i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0

Available online at www.sciencedirect.com

ScienceDirect

journal homepage: www.elsevier.com/locate/he

Comparative study of a combined heat and power

plant retrofitted by CO2 capture during the
combustion of syngas from sewage sludge
gasification versus zero-emission combustion of
hydrogen produced using renewables

łkowski*, Jacek Frost, Marta Drosin

Kacper Ba˛k, Paweł Zio
ska-Komor

sk University of Technology, Faculty of Mechanical Engineering and Ship Technology, Poland
Gdan

highlights

Examples of possibilities to reduce CO2 production in industry by hydrogen burn.

Modernization of an existing Polish heat and power unit to capture CO2.

Cooperation of the Combined Heat and Power plant with RES producing hydrogen.

Validation of calculations in the numerical commercial program and in-house EcoPG.

article info abstract

Article history: With ecological requirements aimed at limiting the production of CO2, it is necessary to
Received 1 April 2023 produce all, or most of the energy from RES. During the transformation process, ecological
Received in revised form and highly efficient combustion power plants will be needed. The classic cycle of combined
17 June 2023 heat and power (CCGT) with green improvements will continue to be one of the most
Accepted 28 July 2023 suitable technologies for this task. This article presents the modernization of the CCGT
Available online 22 August 2023 power plant in Zielona Go
ra in terms of possible solutions to reduce CO2 emissions and
cooperation with RES producing hydrogen. Two variants of retrofit were considered: CO2
Keywords: capture following the combustion of syngas obtained from gasification of sewage sludge,
CO2 capture and emission-free hydrogen combustion in a gas turbine. Calculations were made using
Combined cycle gas turbine numerical modelling and the obtained results were validated. Avoided CO2 emissions for
Alternative fuels both solutions are shown. The proposed upgrades were compared with the basic variant
Hydrogen production and and other gaseous fuels.
combustion © 2023 The Author(s). Published by Elsevier Ltd on behalf of Hydrogen Energy Publications
Numerical modelling LLC. This is an open access article under the CC BY-NC-ND license (http://creativecommo
ns.org/licenses/by-nc-nd/4.0/).

* Corresponding author.

łkowski).
E-mail address: pawel.ziolkowski1@pg.edu.pl (P. Zio
https://doi.org/10.1016/j.ijhydene.2023.07.322
0360-3199/© 2023 The Author(s). Published by Elsevier Ltd on behalf of Hydrogen Energy Publications LLC. This is an open access article under the CC BY-NC-
ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).
39626 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0

Nomenclature Nel1 Gas turbine gross electric power output [MW]

Nel2 Steam turbine gross electric power output [MW]
A Anode
OC Outside heat Consumers
AB Absorber
P Pump
B Steam bleed from ST for MEA regeneration
p Pressure [bar]
BAT Best Available Technology
PEP2040 Poland's Energy Policy 2040
C Compressor
PEHA Pentaethylenehexamine
CCO2 Compressor for compressing CO2 for storage or
SH Superheater
transport
SHHP I, II High-pressure section consists of two steam
Cfuel Fuel compressor
superheaters
CC Combustion chamber
ST Steam Turbine
CCGT Combined Cycle Gas Turbine
Q_ HC Net heating capacity output [MW]
CCS Carbon Capture and Storage
qel;CO2 Electric power demand to the system [MJ =kgCO2 
CHP Combined Heat and Power
qH;CO2 Heat demand to reboiler [MJ =kgCO2 
COL Cooler
RES Renewable Energy Sources
DC/AC Direct curent/alternating curent
SHLP Low-pressure section includes a superheater
DE Desorber
SMR Steam Methane Reformation
DH Distric heat
t Temperature [ C]
ECO Economizer
TR Transmission
EL Electrolite
WINJ Water injection
EVAP Evaporator
dtHP Evaporator high pressure pinch point [ C]
F Filter
dtLP Evaporator low pressure pinch point [ C]
FG Flue Gases
hCHP;gross Combined Heat and Power plant gross efficiency
G Power generator
[%]
GT Gas Turbine
hCHP,net Combined Heat and Power plant net efficiency [%]
HC Heat consumers
hel;gross Gross electrical efficiency [%]
HE Heat exchanger
hel,net Net electric efficiency [%]
HP High pressure
hel,TG Electrical efficiency of the gas cycle [%]
HRSG Heat recovery steam generator
P Compressor pressure ratio
K Catode
DpA Flue gas pressure drop in absorber column
LHV Lower Heating Value, [MJ/kg]
 
kg CO
2;fg
LP Low pressure Pa= s
m_ Mass flow [kg/s]
MEA Mono-ethanol Amine DpR Pressure drop in reboiler [bar]

emissions related to energy production [19]. It is impeding the

1. Introduction progress to lower the temperature worldwide at a safe level;
according to the Paris Agreement [20e22] it is a limit of tem-
Currently, a significant increase in demand for electricity can perature return below 2  C, and ideally 1.5  C [23,24]. Since the
be observed in the world [1,2], which results, among others, implementation of the Paris Agreement in 2015, it has been
from economic development [3]. Thus, power plants must the basis in the fight against the climate crisis [25,26]. This is
operate with higher efficiencies to reduce fuel consumption where carbon capture and storage (CCS) technologies emerge
[4e6]. Nevertheless, this economic development also gener- as possible solutions to this problem.
ates some disadvantages in the form of the production of According to Poland's Energy Policy 2040 (PEP2040) [27] and
greenhouse gases, e.g. NOx, SOx, and CO2 [7e10], and other the current state of the Polish energy sector, it is impossible to
substances generated during the combustion of coal [11,12] switch to renewables and cut off conventional power plants
including hard and brown coal in conventional power plants almost immediately, as it will endanger energy safety. A lot of
[11,13,14]. All of the stated above leads to global climate other countries are in a similar situation. One of the reason-
change, an example of which is global warming. The solution able solutions in the transition process seems to be highly
to this problem might be to focus more on renewable energy efficient and low-emissive combined cycle gas turbine (CCGT)
sources [15], which is dictated by the rise of public awareness plants, developed as combined heat and power (CHP) facil-
on environment protection, carbon footprint reduction [8,16], ities, with the use of CCS technologies. Such technologies
and political restrictions through the Best Available Technol- seem to be more attractive than in recent years because of the
ogy (BAT) reference documents applied in the EU countries. significant increase of CO2 emission allowance prices, which
The largest problem seems to be CO2 emissions from burning recently achieved around 100 V/tCO2.
fossil fuels, constantly growing at the scale of the whole world CCGT is a favourable technology for the transition process
[17,18]. In 2017 it was emitted 32.5 gigatons of global CO2 into renewables also because of its higher flexibility [28] and
 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0 39627

efficiency over coal-fired power plants (63% electrical effi- transformation, with grid stabilization after this process.
ciency with development possibilities [29] compared to a po- Syngas produced from sewage sludge could help with utilizing
tential maximum of around 50% for supercritical technology this problematic waste to use it as a fuel in CCGT plants
[30]). What is more, it is a constantly developing technology equipped with CCS installation, which might be a promising
resulting from the progress of material engineering, allowing alternative to methane. Such power plant concepts are called
the achievement of higher turbine inlet temperatures, thus negative CO2 emission power plants as it was shown in
higher efficiencies. The recent state of CCGT technology has Ref. [24] because syngas from sewage sludge is sometimes
been widely shown in Refs. [31,32]. The advantage of these considered as a renewable source of energy. Hydrogen, how-
plants also results from a variety of gas turbines (GT) and the ever, is a prospective fuel in terms of energy storage, as using
CCGT concepts, which are still being developed e.g. CCGT power cells to convert the electricity produced by renewables
cycles integrated with coal gasification [33], GT with heat during peak hours into hydrogen [52], and then burn it as a
regeneration [34] or steam injection to the combustion fuel in CCGT CHP plants seems to be one of the best future
chamber (CC) [35]. In addition, CCGT systems can be inte- energy scenarios [53]. The schematic production of hydrogen
grated with energy storage to reduce energy supply in- in the electrolyser is shown in Fig. 1b.
terruptions into the electrical grid resulting from temporary Among the variety of power cells, alkaline and polymeric
changes in RES power output [36]. ones are the most promising, where polymeric power cells have
CCS technology has been used in the industry for around 80 the advantage of good flexibility at quickly changing power
years now, but not in the power industry. The trend seems to loads [30]. There are numerous researches done on burning
change as further developments of different CO2 removal hydrogen in GT, as there are plenty of problems associated with
methods result in achieving economic competitiveness. This burning pure hydrogen such as its explosiveness and high
can be seen when looking at the numbers of current CCS lower heating value (LHV) which prevent this technology to be
projects, which doubled in the recent year [37]. There are used today. Research should be continued due to the need to
several different approaches to CCS [38]: pre-combustion reduce CO2 emissions, and this can be achieved by burning
carbon capture [39], post-combustion carbon capture [40] syngas with a higher proportion of hydrogen. Scientists
and oxy-combustion CO2 capture [9,41,42]. emphasize the possibility of co-burning hydrogen with other
Chemical absorption capture processes are told to have the fuels such as biogas [9] or syngas. Such a mixture, thanks to the
highest technical maturity and implementation potential. use of hydrogen, has better combustion properties than biogas
However, other methods such as physical/chemical adsorp- itself, higher calorific value, low ignition delay, high flame
tion, membrane separation, chemical looping or cryogenics speed, high energy density, and lower CO2 emissions [35].
are a part of the research as well [9,43]. It is necessary to Currently, the maximum volumetric content of hydrogen in a
mention, that CCS installations are easier to implement in gaseous fuel mixture which the combustion process could be
coal-fired power plants where the flue gases mass flow is controlled is about 70e95% for co-combustion with syngas
significantly smaller than for gas-fired power plants, and the [30,54]. An example is the GE 9F Syngas turbine, which achieves
CO2 concentration is higher. In Ref. [44] Wu, Chen et al. pre- 40% efficiency in a simple cycle, and 57.4% in a combined cycle
sented the possibility of retrofitting a 600 MW coal-fired power [54]. However, some companies and utilities carry on the
plant where three different solid sorbents were used to cap- research of burning 100% hydrogen in GT [30]. As a result of the
ture CO2, namely the solid amine Pentaethylenehexamine combustion of fuels with an increased hydrogen content, it is
(PEHA), Na2CO3 and K2CO3. As a result of their research, it necessary to develop new designs of GT blade systems in terms
turns out that the solid amine sorbent (PEHA) is the best sor- of both high-temperature strength and cooling systems for the
bent because twofold: 1) there is the smallest decrease in ef- first stage blades.
ficiency and 2) it is also competitive in terms of energy This paper's goal is to analyse the potential of retrofitting an
consumption. existing CCGT CHP with syngas combustion coupled with CCS
There have been several types of researches done, proving amine-based installation, and its influence on the energy and
the possibilities of using chemical absorption based on environmental performance of the plant. The CO2 separation
amines [43,45], physical adsorption using zeolites [46] or reactor has been simply modelled as well as the CO2
membrane separation [47] for CCGT power plants, achieving compression unit. Due to the demand for low-temperature of
over 90% of capture efficiency. Chemical absorption separa- flue gases, heat recovery for municipal heating has been
tion using mono-ethanol amine (MEA) (Fig. 1 a) has been considered, as well as heat recovery of the water returning from
chosen for this paper, as the best examined option currently the reboiler. The results are compared to the case of zero-
[48,49]. On the other hand, significant attention should be paid emissive combustion of pure hydrogen, as well as the co-
to membrane separation technology, as the membrane ma- combustion with CCS installation. Both cases are then
terials development could potentially make this method more compared to other, conventional gaseous fuels such as
competitive. methane and the base case nitrogen-rich natural gas. The
However, gas technologies are currently during a crisis models were prepared and calculations were made using
caused by the unstable situation on the gas market. It can be commercial and in-house numerical softwares. In addition, the
seen when comparing recent energy production from gas- topics covered in this scientific work fit into the future process
fired plants to previous years [50]. This results in increased of water electrolysis to generate hydrogen using renewable
research on alternative fuels for gas turbines, such as energy sources. RES will be treated as a source of energy for the
hydrogen [51] or syngas. Both of these fuels also seem to fit in entire process. The hydrogen obtained in this way in case of
the idea of energy safety and low-emission energy
39628 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0

Fig. 1 e Schematic diagram of retrofits: a) CO2 sequestration by the amine method using MEA; AB e absorber, DE e desorber,
point A e flue gas inflow for sequestration, point B e steam bleed from ST for MEA regeneration, C e compressor for
compressing CO2 for storage or transport [32]; b) hydrogen generation from RES to stabilise the energy system: A e anode, K
e catode, EL e electrolite, TR e transmission, DC/AC e direct curent/alternating curent, RES e renewable energy source.

RES overgeneration will act as a energy storage (chemical fuel) output and 95 MW of heat output [55], however, the calcula-
used in periods of energy deman on the market. tions were conducted for ISO conditions and around 34 MW of
heat output as presented in Ref. [56]. All the reference data of
modelled CHP were based on three sources, namely: 1) the
2. Framework for the process simulations measurements and calculations presented at the heat and
power plant's website [55], 2) an article [56] where a mathe-
In the next sections (2.1 and 2.2), the reference cycle for which matical model of this CHP was made, and 3) the district heating
the retrofit was made will be presented, as well as validation part of the model was based on data presented in the research
for it to check the correctness of the calculations, respectively. report on the steam turbine used at this plant [57].
The thermodynamic cycle of the examined CHP is pre-
2.1. Reference plant sented in Fig. 2. The gas cycle consists of a gas expander (GT)
coupled with air compressor (C), an air filter at compressor
The considerations on the performance of a CCGT CHP plant inlet (F), compressed air extraction for first-stage GT blades
retrofitted with a CCS installation and hydrogen combustion cooling, combustion chamber (CC) and electrical power
were made basing on an existing heat and power plant in Zie- generator (G). Fuel compressor (Cfuel) is added for the purpose
lona Go
ra, Poland (Fig. 2). The F9E PG9171 gas turbine manu- of comparing electrical power input for different gaseous fuels
factured by General Electric was installed here. The combined compression. The heat recovery steam generator (HRSG)
heat and power plant has 190 MW of net electrical power consists of two steam pressure levels. The high-pressure

Fig. 2 e Reference cycle modelled in EBSILON®Professional [58] and EcoPG [59].

 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0 39629

section consists of two steam superheaters (SHHP I, II), an cycle diagram is shown at Fig. 2. For the purpose of verifying
evaporator (EVAP HP), two economizers (ECO HPI, II), and the correctness of the calculation model, the most important
water injection for control purposes (point 43). The low- available reference values from the literature were selected
pressure section includes a superheater (SHLP), an evapo- (as described in section 2.1), and the relative error of the
rator (EVAP LP), and an economizer (ECO LP). Steam turbine calculated values was calculated as the criterion for the cor-
(ST) is powered with steam at two different pressures. Steam rectness and accuracy of the model. The results are presented
extraction for heating purposes is also made at two levels of in Table 2. A satisfactory accuracy of the results was obtained,
pressure, respectively to DH1 and DH2 heat exchangers, with minimal mass flow rate of steam LP and flue gas tem-
heating up the water for oudside heat consumers (OC) at perature at the HRSG outlet. This is due to the assumption of
temperatures t44 ¼ 58 and t45 ¼ 78  C, for heating water return the pinch point at the level of 10 K, because it was not possible
and supply, respectively. Condensed water then flows to the to determine the literature value, which also affects the level
degasser. ST was modelled using four separate components to of cooling of the flue gas at the HRSG outlet. Based on these
include different internal efficiencies, resulting from steam results, it can be concluded that the presented models were
extraction and LP steam injection losses. The condensed made correctly and can be used for further thermodynamic
water is pumped using pumps (P). Important technical data of calculations.
the reference CHP, which was used for model validation in
EBSILON®Professional and in-house code EcoPG, is shown in 2.3. Amine-based absorption process and modelling
Table 1.
Cycle retrofits after adding CCS installation and fuel prepa-
2.2. Model validation ration station are presented in Fig. 3. A schematic diagram of
the considered amine-based absorption system is shown in
At present, when we want to make modifications in the tested Fig. 4. It was based on the model presented and calculated in
facilities as in this case, the gas and steam system installed in the articles: first Mostafavi E. et al., second Amrollahi Z. et al.
the Polish CHP plant located in Zielona Go
ra needs to be used [45,60]. An optimized model with absorber intercooling and
for he EBSILON®Professional and the in-house code EcoPG lean vapor recompression stripping has been chosen, as the
validation. These modifications concern the gas part of the most promising modification resulting in significant save of
facility. Validation is carried out using advanced computa- power demand for CCS system, with a relatively small cost
tional methods. This work uses the EBSILON®Professional increase [60]. 30% MEA e water solution has been chosen as
software and the EcoPG program. Both codes are based on the working fluid. The CSS model has been adopted as a single
momentum and energy mass balances and allow the model- component consisting of inputs and outputs, regarding power
ling CCGT cycles. inputs and fluid flows characterized at nodal points (8, 9, 25,
The data used for validation in the EBSILON®Professional 26, 29 in Figs. 3 and 4) adopted from the work of Amrollahi Z.
and EcoPG programs are included in Table 1, and the validated et al. [45]. Processes that happen inside the model borders are
modelled through performance inputs from the literature
[45,60] (two items already mentioned in this subchapter). Main
input parameters to the CSS installation are shown in Table 3
Table 1 e Technical data of the reference CCGT plant
assumed for model validation. and correspond to all fuel cases.
The principle of work of the CCS system is as follows. The
Parameter Symbol Value Unit
flue gas (nodal point 8 in Fig. 4) flowing at atmospheric pres-
GT model e F9E PG9171 e sure is cooled to 40  C and blown with a fan to the absorber to
GT gross electric power output Nel1 126.1 MW
overcome the pressure drop. In reality, it is the same fan as in
Flue gas flow _7
m 418 kg/s
Fig. 3, but here it was divided to cover pressure losses in the
Compressor pressure ratio P 12.6 e
GT inlet temperature t6 1100 
C absorber independently. In the absorber column flue gas
GT exhaust temperature t7 543 
C contacts the MEA (Figs. 1 and 4) solvent flowing counter-
ST model e 7CK-65 e currently and reacts with it following the reaction in Eq. (1).
ST gross electric power output Nel2 57.7 MW
(with considered heat extraction) C2 H4 OHNH2 þ H2 O þ CO2 ➝C2 H4 OHNH3 þ þ HCO3  þ DQ 1 (1)

HP turbine inlet temperature t21 505 C
HP turbine inlet pressure p21 72 bar
The reaction is exothermic so absorber intercooling is
EVAP HP pinch point dtHP 8 
C used to sustain the higher driving force of the absorption
 process and capacity of the solvent. The rich amine mass
LP turbine inlet temperature t23 217.9 C
LP turbine inlet pressure p23 6.62 bar flow rate (loaded with CO2) leaves the absorber, is preheated

EVAP LP pinch point dtLP 10 C in the heat exchanger (HX) and enters the stripper column.
Condenser pressure p27 0.051 bar
Meanwhile flue gas without CO2 leaves the absorber to the
Mass flow of water m_ 43 1.3 kg/s
scrubber, where some of the liquid water is recycled to the
injection to HP steam
Gross combined el. power output Nel1 þ Nel2 183.8 MW absorber, and the rest heads to the atmosphere (nodal point
Net electric power output Nel,net 177.8 MW 9). The rich solution is heated in the stripper using the heat
Net electric efficiency hel,net 47 % supplied to reboiler (R) (points 25, 26), and CO2 is stripped
Net heating capacity output Q_ HC 34.04 MW out of the solution, following the reaction opposite to Eq.
Combined Heat and Power hCHP,net 56 % (1), leaving at the top of the column (point 29). The lean
plant net efficiency solution leaving the stripper decreases its pressure through
39630 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0

Fig. 3 e Cycle retrofits after adding CCS installation and fuel preparation station.

Table 2 e Compilation of computational results and literature values to determine the relative error and correctness of the
reference computational model.
Parameter Symbol Reference value Value calculated Value calculated Absolute error Unit Relative error [%]
from operating in EBSILON in EcoPG
EBSILON EcoPG EBSILON EcoPG
data
GT electric power Nel1 126.1 126.5 121.2 0.4 4.9 MW 0.32 3.89
Electrical efficiency hel;TG 33.8 33.4 32.8 0.4 1 % 1.18 2.96
of the gas cycle
Exhaust gas mass flow m_6 418 418 418 0 0 kg/s 0 0

Exhaust gas temperature t6 1100 1098.85 1052.17 1.15 47.83 C 0.1 4.35
at GT inlet

Exhaust gas temperature t7 543 543.02 560.4 0.02 17.4 C 0 3.2
at GT outlet
LP steam mass flow _ 23
m 11.14 11.91 11.91 0.77 0.77 kg/s 6.91 6.91
HP steam mass flow _ 21
m 50.98 49.37 49.37 1.61 1.61 kg/s 3.16 3.16
Electrical Power ST Nel2 56.33 57.6 54.24 1.27 2.09 MW 2.25 3.71

a flash valve, so a gaseous phase composed of mainly water The influence of flue gas compositions for different fuels at
vapor is achieved. Then it's recompressed and recycled back sorption process has been neglected, as the content differences
to the stripper where the heat of condensation can be are rather small (no more than 1.5% difference) when compared
harnessed and the heat duty of the reboiler is reduced [45]. to coal fired plants [61]. The mass fluxes of water m _ w and MEA
The lean solution circles back to the absorber and the cycle m_ m that need to be replenished are also omitted. An assump-
is closed. tion of removing water m _ wF after the CO2 capture was made, so
From the perspective of modelling the CCS system few the stream heading for CO2 compression is pure CO2, even
assumptions have been made. The demand for electric power though the real purity for this case is around 96% [45]. Tem-
(pumps, fan, compressor) and heat for the installation to work peratures and pressures at the inlet and outlet of the CO2 cap-
is described using fixed parameters dependent on the ture are fixed, as the process requires, and are shown in Table 3.
captured CO2 mass flow, so the energy balance looks as in Eqs. CO2 compression was modelled using three stage
(2) and (3). compressor, from 1.01 bar to storage pressure at 110 bar,
proposed in different papers before [45,46]. Inter-stage cooling
H _ 25 ¼ H
_ 8 þ NF þ NP1;2 þ NC þ NWH;i þ H _ 9 þH
_ 26 þ H
_ 29
X was implemented to reduce the power input of compressors,
þ _
Q WH;i ½MW (2) with water cooling to 35  C as proposed by Kvamsdal HM,
Jordal K and Bolland O [28]. The pressure ratios of all three
X
_ 8 þm
H _ 29 $qel;CO2 þ m _ 9 þH
_ 29 $qH;CO2 ¼ H _ 29 þ Q_ WH;i ½MW (3) stages were similar to achieve close to equal power inputs and
temperatures of CO2 after each stage. Pressure after first stage
 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0 39631

Fig. 4 e Schematic diagram of the considered amine-based absorption system.

Table 3 e Main parameters adapted for the modelled amine-based absorption system (based on [45]).
Parameter Symbol Value Unit
CO2 capture rate e 0.9 e

  kg !#
Amount of MEA solvent e 16.27 kgMEA CO2;fg
s s

!#
Flue gas pressure drop in absorber column DpA 128.6 kg CO2;fg
Pa=
s
Flue gas inlet pressure p8 1.01 bar
Flue gas outlet pressure p9 1.01 bar

Flue gas inlet temperature t8 48 C

Flue gas outlet temperature t9 45 C
Flue gas mass flow m_8 418 kg/s
CO2 outlet pressure p29 1.01 bar

CO2 outlet temperature t29 30 C
Steam to reboiler pressure p25 4 bar

Steam to reboiler temperature t25 145 C

Water from reboiler temperature t26 130 C
Pressure drop in reboiler DpR 0.08 bar
Electric power demand to the system qel;CO2 0.25 MJ=kgCO2
Heat demand to reboiler qH;CO2 2.71 MJ=kgCO2

of the compressor is equal to 5 bar, after the second stage e significant demand for steam extraction to the reboiler, to strip
23 bar, and after the last stage, it equals 110.1 bar, just slightly the CO2 out of the solution. The steam is extracted from the
more than storage pressure to overcome the pressure drop in turbine at a pressure of slightly over 4 bars, so it reaches the CO2
the last cooler. capture reactor at exactly 4 bars. However, the steam needs to
be cooled to around 145  C [45] which is done through applying
2.4. CCS model integration with CHP plant a heat exchanger at the last part of the municipal heating water
cycle. The condensate leaving reboiler at 130  C is used to heat
To examine the impact of the proposed CO2 capture system on up the municipal water and is cooled to 80  C held constant,
the performance of reference power plant with different fuels and then pumped back to the water cycle of power plant.
considered, some modifications were implemented. The mod- Flue gas leaving the HRSG needs to be cooled to 48  C before
ifications are shown in Fig. 3 with a dashed line. These are entering the reactor. It is a significant amount of heat as the
mostly connected to the steam part of cycle, as there is flue gases leaving HRSG have over 130  C. Heat recovery from
39632 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0

the flue gas is proposed and applied to preheat municipal Fazli-Khalaf et al. [80] presents the possibility of hydrogen
water. Flue gas cooling to 74  C is assumed and held constant, production using the SeI nuclear thermochemical system.
and after-cooling is done in a second cooler. Constant tem- Another method of hydrogen production is the gasification
perature conditions may result in different heat outputs of the of coal or biomass. The advantage of gasification is the treat-
plant, however no lower than nominal, because steam ment of biomass as a renewable resource characterized by
extraction is then used. The concept of recovering flue gas very low greenhouse gas emissions, which is desirable given
heat is important especially when it comes to higher heat the current trends towards their minimization. In case of coal
demands at winter, and fuels with more carbon content, gasification, it is one main disadvantage is releasing green-
where more CO2 is produced which drives the demand of house gases generated during hydrogen production.
reboiler's heat; additionally, steam extraction to DH1 and DH2 Hydrogen can be produced from biofuels and biomass
is used to cover higher heat demands. This helps maintaining [81,82], which have a number of advantages concerning the
constant CO2 capture ratio, without significant redesigning or ease of obtaining renewable and environmentally friendly
adding an extra GT for steam production, as presented by source [83] and also reducing the consumption of crude oil
Bartela Ł. et al. [61]. [84]. On the other hand, biofuels also have disadvantages, in
particular, high costs [85]. One of the sources of biomass may
2.5. Hydrogen production and integration with the cycle be algaes [86,87] which purify water and sewage but also
reduce greenhouse gas emissions [88]. One of the way to
For several years, there has been a growing demand for obtain biohydrogen precisely by direct photolysis of water
hydrogen in the world [62,63], and according to forecasts, it includes using algaes, but if anaerobic algeas growth occurs in
will continue to grow [12,64], depending on the assumptions the light, then, in this case, the hydrogenises enzyme should
from the level of 73 to even 567 Mt/year [65]. Scientists see the be additionally applied [88]. In the first case, we have less
benefit of using hydrogen in industry, e.g., heating [66] or hydrogen production than in the second. Still, in the second,
heavy transport [66]. The use of hydrogen in the energy sector there is a higher energy consumption due to the continuous
together with renewable energy sources will allow the illumination of algaes and the use of the enzyme. The cost of
decarbonization process to be carried out worldwide [67,68]. In producing biofuel from algaes is relatively high because 77% of
addition, hydrogen may enable the storage of overgenerated expenditures in breeding. However, prices of algeas can be
electric power from renewable energy sources [69]. reduced by algaes production from municipal or industrial
In the literature, it can be found works showing the interest wastewater [89,90].
of researchers in the use of hydrogen to drive gas turbines The advantages of using algaes are: firstly, their ability to
[20,67,70]. The technologies used in turbines allow the use of sequester up to 1.3 kg of CO2 while producing 1 kg of biomass
various gaseous or liquid fuels [71e73]. Among the gaseous derived from them [89]; secondly, a possibility to remove ni-
fuels, we can mention, for example, hydrogen, methane and trogen and phosphorus. Algae biomass can also generate
syngas [25] and in the group of liquid fuels: biodiesel [72] or biofuels other than biohydrogen, such as bioethanol or bio-
bioethanol [74]. butanol. The efficiency of the hydrogen production from
One of the goals presented in the European Hydrogen algeas is similar to both ways of breeding, namely: increase of
Strategy is to replace 10 Mt of hydrogen produced from steam- algeas in sewage treatment plants and farms [91]. Microbial
methane reforming (SMR) of natural gas with hydrogen that fuel cells could be integrated with wastewater treatment
can be produced using renewable energy sources and elec- plants and enable the production of biohydrogen [92].
trolysis. This process will be expected to be completed by 2030 Futhermore, sewage-derived algae are more popular in
[25]. biopolymers production [93,94] that will improve the envi-
Various hydrogen production technologies and processes ronment by not applying polypropylene and polyvinyl from oil
can be found in the literature. There are three most popular and replacing this substances with algeas biopolymers [95].
ways to produce hydrogen: steam methane reformation [23], Biopolymers derived from algaes will be biodegradable and
gasification and electrolysis [65]. In addition to those environmentally friendly due to the fact, bioplastic will be
mentioned to a lesser extent, bio-waste from fermentation obtained [96]. Therefore, in algaes biomass the dominant el-
processes [63,75] or electrolysis and biodiesel from algae [76], ements are carbon and hydrogen [97].
as well as refining bio-waste can be used to produce hydrogen.
In the industrial production of hydrogen, the SMR method 2.6. Fuel assumptions
is relatively inexpensive [77]. This method has disadvantages
resulting from the large manufacturing of greenhouse gases. Fuel compositions and lower heating values (LHV) are pre-
Another well-known process is water electrolysis, the sented in Table 4. Besides the reference case, pure methane,
importance of which is expected to grow in the hydrogen syngas [24], pure hydrogen and a mixture of hydrogen and
production market. This increase is due to low greenhouse gas methane [53] are presented. Only a case basing on pure
emissions when using renewable energy sources to produce hydrogen was modelled without CCS installation. Fuel com-
electricity. What is worth emphasizing in this technology, pressors have been modelled to compare the power outputs
alkaline electrolysers used for electrolysis are cheaper and for different fuels and mass flow rates, assuming that all the
more reliable than the opposite oxide electrolysers [78]. fuels are not provided under the right pressure from the gas
In the literature on this subject, it is presented a paper distribution grid. Table 4 shows that the highest LHV is ob-
where Schnuelle et al. [79] show that hydrogen production can tained for pure hydrogen and it is almost 3 times higher than
be modelled using a solar thermochemical system. However, for nitrogen-enriched natural gas, followed by a mixture of
 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0 39633

Table 4 e Fuel compositions and LHV in [MJ/kg].

Fuel type Symbol Fuel compositions by volumetric shares LHV
Nitrogen-enriched natural gas NNG 87% CH4, 12.3% N2, 0.3% C2H6, 0.2% CO2, 0.1% C3H8, 0.1% C4H10 39.98
Methane M 100% CH4 50.015
Syngas S 45.17% H2, 25.61% CO2, 13.64% CH4, 9.09% CO, 3.39% C3H8, 3.1% NH3 17.086
Hydrogen H 100% H2 120
Hydrogen þ Methane HþM 88.8% H2, 11.2% CH4 86

hydrogen and methane. It should be emphasized that the

technology of electrolyzers, which is currently under devel- P
opment, can be used to produce this hydrogen. Besides the Nel1 þ Nel2 þ Q_ HC  Nel: demand;i
hCHP;net ¼ $100 ½% (7)
most developed methods such as alkaline and polymer elec- _ 1F $LHV
m
trolysers, other methods might be used such as SOEC (Solid
Oxide Electrolyzer Cell) electrolyzers which are in the phase of
research and pilot installations. SOEC technology has the
Electrical power penalty (8):
potential to be used especially in large production facilities.
Alkaline and polymer electrolysers are low-temperature de-
vices where water decomposes in a liquid state, while oxide h X i
electrolysers are high-temperature electrolysers (850e950  C) DNel ¼ Nel1 þ Nel2  Nel: demand;i
wo: retr:
[30]. h X i
 ðNel1 þ Nel2 Þ  Nel: demand;i ½MW (8)
with retr:
2.7. CHP with CO2 capture performance indicators

The analysis of syngas and other fuels combustion, combined

CHP plant net efficiency penalty (9):
with CO2 capture, and hydrogen combustion was performed
using different indicators. Some of them, such as efficiency,
emissivity or SPECCA might correspond to local changes
(change between reference plant with various fuel and after DhCHP;net ¼ ðhCHP;net Þwo: retr:  ðhCHP;net Þwith retr: ½% (9)
retrofit) or global (change between reference plant with
nitrogen-enriched fuel and after retrofit with any other fuel).
Symbols not explained under the equations refer to quantities

Specific CO2 emissions (10) [9]:
shown in Fig. 3. The indicators are as follows.

Gross electrical efficiency (4):


3600$XCO2 $m_9 kg CO2
eCO2 ¼ P (10)
Nel1 þ Nel2 þ Q_ HC  Nel: demand;i MWh
Nel1 þ Nel2 m_ 9 mass flow of CO2 emitted to the atmosphere with flue
hel;gross ¼ $100 ½% (4)
m_ 1F $LHV gases [kg/s].
XCO2 CO2 mass fraction in flue gases []

Net electrical efficiency (5):
Specific CO2 emissions avoided (11):

P

Nel1 þ Nel2  Nel: demand;i kg CO2
hel;net ¼ $100 ½% (5) eCO2 ;avoided ¼ eCO2 ;wo: retr:  eCO2 ;with retr: (11)
m _ 1F $LHV MWh
P
Nel: demand;i sum of all electric power demands such as
compressors, pumps, fans, CO2 reactor electricity demand etc.

Specific primary energy consumption for CO2 avoided

CHP plant gross efficiency (6): (SPECCA) (12) [9]:

 " #
Nel1 þ Nel2 þ Q_ HC
1 1

hCHP;gross ¼ $100 ½% (6) ðhCHP;net Þwith retr: ðhCHP;net Þwo: retr: MJ
m_ 1F $LHV SPECCA ¼ 360000$ (12)
eCO2 ;wo:retr:  eCO2 ;with retr: kgCO2

CHP plant net efficiency (7):

39634 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0

globally referring, is achieved e 1.3%, which results in the best

3. Results and discussion CHP net efficiency among all the cases after retrofit. This low
penalty is caused by over three times higher demand for fuel
In this section, several aspects of considered retrofits were compression but compensated by gain of 5.5 MW of GT's
presented and discussed, focusing mostly on power plant electrical power, overall resulting in nearly 6 MW of power
performance and emission related indicators. As stated pre- loss.
viously, some results refer to local changes, where considered Electrical efficiency penalties are slightly higher than CHP
plant before and after retrofit operates at the same fuel, and efficiency penalties, except of syngas combustion, where an
global changes, where the results are compared to reference additional 1.3% efficiency penalty occurred, as an effect of
plant without CO2 capture. omitting the gain of heat for municipal heating. Plants based
on hydrogen combustion achieve the highest electrical effi-
3.1. Plant performance indicators before and after ciencies among all cases, even though before retrofit they
retrofit performed noticeably worse than the reference case.

Electrical and CHP efficiencies were calculated to compare 3.2. Emission indicators before and after retrofit
qualitatively the considered fuels with a combination of CO2
capture technology (except hydrogen), resulting in efficiency Besides performance results, indicators for CO2 emission
penalties for the entire cycle. Fig. 5 presents CHP net local and reduction need to be studied, taking into consideration energy
global efficiencies of the plant after the retrofit. For the refer- costs for carbon capture. In Fig. 7 specific CO2 emissions,
ence case of fuel and methane similar results were obtained, corresponding to overall CHP power instead of just electric
where 6.3% efficiency penalty is observed decreasing the ef- power, as a more representative value for this case of study,
ficiency to 49.6%. Using syngas as fuel resulted in significantly are shown. The CO2 emissions were calculated as defined in
higher efficiency penalties, especially when comparing glob- Eq. (10), and additionally CO2 emissions avoided are presented
ally, where 8.6% efficiency loss was calculated. This high loss according to Eq. (11). The reference to local and global values is
corresponds to the electrical power penalty, as can be seen in explained in the introduction to subsection CHP with CO2
Fig. 6 especially when including 4.8 MW of heat that was capture performance indicators. Reference case, as well as
gained for the same temperature conditions. These losses methane combustion results, are very similar, where emis-
result of higher fuel compressor power input (lower LHV than sivity at a level of 40 kgCO2/MWh with 317 kgCO2/MWh
for reference case resulted in 2.3 times higher fuel mass flow) reduction is observed, comparing to plant without retrofit. CO2
and higher CO2 capture, and compression power demand, as capture for syngas combustion resulted in huge emissivity
for the same capture efficiency higher CO2 mass flow was reduction at the level of 460 kgCO2/MWh locally. However,
obtained. Also around 5 MW more of electrical power was lost, globally the reduction is slightly lower e 296 kgCO2/MWh, as
when comparing to reference plant with CCS, as an effect of higher final emissions of 61 kgCO2/MWh can be seen.
higher steam extraction mass flow to cover reboiler demand. The methodology of this paper does not take into account
Hydrogen and methane combustion present significantly the legal specifics, which in some countries, including Poland,
lower CHP efficiency penalty, as the captured CO2 stream is allow for renewable fuels after CO2 capture to achieve a pos-
over three times smaller than for the reference case, so the itive environmental impact. In this case, we are talking about
previously mentioned power demands are lower as well, and a power plant with negative CO2 emissions [98]. In other
4 MW more of electrical power are generated at the GT, as a words, in the case of syngas from sewage sludge gasification,
result of higher LHV value. The best option seems to be pure negative CO2 emissions [99] would be achieved. Thus, the
hydrogen combustion, as the lowest efficiency penalty, when emissivity in this work referred only to the amount of carbon

Fig. 5 e Net CHP efficiencies and efficiency penalties of CCGT plant after retrofitting with CCS system or hydrogen
combustion: a) locally, b) globally. The horizontal axis refers to fuel types shown in Table 4.
 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0 39635

Fig. 6 e Net electrical efficiencies and efficiency penalties of CCGT plant after retrofitting with CCS system or hydrogen
combustion: a) locally, b) globally. The designation of names on the horizontal axis shows Table 4.

Fig. 7 e Specific CO2 emissions before and after retrofit of the plant.

dioxide emitted into the environment, without taking into valuable also for CCGT and CHP plants, especially when
account the legal situation in the country. considering additional energy-saving actions as provided in
Finally, no emissions of CO2 for hydrogen combustion are subsection: CCS model integration with CHP plant. It is also
achieved, followed by an emissivity of 11.3 kgCO2/MWh for worth noting are the SPECCA values for syngas combustion
hydrogen þ methane combustion. Obviously, the highest CO2 which in this case might be as low as for CCGT burning methane
emissions avoided globally were achieved for these two [100,101]. This allows to burn this high-carbon content fuel with
hydrogen fuels, having the most positive ecological impact on similar energy penalty and ecological impact.
the environment. As a result of this comparison it can be Fig. 8 presents SPECCA for all the examined cases. A cost of
seen, that it is theoretically possible to design low-emissive 2.6 MJ/kgCO2 was obtained for the reference case and
power sources burning fossil fuels, basing on the current methane combustion. What is worth noticing, a slight
technology. This is a valuable result for the purpose of energy decrease of SPECCA locally for syngas was achieved to a value
transformation, before hydrogen technology can be used of 2.4 MJ/kgCO2, as a result of heat gain. However, when
widely. referring to the reference case, the cost stands out from the
However, specific CO2 emissions provide us information only others at a level of 3.9 MJ/kgCO2. SPECCA indicator globally
about the ecological aspect of plants after retrofit, with regards came out the best for hydrogen/hydrogen þ methane com-
to the power produced. As a measure of energy cost related to bustion, 1 MJ/kgCO2 and 0.4 MJ/kgCO2 respectively. According
CO2 capture, a SPECCA indicator is implemented, which was to Refs. [100,101], SPECCA for CCGT with simple amine-based
introduced by Campanari et al. [100]. However, authors (Cam- CO2 capture considered, was equal to 3.2e4 MJ/kgCO2, which
panari S. et al. and Bonalumi D. et al.) in Refs. [100,101] refer this is comparable to syngas combustion in this case. For methane
index to electrical efficiencies, and the reference plants are and reference case, over 0.8 MJ/kgCO2 of savings were made,
considered as the state-of-the-art CCGT plants. For the purpose and 2.2e2.8 MJ/kgCO2 for hydrogen based fuels. However, it is
of this paper, referring to CHP net efficiencies seems to be more worth noting that equally good results as for the case with
accurate, as there are some gains in heating power, and it is also hydrogen are achieved for the system considered in the work
a product of the power plant. Relatively low SPECCA values as [24], namely for the negative emission carbon dioxide power
comparing to other authors [100,101] show that CCS might be plant.
39636 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0

Fig. 8 e SPECCA indicators for proposed retrofits.

organic substances for energy generation are introduced to

4. Conclusions and future development reduce the consumption of traditional energy sources.
directions Hydrogen combustion and co-combustion lead to the best
results, both regarding low plant performance penalties and
This article presents the possibilities of reducing CO2, which is low CO2 emissions to the atmosphere. With the development
necessary to adapt to requirements imposed on countries by of power cells and ground-breaking progress of hydrogen
the EU and the internal energy policy of a given country. combustion in GT, it may in fact be the future of the world's
Currently, the policy focuses on the development and use of energetics. There is still a lot to achieve, however, the results
renewable energy sources to the greatest extent. In a country of this paper show clearly that it makes sense to continue
such as Poland, it is nowadays impossible to close power plants research on this technology.
using solid fuels and produce energy only from RES. Therefore, In the next stage of the work, it is worth conducting an
carrying out actions aimed at reducing the production of economic analysis of the proposed solutions to indicate the
greenhouse gases from the combustion of solid fuels is neces- payback period for the installation of the carbon capture,
sary. Hence, this paper presents the opportunity of retrofitting electrolyzer, or gasification reactor, respectively. In turn, the
the existing CCGT CHP plant in Poland with a system based on main gains will deprive from avoided CO2 emission costs. In
the CCS. To achieve thermodynamic performance of modern- the case of sewage sludge, there will also be a profit from the
ization, numerical models and calculations were prepared in disposal of this harmful waste [98,102]. It is still reasonable to
two software, namely a commercial programme Ebsilon and in- consider other types of fuel, namely biofuels produced from
house code EcoPG. This article compares various efficiency and algaes, wood, straw, etc [103]. Forward-looking work also
emission factors for several fuel cases, such as syngas coupled includes Computational Fluid Dynamics analyses, which can
to an amine-based CCS. Few heat recovery systems were show a change in the emissivity of components such as CO
introduced into CHP to limit steam extraction for heating pur- and NOx. In terms of durability analyses, it will be important
poses, thus mitigating electrical power losses, which were a to determine the flame length and temperature field both in
result of steam extraction to cover reboiler demand. This led to the combustion chamber and in the subsequent expander
lower efficiency penalties and better SPECCA indicators for stages [104,105]. Therefore, the present issues carry a whole
fuels like methane and nitrogen-enriched gas when compared field of perspectives for further research that contributes to
to other authors [100]. In the case of the reference fuel and increasing the share of renewable energy sources in the en-
methane, similar results were obtained, e.g. a decrease in effi- ergy mix.
ciency by 6.3% p. p., the efficiency reduction to 49.6%. Addi-
tionally, CO2 emission at the level of 40 kgCO2/MWh is obtained
with a reduction by 317 kgCO2/MWh compared to the instal- Declaration of competing interest
lation without modernization.
Syngas combustion is characterized by the worst results The authors declare that they have no known competing
for all the indicators examined, mostly because of its high financial interests or personal relationships that could have
carbon content (see Table 4) and low LHV. However, it is appeared to influence the work reported in this paper.
important to notice that this is an alternative fuel, so perhaps
with an increase of prices for CO2 emission allowances and
conventional fuels, it could be a competitive technology. Thus, Acknowledgements
in Fig. 7., a local CO2 emission reduction by 460 kgCO2/MWh
was achieved. In addition, syngas can be produced from a
sk University of
Financial support of these studies from Gdan
variety of unfavourable substances, e.g. sewage sludge, and it Technology by the DEC-50/2020/IDUB/I.3.3 grant under the
may then be useful to dispose of the resulting fuel [16]. As a ARGENTUM TRIGGERING RESEARCH GRANTSdEIRU program
result of biofuel syngas production from sewage sludge, is gratefully acknowledged.
 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0 39637

Ebsilon®Professional 15.00, Steag Energy Services GmbH cooled reactor. Pol Marit Res 2018;25:204e10. https://
program was used for numerical calculations provided by doi.org/10.2478/pomr-2018-0043.
[14] _
Głuch J, Krzyzanowski J. New attempt for diagnostics of the
Flextek company for research purposes.
geometry deterioration of the power system based on
thermal measurement. Proc. ASME Turbo Expo
references 2006;2:531e9. Barcelona: 2006.
[15] Takeda S, Nam H, Chapman A. Low-carbon energy
transition with the sun and forest: solar-driven hydrogen
[1] Javadi M, Jafari N, Khalili M, Jabery R. 4E analysis of three production from biomass. Int J Hydrogen Energy
different configurations of a combined cycle power plant 2022;47:24651e68. https://doi.org/10.1016/
integrated with a solar power tower system. Sustain Energy j.ijhydene.2021.11.203.
Technol Assessments 2021;48:101599. https://doi.org/ [16] Ertesvåg IS, Madejski P, Zio
łkowski P, Mikielewicz D. Exergy
10.1016/j.seta.2021.101599. analysis of a negative CO2 emission gas power plant based
[2] Mohammed RK, Farzaneh H. Life cycle environmental on water oxy-combustion of syngas from sewage sludge
impacts assessment of post-combustion carbon capture for gasification and CCS. Energy 2023;278:127690. https://
natural gas combined cycle power plant in Iraq, considering doi.org/10.1016/j.energy.2023.127690.
grassroots and retrofit design. Energies 2023;16. https:// [17] Ritchie H, Roser M, Rosado P. CO₂ and Greenhouse Gas
doi.org/10.3390/en16031545. Emissions Published online at OurWorldInData.org. Global
[3] Witanowski Ł, Zio
łkowski P, Klonowicz P, Lampart P. A Carbon Project; 2020. https://ourworldindata.org/co2-and-
hybrid approach to optimization of radial inflow turbine other-greenhouse-gas-emissions. Accessed 1 May 2022.
with principal component analysis. Energy 2023;272. [18] Weger L, Aba
nades A, Butler T. Methane cracking as a
https://doi.org/10.1016/j.energy.2023.127064. bridge technology to the hydrogen economy. Int J Hydrogen
[4] Dominiczak K, Drosin
ska-Komor M, Rza˛dkowski R, Głuch J. Energy 2017;42:720e31. https://doi.org/10.1016/
Optimisation of turbine shaft heating process under steam j.ijhydene.2016.11.029.
turbine run-up conditions. Arch Therm 2020;41:255e68. [19] Gilassi S, Taghavi SM, Rodrigue D, Kaliaguine S. Techno-
https://doi.org/10.24425/ather.2020.135863. economic evaluation of membrane and enzymatic-
[5] Bren _

kacz Ł, Zywica G, Drosin
ska-Komor M. The absorption processes for CO2 capture from flue-gas. Sep
experimental identification of the dynamic coefficients of Purif Technol 2020;248:116941. https://doi.org/10.1016/
two hydrodynamic journal bearings operating at constant j.seppur.2020.116941.
rotational speed and under nonlinear conditions. Pol Marit [20] Cloete S, Ruhnau O, Hirth L. ScienceDirect on capital
Res 2017;24:108e15. https://doi.org/10.1515/pomr-2017- utilization in the hydrogen economy : the quest to minimize
0142. idle capacity in renewables- rich energy systems. Int J
[6] Głuch J. Selected problems of determining an efficient Hydrogen Energy 2020;46:169e88. https://doi.org/10.1016/
operation standard in contemporary heat-and-flow j.ijhydene.2020.09.197.
diagnostics. Pol Marit Res 2009;16:22e6. https://doi.org/ [21] Cownden R, Mullen D, Lucquiaud M. ScienceDirect towards
10.2478/v10012-008-0040-6. net-zero compatible hydrogen from steam reformation e
[7] Zio
łkowski P, Głuch S, Zio
łkowski PJ, Badur J. Compact high Techno-economic analysis of process design options. Int J
efficiency and zero-emission gas-fired power plant with Hydrogen Energy 2023. https://doi.org/10.1016/
oxy-combustion and carbon capture. Energies 2022;15:2590. j.ijhydene.2022.12.349.
https://doi.org/10.3390/en15072590. [22] Aburime EI, Omoregbe O, Amenaghawon NA, Aziaka DS,
[8] Zio
łkowski P, Szewczuk-Krypa N, Butterweck A, Stajnke M, Tashie-Lewis BC. Amino-2-methyl-1-propanol-based post-
Głuch S, Drosin
ska-Komor M, et al. Comprehensive combustion capture process with solvent storage for
thermodynamic analysis of steam storage in a steam cycle decarbonisation of natural gas combined cycle power plant.
in a different regime of work: a zero-dimensional and three- Carbon Capture Sci Technol 2022;2:100024. https://doi.org/
dimensional approach. J Energy Resour Technol 10.1016/j.ccst.2021.100024.
2021;143:1e27. https://doi.org/10.1115/1.4052249. [23] Klatzer T, Bachhiesl U, Wogrin S. State-of-the-art expansion
[9] Madejski P, Chmiel K, Subramanian N, Ku
s T. Methods and planning of integrated power, natural gas, and hydrogen
techniques for CO2 capture: review of potential solutions systems. Int J Hydrogen Energy 2022;47:20585e603. https://
and applications in modern energy technologies. Energies doi.org/10.1016/j.ijhydene.2022.04.293.
2022;15:887. https://doi.org/10.3390/en15030887. [24] Zio
łkowski P, Madejski P, Amiri M, Ku
s T, Stasiak K,
[10] Suchocki T, Witanowski, Lampart P, Kazimierski P, Subramanian N, et al. Thermodynamic analysis of negative
Januszewicz K, Gawron B. Experimental investigation of CO2 emission power plant using aspen plus, aspen hysys,
performance and emission characteristics of a miniature and Ebsilon software. Energies 2021;14. https://doi.org/
gas turbine supplied by blends of kerosene and waste tyre 10.3390/en14196304.
[25] €
Oberg S, Odenberger M, Johnsson F. The value of flexible
pyrolysis oil. Energy 2021;215:119125. https://doi.org/
10.1016/j.energy.2020.119125. fuel mixing in hydrogen-fueled gas turbines e a techno-
_
[11] Madejski P, Zymełka P. Calculation methods of steam boiler economic study. Int J Hydrogen Energy 2022;47:31684e702.
operation factors under varying operating conditions with https://doi.org/10.1016/j.ijhydene.2022.07.075.
the use of computational thermodynamic modeling. Energy [26] Drosin
ska-Komor M, Głuch J, Brzezin
ska-Gołe˛biewska K,
2020;197. https://doi.org/10.1016/j.energy.2020.117221. Piotrowicz M, Zio
łkowski P. Conditions for increasing the
[12] Weidner T, Tulus V, Guille
n-Gosa
lbez G. Environmental recognition of degradation in thermal-flow diagnostics,
sustainability assessment of large-scale hydrogen taking into account environmental legal aspects. J Power
production using prospective life cycle analysis. Int J Technol 2023;103:33e48.
Hydrogen Energy 2023;48:8310e27. https://doi.org/10.1016/ [27] Website of the Republic of Poland. Energy policy of Poland
j.ijhydene.2022.11.044. until 2040. n.d. https://www.gov.pl/web/klimat/polityka-
[13] Szewczuk-Krypa N, Drosin
ska-Komor M, Głuch J, energetyczna-polski (accessed May 1, 2022).
Bren
kacz L. Comparison analysis of selected nuclear power [28] Abudu K, Igie U, Roumeliotis I, Hamilton R. Impact of
plants supplied with helium from high-temperature gas- gas turbine flexibility improvements on combined cycle
39638 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0

gas turbine performance. Appl Therm Eng [45] Amrollahi Z, Ystad PAM, Ertesvåg IS, Bolland O. Optimized
2021;189:116703. https://doi.org/10.1016/ process configurations of post-combustion CO2 capture for
j.applthermaleng.2021.116703. natural-gas-fired power plant e power plant efficiency
[29] General Electrics. Breaking the power plant efficiency analysis. Int J Greenh Gas Control 2012;8:1e11. https://
record again. 27 March 2018. n.d, https://www.ge.com/gas- doi.org/10.1016/j.ijggc.2012.01.005.
power/resources/articles/2018/nishi-nagoya-efficiency- [46] Mondino G, Grande CA, Blom R, Nord LO. Moving bed
record. [Accessed 1 May 2022]. temperature swing adsorption for CO2 capture from a
[30] Chmielniak T, Chmielniak T. Energetyka wodorowa. natural gas combined cycle power plant. Int J Greenh Gas
Wydawnictwo Naukowe PWN; 2020. Control 2019;85:58e70. https://doi.org/10.1016/
[31] Badyda K. Perspektywy rozwoju technologii turbin j.ijggc.2019.03.021.
gazowych oraz bloko
w gazowo-parowych. Rynek Energii; [47] Carapellucci R, Giordano L, Vaccarelli M. Study of a natural
2014 [Sierpien
]. gas combined cycle with multi-stage membrane systems
[32] Kotowicz J. Stan i perspektywy rozwoju układo
w gazowo- for CO2 post-combustion capture. Energy Proc
parowych. Arch Energ 2012:23e38. 2015;81:412e21. https://doi.org/10.1016/
[33] Descamps C, Bouallou C, Kanniche M. Efficiency of an j.egypro.2015.12.114.
integrated gasification combined cycle (IGCC) power plant [48] Oh SY, Yun S, Kim JK. Process integration and design for
including CO2 removal. Energy 2008;33:874e81. https:// maximizing energy efficiency of a coal-fired power plant
doi.org/10.1016/j.energy.2007.07.013. integrated with amine-based CO2 capture process. Appl
[34] Zio
łkowski P, Badur J, Zio

łkowski PJ. An energetic analysis of Energy 2018;216:311e22. https://doi.org/10.1016/
a gas turbine with regenerative heating using turbine j.apenergy.2018.02.100.
extraction at intermediate pressure - brayton cycle advanced [49] Lungkadee T, Onsree T, Tangparitkul S, Janwiruch N,
according to Szewalski's idea. Energy 2019;185:763e86. Nuntaphan A, Tippayawong N. Technical and economic
https://doi.org/10.1016/j.energy.2019.06.160. analysis of retrofitting a post-combustion carbon capture
[35] Zio
łkowski P, Kowalczyk T, Leman
ski M, Badur J. On energy, system in a Thai coal-fired power plant. Energy Rep
exergy, and environmental aspects of a combined gas- 2021;7:308e13. https://doi.org/10.1016/j.egyr.2021.06.049.
steam cycle for heat and power generation undergoing a [50] PSE. 2020/2021 Reports n.d. https://www.pse.pl/dane-
process of retrofitting by steam injection. Energy Convers systemowe/funkcjonowanie-kse/raporty-roczne-z-
Manag 2019;192:374e84. https://doi.org/10.1016/ funkcjonowania-kse-za-rok/raporty-za-rok-2021#t1_1
j.enconman.2019.04.033. (accessed May 1, 2022).
[36] Li D, Hu Y, Li D, Wang J. Combined-cycle gas turbine power [51] Abe JO, Popoola API, Ajenifuja E, Popoola OM. Hydrogen
plant integration with cascaded latent heat thermal storage energy, economy and storage: review and recommendation.
for fast dynamic responses. Energy Convers Manag Int J Hydrogen Energy 2019;44:15072e86. https://doi.org/
2019;183:1e13. https://doi.org/10.1016/ 10.1016/j.ijhydene.2019.04.068.
j.enconman.2018.12.082. [52] Choi S, Davenport TC, Haile SM. Protonic ceramic
[37] International Energy Agency. Carbon capture, utilisation and electrochemical cells for hydrogen production and
storage n.d. www.iea.org/fuels-and-technologies/carbon- electricity generation: exceptional reversibility, stability,
capture-utilisation-and-storage (accessed May 1, 2022). and demonstrated faradaic efficiency. Energy Environ Sci
[38] Andrews JW. Hydrogen production and carbon 2019;12:206e15. https://doi.org/10.1039/c8ee02865f.
sequestration by steam methane reforming and fracking [53] Kowalczyk T, Badur J, Bryk M. Energy and exergy analysis of
with carbon dioxide. Int J Hydrogen Energy 2020;45:9279e84. hydrogen production combined with electric energy
https://doi.org/10.1016/j.ijhydene.2020.01.231. generation in a nuclear cogeneration cycle. Energy Convers
[39] Padurean A, Cormos C-C, Agachi P-S. Pre-combustion Manag 2019;198:111805. https://doi.org/10.1016/
carbon dioxide capture by gaseliquid absorption for j.enconman.2019.111805.
Integrated Gasification Combined Cycle power plants. Int J [54] Taamallah S, Vogiatzaki K, Alzahrani FM, Mokheimer EMA,
Greenh Gas Control 2012;7:1e11. https://doi.org/10.1016/ Habib MA, Ghoniem AF. Fuel flexibility, stability and
j.ijggc.2011.12.007. emissions in premixed hydrogen-rich gas turbine
[40] Lawal A, Wang M, Stephenson P, Yeung H. Dynamic combustion: technology, fundamentals, and numerical
modelling of CO2 absorption for post combustion capture in simulations. Appl Energy 2015;154:1020e47. https://doi.org/
coal-fired power plants. Fuel 2009;88:2455e62. https:// 10.1016/j.apenergy.2015.04.044.
doi.org/10.1016/j.fuel.2008.11.009. [55] CHP plant in Zielona Go
ra n.d. http://www.ec.zgora.pl/
[41] Keivani B, Gungor A. Techno-economic assessment of coal technologia/urzadzenia-wytworcze (accessed May 3, 2022).
and torrefied biomass co-combustion: a case study of oxy- [56] Plis M, Rusinowski H. A mathematical model of an existing
combustion carbon capture power plants in Turkey. J CO2 gas-steam combined heat and power plant for thermal
Util 2022;62:102103. https://doi.org/10.1016/ diagnostic systems. Energy 2018;156:606e19. https://
j.jcou.2022.102103. doi.org/10.1016/j.energy.2018.05.113.
[42] Yadav S, Mondal SS. A review on the progress and prospects [57] Gardzilewicz A, Marcinkowski S, Karwacki J. Badania
of oxy-fuel carbon capture and sequestration (CCS) cieplno e przepływowe turbiny 7CK-65 w Elektrociepłowni
technology. Fuel 2022;308:122057. https://doi.org/10.1016/ Zielona Go
ra. Ocena sprawno
sci grupy stopni. Diagnostyka
j.fuel.2021.122057. Masz Sp z o.o w Gdan
sku; 2005.
[43] Kvamsdal HM, Jordal K, Bolland O. A quantitative [58] Flextek Ebsilon®Professional 15.00. Steag Energy Services
comparison of gas turbine cycles with CO2 capture. Energy GmbH; 2022. https://www.ebsilon.com/en/.
2007;32:10e24. https://doi.org/10.1016/j.energy.2006.02.006. [59] Zio
łkowski P. EcoPG e software for the analysis of Ecological
[44] Wu Y, Chen X, Ma J, Wu Y, Liu D, Mi J, et al. System Poly-Generation thermodynamic cycles cooperating with
integration for coal-fired power plant with post combustion renewable energy sources. ARGENTUM TRIGGERING
CO2 capture: comparative study for different solid dry RESEARCH GRANTS: Eco-Poly-Generation systems
sorbents. Fuel 2020;280. https://doi.org/10.1016/ improving the performance of fossil fuel power plants
j.fuel.2020.118561. cooperating with renewable energy source. Gdan
sk 2023.
 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0 39639

[60] Mostafavi E, Ashrafi O, Navarri P. Assessment of process [75] Marou sek J. Review: nanoparticles can change (bio)
modifications for amine-based post-combustion carbon hydrogen competitiveness. Fuel 2022;328:125318. https://
capture processes. Clean Eng Technol 2021;4:100249. doi.org/10.1016/j.fuel.2022.125318.
https://doi.org/10.1016/j.clet.2021.100249. [76] Marou sek J, Strunecký O, Barto
s V, Vochozka M. Revisiting
[61] Bartela Ł, Skorek-Osikowska A, Kotowicz J. competitiveness of hydrogen and algae biodiesel. Fuel
Thermodynamic, ecological and economic aspects of the 2022;328:125317. https://doi.org/10.1016/j.fuel.2022.125317.
use of the gas turbine for heat supply to the stripping [77] Shi Y, Du X, Yang L, Sun Y, Yang Y. Experiments on
process in a supercritical CHP plant integrated with a hydrogen production from methanol steam reforming in
carbon capture installation. Energy Convers Manag fluidized bed reactor. Int J Hydrogen Energy
2014;85:750e63. https://doi.org/10.1016/ 2013;38:13974e81. https://doi.org/10.1016/
j.enconman.2014.02.018. j.ijhydene.2013.08.073.
[62] Badur J, Stajnke M, Zio
łkowski P, Jo

z
wik P, Bojar Z, [78] Dincer I, AlZahrani AA. 4.25 electrolyzers. Compr. Energy
Zio
łkowski PJ. Mathematical modeling of hydrogen syst. Elsevier; 2018. p. 985e1025. https://doi.org/10.1016/
production performance in thermocatalytic reactor based B978-0-12-809597-3.00442-9.
on the intermetallic phase of Ni3Al. Arch Therm [79] Schnuelle C, Wassermann T, Fuhrlaender D, Zondervan E.
2019;40:3e26. https://doi.org/10.24425/ather.2019.129547. Dynamic hydrogen production from PV & wind direct
[63] Bakuru VR, Dmello ME, Kalidindi SB. Metal-organic electricity supply e modeling and techno-economic
frameworks for hydrogen energy applications: advances assessment. Int J Hydrogen Energy 2020;45:29938e52.
and challenges. ChemPhysChem 2019;20:1177e215. https:// https://doi.org/10.1016/j.ijhydene.2020.08.044.
doi.org/10.1002/cphc.201801147. [80] Fazli-Khalaf M, Naderi B, Mohammadi M, Pishvaee MS.
[64] Shiva Kumar S, Himabindu V. Hydrogen production by PEM Design of a sustainable and reliable hydrogen supply chain
water electrolysis e a review. Mater Sci Energy Technol network under mixed uncertainties: a case study. Int J
2019;2:442e54. https://doi.org/10.1016/j.mset.2019.03.002. Hydrogen Energy 2020;45:34503e31. https://doi.org/10.1016/
[65] Lane B, Reed J, Shaffer B, Samuelsen S. Forecasting j.ijhydene.2020.05.276.
renewable hydrogen production technology shares under [81] Kumar G, Shobana S, Nagarajan D, Lee DJ, Lee KS, Lin CY,
cost uncertainty. Int J Hydrogen Energy 2021;46:27293e306. et al. Biomass based hydrogen production by dark
https://doi.org/10.1016/j.ijhydene.2021.06.012. fermentation d recent trends and opportunities for greener
[66] Ueckerdt F, Bauer C, Dirnaichner A, Everall J, Sacchi R, processes. Curr Opin Biotechnol 2018;50:136e45. https://
Luderer G. Potential and risks of hydrogen-based e-fuels in doi.org/10.1016/j.copbio.2017.12.024.
climate change mitigation. Nat Clim Change [82] Sharma A, Arya SK, Lutzu GA, Ciurli A, Chiellini C, Di
2021;11:384e93. https://doi.org/10.1038/s41558-021-01032-7. Caprio F, et al. Hydrogen-rich syngas production via
[67] Lux B, Pfluger B. A supply curve of electricity-based integrated configuration of pyrolysis and air gasification
hydrogen in a decarbonized European energy system in processes of various algal biomass: process simulation and
2050. Appl Energy 2020;269:115011. https://doi.org/10.1016/ evaluation using Aspen Plus software. Int J Hydrogen Energy
j.apenergy.2020.115011. 2021;46:235e45. https://doi.org/10.1016/j.rser.2020.110041.
[68] Staffell I, Scamman D, Velazquez Abad A, Balcombe P, [83] Amulya K, Venkata Mohan S. Green hydrogen based
Dodds PE, Ekins P, et al. The role of hydrogen and fuel cells succinic acid and biopolymer production in a biorefinery:
in the global energy system. Energy Environ Sci adding value to CO2 from acidogenic fermentation. Chem
2019;12:463e91. https://doi.org/10.1039/c8ee01157e. Eng J 2022;429:132163. https://doi.org/10.1016/
[69] Riera JA, Lima RM, Knio OM. A review of hydrogen j.cej.2021.132163.
production and supply chain modeling and optimization. [84] Wilk M, Magdziarz A, Kalemba-Rec I, Szyman
ska-Chargot M.
Int J Hydrogen Energy 2023. https://doi.org/10.1016/ Upgrading of green waste into carbon-rich solid biofuel by
j.ijhydene.2022.12.242. hydrothermal carbonization: the effect of process
[70] Welder L, Stenzel P, Ebersbach N, Markewitz P, Robinius M, parameters on hydrochar derived from acacia. Energy
Emonts B, et al. Design and evaluation of hydrogen electricity 2020;202:117717. https://doi.org/10.1016/j.energy.2020.117717.
reconversion pathways in national energy systems using [85] Riaz S, Rhee KY, Park SJ. Polyhydroxyalkanoates (phas):
spatially and temporally resolved energy system biopolymers for biofuel and biorefineries. Polymers
optimization. Int J Hydrogen Energy 2019;44:9594e607. 2021;13:1e21. https://doi.org/10.3390/polym13020253.
https://doi.org/10.1016/j.ijhydene.2018.11.194. [86] Yin Y, Chen Y, Wang J. Co-fermentation of sewage sludge
[71] Huth M, Heilos A. Fuel flexibility in gas turbine systems: and algae and Fe2þ addition for enhancing hydrogen
impact on burner design and performance. Woodhead production. Int J Hydrogen Energy 2021;46:8950e60. https://
Publishing Limited; 2013. https://doi.org/10.1533/ doi.org/10.1016/j.ijhydene.2021.01.009.
9780857096067.3.635. [87] Raheem A, Ji G, Memon A, Sivasangar S, Wang W, Zhao M,
[72] Campbell A, Goldmeer J, Healy T, Washam R, Molie‘re M, et al. Catalytic gasification of algal biomass for hydrogen-
Citeno J. Heavy duty gas turbines fuel flexibility. Combust. rich gas production: parametric optimization via central
Fuels Emiss Parts A B 2008;3:1077e85. https://doi.org/ composite design. Energy Convers Manag 2018;158:235e45.
10.1115/GT2008-51368. ASMEDC. https://doi.org/10.1016/j.enconman.2017.12.041.
[73] Benaissa S, Adouane B, Ali SM, Rashwan SS, Aouachria Z. [88] Zabochnicka M, Krzywonos M, Romanowska-Duda Z,
Investigation on combustion characteristics and emissions Szufa S, Darkalt A, Mubashar M. Algal biomass utilization
of biogas/hydrogen blends in gas turbine combustors. toward circular economy. Life 2022;12:1e18. https://doi.org/
Therm Sci Eng Prog 2022;27:101178. https://doi.org/10.1016/ 10.3390/life12101480.
j.tsep.2021.101178. [89] Sarwer A, Hamed SM, Osman AI, Jamil F, Al-Muhtaseb AH,
[74] Moliere M, Vierling M, Aboujaib M, Patil P, Eranki A, Alhajeri NS, et al. Algal biomass valorization for biofuel
Campbell A, et al. Gas turbines in alternative fuel production and carbon sequestration: a review, vol. 20.
applications: bio-ethanol field test. Vol. 1 aircr. Engine; Springer International Publishing; 2022. https://doi.org/
ceram. Coal, biomass altern.Fuels; control. Diagnostics 10.1007/s10311-022-01458-1.
instrumentation; educ. Electr. Power. Award. Honor.; 2009. [90] Pagliano G, Ventorino V, Panico A, Pepe O. Integrated
p. 341e8. https://doi.org/10.1115/GT2009-59047. ASMEDC. systems for biopolymers and bioenergy production from
39640 i n t e r n a t i o n a l j o u r n a l o f h y d r o g e n e n e r g y 4 8 ( 2 0 2 3 ) 3 9 6 2 5 e3 9 6 4 0

organic waste and by-products: a review of microbial [98] Zio
łkowski P, Stasiak K, Amiri M, Mikielewicz D. Negative
processes. Biotechnol Biofuels 2017;10:1e24. https://doi.org/ carbon dioxide gas power plant integrated with gasification
10.1186/s13068-017-0802-4. of sewage sludge. Energy 2023;262. https://doi.org/10.1016/
[91] Lage S, Gojkovic Z, Funk C, Gentili FG. Algal biomass from j.energy.2022.125496.
wastewater and flue gases as a source of bioenergy. [99] Zio
łkowski P, Badur J, Pawlak- Kruczek H, Stasiak K,
Energies 2018;11:1e30. https://doi.org/10.3390/en11030664. Amiri M, Niedzwiecki L, et al. Mathematical modelling of
[92] Arun S, Sinharoy A, Pakshirajan K, Lens PNL. Algae based gasification process of sewage sludge in reactor of negative
microbial fuel cells for wastewater treatment and CO2 emission power plant. Energy 2022;244. https://doi.org/
recovery of value-added products. Renew Sustain Energy 10.1016/j.energy.2021.122601.
Rev 2020;132:110041. https://doi.org/10.1016/ [100] Campanari S, Chiesa P, Manzolini G. CO2 capture from
j.rser.2020.110041. combined cycles integrated with Molten Carbonate Fuel
[93] Aswathi Mohan A, Robert Antony A, Greeshma K, Yun JH, Cells. Int J Greenh Gas Control 2010;4:441e51. https://
Ramanan R, Kim HS. Algal biopolymers as sustainable doi.org/10.1016/j.ijggc.2009.11.007.
resources for a net-zero carbon bioeconomy. Bioresour [101] Bonalumi D, Valenti G, Lillia S, Fosbøl PL, Thomsen K. A
Technol 2022;344:126397. https://doi.org/10.1016/ layout for the carbon capture with aqueous ammonia
j.biortech.2021.126397. without salt precipitation. Energy Proc 2016;86:134e43.
[94] Ayala-Parra P, Liu Y, Field JA, Sierra-Alvarez R. Nutrient https://doi.org/10.1016/j.egypro.2016.01.014.
recovery and biogas generation from the anaerobic [102] Vishwajeet, Pawlak-Kruczek H, Baranowski M, Czerep M,
digestion of waste biomass from algal biofuel production. _
Chora˛zyczewski A, Krochmalny K, et al. Entrained flow
Renew Energy 2017;108:410e6. https://doi.org/10.1016/ plasma gasification of sewage sludgee proof-of-concept
j.renene.2017.02.085. and fate of inorganics. Energies 2022;15. https://doi.org/
[95] Lutzu GA, Ciurli A, Chiellini C, Di Caprio F, Concas A, 10.3390/en15051948.
Dunford NT. Latest developments in wastewater treatment [103] Wilk M, Magdziarz A, Gajek M, Zajemska M, Jayaraman K,
and biopolymer production by microalgae. J Environ Chem Gokalp I. Combustion and kinetic parameters estimation of
Eng 2021;9:104926. https://doi.org/10.1016/ torrefied pine, acacia and Miscanthus giganteus using
j.jece.2020.104926. experimental and modelling techniques. Bioresour Technol
[96] Karan H, Funk C, Grabert M, Oey M, Hankamer B. Green 2017;243:304e14. https://doi.org/10.1016/
bioplastics as part of a circular bioeconomy. Trends Plant j.biortech.2017.06.116.
Sci 2019;24:237e49. https://doi.org/10.1016/ [104] Sławin
ski D, Zio

łkowski P, Badur J. Thermal failure of a
j.tplants.2018.11.010. second rotor stage in heavy duty gas turbine. Eng Fail Anal
[97] Kartik A, Akhil D, Lakshmi D, Panchamoorthy Gopinath K, 2020;115. https://doi.org/10.1016/j.engfailanal.2020.104672.
Arun J, Sivaramakrishnan R, et al. A critical review on [105] Badur J, Zio
łkowski P, Sławin
ski D, Kornet S. An approach
production of biopolymers from algae biomass and their for estimation of water wall degradation within pulverized-
applications. Bioresour Technol 2021;329:124868. https:// coal boilers. Energy 2015;92:142e52. https://doi.org/10.1016/
doi.org/10.1016/j.biortech.2021.124868. j.energy.2015.04.061.