The smallest hydro power plants commercially available are used as battery chargers. The systems are often complete battery charging systems which include the control box, wiring harness, generator, meters and a turbine (usually a Pelton or a Turgo wheel). The only other thing required is to “add water”, this usually being supplied through a plastic hose of 3–5 cm2 in diameter. Sites can be utilized with heads as low as a 0,75 m, but around 8 m is more appropriate and higher heads are even better. The price for a complete system is about US$ 350–550. The batteries can be charged directly on the spot or by using transformers and cables for long distance charging. At a head of 8 m a hydro plant of this size produces about as much power as five standard 35 W photovoltaic panels for a much smaller investment cost.
Design of Small Hydro Generation Systems
Morteza Nazari-Heris, Behnam Mohammadi-Ivatloo, in Distributed Generation Systems, 2017
6.5.6 Cost Analysis for Run-of-River Small Hydro Power Systems Projects
This subsection aims to analyze the cost of a run-of-river SHPs project, which is assumed to be a typical layout of run-of-river project with a tubular turbine. This category of turbine has a common utilization in the low head range. Runner diameter determines the turbine size, and the layout of the power house is worked out based on runner diameter. The following equations can be utilized for obtaining runner diameter D :(6.45)(6.46)(6.47)
where the specific speed of the turbine and the rotational speed of the turbine in revolutions per minute are demonstrated by Ns and N, respectively. H and P are the respective elements utilized to show the rated net head in meters and the rated available power in kilowatts at full opening of the gate. As mentioned above, the cost of a hydro power project contains the costs of civil works and the costs related to electromechanical equipment. In  a methodology has been presented for generating the cost data of a run-of-river SHPs project. It should be noted that all costs are taken in Indian rupees (Rs.). In the following discussion, the obtained equations for costs of different equipment of civil works of a run-of-river project are provided.
The cost of a powerhouse per kilowatt CPH (Rs.), which is the major component in low head hydro power projects, can be stated as(6.48)
The cost of a diversion weir and intake per kilowatt CDW (Rs.) can be obtained as follows:(6.49)
The cost of a power channel per kilowatt CPC (Rs.) can be obtained as follows:(6.50)
The cost of a desilting chamber per kilowatt CDC (Rs.) can be calculated as(6.51)
The cost of a forebay and spillway per kilowatt CF (Rs.) can be calculated as(6.52)
The cost of a penstock per kilowatt CPS (Rs.) can be calculated as(6.53)
The cost of a tail race channel per kilowatt CTR (Rs.) can be calculated as(6.54)
As a result, the cost of civil works of a run-of-river SHPs project per kilowatt can be stated as(6.55)
In addition, the costs related to electromechanical equipment should be taken into account. The runner diameter and capacity of the plant considering prevailing market rates are the fundamental parameters that have been considered for providing a calculation formula for the cost of electromechanical equipment, as follows.
The cost per kilowatt of turbines with governing system CT (Rs.) can be calculated as(6.56)
The cost per kilowatt of generator with excitation system CG (Rs.) can be calculated as(6.57)
The cost per kilowatt of electrical and mechanical auxiliary CEM (Rs.) can be calculated as(6.58)
The cost per kilowatt of transformer and switchyard equipment CTS (Rs.) can be calculated as(6.59)
So, the cost per kilowatt of electromechanical equipment CEE (Rs.) can be stated as follows:(6.60)
Considering other miscellaneous costs beyond the cost of the civil works and electromechanical equipment, the total required cost for a run-of-river SHPs project can be estimated. Miscellaneous cost include the cost of establishment including designs, audit and account, indirect charges, tools and plants, communication expenses, preliminary expenses on report preparation, survey and investigations, and cost of land. Miscellaneous cost CM is estimated as 13% of the total costs related to civil works and electromechanical equipment. Accordingly, the total cost per kilowatt of low head run-of-river SHPs project, which is the sum of costs related to civil works and electromechanical equipment and miscellaneous cost, can be stated as follows:(6.61)
Investment costs of small hydro power projects are a bit higher, especially power plants with capacities of less than 1000 kW. Increase of the head and power capacity of a hydro plant results in reduction of investment costs of SHPs. For plants with power capacities between 1 MW and 7 MW in the United Kingdom, the capital costs per kW are between USD 3400 and USD 4000. However, SHPs with power capacities less than 1 MW require a capital cost per kW between USD 3400 and USD 10000.
Consideration of economic evaluation and investigation is one of the key factors of industrial projects. This investigation aims to analyze whether that foundation of SHPs is economical or not. For achieving this goal, sale price of electricity should be obtained and a comparison of sale price and suggested price of energy by the state is done. The net present value can be provided by subtracting the total capital cost from the present value of revenue. For obtaining electricity purchase price λ, formulations have been reported in , in which the 15-year return (N) has been considered. In addition, interest rate r and annual increment in electricity price Δλ are taken into account equal to 6% and 10%, respectively. For obtaining a formulation for λ, VNP should be considered equal to zero. Accordingly, we have (6.62)
where VNP is the net present value. Present value of revenue and the total capital cost have been demonstrated by Ctpp and VRP, respectively.(6.63)(6.64)(6.65)View chapterPurchase book
Paul Breeze, in Hydropower, 2018
The global capacity of small hydropower was estimated to be 78,000 MW at the end of 2016 by the International Center on Small Hydro Power (ICSHP, part of the United Nations Industrial Development Organization). Another report estimated it to be around 110,000 MW.1 Meanwhile the ICSHP has suggested that only 36% of the potential global small hydro-capacity has been exploited and around 139,000 MW remain. Other figures, such as those in Chapter put the potential much higher still with 2,949,000 MW of small hydro and 396,000 MW of micro hydropower available globally. Small hydropower generates 7% of the global renewable electricity according to the World Bank.View chapterPurchase book
Promoting Electricity from Renewable Energy Sources – Lessons Learned from the EU, United States, and Japan
18.104.22.168 Renewable energy schemes in Japan
In 2003, Japan introduced an RPS scheme requiring that approximately 1.35% of each retail supplier’s sales in 201026 come from eligible RES, defined as PV, wind, biomass, geothermal, and small hydro power (1 MW or less), rising to 1.63% by 2014. Electricity from PV is credited at two times the value from 2011 to 2014. To be certified the renewable electricity must be sold to the grid. The total target has been set to increase from 3.3 TWh in 2003 to 12.2 TWh in 2010 and 16 TWh by 2014. The targets are low27 compared to those in the Europe and the United States, partly because large hydro power and geothermal are ineligible under the scheme and also because a considerable amount of electricity generated from biomass is consumed for self-use.
As with other RPS schemes, retail suppliers and renewable generators may trade certificates. Also, banking and borrowing of certificates up to 20% of the target are allowed. The maximum price of the certificate is set at 11 JPY/kWh (approx. 9 US cents/kWh). The total amount of RES supplied in 2005 was 5.6 TWh,28 which exceeded the actual target of 3.8 TWh. The targets from 2006 to 2009 were revised upward by 4 TWh in total as a part of the review process conducted in 2006.
Since the enactment of the RPS scheme, renewable generation has steadily increased (Fig. 12.4), a trend that is expected to continue (Nishio and Asano, 2006), while prices have declined. The certificates were traded at a relatively stable price range of around 5 JPY/kWh (approx. 6 US cents/kWh) from 2003 to 2005 (Fig. 12.11), presumably because the transaction prices are determined by taking the banking into consideration from a long-term viewpoint.
Coal Resources, Production and use in India
Renewable energy sources
There is high potential for generation of renewable energy from various sources like wind, solar, biomass, small hydro and cogeneration bagasse. The total potential for renewable power generation in the country as on 31 March 2010 is estimated at 90 315 MW. This includes 48 560 MW from wind power, 15 385 MW from Small Hydro Power (SHP), i.e., up to 25 MW capacity and 22 535 MW from bagasse based cogeneration from sugar mills. The estimates for solar energy potential are at 20–30 MW per km2 for most parts of the country (Energy Statistics, 2011; Working Group of Power, 2011). Taking into account the limited oil and gas reserves, eco-conservation restrictions on hydroelectric projects and post-Fukushima environmental perception of nuclear power, it is expected that coal will continue to be India’s primary energy resource in the medium to long term.
Coal resources, production and use in Brazil
Tractebel is the largest private power generator in Brazil with plants in the five regions of the country, specifically in the states of Rio Grande do Sul, Santa Catarina, Paraná, São Paulo, Minas Gerais, Mato Grosso do Sul, Mato Grosso, Goiás, Tocantins, Maranhão, Piauí and Ceará. The company has an installed capacity of 6908 MW, equivalent to about 7% of the Brazilian total through 22 plants of which nine are hydroelectric, six thermoelectric and seven additional plants, two being on biomass, three on wind generation and two small hydro power (SHP) plants. Tractebel is owned by GDF Suze, a global leading energy group. Coal-fired power plants are the Jorge Lacerda plant (857 MW) in Santa Catarina State and Charqueadas (72 MW) in Rio Grande do Sul State.
Jorge Lacerda plant is divided into seven generating units having capacities of 50 MW (units 1 and 2 from 1965 and 1967), 66 MW (units 3 and 4 from 1973 and 1974) and 131 MW (units 6, 7 and 8 from 1979, 1980 and 1997). Their coal comes from nearby Capivari with 18.8 MJ/kg calorific value.
Charqueadas plant is comprised of four units of 18 MW each from 1962. It was the first one in Brazil to have FGD process in place. Their coal comes from local Charqueadas mines having volatiles around 20-25%, moisture of 12%, 53% ash, 1.3% sulphur and 12.9 MJ/kg calorific value (Ellwanger, 2012).
Introduction to transmission and distribution (T&D) networks: T&D infrastructure, reliability and engineering, regulation and planning
1.6.1 Technology trend 1: Improving cost effectiveness of distributed resources
The LV and MV levels of the traditional power system are, in a very real sense, their own distributed resources. The LV utility network in particular is distributed over the service territory, reaching every single customer and sized locally in direct proportion to local customer energy needs. However, the term ‘distributed resources’ in modern power systems is used solely to refer to power systems in which the electric energy itself is produced by machinery, facilities, or systems that are distributed throughout the service area rather than concentrated in a few large central-station generating plants, as was depicted earlier in Fig. 1.2. Distributed resources include small generators that might include:•
low head of small hydro-power generation,•
wind energy generation,•
micro-turbine powered generation,•
high- and medium-speed diesel generation,•
photovoltaic power generation,•
small solar thermal and tower generation.
These small generators are distributed throughout the utility service area, although not necessarily in direct proportion to the customer demand. For example, in a rural area a three-turbine wind generator facility of 1 MVA capability might be located in a tilled field two miles from the farmhouse and harvest processing/drying facilities that create the demand for most of that power. In an urban area, a 2 MVA PV panel set located on office rooftops might produce power that at times is moved several miles to serve nearby residential demand. But invariably these distributed generating sources are, on average:•
Closer to the energy consumers than is central-station generation. Hence, power delivery costs are potentially lower, reliability of power transmission is higher and esthetic and environmental impacts of the power transmission lines are all lower than for power delivery in a traditional system (all three because the pathway for power delivery is, ultimately, shorter than in a traditional system).•
Less efficient in overall unit cost of power than larger central-station generating plants, as was discussed earlier. The margin might be small or large depending on technology and characteristics specific to each situation.•
The usefulness and popularity of distributed resources rests on the economic, service quality, social, and market advantages that being closer to the customer has, as opposed to any disadvantages created by the lower potential efficiency of per-unit power production.
Demand response as a distributed resource
In some instances, distributed resources (DR) also include non-generating resources that can be dispatched much like generation. An example is demand response, or load control, in which certain loads can be switched off for a time to keep system resources and demand in balance.2 From the standpoint of many system operating decisions aimed at achieving and maintaining that balance, it makes little difference if generation is increased or demand reduced. Dispatchable load control, whether directly (the appliances and equipment themselves are shut down) or indirectly (voltage on a feeder is reduced slightly lowering the load of connected loads) the result is the same: at the system operator’s request, a change has been made to help control the ratio of generation to load.
In some cases, utility planners, managers, and regulators will restrict ‘demand response’ to methods that are directly dispatchable (controllable in near-real time) by the utility or system operator – methods such as direct load control or active demand limiters. In other cases, however, the term demand response includes programs and load-influencing methods that rely on customer or automatic (customer programmed) price-sensitive responses from the demand, such as real-time-pricing (RTP) methods. These methods do not have the temporal immediacy of direct load control – the demand reduction may take seconds or minutes to affect, or it might not happen at all – customers may override these methods in critical situations, etc. Thus they are less certain in their effect and left out of DR considerations by some, but sometimes included as ‘demand response’ and ‘distributed resources’ by others. It is best to inquire in each instance to avoid ambiguity and confusion.
Small hydropower plants are defined as much by regulatory regimes as by their inherent design features. Plants below a certain size usually qualify as new renewable generation and these are called small hydropower plants. The limit varies from country to country. In Sweden, for example, the upper size of a small hydropower plant that can attract support is 1.5 MW. In Italy the limit is 3 MW, in France 12 MW, in the United Kingdom 20 MW and in Canada and the United States it is between 30 and 50 MW.
The global installed capacity of small hydropower plants was estimated to be around 78,000 MW at the end of 2016 by the International Center on Small Hydro Power (ICSHP, part of the United Nations Industrial Development Organization). The potential for future development is uncertain but the IEA has suggested that there may be 150,000–200,000 MW capable of development, while the ICSHP has put it at 140,000 MW. Other estimates have put the potential 10 times higher.
The design of a small hydropower plant depends very much on its size. Those in the small hydropower category of Table 8.3 (1 MW to between 10 and 30 MW) will be approached in a similar way to a large hydropower project. At this size, dam construction is unlikely to be cost-effective but some sort of barrage may be employed. At the smaller end of the range, off-the-shelf rather than site-specific turbines are also likely to be used. In most cases, these will be of the types discussed above for large hydropower schemes.
Mini and micro hydropower plants of less than 1 MW in size are usually approached differently. Here cost becomes the overriding concern and a range of novel techniques including the use of cheap pumps as turbines and inflatable barrages may be employed to keep costs down.
One major difference between large and small hydropower is the breakdown of head height into categories. For a small hydropower plant a head above 100 m will be considered a high head and any project with a head of this or higher will employ a high head turbine such as a Pelton turbine. For very small projects a Pelton turbine may be used at even lower head heights. Projects with heads of between 30 and 100 m are classified as medium head scheme, while anything under 30 m qualifies as a low-head plant.
Plant design will be much simpler in a small hydro scheme. Most will be run-of-river (or run-of-stream) and any intake structures, where used, are likely to be rudimentary to keep costs low. For larger plants a weir may be employed. Others will take water directly without any type of barrage. In many cases the turbine generator will be placed directly into the waterway.
If water is extracted from the river or stream it may be carried some distance through the equivalent of a headrace, but more commonly it will be fed directly into a penstock-type conduit that carries it into the turbine. Penstock length can affect project costs significantly so this will be kept as short as possible.
Turbine types for small hydropower schemes will depend on head height; Pelton turbines for high head, Turgo and Francis for medium head, and propeller and Kaplan turbines for low-head applications. Other turbines are also commonly used. These include the crossflow turbine, a low-cost type of impulse turbine, the Archimedes Screw and a Gorlov turbine which is a little like a vertical axis wind turbine that operates underwater. Simple paddle-type water wheels are also common (Figure 8.11). For very small applications, cheap pumps can be used in reverse to make turbine generators. These are known as pumps-for-turbines or PATs and can be used with head heights of 13–75 m to build very cheap hydropower facilities. Small propeller turbines fitted with sealed generators can also be dropped directly into a stream to provide a hydropower generating system.
Although larger small hydropower schemes may use synchronous generators of the sort used in large plants, many small plants employ asynchronous generators that rely on the grid to help them control their speed of operation. In some cases, these are simply motors being used in reverse to generate power. The efficiency of such small asynchronous generators is much lower than that of large generators.
Small hydropower schemes tend to be relatively more expensive than larger schemes because costs of many of the components do not fall in line with size. The cost of a grid connection can become a large financial component of a small hydro scheme, while a feasibility study may take up to 50% of the budget. Even with the extra cost a project can still be economical if the small hydropower scheme is supplying power directly to consumers. In this situation the price of the electricity from the plant will be competing with the retail cost of electricity rather than the wholesale cost. Small hydropower can also be extremely effective in supplying power to remote communities far from a grid, especially when the alternative is diesel power.
Need for Reliability and Measuring Its Cost
24.6 Integrating Renewables Through Smarter Grids: Tradeoffs and Synergies
Ensuring a cleaner supply of energy drawing on locally available renewable energy resources has become a key policy objective of European governments. The growing reliance on renewable power sources may result in significant instantaneous shares of their generation. Balancing their often variable output requires a high degree of flexibility in the power system, i.e., changes in generation or demand must be counterbalanced quickly enough to avoid supply interruptions.
Distributed renewables and storage: When solely looking at the probability of interruptions to occur, a system with and without renewables may be designed with the same reliability. Yet, from an operational point of view, the systems may not be directly comparable. Renewable generation often involves distributed generation by households or municipalities. For example, some small hydro power plants which were built in response to Austria’s feed-in tariffs are capable of black-start and isolated operation. As such, the local municipality may still be supplied with electricity even if a major outage in the transmission system occurs. (Note that such decisions taken by local municipalities were rather political than technical, to avoid complaints by their respective constituencies in case of outages.)
Similarly, household PV and solar thermal systems may also provide energy services when outages occur. Germany, for example, launched a support program for PV storage systems, providing a mix of low-interest loans and subsidies for up to a maximum of 30% of the investment cost . The advantages to society are twofold. The PV storage system would increase the supply security of the connected households in the case of outages. Further, pressure on local grids is reduced by lowering the peak production of the PV systems that is fed into the grid.
Decentralized generation has a clear potential to reduce the costs of intermittency by reducing the number of consumers affected, e.g., by an outage in a main transmission line. However, the distribution of the costs for accessing the grid do require consideration. If added as a surcharge to the electricity consumption, such households or municipalities may not pay their fair share due to their low consumption. The share of the grid costs per capacity connected and per electricity generated may need to be revisited to ensure costs and benefits are adequately attributed to the various consumer groups.
Unlike distributed storage options, larger wind farms are commonly built in a more concentrated fashion in areas with favorable wind conditions. Similar to large hydro power plants, they require medium to large voltage grid connections to be established. Depending on the size of the power plant, an outage in such a line may therefore have an effect similar to an outage in a connection to a thermal power plant.
Smart Grids: Increasing shares of (distributed) renewables call for a more flexible power system controlled through smarter grid management techniques. Smart Grids build on a significant increase in the level of communication, automation, and control based on a two-way flow of information and electricity, from supplier to consumer.
One characteristic of Smart Grids is their ability to be self-healing, i.e., to reduce the extent of interruptions and restore the system’s operation when outages do occur. Smart Grids further enable the integration of sources of flexibility which were largely untouched before. This is especially important as increasing the share of variable electricity generation will require a more flexible system based on parallel investments in balancing mechanisms. Conventionally, this would be provided by power plants which can quickly ramp up or down their generation, such as gas turbines. With the advent of Smart Grids, more accessible and cost-efficient options will be available to minimize the extent and costs of interruptions to customers. These may include demand-side options as well as more flexible management and operation of grid infrastructure.
Demand-side management and prioritization of loads: Smart Grids may minimize the cost of interruptions by ensuring near perfect reliability and quality of supply for high-priority demand types, while reducing the requirements for demand types which are less sensitive to these needs . Loads may be prioritized according to demand types such as emergency services, financial institutions, industries, and consumers.
Such a prioritization may not be limited to consumer groups, but may also apply to demand types within one consumer group. For example, approximately half of private household demand does not need to be met instantly and can be shifted flexibly . Examples include dishwashing, washing of clothes, air conditioning, and heating. In the transport sector, electric vehicles may provide this flexibility. In industry, related examples include electric boilers or process heat requirements. So, instead of having to cut off several consumer groups completely, Smart Grids may allow to interrupt specific demands, thus ensuring the supply to more high-value energy services and reducing the cost of interruption. An example of a deconstructed demand profile based on different priorities and flexibilities is provided in Fig. 24.2 .
According to ACER’s estimates, currently only 10% of demand response resources are being utilized within the EU. Pricing schemes would need to ensure that the flexibility provided by consumers is rewarded accordingly. Supportive regulation is needed, not least to ensure cyber security and to protect consumers from data misuse.
Regulation: Present regulation often rewards utilities for delivering network primary assets rather than improving performance through more sophisticated grid management and consumer integration. Thus, regulation can hinder developments that do not focus on investments in network assets. Most current network design and operation practices center on variations of the historic deterministic N–1 approach that were developed in the late 1950s. A system which adheres to the N–1 rule maintains reliable operation even if a major element fails, e.g., a transmission line. This approach has broadly helped deliver secure and reliable electricity services, alongside various other traditionally applied redundancy measures. It can, however, impose major barriers for innovation in network operation and for the implementation of solutions that enhance the utilization of grid assets. Moving away from such historically developed power quality and reliability standards will help balancing asset- and performance-based options, particularly those that involve responsive demand and advanced network management techniques facilitated through Smart Grids.
According to a recent study on demand response measures, few of the EU 28 Member States were found to have created satisfactory regulatory and contractual structures that support aggregated demand response (Fig. 24.3 ). Some Member States are in the stage of reviewing their regulatory framework (such as Austria, the UK, Ireland, Germany, and France), while most Member States are lagging in regulatory and institutional terms. This hinders consumer participation in energy markets and system services such as balancing and the provision of reserve.
Increasing generation from variable renewables requires an increase in power system flexibility to ensure current reliability standards are met. The increased flexibility requirements may trigger investments in a set of smart technologies, which may ultimately allow decreasing the costs of intermittency. This may be achieved by shifting the current focus on the provision of electricity to a focus on the provision of services.