Impact 2/2014 - Shell Global Solutions

ISSUE 2, 2014

Shell Global Solutions

The importance of creative interaction

How Shell is helping to develop fuels for the future

Helping to produce high-quality winter diesel in Russia

THE POWER OF APPLIED TECHNOLOGY AND INNOVATION

2 impact issue 2, 2014

SHELL GLOBAL SOLUTIONS BRAND DISCLAIMER Shell Global Solutions is a network of independent technology companies in the Shell Group. In this material, the expression “Shell Global Solutions” is sometimes used for convenience where reference is made to these companies in general, or where no useful purpose is served by identifying a particular company. These materials are intended for general information purposes only and do not in any way constitute an offer to provide specific services or goods. Some services or goods may not be available in certain countries or political subdivisions thereof.

CRITERION BRAND DISCLAIMER Criterion Catalyst & Technologies (Criterion) is a wholly owned subsidiary of CRI/Criterion Inc., which is a part of the Shell Group.

SHELL GROUP BRAND DISCLAIMER In this material, the expressions “Shell”, “Group” and “Shell Group” are sometimes used for convenience where references are made to Royal Dutch Shell plc companies in general, or where no useful purpose is served by identifying a particular company. These expressions are also used where there is no purpose in identifying specific companies. These materials are intended for general information purposes only and do not in any way constitute an offer to provide specific services or goods. Some services or goods may not be available in certain countries or political subdivisions thereof.

FORWARD-LOOKING STATEMENTS DISCLAIMER This document contains forward-looking statements concerning the financial condition, results of operations and businesses of Royal Dutch Shell plc. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements are statements of future expectations that are based on management’s current expectations and assumptions, and involve known and unknown risks and uncertainties that could cause actual results, performance or events to differ materially from those expressed or implied in these statements. Forward-looking statements include, among other things, statements concerning the potential exposure of Royal Dutch Shell to market risks and statements expressing management’s expectations, beliefs, estimates, forecasts, projections and assumptions. These forward-looking statements are identified by their use of terms and phrases such as ‘’anticipate’’, ‘’believe’’, ‘’could’’, ‘’estimate’’, ‘’expect’’, ‘’intend’’, ‘’may’’, ‘’plan’’, ‘’objectives’’, ‘’outlook’’, ‘’probably’’, ‘’project’’, ‘’will’’, ‘’seek’’, ‘’target’’, ‘’risks’’, ‘’goals’’, ‘’should’’ and similar terms and phrases. There are a number of factors that could affect the future operations of Royal Dutch Shell and could cause those results to differ materially from those expressed in the forward-looking statements included in this document, including (without limitation): (a) price fluctuations in crude oil and natural gas; (b) changes in demand for the Group’s products; (c) currency fluctuations; (d) drilling and production results; (e) reserve estimates; (f) loss of market and industry competition; (g) environmental and physical risks; (h) risks associated with the identification of suitable potential acquisition properties and targets, and successful negotiation and completion of such transactions; (i) the risk of doing business in developing countries and countries subject to international sanctions; (j) legislative, fiscal and regulatory developments including potential litigation and regulatory effects arising from recategorisation of reserves; (k) economic and financial market conditions in various countries and regions; (l) political risks, project delay or advancement, approvals and cost estimates; and (m) changes in trading conditions. All forward-looking statements contained in this material are expressly qualified in their entirety by the cautionary statements contained or referred to in this section. Readers should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the release date of this document. Neither Royal Dutch Shell nor any of its subsidiaries undertake any obligation to publicly update or revise any forward-looking statement as a result of new information, future events or other information. In light of these risks, results could differ materially from those stated, implied or inferred from the forward-looking statements contained in this document.

The United States Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved reserves that a company has demonstrated by actual production or conclusive formation tests to be economically and legally producible under existing economic and operating conditions. We use certain terms in this document, such as “discoverable resources” or “producible resources” that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. The companies in which Royal Dutch Shell directly and indirectly owns investments are separate entities. In this document the expressions “Shell”, “Group” and “Shell Group” are sometimes used for convenience where references are made to Group companies in general. Likewise, the words “we”, “us” and “our” are also used to refer to Group companies in general or those who work for them. These expressions are also used here there is no purpose in identifying specific companies.

All the quotations in this document have been reproduced with the kind permission of our clients.

*Shell Global Solutions is a network of independent technology companies in the Shell Group. Its engineering services in the United States of America are provided by Shell Global Solutions (US) Inc. For projects in the United States of America that entail engineering services, Shell Global Solutions (US) Inc. will retain appropriately licensed engineers as necessary. Please note that certain engineering projects are not offered and are not available to the public in any/some of the States and Territories of the United States of America.

Copyright © 2014 Shell Global Solutions International BV. All rights reserved. No part of this publication may be reproduced or transmitted in any form or by any means, electronic or mechanical including by photocopy, recording or information storage and retrieval system, without permission in writing from Shell Global Solutions International BV. This publication is printed on environmentally friendly paper.

CONTENTS

COMMENT 3 Christophe Boulanger highlights the importance of applying technology and innovations

BUSINESS4 BUILDING ON A CENTURY OF INNOVATION Research continues at Shell Technology Centre Amsterdam

6 GETTING TO GRIPS WITH SULPHUR RECOVERY UNITS Why sulphur recovery unit design is so challenging

9 LEARNING FROM EACH OTHER The importance of creative interaction between the strategic licensor and EPC contractor

10 WORKING TOGETHER TO DEVELOP TOMORROW’S FUEL How Shell’s involvement in endurance racing is helping to develop fuels for the future

CASE STUDY12 MAKING DIESEL FOR RUSSIAN WINTERS Catalytic dewaxing helps refinery to produce high-quality winter diesel

14 TURNING THE TIDE ON HYDROCRACKER BOTTOMS Hyundai Oilbank proves there is value in lower-value by-products

PRODUCED BY MARKETING AND SOLUTIONS DEVELOPMENT

EDITORMergyla van Uytrecht

CONTACT DETAILSTel: +31 70 447 8007Email: [email protected] Web: www.shell.com/globalsolutions

15 FINE-TUNING FOR OPTIMUM PERFORMANCE IN SWEDEN How new reactor internals and catalysts helped Preem to get more from its hydrocracker

16 INSIDE INDONESIA’S ACCELERATED GAS PROJECTS How Indonesia is meeting its increasing national energy demands

19 ORSK’S REJUVENATION JOURNEY Future proofing a Russian refinery’s phased investments

Concept photo: Shutterstock.com

www.shell.com/globalsolutions 3

COMMENT

I recently participated in a meeting with influential economist Andy Xie. He discussed the fact that, even in markets where supply greatly exceeds demand, there will always be survivors. These industry leaders recognise the key role that innovative technologies can play in helping to maintain a competitive advantage. This constant drive for innovation can lead to the development of game-changing technologies, but technical evolution is often just as valuable. The main challenge is identifying which technologies will bring the greatest technical and commercial benefits.

Rising electricity demand in the Middle East and North Africa is one area where technology will play a key role, as these regions prepare for a greater diversification of supply. The first article (page 4) addresses the fact that each customer faces a unique situation based on their assets, markets and specific business objectives. Developing a flexible, tailored approach to their development is often the best way to capture value.

The focus in new fuel development is for greater efficiency and higher biofuel content. One of the best places to test the performance of a new fuel is in endurance racing, where innovative products can be subjected to extreme test conditions (page 10).

Identifying the potential benefits of a new technology is the crucial step, whether the objective is to choose the most effective options for electricity generation in the Middle East or to create innovative fuels. The ability to nurture new technologies and apply them in a commercial setting requires a clear understanding of where the energy industry is now and a clear vision for the future.

CHRISTOPHE BOULANGERVICE PRESIDENT, STRATEGIC CUSTOMERSSHELL GLOBAL SOLUTIONSINDUSTRY LEADERS RECOGNISE THE KEY ROLE THAT

INNOVATIVE TECHNOLOGIES CAN PLAY IN HELPING TO MAINTAIN A COMPETITIVE ADVANTAGE.

““

Concept photo: Shutterstock.com

President Gas Processing, Shell Projects & Technology. “STCA has led in the field of gas treatment for many years: research into the processing the gases released during crude oil cracking operations started in about 1928.”

By the 1950s, Shell was developing its amine processes, which involved cleaning gas by bringing it into contact with an amine (an organic ammonia compound). This method draws pollutants from the gas into the amine, which is then regenerated using steam and redeployed repeatedly in a circulating process. The sulphur compounds released during regeneration are used to make elemental sulphur, which is an important raw material for fertiliser.

For more than 50 years, researchers at the centre have continued to refine the amine processes by responding to industry needs to reduce the energy that the processes require and adapting them to meet ever-stricter environmental requirements. “This work is ongoing,” says Bodewes. “Recently, our efforts have led to the development of a biological desulphurisation processes (developed in

BUILDING ON A CENTURY OF INNOVATION

BUSINESS

4

Research continues at Shell Technology Centre Amsterdam


Sustained efforts in research and development (R&D) are fundamental to the success of technology

companies. The technologies that Shell developed 30 or 40 years ago are very different from the systems it uses today. The changes reflect a continuous process of innovation where research programmes are shaped by market drivers and customers’ needs.

This year marks 100 years of research activity at Shell Technology Centre Amsterdam (STCA), in the Netherlands, one of Shell’s three most important technology centres worldwide. The centre’s history shows how research has enhanced Shell capabilities in key technologies and is helping to shape current oil and gas operations.

H. P. Calis, Site Manager, describes the background to STCA: “Shell began conducting research in the Netherlands in 1895, but the opening of a new laboratory in Amsterdam in 1914 marked the first step towards today’s STCA. Initially, the work at the laboratory reflected the changing world of the

early 20th century, the emergence of the combustion engine and the need to develop materials for constructing roads and other infrastructure. From the start, however, research for the up- and downstream segments of the oil and gas industry was a core focus for the laboratory’s scientists and engineers.”

Real-world needs have guided the selection and development of R&D programmes: the results of which have been applied in all the world’s major oil and gas markets. This article focuses on three areas where the technology centre has made and continues to make strong contributions to the oil and gas industry: gas treatment technology, gas-to-liquids (GTL) processes and distillation technology.

Gas treatment technology Work on improving the methods for treating natural gas is a key research topic at STCA. “Advances in removing sulphur from natural gas and sulphur handling technology have contributed to cleaner combustion and opened up sulphur-rich oil and gas fields once considered uneconomic,” says Theo Bodewes, Vice


www.shell.com/globalsolutions 5www.shell.com/globalsolutions 5

partnership with Paqell BV, a joint venture with Paques Holding BV) in which special biological processes working at ambient temperature and pressure have replaced chemicals and steam.”

GTL technology and the Fischer–Tropsch process The Fischer–Tropsch process is a set of chemical reactions that convert a carbon monoxide and hydrogen mixture into liquid hydrocarbons. First developed in the 1920s, the process is a key component of GTL technology. Shell has more than 40 years of experience in researching GTL technology to convert natural gas into liquid products for use in transport fuel and lubricants and as raw materials for chemicals and detergents.

“Our efforts to develop Shell GTL technology started in 1973,” Guy de Kort, Vice President Development GTL, says, “and a decade later we had built a pilot plant in Amsterdam to conduct larger-scale tests on paraffin synthesis and conversion to make GTL products. The research had also shown that using higher concentrations of GTL products in fuel could help to reduce or improve exhaust emissions.”

By 1993, Shell had established the world’s first commercial GTL plant at Bintulu, Malaysia, which was designed to produce 14,000 barrels per day of high-quality products. In 2006, the government of Qatar approved the 140,000-barrels-per-day Pearl GTL project, a plant 10 times larger than Bintulu.

*Shell ConSep is a Shell trademark.


“The Pearl GTL plant employs almost the entire Shell portfolio of gas treatment technologies, many of which were developed at STCA. This includes technology to treat synthesis gas that needs intense cleaning so that the plant’s catalytic convertors will last for many years,” de Kort concludes.

Improvements in crude oil distillationIn the current economic climate, many refinery operators are focusing on revamping and debottlenecking existing units by making low-cost modifications and on minimising capital expenditure to secure short-term payback. This means there is emphasis on non-intrusive modifications such as replacing internals without modifying column widths. The design and performance of reactor internals are, therefore, of vital importance.

STCA has made a significant contribution in this area, as Amsterdam-based Global Manager for Refining Technology Pieter Eijsberg explains: “We invented the Shell ConSep* (contacting separator) tray at the centre in the early 1990s. Rather than relying on gravity, the Shell ConSep tray uses centrifugal force to improve the separation of gas and liquid, thereby enabling throughput gains of up to 60% for distillation columns. Shell has used this technology internally since 1995 and licensed it to customers since 2006.”

The truncated downcomers in the Shell ConSep trays are arranged for simultaneous maximisation of active area,

weir length, flow path and distribution. A revamp with these trays can help refinery operators to increase throughput without making major changes to a plant.

“Research into distillation at the centre continues to focus on improving distillation trays and separators,” says Eijsberg. “We have successfully tested a new version of the Shell ConSep tray in the laboratory and will demonstrate it on a bigger scale before potentially deploying it in several refineries.”

Looking to the past and to the future Innovation is a vital response in a changing world. The research at STCA is not about developing technology for its own sake: it is about finding solutions, deploying them quickly and adapting them to meet local needs.

“The work at STCA has led to discoveries and technical solutions that few would have dreamed of when we established the programmes. The projects that the teams in Amsterdam conduct illustrate the continuing power of scientific R&D to transform our lives,” Calis concludes. “As we prepare to meet the future’s challenges, we know that we will have to maintain a clear focus on the commercial goals that stimulated our work. For Shell and STCA, this means contributing to a sustainable energy future and helping to shape the future of energy through innovation.”


GETTING TO GRIPS WITH SULPHUR RECOVERY UNITS

A wave of new gasification plants is likely over the next few years as companies draw on the process’s

flexibility to use bottom-of-the barrel oil to produce feedstock for power generation and sufficient hydrogen to increase clean fuel yields to meet ever-more-stringent requirements. The design of the sulphur recovery unit (SRU) downstream of the gasification unit is a particularly challenging aspect of these projects.

“Gasification projects are characterised by their large production capacity (there are often multiple gasifiers) and the low hydrogen sulphide content in the acid gas sent to the SRU (the so-called lean acid gas),” says Gabi Leene, Senior Process Engineer, Shell Projects & Technology.

According to Leene, the following key aspects require careful consideration during the design of an SRU:

■ the ideal number of trains; ■ the right burner configuration to achieve sufficiently high combustion temperatures for effective contaminant destruction; and

■ for pure oxygen-fired Claus units: ■ whether a “heat sink” is necessary; and ■ the safe operation of the Claus unit by implementing the additional design requirements necessary for working with pure oxygen.

Determining the ideal number of SRU trainsSelecting the ideal number of SRU trains is a critical consideration, as it helps to balance the capital cost against plant availability. A minimum of two SRU trains is required (2 × 100%) to enable maintenance while the upstream gasifiers are operating, but additional trains are often installed (3 × 50% or 4 × 25%) to meet the required turndown. The resultant redundancy provides spare capacity in case of operational issues.

“Depending on the start-up philosophy of the gasification plant, the design engineer must first determine the minimum acid gas flow at which the SRU should be operational,” says Leene. “By taking this flow as the turndown requirement for a single SRU train, the engineer can determine the initial value for the design capacity per SRU train and the ideal number of trains. Of course, the final decision on the number of trains also depends on economics and emission requirements. With regard to the latter, the permissibility of temporary flaring at start-up needs to be checked.”

When multiple SRU trains are installed, all but one typically operate on fixed-flow control. The remaining train operates on pressure control to handle the fluctuations from the upstream units. Outside the scheduled turnaround, it is preferable that all trains should operate on acid gas rather than putting one train on hot standby. Long-term operation on hot standby or even shutdown is undesirable because of the risk of fouling or cold spots, which typically result in lower reliability and availability for this SRU train.

Selecting the right burner configurationFor proper destruction of the ammonia in the sour water stripper acid gas, the temperature in the Claus burner must be sufficiently high. If the temperature is too low, ammonia will slip and may form low concentrations of ammonia salts with the sulphite/sulphate ions present in the system. These salts can cause fouling and plugging of the downstream system. The precise temperature for ammonia destruction depends on the ammonia content of the burner feed. At low to medium ammonia levels, this is 1,250°C. To reach it, a combination of design measures is required.

There are three things to consider, Leene says. “First, high oxygen enrichment is necessary, i.e., 45–100% oxygen. This requires a different burner design, refractory precautions and special materials. Oxygen availability is normally not an issue, as the gasification process itself requires oxygen. An air separation unit typically provides the oxygen at about 99.5% purity. It is most cost-effective to design the SRU for such pure oxygen, as this provides the most reduction in equipment size.

BUSINESS


“Second, it is necessary to preheat the acid gas. This has several advantages. It helps to increase the combustion temperature, but is mainly required to keep the temperature of the mixed feed gas from the acid gas removal (AGR) unit and the sour water stripper above 70°C, which prevents ammonium bisulphide deposits from blocking the feed lines. In addition, it prevents condensed liquid from entering the SRU, as this could damage the burner and the refractory in the reaction chamber.

“Finally, a lean feed gas split flow from the acid gas from the AGR unit is often necessary. Here, part of the acid gas from the AGR unit bypasses the main burner and is injected directly into the back end of the main combustion chamber. In this way, the temperature in the front end of the main burner can be increased by allowing a higher percentage of hydrogen sulphide conversion in the process gas before it is diluted with the bypass gas fraction,” she concludes.

Checking if a “heat sink” is necessaryTo prevent catalyst deactivation and ensure stable operation of the absorber and the incinerator, the temperature development and the component levels in the Claus tail gas need to be checked. As the Claus burner uses pure oxygen, the process gas stream in the SRU will contain fewer inert components. Consequently, there may be a relatively large temperature increase across the Claus

Complex plants Gasification plants are complex integrated plants that combine a series of gas-treating technologies, as the synthesis gas (syngas) they produce needs purifying for use in the gas turbines of a power plant. Hydrogen cyanide/carbonyl sulphide hydrolysis and AGR remove the contaminants. The hydrogen cyanide and carbonyl sulphide are converted into hydrogen sulphide, carbon dioxide and ammonia. Most of the ammonia is knocked out using water and sent to the sour water stripper. The hydrogen sulphide and carbon dioxide are recovered as acid gas in the AGR unit.

The acid gas from the AGR unit and the sour water stripper is routed to the SRU for sulphur removal and recovery. The remaining tail gas is almost sulphur-free and will meet the emission specifications for release to atmosphere.

For a typical gasification unit, a conventional SRU configuration can be used. This has a Claus section, a sulphur degassing section, a tail gas treatment section (Shell Claus off-gas treating, SCOT*, unit) and an (thermal) incinerator. Overall, a sulphur recovery of up to 99.9% is achievable.

*SCOT is a Shell trademark.

GASIFICATION PROJECTS PRESENT SOME DESIGN CHALLENGES BUT ALSO OFFER SOME INTERESTING OPPORTUNITIES.“ “


BUSINESS

and SCOT reactors that almost exceeds the maximum design temperature. Outlet temperatures that exceed the normal operating temperatures of 300°C will accelerate catalyst ageing.

In addition, the hydrogen content in the treated SCOT gas sent to the incinerator will be fairly high. With fluctuations in the hydrogen content, temperature control of the incinerator becomes more difficult as the auto-ignition temperature for hydrogen is relatively high. More stable control is achievable if the hydrogen content is not too high.

The carbon dioxide content in the feed to the SCOT absorber will also be high (up to 50–80%). This increases the tendency for carbon dioxide co-absorption, the exothermic effect of which may hamper the selectivity of the amine solvent towards hydrogen sulphide.

“To mitigate these effects, one option might be a small nitrogen stream fed into the back end of the Claus main burner to provide a ‘heat sink’ and reduce the carbon dioxide and hydrogen levels in the Claus tail gas. This stabilises the operation of the reactor, absorber and incinerator,” Leene explains.

Ensuring safety in the Claus unitCompared with a standard air-operated Claus unit, SRUs operating on pure oxygen require additional safety measures. The main hazard in oxygen service is the risk of fire.

“Material selection considerations alone cannot prevent incidents during oxygen service,” Leene asserts. “Designers should take all possible precautions to avoid the initiation of an oxygen fire. The key factors to consider include the plot layout, system cleanliness and purging requirements, valve type and filter selection, and vent configurations. We follow Shell guidelines to help secure safe design and operation of oxygen-enriched Claus units. These guidelines are in line with international standards.”

The burner’s start-up and shutdown procedures should also receive special attention. To reduce the risk of an

flow contains fewer inert components. For a safe and optimised design,” she concludes, “the technologists need to tailor the design according to the specific feed and operating conditions, which affects the design of several different process units. An integrated design for the gasification and gas processing technologies can help to unlock substantial value.”

explosion, the burner should start up on air with fuel gas of constant quality for accurate air–fuel ratio control (preferably natural gas). The transition to acid gas/oxygen firing is a critical procedure. Co-firing of fuel gas with acid gas/oxygen can lead to overheating of the refractory and should be restricted to a short period while ensuring sufficient flexibility for the burner to reach a flawless and safe start-up. The burner control and safeguarding philosophy addresses all these aspects as part of a well-developed process design.

Challenges and opportunities“Gasification projects present some design challenges but also offer interesting opportunities, such as the unusual situation of having a good-quality supply of oxygen available,” says Leene.

“This enables equipment sizes to be smaller, as the reduced process gas


BUSINESS

From time to time, reports surface of major refinery projects in which it has become apparent that there is a lack

of integration between the engineering, procurement and construction (EPC) contractor and the technology licensor. This has led to instances, for example, where the licensor has not adequately responded to the EPC contractor’s requests for clarifications, which has resulted in the EPC contractor making seemingly inconsequential adjustments that have had a critical impact on the overall design.

Fortunately, it does not have to be this way.

Ravi Ravindran, Regional Lead Technical Packages EMEA, Shell Global Solutions International BV, has broad experience of interfacing with EPC contractors while project managing Shell Global Solutions’ licensing projects. He says that although this is an area where substantial long-term value can be at risk for the owner, the right approach and procedures can not only help to alleviate these concerns, they can also add substantial value.

As an example, he explains that many EPC contractors will often challenge the licensor’s design. Why are you using that type of compressor? Have you considered this type of valve concept? Is that redundancy really necessary? And Ravindran welcomes such suggestions.

“Good EPC contractors are highly knowledgeable and bring priceless experience, successful practices and valuable ideas,” he says.

For example, during the execution phase of a new base oil plant, Ravindran says the EPC contractor put forward several suggestions. “In some cases, they were to save capital expenditure; in others, the EPC contractor had identified alternative equipment that could be sourced with a shorter lead time or more locally. We declined some of these requests because we did not have sufficient experience with the hardware, process or concept. However, we did give the green light to some of their changes after a thorough technical assessment. We have to be assertive or flexible, depending on the situation, and we always screen any suggestions to guard against diluting our original design, but we welcome such dialogue with the EPC contractor because it can help towards ensuring the cost-effective and timely implementation of a quality project.”

Often, Ravindran’s interaction with the EPC contractor is about education to understand where the criticality lies, or it may simply be about clarification. “For instance, if the EPC contractor has never built a Shell-licensed hydrocracker

before they will likely have questions, so we always make ourselves available to respond and provide details and explanations,” he says.

Because the quality of that interaction is critical, Ravindran establishes a set of communication protocols with the EPC contractor early on in a project. This includes creating key focal points on each side and defining the handover procedures. “It is about making sure that the teams are organised and integrated in a proper way so that we can have creative interaction with the EPC contractor,” he says. “These collaborative discussions can really add value to the overall project.”

LEARNING FROM EACH OTHERThe importance of creative interaction between the strategic licensor and EPC contractor


WORKING TOGETHER TO DEVELOP TOMORROW’S FUELHow Shell’s involvement in endurance racing is helping to develop fuels for the future

In the global drive to reduce carbon dioxide emissions, governments are legislating to reduce fuel consumption

and increase the biofuel content of fuels. These requirements affect the vehicle manufacturers and fuel producers developing engines and fuels for the future. Where better to test these new fuels than in endurance racing.

Shell has long been associated with this sport. Its strong link with the 24 Hours of Le Mans dates back to the 1930s and includes being sole fuel supplier in 1935 and a partnership with Scuderia Ferrari established in the 1950s and one with Porsche established in the 1960s. Shell also helped Audi to win the race in 2006 with the first diesel car and to be the first to use an advanced biofuel for the 2009 race.

Shell has now signed an agreement with the Automobile Club de l’Ouest to be the official fuel partner to the FIA World Endurance Championship (FIA WEC) and the European Le Mans Series (ELMS). Shell has developed new gasoline and diesel race fuels, Shell V-Power* LM24 and Shell V-Power Diesel LM24, and is supplying fuel

to all the teams registered for the FIA WEC and ELMS.

At this year’s 24 Hours of Le Mans, Shell and the vehicle manufacturers faced some tough new regulations for the top-tier LMP1 (Le Mans prototype) cars. Compared with 2013, the teams were required to reduce their fuel consumption by 30% and to double the biofuel content from 10 to 20% in gasoline and 5 to 10% in diesel.

As well as these challenges, Shell faced a range of different requirements from the LMP1 manufacturers, Audi, Porsche and Toyota. The design for LMP1 engines is not stipulated, so manufacturers can use whichever design they prefer – from large, normally aspirated or smaller, turbocharged gasoline engines to diesel engines. The top-tier cars are also required to use energy recovery systems (kinematic and heat energy) to achieve the overall efficiency and performance targets.

The key to meeting the regulations was for the vehicle manufacturers and Shell to work together to design the engines and the fuels at the same time. Richard Karlstetter, Technology Manager Speciality Fuels, Shell

Global Solutions (Deutschland) GmbH, refers to this process as “co-engineering”.

“As a result of the new 2014 FIA WEC regulations, fuel composition is really a part of the design process of the new generation of engines,” says Karlstetter. “We are working with the car manufacturers to develop fuel with properties that enable the next generation of engine and combustion design. Therefore, the fuel is part of the design. Co-engineering has been essential because, to achieve the 30% fuel reduction target, the engine, fuel and hybrid system have to work together.”

Work began on the new fuels in 2012 with Shell and the race teams identifying the fuel requirements and specifying the formulations. The Shell technologists conducted desk studies and computer modelling to select the initial fuel candidates. They then produced small quantities of blends for the teams to test while they were developing the prototype engines. After feedback from both sides, the formulations moved to the next development stage: a process

BUSINESS



repeated several times before the final fuel candidates were identified.

Of this process, Alex Hitzinger, Head of LMP1 Development, Porsche, says, “Shell has the hard task of producing fuel that satisfies very different requirements, for example, a gasoline fuel for both turbocharged engines and for naturally aspirated engines. That is why it was important to find a good compromise to satisfy these different requirements.

“One difficult aspect is to maximise the useable energy you get out of the fuel. So, the whole development programme centres on improving engine efficiency. Here we look for friction, combustion and thermodynamic efficiency. Everything we do is about efficiency.”

The Shell V-Power race fuel formulations have been designed to enable the engine to operate as efficiently as possible. At the 2014 24 Hours of Le Mans race, the three teams competing for victory met the reduced fuel consumption target without any impact on performance – they achieved the same lap times and top speeds as in 2013. Audi won first and

second places, with Toyota in third place.

Working with leading car manufacturers and developing the fuels for endurance racing gives Shell the opportunity to develop more-efficient energy solutions for future road use. Karlstetter says, “The latest changes aim to focus development on technology that can be adapted for future production vehicles. Our work with the manufacturers has given us invaluable insights into the way they are thinking about the future of vehicle technology and better understanding of the demands these innovative racing drivetrains place on the fuel.”

Shell’s involvement in developing fuels for motorsport also provides the opportunity to test its fuel in demanding environments. Endurance racing is especially valuable says Karlstetter. “In terms of mileage, the 24 hours of Le Mans is the equivalent of about one season of Formula 1 or one year’s testing with a road car. And the diversity of powertrain technology in endurance racing provides wider opportunities for us to test the performance of our fuel formulations. We learn what the next-generation combustion engines

are going to have in terms of a fuel appetite. What we have learned in this year’s Le Mans will give us a greater insight into what is necessary.”

Karlstetter continues, “Our industry needs to identify new and effective ways to reduce the carbon footprint of a car, and we have demonstrated in this race that it is possible. The demand of the car industry will grow to bring these types of fuels to the market.

“Shell has an important role here because it can influence the way energy efficiency is defined and developed in the transport industry in the future. Motorsport is a unique opportunity and Shell believes this is the best place to push innovation and to look ahead before going to the market. We can gain considerable insights at an early stage and this helps us to develop the road fuels that will be needed in the future,” concludes Karlstetter.

*Shell V-Power is a Shell trademark.

SHELL’S INVOLVEMENT IN DEVELOPING FUELS FOR MOTORSPORT ALSO PROVIDES THE OPPORTUNITY TO TEST ITS FUEL IN DEMANDING ENVIRONMENTS.“

“



MAKING DIESEL FOR RUSSIAN WINTERS

because it avoids the need for expensive additives or kerosene blending. In addition, it enables the use of heavier or more paraffinic feedstocks that have a higher cloud or pour point, or more wax.

Catalytic dewaxing helps refiners to achieve the cold flow properties, such as cloud, pour and cold filter plugging points, necessary for marketing diesel in cold climates by preventing wax compounds from crystallising in the diesel and causing engine problems.

One of the factors that prompted the Gazprom Neft Omsk refinery to choose the Shell Global Solutions–Criterion option was that it wanted to use an old diesel hydrotreater with two parallel trains to produce its winter diesel. This hydrotreater was commissioned in 1967 but had limited use for the production of ultra-low-sulphur diesel. Shell Global Solutions devised a solution that enabled the refinery to use this unit and recommended the use of its advanced reactor internals and the SDD-800 dewaxing catalyst from Criterion.

The two-phase revamp was implemented without major changes and took account of the process constraints of using an old unit, for example, the low hydrogen partial pressure and the limited space velocity.

The first phase involved installing a connecting pipeline from the hydrotreating section to the dewaxing section and a pipeline to withdraw treated winter diesel from the unit; replacing the dewaxing section reactor internals and the catalyst systems; and removing internal pipes from

In countries such as Russia that experience severe winter weather, the demand for winter diesel is particularly

strong. The Russian government is encouraging refineries to increase the production of winter diesel to address the shortage in supply. However, producing good-quality winter diesel with the necessary cold-flow properties, such as cloud point, pour point and cold filter plugging point, is challenging for refiners.

One way that refineries have traditionally sought to achieve the required cold flow properties is through additivation. However, this is insufficient where the local weather conditions require the use of extreme winter diesel grades. Adding kerosene to the diesel oil pool is also a common solution for meeting cold flow specifications. However, both options are expensive and can detract from the refinery’s bottom line.

The Gazprom Neft refinery in Omsk, Russia, needed to increase its production of high-quality winter diesel to meet demand and to maximise its yield of high-value winter diesel fuels. It also wanted to produce additional kerosene, which is in short supply during the winter months because it is traditionally blended with diesel.

After investigating the technologies offered by different suppliers, the Gazprom Neft Omsk refinery decided to implement catalytic dewaxing technology from Shell Global Solutions and Criterion Catalysts & Technologies (Criterion). Diesel dewaxing can help refiners to enhance their margins

Catalytic dewaxing helps refinery to produce high-quality winter diesel

CASE STUDY

www.shell.com/globalsolutions 13www.shell.com/globalsolutions 13

the reactors. The two trains of the unit were operated in parallel during the first phase of the project. Hydrotreatment was completed in train one. The dewaxing was carried out in the second train.

During the second phase, the unit was brought back to the design scheme with double the production of winter diesel through parallel operation of the two trains. Hydrotreated diesel fuel produced in two of the refinery’s other units was used as the feedstock.

Ivan Gorodok, Chief Project Engineer, Gazprom Neft Omsk refinery, says it was a novel application for the refinery. “This was our first attempt to use a base metal dewaxing catalyst in a ‘clean’ (second-stage) environment and one that also gave additional economic benefits for the refinery. It managed to achieve very good product yields and made more high-quality ultra-low-sulphur and winter diesel.”

Previously in Russia, the main standard for diesel was GOST R 52368-2005 (equivalent to European standard EN 590), which prescribes the ASTM D86 95% distillation point for winter diesel as 340°C. The application of the dewaxing technology enables Gazprom Neft to produce winter diesel with an ASTM D86 95% distillation point of 360°C, as for summer diesel. This generated a good incentive to create a new standard for winter diesel: GOST R 55475-2013 Dewaxed Winter Grade Diesel Fuel and Arctic Grade Diesel Fuel. This standard allows the production of relatively heavy winter diesel in Russia, which was only possible previously through additivation.

“With the technology we have implemented at Omsk,” says Gorodok, “it is possible to produce winter diesel with the same distillation point as summer diesel and that meets international standards for an end boiling point of 360°C. This diesel is better for engines because it has

a higher density and calorific value, so produces more power, and it has higher lubricity. We have also been able to increase our production of kerosene.

“The application of modern Shell Global Solutions–Criterion dewaxing technology enables us to produce high-quality winter and extreme-winter-grade diesel fuels at minimum capital cost, even in relatively old hydrotreating units with low hydrogen pressure, and with minimum changes to process configuration.

“Despite the fact that the trial on the new technology was carried out using old equipment, we obtained good results. The targeted dewaxed product yield was within 90–93%. We were pleased to produce high dewaxed product yields after the first year of operation. We required a substantially lower quantity of dewaxing catalyst to give a relatively high yield of the target product, which resulted in much lower overall project costs,” concludes Gorodok.

Gazprom Neft will continue to work with Shell Global Solutions and Criterion and plans to use the new technology in revamps at its other refineries in Russia to produce diesel for extreme winter conditions.


TURNING THE TIDE ON HYDROCRACKER BOTTOMS

Hydrocracker bottoms (hydrowax) can be a low-value product for refineries. However, transforming

it into higher-value lubricant base oils can be a lucrative option, as proven by Hyundai Oilbank, whose decision to do just that is now set to bring in additional revenue of almost $1 billion per year at its Daesan refinery in South Korea.

Hyundai Oilbank was keen to enter the lubricant base oil market because of the growth in sales, particularly in Asia. Consequently, the company set about exploring the economic and technical feasibility of building a base oil plant connected to its refinery that could process the hydrowax previously sold to a third party.

Early-stage discussions with Shell Global Solutions about this plan provided the developer with a valuable lead. “We learned that Shell Lubricants was looking for a stable, high-quality producer to supply base oil in Asia,” explains Ji-Hoon Ha, Chief Operating Officer, Hyundai and Shell Base Oil Co., Ltd. “This led to the creation of a joint venture.”

With a new partner through which it could distribute the base oil, Hyundai Oilbank went on to contract Shell Global Solutions to provide the

necessary technology, which needed to be capable of producing high-quality (Group II) base oils to satisfy Shell Lubricants’ requirements.

To ensure the new base oil plant would be as cost-effective as possible, Shell Global Solutions realised there would also need to be upgrades to the Daesan refinery. “If we could achieve the product qualities that the lubricant base oil plant required, it would really maximise the value of the project, but it became clear that to do so we would have to modify the catalyst system and operating mode of the existing hydrocracker,” explains John Baric, Licensing Technology Manager, Shell Global Solutions.

“Not only that, we also identified clear advantages by going back even further into the processing stream and revamping the high-vacuum unit to Shell’s deep-flash technology mode.”

A tailored catalyst system, developed jointly with Criterion Catalysts & Technologies, was introduced to the hydrocracker to change its operating mode and enable the delivery of the right quality of hydrowax, which is essential to maximise heavy base oil yields.

The high-vacuum unit revamp expanded the ability of the unit to produce more

heavy vacuum gas oil. Replacing all of the internals, revamping the furnace and changing the transfer line between the furnace and the column improved its overall performance.

With all of the individual units in place, the new base oil plant started up and delivered the first on-specification products in July 2014. Immediately, the joint venture’s operations and technical support team began pushing the production rate to its initial design capacity (20,000 barrels a day of Group II grades 150N and 500N lubricant base oil) and optimising the yield within the product quality constraints.

Baric explains that the key to the success of the project is that each element has been optimised to work as a value chain. “The vacuum unit is delivering the vacuum gas oil feed to the hydrocracker at the right heaviness, the profile is exactly as per design and the yield is there. The hydrocracker is operating at target conversion to deliver the hydrowax quantity and quality that the base oil plant needs,” he says. “And all of this is helping the base oil plant to deliver the right product quality.”

Hyundai Oilbank proves there is value in lower-value by-products

CASE STUDY



FINE-TUNING FOR OPTIMUM PERFORMANCE IN SWEDEN

Sweden’s largest refiner Preem AB expects optimum performance from all elements of its refinery, which

is one of the most modern in Europe. Consequently, the company went out to the market for new reactor internals when it discovered there was scope to improve the catalyst utilisation in its hydrocracker and maximise diesel yield.

Preem operates a single-stage, two-reactor, 142-bar, 53,000-barrels-a-day hydrocracker at its 220,000-barrels-a-day Preemraff Lysekil facility. Studies showed, however, that only about 85% of the two reactors’ catalyst volume was being utilised owing to thermal maldistribution.

Thermal maldistribution in pretreatment and cracking reactors is a common issue that can cause performance-limiting hot spots and dry areas. In an effort to boost catalyst utilisation, Preem’s technologists called on catalyst vendors to suggest their best catalyst option and reactor internals to solve this problem.

The proposed catalysts were then tested competitively back to back at an independent pilot plant testing laboratory. After successful testing, Shell Global Solutions’ reactor internals and catalysts offered through Criterion Catalysts & Technologies (Criterion) were selected

and implemented at Preem’s refinery during a 2013 shutdown.

Shell’s internals include HD (high dispersion) trays, which provide ultra-uniform vapour–liquid distribution and excellent thermal distribution; UFQ (ultra-flat quench) interbed internals for uniform process and quench mixing at the interbeds; catalyst support grids for improved catalyst retention and better fouling handling; and a skirt to raise the HD tray and provide more catalyst volume.

Installing the new internals has led to a 10% increase in the amount of catalyst that can be loaded into the reactor and, because of the improved dispersion, nearly 100% of the catalyst is now being used.

The quick to open and close design also means that the time spent on any future maintenance of the new reactor internals will be less, which means more on-stream days for the hydrocracker.

Criterion also provided its most active and stable pretreatment catalyst, CENTERA®

DN-3620 Z-2513, which offers outstanding selectivity for middle distillates; and guard beds and grading to protect the pretreatment catalyst from fouling.

The catalyst and the internals are already improving performance and helping

Preem to run its hydrocracker at a higher conversion rate. “The results so far are all in line with Criterion’s catalyst offer and the pilot plant tests. They are not due only to the internals, although we do have an excellent temperature profile in all four beds. The internals ensure that we can benefit from the new, improved catalyst throughout the cycle,” says Mats Hörnfelt, Senior Process Engineer, Preemraff Lysekil.

“The advantage of the catalyst is its selectivity towards diesel with lower yields of fuel gas and naphtha, which were limiting the throughput of the last cycle. This enables us to run at a higher conversion within the maximum fuel gas and naphtha make. In fact, we are close to the maximum rundown of diesel at a lower feed rate, which is very valuable when you are importing hydrocracker feed.”

Since start-up of the catalysts, Criterion has continued to support Preem with continuous monitoring and technical services to ensure that the catalysts function as predicted and that the hydrocracker performs to its full potential over the long term.

How new reactor internals and catalysts helped Preem to avoid a common issue and get more from its hydrocracker

CASE STUDY


INSIDE INDONESIA’S ACCELERATED GAS PROJECTS

The Indonesian government has stepped up its gas projects as it strives to meet the increasing needs

of the country for both the commercial and domestic demand. Each of its projects presents specific technical challenges but one constant is the pressure to accelerate the time to start-up while processing complex contaminants. Here we focus on three projects that provide interesting case studies on using technology to manage complex and contaminated gas, and how adopting a different approach during front-end development can help to accelerate the schedule.

Although Indonesia has historically been a significant exporter of gas, domestic energy demand is growing rapidly and the country is forecast to become a net importer in the next few years unless it develops new gas assets. Fortunately, it enjoys huge untapped natural gas reserves, so the Indonesian government is fast-tracking the development of additional natural gas resources.

One of these is the development of the Jambaran–Tiung Biru project in Central and East Java, which is a joint venture between PT Pertamina EP Cepu, Mobil Cepu Ltd and local government. This initiative is the country’s biggest onshore associated gas project and is said to involve some 1.2 trillion cubic feet of natural gas and 18.6 million barrels of condensate.

The complex composition of the gas, however, presents significant challenges. It has extremely high levels of carbon dioxide (33–40 vol%), high levels of hydrogen sulphide, and significant levels of contaminants such as mercaptans, carbonyl sulphide and aromatics.

Nevertheless, by working with Shell Global Solutions, the operator, PT Pertamina EP Cepu, has been able to

develop a processing scheme that can cost-effectively handle these contaminants.

Moreover, the project teams were able to accelerate the schedule, as Derek Ritchie, Technology Commercialisation and Licensing Manager, Shell Global Solutions, explains.

“When we begin working with a customer, we are always keen to understand their underlying business objectives and here it quickly became clear that schedule was a strategic priority,” he says. “Working with PT Pertamina EP Cepu, we identified an opportunity to compress the timeline through an alternative approach to the

sequencing of activities around the project critical path.”

Essentially, this involved PT Pertamina EP Cepu committing to a technology and technology line-up earlier than is conventional so that Shell Global Solutions could start to develop a basic design and engineering package (BDEP), which is more detailed than Shell Global Solutions’ standard deliverable, a basic design package (BDP).

This meant that, on selection, the engineering, procurement and construction contractor would have significantly more mature and comprehensive information than with

CASE STUDY


standard sequencing, when they would receive just a BDP. “By involving us at a very early stage of the discussion when they were still brainstorming how to do the project, PT Pertamina EP Cepu has been able to fast-track the schedule by some 15 weeks,” says Ritchie.

The solution that the project teams developed involves a complex, integrated line-up of multiple licensed technologies. Shell Global Solutions has licensed the acid gas removal unit (AGRU), sulphur removal unit (SRU), hydrogenation section of the tail-gas treating unit (TGTU) and sulphur degasser, while another licensor has provided the acid-gas enrichment unit (AGEU) and the solvent side of the TGTU. “On other projects, we have licensed the entire gas-treating block, but this job demonstrates that we also have the flexibility and willingness to co-operate with

our clients’ requirements. We worked very compliantly with them,” says Ritchie.

The AGRU removes most of the hydrogen sulphide and carbon dioxide from the feed gas. In addition, because the Jambaran–Tiung Biru scheme uses Sulfinol-X* technology, mercaptans, carbonyl sulphide and other sulphur species are also removed to meet required specifications in the AGRU. This all-in-one removal of contaminants can create substantial value, as it can help to reduce capital and operating expenditure; for more on this, see box “How Sulfinol-X enables process line-up simplification”.

After the AGRU, the lean acid gas is routed to the AGEU, which enriches the acid gas to enable the stable operation of the SRU. In the SRU and TGTU, the sulphur-containing components are converted into liquid elemental sulphur and the hydrocarbons in the feed are converted to carbon dioxide and water. More than 98% of the sulphur in the feed gas is converted to elemental sulphur and is brought to the

hydrogen sulphide specification in the sulphur degassing unit.

Together with the off-gases from the AGEU and TGTU (which are rich in carbon dioxide), any residual sulphur compounds not recovered in the SRU/TGTU are oxidised to convert them to sulphur dioxide. This occurs in a thermal oxidiser operating at a sufficiently high temperature to also ensure the destruction of the remaining aromatic hydrocarbon compounds, ethylbenzene and xylene, and to oxidise the carbon monoxide completely to carbon dioxide.

Different circumstances, different technologiesA few hundred kilometres away in Central Sulawesi, PT Pertamina EP (100% Pertamina) is developing another major onshore Indonesian gas development called PPGM Donggi. Here, the project team adopted a similar approach to their counterparts at Jambaran–Tiung Biru to compress the schedule. Early selection

The complex composition of the feed gas at Jambaran–Tiung Biru meant that Sulfinol-X technology could unlock substantial value, writes Gary Bowerbank, Senior Gas Treating and Sulphur Recovery Technologist at Shell Global Solutions.

“The feed gas contains high levels of mercaptans, which our solvent can treat while also removing the carbon dioxide and the hydrogen sulphide. This enables the line-up to be significantly simplified. The alternatives would be to use molecular sieves downstream for mercaptans removal or a caustic-based process, which adds complexity and cost to a project.

Sulfinol-X is interesting because it is a hybrid technology; it is not solely a

physical or a chemical solvent. The inclusion of the physical component is key because it overcomes the key limitation of physical solvents: high loss of hydrocarbon components through co-absorption.

And, not only does this hybrid solvent enable the hydrocarbon co-absorption losses to be minimised, but, at Jambaran–Tiung Biru, any hydrocarbons that are “lost” are actually consumed within the thermal oxidiser, which minimises the use of valuable sales gas. So, the hydrocarbon losses are no different than if they had used a solvent that had no hydrocarbon co-absorption.”

How Sulfinol-X enables process line-up simplification


of the technology again enabled Shell Global Solutions to develop the BDEP instead of the BDP to support the strategic aim of the project of reducing the schedule.

At PPGM Donggi though, because the feed gas composition is very different to that at Jambaran–Tiung Biru (it contains more hydrogen sulphide and less carbon dioxide) the processing scheme is very different. “The customer’s drivers were very similar: to manage complex, contaminated gas, minimise life-cycle costs and optimise the project timeline,” says Ritchie. “And we are using the same acid gas recovery technology, Sulfinol-X, but the sulphur recovery element is completely different.”

Here, Shell licensed the entire gas treating block, and a similar design is being used at neighbouring project PPGM Matindok. For sulphur recovery, PPGM Donggi and PPGM Matindok are both using THIOPAQ O&G, a biological desulphurisation process that integrates gas purification with sulphur recovery in one unit. The technology removes in excess of 99.9% of the hydrogen sulphide from sour gas streams and recovers it as elemental sulphur. For more on this,

CASE STUDY

Because the THIOPAQ O&G process uses naturally occurring bacteria to oxidise the hydrogen sulphide to elemental sulphur, it can deliver distinct advantages at PPGM Donggi and PPGM Matindok, writes Derek Ritchie, Technology Commercialisation Manager, Shell Global Solutions.

“Although the conventional Claus/SCOT* (Shell Claus off-gas treating) technology is the one most commonly applied for sulphur removal, THIOPAQ O&G is playing an increasing role.

“One reason for this is that it is typically much less capital intensive. This is because a THIOPAQ O&G plant (which comprises an absorption section, an optional flash vessel, a reactor section and a sulphur recovery section) can replace the amine unit, SRU, TGTU,

incinerator and degasser that may be required in a typical process line-up. Moreover, costly equipment items such as burners, refractory-lined equipment and reboilers are unnecessary.

“It is relatively inexpensive to operate, too, because the expensive chemicals required for liquid redox processes are unnecessary: only sodium hydroxide and nutrients are required.

“There are many other benefits. For instance, because the biologically produced sulphur is hydrophilic, there are no plugging problems (which are often associated with redox processes), so minimal operator attention is required. Moreover, there is no free hydrogen sulphide after the bioreactor, which enhances safety.”

The advantages of biological desulphurisation

see box “The advantages of biological desulphurisation”.

Each of the three projects discussed in this article are progressing well and are set to begin supporting Indonesia’s strategic imperative of meeting national energy demand while also raising state revenues through exports. In each case, says Ritchie, owner–licensor collaboration has been key. “Client requirements differ from project to project and from time to time, but by working closely with our

counterparts, listening to their objectives, jointly developing a flexible approach to project sequencing, and deploying appropriate technology solutions, we have been able to help them to achieve their objectives.”

*Sulfinol is a Shell trademark


ORSK’S REJUVENATION JOURNEY

Growing demand for middle distillates in Russia and a desire to modernise and scale

up operations has led ForteInvest, a key partner, to invest up to $3 billion in a series of projects that includes a hydrocracker, a reformer and an isomerisation complex at the Orsknefteorgsintez (Orsk) refinery.

This significant boost in financial backing, which follows a decade of underinvestment at the refinery, will help to enhance the plant’s size and complexity and ensure its competitiveness.

Orsk is currently a medium-sized refinery producing a relatively wide product slate, including diesel, gasoline and jet fuel, with high product qualities that can meet Euro 5 specifications.

As part of the upgrade, the new equipment will be phased in, which makes choosing the right technology at each stage vital to the overall success of the project. This need for future-proof technology helped Shell Global Solutions to secure the licensing contract for the new hydrocracker.

During discussions with the refinery executives, Shell Global Solutions learned

of a possible coker installation during a later phase of expansion, which would bring on board more fuel oil conversion. This, the company discovered, would present problems for the hydrocracker the refinery executives were asking for, as it would be unable to handle the feed from such a unit.

Shell Global Solutions therefore proposed a tailored design that is robust for processing vacuum gas oil and for coker gas oil if this were to be added in the future. Although this required higher pre-investment, ForteInvest was keen to ensure that it made the right investment and could avoid having to reinvest later.

“This was a good match for our business objectives because we have plans to continue upgrading the refinery after the hydrocracker’s installation,” says Kustarev Dmitry, Section Head, Project Planning Department, ForteInvest.

He adds that ForteInvest selected Shell Global Solutions to provide the hydrocracker owing to its track record of successful operating units on the ground. In addition, the company had also previously delivered a project to supply catalyst and reactor internals for a diesel

hydrotreater revamp at Orsk in 2012, which enhanced product qualities.

“Its technology has been proven at many commercial units: that was a key factor in our decision. Shell Global Solutions’ affiliation with Criterion Catalysts & Technologies was also influential. It enables us to source both the hardware and the catalyst from, essentially, one supplier,” says Dmitry. “In addition, their solution meets our constraints in terms of reactor size and gasoline yield.”

ForteInvest decided on a single-stage hydrocracker that is designed for high conversion and a four-year cycle length when processing vacuum gas oil. If a coker is added, the design and the reactors will remain fit for purpose, which means that no additional investment will be necessary. Choosing this configuration has helped ForteInvest to future-proof its investment and to maximise the hydrocracker’s service life, which will enable the company to move forward with other projects with confidence that this one will not need revisiting in the near future.

Future proofing a Russian refinery’s phased investments

CASE STUDY

www.shell.com/globalsolutions

Impact 2/2014 - Shell Global Solutions

Documents

Transcript of Impact 2/2014 - Shell Global Solutions