Synthesis of water capture technologies for gas fired power plants in Qatar

Journal Pre-proof Synthesis of water capture technologies for gas fired power plants in Qatar Ahmed T. Yasir, Fadwa Eljack, Monzure-Khoda Kazi

PII:

S0263-8762(19)30580-5

DOI:

https://doi.org/10.1016/j.cherd.2019.12.013

Reference:

CHERD 3936

To appear in:

Chemical Engineering Research and Design

Received Date:

20 October 2019

Revised Date:

9 December 2019

Accepted Date:

11 December 2019

Please cite this article as: Yasir AT, Eljack F, Kazi M-Khoda, Synthesis of water capture technologies for gas fired power plants in Qatar, Chemical Engineering Research and Design (2019), doi: https://doi.org/10.1016/j.cherd.2019.12.013

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Synthesis of water capture technologies for gas fired power plants in Qatar

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Ahmed T. Yasir†, Fadwa Eljack†,‡, Monzure-Khoda Kazi†

Department of Chemical Engineering, Qatar University, P.O. Box 2713, Doha, Qatar

‡

Address all correspondence to: Fadwa Eljack ([email protected])

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Graphical Abstract

Highlights 

47.3% of the water available in flue gas was captured using quenching. If flue gas is available at high pressure, the water capture rate goes to 80.7%.

  

In a power plant-desal coupled system, adding a water capture plant can reduce the heating requirement of desalination plant by 9%-25% (depending on the condition of feed). The water capture plant emits 13-17 kg CO2e/m3 H2O, which is lower than the global average of 25 kg CO2e/m3 H2O. A water capture plant can reduce the brine production rate by 2.02 -3.44%.

Abstract: Flue gas from gas fired power plants contains 10-16% (w/w) water vapor with

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considerable amount of latent heat. Although CO2 capture and utilization have received great

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attention, water capture from power plant has received limited attention. The power plants in Qatar exhaust 33 Million m3 of water per year. This paper explores selected alternative technologies

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namely absorption, compression & cooling, and quenching, to enable the recovery of water vapor

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contained in a base case 750 MW power plant flue gas streams. The alternatives for water capture were modeled and optimized over a wide range of operating conditions (pressure, temperature,

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and flow rate). Using data from an actual gas fired power plant in the state of Qatar, simulation studies were carried out and optimized for all modeled technologies to minimize production cost

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using Aspen HYSYS V8.6. The results show that the quench unit, operated at pertinent water circulation temperature (50oC), pressure (6 atm), and flowrate of 3500 m3/hour (recyclable), can extract up to 80.7% of the water in the flue gas. Apart from production cost and water capture percentage, criteria used to screen the alternative technologies were payback period, CO2e

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emission and brine reduction rate. The research work determined that the quench alternative had the lowest payback period (8.8 years), lowest CO2 emission rate (13 kg CO2/ m3 H2O) and highest brine reduction (3.44%) among all the tested alternatives. The proposed quench water-recovery technology will have added value to Qatar and other nations with limited water resources, specifically those with access to natural gas resources.

Keywords: Water capture; dehumidification; gas fired power plant; Simulation; Energy integration

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Nomenclature

Notation

Denotation

Unit

𝜌

Density

kg/m3

𝜂

Efficiency of pump

%

Temperature

o

Δ𝑇

C

Sizing constant

-

𝐴𝐷

Activity Data

-

𝐴𝐹𝐶

Annual fixed cost

US $/year

𝐴𝑂𝐶

Annual operating cost

US $/year

𝑏

Sizing constant

-

𝑐𝑝

Specific heat

kJ/kg.K

𝐶𝐶

Cumulative cash flow

US $

𝐶𝐼

Capital investment

US $

𝐸𝐹

Effectiveness factor

-

𝐺𝑊𝑃

Global

warming -

potential 𝑉̇ 𝑛 𝑂𝐹 𝑃

kJ/year

Volumetric flow rate

m3/year

Sizing constant

-

Oxidation factor

-

Pressure

kPa

Production cost

US $/m3

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𝑃𝐶

Heat duty

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𝑄̇

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𝑎

𝑆

Sizing parameter

-

𝑇

Temperature

o

Total annual cost

US $

𝑇𝐴𝐶 𝑖

Utility

𝑗

Processing equipment

C

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kPa

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Pressure difference

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Δ𝑃

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difference

𝑘

Process alternative Water year

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1. Introduction Qatar has the 2nd highest per capita water consumption in the world in 2015, the per capita water consumption in Qatar was 255.5 m3 (WATER STATISTICS In The State of Qatar, 2015, 2017). However, geographically, Qatar is located at one of the most arid regions of the world (Naveed Cheema & Irfan, 2012). With a booming economy, the need for fresh water is increasing every

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day in Qatar. It is expected that the demand of fresh water in Qatar will reach 554 Million m 3 by

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2020 from 456 Million m3 in 2015 (Baalousha & Ouda, 2017).

The ground water is the only source of fresh water and meets only 30% of the local demand. It is

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exclusively used by agricultural sector. In 2015, 250 Million m3 of water was extracted from the underground aquifers of Qatar. However, the total recharge of the aquifers from rainfall and inflow

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from surrounding regions was merely 47.5 Million m3 (WATER STATISTICS In The State of Qatar,

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2015, 2017). This imbalance possesses a significant threat to these fresh water aquifers as influx of sea water in ground water is a direct consequence of this imbalance (WATER STATISTICS In

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The State of Qatar, 2015, 2017).

The main source of water in Qatar are the desalination plants that meets 68% of the local fresh water (WATER STATISTICS In The State of Qatar, 2015, 2017). The current desalination capacity of Qatar is 451 Million Imperial Gallons per Day (MIGD) or 2.2 Million m3/day ("Overview on-

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KAHRAMAA drinking water quality requirement.," 2014). To meet the increasing demand of water, Qatar plans to increase the desalination capacity to 500 MIGD by 2022 (Zaidi & Siddiqui, 2018). As desalination plants are highly energy intensive, in Qatar, 75% of the desalinated water and 71% of electricity is produced from desalination plants couple with power plants (desal-power

plants) (Harandi, Rahnama, Jahanshahi Javaran, & Asadi, 2017). Their name and production capacity are listed in

Description

Process Synthesis

Power plant, Desalination plant and water capture processes would be modeled on Aspen HYSYS v8.6.

Model Verification

Performance of simulated models would be validated using published results for similar processes.

Optimization

The validated models would be optimized to maximize water capture rate and minimize production cost.

Heat Integration

Energy requirement of the optimized models would be reduced by heat integration with desalination plant.

Result Analysis

The payback period, carbon foot print and brine reduction rate of the optimized processes would be studied.

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Steps

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Figure 1. Developed approach to determine suitable water capture technology from gas fired power

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plants.

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(a)

Heat rejection stage

. . . . . .

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. . . . . .

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Heat recovery stage

N=1

N=2

N=3

N=18

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Figure 2. Simulated (a) Power plant and (b) Desalination plant

N=19

N=20

N=21

(b)

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(a)

(b)

(c)

(d)

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(e)

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Figure 3. Simulated flow diagrams for (a) Absorption, (b) Cooling, (c) Cooling and Absorption,

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(d) Compression A & Cooling and (e) Quenching

Absorption

Cooling absorption

Cooling

and

Compression cooling

and

Quenching

Cooling

Cooling and absorption

Quenching

a(ii)

and

Compression cooling

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Cooling

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Absorption

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b(i)

Cooling absorption

Cooling

and

Quenching

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Absorption

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Absorption

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a(i)

Cooling and absorption

Quenching

b(ii)

Figure 4. Energy duty reduction of (a) Water capture plant and (b) Desalination plant with (i) feed at 1 atm & 85 oC and (ii) feed at 6 atm & 150 oC.

a)

Production cost (US$/m3 H2O)

35

Absorption Cooling Compression and cooling Cooling and absorption Quenching

30 25 20 15 10

0 20

40 60 Water capture (%)

b) 20

100

Absorption Cooling Cooling and absorption Quenching

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18

Production cost (US$/m3 H2O)

80

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0

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5

16 14

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12 10 8 4

2 0

20

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0

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6

40 60 Water capture (%)

80

100

Figure 5. Water capture performance and production cost of tested alternatives for a) feed at 1 atm

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and 85oC b) feed at 6 atm and 150oC.

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1.5

KW/kg kW/kgHH22OO

KW/kg kW/kg H2 O

2

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(a)

1

0.5

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Absorption

b(i)

Cooling

Cooling and absorption

Quenching

b(ii)

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Figure 6. (a) Water capture rate and (b)Energy intensity of the tested alternatives with (i) feed at

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85 oC and 1 atm and (ii) feed at 150 oC and 6 atm.

Table 1.

The power plants in Qatar are gas fired combined cycle power plants and have combined power generation capacity of 11,590 MW. Natural gas is their primary source of fuel; and the natural gas (NG) in Qatar contains about 89% methane (Atilhan, Aparicio, Karadaş, Hall, & Alcalde, 2012).

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The combustion of NG produces carbon dioxide, water and heat according to the following

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combustion reaction (Sarkar, 2015): ΔH=-890.31

C2H6 + 3.5O2 → 2CO2 + 3 H2O

ΔH=-1,559.83

C3H8 + 5O2 → 3CO2 + 4H2O

ΔH=-2,219.90

(3)

C4H10 + 6.5O2 → 4CO2 + 5H2O

ΔH=-2877.25

(4)

(1) (2)

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CH4 + 2O2 → CO2 + 2H2O

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In 2012, Mesaieed Power Company Limited (MPCL) used 56 Gmol NG and produced 750 MW of electricity. As by product, 5,952 m3 water was released with flue gas daily. By extrapolating

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this number for 11,590 MW, it can be estimated that annually, 33 Million m3 of water is exhausted to the atmosphere in Qatar. Capturing this water can potentially meet 4.7% of the total water demand in Qatar, as per the country’s demand in 2015.

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Water from flue gas can be captured by dehumidification of the flue gas. Dehumidification of gaseous streams is done extensively in natural gas processing industry; yet, water recovery from power plant flue gas is a relatively new concept. Previously, Liquid desiccant dehumidification has been used to remove 64-68% water from the flue gas of a coal fired power plant (Martin, Folkedahl, Dunham, & Kay, 2016). Furthermore, condensing boilers has been used in coal fired power plant to recover water and nearly 15% of residual energy (Q. Chen et al., 2012). Moreover,

thermal membrane condensers has been used to recover heat and water from saturated air streams (Cao et al., 2019). Although, water recovery from coal-fired power plants has been addressed in the literature; gas fired combined cycle power plants have received little attention. Flue gas from gas fired power plants contains significantly higher water content than coal fired power plant; based on the reaction stoichiometry. This paper will focus on recovering water and energy from

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gas fired power plant's flue gas. In order to recover water, absorption, compression and cooling, quenching, adsorption and

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membrane filtration can be used. Absorption with glycol solvent is widely used for natural gas

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dehydration (Mokhatab & Poe, 2012). Compression and cooling technology is used for extensively for air separation (Aneke & Wang, 2015). Through quenching, the temperature of flue gas is

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reduced below dew point, resulting in water precipitation (X. Chen, Sun, Chen, & Gao, 2019). Adsorption is utilized in gas processing industry to remove moisture from NG with low water

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content using silica gel, alumina and carbon molecular sieve as adsorbate (Mokhatab & Poe, 2012). In membrane filtration, the water vapor from air diffuses across the membrane (Liu, 2014). The

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separated water is then collected by a stream of sweeping air or by a vacuum chamber (Liu, 2014). Absorption, compression and cooling and quenching deem to be suitable for water capture from combined cycle gas fired power plant flue gas. In case of adsorption, the limitation of arises during

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the regeneration of adsorption beds. The air used for regeneration of adsorbate would dissolve the water in it and the captured water would be lost. For membrane filtration, sufficient experimental data are not available to carry out a techno-economic study. Thus, adsorption and membrane filtration as a technology for flue gas dehydration have not been considered in this paper.

In this paper the viable process alternatives would be assessed based on their technical, economic and environmental performance. It is desired to synthesize a suitable water recovery process that can maximize the recovery of water from flue gas of a gas fired power plant-desalination coupled system at favorable economic and environmental consequence.

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2. Methodology In order to design a suitable water capture process, the methodology shown in Figure 1 has been

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followed. Firstly, a power plant and a desalination plant have been simulated in Aspen HYSYS v8.6. The power plant and desalination plants have been developed based on MPCL and RAF B

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facility and validated against published data. This powerplant –desalination coupled system is

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technologically closer to all other coupled desal-power plants in Qatar. In addition, alternative process flowsheets capable of capturing water from flue gas have been synthesized and key

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parameters that affects the water capture rate and total annual cost have been identified. The synthesized process alternatives followed the principle of absorption, compression & cooling and

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Quenching for water recovery. After process synthesis, the developed models have been validated using published data available in literature. The energy intensity of different units in the synthesized water capture processes have been compared with comparable units. Once validated, selected process variables in each process alternative have been optimized, using HYSYS

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optimization spreadsheet, to enhance water capture rate at a reduced total annual cost. Once key variables have been optimized following the steps described in section 5.1.2, the waste heat from each developed alternative was integrated with desalination plant using Aspen energy analyzer. Finally, the techno-economic and environmental performance of the process alternatives have been evaluated.

The technical performances have been gauged based on water recovery rate (%) and heat intensity (kJ/m3 H2O) of the process alternatives. The water recovery rate and energy intensity have been calculated as:

𝑊𝑎𝑡𝑒𝑟 𝑟𝑒𝑐𝑜𝑣𝑒𝑟𝑦 (%) =

𝑇𝑜𝑡𝑎𝑙 𝑒𝑛𝑒𝑟𝑔𝑦 𝑑𝑢𝑡𝑦 𝑜𝑓 𝑡ℎ𝑒 𝑝𝑟𝑜𝑐𝑒𝑠𝑠 × 100% 𝑊𝑎𝑡𝑒𝑟 𝑐𝑎𝑝𝑡𝑢𝑟𝑒𝑑

(5)

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𝐻𝑒𝑎𝑡 𝑖𝑛𝑡𝑒𝑛𝑠𝑖𝑡𝑦 =

𝑊𝑎𝑡𝑒𝑟 𝑐𝑎𝑝𝑡𝑢𝑟𝑒𝑑 × 100% 𝑊𝑎𝑡𝑒𝑟 𝑎𝑣𝑎𝑖𝑙𝑎𝑏𝑙𝑒 𝑖𝑛 𝑓𝑙𝑢𝑒 𝑔𝑎𝑠

(6)

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The economic performance of the process alternatives have been assessed based on their payback

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period, which is the time required for an investment to recover its initial outlay in terms of savings or profits (Yard, 2000). Using net cash flow per year, the period required to regain the initial

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investment as profit, i.e. the pay back period, can be calculated. The net cash flow of each year is

𝑁𝑒𝑡 𝑐𝑎𝑠ℎ 𝑓𝑙𝑜𝑤𝑦

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calculated as:

(7)

= 𝑃𝑟𝑜𝑑𝑢𝑐𝑡 × 𝑆𝑒𝑙𝑙𝑖𝑛𝑔 𝑝𝑟𝑖𝑐𝑒 − 𝑟𝑎𝑤 𝑚𝑎𝑡𝑒𝑟𝑖𝑎𝑙 𝑐𝑜𝑠𝑡

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− 𝐴𝑛𝑛𝑢𝑎𝑙 𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝑐𝑜𝑠𝑡

The environmental performance of the process alternatives has been assessed based on their greenhouse gas (GHG) emissions and their capability to reduce brine production. Greenhouse gas

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(GHG) emission in terms of CO2 have been calculated using equation (4) and (5). Where, Effectiveness factor (EF) indicates how much a component facilitates global warming and it depends on the quality of fuel. EF for CO2, CH4 and N2O is 1879 g CO2/Nm3 NG, 0.04 g CH4/Nm3NG and 0.03 g N2O/Nm3 NG, respectively ("National Inventory Report," 2012). The EF for SOx and NOx emission depends on the type of burner used. The EF for NOx and SOx is 4.48 g NOx/Nm3 NG and 96×10-3 g SOx/Nm3 NG respectively (Background Information Document for

Industrial Boilers, 1982).The global warming potential (GWP) converts emitted CH4 and N2O to CO2 equivalent. The GWP for CO2, CH4 and N2O are 1, 56 and 280 respectively ("United Nations Framework Convention on Climate Change," 2014). The oxidation factor measures the percentage of carbon that has been oxidized and its value have been assumed to be 1 (Eggleston, Buendia, Miwa, Ngara, & Tanabe, 2006),(Eggleston et al., 2006).

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𝐶𝑂2 𝑒 𝑒𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠

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= 𝐴𝐷 × [𝐸𝐹𝐶𝑂2 + (𝐸𝐹𝐶𝐻4 × 𝐺𝑊𝑃𝐶𝐻4 ) + (𝐸𝐹𝑁2 𝑂 × 𝐺𝑊𝑃𝑁2 𝑂 )] × 𝑂𝐹

(9)

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𝐴𝐷 = 𝐹𝑢𝑒𝑙 𝐶𝑜𝑛𝑠𝑢𝑚𝑒𝑑 × 𝑁𝑒𝑡 𝐶𝑎𝑙𝑜𝑟𝑖𝑓𝑖𝑐 𝑉𝑎𝑙𝑢𝑒

(8)

The quantity of water produced from desalination plant would increase because of the water

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capture plant, thereby, increasing the water production efficiency. Higher efficiency would result

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in lower sea water intake by desalination plant. This in turn would reduce the volume of brine produced by the desalination plant. The water production efficiency has been defined as:

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𝑊𝑎𝑡𝑒𝑟 𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛 𝑒𝑓𝑓𝑖𝑐𝑖𝑒𝑛𝑐𝑦 (%) =

m3

𝑊𝑎𝑡𝑒𝑟 𝑝𝑟𝑜𝑑𝑢𝑐𝑒𝑑𝑓𝑟𝑜𝑚 𝑑𝑒𝑠𝑎𝑙𝑖𝑛𝑎𝑡𝑖𝑜𝑛 𝑝𝑙𝑎𝑛𝑡(year) 𝑚3

𝑆𝑒𝑎 𝑤𝑎𝑡𝑒𝑟 𝑖𝑛𝑡𝑎𝑘𝑒 (𝑦𝑒𝑎𝑟)

× 100%

(10)

The first step for achieve the objective is synthesis of water capture technologies. Before

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synthesizing process alternatives to capture water, a coupled desal-power plant has been simulated to generate feed for the water capture plant.

3. Coupled Desal-Power plant 3.1 Power plant

The combined capacity of the power plants in Qatar is 11,590 MW ("Qatar's power capacity tipped to reach 13,000 MW by 2018.," 2016). All the power plants in Qatar are combined cycle gas fired power plants. A combined cycle power plant uses both gas turbine and steam turbine to produce electricity. The efficiency of the combined process is approximately 60% (Rao, 2010). The natural gas coming to power plant is mixed with compressed air and burned in a gas turbine to produce electricity. The highest temperature inside the turbine is 1400-1600oC. The gaseous effluent from

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the turbine exits at 600oC and is sent to a heat recovery steam generation unit, to produce more

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electricity. In the steam cycle, excess heat from the steam turbine effluent is recovered and integrated within the desalination plant. This is one of the main reasons of constructing coupled

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power and desalination facilities (Hubka & Skolnik, 2013). In this paper, we will use Mesaieed

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Power Company Limited (MPCL) published process data as the basis for the study ("2012 Sustainability Report," 2013). In 2012, MPCL used 56 Gmol natural gas and produced 5,648 GWh

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of net electricity. Figure 2 (a) shows the developed flowsheet model based on the MPCL combined cycle gas fired power plant. The heat exchange E-122 is being used for heat integration with

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desalination plant. 3.1.1 Flue gas

The exhaust of the steam cycle provides the flue gas from the combined cycle gas fired power

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plant. The type of gas turbine determines the outlet temperature and pressure of the flue gas. The temperature of the flue gas is reduced from 600oC to 85oC after heat recovery steam generator (HRSG) and flue gas cooler (FGC). Generally the feed would be available at 1 atm (Mylläri et al., 2017). However, the flue gas from a multi stage gas turbine would be available at a pressure of 6 atm (Albeirutty, Alghamdi, & Najjar, 2004),(Jansohn, Griffin, Mantzaras, Marechal, & Clemens, 2011)-(Mletzko, Ehlers, & Kather, 2016). In order to carry out simulation studies, two different

flue gas conditions were considered: 85oC and 1 atm, and 150oC and 6 atm. Typical flue gas composition for a gas fired power plant using 10 to 30% excess air along with the flue gas composition of Mesaieed Power Company Limited is shown in Table 2. MPCL’s flue gas composition falls within the range of characteristic flue gas composition.

3.2 Desalination plant

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There are three types of desalination technology available: multi stage flash (MSF), multi effect (ME), and reverse osmosis (RO). In Qatar, most of the facilities are based on MSF technology. In

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MSF, the seawater is heated to top brine temperature of 95-110oC. Then flash columns are used to

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evaporate the brine partially. The number of flash columns can vary between 17 and 40. The vapor from each flashing unit is used to heat up the incoming brine. The first 20-30 stages are known as

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heat recovery stages; this is where the brine is heated using the vapor from flashing. The last 3-10

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stages are known as heat rejection stages (Fiorini & Sciubba, 2005). In this study, a MSF desalination plant with 40 MIGD capacity have been simulated, as shown in

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Figure 2 (b). The plant consists of 20 heat recovery units and 3 heat rejection units. The top brine temperature is 105oC. The simulated model was used to evaluate potential energy synergies between it and the synthesized water capture plants.

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3.3 Utility cost

Water capture plant is primarily a cooling process. So, chilled water would be required to cool the hot streams. Moreover, for compression, high pressure steam would be used. Furthermore, electricity would be used as utility for the pumps. It is assumed that, all pumps have 90% efficiency. The cost of cooling water, steam (at 690 KPa) and electricity were 0.032 US$/m3,

0.018 US$/m3 and 0.008 US$/kW. After developing the flowsheets for a coupled desal-power plant, water capture processes have been synthesized.

4. Process Synthesis and Validation 4.1 Process synthesis

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The alternative processes for water capture were synthesized using Aspen HYSYS v8.6 as

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discussed in Methodology. 4.1.1 Absorption

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Absorption has two main processing units: absorption and regeneration. For absorption, glycol package has been used as the thermodynamic package because this package can accurately predict

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thermodynamic behavior of TEG which has been used as absorbate. As shown in Figure 3 (a), the

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flue gas from power plant is sent to a compressor and then to an absorber, where lean TEG absorbs the water from the flue gas. After absorption, the rich TEG is heated to 130oC and sent to the

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regenerator. It is assumed that the TEG regeneration temperature could not be higher than 204oC as TEG would degrade. From the top of regenerator, water comes out and TEG is collected from the bottom. Any lost TEG in the regeneration process is made up by adding 95% TEG to the regenerated TEG stream. The regenerated TEG stream is cooled and recycled back to the top of

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absorber. In this process alternative, the compression ratio in the compressor and flowrate, pressure and temperature of the lean TEG are main process variables that dictates the water capture rate and total annual cost and have been optimized in the optimization section. 4.1.2 Cooling

In order to synthesize a flowsheet with cooling, Peng-Robinson EOS has been used because this EOS is very reliable for calculation of vapor-liquid equilibrium of water. The flue gas from the power plant is sent to a cooler. The suitable outlet temperature of the stream is found after optimizing the process. The cold stream is then sent to a phase separator, where water is collected from the bottom. If the flue gas is at high pressure, then an expander has been used to reduce the

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pressure of the stream and a secondary phase separator is used to collect water. The simulated flow

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sheet for the cooling process is presented in Figure 3 (b). 4.1.3 Cooling and absorption

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In this process alternative, Glycol property package is used as EOS because the most significant

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unit in this process alternative is absorption, which is being carried out using TEG. The flue gas is first cooled by following the steps mentioned in section 4.1.2. The cooled flue gas is then sent

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to the absorption section and the procedure mentioned in section 4.1.1 is followed. All the

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parameters mentioned in section 4.1.1 and 4.1.2 would be optimized for this process alternative. The simulated flow sheet can be seen in Figure 3 (c). 4.1.4 Compression and cooling

For compression and cooling, Peng-Robinson equation of state (EOS) was used to obtain

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thermodynamic parameters because this EOS can accurately calculate the required vapor liquid equilibrium for this process. The flue gas coming from the power plant is sent to a compressor, and then a cooler is used to cool the flue gas. The cooled flue gas is sent to a phase separator to collect any condensed water in the stream. The gas stream is expanded and sent to another flash separator for further water separation. The compression ratio at the compressor and the cooler

effluent temperature are the main operating variable that effects the water capture rate and total annual cost of the process. Thus, they have been optimized in the optimization section. The simulated process flow sheet is shown in Figure 3 (d). 4.1.5 Quenching The Peng-Robinson equation of state (EOS) is used to obtain thermodynamic parameters for the

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quenching process because this EOS can accurately predict the vapor liquid equilibrium present in

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the process. The flue gas from the power plant is sent to the compressor and then to the quenching unit. The service fluid inside the quencher is water, whose inlet temperature, pressure and flow

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rate have been optimized using the optimization spreadsheet available in Aspen HYSYS v8.6. Water effluent at the bottom of quencher is partially recycled to service the process and residue is

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the captured water. Before recycling, the stream is cooled and pumped to the desirable temperature

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and pressure of the quencher inlet. The flow sheet of the quenching process is presented in Figure

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3 (d).

4.2 Models’ validation

As there were no processes available in the literature that reports water capture using the proposed technologies, different processing steps of the technologies were compared independently based

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on their energy consumption for producing similar quantity of products. Each of the simulated water capture alternative has multiple processing steps. For example, cooling and absorption has 3 steps: compression, cooling, and absorption. All energy demand for all three sections were validated separately, and their range of variation were reported in table 3. The energy demand is compared based on the amount of nitrogen compressed and compression ratio (i.e. kJ/kg N2. kPa) (Aneke & Wang, 2015; Ebrahimi, Meratizaman, Akbarpour Reyhani, Pourali, & Amidpour, 2015).

For cooling, the energy requirement is validated based on processed nitrogen in the feed and temperature difference between the inlet and outlet of the cooler (i.e. kJ/kg N2. K) (Aneke & Wang, 2015; Ebrahimi et al., 2015). For absorption, the energy demand is validated based on the amount of water absorbed (i.e. kJ/kg H2O) (Kinigoma & Ani, 2016; Mokhatab & Poe, 2012). For quenching, energy demand is validated based on energy requirement of the recycled water (i.e kJ/kg H2O) (Zhou & Ni, 2008). Table 3 shows the % difference between simulation results and

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available published data. It can be observed that the simulated results were all within 1 to 9 %

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margin.

The validated models now have to be optimized to obtain maximum water capture rate at minimum

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total annual cost. Moreover, waste heat from the water capture plant has to be utilized to make the

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process energy efficient.

5.1 Optimization

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5. Process optimization and heat integration

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The objective function presented in equation (7) was minimized over the range of the decision variables that have been identified before during process synthesis. For minimization, Sequential Quadratic Programming was used as the optimization algorithm. Using the Optimization spreadsheet in ASPEN Hysys the optimum operating conditions (i.e. decision variables) that result in the lowest production cost have been identified.

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5.1.1 Decision variables

The decision variables selected for optimization were flue gas inlet temperature, flue gas inlet pressure and service fluid flowrate of the aforementioned technologies. The range of temperature and pressure was 15-150 °𝐶 and 1-6 bar. For different technologies different service fluids were used to maximize water capture rate. The service fluid for absorption and quenching was TEG and water, respectively. The range over which the flowrates of both of them were optimized was 15,000-500,000 kg/hr and 100,000-10,000,000 kg/hr, respectively. It may be noted that all the

process simulations were carried out at a flu gas flow rate of 2.28 × 106 𝑘𝑔/ℎ𝑟 , which was the actual flue gas flow rate of Mesaieed Power Company Limited (in 2012), providing a common basis for comparison among the assessed technologies. 5.1.2 Problem formulation The optimization objective was to capture maximum amount of water at lowest total annual cost. At maximized water capture flowrate, the brine production would be at a minimum. And at lowest

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total annual cost, heat intensity and CO2e emission would be lowest. Moreover, the optimization

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objective will also result in lowest payback period for the synthesized process alternatives. The following equation have been used as the optimization function: 𝐴𝑂𝐶𝑘 + 𝐴𝐹𝐶𝑘 𝑉̇𝑤.𝑘

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𝑐𝑜𝑠𝑡𝑤 =

(11)

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Here, 𝐴𝐹𝐶𝑘 , and 𝐴𝑂𝐶𝑘 denotes annual operation cost (𝑈𝑆 $/𝑦𝑒𝑎𝑟) and annual fixed cost (𝑈𝑆 $/

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𝑦𝑒𝑎𝑟) for process k. 𝑉𝑤̇ denotes the quantity of captured water (𝑚3 /𝑦𝑒𝑎𝑟). 𝐴𝐹𝐶𝑘 , 𝐴𝑂𝐶𝑘 , and 𝑉̇𝑤.𝑘 are functions of the decision variables identified in section5.1.1. 𝐴𝑂𝐶𝑘 is calculated as: 𝑛

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𝐴𝑂𝐶𝑘 = ∑ 𝑚̇𝑢.𝑗 × 𝑐𝑜𝑠𝑡𝑖

(12)

𝑗=1

Here, 𝑚̇𝑢.𝑗 and 𝑐𝑜𝑠𝑡𝑖 are the utility flow rates and cost of utility (𝑖) used in equipment 𝑗 respectively. The cost of utilities has been reported in section 3.3. The utility flow rate required in

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each type of equipment was calculated as: Cooler/Condenser: 𝑚̇𝑢.𝑗 = 𝑐

𝑄̇𝑘.𝐽

(13)

𝑝.𝑐𝑤 Δ𝑇𝑐𝑤

𝑄̇

Heater/ Reboiler/ compressor: 𝑚̇𝑢.𝑗 = Δ𝐻𝑘.𝐽

(14)

Pump: 𝑚̇𝑢.𝑗 = 𝑄̇𝑘.𝐽

(15)

𝑣𝑎𝑝

And energy duty of each type of equipment have been estimated as: Cooler/Condenser: 𝑄̇𝑘.𝐽 = 𝑚̇ 𝑘.𝐽 𝑐𝑝.𝑘.𝑗 Δ𝑇𝑘.𝑗

(16)

Heater/ Reboiler/ compressor: 𝑄̇𝑘.𝐽 = 𝑚̇ 𝑘.𝐽 𝑐𝑝.𝑘.𝑗 Δ𝑇𝑘.𝑗

(17)

Pump: 𝑄̇𝑘.𝐽 = 𝑚̇ 𝑘.𝐽 𝜌𝑘.𝑗 Δ𝑃𝑘.𝑗

(18)

Here, 𝑐𝑝,𝑘,𝑗 is the specific heat of fluid flowing through equipment 𝑗 in process 𝑘. The dependence

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of 𝑐𝑝,𝑘,𝑗 on pressure and temperature have been accounted using built in equation of states in ASPEN Hysys which were identified in section 4.1. It is to be noted that absorber, quench tower

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and separators do not have any heating requirement and will have no utility flow. The annual fixed

𝑛

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cost (𝐴𝐹𝐶) of process 𝑘 has been calculated using the following formula.

𝐴𝐹𝐶𝑘 = ∑ 𝐴𝐹𝐶𝑘,𝑗

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𝑗=1

(19)

𝑎𝑘,𝑗 + 𝑏𝑘,𝑗 (𝑆𝑘,𝑗 ) = 25

𝑛𝑘,𝑗

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(Towler & Sinnott, 2013):

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Here, 𝐴𝐹𝐶𝑘,𝑗 is the cost of equipment number 𝑗 of process 𝑘 per year. This can be calculated using

𝐴𝐹𝐶𝑘,𝑗

(20)

Here, 𝑎𝑘,𝑗 , 𝑏𝑘,𝑗 and, 𝑛𝑘,𝑗 are constants. Their respective values for different processes and equipment were taken from Towler et al (Towler & Sinnott, 2013). 𝑆𝑘,𝑗 is the sizing parameter of

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equipment 𝑗 of process 𝑘 .𝑆𝑘,𝑗 is a function of decision variables identified in section 5.1.1 and calculated using the following equations: Heater/ Cooler/Condenser: 𝑆𝑘,𝑗 =𝑈

𝑄̇𝑘𝑗

(21)

𝑘𝑗 Δ𝑇𝑘𝑗

Regenerator/ Quench tower: 𝑆𝑘,𝑗 =(𝑚̇w.k,𝑗 + 𝑚̇sf.k,𝑗 )𝜌k,𝑗

(22)

Pump/compressor: 𝑆𝑘,𝑗 =(𝑚̇w.k,𝑗 + 𝑚̇sf.k,𝑗 )𝜌k,𝑗 Δ𝑃k,𝑗

(23)

Here, 𝑈𝑘.𝑗 𝑎𝑛𝑑 𝜌𝑖,𝑗 are overall heat transfer coefficient and the density of the fluid in equipment 𝑗 in process 𝑖. It may be noted that additional retrofitting cost for any process alternatives were not considered. Finally, the quantity of captured water (𝑚̇𝑤 ) is the outlet flow rate of each stream and is obtained from simulation. Minimizing equation (7) resulted in optimum set of decision variables

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for each process alternatives. 5.1.3 Optimization result

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The optimum annual operating cost (𝐴𝑂𝐶), annual fixed cost (𝐴𝐹𝐶) and water capture flow rate

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(𝑚̇𝑤 ) for each process alternative (𝑘) are summarized in Table 4. The water captured is expressed as the percentage of total available water initially available in the flue gas (i.e. 250 m3/hr). It can

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be observed that quenching alternative has the highest water capture rate (47.3% and 80.7%) for both type of feed. Absorption alternative is the lowest performing alternative in all aspects; this

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includes water capture of 13.9% and 4.8% for low pressure and high pressure feed, respectively. However, the production cost for quenching; which is 5.00 US$/m3 and 4.34 US$/m3 for low and

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high temperature feed respectively; is higher than production cost for cooling; which is 3.50 US$/m3 and 5.54 US$/m3 for both low and high pressure feed respectively. The production cost of water using MED, MSF and RO plant is 2.62-10.47 $/m3, 0.55-2.29 US$.m3 and 1.57-3.55 $/m3

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respectively (Karagiannis & Soldatos, 2008). The production cost of water from the proposed water capture plant falls on the higher end of the production cost spectrum. It is to be noted that, the water production cost in middle east has been reported to be on the higher end of the production cost spectrum (Pinto & Marques, 2017). By optimizing the process variables, the energy demand of the water capture plant has been optimized. They can be further reduced by utilizing the waste heat from desalination plant.

5.2 Heat integration Water capture plant is a cooling process and desalination plant is a heating process because the flue gas has to be cooled in water capture plant to for water recovery, and in desalination plant seawater has to be heated to produce fresh water. Thus, an opportunity for heat integration is present. Reducing the energy requirements for both water capture and desalination plant is

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addressed using heat integration using Aspen Energy Analyzer. Aspen Energy Analyzer identifies target for minimum utility requirement by maximizing the heat recovery amongst processes. In

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addition, the tool designs optimum heat exchange network to match this target. The minimum

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temperature driving force chosen for the integration is 10oC for all alternatives.

The AOC and AFC for process alternatives were re-evaluated after heat integration. The results

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are presented in

Table 5. For low pressure feed, the production cost of water using compression and cooling and quenching reduced by 6.25% and 12.5% respectively. For high pressure feed, the production cost for cooling, cooling & absorption and quenching reduced by 50.2%, 40.8% and 9.0% respectively. Investigating into the source of this reductions, it can be seen from Figure 4 (a) that, excess energy from desalination plant is reducing the utility requirement of the water capture plant. For low

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pressure feed, 19% and 50% of energy duty for compression & cooling and Quenching is met by desalination plant respectively. And for high pressure feed, desalination plant can provide 70%,

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32% and 41% energy for cooling, cooling & absorption and quenching alternatives respectively.

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Not only water capture plant, but also desalination plant’s energy demand reduces because of heat integration as shown in Figure 4 (b). For low pressure feed, 31% of the energy demand for

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desalination plant can be met by compression & cooling, while quenching can provide 9% of

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energy required. At high pressure feed, there is greater potential for water capture pants to meet the desalination plant energy needs; as high as 41% can be meet by cooling or cooling & absorption

plant.

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alternatives. Moreover, Quenching can provide 25% of the energy required by the desalination

5.3 Ideal water capture technology

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The ideal water capture technology would be one with lowest production cost and highest water capture rate. Figure 5 shows the water capture rate and production cost for the synthesized alternatives at low- and high-pressure feed. For high pressure feed, quenching has the highest water capture rate (at 80.7%), but cooling has the lowest production cost (at 2.78 US$/m3). On the other hand, for low pressure feed, quenching has the highest water capture rate (47.3%). However, cooling has the lowest production cost (3.50 US$/m3).

As there are no technologies that fulfill both conditions, the final decision would depend on technoeconomic and environmental assessment.

6.0 Techno-economic and environmental evaluation The technical, economic and environmental performances identified in section 2 has to be analyzed

The major outcomes of the techno-economic and environmental analysis are presented at

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

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for each synthesized process alternative to identify the pro and cons of each process alternatives.

the low and high pressure feed systems. In Figure 6. (a) Water capture rate and (b)Energy oC

and 1 atm and (ii) feed at 150

oC

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intensity of the tested alternatives with (i) feed at 85

and 6 atm. quenching can extract maximum amount of water (47.3% and 80.7%) in both

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feed conditions. This means, quenching should have highest brine reduction ability. On the



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other hand, absorption has the lowest water capture rate at 13.9% and 4.8%. In terms of energy intensity, again quenching is the lowest energy intensity alternative (0.9

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and 1.1 kW/kg) among the synthesized alternatives, as shown in Figure 6 (a). While, compression and cooling (for low pressure feed) and absorption (for high pressure feed) have the highest energy intensity at 2 and 4.5 kW/kg respectively. Due to lower energy and utility requirements, the quench water capture exhibit lowest operating cost and lowest

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CO2e emission. The quench alternative has 13 and 17 kg CO2e/m3 H2O, for the low and high pressure feed, as seen in Table 6.



As seen in Table 6, the payback period for all the synthesized alternatives are between 8.8 and 9.1 years. The best payback period is obtained for quenching at 8.8 years. The highest

water capture rate and lowest utility cost for quenching supports this outcome. However, the best process alternative should not be selected based on payback period as they are very close to each other. 

The CO2 emission rate for desalination plants are between 6-25 kg/m(Mezher, Fath, Abbas, & Khaled, 2011). As seen in Table 6, all the synthesized technologies except absorption has GHG emission within this limit. Moreover, quenching has the lowest CO2e emission

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at 13 and 17 kg CO2e/m3 H2O. This implies that the utility requirement for quenching

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would be the lowest. Thus, the annual operating cost for quenching would be the lowest. As seen in Table 6, maximum brine reduction is possible by utilizing the quenching

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technology (2.02% and 3.44%). This implies that, quenching can be used to achieve

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7. Conclusion

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maximum water capture rate.

In order to capture water from gas fired power plants in Qatar, quenching showed better techno-

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economic and environmental performance. The temperature, pressure, service fluid flow rate of the technologies was optimized to minimize total annual cost and to maximize water capture rate. With low pressure feed, quenching was able to recover 47.3% of the total available water with energy intensity of 0.9 kW/kg water and CO2e emission of 13 kg/m3 water. Moreover, the payback

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period was found to be 8.8 years and the brine reduction was found to be 2%. With high pressure feed, quenching was able to recover 80.7% of the total available water with energy intensity of 1.1 kW/kg water and CO2e emission of 17 kg/m3 water. Moreover, the payback period was found to be 8.8 years and the brine reduction was found to be 3.4%. It is being suggested that, the possibility of high-pressure flue gas extraction is studied in more details, retrofitting costs for the power plant

to be studied, pilot scale study to be conducted for the quenching technology and other possible technologies; e.g. thermal membrane condensers; has to be studied.

Declaration of interests The authors declare that they have no known competing financial interests or personal

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relationships that could have appeared to influence the work reported in this paper.

Acknowledgment

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The authors would like to thank Dr. Mohammad Amanullah for his continuous support during the project. This paper was made possible by Qatar University grant No QUUG-CENG-CHE-15/16-

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2. The statements made herein are solely the responsibility of the author[s].

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Description

Process Synthesis

Power plant, Desalination plant and water capture processes would be modeled on Aspen HYSYS v8.6.

Model Verification

Performance of simulated models would be validated using published results for similar processes.

Optimization

The validated models would be optimized to maximize water capture rate and minimize production cost.

Heat Integration

Energy requirement of the optimized models would be reduced by heat integration with desalination plant.

Result Analysis

The payback period, carbon foot print and brine reduction rate of the optimized processes would be studied.

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Steps

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Figure 1. Developed approach to determine suitable water capture technology from gas fired power

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plants.

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(a)

Heat rejection stage

. . . . . .

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. . . . . .

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Heat recovery stage

N=1

N=2

N=3

N=18

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Figure 2. Simulated (a) Power plant and (b) Desalination plant

N=19

N=20

N=21

(b)

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(a)

(b)

(c)

(d)

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(e)

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Figure 3. Simulated flow diagrams for (a) Absorption, (b) Cooling, (c) Cooling and Absorption,

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(d) Compression A & Cooling and (e) Quenching

Absorption

Cooling absorption

Cooling

and

Compression cooling

and

Quenching

Cooling

Cooling and absorption

Quenching

a(ii)

and

Compression cooling

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Cooling

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Absorption

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b(i)

Cooling absorption

Cooling

and

Quenching

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Absorption

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Absorption

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a(i)

Cooling and absorption

Quenching

b(ii)

Figure 4. Energy duty reduction of (a) Water capture plant and (b) Desalination plant with (i) feed at 1 atm & 85 oC and (ii) feed at 6 atm & 150 oC.

a)

Production cost (US$/m3 H2O)

35

Absorption Cooling Compression and cooling Cooling and absorption Quenching

30 25 20 15 10

0 20

40 60 Water capture (%)

b) 20

100

Absorption Cooling Cooling and absorption Quenching

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18

Production cost (US$/m3 H2O)

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5

16 14

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12 10 8 4

2 0

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0

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6

40 60 Water capture (%)

80

100

Figure 5. Water capture performance and production cost of tested alternatives for a) feed at 1 atm

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and 85oC b) feed at 6 atm and 150oC.

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1.5

KW/kg kW/kgHH22OO

KW/kg kW/kg H2 O

2

ro

(a)

1

0.5

re

0

lP

Absorption

b(i)

Cooling

Cooling and absorption

Quenching

b(ii)

ur na

Figure 6. (a) Water capture rate and (b)Energy intensity of the tested alternatives with (i) feed at

Jo

85 oC and 1 atm and (ii) feed at 150 oC and 6 atm.

Table 1. Capacity of combined desal-power plants in Qatar (2018). Electricity (MW)

Desalination (MIGD)

Ras Abu Fontas B

609

33

Ras Abu Fontas B3

567

29.2

Ras Laffan Power

756

40

1025

60

2730

63

Qatar Power Ras Girtas Power

136

Jo

ur na

lP

re

-p

ro

Umm Al Houl Power 2520

of

Company

Table 2. Flue gas composition Component

Typical flue gas composition Composition at MPCL

7.3-9.1%

8.9%

H2O

13.5-16.8%

16.5%

N2

71.5-74.0%

71.6%

O2

1.7-5.6%

2.1%

Argon

0.85-0.86%

0.85%

Jo

ur na

lP

re

-p

ro

CO2

of

(Scholes, Ho, & Wiley, 2016)

Table 3. Validation of simulation results against published actual plant data Processing steps % Difference

References

against actual plant data 3 to 7

(Aneke & Wang, 2015; Ebrahimi et al., 2015)

Cooling

1 to 4

(Aneke & Wang, 2015; Ebrahimi et al., 2015)

Absorption

2 to 9

(Kinigoma & Ani, 2016; Mokhatab & Poe, 2012)

Quenching

2 to 4

(Zhou & Ni, 2008)

Jo

ur na

lP

re

-p

ro

of

Compression

Table 4. Water production cost before optimization and heat integration

Water Process

Condition

Alternatives

fixed cost (𝐴𝐹𝐶)

annual

Production cost

Cost

(𝑐𝑜𝑠𝑡𝑤 ) 𝑈𝑆 $⁄ 𝑚3 𝐻2 𝑂

M US$/yr

M US$/yr

Absorption

13.9

0.54

9.4

9.94

32.67

Cooling

31.3

0.20

2.2

2.40

3.50

40.8

0.74

11.6

12.34

13.82

42.1

15.17

3.5

18.67

20.25

47.3

1.48

2.8

4.28

5.00

4.8

0.44

1.5

1.94

18.46

65.2

0.31

7.6

7.91

5.54

66.0

0.75

9.1

9.85

6.81

80.7

1.16

6.5

7.66

4.34

and

Compression & cooling

lP

Quenching

ur na

Absorption Cooling Cooling

absorption

Jo

Quenching

and

ro

Cooling

of

M US$

85 °𝐶

150 °𝐶

(𝐴𝑂𝐶)

Total

%

absorption

6 𝑎𝑡𝑚,

cost

-p

1 𝑎𝑡𝑚,

capture

operating

re

Feed

Annual

Annual

Table 5. Water production cost after optimization and heat integration Annual

Annual

Water

fixed

operating

capture

cost

cost

(𝐴𝐹𝐶)

(𝐴𝑂𝐶)

%

M US$

Absorption

13.9

Cooling

Condition

Alternatives

M US$/yr

M US$/yr

𝑈𝑆 $⁄ 𝑚3 𝐻2 𝑂

0.54

9.4

9.94

32.67

31.3

0.20

2.2

2.40

3.50

40.8

0.74

11.6

12.34

13.82

42.1

15.50

2.4

17.90

19.57

Quenching

47.3

1.53

2.8

4.33

4.12

Absorption

4.8

0.44

1.5

1.94

18.46

65.2

0.44

3.5

3.94

2.78

66.0

0.88

5.0

5.88

4.10

80.7

1.68

5.3

6.98

3.98

Cooling and

Compressio

ur na

n & cooling

150 °𝐶

Cooling

Absorption

and cooling

Jo

Quenching

re

85 °𝐶

of

(𝑐𝑜𝑠𝑡𝑤 )

absorption

6 𝑎𝑡𝑚,

cost

Cost

-p

1 𝑎𝑡𝑚,

annual

ro

Process

Production

lP

Feed

Total

Table 6. Reduction in brine production (%), payback period and CO2e emission from the optimized processes. Feed at 85oC and 1 atm

Feed at 150oC and 6 atm CO2e

reduction

period

Absorption

0.59

Cooling Cooling

and

absorption Compression & cooling Quenching

Payback

CO2e

emission reduction

period

emission

8.9

110

0.21

9.0

153

1.34

8.8

18

2.79

8.8

19

1.74

8.9

18

2.82

8.8

20

1.80

9.1

34

2.02

8.8

13

Literature

6-25*

3.44

Jo

ur na

lP

re

*(Mezher et al., 2011)

Brine

of

Payback

ro

Brine

8.8

-p

Processes

17 6-25*