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CHE4036Z - 2015

Chemical Engineering Design

Individual Feasibility Report

ANONYMOUS CANDIDATE # __405___

PLAGIARISM DECLARATION

I know that plagiarism is wrong. Plagiarism is to use anothers

work and pretend that it is my own.

I have used the Harvard system for citation and referencing. In

this report, all contributions to, and quotations from, the

work(s) of other people have been cited and referenced.

This report is my own work. I have not allowed, and will not

allow, anyone to copy my work.

Signed ___________________ Dated _____________

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CHE4036Z - 2015

Chemical Engineering Design

Individual Feasibility Report

ANONYMOUS CANDIDATE # _405____

Word Count _______1488_____

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Executive summary

Purpose of the report

The purpose of this report is to establish the preferred type of process for treating Natural gas

from a wellhead, and after reviewing various process options used worldwide, a suitable

process will be chosen based on viability and compatibility with processing the available natural

gas and meet the predefined specifications.

Evaluated processes

The different process routes explored were, Thiopaq, an environmentally friendly process that

uses bacteria to oxidise H2S to elementary sulphur; Acid Gas Re-injection, which involves the

injection of the H2S and some CO2 into an underground reservoir, but in this case was found to

not viable since it requires an existing well, and for this case no such well is available. Some

other processes explored were the Claus process and the Wet Sulphuric Acid process which

were also focused on sulphur recovery.

Results

The chosen process includes the conventional Claus process with the tail gas treating unit.

Sour gas treating unit

(Amine)Dehydration unit

Claus Process+SCOT

Air

Pre treated natural gas

Water

Dry natural gas

Off gas

Sulphur

Figure 1: Summary of a chosen process route.

Conclusion

The chosen route was the Claus process fitted with a tail gas treating unit. The gas stream

going to the SA grid has a Wobbe index of 49.8 and contains 5 ppm of H2S. The overall

recovery of sulphur is 99.9% with the rest of the uncovered H2S and CO2 sent to the incinerator

before being released to the atmosphere

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Contents

Executive summary ...................................................................................................................... i

Purpose of the report ................................................................................................................ i

Evaluated processes ................................................................................................................ i

Results ..................................................................................................................................... i

Conclusion ............................................................................................................................... i

List of tables and figures ............................................................................................................ iii

List of tables and figures ............................................................................................................ iii

1. Introduction ......................................................................................................................... 1

1.1. Purpose/motivation of the report .................................................................................. 1

1.2. Process background .................................................................................................... 1

1.3. Objectives of the report ................................................................................................ 1

1.4. Scope and limitations ................................................................................................... 1

1.5. Key issues ................................................................................................................... 1

2. Critical evaluation of process options .................................................................................. 2

2.1. Sour gas treating ......................................................................................................... 2

2.2. H2S handling and Sulphur recovery ............................................................................. 3

2.3. Gas dehydration .......................................................................................................... 5

3. Results of investigation ....................................................................................................... 6

3.1. Route chosen ............................................................................................................... 6

3.2. Preliminary flowsheet ................................................................................................... 6

3.3. Key assumptions for the mass balance ........................................................................ 8

4. Conclusion .........................................................................................................................11

5. References ........................................................................................................................12

iii

List of tables and figures

Table 1: Table comparing advantages and disadvantages of sour gas treating unit. .................. 2

Table 2: Table comparing advantages and disadvantages of Sulphur recovery unit .................. 4

Table 3: The capital investment and operational costs for treatment of low-pressure gas (Cline,

et al., 2003) ................................................................................................................................ 5

Table 4: Stream table complementing the above block flow diagram ......................................... 9

List of tables and figures

Figure 1: Summary of a chosen process route. ............................................................................ i

Figure 2: Preliminary block flow diagram of the Natural gas process .......................................... 7

1

1. Introduction

1.1. Purpose/motivation of the report

This paper is a feasibility study that explores and compares different processes which

treat natural gas from a wellhead by separating the acid gas impurities and recovering

sulphur from the H2S present in the natural gas. The processes are compared based on

their advantages and disadvantages in view of their design cost, reliability and duty. The

chosen process should treat 372 tonnes/hr of natural gas and should recover close to

100% of sulphur from H2S contained from the natural gas with 0 ppm of H2S released to

the atmosphere.

1.2. Process background

Natural gas processing involves treating the wellhead gas by separating the acids

contained, impurities and dehydrating the gas before it can be used a fuel gas. The

treated gas to be discussed on this paper will be mainly used for the operation of a

power station and is to contain less than 5 ppm of H2S and a Wobbe index of 47.2 and

51.41 MJ/m3. The separated H2S is to be converted to elementary sulphur.

1.3. Objectives of the report

To determine a viable process route for treating sour gas and recovering sulphur from

H2S by exploring and critically evaluating advantages and disadvantages of existing

processes in view of their design cost, reliability and duty.

1.4. Scope and limitations

This report is only focused on sour gas treatment, sulphur recovery and the Wobbe

index of the dry gas stream and does not offer insight on the extracting of the gas from

the well and its initial phase separation nor does it go deeper on the fractionation of the

natural gas liquids.

1.5. Key issues

Getting the 0 ppm H2S concentration specification and Wobbe index in the acceptable

range.

2

2. Critical evaluation of process options

This section will discuss some of the available process on literature and explore their

advantages and disadvantages in view of their design cost, reliability and duty.

2.1. Sour gas treating

This unit sweetens the gas coming from the wellhead by removing the acid content which may

be contained in that gas. Such acid gases in this study are the H2S and CO2. This will happen

offshore on the rig, this is to save the limited space on land for the other processing units.

Reactive solvent with MEA as a solvent will be used to absorb both the H2S and CO2 (Abdel-

Aal, et al., 2003) as this has a high selectivity of H2S before sending the acid gas to the sulphur

recovering unit onshore using a different pipeline form the sweetened gas which will also be

further processed on land because of the space limitations on the rig.

Table 1: Table comparing advantages and disadvantages of sour gas treating unit.

Process Chemical absorption

(Reactive solvent)

Physical

absorption

Batch solid bed

absorption

Advantages - Use regeneratable

solvent that

remove large

amount H2S and

CO2

- Reliable since it is

an established

commonly used

process

- Regenerated

solvents

- Presence of

CO2 has no

effect on the

process

3

Table 1 continues..

Disadvantages - Large equipment

that require close

monitoring

- Degradation,

foaming and

corrosion of the

units hence

regular repairs

- Low

selectivity of

H2S,

requiring

more than

one unit

- Only works well

with low

concentrations

of H2S

Cost

- Investment - High - Medium - Medium

- Operational - Medium - low - low

Energy requirement - high - low - medium

(MOKHATAB, et al., 2012)

2.2. H2S handling and Sulphur recovery

The H2S acid gas handling is another important step. Since H2S cannot be released to the

atmosphere; it is important to consider a process to recover elementary sulphur from it. Such

process involve Acid Gas Re-injection which in this case a has the main disadvantage of that

it requires an existing well, as for this case no such well is available. One other promising

process is Thiopaq, an environmentally friendly process that uses bacteria to oxidise H2S to

elementary sulphur (Shell Global solutions, 2011). However this process has a very small

capacity and can only process a maximum of 150 tonnes/day of H2S, and since the available

gas has a flow of over 400 tonnes/day this process will therefore not be considered as it not

be able to handle the supplied gas. Even though Thiopaq was found to be viable cheap as

seen on Table 3 below the chosen process is the Claus process with the SCOT tail gas

treatment unit. This is due to the Claus process being established with worldwide application

and will assist in increasing the conversion to 99.9% (MOKHATAB, et al., 2012) so as to

minimise the overall H2S released to the environment as per process implementation

specifications.

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Table 2: Table comparing advantages and disadvantages of Sulphur recovery unit

Process

Advantages Disadvantages

1. Shell Claus Off-Gas

Treating

- Produces very high recovery

of sulphur.

- Well established technology

- low maintenance

requirements

- The unit requires little

operational attention (Shell

Global solutions)

- Not economical for feed

concentration of greater than

15%

2. Acid Gas reinjection

- No worry about handling

H2S

- Required an existing well to

inject into, which is currently

not available

Table 2 continues

3. Wet sulfuric acid

( ROSENBERG, 2006)

- more than 99% of the sulfur

is recovered as concentrated

sulfuric acid of commercial

grade

- flexibility in feed composition

- simple layout and operation

- high cost of H2SO4 transport

4. Thiopaq

- Integrates gas purification

with sulphur recovery in one

unit.

- All H2S is consumed in the

bioreactor

- Process low capacity of H2S

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Table 3: The capital investment and operational costs for treatment of low-pressure gas (Cline, et al., 2003)

Configuration THIOPAQ Amine +

Claus

Amine +

Claus + SCOT

Capital investment + 10 year Operational

costs (MMUS$) NOTE

16.6 17.7 22.2

Operators costs

Low High High

Maintenance costs Low High High

Sulphur removal (based on SO2 emitted) > 99.95 > 95.0 > 99.9

Sulphur recovery (based on S0 produced) 96.5 95.0 99.9

2.3. Gas dehydration

The two possible dehydration routes explored in this paper are adsorption and adsorption.

Absorption with glycol is the preferred dehydration method because it is more economical

than adsorption. This is due to the following differences between absorption and adsorption

(Christensen, 2009)

Adsorbent is more expensive than glycol.

It requires more energy to regenerate adsorbent than glycol.

Replacing glycol is much cheaper than replacing an adsorption bed.

Glycol can be changed continuously, while changing an adsorption bed requires a

shutdown.

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3. Results of investigation

3.1. Route chosen

The route chosen treats the sour gas in an absorber with MEA solvent fitted with the solvent

regenerator, the choice was motivated by the fact that this is an established process with world

wide application (MOKHATAB, et al., 2012). The sweetened gas is dehydrated by absorption

with glycol as a preferred agent since this very economical and requires less energy than its

counterparts (Christensen, 2009). The dehydrated gas goes to the SA grid with a Wobbe index

of 49.8. The sulphur is recovered using a Claus process tailored with a Tail Gas Treatment unit

to improve the conversion to 99.9%.

3.2. Preliminary flowsheet

The sour gas coming from the wellhead separator is fed to the absorber on the rig to be sweetened

by removing the H2S and CO2 using the amine solvent. The sweetened gas is dehydrated in the

dehydration unit using glycol to remove all the water present in the sweet gas. The dehydrated

gas is then ready to be sent to the SA gas grid. The H2S and CO2 are sent to the Claus process

fitted with the Tail gas treatment unit to increase the sulphur recovery to 99.9%. Elementary

sulphur is separated from the gas and sent to storage whilst the CO2 and very little unconverted

H2S are released to the atmosphere.

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Block flow diagram

Sour Gas Treating unit

Sulphur Recovery Unit

(Claus Process)

Gas Dehydration

Tail Gas Treating Unit

1

2

3

9

7

4

5

8

Sulphur to

storage

Water to

treatment

Air

Natural gas to

sale

Off gas to

atm

Sour gas

6

10

Sour gas treatment and Sulphur recovery process

Date: 21/07/2015

Sheet: 01/01

Drawn: No. 405

DRAWING No. ZZ-2665

REVISION No. Rev 01

Figure 2: Preliminary block flow diagram of the Natural gas process

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3.3. Key assumptions for the mass balance

Assumed a basis of 100 kmol/hr of gas coming into the battery limits, which was later

corrected using Goal Seek function in excel.

None of the hydrocarbons are absorbed by the amine solvent.

All water contained in the sweet gas is removed in the dehydration unit.

Clause overall reaction 22 + 2 2 + 22

Conversion of the Clause process is 97%

Tail gas overall reaction 2 + 32 2 + 22

Overall elementary sulphur recovery including the tail is 99.9% with stream 9 and 10 not

calculated in the stream table as all the SO2 formed is completely converted back to H2S

and hence these streams have no effect on the mass balance.

All water formed in the Claus process exit via the tail gas exit stream.

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Table 4: Stream table complementing the above block flow diagram

Stream 1 2 3 4 5 6 7 8 9 10

Mole Flow kmol/hr 20400 585 19820 19720 100 2840 542 3160

Mass Flow kg/hr 372000 20360 351600 349800 1810 81960 17380 84930

Mass Flow kg/hr

Nitrogen 3720 0 3720 3720 0 62870 0 62870

Oxygen 0 0 0 0 0 19100 0 10420

Carbon dioxide 19220 1870 17350 17350 0 0 0 1870

Hydrogen sulphide 18490 18490 3.36 3.36 0 0 0 18.5

Sulphur 0 0 0 0 0 0 17380 0

Methane 287600 0 287600 287600 0 0 0 0

Ethane 32010 0 32010 32010 0 0 0 0

Propane 6750 0 6750 6750 0 0 0 0

n-Butane 1040 0 1040 1040 0 0 0 0

i-Butane 842 0 842 842 0 0 0 0

n-Pentane 319 0 319 319 0 0 0 0

n-Hexane 104 0 104 104 0 0 0 0

n-Heptane 40.3 0 40.3 40.3 0 0 0 0

n-Octane 23 0 23 23 0 0 0 0

Water 1810 0 1810 0 1810 0 0 9760

Mass Frac

Nitrogen 0.01 0 0.0106 0.0106 0 0.767 0 0.74

Oxygen 0 0 0 0 0 0.233 0 0.123

Carbon dioxide 0.0517 0.0917 0.0493 0.0496 0 0 0 0.022

Hydrogen sulphide 0.0497 0.908 9.55E-06 0.0000096 0 0 0 0.000218

Sulphur 0 0 0 0 0 0 1 0

Methane 0.773 0 0.818 0.822 0 0 0 0

Ethane 0.0861 0 0.091 0.0915 0 0 0 0

Propane 0.0181 0 0.0192 0.0193 0 0 0 0

n-Butane 0.0028 0 0.00296 0.00298 0 0 0 0

i-Butane 0.00226 0 0.0024 0.00241 0 0 0 0

n-Hexane 0.00028 0 0.000296 0.000297 0 0 0 0

n-Heptane 0.000108 0 0.000115 0.000115 0 0 0 0

n-Octane 0.0000618 0 0.0000654 0.0000657 0 0 0 0

Water 0.00485 0 0.00513 0 1 0 0 0.115

Mole Flow kmol/hr

Nitrogen 133 0 133 133 0 2250 0 2250

Oxygen 0 0 0 0 0 597 0 326

Carbon dioxide 437 42.4 394 394 0 0 0 42.4

Hydrogen sulphide 543 543 0.0986 0.0986 0 0 0 0.543

Sulphur 0 0 0 0 0 0 542 0

Methane 17930 0 17930 17930 0 0 0 0

Ethane 1060 0 1060 1060 0 0 0 0

Propane 153 0 153 153 0 0 0 0

n-Butane 17.9 0 17.9 17.9 0 0 0 0

i-Butane 14.5 0 14.5 14.5 0 0 0 0

n-Pentane 4.43 0 4.43 4.43 0 0 0 0

n-Hexane 1.21 0 1.21 1.21 0 0 0 0

n-Heptane 0.403 0 0.403 0.403 0 0 0 0

n-Octane 0.201 0 0.201 0.201 0 0 0 0

Water 100 0 100 0 100 0 542

Mole Frac

Nitrogen 0.00651 0 0.0067 0.00674 0 0.79 0 0.711

Oxygen 0 0 0 0 0 0.21 0 0.103

Carbon dioxide 0.0214 0.0725 0.0199 0.02 0 0 0 0.0134

Hydrogen sulphide 0.0266 0.927 4.97E-06 0.000005 0 0 0 0.000172

Sulphur 0 0 0 0 0 0 1 0

Methane 0.879 0 0.905 0.91 0 0 0 0

Ethane 0.0522 0 0.0537 0.054 0 0 0 0

Propane 0.0075 0 0.00772 0.00776 0 0 0 0

n-Butane 0.000878 0 0.000904 0.000909 0 0 0 0

i-Butane 0.00071 0 0.000731 0.000735 0 0 0 0

n-Pentane 0.000217 0 0.000223 0.000225 0 0 0 0

n-Hexane 0.0000592 0 0.0000609 0.0000612 0 0 0 0

n-Heptane 0.0000197 0 0.0000203 0.0000204 0 0 0 0

n-Octane 0.00000987 0 0.0000102 0.0000102 0 0 0 0

Water 0.00491 0 0.00506 0 1 0 0 0.172

10

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4. Conclusion

The chosen route was the Claus process fitted with a tail gas treating unit. The gas stream

going to the SA gas grid has a Wobbe index of 49.8 and contains 5 ppm of H2S. The overall

recovery of sulphur is 99.9% with the rest of the minimal uncovered H2S and CO2 sent to the

incinerator before being released to the atmosphere.

12

5. References

ROSENBERG, H., 2006. Topsoe wet gas sulphuric acid (WSA) technologyan attractive

alternative for reduction of sulphur emissions from furnaces and converters, Johannesburg: The

Southern African Institute of Mining and Metallurgy.

Abdel-Aal, H. K., Aggour, M. & Fahim, M. A., 2003. Petroleum and Gas Field Processing.

Dhahram: Marcel Dekker.

Christensen, D. L., 2009. Thermodynamic simulation of the water/glycol mixture, Aalborg:

Aalborg University Esbjerg.

Cline, C., Hoksberg, A., Abry, R. & Janssen, A., 2003. Biological process for H2S removal from

gas streams The Shell-Paques/Thiopaq gas desulfurization process. Norman (Oklohoma),

Conference Proceedings LRGCC.

MOKHATAB, S. et al., 2012. Handbook of Natural Gas Transmission and Processing. 2nd ed.

Gulf Professional Publishing: Gulf Professional Publishing.

RETIRED, G. H. et al., 2012. Ullmann's Encyclopedia of Industrial Chemistry. Natural Gas,

Volume 23, pp. 740-741.

Shell Global solutions, 2011. THIOPAQ O&G, s.l.: Shell Global Solutions International BV.