Harnessing Biogas from STPs for Sustainable Energy: A Techno-Economic Study

doi:10.21203/rs.3.rs-4853625/v1

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Harnessing Biogas from STPs for Sustainable Energy: A Techno-Economic Study

https://doi.org/10.21203/rs.3.rs-4853625/v1

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The pursuit of affordable renewable energy sources has increased interest in biogas. One of the sources used to produce this fuel type is organic waste, which turns what would have been discarded into a valuable product. This study evaluated the potential and economic feasibility of generating electricity using biogas produced in a sewage treatment plant. The plant currently operates with an average inflow of 25 litres per second, producing an estimated 9.69 cubic meters of biogas per hour. The electricity generated has a potential of 125.22 megawatt-hours per year, meeting 47.4% of the plant's electricity needs. The average cost of the electricity produced ranges from 0.09 to 0.12 R$/kWh, depending on the interest rate used. The economic analysis suggests a maximum payback period of two years for the initial investment, with a net present value (NPV) of R$ 47,687.49 over the project's 20-year lifespan. Additionally, extrapolating the results to account for future expansion of the sewage treatment plant based on the total population in the region served by the sewage system reveals even more promising results.

Sewage treatment plant

Biogas

Energy production

Renewable energy

Due to the intensification of human activity, waste generation has exponentially increased in recent decades, which has become a serious problem for public administration. Urban waste deposited in inappropriate places such as dumps causes soil, air, and water pollution, as well as the appearance of disease vectors [1][2].

According to the Brazilian standard NBR 9648 from the Brazilian Association of Technical Standards - ABNT (1986), sanitary sewage is defined as liquid waste made up of domestic and industrial sewage, seepage water and rainwater. Domestic sewage is defined as the waste resulting from water use for hygiene and the physiological needs of the population [3]. Brazil has a water supply network that, although not universalised, can be considered comprehensive. This scenario needs to be observed in sewage collection and service in a deplorable situation regarding collection and treatment [4].

According to the IBGE (2024), only three thousand municipalities out of more than five thousand in Brazil properly dispose of their waste through collection networks to Sewage Treatment Plants (STP), according to information published in the latest national survey on basic sanitation [5]. The lack of collection and treatment of a considerable part of the sewage generated, for example, can impact the environment, health and, therefore, the population's quality of life. It is estimated that in Brazil, 65% of hospital admissions of children under the age of 10 are due to the inefficiency or absence of sewage treatment and the lack of clean drinking water [4]. However, with the enactment of Law 11.445 of January 5, 2007, basic sanitation became a right guaranteed to all. Municipalities have invested in recent years in new treatment plants [6] in order to reverse this situation and provide access to clean water, sanitation and clean and affordable energy, which correspond, respectively, to goals 6 and 7 of the United Nations Sustainable Development Program [7].

The increase in anaerobic STP in Brazil has led to an increase in the generation of biogas and sludge, which are the main by-products of the process [6][8]. Unfortunately, the energetic use of biogas is still incipient, with most landfills, domestic sewage, and industrial effluent treatment plants simply collecting and burning the generated biogas without taking advantage of its energetic potential.

The practice of producing energy from waste, Waste to Energy (WtE), is ideal for avoiding competition for arable land (for food production) and other land uses. Energy production using biogas from anaerobic digestion is becoming increasingly viable due to the improvement of the legal framework and the greater use of biomass sources, as well as the contribution to reducing greenhouse gas emissions such as methane in the atmosphere [9].

Decentralised electricity generation and heat production are two ways of using the main by-products generated in STP [10]. The National Electric Energy Agency (ANEEL) Normative Resolution No. 1,059 of February 7, 2023, the product of an action to minimise the intrinsic barriers to distributed generation in Brazil, established the general conditions for access to distributed micro and mini generation of electricity in the national territory, as well as defining the electricity tariff compensation system. For this resolution, distributed microgeneration is an electricity-generating plant with an installed capacity of less than or equal to 100 kW. On the other hand, distributed mini-generation is a generating plant with an installed capacity of more than 100 kW and less than or equal to 5 MW [11].

This resolution benefits sanitation companies that have anaerobic STP. These systems, especially those based on Upflow Anaerobic Sludge Blanket (UASB) reactors, are widely used in Brazil due to the low cost of installation and operation compared to aerobic systems, which require aerators. UASB reactors produce biogas as a by-product of the degradation of organic matter, composed mainly of 60–80% methane CH4, 10–25% nitrogen N2, dissolved in the sewage, and 5–10% CO2 [6][10], which can be used as an energy input within the STP itself, which consumes significant amounts of electricity, especially in the aeration aerobic systems, which can account for 30–80% of the plant's electricity demand [12]. Taking advantage of the biogas generated to generate electricity provides a reliable supply and, at the same time, helps to mitigate greenhouse gas emissions [13]. On the other hand, when there is a surplus in generation, it can be redirected to reduce the energy bills of other projects run by the concessionaire, such as water treatment plants, administrative buildings or other (STPs) that do not have the technology to collect biogas, by reinjecting this extra energy into the electricity grid of the local energy concessionaire, as provided for in ANEEL's resolution [11].

Various studies reported in the literature show the feasibility of using the biogas generated in STP for energy. Basrawi et al. [14] carried out an economic study of the behaviour of a cogeneration system employing micro gas turbines (MTG) of different powers (30–200 kW) in a sewage treatment plant. They concluded that the best configuration results when the nominal fuel consumption of the MTG is approximately equal to the plant's biogas production. Mirmasoumi et al. [15] studied the effect of pre-treating the sludge and increasing the temperature in the biodigester at an anaerobic digestion sewage treatment plant in Tabriz, Iran, combined with a trigeneration energy system (cooling, heat, and power). The results showed an increase in biogas production with pre-treatment and an increase in temperature in the biodigester of up to 180%, which consequently led to a decrease in the total cost rate and the levelized energy cost of up to 41.29%. Lee et al. [16] integrated an anaerobic STP with a cogeneration system, investigating the effect of component efficiencies, temperature differences in the heat exchangers and the ratio of pressures in the compressor and gas turbines. A multi-objective genetic algorithm was used to minimise environmental impacts, and the total cost rate, achieving a reduction of 5.3% and 16.9%, respectively, and the energy generated could cover 47% of the plant's electrical demand and 100% of the thermal demand. Mosayebnezhad et al. [17] investigated a hybrid system that employs MTG and solid-state fuel cells (SOFC) using biogas generated at a wastewater treatment plant (WWTP) in Italy. Two configurations were analysed: SOFC-WWTP and SOFC-MTG-WWTP. The results showed an increase in electricity generation and a decrease in the levelized cost of electricity of 12% in the second configuration. Di Fraia et al. [18] use a cogeneration system composed of an Internal Combustion Engine (ICE) and a gasification system that uses the sludge generated in a WWTP as fuel. The gas produced in the gasifier drives a dual-fuel ICE that uses waste vegetable oil altogether. The economic analysis showed a payback for the proposed installation of 6.8 years, one year longer than that calculated for an analogous conventional system, but the Net Present Value was 30% higher. A study on two WWTP plants in Austria using biogas produced in CHP systems with heat pumps and co-digestion systems fed with organic waste and concentrated wastewater was conducted by Nowak et al. [19]. The results showed a 180% increase in energy generation compared to the plants' energy needs, making them self-sufficient. Helal et al. [20] studied the application of renewable energy sources in a WWTP plant in Toukk, Egypt, using HOME software to simulate and compare different hybrid systems composed of CHP units, fuel cells, wind turbines and photovoltaic systems, concluding that the fuel cell and the microturbine variant maximises the power-heat ratio. Five WWTP plants located in Catalonia, Spain, which treat mixtures of domestic and industrial wastewater, were studied by Silvestre et al. [21]. The results showed that depending on the configuration of the installation and its operation, between 39% and 76% of the electricity consumed could be supplied by the biogas produced in the process when burned in internal combustion engines coupled to electric generators with a payback period of between 2–3 years.

The main advantages of producing electricity using biogas are [6]:

1. Decentralised energy generation, close to the consuming source;
2. The possibility of additional profit from the production and sale of energy following the rules of the electricity market regulatory system;
3. A reduction in the consumption of externally supplied electricity;
4. Potential for use in processes for the cogeneration of electricity and heat and
5. Reduction of methane emissions, which is a greenhouse gas.

According to Karlsson et al. (2014), Brazil needs to implement biogas in its electricity matrix faster than the international scene. Despite being a country where most of its energy comes from renewable sources and one of the leaders in the use of biomass to generate bioelectricity, public policy investments in the introduction of biogas in Brazil are not very stimulating, even though there are results that show that the country would be technologically capable of developing a sizeable national biogas program [22].

This research aims to assess the potential for using the biogas generated in an STP run by the Autonomous Water and Sewage Service (SAAE) in the city of Angra dos Reis, in the area known as Praia da Chácara, which uses an Upflow Anaerobic Sludge Blanket (UASB) reactor. It is also planned to analyse the economic viability of implementing a CHP system that burns the biogas generated in an internal combustion engine coupled to a generator. The electricity produced would be distributed on the grid, contributing to the diversification of the Brazilian electricity matrix, making it much more sustainable using renewable sources.

This work is based on a case study that will evaluate the possibility of implementing the use of internal combustion engines to use the biogas generated in an operational sewage treatment plant run by SAAE in Angra dos Reis, in the area known as Praia da Chácara, located in 23°00′11.2′′S, 44°18′18.4′′W. This plant is part of the sewage system in sub-basin G, which includes the neighbourhoods of Balneário and Parque das Palmeiras. Designed to serve 10,000 people, it currently treats the sewage of 6,600 inhabitants with a mean flow of 25 l/s proposed in the project developed by SANEVIX ENGENHARIA company. In the future, the idea is to expand the STP area of operation and include other neighbourhoods, such as Marinas and the hills closest to Parque das Palmeiras (Fig. 1).

The STP-type UASB + BFMO + DS is pre-moulded and built entirely in carbon and stainless steel to ensure considerable durability due to its proximity to the sea. It uses an Ascending Flow Anaerobic Reactor, an Organic Matter Biofilter, and a Secondary Decanter, with an inlet box system to retain the solids and dirt thrown into the network. It is followed by an anaerobic treatment process in which a colony of bacteria feeds on the organic loads. It is followed by an aerobic process that carries out the final treatment with new bacteria colonies. This process reduces the organic load by 96%. It also has a particular system to prevent bad smells. Even though the reactor technology (UASB - Upflow Anaerobic Sludge Blanket) has been implemented, which increases the production of biogas and sludge, the project proposed by the company does not offer the option of using the biogas generated from anaerobic digesters and sludge storage tanks for energy, being burned directly in a flare without any energy use. A new plant configuration scheme similar to the plant under study but using the biogas generated can be seen in Fig. 2.

Two scenarios will be analysed: The first scenario would consider the plant's current situation with an average flow of 25 l/s of effluent, a flow from a small station that will only serve a small territory. The second scenario would be a hypothetical situation in a future expansion of the plant that would be able to meet the needs of the entire population of the city of Angra dos Reis, which amounts to approximately 167,434 inhabitants, of whom 85% have access to adequate sewage systems [23].

Understanding the viability of biogas energetic use in an internal combustion engine requires a thorough calculation of project variables. These variables play a crucial role in the production of biogas in the sludge treatment plant, and their accurate assessment is key to the success of the project.

Affluent sewage volumetric flow

The amount of sewage that feeds the sewage treatment plant is currently stipulated in the project at 25 l/s, which will be the average flow for scenario 1. For scenario 2, an estimated effluent flow will be considered based on the population that will be served by the hypothetical plant, which, according to IBGE data for the municipality in question, would amount to 142,319 inhabitants. Using the example from Eq. (1), it determines that:

$$\:Q=\:\frac{QPC\times\:{C}_{r}\times\:Pop}{1000}$$

where:

Q – Influent sewage flow in the STP (m³/d).

Q_Hab – Per capita contribution flow (l/inhab.d).

C_r – Coefficient of recycle of sewage/water per capita.

Pop - Population (inhab).

In Brazil, according to the last census carried out by the IBGE, an individual's per capita use of water, called Quota Per Capita (QPC), was 116 litres per day. Among the major regions, the Southeast has the highest per capita use, with 143 litres, while the lowest use is recorded in the Northeast, with 83 litres per inhabitant. The domestic sewage flow was calculated based on the project population and the value assigned to the average daily water consumption (assumed to be equal to 116 l/inhab. day) [5], with a correspondence between sewage production and water consumption. The return coefficient (Cr) was adopted as 0.8 inhabitant/day, the recommended value when no local research data is available [24].

Volume of biogas produced in UASB reactors

According to Von Sperling [25] and Lobato et al. [26], it is acceptable to use 300mg/l for Biological Oxygen Demand (BOD) and 600mg/l of Chemical Oxygen Demand (COD), respectively, due to the physical chemistry characteristics of domestic and sanitary sewage influents into wastewater plants. These values of BOD and COD are the same as the ones proposed in the project and are consistent with the COD values obtained with diluted domestic wastewater in tropical conditions, COD < 1000mg/l and T > 20°C [27].

Chernicharo [28] has pointed out that the production of biogas is directly linked to the complete removal of organic loads in the reactor. The efficiency of the reactor, as demonstrated in Eq. (2), determines the COD from the effluent.

$$\:{E}_{COD}=1-\text{0,68}\times\:{HRT}^{-0.35}$$

In which:

E_COD – Efficiency of COD removal in the UASB reactor (%).

HRT – Hydraulic retention time (h). Adopted in this study 8 hours [27].

The removed organic load in the reactor can be obtained by Eq. (3).

$$\:{COD}_{CH4}=\left[Q\times\:\left({S}_{0}-S\right)\right]-\left({Y}_{obs}\times\:{S}_{0}\times\:Q\right)\:\:$$

Where:

COD_CH4 - organic load converted to methane (kgCOD_CH4/d).

Q – mean influent flow (m³/d).

S₀ -influent COD to UASB reactor. Adopted 0.60 kgCOD/m³) [26, 27] .

S - effluent COD filtered into UASB reactor (kgCOD_fil/ m³).

Y_obs - Coefficient of Total Suspended Solids production (kgCOD_TVS/kgCODapplied).

The effluent COD load (S) can be determined when the removal efficiency of the USAB reactor is known as:

$$\:S={S}_{0}\times\:(1-{E}_{COD})$$

Van Haandel & Lettinga [29] determined that the value of the Coefficient of Total Suspended Solids Production in UASB reactors (Yobs) may vary between 0.1 and 0.2. In this study, the value of 0.2 was used. The higher limit was selected because, the more sludge generated, the lower the methane production would be the worst-case scenario for a sewage plant.

Chernicharo also states that the methane flow can be calculated once the correction factor of the reactor temperature is known, as shown in Eq. (4).

$$\:{K}_{\left(T\right)}=\frac{P\times\:K}{R\times\:\left(273+T\right)}$$

Where:

K_(T) - Correction Factor to the operational temperature in the reactor (gCOD_CH4/l).

P - Atmospheric pressure (atm).

K - COD corresponding to 1 mol of CH₄ (64gCOD/mol).

R - Gas constant (0.08206 atm.l/mol.K).

T - Operational temperature in the reactor (25ºC).

The methane flow produced in m³/d is the ratio of organic load converted to COD_CH4 by the correction factor to an operational temperature K_(T), as shown in Eq. (5).

$$\:{Q}_{CH4}=\frac{{COD}_{CH4}}{{K}_{\left(T\right)}}\:\:\:\:$$

The biogas from domestic sewage has a typical concentration of 60 to 80% methane depending on the organic load [6][10], considering the mean methane concentration experimentally determined in Brazilian STP using UASB reactors is higher than 70% [6]. We will consider the worst-case scenario, which would be a biogas production with 60% CH4 in its composition. Another estimate refers to the losses of methane to the theoretical production, which are around 20–50% [30]. In this case, full-scale sewage plant measurements in Brazil were considered, where losses were estimated between 36–40% of the produced methane, which leaves the reactor dissolved in the effluent. Other losses considered in the order of 5% can also occur through the surface of the settler compartment and leaks in the system. For these reasons, the total loss value assumed was 40% of the methane flow produced [27]. Thus, the worst operating conditions of the plant were considered.

The actual mass flow of biogas produced can then be determined as follows:

$$\:{Q}_{biogas}=\frac{{Q}_{CH4}}{{\%CH}_{4}}$$

Potential of energy generation in STP

The annual electricity produced from biogas can be estimated by Eq. (8)

$$\:{P}_{generation\:EE}=\frac{({Q}_{biogas}\times\:365)}{1000}\times\:\frac{LHV\times\:{\eta\:}_{engine}\times\:{\eta\:}_{generator}\times\:{C}_{s}}{{C}_{kw}}$$

In which:

P_{generation EE} – Potential of electricity generation (MWh/yr).

LHV – Lower Heating value of biogas with 60% of Methane from reference [8] assume as 5500 kcal/Nm³.

ƞ_engine– Engine efficiency (%).

ƞ_gerador – Generator efficiency (%).

C_s – Coefficient that adjusts the plant operation throughout the year (considering an operation of 8000 hours during a year, which corresponds to an availability factor of more than 90% [31]).

C_kw – Factor of conversion kcal to kWh (860.42kcal/kWh).

According to Perez et al. [32] and [33], the thermal efficiency of biogas engines varies between 30 and 40%. The electric generator's efficiency ranges between 90 and 97%; to be on the safe side and consider the worst case, the lowest values will be used for both cases.

Economic Viability

The economic viability will be assessed by an extensive analysis of all costs involved in implementing the plant and the annual revenue. Economic decision-making indicators, such as payback and net present value, will be determined. Any investment project has an initial period of expenses followed by a net revenue period. Payback is the period in which all expenses are covered by revenues. This period can be considered with or without an updated cash flow.

In the NPV model, the aim is to find the value of the investment by discounting the cash flow at a rate that reflects the associated risk. The Internal Rate of Return (IRR) is initially calculated to verify the investment profitability. This rate shows the equivalence between the incoming and outgoing cash flows when the NPV is zero. Compared to the Minimum Attractive Rate of Return (MARR), this rate must be higher for the investment to be advantageous, underscoring the importance of the MARR as a profitability threshold. The MARR indicates a project's minimum value for profitability for it to be a viable implementation. These indicators are used as decision-making criteria for financial investment in cogeneration plants [34].

2.4.1 Cost with implementation of the energy generation unit

One will evaluate the cost of implementing the unit that meets the project's demands and the size of the STP already in operation at Praia da Chácara with an influent mean flow of 25 l/s, as well as the hypothetical situation in a future expansion of the plant that would be able to meet the needs of the entire population of Angra dos Reis city.

Our experimental tests at the STP in Barueri/SP, comparing the performance of a microturbine system unit and an internal combustion engine unit (Otto cycle) working in parallel to burn the biogas produced at the plant, yielded significant findings. The results clearly demonstrated the superior cost/benefit of the genset system over the microturbine. This was primarily due to its low investment and operating costs in relation to the installed power and the energy produced, when compared to other commonly used technologies such as gas turbines and micro turbines [35].

It's important to note that for the biogas generated in the STP to be used in a gas engine, it must undergo a rigorous purification process. This process is crucial for removing the main impurities such as moisture, siloxanes, sulfur, halogenated compounds and other contaminants [10], particularly CO2 and H2S, which can significantly impact the combustion process and increase heat losses in the engine [36]. The efficiency of this purification process is heavily dependent on the technological alternative used [27]. Therefore, the following economic feasibility assessment will be based on a unit that operates 24 hours a day, consisting of a basic system with a dehumidifier, purifier with Fe2O3 bed and cooling tank, gasometer and generator set (internal combustion engine + electrical generator).

All components have their respective functions in the process aiming to improve biogas conditions. The generator group, or internal combustion engine, will be chosen according to the estimated biogas flow produced in the STP. The cost of purchasing the equipment used in the current plant (first scenario) was estimated through direct price surveys with international equipment suppliers. For the second scenario, the total capital investment in each subsystem was calculated using the factorial estimation method reported by Aguilera et al. [31] (Table 1). In this method, the costs of the main components of the plant for a known size are obtained as a reference and an appropriate scaling factor is applied to calculate the cost for a desired equipment size using the following equation:

$$\:C={C}_{r}\:{\left(\frac{S}{{S}_{r}}\right)}^{m}$$

Where:

Equipment cost with a certain capacity of interest S;

$\:{C}_{r}$ : Equipment cost for the reference capacity $\:{S}_{r}$;

m: Incidence factor for economy scale (assumed to be equal to 0.6 [31]).

The purchase costs obtained from suppliers show a certain lag with respect to current values, so the Chemical Engineering Plant Cost Index (CEPCI) was used. This index accounts for inflation and changes in equipment costs over the years and is used to update all data to the current year.

$$\:{C}_{2023}={C}_{year\:ref}\:\bullet\:\:\frac{{CEPCI}_{2023}}{{CEPCI}_{year\:ref}}\:\:\:$$

The CEPCI values used for 2019 were 607.5, and the average value of 797.9 from the current year's CEPCI for 2023 was used.

Besides investment equipment costs, operation and maintenance costs must also be estimated. According to Souza et al. (2004), the cost of the operation and maintenance is present annually, about 2–4% of the total investment of the unit. The estimated cost of operation and maintenance is calculated in Eq. (11).

$$\:{C}_{o\&m}=\left({{C}_{d}+C}_{p}+{C}_{gas}+{C}_{gg}+\alpha\:\right)\times\:0.04\:\:$$

In which:

C_o&m – Cost with operation and maintenance (R$/yr).

C_d – Cost of investment with dehumidifier (R$).

C_p – Cost of investment with purifier (R$).

C_gas – Cost of investment with gasometer (R$).

C_gg – Cost of investment with generator group (R$).

α – Diverse cost with flowmeters, pipelines, valves and connections, peripherical and structure (estimated from data gave by Hengeveld et al [37] and Basrawi et al. [14].

It is important to consider the equipment's depreciation. The annual depreciation of the equipment is assumed to be linear for a 10-year period and was calculated by considering an average plant lifespan of 20 years, according to the estimates of lifespan for STP reported by [31] and [33], varying between 15–30 years.

$$\:W=\:\frac{100\%\times\:C}{{U}_{l}}$$

In which:

W - Depreciation of equipment (R$).

C - Total cost of equipment (R$).

U_l - Useful life (years).

The results of the investments will be evaluated according to the distribution of electricity produced in the network and the gain through the generation of credit with the local energy distributor. This work did not evaluate bureaucratic terms such as environmental licensing, risk analysis, and the resistance of the existing market to the acceptance of sustainable projects. Therefore, a more thorough and complete analysis may be a topic addressed in another study.

The BDI (Benefits and Indirect Expenses) is the element of a budget whose purpose is to measure the portions of the price of the civil work that indirectly affect the execution of the object. The BDI is made up of: central administration costs; financial costs of the civil work; systematic (non-diversifiable) risk costs applied to the project; municipal, state and federal taxes; insurance and guarantees; and profit margin. Added to the direct cost of a civil work or service, the BDI defines the total cost of the project. In this study, a BDI of 24% was adopted for civil works and services and 14% for equipment, in strict accordance with Ruling 2622/2013 of the Federal Court of Auditors.

Table 1

General investment costs of the energy generation unit in R$^*.
Equipment/Operation	Actual Plant (9,69 m³/h)	Future expansion Plant (70,67 m³/h)
Purifier	10,042.5	52,762.43
Gasometer	2,811.9	45,925.32
Engine generator	46,350.5	274,018.29
Flow meter	5,910.37	32,785.05
Diverse	37,693.28	119,280.92
Civil work	28,035.3	92,295.08
Equipment depreciation	6,393.31	30,853.35
Operation and maintenance	5,278.65	24,682.68
Total	142,663.85	672,603.13

*An average dollar exchange of 5.13 R$ for the year 2023, defined by the central bank, was used to convert the values.

The company Shandong Tiger Machinery Technology Co., Ltd provides equipment quotations for actual plants, including 25kW biogas genset with a configuration of 3 phase, 60Hz, 127V/220V, PF = 0.8, with 30kW gas engine (with gas engine control system), 25kW alternator, base frame & shock absorbers, with control cabinet, free maintenance battery, wood case packing, heat recover system, silent canopy and an auto-parallel for gas genset. The gasometer with a double membrane that works at low pressure was selected with a storage capacity of at least 2 hours of production. The purifier has filters with molecular sieves to remove CO2 and a column with iron oxide to remove sulfide. It consists of 4 tanks supplied by the Chinese company Holly Enterprise ElecMech Equip. Co., ltd. The KFG-1009 vortex flow meter with CVT-TEM remote flow indicator was selected.

2.4.2 Cost of electricity generation

According to the methodology of Silveira et al. (2012), the cost is calculated by Eq. 10. In this method, the cost is estimated by the ratio between the initial investment of the project and the potential of electricity generation amortized according to a rate of interest added to the cost of operation and maintenance.

$$\:{C}_{el}=\frac{\left({Inv}_{plant}\right)\times\:f+{C}_{o\&m}}{{P}_{generation\:EE}\times\:1000}$$

In which the annuity factor is defined by:

$$\:f=\frac{{q}^{k}\times\:(q-1)}{{q}^{k}-1}\:\:$$

with: $\:q=1+\frac{i}{100}$ (15)

In which:

C_el – Cost with electricity production (R$/kWh).

Inv_plant – Total investment with the unit ( $\:{{C}_{d}+C}_{p}+{C}_{gas}+{C}_{gg}+\alpha\:$ in R$).

P_generationEE – Potential of electricity generation (MWh/yr).

f – Annuity factor (1/year).

C_o&m – Cost with operation and maintenance (R$/kWh).

k – service life of the system (20 years) or payback.

i – Interest rate (8%, 12% and 15%).

2.4.3 Revenue from electricity added to the distribution network

Through the Compensation System mechanism from ANEEL Normative Resolution No. 1,059 [11], consumers can inject the energy generated in their consumer unit directly into the distribution network and receive a return in the form of energy credits, i.e. at the end of the month, the amount injected into the network is deducted from the amount consumed. To calculate the revenue generated by the generation of electricity, a tariff weight average is used (Eq. 16), composed by the tariff of electric energy (TE) and tariff for use of the distribution system (TUSD), value determined by ANEEL, in R$/MWh, used for the monthly billing of consumers and other users of the monthly billing of the electricity distribution system by the use of the system, considering the value of the peak hours and off-peak hours tariffs. Peak hours are between 6 pm and 8:59 pm, not applicable on Saturdays, Sundays and public holidays. During daylight saving time, peak hours are between 7:00 and 9:59 pm.

$$\:{T}_{end}=\frac{\left[\left({TE}_{p}+{TUSD}_{p}\right)\times\:{H}_{p}\right]+\left[\right({TE}_{op}+{TUSD}_{op})\times\:{H}_{op}]}{24}$$

The electricity generated by hydroelectric plants represents the largest share of Brazil's electricity matrix [38]. During months with little rainfall, energy production from this source is reduced due to low water flow. Under these meteorological conditions, more expensive energy sources, such as thermal power stations, come into play. The cost to energy distributors increases with the need to use more expensive sources. In 2015, ANEEL implemented a tariff flag system that reflects an increase in electricity tariffs for residential consumers due to unfavourable hydrological conditions. This feature is unique and relevant in the context of tariffs, focusing on seasonal fluctuations in water availability. The system comprises three tariff flags: green, yellow, red level 1 and red level 2. The green flag corresponds to the scenario of tranquillity for the consumer, as it represents favourable hydrological conditions, and the final tariff is not increased. The yellow flag is already a warning sign for less favourable generational conditions. Following the warning logic, the red flag - level 1 corresponds to more costly generation conditions. Finally, the red flag - level 2 represents the worst hydro scenario [39]. The additional cost of the electricity tariff due to the flag colour is defined annually by ANEEL.

In the case of STP, considering it a mini generation plant, included in the Electricity Compensation System (SCEE), ANEEL consumers group them into group B: a group made up of consumer units with a voltage connection of less than 2.3 kV and subdivided into subgroup B3. The tariffs for this group are listed in Table 2 [40]. In addition to the final tariff value, the Federal, State and Municipal Governments add tax PIS/COFINS, ICMS and the Contribution for Public Lighting, which are not included as they change from state to state. However, this final value serves as a benchmark for everyone.

Table 2

composition of the final electricity tariff (R$/MWh)
	peak hours tariff		off-peak hours Tariffs
Distributor	TUSD	TE	TUSD	TE	Final Tarrif
ENEL-RJ	1,494.72	62.57	469.10	62.57	659.87

Them the revenue is given by Eq. 17.

$$\:Revenue=\:{P}_{generation\:EE}\times\:{(R}_{final}-{C}_{el})\times\:1000\:$$

2.4.4 Payback

Payback is the most common method in the analysis of investments. It consists of quantifying the period required to cover the initial investment by means of cash flow. This method analyzes the moment at which the net profit accumulated is equal to the initial investment. The period can be found by the analysis of cash flow as well as the ratio between investment cost and expected profit [41]. Three variations of interest rate are used in Payback, amortized throughout the unit period, of 15%, 12% and 8%.

2.4.5 Net present value

The Net Present Value, NPV, is used to assess the profitability of an investment. The calculation is done by Eq. (18), decreasing the cash flow of the project that is being evaluated to a determined interest rate from the investor. This rate, called the discount rate, is the minimum return that must be expected for the project to be accepted. The project is viable if the discount rate is higher or equal to zero [41]. One of the advantages of the process is the inclusion of the capital cost of the company and the possibility of applying it to any cash flow. However, it is usually a complex method because it requires several parameters to be calculated. The adopted minimum rate of attractiveness will be 15%. This figure was devised considering the average of the most profitable yield, plus inflation and an investment risk rate related to market uncertainties stipulated at 2.25%.

$$\:NPV=\:-{C}_{0}+\sum\:_{i=1}^{n}\frac{{C}_{i}}{{(1+r)}^{n}}$$

In which:

C₀ – Initial cost.

C_i – Cash flow year by year.

i – years.

n – total time of the project.

r – risk rate to be discounted.

The final value of NPV must be positive for profit. If it is zero, there is no profit or loss; the investor will not have guarantees with such an investment.

The potential of biogas production and electricity generation at the current plant in operation is significant. Considering the design flow of 25 l/s and the volume of sewage at 2.160 m3/d, we can estimate the theoretical production of methane. This corresponds to the maximum number of inhabitants served by the plant, who contribute an average flow of domestic sewage of 116 l/inhab.day. In the second scenario, a future expansion of the station is expected to serve the entire population of the municipality of Angra dos Reis with access to the sewage network. The volume of affluent determined was 13,207.2 m3/d, representing the real potential of the region if all the domestic sewage generated was appropriately treated.

Considering the average effluent flow rate and a COD concentration of 0.6 kg/m3 with a hydraulic retention time of 8 hours, a COD removal efficiency of 0.67 was determined, which is within the expected range for this type of technology using UASB reactors [27]. Based on the abovementioned methodology, the effluent or removed COD concentration was 0.198 kgCOD/m3. Considering a total solids production coefficient of 0.2, the theoretical flow rate of biogas produced was 387.48 m3/d for scenario 1 and 2826.72 m3/d for scenario 2, considering a biogas composition of 60% CH4. A considerable part of the CH4 produced is expected to be lost in the hydraulic structures at the reactor outlet, dissolved in the effluent or emitted into the atmosphere. Considering these losses of around 40% of the theoretical biogas flow rate [27], we can estimate an actual production of 232.49 m3/d (9.69m3/h) and 1,696.03 m3/d (70.67m3/h) of biogas respectively for both scenarios.

From Eq. (8), applying the appropriate considerations (motor efficiency of 30% and generator efficiency of 90%), the energy potential of biogas generated for electricity production was 125.22 MWh/yr for the current STP. When the capacity of the entire region is considered, i.e. sewage production per total number of inhabitants, the energy potential would be 913.48 MWh/yr.

The electricity produced using the biogas generated in the UASB reactors represents a significant opportunity for reducing greenhouse gas emissions. This distributed mini generation promotes the sustainability and viability of the STP, contributing to reducing greenhouse gas emissions and consequently global warming and climate change. The determined electricity production capacity of 125.22 MWh/yr, burning the biogas generated in internal combustion engines, is adequate for the size of the current STP. It is worth noting that this study does not consider the thermal energy contained in the engine's exhaust gases, which could be reused in the sludge dewatering process, nor the sludge's own potential to generate CH4 during pre-treatment, which would further favour the implementation of this technology.

Considering a typical STP composed of UASB + BFMO + DS that demands approximately 0.34 kWh/m3 of treated sewage effluent [13], it is possible to determine an annual electricity demand for the Scenario 1 plant of approximately 264.4 MWh/yr, so the current proposal would be able to meet 47.4% of the plant's needs. When scenario two is analysed, this percentage rises to 56.5%, a figure like that reported by Rosa et al. in a plant using the same technology and capacity [6].

Figure 3 shows the cost of electricity generation. The cash flow is amortized throughout its useful life by the annuity factor obtained by the interest of 15%, 12%, and 8%, as shown in Fig. 1.

The cost of electricity production decreases with time for different amortized rates (15%, 12% and 8%) for both scenarios. This trend underscores the cost-effectiveness of using biogas for electricity production. Considering the final electricity tariff made up of the tariffs charged at peak and off-peak times for generating units incorporated into ANEEL's electricity compensation system, we can see that in approximately two years, the cost of generating electricity from the plant considered scenario 1 is equal to the energy utility's sales tariff. From the second year onwards, the cost of generation falls below the value of the sales tariff, with a minimum value from the tenth year of the plant's useful life of 0.12 R$/kWh and 0.09 R$/kWh for the interest rates of 15% and 8% respectively. These values when converted into US currency, considering that one dollar is equivalent to 5.13 reais (average value in direct conversion in the year 2023) reach the values of 0.023 US$/kWh and 0.017 US$/kWh, which represents half the value of the cost of the electricity produced reported in the study by Arslan and Yılmaz [42] in a CHP trigeneration plant with a gas turbine (power, cooling, and heating) that uses biogas as fuel. When we look at the cost of producing electricity at the current plant, we can see that it varies from 0.41 R$/kWh from the third year onwards until it stabilizes around the tenth year of operation, with a value of 0.16 R$/kWh for the minimum interest rate used, which represents around 0.079 US$/kWh and 0.031 US$/kWh in direct conversion to dollars. These results corroborate the fact that internal combustion engine technology for the reuse of biogas produced in STP is one of the most economical due to the relatively low initial investment, maintenance and operating costs when compared to systems that use gas turbines or hybrid systems [17], which favours its attractiveness in specific scenarios. For scenario 2, considering an expansion of STP's current capacity, the cost of electricity decreases when compared to the current plant, showing that the scale factor has a positive impact on reducing generation costs. In approximately one year, the electricity produced would reach a cost equal to the current tariff charged by the utility, depending on the interest rate used. In general, the electricity generation costs obtained in this work are lower than those reported by other thermoelectric generation technologies such as Rankine cycles, which are 250–300 R$/MWh [43].

The Payback is shown in Fig. 4 and was obtained from an analysis of cash flow year by year in terms of revenue obtained from using biogas to produce electricity. The revenue consists of the difference between the local energy tariff; this is calculated from the weighted electricity tariff applied by the concessionary and the cost of electricity production throughout the unit's useful life (20 years).

The evaluation of the annual revenue from the electricity produced by the 9.69 m³/h unit revealed a return on investment (Payback) of two years. As for the unit with a biogas production capacity of 70.67 m3/h, the return on investment was one year and one month of operation. This quick return on investment underscores the profitability of the project. The payback analysis shows that using biogas to produce electricity is a profitable option with a quick return. As this biogas is a by-product that would usually be burned in a flare, using it more efficiently gives it a more noble destination, turning it into a low-cost fuel that is used in the motor-generator set.

Another factor that affects the payback time is the initial investment in the equipment. All the equipment in the lower capacity unit is imported, and even with the high import and freight taxes, the price is highly competitive against domestic equipment. This fact may be due to the lack of investment in this area, which explains the lack of competitive technologies with more attractive prices at a national level.

When comparing the payback results obtained with other studies, such as the one reported by Buller et al. [13], which simulates different scenarios in an STP using the software HOMER, we can conclude that they are consistent since the payback time for a plant considered to be medium-sized with a hybrid off-grid system that uses solar panels and an internal combustion engine to supply the plant's internal demand (scenario 4) was 3.35 years. When considering the same hybrid system configuration, this time interconnected to the electricity grid (scenario 6), the Payback determined was 1.38 years. The differences can be explained by the type of configuration used in each case and the values considered for the economic calculation, such as the value of the annual interest rate and the number of years of the plant's useful life. Comparing the payback period to other technologies, such as fuel cells SOFC or MGT, we can see the advantage of using ICE because the technology presents the lowest investment and operation cost concerning the installed power and the energy produced [17].

The calculation of NPV is a comprehensive process that considers the minimum rate of attractiveness higher than the percentage of the most profitable investment return that includes inflation, and a percentage related to market uncertainties. This thorough approach ensures that all potential factors are considered. Considering the Selic rate, which represents the introductory interest rate of the Brazilian economy, is currently at 10.5%, an investment that remunerates 115% of IDC (Interbank Deposit Certificate), considering an ID equals Selic) generates an annual return of 7.47%. As inflation is at 4.62% and adding a risk rate due to uncertainties in the Market of 2.25%, there is a value minimum rate of attractiveness of 15%. The values of cash flow, applied to different interest rates (15%, 12% and 8%), refer to a projection throughout the years of operation of the units and are shown in Fig. 5.

The criterion when the NPV is used to make decisions such as "accept" or "reject" the project is as follows: if the NPV is greater than or equal to zero, the project should be accepted, as the company will obtain a return equal to or greater than the cost of capital invested and the project will preserve or increase its assets; otherwise, if the NPV is less than zero, the project should be rejected. For the two proposals evaluated, the NPV is positive over a given period, indicating the viability and attractiveness of the investment. Considering the useful life of the plant, the NPV indicates that the investment is not only viable but also very attractive, observing the moment when the IRR (rate of return on investment) exceeds the MARR (minimum attractive rate), i.e. NPV equal to zero.

Figure 5 shows that the plant in scenario one does not offer high NPV values. However, it is still a viable investment for the three proposed interest rates. The best option is to use an interest rate of 8%, which would give an NPV of R$47.687,49, considering a project lifetime of 20 years. For the proposed plant in scenario 2, the NPV reaches R$1.204.129,90.

The sensitivity analysis shows that the inclusion of the use of internal combustion engines for the reuse of biogas generated in small STPs of up to 10,000 inhabitants for electricity generation becomes economically viable with relatively short payback periods when the price of electricity is at least 600 R$/MWh, below this value the projects become unviable. For medium-sized and large STPs above 100,000 inhabitants, this figure can reach 520 R$/MWh; considering interest rates of 8%, 12% and 15%, the investment remains attractive and economically feasible.

Another interesting aspect that has yet to be studied in this work, but which would help to improve and reduce the return on investment would be the revenue generated in the carbon credit market due to the reduction in greenhouse gas emissions from using biogas generated in STPs. The market still needs to be regulated in Brazil, but this has already been applied in the EU and other parts of the world. Studies show a more than 50% reduction in the payback period when considering the tax received for the CO2 that is no longer emitted [12].

The preliminary techno-economic assessment carried out in this work, taking as a reference an actual small-scale plant in operation and extrapolating the results to a larger capacity plant, shows that the introduction of technologies for the energy use of biogas produced by anaerobic digestion in UASB reactors is feasible, implemented specifically using internal combustion engines to produce electricity mainly due to their low initial investment and operating costs when compared to other technologies. The specific cost of electricity produced with the reuse of biogas showed competitive values in the range of 0.023–0.079 US$/kWh depending on STP's processing capacity with an annual interest rate of 8%, with a payback period between 1–2 years. Finally, it is possible to conclude that implementing this technology would make it possible to supply between 46–57% of the plant's internal electricity demand, contributing to minimizing greenhouse gas emissions and reducing the cost of paying the electricity tariff to the energy concessionaire.

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Harnessing Biogas from STPs for Sustainable Energy: A Techno-Economic Study

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Abstract

Figures

Introduction

Methodology

2.4.1 Cost with implementation of the energy generation unit

2.4.2 Cost of electricity generation

2.4.3 Revenue from electricity added to the distribution network

2.4.4 Payback

2.4.5 Net present value

Results and Discussion

Conclusions

References

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