guidelines and techniques for the effective control of

GUIDELINES & TECHNIQUES FOR THE EFFECTIVE CONTROL OF CONDENSATE DISSOLVED OXYGEN IN STEAM SURFACE CONDENSERS

Author Darren M. Nightingale

Director of Engineering, Condensers Thermal Engineering International (TEi)

Santa Fe Springs, California, USA

ABSTRACT Low levels of dissolved oxygen for the condensate

produced within steam surface condensers is highly desirable and an increasingly important performance metric related to the efficient operation of today’s power plants. The presence of high levels of dissolved oxygen within condensate can quickly contribute to; accelerated corrosion, the need for additional treatment requirements, increased maintenance, operational challenges and even early equipment failure.

Under certain operating conditions, steam surface condensers can be expected to produce condensate with defined and/or guaranteed levels of dissolved oxygen. However, these levels can only be achieved provided certain guidelines are maintained and operational limitations are not exceeded. This is not always the case.

This paper includes the latest design guidelines, operational limitations, general considerations and practical techniques for controlling and minimizing condensate dissolved oxygen levels produced within steam surface condensers.

INTRODUCTION

Condensate is generally defined as steam that has been condensed back into water by either; (1) raising its pressure, or, (2) lowering its temperature. In the case of a steam surface condenser, the condensate is produced from saturated steam exiting the low pressure exhaust of the steam turbine, which has been condensed back into water. This is achieved by way of lowering the steam temperature by distribution over a bank of tubes (which has cooling water running on the inside) at a temperature lower than that of the steam.

Steam surface condensers all have the ability to reheat and deaerate falling condensate, albeit to different degrees and with certain limitations. Most condenser designs accomplish this

reheating and deaeration by direct contact between the low pressure steam and recently formed condensate. Uncondensed steam moves into, around & underneath the bundle, whilst condensate (formed within the bundle) cascades down through the tube bundle & eventually into the hotwell area. Condensate is then collected & stored for a short period of time in the hotwell, where it mixes with other drains, before eventually being extracted by the condensate pumps, see Figure 1.

Ideally, the condensate that is extracted from the condenser hotwell will be at the saturation temperature directly corresponding to the operating pressure (backpressure) of the condenser. When the temperature of the condensate is depressed from that of the saturation temperature, this is known as sub-cooling, and is detrimental to cycle efficiency. The ability of a surface condenser to produce condensate, at the saturation temperature without any sub-cooling, is considered an important performance metric.

Aside from the low pressure exhaust steam from the steam turbine, additional condenser drains will also mix with the condensate in the hotwell. Depending on the nature and source of these drains, additional heating and/or cooling of the condensate can occur. Storage levels within the condenser will vary dependent on plant design and requirements, but typically a hotwell is designed to store between 2 to 5 minutes of condensate, based on maximum extraction rates. This is to allow safe shut down of the plant in the event of an emergency, such that condensate pumps will not experience cavitation.

Once condensate leaves the condenser, it will eventually enter a feed pump, after which the condensate becomes feedwater; moving onto a boiler, or a reactor, or a HRSG, etc. Often treatment chemicals, if used, are added at this point. Dissolved oxygen in the feedwater creates a strong oxidizing agent that attacks metals, notably carbon steels. This can contribute to accelerated corrosion problems if dissolved

Proceedings of the ASME 2016 Power Conference POWER2016

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oxygen levels are not properly controlled. In addition, dissolved gases entrained at high levels within feedwater (and condensate) can sometimes contribute to cavitation within pumps. Rather than deal with this issue in the feedwater, it is of course better to reduce the dissolved oxygen levels within the condensate prior to it leaving the condenser hotwell and entering the feed pump.

Figure 1: Typical Tube Bundle, Steam & Condensate Paths. An ounce of prevention is always worth a pound of cure. It

is essential therefore that the design of any surface condenser maximizes the efficiency for the dispersal and removal of dissolved oxygen, as well as maintaining the lowest possible levels for a number of different operational regimes, such as low load operation for example. Minimizing sources of oxygen, and careful consideration of how a condenser unit will be operated, are both essential to ensuring that dissolved oxygen levels are always kept to the lowest possible levels.

1. WHAT IS DISSOLVED OXYGEN?

Dissolved Oxygen is the amount of free oxygen (i.e. not chemically combined) dissolved within the condensate. This is usually expressed in Parts per Million/Billion (ppm/ppb), Cubic Centimeters/Liter (cc/l) or Milligrams/Liter (mg/L), see Figure 2. Percent of Saturation may be used, but this is a relative term and therefore very rarely used for Condensate applications. Dissolved Oxygen is often referred to as simply, DO or, DO2.

7 ppb 0.007 ppm 0.005 cc/l 0.007 mg/l 14 ppb 0.014 ppm 0.010 cc/l 0.014 mg/l 21 ppb 0.021 ppm 0.015 cc/l 0.021 mg/l 42 ppb 0.042 ppm 0.030 cc/l 0.042 mg/l

Figure 2: Reference Values for Dissolved Oxygen.

Oxygen occurs in its free state as a gas, which is colorless, odorless and tasteless. It is a liquid only at -297.4°F (-183.0 °C, 90.15 °K). In air; oxygen is approximately 20.9% by Volume, and 23.1% by Mass. Under assumed standard conditions, one pound of air, occupies 13.15 cubic feet (whereas 1lb O2 = 12.03ft3) [14]. Typically, dissolved Oxygen in air saturated make-up condensate, under atmospheric conditions, can be as high as 8,000 to 12,000 ppb, see Figure 3.

Figure 3: Oxygen Solubility Chart (Typical) 2. WHY IS DISSOLVED OXYGEN A PROBLEM?

Dissolved oxygen can directly affect pH levels and increase the rate of corrosion for a number of materials within a power plant, specifically carbon steel. This can lead to a deterioration of things like seal faces and boiler piping. Further, it can also result in other operational issues, such as increased potential of cavitation within pumps etc.

Generally, most plants desire condensate, and/or feedwater, to have dissolved oxygen levels of less than 10ppb. Pitting and accelerated corrosion can occur at levels as low as 5ppb, see Figure 4. Dissolved oxygen can be removed by the use of chemical treatment, such as oxygen scavengers, but this approach has several downsides. Notably, accurate chemical treatment can be difficult for large volumes of feedwater due to irregularities with uniform dosing, etc.

Figure 4: Typical Oxygen Pitting of Boiler Tubes.

Low Pressure Steam Non-Condensible Gases

Condensate (High DO) Condensate (Low DO)


Accurate dosing is required such that over- and under- dosing is avoided, as this too can lead to additional side effects. Dosing can be expensive and there may also be undesirable environmental, and safety related, concerns with using oxygen scavengers. Careful control of plant water chemistry is therefore absolutely essential at all times.

Henry’s Law, formulated by the English chemist William Henry, states that at a given pressure, the solubility of gas is directly proportional to the (partial) pressure of the gas directly above the liquid. Further, Le Chatelier’s principle states that a change in any of the factors determining equilibrium will cause the system to adjust to the changes in order to restore equilibrium. Therefore, Le Chatelier’s principle predicts that the solubility of a gas will increase as a system loses heat, and will decrease as a system gains heat.

Steam surface condensers therefore need to operate at maximum efficiency to remove as much dissolved oxygen as possible; however, this is limited by physical factors, such as those above and also operational parameters.

Condensate temperature will have a major impact on the level of dissolved oxygen and is therefore an important factor in achieving the optimum levels of dissolved oxygen. Condensate leaving the condenser should always be at, or as close as possible to, the saturation temperature corresponding to the condenser pressure. Sub-cooling, when condensate temperature depression occurs, will entrain higher levels of dissolved oxygen. It is for this reason that the condenser design and operation should be optimized to ensure sub-cooling is always kept to a minimum, preferably zero degrees. 3. WHERE DOES DISSOLVED OXYGEN COME FROM?

There are a number of ways that oxygen can enter a steam surface condenser and become entrained into the condensate. All of these sources need to be properly understood and reviewed such that programs for eliminating, or at the very least minimizing, dissolved oxygen can be successfully implemented. Typical sources of oxygen are as follows:

Air In-Leakage

o Anchor Bolts (Internal to Hotwell) o Grout Pockets (In Base of Hotwell) o Cracks (in Shell, Hotwell, etc.)

Condensate Make-Up o Entrained (Atmospheric Tanks) o Below Saturation Temperature

Condensate Recirculation o Leaks from Pump Seals

Connections (Drains, etc.) Expansion Joints (esp. Rubber, St/St) Flanged Joints, Instrumentation, etc. Gaskets (poorly seated, worn, leaking) Gland Seal Steam Piping & Steam Seals LP Exhaust – Turbine Shaft Seals Weld Porosity

4. WHEN DOES HIGH DISSOLVED OXYGEN OCCUR? A number of conditions can contribute directly to levels of

dissolved oxygen higher than those expected and/or predicted, examples of these are as follows; see also Section 5.

(i) Venting Equipment Design and Operation

The use of venting equipment systems - such as liquid ring vacuum pumps, ejectors, or even hybrid systems that employ both - is required to continually remove non-condensible gases from the condenser. Incorrectly sized, and/or poorly maintained venting equipment can result in a reduction in the rate of removal of non-condensible gases. This can significantly impact back-pressure and therefore dissolved oxygen levels.

The proper design of venting equipment is imperative to the efficient operation of the steam surface condenser. The Actual Load to Design Capacity Ratio should be per the HEI Standards [10,11], and the Air In-Leakage rates should be per the guidelines within ASME PTC 12.2-2010 [2], to ensure dissolved oxygen levels are maintained at close to design requirements, see also Section 6.1.

(ii) Air In-Leakage

The single biggest source of dissolved oxygen is air in-leakage. Condensers work under vacuum, below atmospheric pressure, so therefore any leaks present on the shell side will always allow air to leak into the unit. This quickly introduces increased levels of oxygen into the condenser which directly impacts the dissolved oxygen within the condensate produced.

Leakage should always be kept to a practical minimum. ASME PTC 12.2-2010 [2] provides guidance on acceptable levels of air in-leakage, see also Section 6.2.

(iii) Make-Up at < Tsat

Volumes of condensate make-up, at a temperature lower than the steam inlet temperature, will have the direct effect of sub-cooling the condensate in the hotwell. The higher the volumes of such make-up, and the cooler it is, the greater the impact to the overall sub-cooling and dissolved oxygen levels.

Total condensate introduced to the Condenser at a temperature lower than the inlet steam temperature, should not be more than 5% of the steam flow for 14ppb, or more than 3% for 7ppb, see Figure 7, see also Section 6.3.

(iv) Make-Up in Poor Location

The location of make-up connections, especially if they require deaeration, can impact dissolved oxygen levels. For example, make-up at below Tsat introduced below the tube bundle, will inevitably lead to a poor reheat rate and limit deaeration. In addition, poorly designed connections above the tube bundle can equally cause issues by potentially ‘flooding’ the tubes, limiting heat transfer & reducing the reheating effect.

HEI Standards [10,11] provide guidance on preferred locations for condensate make-up connections, see Figure 9. More detailed recommendations on preferred make-up locations are included below, see also Section 6.4.1.


(v) Make-Up with Poor Distribution As well as location, the proper design of make-up

connections is also critically important. Distribution of condensate make-up within the condenser should be maximized, such that condensate can be effectively reheated, and subsequently deaerated. Nozzles produce cones, often hollow, to maximize this effect, see Figure 5. Spraying can vastly improve the available contact surface area and volume, such that optimized latent heat transfer occurs.

Spray pipe headers are therefore often used for distributing condensate within condensers. Further, the use of headers with specially designed spray nozzles can also be used. Recommendations on make-up distribution are included below, see also Section 6.4.2.

Figure 5: Spray Pipe with Nozzles for Condensate Make-Up.

(vi) Operational Parameters Low back-pressures will result in lower condensate

temperatures, and as the Circulating Water Inlet Temperature, T1, and Back-pressure, PS, decrease - the ability of the condenser to deaerate also reduces, as shown in HEI Standards [10,11], see Figure 6. This condition can be exacerbated during colder times of the year, such as winter in cooler climes. Operating at Low Loads, Cycling and other Transient modes of operation can also induce the same results, for pretty much the same reasons.

As the condenser has a fixed surface, it is difficult to address this issue, without the use of additional methods. Limitations to expected levels of dissolved oxygen based on operational parameters should be properly understood and accounted for. 5. HOW SHOULD MY CONDENSER PERFORM?

Most steam surface condensers should not exceed 42ppb under practical operating conditions. Exceptions to this would be condensers in a nuclear plant that has a (BWR) Boiling Water Reactor, where levels can be higher, above 50ppb [7,8].

Condensers can achieve dissolved oxygen levels as low as 14ppb and even 7ppb - given stable operation at the design condition together with zero to very low air leakage and with properly designed, maintained & operating Venting Equipment.

Condensate dissolved oxygen levels will be affected by many factors, as noted above, but in summary these are:

Low Loads Cyclic or Transient Operation High Volumes of Make-Up below Tsat Excessive levels of Air In-Leakage

The HEI Standards for Steam Surface Condensers [10,11], contain quantitative guidelines on expectations for dissolved oxygen for a number of operational parameters. Design guidelines for dissolved oxygen, sample calculations, venting capacity for associated venting equipment and performance curves are all included within the Standard. These guidelines were actually introduced into the 5th Edition of the HEI Standards [9] back in 1965, as the importance of low levels of dissolved oxygen was beginning to be recognized. The guidelines were keenly premised on certain specified limitations to ensure attainment. To some degree, the guidelines within HEI Standards have now become the base line expectation for guaranteed performance of steam surface condensers - although it is recognized that individual Condenser OEM’s may offer alternate, or even improved, guarantees.

Absolute pressure limit curves within HEI [10,11] provide expected oxygen content based on Cooling Water Inlet Temperature (T1) versus Saturation Pressure (PSat). Two curves are developed and set against these parameters. The area above Curve “A” depicts the operational parameters where dissolved oxygen levels can be expected to be equal to, or less than 7ppb. The area below Curve “B” depicts the operational parameters where dissolved oxygen levels can be expected to be equal to, or more than 14ppb. In the area between the two curves, dissolved oxygen levels can be expected to be between 7ppb and 14ppb, see Figure 6.

Figure 6: Dissolved Oxygen Curves (PSat vs T1).


The curves provided within HEI [10], see Figure 6, are predicated on a number of conditions, or limitations, on attainment. The most important of these conditions is the amount of condensate make-up that can be introduced to the condenser without affecting the dissolved oxygen level. Eliminating sub-cooling of the condensate is highly desirable, as it reduces fuel consumption, but equally important is the fact that the amount of dissolved oxygen is directly proportional to the temperature of the condensate per Le Chatelier’s principle.

Surface condensers can deaerate and reheat incoming drains, but only to a limited degree. HEI Standards [10] provide the following guidelines with respect to the limitations on condensate that can be introduced to the condenser below the temperature of the steam, which is summarized as follows: ≤ 7 ppb Make-Up at < Tsat should be < 3% of Steam Flow (Ws)

≤ 14 ppb Make-Up at < Tsat should be < 5% of Steam Flow (Ws)

Figure 7: Make-Up at < TSat - Limitations to maintain DO2 levels. Further, this same requirement for make-up introduced to

the condenser at temperatures below Tsat, is referenced in Section 3.11 of ASME PTC12.2-2010 [2], and so also forms a part of the Condenser Performance Test Code. In addition, PTC 12.2-2010 [2] goes on to provide detailed clarification on the compliance requirements for specified dissolved oxygen concentration by providing guidance on acceptable air in-leakage rates during testing, these can be found in Table A-1-1 [2] of the Nonmandatory Appendix A [2], and are more stringent than those provided in Table 3-4-1 [2] which are not applicable during testing for dissolved oxygen.

For example, a Unit that is designed for 1,000,000 lb/hr of Steam (Ws) from the Low Pressure Exhaust, with Cooling Water Inlet Temperature (T1) of 80°F is guaranteed to operate at 1.70in HgAbs. With no sub-cooling, the Saturation Temperature of the condensate (TSat) should be 95.73°F [5]. Per the HEI Curves, expected dissolved oxygen levels should be <7ppb. To maintain this, condensate make-up below 95.73°F, should therefore be limited to less than 3% of the steam flow, which would be 30,000 lb/hr, (59.91 GPM). Should the quantity of make-up water exceed these guidelines additional methods of deaeration and reheating will be required, see also Section 6 below.

The design of the steam surface condenser will have a bearing on the capability and limitations for maintaining dissolved oxygen levels at desired levels. It is therefore very important that an accurate Data Sheet and set of Performance Curves be provided and available for all steam surface condensers, as these will provide the basis of the guaranteed levels of dissolved oxygen to be expected within the condensate. Condenser performance curves set the datum base line for expected levels of dissolved oxygen for a number of operational parameters. These performance curves are therefore very important and critical to any subsequent investigation when reviewing dissolved oxygen anomalies within steam surface condensers.

6. REDUCING DISSOLVED OXYGEN – THE OPTIONS! There are a number of contributory factors that can

influence condensate dissolved oxygen levels within steam surface condensers, but they can be separated into two basic categories:

(i) Design. Poor condenser design will impact dissolved oxygen levels during operation. So it is important to review the design aspects of a condenser when performing troubleshooting of higher than expected dissolved oxygen levels, as often the root-cause contributory factor can be an inherent design issue, rather than an operational factor. (ii) Operation. Reducing dissolved oxygen to the lowest practically achievable levels will require individual review of many possible factors, most of which are typically related to operation; such as air in-leakage rates, low loads, etc. These also need to be properly understood, in conjunction with the design factors, when troubleshooting higher than expected dissolved oxygen levels. Below are the main contributory factors that can influence

the levels of dissolved oxygen, as well as suggestions for addressing design and operational issues that can lead to direct improvements and reductions in the levels of dissolved oxygen.

6.1 VENTING EQUIPMENT

During operation, non-condensible gases (NCG) must be continually removed from the condenser to ensure that the tubes are not ‘blanketed’ by pockets of gases, which can reduce available surface area and therefore back-pressure. Venting equipment must be properly designed so as to continually remove all non-condensible gases (and associated water vapor) to ensure optimum heat transfer and maintain the desired back pressure, at all times, as well as provide for adequate deaeration of condensate.

The design of venting equipment should follow recognized standards, e.g. VGB [16] or HEI [12,13]. An important aspect of the design of all venting equipment, related specifically to the required condensate dissolved oxygen levels, is the venting capacity, specifically the ratio of actual non-condensible gases removed from the system, to the design capacity of the venting equipment. Recommendations for maximum ratios are provided in the HEI Standards for Steam Surface Condensers [10], see Figure 8. There should also be zero air in-leakage directly into the condensate below the condensate level.

Figure 8: Venting Capacity and Oxygen Content (0-40 SCFM).

VENTING EQUIPMENT ACTUAL LOAD / EXPECTED OXYGEN CONTENT IN

DESIGN CAPACITY (SCFM) DESIGN CAPACITY RATIO CONDENSATE PPB (cc/L)

0.50 42 (0.03)

0.35 14 (0.01)

0.25 7 (0.005)

0.50 42 (0.03)

0.24 14 (0.01)

0.15 7 (0.005)

0 ‐ 20

20 ‐ 40


6.2 AIR IN-LEAKAGE One of the biggest contributors to degraded condenser

performance is air in-leakage. Venting equipment is designed to continually remove non-condensible gases, but additional leaks into the condenser can quickly impact unit performance, which in turn can elevate back-pressures and directly raise dissolved oxygen levels within the hotwell condensate.

It is recommended to replace bolted connections with welded connections, where possible, and eliminate all sources of potential air in leakage. Nonetheless, air in-leakage levels should be continually monitored, typically via a rotameter on the venting equipment, and compared to expected levels. Increases in the levels of non-condensible gases should be quickly and thoroughly investigated. There are a number of leak detection methods that can be successfully employed to source leaks, e.g. Helium or SF6 tracers. Leaks should always be located, and then fixed as quickly as possible to improve performance for the condenser and also to reduce any unnecessary loading on associated venting equipment.

6.3 CONDENSER DESIGN

Steam surface condensers should be designed to maintain steam velocities anywhere on the tube bundle periphery below advised maximums, e.g. less than 500 ft/sec per HEI [10]. In addition, sufficient spacing should be provided to allow steam flow so as to promote reheating, and deaeration of, falling condensate, see Figure 1.

Where specially designed trays are employed to promote reheating of falling condensate, these should be regularly inspected and kept in good working order.

Subsequent design revisions to the plant and condenser, as well as changes in operation, can adversely impact dissolved oxygen levels. In this situation, additional methods and/or modifications may be required to reduce dissolved oxygen levels. There are times when make-up conditions change. For example, flowrates may increase and temperatures may reduce – both factors that will adversely impact dissolved oxygen levels. Further, additional drains may be installed onto a condenser, also increasing the levels of sub-cooling.

In these situations, additional methods may be necessary to help maintain and/or improve condensate dissolved oxygen levels, some of which are referenced below. 6.4 CONNECTION DESIGN (CONDENSATE)

Steam surface condensers are often situated at the lowest physical level, and operate at the lowest pressure, within a power plant. This makes them an ideal location for capturing and recycling steam and condensate drains.

Condenser drains will vary in temperature, pressure & flowrate and all can have a significant impact to the condensate dissolved oxygen levels within the hotwell.

Temperature of returned drains is the prime concern when reviewing dissolved oxygen content of hotwell condensate. Drains that enter the condenser at a temperature higher than saturation temperature (or ‘hot’ drains), will not contribute to

any sub-cooling, and therefore have a negligible impact to dissolved oxygen in the condensate. In fact, if these ‘hot’ drains are located wisely, they can often assist with providing additional reheating of condensate in the hotwell, and actually improve dissolved oxygen levels by minimizing sub-cooling.

However, when high volumes of condensate are introduced into a condenser, at a temperature below saturation (or ‘cold’ drains) - then careful attention needs to be paid to these connections. Cold condensate will directly contribute to sub-cooling of the hotwell condensate and therefore impact dissolved oxygen levels. Cold drains also usually contain high dissolved oxygen levels prior to entering the condenser, which further impacts performance. Guidelines on acceptable limits for admission of ‘cold’ drains are noted within in HEI [10], see also Section 5 and Figure 7 above.

There are however, additional design factors that should be followed with respect to connection location and internal dispersion as noted below.

6.4.1 CONNECTION LOCATION

HEI Standards [10] provide guidelines on the best suited locations for connections of various kinds, see Figure 9.

Figure 9: HEI Recommendations for Service Connections.

Drain Type C B (d) A

Low Temp (a) Drains requiring Deaeration 1 (e) 2 NOT Recommended

Low Temp (a) Drains Not requiring Deaeration 2 3 1

Make-Up 1 2 NOT Recommended

Condensate Recirculation 1 (e) 2 3

Boiler Feed Pump Turbine Exhaust 1 3 2

Gland Seal Drain 1 2 NOT Recommended

High Temp Steam Drains (High Flow) 1 2 1 (c)

High Temp Steam Drains (Low Flow) 1 2 1

High Temp Water Drains 1 2 1

Steam Dumps 1 2 1 (c)

FWH Drains 1 (e) 2 NOT Recommended

Water Dumps 1 (e) 2 NOT Recommended

Control/Instruments As Required As Required As Required

Miscelleanous Drains & Vents See Above See Above See Above

(a) Low Temp = Max. Temp of Tsat+100 Deg.F.

(b) 1 = First Choice, 2 = Second Choice, 3 = Third Choice.

(c) Note Liquid Levels for these Choices.

(d) Drains requiring Deaeration should be on CL.

(e) Locate in Lower 1/3 of Exhaust Transition


Specifically, the latest HEI Standards [10] recommend that Low Temperature Drains requiring Deaeration, Condensate Make-Up, and Condensate Recirculation connections, shall be located Above the Top Tube (tube bundle), or in the Transition, as a preference. In addition, it is always recommended for drains that require deaeration to be supplied to the condenser at a pressure of at least 5psia.

EPRI Paper CS-2251 [6] also provides additional guidelines for dealing with what it refers to as ‘cool’ or ‘cold’ water drains (i.e. lower than saturation). EPRI [6] recommendations mirror those of HEI [10] in so much as these drains should be introduced high up & directed down onto the tube bundle and sprayed to provide effective deaeration.

Locating a condensate make up connection, which is at <Tsat, in the transition and/or above the tube bundle, will further improve, and maximize, the ability to reheat the condensate. The aim is to reheat the condensate make-up to equal Tsat prior to the condensate reaching the hotwell. Spraying condensate into the transition and/or over the tube bundle, both improves contact with (uncondensed) low pressure steam, as well as increasing residence time. The effect of spraying over the tube bundle maximizes the reheating to optimal levels. Having reheating occur over and within the tube bundle aids both liberation, and removal, of non-condensible gases. This is desirable as the non-condensible gas venting section for most condensers is usually deep inside the tube bundle, see Figure 1.

Ensuring the optimal location for condensate make-up can have a significant impact to the levels of dissolved oxygen during operation.

6.4.2 INTERNAL DISTRIBUTION

The use of low pressure steam within the condenser to reheat condensate is a widely used technique - though frequently this method is not used to its best advantage - and often, it is even ignored. The use of elbows, or baffles, for ditribution of condensate (which will be introduced at a temperature below saturation) is not recommended as it does not maximize the ability of the condenser to reheat the condensate. Introducing condensate at the side of, or below the tube bundle, will only reduce residence time and impact the ability of the condenser to reheat the condensate.

Spraying, or atomizing, the condensate when it is introduced into the condenser, will greatly increase the available surface area of the condensate once inside the condenser, and thereby improve the efficiency of (re)heating the condensate. Where the use of a simple elbow, or baffle, can restrict the ability of the low pressure steam to reheat condensate, the use of a spray pipe, header, or sparger, can vastly improve the efficiency of reheating condensate up to TSat. Spray pipes may employ a series of drilled holes, or better still, if desired, specialist spray nozzles can be employed to further improve atomization by reducing the condensate to a fine mist, see Figure 5.

Whilst EPRI [6] recommendations on condensate make-up locations matches that of HEI [10], EPRI tends to provide more design details for optimum dispersion. EPRI warns that whilst it is good practice to spray condensate high over the tube bundle, it goes further by stating that the design of the make-up connection should provide:

(i) good distribution, ...without overloading the bundle, (ii) have low fluid velocities, and use, (iii) small diameter holes in headers to avoid damage to tubes. EPRI guidelines limit condensate sprayed onto tube

bundles to between 6 to 10 ft/sec, and recommends the release point be no more than 2 feet above the bundle to limit acceleration of the condensate and possible erosion. Heating of condensate which enters a condenser at a temperature below that of saturation, is critical to reducing dissolved oxygen content. With no thermal energy relative to the condenser, considerations are primarily to accommodate pressure and flow-rate. Upstream valves, or orifice plates, should be sized to pass the design flow-rate of condensate. Dispersion of the condensate is the prime concern, such that distribution is maximized and discharge velocities limited.

Materials of construction for condensate make-up headers should be properly considered. Stainless steel is preferred and regularly utilized due to its superior corrosion resistance in relation to carbon steel. This is clearly advantageous when dealing with condensate make-up which can contain relatively high levels of dissolved oxygen, and promote erosion and corrosion when carbon steel pipe is used, see Figure 10.

Figure 10: Eroded Condensate Make-Up Spray Pipes (C/Steel). Optimizing the design of the internal dispersion device

utilized for condensate make-up, as well as utilizing the preferred location, are two very effective improvements that can be made to existing plants in helping to reduce dissolved oxygen levels. It should be noted that whilst these are two improvements that can help to achieve guarantee levels, the success of these methods is still limited by the previous design guidelines as noted, see also Section 5.

The proper design and location for connections can usually be achieved at relatively low cost, see also Section 9, appended CASE STUDY for further details of how recommendations in Sections 6.4.1 and 6.4.2 have been implemented on an existing unit.

Where guidelines for connection location, and/or internal dispersion design cannot be effectively, practically or safely


achieved – and where high levels of condensate are required to be handled, then the use of an appropriately designed Hotwell Sparger, see also Section 6.5, should be considered. For very high condensate make-up levels, the use of a Vacuum Deaerator, see Section 6.6, must be seriously considered and evaluated. 6.5 INSTALL A HOTWELL SPARGER

For start-up and low load operation, the installation of additional steam heating into a condenser has proved to be effective. This most commonly takes the form of a submerged steam header that is located within the hotwell. It is usually located several inches above the bottom plate, such that it remains submerged at all times. Often referred to as a Hotwell Sparger, steam enters the hotwell condensate via holes, or spray nozzles, and is equally distributed throughout the length of the sparger piping, see Figure 11. Sparging steam requirement is typically about 1% of the full load condensation rate.

Figure 11: Hotwell 3-D Model (Cut-Away), Typical Sparger (in Green). Hotwell spargers are usually designed to serve two

different, but equally important, functions: (1) Start-Up: The hotwell sparger can be used during

start-up to heat standing condensate up to the desired temperature, usually equivalent to that of the saturation temperature based on guaranteed back-pressure. This minimizes the effects of ‘cold’ condensate on the plant during start-up operations, thereby reducing the need to remove dissolved oxygen further downstream. A viable steam source is required during plant start up, but this is not always possible.

(2) Low Loads: For power plants that may cycle frequently, a hotwell sparger can also be utilized at low loads to reheat condensate to a temperature higher than is to be expected, but equal to that which is desired.

With a hotwell sparger, the condensate is only being reheated, and the dissolved oxygen is still removed by the condenser via the Venting Equipment. Note that it is possible to overload the condenser venting system, if this operation is not accounted for within the original condenser design.

Whilst the use of a hotwell sparger is very effective for start-up, it has some limitations at low load operation. In addition, retention time in the hotwell at low loads is not ideal, so the hotwell sparger is more efficient for use during start-up

with standing condensate than at low load operation when the retention time can be insufficient for reheating the condensate to the required temperature.

6.6 USE A (VACUUM) DEAERATOR

Deaerators, of various types, have been an essential part of most steam systems for many years. Whilst dissolved oxygen can be removed chemically, with the use of scavengers (e.g. tannin, hydrazine, etc.), there are limitations to this approach. Chemical treatment requires accurate dosing control, which can often be very difficult to achieve due to poor mixing at high volumes and varying loads. As well, it also brings additional safety & environmental concerns.

Alternatively, dissolved oxygen can be removed mechanically with the use of a Deaerator, which separates oxygen and other dissolved gases. This is by far the most efficient and economical method rather than chemical dosing.

Most Deaerators use one, or both, of two basic principles for removing oxygen and dissolved gases:

Figure 12 (Left): Vertical Vacuum Deaerator Schematic. Figure 13 (Top Right): Typical Self Adjusting Spray Nozzles. Figure 14 (Bottom Right): Typical Trays.

(1) Spraying: Condensate is usually sprayed into a section of

a vessel where it is pre-heated using rising steam, see Figure 12. Self-adjusting, high performance spray nozzles are typically utilized, such that incoming condensate, (which is to be deaerated) discharges as a thin-walled hollow cone, see Figure 13. Steam, which flows counter current to the hollow cone of condensate spray, now has a vastly improved contact surface area and volume, such that optimized latent heat transfer can occur. Spraying can typically attain approach temperatures between the make-up condensate and steam, of as low as 1°F. Most of the dissolved oxygen and gases (incl. free carbon dioxide) will be removed at this stage. At this point nearly all of the


steam is condensed and the non-condensible gases can then safely exit via the vent piping. Usually, a separate liquid ring vacuum pump, or steam jet air ejector, is designed and supplied for this purpose.

(2) Trays: The condensate, at a temperature equal to, or within a few degrees of, the steam saturation temperature, can then flow liberally over a series of specially designed Trays, see Figure 14. These Trays usually involve special geometric configurations, and/or perforated plates, to improve contact surface area and volume - thereby also promoting additional mixing and extended contact with the counterflow steam. The use of Trays increases the retention time to allow the final vestiges of oxygen and dissolved gases to be stripped from the condensate by the steam. These two methods are best combined to effectively and

efficiently remove as much oxygen and dissolved gases (a.k.a. non-condensible gases) as possible. The combination of these two methods; often referred to as ‘Spray and Tray Type Deaerators’, is the most reliable approach for meeting critical performance parameters for a number of design cases. The ‘Spray and Tray’ approach, see Figures 12, 13 & 14, can reduce oxygen concentration to levels less than 7ppb over a very wide range of operational criteria.

Figure 15: Spray & Tray Type Deaerator for Axial Condenser (CCGT). When there is a requirement that the surface condenser be

designed to handle very high volumes of condensate below Tsat,

with a requirement to maintain relatively low levels of dissolved oxygen, across a wide spectrum of operational scenarios - the use of a deaerator is therefore by far the most effective method for achieving this. Large volumes of make-up can be directly routed to a deaerator such that the condensate is reheated and deaerated prior to even entering the condenser.

In the case of power plant steam surface condensers, a Spray and Tray Type Deaerator, designed to work under Vaccum, should be used. Often these are referred to as simply ‘Vacuum Deaerators’. Typically, they are comprised of a vertical cylindrical tank, with upper and lower dished heads,

supported on legs, see Figures 12 and 15. The upper body (dome) of the tank will contain a number of self-adjusting high performance spray nozzles [as noted in (1) above] which are supplied with condensate from an internal make-up distribution header. The center section of the body of the deaerator will contain an arrangement of trays, below the steam dome area, to further promote reheating [as noted in (2) above]. Reheated condensate is then collected in the lower dished head and immediately routed to the condenser via drain piping. Adequate space is allowed around the trays for proper steam distribution and improved performance.

Steam to the vacuum deaerator can be supplied directly from the condenser at low pressure, or, via a separate external source for higher pressure auxiliary (or ‘pegging’) steam. The deaerator works under vacuum alongside the condenser, see Figure 15, and should be designed accordingly. Special attention should be paid when auxiliary steam is used, as an appropriately designed steam diffuser, internal to the vacuum dearator, is often required. Most vacuum deaerators are in fact routinely designed per ASME Section VIII, Div.1 [1] - but rarely are they code stamped in practice when used in combination with a steam surface condenser.

The use of a vacuum deaerator offers great flexibility when dealing with massive volumes of highly oxygenated condensate, which exceed the guidelines as noted within HEI Standards [10], see also Section 5 and Figure 7. Using a vacuum deaerator provides an effective method for dealing with large volumes of condensate below Tsat, such that reheating and deaeration can be quickly and effectively achieved. It should be noted that there is usually no storage within these vacuum deaerators, as the storage requirements should be included within the surface condenser design. In this light, a drain connection should be sized accordingly to allow the deaerated and reheated condensate to immediately flow down into the condenser hotwell, via a loop seal, if one is deemed necessary, see Figure 17.

For very large make-up requirements, e.g. make-up above 100% of steam flow from the LP exhaust, larger horizontal deaerators, with a separate storage tank & multiple condensate make-up and drains to the condenser hotwell can be utilized.

Venting of vacuum deaerators is very important, and it is usually best to use a liquid ring vacuum pump, or steam jet air ejector for this purpose. These are usually provided separate to the main condenser venting equipment. Piping between the condenser and vacuum deaerator should be kept to a minimum. This is rarely an issue as space is typically restricted in plants. Most vacuum deaerators are often ‘close coupled’ to the steam surface condenser, and even supported on structural steel mounted off of the condenser itself, see Figure 17.

7. MULTI-PRESSURE CONDENSERS

Whereas single pressure units, when operating under ideal guarantee case conditions, will produce little to no sub-cooling, the design of multi-pressure units is such that they are likely to experience a higher degree of sub-cooling during operation.


This is due to the fact that as cooling water passes through each of the zones/shells in a multi-pressure unit, condensing efficiency decreases and the steam side absolute pressure, and corresponding condensate saturation temperature, also increases in each pressure zone. Condensate in each of the pressure zones will therefore be at differing temperatures, with the lowest temperature in the first or lowest pressure zone. Condensate is therefore ideally removed from multi-pressure units at the conditions corresponding to high(er) pressure shell, as this will give the highest temperature and accordingly therefore the lowest dissolved oxygen levels. However, cooler condensate from the low(er) pressure shell/s will require to be reheated to a temperature as close as is practically possible to equal that of the high(er) pressure shell. In order to properly achieve this, condensate is typically ‘cascaded’ between the shells in a multi-pressure unit, see Figure 16. The use of a well designed reheat system is required to achieve optimal reheating of the condensate, and should be capable of achieving a reheat rate of 80%, or better, of the temperature difference between the respective shells and pressure zones [10].

Reheat systems that are not properly designed, operated incorrectly and/or simply damaged, will therefore lead to a higher degree of sub-cooling resulting in higher overall levels of dissolved oxygen in the resulting condensate extracted from the unit. Reheat systems should always be reviewed when dissolved oxygen levels are an issue in multi-pressure units.

Figure 16: Typical Twin-Shell, Dual-Pressure Condenser

8. COMBINED CYCLE OPERATION

It is noteworthy that several Heat Recovery Steam Generator (HRSG) designs have appeared on the market in recent years which advertise the ability for ‘fast-start up’. The latest generation of Combined Cycle Gas Turbine (CCGT) power plants, are now starting to include these HRSG’s. The ‘fast start up’ HRGS’s designs can have aggressive targets for start-up, and often operate with frequent load swings. This complicates the steam cycle chemistry issues to some degree, and places a further burden on the condenser to maintain lower levels of condensate dissolved oxygen.

As previously noted, dissolved oxygen levels are adversely affected during start-up, shut down and low load operation. Whilst higher than expected levels of dissolved oxygen were acceptable on the basis of being off-design and short-lived infrequent modes of operation; for example say on a base loaded fossil plant - it is now no longer acceptable for some combined cycle plants. This is due to the more frequent nature of the start-up/shut-down and low load operation together with the higher rate of cycling on these ‘fast start up’ CCGT plants.

Hotwell spargers can be designed and installed to achieve the required dissolved oxygen levels for start-up conditions (that were previously not considered to be guarantee points). Based on retention time within the hotwell, even a hotwell sparger may not be best suited to some of the shorter ‘fast-starts’. The use of a vacuum deaerator is also frequently considered to meet dissolved oxygen levels over a wider spectrum of operational scenarios. The combined use of a hotwell sparger and a vacuum deaerator, often with the ability to handle condensate recirculation, is the most effective approach to guaranteeing dissolved oxygen levels are maintained at the lowest possible levels at all times.

Figure 17: Typical Vacuum Deaerator (Repower Project [4]) Hotwell spargers and vacuum deaerators can be retro-fitted

onto existing plants, and they have even been utilized successfully in several repowering projects [4], see Figure 17.

9. CASE STUDY: CONDENSATE MAKE-UP REDESIGN

HISTORY: Existing Fossil Plant, 200,000 ft2 Twin-Shell, Dual Pressure Condenser Unit, early 1970’s. Subsequent plant degradations, improvements and some ad hoc modifications had all had an effect on dissolved oxygen levels which had been running at higher than expected/guarantee levels for some years. On review the plant’s desire was to implement a combination of procedures, modifications and upgrades to lower the condensate dissolved oxygen to the lowest practically achievable level. Helium leak testing had helped to reduce air in-leakage to below acceptable levels, and assisted in reducing dissolved oxygen levels, but not as much as desired – so air in-leakage was not considered to be a root cause. Detailed analysis of performance data revealed continued ‘spikes’ in the levels of dissolved oxygen coincided directly with the


operation of the make-up connection on the unit. Further investigation of the make-up connections design and operation was therefore warranted. Results of the Study are as follows.

ORIGINAL Connection Details: The condensate make-up connection original (as supplied) design details were:

Connection: 6”, Condensate Make-Up. Operation: Intermittent (matched DO2 ‘Spikes’) Location: Side of Bundle (less than Halfway Up). Internal Design: Perforated Cage with Plate Cap. Temperature: 100 Deg.F Flowrate: 90 US GPM (45,000 lb/hr) LP Shell A: 3.17 inHgA, TSat = 117°F (Design) LP Steamflow: 1,600,000 lb/hr (Design) CW Inlet: 95°F (Design)

Operational Review: The temperature of the make-up, 100°F, was well below the corresponding saturation temperature of 117°F. In this light, the condensate make-up would therefore require reheating and deaeration. In addition, the percentage of make-up in relation to the LP steam flow was also reviewed, the condensate make-up represented a little less than 3% (45,000/1,600,000 = 2.8%) of the LP steam flow. Therefore, per HEI Standards [10], see Figure 7, the unit should be able to adequately reheat this level of cold make-up and still achieve less than 7 ppb. Plotting the CW Inlet Temperature (T1=95°F) against the Design Saturation Pressure (PSat=3.17inHgA) onto the HEI Oxygen Limit Curves, see Figure 6, also predicted that the Unit should be easily capable of achieving 7pbb or less. Clearly, the operational conditions were not a factor with the high DO2 issue experienced.

Design Review: The location of the make-up connection was in the side of the shell, halfway down the tube bundle. The location of the condensate make-up was clearly not ideal. The internal dispersion consisted of a simple rolled perforated plate, with a solid plate cap.

CONCLUSION: The operation of the connection was within current HEI guidelines, but the location was not. Also, the internal dispersion was deemed wholly inadequate as it severely limited distribution and therefore reheat & deaearation capability, see Figure 18. A complete redesign and relocation was necessary,

NEW Connection Details: The condensate make-up connection was to be redesigned to address both the (i) location and (ii) distribution.

Location: It was highly desirable for the plant not to have to relocate external piping due to the high cost impact. It was also a requirement to perform all modifications in as least time as possible during an upcoming outage. It was decided to re-route piping internally within the condenser to achieve these two goals, i.e. lowest cost and shortest time frame. Available system head pressure had first to be reviewed to ensure that the increase in elevation of the spray pipe was possible, whilst maintaining the supply pressure to acceptable limits - and per HEI guidelines.

Figure 18: BEFORE – Existing Make-Up Connection. Figure 19: AFTER – NEW Make-Up Spray Pipe.

Low Press. Steam

Non-Cond. Gases

Cond’sate High DO

Cond’sate Low DO


Dispersion: The location of the connection was such that optimal dispersion for reheating could not be achieved but nonetheless, separately, the design of the existing internal dispersion device was also deemed to be inadequate to achieve optimized reheating and deaeration. The perforated cage with the solid end cap was ineffective – (i) it had a small relative cross-section, (ii) the size of the holes in the perforated plate were relatively large, such that they were not optimizing the spraying of the condensate so that atomization could occur, and (iii) the perforated cage did not spray condensate over the bundle. The internal dispersion was such that the reheating effect was severely limited; this likely resulted in most of the associated dissolved oxygen being directed into the hotwell condensate.

The perforated cage was replaced with a new custom-designed spray pipe, with smaller drilled holes, to effect maximum dispersion of the condensate over a much wider cross-sectional area. The spray pipe was located above and over the entire width of the adjacent tube bundle, massively increasing the both the dispersion within the transition plenum, and contact area over the tube bundle.

Modification: As Figure 18 shows, the location and internal design of the existing connection was not ideal. A review of the design and operational parameters summarized that modifications were required to both the location and internal design. Once the new design and location was finalized, all of the parts were pre-fabricated in an off-site shop, with the parts being fabricated to the maximum extent possible such that field welding was kept to a minimum, reducing the installation time frame. The newly designed and located connection, see Figure 19, has drastically improved and lowered the dissolved oxygen levels within the condenser.

RESULTS: The new spray pipe was designed, supplied

and installed within budget and ahead of schedule. Installation during the outage was achieved with no issues. Benefits of the condensate make-up redesign included.

Spray Pipe above vs Baffle on side of Bundle!! Increased Distribution Area & Volume. Improved the Contact/Residence Time. Reheating was vastly improved. Dissolved Oxygen liberated IN Bundle. Dissolved Oxygen removed from Bundle via Air

Draw Off, Vent Duct & Vacuum Equipment. Eliminated “Spikes” in DO2 during Make-Up. Reduced DO2 by up to 21 ppb, and below 7ppb.

Once the unit went back into service and the make-up

connection operated (as it had been previously) the ‘spikes’ in dissolved oxygen were eliminated and there was a noticeable improvement in dissolved oxygen together with a reduction in sub-cooling also.

10. SUMMARY Clearly, a number of very different factors influence the

condensate dissolved oxygen levels produced within steam surface condensers.

Understanding the design limitations of a steam surface condenser (and associated venting equipment) is the primary starting point when reviewing ways to possibly improve condensate dissolved oxygen levels. OEM information such as data sheets and predicated performance curves should provide this information. HEI Standards [10,11] can also be consulted to determine expectations for unit performance with respect to dissolved oxygen.

Air in-leakage should be kept low, leaks located & fixed as soon as possible, as they are typically the single largest source of oxygen in any condenser. Regular inspections are recommended as a part of any routine maintenance plan, and leak testing (should it be warranted) is a key aspect of this, e.g. Helium leak testing. Effective control of leaks is often the single most important aspect of helping to minimize and significantly reduce levels of dissolved oxygen in any plant.

The amount of make-up condensate entering a condenser, at temperatures below saturation, should be known. The internal design, dispersion method and location of condensate make-up drains should be reviewed to ensure that the optimum reheat is effected at all times. Redesign of ineffective condensate make up drain connections can be a relatively low cost improvement, as previously shown.

A hotwell sparger should be considered to provide additional reheat, for low load, cyclic or transient operation. Vacuum deaerators can be used to great effect, for handling high volumes of ‘cold’ condensate make-up, where necessary. The use of both of these methods should be seriously considered to provide the lowest possible levels of dissolved oxygen for a wide range of design cases and varying loads.

Reheat systems in multi-pressure units should be properly designed and in good working order. The condition of reheat trays and false bottom plates should be frequently checked to ensure sub-cooling is kept as low as possible.

Finally, condensate dissolved oxygen levels should be frequently monitored with recorded (actual) levels compared to design (expected) levels when reviewing unit performance. Increases in dissolved oxygen levels should always be investigated, whilst the target aim should be to keep them within expectations at all times. Fluctuations, especially ‘spikes’ or dramatic increases, should never be ignored, but always investigated. Required repairs, replacements, modifications and/or improvement should never be deferred - most are typically low cost in relative terms, and can have attractive pay backs. These design and operation elements are both critical aspects when controlling the levels of dissolved oxygen within steam surface condensers, and helping to maintain them at the expected levels.

HEI Standards [10,11] also include a Troubleshooting Guide that provides more details for operators of steam surface condensers, and can be referenced for dissolved oxygen issues.


ACKNOWLEDGEMENTS (WEB) American Society of Mechanical Engineers (ASME) – www.asme.org Electric Power Research Institute (EPRI) – www.epri.com Heat Exchange Institute (HEI) – www.heatexchange.org Lechler Incorporated – www.lechlerusa.com Sterling Deaerator Company – www.sterlingdeaerator.com

REFERENCES [1] ASME Boiler & Pressure Vessel Code (BVPC), Section VIII, Divisions I, II & III, 2015.

[2] ASME PTC 12.2-2010 [Revision of PTC 12.2-1998 (R2007)], Steam Surface Condensers, Performance Test Codes.

[3] ASME PTC 12.3-2014 [Revision of PTC 12.3-1997 (R2014)], Performance Test Code on Deaerators.

[4] ASME POWER2014-32030, “CASE STUDIES: Nueces Bay, Unit #7 & Barney Davis, Unit #2 for Topaz Power. The successful Turnkey Repowering of existing Steam Surface Condensers from traditional Rankine to a 2x1 Combined Cycle configuration.” ©2013 by ASME.

[5] ASME Steam Tables [IAPWS 1997], ©2006 by ASME.

[6] EPRI CS-2251, (Feb. 1982), “Recommended Guidelines for the Admission of High Energy Fluids to Steam Surface Condensers”, EPRI CS-2251, Project 1689-1, Final Report, February 1, 1982.

[7] EPRI NP-2294, (March 1982), “Guide to the Design of Secondary Systems and Their Components to Minimize Oxygen-Induced Corrosion”, Project S189-1, Final Report, March, 1982. [8] EPRI NP-6945, (August 1990), “Oxygen Control in Makeup Water for PWRs”, Project S402-1, Final Report, August, 1990.

[9] Heat Exchange Institute, Inc., “Standards for Steam Surface Condensers”, 5th Edition ©1965.

[10] Heat Exchange Institute, Inc., “Standards for Steam Surface Condensers”, 11th Edition ©September 2012.

[11] Heat Exchange Institute, Inc., “Standards for Steam Surface Condensers”, 11th Edition Addendum 1 ©August 2014.

[12] Heat Exchange Institute, Inc., “Standards for Liquid Ring Vacuum Pumps”, 4th Edition © 2011.

[13] Heat Exchange Institute, Inc., “Standards for Steam Jet vacuum Systems”, 7th Edition ©October 2012.

[14] Perry’s Chemical Engineers’ Handbook, 6th Edition (50th Anniversary International Edition) ©1984 McGraw-Hill, Inc.

[15] Putman, Richard E., (2001). “Steam Surface Condensers: Basic Principles, Performance Monitoring, and Maintenance”. ASME Press.

[16] VGB-R 126 L e, “Recommendations for the Design and Operation of Vacuum Pumps at Steam Turbine Condensers”. VGB-Kraftwerkstechnik GmbH (Reprint 1995)

NOMENCLATURE The following Nomenclature has been used and referenced

throughout this Paper.

Symbol Description US Units S.I. Units DO/DO2 Dissolved Oxygen ppb µg/L NCG Non-Condensible Gases SCFM SCMM PS Saturation Pressure inHgA mmHgA T1 Inlet Water Temperature Deg.F Deg.C TD Temperature of Depression Deg.F Deg.C TSat Saturation Temperature Deg.F Deg.C Ws Steam Flow lb/hr kg/hr


Revision Date Status By

A 12-28-15 DRAFT DMN

B 12-30-15 DRAFT DMN

C 12-31-15 DRAFT DMN

DRAFT PAPER ACCEPTED 2-09-16 (COMMENTS)

D 2-12-16 REVISED DMN

E 3-14-16 FINAL DRAFT DMN

F 3-21-16 FINAL DMN

Fa 4-14-16 FINAL DMN


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