White paper IMO Impact on Ship-Owners, Refineries and TC Rental Industry

Transcription

1 White paper IMO 2020 Impact on Ship-Owners, Refineries and TC Rental Industry

2 Impact on Ship-Owners, Refineries and TC Rental Industry December 2017, Massimo Capra, Manager Aggreko Process Services EMEA As Crudes are becoming heavier and sourer, the reduction of the sulphur cap imposed by IMO 2020 will accelerate the trend in improving conversion of the barrel bottom as well as increasing pressure on hydrodesulphurization reactors, amine scrubbing efficiency, H2S conversion to sulphur and H2 generation. Engineered Temporary Cooling Solutions can relieve some of this pressure safely and at zero capital investment Some facts and data As the marine industry accounts for about 10% of the man-made SOx emissions, IMO MARPOL 73/78 Annex VI (IMO 2020) is going to tighten from Jan 1st 2020 the sulphur cap on Marine Fuels to 0.5% wt, down from the existing 3.5%wt. Refineries will have to manage the impact on their production cycle and strategies. At the same time the huge challenge has to be dealt with by the shipping industry. The shape of the new Bunker Oil Market presumably made of LSFO as well as HSFO niches is going to be the result of strategic choices of refining and shipping industries depending on the best technologies available on the market and Capex required. Ship owners are certainly going to face a sharp rise in costs for marine fuels estimated in additional spending of $60 billion, according to Wood Mackenzie, if every ship is going to comply with the 0.5% sulphur cap. Bunker Oil is about 50% of the global fuel oil demand and correspond to about 6.1% of the global oil demand: marine fuel oils consumption is about 228 MMt/y of the 300 MMt/y of fuels consumed by the marine industry, the rest being LNG (8 MMt/y) and MDO (64 MMt/y). Ship-owners In less than three years, ship-owners have different options to address the extra-costs the new sulphur limits will bring: Shifting to 0.5 % wt S Bunker Oils, Investing in emissions-cleaning technology: scrubbing SOx from exhaust fumes shifting to cleaner alternative fuels The shift to 0.5% S Bunker seems the simplest response. Lessons learnt during the 0.1% S fuels implementation in North-Western Europe showed challenges in pricing, availability and uniform specifications. The production methods may span from working sweeter crudes naturally producing on-spec fuel oils to mixing lighter distillates with residues from Hydrocrackers, FCC or Vacuum units: these pose a problem of fuels stability. Some price issues will surface as 228 MMt/y of new demand of clean fuels will emerge; this corresponds to about 4 MMBPSD of refineries output. Investing in emission control technologies mainly means exhaust fumes scrubbing with sea water or alkaline water to contain SOx emission in to atmosphere while burning high sulfur fuels. For 11,000 HP (8 MW) engines the cost will be approx. $4.2 mil with five years payback time. Considering one month docking time for scrubbing retrofitting, availability and costs of docking time as well as the limited residual life of many vessels, this option does not seem so attractive: it is believed that a maximum of 15% of the marine vessels will be equipped with scrubbing technology. In a market progressively switching to low sulfur fuels this also poses the problem of high sulfur fuels becoming a niche market with issues of availability and price. Alternative fuels like LNG have long being advocated by politicians as cleaner than bunker oils. This can be considered for new vessels as retrofitting existing ships with LNG engines appears too expensive. Also worth considering are the big volumes required for on-board storage, specialised skills of operators and availability of bunkering facility, at present only 2.6% of marine fuel demand is LNG. The situation for ship-owners looks rather fluid and uncertain with cost differentials forecast reach $/t, leading to $60 billion extra-cost for a global switch to low sulfur marine fuels. 1.

3 Refiners On the ability to process the 350 C+ oil cuts, refineries have different options to cope with the new limits and can be classified as operating in: Topping mode : only the products that naturally occur in crude oil are produced as light products. The portion of the crude oil barrel that boils above 350 C (650 F) is often directed to fuel oil. Topping refineries that process high sulfur crude oils will need to find new outlets for the significant volume of high sulfur residual production that will be displaced by the IMO 2020 Rule or switch to sweeter crudes. Of all classes of refineries, topping refineries producing HSFO will likely feel the greatest threat to continued operation. Coastal refineries that produce HSFO may be at risk if they cannot switch to a low sulfur crude slate. Cracking mode: the gas oil portion with a boiling point around C ( F) of crude oil is drawn off and upgraded to light products, primarily via FCC or hydrocracking processes. The 570 C+ cut (1050 F+) is often produced as bitumen or blended with distillate for fuel oil. Cracking refineries producing HSFO will feel much of the same economic pain. Cracking refineries should have more options than topping refineries. The majority of HSFO currently consumed as marine fuel comes from refineries operating in cracking mode that process sour crudes, pricing of fuel oils historically fell in the range of 70 85% of the crude price. The available options for these refineries are: Changing crude slate to sweet crude processing; Converting FCC units to residual cracking mode; increasing vacuum distillation unit cut-points; Selling high sulfur residual material to full conversion refineries as feedstock Alliances with ship-owners to contract for HSFO supply from the refiner in return for the refiner providing the capital for vessel scrubbing facilities installation; Producing bitumen; For companies that operate multiple refineries, with some of them operating in full conversion mode, changing crude slates and optimizing the HS residuals among refineries as feedstock for full conversion; Continue to produce and sell HSFO recognising that market demand and prices will be lower. Full conversion mode: not only the C material, but also the 570 C+ material is converted to light products (primarily via coking, visbreaking or hydrocracking). Most refineries that operate in this mode produce only a small amount of residual-type material and their production cycle is very flexible. These refineries will be the big winners of the IMO 2020 Rule change since the distillate price, sweet/sour price differentials, and light/heavy crude differentials will all increase. Optimisation of crude slates and product mixes will bear significant fruit. In addition, HSFO price may fall low enough to replace crude oil with HSFO as a refinery input. A driver for using HSFO as a feedstock is that it usually contains 30% distillate and 70% resid, automatically increasing a refinery s distillate yield. In 2016 the world wide refinery throughput was about 81 MMBPSD with 8 MMBPSD of fuel oil production; half of it was Marine Bunker HSFO. Out of 8 MMBPSD of fuel oil production only 420,000 BPSD was produced in US. The above data has also to be analysed considering the Coking and Hydrocracking capacity as percentages of crude oil capacity, which is 13.6% for US, 3.2% in EU and 3.2% in Asia. The residual fuel oils yield is 2.6% of the crude processed in US vs 9.5% outside US, this makes the North American refining industry a marginal player in these kind of products. Refiners need to plan their position to capitalise on the market changes that IMO 2020 will bring. Increased capacity utilisation could come from purchasing residual stocks from other refineries, modifying crude slates to capitalise on the ability to handle higher sulfur residual material, increasing refinery runs, or some combination of these. Full conversion refiners will also see an economic incentive to expand capacity of their resid processing facilities to minimise Fuel Oils production by converting it into lighter fuels. On the other side, aggressive deployment of stack gas scrubbing could largely erode any economic driver to install new refinery residual destruction and associated processing facilities capacity. 2.

4 Ancillary facilities such as amine scrubbing units, sulfur recovery units, hydrogen generation, and additional hydrotreating will likely also be part of project scopes. Strategies of the major players in the bunker market are already surfacing through their projects announcements: Topping mode : Cepsa, a major player in the Mediterranean bunkers market confirmed that it is in the basic engineering phase for a potential residual hydrocracker that will cost close to $2bn a massive investment project for a mid-sized refiner. PKN Orlen said it is considering investing in a similar unit at its 263,000 b/d Mazeikiai plant in Lithuania, having already decided to upgrade the H-oil unit at its 325,000 b/d Plock plant to produce a low-sulphur fuel oil blending component as well as install a new visbreaker in time for Ina, another Mediterranean bunker supplier, confirmed that it will complete a new delayed coking unit at the 90,000 b/d Rijeka plant by 2020 ExxonMobil s 310,000 b/d Antwerp plant, Lotos s 210,000 b/d Gdansk refinery and NIS s 110,000 b/d Pancevo facility are all build- ing delayed coking units. Total is due to start up a solvent deasphalting unit at its 308,000 b/d Antwerp refinery, while Neste s deasphalting unit began production in April at the 197,000 b/d Porvoo plant. Preem has commissioned a new vacuum distillation unit and is considering building a residual hydrocracker at its 220,000 b/d Lysekil plant, while its 106,000 b/d Gothenburg plant has commissioned a new hydrogen production unit enabling further desul- phurisation, due for completion by the end of Refiners looking to cut down on high-sulphur fuel oil output must decide whether they will target the expected post-2020 low-sulphur fuel oil market or try to get out of fuel oil all together, focusing on middle distillate and light ends output. IMO 2020 impact on refinery processes The refinery s options in reducing the amount of HSFO produced depends on complexity, competitive pressure, location, available technologies and Capex required. Competitiveness of European refiners suffers due to higher wages and energy costs, stricter Environmental rules and Safety protocols than direct competitors. The disadvantage has to be compensated with higher than benchmark operational margins. The recognised sources of operational margins improvement must be found laid in the areas of: assets high utilisation, energy efficiency, integration of production among different facilities, crude slate enhancement and human capital development. Switch to sweeter crude oils, like Ecofisk, Urals, Bonny Light, and Forcados. The achievement of the new sulphur target of 0.5% wt will largely depend on the sulphur content of the worked crude. It will be enough mixing diesel or kerosene to residual fuel oil to match the new specifications. The SECAs limit of 0.1% wt will not be achieved in any case by mixing Vacuum Residue with distillates. Blend-stock hydrotreatment, as the evident solution to achieve 0.5% wt seems the desulphurization of blend stock, because blend-stock is the easiest to desulphurise: this way is hardly workable. For middle sour crudes the desulphurization of kerosene or diesel used as blend-stock will only marginally decrease sulphur in fuel oils. HVGO hydrotreating: As FCC products like LCO and DCO constitutes the larger part of Fuel Oils there is more scope in the hy- drotreating HVGO (FCC feedstock) to achieve the sulphur concentration targets. While HVGO is more difficult to treat than diesel or kerosene, it is still much easier to treat than a full residue stream. Atmospheric Residue hydrotreating: AtmResid is the most difficult oil cut to desulphurise, the high levels of catalyst poisons present challenges in terms of catalyst life and severity of the desulphurization reaction. Fuel Oils destruction: it is also an option to implement processes like delayed coking or visbreaking that destroy fuel oils. 3.

5 Capex intensity will also shape the refinery response in assets acquisition to cope with the new market conditions: Revamps of Vacuum Units top pressure and addition of a Vacuum column to the Visbreaking Unit appears to be among the less capital intensive but bringing the lowest benefits in term of conversion improvements. Addition of Solvent Deasphalting units combined with revamps/debottlenecking of coking and hydrocracking units looks higher in both conversion and investments Investments in Residue Slurry Hydrocracking, Ebullated bed Hydrocracking as well as Delayed Coking seems to be the most expensive even though returning the highest conversion. Furthermore, hydrotreating mid-distillates require revamping of hydrogen plants, Amine scrubbing and regeneration facility as well as Claus units. Finally, refinery will have to cope with high hydrogen consumption. IMO 2020 impact on refinery processes As technologies for crudes hydrodesulphurization are not yet commercially proven and the same operations on residues still present big challenges, it is likely to see more VDU revamps and HVGO desulphurization. Processes like ExxonMobil Gofiners removing sulphur compounds from the feed streams entering the FCCU create greater flexibility in the types of crude oil the plant can run. No matter if the technology of choice will be hydrodesulphurization of HVGO or simply to operate HDS units at higher severity, the frequency of HDS shut-downs for catalyst replacement will increase. As the reactors cooling time is on the critical shut-down path, refiners will have a higher demand for accelerated cooling of HDS reactors. Catalyst deactivation in Gofiner-like processes will even be faster, year. The dominant hydrocracking technology is implemented with HDS reactors (removing S, N, O) upstream the hydrocracking reactors. Heavier and high sulphur charges will deactivate the HDS catalyst faster than HDC catalyst with an increasing need of hot shut-downs : cooling and replacing HDS catalyst while maintaining HDC reactor hot. Implementation of this solution will require compressors for N2 (polluted with HC and H2) recirculation. The new IMO limits will push refineries to cut their HVGO deeper, in order to reduce residues. VDU will have to be operated at lower pressure. As already noticed in the last two years, refineries are more and more interested in adopting vacuum improvement solutions for 12 months a year, as a transition period to implementation of revamping projects. Certainly the summer time variability in Vacuum will be less tolerated as making a deeper dent in overall refinery profitability. As FCCU feedstock will be heavier, higher carbon deposition on the catalyst will demand for more regeneration air. This is a trend already on its way and due to crudes becoming heavier; the process will certainly be accelerated by the new IMO limits on sulphur. Demand for FCC dense air applications are ramping up even though not so fast as VDU top pressure improvements, this is due to alternative solutions already existing: oxygen injection or rental of additional air compressor. Dense air injection offer a more performing and flexible solution, lower rental costs (about half), no capital investments (like oxygen injection does) and no piping modifications (like addition of temporary compressor does). Higher severity operations of the FCC reactor will increase incondensable gas production and higher WGC capacity. Improvement of the WGC pre-condensation will reduce wet gas flow rate avoiding the WCG to hit its max capacity. Considering that majority of refiners are still looking for the best strategies to respond to IMO-2020, therefore, many capital investments are likely to suffer a certain time delay, temporary cooling solutions are valuable alternatives during the transition time. About the Author Massimo Capra is the manager of Aggreko Process Services in Europe, supporting the Russian and Caspian areas as well as the M iddle East s refining and petrochemical sectors. He has 31 years experience in the refining and chemical process industry as proce ss and project engineering manager for com- panies including AGIP, Foster Wheeler Italiana, Tecnimont, Aramco Overseas Company, and as a freelance consultant. He worked as Process Technolo- gist and Team Leader at OPCW (Nobel Peace Prize 2013), conducting more than 150 process assessments in chemical facilities. Massimo earned a MS in Chemical Engineering from Politecnico di Torino (IT), PGC in Project Management from University of Wales (UK), MBA from Robert Kennedy College (CH), Lean 6 Sigma Black Belt from BMGI (USA) and ISO9001 Lead Assessor cert. from SGS (NL). 4. Tell us what you need aggreko.com