Preventing Catastrophe

Almost 80 percent of all reported boiler accidents were attributed to two causes: low water cutoff, and operator error/poor maintenance. A low water cutoff condition occurs when the water level in the boiler steam drum drops below a pre-set safe level (as determined by the boiler manufacturer) and, in turn, shuts off the boiler. This condition, and the subsequent cause, should be investigated and corrected immediately. Failure of this safety control may result, at a minimum, in costly tube or vessel repairs, or, in the worst cases, catastrophic boiler and building damage and personnel injury or death.

Some common causes of low water conditions include:
•    Feedwater pump failure
•    Control valve failure
•    Loss of water to the deaerator or make-up water system
•    Drum level controller failure
•    Drum level controller inadvertently left in “manual” position
•    Loss of plant air pressure to the control valve actuator
•    Safety valve lifting
•    Wide variations or sudden changes in steam load

Avoiding the above conditions is critical to ensuring safe and reliable boiler operation. Maintenance, inspection, and operational logs are recommended and required by insurance companies.  These records not only help determine boiler performance trends, but also keep operators focused on the safe performance of the boiler and auxiliary plant equipment.  To this end, unnecessary boiler downtime (together with the loss of plant production) and lost time accidents are avoided.

The only way to avoid premature downtime and accidents (in the worst cases) is to make certain that operators and plant owners are committed to an on-going operational and preventative maintenance programs.  The Hartford Steam Boiler website www.hsb.com is a good resource.  Turning a blind eye to safe boiler operations puts operators, company employees, and equipment at unnecessary risk.

Edited from Nationwide Blog

Myths and Truths about Balancing

MYTH: “1x RPM is always caused by unbalance.”
TRUTH: Unbalance always causes vibration at 1x RPM.  However, 1 x RPM is not always caused by unbalance.  Many other problems can exhibit vibration at this frequency.  Examples are:  Misalignment, Bent shaft, bowed shaft, cracked shaft, eccentricity, open rotor bars in the motor, rubs, looseness, belt issues  and resonance. 

MYTH: “The run time and lifetime of the equipment can be extended by performing a balance job on the equipment.”
TRUTH: Problems such as misalignment, bad bearings, looseness, etc cannot be corrected by balancing the machine.  It is almost impossible to correctly balance a machine that has other defects affecting its performance.  Misalignment, bad bearings looseness etc should be corrected before attempting to balance equipment.

Pipe Strain is Soft Foot!

Soft foot means machine frame distortion. If you are missing shims under a foot and tighten the hold-down bolt until you have forced the foot down to the base, you will have distorted the machine frame. If you have severe pipe stress on a pump, and the anchor bolts are tight, chances are great you are also distorting the pump casing. Consider that if the pump’s anchor bolts were completely loosened or removed, the pump might be hanging in the air from the piping. So if you were now to tighten the anchor bolts, you would be forcing the pump down to the base and distorting it, just as happens when you are missing shims under a foot.

Shimming the feet will rarely solve the problem completely; rather, the correct solution is to eliminate the undesirable pipe stress. “Stress” is the force acting on something, while “strain” is the deflection or distortion resulting from the stress. A soft foot condition means you have machine frame strain, and pipe stress is just one of several examples of this. When the machine casing is distorted, the internal alignment between the bearings is changed and the shaft is deflected. This produces enormous stress on the bearings and increased vibration in your machines, resulting in premature wear and tear as well as loss of efficiency. Your seals and bearings will fail much faster. If a significant soft foot condition exists, a good alignment of the centerlines of the shaft rotation is almost pointless. The machines will still fail more quickly and lose efficiency. How do we diagnose and fix this?

The trick lies in knowing how to recognize that a pipe strain problem exists. The behavior of a machine with pipe strain differs significantly from one whose soft foot condition is caused by one of the more traditional shimming problems or unevenness of base or feet.

Any impact on the alignment of more than about 2 mils indicates a pipe strain problem that should be dealt with. Correcting pipe strain is a task for an experienced pipefitter who must see to it that connecting and torquing the piping should not move the machine from its rough aligned condition, nor distort its casing in any way. Proper pipe hanging techniques and a good knowledge of calculating and designing “Dutchman” spacers is essential.

Taken from Ludeca Blog

Understand shaft alignment fundamentals

Keeping your rotating shafts in alignment is a fundamental—and often overlooked—maintenance project. Alan Luedeking, the manager of technical support for Ludeca Inc., Doral, Fla., talked with Plant Engineering (PE) about some of the critical issues in shaft alignment, and how they affect safety, energy, and productivity.



PE: Maintenance personnel aren’t always looking for issues with shaft alignment. Are there some warning signs or performance cues that operators or maintenance staff should be on the lookout for that might indicate a problem?


Luedeking: Yes indeed. If you hear unusual noise or feel increased vibration, those are important warning signs that should not be ignored. All the senses should be involved. Smell your environment: chemical leaks, overheating grease, and unusual stains, all are diagnostic clues and warning signs. One should always be alert to everything in one's surroundings in the plant, for safety as much as for good maintenance. Most importantly, a proactive maintenance program should include condition monitoring-based strategies and solutions to prevent unnecessary repairs and unscheduled downtime in the first place.


PE: Let’s talk about the ROI of shaft alignment. When you’re out of alignment, what are the potential losses in terms of both productivity and uptime?


Luedeking: They are great. Besides the obvious risks of a broken coupling or shaft, misaligned shafts lead to increased radial load on the bearings with consequent great reduction in service life. Besides wear and tear, less obvious is that misalignment also results in increased power consumption, which several careful studies have shown to range as high as 10%, although more conservative estimates easily reach 4%. The efficiency of the machines is impacted, and product quality may be affected by the increased vibration resulting from misalignment.


PE: What’s the correlation between shaft alignment and energy efficiency? This would seem to be an overlooked area.


Luedeking: Funny you asked—I was just thinking about that in my previous answer. This aspect is often overlooked, and a savings of 4% on an energy bill of $50,000 a month easily justifies the best laser shaft alignment on the market in less than a year, without even considering the benefits of greater uptime, less repair expense, and time saved on the alignment itself.


PE: What are a few basics about shaft alignment that should be on the minds of operators and maintenance staff?


Luedeking: Safety and quality. Safety first, always. Make sure your machines are locked out and tagged out before you set up. When I say quality I refer to two things: the suitability of your laser alignment system for the task at hand, and the excellence of your alignment procedures. Are the machine bases properly designed, installed, and cared for? Always check for, analyze, and correct soft foot. Does your laser system help you do this?


Do you have jackscrews in place to move your machines? Do your millwrights have access to good-quality stainless steel shims? Are your machines under pipe strain? Can your laser system even measure that and help you find it? Are you considering thermal growth and dynamic load shifts in the positions of your machines? If not, you may be grossly misaligning your machines by aligning them to zero when cold.


Your laser system should let you input target specs, or thermal growth values at the feet, and calculate this growth from observed changes in temperature, or even measure and monitor this growth live as you run the machines! Only the best-quality laser system will let you do all of these things, thereby achieving better results and saving you time and money at every step.


Taken from Plant Engineering

Why air is compressed in Gas turbine engine ?

To understand why we compress air in a jet engine, one must first understand the goal. For an aviation gas turbine, the goal is thrust. The purpose of the turbine stage is to power the fan and the compressor. The thrust comes from moving air through the engine.
Now, we know why the fan is there. It's there to move the air. We get thrust from that. Now, the compressor's main purpose is to assist the turbine in energy extraction. By compressing the air, not only does it assist in combustion, it also helps in energy extraction by the turbine stage(s).
As for the temperatures, a turbojet will have significantly higher higher temperatures, as 100% of the flow goes through the turbine stage. As we mentioned, for a thrust-producing aviation engine, the goal of the turbine is to extract 'just' enough energy to power the fan/compressor stages. So, the flow still has a ton of energy, in the form of velocity and temperature. Exhaust temperatures can be well over 1000 degrees.
In a turbofan, as mentioned, some, if not almost all (in the case of the bigger engines) of the flow goes through the bypass. So, while the inner core flow will be hot, after the mixing region, it is relatively mild.

Proper Sizing and Installation Tips – Boiler Safety Valves

The safety valve is one of the most important safety mechanisms in a steam system. Not only are they required by code, but most importantly, safety valves provide a measure of safety for plant operators and for the equipment.
The American Society of Mechanical Engineers (ASME) governs the code that establishes the requirements for safety valves, therefore it key that all plant personnel are familiar with current codes that apply to their system.
The following sizing guidelines and installation tips listed in Process Heating Magazine and thought the information would be useful to pass on. We hope that this enhances your knowledge and understanding of safety valves.

Sizing Guidelines
The two major considerations for safety valves are proper sizing and correct installation. The following tips address safety valve sizing.

• It is suggested that the setpoint selected for the safety valve provide a differential of at least 20 percent between operating and set steam pressures.
• When considering installation of a safety valve downstream of a steam pressure control valve, the total capacity of the safety valve at the setpoint must exceed the steam control valve’s maximum flow capacity (the largest orifice available from that manufacturer) if the steam valve were to fail to open. The inlet steam pressure to the valve must be calculated at the maximum safety valve setting of the steam supply source, not the nominal operating pressure.
• It is important not to oversize a safety valve. Bigger is not better in this case because a larger-than-required valve could cause chatter, leakage and premature failure.
• Many times, a single safety valve is not possible due to high capacity, physical limitations or economic considerations. An acceptable alternative is to employ multiple safety valves on the same system. The valves should be of the same setpoint and the capacities must be equal to or greater than the rating of the equipment. Additionally, the vent pipe must be sized to account for the venting capacity of all of the safety valves fully opening at the same time.
• The set pressure of the safety valve should be set at or below the maximum allowable working pressure (MAWP) of the component with the lowest setpoint in the system. This includes steam boilers, pressure vessels and equipment, and piping systems. In other words, if two components on the same system are rated at different pressures, the safety device protecting both of these devices must be set at the lower of the two ratings.

Installation
Once sizing has been properly determined, proper installation is the next crucial step to ensure safety. There are several points to consider when installing the safety valve.

• The steam system must be clean and free of any dirt or sediment before commissioning the steam system with a safety valve.
• The safety valve must be mounted vertically with the valve’s spindle in the vertical position.
• The inlet steam piping to the safety valve must be equal to or larger than the safety valve inlet connection.
• There should be no intervening shutoff valves located between the safety valve inlet and the steam component that could permit the safety valve to be isolated from the system.
• Drains or vent openings on the safety valve should not be plugged or capped. They are on the safety valve for a reason.
• Safety valves are set, sealed and certified to prevent tampering. If the wire seal is broken, the valve is unsafe and should not be used. Contact the supplier immediately.
• For multiple safety valve installations using a single connection, the internal cross-sectional area of the inlet shall be equal to the combined inlet areas of all the safety valves.
• All safety valves should use a drip pan elbow on the outlet. The drip pan elbow changes the outlet of the safety device from horizontal to vertical. Installation of the drip pan elbow has its own guidelines, which should be researched and addressed to meet the needs of each application.
• Never attach the vent discharge piping directly to the safety valve. This would place undue stress and weight on the valve body. Also, the safety valve vent pipe may not touch the drip pan elbow.
• The drains on the drip pan elbows are to direct condensed vapor and rain safely away to the drain. Do not plug these openings.
• Steam will not escape from the drip pan elbow if the vent line is sized correctly.

Vent Piping
There also are some important considerations when it comes to the vent piping of the safety valve and the steam system.

• The diameter of the vent pipe must be equal to or greater than the safety valve outlet.
• The vent line should be sized so that back pressure is not placed on the drip pan elbow.
• The length of the vent pipe should be minimized where possible.
• The discharge outlet of the vent pipe should be piped to the closest location where free discharge of the safety device will not pose a safety hazard to personnel. For a roof-line termination, the vent should be no less than 7′ above roof line. The top of the vent line should be cut at a 45° angle to dissipate the discharge thrust of the steam, prevent capping of the pipe and to visually signify that it is a safety valve vent line.

Fig. 1: Typical safety valve designs

Taken from Nationwide Boiler Blog



The Function of the Volute

Misunderstood pump element serves to minimize mixing loss

It is a common misconception in the U.S. pump industry that the function of the volute is that of a diffuser: to convert velocity into pressure. The McGraw-Hill scientific dictionary states that a volute is “a spiral casing for a centrifugal pump…designed so that speed will be converted to pressure.”


Function at Best Efficiency Point (BEP)

Figure 1. A single-volute casing maintains a constant velocity and uniform pressure around the impeller only at BEP.

Figure 2. Hydraulic radial thrust for volute casings.

It is understandable that such a concept has been adopted because the volute has an increasing flow area as it wraps around the impeller, similar to a diffuser, but it is not the purpose of the volute to be a diffuser. Its function—when the pump is operating at the best efficiency point (BEP)—is to keep the velocity constant around the impeller so that mixing losses are minimized. To achieve that function, the area increases so as to accept the additional flow exiting the impeller, which exits the impeller all around the outside diameter (OD)—360 degrees. The pressure surrounding the impeller is uniform, resulting in zero hydraulic radial thrust on the impeller.
 
Performance with Restricted Flow
When the flow from the pump is restricted, forcing the pump to operate at a reduced capacity, the flow from the impeller is reduced, and the volute does act as a diffuser, creating an increasing pressure from the cutwater all the way around to the casing throat. The maximum pressure rise occurs at shut-off (zero flow). As shown in Figure 1, this rise in pressure around the impeller creates a radial thrust on the impeller that pushes the impeller in a direction approximately 90 degrees downstream from the cutwater. As shown in Figure 2, the maximum thrust occurs at shut-off.

Performance with Excess Capacity
When the pump is allowed to operate at a capacity that exceeds the BEP, the result is just the opposite. The velocity around the impeller increases, from the cutwater to the throat, causing a drop in pressure. This results in a radial thrust that pushes the impeller in the opposite direction, approximately 270 degrees downstream from the cutwater, as shown in Figures 1 and 2.
 
Taken From Pump-Zone

Combustion Air Fan & Efficiency

In order for your boiler to operate at peak efficiency, it is important that the correct balance of fuel and combustion air is achieved. Air and fuel ratios are controlled through linkages, fans, dampers and the increase or decrease of gas pressure. Gas pressure is controlled through a pressure regulator and a fan controls the volume of combustion air.

If there are any problems with the fan, more energy may be introduced into the system, causing decreased efficiency. To help ensure that your equipment is running at its peak performance, please review the common fan problems below.

Fan Capacity/Pressure is Below Rating:
1. Dampers or variable inlet vanes are not adjusted properly
2. Fan inlet or outlet conditions are impaired
3. Multiple air leaks within the system
4. Damage sustained to the blower wheel
5. Direction of rotation is incorrect

Fan Vibration:
1. Worn bearings
2. Unstable foundation
3. Foreign material in the fan causing an imbalance
4. Misalignment of bearings, couplings, wheel or v-belt drive
5. Damaged wheel or motor
6. Bent shaft
7. Worn coupling
8. Loose dampers or variable inlet vanes
9. Speed too high or incorrect fan rotation
10. Vibration to fan transmitted from another source
11. Uneven blade wear
12. Loose or broken bolts or set screws

Overheated Bearings:
1. Improper lubrication
2. Poor alignment
3. Damaged wheel or driver
4. Bent shaft
5. Abnormal end thrust
6. Dirt in bearings
7. Improper belt tension

Overload on Driver:
1. Speed too high
2. Direction of rotation is incorrect
3. Bent shaft
4. Poor alignment
5. Improper lubrication
6. Wheel wedging or binding on fan housing

Taken from Nationwide Boiler Blog

What is Shaft Alignment?

For machinery installation, only the rotating shaft centerlines of different machines are aligned. Not the feet, not the coupling, not the shaft surfaces, not the machine housings, not the bearings; only the rotating shaft centerlines. It is important to understand that alignment refers to the positions of two centerlines of rotation or two rotational axes. Note that the shaft’s rotational centerline may be different than its machined centerline.
 Shaft alignment means: Positioning two or more machines so that their rotational centerlines are colinear at the coupling point under operating conditions. Colinear means two lines that are positioned as if they were one line. Colinear as used in alignment means two or more centerlines of rotation with no offset or angularity between them.
 

The phrase “coupling point” in the definition of shaft alignment is an acknowledgement that vibration due to misalignment originates at the point of power transmission, the coupling. It does not mean that the couplings are being aligned. The shafts are being aligned, and the coupling center is just the measuring point.”At operating conditions” is an acknowledgement that machines often move after start-up due to wear, thermal growth, dynamic load shifts, or support structure shifts.Besides the above considerations, the term shaft alignment also implies that the bearings and shafts are free from preloads. In properly installed equipment, there are no forces or strains on the bearings and shafts, except those the designers intended. If the machine is installed with the frame distorted because of uneven or imperfect base plates, bent feet, pipe stresses, or whatever, then machine life will be shortened, often significantly.The only way to determine rotational centerlines is to rotate the equipment. There is no series of measurements that do not involve turning the shafts between readings that can be used to find the rotational centerline.

If you don’t turn the shafts…Any system that takes so-called alignment measurements without turning BOTH shafts is aligning surfaces, not centerlines of rotation. The results of any alignment efforts where one or both shafts are not turned are highly dependent upon surface quality, rotor eccentricity, shaft straightness, and other surface defects. In short: “If you do not turn the shafts, you are not doing shaft alignment.”


Taken from Ludeca Blog
 

Sir Frank Whittle, Father of the Gas Turbine

Discussions about gas turbines and their application to land-based power generation, gas pipeline and process plants should rightfully begin with British engineer Sir Frank Whittle.  The key word here is application. His predecessors were many, but Whittle should be credited for bringing ideas regarding the jet engine to fruition in industrial applications.
  In 1941, Sir Frank Whittle designed the first successful turbojet engine for air defense during World War II.  Dubbed the Gloster Meteor, it flew in defense over Great Britain.  Whittle improved his jet engine as the war progressed.  He shipped a prototype engine to General Electric in the United States in 1942.  GE built America’s first jet engine for military aviation applications the following year.
  Whittle came to the USA for the first time on a secret mission in the summer of 1942.  He met with officials from General Electric in Lynn, MA and Bell Aircraft Company in Buffalo, NY.  Later in 1942, he visited GE in Schenectady, NY, where a rudimentary propeller jet engine was under development.  Whittle’s comments and suggestions to American engineers proved invaluable in modifications and improvements that soon followed.
  One can argue that the development of jet engine might have been accelerated had World War II lasted longer.  However, the other side of that argument is that the application of turbo-technology to other industries became a post-war quest of American industry.  In the eyes of many engineers on both sides of “the pond,” this method of power production and propulsion could be used to drive land-based generators, compressors and other load devices, as well as to propel ships and aircraft in commercial applications.  All that was needed was funding and the imagination of the engineers involved, eager as they were to apply this innovative prime mover.

Fig. 1-1: Sir Frank Whittle and his multi-combustor jet turbine (circa 1941)

The multi-combustor, turbo-jet engine (hereafter called the gas turbine) has Frank Whittle proudly standing beside it in Fig. 1-1.  Notice that there are 10 combustion chambers (tube shaped) encircling the engine, with stainless steel nozzles to inject fuel into them at the front ends.  The chambers are interconnected by cross-fire tubes, as is common on most modern gas turbines.  The exhaust diffuser is in the center.  The reverse-flow concept of the hot gases is obvious from the photograph.  So are the transition pieces curling from the discharge of each combustor.
  “If necessity is the mother of invention,” as preached to engineering students by college professors, then the end of WW-II brought many needs to the front burner ready to be invented.  Jet engine technology needed to be harnessed and applied to other commercial endeavors.  As a prime mover, the gas turbine needed to find applications that could deliver power to other modes of transportation, electrical power delivery and natural gas pipelines prime movers.  However, as inventors soon found, not every idea has a viable application to industry, or a willingness of the public to accept them.  Engineers like Whittle would encounter doubters, the enemies of progressive thinkers.  Progress often depended upon inventors who could convince entrepreneurs and angel investors to take a chance on their ideas and innovations.  This presumes that negative forces are not overwhelmingly against such visionaries.  As explained in later chapters of this blog, GE engineers struggled to get funding in a fledgling gas turbine department in Schenectady, NY in the 1950s.
It is uncertain if Frank Whittle could have envisioned a modern gas turbine like the one shown in Fig. 1-2 below.  A single-fuel (natural gas) General Electric MS7001EA gas turbine (approximately 80 megawatt rating) is shown, with fuel line “pigtails” coming from the manifold on the left leading to each combustor. The chambers themselves are inside the combustion wrapper, which encircles the turbine, so only the covers are showing.

 

 Fig 1-2; Multi-combustor GE MS7001EA Gas Turbine inside Combustion Wrapper (circa 2000)

  Since the combustors are interconnected via cross-fire tubes, only one combustor needs to have a sparkplug (igniter) and another, a flame detector.  However, for redundancy and reliability, modern gas turbines typically have at least two of each, as shown in Fig. 1-3.

 Fig 1-3: Typical configuration of Multi-combustor Gas Turbine with Spark Plugs & Flame Detectors

Design of combustion systems, like those depicted herein, seems to be a “settled” issue.  Most manufacturers have decided that this is the design that makes the most sense.  It allows for temperature equalization and flow distribution to the first-stage turbine nozzle and rotating wheels with buckets (blades) that develop the output power.  Refer to Fig. 1-4 below.

 Fig 1-4: Cross-fire tubes between adjacent combustion chambers

Fig. 1-5 below should be studied for its completeness regarding the design of a typical modern combustion system for a GE MS7001EA gas turbine.  Notice that the combustors are “canted” in design to straighten the hot gas flow through the transition pieces toward the first-stage nozzle (not shown).  Also, this design shortens the length of the turbine and thus bearing spans.  The reverse flow of the air from the compressor discharge casing is also shown entering the combustor.

Fig 1-5: Typical Modern Combustion Chamber and Transition Piece Configuration

Other areas of development have also occurred over the past 70 years with gas turbine technology.  Advances in metallurgy, ceramic coatings and internal cooling designs have evolved over the past seven decades, to a point where efficiencies and higher internal firing temperatures have made the gas turbine a viable competitor to other forms of power generation.
  In conclusion, over sixty years ago an engineer from Britain named Frank Whittle envisioned, designed and built a multi-combustor, aero-derivative gas turbine engine for land-based applications. His innovative design in gas turbine technology has prevailed for the following six decades well into the 21st century.
Taken from Lucier Blog

Air-Operated Double-Diaphragm (AODD) Pump

The ancient Greek philosopher Plato is credited with coining the phrase, “Necessity is the mother of invention,” meaning that a need or problem encourages creative efforts to meet the need or solve the problem. It is unknown whether that phrase was going through Jim Wilden’s head as he watched water from a ruptured pipe gush into a shop at a steel factory in San Bernardino County, Calif., 50 years ago. Knowing that it needed to be removed, Wilden went to work, and in 1955, he had the solution—the air-operated double-diaphragm (AODD) pump.

The same ingenuity still occurs today, but now for a multitude of biopharmaceutical processes. The AODD pump has evolved to uniquely solve complex fluid transfer needs in this industry. Because of the critical nature of some processes, inefficient product transfer methods such as manual rolling carts with containers, purging tanks to evacuate product or manual gravity feeding transfers have been common. However, specifically designed AODD pumps for this industry now allow further use of pumped transfer processes (and associated production and energy efficiency) approaching the degree already found in the general chemical/industrial sector. 

First, Do No Harm

The diaphragm pump already has a cousin in the industry…the diaphragm valve. The diaphragm valve has long been the valve of choice in these types of applications because of its high product containment and clean ability traits. These are also available with AODD pump technology, along with a sealless stem and shaft-free product-side environment.
This is important as both the diaphragm valve and diaphragm pump have less risk of producing product damaging shear, and neither technology has dynamic seals that would risk leaks that could contaminate the product or the production environment.

So with innovations and enhancements for the ultra-sanitary conditions needed by the pharmaceutical industry, the diaphragm pump is now an attractive option for many fluid transfer needs. These processes—and the products they produce—must meet a wide array of regulations and certifications to ensure that they are being performed in a high-purity environment. Among the regulations that AODD pumps can satisfy are those from EHEDG, 3A, CE, ATEX, USP Class VI and FDA CFR 21.177. This includes a validation package with mill, 3.1b, polish, passivation and classified area use certifications. 

The liquids can run the gamut from extremely shear-sensitive to extremely viscous, and semi-solids can range from liquid glucose to polymer slurries. Pharmaceutical and biochemical fluids currently pumped with diaphragm pumps include: blood and by-products, live cell cultures and vaccine producing solutions, egg emulsions for vaccine production, pill coatings, eye care solutions, fluids for oncology, specialized disinfectants, nutraceuticals, vitamins, topicals (creams/lotions) and filter media.  The use of AODD technology can guarantee safe transfer during the production process.

According to Hoover’s, Inc., which analyzes companies and industries that drive the economy, as many as 1,500 companies in the U.S. manufacture and market pharmaceuticals (defined as a compound manufactured for use as a medicinal drug), with combined annual revenue of more than $200 billion. These numbers indicate that the manufacture of pharmaceuticals is one of the lynchpins of the American economy. The actual creation of pharmaceuticals involves one of three major methods:

Synthesis—using chemical reactions to build a drug from simpler components
Extraction—using solvents to remove and purify a drug from a natural source
Biotechnology—using methods such as gene-splicing or the production of antibodies using mammalian (animal-based) cells

No matter the method used to produce biopharmaceuticals, the actual manufacturing process is a precise one that must be performed under demanding, exacting conditions, often in a cleanroom environment that prohibits instances of product leakage, fouling or cross-contamination.

AODD Benefits

Specifically, AODD technology is a boon to pharmaceutical manufacture in a number of crucial areas:

Sterile product transfer —AODD pumps remove the need for gas-purge systems in continuous processes because the technology allows both the filling and emptying process to occur at the same time while keeping the product contained and pure.
Process flexibility —AODD pumps can handle highly variable process conditions found in many hygienic applications.
Sampling—complex pharmaceutical processes under strict conditions require frequent and multipoint sampling. AODD pumps provide the ability to extract these samples while maintaining a high degree of containment and avoiding cross-contamination.
Clean in place (CIP) —the AODD pump’s self-priming, dry-running and sealless design is ideal for CIP operations.
Chemical feed —this is a traditional role for AODD pumps as their sealless design and reliable product containment ensure safety when handling volatile or potent chemicals.
Ingredient unloading —because they self-prime, run dry and have negative suction lift, AODD pumps meet pharmaceutical-validation requirements and can be applied where needed.
Product recovery and semi-solids removal —again, the AODD pump’s dry-run, self-priming and full product containment makes it ideal for use in most filtering or separation processes.
Chromatography, separation, purification and filter feed —these processes often require shear-sensitive transfer and constant pressure feed, traits found in AODD pumps. Extracting delicate cell structures from centrifuge discharge is a good example (see Figure 1)

Maintenance

Simplicity defines the cleaning and maintaining of these pumps. In the highest hygienic configurations, these pumps are designed for CIP so that manual labor and contamination risks do not occur. However, at the same time, these pumps have been purposely designed to be simple to disassemble for either manual cleaning procedures or routine maintenance.

Power and Fluid End Separation

As biopharmaceutical processes evolve, more attention is paid to optimizing the process. The separation of mechanical and utility functions is an example of area/floor space optimization. AODD pumps can be split so that the “power side” is mostly located remotely in an unclassified area and the fluid end can be placed in a classified area, with only an instrument air-supply line connecting the two. This means that electric motors, oil-filled gear cases and greased bearings no longer need to be located in the clean area, raising the level of hygiene and reducing the risk of product contamination.

Figure 1. Integral piston diaphragms (IPD) are featured in certain AODD pumps.

Integral Piston Diaphragm

For high purity industries, one primary innovation that has made this pump among the most viable selections in the industry has been the integral piston diaphragm (IPD) (see Figure 1). Unlike traditional pump diaphragms that have an outer plate that supports the diaphragm that is subject to more difficult cleaning or can be a potential leak point, the IPD is completely laminated with USP Class VI PTFE on the product contact side. This offers the highest degree of containment and clean ability among pumps.

Inside an AODD Pump

The uncomplicated design of AODD pumps features few moving parts, and those that do move have simple, specific tasks:
• Air chamber—houses the air that powers the diaphragms
• Air distribution system—the heart of the pump, it is the mechanism that shifts the pump to create suction and discharge strokes
• Outer diaphragm piston—connects the diaphragms to the reciprocating common shaft and seals the liquid side from the air side of the diaphragm
• Inner diaphragm piston—located on the air side of the pump, it does not come in contact with the process fluid
• Valve ball—seals and releases on the check-valve seats, allowing for discharge and suction of process fluids to occur
• Valve seat—provides the ball valves a place to check
• Discharge manifold—allows fluid to exit the pump through the discharge port, which is typically located at the top of the pump
• Liquid chamber—separated from the compressed air by the diaphragms, it fills with process fluid during the suction stroke and is emptied during the discharge stroke
• Diaphragm—acts as a separation membrane between the process fluid and the compressed air that is the driving force of the pump; to perform adequately, diaphragms should be of sufficient thickness and of appropriate material to prevent degradation or permeation in specific process-fluid applications
• Inlet manifold—allows fluid to enter the pump through the intake port located at the bottom of the pump

(Above): Inside an AODD Pump

Taken from Pump-Zone website

Myth and Truth about Shaft Alignment and Shimming

MYTH: “You should always do your shimming first and then make your horizontal moves.”

TRUTH: This is generally true for the final alignment after soft foot has been corrected, but is not universally true for all alignments. In fact, for the initial rough alignment you should correct the plane with the largest misalignment first, even if this means making a horizontal move first.

Reason: If you have gross misalignment, you could be binding the coupling, deflecting the shafts and imposing undue load on the bearings. By relieving strain from excess misalignment, a truer picture of the alignment condition emerges, and you eliminate one important outside force that affects your soft foot distortion. Therefore, the correct sequence of events in any alignment job is:
1) Safety: Lock out & tag out
2) Clean up and Rough Align
3) Find, diagnose and eliminate Soft Foot
4) Final Alignment:  shimming first, then moves.

Tips from Ludeca Blog

10 Tips to Improve Boiler Efficiency

The need to operate a boiler efficiently in today’s environment and competitive landscape is at the top of many plant owners and operators list. Unfortunately operating a boiler efficiently while meeting local emission regulations do not always go hand in hand. However, advances in boiler system design and low NOx technology solutions have made this a much more achievable task.
The list below includes 10 tips which can instantly improve overall boiler performance and sustainability, helping to achieve more cost-effective maintenance and operations of your steam system.

1. Reduce Excess Air
2. Install an Economizer
3. Install a Condensing Economizer
4. Upgrade to VFD Fan Controls
5. Install a Selective Catalytic Reduction System (SCR) with a Standard Low Excess Air/No FGR Burner
6. Perform Proper Water Treatment
7. Reduce Boiler Pressure
8. Consider Boiler Blowdown Heat Recovery
9. Upgrade to a High Turndown Burner & Controls
10. Implement an Energy Efficiency Program

Tips from Nationwide Boiler

Gas Turbine Performance, Simplified

 It is generally known by observation that gases have particular characteristics.  Variables like pressure (P), temperature (T) and volume (V) have a special relationship in gases that is best understood when considering the model below.  In words, Pressure (P) multiplied by Volume (V) and then divided by Temperature (T) is always constant.  It is a different constant for each gas.  Air, which includes many gases, would have still a different constant than the particular gases in the mixture.  Finally, when fuel (natural gas, for instance) is mixed with air in a gas turbine combustion system, still another constant is realized.  However, when considering the various stages of the Brayton Cycle, the specific constant does not matter in the analysis.
In equation form, that would be:

(P) multiplied by (V)  then divided by (T) = constant

or simply (P x V) ÷ T = constant

This relationship holds through all stages of the gas turbine. It is important, however, that the units of each of the three variables be correct.  In English units, that would be:

• Pressure (P) in pounds per square inch absolute, (psia)
• Temperature (T) must be in degrees Rankin, (˚R). That is, to convert from Fahrenheit to  Rankin, it would be:  T (˚R) = T (˚F) + 460
•  Volume (V) must be in cubic inches, (in³)
  
  Or it can be said, simply:

P (psia)  x  V (cubic inches) ÷ T (degrees R) = constant

  For the four regions of the gas turbine on the pressure-volume (PV) diagram we have:

Region  1 – 2     Region 2 – 3   Region 3 – 4  Region 4 – 1
Compresion      Combustion     Expansion       Exhaust

Thus, we have:

P1  x V1   =    P2 x V2   =    P3 x V3   =    P4 x V4
     T1                  T2                   T3                  T4

 

Imagine a cubic foot of air.  Assume that the “box” of air has dimensions of 12 x 12 x 12 inches, as it enters the compressor.  Try to envision this air cube passing through the gas turbine.

• From the compressor inlet (point 1) the air cube passes through the axial-flow compressor diminishing in size through each stage.
• The air cube, now smaller in size, leaves the compressor discharge (point 2) and enters the combustors at essentially the same pressure.  That is, P2 = P3.
• Then the smaller air cube expands through the combustors to the first stage turbine nozzle, to a point just in front of the turbine buckets at essentially constant pressure (point 3).
• After expanding through the turbine stages, the air cube increases in size, continuing  out the exhaust reaching approximately the same pressure as the compressor inlet (point 4),  That is, P4 = P1.

Fig 1-1 - Brayton Cycle-Pressure Volume Diagram

  We know that pressure, volume and temperature are variables.  However, they only vary throughout the gas turbine cycle in the relationship described above.  Also, notice that the pressure from points P2 to P3 is considered constant, horizontal line on the P-V diagram.  Thus, in the combustion zone, they would then P2 and P3 cancel out on each side of in the following equation leaving:

V2 =  V3

T2     T3

The formula only works for temperatures in degrees Rankin.  Converting to Fahrenheit we have
___V2___ =       ___V3___
(T2 + 460)           (T3 +460)

Take a typical General Electric model series MS5001P, a very popular gas turbine in the world-wide market.  Assume that the turbine firing temperature is Tf = 1800 degrees Fahrenheit.  Assume that the air temperature at the discharge of the compressor is approximately 500 F.  Thus, we would have:
___V2___    =       ___V3___
(500 + 460)           (1800 + 460)

___V2___ =       ___V3___
(960)                   (2260)
Thus, in the gas turbine’s combustion system, the pressure remains essentially constant (P2 ≈ P3).  However, the volume more than doubles, or in this case V3 = 2.35 (V2)

Fig 1-2 - Compressor End View of a Typical Gas Turbine

View of the gas turbine in Fig. 1-2 above showing the compressor and turbine rotor installed inside the casings.  Notice how the compressor stage passageways diminish in size as the air flows through the turbine (getting smaller with every stage).  In Fig. 1-3 below, the compressor rotor blades diminish in size from the R-0 stage to the R-16 stage; again, the air passage ways for the air to flow diminish through this 17-stage compressor.

Fig 1-3 - Compressor Rotor View

Gas turbine performance can be affected by many variables.  One of the most important factors is the change of ambient temperature at the compressor inlet.  Figure 1-4 below shows how changes in ambient temperature impact such variables as Heat Rate, Exhaust Temperature, Exhaust Flow, Fuel Flow and Power Output.  Notice how the Heat Rate (thus the Thermal Efficiency) improves on colder days.  Fuel Flow does increase, as does Power Output.  However, notice that the slope of the Power line is steeper than that of the Fuel Flow, which flattens the Heat Rate line.  More power output for less fuel means higher efficiency.

Fig 1-4 - The Effects of Changes in Compressor Inlet Temperature

So what can I do to improve gas turbine performance without spending tons of money?

• Check compressor discharge pressure (CPD). If it is low, you should clean the compressor by on-line washing or other techniques.
• Boroscope the turbine on a regular basis. If the trailing edge of the first-stage turbine nozzle is distorted or missing metal, performance will suffer. The forces acting on the buckets that develop power output is diminished by a reduction in back pressure on the compressor reduces CPD.
• Be sure that the inlet guide vane (IGV) angles are set properly. This can be determined during a boroscope inspection.  Incorrect settings can reduce air flow and adversely affect power output.
• Record FSNL Data. Once the gas turbine reaches operating speed (called Full Speed, No Load or FSNL), record the following data: 

           1. Compressor Discharge Pressure (CPD)

           2. Fuel Flow (gpm, if liquid fuel or SCFM, if gas fuel)

           3. Average Turbine Exhaust Temperature (TTXM)

           4. Megawatts (MW) – Zero at the moment.

         

Then begin loading the generator and record power output (MW) and observe the other data points (CPD, FF and TTXM) until base load is reached.  These variables should increase in essentially equal proportions from the FSNL data.  Once base load is reached, you should determine if the correct turbine firing temperature, Tf is reached.  

Taken from Lucier Blog