Increasing the amount of hydrogen (H2) in natural gas mixtures contributes to gas turbine (GT) decarbonisation initiatives. Hence, the swirling flame characteristics of natural gas mixtures with H2 are investigated in the current work using a numerical assessment of a single swirl burner, which is extensively employed in GT combustors. The baseline numerical and experimental cases pertained to natural gas compositions largely consisting of methane (CH4). The results show that the numerical model adequately describes the swirling component of the flame observed in the experiment. Altogether, the findings show that hydroxyl (OH) radical levels increase in H2-enriched CH4 flames, implying that greater OH pools are responsible for the change in flame structure caused by considerable H2 addition. The addition of 10 % H2 is predicted to raise the peak flame temperature by 4 % compared to the baseline CH4 flame. Therefore, adding 10 % H2 into a GT combustor without any flowrate tuning raises the risk of turbine material deterioration and increased thermal NOx emission. Due to the lower volumetric Lower Heating Value (LHV) of H2, which needs a higher volumetric fuel flow rate than burning natural gas/CH4 at the same thermal output, the addition of 2 % H2 is predicted to reduce the peak flame temperature by 4 % compared to the baseline CH4 flame. Hence, if 2 % H2 is fed into a GT combustor without any flowrate tuning, the required load may not be obtained. When compared to the baseline CH4 case, the addition of 5 % H2 is predicted to provide almost identical peak flame temperature, which can be postulated that the addition of 5 % H2 can produce roughly the same peak flame temperature as the pure CH4 flame because the Wobbe Index is comparable. Therefore, it reveals that incorporating 5 % H2 in the natural gas-fired GT combustor with nearly no modification is viable. More research, however, is required to fully capture the flame structure and strain for assessing transient-related phenomena such as flashback and blow off by raising the H2 proportion and utilising a higher precision turbulence model.

Malaysia is rich in palm oil plantations, where oil palm wastes (OPWs) are one of the readily accessible biomass resources. OPWs has the potential to be used as a fuel for electricity generation. Hence, the evaluation of OPWs co-firing for one of Malaysia's 500 MW utility boilers was executed numerically. Three types of OPWs were tested including empty fruit bunches (EFB), palm kernel shell (PKS), and palm mesocarp fibres (PMF). The predicted furnace exit gas temperature (FEGT) from the numerical model was validated against the actual FEGT from the power plant where the current boiler is situated, revealing a difference of less than 10%. The nose area temperature was predicted to exceed the cap of 1200°C in OPWs co-firing cases due to higher volatile matter (VM) in OPWs than the baseline of pure coal case, leading to higher levels of volatile release. When co-firing with OPWs, the predicted unburned carbon (UBC) at the boiler's outlet is lower because OPWs-coal blends contain less fixed carbon (FC) than the pure coal blend. UBC levels were anticipated to be lower than the loss of ignition (LOI) limit in all cases, highlighting its positive impact on carbon reduction. Slightly lowered mill performance was observed as a result of the calculated OPWs fuel flow surpassing the normal operation in the power plant to make up for the low gross calorific value (GCV) of OPWs while meeting the required load from the boiler. OPWs co-firing was predicted to emit lower carbon monoxide (CO) and carbon dioxide (CO2) than baseline coal due to lower FC. Nonetheless, higher thermal nitrogen oxides (NOx) were predicted due to the higher flame temperature created by OPWs co-firing. Even so, it is recommended that the ash mineral composition be included in future numerical studies since the ash minerals may have an effect on the emitted NOx.

Continuous research on the clean and effective use of coal is still necessary as coal will continue to play a key role in global energy supply for the foreseeable future. Hence, in the current study, the optimisation of in-furnace coal blending for one of Malaysia's opposed-firing utility boilers was numerically executed on the basis of hydrodynamics and combustion characteristics. The predicted FEGT from the numerical model was validated against the actual FEGT from the coal-fired power plant, revealing a difference of less than 10 %. Four (4) coal blended cases were tested, which included both bituminous (bit) and sub-bituminous (sub-bit) coals. The findings demonstrate that due to the difference in density between bit and sub-bit coals, the hydrodynamic performance is predicted to significantly improve when sub-bit coal is injected at the bottom burner as opposed to the upper burner. In terms of kinetics, the higher volatile matter (VM) of sub-bit coal in contrast to bit coal has been postulated to release a substantial amount of volatiles and improve the combustibility of bit coal. Furthermore, enhanced oxygen release from sub-bit coal volatiles can aggravate the gas-solid heterogeneous reaction during bit coal char combustion. As a result of the bottom burner's high temperature, it has been discovered that introducing sub-bit coals into those burners speeds up VM release and char combustion, which increases the rate of combustion. Thus, when combustibility rises, the peak temperature position moves downward, reducing the likelihood of delayed combustion and, consequently, the risk of heat exchanger pendant failure and ash deposition. In a furnace with a relatively long coal residence time, a considerable fraction (>20 %) of high gross calorific value (GCV) sub-bit coal (>5800 kcal/kg) is predicted to produce two peak flame temperatures exceeding 1600°C owing to the likelihood of enhanced char which created delayed combustion. Therefore, a furnace condition with a comparatively shorter coal residence time may aid in the rapid evacuation of residual char from the combustion/burner zone and minimise the potential for delayed combustion. Nonetheless, residual char escape may exacerbate the emission problem by releasing considerable unburned carbon. Overall, the current numerical model has the potential to be a reliable and cost-effective tool for investigating the combustion characteristics of coal blends in a power plant boiler.

The desire to develop gas turbines (GTs) that can utilise natural gas (NG) blended with hydrogen (H2) often encounters operability challenges related to combustion-induced vortex breakdown (CIVB) flashback issues. Hence, a detailed Large Eddy Simulation (LES) was employed in this study to examine the impact of H2-NG co-firing on central recirculation zones (CRZs), combustion properties, and the risk of CIVB flashback in a pilot-scale swirl burner facility. The LES model successfully replicated the swirling component of the flame observed in the experiment with reasonable accuracy. The findings revealed that the introduction of H2 into the burner increased the velocity and temperature of the burned gases. The higher reactivity of H2 resulted in faster burning rates and a shift in the reaction zone, indicating that NG-H2 firing burns more rapidly than pure NG firing. Additionally, H2 was found to enhance the velocity gradient, pushing the CRZ upstream. Changes in the location of the CRZ can disrupt density and velocity gradients, affecting the generation of vorticity by the baroclinic torque and potentially increasing negative axial velocity, thereby increasing the risk of CIVB flashback. Further research is necessary to comprehensively assess the CIVB flashback risk, particularly when the proportion of H2 exceeds 30 %.

The fluctuating quality of natural gas (NG) in Peninsular Malaysia (PM) makes it challenging for the gas turbine (GT) combustor to meet the combustion performance requirements from the Original Equipment Manufacturer (OEM). Moreover, the gas quality sensitivity is more apparent in modern dry low NOx (DLN) combustors. Many of the prior combustion investigations were conducted on a modest scale in the laboratory. In actuality, combustion characterizations in complicated DLN combustors are more valuable to the power generation sector. Hence, the current numerical analysis utilized the RANS formulation and a detailed chemistry to examine the impact of ethane (C2H6), carbon dioxide (CO2), and nitrogen (N2) proportions in NG on combustion characteristics in a multi-nozzle DLN (MN-DLN) combustor, with the support of Modified Wobbe Index (MWI) calculations. Validations were performed using the combustor outlet temperature (COT) from the power plant where the actual MN-DLN combustor is operated, which revealed less than 10 % discrepancy. Qualitative validations were carried out by comparing the burn trace from the actual combustor wall to the predicted results, revealing an adequate Structural Similarity Index (SSIM) of 0.43. From numerical results of flame fronts and COTs, the addition of 20 % diluents (CO2 and N2) to NG demonstrated the blowoff risk. When MWIs of Kerteh and the JDA (major NG resources) were used as baselines, MWI ranges of all NG compositions under study surpassed the OEM’s ± 5 % limit. The increase in CO2 proportion results in a wide MWI range, especially when Kerteh is used as the baseline. Therefore, any GTs in PM that have previously been calibrated to use Kerteh's NG are more likely to have combustion instabilities if CO2 levels in NG suddenly increase. The higher MWI range backs up the current numerical results that showed the deleterious effects of a high CO2 composition throughout the combustor firing process. However, increasing the amount of C2H6 by up to 20 % is predicted to have minor effects on combustion characteristics. Overall, the validated numerical model of the MN-DLN combustor provided critical information about combustion characteristics and multifuel capabilities in respect to the NG quality in PM.