The global industrial revolution in the late nineteenth century originated in the United Kingdom with coal powering steam engines and iron smelting. Now in the twenty-first century electricity generation by coal is constrained by economics, carbon emission penalties and the availability of cleaner natural gas [49]. Though coal remains the planet’s largest fossil-fuel resource [55] its large-scale utilization is presently incompatible with the pursuit of low carbon emissions. As well as carbon dioxide, other environmentally damaging combustion products [55] include sulfurous oxides and fly ash which contains mercury, arsenic and radioactive uranium and thorium. In fact without fly ash capture equipment, coal-fired stations would contribute signifi­cantly to background radiation. Table 1.5 shows the estimated coal

reserves [53] of all types17 for a number of industrialized countries in 2006-07. It suggests the strong motivation [50] to develop so-called Clean Coal technology for reducing pollutants and achieving fuller combustion by pulverization. Because nitrogenous oxides are produced at combustion temperatures above 1370 °C, temperature control between 760 to 927 °C eliminates these without the need for flue­gas scrubbers [50].

When finely divided limestone is intermixed with pulverized coal, 95% of the sulfurous precursors of acid rain are absorbed: but at the expense of larger carbon dioxide emissions. Present research searches for more suitable sorbants [50] and Carbon Capture processes [54]. By measuring the ratios of stable isotopes of carbon dioxide and noble gases, recent studies of nine gas fields in North America, China and Europe have established that underground water is the principal sink and has been so for millennia [54]. These experiments could provide a basis for validating mathematical models of future storage locations and for tracing captured carbon dioxide. However, on-going capture tests require 25% of the Longannet 2.4 GW station’s output [56] so that an economically viable process has yet to be developed. A sum of £1 billion was allocated for this purpose in the October 2010-UK Spending Review, but was declined by a consortium of Scottish Power, Shell, and National Grid.

Commercial quantities of natural gas were discovered in the North Sea during 1965, and since then in many other countries. Combined cycle gas turbine plants (CCGT) [51] have subsequently had a material impact on new-build generating capacity as illustrated [57] for the United Kingdom in Figure 1.2. In these, gas first powers a gas turbine whose exhaust via a heat exchanger provides steam for a conventional steam turbine with feed water heating and reheat to enhance thermal efficiency. With the lower cost CCGT configuration, an alternator is driven by gas and steam turbines sharing a common shaft, while with the more flexible but more expensive multishaft arrangement, each has its own alternator. Typical burnt-gas and steam-inlet temperatures for CCGT and coal fired plants are

Tccgt ‘ 1000 °C and Troal ‘ 570 °C (1.7)

Anthracite, coking, lignite, and steam.

For an ambient condenser temperature of 30 °C, the corresponding Carnot Efficiencies are derived from equation (1.2) as

hCCGT ‘ 76% and hcoal ‘ 64% (1.8)

but due to thermodynamic irreversibilities, the practical efficiencies achieved are

hCCGT ‘ 50% and hcoal940% (1.9)

The preferential installation of CCGT units shown in Figure 1.2 is now clear. Because investment in a privatized market is governed by a commensurate return on capital expenditure and associated risks, and because UKelectricity prices are set by those for CCGT generation [52] and infrastructure provision, utility companies are assured a fair and timely low-risk return. During 2011 CCGT stations delivered around 44% of the UK electricity: but what of the future?

With the reduction in North Sea gas production, the United Kingdom has now become a net importer and is therefore potentially beholden to the vagaries of international markets or the political whims of some exporters. Accordingly coal-bed methane, shale and conven­tionally drilled gas production are being actively investigated to regain a self-sufficient supply. Hydraulic fracturing [323] or “fracking” is particularly successful in speeding up gas flow rates from shale or other “tight” reservoirs to render them economical. This technology

involves unconventional horizontal drilling along a promising shale strata followed by the injection of high-pressure water and chemicals. The process has transformed US gas production from next to zero in 2000 to an almost self-sufficient 13.4 billion cubic feet per day. Cuadrilla Resources plc claims to have discovered a potential 200 trillion cubic-feet shale gas reservoir in the northwest of England, and the British Geological Survey suggests a total onshore resource of some 1000 trillion cubic-feet. However, test drillings have elicited small earth tremors[13] at Blackpool and there are further concerns regarding the contamination of drinking water supplies. Consequently commercial development has been halted until the Department of Energy and Climate Change has completed a review. Even if an abundance of onshore gas becomes available, a detailed study [57] reveals that CCGT generation alone could not fill the UK energy gap within the ratified carbon emission targets [1,52], so that a nuclear component appears as the necessary reliable complement in the eventual “mix” of generating stations. To achieve an economical fuel cycle (burn-up) and the inter­vention of safety circuits nuclear stations must supply the more slowly varying and largely predictable national base load.[14] Accordingly CCGT plants with preferably Lamont boilers [117] are better able to provide the more flexible and faster responses to rapid unscheduled changes in Grid power demand.

Sizeable UK oil-fired power stations like Poole and Marchwood were decommissioned over 10 years ago, but a number of small (<10MW) units still exist to buffer unexpected peaks in national demand. These relatively low thermal efficiency, but highly responsive “peak lopping” units presently contribute around 1% of national energy consumption [49].