Energy efficiency and greenhouse gas emission abatement opportunities for an existing gas treatment plant: a comprehensive technical and economic analysis

This research paper examined the operational performance and greenhouse gas (GHG) emissions of an existing gas treatment plant. Extensive data collection and analysis were undertaken to assess energy consumption and emissions and identify major emitter units. A GHG emission inventory was developed, and a benchmarking analysis was conducted. The gap analysis revealed excessive emissions, leading to the identification of potential GHG abatement alternatives for the turbo compressor and stabilizer heater. Technical feasibility assessments and economic evaluations were performed for the implementation of waste heat recovery systems, specifically an absorption chiller and a hot oil-driven re-boiler. The results demonstrated significant energy savings, emission reduction, and positive financial returns. The economic evaluation of the abatement opportunities revealed an estimated annual savings of $229,287 US with a simple payback period (SPBP) of 2.96 years and an internal rate of return (IRR) of 32%/year for the absorption chiller. The re-boiler heat system showed an estimated annual savings of $209,456 US with an SPBP of 5.14 years and an IRR of 14%/year. The total investment for both opportunities amounted to $1,755,773 US, with a total annual savings of $438,743 US. The combined SPBP for the opportunities was 4 years, with an IRR of 21%/year. Sensitivity analyses demonstrated the absorption chiller’s financial viability, while the hot oil-driven re-boiler opportunity proved more sensitive to variations in investment costs and savings. Therefore, it is recommended to implement both opportunities together.

past decade, there has been a notable surge in gas consumption, accompanied by an increase in fuel costs, thereby straining energy markets.Consequently, certain countries are grappling with the challenge of meeting rising demands while experiencing stagnant or diminishing power supply, leading to a widening energy shortage gap [2,3].Additionally, traditional gas supply and delivery face constraints, intensified by factors such as global competition, concerns regarding climate change, deteriorating grid infrastructure, and security issues [4][5][6].These circumstances further exacerbate the energy situation, resulting in adverse environmental, human health, and financial consequences.Hence, it becomes imperative to optimize energy usage by enhancing the efficiency of gas plants, improving facility designs and equipment, conserving energy, and promoting sustainable and renewable energy sources [7].
Gas treatment plants, responsible for processing raw natural gas from the wellhead, are crucial components of the natural gas supply chain [8].These plants remove impurities and contaminants, ensuring the final product meets the stringent quality standards required for consumption and industrial use [9].Nevertheless, these gas treatment plants are notorious for their substantial energy consumption and subsequent carbon emissions, particularly due to the operation of gas turbines and fired heaters, which are among the major GHG emitters in such facilities [10].
Energy efficiency stands at the forefront of the global drive for sustainability [11].In the oil and gas sector, improving energy efficiency not only reduces operational costs but also minimizes the environmental footprint [12].The quest for energy optimization and emissions reduction in gas treatment plants represents a multifaceted challenge that requires innovative solutions [13].Through a comprehensive assessment of the energy consumption patterns and emissions sources within a gas treatment plant, opportunities for optimization can be identified and harnessed [14].One of the most promising avenues in this regard is the utilization of waste heat recovery techniques [15].
The definition of industrial waste heat has been described in various ways.According to Viklund and Johansson [16] waste heat refers to the heat produced as a by-product during industrial processes, without considering the potential for heat recovery within or between processes.On the other hand, Ammar et al. [17] define waste heat as heat that is not economically viable for recovery.Meanwhile, Bendig et al. [18] define waste heat as the exergy available in a process after heat recovery and utility integration.While both Ammar et al. [17] and Bendig et al. [18] acknowledge the possibility of heat recovery within a process, they fail to account for the heat rejected from a site utility system designed to fulfill the process energy demand.
Various methods can be employed for waste heat recovery.Heat exchangers are commonly used to transfer heat from hot waste streams to colder fluids or gases, which can be utilized for preheating, steam generation, or electricity production.Organic Rankine cycles (ORCs) utilize organic fluids with lower boiling points to convert waste heat into electricity efficiently.Combined heat and power (CHP) systems simultaneously generate heat and electricity from industrial waste heat.Other methods include thermoelectric generators and absorption refrigeration systems, which directly convert waste heat into electricity or use it for cooling applications, respectively [19,20].
Under ISO ambient conditions, gas turbine energy efficiencies are typically around 30% [21].However, high ambient temperature and relative humidity have a negative impact on turbine energy efficiency.Gas turbines operate at a constant volume, so power output decreases as air density and mass flow rate decrease in elevated temperatures.Additionally, high humidity conditions increase the heat consumption of the gas turbine combustion chamber due to water's high specific heat [22][23][24].On average, for every 1°C increase in ambient temperature, gas turbine output power decreases by approximately 0.5 to 0.9% [24].To improve NG turbine performance and overall plant energy efficiency, a promising approach is to utilize waste heat for powering an absorption chiller to produce chilled water for cooling and generate a thermal load within the plant.This study explores these approaches.
In the past, the utilization of waste heat for enhancing the efficiency of gas plants has been relatively insignificant.This lack of progress can be attributed to various factors, including the absence of financial incentives, limitations imposed by licensed process technologies that impede energy efficiency improvements, and concerns surrounding the safety of specific waste heat sources.However, with increasing environmental concerns and the global energy shortage, there is mounting pressure on plants to embrace waste heat recovery technologies.Furthermore, as most natural gas plants have already achieved a notable level of process heat integration, the next significant step towards enhancing energy efficiency lies predominantly in the utilization of waste heat [25].
Absorption chillers offer various benefits such as reduced energy usage, eco-friendliness, and silent operation [26].They can seamlessly integrate into pre-existing natural gas treatment plants.This research focuses on utilizing waste heat from gas turbine exhaust gases to provide the required heat, enabling cooling of the gas turbine compressor inlet air while also delivering extra cooling capacity for controlling room buildings.
Previous studies have shown the benefits of absorption chillers.Mohanty and Paloso Jr. [27] found that absorption chillers can increase a gas turbine's power output by up to 13%.Al-Ibrahim and Varnham [28] compared different cooling technologies and concluded that absorption refrigeration is the most effective but expensive option.Popli, Rodgers, and Eveloy [29] focused on waste heat-powered absorption chillers, which can enhance power output and reduce fuel consumption in the oil and gas industry.Ameri and Hejazi [30] reported a power output increase of up to 9.99% with absorption chillers.Other studies have explored the impact of inlet air cooling (IAC) on gas turbines, with improvements in performance observed [31,32].Caresana et al. [33] noted the effects of ambient temperature on power output and system efficiency.Singh [34] investigated the use of absorption refrigeration for inlet air cooling and observed an increase in net power output.Radchenko et al. [35] proposed a design methodology for efficient turbine intake air cooling.Al Moussawi et al. [36] reviewed trigeneration technologies, emphasizing their energy and economic savings potential.Baudat and Fan [37] proposed a power recovery system, and Popli, Rodgers, and Eveloy [38] presented a trigeneration scheme using waste heat.

Methods
The process of developing a GHG abatement plan for the gas treatment plant involves the following steps:

Plant identification and process description
This study focuses on an existing upstream gas treatment plant designed to utilize highpressure associated gases from nearby gas wells.The plant has a processing capacity of 85 MMSCFD of high-pressure gas and approximately 3000 barrels per day of condensate.It produces two main products: residue gas, which is transported 58 km through a gas transmission line to another processing plant, and recovered stabilized condensate, which is stored in two tanks and subsequently pumped into the company's crude oil pipeline.The plant comprises six vessel-type slug catchers, a dew-pointing control unit, a condensate recovery stabilization unit, and a gas compression unit.In addition, it includes auxiliary facilities such as wastewater treatment, flare, and venting, as well as utility systems like water supply and drainage, fuel gas, power supply, instrumentation, and utility air.Figure 1 provides a simplified block diagram of the selected plant.

Data collection
Extensive data collection was conducted for one year prior to the study to comprehensively analyze the plant's operational performance.Performance variables, including flow rate data for sales gas and condensate, were captured (Fig. 2), and monthly fuel gas consumption was examined (Fig. 3).

Preliminary analysis of the data
Preliminary data analysis will provide a better understanding of the operational regime, the nature and quantity of energy consumption, and their associated emissions.It will also facilitate the identification of major emitter units that need to be closely examined during the study.The preliminary analysis was carried out based on the available data, following the approach outlined below:

Specifying the types and quantities of energy sources and their associated emissions
The selected gas plant relied solely on an internal fuel gas source as the primary energy source, driving all systems either directly for thermal loads or indirectly through electricity generation units for electrically driven equipment.The annual fuel gas consumption amounted to approximately 839.10 MMSCF, resulting in approximately 60.13 K tons of carbon dioxide (CO 2 ) equivalent emissions.It is clear that there was a significant increase in the CI from March to July, with another peak in October.These spikes were associated with decreased production levels, while energy consumption and flaring remained relatively high.

Developing plant GHG emission inventory
The total plant's GHG emissions amount to approximately 113,039 tons of CO 2 -eq and arise from a variety of sources, including energy consumption, non-routine flaring, and methane emissions.A detailed breakdown of the plant's annual GHG emissions by source category is provided in Fig. 6.Additionally, Table 1  major emitters within the plant that necessitate further investigation.Remarkably, these major units collectively contribute to around 82% of the total GHG emissions.

Plant emission benchmarking
The benchmarking analysis was conducted to evaluate the CI of the plant in comparison to similar facilities.Furthermore, the analysis extended to making comparisons across diverse sectors, notably the upstream sector encompassing oil and gas production, the midstream sector linked to transportation, and the downstream segment involving crude refining.Data from the National Inventory Reports (NIR) of various countries, compiled under the United Nations Framework Convention on Climate Change (UNFCCC), were utilized for this purpose.plant and global oil and gas peers, focusing on total emissions (blue bar), flaring emissions (orange bar), and methane emissions (silver bar).Upon comparing the plant's CI in 2021 with that of global oil and gas peers, it becomes apparent that the plant's CI exceeds the observed average.The total CI of the plant was measured at 27.0 kg CO 2 -eq/boe, surpassing the overall average of 24.07 kg CO 2 -eq/boe.Additionally, the plant's CI associated with flaring, measuring 7.89 kg CO 2 -eq/boe, surpasses the presented average of 5.5 kg CO 2 -eq/boe.However, the plant's CI related to methane, recorded at 4.46 kg CO 2 -eq/boe, was nearly identical to the presented average of 4.40 kg CO 2 -eq/boe.
In parallel, Fig. 8 delves into the carbon intensity (CI) of the plant by comparing it to the context of upstream, midstream, and downstream activities within the local environment.It is evident that the plant's CI values are notably competitive when compared to both upstream and downstream sectors.

Gap analysis
A comprehensive assessment was conducted to compare actual emissions with benchmark emissions.Figure 9 displays the cumulative sum of the difference (CUSUM) between these two values.The graph reveals that over the course of 1 year, there was an excess emission of approximately 37,000 tons of CO 2 equivalent.
Further investigation identified several factors contributing to the elevated CI observed in the plant.These factors include non-routine flaring, methane fugitives, and emissions related to the energy consumption of significant energy users, specifically the turbo compressor and stabilizer heater.It is worth noting that the study did not specifically focus on flaring and methane emissions, as separate studies have extensively addressed abatement techniques in those areas.Consequently, the study primarily concentrated on assessing the performance of significant energy users.

Turbo compressor process description
The plant is equipped with two dual-shaft open-cycle gas turbine-driven centrifugal compressors, both of which were commissioned in 1990.One of these compressors is currently operational, while the other serves as a standby unit.The gas turbine has a design efficiency rating of 25.7% and a total power capacity of 3.2 MW.The compressor is designed to operate with an efficiency of 72%, and the corresponding cycle design efficiency is 18.5%.

Turbo compressor performance analysis
It is worth noting that the operating efficiency of the cycle typically ranges from 10 to 13%.Furthermore, in this open cycle system, the turbine exhaust, which reaches temperatures as high as 450 to 550°C, goes unused, resulting in significant heat wastage.Figure 10 presents the actual cycle performance throughout the year 2021.It is evident from the graph that there is a notable peak in heat rate during the month of October.Further analysis revealed that this increase in heat rate coincided with a decrease in production rate, while the fuel consumption did not decrease by the same proportion.
Figure 11 provides insights into the impact of ambient temperature and load factors on the cycle performance.It is evident that ambient temperature has a significant influence on cycle performance.

Stabilizer heater process description
The stabilizer heater serves as a re-boiler for the condensate stabilizer tower.The heater is a vertical cylindrical, natural draft with fuel gas firing, and it is equipped with three burners complete with their pilots and electrical igniters.The heater design efficiency is 82.68%, based on a design stack temperature of 335 °C and a design excess air of 10%.

Stabilizer heater performance analysis
The heater exhibited an average operating efficiency of approximately 65%. Figure 12 provides a monthly performance overview of the heater throughout the year 2021.
Figure 13 provides an illustration of the average monthly oxygen concentration in the flue gases.It is evident from the graph that the oxygen concentration is relatively high throughout the year, exceeding the recommended oxygen concentration of 2%.This indicates the presence of excess air in the combustion process, which in turn has led to decreased combustion efficiency.
Figure 14 presents an illustration of the average monthly heater stack temperature.It is evident from the graph that the stack temperature remains consistently high throughout the year, exceeding the design stack temperature of 335°C.The elevated stack temperature suggests that a significant amount of heat was being lost through the flue gases without effectively transferring it to the desired process.

Identification of potential GHG abatement alternatives
Based on the results of the plant's GHG emissions inventory and the conducted gap analysis, a concise list of potentially applicable alternatives for reducing GHG emissions was developed.

Abatement measures for the turbo compressor
Based on the performance analysis, it is evident that the exhaust gases contain recoverable heat that can be utilized.Approximately 5.0 MW thermal of net heat could be recovered from a single-gas turbine (GT).This recovered thermal energy can be employed in the following ways: • Powering an absorption chiller to produce chilled water for cooling purposes.This includes cooling the intake air for the gas turbine compressor.• Additionally, the recovered thermal energy can meet the cooling requirements of the main control building.• Generating thermal load for use within the plant.

Abatement measures for the stabilizer heater
Based on the performance analysis, it was found that the heater had significantly low operating efficiency, accompanied by high stack temperature and oxygen concentration.Utilizing the available recovered thermal energy from the turbine exhaust, it is feasible to replace the current heater with a more efficient oil heating system.
Regarding the pre-defined abatement opportunities, Fig. 15 illustrates the system setup that showcases the proposed approaches.

Technical feasibility
The different proposed opportunities for harnessing the recovered heat were evaluated in terms of their sizing, taking into consideration the availability of the heat and the relevant operating parameters.

Generation of thermal cooling through an absorption chiller
The absorption chiller was sized based on the cooling demand for cooling the combustion air intake to the GT compressor, as well as the cooling demand for the DCS building and the Switchgear Power Generation Building.

Absorption chiller process description
Figure 16 provides an illustration of the proposed absorption chiller system utilizing water and lithium bromide (LiBr) as the refrigerant and absorbent pair.The system utilizes the exhaust gas from a gas turbine, with a temperature of 480°C, as the heat source in the water heater (generator).This generator increases the temperature of the LiBr solution, causing water to evaporate and leaving behind a concentrated LiBr solution.The high-pressure and high-temperature vapor generated enters the condenser, where it releases heat to a cooling medium (cooled water) and condenses into a high-pressure liquid.The high-pressure liquid then flows through an expansion valve, reducing its pressure and temperature, resulting in partial evaporation and transformation into a low-pressure vapor.This low-pressure vapor is directed to three separate evaporators: one absorbs heat from the combustion air intake to the gas turbine compressor, another caters to the cooling demand of the distributed control system (DCS) building, and the third cools the switchgear power generation building.These absorption processes cause further evaporation of the vapor, converting it back to a gaseous state.The vapor subsequently returns to the absorber, where it is absorbed by the LiBr solution, forming a dilute LiBr solution.To restart the cycle, a pump is employed to increase the pressure of the dilute LiBr solution from the absorber, sending it back to the generator.
The cooling load for each specific application within the demonstrated setup was estimated based on the existing operating parameters at the plant.

Assessment of combustion air intake cooling for the gas turbine
The cooling load for the GT is presented in Table 2, considering the GT air intake of 16.93 kg/s based on the exhaust gases at ISO condition with a flow rate of 17.2 kg/s for the exhausted flue gases.Additionally, an assumed air temperature drop of 15 °C in the air intake was considered.
According to plant representatives, both turbo compressors will run simultaneously to meet increased production demands.This results in an estimated cooling load of 150 ton of refrigeration (TOR) for the two turbines.To address this requirement, the sizing and specifications of air handling unit (AHU) #1, as presented in Table 3, need to be considered.

Assessment of cooling load for the DCS and switchgear buildings
In the switchgear building, two direct expansion (DX) packaged units are installed to provide central air conditioning.Each unit has a capacity of 233,000 Btu/h (19.4 TOR) with a coefficient of performance (COP) of 2.22 at ISO Condition.Consequently, the AHU #2 will be sized at 40 TOR to meet the cooling requirements of this building.
Similarly, the DCS building is equipped with two DX-packaged units for its central air conditioning system.Each unit has a capacity of 144,000 Btu/h (12 TOR) with a COP of 2.22 at ISO condition.As a result, the AHU #3 will be sized at 24 TOR to adequately serve the cooling needs of the DCS building.The sizing and specifications for AHU#2 and AHU#3 are presented in Table 4.

Sizing of absorption chiller and the associated components
The sizing of the absorption chiller is designed to fulfill the cooling requirements of three AHUs responsible for supplying chilled air to the gas turbines' air intake, the switchgear building, and the DCS building.To meet these demands, the total capacity of the absorption chiller will be sized at 220 TOR, while the cooling tower capacity will be sized at 410 TOR.The capacities for the chilled water pump, condenser water pump, and makeup water for the cooling tower, along with their respective specifications, can be found in Table 5.According to this analysis, it has been determined that the waste heat recovery (WHR) system's capacity to produce hot water, which drives the absorption chiller, is sized at 1.14 MW thermal .

Avoided energy through waste heat recovery (WHR) system
Table 6 presents a summary of the achieved energy savings and reduction in GHG emissions resulting from the implementation of the absorption chiller to serve the assumed cooling load.
Table 7 presents a summary of the calculations for the additional energy consumption, GHG emissions, and associated costs resulting from the implementation of the WHR system to generate thermal cooling energy.The WHR system requires energy consumption for the operation of pumps related to the cooling towers (condenser water cooling) and chilled water distribution.
The implementation of the absorption chiller system results in a net avoided energy cost of approximately $229,000 US/year, a reduction of 2560 tons of CO 2 -eq emissions/ year.Additionally, it achieves a net energy reduction of 9.53% in the total energy input.

Hot oil-driven re-boiler process description
This opportunity involves utilizing recovered waste heat to generate a thermal load.The process involves passing the waste heat through a gas-to-fluid heat exchanger, which then allows for the design of a hot oil-driven re-boiler, as illustrated in Fig. 17.
The assessment of the assumed system has been carried out considering the 100% duty of the re-boiler from a sizing perspective.However, the calculation of   anticipated energy savings was performed based on the actual operating duty.The existing operating parameters for the re-boiler at 100% performance duty are illustrated in Table 8.

Avoided energy for replacement of the existing re-boiler
The existing re-boiler was operated at approximately 40% loading, which served as the basis for calculating the avoided energy.Table 9 presents the avoided energy and the corresponding reduction in GHG emissions resulting from the replacement of the existing re-boiler and the corresponding reduction in energy consumption.
The study demonstrated that the recovered gases amounted to 4.4 MW thermal .Out of this, 1.13 MW thermal was utilized to drive the absorption chiller, and 3.26 MW ther- mal was allocated for hot oil generation.Furthermore, the available exhaust gases to be recovered from the single-gas turbine were estimated to be approximately 5 MW thermal .Based on these findings, the study was deemed feasible from a technical point of view.

Investment cost estimation for emission abatement opportunities
The total investment cost for each abatement opportunity was estimated to assess the financial feasibility of each option.The cost estimates were presented as an order of magnitude, indicating a broad range of values, with an approximate accuracy of ±15%.

Waste heat recovery to generate hot water and hot oil
The total investment cost for both WHR systems, including the generation of cooling load and the heated oil, is illustrated in Table 10.The total investment cost is $1,761,000 US.Out of this amount, $1,081,000 US is allocated for the installation of a hot oil driven re-boiler, while $680,000 US is dedicated to the generation of thermal cooling through an absorption chiller.

Economical and financial evaluation
The abatement cost for the identified opportunities, expressed in $/ton CO 2 -eq, can be derived using the subsequent formula: Marginal abatement cost ($/ton CO 2 -eq) = net present value/total GHG emissions abated over project life   where d signifies the discount rate, set at 10% for this analysis, i denotes the interest rate, which is also 10% in this instance, and t represents the time of cash flow, specifically spanning 10 years.Table 11 offers a comprehensive economic assessment of the identified opportunities through the lens of abatement costs.
Table 12 provides an economical evaluation of the abatement opportunities using the simple payback period (SPBP) as an economic indicator.
It is evident that the evaluated abatement opportunities are long-term projects.Consequently, the internal rate of return (IRR) was employed as an economic evaluation tool, considering the time value of money.Table 13 presents the calculated IRR for each opportunity.

Sensitivity analysis
The economic indicators mentioned above were calculated using two main inputs.Firstly, the investment cost was estimated using the order of magnitude technique, which involved considering data from similar projects and utilizing engineering expertise.Secondly, the annual cost savings were determined through a combination of engineering calculations, historical data analysis, anticipated data, and an assumed cost of $4.75 US per MMBTU.
The sensitivity analysis outputs in Fig. 18 illustrate the variations in economic indicators for the generation of thermal cooling through an absorption chiller, considering a range of − 15 to + 15%.It is evident from the analysis that the opportunity maintains its economic feasibility even in scenarios where the investment cost increases by 15% resulting in a 5% decrease in IRR or a 15% decrease in savings leading to a 6% decrease in IRR.
Figure 19 presents the sensitivity analysis outputs for the installation of a hot oil driven re-boiler.This opportunity exhibits a moderate IRR of approximately 14%.It is noteworthy that the project is sensitive to variations in both the estimated investment cost and the calculated savings.If the investment cost increases by 15%, the IRR is projected to decrease to 11%.Similarly, a 15% decrease in savings would result in an IRR of 10%.

Recommendation
It is recommended to implement both opportunities in conjunction with each other.The combination of these opportunities yields improved economic indicators, as demonstrated in Fig. 20.

Conclusions
This research paper provided a comprehensive analysis of the operational performance, energy consumption, and greenhouse gas emissions of an existing gas treatment plant.Major emitter units were identified, and their contributions to the overall emissions profile were quantified.Potential GHG abatement alternatives for the turbo compressor and stabilizer heater were proposed, involving the recovery and utilization of waste heat.Technical feasibility assessments confirmed the viability of implementing waste heat recovery systems, while economic evaluations demonstrated positive financial returns over time.
The research findings indicated that the adoption of an absorption chiller and a hot oil-driven re-boiler could result in substantial energy savings, emission reduction, and Fig. 20 Sensitivity analysis outputs for both opportunities improved operational efficiency.Moreover, sensitivity analyses have underscored the financial viability of the absorption chiller, while shedding light on the hot oil-driven reboiler's sensitivity to variations in investment costs and savings.To ensure maximum feasibility and profitability, it is strongly recommended to implement both opportunities together.
These findings contribute to the field of energy optimization and emissions reduction in gas treatment plants, providing valuable insights for the industry.The research underscores the importance of implementing sustainable practices and technologies to mitigate environmental impact while realizing economic benefits.

Fig. 1
Fig. 1 Block diagram of the selected gas plant

Figure 4
Figure4presents the monthly GHG emissions associated with the plant's energy consumption during 2021.Furthermore, Fig.5illustrates the plant's monthly carbon intensities (CIs), which reflect the level of GHG emissions adjusted by the total barrels of oil equivalent produced.It is clear that there was a significant increase in the CI from March to July, with another peak in October.These spikes were associated with decreased production levels, while energy consumption and flaring remained relatively high.

Fig. 2 Fig. 3
Fig. 2 Monthly plant products flow rates Figure 7 displays the CIs of the

Fig. 9
Fig. 9 Emission cumulative sum of difference

Fig. 11 Fig. 12
Fig. 11 Effect of ambient temperature and load factor on cycle performance

Fig. 17
Fig. 17Waste heat recovery system to drive a re-boiler Fig. 17Waste heat recovery system to drive a re-boiler

Table 1
List of the major emitter units [39]pmentEnergy used MMBTU/Y Emissions (K Ton CO 2 e) % from total emissions Fig.7Facilities carbon intensities[39]

Table 2
Cooling load calculation for combustion air intake

Table 3
The air handling unit #1 sizing and specs

Table 4
The AHUs #2&3 sizing and specs

Table 5
Absorption chiller sizing

Table 6
Summary of avoided energy and ghg emission reduction due to absorption chiller

Table 7
Operating cost for absorption chiller cooling system

Table 8
Existing operating parameters for the re-boiler at 100% duty

Table 9
Avoided energy due to re-boiler replacement

Table 10
Estimated investment cost-WHR system

Table 11
Cost-effectiveness evaluation of opportunities: abatement cost analysis

Table 12
Emission abatement opportunity economic evaluation by SPBP

Table 13
Emission abatement opportunities economic evaluation by IRR