Sour Water Stripping Systems

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Design of Sour Water Stripping System CONFERENCE PAPER · FEBRUARY 2009

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Jed Bellen Hyundai Engineering and Construction Co. Ltd. 7

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Design of Sour Water Stripping System Jed M. Bellen rd  Fluor Daniel Inc. Philippines, 3  Floor Asian Star Building 2402 – 2404 ASEAN Drive, Filinvest Corporate City, Alabang Muntinlupa City 1781 Philippines Telephone Number: (632) 8504451 Email: [email protected]  Abstract:

Among the vital units in a refinery is the Sulfur Recovery Unit, where elemental sulphur is recovered from gaseous hydrogen sulphide. Part of the Sulfur Recovery Unit is the Sour Water Stripping Section which would treat sour water coming from various sources around the refinery. Sour water is basically waste water which contains H2S and NH3  and sometimes phenol which can be treated by stripping in a Sour Water Stripper to remove the H2S and NH3 content (or phenol) so that the water can be reused, further treated or discarded to sewerage if it met the required quality. In this paper, the general approach to the design of sour water stripping section is described which involves process simulation, design and operating conditions map  preparation, material selection diagram preparation, preparation, flash drum, feed tank and stripper sizing, tray and heat exchanger rating, hydraulic calculations and pump design. As sour water treatment is very important in every refinery, it is therefore desirable to come up with an a n optimal design of sour water stripping systems. Key words:  Sulfur Recovery Unit, Sour Water, Sour Water Stripper, Refinery,

Optimal Design Introduction

Among the most vital units in a refinery is the Sulfur Recovery Unit where elemental sulphur is recovered from gaseous hydrogen sulphide. Part of the Sulfur Recovery Unit is the Sour Water Stripping Section which would treat sour water coming from various sources around the refinery.

Sour water is produced in Atmospheric Crude Columns and Vacuum Crude Towers when stripping steam is condensed and removed by overhead condensing systems. It is also produced in Vacuum Crude Towers from equipments such as ejectors and barometric condensers which are designed to maintain vacuum inside the column. Steam injection to vacuum heater is another source of sour water in Vacuum Distillation Unit. In Thermal and Catalytic Cracking Units, sour water is produced as condensates from steam used in injection, stripping and aeration. Hydrotreater wash water is also another major source of sour water. Heavy viscous feeds which are rich in sulphur produce high H 2S concentrations when hydrogenated while ammonia (NH 3) is produced from hydrogenation of organic nitrogen compounds. If more sulphur will be removed to meet the more stringent environmental requirements then there may be more nitrogen converted to ammonia which would accumulate in wash water. Hydrogen sulphide and ammonia concentrations are highest in sour water coming from Hydrodesulfurization (HDS) Units and Fluid Catalytic Cracking (FCC) Units. In addition to this, phenols are  produced from reactions between steam and cyclic hydrocarbons. Sour water with extremely high concentration of phenols would come from the FCC Units. Sour water systems are garbage disposals or toilets of refineries. It does not receive constant feed rate and composition. Any water soluble waste produced in the refinery, either continuously, intermittently or in slug will be disposed into this system (Armstrong, et al., 1996). Process Description

The sour water from various sources in the refinery is coursed to the Sour Water Stripping Unit to strip the water of its sour content like H 2S, NH3 and phenol. The sour water is first fed to a Flash Drum where hydrocarbon vapours and liquids are removed. The vapours are flashed through a pressure controlled vent connected to a low pressure system like sour water system flare knock out drum. The collected hydrocarbons are pumped to a slop system where it could be reprocessed.

The sour water from the flash drum is then fed to the Feed Stabilization Tank. This stabilization tank is used to increase the residence time of the sour water for longer mixing and homogenization of the feed composition and for further removal of hydrocarbons. If this is not done and it happens that sour water composition changes significantly, the stripper will not operate properly and it could result to inconsistency in product specification or steam wastage by overstripping leading to the worst composition. Furthermore, environmental regulations might require vent gases to be treated for hydrocarbon or H2S (Armstrong et al., 1996). The sour water from the tank is sent to a heat exchanger where it is pre-heated through heat exchange with the stripped water. Then it flows to the Sour Water Stripper where some of it is flashed through a reduction in the pressure across a control valve. There are varieties of sour water stripping methods employed. Most of them involve the flow of sour water through trays or packings in a column while the stripping steam or gas flowing upwards removes H 2S and sometimes NH3 (Beychock, 1967).  The steam that could be used maybe live steam or steam produced from the reboiler. The reboiler boils sour water at the minimum tower operating pressure by utilizing the latent heat of low pressure steam as the heating medium. This has the advantage of no additional water load in the stripper and the steam condensate can be recovered and returned to the boiler house. The H 2S, NH3  and steam rising to the tower cooling section are cooled by pumped-around sour water in the middle of the 0

tower. The temperature is maintained at 180 F. The reason for this is that if the temperature would be well above this value, there could be carry over of condensates into the overhead due to high vapour flow. On the other hand, if the temperature is well below this value there could be no sufficient removal of H2S in the sour water. The overhead gases flow by pressure control to a lower pressure system like the Sour Water Gas Flare Knock Out Drum or Sulphur Recovery Unit. The stripped water collected at the tower bottom flows through a heat exchanger where it is cooled via heat exchange with sour water feed to the tower. It is then pumped off-site on level control for further processing. It could be sent to a crude unit desalter; a liquid/liquid extractor that transfer ninety-five percent (95%) of phenols in water to atmospheric

crude feed. Phenol removal in sour water stripper is minimal (~ 10% reduction) but if it is sent to the desalter, phenol content is reduced substantially. The Process Flow Diagram is shown in Figure 1.

G as to Flare K.O. Drum

Vap or to Flare K.O. Drum

G as to Sulfur Recovery Unit Drum

PC

Sour Water Feed  TIC PIC

LIC

FLASH DRUM

SOUR WA TER STRIPPING  TOWER

Hydrocarbon Liquids

LIC

FIC

FIC

LP STEAM COND.

FEED STABILIZATION  TANK FIC

STRIPPED WATER TO DESALTER

Figure 1. The Process Flow Diagram of Sour Water Stripping Systems

Sour Water Chemistry

Sour water is an aqueous solution of NH 3 and H2S which may contain as much as 10,000 ppm of H 2S. The NH3 to H2S ratio ranges from 1 to 2 usually 1.5 as the average. The alkalinity ranges from pH 7.8 to pH 9.3. The NH 3 and H2S are present in aqueous solution as NH 4SH which is the salt of a weak base (NH 4OH) and a weak

acid (H2S).

This salt would undergo hydrolysis in solution to form back H 2S and

 NH3. The hydrolysis reaction could be represented by Figure 2.

NH3 P.P.

(Vap or Phase) (Aqueous Phase)

H2S P.P.

NH4++SH- < - - > NH3 +H2S

Figure 2. Overall Equilibrium in Sour Water

For a detailed discussion on sour water chemistry, Ref. 1 ca n be consulted. It provides a discussion on the pH of sour water and vapour pressure of NH 3  and H2S above aqueous NH4SH solutions. It also provides useful graphs showing the correlation of concentration of NH3  (in ppm) in aqueous solution versus the pH of the solution; temperature versus correlation factor for partial pressure of H2S over aqueous solutions of NH3 and H2S; and Henry’s Law coefficient for pure water versus the temperature and vapour pressures of H 2S and NH3 over the aqueous solutions of H 2S 0

0

0

0

0

and NH3  at the temperatures of 200 F, 210 F, 220 F, 225 F and 230 F .These graphs were based on the study conducted by Van Krevelin, et al. Process Simulation

Recent simulation software like HYSYS or PRO/II has “drag and drop” features that make simulation relatively easy. Other software like Aspen Plus, ProMax, TSWEET and PROSIM can also be used. Simulating Sour Water Stripping Systems would have direct convergence since both mass and heat can flow in and out of the system. Since the sour water that would be fed into the flash drum is at saturated conditions; then, in the flash drum, it is expected that there would be liquid-vapour separation, though the flashed vapour may be minimal. Another flash drum could represent the feed stabilization tank but, in here, it is expected that liquid water comes out of the vessel. The sour water would then pass through the Feed-Bottoms Heat 0

Exchanger to preheat the sour water to 180 F by heat exchange with the stripped sour

water. The preheated Feed Sour water is fed to the Sour Water Stripper. The Feed Tray and the Number of Trays are determined through adjustments so that the Stripped Water specified quality will be met. The number of trays that is obtained here is the theoretical number of trays. Since the stripper has pumparound, the steam going in and out of the condenser can be represented by pseudo-streams for tractable stream flow rates and properties. If a kettle reboiler is used, the fraction of liquid to be vaporized needs to be specified. The H 2S vapour coming out of the stripper could be sent to the Sulfur Recovery Unit to recover the sulfur. Finally, the stripped sour water coming out of the Stripper bottom is cooled through heat exchange with the feed. In PRO/II there are two (2) methods for use in modelling the system equilibrium. These are SOUR and GPSWAT methods. The SOUR method is based on Sour Water Equilibrium (SWEQ) model developed by Grant Wilson for the American Petroleum Institute (API) and the Environmental Protection Agency (EPA). This method contains four components namely H 2O, NH3, H2S and CO2. The correlation is  based on the components partial pressures. Similarly, the GPSWAT method was developed by Grant Wilson for the GPA. This method contains nineteen components, including H2O, NH3, H 2S and CO2. This is a rigorous model of the reactive equilibria in the system. Both these methods can be used for rigorous Vapor-Liquid-Liquid Equilibrium (VLLE) calculations and can be used with petroleum fractions. The keyword input for thermodynamic data is provided in the Appendix 1 (Lecture of Dr. Jungho Cho). See Figure 3 for the sample HYSYS Simulation of Sour Water Stripping System.

Figure 3. HYSYS Simulation of Sour Water Stripping Systems

Determination of Design and Operating Conditions

The design and operating conditions of the flash drum, feed tank, sour water stripper and internals, heat exchangers and pumps need to be specified to help the equipment engineer determine the equipment’s thickness and all the other requirements specified in the applicable code. Also the pipeline design and operating conditions need to be determined to help the piping engineer in computing for the pipe thickness and other various requirements by applicable code. See Figure 4 for the Design and Operating Conditions Map.

Legend: DP = Design Pressure DT = Design Temperature OP = Ope rating Pressure OT = Operating Temp erature

Vapour to Flare K.O. Drum

DP=Design Battery Limit Pressure DT=O T + 500F OP=Normal Battery Limit Pressure OT=Feed Temp.

Sour Water Feed

G as to Flare K.O. Drum G as to Sulfur Recovery Unit Drum

PC

DP=From Standa rd DT=O T + 50 0F OP=From Simulation OT= From Simulation

 TIC PIC

FLASH DRUM

LIC

DP=From Standa rd DT=O T +500F OP=Saturation Pressure OT=Feed Temp.

DP= Pump Shut-off DT=230 0F OP= Heat Ex. Outlet Pressure OT=180 0F

Hydrocarbon Liquids DP=Max. Suction DT= OT +500F OP=Pump Suction OT= Feed Temp .

SOUR WA TER STRIPPING  TOWER

DP=Pump Shut off/Full Vacuum DT=O T + 500F OP=ATM OT=Feed Temp.

LIC

LP STEAM

DP= From Std. DT=250 0F OP= 10 psig OT=200 0F

FIC

DP=Pump Shut-off DT= OT +500F OP=Pump Discharge minus DP ac ross the C ontrol Valve OT= Feed Temp .

FIC

COND.

FEED STABILIZATION  TANK

DP=Pump Shut-off DT=O T + 500F OP=Pump Discha rge OT=Fee d Temp.

FIC

DP=Max. Suction DT=2500F OP= Shell Inlet Pressure OT=2000F

DP= Pump Shut-off (In & Out) DT=O T + 500F (In & Out) OP= Tube Inlet Pressure (In) =Inlet Pressure – ΔP (Out) OT=Feed Temp (In) =Outlet Temp (Out)

Figure 4. Design and Operating Conditions Map

Material Selection

Basically, the material that can be used for the vessels, tanks, stripper, pumps, heat exchangers and piping is carbon steel. Higher grade killed carbon steel can also  be used. See the Material Selection Diagram depicted in Figure 5.

STRIPPED WATER TO DESALTER

Vap or to Flare K.O. Drum

Gas to Flare K.O. Drum

Mat’l: CS C A: 1/8 in

G as to Sulfur Recovery Unit Drum

PC

Sour Water Feed

Mat’l: CS with Ti  TIC

Mat’l: CS C A: 1/8 in

Mat’l: CS CA : 1/8 in

PIC

FLASH DRUM

LIC

Ma t’l: CS C A: 1/8 in

Ma t’l: CS C A: 1/8 in

Hydrocarbon Liquids

SOUR WA TER STRIPPING  TOWER

Mat’l: CS C A: 1/8 in

FIC

FIC LIC

LP STEAM COND.

FEED STABILIZATION  TANK FIC Mat’l: CS

Mat’l: CS C A: 1/8 in Mat’l: CS CA : 1/8 in Ma t’l: CS C A: 1/8 in

Legend: Mat’l = Material CA = Corrosion Allowance Figure 5. Material Selection Diagram Equipment Design Flash Drum

The sour water introduced to the drum contains minimal amount of oil which should be removed by flotation to protect the downstream equipment from fouling and foaming in the stripping column. Knowing that the oil is less dense than water, it would float above the water; and to achieve separation, a weir could be installed near the other end of the drum opposite the feed inlet. The oil would overflow from this weir and would be collected to the smaller chamber. See Figure 6. In this configuration, level is controlled to about three (3) inches from the top of the weir.

Mat’l: CS C A: 1/8 in

Stripped Water to Desalter

Figure 6. Flash Drum with Overflow Weir

Another way of collecting the oil is to install inside the flash drum a draw-off  box which would collect the oil overflowing into it. See Figure 7.

Figure 7. Flash Drum with Draw-off Box

Drawing off the oil is done when the chamber or the draw-off box is already full. The oil is then sent to the designated refinery sump. The designated residence time for the sour water inside the drum is usually twenty (20) minutes. The flash drum can be sized using the following steps as provided by Branan (2005): Step 1. Calculate the separation factor, S.F . 0.5

S .F . =

⎛   ⎞ W   L  ρ V 

⎜⎜ ⎟⎟ W V  ⎝  ρ  L ⎠

 

where: W  = liquid or vapour rate  ρ  =

density of liquid or vapor

Step 2. Look up for system constant, K  H . The Figure is provided by Branan (2005) in Ref. 1, Figure 1, page 132. Step 3. Calculate the maximum vapour velocity, U vapour max. U vapor max

⎡ ( ρ  −  ρ  ) ⎤ = K  H  ⎢  L V  ⎥ ⎣  ρ V  ⎦

0.5

Step 4. Calculate the required vapour flow area.

 AV min

=

QV  U vapor max

where: QV = vapour volumetric flow rate  AVmin = required vapour flow area

Step 5. Select the appropriate design surge time and calculate the full liquid volume. Step 6. When vessel is at full liquid volume:

 Atotalmin =

 Dmin

 AV min

0.2

= (4[ Atotal ]min / π )0.5

where: Dmin = minimum diameter  Step 7. Calculate the vessel length.

 L =

FLV 

⎛ π  ⎞ D 2 ⎜ ⎟ ⎝ 4 ⎠

where: FLV  = Full Liquid Volume  D = Dmin to the next largest 6 in

Step 8. If 5 <  L/D < 3, resize.

Feed Stabilization Tank Sizing

The sour water from the flash drum is directed to the feed tank. This tank could  be a fixed or a floating-roof type. It could be operated to about 60% full. About two (2) feet of hydrocarbons should be allowed to float above the sour water to reduce odour. For cone roof tanks, nitrogen blanketing is required to control odour and to  prevent the formation of explosive mixtures. The sour water is pumped on flow control to the Sour Water Stripper. The tank is sized using the volume equation for cylinder if the volume to be contained is known. The very important volume to consider is the tank’s working volume. Sour Water Stripper Design

There are two types of sour water stripper: a steam stripper and a reboiled stripper. The design configurations of these two are discussed in the forgoing  paragraphs. Steam Strippers

In this stripper, the stripping media used is steam. The operating condition 0

varies from 1 to 50 psig and from 100 to 270 F. The sour water may or may not be  pre-treated with mineral acid like H2SO4 or HCl before stripping (Beychock, 1967). A major portion of stripping steam is used in heating the sour water feed from 0

0

180 F to 230 F. The heat that is being utilized is the latent heat of the steam. A  portion of the stripping steam breaks the bond between H2O and H 2S and the bond  between H 2O and NH3. When these species dissolves in water, it evolves heat called the heat of solution. In order for those components to be removed from water, the same amount of heat must be supplied to the solution. The heat that is supplied comes from the latent heat of steam condensing across the trays in the tower. Some of the stripping steam condenses in the overhead condenser. The condensed steam which accumulates in the reflux drum is totally refluxed back to the top tray of the tower. The small amount of stripping steam remaining as vapour leaves the reflux drum, together with H2S and NH3 vapour.

Using this kind of stripper, however, would add steam condensate to the stripped water, thereby increasing the plant’s water e ffluent (Lieberman, 2003). CW Steam + H2S + NH3

Sour Water

Reflux

Steam

Stripped Water

Figure 8. Steam Stripper  Reboiled Stripper

The same amount of steam is required for this type of stripper as that of steam stripper. The advantage of using this type of stripper is that the steam condensate can  be recovered and recycled back to boilers. However, its main disadvantage is fouling in the reboiler wherein the causes are difficult to determine and control (Lieberman,

2003). In addition to that, reboiled strippers involve higher investment cost. Figure 9 shows the configuration of this type of stripper. Sour G as

 TIC

Sour Water FIC

Steam

Stripped Water

Figure 9. Reboiler Stripper

In sizing this stripper, tray rating is first performed using any available software. The tray type should be specified but sieve tray is commonly used. Basically, the size of the tray will depend on the maximum vapour and liquid load. The tray hole diameter is specified, ranging from 1/16 to 1 inch. Also the fractional hole areas is specified. For commercial sieve trays, the optimum value for fractional

hole area is from 0.08 to 0.12 (Kister, 1990). The downcomer width needs to be specified and the pressure drop across the tray is closely monitored. The height of the column would depend on tray spacing. Kister (1990) recommended a tray space, ranging from 8 to 36 inches, though 24 inches is most common for columns with diameter 4 feet and larger. The reason for this value is for a space sufficiently large that a worker can crawl freely between trays.

Equally important to consider in designing a stripper column is the removal of aromatic components in sour water because of environment requirements. To effect the efficient removal of aromatics, saltwater is added to the stripper feed because aromatics, like benzene, are less soluble in brine than in freshwater. However, brine is corrosive to the stripper.

 Heat Exchanger Feed-Bottoms Exchanger

The rating of this heat exchanger is much simpler as compared to rating reboilers. The rating could be done using software li ke HTRI. The most tedious part of this activity is finding the shell diameter and tube length. However, HTRI offers the Design Mode which can calculate the shell diameter and tube length. Upon knowing the shell diameter and tube length, the HTRI design mode is changed to rating mode, and those values are used as initial input for rating the heat exchanger. The  parameters, which are closely guarded, are shell side and tube side pressure drop, shell side and tube side velocity,

ρv2  and

overdesign. The Overdesign is defined as the

actual overall heat transfer coefficient divided by the design overall heat transfer coefficient. Its value must be greater than zero (0).  Reboiler

The types of reboiler which can be used are either the once-through thermosiphon reboiler or the kettle reboiler.

Once-through Thermosiphon Reboiler In a thermosiphon reboiler, the driving force to effect flow is the density difference between the reboiler feed line and the froth filled reboiler return line. The differential pressure driving force can be obtained from the values of the specific gravity of the liquid in the reboiler feed line, t he height of the liquid above the reboiler inlet, the mixed-phase specific gravity of the froth leaving the reboiler, and the height of the return line. The differential pressure is consumed by frictional losses in the reboiler, the inlet line, the outlet line and the nozzles. Figure 9 shows the configuration at the tower bottoms and another configuration is shown below.

BAFFLE SEAL PAN LP Steam

Stripped Water

Figure 10. Tower Bottoms Configuration for Once-Through Thermosiphon Reboiler

In Figure 10, all liquid from the bottom tray flows to the reboiler. No liquid from tower bottoms flows into it. The bottoms product came from the reboilers liquid effluent. Hence, the reboiler outlet temperature is equal to tower bottoms temperature (Lieberman, 2003). Kettle Reboiler Kettle reboilers are installed external to the tower as shown in Figure 11.

LP Steam

Stripped Water

Figure 11. Kettle Reboiler

It is important to note that the bottoms product level control only controls the liquid level in the product side of the reboiler and not the liquid level in the tower. The liquid level on the boiling side of heat exchanger is controlled by the overflow weir. The water that comes out of the tower would flow to the bottom of the reboiler shell. Once it entered the boiling side of the heat exchanger, it is partially vaporized. The top section of the reboiler separates the vapour and the liquid. The vapour flows  back to the tower via the riser or return line. The vapour becomes the stripping vapour or heat source. The overflow weir height must ensure that the tube bundle is submerged in the liquid. The liquid that flows over the weir becomes the bottoms  product (Lieberman, 2003). Another important thing affected by the reboiler operation is the liquid level in the tower. The liquid level in the tower is the sum of the nozzle exit loss of the liquid leaving the bottom of the tower, the liquid feed-line pressure drop, the shell-side exchanger pressure drop (including the effect of baffle height) and the vapour-line riser pressure drop (including the vapour outlet nozzle loss). It is important to note, however, that it is the elevation and not the static head pressure in the tower that drives the reboiler. This means that the pressure in the kettle is greater than the  pressure in the tower. Any increase in reboiler duty would correspond to an increase in liquid level at the bottom of the tower. If the liquid level at the bottom of the tower rise to the reboiler vapour return nozzle, the tower will flood but the duty will remain the same. Reboiler shell-side fouling may lead to tray flooding because it can cause  pressure drop build-up on the shell side of the reboiler.

The Pumparound

There are two ways to remove heat from a distillation tower. The first one is by introducing a top reflux and the second one is by using a circulating reflux called  pumparound. The hot liquid is drawn from the pumparound draw tray, cooled in a condenser or air fin cooler and returned to the tower at a higher elevation. It is best  practice if this pumparound return liquid enters the tray downcomer as shown in Figure 9. The purpose of pumparound is to cool and partially condense the upflowing vapors. The typical number of pumparound trays is a minimum of two (2) and a maximum of five (5). In the case of steam stripper (See Figure 8), it is employed to recover heat to a process stream that would otherwise be lost to the cooling water. Hence, this could lower the cooling water outlet temperature. It is best to keep the 0

cooling water outlet temperature below 125 F to retard water hardness deposition. Pumparound is also used to prevent top-tray flooding by decreasing the vapour temperature. In so doing, less vapour would reach the top tray resulting to lower vapour velocity and lower tray pressure differential. In this case the ability of the vapour to carry entrained liquid will be lessened and the height of the liquid in the downcomer will be reduced and tray flooding will be avoided. It should be noted that too much lowering of the vapour velocity can lead to tray weeping which is undesirable since it does not provide good liquid-vapour contact. Also if vapour velocity is too low, it may lead to the loss of the downcomer seal, causing vapour to  by-pass the trays via the downcomer. The temperature difference in the pumparound trays indicates that fractionation is taking place. The temperature difference is a measure of the amount of fractionation as expressed in the following equation:

ΔT=

temperature of liquid - temperature of vapour leaving a lower tray leaving a higher tray

In the equation above, the bigger the temperature difference, the more fractionation would take place across the trays (Lieberman, 2003).

Pump Design

The type of pump commonly used in this system is centrifugal pump. When designing a centrifugal pump the horsepower requirement needs to be determined. The handiest formula for horsepower is HP=GPM(ΔP)/1751(Eff) where: HP = Pump Horsepower GPM = Gallons per Minute

ΔP = Delivered Pressure Eff = Pump Efficiency Branan (2005) provided an approximate formula for pump effici ency as below: -4

-7

2

-4

2

Eff = 80 – 0.2855F + 3.78(10 )FG – 2.38(10 )FG  + 5.39(10 )F  – -7

2

6.39(10 )F G + 4(10

-10

2

2

)F G

where: F = developed head, ft G = Flow, GPM The preceding equation is applicable for F=50 to 30 feet and G = 100 to 1000 GPM. The result of the equation is within about 7% of the pump curves. For G < 100, a rough efficiency could be obtained by using the equation for 100 GPM. Another consideration in pump design is the provision for minimum flow. Minimum flow is needed to protect the pump from shut-off. At shut-off, all of the  pump’s horsepower turns into heat and it can vaporize the liquid and damage the  pump. The minimum flow is constant from discharge to suction. For preliminary estimation, assume that all the horsepower at blocked-in conditions turns into heat. 0

Thereafter, provide a minimum flow that could remove 15 F rise in the minimum flow stream temperature. It is also essential to ensure that the fluid flowing in the pump suction line is not vaporizing. Hence, the pressure along the line must not go below the fluid’s vapour pressure. The lowest pressure is at the impeller inlet where a sharp pressure lowering occurs. The impeller rapidly builds pressure and collapses the vapour  bubbles, causing cavitation and damage. To prevent this, a sufficient net positive suction head (NPSH) must be maintained. NPSH is the pressure available at the pump suction after vapour pressure is subtracted. In equation form:

 NPSH = Absolute – Vapor – Line + Difference Available Pressure, ft Pressure, ft Loss, ft in Elevation, ft As a rule, NPSH available must be greater than NPSH required. Maximum flow usually has higher NPSH than normal flow. For extremely low flows, NPSH could be higher. In choosing the pump, an economic balance between NPSH requirements and  pump speed need to be studied. A lower speed pump would require a lower NPSH and hence, lower vessel heights. A low speed pump will also be easy to maintain. On the other hand, a higher speed pump delivers the required head economically. The suction piping should be adequately sized. Normally, it is larger than pump suction nozzle. Its layout should also be kept simple. In here, the pressure should be kept below the vapour pressure of the fluid. To achieve this objective, Kern, as cited  by Branan (2005), provided the following rules of thumb: 1. The minimum liquid head above the drawoff nozzle should be greater than the exit nozzle resistance. To determine the liquid level, the following formula can  be used: 2

hL=u /g where: hL = Liquid Level Above Nozzle, ft u = Nozzle Velocity, ft/sec g = 32.2 ft/s

2

The equation is based on safety factor of 4 and a velocity head factor K of 0.5. 2. For a saturated liquid, the pipe should be vertical downward from draw-off nozzle and must be close to the nozzle as possible. This configuration will give the maximum static head above the horizontal portion of piping at the pump suction. A vortex breaker should also be provided for the draw-off nozzle. The following are guidelines for suction pipeline: 1. Layout the pipeline short and simple. 2. Avoid loop and pockets to prevent the accumulation of vapour or dirt. 3. Use an eccentric reducer with the flat side up to prevent trapping vapour as the larger suction line transition to the pump suction nozzle.

4. The following are acceptable ΔP/100 ft: Saturated Liquids = 0.05 to 0.5 psi/100 ft Subcooled liquids = 0.5 to 1.0 psi/100 ft

Conclusion

This paper explores on the underlying concepts used in designing an optimal sour water stripping systems. The sour water stripping process is described and its simulation using PRO/II and HYSYS software is presented. It also showcased the  preparation of the Design and Operating Conditions Map and the Material Selection Diagram. Discussions on the design considerations for sizing t he flash drum, tank and stripper and rating of trays and heat exchangers are also provided. Moreover, various configurations for those equipments are presented. Design considerations for  pumparound and pumps are also discussed with sufficient detail.

APPENDIX 1 Keyword Input for SOUR Method:

THERMODYNAMIC DATA METHOD KVAL (VLE) = SOUR, ENTH (L) = IDEAL, & ENTH (V) = SRKM, DENS (L) = IDEAL, & DENS (V) = SRKM

Keyword Input for GPSWATER Method:

THERMODYNAMIC DATA METHOD KVAL (VLE) = GPSWAT, ENTH (L) = IDEAL, & ENTH (V) = SRKM, DENS (L) = IDEAL, & DENS (V) = SRKM

Acknowledgment

The author would like to thank, Fluor Daniel Inc. Philippines through the Process Department Manager, Ma’am Corazon S. Almirez and the Former Department Manager, Ma’am Josephine B. Sabay for their unwavering support in this endeavour. I would also like to thank my Most Loved Mentor Ever, Ma’am Melody Lee M. Estrada for showing me how sweet sour water can be with the enormous learning that I had from her motherly mentoring. My gratitude also goes to Sir Raul L. Bicol, the indomitable process engineer, for sharing to me his vast refinery experiences and for  being the reviewer of this paper. I would also like to extend my gratitude to Jay R T. Adolacion, for reviewing and critiquing my paper. Finally, I would also like to thank Herbie Gino S. Vinluan and Marcial N. Barroga for driving me to bring out the best that I can be.

References

1. Beychock, Milton R. (1967) Aqueous Wastes from Petroleum and Petrochemical Plants, England: John Wiley and Sons Ltd. th

2. Branan, Carl (2005) Rules of Thumb for Chemical Engineers. 4  Ed. USA: Elsevier. 3. Kister, Henry Z. (1990) Distillation Operation. USA: McGraw-Hill. 4. Lieberman, Norman P. And Elizabeth T. Lieberman (2003) Working Guide nd 

to Process Equipment, 2  Ed. USA: McGraw-Hill. 5. http://www.cbi.com/services/sour-water-stripping-units.aspx 6. http://www.cheresources.com 7. http://www.hydrocarbonprocessing.com 8. http://www.insightengineers.com/articles/SourWaterStripping.pdf  9. http://www.jaeger.com/Brochure/steamstripping.pdf  10. http://www.koch-glitsch.com/koch/product_brochures/KGIMTP.pdf