article on essar steel algoma plant

8/8/2019 Article on Essar Steel Algoma Plant

1/19

Panglobal on Canada/ U.S. issues

Algoma Steel

July 2005

Institute of

Power Engineers


2/19

Editor-

George Reid

Contributors

Robert CummingAlgoma Steel

Tony ConnerTBP IndustrialSteam SystemsJohn Cerniuk

Wayne Kirsner,P.E.

A. Banweg,Nalco Company

3 Headlines

4 Nuts and Bolts

6 Man, This Blows

8 Condensate Induced

WaterHammer

12 Power Engineering

A North American Profession in

Transition

14 Nalco water treatment

Institute of

Power EngineersTab l e o f Con ten ts

Check us out at http://www.nipe.ca


3/19

Ontarios New Energy

Market Emerges

Ontarios energy minister Dwight

Duncan announced new developments in

the Ontario energy market that will add

another 1600MW to Ontarios energy

supply to help offset the replacement of its

coal plant .

Headlines

National IPE

Convention

The 2005 annual IPE

national convention will be held in

Toronto this year from September

14 through to the 18th. The main

convention will be held at the Days

Inn and Conference Centre at 6257

Airport Road Mississauga Ontario.

For all the details check out the

Toronto branchs web site at

Bruce nuclear

The potential restart of Units 1and 2 at the Bruce facility would

result in an additional 1,540megawatts of electricity generatingcapacity, which is enough to power

over one million homes across

Ontario. Restarting these units wouldalso potentially replace over 20 per

cent of Ontario's current coalcapacity and related harmful

emissions

New Brunswick PointLepreau Nuclear Station

The province of New

Brunswick and Atomic Energy of

Canada Ltd are looking into

extending the operational life of the

Point Lepreau nuclear station. With

this project the operational life of the

station will hopefully be extended 25

years..

www.ipe.org

http://www.energy.gov.on.ca/index.cf

m?fuseaction=english.news&body=y

es&news_id=91

http://www.canelect.ca/english/a

rticle.html?SMContentIndex=4&

SMContentSet=0

http://www.energy.gov.on.ca/index.cf

m?fuseaction=english.news&body=yes

&news_id=93


4/19

The most common flanges found in

general industrial & institutional steam plants are

Class 125 & 250 cast iron, Class 150 & 300forged steel. These are used to connect flanged

components, such as boilers, valves, strainers,

pumps, etc.

Cast iron components like valves &strainers are typically much cheaper than cast

steel, for the same sizes. This is because iron is

much easier to cast than steel. This lower cost forcast iron components that are dimensionally the

same, means that they are often chosen over steel,

especially in the 125/150 Classes. As with mostthings, cost should not be the only consideration.

It is very common for boiler safety valves

to be set for 150 PSIG, while the boiler fires tomaintain a header pressure of 125 PSIG. Systems

like this are routinely filled with Class 125 cast

iron gate & globe valves, control valves, strainers,

trap bodies, etc., because everyone is looking atthe operating pressure. These Class 125

components drop nicely between Class 150

flanges. Theyre a perfect fit. Unfortunately, if thesafety valves protecting these steam system

components lift at anything over 125 PSIG, the

installation does not meet pressure piping coderequirements. Even if the safety valves are set for

125 or below, the installation still may not be

code compliant.

If a Class 125 cast iron flanged componentis connected to a Class 150 steel flange (which is

very common), more factors come into play. 125

cast iron flanges have a flat face designed for afull-face gasket, while 150 steel flanges have a

raised face, designed for a ring gasket. For

pressure piping applications, it is required by theASME B31.1 Power Piping Code that the raised

face on the Class 150 flange be removed, and that

a full-face gasket be used to join the 125 & 150

flanges.

Flanged JointsBy Tony Conner of TBP Industrial Steam Systems

The use of a full-face gasket leaves no

gap between the flanges outside of the bolt circlediameter. If this gap exists, it can allow the

relatively thin and brittle cast iron flange to spring

into it, possibly splitting the flange when the

flange bolts are tightened. If a ring gasket is usedto join two Class 125 flanges, then low strength

bolts, such as A 307 Gr B, must be used, along

with nuts of a corresponding material. In addition

to a minimum listed tensile strength, these boltsalso have maximum tensile strength, meaning that

the fastener will fail before the flanges, if thebolts are over-torqued during installation.

From the ASME B31.1 Power Piping

Code: When bolting Class 150 standard steelflanges to flat face cast iron flanges, the steel

flange shall be furnished with a flat face. Steel

flanges of Class 300 raised face standard may be

bolted to Class 250 raised face cast iron.Many people dont realize that the

fasteners themselves also need to be codecompliant. There are a huge number of fastenergrades available. Among the most common are

SAE Gr. 5 and Gr. 8. However, these are not

listed as approved for use in pressure piping,falling under ASME B31.1. The most commonly

available code compliant grade is B7, which can

be either studs, or bolts. B7 will be in raised

lettering on bolt heads, or stamped into one end offactory-cut studs. B7 material is also available in

a range of diameters, as lengths of threaded rod,

which can be cut field-cut to length. Thematching nut grade is 2H, which has a noticeably

heavier wall and higher profile than the

corresponding size of SAE grades. The 2H willbe shown in raised lettering on one face of the

nut. The B7 studs and 2H nuts are suitable for

most of the steel flanged piping joints found intypical powerhouse applications. Table 112 in the

B31.1 Code lists


5/19

For those that think this is all academic,with no relationship to the real world, please

refer at the photographs below. These are

posted on Wayne Kirsners websitewww.kirsner.org . Hes a professional engineer

from Atlanta, who specializes in the

investigation of steam system water hammerevents resulting in fatalities. Note that the valve

itself (a Class 150 cast steel) did not fail. The

flange fasteners however, did fail, resulting inthe death of the operator. Note that the fatality

DID NOT occur as a result of operator error,

but rather a piping design flaw. Steam valves

should not be installed in vertical piping runs.Where it is not possible to avoid this, an

overseat drain must be provided so that any

accumulated condensate on top of the valve

disk can be drained, prior to opening the valve.It is NOT POSSIBLE to slowly crack the

valve, in order to avoid condensation induced

water hammer. It is not clear (the accident

may still be under investigation) if the correct

grades of bolts or studs & nuts were used to join

this flange. Even if they were code compliantfasteners, it is obvious that they were subjected

to forces beyond what they could withstand,

with the nuts being stripped-off. It is certain thatany plant people involved in the accident

investigation regarding this failure would verymuch like to be able to assure the investigatorsthat the correct size & grade of fasteners were

used, and that all of the available threads were

fully engaged

approved fastener grades & materials for various

applications. The use of steel flanges and

components eliminates trying to keep track of thevarious requirements regarding flange faces and

fasteners.

From IPTs Industrial Fasteners

Handbook by Bruce Basaraba:

The functional (clamp load) strength of any nutand bolt system is dependent upon both the proof

load strength of the bolt and the proof load

strength of the nut. Functional nut strength is

determined by both nut hardness and the shape ofthe nut. Nuts generally fail under high loading by

thread stripping that begins at the threads next to

the bearing surface of the nut.When tightening flange bolts, the nut

acting against the flange is subjected to very high

stress. Because of this, the wall of the nut tends todilate or mushroom the bottom of the nut against

the flange. If the nut fails, it typically results in

the nut threads stripping progressively from the

inner (against the flange surface) outward, muchlike undoing a zipper. This dilating or

mushrooming of the nut can only be controlled by

strengthening the nut wall through heat treatment,or by increasing the thickness of the nut wall and/

or height of the nut. The use of 2H nuts vsmany other grades such as SAE, means that afastener with a heavier wall that resists

mushrooming, and the higher profile provides

more threads to engage.


6/19

Steam turbines play a vital role in many

of todays industrial and commercial

operations. Applications range from small,single-stage units used to drive pumps, all the

way up to the large, multi-stage turbines that

produce thousands of megawatts of power.Steam turbines are found in many industrial

applications ranging from co-generations to

pulp and paper production, where the majority

of their use is for the generation of power.

Steel mills are no different. They oftenhave large steam-driven turbo-generator units

used to supply some of the power demand for

the mill. However, the need for steam turbines

at a steel mill does not stop at the electricalgrid. Most integrated steel mills that operate a

blast furnace require a high volume of low

pressure air called wind in order to operate.This wind is usually supplied by a steam

turbine driven blower. These units are known

as turbo-blowers and are basically large aircompressors. These units are vital to the safe

operation of a blast furnace.

MAN, This BlowsBy Robert Cumming and photos by Paul Lalonde, Courtesy of

Algoma Steel

Algoma Steel is an integrated steel mill

located in Sault Ste. Marie Ontario. Onsite is one ofthe largest operational blast furnaces in North

America. The furnace, known as #7 Blast Furnace is

the heart of the operation, supplying all of the liquid

iron for the BOSP (Basic Oxygen SteelmakingProcess). At full capacity, the furnace can produce

up to five tons of liquid iron perminute.

A blast furnace is a vessel in which liquid

iron is produced. Raw materials such as iron ore

pellets and coke (large pieces of carbon) are addedto the top of the furnace to form what is called a

burden. The burden is held in suspension by the

wind which is supplied by the turbo-blower. Thiswind, known as cold blast discharges from the

blower at approximately 350 degrees Fahrenheit and

travels through a large line known as a header to the

blast furnace stoves. At the stoves, the wind isheated to approximately 2300 degrees Fahrenheit.

The wind, now hot blast, continues to thefurnace where it collects at what is called the bustle

pipe and then enters the furnace proper through

nozzles called tuyers. The hot blast is then mixedwith fuels like oxygen and natural gas to start a

chemical reaction needed to melt the burden. Once

liquefied, a hole is drilled at the bottom of the

furnace and the liquid iron is poured. The iron isthen sent to the steel making shop where it is

processed into steel. It takes approximately six

hours to melt raw material to liquid iron.

Algoma Steels #7 Furnace


7/19

The #7 Blast Furnace at Algoma Steelgets all of its required wind from #5Turbo-

Blower. This blower was installed in the mid

1970s specifically for #7 Blast Furnace. Theturbine is a 28 stage impulse-reaction machine

built by Brown Boveri. It operates on 600 lbs.

superheated steam and exhausts under vacuum to

a condenser. The machine has five admissionvalves and uses up to 180 000 lbs. of steam per

hour and operates at a rated speed of 3800 RPM

producing up to 30, 800 horse power. Theblower end of the machine was originally a 16

stage axial compressor, but was upgraded in

October of 2002 with a more efficient 13 stageaxial rotor. The rotor is surrounded by a stator

blade carrier that is equipped with adjustable

blades. Both the rotor and blade carrier weresupplied by MAN Turbo.

The controls for this machine were

upgraded in the mid 1990s from the original Pto H controls to the more efficient I to H

controls. The control systems were supplied by

Compressor Controls Corporation. The machine

is operated by three separate control systems : aSpeed Controller maintains the machine at arated speed of 3800 RPM when the unit is

online: aPerformance Controller maintains the

flow of wind to the blast furnace by adjusting the

angle of the blades on the stator blade carrier ;and anAnti-Surge Controller, which is a safety

relief device designed to protect the blower from

surging under a reverse flow condition.

At full production, the blast furnacerequires up to 150 000 CFM of wind at pressures

up to 48 PSI. The Turbo-Blower can easily meet

these requirements.As stated before, a turbo-blower is a key

piece of equipment needed to safely run the blast

furnace. Thus, if anything were to happen to theoperational unit, a stand by would be required to

maintain the blast furnace until the main blower

can be returned to service. Algoma Steel has two

stand-by units that can be used to operate theblast furnace if the need arises. Number 1 Turbo-

Blower is the main stand-by machine, rolling

over at 1200 RPM and is located in the Turbo-Blower Building. This machine is a steam

turbine-driven centrifugal compressor produced

by Ingersol-Rand Company. The second stand-

by machine is #4 Turbo-Blower and it is locatedat the Main Boiler House. This is a smaller steam

turbine- driven axial compressor also produced

by Brown-Boveri. This unit is on a barring gearand can be put into service from a cold start upin two hours.

#1 Turbo Blower

Operating a turbo blower within an integratedsteel mill such as Algoma, has its own uniquechallenges. This can be one of the most complex

systems for a power engineer to operate, due to the

ever-changing operating parameters of these machinesand conditions present at the blast furnace. Although

operating turbo blowers is only one job that a power

engineer may perform in an integrated steel company,it is one of the most critical to the safe and efficient

operation of a blast furnace.

EngineersInspectingAdmissonValveson#5Turbo-Blower1


8/19

Condensate Induced Water HammerPart 2continued from last issue

What Happened

For four weeks asbestos workers had been removing asbestos insulation from the 2,200

foot section of steam main known as the G-Line and the 120 foot H-Line. (See Figure

1) Like all steam mains at Fort Wainwright, Alaska, the G and H Lines ran underground

in narrow utilidors filled with pipe. Originally, the contractor had tried to abate thesteam main with the lines energized. This proved to be near impossible for the workers.

Utilidor temperatures reached 160 degree F as insulation was removed from the 325

degree F pipe carrying 80 psig steam. Laborers who had to be suited-up and masked to

work in the asbestos laden environment were dropping like flies from the heat and/or

quitting. The contractor was forced to seek relief from the Owner. A compromise was

negotiated after the first week-- steam would be de-energized at midnight before each

workday, asbestos abators would start work at 4:00 a.m. and finish by noontime at

which time steam would be restored. The asbestos removal contractor would be

responsible for de-energizing and re-energizing the steam line daily. For the threeweeks before the accident this was the procedure. By the beginning of the laborers'

workday, temperatures in the utilidors were still around 120 degree F but, with frequent

breaks to cool off and re-hydrate, conditions were tolerable.

Fig 1 Isometric view of G- and H-Lines (no scale).

This article is from Wayne Kirsner, P.E.

Who investigates industrial steam accidents. For more of his work

visit his web site http://www.kirsner.org


9/19

Unfortunately, the discomfort to the workers was not the only consequence of

removing the insulation from active steam mains that had gone unforeseen. There was

also the effect on the steam traps. 3/8" thermodynamic traps were installed at each

manhole except C-4 which contained a 1/2" trap. At the system's operating conditions,

the 3/8" traps could remove 295 pounds of condensate per hour . With 3-1/2" ofinsulation, 300 feet of 12" pipe generates 41 pounds of condensate per hour.

Thus, for a typical pipe segment, the traps had better than a 7 to 1 safety factor

for condensate removal with the line insulated. With the insulation removed, however,

heat loss increased almost 18 fold so that condensate formation jumped to 729 #'s/hr

over 300 feet of pipe. At this rate of heat loss, the 3/8" traps had less than one-half the

capacity needed to keep up with the condensate production. This was not good.

ThAbatement began at Manhole G-1 and headed south toward C-4 at the rate of

about 125 feet a day. As abatement proceeded down the G-Line, local traps serving the

uninsulated portion of the line were overwhelmed with condensate during the periodthe lines were energized each day. In the first two weeks, however, this didn't cause a

problem. Excess condensate merely rolled down to C-4 on the south end and G-1 on

the North end. Traps on the south end still serving insulated portions of the line had

adequate capacity to remove the excess condensate. On the north end, the steam valve

was left closed so trouble was avoided. After two weeks of daily start-ups without

serious incident, save some minor waterhammers, asbestos crew operators grew

confident that start-up of the steam line was no big deal. By the beginning of the third

week, insulation removal had reached Manhole G-9. Calculations show that at this

point the rate of condensate being generated in the southern section of the G-Line

began to exceed the net capacity of the traps to remove it.

Condensate accumulation during steam operation is potentially destructive, but even

so, as long as condensate is religiously drained everyday before start-up, a catastrophic

waterhammer accident might still be averted. The problem was--condensate wasn't

being drained religiously. The asbestos workers given responsibility for energizing the

steam main daily didn't fully appreciate the danger inherent in starting up a high

pressure steam system with condensate in it.

They did not routinely open drain valves to bleed the system of excess

condensate either at night, when they shut the system down, or at noontime, when theyre-admitted steam through the C-4 valve to re-energize the steam main. Their belief

was that steam admitted through the C-4 valve would blow condensate to the far end

of the main at G-1. Thus, in their view, only the drain at G-1 "really" needed to be

opened at start-up. Accordingly, there was a tacit understanding that the bleeder valve

at G-1 would be opened daily by the quality control supervisor for the prime

contractor, and any condensate that wasn't drained at start-up, they apparently thought,

would be mopped up by traps after start-up.


10/19


11/19

This had the likely effect of sweeping undrained condensate residing against the G-1

valve on the north end of the line south to C-4, and completely filling the H-Line as

explained in the sequence of figures a thru c in sidebar at end of article.

The situation, then, 15 minutes before the Accident as Bobby readied to crackopen the C-4 valve, is as shown in Figure 3.

Subcooled condensate filled the steam line on both sides of the C-4 valve as

well as completely filling the H Line. High pressure steam admitted through G-1 had

pressurized the steam main and was sitting atop the condensate on the north side of C-

4. The south side of the valve was also under steam pressure which, based on

testimony, was likely slightly less that that on the north side.

Now, put yourself in Bobby's place, except, assume you know all the

information described above, i.e., in your mind's eye, you can 'see' the build up of

condensate shown in Figure 3 and figure out, based on the ease with which the valve's

handwheel spun, that there is full steam pressure atop the condensate. Ask yourself two

questions:#1. Is this Situation Dangerous? Some steam people would say "no, as long as

there is no fast moving steam, there's no danger of waterhammer. Opening C-4

slowly and incrementally should prevent steam or condensate from moving

quickly and thus prevent a waterhammer." This is wrong, dead wrong.

High pressure steam in contact with subcooled condensate is dangerous. It's a recipe

for Condensation Induced Waterhammer. The sidebar (See sidebar near bottom page)

explains why this type event is 10 to 100 times more powerful that conventional

"steam flow" driven waterhammer.

#2. What Would You have Done in Bobby's place? If your answer is, "I'd first

open the C-4 bleeder valve to drain the condensate," you're toast. Although this is the

answer most steam operators would give, it will trigger the accident. Neither the

bleeder valve nor the steam valve can be opened without provoking this accident. To

understand why, it's crucial for steam fitters and operators to understand the

mechanism of Condensation Induced Waterhammer.


12/19

Introduction

At the heart of most industrial complexes lies a steam-driven utility system. Whether control-ling thermal processes or generating power, modern steam production facilities are extremely complex

and require skilled professionals for efficient, and even more importantly, safe operation. Throughout

North America and around the world, these professionals are known by any number of titles but are

commonly referred to as Power Engineers.

The power and heating plants at the core of every industrial and commercial complex are criti-

cal to the success of each facility. The safe and efficient operation of these plants has been the respon-

sibility of the Power Engineer for more than 120 years in Canada and many parts of the world. As theprofession looks forward to new challenges and opportunities, it is prudent to reflect on where we

have come from and where we may go.

There are many similarities throughout the industries supported by this profession. A North

American design and construction standard for boilers has existed for a number of years. The codewas developed by the American Society of Mechanical Engineers originally in 1914 and has been up-

dated continuously ever since. Recent versions are updated every three years. The most recent version

(2004) has included both SI and USCS units, for the first time since 1983. The code has been adopted

by most jurisdictions that use qualified Inspectors to administer the standards. Uniformity of inspectorqualification is provided through a single group; the National Board of Boiler and Pressure Vessel In-

spectors.

The pressure and energy created by steam production, if improperly managed, is potentiallydevastating to plant and personnel. The ramifications of boiler accidents have been recognized for

many years. As a result, all facets of boiler design and construction are rigorously specified by profes-

sional and regulatory bodies, closely monitored, and require highly trained and certified professionals.

Why then would we condone a lesser standard for the Power Engineers operating the equipment?

One of the most important differences throughout the industries supported by this profession isa significant variance in operator certification standards and training. The lack of a uniform standard

of training across North America has created an environment wherein unnecessary litigation, insur-ance claims and injuries continue to exist.

Each year, boiler incidents cause billions of dollars worth of damage. At times, injuries andhuman fatalities add to the physical damage resulting from the incidents. According to the National

Board of Boiler and Pressure Vessel Inspectors (NBBI) statistics, the cause of approximately 80% of

these accidents can be directly or indirectly attributed to Operator error.

Power Engineering

A North American Profession in TransitionR. A. Clarke,

President and Chief Operating Officer

PanGlobal Training Systems Ltd.


13/19

On a per capita basis, however, Canada has less than 1/6 th of the number of accidents thatoccur in the US. This serious discrepancy needs to be addressed, ideally with an overall solution

meeting the needs of all stakeholders in a common North American vision.

Specific training and certification standards may exist in each jurisdiction, but in Canada

over the past twenty years what is essentially a single standard has been achieved. Working collabo-

ratively, Industry Groups, Certifying Bodies and Regulators have facilitated the adoption of a uni-versal Certification and Training Standard across jurisdictions. Similar opportunities still exist in

collaboratively developing a broader standard amongst National Board jurisdictions across North

America.

The future of Power Engineering has many technological and staffing challenges. Rapid ad-

vances in technology, increasing operational automation and the convergence of Power, Heating and

Pressure Plants combine with the aging operator population to add complexity to corporate staffingdecisions. These challenges can be met successfully if an effective partnership model is adopted by

all stakeholders, including; industry, regulators, educators and professional organizations. Together

we can produce a North American Standard.

US and Canadian Historical Perspectives on Operator Certification

Over the years, many schools in Canada participated in the instruction of Power Engineers asindustry and jurisdictions realized that educator-based training preparation produced better qualified

and more importantly, more competent operators. Most of these educators chose to utilize the al-

ready-established instructional materials prepared for SAITs correspondence courses.The wide-spread use of the same instructional material created a uniform educational stan-

dard which in turn naturally produced a pathway towards uniform operator certification. This proc-

ess culminated in 1971 with the formation of the Standardization of Power Engineering Examina-tions Committee (SOPEEC). A sub-committee of the Canadian Chief Inspectors Association (ACI).

, SOPEEC was established to allow for the standardization of power engineering examinations and

certifications as well as to promote the free movement of Power Engineers across Canada. In 1972,SOPEEC approved the SAIT correspondence courses as the standard curriculum and along with its

uniform set of examinations created a national program for education and Certification of Power En-

gineers. At its' inception 2000 students were educated each year within the system. Currently, over

5000 courses are purchased each year from across Canada, the United States, Australia, and the Car-ibbean.

In the US, operator certification standards vary from jurisdiction to jurisdiction and in manystates, there is no existing standard. Differences in certification standards are seen at the National,

State and Local levels. The largest third party certifying body in the United States is the National

Institute for the Uniform Licensing of Power Engineers (NIULPE) which is recognized in forty onestates and by the US Military. A large portion of US industry has historically depended upon power

engineering training obtained in the military as the basis of background experience qualificationwhen recent direct experience was not documented.

Recognition is different than adoption however, and less than 10 states have formallyadopted regulatory licensure or indeed any standard for certification. In Canada there is one standard

for Operator Certification administered under the authority of Canadas NBBI members (ACI).

The next issue will continue this article with US and Canadian comparisons in accident rates;

design and construction standards; education, training, and certification; and conclusions .


14/19

Evaluation of New Condensate Corrosion Filming

Technologies in Steam Trap Devices

Steam traps are essential for maximizing efficiency in a steam system. It is important to under-stand how corrosion inhibitors affect these units. Since the 1940s, volatile amine treatments have

been used in condensate systems to minimize corrosion. These compounds neutralize carbonic acid

formed in the condensate system and raise the condensate pH to a non-corrosive level. Amine-based

inhibitors are effective if proper concentrations and performance parameters are maintained.Although effective in reducing condensate system corrosion, many of these chemicals are

somewhat hazardous and have permissible exposure limits (PELs) established by the Occupational

Safety and Health Administration (OSHA). If the concentrations of thesecompounds exceed these limits, adverse health effects can occur. Chemical odors can result well be-

low these limits, raising questions about the safety of the inhibitors.

Often, sophisticated monitoring practices are put into place to avoid this problem most commonly inhospitals, universities and commercial buildings. A new, innovative condensate corrosion treatment

was developed in 1998, in response to increasing regulatory,

safety, technical, and economical needs voiced by managers of steam systems. Based on emulsifierscommonly used in the food industry, this chemistry presented concerned facility personnel with a

safer material that met all their regulatory, technical, and

economic needs. As with any new technology, its long-term impact on the steam system equipment,such as steam traps, was unclear as it was brought to market.

By Melissa Kegley, Nalco Company and Jim Daugherty, ArmstrongInternational Inc.

There are four common types of condensate corrosion inhibitors: neutralizing amines, filming

amines, oxygen scavengers, and a new emulsifier technology. The most common type of corrosioninhibitor is the neutralizing amine (such as morpholine, cyclohexylamine, and diethylaminoetha-

nol). These chemicals are volatile, nitrogen-bearing compounds that condense with the steam andneutralize any carbonic acid formed in the condensate system. Neutralizing amines increase the

condensate pH to reduce corrosion.

CORROSION INHIBITORS


15/19


16/19

http://www.tbpindustrial.com/


17/19


18/19


19/19

WHERE IS YOUR BRANCH??

Victoria

Edmonton

Calgary

Winnipeg

Windsor

Vancouver London

Hamilton

Toronto

Welland

Ottawa

Sudbury

Sarnia

Montreal

Newfoundland

Nova Scotia

Sault Ste MarieLakehead

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