HARNESS THE POWER
OF ADVANCED HRSG TECHNOLOGY
The industry leader in Heat Recovery Steam Generators for gas
turbines up to 30 MW, RENTECH offers a full range of HRSG systems
to meet your toughest project requirements.
We custom engineer ourcrossflow two-drum and waterwall designs to perform superbly in the most demanding applications and operating conditions. We master every detail to deliver elemental power for clients worldwide.
HARNESS THE POWER WITH RENTECH.
HEAT RECOVERY STEAM GENERATORS WASTE HEAT BOILERS
FIRED PACKAGED WATERTUBE BOILERS SPECIALTY BOILERS
FEBRUARY 2017 | HydrocarbonProcessing.com
CLEAN FUELS
Convert CO2 to fuels to mitigate emissions from industrial plantsDME as a diesel alternative in North America
PROCESS OPTIMIZATION
Use the right model to unlock utility system potentialMAINTENANCE AND RELIABILITY
Determine the standard hoop densityof spiral-wound gaskets on flanges
BUSINESS TRENDS
Anticipated impacts of theA World of Solutions
Visit www.CBI.com
YOUR REFINERY CHALLENGES
Today’s Refinery Challenges
Processing tight oil
Managing stringent sulfur limits
Monetizing orphan streams
Upgrading residuals
CB&I’s Comprehensive Solutions
CB&I’s broad portfolio of both refining and petrochemical technologies,
combined with our execution expertise, will help you maximize processing
flexibility and achieve margin benefits in the widest range of scenarios.
We are with you through every stage of the process plant life cycle, from
feasibility studies to identifying plant optimization and upgrade solutions,
through technology selection, full-scope EPFC, commissioning and start-up.
PROCESS PLANNING AND DEVELOPMENTLICENSED TECHNOLOGIES AND CATALYSTS FULL-SCOPE EPFC SERVICES
PROJECT MANAGEMENT AND CONSULTING AFTERMARKET SERVICES
FEBRUARY 2017 | Volume 96 Number 2
HydrocarbonProcessing.com
SPECIAL FOCUS: CLEAN FUELS
29 Commercialization of pyrolysis oil in existing refineries—Part 2
S. Arbogast, D. Bellman, D. Paynter, J. Wykowski and R. M. Baldwin
39 Put acid gas hydrocarbons in their place with staged regeneration
F. Bela
43 DME as a diesel alternative in North America
R. A. Sills
47 Mitigate CO2 emissions from industrial plants by conversion to fuels G. C. Young
PROCESS OPTIMIZATION
49 Reduce coke formation and save operating costs with optimization of DMDS into ethane cracking furnaces
G. Hay, G. Rasouli, L. Carbognani-Arambarri, R. Suzuki, K. Urata and M. Inoue
53 Use the right model to unlock utility system potential
J. Gomez-Prado and D. Hutton
57 Performance testing: The key to successful revamps
N. Lieberman
MAINTENANCE AND RELIABILITY
63 Determine the standard hoop density of spiral-wound gaskets on flanges
S. H. Lee, S. Lee and S. Jeon
65 Design operations-and-maintenance-friendly skid-mounted units
G. Murti
73 Maintain the simplicity of maintenance work processes
M. Asquini
77 Improve metering pump reliability through maintenance training
K. Louque
ENVIRONMENT AND SAFETY
79 Never waste a shutdown to improve process safety and uptime
M. Loseto
GAS PROCESSING SUPPLEMENT
GP-1 Technology and Business Information for the Global Gas Processing Industry
Cover Image: Flint Hills Resources’ Pine Bend refinery near Saint Paul, Minnesota is making several major investments to improve the refinery’s efficiency and help lower emissions. The projects include a state-of-the-art combined-heat-and-power system and an ammonium thiosulfate project that will convert sulfur to liquid fertilizer and help lower vehicle tailpipe emissions. Photo courtesy of Flint Hills Resources.
DEPARTMENTS
4 Industry Perspectives
8 Business Trends
15 Industry Metrics
17 Global Project Data
81 Innovations 83 Marketplace 84 Advertiser Index 85 Events 86 People COLUMNS 7 Editorial Comment
The future of refining lies in clean fuels
19 Reliability
The risks of deferred compressor maintenance
21 Automation Strategies
Next-gen automation services support operational excellence and reduce project cost
23 Refining
Europe’s refineries: Walking dead or happy valley?
25 Global
Is India ready for the BS-6 changeover?
28
www.HydrocarbonProcessing.com
Industry Perspectives
President/CEO John Royall
CFO Pamela Harvey
Vice President Ron Higgins
Vice President, Production Sheryl Stone
Publication Agreement Number 40034765 Printed in USA Other Gulf Publishing Company titles include: Gas ProcessingTM, Petroleum Economist©
and World Oil®.
Global desulfurization capacity to
skyrocket over the long term
According to OPEC’s World Oil Outlook 2016, desulfurization
capacity additions represent the largest capacity increases among all process units to 2040. This trend is due to increased regulations on the amount of sulfur allowed in transportation fuels. According to the report, nearly 4 MMbpd of new desulfurization capacity is expected to begin operations by 2021. However, an additional 13.7 MMbpd of desulfurization capacity is projected to be needed by 2030, with a requirement for an additional 5.6 MMbpd between 2030 and 2040 (FIG. 1).
In total, the global refining industry is expected to add more than 23 MMbpd of new desulfurization capacity by 2040. The majority of this new capacity will be located in the Asia-Pacific region, primarily in China, followed by the Middle East, which is investing heavily in capital-intensive projects to meet Euro 4 and Euro 5 specified fuels. Saudi Arabia and Kuwait lead the way in clean fuels investments in the Middle East. These projects include Saudi Aramco’s near-zero-sulfur fuels goal, as well as Kuwait’s Clean Fuels and Al-Zour refinery projects.
Other regions with strong growth in desulfurization capacity include Russia, which has invested nearly $55 B in its refinery modernization program. The program calls for the installation of 130 new units by 2020. The modernization plan focuses on upgrading and conversion capacity to produce higher-quality refined products that meet stricter domestic fuel specifications, and promotes the export of high-value products to regions where they are in demand, such as Europe.
According to the report, a breakdown of the 23 MMbpd of the market share for the global desulfurization capacity additions include:
• Distillate desulfurization capacity: 16.5 MMbpd (71% market share)
• Gasoline sulfur reduction: 4.2 MMbpd (18% market share)
• Vacuum gasoil/resid processing: 2.5 MMbpd (11% market share)
New regulations on fuel sulfur limits will have profound effects on the global hydrocarbon processing industry, a trend that will continue over the long term.
PUBLISHER Catherine Watkins
[email protected] EDITOR/ASSOCIATE PUBLISHER Lee Nichols
[email protected] EDITORIAL
Executive Editor Adrienne Blume Managing Editor Mike Rhodes Technical Editor Bob Andrew Digital Editor Ashley Smith Reliability/Equipment Editor Heinz P. Bloch Contributing Editor Alissa Leeton Contributing Editor ARC Advisory Group Contributing Editor Anthony Sofronas MAGAZINE PRODUCTION / +1 (713) 525-4633
Vice President, Production Sheryl Stone Manager, Editorial Production Angela Bathe Dietrich Assistant Manager, Editorial Production Lindsey Craun Artist/Illustrator David Weeks Graphic Designer Andreina Keller Manager, Advertising Production Cheryl Willis ADVERTISING SALES
See Sales Offices, page 84.
CIRCULATION / +1 (713) 520-4440 / [email protected]
Manager, Circulation Alice Murrell SUBSCRIPTIONS
Subscription price (includes both print and digital versions): One year $399, two years $679, three years $897. Airmail rate outside North America $175 addi-tional a year. Single copies $35, prepaid.
Hydrocarbon Processing’s Full Data Access subscription plan is priced at $1,695.
This plan provides full access to all information and data Hydrocarbon Processing has to offer. It includes a print or digital version of the magazine, as well as full access to all posted articles (current and archived), process handbooks, the
HPI Market Data book, Construction Boxscore Database project updates and more.
Because Hydrocarbon Processing is edited specifically to be of greatest value to people working in this specialized business, subscriptions are restricted to those engaged in the hydrocarbon processing industry, or service and supply company personnel connected thereto.
Hydrocarbon Processing is indexed by Applied Science & Technology Index, by
Chemical Abstracts and by Engineering Index Inc. Microfilm copies available through University Microfilms, International, Ann Arbor, Mich. The full text of Hydrocarbon
Processing is also available in electronic versions of the Business Periodicals Index.
DISTRIBUTION OF ARTICLES
Published articles are available for distribution in a PDF format or as professionally printed handouts. Contact Foster Printing Company for a price quote and details about how you can customize with company logo and contact information.
For more information, call Rhonda Brown with Foster Printing Company at +1 (866) 879-9144 ext. 194 or e-mail [email protected].
Hydrocarbon Processing (ISSN 0018-8190) is published monthly by Gulf Publishing
Company, 2 Greenway Plaza, Suite 1020, Houston, Texas 77046. Periodicals post-age paid at Houston, Texas, and at additional mailing office. POSTMASTER: Send address changes to Hydrocarbon Processing, P.O. Box 2608, Houston, Texas 77252. Copyright © 2017 by Gulf Publishing Company. All rights reserved.
Permission is granted by the copyright owner to libraries and others registered with the Copyright Clearance Center (CCC) to photocopy any articles herein for the base fee of $3 per copy per page. Payment should be sent directly to the CCC, 21 Congress St., Salem, Mass. 01970. Copying for other than personal or internal reference use without express permission is prohibited. Requests for special permission or bulk orders should be addressed to the Editor. ISSN 0018-8190/01.
MMbpd
Vacuum gasoil/residual fuel Middle distillates Gasoline/naphtha
US and
Canada AmericaLatin Africa Europe Russia andCaspian Middle East China Other Asia-Pacific 0 1 2 3 4 5 6 7
FIG. 1. Desulfurization capacity requirements by product and region, 2016–2040. Source: OPEC World Oil Outlook 2016.
The power of our resources means nothing without the energy of our people. Their
focus and expertise make our energy more dependable, more sustainable, and
more useful.
We are looking for experienced downstream professionals to join our team.
Apply now.
people
powered
www.aramco.jobs/hp
Reduce
Costs
Improve
Efficiencies
Introducing FFC Plus, the next generation of FIBER FILM®Contactor technology. Merichem Company’s advanced FIBER FILM technology with an
integrated coalescer and treater pushes the boundaries of extractive technologies. With this latest advancement to Merichem’s proven technology, hydrocarbon treating rates can be increased by up to 150% through increased mercaptan extraction efficiency. The integrated coalescing and treating device offers a simple installation, reduced chemical use, and reduced service and maintenance complexity. FFC Plus truly is mercaptan treating made better.
Improved Treating Rates
The FFC Plus technology from Merichem delivers increased capacity and more efficient sulfur extraction treating of hydrocarbons. This technology enables higher through-put within smaller equipment and better turndown at no additional cost. Process changes and upsets are also handled more effectively without affecting product quality.
Reduced Carryover
Merichem’s advanced FIBER FILM technology provides enhanced coalescing of both liquid phases that improves separation efficiency and reduces contaminant carryover. These features protect downstream equipment and catalysts.
Reduced Plot Space
The higher capacity and efficiency of FFC Plus translates into reduced equipment sizes and plot space. This reduces project capital and lowers plant operating costs.
Existing Merichem or other treating units can be easily retrofitted with FFC Plus, providing up to 150% additional capacity. This capacity increase will not affect the existing turndown range of Merichem units and will improve the turndown of other units. The new contactor is a direct “drop-in” replacement that can be added or switched with minimal modifications within a short shutdown period.
Editorial
Comment
LEE NICHOLS, EDITOR/ASSOCIATE PUBLISHER
[email protected]Hydrocarbon Processing | FEBRUARY 2017 7
INSIDE THIS ISSUE
8
Business Trends. With the implementation of the International Maritime Organization’s 0.5% Global Sulfur Cap on marine fuels, many questions remain on how this new regulation will impact the downstream industry. This month’s Business Trends explores the IMO’s Global Sulfur Cap regulation, and the anticipated impacts to the refining industry and petroleum products markets.28
Special Focus. To combat increased emissions rates and airborne pollutants, governments around the world are implementing new legislation to reduce these toxins. In response, refiners are implementing operational and processing changes to reduce sulfur levels in transportation fuels. The Special Focus section investigates opportunities available to cost-effectively produce clean transportation fuels and products while adhering to existing and impending environmental regulations.63
Maintenance andReliability. To achieve high levels of production in the HPI, assets must be readily available. The best way to reach this goal is by properly planning, scheduling and executing preventive and corrective maintenance activities. A company can realize this goal through a clear and structured work order management system.
57
Process Optimization.Often, process unit revamps do not result in the achievement of the refiner’s objectives. This outcome is usually not the result of mechanical defects in the process equipment. More commonly, errors are made in the process design phase of the project. This article suggests using prototypes and performance testing, in lieu of computer modeling, when considering revamps to refinery processing units.
The future of refining lies in clean fuels
Each year, Hydrocarbon Processing
de-votes an issue to the topic of clean fuels— and rightly so. As the world continues to welcome more vehicles on the road, and as emerging economies invest in civil, in-dustrial and energy projects, global fuels demand is forecast to increase through the end of the decade. Multiple industry outlooks predict that global oil demand will increase from approximately 94 MMbpd in 2015 to between 99 MMbpd and 101 MMbpd by 2021 (FIG. 1).
With the increase in demand for re-fined fuels, additional consumption equates to higher emissions rates and, in turn, more airborne pollutants. To com-bat these effects, legislation mandating decreased emissions and lower levels of airborne pollutants will take effect over the next few years.
For decades, global refiners have made incredible strides in reducing sul-fur in transportation fuels, and have in-vested billions of dollars to decrease the amount of sulfur in refined fuels. These investments have not only decreased the amount of sulfur in fuels, but they have also provided higher-quality fuels for do-mestic and international use. This trend will continue for the foreseeable future.
However, a low-sulfur world does not come cheap. Refiners are investing billions of dollars to meet new sulfur and
emis-sions regulations. These investments aim to produce high-quality fuels that meet Euro 4, Euro 5 and Euro 6 specifications. Many nations around the world already produce transportation fuels that meet Euro 4 specifications. Other regions, such as the Middle East, are investing heavily to increase the production of Euro 4 and Euro 5 standard fuels.
Some of the major policies governing the mandatory decrease in emissions and the allowable amount of sulfur in fuels include:
• Tier 3 fuel regulations in the US and Canada
• National 5 in China • Bharat Stage 6 in India • Capital-intensive clean fuels
projects in the Middle East • Higher ethanol blending rates • Increased use of biofuels,
and electric and natural gas-powered vehicles.
In October 2016, the International Maritime Organization announced that it will implement its Global Sulfur Cap beginning in 2020. The new regulation calls for the decrease of sulfur in marine fuels from 3.5% to 0.5%. This regulation will have a dramatic effect on both the shipping industry and refiners, and is the focus of Hydrocarbon Processing’s Business
Trends section this month.
88 90 92 94 96 98 100 102
US EIA International Energy Outlook 2016 IEA Medium-Term Oil Market Report 2016 OPEC World Oil Outlook 2016
2020 2019 2018 2017 2016 2015
In October 2016, the International Maritime Organization (IMO) announced that it will implement a new regulation that calls for the sulfur content in marine fuels to be reduced from 3.5% to 0.5%. The new regulation will go into effect in January 2020. This action by the IMO will have a profound impact on the maritime and refining industries worldwide, as well as on the environment. This month’s Business Trends section provides an overview on the anticipated impacts of the IMO’s
Hydrocarbon Processing | FEBRUARY 2017 9
Business Trends
D. DUNBAR, M. TALLETT and T. WITMER, EnSys Energy; and D. ST. AMAND, Navigistics Consulting
Anticipated market and pricing impacts
from new marine fuel regulations
At its MEPC70 meeting in October 2016, the International Maritime Organization (IMO) announced that it will imple-ment the 0.5% Global Sulfur Cap starting on January 1, 2020. The new regulation is part of the MARPOL Annex VI regula-tion (FIG. 1).
In an effort to better inform the industry of the IMO’s de-cision, the authors delivered a rigorous analysis in mid-2016 on the likely implications of implementing the regulation in 2020.1 Decreasing the allowable percentage of sulfur in marine
fuels consumed in international (non-emissions control area, or ECA) waters from 3.5% to 0.5% represents a profound change. Some observers have likened the Global Sulfur Cap to the re-cent change from 1% to 0.1% sulfur in ECAs, but the fact is that the Global Sulfur Rule is likely to have a magnitude ten times greater than that of the recent ECA rule, in terms of the volume of marine fuel that must be “switched” to the new standard.
The driver behind the MARPOL Annex VI rule is to po-tentially improve the health of millions of people, particularly those living in coastal areas. At the IMO’s MEPC70 meeting, it was clear that the group was keen to avoid the regulation being pushed back until 2025. Nonetheless, this step change in global marine sulfur limits will have major impacts on the maritime and refining industries worldwide, as well as on the environment.
Regulatory uncertainty has limited progress toward compliance. The MARPOL Annex VI Global Sulfur
regu-lation is unique in the uncertainties it embodies. A five-year timing question—implement in January 2020 or delay until 2025—was settled at MEPC70.
However, compliance uncertainty remains, as shipowners can respond by purchasing 0.5% sulfur-compliant fuel, by in-stalling onboard scrubbers and by staying with high-sulfur fuel, or they can switch to an alternative fuel, such as LNG. The tim-ing and compliance uncertainties, along with a lack of incen-tive for either shipowners or refiners to pre-invest before the Global Sulfur Rule comes into effect, have deterred all parties from investing.
Limited LNG or scrubber penetration seen by 2020.
LNG has virtually no sulfur and very low particulate and nitrous oxide (NOx) emissions. As such, it represents a potentially
at-tractive fuel under MARPOL Annex VI; however, it suffers from the “chicken-or-the-egg” syndrome. Shipowners cannot justify investing in vessels capable of running LNG until the promise of LNG supply infrastructure is well established. Similarly, a
re-luctance is seen by companies to invest in LNG infrastructure until a sound demand basis is set from shipowners.
The authors’ view is that LNG will continue to gain ground as a fuel source for marine vessels over the long term, but will have limited market penetration by 2020. Alternative fuels, such as methanol, have also been discussed, but the potential is small, especially in the short term.
As a result of this scenario, switching to 0.5%-sulfur fuel or installing scrubbers are the primary options for compliance by 2020. Through a survey of Exhaust Gas Cleaning System As-sociation (EGCSA) members, the authors found that only 346 vessels had scrubbers installed, or on order, through December 2015. Virtually all of the scrubbing systems were designated for use in ECAs. This vessel count represents a miniscule 1.4% of the 24,000 “candidate” ships worldwide that are economically suitable for scrubbers; in other words, a very small degree of progress has been made to date.
Via survey, modeling of scrubber technology takeup and al-lowance for manufacturing and installation limits, the authors estimate that scrubbers will be installed on, at most, 5,000 ves-sels by 2020. These vesves-sels will consume an estimated 48 MMt-py (900 Mbpd) of high-sulfur heavy fuel oil (HS HFO). This assessment is close to the 36 MMtpy projected for 2020 by one IMO study,2 but well above the more conservative 11 MMtpy
projected by a marine analyst.3
Uncertainties surrounding the use of scrubbers on ships are a factor affecting expected takeup. These include limited oper-ating experience, management and disposal of acidic wash wa-ter, and concern over whether scrubbers will be able to meet
0.0 2000 2001 2002 2003 2004 2005 2006 2007 2008 2009 2010 2011 2012 1320 2014 2015 2016 2017 1820 2019 2020 2021 2022 2023 Sulfur , % 0.5 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 Global cap ECA zone cap
more stringent emissions regulations in the future, should they be implemented. Prior to MEPC70, shipowners commonly expressed unwillingness to invest $3 MM–$8 MM to install a scrubber. Retrofitting is achievable, but is unlikely to be consid-ered economic by the owner where the remaining vessel life is short or where vessel sale is anticipated.
In addition, the shipping industry is experiencing severe fi-nancial difficulties, based on vessel oversupply and trade uncer-tainties, and will need to deal with a new IMO Ballast Water Convention coming into effect in September. The net effect is that the bulk of the burden, from what is fundamentally a ship-ping-sector regulation, will fall on the refining sector—at least at the immediate onset of the rule in 2020. This situation also raises the question of whether the refining industry will be able to meet the demands placed on it by the Global Sulfur Rule.
The switch constitutes a major market impact. If the
authors’ outlook holds true, the 2020 requirement will be to switch roughly 200 MMtpy (3.8 MMbpd) of HS HFO to 0.5% fuel, with a range of uncertainty of approximately +/– 10%. A forecast for all marine fuel types in 2020 is shown in TABLE 1.
The magnitude of a 3.8-MMbpd switch volume, and the corresponding market impacts, should not be underestimated. While economic incentives exist to produce heavier marine fuels to the 0.5% sulfur standard, the expectation is that these will initially play only a small role, partly because of the need to establish acceptability for onboard-ship operation. Testing new fuels can be done safely (shippers generally perform onboard fuel compatibility tests before committing to fuel use), but fuel compatibility is a concern for shipowners. Asphaltene-like sedi-ment can form in fuel storage tanks and clog the ship fuel
deliv-ery system. According to Steve Bee, Global Business Director at Intertek ShipCare Services, the blending of two bunker fuels that are each perfectly within ISO 8217 specifications can lead to incompatibility and an unusable product. The risk, however small, of engine issues cannot be passed along in the same man-ner as fuel costs for vessels on term charter.
Consequently, the authors see the bulk of the 0.5%-sulfur fuel as being marine distillate, especially in early 2020 (FIG. 2). The industry is facing a demand to convert nearly 4 MMbpd of HS HFO supply to much lower-sulfur fuel (mainly distillate) over a short period of time. This trend equates to a shock to the supply system. To put this into context, it equals:
• 8 yr–9 yr of past growth in (inland) gasoil/diesel • Five years of growth (2015–2020) in total main light
products (gasoline, jet fuel, kerosine, gasoil and diesel) • A 45% reduction in total residual fuel demand.
Refining industry to the rescue? Hydrogen and sulfur plant limits foreseen. Will the refining sector be able to fully
respond and meet the switch requirements on January 1, 2020? Evidence indicates that this is unlikely.
Through a compilation of data from Hydrocarbon Processing’s
Construction Boxscore Database and other sources, the authors believe crude distillation capacity and secondary (upgrading) capacity to be adequate to fully respond to the Global Sulfur Cap in 2020. The authors also project that available desulfur-ization and hydrocracking capacity will be adequate to handle increased feed sulfur loads, albeit with potential strain and im-plications for catalyst life. The notable exceptions are sulfur re-covery plant and, to a lesser degree, hydrogen (H2) plant
capac-ity; both are vital for desulfurizing refinery streams.
The authors estimate that further additions, equating to 60%–75% over and above planned 2016–2019 projects, will be needed to meet the industry’s sulfur recovery needs; likewise, H2 plant additions of 20%–35% of firm projects will be needed.
The authors estimate that SRU base capacity in 2016 was just over 128,000 short tons per calendar day (st/cd). Even with the additional 13,366 st/cd of SRU capacity that is likely to be added between 2016 and 2019, the authors believe that an ad-ditional 8,000 st/cd–10,000 st/cd of SRU capacity, above that which has already been announced, will be needed to meet the Global Sulfur Rule.
These findings are based on rigorous, integrated modeling using two scenarios: one without the Global Sulfur Rule in 2020, and one with it included, at different levels of switch vol-ume and light/heavy marine fuel mix. Full compliance with the Global Sulfur Rule will require the removal of approximately 15,000 st/cd of additional sulfur from marine fuel products (TABLE 2). The authors’ modeling does not place this burden solely on additional SRU capacity. It allows for increases in coker throughput, with rejection of sulfur into petroleum coke, limited increases in FCC sulfur oxide (SOx) emissions, limited
increases in throughputs on base 2020 SRU capacity (including firm projects), and close to 10,000 st/cd of needed additional SRU capacity.
In short, even allowing for flexibility within the projected 2020 refining system, the authors see a shortfall in SRU—and also H2—capacity needed to achieve full adaptation to the
Global Sulfur Rule. 0 50 100 150 200 250 300 350 400
Without regulation With 0.5% sulfur regulation
MMtpy
HS HFO
≤ 0.5% fuel (mostly distillate)
FIG. 2. Global marine fuel consumption in 2020 (excluding LNG). TABLE 1. Marine fuel consumed globally in 20201
Global fuel HS HFO with scrubbers Global 0.5% fuel switched from HS HFO ECA/ other distillate2 LNG Total MMtpy 48 195 88 11 342 MMbpd 0.9 3.8 1.7 0.4 6.8 Global 2020, % 12.5 55.4 25.6 6.5 100
1 Source: EnSys-Navigistics Supplemental Marine Fuel Availability Study. 2 ECA fuel already at 0.1%, other marine distillate either already at 0.5% (EU EEZ,
China DECAs) or will need to be reduced to 0.5%; entails only limited further desulfurization from present levels.
We create
chemistry
that makes
individual
refiners love
fueling the
world.
As the global leader in catalysis, BASF helps fuel the world by providing innovative technologies, products and services to enhance performance and sustainability in the petroleum refining industry. We create value for refineries through a flexible offering of FCC catalysts and additive solutions, and advanced technical service. When individual solutions solve global problems, it‘s because at BASF, we create chemistry.
www.catalysts.basf.com/refining
An official IMO study also projected substantial SRU and H2 plant shortages.2 These two sets of modeling analyses beg
the question of whether the refining industry is willing and able to “fill the gap,” now that the timing is set for the Global Sulfur Rule implementation. It would need to build significant addi-tional SRU and H2 capacity before 2020. The authors, as well as
other industry analysts, are not optimistic that the refining in-dustry will make the required investments to the scale needed, for three main reasons:
1. Insufficient time. Historical refining project completion times and discussions with experts in this area indicate a build time of at least 2 yr–3 yr for newbuild SRUs. The authors perceive a low likelihood of new major SRU projects (i.e., those not already in the advanced planning to engineering stage) entering into service by 2020. Significant time is needed to complete a project, from idea inception to startup, even with the ability to deliver skid-mounted and modular units. 2. Unclear long-term economics. Economic justification
for refining projects is always a key factor. The authors estimate that the necessary incremental SRU and H2 capacity additions needed to fully comply with
the Global Sulfur Rule will entail an investment of approximately $5 B. With uncertainty on how the regulation will be met post 2020, it remains to be seen whether sufficient new refining projects will be announced and materialize.
Refiners have indicated concern over these projects because of uncertain long-term justification for them. The scenario that puts refiners in a quandary is that a surge in distillate costs in 2020 will lead to a rush by shipowners to install scrubbers. This will, in turn, lead to a partial reversion to high-sulfur marine fuel after a few years. Economic justification for a project must usually extend significantly beyond a 2 yr–5 yr payback window. Therefore, however profitable 2020–2024 may be for building a new SRU, the investment may not make sense.
3. Marine fuels not strategically necessary for many refiners. Marine fuels comprise a relatively small percentage of total global liquids demand (an estimated 6% in 2020), and are not a significant driver of
refiner planning and investment. While maintaining compliance with regulations for gasoline, onroad diesel and jet fuel is a strategic necessity for nearly all refiners; participation in the marine fuels market is more of an option. Several oil majors are leading suppliers of marine fuels, but other refiners do not participate directly—hence the large and active bunker fuels blending and supply sector.
Moreover, while major bunkering centers are located in places such as Houston, Rotterdam, Fujairah and Singapore, volumes sold can be more fluid than those of fuels for inland consumption. Ships can and do alter where they bunker, based on supply and pricing. Therefore, there is not the same onus on many individual refiners to be involved in the marine fuels market as there is for other transportation fuels.
Bunching of refinery projects in 2019 represents a danger. A critical determinant for the refining industry is
whether scheduled capacity additions between 2016 and 2019 will materialize in time. The drop in crude oil prices has im-pacted the timing of refining investments. It has led to the defer-ral of planned refinery additions, such that now a peak of ap-proximately 1.7 MMbpd of new capacity is projected for 2019 (FIG. 3). This capacity includes projects that have not started construction, adding a concern that any further slippage will ex-acerbate 2020 marine fuel supply issues.
Potential for widespread economic strain on markets, with winners and losers. In a situation that calls for full
compliance in 2020, the authors’ outlook is for severe strain on petroleum product markets. This outlook is based on sharp in-creases in marine gasoil-intermediate fuel oil (MGO-IFO) price differentials, which translate into higher prices for inland diesel/ gasoil, jet fuel, kerosine and gasoline throughout the world be-cause of the coproduct nature of refining. Prices for HS HFO are expected to drop significantly. Initial “spike” differentials could hit or exceed $500/t, $60/bbl for diesel vs. HS HFO.
This points to winners and losers among refiners. Deep-con-version, high-complexity refineries (those able to process high volumes of heavy, sour crude) are clear winners, especially where the orientation is toward distillate yield. Conversely, less com-plex refineries producing high HS HFO yields look to be losers, with implications for possible additional refinery closures.
2012 Mbpd $ B, 20 15 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 2.0 0 10 20 30 40 50 60 70 80 2013 2014 2015 2016 2017 2018 2019 2020 2021 Deferrals
FIG. 3. Annual distillation capacity additions and total projects investments, 2012–2021.
TABLE 2. Sulfur reduction/recovery mechanisms from authors’ modeling analysis1
Amount, st/cd % of total
Sulfur into petcoke (increased
coking unit throughputs) 4,500 30% Sulfur into increased FCC stack gas SOx 250 < 2%
Sulfur recovered via increased throughputs on existing 2020 SRUs (close to 4% utilization increase, worldwide average)
5,400 36%
Sulfur recovered from needed 2020 SRU capacity additions beyond projects (nameplate capacity approximately + 9,500 st/cd)
4,850 32%
Total incremental sulfur 15,000 100%
DON’T LET JUST ANY SUPPORT
MEDIA IN YOUR BED
Keep your catalyst safe and supported with Denstone
®media
For more than 60 years, Denstone® has been the industry standard in catalyst bed supportmedia, and with good reason. Denstone offers consistent, reliable quality and performance that no other support media can match.
Don’t compromise the integrity of your reactor. Put your concerns to rest with Denstone®
spherical and Denstone® deltaP® shaped support media.
Discover more about Denstone support media at
www.Denstone.com
Market will ‘clear’—but when and how are uncertain.
These predictions of tight/inadequate capacity and severe eco-nomic strain raise the question of what will actually happen in 2020. For a start, 100% compliance with the Global Sulfur Rule seems unlikely because of supply tightness and limitations on what the shipping sector can afford to pay for fuel. Also, MAR-POL Annex VI allows for waivers in the event of non-availabil-ity of compliant fuel.
Equally, enforcement is a prospective issue, opening up the potential for illegal non-compliance. Strained economics could also lead the market to enter into additional adaptations and clearing mechanisms, driven by price elasticity effects:
• Depressed prices for HS HFO could open up more outlets, thereby boosting demand to a limited extent: o Industrial boiler/power sector (although widespread
restrictions on sulfur apply) o Seasonal demand for asphalt
• Increased prices for diesel/gasoil, jet fuel/kerosine and gasoline could curb demand, but with the associated risk of adverse economic impacts
• A strong market contango on HS HFO could instigate a move to build HFO stocks—effectively following in the footsteps of the crude oil inventory build of recent years • Over the medium term, increased premiums for light
sweet crudes and higher discounts for heavy sour grades could affect supply in regions where production is economically sensitive; think increased production of
light sweet oil (notably North American LTO) and lower production of heavy sour crudes (such as Canadian oil sands).
Takeaway. The next scheduled step in the IMO Annex VI
pro-cess was for an implementation plan to be developed at a meet-ing of the subcommittee on Pollution, Prevention, and Response (PPR) in late January, with submission to MEPC 71 in July 2017 for approval. This timeline is only part of what is sure to be a long and complex process with far-reaching consequences.
Recognizing the amount of time needed for the shipping and refining industries to adapt—and that the outcome is un-certain, with a lot of “moving parts”—it will be essential for all stakeholders to stay on top of developments. This will entail tracking and evaluating the outlook from the present to 2020 and beyond, with a keen focus on progress in necessary refinery investments, scrubber installations, fuel demand mix, formula-tions and compatibility, market supply/demand, compliance and price impacts worldwide.
LITERATURE CITED
1 EnSys Energy and Navigistics Consulting, “Supplemental marine fuel availability
study,” July 2016, sponsored by IPIECA, BIMCO, CONCAWE/Fuels Europe, Canadian Fuels Association and Petroleum Association of Japan.
2 Faber, J., “Assessment of fuel oil availability—final report,” July 2016.
3 Field Upgrading, “Ship and bunker update: IMO decides on 2020 for 0.5% global
bunker sulfur cap,” October 2016.
MARTIN TALLETT is founder and President of EnSys Energy,
a consulting practice specializing in quantitative assessment of the global downstream petroleum industry, covering refining, logistics, trade, regulations, investment and related strategic issues. He co-leads, with David St. Amand, the EnSys-Navigistics Marine Fuels 2020 service. His early background was in a variety of refining and planning positions with Exxon and Amoco. Since 2007, he has been involved in marine fuels assessments for a range of government, refining and shipping industry clients. He holds a BSc degree in chemical engineering from the University of Nottingham in the UK.
DAVID ST. AMAND is President of Navigistics Consulting, a
management consultancy dedicated to the maritime and energy fields. He has extensive expertise on marine fuel consumption, marine fuels (including LNG and hybrid fuels) and marine fuel markets. He has conducted global and regional studies of marine air emissions, marine fuel efficiency, marine bunker fuel markets and technical issues for a wide variety of public and private clients. Mr. St. Amand began his career with a major oil company and was technical lead on its tanker energy conservation efforts before moving into crude oil supply. He holds a BS degree in naval architecture and marine engineering from Webb Institute in Glen Cove, New York, and an MBA from Dartmouth’s Tuck School of Business in Hanover, New Hampshire.
THOMAS WITMER is a consultant for EnSys Energy, where he
supports technical and business strategy throughout the upstream and downstream. His most recent assignments include analysis of marine fuels issues and the US Strategic Petroleum Reserve. He holds BS degrees in industrial engineering and finance from Lehigh University, and is an active member of the Society of Petroleum Engineers.
DANIEL DUNBAR has been associated with EnSys since 1984.
He has more than 30 years of experience in the petroleum and related industries, with particular expertise in petroleum technology and economics, oil and gas production, electric utilities and computer-based simulation. Prior to his association with EnSys, he held supervisory and executive positions with Getty, Chemico and Commonwealth Oil, Nuclear Power Services Co., Gordian and ICF. Mr. Dunbar received a BS degree in chemical engineering from Columbia University in New York, New York.
TRI-CON TRI-CHECK TRI-BLOCK
TRI-SHARK
THE NEXT GENERATION
TRI-CONTROL TRI-JACK
WWW.ZWICK-VALVES.COM
Industry Metrics
MIKE RHODES, MANAGING EDITOR
Hydrocarbon Processing | FEBRUARY 2017 15 European refinery margins weakened due to slower gasoline export
opportunities, despite the colder weather. Strong regional demand and the end of maintenance season in Asia could not overcome margins weakened by oversupply. US refinery margins saw recovery in US gasoline crack spreads on the back of healthy domestic demand amid stronger exports to Latin America.
Pr oduc tion, Bcf d 0 20 40 60 80 100 0 1 2 3 4 5 6 7
Monthly price (Henry Hub) 12-month price avg. Production D N O S A J J M A M F J D N O S A J J M A M F J D
Production equals U.S. marketed production, wet gas. Source: EIA.
2014 2015 2016
Monthly price (Henry Hub) 12-month price avg. Production
US gas production (Bcfd) and prices ($/Mcf)
2016 2015 2014 Oil pric es, $/bbl 20 30 40 50 60 70 80 Dubai Fateh W. Texas Inter. Brent Blend D N O S A J J M A M F J D N O S A J J M A M F J D Source: DOE
Selected world oil prices, $/bbl
Global refining margins, 2015–2016*
Margins, US$/bbl 5 WTI, US Gulf Brent, Rotterdam Oman, Singapore 0 10 15 20
Mar.-16 April-16 May-16
June-16 July-16
Aug.-16 Sept.-16 Oct.-16 Nov.-16 Dec.-16 Dec.-15 Jan.-16 Feb.-16
Global refining utilization rates, 2015–2016*
60 70 80 90 100
Utilization rates, % USEU 16 JapanSingapore
Mar.-16 April-16 May-16 June-16 July-16 Aug.-16 Sept.-16 Oct.-16 Nov.-16 Dec.-16 Dec.-15 Jan.-16 Feb.-16
US Gulf cracking spread vs. WTI, 2015–2017*
Feb.-16
Cracking spread, US$/bbl
Prem. gasoline Jet/kero Diesel Fuel oil -20-10 0 10 20 30 40 50 60
Mar.-16 April-16 May-16 June-16 Joly-16 Aug.-16 Sept.-16 Oct.-16 Nov.-16 Dec.-16 Jan.-17 Dec.-15 Jan.-16
Rotterdam cracking spread vs. Brent, 2015–2017*
Prem. gasoline Jet/kero GasoilFuel oil
-20 -10 10 20 40 30
Cracking spread, US$/bbl
0
May-16 Oct.-16 Nov.-16 Dec.-16 Jan.-17 Dec.-15 Jan.-16 Feb.-16 Mar.-16 April-16 June-16 July-16 Aug.-16 Sept.-16
Singapore cracking spread vs. Oman, 2015–2017*
-20 -10 0 10 20 30
Cracking spread, US$/bbl
Prem. gasoline Jet/kero GasoilFuel oil
Sept.-16 Oct.-16 Nov.-16 Dec.-16 Jan.-17 Dec.-15 Jan.-16 Feb.-16 Mar.-16 April-16 May-16 June-16 July-16 Aug.-16
Supply and demand, MMbpd
Stock change and balance, MMbpd
Source: EIA Short-Term Energy Outlook, January 2017.
82 84 86 88 90 92 94 96 98 100 -3 -2 -1 0 1 2 3 4 5 6 Stock change and balance
World demand World supply
Forecast
2012-Q1 2013-Q1 2014-Q1 2015-Q1 2016-Q1 2017-Q1 2018-Q1
World liquid fuel supply and demand, MMbpd
* Material published permission of the OPEC Secretariat; copyright 2017; all rights reserved; OPEC Monthly Oil Market Report, January 2017. An expanded version of Industry Metrics can be found
online at HydrocarbonProcessing.com.
Brent dated vs. sour grades (Urals and Dubai) spread, 2015–2017*
Light sweet/medium sour crude spread, US$/bbl-4-2 DubaiUrals
0 2 4 8 6
July-16 Aug.-16 Sept.-16 Oct.-16 Nov.-16 Dec.-16 Jan.-17 Dec.-15 Jan.-16 Feb.-16 Mar.-16 April-16 May-16 June-16
HIGHEST AVAILABILITY
API 618
COMBINED WITH BESTMAINTAINABILITY; FAST ACCESS TO ALL WEAR PARTS Full range:
Rod load up to 1’500 kN / 335’000 lbs Power up to 31’000 kW / 42’100 hp Lubricated up to 1’000 bara, non-lubricated up to 300 bara Advanced solutions for demanding and sour gas applications
Over 120 years of experience in valve design and manufacturing
Outstanding durability of Redura® sealing elements for longest mean time between overhaul (MTBO) Worldwide Burckhardt Compression quality, engineered in Switzerland Your solution partner – From bare shaft compressors to turnkey solutions
Full range of services and top performing components through global organization and local service centers
→ www.recip.com/api618
API 618
Global Project Data
LEE NICHOLS, EDITOR/ASSOCIATE PUBLISHER
Hydrocarbon Processing | FEBRUARY 2017 17 According to Hydrocarbon Processing’s Construction Boxscore
Database, new project announcements have averaged 11 per month since mid-2016. However, when compared to the same time frame in 2015, new project announcements per month have nearly halved. Although new project announcements have decreased over the past
couple of months, global downstream project investments are near an all-time high. The Hydrocarbon Processing Construction Boxscore Database is tracking more than $1.6 T in announced projects around the world. In total, approximately 60% of active downstream projects are in the preconstruction phase.
Boxscore new project announcements, December 2015–present $430 B $275 B $168 B $222 B $332 B $77 B $140 B Asia-Pacific Canada Latin America Middle East Europe Africa US
Detailed and up-to-date information for active construction projects in the refining, gas processing and petrochemical industries across the globe | ConstructionBoxscore.com
Market share analysis of active downstream projects by region
Jan.-17 Dec.-16 Nov.-16 Oct.-16 Sept.-16 Aug.-16 July-16 June-16 May-16 April-16 Mar.-16 Feb.-16 Jan.-16 Dec.-15 18 27 18 21 15 13 12 12 12 11 13 10 10 26
16%
US21%
Middle East11%
Latin America14%
Europe4%
Canada28%
Asia-Pacific6%
AfricaTotal announced downstream project investments by region, 2017–2030.
OPTIMIZE
PERFORMANCE
Prior to fabrication, we can use Computational Fluid Dynamics (CFD) to validate injector spray performance. We can also use failure analysis modeling to verify the injector design will withstand process conditions such as thermal stresses, heat transfer, vortex shedding and more. Prior to fabrication, we can use
VALIDATE
DESIGN
Whether you need to cool gas, dissolve salts in overhead lines or inject chemicals or torch oil into a gas stream, we can meet your needs. Injector types include hydraulic, gas atomizing and steam versions equipped with a wide range of nozzles.
Whether you need to cool gas,
BUILD
TO ORDER
Companies like Technip, Mustang Engineering, Bechtel, Shell and many others rely on us to manufacture B31.1, B31.3 and U-Stamp code-compliant injectors and conduct radiographic, hydrostatic, ferrite tests and more. Let us do the same for you. Our local experts and Spray Technology Centers are right where you need them – in your area.
For unmatched service and support, visit spray.com/localexpert or call 1.800.95.SPRAY.
TALK WITH YOUR LOCAL SPRAY EXPERT TO FIND OUT HOW WE CAN HELP
Let us assist with nozzle selection, determination of injector placement in the vessel and spray direction to ensure optimal performance based on your exact operating conditions.
Hydrocarbon Processing | FEBRUARY 2017 19
Reliability
HEINZ P. BLOCH, RELIABILITY/EQUIPMENT EDITOR
[email protected]The risks of deferred compressor maintenance
At a recent conference attended by failure investigation professionals in San Antonio, Texas, a participant spoke about an explosion and fire event on a multistage horizontally opposed compressor in oxy-gen (O2) service. He had scant data, but
he knew the machine did not have cylinder lubrication. Pure O2 and lubricants cannot
coexist, which means that non-lubricated compressors must be used in O2 service.
Moving compressor pistons cannot be allowed to scrape on cylinder walls. Therefore, on horizontally arranged compressors, the pistons are fitted with Teflon, or even more advanced carbon-containing, high-performance polymer rider bands.1 These rider bands make
slid-ing contact with the cylinder bore. Once the rider band is worn off and the piston makes contact with the cylinder bore, it does not take long to create red-hot condi-tions of frictional heat.
At this point, the conference partici-pant recalled that the horizontally opposed machine had not been properly grounded. He said this condition had led people to surmise that the event had something to do with static electricity. However, the participant then said that the compressor internals had not been looked at in a while due to “deferred maintenance.”
Deferred maintenance can be a huge mistake and, while generally acceptable for non-critical equipment, it is decidedly
not acceptable for horizontal multistage
reciprocating compressors in O2 service. Why vertical non-lubricated compres-sors are best. When Pennsylvania-based
York Manufacturing built the vertical com-pressor shown in FIG. 1 for Pearl Brewing Co. in San Antonio, York’s designers had good reason to opt for a vertical piston ar-rangement in this two-stage compressor. The rider bands in this machine were likely made of soft copper or graphite, for tech-nical and metallurgical reasons. The rider bands in a vertical compressor make little or no contact with the cylinder bores.
Furthermore, modern user plants are acutely aware of low-maintenance, verti-cally oriented labyrinth piston compres-sors. Pick a leading manufacturer of such machines. Observe from the manufac-turer’s website, or from the many available texts on this equipment, how the piston periphery is machined threadlike, perhaps similar to the pitch of a ¼-20 screw thread. Slight tapering of the top of the piston assists the compressor piston to remain concentric relative to the cylinder bore, although the radial clearance is often less than the thickness of a hair.
Thousands of these machines are in service today. Reference 22 devotes a full
chapter to this “best available technology” non-lubricated category of compressors. Since the museum-grade 225-hp York compressor in FIG. 1 is probably not for sale, and its 257-rpm 14-pole synchro-nous Allis-Chalmers motor is surely out of warranty, the author suggested that the at-tendee look for a used or remanufactured vertical compressor. If no replacement compressor is found, then the attendee may need to opt for another horizontally opposed reciprocating compressor and ensure that first-rate piston rings, valves, rider bands and packing rings are used.
Teflon must be run in; a good book should be consulted for guidance. Rod drop indicators must be installed on each piston rod, and these eddy current-based indicators must be connected to alarm and shutdown circuitry. The claim that “all instruments were destroyed in the fire” is unrelated to the monitoring instruments, which should have given warning before the ultimate catastrophic event. The machine should be grounded, and a regulated supply of nitrogen sweep should always keep the distance piece above atmospheric pressure.
An additional piece of advice might be: While reviewing maintenance inter-vals, instrument surveillance, account-ability issues, operator vigilance, and perhaps even issues of basic competence,
it would be prudent, ethical and humane for the attendee’s company to put up a big
sign: “Stay clear! Oxygen compressor on deferred maintenance list.”
LITERATURE CITED
1 Bloch, H. P., Petrochemical Machinery Insights,
Elsevier Publishing, Oxford, UK and Waltham, Massachusetts, 2016.
2 Bloch, H. P., A Practical Guide to Compressor
Technology, 2nd Ed., John Wiley & Sons, Hoboken,
New Jersey, 2006.
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 or co-written close to 700 publications, among them 20 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 (cum laude) in mechanical engineering. He is an ASME Life Fellow and maintains registration as a Professional Engineer in New Jersey.
FIG. 1. A two-stage, non-lubricated vertical compressor, built for Pearl Brewing Co. in San Antonio, Texas, by York Manufacturing.
Automation and continuous monitoring of industrial processes are essential to achieve the best profitability and safety for chemical and petrochemical production plants. SICK offers a broad product portfolio for gas analysis, flow metering and particulate measurement. The devices use cutting-edge technology and cover extractive as well as in-situ techniques. They are designed to cope with aggressive environments and hazardous process conditions. We support our customers with intelligent, tailor-made solutions, which include sample conditioning systems and system integration. With a strong, expanding presence across the country, SICK is able to provide full after-sales support covering spare parts, repairs, field service and customer training. We think that’s intelligent.
In the US visit www.sickusa.com In Canada visit www.sickcanada.com
Hydrocarbon Processing | FEBRUARY 2017 21
Automation
Strategies
LARRY O’BRIEN, VICE PRESIDENT
ARC Advisory GroupNext-gen automation services support
operational excellence and reduce project cost
Major suppliers are expanding their automation-related ser-vice capabilities from project and engineering serser-vices through services for operations and maintenance. This is happening partly in response to overall automation market conditions, but largely in response to evolving user challenges and require-ments. At the same time, the Industrial Internet of Things (IIoT) now provides an enabling platform for a new generation of IIoT-enabled remote support services. These services span the plant lifecycle, from system engineering and design “in the cloud,” to data as a service for operating process plants.
These services can be quite sophisticated, involving com-plex analytical capabilities. On the other end of the spectrum, smaller “microservices” are particularly easy to use and de-ploy, and they can provide quick, easy-to-access information about key plant assets.
To date, the IIoT message for the hydrocarbon processing industry has focused largely on unlocking asset information to support the move toward condition-based and predic-tive maintenance strategies. Others see the IIoT as a path to help improve plant operations, operator training services and more. This raises new concerns and questions regarding how automation suppliers will provide remote services for asset management and monitoring, particularly with regard to who owns plant data and how that data is shared. Cyber security is another primary concern.
As owner-operators continue to struggle with the mass exodus of experienced talent in the workforce, automation suppliers have a prime opportunity to expand their respec-tive service businesses with new service delivery approaches and capabilities.
Today, owner-operators are leveraging automation supplier-provided services to improve operational excellence and man-age migration and modernization projects, as well as the in-creasing use of commercial IT technologies on the plant floor.
IIoT breathes new life into remote services. Automation
suppliers are aggressively targeting IIoT-enabled services for re-mote monitoring and supporting their customers’ plant assets. The ability of the IIoT to place large amounts of plant and asset data into the cloud for analysis provides a relatively simple, se-cure and cost-effective way to perform predictive analytics and provide guidance on how to improve plant operations, increase maintenance effectiveness and avoid unplanned downtime.
The IIoT also enables simple “microservices” that provide real-time feedback on the condition of certain classes of plant assets. These microservices can also incorporate “lightweight” analytics models that can present information in simple ways
on mobile devices. More complex and far-reaching services can incorporate sophisticated models and analytical tools to optimize the performance of thousands of individual assets or classes of assets across an entire plant, multiple plants or the entire enterprise.
Hybrid product/service model. These new IIoT-enabled
services could not exist without appropriate products and applications. Connected products go hand-in-hand with con-nected services. Services will become a much larger compo-nent of the overall automation space, which previously fo-cused on products and hardware.
Some owner-operators are also moving to a model where they do not purchase the equipment themselves. The equip-ment can be provided as part of an outcome-based service agreement that includes software and monitoring services.
Supplier service capabilities can reduce project costs.
Owner-operators also face significant pressure to reduce the cost and complexity of automation projects. Here, next-gen services complement a new generation of products, such as configurable and characterizable I/O and cloud-enabled sys-tem engineering environments that allow for late binding of the automation system software to the hardware.
Most major suppliers started building their main automa-tion contractor (MAC) capabilities a decade ago. Shrinking end-user resources and diminishing focus on process automa-tion were increasing demand for a single point of responsibil-ity for all automation-related aspects of a project. Today, sup-plier MAC capabilities incorporate these new technologies to drastically reduce the time to project completion and mini-mize customization costs associated with automation projects. ARC’s recently updated, “Supplier-provided automation services” report provides a good starting point for owner-op-erators to evaluate supplier capabilities and market presence by industry, region, and types of products and solutions sup-ported.
LARRY O’BRIEN, Vice President of Process Automation at ARC Advisory Group, has more than 20 years of experience working in the automation and consulting business. He has helped author numerous reports at ARC, including, “Collaborative process automation system 2.0,” “Distributed control system market size and forecast,” “Control system migration survival manual,” and “Automation supplier provided services market size and forecast.” Mr. O’Brien also served for three years as global marketing manager at Fieldbus Foundation.
FASTER. SAFER.
PREPARE PLANT
EQUIPMENT FOR
ENTRY IN
8-12 HOURS
©2016. United Laboratories International, LLC. All Rights Reserved.
For more information, contact:
Meghan Kidwell, Global Marketing Manager
[email protected]
+1.832.775.1548 | www.zymeflow.com
Shorten your turnaround using ZymeFlow
®Decon.
Save Time. Increase Safety. Choose ZymeFlow
®.
With 25 years of experience in refining and petrochemical
applications, the ZymeFlow brand of specialty decontamination
chemistries and services is the global leader for fast and safe
vessel entry. The unique ZymeFlow process simultaneously
eliminates benzene, LEL's, hydrogen sulfide, and pyrophoric iron
sulfides, dramatically reducing the time spent to prepare vessels
for entry and hot work. Furthermore, the process is safe for
people, equipment, and wastewater plants.
ZymeFlow Decon is active in over 50 countries, performing about
200 specialized decontamination projects each year.
Hydrocarbon Processing | FEBRUARY 2017 23
Refining
TOMMY MARS, MANAGING DIRECTOR
Opportune LLP, London, UKEurope’s refineries: Walking dead or happy valley?
Unloved and increasingly unneeded, Europe’s oil refining sector has been under duress for an astonishing four de-cades. As in many other sectors, Europe’s refineries expanded during the post-war decades to accommodate the internal needs of national markets. That world changed following the second oil shock of 1979–1980 and the globalization of the oil industry. Increased efficiency and weak economic growth reduced demand, and new, lower-cost producers, such as Russia, the US and the Middle East, forged a strong competitive advantage. Europe’s refineries became less relevant as the shortcomings of small-scale and high cost became increasingly apparent.
To be blunt, in today’s uncertain envi-ronment, many European refineries sim-ply do not need to exist, at least not for economic reasons. Yet, there they remain.
This picture of decline and irrelevan-cy may not be promising, but first glances can be deceiving. First, it is necessary to examine how we got here.
How European refining became a zombie sector. Despite some
consolida-tion and a few—too few—closures over the years, European refining has remained characterized by vast overcapacity, under-utilization and a lack of profitability.
How the sector continues to exist at all can be explained by factors that will be familiar to veterans of other sluggish industries across Europe. In some cases, refineries are seen as national strategic as-sets that are vital to securing fuel reserves. This is sometimes combined with a lack of political will to close refineries for fear of incurring the wrath (and negative pub-licity) of powerful labor unions.
Beyond that, regulatory and environ-mental challenges can make it prohibi-tively expensive to close refineries; they are literally unable to die. Finally, in a few instances, refiners compounded their misery by over-investing in diesel pro-duction just before the European market
was flooded with diesel from Russia, the US and the Middle East. These firms are now hanging on, reluctant to abandon their investments until they can recoup some of their costs.
How the M&A market for European refining was wiped out in a flash.
For a brief, idyllic period in the mid-2000s, it appeared that European refin-ing might consolidate its way to viability and relative health. The high-margin en-vironment and economic robustness of the 2004–2008 “golden age” of refining gave the sector a new lease on life. Inves-tor interest increased as international oil companies (IOCs) were keen to offload refineries. Several independents, such as Petroplus, were able to reshape and consolidate assets, and national oil com-panies (NOCs) became a buying force in the market, as Lukoil, KuzMunaiGas, Rosneft, Petrochina and others acquired refining assets across Europe.
Sadly, this exuberance gave way to tears once the price environment declined and imports soared. As market condi-tions worsened, European refiners faced complex and potentially overwhelming economic challenges, and not all of them were well-equipped to survive. At pres-ent, operators are confronted with only a handful of options for their refineries:
• Outright sale of the plant, but the number of buyers is limited to trading houses and select private equity firms • Increasing plant flexibility to take
advantage of market opportunities, such as producing low-sulfur fuels compliant with European regulations
• Conversion to a storage terminal, which has been the traditional approach to shutting down refinery operations, minimizing remediation and conversion costs • Conversion to a biofuels plant,
which is a new approach being
implemented by European IOCs to shut down uncompetitive refineries • Permanent closures of European
refineries present several challenges that have prevented an efficient and timely
rationalization of the sector for decades. In general, refinery closures in Europe have been difficult to implement, and this trend will likely continue.
This predicament shines a light on some common-sense, yet surprisingly in-novative, opportunities for a new type of buyer that is willing to approach this sec-tor from a different perspective:
• Oil traders. Traders are now the main buyers of refineries, using them as a platform for an asset-backed trading model. The model enables both flexibility and arbitrage, and traders profit from storage potential, demand and supply disconnects in time, highlighted when forward prices are higher than spot prices (what is called contango), location (geographical price differentials) and quality. • Selected distressed asset
investors/private equity. Using the same logic as traders, these investors take a wider strategic focus built around the “old fashioned” idea that refining assets can be run more efficiently.
So, are there opportunities, after all?
As traders and others have demonstrated, sophisticated investors have seemingly “cracked the code,” showing how crude oil and refined product flows and coordi-nated logistics are the keys to profitability in European refining. The money is not in
the refining business itself; it is all about the ability to exploit market disconnects.
With traditional operators openly di-vesting their downstream business,
as-tute investors have the opportunity to “bargain hunt,” cherry-picking the best refining assets for their portfolios and un-locking the potential to build them into profitable asset-backed trading platforms.
However, not all refineries are attrac-tive. Investors will benefit only from re-finery assets that offer size and econo-mies of scale, are nimble enough to react quickly to market changes, can market themselves flexibly, are able to integrate well with supply chains, have efficient logistics and infrastructure, or can offer a captive market for refined products. All others will need to review alternatives and analyze the cost-benefit profile of a conversion project.
This is not an opportunity for the faint of heart. As with secondhand cars, the rule is, “Buy the best that you can af-ford.” Success depends on:
• Valuation: Only distressed sales have any chance of success. • Limited CAPEX: The cushion
to spend on major upgrading is limited, or nonexistent.
• Good configuration and location:
Ready access to crude intake and markets is vital.
• Potential uplift in profits: While not necessarily related to processing, upside potential still exists for improvements in operational efficiency, reducing energy consumption, etc. • Favorable labor environment:
This is critical, and often difficult, but the ability to streamline workforces is vital.
• Sustainable environmental liabilities: As noted, regulatory and environmental constraints can be show-stoppers, precluding a buyer from making any
meaningful changes.
Refiners and traders are converging toward an asset-backed trading model, which provides an avenue to expand rev-enues, stabilize returns (returns on trad-ing are less affected by the level or direc-tion of oil prices and refining margins) and make companies more flexible. As such, refiners are shifting their emphasis from marketing to trading, while traders
are acquiring refining and logistical assets. IOCs and refining independent players must reshape their portfolios and change the configurations of their assets to take advantage of such opportunities.
In a segment of the industry thought to be moribund and declining, the spirit of innovation has opened a surprising win-dow of opportunity for canny investors.
TOMMY MARS is a Managing Director and leads Opportune’s European practice. He has more than 15 years of international energy industry experience, gained by working with supermajors, national oil companies, regional oil and gas players, oilfield services companies, governments and related institutions on a wide range of topics. Throughout his career, Mr. Mars has worked for and with energy companies throughout the Western world and the Middle East on strategic, operational and financial matters covering all parts of the oil and gas value chain. He is a trusted advisor to senior executives, and is well-known for his ability to integrate and drive collaboration across silos and disciplines in complex oil and gas businesses.
5 June 2017 –
Vienna, Austria
HydrocarbonProcessing.com/AwardsNominations Close: 3 April 2017
Nominations Now Open for the Hydrocarbon Processing Awards
The editors of Hydrocarbon Processing are thrilled to announce the launch of the annual Hydrocarbon Processing Awards.
The awards program will honor the downstream energy segment’s leading innovations, as well as outstanding personal contributions to the industry.
It is FREE to submit an entry. To be considered, projects must have been started between January 2016 and December of 2016 and fall under one of 12 award categories. (Companies may submit nominations in more than one category, as well as provide multiple submissions in the same category.) Winners will be announced at a black tie gala to be held 5 June at the Hilton Vienna Danube Waterfront in Vienna, Austria.
The categories for nomination are:
• Best asset integrity
• Best automation/modeling/ instrumentation
• Best gas processing technology • Best petrochemical technology
• Best refi ning technology • Best catalyst technology • Best community outreach award • Best E&C design
• Best HSE petrochemical • Best HSE refi ning • Lifetime achievement • Most promising engineer Visit HydrocarbonProcessing.com/Awards by 3 April to make your nomination(s)!