Sru-presentation

Indian Oil Corporation Ltd Panipat Refinery Presentation on Sulphur Recovery SRU/ TGU: Process, Operation, Controls & best practices

SULPHUR RECOVERY UNIT

Objectives of the Training Program Familiar with process, chemistry for SRU. Discussion of operating variables.

Start-up/Shutdown and Emergency handling. Troubleshooting. Operational Safety. Experience Sharing including Case Studies/Q&As.

MAIN PRESENTATION: CONTENT AND SEQUENCE  INTRODUCTION  OBJECTIVE OF THE WORKSHOP  GENERAL GLOBAL PERSPECTIVE  DESCRIPTION OF THE PROCESS  CHEMICAL REACTIONS AND CATALYSTS  PROCESS VARIABLES  NORMAL PLANT OPERATIONS  TAIL GAS AND INCINERATOR  START UP  EMERGENCY HANDLING  TROUBLE SHOOTING  SULPHUR RECOVERY PROCESSES  OPERATIONS SAFETY/ HAZARDS

INTRODUCTION  Crude oils divided into "sweet" and "sour" crudes, depending on their sulfur content.  All crude oils contain some sulfur, ranging from over 5 weight percent to well below 0.1 weight percent.  Sulfur in crude oil presents a real challenge to the refiner because it is corrosive and malodorous, and because most product specifications severely limit the sulfur content in petroleum-derived fuels.  These sulfur compounds can ultimately end up as sulfur dioxide emissions once the petroleum fuels are burnt AND WILL ADD TO THE EMISSIONS.

INTRODUCTION-contd  Over the years the petroleum refining industry has developed a number of processes dedicated to the recovery of hydrogen sulfide and to convert it into elemental sulfur.  During this program, a detailed description of sulfur recovery fundamentals will be presented. The technologies discussed will include processes such as Claus units, and tail gas treating.

 Topics ranging from process chemistry and fundamentals through monitoring and troubleshooting of commercial operating units are intended to be covered.

SRU Block A typical “Sulphur Recovery Unit” complex consists of process units like:  Amine regeneration Unit  Sour Water Stripping Unit  Sulphur Recovery Unit  Tail Gas Treating Unit

(ARU) (SWS) (SRU) (TGTU)

Amine Regeneration Unit The purpose of this unit is to receive rich amine (containing a high amount of dissolved H2S) from upstream absorbers in PR & PREP, remove the H2S from it and return the lean amine (containing very low H2S) back to PR & PRE for further absorption. The H2S thus released is sent to Sulphur Recovery Unit. Sl No.

Absorber

Flow Rate (Kg/hr)

1

CDU LPG Absorber

4676

2

DCU LPG Absorber

10086

3

DCU FG Absorber

5452

4

DCU De-Ethanizer Gas Absorber

78851

5

DCU Light Naphtha Absorber

5512

6

DHDT HP Gas Absorber

130192

7

DHDT LP Gas Absorber

46886

8

HCU Recycle Gas Absorber

107781

9

HCU HP Amine Absorber

10

HCU LPG Absorber

11

HGU Off Gases

0 (Gas to be routed to DHDT LP Gas Absorber) 12907 0 (Gas to be routed to DHDT LP Gas Absorber)

Diagram of Amine Regeneration Unit REGENERATOR AIR CONDENSER

92 OC

RICH AMINE FROM UNITS

104 OC

40 OC

RICH/LEAN SOLVENT EXCH

CW 59 OC

LEAN SOLVENT TRIM COOLER 50 OC

LEAN SOLVENT AIR COOLER

72 OC

AMINE REGENERATOR COLUMN

RICH SOLVENT FLASH DRUM

59

ACID GAS 0.95 KG/CM2

TO SRU 55 OC

CW

OC

TO FLARE

REGENERATOR TRIM CONDENSER

REGENERATOR REFLUX DRUM

1.05 KG/CM2

REGENERATOR REFLUX PUMP 127 OC

RICH AMINE PUMP

LP STEAM REGENERATOR REBOILERS

AMINE FILTER

AMINE CIRCULATION TANK (785 M3)

REGENERATOR BOTTOMS PUMP

127 OC

126 OC

LP CONDENSATE 8.0 KG/CM2 40 OC

LEAN SOLVENT PUMP

LEAN SOLVENT TO UNITS

Advantages Of MDEA Over DEA The advantages of an MDEA based system over a DEA based system are 1. Around 15 to 20 % capacity increase if existing DEA based plant is converted to MDEA based plant with practically no capital investment.

2. Around 15 to 20 % less energy cost compared to DEA system due to low reboiler duty as less energy is required to break the bond between acid gas and MDEA. 3. Around 15 to 20 % less energy required for pumping as MDEA concentration upto 50 wt % can be kept compared to 25 wt % limitation in case of DEA, thus circulation rate can be reduced and pumping requirements will also be reduced accordingly. 4. Higher acid gas loading in rich amine (0.45 to 0.5 m/m in MDEA system) compared to 0.35 to 0.4 m/m in DEA system. 5. Selective absorption of H2S over CO2 in MDEA is better compared to DEA. 6. MDEA freezing point is much lower than DEA, making handling of the solvent much easier.

Comparison between DEA & MDEA Parameter

Di Ethanol Amine (DEA)

Methyl-Di Ethanol Amine (MDEA)

Structural Formula

HN(CH2CH2OH)2

CH3N-(CH2CH2OH)2

Molecular Weight

105.14

119.16

Specific Gravity at 20/20°C

1.092

1.041

Boiling Point, °C at 760 mm Hg

268

247.3

Freezing Point, °C

-2

-21

Solubility, at 20°C in water water in Vapor Pressure, mm Hg at 20°C Viscosity, cP

Complete Complete

Complete Complete <0.01

380

<0.01

33.8

at 40°C Refractive Index, nD, 20°C

1.4747

1.4694

Flash Point, °C (°F)

191

138

Amine Chemistry H2S + R2CH3N  R2CH3NH+ + HSCO2 + R2CH3N + H2O  R2CH3NH+ + HCO3(where R = C2H4OH) H2S Absorption Rate is Fast CO2 Absorption Rate is Slow

Normal 40 wt% MDEA

Refinery Sour Water Stripper Unit

The refinery sour water stripper unit is dedicated to treat sour water from non hydroprocessing units, i.e.CDU/VDU, DCU, SRU, HGU & PX-PTA. The H2S and NH3 in the sour water are stripped away and sent to Sulphur Recovery Unit or sour flare. The stripped sour water is sent to CDU/DCU or ETP. Approximate feed flow rates and compositions are Sl No.

Unit

Sour Water Flow (kg/hr)

H2S ppm

NH3 ppm

1

CDU/VDU

105600

1000

300

2

DCU

15000

6000

2600

3

SRU

21000

120

-

4

HGU

7200

500

1700

5

PX/PTA

2500

150

-

Stripped sour water will contain not more than 50 ppm H2S and 50 ppm NH3.

Diagram of Refinery Sour Water Stripper Unit 0.9

90 OC SOUR GAS

KG/CM2

SOUR WATER FROM UNITS

71.6

OC

40 OC SWS FEED PUMPS

REFINERY SOUR WATER STRIPPER COLUMN

92.4 OC FEED/BOTTOMS EXCHANGER

STRIPPED WATER TO ETP 40 OC

TO SRU

65 OC

SOUR WATER SURGE DRUM

REFINERY STRIPPER CR AIR COOLER

90 OC REFINERY STRIPPER CR PUMP 123.6 OC 123.8 OC LP STEAM REFINERY STRIPPER REBOILER

STRIPPED WATER AIR COOLER 123.8 OC

STRIPPED WATER TRIM COOLER STRIPPED WATER TO CDU/DCU

TO FLARE

REFINERY STRIPPER BOTTOM PUMP

LP CONDENSATE

Hydroprocessing Sour Water Stripper Unit

The hydroprocessing sour water stripper unit is dedicated to treat sour water from hydro-processing units, i.e.HCU and DHDT.The H2S and NH3 in the sour water are stripped away and sent to Sulphur Recovery Unit or sour flare. The stripped sour water is sent back to HCU/DHDT or ETP. Approximate feed flow rates are Sl No.

Unit

Sour Water Flow (kg/hr)

H2S ppm

NH3 ppm

1

HCU

19900

22855

46610

2

DHDT

16417

13340

26682

Stripped sour water will contain not more than 50 ppm H2S and 50 ppm NH3.

Diagram of Hydroprocessing Sour Water Stripper Unit

SOUR WATER FROM HCU/ DHDT

HYDROPROCESSING FEED MIX COOLER

0.9

SOUR WATER SURGE DRUM 40 OC 94.5 OC FEED/BOTTOMS EXCHANGER 65.5 OC

40 OC SOUR WATER STORAGE TANKS STRIPPED WATER TO ETP

CW

HYDROPROCESSING STRIPPED WATER COOLER STRIPPED WATER TO HCU/DHDT

SWS FEED PUMPS

90 OC SOUR GAS

KG/CM2

HYDROPROCESSING SOUR WATER STRIPPER COLUMN

CW

TO FLARE

TO SRU

65 OC HYDROPROCESSING STRIPPER CR AIR COOLER

90 OC

123.6 OC

123.8 OC

HYDROPROCESSING STRIPPER CR PUMP 123.8 OC LP STEAM HYDROPROCESSING STRIPPER REBOILER

LP CONDENSATE

‘S’ is removed by Hydroprocessing

Off Gas

S+H2

Amine Absorption

ARU Acid Gas

H2S

SRU

Sour water

SWS

Sour Gas

Sulphur Scenario in Panipat Refinery

Panipat Refinery presently has a total crude processing capacity of 15 Million Metric Tonnes per Annum, comprising 25% sweet crude oil and balance 75% sour crude oil. Purpose of Sulphur Recovery Unit 1. To remove various sulphur compounds from the petroleum products and converting them to elemental sulphur, thereby making them cleaner and reducing Sulphur Dioxide emissions and meeting environmental norms. 2. Solidification and despatch of this elemental sulphur, which is an important byproduct of the refinery.

Panipat Refinery has two Sulphur Blocks PR Sulphur Block, commissioned in 1999, having capacity of 230 MT/day. PRE Sulphur Block, commissioned in 2006, having capacity of 450MT/day. PRAE(P-15) commissioned in 2011, having capacity of 225 MT/day.

Design Features  Capacity: 3 X 225 MT /day  Process Licensor : Black & Veatch, USA  Capacity -2 X115 MT /day  Licensor - Delta Hudson, Canada

 Feed sources :  H2S (Acid rich gas )from Amine treating unit  Stripped Gases from Sour water Stripper  H2S gas from TGT unit



PRODUCT SPECIFICATIONS

The product sulphur will meet the following specification after degassing. State : liquid sulphur Colour : bright yellow (as solid state) Purity : min. 99.9 wt% on dry basis H2S : 10 ppm weight max

Claus Section  Friedrich Claus originally patented the Claus Reaction June 30, 1884. The original process was based on the direct oxidation of H2S over a catalyst, using air (oxygen), to form elemental Sulfur and water: Direct Oxidation of H2S using Oxygen

ELEMENTAL SULFUR & WATER CATALYST

H2S + 0.5 O2 →S + H2O Oxidation  Since the oxidation reaction is extremely exothermic, the control of this reaction was difficult and Sulfur recovery efficiencies were low.  The basis of the modern Claus Sulfur Recovery process in two steps:  Step No.1: thermal step;  Step No.2: catalytic step.

PROCESS DESCRIPTION OF SULFUR PLANT (CLAUS SECTION) Process Step

Process Section

Claus thermal conversion

Claus catalytic conversion

Sulfur vapour condensation

Claus Section

CLAUS SECTION Thermal Stage

Catalytic Stage

Acid Gas Separator Sour Gas Separator Thermal Reactor Burner Thermal Reactor Thermal Reactor Waste Heat Boiler • Thermal Reactor Waste Heat Boiler Steam Drum • Combustion Air Blower (one operating, one spare)

• 1st & 2nd Sulfur Condensers • 1st & 2nd Claus Reactor • 1st & 2nd Claus Reactor Reheaters • Final Sulfur Condenser • LLP Steam Condenser

• • • • •

Typical Temperature Profile HP STEAM (42 Kg/cm2) ACID GAS KOD

1400 OC

LP STEAM

REACTION FURNACE

322 OC

WASTE HEAT BOILER

SOUR GAS KOD

BFW

232 OC

AIR BLOWER TO INCINERATOR DEGASSING CONTACTOR

180 OC

IST CONDENSER 208 OC

IST CONVERTER

BFW

2ND CONVERTER TAIL GAS TO TGTU 132 OC

HP STEAM

HP STEAM IST REHEATER 287 OC

2ND CONDENSER

2ND REHEATER LP STEAM 173 OC

BFW

HEATED BFW 233 OC

FINAL CONDENSER

BFW DEGASSED SULPHUR TO YARD SULPHUR PIT

BFW

CHEMICAL REACTIONS & CATALYSTS

Typical Recovery System Plant Feed Gas

Acid Gas {H2S + CO2} H2S Recycle Claus S.R.

Sulphur

Tail Gas Treat

Incinerator

Stack gas

Claus Section  In the thermal step, the Acid Gas containing H2S is burnt in the Thermal Reactor where only one third of H2S has to be oxidized to SO2.  In the catalytic step the SO2 formed in the combustion step reacts with the unburned H2S to form elemental Sulfur.  The main reactions of the Claus process can be written as follows:  H2S + 1.5O2 →H2O + SO2 Oxidation  2 H2S + SO2 →1.5S2 + 2H2O Conversion  3 H2S + 1.5O2 →3H2O + 1.5S2 Overall

Claus Section  During the H2S combustion, part of H2S is dissociated to H2 and S depending on the temperature level;  When CO2, CO or hydrocarbons are present in the Acid Gas feed, side reaction forming COS (Carbonyl Sulfide) and CS2 are taking place.  Some side reactions that might occur in the thermal stage are shown as follow:  H2S → H2 + 0.5S2 Dissociation  CO2 + H2S →COS + H2O COS formation  CO2 + 2 H2S →CS2 + 2H2O CS2 formation

Claus Section  Many chemical reactions in modified Claus plants occur either in the Thermal Reactor or in the Catalytic Reactors: the most important is Sulfur vapour species transformations.  Elemental Sulfur vapour can exist as four separate species, hence it is important to consider the reaction: S2 ↔ S4 ↔ S6 ↔ S8 ↔ Sliq  Most of the Sulfur vapour formed in the Thermal Reactor exists as S2. As the gas passes through the Waste Heat Boiler and Condenser and therefore the temperature of the process gas decreases, the Sulfur shifts partially to S4 and then to nearly all S6 and S8.

Claus Section  The purpose of the Main Burner combustion is to reach a suitable flame temperature while the purpose of the Thermal Reactor is to provide additional space at high temperatures in which the desired reaction can progress to a point as nearly approaching equilibrium as possible.  For thermodynamic reasons, the maximum equilibrium conversion of H2S to Sulfur that can be achieved at high temperature is only about 70%. It is considerably better at lower temperature (exothermic reaction), but the rate of the equilibrium is much lower and reaction has to be assisted by a catalyst.  The Main Burner of the Claus Section can operate in two different ways:  Acid Gas combustion (normal operation);  Natural Gas combustion (start-up/shut-down operation);

Claus Catalyst The acceptable value for the CO and O2 content in the flue gas are:  CO = 0.4% by volume max;  O2 = 0.1% by volume (expect normal operating value)  O2 = 0.4% by volume max (not prolonged, maximum figure tolerate by catalyst).

 Thermal Reactor lining has a max operating design temperature of about 1450 °C, it is necessary to moderate the flame temperature by means of quench steam.  The steam rate is controlled in ratio with the natural gas flow rate.  The suggested maximum adiabatic temperature in the Thermal Reactor is 1420 °C; the theoretical quantity of steam to moderate the flame temperature to adiabatic 1420 °C is about 5-6 kg steam/kg natural gas

Reaction Furnace

Reaction Furnace with Waste Heat Exchanger (Modified Claus Process) Main Process Stream

Air

Steam Start-up Fuel Gas

Refractory lining

2nd pass tubes

1st pass tubes Acid Gas Ceramic Ferrule

Burner Saddle

Sulphur drain

BFW

Reaction Furnace  Burner  Flame scanners, igniters, pilots  Checker wall  Refractory lining (90-95% alumina)  Ceramic ferrules  Temperature measurement  Skin temperature  Rain shield

Claus Section  During the Acid Gas combustion, all the combustible components, if any, contained in the Acid Gas, are burnt according to the following exothermic reactions:  H2 + 1/2O2 → H2O  CH4 + 2O2 →CO2 + 2H2O  C2H6 + 3.5 O2 →2CO2 + 3H2O  C2H4 + 3O2 →2CO2 + 2H2O  C3H8 + 5O2 →3CO2 + 4H2O  C3H6 + 4.5 O2 →3CO2 + 3H2O  C4H10 + 6.5 O2 →4CO2 + 5H2O  The listed reactions are practically fully displaced to the right side. A little part of hydrocarbons is also partially burnt to CO:  CH4 + 1.5O2 →CO + 2H2O  C2H6 + 2.5O2 →2CO + 3H2O  C3H8 + 3.5O2 →3CO + 4H2O  CO2 + H2S →COS + H2O ;CO2 + 2 H2S →CS2 + 2H2O

Natural Gas Combustion  During this operation mode, the adiabatic flame has to be maintained below the maximum operating temperature of refractory material lining the Thermal Reactor.  Quench steam is used to moderate the flame temperature at values around 1300 °C (not higher than 1400 °C);  Excess oxygen, if any, shall react with the Sulfur present in the plant, particularly over the catalyst, according to the following reaction: S + O2 → SO2

Claus Process – 1st Stage Reaction Furnace: Expectations

Oxidize all hydrocarbons to CO2 and water. Oxidize all NH3 to Nitrogen. Convert 1/3rd of the H2S to SO2.

Natural Gas Combustion  If the natural gas combustion is carried out with large oxygen the hydrocarbons contained in natural gas shall not be completely burnt and some carbon can get formed.  Carbon tends to be adsorbed on the catalytic beds of Claus reactor and then the catalyst gets fouled and poor quality Sulfur may be produced.  Operating with O2 deficiency higher than 5% a certain part of the methane present in the natural gas shall react according to the equation: CH4 + 3/2O2 →CO + 2H2O

Claus Catalyst  The catalyst used in the Claus Catalytic Reactors is Alumina. The First Claus Reactor catalyst bed is a special type particularly active towards the hydrolysis of COS and CS2.  The presence of unreacted oxygen in the gas fed to catalyst must be avoided.

Claus Catalyst  Formation of carbon (caused by the uncompleted combustion of hydrocarbons present in Acid Gas and in natural gas) and its deposit on the catalyst shall lead to a poisoning of the catalyst itself and to the production of fouled Sulfur

 Checks of catalyst pressure drops are also necessary to detect any catalyst plugging due to Sulfur condensation, carbon formation or catalyst thermal degradation.

Claus Catalyst Standard (activated alumina)  Alcoa/Discovery  Alcan  Porocel

Special properties  COS/CS2 hydrolysis / O2 scavenger / deactivation resistance

Claus Catalyst Catalyst ageing: The ageing of the catalyst is due to thermal and hydro-thermal causes and to sulphation. a) Thermal and hydro-thermal ageing  It is known that alumina transforms and loses part of its catalytic activity when temperatures exceed 600 °C. The specific surface reduces then, and the diameter of micropores increases.  The use of inert gasses (nitrogen) is recommended

Claus Catalyst b) Sulphate poisoning When activated alumina is brought into contact with gaseous SO2, the initial phenomenon corresponds to an absorption of SO2. A fraction of this SO2 is actually chemisorbed and irreversibly fixed The chemisorbed SO2 is not chemically stable and tends to enter into reaction with superficial hydroxyl groups, building up bound sulphate groups At higher temperatures, the sulphate formation is markedly increased. This reaction causes the rapid ageing of catalysts.

Precautionary measures to avoid damage to Claus catalyst 1. Liquid water damages the catalyst causing it to crumble; it also damages the reactor refractory and causes corrosions. 2. 100% steam on the catalyst causes its temporary deactivation due to water absorption. 3. The presence of a high quantity of oxygen in the process gas fed to the catalyst (more than 0.4% by volume) may cause catalyst sulphation, due to the formation of aluminium sulphate. This shall cause the decrease of the catalyst activity. 4. The maximum safe working temperature of the catalyst shall not exceed 400 °C.

Claus Catalyst  When Sulfur is present in the plant, the oxygen contained in flue gas can react with the liquid Sulfur at temperatures higher than 150 °C producing SO2 and SO3 and causing very high localised and uncontrolled temperatures.  SO3 is very dangerous because it generates corrosion in all the parts of the plant; in addition the formation of SO2 on the Claus catalyst causes the progressive deactivation from sulphation.

Claus Catalyst  Any carbon contained in flue gas produced during natural gas combustion is harmful at any stage of operation; carbon tends to deactivate the catalysts itself because it plugs the catalysts micropores.

 Another effect of catalyst poisoning from carbon is the high-pressure drop that may reduce the plant capacity.  Catalyst fouling by carbon is irreversible and consequently the fouled catalyst needs to be replaced.

PROCESS DIAGRAM

Typical Sulphur Lock and Look Pot

GROUND

Flow of liquid Sulphur

PROCESS VARIABLES

Claus Section normal operation with Acid Gas During the normal operation with Acid Gas, the following variables are highly important:  Ratio Air/Acid Gas;  Thermal Reactor temperature;  Claus Reactors temperature;  Mass velocity in Sulfur Condensers;  Steam pressure;  Feed composition variations;  Liquid carry over;  Pressure and temperature;  Liquid Sulfur quality and yield.

Process Variables 1. Ratio Air/Acid Gas:  The control of the Thermal Reactor is achieved by regulating the ratio of total air (oxygen) to total Acid Gas (H2S) entering the Plant.  The air entering in the Main Burner of the Thermal Reactor is described by the following equation: (total air to Claus Burner)=(main air)+(trim air)  The control strategy is based on a feedforward control on the main air and on a feedback control on the trim air to the Claus Burner.  The Tail Gas analyser measures the H2S and SO2 concentrations in the Tail Gas; a ratio 2/1 of H2S /O2 is the stoichiometric relationship between the reactants that produces the maximum products.  Unfortunately this ratio is not convenient to use as control signal, since the ratio is non-linear. For this reason, the Air Demand (AD) concept has been introduced.

Process Variables  The Tail Gas analyser control loop will control only about 10% of the combustion air to the process.  The Air/Acid Gas ratio can be fixed by the operator and shall be used to modify the set point of the main air controller.  In case the Tail Gas analyser is not on stream, laboratory analysis of H2S and SO2 in the Claus Tail Gas shall be necessary to set the correct Air/Acid Gas ratio.  The plant operation with incorrect H2S /SO2 ratio content in the Claus Tail Gas would lead to a decrease of Sulfur yield.

Process Variables Acid Gas Operation:  During the Acid Gas operation an increase of the flame temperature is possible if the content of Acid Gas increases and/or if more air then necessary is sent to the Thermal Reactor.  During the Acid Gas operation in case of presence of hydrocarbons, the flame temperature is also considerably higher than normal.

Process Variables Reactor parameters: It is important to analyze different combustion air ratios during Acid Gas combustion (containing about 90% by vol. H2S)  The flame temperature should not be used as a parameter to adjust the Air/Acid Gas ratio during the operation with Acid Gas, because it is possible to have the same flame temperature with different air/gas ratios.  The only operational parameter to be used to operate the plant is the Claus Tail Gas analysis.

Process Variables  Mass velocity in Sulfur Condensers o The Sulfur Condensers have been designed with a minimum of mass velocity, which prevents any operating problems. o In case of operation below the safe limits Sulfur fogs can be formed; Sulfur fogs formation originates problems to the Catalytic Reactors and also decrease the unit performances.

 Steam pressure o The produced steam pressure can be modified to implement the cooling or the heating rate of process gas at boilers outlet.

 IMPORTANT: During Acid Gas operation, the produced steam pres. has not to be allowed to drop below 1 barg (corresponding to a steam temp. of 121 °C) to avoid risks of Sulfur solidification.

Process Variables  Feed Composition variations o Load variations should be as smooth as possible to avoid plant upset and shut-down. o Acid Gas composition variations can produce a remarkable effect on the plant operation and/or on Sulfur Recovery Efficiency.

 Hydrogen sulphide o The concentration of H2S in the Acid Gas determines the achievable flame temperature, the concentration of H2S is directly proportional to the flame temperature. o Fast fluctuation in H2S composition can create upset reducing the efficiency of the plant due to delay in the control system reaction.

Process Variables  Carbon Dioxide o Carbon dioxide plays the role of diluting process gas, producing COS and CS2 during the Acid Gas combustion. o The production rate of COS and CS2 is proportional to the concentration of CO2 and hydrocarbons in the feed Acid Gas.

 Steam o Steam present in the Acid Gas acts as a diluting agent. The increasing of the rate of the Acid Gas diluting agents implies, in addition to the Sulfur Recovery Efficiency decreasing, the lowering of the plant capacity due to the increase of the pressure drops of the system.

 Hydrocarbons o Hydrocarbons have several negative effects on the Acid Gas combustion; 1. 2. 3.   

The difficulty in burning hydrocarbons if they are present in massive quantities, The effect of dilution of the process gas with the consequent Sulfur efficiency decreasing. A further negative effect is the consumption of combustion air according; it is important to note that while the H2S combustion requires about 0.5 molO2/mol H2S, the combustion of hydrocarbons requires: molO2/mol CH4 molO2/mol C2H6 molO2/mol C3H8

Process Variables Hydrocarbons (Continued):  The Thermal Reactor effluent temperature should be always higher than 1000 °C to ensure the hydrocarbons complete destruction.  In case the hydrocarbons content in the Acid Gas exceeds the tolerance calculated as per the above system, some carbon can be formed during the Acid Gas combustion with the consequence of catalyst plugging and fouling. In addition, note that the carbon formation can also be caused by deficiency air operation.

Inert Gases N2

Ar

Decreases furnace temperature Decreases plant capacity

Reduces partial pressure of Claus reactants Shifts Claus reaction equilibrium

CO2 Decreases furnace temperature Decreases plant capacity Participates in undesirable side reactions CO and COS formation

Ammonia Increases air demand Increases furnace temperature Decreases plant capacity Possible downstream contamination and plugging from ammonia salts

CO Formed from CO2 Up to 20%of total inlet carbon Increases with increasing furnace temperature Tends to decrease the furnace temperature Decreases air demand Participates in undesirable side reactions

HYDROCARBON Increase air demand Increases furnace temperature Decreases plant capacity Possible downstream contamination Participates in undesirable side reactions  CS2 formation

Process Variables  Liquid carry-over o KO drums are provided upstream the Thermal Reactor burner with the purpose to remove all the entrained liquids that are separated and transferred outside the SRU battery limits.

o The effect of liquid entrained to the burner is it creates disturbance to the Acid Gas flame and the sudden evaporation in the combustion chamber damages the reactor refractory lining and also the corrosion of the Acid Gas piping lines. o In case of impossibility in removing liquids from the Acid Gas separators, very high level switches shall shut down the Claus Section. The Acid Gas line is steam traced, the tracing shall be maintained in operation in all seasons with the purpose to avoid condensation and corrosion.

Process Variables  Pressure and Temperature o Variation of the pressure in the Acid Gas feed lines upstream the unit pressure control valves shall correspond to variations of the load of the unit. o Small and smooth variations of the Acid Gas load shall be automatically compensated by adjusting the necessary quantity of combustion air. o Very large throughput variations in a very short period of time require the operator to re-adjust some operating parameters. o Acid Gas temperature variations shall not have an appreciable effect on the system if no composition variations are involved.

Process Variables  Liquid Sulfur quality and yield o Liquid Sulfur is collected in an underground Pit from which it is transferred to the storage system. o The Sulfur yield is the most important parameter for the definition of the acceptability of the plant operation. o The only impurity, which can be present in noticeable quantity, is carbon. Carbon can be originated by bad combustion of natural gas during plant heating-up and during the operation with Acid Gas containing abnormally high quantities of hydrocarbons or in case of operation with strong process air deficiency. o The Sulfur produced in the Claus plant is saturated with H2S and contains Sulfur polysulphides.

Typical Operating Conditions Parameters

Normal @ design capacity

Normal during Heat-up

Minimum acceptable

Temperatures Thermal Reactor (1st zone) °C

1350

1350

1000

First Claus Reactor inlet °C

235

205

200

First Claus Reactor outlet °C

300

205

200

Second Claus Reactor inlet °C

210

205

190

Second Claus Reactor outlet °C

236

200

180

Incinerator °C

750

750

600

Claus tail gas °C

135

140

130

Pressures WHB (steam side) barg

50

50

50

Sulfur condenser (steam side) barg

4.5

4.5

4.5

TAIL GAS CLEAN-UP

Tail Gas Treating Unit  The tail gas from the Claus units is heated by superheated HP steam and mixed with hydrogen.  Then passed over a catalyst bed in order to convert any SO2 present in the tail gas back to H2S.  This gas is then cooled and passed through an Amine absorber, where H2S is absorbed in MDEA.  The rich MDEA thus formed is regenerated in the amine regeneration system inbuilt within the TGTU and returned to the absorber.  The acid gas released is sent back to SRU for Sulphur Recovery.  The Tail gas then goes to the Incinerator, where it is burnt off and the flue gas goes to the stack.  The main reaction in the hydrogenation reaction is

SO2 + 3H2

H2S + 2H2O

Precautionary measures to avoid damage to hydrogenation catalyst  

  

The hydrogenation catalyst is subject to spontaneous combustion in the presence of oxygen. During the normal operation the Claus tail gas should not contain oxygen. During unit shut-down it is necessary to burn off Sulfur and return the catalyst to its oxide state. Refer to the shut-down. The maximum temperature to avoid damage of the catalyst is 427 °C. The oxygen presence shall be avoided in normal operation and during nitrogen circulation steps. The hydrogen concentration in the process gas shall not be allowed to exceed 6% by volume.

Diagram of Tail Gas Treating Unit 39 OC

39 OC

HYDROGENATION REACTOR

333 OC

LP STEAM 177 OC

FG

815 OC

INCINERATOR

316 OC

39 OC

OC

QUENCH COLUMN

286

TGTU AMINE ABSORBER COLUMN

TAIL GAS FROM SRU

SUPERHEATED HP STEAM

HP STEAM SUPERHEATER

BFW

STACK

HYDROGEN

HP STEAM (42 Kg/cm2)

INCINERATOR AIR BLOWER

122

OC

REGENERATOR AIR CONDENSER

ACID GAS TO SRU

43 OC

AMINE FILTER SYSTEM

45 OC

RICH SOLVENT PUMPS

LEAN SOLVENT COOLER

115 OC RICH/LEAN SOLVENT EXCH

51 OC

REGENERATOR BOTTOMS PUMP

132 OC

REGENERATOR REFLUX DRUM

AMMONIA

55 OC TGTU AMINE REGENERATOR COLUMN

70

BFW

OC

REGENERATOR REFLUX PUMP REGENERATOR REBOILERS

55 OC LP STEAM

LP CONDENSATE

Process Description TGU Hydrogenation Reactor Reactions SO2 + 3H2

H2S + 2H2O

Other Reactions (All Exothermic) Hydrolysis Due to the Presence of Steam COS + H2O  H2S + CO2 CS2 + 2H2O  2H2S + CO2 Very Small Amount of COS and CS2 Reduced by Hydrogen COS + 4H 2 H2S + CH4 + H2O CS2 + 4H2  2H2S + CH4 Few ppm of Methane Will Be Combusted in the Incinerator

SCOT Process Fundamentals Process stages: Tail gas heating and sulphurous compound reduction to H2S Cooling and quenching to near ambient temperatures H2S absorption, stripping and recycle

SCOT (99.8% Recovery)  Shell Claus Offgas Treatment (SCOT):

SCOT Objective – Convert to H2S & Recycle

Claus Offgas

SO2

S6

S8 COS CS2 S8-Fog

Catalyst

H2S Absorb & Recycle

Incineration

Incinerator Operation Purpose : *To oxidise all sulphur compounds in the tail gas to SO2 H2S + 3/2 O2  SO2 + H2O 2 COS + 3 O2  2 CO2 + 2SO2 CO + ½ O2  CO2 CS2 + 3 O2  2 SO2 + CO2 Sn + n O2  SO2

Typical Operating Conditions Incinerator temperature 600-7500C (1100-13800F) Stack exit temperature 2400C

“Excess” oxygen : 2 to 6+ mole% in stack

Operating Issues NOx and SO3 formation Usually a result of poor control of operation  Excess oxygen much higher than required  Incinerator temperature much higher than required

NOx is emissions problem SO3 is a corrosion problem

Operating Issues CO destruction Usually requires very high temperature and excess oxygen Usually results in high NOx and SO3 formation

EMERGENCY SITUATIONS

Emergency Shutdown  Steam Failure Effects: a) The heating of liquid Sulfur is not possible; b) The heating of equipment and piping is not possible; c) The regeneration of amine solution is not possible; d) The quench of In-line Heater flame is not possible.

Emergency Shutdown  Steam Failure-contd Consequences: a) An extended failure of the steam network may cause the solidification of the Sulfur; b) Shut-down of the Claus Section; Shut-down of the TGT Section; Possible shut-down of the Incineration Section for high temperature; Corrosion problems since steam heating system is part of corrosion protection strategy. When the network re-starts working, all steam traps must be checked to ensure correct operation.

Boiler feed water and demi-water makeup failure  Consequences: a) Shut-down of the Incineration Section; b) Shut-down of the Claus Section; c) Shut-down of the TGT Section; d) Shut-down of the Sulfur Degassing Section; e) No production of steam.  Actions to be taken: a) The problem must be quickly found to permit an immediate restart; b) Avoid losing completely the water inside the boiler. IMPORTANT: In case of complete loss of water inside the boiler do not re-feel instantaneously the boiler because this will damage the tubes. Wait that the tubes are cold then start to fill slowly the boiler with hot BFW.

Emergency Shutdown  Natural gas failure Effects: a) No flame in the Thermal Incinerator;

Consequences: a) Shut-down of the Incineration Section; b) Shut-down of the Claus Section; c) Shut-down of the TGT Section; d) No production of steam. Actions to be taken: The problem must be quickly found to permit an immediate restart.

Emergency Shutdown  Electric Power Failure

Actions to be taken following a Plant trip

 

Immediately Plant trip, the trip cause must be found and corrected as quickly as possible; The air, natural gas, acid gas and quench steam manual block valves at burners shall be closed by the operator; the operator shall also check that the nitrogen purge valves are open;

Emergency Shutdown   

The temperatures throughout the Unit shall be observed and if they increase the Unit shall be purged again with nitrogen; The Plant shall be restarted in accordance with the procedure described in this operating manual; If it is decided to keep the Plant down for repairs after a shutdown, the catalysts must be stripped of Sulfur and the hydrogenation catalyst must be returned to its oxide form, following a planned shut-down procedure.

IMPORTANT:

During the shut-down phase, it must be constantly reminded that a rapid change of temperatures is completely undesirable for the following reasons: a. Solidification of Sulfur may occur; b. Thermal expansion or contraction of the equipment may deform piping and equipment themselves, causing leaks after a restart; c. Refractory lining materials may be damaged.

TROUBLESHOOTING

TROUBLESHOOTING  If tail gas analyses indicate a high H2S/SO2 ratio then insufficient air is reaching the Thermal Reactor.  This, in turn, prevents complete hydrocarbon combustion, which may cause carbon deactivation of the catalyst beds  The first step would be to increase the air/acid gas ratio. If the air/acid gas ratio is greater than normal, operation of the amine system should be examined to reduce the hydrocarbon content of the acid gas.

TROUBLESHOOTING  Temperature profiles through the catalyst bed should be checked periodically if the catalyst needs changing.  Even in plants operating smoothly at design conversion levels, catalyst may have slowly lost surface area and become deactivated.

TROUBLESHOOTING  Steam leaks from Boiler or Condensers can cause plugging and reduced plant efficiency. Moisture tends to promote catalyst disintegration  Boiler leak has probably developed due to: 1) low steam production; 2) low boiler effluent temperature;

TROUBLESHOOTING Plugged Seal Legs  The first indication of a plugged seal leg is increased pressure drop caused by liquid Sulfur backing into the Sulfur Condenser outlet channel and then into the effluent Process Gas line, thus restricting gas flow area.  Seal legs may plug due to the presence of refractory dust, corrosion products, catalyst particles

OPERATIONAL SAFETY ASPECTS

H2S Poisoning  Hydrogen sulphide is both an irritant and an extremely poisonous gas.  Breathing even low concentrations of hydrogen sulphide (H2S) gas can cause poisoning.  Many natural and refinery gases contain more than 0.10 molpercent H2S.  The current OSHA permissible exposure limits are 20 molppm ceiling concentration and 50 mol-ppm peak concentration for a maximum 10-minute exposure.  The Sulfur Recovery and Tail Gas Treatment Unit gases contain H2S. These gases must NEVER be inhaled. Also, the water in the Separators contains dissolved H2S, which will flash at atmospheric pressure. NEVER drain this water to an open sewer.

H2S Poisoning  One full breath of high concentration hydrogen sulphide gas will cause unconsciousness and could cause death, particularly if the victim falls and remains in the presence of the H2S.  The operation of any unit processing gases containing H2S remains safe provided ordinary precautions are taken and the poisonous nature of H2S is recognized and understood.  No work should be undertaken on the unit where there is danger of breathing H2S, and one should never enter or remain in an area containing it without wearing a suitable fresh air mask.

Acute Hydrogen Sulphide Poisoning First Aid Treatment of Acute Hydrogen Sulphide Poisoning:  Move the victim at once to fresh air. If breathing has not stopped, keep the victim in fresh air and keep him quiet. If possible, put him to bed.  Secure a physician and keep the patient quiet and under close observation for about 48 hours.  In cases where the victim has become unconscious and breathing has stopped, artificial respiration must be started at once.  If other persons are present send one of them for a physician.  Others should rub the patient's arms and legs and apply hot water bottles, blankets or other sources of warmth to keep him warm.

Process Safety Concerns Exceeding plant designed operating parameters can lead to any of the following events :

• • • • • • •

Toxic gas exposure Explosions Sulphur Fire Sulphur solidification Corrosion Catalyst damage Refractory & Equipment Damage

DANGER  H2S is extremely poisonous gas (as toxic as hydrogen cyanide) Maxm permissible conc.of H2S in air as per OSHA during 8Hrs working day = 10ppm(v) short-term exposure limits(10 minutes) = 15 ppmv FATAL :Conc. Of 500-700 ppm in 30 minutes  H2S is also a flammable gas  Explosive limit in air LEL (4%)

 Ensure that water does not enter the condenser seal pots prior to filling with sulphur. Molten sulphur reacts violently when it comes in contact with water, creating a hazardous situation.

Extinguishing Sulfur Pit fires 1. In case of fire in the Sulfur Pit, steam is used to snuff the fire. This operation shall be done at a safe distance from the Pit by opening a steam valve. The steam shall break the bursting disks and shall enter the Sulfur Pit. 2. When the fire is extinguished the steam valve shall be closed and a new bursting disk shall be installed.

Fire Protection  The spontaneous ignition temperature of Sulfur in air is about 170 °C. When the Sulfur ignites, it is difficult to extinguish and it can ignite again spontaneously. In order to minimize the risk of Sulfur fires, all Sulfur spillage must be removed as soon as they occur.

 When Sulfur fires are extinguished with water, a white toxic choking acidic fume is released which is extremely hazardous and inhalation or contact with the skin should be avoided.  Sulfur fire can also be extinguished by smothering with sand. Carbon dioxide fire extinguishers of steam smothering may also be used.

SAFE HANDLING OF SAMPLE  All samples taken on Sulfur plant are considered to be hazardous and the sampler must wear suitable breathing apparatus and acid resistant gloves.  The equipment used must be gas tight and able to withstand temperatures up to 180 °C. Handling of gas samples containing H2S : 1) The acid gases are analysed for H2S, H2, hydrocarbons and ammonia concentration. 2) The Claus tail gas is analysed to check the H2S and SO2 concentration. 3) The reduced gas is analysed to check the H2S. 4) In order to purge the acid gas sample line, the gas may be passed into a freshly prepared strong caustic solution or sent to flare; acid gas sampling sent to atmosphere is not allowed. 5) The sample must be taken in a gas tight container. 6) The sampler must have an assistant at hand in case of emergency.

Handling of liquid Sulfur  Sulfur collected from the Sulfur Pit or Sulfur Hydraulic Seals outlet will be hot, about 140 °C and care must be taken to avoid burns and contact with the skin. When taking a sample from the Sulfur Pit a rod with a cup on the end can be used.  When standing on top of the pit taking a sample through the inspection hole, the sampler must wear an anti-gas mask with suitable filter for H2S protection.

Sulphur - Applications COMMERCIAL USES OF SULPHUR

Commercial Uses of Sulphur Sulphuric Acid – largest chemical produced in the world by tonnage – 200mln tpy Fertilizers Making tyres Vulcanisation of rubber Black gun powder

Commercial Uses of Sulphur Detergents – Cleansing Agent Medicinal Usage Matches Adhesives Waste Water Processing Sugar refining Burnt Sulphur Powder used in dry fruits preservation Glow Painting

SULPHUR LOADING AT YARD

SULPHUR LOADING AT YARD

Thank you !!