2022 revamps ptq
CRUDE PREHEAT TRAIN MODIFICATIONS
STEAM EJECTOR UPGRADES
FIRED HEATER OPTIMISATION
REDUCING TURNAROUND TIME
Supplement to PTQ
Finding our Common Thread
The petrochemical industry relies upon a wide range of intermediate products and processes to turn source materials into finished goods. Axens provides efficient and reliable technologies, along with class- leading catalysts and adsorbents, for the production and purification of olefins and aromatics. www.axens.net
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REVAMP TO THRIVE IN THE NEW REALITY
The global economic challenges impact product demand and skew product slates. As you continue to deal with the challenges in the present, its critical to think about long-term solutions. Shell Catalysts & Technologies, has solutions to enable you to make smart investments while preserving cash through revamping, reconfiguring, or optimising your existing assets. Our experts co-create tailored solutions for current units while keeping your margins in mind — ensuring the investments you make right now can help you maintain your competitive advantage into the future. Learn more at catalysts.shell.com/revamps
revamps ptq ptq PETROLEUM TECHNOLOGY QUARTERLY
Editor Rene Gonzalez editor@petroleumtechnology.com tel: +1 713 449 5817 Managing Editor Rachel Storry rachel.storry@emap.com Graphics Peter Harper Digital Editorial Assistant Ciaran Nerval US Operations Mark Peters mark.peters@emap.com tel: +1 832 656 5341 Business Development Director Paul Mason sales@petroleumtechnology.com tel: +44 7841 699431 Managing Director Richard Watts richard.watts@emap.com Circulation Fran Havard circulation@petroleumtechnology.com
11 Identifying the root cause of underperforming ejector systems Scott Golden, Tony Barletta, Steve White and Darrell Campbell Process Consulting Services, Inc.
14 Crude preheat train fouling and fix-up S D Radia Fluor Canada Ltd
21 Safer and efficient combustion for fired heaters and boilers Francisco Rodríguez, Enrique Tova, Miguel A. Portilla, Miguel A. Delgado, Sixto López and Alfonso García-Marcos Suanzes INERCO
27 Chemical cleaning and fouling removal technologies Berthold Otzisk and Luis Del Castillo Kurita
32 Life or death of the PSA Annette Karstensen Becht Inc.
3 7 Tools for FCC unit troubleshooting Warren Letzsch Warren Letzsch Consulting PC
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Cover Neste’s Rotterdam complex overall renewable product capacity will be increased by 1.3 billion tpy using NEXTEL technology and Technip Energies EPC capabilities. Photo: Neste
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Flexibility is profitable
Flexibility Matters
tray vapor loads and internal liquid reflux rates. Keeping the upper pumparounds loaded can also help avoid low pumparound return or tower overhead temperatures that condense water and cause salting or corrosion problems. It may even make sense to turn off a lower pumparound. L ONG - TERM SOLUTIONS inking longer-term, cost-effective revamps can add critical flexibility to allow for wide swings in unit throughput and crude blends while still operating in control. e right process design enables operators to consistently:
In uncertain times, refineries can maximize profit (or at least minimize loss) through flexible operations. Crude units are the first link in the refinery processing chain, and making large changes in crude diet or throughput stresses even the most state-of-the-art unit. S HORT - TERM STRATEGIES Certain operating strategies can maximize reliability, yields, and product qualities. Some practical short- term options include: • K EEP THE BOTTOMS STRIPPING STEAM
At turndown, consider maintaining normal crude tower and vacuum tower bottoms stripping steam rates and lowering heater outlet temperature to control cutpoint. is allows the stripping steam to do the work while heater firing is minimized to protect the heater tubes at low mass velocities. L OWER THE PRESSURE Lowering tower pressures at turndown lowers the density of the vapor, which keeps trays loaded and can avoid weeping and loss of efficiency. Lower pressure also lowers draw temperatures, increasing pumparound rates and hopefully avoiding minimum flow limits for pumps and tower internals. M OVE HEAT UP In multi-pumparound towers, shifting heat to the upper pumparounds at turndown increases
•
Control desalter inlet temperature,
• Control preflash column inlet temperature and naphtha production, • Control pumparound return temperatures and rates independent of pumparound heat removal requirements, and • Precisely control vacuum column top pressure. is advice is, of course, generic. To discuss challenges unique to your own crude/vacuum unit, give us a call. Process Consulting Services believes crude units should have flexibility. We believe that revamp solutions should be flexible too - one size doesn’t fit all. We look forward to working together to find the most cost-effective and reliable solution to your crude processing problems.
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3400 Bissonnet St. Suite 130 Houston, TX 77005, USA
+1 (713) 665-7046 info@revamps.com www.revamps.com
revamps q&a
More answers to these questions can be found at www.digitalrefining.com/qanda
Q With the needle coke market expected to register a CAGR greater than 10% between 2022–2027 to meet the growing demand for lithium-ion batteries and graphite electrodes, do you see scope for reconfiguring underuti - lised fuel-grade cokers to needle coke production? A Dinesh-Kumar Khosla, Global Market Manager Heavy Ends & HDC, Axens, dinesh-Kumar.KHOSLA@axens.net, and Hugues Dulot, Technology Advisor - Hydroprocessing Technologies Expert, Axens, hugues.dulot@axens.net: Needle-grade coke is produced from highly aromatic feed- stocks with low asphaltenes, sulphur, and ash contents. This coke, with high strength and a low coefficient of ther - mal expansion, is used for graphite electrodes and lithium batteries (anode material). Needle coke is a scarce product in the refining and by-product coke industry. Owing to an increase in demand, there is increased focus on maximisa- tion of needle coke production with the right quality from existing processes, expanding the process raw material base and towards the treatment of raw material in the coal carbonising process. Production of high-quality needle coke requires quality control of the feed stream, targeting high aromaticity, low ash content, low sulphur and nitrogen content, and low CCR content. Indeed, these impurities are detrimental to the growth of coke in needle form. Feedstocks such as FCC unit decant or slurry oil and coke derivate cuts are being consid- ered for maximising needle coke production using existing fuel-grade cokers. Slurry oil was previously blended and sold as bunker fuel but is no longer feasible with the new marine fuel sulphur specification of 0.5 wt%. Axens’ slurry oil hydrotreatment solution enables maximisation of coker feedstock, which could produce high-performing needle coke. This process boosts refinery economics by converting a low-cost feed - stock into a high-value product with minimum hydrogen consumption. Depending on economics, other opportunities could include using coal tar or thermal tar from VGO thermal cracking. Aromatic extracts from lube oil solvent refining are another possible feedstock, even though they are of inferior quality compared to slurry oil. Coker feed pretreatment objectives include minimising ash, sulphur, CCR, and other coker feed contaminants while maximising aromatics retention. These targets emphasise the experiential importance of designing the feed pretreat- ment section. For instance, reducing the ash content in FCC decant oil requires a clarifier or similar equipment (filter, cen - trifuge). Additionally, optimisation of operating conditions (reactor temperature and operating pressure) and catalyst selection for this feed pretreatment section are equally important in maximising hydrodesulphurisation (HDS) while minimising aromatic saturation (HDA). Converting fuel-grade cokers towards needle coke production requires extensive experience with regard to
optimising coker feed pretreatment. Against this backdrop, the slurry hydrotreating process meets the targets with regards to HDS while minimising HDA (at minimum hydro - gen consumption). The proprietary Hyvahl process with the Permutable Reactor System (PRS) maximises the main hydrotreating catalyst’s cycle length while managing the pressure drop using PRS. All these solutions are already in operation for targeting high-quality needle coke. A Scott Sayles, Manager Renewables and Alternate Feeds, ssayles@becht.com, Mel Larson, Manager Strategic Consulting, mlarson@becht.com, and Robert Ohmes, Division Manager Strategic Business Planning, rohmes@ becht.com, Becht: Needle coke or graphite is about 70 to 80 wt% of the lithium battery’s mass, such that the growing market for EV vehicle batteries and other battery systems for storing off-peak ‘green’ power is promising. That said, redefining a coker’s operation to produce needle-grade or graphite electrodes can be a significant challenge. Several entities are examin - ing this opportunity, but limited firm plans for conversion have been announced. Fundamental to producing needle coke is access to a highlight aromatic feedstock, such as decant/slurry oil from an FCC, thermal tar vacuum gasoil, coal tar, or lube extracts. Given shifts in crude slates to light tight oils, impacts of IMO 2020 implementation, further decarbonisation efforts in the fuel oil market, and continued efforts to convert fos- sil feed refineries to renewable processing, these potential feedstocks are becoming more difficult to secure. In addi - tion, depending on the capacity of the existing coker, find - ing sufficient material from local sources will be a challenge, such that the costs and systems associated with feedstock logistics could significantly limit this possibility. Some refiners are examining the use of renewable feed - stock as a potential feed source, especially in the area of plastics recycling. Finally, the feedstock may need process- ing in a dedicated hydroprocessing unit, such that a candi- date refiner will need to repurpose a unit for this processing arrangement, as well as understand the impact of changing to needle coke service for the upstream and downstream units, crude processing optionality, and modified product mix. In addition, the following considerations should be addressed: • Fundamentally, the requirement for needle coke yield will lower the delayed coker feed as this requires a higher com- bined feed recycle ratio of 1.15 to 1.25 • Additionally, needle coke feed sources are low in metals (500 ppm combined max) and low in sulphur, thus moving the cost of crude sources higher and challenging refinery economics • Economically, needle coke contributes less than 5% of the overall refinery margin when all factors are considered; thus, moving to needle coke will require other advantages
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• Tight oils crude sources are not conducive for needle coke production, as noted the need for aromatic feedstock to pro- duce the needle structures. In summary, without the necessary infrastructure of spe- cific crude, sweet decant oil, and market potential, the ben - efit of competing with existing producers and providers can be a challenge. A Matthew Stephens, Senior Manager of Economic Engineering, Imubit, matthew.stephens@imubit.com: There is an opportunity to convert fuel-grade cokers to needle coke production, but it will also require additional equipment at refineries to reduce metals/contaminants in the coker feed while providing the required aromaticity. This could mean adding a unit such as a visbreaker or thermal cracker with additional vacuum fractionation to provide these clean and aromatic coker feeds. This seems like a particularly good fit for sites with multiple cokers where the dirty portion of the remaining coker feed could still be fed to a fuels coker. There will also be the need for increased specialty coke calcining capacity to provide the incremental final processing of this material. A Marcio Wagner da Silva, Consultant, marciows30@ gmail.com: The needle coke market is very attractive nowadays, and some short-term capital investment could be made to opti - mise brownfield delayed coking unit (DCU) performance to maximise needle coke or even greenfield capital investment for new DCUs. It is important to consider the possibility of producing needle coke just by using specific feeds with high aromaticity, depending on the refinery configuration and the processed crude. An example is to use FCC decanted oil as feed to the DCU. It is nonetheless necessary to consider the global impact over refinery-wide production planning when considering that FCC optimisation to maximise decanted oil output reduces the yield of intermediate streams considered of high added value. Q Engineering and construction cost indexes remain high according to IHS Markit Insights, along with global increases in shipping and equipment costs, particu- larly electrical machinery - how is this affecting refinery revamp planning? A Gordon Lawrence, Regional Manager Turnaround and Project Assurance, Becht, glawrence@becht.com: We have seen astonishing increases in equipment costs and shipping times. This has been affecting our clients across the globe, not just in North America or Western Europe. It has caught a few owners out, leading to project or turn- around budget busts when prices are higher than estimated and schedule busts when shipping times are longer than planned. But in general, the increases in equipment cost and shipping time have been well signalled in advance. This has meant that those project or turnaround owners who con- tinue to follow the time-honoured rules of good and timely front-end definition have been able to ensure their budgets and lead times reflect the current reality.
Developing a good-quality estimate, with budget or firm quotes on price and delivery from vendors before going for a Final Investment Decision is as important as always. The issues with shipping also bring into focus the value of hav - ing in-house procurement and expediting resources and not leaving those tasks solely to the engineering contractor. It is important to keep an eye on deliveries and ensure your orders are not ‘shunted to the back of the queue’ by other customers who are shouting louder for their orders. However, the area where teams are perhaps not yet fully grasping the implications for the future is the recognition of the impact of escalation. For a turnaround, with its shorter lead time, this has perhaps a slightly lesser impact. But for large capital projects, trying to take account of the latest inflation figures in the escalation allowance for a project budget is an interesting exercise in ‘crystal ball gazing’. A Kevin Clarke, Chief Strategy Officer, Imubit, kevin. clarke@imubit.com: As the energy industry progresses with the transition toward low and zero-carbon emissions, the growth in proj - ect volume for sectors such as renewable energy, hydrogen production, carbon capture, and e-fuels will begin to com - pete for manufacturing capacity with traditional energy industries. As mentioned, there is obviously competition for electrical machinery with renewables installation and elec - trical grid upgrading. However, it can be expected that there will, for example, be a sharp growth in demand for very high pressure, thick-walled storage vessels and compressors for hydrogen applications, so equipment items that were his - torically deemed to be easily accessible within the market are increasingly long-lead items that will drive the project timing and delivery schedule. For those facilities looking to switch toward green hydro - gen, supply of electrolysers will be increasingly constrained by manufacturing capacity as OEMs gradually build out giga-factories in the future. Thus, one can envisage a situ- ation where, in the case of some of these equipment items, the actual project scale and concept, technology selec- tion, and vendor selection could be driven more by what equipment each supplier could provide within the project timeframe. The traditional technology selection process or vendor competitive bidding process may be less relevant in this environment, so procurement divisions should be cognizant of the possibility that there may only be one bid - der able to supply these critical equipment items in the timeframe. Q Against a backdrop of contractors and subcontractors challenged with staffing up in advance of a refinery or petrochemical facility revamp, can you comment on what is needed to increase the quantity of well-qualified crafts - men in the post-pandemic era? A Gordon Lawrence, Regional Manager Turnaround and Project Assurance, Becht, glawrence@becht.com: Finding well-qualified craftsmen has been a concern in North America and Western Europe for some time. The recent pandemic has merely increased a pre-existing
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END-TO-END SOLUTIONS FOR MAXIMIZING THE PRODUCTION OF PETROCHEMICALS FROM CRUDE OIL
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concern rather than caused it per se. There seems to be a number of factors in play: • The societal shift in North America and Western Europe to put less social cachet on manual labour means fewer young adults are interested in this work. The drop in vocational training and apprenticeships, coupled with the growth in the desire for degree qualifications, is one sign of this • The societal concern about climate change has led to a situation where (rightly or wrongly) young adults in those regions view the oil/petrochemical industry as being a bad industry to go into, both for personal social standing and because they don’t view it as having long-term career prospects • Then, finally, the recent pandemic has awoken a greater desire amongst young adults for work that can be done remotely, from home and does not involve a nomadic exis- tence, travelling from job site to job site. In the European Union, the shortage in skilled labour in Western Europe was, until recently at least, partly covered by the migration of skilled labour from Central and Eastern countries within the Union that had not yet de-industri- alised. That migration has slowed as the Central and Eastern economies have grown to the point where the disruption of moving west is no longer offset by a bigger pay packet than could be earned at home. In the near term, the shortages may be covered by higher wages to encourage existing skilled workers to stay in this line of work, perhaps coupled with loosening restrictions on migratory labour. In the medium term, companies may need to set up testing and training courses for their contractor workforce and help improve the training of workers who are not at the right skill level. In the longer term, there may be an opportunity to highlight that the ‘green’ industry will still need craftsmen (albeit perhaps not as many as before). But unless and until society returns to a situation where skilled manual labour is perceived as having social stand- ing, we likely need to begin planning to work with a leaner workforce than we’ve used to in the past. This may include, for projects, accepting longer construction periods, and for turnarounds, reverting to smaller, more frequent events to match the size of the available workforce. A Kevin Clarke, Chief Strategy Officer, Imubit, kevin. clarke@imubit.com: The traditional role of craftsmen has been evolving over recent times, driven both by demographics and the pan- demic. It is becoming harder to encourage school leavers to enter these hands-on, mechanical roles, resulting in plant owners increasingly seeking to use advanced technologies to change how equipment is built, maintained, and oper- ated. The arrival of drones for inspection of remote locations such as flare tips, non-intrusive wireless ultrasonic wall thickness measurements to reduce the need for inspectors to access remote or risky locations, and increasing deploy- ment of robotics and mechanical automation in, for example, warehouse management are symptoms of this change. Today’s school leaver expects facilities to have a high degree of digitalisation, as they experience in their home life – a highly connected plant with data to enable predictive
performance assessment, a high degree of plant automation and optimisation (using artificial intelligence, for example), and easy access to all of the plant information (drawings, design data, live data) in a user-friendly environment, such as a digital twin model of the plant. Leading operators are using connected field workers to assign field maintenance work digitally in real-time across the team, linked automatically to the appropriate work pack preparation in the warehouse, to facilitate efficient execu - tion of preventive maintenance. The benefits are amplified many-fold when incorporated into the deployment of a major capital project or the timely execution of a plant main- tenance turnaround. Finally, within the context of capital project development, this evolution of the craftsman’s role is pushing the consideration of modular construction, with reduced on-site build content. A Marcello Ferrara, Chairman, ITW Technologies, mfer- rara@itwtechnologies.com: Hiring qualified people is one of the major challenges facing the oil and gas industry in the post-pandemic era. Qualified people need experience and long-lasting formation, and the oil and gas industry was already short of qualified people. The pandemic era has exacerbated the labour shortage. In addition to retirements, highly qualified workers frequently move to other companies and sometimes to other industries. Reuters recently reported that 43% of workers surveyed globally in 2020 planned to leave the energy sector over the next five years. Many factors influence the availability of qualified people. First, workers are no longer motivated solely by wages. Many people are readdressing their pri - orities post-pandemic (family, quality of life). Second, the oil and gas industry is no longer perceived as a secure job opportunity. The two industry collapses in 2014 and 2020 led to massive layoffs and project cancellations. The threat of getting laid off or the need to constantly search for a new job pushed workers to seek employment in other industries. Third, there is a perception that the oil and gas industry, and fossil fuels in general, is one of the major causes of climate change. Finally, new generations are no longer keen on energy industry jobs because the model they have from the media is big money with less effort (but this would lead us too far into the discussion). Job offers today include professions that didn’t exist years ago, so younger generations have more choices. All these bespoke factors are exogenous to oil companies. A thoughtful question arises when considering that some oil companies put in place bidding, awarding contracts to the lowest bidder. Lowest bidding has primary practical effects on project execution, namely: a) The lower price bidder may face contingencies not con- sidered during the bid and therefore seek a way to save money b) The contractors generally lack incentives to hire expe- rienced and skilled people and/or invest in forming skilled professionals simply because they will not get any reward for it. On the contrary, they will increase their costs and be less competitive for bidding
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c) The contractors will have no incentive for innovation for the same reason as before. We believe it is not a matter of quantity of workers but much of quality and value: a good professional can give more value than a few average ones (the old 80/20 rule is still much valid). The solutions we propose can be sum- marised as follows: a) The oil and gas industry should invest more in enhancing its image and attracting talent and the younger generation b) Low labour-intensive technologies should be preferred to high ones c) Highly sustainable technologies should be preferred (with special reference to SDGs referring to good health, decent work, innovation, responsible production) d) Priority should be given to innovative contractors, who can improve SDGs and lower labor requirements e) Priority should be given to contractors with skilled per- sonnel, with proven qualities to give value to customers f) A scoring model should be developed in bids, to take into account the above priorities and to disengage from lower price. A Lindsay Shumate, Senior HR Generalist, KBC (A Yokogawa Company), lindsay.shumate@kbc.global: The worldwide oil and gas industry faces a shortage of well-qualified skilled workers. A shortage of skills can frus - trate firms. Besides hindering their safety, it can also reduce their productivity. While many skills take years to develop or an investment to acquire, oil and gas companies can take several steps to fill the gaps of talent shortage. When looking externally to fill these gaps for more immediate staffing needs, many SMEs in the industry have become subcontractors to remain focused on their specialty area of interest, which is quite helpful to have these indi- viduals on contract to assign project work on an as-needed basis. While hourly rates for SMEs can be quite higher than what is normally seen on an average salary, only paying for this time based on project needs has some advantages to reduce other payroll costs and that could better suit the subcontractors’ work/life balance while maintaining the ability to carry a variety of projects in their interests. When looking internally to fill staffing gaps with well- qualified individuals, this should be considered a continuous investment that is more rewarding, not only for the individ- ual seeking development but also bodes well for company culture with a likely reduction of attrition or staff turnover. Many early- to mid-level craftsman seek and express appre - ciation for company investment in developing their talents further and have been proven to remain in tenure of their position for longer. To accelerate internal ‘upskilling’, one of the best ways to fast-track learning is through in-house mentoring programmes. Pairing a protégé with a mentor who has already mas- tered the skill(s) allows the protégé to learn the skills nec- essary to succeed through a psychologically safe working relationship – typically, a mentor is not the reporting man- ager. An alternative approach includes offering on-the-job (OTJ) skill-based training. OTJ training programmes may consist of either workshop sessions, long-term rotational
assignments in a practical environment that last from a few months to two years, or a combination of both. Another option involves targeting skilled workers from other industries, such as manufacturing or construction since these individuals have highly transferrable skills that can be applied to the oil and gas industry. Next, vocational education has an important role to play in matching employ- ers’ needs with workers’ skills, knowledge, and qualifica - tions in the oil and gas industry. Finally, businesses and their stakeholders can get involved in manufacturing events and organisations, such as the Manufacturing Institute, to sup - port career training and trade skills education. Q How receptive do you think the industry is to the push to digitalise the repair processes of compressor components, such as valves, packing cases, piston and rod assemblies, to facilitate tracking each single maintenance event? A Nina Hirsch, Vice President, Market Segment Compressor Service, Strategic Business Unit Compression Technology, Hoerbiger, nina.hirsch@hoerbiger.com: We clearly see across the industry the common under- standing that digitalisation is not only important but viable for successful business operations in the long run. In most cases, receptiveness depends very much on an organisa- tion’s company culture and digital maturity. In the end, it is very simple – to achieve value gains in pro - duction optimisation and along the value chain, data has to be collected and thus certain transactions, like maintenance events, recorded. The goal is to spot trends and abnor- malities supporting information-based decision-making. Regarding our digital spare parts and proprietary VISTRA performance assistant, this means an immediate benefit by gaining deep insights into someone’s compressor fleet per - formance and bad actors down to component level. If these outcomes are perceived as value-add and provide benefits to the overall company’s goals, receptiveness is not just very high but naturally given. A Kevin Clarke, Chief Strategy Officer, Imubit, kevin. clarke@imubit.com: This type of advanced digital preparation and tracking of maintenance activity is already happening with some vision- ary operators. A digital environment has been deployed that has a complete task breakdown from equipment shutdown and preparation for maintenance, specific maintenance activities, start-up readiness, and reinstatement to operation. Each task within the maintenance process is linked to the others to understand if tasks can be carried out in parallel or series, what tools and parts are required (tied into the stores system), any lifting or access considerations (scaf- folding), permitting requirements and their preparation, and the personnel selection for the job based on skills required and competencies of the individuals available on the day. The software captures the start and completion time of each task, which can be used for benchmarking and continuous improvement of future similar maintenance activities or used to drive standardisation and implementation of best prac- tices across multiple sites within a larger corporate group.
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Identifying the root cause of underperforming ejector systems Underperforming ejector systems illustrate the importance of the long air baffle, its proper operation, and how to quickly identify problems when they arise
Scott Golden, Tony Barletta, Steve White and Darrell Campbell Process Consulting Services, Inc.
V acuum column steam ejector systems are typically engineered with very small design margins. The incen- tives to design with low margin are lower installed ini- tial cost and/or lower utility consumption. Systems designed with low margin must operate as designed. Otherwise, loss in performance can lead to millions of dollars in lost oppor- tunity. A common problem which results in breaking of the first-stage ejector operation, and as a consequence signifi - cantly higher operating pressure, is a failure to seal the first- stage inter-condenser ‘long air baffle’. First-stage inter-condenser design Figure 1 is an elevation view of a first-stage inter-condenser using a typical X-shell exchanger with a long air baffle. Vapour from the first-stage ejector is partially condensed in the inter-condenser to reduce the load on downstream ejec- tors. The vapour mixture from the first-stage ejector is non- condensable gas, condensable oil, and water vapour. The non-condensable vapour is cracked hydrocarbon gas created in the heater and air leakage. The condensed oil is primarily unstripped naphtha/kerosene/diesel boiling range material that leaves the bottom of the crude tower. The water vapour is process steam leaving the vacuum tower (stripping and heater coil) and first-stage ejector motive steam. There is a small amount of saturated water leaving with crude tower bottoms product. Figure 2 shows the flow pattern across the tube bundle. The coldest cooling water contacts the vapour from the fluid mixture exiting the bundle area above the long air baffle,
ensuring that the gas leaving is colder than the condensate. The purpose of the long air baffle is to direct the vapour flow through the coldest tube section to allow sub-cooling of the gas compared to the liquid out. This minimises vapour to the second-stage ejector. First-stage ejector outlet vapour enters the top of the exchanger and ideally is distributed uniformly along the length of the exchanger bundle top side. The inlet vapour partially condenses as it moves from the top of the bundle to the bottom. Condensate falls to the bottom of the exchanger shell, and the uncondensed vapour enters the area under the long air baffle for further cooling. The first-stage inter-condenser X-shell design with a long air baffle is conceptually two exchangers in series, as illus - trated in Figure 3 . The long air baffle is a seal plate, either slanted or ‘L’ shaped and typically contains 20-25% of the tubes under the projection of the baffle. This essentially creates two exchangers in series. When modelling perfor- mance of an X-type first-stage inter-condenser, a two series exchanger arrangement is a better representation of true performance. In the example, 90ºF CW has a 3ºF rise across the area below the long air baffle, with the remaining 7ºF rise across the area above the long air baffle. Condensate leaving the first-stage inter-condenser is created from the area outside the long air baffle and the remaining area under the baffle.
Vapour leaving 1st stage ejector
‘Long air ba e’
1st stage ejector vapour inlet
Cooling water outlet (typically 10˚F higher than inlet)
Tube bundles
Gas outlet
CW outlet
VAPOUR
CW intlet
Condensate from area outside ba e
Condensate from ‘Long air ba e’
‘Long air ba e’
Vapour outlet
Tube support
Condensate outlet
Cooling water inlet (coldest)
Total condensate
Figure 1 Elevation view of TEMA X-shell
Figure 2 Vapour flow across bundle
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1st stage ejector outlet
1st stage gas outlet
Area above ba e
Area below ba e
CW inlet
CW outlet
1st stage discharge piping pressure drop
90˚F
93˚F
100˚F
DP1
Condensate leaving bundle area above ‘Long air ba e’
Condensate leaving area under ‘Long air ba e’
2nd stage suction pressure drop
DP3
Condensate leaving 1st stage intercondenser
Figure 3 Model for X-shell simulation
DP2
Intercondenser pressure drop
If the long air baffle is properly sealed, the vapour leaving the first-stage inter-condenser must be colder than the con- densate since it has been further cooled by the surface area located under the baffle. Maximum discharge pressure and ejector break operation If the discharge pressure of the first-stage ejector operates above the maximum discharge pressure (MDP), then the operation of the ejector will be unstable due to a lack of the necessary shockwave in the ejector. This operating condi- tion is called ‘break’. Broken operation is characterised by an increase in suction pressure. Depending on the ejector design, the suction pressure can be 20-40 mmHG higher than design. The second-stage ejector load and the first-stage ejector system pressure drop determine the first-stage ejector dis- charge pressure. Figure 4 shows three major components that make up the first-stage ejector system pressure drop. They are: • The pressure drop in the piping from the first-stage ejector to the inter-condenser (DP1) • The inter-condenser pressure drop (DP2) and the piping from the inter-condenser to the second-stage ejector (DP3). The second-stage ejector suction pressure is a function of the load to that ejector. If the load goes up, so does the pressure. The first-stage ejector discharge pressure is cal- culated by adding the system pressure drop to the second- stage ejector suction pressure. If the process load or the
Figure 4 Pressure drop across ejector stage
inter-condenser pressure drop is higher than design, then depending on how much margin was applied to the design, the ejector discharge pressure may exceed the MDP and result in broken operation. It is not uncommon for the ejector MDP to be only 3-8 mmHG above the normal design operating pressure. Calculated first-stage inter-condenser pressure drops are about the same magnitude, about 3 to 5 mmHG. This leaves very little margin for inter-condenser fouling or underperfor- mance of the long air baffle. A small leak around the baffle can easily increase the load to the second-stage ejector and increase the suction pres- sure by 5-10 mmHG. Therefore, the performance of the long air baffle and its proper sealing are critical to first-stage ejec- tor performance. Quickly identify long air baffle problems If an ejector is breaking, it is quick and easy to determine if the long air baffle may be the problem. The temperature of the vapour outlet should be, at a minimum, the same temperature or a few degrees lower than the temperature of the condensate outlet. The condensate and vapour out- let streams are rarely instrumented, so a trip to the unit is required to measure these temperatures. Since the temperature difference between the two streams is small, accurate measurement is required. If the vapour out- let temperature is higher than the condensate temperature, then the air baffle is not performing properly. Data taken from operating units (see Figure 5 ) show the first-stage inter-condenser outlet gas temperature 8-15⁰F higher than the condensate. The root cause is the hot gas bypassing the long air baffle. Long air baffle hot gas bypass Low motive steam pressure, high cooling water tempera- tures, low cooling water flow, and exchanger fouling can all lead to underperformance and ultimately broken operation. The conditions do not cause the vapour outlet temperature to be higher than the liquid condensate. Figure 6 shows how second-stage inlet gas load increases with increasing condensing temperature at a constant
1st stage ejector outlet vapour
106˚F 105˚F 78˚F
CW outlet
87˚F 87˚F 72˚F
Gas outlet
109˚F 113˚F 94˚F
CW intlet
106˚F 106˚F 78˚F
Condensate to hotwell
Figure 5 Field temperatures
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QUESTIONS & ANSWE
pressure. Note the very sharp break in vapour load, which occurs as the condensing temperature causes the water vapour pressure to approach the condensers operating pres- sure. This is a result of condenser underperformance, possi- bly due to the conditions listed previously, and can also cause ejector break. It will not, however, result in the vapour outlet temperature exceeding the condensate outlet temperature. The X-shell first-stage inter-condenser long air baffle design principle is to minimise the gas outlet temperature, thereby reducing second-stage gas load for a given non- condensable gas load. First-stage inter-condensers hot vapour bypass of the long air baffle is a major cause of ejec - tor system break. Baffle sealing A key feature of the long baffle design is the baffle edge seal - ing. Seal strips are a critical component of TEMA X-type con- densers with removable bundles. In removable bundles, the baffle cannot be welded to the shell. To seal the long baffle and prevent vapour bypassing, sealing strips are attached at the baffle to shell junctions. These strips are made from thin corrosion-resistant material. These can be easily damaged during bundle installation. Seals should be replaced, not reused, every time the bundle is removed. The installer should never allow the bundle to twist or rotate during installation. If the bundle is not sealed properly, some fraction of the vapour entering the exchanger will bypass the condensing area and flow directly to the outlet nozzle. This adds additional load to the next stage, increasing suction pressure and back pressure on the first stage. In practice, when cooling water temperature is lower than design and as long as cooling water flow rates are at design the extra load due to bypass of the long air baffle may still be within the capabilities of the second-stage ejector and not lead to broken operation. As cooling water inlet temperature increases seasonally and reaches its design, second-stage gas load often exceeds the second-stage capacity, resulting in excessive back pressure on the first stage. In this case, higher pressure in the first-stage condenser is not due to exchanger heat transfer underperformance, but a faulty long baffle as indicated by vapour temperatures higher than the liquid condensate. Once the second-stage pressure exceeds the maximum discharge pressure of the first-stage ejector, the ejector breaks and, once broken, further increases in first-stage ejector discharge pressure continue to increase vacuum col- umn operating pressure. It is not unusual for the first-stage ejector operating in broken mode to generate higher noise levels than the already high noise levels generated by large first stage ejectors. Depending on the severity of the situation, it is sometimes possible to compensate for the higher bypass with first- stage inter-condenser motive steam nozzle changes. Either nozzle location in the steam chest or larger nozzle sizes have been used to increase the ejector MDP and eliminate system break. For more severe cases, rather than replace the entire system installing larger second-stage ejectors and condens- ers to handle high gas load has been a successful solution.
capital fr one of th alysts du Nobel ar phur red abatemen platinum capabiliti ❝ Ho wo technolo molecula ing facil Goelzer: between respect to opposed sented) f few alter From plier or c lar and feeds and problems and guar Refine methods under-ac or in oilf gy/cataly tolerance Some for advan and mole or via mo ry analys cated ana For ex FCC/RFC ern fluid reactor o pilot plan A num or weekl tion ana high tem sophistic tion and with RVP for distil ucts and dard for s D-1160 employed Bertho for direct key ma (FCC/RF diesel hydrogen been slow tions and gen as ke
120 With respect to the processing of residual feedstock in FCC, perhaps the most important change in modern FCC catalyst design is the quantification and subsequent optimisation of catalyst accessibility. Data from about 20 commercial experiences show that when contaminants like iron, vanadium, calcium and sodium increase, cata- lyst accessibility decreases rapidly. When catalysts with high accessibility (as measured by the AAI – Akzo Acces- sibility Index) are used, very marked improvements in activity and selectivity are achieved. 110 115 105 100 95 90 Vapour temperature Scott Golden is President of Process Consulting Services. He has more than 40 years of experience including refinery process design, refinery technical service, and distillation equipment design. Tony Barletta is Vice President of Process Consulting Services, Inc. He has over 34 years of experience with refinery revamps and process design for heavy oil units. To enhance the production of light olefins, especially propylene, in the FCCU stable narrow pore zeolites, eg ZSM-5, are required. This has to be combined with a host FCC catalyst featuring high propensity to produce olefinic precursors, which are subsequently cracked to light olefins. Steve White is a chemical engineer with Process Consulting Services. He has more than 46 years of process design experience for revamps and grass roots units, including crude/vacuum, FCC, hydrotreating, alkylation, isomerisation, reforming and other processes. Darrell Campbell is a process engineer specialising in refinery revamps. He received a degree in Aerospace Engineering from Texas A&M University in 1994 and earned his PE in Chemical Engineering in 2014. Increased ability of the FCC catalysts system to make lower sulphur-containing products is necessary for an overall more profitable refining operation. Reduced NO x and SO x emissions from the FCC stack are also required. The introduction of new FCC catalyst additives as Figure 6 Condenser vapour rate upgrading process for the oil refining industry, producing vast quantities of transportation fuels. It is also expected that it will gain importance as supplier of propylene worldwide and occasionally ethylene. The FCC process and the products it produces will have to meet strict emission standards. High accessibility and accessibility retention are required the make the processing of even more contam- inated residual feedstock possible. Akzo Nobel has intro- duced the Opal, Sapphire and Coral catalysts line featuring enhanced accessibility.
Kidextractor Quarter page
After you have used it the first time, the Kid Extractor will become your trusty hydraulic-tube- bundle-extractor
KIDExtractor Ltd. P.O. Box 11, Zebbug MALTA
Tel. 00356-21-462891 Fax. 00356-21-462755 MOBILE: 00356-94-20596 E-mail: idrojet@videobank.it Website: www.kidextractor.com
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Crude preheat train fouling and fix-up
Rigorous modelling of crude preheat train exchangers allows for fouling progression of the heat exchangers to be monitored throughout the crude unit run length
S D Radia Fluor Canada Ltd
C rude preheat train fouling is a serious operating problem in a refinery crude and vacuum unit. It reduces exchanger performance, increases furnace duty and associate fuel cost, reduces cooling capacity, and increases train pressure drop. The resulting increase in fuel costs and loss in throughput can significantly influ - ence refinery profitability. Crude oil is generally contaminated with water, salt, wax, sand, and mud, containing metal oxides and other particulates. These particulates deposit on heat exchanger surfaces, promoting the build-up of organic and inorganic fouling. Common techniques to prevent fouling include filtration, desalting, fouling inhibition, crude compatibility analysis, and preheat train revamp. Cleaning of exchangers is also carried out during unit operation to maintain throughput, maximise run length, and maximise operating performance. Fouling trends are often monitored by refinery opera - tions based on overall heat exchanger performance (over - all heat transfer coefficient x area or UA) estimations in the preheat train. These estimations cannot distinguish the performance penalty caused by fouling or that caused by flow reduction. A rigorous simulation model with a detailed rating of the preheat train exchangers can over - come this problem. Rigorous modelling of crude preheat train exchangers is described using a detailed heat exchanger rating program within a simulation model of an atmospheric and vacuum unit at an existing refinery. The exchangers are modelled with shell and tube side temperature and flow profiles that match the actual performance of various feed, product, and pumparound (PA) streams. The modelling establishes the fouling state of the shell and tubes to obtain the actual performance (duty and out - let temperature) of the crude preheat train exchangers. The modelling allows the fouling progression of the exchangers to be monitored through the crude unit run length. Crude preheat train In this case study, the crude preheat train consists of raw crude, desalted crude, and flashed crude preheat in an existing refinery, as shown in Figures 1 and 2 . The atmo - spheric and vacuum columns with feed, product, and PA streams are shown in Figures 3 and 4 . The raw crude is mixed with wash water and heated in the raw crude preheat train upstream of the desalters with
naphtha and jet PA and products from the atmospheric col - umn, and medium vacuum gas oil (MVGO) PA and products from the vacuum column. Temperature bypasses of hot streams are used to control the temperature of the return streams to the two columns for adequate PA heat removal. The raw crude temperature to the desalters is controlled to reduce brine, sediment, and water and water-soluble salts in the two desalters to minimise column overhead corro - sion. The desalter pressure is maintained high enough to prevent light crude oil fractions and water vaporising. The desalted crude is further preheated using MVGO PA and the product streams from the atmospheric and vacuum columns in a desalted crude preheat train and routed to a preflash drum. Light ends from the crude and entrained water from the desalters are flashed off and routed to the flash zone of the atmospheric column. This configuration prevents the vaporisation of these components upstream of the heater pass valves and potential pass flow imbalances. The flashed crude from the preflash drum is further heated using MVGO product and PA, medium diesel PA, heavy atmospheric gas oil PA, and product streams from the atmospheric and vacuum column in a flashed crude preheat train. The preheated flashed crude is further heated in the atmospheric heater and sent to the atmospheric column. The majority of atmospheric tower bottoms (ATB) from the atmospheric column is sent to the vacuum column via the vacuum heater, where it is fractionated into light, medium, and heavy vacuum gas oils. The slop oil from the vacuum seal drum in the column overhead is recycled to raw crude at the crude preheat train inlet, while the sour water from the same drum is sent to the stage 2 desalter as make-up water. Atmospheric tower bottoms bypass circuit Some of the ATB is bypassed around the vacuum column and sent to another unit for further processing. The ATB bypass is cooled with the flashed crude for heat recovery and finally cooled in an air cooler (E-30) prior to export to another unit. The ATB to this air cooler can run very hot due to fouling in the upstream exchanger, which causes numerous leaks. The air cooler also badly fouls up, and the high-pressure drop across this exchanger causes a hydrau - lic limit on the ATB circuit. A new exchanger to reduce the inlet temperature to E-30 by recovering heat from the ATB bypass was proposed to debottleneck the ATB bypass circuit. Before integrating the
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