National Renewable Energy Laboratory 

Innovation for Our Energy Future 

A national laboratory of the U.S. Department of Energy

Office of Energy Efficiency & Renewable Energy

NREL is operated by Midwest Research Institute ● Battelle Contract No. DE-AC36-99-GO10337 

Parabolic Trough Solar System 

Piping Model 

Final Report 

May 13, 2002 — December 31, 2004 

B. Kelly 

Nexant, Inc. 

San Francisco, California 

D. Kearney 

Kearney & Associates 

Vashon, Washington 

Subcontract Report 

NREL/SR-550-40165 

July 2006 
Parabolic Trough Solar System 

Piping Model 

Final Report 

May 13, 2002 — December 31, 2004 

B. Kelly 

Nexant, Inc. 

San Francisco, California 

D. Kearney 

Kearney & Associates 

Vashon, Washington 

NREL Technical Monitor: H. Price 

Prepared under Subcontract No. AAA-2-32432-01 

Subcontract Report 

NREL/SR-550-40165 

July 2006

National Renewable Energy Laboratory

1617 Cole Boulevard, Golden, Colorado 80401-3393 

303-275-3000 • www.nrel.gov 

Operated for the U.S. Department of Energy 

Office of Energy Efficiency and Renewable Energy 

by Midwest Research Institute • Battelle 

Contract No. DE-AC36-99-GO10337
This publication was reproduced from the best available copy 

Submitted by the subcontractor and received no editorial review at NREL

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Parabolic Trough Solar System Piping Model Final Report 

NREL Contract No. AAA-2-32432-01 

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Parabolic Trough Solar System Piping Model 

Final Report 

Table of Contents 

A. Introduction...........................................................................................................1

B. Flabeg Solar System Piping Model.......................................................................3

C. NREL Solar System Piping Model ........................................................................5

D. General Comparison of Results..........................................................................16
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A. Introduction

One requirement in a conceptual design of a solar power plant is to estimate the cost of 

the solar steam system. The main elements of that cost estimate are the solar 

collectors, control system, heat transfer fluid (HTF) piping system, HTF pump system, 

and solar heat exchangers. The piping system consists of header piping, valves, and 

fittings. Since the piping system cost can constitute up to 10% of the total solar system 

cost, it is important to obtain a reasonably accurate estimate. 

The piping system design also affects performance. The pumping power required to 

circulate the HTF through the system is a significant contributor to the plant parasitic 

power requirement. Further, the piping heat loss reduces the useful heat delivered by 

the solar field to the power plant. 

As part of their performance and cost modeling development for parabolic trough power 

plant development, Flabeg Solar International (Cologne, Germany) developed an 

internal solar field piping model – termed SolPipe -- for use in their solar system design 

work on parabolic trough configurations. The purpose of the model was to estimate, for a 

solar field size and layout configuration, the piping system parts list, costs, and pumping 

power for the HTF flow at design capacity. These results can then be utilized to provide 

input into subsequent performance and investment cost models, with the final criterion 

being the impact of the solar field piping design on the overall levelized electricity cost. 

NREL requires a similar piping model to provide similar input to the Trough Excelergy 

parabolic trough plant performance and cost model. The purpose of the present work is 

to develop a spreadsheet model to satisfy this need. Flabeg has provided access to 

SolPipe for purposes of comparison of the methodology and results. 
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B. Flabeg Solar System Piping Model

Design Approach 

The basic method used by SolPipe is to calculate the HTF header configurations based 

on an assumed design flow velocity in the piping. This is a key design feature. The 

design velocity is chosen by the user as part of a process to approximately optimize 

solar field piping costs, that is, to find the velocity that optimizes the tradeoff between 

piping size and parasitic pumping power. Generally a values in the range of 2-3 m/s 

have been assumed based on past experience or results of optimizations. The input 

parameters to SolPipe basically set the total HTF flow, the flow per loop, the number of 

loops and the solar field configuration. In the design tradeoff, small header pipes would 

reduce piping and fitting costs, but increase pumping parasitics, while larger header 

pipes would have the opposite effect. Setting the design velocity, however, enables 

calculation of the pipe diameters for subsequent costing evaluations. 

Header Piping, Valves and Fittings 

In SolPipe, as in a real solar field, header pipe sizes change along the flow path to 

approximately maintain the design flow velocity. In a typical parabolic trough solar field 

configuration, the flow in the cold header is incrementally drawn off through a collector 

loop and passed to the hot header. Therefore the cold header piping diameters can be 

reduced along the header length, reducing costs and maintaining the appropriate 

velocity. The SolPipe code does this calculation automatically for the configuration 

chosen. In doing so, the code selects standard piping sizes that result in a flow velocity 

close to the desired design velocity. 

Expansion loops are placed in the cold and hot headers between every two loops in the 

solar field, following the design of the SEGS plants. Pipe supports for the headers also 

follow SEGS plant design practice. 

Following this calculation scheme, the results produced by SolPipe include: 

 number and size of pipe segments and fittings (such as reducers, elbows, and 

valves) for HTF system, including the headers and several loop piping elements such 

as the interconnection to the headers, the crossover pipes between rows, and 

interconnections within the SCA’s, i.e., ball joints or flex hoses. 

 insulation on pipes and fittings at prescribed thicknesses. 

 costs for elements described above. 

 pressure drops throughout the complete HTF system, including the SCA’s, and the 

resulting parasitic pumping power requirement. 

User Input 

Several types of input data are needed from the user: 

 number of collectors (to set the size of the solar field) 

 basic type of layout to determine the layout configuration, e.g., like the 30 MW or 80 

MW SEGS plants, or a straight-through (non-loop) system between parallel hot and 

cold headers. 

 number of collectors/loop (to determine layout configuration) 
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 sufficient power cycle information to set the HTF flow rate (either in a simplified or 

more detailed form). 

 other various layout parameters, e.g., distance between rows 

 unit cost data for piping and fittings by type and size 

 detailed assumptions related to pressure drop calculations 

The input data sheet is formatted to differentiate between input data that needs to be 

provided for each new case (like solar field size and power rating), and input data that is 

required for the calculations but is not often changed by the user (if ever, such as 

standard pipe sizes and basic solar collector design information). The HTF flow is 

calculated from power cycle data to be input by the user. Better results are obtained if 

detailed thermodynamic data is available from a power cycle calculation, but quite 

reasonable results can also be obtained via an optional method that requires only 

simplified power cycle data. 

Certain data is imbedded in the cost worksheets, such as piping, insulation and fitting 

costs, fluid properties, and valve arrangements. All these can, of course, be changed 

within the code if desired. 

Solar field layouts that can be modeled in the Flabeg code generally reflect SEGS 

design practice for 30 MW and 80 MW solar plants, and are specified by the user. 

Design Optimization 

For a typical solar power plant conceptual design study, an initial design configuration 

and flow velocity in the headers is chosen by the user. The results of SolPipe for piping 

cost and pumping power are fed into the Flabeg models for overall cost and 

performance, and the LEC determined. Variations on the input, such as the design 

velocity, are then varied to find the optimum value that provides the lowest LEC. For this 

specific parameter, recent results from the salt HTF study indicated that the LEC 

variation is relatively flat for a range of 2-4 m/s in flow velocity, with the lowest values at 

the low end. 
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C. NREL Solar System Piping Model 

Under contract to NREL, Kearney & Associates and Nexant worked together to develop 

a solar system piping model to develop piping system costs. Bruce Kelly of Nexant 

devised a new method for this purpose, with particular emphasis on incorporating added 

features in the model to automate the optimization method. The following description 

provides detailed information on the approach and construction of the model. 

Approach 

The coding of the new model differs completely from SolPipe, though the objectives are 

similar. One key difference is that the new model includes internal optimizations to 

arrive at a conceptual design. The optimum collector field piping arrangement should be 

one in which the sum of the following three elements is a minimum: 1) the capital cost of 

the pipe, insulation, and supports; 2) the equivalent capital cost of the thermal losses 

through the pipe insulation; and 3) the equivalent capital cost of the electric energy to 

circulate the fluid through the piping. 

A draft optimization model using Excel spreadsheet has been assembled which 

calculates the pipe capital and operating costs for two representative types of field 

layouts. The sections below describe how the model was assembled and how it 

operates. 

Generic Collector Field Layouts 

In the draft model, two field layouts are available as an option for the user: an ‘H’ field 

layout for collector field areas greater than 400,000 m2

, and an ‘I’ field layout for areas 

less than 400,000 m2

. 

‘H’ Field Layout

An example of a possible ‘H’ field piping layout for a representative 80 MWe plant has 

been prepared, as follows: 

 • The field is divided into 4 header-pair sections, with the power block located at 

the center of the field. Cold fluid is distributed from the cold header to solar fields on 

each side of the header, passing through a series of SCAs arranged in a row, crossing 

over at the end to an adjacent row, and returning to the hot header via a symmetrical set 

of SCAs. This arrangement is referred to as a “loop”. Hence there are similar loops on 

each side of the headers along the header length. In the base case, the headers run 

East-West. 

 • Each collector loop consists of 6 LS-3 solar collector assemblies, with the flow 

going out from the cold header through 3 assemblies, reversing direction, and then 

returning to the hot header through the remaining 3 assemblies. A total of 36 loops is 

supplied from the two headers. The arrangement is illustrated in Figure 1. 
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 • The pressure loss in the flow to the outermost loop defines the pressure loss in 

the flows through all of the loops. The pressure loss in the inner loops is set equal to the 

pressure loss in the outermost loop by the throttling action of either orifices or valves in 

the inner loops. 

 • The diameter of the cold header steps down as the distance from the power 

block increases to provide a roughly uniform fluid velocity in the header. Similarly, the 

diameter of the hot header increases as the distance to the power block decreases. 

Loop 1a

Loop 2a

Loop 14a

Loop 15a

Loop 16a

Loop 17a

Loop 18a

Section Cold Header

Section Hot Header

Cold Header

Section 3

Hot Header

Section 18

. . . . . . . . . . . . . . . . . . . .

From Power Block

via North-South

Cold Header

Loop 2b

Loop 1b

Loop 14b

Loop 15b

Loop 16b

Loop 17b

Loop 18b

To Power Block

via North-South

Hot Header

Figure 1. One Section of the Collector Field Layout for a Representative 80 MWe Plant 
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The flow rate in the East-West cold header for this example is 229 kg/sec, and is 

calculated as follows: 

(H_Thermin ol H_Thermino (4) J/kg) ,l

sec

J 0234,700,00

C 393 − C 288 

[1]

where 234,700,000 J/sec is the thermal rating of the collector field, and the ‘4’ represents one-fourth of the collector field. The flow rate in the standard collector loop is 6.4 

kg/sec, or 1/36th of the flow in the section header. The flow rate in the third header 

section is 217 kg/sec [229 kg/sec - (2)(6.4 kg/sec) for the two standard collector loops 

fed by this section]. The balance of the cold header and hot header section flow rates 

are calculated in a similar fashion. 

‘I’ Field Layout

An example of a possible ‘I’ field piping layout for a representative 30 MWe plant has 

been developed, as follows: 

 • The field is divided into 2 header-pair sections, with the power block located at 

the center of the field. 

 • A cold oil header, in parallel with a hot oil header, runs East-West through the 

center of the section. 

 • Each collector loop consists of 16 LS-2 solar collector assemblies, with the flow 

going out from the cold header through 8 assemblies, reversing direction, and then 

returning to the hot header through the remaining 8 assemblies. A total of 22 loops is 

supplied from the two headers. The arrangement is illustrated in Figure 2. 

The flow rate in the cold header for this example is 172 kg/sec, and is calculated as 

follows: 

(H_Thermin ol H_Thermino (2) J/kg) ,l

sec

J 88,000,000

C 393 − C 288 [2] 

where 88,000,000 J/sec is the collector field thermal rating, and the ‘2’ represents onehalf of the collector field. The flow rate in the standard collector loop is 7.8 kg/sec, or 

1/22nd of the flow in the quadrant header. The flow rate in the third header section is 156 

kg/sec [172 kg/sec - (2)(7.8 kg/sec) for the two standard collector loops fed by this 

section]. The balance of the cold header and hot header section flow rates are 

calculated in a similar manner. 
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Heat Transport Fluid Properties 

The user can select among the following heat transport fluids: Therminol VP-1; Caloria 

HT-43; Hitec, a eutectic mixture of sodium nitrite, sodium nitrate, and potassium nitrate; 

Hitec XL, a eutectic mixture of calcium nitrate, sodium nitrate, and potassium nitrate; and 

a binary nitrate salt mixture of sodium nitrate and potassium nitrate, or Solar Salt. The 

model contains the following thermodynamic properties for the five fluids, each as a 

function of temperature: density; specific heat; enthalpy; and absolute viscosity. 

Section Cold Header

Section Hot Header

Cold Header

Section 3

Hot Header

Section 11

. . . . . . . . . . . . . . . . . . . .

From Power Block

Loop 1b

To Power Block

Loop 11b

Loop 11a Loop 1a

Figure 2. One Section of the Collector Field Layout for a Representative 30 MWe Plant 
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Optimization Process 

The procedures for calculating the pipe diameters, wall thicknesses, and insulation 

thicknesses for each header section are outlined below. The only constraint on the 

design is the fluid pressure at the exit from the hot header must be equal to a minimum 

value set by the user. This feature is principally used with a synthetic oil heat transport 

fluid to ensure the fluid pressure always remains above the vapor pressure. 

Hydraulic and Thermal Development

1. Basic pipe dimension data, such as nominal diameter, wall thickness, and unit 

weight, for commercial pipe sizes between 2.5 and 48 inches are shown in the 

worksheet labeled “PipeData”. 

2. Allowable pipe stresses as a function of temperature are shown in the worksheet 

labeled “SvsT”. For fluid temperatures below 399 °C, the data are applicable for ASTM 

A106, Grade B, seamless carbon steel pipe. For fluid temperatures between 400 °C and 

510 °C, the data are applicable for ASTM A335, Grade P91, low alloy steel. 

3. For a given nominal pipe diameter, the required wall thickness is calculated using 

the familiar equation: 

) bar

Pa (100,000 1)bar (Pressure, (0.4)) MPaPa (2)(Allowa stress,ble (1,000,000 MPa)

) bar

Pa diameter, (Outside 1)bar (Pressure, (100,000 mm)

mm thickness, Wall

+ −

−

=

[3] 

 The allowable stress is a function of the pipe temperature, and is calculated 

through a curve fit of the data in “SvsT”. 

4. The actual wall thickness is calculated from the minimum wall thickness through 

the Excel function ActualWall(Dia, MinWall), where ‘Dia’ is the nominal pipe diameter in 

inches, and ‘MinWall’ is the calculated wall thickness from above. ActualWall is, in 

essence, a lookup table, which searches for the wall thickness that is the greater of the 

following: the first commercial pipe wall thickness greater than ‘MinWall’, or a minimum 

wall thickness of ‘STD’. 

5. Friction losses through the header sections, the heat collection elements, and the 

crossover piping, per meter of length, are calculated using the standard Darcy-Weisbach 

equation: 

⎥

⎥

⎥

⎥

⎦

⎤

⎢

⎢

⎢

⎢

⎣

⎡

⎥

⎦

⎤ ⎢

⎣

⎡ =

)

sec

,

,

2

m (2)(g

)

sec

m

 (Velocity,

m diameter, inside Pipe

m 1 (f)mh

c

2

f

[4]

where f is the friction factor, and gc is the acceleration due to gravity. The friction factor 

is calculated using the FricFactor(Rough, Reynold) function in Excel, where ‘Rough’ is 
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the relative pipe roughness, and ‘Reynold’ is the Reynolds number. The relative 

roughness is: 

mm diameter, inside Pipe

commercial for roughness absolute mm 0.0457 pipe steel

 [5] 

The Reynolds number is calculated using internal Excel Functions for the absolute 

viscosity and density of the selected heat transport fluid. 

6. Friction losses through the pipe fittings are calculated using: 

⎥

⎦

⎤ ⎢

⎣

⎡ = factor Friction

m diameter, inside Pipe e K L

 [6] 

 and 

m) loss, head pipe )(UnitL m loss, head Fitting e = ( [7] 

where Le is the pipe length which gives the same pressure loss as the fitting, and K is 

the fitting factor. 

The types of fittings in the model include reducers (both expansion and contraction 

losses); short-, medium-, and long-radius elbows; check valves; gate valves; tees; and 

ball joints. The number of each type of fitting in the cold header sections is set in Rows 

10 through 20 of the worksheet labeled “PressureLosses”. The number and type of 

fittings for the hot header sections are set in Rows 133 through 143. 

Several of the types and locations of the fittings were set automatically by the program, 

as follows: 

 • A header reducer was located at each change in the header diameter. 

 • An isolation gate valve was located at the inlet to, and outlet from, each loop. 

 • A globe valve was located in each loop for flow rate control. 

 • A Weldolet was located at the inlet to, and outlet from, each loop for 

 connecting the loop piping to the header. 

 • Each crossover pipe had two standard elbows, and each collector loop had 

 10 standard elbows. 

 • The number of ball joint assemblies in a loop was equal to [2 + Number of 

 solar collector assemblies in the loop]. 

 • The header between every other loop had an expansion loop, with 4 long 

 radius elbows in the loop. 

 • A gate valve was located at the inlet to, and outlet from, the hot and cold 

 headers for each field section; i.e., there were 4 gate valves for an ‘I’ field 

 configuration, and 8 gate valves for an ‘H’ configuration. 

7. The pressure distribution through the cold and the hot headers is a function of 

the local fluid velocities, pipe diameters, and wall thicknesses. However, the wall 

thickness is also a function of the pressure distribution. The button labeled “Adjust 

pressure” recalculates both the pressure at the inlet to the cold header and the local pipe 
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wall thicknesses such that pressure at the outlet of the hot header is equal to the 

minimum value set by the user. 

8. Unit thermal losses through the pipe insulation are calculated as follows: 

( ) ⎥

⎥

⎥

⎥

⎦

⎤

⎢

⎢

⎢

⎢

⎣

⎡

=

i

o

r

r

o ambient o inside o

ln

C) ,T-C ,m)(T )(1

C-m-sec

J (k,(2)(

 m-J/sec loss, Heat

π )

 [8] 

 where k is the thermal conductivity of the insulation, ro is the outside radius of the 

insulation, and ri

 is the inside radius of the insulation. The thermal conductivity is 

evaluated at the average of the inside and the ambient temperatures. The conductivity 

values are derived from a curve fit of the data on the worksheet labeled “Insulation k vs 

T”. For the purposes of the model, the thermal resistances of both the inside and the 

outside convection coefficients are assumed to small compared to the conduction 

resistance, and, for simplicity, are ignored. 

Annual Losses Development

1. The annual pumping energy for each segment of pipe is assumed to follow a 

“cube root mean cubed” function; i.e., the pressure loss is proportional to the square of 

the velocity, and the pumping power is proportional to the flow rate times the pressure 

loss. The equations are as follows: 

 MWtfluid, workingto power Design

hours time, operating field collector Annual

 MWt)fluid, workingto (Power

fraction flow Average

3

hours time, operating field collector Annual

3

∑

=

1

 [9] 

 and 

energy pump Annual = kWhe demand,

)efficiency pump annual )(0.75 hr

sec )(3600 seckW

J (1000

) hr

sec )(3600 sec2

m hours)(Des time, operating field collector (Annual kg/sec)(Av rate, flow ign ,m)(g loss, head erage c

−

[10] 

 where Average head loss, m = (Design head loss, m)(Average flow fraction) 

 The hourly values for the power to the working fluid, shown on the worksheet 

labeled “HourOutput”, were taken from an Trough Excelergy output file and a weather 

file for Barstow, California. The annual collector field operating time is 3,436 hours. 
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2. The annual thermal losses through the insulation are calculated as follows: 

hours)(The time, operating field collector (Annual temperatur design at losses rmal sec/hr)00J/sec)(3,6 e, +

hours)(The time, operating field collector Annual - (8,760 temperatur overnight at losses rmal sec/hr)00J/sec)(3,6 e,

 [11] 

where the average fluid temperature during the overnight circulation periods is assumed 

to be 200 °C. This value can be adjusted in the future based on analysis of the annual 

average using Excelergy. 

Capital Cost Development

1. The capital cost of the pipe and fittings is estimated as follows: 

= (Unit$/m cost, Unit $/kg) cost, kg/m)(Unit weight, [12] 

 where the unit cost, in $/kg, is a function of the pipe diameter and material. 

2. The installed cost for the pipe fittings and valves were estimated from the number 

of fittings and valves, specified by the user, and cost data from vendor quotes1

. 

3. The installation labor costs for the pipe, supports, and hangers include the 

following elements: material handling; erection, lineup, and tack welds; production 

welds; inspections; and hydraulic tests. The labor hours are a function of the pipe 

diameter and wall thickness, and were derived from historical Bechtel cost data. 

4. The installed costs for the pipe insulation are estimated from a three-dimensional 

surface fit of cost as a function of pipe diameter and insulation thickness. The cost data 

were derived from parametric vendor cost information on the Solar Two project, and 

from project cost data identical to the Flabeg model. 

5. In the absence of a pipe stress analysis, pipe supports and anchors were assumed 

to be located every 8 m. The installed costs for the supports were estimated from 

cost data from the Flabeg model. 

Equivalent Capital Cost of Losses

1. The equivalent capital cost of the heat loss through the insulation is calculated as 

follows: 

rate charge Fixed

$/kWht) energy, thermal of kWht)(Cost losses, thermal (Annual = cost capital Equivalent

 [13] 

where 

 

1

 Currently this cost data is identical to that used in the Flabeg model, with the original source 

being data obtained from a vendor to Kramer Junction. 
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efficiency collector (Annual )kWht/m radiation, )(Annual

)$/m cost, collector rate)(Unit charge (Fixed $/kWht energy, thermal of Cost 2

2

=

 [14] 

 where the fixed charge rate is an economic factor for converting a capital 

investment into an equivalent annual expense. The model uses a unit collector cost 

specified by the user (for example, $200/m2

), an annual collector efficiency of 0.50, and 

an annual direct normal radiation of 2,714 kWh/m2

. The value for the fixed charge rate is 

arbitrary. 

2. The equivalent capital cost of the pressure loss in each header section and the 

standard collector loop is calculated using the following equations: 

rate charge Fixed

energy pump (Annual $/kWhe) energy, electric of kWhe)(Cost demand, = cost capital Equivalent

 [15] 

 and 

energy pump Annual = kWhe demand,

)efficiency pump annual )(0.75 hr

sec )(3600 seckW

J (1000

) hr

sec )(3600 sec2

m hours/year (3,436 kg/sec)(Av rate, flow )(Design ,m)(g loss, head erage c

−

 [16] 

and 

efficiency plant (Annual )kWht/m radiation, )(Annual

)$/m cost, plant rate)(Unit charge (Fixed $/kWhe energy, electric of Cost 2

2

=

 [17] 

The model uses a unit plant cost specified by the user (for example, $450/m2

), an annual 

plant efficiency of 0.135, and an annual direct normal radiation of 2,714 kWh/m2

. 

Header Section Diameter Optimization

The optimization process assumes 1) the optimization procedure for each header 

section can be conducted independently from the balance of the header sections, and 2) 

the combination of the optimum header designs is the optimum piping configuration for 

the collector field. 

The calculation is started by pushing the button labeled “Optimum header diameters”, 

and proceeds as follows: 
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1. The number of loops, and the hydraulic characteristics of each loop, are set 

automatically, based on the field configuration, the fluid number, the cold fluid 

temperature, the hot fluid temperature, and the collector field power rating. 

2. A trial diameter is selected for each header section. The capital cost, and the 

equivalent capital cost of the insulation heat loss and pump energy, are calculated. 

3. New costs are calculated for the following pipe sizes: two standard sizes below the 

trial diameter; one standard size below; one standard size above; and two standard 

sizes above. The costs are stored in a temporary matrix, and the size that provided 

the lowest cost is selected. During the calculation of the new costs, 1) the pressure 

distribution is recalculated to provide a pressure at the outlet of the hot header equal 

to the minimum value set by the user, and 2) the thickness of the thermal insulation 

is adjusted such that the sum of the capital cost and the equivalent capital cost of the 

heat loss is a minimum. (The calculation to optimize the insulation thickness can 

also be run independently of the header optimization by pushing the button labeled 

‘Optimum insulation thickness’.) 

4. The process is repeated for each header section. 

5. The process is repeated again for all of the cold and hot header sections to ensure 

local cost minima were not selected in preference to an overall cost minimum. 

The optimum cold header section diameters were shown in Row 7, and the optimum hot 

header section diameters were shown in Row 130. 

Piping and Valves for the Steam Generator and the Heat Transport Fluid Pumps 

Cost estimates are also developed for the piping system in and around the steam generator 

and the heat transport fluid pumps. Line sizes are calculated for the 8 lines summarized in 

Table 1. 

Table 1 Steam Generator and Heat Transport Fluid Pump Line Designation 

Line From To

1 Expansion vessel or thermal storage tank Pump suction header 

2 Pump suction header Individual pump inlet 

3 Individual pump discharge Pump discharge header 

4 Pump discharge header Collector field section headers 

5 Collector field section outlet headers Expansion vessel or thermal storage tank 

6 Steam generator supply header Steam generator supply header 

7 Inter steam generator piping Inter steam generator piping 

8 Steam generator outlet header Expansion vessel or thermal storage tank 
Parabolic Trough Solar System Piping Model Final Report 

NREL Contract No. AAA-2-32432-01 

 - 15 - September 15, 2002

The bases for the calculations are as follows: 

 • Economic optimizations of the line diameters are not performed; rather, the line sizes 

are based on a fluid velocity specified by the user to meet the system hydraulic 

requirements, such as uniform fluid distribution or maximum allowable pressure loss. 

The velocity is specified in Cell B17 on the worksheet labeled ‘Pump-SGS’. 

 • The number and capacity of the heat transport fluid pumps are specified by the user in 

Cell B18 and Cell B19, respectively, on the worksheet labeled ‘Pump-SGS’. 

 • The fluid flow rates in Lines 1 through 4 are calculated based on the following: the 

collector field thermal power rating in ‘Model Inputs’!Cell B3; the fluid number in Cell 

B16; the cold fluid temperature in Cell B25; and the hot fluid temperature in Cell B26. 

 • The fluid flow rates in Lines 5 through 8 are calculated based on the following: the 

steam generator thermal power rating in ‘Model Inputs’!Cell B4; the fluid number in Cell 

B16; the cold fluid temperature in Cell B25; and the hot fluid temperature in Cell B26. 

(The model allows separate values for Cell B3 and Cell B4; thus, the ratio of Cell B3 to 

Cell B4 is effectively the solar multiple for the plant.) 

 • One gate valve is located in each of Lines 1, 2, and 3, and one check valve is located in 

each Line 3. 

 • Long radius elbows are located in Line 1, and in Lines 2 through 8, for thermal 

expansion loops. (The number of elbows is currently an allowance; the actual number 

would be an input to the model following a stress analysis of the piping system. 

Similarly, the pipe lengths shown for Lines 1 through 8 are also currently an allowance, 

and must be revised following the development of the piping arrangement.) 

The pipe, valve, fitting, support, and insulation costs for the 8 lines are summarized on 

the Model Inputs worksheet. The cost for Line 2 and the cost for Line 3 were multiplied 

by the number of heat transport fluid pumps in the calculation of the total system piping 

cost. 
Parabolic Trough Solar System Piping Model Final Report 

NREL Contract No. AAA-2-32432-01 

 - 16 - September 15, 2002

D. General Comparison of Results

Model Comparison 

The following table compares the features of the Flabeg and NREL models: 

Table 2. Comparison of features in the SolPipe and NREL models 

Feature SolPipe NREL 

Overall layout H (80MW) or I (30MW) with loops; 

also straight no-loop layout 

Presently H and I configurations 

Pipe sizing Sized based on design velocity 

set by user 

Optimizes each piping section 

(defined as header piping between 

loop connections). See below. 

Pipe wall thickness Uses Sked 40 piping Wall thickness is no thicker than 

needed for required pressure 

Piping/fitting capital 

costs 

Table lookup from vendor data Table lookup from vendor data 

Piping/fitting labor 

costs 

Table lookup from vendor data Based on Bechtel experience 

Insulation costs Table lookup from vendor data Table lookup from Solar Two data 

based on both ID and thickness of 

insulation 

Pumping power cost Not used Calculated for typical year 

Heat loss Not used Calculated for typical year 

Optimization for pipe 

size 

Not done Per section: pipe D 

assumedÆmodel calculates wall 

thickness, then capital costs, 

equiv. heat loss cost, equiv. 

pumping cost. Then increases D 

to next std size and recalculates 

cost for comparison. Within this 

process, thickness of insulation is 

optimized. 

Expansion loops Based on SEGS design; between 

every 2 loops 

Same 

Loops Design based on SEGS Same 

Valves/fittings Specified Same 

Calculation method Simple arithmetic within cells Uses macros 

Input data Entered in Input worksheet Entered in Input worksheet 

A case was run for a 30MW plant using the I configuration, similar to the SEGS VI solar 

plant, for comparison of the NREL and SolPipe codes. The cost results compare 

satisfactorily for the headers as a whole -- NREL: $16.6/m2

 vs. SolPipe: $16.5/m2 -- but 

differ in several specific cost elements due to understandable differences in the model. 

The header piping sizes are not identical due to the different methods used to select the 

appropriate diameters. Costs for installed pipe of the same size and type are higher in 

the NREL model because the labor hours per unit length based on Bechtel historical 

data base are higher than those assumed in SolPipe. Different pipe sizes lead to 

variations in fitting and insulation costs, causing a further deviation in the overall cost. 
Parabolic Trough Solar System Piping Model Final Report 

NREL Contract No. AAA-2-32432-01 

 - 17 - September 15, 2002

Further, the philosophies differ to a modest degree on the numbers of fittings such as 

valves and the placement of pipe supports. 

[It should be noted that the SolPipe value of $16.5/m2

 is considerably higher than 

reported in earlier Flabeg studies. This is because the interconnection piping in the 

loops (the ball joint assemblies) are included here, whereas in the previous Flabeg cost 

estimates that cost is included in the solar field category, not in the piping category. For 

comparison, the SolPipe result for this 30MW case is $9.2/m2

 if the ball joint costs are 

removed.] 

With respect to the HTF pressure drop for solar steam system, the NREL code is more 

inclusive in that it includes all elements of the system (i.e., header piping, solar field 

loops, and solar heat exchangers). SolPipe contains a less sophisticated pressure drop 

calculation that is partially scaled from early SEGS VI information. 

Use in Trough Excelergy 

It is expected that the NREL piping code would be run upfront within Excelergy for each 

plant configuration, and the results for piping costs and design point solar system 

parasitics would then be fed into the appropriate part of Trough Excelergy for use. 
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PLEASE DO NOT RETURN YOUR FORM TO THE ABOVE ORGANIZATION.

1. REPORT DATE (DD-MM-YYYY)

July 2006 

2. REPORT TYPE

Subcontract Report 

3. DATES COVERED (From - To)

May 13, 2002 – December 31, 2004 

5a. CONTRACT NUMBER

DE-AC36-99-GO10337 

5b. GRANT NUMBER

4. TITLE AND SUBTITLE

Parabolic Trough Solar System Piping Model: 

Final Report, May 13, 2002 — December 31, 2004 

5c. PROGRAM ELEMENT NUMBER

5d. PROJECT NUMBER

NREL/SR-550-40165 

5e. TASK NUMBER

CP06.1301 

6. AUTHOR(S)

B. Kelly and D. Kearney 

5f. WORK UNIT NUMBER

7. PERFORMING ORGANIZATION NAME(S) AND ADDRESS(ES)

Nexant, Inc.; 101 Second St., 11th Floor; San Francisco, CA 94105-3672 

Kearney & Associates; PO Box 2568; Vashon, WA 98070 

8. PERFORMING ORGANIZATION 

REPORT NUMBER

AAA-2-32432-01 

10. SPONSOR/MONITOR'S ACRONYM(S)

NREL 

9. SPONSORING/MONITORING AGENCY NAME(S) AND ADDRESS(ES)

National Renewable Energy Laboratory 

1617 Cole Blvd. 

Golden, CO 80401-3393 11. SPONSORING/MONITORING 

AGENCY REPORT NUMBER

NREL/SR-550-40165 

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13. SUPPLEMENTARY NOTES

NREL Technical Monitor: H. Price 

14. ABSTRACT (Maximum 200 Words)

Subcontract report by Nexant, Inc., and Kearny and Associates regarding a study of a piping model for a solar 

parabolic trough system. 

15. SUBJECT TERMS

concentrating solar power; solar parabolic trough; solar; solar thermal electricity 

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