Energy and Exergy Assessment of a 250 MW Steam Boiler Under Partial Load Conditions: Comparative Analysis of Fuel Oil and Enhanced Crude Oil

Abstract

This study presents a comprehensive thermo-energetic and exergetic assessment of a 250 MW steam boiler in a Cuban thermal power plant, operating under partial load conditions (plant: 62–66%; boiler: 58–61%). An integrated diagnostic methodology was developed and implemented in Mathcad 15 to evaluate key performance indicators, including thermal efficiency (η_tGV); exergetic efficiency (η_ExGV); exergy destruction ratio (γ_ExGV); steam generation index (IG_v); and specific fuel consumption (B_Esp). The methodology was applied to two fuels with contrasting thermophysical and chemical properties: fuel oil and Enhanced Crude Oil 650. The results indicate superior performance with fuel oil due to its higher heating value; however, efficiency losses were mainly attributed to operational factors such as excessive air supply (22.7–26.4%), heat transfer surface fouling, and inadequate maintenance. The analysis revealed significant deviations from design values—thermal efficiency (90.27–90.59%) and exergetic efficiency (<60%)—highlighting an untapped potential for energy savings. Quantitative estimates indicate potential annual fuel cost savings of approximately 1.2 million USD through optimized combustion and maintenance practices. The proposed framework enables accurate diagnostics of complex boiler systems and provides actionable indicators to support combustion optimization and energy efficiency strategies in conventional thermal power plants.

1. Introduction

Fuel is a critical component in the operation of steam boilers, particularly in terms of their economic performance, with approximately 80% of operating costs attributed to fuel consumption [1]. This characteristic underscores the need for efficient boiler operation to reduce fuel expenditure and production costs [2,3,4]. To achieve this, comprehensive diagnostics of steam generators are essential to determine key energy performance parameters and implement measures to enhance thermo-exergetic efficiency [5,6,7].

Steam boilers in Cuban thermoelectric power plants (TPPs), due to their socio-economic and environmental impacts, are subject to systematic study. Retirado-Mediaceja et al. [1] conducted an energy balance of a 49 MW steam generation system, identifying performance parameters and proposing an algorithm that integrated established computational methods [8,9]; however, their scope was limited to thermal and exergetic balances. Other studies on boilers in TPPs across various countries have analyzed operations under non-nominal and non-design load conditions [10,11,12,13], applying computational fluid dynamics (CFD) for combustion modeling [14].

Camaraza-Medina et al. [15] evaluated energy efficiency indicators for the boiler investigated in this study during a test under four load conditions: 150 MW (60%); 180 MW (72%); 220 MW (88%); and 250 MW (100%). Their work serves as a key reference though it was limited to Cuban crude with 7.17% sulfur content (crude 2). Currently, the steam generator operates using two fuels—fuel oil and Enhanced Crude 650 (henceforth fuel and crude)—with distinct chemical compositions and thermophysical properties, necessitating an updated evaluation of energy performance.

During the past 5 years (2021–2025), international research has addressed various aspects of boiler energy performance. Babatunde et al. [16] simulated a large-scale boiler, determining energy indicators for natural gas and low-viscosity fuel oil, and provided recommendations for optimal air–fuel ratios based on the thermodynamic performance and exergetic cost. Tic and Guziałowska-Tic [17] analyzed the energy and ecological efficiency of fuel oil combustion using a Fe/Mg/Ce modifier, achieving fuel savings and reduced greenhouse gas emissions in plants up to 5 MW. In addition, studies have explored artificial intelligence (AI) for boiler control and optimization, including neural networks and genetic algorithms [18]; onboard carbon capture systems [19]; electronic combustion control through regulated residual sub-combustion [20]; and fuel cell integration downstream of power plants [21]. These technologies aim to improve efficient and clean energy production [22,23,24,25,26].

Varganova et al. [27] developed a computational system for automated analysis of feasible boiler unit loads, achieving a 1.4% reduction in energy costs through rational fuel redistribution. Abuelnuor et al. [28] evaluated energy and exergetic parameters of a Sudanese TPP boiler, identifying significant heat losses (stack, 18%) and exergy losses (combustion chamber, 39.8%), and proposed efficiency improvements [29]. These studies highlight advances in combustion efficiency, irreversibility reduction, dynamic modeling at partial loads, and utilization of waste heat, as well as a novel trigeneration process [30,31,32,33,34].

The influence of the fuel type on thermal and exergetic performance under varying load conditions in conventional TPPs is a critical research focus due to its socio-economic and environmental implications [1]. This study evaluates the energy and exergetic performance of a 250 MW TPP steam boiler operating with fuel oil and Enhanced Crude Oil 650 under partial load conditions (plant: 62–66%; boiler: 58–61%), highlighting the impact of fuel properties, such as the sulfur content, on stack gas temperature and efficiency. A novel aspect of this work lies in the development of a structured diagnostic procedure that combines direct and indirect methods with a coherence verification loop, implemented in a computational environment tailored to the specific boiler and fuel types. This procedure assesses key performance indicators, including thermal efficiency (η_tGV); exergetic efficiency (η_ExGV); exergy loss (γ_ExGV); steam production index (IG_v); and specific fuel consumption (B_Esp), addressing operational challenges such as suboptimal combustion and inadequate maintenance. Section 2 details the calculation procedure and measurement methods, Section 3 discusses the findings, and Section 4 summarizes the conclusions and future research directions.

2. Materials and Methods

In steam boilers, thermal and exergetic efficiencies are commonly used as energy performance indicators [35]. However, given that the installation under study operates within a TPP, additional indicators are incorporated for a comprehensive analysis: fuel consumption, steam production index, specific fuel consumption relative to total electricity production, and exergy loss. The methodology for energy evaluation, tailored to the investigated boiler, is detailed in the following subsections (Section 2.1, Section 2.2 and Section 2.3), based on a general framework of thermo-exergetic analysis [13] and adapted to the technological characteristics of the studied installation (Figure 1), while branch thickness is uniform and is used only to illustrate the qualitative relationships among the main input, output, and loss streams. A detailed representation of exergy flows considered in the balance is shown in Section 3.3, which provides a Sankey diagram of the input, destroyed, and lost exergies for the two fuels under study.

2.1. Gross Thermal Efficiency and Heat Losses

The thermal efficiency can be calculated using the direct method (DM, Equation (1)) or the indirect method (IM). The direct method requires measurements of superheated and reheated steam, fuel, air, and atomizing steam parameters [9].

$${\eta }_{tG{V}_{DM}}=\left[{\displaystyle \frac{D_{vSC}\cdot \left(I_{vSC}-I_{aa}\right)+D_{vRC}\cdot \left(I_{vSRC\left(2\right)}-I_{vERC\left(1\right)}\right)}{(Q_b+Q_{fc}+Q_{fa}+Q_{atm})\cdot B_M}}\right]\cdot 100$$

(1)

where η_tGVDM represents the gross thermal efficiency of the boiler (%); D_vSC is the mass flow rate of superheated steam (kg/s); I_vSC and I_aa denote the specific enthalpy of superheated steam and feedwater (kJ/kg), respectively; D_vRC refers to the mass flow rate of reheated steam (kg/s); I_vSRC(2) and I_vERC(1) correspond to the specific enthalpies of the reheated steam at the outlet of reheater 2 and the inlet of reheater 1, respectively, also expressed in kJ/kg; and B_M is the fuel consumption measured at the steam generator (kg/s) [36].

The boiler produces superheated steam and reheats steam in two stages. The physical heat of the air (Q_fa ≈ 0) is neglected, as it is not preheated by external sources [37]. The heat input is calculated as:

$$Q_b=339.2\cdot C^t+1030.4\cdot H^t-108.9\cdot \left(O^t-S^t\right)-25.14\cdot W^t$$

(2)

$$Q_{fc}=t_c\cdot \left(1.737+0.0025\cdot t_c\right)$$

(3)

$$Q_{atm}=D{v}_{atm}\cdot \left(I{v}_{atm}-I{v}_{sgv}\right)$$

(4)

where Q_b is the combustion heat (kJ/kg); Q_fc is the heat supplied by the preheated fuel (kJ/kg); Q_atm is the heat contributed by the atomized steam (kJ/kg); C^t, H^t, O^t, S^t, and W^t are carbon, hydrogen, oxygen, sulfur, and moisture content in the fuel, respectively (all expressed as main mass fractions (%); T_c is the fuel temperature (°C); Dv_atm is the mass flow rate of atomized steam (kg_steam/kg_Fuel) (typically Dv_atm = 0.02–0.1 kg_steam/kg_Fuel for TPP boilers); and I_vatm and I_vsgv are the specific enthalpies of the steam used for atomization and the steam at the boiler outlet (kJ/kg), respectively.

The indirect method (Equation (5)) requires measurements of gas temperature, chemical composition, superheated steam flow, and extractions, followed by the heat loss calculations [38].

$${\eta }_{tG{V}_{IM}}=100-\left[q_2+q_3+q_4+q_5+q_6+q_7\right]$$

(5)

where η_tGVIM is the gross thermal efficiency of the steam generator (calculated by IM), expressed in (%), while q₂, q₃, q₄, q₅, q₆, and q₇ represent the heat losses associated with combustion gases, the incomplete chemical and mechanical combustion, the heat transfer to the surroundings, the unburned residues extracted from the furnace, and the extractions carried out in the dome, respectively, all expressed as percentages [39].

$$q_2={\displaystyle \frac{\left(I_{sgv}-\alpha \cdot I_{af}^o\right)\cdot \left(100-q_4\right)}{Q_d}}$$

(6)

where

$$I_{sgv}=I_g^o+\left(\alpha -1\right)\cdot I_{aire}^o+I_c$$

(7)

$$\alpha ={\displaystyle \frac{N_2}{N_2-3.76\cdot (O_2-0.5\cdot CO-0.5\cdot H_2-2\cdot C{H}_4)}}$$

(8)

$$N_2=100-\left(CO+R{O}_2+O_2+H_2+C{H}_4\right)$$

(9)

where $I_{sgv}$is the enthalpy of the flue gases (kJ/kg); α is the excess air coefficient (dimensionless); $I_{af}^o$and $I_g^o$ are the theoretical enthalpy of cold air and flue gases (kJ/kg), respectively; $I_{aire}^o$ is the enthalpy of the theoretical air quantity, in kJ/kg; I_c is the enthalpy of volatile ash in the gases (kJ/kg); and N₂, O₂, CO, H₂, CH₄, and RO₂ are the concentrations of nitrogen, oxygen, carbon monoxide, hydrogen, methane, and triatomic gases in the dry flue gases, all expressed as volume percentages.

Losses q₃ and q₄ are determined as [35]:

$$q_3={\displaystyle \frac{126.4\cdot CO+108\cdot H_2+358.1\cdot C{H}_4}{Q_d}}\cdot \left[{\displaystyle \frac{1.86\cdot \left(C^t+0.375\cdot S^t\right)}{R{O}_2+CO+C{H}_4}}\right]\cdot \left(100-q_4\right)$$

(10)

$$q_4=q_{4p}+q_{4v}$$

(11)

where q_4p and q_4v represent the heat losses due to mechanical unburned residues on the grate and volatile matter, respectively, expressed as percentages.

For liquid fuels, q_4p = 0 because they do not produce unburned residues on the grate. Consequently, the Bacharach Index (BI) is used to estimate the magnitude of the total loss (q₄ = q_4v). The recommended values are provided in

Table 1. Loss due to volatile incomplete combustion (q_4v) according to Bacharach Index.

BI Range	1–2	3–4	5–7	8–10
q4v (%)	0.2	0.4	0.8	0.9

[1].

Heat loss q₅ accounts for radiation, conduction, and convection losses through open registers, walls, the floor, and the ceiling [39]:

$$q_5=q_{5_{DN}}\cdot {\displaystyle \frac{D_{Nvsc}}{D_{Rvsc}}}$$

(12)

where q_5DN is the heat loss at nominal steam production (%), while D_Nvsc and D_Rvsc are the nominal and actual superheated steam mass flow rates (kg/s). Dome extraction heat loss is calculated as follows [1]:

$$q_7={\displaystyle \frac{G_e\cdot I_e}{Q_d\cdot B_M}}\cdot 100$$

(13)

where G_e is the extraction steam flow rate—G_e = (0.003–0.03) · D_vSC for TPP boilers—(kg/s) and I_e is the specific enthalpy of the extracted steam (kJ/kg).

Fuel consumption (B_C) is verified using η_b by integrating Equations (1) and (5):

$$B_C={\displaystyle \frac{D_{vSC}\cdot \left(I_{vSC}-I_{aa}\right)+D_{vRC}\cdot \left(I_{vSRC\left(2\right)}-I_{vERC\left(1\right)}\right)}{\left(Q_b+Q_{fc}+Q_{atm}\right)\cdot \left[100-\left(q_2+q_3+q_4+q_5+q_6+q_7\right)\right]}}\cdot 100\approx B_M$$

(14)

2.2. Steam Generation Index and Specific Fuel Consumption

In addition to fuel consumption (B_M) and thermal efficiency (η_b), other efficiency indicators relevant for TPP boilers include the steam generation index (IG_v); specific fuel consumption (B_Esp); exergetic efficiency (η_ex); and exergy loss (Ex_p). The steam generation index is defined as [40]:

$$I{G}_v={\displaystyle \frac{D_{vSC}}{B_M}}\approx {\displaystyle \frac{D_{vSC}}{B_C}}$$

(15)

The total fuel supply, whether measured (B_M) or calculated (B_C), corresponds to all the fuel delivered to the boiler burners. However, this value does not represent the actual burned fuel, as a small portion remains unburned due to mechanical losses. The effective burned fuel flow (B_Q) is determined using Equation (16), as proposed by Cabello [41]:

$$B_Q=B_M\cdot \left(1-{\displaystyle \frac{q_4}{100}}\right)\approx B_C\cdot \left(1-{\displaystyle \frac{q_4}{100}}\right)$$

(16)

Equivalent fuel consumption considers the correction factor (F) for different fuels [42]:

$$B_E=B_M\cdot F\approx B_C\cdot F$$

(17)

$$F={\displaystyle \frac{GE\cdot Q_{S\left(M\right)}}{{Q_S}_{\left(ref\right)}}}\approx {\displaystyle \frac{GE\cdot Q_{S\left(C\right)}}{{Q_S}_{\left(ref\right)}}}$$

(18)

$$Q_{S\left(C\right)}=339.2\cdot C^t+1257\cdot H^t-108.9\cdot \left(O^t-S^t\right)$$

(19)

where Q_S(ref) = 43,160.00 kJ/kg; B_C, B_Q, and B_E represent the calculated, burned, and equivalent fuel consumption (kg/s); F is the correction factor for the analyzed fuel (dimensionless); GE is the specific gravity of the fuel at 15.5 °C (GE = 0.95–1.05, for heavy fuels), dimensionless; Q_S(M) and Q_S(C) are the higher heating values (measured and calculated, respectively) of the analyzed fuel; and Q_S(ref) is the reference higher heating value (kJ/kg).

Specific fuel consumption is calculated as:

$$B_{Esp}=B_M\cdot {\displaystyle \frac{GE\cdot Q_{S\left(M\right)}}{Q_{S\left(ref\right)}\cdot P_{E\left(TPP\right)}}}\approx B_C\cdot {\displaystyle \frac{GE\cdot Q_{S\left(C\right)}}{Q_{S\left(ref\right)}\cdot P_{E\left(TPP\right)}}}$$

(20)

where B_Esp is the specific fuel consumption (g/kW·h) and P_E (TPP) is the rated power output of the TPP (MW).

2.3. Exergetic Efficiency and Exergy Loss

Exergetic efficiency is calculated as [43,44]:

$${\eta }_{Ex\left(GV\right)}={\displaystyle \frac{E{x}_R}{E{x}_E}}\cdot 100$$

(21)

where η_Ex is the exergetic efficiency (%), while Ex_R and Ex_E are the recovered and employed exergies (J/s).

All exergy calculations were performed using a reference (dead) state of T₀ = T_ma = 305.15 K (32 °C) and P₀ = P_ma = 101.325 kPa (1 atm), corresponding to the average ambient conditions during the measurement campaign (

Table 2. Operating parameters measured in the steam boiler.

No.	Parameter	Unit	Fuel Oil (St = 2.18%)	Crude Oil (St = 4.86%)
	Steam subsystem
1	Superheated steam flow rate, (DvSC)	t/h	521.2	494.0
2	Superheated steam temperature, (TvSC)	°C	526.55	525.87
3	Superheated steam pressure, (PvSC)	MPa	13.22	13.41
4	Reheated steam flow rate, (DvRC)	t/h	472.02	444.97
5	Reheater inlet temperature, (TvRC,in)	°C	336.49	331.43
6	Reheater inlet pressure, (PvRC,in)	MPa	2.53	2.17
7	Reheater outlet temperature, (TvRC,out)	°C	520.71	524.61
8	Reheater outlet pressure, (PvRC,out)	MPa	2.38	2.15
9	Atomizing steam flow rate, (Datm)	t/h	2.88	2.61
10	Atomizing steam pressure, (Patm)	MPa	1.50	1.50
11	Atomizing steam temperature, (Tatm)	°C	236.51	229.00
12	Extraction steam flow rate, (Dext)	t/h	14.14	14.02
13	Saturated liquid temp. in dome, (Tsat,dome)	°C	339.75	342.40
14	Dome pressure, (Pdome)	MPa	13.87	13.99
	Feedwater subsystem
15	Feedwater temperature, (Taa)	°C	182.01	204.53
16	Feedwater pressure, (Paa)	MPa	15.20	15.20
	Combustion and air subsystem
17	Air temperature after CAR (Tair,CAR)	°C	249.14	238.44
18	Fuel flow rate, (BQ)	t/h	42.79	42.39
19	Fuel temperature, (Tc)	°C	126.58	128.91
20	Flue gas outlet temperature, (Tsgv)	°C	155.84	148.38
	Global
21	Power plant load, (λT PP)	MW	165.00	155.26
	Dead-state conditions used for all exergy calculations (average ambient conditions)
22	Reference temperature (T0)	°C	32	32
23	Reference pressure (P0)	kPa	101.325	101.325

).

The exergies of superheated steam (Ex_vsc); reheated steam (Ex_vrec); feedwater (Ex_aa); and extractions (Ex_ext) are:

$$E{x}_{vsc}=m_{vsc}\cdot \left[\left(h_{s\left(vsc\right)}-h_{ma\left(vsc\right)}\right)-T_{ma}\cdot \left(S_{s\left(vsc\right)}-S_{ma\left(vsc\right)}\right)\right]$$

(22)

$$E{x}_{vrec}=m_{vrec}\cdot \left[\left(h_{s\left(vrec\right)}-h_{ma\left(vrec\right)}\right)-T_{ma}\cdot \left(S_{s\left(vrec\right)}-S_{ma\left(vsc\right)}\right)\right]$$

(23)

$$E{x}_{aa}=m_{aa}\cdot \left[\left(h_{s\left(aa\right)}-h_{ma\left(aa\right)}\right)-T_{ma}\cdot \left(S_{s\left(aa\right)}-S_{ma\left(aa\right)}\right)\right]$$

(24)

$$E{x}_{ext}=m_{ext}\cdot \left[\left(h_{s\left(ext\right)}-h_{ma\left(ext\right)}\right)-T_{ma}\cdot \left(S_{s\left(ext\right)}-S_{ma\left(ext\right)}\right)\right]$$

(25)

where Ex is the exergy of the corresponding flow (J/s); m is the mass flow rate (kg/s); h is the specific enthalpy (J/kg); S is the specific entropy (J/kg·K); and T_ma is the ambient temperature (K).

The exergies of fuel (Ex_c); combustion heat (Ex_qc); cold air (Ex_af); and flue gases (Ex_g) are:

$$E{x}_c=B_M\cdot \left[t_c\cdot \left(1.737+0.0025\cdot t_c\right)\right]$$

(26)

$$E{x}_{qc}=B_M\cdot \left(1-{\displaystyle \frac{q_4}{100}}\right)\cdot Q_b\cdot \left(1-{\displaystyle \frac{T_{ma}}{T_{Comb}}}\right)$$

(27)

$$E{x}_{af}=I_{af}\cdot Q_a$$

(28)

$$E{x}_g=I_{sgv}\cdot {\displaystyle \frac{Q_g}{V_g}}$$

(29)

As stated in Cabello [41]:

$$Q_a={\beta }_1\cdot B_M\cdot \left(1-{\displaystyle \frac{q_4}{100}}\right)\cdot V_a^o\cdot {\alpha }_h\cdot \left({\displaystyle \frac{T_{af}+273.15}{273.15}}\right)\cdot {\displaystyle \frac{1.01\cdot 10^5}{h_b}}$$

(30)

$$Q_g={\beta }_1\cdot B_M\cdot \left(1-{\displaystyle \frac{q_4}{100}}\right)\cdot \left[V_g^o+\left({\alpha }_{av}-1\right)\cdot V_a^o\right]\cdot \left({\displaystyle \frac{T_g+273.15}{273.15}}\right)\cdot {\displaystyle \frac{1.01\cdot 10^5}{h_b}}$$

(31)

where T_comb is the maximum combustion temperature (K); I_af is the actual enthalpy of the cold air (kJ/m³); Q_a and Q_g are the airflow and flue gas flow rates from the forced and induced draft fans (FDFs and IDFs) (m³/s); V_g is the actual gas volume (m³N/kg); β₁ is the fuel feed reserve coefficient (β₁ = 1.05 for D_vsc > 5.6 kg/s), dimensionless; V⁰ is the theoretical dry-air volume (m³N/kg); α_h and α_av are the excess air coefficients at the furnace and the FDF inlet—from Equation (8)—(dimensionless); T_af is the temperature of the air entering the FDFs (°C); h_b is the barometric pressure (Pa); T_g is the temperature of the flue gases at the IDF inlet (°C); and V⁰ is the theoretical gas volume (m³N/kg).

Parameters V_g, V^o, and V^o are determined using Equations (32)–(34). To compute them, it is necessary to know the chemical composition of the fuel, the air humidity, and the other previously defined parameters.

$$V_g=V_g^o+\left(\alpha -1\right)\cdot V_a^o+0.00161\cdot d\cdot \left(\alpha -1\right)\cdot V_a^o$$

(32)

$$V_a^o=0.0889\cdot \left(C^t+0.375\cdot S^t\right)+0.265\cdot H^t-0.0333\cdot O^t$$

(33)

$$V_g^o=\left[1.866\cdot \left({\displaystyle \frac{C^t+0.375\cdot S^t}{100}}\right)\right]+\left[0.79\cdot V_a^o+0.8{\displaystyle \frac{N^t}{100}}\right]+\left[0.111\cdot H^t+0.0124\cdot W^t+0.00161\cdot d\cdot V_a^o+1.24\cdot {\displaystyle \frac{D{v}_{atm}}{B_M}}\right]$$

(34)

where d—air humidity, in g_water/kg_{dry air} (for Cuba, d = 13–23 g_water/kg_{dry air}).

Then, the exergetic efficiency η_EX(GV) and the exergy destruction ratio γ_EX(GV) are calculated as:

$${\eta }_{E{x}_{\left(GV\right)}}={\displaystyle \frac{E{x_R}_{\left(GV\right)}}{E{x_E}_{\left(GV\right)}}}\cdot 100={\displaystyle \frac{E{x}_{vsc}+E{x}_{vrec}}{E{x}_{aa}+E{x}_c+E{x}_{qc}+E{x}_{af}}}\cdot 100$$

(35)

$${\gamma }_{E{x}_{GV}}=100-{\eta }_{E{x}_{\left(GV\right)}}={\displaystyle \frac{E{x_P}_{\left(GV\right)}}{E{x_E}_{\left(GV\right)}}}\cdot 100={\displaystyle \frac{E{x_E}_{\left(GV\right)}-E{x_R}_{\left(GV\right)}}{E{x_E}_{\left(GV\right)}}}\cdot 100$$

(36)

where η_EX(GV) is the exergy efficiency of the steam generator (GV), %; γ_EX(GV) is the exergy destruction ratio of the GV (%); and Ex_P(GV) and Ex_E(GV) are the lost and supplied exergies (J/s), respectively.

The energy balance procedure is systematized in Figure 2, which constitutes the primary contribution of this work. Implemented in Mathcad 15, the integrated diagnostic methodology is practical for the thermo-exergetic analysis of complex boilers in conventional thermal plants, enabling performance evaluation under different fuels and load conditions. Partial implementation yielded satisfactory results in small TPPs of the Cuban nickel industry [1,13]. Legend: FEEa-v (expenditures and thermodynamic properties of feedwater, superheated steam, reheated steam, and atomization steam); FPc (fuel expenditure and properties); FPg-a (flue gas and air expenditures and properties); FPe (extraction flowrate, enthalpy, and entropy); and ER (relative error).

2.4. Boiler Measurements

Measurements were carried out during operation with two fuels (fuel and crude) of different characteristics [45,46]. The mean values of 30 determinations of operating parameters were calculated (Table 2), followed by the energy evaluation. A passive experiment was conducted due to the continuous operation of the boiler [47].

Measurements were performed using calibrated instruments certified by the TPP Instrumentation and Control Department and used by operators, administrative staff, and researchers. The chemical composition of the fuel and the lower heating values were determined in specialized laboratories using standardized ASTM methods (

Table 3. Measurements that were performed on fuels and flue gases.

	Fuel Chemical Composition (%)							Flue Gas Composition (%)
	Ct	Ht	St	Ot	Wt	Nt	At	O2	CO2	CO	H2	CH4
Fuel Oil	85.20	10.95	2.18	0.10	0.66	0.50	0.41	4.16	12.74	0.15	0.00	0.00
Crude Oil	83.02	10.20	4.86	0.30	0.54	0.60	0.48	4.68	12.28	0.15	0.00	0.00

Note: C^t = carbon; H^t = hydrogen; S^t = sulfur; O^t = oxygen; W^t = moisture; N^t = nitrogen; A^t = ash. Lower heating value (Q_b = Q_LHV): fuel oil = 9490.28 kcal/kg; crude oil = 9150.00 kcal/kg.

).

The following methods were applied: D-4698 (Higher Heating Value); D-1298 (Density and Gravity at 15 °C); D-1548 (Asphaltenes); D-473 (Mechanical Impurities); D-445 (Viscosity at 50 °C); D-382 (Ash); D-189 (Conradson Carbon Residue); D-129 (Sulfur); D-95 (Water); and D-93 (Flash Point); All measured parameters complied with the minimum and maximum thresholds reported in the scientific literature [1]. Performance indicators were calculated using Mathcad 15. Thermodynamic properties were determined using tables [41], online applications, and interpolation methods. The gas composition was measured using ULTRAMAT 23 analyzers powered by 230 V AC, with a 4–20 mA output signal. The equipment used corresponds to model 7MB2335-2CP10-3AA1-Z-A31, with the following measurement ranges: O₂ (0–25%); CO₂ (0–50%); CO (0–250 mg/m³); SO₂ (0–400 mg/m³); and NO (0–250 mg/m³).

3. Results and Discussions

This section analyzes the main findings of the boiler energy evaluation. Preliminary observations indicate that the operating parameters varied when using crude compared to fuel, the latter being the design fuel. The values of the specific parameters are derived from Table 2 and are illustrated in Figure 3.

Generally, the parameter deviations were small (±10%), except for reheater inlet pressure and feedwater temperature (parameters 6 and 15, Table 2). The former resulted from increased expansion work in the high-pressure turbine stage, while the latter resulted from enhanced heat transfer in low-temperature zones (economizers). Both turbine work and feedwater heating were higher with crude, aimed at maximizing its lower energy content compared to fuel. However, this operation increases corrosion risks in the gas evacuation system (ducts, induced draft fans, chimney) due to sulfuric acid (H₂SO₄) formation, raising maintenance and equipment costs. Evidence of excessive gas cooling is reflected in the chimney outlet temperature, which was 148.38 °C for crude, 7.46 °C lower than for fuel.

3.1. Specific Fuel Consumption

Steam flow rate, the primary energy transport medium for TPP power production, yielded steam-to-power ratios of 3.158 and 3.181 for fuel and crude, respectively. This indicates an additional 23 kg/h of steam per MW with crude, increasing production costs and environmental impact by 3.71 kg of fuel per ton of steam (

Table 4. Specific fuel consumption of the boiler under different operating and maintenance conditions.

		Present Study		Camaraza-Medina et al. [15]
Parameter	Unit	Fuel (LSG = 61%)	Crude (LSG = 58%)	Crude 2 (LSG = 61%)
Maintenance status, (tm)	year	1 (post-overhaul)	1 (post-overhaul)	0 (immediate)
Specific fuel consumption, (BEsp)	kg/t	82.10	85.81	73.42

L_SG represents the steam generator load, relative to nominal.

). This is attributed to the 1424.5 kJ/kg lower heating value difference between the fuels (Table 3).

Steam quality (pressure and temperature) showed minor variations (0.19 MPa, 0.68 °C) between the fuels within nominal ranges (13.9 MPa, 525 ± 8 °C). Compared to the 220 MW TPP boiler studied by Babatunde et al. [16], the steam-to-power ratio in the present study was less efficient (3.158–3.181 vs. 2.972 t/h per MW). This difference is mainly attributed to the higher sulfur content of the fuels used here (2.18% and 4.86%) compared to the reference fuel (0.3% sulfur), which affects flue gas properties and heat recovery (

Table 5. Impact of fuel quality on selected parameters of the steam generator.

		Babatunde et al. [16]	Present Study		Camaraza-Medina et al. [15]
Parameter	Unit	Fuel 2 (LSG = 100%)	Fuel (LSG = 61%)	Crude (LSG = 58%)	Crude 2 (LSG = 61%)
Steam flow rate/power ratio, (RvP)	(t/h)/MW	2.972	3.158	3.181	3.456
Steam quality, (TvSC—PvSC)	°C—MPa	541—12.92	526.55—13.22	525.87—13.41	524.9—13.52
Steam enthalpy, (IvSC)	kJ/kg	3448.544	3406.748	3402.730	3398.834

). The exergy destruction values obtained (≈41%) are in line with those reported by Abuelnuor et al. [27] for a Sudanese power plant boiler, where the combustion chamber was identified as the main source of irreversibilities (39.8% of input exergy).

3.2. Excess Air and Air/Gas Flows

The fuel type influences excess air and gas volumes, affecting chimney design, fan selection, and boiler efficiency [13]. The excess air was 22.7% and 26.4% for fuel and crude, respectively (

Table 6. Air excess coefficient under different operating conditions.

		Present Study		Camaraza-Medina et al. [15]
Parameter	Unit	Fuel	Crude	Crude 2
Steam generator load, (LSG)	%	61	58	61	70	84	101
TPP load relative to nominal, (λT PP)	%	66	62	60	72	88	100
Air excess coefficient, (α)	-	1.227	1.264	1.117	1.111	1.096	1.067

), exceeding the recommended 10–15% for steam atomized fuel combustion [48]. Crude’s high sulfur content (4.86%) necessitated additional air, requiring solvents, dispersants, and optimized combustion strategies [20,33]. These were partially implemented.

For TPP heavy fuel oil boilers, the furnace excess air coefficient should be 1.03–1.15 for loads of 50–100% nominal [1]. Non-compliance in the studied boiler resulted from inadequate maintenance and fuel properties. Previous studies [15] showed that at 150–180 MW loads, excess air could be reduced to 11.1–11.7% with crude 2 (7.17% sulfur) through proper maintenance and operational practices [13]. The increases in load from 58 to 61% reduced the excess air by 3.7% (fuel vs. crude) and 5% (crude 2, 61–101% load). Maintenance deficiencies increased excess air by 11 at 61% load, despite fuel’s lower sulfur content.

Air and gas flows (Q_a, Q_g) increased with TPP load from 155.26 MW (crude) to 165.00 MW (fuel) (

Table 7. Air and gas flow rates under comparable load conditions.

		Present Study		Camaraza-Medina et al. [15]
Parameter	Unit	Fuel (LSG = 61%)	Crude (LSG = 58%)	Crude 2 (LSG = 61%)
Air flow to be driven through the FDFs, (Qa)	m3/s	178.24	176.53	136.68
Gas flow to be evacuated through the IDFs, (Qg)	m3/s	270.73	262.39	206.11

), as expected, due to higher steam and fuel demands [49]. These flows impact on net thermal efficiency (gross efficiency minus auxiliary equipment consumption), affecting 2000 kW forced and induced draft fans and fuel pumping systems [50,51]. Flows exceeded post-maintenance values by 30.41–31.35% at 61% load [15], equivalent to 82.6–83.8% load (206.6–209.6 MW), indicating untapped efficiency potential.

3.3. Boiler Efficiencies

Steam quantity and quality determine useful heat and thermal efficiency (

Table 8. Heat output and efficiency indicators of the boiler under selected fuel conditions.

		Present Study		Camaraza-Medina et al. [15]
Parameter	Unit	Fuel (LSG = 61%)	Crude (LSG = 58%)	Crude 2 (LSG = 61%)
Useful heat output, (Qu)	MW	437.5	416.9	378.8
Available heat, (Qd)	MJ/kg	40.661	39.427	38.435
Average thermal efficiency, (ηtGV)	%	90.59	90.27	92.33
Exergetic efficiency, (ηExGV)	%	58.67	58.34	59.69

). The boiler produced high-quality steam near design parameters but had low productivity (61 and 58% of nominal for fuel and crude) due to partial TPP loads (66 and 62%) [16,18,19,28]. Partial loads risk water vapor condensation in gases, reducing temperatures and increasing corrosion in heat transfer surfaces and gas evacuation systems.

The available heat (Q_d) was higher with fuel (1.234 kJ/kg), driven by its higher lower heating value (Table 3), yielding greater productivity (27.2 t/h) and useful heat (74 · 10⁶ kJ/h). Average thermal efficiencies (90.59 and 90.27%) indicate satisfactory energy utilization but fall below the 94% design value due to irregular maintenance. Prior studies [15] reported efficiencies 1.74–2.06% higher with crude 2. Exergetic efficiencies were below 60%, slightly improved post-maintenance, due to irreversibilities and temperature differences [13].

The primary exergy destruction occurs in the combustion chamber, where the flame temperature (≈1800 K) is much higher than the working fluid temperature (≈500 K), generating large irreversibilities. Excess air further increases exergy destruction by diluting the combustion products, reducing the effective flame temperature and increasing entropy generation. The temperature gradient between the flue gases and water/steam in the economizer, evaporator, and superheater also contributes to additional exergy destruction. Figure 4 presents a Sankey diagram that quantifies these contributions; for example, the combustion chamber accounts for approximately 70% of the total exergy destruction under the tested conditions whereas fuel oil (black color) and crude oil (red color).

3.4. Steam Production Index and Specific Fuel Consumption

The steam production index (IG_v, t_steam/t_fuel) and specific fuel consumption (B_Esp, g_fuel/kW·h) indicate higher efficiency with fuel, producing 0.53 t_steam/t_fuel more and consuming 13.02 g/kW·h less than crude (

Table 9. Steam production index and specific fuel consumption of the TPP.

		Present Study		Camaraza-Medina et al. [15]
Parameter	Unit	Fuel (LSG = 61%)	Crude (LSG = 58%)	Crude 2 (LSG = 61%)
Steam production index, (IGv)	t/t	12.18	11.65	13.61
Specific fuel consumption, (BEsp)	g/kW·h	238.62	251.64	238.70

). The real thermal efficiencies were 3.41–3.73% below design due to excessive air, fouling, and inadequate maintenance [52,53]. High-sulfur fuels exacerbate fouling and corrosion, reducing heat transfer and increasing aerodynamic resistance [54], impacting boiler availability and socio-economic consequences. The exergy-based sustainability indicators developed by Gungor Celik and Aydemir [55] provide a valuable framework for evaluating system performance under realistic conditions, which can inform future combustion tuning and maintenance planning in industrial steam generators.

3.5. Proposed Technical and Organizational Actions to Improve the Thermo-Exergetic Performance of the Boiler

Considering the issues identified in the boiler, including prolonged operation under partial load conditions, inadequate maintenance, and the use of a fuel different from the original design specification (i.e., Enhanced Crude Oil 650) that have resulted in suboptimal thermo-exergetic performance of the system (Figure 4), the implementation of the following actions is recommended [1]:

▪

Optimize the boiler energy management system through the application of the ISO 50001 standard [56]. This framework enables systematic monitoring and evaluation of steam generation processes, guiding continuous improvement in alignment with the energy policies of the power plant and national objectives.

▪

Operate the steam generator at or near nominal load, whenever possible, to minimize inefficiencies associated with underutilization, reduce the likelihood of major mechanical failures, and maintain operational safety margins.

▪

Preheat combustion air and ensure adequate air supply to enhance combustion efficiency and increase available exergy. This requires a detailed analysis of the mechanisms of heat transfer in the presence of chemical reactions, particularly in fossil fuel boilers [14].

▪

Operate the burners according to established parameters—atomization flow and pressure, fuel preheating temperature, fuel moisture content, and degree of preparation—to ensure stable and efficient combustion.

▪

Minimize excess air levels and maintain optimal α values during partial load operation to reduce energy consumption by forced and induced draft fans (FDFs and IDFs).

▪

Maximize the recovery of sensible heat from combustion gases to reduce the temperature of the gas outlet of the stack, avoiding water vapor condensation and associated corrosion in the flue gas and water circulation systems.

▪

Maintain clean internal and external heat transfer surfaces and ensure proper technical condition of the boiler insulation to reduce heat losses.

▪

Ensure tight sealing of inspection ports, walls, and registers, and avoid unnecessary openings of these elements to minimize air infiltration and gas leakage.

▪

Maintain the combustion temperature at a stable and optimal level to maximize the conversion of combustion heat into useful exergy.

▪

Reduce the temperature gradient between the working flid (water) and the combustion gases to minimize irreversibilities during heat transfer and phase change, such as implementing multistage feedwater heating in economizers to support this objective.

▪

Through validated numerical methods and simulation tools [57], assess the feasibility of integrating renewable energy sources to preheat feedwater. This strategy would reduce fossil fuel consumption and mitigate the associated environmental impacts [58].

The timely and integrated implementation of these actions, as envisioned in the structured diagnostic procedure presented in Figure 2, will contribute to reducing thermal losses and improving the overall indicators of energy performance of the boiler. However, the positive impacts of such measures remain insufficiently quantified in this specific installation. Future studies will address this gap and explore the use of artificial intelligence for operational and energy optimization in industrial steam generators.

3.6. Estimated Economic Implications

The inefficiencies identified have direct economic consequences. Using the specific fuel consumption values (B_Esp) from Table 9 and local fuel prices (approximately 450 USD/t for fuel oil and 420 USD/t for crude), the additional fuel cost associated with operating with crude under the current suboptimal conditions can be estimated. Compared to operation with fuel oil under proper maintenance (B_Esp = 238.62 g/kWh), the higher specific consumption for crude (251.64 g/kWh) results in an extra fuel use of about 13.02 g/kWh. For an annual operation of 7000 h at an average load of 160 MW, this translates to approximately 14,560 t of additional fuel per year. Considering the price difference, the net additional annual cost is roughly 1.2 million USD. This estimate, while preliminary, underscores the tangible economic benefit that could be achieved by implementing the corrective measures proposed in Section 3.5.

3.7. Generalization and Applicability of the Methodology

The integrated diagnostic procedure presented in Figure 2 is based on fundamental mass, energy, and exergy balances that are universally applicable to any fossil-fuel-fired steam generator. The coherence verification loop (ER in Figure 2) is a generic tool for improving the reliability of performance assessments by reconciling direct and indirect method results. However, the specific correlations used for certain heat losses—such as the load dependent q₅ correlation (Equation (12)) or the treatment of mechanical unburned losses (q₄)—must be adapted when applying the methodology to different boiler types (e.g., fluidized bed, grate fired) or to fuels with distinct combustion characteristics (e.g., solid fuels, biomass). Nevertheless, the overall methodological framework is versatile and can be transferred to other industrial boilers after appropriate parameterization.

4. Conclusions

A structured diagnostic procedure was developed for the thermo-energetic evaluation of a 250 MW TPP boiler, enabling precise determination of its energy performance indicators. Applied to the studied steam generator, the procedure proved effective and practical for thermo-exergetic analysis of complex boilers in conventional thermal power plants.

The boiler exhibited superior energy performance with fuel oil (thermal efficiency 90.59% and exergetic efficiency 58.67%) compared to Enhanced Crude 650 (90.27% and 58.34%, respectively). However, these differences were mainly due to operational factors rather than the fuel type, including partial load operation (plant: 66% and 62%; boiler: 61% and 58%), suboptimal combustion adjustments causing elevated excess air (22.7% and 26.4%), and heat transfer surface fouling due to inadequate maintenance.

Key performance indicators—thermal efficiency (η_tGV); exergetic efficiency (η_ExGV); exergy loss (γ_ExGV); steam production index (IG_v); and specific fuel consumption (B_Esp)—revealed progressive deterioration relative to design values. The specific fuel consumption was 238.62 g/kWh for fuel oil and 251.64 g/kWh for crude, indicating an additional fuel cost of approximately 1.2 million USD per year under current operating conditions. Adopting best practices and robust maintenance strategies can unlock significant energy efficiency reserves in the boiler and the TPP.