WO2010088724A1

WO2010088724A1 - Electrical power generation system

Info

Publication number: WO2010088724A1
Application number: PCT/AU2010/000107
Authority: WO
Inventors: Petar Branko Atanackovic; John Charles Ellice-Flint
Original assignee: Applied Hybrid Energy Pty Ltd
Priority date: 2009-02-04
Filing date: 2010-02-04
Publication date: 2010-08-12
Also published as: AU2009236018B2; AU2009236018A1

Abstract

An electrical power generating system which includes a fossil fuel powered electrical generator (1505) and carbon capture apparatus (1410) associated with the fossil fuel powered electrical generator to capture carbon emissions (1511 ) from the electrical generator. A solar electrical power generating array (400) is located in proximity to the fossil fuel powered electrical generator. The fossil fuel powered electrical generator (1505) and the solar electrical power generating array (400) are for supplying base load electrical power (1510, 1540) over a 24 hour cycle to remotely located consumers. The fossil fuel powered electrical generator (1505) is located in proximity to a source of the fossil fuel (1500) for the captured carbon emissions to be sequestered (1412) within that source, being a source in which the captured carbon emissions are sequesterable. The invention addresses the problem of the fossil fuel reserves existing large distances from the end-user and utilizes advantageously local and distributed solar energy product.

Description

ELECTRICAL POWER GENERATION SYSTEM

Technical Field The present invention relates to an electrical power generating system.

Background

Emissions from fossil fuel powered electrical power generating stations contribute a significant amount of the "greenhouse" gas carbon dioxide (CO₂) to the atmosphere and this gas, according to a majority of current scientific opinion, is driving global climate change. It is therefore desirable to minimise the entry of CO₂ emissions into the atmosphere. Thus "carbon capture" technologies have been developed to capture such CO₂ emissions for sequestration of the captured carbon. However the capture and sequestration of CO₂ emissions add significant costs to the capital requirements and operation of a fossil fuel powered electrical generator. The present invention seeks to provide electrical power generation systems in which some of the costs for carbon capture associated with the system can be offset and thereby minimise CO₂ emissions per fuel usage.

Disclosure of the Invention

According to the present invention, there is provided an electrical power generating system including: a fossil fuel powered electrical generator, carbon capture apparatus associated with the fossil fuel powered electrical generator to capture carbon emissions from the electrical generator, a solar electrical power generating array in proximity to the fossil fuel powered electrical generator, wherein the fossil fuel powered electrical generator and the solar electrical power generating array are for supplying base load electrical power over a 24 hour cycle to remotely located consumers, and wherein the fossil fuel powered electrical generator is located in proximity to a source of the fossil fuel for the captured carbon emissions to be sequestered within that source, being a source in which said captured carbon emissions are sequesterable. Preferably the fossil fuel is natural gas or methane or coal seam gas and the source thereof is a field for production of the gas.

The solar electrical power generating array may be an array of modules, each module in the form of a panel that comprises a substrate for transmission of solar energy on which a multiplicity of photovoltaic cells are formed for converting the solar energy into electrical energy, the panel including at least one capacitor for storing the electrical energy generated by the photovoltaic cells. The solar electrical power generating array may be of a size and capacity as to be capable of producing 20 to 250 MW peak power.

Preferably the fossil fuel is natural gas and portion of the natural gas is transported to the remotely located consumers via a pipeline. This natural gas pipeline may include repeater plants spaced along its length, each repeater plant including a scrubber to remove impurities from the gas and a compressor to pressurise the gas into the next pipeline section. A solar electrical power generating array may be associated with each repeater plant for providing power for operation of the repeater plant for at least a portion of a 24 hour period.

Preferably the solar electrical power generating array that is located in proximity to the fossil fuel powered electrical generator provides power over at least a portion of a 24 hour period for operation of the carbon capture apparatus and/or for the sequestration of the captured carbon emissions.

The electrical power generating system preferably includes a high voltage transmission line for the supply of base load electrical power to the remotely located consumers and preferably the transmission line is for high voltage direct current (HVDC) power transmission.

If the electrical power generating system includes a natural gas pipeline, a HVDC transmission line may be located in proximity and substantially parallel to the gas pipeline. The HVDC transmission line may also be located within the pipeline.

The transmission line may be for hybrid transmission of high voltage direct current (HVDC) and high voltage alternating current (HVAC) power. For example, the HVAC may be superimposed upon the HVDC. Alternatively, the transmission line may include a bi-polar HVDC link and the HVAC may be transmitted on a link between the bi-polar positive and negative DC potentials.

Preferably the electrical power generating system includes a controller for receiving feedback of power demand (either real time or projected) by the remotely located consumers, wherein the controller is operatively associated with the fossil fuel powered electrical generator for altering the proportion of electrical power that is supplied by the fossil fuel powered electrical generator compared to the proportion supplied by the solar electrical power generator array.

The invention also provides an electrical power generating system including: a coal powered electrical generator, carbon capture apparatus associated with the coal powered electrical generator to capture carbon emissions from the electrical generator, a solar electrical power generating array in proximity to the coal powered electrical generator, wherein the coal powered electrical generator and the solar electrical power generating array are for supplying base load electrical power over a 24 hour cycle to remotely located consumers, and wherein the solar electrical power generating array supplies power for operation of the carbon capture apparatus and for forming the captured carbon emissions into environmentally stable products or into a form for transport to a sequestration location.

For a better understanding of the invention and to show how it may be performed, embodiments thereof will now be described, by way of non-limiting example only, with reference to the accompanying drawings.

Brief Description of Drawings

Figure 1 schematically illustrates a process for zero carbon emission power generation, according to an embodiment of the invention. Figure 1 B illustrates carbon and energy flow from the production of coal and natural gas into electrical energy. Figure 2 illustrates economic natural gas field resources distributed across Australia.

Figure 3 shows the yearly average number of hours per day of clear sunlight available across Australia (i.e. an insolation map). Figure 4 illustrates a large scale utility photovoltaic plant.

Figures 5 and 6 show the insolation map of Figure 3 with an optimally located photovoltaic plant as in Figure 4.

Figure 7 illustrates overlapping known natural gas fields with areas of high average annual insolation in Australia. Figure 8 corresponds with Figure 7 but additionally identifies large population centres.

Figure 9 illustrates the most efficient technologies for supplying natural gas to end users as a function of capacity and distance.

Figure 10 generally illustrates a natural or coal seam gas field. Figure 11A illustrates sequestering CO2 in a gas field.

Figure 11 B is a graph illustrating temperature and pressure conditions for sequestering of CO₂ in a gas field.

Figure 12 schematically illustrates a conventional process of natural gas extraction, transportation and end use. Figure 13 schematically illustrates the carbon oxide or dioxide emission of a process as in Figure 12.

Figure 14 schematically illustrates a hybrid natural gas transportation network utilizing renewable energy resources.

Figure 15A schematically illustrates in more detail a zero carbon emission embodiment wherein a gas field and power generation are proximate to each other.

Figure 15B and 15C schematically illustrate further embodiments similar to that of Figure 15A.

Figure 16 schematically illustrates an embodiment of the invention involving the fossil fuels natural gas and coal. Figure 17A is a graph showing a comparison of electrical losses as a function of point to point link distance of equivalent power HVAC and HVDC links.

Figure 17B is a graph showing costs versus distance for equivalent HVAC and HVDC links. Figure 18 shows the potential of integrating HVDC power generation at a gas field with transport via an existing natural gas pipeline.

Figure 19 schematically illustrates integrating HVDC cables with a natural gas pipeline. Figure 20 schematically illustrates an example implementation of power generation in an embodiment according to the invention.

Figures 21 A and 21 B illustrate electrical power transmission methods.

Figure 22 illustrates an electrical power transmission method that integrates HVAC and HVDC. Figure 23 as a graph of power demand versus time to show peak demand relative to a base supply.

Figure 24 illustrates another embodiment of the invention.

Figure 25 illustrates the temporal effect of geographic location of large scale solar power generation plant. Figure 26 illustrates potential benefits of embodiments of the invention.

Detailed Description of Embodiments

Figure 1 schematically discloses a process for zero carbon emission (ZCE) power generation utilizing a fossil fuel 105 and fossil fuel powered generator 109. In preference, fossil fuel type is substantially natural gas (NG) and or hydrogen. Generator 109 is preferably a high efficiency combined cycle gas turbine coupled to an electromechanical generator set. The by-products from post-combustion power generation in module 109 are fed into a carbon capture module 112 and the captured oxides of carbon 114 are sequestered and or formed into environmentally stable and or benign product(s).

A portion of the natural gas 105 collected from the gas field is diverted 106 to the power generation in module 109 and the remainder of the natural gas and or fossil fuel 108 is compressed 116 for transport to gas pipeline transport system 122. The end user 123 is physically located a large distance 120 from both the gas field and the hybrid power generation plant 130. The end user 123 consumes the compressed NG feedstock 126. The electrical power generated by gas-fired module 109 is similarly transported to remote end user via electrical transmission system 121. In preference, the electrical transmission system is of high efficiency and high power capacity HVDC system. Additionally, a renewable energy plant 103 is physically located at the hybrid power plant 130 and or is distributed along the electrical transmission channel. In preference, the renewable energy plant 103 comprises large scale photovoltaic (PV) type capable of producing 20-250MW peak power. Solar powered 101 PV plants may optionally incorporate charge storage for optimizing the PV / Fossil fuel derived electrical power ratio required to meet demand by the end user 123. Electrical power transported by HVDC may require the gas-fired plant 109 to convert AC power from electromechanical generator into HVDC. Conversely, large scale PV plant 103 can be directly configured to provide HVDC output suitable for transport over channel 121. The gas-field and hybrid plant are located in proximity to each other, so that the captured carbon can be sequestered into the gas field, thus producing ZCE plant. The general system described in Fig.1 enables optimization of renewable energy and finite resource fossil fuel for power generation. Base load electrical energy can be delivered to a remote end user with the renewable energy content provided in preference to consuming fossil fuel. In the absence of available renewable energy source (e.g. at night), fossil fuel is used. The hybrid plant 130 therefore functions as optimal peak power plant with zero carbon emission of green house gases (GHGs). This disclosed concept is termed point-of-burn (PoB) technology. It is to be understood that the just described embodiment is adaptable and thus other forms of fossil fuel may be used, such as, oil, syngas, biogas among others. It is also to be understood the electricity transport channel may be chosen from HVDC, HVAC and hybrid HVAC/HVDC depending upon requirements.

An example implementation of the present invention incorporates the opportunistic fossil fuel resources typically geographically located in remote areas and far from end-users. Integrating renewable energy production and carbon capture in the vicinity of the fossil fuel resource enables the production of electrical energy with zero GHG emission. Transportation of the electrical power generated from the generation site to the end user is via optimal low loss transport channel, namely HVDC. It is anticipated that embodiments of the present invention are particularly well suited to remote natural gas fields supplying methane along existing pipelines to distant end users. For example, existing NG pipelines allow straight forward right of way (ROW) infrastructure required for parallel transport of HVDC power. It is further anticipated the HVDC power flow will be one-way from the generation site toward the end user and thus requires only single-mode operation. Only the end user would require DC-to- AC conversion suitable for short haul AC power distribution. Furthermore, utilizing an existing pipeline enables the HVDC cables to be integrated into the physical pipe potentially by threading the insulated HVDC cables inside the NG pipeline. The reliability of the HVDC cables would be considerably increased by environmental protection.

The feasibility of disposing CO2 in exhausted hydrocarbon reservoirs is due to the fact underground withdrawal of fossil fuels can be balanced by CO₂ storage in the subsurface. That is, the consumed fuels via combustion process may be disposed of in the reservoir they came from. It is noted, depending upon the type of fossil fuel consumed in combustion places upper limits on the amount CO₂ that must be sequestered. Fossil fuels predominately contain carbon and hydrogen. Upon combustion carbon dioxide and water are produced, along with other by-products depending on the type of fuel used. Combustion in pure oxygen of natural gas, oil and coal produces the following main reactions:

Case I: Natural Gas

CH₄ + 2O₂ →CO₂ +2H₂O Case II: Fuel Oil

2CH₂ + 3O₂→2CO₂ + 2H₂O Case III: Coal

C + O₂→CO₂

The material balance by weight for each case is: Natural gas:

1kg CH₄ + 4kg O₂→2.75kg CO₂ +2.25kg H₂O Fuel Oil:

1kg CH₂ + 3.43 kg O₂→3.14kg CO₂ + 1.29kg H₂O Coal: 1kg C + 2.67kg O₂→3.67kg CO₂.

The density p under average sequestered reservoir conditions (refer Fig. 11 B) for each case produces: p (Natural gas)=150kg/m³, p (Fuel Oil)=800kg/m³,and p (Coal)=700kg/m³.

The material balance by underground volume for oil and gas (ignoring oxygen and water) can be approximated as: Natural gas:

1m³ CH ₄→0.59m³ CO₂

Fuel Oil:

1m³ CH₂→2.75m³ 3CO₂

Therefore, this simplistic model demonstrates the underground volume of the natural gas extracted can be replaced by the CO2 produced by direct combustion. However, the burning of oil produces a considerably higher volume of CO₂ such that the underground volume of oil extracted is much smaller than the volume that would be occupied by the CO₂ produced.

It is therefore desirable to efficiently capture CO₂ and store it decoupled from the atmosphere as long lived and or permanent products. Capture cost and the associated energy consumption is dependent upon the size of the capture process (tonnes/day). Man-made sources of CO₂ above a rate of ~ 0.1 Mt CO₂/year is primarily due to power generation and is thus the most important emitter, followed by the cement industry, refineries and iron/steel industry. The current trend of increasing demand for power globally, indicates that power plants will be the primary targets for implementation of CO₂ capture. CO₂ has been captured from industrial process streams for over 80 years, however most of the CO₂ that is captured is vented to the atmosphere because there is no incentive or requirement to store it away from the atmosphere. Current examples of CO₂ capture from process streams are purification of natural gas and production of hydrogen-containing synthesis gas for the manufacture of ammonia, alcohols and synthetic liquid fuels. Commercial ready power plant scale CO₂ separation technologies are based on absorption via physical and chemical solvents, membranes using polymeric materials based on ceramics, solid sorbents using zeolites and activated carbon and cryogenic and or distillation processes. An alternative technology utilizes rare-earth based materials, for example, rare-earth carbide and rare-earth oxides to separate CO₂. Historically a large number of electricity producing power stations are coal-fired. The combustion of coal produces more CO2 than can be stored in the space the coal originally came from. If there exists a need to dispose of the CO2 permanently, it may ideally be confined within depleted hydrocarbon reservoirs or a trap or an aquifer directly analogous to the hydrocarbon reservoir. Furthermore, the underground reservoir needs to be a sealed trap to prevent the CO2 from percolating upwards through the water and reaching the surface. Supercritical- liquid CO2 is also lighter than water and must be contained effectively. Hydrocarbon reservoirs offer many advantages over aquifers: (i) exploration costs are zero or limited; (ii) candidate reservoirs exhibit a seal and trap capable of retaining liquids or gases for up to 10⁶ years; (iii) the reservoir properties, such as porosity, permeability, pressure, temperature and overall CO2 storage capacity are known by workers in the field; and (iv) the equipment installed on the surface or underground for oil or gas recovery may be re-used for the carbon dioxide disposal.

Consider the simplified diagrams in Fig. 1 B describing the carbon and energy flow from the production of coal and natural gas directly into electricity generation. Coal is carbonized biomass, and 500kg of carbon in coal contains approximately 18.5GJ primary energy. Furthermore, the energy required to mine coal and deliver it to a power station is similar to that required to produce biomass, per unit of carbon or energy content and can be approximated as 0.5-2.0 GJ. A coal-fired power plant would emit 10-50kgC for every 500kg of carbon (500kgC) in coal combusted. A high performance coal-fired plant has conversion efficiency of coal to electricity -35-40% without any loss due to carbon capture process and may produce 7.4GJ of electricity for every 500kgC in coal consumed. It is noted that for electricity generation, biomass and coal are approximate energy equivalents.

For the case of natural gas, there exits an advantage over coal because CH₄ contains more energy per unit of carbon emitted -15 kgC/GJ. Conversion to electricity is more efficient as direct combustion gas-turbine technology can be utilized providing -50% efficiency for standard technology and up to 65% efficiency for state-of-the-art combined cycle gas-turbine technology. In terms of electrical energy, assuming 50% conversion efficiency a gas-fired plant is capable of producing 16.5GJ of electricity for every equivalent 500kgC in natural gas. Long term, therefore, it is anticipated that natural gas reserves will be exploited in preference to coal due to the higher electricity output potential coupled with the sequestration properties available.

Fundamentally, a majority of fossil fuel resources are located in extreme and or remote regions and distant to the end user location. By way of example, Fig. 2 shows the general areas of economic natural gas field resources 201 -209 distributed across Australia 200.

Figure 3 shows the yearly average number of hours per day of clear sun light available across Australia. The solar insolation map of Fig.3. shows up to 10 hours/day in region 301 , 9 hours/day in region 302, 8 hours/day in region 303, and <7 hours/day in region 304.

Figure 4 describes a general large scale utility photovoltaic plant 400 comprising large area flat plate thin film on glass modules 405. Other types of PV plants such as concentrating systems can equally be utilized. However, charge storage is enabled by using large area glass substrates and integrating capacitive storage. An advantage of thin film on glass PV technology, relative to solar concentrating systems, is the lower sensitivity to clouds 406 obscuring and or diffusing solar radiation 408. Flat plate PV designs also do not require costly 2-axis tracking of the sun's location as is required by concentrating systems.

In view of the average insolation map of Fig.5 optimal placement of solar energy conversion plants 400 would therefore be located in region 301 located to the far west of Australia.

The next best locations for PV plants are in the interior region 302 capable of on average 9hrs/day clear sunlight, shown in Fig.6. A majority of Australia has large number of hours/day for clear sunlight and is thus well suited for solar energy conversion power generation.

An embodiment of the present invention teaches the use of hybrid power generation principle via incorporation of natural gas fired and renewable energy generation systems physically located at the fossil fuel source. Figure 7 discloses substantial overlap existing between known and or currently accessible NG fields and high average annual solar insolation.

Unfortunately, by referring to Fig. 8, the location of major capital cities and or population densities 800-809 do not overlap well with optimal gas fields or high insolation above 9hrs/day. This poses two major technical obstacles, first the gas pipelines must transport gas to the end user over a long distance.

Currently, NG transport pipelines incorporate technology that consumes approximately 10% of the total input gas feedstock to power gas-fired compressor plants along the length of the transport pipeline from the gas field to the end user. Australia's large reserves of NG and coal-seam-gas enable low cost fossil fuel supply over a well established and existing pipeline network.

For example, approximately 50% of the NG supplied from the Moomba gas fields located in region 206 of Fig.2 supplying South Australia is consumed for gas-fired combustion in electricity generation. Typically, gas-fired plants are favoured for implementing demand growth and peaker supply, due to the fast spin up time for matching demand. It is therefore an object of an embodiment of the present invention to physically locate the gas-fired electricity production at the NG source and transport the power via HVDC to the end user. In doing so ZCE technology can be utilized, thereby producing zero GHG emission from fossil fuel based electricity generation schema.

The most efficient form factor of supplying NG to an end user as a function of distance separating the field and end user is shown in Fig. 9. Depending upon the capacity of NG required 900 compared to the distance of transport channel 901 , various technologies can be chosen. For example, for high capacity over distances <2000km it is economically efficient to transport the NG over pressurized pipeline. The infrastructure cost of the pipeline is substantial but retains long lifetime. The capacity of the pipeline is not easily increased without increasing the effective diameter of the pipeline and or pressure. A relatively straight forward solution to effective pipeline capacity increase is via the use of converting the energy available in the NG into HVDC and transporting it to the end user as electrical power. HVDC is the most efficient electrical transport technology over long distances, in excess of 100km due to the inherently low losses.

It can be seen in Fig.9 the equivalent transport of converted energy derived from NG fired electricity generation is economically feasible for HVDC conversion at the source as shown in region 910. That is, equivalent lower capacity supply in the form of electrical power becomes economically feasible compared to pressurized pipeline 902 or liquid natural gas (LNG) transport 904 or 905. In determining which system is best suited to establishing an initial transport channel to the end user, the above guide can be used (refer Fig.9).

Conversely, it is anticipated in an embodiment of the present invention that an existing pipeline can be retrofitted and or improved by increasing the effective energy capacity transportable over an existing supply link by integrating a parallel HVDC channel. Yet a further object of an embodiment of the present invention is the utility of point-of-burn (PoB) technology integrated with parallel HVDC power transmission along with NG pipeline energy transport. Such an integrated system delivers ZCE and removes the need for physically locating peaking electricity generation plant at the end user location.

The present invention may be used with known types of fossil and biomass fuels. In preference, natural gas is utilized efficiently for implementing ZCE plants. Typically natural gas can be extracted from a naturally occurring gas field or by functionalizing a coal bed by technique of coal seam gas (CSG) extraction. The carbon dioxide released by extracting natural gas from the buried field, by either method, depends on the specific local geology. For example, CSG extraction can produce NG with high percentage methane CH₄ and very low portion of CO2. Typically, NG fields located in terrestrially derived deposits (such as region 206 of Fig. 2) also produce very small amounts of CO₂ upon extraction. Generally, marine derived NG deposits co-produce larger amounts of CO₂ and sulphides compared to terrestrial deposits. A general NG and or CSG field is described in Fig. 10. Access shafts 1005 are drilled down approximately 1 km 1002 from the surface 1004 to intersect a majority of a subterranean NG and or CSG deposit 1000. An example shaft configuration comprises multiple shafts 1005 disposed generally in homogenous and non- homogenous matrix such that the gas products 1001 are transported up to the surface for collection.

Generally, within the type of source reservoir, natural gas is more mobile than oil and can migrate through smaller pores. Gas reservoirs therefore have a tendency to exhibit a lower permeability and may occur at shallower depths than oil reservoirs.

Undepleted, partially depleted or substantially depleted gas fields can be utilized for efficient storage of carbon dioxide. Figure 11A described a gas field with at least one injector shaft tailored for pumping carbon dioxide as gas, liquid and or other carbon based material into and or underneath the deposit 1000. It is found that advantageous injection of CO2 as described in Fig. 11A will enhance the NG and or CSG extraction process and extend the useful life of a partially depleted gas field. Therefore, carbon capture technologies using pre- or post combustion carbon capture can store and sequester the CO₂ products as shown in Fig. 11 A. Embodiments of the present invention solve the requirement of reducing and or eliminating GHG emission derived from fossil fuel combustion by physically locating the gas extraction field, power generation plant and sequestration a short distance from each other compared to the longer distance of for example the end-user.

Pressure and temperature increase with depth below the earth's surface. Assuming an average geothermal gradient of 30°C/km and a normal hydrostatic gradient of -10 MPa / km, the temperature and pressure in a reservoir may reach up to 175°C and 70 MPa, respectively. There is also a general increase of the pore water salinity with depth. The salinity gradients vary, although in many cases the salinity is not linearly related to depth. Pore water salinities range from fresh water to brines. Since salt water is heavier that fresh water, the hydrostatic gradient is normally more than 10 M Pa/km .

The critical temperature of CO₂ is 31.1⁰C and its critical pressure is 7.38 MPa, as shown in Figure 11 B. In comparison, a natural gas pipeline may similarly transport product up to 7MPa (100psi) over long haul links and up to 15MPa for high capacity links. The underground temperature and pressure below a depth of about ~1 km are such that CO₂ is in a supercritical state, meaning that no distinction can be made between liquid or vapour and the CO₂ acts as a gas-like compressible fluid. The supercritical CO₂ (characterized by region 1130 in Fig. 11 B) will therefore take the shape and fill the container it occupies. Above the supercritical depth the CO₂ will be in the form of a gas and thus the density will potentially be too low to store large volumes economically.

Supercritical CO₂ density and viscosity are a function of temperature and pressure. At the underground temperature and pressure of interest for sequestration, the density varies between 600 kg/m³ (at 30⁰C and 8 MPa) and 800 kg/m³ (at 160⁰C and 70 MPa). The density of supercritical CO₂ is significantly reduced if the CO₂ is contaminated with methane (CH₄). At a pressure of 19.3 MPa and a temperature of 60°C the density declines from 700 kg/m³ for pure CO₂ to 500 kg/m³ for CO₂ with 3% CH₄. The solubility of CO₂ in water increases with pressure and decreases with temperature. About 5g CO₂ can be dissolved in 10Og fresh water under subsurface conditions. Therefore, the operation of sequestered carbon dioxide in partially and or fully depleted natural gas fields will be affected by the methane and saline water interaction. It is anticipated that the sequestered CO₂ feed pipe into the gas field can be advantageously positioned to optimize these effects.

Like NG pipeline, CO₂ compressor stations will have to be spaced approximately 100-200km along the length of the CO₂ transport line from the source to the sink.

A critical issue with both the transport of NG and CO₂ in steel pipelines is water content of the gas/liquid. It is known CO₂ is soluble in water and will form carbonic acid via the reaction ∞₂ ^{+ H} ₂ ^O=^= ^H ₂ ^CO ₃ jhe vulnerability of most steel pipelines and turbines/compressors to the presence of carbonic acid requires careful management of the water content in the CO₂ pipeline.

The general conventional process of natural gas extraction, transportation and end use is schematically described in Fig. 12. The gas field 1200 comprises collection manifold 1231 for aggregation of individual shaft extraction gases into cumulative flow

1201. Storage of the NG 1202 can be used and or processing of the raw NG is performed to provide suitable products 1204 for transportation over pipeline delivery system and or liquefaction process. Depending upon the pipeline cross-sectional geometry and capacity required, the NG must be pressurized via compression process 1206. Typically, compressor 1206 is a gas-fired gas turbine deriving fuel 1203 from the input gas stream 1204. The NG field extraction and primary compressor plant are physically located in the same general area 1230. The NG transportation to the end user located a distance 1251 requires a pipeline configured to provide the desired capacity. Typically, over long distances repeater plants are located along the length of the pipeline spaced a distance 1250. The repeater plants 1209 comprise scrubbers to remove impurities and or water and compressors to pressurize the gas into the remaining pipeline.

Conventional pipeline technology derives the energy required for process 1209 by consuming a portion of the input NG stream 1208. Therefore, along the length of the pipeline the transported NG product is depleted by consuming NG to power the repeater plants. The portion of NG depleted from the product stream is shown in 1260 of the graph in Fig. 12.

Figure 13 schematically describes the carbon oxide and or dioxide emission C₁ generated for the lumped processes of extraction and compression and end-use. The cumulative GHG emission is shown for a conventional gas-fired compressor transportation system with end-user producing largest GHG by combustion. For example, end-user 1310 consumes a majority of NG product for power generation 1311 producing GHG emission C_E 1307. Location of suitable carbon sequestration fields are typically not found in the local vicinity of the end-user. Therefore, if electrical power is required by an end-user 1310 a solution to the GHG emission problem can be via location of the gas-fired electrical power generation plant near NG fields enabling an efficient sequestration path. The electrical energy can be transported efficiently via HVDC and HVAC networks to the end user. Embodiments of the present invention also disclose the utility of hybrid HVDC and HVAC power transmission systems that are capable of integrating both AC and DC generation sources.

Figure 14 further shows a hybrid NG transportation network deriving power required to drive compression processes 1400 and 1403 via renewable energy sources. Large scale PV utility plants 400 provide electrical power for driving electrical and or hybrid gas-fired/electrical compressors 1400 and 1403. Utilizing energy storage in the PV and or solar thermal plants to drive the NG compressors enables the pipeline to deliver NG product without consuming the NG stream along the length of the pipeline. For compressors utilizing gas-fired by night and PV by day derived power for the compressors, the product gas stream depletion is reduced compared to the conventional case of Fig. 13. Furthermore the NG consumed for power generation by the end user using direct combustion and carbon capture process 1410 can use renewable energy sources 400 to power carbon capture 1410 and or sequestration 1412. An important factor favouring electric-driven compressor stations is the fact the fuel gas otherwise used for gas turbine-driven compressor station will be transformed into capacity increase for the electric-driven compressor station. Overhaul cost for existing gas turbines typically occur after completing around ~40k (~4.5yrs) running hours and can be accounted in the OPEX costs. Compressor station spacing is fundamentally a matter of balancing capital and operating costs in order to meet the planned operating conditions of the transmission system.

For a given pipeline diameter, the distance between compressor stations may be computed from the gas flow equation, assuming a value of pipeline operating pressure (station discharge pressure) and a next compressor station suction pressure limited to the maximum compression ratio adopted for the project. Ideally, the pipeline should operate as close to maximum allowable operating pressure (MAOP) as possible, as high density in the line of the flowing gas gives best gas flow efficiency. This would point to the selection of close compressor station spacing although this approach may not be the best economical decision. When factoring in the GHG costs for electricity production it becomes clear that additional pipeline capacity increase may be better served by utilizing PoB technology as described herein and provide HVDC/HVAC transport of power to the end user.

Figure 15A schematically describes one preferred embodiment of the ZCE module 130 disclosed in Fig. 1. Natural gas 1500 derived from one or more gas fields is directed to processing plant 130. A portion of the input gas stream 1500 is diverted 1503 toward electrical power generation plant 1505. Plant 1505 is in preference a high efficiency gas-fired boiler and or combined cycle gas-turbine coupled to an electromechanical generator set producing AC or DC power output. The output flue gas stream 1511 of generator 1505 is fed into a post-combustion carbon capture process 1410, preferably powered or auxiliary powered by renewable energy source 400. Power source 400 can be large scale PV or solar thermal chosen to optimize the specified type of carbon capture process 1410. Carbon dioxide captured is compressed 1411 and sequestered back to gas field 1412. The compression and or transport of liquefied CO2 1411 can be accomplished efficiently by PV powered sources 1520.

The electrical power generated 1506 by process 1505 is input into electrical converter plant 1507. Plant 1507 can be an AC-to-HVDC converter for the case of AC power output from generator 1505, or high voltage DC step up for the case of DC output from generator 1505. The modified electrical power 1508 is fed into combiner and or summer process 1509 which is used to input renewable electrical energy 1512 from plant 400. The combined and or switched electrical power stream 1510 is used to transport electrical power to the end-suer. In preference, the mode of electrical power transmission is low loss HVDC. The remainder of the input NG stream 1502 is fed into a compressor plant 1504 suitable for pressurizing NG into pipeline 1530 suitable for transport of NG product to the end-user location. Gas compression plant 1504 is optionally powered in-part or full by renewable energy source 1521 , and in preference by large scale PV array 400.

The real-time end user electrical power demand is transmitted and fed-back to the hybrid power generation plant controller via signal 1550 which can be used to advantageously alter the proportion of gas-fired and renewable power generation plants. For example, during optimal PV power generation cycle the gas fired plant can be throttled up or down depending upon real-time and or projected demand of end user. Conversely, during depleted and or unavailable spot peak supply the gas fired plant output can be appropriately increased. On average, the combined gas-fired and PV electrical power generation plant will increase the expected lifetime of the field by conserving the limited fossil fuel resource.

Figure 15B describes further the claimed operation of the combined natural gas extraction, power generation, and CO₂ sequestration processes.

Natural gas 1563 is collected from gas-field via manifold 1231 and optionally supplied to storage vessel 1564. The gas is transported to the gas-fired power plant 1505 via optional compressor 1566. A portion of the initial gas stream 1500 is diverted 1502 for subsequent local compression into pipeline transport system 1530. The remained gas feedstock 1503 supplied power plant 1505 generating electrical power output 1506 and producing waste flue gas 1511 directed to carbon capture plant 1410. The carbon capture plant 1410 spatially separates the CO2 stream 1411 from other by-products 1409. The CO2 is compressed 1571 ideally as liquid form as described above and transported by high pressure pipeline 1570 to a partially or fully depleted gas-field via injector 1102. The injected CO₂ 1103 sequestered into the gas-field is advantageously positioned within the local gas-field structure to contain and or trap the CO2. The natural gas 1567 and 1504 and CO2 compressors 1571 are optionally powered via renewable energy sources 400, and more preferably using large scale photovoltaic power. A key distinction with the gas-fired plant described in Figs. 15A and 15B is the power generation occurs within relatively close proximity to the source gas-field as compared with Fig. 14. The electrical power 1506 / 1515 and compressed gas 1530 are transported to the end user.

Typically, raw natural gas collected from the gas field comprises 1 -5% CO₂ is sweetened prior to pipeline transport. Figure 15C describes integrated gas-fired power generation and CCS plant with additional CO₂ removal prior to pipeline transport. The carbon capture module 1580 removes CO2 and other pipeline impurities and provides methane for compression 1504 and transport 1530 to the remote end user. The scavenged CO2 is then either injected into the feedstock of the power generation plant 1505 or compressed for sequestration 1582. The renewable energy components are shown driving the carbon capture modules 1580 and 1410 and the compression plants 1567, 1504 and 1571. The reduction in additional fossil fuel consumed for the CCS systems enables the total efficiency of the integrated plant to approach that of a power generation plant 1505 without CSS systems (refer Fig. 26).

For the case of integrating a coal-based power generation plant, carbon-capture and sequestration the configuration is potentially different to the case for natural gas. Figure 16 discloses the general processes used for accomplishing the function ZCE operation.

Generally, coal deposits 1600 are not geographically found in the same local region as natural gas 1660. Furthermore, there may exist a large distance between an existing coal-fired power plant 1602 relative to both the sequestration gas-field 1660 and end user of electrical power 1680. Two functional blocks are shown, the coal- based power plant 1620 comprising transport channel of coal raw material 1601 to coal-to-electricity conversion facility 1602 and carbon capture plant 1605. A portion of the electrical power produced 1603 is diverted 1621 to power auxiliary plants and the majority is transported to the end user 1680. The captured carbon dioxide is then liquefied and then transported to the sequestration site 1640, typically a gas-field, though other regions may be used.

The coal 1601 may be optionally processed into syngas and or gasified coal 1690 feeding power plant 1602. The waste stream from post-combustion of the coal and syngas 1604 is fed into carbon capture plant 1605 separating the CO₂ 1609 from non- carbon waste 1612. The CO₂ is then liquefied by compressor 1624 for transport in pipeline 1611 to sequestration site 1640. It is likely, the sequestration site 1640 is distant from power plant 1620 and thus additional compression and or scrubber plants 1632 may be required. Storage 1641 of delivered CO₂ at site 1640 is then optionally processed and or compressed 1644 prior to injection 1645 into depleted gas-field 1661. It is noted the compressor plants for liquefying and transporting the CO₂ product from the power plant 1620 to the sequestration site 1640 require energy to drive them. Unlike in the case of extraction and transport of natural gas, there is no energy content in the liquid CO₂ pipeline that can be diverted to power the compressor/scrubber plants (compare with NG transport of Fig. 12). Therefore, it is anticipated that electrically driven compressor plants would be required, and thus electrical power delivery via links 1622, 1623 and 1624 is required to plants 1624, 1632 and 1644, respectively. In preference, however, the utility of large scale renewable energy production 1606, 1630 and 1650 is used to power the auxiliary plants 1607, 1632 and 1644, respectively.

One preferred method of high electrical power transmission is via high voltage direct current (HVDC) link. For the present invention the HVDC link is one-way power flow, from generation location to end-user, greatly simplifying the link infrastructure and end station configurations. In particular, the source HVDC can be implemented using large scale PV array so as to produce directly the HVDC without voltage-to-voltage conversion. Figure 17A shows a comparison of electrical losses as a function of point to point link distance of equivalent power HVAC and HVDC links. For link distances in excess of ~100km, HVDC attains significantly lower loss than similar power high voltage alternating current (HVAC) link. AC power transmission, generally has a technical limit of around 100km due to reactive power and losses, DC-power transmission has no technical limit to distance. The higher the voltage used in a HVDC link, the lower the DC current required for a given power transfer. Smaller currents enable smaller diameter conductors and thus dramatically lower cable cost. Dielectric breakdown of insulation materials are well characterized and understood for high reliability and low cost cable production. DC cables have a longer life expectancy than AC cables due to its lower operational stress level of around 20kV/mm. HVDC cables can carry up to 50% more power than the equivalent HVAC cable. The investment cost for HVDC AC-DC and DC-AC converter stations are higher than for HVAC substations. Therefore, HVDC is well suited to long haul transmission of power and AC is well suited to local distribution using relatively simple set-up and step-down transformers. However, the costs of transmission medium (e.g., overhead lines and cables), land acquisition/right-of-way costs are lower in the HVDC case. As there is no need to maintain wide distances between groups of DC cables, they can be ploughed direct in the ground or laid together in narrow trenches.

Moreover, the operation and maintenance costs are lower in the HVDC case. Initial terminal-loss levels are higher in the HVDC system, but the loss increases much slower with distance than equivalent HVAC links. In contrast, loss levels increase markedly with distance in a HVAC system.

Figure 17B shows the cost breakdown (shown with and without considering losses) for equivalent HVAC and HVDC links.

The cross-over between optimal choice of HVDC over HVAC lies in the lower losses as a function of distance, relative cost of end-station terminals and link cost.

Clearly, the HVDC transmission link in excess of 100km outperforms an equivalent power HVAC link. HVDC links can transport power up to several gigawatts (GW) over distances in excess of 2000km. The HVDC technology is enabled in large part by relatively new technology based on insulated gate bipolar transistors. These solid state switches enable cost effective high power circuits to be built for AC-DC and DC- AC conversion.

Figure 18 shows the potential of integrating HVDC power generation at the gas field and integrating with transport via existing NG pipeline. The effective capacity increase of energy supplied to the user can be seen as an expanded operational region 1800 of Fig. 18. Such a method enables an existing NG pipeline to increase energy capacity supply to a remote user.

A method is proposed in embodiments of the present invention for integrating HVDC cables with new or existing NG pipeline, disclosed in Fig. 19. The HVDC link comprises and isolated DC conductor having resistance per unit length 1910. A ground return conductor 1908 is provided enabling HVDC 1920 and 1921 to be attained over large link distance.

The HVDC cable is inherently a compact technology and can be placed along-side and above ground 1905 parallel to the length on a NG pipeline, and or physically buried 1906 beneath the ground. Ideally, the insulated small cross-section HVDC cable can be threaded down the interior 1903 of the pipeline and can be directly exposed to the NG flow 1904. If ground return is used with mono-polar operation, the resulting DC magnetic field can cause magnetic effects in the vicinity of the DC line or cable. This impact is minimized by providing a conductor or cable return path (known as metallic return) in close proximity to the main conductor or cable for magnetic field cancellation. Continuous ground current of the return current may flow in metallic structures such as pipelines and intensify corrosion if cathodic protection is not provided. When pipelines or other continuous metallic grounded structures are in the vicinity of a DC link, metallic return may be necessary. The pipeline itself may form the metallic return.

Figure 20 schematically describes an example implementation of the concept proposed in the present invention. The power transmission 2030 plant located in the vicinity of the NG fields comprises ZCE gas-fired electrical power generator 2010 and large scale photovoltaic array 2002. The gas-fired generator 2011 is fed by NG 2012 stream and can be throttled to increase or decrease power production in response to control 2013. Controller 2013 derives information of remote user real-time and or projected demand by information signal 2032 transmitted by end user load sensor 2051 of end user load 2050. The PV array 2003 incorporates optional charge storage 2006 that can be switched in and out of the circuit via switches 2005. Solar radiation 2001 is incident on PV array 2002 with peak output power generated by the peak solar flux during the day determined by local time zone. The electrical power transmission channel is via HVDC link 2060

The electrical power flow is from the transmitter 2030 toward the end user load receiver 2031. Effective grounds 2020 are shown and may comprise a return conductor and or link.

Yet a further electrical power transmission method is disclosed for connecting and or integrating HVDC and HVAC networks. Figure 21A describes a unipolar HVDC link connecting to end station 2101 and 2102. The HVDC is generated as voltage 2103 with respect to ground potential 2107. HVAC 2105 is superimposed upon preferably the positive potential 2104 of the HVDC line. The peak-to-peak AC voltage 2106 is advantageously positioned with respect to the positive HVDC line.

Yet a further method of integrating HVDC and HVAC is via the use of a bi-polar HVDC link as shown in Fig. 21 B. The HVAC is optionally positioned with average potential bounded by the positive 2140 and negative 2141 lines of the HVDC link connecting end station 2121 and 2222. Ideally, the peak-peak HVAC voltage 2106 should not exceed the HVDC potentials 2103 or 2130/2131. The integration of HVAC and HVDC can also be accomplished between an established HVDC link connecting end stations 2202 and 2205 (Fig. 22). An intermediate station 2203 combines AC power from station 2201 and supplies the additional power to end station 2105.

Figure 23 describes the relationship between physically locating a PV power generation facility in a time zone different to the end user wherein the peak solar radiation 2304 does not coincide with the end user peak demand curve 2300.

The fluctuating end user demand curve 2300 can be supported by a base supply 2303 and supplemented with peak power additions. Gas-fired turbine electricity production is well suited to fast spin up and down times required for dynamic demand matching. Integrating PV renewable energy production can be enhanced via utilizing electrical charge storage so that the PV contribution can be matched to greater extent with the end user demand. Regardless, if the as-generated PV power generated can be consumed by the end user, then the gas-fired plant can dynamically match the PV contribution to the end user demand. Figure 24 describes generally one example of a preferred embodiment of the present invention. Large scale PV arrays of the order of 20-10OMW are used advantageously in the energy production and transport system shown in Figs. 20 and 21. The PV arrays are positioned for optimal utility of the sun transit time and placed in the required geographic region. PV can assist in the energy production by minimizing the contribution of fossil fuel consumed for ZCE- thereby extending the useful lifetime of the limit fossil fuel resource. The PV array can also be configured to directly provide HVDC bias voltage for the transport network. HVDC PV arrays can also be used for overcoming losses over long distance HVDC links. PV arrays can easily be incorporated in to end user HVDC and HVAC systems.

Figure 25 describes the temporal effect of geographic location of large scale solar power generation plant. The sun transit time (peak or high noon position) as a function of several positions ranging from east-mid-west at Perth, Adelaide and Sydney, respectively are shown. Major electricity consumers comprise mining, mineral extraction and fossil fuel extraction enterprises are typically located in remote areas distant from highly urbanized areas. Australia, for example, is a highly urbanized continent and thus the capital cities are typically sinks for electricity consumption.

Large scale PV plants networked or stand alone advantageously located in various time zones can provide peak power for electricity end users. Coupling PV plants to ZCE technology disclosed herein further provides a flexible and highly optimal use of the PV power generated.

The cost of electricity (COE) in units of (AUS$ kWhr^"1) for a power plant can be expressed as:

COE = [(FOM) + (TCR)(FCF)]/[(8760)(kW)(CF)] + VOM+ (HR)(FC),

where, TCR=total capital requirement $, FCF=fixed charge factor, FOM= fixed operating cost ($/yr), VOM, variable operating cost ($ kW.hr^"1), HR= net plant heat rate (kJ.kW.hr^"1), FC=unit fuel cost ($/kJ), CF=capacity, kW=net plant power (kW) and 8760=typ. number hrs per year. The total CCS costs must factor into the COE calculation the cost of CO₂ transportation and storage so as to represent a complete system.

A figure of merit for a plant with CCS system functioning is the cost of CO₂ avoided (in units of AUS$/tCO2), reflecting the average cost of reducing atmospheric CO2 emission by one unit while providing the same amount of useful electricity as a reference plant without CCS. The reference plant is assumed to be of the same type and design as the plant using CCS. The CO2 avoidance cost for a complete power plant with total CCS system is thus given as :

Cost of CO₂ avoided (AUS$/tCO₂)= [(COE)CCS-(COE)REF]/ [(CO₂ kWhr-¹)_REF-(CO₂ kWhr¹)ccs],

where (CO₂ kWhr^"1)= the rate mass of CO₂ emitted in tones per kWh^"1 generated. Note if the plant with CCS does not include the associated costs of transportation of CO₂ and subsequent sequestration/storage, then the above analysis is deficient.

In general carbon capture and sequestration (CCS) systems place additional energy requirement per unit of CO₂ product on a fossil fuel power plant. The change in net plant efficiency can be calculated when the efficiency of the plant with carbon capture (ηcc) is referenced to an equivalent plant without carbon capture system (η_Ref). The fractional increase in plant energy input per unit of product ΔE = (ηRef./ ηccs)-1 - That is, addition of conventional CCSs require energy to be diverted from the energy output of the plant to drive the CCS (i.e., the CCS is an energy loss to the plant output). By integrating renewable energy sources to power the CCS, the energy loss can be compensated thereby increasing the efficiency of the fossil fuel powered electricity plant output.

The location of a new electric power generation system with carbon capture and sequestration relative to the source fossil fuel and sequestration sites will affect the profitability of the facility and determines the amount of infrastructure required to connect the plant to the larger world. Profit-maximizing of power production would generally locate a new generator with optimization of cost for carbon capture in relation to a fuel source, electric load, and CO₂ sequestration site. Comparing the costs for HVDC/HVAC transmission lines, CO₂ pipelines, and fuel transportation, it is an ideal scenario to locate a CCS power facility nearest both the fossil fuel source and sequestration field simultaneously. Electric losses for bulk electricity transmission can be compensated for by various renewable energy sources.

A power system with significant amounts of CCS and not located in close proximity to a CO2 storage/sequestration site will require a large diameter CO2 pipeline infrastructure and thus must be factored into the whole system cost. For example an existing GW-scale coal burning power station will require a large amount of CCS and thus the CO2 pipeline cost per km will affect the viability. Transport of liquid-CO2 over long pipelines from the coal power station to the sequestration site may become more cost effective by the use of renewable powered compressor plants thereby removing the need for the coal power station to prove energy along the pipeline.

Figure 26 summarizes the potential benefit of designing an integrated ZCE power plant according to the method of the present invention. Comparing coal 2603 and natural gas 2604 fired power plants with and without CCS systems in place is characterized by the CO2 emitted versus the fuel consumed. The coal powered electricity plant without CCS is shown as region 2613 and can reduce CO₂ emission via CCS system as shown in region 2623, inevitably consuming a higher amount of fuel. Similarly, a natural gas powered electricity plant without CCS is shown as region 2614 and can reduce CO₂ emission via CCS system as shown in region 2624, inevitably consuming a higher amount of fuel. Overall the gas fired plant emits considerably less GHG than an equivalent coal based power plant. Using ZCE technology and judicious use of renewable energy sources, the power plants with integrated CCS systems can produce CO₂ output versus fuel input characteristic as shown by regions 2634 and 2633 for NG and coal, respectively.

The invention described herein is susceptible to variations, modifications and/or additions other than those specifically described and it is to be understood that the invention includes all such variations, modifications and/or additions which fall within the spirit of the above description or the scope of the following claims.

Claims

The claims defining the invention are as follows:

1. An electrical power generating system including: a fossil fuel powered electrical generator, carbon capture apparatus associated with the fossil fuel powered electrical generator to capture carbon emissions from the electrical generator, a solar electrical power generating array in proximity to the fossil fuel powered electrical generator, wherein the fossil fuel powered electrical generator and the solar electrical power generating array are for supplying base load electrical power over a 24 hour cycle to remotely located consumers, and wherein the fossil fuel powered electrical generator is located in proximity to a source of the fossil fuel for the captured carbon emissions to be sequestered within that source, being a source in which said captured carbon emissions are sequesterable.

2. An electrical power generating system as claimed in claim 1 wherein the fossil fuel is natural gas or methane or coal seam gas and the source thereof is a field for production of the gas.

3. An electrical power generating system as claimed in claim 1 or claim 2 wherein the solar electrical power generating array is an array of modules, each module in the form of a panel that comprises a substrate for transmission of solar energy on which a multiplicity of photovoltaic cells are formed for converting the solar energy into electrical energy, the panel including at least one capacitor for storing the electrical energy generated by the photovoltaic cells.

4. An electrical power generating system as claimed in any one of claims 1 to 3 wherein the solar electrical power generating array is of a size and capacity as to be capable of producing 20 to 250 MW peak power.

5. An electrical power generating system as claimed in any one of claims 1 to 4 wherein the fossil fuel is natural gas and portion of the natural gas is transported to said remotely located consumers via a pipeline.

6. An electrical power generating system as claimed in claim 5 wherein the natural gas pipeline includes repeater plants spaced along its length, each repeater plant including a scrubber to remove impurities from the gas and a compressor to pressurise the gas into the next pipeline section, wherein a solar electrical power generating array is associated with each repeater plant for providing power for operation of the repeater plant for at least a portion of a 24 hour period.

7. An electrical power generating system as claimed in any one of claims 1 to 6 wherein the solar electrical power generating array in proximity to the fossil fuel powered electrical generator provides power over at least a portion of a 24 hour period for operation of the carbon capture apparatus and/or for the sequestration of the captured carbon emissions.

8. An electrical power generating system as claimed in any one of claims 1 to 7 including a high voltage transmission line for the supply of base load electrical power to the remotely located consumers.

9. An electrical power generating system as claimed in claim 8 wherein the transmission line is for high voltage direct current (HVDC) power transmission.

10. An electrical power generating system as claimed in claim 9 as appended through claim 5 wherein the transmission line is located in proximity and substantially parallel to the gas pipeline.

1 1. An electrical power generating system as claimed in claim 10 wherein the HVDC transmission line is located within the pipeline.

12. An electrical power generating system as claimed in any one of claims 8 to 1 1 wherein the transmission line is for hybrid transmission of high voltage direct current

(HVDC) and high voltage alternating current (HVAC) power.

13. An electrical power generating system as claimed in claim 12 wherein the HVAC is superimposed upon the HVDC.

14. An electrical power generating system as claimed in claim 13 wherein the transmission line includes a bi-polar HVDC link and the HVAC is transmitted on a link between the bi-polar positive and negative DC potentials.

15. An electrical power generating system as claimed in any one of claims 1 to 14 including a controller for receiving feedback of power demand (either real time or projected) by the remotely located consumers, wherein the controller is operatively associated with the fossil fuel powered electrical generator for altering the proportion of electrical power that is supplied by the fossil fuel powered electrical generator compared to the proportion supplied by the solar electrical power generator array.

16. An electrical power generating system including: a coal powered electrical generator, carbon capture apparatus associated with the coal powered electrical generator to capture carbon emissions from the electrical generator, a solar electrical power generating array in proximity to the coal powered electrical generator, wherein the coal powered electrical generator and the solar electrical power generating array are for supplying base load electrical power over a 24 hour cycle to remotely located consumers, and wherein the solar electrical power generating array supplies power for operation of the carbon capture apparatus and for forming the captured carbon emissions into environmentally stable products or into a form for transport to a sequestration location.

17. An electrical power generating system substantially as hereinbefore described with reference to the figures.