There can be substantial economic benefits when it comes to interconnecting hydro and thermal systems, according to Ivar Wangensteen
The benefits of establishing international interconnections and regional power pooling arrangements can in many cases be substantial, particularly when it comes to hydro and thermal systems.
Several factors contribute to the economic benefit of an interconnection and pooling arrangement, including:
• Operational benefits.
• Lower total investment.
• Lower total reserve requirement (which also contributes to lower investment).
• Use of hydro as an inexpensive frequency control reserve (FCR) and other reserve.
• Use of hydro as low cost load following.
Making a link
A thermal electricity system is always capacity constrained, whereas a hydro system can be either capacity constrained or energy constrained. In both cases, there will be an economic benefit in linking the two systems together.
A capacity constrained system means that there is water available to increase the power generation in off-peak periods. The demand is variable, and the system is designed to cover peak demand. In off-peak periods there is spare capacity and water available. In an extreme case, there is sufficient water to run the plants at full capacity all the time. In many cases, a hydro generation system in an early stage of development will be capacity constrained.
The benefit of connecting such a hydro system to a thermal one is an increased hydro generation in off-peak periods at almost zero cost. This can replace thermal generation and thereby save fuel in the thermal system. The net effect is a reduced operation cost in the total system.
There can be some investment savings in the generating system in this case. This depends on the fact that peak demand in different areas is normally not coincident. If the load curves in the different areas (countries) are known, these savings can be estimated.
The basic concern in an energy constrained system is the amount of water available. An energy constrained hydro system will normally have a surplus of capacity.
An estimation of the benefits of close interplay between a thermal power system and a predominantly hydro-based power system, involves evaluating the following main
• Investments in supplementary hydro MW capacity expansion, if necessary.
• Reduction or postponement of investments in new peak power capacity in the thermal generating system.
• Changes in operational costs related to start/stop of units, fuel consumption, and import/export transactions vis-à-vis third parties involved.
As a general rule, the requirement for short term (spinning) reserve in a generating system is set by the largest unit in the system. The system should be able to cover demand even if an outage of the largest unit should occur.
It follows from this that the total short term reserve requirement for each subsystem is reduced when several subsystems are integrated into one. It is also obvious that several small subsystems have more to gain with respect to reserve requirement than large subsystems. This depends on the fact that in a small system, the largest unit is probably larger in relation to total system capacity than in a large system.
There is almost no operation cost connected to the
provision of FRC and other reserves in a hydro system. In a thermal system, additional operational cost (fuel cost) for keeping reserves on standby is estimated to be 1-3% of total operation cost.
The cost of holding capacity reserves on standby in the production system is influenced by how the unit efficiencies depend on output. In this case there is a difference between thermal and hydro systems.
The figure above shows efficiency curves of different types of hydro power units. The curves depend on what type of turbine is used. Common for all however is that the maximum efficiency is far below the maximum output. For a Francis turbine, the best efficiency is at approximately 80% of maximum load. This means that when units are operated at best efficiency, which is required in most cases, there is a sufficient spinning reserve without any extra operational costs. The operational costs to keep the reserves on standby include, in some situations, costs for personnel and other operating costs to keep the units ready to start within a specified time. These costs are low for a hydro unit.
Operational costs connected to activation of reserves costs consist of efficiency related costs generated by deviations from the best efficiency level, and also start up costs related to the need to involve extra units.
The costs caused by the drop in efficiency when reserves are activated can in some cases be high. We can see from the figure above that the drop in efficiency is small for most types of units. The units with the flattest efficiency curve are also the ones that are usually used for primary control services.
However, we must remember that the drop in efficiency affects the whole production from the specific unit, and not only the additional production that is needed to perform the control.
On the basis of such curves, it is reasonable to anticipate that the decrease in efficiency is 3% if the output is increased 20%. If this efficiency reduction, which affects the whole production, is charged the 20% that comes as an addition, we will see the cost increase is 15% relative to the ordinary production. This is a rough estimate, but gives a certain indication of the marginal cost increase.
We must include start-up costs when we activate a reserve that is ready to start. These costs consist of abrasion, and a certain amount of wasted water. These costs are small for hydro units.
We assume that a thermal system is capacity constrained. This means that capacity kept in reserve must be replaced by a different source to cover the maximum load, the other source usually consists of gas turbines. Even if it is a coal power plant, which is often used as primary power control, it would be correct to use a power cost equal to the similar investment cost for gas turbines.
Major investments are often made in thermal power plants to improve control capabilities, and to influence operational costs. This is related to how the control service is conducted.
There are several ways to provide primary control reserves in thermal power plants, but the most common method is to throttle the inlet valves on the high pressure turbine in conventional coal power plants. Extra energy is thereby stored in the boiler in the form of steam pressure, and can be released by fast turning the valves open. The duration of the power increase is limited by the accessible steam volume in the boiler. The negative consequence of this method is that power plants must operate with throttled valves and over-pressure as a standard setting, which reduces the efficiency by 0.5 percentage points, and also increases the fuel cost.
If a unit runs on part load due to control reserve requirement, another unit with accessible capacity must replace the capacity reduced. Since this unit has unused capacity, it will most likely have higher operational costs. If there are no units with accessible capacity, the missing capacity must be obtained from elsewhere, either from neighbouring areas, or in a worst case scenario, from a brand new system.
Estimates of compensation costs, must be based on operation simulations on units with load curves for typical day and night productions. Generally, these costs will be highest in peak periods, where the number of units run on rated load is high. In off peak periods there is often enough available capacity in the running units, so there is no need to compensate for the reserve capacity.
Secondary control reserve
The secondary control reserve is normally spinning reserve in a thermal system. It is not normal to include start/stop procedures in the automatic control functions, even if fast starting gas turbines are used as a part of the secondary control. Usually, a number of preordain power plants with excellent control capabilities are used for this purpose. These power plants are directly linked to the national or regional secondary regulator.
Producers with pump, or in-storage power plants available, will usually use these for secondary control since the hydro plants are considered excellent control sources with hardly any costs.
One important issue here is that pumped storage power plants are not adjustable when they are in pump mode. This means that in low load periods when the plant pumps water (night/weekend), other units must contribute to the secondary control.
The costs associated with the secondary control are found by estimation of load curves for chosen day and night periods. The requirement for the spinning reserve to be available at any time, will represent a restriction on the operation of the system that is normally based on a cost minimisation objective, and contribute to a lower profit for the plant. The difference between accumulated costs without restrictions, and at operations when the reserve requirement is fulfilled, will give an estimation of how valuable the secondary control reserve from a hydro system can be as a service to typical thermal systems.
With respect to load following, hydro generation has some inherent advantages compared with thermal units. The start up cost of a coal fired unit is about 100 times higher than for comparable hydro generators. These features contribute to cost savings if hydro and thermal systems are integrated.
Interconnection can be affected by deregulation. One motivation for interconnection in a competitive environment is its contribution to increased competitive pressure. This will in most cases contribute to improved efficiency.
One important aspect in a competitive setting is how different factors affect market price. If one region has a surplus of cheap electricity and correspondingly low prices and another country has comparatively high generation cost and high prices, it is evident that an interconnection will affect the price level in the two countries. On the lower price side the price will go up and on the higher price side the price will go down. So generators in the low price country will probably benefit from an interconnection and generators in the low price country will suffer.