Further Reading
Section 6.2.5 Section 6.2.5 (a) 3.97%
7.2 Case Study Details .1 General
Fuel required to produce electricity purchased from a utility, and therefore the indirect CO2 emission for purchased power, is difficult to establish. The actual quantity of fuel per MWh may change in real time depending on the utility’s system load and the units in service at the time. Recognizing this difficulty, the fuel required may be approximated with a blended average heat rate for the utility system for economic calculations. Published records for the local utility serving the refinery show the percent of annual generation from various sources with their average heat rate. These are reproduced in Table 7.2. The useful energy in the electricity is the full value of the power purchased in MWh.
Fuel required by a steam boiler may be calculated by an energy balance. A gas turbine’s fuel requirement is provided by the manufacturer, usually in terms of the LHV of the fuel. For comparison with steam, and for economic calculations, the manufacturer’s LHV fuel requirement must be converted to HHV. The concept of LHV is irrelevant for steam, and the unit price for gas fuels is generally based on higher heating value around the globe.
7.2 Case Study Details
7.2.2 Proposed CHP Plant
A thermodynamic heat balance of the proposed CHP plant is shown in Figure 7.2. The figure shows details of a single gas turbine and the performance of two HRSGs generating steam with the exhaust from two gas turbines. As shown, the two gas turbines produce just over 95.5 MW, after netting auxiliary power requirements to run the cycle and transformer losses.
Fuel to the gas turbine is compressed from normal pipeline pressure for injection into the gas turbine combustors.
The HRSG is comprised of three pressure levels, each with a steam drum. The low‐pressure (LP) steam drum provides steam for the deaerating feedwater heater. Such a direct contact heater would typically be provided as an integral part of the HRSG.
The intermediate pressure (IP) drum provides steam to a tube bundle section that provides the necessary temperature for the MP process steam to the refinery. The HP drum, likewise, provides steam to a superheating tube bundle that heats the steam to the required temperature for the HP steam to the refinery. Duct firing with natural gas, located in the gas stream down- stream of the HP superheater section, provides additional energy to the HRSG for steam generation.
GT PRO 24.0 Stuart Net power 95540 kW
LHV net heat rate 10122 BTU/kWh LHV net efficiency 33.71%
p[psia], T[F], M[kpph], Steam properties: IFC-67 118 11-09-2014 11:51:57
1X GE LM6000 PC SPRINT
(Data-defined model #330) 2 X GT
49203 kW 14.7 p
59 T 60 %RH 1020.4 m 0 ft elev.
14.55 p 59 T 1020.4 m
Blended fuel 20.38 m LHV 422144 kBTU/h
77 T 169 T
Water 19.45 m 9.625 m 13.82 m
1056 m
15.08 p 846 T 2112 M 27.33 ppm NOx
71.62 %N2 12.79 %O2 3.403 %CO2 11.32 %H2O 0.8622 %Ar 0.0008 %SO2
842 T 2112 M 33.05 ft^3/lb 19387 ft^3/s 842 821 1021 1021
785 782 767 747 720 403 403 280 280 265 265
210 T 2118 M 17.46 ft^3/lb 10275 ft^3/s
Natural gas 5.961 M LHV 122736 kBTU/h 17.19 p
200 T 409.1 M
LTE 127 T 409.1 M
200 T 17.19 p 220 T
8.575 M
17.19 p 220 T 8.533 M
LPB 8.533 M 222.5 p 221 T409 M
216 p 381 T 409 M IPE2
216 p 388 T 210.9 M
IPB
208.8 p 475 T 210.9 M
IPS1 2.067 M
207.7 p 475 T 213 M IPS2 726.5 p
383 T
712.7 p 458 T 195 M HPE2
705.3 p 497 T 195 M HPE3
705.3 p 504 T 194 M HPB1
681.4 p 575 T 194 M HPS3 2.07 M
660 p 570 T 194 M V2
195 p 470 T 213 M V4
Includes DB, SCR
Figure 7.2 Proposed CHP plant. Source: Reproduced by permission of ThermoFlow.
7.2.3 Steam Boilers
The current refinery steam generating equipment consists of two identical steam boilers that have an efficiency of 85.1% based on the HHV of the fuel. The fuel to the boilers is comprised of a mixture of refinery off gas (ROG) and natural gas, which makes up the balance of the fuel not available from ROG.
Figure 7.3 shows a sketch of the boiler feedwater, and steam systems. Medium‐pressure steam is manufactured from a pressure letdown of HP steam that is tempered with feedwater flow to the required temperature. Within the boiler system, MP steam is used for feedwater heating in a direct contact deaerating heater. The feedwater enters the boiler at 704.6 psia and 235.5 °F. Makeup demineralized water completes the feedwater requirements for condensate or steam that is consumed by the refinery.
7.2.4 Fuel
The refinery produces a byproduct gaseous fuel (refinery off gas or ROG) that must be con- sumed by the steam boilers or the new cogeneration facility. The ROG has high hydrogen and sulfur concentrations compared to natural gas. Various olefins are also present making it unac- ceptable for blending into the local natural gas pipelines. Incinerating the gas (flaring or combustion in a thermal oxidizer) would not be permitted. The average production of ROG is 10.23 million standard cubic feet per day (scfd) and its composition is shown in Table 7.3 with that of the local pipeline natural gas.
7.2.5 Gas Turbine
The development team has screened several candidate gas turbines to replace the aging boilers and settled on the GE LM6000™‐PC Sprint®. This model is an aeroderivative machine with a power turbine added to the base gas turbine, which drives an electric generator. The unit has
85.1% HHV
194 kpph 660 psia/570 °F
704.6 psia 235.5 °F
Deaerator 55.4 kpph
Condensate collection and makeup
213 kpph 195 psia/470 °F
Figure 7.3 Existing boiler and feedwater system.
a Sprint® package that increases power output by spraying water into a midpoint of the compressor. The water spray cools the compressed air, which reduces compressor power and adds mass flow for additional output. Water is injected into the combustion section to reduce the production of NOX. General Electric has provided the performance listed in Table 7.4 for natural gas.
Table 7.3 Fuel gas composition and heating values.
Component Natural Gas
(%vol)
Ref gas (%vol)
LHV (kJ/mol)
LHV Btu/scf
HHV Btu/scf
Methane (CH4) 95.20 48.85 802.6 909.3 1009.9
Ethane (C2H6) 2.50 13.20 1428.6 1618.5 1769.4
Ethene (C2H4) 0.00 0.87 1323 1498.8 1599.4
Propane (C3H8) 0.20 9.52 2043.2 2314.7 2515.8
Propene (C3H6) 0.00 1.75 1926.2 2182.2 2333.1
Butane (C4H10) 0.06 4.28 2567.3 2908.6 3160.0
cis‐2‐butene (C4H8) 0.00 0.68 2533.9 2870.7 3071.9
Pentane (C5H12) 0.02 0.58 3244.9 3676.2 3978.0
Hexane+ (C6H14) 0.01 0.10 3855.1 4367.5 4719.5
Hydrogen (H2) 0.00 19.05 241.8 274.0 324.3
Nitrogen (N2) 1.29 0.78 0 0.0 0.0
Carbon monoxide (CO) 0.00 0.10 283 320.6 320.6
Carbon dioxide (CO2) 0.70 0.19 0.0 0.0
Oxygen (O2) 0.02 0.00 0.0 0.0
Hydrogen sulfidea (H2S) 0.00 0.05a 518 586.9 637.1
Total 100.00 100.00
Note: a Total sulfur: maximum 1 hour sulfur concentration is 800 ppm by weight expressed as H2S.
Source: Green and Perry (2007) Reproduced with permission of McGraw Hill.
Table 7.4 Gas turbine performance data at 59 °F.
Gas turbine data (each)
Output (kW) 49 120
Heat rate (Btu/kWh) LHV 8582
Fuel flow (lb/h) 22 188
Fuel flow (MMBtu/h) LHV 421.6
NOx water injection (lb/hr) 19 448 Sprint water flow (lb/hr) 9599
Exhaust flow (lb/s) 293
Exhaust temperature (°F) 847
NOx emissions (lb/h) 43
Net plant output (MW) 94.6
Notes: Natural gas fuel. Sea level at 59 °F ambient temperature with 60% relative humidity, 4” inlet pressure drop, 10” exhaust pressure drop, 13.8 kV generator and 0.85 power factor.
Source: General Electric.
For the case study, the gas turbine will consume all the ROG and supplement the fuel supply with natural gas. Gas‐turbine exhaust, together with supplemental duct firing in the heat recovery steam generator (HRSG), will produce the refinery’s steam requirement and provide flexibility to follow the variable steam demand.
7.2.6 Air
For this case study, atmospheric air at 60% relative humidity has the composition shown in Table 7.5.