Masters G.M. Renewable and Efficient Electric Power Systems

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188 DISTRIBUTED GENERATION

Solar field

Hot

tank

Cold

tank

Pump

Heater

Air-cooled

condenser

Inlet manifold Inlet manifold

Turbine

Generator

Boiler

Cooling towers

Gear

Motor

Figure 4.11 An organic Rankine-cycle, solar-trough system that eliminates the need for

cooling water. From NREL, in Price et al. (2002).

cooling towers are used, the water demand is still high. Since these plants are

likely to be located in desert areas, where water is precious, it would be highly

advantageous to develop a trough technology that might eliminate this constraint.

One approach, shown in Fig. 4.11, is based on a modiﬁed, organic ﬂuid, Rankine-

cycle technology currently used in geothermal power plants. The key is the use

of an organic ﬂuid that can be condensed at above-atmospheric pressures using

air-cooled, fan-driven, cooling towers. This technology is being evaluated for

relatively small plants, on the order of 100 kW to 10 MW, which could make

them attractive for remote or distributed generation applications.

The SEGS experience has demonstrated that solar trough systems can be

reliable and reasonably cost effective. Operating experience with the later 80-

MW SEGS plants show overall annual solar-to-electricity efﬁciencies of around

10% with generation costs of about 12¢/kWh (in 2001 dollars), which makes

them the least expensive source of solar electricity today. Advanced, 200-MW

plants with more efﬁcient thermal storage units and reﬁnements in receivers

coupled with general cost reductions associated with gained experience suggest

that electricity from future solar-trough systems could be close to 5¢/kWh (Price

et al., 2002). While this technology was ﬁrst demonstrated on a large scale in the

United States, much of the current development is taking place in other countries,

including Spain, Greece, Italy, India, and Mexico.

CONCENTRATING SOLAR POWER (CSP) TECHNOLOGIES 189

4.3.3 Solar Central Receiver Systems

Another approach to achieving the concentrated sunlight needed for solar thermal

power plants is based on a system of computer-controlled mirrors, called

heliostats, which bounce sunlight onto a receiver mounted on top of a tower

(Fig. 4.12).

The evolution of power towers began in 1976 with the establishment of the

National Solar Thermal Test Facility at Sandia National Laboratories in Albu-

querque, New Mexico. That soon led to the construction of number of test

facilities around the world, the largest of which was a 90-m-tall, 10-MW power

tower, called Solar One, built near Barstow, California. In Solar One, water was

pumped up to the receiver where it was turned into steam that was brought back

down to a steam turbine/generator. Steam could also be diverted to a large, ther-

mal storage tank ﬁlled with oil, rock, and sand to test the potential for continued

power generation during marginal solar conditions or after the sun had set. While

thermal storage as a concept was successfully demonstrated, there was a sizable

mismatch between the storage tank temperature and the temperature needed by

the turbine for maximum efﬁciency.

Solar One operated from 1982 to 1988, after which time it was dismantled;

parts of it, including the 1818 heliostats and the tower itself, were reused in

another 10-MW test facility called Solar Two. While Solar One used water as

the heat exchange medium, Solar Two used molten nitrate salts (60% sodium

nitrate and 40% potassium nitrate). A two-tank, molten-salt thermal storage sys-

tem replaced the original oil/rock storage tank in the conﬁguration shown in

Fig. 4.13. The molten-salt system has proven to be a great success. Its temper-

ature of 565

◦

C well matches the needs of the steam turbine, and its round-trip

efﬁciency (the ratio of thermal energy out to thermal energy in) was greater than

97%. It was designed to provide enough storage to deliver the full 10-MW output

of the plant for an extra three hours past sunset. With reduced output, it could

deliver power for much longer periods from stored solar energy.

Central

receiver

Heliostats

Figure 4.12 Central receiver system (CRS) with heliostats to reﬂect sunlight onto a

central receiver.

190 DISTRIBUTED GENERATION

Central

receiver

Hot salt

565°C

Hot salt

storage

tank

Heliostats

Cold salt 285°C

Turbine

Generator

Cooling

water

Condenser

Cold salt

storage tank

Steam generator

Figure 4.13 Schematic of a molten-salt central receiver system.

After operating for three years, Solar Two was decommissioned in 1999. Since

then, a design team from the United States and Spain has proposed construction

of a 15-MW Solar Tres, to be located somewhere in Spain. This system will

have a much higher ratio of heliostat area to rated generator power and a much

larger molten-salt thermal storage tank, which will enable it to operate at full

capacity for over 12 h on stored energy alone. Systems with more collector area

than is needed to run the turbines while the sun is out, augmented with more

thermal storage to save that extra solar energy until it is needed later, could

become reliable sources of power, ready when needed to meet typical afternoon

and evening peak demands. This dispatchability advantage of power towers with

thermal storage would add considerably to their value.

The future of central receiver systems is promising, but somewhat uncertain.

Molten-salt power towers are the most well understood technology, but to be cost

effective they need to be made much larger—probably on the order of 100 MW,

which means that the ﬁrst ones will cost hundreds of millions of dollars. The

ﬁnancial risk for the ﬁrst plants will likely be a signiﬁcant deterrent. There are

also emerging power tower technologies that use air as the working ﬂuid rather

than molten salt. Solar-heated air could be used directly in a steam generator

for a conventional Rankine-cycle power plant, or it might be used to preheat

air leaving the compressor on its way to the combustor of a gas turbine in a

combined-cycle hybrid power plant.

4.3.4 Some Comparisons of Concentrating Solar Power Systems

The three approaches to concentrating solar thermal power systems—dish Stir-

ling, parabolic trough, and central receiver—can be compared from a variety of

perspectives. Although they share the same fundamental approach of using mir-

rored surfaces to reﬂect and concentrate sunlight onto a receiver creating high

enough temperatures to run a heat engine with reasonable efﬁciency, they are in

many ways quite different from one another.

CONCENTRATING SOLAR POWER (CSP) TECHNOLOGIES 191

With regard to efﬁciency, all three of these technologies incorporate heat

engines, which means the higher the temperature of the heat source, the greater the

potential efﬁciency. The key to high temperatures is the intensity of solar radiation

focused onto the receiver, which is usually expressed in dimensionless “suns” of

concentration where the reference point of 1 sun means no concentration. Dish

Stirling systems achieve concentration ratios of about 3000 suns, power towers

about 1000 suns, and parabolic trough systems about 100 suns. Not surprisingly,

the corresponding efﬁciencies of these technologies follow the same ranking,

with dish Stirling the highest and parabolic trough the lowest.

There are a number of measures of efﬁciency, including peak efﬁciency under

design conditions, annual efﬁciency as measured in the ﬁeld, and land area

required per unit of electrical output. The current annual efﬁciency from sun-

light hitting collectors to electrical energy delivered to the grid for these systems

is approximately: Dish Stirling 21%, power towers 16%, and parabolic troughs

14%. In terms of land area required, however, power towers suffer because of

the empty space between tower and mirrors, so the rankings shift some. Dish

Stirling requires about 4 acres per MW, parabolic troughs about 5 a cres/MW,

and power towers about 8 acres/MW.

Another important concern for solar systems in general is whether they can

deliver electricity whenever it is needed. All three of these CSP technologies

can be hybridized using fossil fuel auxiliary heat sources, so they are the some-

what the same in that regard. Another way to achieve reliability, however, is

with thermal storage; in that regard, parabolic troughs and power towers have

an advantage over dish Stirling engines. When thermal storage is the backup

rather than fuel combustion, systems are easier to permit since they can be

100% solar.

Since all CSP technologies need to be able to focus the suns rays, they will

most likely be used in areas with very clear skies. If those are desert areas,

minimizing the need for cooling water can be a signiﬁcant concern. In that

regard, Dish Stirling engines, which need no cooling water have the advan-

tage over current designs for troughs and towers. They also make very little

noise and have a r elatively low proﬁle so they may be easier to site close to

residential loads.

During the early stages of development, and as technologies begin to be

deployed, economic risks are incurred and the scale of the investments required

can be an important determinant of the speed with which markets expand. Small-

scale systems cost less per modular unit so the ﬁnancial risks associated with the

ﬁrst few units are similarly small. Dish Stirling systems appear to be appropri-

ately sized at about 25 kW each, but economies of scale play a bigger role for

troughs and towers and they may be most economical in unit sizes of about

100 MW. It seems likely to be easier to ﬁnd investors willing to help develop

$100,000 dish systems, working out the bugs and improving the technology as

they go along, than to assemble the hundreds of millions of dollars needed for a

single trough or tower system. Wind turbines, with their explosive growth, have

certainly beneﬁted from the fact that they too are small in scale.

192 DISTRIBUTED GENERATION

4.4 BIOMASS FOR ELECTRICITY

Biomass energy systems utilize solar energy that has been captured and stored in

plant material during photosynthesis. While the overall efﬁciency of conversion

of sunlight to stored chemical energy is low, plants have already solved the

two key problems associated with all solar energy technologies—that is, how

to collect the energy when it is available, and how to store it for use when the

sun isn’t shining. Plants have also very nicely dealt with the greenhouse problem

since the carbon released when they use that stored energy for respiration is the

same carbon they extracted in the ﬁrst place during photosynthesis. That is, they

get energy with no net carbon emissions.

While there is already a sizable agricultural industry devoted to growing crops

speciﬁcally for their energy content, it is almost entirely devoted to converting

plant material into alcohol fuels for motor vehicles. On the other hand, biomass

for electricity production is essentially all waste residues from agricultural and

forestry industries and, to some extent, municipal solid wastes. Since it is based

on wastes that must be disposed of anyway, biomass feedstocks for electricity

production may have low-cost, no-cost, or even negative-cost advantages.

Currently there are about 14 GW of installed generation capacity powered

by biomass in the world, with about half of that being in the United States.

About two-thirds of the biomass power plants in the United States cogenerate

both electricity and useful heat. Virtually all biomass power plants operate on a

conventional steam–Rankine cycle. Since transporting their rather disbursed fuel

sources over any great distances could be prohibitively expensive, biomass power

plants tend to be small and located near their fuel source, so they aren’t able to

take advantage of the economies of scale that go with large steam plants. To

offset the higher cost of smaller plants, lower-grade steel and other materials are

often used, which requires lower operating temperatures and pressures and hence

lower efﬁciencies. Moreover, biomass fuels tend to have high water content and

are often wet when burned, which means that wasted energy goes up the stack

as water vapor. The net result is that existing biomass plants tend to have rather

low efﬁciencies—typically less than 20%. Even though the fuel may be very

inexpensive, those low efﬁciencies translate to reasonably expensive electricity,

which is currently around 9¢/kWh.

An alternative approach to building small, inefﬁcient plants dedicated to

biomass power production is to burn biomass along with coal in slightly modiﬁed,

conventional steam-cycle power plants. Called co-ﬁring, this method is an

economical way to utilize biomass fuels in relatively efﬁcient plants. And, since

biomass burns cleaner than coal, overall emissions are correspondingly reduced

in co-ﬁred facilities.

New combined-cycle power plants don’t need to be large to be efﬁcient, so it is

interesting to contemplate a new generation of biomass power plants based on gas

turbines rather than steam. The problem is, however, that gas turbines cannot run

directly on biomass fuels since the resulting combustion products would damage

the turbine blades, so an intermediate step would have to be introduced. By gasify-

ing the fuel ﬁrst and then cleaning the gas before combustion, it would be possible

BIOMASS FOR ELECTRICITY 193

to use biomass with gas turbines. Indeed, considerable work has already been

done on coal-integrated gasiﬁer/gas turbine CIG/GT systems. CIG/GT systems

have not been commercialized, however, in part due to gas-cleaning problems

caused by the high sulfur content of coal. Biomass, however, tends to have very

little sulfur, so this problem is minimized. Moreover, biomass tends to gasify eas-

ier than coal, so it may well be that it will be easier to develop biomass-integrated

gasiﬁer/gas turbine (BIG/GT) systems than to develop CIG/GTs. Biomass fuels

do, however, have rather high nitrogen content, and control of NO

would have

to be addressed. It is projected that BIG/GT plants could generate electricity at

about 5¢/kWh.

A two-step process for gasifying biomass fuels is illustrated in Fig. 4.14. In the

ﬁrst step, the raw biomass fuel is heated, causing it to undergo a process called

pyrolysis in which the volatile components of the biomass are vaporized. As the

fuel is heated, moisture is ﬁrst driven off; then at a temperature of about 400

◦

the biomass begins to break down, yielding a product gas, or syngas, consisting

mostly of hydrogen (H

), carbon monoxide (CO), methane (CH

), carbon dioxide

(CO

), and nitrogen (N

) as well as tar. The solid byproducts of pyrolysis are

char (ﬁxed carbon) and ash. In the second step, char heated to about 700

◦

C reacts

with oxygen, steam, and hydrogen to provide additional syngas. The heat needed

to drive both steps comes from the combustion of some of the char.

The relative percentages of each gas vary considerably, depending on the tech-

nology used in the gasiﬁer, and so does the heating value of the mix. High heating

values (HHV) of syngas ranges from about 5.4 to 17.4 MJ/m

. For comparison,

natural gas typically has an HHV of anywhere from 36 to 42 MJ/m

Pyrolysis reactions can also be used to convert biomass to liquid, as dia-

grammed in Fig. 4.15. Different temperatures and reaction rates produce energy-

rich vapors that can be condensed into a liquid “biocrude” oil with a heating

value about 60% that of diesel fuel.

Another technology for converting biomass to energy is based on the anaero-

bic (without oxygen) decomposition of organic materials by microorganisms to

produce a biogas consisting primarily of methane and carbon dioxide. The bio-

chemical reactions taking place are extremely complex, but in simpliﬁed terms

Pyrolysis

Biomass

Char

Conversion

Combustion

Char

Char & Ash

Heat

Vapors

(Syngas)

Ash &

Exhaust Gases

Heat

Vapors (Syngas)

Syngas

Figure 4.14 Biomass gasiﬁcation process.

194 DISTRIBUTED GENERATION

Pyrolysis

Biomass

Combustion

Char & Ash

Exhaust Gases

Heat

Vapors

Condenser

Non-condensible Vapors

Biocrude Oils

Figure 4.15 Biomass pyrolysis used to create liquid biocrude oil.

they can be summarized as

+ H

O + bacteria → CH

+ CO

+ NH

+ H

S + new cells

(4.2)

where C

is meant to represent organic matter, and the equation is

obviously not chemically balanced. The technology is conceptually simple, con-

sisting primarily of a closed tank, called a digester, in which the reactions can

take place in the absence of oxygen. The desired end product is methane, CH

and the relative amount of methane in the digester gas is typically between 55%

and 75%.

Anaerobic digesters are fairly common in municipal wastewater treatment

plants where their main purpose is to transform sewage sludge into innocuous,

stabilized end products that can be easily disposed of in landﬁlls or, sometimes,

recycled as soil conditioners. Anaerobic digesters can be used with other biomass

feedstocks including food processing wastes, various agricultural wastes, munic-

ipal solid wastes, bagasse, and aquatic plants such as kelp and water hyacinth.

When the biogas is treated to remove its sulfur, the resulting gas can be burned

in reciprocating engines to produce electricity and usable waste heat.

4.5 MICRO-HYDROPOWER SYSTEMS

Hydroelectric power is a very signiﬁcant source, accounting for 19% of the global

production of electricity. In a number of countries in Africa and South America,

it is the source of more than 90% of their electric power. Hydropower generates

9% of U.S. electricity, which may sound modest, but it is still almost an order of

magnitude more than the combined output of all of the other renewables. Almost

all of that hydropower is generated in large-scale projects, which are sometimes

deﬁned to be those larger than 30 MW in capacity. Small-scale hydropower

systems are considered to be those that generate between 100 kW and 30 MW,

while micro-hydro plants are smaller than 100 kW. Our interest here is in micro-

hydropower.

The simplest micro-hydro plants are run-of-the-river systems, which means

that they don’t include a dam. As such, they don’t cause nearly the ecosystem dis-

ruption of their dams and reservoir counterparts. An example of a run-of-the-river

MICRO-HYDROPOWER SYSTEMS 195

Canal

Intake

Forebay

Penstock

Powerhouse

Figure 4.16 A micro-hydropower system in which water is diverted into a penstock and

delivered to a powerhouse below. Source: Small Hydropower Systems, DOE/GO-102001-

1173, July 2001.

system is shown in Fig. 4.16. A portion of the river is diverted into a pipeline,

called a penstock, that delivers water under pressure to a hydraulic turbine/

generator located in a powerhouse located at some elevation below the intake.

Depending on how the system has been designed, the powerhouse may also con-

tain a battery bank to help provide for peak demands that exceed the average

generator output.

4.5.1 Power From a Micro-Hydro Plant

The energy associated with water manifests itself in three ways: as potential

energy, pressure energy, and kinetic energy. The energy in a hydroelectric sys-

tem starts out as potential energy by virtue of its height above some reference

level—in this case, the height above the powerhouse. Water under pressure in

the penstock is able to do work when released, so there is energy associated with

that pressure as well. Finally, as water ﬂows there is the kinetic energy that is

associated with any mass that is moving. Figure 4.17 suggests the transforma-

tions between these forms of energy as water ﬂows from the forebay, through

the penstock, and out of a nozzle.

196 DISTRIBUTED GENERATION

Kinetic energy

/ 2

Pressure energy

Potential energy

Figure 4.17 Transformations of energy from potential, to pressure, to kinetic.

It is convenient to express each of these three forms of energy on a per unit

of weight basis, in which case energy is referred to as head and has dimensions

of length, with units such as “feet of head” or “meters of head.” The total energy

is the sum of the potential, pressure, and kinetic head and is given by

Energy head = z +

(4.3)

where z is the elevation above a reference height (m) or (ft), p is the pressure

(N/m

)or(lb/ft

), γ is the speciﬁc weight (N/m

)or(lb/ft

), v is the aver-

age velocity (m/s) or (ft/s), and g is gravitational acceleration (9.81 m/s

)or

(32.2 ft/s

In working with micro-hydropower systems, especially in the United States,

mixed units are likely to be incurred, so Table 4.5 is presented to help sort

them out.

TA BLE 4.5 Useful Conversions for Water

American SI

1 cubic foot = 7.4805 gal 0.02832 m

1 foot per second = 0.6818 mph 0.3048 m/s

1 cubic foot per second = 448.8 gal/min (gpm) 0.02832 m

Water density = 62.428 lb/ft

1000 kg/m

1 pound per square inch = 2.307 ft of water 6896 N/m

1kW= 737.56 ft-lb/s 1000 N-m/s

Example 4.3 Mixed Units in the American System. Suppose a 4-in.-diameter

penstock delivers 150 gpm of water through an elevation change of 100 feet.

The pressure in the pipe is 27 psi when it reaches the powerhouse. What frac-

tion of the available head is lost in the pipe? What power is available for the

turbine?

MICRO-HYDROPOWER SYSTEMS 197

Solution. From (4.3)

Pressure head =

27 lb/in.

× 144 in.

/ft

62.428 lb/ft

= 62.28 ft

To ﬁnd velocity head, we need to use Q = vA,whereQ is ﬂow rate, v is velocity,

and A is cross-sectional area:

v =

150 gal/ min

(π/4)(4/12 ft)

× 60 s/ min ×7.4805 gal/ft

= 3.830 ft/s

So, from (4.3) the velocity head is

Velocity head =

(3.830 ft/s)

2 × 32.2 ft/s

= 0.228 ft

The total head left at the bottom of the penstock is the sum of the pressure

and velocity head, or 62.28 ft + 0.228 ft = 62.51 ft. Notice the velocity head is

negligible. Since we started with 100 ft of head, pipe losses are 100 − 62.51 =

37.49 ft, or 37.49%.

Using conversions from Table 4.5, while carefully checking to see that units

properly cancel, the power represented by a ﬂow of 150 gpm at a head of

62.51 ft is

P =

150 gal/ min ×62.428 lb/ft

× 62.51 ft

60 s/ min ×7.4805 gal/ft

× 737.56 ft-lb/s-kW

= 1.77 kW

The power theoretically available from a site is proportional to the difference

in elevation between the source and the turbine, called the head H, times the

rate at which water ﬂows from one to the other, Q. Using a simple dimensional

analysis, we can write that

Power =

Energy

Time

Weight

Vo l u m e

Time

Energy

Weight

= γ QH (4.4)

Substituting appropriate units in both the SI and American systems results in the

following key relationships for water:

P(W)= 9810 Q(m

/s)H(m) =

Q(gpm)H(ft)

5.3

(4.5)

While (4.5) makes no distinction between a site with high head and low ﬂow

versus one with the opposite characteristics, the differences in physical facilities

are considerable. With a high-head site, lower ﬂow rates translate into smaller-

diameter piping, which is more readily available and a lot easier to work with, as