The Seven Deadly Sins of Sour Water Stripping

COMMON MISTAKES IN SWS

The seven deadly sins of sour water stripping

Sour water systems should be designed to minimise operating problems, maximise on-line factor and optimise the quality of the feed gas to the sulphur recovery unit. D. Engel, P. le Grange, M. Sheilan and B. Spooner of Sulphur Experts describe the process of sour water stripping and focus on the most common mistakes (the seven deadly sins) made in operating and designing these units.

our water stripping is the first step put or even temporarily shut down. As a species in the sour water such as carbon in the treatment of ‘process’ waste- result, sour water must be stored in a hold- dioxide, hydrogen cyanide, mercaptans and Swater in many industrial operations, ing tank until processing is re-established ‘light’ hydrocarbons are also stripped. particularly in refineries. Water streams and must often use tank capacity not des- H S + NH NH SH NH + + HS– from a number of process units through- ignated for water storage. Quite often sour 2 3 4 4 temperature out a refinery complex are typically sent water composition is unknown (especially to the sour water stripper (SWS), which the contaminants other than H2S and NH3), There are many process wastewater is designed to remove hydrogen sulphide which can make correctly setting operating sources in a refinery, all of which have

(H2S) and ammonia (NH3) from the process conditions quite difficult. In other situa- different contaminant compositions, flow water. There are several variations in the tions, SWS units with fluctuating hydrocar- rates and pressures. In addition, some designs of sour water strippers, all play- bons in the feed create problems for the sources may be continuous while others ing upon the same theme of using heat downstream sulphur recovery unit. In these are intermittent. As a result, without proper to break the bonded ions in the NH4SH cases the acid gas is sent to a furnace or upstream equilibration, design, and opera- salt contaminant in the wastewater. This flare system for incineration, resulting in tion, the chemical composition and flow of liberates gaseous ammonia and hydrogen significant SOx and NOx emissions. Finally, water to the SWS may vary significantly. sulphide in a produced sour water acid gas some units do not make product specifica- This can result in frequent and severe oper-

(SWAG). In some designs the NH3 and H2S tion treated water and therefore a proper ational upsets both for the stripper and the are separated in separate columns and understanding of the fundamentals of the downstream sulphur plant, the destination sent to individual destinations, but in the process can help the operator come to a for the gases stripped from the water. majority of SWS applications the effluent rapid and effective optimisation of the unit. The most common process feed water acid gas from a sour water stripper over- sources are from: atmospheric crude head is processed in a sulphur plant. Sour water stripping process columns, vacuum crude towers, steam As oil and gas processing facilities deal chemistry crackers, fluid catalytic crackers (FCC), with increasing sulphur content in their hydrodesulphurisation (HDS) units, hydro- feedstock in combination with enhanced The purpose of a sour water stripper is to cracking (HCU) units, atmospheric des- environmental pressures to remove sul- remove components that are toxic or cause ulphurisation (ARDS) units, coker units, phur from finished hydrocarbon products, undesired odour. The most important ones amine reflux purges and TGTU quench the volume of “sour” water containing are H2S and NH3 but other components towers. H2S and NH3 concentrations are

H2S, ammonia and other contaminants is like CO2, HCN, mercaptans, phenols, the highest in water from the HDS, HCU, increasing. Additionally, the concentration hydrocarbons and solids are removed to ARDS, and FCC units. Any water stream of contaminants is increasing and exerting varying degrees. containing 10ppm or more of H2S requires higher demands for sour water processing The SWS process entails contacting the treatment before leaving site limits. capacity. Simultaneously, more stringent sour water flowing down a stripper column Meeting specification on NH3 and H2S environmental legislation and tougher fines with steam flowing up the tower. When sour in the treated water is extremely important for non-compliance have led to increased water enters the stripper it is heated, caus- as subsequent steps in wastewater treat- focus on the availability and reliability of ing the ionically-bonded ammonium sulphate ment usually involve biological treatment sour water treating units. salt (NH4SH), which is in the aqueous phase which cannot operate under high hydrogen A correctly designed, properly operated and has no vapour pressure, to decompose sulphide levels. and well maintained sour water stripper into H2S and NH3. H2S and NH3 have a (SWS) unit is critical to these operations. vapour pressure and thus can be stripped Sour water process description If the SWS unit is ever out of service, the into the vapour phase and separated into a The process can be viewed in Fig. 1 and facility must often run at reduced through- different process stream. Any other volatile summarised as follows:

Sulphur 363 | March - April 2016 www.sulphurmagazine.com 1 COMMON MISTAKES IN SWS

Fig 1: Generalised sour water process scheme for a pumparound SWS used in many ways such as: quench water, steam, wash water and is also generated by the various distillation fractions where acid gas to SRU effluent pump water is co-distilled with certain hydrocar- effluent to bons. Figures 2 and 3 show the diversity biotreater cooler of a number of sour waters originating from cooler various units and Fig. 3 provides an indica- tion of the quality of the treated water in relation to the feed quality. feed flash gas reflux pump Primary sour water sources include: effluent l Amine system reflux water purges. flash drum exchanger stripper TGTU quench water. hydrocarbons l Atmospheric and vacuum crude towers: to slops reboiler water is produced by condensation of sour steam in overhead streams. Vacuum tow- process buffer tank ers may also contribute sour water from water ejectors and barometric condensers. l Thermal and catalytic cracking units: sour water pump sour water pump sour water originates from wash water injection, stripping and aeration. l Hydrotreater and hydrocracker wash water from high and low pressure sepa-

Various sour water streams are col- wards and is stripped of H2S, NH3, ‘light’ rators. lected from throughout the refinery and sent hydrocarbons and other volatile species, by l Cokers, delayed and fluid type plants. to the flash drum. The flash drum removes the steam rising from the bottom. Steam is Water is produced from decoking and entrained and dissolved gases by allowing produced in a reboiler or introduced into the quench water. the water to de-pressurise and settle. column directly as live steam. l Flare seals and knock out drums. The degassed water flows to a holding, The overhead of the stripper may con- l Hot condensates from throughout the or settling tank (buffer tank). In this tank sist of a pump-around cooling section refinery which may have had contact with there may be further degassing as well as which cools the stream to a minimum of hydrocarbons (often the concentration of the separation of some liquid hydrocar- 85°C. Alternatively, a reflux system is used contaminants in these streams is low). bons that float to the surface of the water. for the same purpose. These systems l Any refinery water draw boot: each con- If the residence time is long enough, the recover a portion of the water in the over- tains a different sour water composition composition of the water stabilises and head stream, decreasing the amount being and flow, depending on crude type and allows for a consistent flow and composi- sent to the SRU. the severity of the process. Manual level tion of water to the stripper. The stripped water is cooled in the controls can also affect the hydrocarbon If any filters are present in the process feed/effluent exchanger, then pumped to content of the water especially if they are loop, they may be present upstream or various areas for further use or processing accidently left open for too long. downstream of the settling tank. (crude desalter, tail gas unit quench tower, The water exiting the settling tank is biological treatment, etc.). According to a previous study by the Ameri- heated in an exchanger (feed/effluent can Petroleum Institute2 covering process exchanger) by hot, stripped water exiting Sour water sources water consumption estimates, the sum- the stripper. In a refinery setting or any plant in general, mary level quantities of water used in refin- The heated sour water enters near the sour water can be generated in many loca- eries were as presented in Table 1. top of the stripper tower where it flows down- tions. Water for process applications is Seven deadly sins of sour water Table 1: Refinery conversion unit process water estimates2 stripping Over the years, multiple problems and Refinery conversion unit Estimated process water use Water use, US gpm per deficiencies have been uncovered. These US Gal/1000 bbl 100,000 BPSD crude have been compiled in the form of a list of Distillate hydrotreater 1,500 31 the seven most deadly sins of sour water Cat Feed hydrotreater 2,400 66 stripping: Vacuum unit 2,000 69 1. incorrectly designing the sour water stripper column; Crude unit 1,400 97 2. incorrectly controlling the overhead and Coker 8,000 112 acid gas temperatures; FCCU 4,500 125 3. poorly managing the sour water; Total 500 4. poorly operating or designing the flash vessel and feed stabilisation tank;

2 www.sulphurmagazine.com Sulphur 363 | March - April 2016 COMMON MISTAKES IN SWS

5. inadequate removal of solids and liquid Fig 2: Various process water streams feeding an SWS hydrocarbons; 6. lack of a detailed sour water analysis; 7. neglecting the sour water stripper metallurgy. No. 1: Incorrectly designing the sour water stripper column In designing a sour water stripper tower, there are several options available depending on the treated water specification of the particular plant. The downstream destination of the water determines the allow- able amount of H2S and NH3. The typical Fig 3: Water quality in feed and effluent of an FCC (L), Coker (C) & HT (R) SWS design basis can be described as follows:

Feed

[H2S] ≈ 500 – 24,000 ppm

[NH3] ≈ 250 – 12,000 ppm

Product

[H2S] ≈ 1 - 25 ppm

[NH3] ≈ 10 - 50 ppm

Generally, the options for design relate to a trade-off between the number of trays or height of packing and the quantity of steam required for stripping the contaminants from the process feed water. That is, the more contact stages available in the tower, the less steam required for stripping. Also, since ammonia is less volatile than hydro- fresh water make-up. The typical energy in the event that feed temperature drops, gen sulphide (therefore, harder to strip) it is usage in the stripper is in the range of 15% because of exchanger fouling for instance. usually the component that sets the quan- steam on a mass basis to the pounds/kilo- A feed temperature drop in a non-refluxed tity of contact stages. In general, the more grams of sour water; 1.3 – 1.5 lb steam stripper needs to be compensated for via the ammonia content in the feed stream, per US gallon of sour water1. increased boil-up which in turn leads to the more contact stages required or the There are several options related to higher vapour and liquid traffic below the higher the steam rates for stripping. the type of reflux section in the top of the feed tray with potentially lower flood points There are also options related to the tower. Options to choose from include: in the column as a result. regeneration medium; stripping steam l no reflux at all (generating enough The pumparound process has potential generated within a reboiler or live stream steam in the reboiler (or via live steam) for less corrosion than a refluxed system injection directly into the base of the tower. to produce a stripper overhead temper- because it is liquid filled and not as prone If a reboiler is used, there is an option to ature of around 88°C)3; to solid salt deposition; the relative con- go with a kettle-type or thermosyphon, or l standard refluxed sour water stripper, centration of ammonium salts is less in one of these reboiler types in combination with condenser/cooler, accumulator the pumparound as long as the tempera- with the option of incremental live steam and pump; ture does not drop too low. The general injection. If live steam is used, it must l pumparound reflux, with externally target for the reflux temperature is >185°F be understood that this will increase the cooled and pumped water system in a (>85°C) to eliminate the potential for treated water content by 10-15%, which discreet top section of the tower. ammonium salt precipitation in the water could increase treatment costs, which are loop and the associated piping to the SRU. normally linked to volume. The majority of the sour water strippers There are also options on the tower Lieberman3 has stated that it may be around the world use either the pumpa- internals themselves. Historically, the tow- possible that the extra water generated round or refluxed condenser methods, ers have been trayed, with an option for in the live steam mode could reduce the with close to an even split between the sieve or valve trays. Anecdotal evidence make-up water requirements for processes two methods. Non-refluxed strippers are seems to indicate that either sieve trays or such as de-salters and hydrotreater efflu- not favoured in modern industry as they grid trays will handle the inherently fouling ent washes. Since external water is can have excessive water content in the service best. Valves can become stuck to required for make-up for the above men- SWAG if overhead temperatures are not the tray deck, which will promote plugging tioned units, the increased water produced diligently monitored. Further they may and flooding. In recent years, some opera- by the live steam injection could off-set the experience significant capacity limitations tors/designers have tried using random

Sulphur 363 | March - April 2016 www.sulphurmagazine.com 3 COMMON MISTAKES IN SWS

elevated. It is important that the lag time Fig 4: Tray and steam effect on H2S and NH3 removal between dosing and pH measurement is minimised to avoid overdosing the unit. 100 lines indicate theoretical stages - 2-3 actual trays Figure 5 provides a review of a particu- 90 larly poorly designed sour water system. NH3 80 There was no buffer tank after the flash , %,

S drum, leaving no opportunity to moderate 2 70 flow rate and composition. Lack of a buffer 60 and H and 3 15 stages 10 stages 5 stages tank also means there is no place to store 50 sour water in the event of a stripper outage. 40 With no feed/effluent exchanger, the 30 feed temperature to the SWS is too cold, remaining NH remaining NH requiring an inordinately high amount of 20 stripping steam. H2S 10 Because there is no reboiler, this extra 15 stages 10 stages 5 stages 0 steam is all live steam injection, which 0 5 10 15 20 25 increases the effluent water volume dra- weight of steam on feed, % matically. Finally, and most troubling, is the routing of the flash gas vapours (primarily hydrocarbons) to the SRU feed stream. packing. Random packing has much lower high pH of the water to return to its gase- The flash tank is present to remove hydro- pressure drop, thus providing a higher ous form. Full dissolution can be achieved carbons from the feed to the SWS because tower capacity than a trayed vessel. Unfor- if the pH is in excess of 10 and sufficient they will naturally end up in the SWS over- tunately, a packed bed requires exception- steam is introduced to the regenerator or head stream feeding the SRU. But this ally good liquid and vapour distribution stripper bottoms. design sends these removed hydrocarbons within the tower and given the potential for Theoretically, there would be two strip- right back into the SRU feed. There is prac- fouling in sour water service, this option pers, one operating with a low pH for maxi- tically no reason to have the flash tank in may prove to be troublesome. To be safe, mum H2S removal and another operating this design. These hydrocarbons wreak

Sulphur Experts recommends that packing at high pH for maximum NH3 removal. havoc in the SRU as far as air demand (either random or structured) not be used Because most refineries do not have in the reaction furnace, side reactions to in sour water service. that luxury, the single stripper may need unwanted species and major coking on the The core question becomes how many to be modified to improve the potential sulphur catalyst. stripping trays or how high a packing height for success of removing these disparate Major capital outlay was required to and how many reflux trays are required to contaminants from the water. Because bring the unit up to ‘best practices’ guide- properly strip the sour water. Figure 4 pro- H2S is easier to strip than NH3, operations lines (installed a buffer tank, a reboiler and vides a graphical overview of the effect of should err on the side of improving the NH3 a feed/effluent exchanger) and the flash theoretical stripping stages and weight of removal so the target pH of the sour water gas was re-routed to a low pressure refin- steam to feed on the treated water H2S is slightly basic (around 7.5 to 8.5) to try ery absorber. Currently, the unit runs virtu- and NH3 content. Tray efficiencies have to improve the removal of the less volatile ally trouble-free, steam consumption has been loosely regarded as being some- ammonia fraction. been more than halved, SRU operations where between 30-45%, so around three A possible modification would be the are smooth and sulphur quality is excellent. trays per theoretical stage. There are addition of a strong base such as caustic. rate-based software simulators available Historically, the addition point has been No. 2: Incorrectly controlling the that can accurately predict sour water per- recommended at some point lower in the overhead and acid gas temperatures formance on an actual tray-by-tray basis, tower to reduce the likelihood of “bind- Heat is the primary component in effective allowing the design engineer to feel con- ing” the H2S before it has had a chance SWS operation. Heat is required for: fident in accurately determining the tray- to be stripped from the sour water. The l raising the water temperature from the to-steam ratio that will most economically ideal location of addition may even be in feed temperature to the boiling point and efficiently treat the sour water. the sour water feed itself, but that is best (reboiler temperature); sensible heat load; The pH of the sour water plays a very decided upon with rigorous rate-based l providing the temperature for the reac- significant role in the ability of the steam modelling for any particular application. tion of the ionic salts back into pure to strip the H2S and NH3. Because H2S is Associated with the addition of the caus- components; a weak acid in solution, it remains dissoci- tic is the need for an accurate means of l providing the heat to transfer the pure ated under alkaline conditions and is diffi- measuring the water pH in both the sour components from the liquid to the cult to strip from the water. If the pH is low water feed and effluent. Any excess addi- vapour phase; (<5.5) it returns to its gaseous form much tion of caustic can be detrimental and l providing a diluent environment by low- more readily and it is possible to remove result in caustic deposition, binding of ering the partial pressure of the stripped almost all of the H2S from the water. NH3 H2S and poor stripped water performance gases by providing excess steam vapour is basic in nature, so it would require a in the de-salter as emulsion formation is (produces the reflux flow).

4 www.sulphurmagazine.com Sulphur 363 | March - April 2016 COMMON MISTAKES IN SWS

Fig 5: Improperly designed sour water system

flash gas routed to SRU

sour gas to SRU

no feed effluent sour water feed sources exchanger sour water stripper reflux accumulator

flash drum no buffer tank

HC drain

steam no reboiler effluent stream

Without sufficient heat, the stripping of Fig 6: Ammonium salt sublimation

H2S and NH3 will not occur. In a well operated and designed sour water stripper there is always sufficient heat available in NH3 - CO2 plug the column for the final stripping of H2S in cold SWS AG line and NH3 to occur. There are three temperature effects in the overhead system that the SWS operator should be aware of: l ammonium salt sublimation; l corrosion due to high salt content in the reflux water; l high temperature polymerisation.

Ammonium salt sublimation lar basis. It is standard industry practice SRU which has an adverse effect on Ammonium carbonate and bicarbonate for these lines to be insulated and steam its operation. Salt content in the reflux sublime in the temperature range of 55 traced but steam jacketing is preferred. system is SWS specific. With good test to 75°C (130 to 167°F). When SWS over- data a safe operational temperature can head gas is cooled too much, salts precipi- Corrosion due to high salt content in the be set. tate and foul instruments, control valves reflux water The pump shown in Fig. 7 is from the and lines. This has been experienced on Most metallurgy is not rated for the high pumparound reflux of the first stage of numerous sites throughout the industry, salt contents (>35 wt-%) that can be a two stage stripper unit. The highly cor- some typical examples of this are shown in found in reflux water if the temperature is roded stainless steel impeller was found

Fig. 6. Sulphur Experts recommends a min- not maintained (Fig. 6). As H2S and NH3 only six months after the unit was com- imum temperature of 85°C to prevent foul- are more volatile than H2O, operating the missioned along with multiple other leaks ing of the system due to salt deposition. overhead system at a higher temperature in the pumparound system. The pumpa- Checking the instruments and overhead will decrease the salt content in the reflux round was operating at 59°C. Simulation lines to the sulphur recovery unit (SRU) water. This, unfortunately, increases the revealed that the ammonium salt content for cold spots should be done on a regu- water content of the SWAG gas to the in the reflux was at 35 wt-%; subsequent

Sulphur 363 | March - April 2016 www.sulphurmagazine.com 5 COMMON MISTAKES IN SWS

Fig 7: Reflux pump corrosion due to Dilution Fig 8: A low-flow sour water system elevated salt content Dilution has the following negative impacts: with high hydrocarbon levels l causes poor energy efficiency in the SWS due to unnecessary processing of inappropriate waters l increases the cost of downstream treatment and disposal due to greater treated water volumes l uses SWS capacity unnecessarily, which may affect plant flexibility Common sources of SWS water dilution include: l direct steam injection: this traditional (low capital) design approach should not be used because it increases the effluent water quantity by 10 to 20%; l routing uncontaminated or low contami- lab analysis revealed 38 wt-% of NH4HS in nation streams to SWS (streams feed- the pumparound. ing the stripper should be tested for

After extensive simulation study the H2S, NH3 and phenols); best solution (which was later imple- l dumping of other (non-sour) water mented) was to take the pumparound out streams into the SWS system. of service and utilise a water wash in the top of the column to keep the stripper top Segregation of phenolic water temperature at a reasonable level (~85°C). Phenolic water primarily comes from refinery cracking units such as cokers or FCCs. High temperature polymerisation It is important to understand that only a At the commissioning of a Middle Steam tracing/jacketing for winterisation small fraction of phenols in water will be Eastern refinery, there was a significant or fouling prevention should not exceed removed in a SWS. One African refinery amount of bulk heavy diesel fraction hydro- 150°C as this increases polymerisation was off-specification on phenols for several carbon in the sour water. This led to foul- reactions which can result in fouling. years as a result of not been cognisant of ing of the feed/effluent exchanger within this. This is largely a result of the low phe- three months of start-up and reduced per- No. 3: Poorly managing the sour water nol volatility. A good simulation study of formance on the stripper. Poor water management is, unfortunately, this was published by Hatcher et al14. quite prevalent in the industry. Broadly, Most of the phenols can be removed No. 4: Poorly operating or designing the this falls into four categories: in the crude desalter unit, which is down- flash vessel and feed stabilisation tank l cross contamination; stream of the SWS. It is important to Good flash vessel operation and design l dilution; route all the phenolic effluent water to is vital. The flash vessel serves to remove l segregation of phenolic water; the desalter, as the phenols tend to parti- the light hydrocarbons and the bulk of the l bulk hydrocarbon ingress. tion into the oil phase, thus reducing their heavier liquid hydrocarbons. Without a phenol content in the effluent stream. If proper flash vessel the SWAG cannot be Cross contamination possible it is also recommended to use a safely sent to an SRU. Contamination of the SWS system with separate SWS for phenolic waters so that Preventing hydrocarbons from entering improper water streams needs to be the non-phenolic water can stay segre- the SWS will prevent hydrocarbon from avoided. There is no reason for cooling, gated from the phenolic waters. entering the sulphur plant (SRU). There are fire or ballast water in a SWS system, as several reasons why it is advantageous to the Ca/Mg hardness in these streams will Bulk Hydrocarbon Ingress minimise hydrocarbon in the SRU feed, the foul the reboiler and trays below the feed The best solution to minimising hydro- most important being: nozzle. Spent caustic or waste from an carbons in sour water feeds is to ensure l difficulties maintaining stable SWS (and alkylation unit should also not be sent to that the hydrocarbons are not in the water consequently SRU) operation; a SWS, as these streams contain strong in the first place. This is carried out by a l decreased capacity; bases or acids which will bind H2S or comprehensive and thorough evaluation of l lower efficiencies;

NH3, resulting in off specification stripped sour water generation points. It is impor- l potential catalyst deactivation and sul- water. It is critical that only “process” tant that all SWS feed streams are ana- phur quality issues due to soot forma- water streams be routed to the SWS. lysed, regardless of flow rate. An example tion in the downstream Claus reactors. Note that spent caustic could potentially of this is shown in Fig. 8, which shows a be used for caustic dosing, however the sample from a water stream which contrib- Hydrocarbons in the sour water feeding caustic strength must be quantified and uted less than 10% of the feed flow, but the stripper will also significantly increase dosing rates or PH controller tuning should was responsible for over 90% of the hydro- the fouling of stripper internals. The “black be adjusted accordingly. carbon contamination. shoe polish”, which is found on sour water

6 www.sulphurmagazine.com Sulphur 363 | March - April 2016 COMMON MISTAKES IN SWS

stripper internals, typically contains heavy Fig 9: Effect of hydrocarbons on reaction furnace air flow hydrocarbons at varying degrees. The flash vessel is a three phase separator; its purpose is to separate water, oil 100 250 and gas. This is achieved through pressure drop and residence time; the greater the 200% 200 pressure drop or greater the residence 75 time, the better the separation of the three CO2 CO2 CO2 CO2 CO2 phases. Flash vessel operation is there- 150 fore at its peak when the pressure in the 135% vessel is as low as possible and residence 50 124% 110% time maximised. The minimum recom- 100% 100

mended residence time is 20 minutes at % increase, flow air the normal operating level of 50-60%. The 25 lower the pressure, the more likely hydro- mol-% concentrations, gas feed 50 H S H S H S H S H S carbons will flash off, as pressure has a 2 2 2 2 2 direct effect on the vaporisation point of hydrocarbons. 0 0 no hydrocarbons 2% light 2% light 6% light 6% C1 to C6 The pressure is set by the destination hydrocarbons hydrocarbons hydrocarbons hydrocarbons pressure of the flash gases. These gases and aromatics are normally sent to flare, incineration, or a low pressure fuel gas amine absorber. Under no circumstances should flash gas be is a more costly option but it will signifi- water acid gas affecting the downstream routed to the SRU, as the flash gas will have cantly reduce the serious odour problems sulphur recovery process. a continuous fluctuation in both flow and of SWS feed water. Hydrocarbons composition. Figure 9 presents a graphic Similar to the flash vessel, this stabili- Hydrocarbons in water streams can be pre- visual of the potential effect of hydrocarbon sation tank is normally operated 50% full. sent essentially in three forms: load on reaction furnace operation. With The correct level is however, always a com- l free hydrocarbons; excess heavy-end hydrocarbons the required promise between the various functions: l soluble hydrocarbons; air flow for combustion can double. feed stabilisation, free storage capacity l emulsified hydrocarbons. If the flash vessel uses weirs, they will and separation. This tank must be partly typically be set at a height of 50-60% of empty, to allow for upsets of the stripper Free hydrocarbons the vessel. The water level should be main- which can last hours or significantly longer. These will not interact with the bulk water tained at 7-8 cm below the weir height, On the other hand, a longer residence time and will tend to separate within a few allowing liquid hydrocarbons to then flow will improve hydrocarbon/solids separa- minutes in the flash vessel. Free hydro- over into the oil side of the weir. When tion and most importantly will stabilise the carbons are normally observed by the for- both the size of the tank and liquid level SWS feed composition and flow. mation of a top hydrocarbon layer above are set, then the only option to increase Along with the height of the liquid level, the water phase (or below depending on residence time is to reduce the water flow the location of the feed and discharge water the density difference). The levels of free to the vessel by critically evaluating all lines play an important part in the stabilisa- hydrocarbons can vary from 100 ppmw to streams feeding this vessel. tion role. The inlet and outlet nozzles should percentage levels. Their separation effi- One of the prevalent causes of SWS be located at opposite ends of the vessel, ciency is calculated via Stokes Law, which unit upsets is from large fluctuations in so as to minimise potential bypassing of has a large effect from the droplet diam- the composition and quantity of the sour contaminants. The outlet nozzle is often eter (Figure 10). Viscosity and density dif- process water. These fluctuations are 600 mm from the bottom of the tank so ference between the phases also plays a inherent to refinery operation and can be that precipitated solids or heavy oils are not lesser role, with lower viscosities improv- prevented by a properly sized SWS feed pumped out of the tank along with the sour ing separation velocity. Generally, this indi- stabilisation/buffer tank, with the water water. The buffer tank should be designed cates some benefit from running at slightly feed on one side of the vessel and the exit with a bypass to accommodate cleaning. higher temperatures as the fluid viscosi- on the other. ties decrease at higher temperatures. The stabilisation/buffer tank also No. 5: Inadequate removal of solids and Soluble hydrocarbons serves to partially remove suspended sol- liquid hydrocarbons All hydrocarbons will have a certain solubil- ids and liquid hydrocarbons. It is essential Poor filtration of solids and inferior liquid ity in water phases. The extent of hydro- that the buffer tank has skimming facili- hydrocarbon removal can result in foul- carbon solubility in water will depend on ties installed to remove these hydrocar- ing and corrosion problems of the SWS the pH of the water, water pressure, tem- bons. The buffer tank can be designed unit, which then leads to poor reliability perature and the type of hydrocarbon. It with a gasoil layer floating on the top, as a and decreased run lengths between shut- is impossible to observe dissolved hydro- blanket, to avoid smell problems. A better downs. Additionally, hydrocarbons that are carbon in a water phase as it is indistin- option is to use an internal floating roof not separated at the source of the feed guishable from pure water. In general, with hydrocarbon skimming facilities. This sour water can be present in the sour the solubility of hydrocarbon in water can

Sulphur 363 | March - April 2016 www.sulphurmagazine.com 7 COMMON MISTAKES IN SWS

Fig 10: Relationship between hydrocarbon droplet diameter & separation time surfaces leading to reduced flows and under-deposit corrosion. Most refineries use stripped sour water Stokes Law: where: as desalter wash water, particularly in FCC V = separation velocity refineries to remove the phenols from the g = gravitational force stripped water. The presence of solids 2 µ = viscosity continuous phase (water) will enhance emulsification, impacting the V = gd (ρa - ρb) ρ = density of solvent phase effectiveness of water and crude separa- 18µ a ρb = density of liquid contaminant tion in the desalter unit. This can lead to d = diameter contaminant droplet increased salts in treated crude, generating higher corrosion rates in the crude Droplet diameter, microns Time unit overhead. Many crude unit corrosion 160 30 min problems, desalter upsets and increased 106 1 h water + diesel-like hydrocarbon additive usage can be tied to improperly 75 2 h at the discharge of a stripped water. 43 6 h centrifugal pump Many solids are present at diameters 22 24 h less than the visual acuity of the human 16 48 h eye (<40 microns) and they are not 8 168 h detected until they precipitate out of the solution en masse (Fig. 12). These are the types of solids that can really stabilise a foaming condition, and there is a very good range from a few ppm to a few hundred to about 500 microns. Micro-emulsions chance that these low micron solids and ppm. The solubility of hydrocarbon in sour are the most stable emulsion type and can the larger visible solids will settle in any water has a direct relationship with the pH; take weeks to naturally separate. Micro- stabilisation tank, so it is generally recom- the higher the pH, the higher the solubility. emulsions are typically found when droplet mended to include tank cleaning during sizes are less than 10 microns. any turnaround situation. Leaving exces- Emulsified hydrocarbon sive solids in the stabilisation tank can Under normal conditions, hydrocarbons Suspended solids lead to the eventual transfer of these sol- will be either free or dissolved in a water Suspended solids in the sour water feed ids out of the tank with the process water phase. However, when conditions are are fairly common, especially in plants if they are allowed to rise to the level of the conducive (including the presence of sur- associated with coker units. To some outlet nozzle on the tank. factants and energy), the hydrocarbon con- extent these solids will settle in the taminants can form very small droplets in upstream feed stabilisation tanks (also Possible remedies for the conditioning of the water phase (Fig. 11). These droplets undesirable), however, a considerable por- sour water are stabilised by molecular surfactants tion can be present in the effluent. The Filtration is the basic technology for remov- (similar to soaps or detergents) and also effects of suspended solids can be some- ing suspended matter from the sour water. by small size suspended solids. Emulsion what similar to hydrocarbons, as they will For the removal of emulsified hydrocar- droplet sizes can range from a few microns stabilise foaming and deposit on metal bons, the technology of choice is a coa-

Fig 11: Water and oil micro-emulsion Fig 12: Solids precipitating out of sour water after 12 hours

8 www.sulphurmagazine.com Sulphur 363 | March - April 2016 COMMON MISTAKES IN SWS

lescer. Coalescence is the recombination Fig 13: Optimal filtering and coalescing of sour water of two or more small liquid droplets to produce a single entity larger in size. A large stabilisation/buffer tank could sour gas to SRU be used to separate hydrocarbons and suspended solids from the various sour water 3-phase separator streams. However, this is quite costly. A buffer tank rarely has sufficient residence sour water off gas flare stripper or fuel gas time to accommodate effective separation of fine particulate and micro-emulsions (10 microns and smaller). It is therefore recommended to use filters and coalescers. Due to the particle size and the high stripped sour water fouling properties of emulsified hydrocar- hydrocarbons bons in sour water streams, only dispos- able microfiber-based coalescers are able to provide proper emulsion separation. sour water Other systems such as inclined plates and feed fibre mesh are not effective. stabilisation tank Suspended solids removal upstream of the hydrocarbon coalescer is manda- tory. Particulate removal will protect the solids separation stage liquids separation stage coalescer elements and also destabilise the emulsion, significantly improving overall system efficiency. The particle filter Fig 14: Fouling in an SWS tower and liquid coalescer combination system should always be installed downstream of the sour water charge pump and upstream of the heat exchanger. This configuration is illustrated in Figure 13 and the effectiveness of such an arrangement is shown in Fig. 15. Figure 14 presents the deposition in a packed SWS caused by ineffective upstream solids removal. No. 6: Lack of a detailed sour water analysis The design specifications of a SWS often only list the H2S and NH3 content of the combined feed. The possible presence of other components is very rarely mentioned. These other contaminants can create significant problems because they could: l bind H2S to the water and reduce its by addition of a strong base, normally from FCC units, cokers and thermal tendency to be stripped; caustic, to neutralise the strong acids. cracking units. Preferably this process l bind NH3 to the water and reduce its l Calcium and magnesium can be pre- water should be segregated in phenolic tendency to be stripped; sent if hard-water has been used as and non-phenolic water. Phenols are not l plug up the trays or packing or scale on process water. It is also possible that properly removed in a SWS and there- hot surfaces; fire water or cooling water has been dis- fore the phenolic water effluent should l lead to foaming conditions in the stripper; charged to the SWS unit. As a result, be sent to the crude desalter where the l affect the performance of the down- calcium and magnesium carbonates phenols are extracted to the crude. stream bio-treaters. will deposit as scale in the reboiler. l Nitrogen components such amines, l Elemental sulphur or polysulphides filming corrosion inhibitors or HCN are Common “other” sour contaminants are are normally caused by air ingress to very poorly removed in a SWS. Often the listed below: the process water system. H2S will be stripped effluent of the SWS is only ana- l Sulphuric acid, hydrofluoric acid, formic oxidised to sulphur and polysulphides. lysed for NH3 and therefore these other

acid and other acids will bind NH3 in This sulphur will deposit as a scale on nitrogen components are missed. One such a strong way that it will be almost the bottom trays of the stripper and in of the important environmental goals of

impossible to strip. The NH3 can be the feed/effluent exchanger. the SWS is to remove as much of the liberated and subsequently stripped l Phenols are present in the process water nitrogen components as possible.

Sulphur 363 | March - April 2016 www.sulphurmagazine.com 9 COMMON MISTAKES IN SWS

Fig 15: Photograph of coalescer effectiveness in sour water service

filtered sour water feed recovered hydrocarbon HYDROCARBON dissolved, emulsified and free dissolved,

sour water feed filtered and coalesced sour water feed

Fig 16: Relative corrosion resistance for test materials in ammonium bisulphide No. 7: Neglecting the sour water environments9 stripper metallurgy The presence of ammonium bisulphide in Alloy C-276 sour water systems where both ammonia Alloy AL-6XN and hydrogen sulphide are present is the Alloy 2507 main driving force for corrosion. Ammo- Alloy 625 nium bisulphide corrosion appears to be enhanced when flow rates are increased Alloy 825 and also contributes to under-deposit Alloy 20cB-3 attack. Flow-enhanced corrosion occurs Alloy 600 at impingement points or after flow dis- Alloy 800 least resistant turbances. The problem with corrosion in most resistant Alloy 2205 sour water strippers is that the corrosion 316 SS has been historically hard to predict and 304 SS most industry guidelines have been based 410 SS on collected field experience with existing Alloy 400 metallurgies. More recently, work has been Carbon Steel done to build tools that will better predict sour water corrosion. The following factors have been found l Surfactants will certainly be present in to the sulphur and hydrocarbon content to contribute to corrosion in sour water the SWS feed, as they are removed by of the acid off-gas going to the SRU. stripping systems: the various refinery wash-water systems. The overall design of the SWS and the l Ammonium bisulphide Analysis of these trace components is SRU needs to allow for the additional m Increasing concentrations result in close-to impossible. As a consequence, air requirement for the SRU. increased corrosion the SWS needs to be designed with a l Benzene, toluene, ethyl benzene and m Some texts indicate a threshold safety margin to allow for foaming upsets. xylene (BTEX) will also be present in the level of 35 wt-% l Mercaptans may also be present in the SWS feed and removed in the stripper. m Corrosion rates increase with water SWS feed, and will be removed in the BTEX compounds are well known to be det- velocity stripper. As a result, they will contribute rimental to the life of catalyst in the SRU. l Hydrogen sulphide partial pressure

11 www.sulphurmagazine.com Sulphur 363 | March - April 2016 COMMON MISTAKES IN SWS

Table 2: Recommended metallurgy in sour water strippers

Location Minimum metallurgy Notes Sour water flash vessel Carbon steel with 6 mm corrosion allowance Feed pump 300 series stainless steel internals Feed / effluent exchanger Carbon steel shell with 6 mm C.A. AISI 316(L) SS or Incoloy 825 tubes Stripping column Carbon steel shell with 6mm C.A. 400 series metallurgy not sufficient Trays are 316(L) SS Effluent pump Carbon steel casing and internals Overhead cooler Titanium or Avesta 254 tube bundle; headers can be 316(L) SS Overhead accumulator Carbon steel with 6 mm C.A. It is important to Control reflux temperature well to

maintain an acceptable level of NH4SH Reflux pump 316(L) SS casing and internals Piping Most piping can be carbon steel with 3 mm C.A. Piping in the overhead section should have a more

robust 6 mm C.A. due to high NH4SH levels General If cyanides are present at ≥30 ppm then HIC resistant steel should be selected (cyanides are usually present in the sour water from FCC units)

m Corrosion rates increased with an minutes residence time; Claus SRU reaction furnace”, Sulphur Recov- ery textbook, published by Sulphur Experts increase in H2S partial pressure; l a buffer tank with a minimum 24 hour accentuated by higher velocities residence time at 50% full; (2005-2012). and higher ammonium bisulphide l a filter followed by a coalescer for sol- 6. Engel D.B.: “Filtration and separation tech- concentrations ids and hydrocarbon removal; nologies in sulphur recovery”, Chemical Engi- m Effect was far more extreme for the l a feed/effluent exchanger to heat up neering Magazine (April 2013). least corrosion-resistant materials the feed stream and reduce the reboiler 7. Kister, H.Z., Mathias P.M., Steinmeyer D E., (carbon steel, Monel 400 and Type load; Penney W R., Crocker B B., and Fair J.R.: 410 SS) – Fig. 16 l some consideration to segregating the “Equipment for distillation, gas absorption, phase dispersion and phase separation”, l Temperature ammonia fraction from the SRU feed “Perry’s Chemical Engineers’ Handbook”, m As expected, an increase in temper- stream (two-stage stripping); 8th Ed., Section 14, McGraw-Hill, New York ature increased corrosion rates l a reboiler (with the potential for live (2008). steam injection; a last resort as “dilu- 8. Horvath R.J., Lagad V.V., Srinivasav S., Kane Table 2 provides a quick review of recom- tion should not be the solution to pollu- R.D.: “Prediction and assessment of ammo- mended metallurgy. tion”); nium bisulfide corrosion under refinery sour l reflux loop to control SRU feed tempera- water service conditions – Part 2; ture; Conclusions 9. Tems R.D.: “Ammonium bisulfide corrosion l insulated and steam traced piping to in hydrocracker and refinery sour water ser- In summary, sour water strippers have the SRU; vice”, SAER-5942 Final Report on a Joint been designed and operated from sim- l a detailed feed water analysis; Industry Program (JIP) ple systems with no buffer tank, minimal l the correct metallurgy for the location in 10. “HCN and phenol in a refinery sour water hydrocarbon removal, no filters, towers the system. n stripper”, The Contactor, Optimised Gas with few trays and live steam injection Treating Inc., Volume 7, Issue 11, (Nov to deluxe systems with full pre-treatment References: 2013). stages (including flash tank, buffer tank, 1. Weiland R.H. and Hatcher N.A.: “Sour water 11. Spooner B., Sheilan M., van Hoorn E., Engel coalescer and filters) and segregated H2S strippers exposed”, LRGCC (2012) D., le Grange P., Derakhshan F.: “Reducing hydrocarbons in sour water stripper acid stripping and NH3 stripping towers. 2. The sources, chemistry, fate and effects of Ultimately, sour water systems should ammonia in aquatic environments, American gas”, LRGCC (Feb 2014). be designed to minimise operating prob- Petroleum Institute (1981). 12. Armstrong T., Scott B., Gardner A.: “Sour lems, maximise on-line factor and opti- 3. Lieberman N.: “Sour water strippers: Design water stripping; Today’s Refinery, (June mise the SRU feed gas quality. In order and operation”, PTQ (Q2 2013). 1996). to accomplish this the system should be 4. Van Hoorn E: “The basics of sour water 13. Kister H.: “Distillation operation”; pp327.; designed with: stripping, Amine Processing Textbook”, pub- McGraw Hill, New York (1990). l a flash drum with three-phase separa- lished by Sulphur Experts (2002-2012). 14. Hatcher, N. A., Jones, C. E., and Weiland, R. tion capabilities and a minimum of 20 5. Klint B. “Hydrocarbon destruction in the H.: “Sour water stripping”.

Sulphur 363 | March - April 2016 www.sulphurmagazine.com 11