MOHD_FIRDAUS_BIN_CHE_ISMAIL.PDF

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ENHANCEMENT OF CARBON DIOXIDE (CO ) REMOVAL PRO CESS IN LIQUEFIED NATURAL GAS (LNG) PRODU CTION SYSTEM

MOHD FIRDAUS BIN CHE ISMAIL

A thesis submitted in fuilfihiment

of the requirements for the award of the degree of

Bachelor of Chemical Engineering Gas Technology)

Faculty of Chemical Natural Resources Engineering

Universiti M alaysia P ahang

APRIL 2010

P R P U S NJN IV E R S IT I M W AY S A PA H A N G

No. Pariggilan

Trdch

2Sc.

T i


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AB S TR AC T

Removal of CO from natural gas is currently a global issue apart from meeting

the customer s contract specifications and for successful liquefaction process in any

LNG project it is also a measure for reducing the global CO emission. The aims of this

research are to present a comprehensive review for removal of CO from natural gas to

meet LNG production specifications and explore the capability of Aspen HYSYS

process simulator to predict the CO removal process. A base case of typical CO

removal process is used to create a steady-state simulation using Aspen HYSYS 7.0

process simulator. Then, the simulation program is developed (Sulfinol process model)

to modify the physical, thermodynamics and transport properties of the gas and the

process units involved to improve process performance. Next, the constructed model

was then validated against the existing plant data which in turn provide information on

potential problem areas within the current simulation process. Moreover the model was

then used to determine the CO removal efficiency maximize the heavier hydrocarbon

recovery and reduce the power consumption at the optimum Sulfinol hybrid solution

composition. The best optimum simulation result shows that increasing of CO capturing

capacity in the Sulfinol contactor to almost 84 percent. This process also met the LNG

product specifications which is 1.69 mole percent of CO in the LNG product stream and

the reduction to about 11.14 percent of carbon dioxide slippage in sweet gas stream. In

term of economics, this process can safe heat consumption at stripper reboiler up to

18.39 percent and power consumption at pump up to 6.68 percent. For the heavierhydrocarbons recovery, this process can recover to almost 8.89 kgmole per hour. As a

conclusion, this research has achieved its objectives which are to improve the carbon

dioxide removal process and also to model Sulfinol process model in Aspen HYSYS

simulator. It is recom mend ed to run a sensitivity analysis of this mod el when the feed to

AG RU is increased in the case of bottleneck conditions.


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B S TR K

Penyingkiran karbon dioksida CO ) daripada gas asli kini telah menjadi isu

global selain daripada memenuhi permintaan spesifikasi kontrak daripada pelanggan dan

penentu keberjayaan proses penyejukkan di dalam proses penghasilan gas asli cecair.

Proses mi juga menjadi penanda ukur kepada penurunan kadar pembebasan karbon

dioksida secara global. Matlamat projek mi adalah untuk menunjukkan ulasan secara

komprehensif tentang proses penyerapan untuk penyingkiran karbon dioksida daripada

gas ash, juga untuk memenuhi spesifikasi produk gas asli cecair serta mendalami

keupayaan program simulasi Aspen HYSYS dalam meramal bans situasi operasi proses

penyingkiran karbon dioksida. Kes dasar daripada proses asas dalam penyingkiran

karbon dioksida digunakan untuk mencipta satu keadaan kekal simulasi menggunakan

program simuhasi Aspen HYSYS 7.0. Kemudian, program simulasi telah dibina iaitu

model proses Sulfinol untuk mengubah fizikal, termodinamik dan sifat pergerakan gas

serta unit yang terlibat di dalam proses un tuk men ingkatkan prestasi proses. Selepas itu

model yang telah dibina kemudian disabkan dengan melibatkan pembezan di antara

keputusan simulasi model dan data sedia ada daripada loji loji gas asli cecair) yang

telah beroperasi. Faedah kepada proses tersebut, proses simulasi dapat membantu

menyediakan data untuk masalah yang mungkin timbul seperti di dalam proses yang

sedia ada. Tambahan lagi, model simulasi mi kemudian digunakan untuk menentukan

kecekapan proses penyingkiran karbon dioksida, memaksimakan kadar penyerapan

hidrokarbon berat dan mengurang kan penggunaan k uasa pada kompo sisi pelarut Sulfinol

yang terbaik. Keputusan optimum terbaik simulasi menunjukkan peningkatan kapasiti

penangkapan karbon dioksida di dalam penyerap Sulfinol dengan kecekapan sehingga

84 peratus. Proses m i juga mem enuhi spesifikasi produk gas asli cecair iaitu 1.69 peratus

mol di dalam ahiran produk gas asli cecair dengan mengurangkan kadar karbon dioksida

yang terlepas hampir 11.14 peratus di daham aliran gas manis. Dalam terma ekonomi

v


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vii

pula proses mi dapat menjimatkan proses pemanasan di sistem penyingkiran sebanyak

18.39 peratus dan penggunaan kuasa di pam sebanyak 6.68 peratus. Untuk pemulihan

kadar hidrokarbon berat proses mi dapat memulihkan sehingga 8.89 kgmolar per jam.

Sebagai kesimpulan kajian mi telah mencapai objektif iaitu untuk menambah baik

proses penyingkiran karbon dioksida dan juga mereka model proses Sulfinol di dalam

simulasi Aspen HYSYS. Model proses mi disaran dijalankan analisa sensitif apabila

kadar gas asli masuk ke AGRU ditingkatkan dalam kes dan situasi bottleneck .


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T BL E OF CONT E NT S

CH PT E R ITLE G ERESE RCH TITLE

DE CL R T I ON

DEDIC TION

C K N O W L E D G E M E N T iv

BSTR CT v

BSTR K v i

T BL E OF CONT E NT viii

LIST OF T BLES x i

L I ST OF FI G URE Sxii

NOMENCL TURES xiii

NTRODUCTION

1 1 Natural Gas and Natural Gas Processing

1 1 1

istory and Development

1 1 2

nvironmental Impact on Acid Gas Removal

1 1 3

eneral Criterion for Acid Gas Remov al

1 1 4

ulfinol Process

5 rocess Simulation Software 81 2 Problem Statement 91 3 Objective 9

1 4 Scope of Study 10

viii


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lx

5 enefit and Significance of Study 2

ITER TUR E R EVIEW

2.1 Liquefied Natural Gas LN G) Production

2.1 .1 Gas Production and Field Developme nt 1 2

2.1.2 Onshore Gas Treatment 1 3

2.1.3 Liquefaction Process 1 3

2.1.4 LNG Shipping 1 4

2 5 Receiving and Re-gasification Terminal 1 4

2.1.6 End use as Fuel 1 4

2 .2 Carbon Dioxide Removal 1 5

2.2.1 Process Selection Factors 1 5

2.2.2 Physical Absorption Processes 1 6

2.2.3 Chemical Absorption Process 1 7

2.2.4 Memb rane Process 1 7

2.2.5 Adsorption Process 1 8

2.2.6 Cryogenic Process 1 9

2.2.7 Hybrid S olution 2

2.3 Aspen HY SYS Simulation Package 2 1

2 .4 Amine Based Process System 2 3

2 5 Previous Works 2 5

2 5 Modeling of Carbon Dioxide Absorber Using

Hot Carbonate Process 2 5

2.5.2 Rem oval of Carbon Dioxide by Absorption in

Mix Am ines: Modeling of Absorption in AqueousMD EA/MEA and AMP /MEA solutions 2 6

2.5.3 On the Mo deling and Simulation of Sour Gas

Absorption by Aqueous A mine Solutions 26


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x

E SE ARCH M E T HODOL OGY

3.1 Modeling of Flowsheeet for the Aspen HY SYS Simulation

of Sulfinol Process in Acid Gas Removal Unit AGRU ) 2 8

3.2 Identifying Controlling Factor 3 3

3.3 Modeling A ssumptions 3 4

3.4 Simulation of AGRU using Aspen HYSY S 3 4

3.5 Existing Performance Analysis of AGRU System 3 7

3.6 Form ulation of Sulfinol Hybrid Solution for Process

Improvement 3 8

3.7 Summ ary of Research Methodology 39

4

ESULTS AND DISCUSSION

4.1 cid Gas Removal Unit Modeling and Simulation usingSulfinol Process 4.2 omparison of Acid Gas Composition and Sw eet GasCom position after Man ipulation of Sulfinol Mo leComposition

2

4.3

dvantages of Sulfinol Process

7

CONCLUSION AND RECOMMENDATION

5 1 onclusion 95 ecommendation 0R E F E R E N C E S

APPE NDI CE S


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LIST OF TABLES

TABL E NO ITLE AGE2.1 Typical product specifications of LNG . 2

3.1 Typical mole composition of feed natural gas to AGRU 3 2

3 .2 Typical mole com position of Sulfinol solution 3 2

3 .3 Comparison of a formulation between SRK and PR in

Aspen HYSYS 3 6

3 .4 Feed natural gas composition to the AG RU 3 7

5 Sweet gas composition for Amine based process 3 8

3 .6 Form ulation of Sulfinol hybrid solution 3 8

4.1 Manipulation of composition by runs case 4 2

4.2 Data obtained from sim ulation before and after

manipulation of Sulfinol comp osition 4 3

4.3 Comparison of RUIN 3 with Based RUN 4 7

4.4 Comparison of RUN 4 w ith Based RUIN 47

x l


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LIST OF FIGURES

FIGURE NO ITLE AGE1.1 Process flow diagrams for natural gas processing 3

2.1 CryoCell process flow diagram for low CO / lean

Natural gas 2

2 .2 Summ ary of the previous works 2 7

3.1 Typical Amine-based process model 3 1

3.2 Sulfinol Hybrid Solution process model 3 1

3 .3 Summ ary of research methodology 3 9

4.1 Aspen HYSYS m odel of CO remov al Sulfinol process) 4 1

4 .2 Graph of h eavier hydrocarbons molar flowrate versus runcases 4 4

4.3 Graph of heat duty/pow er consumption versus run cases 4 4

4 .4 Graph of fresh sulfinol loading versus run cases 4 55 Graph of CO mole percent versus run cases 5

xli


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LIST OF NOME NCL TURES

AGRU Acid Gas Rem oval Unit

GPP : Gas Processing Plant

MLNG : Malaysia Liquefied Natural Gas

DEA : Diethanolamine

DGA : DiglycolamineDIPA : Diisopropanolamine

EOR : Enhanced O il Recovery

GP SA : G as P rocessors Suppliers A ssociation

LNG : Liquefied Natural Gas

NGL : Natural Gas Liquid

LPG : Liquefied Petroleum Gas

MDEA MethyldiethanolamineMEA Monoethanolamine

AM P : 2 amino 2 methyl 1 propanol

NOx : Nitrogen Dioxide

CO Carbon Dioxide

CS2 : Carbon D isulfide

COS : Carbonyl Sulfide

Ppmv : Part Per Million Volume

Ppm : Part Per Million

x : Sulfur Dioxide

TEA : Triethanolamine

TEG : Triethylene Glycol

TEMA Tubular Exchanger Manufacturer A ssociation.

VOC Volatile Organic Components

xlii


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xiv

H S Hydrogen S ulfideEOS

Equation of State

NH

Ammonia


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CHAPTER 1

INTRODUCTION

1 1

atural Gas and Natural Gas Processing

Natural gas, called the prince of hydrocarbons, is the fastest growing

energy source in the world. Natural gas also has been used for more than 150

years. As the m ost flexible of all primary fo ssil fuels, it can be b urned d irectly to

generate power and heat, converted to diesel for transportation fuel, and

chemically altered to produce a plethora of useful products. Such products

include liquid vehicle fuels, fertilizer, chemicals, and plastics. Best of all, it can

do all of this at competitive costs and from a plentiful supply, while emitting

significantly fewer h armful pollutants than other fuels (Chandra, 20 06).

1 1 1 H istory and Development

The natural gas used by consumers is composed almost entirely of

methane. However, natural gas found at the wellhead, although still composed

primarily of methane, is by no means as pure. Raw natural gas comes from three

types of w ells: oil wells, gas wells, and condensate w ells. Natural gas that com esfrom oil wells is typically termed 'associated gas'. This gas can exist separate

from oil in the formation free gas), or dissolved in the crude oil dissolved gas).

Natural gas from gas and condensate wells, in which there is little or no crude

oil, is termed non-associated gas . Gas wells typically produce raw natural gas by

itself, while condensate wells produce free natural gas along with a semi-liquid


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hydrocarbon condensate. Whatever the source of the natural gas, once separated

from crude oil (if present) it commonly exists in mixtures with other

hydrocarbons; principally ethane, propane, butane, and pentanes. In addition, raw

natural gas contains water vapor, hydrog en sulfide (1-1 S), carbon dioxide (CO2),

helium, nitrogen, and other compounds. Natural gas processing consists of

separating all of the various hydrocarbons and fluids from the pure natural gas, to

produce what is known as 'pipeline quality' dry natural gas. Major transportation

pipelines usually impose restrictions on the makeup of the natural gas that is

allowed into the pipeline and measure energy content in kJ/kg (also called

calorific value or Wobbe index).

For decades to come, gas will be the energy source of choice to meet

increasing demand and ever-greener worldwide environmental standards. When

natural wellhead or oil field associated gases are highly loaded with acid gases,

the difficulty facing most operators is what to do, how and when to best exploit

these poor quality resources. Many operators are confronted with these choices

around the world, especially in areas known to have highly sour oil and gas

reserves, such as the Caspian Sea region. Acid gas cycling and/or disposal by re-

injection offer a promising alternative to avoid sulfur production to a diminishingmarket and reduce CO emissions to the atmosphere simultaneously. To this end,

technologies of choice are those which offer maximum simplicity and require

least downstream processing intensity for reinjection.

With increasing demands for natural gas, natural gases containing H2S

and CO are also being tapped for utilization after purification. Natural gas

containing H S and CO are classified as sour , and those that are H S and CO

free are called sweet in processing practice. Produced gases from reservoirs

usually contains H S in concentrations ranging from .barely detectable quantities

to more than 0.30 (3,000 ppm) and for CO in concentrations ranging generally

between 1% to 4% (1,000-4,000 ppm). Most contracts for the sale natural gas

require less than 4 ppm (parts per million) of H S and also no less of heating

value ranging 920 to 980 Btu/scf (Mokhatab et. al, 2006). In gases devoid of


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2S, however, such concentrations are rare. 112S and CO2 are commonly referred

to as acid gas because they form acids or acidic solutions in the presence of

water Kum ar, 1987).

_ _idaxGasg a s ells TA I L G A S T R E AT I N 61AS TD

t h e r sZ e M O A L

Wa s t e w a t e r

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Berifleld process01 oF nit

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ol sieves

bsorption p roe

'Su lfinol prccss Activated Qrton Adsorption proce se O t h e r sftn N I N G U N I T SPfopahe M e r o x p r o ce s s

Suifrex pro ci es M c i s ie v e

L E G E N D :

T o ie O p i a l i h eF CTTON ATION TPII

Q e e t h s r i i c e rDepropn ierD b u t s r i i z e r

4 G L R E C O V E RTurboexpnix nddemethsnir

bxorp tion un :l 3rpi.nt1

ocated at gas we lls

ocated in gas proce ssing plant

Re d Indicates final sales p roducts

lue Indicates optional unit p roce sses available C ondensate is also c alled natural gasoline or c asinghe ad gasoline Pe ritanes + are pen tanes plus he avier hydrocarbon s and also called natural gasoline A cid gases are hydroge n sulfide and carbon dioxide Swe etening processes remov e me rcaptans from the N OL p roducts PSA is Pressure Sw ing Adsorption N O L is Natural Gas Liquids

Figure 1 1 Process flow diagrams for natural gas processing

Figure 1.1 above shows that the typical process flow diagram for natural

gas processing which in the system, there are many units such as Conden sate and

Water Rem oval Unit, A cid Gas Removal Unit, Dehydration Unit, NGL Recovery

Unit, Fractionation Train Unit and Sweetening Units. Natural gas is of little

value unless it can be brought from the wellhead to the customers, who may be

several thousand of kilometer from the source. Natural gas is relatively low in

energy content per unit volume, it is expensive to transport. The most popular

way to move gas from the source to the consumer is through pipelines Gou and

Ghalambor, 2005).


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l

However as transportation distance increases, pipelines become

uneconomical, Liquefied Natural Gas LNG), Gas to liquid and chemicals are

more viable options. Liquefaction process which is the transformation of natural

gas to liquid form involve operation at a very low Temperature -161C) and as

low as atmospheric pressure. At these conditions, CO can freeze out on

exchanger surface, plugging lines and reduce plant efficiency. Therefore there is

need for removal of CO before liquefaction process, this is done not to

overcome the process bottlenecks but also to meet the LNG product

specifications, prevent corrosion of process equipment and environmental

performance. There a re many a cid gas treating processes available for removal of

CO from natural gas such as Selexol Process, Rectisol Process and Flour

Process Ebenezer, 200 5).

1 1 2 Environmental Impact on Acid Gas Removal

Environmental concern over global warming due to greenhouse gas

emissions has given ever rising importance to the re-injection of CO removed

from natural gases; either for reutilization to Enhance Oil Recovery EOR) or

just simple disposal to a depleted reservoir to avoid atmospheric venting. The

removal of CO from natural gas process is comprised of operations required to

provide clean, pipeline quality gas and, LN G fee d gas. These operations in return

produce some wastes that must be managed in accordance with the applicable

environmental regulatory agency, to ensure operations with less impact to the

environment. Emissions associated with CO removal process includes; VOCs

volatile Organic compounds), carbon monoxide CO), sulfur oxides SOx),

nitrogen oxides NOx), particulates, ammonia NH 3), hydrogen sulfide H2S),metals, spent solvents, and num erous toxic organic compound s.

These pollutants may be discharged as air emissions, waste water, or

solid waste. All of these wastes are treated. However, air emissions are more

difficult to capture than waste water or solid waste. Thus, air emissions are the

largest source of untreated wastes released to the environment. Air emissions


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include point and non-point sources. Point sources are emissions that exit stacks

and flares which can be monitored and treated. Non-point Sources are fugitive

emissions which are difficult to locate and capture. Fugitive emissions occur

through valves, pumps, tanks, pressure relief valves, flanges, etc. Generally,

Identification and characterization wastes generated can be organized into three

major categories (Ebenezer, 2005) which are intrinsic wastes that are derived

from the natura l gas stream and are gene rated at facilities that receive and han dle

natural gas from production well head to storage field, treatment/processing;

wastes that are generated from equipment or unit operations required to treat

process and transport natural gas and maintenance; wastes resulting from

maintaining facility equipment in clean w orking order.

However, in this research the wastes/emissions identified above can be

eliminated by establishing optimum operating conditions that will improve

process environmental performance. This involves modification of process

operating parameters temperature, pressure and solvent composition) to reduce

the amount or toxicity of wastes that are generated. Operating at optimum

conditions ensure low hydrocarbon and chemical solvents) losses, thus reduces

waste accum ulated in the process units and emission to the environment.

1 1 3 General Criterion of Acid Gas Removal

Acid gas removal from the desired marketable hydrocarbons is the first

step in the sour gas production scheme. Many acid gas removal processes are

available to meet current pipeline sales gas specifications in H S and CO2

content. However for maximum versatility and economic benefit to an acid gas

removal to re-injection or disposal project the overall process scheme should

have quality characteristics amo ng which are; high capacity for acid gas removal

with minimum hydrocarbon co-absorption, easy regeneration by pressure let

dow n with minimal thermal input as co produced h eat energy of the Claus unit is

no longer available, liberation of acid gases at some pressure and preferably cold


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m

and dry and possibility to adapt regeneration pressures to interstage acid gas

compression.

Physical solvent processes give some but not all of the above qualities.

The Selexol process has a number of industrial references most of them for

synthesis gas de-acidification and some for natural gas treatment. A methanol

based refrigerated solvent process such as the Ifpex-2 process from the Ifpexol

technology matrix from Prosernat is also a good contender. However physical

solvents have a high affinity for hydrocarbons and the separated acid gas stream

contains large quantities of valuable hydrocarbon products. Chemical solvent

processes generally have a higher energy requirement than physical solvent

processes but are very selective towards hydrocarbons. Anyhow among theseproc esses, the Activated MDEA proc ess of total available today from Pro sernat)

which removes H S completely and CO as required and has a low energy

requirement. The important criterion for acid gas removal is not only to reduce

sales gas shrinkage but also to reduce re -com pression flowing capac ity. The cost

of acid gas removal is strongly dependent on feed acid gas content and

downstream acid gas compression re-injection network and re-injection well

com pletion design is strongly influenced by the acid gas quality.

1 1 4 Sulfinol Process

The Sulfinol process is a regenerative process developed to reduce H2S

CO COS and mercaptans from gases. The sulfur compounds in the product gas

can be reduced to low ppm levels. This process has been developed specifically

for treating large quantities of gas such as natural gas which are available at

elevated pressures. The Sulfinol process is unique in the class of absorption

proce sses because it uses a mixture of solvents, which allows it to behave as bo th

a chemical and a physical absorption process. The solvent is composed of

Sulfolane, DIPA and water. The acid gas loading of the Sulfinol solven t is higher

and the energy required for its regeneration is lower than those of purely

chemical solvents. At the same time it has the advantage over purely physical


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7

solvents that severe product specifications can be met more easily and co-

absorption of hydrocarbons is relatively low. The Sulfinol-M process has been

developed for selective absorption of H S, COS and mercaptans, while co-

absorbing only part of the CO . Deep removal of CO

in LNG plants is another

application. Integration of gas treating with the SCOT solvent system is an

option.

The feed gas is contacted counter-currently in an absorption column w ith

the Sulfinol solvent. The regenerated solvent is introduced at the top of the

absorber. The sulfur compounds loaded solvent rich solvent) is heated by heat

exchange with the regenerated solvent and is fed back to the regenerator where it

is further heated and freed of the acid gases with steam The acid gases removed

from the solvent in the regenerator are cooled with air or water so that the major

part of the water vapor they contain is condensed. The sour condensate is

reintroduced into the system as a reflux. The acid gas is passed to the sulfur

recovery plant Claus plant) in which elemental sulfur is recovered. The

application of a flash vessel is optional; it depends on the heavier hydrocarbon

content of the feed gas. The application of a reclaimer is also optional and

depends on the amount of non-regenerative compounds in the solvent.

Sulfinol process has a very wide range of treating pressures and

contaminant concentrations can be accommodated. Natural gas pipeline

specifications are easily met. Removal of organic sulfur compounds is usually

accomplished by the solvent circulations as set by H S and CO . In LNG plants aspecification of 5 ppm CO prior to liquefaction is attained without difficulty.

The utility consumption varies widely with feed gas co mposition and p roduct gas

specification The features of this process are; removal of H S COS and organic

sulfur to natural gas pipeline specification, low steam consumption and solvent

circulation, low corrosion rates, selective removal of H S in some natural gas

applications smaller equipment due to low foaming tendency and high on-stream

factor. For the references, more than 200 Sulfinol units ranging in capacity from


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8

10,000 Nm 3/d to 32,000,000 Nm 3/d are in operation throughout the world,

demo nstrating the reliability of the proce ss.

1 1 5 Process Simulation Software

Today, computer-aided process simulation is nearly universally

recognized as an essential tool in the process industries. Indeed, simulation

software play a key role in: process development - to study process alternatives

assess feasibility and preliminary economics, and interpret pilot-plant data;

process design to optimize hardware and flowsheets, estimate equipment and

operating cost and investigate feedstock flexibility; and plant operation to reduce

energy use, increase yield and improve pollution control. The ability of the

natural gas especially LNG option to continue to compete with existing and

emerging gas monetization, option will depend on the industry's success in

reducing cost throughout the LNG value chain and maintaining exceptional

safety, reliable and less environmen tal impact operations Ebenezer, 2005).

This research therefore summarizes the processes available and suitable

for the enhancement of removal of CO from natural gas in Acid Gas Removal

Unit (AGRU) to meet the LNG stringent specification of about 50-100 ppmv or

2-3 CO concentration in the product stream. Different processes scalability,

advantages and disadvantages will be highlighted. Simulation of a typical amine

solvent based CO removal plant using Aspen HYSYS process simulator to

establish optimum operating conditions that will improve process -environmental

performance will be considered in detail.


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1 2 roblem StatementThe existing AGRU in the gas processing plant usually use Benfield

process GPP A) and Amine-Based solution process GPP B). In the MLNG

production plant, it also uses Amine-Based solution process Jamaludin et. al.,

2005). Benfield process generally causes stress corrosion of the unit operation

and has high tendency of foaming while Amine-Based solution process can not

handle varies feed composition of sour natural gas and have high tendency to

degrade Ebenezer, 2005 . Therefore, there is slippage of C O and will end up in

the liquid product. Through liquefaction process, CO will solidify under

extreme low temperature of liquefaction process -161 C) and cause severe

problem which freezing that can cause equipment plugging in the liquefaction

section. Failure to reduce the slippage of CO may require more cost for the

liquid product treating and for the maintenance cost of the liquefaction process

section. Formulation of suitable absorption solvent combining physical and

chem ical solvents that can treat acid gas or sour gas is crucial. How ever, there is

not much d evelopment in this effort such as process modeling and improvem ent.

1 3

bjective

This research contains two main objectives. The first objective of this

research is to model, design and simulate Acid Gas Remo val Unit AG RU) using

special solvent which is a formulation between chemical and physical solvents

for absorption process called Sulfinol process. The second objective is to

enhance the method of carbon dioxide CO ) removal from sour natural gas by

manipulating the combination of m ole composition of Sulfinol process before the

treated natural gas enters the L NG production facilities.


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1

1 4 cope of studyThis research will be focusing on the simulation analysis using Aspen

HYSYS. This research will be done based on the case study from the industrial

problem and the established Acid Gas Removal Unit (AGRU) process flow

diagrams. Enhancement and improvement of the existing AG RU are being m ade

in terms of solvent efficiency that can handle varies upstream natural gas feed

composition and minimize the slippage of the CO in the liquid product stream

Heavier hydrocarbons loss and energy consumption issues also will be

emphasized throughout this research.

1 5

enefit and Significance of Study

In this research, the motivations are to increase the efficiency and

performance of the AGRU for the LNG production system and natural gas

processing instead of spent more co st for the liquid produc t treatment to meet the

specifications. Typical AGRU system has many operational problems such as

foaming and corrosion, solvent loss and degradation, therefore the selection of

the efficient solvent is very important for the cost-cutting strategies. This

research also concern about environment and the current issue; global warming

by greenhouse gas emission which is CO . Therefore there are needs to process

the sour gas to recover CO from the sour natural gas for the other benefit use.

The usage of natural gas have large consumers and producers of utilities

therefore these are studies to investigate and create solutions for the utilities in

order to improve availability and reduce pollution and more to environmental

friendly towards green world .


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CHAPTER 2

LITERATURE REVIEW

2.1

iquefied Natural Gas LNG ) Production

Liquefied Natural Gas (LNG) Production is one of the fastest growing

processes nowadays. Despite its rapid growth in recent years, LNG remains a

relatively small contributor to world gas demand (under 7% of the total in 2005)

and even to total internationally traded gas which LNG trade is said to account

for about 24.2 of international natural gas trade (Ebenezer, 2005 . L N G

production value chains include the following steps; which are Gas Production

and Field Processing, Onshore gas treatment, Gas Conversion via Liquefaction,

LNG Shipping, Receiving Terminal and end use as fuel (power generation,

fertilizer industry, gas distribution, etc). Table 2.1 shows the typical product

specifications for LNG. This general specification is use in the processing

practice throughout the world of natural gas processing especially LNG

production process


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2

Table 2 1 Typical product specifications of LNG

Components Limit Maximum)Hydrogen S ulfide 3-4 ppmvTotal sulfur 30 m illigrams per norm al cubic meter

Carbon dioxide 50-100 ppmv or 2-3 mole

Mercury0.01 micrograms per normal cubicmeter

Nitrogen 1 moleWater Vapor 1 ppmvBenzene 1 ppmvEthane 6-8 m olePropane 3 moleButane and heavier 2 molePentane and heavier 1 moleHigh Heating Value 1050 Btulscf (Europe and USA)

>1100 B tulscf (East Asia)

2 1 1 Gas Production and Field Development

The exploration and production of gas is the starting point for all gas

utilization options. The source of natural gas feed to the LNG plant could be

either associated gas or non-associated gas. Natural gas is naturally occurringgaseous mixture or hydrocarbon components and consists mainly of methane.

Other constituents include ethane, propane and butane which refer to as liquefied

petroleum gas (LPG) and condensate which are heavier hydrocarbons. The

compositions of the gas differ from one gas reservoir to another. The gas

production step includes some field processing depending on the nature of the

gas source and the requirement for pipeline transport to liquefaction site.

Typically, field processing is needed to prevent hydrocarbon drop-out, hydrate

formation or corrosion in the pipeline to the liquefaction site (Ebenezer, 2005).


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2 1 2 Onshore Gas Treatment

The gas from the reservoir may also contain components such as

nitrogen carbon dioxide and sulfur compounds. The feed gas has to be treated

for removal of impurities before it can be liquefied. Hence onshore gas treatme ntis required to meet the specification set by the LNG buyers as well as

requirements for the LNG liquefaction process. The onshore gas treatment

typically comprises of gas reception facilities acid gas removal and disposal

section gas dehydration mercury removal and particle filtration. The gas

reception facilities section provided for the removal of liquid entrainment

gathering the system due to condensation and pressure reduction of the fluid

Joule Thomson effect). At this section the pressure of the LNG feed is adjustedto meet the requirement of the liquefaction facilities. If the pressure is lower than

that of the liquefaction facilities a compressor may be installed to beef up the

pressure difference. Acid gas rem oval and disposal section is provided to rem ove

acid gases CO , H S and other sulfur comp onents) from the feed gas. The extent

of removal is influenced by the LNG specification and the requirement of the

liquefaction process. The dehydration section removes water from the fees gas.

Water vapor must be removed to prevent corrosion and freezing in the

liquefaction process of the plant that operate at cryogenic condition. Trace. of

mercury in the feed gas which attacks piping and equipment made from

aluminum and aluminum com pounds is removed in the mercury removal section.

Aluminum is universally used for the construction of cryogenic equipment.

Filtration of the gas stream following the mercury removal unit is essential to

prevent particle into the liquefaction section of the plant, thus prevent equipme nt

plugging Ebenezer, 2005).

2 1 3 Liquefaction Process

The liquefaction section is the heart of LNG value chain. The process

involved cooling the clean feed gas in succession Pre-cooling, Liquefaction and

Sub-cooling) to -161C using mec hanical refrigeration. The refrigerants for LN G

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