GDS International - Next - Generation - Downstream - Summit - Europe - 1

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Fuel Oil ISO 8217 Specification Challenges & Solutions

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GDS International - Next - Generation - Downstream - Summit - Europe - 1

  1. 1. Challenges and Solutions toMeeting Changes in Marine An Ecolab Company Reprint R-1077EFuel Oil ISO 8217 SpecificationsBy Ron Sharpe and Tony OBrien, Energy Services Downstream,Ir. G. Tjalmaweg 1, 2342 BV Oegstgeest, The Netherlands ABSTRACT It must be emphasised that the system details that influence the performance of the above programmesNew ISO 8217 Marine Fuel Oil supply specifica- are unique to each refinery. No accurate estimatetions call on fuel oil producers and blenders to meet of chemical requirements can be given before aa tighter specification on aluminium and silicon detailed and controlled field trial has been carried(Al and Si) levels. Current Al and Si specifications out. It is the experience of Nalco that long-termare to be reduced immediately from 80 mg/kg to optimisation opportunities can be realised by track-60 mg/kg. In addition suppliers are being advised ing the fluctuations in base H2S levels in untreatedthat from July 2012 they will also be required to sour streams and in the case of slurry oil, catalystmeet a 2 mg/kg liquid phase hydrogen sulphide fines loading and particle size distribution.(H2S) specification. Although the delay in intro-ducing the H2S specification was in part to giverefiners time to make the necessary changes to meet ISO 8217 MARINE FUEL SPECIFICATIONSthe new specification, many traders are alreadydemanding that their suppliers look to meet the In June 2010 several revisions were made to the ISOspecification now. 8217 marine fuel oil supply specifications. Two key changes that can affect refiners and blenders are:A key enabling factor in setting this H2S level hasbeen the development of a new, rapid, instrumen- • The introduction in July 2012 of a H2S specifica-tal method for the analysis of H2S in fuel oil as tion of 2 mg/kg in bunker fuel and marine gas oil.described in IP 570. • An immediate reduction in aluminium andNalco has been instrumental in the development silicon (Al and Si) specifications in bunker fuelof this technique, which has become an essential from 80 mg/kg to 60 mg/kg.tool in the application and optimisation of our H2S With reference to H2S in fuel oil refiners, shippersscavenger programmes. Rapid monitoring of H2S to and terminal operators have for many years expe-determine initial loadings and final fuel oil levels rienced occasional problems associated with theis key to efficient scavenger optimisation. release of H2S from heavy fuel oils and in particularNalco H2S scavenger technology is based on com- bunker fuel. Problems arising are related to:plex triazine formulations incorporating a patented • Safety – Particularly for personnel involved inactivator for rapid efficient reaction. The reaction the storage and movement of these oils. Underproducts are oil-soluble and thermally stable, per- United States (US) National Institute of Occu-manently removing H2S from the fuel oil. pational Health and Safety (OSHA), guidelinesNalco has extensive experience in the application H2S levels in excess of 100 wppm in the vapourand optimisation of fuel oil sweetening and catalyst phase are considered immediately hazardousfines settling aid programmes and treats many to life and health. In Europe, exposure limitsmajor refineries in Europe, Asia and the USA. The for H2S in the atmosphere have been set at akey to the success of these applications depends on maximum of 15 wppm for fifteen minutes.the following: • Odour Mitigation – Local authorities are• Use of appropriate H2S scavenger and catalyst increasingly putting pressure on refiners and fines settling aid chemistries terminals to minimise fugitive emissions.• A detailed understanding of the system• An efficient monitoring and dosage optimisation service programme
  2. 2. • Demurrage Charges – If because of an H2S Test data has shown that 1 wppm of H2S dissolved problem, a cargo cannot be either loaded or dis- in the bulk liquid phase can produce between 5 – charged, traders handling the cargo can accrue 500 wppm in the vapour phase. Consequently, by significant demurrage charges and these can be lowering H2S levels in the liquid phase you can approximately $ 30,000 (€ 22,300) per day for a minimise, but not totally remove toxic exposure risks. 30,000 tonne tanker. To overcome this problem several oil companies• Revenue Loss – If a cargo cannot be treated, started to measure H2S levels in the liquid phase traders face the problem of having to sell fuel using a variety of in-house techniques. It was oils at a significant discount. however soon realised that dependent on the method used, different results could be obtained.• Costs – Associated with the implementation of In an effort to address this issue a task force set environmental compliance strategies. up by Europia looked at the various analyticalAl and Si specifications are being implemented to techniques and agreed on a standard method nowreduce the potential for engine wear and fouling called IP 399.problems when slurry oil is blended into fuel oil. Although the repeatability and reproducibility ofThe slurry oil is being used as a more cost effec- the method was reasonable, analysis had to betive blend component to other distillate streams carried out by an experienced analyst in a labora-in finished fuel oil blends. Slurry oil is typically tory and was both time-consuming and laborious,added to fuel oil to meet viscosity specifications. with the analysis taking approximately four hoursSlurry oil and blend components containing slurry to complete.oil are also burnt directly in refinery furnaces and To overcome this problem Nalco as part of anblended into heavy fuels destined for inland mar- Energy Institute task group ST-G-5EI, (includingkets where in addition to the potential problems representatives from Shell, ExxonMobil, BP andmentioned above, their use without treatment Total) have for several years worked with Setacould give rise to burner tip erosion and particulate Analytics on the development of a new analyser.emissions problems. This new instrument, as shown in Figure 1, has now been approved for use under the method num- ber IP 570 and is now the officially recommendedHYDROGEN SULPHIDE (H2S) REDUCTION method for determining H2S levels in marine fuelMeasurement Techniques oils and distillates.The prime risks posed by H2S relates to poisonous The new instrument is capable of determining H2Sgas levels in the vapour phase above tanks. For this levels in fuel oil within 30 minutes compared withreason historically it was considered that vapour 3-4 hours by the IP 399 method and has betterphase measurement was the most applicable when repeatability and reproducibility.determining whether or not a cargo was safe totransport. This however, is not the case. H2S in To further improve testing procedures and mini-the liquid phase and in the vapour above tanks mise the risk of volatile hydrocarbons interferingexist in equilibrium. Consequently, if for example with sensor activity a modification to the analyserH2S vapour in a tank was removed by purging is planned later this year. This will involve theor chemical treatment, H2S present in the liquid fitting of an attachment called a Vapour Phasephase would migrate from the liquid to the vapour Processor (VPP) which by cooling the gas evolvedphase establishing a new equilibrium. during sparging and passing it through a sorbent cartridge will effectively remove interfering chemicalPhysical factors affecting H2S liberation from the species such as volatile thiols and alkyl sulphides.liquid phase include:• Temperature – Hot hydrocarbons release more H2 S The development of this method has been one of• Viscosity – Viscous hydrocarbons trap and re- lease H2S more slowly than less viscous liquids• Mixing – Agitation causes H2S to be more quickly released from the bulk liquid• Weathering – H2S levels decrease through vents, sparging and open hatches• Hydrocarbon Composition – H2S solubility varies with hydrocarbon composition Figure 1 – IP 570 instrumentation with VPP for H2S measurement. 2
  3. 3. the key enabling factors for the revision of the ISO sulphur compound present rather than overall8217 standard. From June 2012 marine fuel oil sulphur levels that affect H2S production.suppliers are being advised only to use this new • Lower temperatures on tower bottom residuetest method and to supply oil into the market with streams. Although for example VDU bottoma maximum level of 2 wppm H2S. In reality many temperatures are typically adjusted to maxi-traders are already demanding that their suppliers mise product yields and the quality of the finallook to meet the specification now. residue, lowering bottom temperatures by just aUse of the analyser will be extended to marine gas few degrees can significantly reduce the amountoil, which will in 2012 also have to meet a 2 wppm of H2S generated, as shown in Figure 3.maximum H2S specification. Plans are also being • Desulphurise fuel blend components.considered to modify the instrument to allow itto be potentially used to test for H2S in crude oil.Nalco would recommend the use of this H2S analys-er when looking to determine H2S levels in finishedbunker fuel and for residue blend components withrelatively low viscosities.Where blend component viscosities at 50°C areabove 3,000 centistokes we would recommend theuse of the Nalco Dilute and Purge Analyser, whichis not subject to the same viscosity restriction.The Nalco analyser, as shown in Figure 2, is typicallyused to test base H2S levels in blend components likevacuum distillation and visbreaker residue streams. Figure 3 – Impact of vacuum column bottom temperature on H2S generation. • Increase steam-stripping rates on problem streams. • Utilise a H2S scavenger programme. For a variety of reasons the economics of the first three options would not normally be considered viable. However, providing that there is sufficient steam available and it is economically viable, steam stripping has been found in some cases to be an effective solution removing the bulk of the toxic gas. H2S stripped out of the fuel oil is handled in the refinery off gas systems where amine units can remove it and then either burn it as fuel gas or convert the toxic gas to sulphur at the Claus unit. Another option available is chemical treatment using a H2S scavenger. While several chemical treatment options exist, selection of a suitable program is essential if the application is not going to give rise to other issues. The types of chemicalFigure 2 – Nalco Dilute and Purge treatment options available include the use of:Analyser for H2S measurement. • Caustic – While caustic is cheap its use will increase sodium level in the fuel oil and increaseTreatment Options the potential for burner tip fouling and corrosion.Refiners who find that they cannot meet the new It can also give rise to corrosion problems wherespecification have several process treatment options. water accumulates in tanks and pipe work. ForThese being: these reasons most engine manufacturers set low sodium specifications on fuels recommended for• Move to processing lower sulphur crude oils. This their engines. is not always feasible as it is the type of organo- 3
  4. 4. • Formaldehyde based products – These prod- • Metal Carboxylates – Where mixing efficiency ucts while effective and inexpensive pose serious is poor or temperature limitations rule out the handling and storage issues. Not surprisingly, use of more conventional treatment chemistries most refiners are very reluctant to use such a the use of metal carboxylates have been found material. to be a cost effective option because of their oil solubility and rapid rate of reaction, e.g. iron 2• Simple Amines – Simple amines such as mono- ethyl hexanoate as shown in Figure 6. ethanolamine (MEA), diethanolamine (DEA), and methyldiethanolamine (MDEA) are typi- cally used in these formulations. These organic amines are weak bases, while H2S is a weak acid. The amine salts formed easily dissociate when thermally stressed, re-releasing H2S into the vapour space. This problem has already been seen in the USA and Asia.• Complex Proprietary Amines – Some pat- ented proprietary products react with H2S to form heat stable, oil soluble materials, which do not subsequently breakdown on heating to re- lease H2S. Examples of such products are Nalco Sulfa-Check® EC9085A and EC5495A which on Figure 6 – Example of an iron carboxylate. reaction with H2S form oil soluble complexes, as shown in the reaction mechanisms illustrated in H2S SCAVENGER APPLICATION Figure 4. Both products also contain patented activators, which catalyse the reaction. The key factors affecting the performance of a H2S scavenger are: • Temperature • Residence time • Mixing efficiency Both the temperature at which the scavenger is added, and the residence time for reaction are often dictated by the availability of suitable chemi- cal injection points on the unit. As a general rule the scavenger product should be injected as far upstream in the run-down as possible, maximising both temperature and residence time. However this will ultimately be limited by the thermal stability of the scavenger itself which will vary depending onFigure 4 – Reaction mechanisms of EC9085A and its specific chemical structure. The thermal stabil-EC5495A with H2S. ity of the scavenger should therefore be determined prior to establishing the injection location.• Glyoxal – Aqueous solutions of glyoxal are mix- Mixing efficiency also is an important factor and tures of hydrated monomers dimers and trimers. this is particularly the case with water based for- They have been show to react with hydrogen mulations. While water based formulations can sulphide to give products such as trans, trans often be the most cost effective solution these need 4,4’,5,5’,-tetrahydroxy –2,2’-(1,3-thioxolane), as to be highly dispersed as very fine droplets on initial shown in Figure 5. Glyoxal is very acidic and can injection into the oil. This maximises the droplet cause corrosion in line work and oil tanks. The surface area available for reaction and minimises reaction product is also not oil soluble and may any subsequent settlement or coalescence that cause fouling problems in distillation columns. might occur further down stream. The data shown in Figure 7 demonstrates relative scavenging performance of a water-based triazine scavenger under low and high mixing conditions. To ensure good mixing efficiency Nalco recommend the use of a patented purpose-designed “Nalguard” quill installed in the rundown line to improve mix- ing efficiency, as shown in Figure 8, and/or the installation of a static mixer.Figure 5 – Reaction of glyoxal with H2S. 4
  5. 5. Figure 7 – Effect of mixing on the reaction rate of triazine. Nalco have sometimes dosed at higher levels, but this tends to be on applications where: • Mixing efficiency is poor • There is interactions with other components e.g. naphthenic acids • A rapid reduction in H2S levels is required quickly. E.g. when tankers are being loaded or awaiting discharge. The only real way to determine optimum require- ments would be in an efficiently monitored and controlled field trial. Programme performance and Optimisation The supply of an effective product does not in itself guarantee the success of any treatment chemical programme. Of equal importance is effective appli-   cation and control of chemical dosing and reaction to the results of treatment. Figure 8 – Nalguard Quill Programme performance would be determined based on H2S measurements taken before and afterGiven the variation in plant design and the blend scavenger addition. As already mentioned howevercomponents available we would always recom- depending on stream viscosity we may in the casemended that ahead of the implementation of a H2S of residue streams opt to use the Nalco Dilute &scavenger programme that one of our technologists Purge Analyser, using IP 570 methodology only tovisits a plant to carry out a detailed survey and determine H2S levels in finished fuel.advise on how the product should be best applied, Once the first set of base data is obtained weand controlled. would use this and further results to establish the optimum H2S to scavenger dosage ratio for that particular system. H2S levels can however, varyDosage Requirements significant over short times frames and it may beBased on a considerable amount of field experi- necessary at some plants to test untreated fuelsence we have found typical H2S scavenger dosage or blend components up to three times per day torates to be in the range of 12-25 wppm of product effectively control scavenger dosage rates.per wppm H2S. Figure 9 illustrates the use of H2Sscavenger in a large-scale application. 5
  6. 6. Figure 9 – Impact of using H2S scavenger on a large scale application. CATALYST FINES REDUCTION Treatment OptionsNalco have supplied catalyst fines settling aids Reactor cyclones – The reactor cyclones are theto refineries for many years. Although the reason first step in the removal of catalyst fines. A prop-for settling aid use differs from plant to plant the erly operating system with two-stage cycloneskey drivers are: will remove particles larger than 15-20 microns in diameter. Mechanical problems with the cyclones,• To allow a refiner to maximise the amount of operating changes to the FCCU, or the use of a slurry oil they can blend into fuel oil while still softer catalyst will tend to increase catalyst losses meeting ash and Al /Si specifications. to the slurry oil, as well as changing the slurry oils• To meet carbon black manufacturers specifica- particle size distribution. The amount of catalyst tions. fines in circulating slurry oil normally ranges be- tween 0.2 wt% and 0.8 wt%. Further reductions• Minimise furnace fouling and burner tip erosion in fines levels can be achieved by using one of the issues where the slurry is burnt on site. other methods described below.• Reduce customer complaints. E.g. engine dam- Electrostatic precipitators and mechanical age claims. filtration – Some FCC units have mechanical or• Minimise particulate emissions particularly electrostatic separation devices installed to remove when the fuel oil is burnt on a power station. catalyst fines from slurry. Generally, the separated fines are back-washed using slurry or heavy cycle• Minimisation of plugging and catalyst deactiva- oil back to the riser. These devices when operating tion in fixed bed Hydrocrackers or ebullating bed properly can be very effective in removing fines. conversion processes. They do however represent a significant capital• Increase the saleable value of slurry oil sold on investment and many refiners have reported hav- the open market. ing problems operating and maintaining. A further disadvantage is that the recycle stream back to the riser is usually high in difficult to crack aromaticMeasurement Techniques compounds, that will increase coke formation and product yield losses.Testing for aluminium and silicon levels in fuel oilis covered in several IP test method including IP Tank Settling – Settling of the catalyst fines in501. Going forward however Nalco is looking into tankage is the most common method used by refin-faster and potential more accurate techniques to ers to achieve finished ash and Al and Si specifi-measure these two materials. We are also looking cations. Normally, one or more settling tanks areto use laser particle analysers to monitor FCCU cy- devoted to this service. Catalyst fines in slurry oilclone efficiency and its impact on catalyst fines gen- often do not settle readily in tankage and do noteration and catalyst fines settling aid performance. settle according to Stokes law. Micro-fines would take an excessively long time to settle out, par- 6
  7. 7. ticularly in the non-static environment of a heatedtank, where convection currents are present.There are three key factors in tank settling. Bulkfluid viscosity affects the slurry oil viscosity, dictat-ing in part the settling rate of the catalyst fines. Thebulk fluid temperature should be maintained at 70°Cor greater. The settling efficiency decreases with in-creasing viscosity at low temperatures. In some casessteam coils are used to maintain sufficient heat intanks. In either case tanks should be well insulated.In tanks without an internal heating source, rapidsettling of the fines is important before the tank cools.Placement of the inlet and outlet nozzles on thetanks should be considered. Inlet nozzles should beplaced far enough above the tank bottom to avoid Figure 10 – Flocculation of micro-fines on to largedisturbing the layer of sludge and re-suspending catalyst particles, shown at 3,000x magnificationfines. The outlet nozzle should be designed and under the microscopeplaced to avoid drawing out solid material near thebottoms of tanks. Some refiners have used floating considerable holding time would not to a great extentroof suctions with good success. settle in tankage. Figure 10 shows the flocculation of micro-fines on to large catalyst particles.Refiners often devote several tanks to this servicearranged in series or parallel. A typical arrangement Settling aids can improve fines removal by up tois to fill one tank while allowing a second parallel 90 % over untreated systems. Even under mildlytank to settle. Another arrangement is to cascade turbulent situations seen in heated tanks settlingthe slurry from a primary settling tank to finished aids improve catalyst fines separation and theirproduct tanks. In some cases, limited tank avail- removal from slurry oil, as shown in Figure 11.ability force refiners to use a single tank for settling. To ensure programme success it is vital to car- ryout preliminary laboratory screening exercises to establish settling aid dosage requirements andCatalyst fines settling aids with support from local refinery personnel agreeSettling aids are polymeric compounds formulated to an evaluation protocol.react with catalyst fines surfaces causing them to floc-culate and so accelerate settling rates. Flocculation Other than the requirement for a low cost dosingof micro-fines on to much larger catalyst particle also pump, settling aid use requires no major capitalaids the removal of particles that would even allowing investment. Figure 11 – Removal of fines over 24 and 48 hours using various dosages of settling aid. 7
  8. 8. The chemical is injected via a suitably designed cal system is shown in Figure 12. The temperaturequill into the slurry oil rundown line to tankage at the point of injection should be below 230°C tointo a point in the system that will allow intimate avoid additive decomposition.contact of the chemical with catalyst fines. A typi-Figure 12 – Schematic of a typical application where the use of settling aids improves the removal of fines. Nalco Company 1601 West Diehl Road • Naperville, Illinois 60563-1198 SUBSIDIARIES AND AFFILIATES IN PRINCIPAL LOCATIONS AROUND THE WORLD Sulfa-Check, Nalco and the logo, are trademarks of Nalco Company. Ecolab is a trademark of Ecolab USA, Inc 5-12

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