3 2 1 0 -1 -2 -3

May 14

Forecast

Stock change and balance, MMbpd

100 Stock change and balance 98 World demand 96 World supply 94 92 90 88 86 84 82 2010-Q1 2011-Q1 2012-Q1 2013-Q1

Aug. 14

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

July 14

Source: DOE

40

Prem. gasoline unl. 93 Jet/kero

June 14

W. Texas Inter. Brent Blend Dubai Fateh

Cracking spread, US$/bbl

100

50 40 30 20 10 0 -10 May 14

Singapore cracking spread vs. Dubai, 2014–2015*

Source: Hydrocarbon Processing Construction Boxscore Database

0

May 15

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

April 15

Feb. 15

Jan. 15

Dec. 14

Nov. 14

Oct. 14

Sept. 14

Prem. gasoline unl. 92 Jet/kero

Mar. 15

-10 -20 Aug. 14

Nov. Dec.- Jan.- Feb.- Mar.- April- May-14 14 15 15 15 15 15

10

July 14

June- July- Aug.- Sept. Oct.14 14 14 -14 14

20

May 14

Cracking spread, US$/bbl

30

June 14

Oil prices, $/bbl

Japan Singapore

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

115

Supply and demand, MMbpd

US EU 16 Sept. 14

May 14

Selected world oil prices, $/bbl

New projects

Sept. 14

70 60 50

130

55

Aug. 14

80

Aug. 14

1 0

90

July 14

2

June 14

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

Global refining utilization rates, 2014–2015* 100 Utilization rates, %

4

Gas prices, $/Mcf

Production, Bcfd

5

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

85

Brent, Rotterdam

6

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

70

Arab Heavy, US Gulf LLS, US Gulf

WTI, US Gulf Dubai, Singapore

July 14

7

80 70 60 50 40 30 20 10 0

5 0 -5

May 14

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

15 10

June 14

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

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

US refineries are running at record levels and delaying their scheduled 2015 maintenance until 2016 to take advantage of very high margins and demand for refined products, including gasoline. In the Asian market, refinery margins strengthened on the back of higher regional demand amid tightening sentiment due to the maintenance season.

* Material published permission of the OPEC Secretariat; copyright 2015; all rights reserved; OPEC Monthly Oil Market Report, June 2015. Hydrocarbon Processing | JULY 201517

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Reliability

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

Trends from the 2015 AFPM Maintenance and Reliability Conference The annual American Fuel & Petrochemical Manufacturers (AFPM) Reliability and Maintenance Conference and Exhibition was held in Austin, Texas, in late May. This conference has been held for a long time. Over the decades, there have been good and not-so-good trends presented at this event, and the 2015 maintenance and reliability conference was no exception. Training. As in previous years, over 200 exhibitors were represented at this conference. Unfortunately, the service providers and their staff outnumbered attendees from operating companies. It was again clear how, to some managers in the hydrocarbon processing industry (HPI), training is a deferrable option. It is assumed that not investing in targeted training will appear neatly on the company’s balance sheet. Conversely, deferred training is a very unhealthy trend if it is sustained over the long term. Stars of AFPM 2015. Fortunately, the 2015 maintenance and

reliability event had many presenters and exhibitors deserving of commendations. Two co-presenters from Flint Hills Resources (FHR) plants in Minneapolis/St. Paul, Minnesota, and Corpus Christi, Texas, conveyed their personal commitment and the company’s consistent leadership model. Their collective norms of behavior are based on shared values and beliefs— a slow but commendable trend. Likewise, FHR doubled down on the company’s commitment to training and sent a sizable group of reliability professionals to attend this conference. Good for FHR! Such actions have a greater impact for employees than clever slogans and press releases. New trends. Favorable trends are developing in the emergence of service organizations with global experience that is anchored in analytical and implementation tasks. More specifically, companies, such as T.A. Cook, can find and explain massive opportunities hidden in an HPI company’s maintenance routines or data. Suitable analyses and comparisons with other locations and competitors can help uncover opportunities that may have remained untapped due to a lack of solid proof. The time (or training) may not have been available to properly examine workflow or asset upgrading opportunities in a complex processing environment. Also, it is difficult to identify and apply benchmarking techniques that were devised for another industry or company. Shutdown management and work definitions are deserving of accurate data gathering and detailed cost justification. Also, there are elements of risk management (RM) that are frequent prerequisites to turnaround work. Entrusting RM to competent service organizations that can provide all needed and relevant analysis and auditing tasks is a viable action.

In a follow-up review centered on one asset management/ operational excellence provider, this author came away with the impression that sustainable efficiency gains, massive and accelerated learning tasks, plus effective management of future processes and decisions are needed. Working with highly experienced consulting companies and service providers is a favorable action. Such providers were present at the 2015 AFPM Reliability Conference and Exhibition. This is an obviously desirable trend. Program. The 2015 program committee should be praised

for selecting an unusually relevant keynote speaker, D. Michael Abrashoff, a former US Navy commander and the author of It’s Your Ship. He was a navy officer who was assigned to a ship with very poor performance and very low morale. To drastically improve the performance of the ship’s crew, he had to change his own leadership style from the traditional command-and-control model. Captain Abrashoff created a high-performance culture, and it is one worthy of imitation. He encouraged crew members to identify problems when they are still small, and empowered them to take corrective action. Abrashoff ’s program was in sync with FHR. On a similar path, FHR developed and nurtured a culture strongly biased to action. It is the author’s humble opinion that it is time for HPI organizations to recognize and imitate both FHR and Captain Abrashoff. Next year’s wishes. The 2016 event will take place in San Antonio, Texas. The optimist in us hopes to hear how other companies joined best-of-class ranks and learn how these organizations took steps toward growth. There is a need to become problem solvers and to mature in status and reliability performance. We must find and cure root causes of problems instead of just treating the symptoms. An optimistic trend would be that more companies work closely with competent solution providers. Finally, there are merits in training and grooming professionals in both salaried and wage positions. If you are among the very best, then please share your wisdom and experience. HEINZ P. BLOCH resides in Westminster, Colorado. His professional career commenced in 1962 and included long-term assignments as Exxon Chemical’s regional machinery specialist for the US. He has authored over 600 publications, among them 19 comprehensive books on practical machinery management, failure analysis, failure avoidance, compressors, steam turbines, pumps, oil mist lubrication and practical lubrication for industry. Mr. Bloch holds BS and MS degrees in mechanical engineering. He is an ASME Life Fellow and maintains registration as a professional engineer in New Jersey and Texas. Hydrocarbon Processing | JULY 201519

Meet Regulatory g y Compliance p And T urn Underutilized Underutilized Assets Assets Into o Profit Profit With With Turn

RENEWABLE REVAMPS REVAMP YOUR REFINERY WITH THE UOP RENEWABLE JET FUEL™ PROCESS Refineries that revamp using the UOP Renewable Jet Fuel process turn waste feedstocks into high-quality renewable diesel or renewable jet fuel, resulting in a stream of additional profits without high capital investment costs. In addition, the production of renewable fuel helps these companies lower their compliance costs.

ENHANCED FUEL POOL The unique UOP Renewable Jet Fuel process efficiently converts waste feedstocks, nonedible fats, oils and greases into a highperforming, renewable diesel or jet fuel. That’s a huge return from feedstocks that were previously mere waste materials. ™

Honeywell Green Diesel produced by the process has a cetane value of 80 — much better than the cetane value of traditional diesel, meaning better operating efficiency. Unlike biodiesel, renewable diesel produced using the UOP process is chemically identical to petroleum-based diesel and can be used as a drop-in replacement in vehicles with no modifications required. Refineries can expand the diesel pool by blending this high-quality supply with lowerquality blendstocks. Additionally, Honeywell Green Diesel is compatible with existing fuel distribution and delivery infrastructure.

Honeywell Green Jet Fuel™ has shown less emission of particulate matter and higher energy density in flight, allowing aircraft to fly farther on less fuel. When blended up to 50% with petroleumbased jet fuel, this super efficient fuel offers significant advantages over traditional fuel. It’s a drop-in replacement that requires no changes to aircraft technology or fuel infrastructure, and it meets or exceeds critical jet fuel specifications.

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MEETING ENVIRONMENTAL CHALLENGES In addition to increasing profits and lowering the cost of meeting today’s compliance requirements, creating renewable fuels using the UOP Renewable Jet Fuel process is simply the right thing to do. Greenhouse gas emissions from the renewable diesel and renewable jet fuel are up to 85% lower than fuel from petroleum.

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NOT LIMITED TO REVAMPS Revamping with the UOP Renewable Jet Fuel process gives refineries a new income stream with capital costs much lower than building a new unit, but the technology also offers advantages for new refineries. Foremost is that the process begins turning waste feedstocks into renewable fuels right from the start for an immediate return. Compliance costs are also reduced right away.

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Automation Strategies

JOSEPH SCALIA, SENIOR CONSULTANT ARC Advisory Group

Safety lifecycle management challenges in hydrocarbon processing plants Although they are mandated by functional and process safety standards, such as ISA-84 and IEC 61511, many automation and safety instrumented system (SIS) vendors to the downstream hydrocarbon processing industry (HPI) do not provide safety lifecycle management software that extends beyond the initial work performed to commission the SIS logic solver. As a result, in many cases, only the bare minimum safety instrumented function (SIF) proof testing has been performed for the most critical protective and mitigative functions. While the mandated functional safety requirements specification (SRS) should provide a description of how safety should be maintained within a process or plant area, ARC Advisory Group has observed that most vendors do not support these requirements with an appropriate suite of supervisory software to maintain, enforce and prove compliance. This often puts an unnecessary burden on end users, to comply fully with all functional safety requirements, including the ability to prove compliance. So, what should end users be thinking about as necessary parts of their safety lifecycle compliance program? For a start, do you use electronic safety lifecycle management tools to help meet traceability requirements, or are you attempting to do this manually? Do you have any tools beyond what you used to perform your initial hazardous operations (HAZOP) and layer of protection analysis (LOPA)? What about your SIS logic solver? Can your current software tools “talk” to each other to share data, or do you frequently have to re-enter the same data into different tools? Automation suppliers typically offer tools to help owneroperators determine required safety integrity levels (SILs). However, that is where the functionality often ends. While some suppliers offer rudimentary utilities to help trace and document changes to the logic solver programming, most do not offer a full suite of “fully baked” software that meets the other traceability requirements for maintaining safety instrumentation. Current limitations to most automation suppliers’ solutions require extensive custom integration, which is both costly and time consuming. Do you know if you are really in compliance? IEC 61511,

ISA TR84.00.04, OSHA 1910 and other standards define specific requirements for effective safety lifecycle management. All of these organizations emphasize that being in compliance with safety lifecycle management requirements should extend beyond just proving the compliance of initial site acceptance testing and commissioning of production equipment, controllers and processes.

This requires identifying and documenting that equipment, controllers and processes are running as designed day after day, week after week, year after year. Processes change, equipment ages and wears, procedures become “culturally blurred,” and people become complacent, believing the results of their basic safety key performance indicators (KPIs). Historically, this is when the serious “big incident” occurs, with the resulting tragic loss of life and damage to a company’s financial success and reputation. Since this is a complex problem with potentially serious ramifications for noncompliance, ARC recommends that owneroperators return to an appropriate “beginning point” to obtain the needed clarity. Start with a thorough review of your existing HAZOPs, the origin of your SIF designs and SIL requirements. Identify the specific real-time and historical data needed to confirm that you are meeting your SIL requirements. Track the status—automatic, manual and bypassed—that represent your control loops and their safety functions. Ask your vendors if they have software that does this for you automatically. Reread the standards, focusing specifically on the safety life cycle and your current operations. Is your current safety requirements specification comprehensive enough? Does it compel your organization to operate, maintain and verify the required functionalities? Do you understand what data you need to comply with OSHA 1910, IEC 61511 and ISA TR84.00.04, API 14C and OLF 70? Most importantly, are you doing your periodic safety proof tests? Are you recording all the correct information? Are you ensuring that your knowledge workers are competent, qualified and appropriately certified? Are you keeping electronic or paper records of your proof tests for each and every safety instrumented function in your operation? If so, are you performing everything on time? If you aren’t aware of and/or keeping records of how often you defer a proof test or compromise a layer of protection against any of the many defined hazards, consider taking advantage of the broader process safety management solutions offered by several consulting and engineering companies with skills and experience in these areas. JOSEPH SCALIA covers process safety and functional safety for the chemical, oil and gas, power generation and manufacturing industries. He has over 30 years of experience in industrial automation for discrete manufacturing and process control industries. Mr. Scalia has a BS degree in electrical and controls engineering (BSEE) from Kettering University, and is a TÜV-certified functional safety engineer. He has also received formal instruction in software architecture, software modeling, threat modeling and cybersecurity.

Hydrocarbon Processing | JULY 201521

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Global

SHEM OIRERE Guest Columnist

Investment in Egypt’s downstream on the rise Egypt is adopting a mix of investment strategies in refinery upgrades and construction of new capacity to meet the nation’s target for more high-quality light and middle distillate products and a reduction of transportation fuel imports. Such investments are materializing as the government becomes more stabilized and the economy shows strong signs of recovery. Demand growth for petrochemicals. The increasing demand for petrochemical products, especially ethylene, and the global shift to cleaner Euro-V-grade diesel are the main drivers for heightened investment in the Egyptian refining sector. Egypt, with total oil production of 680 Mbpd, operates nine refineries with an estimated combined capacity of 704 Mbpd. It is the largest refining network in Africa, as summarized in TABLE 1. Egypt’s refining output averages 445 Mbpd, suggesting that its refinery utilization is only approximately 63%. In contrast, the US Energy Information Administration (EIA) estimates that the country’s refinery throughput dropped by 28% between 2009 and 2013 “despite growing domestic consumption (forcing) Egypt to import petroleum products to make up for the shortfall.” Imports. Reduction of fuel imports is the focus of $3.7-B investment in upgrades to the Egypt Refining Co.’s Mostorod refinery in the Greater Cairo area. Approximately $11.7 B was spent on fuel imports in 2013, according to Egypt Central Bank. The project is financed by Qalaa Holdings, previously Citadel Capital, and is expected to be onstream within two years. According to Qalaa Chairman and Founder Ahmed Heikal, the project is fully funded and 50% complete, putting it on track to begin production in 2017 as planned. The new facility will receive low-value fuel from Cairo Oil Refinery, operated by Egyptian General Petroleum Corp., and will upgrade the

fuel to higher-value middle and light distillates. Domestic demand for distillates is increasing; the new capacity is aimed at reducing imports. “At present, demand for diesel and gasoline is rising fast and outstripping domestic supplies,” Heikal said. “The government of Egypt is simultaneously gradually decreasing its sizeable fuel subsidy. Qalaa Holdings and partners saw opportunities for a refining project that would ease reliance on imports and produce cleaner-burning fuels as one of the cornerstones of the country’s energy security policy.” The refining upgrade project will have the capacity to produce 4.2 MMton of refined products, which includes 2.3 MMt of Euro V diesel. Some of Qalaa’s equity partners in the project include Egyptian General Petroleum Corp., Qatar Petroleum International, International Finance Corp. and Germany’s DEG. With financial backing from the Japan Bank for International Cooperation, Nippon Export and Investment Insurance, Export-Import Bank of Korea, European Investment Bank, the African Development Bank and Mitsui & Co., the refinery has already signed a 25year off-take agreement with Egyptian General Petroleum Corp. at international prices, according to Heikal.

Despite the ongoing global crude price instability, Egypt is planning other new investments at existing refineries to increase throughput capacity and upgrade the refinery scheme to yield cleaner fuels with less sulfur content. Egypt produces three crude blends of Suez, Belayim and Western Desert with a sulfur content of 1.4%, 1.6% and 1.7%, respectively. Topping the list of Egypt’s refinery sector investment is the $1.4-B expansion of the Middle East Oil Refinery (MIDOR) to increase production capacity from 100 Mbpd to 160 Mbpd. The refinery plans to complete the expansion by 2017. According to the refinery’s management, there is high economic feasibility of the expansions that will increase income by 18% and transfer MIDOR from third- to fourth-generation technology. The MIDOR refinery expansion would boost middle distillate production, especially diesel, by maximizing utilization rates of existing processing units and upgrading refined products to meet Euro V specifications. In April, MIDOR signed an engineering, design and licensing contract with UOP LLC, a Honeywell company. UOP had previously provided processing and licensing for eight of MIDOR’s processing units, while three other units have

TABLE 1. Egypt’s crude oil refineries Refinery operator

Location

El-Nasr Petroleum Co.

El Suez

100,000

Cairo Petroleum Refining Co.

Mostorod (Cairo)

142,000

Alexandria Petroleum Co.

Alexandria (El Mex)

115,000

Middle East Oil Refinery

Alexandria (Sidi Kerir)

Amreya Petroleum Refining Co.

Alexandria

75,000

Suez Petroleum Processing Co.

El Suez

68,000

Assiut Petroleum Refining Co.

Assiut

50,000

Cairo Petroleum Refining Co.

Tanta

54,000

Total

Nameplate capacity, bpd

100,000

704,000

Sources: Arabian Oil & Gas and Egyptian General Petroleum Corp.

Hydrocarbon Processing | JULY 201523

Global been licensed by Mannesmann KTI and Bechtel Corp. With the new expansion, this refinery will increase product output to 245 Mton of butane gas, 1.3 MMton of gasoline, 3.2 MMton of diesel, 570 Mton of coke and 135 Mton of sulfur, according to Egypt’s Ministry of Petroleum and Mineral Resources. Optimistic outlook. Both the ongoing and planned refinery projects in Egypt

come at a time when market analyst Business Monitor International (BMI) has predicted growth in both upstream and downstream investments in the country’s hydrocarbon sector, particularly in the petrochemical industry. However, delays in bringing the announced projects online are highly probable due to problems in tapping natural gas resources. “Gas shortages are plaguing the petrochemicals and chemical fertilizer sectors,” ac-

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cording to BMI’s Egypt Petrochemicals Report Q1 2015. London-based analysts estimate Egypt’s present ethylene demand at 500 Mtpy. This volume is needed to sustain downstream production, despite the previous year’s output falling below production targets. Egyptian Ethylene and Derivatives Co. (Ethydco) is likely to commission its olefins facility this year with the capacity to produce 400 Mtpy of ethylene when a consortium of Japan’s Toyo Engineering Corp. and Egypt’s Engineering for the Petroleum and Process Industries (Enppi) completes construction of a polyethylene (PE) plant in Alexandria. More petrochemical capacity is also anticipated in 2019. For example, Carbon Holdings has commissioned its $6.8B petrochemical plant at Ain Sokhna. Developers believe this facility will yield 1.35 MMtpy of PE as supported by the 900-Mty olefins cracker. Continent leader. Egypt is the largest

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non-OPEC producer in Africa and the largest oil consumer on the continent. This nation accounts for 20% of the continent’s total refined product consumption. Likewise, Egypt has been grappling with oil and gas subsidies that hit an alltime high of $26 B in 2012. The government of President Abdel Fattah al-Sisi wants to phase out fossil fuel subsidies by 2019, thus narrowing the state’s budget and encouraging investments in the country’s hydrocarbon sector. The International Monetary Fund (IMF) says that Egypt realizes that the energy sector reforms and increased investments are critical to reducing energy supply bottlenecks, raising potential growth and increasing exports. However, despite growing interest in private investment in oil, the IMF says that the willingness of investors to commit resources may be reduced by recent falls in oil prices. SHEM OIRERE has reported widely on the business beat for Kenyan newspapers The Daily Nation, Kenya Times and The People. He also freelances, reporting extensively on Africa’s energy, construction and chemical industries for various international publications. He graduated from journalism school in London.

Petrochemicals

SHEENA MARTIN Contributing Editor

Higher international sales boost 2015 earnings above forecast for many chemical leaders Raw materials costs continue to stay low in the US thanks to the shale boom, but the global decline in oil markets has eroded selling prices for many of the nation’s domestic chemicals and plastics producers. As it turns out, a high raw volume of sales to Asia and Europe has been the saving grace for chemical companies in 2015, as the cost advantages from US-sourced ethane and propane remain strong. Thus far, 2015 earnings reports for most of the industry have come in ahead of analyst expectations, with many leaders pointing to rising international volumes offsetting weaker prices. “The oil market is projected to be more favorable behind growing global demand,” Dow Chemical CEO Andrew Liveris said during his company’s earnings call, although he warned of economic uncertainty later in the year. Asian sales rise. During the first quarter, Dow noted that

chemicals demand rose internationally, with a 5% boost in emerging markets. Additionally, Dow said demand jumped an encouraging 10% in its “greater China” business, buoyed by a longer-than-normal Chinese New Year. Heavy restocking from the end of March and through May was another encouraging factor. Elsewhere, Huntsman and LyondellBasell also say they are benefiting from Asian markets, with CEO Peter Huntsman noting there seems to be a “general softening of market conditions” across the board. At the moment, China’s supply and demand balances appear tight due to a number of plant outages early in the year. Moreover, even more outages were seen in the second quarter, said LyondellBasell CEO Bob Patel. Patel said these factors “should be positive for product sales in Asia,” and should further tighten the global supply-demand balance for products, such as polyethylene (PE). US holds cost advantage over Europe. The biggest lingering price advantage for the US petrochemical industry is relative to Europe. As producers harvest shale basins, the ongoing focus on “wet gas” provides a far cheaper alternative to oilbased naphtha, which European petrochemical makers rely on to make plastics. US petrochemicals, on the other hand, utilize cheaper natural gas liquids (NGL). LyondellBasell, which has operations extending outside of the US, “produced almost 50% of our ethylene from raw materials with the cost advantage to naphtha,” Patel said. Huntsman also caters to Europe, the company’s largest market, with higher sales in the continent offsetting lower-thanaverage selling prices in all regions.

However, the currency exchange involved in increased sales abroad negatively impacted revenues, with Dow and Huntsman attributing part of their decline in first-quarter net sales to this effect. Meanwhile, Germany-based BASF saw earnings rise, being on the favorable end of the currency dynamics. Looking beyond 2015. The major chemical companies,

however, all claimed to be aligning their portfolios for longterm growth and not just for 2015. The volatility of the marketplace, as evidenced by the recent crash in oil prices, made this a strategy of necessity. This strategy consists of a flexible portfolio—allowing for changes in emphasis of market segments based on profits—and innovation, while maintaining work on strategic projects. To that end, Dow said it continued to improve on its diverse portfolio during the first quarter with its plan to spin off a major portion of its chlor-alkali and downstream derivatives business. “The transaction will enable us to continue our drive to grow in our higher-value markets as we continue to go narrower and deeper with our portfolio,” said Dow’s chief financial officer, Howard Ungerleider. BASF, Dow and Huntsman all spoke of research, efforts to innovate and ongoing projects during their quarterly calls to show the oil price environment is not slowing their momentum. “We will continue to research and develop, as the challenges stemming from an increasing population are far from being resolved,” said BASF chief executive Kurt Bock. “This is especially true for energy. We are looking for entirely new materials to help make Germany’s energy transition successful.” BASF is researching battery materials for electric cars to reduce the price, along with plastic components for the cars to reduce their weight. Meanwhile, Dow is working on a cogeneration project in Brazil to supply power from eucalyptus biomass to the company’s largest plant in the country. Also, in late April, Dow signed a deal to provide wind-generated electricity to operate its Freeport plant in Texas—the largest integrated chemical complex in the West. Those projects, of course, are all long-term endeavors— and that may not satisfy some investors who are seeking quicker returns. But the uptick in international volumes has kept current industry profits ahead of expectations, and that’s enough to keep project momentum flowing as we head into the second half of the year. “It’s a volume and margin story,” said Liveris. “Whether it’s plastics or our mix, we’re maximizing margins and minimizing the effect of the volatility on our inputs.” Hydrocarbon Processing | JULY 201525

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Engineering Case Histories

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

Case 85: Learnings on hydraulically fitted hubs This article is a brief tutorial on hydraulically fitted hubs. It is intended to alert the reader to major safety concerns when removing hydraulically fitted hubs. What is the purpose of a hub? Hubs connect one piece

of machinery to another, usually with some flexible coupling between them. On straight-end shafts, hubs may be installed by press fits or heating. On taper-end shafts, the hubs may be heated and then advanced for a desired interference fit. One problem is that the installers have only limited time to work with the hot hub. When incorrectly positioned, it may have to be removed. This has the potential of damaging the shaft end. Why are hydraulically fitted hubs used? A method with many advantages is to expand (dilate) the hub bore hydraulically and to advance it a known amount up the taper. When the pressure is released, the hub is frictionally clamped onto the shaft with the correct interference fit and torque holding capacity. Keyless hydraulic fits are preferred for several reasons and include: • Greater torque transmission because the key (a stress riser) is eliminated • Minimal shaft gouging during removal • No heating equipment needed for assembly and removal • Shorter installation and removal time. Likewise, there are some disadvantages that are manageable: • Installation and removal of the hub can be hazardous • Correct design and pull-up of the hub is critical • Slippage is possible when sudden acceleration changes occur. Industries using high-hp equipment such as steam turbines, large motor drivers or high-torque gear units prefer hydraulically fitted hubs. FIG. 1 is a simplified drawing of how these hubs are installed and removed. Installation. The hydraulically fitted hubs are installed by dilating the hub with high hydraulic pressure. As the bore expands (dilates), the hub is advanced up the taper with the low hydraulic pressure fixture. Releasing the pressures produces a friction interference fit, which clamps the hub and shaft together. The low-pressure pull-up fixture is removed, and the safety nut is put in place. In special designs, O-rings are not needed. This removes the stress concentration caused by the O-rings grooves, and it allows for a higher torque capacity. What are the major safety concerns? As shown in FIG. 1, the pop-off or hub is removed. When there is distance between the machines, it is possible for someone to be standing directly in line with the hub as it is being removed. During this author’s career, he has witnessed a hydraulic hub removal without a safe-

FIG. 1. Keyless hydraulically fitted hub.

ty nut. With a loud “bang,” the hub traveled several feet, with some very unfortunate consequences. To prevent a recurrence, an analysis was performed to show the energy stored in the hub when released. This was illustrated by determining how fast and far the hub would travel. Also, the analysis indicated that, in one case, a typical hub could pop off at a velocity of 25 mph and travel a distance of 20 ft or more. What is the lesson learned? The calculation was approxi-

mate, but it does show that taper-fitted hubs when removed should be treated as one would handle a loaded gun—stay out of the line of fire. Even the threads on a safety nut can strip off with the “pop-off ” impact. Also shown in FIG. 1, a lead washer is used during removal. This washer reduces the impact of the hub with the nut when it first “pops” by deforming and absorbing some of the energy. All of the manufacturer’s safety precautions must be followed in addition to securing the area in the potential flight path of the hub. NOTE Case 84 was published in HP in May. For past cases, please visit HydrocarbonProcessing.com. TONY SOFRONAS, D. Eng, P.E., was worldwide lead mechanical engineer for ExxonMobil Chemicals before retiring. He now owns Engineered Products, which provides consulting and engineering seminars on machinery and pressure vessels. Dr. Sofronas has authored two engineering books and numerous technical articles on analytical methods.

Hydrocarbon Processing | JULY 201527

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–Speed Kills, Klaver, Ali. 2012 Project Manager Magazine.

40 percent of projects in the oil and gas industry are subject to budget and schedule overruns. –Capital Project Execution in the Oil and Gas Industry. M. McKenna, H. Wilczynski, D. VanderSchee. 2006 Booz Allen Hamilton survey from 2006 of 20 companies (super-majors, independents and EPC firms).

20%

30

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39%

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67 TO

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CHARLES T. DREVNA Distinguished Senior Fellow, Institue for Energy Research, and Former President, American Fuel & Petrochemical Manufacturers

Advice for the downstream: Keep the faith

CHARLES T. DREVNA is a distinguished senior fellow of the Institue for Energy Research and the former president of the American Fuel & Petrochemical Manufacturers. He was president of the trade association, formerly known as the National Petrochemical & Refiners Association, from 2007 until this May. He joined the association in 2002 as executive vice president and director of policy and planning. At AFPM, Mr. Drevna led a staff that advocates for petroleum refiners and petrochemical manufacturers before Congress and the Executive Branch on a broad range of public policy issues. AFPM emphasizes the importance of petroleum refiners and petrochemical manufacturers to America’s economic growth and national security. Mr. Drevna has extensive experience in legislative, regulatory, public policy and marketplace issues involving energy and the environment. His previous positions include director of state and federal government relations for Tosco, Inc.; director of government and regulatory affairs for the Oxygenated Fuels Association; vice president at the Washington, DC consulting firm of Jefferson Waterman International; several positions at Sunoco, including vice president for public affairs for Sun Coal Co.; director of environmental affairs for the National Coal Association; and supervisor of environmental quality control for the Consolidation Coal Co. Mr. Drevna received his BA degree in chemistry from Washington and Jefferson College and performed graduate work at Carnegie-Mellon University. He grew up in Pittsburgh, Pennsylvania and worked as a laborer in a steel mill there during summers while attending college.

People who know me well know that I enjoy listening to music. If you attended American Fuel & Petrochemical Manufacturers’ (AFPM’s) 2015 Annual Meeting, you’ll recall that I worked this love of music into my remarks. I asked attendees to “Don’t Stop Believin’” while subjecting them to a few moments of the old Journey hit. This sentiment is important for everyone in this industry to consider because, despite the many benefits and technological advancements made possible by oil and natural gas, the industry is often viewed negatively. Every one of us associated with the industry must firmly believe and remember that what we do is important and that we have a long and beneficial future. Working in the refining and petrochemical industries for so many years, I am too familiar with the fact that there are many detractors intent on seeing the demise of the use of the hydrocarbon molecule. Back in 2006, at an earlier AFPM (then the National Petrochemical & Refiners Association) annual meeting, I was quoted as saying, “This industry knows that Camelot is not just around the corner.” Later in the same address I stated, “The demise of the hydrocarbon molecule has been greatly exaggerated.” Although I was wrong about one thing (Camelot was around the corner, not in the form of renewable fuels, but in the way of booming shale production), I was right about the other. The hydrocarbon molecule is here to stay. In 2006, no one imagined that the US would become one of the world’s largest producers of oil and natural gas. Or that this nation, once dependent on others for energy, would begin to produce more oil than we import and that we would become a net exporter of finished petroleum goods. But, instead of valuing our abundant, efficient, easily accessible and affordable

energy resources, many view fossil fuels as having reached the pinnacle. They feel traditional forms of energy are in a steady decline, inevitably to be replaced by so-called “alternatives.” This doomsday rhetoric is factually inaccurate and it places our economy and, ultimately, our national security in jeopardy. Sadly, this attitude comes not just from the detractors, but also from some in our own industry. This attitude is not justifiable, and it is also foolish. The list of benefits we bring to consumers every day is long, from affordable energy to good-paying careers to countless products that are made from oil and natural gas, including plastics, fabrics and medicine. What’s not to be proud of? We have an opportunity and a duty to promote our industry, not just for our sake, but for the overall well-being of the American economy and consumer, and many around the world. Fossil fuels have raised, and will continue raising, the standard of living for billions of people worldwide. It is coal, oil and natural gas that will continue to lift developing countries out of poverty, provide them with affordable sources of energy and secure the power to bring them essential services. My final days as the head of AFPM took place in May at the annual meeting, and one last sentiment I wanted to get across then, again in musical refrain, is that all of you are “Simply the Best,” as Tina Turner expressed through this great song. I am proud to have spent nearly 45 years of my life promoting fossil fuels and happy that I can continue to do so. We have been the driver of the economy of the past, we are the driver of the economy of the present, and we will certainly be the driver of the economy of the future. We should no longer be satisfied to merely defend our industry. Rather, we should be promoting it at every opportunity we get, because we are simply the best. Hydrocarbon Processing | JULY 201529

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| Special Report REFINERY OF THE FUTURE How will oil refineries operate in the future? Which refined products will be in high demand in 20 years? What licensed process technologies will be used by existing and new refineries? These are just a few of the questions now under debate. To remain profitable, refiners must have the flexibility to adapt as the global HPI reacts to changing market conditions and numerous outside forces. New transportation fuels must be developed to power late-model vehicles and energy-efficient engines. The products and services from future refining operations will be vastly different from those provided now. This month's special report provides insight into the new technologies and trends shaping the international refining industry. Photo courtesy of Raffinerie Heide.

Special Report

Refinery of the Future C. BOLOHAN and L. MANAFU, Rompetrol Rafinare S.A., Navodari, Romania; J. D. WARD, Bechtel Hydrocarbon Technology Solutions, Inc., Houston, Texas

European refiner revamps delayed coker to meet Euro 5 specifications In this case history, the European refiner Rompetrol Rafinare SA upgraded its Petromidia refinery in Navodari, Romania. The project included revamping the delayed coker unit (DCU) to address existing operating problems.1 Rompetrol’s coker experienced excessive daily air emissions, contaminated water disposal issues and safety concerns related to the coke drum top head area. Problems were largely caused by the existing open blowdown system, manual coke drum isolation valves and ineffective control/safety interlock systems. A new closed blowdown system (CBS) was installed and the coke drum isolation valves were replaced with modern, motoroperated valves (MOVs) that were part of an interlocked safety system (FIG. 1). Likewise, the refinery staff developed new operating procedures to meet the demands of the upgraded equipment. These modifications successfully addressed the environmental issues, and demonstrated improved unit safety and efficiency during the acceptance performance test.

BACKGROUND Crude oil refiners are always seeking ways to improve safety and productivity while meeting increasingly stringent environmental regulations. Rompetrol Rafinare, a member of the Rompetrol Group, met this challenge by revamping the Petromidia refinery. The modernization program of the Petromidia Refinery increased processing capacity from 3.5 MMty to 5 MMty of raw materials, with exclusive production of Euro 5 fuels. Initiated in 2006, the program focused on nine major projects, including the construction of five new processing units: mild hydrocracking, hydrogen production, sulfur recovery (SRU), nitrogen production and a new flare. Additionally, four existing process units were modernized (gas desulfurization, conversion of the vacuum distillate desulfurization unit to a diesel desulfurization plant, a catalytic cracking unit and an SRU). Incorporating best available technology (BAT) standards, the Petromidia refinery successfully completed this transition to align all processing units to meet EU environmental requirements. The last project was commissioned in 2013; it involved the revamp of the existing DCU. The DCU capacity was adequate to avoid restricting the refinery throughput. However, it was experiencing significant environmental problems due to the existing open blowdown system. To comply with EU regulations and possibly enhance safety, Rompetrol decided to modernize the DCU.

DELAYED COKING PROCESS DCU is a thermal cracking process used to convert lowvalue petroleum residues, typically from vacuum distillation, into higher-value liquid and gas products and coke. The process leaves behind a concentrated carbon material (solid coke), which may or may not have significant commercial value. Liquid yields can range from 60 wt% to 70 wt%. The DCU process has many advantages over other residuum conversion processes. It is a reliable, low-capital process, with processing flexibility to handle a wide range of feeds. FIG. 2 is a typical flow diagram of a DCU. The purpose of the coker furnace is to heat the DCU feed to initiate coking reactions as rapidly as possible. The coke drums are designed to provide adequate residence time to complete these coking reactions and the volume needed to accumulate the solid coke that is formed. The DCU process is batch-continuous, with a pair of coke drums available for receiving the furnace effluent. One coke drum accumulates coke, while the corresponding offline drum is steamed, quenched, drained, decoked, preheated and prepared for return to service. Each coke drum goes through a complete cycle, which includes both coking and decoking operations. The offline coke drum decoking steps are supported by the CBS. New blowdown systems are closed systems to:

FIG. 1. The new CBS at the Petromidia refinery. Hydrocarbon Processing | JULY 201533

Refinery of the Future • Minimize noise, air and water pollution • Condense and collect steam and hydrocarbon (HC) vapors generated during the steam stripping, water quenching and back-warming steps of the decoking cycles • Condense and collect the steam and heavy HC vapors generated during coker startup and shutdown, as well as during coke drum overpressure upsets. The modern CBS was selected for the revamp of the Rompetrol unit. FIG. 2 shows the sections modified in this project as shaded in blue. The isolation valves around the coke drums were replaced to allow for safer, more efficient offline drum operations. New tie-ins from the CBS to the fractionation section were also done.

PROJECT DEFINITION AND EXECUTION Rompetrol contracted a technology licensor to do the revamp design of the DCU and replace the existing open-blowdown system with a new CBS.1 In addition to the blowdown system, other parts of the unit were upgraded. The manual coke drum isolation valves were replaced with MOVs; top unheading valves were installed; and the steam/air decoking system was automated. Other sections of the unit were targeted for upgrading, but were not implemented at this stage. The project goals were to: • Eliminate the environmental problems • Upgrade the safety of the DCU by installing modern isolation valves and top unheading valves; bottom unheading valves were targeted for a later implementation • Improve safety by installing an interlock system for safe coke drum valve operations • Recover all liquid HCs from the offline coke drum operations for reprocessing within the unit and eliminate regular flaring or venting of gas from the blowdown system • Recover all water from the offline coke drum operations for recycling through an existing sour water stripper (SWS). Fuel gas Unstabilized naphtha Lean sponge oil

C3/C4 Gas recovery plant

Stabilized naphtha Sour water

Rich sponge oil

Sour water

Fractionation and preheat section

Light coker GO Heavy coker GO

Fresh feed

Coke drum vapor

Furnace charge Fuel gas

Light slop oil

Furnace and coke drum section

Offgas Steam from water quench

Coke drum (offline) Backwarm effluent

Velocity steam Quench water

Steam-out steam

Coke product

FIG. 2. Process flow diagram of the DCU.

34JULY 2015 | HydrocarbonProcessing.com

Closed blowdown system

Heavy slop oil

Sour water

DESIGN BASIS The DCU’s design fresh feedrate was 143.8 tph (21,937 bpsd) of a mixture of vacuum residue (VR) and FCC slurry oil (95 wt%/5 wt%). The unit products included offgas to the amine plant, coker naphtha, light coker gasoil (GO), heavy coker GO and specialty coke. In this case, the specialty coke was not anode grade, but sponge coke that was required to meet specific market requirements. To determine the new blowdown system capacity, yields were developed for the design feedstock, and the coke drum capacity and cycle time were confirmed. The blowdown system was also designed to process two additional streams: • An external refinery slop-oil stream with a maximum feedrate of 15 m3/h • An emergency purge-oil stream from the existing coker heater, which had previously been sent to the open blowdown system. The residence time had to be made available in the quench tower for this potential emergency stream. FIG. 3 shows a simplified flow diagram of the new CBS.2 Design features. A revamp is frequently more demanding than a grassroots design. Experience is necessary to avoid pitfalls and find the most cost-efficient path. Such projects require team work from the technology provider and the operating company during the project. CBS. The CBS recovered all offline drum effluents and eliminated flaring. This system recovered all HCs for reprocessing in the unit and water for recycling through a SWS. The CBS was also required to condense and collect the steam and heavy HC vapors generated during coker startups and shutdowns, as well as the external refinery slop oil and heater coil emergency purge. Relief through the CBS. The CBS also served as a relief system for the discharge of the coke drum relief valves. Other systems were considered for the coke drum relief valves, such as following the existing practice of discharging the relief valves to the fractionator. If the relief valves open, this practice can result in a major cleanup of the fractionator bottom section, and it may result in tray damage. A preferable solution is to discharge the coke drum relief valves to the quench tower, where a similar cleanup may be required. However, with simpler and more robust internals, the quench tower should be more readily cleaned and able to avoid damage.1 In addition, the existing flare-header design temperature was low, and cooling of the coke drum relief load was required. Relief through the CBS condenser allowed this consideration to be met. Dual-duty blowdown condenser. The relief load cooling requirement required a disproportionately large blowdown condenser. This became an issue due to space limitations. However, the location of the large blowdown condenser and associated piping was carefully managed during detailed engineering and was fitted into the available plot space. Relief devices in the CBS. Normally, because of the robust nature of coke drums, the set pressure of the coke drum relief valves is high enough so that relief valve settings in the CBS do not pose a backpressure problem. Typically, the coke drum relief valves discharge to the CBS, and the relief valves in this system discharge to the flare. For a revamp situation, the set pressure of the existing coke drum relief valves are frequently lower than

Refinery of the Future that for a grassroots unit, and care must be taken to ensure that there will be no backpressure problems due to the relief valve settings in the CBS. In Rompetrol’s case, the existing coke drum relief valves were set at 5 barg. To satisfy the backpressure requirements on these relief valves and the maximum pressure drop through the CBS during relief, it was decided to use a high-integrity pressure system (HIPS) valve on the settling drum. As long as the HIPS valve is set up appropriately, it will have an equal or higher reliability than a regular relief valve. Gravity-drain blowdown header. A major advantage of the new design is that the condensate drum and pumps used for sending backwarm liquid to the quench tower are not needed. This system is known to be prone to operating difficulties that were simply avoided in this revamp. Instead, a gravity-drain blowdown header was installed so that the coke drums could be drained to the quench tower. To achieve this, the elevations of the coke drums, the new blowdown header and the inlet to the new quench tower had to be carefully evaluated during an onsite review. Gravity-drain backwarm to fractionator. Gravity-draining the backwarm condensate to the existing fractionator was also assessed as feasible, and it was included in the design. Gravitydraining the coke drums to the quench tower and the fractionator is a proven concept.1 Low-cost depressuring of coke drums. In many DCU revamps, an ejector is included in the CBS to depressure the coke drums before venting to atmosphere. A vapor line from the settling drum is typically tied into the flare header. In Rompetrol’s case, the existing flare-gas-recovery compressors were used to reduce the pressure in the CBS and coke drum prior to isolating the coke drum from the CBS and venting to atmosphere. The ejector option was not required. Safety interlock matrix. A safety interlock system was installed for the coke drum isolation valves. This was based on the matrix provided in the licensor design package, and it was expanded during detailed engineering by Rompetrol and the local contractor. The provided matrix is the minimum required to avoid sending HCs to atmosphere, and it is frequently expanded to avoid upsets due to operator error. This is fine as long as the system does not become so complex that it limits operational flexibility. Automation of coke drum structure operations. The level of automation of the coke drum switch and isolation operations was considered. It was recommended that the board operator and structure operator work together to confirm via both DCS screens and local observation that the coke drum operations are conducted safely. The board operator supervises the operation and is in radio contact with the structure operator. This operator acknowledges that required procedures have been met and then authorizes the structure operator to activate the appropriate motor-operated valves from local panels on the switchdeck. The structure operator also manually turns the appropriate small steam-purge valves associated with the major valves and piping. The structure operator performs the actuation of valve movement from local switchdeck panels, and not the board operator. The procedure is done so that proper valve movement can be visually confirmed. The board operator should confirm the new valve position on the DCS screens.

In Rompetrol’s case, not all coke drum isolation valves were automated at this stage (e.g., drain, steam and water valves). The structure operator was still required to manually turn some of the isolation valves and report to the board operator when completed. Water handling. Modifications to the existing water handling system including the fines settling basin and quench water storage tank were proposed. These changes were not required by Rompetrol. Operating guidelines. The licensed package included operating guidelines from which Rompetrol developed its own detailed operating instructions. The addition of the new CBS required a philosophical change in the way some operations were completed. For example, backwarming procedures for coke drum warmup during startup and normal operation were significantly impacted. The coke drum quench procedure was also changed. Instead of overflowing the coke drums at the end of the water quench, they were now filling the drums to about 2 m above the coke bed, pressure draining while adding top water, then venting to atmosphere at less than 0.14 barg. Inspections and startup. Piping modifications were made to accommodate the new MOVs and the tie-ins to the new CBS. Licensor inspection required changes primarily to ensure that the risk of plugging with batch usage was minimized, particularly for the switchdeck piping. Also, coke drum thermal growth issues were identified at the cutting deck that required and received attention. Rompetrol worked extremely efficiently in making some piping changes and adding steam purges prior to commissioning and startup. Rompetrol and the DCU technology licensor worked together during precommissioning and startup, and a smooth startup was achieved on April 30, 2013.1 The performance test, conducted on Oct. 29–31, 2013, comfortably demonstrated that the new CBS could support the targeted fresh feedrate. Unit performance. The main factors affecting CBS perfor-

mance, for a given coke drum size, are the quench time and the backwarm time. During the performance test, the time duration for these operations did not exceed the design time durations. Blowdown condenser

To flare PC

FC

PC To fractionator overhead condenser

Settling drum From coke drums

Blowdown quench tower LC Light slop oil to fractionator or quench tower LC FC FC

Condensed water to SWS

Heavy slop oil to coke drum overhead quench oil

FIG. 3. New CBS.2 Hydrocarbon Processing | JULY 201535

Refinery of the Future As long as the design time durations are not exceeded, and there is no overlap in offline drum operations, the CBS should be capable of supporting higher fresh feedrates to the unit, with an associated lower cycle time. TABLE 1 lists the performance test durations for offline coke drum operations.

sumption is usually more of a concern for the bottom unheading valves. Regardless, the total amount of steam entering the coke drums should be carefully determined. In Rompetrol’s case, the additional steam resulted in a slightly increased coke drum vapor velocity that did not increase fines carryover significantly.

Coke drum capacity. The selection of the type of coke drum

Coke morphology. Shortly after startup, shot coke was pro-

isolation valve (ball or wedge plug) can impact the amount of fines carried over from the coke drums. With the installation of steam-purged ball valves, steam-purged unheading valves and additional line steam purges, the amount of steam entering the coke drums can be higher than in previous operations. This impact can be much higher if the unheading valve steam purge increases over time due to seal wear and upsets. The increased steam conTABLE 1. Performance test times for offline drum operations

Steam out

2 hours

Water quench

5 hours 20 minutes

Drain

2 hours (ranged from 1.4 to 2.7 hours)

Unheading and coke cutting 3 hours Standby

2 hours

Reheading and pressure test 1 hour Backwarm to CBS

2 hours (ranged from 1.5 to 2.5 hours)

Backwarm to fractionator

6 hours (ranged from 5 to 7 hours)

Total

23.5 hours (ranged from 22.6 to 24 hours)

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36JULY 2015 | HydrocarbonProcessing.com

duced for several drums and represented a major issue as the coke market required sponge coke. The shot coke produced was formed due to a high percentage of asphaltenes in the feedstock. To suppress the shot coke formation, in addition to adjusting coke drum operating conditions, FCC slurry was introduced into the feedstock so that sponge coke was again produced. Although not part of the initial scope of work, Rompetrol consulted with the DCU licensor on this issue.1 The traditional “rule of thumb” for predicting whether shot or sponge coke will be made is to calculate the mass ratio of CCR to asphaltenes in the feed. If this ratio is less than 2, production of shot coke is likely. This rule is neither accurate nor particularly useful in Rompetrol’s case because asphaltene analysis of the feed was not typically done, and it would take about three days to perform. A more reliable approach to determine the morphology of the produced coke is based on parameters that are readily available for most feedstocks. For unusual or specific feeds, laboratory analysis is performed on the DCU feedstock to confirm the predictions and to account for commercial operation.

Review. The DCU revamp was successfully executed by Rompetrol, and is presently meeting all the project goals. The success of this revamp project was largely due to the effective teamwork between Rompetrol, local contractors and the DCU technology licensor. The cooperative nature of this team allowed the project to be defined and executed efficiently. More importantly, the unit started up safely and performs satisfactorily. NOTES Bechtel Hydrocarbon Technology Solutions (BHTS) purchased ThruPlus technology from ConocoPhillips in 2011. 2 BHTS closed blowdown system. 1

CRISTIAN BOLOHAN is the process director within Rompetrol Rafinare, company member of The Rompetrol Group. He joined the Rompetrol team in 2003. During the development and modernization of the Petromidia refinery, as progect manager, he coordinated and implemented projects. Mr. Bolohan graduated from the Faculty of Physics, Chemistry and Technology of Processing Crude Oil and Petrochemicals within Ovidius University, Constanta, Romania, and he holds an MS degree in oil and gas management. In his present position, he is responsible for the design, coordination and success for the development plan of the Petromidia refinery, in accordance with the Rompetrol Group strategy, as well as the optimization of the refining processes within the business unit. LUMINITA MANAFU has over 30 years of experience in operations and process engineering for the delayed coker, amine and sulfur recovery, flare-gases recovery units with Rompetrol Rafinare S.A. She graduated in petrochemical engineering from the Oil and Gas Institute, located in Ploiesti, Romania. She has been involved in many projects, startup and performance testing at the Petromidia refinery. JOHN D. WARD has over 35 years of experience in process engineering design and operations, particularly in refining and petrochemical operations. He has specialized in the ThruPlus delayed coking technology for more than 15 years, and has been involved in many delayed coker startups and performance tests. As a coking technologist with Bechtel Hydrocarbon Technology Solutions, Inc. (BHTS), he has led the production of process design packages for licensees and provided technology support for business development. Mr. Ward holds a BS degree in chemical engineering from the University of Manchester, Institute of Science and Technology, UK.

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Special Report

Refinery of the Future E. SPIROPOULOS, Yokogawa Corp. of America, Houston, Texas

Use advanced automation and project management to simplify refinery construction Process automation in oil refineries is undergoing major changes, driven by customers frustrated by what they consider to be slow and incremental advances from the main automation original equipment manufacturers (OEMs) in the industry. ExxonMobil has become a de facto industry representative and is driving vendors like Yokogawa and others to reevaluate how large-scale automation projects are implemented. The customer message is clear: projects take too long; they are too engineering-intensive; and the automation systems frequently become the critical path in the final stages, often causing the project to fall behind schedule. In many instances, automation engineers can legitimately point at process engineers and others for last-minute changes, but with little consolation from the owners. With several hundred major automation projects executed globally each year, the industry-leading automation OEMs can draw on several decades of experience working in various industries and with a range of technologies. Individually and collectively, they are applying their knowledge of best automation practices and lessons learned to answer the question, “How can we do things better?” As a result, automation OEMs are being guided by the industries they serve to develop and improve solutions that provide the reliability, operability and safety expected from control system platforms. OEMs are also being asked to improve methodologies for assembling, executing and deploying a complex process solution with improved efficiency, lower installation cost and greater adherence to schedule. Most of the efforts fall into two main categories: project management and

technical improvements. These two categories are deeply intertwined on multiple levels and, as such, can work together to improve projects. Serial to parallel. For the past few decades, projects have followed the same basic path shown in FIG. 1. Each phase takes place in a serial fashion, as each builds on the previous effort: 1. The design phase typically includes development of functional detailed specifications and agreement on project engineering standards, schema and, sometimes, resources. 2. The design phase leads to the main engineering activities, which can be grouped into hardware-related and software-related activities. It is desirable to have as much parallel engineering as possible with these activities, and the conventional model achieves this up to a certain point. Control logic, graphics, alarm

configurations, tuning parameters, etc., can be application-engineered by a software team in a single location or multiple locations. At the same time, controllers, input/ output (I/O) cabinets, marshalling boxes and enclosures can be manufactured, wired and tested by another specialized team. 3. The significant dependence of application engineering on the design hardware is a challenge. An automation application must be configured to fit the very specific controller, I/O module, marshalling, termination and wiring plan for which it is designed. 4. Upon site delivery, the application piece is bound to the hardware loop by loop. Late binding allows enough time in the schedule for project design changes to be implemented in both hardware and software before final binding.

Conventional project execution Project start Definitions, standards, detailed functional specifications

Control logic, graphics, alarms, procedures

Software to hardware binding

Project delivery and startup

Design Application

High application dependency on hardware and field wiring

Hardware Field installation Loop check

HW, cabinets, marshalling, ship to site

HW installation, wiring, device configuration, signal termination

Project risk mitigation

FIG. 1. Traditional project management techniques follow a serial process, with each step following the previous one in sequence. Hydrocarbon Processing | JULY 201539

Refinery of the Future Flexible binding allows for these changes, as well as reconfiguration, at any point in the project.

5. Either after or during loop commissioning, the owner signs off on the automation project, and the

ExxonMobil’s plan for self-configuring field devices T. MADDEN, ExxonMobil Development Co., Houston, Texas Presented at the Yokogawa Users Conference and Exhibition, September 2014

The concept of self-configuration devices can be explained with the term DICED: DETECT: When a new (to the system) HART-enabled device is connected to the configurable I/O, the I/O channel detects that current is flowing where it previously was not. INTERROGATE: The I/O channel transmits the HART command requesting

the device tag. The HART-enabled device responds with its tag. (ExxonMobil requires HART 6 or HART 7 devices with long tags.) If the new device is not a HART-enabled device (a shutoff valve, for example), it will obviously be unable to respond to the HART tag name request. In this case, the DICED process is aborted, but a notification to the user can still be generated informing that there has been a change in the field wiring, and it is likely that a new direct-input or direct-output device has been installed.

CONFIGURE: Once the system has detected and determined that there is a new

HART-enabled device, the system can configure that device with its engineering range, engineering units and other configuration information. ExxonMobil’s plan is to purchase field devices with only the tag preconfigured and then allow the system, which generally contains the latest data, to configure the field devices accordingly.

ENABLE: The field devices are assumed to be configured in the system and associated with a particular control strategy. ExxonMobil’s project execution process assumes that the company will complete most of the engineering, configuration and testing in a virtual environment, but that the company will likely not know exactly to which I/O channel each field device is configured. In this step, the system will know to which I/O channel the new device is connected, and a logical association between the control strategy and the field device can be made. Once this happens, the field device and its associated logic are enabled for use. DOCUMENT: Assuming that all of the above steps are completed successfully, ExxonMobil’s expectation is that the system will report this success in an event log. The company aims to greatly streamline field commissioning activities that today require paper loop folders and many field trips. ExxonMobil also believes that the system can automate some of the testing that is performed by an engineer or operator sitting at the console in radio contact with a field team. For example, if the detected device is a control valve, an analog output can be sent to the valve and its position read back via HART. It can be verified that the valve is working correctly, that it is not sticking, that its failure mode (fail closed or fail open) is correct, and that it positions correctly over its range. It would be desirable to contain all of the circuitry needed to implement DICED in the configurable I/O module. If the software can be implemented to take full advantage of this hardware, then this desire may be realized. Note that DICED requires no changes in the field devices themselves. 40JULY 2015 | HydrocarbonProcessing.com

plant starts up. Depending on the business environment, schedule flexibility in startup may be acceptable, but late is never desired. If events unfold as planned, then the project can stay on schedule, although the schedule might be longer than the company considers desirable. However, most projects do not run exactly as planned because process engineers may realize a vessel is not in an ideal location, the distillation tower is not large enough, or another pump needs to be added at some point to maintain sufficient flow. Any of these process equipment changes will create process automation system changes by moving or adding hardware and related instrumentation. As FIG. 2 shows, such changes can extend the time necessary for one or more project phases, ultimately stretching out the schedule and eventually pushing the project past the startup deadline. The automation system now becomes the critical path item holding up the schedule. Technical aspects of the problem and solution. Compressing the sched-

ule by including more parallel, instead of serial, activities depends on the ability to decouple many elements of the process and mechanical design from the automation system details. To be effective, this requires a method of maintaining overall project management and information for automation software and hardware layers. One reason why traditional automation projects make such decoupling difficult is the highly customized nature of the hardware, particularly I/O and field wiring. These designs cannot be finalized and built until the process and mechanical portions of the plant are completed. A typical example is as follows: A vessel in the process needs a level sensor to ensure that the amount of liquid is beyond a given point. For the sake of simplicity and economy, a level switch is specified with a digital on/off output and an appropriate I/O channel created in the control system to receive the signal. However, the process designer later decides that it is critical to know the actual level, and requests a modification. A level transmitter must now be deployed in place of a level switch alone, so it is necessary to change from a digital signal to a 4-20 mA signal. Such a change might not seem substantial, but, in the real world,

Refinery of the Future it can involve an entire series of steps, from hardware implementation to documentation updates. Multiply this process by a few (or even dozens of) such changes, and construction begins to fall behind schedule. Fortunately, there is a solution to this problem, and it lies with more flexible I/O systems. Configurable I/O cabinets. Several au-

tomation OEMs have developed smart, configurable I/O technology capable of supporting multiple signal types on a perchannel basis, and this development is arguably the most critical for the parallel execution of process/mechanical and automation system design (FIG. 3). Wiring cabinets outfitted with configurable I/O can now be provided as stock items by the manufacturer, tested and made ready to ship from stock or with a short lead time. They are built to withstand process plant environments, allowing them to be mounted in the field to reduce wiring complexity. Marshalling cabinets are eliminated, along with most termination points. The number of wiring terminations from each device to the control system is reduced from 20 or even more, to perhaps five. This kind of smart I/O increases the independence of the automation system from the process/mechanical design since it supports system-independent loop commissioning. When the I/O cabinet is in place and the field devices are installed, the performance of the field device and its interaction with the relevant final control element can usually be verified, even before the control system is installed. When changes come late in the project, such as the shift from a point level sensor to a level transmitter, as mentioned previously, it is a simple matter to reconfigure the connection point in the cabinet. This capability for changing configurations, along with flexible binding of the automation hardware layer to the software layer, support a seamless transition to the final phases of project completion, without gaps in the schedule. This is because much of the hardware loop validation is accomplished during system-independent loop commissioning. Smart communication for smart devices. A common element of the new

configurable I/O systems is their ability to use the latest digital communication

protocols for communication with smart field devices, typically instruments and analyzers. With natively supported communication in place, the diagnostic information from these smart field devices can be gathered and used in a sophisticated asset-management program. One of the interesting aspects of this capability is its bidirectionality. Not only do the smart field devices send information to the control system, but the control system can also send information to the devices. Customers looking at this

capability have asked, “Why can’t the control system do the entire smart field device configuration?” This is a simple question with huge implications. While users appreciate how the capabilities of present-generation smart devices have advanced, the downside is the complexity of configuration. While a pressure sensor 20 years ago might have contained a dozen or so parameters in need of setting, today’s units can have hundreds of parameters, so the configuration process can be quite tedious.

Conventional project execution: impact of design changes Project start Project delivery and startup

Design Application

High application dependency on hardware and field wiring

Hardware Field installation Loop check Late data changes can impact all project pieces and require engineering rework

Project risk mitigation

FIG. 2. Late changes to a project cause delays in each phase. These delays cascade down the schedule, pushing past the deadline.

FIG. 3. Multiple control system hardware suppliers are already shipping or designing configurable I/O cabinets. These cabinets are a key element of new project management techniques. Hydrocarbon Processing | JULY 201541

Refinery of the Future Agile project execution: detail Project start Project delivery and startup

Modular engineering Design

Wiring independent

Application Flexible binding after system-independent loop check Hardware

System independent

Field installation Loop check Smart, configurable I/O modules

System System cabinet parts independent loop order commissioning

Project risk mitigation

FIG. 4. New capabilities allow for a high level of parallel activity, which compresses the overall schedule.

All of the information necessary to configure field devices is contained in databases in the control system, so why should these systems be unable to transfer all of the parameters to the device? The technical capabilities are indeed present, and several automation OEMs are developing the process to make it happen. ExxonMobil has characterized this approach with the acronym DICED, which stands for Detect, Interrogate, Configure, Enable and Document (see sidebar article). Present thinking is that all of these steps should happen automatically. When a technician installs a new field device by placing a device with a specific tag number in a specific location, the process follows of its own accord to accomplish the following: • The control system detects when a new device is in place and wired. • The control system interrogates the device by sending a command requesting its tag. The tag number is the only setting the device requires before installation, and this can be put in by the manufacturer per the customer’s request. • Once the device is identified, the system looks in its database at the configuration parameters and downloads them to the device. These parameters can include range, engineering units, alarms, etc. • Once the system verifies that the configuration and the I/O channel are established, the system then enables the device. • Since this process is automated, the system can create its own 42JULY 2015 | HydrocarbonProcessing.com

documentation, thereby updating all related databases automatically and drastically reducing the need for human intervention. Combining these technologies can have profound positive effects. Putting technical advances to work. When smart I/O, system-independent loop checking and automated device configuration are used together, different functions can overlap to shorten project execution time and reduce required engineering resources (FIG. 4). With this project methodology, there is significant risk reduction as a result of parallel engineering, reduced automation hardware-to-software dependence, flexibility in binding, reusability of engineering modules and best practices. There is an additional decrease in total project installed cost due to the reduction in wiring, marshalling and field terminations. It becomes possible to envision both parts of the automation effort—hardware and software—as independent pieces assembled from reusable modules following their own schedules. More equipment is purchased “off the shelf,” already engineered and tested to relevant standards, and then shipped and assembled in modular fashion, with flexible binding applied at the appropriate time. This approach allows for design changes and the containment of problems related to late data within a particular execution piece, reducing overall project impact. In fact, it becomes possible to construct an entire process unit or skid offsite, with its

associated devices, wiring, piping, equipment, etc., and to mount configurable I/O cabinets as part of the completed unit. Device and I/O loops can be checked and commissioned in staging, independent of the plant’s automation system design specifics. The construction and hardware pieces can be factory accepted, and the entire unit can then be shipped to the site for assembly and connection with the rest of the plant, or adjacent units, all independent of the actual application engineering or system platform at the site. Creating mechanisms capable of supporting parallel activity on this scale is valuable for all of the reasons discussed, but it does not entirely address the human resource requirements needed to exploit the advantages in the face of demographic changes. Process control system OEMs and user companies are increasingly using engineering resources that are scattered around the world, and many of the new developments make that easier; there are growing libraries of modules to avoid the need for writing code from scratch for a single project. Customers and suppliers alike are looking for ways to use intellectual property repeatedly, reducing time and cost. Changing to new I/O platforms with self-configuring field devices reduces the time a technician must manually key in parameter values. Nonetheless, many aspects of a project are still labor intensive, although where, when and by whom specific functions are performed are becoming more fluid. If a greater number of tasks can be carried out simultaneously earlier in the project, then more people will be needed for a shorter period of time. Users will need to utilize combinations of resources—internal engineering staff, construction companies, automation system integrators and automation supplier(s)—in new and flexible combinations, as needed, to realize the biggest benefit. New technologies and work practices are making these engineering approaches possible and more practical. They can provide great benefits to EPC companies and technology licensors, who can protect their own technology and execute projects using methodologies to provide the most value. Automation OEMs are creating these advances now. Some are already available, but it is certain that many more will be available in the near future.

Special Report

Refinery of the Future J. ESTEBAN, Criterion Catalysts and Technologies; and M. HARTMAN, Marathon Petroleum Co.

Turning a Tier 3 profit In the highly competitive refining market, profitability is not a benefit of successful business, but rather a necessity for sustainable business. Profitable solutions and technologies are inherent to a refiner’s success, providing the driving force to transition from survival in tough markets to thriving sustainable development. The hydrocarbon processing industry (HPI) faces threats on many fronts that challenge profit margins and business development. Growth in challenging crude oil and products markets requires the careful application of best practices for asset utilization and strong technical solutions to adapt to changing constraints. Environmental regulations have made it increasingly challenging for refiners to adapt profitable solutions while maintaining feedstock and product flexibility. Notably, the continued reduction in refined product sulfur (S) specifications has revolutionized the industry’s landscape over the last decade, increasing the importance of hydrotreating solutions within refinery complexes. This will continue as the industry moves toward the future Tier 3 regulations where the production of less than 10 ppm of ultra-low-S gasoline (ULSG) will be required in 2017. Several refiners have already implemented technologies and strategies with profitable and flexible solutions to meet Tier 3 blend stock requirements. This is a testament to the industry’s commitment to enriching the environment and communities to which it provides energy solutions. Tier 3 strategies. Many of the blend components of typical gasoline product streams are very low in S, so achieving Tier 3 specifications for most refiners requires focus on a limited number of blend components in the gasoline pool. Generally, these blend components are untreated light straight-run gasoline, straight-run naphtha, natural gasoline, purchased blend stocks and fluid catalytic cracking unit (FCCU) gasoline. Most of these components are small portions of the overall pool, and they often fit into a simple model for S reduction consisting of inclusion in existing treating facilities, additional conventional treating or exclusion from the blend pool. The primary target stream for S reduction is FCC gasoline, usually the largest blend component and the highest S contributor to the blend. In many applications, a target of 20–30 ppm of S in FCC gasoline is required to meet the less than 10 ppm specification in the blended gasoline product streams. FCC gasoline is also a large contributor of octane barrels to the gasoline pool, and retention of superior blend properties is highly important when considering options for stream S reduction. The challenge is providing profitable solutions for a

superior blend component low in S that does not result in the hydrogenation of valuable olefins found in FCC gasoline. Reduction of FCC gasoline S is achieved today using multiple approaches: the pretreatment of FCC feed streams, the post-treatment of FCC gasoline or a combination of the two. The post-treatment of FCC gasoline, unlike conventional hydrotreating, targets the selective removal of S from the feed stream while limiting hydrogenation of the feed to minimize the reduction of valuable olefins in the stream. These olefins contribute to the higher octane of FCC gasoline and are inherently essential to the overall value of the stream as a blend component. Established processes for post-treatment have demonstrated successful production of Tier 2 blend components without significant losses of octane. However, there remains some degradation in product value for this method of S reduction. Further S reductions using typical post-treatment methods to achieve Tier 3 levels require increases in operating severity, which can result in additional octane loss, creating a significant economic penalty. Alternatively, the pretreatment of FCC feed streams removes heteroatoms, including S and nitrogen (N2 ), resulting in favorable reductions in product S contents for all FCC products. In addition, pretreatment also removes metals and aromatics from the feed streams, reducing FCC catalyst poison effects and improving feed crackability, respectively. Achieving additional reductions from existing pretreatment facilities requires higher-severity operation, which can result in reduced catalyst life cycles. Recent developments for both processes have provided favorable results for the application of potential drop in existing facilities. Benefits of FCC pretreat strategy. Synergies between an FCC pretreat unit and an FCCU may start with, but may not be limited to, reduced S in products. Pretreatment of FCC feed provides significant upgrades in feed quality for an FCCU, resulting in improved yields and beneficial distribution of heteroatoms in the product streams. The hydrogenation of FCC feed streams is necessary for deep desulfurization, especially when operating at higher S conversion targets for Tier 3 FCC gasoline production. This hydrogenation of feed results in the removal of metals and N2 , which are poisons to FCC catalysts, as well as the saturation of aromatics, improving the conversion potential of feed streams. More highly hydrogenated feed streams achieve higher conversion in an FCCU, given constant operating conditions. It is important to note that conversion in any FCCU is a choice, meaning that the desired product slate is flexible withHydrocarbon Processing | JULY 201543

Refinery of the Future in heat balance constraints with the adjustment of operating parameters. Since an FCCU must remain in heat balance, the introduction of upgraded feed streams results in lower coke production and higher catalyst-to-oil ratios. The unit responds by increasing the circulation of catalyst from the regenerator to the riser to generate similar coke make and remain in heat balance. The increased catalyst:oil ratio provides a boost in conversion of feed to saleable liquid products. Typically, dayto-day changes in FCC conversion are made by controlled adjustments in the riser top or reactor temperature. These changes influence the operation of the regenerator slide valve controlling the contact of hot catalyst with feed injected at the bottom of the riser. However, feed preheating is also used to influence conversion by pre-atomization of feed prior to entering the mixing zone of the riser. Feed preheat also impacts the catalyst:oil ratio by playing a role in the amount of hot catalyst required to achieve the target riser top temperature. A higher degree of feed preheat results in a reduced need for hot catalyst from the regenerator, thus a reduction in conversion by indirect effect on the catalyst:oil ratio. The recycling of products such as heavy cycle oil and slurry oil increases coke deposition on catalyst, resulting in conversion control, regenerator heat balancing and black oil minimization. Beyond day-to-day operating parameter control, the very nature of a circulating fluidized bed allows for the adjustment of catalyst formulations and custom control on catalytic activity throughout the operating cycle. It is this dynamic nature that plays well into the synergies of FCC pretreat and operation, yielding market trending control for profit maximization. The addition of hydrogen (H2 ) to FCC feed results in an increase in feed API gravity due to aromatic saturation and removal of heteroatoms, leading to an increase in total liquid volume yield. This increase in feed gravity is associated with a shift in feed boiling range, since the boiling point of the saturated aromatic structures is lower. FIG. 1 shows this effect. Aromatic rings do not crack in the FCCU, but saturated molecules do, creating improved feed crackability. The saturation of rings in polynuclear aromatics increases the available molecules for conversion in the FCCU. The removal of N2 from FCC feed streams reduces the inhibition of cracking mechanisms critical to both FCC performance and the distribution of the remaining heteroatoms in FCC product streams. Targeting low FCC feed N2 levels results in a more favorable S distribution in FCC product streams with lower FCC gasoline BP 176°F BP 424°F

BP 178°F BP 403°F

BP 644°F

BP 554°F

BP 644°F

BP 554°F

FIG. 1. The increase in feed gravity is associated with a shift in feed boiling range.

44JULY 2015 | HydrocarbonProcessing.com

S levels. This indicates that FCC pretreat hydrodenitrification (HDN) and hydrodearomatization (HDA) performance, not solely hydrodesulfurization (HDS), are critical influencing factors in the production of Tier 3-quality FCC gasoline. When treating FCC feed streams, the saturation of polynuclear aromatic species can be used to influence the distribution of aromatics in FCC product streams. The FCCU will remove functional groups from aromatic rings while leaving the rings intact. Because the boiling range of single-ring aromatics falls in the same range as gasoline, reducing polynuclear aromatics to single unsaturated aromatic species increases the production of FCC gasoline, given the same operating conditions. Di- and tri-aromatic species have boiling points that fall in the typical light crude oil (LCO) range, resulting in conversion to LCO after functional groups and saturated species are removed. Thus, the saturation of heavy polynuclear aromatic species provides an increase in feed conversion to products in the FCCU, including gasoline and LCO. Inherently, this relates to the profitability achieved from feed treating, but the removal of aromatics is also essential in deep desulfurization and denitrification of feed streams. As higher conversion levels of S and N2 are required in hydrotreating, the remaining molecules containing S and N2 become increasingly more difficult to treat due to the molecular structure associated with aromatic species. To remove these heteroatoms, hydrogenation of the molecular structure is required to expose the occluded heteroatoms. The influence of feed N2 in the FCCU is key to understanding the synergy between FCC pretreat operation and FCC response. N2 inhibits the catalytic function in an FCCU and reduces catalytic cracking reactions, including secondary cracking mechanisms. In turn, this reduces the conversion of feed to products in the FCCU, as well as the distribution of heteroatoms in FCC product streams. Because Tier 3 regulations are very stringent with respect to gasoline S, the focus of heteroatom distribution is heavily weighted toward S in FCC gasoline. When secondary cracking mechanisms are inhibited by higher feed N2 values, there is an increase in S found in the gasoline fraction. However, reducing feed N2 increases the conversion of organic S molecules to H2S and liquid products. This relationship between feed S and N2 implies that when feed streams are treated to reduce N2 , the feed S can be increased while sustaining Tier 3-quality FCC gasoline production.

CASE STUDIES The following studies explore the strategies of two separate refiners in employing latest-generation FCC pretreat catalyst technology to maximize profitability. The three main areas of profit generation when considering high-severity FCC feed pretreatment are hydrotreater volume gain, FCC conversion enhancement and, relevant to current trending markets, ultralow-S diesel (ULSD) maximization. Marathon Petroleum Co. (MPC), Catlettsburg. MPC

operates the Catlettsburg refinery in Catlettsburg, Kentucky. The strategy for Tier 3 fuels production at the refinery is higher-severity FCC feed pretreatment to reduce FCC gasoline S for a combined gasoline pool blend below the required 10 ppm. The refinery recently replaced and upgraded the catalyst in one of its two FCC pretreat units, and it operates two

Refinery of the Future

Total aromatics removal, %

FCC pretreat units, a low-pressure vacuum gasoil (LPVGO) and a high-pressure vacuum gasoil (HPVGO), to hydrotreat 100% of the feed streams for the 100-Mbpd FCCU. The two FCC pretreat units are operated in concert to reduce feed S levels. The LPVGO operates at low pressure and is used to treat the “easy” feed streams sourced from the crude units, including atmospheric gasoils and light vacuum gasoils. Processing roughly 40% of the FCC feed, this unit operates at lower conversion targets with a regenerated catalyst system. The HPVGO operates at higher pressure and severity to treat the more difficult feed streams, including heavy vacuum gasoils and deasphalted oils. This unit processes roughly 60% of the FCC feed and is loaded with FIG. 2. MPC’s HPVGO operating strategy for its Catlettsburg refinery. a new generation catalyst. With nearly a year of the anticipated four-year cycle completed, the unit has ppH2 determines Plateau Constant ppH2 provided stellar performance with respect to both hydrotreater equilibrium limitation operation, as well as positive benefits for the FCCU. While MPC is not required to produce ULSG today, the Crossover point Equilibrium team at Catlettsburg has been operating the HPVGO at higher ASAT less temperatures and S conversion to maximize unit profitability. favorable Dehydrogenation The team is keen to recognize the value inherent to aromatics more favorable Decreasing LHSV saturation of FCC feed streams and the conversion of excess H2 Coking more favorable/rapid available to saleable liquid products. The refinery generates a large volume of H2 from the proEquilibrium duction of reformate gasoline and a dedicated H2 plant. This H2 control R + XH2 R is used by the various hydrotreaters in the refinery and is subsequently converted back into liquid products by the hydrogeIncreasing reactor temperature nation of hydrotreater feed streams. The HPVGO feed stream FIG. 3. Aromatic saturation as a function of temperature and the has excellent potential for upgrade by hydrogenation. The influence of H2 partial pressure. operation at elevated temperatures increases the saturation of aromatics because the HDA reaction is kinetically driven up to an equilibrium constraint. Operation at elevated temperatures result in reduced light olefin selectivity and gasoline olefinicity, also further reduces FCC feed S and N2 . Operating in this manwhich relates directly to product octane due to a shift in riser hydrocarbon partial pressure. Increasing feed can also result in ner requires the careful attention of refinery engineering and lower conversion due to residence time effects. However, the operations staff to evaluate and maximize unit performance. upgraded feed quality from feed pretreatment has allowed the The graphics in FIG. 2 depict the constant weighted averincrease in feed rate, along with a reduction in riser top temperage bed temperature (WABT) of the HPVGO and associated ature with slightly elevated conversion and steady light olefins product S and N2 levels. The unit is operated to target equal yield. The FCC gasoline S is extremely low, highlighting the bed outlet temperatures at the lowest point required to achieve benefits of HDN and HDA. the peak aromatic saturation, a function of temperature and H2 The FCC gasoline stream is not only very low in S, but also partial pressure. The highest operationally feasible H2 partial retains superior blending qualities, including high octane even pressure is maintained while also minimizing reactor bed outat lower riser top temperatures. Reducing riser top temperalet temperatures within the peak window of aromatic saturature in the FCCU reduces conversion of feed to gasoline and tion to minimize deactivation of the catalyst system. FIG. 3 dislighter products, but it can also reduce the quality of the FCC plays aromatic saturation as a function of temperature and the gasoline. The retention of gasoline octane at lower riser top influence of H2 partial pressure. temperatures is a function of the increased feed crackability. The subsequent value provided the FCCU by operation of The retention of overall olefin selectivity further illustrates the the HPVGO in aromatics saturation mode are shown in the high potential value from feed pretreatment associated with performance plots in FIG. 4. The FCC feed rate has been inpremium products such as alkylate and propylene. creased significantly following the change in catalyst system FCCUs produce a large amount of low-value light gases in the HPVGO. Given constant feed properties and operating that are typically directed to fuel gas (FIG. 5). These light gases conditions, increasing feed rate in an FCCU would typically Hydrocarbon Processing | JULY 201545

Refinery of the Future (referred to as dry gases) are produced from over-cracking reactions, which are enhanced by thermal cracking mechanisms. As regenerator temperatures increase, there is a higher ratio of thermal:catalytic cracking at the base of the riser. The increased feed H2 :hydrocarbon (HC) ratio for heavily hydrotreated feeds influences the coke deposition rate on the catalyst, resulting in lower regenerator operating temperatures at a given conversion target. This, in turn, reduces the production of dry gases. This is illustrated by the significant reduction in dry gas yield following an upgrade in the catalyst system and the operation of the HPVGO in aromatics saturation mode. While the overall coke make remains similar to retain heat balance in the FCCU and maintain similar conversion, the rate of coke deposited per pound of circulating catalyst is reduced, leading to an increase in catalyst circulation rate and a reduction in regenerator temperatures (FIG. 6).

Despite the potential advantages in gasoline production from increased severity hydrotreating in the HPVGO, MPC continues to operate the FCCU at similar conversion targets primarily to capture margins in the distillate market. This flexibility allows MPC to capture margins in a gasoline or diesel economy while continuing to make high-quality gasoline streams. The maximization of distillate from an FCCU can be accomplished via several routes: • Fractionation adjustments to reduce gasoline endpoint and maximize LCO endpoint • Lowering conversion by decreasing the reactor temperature and catalyst activity, or increasing feed preheat temperature • Catalyst optimization with respect to zeolite:matrix ratios

FIG. 4. The performance plots depict changes from previous typical values for key FCC performance indicators as a function of time in relation to days on stream (DOS) for the HPVGO.

46JULY 2015 | HydrocarbonProcessing.com

Refinery of the Future • Feedstock optimization, including the removal of diesel range material from feedstocks (general refinery distillate maximization), the optimization of feed pretreatment assets and the optimization of recycle streams. For the Catlettsburg refinery, distillate maximization begins with optimization of crude fractions and is further extended to bottoms conversion. The conversion of FCC feed is adjusted to target balanced yields of both gasoline and LCO. The LCO produced from an FCCU must be further processed to meet ULSD specifications, but it remains a valuable product. Extending this flexibility further, accomplishing equal

conversion at lower riser temperatures can allow for increased product recycle capability. The recycling of products, especially heavy cycle oil, can be employed to increase LCO production in an FCC and bottoms conversion, resulting in black oil minimization. Note the observed slight reduction in slurry and the retention of LCO yields following the change out in the HPVGO catalyst system (FIG. 7). A summary of the average benefits observed from operation of the HPVGO at higher severity for maximum aromatics saturation, as well as the production of Tier 3-quality FCC gasoline, is offered in TABLES 1 and 2.

FIG. 5. FCC light ends production.

FIG. 6. FCC dry gas and coke Δ yield.

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Hydrocarbon Processing | JULY 201547

Refinery of the Future TABLE 1. Average benefits at higher severity FCCPT, HPVGO

Typical

Tier 3 mode

Operating mode

HDS

Arosat

TLP volume gain, lv% of feed

Base

+1.25

Product S, ppmw

1,000

300

Product N2, ppmw

500

100

API gain, °

Base

+1.2

Diesel make, lv% of feed

Base

+2.1

TABLE 2. Tier 3-quality gasoline production FCC

Typical

Tier 3 mode

Combined feed S, ppmw

1,200

570

Combined feed N2, ppmw

360

160

Combined feed API, °

Base

+0.7

Riser top, °F

Base

–20

Conversion, %

Base

+0.5

46

10

Gasoline octane, R+M/2

Base

Base

Dry gas, wt% of feed

Base

–0.51

TLP volume gain, lv% of feed

Base

+1.75

Gasoline, lv% of feed

Base

+2.34

LCO, lv% of feed

Base

+0.18

Slurry make, lv% of feed

Base

–0.35

Gasoline S, ppmw

US refiner. Another refiner operating a medium-high pres-

sure FCC pretreat unit has employed an alternative strategy to capitalize on the value of high-severity feed pretreatment. The unit has been operating at high severity for quite some time with an alternative objective of the production of Tier 3-quality FCC gasoline. While the FCC downstream produces verylow-S gasoline, the unit is primarily operated at high severity to produce a ULSD stream from the fractionation column workup section. The unit was originally envisioned to solely treat gasoil streams for processing in the downstream FCCU. However, the refinery has leveraged the unit’s excess capacity and performance capability to increase overall distillate production refinery-wide. This has enabled a significant increase in overall ULSD production and an improvement in crude oil capacity. The unit has been operating at higher severity with latestgeneration catalysts to maximize overall refining yields. Not only does the unit produce a large volume of ULSD, but it also provides severely hydrotreated feed for the FCCU, which is significantly upgraded with very low N2 and S, as well as a significant degree of aromatic saturation. As such, the gasoline produced from the unit is very low in S and suitable in blends to meet Tier 3 specifications. Similar to MPC, this refiner capitalizes on the advantages afforded from the significant feed upgrade for the FCCU. The unit is operated at very low riser top temperatures in the 930°F–945°F range, achieving high levels of conversion. The US refiner also recycles heavy cycle oil to maximize desired 48JULY 2015 | HydrocarbonProcessing.com

FIG. 7. Slurry and LCO Δ yields following a change out in the HPVGO catalyst system.

FCC product yields and minimize the production of slurry oil. In some cases, the recycle of bottoms to extinction is accomplished with complete conversion of black oil to other saleable products. Weathering the industry’s cyclical nature. The refining

industry is rich with a tradition of technical solutions when faced with challenging constraints and markets. To weather the cyclic and volatile nature of the business, it must employ robust and flexible solutions to meet future environmental regulations, capturing limited margins at the lowest possible capital investment. The application of latest-generation catalytic advancements can provide both flexibility and low capital solutions for the production of Tier 3 fuels. Many refiners have already transitioned to advanced catalytic solutions in the FCC pretreat arena, which can be used as a Tier 3 fuels strategy for the advantages afforded in FCC operation and yield selectivity, capitalizing on both clean fuels and profitability. LITERATURE CITED Gripka, P., O. Bhan, J. Esteban and W. Whitecotton, “Tier 3 capital avoidance with catalytic solutions,” AFPM Spring Annual Meeting, March 2014. Street, R. D., L. Allen, J. Swain and S. Torrisi, “Optimizing potential returns,” Hydrocarbon Engineering, March 2002. Cerić, E., Crude Oil, Processes and Products, IBC & PetroInvest Sarajevo, 2012. Magee, J. S. and M. M. Mitchell, Fluid Catalytic Cracking Science and Technology, Elsevier Science Publisher B.V., 1993. Hunt, D., R. Hu, H. Ma, L. Langan and W. Cheng, “Strategies for increasing production of light cycle oil,” PTQ Catalysis, 2009. Niccum, P. K., “Maximize diesel production in an FCC-centered refinery,” Hydrocarbon Processing, Gulf Publishing Company, September 2012, December 2014. Gillespie, B., A. Gabrielov, T. Weber and L. Kraus, “Advances in FCC pretreatment catalysis,” PTQ Catalysis, 2013, Vol. 18, No. 2. JAMES ESTEBAN is a senior technical service engineer for Criterion Catalysts and Technologies, specializing in technical service and solutions for hydroprocessing applications, as well as being the Criterion global subject matter expert for naphtha hydroprocessing. In addition to other refinery processes, Mr. Esteban has extensive experience in FCCPT, ULSD and ULSK applications. Prior to joining Criterion, he served in various refinery roles, including operations, unit engineering, process engineering, project engineering and project management. Mr. Esteban holds a BS degree in chemical and petroleum refining engineering from the Colorado School of Mines. MICHAEL HARTMAN is a technical service engineer with Marathon Petroleum, beginning his career there in July 2012. He holds a BS degree in chemical engineering from Ohio State University.

Special Report

Refinery of the Future D. LINDSAY, M. GRIFFITHS, A. SABITOV, D. SIOUI and B. GLOVER, UOP LLC, a Honeywell Company, Des Plaines, Illinois

How to cost-effectively adapt to a tight oil world The increase in domestic production of light tight oil (LTO) has resulted in rapid shifts to processing these crudes in North American (NA) refineries. In spite of the logistical challenges involved with bringing these new crudes to the market, the impact by LTO on the NA refining industry has been dramatic. Waterborne imports declined from more than 60% in 2010 to less than 50% in 2014. The shift has been even more dramatic for light sweet crudes, with US Gulf Coast waterborne import of these crudes dropping from nearly 1 MMbpd in 2010 to virtually none in 2014. LTOs typically have a much higher content of light material compared to the traditional light sweet crudes that most NA refineries have processed. While these domestic crudes offer lower-cost raw materials, there are inherent limits to the amount of LTOs that can be processed by installed assets. These limits can result from the additional light content or from feed quality parameters, such as the high paraffin content that is characteristic of most LTOs. Addressing these limitations will enable capturing the higher value from LTOs.

MARKET OVERVIEW As crude prices have dropped, there has been a slowdown in the level of new LTO drilling activity, which may result in another rebalancing of crude slate for NA refiners. While strategies are needed to most effectively handle the large increase in LTOs, it is more critical that NA refiners remain flexible and control investment to navigate these uncertain times. A number of typical scenarios that refiners may face are presented, along with cost-effective solutions that allow for increased LTO processing while still maintaining operating flexibility.

Diesel cut: Higher cetane number with poorer cold-flow properties o Naphtha cut: Leaner reformer feed, lower C5+ and hydrogen yields, less benzene saturation required • Higher light and heavy naphtha yields o Larger increase in light naphtha; greater need for isomerization o Increase in feedrate to reforming unit (fixed bed or CCR) o Higher quantity of isomerate and reformate in gasoline pool • Higher LPG yields. o

CASE STUDIES A number of case studies have been developed to look at options across the refinery to capitalize on increased LTO processing while also maintaining overall refinery flexibility. These cases will: 1. Evaluate the impact of the increased LTO component in the crude mix to the refinery 2. Show how a refiner might take advantage of processing opportunities that result from an increase in the amount of LTO in the crude mix. Base Case. The crude rate to the Base Case NA refinery is 150 Mbpd. In this case, the crude contains approximately 7 vol% of

Naphtha

C3= excess

Benzene saturation unit

NHT

Crude 150 Mpd

Refining impact from LTO. While there is significant vari-

ability in individual LTOs, they generally share characteristics that distinguish them from most other light sweet crudes: • Lower sulfur (S), nitrogen (N) contaminants o Lower hydrogen demand for hydrotreating and hydrocracking units • Lower vacuum residue (VR) yield o Lower vacuum gasoil (VGO), coker and fluid catalytic cracking (FCC) rates o Lower FCC rates, lower C3=/C4= to alkylation unit, less alkylate o Less FCC naphtha, alkylate in gasoline pool • Higher paraffin concentration

LPG

LPG

Alkylation

Reformate splitter

Reformer

Gasoline hydrotreater

Kero AGO LKGO

C3=, C4=

Cat-feed hydrotreater Vacuum

FCC

HKGO Coker

Coke

HT VGO

Propylene

Gasoline

Diesel hydrotreater

Diesel

CCN LCO

Slurry

FIG. 1. Refinery model configuration. Note: Base Cases with and without CFHT were considered. Hydrocarbon Processing | JULY 201549

Refinery of the Future LTO. The price set is indicative of more current market conditions in the US, where WTI crude has been trading at an average price of < $60/bbl since December 2014. Ultra-low-sulfur diesel (ULSD) is priced at a premium over regular gasoline. Propylene is priced such that alkylation of propylene to a premium gasoline-blend component is favored over the direct sale of propylene. The heavy-oil upgrading section of the refinery contains a vacuum distillation unit (VDU), coker and FCC unit (FCCU). GO from the VDU and the coker is fed to the FCCU. Scenarios with and without an FCC feed hydrotreater (CFHT) were analyzed. The alkylation unit is at full capacity to meet the premium gasoline production target. For the case without a CFHT, the net margin was established to be $103 MM/yr. Basis. The price basis used in this study is provided in TABLE 1. The transportation fuel specifications are based on typical US requirements including ULSD with a target cetane of 45 and gasoline (R + M) / 2 = 83.7 (before ethanol addition) for regular and 91.4 for premium at a 9 psig Rvp. The WTI crude price was used as the benchmark with crude purchases and products being compared on a relative basis. TABLE 2 shows the crude properties used in the study. Case 1: Increased quantity of LTO in crude. In this case, the amount of LTO in the crude has been increased from 7 vol% (Base Case) to 30 vol%. The amount of LPG, naphtha and diesel from the refinery increases, but the production of GO and residue decreases significantly. The increased amount TABLE 1. Study pricing basis

Crude feed

Base

Major products, % of crude ULSD

111%

Regular gasoline (83.7 RM/2)

104%

Premium gasoline (91.4 RM/2)

113%

Naphtha

91%

Propylene

84%

Combined LPG

46%

Slurry

80%

Bunker fuel oil

78%

TABLE 2. Crude properties Base Case crude slate

API

Possible future crude slate

7% tight oil in crude 30% tight oil in crude 29.6

33.2

1.6

1.3

TAN, mgKOH/g

0.45

0.35

650°F-minus, vol%

50.1

54.8

1,000°F-plus, vol%

21.7

17.8

Sulfur, wt%

Ramsbottom carbon, wt%

Case 2: Divert VR from coker to FCCU. This scenario builds on Case 1, and takes advantage of the reduced flow of improved quality feed to the FCCU. VR is diverted from the coker to the FCCU. The introduction of low-quality VR to the FCCU results in lower conversion and volume expansion compared to Case 1. However, even though this case results in lower conversion in the FCCU, upgrading the VR still proves to be valuable. The net margin increases by $18 MM/yr above Case 1. The amount of VR that could be diverted to an FCCU depends on the ultimate coke-burning capacity limit of the regenerator and the catalyst hydrothermal deactivation temperature limitations. The feedrate to the alkylation unit is maintained by feeding all of the FCC propylene to the unit, and this will result in zero propylene sales. Additional slurry from the FCCU is recycled to the coker, but, as the amount of VR to the coker has decreased, the total concarbon content of the feed to the coker is also lower. The refinery coke production decreases. Case 3: Produce high-quality diesel by oligomerization of light olefins from the FCCU. This case is the same as

Relative pricing

Description

of LTO being processed in the refinery results in improved FCC feed quality, but it also reduces the amount of GO feed available to run to the FCCU. The FCC feed is more paraffinic and contains more hydrogen. This higher-quality feed enables higher conversion, improved gasoline selectivity and increased light olefin (C3= and C4=) yields. The FCC also produces less light cycle oil (LCO) and slurry. Both, the crude composition change and the FCC yield shift resulted in an additional net margin of $25 MM/yr above the Base Case.

5.6

4.4

Vanadium, ppm

85.4

65.9

Nickel, ppm

22.7

17.6

50JULY 2015 | HydrocarbonProcessing.com

Case 1, except that an oligomerization and indirect alkylation processes are used to increase diesel production.1 This processing route can increase refinery margins by oligomerizing lowvalue light olefin streams to high-quality, high-value blending components for the gasoline pool.1 C4 and C5 olefins from the FCCU are oligomerized to produce a high-quality, low-S distillate range material. The improved quality FCC feed results in more light (C3–C5 ) olefins that can be converted to alkylate in the alkylation unit and/or to diesel in the oligerization unit.1 The feedrate to the alkylation unit was maintained by preferentially feeding C3= and then C4= to the unit. C5= and leftover C4= are routed to the oligomerization unit, which primarily produces diesel. As summarized in TABLE 3, this scenario results in an additional net margin of $7 MM/yr above Case 1. As in Case 2, this scenario results in zero propylene sales. Case 4: Increasing refinery margin via changes in CFHT. Corresponding cases were developed for a refinery flow

scheme that includes a CFHT unit. In this Base Case (CFHT Base), the CFHT provides more than 90% desulfurization and 40% conversion of N content, which enables the FCCU to increase conversion and refinery margins. With the benefit of the CFHT, the modified Base Case will have a $37-MM higher margin compared to the case without a CFHT. Since the refinery with a CFHT begins with a higher-gross-margin starting point, the crude change alone does not lead to the benefits described earlier. However, an upgrade in CFHT operation to a mild hydrocracking unit (MHCU) will provide substantial margin improvement.

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Refinery of the Future With the increase of the LTO component into the crude mix, the performance of the CFHT unit can be pushed to provide even larger margin benefits. With the crude change, the feedrate to the CFHT is decreased by 3 Mbpsd. The feed quality also improves significantly with a 1.5 API increase and approximately 10% less S and N. These changes enable the CFHT to provide a significant improvement in FCC feed, while maintaining the same cycle length. FCC feed S and N contents are both reduced by more than 30% compared to the CFHT Base Case. The improved feed will increase refinery margins by $18 MM/yr. This margin improvement is significant, but an even larger boost can be obtained by converting the CFHT into an MHCU. The reduction in feedrate to the CFHT, as well as the reduction of the feed N coupled with the addition of a second reactor in series, enables the revamped unit to convert about 30% of the FCC feed into diesel and lighter products. The existing reactor is loaded with high-activity Ni-Mo HC-pretreat catalyst and the new reactor is loaded with HC catalyst. The conversion to MHCU will require capital investment for revamp of the CFHT. However, that investment is expected to pay off within one to two years with a $53 MM/yr improvement in refinery

margins. The total economic impact for the crude change and the conversion of the CFHT to MHC operation is $71 MM/yr. TABLE 4 summarizes the CFHT options discussed earlier. To achieve that boost in margin, the FCCU feed is adjusted to contain approximately 25% VR. As in Case 2, directing VR to the FCCU will reduce coke make and slurry oil yields with a corresponding increase in gasoline and diesel yields. For the MHC case, propylene production is eliminated. Propylene can be produced by introducing ZSM-5 into the FCC catalyst mix. The propylene would be produced at the expense of regular gasoline. The benefit of converting a CFHT into an MHCU has been demonstrated in implemented projects. For example, similar results were achieved by a refinery for conversion of a CFHT to an MHCU. In that case, an existing 1,500 psig, 30 Mbpd CFH feeding a mixture of 24% CGO, 18% LVGO and 58% HVGO, operating at 17% conversion was converted into an MHCU by replacing part of the existing hydrotreating catalyst with advanced hydrotreating catalyst and the remainder with hydrocracking catalyst. In addition, a catalyst cooler was added to the FCCU to permit the processing of the higher-concarbon VR feedstock. As a result of the modifications, the unit conver-

TABLE 3. Summary of Cases 1–3 Case description

Base

FCC feed type

GO

Product rates

Base w/additional LTO, Case 1

Divert VR to FCC, Case 2

Implement oligomerization technology, Case 3

GO

GO + VR

GO

% of Base

% of Base

% of Base

Coke

Base

82

77

82

LPG

Base

107

104

107

Propylene

Base

89

0

0

Gasoline—Regular

Base

102

103

101

Gasoline—Premium

Base

100

100

100

ULSD

Base

100

103

103

Fuel oil

Base

86

86

86

150,000

150,000

150,000

Asset utilization rates CDU, bpsd

150,000

% of Base

% of Base

% of Base

VDU

Base

90

90

90

Coker

Base

82

82

82

FCC

Base

94

100

94

Portion of feed that is VR, %

0

0

6

0

Oligomerization unit

No

No

No

Yes

Alkylation

Base

100

100

100

LT naphtha hydrotreater

Base

118

118

118

HN naphtha hydrotreater

Base

107

107

107

Reforming unit

Base

107

107

107

Benzene unit

Base

107

107

107

FCC naphtha hydrotreater

Base

96

96

96

Distillate hydrotreater

Base

100

103

102

FCC feed hydrotreater

0

Relative refinery margin, $MM/yr

Base

52JULY 2015 | HydrocarbonProcessing.com

0

0

0

Base + 25

Base + 43

Base + 32

Refinery of the Future sion was increased from 17% to 40%, and the overall refinery distillate production was increased by 7%. Given a diesel-togasoline price differential of $5.25/bbl, this conversion project had a payback of less than two years and an internal rate of return (IRR) of 54%. The shift to LTO is expected to provide more opportunities for these conversions.

Case description

Case 5: Increasing light naphtha isomerization with low-cost revamp. While many NA refiners have isomeriza-

tion units, these were typically installed before the current ethanol mandates. At present, many of these units have been idled or are being used primarily for benzene saturation in combination with seasonal campaigns of paraffin isomerization. With an increasing diet of LTO crudes, the composition of gasoline will shift away from FCC gasoline and alkylate and more toward reformate and isomerate. For refineries that do not operate an isomerization unit, or where isomerization capacity is limited, this can cause a bottleneck when LTO content of the crude is increased. There are a number of costeffective approaches; they include: • Revamp an existing isomerization unit • Convert a recycle gas pentane isomerization unit to a light naphtha isomerization unit2, 3 • Convert a zeolitic isomerization unit to a light naphtha isomerization unit3 • Convert an idle naphtha hydrotreater or a fixed-bed reformer to an isomerization operation

TABLE 4. Case 4—FCC feed pretreating unit case summary

CFHT feedrate, bpsd

CFHT Base

CFHT Base w/ additional LTO

Conversion to MHC

45,114

42,360

42,360

S, wppm

1,300

900

65

N, wppm

1,343

871

133

CFHT product properties (680°F-plus)

CFHT/MHC yield, vol% FF Naphtha

3

3.4

7

Diesel

10.5

11.5

23

FCC feed

88.3

86.7

72.7

0

0

9.6

Propylene

Base

62

0

LPG

Base

104

96

VR, vol% of FCC feed Refinery product rates, % of Base

Gasoline

Base

101

101

Diesel

Base

101

108

Slurry oil

Base

87

25

Coke

Base

82

76

Base

Base + 18

Base + 71

Refinery margin, $MM/yr

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Hydrocarbon Processing | JULY 201553

Refinery of the Future • Add a light naphtha isomerization reactor (side-car) to an existing reforming unit.3 A typical case would include a light naphtha isomerization unit that was originally commissioned in the late 1970s or 1980s.3 Most likely, the unit was originally designed to process pentanes and hexanes on a once-through hydrocarbon basis to achieve a product RON of 80 to 82. While present-generation isomerization units are designed with a once-through hydrogen configuration, older units were designed with a hydrogenrich recycle gas system. With increasing use of ethanol in gasoline blending, the RON requirement for many isomerization units of this design has steadily declined. The addition of a coker and an earlier shift to heavier, imported crudes would further reduce isomerization RON demand by decreasing the overall volume contribution of isomerate to the gasoline pool. The operation of many of these isomerization units has been shifted to processing C6 straight-run naphtha in a purely benzene saturation role. In this operating mode, the dryer and chloride management equipment in the unit are no longer required. Often, these systems have been decommissioned and are no longer maintained. With the realignment of the crude to significant quantities of LTO, there are cases where the isomerization unit can no longer be idle, as the octane of the light naphtha is now too low to be blended directly with the cracked gasoline and reformate. While additional RON can be achieved in the naphtha reforming unit, the liquid volume loss and increased LPG production that would result makes that option less attractive. The ability of light paraffin isomerization to increase RON on a significant fraction of the gasoline with very low volume loss makes this the most attractive solution to the gasoline RON shortfall. In situations like this, an existing pentane isomerization unit can be brought back into isomerization service quickly and at low cost by converting it to a light naphtha isomerization unit.2, 3 The catalyst is a non-chloride-based catalyst. It does not require any of the chloride addition or caustic treatment characteristics of chlorided-alumina pentane isomerization systems.2 It is considerably more contaminant resistant, so it also does not require the liquid feed and hydrogen feed dryers that are a fixture in chlorided alumina systems.2 For existing chlorided-alumina isomerization units, which include a recycle gas compressor, conversion to light naphtha isomerization operation can be CO3, H2S, C2– Propane NGL feed

C3 sweetening unit

Deethanizer

Caustic regeneration i-butane C3 sweetening unit

Depropanizer

Deisobutanizer n-butane

Debutanizer C5+ sweetening unit

C5+

FIG. 2. Example flow scheme of an NGL fractionation facility featuring a treating unit with common caustic regeneration.

54JULY 2015 | HydrocarbonProcessing.com

done easily, at low cost, with no need to re-commission feed dryers and caustic-scrubbing or chloride-injection equipment.3 Tight-oil liquids: Impact on LPG handling. As noted in TABLE

3, increasing the tight-oil crude component in the feed increases the amount of light material that must be processed through the refinery system. Depending on how the crude diet changes, the increase in light materials can be significant. It can be double or more the content level as compared to the crude streams it is displacing from the refinery. This may be one of the key limits to leveraging the typically discounted pricing of domestic tight oil. Many refiners have found that their ability to blend LTO into their feedstocks has been restricted by the higher content of light materials, including LPG in the crude. Debottlenecking the top of the crude column through a revamp or by first processing the crude in a preflash column has proven an effective component of programs aimed at increasing the amount of LTO processed. Once separated in either the preflash or in the crude column itself, this higher amount of LPG must be treated for S before being offered for sale or sent to downstream processing units. This increased demand for LPG treating in refineries has coincided with the increase in field NGL available from the production of wet natural gas fields. Producers have focused on wet plays to increase production returns in the face of lower natural gas prices. This strategy has been effective and has resulted in large increases in field NGL requiring separation and treating. The first step of separating the bulk liquids from natural gas results in a mixed stream known as y-grade liquids. Once recovered, the next step in maximizing the value of ygrade NGL is to fractionate them into the purity components of ethane, propane, butane and natural gasoline (C5+). FIG. 2 is an example of an NGL fractionation plant flow scheme. Depending on markets available to the processor, it may also be economically advantageous to split the butane stream further into isobutane and n-butane with a de-isobutanizer column. Isobutane is a valued feedstock for refineries with an alkylation process unit. If additional isobutane is needed by the local market, the n-butane can be converted to isobutane with isomerization process technology.4 Whether collected directly from the field or from the processing of crude oil at a refinery, untreated LPG may contain S. The S is typically present as mercaptan, but this stream may also contain carbonyl sulfide (COS) and hydrogen sulfide (H2S). When present, this S may need to be removed to meet downstream pipeline specifications. In addition, S is a deactivating poison to many catalytic systems, and it must be removed to protect downstream catalyst systems. The most effective means of meeting this sulfur extraction need is to process the materials with an LPG caustic “sweetening” treating process.5 The S-containing feed is treated in a combination column containing a prewash to first remove COS and H2S, and an extraction section to remove mercaptan S. The extracted mercaptan is removed from the caustic in the caustic regeneration section. The fully regenerated caustic is then sent back to the extraction section. Projects related to NGL processing have been moving ahead at a rapid pace, and the ability to process feedstocks quickly is critical. To meet the schedule and construction needs of these

Refinery of the Future projects, modular construction techniques have been favored. Modular packaging of the LPG treating units shortens the project schedule while minimizing onsite construction requirements and time to operation.5 With the modular sweetening units, it is fabricated into a number of individual modules in a fabrication shop including piping, valves, vessels and pumps, as well as the instrumentation and electrical for the process unit.6 The modules are shipped complete and ready for installation at the processing site, enabling a compressed project schedule. To improve the packaging for modular supply, as well as improve the extraction capability, the regeneration section of caustic treating units has been redesigned. The redesigned system results in a reduced plot plan and lower emissions, both valuable aspects especially for revamps, as well as improved caustic regeneration.7 Options. With the shift to increased consumption of tight-oil

crudes, refiners need processing strategies that allow them to effectively deal with the resulting change in crude properties. LTOs typically have a much higher content of light material compared to the traditional light sweet crudes. To maximize the benefit of processing these lower-cost crudes, the inherent limits of the installed assets must be considered. In most cases, modifications will be required. A number of options are available and can bring significant value while minimizing investment and still maintaining processing flexibility.

ACKNOWLEDGMENTS The authors acknowledge the following individuals, for their assistance in generating data and for providing support for this article: 1. Tony Navarro, UOP refinery modeler, for providing refinery modeling and evaluation support 2. Joe Ritchie, UOP refinery configuration leader, for providing configuration and optimization support 3. Jeff Bray, UOP refinery configuration leader, for providing configuration and optimization support. NOTES UOP’s Catolene-D technology has been employed to increase diesel production. Catolene-D technology leverages UOP’s extensive experience with catalytic condensation and indirect alkylation (InAlk) process technologies. 2 UOP Penex process. 3 Par-Isom isomerization operation. 4 Isobutane with isomerization process technology, such as a UOP Butamer Process unit. 5 The UOP Merox units is a treating “sweetening” process with common caustic regeneration. 6 Most effective means of meeting this sulfur extraction need is to process the materials with an LPG Extraction Merox process unit. 7 The regeneration section of caustic treating units has been redesigned is known as MVP caustic regeneration. 1

BIBLIOGRAPHY Huovie, C., M. J. Wier, R. Rossi and D. Sioui, “Solutions for FCC Refiners in the Shale Oil Era,” AFPM Annual Meeting, March 2013. Lippmann, M. and L. Wolschlag, “Innovative Technology to Improve FCC Flexibility,” AFPM Annual Meeting, March 2012. Thomas, D., G. Kirker and D. Pappal, “Gas-to-Liquids via Mild Hydrocracking,” AFPM Annual Meeting, March 2013. Wier, M. J., D. Sioui, S. Metro, A. Sabitov and M. Lapinski, “Optimizing Naphtha Complexes in the Tight Oil Boom,” AFPM Annual Meeting, March 2014.

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Hydrocarbon Processing | JULY 201555

| Bonus Report LNG The LNG sector is undergoing change as projects are consolidated in regions with an abundance of proposed, expensive LNG export projects, and as gas prices fluctuate alongside other energy benchmarks. Deloitte’s Andrew Slaughter discusses how the drop in oil prices will impact the construction of LNG export terminals and future LNG pricing, as well as the potential establishment of an Asian LNG hub. Despite changing market conditions, new sources of supply into the global LNG market are actively under development, both in terms of exporter startups and new methods of supply delivery. Slaughter explains the major factors that could influence global LNG trade patterns and the development of FLNG vessels. Photo courtesy of Center for Liquefied Natural Gas (CLNG).

Bonus Report

LNG A. SLAUGHTER, Executive Director for the Deloitte Center for Energy Solutions, Deloitte Services, Houston, Texas

US liquefaction projects to drive global expansion of LNG trade HP. Will the drop in oil prices impact the construction of LNG export terminals? If so, how?

As executive director for the Deloitte Center for Energy Solutions, Deloitte Services LP, ANDREW SLAUGHTER works closely with Deloitte’s Energy and Resources leadership to define, implement and manage the execution of the Center’s strategy. He also helps develop and drive energy research initiatives and manage the development of the Center’s eminence and thought leadership. During his 25-year career as an oil and gas leader, he has occupied senior roles in both major oil and gas companies and consulting/advisory firms.

The LNG sector is undergoing change as projects are consolidated in regions with an abundance of proposed, expensive LNG export projects, and as gas prices fluctuate alongside other energy benchmarks. Hydrocarbon Processing spoke to Andrew Slaughter, executive director for the Deloitte Center for Energy Solutions, about the state of the LNG industry and how trade patterns and project slates could change in the upcoming years.

Slaughter. Lower oil prices in 2015 are translating via contractual price linkages into lower delivered LNG prices into the Asian market. This directly reduces margins available to existing LNG sellers who supply large buyers in Japan, South Korea and elsewhere in Asia. However, future exports, from facilities not yet onstream, will deliver into the prevailing price environment at the time when they become operational. Deloitte’s view is that, over the next several years, oil prices are likely to recover from current levels, although probably not at the $100-plus/bbl level for quite some time. Each LNG project developer will take a view on future oil prices and the implications for the specific economics of their project, rather than make hasty decisions based solely on the price downturn of late 2014 and early 2015. In the US, a number of LNG export facilities are well advanced down the development path, having obtained the necessary regulatory approvals from the US Federal Energy Regulatory Commission and the US Department of Energy, established commercial arrangements for LNG sales and gas supply, and taken final investment decision [FID]. These projects are definitely moving ahead, and Deloitte expects the first ramp-up of US LNG exports to begin in early 2016, after the planned startup of Cheniere’s Sabine Pass facility in Louisiana. Some of the other projects to have taken FID are Freeport LNG and Cove Point LNG. These facilities are under construction and will almost certainly go ahead,

with a total capacity of about 6.5 Bcfd to 7 Bcfd. Additional projects, such as Lake Charles LNG, Corpus Christi LNG and Elba LNG, are close to FID and have a high probability of moving forward on or near their proposed timeline. The December announcement by Petronas of a delay in taking FID at its proposed LNG facility in British Columbia [BC] was partially attributed to greater uncertainty in the oil price environment. However, there are other factors in play, including greenfield development costs in BC and the greater distance from gas supplies. Many developers are testing their economics at a range of levels, examining strategies for efficient, cost-effective project development and determining that commercial arrangements are robust before taking FID. In some cases, this may mean the delay or deferral of projects, but there are enough projects sufficiently well advanced to ensure that the US is able to become a large LNG exporter over the rest of this decade. HP. How will LNG pricing be impacted by today’s market conditions? In the future, do you see a large-scale switch to gas-indexed pricing vs. oil-indexed pricing for LNG?

Slaughter. For LNG supply under existing contracts, changes in the oil price translate directly into LNG prices, albeit with a three- to six-month lag; and spot prices for LNG are influenced by current levels of contracted LNG prices. This year and into early next year, LNG prices are moving significantly lower than they have been for the past several years. LNG delivered to Tokyo has come Hydrocarbon Processing | JULY 201557

LNG down from the $15/MMBtu to $16/ MMBtu range to below $10/MMBtu. Long-term LNG supply contracts into Asia have largely remained linked to oil in some way throughout the history of LNG trade. Depending on the supply-demand balance at the time of contract negotiation, the nature of the linkage can vary, giving a degree of price responsiveness to market conditions. When oil prices are low, there is less incentive to look for alternative price methodologies, such as gas-indexed pricing. The introduction of US LNG supply, with feed gas purchased at Henry Hubrelated prices, will introduce an element of gas-indexed pricing into the market, but it is unlikely that this can be applied to gas from other sources in the near to medium term. HP. What conditions would need to be in place for an Asian LNG hub to be successful?

Slaughter. To establish a commodity trading hub around which to develop financial trading, you need a location

where physical delivery of the traded commodity is possible, and a spot market with the potential to trade sufficient volumes to underpin demand for participation in a financial market. Both of these elements are at a relatively early stage in Asia. Singapore has developed LNG facilities to import LNG for its domestic gas needs and has ambitions to expand this to be the basis for a regional hub. Spot trade in LNG in Asia has grown in recent years, partly consequent on Japan’s need to secure additional gas on a short-term basis as a power generation fuel to replace nuclear generation. However, most gas is still traded on long-term pointto-point contracts, and LNG trade is structurally much less fungible than oil trade. The critical question is whether enough liquidity can be established to support physical and financial market trading. Asian buyers and sellers have largely been risk averse, mostly wanting to lock in supply and pricing arrangements. There may have to be a major shift in this preference to allow the takeoff of a significant new LNG trading hub.

HP. What do you see as the major factors that will contribute to the success or failure of floating LNG (FLNG) ventures?

Slaughter. The main advantages of FLNG are that this technology allows for the development of gas in more remote offshore locations. Also, the FLNG vessel can be relocated at the end of the economic life of the initial field. In some cases, FLNG development costs can be lower than those of onshore liquefaction. Shell and Petronas are both developing large-scale FLNG projects for deployment offshore Australia and Malaysia, and there is a much smaller FLNG vessel due to be deployed offshore Colombia. These projects will come onstream in the next two to three years, and achievements will be measured by their cost and operational reliability. If success on these initial projects is demonstrated, then there are many other candidate fields around the world where FLNG could be a viable development option. HP. Which countries will shape global LNG trade flows over the next five years?

Slaughter. The number of countries becoming either sellers or buyers of LNG has expanded significantly in recent years, to approximately 20 exporting countries and 30 importing countries. New sources of supply into this global market are actively under development, including the US (although the US has already been a long-term exporter of LNG on a small scale, with gas shipped from the Kenai facility), Canada, Mozambique and Tanzania. On the importing side, several smaller new markets are emerging, such as Egypt, Pakistan and Poland. Deloitte expects the most significant impact on global trade to come from the establishment of the US as a major source of new supply, along with Qatar and Australia. In particular, this gives Asia’s large buyers more supply options and some exposure to North American hub-based pricing. The Panama Canal expansion opens up a shorter trade route for US Gulf Coast LNG to access Asian markets and enhances its competitive position. With respect to LNG imports, Deloitte will be closely watching trends in China and India for indications of which mix of supply sources they will favor. 58

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Regional report

M. RHODES, Technical Editor

China’s ‘energy revolution’ strives for sustainable growth Over the past decade, the People’s Republic of China has experienced unprecedented growth. The country’s energy demand, particularly for petroleum and other liquids, is rapidly increasing as its industrial and transportation infrastructures expand. While striving to secure energy resources, China is facing pressure to reduce air pollution levels caused by these expansions. Traffic congestion and smog levels in China’s major cities are among the most polluted in the world. In March 2013, a new governmental leadership emerged when Xi Jinping became president and Li Keqiang assumed the premiership. The new administration is keen to initiate economic and financial reform in China in the interest of greater longterm and sustainable growth.1 The National Development and Reform Commission (NDRC), a department of China’s State Council, is the primary policymaking, planning and regulatory authority of the energy sector, among others. In June 2014, China’s energy security strategies were revealed, with the president introducing the key elements of China’s ‘energy revolution.’ The newest energy policies are driven by the country’s growing demand for oil and its reliance on oil imports. The National Energy Administration (NEA), launched in 2008, along with the NDRC, are charged with policy implementation.2

world’s second-largest consumer of oil and surpassed the US in 2013 as the world’s largest net importer of petroleum and other liquids (FIG. 1). China’s petroleum production has risen approximately 50% over the past two decades, but it serves only the domestic market. Long-term growth will require enhanced recovery at mature crude oil fields; greater investment to access more technically challenging plays, such as shale oil, tight oil and deepwater fields; and growth in nonpetroleum liquids, such as gas-to-liquids (GTL), coal-to-liquids (CTL) and biofuels. Due to the growing disparity of consumption vs. production (FIG. 2), the country imports approximately 50% of its crude oil needs. China accounted for more than an estimated one third of global oil demand growth in 2014, averaging net total oil imports of 6.1 MMbpd. The EIA’s International Energy Outlook 2014 forecasts that China’s oil consumption will continue growing through 2016 to approximately 11.3 MMbpd, and will continue to rise by approximately 2.6%/yr through 2040, reaching 13.1 MMbpd in 2020, 16.9 MMbpd in 2030 and 20 MMbpd in 2040. This level will exceed US consumption by 2034.1 In the past year, crude imports have increased by around 8%.3

China’s energy outlook. The US Energy Information Ad-

As China seeks greater energy security and moves away from obsolete facilities (left), it is increasing its refining capacity with construction and expansion projects like the Sinopec and BASF JV complex in Nanjing (right).

ministration (EIA) reports that China, the world’s most populous country with an estimated 1.3 B people in 2013, is the

Hydrocarbon Processing | JULY 201559

Regional Report Dominance of national oil companies. Because they control much of the oil and natural gas upstream and downstream sectors, China’s national oil companies (NOCs) wield a great amount of influence. However, the government has been granting international oil companies (IOCs) more access to technically challenging onshore and deepwater offshore fields, mainly through production-sharing contracts (PSCs) and joint ventures ( JVs). China revised its oil price reform legislation in 2013 to further reflect international oil prices in the country’s domestic demand. NOCs from Kuwait, Saudi Arabia, Russia, Qatar and Venezuela have entered into JVs with Chinese companies to build integrated refinery and petrochemical projects and to gain a foothold in China’s downstream oil sector.1 IOCs—such as Anadarko, BP, Chevron, ConocoPhillips, Eni, Husky, Kuwait Petroleum, PDVSA, Rosneft, Saudi Aramco, Shell, Total and Yuntianhua Group, among others—are offering technical expertise to China’s NOCs to gain access to Chinese markets. The three largest state-owned oil and gas companies are China Petroleum and Chemical Corp. (Sinopec); China National Petroleum Corp. (CNPC), the parent company to PetroChina; and China National Offshore Oil Corp. (CNOOC). Government restructuring in the late 1990s reorganized state-owned assets and expanded their operational responsibilities. Sinopec, which operated 5.6 MMbpd of oil processing capacity in China in 2014, is the largest oil refiner in the world, according to the US EIA, and it operates a significant refining presence in the coastal and southern areas of China (FIG. 3). Sinopec accounted for approximately 41% of the country’s refining capacity in 2014 and relies heavily on imported crude oil China

6.1 5.1

Net oil imports, MMbpd

US 4.2

Japan 2.7

India South Korea

2.3

Germany

2.2

Crude purchases and teapot refineries. Demand contin-

ues to outpace production, and imports of crude oil have risen

1.6

France

for its refineries. Most of the NOC’s refineries are configured to handle crude oil that is higher in sulfur (S) and acidity.1 In addition to its strong domestic presence, Sinopec is gradually investing in refining assets overseas. In 2015, it purchased a 37.5% stake in Saudi Arabia’s 400-Mbpd Yanbu refinery and began processing heavy crude oils. Sinopec recently entered into JV partnerships for two large refineries, Mthomobo in South Africa and Premium 1 in Brazil, and has also invested in oil storage projects abroad. CNPC/Petrochina is the country’s second-largest refiner. The company is the leading upstream player in China and represents an estimated 54% and 77% of China’s crude oil and natural gas output, respectively.4 With a refining capacity of 3.44 MMbpd, it accounted for approximately 30% of the country’s 2013 capacity.5 In 2014, CNPC/Petrochina expanded its downstream presence in southern China with the start of commercial operations of its 200-Mbpd Pengzhou refinery in Sichuan province. The company has also acquired refinery stakes in other countries (e.g., Singapore and Japan) to secure more global trading and arbitrage opportunities in the downstream sector. CNPC has invested in refineries and pipelines in African countries in exchange for exploration and production rights. CNOOC, which operates over 600 Mbpd of refining capacity, entered the downstream sector through the commissioning of the company’s first refinery, the 240-Mbpd Huizhou plant, in 2009. The third major NOC anticipates expanding this refinery by 200 Mbpd in 2016. Primarily responsible for offshore oil and gas exploration and production (E&P), CNOOC is becoming a growing competitor to CNPC and Sinopec by not only increasing its E&P expenditures in the South China Sea, but also by extending its reach into the downstream sector, particularly in southern Guangdong province. While the ‘big three’ NOCs continue to plan and carry out construction and expansions projects, shown in TABLE 1, smaller NOCs and regional companies (FIG. 4) are struggling to compete.

1.2

Spain Italy

1.1

Taiwan

1.0

FIG. 1. Top 10 annual net oil importers, 2014. Source: US EIA.

Oil production and consumption, MMbpd

12

Forecast

10 8

Consumption

6 4

Production

2 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

0

PetroChina Sinopec CNOOC

FIG. 2. China’s oil production vs. consumption, 1993–2016. Source: US EIA.

60JULY 2015 | HydrocarbonProcessing.com

FIG. 3. Distribution of China’s major NOC refineries. Source: Hydrocarbon Processing Construction Boxscore Database.

Regional Report dramatically in the last decade, driving the need for increased refining capacity. Investment research firm Sanford C. Bernstein & Co. Inc. said that China’s increasing demand and record purchases will create a global shortfall of 1.5 MMbpd in 4Q.6 As the oil refining sector undergoes modernization, smaller independent refineries (commonly known as ‘teapots’), many of which are located in the eastern province of Shandong, are being encouraged to increase capacity, streamline operations, improve efficiencies and even consolidate with larger facilities. These teapot refineries account for almost one third of China’s total refinery capacity. Earlier this year, the NDRC announced a policy allowing local refiners to almost double the amount of crude they can import if they remove facilities with less than 40-Mbpd capacity, modernize or remove antiquated facilities, and build oil storage facilities.1 Many teapot refineries are likely to get quotas in 2015 for as much as 30 metric MMt of foreign oil, equivalent to approximately 600 Mbpd, according to Beijing-based China International Capital Corp. Consultancy ICIS China believes this expansion will increase refining capacity by 15% to approximately 4.4 MMbpd. The transition from fuel oil to crude, which can yield higherquality gasoline and diesel, is becoming increasingly prevalent at the teapot refineries. SCI International reported that crude oil accounted for almost 70% of the feedstock used by the plants last year, compared with 53% in 2011.

Strategic petroleum reserves and crude oil storage. Capi-

talizing on a decision by the Organization of the Petroleum Exporting Countries (OPEC) to protect its market share rather than cut production amid a global oversupply, China has increased purchases of crude to expand its strategic petroleum stockpiles, buying a record 7.4 MMbpd in April 2015, up almost 17% from March and 3.1% from the previous high in December 2014. Comparatively, the US imported approximately 7.3 MMbpd. To ensure adequate supply and provide a buffer against geopolitical issues, China has diversified its sources of crude oil imports, although the largest source remains the Middle East.

FIG. 4. Smaller regional refineries, like this one in east China’s Shandong Province, are struggling to compete against NOCs.

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Hydrocarbon Processing | JULY 201561

Regional Report Driven primarily by crude oil imports, total net oil imports now exceed domestic supply, increasing import dependency from 30% in 2000 to approximately 57% in 2014, the US EIA said. As part of its 10th Five-Year Plan, China has established a government-administered strategic petroleum reserve (SPR) program, involving three phases and the construction of facilities by 2020 that can hold 500 MMbbl of crude. Between 141 MMbbl and 180 MMbbl of storage capacity has been built, and several sites are under construction. Completed in 2009, Phase 1 has a capacity of 103 MMbbl at four sites. Phase 2 is expected to provide an additional 170 MMbbl by 2020, while 232 MMbbl of storage are proposed for Phase 3.1 The facilities are spread along the country’s eastern and southern coasts for improved accessibility.7 The threat of overcapacity. China ranks behind only the US and EU in refining capacity: its installed crude refining capacity reached nearly 14.2 MMbpd by 2015, about 680 Mbpd higher than in 2013, according to Facts Global Energy (FGE). China’s refinery throughput in April averaged 10.54 MMbpd, up 6.9% from a year earlier. Two new greenfield terminals began operations in the first half of 2014: CNPC’s Pengzhou and Sinochem’s Quanzhou. No

Natural gas production vs. consumption, Tcf

6 Production Consumption

5 4

Imports exceeded exports 3 2 1 0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 2013

FIG. 5. China’s natural gas production and consumption, 2000–2013. Source: US EIA.

new terminals are expected until late 2016, and only a few expansion projects are expected to add capacity in 2015. Some of the new refineries are designed to accept all grades of crude oil, which will help the country meet domestic demand and export petroleum products in the region.1 Domestic refining capacity topped 14 MMbpd by 2015 with the commissioning of PetroChina’s 200-Mbpd Sichuan facility, Sinochem’s 240-Mbpd plant and Sinopec’s 160-Mbpd Shijiazhuang refinery expansion.5 Capacity is expected to increase to 17 MMbpd by 2025. Utilization rates declined to less than 75% in the past year as Chinese companies continued to build, despite slower oil demand growth in China and around the world. Industry analysts anticipate that China will add only 1.5 MMbpd of net capacity between 2015 and 2020 due to project delays and overcapacity. Projects such as CNOOC’s Huizhou expansion, Sinopec’s Zhangjiang facility and CNPC’s Huabei, Anning and Jieyang projects have all been pushed back.1 Additional lower-S requirements in transportation fuels may also delay the start of some new projects. China is implementing a nationwide Euro 5 fuel standard by the end of 2017. Despite the threat of overcapacity, the country is still pursuing many of its refining capacity additions. According to IHS, nearly 1 Bt of total chemical capacity has been added globally since 2000. China has accounted for more than 70% of this increase. Its ethylene capacity is forecast to hit nearly 27 MMtpy in 2015, representing an increase of more than 80% from 15 MMtpy in 2010.5 Increasing regasification capacity. China is adding massive regasification capacity. Two new terminals came online in 2014: • The 3-MMtpy Qingdao import terminal developed by Sinopec was commissioned in December with a cargo from Papua New Guinea (PNG). Sinopec has a 2-MMtpy long-term contract with PNG LNG. • The Hainan LNG terminal (CNOOC’s 7th terminal) received a commissioning cargo from Qatar in August 2014. The floating storage and regasification unit (FSRU) has a nameplate capacity of 3 MMtpy and is the second terminal in China after Dalian to have reloading capabilities.

TABLE 1. Notable refinery projects and expansions. Sources: US EIA, based on FACTS Global Energy, IEA, Reuters and company information Company owner

Location

Capacity, Mbpd

Start date

Sinopec

Notes

Caofeidian/Tianjin

240

2020+

Sinopec

Guangdong/Zhanjiang

300

2017

Sinopec

Hainan

100

2020+

Construction: Environmental approval received in 2013

Sinopec

Luoyang

160

2020

Expansion project

Construction: Received NDRC approval January 2015; plans to process crude oil from Saudi Arabia Construction: Developing with Kuwait Petroleum (30%) and Total (20%)

CNPC/PetroChina

Huabei

100

2017

Upgrading: Construciton

CNPC/PetroChina

Anning/Yunnan

200

2016

Construction: Plans to process oil from Saudi Arabia and Kuwait via the crude oil pipeline from Myanmar; JV with Saudi Aramco (39%) and Yuntianhua Group (10%)

CNPC/PetroChina

Guangdong/Jieyang

400

2018

Construction: JV with PDVSA (40%)

CNPC/PetroChina

Tianjin

320

2020

Construction: agreement signed between partners; JV with Rosneft (49%)

CNOOC

Ningbo Daxie/Zhejiang

140

2015

Construction: Expansion to 300 Mbpd

CNOOC

Huizhou Phase 2

200

2016

Construction: Expansion

62JULY 2015 | HydrocarbonProcessing.com

Regional Report Additionally, three terminals are being expanded: • In Guangdong, a 4th tank with a capacity of 160 Mcm is being constructed and is scheduled to be commissioned by September 2015. • The Jiangsu (Rudong) terminal will receive a 4th storage tank with 200 Mcm of capacity. The completion is scheduled for the end of December. The terminal has a sendout capacity of 3.5 MMtpy. • In Tianjin, a land-based expansion project will increase FRSU terminal capacity to 6 MMtpy. Six new terminals (Beihai, Shenzhen, Tianjin, Yantai, Yuedong and Zhangzhou) are also under construction for a combined capacity of around 16 MMtpy. Decreasing reliance on coal. China’s rising coal production and its sizeable industrialization and swiftly modernizing economy helped it become the world’s largest power generator in 2011. Consequently, as the world’s top coal producer, consumer and importer (an estimated 66% of its energy consumption is coal), the country is also the world’s leading energyrelated carbon dioxide (CO2 ) emitter, releasing 8,106 metric MMt of CO2 in 2012. The government has announced plans to reduce its overall CO2 emissions by at least 40% between 2005 and 2020, mainly in energy-intensive industries and in construction. These goals assume a sizable reduction in coal reliance and a diversification of energy supplies.

Boosting natural gas use. To alleviate high levels of pollu-

tion, the government has committed to increasing natural gas use to at least 10% of total energy consumption by 2020, a jump from its 2012 level of only 5%. In 2013, consumption increased to 5.7 Tcf, 12% more than in 2012, and the country imported approximately 1.8 Tcf of liquefied natural gas (LNG) and pipeline gas to make up the difference (FIG. 5). China’s gas consumption in 2013 was 161.6 Bcm, against production of 117.1 Bcm. The country’s gas demand is forecast to increase to 315 Bcm by 2019, while its production is expected to rise to 193 Bcm. By 2035, the country is anticipated to consume the same volume of gas as Europe. In response to this rapidly expanding demand, China’s LNG imports will rise significantly. Domestic LNG imports reached 15 MMtpy in 2012 and are expected to double by 2015.5 As with the oil segment, the three major NOCs dominate the natural gas market. CNPC, which accounts for roughly 77% of the country’s natural gas production, is the country’s largest natural gas company in both the upstream and downstream sectors.8 Sinopec operates the promising Puguang natural gas field in Sichuan province, while CNOOC led the development of China’s first three LNG import terminals at Guangdong, Fujian and Shanghai. Although the three NOCs own majority stakes in many of the existing and proposed terminals, the changing natural gas landscape has created opportunities for independent energy companies in the LNG and unconventional gas production sectors.

KNOWLEDGE & EXPERIENCE

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Hydrocarbon Processing | JULY 201563

Regional Report Two non-NOCs own majority stakes in terminals: Shenergy Group and JOVO Group, which became the first private Chinese company to hold a majority stake in a regasification terminal. Several state-owned municipalities, distributors and developers own minority stakes in existing LNG terminals. To replace coal with natural gas for power generation, additional pipeline and LNG import terminal infrastructure will need to be constructed. LNG imports are forecast to rise from 18 MMtpy in 2013 to over 60 MMtpy by 2020. Projects have been planned to raise the capacity to almost 80 MMtpy by 2018, but this could change with the development of the country’s shale gas reserves, which the US EIA estimates to be the largest in the world at 1.115 Tcf. The government promises to encourage shale play development by prioritizing land approvals, allowing tax-free imports of equipment and offering subsidies to explorers. The country is pumping more than 2 MMcmd of shale gas, with a 2015 production target of 6.5 Bcmy. China is also investing heavily in LNG projects in major gasproducing regions, such as North America (NA) and Russia. Shale potential. China’s shale gas industry developers and

regulators face many challenges. Most of the country’s proven TABLE 2. China’s major CBM basins and their capacities Name of basin Region

Resources, Tcf

% of total resources

Ordos

North

348.2

26.8

Qinshui

North

139.5

10.7

Junggar

Northwest

135.3

10.4

Dian-Qian-Gui

South

122.5

9.4

Erlian

North

91.1

7

Tu-Ha

Northwest

74.9

5.8

Tarim

Northwest

68.2

5.2

Tianshan

Northwest

57.6

4.4

Hailar

North

56.5

4.3

Source: Facts Global Energy.

Junggar Urumqi

Songliao

Turpan Tarim Beijing

Qaidam

China

Ordos Xian

Lhasa

Chengdu

Sichuan

Chongqing

Assessed basin Other basin

Guiyang

Subei Wuhan

Shaighai

Jianghan South Chian/ Yangtze platform Hong Kong

FIG. 6. Shale gas and oil reserves. Sources: Advanced Resources International Inc. and US EIA.

64JULY 2015 | HydrocarbonProcessing.com

shale gas resources are in the Sichuan and Tarim basins in the southern and western regions, and in the northern and northeastern basins (FIG. 6). Shale gas production grew by more than five times between 2013 and 2014 to reach 46 Bcfy. Again, while many small companies have entered the shale gas industry, NOCs own the vast majority of the resources and are partnering with various IOCs to develop them. Sinopec is boosting the production levels of its Fuling gas field and has reported that it could reach output of 353 Bcf by 2017. However, shale production is falling short of the original 2015 goal of 230 Bcf and the hope of replicating the NA shale boom. As seen in Europe, many Chinese shale plays are characterized by low organic content, meaning that producers will need to drill more wells to equal US production volumes. The limited availability of water resources, the geological risks and lowerthan-expected production rates have complicated the exploitation of unconventional gas reserves. It will be easier for China to focus on tight gas production to meet the government target for total gas output of 420 Bcm by 2020. Coalbed methane and coal-to-gas. The coalbed methane (CBM) and coal-to-gas (CTG) industries in China are in the early stages of development. Challenges to development include lack of technical expertise, water shortages, regulatory hurdles, transportation constraints and competition with other fuels and conventional natural gas. Despite CBM resources that are estimated at 1,300 Tcf, the cumulative proven geological reserves in 2014 were just 19.7 Tcf, representing only 1.5% (TABLE 2). The CBM transportation network is gradually being constructed. At present, CBM transportation pipelines have exceeded 1,632 km, 90% of which are in Shanxi province. Small liquefaction plants and trucks are also used to transport CBM to demand centers. However, this is insufficient to support high levels of CBM production and transportation. In 2013, only 596 MMcfd of CBM was used out of a total output of 1.3 Bcfd.9 Since the majority of China’s CBM production comes from the traditional coal mine extractions instead of surface operations, the utilization rate is much lower than those of other major CBM producers in the world (US, Canada and Australia). Steady growth of CBM production and consumption will be slow, so its impact on China’s LNG imports will not be felt until 2025 or later. After 2012, China rapidly approved CTG projects so that it could use its vast resources of coal to satisfy growing natural gas demand along the eastern and southern coastal areas. Looser government regulations and more favorable economics opened the door for the development of several CTG projects, but progress has been slow. Two operational CTG plants, Datang Group’s plant in the northern province of Inner Mongolia and Kingho Energy Group’s plant in northwestern Xinjiang province, produced only 75 Bcf in 2014, far short of the 530-Bcf target. The plants are running at low utilization rates due to technical problems and design issues. Three other projects are under construction, including Sinopec’s Zhundong project in Xinjiang province. China’s largest CTG project is scheduled to come online in 2017 and connect with pipelines carrying the natural gas toward eastern China. CTG projects face high capital costs required to develop the attendant infrastructure, scarce water resources and high levels

Regional Report of emissions. The government does not want the industry to overbuild with many small facilities, so regulations require that CTG plants operate at a capacity of at least 70 Bcfy. Downstream transportation. Although China has nearly

35,498 mi of main natural gas pipelines as of late 2013, the network is fragmented. NOCs, which operate the trunk pipelines, are investing in the downstream transmission system (FIG. 7) to supply demand centers and integrate local gas distribution networks. Imports of natural gas via pipeline have increased as production from Central Asia and Myanmar has grown and gas infrastructure has improved in the region. China has set a goal to achieve a pipeline network of 74,564 mi by 2020. CNPC is the key operator of the main gas pipelines, including the west-east pipelines, and holds nearly 80% of China’s gas transmission capacity.1 CNPC developed the ShanJing pipelines, three parallel pipelines linking the major Ordos basin in the north with Beijing and surrounding areas. The company’s Zhongwei-to-Guiyang gas pipeline, completed in 2013, delivers gas from the West-East pipeline network to markets in southwestern China. Sinopec operates long-haul pipelines from the Sichuan province to Shanghai and the northcentral region to Shandong along the northeastern coast, while CNOOC pipelines run mainly along the coastal areas of China. A momentous deal. After years of negotiations with Russia

over import prices and supply routes, China has agreed to pur-

chase 1.3 Tcfy of gas from Gazprom’s East Siberian fields. The price tag is $400 B over a 30-year period. The proposed Power of Siberia pipeline, which is expected to come online in 2018, will connect Russia’s eastern Siberian gas fields and Sakhalin Island to northeastern China. In November 2014, Gazprom and CNPC also signed a memorandum of understanding (MOU) for China to import 1.1 Bcfy from Russia’s western Siberian gas fields. Growing petrochemical demand. China plans to nearly dou-

ble its domestic ethylene capacity by 2025, reaching 33 MMtpy in 2020 and nearly 50 MMtpy by 2025. However, the country is exploring alternative supply options, such as coal-to-olefin (CTO) projects and imports, to satisfy domestic petrochemical demand. The US EIA reported that it is also seeing methanol-topropylene (MTP) and propane dehydrogenation (PDH) plant construction to meet strong demand for propylene and propyl-

FIG. 7. CNPC is adding new pipelines for the country’s downstream transportation sector.

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Hydrocarbon Processing | JULY 201565

Regional Report

TABLE 3. China’s PDH plants

Company

Capacity, 2014 propane metric consumption, Mtpy metric Mtpy

2015 (est.) propane consumption, metric Mtpy

Bohai Chemical

600

547.4

576

Ningbo Haiyue

600

240

505

Zhejiang Satellite

450

242.5

378

Sanyuan Petchem

450

59

346

Yangzijiang Petchem

600

–

270

Wanhua Chemical

750

–

337.5

Increased interest in the LPG sector. Since PDH plants

primarily use imported liquefied petroleum gas (LPG) as feedstock, demand in China has increased in recent years (FIG. 9). Sinopec’s Qingdao ethylene plant was slated to become the country’s first ethylene plant to utilize natural gas and light hydrocarbon feedstocks, like LPG and ethane. The 1-metricMMtpy plant was to be completed in 2017, but its future is now uncertain. Half of the feedstock will come from imported natural gas and ethane, and the remaining feed will be LPG produced from a nearby refinery in Qingdao. China’s future olefin plants might allow for higher feedstock flexibility for lighter hydrocarbons. Unipec has inked two propane supply agreements over a five-year period with Enterprise Products (0.5 metric MMtpy) and Phillips 66 (1 metric MMtpy). CNOOC is exploring the use of LPG for its upcoming 1-metric-MMtpy ethylene cracker in southern China’s Guangdong province. The increase in LPG imports may be due to what the Chinese call ‘deep processing.’ Deep processing plants could make more alkylate for the gasoline blending pool, or for the production of methyl tertiary butyl ether (MTBE). Notably, apparent gasoline demand in China grew as much as 13% year-on-year between April and May.10 Gasoline wholesalers in China have a tax incentive to alkylate butane to produce a gasoline blendstock or MTBE. Deep processing plants are finding alternative uses for their butane, primarily in the manufacture of isobutylene, maleic anhydride and alkylates. So far, China has not needed to import butane for deep processing purposes, which only uses 93 metric Mtpy of butane. Isobutane use, mainly for alkylation processes (as a precursor to MTBE), accounted for about two thirds of the total butane used for deep processing, according to FGE. This year, demand for butane as feed for deep processing plants is growing.10 Last year, China produced 23 metric MMtpy of LPG, of which: • 13.4 metric MMtpy were propane • 3.3 metric MMtpy were normal butane • 6.3 metric MMtpy were isobutane. China has traditionally allocated two thirds of this LPG for household use. This year, growing butane demand for deep processing has already impacted the LPG household allotment; it is estimated that only one third of the butane produced went to household use. Reasons that might necessitate butane imports into China include: • Maleic anhydride production needs 95%-purity normal

Others Diesel

FIG. 8. The Yantai chemical complex.

66JULY 2015 | HydrocarbonProcessing.com

LPG Fuel oil

Naphtha Asphalt

Gasoline Crude (RHS)

Apr 15

Mar 15

Feb 15

Jan 15

Dec 14

Nov 14

Oct 14

Sep 14

Aug 14

Jul 14

Jun 14

Apr 14

May 14

Imports, Mbpd

1,000 800 600 400 200 0

Jet fuel

FIG. 9. China’s imports of crude oil and petroleum products. Source: OPEC.

180 140 100 60 20 -20

Crude (RHS)

ene derivatives. Propylene consumption is expected to grow by around 3.1 metric MMtpy to 25.1 metric MMtpy in 2015. China has become the largest importer of propylene products, and around 20 new PDH plants are expected to come online by 2018, representing over 10 MMtpy of additional propylene (TABLE 3). Propane demand from PDH units is estimated to reach 2.4 metric MMtpy, more than double the 1.1 metric MMtpy in 2014. China operates four PDH units with a combined propylene capacity of 2.1 metric MMtpy: two 600-metric Mtpy units and two 450-metric Mtpy units, according to ICIS data. At an average run rate of 70%, the four plants will require approximately 1.8 metric MMtpy of propane. Two new PDH plants will boost capacity by a combined 1.35 metric MMtpy. Yangzijiang Petrochemical will start up its 600-metric Mtpy PDH unit at Zhangjiagang in Zhejiang province in the first half of 2015, while Wanhua Chemical commissioned its 750-metric MMtpy unit at Yantai in Shandong province in March (FIG. 8). These units are expected to run at 70% of capacity this year based on projected propylene demand. The country is also experiencing a surge in new methanol-toolefins (MTO) plants along China’s East Coast to offset increasing domestic methanol demand. Just as shale-derived ethane is changing the game in NA, lowcost coal from the inner regions of China is driving new investment in chemicals using CTO and coal-to-methanol (CTM) technologies. In 2013, China produced an estimated 18 MMtpy of ethylene, according to IHS, while the total equivalent ethylene demand exceeded 30 metric MMtpy. To avoid over-dependency on imports, 25 MMtpy of new ethylene capacity is planned. By 2016 and 2017, 31.9 MMtpy of new ethylene, propylene and butadiene capacity could be built in China, potentially exceeding demand growth and leading to a decline in capacity utilization rates in the years ahead.

Regional Report butane, but China does not produce a large enough volume of the quality required. • Most new plants are located in eastern China and Shandong province, where LPG production already does not meet residential demand. • Many of these plants are independent players that do not have access to bulk butane volumes from state-owned refineries.10 Setting higher standards for new petrochemical projects. To boost efficiencies and ease public and international opposition to projects that are perceived as harmful to local inhabitants and the environment, the NDRC has published a petrochemical industry plan with higher standards. The Chinese government has been faced with increasing protests against the construction of petrochemical facilities in heavily populated areas. Accordingly, the NDRC’s stringent standards for new petrochemical facilities encompass several facets: • Newly built crude distillation units (CDUs) must have a production capacity of no less than 15 metric MMtpy, or 300 Mbpd. • Ethylene units should have a minimum capacity of 1 metric MMtpy. • Fuels produced by the new refining units should meet the equivalent of Euro 5 emissions standards. • Petrochemical complexes should be built on abandoned land, islands or peninsulas, and should have a crude

processing capacity of no less than 40 metric MMtpy (800 Mbpd) and span at least 40 km.2 • The facilities will have 6 MMcm of crude and oil product storage capacity. • New paraxylene (PX) units should reach an annual capacity of at least 600 metric Mtpy, while new methylene diphenyl diisocyanate (MDI) units should have a capacity of least 400 metric Mtpy. PX and MDI projects must also meet pollutant emissions standards.11 Fuel demands. The growth in oil product demand has slowed since a short growth spurt in 2010. Slowed economic growth, decreased production from the coal and mining sectors that use rail and trucks to transport products, greater efficiency in heavy vehicles and the increased use of gas-powered vehicles are all contributing factors to the slowdown in fuel demand growth. Gasoline. With an estimated 23% share in 2014, gasoline is

still growing as China’s middle class expands and car sales rise. Since Chinese drivers are less sensitive to changes in pump prices, prices are not likely to have a near-term impact on China gasoline sales. The drop in international crude prices does not necessarily translate to pump prices; the NDRC raised retail gasoline prices for the first time after 13 consecutive fuel price reductions since July 2014, according to FGE. Increased traffic congestion and its resultant lower mileage driven, car purchase restrictions and the government’s push for

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Hydrocarbon Processing | JULY 201567

Regional Report more fuel-efficient vehicles are all expected to limit gasoline demand growth to around 7% in 2015.12

Demand growth in 2015 is expected to be flat as the freight transport and construction sectors continue to soften.

Kerosine/jet fuel demand. Growth in kero/jet demand slowed

Fuel oil. Lower bunkering demand and the increased use of

considerably in 2014 to 5%, from 13% in 2013. The drop for jet fuel was, in part, due to passenger traffic utilizing high-speed rail (HSR) instead of air options for short-to-medium trips. The reinstatement of the value-added tax (VAT) on jet fuel by the Chinese government in 2013 also took a toll on jet fuel imports. An increase of up to 6% of kero/jet demand could be brought about by lower fuel costs and reduced air fares, and the elimination of fuel surcharges by air carriers. With fuel costs accounting for 30% of air travel costs, reduced jet fuel costs may somewhat reduce the incentive to raise overall fuel efficiency, thereby providing further support to jet fuel use.12

natural gas have caused a drop in fuel oil demand, as well. Consumption tax increases are expected to reduce imports of fuel oil and increase prices for teapot refineries, which are now increasingly substituting imported crude oil as feedstock. Looking ahead in 2015, China’s real petroleum products demand growth is projected to pick up slightly to 2.7%.3 As the country moves forward and pursues its ‘energy revolution,’ it faces pressure to not only keep pace with the needs of an evergrowing population and industrial infrastructure, but also to improve its environmental practices and achieve greater longterm, sustainable growth.

Gasoil. Several factors have contributed to a drop in gasoil de-

mand in the last few years, including declining growth and economic structural changes, slower growth in heavy commercial vehicle use, efficiency gains in freight transport, the government’s goal of reducing overcapacity in high-polluting heavy industries, and reduced diesel usage in mining, trucking and rail activities for a sagging coal industry. However, gasoil remains the most widely consumed oil product in China. According to the US EIA, sales of commercial vehicles plunged nearly 11% year-on-year in 2014, down from 3% growth in 2013 and peak growth of 32% over the 2009–2010 period.

LITERATURE CITED US Energy Information Administration (EIA), “International energy data and analysis: China,” May 14, 2015. 2 Facts Global Energy (FGE), China energy series: oil edition, “Recent leadership change: who’s who in the Chinese government concerning the oil and gas sector,” July 2, 2013. 3 Organization of the Petroleum Exporting Countries, “Monthly oil market report,” May 2015 . 4 FGE, China oil & gas monthly: data tables, March 2015. 5 Nichols, L., S. Romanow, A. Blume and B. DuBose, Hydrocarbon Processing’s HPI Market Data 2015, “Global construction and investment,” “Refining,” “Natural gas/LNG” and “Petrochemicals.” 1

Complete literature cited avaibale online at HydrocarbonProcessing.com.

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Managing Editor Hydrocarbon Processing

Founder and Chief Executive Officer Pink Petro™

Project Management C. RENTSCHLER and G. SHAHANI, Linde Engineering North America, Blue Bell, Pennsylvania

Better risk-management methods ensure project success

What is risk? In simple terms, risk is defined as an uncertain event or condition that, if it occurs, has a positive or negative effect on at least one project objective. There can be many causes for risks, and great efforts are typically undertaken to define them. In a global market, there are risk drivers, such as oil price volatility, stock market, political unrest, geopolitical events (as in 15

Natural gas wellhead price, $/Mcf

The North American renaissance. Five years ago, during the “great recession,” the media was focused on the global economic downturn. In particular, the refining and petrochemical industries were impacted by highly fluctuating global supplyand-demand conditions, extreme price volatility and tremendous market uncertainty. There had been numerous plant closings, project cancellations and employee layoffs. New project development and capital investment were greatly curtailed. Today, the media is much more upbeat due to the discovery and exploitation of shale gas and light tight oil in North America (NA). Vast quantities of natural gas or shale gas are being recovered due to advances in horizontal drilling and well fracturing. Shale gas has become an attractive fuel and chemical feedstock. The advent of inexpensive shale gas has been referred to as a potential game changer, which is making NA energy independent and revitalizing manufacturing, particularly in the refining and petrochemical sectors. In a recent article, new capital spending in the hydrocarbon processing industry (HPI) was estimated to increase to $77.7 B.1 Some of this growth has been due to inflation in the cost of raw materials, equipment and construction. However, a sizable portion of the growth is due to building larger, more complex projects, thus taking advantage of economies of scale. Two recent scenarios highlight how the economy can change drastically in the short run from one extreme to the other. A good indication of volatility is depicted by the price of natural gas (FIG. 1) and crude oil (FIG. 2). Similar fluctuations in the price of other commodities from gasoline to ethylene have exacerbated market turmoil, making investment decisions difficult. The price of essential construction materials (stainless, alloys, etc.) has also experienced a high degree of price volatility. This has impacted the actual costs of project equipment.

The challenge for the petrochemical and refining sectors is to manage their businesses through the peaks and valleys and to make informed investment decisions. Typically, investments made at the bottom of an economic cycle perform better than those made at the top. These investments have to be carefully conceived, developed and executed. Larger complex projects are accompanied by a corresponding increase in schedule and cost risk. While it is not possible to eliminate risk altogether, it is possible to manage risk effectively.

10

5

0 2002

2004

2006

2008

2010

2012

2014

Source: EIA

FIG. 1. US natural gas price.

Cushing, OK, WTI spot price FOB, $/bbl

Management of project risk is a challenge under normal times. However, this crucial activity is exasperated in complex projects as a result of the shale gas revolution. Pundits in successful project management nearly all point to successful risk management (RM) as a key ingredient for successful project execution. Tight schedules and insufficient resources are at the heart of the problems as projects “race” to capitalize on the less-expensive feedstocks or fuel. The authors discuss the risks across elements of a project and assess impacts in recent years. Examples demonstrate how risk can be successfully managed. In addition, alternative strategies for dealing with risk will be discussed.

200 150 100 50 0 1990

1995

2000

2005

2010

2015

Source: Thomson Reuters

FIG. 2. Crude oil price. Hydrocarbon Processing | JULY 201569

Project Management Russia and the Middle East) and new technology. On the local level, risks can be categorized as technical, cost, schedule, client, contractual, weather, financial, environmental or people-related. Despite the exhaustive efforts that generally go into defining risks, there are always subsets that are unknown. Donald Rumsfeld said it very aptly, “As we know, there are known knowns; and there are things we know we know. We also know there are known unknowns; that is to say we know there are some things we do not know. But there are also unknown unknowns—the ones we don’t know we don’t know.” The last category, the unknown unknowns, is the most vexing for companies executing major projects. Risks can be looked at from different perspectives. Certainly, most risks are viewed as bad and threats to a project. However, there are actually risks that can produce an upside. Currency risks represent one area where this can occur during international projects. If exchange rates change favorably during the project, there may be a benefit to do fabrication in areas not planned during the bid stage. In addition to risks being good or bad, another perspective is big or small. Certainly, the focus should be on the larger risks with limited focus on small risks. Finally, risks can be looked at from an impact/probability standpoint, as shown in FIG. 3. Based on defined criteria for impact, it may be decided to focus efforts on high-probability, high-impact risks. In a recent article, the importance of risk management (RM) was stressed.1 This area was highlighted as a key factor in determining the success of a project. In fact, tolerance to risk drives many project elements, including contracting approach. The method in which the owner chooses to execute a project requires significant forethought to satisfy the risk tolerance of both the owner and the executing company. Traditional RM. RM is highlighted as one of the key success

factors for a project.2 Some have said that RM is probably the most difficult aspect of project management. A project manager must be able to identify the root causes of risks and to trace these risks through the project to possible consequences. RM techniques have been described in numerous publications and generally include: • Risk identification • Risk assessment • Risk mitigation • Risk monitoring. Impact Low high

Risk identification is the first and perhaps the most important step, since an effort is made to identify the source and types of risks. This permits a more structured approach to following steps in RM. Remember: Risk identification is an iterative process because new risks may arise through the course of the project, while others may drop out. Risk assessment can be performed by qualitative or quantitative analysis, or both. Qualitative analysis assesses the impact and likelihood of the risks and develops prioritized lists of risks for further analysis or direct mitigation. Quantitative risk analysis is more refined and attempts to estimate the frequency of risks and the magnitude of their consequences. This can be done by tree analysis, cost-risk analysis or Monte Carlo simulation. Once risks have been identified and assessed, the next step is to define a risk mitigation plan. There are several means to address risks, including: avoid the risk, reduce the risk, transfer the risk, share the risk or accept the risk (do nothing). Risk avoidance strives to eliminate the risk by going with a proven technique or technology rather than with a more risky technique that could be cheaper if everything worked to perfection. With risk reduction, a means is determined to “soften” the risk through the involvement of outside influences, such as currency hedging or involving industry experts. Risk transfer is a risk-reduction technique that transfers risk from the project to another party. Purchasing insurance is a common means of transferring the risk to another party, which, in this case, is the insurance company. Transferring risk to a vendor is another possibility. Risk sharing generally involves partnering with another party to share the responsibility. This technique is particularly useful when the other company has expertise or experience that the project team does not have. Accepting the risk is likely to occur in cases where the risk is so small that the effort to do anything is not worthwhile. Some common risks in the different phases of an engineering, procurement and construction (EPC) project, along with the appropriate mitigation plan, are presented. Risk alternatives often involve increased costs. Funds used to address unforeseen events are called contingency funds. They are generally set aside in a budget as a separate line item. The final step in RM is to continually monitor risks to identify any changes related to new risks, risks being dismissed or the magnitude of risks being modified. It is prudent to hold regular risk review meetings through the project execution phase to further assess risk probability and impact, and to de-

TABLE 1. Capital project risks and mitigation plan

High high

Risk

Mitigation

Engineering Workload could delay project schedule

Shift engineering to other centers Pre-order long-lead components

Probability Procurement

Low low

High low

Equipment prices could become higher due to currency

70JULY 2015 | HydrocarbonProcessing.com

Hedge against currency variations

Construction Labor availability could add cost and delays

FIG. 3. Impact—probability matrix.

Fabricate where currency is favorable

Fabricate more modular systems Sequence to minimize field hours

MOVE

Beyond

Limitations

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Project Management

Recent projects The EPC market has been very active in NA. The Linde Group is investing over $250 MM in a state-of-the-art air separation unit (ASU) and the expansion of a gasifier train in La Porte, Texas. When these plants come fully onstream later in 2015, they will constitute the largest natural-gasbased gasification complex for petrochemical production in the world. Separately, a 600-tpd ammonia plant is being built in Rock Springs, Wyoming, for J.R. Simplot. These large capital investments are being carried out in a relatively “heated” market where construction labor is relatively scarce, schedules are extremely critical and project costs have to be carefully controlled. These challenges can be met by applying the techniques discussed in this article. Over the years, similar large projects have been executed under relatively difficult conditions. FIG. 4 is an extremely large ASU that was constructed on the US Gulf Coast. termine if the magnitude of contingency funds are adequate. Corporate senior management must always know the worstcase scenario for a project, and a current risk plan is a key ingredient to providing this information. New perspectives. As with any technique, the success is highly dependent on the rigor to which principles are followed. RM must be applied from proposal inception through completion of a project. Too often, risks are identified early in a proposal and continual follow-through is neglected. This only partially accounts for the effects, and it does not provide the insight for the addition of further risks or deletion of risks that do not materialize. A key to successful RM is the continual engagement of experienced people in the process. Finding the unknown unknowns is the challenge for embracing project risks. This requires participants to ask the tough questions and to have foresight into the future. This is best done by veteran people. Since there are only a limited number of experienced people, these individuals should be used strategically within the process. One idea is to have highly seasoned people circulate across a few projects, thereby getting the greatest impact from the RM process, but also allowing for a “lessons learned” exchange across projects. Innovation and advancements in technology are having a dramatic effect on the way engineering projects are executed. This technology boon has produced a very positive effect on RM. For example, it is now possible to access the virtual model live on the jobsite and view subcontractor installations to reduce risk in conflicts and clashes. Drones are being used on construction sites to monitor safety and other hazard risks. Robots can ensure highquality and timely production of routine construction tasks. These and other technology areas can benefit any RM plan. In particular, Internet and software are having a dramatic effect on productivity and RM. General Electric CEO Jeffrey Immelt said at the GE Intelligent Platforms Business 2014 User Summit, “All companies need to become Internet and software companies. The industrial world is changing dramatically, and 72JULY 2015 | HydrocarbonProcessing.com

FIG. 4. Large ASU constructed on the US Gulf Coast.

those companies that make the best use of data will be the most successful.” The more data routinely taken on a project, the greater likelihood that the project risks can be controlled, and getting all of this data is now possible with proven Internet and software capabilities. Finally, RM must be driven from the highest level of an organization. How risks are handled represents the difference between a successful (profitable) project and one fraught with problems. Some organizations have adopted a senior-level position, such as vice president of RM, to ensure focus and commonality of approach in this area. Whether or not the position is formalized to this degree, considerable senior-level focus is needed in RM, particularly as projects become more challenging. Options. Recent years have demonstrated the volatility that can exist with large refining and petrochemical projects. These projects often face enormous risk, and how this risk is handled represents the difference between success and failure. It is important to approach RM in a rigorous manner from project concept to execution. This involves the four-step process of risk identification, assessment, mitigation and monitoring. It is also important to have more seasoned managers and engineers involved so that the best minds are involved in devising and implementing an effective risk plan. Finally, technology offers many opportunities to collect and monitor data crucial to successfully managing risk. This provides advantages that did not exist in the past, and can be a deciding factor in successful RM. LITERATURE Rentschler, C. N. and G. H. Shahani, “Successful project development and execution: Beyond EPC to ‘T-EPC,’” Hydrocarbon Processing, December 2014. 2 Project Management Institute, Guide to the Project Management Body of Knowledge (PMBOK Guide), 4th Ed., Newtown Square, Project Management Institute, 2008. 1

BIBLIOGRAPHY Culp, S., “Managing capital projects in a high-risk world,” Forbes, May 29, 2012. Jutte, B., “10 golden rules of project management,” Project Smart, 2014. Merritt, G. M. and P. G. Smith, “Techniques for managing risk,” Field Guide to Project Management, 2nd Ed., Chapter 13, 2004, John Wiley & Sons Inc., New York, New York. Merrow, E. W., Industrial Megaprojects, Concepts, Strategies and Practices for Success, John Wiley & Sons, New York, New York, 2011. Special Advertising Section, Engineering News-Record, November 10, 2014. Symonds, M., “The problem with project risk management,” IT Consultant, August 6, 2013. Turbit, N., “Basics of managing risk,” The Project Perfect White Paper Collection.

Gas Treating D. ENGEL and H. BURNS, Nexo Solutions, The Woodlands, Texas; and B. SPOONER, Amine Experts, Kemah, Texas

Improve LPG treating via advanced amine-solvent recovery technologies Processing liquefied petroleum gas (LPG) in refineries using amine units has its challenges with respect to hydrogen sulfide (H2S) and mercaptans removal. Amine sweetening of LPG can also result in major amine solvent losses. Such losses are not only confined to the loss of the amine solvent itself, but they can also have a negative impact on downstream processes, such as caustic treaters, molecular (mol) sieve dryers and alkylation units. Often, the end result is that the final hydrocarbon product is out of specification. Copper-strip corrosion analysis is a common method that determines whether a final product is in specification. A difficulty for hydrocarbon processing industry (HPI) plants is that amine carryover is not understood well (beyond soluble losses), and there is a lack of good analytical techniques to detect amine carryover in an LPG sample cylinder. This article will discuss capacity and throughput improvement in an LPG treating unit, made possible by implementing an amine recovery program. The integrated use and benefits of new techniques for testing and quantifying amine losses, innovative technologies for amine recovery and improvements for increased plant processing capacity are also presented.

BACKGROUND A US refinery added a caustic treating unit downstream of its existing LPG amine treater for deeper sulfur removal.1 This was done to consistently ensure passing of copper strip testing. While this enhanced the LPG quality in terms of sulfur contamination, the caustic treating unit was experiencing intermittent foaming episodes, which, if left unattended, would affect the LPG product quality. The plant was also experiencing amine losses based on inventory replacement, and it was believed that amine carryover was what was causing the instability of the caustic treating unit and amine losses. To help mitigate the instability of the caustic-treating unit, an emulsion breaker was continuously added to the LPG. Despite these operating issues, the refiner also wanted to enhance the throughput capacity of the LPG system. Increasing LPG flowrates would only worsen the existing amine losses. To increase LPG production rates, several items needed to be achieved and these included: • Determining if the current amine absorber had the treating capacity for the increased flowrates, including an engineering review of the LPG and amine distributors

• Preventing carryover amine from contaminating the caustic treating system • Recovering any amine carried over with the treated LPG • Removing the need for continuous chemical injection. To determine if the amine absorber had the capacity for increased LPG flow, the tower was evaluated, using an advanced simulation software package.2 This included a review of fluid velocities to determine if the values were within industry-accepted ranges. Contaminants add problems. Amine carryover with treated LPG is often not a fully understood phenomenon. Sometimes it is as simple as a treating tower being operated above design capacity. Often, there are many situations where all operational conditions are in normal ranges, and amine losses and carryover are still experienced. This can be a result of contaminants such as surfactants, inherent design deficiencies in the treater, stabilized emulsions, fouling, etc. Among the various complications, amine units using methyldiethanolamine (MDEA) will cut back the typical 50% concentration in water to 40% or less to avoid emulsion formation and excess losses of MDEA when the amine system is tied to other gas treating absorbers. Wash systems. Using water-wash systems as a method of amine recovery after amine treating is common industry practice. However, the trouble with surfactants and emulsions is that a conventional water-wash tower or drum may still not recover enough of the amine due to these devices’ low separation efficiencies. Conventional water-wash equipment will usually incorporate a mesh pad, but this is still not considered a highefficiency separator and emulsions are still capable of passing through these devices unimpeded. Even oversizing the separator to allow for more residence time has no significant effect, and it only results in higher costs for equipment that is already large and expensive. Designing a system that is capable of highefficiency contact combined with high-efficiency separation was the task for this project.

SIMULATION STUDY A simulation study was conducted to determine the treating capacity of the LPG/amine absorber. The system was composed of the amine treater, a knockout (KO) drum and an LPG coalescer for separating the amine that was carried over. The amine used was MDEA. With the issues experienced in the Hydrocarbon Processing | JULY 201573

Gas Treating caustic treating unit, it was believed that the KO drum and coalescer were lacking in the separation efficiency necessary for this unit. The first step was to understand if the treater could still remove the H2S in the LPG to the desired specification at the higher flowrate of 2,000 bpd from 1,259 bpd. The amine unit operated with the LPG-amine solution interface at the top of the column. The amine is the continuous phase, and the LPG is routed into the bottom of the treater, dispersed, and bubbled up through the amine solution column, which was operated at 205 psig and had an internal diameter of 29 in. with 16 ft of packing. LPG compositional analyses. The feed LPG composition to the amine unit was provided by the facility and was used as the basis for this study. TABLE 1 summarizes the various components of LPG stream. LPG system review. The data provided by the facility was used to set up a model of the LPG treater (A2005), using the simulation software package with two LPG streams: liquids recovery unit (LRU) and crude.2 FIG. 1 illustrates the LPG system modeled. TABLE 1. LPG stream composition Component

LPG from crude, mol%

LPG from LRU, mol%

Methane

0.3

0.0

Ethane

3.0

10.0

Propane

25.7

35.1

1-Butene

0.1

0.13

n-Butane

50.64

10.0

Isobutane

20.1

20.1

Isopentane

0.0

20.1

n-Pentane

0.0

2.5

n-Hexane

0.0

2.0

Carbonyl sulfide

0.01

0.01

Carbon disulfide

0.01

0.0

Methyl mercaptan

0.01

0.01

Ethyl mercaptan

0.02

0.01

Hydrogen sulfide

0.25

0.05

TABLE 2. LPG amine treated operational data Parameter

Actual flow

MDEA strength, % MDEA lean loading*

30

30 0.0007 mol/mol

110

110

1,250

2,000

104

104

2,500

2,500

Inlet crude LPG flow, bpd Inlet crude LPG temperature, °F Inlet crude LPG H2S content, ppm Inlet LRU LPG flow, bpd Inlet LRU LPG temperature, °F Inlet LRU LPG H2S content, ppm *Taken from the amine vendor analysis

74JULY 2015 | HydrocarbonProcessing.com

Simulation and flow calculation results. The two-theo-

retical-stage simulation requires higher amine circulation rates to achieve the same level of H2S removal as three theoretical stages. To treat the LPG down to below 10 ppm of H2S, simulations predict the optimum circulation rate of 30% MDEA in the two-theoretical stage case is 120 bpd or 3.5 gpm. The three-theoretical-stage simulations require an amine flowrate of 70 bpd or 2.04 gpm. Combined liquid flux conditions using two and three theoretical stages is calculated in TABLE 3. Both total liquid flux values were within the maximum recommended guideline. TABLE 4 shows the various simulated parameters for the increased LPG flow into the amine treater: Treated LPG

Maximum flow case

0.0007 mol/mol

Lean amine temperature, °F

LPG treater operational data. The operating data for the LPG amine unit treater is summarized in TABLE 2. The two LPG feed streams combined to yield a feed temperature of 95°F. This data indicates a 15° temperature difference between the lean amine and the combined inlet LPG stream. A cooler amine temperature would benefit the performance of the amine in the LPG contactor (~105°F) for reaction energetics. The differential temperature between the two liquids should be as low as feasible; down to 5°F on the blended product if this will not affect any gas absorbers. Determining the optimum circulation rate for LPG treaters is based on several different criteria: 1. The recommended ratio of amine to LPG for this treater is > 1:10. This is fine-tuned based on the treated LPG H2S content. 2. The recommended “best practices” guideline is a combined cross-sectional liquid flowrate (LPG + MDEA) of < 15 gpm/ft2. This is to help minimize amine entrainment in the LPG. References such as the GPSA Data Book allow 20 gpm/ft2, so this guideline is not out of the realm of published values. Unfortunately, there is no accurate way to concretely determine the number of “theoretical stages” in the LPG tower with the used simulator. Two 8-ft sections of packing are equal to roughly 2.5 theoretical stages (determined by the manufacturer), which is not possible to enter into the simulator. Instead, simulations have been run at both two and three stages. The actual operation should be somewhere inbetween the two results.

2 3 LRU

Lean MDEA

5 A2005

Mixer 1

650

1,000

80

80

500

500

Crude

4 6

FIG. 1. LPG amine absorber.

Rich MDEA

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Gas Treating • The treated LPG will contain 7 ppm–8 ppm of H2S in either the two- or three-theoretical-stage scenarios. Both are below the 10-ppm specified maximum specification. • With the inlet LPG containing 0.12 mol% H2S, and the amine circulation rate at 70 bpd–120 bpd, the calculated rich amine loading was between 0.07 mol/mol and 0.12 mol/mol. • “Equilibrium loading” refers to the theoretical maximum loading achievable between the H2S and amine. This loading is dependent on the temperature and pressure conditions in the treater and the H2S concentration of the inlet LPG. It is normally recommended not to exceed 80% of equilibrium to avoid the risk of corrosion and subsequent fouling. The H2S equilibrium loading was 36%–61%, which was well below the recommended maximum, indicating the tower should not suffer from corrosion. It also indicates that the circulation rate of the amine was appropriate. The current treater has the capacity to remove the H2S levels to the desired specification of 10 ppm or less.

LPG TREATER INTERNAL COMPONENTS Once it was determined that the absorber had the necessary treating capacity for H2S removal, a review of the internals was necessary. Treater packing. The packing itself should be 2 in. in diameter, to maximize available liquid flow area. At present, the LPG treater uses random packing (high-performance packing in a saddle-type configuration), which is commonly used. For the packing to function correctly, it must be kept clean at all times. TABLE 3. Liquid flux conditions using theoretical stages Two theoretical stages

Three theoretical stages

55.7 (1,910)

55.7 (1,910)

3.5 (120)

2.04 (70)

Total liquid flow (LPG + MDEA), gpm

59.2

57.7

Cross-sectional area of 29-in.-diameter treater, ft2

4.58

4.58

Total liquid flux, gpm/ft2

12.9

12.6

LPG flowrate, gpm (bpd) MDEA flowrate, gpm (bpd)

TABLE 4. Simulated parameters for Increased LPG flowrates Simulation results—LPG flow conditions Two theoretical stages

Three theoretical stages

120

70

0.07

0.12

36

61

8

7

0.0046

0.0045

109

109

30% lean MDEA circulation rate, bpd Rich-amine loading at low flow, mol/mol H2S equilibrium loading, % H2S in treated LPG, ppm MDEA in treated LPG, lbmol/hr Other sulfur species, ppm

Note: The maximum values of H2S in both the LRU and crude feeds were used in the simulations. All other component values were the normal values.

76JULY 2015 | HydrocarbonProcessing.com

Therefore, full-flow filtration of the lean amine feeding this treater is recommended. The recommended packed bed height is between 8 ft and 12 ft. The tower’s bed heights are 8 ft. If the packing bed height is too high, then the LPG bubbles can coalesce and form large droplets. This reduces the contact efficiency between the LPG and amine. Each packed section must have effective redistribution to re-disperse the LPG droplets and correct any channeling, which may have occurred in the previous bed. The most common packing material is 316 stainless steel. When using metal packing, it is important to ensure that the metal is fully wetted by the amine before bringing any LPG flow into the tower, as metal can be wetted by either amine or LPG. LPG distributors/packing support tray. The distributor/ support tray is very important, not only for supporting the packing that sits on it but also to control the LPG droplet size. The LPG pools below the plate and bubbles upward through the packing. The amine flows downward through several pathways (downcomers) to below the LPG directly under the plate. The recommended design velocity through the LPG distributor is 70 ft/min with an operational window of 30 ft/min to 75 ft/min. Excessive velocity of the LPG droplets can create emulsions, whereas low droplet velocity can result in insufficient distribution and entrainment of LPG in the rich amine. The distributor has hole diameters of 124 in. × 0.44 in. The distributor must be checked for an LPG flowrate of 2,000 bpd, or 58.4 gpm. To calculate LPG droplet velocity for this configuration:

Cross-sectional area = (124 × π × (0.44 in./12 in./ft)2/4) = 0.13087 ft2 Design LPG flow = (58.4 gal/min) × (ft3/7.48 gal) = 7.81 ft3/min Design velocity = 11.75 ft3/min ÷ 0.13087 ft2 = 59.68 ft/min The total LPG orifice velocity is below the maximum acceptable guideline of 75 ft/min. Nevertheless, the LPG distributor drawing states it was designed for an LPG flow of 46.7 gpm. If there is a case where the LPG flow is increased beyond 2,500 bpd (nearing the limit of 75 ft/min), then the plant should consider installation of a new inlet distributor plate. Ladder-type distributors are most commonly used to inject the LPG into the tower, which is then dispersed through the smaller openings on the packing support tray. Adequate space must be available below the distributor and the rich amine level to minimize LPG entrainment. It is recommended that amine have a 10-min residence time in the bottom of the treater before leaving to the downstream flash tank. It was also suggested that the LPG treater be retrofitted with a ladder-type inlet distributor consisting of a series of parallel tubes fed by a central pipe. This is a commonly used design and should be adequate. The orifices in the parallel tubes must be directed downward across the entire cross-sectional area of the packing.

LPG/AMINE SEPARATION, TESTING AND AMINE RECOVERY Once it was determined that the amine treater did not need to be replaced and had the capacity for higher flowrates, then

Gas Treating the issue of instability in the caustic treater needed to be addressed.1 At maximum flow conditions of 2,000 bpd, the treated LPG will certainly carry more amine with it. To address the amine carryover challenges, the plant installed an advanced amine recovery system.3 This recovery system has two functions: recovery of free and emulsified amine, and recovery of soluble amine in the treated LPG. This system would, in turn, protect the downstream caustic treating unit from any amine contamination.1 The advanced amine recovery system, as a skid, incorporates a filtration section for particle removal followed by water injection, mixing and contacting/separation to extract free, emulsified, and a portion of the dissolved amine from the LPG product.3 The advanced amine recovery process was chosen for its high efficiency of mass transfer coupled with its ability for high-separation efficiency in a small equipment envelope.3 LPG sampling procedure and MDEA analysis. Once the

recovery skid was in place and operating, qualification of its performance was needed to ensure amine would not upset the downstream caustic treating unit.1 As mentioned earlier, detecting amine in LPG is difficult. The sampling procedure was specifically designed to accommodate the analytical method selected for this application. Since there is no direct method to properly quantify amine concentration in LPG, an indirect method was used. The method involves transferring the amine by extraction into a suitable immiscible solvent for analysis by ion chromatography (IC).

The sampling was performed by collecting LPG into stainless steel cylinders filled with a predetermined amount of distilled water. Cylinders were then exposed to low vacuum to properly accommodate the subsequent LPG sample volume. The cylinders were equipped with internal mixing elements to maximize mass transfer between the two liquid phases. A total of four cylinders were used to collect the LPG samples, at two different water injection rates. During the initial system operation, the water injection rate was adjusted to 1.5 gpm prior to LPG sample collection. The second sets of LPG samples were collected at a water injection rate of 1 gpm. Each cylinder was attached to the sampling port and filled with LPG. The water phase was removed from the cylinder, and the remaining LPG was vaporized into a known volume of distilled water (100 ml) to capture any residual amine that might be left. The empty cylinder was further rinsed internally with distilled water (30 ml to 50 ml) to capture any other possible amine traces. All aqueous samples were processed by IC analysis for amine determination. The analysis was performed using an advanced column and an isocratic methanesulfonic acid (MSA) eluent.4

SAMPLING AND AMINE RECOVERY RESULTS The results of the various water samples analyzed by IC are shown in TABLE 5. The concentration represents the total methyl MDEA mass contained in the LPG as determined by combining the results of the extraction water, purge water and

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Gas Treating TABLE 5. MDEA concentration in the LPG stream at the inlet and outlet of the advanced amine recovery system3 Sample

1-gpm injection rate 1.5-gpm injection rate

Inlet LPG amine concentration, ppmm

110.3

179.2

Outlet LPG amine concentration, ppmm

20.6

21.1

Amine-recovery system efficiency, %

81.3

88.2

TABLE 6. Amine recovery at 2,000 bpd of LPG and 1.5-gpm water injection rates Parameter

Amine-recovery system inlet

LPG flow, gpm

Amine-recovery system outlet

58.3

58.3

LPG mass flow, lb/min

253.0

253.0

Amine concentration, ppmm

179.2

21.1

Amine flow, lb/day

65.3

7.7

rinse water fractions. The recovery efficiency associated with a water injection rate of 1.5 gpm is higher compared to the 1-gpm water injection rate. This is expected, as it is generally observed that recovery increases at higher water injection rates. The inlet amine carryover was higher from the first sampling to the second by nearly 60%. This could be part of the normal fluctuation of the process, but the higher water injection rate caused a higher percent of amine recovery (by 9%) with a similar residual amine concentration in the LPG effluent. At a 1.5-gpm water injection rate, the amine recovery was calculated to be at 88.2%. The expected solubility of amine into the LPG is between 90 ppm to 150 ppm. The recovery system is able to remove the amine concentration below soluble levels. TABLE 6 highlights what it means in terms of amine recovery under normal operation at a 1.5-gpm water injection rate. The following table is based on an LPG flow of 2,000 bpd and an LPG density of 0.52 kg/l. TABLE 6 shows that a significant amount of amine is being recovered daily by the amine recovery system (89%). The recovery amount is the difference between the amine recovery system inlet and outlet. This equates to 57.6 lb/day of amine recovered. The recovered amine can be, in principle, added back to the amine unit, minimizing losses. Options. The first phase of the evaluation determined the

treatment capacity of the LPG amine contactor for a higher flow up to 2,000 bpd. The treater was simulated.2 It was concluded that the treater was able to reduce the H2S content below the 10 ppm specification. The combination of the detrimental impacts on the caustic treater and higher amine-treater flowrates required use of an amine recovery system. The advanced amine recovery system was installed in the treat LPG stream, at the outlet of the amine unit.1, 3 The system was selected for its high amine recovery efficiency and effective phase separation, in addition to a small equipment envelope and low cost. Comprehensive performance testing of the system was conducted using equipment designed specifically for LPG sampling and amine extraction. The sampling technique and 78JULY 2015 | HydrocarbonProcessing.com

analysis of amine extracted from the LPG yielded accurate quantification of both amine losses and amine recovery using the advanced amine recovery system.3 The test data showed that the recovery system was able to remove the MDEA amine solvent in the treated LPG to below soluble limits. After the advanced amine recovery system was installed and operated at 1.5-gpm injected water rate, the amine recovery efficiency was nearly 89%.3 This translated to a savings of about $120,000/ yr only in amine solvent. However, not only was the MDEA amine recovered, but the various impacts downstream at the caustic treating unit and other units were greatly reduced.1 An evaluation of the amine system equipment design and of the operation of that equipment in comparison to design guidelines and best practices was also conducted. It was recommended to change the packing rings and upgrade the inlet LPG distributor in addition to adjusting the lean amine temperature. NOTES The THIOLEX process licensed by Merichem uses the FIBER FILM Contactor as the mass-transfer device and caustic as the treating reagent to remove acid gas and mercaptan compounds from liquid and gas hydrocarbon streams. 2 ProTreat is a licensed simulation software. 3 The Exion system for amine recovery was designed to recover carried-over amine and to extract residual dissolved amine in LPG streams; the process is licensed by Nexo Solutions. 4 A Dionex IonPac column. 1

DAVID ENGEL, managing director of Nexo Solutions, has more than 20 years of industrial experience in a variety of areas, including chemical synthesis, corrosion-resistant materials, sensors, light-to-energy conversion, membranes, nanotechnology, separation technologies, analytical methods and chemical additives. Dr. Engel holds 17 US patents covering a wide array of engineering inventions, and is the author of several technical and scientific papers. He has developed business and technology for Eastman Kodak, Eli Lilly, Pentair, General Electric and Sulphur Experts. Dr. Engel has specialized in advanced process systems and multicomponent separation methods for removing or mitigating contaminants in process streams. He is the co-founder of Filtration Experts, a division of Sulphur Experts, and managing director of Nexo Solutions. Dr. Engel holds a BS degree in industrial chemistry and a PhD in organic chemistry, and is Six-Sigma certified. He is member of the American Chemical Society and the Gas Processors Association. He also serves as the president of the American Filtration & Separation Society (Southwest Region), a member of GLC Consulting, an editorial board member for Elsevier, and a member of the board for Genesis BioHealth Co. and Amine Filtration Co. HEATH BURNS has over 14 years of experience in the oil, gas and process industries with regard to filtration and separation technology. He has a well-rounded background in manufacturing, R&D, pilot testing, engineering design and business development. Mr. Burns has extensive field experience in solid/liquid, liquid/liquid and gas/liquid separations. He has worked extensively with chemical process plants and natural gas facilities, troubleshooting fouling issues and determining the best technology for mitigation of contaminants. Mr. Burns holds a BS degree in mechanical engineering technology from Texas A&M University. BEN SPOONER, a 1998 graduate of the University of Alberta’s petroleum engineering program, has spent his entire career as a process engineer, focusing almost entirely on amine and sour water systems. He has been working for Sulphur Experts since 2003 and has been heavily involved with the troubleshooting, designing, testing and starting up of amine systems in over 25 countries around the globe. Mr. Spooner is also a principal member of the Amine Experts Seminar presentation team, co-author of Amine Treating and has authored several papers dealing with amine treating and sour water stripper optimization. Prior to joining Amine Experts, he worked as a roughneck on drilling rigs, an operator at a gas processing plant in northern Alberta, and as an engineer in the technical services department of a large amine vendor.

Management B. GLASSCOCK, Solomon Associates, Dallas, Texas

A data-driven, experience-based approach to workforce optimization In recent years, many energy-intensive companies have sought to “cut costs at all cost.” Frequently, the decision is made to arbitrarily reduce staffing levels as a primary vehicle for reducing costs. Rather than viewing facility staff as a key asset that leads to higher performance and profitability, these organizations focus on reducing the cost of staffing by decreasing cost per staff member, the number of staff, or both. Organizations utilizing this approach also tend to use changes in organizational structure to solve business problems, only to find that another structural change is required two to three years later. Through this approach, organizational health and competency are given little consideration and, in most instances, unintended consequences can include reduced productivity, poor organizational health, undermined safety and lower profitability. In the end, these organizations end up paying a price that far exceeds the apparent cost savings, and business problems continue to go unresolved. There are alternatives for implementing successful and sustainable staffing changes. Staffing changes for the purpose of improving profitability should be viewed as an optimization process rather than a reduction process.

• Achievement of targeted business safety, environmental and financial objectives • Visible and strong leadership at all organization levels— management, supervision and staff • Clearly defined and consistently understood accountability and responsibility for each person participating in the work processes and practices that make up each business • Leadership that is viewed as consistent, fair and competent by a facility’s employees and executive management • Efficient work processes that are consistently implemented across the business • Utilization of best practices to carry out key businessrelated activities • Individual employee competencies—knowledge, training, qualifications and experience • Employee utilization. These factors must be considered when modifying existing organization structures and staffing levels, and when developing organizational and staffing plans for new facilities. Correctly analyzing them and developing effective recommendations to

Workforce optimization consulting. Workforce optimiza-

16 14 12

Direct staff ratio

tion consulting (WOC) moves beyond the simple quantitative formulas and across-the-board cuts that many companies employ in an attempt to reduce costs. The data-supported staffing assessment approach (FIG. 1) consists of proprietary methodology and tools, as well as seasoned consultants focused on helping operators determine and implement the optimum workforces for their facilities and companies within the context of the business process. Truly optimum staffing results in sustainable benefits of improved profitability, safety, regulatory compliance, a highly competent workforce, and a healthy and effective organization. Successful workforce optimization methodologies are grounded in industry best practices and require a thorough analysis of a facility’s total workforce that embraces both quantitative and qualitative criteria. Comparing work practices at a particular site to top performers will yield staffing recommendations that are both realistic and sustainable. Onsite interaction with the facility’s workforce is key to measuring workforce morale, competency and organizational effectiveness. From a practical viewpoint, workforce competency comprises a number of factors:

10 8 6 4 2 0

0

500

1,000

1,500 2,000 2,500 3.000 Direct full-time equivalent employees

3,500

4,000

FIG. 1. Non-salaried to salaried employee ratio vs. total staffing level. Better performers generally have higher ratios in the 6–8 range. Hydrocarbon Processing | JULY 201579

Management help achieve them requires consultants who have extensive experience and a successful track record. Implementing a WOC solution considers the time required to achieve organizational maximum competency when defining recommended organizational structure and staffing levels. Actual individual employee competency must be measured when determining the number of employees required to perform identified workloads within reasonable timeframes and at sustainable work rates. Organizational health. A competent and valued workforce is

the foundation for good organizational health, which essentially translates to employee motivation: • How happy are the people that come to work each day? • Are working relationships adversarial or cooperative? • Does communication occur freely and effectively? • Is there mutual respect between all components of the workforce? • Is the workforce a team rather than a collection of many individual franchises? • Is there a clearly defined and balanced value relationship between management and employees? • Do employees feel a sense of pride regarding their jobs and the company for which they work? A quality WOC methodology should utilize an employee perception survey to help measure employee perception of organizational health and performance. The methodology should also evaluate employee experience levels from both a department and company perspective. The methodology should consider qualifications, education and training, preferably for everyone in the organization. This information is valuable when looking to either qualitatively or quantitatively measure the key elements comprising workforce competency (i.e., knowledge, training, qualifications and experience) and how well these elements are utilized.

Extensive data request. WOC begins with a request for demographic data, such as the age groupings of personnel and their experience levels. The data should include listings of qualifications; length and type of education; training programs that em100

4 21

80

29

20

31

37

Efficiency, % of time

52 60

18 14

48

58

41

40

20

31

53

49

Non-value added Necessary Value added

44 28

22

0 Maintenance engineer

Maintenance Craftspersons planner

Operations engineer

Project manager

Inspectors

FIG. 2. Examples of measured work efficiency by type of work.

80JULY 2015 | HydrocarbonProcessing.com

ployees attended; and positions that employees have held in the company and in previous employment. Employing a comprehensive methodology requires gathering a significant amount of operational and business information. For example, process flow diagrams and written procedures should be requested. If work processes have already been mapped, copies of those maps will be needed. If the facility has any documented practices to accompany the procedures, those should also be gathered. This information is used to identify key work processes for mapping to develop an understanding of how work is actually conducted across the business. Additionally, a targeted interview list and schedule, along with a work sampling plan, should be developed to determine employee utilization. These information and data reviews are aimed at developing an overall project work plan that will achieve maximum benefit for the organization with minimal disruption of its work. The onsite portion of a WOC effort should begin with workprocess mapping and a best-practices assessment, followed by a detailed work sampling and data analysis (FIG. 2). Multiple techniques can be employed to develop an accurate understanding of current work practices and procedures that impact workload and manpower. Employee consideration. All too often, companies consider only direct employees, but, throughout this process, the roles of contract employees should be evaluated. Many companies reduce the number of direct employees only to replace them with an equal or greater number of contract employees. The concept of optimization does not always mean a simple reduction in staff: the solution may involve adding staff members to certain department areas. For example, most leading-performance facilities have higher levels of technical staffing than their poorerperforming peers. The optimization process helps operators determine the staffing levels and organizational structures that will sustainably maximize workforce efficiency and effectiveness. The methodology evaluates the organization and staffing levels in the context of the business model. The success of the business model (FIG. 3) is proportional to workforce competency and organizational health. The business objective defines how profit will be generated (e.g., converting crude oil into light, premium products). Highlevel work processes, such as operations and maintenance, are a series of repetitive actions that must take place to accomplish the business objective. The organizational structure defines how employees will accomplish the work process. The roles and responsibilities within this structure must be well-defined, with clear performance expectations for each position within the organization. Practices and procedures tell what and how the actions in the work process will be accomplished. How much time it takes to perform the practices and procedures, and the efficiency with which they are performed, establish employee utilization and, ultimately, the number of employees and employee skills and knowledge required. Training is also an important element in the business model because improvement in employee knowledge and skills is heavily dependent upon instruction. Results must also be routinely measured and evaluated so that performance is continually improved. The measured results are used to develop future business plans, including performance improvement strategies, and to manage and maximize ongo-

Management ing business. A thorough understanding of each element is necessary for effective and sustainable workforce optimization. WOC investigates and analyzes each of the business model elements, along with workforce competency and organizational health, before developing recommendations and an overall staffing plan.

Continuous improvement cycle

Business objectives

Work processes

Organization structure

Practices/ procedures (best practices)

Roles and responsibilities

Workload and utilization

Process mapping

Workforce competency

Work process evaluation

Performance monitoring and metrics

Improvement plan and implementation

Activity analyses work sampling

Organizational health

Tools, Phased staffing level changes. To Roles and equipment responsibilities reach set goals and objectives, companies and software must determine what drives their business and develop an optimized business strucStaffing ture. Accomplishing this task requires time level and discipline, using a documented schedule and plan. By adopting a methodology Training that measures current work processes and workloads, and considers future workFIG. 3. The business model defines how work processes are accomplished and optimized. loads, facilities can optimize both staffing levels and work processes over time. The phased changes in staffing levels are adjusted to meet the busiand lived most of the recommendations and changes that they ness environment and requirements of each company and its farecommend. As a result, their analysis goes far beyond numericilities, rather than applying a “cookie-cutter” approach. cal analysis and the basic tenets of a high-quality Master of BusiTypical time periods (tiers) for making staffing level changes ness Administration (MBA) degree. include short-range staffing targets with associated business proHigh-performance benchmarks are always changing, so cesses and practice changes that are within the authority level of downstream operators must constantly observe these changes a facility’s management. These targets should be achievable in and work to adopt new philosophies and optimize work proone year or less. Mid-range staffing-level targets requiring minor cesses to stay competitive. changes to the overall business model typically require one to three years and are often within the facility’s management auA new way of thinking. Going beyond simple, quantitative thority level. Longer-range targets demand staffing levels requirformulas and across-the-board cuts, the data-driven and experiing major changes to the company’s existing business model and ence-based approach takes all critical factors into account. The possibly its organizational structure. The business changes to result is custom recommendations for reaching optimal staffing reach this level of staffing may require three to five years to fully levels and organizational structure (which can mean staff reducachieve. Such changes to the organization’s business model may tions and/or staff additions) based on specified goals, objecinclude streamlining existing corporate procedures to which tives and social standards for the business. each site or division is required to adhere, or delegating higher Management is tasked with identifying and closing the gaps in levels of authority to managers and/or supervisors. operational performance, and an expert consultant can provide: Staffing targets for each customized time period are tabulated • Performance benchmarking to compare the company’s for each functional area. In addition to staffing targets and overall personnel efficiency relative to peers recommendations, an estimation of the total annual savings or fi• Process mapping to evaluate actual work processes, nancial impact in connection with the recommendations for each such as operator maintenance, routine maintenance, set of staffing targets can be provided using WOC methodology. shift operations and procurement to identify WOC can help companies that are both understaffed and opportunities for streamlining overstaffed. Most often, the results are able to significantly mod• Assessment of the facility’s current key work practices ify staffing levels in the range of 10%–15%. However, reducing and identification of inefficiencies employees and changing organizational structure is not always • Work sampling analysis to assess how employees in the answer. WOC utilizes proprietary information and data from various work streams expend their efforts on necessary large and mature industry performance databases as a valuable tasks, which assists in identifying obstructions to tool in the identification of potential staffing optimization opimproving efficiency portunities. Specifically, the databases allow comparisons using • Application of best professional judgment of seasoned key performance indicators and actual staffing levels for peer industry professionals. facilities in relation to the client facility. As a result, this unique There is no single, perfect organizational structure: many analysis capability enables development of proven, achievable models are successful. WOC can be the key to achieving greater and sustainable recommendations for a facility. efficiencies, enhanced reliability, improved margins and susEqually important as data access capabilities is that the worktainable performance. force analysis and development of improvement recommendaBILL GLASSCOCK is vice president of consulting at Solomon Associates, which tions are performed by personnel with an average experience provides benchmarking and performance improvement consulting services to level greater than 30 years. These consultants have experienced energy-intensive industries. Hydrocarbon Processing | JULY 201581

Process Automation T. MEEK, Thermo Fisher Scientific, Philadelphia, Pennsylvania

Automate environmental monitoring at petrochemical plants with LIMS Environmental regulations can add to the cost of doing business in the petrochemical industry, so making compliance more efficient and less expensive is a bottom-line priority. To fully understand the costs of compliance, upstream and downstream processing plants must account for not only the processes in place to meet compliance guidelines, but also for managing the entire process of capturing, collating and reporting on instrument data that oversees each process. These actions are becoming even more important as new regulations require continuous or near-continuous monitoring of a plant’s environmental impact. While tracking environmental footprints can be onerous, there are nonetheless many opportunities to increase compliance efficiency. Companies that plan for, and build in, compliance early in their process definitions establish a best-practice environment that sets the stage for easier conformance with regulatory guidelines and more reliable reporting. Uncovering efficiencies in any process is challenging. It depends on rigorous data analysis that relies heavily on informatics solutions. Finding efficiencies in a compliance process is even more challenging, as it involves internal stakeholders who must agree and adapt to workflows that are new and, in some cases, disruptive. Achieving compliance efficiency is only possible with a solid management framework and a data-management system to support it. ISO 14000 and LIMS. A proven way to meet the compliance efficiency challenge is to combine the environmental management system (EMS) outlined in the ISO 14001 standard with a laboratory information management system (LIMS). The EMS gives plant management a useful framework for identifying opportunities for increased environmental performance and efficiency. For its part, the LIMS manages all monitoring data produced around the plant and organizes it into templates for analysis and regulatory reporting. The core of an ISO 14001 EMS is a five-step environmental management process (FIG. 1) that helps plant management set and achieve goals related to environmental monitoring. The cyclical structure of the EMS encourages continuous improvement; after evaluating progress toward goals set in the previous cycle’s planning phase, management is immediately encouraged to continue improving by setting new goals. The process is flexible enough to allow plants to tackle nearly any process that involves environmental regulations. 82JULY 2015 | HydrocarbonProcessing.com

The other half of the equation is the LIMS. Traditionally used by laboratories to collect and manage product sample data, LIMSs have evolved and expanded over the decades and are managing environmental monitoring programs that require scientific analysis to deliver actionable results. Just as a LIMS can track the journey of a sample through a lab, from receipt through sample testing and reporting, it can now also monitor all of the environmental aspects of a given process within a plant, including scheduling, location tracking and automated compliance alerts. These data, required by environmental and regulatory authorities and built into the LIMS library of workflows and reporting, are then organized for easy review by management and auditors. Together, the LIMS and the EMS give plant management complete visibility into all five steps of the EMS process, allowing them to reduce compliance costs by identifying opportunities for process efficiency based on measured results. Step 1: Planning. The first step in establishing an EMS is to catalog all plant operations that are potentially relevant to a given regulation. This catalog is stored in the LIMS as a virtual map of the plant, which management can use to identify environmental risks within the process. One application where the LIMS/EMS solution excels is management of stack monitoring data. In most plants, data generated by continuous emissions monitoring systems (CEMSs) in the stack are fed into a process information management solution (PIMS) and/or data acquisition and handling system (DAHS). Integrating these systems with the LIMS allows plants to automatically generate reports from these data, simplifying the compliance demonstration process. Other applications of the LIMS/EMS solution include: • Spillage-monitoring data • Storage of spot sample data • Recording of rainwater sulfur content measurements • Mercury-monitoring data • Historic cleanup statistics • Effluent-monitoring data. Step 2: Implementation. After the management team has

identified the processes it wants to improve, the next challenge is rolling out these changes to the affected staff. This step is often where efficiency gains won in the other steps can be lost; training employees on new processes is time-consuming, and

Process Automation ensuring that they follow new procedures is even more difficult. A LIMS solves this problem by fully automating the distribution of standard operating procedures (SOPs) for use by relevant staff. SOPs can walk staff through a new process step by step, preventing costly human error. The LIMS can also store employee competence records, which are a significant part of compliance with many regulations. A LIMS can also automatically alert staff to both process and environmental errors. If an environmental parameter being monitored by the LIMS exceeds a limit defined in the EMS, then the LIMS will automatically alert responsible staff and provide them with an SOP to correct the error. Step 3: Evaluation. Evaluation is the most data-intensive step of the ISO 14001 EMS. All collected data must be regularly reviewed and measured against EMS and regulatory goals. Here, the combined effect of the LIMS and EMS is most obvious. Since the LIMS acts as a central repository for all plant regulatory data, the development of EMS results for evaluation is fully automated. Saving this small amount of staff time during each evaluation adds up over hundreds of evaluations; efficiency gains will ultimately contribute to significant cost savings. Step 4: Management review. ISO 14001 EMS systems require plant management to review progress toward their Step 1 goals at the end of every monitoring period. While this may sound tedious, it actually provides a critical opportunity for plant management to encourage continuous process improvement. Just as the LIMS can automate reporting to external regulators, it can also generate comprehensive reports for the management team. These auto-generated reports make the management review much more efficient. If the efficiency and regulatory goals for the previous period were met, management can then use the report data to set new goals for the next period. Step 5: (Re)commitment. At the end of each cycle, the plant must report its results to both regulators and an auditing body for ISO 14001 certification. The LIMS generates reports that are tailored to the requirements of each auditor, which significantly reduces the administrative work necessary for demonstrating compliance.

Commitment and policy

Review

Planning

Continuous improvement

Takeaway. Environmental compliance is part of doing business, but plant operators have more control over costs than they realize. By taking stock of all the costs of regulatory compliance, it is possible to achieve measurable and repeatable savings. Combining the data reporting required for an EMS-compliant environment with the enterprise-level data reporting of a LIMS, plants are able to lay out and analyze the entire process of capturing, managing and reporting data related to environmental compliance. This process may seem challenging at first, but the LIMS is built precisely to enable this level of complex and cross-platform data management. The bottom-line costs of environmental compliance are not fixed; there is opportunity to drive greater efficiencies into the process and save money. However, data is the key to making all the right decisions about where opportunities exist to implement improvements across the entire organization. All it takes is a solid management framework and the right data management system to support it. TRISH MEEK is the director of product strategy at Thermo Fisher Scientific and has been with the company since 1999. She works closely with customers to understand their business needs and long-term strategies to drive the Informatics product roadmap and business strategy. Prior to this role, Ms. Meek occupied various roles in the organization in product management, sales and support. Prior to Thermo Fisher, she performed heavy metal analyses of contaminated soil samples using X-ray fluorescence and atomic absorption spectrometers. She has a BS degree in chemistry from Loyola University in New Orleans, Louisiana.

The industry-standard software for instrumentation design Featuring more than 70 routines associated with control valves, rupture disks, flow elements, relief valves and process data calculations, InstruCalcTM is one of the industry’s most popular desktop applications for instrumentation calculations and analyses. Features: NEW • Graphs for Control Valves and Flow Elements Version 8.1 • Restriction devices • Material yield strengths file • ISO orifice plate calculations have been updated to ISO 5167, 2003 sudden entrance and exit to the calculations. • Relieff VValve alve ve pprograms, ve rg ro +1 ((713) 520-4426 l [email protected] +1 om www.GulfPub.com

Evaluation

Implementation

FIG. 1. The five-step EMS. Source: US Environmental Protection Agency. Hydrocarbon Processing | JULY 201583

ADRIENNE BLUME, MANAGING EDITOR [email protected]

Innovations Communication in digitally networked plant of the future With the new HIPRO-S V2 safety protocol, automation solutions firm HIMA introduces a unique safety protocol for efficiently migrating existing plants to digitally networked plants. The protocol enables Ethernet-based, safety-related communication between three safety controller families: HIMatrix, HIMax and HIQuad (FIG. 1). Separate certification is not necessary, as HIPRO-S V2 is a component of HIQuad, HIMax and HIMatrix controllers and is covered by their certificates. HIPRO-S V2 can be implemented universally. Like safeethernet, developed by HIMA in 1997, HIPRO-S V2 utilizes user datagram protocol packets. These packets can be transmitted via standard Ethernet infrastructures, such as switches, firewalls, WLANs or other devices that are suitable for Ex zones. The use of these proven industrial infrastructure components enables economical and reliable solutions. HIMA safety protocols can be operated in the same network with non-safe protocols, e.g., Modbus TCP or the connection via OPC. Controllers can also be programmed via this network, which helps reduce the costs of generating and maintaining the network infrastructure. Select 1 at www.HydrocarbonProcessing.com/RS

FIG. 1. HIPRO-S V2’s safety protocol enables Ethernet-based communication between three safety controller families.

84JULY 2015 | HydrocarbonProcessing.com

Catalyst discovery for higher performance Catalyst researchers at IFP Energies nouvelles (IFPEN) have, for the first time, uncovered a molecular recognition phenomenon between cobalt-based catalyst precursors and the alumina support surface. This discovery paves the way for catalyst improvements and has led to a paper being published in the international edition of Angewandte Chemie. In heterogeneous catalysis, the interaction between transition metal complexes and oxide surfaces concerns the preparation of supported metal catalysts. Such catalysts include cobalt-based catalysts supported on alumina, which are used in numerous refining processes (hydrotreatment, Fischer-Tropsch synthesis, etc.) and chemical processes (particularly the conversion of molecules with a single carbon atom). On theoretical gamma-alumina surface models, calculations based on Density Functional Theory tend to demonstrate that the metal precursor coordination modes often invoked (coordination at surface hydroxyls) do not generate the octahedral cobalt species observed experimentally. The most stable grafts are obtained by the additional incorporation, in the metal coordination sphere, of oxygen atoms from the alumina network, resulting in a molecular recognition phenomenon (FIG. 2). In their recent publication, the authors propose a mechanism of epitactic cobalt hydroxide layer growth with the support, explain the multiple experimental results and predict the geometry

FIG. 2. IFP Energies nouvelles uncovered a molecular recognition phenomenon between cobalt-based catalyst precursors and the alumina support surface.

of the grafting sites, along with the way these layers will be oriented with respect to the alumina support. A passivation effect of the silica is also demonstrated by the calculation of the interaction of the same cobalt precursors with amorphous silica-alumina surface models developed at IFPEN. In fact, the amorphous nature of the surface limits the occurrences of the molecular recognition phenomenon. These studies represent an advancement in terms of the rationalization of the interface phenomena involved in the drying step of the preparation of heterogeneous catalysts, and pave the way for future investigations during the liquidmedium impregnation steps. Select 2 at www.HydrocarbonProcessing.com/RS

Methaforming cuts cost of high-octane gasoline The New Gas Technologies–Synthesis (NGTS) Methaforming process removes sulfur and converts naphtha and methanol into a high-octane gasoline blendstock with low benzene, releasing hydrogen. Methaforming uses a proprietary zeolite catalyst in a process flow scheme that is similar to naphtha hydrotreating. The methanol is dehydrated in a highly exothermic reaction, releasing the methyl radical for alkylating benzene into toluene. As in reforming, the normal paraffins and naphthenes are converted to aromatics, releasing hydrogen in a highly endothermic reaction. The methanol is injected into the fixed-bed reactor in stages to balance reaction temperature and optimize the conversion (FIG. 3). Unlike conventional reforming processes, Methaforming can tolerate sulfur content up to 500 ppm wt, reducing it by 90%. The presence of olefins and dienes do not significantly affect catalyst life. Catalyst activity is recovered by in-situ regeneration. Typical cycle time between regenerations is one month. For continuous operation, two reactors and regeneration facilities are needed.

Innovations

Select 3 at www.HydrocarbonProcessing.com/RS

SRU analyzer wins innovation award The analysis division of the International Society of Automation (ISA) selected AMETEK Process Instruments to receive the Innovative Product of the Year award at the 2015 ISA Analysis Division Symposium, held this past April in Galveston, Texas. AMETEK was chosen over 12 other entrants for its Model 888 sulfur recovery unit (SRU) tail gas analyzer (FIG. 4). The third-generation analyzer represents advancement in the control of the Claus sulfur recovery process. It addresses the three most common external failure modes encountered by SRUs and incorporates the following features to deal with them: • Automatic flow control for a proactive response to adverse process conditions, such as reducing entrainment during SRU turndown • Flange temperature alarm to give early warning of bad steam quality or a defunct steam trap

• An extended ambient temperature range to 60°C, without external cooling, that increases the life of electronics. In addition, the Model 888 features a full-color, web-enabled user interface and smart diagnostics. The unit’s self-diagnostics monitor six temperature zones and automatically adjust to changes in four pressures. It is also equipped with anticlogging blowback features that initiate automatically if plugging is detected. The analyzer mounts directly on the process pipe without an external sample line, eliminating the complexity of fiberoptic-coupled photometers. In addition, the Model 888 occupies the same footprint and uses the same connections as its predecessor, enabling a new unit to be substituted in less than a day. Select 4 at www.HydrocarbonProcessing.com/RS

Compact hydrogen generator line launched The Linde Group has launched its new HYDROPRIME plant line of innovative, cost-effective hydrogen generators (FIG. 5), which are based on proven steam methane reforming technology. Hydro-Chem, a division of Linde Engineering North America, has tested and proven the reliability and suitability of these units in various applications. The company is now launching the mass-production release of HYDROPRIME as a local production alternative to trucked-in bulk gases. HYDROPRIME plants offer many advantages over traditional supply modes, such as truck-delivered liquid hydrogen, electrolytic plants and conventional steam methane reforming plants. These plants have a capacity of 0.15 MMscfd to 0.9 MMscfd (165 Nm3/h to 1,000 Nm3/h)

and produce ultra-high-purity hydrogen (99.999+%) at 200 psi (13.8 bar), reducing the need for product compression in most uses. The new product line has a high natural gas conversion rate and is highly heat integrated, which translates into low operating cost. HYDROPRIME plants are fully automatic with failsafe controls, allowing for unattended operation and remote startup, operation and monitoring. In addition, they feature a modular open-skid design and a small footprint. Recognizing the diverse needs of a global marketplace, Linde offers HYDROPRIME as a build-own-operate solution to simplify ownership and maintenance for the end user and eliminate customer-owned capital investment. Alternatively, HYDROPRIME plants can be owned and operated by the end user with various support models by Linde. Select 5 at www.HydrocarbonProcessing.com/RS

FIG. 4. AMETEK Process Instruments’ Model 888 sulfur recovery unit tail gas analyzer received a top innovation award in April.

H2, H2S C1-C4 Naphtha ( 35 180°C) Methanol (25%)

Methaforming unit 10 atm 370°C

Stabilizer

This one-step process replaces naphtha desulfurization, reforming, isomerization and benzene removal, thereby reducing costs to one third. For new plant applications, the major benefit is cost, both initial capital cost and ongoing operating cost. For a 20-Mbpd unit, the savings total $240 MM net present value. Methaforming yields and associated octane are comparable to isomerization with continuous catalyst regeneration reforming; both are significantly better than semi-regenerative reforming. As a result, Methaforming offers a low-cost approach to improve yields and to debottleneck gasoline production for existing semi-regenerative reformers. This yield advantage is worth $80 MM/yr, at a retrofit cost of approximately $15 MM. The retrofit is done at the associated naphtha hydrotreater, with the major cost being the replacement of the existing reactor with two larger ones. Five years of pilot plant processing have demonstrated performance on fullrange naphtha, LPG, natural gasoline and pyrolysis gasoline in three pilot plants. NGTS’ next step is to locate an existing idle naphtha hydrotreater or reformer for a low-cost conversion into a Methaforming commercial demonstration plant.

Gasoline blendstock High octane 10-30 ppm sulfur