Process Std 306

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PROCESS STD 306 PAGE Contents- 2 REV 10 DATE JULY 2002

HEAT TRANSFER HEATERS/FURNACES

PROCESS PROCESS PLANTS DIVISION DIVISION

CONTENTS

4.3

4.4

PAGE

4.2.4 Furnace Box Purging 4.2.5 Header Box Smothering 4.2.6 Emergency Purging of Furnace Coil 4.2.7 Fan Drive 4.2.8 Steam-Air Decoking Refinery Air 4.3.1 Soot Blowers 4.3.2 Steam-Air Decoking Electricity 4.4.1 Fans 4.4.2 Regenerative Air Preheater 4.4.3 Soot Blowers

4.0-2 4.0-3 4.0-3 4.0-4 4.0-5 4.0-5 4.0-5 4.0-5 4.0-5 4.0-5 4.0-5 4.0-5

5.0

INSTRUMENTATION

5.0-1

6.0

STEAM-AIR DECOKING

6.0-1

6.1 6.2

6.0-2 6.0-6

7.0

Coil Decoking Sample Calculation Coke Knockout Drum Sample Calculation

STACK DESIGN

7.0-1

7.1 7.2 7.3 7.4

7.0-1 7.0-1 7.0-2 7.0-6

Type of Stacks Stack Diameter Stack Height Stack Design Sample Calculation

APPENDIX APPENDIX Steam Air Decoking

A-1

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CONTENTS

4.3

4.4

PAGE

4.2.4 Furnace Box Purging 4.2.5 Header Box Smothering 4.2.6 Emergency Purging of Furnace Coil 4.2.7 Fan Drive 4.2.8 Steam-Air Decoking Refinery Air 4.3.1 Soot Blowers 4.3.2 Steam-Air Decoking Electricity 4.4.1 Fans 4.4.2 Regenerative Air Preheater 4.4.3 Soot Blowers

4.0-2 4.0-3 4.0-3 4.0-4 4.0-5 4.0-5 4.0-5 4.0-5 4.0-5 4.0-5 4.0-5 4.0-5

5.0

INSTRUMENTATION

5.0-1

6.0

STEAM-AIR DECOKING

6.0-1

6.1 6.2

6.0-2 6.0-6

7.0

Coil Decoking Sample Calculation Coke Knockout Drum Sample Calculation

STACK DESIGN

7.0-1

7.1 7.2 7.3 7.4

7.0-1 7.0-1 7.0-2 7.0-6

Type of Stacks Stack Diameter Stack Height Stack Design Sample Calculation

APPENDIX APPENDIX Steam Air Decoking

A-1


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LIST OF FIGURE’S

FIGURE DESCRIPTION

PAGE

FIGURE 1 – VERTICAL-CYLINDRICAL FIRED HEATER, ALL RADIANT

1.0-8

FIGURE 2 – VERTICAL-CYLINDRICAL FIRED HEATER 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 THRU H20 BASED ON o WATER AT 70 F LIST OF TABLE’S TABLE 1 –

TABLE DESCRIPTION

6.0-16 PAGE

TYPICAL VALUES OF AVERAGE RADIANT HEAT FLUW AND COIL COIL MASS VELOCITIES 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


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PROCESS PLANTS DIVISION

1.0


PROCESS STD 306 PAGE 1.0- 1 REV 10 DATE JULY 2002

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. FOSTER WHEELER ENERGY LIMITED 2002

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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 180 0 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 FOSTER WHEELER ENERGY LIMITED 2002

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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 The ratio of heat absorbed to the heat fired. The lower Efficiency 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


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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-ft 2). It is also called "heat density", "heat transfer rate", "flux density

Higher Heating The theoretical heat of combustion of a fuel, beginning Value (HHV) and ending at 60 0F, 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 The theoretical heat of combustion of a fuel, beginning Value (LHV) and ending at 60 0F, 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-ft 2).


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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


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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. FOSTER WHEELER ENERGY LIMITED 2002

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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.


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PROCESS STD 306 PAGE 1.0-10 REV 10 DATE JULY 2002


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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 0 API, 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.


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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-ft 2) for most process fired heaters in allliquid or vaporizing services where coking or fouling can occur. Under turndown conditions, mass velocity should be kept above 150 lb/(sec-ft 2) 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.


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This practice usually requires reducing the design mass velocity in the heater outlet tubes to about 80 to 120 lb/(sec-ft 2), and no lower than bout 60 lb/(sec-ft 2) 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-ft 2). High mass velocities, such as those used in vaporizing services, would cause very high pressure drops in allvapor 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.


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PROCESS PLANTS DIVISION 

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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. Nonstandard 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 FOSTER WHEELER ENERGY LIMITED 2002

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Solution Recommended Mass Velocity (Table 1) = 250-350 lb/(sec-ft 2) Tube Size IPS

6 inch

5 inch

Cross Sectional Flow Area, ft 2 0.2006

0.1390

No. of Passes

Mass Velocity lb (sec-ft2)

6

392

8

294

10

235

8

425

10

340

12

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.


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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.


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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 requi re 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.


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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 150°F. Stack temperatures usually range from 350-700°F. The 350°F 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 250-300°F). 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 (SO 2), and part of the sulfur dioxide is converted to sulfur trioxide (SO 3) 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 300°F) 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. FOSTER WHEELER ENERGY LIMITED 2002

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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: 1,000 T DP

= 1.7842 + 0.0269 log10 P H 2O - 0.1029 log10 P SO3 + 0.0329 log10 P H 2O log10 P SO3

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: E LHV =

Heat Absorbed Heat Fired (LHV)

x 100


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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 150°F 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: Heat Absorbed: Fuel:

450 oF 350 million BTU/hr 15o API fuel oil LHV = 17,500 BTU/lb

Burners

Combination Gas/Oil - Natural Draft

Solution a)

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

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 600°F flue gas temperature and 20% excess air = 15,100 BTU/lb of fuel FOSTER WHEELER ENERGY LIMITED 2002

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350 Million BTU/hr

d)

Net Fuel Fired =

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 =

15,100 BTU/lb

= 23,180 lb/hr

350 Million BTU/hr 410 Million BTU/hr

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. FOSTER WHEELER ENERGY LIMITED 2002

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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.


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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 350 0F 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 250 0F. 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 NO x level in the flue gas, and if air pollution regulations would be violated, some form of NO x control would have to be added. The fired heater vendor will have to consider the cost of any such NO x 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. FOSTER WHEELER ENERGY LIMITED 2002

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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.


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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 SO 2 to SO3.


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Sulfur is generally the principal corrosive constituent of the process fluid. For hydrocarbon streams containing H 2S 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.


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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 fir ed 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, 1210, 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.


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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.


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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. Allradiant 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. FOSTER WHEELER ENERGY LIMITED 2002

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3.2.3


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.

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.


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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 SO 2, SO3, NOx (as NO2), CO, hydrocarbons, and particulate matter from stack.

10.

Vendor to supply estimate of flue gas acid dewpoint temperature.


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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.


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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.


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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.


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The steam rate must be sufficient suffici ent 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-ft 3). As an example, example, for a 100 million BTU/hr furnace, the fire box volume would be estimated to be 20,000 ft 3. For 12 changes per hour, a steam rate of 240,000 ft 3/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 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-ft 2) 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: FOSTER WHEELER ENERGY LIMITED 2002

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

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, temperature, T = 560 0R 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: Fan P, P = 11 inches of water Air temperature, temperature, T = 560 0R For the induced draft fan, use the following conditions: Fan P, P = 6 inches of water Flue gas temperature, T = 910 0R The gross fuel fired can be calculated calculat ed 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.


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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 rates for this service are obtained as described 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 small motor is required required to rotate rotate a regenerative regenerative preheater preheater such such as the Ljungst Ljungstrom. rom. Motor Motor HP HP range ranges s from from 1• •to •to 7• 7• •depe •dependin nding g on size. This type of air preheater is generally 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 estim ated as 0.8.


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5.0


INSTRUMENTATION OF FIRED HEATERS The general guidelines and recommendations for fired heater instrumentat ion 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.


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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 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 veloci ty steam; and by chemical action, such as the gas reaction, C + H 2O = CO + H 2. 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 10°F lower than the boiling point of water. At sea level, this is 200°F. The water then carries the coke to the sewer. The plant sewer and water treatment facilities have to be checked to assure that 200°F 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 500 0F 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 pr ovided below to be used in conjunction with DEP-2241-01.


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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/ft 3)



pass heater



One heater pass to be decoked at a time



Steam inlet pressure and temperature = 150 psig and 500 0F



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



Tube metal temperature is monitored to prevent exceeding 1200°F



Quench water inlet temperature = 90°F

Determine A)

Spalling Spalling steam rate rate

B)

Temperature of effluent steam from spalling operation

C)

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

D)

Steam and air rates for coke burning

E)

Coke burning rate and effluent from this operation


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Solution A)

Spalling Spalling Steam Rate Rate a

Use steam mass velocity = 18lb/(sec-ft 2)(dep-2241-01) Section V.A.6.h) Cross sectional area of 6" SCH 80 tube = 0.1810 ft 2 18 lb 2

sec- ft

x 3,600

sec

hr

2

x 0.1810 ft = 11,729 lb/hr,

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, 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 B)

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

Temperature of Effluent Steam from Spalling Operation a

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

3,000 lb/hr x (h g 35 psia/1150°F - hg 165 psia/500°F) 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 spalling steam assuming assuming heat transferred transferred to coil being decoked is the same as to the other coils: hg out spalling steam =

1,020,000 BTU/hr 12,000 lb/hr

+ 1,272.5 BTU/lb

= 1,357.5 BTU/lb


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From steam tables, temperature of 20 psig steam with h g = 1,357.5 Btu/lb is 649 0F. Since heat pickup in spalling coil should be greater than that in other coils because of higher steam mass velocity in this coil, add 200 0F as design margin. Use outlet temperature of spalling steam = 850 0F. C)

Water Rate to Condense All Steam and Cool to 200°F Quench Duty = 3,000 lb/hr-coil x (3 coils) x (h g 35 psia/1150°F - hL 200°F) + 12,000 lb/hr-coil x (1 coil) x (h g 35 psia/850°F - hL 200°F) = 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 =

D)

(1.0)(200 - 90)500

= 518 GPM

Steam and Air Rates for Coke Burning a

E)

28.5 x 106

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)

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; 1.93 mols/hr x 44 lb/mol = 84.9 lb/hr CO:

2.90 x 2/3 = 1.93 mols/hr; FOSTER WHEELER ENERGY LIMITED 2002

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WHEELER


1.93 mols/hr x 28 lb/mol = 54.0 lb/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

4,535

18.6

244.4

735

22.1

33.3

Total Dry Gas 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 =

135 lb/hr 60 min /hr

= 2.25 lb/min


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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:

  5.761 in 2  5.761 in - 0.25 in 2    -    x x 1 ft Vol =   12 in/ft 12 in/ft       4 = 0.0154 ft3/ft Wt. = 90 lb/ft3 x 0.0154 ft 3/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.)


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Solution A-

Drum Diameter

a) Vapor leaving drum: 1)

Dry gas = 33.3 mols/hr (Section 6.1.E.b)

2)

Water vapor to saturate gas @ 200 0F and 14.7 psia = 33.3 x

11.53 (14.7 - 11.53)

= 121.1 mols/hr

where 11.53 = vapor pressure of water at 200 0F, psia 3)

Total vapor is as follows: Component

lbs/Hr

MW

Mol/hr

735

22.1

33.3

Water Vapor

2,182

18.02

121.1

Total

2,917

18.9

154.4

Dry Gas

The drum diameter is sized on the basis of an allowable vapor velocity obtained by using a Souders-Brown coefficient of 0.15. V a = 0.15

 L

-1

 v

where Va = allowable vapor velocity, ft/sec

L = liquid density, lb/ft 3 v = vapor density, lb/ft 3 MW x P 18.9 x 14.7 3 = = 0.0392 lb/ ft R x T 10.731 x 660

4)

 v =

5)

Vapor flow =

6)

L = 60.11 lb/ft 3 (H2O @ 2000F)

7)

Va = 0.15

2,917 lb/hr 3

0.0392 lb/ ft x 3,600 sec /hr

60.11 0.0392

= 20.7 ft 3/sec

- 1 = 5.87 ft/ sec FOSTER WHEELER ENERGY LIMITED 2002

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8)

Drum cross-sectional area required 3

=

20.7 ft / sec 5.87 ft/ sec

2

= 3.53 ft

9) Drum diameter =

(4)(3.53)

= 2.12 ft



b)

Vapor entering drum: 1)

Maximum vapor rate is during spalling operation. Steam rate = 21,000 lb/hr (Section 6.1.A.c)

2)

Enthalpy of entering steam (Section 6.1C): h steam =

(9,000)(1, 612.5) + (12,000)(1 ,457.4) 21,000

= 1,523.9 Btu/lb 3)

With pressure of 15 psia: (from steam tables) Steam temperature = 980 0F

v = 0.0175 lb/ft 3 L = 60.11 lb/ft 3 (H2O @ 2000F) 4)

Vapor flow =

21,000 lb/hr

= 3 0.0175 lb/ ft x 3,600 sec /hr

= 333.3 ft3/sec 5)

For entering superheated steam, use a Souders-Brown coefficient of 0.6 to determine the allowable vapor velocity. Va = (0.6)

6) c)

60.11 0.0175

Drum diameter =

- 1 = 35.16 ft/ sec

(333.3)(4) 35.16)(  )

= 3.47 ft

The entering vapor rate controls. Use a 3'-6" diameter drum (a minimum diameter of 3'-0" should be used for coke knockout drums). FOSTER WHEELER ENERGY LIMITED 2002

FOSTER

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WHEELER


B-


Spray Nozzles a

Two relatively large capacity spray nozzles are used to supply quench for the cooling and condensing loads. It has been determined that the most efficient dust removal occurs when the spray droplet mean diameter is in the range of 500 to 1,000 microns (Industrial Gas Cleaning, W. Strauss, 2nd Edition, page 369). Since the relatively large quench nozzles for cooling and condensing produce larger diameter droplets, a cluster of smaller nozzles are installed above the two main nozzles in order to improve dust removal efficiency. For this service, a minimum of 10 gallons of water per 1,000 actual cubic feet of vapor leaving the drum should be used. The higher the pressure drop across the spray nozzles, the smaller will be the droplet size. Therefore, the maximum pressure available should be used for the spray nozzles. Nozzle data for full cone nozzles, from Spraying Systems Co., can be obtained from Tables 2, 3, and 4, and Figure 8.

b

Use as many Spraying Systems Co. ¾" - 7G1.5 nozzles, or equivalent, as required to give a water rate of approximately 10 gallons per 1,000 cubic feet of vapor leaving: 1)

Vapor flow = 20.7 ft 3/sec x 60 sec/min = 1,242 CFM (Section 6.2.A.a(5))

2)

Water flow =

3)

Number of 7G1.5 nozzles required =

1,242 CFM 1,000 CFM

12.4 GPM 2.5 GPM/nozzle

x 10 GPM = 12.4 GPM

= 5 (Table 4)

c

Quench water required = 518 GPM (Section 6.1C)

d

Nozzles required for cooling and condensing: 1) 2)

(518 GPM - 12.4 GPM) = 253 GPM/nozzle 2 nozzles

Use two 3H90 nozzles from Spraying Systems Co., or equivalent (Table 3). FOSTER WHEELER ENERGY LIMITED 2002

FOSTER

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WHEELER


C-

Drum Height a

Provide a height of 3 feet above the top spray to the upper tangent line.

b

Provide a height of 3 feet between the top spray nozzle and the upper cooling and condensing nozzle.

c

Calculate the spacing between the two cooling and condensing nozzles and between the vapor inlet and lower nozzle based on the drum diameter and the spray angle of the nozzle chosen.

1)

Spray angle = 80 0 (Table 3)

2)

Drum diameter = 3'-6" (Section 6.2.A.c)

3)

Spacing = S =

1.75 ft tan 40

= 2.1 ft, say 2'-6"


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4)

d) e) D-


Experience has shown that the heat transfer coefficient for condensing steam by direct contact with water is very high, and that the volume obtained by this calculation method will be adequate to condense the steam.

Provide 2 ft from the vapor inlet nozzle to the liquid level (maintained by seal leg). Provide 2 ft from liquid level to lower tangent line for seal.

Furnace Coil Effluent Line Quench Although the coke knockout drum is designed as described above, a water quench nozzle should be installed in the coke knockout drum header system, immediately downstream of the furnace coil effluent connection, to reduce the downstream temperature and velocity. A straight run pipe length of 12 to 15 feet should be provided downstream of the quench nozzle. The decoking effluent lines should be sized to limit the velocity to a maximum of 600 ft/sec to avoid severe erosion. Enough line quench should be added to desuperheat the steam, and the quantity of water vaporized should be included in line size calculations. Operating instructions, if any, should make a point of requiring the use of the line quench, and the engineering flow diagram should contain the following note next to the inline quench valve: "Wash water to be put into service only when line is cold prior to initiating steam air decoking procedure."


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7.0


STACK DESIGN The process engineer does not normally design the furnace stack, but only provides special requirements, such as a minimum height, in the process specification. Occasionally, however, the process engineer may have to estimate a stack size for a cost estimate. 7.1

Type of Stacks Stacks may be mounted on top of the furnace itself or may be placed on the ground beside the furnace. Ground-supported stacks are often used to serve several furnaces. Stacks are usually made of steel or concrete; below a height of 250 feet they are usually made of steel. Furnace-supported stacks are always made of steel. In order to assure good flue gas distribution throughout the convection section, it is usual for a flue gas withdrawal opening to be provided for each 40 feet of convection section length. Multiple furnace-supported stacks may be used, or the take-offs may be ducted to a common stack, which can be either furnace-supported or ground-supported.

7.2

Stack Diameter The stack diameter can be estimated using an inlet flue gas velocity of 25 ft/sec. (When relatively high stacks are required because of environmental requirements, higher stack gas velocities may be used because the extra draft generated can overcome the higher pressure drop. Higher velocities may also be required for pollution control considerations.) The gross fuel fired can be calculated as outlined in Section 2.12, and the flue gas quantity can be obtained using Chart 14C1.1 of the API Technical Data Book. The molecular weight of the flue gas can be assumed to be the same as that of air, and the flue gas density can be calculated from the following equation.  g =

39.5 Tg

where g = flue gas density @ sea level, lb/ft 3 Tg = flue gas temperature, 0R To correct density for altitude, the value obtained from the above equation should be multiplied by a factor obtained from the following table: FOSTER WHEELER ENERGY LIMITED 2002

FOSTER

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WHEELER



Elevation, ft.

Correction Factor

0

1.000

1,000

0.965

2,000

0.930

3,000

0.896

4,000

0.863

5,000

0.831

6,000

0.800

7,000

0.770

8,000

0.742

9,000

0.714

10,000

0.686

The temperature of the flue gas to the stack can be estimated as discussed in Section 2.10. 7.3

Stack Height The main function of a stack is to produce draft sufficient to overcome all obstructions to the flow of flue gas and maintain a negative pressure throughout the furnace. Sometimes stacks are made taller than required to produce the necessary draft because of pollution control requirements. The actual draft required cannot be calculated accurately before the furnace configuration has been determined. If a minimum stack height of say 200 feet is specified because of pollution control, this height will normally be more than adequate to provide the required draft, but this should be confirmed. Previous designs of similar furnaces may be checked. When the furnace design is known or can be estimated, the minimum stack height can be calculated by balancing the pressure gains and losses to produce a negative pressure of 0.10 inches of water at the top of the radiant section. The following pressure losses and gains, in inches of water, should be included in the system pressure balance:


FOSTER

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1 Stack Exit Loss Use 1 velocity head  P =

(0.0030)( G g )

2

 g

Where

P

=

one velocity head, inches of water

Gg

=

Flue gas mass velocity, lb/(sec-ft 2)

g

=

flue gas density, lb/ft 3

The flue gas temperature leaving the stack is lower than at the inlet because of heat loss through the stack. The magnitude of the differential depends on several factors, including the type of stack, stack dimensions, and the insulation. The approximate temperature drop through stacks can be obtained from a chart published by Babcock & Wilcox in their book "Steam". The chart can be represented by the following equation: Texit = Tinlet (1 - 0.11 X) + 19 X Where

Texit

=

Stack exit gas temperature, 0F

Tinlet

=

Stack inlet gas temperature, 0F

X

=

(3.7134 - 0.10484 D) (H/100) + (0.02098D - 0.6576) (H/100) 2

D

=

Stack diameter, ft

H

=

Stack height, ft

The equation is limited to the following ranges: Stack heights:

0-300 ft

Stack diameters:

2-24 ft

Inlet gas temperatures:

250-900 0F

Do not use the above equation with stack heights greater than 300ft


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2

Loss Across Damper For damper wide open, use P = 1.5 velocity heads.

3

Losses in Ducts The pressure losses through the ducting connecting the convection section and the stack are obtained by standard fluid flow calculation procedures. The pressure drops in psi are converted to inches of water by multiplying by 27.7. For calculating the pressure drop in a duct of rectangular crosssection, it is necessary to use an equivalent hydraulic diameter in the equations intended for pipe. The hydraulic diameter is four times the hydraulic radius, and the hydraulic radius is defined as the conduit cross sectional area divided by its wetted perimeter. For rectangular ducts: De =

2a b a+b

Where

De

=

equivalent hydraulic diameter, ft

a

depth of duct, ft.

b

width of duct, ft.

In determining the friction factor, f, for use in the pressure drop equation, use a surface roughness factor, , of 0.0027 ft for internally insulated steel ducts. Depending on the ducting and stack arrangement, other pressure drops will result from sudden expansions and contractions, bends, and the combining of flue gas streams. 4

Stack Entrance Loss Use 1 velocity head at the stack entrance to account for a sudden contraction plus a change in direction.

5

Loss Through Convection Section Estimate the pressure drop as 0.5 velocity heads per row of tubes. The mass velocity should be based on the free flow area at the tube row centerline. For extended surface tubes, the free flow area should be based on bare tubes of diameter equal to the extreme diameter of extended surface. No credit is taken for the free area between individual studs or fins on a tube. FOSTER WHEELER ENERGY LIMITED 2002

FOSTER

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WHEELER


6


Negative Pressure at Top of Radiant Section Use P = 0.10 inches of water

7

Stack Effect There is a pressure gain in the convection section due to a stack effect which must be subtracted from the above pressure drop in order to obtain the net stack effect required. The following equation should be used to calculate this pressure gain:

 1 1  PSE = (0.52) (L) (P)  -   T a T g  Where

PSE

=

Stack effect, inches of water

L

=

Height of stack, ft

P

=

Atmospheric pressure, psia

Ta

=

Summer design air temperature, 0R

Tg

=

Average flue gas temperature, 0R

The net stack effect per foot is obtained by subtracting the stack pressure drop per foot from the stack effect per foot. The stack effect is obtained from the same equation used for the convection section stack effect, and the stack pressure drop is obtained by standard fluid flow calculation procedures. The stack average flue gas temperature is used in both cases. In determining the friction factor, f, for use in the pressure drop equation, use a surface roughness factor, , of 0.0027 ft for internally insulated steel stacks and for concrete stacks. 8

Calculated Stack Height The stack height is obtained by dividing the net stack effect required by the net stack effect per foot and multiplying by a safety factor of 1.05.

7.4

Stack Design Sample Calculation Given

 Atmospheric Crude Unit Fired Heater 

Gross Fuel Fired = 23,410 lb/hr of 15 0 API fuel oil



Percent Excess Air = 20 FOSTER WHEELER ENERGY LIMITED 2002

FOSTER

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WHEELER

PROCESS PLANTS DIVISION 

Temperature of Flue Gas to Convection Section = 1600°F



Temperature of Flue Gas Leaving Convection Section = 600°F



Convection Section



1)

4 rows of bare tubes with flue gas mass velocity = 0.35 lb/(secft2) and average temperature = 1500°F

2)

2 rows of studded tubes with flue gas mass velocity = 0.50 lb/(sec-ft 2) and average temperature = 1250°F

3)

5 rows of studded tubes with flue gas mass velocity = 1.05 lb/(sec-ft 2) and average temperature = 850°F

4)

height = 11 ft and length = 65 ft

Design Air Temperature = 90°F

Determine Furnace mounted stack diameter and height required for draft. Solution Since convection section is 65 feet long, assume 2 stacks will be used. A

Stack Diameter a

From fuel fired with 20% excess air and Figure 14C1.1 from the API Technical Data Book, the flue gas rate is calculated. W = 23,410 x 17.7 = 414,360 lb/hr  g =

39.5 T g

=

39.5 (600 + 460)

= 0.0373 lb/ft 3 (Section 7.2)

Volumetric Flow Rate = b

414,360 (0.0373)(3 ,600)

= 3,086 ft 3/sec

Using a flue gas velocity of 25 ft/sec, calculate stack diameter required. Area per stack =

3,086 (25)(2 stacks)

= 61.7 ft 2


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WHEELER


(4)(61.7)

Diameter of each stack =

= 8.86 ft, say 9'-0"



B)

Stack Height a

Estimate stack exit gas temperature from equation given in Section 7.3(1). Assume a stack height of 100 ft. X

=

(3.7134 - 0.10484D) (H/100) + (0.02098D - 0.6576) (H/100) 2

X

=

(3.7134 - 0.10484 x 9.0) (100/100) + (0.02098 x 9.0 - 0.6576) (100/100) 2 = 2.301

Texit =

Tinlet (1 - 0.11 X) + 19 X

Texit =

600 (1 - 0.11 X 2.301) + (19) (2.301)

= b

492°F say 490°F

Pressure Balance (as per Section 7.3) 1)

Stack Exit Loss (0.0030)( G g )

P =

2

 g

414,360 = 0.9046 lb/(sec-ft 2) (  ) 2 (3,600) (9.0 ) (2 stacks) 4

Gg =

g =

39.5 (490 + 460)

= 0.0416 lb/ft3 2

P = 2)

(0.0030) (0.9046 ) 0.0416

= 0.059 inches water

Loss across damper

g

=

0.0373 (Section 7.4 A.a) 2

1 velocity head =

P

=

(0.0030) (0.9046 ) 0.0373


1.5 velocity heads = (1.5) (0.066) FOSTER WHEELER ENERGY LIMITED 2002

FOSTER





WHEELER


= 3)

0.099 inches water

Losses in ducts None for this case.

4)

Stack entrance loss

P = 1 velocity head = 0.066 inches water 5)

Loss through convection section Through 4 rows of bare tubes

g =

39.5 (1,500 + 460)

= 0.0202 lb/ft 3 2

1 velocity head =

(0.0030) (0.35 ) 0.0202


P = (0.5) (0.018) (4 rows) = 0.036 inches water Through 2 rows of studded tubes

g =

39.5 (1,250 + 460)

= 0.0231 lb/ft 3 2

1 velocity head =

(0.0030) (0.50 ) 0.0231


P = (0.5) (0.032) (2 rows) = 0.032 inches water Through 5 rows of studded tubes

g =

39.5 (850 + 460)

= 0.032 lb/ft 3 2

1 velocity head =

(0.0030) (1.05 ) 0.0302


P = (0.5) (0.110) (5 rows) = 0.275 inches water Total convection section loss

P = 0.036 + 0.032 + 0.275 = 0.343 inches water FOSTER WHEELER ENERGY LIMITED 2002

FOSTER

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WHEELER


6)

Negative pressure at top of radiant section Set P = 0.10 inches water

7)

Stack effect in convection section Tg =

1,600 + 600 2

= 11000F

 1 1  PSE = (0.52) (L) (P)  -   T a T g    1 1  (90 + 460) - 1,100 + 460)   

= (0.52) (11) (14.7) = 0.099 inches water 8)

Net stack effect required

P = 0.059 + 0.099 + 0.066 + 0.343 + 0.100 - 0.099 = 0.568 inches water 9)

Net stack effect per foot of stack Tg =

600 + 490 2

= 5450F

  1 1 PSE = (0.52) (1) (14.7)    (90 + 460) (545 + 460)  = 0.00629 inches water/ft

Pf = Where

f L  g V 2 2,316 D

PSE

=

Stack effect, inches of water

Pf

=

Frictional pressure drop, psi

L

=

Stack height, ft

g

=

Average flue gas density, lb/ft 3

V

=

Flue gas velocity, ft/sec

D

=

Stack diameter, ft FOSTER WHEELER ENERGY LIMITED 2002

FOSTER

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WHEELER


F

=

Re = 1,488

Fanning friction factor

DV  g 

Where

Re

=

D,V,

g =

 g =  @

39.5 T g

=

Reynolds number As above

= 39.5

(545 + 460)

Flue gas viscosity, cp

= 0.0393 lb/ft 3

545°F = 0.0275 cp

(Use curve for nitrogen or carbon dioxide, whichever gives higher viscosity at given temperature from Figure 11C1.2 of API Technical Data Book or, if available, use chart on page 191 of "Data Book on Hydrocarbons" by J. B. Maxwell.) Stack cross-sectional area = A

 D

2

4

2

=

 (9.0 )

4

V

=

= 6.36 ft 2 414,360 lb/hr 3

2

(2 stacks)(3 ,600 sec /hr)(0.0393 lb/ ft )(63.6 ft )

= 23.0 ft/sec Re

= 1,488

(9.0) (23.0) (0.0393) 0.0275

= 440,180 Using



D

=

0.0027 9.0

= 0.0003 (assuming lined stack)

From Fanning friction factor chart, f = 0.004 2

Pf =

(0.004) (1) (0.0393) (23.0 ) (2,316) (9.0)

= 4.0 x 10 -6 psi/ft


FOSTER

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WHEELER


(4.0 x 10 -6 psi/ft) (27.7 in water/psi) = 0.00011 inches water/ft Net stack effect = 0.00629 - 0.00011 = 0.00618 inches water/ft 10) Calculated stack height required for draft H=

0.568 0.00618

(1.05) = 97

say 100 feet above convection section.


FOSTER



WHEELER



PROCESS STD 306 PAGE A-1 REV 10 DATE JULY 2002

APPENDIX STEAM AIR DECOKING I

SCOPE This DEP shall define the mechanics, operating procedures, and precautions Governing the principles of Steam-Air Decoking of process heater tubes.

II

DEFINITION Steam-air decoking is the art of removal of coke deposited inside heater tubes by spalling and/or burning, utilizing steam and air as agents.

III

MECHANICS OF STEAM-AIR DECOKING The mechanics of steam-air decoking for heater tubes are: a)

Contraction of the tubes due to cooling will cause the coke deposits within the tube to crack and spall. Reduction of the number of burners being fired and the introduction of steam will speed this action. Steam injection in addition to accelerating spalling will remove loose coke from the tubes.

b)

It is of utmost importance that steam be injected into the tubes not being decoked to prevent damage to these tubes.

c)

Injection of steam into the tubes is a chemical reaction3 H 2O  2C  CO2

 CO  3H 2

The oxygen in the air also generates a chemical reaction with the heated coke- 3O2  4C  2CO2  2CO IV

GENERAL a)

Steam-air decoking is less expensive and more efficient than mechanical decoking, however it is a more critical operation in that heater tubes can be damaged at elevated temperatures if operations are not properly conducted.

b)

The decoking operation normally requires the services of two men. Their functions are: 1.

One man will be required to check continuously the coke burning rate by observing the metal temperature of the tubes.

2.

The second man will be required to for control of the steam-air rates FOSTER WHEELER ENERGY LIMITED 2002

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and for the checking of the effluent samples from the tubes. c)

This type of operation lends itself to being conducted at might since the glow of the tubes can be observed more easily during the coke burning operation. The use of an optical pyrometer is recommended.

d)

The metal content of the tubes governs the controlling temperature at which the operation shall be conducted. Coke will burn at temperatures between 10500F to 1350 0F. The tube metal temperatures recommended below are approximate and the manufacturer must advise the maximum temperature the tubes supplied can withstand.

e)

The time required for completion of the decoking operation can vary from six hours to three days, dependent upon the thickness of coke deposits and/or the detailed procedures to be followed.

f)

A schematic piping diagram showing piping manifolds for the injection of steam, air, and water is shown on page 11.

g)

The steam-air decoking should not be used where tube deposits contain a large proportion of salt or lime. This is apt to occur in topping or other crude processing unit when the crude has not been desalted.

h)

Steam(150 psig), water, and air (50psig), are to be manifolded to permit simultaneous and/or alternate injection into the hot tubes. Steam and air are used to accelerate coke spalling and burning, whereas, water is injected into the tubes after completion of spalling and burning. Water washing of the tubes for ash removal shall be done only after t he tube metal temperatures have cooled to 500 0F.

i)

The total tube length to be decoked in a single operation is of major importance in securing a satisfactory operation. Using 150 pound steam, and assuming five (5 pounds pressure drop per hundred (100’-0”) feet permits 3000 equivalent feet of tubing to be decoked in one operation. The tube arrangement in heaters in delayed coker and visbreaker service is usually two-pass and in crude units, four pass. These passes may be joined together by means of a jump over to develop a series flow.

i)

The length of time between decoking operations is dependent upon a number of variables such as flow rates, operating temperatures, pressure drop, properties of fluids and operating procedures. Pressure drop through the heater is the operator’s best indication of when decoking is required.


FOSTER

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V


OPERATING PROCEDURES Three operating procedures are outlined herein. The procedure to be used is dictated by the tubing materials and functions of the heater. a)

Case I Low Chrome Molybdenum Steels 1.

Case I is applicable to heaters equipped with low chromemolybdenum tubes, normally in crude unit, delayed coker, and Visbreaker service.

2.

A pressure drop increase of 20 to 30 psig through the tubes during operation is an indication that decoking is required.

3.

Tube temperatures must be carefully controlled since the materials in this category cannot withstand, without damage, temperatures greater than 1200 oF for extended periods.

4.

Steam and effluent should not be vented to the stack of the heater since carbon may precipitate out and form undesirable deposits on outer surfaces of tubes in the top of the heater. Since CO, CO 2 , and H2 are formed during decoking, the vapors should be vented through a portable stack or other equivalent means and discharged to atmosphere at least 10 feet above grade.

5.

It is desirable to remove as much coke as possible by spalling action in the tubes prior to removal of the remaining coke by burning.

Sequential Operation a)

The piping connections for steam, air and water are connected to the pass or passes of tubes. See typical Piping Detail for Steam-Air Decoking page 11, this standard.

b)

The feed to the heaters is shut off and the burners extinguished.

c)

Steam is introduced to the tubes to purge the lines of residual oil and oil vapors. The steam purge is a precautionary measure to prevent the ignition of a flammable mixture of air and oil vapors.

d)

When the purge is complete, drains are opened and the heater is taken out of service. Jump overs are installed where required (See paragraph IV-1 General). Figure eight blinds are put in place. Swing elbows are rotated. Steam is introduced to all tubes (even those tubes not being decoked) to prevent overheating. Quench water to the sample connections and drain is turned on.

e)

Every other burner is ignited to provide an even distribution of heat. FOSTER WHEELER ENERGY LIMITED 2002

FOSTER

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f)

Increase flue gas temperatures leaving the radiant section at the rate of 3000F/hr. until it reaches 1350 0F. Hold this flue gas temperature though the spalling period or until air is introduced.

g)

The furnace temperature shall be increased at the rate of 300 0F per hour with a close check being made on tube metal temperature. The metal temperature is not to exceed 1200 OF. Steam injection shall be used to regulate metal temperatures of the tubes during the controlled heating period in the heater. Skin thermocouples on the tubes, if installed, and flue gas outlet thermocouples are to be used in verifying and controlling tube and gas temperatures during the decoking operations. Excessive use of steam can cause severe erosion in the tubes and fittings during spalling since the coke is very abrasive. Steam velocity is to be as low as possible while still removing the coke from the tubes.

h)

When the flue gas outlet temperature reaches 1000 0F, increase steam injection to the equivalent of a mass velocity of 18 pounds per square foot per second. The approximate steam flows for a mass velocity of 18 pounds per square foot per second are: Tube I.D., Inches

i)

Steam Flow, lbs/Hour

2

1,200

2.5

1,900

3

2,800

4

5,100

5

8,200

The quench water is to be sampled for indications of spalled coke, and if after five to ten minutes, spalling has not started, the fol lowing method and/or methods shall be used to start spalling.

 Alternately reduce and increase the steam flow rate though the tubes.

 Reverse the steam flow through the tubes.  Lower the flue gas temperature 100 0F to 2000F.  Add a small quantity of air to the steam for a few minutes, then shut off air. j)

The sample connection must be observed constantly for evidence and extent of spalling. The degree of spalling will be indicated by the color of the water flowing from the sample connection, to the sewer, FOSTER WHEELER ENERGY LIMITED 2002

FOSTER

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WHEELER



and the number of coke particles settled in a standard sample container. The color and condition of the effluent streams will vary during various stages as follows: 1)

The discharge will be milky with a slight gray colour before and after decoking has started and has been completed.

2)

A light gray color will be seen in the effluent to the sewer when a fine soot is being removed

3)

As spalling increases, large particles of coke will be removed. This condition is indicated by a dark gray to black color in the effluent to the sewer.

4)

At the completion of the spalling and burning cycle the effluent will be reddish brown in color.

k)

When heavy spalling starts, steam flow should be reduced to prevent erosion. There is no strict measure to the amount of steam required, and the operator must depend on pressure control and visual observation of discharge at bleeder. Maintain pressure and flow at lowest point and yet maintain spalling. This will reduce the abrasive action of the coke particles being removed.

l)

When sampler outlet shows fine coke dust, reduce inlet pressure for a minimum of 10 minutes to see if any grainy coke will show up. If fine coke dust continues, reduce pressure further to be sure dust is not produced by high velocities.

m)

After all spalling has stopped and cannot be restored by method V A6(i) reduce flue gas to 1200 0F and set steam flow approximately as follows: Tube ID .

# Steam/hr.

TubeID

# Steam/hr

2

500

3.5

1500

2.5

700

4

1800

3

1000

5

3000

6

4000

Gradually add air to approximately 1/10 of steam quantities.


FOSTER

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WHEELER




n)

It is important that the operator be in a position to observe, through the observation port, the coke burning in the tube. Coke burning, indicated by a slight glow on the tube surface, approximately one foot in length will start at the inlet end of the tubes and will progress at the rate of one to one and one half feet per minute. Metal surfaces should not be permitted to glow cherry red since this indicates a temperature in excess of the 1200 0 F maximum allowable. If metal does glow cherry red reduce the air input or stop air altogether.

o)

The air-steam mixture will require adjustment, increasing the air or reducing the steam volume, if there are indications (tube glow) that burning has stopped or is slowing down. As an added means for restarting burning, the flue gas outlet temperature can be increased 1000F. Should burning not be resumed, reverse the steam-air flow through the tubes.

p)

Should burning proceed at too rapid a rate, causing excessive heating of the tubes, the air volume should be reduced or the steam volume increased. Should the adjustment of the air-steam mixture fail to slow down the burning rate, the flue gas temperature should be lowered in steps of 100 0 F until the desired burning rate has been achieved.

q)

Completion of coke burning can be checked by the color of the effluent as outlined in paragraph VA6(j), and should be confirmed by the results obtained in a gas analysis. This gas analysis should indicate about one percent CO 2 confirms that burning has been completed.

r)

Another method for verification of the decoking operation is by performance of the “glow” test. A glowing wood ember is placed in the effluent from the sample connection after the water has been turned off. If the ember is extinguished, decoking has not been completed. If the ember glows more brightly the decoking operation has been completed.

s)

Upon completion of the decoking operation air injection into the tubes is to be stopped and steam flow rate increased for the removal of residual ash giving the effluent a milky white colour.


FOSTER

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WHEELER


b)

Case II – 9% Chrome, 18-8, Incoloy Tubes 1.

The procedure outlined under Case II is applicable for heaters equipped with tubes of high alloy steels, primarily 9 per cent chromemoly steels, 18-8 stainless steels, and Incoloys. This type of heater is normally in ethylene pyrolysis and equivalent process service. For typical piping arrangement, see detail “A” 11 this standard.

2.

When the pressure drop increases about 10 per cent, the tubes require decoking. An alternate method is to schedule decoking at regular intervals.

3.

Tubes fabricated from these materials can withstand temperature of 13000F to 1350 0F during decoking operations without suffering damage.

4.

The spalling action, outlined in Case I, is not desirable for Case II because this type of coke is very hard and abrasive, and furthermore, the tubes can become plugged with the loose coke.

5.

Normally there is no requirement for reversible flow. The deposition of coke is towards the outlet end of the heater. However, steam connections should be provided on the outlet side of the heater as a precautionary measure.

6.

Vapors, resulting from the decoking operations, can be vented through the heater stack without producing undesirable side effects. The coke is converted, almost completely, to CO 2 and CO2 during the burning operation. There is little or no ash residue.

7.

The decoking operation normally requires 6 to 8 hours for completion.

8.

Sequential Operation a)

Interrupt the process flow through the heater.

b)

There is no need to extinguish the burners as in Case I.

c)

Introduce steam into the tubes. It is assumed that connections for steam-air decoking are included in the design of the heater piping. See typical steam-air decoking detail A page 11 this standard. This arrangement presupposes series flow – note the jump over.


FOSTER

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d)

Wherever possible the tubes in one heater should be decoked in series. An exception to this rule is Cracking Heaters, which usually are two (2) pass. Each pass should be decoked separately with cooling steam flowing thru the other passes.

e)

Steam mass velocity through tubes being decoked should be at the rate of approximately 10 pounds per square foot per second. Approximate steam flow for a mass velocity of 10 pounds per square foot per second for various tube diameters are: Tube, I.D. Inches

Steam Flow, lbs/Hr.

2”

670

2.5”

1,050

3”

1,550

4”

2,800

5”

4,500

f)

A pressure drop of 1 ½ psi per one hundred feet is to be expected when the recommended steam mass velocity is achieved through the tubes. Appreciable variations in pressure drop can be indicative that spalling has occurred and the tubes have become plugged with coke. Should this occur the direction of steam flow is to be reversed to free the tubes.

g)

Quench water is to be turned on to the sample connection to the sewer at the time steam is injected into the tubes.

h)

Samples of the effluent should be checked to ensure that effluent is not carrying coke removed by spalling. If spalling occurs, the mass velocity should be reduced slightly.

i)

A small amount of air may be required to start the coke burning.

j)

The operator must watch carefully to ensure that tubes are not overheated during the burning operation. Tubes will not be damaged if they glow cherry red at the point of coke burning. Tubes shall not be permitted to reach white heat. At the point where coke is burning, the tube will have a cherry red glow, approximately one foot long. The rate of burning will be approximately one and one-half feet per minute.


FOSTER

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c)


k)

Should tubes reach white heat, cut off air injection to the steam and reduce the flue gas temperature 200 0F, and continue stepwise temperature reduction until the tube metal temperature has been lowered.

l)

When it appears that coke burning is about to stop or is nearing completion, gradually increase the quantity of air being injected with the steam.

m)

It is recommended that a gas analysis be used to verify the completion of coke burning. During decoking operations the CO2 content will be about 4 to 5 percent, and the CO-CO 2 ratio will be high because of insufficient oxygen. As the decoking operation nears completion, the CO-CO 2 ratio will be reduced, and in the last stages O 2 will be evident in the sample. CAUTION: Air injection during burning must be regulated to control tube temperature. The “glow” test outlined in Case I can be used as additional means of verifying the completion of coke burning.

n)

Upon completion of the decoking operation the heater can be placed in normal service.

o)

At no time is water to be injected into the tubes.

Case III – Tubes Containing Catalyst – 25/20 Inconel Tubes 1.

The procedure outlined in Case III is applicable for decoking of Catalyst Heaters equipped with high alloy steel tubes fabricated from materials similar to those outlined in Case II. However, in Case III the tubes have been charged with catalyst. This method of decoking is employed for steam methane reforming heaters and similar services.

2.

Tubes fabricated from high alloy steels can withstand temperatures of 1500 – 1800 0F during decoking operations without suffering damage.

3.

Vapors resulting from the decoking operations can be vented through the heater stack.

4.

An increase of 6 to 10 psi pressure drop through the tubes in an indication of coke build-up on tubes and catalyst.

5.

Coke formation in the tubes and on the catalyst normally is the result of system upsets or improper operation of the heater. FOSTER WHEELER ENERGY LIMITED 2002

FOSTER




WHEELER



6.

The time required for the decoking operation ranges between 2 and 3 days, dependent upon the degree of coke build-up.

7.

a)

Remove the heater from service.

b)

Only process steam is used in decoking operations for Case III. It is assumed that connections have been provided in the heater for the injection of steam.

c)

The steam flow rate for decoking should be equivalent to the normal operating steam flow rate.

d)

During the decoking operation the burners are to be fired as for normal product service and could outlet temperatures and tube metal temperatures maintained at/or below design.

e)

The operator must watch continuously the temperature of the tubes. This material can glow cherry red without incurring damage, but a white heat will result in damage to the tubes.

f)

Under no circumstances are water or air to be used in decoking operations for these heaters.

g)

Changes in the pressure drop through the tubes during decoking must be observed very carefully, since a reduction in the pressure drop is the only indication that coke is being removed. Small quantities of CO will be produced but measurement will be difficult.

h) It is of utmost importance that once started the supply of steam be continued without interruption to completion of decoking. Loss of steam for only a few minutes will result in the deposit of carbon on the catalyst and require the removal of catalyst from the tubes. i) Upon completion of the decoking operation the heater can be returned to normal service without any further handling.


Process Std 306

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