Feasibility Study of an Off-Grid Biomethane Mobile Solution for Agri-Waste

Applied Energy 239 (2019) 471–481

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Applied Energy

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Feasibility study of an oﬀ-grid biomethane mobile solution for agri-waste T ⁎ Laura Gil-Carreraa, , James D. Brownea, Ian Kilgallona, Jerry D. Murphyb,c a Gas Networks Ireland, Gasworks Road, Cork, Ireland b MaREI Centre, Environmental Research Institute, University College Cork, Ireland c School of Engineering, University College Cork, Ireland

HIGHLIGHTS GRAPHICAL ABSTRACT

• Mobile upgrading of biogas from a number of small digesters was assessed. − • Upgrading costs €0.62 Nm 3 biomethane for a mobile upgrading − system (250 Nm 3). • The cost slightly increases with increasing number and decreasing size of digesters. • Mobile upgrading was assessed as − €0.18 Nm 3 biomethane cheaper than onsite upgrading. − • A minimum revenue of €1.10 Nm 3 biomethane is required for ﬁnancial sustainability.

ARTICLE INFO ABSTRACT

Keywords: Research shows that gas grid injection of upgraded biogas is very advantageous in maximizing energy recovery. Biomethane However, the majority of farms are more than 10 km away from the gas network in Ireland, therefore trans- Off-grid porting biomethane by road to suitable injections points on the gas network would maximize the mobilization of Mobile solution potential biomethane resources. This represents both a challenge and an opportunity in getting to market. A Storage model was developed to describe an off-grid biomethane virtual pipeline solution (cleaning, upgrading and Natural gas storage mobile units) for small-scale farm biogas plants located at more than 10 km from the gas grid system. The cost for 1 Nm3 of biomethane, transported and injected into the gas grid was calculated between €0.62 and €0.80. The model evaluates different scenarios, which differ in the number and size of biogas plants. Comparisons are made to a traditional upgrading model. The model showed that the off-grid biomethane mobile (virtual pipeline) solution costs are €0.18/Nm3 lower than in a configuration of onsite upgrading plants at a biogas production rate of 150 m3/hour. This solution was found to be critical to the development of the wider biomethane industry in countries where direct access to the gas grid is limited by remote location and/or grid injection capacities in some parts of the network capacity.

⁎ Corresponding author. E-mail address: [email protected] (L. Gil-Carrera). https://doi.org/10.1016/j.apenergy.2019.01.141 Received 19 May 2018; Received in revised form 18 November 2018; Accepted 19 January 2019 0306-2619/ © 2019 Elsevier Ltd. All rights reserved. L. Gil-Carrera et al. Applied Energy 239 (2019) 471–481

1. Introduction 1.2. Focus of paper

1.1. Rationale for agri-waste utilization The aim of this paper is to examine biogas production of small scale farm sites located at a remote from the gas grid system in Ireland and In Ireland, 53% of natural gas demand is met by UK imports with the feasibility of an off-grid biomethane mobile solution (cleaning, the remaining gas supplied by means of indigenous gas with field re- upgrading, storage and virtual pipeline) that runs between biogas serves and storage [1]. The UK have commissioned over 80 Biomethane plants and delivers the biomethane to a centralized grid injection fa- Network Entry Facilities in the last three years which allows 3.5 TWh of cility. biomethane on the system [2], this was possible due to the Renewable There is very little literature on biomethane mobile solutions where Heat Incentive (RHI). Ireland could significantly reduce the dependency a small-scale upgrading plant and storage are integrated in one mobile on imports if a similar biomethane system/incentive would be estab- unit, providing a transportable upgrading and virtual pipeline model. lished. In addition to the dependency on imports, the Renewable En- Research has been done to analyse the viability of decentralised biogas ergy Directive (2009/28/EC) published in 2009, established European production with a centralized upgrading and injection into natural gas mandatory targets, which requires 20% of all energy to come from grid model; this showed the financial benefit for small-scale biogas on renewable energy sources including a 10% share of biofuels in the farm producers [15]. This study evaluated a centralized upgrading transport sector by 2020. Ireland's target is 16% of gross final con- model through local pipelines from biogas plants with production of − sumption to come from renewables by 2020 [3]. This target should be over 250 Nm3 h 1, however the majority of the small scale biogas farm made up of contributions of 40% renewable energy in electricity (RES- plants in Ireland will have a potential biogas production below − E), 10% renewable energy in transport (RES-T) and 12% renewable 100 Nm3 h 1 [14]. From literature, it is evident that for biogas flow − energy for heat and cooling (RES-H) [4]. Up to date only 27.2% (RES- rates below 250 Nm3 h 1 the unit cost of upgrading increases drama- E), 6.8% (RES-H) and 5.0% (RES-T) have been achieved [5]. Since the tically making small scale biogas upgrading commercially challenging. publication of the 2008 EU Climate and Energy Package 20-20-20, EU The main reason for the high cost for small scale biogas upgrading is a legislation mandates Ireland to reduce by 20% its Green House Gases lack of upgrading technologies designed for smaller biogas flow rates. (GHG) emissions relative to 2005 by 2020 [6]. Ireland's total GHG Historically gas purification technology focused on large scale natural emissions per capita are among the highest in the EU, and almost a gas purification, moreover with increasing renewable energy demand third (32%) come from agriculture [7], fwith ca. 9% from manure for renewable energy supported by government subsidy schemes in storage [8]. Furthermore, the Nitrates Directive (91/676/EEC) aims to many EU countries, manufacturers have focused on developing biogas reduce the amount of nitrogen from farm waste entering Irish waters upgrading technologies for biogas flow rates ranging from 500 to − [5–6]. Due to the dominance of livestock farming in Ireland and high 2000 Nm3 h 1 [16]. AD plant capital and operational cost vary sig- annual rainfall, the country has been designated as a nitrogen vulner- nificantly depending on plant capacity, type (e.g. dry, batch, con- able zone (NVZ) which requires that organic sources of nitrogen, such tinuous) and specification, but smaller plants can still be built and as manure and slurries, must be stored from 16 to 22 weeks during operated relatively cheaply, as is demonstrated by the large number of winter months depending on the region within the country [9]. small-scale plants in China and India [17]. However, the Swedish Gas Processing agricultural waste such as manure and slurry in an Centre [18] highlighted that total biogas cleaning costs for upgrading anaerobic digester is a sustainable method of treating animal manure are considerably higher for smaller plants, especially for plants treating − and is one of the few commercially available technologies that can less than 100 Nm3 h 1 of raw biogas. Therefore, there is a necessity to reduce the GHG emissions from agriculture. investigate models to allow those small scale AD plants to access the Biomethane from wet and dry manure could be GHG negative on a biomethane market. This is critical to the development of the wider whole life cycle analysis (LCA) basis achieving up to 140% GHG saving green gas industry in countries where small-scale biogas producers are due to the additional carbon saved from avoided methane emissions predominant and the physical or economic conditions deem the in- from manure storage [10]. stallation of a real pipeline unfeasible. Hakawati et al. [11] performed an intensive study on the most en- The model proposed in this paper facilitates the integration of ergy efficient route for biogas and it was found that biomethane uses biomethane as a route to meeting renewable energy targets and off- competes well with biogas and is more easily transported and used in a setting reliance on imported oil and gas, as well as offering a solution wide variety of applications. There is a perspective that bioenergy is that can be used to provide a sustainable and cost effective route to better employed in systems, which are difficult to decarbonise. In an market for small scale biogas producers to the gas grid. Irish context industrial heat (such as in breweries, distilleries and The objectives of this paper are to establish: creamery plants) is difficult to decarbonise. On an international basis transport fuel is difficult to decarbonise. Green gas is a decarbonised • What is the cost of upgrading, storing, transporting and injecting substitute for all natural gas applications, in particular in this work for into the gas grid with the mobile solution expressed per Nm3 of transport and heat. biomethane? It was estimated that biomethane production from agricultural • What is the effect of the size and scale of biogas plants on the overall slurry could achieve 15.53 PJ by 2020, which represents 6.4% of the cost and technical feasibility of the mobile solution? estimated natural gas demand in 2017 [12]. Furthermore, the farming • Can a mobile solution (upgrading, storage and transport) on a re- sector is still crucial to Ireland’s economy and the most important in- mote site coupled with a centralized biomethane injection facility be digenous sector. O’Shea et al. estimates that total annual cattle slurry feasible? production in Ireland is approximately 28.9 Mtwwt, which represents • What is the potential of the mobile solution and virtual biomethane 91% of the total theoretical biomethane resources [13]. pipeline model? These studies show a good opportunity for the biomethane market, however the majority of farms in Ireland are located remotely in the 2. Methodology country and further than 10 km from the gas grid [4] and have an average of 57–106 cows [13,14], and as such are significantly affected 2.1. Concepts of analysis by the economy of scale, and thus represents both a challenge and an opportunity in getting to market/grid. The concept of analysis will focus on the feasibility of an off-grid biomethane mobile solution, which includes a mobile upgrading/ cleaning and storage unit coupled with gas injection into the gas grid.

472 L. Gil-Carrera et al. Applied Energy 239 (2019) 471–481

Fig. 1. Extension of gas grid in Ireland.

This concept is applied in farms with a small scale AD plant (less than therefore described in Section 2.2. − 50 Nm3 h 1) and exemplified in an Irish context. The Irish gas network In an effort to further assess the feasibility of such an off-grid bio- is indicated in Fig. 1. methane mobile solution, the results of the most cost-effective mobile A model was developed to calculate costs per m3 produced of bio- solution configuration were compared to a configuration with the same methane in a biogas system with several small-scale anaerobic diges- number of digesters, onsite upgrading, biomethane transport and in- ters, a mobile upgrading plant, mobile storage units and an injection jection into the gas grid. facility. This model calculates results from different configurations such as a variation on the number of digesters and storage/transport capa- 2.2. Assumptions city. The organization of the model is based on a previous study by 2.2.1. Biogas production Hengeveld et al. [15]. The off-grid biomethane system is described Cattle manure consists of cattle excreta and bedding material col- using three transformation blocks: raw biogas is stored in biogas storage lected during animal housing while cattle slurry is more dilute con- at each site, then in the mobile solution (virtual pipeline) biogas is sisting of scraped cattle excreta and some wash down water collected cleaned, upgraded and biomethane is stored, transported and injected from animal housing facilities. Cattle manure and slurries are readily into the gas network (Fig. 2). The main stream is from left to right from available in the agricultural sector and in 2011, over 56 million tonnes produced biogas to the injected biomethane. The dotted arrows are the 3 of cattle slurry were produced on Irish farms and 20,699,000 m of auxiliary streams which describe the cost items and are not used further dairy and cattle manure were stored on farms [9]. At present, the downward in the stream. The total of these auxiliary streams define the majority of this manure is spread on land. Common practice is that costs cost price and sustainability criteria per Nm3 biomethane injected into and environmental effects of storage are allocated to cattle farming and the gas grid. The model does not include manure handling, digester and not to biogas production [19]. digestate handling, as only the technical feasibility and cost of the off- Beef production is the most common farm type in Ireland ac- grid biomethane mobile solution and injection into the grid are the aim counting for 53% of farms [20], with 6,926,100 cattle from over of this study. However, for financial analysis the cost of biogas pro- 139,800 family farms in 2014 [14]. Hence the biogas plants considered duction was included in Section 3.3. This and other assumptions are in this study are farm based. In this paper an assumed cooperative biogas production of − 150 Nm3 h 1 is chosen; such biogas production is equivalent to about 250 kWe (assuming methane content of 56%, net calorific value of − 9.3 kWh m 3 and electrical efficiency of 30%). Below this threshold AD combined heat and power (CHP) receives a higher Feed-in-Tariff in the UK [21], Austria and Slovakia. − Therefore 150 Nm3 h 1 was considered for all configurations, but − specific site production was varied between 21 and 50 Nm3 h 1. This amount of biogas is based on intensive livestock regions in Ireland, ff − Fig. 2. An o -grid biomethane system based on small scale farm digesters. where 150 Nm3 h 1 would be available within a 15 km radius [22].

473 L. Gil-Carrera et al. Applied Energy 239 (2019) 471–481

Examples include the rural district of Bandon, Co. Cork where 928 volume utilization. However, high-pressure compression of raw biogas farms are spread in a land area of 35,458 ha; 20% of the slurry from for storage purposes is unadvisable as CO2 starts to condense at medium dairy cows here would be sufficient to satisfy such biogas production. pressures in raw biogas mixtures. The resulting two‐phase mixtures are An average cattle farm in Ireland has approximately 57–70 cows very disadvantageous for any storage concepts. Low pressure storage with up to 106 cows in southern parts of the country [13,14,22,23]; tanks are more economical and very common even at small scale AD − these farms could produce on average over 21 m3 of biogas h 1 when plants. Nevertheless, the biogas storage volumes necessary to support a combining with 1000 tonnes of food waste per year. The annually mobile and discontinuous upgrading plant will be significant in scale production of slurry per head of beef cattle was based on previous (1000–2500 Nm3 – Table 1). Biogas production at each site varies be- − studies [9] which assumes that animals are housed indoors for at least tween 21 and 50 Nm3 h 1 while the mobile upgrading plant capacity is − 20 weeks per year. Wall et al. reported an average of 16 m3 per tonne of up to 250 Nm3 h 1. Therefore, the optimum size of this storage tank is dairy cow slurry in Ireland [24]. O'Shea et al. [13] found that the lar- calculated depending on the number of digesters and the planned fre- gest theoretical biomethane resource arising from cattle slurry in Ire- quency of upgrading plant deployment to optimize the use of resources land can be found in the southern (45% of resource) regions of Ireland. and maximize the capacity of the biomethane storage. Considering Besides the natural gas network in Ireland is considerably more spread these factors, it was assumed a biogas storage capacity of 50 h at each in the southern parts of the country (Fig. 1). Hence this region of the site (total 7500 Nm3 raw biogas storage for each scenario as shown in country was selected to asset this study. Table 1). For simplicity the maximum time for biogas storage is con- Biogas from manure has a methane content of about 60–70% [21] stant for all AD plants, varying the volume of biogas storage at each site and from organic waste the methane content is about 61% [17], in each scenario. This is further explained in the logistics section. moreover a long term study of mono-digestion of dairy cattle slurry Several commercial references were reviewed and a cost of − show a methane content of about 56% [25]. In this study it was as- €35 Nm3 h 1 raw biogas storage is assumed (Table 2). Additional sumed that the CH4 concentration of biogas was 56% to be con- biogas storage is not required in scenario 3.OS since an onsite up- servative, although a higher content could slightly improve the business grading system applies. case of the small farm biogas plants [26]. 2.2.4. Biogas upgrading, biomethane storage & transport (mobile solution) 2.2.2. Biogas plants configuration and scenarios The AD farm based plants require raw biogas storage holders and a In the model calculation in our study, we consider four different mobile solution (biogas cleaning/upgrading and biomethane storage configurations varying the number of digesters from 3 to 7 for the unit) that rotates between those biogas plants (Fig. 3). Eventually, the mobile solution. It was assumed a cooperative biogas production of mobile solution delivers the biomethane to a centralized injection fa- − 150 Nm3 h 1 for all configurations and each site production is between cility where it is injected into the gas grid. − 21 and 50 Nm3 h 1. Previous studies have shown that the optimal distance for transportation of livestock slurries for digestion, upgrading Upgrading. A mobile gas upgrading module has been proposed as part and injection into the grid was between 10 and 20 km [27,28]. Hence a of the mobile solution to implement the concept of cooperative biogas conservative value of 15 km between the plants was used in this study. upgrading, storage and transport. The mobile biogas cleaning and This 15 km distance was maintained for all scenarios for simplicity and upgrading module is designed to be transported, inside a 20‘(20 foot) better comparison. container on a truck and shared amongst the involved AD plants whilst Three scenarios with a mobile solution (MS) and 3, 5 and 7 biogas operating a defined percentage of the day at each site, as explain in the plants and one scenario with 3 biogas plants with onsite solutions (OS- logistics section (below) and Table 1. upgrading plant at each site) were analyzed (Table 1). The last scenario A module A (upgrading system) is mounted in a 20′ container along (3.OS) was designed to allow comparison between a mobile model with a second module B consisting of another 20′ container for bio- (scenario 3.MS) and a scenario including the same number of digesters, methane storage. Module A consists of an upgrading plant with in- onsite upgrading plants and a centralized transport and injection to gas tegrated activated carbon, a compressor, dryer and electrical equip- grid. Table 1 summarizes the analyzed scenarios. The results from the ment. Pressure swing adsorption (PSA) technology has been proposed mobile solution are also compared in the discussion with this scenario − as the most suitable technology for the mobile solution, due to the with 3 biogas plants with a production of 50 m3 biogas h 1 each. following technical and economic reasons: (a) it is capable of being constructed on a stand‐alone mobile container implying low weight, 2.2.3. Biogas storage low complexity and compact construction; (b) it is amenable to fast

Anaerobic digesters continuously produce biogas. Since the mobile start-up and can operate intermittently; (c) it can eliminate H2S without upgrading plant is proposed to operate across a number of facilities it larger additional equipment [29] and is capable of coping with different operates discontinuously at each facility. This necessitates raw biogas raw biogas qualities at the different AD plants; (d) it is able to remove storage at each farm. Storage capacity depends on the pressure, the rate oxygen and nitrogen [29]; (e) it is resistant to the stresses and strains of of production and the biogas upgrading plant size. Storage tanks can transportation; (f) it has low energy consumption compared to other operate at low pressure or at elevated pressure for improved storage technologies and (g) is very cost‐effective [30].

Table 1 Characteristics of scenarios. Design of experiment.

Scenarios 3. MS 5. MS 7. MS 3. OS

Number of facilities 3 5 7 3 − Biogas production/plant (Nm3 h 1) 50 30 21.4 50 − Biomethane production/plant (Nm3 h 1) 28 16.8 12 28 Biogas storage/plant (Nm3) 2500 1500 1072 – Upgrading system Mobile upgrading-mobile PSA Mobile upgrading-mobile PSA Mobile upgrading-mobile PSA Onsite upgrading- PSA on site − Upgrading capacity (Nm3 h 1) 250 250 250 250 − Upgrading time/plant (h cycle 1) 10 6 4.3 Continuously − Biomethane storage /scenario (Nm3 cycle 1) 4200 4200 4200 2250 Cycle time/scenario (h) 42 46 50 3.3 days

474 L. Gil-Carrera et al. Applied Energy 239 (2019) 471–481

Table 2 Data for cost calculation.

Production Biogas production cost- slurry & food waste €0.22/Nm3 biomethane [26] Raw biogas holder/tank €35/Nm3 [51–53]

CH4 content 56% [21,25] Distance between AD facilities 15 km

Transport Truck €120,000 [54] Fuel eﬃciency 0.4 L /km [32–33] Biomethane storage Composite vessels €42.3 /m3 [55–56] Steel vessels €39/m3 [57] Compressor consumption 0.23 kWh/Nm3 [30]

Upgrading Pressure Swing Absorption capacity 250 Nm3/h PSA investment €0.42 / Nm3 biomethane [16,58] PSA Eﬃciency 95% (8322 h) [18,31] 3 PSA + H2Sequipment + Dryer + compressor consumption 0.25 kWh/Nm [12,58–59]

CH4 eﬃciency 98% [18,60] Overall cost (Capex + Opex −15 years) €0.12/kWh [31,58,61] 3 H2S equipment + dryer + compressor CAPEX €0.23/Nm biomethane [12,16,59,62] Connection Gas grid connection fee €342,000 [31] Electricity connection fee €75,000 [63] Revenue Biomethane sale €0.20/Nm3 RHI €ct7.5/kWh [44] BOC €60/MWh–€106/MWh [42] Feed in Tariﬀ €157/MWh [64]

General Depreciation & Discount rate 15 years & 8% [44–45] Consumer Price Index 2% Operating hours installations 8322 [31] Electricity price Band IB: €0.1806/MWh [65] Band IC: €0.1488/MWh Night rate: €0.0757/MWh Reference scale 150 Nm3/h [9,14,31] Labour €60,000/a [31,63,66] Insurance €98400/a [31]

Through communication with the industry community and with number of journeys. For gas reservoirs at 220–250 bar, the energy − cognizance of the size of Irish farms, the PSA capacity is assumed at requirement is of about 0.23 kWh Nm 3 [18]. The model included for − 250 Nm3 h 1 [31–33]. The major costs of PSA include for energy con- utilization of a 10′ container (2250 m3) as a biomethane buffer. This sumption, capital investment, operational cost, H2S removal, com- would serve in case of technical issues causing the storage unit to being pression and dryer equipment (gas conditioning) and inertization of the inoperative for a period of time and/or maintenance. upgrading unit after its utilization (Table 2). A number of studies In scenario 3.OS biomethane storage is required at each site prior to [12,21,25] have calculated the required energy demand for operating a transportation to the injection facility (virtual pipeline). It was assumed − PSA between 0.16 and 0.35 kWh Nm 3 biogas. Based on these refer- to transport biomethane in steel vessels at 250 bar, as the transportation ences and a review of the industry, PSA electricity consumption is as- volume is not limiting in this scenario and the cost of each set of vessels − sumed to be 0.25 kWh Nm 3. Capital and operational costs are shown (2250 m3) is lower than composite cylinders. in Table 2, all figures are based on quotations from small-scale PSA In Ireland, the fuel predominately used in captive fleets is diesel; plants manufactures and from literature [31]. In scenario 3.OS, the buses and LGVs are typically designed to operate on diesel. Thus, when selected onsite upgrading technology was PSA, to allow comparison estimating operational cost and comparing biomethane to fossil fuels, with the previous analysis. the calculations are made against diesel. − Transport consumption was assumed to be 0.4 L km 1, using previous studies [32,33]. Diesel consumption was calculated based on the Storage and transportation (virtual pipeline). Module B consists of distance of each cycle, the number of cycles, a weight of 25 tonnes HGV − composite vessels operating at 250 bar (at 15 °C) providing a total (Heavy Good Vehicle) and a speed of 35 km h 1. A tortuosity factor of capacity of 4200 m3 of biomethane for scenario 3.MS, 5.MS and 7.MS. 1.2 is used to account for the winding of primary and rural roads [4]. − The aggregate biomethane production in all scenarios is the same as The price of diesel used in our calculation is €1.27 L 1 [34]. well as the capacity of biomethane storage (max. 4200 m3) in the module B, only the variation in cycle length is different depending on the number of plants as explained in the Logistics section). Composite Logistics. Logistics are a key element of the whole mobile solution vessels have been chosen, as they are capable of storing higher amounts concept; a successful operation of the system requires a precise logistic of gas compared to standard steel vessels. High pressure storage has plan. Transport frequency, distances, time for upgrading, storing and high operation costs and high energy consumption; however, composite injection are parameters that should be optimized in order to achieve tanks are a cost-effective solution for storage and transportation in this maximum efficiency and a cost-effective model. particular case. Composite cylinders could save more time and allow Fig. 3 shows the logistics for the mobile solution where a mobile the truck and PSA to be constantly running, therefore reducing the upgrading plant and storage runs from one biogas plant to another,

475 L. Gil-Carrera et al. Applied Energy 239 (2019) 471–481

Fig. 3. Logistics of off-grid cooperative biomethane production applying mobile upgrading plant and storage tanks (mobile solution/virtual pipeline). collecting the biogas, upgrading it and eventually injecting into the gas In scenarios 7.MS, 5.MS and 3.MS the mobile solution is scheduled grid to complete a cycle. Each cycle is calculated based on: the number to run a cycle of 50, 46 and 42 h, respectively. The cycles vary in each of plants; the time of upgrading at each site, which varies with the scenario since the time that is required for installation and transpor- biogas storage volume at each site and the upgrading capacity; time to tation depends on the number of AD facilities and consequently on the travel from plant to plant and to injection point; time to set up and start raw biogas storage capacity at each site. up and time for injection into the grid. In scenario 3.OS a truck is scheduled to collect the biomethane tanks Each cycle has been calculated to optimize the amount of bio- every 3.3 days, that is the time required to fill a 2250 m3 biomethane methane that is transported in each cycle and ensure the module B runs storage, and deliver to the biomethane injection facility. Such figures at maximum capacity (4200 m3). It was calculated using Eq. (1): are based on the parameters described above. Overall, each cycle includes a transportation time of the mobile solution rotating from one C biogas plant to another, biogas upgrading, biomethane storage time at CT= ⎜⎟⎛ Stp+ ⎛ ⎞⎞ ∗+∗∗+NDVNI() pt ⎝ ⎝U ⎠⎠ (1) each plant and injection into the gas grid. where CT is the cycle time in hours, St is the setting time for the upgrading time at each site, C is the biogas storage capacity per site, U is 2.2.5. Biomethane injection the upgrading capacity, Np is the number of biogas plants, D is the The Irish gas grid has a total transmission network (45–70 bar) average distance between plants and to the injection point, V is the length of 2200 km transporting gas to the major urban centers and speed of transportation and Itis the time required for injection of one larger industrial loads and another 11,200 km of distribution network full load of 4200 Nm3. (25 mbar−4 bar), in 2014 the consumption of natural gas accounted for The biogas storage capacity, C, was calculated to optimize each 30% of Ireland’s Total Primary Energy Requirement (TPER) [35]. Fig. 1 cycle regarding the use of resources and to operate module B at max- shows the gas grid in Ireland, this is not as extensive a network as imum capacity (4200 Nm3). For simplicity and lower cost, the max- compared to the UK and mainland Europe but nonetheless, natural gas imum time for biogas storage is constant for all AD plants and scenarios provides heating to over 30% of the residential market. However, the (50 h). This time has been optimized for a biogas storage of 7500 Nm3 majority of the farms located in rural areas do not have access to the gas per cycle in all scenarios to achieve the maximum capacity of bio- networks; hence the development of an off-grid biomethane mobile methane to be transported in each cycle and to ensure the biogas pro- solution becomes critical. There is widespread experience throughout duced at each site can be stored while the mobile solution is at other Europe of injection into the distribution grid [36], but there is only sites. limited experience of injection into the transmission network. Many gas Depending on the biogas production and the raw biogas storage at distribution lines feed domestic and small business customers whose gas each site, the upgrading plant per cycle may require from 4.3 h of op- use is weather dependent and therefore have very low demand in − eration at 250 Nm3 h 1 in the scenario with 7 plants to 10 h in the summer months (although this limitation can be lessened by the pro- scenario with 3 plants (Table 1). The mobile solution set up is estimated vision of on-site storage, but this would increase the capital and op- quite conservatively to be one hour for connecting, disconnecting and eration cost). Therefore, the amount of biomethane injected is limited storing at each site. Injection into the grid is assumed to take 4.5 h for a by the size of the load. There is no such limitation with the transmission − full load, assuming 1000 m3 h 1 at the injection facility. grid. Moreover, injection into the distribution grid might require the

476 L. Gil-Carrera et al. Applied Energy 239 (2019) 471–481 addition of propane to meet the calorific value, which has a tight range public transport, which will drive the development of biomethane in in the distribution network. the transport industry [43]. A previous study [37] found that there are no suitable rural based Another support mechanism that, if approved, might come into nodes on the low-pressure distribution network, which could accept in place in the coming years would significantly change the business case − excess of 3250 Nm3 h 1 of biomethane all year round. As the small of farm-based biogas producers. This is a Renewable Heat Incentive scale facilities, considered in this study, are located in rural areas and (RHI). The RHI provides a fixed income (per kWh) to generators of long distance transportation to suitable nodes would increase sig- renewable heat, and producers of renewable biogas and biomethane. nificantly the operational cost, this limits the centralized grid injection Such incentive would depend on the size of the plant and the price facility to the transmission grid. required for biomethane to be financially viable would probably be in In this study it is assumed that the connection cost is paid for in full the range of €ct7–9/kWh of energy [44]. This study assumed a RHI of at the time of connection as a fixed capital cost. Such gas grid con- €ct7.5/kWh. If RHI is considered in the previously described scenarios, nection could be of the order of €342,000 [31,38]. That cost would each scenario has a total production of 6.7 GWh which will be trans- depend on economic assessment and depends on connection policy, lated in annual revenue of over € 500,000. whereby the gas operator covers 70% of the renewable gas injection facility; this is subject to approval by the Commission for Energy Reg- 2.2.7. Financial analysis − ulation (CER). This assumption is based on the German renewable gas The cost per Nm 3 of biomethane was calculated and compared for connection policy, where the cost of injection, measurement equip- each scenario over a 15-year operational life (2017–2031). The CAPEX, ment, compression costs are shared between the gas grid operator and was calculated over the lifetime of the mobile solution (15 years) as- the biogas producer, which covers around 20% [39]. suming a discount rate of 8%, using Eq. (2):

The cost of gas quality monitoring, odourisation, compression, N Crro (1+ ) metering and general administration is paid by the Irish natural gas grid Pa = [(1+−r )N 1] (2) operator as an investment cost, which is recovered by entry tariﬀ over

15 years. The connection policy in the Republic of Ireland proposes that where Pa is the CAPEX; Co is the investment cost; N is the number of for small, turn-key biomethane facilities these charges could be on a years and r is the discount rate. ﬁxed cost per annum based on the rated output of the facility [40], The total liabilities (Table 3) or equivalent annual cost is calculated however, for simplicity this cost was considered as capital investment. according to Eq. (3),

R =+POPEXa (3) 2.2.6. Market for biomethane Biomethane injected into the gas grid can be sold to a customer and where R is the equivalent annual cost, Pa is the annualized cost of ca- utilized for process load, heat and/or electricity. Moreover, the bio- pital, CAPEX and OPEX is the annual operational costs. The equivalent methane could be sold to a Compressed Natural Gas (CNG) filling sta- annual cost method or annual liabilities is based on discounted cash tion and utilized as a transport fuel. Biomethane as a transport fuel is flow analysis and spreads the capital cost over the lifetime of the pro- subjected to a number of taxes and charges that must be applied to the ject. fuel before sale. Excise duty for natural gas as transport fuel is Net present value (NPV) was used to identify the economic feasi- − €2.6 GJ 1 and is assumed to apply to biomethane. Furthermore, the bility of the scenarios. NPV is the sum of the total discounted lifetime − National Oil Reserves Agency (NORA) biofuel levy is €0.02 L 1, as- cash flows, both incoming and outgoing. NPV was calculated according − sumed to be €0.02 Nm 3 or €0.0021 kWh. According to NORA [37] to Eq. (4). − biogas, which has an energy value of 35–49.99 MJ Nm 3 (i.e. 98% ⎛ N in out ⎛ 1 ⎞⎞ biomethane) has a gas to liquid conversion factor of 1.5. NPV = ⎜⎟∑ (Casht −∗ CPI Cash ) ∗⎜⎟− CT t=1 t (1+ r )t The Biofuels Obligation Scheme (BOS) Legislation provides that any ⎝ ⎝ ⎠⎠ (4) in out fl biofuel, which is produced from a material considered to be a biode- where Casht and Casht are the incoming and outgoing cash ows in gradable waste, residue, non-food cellulosic material, lignocellulosic year t respectively, CPI is the consumer price index, r is the discount material or algae may be granted 2 certificates per liter [41]. Therefore rate, N is the total number of years (15), and CT is the initial capital −3 out 98% biomethane (35.07 MJ Nm based on NORA NCV value) pro- expenditure in year 0. Casht and Co includes the production cost of the duced from biodegradable waste should be eligible for 3 BOCs (2 waste mobile solution as well as the cost of the biomethane production to certificates * 1.5 conversation factor). The value of the certificates is not assume more realistic scenarios. The discount rate used in the calcu- publicly accessible. However, it is assumed that the certificate value is lation of NPV was 8% as specified in Zamalloa et al. [45] and in As- −1 −1 between €0.02 L and €0.45 L of biofuel, as a €0.02 cent per liter sessment of Cost and Benefits of Biogas and Biomethane in Ireland [44]. levy to fund NORA, to administer the BOS is a requirement for all CPI was assumed to be 2%. suppliers and the penalty for obligated parties who fail to meet their The annual revenue, as previously described, was calculated as a − BOS obligation requirements is €0.45 cent per liter of biofuel. However, sum of the wholesale value of €0.20 Nm 3 of biomethane plus an in- −1 the market forces and trade drive the BOC prices between €0.13 L to centive according to the Eq. (5). − €0.36 L 1 of liquid biofuel equivalent [42]. Assuming each cubic meter R =+∗()NGP I B (5) of biomethane for transport (at 98% methane) will qualify for 3 certi- a ficates the revenue per cubic meter of biomethane for transport is from where Ra is the annual revenue, NPG is the natural gas price, I the €0.39 to 1.08. In this model it was assumed a conservative value of incentive (RHI or BOC) and B the annual biomethane production. − − €60/MWh (€0.61 Nm 3 assuming energy content of 10.17 kWh Nm 3) through the whole analysis; however an evaluation with the highest 3. Results and discussion value of €106/MWh was conducted for the best scenario in order to evaluate the effect on the financial performance. 3.1. Cost of an off-biomethane mobile solution (virtual pipeline) Therefore, the annual revenue in an agriculture biomethane facility would be from the sale of one m3 of biomethane at a wholesale value of The cost of upgrading, transporting and injecting biomethane into €0.20 plus the BOS certificates at €0.61 if sold as transport fuel. These the natural gas grid for the three studied mobile solution scenarios − − − incomes will translate to a revenue of €0.81 Nm 3 of biomethane sold. varies from €ct 61.8 Nm 3 to €ct 64.3 Nm 3. Total biomethane injec- − The Republic of Ireland targets 70 CNG stations over the next tion into the gas grid is 90 m3 h 1 for all configurations in Fig. 4. This decade for refueling infrastructure mainly for heavy good vehicles and figure shows that the overall cost of biomethane for a configuration of 3

477 L. Gil-Carrera et al. Applied Energy 239 (2019) 471–481

Table 3 Commercial viability of scenarios 3.OS, 3.MS, 5.MS and 7.MS. (A) BOC (B) RHI.

Scenario 3.OS Scenario 3.MS Scenario 3.MS* Scenario 5.MS Scenario 7.MS

Revenue & Finance

A Biomethane production 6.7 GWh 6.7 GWh 6.7 GWh 6.7 GWh 6.7 GWh Gas Wholesale Value (€0.020/kWh) 135,077 135,077 135,077 135,077 135,077 BOC(€0.060/kWh) 405,231 405,231 715,908** 405,231 405,231 Annual revenue 540,308 540,308 850,985 540,308 540,308 Total liabilities (MS/OS & biogas production if co-substrate is): Food waste 679,476 556,865 556,865 564,719 573,130 10 Year NPV −2,077,497 −1,237,739 791,409 −1,188,593 −1,245,105

B Biomethane production 6.7 GWh 6.7 GWh 6.7 GWh 6.7 GWh 6.7 GWh Gas Wholesale Value (€0.020/kWh) 135,077 135,077 135,077 135,077 135,077 RHI (€0.075/kWh) 506,538 506,538 607,846*** 506,538 506,538 Annual revenue 679,476 641,616 742,500 641,616 641,616 Total liabilities (MS/OS & biogas production if co-substrate is): Food waste 679,476 556,865 556,865 564,719 573,130 10 Year NPV −1,428,980 −508,669 120,401 −559,163 −615,676

* This scenario was also evaluated assuming a higher incentive. ** The highest value for BOC was assumed in this scenario (€0.106/kWh). *** The highest value for RHI was assumed in this scenario (€0.090/kWh).

− AD facilities (scenario 3.MS) at a production rate of 150 m3 h 1 of number and length of cycles (Fig. 4); storage contributes over 7% to the − biogas in 3 digesters is slightly lower than when producing 150 m3 h 1 total cost. This cost could be reduced if the cycles became shorter; of biogas in 5 or 7 AD facility configurations; scenario 5.MS and 7.MS however this would be detrimental to the optimal biomethane capacity, respectively. which contributes to the total 1% more than the biogas storage. The costs for injection and upgrading are the same for all mobile Diesel consumption increases within the number of AD units, from − − solution scenarios (3.MS, 5.MS and 7.MS) contributing €ct 13/m3 bio- €ct 1.1 Nm 3 in scenario 3.MS to €ct 1.9 Nm 3 in scenario 7.MS due to methane. Also costs of labour and truck equipment remains constant in the longer cycles and distances. However, the cost of transport is sig- those scenarios. The selection of configurations for the mobile up- nificantly lower when compare to centralized biogas plants where grading scenarios does not have a strong impact on these results. It can wastes are collected in the vicinities and transported to a centralized be highlighted that the cost of grid injection and the upgrading and anaerobic digester [46,47]; this practice is very common in Denmark. conditioning contribute significantly to the total cost. The cost of in- Moreover, previous studies on local biogas pipelines to a centralized jection is from 20.2% to 21% of the whole cost in scenarios 3.MS and upgrading plant also show a cost for biogas transport from €ct 3.6 to − 7.MS. Upgrading and conditioning contributes over 23.7% to the 8Nm 3 depending on the number of digesters [15,48]. If trucks run on overall cost, although the PSA technology is well proven and cost-ef- biomethane, such consumption could be saved since 1 Nm3 of bio- ficient. The novelty of the proposed system, a mobile PSA, increases the methane replaces 0.7 L of diesel [33,49], however higher capital in- cost due to the necessity of small size conditioning equipment, a pow- vestment would be required to purchase biomethane trucks. The erful compressor and a unit for inertization to eliminate the bio- number of digesters does not have any impact on the injection fee and methane/biogas in the system while being transported. labor costs, which remained the same for all configurations. − Cost of total raw biogas storage is €ct 4.7 Nm 3, the same for all The scale advantage of the investment decreased the costs of sce- − scenarios; this was maintained constant allowing for a change in the nario 3.MS with 3 biogas plants and lager digesters (50 m3 h 1 biogas)

Fig. 4. Comparison cost of one m3 of biomethane for centralized mobile upgrading & storage (Scenario 3.MS, 5.MS and 7.MS) and onsite upgrading plants (Scenario 3.OS) conﬁgurations. Calculations are based on the equivalent annual cost (15 year operational life).

478 L. Gil-Carrera et al. Applied Energy 239 (2019) 471–481

Fig. 5. Economic analysis of scenarios 3.OS, 3.MS, 5.MS and 7.MS. Annual liabilities (OPEX & CAPEX) per scenario (bars) and investment cost per site (points).

− − as compared to 5 (30 m3 h 1 biogas) and 7 (21 m3 h 1 biogas) biogas Fig. 5, indicates another economic advantage of the mobile solution plants in scenario 5.MS and 7.MS, respectively. The most feasible (scenario 3.MS) for each biogas producer, in this case the investment configuration, in terms of total cost per m3 biomethane, is the 3 AD required is over €234,000 lower than the configuration with upgrading facility configuration (scenario 3.MS). However, the total investment onsite (scenario 3.OS). per site contributes to the advantage of 5 and 7 plants configuration, The lack of biogas storage and the lower number of trips due to the where the capital that each farmer would have to invest is significantly larger biomethane storage in the 3.OS scenario are the main economic less compared with scenario 3.MS. Similar results were found by advantages when compared to the mobile solution scenarios. This re- − Jenkins et al. [50] that suggested that the scale advantage of the di- duces the cost of biogas storage by €ct 4.6 Nm 3 and transport by €ct − gester could be overestimated. For historical reasons, because of sub- 0.7 Nm 3 biomethane, respectively. sidies or to reduce risks in the operation of the plant, it is common to Overall, the cooperative advantage is demonstrated in this model; a find several smaller sized digesters instead of one large-scale digester. savings of €ct 18 to clean/upgrade one Nm3 of biomethane in a mobile Hengevel et al. [15] evaluated a model with decentralized biogas solution (scenario 3.MS). However, one significant advantage of using plants, local biogas grids, a centralized upgrading plant and injection to onsite upgrading plants could be the operational reliability, which is the grid. In this model the total cost to produce one m3 of biomethane higher due to the lower level of logistic requirements. Therefore, the varied from €0.66 for 2 digesters up to €0.74 for 8 digesters; this shows risk of operational break down of the biomethane production chain is a similar trend where increasing number of digesters slightly increases lower; however, such risk is very uncertain and economically un- the total cost. quantifiable.

3.2. Centralized upgrading against onsite upgrading 3.3. Commercial viability

− Figs. 4 and 5 present the costs calculated for multiple configurations Fig. 5 shows the breakdown cost of producing 6.7 GWh year 1 of with a mobile upgrading plant, a virtual pipeline and injection and a biomethane in all scenarios. Capital cost and annual liabilities are sig- configuration of 3 digesters with onsite upgrading plant, a virtual pi- nificantly higher for scenario 3.OS showing again the disadvantage of peline and injection. The advantages of the mobile solution model are this configuration. Economy of scale has an impact on total capital costs shown in Fig. 4. This suggests that for a mobile upgrading and transport and it shows clearly the significant advantage of the mobile upgrading configuration, the cost per m3 of biomethane is significantly lower as unit and the virtual pipeline which has the lowest cost per m3 of bio- compared to an onsite-upgrading configuration. The mobile upgrading methane at €0.62. plant decreases the overall investment and operational cost from €ct Table 3 presents the profitability of all scenarios in terms of annual − 80.3 to 61.8 Nm 3 biomethane. revenue and finance. Total liabilities have been calculated based on cost − It is also shown that the cooperative advantage significantly de- of biogas production which is typically of the order of €0.22 Nm 3 creases the investment, CAPEX and OPEX of the upgrading unit, redu- biomethane when food waste is used as a co-substrate [30,37] and the − cing the cost by €ct 18.4 Nm 3 biomethane. The main contributor to cost of upgrading, compression, distribution as per results showed in the cost differential is the necessity of 3 upgrading plants each of ca- Fig. 5. The selection of the co-substrate would obviously have a sig- − pacity of 50 m3 h 1 of biogas. Furthermore, the onsite-upgrading model nificant impact on finances, which would change drastically if feed increases electricity consumption since power for three gas con- gates were available or if the substrate needed to be purchased. ditioning pieces of equipment, PSA plants and compressors would be Fig. 6 shows a negative 10 year NPV for all scenarios if a con- required, instead of one as in the mobile solution. Moreover, small servative incentive is applied, even after 15 years only the scenario plants are typically less efficient than larger capacity upgrading plants 3.MS with the RHI incentive has a positive NPV. Scenario 3.OS shows and compressors. This agrees with previous studies [18] that suggested the most negative business case, which would require over 30 years to − that upgrading plant size has a high impact on the cost of upgrading, break even. This is based on a revenue of €80–95 MWh 1 if BOC or RHI − especially for plants less than 100 Nm3 h 1. are claimed and no capital grants for any part of the biogas plant, up- The biomethane storage unit also contributes to the difference be- grading system, transport or injection equipment are provided. These − tween mobile and onsite scenarios; this cost is €ct 1.5 Nm 3 bio- results suggest that additional or higher incentives are required to make methane more costly in scenario 3.OS despite using low cost steel financially sustainability. − vessels. This is due to the requirement of an extra set of vessels at each In examining incentives, €60 MWh 1 could be earned in the form of location to collect and store the biogas that is continuously upgraded. BOCs, if the biomethane produced has energy content of 35 MJ m3 and

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Fig. 6. Net present value curves of scenarios 3.OS, 3.MS, 5.MS and 7.MS applying RHI and BOC incentives. comes from waste, which is the case for slurry and manures. This would Acknowledgements − allow a total earning of €80 MWh 1 including the price of natural gas. − − However, the value of one BOC trades between €0.13 L 1 to €0.36 L 1 This work was completed as part of the ATBEST (Advanced of liquid biofuel equivalent [42]. Therefore the most optimum scenario Technologies for Biogas Efficiency, Sustainability and Transport) Marie- − could allow a total earning of €106 MWh 1. The payback in our most Curie Initial Training Network. The network has received funding from favorable scenario (3.MS) could be reduced down to 7 years. RHI shows the European Union’s Seventh Framework Programme for research, a similar viability (Figs. 5 and 6), only when the highest value of technological development and demonstration under grant agreement €0.090/kWh, suggested in the report “Assessment of Cost and Benefits n. 316838. ATBEST is coordinated by the QUESTOR Centre at Queen’s of Biogas and Biomethane in Ireland” [44] for RHI, is assumed, the University Belfast. Prof Murphy is funded by Science Foundation scenario 3.MS becomes profitable after 2.3 years later than in the case Ireland (SFI) through the Centre for Marine and Renewable Energy of BOC. (MaREI) under Grant No. 12/RC/2302. The work was also co-funded by Gas Networks Ireland (GNI) through the Gas Innovation Group and by ERVIA. 4. Conclusions References Establishing farming cooperatives to facilitate use of a mobile upgrading system is imperative for achieving economies of scale on up- [1] Ervia. 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