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Replacing Pressure Reducing Valves with Backpressure Steam Turbine-Generators
in Heat Plant
By Vivek Srivatsa
Current Process
The heat plant currently operates on a modified Rankine cycle (Figure 1). In the plant, the boilers operate
on steam at 180 psig, while the heat exchangers must operate on steam at 25 psig. In between the two,
there are pressure reducing valves (PRVs) that lower the incoming steam pressure from the boiler to the
working pressure of the heat exchangers. This is the pressure reducing station.
Figure 1: The modified Rankine cycle that the heat plant operates on, and the corresponding T-s diagram.
There are three different paths for steam in this cycle. The first is 1-2-3-5-6-hot well-deaerator-1.
Although we say point 1 is the pump inlet, in reality the cycle starts when coal is conveyed to a bunker
with the boilers. An economizer uses the boiler exhaust gases to preheat the cold water used to fill the
boiler up to its boiling point (hence the temperature increase from point 2 to the point on the saturation
dome). Heat is then transferred to the steam inside the boiler (Qin). Following this, the steam passes
through a set of pressure reducing valves. The PRVs act isenthalpically, reducing the steam pressure from
180 psi to 25 psi, and the steam is left slightly superheated. While passing through the heat exchanger,
some energy is required to overcome the superheat, while the remaining heat QL1 is rejected to the
medium temperature hot water that goes out and does useful work heating the academic Grounds. The
liquid then enters a hot well. We will discuss the second path before continuing with the hot well.
The second path that the steam takes is 1-2-3-4-7-hot well-deaerator-1. It differs from the first path
starting at point 3. The steam is sent out to the University and its pressure is reduced through hundreds of
PRVs located on Grounds (and modeled isenthalpically, where the steam exits slightly superheated). The
steam then flows through hundreds of on-Grounds heat exchangers (represented by a single heat
exchanger on the cycle) that operate on steam at atmospheric pressure. The steam goes out to heat the
hospital and Grounds through these heat exchangers (QL2), and comes back to the plant as condensate.
From here, the condensate as well as the liquid from the previous path both enter the hot well, and come

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to atmospheric pressure at around saturation (so the hot well is essentially at point 7 as well). We will
discuss the final path before moving on to the deaerator.
The third path for the steam is 1-2-3-5-8-deaerator-1. The difference here is at point 5. After flowing
through the PRVs and being reduced to a pressure of 25 psi, some steam flows through another set of
PRVs that further reduces the pressure to 5 psi. The saturated steam at point 8 then flows to an open
feedwater heater (a deaerator) where it mixes with the condensate from the hot well. Here, saturated
liquid is formed, and we have our outlet at point 1. Then, the liquid flows to the feedwater pumps where
the pressure is increased to 180 psi, and we start our process over again.
In a traditional Rankine cycle, there is a work output from the turbine. However, since this modified cycle
uses PRVs in the pressure reducing station, there is no work outputted, so the Wout term in the cycle
efficiency equation is 0:
𝜂 =
𝑊𝑜𝑢𝑡 − 𝑊𝑖𝑛 + 𝑄 𝐿1 + 𝑄 𝐿2
𝑄𝑖𝑛
Proposed Change
With the current system of PRVs, there is no work output from the pressure reducing station. In a
traditional Rankine cycle, when the steam enters and expands through a turbine, the internal energy is
converted to shaft work, resulting in a positive Wout term, which therefore means a more efficient cycle.
Figure 2: The proposed cogeneration cycle that the heat plant would operate on and corresponding T-s diagram.
For this plant, a potentially effective way to increase the cycle efficiency would be to install a
backpressure turbine-generator to conduct the pressure reducing process between the boilers and the heat
exchangers (figure 2). A backpressure steam turbine-generator is a combination of a turbine connected
directly to an electrical generator. A microturbine would be sufficient for this application, as it can deliver
the appropriate power while also fitting in the heat plant. The steam expands through the turbine, resulting
in pressure reduction and electricity generation. It expands until reaching a pressure that the facility can
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use. Lower pressure steam is exhausted into a process header from the steam turbine, where a nozzle
directs high pressure steam against the turbine rotor blades. The blades are attached to a shaft which
rotates to produce power for the electrical generator. The energy from the high pressure inlet is converted
to electricity, and the low pressure exhaust steam is provided to a plant process. The amount of electricity
generated depends on required pressure drop and flow. The steam turbine-generator can be connected in
parallel with the existing PRVs, so that when it needs to be taken out for maintenance, the heat plant can
still run with the PRVs [1,2].
Energy and Cost Calculations
For preliminary efficiency calculations, we find the enthalpy at the various points of both the PRV cycle
and the turbine-generator cycle using known pressure values and the steam tables. We also give flow
values at various points. These values are summarized in figure 3.
PRVs Turbine-Generator
Notes: 1. Flow calculations are shown in appendix 1.
Figure 3: Property table for the PRV cycle (left) that the plant operates on and the hypothetical turbine-generator cycle (right)
To calculate the efficiency of using both PRVs and microturbine-generators, we find the heat and work
transfer rate terms throughout the cycle. We assume that the boiler operates at an 82% efficiency, and the
hypothetical turbine to be installed will operate at a 70% efficiency. These preliminary efficiency
calculations are summarized in figure 4.
Figure 4: Heat, work, and efficiency calculations for the plant using the existing PRVs and for the proposed microturbine-generator installation.

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We see that with the PRVs, the cycle efficiency is about 76.6%, while with the proposed microturbine-
generator installation, the efficiency slightly increases to 77.2%.
In figure 5, we show a Mollier diagram with both the PRV scenario and the microturbine scenario
outlined. The various colored lines represent different conditions associated with the scenario: black for
constant pressure (195 and 40 psia), green for the saturation line, red for the isenthalpic valve condition,
yellow for an isentropic turbine condition, and blue for the microturbine with 70% efficiency. The
enthalpy values for each condition are given to the left of the diagram, and from this, we can find the
enthalpy differences between different conditions.
Figure 5: Mollier diagram that outlines the process of the PRVs and the microturbine. The black lines represent constant pressure lines (195 and
40 psia), the green line represents the saturation line, the red line represents the isenthalpic valve condition, the yellow line represent an
insentropic turbine condition, and the blue line represent a microturbine with 70% efficiency.
Next we will conduct a cost analysis of backpressure turbine generators, using values given from the
master plan. We will provide calculations of the values given in the master plan.
We will look at BPT-3B from the master plan. The indicated pressure decrease is from 180 psig to 25
psig, and the enthalpy difference between the inlet and outlet streams given is 86.2
𝑏𝑡𝑢
𝑙𝑏
. Using a turbine
efficiency of 70% and a conversion factor of 1 btu = .293 Watt × hr, we find both the peak and annual
electrical generation as given in the master plan:
50,000
lb
hr
× 86.2
btu
lb
= 4,310,000
btu
hr
× .293
Watt ∙ hr
btu
= 1,260,000 Watt × .96 = 1,200 kW
299,787
klb
yr
× 86.2
btu
lb
= 26,000,000
kbtu
yr
× .293 = 7,500,000
kW ∙ hr
yr
× .96 = 7,200,000
kW ∙ hr
yr
In addition to this, the master plan includes a fuel cost, from which the electric savings are subtracted in
order to find annual savings. The issue with this is the fuel cost is not dependent on whether a
microturbine is installed, and therefore it should be ignored. A generated power cost is included in the
table below, but it does not have any impact on savings. With these new values calculated, parts of the
table given in the master plan are reproduced with the necessary alterations in figure 6:

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Notes: 1. Electric Peak = (Steam Peak) ∗ (h3−h5) ∗ (. 293071
Watt∙hr
btu
) ∗ (Generator Efficiency)
2. Electric Annual = (Steam Annual) ∗ (h3−h5) ∗ (.293071
Watt∙hr
btu
) ∗ (Generator Efficiency)
3. Electric Savings = Electric Annual ∗
$.059
KWH
4. Amort.Period =
Initial Cost
Electric Savings
5. Initial Cost Explanations and Calculations are given in Appendix 2
Figure 6: A revised analysis of backpressure turbine-generators as given in the master plan. Electric cost is $.059/KWH, fuel cost is
$5.70/mmbtu, turbine efficiency is 70%, boiler efficiency is 82%, and generator efficiency is 95%.
We can see the total savings and the payback period in figure 7 below. The lifetime for a backpressure
steam turbine-generator is about 20 years as given by the Department of Energy [1].
Figure 7: A graph of the lifetime savings for BPT-1. The payback period and the savings are indicted.
Carbon Footprint Calculations
The emissions factors for Natural Gas and Electricity are 117
lb
MMBtu
and 1.2
lb
kWh
respectively. Using a
boiler efficiency of 82% and a generator efficiency of 96%, we can find the following:
Natural Gas In =
7,199,400 kWh × 3413
Btu
kWh
. 82 Boiler Eff.× .96 Generator Eff.× 1,000,000
Btu
mmBtu
= 31,214 mmBtu
-4000000
-3000000
-2000000
-1000000
0
1000000
2000000
3000000
4000000
5000000
6000000
7000000
0 5 10 15 20 25
Savings($)
Time (yrs)
Lifetime Savings for BPT-1
Payback
Period Total Savings

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Natural Gas In CO2 =
1
DT
mmBtu
× 31,214 mmBtu × 117
lb CO2
mmBtu
2200
lb
mmBtu
= 1660
MT
yr
Electric Out CO2 =
7,199,400 kWh × 1.2
lb CO2
kWh
2200
lb
MMBtu
= 3927
MT
yr
Electric Out − Natural Gas In = 2267
MT
yr
.
The Carbon emissions for the backpressure turbine being considered are about 2300 metric tons per year.
Case Studies
Princeton University: Princeton replaced their pressure reducing valves with 2 backpressure turbine units
made by Carrier Corporation. Their Microsteam Power System has a small footprint due to its vertical
shaft design. This arrangement has a better turn-down capability over horizontal steam turbines, which
gives better low-load performance. The two units operate in parallel, and provide 550 kW at peak. The
inlet steam pressure is between 180 psig and 220 psig, and produces 4 million kWh for the university
annually. The Microsteam turbine takes the superheated low-pressure steam that exits the PRV, which has
the same energy content as the high pressure steam, and converts it to power that generates up to 275 kW
of electricity per unit. The turbines reduce greenhouse gas emission by over 1,200 tons of CO2 annually
[5].
Indiana University operates a Microsteam turbine. It uses waste steam to generate electricity to power the
central heating plant, providing 20% of the required electricity. Their savings are $120,000 per year, and
CO2 emission are reduced by 2,000 tons per year. They installed the Microsteam power system in parallel
with the PRVs. This pressure reducing station reduces the steam from 150 psig to between 54 and 40 psig
[3].
Vanderbilt University: In 1986, Vanderbilt installed a 7000 kW backpressure steam turbine driven
generator. The load capacity is a function of steam demand; for every 27 lbs of steam flowing through the
main steam pipe leaving the power plant, 1 kW is produced from the generator. The inlet pressure and
temperature are 650 psig and 750°F. Their turbine is a single-stage, impulse-type designed and
manufactured by Murray Turbomachinery as part of a complete turbine-generator package. The exhaust
steam from the backpressure turbine is directed to a campus steam distribution system. The turbine
control is provided by a Woodward Dg 505 governor configured for exhaust pressure control between 60
and 125 psig. Their turbine has a 10’’ inlet and the operating speed is 9807 RPM. The electrical generator
is manufactured by Ideal Electric Company and produces 7850 kW at 4160 Volts and 60 Hz when the
turbine is provided with 200,000
𝑙𝑏
𝑊
of steam at 650 psig, 750°F. In 2000, Vanderbilt installed 2 natural
gas turbine generators [6].

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Penn State: Uses backpressure turbine cogeneration in their West Campus steam plant. Low (13 psig) and
medium (150-170 psig) pressure steam is delivered separately to the campus, and electricity is also
generated. Both the turbines and generators are manufactured by Elliot. Their steam capacity is 350,000
(117,000 from a different source) PPH, electrical capacity is 6 (7) MW, and overall plant efficiency is
between 50 and 70%. One of their current projects is to replace two of their existing backpressure steam
turbines that are over 50 years old, which they estimate will be less than a 5.5 year payback [7,8].
Pre-design Phase
Equipment and Location: The plan is to install a backpressure steam microturbine along with a
synchronous generator in the heat plant. The unit should be able to fit through a double door. Two quotes
from manufacturers are included in Appendix 4; one from Elliott and one from AirClean Technologies.
The Elliott Turbine dimensions are about 193’’ x 96’’ x 70.5’’. Auxiliary equipment includes steam traps
and condensate drains. Additional considerations involve the heat exchanger that the steam travels to
following the pressure reducing station. The heat exchanger performance at lower temperatures should be
further evaluated, since it is usually designed for a temperature change of 40°F, but during the winter the
temperature change is greater.
The following are potential locations for the turbine-generator to be installed:
1. The area in front of the pressure reducing valves, although there may be too little space to fit the
set. The benefit is the ease of feeding the steam with different pressures through the turbine, due
to proximity. Drawbacks include the lack of space, and the need for the flooring to be redone.

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2. Another option is on the entry floor, just next to the control room. It is more spacious, although it
is more difficult to feed piping from the existing steam.
3. The best option would be to install the set in the basement. The double doors for entry are located
a few feet away, and the steam can be fed directly downward to this location. In addition, the
domestic hot water tanks and old condensate pumps and flash tank will be removed, so there will
be plenty of space in the bay. This is highlighted in red in figure 8. The steam is exhausted at the
coordinate A.7 x 6, and it will move perpendicularly up from around the middle of the turbine.
The supply steam is located towards the end of the turbine.

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Figure 8: A portion of a diagram of the heat plant, where the red marks represent the bays for the turbine-generator set.
Piping: Piping is based on the velocity of the steam through the pipe. In this case, the steam flow is
50,000
lb
yr
. The inlet to the turbine is saturated steam at 180 psig. Our design limit will be steam moving at
100
ft
sec
, or 7200
ft
min
. We look up pipe sizes in the Camron’s Hydraulic Data manual, finding the external
diameter, thickness, and internal diameter. For an 8 inch pipe, the external diameter is 8.625 inches and
the thickness is .322 inches. This means that the internal diameter is 7.981 inches. We calculate the area
(𝐴 =
𝜋𝐷2
4
) to be .347 ft2
. We also know that the specific volume of steam at our given conditions is 2.345
𝑓𝑡3
𝑙𝑏
. We can therefore find the velocity of steam through an 8 inch pipe:
𝑣 = 50,000
lb
hr
× 2.345
ft3
lb
÷ .347ft2
÷ 3600
sec
hr
= 93.86
ft
sec
We see that the velocity is within our design limit of 100
ft
sec
. Therefore, our inlet pipe size will be 8
inches. The turbine outlet conditions are saturated steam at 25 psig with 50,000
lb
yr
flow. Our design limit
will again be 100
ft
sec
. At these conditions, the specific volume is 10.4965
𝑓𝑡3
𝑙𝑏
. After looking up pipe sizes
we see that an 18 inch pipe is an external diameter of 18.0 inches and a thickness of .375 inches, which
gives an internal diameter of 17.25 inches. From this, we calculate the area (𝐴 =
𝜋𝐷2
4
) to be 1.623 ft2
. We
can therefore find the velocity of steam through an 18 inch pipe:

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𝑣 = 50,000
lb
hr
× 10.4965
ft3
lb
÷ 1.623ft2
÷ 3600
sec
hr
= 89.82
ft
sec
Again, this velocity is within our 100
ft
sec
design limit, so the outlet pipe size will be 18 inches. These
calculations don’t take into consideration the effect that elbows and joints may have on the piping due to
pressure drops. The pipe sizings may need to be increased to combat this.
Electrical Connections: There are two options for the electrical connections:
1. The switchgear for the heat plant allows a maximum voltage of 480 V. Therefore, electricity
could be generated at 480 V in parallel with the transformers on the heat plant side of the
substation. To connect the generator to the switchboard, an insulated copper cable will be used.
The cable should be rated 600 V (so that it can carry 480 V) and be large enough to meet the
ampacity demands.
2. Generate power at 12.5 kVA and feed it to the other side of the transformer so that it is in parallel
with the Cavalier substation side. In this case, the cable voltage rating will be higher but the
diameter of the cable will be smaller due to the decreased ampacity.
Controls: The two vendors whose quotes are given in the appendix both specify a Siemens S7-300
controller. This controller will have to communicate with the rest of the heat plant by integrating with the
existing Toshiba DCS control system that is in place. This could be accomplished through communication
with Modbus.
References
1. http://www.energy.gov/sites/prod/files/2014/05/f16/steam20_turbogenerators.pdf
2. http://members.questline.com/Article.aspx?articleID=21655&accountID=1693&nl=12597
3. http://dms.hvacpartners.com/docs/1001/Public/02/CASESTUDY60.pdf
4. http://www.energent.net/documents/microsteam_brochure.pdf
5. http://dms.hvacpartners.com/docs/1001/Public/04/CASESTUDY57.pdf
6. http://www.vanderbilt.edu/plantops/plant.php
7. http://www.opp.psu.edu/about-opp/divisions/ee/util/steam-services/overview-of-steam-services
8. https://fod.osu.edu/utilities/files/2012_big_10.pdf
9. https://www1.eere.energy.gov/manufacturing/tech_assistance/pdfs/steam22_backpressure.pdf

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Appendix 1: Flow Calculations
We first have the diagram of the cycle that the plant operates on. We start by labeling the flow in the
portion between the feedwater pumps and the boilers (1 and 2) as x. Each time the cycle branches out
from a junction, the flow in each branch is different from the flow that enters the point. We represent this
by labeling the flow in one branch with a second variable, and labeling the flow in the other branch as the
difference between the flow entering the junction and the flow in the first branch. The reason there are
only 5 flow labels is because each device operates on the steady-flow condition. This means that the flow
entering a device is the same as the flow exiting the device. The flow exiting the hot well is the sum of the
flows at point 6 and 7 (which is 1-x), but we don’t include this because it is not needed for the heat and
work rate calculations.
Having established the points at which we have different flow values, we can solve for the actual values.
By looking at a schematic of the heat plant (not shown here), we find that the flow value at x is 270,000
PPH, at y is 50,000 PPH, and at z is 6000 PPH. With these values, we can calculate that the flow (x-y) is
220,000 PPH, and the flow (y-z) is 44,000 PPH. These calculations are summarized in the table below:

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Appendix 2: Initial Cost Calculations
The Department of Energy gives a range of costs for backpressure turbogenerators based on electrical
output. For 150 kW systems, the equipment cost is $900 per kW, and for $2000 kW systems, the cost is
$200 per kW. We assume a linear relationship, and plot in order to find costs for the systems under our
consideration, shown below.
The equation for the line is given on the graph, and the peak electrical generation value can be plugged in
for x to find the cost per kW for the specific turbine-generator system. In order to find the total equipment
cost for each system, the cost per kW is multiplied by the peak electrical generation. Per the Department
of Energy, installation costs are generally 75% of equipment costs [9]. In addition, other costs such as
operation and maintenance need to be factored in. The quotes given in the ‘Manufacturer Quotes’ section
have some cost numbers included.
y = -0.3784x + 956.76
0
100
200
300
400
500
600
700
800
900
1000
0 200 400 600 800 1000 1200 1400 1600 1800 2000 2200
Cost($/kW)
Output (kW)
Cost vs. Output for Backpressure
Turbine-Generators

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Appendix 3: Sankey Diagram
The following is a Sankey diagram for the heat plant with the hypothetical turbine installed:
Appendix 4: Manufacturer Quotes
From Elliott: pages 14-28
From AirClean Technologies: pages 29-38

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