Impact2 2015

Shell Global Solutions

ISSUE 2, 2015

REFINERY REVAMPS: THE LATEST THINKING How integrated process design can boost value Responding to changing downstream conditions in India Do revamps hold the key to competitive futures?

CONTENTS

PRODUCED BY MARKETING AND SOLUTIONS DEVELOPMENT EDITOR

Mergyla van Uytrecht Tel: +31 70 447 8007 Email: mergyla.vanuytrecht@shell.com

CONTACT

Email: impact@shell.com Visit our website at www.shell.com/globalsolutions

IN THIS ISSUE COMMENT 3 Christophe Boulanger discusses the

untapped potential of refinery revamps BUSINESS 4 GETTING AHEAD OF THE CURVE

Why revamps could be key to

refiners’ competitive futures 6 BOOSTING VALUE WITH ROBUST

PROCESSING DESIGNS

An integrated design for handling

ill-defined feed compositions helps to

monetise assets

CASE STUDY 8 FLEXIBILITY OPENS THE DOOR

TO NEW POSSIBILITIES

Bharat Petroleum’s decision to

future‑proof its mild hydrocracker

pays dividends 10 BEATING METALS ENTRAINMENT

A high-impact, low-cost, vacuum

distillation unit revamp 12

MOVING THE OPERATING WINDOW The importance of hardwiring a refiner’s business drivers into a hydrocracker revamp project

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.

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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.

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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.

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impact issue 2, 2015

COMMENT

CHRISTOPHE BOULANGER VICE PRESIDENT, STRATEGIC CUSTOMERS SHELL GLOBAL SOLUTIONS

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MANY OF THE WORLD’S LEADING REFINERS ARE USING REVAMPS TO OVERHAUL, MODIFY OR FINE-TUNE THEIR CONFIGURATIONS TO MATCH THE DYNAMICS OF THE MARKET BETTER.

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Right now, in plants, laboratories and offices all around the world, teams of process engineers and technologists are performing test runs, devising creative configurations and making sophisticated calculations in order to revamp or upgrade pressurised refineries to give them a competitive edge.

In recent years, we have seen a strong trend towards revamps rather than grassroots capital projects and this seems set to continue, given the current market uncertainty. Many benefits of revamps are discussed on page 4, but, in brief, they include an enhanced return on investment, a lower capital cost and a shorter gestation period.

For me, this issue of Impact reinforces the notion that nearly all refineries have untapped potential. This does not apply only to those with units fitted with older technologies that are generating suboptimal yields or that have poor reliability. Even those that are equipped with the best-available technology and that are achieving benchmark performance levels may be able to generate more value from their existing assets. We discuss how many of the world’s leading refiners are using revamps to overhaul, modify or fine-tune their configurations to match the dynamics of the market better, which, of course, are in constant flux.

Cutting-edge technology was certainly key to each project. But, interestingly, there are other common denominators that run through these projects: the high levels of creativity and experience of the process engineers and technologists that developed them.

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BUSINESS

GETTING AHEAD OF THE CURVE Why revamps could be key to refiners’ competitive futures

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impact issue 2, 2015

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ith global refining capacity growing at a historically high rate and its complexity increasing, many refiners around the world are likely to be beset by downward pressure on utilisation levels and margins, according to a recent report by McKinsey & Company.1 There are actions that refiners can take to protect or improve their individual positions, but, crucially, says the report, they must be willing to invest to get there.

But what types of investments should refiners be making in order to maintain or improve their competitive position? Should they be, for instance, building highly efficient, mega-scale refineries that use the latest technology and have a large conversion capacity? Should existing refineries be adding new facilities based on emerging technologies aimed at near total destruction of fuel oil? Or would they be better off focusing on getting more out of their existing equipment by a combination of operational improvements and selective revamps or realignments of existing units?

According to Süleyman Özmen, Vice President, Refining and Chemical Licensing, Shell Global Solutions, today’s volatile markets mean that revamps are one of the most compelling investment opportunities open to refiners.

“In most parts of the world today, a proposal for a grassroots refinery is extremely unlikely to get off the ground,” he says. “At a cost of $10–20 billion, depending on the scope and size of the refinery, and with gross refinery margins being viewed as poor to average at best, such a project is likely to be out of reach for most investors.”

Refiners can often achieve better payback with less risk by improving or upgrading their existing assets, Özmen says.

Depending on the refiner’s business drivers, there are typically numerous revamping and upgrading opportunities that can help them to capture more margin from their existing

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assets. Such opportunities can include converting simple distillate hydrotreaters into dewaxing units for winter diesel production, and adapting distillate hydrocracking units to enable the conversion of very heavy gas oil components into diesel to expand hydrocracking capacity. The business case for such projects, which can have a wide range in cost ($10–500 million), is usually far more compelling.

Crucially, the return on investment also tends to be better. The cost per tonne of the capacity installed during a revamp is about 20–50% of that for a grassroots facility.

That is because existing equipment is reused as much as possible during a revamp. “We try to minimise major equipment changes; the kit that needs acquiring is usually limited to items that have a modest capital cost,” says Özmen. For example, he explains that, to improve the throughput and vacuum gas oil recovery of a high-vacuum unit in order to increase hydrocracker capacity, Shell employs its high-performance internals but retains the vacuum column itself and all its ancillaries. For existing hydroprocessing units, installing Shell’s latest-generation reactor internals addresses fouling and liquid maldistribution and dramatically improves the overall catalyst utilisation, thus resulting in opportunities for increased capacity, improved product yields and longer cycle lengths.

The turbines and motors that drive the pumps and compressors need to be checked to see whether they can support the increased capacity. But Özmen is keen to emphasise that existing equipment is not replaced unless there is a strong economic case.

Consequently, recycle gas compressors, for example, are rarely touched.

Operational changes may also be required. For example, revamps may involve realigning the process configuration to modify the conversion; optimising the feedstock selection and preparation; or running the unit to the limit of its design constraints to achieve capacity creep.

In addition, studies and reviews are often necessary. For example, dynamic simulations for reactor thermal stability checks during normal and upset conditions, and material reviews of corrosion rates in wash-water loops and fired equipment.

It is clear that revamping an existing process unit is substantially more complex than building a new one. The project planners have to ensure that they do not disrupt the continuing operation of the existing facility.

They have to design within the existing unit’s precise boundary conditions, such as the size and duty of the existing reactors, and plan the tie-ins during project execution carefully. But such issues can usually be mitigated, Özmen says, when there is a high-quality collaboration between the owner and the strategic licensor.

As many refiners grapple with issues of overcapacity, market volatility and low margins, Özmen strongly advocates that they consider making smaller, incremental investments rather than investing in new assets. “The lower capital expenditure means they carry a smaller investment risk and can help to generate credibility with investors. They also deliver returns far quicker than the three to four years it would take for a grassroots project.

“At Shell Global Solutions, we have always advised customers not to overlook their existing assets. Operational excellence should be the first consideration.

Then, look to generate as much value as possible from existing assets through revamp projects, which can provide big gains for a relatively modest investment.

The returns from those can help to fund any larger capital projects required.”

For more information contact: Süleyman Özmen Email: suleyman.ozmen@shell.com Profitability in a world of over capacity, McKinsey & Company, May 2015

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BUSINESS

BOOSTING VALUE WITH ROBUST PROCESSING DESIGNS An integrated line-up for handling ill-defined feed compositions with varying levels of contaminants enables quicker monetisation of assets

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he opportunities to develop sweet, easy fields are slipping away and leaving behind more difficult sour and contaminated gas fields that present new gas processing challenges. Additionally, project developers are under constant pressure to reduce the time it takes from project definition to project payback.

Often, however, much value can be eroded when gas field developers have to wait for more concrete well test data on which to base a gas processing line-up.

Rising to these challenges requires new thinking on the part of the project developer and the technology licensor. They must be able to select a gas processing concept that is both robust against changes in predicted gas composition during project maturation and capable of handling contaminantriddled feedstock.

Shell Global Solutions and one of its customers, a gas field developer, came up with an integrated gas processing design that is robust enough to handle a range of feed compositions. It is expected to help the customer to avoid a project delay of a year, which would have reduced the net present value of the project by about 8–12%,

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depending on the oil price. This equates to a $2–5 billion saving in net present value.

The integrated design, consisting of easily replicable technology units and proprietary Shell sulphur technology, is able to do this by offering flexibility that will prevent additional design cycles further down the line and therefore enable quicker project delivery, thus boosting the net present value of the project.

The integrated line-up does require an additional capital investment of about 10–15%, or $150–250 million, over a more conventional, optimised system.

However, the projected net present value savings far outweigh these additional up‑front costs.

“A robust, integrated and easily adaptable design enables a project to progress quicker into the front-end engineering and design phase, thereby reducing the overall project schedule. This shorter timeline can bolster the net present value of a project by enabling the developer to produce gas quicker and get an earlier return on investment,” explains Stéphane Charest, Upstream Strategic Business and Marketing Manager at Shell Global Solutions.

“An 8–12% net present value improvement is not negligible. It provides a lot of safety margin within a project to affirm your decision to go ahead with development,” adds Charest.

The design basis The need for this robust design stemmed from the early data available for the project, which presented a hydrogen sulphide/carbon dioxide ratio in the feed ranging from 0.25 to 2.5; an uncertain production profile; sulphur production in the range 500 to 2,000 tonnes per day; and uncertain levels of trace contaminants in the feed, with no specific data available on benzene, toluene, ethylbenzene, xylenes and mercaptans. impact issue 2, 2015

while eliminating the need for additional treating of natural gas liquids.

As sulphur recovery is one of the key variables for this project, multiple sulphur trains were designed. These trains are identical, so additional units can be replicated during the engineering, procurement and construction phase, if required, to handle higher sulphur loads without going through a redesign phase.

The line-up also includes an acid gas enrichment unit that widens the line‑up’s operating window by enabling the processing of gases with variable hydrogen sulphide to carbon dioxide ratios.

The design concept for the project evolved from key lessons and experiences that Shell Global Solutions has gathered from previous projects. “Those projects were the building blocks for the further development of what we now call the Shell CANSOLV TGT+ process,” says Charest.

“Through close collaboration with the gas field developer, we used the capabilities of the Shell CANSOLV TGT+ process to extend the capabilities of an integrated line-up.

“Being a licensor and an owner-operator enables us, at Shell Global Solutions, to collate these lessons learned from other projects and integrate them into a robust package to accommodate future clients’ needs,” he adds.

“After discussions with the customer, we realised there were a lot of constraints and contaminants that were making the project more challenging to develop. There was also a limited amount of well data on which to define the project. Understanding those issues and their business impact was key to developing a robust solution,” explains Charest.

“With the customer, the project team was able to put together a technology line-up consisting of easily replicable units that can accommodate an ill-defined feedstock, which means that we can avoid the schedule delays associated with waiting for more accurate feed data or having to redesign the line-up at a later stage once newer data become www.shell.com/globalsolutions

available. This then means a quicker return on investment,” says Charest.

The technology line-up The technology line-up comprises the Shell proprietary Sulfinol*-X all-in-one acid gas treating technology along with selective acid gas enrichment, a Claus unit and sulphur dioxide tail gas treatment using the proprietary Shell CANSOLV* SO2 Scrubbing System, which enables sulphur recovery to meet World Bank standards. Together, these technologies provide the robustness to deal with high compositional uncertainty for the gas.

The Sulfinol-X all-in-one amine technology enables deep removal of acid gases and (organic) sulphur contaminants

The integrated gas processing line-up’s adaptability means it can be used for many projects faced with uncertain levels of contamination in the feed, thereby opening the doors to economic development of the more difficult oil and gas fields.

For more information contact: Stéphane Charest Email: stephane.charest@shell.com *CANSOLV and Sulfinol are Shell trademarks

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CASE STUDY

FLEXIBILITY OPENS THE DOOR TO NEW POSSIBILITIES Bharat Petroleum’s decision to future-proof its mild hydrocracker pays dividends

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ew process units are usually carefully designed for a specific scenario, but progressive refiners are keen to ensure that their new assets will continue to deliver value in a range of scenarios in case external factors change, as they inevitably will.

A recent project at Bharat Petroleum Corporation Ltd’s Kochi refinery in India provides a compelling example of this.

Keen to increase propylene production to feed the neighbouring petrochemical plant that it was building, the refiner worked with Shell Global Solutions to evaluate solutions.

gas (LPG) than we anticipated. We need to build additional facilities for its evacuation, and it could be difficult to move large quantities of LPG,” he says. “So, we wanted the flexibility of increasing the conversion in the mild hydrocracker to produce more middle distillates, such as diesel, for which there is plenty of demand. This could then be used for when we would be unable to run the FCC unit at full charge and severity owing to the challenge of moving the propylene or LPG.”

Of course, it was equally important that this flexibility did not add substantial cost, so, to achieve this, Shell’s technologists had designed a slightly longer five-bed reactor, but planned to leave the final bed empty initially. Four beds would achieve the required 27% conversion; the fifth would provide the all-important contingency that would enable higher conversion at minimum cost.

In fact, this design feature delivered value sooner than either of the parties had anticipated.

Ultimately, Bharat Petroleum licensed a 375-tonnes-per-hour mild hydrocracking unit that will process straight-run vacuum gas oil and up to 20% heavy coker gas oil at 27% conversion. This was designed to feed an existing fluidised catalytic cracking (FCC) unit and a new one, with both lined up to target propylene. The unit is to be loaded with catalysts from Shell Global Solutions’ affiliated catalyst company, Criterion Catalysts & Technologies (Criterion).

A key feature of this proposed unit was that it had the potential to operate in the future in a different mode of operation, at higher conversion, if necessary. Crucially, this could be achieved without any modifications to the unit, other than those agreed at the kick‑off meeting for the design effort.

Mohan Menon, Chief Manager at Bharat Petroleum, explains that this capability had been a particularly important requirement for the refiner. “We had looked at the net present value calculations for the new FCC unit and realised that, although it would increase propylene, it would also produce a lot more liquefied petroleum 8

impact issue 2, 2015

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WE WANTED THE FLEXIBILITY OF INCREASING THE CONVERSION IN THE MILD HYDROCRACKER TO PRODUCE MORE MIDDLE DISTILLATES, SUCH AS DIESEL, FOR WHICH THERE IS PLENTY OF DEMAND.

An expected two-year delay with getting the downstream petrochemicals plant off the ground meant that there would not be the same requirement for additional propylene volumes from the FCC units and, in turn, less feed required from the new mild hydrocracker. There were also some delays expected in the implementation of a longdistance liquefied natural gas export pipeline.

At that point, it became important for Bharat Petroleum to tune the unit towards middle distillates rather than FCC feed – and that meant increasing its conversion.

So, the contingency that had been built in from the beginning now paid dividends: the unit could be modified to achieve 35% conversion, at no additional capital cost, by making small process modifications and loading a hydrocracking catalyst in the fifth bed.

Menon comments that Shell Global Solutions and Criterion responded quickly to this development by presenting several catalyst options with different cycle lengths and diesel yields to Bharat Petroleum.

“Criterion responded very positively and

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immediately accommodated our request,” he says. “Their quick response enabled us to calculate the added value of each catalyst configuration and decide very quickly, which meant no schedule delays.”

As part of the technology licensing contract with Bharat Petroleum, Shell Global Solutions will provide full support for inspection of critical equipment, supervision of start-up and support during the process guarantee test run.

It will also provide training to 15 engineers from Kochi refinery to help them to operate the new unit. This will consist of classroom training at the Shell Technology Centre Amsterdam in the Netherlands; field training at a site operating a similar Shell technology; and on-site training at Kochi.

According to Bharat Goenka, Head of Technology Licensing India, Shell Global Solutions, this training is very important for the project because it will help ensure the smooth start-up and operation of the unit.

But, for him, it is the future-proofing aspect of the design that is the most significant element. “Bharat Petroleum is to be congratulated for having the foresight to build in such flexibility,” he says. “Business circumstances are always changing, but, without any pre-investment, the refiner has ensured that its new assets continue to be relevant to a range of different scenarios.”

For more information contact: Bharat Goenka Email: bharat.goenka@shell.com

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CASE STUDY

BEATING METALS ENTRAINMENT A high-impact, low-cost, vacuum distillation unit revamp

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aximising vacuum gas oil yield is a goal shared by most refiners worldwide, so many operate their vacuum distillation units close to or beyond their design capacity. The downside is, however, that more harmful metals such as nickel and vanadium can become entrained from the short residue, which can affect the performance or cycle length of the downstream conversion unit.

Fortunately, the capacity of the vacuum distillation unit and the quality of the vacuum gas oil that it provides can often be increased in a cost-effective way, as a recent project at Bharat Petroleum’s refinery in Mumbai, India, demonstrates.

The 240,000-barrels-a-day facility is one of India’s most flexible refineries and, with energy demand in the region continuing to grow, the refiner was keen to produce more vacuum gas oil from its non-Shelllicensed vacuum distillation unit. As well as vacuum diesel, this unit produces light and heavy vacuum gas oils, which are combined and routed to a hydrocracker.

Bharat Petroleum’s previous attempts to increase the vacuum gas oil yield had resulted in the vacuum gas oil having an excessively high metals content, so this was a key focus area during a refinery performance improvement programme that the refiner undertook with Shell Global Solutions. During this review, the refinery technologists worked closely with

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consultants from Shell Global Solutions and, together, they identified several potential causes for the vacuum gas oil’s quality issues. For example, they found that the feed entry device was not doing enough to de-entrain the short residue from the vacuum gas oil, the velocity in the transfer line was excessively high and the vacuum residue entrainment level in the slop cut and the wash oil rates both exceeded Shell guidelines.

“We proposed two actions to improve the situation,” explains Kaushik Majumder, Team Lead and Licensing Technology Manager – Distillation, Shell Global Solutions. “The first was to recycle vacuum slops to the vacuum distillation unit furnace for reprocessing and recovering additional vacuum gas oil. The second was to install Shell proprietary internals in the vacuum distillation unit column to improve the vapour–liquid separation and help to maximise the vacuum gas oil recovery within the vacuum distillation unit.”

A key component that was introduced here was the Shell Schoepentoeter* Plus, an advanced vane feed inlet device that has high de-entrainment efficiency. This decreases the momentum of the feed, performs a first-stage separation of solids and liquid from the vapour and achieves even vapour distribution across the vessel cross section. It does this by splitting the feed mixture into a series of flat jets.

Minimum scope versus maximum scope The scope and cost of some vacuum distillation unit revamps can be considerably larger than for Bharat Petroleum’s project, but, says Majumder, it all depends on the customer’s individual situation and what it is trying to achieve. “At Bharat Petroleum, there was sufficient capacity in the column, impact issue 2, 2015

Majumder insists that is not a problem: “We can be flexible,” he says. “We have done it in many cases; it just depends on the customer’s business objectives.”

In fact, at Bharat Petroleum, the existing transfer line was suboptimal, but Shell Global Solutions was able to avoid revamping it by increasing the flash zone and overall column pressure by a few millibars, which brought the transfer line velocity within acceptable limits.

Delivering value The modifications were implemented within a turnaround window, and the data from a test run then enabled the vacuum gas oil increase to be calculated.

After derating, which was necessary because of a change in feed quality and because the plant operates in bituminous mode for eight months of the year, the average annual vacuum gas oil benefit was calculated to be 1.5 wt% on crude throughput. Given the enhanced value of vacuum gas oil compared with that of short residue, this will have a major impact on Bharat Petroleum’s margins.

the furnace and the transfer line,” he says. “So, we did not have to upgrade those; we just had to introduce a better inlet device, a better wash bed and a better operating philosophy.”

This was what Shell Global Solutions terms a minimum scope revamp. “There is no clear-cut boundary between minimum and maximum scope, but, generally speaking, we call it a maximum scope revamp if the furnace and the transfer line www.shell.com/globalsolutions

are upgraded as well as the column. If it only involves the internals, we refer to that as minimum scope,” Majumder adds.

Although Shell Global Solutions has conducted several maximum scope vacuum distillation unit revamps in recent years (including a high-profile project at Hyundai Oilbank in South Korea, for example), in today’s capital-constrained industry, many clients are keen to avoid replacing the furnace and transfer line. However,

“Whether the project involves maximum scope, minimum scope or something in-between, a vacuum distillation unit revamp can often be an extremely compelling project. Typically, the capital cost is relatively low, the payback time is short and the hardware changes can often be made within a turnaround,” says Majumder. “Having said that, such projects can often be very challenging and, if they are not engineered properly, it may be impossible to meet the desired revamp objectives.”

For more information contact: Kaushik Majumder Email: kaushik.majumder@shell.com *Schoepentoeter is a Shell trademark.

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BUSINESS

MOVING THE OPERATING WINDOW The importance of hardwiring a refiner’s business drivers into a hydrocracker revamp project

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sed properly, revamp projects can help refiners to ensure that their assets continue to deliver an attractive margin, even when the market conditions change. According to Simon Cackett, Licensing Technology Manager, Shell Global Solutions, the common denominator behind some of the most successful recent hydrocracker revamp projects is that they have been carefully designed to integrate into the refiner’s specific configuration and therefore best meet their business objectives.

“Regional and site-specific economics prevail,” he continues. “Middle distillates may not always be the highest-value product stream. In some regions, the economics are better for lubricant base oils. That was the case for Hyundai Oilbank. It had originally started up the hydrocracker at 98% conversion aimed at middle distillate production, but has since dialled down its conversion to 50% because it now routes the bottoms product to its new lubricant base oil plant.”

“As every refiner’s situation is unique, so are the drivers behind their revamp projects,” he explains. “For example, where one will seek to increase conversion by targeting greater yields of middle distillates, another will strive to reduce it by being more focused on integrated petrochemicals or lubricant base oils.”

CNOOC’s refinery in Guangzhou Province, China, made a similar adjustment. It also realigned the routing of the hydrocarbon streams to take advantage of the premium on base oils, but in this case it was switching away from petrochemical products. Its hydrocracker bottoms originally fed an olefins plant (ethylene cracker). Now, they are routed to a base oils plant because that can recoup better margins.

He references two recent projects to illustrate this point. “While Grupa LOTOS refinery in Gdansk, Poland, was revamping to increase the conversion rate of its hydrocracker to produce more jet fuel and Euro 5 diesel, Hyundai Oilbank was revamping the unit at its Daesan facility in South Korea to reduce it,” Cackett says.

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Again, Cackett cites the example of an operator for which there was a compelling business case to do the opposite. Because it serves a different region, a Shell hydrocracker in a refinery integrated with a neighbouring petrochemical facility was

revamped recently to provide additional petrochemical feedstocks. “It now runs at twice the capacity and a lower percentage conversion so that it can make ethylene cracker feedstock,” he says.

Of course, it is not always the conversion level that is changed in a revamp, as projects at Valero’s St Charles and Port Arthur refineries, and Marathon Oil Corporation’s Garyville refinery, illustrate. All three US facilities maintained conversion at approximately the same level but unlocked substantial, and very profitable, increases in middle distillates production by increasing their hydrocrackers’ capacity.

“These examples demonstrate that every revamp project is unique and should be carefully tailored towards a refiner’s specific situation,” Cackett concludes. “Should you process heavier feeds? Should you increase conversion or reduce it? Could you improve the yield of middle distillates, petrochemicals or lubricant base oils? The answer will depend on your business objectives, assets and the dynamics of the markets you serve.”

For more information contact: John Baric Email: john.baric@shell.com

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