Process Std 306

PROCESS STD 306 FOSTER WHEELER HEAT TRANSFER PAGE Contents-1 HEATERS/FURNACES REV 10

PROCESS PLANTS DIVISION DATE JULY 2002

FOSTER WHEELER ENERGY LIMITED 2002

CONTENTSPAGE

1.0 GENERAL 1.0-1

1.1 Introduction 1.0-1 1.2 Definition of Terms 1.0-2 1.3 Types of Fired Heaters 1.0-6

2.0 DESIGN CONSIDERATIONS 2.0-1

2.01 Type of Fired Heaters Covered 2.0-1 2.02 Feed Description 2.0-1 2.03 Heat Duty 2.0-1 2.04 Average Radiant Heat Flux 2.0-1 2.05 Mass Velocity through Coil 2.0-2 2.06 Vaporization 2.0-3 2.07 Tube Size and Number of Passes 2.0-4 2.08 Pressure Drop 2.0-5 2.09 Turndown 2.0-7 2.10 Stack Temperature 2.0-8 2.11 Excess Air 2.0-9 2.12 Heater Efficiency 2.0-9 2.13 Burners 2.0-11 2.14 Air Preheat 2.0-13 2.15 Corrosive Compounds 2.0-15

3.0 PROCESS SPECIFICATION 3.0-1

3.1 Fired Heater Process Data Form 110-21A 3.0-1 3.2 Procedure for Completing Form 110-21A 3.0-1

3.2.1 Process Requirements 3.0-1 3.2.2 Mechanical Requirements 3.0-3 3.2.3 Notes for Additional Information 3.0-5

4.0 UTILITIES 4.0-1

4.1 Fuel 4.0-1 4.1.1 Main Burners 4.0-1 4.1.2 Pilots 4.0-1

4.2 Steam 4.0-1 4.2.1 Atomizing 4.0-2 4.2.2 Low Pressure Burners 4.0-2 4.2.3 Soot Blowers 4.0-2




CONTENTS PAGE

4.2.4 Furnace Box Purging 4.0-2 4.2.5 Header Box Smothering 4.0-3 4.2.6 Emergency Purging of Furnace Coil 4.0-3 4.2.7 Fan Drive 4.0-4 4.2.8 Steam-Air Decoking 4.0-5

4.3 Refinery Air 4.0-5 4.3.1 Soot Blowers 4.0-5 4.3.2 Steam-Air Decoking 4.0-5

4.4 Electricity 4.0-5 4.4.1 Fans 4.0-5 4.4.2 Regenerative Air Preheater 4.0-5 4.4.3 Soot Blowers 4.0-5

5.0 INSTRUMENTATION 5.0-1

6.0 STEAM-AIR DECOKING 6.0-1

6.1 Coil Decoking Sample Calculation 6.0-2 6.2 Coke Knockout Drum Sample Calculation 6.0-6

7.0 STACK DESIGN 7.0-1

7.1 Type of Stacks 7.0-1 7.2 Stack Diameter 7.0-1 7.3 Stack Height 7.0-2 7.4 Stack Design Sample Calculation 7.0-6

APPENDIX

Steam Air Decoking A-1




LIST OF FIGURES FIGURE DESCRIPTION PAGE

FIGURE 1 VERTICAL-CYLINDRICAL FIRED HEATER, ALL RADIANT 1.0-8

FIGURE 2 VERTICAL-CYLINDRICAL FIRED HEATER WITH INTEGRAL CONVECTION 1.0-9

FIGURE 3 VERTICAL-CYLINDRICAL FIRED HEATER WITH CROSS FLOW CONVECTION 1.0-10

FIGURE 4 ARBOR OR WICKET FIRED HEATER 1.0-11

FIGURE 5 HORIZONTAL TUBE CABIN FIRED HEATER 1.0-12

FIGURE 6 TWO-CELL HORIZONTAL TUBE BOX FIRED HEATER 1.0-13

FIGURE 7 HORIZONTAL TUBE CABIN FIRED HEATER WITH DIVIDING CENTRE-WALL 1.0-14

FIGURE 8 - FULJET NOZZLES CAPACITIES GI THRU H20 BASED ON WATER AT 70oF 6.0-16

LIST OF TABLES TABLE DESCRIPTION PAGE

TABLE 1 TYPICAL VALUES OF AVERAGE RADIANT HEAT FLUW AND COIL MASS VELOCITIES 2.0-16

TABLE 2 - FULLJET NOZZLES 6.0-13

TABLE 3 - FULLJET NOZZLES - LARGER CAPACITIES 6.0-14

TABLE 4 - FOGJET NOZZLES 6.0-15

PROCESS STD 306 FOSTER WHEELER HEAT TRANSFER PAGE 1.0-1 HEATERS/FURNACES REV 10



1.0 GENERAL

1.1 Introduction

Information is given in this Process Standard to familiarize process engineers with fired heaters and to aid them in completing process specifications for fired heaters. Methods for estimating utilities associated with fired heaters are also given. All preliminary estimates made will have to be confirmed by the furnace vendor who is ultimately responsible for the design of the fired heater.

Fired heaters are also called process heaters, furnaces, process furnaces, and direct-fired heaters. Fired heaters are devices in which heat, provided by burning fuel in a combustion chamber, is transferred to a process fluid contained in tubes. The fuel is usually oil or gas or a combination of both. Tubes are installed along the walls and roof of the combustion chamber, and heat is transferred to the tube wall primarily by radiation in this section. The partially cooled flue gases are then passed through a separate tube bank section where heat is transferred to the tube wall primarily by convection. After all the heat that can be economically recovered has been transferred to the process fluid and used for any auxiliary services such as steam generation, boiler feed water preheat, and combustion air preheat, the flue gas passes through a stack to the atmosphere. The usual flow pattern of the process fluid is to first pass countercurrent to the flue gas through the convection section and then through the radiant section of the fired heater.

Some fired heaters, for very low heat duty services, have no convection section. This is based on economics. Such a design, which consists only of a radiant section, is characterized by low thermal efficiency, but represents the lowest capital investment for a specified duty. Most fired heaters, however, have both a radiant and a convection section.

Fired heater size is defined in terms of heat duty (heat absorbed). Duties range from about a half million Btu/hr for small, specialty units to about 500 million Btu/hr. By and large, the vast majority of fired heater installations fall within the 10 to 350 million Btu/hr range.

Fired heaters fall into two main categories of application: process and pyrolysis.

Process fired heaters provide heat, which is needed in equipment downstream of the fired heater. Typical examples are crude heaters, vacuum heaters, reactor charge heaters for hydrotreaters and catalytic reformers, reboilers, and hot oil belt heaters.




Pyrolysis fired heaters provide heat for a chemical reaction taking place inside the tubes. Examples are steam crackers for ethylene production and steam reformers for hydrogen manufacture. These furnaces and fired steam boilers are not covered in this Process Standard.

Some fired heaters, such as visbreakers, coker heaters, and thermal crackers are considered to be process fired heaters even though they have chemical reactions taking place inside the tubes. Their temperatures are low compared to those of pyrolysis fired heaters and apart from the cracking calculations, the furnace designs closely resemble those for process fired heaters.

1.2 Definition of Terms (also see Figures 1-7)

The following list defines commonly used terms relating to fired heaters:

Air Preheater A heat exchanger which heats the air required for combustion by transferring heat from the flue gas leaving the convection section

Breeching The hood which collects the flue gas at the convection section outlet for transmission to the stack

Bridgewall Temperature

The temperature of the flue gas leaving the radiant section. The term comes from the old horizontal box furnace design in which a bridgewall physically separated the radiant and convection sections

Burner A device for mixing fuel and air for combustion

Cell A portion of the radiant section, separated from other cells by tubes or a refractory wall. Also called a "zone

Coil A tubular configuration, usually a series of straight tube lengths connected by 1800 return bends, forming a continuous path, through which fluid passes and is heated.

Convection Section

The portion of the fired heater, consisting of a bank of tubes, which receives heat from the hot flue gas, mainly by convection

Corbelling Narrow ledges extending from the convection section side walls to prevent flue gas from bypassing tube rows.

Crossover Piping which transfers the process fluid from the




convection section outlet to the radiant section inlet

Damper A device to regulate flow of gas through a stack or duct and to control draft in a fired heater. A typical damper consists of a flat plate connected to a shaft which can be rotated, similar to a butterfly valve

Draft The negative pressure (vacuum) at a given point inside the fired heater usually expressed as inches of water (vacuum gauge).

Excess Air The percentage of air in the fired heater in excess of the stoichiometric amount required for combustion.

Fired Heater Efficiency

The ratio of heat absorbed to the heat fired. The lower heating value (LHV) of the fuel fired is almost always used for fired heaters.

Fire Box The structure which surrounds the radiant coil and into which the burners protrude

Flue Gas A mixture of gaseous products resulting from combustion of the fuel

Forced Draft Use of a fan to supply combustion air to the burners and to overcome the pressure drop through the burners. This is in contrast to natural draft, where the buoyancy of the column of hot flue gas in the stack and fired heater provides the "suction" to pull combustion air into the fired heater.

Gross Fuel The total fuel fired in the heater, usually expressed in lb/hr.

Header Box The compartment at either end of the convection section, which houses the return, bends (headers). There is no flue gas flow in the header box, since it is separated from the inside of the fired heater by an insulated tube sheet. Header boxes are sometimes also used in the radiant section




Heat Duty The total heat absorbed by the process fluid, usually expressed in Btu/hr. Total fired heater duty is the sum of heat transferred to all process streams, including auxiliary services such as steam superheaters

Heat Fired The total heat released in the fired heater, equal to gross fuel times the lower heating value (LHV) of the fuel, usually expressed in Btu/hr. It is also called "heat liberated

Heat Flux The rate of heat transfer per unit area to a tube usually based on total tube outer surface area. Typical units are Btu/(hr-ft2). It is also called "heat density", "heat transfer rate", "flux density

Higher Heating Value (HHV)

The theoretical heat of combustion of a fuel, beginning and ending at 600F, when the water formed is considered as a liquid, i.e. credit is taken for its heat of condensation. It is also called gross heating value, and is usually expressed in Btu/lb for liquids and gases, or Btu/SCF for gases

Hip Section The transition zone at the top of the radiant section in cabin type furnaces. The wall of this section is usually at a 450angle

Induced Draft Use of a fan on the flue gas side of the furnace to provide the additional draft required over that supplied by the stack to draw the flue gas through the convection section

Lower Heating Value (LHV)

The theoretical heat of combustion of a fuel, beginning and ending at 600F, when no credit is taken for the heat of condensation of water in the flue gas. The LHV equals the HHV minus the latent heat of vaporization of water. It is also called net heating value, and is usually expressed in Btu/lb for liquids and gases, or Btu/SCF for gases.

Mass Velocity The mass flow rate per unit of flow area through the coil. Typical units are lb/(sec-ft2).




Natural Draft The system in which the draft required to move combustion air into the fired heater and flue gas through the fired heater and out the stack is provided by stack buoyancy effect alone

Net Fuel The fuel which would be required in the fired heater if there were no heat losses. It is usually expressed in lb/hr.

Pass A coil, which transports the process fluid from, fired heater inlet to outlet. The total process fluid can be transported through the fired heater by one or more parallel passes

Radiant Section

The portion of the fired heater in which heat is transferred to the tubes primarily by radiation from the flame and high temperature flue gas

Shield Section The first two tube rows of the convection section. These tubes are exposed to direct radiation from the radiant section and usually receive about half of their heat in this manner. They are usually made of more resistant material than the rest of the tubes in the convection section. They are also called shock tubes

Soot Blower A steam lance (usually movable) in the convection section for blowing soot and ash from the outer surface of the tubes with high pressure steam

Stack A steel, concrete or brick cylinder which carries flue gas to the atmosphere and provides necessary draft

Stack Effect The buoyancy obtained from the difference in density between a column of high temperature gas inside the fired heater and/or stack and an equivalent column of external (ambient) air, usually expressed in inches of water per foot of height

Stack Temperature

The temperature of the flue gas as it enters the stack




1.3 Types of Fired Heaters

There are many variations in the layout, design, and construction details of fired heaters. A consequence of this flexibility is that virtually every fired heater is custom engineered for its particular application.

The principal classification of fired heaters, however, relates to the orientation of the heating coil in the radiant section; i.e. whether the tubes are vertical or horizontal. Typical vertical arrangements are shown in Figures 1 to 4. Horizontal arrangements are shown in Figures 5 to 7.

The main features for several configurations of fired heaters are noted below:

Vertical-cylindrical, all radiant (Figure 1)

The tube coil is placed vertically along the walls of the combustion chamber. Firing is vertical from the floor of the heater, parallel to the tubes.

Heaters of this type represent a low cost, low efficiency design, which requires a minimum of plot area. Typical duties are 0.5 to 10 million Btu/hr.

Vertical-cylindrical, with integral convection (Figure 2)

Although this design is rarely chosen for new installations, because of the difficulty in cleaning the convection section, the vast number of existing units of this type warrants its mention.

As with the all radiant type, this design is vertically fired from the floor, with its tube coil installed in a vertical arrangement along the walls. The distinguishing feature of this type is the use of added surface area on the upper section of each tube to promote convection heating. This surface area is located in the annular space formed between the convection walls and a central baffle sleeve. Medium efficiency can be achieved with a minimum of plot area. Typical duties for this design are 10 to 100 million Btu/hr.

Vertical-cylindrical, with cross flow convection (Figure 3)

These heaters are fired vertically from the floor and feature both radiant and convection sections. The radiant section tube coil is arranged vertically along the walls of the combustion chamber. The convection section tube coil is arranged in a horizontal bank of tubes positioned above the combustion chamber.




This heater configuration provides an economical, high efficiency design that requires a minimum of plot area. The majority of new, vertical-tube fired heater installations fall into this Category. Typical duties range from 10 to 200 million Btu/hr.

Arbor or Wicket (Figure 4)

This is a specialty design in which the radiant heat surface is provided by U-tubes connecting the inlet and outlet terminal manifolds. This type is especially suited for heating large flows of gas under conditions of low pressure drop. Typical applications are found in petroleum refining, where this design is often employed in the catalytic reformer charge heater, and in various reheat services. The firing modes are usually vertical from the floor, or horizontal between the U-tubes.

This design type can be expanded to accommodate several arbor coils within one structure. Each coil can be separated by dividing walls so that individual firing control can be attained. In order to increase heater efficiency, a crossflow convection section is normally installed to provide supplementary heating for services such as steam generation. In this design, variations in operating conditions of the individual services must be carefully considered since each radiant zone is providing heat to the common convection section. Typical duties for each arbor coil of this design are 50 to 100 million Btu/hr.

Two-cell horizontal tube box (Figure 6)

The radiant section tube coil is arranged horizontally along the sidewalls and roof of the two combustion chambers. The convection section tube coil is arranged as a horizontal bank of tubes positioned above and between the combustion chambers. Vertically fired from the floor, this is again an economical, high efficiency design. Typical duties range from 100 to 300 million Btu/hr. For increased capacity, the basic concept can be expanded to include three or four radiant chambers.

Horizontal tube cabin, with dividing center wall (Figure 7)

The radiant section tube coil is arranged horizontally along the sidewalls of the combustion chamber, and along the hip. The convection section tube coil takes the form of a horizontal bank of tubes positioned above the combustion chamber. A dividing center wall between the cells allows for individual firing control over each cell in the combustion chamber. Available options permit horizontal firing with sidewall-mounted burners (as shown), or vertical firing from the floor along both sides of the center wall. A typical duty range for this design is 20 to 100 million Btu/hr.




2.0 DESIGN CONSIDERATIONS

2.01 Type of Fired Heaters Covered

Guidelines for specifying process fired heaters are given in this Process Standard. As mentioned in Section 1.1, pyrolysis furnaces and fired steam boilers are not covered in this Standard.

2.02 Feed Description

Characteristics of the fluid to be heated must be given. If feed is all or part liquid and vaporization will occur during passage through the heater, a feed phase diagram must be provided which shows the LV% (liquid volume %), or wt% vaporized at any given temperature and pressure. The full operating range must be covered. Curves showing the vapor molecular weights, liquid 0API, and wt% vaporized vs. LV% vaporized should also be provided.

2.03 Heat Duty

The total furnace heat duty is obtained from the process requirements, and is the sum of heat transferred to all process streams, including auxiliary services such as steam superheaters. All operating cases must be included. The process engineer should also establish any design margin that may be required from the design case, based on experience with the particular process.

2.04 Average Radiant Heat Flux

The selection of the average radiant transfer rate (heat flux) is an essential step in the design of a fired heater. The higher the design radiant rates, the less the amount of heat transfers surface, the smaller the heater, and the lower the cost.

Unduly high radiant rates, however, result in higher maintenance costs because the refractories and tube supports are exposed to higher temperatures and thus have shorter service lives. Furthermore, high tube wall temperatures reduce tube life and raise the potential for coke deposition and product degradation.

Heat transfer is not uniform throughout the radiant coil. The average heat flux is about 40 to 50% of the maximum for one-side fired tubes, the actual maldistribution being determined by the fired heater configuration. Therefore, the fired heater design and operation must be based on an average heat flux low enough to obtain a satisfactory maximum heat flux.




The allowable average radiant heat flux rate is a function of several factors including fired heater type, feedstock, service, and coil outlet temperature. The allowable average radiant heat flux is, therefore, established by experience. Table 1 lists typical values of average radiant heat flux for various services.

2.05 Mass Velocity through Coil

Fired heaters in all-liquid or in vaporizing service where coking or fouling can occur must be designed with high enough mass velocities to minimize coking or fouling. Cracking and polymerization occur in the film on the inside tube wall surface and a layer of coke or polymer gradually builds up. The layer increases the coil pressure drop and increases tube metal temperatures until at some point, the fired heater has to be decoked.

The higher the film temperature, the higher the cracking rate. The higher the mass velocity, the higher the heat transfer coefficient, and the higher the heat transfer coefficient, the lower the film temperature will be at a given bulk fluid temperature. However, too high a mass velocity will cause a high coil pressure drop, resulting in high pumping or compressor costs, increased design pressure of upstream equipment, and possible erosion of heater return bends. Therefore, the design mass velocity is usually kept in the range of 250 to 350 lb (sec-ft2) for most process fired heaters in all-liquid or vaporizing services where coking or fouling can occur.

Under turndown conditions, mass velocity should be kept above 150 lb/(sec-ft2) in order to prevent excessive coking or fouling. This may result in a high mass velocity at design conditions (and associated high costs) for fired heaters designed for large turndowns or where pre-investment is made for substantial future increases in throughput. Recycling through the fired heater can be considered as a means of maintaining mass velocity at turndown conditions and yet avoiding high pressure drops at design conditions, provided the recycle fluid is thermally stable.

In some special situations, such as at the outlet of a vacuum heater, it is not possible to maintain this high mass velocity. Because of the low pressure and resulting high specific volume of the vapor, sonic velocity would be reached at the furnace outlet at high mass velocity. This can cause erosion of the heater tubes or transfer line, and fogging of the fluid (which could upset fractionation in the vacuum tower as well as limit tower throughput). To avoid these problems, vacuum heater outlet tubes and transfer lines are usually designed for velocities below 80% of sonic.




This practice usually requires reducing the design mass velocity in the heater outlet tubes to about 80 to 120 lb/(sec-ft2), and no lower than bout 60 lb/(sec-ft2) under turndown conditions. Even with this reduced mass velocity, coking is not normally a problem in the outlet tubes because of the high linear velocity and low residence time. Refer to the FWEC Vacuum Unit Design Manual for the specifics of vacuum heater and transfer line design procedures.

Fired heaters with all-vapor flow are generally not susceptible to the same severe coking problems as those in vaporizing services. Satisfactory film coefficients usually can be obtained with a mass velocity at design conditions as low as 15 lb/(sec-ft2). High mass velocities, such as those used in vaporizing services, would cause very high pressure drops in all-vapor flow.

Table 1 gives typical design fluid mass velocities for various services.

2.06 Vaporization

Usually it is best to avoid the situation in which the liquid or partially vaporized feed to a fired heater reaches a point within the heater in which it becomes 100% vaporized (dry point). Foreign material or polymer formed in tankage which does not vaporize might deposit on the tube at the dry point (point where the last liquid on the tube wall vaporizes) and cause a coking or fouling problem. Therefore, maximum vaporization in the coil should be limited to about 80 LV%.

When a clean distillate, such as a crude unit sidestream, is fed directly into a fired heater with no intermediate storage, the risk of fouling associated with going through the dry point is minimal, since the distillate has just been completely vaporized and condensed.

Poor flow distribution to the coils in multi-pass fired heaters, which result in low flow to one or more passes, can cause overheating, coking, and tube burnout in those passes. Flow controllers are used on each pass to assure equal flow distribution, but if there is partial vaporization at the orifices which measure the flow rate through each pass, erroneous indications of flow rate can occur. Therefore, partial vaporization upstream of the control valves should be avoided, where reasonable, and the following alternatives should be considered to prevent any vaporization.

Specify a higher than normal pressure drop for the inlet control valves in order to prevent vaporization.




Install a flash drum and booster pump in the exchanger train. The vapor bypasses the heater and the liquid is pumped through the heater. In this scheme, the furnace coil outlet temperature will increase because of bypassing vapor.

Split the feed stream before any vaporization occurs. The final preheat is then accomplished in parallel trains, one for each furnace pass.

In some cases, the client will accept a degree of vaporization upstream of the control valves. In such cases, the piping to the flow controllers on each pass must be symmetrical, and flow must be dispersed under all operating conditions. The maximum amount vaporized before the control valves should be limited to 5 LV%.

2.07 Tube Size and Number of Passes

A combination of tube diameter and number of passes is selected to satisfy both the mass velocity and throughput requirements. Tube diameters are normally selected from standard nominal pipe sizes (IPS) in the range of 4 to 8 inches. For small furnaces tubes may be only 2 inches, and for vacuum furnaces, outlet tubes up to 10 inches may be used. Non-standard sizes can also be used when design parameters cannot be met with standard sizes.

The number of passes must be consistent with the furnace type, so that each pass receives the same amount of heat. While vertical-cylindrical furnaces can be designed for almost any number of passes, cabin furnaces usually require an even number of passes so that they can be symmetrically arranged in the furnace.

In vaporizing or all-liquid services, the cost and complexity of uniformly distributing flow to multiple passes increases with the number of passes. Therefore, the number of passes should be minimized, consistent with the fired heater arrangement. The same number of passes should be maintained throughout the furnace.

In all-vapor services, even distribution of flow to individual passes can be obtained by proper manifold design. A different number of passes and different tube sizes can be used for the radiant and convection sections, since convection section outlets can be combined and then redistributed at the radiant section inlets.

Example of How to Estimate Tube Size and Number of Passes Given

Atmospheric Crude Unit Fired Heater

Throughput = 1,700,000 lb/hr of crude oil




Solution

Recommended Mass Velocity (Table 1) = 250-350 lb/(sec-ft2)

Tube Size IPS

Cross Sectional

Flow Area, ft2No. of Passes

Mass Velocity

lb (sec-ft2)

6 inch 0.2006

6

8

10

392

294

235

5 inch 0.1390

8

10

12

425

340

283

Since the most economical tube size is generally in the 4-6 inch range, and the number of passes should be minimized, assume 8-pass, 6 inch IPS as best combination. This method of estimating tube size and number of passes can only be approximate, and the furnace vendor will have to determine the most economical tube size/pass arrangement.

2.08 Pressure Drop

During detailed heater design, the pressure drop through the coil is determined by the fired heater vendor. The calculation is complex for vaporizing services where the pressure drop per unit length changes continuously with changes in the gas-liquid ratio.

In general, after the number of tubes and the tube layout have been established, the coil is divided into a number of sequential sections for the pressure drop calculation. Smaller sections are used at the outlet (as few as two tubes), where the specific volume is changing rapidly. Larger sections are taken as one proceeds back into the coil. For a typical crude unit fired heater, approximately 6 sections should be satisfactory.




Calculations are started at the coil outlet where the temperature and pressure are known. Here the enthalpy and composition can be calculated. Then a pressure is assumed at the inlet to the first section back in the coil. The enthalpy added in this section (heat flux in radiant section is assumed to be uniform) is subtracted from the coil outlet enthalpy and the temperature and composition calculated with this enthalpy and the assumed pressure. Using the inlet and outlet conditions, and the equivalent length of the section (straight run plus fittings), the pressure drop in the section is calculated, due to friction, changes in kinetic energy, and changes in static head. In the case of partially vaporized liquids, no appreciable error is introduced if the change in static head is neglected, since the change is generally very small.

If the calculated pressure drop does not agree with the assumed inlet pressure, a new pressure must be assumed and the calculations repeated. When good agreement is reached, the calculations are continued upstream until the coil inlet is reached.

In heaters with a high percent of vaporization, it is possible for a temperature peaking condition to occur. As the mixed-phase fluid flows through the coil, it undergoes a substantial drop in pressure per unit length of flow. This can result in the rate of vaporization in a section to be high enough to cause the fluid temperature to fall, even though the enthalpy of the fluid increases. The fluid outlet temperature, therefore, could be less then the temperature at some point back in the coil. In some fired heaters, such as lube vacuum heaters, it is important to have a continually rising temperature profile (no temperature peaking), and this may dictate tube sizes.

The process engineer is required to give the maximum allowable pressure drop through the heater coil on the process heater specification. This pressure drop is obtained from experience with similar heaters. Generally the pressure drop has to be estimated for both clean and fouled conditions.

For heaters in vaporizing service, the pressure drop is usually relatively high because of the required mass velocities and the fluid vaporization. Typical pressure drops for crude unit heaters are 150-200 psi with clean tubes and an additional 25-50 psi with fouled tubes. For vacuum unit heaters, typical pressure drops are 50-75 psi with clean tubes and an additional 15-25 psi with fouled tubes. Coker heaters take about a 350 psi pressure drop clean and an additional 50-100 psi when fouled.




Heaters in all-vapor service have much lower pressure drops. As an example a catalytic reformer preheater may have a pressure drop of 15-25 psi, and the reheat furnaces as little as 3-6 psi. These furnaces, of course, are designed for low pressure drops in order to minimize recycle compressor head.

2.09 Turndown

Turndown requirements will be set by process considerations. If multiple design cases are specified, the furnace must be able to handle all operations. Also, with any operation, a certain minimum throughput may be required.

In general, turndown rates of 60% of design can be used without falling below mass velocity rates needed to prevent excessive coking rates. If very high turndown rates are required, it may be necessary to recycle through the furnace in order to maintain the minimum desired mass velocity.

Burner turndown is a function of burner design and type of fuel. However, burner turndown does not normally affect furnace turndown, since burners can be turned off or excess air increased when the furnace is operated at greatly reduced firing rates. Below about 35% of design, many burners are shut and uneven heating patterns limit lower rates.

If auxiliary services are included in the heater convection section, these must be considered for the turndown case. For instance, if a steam superheater coil is included in the convection section, the heater may have to supply the design superheat duty while supplying the minimum process duty.

The turndown analysis for multi-cell furnaces for two or more services is even more complex. Consider a furnace with three radiant zones and a common convection section, as might be used for a catalytic reformer. The central radiant zone and the convection section would be used for preheat and the other two radiant zones for reheat. The heat input to any zone is influenced to some extent by the heat input to the other zones. Also, since each radiant zone contributes flue gas to the convection section, any reduction in the reheat radiant zones would require additional firing to the preheat radiant zone to make up for the reduced convection section heat input. Variations in relative duties over the run length would have to be considered. A complete analysis sometimes shows that a separate furnace is required for steam superheat, usually to meet "oil-side" process needs. Also, small reheat duties are often put in separate heaters to solve problems.




The furnace vendor must examine the tube metal temperature at the convection section cold end at turndown conditions, particularly with relatively cold coil inlet temperatures, to assure that the acid dewpoint of the flue gas is not reached. See Section 2.10 - Stack Temperature.

2.10 Stack Temperature

The economic stack temperature is a function of fuel value, inlet oil temperature, investment cost of incremental convection section, and the required rate of return from incremental investment. The stack temperature is determined by the fired heater designer, but the process engineer generally has to estimate fuel requirements before the furnace design is completed. For this purpose, it is reasonable to assume an approach temperature (stack temperature minus coil inlet temperature) of 150F. Stack temperatures usually range from 350-700F. The 350F stack temperature can be achieved with a furnace firing very low sulfur and using combustion air preheat.

Special attention must be given to the stack temperature when coil inlet temperatures are low (below 250-300F). The stack temperature must be high enough to prevent acid condensation on the convection section inlet tubes. When fuels containing sulfur are burned, the sulfur is converted to sulfur dioxide (SO2), and part of the sulfur dioxide is converted to sulfur trioxide (SO3) which combines with water vapor to form sulfuric acid. This sulfuric acid remains in the vapor state as long as the temperature is above the acid dewpoint of the gas, but condenses out on relatively cool surfaces (below about 250 to 300F) and causes metal corrosion.

The furnace vendor shall be asked to calculate the flue gas acid dewpoint temperature. The process engineer can estimate this temperature from correlations of acid dewpoint vs. the percentage of water vapor and sulfur trioxide in the flue gas. The volume percent water vapor in the flue gas can be calculated from the fuel analysis, the percent excess air, the air humidity, and the fuel atomizing steam, if any. In the case of liquid fuels, the composition is rarely provided. If only the gravity is given, the carbon to hydrogen ratio can be estimated from the data in the "Liquid Fuels" table on page 14.1 (Combustion Section) of the API Technical Data Book. If the Watson Characterization Factor, K, is also known, Figure 2B6.1 of the API Technical Data Book can be used. The calculation of the volume percent sulfur trioxide is much more complex. The amount of sulfur dioxide converted to sulfur trioxide depends on many factors including fuel composition, excess air, firing rates, and the presence of vanadium in the fuel oil. As a rough estimate, it can be assumed that 1-2% of the fuel sulfur is converted to sulfur trioxide. For design purposes, assume 5% is converted to sulfur trioxide.




Knowing the percentage of water vapor and sulfur trioxide in the gas, the acid dewpoint temperature in degrees Kelvin can be calculated from the following equation:

P0.0269+1.7842=T

1,000OH10

DP2

log

PP0.0329+P0.1029- SO10OH10SO10 323 logloglog

Where TDP = Dewpoint in K (273 + C)

P = partial pressures in atmospheres

This equation was published on page 125 of the article, "Estimating Acid Dewpoints in Stack Gases, " by Robert R. Pierce, Chemical Engineering,11 April 1977, pages 125-128.

2.11 Excess Air

A higher combustion air rate is necessary than that theoretically required for complete combustion of the fuel. This is caused by variations in the distribution of air and fuel to the individual burners, as well as by imperfect mixing of air and fuel in the burner and the flame. Consequently, extra air must be supplied to obtain satisfactory combustion. However, no more excess air should be furnished than that actually required, since any additional air must be heated up to the stack exit temperature, wasting fuel.

In estimating the combustion air requirements, assume 10% excess air for all process fired heaters designed for forced draft firing (regardless of fuel) or for natural draft firing of gas fuel. Fired heaters designed for natural draft fuel oil firing, or combination gas/oil firing, encounter greater mixing difficulties and should be assumed to require 20% excess air.

2.12 Heater Efficiency

In the United States, the thermal efficiency of process fired heaters is almost always based on the LHV of the fuel. To avoid confusion, however, the basis should be given when stating the efficiency.

The thermal efficiency of a fired heater in percent, based on the LHV of the fuel, is defined as follows:

100x(LHV)FiredHeat

AbsorbedHeat=ELHV




The heat absorbed is obtained from the process requirements. The heat fired must be calculated. First the flue gas temperature leaving the convection section must be estimated. As mentioned in Section 2.10, this can be estimated as 150F above the coil inlet temperature. Then the heat extracted from the flue gas (in BTU/lb of fuel fired) in reaching the flue gas outlet temperature is obtained from the fuel characteristics, percent excess air, and the "Heat Available from Combustion" charts in the API Technical Data Book (Figures 14B1.1-14B1.7). Use the chart for fuel closest to characteristics of fuel fired.

To obtain the net fuel fired in lbs/hr, divide the heat absorbed in BTU/hr by the heat extracted from the fuel gas in BTU/lb of fuel fired. To obtain the gross fuel fired, the net fuel fired has to be increased to account for furnace heat losses (excluding stack losses). As an estimate, the net fuel fired can be increased by the following factors to obtain the gross fuel fired:

Fired Heater Size

Million BTU/hr Heat Absorbed Factor

Greater than 100 1.01

15 to 100 1.02

Less than 15 1.03

Since the fired heater efficiency is to be calculated on the basis of fuel LHV, the gross fuel fired is multiplied by the fuel LHV.

Example of Furnace Efficiency Calculation Given

Coil Inlet Temperature: 450oF

Heat Absorbed: 350 million BTU/hr

Fuel: 15o API fuel oil

LHV = 17,500 BTU/lb

Burners Combination Gas/Oil - Natural Draft

Solution

a) Flue gas temperature leaving convection section, using 150F stack approach = 450F + 150F = 600F

b) Excess air = 20% (based on combination gas/oil natural draft burners)

c) Heat extracted from flue gas (Figure 14B1.6 API Technical Data Book) based on 600F flue gas temperature and 20% excess air = 15,100 BTU/lb of fuel




d) Net Fuel Fired =BTU/lb15,100

BTU/hrMillion350 = 23,180 lb/hr

e) Gross Fuel Fired = 23,180 lb/hr x 1.01 = 23,410 lb/hr

f) Heat Fired = 23,410 lb/hr x 17,500 BTU/lb = 410 Million BTU/hr

g) LHV Efficiency =BTU/hrMillion410

BTU/hrMillion350 x 100 = 85.4%

The efficiency of a fired heater can be increased by reducing the stack gas temperature, but the temperature should only be reduced to a point where it is still certain that acid will not condense from the flue gas. To reduce the temperature, auxiliary services such as steam generation and boiler feed water preheat can be added, or combustion air preheat should be considered. These options are all subject to economic evaluation.

2.13 Burners

Burners are classified according to the type of fuel, which they burn: gas, liquid, or combination gas and liquid.

When only gaseous fuels are to be fired in process furnaces, and no combustion air preheat is used, natural-draft gas burners are normally specified. They are either of the raw gas or pre-mix type. The raw gas burner is one in which the fuel gas is injected into the air stream for ignition. The pre-mix burner uses the kinetic energy of the fuel gas to inspirate and mix part or all of the combustion air with the fuel gas in a mixing tube. The air/fuel mixture is then introduced into the ignition zone. Any additional (secondary) air required enters through, and is controlled by, an air register. Both types are easy to operate and maintain, and noise attenuation is accomplished by primary air mufflers and acoustical plenum chambers.

Pre-mix burners may be limited in turndown because of the possibility of flashback into the mixing tube. Flashback occurs when the velocity of the air/fuel mixture drops below the flame velocity for the mixture. Hydrogen has a significantly higher flame velocity than do hydrocarbon gases. Thus, with high hydrogen concentrations in the fuel gas (30 to 50%) the degree of turndown can be limited, and pre-mix burners are not normally used.

Liquid burners of the natural draft type are available. Forced draft liquid burners are more expensive than natural draft liquid burners, but they provide more efficient fuel/air mixing, and noise in the system may be more easily attenuated.




Liquid fuels must be properly atomized in order to achieve complete combustion. For good atomization, the fuel should be supplied to the burner at a viscosity of 125 SSU (26 centistokes) or less. However, high viscosity burners are available which are capable of operating on vacuum residue at 300 SSU. Atomization is usually accomplished by the use of steam. The kinetic energy of steam jets break the fuel into small droplets and the atomized fuel is carried into the ignition zone by the steam. The fuel pressure at the burner should be 60 to 100 psig, with the higher pressure preferable, if available. The steam pressure should be about 30 psi higher than the fuel pressure.

For those rare instances when steam is not available, air atomization or mechanical atomization can be employed. The operating requirements of air-atomized oil burners are similar to those of steam-atomized ones. A slightly higher oil temperature may be needed, however, to compensate for the cooling effect of the atomizing air. Mechanically atomized units take advantage of the oil's kinetic energy to atomize the fuel stream in the tip itself. High fuel pressure, 350 psig and greater, is required.

When volatile fuels such as naphtha are used, care must be taken that partial vaporization of the fuel does not take place upstream of the fuel gun. This condition would result in severe burner instabilities and possibly cause burner flame out. Also, safety interlocks should be specified to prevent removal of a burner gun without complete shutoff of the fuel and prior to automatic steam purge of the fuel remaining in the burner gun.

Combination gas/liquid burners are essentially the combination of a liquid burner and a multi-gun gas burner. These burners are capable of firing all gas, all liquid, or both fuels simultaneously.

Several high intensity burners are available for fired heater applications. In general, they feature a large, cylindrical-shaped, refractory-lined combustion chamber. Combustion is fully established in this chamber, but not completed. By means of the circulation patterns developed within the chamber, flames of controlled shape and size can be produced at relatively low excess air. High intensity combustion expels the flue gas at high velocity and temperature producing very uniform firebox temperature profiles.

For very low pressure gases, a special pre-mix burner with steam eductor can be used. This burner (aspirating type) is often used to burn waste gas streams as vacuum unit non-condensibles. Specialty burners are also available for firing mixtures of unsaturated gases, which have a tendency to polymerize. High pressure or steam injection is used.




Safety considerations require that flameout protection be provided for each burner in a furnace. Usually this is accomplished by means of gas-fired continuous pilots which will immediately reignite the fuel after flameout. Only clean dry fuel gas may be used for the pilots. The fuel gas can be supplied either from the main furnace fuel gas system or, preferably, from a reliable independent source. If the fuel gas comes from the main system, the pilot gas must come from upstream of the furnace fuel control and shutoff valves.

2.14 Air Preheat

Fuel consumption in a fired heater can be reduced markedly by preheating the combustion air. In the preheater, heat is transferred from the flue gas to the combustion air, reducing the exit temperature of the flue gas and raising the thermal efficiency. With air preheat systems, exit flue gas temperatures often range around 325 to 3500F and efficiency levels commonly reach 90 to 92% (LHV). When firing gas with very low sulfur content, exit flue gas temperature can be as low as 2500F. With such systems, the attainable thermal efficiency is no longer controlled by the approach between the flue gas and inlet fluid temperatures. The temperature of the flue gas leaving the preheater, which determines the efficiency, should be as low as possible without risking low temperature corrosion of the preheater elements. The cost of the air preheat system, however, must be justified by the resulting fuel savings. The higher combustion air temperature will increase the NOx level in the flue gas, and if air pollution regulations would be violated, some form of NOx control would have to be added. The fired heater vendor will have to consider the cost of any such NOx control in making economic evaluations on the use of air preheat.

Regenerative Air Preheater

The regenerative preheater consists of metallic elements that are alternately heated and cooled. The most common type of regenerative preheater is the Ljungstrom. The metallic elements are contained in a subdivided cylinder that rotates inside a casing. Hot flue gas flows through one side of this cylinder and heats the elements, while the air to be heated flows through the other side. The cylinder rotates and heat is transferred from the heated elements to the cooler air.

Baffles, which subdivide the cylinder, as well as seals between the cylinder and the casing, limit the amount of leakage from the air side to the flue gas side. Since the air side is at a higher pressure than the flue gas side, leakage is always toward the flue gas side. This leakage, which is usually 10 to 20% of the total flow, must be taken into account in the design, particularly of the fans.




The regenerative preheater is normally mounted at grade, adjacent to the furnace. Ambient air is forced through the preheater by a forced draft fan and is carried in ducts from the preheater to the furnace and burners. The hot flue gas is carried in ducts from the top of the convection section to the preheater. An induced draft-fan draws this flue gas through the convection section, ducting, and preheater and discharges it into the stack. An increase in plot area is required over that for a conventional furnace, because of the preheater, fans, and ducts.

The regenerative type of preheater is often used for very large duty heaters and with oil or dirty gas fuels where fouling or corrosion of preheater elements could be a problem. It is the classical type of preheater with a long history of use, and until relatively recently, was the only type of design available. Its main advantage as compared to other newer types of air preheaters is that it is mechanical in nature, with moving parts, and thus may be subject to breakdown.

Tubular Air Preheater

A tubular air preheater normally consists of a large rectangular heat exchange bundle. The air to be preheated is forced through the tubes, while the hot flue gases pass across the tubes. The tubes are usually finned to improve heat transfer on the flue gas side. This type of preheater may be mounted either on the ground or above the process convection section of the furnace. When it is mounted on the ground, the ducts and fans are similar to those for the regenerative air preheater.

In the case of furnace mounted tubular air preheaters, the flue gas passes directly from the furnace through the preheater and into the stack. In most cases, the induced draft fan is eliminated. However, ducting is required to carry the cool air from the forced draft fan up to the preheater and the hot air back down to the burners. In some cases, the forced draft fan can be mounted at the top of the furnace to eliminate the long ducts from the fan to the preheater.

In certain applications where clean fuel gas is used, a tubular air preheater installation may prove to be less expensive than a regenerative one. It has the advantage of no moving parts, and no leakage between the flue gas and the air.




Heat Pipe Air Preheater

Within the last few years, Q-Dot Corporation, which is partially owned by Foster Wheeler, has been successfully manufacturing heat pipes as a new innovation. The heat pipe, which is used for air preheating, is a tube which has been fabricated with a capillary wick structure, evacuated, filled with a suitably selected heat transfer liquid, and permanently sealed. Thermal energy applied to either end of the pipe causes the heat transfer liquid at that end to vaporize. The vapor then travels to the other end of the pipe where thermal energy is removed, causing the vapor to condense, thereby giving up the latent heat of condensation. The condensed liquid then flows back to the evaporator section to be reused, thus completing the cycle.

Heat pipes have the advantage of no moving parts, no leakage, light weight, and low pressure drop.

A bypass duct should be provided around the air side of the preheater. In addition to its use in completely bypassing the preheater, this duct is used to control flue gas exit temperature, thereby minimizing preheater corrosion caused by condensation on the flue gas side at low firing rates or low ambient air temperatures. A flue gas bypass duct to the stack should also be provided to bypass the preheater and the induced draft fan.

2.15 Corrosive Compounds

The primary considerations for material selection are the required strength, resistance to corrosion (or erosion), and oxidation (or reduction) characteristics. Bearing upon these characteristics are the temperature level, the fired heater atmosphere, and corrosive constituents of the process fluid and the fuel.

Special construction materials may be required for refractory and tube supports if the fuel contains high concentrations of corrosive materials such as vanadium, sodium or sulfur. Not only do vanadium oxides cause severe metallurgical attack at elevated temperature and refractory attack through the formation of a lower melting temperature eutectic layer at the surface of the refractory, but vanadium pentoxide is also a prime catalyst for the conversion of SO2 to SO3.




Sulfur is generally the principal corrosive constituent of the process fluid. For hydrocarbon streams containing H2S and H2, the quantities of these materials are important in choosing tube materials.

The process engineer must specify the quantities of corrosive components in both the process fluid and the fuel so that the appropriate materials an design features can be selected.




3.0 PROCESS SPECIFICATION

3.1 Fired Heater Process Data Form 110-21 A

A copy of Form 110-21 A is found on the next page. This form is to be used when preparing a process specification for a process fired heater. A completed form for an atmospheric unit fired heater is found at the end of Section 3.

3.2 Procedure for Completing Form 110-21 A

Specific Customer/Licensor Requirements, the Basis of Design, and the Basic Engineering Data for a specific project must be followed.

3.2.1 Process Requirements

a) Three columns are provided for different cases or for a case with multiple coils in different services. All coils and/or cases must be properly identified.

b) The type of fluid to be heated is given, and if pertinent, the composition must be given in the Notes. Notes are usually given on attached sheets. The flow rates are given both in B/SD and in lbs/hr.

c) The inlet and outlet conditions are established from process heat and material balances. Liquid viscosities should be obtained from crude assays or from other data on the specific fluid being heated. If no data are available, viscosities will have to be estimated from correlations in either the API Technical Data Book (Figure 11A4.1) or in the FWEC Design Data Book (Charts 1-202, 1-203, 1-204, 1-210, 1-211, 1-212, and 1-213). If vaporization occurs in the heater, vaporization data as described in Section 2.2 should be attached.

d) The maximum pressure drop allowable is estimated from experience as discussed in Section 2.08.

e) The coil heat duty is obtained from the process requirements. As discussed in Section 2.03, any safety factor added should be based on experience with the particular process.




f) The maximum bulk fluid temperature to be reached is sometimes very important. The higher the temperature reached by the fluid, the greater the tendency to crack or polymerize. If the peak bulk fluid temperature is important, it should be given.

g) The average radiant heat flux is discussed in Section 2.04. Frequently, the customer or licensor will set this value, but otherwise the process engineer does not normally specify it.

h) Corrosive compounds are discussed in Section 2.15. Any material in the feed, which can cause erosion, should also be described.

i) The total heat absorbed is set by process requirements and is discussed in Section 2.03.

j) The minimum net efficiency required is sometimes set by the customer. If not, none is usually given by the process engineer, although the furnace vendor is often asked to determine the economics of preheating combustion air.

k) The payout period for delta investment is given by the customer. A typical value is three years, before taxes.

l) The fuel properties and steam available for fuel atomization together with costs for payout calculations are given in the Basic Engineering Data (BED) for the project, and it should be so stated. If a project has no BED, the fuel and steam data will have to be included in the notes.




3.2.2 Mechanical Requirements

a) The type of heater is often specified by the customer or licensor, or there may be a preference based on experience with a particular service. Otherwise, the option can be left to the furnace vendor. The vertical cylindrical furnace is probably the most common in use for heat duties up to about 150 million Btu/hr and requires the least plot area. All-radiant furnaces are rarely used and can be justified only for very small furnaces or for furnaces used infrequently, as for start-up heating.

b) The material and corrosion allowance is not specified by the process engineer, unless specified by the customer or licensor.

c) The minimum tube thickness and design temperature is to be established by the furnace vendor. The design fluid temperature is given by the process engineer.

d) The design pressure for the process coil is determined by adding the safety valve set pressure on the vessel (or design pressure of the vessel), that the furnace feeds (psig), the pressure drop through the vessel (psi), the transfer line pressure drop (psi), the maximum furnace coil pressure drop (psi), and the transfer line static head (psi), assuming the line to be full of cold liquid as at start-up. If necessary, this design pressure can be revised when the furnace pressure drop has been calculated by the furnace vendor.

e) The preferred tube size and number of passes are usually not specified by the process engineer. For the preparation of engineering flow diagrams, tube size and number of passes can be estimated as outlined in Section 2.07. The final values must be confirmed by the vendor.

f) Pipe and extended surface convection tubes can be used, unless prohibited by the customer or licensor. Densely finned tubes are easily fouled, and therefore are used only with gas firing or with very light liquid fuels. Less densely finned or studded tubes are used when firing fuel oil.

g) Return fitting data are not normally specified by the process engineer unless special requirements have been set up by the customer or licensor.

h) Terminal sizes are not specified by the process engineer.




i) Stack data are not normally specified except for specific customer requirements. The process engineer must check, however, to determine if there are any special environmental requirements to be met by the stack design.

j) The type of burner (gas, liquid or combination gas/liquid firing) should be specified, and continuous gas pilots are usually used. The type of burner required is generally given by the customer. The process engineer must check to determine if any special type burner is required because of environmental reasons. Also, the gas composition to be used for pilots must be given in the BED or in the Notes.

3.2.3 Notes for Additional Information

In addition to the data covered in Section 3.2.1 and 3.2.2, any special requirements requested by the customer, licensor, or by FWEC for a specific service should be included in the Notes. Some typical Notes are:

1. Vendor to advise maximum tube wall, fluid bulk, and film temperature of the process and steam superheat (where applicable) coils.

2. Vendor to advise economics of preheating combustion air.

3. Vendor to establish tube design temperature. In coking services, vendor to advise maximum metal temperature allowable during steam-air decoking.

4. Vendor to confirm that steam superheat coil is capable of withstanding zero steam flow during normal process coil operating conditions.

5. Turndown requirements to be specified, or vendor to advise minimum operating rate when no turndown requirements have been specified.

6. Vendor to advise heater pressure drop for both clean and fouled tubes. In coking services, vendor to be given basis for fouled tube pressure drop calculation, such as 1/8" thickness of coke.

7. Vendor to be advised of any soot blower requirements.




8. Vendor to be advised if any very low pressure gas burners are to be provided to burn waste gases. In such cases, the pressure at the burner and the composition of the gases must be given.

9. Vendor to supply estimate of SO2, SO3, NOx (as NO2), CO, hydrocarbons, and particulate matter from stack.

10. Vendor to supply estimate of flue gas acid dewpoint temperature.




PROCESS REQUIREMENTS

Notes:

1. Vendor to advise maximum tube wall, fluid bulk, and film temperature of the process and steam superheat coils.

2. Vendor to advise economics of preheating combustion air. Consideration should be given to the use of heat pipes.

3. Design temperature for heater coil is to be established by heater vendor. The heater vendor shall specify the maximum metal temperature allowable during steam-air decoking.

4. Heater shall be designed for continuous operation at 50% turndown for both Alaskan and Nigerian cases.

5. Vendor to advise heater pressure drop with both clean tubes and with 1/8" coke laydown.

6. Gulf high intensity type (vortometric) burners shall be used. Controlled steam pressure at burners will be 50 psig.

7. Vendor shall make provision for the future addition of steam soot blowers of the multi-jet type for the convection section of this heater.

8. Heater shall be designed to operate for 4 years before requiring decoking.

9. Vendor to confirm that steam superheat coil is capable of withstanding zero steam flow during normal process coil operating conditions.

10. Vendor to supply estimate of flue gas acid dewpoint temperature.




4.0 UTILITIES

4.1 Fuel

4.1.1 Main Burners

The heat fired can be estimated as described in Section 2.12. Fuel gas should have a knockout drum close to the furnace to protect against slugs of liquid in the gas, and the minimum pressure at the burner should be about 30 psig at the maximum firing rate. As discussed in Section 2.13, the fuel oil pressure at the burner should be 60 to 100 psig, with the higher pressure being preferable, and the viscosity should be 125 SSU (26 centistokes) or less, but exceptions are possible with specially designed burners. Also, a circulating system is used with fuel oil. Usually the amount returned (not fired) is 1.5 to 2.0 times the amount fired in fuel oil systems of 100 million BTU/hr or larger. For smaller systems, or for high viscosity fuel, the circulation rate is sometimes higher.

4.1.2 Pilots

If the gas for the pilots is the same as the gas for the main burners, no pilot fuel gas has to be estimated, since the pilots also supply heat to the process. If an independent gas supply is used, however, the quantity needed can be estimated (for utility consumption estimates) by assuming that the pilot heat fired will be 5 percent of the furnace heat fired. Each pilot fires approximately 100,000 BTU/hr and operates with fuel pressures of 2 to 15 psig.

4.2 Steam

4.2.1 Atomizing

As discussed in Section 2.13, liquid fuels must be atomized in order to achieve complete combustion. This is usually done with steam at a pressure about 30 psig higher than the fuel oil pressure. For utility consumption estimates, atomizing steam can be estimated as 0.5 pounds of steam per pound of fuel. For sizing the steam lines, however, 1.0 pound of steam per pound of fuel should be used.




4.2.2 Low Pressure Burners

As discussed in Section 2.13, very low pressure gas can be burned in a special pre-mix burner with steam eductor.

Steam consumption for this type of burner can be estimated as 0.3 pounds per pound of fuel and should be supplied to the burner at a pressure of 30 psig.

4.2.3 Soot Blowers

Furnaces firing a gas fuel or a clean liquid distillate will normally encounter little convection section fouling. Furnaces firing a typical residual fuel will encounter a build-up of soot throughout the entire convection section. Unless the soot is removed, the heat transfer rate is reduced in the convection section and the flue gas pressure drop increases.

The retractable soot blower has been the most successful method of onstream convection section cleaning to date and is specified when firing residual fuels. A high investment cost is required for the retractable system, but in the usual case, the facilities can be justified.

The cleaning medium should be dry saturated steam at a pressure of 250 psig or higher. Although steam pressures as low as 150 psig have been used, the higher pressure is recommended for better cleaning. A steam rate of approximately 10,000 lbs/hr is required for effective cleaning. Since blowers are operated individually in sequence, the maximum steam demand is 10,000 lbs/hr, regardless of the number of blowers. Typical cleaning cycles vary from one to three times a day.

Air can also be used for cleaning, but it is normally not recommended. The maximum air demand would be about 10,000 lbs/hr.

4.2.4 Furnace Box Purging

Each furnace design should include provisions for carrying purging steam to the furnace box. Before igniting the burners of a furnace, the fire box must be purged to remove any fuel gas which may have leaked into the furnace. Otherwise an explosion could occur.




The steam rate must be sufficient to provide 12 changes per hour, and the steam must be distributed throughout the combustion chamber. In order to estimate the steam rate required, the fire box volume can be conservatively estimated by assuming a furnace volumetric heat release of 5,000 BTU/(hr-ft3).

As an example, for a 100 million BTU/hr furnace, the fire box volume would be estimated to be 20,000 ft3. For 12 changes per hour, a steam rate of 240,000 ft3/hr is required. Using 15 psig saturated steam, the specific volume at atmospheric pressure is 28 ft3/lb. The steam rate is then 8,570 lb/hr.

The purging steam control valve should be located a minimum of 50 feet from the furnace.

4.2.5 Header Box Smothering

Generally, smothering steam and condensate drain connections are provided for each header box. Smothering steam is required to the header box when plug headers (fittings with removable plugs for mechanical cleaning) or flanged headers are used. For an estimate of the steam required, a steam rate of 250 lb/hr to each header box can be used.

4.2.6 Emergency Purging of Furnace Coil

Facilities for steam purging the furnace coil in the event of a loss of flow are sometimes specified. This coil purge is used to prevent the high temperature residual heat in the furnace refractory from coking the hydrocarbon remaining in the coil. However, a steam purge has little or no value in services containing light hydrocarbons or mixtures of hydrocarbon and hydrogen. Coil purge steam should never be considered as a substitute for immediately shutting off the fuel upon loss of flow in the coil.

If coil purge steam is specified, a steam rate of 5 lb/(sec-ft2)should be adequate for low pressure systems. This should evacuate the coil in less than 2 minutes. The steam supply pressure must be higher than the downstream system pressure.

4.2.7 Fan Drive

If induced and/or forced draft fans, which are steam driven, are used, the steam consumption for the fans may have to be estimated before the fans are selected by the vendor. The horsepower of the induced draft fan for flue gas and the forced draft fan for air can be estimated from the following equation:




(W)(T)(P)10 x 1.6=HP-7

Where HP = horsepower of fan

W = flue gas or air rate, lb/hr

T = temperature of flue gas or air, 0R

P = Fan !P, inches of water

For fired heaters without air preheat, use the following conditions for a forced draft fan:

Fan !P, P = 7 inches of water

Air temperature, T = 5600R

For fired heaters with air preheat, both an induced draft and a forced draft fan are required. For the forced draft fan, use the following conditions:


Air temperature, T = 5600R

For the induced draft fan, use the following conditions:


Flue gas temperature, T = 9100R

The gross fuel fired can be calculated as outlined in Section 2.12, and the flue gas rate, W, can then be calculated using Chart 14C1.1 of the API Technical Data Book. The pounds of air per hour can then be obtained by subtracting the pounds of fuel fired per hour from the flue gas rate in pounds per hour.

For design, add 20% to the HP determined above. The steam rate for the fan turbine drives can be estimated as described in Process Standard 400-1.1.

4.2.8 Steam-Air Decoking

Steam rates for this service are obtained as described in Section 6.0.




4.3 Refinery Air

4.3.1 Soot Blowers

If an air motor drive is provided for soot blowers, a 3 HP motor is used to drive and rotate each lance, requiring air pressures between 80 and 100 psig and air rates of about 80 SCFM. Air for a motor drive must be dry.

4.3.2 Steam-Air Decoking

Air rates for this service are obtained as described in Section 6.0.

4.4 Electricity

4.4.1 Fans

If induced and/or forced draft fans, which are motor, driven are used, the KW consumption for the fans must be estimated. Fan horsepowers can be estimated as described in Section 4.2.7. The KW consumption for the motor drives can be estimated as described in Process Standard 400-1.1.

4.4.2 Regenerative Air Preheater

A small motor is required to rotate a regenerative preheater such as the Ljungstrom. Motor HP ranges from 1 to 7 depending on size. This type of air preheater is generally used on large units, and if no vendor information is available, the motor HP can be taken as 5, and the KW consumption as 3.5 for utility estimates.

4.4.3 Soot Blowers

If electric drivers are to be provided for soot blowers, a 1.5 HP motor is used, and the KW consumption can be estimated as 0.8.




5.0 INSTRUMENTATION OF FIRED HEATERS

The general guidelines and recommendations for fired heater instrumentation are contained in the FWEC Process Standard 508. Specific customer requirements and the Basis of Design for a specific project must also be followed. In addition, heater instrumentation should be discussed with the instrument engineer and fired heater vendor.




6.0 STEAM-AIR DECOKING

FWEC Department Engineering Practice (DEP) 2241-01 defines the mechanics, operating procedures, and precautions governing the principles of steam-air decoking of process heater tubes. A copy of this DEP is included at the end of this section.

Steam-air decoking refers to the cleaning of fired heater tubes by the action of steam and air. The process is usually divided into two parts, known as "spalling" and "burning".

During spalling, steam only is admitted to the normal coil inlet of the fired heater at fairly high rates while the furnace is fired. Coke is removed by the cooling action of the steam on the hot tubes, causing the coke to contract and break away; by the scouring action of the high velocity steam; and by chemical action, such as the gas reaction, C + H2O = CO + H2. With proper operation, as much as 90 to 95 percent of the coke can be removed by spalling.

During the burning period, both air and steam flow through the coil, and the remaining coke is removed by direct oxidation.

Steam and combustion product effluent is fed to a coke knockout drum. In order to remove coke dust from the vapor effluent, it has been FWEC practice to condense steam and cool the gas with quench water. The gas is cooled to about 10F lower than the boiling point of water. At sea level, this is 200F. The water then carries the coke to the sewer.

The plant sewer and water treatment facilities have to be checked to assure that 200F water can be sent to the sewer. If it cannot, more quench water will have to be used. In the case of excessive water requirements, consideration should be given to quenching only to approximately 5000F and discharging the total vapor to the atmosphere. In this case, only the solid coke is collected in the drum and the drum will have to be made big enough to hold all the coke from the spalling operation. Depending on environmental regulations, it may be necessary to provide a coke separator (such as made by Peerless Manufacturing Co.) For the vapor effluent.

The process engineer is responsible for estimating the steam, air, and quench water requirements for the steam-air decoking operation, as well as for designing the coke knockout drum in which the steam is condensed with quench water. A sample calculation is provided below to be used in conjunction with DEP-2241-01.




6.1 COIL DECOKING SAMPLE CALCULATION

Atmospheric crude unit fired heater

6" SCH 80 low chrome molybdenum steel tubes

1/8" coke laydown tubes (coke density = 90 lb/ft3)

pass heater

One heater pass to be decoked at a time

Steam inlet pressure and temperature = 150 psig and 5000F

Steam outlet pressure and temperature = 20 psig and 1150F (max)

Tube metal temperature is monitored to prevent exceeding 1200F

Quench water inlet temperature = 90F

Determine

A) Spalling steam rate

B) Temperature of effluent steam from spalling operation

C) Water rate to condense all steam from spalling operation and cool condensate to 200F

D) Steam and air rates for coke burning

E) Coke burning rate and effluent from this operation




Solution

A) Spalling Steam Rate

a Use steam mass velocity = 18lb/(sec-ft2)(dep-2241-01)

Section V.A.6.h)

Cross sectional area of 6" SCH 80 tube = 0.1810 ft2

lb/hr,11,729=ft0.1810xhr

3,600xft-

lb18 22

sec

sec

say 12,000 lb/hr spalling steam

b Steam must also be introduced to all tubes not being decoked to prevent overheating. The actual amount of steam required is determined by monitoring tube temperatures during operation. To estimate the steam required, assume it to be 25 percent of the spalling steam rate.

Cooling steam/coil = 12,000 lb/hr x 0.25 = 3,000 lb/hr

c Total steam rate during spalling operation = 12,000 lb/hr + 3 (3,000 lb/hr) = 21,000 lb/hr

B) Temperature of Effluent Steam from Spalling Operation

a Duty to heat steam in each coil not being decoked to the maximum temperature of 1,150F:

3,000 lb/hr x (hg 35 psia/1150F - hg 165 psia/500F)

3,000 lb/hr x (1,612.5 BTU/lb - 1,272.5 BTU/lb) = 1,020,000 BTU/hr per pass

b Outlet temperature of spalling steam assuming heat transferred to coil being decoked is the same as to the other coils:

hg out spalling steam =lb/hr12,000

BTU/hr1,020,000 + 1,272.5 BTU/lb

= 1,357.5 BTU/lb




From steam tables, temperature of 20 psig steam with hg = 1,357.5 Btu/lb is 6490F. Since heat pickup in spalling coil should be greater than that in other coils because of higher steam mass velocity in this coil, add 2000F as design margin. Use outlet temperature of spalling steam = 8500F.

C) Water Rate to Condense All Steam and Cool to 200F

Quench Duty

= 3,000 lb/hr-coil x (3 coils) x (hg 35 psia/1150F - hL 200F)

+ 12,000 lb/hr-coil x (1 coil) x (hg 35 psia/850F - hL 200F)

= 9,000 lb/hr x (1,612.5 Btu/lb - 168.07 Btu/lb)

+ 12,000 lb/hr x (1,457.4 Btu/lb - 168.07 Btu/lb)

= 28.5 Million Btu/hr

Required Quench Water =90)500-(1.0)(200

10x28.56

= 518 GPM

D) Steam and Air Rates for Coke Burning

a From DEP-2241-01, Section V.A.6.m.

1) Steam rate = 4,000 lb/hr

2) Air rate = 400 lb/hr (10% of steam rate)

E) Coke Burning Rate and Effluent from this Operation

a Chemical Reaction for Burning Operation

1) 302 + 4C 2 CO2 + 2CO

Air: 400 lb/hr

O2: 400/29 x 0.21 = 2.90 mols/hr;

2.90 mols/hr x 32 lb/mol = 92.8 lb/hr

CO2: 2.90 X 2/3 = 1.93 mols/hr;


CO: 2.90 x 2/3 = 1.93 mols/hr;





2) 3H2O + 2C CO2 + CO + 3H2

Assume 200 lb/hr of steam reacts (5% of steam)

Steam: 200/18.02 = 11.1 mol/hr

CO2:11.1 x 1/3 x 44 = 162.8 lb/hr

CO: 11.1 x 1/3 x 28 = 103.6 lb/hr

H2: 11.1 x 3/3 x 2 = 22.2 lb/hr

b Burning Operation Material Balance (assume combustion proceeds according to above reactions

Component Lbs/Hr MW Mol/Hr

Steam 3,800 18 211.1

CO2 248 44 5.6

CO 158 28 5.6

H2 22.2 2 11.1

N2 307 28 11.0

Total 4,535 18.6 244.4

Dry Gas 735 22.1 33.3

c Coke Burning Rate

1) Burning rate from the reactions assumed in "a" above:

Coke reacting with oxygen = 2.90 x 4/3 x 12 = 46 lb/hr

Coke reacting with steam = 11.1 x 2/3 x 12 = 89 lb/hr

Total coke reacting rate = 135 lb/hr

Coke burning rate =/hr60

lb/hr135

min = 2.25 lb/min




2) From DEP-2241-01, Section V.A.6.n, the maximum permissible burning rate during decoking is 1.5 ft/min. Using this rate and the coke laydown given, the maximum coke burning rate should be calculated to assure that enough air was used in the assumed reactions to permit the maximum decoking rate. If too little air was used, the effluent rate calculated above will be too low.

Coke per foot of coil length:

ft1x4

xin/ft12

in0.25-in5.761-

in/ft12

in5.761=Vol

22

"

##$

%

&&'

())*

+,,-

.))*

+,,-

.

= 0.0154 ft3/ft

Wt. = 90 lb/ft3 x 0.0154 ft3/ft = 1.4 lb/ft

Maximum permissible coke burning rate

= 1.4 lb/ft x 1.5 ft/min = 2.1 lbs/min

Since the maximum burning rate is less than the rate obtained from the oxidation reactions assumed, even with no coke removed by spalling, the effluent rates calculated are satisfactory for design. If the maximum burning rate calculated were higher than the rate obtained from the oxidation reactions, a higher air rate would have to be assumed, and the calculations repeated to obtain a conservative effluent rate for the coke knockout drum design.

6.2 COKE KNOCKOUT DRUM SAMPLE CALCULATION GIVEN

/ Information from Section 6.1.

/ Water pressure available at quench nozzles is 65 psig.

Determine

/ Dimensions of coke knockout drum and spray nozzles required. (Drum sketch shown at end of Section 6.2.)




Solution

Process Std 306

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