glaxosmithkline - armstrong inc.€¦ · glaxosmithkline mississauga, ontario steam and condensate...

©2010 Armstrong Service, Inc.

GlaxoSmithKline Mississauga, Ontario

STEAM AND CONDENSATE AUDIT REPORT

Project No: ASIR-10125-01-1210

Prepared for:

Neil Young – Project Engineer Technical 7333 Mississauga Road, Mississauga, Ontario, Canada L5N 6L4

Phone: 915-819-3000

January 10, 2010

Prepared By:

Armstrong Service Inc 8615 Commodity Circle, Suite 17

Orlando FL-32819

Ph: 407-370-3301 / Fax: 407-370-3399

STEAM AND CONDENSATE AUDIT

ASIR-10125-01-1110

GSK Mississauga, Ontario

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To the attention of Mr. Neil Young

Prepared by N. Iordanova

© 2011 Armstrong Service, Inc.

NOTICE This proposal has been submitted to GlaxoSmithKline (GSK) Mississauga, Ontario in confidence and it contains trade secrets, as well as privileged information, and/or proprietary work product of Armstrong Service, Inc. (ASI). In consideration of the receipt of this Proposal and the information and data herein, Recipient agrees that it will use this document and the information contained herein only for internal use and only for the purpose of evaluating a business transaction with Armstrong. Recipient agrees that it will not disclose this Proposal or any part thereof to any third parties and Recipient may only disclose this document to those employees involved in the evaluation of a business transaction with Armstrong, on an as need basis. Recipient may make only those copies needed for such internal review. Upon conclusion of business discussions, this document and all copies shall be returned to Armstrong upon its or their request.


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TABLE OF CONTENTS

EXECUTIVE SUMMARY .......................................................................................................... 4

1 STEAM BUDGET AND SUMMARY OF POTENTIAL SAVINGS ....................................... 6

2 OPTIMIZATION PROJECTS ............................................................................................. 9

2.1 OPTIMIZATION PROJECT # 1: REDUCE STACK LOSSES – CONTINUOUS FEED WATER

CIRCULATION ............................................................................................................................................ 9

2.2 OPTIMIZATION PROJECT # 2: BLOWDOWN REDUCTION......................................................... 18

2.3 OPTIMIZATION PROJECT # 3: DEAERATOR VENT STEAM RECOVERY ..................................... 21

2.4 OPTIMIZATION PROJECT # 4 INSTALL REMOVABLE INSULATION ............................................. 25

2.5 OPTIMIZATION PROJECT # 5 STEAM TRAPS .......................................................................... 34

2.6 OPTIMIZATION PROJECT # 6A HEATING HOT WATER HEAT EXCHANGERS - RETURN CONDENSATE

TO THE DA .............................................................................................................................................. 39

2.7 OPTIMIZATION PROJECT # 7A DOMESTIC HOT WATER HEAT EXCHANGER - RETURN CONDENSATE

TO THE DA .............................................................................................................................................. 43

3 CHECK LIST VERIFICATIONS COMPLETED DURING THE AUDIT .............................. 46

4 RECOMMENDED ADDITIONAL STUDIES ..................................................................... 48

4.1 PROJECT 6B HEATING HOT WATER HEATER – FLOODED HEAT EXCHANGER .................................. 48

4.2 PROJECT 7B DOMESTIC HOT WATER HEATER – FLOODED HE AND CTE DIRECT NG FIRED HE .... 49

4.3 PREHEAT RO WATER THROUGH HEAT RECOVERY ........................................................................ 50

4.4 REDUCE USE OF CHILLED WATER IN COMPRESSED AIR COOLING ................................................ 51

4.5 REPLACE ELECTRIC COIL WITH STEAM COIL FOR REGENERATION AIR AT AHU 518 GLATT ............ 52

5 ADDITIONAL OBSERVATIONS AND RECOMMENDATIONS ........................................ 53

5.1 BEST PIPING PRACTICES AND STEAM TRAPS INSTALLATION ......................................................... 53

6 CLOSING ........................................................................................................................ 59


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EXECUTIVE SUMMARY During the period of November 16th through 19th of 2009, ASI conducted an energy audit of the steam system (generation, distribution, and users), and condensate return at GSK, Mississauga, Ontario. ASI estimated the potential energy savings of 12.7% of the current yearly steam budget ($515,438 / 74,637GJ, or 70,790 MMBTU or 20.73 GWh), which represents a yearly estimated saving of 9,000 MMBTU or 2.8 GWh, 479 tons of CO2, and $67,490. After the walkthrough ASI concluded that overall, the plant is in a very good shape and many energy savings projects have been already implemented, i.e.:

• Multiple small boilers installation for best performance at any steam load

• Economizers installation

• Elimination of flash steam through flooded heat exchangers

• Fresh boiler room air (combustion air) preheating by flash steam

• Hot exhaust air heat recovery to cold regeneration service air (before steam coil) on dehumidification desiccant dryer wheels

• Insulation of pipes and removable insulation on equipment requiring access for maintenance

It was mutually decided between GSK and ASI that the major opportunities for further improvements (cost savings and reliability) are in the following two areas:

• The boiler room, where the steam is generated and the equipment is concentrated in one location, represents the most opportunities. Although the system is very efficient, improvements can be made from a reliability stand point (multiple pumps serving a common feed water (FW) header to boilers) and for more efficient operation (improve economizers and prevent flash steam venting).

• The steam distribution systems, insulation, and steam traps which always provide opportunities for energy, reliability and safety improvements.

The steam users do not provide feasible opportunities for energy improvements. These users are hot water systems (heating and domestic), dehumidification units (desiccant dryer wheels), clean steam generators (CSG), process air heating units (AHU), and environmental air handling


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units. Many of the process heat exchangers on AHUs have been converted to operate under flooded condition. Based on the ASI audit a minimum of 2.5% of the savings are expected from the steam generation areas, related to operation practices and overall boiler room efficiency improvements. The majority of these savings will be achieved with the continuous heat recovery from the economizers and the vent condensers on the deaerator vent. There is potential for another 8.9% energy savings related to the steam distribution. Steam

leaks were not observed anywhere in the plant except on one safety relief valve which was already addressed by plant personnel (the needed part was ordered). In general, the steam

distribution system is well maintained and insulated, with few exceptions. A sample steam trap survey was performed and many steam traps on the high pressure (HP) steam applications were found to be failed. Failed steam traps (blowing through) need to be addressed even if they discharge to flash tanks and do not have direct steam losses. They may create high pressures in LP lines and trigger popping of safety relief valves. The feasible energy savings related to the condensate return are associated with flash steam reduction from the hot water (HW) heaters in the boiler room. All four heaters have closed condensate returns, which may add more than 1% savings if routed directly to the deaerator

(DA). Both of these HW systems were looked at for conversion to flooded heat exchangers, which will lead to the same savings. However, it should be noted that additional data collection needs to be performed (HW flow information needs to be collected and analyzed), which will allow GSK to make an educated decision for the future of the discussed projects. Several more projects, some related to other utilities but affecting the fuel consumption in GSK, were left for additional study and will be described only briefly in the report:

• Preheat RO water. Now using steam to preheat water up to 24C.

• Reduce DA pressure and improve controls. Currently it is maintained at 5 to 20 psig.

• Eliminate electric heating in AHU518 dehumidifier regeneration air.

• Reduce the use of chilled water in compressed air cooling. Even though a compressed air audit was already done, there may be an opportunity to reduce the energy associated with the CA generation. Additional audits may be performed.


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1 STEAM BUDGET AND SUMMARY OF POTENTIAL SAVINGS Total annual steam generation - 59,718 klbs/yr (27,083 tons) Steam Cost - $8.63/klbs ($18.99/ton) Annual Steam Fuel Budget - $515,438. Below is the summary of identified energy-saving improvements and their estimated annual benefits.

The above savings are calculated based on utility data and costs for the past 12 months, and information gathered during the audit. For the systems in which information was not available, engineering assumptions were made based on observations and standard engineering practices.


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The investment costs are estimated based on data and experience from similar projects implemented in the past. Utility data and costs for the past 12 months.

The natural gas (NG) is metered for the entire plant, as well as, separately for the LOC and the GMS areas. The four Miura boilers consume 100% of the NG to the GMS area presented in the table below (past 12 months). The NG consumption for the months of November and December of 2009 were estimated as a percentage from the available data for the total to the site NG.


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2 OPTIMIZATION PROJECTS 2.1 OPTIMIZATION PROJECT # 1:

Reduce Stack Losses – Continuous Feed Water Circula tion

Current System Description and Observed Deficiency There are four Miura LX-200 SG boilers installed in 1993. They operate year round to satisfy the process steam needs. The load is generally stable throughout the year varying between 5,000 lbs/hr and 10,000 lbs/hr (average 6,817 lbs/hr). Each boiler is equipped with an economizer. The economizers design capacity is 173,000 BTU/hr rated heat absorption. The boilers are tuned twice per year. Based on the data from the last combustion analysis performed in October 2010, the boiler’s operation and efficiencies were analyzed at low and high fire, based on readings for excess O2%, CO ppm and stack temperature. The summarized combustion test reports data and the calculated overall boiler efficiency (including radiation losses of conservative 0.75%) before the economizer are included in the tables and charts below. The feed water (FW) pumps operate in an “On/Off” mode. Additionally, an On/Off control valve is located before the economizer. Presently, the economizers do not have continuous water supplied to them. The on/off operation of the FW flow limits the heat recovery from the economizer, only to the time when the pump is on. The schematic below presents the existing arrangement and operation of the system. Each boiler has single individual pump, which reduces the reliability of the steam supply system, in case of a pump failure. The deaerator (DA) is maintained between 5 psig and 20 psig the majority of the time being at 15 psig.


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There is no steam or feed water meters installed on the main headers and the actual steam generation can only be calculated based on the boiler efficiency. After the economizer the feed water temperature rises 20°F to 25°F. Discussion Essentials of low excess air boiler operation: Combustion is a chemical reaction in which a fuel constituent reacts with oxygen to release heat. As a result, all fuels need oxygen, and the natural available oxygen source is air. However, air contains nitrogen that has no role in the combustion reaction except absorption of a portion of the released heat of reaction. Every cubic foot of oxygen brings four cubic feet of nitrogen along with it. This unwanted nitrogen leaves the boiler stack as a part of waste gases, taking with it a portion of the heat released from the fuel. Hence, the quantity of unwanted nitrogen has to be kept at a minimum by controlling the excess oxygen level in stack gases. The optimum excess air level depends on the type of fuel and burner design. In general, gas burners are designed to operate at 10 - 15% excess air (2% to 3% oxygen in the exhaust flue gas). The recommended excess air level by the burner manufacturer already includes a safety margin. Any additional margin, if maintained, simply lowers the boiler efficiency. Low NOx burners require slightly higher level of air supply but based on the comparison between the four boilers it’s visible that not all boilers are equally efficient. Boiler #3 and #4 are more efficient in general, while Boiler #2 is efficient on low fire. Boiler #1 could be improved.


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Flue gas/ Stack temperatures Hot flue gases contain a lot of wasted energy. It is beneficial to use/return this energy back into the boiler with heat recovery equipment. Economizers recover energy from the flue gases while preheating the feed water (FW) going into the boilers and lower the stack temperatures. A properly designed economizer reduces the stack temperatures to approximately 50°F above the FW temperature. Presently the FW temperature from the DA varies between 210°F and 240°F and the stack exhaust gas temperatures after the economizers could be around 290°F. At present the DA has steam supply valves to maintain the pressure. If the FW is re-circulated, the economizer can operate continuously and reduce the stack temperatures. Optimization

ASI recommends:

• For energy savings - converting the water supply to the economizers to a continuous flow supply will increase the heat recovery from the economizers. A better heat recovery will be achieved if the DA pressure is maintained at 5 psig.

• For reliability Improvement - converting the feed water supply to a common supply header will assure the boilers not being dependent on a single pump.

To achieve this, the following is recommended:

• Relocate the On/Off control valve from upstream of the economizer, to between the economizer and the boiler.

• Install a tee and a new recirculation pipe to the DA with an On/Off control valve on it.

• Coordinate the signals to the present valve and new valve to operate in an opposite manner. If the main valve is On, the recirculation valve to be Off, and visa-versa. A second control signal from the boiler will assure that if the boiler is Off, the recirculation valve is Off.

• Tie-into the present FW pipe coming from the DA and create new header to feed the pumps.

• Relocate the four pumps from at the boilers, to a common location. The existing isolation valves, strainers and check valves will be used.

• Control for the pumps will be based on the pressure in the FW header.


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• Create a common header after the four pumps and extend the header to connect with the FW supply pipes to each boiler.

To assure the most savings are achieved the boilers need to be put in operation at their most efficient range, unless they are re-tuned for equal efficiencies. Boilers #3 and #4 can operate at


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any firing level, while Boiler #2 is preferred to operate at low loads. Boiler #1 is the least efficient among the four and should be operated the least hours, unless retuned. Savings Lowering the flue gas temperatures from the observed level down to a conservative 290°F will save $9,200 annually. The savings are calculated based on the past 12 months NG

consumption and the respective calculated efficiencies.

Estimated Investment and Payback The budgetary costs for this project are $85,000 and exceed the 5 year payback (9.2 years). Considering the reliability of the steam generation process the plant may evaluate it further and take actions. Included in the project:

• Design

• Equipment supply (controls and panel for pumps, pressure transmitter, on/off solenoid valves on recirculation, piping and valves as applicable.

• Existing on/off control valves and pumps, including surrounding valves, strainers and check valves will be reused.


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• Relocation and installation by a mechanical contractor

• PLC programming.

• Project management and start-up


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Detailed Calculations


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2.2 OPTIMIZATION PROJECT # 2:

Blowdown Reduction

Current System Description and Observed Deficiency The continuous blowdown (BD) percentage is calculated at 3.3%. The water treatment analysis reports from GE Betz and the field tests performed during the audit show the boiler water sodium sulfite levels are much higher than recommended, varying between 160 ppm and 180 ppm. The recommended limits for the oxygen scavenger are normally between 30 to 60 ppm.

The boiler operator also collects daily data about the boiler water quality.

There is no BD heat recovery system installed. Cold water is used to bring down the temperature of the liquid before it is discharged to the sewer.


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Discussion In the generation of steam, most water impurities come with the FW and are not evaporated with the steam therefore, they concentrate in the boiler water. In the DA, the oxygen from the feed water is mechanically removed however, an additional chemical oxygen scavenger (sodium sulfate) is added to completely prevent the boiler and the piping from corrosion from oxygen. With the addition of chemicals in the FW, the BD rates increase and create excessive removal of hot water resulting in increased boiler fuel, feedwater, and chemical consumption. Therefore, establishing optimum oxygen scavenger addition, and respectively BD levels, to maintain acceptable boiler water quality presents a significant energy conservation opportunity. Optimization ASI recommends lowering the residual sodium sulfite levels down to 60 ppm. The chemical treatment company was consulted during the study and agreed with the proposal. The control of the sodium sulfites will be improved by installing the new controller (Lakewood 1575). If the scavenger limits are maintained at the lower level the BD percentage could be reduced from 3.34% (present) down to 3.21%. Savings The implementation of this project will save $236 annually.


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Estimated investment and Payback There is no investment associated with this project. The payback is immediate.


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2.3 OPTIMIZATION PROJECT # 3:

Deaerator Vent Steam Recovery

Current System Description and Observed Deficiency The plant has one deaerator with a design load of 30,000 lbs/h. A significant plume through the deaerator’s vent was observed during the audit. The estimated amount of vented steam lost to the atmosphere was 50 lbs/hr. The deaerator operational parameters are shown below:

Deaerator Operational Parameters Feedwater Load Lbs/hr 10,000 Deaerator Pressure Psig 15 Deaerator Temperature oF 240

The condensate is returned at 170°F and is estimate d at 80% of the steam load. The rest is compensated by the make-up water (MUW). The MUW is not preheated and the average annual inlet temperature is 50°F. Two pressure red ucing valves (PRVs) in parallel supply live steam to the DA at 15 psig. The steam heats up the cold condensate and the MUW.

MUW supply to the DA. Steam supply and vent from the DA In the same room is located the domestic hot water (DHW) tank and recirculation pumps and return pipes. Approximately 10 gpm of water is re-circulated and returned to the tank at 5°F to 10°F less than the supply DHW temperature.


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Discussion The deaerator has an important role in the boiler water system since it is designed to remove dissolved gases (oxygen and carbon dioxide) from the boiler feed water. In the deaerator, the steam is used to heat feedwater to a certain temperature. During this process, the dissolved gas continuously emerges from the water and is removed through the vent. A fraction of the steam also is vented out along with non-condensable gases. This vented steam contains energy that can be recovered using a condenser. If a vent condenser is installed, steam and non-condensable gases will flow upward into the vent condensing section where a portion of the steam is condensed. The non-condensable gases are discharged to atmosphere through the vent of the condenser. Optimization ASI recommends recovering the steam from the DA vent by using re-circulated domestic hot water (DHW). Additional to the DHW recirculation water, the MUW, or both, MUW and DHW can be used. The following schematic shows the heat recovery of the vented steam by using 2 vent condensers. The existing vent line will be routed through one or two new small vent condensers, or a combined shell with two tube bundles inside. The two small heat exchangers (HEs) (vent condensers) will be installed in series on the DA vent pipe. As a cooling media, one HE would be using the water from the recirculation pumps from the DHW system (10 gpm), and the other HE would be using the MUW. A needle valve on the MUW pipe will assure the necessary minimal MUW flow (1 gpm to 2 gpm) through HE. To close this valve when the DA is down (and prevent overflow), a solenoid valve needs to be installed and to be automatically shut down, based on the DA level, or the FW pumps are not running.


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Savings The savings from the heat recovery of the flash steam will be $3,637 per year. The saving calculations details are shown in the next table.

Estimated Investment and Payback Budgetary cost for this project is $14,500.

Included:

• No additional design

• Equipment supply (two stainless steel vent condensers, needle solenoid valve and control, temperature gauges)

• Installation by a mechanical contractor

• Project management The payback of this installation is expected to be around four years. If only the recirculation DHW vent condenser is installed, the payback will be reduced to less than two years.


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2.4 OPTIMIZATION PROJECT # 4 Install Removable Insulation

Current System Description and Observed Deficiency

The overall condition of the insulation in the plant is very good, and it improved further with the recently performed phases of insulation surveys and subsequent installations. A third phase of insulation improvements will be performed in 2011. During the audit ASI’s engineer discovered some areas not covered by the previous surveys. As a help for the next stage, it was agreed to list the insulation deficiencies in this report. There were several hot surfaces in the plant that had missing or defective insulation, most being valves and fittings or other equipment requiring frequent access for maintenance or repair. The list of the observed bare surfaces, their location and approximate length, or equivalent length, as well as summary of heat losses and associated savings are included in the subsequent tables. Discussion The basic reasons for insulation are:

• Energy savings: Insulation is primarily used to conserve energy by reducing heat loss to the atmosphere or reducing heat gain from the surrounding;

• Safety/Personnel protection: Protecting plant personnel from burns by keeping surface temperatures below 140oF.

Insulating steam piping does not only mean the main piping. The unions, flanges, and valve bodies should be the target of insulation because of their extended surface areas. The heat losses in the steam distribution lines contribute to an increase in the steam load. Condensate lines and receivers should also be insulated to ensure maximum heat recovery.


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Optimization ASI recommends insulating the bare surfaces above 140ºF, including steam, condensate, and hot water valves, fittings, and piping. Areas with frequent maintenance should be insulated with removable insulation. A total of 29 items were identified and documented with a picture for easier identification. Savings The implementation of this project will save $2,931 annually. The overall savings from this

project are presented in the table below and in details by location, on the next page:

The list of the observed bare pipes, valves, flanges and fittings, and their locations are included in the detailed table. Estimated investment and Payback Budgetary cost for this project is $6,415. Included:

• Equipment supply (removable insulation)

• Installation by plant personnel. Additional cost will occur if a mechanical contractor is used.

The payback of this installation is expected to be around 2.2 years. Priority should be given to the HP steam bare surfaces and to the outside locations, if any, which have the quickest payback


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Details and calculations

Location Description Picture

B5 Boiler Room

DHW Heater – 2” Pressure Reducing

Valve

B5 Boiler Room

Stairs to 3rd Floor – 3” Pipe Condensate, 4” Pipe Feedwater

B5 AHU 519

Regen Air - .75” Control Valve

B5 AHU 570-

F2

Humidifier – 1.5” Control Valve


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B5 Cemline

CSG

1” Control Valve, 6” Front Flange

B9 AHU 940 1” Control Valve

B5 3rd Floor

Main Header 1” Pressure Reducing Valve

B5 3rd Floor

Main Header – 6” Flange and Elbow


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B9 3rd Floor

AHU 946-Heat ¾” Control Valve

B9 3rd Floor

AHU 946-PreHeat ¾” Control Valve

B9 3rd Floor Distribution - 1.5” SS Pipe

B9 3rd Floor

CIP Room Cemline CSG – 1.25” Control Valve,

Strainer, 12” Flange, 4” Elbow, 1.25” Valve,

Strainer, Elbow, Union, 4” Receiver, 12” AFT


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B5 3rd Floor

HPS Header – 1.5” Pressure Reducing Valve

B5 3rd Floor

AHU 519 – 1” Control Valve

B5 3rd Floor

AHU 519-Heat – 1” Control Valve


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B3 Room 5-1223

Bin Washer – 4” x 12” x 24” P&F Heat

Exchanger


B5 1st Floor RO Heat Exchanger AFT


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Detailed Calculations


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2.5 OPTIMIZATION PROJECT # 5 Steam Traps

Current System Description and Observed Deficiency

There are more than 250 steam traps installed at the plant. Last complete steam trap survey was performed in 2005. A sample survey was performed during the audit. Total of 30 traps were checked and 35% of the traps have been identified as failed in blowing through (BT) or leaking (LK) condition. The results are presented in the Executive Summary Reports from Steam Star:

- Condition Summary - Trap Type Summary - Application Summary - Manufacturer Summary - Annualized Loss Summaries - a total breakdown of estimated steam and monetary loss


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Many steam traps on the high pressure (HP) steam headers were identified as failed. Majority of the HP drip traps discharge to flash tanks and the flash steam is recovered to the low pressure (LP) steam headers. Failed steam traps (BT, LK) need to be addressed even if they discharge to flash tanks and do not have direc t steam losses. They may create high pressures in LP lines and trigger popping of safety relief valves. Detailed data related to the sampled steam traps and their performance is available on the Steam Star website and will be discussed further in the report. During the survey, the following system deficiencies were observed:

• Missing or undersized drip legs • Undersized trap • Improper installation of a steam trap (upside down) • Drip on the side of the pipe • Take-off off the side of the main • Elevated condensate return and condensate pipes pitched backwards

Details of the observed deficiencies are shown in the Section 5. Additional Observations and Recommendations.


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Discussion The basic reasons for steam trap surveys and subsequent actions, i.e. repairs or replacements are:

• Energy savings: blowing through and leaking traps are wasting 100% of the fuel, water and chemicals used in the process of steam generation;

• Reliability and performance improvements: Undersized or plugged traps, or bad piping practices lead to energy and performance inefficiency, low steam quality, losses and safety concerns. Equipment becomes damaged (water-hammered and/or corroded) thus prompting increased manpower for maintenance and opportunity for failures.

Failed steam traps (blowing through) need to be add ressed even if they do not have direct steam losses (discharge to flash tanks), as they may create high pressures in LP lines as well as trigger popping of safety relief v alves.

Best Practices Recommended Testing Schedule for Steam Traps For maximum trap life and steam economy, a regular schedule should be set up for trap testing and preventive maintenance. Trap size, operating pressure and importance determine how frequently traps should be checked.

Optimization In order to maintain a low steam trap failure rate, ASI recommends establishing a preventive maintenance program to manage the entire steam trap population. This requires that all traps are tagged and recorded to maintain a steam trap inventory. Scheduled surveys should be


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performed to ensure that all traps are properly operating and to identify failures and prevent losses as soon as possible. ASI recommends, after the complete (100% of the trap population) steam trap survey, repairing/replacing all identified failed steam traps. The details of the trap survey and its results would be available on SteamStar trap management online platform, accessible via the GSK – Armstrong dedicated web site. Recommendations for steam trap replacement, as needed, will be based on steam operating conditions and specific application. Frequent checks to steam traps are seldom possible because of the steam trap locations (i.e. crawl space) or shortage of manpower, and traps fail in-between surveys. ASI suggests the installation of SteamEye to all the High Pressure and Medium Pressure steam traps, as they are the steam traps that waste the most energy. SteamEye will show an alarm for failed traps as soon as failure occurs, minimizing the potential energy loss. Savings

The savings from the repair/replacement of the failed steam traps will be calculated as a result of the complete Steam Trap Survey. The steam savings can be traced back to the boiler room, and consist of reduced fuel, water, and chemical costs. The savings will be calculated based on the type of trap, orifice size, trap application and inlet steam pressure. The steam cost is calculated in this report and is based on the system operating conditions and the provided utility costs. The replacement or repair of the failed traps from the tested sample will save $45,076 annually.

The savings from this project are presented in Steam Star by location. The tested sample may not be representative for the entire steam trap population and the results of this sample should not be extrapolated to the entire population. A complete steam trap survey will be needed.

Estimated investment and Payback

Complete steam trap survey cost, including Steam Star - $6,200 Steam traps repair cost will be defined after the 100% steam trap population survey.


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The payback of the trap repairs is expected to be between 1 and 2 years. Priority should be given to the HP steam traps, which have the quickest payback or can create additional problems to the system when discharging to a low pressure header.


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2.6 OPTIMIZATION PROJECT # 6a

Heating Hot Water Heat Exchangers - Return Condensa te to the DA

Current System Description and Observed Deficiency There are two Heating Hot Water (HHW) heat exchangers (HE) in the boiler room, which reheat the circulation heating water. The design rate is for 450 gpm and 180F/160F water supply and return temperatures. During the study the observed differential temperature was 7°F, supply 132°F and return 125°F. The condensate is collecte d in a closed system (receiver and pump steam trap) and pumped to an atmospheric receiver. The flash steam is vented above the roof level. The vent pipe from this receiver tank joins the other vent pipes from the plant after the arranged heat recovery (preheating the fresh air supply to the boiler room) and 100% of the flash is lost. The liquid condensate is pumped to the DA. Presently, the venting from the tank is excessive (an estimated 83 lbs/hr steam is lost to the atmosphere).

HHW HEs Tie-in after the heat recovery. Vent on the roof

Vent


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Discussion When high pressure liquid (condensate) is discharged into a lower pressure receiver, flash steam forms. Discharging condensate from 20 psig to atmospheric pressure generates 4.9% flash steam. If vented this flash steam (energy) is lost to the environment. If returned to the DA it reduces the steam used in the DA and thereby the fuel burned in the boiler. It also reduces the quantity of make-up water, as well as, the amount of chemicals for water treatment. Optimization ASI recommends extending the existing condensate return line after the pumping steam trap to the DA. Returning the medium pressure (MP) liquid condensate to the DA will eliminate the flash steam losses. This evaporation into flash steam taking place in the DA will offset the live steam used to bring up the condensate and MUW mixture temperature from 170°F up to 220°F. The project will require re-piping of the existing system to allow for a direct connection between the existing MP condensate pipe and the DA.


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Savings The implementation of this project will save $6,376 annually. The savings are shown in the table below and are calculated for 83 lbs/hr of vented steam.


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Budgetary cost for this project is $6,000.

Included:

• Design – not required

• Equipment – no new equipment. The existing steam pumping traps are expected to have sufficient capacity under the new conditions (pumping against the pressure in the DA).

• Installation by a mechanical contractor, including the extension of the existing 2” pipe to the DA. It is assumed that there is an existing nozzle to use at the DA.

• Project management The payback of this installation is expected to be around 1 year.


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2.7 OPTIMIZATION PROJECT # 7a

Domestic Hot Water Heat Exchanger - Return condensa te to the DA

Current System Description and Observed Deficiency This project is identical to Project 6a but refers to the Domestic Hot Water (DHW) heat exchangers (HE) in the boiler room. There are two DHW HEs, which heat the circulating DHW from the 3600 gal tank on the fifth floor. Based on the pump capacity, the design rate is 40 gpm. During the study the observed differential temperature was 10°F, supply 145°F and return 135°F. The condensate is collected in a closed syst em (receiver and pump steam trap) and pumped to the same open receiver. The flash steam is vented.

Discussion As discussed in the previous project, when high pressure liquid (condensate) is discharged to a lower pressure, flash steam forms. Discharging condensate from 20 psig to atmospheric pressure generates 4.9% flash steam.


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Optimization ASI recommends extending the existing condensate return line after the pumping steam trap to the DA. It could be combined with the previous Project 6a. The conceptual schematic is presented in Project 6a.

Savings The implementation of this project will save $810 annually. The savings are shown in the table

below and are calculated for 10 lbs/hr of vented steam.


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Budgetary cost for this project is $2,000, assuming executed together with Project 6a.

Included:

• Design – not required

• Equipment – no new equipment. The existing steam pumping traps are expected to have sufficient capacity under the new conditions (pumping against the pressure in the DA).

• Installation by a mechanical contractor, including the extension of the existing 2” pipe to the piping from the HHW condensate to the DA.

• Project management The payback of this installation is expected to be around three years.


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3 CHECK LIST VERIFICATIONS COMPLETED DURING THE AUD IT


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4 RECOMMENDED ADDITIONAL STUDIES

4.1 Project 6b Heating Hot water heater – Flooded Heat Exchanger

As discussed in project 6a, due to the discharge of condensate at saturation pressure (design 40 psig, actual 20 psig), there is a significant amount of flash steam vented through the open receiver tank. Another way to avoid the flash steam is to install a different type of heat exchanger, which sub-cools the condensate during its operation and does not allow flash steam to be vented at any time. The heat transfer surface is designed in such way that condensate is subcooled to 180°F even when the HE operates at 100 % of its capacity. This is the “Flooded” type of HE. The water temperature is controlled not through a steam control valve but by a condensate control valve. By manipulating the level of condensate in the vessel, the heat exchange surface available for heat transfer between the steam and the heated fluid varies to maintain the set point of the heated water temperature. The steam supply to the HE is constant, and a solenoid on/off valve may be installed just for safety reasons to make sure there is an interruption of steam supply when the system is not in operation. The existing system will be removed and the new system will be installed on its place. The estimated cost to remove the existing and to install two new heaters is in the range of $150,000. The savings would be the same as in Project 6a - $6,376 per year.


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4.2 Project 7b Domestic Hot Water Heater – Flooded HE a nd CTE Direct NG Fired HE

As discussed in project 7a, due to the discharge of condensate at saturation pressure (design 40 psig, actual 20 psig), there is a significant amount of flash steam vented through the open receiver tank. Another way to avoid the flash steam is to install a different type of heat exchanger (using steam) or a different type of heating (using Natural Gas):

• Flooded HE which sub-cools the condensate during the majority of its operation and does not allow flash steam to be vented. The only time when there will be flash steam is when the HE operates at 100% of its capacity. This is the “Flooded” type of HE. The water temperature is controlled not through a steam control valve, but by a condensate control valve. By manipulating the level of condensate in the vessel, the heat exchange surface available for heat transfer between the steam and the heated fluid varies to maintain the set point of the heated water temperature. The savings from this HE will be the same as in Project 7a- $810.

• Complete Thermal Exchange (CTE) Direct Contact Gas Fired HE (Armstrong Flo-Direct, AFD), which does not use steam, but directly heats the water. The savings from this installation will be higher than Project 7a, as the efficiency of this system is 99.7%, compared to the 83% efficiency of the boilers steam generation and the subsequent losses of the steam system. The most benefit of the savings will be achieved if this heat exchanger is installed on the MUW supply to the 3600 gal tank, rather than on the existing circulation loop between the tank and the DHW HE. The downside of it is that the size of the heat exchanger will increase significantly. The additional savings would be $2,526, for a total of $3,336 per year.


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To qualify the feasibility of this project and to properly size and design the proposed equipment, additional measurements and data collection will be needed. This will allow a better evaluation the actual savings as well as the peak demands, which are the bases for the sizing. The existing system will be demolished and the new system will be installed next to the DA on the 5th floor. There is no estimated cost for this project at this time.

4.3 Preheat RO water through heat recovery

The city water flow to the RO system is 21 gpm at ambient temperature. For the RO system to operate at its best efficiency the water is preheated by steam up to 24°C (75°F). For this low level of heat it is beneficial to consider heat recovery from another heat source, instead of using live steam. In relatively close proximity to this system are the compressors for the compressed air system and the chillers, which all require cooling. The expected savings are around $9,400 per year.


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4.4 Reduce Use of Chilled Water in Compressed Air Cooli ng

There are 2 x 100HP compressors in operation at any time, generating compressed air at 125 psig. In the intercooler and aftercooler heat exchangers, the compressed air is cooled by chilled water. The temperature of the compressed air leaving the compressors is 66°F. To generate chilled water (CHW) it takes approximately 0.8kW per ton of cooling. Considering the chilled water cost, it’s recommended to use cooling tower water or other source of cold water that needs to be preheated (i.e. RO water or heating hot water). Assuming only 70% of the available heat is removed by other means (not CHW), the electrical savings result in over $20,000 per year. Additional study is recommended.


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4.5 Replace Electric Coil with Steam Coil for Regenerat ion air at AHU 518 Glatt

The regeneration air heating coil for the dehumidification wheel at AHU 518 is electric. Electrical energy is more than four times more expensive compared to steam heating. Estimated savings are above $10,000 per year. If the system will stay in place additional study is recommended to define more accurate savings and investment.


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5 ADDITIONAL OBSERVATIONS AND RECOMMENDATIONS

This chapter will cover observed deficiencies not related to energy savings but are vital for the safe and reliable operation of the plant. 5.1 Best Piping Practices and Steam Traps Installation During the survey, the following piping practices and deficiencies were observed:

• Missing / undersized drip legs

Main header in Boiler room. Take off to AHU 519. Missing drip leg. Missing drip leg at the other end of header. Condensate would not enter there. The drip leg captures condensate only when it is properly located and sized. An undersized drip leg can cause the condensate to be pooled out of it (venturi “piccolo” effect).


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• Undersized trap – Clean Steam Generator (CSG) at AHU 570

The steam trap for the steam generator is much larger than the steam trap at the flash tank. These two traps should be at least identical in capacity as the flash steam from the condensate from the CSG trap is not more than 10% of the flow and other drip traps also discharge to this flash tank. Additional to the noticed by ASI disproportion of the trap sizing, the plant personnel reported an over pressurization of the LP steam header during the summer, when all the LP steam users are not in operation. The excessive flash steam triggers the safety relief valve opening, which is close to the fire alarm sensor and consequently requires additional attention from the fire crew and the maintenance and operation department. ASI did not address further these deficiencies as this humidification system will be removed in the near future and replaced with ultrasonic humidifiers.


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• Improper installation of a steam trap - AHU 942

The trap is turned upside down. Due to gravity, the float mechanism (opening and closing the orifice when there is condensate) will stay down and the orifice will be open all the time. The trap is blowing through steam and pressurizing the condensate return lines

• Drip on the side of the pipe - AHU 572

The header will always be flooded as the condensate would stay on the bottom of the pipe up to the level where it can “overflow” to the drip.

The Steam Trap is upside down. It needs to be turned 180° t o function properly.


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• Take-off off the side of the main – Main distribution, Building 5, 3rd floor

A best piping practice recommendation is to take off the steam from the top of the headers, or at least at 45 degrees, in order to have dry steam supply. In the above side take-off, the probability to have wet steam (condensate entrainments with the steam) is high.

• Elevated condensate return after steam traps

Bin Washer. AHU 514. Returning condensate to an elevated location, creates back pressure downstream of the trap. As the traps discharge condensate based on pressure differential, it will be impossible to return condensate 100% of the time. The condensate will stay upstream


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of the trap any time during a start-up or when the supply pressure is lower than the discharge pressure.

The above listed deficiencies lead to energy and performance inefficiency, low steam quality, losses and safety concerns. Equipment becomes damaged (water-hammered and/or corroded) thus prompting increased manpower for maintenance and opportunity for failures. Essentials of installing drip legs

The drip legs are main components of the steam distribution system, assuring the quality of the steam at the point of usage.

Steam

Droplets

Steam Line

Steam +condensateDrip Leg

Condensate

They are provided to:

• Let condensate escape by gravity from the fast moving steam

• Store condensate until the pressure differential can discharge through the steam trap The drip legs are installed at various intervals (max 300 ft), changes in elevation, and low spots or natural drainage points such as:

• Main headers

• Ahead of risers

• End of mains

• Ahead of valves or regulators or equipment The condensate will be captured in the drip leg, when it is properly sized. A correctly sized drip leg must have sufficiently large diameter to catch droplets of condensate moving above it. A


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drip leg that is undersized can actually cause a venturi “piccolo” effect where pressure drop pulls condensate out of the trap and drip leg.

The correct size of a drip leg depends on the diameter of the supply pipe. For proper sizing see the following drawing.

Essentials of sizing drip traps If the steam trap size is not correctly calculated, the result will be:

• If undersized , the steam trap will not handle the released condensate and the drained equipment or line will be flooded. Condensate can back up and cause unsafe water hammer.

• If oversized , it may result in:

1. Waste of live steam, 2. Back pressure in the return lines, which could disturb the function of other

parts of the system.


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6 CLOSING

ASI appreciates the opportunity to assist GSK with this steam and condensate audit and welcomes the opportunity to be GSK’s energy services partner and provider. We are pleased to report there is potential for significant cost savings in the facility and propose to work with the facility in further development into definitive projects for these findings. A more detailed analysis will confirm payback criteria, and potentially identify additional savings opportunities. Please contact Armstrong Service to define next steps.

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