Pumped and Waste Heat Technologies in a High-Efficiency Sustainable Energy Future

Pumped and Waste Heat Technologies in a High-Efficiency Sustainable Energy Future

C.N. Markides*

Dr Christos N. Markides, Imperial College London, collaborates with the European Energy Centre (EEC) and is the author of the below article entitled:

Christos N. Markides, The role of pumped and waste heat technologies in a high-efficiency sustainable energy future for the UK, Applied Thermal Engineering, Volume 53, Issue 2, 2 May 2013, Pages 197-209.

http://dx.doi.org/10.1016/j.applthermaleng.2012.02.037 (http://www.sciencedirect.com/science/article/pii/S1359431112001330)

Department of Chemical Engineering,ImperialCollege, South Kensington Campus,LondonSW7 2AZ,UK

*Corresponding author. Email: This email address is being protected from spambots. You need JavaScript enabled to view it. ; Tel. +44 (0)20 759 41601; Fax. +44 (0)20 759 45700

Abstract

This paper begins with a brief review and discussion of a variety of solutions that are being proposed currently for the provision of a sustainable energy landscape in theUK. An overview of the current supply and consumption of primary energy for heat and power is presented, as are the economics and global energy provision characteristics of various renewable systems in comparison to fossil fuel equivalents. Clean coal, wind and solar are mentioned briefly. Placed in this context, the study then focuses on the role of pumped heat, CHP schemes, and a range of options for the recovery and conversion of waste heat into useful work, all of which have a high potential for creating a ‘high-efficiency sustainable energy future’. It is concluded that although the problem is complex, the costs of relevant competing technologies are not prohibitive and not far from conventional options. Unfortunately, these costs are also comparable across the different options, leading to an inability to make a decisive choice and delaying further progress. CHP and pumped heat are found to be similar in terms of overall efficiency, with the load factor (heat-to-power demand ratio) being of critical importance. In addition, the various waste heat systems are also found to be similar in terms of efficiency per unit cost, which is highlighted herein as the key techno-economic performance indicator.

Keywords energy efficiency; low grade heat; waste heat; heat engines; heat pumps; heat and power 

1 Introduction

In this section the case is made for a high-efficiency sustainable energy future, from an environmental, health, economic and security perspective. This leads, in Section 2, to an overview of a wide range of technologies that are being considered as viable means for the provision of such an energy landscape.

1.1 Fossil fuels, combustion and energy

Mankind has been burning fossil fuels for light, heat and power for a very long time, and for good reason. On combustion, fossil fuels release substantial amounts of heat at high temperature and are thus associated with high energy and exergy densities. The latter in particular makes them ideal candidates for use in heat engines for the production of power, whether this is motion or electricity, since the efficiency of any such device will increase with the temperature of the available heat source. Fossil fuels are and will remain the most important energy carrier over the next few decades. In theUK, oil, gas and coal accounted collectively for 90% of all the consumed primary fuel sources (including fossil, nuclear, wind, hydro- and imported electricity) in 2009.

Fossil fuels were also responsible for approximately 75% of the electricity generated in 2008 and 2009 [1]. Yet, along with high-grade (temperature) heat, combustion flames produce gases including oxides of carbon (COx), nitrogen (NOx) and sulphur (SOx), as well as water vapour. Imperfect combustion also produces unburnt hydrocarbons (UHC) and particulate matter (PM) such as soot. Increasing attention is being paid to these emissions and their possible effects on human health and the Earth’s climate [2].

1.2 Emissions, climate change and health effects

Water vapour (H2O), carbon dioxide (CO2), nitrous oxide (N2O), methane (CH4) and ozone (O3) are considered to be the primary greenhouse gases (GHGs) in the Earth’s atmosphere [2,3]. Considerable interest is being shown in CO2 in particular and a variety of ‘decarbonised’ strategies that would promote the reduction of CO2 emissions over the next few decades are being considered. According to the Department of Energy and Climate Change [4], if one excludes H2O, CO2 accounts for >99% of the weight and ~85% of the global warming potential of all GHGs. So it is possible to refer to GHG and CO2 emissions interchangeably, though the significance of excluding H2O is recognised and noted.

A hypothetical roadmap for the worldwide curbing of CO2 emissions with estimated contributions from various practices and technologies has been published by the International Energy Agency (IEA) [5]. The UK Government has made a legally binding international commitment directly with respect to total GHG (and hence CO2) emissions, currently (2009 figures) at 570 Mt CO2 (and 470 Mt CO2) [4]. In 1997, it adopted theKyotoprotocol to cut GHG emissions by 12.5% below 1990 levels (780 Mt CO2 [4,6]) by 2008-12. Subsequently, in the Climate Change Act of 2008 it pledged to cut emissions by 80% relative to 1990 levels by 2050 and by at least 34% by 2020, though GHG/CO2 emissions had already dropped by 20%/11% between 1990 and 2008 [4], in line with Kyoto. The IEA observes however that “Current energy and CO2 trends run directly counter to the repeated warnings sent by the United Nations Intergovernmental Panel on Climate Change (IPCC), which concludes tha reductions of at least 50% in global CO2 emissions compared to 2000 levels will need to be achieved by 2050 to limit the long-term global average temperature rise to between 2.0 °C and 2.4 °C” [5]. It proceeds to note that “Recent studies suggest that climate change is occurring even faster than previously expected and that even the ‘50% by 2050’ goal may be inadequate to prevent dangerous climate change”.

In addition, beyond the possible contribution of the release of combustion products to the greenhouse effect, NOx and SOx emissions have been associated with other aspects of climate change, such as acid rain, while air pollution from PM, aerosols and even O3 have been linked to adverse human health effects. Specifically for instance, PM has been implicated in damage to the heart and lungs [7].

1.3 Sustainability and economics

At the same time finite resources of oil and gas, but also of coal (theUKis already a net importer of all three), demand the identification and implementation of more sustainable (i.e. in this context, long term) energy solutions. Declining reserves will lead eventually to escalating energy prices and increased propensity for economic slow-downs, recessions and even depressions [8,9], as well as issues related to energy security when the commodities become scarce and need to be imported to cover demand. In fact, domestic electricity costs in both the UK and the EU have shown an increase by a factor of 1.9 in the last decade, while industrial sector costs have increased by 2.4 and 2.9, respectively [10,11].

Rising electricity prices, together with a growing public acceptance and even demand for Government regulation to address sustainable development, environmental and health concerns, fuel economy and energy security issues are acting, and will continue to act, as major and intensifying drivers for the widespread application of energy efficiency schemes and the utilisation of alternative energy sources to fossil fuels. TheUK has already signed up to the EU Renewable Energy Directive, which includes aUKtarget of 15% of energy from renewables by 2020, a seven-fold increase inUKrenewable energy consumption relative to 2008 levels. One may argue that selfregulation market forces, due to scarcity of supply and increasing demand for energy and fossil fuels, will lead away from a globalised world that favours low-cost labour, towards local economies that favour low-cost transportation and energy usage [8,9]. Or, perhaps, a sustainable future will arise as a consequence of public opinion, or on the basis of national security or economic competitiveness. This paper discusses techno economically feasible solutions and systems that will be required to deliver a ‘high-efficiency, sustainable (and hence also decarbonised) energy future’, irrespective of the underlying forces that might give rise to it.

2 High-efficiency sustainable energy futures

Having established the drivers for a high-efficiency sustainable energy future the aim here is to present relevant technologies. As our starting point we consider options that coincide with those in MacKay [12]. These are presented briefly before a shortlist is made that will be discussed in detail in Sections 3 and 4.

2.1 Energy options and combinations

It is important to recognise the great uncertainty in the ever-expanding dialogue concerning the pros and cons of various energy futures. The excellent book by MacKay [12] has been an invaluable contribution to this discussion in the area of energy and efficiency, by pointing out the importance of quantifying realistically the benefits and potential of competing technologies. MacKay focuses on the combined domestic/residential and transport sectors in theUK and this can be justified on the basis that 65% of total consumed energy is used up in these two sectors [1]. The present paper is a simple, complementary analysis to that of MacKay, concerned with the direct comparison of specific energy solutions and systems that address the issues raised above. The starting points for the present study are the five plans for the future supply of energy in the UK that appear in the book, repeated here in Figure 1.

 

Figure 1: Five plans for future energy supply in the UK proposed by MacKay, taken from Ref. [12]

2.2 Generation, supply and consumption framework

Two opposing hypothetical scenarios are imagined in the context of energy provision: a ‘centralised’ scenario in which electricity and possibly heat would be produced at large point sources/plants and distributed via a grid to the domestic level; and a ‘decentralised’ one in which distributed individual energy units would aim to become self-sufficient with respect to heat and power, via cogeneration or other means. In effect, the former is a decarbonised upgrade of the present situation, plus (potentially) district heating.

Electricity and also (possibly) heat are produced by renewables, or otherwise, at large point sources/plants and distributed via a grid out to the end-users. The decentralised scenario describes an approach that is conceptually exactly opposite to this, with distributed generation matching demand. Heat and power (electricity) are produced at the level of a household, a group of households, a large building (school, hospital, etc.), a small community, or even a small ‘energy farm’.

A realistic energy solution is sought for heat and electricity provision that is ‘sustainable’ (i.e. long term) and decarbonised. In this sense, even though its characterisation as a ‘sustainable’ energy source is debatable, the nuclear option is not rejected. In Figure 1 one can identify 8 potential sources; in order of potential [12]: (1) nuclear; (2) wind; (3) solar (solar thermal and photovoltaic-PV); (4) clean coal; (5) pumped heat; (6) waste/biomass (wood, biofuels, biogas); (7) tide/wave; and (8) hydroelectricity. Waste/biomass, tides/waves and hydroelectricity (and also geothermal) are not considered further here, on the grounds of reduced capacity for the provision of the total required energy in theUK. In Ref. [12] a generous application of these solutions, allocated a collective potential towards meeting the required total energy demand of only 15-20% from all of these sources together. It is emphasised that this does not imply that hydroelectricity, for example, is to be rejected. On the contrary, it should be harnessed wherever and whenever this is possible. However, it is simply the case that the potential of this source to provide a significant fraction of the overall UK’s national energy need is limited.

2.3 Renewable versus conventional energy option costs

The levelised electricity cost (LEC) includes all aspects of the initial investment, the capital costs, the fuel cost, operations and maintenance costs over the complete lifetime of the system, usually specified as being between 20-30 years (or up to 40 for solar thermal), as well as the capacity or load factor/duty of the system.

The LEC studies by Lazard [13] and Emerging Energy Research (EER) [14] (Figure 2) paint a similar picture, as do the 2010 global study by the International Energy Agency [15] and UK-specific studies by Parsons Brinckerhoff [16] and Mott MacDonald [17] (Figure 3), and others.

Figure 2: Top: US-based LEC (light blue) with fuel price sensitivity (dark blue) study by Lazard in 2008 [13].

Bottom: US- and EU-based LEC (left) and predicted cost evolution (right); study by EER in 2010 [14]

An inspection of Figs. 2 and 3, while noting that deviations between sources [13-18] often amount to 20-40% (sometimes 50-60% in projected LECs), reveals that: (i) the LEC for most technologies (conventional or renewable) is, even now, to a great extent comparable, with the possible exception of tidal and crystalline PV; and (ii) there is general agreement that renewables are on a decreasing cost curve, while non-renewables are on an increasing one, with grid parity expected in the next 5-20 years depending on the technology. Taking a figure of £100/MWh (±20-40%) as indicative, the supply of theUK’s total current electricity need (350 TWh/year [19]) over 20 years is associated with a total cost of £700 Bn, or £35 Bn per year for 20 years. This represents 5% of annual Government spending and 80% of the £850 Bn official direct bank bailout cost.

Figure 3(a): UK LEC (p/kWh) for  various electricity technologies (legend from left), taken from Ref. [16]

  Figure 3(b): Predicted LEC (£/MWh=0.1p/kWh)                                       evolution in the UK, taken from Ref. [17]


2.4 Clean coal

The Coal Authority, the UK regulatory body responsible for the licensing of coal mines and owner of the vast majority of coal and coal mines, has indicated that “in 2005 coal resources at existing deep mines and existing, planned and known potential surface mining sites were in the order of 900 million tonnes” [20]. In addition, it states that “recoverable tonnages considered to be potentially available from new or expanded deep-mining operations amounted to almost 1.4 billion tonnes”. If we take a generous figure of 5 billion tonnes of coal and a 1.9 MWh/ton conversion based on coal-fired power plants with 40% thermal efficiency and 10% point efficiency penalty to carbon capture and storage (CCS) [21], the total reserves represent 25-30 years of the UK’s need in electricity at current demand, i.e. ~350 TWh per year (average over the period 2005-08 [19]). This demand accounts for 18% of the total current energy use in the UK [1]. For higher efficiency (up to 2.4 kWh/kg [21]) advanced clean coal technologies based on supercritical coal (SCC) power plants with CCS, this figure improves to ~35 years. However, these results would be reduced by any growth leading to greater consumption.

It is possible to suggest that clean coal would not replace all fossil fuel powered electricity generation, which then leaves a question mark concerning the supply of the remaining required oil and/or gas. Nevertheless, even if coal covered as little as 50% of the current fossil fuel electricity share (currently at 16% [1]), provisions would only stretch to about 50-55 years for the case of non-SCC with CCS. This “stop-gap” role of clean coal has also been identified by MacKay [12]. Yet it is also likely that road transport (responsible for 70% of all transport, and 25% of the total current energy use [1]) will evolve to displace internal combustion engines (ICEs) and to embrace technologies that require an additional supply of electricity, either directly such as in battery electric vehicles (BEVs), or indirectly through an intermediate vector such as hydrogen (H2), as in fuel cell electric vehicles (FCEVs) or otherwise. Even with a modest 50% market penetration, coal provisions fall back down to 25-30 years. Hence, there exist non-trivial energetic grounds to reflect carefully a move to clean coal. Further, the LEC from renewables is expected to become comparable to that of clean coal as early as the coming decade (see Section 2.3), while coal has much higher GHG emissions even with CCS (~3-10× at 150-250 gCO2/kWh), mainly due to the processes of mining and coal supply [22]. Returning to Section 2.2 andFigure 1 we retain: onshore/offshore wind, solar thermal and PV, pumped heat and possibly nuclear.

2.5 Wind and solar energy

Wind energy appears consistently as one of the cheapest renewable options, but with a UK load factor of~30% [23] the management of transient wind-generated electricity requires farm over-capacity or loadlevelling (e.g. in Figure 3(a) by oil-firing in open cycle gas turbine-OCGT plants [16]). Depending on the action this can increase the cost and emissions, or decrease the total energy supply potential per unit area. In fact, wind’s load factor profile is considerably worse than that of solar where daytime generation more closely matches the demand (although in theUKthis remains sub-optimal, as discussed in the next paragraph) and thermal storage can be made available more readily [24,25]. In the future, load factor variations may be overcome with electricity storage schemes (pumped thermal [26] or other [27]), but these are still under development. Wind remains a serious energy option for theUKand can deliver a reasonable part of the total energy demand, as part of a mix of technologies.

We turn now to solar energy (thermal and PV). It is important to realise from Figs. 2 and 4 that concentrating solar thermal (CST) systems are basically either on par or slightly cheaper than PV (both in the range ~£100-200/MWh [14,18,28]) and have an edge in terms of efficiency [14,24,25]. Cradle from the solar options are also comparable, with CST again (perhaps) having a small lead. A brief meta over a number of sources [29-33] gives, for PV: thin-film CdTe 18-67 g, Si 32-104 g; and for CST: trough 14-90g, receiver 21-60 g, dish 22-58 gCO2/kWh. Furthermore, unlike PV, large-scale (>100 MW) CST installations have been in operation since the mid-80s, while up to 15-hr heat storage can be provide for demand matching and load factor enhancement at a fraction of the cost of batteries [18,24,25]. Thin concentrator PV show promise in either LEC, efficiency or GHGs, but gains in one aspect typically lead to losses in another, while improvements to the estimated values are often well within the bounds of their uncertainty.

 

Figure 4(a): Comparison of typical efficiencies, taken from Ref. [14]

Unfortunately, seasonal characteristics of solar intensity in the UKare not favourable for these technologies, even excluding climatic conditions (cloud coverage). The daily load factor varies strongly between summer and winter, with peak demand at 6 pm in January when solar intensity is almost zero. Therefore, solar electricity is considerably more expensive than predictions from generic LEC studies and often does not even appear in UKspecific studies (e.g. see Fig is the author’s opinion that imported large-scale solar option for theUK [12,34,35], along the lines of the current DESERTEC proposal [34-36]

This involves a network of CST and to lesser extent PV systems and wind farms, and a high transmission grid capable of providing Europe with up to 15% of its need in electricity. Projected LECs should be in the range €80-200/MWh to begin with, falling with time [34-36], but the large scale of the project leads to a considerable total cost of €500 Bn. This project is, nevertheless, not without its challenges.

Having presented briefly a number of relevant options, it is possible to conclude that a high sustainable UK energy landscape could include a mix of wind, pumped heat and (possibly) and nuclear. Thus, pumped heat, but also combined heat and power (CHP) and waste heat recovery for overall efficiency improvement and primary energy usage minimisation are key solutions for the provision of heating and power. Section 3 below examines specifically the role of CHP and pumped heat, while Section 4 discusses the scope for recovery and conversion of waste heat to power.

3 Heating: central heating boilers, CHP and heat pumps

Current heat-to-electricity consumption ratios (H/E) in the domestic/residential sector areof the order of 4. As such, heating is a major energy sink in theUKin need of attention. The purpose here is to propose actions beyond simple energy efficiency schemes (thermal insulation, etc.) that certainly need to be employed. In particular we consider central heating boilers, comined heat and power (CHP) and heat pumps. The combustion of natural gas in boilers for domestic heating is, thermodynamically, a pure waste of exergy. Nevertheless it is examined, in conjunction with power plants for the provision of both heat and power. With regards to the other two options, it was suggested in Ref. [12] that heat pumps have an edge of CHP plants and by extension smaller, distributed micro-CHP unites for heat provision. Let us consider this more closely.

In Figure 5(a), following Ref. [12], the thick line shows the current best achievable heat and electrical efficiency, involving a mix of heat from a high-efficiency condensing boiler (fuel-to-heat conversion 95%) and electricity from a high-efficiency CCGT plant (fuel-to-electricity conversion 50%; including a 7-9% point electricity transmission loss, averaged over the period 1980-2000 [39]). The dashed lines denoted by ‘H/E’ enclose the region H/E = 3.5-5.3. The dashed ‘HP’ line shows the current best heat and electrical efficiency that can be achieved with a mix of heat from heat pumps with a coefficient of performance (COP) of 4 (electricity-to-heat conversion 400%) and electricity from CCGT plants. The ‘CHP’ lines show the performance of CHP after deducting a 10% heat and 8% point electricity transmission loss. The open circles were obtained for a hypothetical steam cycle CHP plant with a boiler temperature and pressure of 550 °C and 100-150 bar, respectively, and a gradual increase in the heat rejection temperature from 60 to 120 °C. The maximum electrical efficiency of this plant is 35% (27% after the losses), when rejecting heat at 60 °C. Note that this is 15% points lower than that used above in the CCGT/heat pump scenario. This operating point has the lowest H/E, so an overcapacity with respect to the demanded heat would lead to heat being rejected to the environment (indicated by the vertical line). The filled circles are for actual CHP plants and studies by the Carbon Trust [12]. The dashed line is an extrapolation from the hypothetical CHP plant. The fact that it passes through all points implies that a reasonable ‘total efficiency’ (heat plus electrical) for CHP is about 80%.

 

Figure 5(a): Basic steam cycle CHP scheme and comparison with ‘best CCGT’ pumped heat

Figure 5(b): Contribution of high-efficiency steam cycles to both CHP and pumped heat schemes

Now, if we look at the performance of these solutions in the region between the dashed ‘H/E’ lines we observe that the heat pump/CCGT combination has a higher total efficiency (~125%) than the current best and CHP solutions (both ~80%; dashed circle). However, a decarbonised future will have two effects: (i) a reduced maximum possible electrical efficiency (a move away from CCGT); and (ii) a replacement of ICE vehicles with electric alternatives, such that the H/E consumption ratio could drop as low as 0.5-0.8. This shifts the H/E operation regime (solid ‘H/E’ lines) and the heat pump/power combination performance (solid ‘HP’ line) to a total efficiency of ~45% (solid circle). Clearly, the two solutions are now almost identical. Proceeding further, Figure 5(b) addresses the potential improvements from a higher efficiency electricity generation process. A 45% efficient electrical power plant would improve both the heat pump and the CHP to operating points within the required H/E operation regime with a total efficiency of ~65%, and that the two solutions remain identical. Hence, the incentive for maximising efficiency is substantial and independent of the solution employed for heat provision.

4 Energy efficiency through waste heat conversion

It was stated in Section 1.1 that fossil fuels account for 90% of all consumed primary energy supplies in theUK. They also account for 80% of all energy consumption [1]. With renewables amounting currently to only a few % points of the same energy supply and consumption, high-efficiency energy solutions will be a necessity if a real impact is to be made in decarbonising the energy landscape. In the interim, increased efficiency will allow current fossil fuel supplies to last for longer, thus proving a time buffer necessary for the development and deployment of this desired future energy infrastructure. According to the IEA [5]: (i) the largest opportunity for emission reductions comes from improved efficiency, which encompasses end-use fuel and electricity efficiency, as well as power generation efficiency, accounting for about 60% of the overall possible reductions; and (ii) renewables have as much potential as CCS schemes, with each of these two having one third of the potential for emission reductions compared to that of improved efficiency. Clearly, a sustainable and decarbonised energy future is synonymous with a high-efficiency energy future, whichever energy scenario emerges.

The term ‘high efficiency’ has several implications with regards to waste heat. Heat recovery and re-use to displace fossil fuel burning for heating where possible is by far a better use of waste heat compared to conversion to power. This arises due to the low thermal efficiencies associated with the conversion of low temperature heat (20% at best; see Table 1). Yet, as stated above, the purpose here is to propose options beyond passive energy (heat) efficiency schemes (e.g. thermal insulation), or end-use energy (heat) reuse or minimisation: (i) bottoming cycles that recover heat rejected from power-producing systems, for increased overall efficiency; or (ii) standalone systems for waste heat conversion to useful work, either fluid pumping (circulation or compression) or electrical power. Suitable systems employ a wide array of technologies based, amongst other, on: (i) subcritical, ‘modified’ and supercritical Rankine or Kalina cycles; or (ii) gas-phase thermoacoustic, Stirling-based and two-phase equivalent cycles.

Thermoelectric generators (TEGs) that convert heat directly into electrical energy by using the Seebeck effect are not considered here. TEGs are compact, simple and have long lifetimes, but also have lower efficiencies than thermodynamic heat engines and higher costs in large systems, restricting their employment to specific small-scale applications. TEGs are being developed in the automotive sector for the conversion of waste heat from IC engines (exhaust gas and cooling water) [40]. Typical current thermal ηth and exergetic efficiencies ηex when using heat at 200-250 °C are about 5-6% and ~15%, respectively.

A major advantage of waste heat conversion systems arises from the easy access to and abundant availability of waste heat, leading to low operating expenses. Low-grade heat, i.e. heat at ‘low’ temperature (with respect to the original process from which the heat was rejected), is rejected to the environment in vast quantities from a host of power generating and other industrial applications, and even domestic settings. Unfortunately, the conversion of this low-exergy heat to additional useful power (electricity or otherwise) with the use of appropriate heat engines is inevitably associated with low thermodynamic efficiencies. Their usefulness and wider deployment are thus highly dependent upon minimising the capital expense associated with their installation, and the achievement of high efficiencies per unit cost and power densities for rapid cost payback. This is especially true for devices that are capable of operating with marginal energy sources and close to ambient temperatures.

4.1 Heat supply and removal stream matching

Consider Figure 6(a), in which T-S diagrams of standard subcritical ORC (dark), supercritical (SC-) ORC (light) and Kalina cycles (medium shading) are overlaid; both ‘dry’ (solid) and ‘wet’ (dashed) working fluids are shown. These cycles have been targeted for use primarily with geothermal heat, heat from biomass, and to a lesser extent waste heat (mostly from IC engines). Neglecting irreversibilities, the area within each cycle represents the net heat flow into each cycle, which is also equal to the net work produced by that cycle. Hence, there is an incentive to maximise this area. The arrow from right to left represents the waste heat stream from which heat is extracted as this is taken up by the cycle, and as such represents a limitation to the area of the cycle that must remain at all times below this curve by at least 5-10 °C. The point at which the cycle and the curve are closest is the well-known ‘pinch point’. It is clear that matching the cycle diagram to the evolving temperature of the waste stream from which the heat is recovered is a crucial issue for the efficient utilisation of this heat, which identifies the potential advantages that SC-ORC and Kalina cycles have over the standard ORC. Figure 6(b) indicates another important point. As well as matching a varying heat source temperature, it may also be that the heat sink temperature varies as heat from the cycle is rejected to the cooling stream. TFOs (see Section 4.2), dry-fluids and reheating with regeneration can go some way towards taking advantage of this process. Since the exergetic ηex ≡ ηth/ηMAX is a key and often-quoted thermodynamic performance indicator that compares the actual ηth to the best attainable ηMAX, it is important to investigate ηMAX.

 

Figure 6(a): Waste heat supply stream matching: subcritical and supercritical ORC, and Kalina cycle

Figure 6(b): Waste heat supply and removal stream matching: subcritical ORC and two-phase TFO cycle


Figure 6(c): Effect of heat source cooling and sink heating on maximum cycle efficiency, Tcold,in = 25 °C

Figure 6(d): Effect of heat source cooling and sink heating on maximum cycle power, Tcold,in = 25 °C

Figs. 6(c) and (d) show the effects of a decreasing heat source temperature Thot and an increasing heat sink temperature Tcold on the maximum theoretical thermal ηMAX and output work Wnet of an ideal cycle, respectively. In Figure 6(c) the Carnot ηth (top surface) is shown for constant temperature hot/cold reservoirs.

The other two surfaces are calculated by integrating over an infinite array of infinitesimal Carnot engines operating between changing source Thot and sink Tcold, with a source temperature drop parameter or ‘heat fraction’ θ. Assuming equal heat duties (mcp) for both streams for simplicity, gives,

ηMAX = 1 – f/_Thot ; Wnet = ηMAX mcp _Thot , where _Thot = θ Thot,in , and;

f = –Tcold,in ln(1 – θ) for _Thot > 0 and _Tcold = 0; f = _Tcold = Tcold,in θ/(1 – θ) for _Thot > 0 and _Tcold > 0

[1]

At a given hot temperature supply Thot,in, ηMAX decreases with θ, as Wnet increases (except at low Thot,in), revealing a central optimisation problem in the design of these systems. Hence, working fluid selection and careful matching to the available heat source and sink are crucial to the ultimate performance of these systems, as is the design of the heat exchangers required to operate over the small temperature differences, component (pumps, turbines, etc.) performance and materials compatibility. Conventional ORC systems [41,42] are relatively established and commercially available (0.5 to a few MW). GE and Pratt & Whitney have entered the waste heat market and systems have been in operation successfully for many years. Capital costs amount to £1.5-4/W (£15-35/MWe over 25 yrs) with 10-20 yrs for payback. Referring to Table 1, standard operation from 100-300 °C heat gives ηth = 8-20% and ηex = 25-45%. SC-ORCs [42-44] can reach ηth = 10-25% and ηex = 30-50% over the same temperature range, but the high pressures result in higher LEC of £25-40/MWe over a 20-yr life.

For an ammonia- water Kalina system operating between ~500 °C and 70-100 °C, a ηth of 30-35% and corresponding ηex of 50-60% have been predicted [45], while a low-temperature (90-150 °C) geothermal heatpowered plant is now capable of 15/35% [46]. Typically [47-49], we would expect to operate with heat in the low-to-medium 100-200 °C range and 10-20/40-50% efficiencies. Special materials are needed to deal with corrosion and added components lead to increased system complexity. Still, capital investment is modest at £1.5-2.5/W (£15-25/MWe over 25 yrs) with an 8-18 yr payback depending on plant size, but higher maintenance is expected than for the ORC which is more common and generally better known. 

4.2 Two-phase thermofluidic oscillators

Thermofluidic oscillators (TFOs) include devices such as thermoacoustic engines [50-52], dry free-liquidpiston (Fluidyne) engines and free-pistonStirlingengines [53-58], pulse-jets and pulse-tubes [59-61] that are particularly well-suited to the conversion of low-grade heat. In effect, TFOs exchange construction simplicity for operation simplicity. They consist of a network of interconnected chambers and tubes, usually without mechanical moving parts, and sometimes with a liquid piston in place of a mechanical displacer. However, within this very simple layout, fluids are subjected to complex time-varying flow and heat transfer processes, driven by the working fluid as it undergoes a thermodynamic cycle. TFOs have many dynamic similarities with analogue electronic oscillator circuits, and thus, electrical analogies have been used to predict approximate stability/instability criteria and to estimate first order heat and work flows, and efficiencies (e.g. [50,52,59]).

Their complicated operating nature has meant that analysis and design has proved challenging, but modern computational methods, rapid prototyping techniques, advances in materials and working fluids are allowing significant progress to be made. Two-phase thermofluidic oscillators, if designed properly, can have advantages over gas cycle equivalents because phase change allows smaller surface areas (Ahx) and temperature differences (_T) to drive the heat supply/removal (Q) required by the cycle. This conclusion arises from the higher heat transfer coefficients (h) associated with phase change (by orders of magnitude) relative to that of forced convection between a gas a solid surface, Q = hAhx _T. Smaller surface areas lead to compact heat exchangers, with simpler designs not requiring the extensive use of fins. Since heat exchangers are the most expensive components of these devices, this has a great effect on reducing the overall cost. A promising low-grade heat conversion technology that has attracted attention recently as a result of potential reliability advantages as well as reduced capital and maintenance costs, on account of its few moving parts relative to mechanical heat engines, is the NIFTE as proposed in Refs. [62,63]. The NIFTE is as a two-phase TFO in which persistent and reliable thermodynamic oscillations are generated and sustained by external temperature differences _Te. These oscillations are driven by and give rise to heat and fluid flows, which involve the evaporation and condensation of the working fluid. The NIFTE can produce useful hydraulic work for fluid pumping, heating and/or cooling and niche power generation applications; in a variety of solar thermal and energy recovery settings, and in combined heat and power/pumping schemes. It has been demonstrated as being capable of operating across _Te between a heat source and sink down to 30 K. At these low temperatures, ηex = 5% has been reported [62,63], while projections from recent modelling studies [64,65] indicate that, with careful design, the potential exists for considerable improvements to be made, with operation possible at _Te as low as 10 K. Performance characteristics are summarised in Table 1, the main conclusion being that there is not a great deal of difference between the various options per unit cost.

 

Table 1: Comparison of typical performance characteristics of waste heat technologies (ηex based on Carnot)Technology ηth ηex Thot,in (Tcold,in = 10-30 °C) Relative Cost Organic Rankine Cycles (ORC) [41,42] 8-20% 25-45% 100-300 °C Intermediate Supercritical (SC-) ORC[42-44] 10-25% 30-50% 100-300 °C High Kalina Cycles [45-49] 10-20% 40-50% 100-200 °C Intermediate Thermofluidic oscillators (TFO) [62-65] 1-5% 5-20% 30-150 °C Low

5 Further discussion and conclusions

It is acknowledged that the Government has shown sensitivity towards energy issues [1,4] and made noteworthy steps in a variety of directions over the last decade [21,39,66]. However, although a sense of purpose permeates public discourse on these matters and at least from the societal point of view the desire is generally present, arising from a variety of motives, Government and industry have yet to embrace and to commit firmly and consistently to a specific energy solution [24]. The industrial sector alone is a ~60% contributor to all emissions (the transport sector is at 20-22% and the residential sector at 14%) [4] and also a ~30% contributor to all primary energy use (with transport at 37% and domestic use at 28%) [1]. Instead, the status quo has been to keep the discussion concerning the multitude of options alive and to drift by uncertainty or inaction towards a diverse, but unknown energy landscape. Though energy diversity and decentralisation is desirable and will emerge naturally to some extent, led by end-users and market forces, it cannot be relied upon for the bulk of the change that is required if a sustainable energy future is to be attained. A shift is required in which the Government must lead the way with a careful mix of incentives, but more importantly taxation, including breaks, as necessary. The cost of alternative energy is either competitive to fossil fuels or expected to become so, soon. Investment in R&D and embracing any technology on a large scale will shorten this timescale.

And, although technical improvements are possible, many technologies are mature and ready to be implemented. At this stage progress is being held up by an inability to decide on a particular (mix) of energy solution(s) and to take action, perhaps because the ultimate differences between competing technologies are small and of the order of their estimated potential and cost [16,17,23]. Considering the time-lag required by the EPC process, a coherent energy vision based on sound techno-economic principles must be defined and offered to the public for consultation soon if the ambitious targets we have set ourselves are to be met.

Acknowledgement

The author would like to acknowledge Dr Thomas C.B. Smith (UniversityofOxford) for bringing this topic to his attention, Dr Alexander J. White (UniversityofCambridge) for the stimulating discussions and for his inspiring thoughts, and Moncef Tanfour (Alstom Power) for his generous assistance and continuing support.

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