Process Unit Steam Generation

1. Table of Contents

1. Table of Contents 1

2. Purpose 1

3. General 1

4. Background 2

4.1 Stop-Check (Non-Return) Valves 2

4.2 Desuperheaters 3

4.3 Required Boiler Feedwater Pressure 3

4.4 Steam Drum Design Pressure 4

4.5 Safety Relief Valves 5

4.6 Mandatory Reduced Ratings for Some Piping and Nozzles 8

4.7 Steam Disengaging Drum and Internals 9

4.8 General Layout 13

4.9 Water Quality and Blowdown 14

4.10 Blowdown Drums 14

4.11 Steam Generator Elevation 15

4.12 Kettle Boiler 16

4.13 Steam Coil Design Pressures 16

4.14 Circulating Water Pumps 17

5. Examples 17

5.1 Sample Hydraulics and Safety Valve Calculations 17

5.2 Hydraulic Diagram 17

5.3 Safety Valve Set Pressures 17

5.4 Required Total Relief Capacity 17

5.5 Drum Valve Capacity Requirement 18

5.6 Drum Valve Calculation 18

5.7 Superheater Valve Capacity Requirement 18

5.8 Normal Superheater Duty 18

5.9 Required Superheater Flow During Relief to Keep Steam Below 1020°F 19

Attachment 1 Distance between Steam Inlet & Outlet 21

Attachment 2 Project Spec 301 - Vessels 22

Attachment 3 Hydraulic Diagram 23

Attachment 4 American Society of Mechanical Engineers - Suggested Water Chemistry Limits 24

Attachment 5 American Boiler Maker Association's Recommended Boiler Water Limits and Estimates of Carryover Limits That Can Be Achieved 25

2. Purpose

This procedure describes the Inflection Point Engineering practice for creating the specifications required for process unit steam generation.

3. General

This procedure discusses some special project engineering considerations which apply to process unit steam generators designed under Section I of the ASME Boiler and Pressure Vessel Code. Every effort was made to provide useable guidelines rather than a comprehensive treatise. However, a modest amount of explanation is included, along with common variations to the rules. It is hoped that this procedure will fully cover most situations and also alert the design engineer when to seek additional information.

4. Background

4.1 Stop-Check (Non-Return) Valves

Stop-check valves, also termed non-return valves, can be thought of as lifting disc check valves with a stem and handwheel. The stem and disc are not connected to each other. This construction permits the valve to be used as a stop valve, a combination throttling and check valve, or a regular check valve, depending on stem position. This versatility is advantageous during startup and shutdown. Unfortunately, the valve's flexibility is achieved at the expense of significant pressure drop. As with any check valve, the stop-check is to be sized small enough to assure full disc lift at minimum (extended period) flow conditions to avoid chattering. When this criterion is met, one finds surprisingly high pressure drops occurring at the desired maximum flow. To the design engineer setting up his hydraulics, the high pressure drop potential is also highly unpredictable. This is because Inflection Point Engineering specifications to date do not specify the size, type, manufacturer, or minimum sustained flow rate. These selections are up to the contractor. To determine what is to be expected in a well designed system, the proper valve for several different cases was determined. In each case the minimum steam flow for an extended period was assumed to be 60% of design. In all cases, a line size valve was too large, in some cases even for the rated steam flow. Generally the proper valve was one size smaller than the line, and in some cases two sizes smaller. The pressure drop for the correct size valve varied from 4 to 18 psi, depending on rated flow, steam conditions, manufacturer (Crane or Edward), and style (globe or angle).

As a general rule, an allowance of 10 psi across the non-return valve at rated flow will permit an adequate estimate of the drum operating pressure. However, in some cases, determining drum operating pressure is critical because of low MTD. This may occur, for example, in the generation of steam by condensing a light overhead vapor. In such cases the engineer may wish to select a particular valve and list it in the piping specification. Another alternative, where low DP between drum and header is important, is to use the combination of a conventional swing check and a gate valve in place of the stop-check valve.

Finally, it must be pointed out that a steam check valve of any kind is not a code requirement. Section I merely requires two block valves with a free blow drain between them on the steam outlet from a boiler having a manway. As long as the header pressure cannot rise above the process steam generator's design pressure, a non-return valve is not mandatory. However, in most situations the utility of the stop-check generally outweighs the disadvantage of a marginal increase in drum operating and design pressures.

4.2 Desuperheaters

In most cases a desuperheater is placed downstream of superheaters to limit the steam temperature entering the header. The most common types of desuperheaters for this application have a venturi configuration, with the water entering at the point of highest velocity. These types can easily handle the 2:1 or 3:1 turndowns commonly required. Turndown refers to the ratio of maximum to minimum steam flow. It does not refer to the range of water flows or attemperating duties.

Specify the desuperheater assuming that at rated flow the superheater outlet temperature may be 100°F above the expected superheater outlet temperature. Calculate desuperheating water requirements using a straightforward heat and mass balance.

For most steam generators specify an "attemperating" type of desuperheater. This type has a venturi insert and negligible pressure drop. A somewhat more expensive model having better turndown is the true "venturi" desuperheater, where the entire steam passage has a venturi configuration. This type will have a steam pressure drop of about 5 psi. Consider its use for turndowns over 3:1 and where the final temperature is within 100°F of saturation.

See " for additional details.

Desuperheating water need only enter the desuperheater at a pressure equal to the steam pressure upstream of the desuperheater. The water is to be essentially free of dissolved solids to avoid contaminating the steam. "Clean condensate" is the most common designation for the required water, although the refiner rarely has such available at 650 psig. Boiler feedwater is usually not acceptable unless the makeup water is demineralized and the oxygen scavenger hydrazine is used rather than sodium sulfite. Put another way, desuperheating water should have a total dissolved solids (TDS) content of less than 5 ppm.

4.3 Required Boiler Feedwater Pressure

Boiler feedwater (BFW) must be available at the design flow rate and at a pressure high enough to get into the boiler during relief. The boiler pressure at relief is usually assumed to include the 6% accumulation. However, where calculation shows that sufficient relief capacity is available to prevent the pressure from rising more than 3% over the highest relief valve setting, this basis may be used instead. This latter basis is only recommended where existing feedwater is at a marginal pressure; the technique can reduce the required pressure, but only if the highest drum valve set pressure is less than 3% over the design pressure (i.e., less staggering of set pressures).

In translating the required boiler inlet pressure to a battery limit pressure, allow for static head, economizer, BFW process exchange, piping, control valve, and other losses as required.

4.4 Steam Drum Design Pressure

a. Starting with the maximum header operating pressure, work back to the corresponding drum operating pressure. The following are general pressure drops between drum and header:

Superheater coil 10 psi

Piping 4 psi

Orifice Plate 1 psi (after pressure recovery)

Non-return valve 10 psi

Desuperheater 5 psi (venturi type)

Total: approx. 30 psi

Obtain actual superheater coil pressure drops from either the 201 Specification or the Heater Specialist.

Once the pressure drops from header to drum have been determined, estimate a drum operating pressure. ” provides the necessary guidelines for setting the drum design pressure.

b. Evaluate how the above drum design pressure compares with the header design pressure:

If header design pressure is greater than or equal to the above drum design pressure, make the drum design pressure equal to the header pressure. Section I refers to the drum design pressure as the Maximum Allowable Working Pressure - MAWP. Proceed to Step c. If the above drum design pressure is greater than the header design pressure, set the MAWP equal to the minimum drum design pressure as outlined in Procedure IPE-TM-100-02. The drum design can proceed to Step c. However, the design engineer must see if the steam generator can overpressure the header beyond allowable accumulations.

In Section I service, generally set the lowest relief valve at the MAWP. Typically set the second valve 3% above the set pressure of the first valve. The maximum accumulated relief pressure is 3% above the highest set pressure. Therefore, the steam generator will have a maximum accumulated relief pressure of 1.03 x 1.03 = 1.06 times the MAWP.

Section VIII generally controls the design of equipment tied to the steam header other than steam generators. Section VIII allows a 10% accumulation, or a 16% accumulation for multiple relief valves. In the case of the steam generator overpressuring the header, assume multiple relief valves, since there are always two relief valves on the steam generators. Therefore, calculate the allowable Section VIII overpressure based on multiple relief valves and compare with the maximum accumulated relief pressure of the steam generator.

If the MAWP x 1.06 < header design x 1.16, then the header is adequately protected. Go to Step c. If the MAWP x 1.06 > header design x 1.16, then the steam generator could overpressure the header, and one must provide some means of protection. This may be additional valves downstream of the superheater or on the header itself. It may also mean less staggering between the relief valves to lower the maximum accumulated relief pressure. Consider using a larger superheater relief valve sized for the full flow. Since this valve is set lower than the drum valves, it may solve the problem.

c. Check whether BFW at its minimum pressure can get into the drum at the maximum accumulated relieving pressure. Be sure to consider static head, pipe friction, BFW preheat exchangers, economizer pressure drop, and the control valve. Generally, the control valve can be assumed wide open for this emergency and only 15-20 PSI needs to be allotted for it.

If the BFW can get in during relief that is good. If not, consider using a lower design pressure to permit use of the existing BFW pressure. If the design pressure is already at the minimum design pressure based on the recommended differentials between operating and set pressure, consider having less than 3% staggering of the relief valves to lower the maximum accumulated relief pressure. As a last resort, ask for a higher BFW pressure.

4.5 Safety Relief Valves

In general, boilers of any substantial size (say over 4000 lbs/hr) must have at least two safety valves. Every attached superheater must have a safety valve near the outlet. If there are no intervening valves between boiler and superheater, the valve on the superheater outlet may be included in determining the number and size of the boiler safety valves.

However, there are three qualifiers in applying the above rules. First, the discharge capacity of the valve or valves on the boiler drum must be at least 75% of the total required capacity. Second, (and this is really obscure) when exactly two safety valves are used on the system, the smaller valve must be at least half the size of the larger valve. Thus, with one valve on the drum and one on the superheater, the installed capacity will be a minimum of (75% + 1/2 x 75%=) 112.5% of required capacity. Usually the installed capacity will be even higher due to round up to the next largest orifice and because of the conservative estimate of required capacity. Excessive oversizing may lead to valve chattering. The third issue is that a large percentage of customers, contractor relief valve experts, and even boiler inspectors mistakenly interpret the code as requiring two valves on the boiler drum plus one on the superheater outlet.

To avoid the very real problems arising from the above considerations, it is recommended that (at least) two valves be located on the drum and one valve on the superheater near its outlet. The two drum valves should have the same orifice area (although this is not mandatory) and must be sized for a combined capacity of at least 75% of the required capacity. Size the superheater outlet safety valve for the remaining relief requirement, but not less than 20% of the total required capacity. However, it is often desirable to size the superheater valve larger to limit the steam temperature during relief. Higher than normal steam temperatures will occur at the superheater outlet during relief because flow is reduced from rated down to the capacity of the safety valve. In high temperature systems, care must be taken to avoid exceeding safety valve temperature ratings during relief. See the example in Section 5.

Set one valve on the boiler drum at (or below) the drum design pressure. Generally, set additional drum valves up to 3% above the design pressure. However, the complete range of set pressures for saturated steam safety valves must be within 10% of the highest valve set pressure. This restriction only becomes governing if the lowest set pressure is selected considerably below the drum design pressure, which is very unusual.

Determining the required relieving capacity is essential to sizing the relief valves, and yet the code states that the required relieving capacity (for a waste heat boiler) must be determined by the manufacturer. Thus one could defend the use of the note on the 807 Specification which says, “Contractor to size following equipment selection.” However, this practice must then be carried over to the vessel specification, and since relief valve nozzle sizes are involved, Inflection Point Engineering avoids potential delays during the fabrication-procurement phase by routinely estimating the required relieving capacity (very conservatively) and preparing the project specifications accordingly. Any resulting excess relief capacity is inconsequential because of staggered set pressures.

The capacity estimating method generally used at Inflection Point Engineering is to multiply the "design" steam generation rate by 1.5 and assume that this is the required relieving capacity.

In determining relief valve sizes, the usual Section VIII accumulation percentages and area formulas do not apply. For the usual situation in which one drum valve is set at the design pressure, and the other is set 3% higher, the pressure must not rise more than 6% above the design pressure (1.03 x 1.03 = 1.06). Thus, a 6% accumulation over the design pressure may be assumed for calculating required orifice areas. The area formula to be used for Section I work must derate the valve by 10%, compared to the Section VIII formula. Thus modify the formula A = W/50 PKsh used for Section VIII to A = W/45 PKsh for Section I work.

Set the superheater safety valve design temperature equal to the relief temperature. As was mentioned earlier, the temperature during relief for superheater valves may be far above the normal temperature because the steam flow through the superheater is reduced from rated flow down to the capacity of the safety valve.

For medium pressure steam generators and high pressure steam generators where normal superheated steam temperature is 700ºF or lower, select a relief rate high enough to limit the relief temperature equal to 750ºF, the limit for carbon steel safety valves. Set the relief temperature at 750ºF.

A conservative and simple way to calculate the required steam flow for a given superheater outlet flow is to assume a constant superheater duty and determine the flow rate which will absorb that duty without exceeding the desired temperature (see example in Section 5). For high pressure steam generators where normal superheated steam temperature is greater than 700ºF, select a relief rate high enough to limit the relief temperature to 1020ºF, the temperature limit for alloy steel safety valves. Set the relief temperature at 1020ºF.

At a design temperature of 1020ºF, however, the strength of even an alloy steel is substantially reduced. Most high pressure steam generators would require a safety valve with a Class 1500 inlet flange rating and a Class 300 outlet flange rating - even though the outlet vents to atmosphere!

To avoid the Class 1500 and Class 300 flanges, and thus meet the “funny look” test, reduce the relief temperature by increasing the steam flow rate. The resulting larger orifice size is preferable to the Class 1500 flange. Class 600 flanges are preferred, but a Class 900 flange rating is acceptable. Avoid the use of multiple superheater safety valves if possible.

In some cases, it may be necessary to reduce the allowable backpressure on the safety valve specification to below the typical 10% in order to maintain a Class 150 flange. Reducing the backpressure is preferable to specifying a Class 300 flange on the outlet.

Set the superheater outlet safety valve set pressure so that this valve opens before the valves on the drum. This permits a flow of cooling steam through the superheater. While in some cases the superheater metallurgy is specified based on no cooling steam flow, loss of flow is always a condition better avoided. Therefore, set the superheater valve set pressure lower than the lowest drum valve set pressure by an amount somewhat greater than the pressure drop through the superheater at rated flow. Exercise good judgement to assure a sufficient differential between operating and popping pressures at each relief valve location.

4.6 Mandatory Reduced Ratings for Some Piping and Nozzles

Section I, A-361 Referenced Standards, requires reduced ratings for flanges, fittings, and valves in boiler feedwater and intermittent blowoff services. This sometimes results in a drum with two different classes of flanges. Likewise, some lines will have a higher piping class than expected. Use the following table for equipment covered under Section I.

Table 1

MAXIMUM ALLOWABLE WORKING PRESSURE (MAWP) FOR THE USE OFANSI B16.5-2001 PIPE FLANGES AND FLANGED FITTINGS AND ASME/ANSI B16.34-2001 VALVES-FLANGED, THREADED, AND WELDING END (STANDARD CLASS)	MAXIMUM ALLOWABLE WORKING PRESSURE (MAWP) FOR THE USE OFANSI B16.5-2001 PIPE FLANGES AND FLANGED FITTINGS AND ASME/ANSI B16.34-2001 VALVES-FLANGED, THREADED, AND WELDING END (STANDARD CLASS)	MAXIMUM ALLOWABLE WORKING PRESSURE (MAWP) FOR THE USE OFANSI B16.5-2001 PIPE FLANGES AND FLANGED FITTINGS AND ASME/ANSI B16.34-2001 VALVES-FLANGED, THREADED, AND WELDING END (STANDARD CLASS)
Maximum Allowable Working Pressure (MAWP) psig, Except as Noted	Maximum Allowable Working Pressure (MAWP) psig, Except as Noted	Maximum Allowable Working Pressure (MAWP) psig, Except as Noted
ANSI B16.5-2001 and B16.34-2001 Class	Steam Service at Saturation Temperature [Notes (1), (4)]	Boiler Feed and Blowoff Line Service [Notes (1), (2), (4)]
150	205	170
300	605	490
400	785	640
600	1135	935
900	1635	1430
1500	2675	2455
2500	3206 psi [Note (3)]	3206 psi [Note (3)]

Notes:

(1) Adjusted pressure ratings for Steel Pipe Flanges and Flanged Fitting, for steam service at saturation temperature corresponding to the pressure, derived from Tables 1A and 2, using material group 1.1 of ANSI B16.5-2001. Adjusted pressure ratings for Steel Valves (Standard Class) for steam service at saturation temperature corresponding to the pressure, derived from Tables 1 and 2-1.1A, using material group 1.1 of ASME B16.34-2001. For other materials or design temperatures exceeding saturation temperature, see ASME B16.5-2001 and ASME B16.34-2001 for pressure-temperature limitations. The pressure listed is rounded to the nearest 5 psi.

(2) Pressures shown include the factor for boiler feed and blowoff line service, corrected for line design temperature, as required by ANSI B31.1. The pressure listed is rounded to the nearest 5 psi.

(3) Rating exceeds critical pressure of water.

(4) The pressure-temperature ratings provided herein apply to the flange and do not necessarily reflect the rating of the assembled flange joint. The pressure-temperature ratings provided apply to the gasketed and bolted flange joint only when the gasket and studs conform to the recommendations of ANSI B16.5-2001.

For installations in which the feedwater is preheated in an economizer (with no valves between the boiler and economizer), the reduced rating only applies to the piping from the economizer inlet header back to and including the required feedwater stop and check valves.

The apparent reason for reduced ratings is the presence of significant temperature differentials. On this basis, it appears reasonable to say that when the feedwater is introduced into the two-phase steam-water line, as is frequently done in a forced circulation system, the downstream drum connection does not require a reduced rating.

4.7 Steam Disengaging Drum and Internals

The proper specification of a steam disengaging drum and its internals requires an understanding of the functions, operating principles, and limitations of the various components. In a specific application, a variety of approaches may be used to meet the design objectives. For this reason the following discussion is intended to provide insight rather than hard-and-fast rules.

A steam disengaging drum and its internals have two major functions-inventory accumulation and vapor-liquid separation. The vapor-liquid separation is performed in two stages. First, the bulk of the liquid is removed from the vapor as the two-phase material enters the drum and flows toward the outlet end. Then, at the vapor outlet a second stage of separation occurs in the internal centrifugal separator.

a. Overall Drum Dimensions

Choose the overall drum dimensions to meet the following requirements:

(1) Permit an initial vapor-liquid separation.

(2) Provide inventory for normal operation and emergency conditions.

(3) Provide space for proper operation of the internal separator

Apply Stokes' law (or the related intermediate law, depending on Reynold's number) to calculate the terminal settling velocity needed to determine a drum size based on initial vapor-liquid separation. Select a horizontal vapor velocity so that moisture particles larger than a certain size will fall from the top of the drum down to the liquid level in less time than the vapor requires to flow from inlet to outlet. Since the drum separation is only an initial separation, the choice of particle diameter is not critical. A particle size of 135 microns has been found to give adequate separation with reasonable drum sizes. The above procedure is incorporated in Attachment 1 which gives the required distance between steam inlet and outlet for combinations of steam flow, pressure, and vessel diameter. The chart assumes the liquid level is at the centerline of the drum. While there is no magic to having the liquid level at the centerline, this chart is useful to estimate reasonable drum sizes based on vapor-liquid separation. Note the distances derived from the chart are the distances which the steam travels. The actual vessel length will be significantly longer.

Another vessel sizing criterion is that sufficient inventory be provided. While some inventory is necessary simply to operate the forced circulation system, provide an added margin to allow some time for operator intervention upon loss of boiler feedwater. In systems where heat input will continue even if feedwater is lost, provision of adequate inventory is particularly critical. As a general guideline, a 10 minute inventory between normal liquid level and the bottom of the vessel is suggested. Base the required inventory on the mass flow rate of feedwater required, not water circulated. For a revamp, a 5 minute inventory is generally sufficient.

The third determinant of drum size is the need to meet the requirements of the internal separator. The entrained moisture which the separator removes is returned below the drum water level by means of the ejects. The ejects are simply lengths of pipe with the top ends at points in the separator where moisture accumulates and the bottom ends submerged in the drum water. Since the separator has a pressure drop across it, the water level inside the ejects is higher than the drum water level. This water column inside the ejects and above the drum liquid level is called a "balance column." The separator must be high enough above the drum liquid level to permit an adequate balance column to form. Unfortunately the vendor is unable to provide designers with balance column requirements, except on a case-by-case basis.

The best general recommendation is to allow 15 inches from the bottom of the separator to the normal liquid level. This guideline is based on the vendor's experience that they rarely see balance columns over 10 inches. The additional 5 inches is an allowance for drum liquid level fluctuation. In some situations, the designer may find that the most economical means of providing necessary clearance is to locate the normal liquid level somewhere below the vessel centerline.

The steam separator specification provides the vendor with the information they need to confirm the adequacy of the design from the separator's point-of-view and requires that this check be made. With this reassurance, the designer usually need not consult the factory at the design stage. However, in unusual situations this may be advisable and might permit a departure from the above guidelines. More separator information is given in the following section on the actual selection of a separator.

When the above three criteria are combined, the steam drum will often have a length to diameter ratio of more than 4:1. In these cases, a larger diameter drum should be considered to reduce the L to D ratio to about 3:1. This consideration is particularly important when a future debottlenecking of the process unit could increase steam rates more than 25% and possibly force a replacement of the steam drum (the larger diameter is more conducive to installing a larger size or a greater number of steam separators).

b. Internal Steam Separator Selection

Before a final drum size may be established, determine the number and size of the steam separators. It is common Inflection Point Engineering practice to base the design on internal type (model BI) separators. See Anderson Separator Company, Separator Engineering Data pp.11 of Bulletin A200.10. In using this chart, the proper choice of steam flow rate is very important because the efficiency of centrifugal separation devices drops off dramatically at turndowns below 50% of design (although this is somewhat mitigated by better gravity separation in the drum at reduced flow rates). Give consideration to the possibility of higher than design steam flows as well as expected minimum flows during process unit turndown. As a general rule, specify the separator for 25% more steam flow than the overall design case. This is because the separator has sometimes been the limiting element as the process unit is pushed beyond design capacity.

There are only two sizes of Anderson Type BI separators available, the 6" and the 10" models. The 10" model has a maximum capacity about three times that of the 6" model. Thus, where a 6" is too small and a 10" rather generous, the best choice may be two 6" separators. The use of more than one size in the same drum, however, is not recommended because of poor flow distribution.

The ejects should extend well below the liquid level, preferably to within 6-12 inches of the vessel bottom which permits the separator to function properly during periods of low water level. Care must be taken to avoid interference between ejects and vortex breaker. This usually means that the water outlet must be located sufficiently upstream of the ejects to avoid interference.

As noted, Anderson Type BI separators will sometimes be a limiting element in revamps when the process unit is pushed beyond the design capacity. Additional steam separation capacity can sometimes be provided if the drum diameter is sufficient. For example, two 6" separators can be replaced with a 10" separator thus providing 50% more separation capacity. However, a steam drum (sized per Inflection Point Engineering's normal drum sizing criteria) with one 10" separator will be too small to allow replacement with four 6" separators.

type BI separators are commercially positioned to produce steam having 1 ppm of TDS. Per Section 4.9, 600 psig steam should have no more than 0.5 ppm. To compensate, the Inflection Point Engineering Steam Separator Specification, Project Specification 918, should call for steam with TDS of 1 ppm based on a steam drum water concentration of 2000 ppm. When the steam drum is operated at 1000 ppm, the steam will have 0.5 ppm of TDS.

A second type of steam separator is the vane type, Anderson AVB series vane purifiers or equivalent. The Anderson AVB series vane purifiers have a greater turndown ratio and can produce steam with lower TDS (<0.1 ppm for 600 psig steam). While not normally specified, this type of separator should be considered if a more stringent steam purity is required.

c. Drum Baffles and Inlet Nozzle

The layout of the drum nozzles and baffles will be discussed with reference to Attachment 2, which is a sketch of the various drum components. As shown, the two phase inlet nozzle is directed away from the steam outlet so that the momentum of the incoming fluid is largely dissipated by the change in direction imposed on it. The horizontal baffle is provided to arrest the downward momentum of the liquid and thus minimize water level disturbances and vapor entrainment below the liquid level. For this reason, locate the baffle near the of the float range. Since the liquid flow off the horizontal baffle will still have a disturbing effect on the drum's liquid level, provide a vertical baffle to localize this effect. The vertical baffle should not extend higher than necessary, since its presence in the vapor space causes increased vapor velocity and reduces the separation time of entrained moisture. Locate the vertical baffle far enough from the horizontal baffle to assure that the water coming off the horizontal baffle does not cascade over the top of the vertical baffle. The bottom of the vertical baffle is to be submerged at least to the bottom of the level controller range.

d. Continuous Blowdown Nozzle

The continuous blowdown nozzle is used to continuously remove a portion of the boiler drum water to control the concentration of dissolved impurities. It is important to locate this nozzle well below the water level where it will always be submerged. Avoid the turbulent area between the baffles. The nozzle is to be high enough on the vessel side to avoid clogging from settled sludge. Finally, locate the nozzle upstream of the chemical feed nozzle.

e. Intermittent Blowdown Nozzle

The intermittent blowdown nozzles are provided to remove the sludge formed from the precipitation of residual hardness by the phosphate injected into the drum. Thus, the best places for these nozzles are the relatively quiescent areas where settling will be the most rapid. Since sludge is most objectionable in the area of the level gage and controller connections, this is a logical location for one nozzle. In drums over 10 feet long, specify a second connection at the quiet end of the drum (the end with the separator). Typically specify a 1-1/2" nozzle for this service.

f. Level Connections

Two sets of level connections are required. Provide a 2" pair of nozzles for a pipe column on which will be mounted a level control and level gage; in addition, provide a 1" pair of nozzles for an additional level gage. The additional gage is a Section I requirement for boilers operated over 400 PSIG and on boilers up to 400 PSIG when gage cocks are not used. Inflection Point Engineering recommends the use of two level gages on all boilers. Locate the level connections well away from the inlet to minimize disturbances.

4.8 General Layout

In laying out the drum, a sketch is recommended showing side and end views that are drawn to scale as part of the design engineer's calculations. Such a drawing has the following advantages:

a. Gives a more realistic sense of proportion for arranging baffling and nozzles.

b. Alerts designer to interference problems such as between ejects and vortex breaker and between inlet elbow and horizontal baffle.

c. Helps determine required length of stub between the separator outlet and vessel nozzle.

d. Helps locate and dimension the manifold required when more than one separator is installed.

e. Provides a check of the distance from the bottom of the separator to the liquid level, which is required to assure adequate separator balance column formation.

To permit an accurate sketch, use Anderson Separator Company Bulletin A100.85 Internal Type BI Hi-eF Separators to obtain the basic separator dimensions.

4.9 Water Quality and Blowdown

Raw water must be treated before it is deaerated and sent to the boiler as boiler feedwater. Typical treatment methods include zeolite softening, demineralization, and reverse osmosis. Without water treatment, operational difficulties such as fouling, scaling, corrosion, and carryover will occur.

Feedwater quality limits are shown in Attachment 4. These limits are excerpted from ASME's "Consensus on Operating Practices for the Control of Feedwater and Boiler Water Chemistry in Modern Industrial Boilers". The limits vary based on boiler drum pressure (the operating pressure of the boiler's steam drum). Higher pressure steam generators require better makeup water so that the steam purity is improved.

As steam is generated in the steam generator, the evaporated water leaves behind its dissolved solids. These solids then concentrate in the boiler water. Limits for boiler water are shown in Attachments 4 and 5. Attachment 5 is taken from the American Boiler Manufacturers Association's (AMBA) "Boiler Water Limits and Achievable Steam Purity For Watertube Boilers".

Steam generator blowdown rates should typically be set at 5% for purposes of sizing steam generator equipment. Higher blowdown rates are required when the boiler feedwater quality is poor. To calculate the blowdown rate,

Here, C stands for the concentration (in ppm) of the particular solid in the Boiler Feedwater (BFW) or the drum. The drum concentration is the concentration in the boiler water, which can be found in Attachment 4 or 5. The boiler feedwater concentration can be found in the BEDQ.

When demineralized water is used as Boiler Feedwater makeup, a 1% blowdown rate is typically encountered in actual operations. The blowdown rate should still be set equal to 5% for purposes of sizing steam generator equipment, however.

4.10 Blowdown Drums

Hot blowdown from the steam drum, whether intermittent or continuous, will flash when the water pressure is reduced. Blowdown drums are provided to separate the vapor and liquid phases safely.

A continuous blowdown drum (CB drum) is provided when there is an economic incentive to capture the continuous blowdown's flashed steam due to the value of the steam, the value of the water, or the avoided wastewater treatment cost. As a general rule, all convection system steam generators should be provided with a CB drum. Kettle boilers, or groups of kettle boilers should be provided with a CB drum if the total high pressure steam generation rate is greater than 40,000 lbs/hr or if the total medium pressure steam generation rate is greater than 100,000 lbs/hr. Also, CB drums should be considered for steam generators with even lower steam generation rates if they are installed in cold locations. This will help minimize icing issues related to vented steam.

Inflection Point Engineering typically designs the CB drum to discharge to the LP steam header for both HP and MP steam generators. The CB drum for a HP steam generator can, of course, discharge steam to the MP steam header if desired. Continuous blowdown from LP steam generators must be sent to the intermittent blowdown drum.

Continuous blowdown drums should have a minimum diameter of 2 feet. Larger diameter drums should be considered as required to meet critical velocity limits and thus avoid liquid carryover. Larger CB drums need not be considered until steam generator capacity exceeds 250,000 lbs/hr.

When a CB drum is not provided, continuous blowdown should be routed to the intermittent blowdown drum (IB drum). An IB drum is required for each steam generator (although a single IB drum can be shared by a group of generators) to flash the intermittent blowdown. The IB drum should be vented to the atmosphere through an 8" line equipped with an exhaust head. Since intermittent blowdown occurs at high rates (to move sludge) but for short periods (e.g., 10 seconds per shift), the capture of flashed intermittent blowdown steam is not usually economical, and, moreover, there exists the possibility of substantial solids contamination.

Intermittent blowdown drums should have a minimum diameter of 3 feet.

4.11 Steam Generator Elevation

The steam drum and the economizer, steam coil, and superheater are all located at some distance above grade. Hydraulics need to reflect the significant elevation involved in delivering boiler feedwater to the economizer and lifting boiler water from the circulating water pumps into the steam coil.

For revamps, actual elevations should be obtained. For new Schedule A steam generators, economizer and steam coil elevations should be obtained from the heater specialist. In absence of design data, an economizer elevation of 90 feet above grade and a steam coil elevation of 80 feet above grade can be used. These should generally be conservative.

The water/steam mixture in the pipe from the steam coil to the steam drum has a relatively low density. SteamPro does not allow for any pressure change in this line (that is, the pressure at the steam coil outlet is assumed equal to the pressure at the steam drum); SteamPro assumes that the frictional loss is essentially equal to the static head.

The elevation of the steam drum is based on the pump NPSH requirement. SteamPro provides details on pipe head loss assumptions and design criteria. Increasing the elevation of the steam drum above that required for NPSH requirements is perfectly acceptable.

4.12 Kettle Boiler

Kettle boiler is a generic term given to unfired steam generators in which a hot fluid, usually a process fluid, is forced through tubes to evaporate BFW contained inside a pressure vessel. Kettle boilers are found in many Inflection Point Engineering process units to recover waste heat.

Kettle boilers are specified in a 401 Project Specification. Detailed design (e.g., shell diameter) of the shell is left to the supplier. Steam side nozzles are specified and are essentially in accordance with nozzles provided with a convection steam generator’s steam drum.

Kettle boilers are not provided with a large volume of water storage. A 4" water level (minimum) above the process tubes is typically maintained.

The typical design approach temperature is 50ºF (process outlet temperature minus steam saturation temperature). Approaches as low as 20ºF may be considered if the process requires it. However, since the exchanger is not truly counter-current, careful review of the LMTD correction “F” factor is required for close approaches to avoid impractical or unreachable designs.

Experience shows that most kettle boilers are not provided with a steam separator. Standard specification 4-11 calls for a separator, if required, for the stated steam purity.

4.13 Steam Coil Design Pressures

The typical convection section steam generator will have a BFW coil (economizer), a steam coil (boiler), and a superheater coil. The design pressures for each coil can be determined as follows:

Superheater coil: Set design pressure equal to design pressure of steam drum

Steam coil: Set design pressure equal to design pressure of steam drum plus design steam coil pressure drop.

BFW coil: Set design pressure equal to design pressure of steam drum plus design BFW coil pressure drop.

4.14 Circulating Water Pumps

Circulating water pumps provide the steam drum water with the head required to overcome the resistance of the steam coil.

Specify new pumps with a circulation ratio of 7:1 (ratio of the water mass flow rate at the steam coil inlet divided by the steam mass flow rate at the steam coil outlet). Larger circulation ratios are acceptable. A circulation ratio as low as 5:1 is sufficient for a revamp.

Provide two pumps normally, one operating and one spare. The preferred driver arrangement is for one pump to have a motor driver, while the other would have a steam turbine. Two motors are acceptable if certain conditions apply (see Utilities Specialists).

Pumps will typically be provided with a low flow auto start control.

5. Examples

5.1 Sample Hydraulics and Safety Valve Calculations

Given: Rated steam = 40,000 lb/hr, 710°F

Header pressure normal range: 570 -600 PSIG

Header design pressure = 700 PSIG

5.2 Hydraulic Diagram

See the figure in Attachment 3.

Design Pressure: Using , the resulting pressure of 700 PSIG is reasonable.

5.3 Safety Valve Set Pressures

#1 Drum Valve = 700 PSIG

#2 Drum Valve = 700 x 1.03 = 721 PSIG

Superheater Valve: 700-11 = 689 PSIG; say, 685 PSIG, to be sure this valve opens first.

5.4 Required Total Relief Capacity

40,000 lb/hr x 1.5 = 60,000 lb/hr.

5.5 Drum Valve Capacity Requirement

Maximum accumulated pressure allowed during relief:

700 x 1.06 + 15 = 757 PSIA.

Required capacity for drum safety valves:

0.75 x 60,000 = 45,000 lb/hr.

Size each drum valve:

1/2 x 45,000 = 22,500 lb/hr.

5.6 Drum Valve Calculation

Use an "H" orifice; Area = .785 in2

Actual installed drum capacity

= 2 (45 A PKsh) = 2 (45 x .785 x 757 x .98) = 52,412 lb/hr

Sat. temp. @ 757 PSIA - 512ºF

Use a 2 x H x 3 safety valve. A 1-1/2 x H x 3 safety valve would also be acceptable.

5.7 Superheater Valve Capacity Requirement

Section I would only require another (60,000 - 52,412 = ) 7588 lb/hr. and Section VII suggests at least 20% of required capacity (.2 x 60,000) = 12,000 lb/hr.

However, in high temperature situations like this, the safety valve operating temperature controls the capacity. Normally, the steam rise across the superheater is from 494°F to 710°F (a 216°F rise). If we conservatively assume that the overall heat transfer coefficient and MTD do not go down, we can estimate the flow rate required during relief to avoid exceeding 1020°F. This is the highest temperature rating available for typical Section I safety valves.

5.8 Normal Superheater Duty

hl = enthalpy of saturated vapor at normal drum pressure (631 PSIG) = 1202.4 btu/lb

h2 = enthalpy of steam at normal superheater outlet conditions (620 PSIG, 700°F) = 1354.8 btu/lb

W = steam flow = 40,000 lb/hr.

Q = Superheater duty

Q = W (h2 - hl)

= 40,000 (1354.8 - 1202.4)

= 6.10 x 106 btu/hr.

5.9 Required Superheater Flow During Relief to Keep Steam Below 1020°F

Drum accumulated pressure = 757 PSIA

Estimated superheater outlet pressure at reduced flow = 754 PSIA.

hl = enthalpy of sat. steam @ 757 PSIA = 1200 btu/lb

h2 = Desired enthalpy at superheater outlet during relief

(754 PSIA, 1020°F) = 1523 btu/lb

Q = superheater duty = 6.10 x 106 btu/lb

W = Required superheater valve capacity, lb/hr

Sizing the safety valve for the above flow and temperature and an accumulated pressure of 3% above set pressure.

Use an"H" orifice; Area = 0.785 in2

Per Tool ", the selected safety valve would have a 2" CL 1500 inlet, a 3" CL 300 outlet, and an "H" orifice.

Reducing the relief temperature to 950°F, and allowing a 34 psig backpressure, gives:

Use a "J" orifice; Area = 1.287 in2

Per T-807-01, the selected safety valve would have a 3" CL 900 inlet, a 4" CL 150 outlet, and a "J" orifice.

Reduction of relief temperature further to 900°F yields:

Use a "J" orifice; Area = 1.287 in2

This results in a safety valve with a 3" CL 600 inlet, the same 4" CL 150 outlet and "J" orifice, and allows a 49 psi backpressure.

IPE-TM-900-01 Page 20 of 24

Attachment 1 Distance between Steam Inlet & Outlet

Attachment 2 Project Spec 301 - Vessels

Attachment 3 Hydraulic Diagram

Attachment 4 American Society of Mechanical Engineers - Suggested Water Chemistry Limits

Boiler Drum Pressure, psig	0 - 300	301 - 450	451 - 600	601 - 750	751 - 900	901 - 1000	1001 - 1500	1501 - 2000
Feedwater
Dissolved Oxygen, ppm	< 0.007	< 0.007	< 0.007	< 0.007	< 0.007	< 0.007	< 0.007	< 0.007
Total Iron, ppm Fe	0.1	0.05	0.03	0.025	0.02	0.02	0.01	0.01
Total Copper, ppm Cu	0.05	0.03	0.025	0.02	0.02	0.01	0.01	0.01
Total Hardness, ppm	0.3	0.3	0.2	0.2	0.1	0.05	Not Detectable	Not Detectable
pH @ 77F	8.3 - 10.0	8.3 - 10.0	8.3 - 10.0	8.3 - 10.0	8.3 - 10.0	8.8 - 9.6	8.8 - 9.6	8.8 - 9.6
Nonvolatile TOC, ppm C	< 1	< 1	< 0.5	< 0.5	< 0.5	< 0.2	< 0.2	< 0.2
Oily Matter, ppm	< 1	< 1	< 0.5	< 0.5	< 0.5	< 0.2	< 0.2	< 0.2
Boiler Water
Silica, ppm SiO2	150	90	40	30	20	8	2	1
Total Alkalinity, ppm	< 700	< 600	< 500	< 200	< 150	< 100	Not Specified	Not Specified
Free OH Alkalinity	Not Specified	Not Specified	Not Specified	Not Specified	Not Specified	Not Specified	Not Detectable	Not Detectable
Specific Conductance, S/cm	5,400 - 1,100	4.600 - 900	3,800 - 800	1,500 - 300	1,200 - 200	1,000 - 200	150	80
Steam
TDS, ppm	1.0 -0.2	1.0 -0.2	1.0 -0.2	0.5 - 0.1	0.5 - 0.1	0.5 - 0.1	0.1	0.1

Notes:

1. Table is for Industrial Watertube, high duty, primary fuel fired, drum type boilers. Table assumes steam goes through a superheater and is used for turbine drives.

2. Water quality for kettle type steam generators may in some cases be relaxed, but in general the above should be used for all Inflection Point Engineering steam generators.

3. When Demineralized water is used as boiler feedwater makeup, the use of limits for the 601 to 750 psig range should be considered as the limits for lower pressure boilers. The lower level of solids will promote better steam purity and take advantage of better water quality.

4. Dissolved oxygen limits are as measured prior to addition of oxygen scavenging chemicals.

Attachment 5 American Boiler Maker Association's Recommended Boiler Water Limits and Estimates of Carryover Limits That Can Be Achieved

Drum Pressure (psig)	Maximum Boiler Water Solids (ppm)	Steam TDS (ppm)	Maximum Total Alkalinity (ppm as CaCO3)	Maximum Suspended Solids (ppm)	Maximum Fractional Carryover
0-300	3,500	1.0	700	15	0.0003
301-450	3,000	1.0	600	10	0.0003
451-600	2,500	1.0	500	8	0.0004
601-750	1,000	0.5	200	3	0.0005
751-900	750	0.5	150	2	0.0006
901-1000	625	0.5	125	1	0.0007
1001-1800	100	0.1	20	1	0.001
1801-2350	50	0.1	10	1	0.002
2351-2600	25	0.05	5	1	0.002
2601-2900	15	0.05	3	1	0.003

Notes

1. Below 1000 psig is based on softened water.

2. If steam requires less TDS than listed, reduce boiler water solids to an amount equal to the maximum allowable TDS in steam divided by the maximum fractional carryover.

3. ABMA does not put limits on silica.

4. Maximum FCO does not include vaporized silica.