Gas Processing Journal - University of Isfahanjournals.ui.ac.ir/article_22905_4533094aeaf2ade2cfaee0c...LPG and fuel gas is simulated using the Aspen HYSYS v. 8.8 simulator. The steam

Gas Processing Journal

Vol. 6, No. 1, 2018, pp. 1-20

http://gpj.ui.ac.ir

DOI: http://dx.doi.org/10.22108/gpj.2018.111048.1028

___________________________________________

*Corresponding Author.

Authors’ Email Address: 1 M. Jafari ([email protected]),

2 S. Ashtab ([email protected]),

3 A. Behroozsarand ([email protected]),

4 K. Ghasemzadeh ([email protected]),

5 D. A. Wood ([email protected])

ISSN (Online): 2345-4172, ISSN (Print): 2322-3251 © 2018 University of Isfahan. All rights reserved

Plant-wide Simulation of an Integrated Zero-Emission Process to

Convert Flare Gas to Gasoline

Mostafa Jafari 1, Sadaf Ashtab 2, Alireza Behroozsarand 3, Kamran Ghasemzadeh 4

and David A. Wood 5*

1,2,3,4 Faculty of Chemical Engineering, Urmia University of Technology, Urmia, Iran 5 DWA Energy Limited, Lincoln, LN5 9JP United Kingdom

Received: 2018-05-18 Revised: 2018-05-28 Accepted: 2018-06-09

Abstract: The Gas to Gasoline (GTG) process includes conversion of natural, flare, and

associated gas into synthetic fuels that can be compositionally upgraded and adjusted into

different useful hydrocarbon fuels including gasoline, liquid petroleum gas (LPG), and fuel

gas. Commonly, the GTG process involves three stages: 1) Synthesis gas (syngas) production

unit 2) Methanol production unit 3) Methanol to Gasoline production unit (MTG). In this

study, an integrated Flare Gas to Gasoline (FGTG) process for converting flare gas to gasoline,

LPG and fuel gas is simulated using the Aspen HYSYS v. 8.8 simulator. The steam methane

reforming (SMR) unit, the syngas to methanol unit, and the MTG unit are configured for

simulation as an integrated FGTG process. In order to reduce carbon dioxide gas emissions to

the atmosphere, a novel closed arrangement for the FGTG process (recycling configuration) is

described and simulated. The simulation results demonstrate that by recycling all gas

emissions, such as flare and off gas from the methanol and MTG units back into the process

cycle, gasoline and LPG productivity can be increased on average by about 53% and 10%,

respectively, compared to a base FGTG configuration that does not involve such recycling. The

integrated simulation is supported by sensitivity analysis based on FGTG plants of various

natural gas capacities (from 70,000 to 130,000 lb./hr.) as the adjustable (independent) variable

and gasoline, LPG, and fuel gas selectivity as the dependent variables. Results of the

simulation cases reveal that the total productivity of the integrated FGTG process could be

increased in terms of flare gas mass flow, with the selectivity of products remaining

approximately fixed for different plant capacities (i.e., at 75% for the gasoline product).

Moreover, the utilities and energy consumption of the FGTG process is compared for several

sensitivity cases. The results reveal that by increasing the capacity of the gas feed (natural gas

mass flow) the Energy Index (i.e., total utilities consumption to product flow rate) decreased

by about 8% and 47% in the base and recycling configurations, respectively. This finding

suggests that an FGTG plant becomes more energy efficient at in higher-capacity plants.

Keywords: Flare gas utilization; process simulation; membrane applications; energy index;

flare gas to gasoline (FGTG); energy and emissions efficiency

1. Introduction

Humans need energy to power our technology

and to broaden and improve quality of life

(Fawole, Cai, & MacKenzie, 2016). Natural gas

will continue over coming decades to provide

an essential component of the global primary

energy mix providing economic growth in

many developing and developed countries

(Tabak, Chitnis, McGihon, & Zhao, 2009).

Until now, there are primarily two

commercially viable methods for converting

natural gas into liquid fuels (GTL) through

intermediate gasification processes (Fig. 1).

These are: 1) Fischer-Tropsch Synthesis (FTS),

discovered in Germany in the 1920’s using coal

as feedstock. FTS can produce a range of

valuable hydrocarbon liquids and waxes from

various hydrocarbon feedstock (e.g., coal,

natural gas or biomass) using different

catalysts and pressure-temperature condition.

2) Hydrocarbon conversion to gasoline (HTG)

processes with methanol production as an

2 Gas Processing Journal, Vol. 6, No. 1, 2018

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intermediate step are established, but less

extensively commercialized than the FTS

methods.

Minimizing or eliminating emissions of

carbon dioxide (CO2), a major greenhouse gas

(GHG) arising from anthropogenic activities, is

also now a priority for most hydrocarbon

processing technologies, in order to inhibit its

potential climate change impacts. Gas flaring

is the process of burning-off associated gas

from producing oil wells, hydrocarbon

processing plants or refineries, either as a

means of disposal or as a safety measure to

relieve pressure (Emam, 2015). Flaring makes

a significant contribution to CO2 emissions.

Gas flaring involves the rapid oxidation and

combustion of the component gases contained in

natural gas leading to the release of CO2 into

the atmosphere. The composition and quantity

of flare gas determines the amount of CO2 and

other combustion products emitted as

pollutants into the atmosphere. In addition, the

prevailing meteorological conditions, flare size

and design and other combustion variables also

determine the exact quantity of CO2 emitted

during the flaring process (Giwa, Nwaokocha,

Kuye, & Adama, 2013). Hydrocarbons,

including natural gas, burnt in thermal power

plants provide a major source of CO2 emissions

entering the atmosphere, and reducing those

emissions has become globally one of our major

challenges in the twenty-first century (Er-rbib,

Bouallou, & Werkoff, 2012). Methane (CH4), the

major constituent of natural gas is the second

most abundant GHGs, after CO2, but with far

more potent greenhouse impacts on the upper

atmosphere, making the venting and fugitive

emissions of natural gas even more important

to avoid. Identifying methods that can reduce

the concentration of methane and CO2 released

to the atmosphere is therefore a priority for

many researchers. Converting methane to

alternative forms more-easily handled energy,

such as methanol, is one potential method for

achieving this [6].

Several methods have been proposed for

conversion of flare gas to valuable products

based on two categories a) separation b)

conversion:

1- Power generation (conversion mode,

(Heidari, Ataei, & Rahdar, 2016; Ojijiagwo,

Oduoza, & Emekwuru, 2016))

2- LNG production (separation mode,

(Soltanieh, Zohrabian, Gholipour, & Kalnay,

2016))

3- CNG production (separation mode,

(Soltanieh et al., 2016))

4- LPG production (separation mode,

(Hajizadeh, Mohamadi-Baghmolaei, Azin,

Osfouri, & Heydari, 2018))

5- GTL process (conversion mode, (Wood,

Nwaoha, & Towler, 2012))

6- GTG process (conversion mode)

However, as a result of the increasing

global demand for transport fuels and the

adverse effects of fluctuating energy prices,

searching for alternatives to crude oil has also

become a priority (Fu, Chang, Shao, & Li,

2017). Furthermore, Gasoline is an important

liquid hydrocarbon-based fuel derived

primarily from fractional distillation of the

petroleum fractions in crude oil conducted in

refineries (Galadima & Muraza, 2015).

Therefore, natural gas to gasoline (GTG)

process is one of the HTL and GTL

technologies of particular interest to the

energy sector. Fischer-Tropsch Synthesis

(FTS) and Gas to Gasoline (GTG) are the two

main GTL technologies being evaluated

commercially at this time [9].

A flow diagram distinguishing the

component processes of the two primary GTL

technologies is illustrated in Fig. 2. According to

this figure, a synthesis gas production unit is

the primary stage for both technologies, but

their subsequent process stages are distinct.

The main difference between FTS and GTG are

their hydrocarbon products. Naphtha, diesel

and long-chain hydrocarbon waxes are the main

products of FTS [10], whereas gasoline is the

primary hydrocarbon product of GTG. Table 1

list of final products and composition of two

GTL processes compared with the GTG process

in a historic New Zealand plants are (Maiden,

1988). The naphtha /gasoline selectivity of the

GTG process in Table 1 is about 82.3%, while it

is only about 36% or 19% for the high-

temperature and low-temperature FTS

processes, respectively.

Published studies have identified key

characteristics of the GTL process such as

catalyst type and synthesis (Nakamura, Wood,

Hou, & Wise, 1981), reactor types (Schanke et

al., 2001), energy and exergy analysis (Iandoli &

Kjelstrup, 2007; Van Vliet, Faaij, & Turkenburg,

2009). Several modifications have been developed

over the years to improve the FTS process,

including those introduced for the Qatar Pearl

Plant, the largest FTS plant in the world, by

Qatar Petroleum and Shell commissioned in

2011 [15]. However, most of these improvements

have focused on catalysts and reactor

configurations in order to increase the liquid

production, increase energy efficiency and

decrease the CO2 formation during this process.

Plant-wide Simulation of an Integrated Zero-Emission Process to Convert Flare Gas to Gasoline 3

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F-T Refining

MeOH MTG

NGL/

Sour gas removal liquefaction

Natural Gas or Coal

Liquid Fuels

Figure 1. Routes for coal and natural gas to liquid

Table 1. Comparison between MTG & FT units of New Zealand [11]

Components Fischer-Tropsch

(high temperature) %

Fischer-Tropsch

(Low-temperature) % Methanol to gasoline %

Methane 8 5 0.7

Ethylene 4 ---- ----

Ethane 3 1 0.4

propylene 11 2 0.2

propane 2 1 4.3

Butylene compounds 9 2 1.1

butane 1 1 10.9

Naphtha 36 19 82.3

Gas oil 19 22 ----

Wax 5 46 ----

Oxygenates 5 1 0.1

Figure 2. GTL and GTG process block diagram

The environmental benefits of using

transport fuels produced by FTS based GTL

technologies are well known [9]. These

include low emissions of sulfur compounds

and NOx. In addition, the lower aromatic

content of GTL fuels reduces their toxicity

and the particulate matter generated when

they are combusted, in comparison to typical

oil refinery produced fuels. The higher Cetane

number (70-80) of FTS diesel enables superior

performance in a range of diesel engines (Bao,

El-Halwagi, & Elbashir, 2010).The ability of

FTS processes to produce highly valued non-

fuel products such as lubricants and waxes

further adds to the value of their product

slates. Behroozsarand and Zamaniyan

(Behroozsarand & Zamaniyan, 2017a), have

recently simulated an optimized integrated

4 Gas Processing Journal, Vol. 6, No. 1 2018

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GTL process for converting of flare gas to

valuable hydrocarbons such as gasoline and

diesel. This study builds upon that work.

It is clear from Fig.2 that there are

similarities between the early steps in the

FTS and GTG processes; both require

synthesis gas production. Moreover, the

methanol production process from synthesis

gas is a well-established commercial

technology with multiple technology

suppliers. Therefore, the key distinctive

production technology stage in the GTG

process is the methanol to gasoline (MTG)

stage. Three companies are the main patent

holders of the MTG process:

1) ExxonMobil, USA

2) Holder Topsoe, Denmark

3) Primus Green Energy (syngas to

gasoline STG+) for small-scale applications

In this study, an integrated FGTG process

for converting flare gas to gasoline, LPG and

fuel gas is simulated using the Aspen HYSYS

v. 8.8 simulator. The steam methane reforming

(SMR) unit, the syngas to methanol unit, and

the MTG unit are configured for simulation as

an integrated FGTG process. In order to

reduce carbon dioxide gas emissions to the

atmosphere, a novel closed arrangement for

the FGTG process (recycling configuration) is

described and simulated. Several researchers

have been reported in that Aspen HYSYS is

employed for simulation of different processes.

Ghorbani and et al. (Hamedi,

Shirmohammadi, Ghorbani, & Sheikhi, 2015)

used Aspen HYSYS software for Advanced

Exergy Evaluation of an Integrated Separation

Process with Optimized Refrigeration System.

Also, Ghorbani and et al. in other work

(Ghorbani, Hamedi, & Amidpour, 2016)

utilized this software for exergoeconomic

evaluation of an integrated nitrogen rejection

unit with LNG and NGL co-production

processes based on the MFC and absorption

refrigeration systems. Shariati Niasar and et

al. (Shariati Niasar et al., 2017) have been

used Aspen HYSYS and plus for simulation of

ammonia water cycle in proposing of

superstructure of cogeneration of power,

heating, cooling and liquid fuels using

gasification of feedstock with primary material

of coal for employing in LNG process.

2. Process Description of GTG

Simulated plant wide GTG process in this

study has three subsections (Fig. 3):

1) Syngas production unit

2) Methanol production unit

3) MTG unit (production and gasoline

separation)

2.1. Synthesis Gas Production Unit

The initial stages in the GTG process are

similar to FTS in producing synthesis gas

(H2+CO). The ratio of hydrogen to carbon

monoxide (H2:CO) in producing synthesis gas

product is the key difference between the

synthesis gas production units of the two

processes. In GTG plants the second process is

the production of methanol for which 3.8 is the

suitable H2:CO ratio, whereas a 1.0-2.5 H2:CO

ratio favors the FTS process. The synthesis gas

product in the GTG process passes directly to a

methanol production plant, whereas it passes

into a FT unit in the FTS process. Two

sequential reactors (conversion and

equilibrium types) are considered [16] for

simulating the steam reforming process to

convert methane into synthesis gas using the

Aspen HYSYS V.8.8 simulation environment

(Fig. 4).

The first reactor is operated as a pre-

reformer for reforming the heavier

hydrocarbon components (i.e., natural gas

liquids). The second reactor reforms the

methane. All conversion and equilibrium

reactions producing H2 and CO involved in

these reactors are listed in Table 2 and 3,

respectively (Behroozsarand & Zamaniyan,

2017a).

Figure 3. Block Flow Diagram (BFD) of simulated FGTG process


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Table 2. List of conversion type reactions of primary steam reformer used in simulation model

(Behroozsarand & Zamaniyan, 2017a)

Number Kinetic equation Conversion value (%)

1 225.0 COOCO

100

2 OHOH222

5.0

100

3 2262522 HCOOHHC

100

4 2283733 HCOOHHC

100

5 22104944 HCOOHHCi

100

6 22104944 HCOOHHCn

100

7 221251155 HCOOHHCn

100


100


100

10 221881788 HCOOHHCn

100

11 222091999 HCOOHHCn

100

12 222210211010 HCOOHHCn

100

Table 3. List of equilibrium type reactions of secondary steam reformer used in simulation model for steam

methane reformer (SMR) process unit for FGTG (Behroozsarand & Zamaniyan, 2017a)

Number Kinetic equation Equilibrium constant*

1 224 2HCOOHCH

(Steam methane reforming)

T(0C) Keq

93 7.8×-19

149 6.8×-15

204 7.8×-12

260 2.2×-9

316 2.2×-7

371 1.0×-5

427 2.7×-4

482 4.3×-3

538 4.9×-2

593 4.1×-1

649 3

704 14

760 63

816 243

871 817

927 2464

982 6755

1038 17010

1093 39670

1149 86640

1204 178400

2 222 HCOOHCO

(Shift reaction)

T(0C) Keq

93 4523

149 783.6

204 206.8

232 119

260 72.75

288 46.7

316 31.44

343 22

371 15.89

399 11.8

427 9.03

454 7.05

482 5.61

510 4.55

538 3.75

566 3.13

593 2.65

621 2.27


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Number Kinetic equation Equilibrium constant*

649 1.97

677 1.72

704 1.51

732 1.34

760 1.2

788 1.08

816 0.98

843 0.89

871 0.82

899 0.75

927 0.70

954 0.65

982 0.60

1038 0.53

1093 0.47

1149 0.42

1204 0.38

* All equilibrium data come from Aspen HYSYS software reaction library.

Figure 4. Schematic of SMR Process as Configured in the Aspen HYSYS software environment

Figure 5. Schematic of MeOH process as configured in the Aspen HYSYS software environment


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Figure 6. Schematic of MTG Process as Configured in the Aspen HYSYS Software Environment

2.2. Methanol Production Unit

Several companies have patented methanol

processes, including “Linde Engineering”,

“Johnson Mattey Process Technology”,

“TOYO”, “Lurgi”, and others. In most

commercial methanol production plants, the

yield of produced methanol is more 98%. The

main reactions involved in methanol reactors

are exothermic for an equilibrium model

involving three reactions (Eq. 1 to 3).

This process may be summarized as follows:

CO +2H2↔CH3OH (1)

CO +H2O↔CO2+H2 (2)

2CH3OH↔CH3OCH3+H2O (3)

As the conversion process is limited by the

equilibrium achieved for each pass of the

reactants through the reactor, a simple loop

arrangement recirculates the unreacted syngas

back through the methanol converter. Fig.5

provides schematic diagram of the methanol

conversion process in the Aspen HYSYS

software environment.

2.3. Methanol to Gasoline (MTG) Unit

Main component process of a GTG plant is the

MTG process unit. Mobil operated the first

MTG plant in New Zealand from 1987 to 1995

[11, 19], producing a Sulphur-free gasoline of

approximately 92-RON quality, based on a

process developed in the 1970’s [20]. Mobil's

novel synthetic gasoline process, based on the

conversion of methanol to hydrocarbons over

zeolite catalysts [19, 20], was a key departure

from the Fischer-Tropsch process

(Behroozsarand & Zamaniyan, 2017a).

MTG reaction paths are summarized by Eq.

4 to 6:

2CH3OH↔CH3OCH3+H2O (4)

Methanol Di-Methyl Ether

CH3OH, CH3OCH3 → Light Olefins+H2O (5)

Methanol, Di-Methyl Ether

Light Olefins→C5+Olefins

Paraffin

C5+OlefinsC→Naphthenes ~Gasoline (6)

Aromatics

In the patented commercial-scale MTG

process, methanol is vaporized and fed into the

fixed bed dimethyl ether (DME) reactor [19],

where it is catalytically equilibrated to a

mixture of DME, methanol and water. The

catalyst used for the MTG process is of

customized alumina at a reaction temperature

and pressure of 310-320°C and about 26 bar,

respectively. A schematic of the MTG process

configured in the Aspen HYSYS software

environment is illustrated in Fig. 6. This is

applied to an integrated plant wide FGTG

process for converting of flare gas to

hydrocarbon fuel products including gasoline

and LPG.

3. GTG Process Simulation and

Results

The FGTG process is simulated using four

model packages of the Aspen HYSYS 8.8

process simulator:

1) Syngas Basis (PRSV model,

(Behroozsarand & Zamaniyan, 2017b))

2) DME Basis (UNIQUAC or NRTL models,

(Kim, Kim, Cho, & Yoon, 2010))


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3) Methanol Basis (PRSV, (Van-Dal &

Bouallou, 2013))

4) MTG Basis (Peng-Robinson, (Kim et al.,

2010))

Models 1, 2, 3, and 4 include of 104, 58, 9,

and 58 components, respectively. Figs. 3, 4, 5,

and 6 provide process flow diagrams of the

simulated FGTG process in Aspen HYSYS v.

8.8 software.

Fig. 4, illustrates how the primary flare gas

is separated into two flow streams:

a) Gas for steam methane reforming (SMR)

feed

b) Gas for fuel gas to the furnace burners.

The ratio a: b is about 64:36. This ratio

confirms that more than one-third of the flare

input gas is consumed as fuel for the furnace

burners in the SMR process. The H2/CO ratio

of 3.8 is the main specification of synthesis gas

(syngas) product. However, there are three

outlet streams from the SMR unit:

1) Reformed gas (syngas)

2) High pressure steam (HPS)

3) Separated sour water

3.1. Validation of the FGTG Process

Simulation

Before simulation of FGTG process it is

necessary to validate the overall simulation

procedure and results. For this reason, a

published MTG process case (Jones & Zhu) is

simulated using the proposed Aspen HYSYS

8.8 process configuration, and the simulation

results compared to the data published for a

biomass to gasoline simulation case study

employing the MTG process [21]. According to

Table 4, the comparison of results show that

our proposed simulation configuration involves

reasonable deviations from the data published

for the published case study. Deviation error

values in Table 4 for the gasoline and LPG

streams are the most relevant as these are the

main products of a MTG plant. The maximum

deviations (our simulation configuration

versus published case study [21]) for the LPG

and gasoline streams are: 283.47 lb/hr for the

propane product (representing 26% of the total

error for the LPG flow stream) and 165.22

lb/hr for the cis2-Butene product (representing

15% of the total error for the gasoline flow

stream), respectively.

Table 4. Comparison of simulated MTG unit and published MTG case study [17]

Stream Name Methanol

to MTG

Component Mass Flow (lb./hr.)

Methanol 91637.9

H2O 2256.1

Hydrogen 4.6855

CO2 1466.74

Methane 304.972

Ethylene 0.0286

Ethane 0.0749

Nitrogen 3.9133

P (psia) 414.7

T(F) 102

Mass Flow (lb./hr.) 95674.41

Stream Name LPG

Reference

LPG

Simulation Error

│Reference-Simulation│

Error/Total Error

(%) Component Mass Flow (lb./hr.)

Mass Flow

(lb./hr.)

Methanol 0.00 0.00 0 0%

H2O 0.00 0.00 0 0%

Hydrogen 0.00 0.00 0 0%

CO2 0.00 0.00 0 0%

Methane 0.00 0.00 0 0%

Ethylene 0.00 0.00 0 0%

Ethane 0.00 0.00 0 0%

Propene 10.41 0.83 9.58 1%

Propane 1437.24 1153.77 283.47 26%

i-Butane 3411.84 3453.92 42.08 4%


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n-Butane 1013.89 1220.44 206.55 19%

cis2-Butene 564.75 753.76 189.01 17%

i-Pentane 993.96 754.61 239.35 22%

n-Pentane 65.46 34.94 30.52 3%

tr2-Pentene 116.47 39.73 76.74 7%

Cyclopentane 0.14 0.54 0.4 0%

22-Mbutane 0.34 1.21 0.87 0%

23-Mbutane 0.01 0.18 0.17 0%

2-Mpentane 0.01 0.11 0.1 0%

3-Mpentane 0.00 0.05 0.05 0%

Mcyclopentan 0.00 0.00 0 0%

Benzene 0.00 0.00 0 0%

24-Mpentane 0.00 0.00 0 0%

Cyclohexane 0.00 0.00 0 0%

2-Mhexane 0.00 0 0%

3-Mhexane 0.00 0.00 0 0%

224-Mpentane 0.00 0.00 0 0%

Mcyclohexane 0.00 0.00 0 0%

33M-1-butene 6.44 2.64 3.8 0%

Toluene 0.00 0.00 0 0%

233-Mpentane 0.00 0.00 0 0%

23-Mhexane 0.00 0.00 0 0%

3-Mheptane 0.00 0.00 0 0%

23M-1-butene 0.02 0.09 0.07 0%

p-Xylene 0.00 0.00 0 0%

m-Xylene 0.00 0.00 0 0%

o-Xylene 0.00 0.00 0 0%

m-Cymene 0.00 0.00 0 0%

23M-2-butene 0.00 0.00 0 0%

diM-Ether 0.00 0.00 0 0%

124-MBenzene 0.00 0.00 0 0%

1245-M-BZ 0.00 0.00 0 0%

P (psia) 110.00 110.00 1086.72

100 T(F) 117.82 118.20 Total Error

Mass Flow (lb./hr.) 7620.98 7416.82

Stream Name Gasoline

Reference

Gasoline

Simulation Error

│Reference-Simulation│

Error/Total Error

(%) Component Mass Flow (lb./hr.)

Mass Flow

(lb./hr.)

Methanol 0 0 0.00 0.0%

H2O 0 0 0.00 0.0%

Hydrogen 0.004 0 0.00 0.0%

CO2 0 0 0.00 0.0%

Methane 0 0 0.00 0.0%

Ethylene 0 0 0.00 0.0%

Ethane 0.0004 0 0.00 0.0%

Propene 0 0 0.00 0.0%

Propane 0.0174 0.0004 0.02 0.0%

i-Butane 28.686 0.9056 27.78 2.5%

n-Butane 163.822 3.3048 160.52 14.6%

cis2-Butene 169.297 4.0742 165.22 15.0%

i-Pentane 2985.42 3137.5148 152.09 13.8%

n-Pentane 1033.24 1050.3910 17.15 1.6%

tr2-Pentene 1091.51 1168.4559 76.95 7.0%

Cyclopentane 200.56 188.5269 12.03 1.1%

22-Mbutane 1755.77 1869.8097 114.04 10.3%

23-Mbutane 1758.41 1716.2842 42.13 3.8%

2-Mpentane 1759.22 1719.0402 40.18 3.6%


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Although the deviations for these specific

components are significant, the overall mass

flow deviations for the two streams (for LPG,

7417 versus 7621 lb/hr; for gasoline, 30705

versus 30937 lb/hr; Table 4) are negligible. The

deviation observed for the propane component

in the mass flow of the LPG stream represents

3.7% of the total LPG flow stream. The

deviation observed for the cis2-Butene

component in the mass flow of the gasoline

stream represents just 0.53% of the total

gasoline flow stream.

(7)

(8)

Based on the results of this comparison, we

assume that our proposed simulation

configuration is an acceptable starting point

for evaluating variations in feed parameters

such as the process arrangement, feed gas

composition, flow rate, and other variables.

3.2. Iran’s Asaluyeh Flare Gas Case

Study Simulation Results for base

Configuration

The Asaluyeh gas processing plant, forming

part of the Pars Special Energy Economic

Zone, is a large-scale gas processing plant

consisting of multiple trains located on the

shore of the Persian Gulf some 270 km

southeast of the provincial capital of Bushehr.

The Asaluyeh facility has significant flare gas

available for processing and could provide feed

gas for a FGTG plant. For the purposes of this

study the input feed (flare) wet gas from the

Asaluyeh facility to the steam reformer stage

of the FGTG plant is assumed to have a mass

flow of 100,000 lb/hr (Table 5) with low

sulphurous and carbon dioxide components.

3-Mpentane 1759.23 1738.9509 20.28 1.8%

Mcyclopentan 641.626 639.6568 1.97 0.2%

Benzene 399.882 392.6952 7.19 0.7%

24-Mpentane 754.446 728.5036 25.94 2.4%

Cyclohexane 411.938 398.0233 13.91 1.3%

2-Mhexane 754.54 743.6384 10.90 1.0%

3-Mhexane 754.549 741.7398 12.81 1.2%

224-Mpentane 754.58 725.4479 29.13 2.6%

Mcyclohexane 641.925 628.1166 13.81 1.3%

33M-1-butene 804.056 765.1240 38.93 3.5%

Toluene 2498.05 2509.9072 11.86 1.1%

233-Mpentane 503.111 493.2406 9.87 0.9%

23-Mhexane 503.114 487.8723 15.24 1.4%

3-Mheptane 504.032 491.6382 12.39 1.1%

23M-1-butene 813.116 824.6683 11.55 1.0%

p-Xylene 1037.65 1048.1484 10.50 1.0%

m-Xylene 2286.73 2299.8263 13.10 1.2%

o-Xylene 940.056 934.3038 5.75 0.5%

m-Cymene 487.942 494.5641 6.62 0.6%

23M-2-butene 632.078 651.3237 19.25 1.7%

diM-Ether 0 0 0.00 0.0%

124-MBenzene 1366.18 1364.9858 1.19 0.1%

1245-M-BZ 21.9705 22.5526 0.58 0.1%

Naphthalene 260.507 260.4051 0.10 0.0%

2-M-Naphtln 39.002 38.9912 0.0108 0.0%

1234-M-BZ 421.011 422.6139 1.6029 0.1%

P (psia) 20 20 1102.609

100 T(F) 110 110

Mass Flow (lb./hr.) 30937.28 30705.25 Total Error


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Table 5. Specification of feed and products of syngas production, methanol, and MTG units

Stream Name

Natural gas to

Synthesis gas

(Feed and fuel)

Total Natural gas

to Reformer Reformed Gas

Component Mole (%) Mole (%) Mole (%)

Hydrogen 0.00 0.00 56.66

CO 0.00 0.00 14.79

CO2 0.60 0.60 4.12

CH4 84.90 84.90 3.27

H2O 0.00 0.00 21.06

Oxygen 0.00 0.00 0.00

Nitrogen 0.50 0.50 0.09

Ethane 9.20 9.20 0.00

Propane 3.50 3.50 0.00

i-Butane 0.40 0.40 0.00

n-Butane 0.70 0.70 0.00

Mass Flow(lb./hr.) 100,000 63,820 206,298

P (psia) 406 406 280

T(F) 69.8 69.8 1112

Stream Name Methanol

Component Mole (%)

Methane 0.02

Ethane 0.00

H2O 3.24

Hydrogen 0.00

CO 0.00

CO2 0.20

Methanol 96.54

Ethanol 0.00

diM-Ether 0.00

Mass Flow(lb./hr.) 101922

P (psia) 415

T(F) 123.5

Stream Name Gasoline LPG Fuel gas Mixture of Gasoline+LPG+Fuel gas

Component Mole (%) Mole (%) Mole (%) Mole (%)

Hydrogen 0.00 0 0.00 0.00

CO 0.00 0 0.67 0.14

CO2 0.00 0 22.85 4.65

Methane 0.00 0 47.71 9.71

H2O 0.00 0 14.99 3.05

Oxygen 0.00 0 1.19 0.24

Nitrogen 0.00 0 0.20 0.04

Ethane 0.00 20.51 11.81 6.81

Propane 0.00 48.13 0.05 10.35

n-Butane 0.00 17.01 0.04 3.66

cis2-Butene 0.00 0.24 0.00 0.05

i-Pentane 12.66 13.82 0.03 10.36

n-Pentane 4.79 0 0.00 2.79

tr2-Pentene 5.12 0.28 0.01 3.05

Cyclopentane 0.91 0 0.00 0.53

22-Mbutane 5.86 0 0.00 3.42

23-Mbutane 5.86 0 0.00 3.42

2-Mpentane 5.89 0 0.02 3.44

3-Mpentane 5.87 0 0.00 3.42

Mcyclopentan 2.56 0 0.00 1.49

Benzene 1.32 0 0.00 0.77

24-Mpentane 1.80 0 0.00 1.05

Cyclohexane 1.37 0 0.00 0.80

2-Mhexane 2.07 0 0.00 1.21

3-Mhexane 2.28 0 0.00 1.33

224-Mpentane 2.09 0 0.00 1.22

Mcyclohexane 1.80 0 0.00 1.05

33M-1-butene 2.44 0 0.00 1.42

Toluene 7.86 0 0.00 4.58

233-Mpentane 1.27 0 0.00 0.74


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23-Mhexane 1.32 0 0.00 0.77

3-Mheptane 1.32 0 0.00 0.77

23M-1-butene 2.05 0 0.00 1.20

p-Xylene 2.97 0 0.00 1.73

m-Xylene 6.53 0 0.00 3.81

o-Xylene 2.66 0 0.00 1.55

m-Cymene 1.15 0 0.00 0.67

23M-2-butene 3.00 0 0.00 1.75

124-MBenzene 3.52 0 0.00 2.05

Naphthalene 0.60 0 0.00 0.35

1234-M-BZ 0.96 0 0.00 0.56

Mass Flow(lb./hr.) 33357 8433 3845 63141

P (psia) 20 110 100 -

T(F) 112 124 6 -

As shown in Fig. 3, six streams distinct

streams require consideration for the overall

simulation of a GTG plant:

1) Feed gas stream (flare gas to synthesis

gas)

2) Reformed gas from the SMR process as

the syngas unit product

3) Methanol as methanol unit product

4) LPG as MTG unit product

5) Gasoline as MTG unit product

6) Fuel gas as MTG unit product

The main product of the syngas unit is

reformed gas and with mass flow of 206,298 lb.

/hr. (i.e. 63.82% of the feed gas mass flow). The

produced syngas from the SMR unit has

significant quantities of CO2 (about 4 mole %)

and water (about 21 mole %). Table 5 shows

mass balance for the feed gas and products for

the SMR syngas unit of the FGTG process.

Table 5 also indicates that the H2/CO in

reformed syngas is about 3.8, which is suitable

for use in the methanol plant, which, based on

equations 1 to 3, can produce methanol with

purity of 97%. The conversion of the carbon

monoxide component of the syngas in the

methanol unit is given by Eq. (9):

(9)

As the methanol mole fraction in the outlet

products of the MTG unit in the simulation is

zero, it can be concluded that the entire input

methanol to the MTG unit is converted into

final products (gasoline, LPG, and fuel gas in

the proportion 74%; 17%; 8%; Table 5). For

detailed evaluation of methanol conversion to

component-based products, mole fraction of

mixed- product output (Gasoline+LPG+Fuel

gas) is provided in Table 5. Results indicate

that propane and i-pentane have maximum

mole fractions among all the components of

mixed-product output. The mass base

conversion of methanol to these components is

about 7.21% as indicated by applying Eq. (10)

to the data from Table 5.

(10)

3.3. Novel Recycling Configuration of

FGTG Plant with Recycling of all

Emission Gases

In all stages of the FGTG process, two streams

are the main candidates for recycling and

reuse:

1- H2 rich off gas from methanol unit

2- CO2 and H2 rich off gas from MTG unit

Specification of these streams before and

after the membrane section are listed in Table

6.

The off-gas specifications reveal that, CH4,

H2 and CO2 have highest molar composition in

these two streams. On the other hand, the

main objective of the FGTG process is to

maximize gasoline productivity. So, producing

fuel gas for recycling to the syngas unit and

synthesis gas for recycling to the methanol

unit are both potentially attractive options for

maximizing methanol productivity and thereby

obtaining maximum gasoline productivity.

Synthesis gas is a mixture of H2 and CO in

varying proportions. In order to efficiently

produce methanol, the syngas H2:CO ratio

needs to be close to 3.8 when it enters the

methanol unit. Unfortunately, the CO content

of off gas streams is very low. Therefore, the

water-gas-shift (WGS) reaction (Eq. (11)) is

required to promote the conversion of CO2 to

CO.

CO2+H2↔CO+H2O Water-Gas-Shift (WGS)

(11)


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Block flow diagrams (BFD) of the

membrane section and a new configuration of

the FGTG process are shown in Figs. 7 and 8.

Firstly, a mixed-off-gas stream from the

methanol and MTG unit enters the membrane

subunit, where H2 purification is performed

through a palladium membrane package. Pure

hydrogen is then fed from this unit to a WGS

reactor, where it reacts with makeup CO2 to

produce synthesis gas with the required

hydrogen to carbon monoxide ratio of 3.83.

Secondly, the methane-rich fuel gas stream

derived (Table 6) is recycled to the synthesis

gas production subunit.

Various dense metal membranes, such Cu,

Al, Pd, Ni, Mo, Pt, Au, Nb, Fe, and Ta, have

potential to purify hydrogen in a dissociated

form, and consequently they can theoretically

provide unbounded selectivity. Among these

dense metal membranes, palladium (Pd)

membranes have recently received

considerable attention for the following

reasons: excellent permeability, high tolerance

to hydrocarbon flows and self-catalyzing

behavior of the H2 dissociation reactions

(Rahimpour, Samimi, Babapoor, Tohidian, &

Mohebi, 2017). Another important feature of a

Pd membrane is its excellent resistance to

hydrogen embrittlement and catalytic ability

for hydrogen recombination (Gade, Thoen, &

Way, 2008).

The material balance and membrane

specifications for hydrogen purification in the

membrane subunit is provided in Table 7.

Table 6. Specification of off gas before and after recycling from membrane unit

Stream Name H2 Rich Off gas CO2-H2 Rich Off gas SynGas Recycle-Ratio 3.83 Fuel Gas-

Recycle

Component Mole (%) Mole (%) Mole (%) Mole (%)

Hydrogen 79 33 64 0

CO 3 0 17 12

CO2 6 38 3 31

Methane 12 14 0 54

H2O 0 1 17 0

Oxygen 0 0 0 0

Nitrogen 0 0 0 0

Ethane 0 1 0 0

Propane 0 12 0 2

Mass Flow(lb./hr.) 33330 5554 50755 30961

P (psia) 686 100 100 100

T(F) -30 10.4 1652 28

Membrane system

for H2 separation(Palladium Membrane)

Mixed Off gasWater Gas Shift

Reactor

Pure Hydrogen

Make-up CO2

FuelGas-Recycle

SynGas Recycle-Ratio 3.83

Figure 7. Block Flow Diagram (BFD) of membrane separation process


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Figure 8. Block Flow Diagram (BFD) of simulated new FGTG process

Table 7. Results of material balance and membrane specification for hydrogen purification in membrane subunit

Stream Name Mixed

off gas

Pure

H2

Fuel gas

recycle

Syngas

recycle

Makeup

CO2

Component Mole (%) Mole

(%) Mole (%) Mole (%) Mole (%)

Hydrogen 76.58 98.9 0.300 63.56 0.00

CO 3.17 0.2 13.48 16.60 0.00

CO2 7.77 0.8 30.65 3.25 1

Methane 11.81 0.00 52.64 0.00 0.00

H2O 0.03 0.00 0.13 16.60 0.00

Oxygen 0.00 0.00 0.00 0.00 0.00

Nitrogen 0.00 0.00 0.01 0.00 0.00

Ethane 0.05 0.00 0.2 0.00 0.00

Propane 0.53 0.00 2.38 0.00 0.00

i-Butane 0.03 0.00 0.09 0.00 0.00

Ethylene 0.03 0.00 0.11 0.00 0.00

Mass Flow(lb./hr.)

P (psia) 100 100 100 100 100

T(F) -29.8 50 28 1652 20

Mass Flow (lb./hr.)

Flare Gas 70000 80000 90000 100000 110000 120000 130000

Mixed off gas 28940 33350 38390 39760 44960 50020 55260

Pure H2 7593 8512 9478 9682 10690 11990 13180

Fuel gas recycle 21350 24848 28920 30700 34280 48030 42080

Syngas recycle 40460 45180 50280 51330 56620 63570 69830

Makeup CO2 32870 36660 40800 41650 45940 51570 56650

Si Membrane surface area (m2) 2.43 2.76 2.915 3.1 3.12 3.3 3.47

Membrane number of stage 3 3 3 3 3 3 3

Permeance of H2

(m3/ (m2.Pa.hr.)) 0.3225 0.3225 0.3225 0.3225 0.3225 0.3225 0.3225

Stage Cut 0.786 0.786 0.782 0.781 0.779 0.78 0.780

3.4. Results of Sensitivity Analysis for

Iran’s Asaluyeh Flare Gas Case Study

in Base and Recycling Configurations

A key objective for the FGTG process is selectivity

of the gasoline product. Three main products are

derived from a FGTG plant (Table 5):

1- Gasoline

2- LPG

3- Fuel gas

Among them, gasoline is the product with

the highest value and demand, so

maximization of gasoline productivity and

selectivity need to be the primary focus of

FGTG process suppliers. For the purpose of

monitoring selectivity and productivity of the

gasoline product, flare gas mass flow as feed to

the FGTG plant is selected as the adjustable

variable. One reason for this selection is that

flare gas mass flow changes dynamically in

Iran’s Asaluyeh facility. Consequently, the

capacity of an FGTG plant needs to vary

between 70,000 to 130,000 lb./hr. according to

maximum and minimum mass flow rates

observed over an annual period. Table 8

presents the results of productivity and

selectivity of all products of the FGTG plant

for a range feed gas flow rates.


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Table 8. Results of productivity and selectivity of all Products

Base FGTG Plant Configuration-Mass Flow (lb./hr.)

Flare Gas 70000 80000 90000 100000 110000 120000 130000

Gasoline 24054 27323 30679 33890 35429 38670 41943

LPG 5540 6264 7142 7667 8024 8478 9108

Fuel Gas 2424 2950 3468 3839 4082 5139 5339

*Total Productivity 29594 33587 37821 41557 43453 47148 51051

Total Utilities [Btu/hr.] 1.36×109 1.45×109 1.60×109 1.79×109 1.90×109 2.01×109 2.15×109

Energy Index in Product base (Btu/lb.) 4.60 4.32 4.23 4.31 4.37 4.26 4.21

Base FGTG Plant Configuration-Product Selectivity (%)

Gasoline 75 75 74 75 75 74 74

LPG 17 17 17 17 17 16 16

Fuel Gas 8 8 8 8 9 10 9

Recycling FGTG Plant Configuration-Mass Flow (lb./hr.)

Flare Gas 70000 80000 90000 100000 110000 120000 130000

Gasoline 37189 42860 47624 49571 54474 59143 64248

LPG 9211 9611 10644 11026 11925 12870 13915

Fuel Gas - - - - - - -

Total Productivity 46400 52471 58268 60597 66399 72013 78163


Energy Index in Product base (Btu/lb.) 3.49 3.98 3.40 3.46 3.83 3.53 1.83

Recycling FGTG Plant Configuration-Product Selectivity (%)

Gasoline 82 82 82 82 82 82 82

LPG 18 18 18 18 18 18 18

Fuel Gas - - - - - - -

Productivity and selectivity comparison

Flare Gas Mass Flow (lb./hr.) 70000 80000 90000 100000 110000 120000 130000

**Productivity enhancement (%) 57 56 54 46 53 53 53

***Gasoline selectivity enhancement (%) 9 9 11 9 9 11 11

****Energy Index enhancement (%) 24 8 20 20 13 17 57

* Total productivity = Gasoline productivity + LPG productivity

** Productivity enhancement =100× (Productivity in Recycling FGTG Plant Configuration - Productivity in

Base FGTG Plant Configuration) / Productivity in Base FGTG Plant Configuration

*** Gasoline selectivity enhancement =100× (Selectivity in Recycling FGTG Plant Configuration - Selectivity

in Base FGTG Plant Configuration) / Selectivity in Base FGTG Plant Configuration

**** Energy Index enhancement =100× (Energy Index in Recycling FGTG Plant Configuration - Energy

Index in Base FGTG Plant Configuration)/ Energy Index in Base FGTG Plant Configuration

The gasoline selectivity remains

approximately constant (75%) in all capacities

of flare gas fed through the FGTG process in the

base configuration (Table 8). On the other hand,

productivity does not remain constant, but

increases, as the feed gas mass flow rate is

increased. Table 8 compares total productivity

for the base configuration and the novel

recycling configuration for the FGTG plant. It

reveals that total productivity and gasoline

selectivity are significantly increased when the

recycling configuration is used instead of the

base configuration. The results (Table 8) show

average 53% and 10% increases, respectively,

for total productivity and gasoline selectivity, as

the main outcomes of the process optimization

achieved by the recycling configuration.

In the bottom section, calculations have

been made on the economic benefits of

increasing the production of products. The base

price of the products is based on Platts price

referance. As the calculations show, the


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increase in product production will result in a

53 percent increase in profits due to the reform

of the process arrangement from base FGTG to

recycling FGTG.

Total productivity = Gasoline

productivity + LPG productivity

Base FGTG: 43453 (lb./hr.) = 35429

(lb./hr.) + 8024 (lb./hr.)

Recycling FGTG: 66399 (lb./hr.) = 54474

(lb./hr.) + 11925 (lb./hr.)

LPG Density = 5.185 (lb./ft3)

Gasoline Density = 43.96 (lb./ft3)

Base cost of Gasoline = 93 $/bbl = 0.585

$/L = 585 $/m3 = 831 $/Ton = 0.377 $/lb.

Base cost of LPG = 576$/Ton = 0.262 $/lb.

Economiy calculation:

Base FGTG: Sale Income = 35429 (lb./hr.)

× 0.377 $/lb.+ 8024 (lb./hr.) × 0.262 $/lb. =

15459 $/hr.

Recycling FGTG: Sale Income = 54474

(lb./hr.) × 0.377 $/lb.+ 11925 (lb./hr.) × 0.262

$/lb. = 23661 $/hr.

Sale Income Enhancement (%) = (23661

$/hr. - 15459 $/hr.) / 15459 $/hr. = + 53%

Other crucial parameters for evaluating the

performance of process units, and in particular

the FGTG process, is energy and utilities

consumption. Table 9 lists the total utilities

and energy consumption for a range of feed gas

flow rate cases for the base configuration and

the novel recycling configuration for the FGTG

plant. The results indicate that increasing the

flare gas mass flow as feed streams has, as to

be expected, a direct effect on increasing the

energy consumption of the FGTG unit.

Minimum and maximum utilities consumption

for the base FGTG configuration vary following

a consistent trend withthe minimum and

maximum of flare gas flow rate. This

consistent trend is not seen in the proposed

recycling configuration for the FGTG plant

(Table 9).

A suitable index for comparing of the

various FGTG capacities on the basis of energy

consumption for the two configurations (i.e.,

base and recycling) is the ratio total utilities

consumption to total productivity (i.e., termed

here the Energy Index, Table 9, expressed in

Btu/lb). The highest feed-gas capacity case

(130,000 lb/hr.) demonstrates the lowest

Energy Index values than the lower- capacity

natural gas mass flow cases for both FGTG

plant configurations considered (4.21 for old

arrangement and 1.83 for new arrangement

model).

Significantly, the recycled FGTG

configuration yields a significantly more

favorable Energy Index than the base

configuration (Fig.9). For example, for a feed-

gas capacity of 100,000 lb./hr. (the expected

average operating conditions) the flare gas

capacity Energy Index is 3.46 for the recycled

FGTG configuration versus 4.31 for the base

configuration. Perhaps, the most important

advantage of the recycled FGTG plant

configuration, in addition to producing more of

the key products (gasoline and LPG) and

consuming less energy per unit of production,

is its lack of emissions of greenhouse gases

(except from the fuel gas consumed in the

process burners) into the atmosphere.

Fig. 10 Summarizes the Plant Fuel Losses

and Productivity from the Simulation Results

for: a) base FGTG Plant Configuration and b)

Recycling FGTG Plant Configuration.

Table 9. Results of utility and energy consumption in all scenarios

Base FGTG Plant Configuration



Heating Utilities [Btu/hr.] 4.67×108 5.17×108 6.18×108 6.78×108 7.34×108 7.83×108 8.47×108

Cooling Utilities [Btu/hr.] 8.73×108 9.29×108 1.03×109 1.12×109 1.17×109 1.23×109 1.30×109

Total Productivity (lb./hr.) 29594 33587 37821 41557 43453 47148 51051

* Energy Index×104 (Btu/lb.) 4.60 4.32 4.23 4.31 4.37 4.26 4.21

Recycling FGTG Plant Configuration



Heating Utilities [Btu/hr.] 6.02×108 8.45×108 7.82×108 8.471×108 9.48×108 1.05×109 5.19×108

Cooling Utilities [Btu/hr.] 1.01×109 1.25×109 1.20×109 1.25×109 1.59×109 1.49×109 9.10×108

Total Productivity (lb./hr.) 46400 52471 58268 60597 66399 72013 78163

Energy Index (Btu/lb.) 2.67 3.99 3.4 3.4 3.83 3.52 1.83

*Energy Index = Total Productivity/ Total Utilities/104


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Figur 9. Comparing of FGTG various cases versus defined energy index

Figure 10. Comparison of fuel losses and productivity of base FGTG and recycling FGTG plants

a) FGTG base; b) FGTG recycling.

4. Conclusions

A comprehensive simulation and sensitivity

analysis of an integrated Flare Gas to Gasoline

(FGTG) process plant with two distinct

configurations (base and recycling) is

described. In the novel recycling FGTG

configuration design involves all off-gas

streams from the syngas to methanol and

methanol to gasoline (MTG) process units

being passed through an additional membrane

unit and Reverse-Water-Gas-Shift (RWGS)

reaction unit. The membrane package and the

WGS reactor, facilitates recycling and reuse of

the off-gas as fuel gas and synthesis gas. Three

main process sections constitute the base

FGTG plant configuration simulated and

analyzed, simultaneously. These three

subunits are: a steam methane reforming

(SMR) synthesis gas unit, a synthesis gas to

methanol production unit, and methanol to

gasoline (MTG) unit. The base FGTG plant

configuration simulation results were

validated using a published MTG case study

showing acceptable product deviations from

the results of the published case.

A series of sensitivity cases run on both

FGTG configurations evaluated that flare gas

capacity of the feed-gas stream into the FGTG

process does not have a considerable effect on

the gasoline and LPG selectivity of the overall

process. The selectivity of gasoline and LPG

remained approximately constant at about

75% and 16%, respectively, for the base

configuration, and about 82% and 18%,

respectively, in the recycling configuration.

Energy Index, defined as the ratio of total

utilities consumption to total productivity

(LPG plus Gasoline mass flow), is used to

compare the energy efficiency of all sensitivity

cases and plant configurations considered.

0.00

0.50

1.00

1.50

2.00

2.50

3.00

3.50

4.00

4.50

5.00

70000 80000 90000 100000 110000 120000 130000

Ener

gy I

nd

ex (

Btu

/lb

.)

Total Productivity (lb./hr)

(LPG+Gasoline)

Old Arrangement New Arrangement


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Increasing the flare gas flow rate (from 70,000

to 130,000 lb./hr.) has the beneficial effect of

reducing the Energy Index (from 4.26 to 4.21

Btu/lb.) for the base FGTG plant configuration.

Although the Energy Index reduction trend is

not uniform with increased feed-gas capacities

for the recycling FGTG plant configuration

model, it is lower than for the base

configuration. The observed Energy Index

results demonstrate that the FGTG plants

with higher capacities are more energy

efficient and should therefore be more

profitable.

Briefly, with considering all the points the

results clearly show that the recycling

FT+GTG plant configuration is significantly

better in terms of gasoline and LPG

productivity (yielding an enhancement of

about 53%), product selectivity (yielding an

enhancement about 10%), and significant

reduction in greenhouse gas emissions,

compared to the base FGTG plant

configuration evaluated.

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