3200 types of waste heat recovery

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3200 Types of Waste Heat Recovery

AbstractThis section discusses the more common types of waste heat recovery. The dission includes the advantages and the disadvantages of the various systems anpredicted efficiency improvement.

Contents Page

3210 Introduction 3200-3

3220 Heat Recovery From Process Streams 3200-

3221 Example Evaluation

3230 Heat Recovery From Boiler Stack-Gases 3200-5

3231 Economizers on Boilers

3232 Air Preheaters on Boilers

3240 Heat Recovery From Fired Heater Stack Gas 3200-11

3241 Differences Between Fired Heaters and Boilers

3242 General Considerations, Waste Heat Recovery in Fired Heaters

3243 Economizers on Fired Heaters

3244 Air Preheaters on Fired Heaters

3250 Heat Recovery From Gas Turbine Exhaust 3200-14

3251 Background

3252 General Description

3253 Heat Recovery Steam Generator (HRSG), Refinery Type

3254 Heat Recovery Steam Generator (HRSG), Enhanced Oil Recovery Type

3260 Heat Recovery on Offshore Platforms 3200-21

3261 Waste Heat Recovery with a Reciprocating Engine

3262 Consideration of Engine Fuels

3263 Waste Heat Recovery with a Gas Turbine

3264 Waste Heat Recovery With High Pressure Steam

Chevron Corporation 3200-1 March 1989

3200 Types of Waste Heat Recovery Fired Heater and Waste Heat Recovery

3265 Waste Heat Recovery With Organic Heat Transfer Fluids

3270 Power Recovery Turbines 3200-25

3280 Condensation Heat Recovery 3200-26

3281 Direct Contact

3282 Indirect Contact

3290 Other Waste Heat Recovery Types 3200-27

March 1989 3200-2 Chevron Corporation

Fired Heater and Waste Heat Recovery 3200 Types of Waste Heat Recovery

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3210 IntroductionInitially, waste heat recovery should consider process to process exchange. Proopportunities almost always offer the best payout. After all of the process recovis optimized, the priority of waste heat recovery should be focused on what equment, (boilers, fired heaters, etc.) is in the plant. The ability to install cogeneratiwith heat recovery steam generators is a very important waste heat recovery altive. The major areas of waste heat recovery that follow are:

• Heat Recovery from Process Streams• Heat Recovery from Boiler Stack Gases• Heat Recovery from Fired-Heater Stack Gases• Heat Recovery from Gas Turbine Exhaust• Heat Recovery in Offshore Platforms• Power Recovery Turbines• Condensation Heat Recovery• Other Types of Waste Heat Recovery

3220 Heat Recovery From Process StreamsWater, sea water, or air-cooled process condensers and process coolers reject heat to the atmosphere from many process streams. In the search for energy eciency, they continue to be candidates for waste heat recovery.

Process waste heat recovery from the effluent of exothermic reforming fired heaand from FCC regenerators, are two major waste heat recovery areas. On theside, these units are similar. They transfer heat from a hot stream to incoming bfeedwater and/or generate steam at pressures and temperatures required in thThis type of waste heat recovery is done in all of Chevron's Hydrogen Plants, Ammonia Plants, and Type IV FCC Units.

Steam is generated in some process units because of process considerations. would include Isocracker reactor effluent exchangers (to remove exothermic hereaction), hydrogen reformer effluent (high temperature of process stream and need for steam within the unit), crude unit pump-around circuits (for ease of control), and the vacuum residuum product exchanger (simplicity of operation).

The following calculation evaluates the alternatives of air cooling a process streversus heating makeup boiler feedwater with it.

3221 Example EvaluationAssume a Unit has a 20,400 BPD process stream being cooled from 360°F to 160°F on its way to storage. Also, there is a 300 GPM, 60°F make-up treated water streamon its way to a deareator, where it must be heated (with steam) to a temperatur260°F. The process stream has a density of 7 pounds/gallon and a specific heaof 0.6 BTU/(LB)(°F); the water has a specific heat of 1.0.



le. the xcess

ts, e

cost

fin

o e drop

Heat Recoverable From the Process Stream

(Eq. 3200-1)

The potential fuel value saved at the boiler, for fuel at $20 per barrel.

(Eq. 3200-2)

Note the fuel saved must be carefully evaluated to ensure a payout is achievabFor example, most deareators use low-pressure steam to heat the feedwater. Ifeffect of such a project is to reduce the use of low-pressure steam which is in esupply already, then there will be little or no payout.

Operating Costs, Exchanger Sizing, and InvestmentTo achieve a savings, the plant needs to install heat exchanger(s), piping, and controls in order to transfer heat to the treated water. Incremental pumping cosexchanger sizing, and investment need to be evaluated to ensure an acceptablpayout.

Additional pumping capacity may be required to route the water through the exchanger(s) on its way to the deareator. A study of the plot plan, structures, platforms, foundations, instrument and electrical needs would become part of aestimate for this project.

For this example there would be a savings on electric power for not running thefan on the cooler.

If additional pumping is required, the incremental pumping cost to be charged twaste heat recovery would only be (assume an increase of 30 PSIG in pressurlosses):

At $0.10/Kilowatt-Hour, and from Horsepower =

(Eq. 3200-3)

M20,400 BBL 42 GAL DAY 7 LB×××

DAY( ) BBL( ) 24 HR( ) GAL( )----------------------------------------------------------------------------------------------- 250,000 LBHR--------= =

Q M Cp Tin Tout–( )=

Q250,000 LB 0.6 BTU 360 160–( )F×

HR( ) LB( ) F( )------------------------------------------------------------------------------------------ 30 MMBH MMBTU/HR( )= =

30MMBH BBL $20××6.3MMBTU HHV( ) BBL( )--------------------------------------------------------------------

8760HR 0.96 Op. Factor×YEAR( ) 80% eff HHV( )×--------------------------------------------------------------------× $1,001,000/YEAR=

GPM PSI×1714 eff.×-----------------------------

CostYEAR-----------------

300GPM 30PSI 0.746W××1714 75% (eff) HP( )×----------------------------------------------------------------------

8760HR $0.10 0.96××YR( ) KWH( )---------------------------------------------------------× $4400

YEAR-----------------= =



wn in

e ase

Even at a cost of 10 cents/kWH, this pumping cost is insignificant to the fuel savings, discussed above. This example illustrates the economic advantage of pumping liquids to “where the heat is.”

Exchanger SizingThe exchanger is the most costly item for this waste heat recovery project. Themanufacturer's price for the heat exchange equipment can be estimated as shoFigure 3200-1.

From the Cost Estimating Book, two low pressure exchangers, with 1852 squarfeet of surface area each, would be about 24 inches in diameter; and the purchprice would be $30,000 each from the manufacturer.

Even for low fuel values, this type of waste heat recovery project could have a payout in less than a year, depending on the fuel savings.

3230 Heat Recovery From Boiler Stack-GasesWaste heat energy in any stack gas consists of:

1. The sensible heat going out the stack with the flue gases, other than watervapor, and

2. The latent and the sensible heat in the water vapor.

Fig. 3200-1 Cost Estimation

Using Equation 3100-1,

Q = 30 MMBH = U A F LMTD; and

A = Q/U × F × LMTD

LMTD = 100

U = 100 Per G-CE-172, E Section of Cost Estimating Book.

F = 0.81 for a two shell pass with four or more tube passes.

Therefore,

(Eq. 3200-4)

AQ

U F LMTD××--------------------------------30MMBH

100 0.81 100××----------------------------------- 3704 SQ FT= = =



oilers

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ilers

Steam temperatures corresponding to the pressure levels used in most of our bare shown in Figure 3200-2.

The temperature of the flue gases leaving the boiler is related to the temperatuthe boiling water. For heat to transfer to the steam generating surfaces, the fluegases have to be at a still higher temperature. For typical boilers, this is in the 600°F to 800°F range.

An economizer or an air preheater recover heat from these high temperature fluegases in a steam boiler.

For industrial boilers, a dual installation using both an economizer and an air preheater is rarely economical or installed.

An economizer takes boiler feedwater (BFW), on its way to the boiler at 225°F to 275°F, and lets it absorb much of the heat in the hot flue gases with substantial improvement to overall efficiency.

An air preheater recovers the heat from flue gases and increases the temperatuthe combustion air to the boiler. The air preheater improves the boiler efficiencyreducing the stack gas temperature and returning the heat to the combustion athereby reducing fuel consumption.

Depending on the cost of fuel, an economizer or air preheater for water-tube boare typically not attractive for the following conditions:

• Water-tube boilers operating under 150 PSIG

• Water tube boilers operating below 30,000 to 40,000 pounds/hour of steamproduction

• Any size boiler that will normally run at reduced capacity

For a preliminary evaluation, the following investments, based on 1983 costs (EDPI) can be used to estimate a payout:

• New Economizer, Convection Section:

$ = 6000 × (Q MMBH)0.9

• Combustion Air Preheater:

$ = 53,000 × (Q MMBH)0.7

Fig. 3200-2 Corresponding Steam Temperatures

Pressure, PSIG Temperature, °F

1500 598

900 534

600 489

250 406



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ed

Economizers payout far better than combustion air preheaters. Further details oeconomizers and air preheaters are covered below and in the Fired Heaters se

3231 Economizers on BoilersAn economizer is a heat exchanger that transfers heat from flue gases on the outside of the exchanger tubes to boiler feedwater on the inside.

Boilers with economizers generally cool the flue gas temperatures from the 600°F to 800°F range to stack temperatures of about 300°F to 350°F.

A stack temperature of 300°F is also near the minimum temperature to avoid corrsion from sulfuric acid condensation in the cold end of the unit. These minimumtemperatures are determined by the sulfur content of the fuel, the excess air, anmoisture of the flue gas.

Figure 3200-3 illustrates the effects of adding an economizer to a typical gas firboiler. It assumes the boiler is making 150,000 pound/hour of 650-PSIG, 750°F steam. Fuel is natural gas, with 2.0% excess oxygen, and 60°F ambient:

• Check, using the rule-of-thumb of 1% efficiency improvement per 40°F of reduced stack temperature:

Evaluation of Figure 3200-3

Fuel Savings: (Fuel fired = Heat Released)

(Eq. 3200-5)

(1) “Guarantee” basis(2) From Combustion Efficiency Tables(3) See Equation 3100-2 for calculation

= 11.25% efficiency improvement. Checks very well with efficiencies shown in Figure 3200-3

Fig. 3200-3 Effects of Adding an Economizer

Without Economizer With Economizer

Stack Exhaust Temperature °F(1) 750.0 300.0

Boiler efficiency HHV, %(1),(2) 73.1 84.2

Boiler Feedwater, °F 250.0 250.0

Temperature of BFW to drum, °F 250.0(1) 372.8(3)

Fuel Consumption, MMBH 237.7 206.3

750°F 300°F–40°F/1% improvement--------------------------------------------------------

Fuel firedSteam rate (LB/HR)

Efficiency------------------------------------------------ h of steam - h of boiler feedwater( )×=



tro- an

he

where:h is the enthalpy of the steam/water (BTU/LB), from steam tables.

• Without Economizer, the heat released

(Eq. 3200-6)

• With Economizer, the heat released

(Eq. 3200-7)

• Savings in Fuel With Economizer

237.7 MMBH - 206.4 MMBH = 31.3 MMBH

• Annual Savings at $20/Equivalent Barrel

(Eq. 3200-8)

Investment. Careful evaluation of installed costs are necessary for situations involving low fuel value, small boilers, boilers running at reduced capacity, or refits. For example, an investment for the economizer above would typically haveacceptable payout if it is a new installation, has a fuel value of $15 to $20 per barrel, and the boiler normally runs at high capacity.

• Heat given up by flue gas

To evaluate the economizer on this boiler further, look at the flue-gas flow. Tbasis continues to be natural gas firing, with 2% excess oxygen, and 60°F:

(Eq. 3200-9)

(Eq. 3200-10)

With the Economizer, the Flue Gas side Q = M Cp (Tin - Tout), Equation 3100-1.

* Note: See Flue Gas Flow and Duty in Section 3100

LB h steam - h bfw( )BTUHR Boiler eff. LB×---------------------------------------------------------------

150.000 1376.3 218–( )73.1%

-------------------------------------------------------- 237.7MMBH= =

LB h steam - h bfw( )BTUHR Boiler eff. LB×---------------------------------------------------------------

150.000 1376.3 218–( )84.2%

-------------------------------------------------------- 206.4MMBH= =

31.3MMBH BBL $20××6.3MMBTU BBL YEAR---------------------------------------------------------------- 8760HR 0.96 op. factor×× $836,500

YEAR----------------------=

*719LB 1.095 AIR××MMBTU

--------------------------------------------------------787.3LB AIR

MMBTU----------------------------------=

*1LB 1,000,000BTU×21,869BTU MMBTU--------------------------------------------------------

45.7LB FUELMMBTU

-----------------------------------=

TOTAL833.0LB FLUE GAS

MMBTU----------------------------------------------------=



ds

cond ine

mate

to

r as

3232.

(Eq. 3200-11)

Q = 19.34 MMBH

where:0.25 BTU/(LB) (°F) is an average value from Figure 3100-1.

• Temperature increase of boiler feedwater

Equation 3100-2, Water side Q = M Cp (Tout - Tin) = Flue Gas Q. Knowing that the flue gas duty equals the water side duty, and that the BFW flow neeto include 5% blowdown from the steam drum, the BFW temperature out ofthe economizer will be:

(Eq. 3200-12)

Tout = 372.8°F

This temperature out of the economizer is more than 100°F below the boiling temperature of 600 PSIG steam. Therefore, there will be no undesirable “steaming” in the economizer.

Estimate Cost to Evaluate the PayoutKnowing all the duties and the economizer inlet and outlet temperatures, the sebasic equation of waste heat recovery (Equation 3100-3) can be used to determthe size of the economizer.

Heat transfer coefficients may be obtained, and the area calculated. A cost estican then be obtained and the payout evaluated.

Figure 3200-4 shows another example of an efficiency improvement from 77.5%88.8% for a boiler, by reducing the flue gas temperature from 800°F to 325°F by using an economizer. The basis is No. 6 Fuel Oil, 3% excess oxygen, and 60°F ambient. The savings shown in Figure 3200-4 is calculated in the same mannethe previous example.

The economizer has cooled the flue gases in the stack from 800°F to 325°F, while heating the incoming BFW from 250°F to 385.5°F.

For a comparison of the merits of economizers and air preheaters, see Section

Q833.0LB 206.4MMBH( )

MMBTU( ) LB( )-------------------------------------------------------------0.25BTU 750°F 300°F–( )

F( )-----------------------------------------------------------------×=

19.34MMBH 1.05 (for b/d)150,000LB/HR 1( )BTU×

LB °F( )---------------------------------------------------------------- Tout 250–( )°F××=



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3232 Air Preheaters on BoilersAir preheaters transfer heat from stack gases to incoming combustion air. In comparing an air preheater to an economizer, the following factors should be considered:

1. Is there an alternative source of heat for the BFW? If there is, the air prehewould become the better choice.

2. Is there a limitation on NOx? An air preheater, with its hot combustion air produces more NOx at the burner than if it were firing air at ambient temperature.

3. How much sulfur is in the fuel? What is the acid dewpoint? Heating ambienair in a preheater (70°F typically) or makeup water (60°F typically) in an econ-omizer, will cause the exchanger metal temperatures to be lower than heatBFW from a deareator (225°F typically). See Section 3421 for a discussion ofa dewpoint.

4. At the pressure selected, will an economizer with an arbitrary approach, i.edifference in the flue gas exit temperature and the economizer inlet temperture of say 50°F, recover more heat than an air preheater that may have an outlet-temperature restriction due to the burner or NOx control?

5. Investment and operating costs for each. This would have to include any opating horsepower for fans to overcome incremental draft losses. Economizehave a significant edge with lower investments. (See Section 3230.) They a

Fig. 3200-4 Efficiency Comparison: Boilers



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have lower draft losses; flue gases normally have to be ducted to an air preheater at grade and then back up to the stack.

6. All boiler manufacturers have arrangements that can satisfy either an econmizer or an air preheater on new boilers. They can also add them to existinboilers.

Types of Air PreheatersThere are two types to consider: regenerative and recuperative.

There is no cost advantage for either type, although domestically the regenerattype is the most frequently used, with the recuperative type most popular in Eur

Regenerative. This type has a record of successful operation, and is referred to Ljungstrom design. It has a compartmented rotor contained in a rotor housing supported by bearings, each filled with metallic heating elements. The rotor slorotates, alternatively through the gas and air streams. Hot flue gases flow throuone side of the rotor and heat the elements. Air flows through the other side whthe stored heat is released to the air stream. The air and gas flows are separatediaphragms in the rotor and seals between the rotor and the rotor housing. Whthis design has little fouling and no heat transfer losses due to soot deposits, it require a motor driver and there is some leakage around seals between the incair and the exhaust gases.

Recuperative. This is a fixed air-to-air flue gas, with no moving parts. It is a bundle of tubes expanded into a tube sheet and enclosed in a casing. Flue gasflow through the tubes, and air to be heated flows over the tubes. Alternatively, extended surface tubes may be used with flue gas flowing over the tubes whileair to be heated flows through the tubes. While soot deposits can lower the heatransfer and increase draft losses, these units are stationary and there is no leabetween the incoming air and the exhaust gases.

Examples of combustion air preheaters on process fired heaters are shown in Section 3300. For further information on combustion air preheaters, see Section 430 of this manual.

3240 Heat Recovery From Fired Heater Stack Gas

3241 Differences Between Fired Heaters and BoilersMost of the information in Section 3230 (economizers and preheaters on boileralso applies to fired heaters. The differences are:

1. On a fired heater an economizer can generate steam as well as preheat waOn a boiler, it only preheats boiler feedwater. In economizers on fired heatethe steam pressure levels can be optimized with the available flue gas temptures and steam balance. Where more steam is being generated than the pcan use, air preheaters may be preferred if steam cannot be used elsewhe



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2. On a fired heater the economizer will heat the process as a first priority if thflue gas and process stream temperatures permit. After all economic proceheat has been recovered, economizer sections can be added to make steaThey also can be added to heat water or intermediate heat transfer fluids.

3. On a fired heater, the temperature available for waste heat recovery is not constant amount above some boiling temperature. On fired heaters, it is demined by the temperature of the hydrocarbon in the fired heater tubes. For example, in an Atmospheric Crude Unit fired heater, this stack temperaturewould be (without heat recovery) about 750°F to 850°F; for the Vacuum fired heater, 900°F to 1000°F; and in a Hydrogen Plant fired heater, about 1500°F. Without waste heat recovery, these would be the stack outlet temperatures

3242 General Considerations, Waste Heat Recovery in Fired HeatersThe example in Section 3120 has 12 process fired heaters and three power boiThe fired heaters range from 425 MMBH to 25 MMBH of absorbed duty. The generation of steam in economizers and the use of air preheaters was investigafor each process fired heater. From an economic standpoint, the rankings of thewaste heat options are:

1. Generation of 150 PSIG steam

2. Generation of 600 PSIG steam

3. Air Preheaters

The reason that the 150 PSIG generation has an economic advantage over the600 PSIG is that per dollars invested, more heat and energy are recovered. Thidue to its lower temperature and resulting lower investment required to generat150 PSIG steam.

As mentioned in Section 3150, a steam balance must be developed to support waste heat recovery project. This is particularly critical for fired heaters, if steamgeneration, boiler feedwater, or make-up water are involved. As discussed in thboiler section, air preheaters do not have the payouts that economizers do. However, once the steam system is at maximum capacity, the air preheater canan economical alternative.

From a practical standpoint, several considerations should be reviewed when comparing steam economizers to air preheaters on fired heaters. Some specificguidelines are:

• The use of air preheaters in a multi-box fired heater (such as a rheniformernot recommended. This is because of the complexity of the control systemsmaintain the correct air/fuel ratio in the fire boxes. Additionally, a rheniformewith its 1000°F stack temperature can provide steam at the highest pressurethat is made in the plant.

• The use of air preheaters with stack temperatures above 900°F to 1000°F presents expansion problems in the rotating elements of regenerative



n

ly

pera-

era-

n may not be e

exchangers. On this basis, air preheaters are not normally used in hydrogeplants and rheniformers.

• Steam generation of less than 10,000 pounds/hour is impractical in large process units. The additional auxiliary facilities, maintenance, laboratory testing, and operator attention cannot normally be justified.

• Depending on the cost of fuel, air preheaters for fired heaters would typicalhave a marginal payout for absorbed duties of 25 to 35 MMBH and less.

3243 Economizers on Fired HeatersFigure 3200-5 illustrates how economizers can reduce fired heater flue gas temtures from a range of 700°F to 1200°F to the range of 300°F to 700°F.

The flue gas outlet temperature depends on:

• The pressure of the steam generated in the economizer, and

• The need to burn higher sulfur fuels as a back-up in the future. Lower temptures could cause corrosion in the cold end of the waste heat recovery equipment.

3244 Air Preheaters on Fired HeatersSections 3230 and 3232 on air preheaters on boilers applies to air preheaters ofired heaters. Air preheaters are more attractive on fired heaters because therebe other sources of low pressure steam and the deareator make-up water mayas handy. However, when steam is needed in the process, the fired heater is thideal place to generate it.

For further information on combustion air preheaters, see Section 430 of this manual.

Fig. 3200-5 Typical Fired Heater Economizer



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is

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3250 Heat Recovery From Gas Turbine Exhaust

3251 BackgroundAnother significant area of waste heat recovery is the Combustion Gas Turbine(CGT), used either as:

• A direct mechanical drive for process equipment. In some instances, the hoturbine exhaust is used as combustion air for a fire heater in the plant whermechanical drive machine is located.

• Part of a “Cogeneration” System. In these plants, the gas turbine shaft produces electricity, and steam to operate the plant is produced from the hoCGT exhaust.

For both situations, the CGT produces hot exhaust gases, typically in the 950°F to 1000°F range. This exhaust is used as:

• Preheated combustion gas for fired heaters, or

• Hot gases to a Steam Generator. The exhaust is almost always supplemenfired, up to 1600°F and 1700°F, to normally produce both dry (saturated) and superheated steam at different pressures for the operating center, or in theof producing, a 60% to 80% quality steam for downhole injection.

Production of electricity and steam from one fuel source is called Cogenerationwhich cuts the amount of energy necessary to make electric power to nearly onhalf. This is based on an economic amount of steam and electrical power beingrequired at the plant.

Public Utilities typically furnish electric power to our operating centers at an effi-ciency of 32% to 35%.

Steam is typically generated in most of our plants at efficiencies of 70% to 75%without waste heat recovery, and 85% to 90% with it (all on a HHV basis).

The overall weighted efficiency for power purchased from a public utility power plant and steam produced at a Company facility is in the 60% to 70% range. Thresults from averaging the electric power at its low efficiency (from the power plant) with the higher efficiency for steam produced (in the Company facility).

By using an on-site gas turbine to simultaneously generate both electric power steam, the overall “weighted” efficiency can be improved to the 75% to 85% ran

Figure 3200-6 compares the efficiency of Cogeneration with the conventional wof making steam at the plant and purchasing electric power from the utility.

3252 General DescriptionThe CGT uses natural gas or process gas in most of our applications. For all coeration projects, the waste heat boiler transfers heat from the hot exhaust to incoming boiler feedwater, plus generates steam to whatever conditions are



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required in the plant (including super heated steam). These waste heat boilers commonly referred to as heat recovery steam generators, (HRSG). The exhausgases in all Chevron's installations are supplementary-fired in the HRSG to furtimprove overall efficiency. This is being done at Pascagoula, Port Arthur, GavioEl Segundo, and shortly, at Belvieu. Richmond has already ordered the CGT anHRSG for a 100 MW Plant. Hawaii is at the Appropriations Request stage, andPaso is evaluating the economics.

In Chevron's producing fields where steam is used for enhanced oil-recovery, thonly difference is that the steam generator does not make superheated steam, required in most refineries, chemical plants, and terminals. In producing, the waheat boilers produce a 60% to 80% quality steam from the exhaust gases. For applications, the unit is normally a multipass economizer design. We have manof these units in the California oilfields and they are being installed in Caltex in Indonesia.

An alternative to a HRSG is to route the turbine exhaust to a process fired heatthese instances, the fired heater burners fire supplementary fuel which combuswith the remaining oxygen in the turbine exhaust. This can achieve optimum effciency, when the fired heaters flue gases are down to 10% to 15% excess air.

Section 3500 contains a simplified evaluation of the economics for a Cogeneratinstallation. It also gives a quick method for evaluating whether the Cogeneratioplant should export power to the Local Utility.

3253 Heat Recovery Steam Generator (HRSG), Refinery TypeFigure 3200-7 summarizes gas turbines and waste heat recovery applications aPascagoula in 1979. This figure illustrates several diverse applications.

In the early 1980's, a General Electric mechanical-drive CGT was installed in thHydrogen Plant of the Pascagoula Resid Conversion Project. Its exhaust was d

Fig. 3200-6 Efficiency Comparison: Electric Power and Steam Generation



Fired Heater and Waste Heat Recovery

March 1989

3200-16Chevron Corporation

Fig. 3200-7 Gas Turbine Installations (Pascagoula Refinery)


ired

e

on

umed t

his

d ach

-17,

into the reforming fired heater. In 1980, there were five units generating electricpower and two direct mechanical drives. Three exhaust streams are routed to fheaters, and four to heat recovery steam generators.

Note Figure 3200-17 is a foldout appearing at the end of this section.

Figure 3200-17 tabulates data for General Electric's combustion gas turbines, Frame 3 through Frame 9, plus the LM2500 and LM5000. Figure 3200-8 lists thkey design parameters for each machine.

(1) For supplementary-firing the exhaust gases to 1600°F.

Figure 3200-9 is a worksheet for a General Electric Frame 6 Gas Turbine-HeatRecovery Steam Generator. It calculates the overall efficiency for this unit on natural gas when making 895 PSIG and 830°F steam. The exhaust from the Gas Turbine to the Heat Recovery Steam Generator is fully fired with a stack conditiout of the HRSG of 10% excess air and temperature of 300°F.

It shows the efficiency of the cycle and the equivalent barrels of fuel that can besaved per year. This savings is based on backing off power boilers that are assto be 84% efficient on a HHV basis. Most plants do not have boilers operating athis high an efficiency, so a little more fuel would be saved. Note that 10,000 BTU/kWH is the heat rate assumed for the fuel consumed at the Utility Plant. Theat rate is very close to the average of most utility fossil fuel fired plants.

Figure 3200-10 uses the procedure in Figure 3200-9 to calculate efficiencies anenergy savings for the popular General Electric Frame 5 and Frame 6 CGT's. Esize is evaluated for making 895 PSIG and 830°F steam where the exhaust gases from the gas turbine to the Heat Recovery Steam Generator are:

• Unfired• Supplementary-fired to 1400°F• Fully fired to 10% excess air and a stack temperature of 300°F

The numbers shown in Figure 3200-10 were calculated from data on Figure 3200previously discussed.

Fig. 3200-8 Key Design Parameters for GE CGT’s

GeneralElectric Frame KW (iso)

Gas FlowLb/Hr

Exhaust Temp. °F

895#, 830°F(1) Steam Produced

Lb/Hr

3 (MS3002J) 9,090 398,400 1,004 94,000

5 (MS5001P) 22,340 926,400 939 219,000

6 (MS6001B) 33,770 1,045,600 1,027 247,500

7 (MS7001E) 73,130 2,203,000 1,080 722,000

9 (MS9001E) 100,760 3,043,000 1,080 722,000

LM2500 19,370 503,900 980 119,600

LM5000 27,040 887,600 820 210,500




March 1989

3200-18Chevron Corporation

Fig. 3200-9 Gas Turbine – HRSG Worksheet, Fully Fired, Frame 6


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r

T-n-

n for

(1) See Figure 3200-9.

With the gas turbine manufacturer, data similar to what is shown on Figure 3200-the efficiency of a “Cogen” project can be calculated. From there, the next step evaluating the operating savings and payout.

Note Figure 3200-18 is a foldout at the end of this section.

Figure 3200-18 is a detailed balance for each section of a proposed Heat RecoSteam Generator for a Brown Boveri, Type 8, gas turbine, generating about 50,000 kW. Important features are:

• Initial cooling of the exhaust gas across the superheater prior to supplemenfiring the exhaust gases. This minimizes the amount of desuperheating.

• Shock tubes installed after supplementary-firing that have a saturated steam/water mixture in the tubes.

• Supplementary-firing to 1476°F.

• Production of two steam levels with superheating.

• The preheater at the cold end, cooling the stack gases from 299°F to 218°F will not be installed due to the high cost of piping the make-up water across theplant from the deareator location, plus the cost penalty for alloy materials foprotection against corrosion.

3254 Heat Recovery Steam Generator (HRSG), Enhanced Oil Recovery TypeOil field cogeneration projects are identical to refinery projects, as far as the CGgenerator is concerned. Where they differ is in what they do with the supplemetally fired gas turbine exhausts. In the refinery type, (HRSG) normally dry (satu-rated) and superheated steam are required.

In the oil field, (HRSG), 60% to 80% quality steam is required for injecting into wells at pressures in the 1000 PSIG range to assist in enhanced oil recovery.

Figure 3200-11 is an isometric of a proposed six-parallel-pass, steam generatioenhanced oil recovery. The design for this project is 220,000 pound/hour of 60%quality steam at 775 PSIG, (from 180°F boiler feedwater), by supplementary-firing

Fig. 3200-10 Efficiency Calculation and Energy Savings

Case Frame Status %Eff. Hhv Bbl/year Saved

1 6 Unfired 69.35 166,000

2 6 Suppl.-fired to 1400°F 77.26 201,000

3(1) 6 Fully fired 84.37 247,200

4 5 Unfired 63.45 66,000

5 5 Suppl.-fired to 1400°F 76.12 109,000

6 5 Fully fired 84.22 153,000



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the gas turbine exhaust to 1394°F. Flow in the preheater is counter-current; flow inthe boiler is co-current. Description of finning, size of tubes, number of tubes inheight and in depth, and the heat balance equations for both boxes are shown.sketch on the top summarizes the heat transfer conditions for the preheater andonce-thru boiler.

Figure 3200-12 is an isometric of the rough outline dimensions for a waste hearecovery type behind a General Electric LM-2500 gas turbine for a producing fieThis unit is also rated as a 220,000 pound/hour, 775 SIG outlet, once-through, 60% steam generator for enhanced oil recovery. Units of this type have multipa

Fig. 3200-11 Proposed 60% Quality Steam Generator



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parallel flow. This unit has four passes. There are no steam drums or mud drumThe passes are heated as in any economizer.

3260 Heat Recovery on Offshore PlatformsThe two main sources of waste-heat on offshore platforms are combustion gas turbines and reciprocating engines. These engines provide power for compresspumping, and/or electrical power. A portion of the fuel consumed by these engiis rejected as heat in their exhaust or cooling system. This waste-heat can be rered and put to use in a variety of ways to improve the platform's overall efficiensuch as heating process fluids or glycol regeneration.

These units are required, and must operate whether the waste-heat is recoverenot. From a safety aspect, waste heat recovery units can be used in place of firheaters to provide platform heating requirements. This eliminates fire hazards aciated with fired heaters.

Waste heat recovery systems may need some backup heat source if the main hsource is to be shut down while the users of the heat are still operating. The basystem may be an independent heating system or duplicate heat recovery systenough heat sources are present. A detailed study of the platform operations aheat balances under various operating schemes must be made to provide an adequate system.

Fig. 3200-12 60% Quality Steam Generator Behind LM-2500 CGT



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The heat energy from either a combustion gas turbine or, reciprocating engine usually recovered by an intermediate heating medium such as water, steam, orheating oil.

Steam and gas turbine exhausts have been discussed in detail in the previous sections.

3261 Waste Heat Recovery with a Reciprocating EngineReciprocating engines convert 20% to 40% of the fuel energy they consume intshaft horsepower. The remainder is removed with the cooling system and rejecin the exhaust. A waste heat recovery system on the engine's exhaust can increfuel thermal efficiency to around 55%. If the cooling system energy is recoveredwell, the efficiency may be increased to about 75%.

The exhaust temperature of reciprocating engines varies from 800°F to 1350°F depending on the size, efficiency and whether it is supercharged. Because recicating engines do not use large amounts of excess air, the combustion productconstitute a larger percentage of the exhaust. The specific gravity of reciprocatiengine exhaust gases is shown, along with that of air, on Figure 3200-13.

Fig. 3200-13 Specific Heat Versus Temperature, Air and Reciprocating Engine Exhaust



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For reciprocating engines, a variety of systems and combinations of systems cabe used, depending on the heating medium, and the temperature required by thheat user.

Figure 3200-14 shows a typical hot water system in which the engine jacket cowater has been replaced by the hot water heating fluid. Additional heat energy then recovered from the hot exhaust gases.

3262 Consideration of Engine FuelsOil fueled engines have dirty exhausts, particularly during rapid load changes owhen the air/fuel mixture is out of adjustment. Reciprocating engines consuminlow sulfur natural gas have clean exhausts. Fuel oils and gases containing sulfucompounds should not be used for waste heat recovery due to the extremely cosive exhaust gases that they produce.

3263 Waste Heat Recovery with a Gas TurbineFigure 3200-15 shows how a hot pressurized water system, utilizing the unfiredexhaust from a combustion gas turbine, can be used economically to recover wheat and to transfer the heat to various users. Most hot water systems (treated water) operate at 230°F to 280°F, which requires a minimum system pressure of 60 PSIG. Water can be used at higher temperatures, up to 400°F, but higher pres-sures are required to prevent boiling. The water is heated by the hot exhaust gawhile flowing through the tubes. The water temperature is controlled by divertinportion of the turbine exhaust. High water temperature or low water flow causes

Fig. 3200-14 Hot Water Heat Recovery System



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entire exhaust to be diverted. An expansion tank is included in the water systemallow for the thermal expansion of the water. The pressure in the expansion tanmaintained with nitrogen gas to prevent the formation of steam. The process loshown can be a single user or a combination of many users. A system for usingheating oil is similar.

3264 Waste Heat Recovery With High Pressure SteamHeat recovery through steam generation is not commonly used offshore. Howehigh pressure steam can be generated from turbines or reciprocating engine exgases. Since this type of system does not provide engine cooling, higher pressusteam may be generated ranging from 100 to 450 PSIG.

The most common high-pressure steam system used offshore is the hybrid steam/water waste heat recovery system. This type of system uses forced circution of water through a waste heat unit, as with the water system shown in Figu3200-15. The outlet of the waste heat exchanger flows to a steam separator vewhere a portion of the water vaporizes to generate steam. This steam maintainpressure in the steam separator at a level to preclude the need for a gas blankesystem. A pressure controller on the steam outlet of this vessel controls the stepressure and, consequently, the water temperature. Hot water from this separacan be pumped to nearby users, as with a water system. At the same time, stemay be used to provide heat to nearby users.

Fig. 3200-15 Closed-System Water Heater Schematic



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3265 Waste Heat Recovery With Organic Heat Transfer FluidsA variety of organic fluids are available for use in heating or waste heat recoversystems. These liquids offer the advantage of low-pressure liquid-phase heat transfer at very high temperatures. Therefore, these systems involve small pipinand low design pressures.

For specifics on the physical properties and system designs, consult the manufturer of the specific fluids. The following summarizes organic fluids:

Mineral Oils. They are noncorrosive, low cost, and can be used from -15°F to 600°F. However, they have low heat capacities and are subject to high temperathermal cracking.

Diphenyl-diphenyl oxide. It is used over a temperature range of 54°F to 750°F. This fluid offers a high specific heat but boils at 496°F. Consequently, a pressurizedsystem may be required. Extreme care must be taken with seals, packing, and fittings. If this fluid leaks out, there are problems of fluid loss, odor, toxicity, andclean up. Dowtherm A is an example of this type fluid which may be used as eia liquid or a vapor heat- transfer fluid.

Glycols. These are used in aqueous solutions for temperatures from -50°F to 350°F. For temperatures over 212°F, some slight pressurization is required. Glycols in water act as a corrosion inhibitor and as an antifreeze.

Polyethylene glycols. These heat transfer fluids have good thermal stability to 555°F. They are easy to pump because of low viscosity. Pressurized systems arequired since these glycols do not boil.

Aromatic based fluids. These fluids may be used over a wide range of operatingtemperatures and are thermally stable. However, their heat capacities tend to band the high temperature versions may require steam tracing.

3270 Power Recovery TurbinesA hydraulic turbine can be considered a “waste heat” recovery unit. It actually recovers energy when letting down high-pressure streams to lower pressures.

As an example, in a Hydrocracker there are process pressures that must be drofrom 2500 PSIG to 120 PSIG, and to 40 PSIG. This let-down energy can furnisabout one half the power required to pump the incoming feed up to the processpressures.

Figure 3200-16 illustrates the principle. A full size motor and a full size spare should be installed. As power recovery takes over, the load on the electric drivereduced.

Section 3320 shows how this is applied in a Hydrocracking Plant.

For details on costs and economical pressures, contact the Mechanical and Eletrical Systems Division of ETD.



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3280 Condensation Heat RecoveryIt has long been desired to lower the temperature out of waste heat streams to the 250°F to 350°F range. With existing technology, this has been considered to the minimum exhaust temperature range due to the condensation of acid from combustion products.

Condensation heat recovery cools the exhaust gases below the water dewpointcan recover a large percentage of the water-vapor latent, and sensible heat. Wthe Company has done very little of this to date, it is an evolving heat recovery type. In Europe, these systems have been used for several years, in hundreds applications. There are two approaches, both discussed below.

3281 Direct ContactThis brings water directly into contact with the flue gases to remove the heat. Twater becomes acidic and a secondary heat exchanger is used to transfer the rered heat in a recirculating loop to a clean water stream.

Direct contact is also referred to as Non-condensing waste heat recovery. Direccontact usually reduces the waste heat recovery stream temperature to around150°F. The acid condition prevails at a pH of about two, and there is little water condensation from the flue gases. Therefore, there is little latent heat recovery.approach saves an additional 3% to 4% of sensible heat from a waste heat recstream, (for either an oil or gas fired exhaust stream), when cooling it from arou300°F to 150°F.

3282 Indirect ContactIn this approach, a corrosion-resistant heat exchanger is placed directly in the fof the waste heat flue gas. There is no contamination of the fluid receiving the h

Fig. 3200-16 Energy Comparison: Hydraulic Turbine



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This fluid can be a process stream or a utility stream that needs the heat. It canbe fluid that is transferring the heat to other users in the plant in a recirculating closed system.

Indirect contact is also referred to as Non-contact or Condensing. Condensing usually done to a temperature below 100°F. The acid condition prevails and the water in the flue gases condenses, diluting the acid.

For this type of heat recovery, we can use the following guidelines. How many ational efficiency points could be gained if we cooled the hot fluid in the waste herecovery unit all the way to ambient temperature? For this condition, we are looking at the absolute maximum recovery. By reducing the temperature from 150°F, (discussed in Section 3281), to ambient, we could save the following addtional fired unit efficiency points:

• On gas: 2% of sensible heat and about 10% latent heat• On oil: 2% of sensible heat and about 5% latent heat

The above variation in efficiency for gas and oil is due to the lower hydrogen content in oil (less water vapor in the gas).

Condensation systems are reported to reduce particulates and sulfur dioxide emissions.

Manufacturers of glass, pyrex, borosilicate, and teflon are actively trying to devecorrosion-resistant heat exchangers for this type of waste heat recovery.

It will be some time before industry adopts this “almost ambient” stack philosop

Note that when stack temperatures become cooler, the penalty for firing with exair is decreased.

3290 Other Waste Heat Recovery TypesOther waste heat recovery opportunities include the following:

• Steam boiler and process steam generator blowdown systems

• Steam condensate return systems

• Steam trap, trap maintenance and steam leaks

• Venting of excess low-pressure steam

• Compressor horsepower reduction from using chilled waters in compressorsuction coolers. (In warmer climates, using 50°F chilled water instead of ambient 80°F water (cooling incoming suction temperatures from 120°F to 80°F), reduces compressor horsepower 7%.)

• Gas Expanders where higher pressure gases are available for energy recoin dropping to lower pressures. (See Section 3270 for Power Recovery Turbines.)



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• Capacity control of rotating equipment by variable speed control of the drive

• High efficiency motors and steam turbines

• Completely automatic boiler and fired heater combustion control

• Control of Oxygen, draft, and leaks in skins of equipment

• Capacity control of reciprocating compressors by automatic unloader contrversus spillback

• Automatic temperature control (on-off, variable speed) of cooling tower andcooler motor drivers

• Low Temperature Rankine Cycle Waste Heat Recovery versus air or water cooling of process streams

• Vacuum pumps versus steam jet ejectors

• Vacuum deareation versus low pressure steam deareation

• Insulation installation and maintenance

• Hot feed to process units. (An example is that the Hydrocracker feed from tVacuum Unit could be fed directly to the Isocracker to avoid cooling for intemediate storage, oxidation, and to conserve energy.)



March 1989


Chevron Corporation 3200-29

Fig. 3200-17 Steam Generation and Fuel Chargeable to Power with Gas Turbines and Exhaust Heat Boilers Gas Fuel


March 1989


Chevron Corporation 3200-31

Fig. 3200-18 Proposed HRSG for a 50,000 kW Gas Turbine Generator

3200 types of waste heat recovery

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