Elsevier

Applied Energy

Volume 224, 15 August 2018, Pages 615-635
Applied Energy

Opportunities for application of BECCS in the Australian power sector

https://doi.org/10.1016/j.apenergy.2018.04.117Get rights and content

Highlights

  • BECCS in Australia has the potential to deliver 25 Mt CO2/year negative emission.

  • BECCS could supply up to 13.7 TW h electricity to the Australian power sector.

  • Deployment of BECCS as a carbon negative strategy requires strong policy support.

  • BECCS could enhance the flexibility and diversity of Australia’s energy portfolio.

Abstract

Australia has committed to meeting its international obligations to decrease its greenhouse gas emissions including transitioning toward decarbonising its emission-intense energy sector. However, it is facing the dual problems of increasing electricity cost and decreasing energy security. One of the potential contributions to reducing its emission while supplying reliable power is deployment of bioenergy with carbon capture and storage (BECCS). BECCS is a carbon removal technology that offers permanent net removal of carbon dioxide from the atmosphere together with the prospect of negative emissions.

The present study was undertaken to assess the potential contribution of BECCS to achieving long term decarbonising of the Australian energy sector. This study considers the availability of sustainable bioenergy resources and the economic viability and environmental impacts of BECCS. In order to avoid the ecological uncertainties and social challenges of dedicated energy crops, this study focuses on organic waste from the municipal, agricultural, and forestry sectors. Based on the quantity of biomass resources available, BECCS options in Australia have the potential to remove a total of 25 million tonne CO2/year from the atmosphere as negative emissions by 2050. In addition, BECCS systems could supply Australia with up to 13.7 terawatt-hours of renewable power by mid-century which is around 3.6% of expected gross electricity generation in 2050. Deployment of BECCS as a reliable supplier of electricity would potentially enhance the flexibility and diversity of Australia’s energy portfolio and remove carbon dioxide from the atmosphere. However, deployment of BECCS as a carbon negative strategy will require strong policy support.

Introduction

A growing global consensus on mitigating anthropogenic greenhouse gas (GHG) emissions led to a historical agreement at the 2015 United Nations Conference of Parties (COP21) in Paris. This agreement sets out a global action plan to put the world on track to avoid dangerous climate change by limiting global warming to well below 2 °C [1]. Achieving this target demands strict emission reduction measures and tight emission budgets. The global budget for 2000–2050 is around 1700 Gt CO2-eq [2] but on current trends, the world is likely to overshoot this budget. According to the IPCC Fifth Assessment Report (AR5), over 100 of the 116 scenarios associated with concentrations between 430 and 480 ppm CO2 (<+2 °C target) rely on removal of around 5–20 Gt CO2-eq annually, starting from mid-century [3], [4], [5]. A range of negative emission technologies (NETs) such as direct air capture and storage, ocean fertilisation, enhanced weathering of minerals, soil carbon sequestration and afforestation have been proposed [4], [6], [7], [8], [9], [10], [11], [12]. Bioenergy with Carbon Capture and Storage (BECCS) is another negative emission technology that offers permanent net removal of carbon dioxide from the atmosphere. Using biomass for energy production is seen as carbon neutral, in that the carbon dioxide released to the atmosphere during energy conversion was first taken from the atmosphere during photosynthesis. However, in the case of BECCS, the CO2 is not released to the atmosphere but is captured, transported and permanently stored in a suitable geological formation. In effect, a negative flow of CO2 from the atmosphere to the subsurface is established.

A wide range of estimations of the NETs potential to remove atmospheric CO2 can be found in the literature. Most of the studies suggest a higher negative emission potential for BECCS, afforestation (AR) and direct air capture (DAC) compared to other NETs [6], [7], [8], [9]. According McLaren [9], BECCS with up to 10 Gt CO2, AR with up to 3 Gt CO2 and DAC with more than 10 Gt CO2 offer the highest negative emission potential. A study by Smith et al. [6] showed a higher technical potential, up to 12 Gt CO2 per year in 2100, for BECCS, AR and DAC. An estimation by Fuss et al. [8] confirmed this range, with BECCS, AR and DAC each having the highest negative emission potential of up to 12.1 Gt CO2/year in 2100. Koelbl et al. [13] estimated that BECCS could offer 10 Gt CO2/year negative emission in 2050 and around 20 Gt CO2/year in 2100, which is several times the potential of AR (around 4 Gt CO2/year).

BECCS is the most significant NET in integrated assessment models (IAMs) [14]. Unlike other NETs, BECCS offers the twofold advantage of delivering negative emission and providing carbon-free energy. Smith et al. [6] estimated the net energy potential of BECCS at around 170 EJ/year in 2100, whereas other NETs are net consumers of energy. Compared to other NETs, BECCS has the most immediate potential and already has pilot-scale demonstrations [7]. Another advantage of BECCS is the possibility of permanent CO2 storage. The inherent susceptibility of terrestrial carbon stocks to disturbance such as wildfires (350 million hectares burnt per year globally [8]) makes sequestration by other land-based NETs such as afforestation and soil carbon sequestration less reliable [11].

The range of negative emission potentials of BECCS reported in the literature varies from zero to 20 Gt CO2/year [11], [15]. According to Gasser et al. [12], a “best-case” to achieve 2 °C target in addition to conventional mitigation, would require BECCS with annual negative emission of 1.8–11 Gt CO2. In the recent International Energy Agency (IEA) global models, BECCS could deliver negative 14 Gt CO2 between 2015 and 2050, of which 11 Gt CO2 is captured from biofuels with CCS and 3 Gt CO2 from dedicated and co-firing BECCS for power [16]. A study by Kemper [17] found the global technical potential of BECCS, through biomass gasification and direct combustion, to be around 10 Gt CO2/year in 2050. Woolf et al. [18] estimated a lower global net negative emission of 3.3–7.5 Gt CO2/year. Ricci and Selosse [19] used the multiregional TIAM-FR optimization model to assess the global and regional potential of BECCS. Their study showed that by 2050, BECCS and CCS could generate 23–30% of the electricity, equivalent to 5.7–7.6 Gt CO2 captured and stored. Most of this capacity lies in developing countries, especially China, India and Brazil. In a complementary study, Ricci and Selosse showed that near-term widespread implementation of CCS with 15% BECCS would be a desirable way to achieve stringent emission targets [20]. In a study by Koornneef et al. [21], the economic potential of BECCS is estimated to be up to 3.5 Gt CO2-eq/year negative emissions from the power sector and 3.1 Gt CO2-eq/year in transportation. However, these potentials are not for the whole sectors but for the “best” routes, i.e. BIGCC-CCS and FT biodiesel in 2050. An assessment of the assumptions underpinning the feasibility of BECCS in IAM scenarios by Vaughan and Gough [22] showed that assumptions regarding technical aspects of BECCS is realistic. However, their results warned that the socio-political assumptions and future bioenergy potential for its large-scale deployment are unrealistic.

Globally there have been twenty BECCS projects, mostly located in North America, Europe and Scandinavia [17], [23], [24]. Currently five of these projects are operating, capturing CO2 from ethanol production plants with a total capacity range of 0.1–1 Mt CO2/year negative emission [25]. Five projects have been cancelled mostly due to lack of economic viability and the remainder are either completed or under evaluations/planning [17]. The BECCS projects under planning use CCS coupled with a variety of bioenergy technologies such as waste-to-energy (in Norway and The Netherlands), ethanol plants (France, Brazil and Sweden), biomass combustion/co-firing (Japan), pulp and paper (2 projects in Sweden), biomass gasification (the U.S) and a biogas plant (Sweden) [15], [17].

The large-scale deployment of BECCS took a major step forward in 2017, with the commencement of the Illinois Industrial CCS Project (IICCSP). The project has received US$140 million in capital support from the U.S Department of Energy and will also be able to access CO2 storage credits of USD 20/t CO2 [17]. IICCSP was established in 2011 [26]. In this project the CO2 released during the fermentation process to produce ethanol at the Archer Daniels Midland (ADM) ethanol plant in Decatur, Illinois, is captured, transported and stored in a deep saline formation, the Mount Simon Sandstone [26]. During its operational period from November 2011 to November 2014, the IL-ICCS project injected 1 Mt CO2 into the subsurface. Since 2017 the IIICCSP project has increased the CO2 injection rate up to 1 Mt CO2/year [26].

Recently a waste to energy agency in the Oslo municipality (EGE) conducted a feasibility study to assess the opportunities for CO2 capture from a waste incineration plant at Klemetsrud [27]. Technical assessments show that the project could potentially capture up to 3.15 Mt CO2 annually with a 90% CO2 capture rate by 2020 [27]. Around 50–60% of this CO2 is biogenic. Another project of this kind is ARV-Duiven in Duiven, in the Netherlands. The ARV-Duiven power plant with 70 MW capacity incinerates municipal solid waste (MSW) to produce around 126 GW h electricity. From 2018, ARV-Duiven is planning to capture up to 50 Kt CO2 per annum using the MEA capture process [28].

Bioenergy required to provide the scale of BECCS projected in most IAMs is estimated to be in the range of 0–1000 EJ/year, with a high probability of around 100 EJ/year [17], [29], [30], [31], [32], [33], [34], [35], [36]. Kemper [17] addressed the lack of standard methodology and the likely effect of climate change as the main reasons for the large variations in estimating the global potential of bioenergy.

The challenge of scaling up bioenergy to the level required in 2 °C scenarios lies in producing sustainable biomass while maintaining a balance with essential food and fibre production. In addition, bioenergy expansion must act in accordance with technical and economic development, social expectations and policy/regulatory regimes [37]. Without this, intensification of bioenergy production, especially from energy crops, could result in severe competition between food, feed, and energy, leading to controversial economic, ethical, and environmental issues [15], [38], [39].

Expansion of bioenergy is constrained by its potential ecological ramifications. Historically, unsustainable biomass harvest has led to loss of a considerable proportion of natural forests and degradation of productive lands [29], [34], [40], increased GHG emissions, loss of biodiversity and carbon stock [41], [42], [43], [44], [45], [46], [47] and depletion of water resources [41], [42], [43], [48]. Expanding bioenergy production must be carefully considered against the background of sustainability [49]. Two of the main environmental issues to be considered are land-use and water consumption; the area of land needed for bioenergy production depends on the productivity of the land, efficiency of production practices and the type of biomass. The area available for bioenergy production from energy crops in the literature is estimated to range from 80 to 2400 Mha [6], [33], [50], [51], [52], [53], [54], [55], [56]. However, the area required for forest, protected lands and human settlement leaves only 140 Mha available for bioenergy expansion [39], [50]. Another crucial limiting factor is the land required to supply food and fibre for the growing population. According to the Food and Agriculture Organization (FAO) [57] an additional 72 Mha is required to meet the anticipated global food demand by 2050. Under current food production systems, 32 countries are facing a food crisis, with approximately 870 million people estimated to be undernourished and 1 billion malnourished [58]. Despite the current inefficiencies to meet food demand, food production still has to grow by 70% to feed around 9 billion people by 2050 [38], [59], [60], [61]. Competition over limited productive land and water resources will put more constraints on expanding lands for energy crop cultivation – especially when energy crops substitute for food crops, or food crops are used for bioenergy production. Increasing food prices is one of the most likely consequences. The water needed to grow dedicated crops to deliver a mid-range of 12.1 Gt CO2/year negative emission through BECCS, by 2100, would be approximately 720 km3 [6]. This is about 18% of current human withdrawal. Energy crop production could require a significant proportion of the available fresh water [17], [48], [62]. That will be especially a challenge in regions such as sub-Saharan Africa, Middle East, western America, Mexico and Australia, all of which are already facing a water scarcity [41], [43], [58].

Using organic waste from municipal, agricultural and forestry sectors for BECCS is one way to avoid the ecological and social challenges of dedicated energy crops. Organic residues are perceived to have less environmental impacts as they are inevitable by-products of high value food and fodder production. The amount of bioenergy derived from organic residue varies from 5 EJ/year to 270 EJ/year [3], [31], [34], [54], [63], [64], [65]. Utilising these wastes in a BECCS system turns a negative externality into a valuable good and provides a source of income for local farmers, industry and state, plus generating energy and delivering negative emissions [3], [17], [34], [66], [67].

Australia has one of the highest GHG emissions per capita among developed countries [66]. Its Intended Nationally Determined Contribution (INDC) to the Paris Agreement is to reduce emissions by 26–28% on 2005 levels by 2030 [2]. The Paris Agreement places the onus on countries to meet the mid-term mitigation targets and increase their reduction target every five years in order to achieve global zero net emission by 2050. Australia’s current emissions are around 600 Mt CO2-eq per year [68] or about 1% of global emissions. It has some mitigation policies in place to help achieving its emission reduction targets. These include two important policy tools already implemented in Australia, namely the Emission Reduction Fund (ERF) – and its related safeguard mechanisms, and the Renewable Energy Target (RET). The RET is expected to deliver a 200 Mt CO2 reduction between 2015 and 2030 [2], with the Australian electricity sector emissions expected to decline to less than 0.25 t CO2-eq/MW h by 2030 and to 0.1 t CO2-eq/MW h by 2050 [69]. This is despite an expected growth in gross electricity generation of 49% (to 377 TW h) by 2050. It is predicted that renewable energy will need to contribute at least 70% of total electricity generation between 2030 and 2050 to make this target achievable [70].

Despite its potential contribution to decreasing emissions and supplying renewable energy, there has to date been no comprehensive assessment of BECCS in Australia. Critical to any such assessment is the availability and compatibility of the sub-systems, namely the bioenergy sector and the opportunities for establishing associated CCS systems. Below, the status of Australian bioenergy and CCS and their potential/challenges are discussed.

In Australia, bioenergy makes up around 4% of the Total Primary Energy Supplies (TPES) and 78% of renewable energy is dominated by an annual usage of 4–60 Mt of firewood for heating [71]. Bioenergy in Australia has an estimated value of more than of AUD 400 million per annum [72]. Other than its use as a cheap fuel for heating, the main drivers for development of bioenergy in Australia have been mitigating GHG and particulate emissions, the oil price and the growing demand for green transport fuels, sustainable development in rural areas, and the transition toward a less carbon intensive energy future [73]. There are a range of estimates for the potential of bioelectricity in Australia. For instance, the Clean Energy Council (CEC) Bioenergy Roadmap [74] estimated that bioenergy could provide 10.6 TW h/year by 2020 and this contribution could increase to 73 TW h/year by 2050. The Australian Business Roundtable on Climate Change foresees that bioelectricity could supply 19.8–30.7% of Australia’s demand by 2050 [47]. According to the CEC [74], waste and by-products from high value primary crops would become the only long-term sustainable source of biomass for bioenergy in Australia. Bioenergy in Australia has mainly relied on organic wastes from the municipal, agricultural and forestry sectors. The main resources are sugarcane bagasse, forestry wastes, wood processing wastes, urban green waste, urban wood waste, landfill gas, agricultural wastes and wet organics. Currently, the bioenergy sector is mainly reliant on wood and bagasse with 42% and 44%, respectively [73].

The 114 bioenergy plants in Australia have a total installed capacity of 812 MW, constituting less than 1% (around 2 TW h) of total national power generation [70]. Around 60% of this bioenergy capacity is from agricultural residues – mostly bagasse. The remainder is made up of 124 MW from forest residues and 209 MW from landfill gas and sewage [75]. The largest bioenergy plant in Australia is the Pioneer Sugar Mill in Queensland with 68 MW capacity, using bagasse [76]. The total annual sugarcane production is about 35.5 Mt [73]. Bagasse is the by-product of sugarcane food manufacturing with a yield of 0.6 kg bagasse per 1 kg of dry sugarcane [77]. Bagasse is used as a feedstock to supply the energy required for running the sugarcane mill. In this way it helps to reduce costs of production and facilitates energy supply in remote areas. Between 10 and 20 tonnes of sugarcane residue per hectare is used to cover the soil for protection and to improve the soil erosion, water content, bulk density, and carbon stock [78].

Municipal Solid Waste (MSW) is another potentially important source of bioenergy. Australia ranks seventh among OECD (Organisation for Economic Co-operation and Development) countries in MSW generation per capita [79]. In 2010–2011 around 14 Mt of MSW was generated in Australia [80]. Around 17% of this was used to produce landfill gas (LFG) [81]. In recent decades, the percentage of the LFG captured for energy recovery has increased from zero in 1990 to 3 Mt in 2010 [82]. New South Wales and Victoria are the states with the highest level of LFG recovery [82]. After bagasse (66%), LFG (22%) is the largest source of bioenergy production in Australia [80]. Australia has one the lowest rates of waste incineration for energy recovery (<1%) amongst OECD countries [82]. One reason for this could be the low landfill tipping fee in Australia, though this varies from State to State. For instance in Queensland there is no fee for landfilled MSW but in Victoria the fee is about AUD 58.5 per tonne [82]. Different waste and energy policies have caused inhomogeneity in the use of energy from waste across the country. However, some national initiatives such as the national waste policy, the Carbon Farming Initiative, the energy white paper and the renewable energy target, encourage mitigation of emissions from the waste sector [83]. Landfill gas can be flared or used to generate renewable electricity or heat. This electricity can be sold back into the electricity grid. Landfill operators can also generate tradeable renewable energy certificates under the Renewable Energy Target scheme [84].

Bioenergy facilities have economic benefits but can also offer social benefits such as stable long-term employment for local and regional communities compared to purely agricultural-based communities, which may only offer seasonal employment or fewer job opportunities. Bioenergy enhances revenue to local producers by selling residues and in some cases fertilizers produced from organic waste digesters. Bioenergy facilities are typically installed in close proximity to the input resources thereby reducing the need to build new electricity networks in surrounding rural areas. Additionally, this reduces transmission losses arising from long distance electricity delivery. However, it is also important to assess the social impact of bioenergy facilities located close to the production sites in rural areas, including land ownership, labour conditions and equitable access to food, land and energy [85], [86], [87], [88].

According to the Global CCS institute, there are 38 large-scale CCS projects under development around the world, seven of which are operational [89]. Australia has been one of the pioneers in CCS research and there are several CCS projects but none commercially operating as yet. Because of its geology and particularly its many sedimentary basins, Australia has a very large storage resource – enough to meet its potential storage needs for many decades, if not centuries. Currently there are no operational large scale CCS projects in Australia [90], [91], but there are a number that are progressing

  • The Gorgon project operated by Chevron Corporation, will be the world largest natural gas CCS project and will separate, capture and geologically store 3–4 Mt of CO2 per annum from high CO2 content natural gas. It expected to commence injection of CO2 in 2018, continuing for up to 40 years.

  • The Callide oxyfuel pilot project successfully captured CO2 from an existing 30 MW coal-fired power plant; the project has now been concluded.

  • South-West Hub: the concept is to capture and store CO2 emissions from industrial sources. Several wells have been drilled, but the future of the project is uncertain.

  • The CarbonNet Project, located in the Gippsland Basin is currently evaluating offshore storage potential and economic opportunities for a potential project of 1–5 Mt CO2 per annum.

  • The CTSCo Project is evaluating storage opportunities in the Surat Basin in Queensland

  • The CO2CRC Otway Project in Victoria, the world’s most comprehensive storage research project is investigating storage in a depleted gas field and in saline aquifers. It has successfully injected, stored and monitored approximately 80 Kt of CO2 rich gas.

Despite its potential as a large scale mitigation option CCS has not yet contributed to significantly reducing emissions globally at scale. Excluding CO2 injected for enhanced oil recovery, the current capacity of the CCS project around the world is around 40 Mt CO2 per annum. This is far less than the capacity required to make a significant contribution to the 2 °C scenario emission trajectory (around 4000 Mt per annum by 2040) [16], [89]. Between 2010 and 2016 more than 20 large scale CCS projects were cancelled across Europe, the U.S and Australia [92]. The CCS flagship program in Australia was reduced from AUD 1.9 billion in 2009 to AUD 500 million in 2015 [93]. This is mainly due to uncertain policy support and economic feasibility [16].

CCS is a heterogeneous technology involving capture, transportation and storage options. The cost of the CCS chain depends on several factors. In Australia depending on the location, the cost of transport and storage is between AUD 8 to AUD 55/t CO2 avoided [91], [92], [94]. Typically, the capture process for coal-fired power generation can constitute more than 50% to the total cost of a CCS project. According to CO2CRC [95] the capital cost of CCS is expected to decrease by 30–50% by 2030 [90]. CO2 transport and storage hubs can further reduce the cost of CCS by cutting the cost of infrastructure and sharing facilities [96].

Whilst long term reliable storage of CO2 has been one of the concerns regarding CCS, the Otway research facility has demonstrated safe long-term storage of CO2 and new monitoring methods such as permanently deployed arrays, could reduce the cost of offshore and onshore monitoring significantly (by ten to hundred millions of dollars) [97]. Having large storage potential in its onshore and offshore sedimentary basins and know-how suggest that BECCS may be a particular opportunity for Australia, but of course this is very dependent on the ready availability of biomass and the overall feasibility of BECCS systems.

The present study offers some insights into the potential contribution of bioenergy with carbon capture and storage (BECCS) in achieving long-term decarbonising of the Australian energy sector and considers the availability of sustainable bioenergy resources and the economic viability and environmental impact of BECCS.

Techno-economic and life cycle assessments were conducted for four organic-based bioenergy technologies with and without CCS; (a) landfill gas combusted in a gas turbine (LFG-GT), (b) bagasse (BG-CFB), (c) forest residue (FR-CFB) and (d) municipal solid waste (MSW-CFB) combusted in circulating fluidised beds (all without CCS) and their corresponding options with CCS: LFG-CCS, BG-CCS, FR-CCS and MSW-CCS.

The four systems without CCS (LFG-GT, BG-CCS, FR-CCS and MSW-CCS) were used as a reference to evaluate the environmental and economic implications of coupling CCS with these organic-based bioenergy technologies. Data available from published literature, reports from national and international organizations and online databases was used in the analysis.

One important factor determining the technical feasibility and economic viability of BECCS is the transportation of biomass to a bioenergy plant and of captured CO2 to a geological storage site. Comparing the location of the storage sites projects in the CO2CRC map [98] with the map of bioenergy facilities developed by Geoscience Australia [73], there appears to be some natural source – sink matching between the biomass production sites and CO2 storage locations. This is potentially very important for large-scale BECCS deployment in Australia.

Fig. 1 shows the distribution of bioenergy facilities around the Australia. As seen, the majority of bioelectricity plants are located on the east coast in close proximity to croplands and forests. All bagasse facilities (blue squares on the map), with a total capacity of around 400 MW, spread within 1500 km of the Queensland east coast. A few wood waste facilities (purple circles on the map) with a total capacity of ∼30 MW are on the boarder of New South Wales and Queensland.

Fig. 2, illustrates the Australian CCS projects and basins with potential for CO2 storage. Comparing Fig. 1, Fig. 2, it can be seen that there is some potential for geological storage in close proximity to bioelectricity plants, especially in Queensland.

The Surat Basin is an asymmetric intracratonic basin with an area of 300,000 km2 in central southern Queensland and central northern New South Wales, within 400–600 km of the emissions hubs [99]. It includes sedimentary formations with up to 2.9 Gt of CO2 storage potential [100] and an annual potential to store 50 Mt CO2 [99]. The Surat Basin storage potential is currently under evaluation [92].

In this study it is assumed that bioelectricity plants are located in the south east of Queensland within a 500 km distance from a storage well in the Surat Basin (Fig. 2).

In the BG-CCS, FR-CSS and MSW-CCS models, biomass is combusted in a circulating fluidised bed (CFB) plant to produce electricity. The electricity generated is exported to the grid. The residue from the combustion plant is mostly ash which is landfilled. The reason for using CFB is its ability to burn fuels with high moisture and low heating value with highest efficiency. In addition, CFB does not require fuel pre-processing. The gas velocity in CFB reactors is between 3 and 9 m/s which results in lower SOx, NOx and HCl formation. CFB reactors offer higher efficiency and less bottom ash than fixed bed boilers [101]. One of the challenges of waste combustion is the presence of trace elements such as Si, Al, K, Mg, Ca and Na which result in formation of heavy metals and salts in the fly ash and bottom ash. Thermal stabilisation by melting and sintering is applied to treat these residues before landfill [102], [103], [104], [105], [106]. Electrostatic precipitators are used to filter the dust and most of the heavy metals.

In the LFG-CCS system, wet MSW is collected and stored in a sanitary landfill facility, where LFG is produced through the activities of methanogenic microorganisms. Methane comprises only 35–65 vol% of LFG. The remainder is CO2 (15–50 vol%), H2 (0–3 vol%), O2 (0–1 vol%), H2S (0–3 vol%) and N2 (10–15%) [107]. In this model, it is assumed that the sanitary LFG facility is equipped with a gas cleaning unit. Therefore, the final product sent through the pipeline to the gas turbine contains 50%:50% CO2/CH4. In some plants, flaring is used to oxidise a fraction of the methane collected [108], but in this study it is assumed that all of the CH4 collected is used for power production. The methanogenic phase of organic waste decomposition is a steady process and typically continues for 20 years. The LFG generation flow rate is not linear and depends on several parameters such as composition of waste, the mass of solid, water content, pH and ambient temperature. The collection efficiency is expressed as the percentage of LFG collected in a landfill site. In an LFG unit with intermediate soil cover, the LFG collection efficiency will range between 55% and 95% [109]. In more advanced facilities with bioreactor LGF cells, collection efficiency could reach close to 100% [110], [111]. In this study, it is assumed that the LFG is collected from a vertical well with an LGF collection rate of 95%. The vertical well for production of the gas is schedule 80 PVC pipe with a diameter of 100 cm. Vacuum blowers send the LFG into pipelines for transportation to a gas cleaning facility [112]. After extraction, LFG requires dehumidification and removal of impurities and particulates. In this study, LFG is combusted in a gas turbine, which means siloxane and hydrogen sulphide must also be removed. Siloxane in the waste converts to SiO2 during LFG combustion and is deposited on the internal surfaces of gas turbines, causing damage and increasing maintenance, while sulfur compounds in the waste lead to formation of corrosive sulphides. In this study, a 10 MW combined cycle gas turbine which utilises the exhaust heat from the turbine to produce electricity with an efficiency up to 40% [113] was assumed for LFG combustion. Gas turbines have relatively low O&M cost compared to internal combustion engines and are more corrosion resistant.

The CO2 capture process in our model is post-combustion chemical absorption using monoethanolamine (MEA). After separation, the CO2 is compressed to 150 bars and sent to the CO2 sink and stored underground in suitable geological formations. Pipelines and compression equipment for transporting the CO2 and injection wells are components of the CO2 storage system. The CO2 capture and storage processes are identical in all the BECCS models.

A conventional MEA-based system comprising a pre-treatment unit, CO2 capture unit and a CO2 compression unit is used in this study. MEA (30 wt%) is a benchmark solvent used in post combustion CO2 capture from coal-fired power plants. It is commercially available and has been extensively used in industrial applications [114], [115], [116], [117].

The pre-treatment unit consists of a selective catalyst reactor (SCR) equipment to remove NOx (NO and NO2) and a flue gas desulfurisation unit (FGD) to remove SOx (SO2 and SO3) in the flue gas. SOx and NOx damage the MEA system by forming corrosive stable salts. The SO2 content of flue gas after FGD is around 30 ppm [116]. Therefore a secondary FGD is required to clean the SO2 to a level (10 ppm) at which the MEA system is not adversely affected. Fly ash is removed using cyclones and suspended particulates are collected by the electrostatic precipitators (ESPs) [118]. After the pre-treatment unit, the flue gas goes through an absorber column. In the pre-treatment unit the temperature of the flue gas, which leaves the FGD units at around 58 °C, is cooled down to a level suitable for the MEA absorber column. In the absorber, CO2 exothermically reacts with 30 wt% aqueous MEA solution, using a lean solvent loading of 0.25 mol CO2/mol MEA forming a water -soluble salt. The CO2 rich solvent goes into the stripper and is heated to 100–140 °C at close to atmospheric pressure. In the stripper the CO2 desorbs from the MEA solution and leaves the stripper saturated with water. The CO2 gas stream (>99% purity) is then dewatered in a condenser and compressed, transported by pipeline and geologically stored. It is assumed that 90% of the CO2 is sequestered from the flue gas. This rate of CO2 capture for a MEA system with the abovementioned characteristics has been frequently reported in the literature [89], [116], [119], [120].

The recovered MEA is cooled to 35 °C and returned to the absorber. After water and MEA vapour are washed from the CO2-lean gas, it leaves the absorber and is released to the atmosphere. Steam heating required for the stripper, and pumping the liquid is the source of the energy penalty in a MEA system. The total energy required to run such a system is around 3.9 GJ/t CO2, the water used for cooling is 106 m3/t CO2 and MEA solvent is 20 m3/t CO2 [115]. Together, these decrease the thermal efficiency of the plant by 25–40% and increase the costs of electricity generation by 70–10% [116]. The thermal energy requirement decreases with increasing lean solvent loading. Abu-Zahra et al. [115] studied the effect of lean solvent loading and showed that higher loading of 0.32–0.33 mol CO2/mol MEA results in a lower thermal energy requirement of 3.45 GJ/t CO2.

For the purposes of this study, it is assumed that CO2 is transported via a carbon-manganese steel pipeline with an external diameter of 600 mm and a thickness of 20 mm [121], to an onshore storage site. CO2 at supercritical conditions (above 32 °C and 73 atm with a density of CO2 approaching 1000 kg/m3) is transported via pipelines [122], [123]. Pipeline transportation is more viable and mature for onshore transportation and is especially suitable when the CO2 source is a power plant with a lifetime of more than 20 years [122]. The pipeline is buried in a trench of 1 m depth and equipped with over-pressure protection and leakage detection systems and block valves every 16–32 km [122], [124]. In this study, the cost of transporting CO2 along a 500 km pipeline is around $8/t for a mass flow of 25 Mt CO2/year [95], [121], [122].

Regions with sedimentary basins are potentially suitable for CO2 storage [124], but tectonic setting, geology (reservoirs, seals, porosity, permeability), and hydrology of the basin are all factors that need to be considered when assessing the suitability of an area for geological storage of CO2. For the purpose of this modelling, it is assumed that the CO2 is stored in the Surat Basin at a depth of 1500 m, that CO2 injection pressure is monitored and that there is ongoing monitoring to ensure that there is no leakage of CO2 from the well or from the storage formation with the expectation that over 99% of injected CO2 will be retained in the storage reservoir over 1000 years [56]. Any contribution to global warming from release of stored CO2, acidification of underground water or damage to ecosystems is judged to be very low provided the storage site is well characterised and best practice is followed for all on-site operations and monitoring. In this study it is assumed the total cost of CO2 injection, storage and monitoring is $15/t CO2 [95], [99], [122]. However, parameters such as depth, permeability of the formation, and transport distance all impact on this base cost of storage.

To investigate the economic viability of BG-CCS, FR-CCS, MSW-CCS and LFG-CCS electricity production systems, techno-economic assessments were conducted. The levelised cost of electricity production (LCOE) was calculated for each system. The LCOE of black coal combusted in a pulverised coal combustion plant (Coal-PC) with and without CCS technology was used as the baseline. In the year 2013–2014, the percentage of power generation from coal was 61% in Australia [125].

The LCOEdefault [$/MW h] was calculated using Eq. (1). All the costs in this study are in 2017 USD. The levelised cost of electricity production is the capital and operating costs spent in a period of time (a year) per the net amount of electricity generated in that period. LCOEdefault is the cost of electricity production in the absence of any emission policy or subsidy;LCOEdefault=capitalcost×(i-ρ)1-1+i-ρ1+ρ-N+O&Mfixed+CF×O&MvariableCF×MW h

In Eq. (1), O&Mfixed is the sum of all fixed annual operating costs, O&Mvariable represents the sum of all variable annual operating costs, including fuel, using a 100% capacity factor. CF is the plant capacity factor (assumed to be constant over the operational period), MW h represents the annual net megawatt-hours of power generated at 100% capacity factor. i is the interest rate, ρ the inflation rate and N the investment lifetime.To evaluate the impact of different emission policies on LCOE, Eq. (2) can be applied. As can be seen, carbon price (Pcarbon), revenues from negative CO2 emission (Pnegative CO2) and renewable energy certificates (REC) are included as possible emission policies in this study.LCOE=LCOEdefault$MW h+PCO2$tCO2×EmissiontCO2MW h-REC$MW h-PnegativeCO2$tCO2×negativeEmissiontCO2MW h

Because the electricity generated from bioenergy plants is regarded as renewable energy, the electricity generated receives renewable energy credits.

Additionally, the CO2 emission from organic waste is from biogenic sources and no CO2 tax is imposed on it. Moreover, the CO2 captured and stored will be counted as negative carbon and it is assumed that it will receive credit for negative emissions.

Table 1 lists the techno-economic data for BG-CCS, FR-CCS, MSW-CCS, LFG-CCS and Coal-CCS, based on information available in the literature.

The Cost of CO2 emission avoided is the cost of the CCS processes added per tonne of CO2 captured; see Eq. (3);CostofCO2avoided=LCOE(withCCS)-LCOE(noCCS)CO2(noCCS)-CO2,(withCCS)

The net CO2 emissions per megawatt-hour of electricity (t CO2/MW h) generation is calculated according to Eq. (4); where CO2 is the total CO2 emissions of the power plant, ηCO2, capture is the efficiency of the carbon capture process and Xb is the fraction of biogenic CO2. It is assumed all the biogenic CO2 is GHG neutral, hence if it is emitted to the atmosphere it is equal to zero and if captured and stored underground is regarded as a negative emission.NetCO2emission=CO2×(1-ηCO2,Capture)×(1-Xb)-CO2×ηCO2,Capture×XbMW h

In this study, ηCO2, capture of the MEA capture unit is 90%. Xb depends on the organic content of the feedstock to the power plant. In this study Xb for LFG, BG and FR is assumed to be 1. Plastic (11.5%) and other inert components such as glass and metal make 32.7% of MSW-see Table 3. It assumed that the carbon content of plastic, which is non-biogenic carbon, is 0.63 wt%. Therefore, the total non-biogenic CO2 content of the outlet CO2 is 7.2%.

Compositions of the fuels are listed in Table 2. It is assumed that LFG sent to the gas turbine is 50:50% CO2/CH4 and its LHV is 18.3 MJ/kg.

Life cycle assessment (LCA) was carried out using SimaPro software version 8.2.0.0 developed by PRé Sustainability Group. The LCA study includes four main steps; defining the goal and scope, life cycle inventory of all the inputs and outputs, lifecycle impact assessment, and interpretation of the results. Allocation modelling was applied to assess the environmental impacts of the BECCS systems with the functional unit of 1 KW h electricity generated. In these assessments, the ALCAS Best Practice LCIA method [143] was used. ALCAS uses the Global Warming Potential (GWP 100) according to IPCC’s fifth assessment report. The impact categories considered in this study were global warming (GWP100a), abiotic depletion (fossil fuels), Ozone Layer Depletion (ODP), eutrophication, acidification, particulate matter, human toxicity (cancer), human toxicity (non-cancer), freshwater ecotoxicity and water scarcity. Most of the inventory data are taken from Ecoinvent-3 [144] and the AusLCI database (developed by Australian LCA Society (ALCAS)) [145]. Data regarding the MEA CO2 capture unit was derived from Hooper et al. [146], [147]. CO2 and CH4 emissions are based on the degradable organic content (DOC) of the waste calculated using the methodology in the National Inventory Report [107]. Table 3 shows the composition of MSW in Australia.

Fig. 3, Fig. 4, Fig. 5 illustrate the BECCS systems with the major components and the system boundaries.

It is assumed that bagasse is produced as a by-product of the sugar industry. The AusLCI database used, includes the transport of sugarcane to the sugar refinery, the processing of sugarcane to sugar and bagasse collection.

Forestry residue potential cannot be aggregated easily, because it is very site specific and depends on several factors such as tree species, management type, silvicultural practices and final product [151]. Residues usually constitute 25–45% of the harvested volume of wood [152]. Although removal of the residues lowers the risk of fire and damage from insects and diseases [152], unsustainable removal could have severe ecological implications [153]. Of the residue produced from logging, wood-processing and tending/thinning a minimum of 1000 t/km2 of forestry residues from final harvest should remain on site to maintain soil properties [151], [154]. In a long term soil productivity study, Curzon et al. [155] demonstrated that increased soil disturbance resulting from the removal of forestry residues may have a negative effect on structural development and forest productivity. In addition to that, forest residues are a source of animal feed and fuel in poor communities. Another concern is biodiversity conservation. Protecting unique ecosystems and critical habitat and balancing the vegetation structure should be included in forest reside management [152]. In this study it is assumed that 25% of final harvest could be utilised for energy production. In addition, forest residues are assumed to be collected as part of non-commercial thinning and whole-tree logging operations on private and state-owned forest lands; national forests, national parks, and other federal or state lands are explicitly excluded from this module.

Both bagasse and forestry residues are assumed to be supplied to the power plants through 100 km road transportation.

In the case of MSW-CCS (see Fig. 4) and LFG-CCS (see Fig. 5), MSW generation and transportation is outside of the system boundary. All the waste after separation of the reusable and recyclables are transported to the waste storage site. The waste is assumed to be composed of some inorganic material (7.2%), mainly from plastic. The CO2 emission from plastic is non-biogenic and is deducted from the total incineration plant CO2 emission.

In this study, waste decomposition and methane generation in a sanitary landfill site was based on first order decay (FOD), as proposed by IPCC Guidelines for National Greenhouse Gas Inventories 2006 [156]. Organic decomposition in a LFG site produces mainly CH4 and CO2 and small percentages of H2S, non -methane volatile organic compounds (NMVOC – around 2%), N2O, NOx and CO.

In FOD the reaction rate is proportional to the amount of degradable organic carbon decomposable under anaerobic conditions and it is assumed that the degradable organic content of the waste decays over several decades but with most decomposition occurring, during the first decade of landfill. The timeframe for complete decomposition in FOD is at least 50 years. In this study it is assumed that approximately 99% of the decomposition was completed during the first two decades after commencing landfilling. The lifetime of the sanitary landfill collection site and the LFG combustion plant is 25 years. Hence, the time for total decomposition in this study is taken to be 25 years. The amounts of CH4 and CO2 generated during the lifetime of the sanitary landfill site are calculated via Eqs. (5), (6), (7), (8), (9) [156].CH4-captured=CH4-generated×ηLFG-captureCH4-generated=t=0nWt×DOC×DOCf×MCF×F×1612×(1-e-k)CH4-emittedtotheambient=CH4-generated×(1-ηLFG-capture)×(1-Ox)CO2-generated=DOC×DOCf×(1-F)×(1-NMVOC)4412CO2-emittedtotheambient=CO2-generated×(1-ηLFG-capture)

In the equations above;

  • CH4-generated: total methane generated during the lifetime of the landfill site [tonne]

  • CH4-captured: total methane collected from the landfill site [tonne]

  • ηLFG- captured: efficiency of the LFG capture, which is taken as 95% in this study

  • t: time [year]

  • F: fraction of CH4, by volume, in generated landfill gas (fraction), assumed to be 50% in this study

  • 16/12: molecular weight ratio CH4/C

  • 44/12: molecular weight ratio CO2/C

  • Wt: mass of waste disposed in year t [tonne]

  • DOC: degradable organic carbon in the year of deposition [tonne C/tonne waste]

  • DOCf: fraction of DOC that can decompose

  • MCF: CH4 correction factor for aerobic decomposition in the year of deposition, for managed anaerobic site MCF equals 1 [156]

  • k: reaction constant

  • Ox: Landfill oxidation factor, assumed to be zero in this study

  • NMVOC = Non-methane volatile organic compounds emission is assumed to be 2% of LFG [157]

The final waste is assumed to be inert, after complete decomposition of the degradable carbon content of the waste. Eq. (10) is used to calculate the amount final waste left after the decomposition is completed [108].Finalwaste=Wt×(1-DOC×DOCf)

DOC, DOCf, k and moisture content of the waste materials is provided in Table 4.

Section snippets

Cost of electricity production

CO2 emissions and levelised cost of electricity production (LCOE) were calculated for LFG combusted in a gas turbine (LFG-GT), MSW, bagasse and forest residue combusted in a CFB (MSW-CFB, BG-CFB and FR-CFB) and pulverised coal combustion (Coal-PC) with and without CCS (Table 5).

Eq. (4) was used to calculate the net CO2 emission with CCS. 100% of the CO2 from combustion of LFG, bagasse and forest residue is biogenic, hence when this CO2 is sequestered and stored it is regarded as negative CO2.

Technical potential for CO2 mitigation using BECCS in a Australian context

The CEC Bioenergy Roadmap provides an appraisal of the Australian biomass resources and their potential electricity generation projected to 2020 and 2050 [74]. According to this report the quantity of bagasse, landfill gas, MSW and forest residue available is 5, 9.46, 3.49 and 8.8 Mt/year, respectively [74]. It should be noted that it is not clear what sustainability criteria were used in the CEC Bioenergy Roadmap report to estimate the availability of biomass. Organic residues are perceived to

Conclusion

Australia will benefit from global mitigation of greenhouse gas emissions given that it is a relatively hot and arid country that in the future could be subject to adverse climate changes, including more bushfires and greater water scarcity. In recognition of this, Australia is among the countries which signed the Paris Agreement in 2015. Having significant resources of organic waste for bioenergy production and the accumulated practical knowledge through ongoing carbon capture and storage

Acknowledgement

Nasim Pour acknowledges scholarship support provided by Peter Cook Centre for CCS Research at the University of Melbourne.

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