Pipeline Inspection

Pipeline Inspection - Ultrasound

2010-06-16T09:50:00.000-07:00

Introduction.

Ultrasound is sound waves of identical nature to sound waves, differing such that its frequency range is located in the audible. This method is a major non-testing methods destructive, for quality control and evaluation of materials in the industry today. Its application allows to know the integrity of material thickness and detect discontinuities internal not visible on the surface of the welding. In addition to determining differences in the structure of the material and physical properties.

Materials and equipment to be used.

• Ultrasonic equipment generator signals of 2.25 MHz with an element of Lucita 6 mm * 6 mm (1 / 4 "* 1 / 4"). It recommends the following equipment:
Krautkramer 6 MHZ, USL-32 model.
Krautkramer 2.2 MHZ, USN-52 model.

• Probes of incidence angle 60th issue specifically.
• Coupling: oil.
• Cleaning cloths.

Surface Preparation.

It recommends a manual cleaning entire area of the weld and its surroundings, In order to remove all traces of dirt present in the sample. The surface must be free of dirt and completely dry. It calibrate the equipment to a nominal frequency of 4 MHZ.

Procedure.

• After cleaning the surface shall be the application of coupling, in this case oil.
• If the ultrasonic beam is sufficiently divergent, they cover the height or thickness
union without moving the probe moving back and forth between the distances d and d / 2 as shown in Figure 2.1

•If the sample is thick and narrow beam, a Once the probe oriented at an angle Straight with the solder joint, we must move according to Figure 2.2.

• Following a reciprocating action, among mentioned distances d and d / 2, so
explore the entire section of the union, and a little more to take into account the width of cord.
• For higher security recommended to repeat the test from the other side of the junction (direction 2), because some heterogeneities are best detected in a in the other direction.
• Should combine reciprocating between d and d / 2, with a slight rotation probe to one side to another address perpendicular to the union in order to detect most favorable angles heterogeneities slopes.
•To detect transverse cracks, apply two probes as (a) and (2) Figure 2.2 (C), connected in parallel

Morphology of the heterogeneity.

Interpretation of the signs.

The presentation of results is the type A-Scan in which the height of the echoes of indication or "peaks" represent the beam intensity reflected ultrasound. The horizontal base line indicates the time or distance of travel, vertically while the amplitude is observed signal. The shape of the indication of the echo can
provide some information about morphology heterogeneity.

If the indication of the echo reaches a total height with few steps (high frequency nodes) usually it comes from a flat reflector irradiated in address next perpendicular to the plane, Figure 2.3 (a). On the contrary if the heterogeneity is not flat or is irregular or is flat or rough does not radiate perpendicular, rising indication Echo is usually more gradual, resulting therefore wider, Figure 2.3 (b).

Here are some figures in the which give some general criteria angular probe testing, which can help classify the heterogeneity within one of three simple forms.

• Flat (Fig. 2.4)

•Cylindrical (Fig. 2.5)

• Spherical (Fig. 2.6)

Pipeline Inspection - Visual Inspection

2010-06-16T09:15:00.000-07:00

Direct visual inspection.

The direct visual examination can usually the eye to be about 24 in (609.6 mm) and angle vision no less than 30 degrees from the surface to be examined. Mirrors can be used to improve viewing angle, like magnifying glasses or magnifiers. It should be sufficiently illuminated area. Lighting can be natural or artificial (350 lux)

Control visual examination.

In some cases, the visual inspection of the examination can substitute for direct examination. Control visual examination can be seen through lenses, fiber optics, cameras, etc..

Procedure.

A written procedure can contain at minimum, a description of how it was done the visual examination conditions available for time of test methods surface preparation and failing that,
control method used, lighting provided, equipment or instruments used, Delos besides making acceptance criteria refer to the code used. In some cases it is preferable to relate the
procedure to a specific component in this case the pipe weld inspection high density polyethylene (HDPE).

Supplemental Inspection

2010-03-21T20:37:00.000-07:00

Other inspections may be scheduled as appropriate or necessary.Examples of such inspections include periodic use of radiography and/or thermography to check for fouling or internal plugging, thermography to check for hot spots in refractory lined systems, or inspection for environmental cracking. Acoustic emission, acoustic leak detection, and thermography can be used for remote leak detection and surveillance.
Ultrasonics and/or radiography can be used for detecting localized corrosion.

Vibrating Piping and Line Movement Surveillance

2010-03-14T20:34:00.000-07:00

Operating personnel should report vibrating or swaying piping to engineering or inspection personnel for assessment. Other significant line movements should be reported that may have resulted from liquid hammer, liquid slugging in vapor lines, or abnormal thermal expansion. At junctions where vibrating piping systems are restrained, periodic magneticparticle testing or liquid-penetrant testing should be considered to check for the onset of fatigue cracking. Branch connections should receive special attention.

External Visual Inspection

2010-03-07T20:23:00.000-08:00

An external visual inspection is performed to determine the condition of the outside of the piping, insulation system,painting and coating systems, and associated hardware; and to check for signs of misalignment, vibration, and leakage.

When corrosion product buildup is noted at pipe support contact areas, lifting off such supports may be required for inspection. When doing this, care should be exercised if the piping is in-service.

External inspections shall include surveys for the condition of piping hangers and supports. Instances of cracked or broken hangers, “bottoming out” of spring supports, support shoes displaced from support members, or other improper
restraint conditions shall be reported and corrected. Vertical support dummy legs also shall be checked to confirm that they have not filled with water that is causing external corrosion of the pressure piping or internal corrosion of the support leg.

Horizontal support dummy legs also shall be checked to determine that slight displacements from horizontal are not causing moisture traps against the external surface of active piping components.

Bellows expansion joints should be inspected visually for unusual deformations, misalignment, or displacements that may exceed design.

The inspector should examine the piping system for the presence of any field modifications or temporary repairs not previously recorded on the piping drawings and/or records.

The inspector also should be alert to the presence of any components in the service that may be unsuitable for long-term operation, such as improper flanges, temporary repairs (clamps), modifications (flexible hoses), or valves of improper specification. Threaded components that may be more easily removed and installed deserve particular attention because of their higher potential for installation of
improper components.

Thickness Measurement Inspection

2010-02-28T20:22:00.000-08:00

A thickness measurement inspection is performed to determine the internal condition and remaining thickness of the piping components. Thickness measurements may be
obtained when the piping system is in or out of operation and shall be performed by the inspector or examiner.

Internal Visual Inspection

2010-02-21T20:12:00.000-08:00

Internal visual inspections are not normally performed on piping. When possible and practical, internal visual inspections may be scheduled for systems such as large-diameter transfer lines, ducts, catalyst lines, or other large-diameter piping systems. Such inspections are similar in nature to pressure vessel inspections and should be conducted with methods and procedures similar to those outlined in API 510.
Remote visual inspection techniques can be helpful when inspecting piping too small to enter. An additional opportunity for internal inspection is provided when piping flanges are disconnected, allowing visual inspection of internal surfaces with or without the use of NDE. Removing a section of piping and splitting it along its centerline also permits access to internal surfaces where there is need for such inspection.

TYPES OF INSPECTION AND SURVEILLANCE

2010-02-14T20:10:00.000-08:00

Different types of inspection and surveillance are appropriate depending on the circumstances and the piping system .These include the following:

a. Internal visual inspection.
b. Thickness measurement inspection.
c. External visual inspection.
d. Vibrating piping inspection.

Insulated Piping Systems Susceptible to CUI

2010-02-07T19:55:00.000-08:00

Certain areas and types of piping systems are potentially
more susceptible to CUI, including the following:

a. Areas exposed to mist overspray from cooling water towers.
b. Areas exposed to steam vents.
c. Areas exposed to deluge systems.
d. Areas subject to process spills, ingress of moisture, or acid vapors.
e. Carbon steel piping systems, including those insulated for personnel protection, operating between 25°F–250°F (–4°C–120°C). CUI is particularly aggressive where operating temperatures cause frequent or continuous condensation and re-evaporation of atmospheric moisture.
f. Carbon steel piping systems that normally operate in-service above 250°F (120°C) but are in intermittent service.
g. Deadlegs and attachments that protrude from insulated piping and operate at a different temperature than the operating temperature of the active line.
h. Austenitic stainless steel piping systems operating between 150°F–400°F (65°C–204°C). (These systems are susceptible to chloride stress corrosion cracking.)
i. Vibrating piping systems that have a tendency to inflict damage to insulation jacketing providing a path for water ingress.
j. Steam traced piping systems that may experience tracing leaks, especially at tubing fittings beneath the insulation.
k. Piping systems with deteriorated coatings and/or wrappings.

Corrosion Under Insulation

2010-01-31T19:42:00.000-08:00

External inspection of insulated piping systems should include a review of the integrity of the insulation system for conditions that could lead to corrosion under insulation (CUI) and for signs of ongoing CUI. Sources of moisture may include rain, water leaks, condensation, and deluge systems. The most common forms of CUI are localized corrosion of carbon steel and chloride stress corrosion cracking of austenitic stainless steels.The extent of a CUI inspection program may vary depending on the local climate—warmer marine locations may require a very active program; whereas
cooler, drier, mid-continent locations may not need as extensive a program.

Pipeline Corrosion - Pt 4 (How are pipelines checked?)

2010-01-28T19:07:00.000-08:00

How are pipelines checked:

• Video Inspection Technology
• Umbilical Operated Ultrasonic Tools.(UT)
• Magnetic Flux Leakage (MFL) Technology
• Pipeline Emergency Repair for external corrosion by Clock Spring
• Pipeline External Inspection for detecting of internal and external metal loss using SLOFEC (Saturated Low Frequency Eddy Current) Technology.
• Tank Floor Inspection using Saturated Low Frequency Eddy Current (SLOFEC)
Technology.
• Pipeline Specialized Internal Cleaning using high pressure water systems or/ and
purpose made hydro mechanical cleaning PIGS.
• Risk Based Inspection.
• Rope Access Based (Abseiling) inspection for hard to reach locations.
• Cathodic Protection Ranging from pre-feasibility to final commissioning.
• Closed Circuit Television (CCTV) Inspection.

Pipeline Corrosion - Pt 3 (How to protect pipelines?)

2010-01-24T19:04:00.000-08:00

How to protect pipelines

Corrosion control of pipelines throughout the world is accomplished in the vast majority of cases through the use of cathodic protections combined with suitable dielectric coating.

The key to a successful pipeline or rebar anti-corrosion program is the coating system. There are also advanced polymers, which help with the battle against corrosion.

According to Michael Osborne, President and CEO of Nukote Coating Systems International, "polymer products are 'Thickfilm coatings', which are very different from traditional paints or coatings. Traditional paints and coatings are Thinfilm products that are applied in multiple layers to achieve reasonable thicknesses. Our polymer coatings are 'Monolithic' or nonlayered at any desired thickness and are extremely durable, resistant to impact, erosion, sunlight, abrasion and chemicals providing superior resistance and longer protection to the end user."

Pipeline Corrosion - Pt 2 (What causes corrosion?)

2010-01-20T19:03:00.000-08:00

What causes corrosion

Corrosion is a natural process. The primary driving force of corrosion is based upon the transformation of iron from its natural state to steel.

• Stress corrosion occurs when even a very small pit forms in a metal under stress.
The concentrated stress either deepens and extends the pit, or cracks the protective
film which tends to form. Under continued exposure to the corrosive medium and
stress, the crack extends by alternate corrosion and stress failure.

• Hydrogen embrittlement and hydrogen attack result when atomic hydrogen
penetrates into the grain boundaries of steel producing microcracks, blistering and
loss of ductility. The atomic hydrogen combines into molecules and results in
blistering and laminations.

• Dissimilar soils can effect a buried pipeline, as they will encounter soils that have varying compositions.

Pipeline corrosion - Pt 1 (Introduction)

2010-01-14T19:00:00.000-08:00

As worldwide demand for oil and gas continues to increase, it remains vitally
important that supplies are able to reach the market both quickly and efficiently,
for this, pipelines are vital in creating a significant transportation network - but
therein lies a totally different problem.

Today, new pipeline projects are being fully welcomed by the industry, but in-line with this existing pipelines need to be maintained so that they stay fully operational and that pipeline corrosion doesn't become an issue. Nonetheless, the oil industry's annual corrosion costs are estimated at about US$15 billion.

Some pipelines deteriorate slowly, and in certain cases pipeline life has been reliably targeted at 70 years or more. Other pipelines have been built which have exhausted their useful life after ONE year of operation, according to Corrosion Doctors.

Accurately tracking changes in corrosion rates is a serious challenge for gas pipeline operators. Pipeline regulators require operators to demonstrate that corrosion rates are as low as two mils/yr. or less to ensure safe operation. Should the measured corrosion rate exceed two mils/yr., operators are required to take actions to mitigate the corrosion or effect repairs.

While many approved technologies (e.g., corrosion coupons and electrical resistance (ER) probes) are available for measuring corrosion, most of these technologies measure the corrosivity of the gas rather than the changes in the pipeline wall. Because these methods infer the rate of corrosion of the pipeline indirectly, the accuracy of the measurements can be influenced by numerous factors.

Pipeline Coating and Tapes : Performance Requirements and Testing Methods

2009-12-24T07:41:00.000-08:00

As stated above, the expectation that the system is required to perform at and long term in-ground performance, 30+ years, are quite demanding. Thus, design parameters, functionality long term heat aging and in-ground testing and exposure to the most corrosive soil environment is the first critical stage of development prior to any new product launch.First, the inner-wrap must form a continuous and permanent bond to the primer providing adhesion, soil stress and resistance to cathodic disbondment as well as bond to itself at the overlap regions. Second, the outer-wrap must bond to the inner-wrap and to itself, provide mechanical strength to resist damage
during shipping, handling backfilling and long term rock penetration damage under load. Other requirements include UV exposure of coated pipes during yard storage, low temperature flexibility down to -40 °C and good ductility and flexibility during bending over a wide temperature range.

Pipeline Coating and Tapes :Tape Application to Pipe

2009-12-21T07:35:00.000-08:00

The pipe coating process consists of the following steps,:

* Drying and cleaning using a grit or sand blasting to remove mil scale
* Phosphoric acid wash and drying, if required
* Primer spray and drying
* Inner-wrap application continuously and spirally using precision tension control
* Outer-wrap application continuously and spirally using precision tension control
* Holiday Detection
* Cut backs at both pipe ends

The above steps are carried out using detailed specifics to conform to industry and tape manufacturer application standards under the watchful eyes of a certified inspector. For example, the sand blasting step requires achieving a well defined cleanliness and anchor pattern for the primer/inner-wrap to achieve expected adhesion, primer dryness and thickness, tape tension, temperature and overlap control
are among many application conditions that are required to be practiced. Both tape layers are applied with recommended tension to insure good application to the pipe, to insure good conformability at the overlap and to achieve the mechanical and chemical adhesion of the coating system to the pipe. With machine application using tension, the coating experiences tension and necking down of the coatings by
< 2%. This tension effect creates a “gasket effect” or flow of the adhesive at the overlap sealing the adhesive to the overlap and further creating mechanical adhesion of the coating to the substrate and to the multiple interfaces within the PE tape coating system. Some of the industry standards include DIN 30672, EN 12068, AWWA C-209, C-214 and C-225.

Pipeline Coating and Tapes :Manufacturing Processes

2009-12-21T07:32:00.000-08:00

PE backings are manufactured by either a Calendering or Co-extrusion process whereby, the Polyethylene resins with additives are blended and processed to form a PE sheet or film. The calendering process by the nature of the methodology orients the molecular chains of the Polyethylene to provide some machine direction orientation of the PE film. This orientation provides some unique application advantages relative to the yield point of the PE film when stressed and stretched during application on pipe. Co-extrusion on the other hand does not impart the same degree of orientation, resulting in different tensile properties requiring different application parameters during application on pipe. After the application of the adhesive to the PE backing or film, the product is rolled into master rolls, slit to width and packaged as required by in-use application in the industry.

Pipeline Coating and Tapes : System Composition and Function

2009-12-18T06:28:00.000-08:00

The total tape system components consist of a primer applied directly to the pipe surface, an inner-wrap tape layer that provides a corrosion barrier and an outer-wrap tape layer that provides mechanical
protection.

1. Primer

The primer is an integral part of the cold applied tape system. It is mainly composed of butyl rubber along with tackifiers, stress corrosion inhibitors and other additives that will facilitate good adhesion to the blasted pipe surface as well as maximize bonding of the inner-wrap tape layer to the pipe. These components are typically dispersed in a high evaporating solvent matrix and sprayed at controlled thickness on the blasted pipe surface, allowed to adequately dry prior to the application of the innerwrap tape layer. Due to recent state and federal regulations mandating solvent emission controls, 100%
solids hot melt adhesive “primers” have been developed and introduced recently to the market as an alternate solution. They are also formulated with a butyl rubber and applied to the pipe surface using more specialized spray equipment.

2. Backing

The inner and outer wrap layers backings are primarily composed of Polyethylene (PE). The PE backing is formulated to the demands of the coating for a specific application on pipe, or for a specific application as a coating. The PE composition of the anti- corrosion layer product is different than the mechanical layer, due to the function of the respective layers. The anti-corrosion layer generally has
more medium and low density PE composition which provide strength and conformability, while mechanical layers require the use of select high and low density PE that provide higher mechanical strength, toughness and resistance to stress cracking. A typical formula would include low and high density PE, antioxidants, UV inhibitor and colorant.

3. Adhesive

The adhesive in both tape layers are elastomeric based. Butyl rubber (BR) is predominantly used as opposed to other elastomers. BR’s molecular structure of low unsaturation levels yields unique characteristics of chemical and moisture resistance, thermal stability, weathering and gas permeability, all essential properties required for long term in-ground performance. In addition to BR, a typical
formula would include a tackifier, oil, filler, antioxidant, biocide and a colorant. Cross-linkers may also be used in applications requiring high, long term resistance to excessive soil stress and continuous heat exposure (up to 125 °C). The adhesive works in conjunction with the primer to form a strong bond to the steel substrate,
providing the corrosion protection and long term performance that the pipe requires as well as imparting high cathodic disbonding resistance, high shear and soil stress resistance. Different adhesive formulas are used depending on the surface to be applied to. There is the steel pipe surface and the PE backing layer of the anti-corrosion layer and the backing layer of the mechanical layer. Each layer of the PE
Tape system must have a specific adhesive composition to insure achievement of a good adhesion at each interface.

Pipeline Coating and Tapes : Coating Types

2009-12-15T06:25:00.000-08:00

There are many coating types that are employed in corrosion protection of steel pipes. This protection can be broken down into 2 areas. First, main line coating where this coating is applied to every pipe section with the exception of the last 6” of both ends and second, girth weld where the pipe ends are coated in the field and after the pipe joints are welded. Main line coating types include:

* Cold applied tapes
* Fused tapes
* Fusion bonded epoxy
* 2 part Urethane
* 2 and 3 layer Polyethylene

Girth weld coating types include:
* Shrink Sleeves
* Cold applied tapes
* 2 part liquid epoxy

Originally written by: Abboud L. Mamish

Pipeline Coating and Tapes : Market

2009-12-12T06:22:00.000-08:00

Oil, gas and water transmission and distribution pipelines are considered an essential part of the infrastructures worldwide. Construction activity has undergone unprecedented increases in the last few years due to demand and population growth. Last year’s figures are a clear reflection of this trend which
indicated that over 107,000 miles of new crude oil and natural gas (excluding water) pipelines are either being built, planned or being studied globally, a 17.8% growth over 2007 (1). Investment in constructing a pipeline can be quite high. For example, a planned 42 inch diameter gas transmission line stretching from Wyoming to Oregon (680 miles) is estimated to cost $2 billion. Thus, protecting such valuable assets against corrosion presents a technical challenge. The coating must demonstrate long term performance to maintain:

* Consistent adhesion
* Mechanical protection under high soil loading
* Cathodic protection
* Resistance to soil stress and low moisture and gas permeation
at the pipe’s operating temperatures and over the expected coating life span of 30+ years.

Originally written by: Abboud L. Mamish

Pipeline Coating and Tapes : History

2009-12-09T06:19:00.000-08:00

PE tape was first introduced into the pipeline oil and gas industry in the early 1950s for the purpose of providing long lasting in-ground corrosion protection. These tapes were first applied in the field by the technique referred to as Over-The-Ditch which was later extended to in-plant application. Since its first
introduction, this technology has advanced for mainline application and girth weld protection for new pipelines as well as for reconditioning of older pipelines. Today PE tape market has undergone further growth to protect pipelines that transmits and distributes potable water. Pipe diameter in this application can typically range from 24 – 144 inches.

Originally written by: Abboud L. Mamish

Pipeline Coating and Tapes : Introduction

2009-12-05T07:32:00.001-08:00

The need to protect underground pipes from corrosion started over 60 years ago. The evolution of such protective pipeline coatings started with the use of asphalt, coal tar to cold applied tapes which were followed shortly thereafter with fusion bonded epoxies and more recently 3-layered systems. The cold applied tape system, which is one of the two leading coating systems in the U.S., is used on new or reconditioned pipelines carrying oil, gas and water. Their main function is to provide long term
corrosion protection form underground elements as well as mechanical protection. This paper is an overview describing the system’s composition, performance, benefits and application methods.

Originally written by: Abboud L. Mamish

Detecting Leakage Problems in a Columbia Gas Pipeline

2009-11-07T10:43:00.000-08:00

Natural gas pipelines are important especially in countries where there is constant demand for such energy. A Columbia Gulf pipeline is functional to transport natural gas to the city of New York from the Gulf of Mexico. A Columbia gas pipeline is a physical tube that connects two terminals, the source in the Gulf of Mexico and the receiver in New York. Without such facilities, there would be scarce supplies of the important energy form in one of the most important business cities not just in the United States but also in the whole of the world.

Any Columbia Gulf pipeline is not spared and exempted from having leak problems. Just like natural pipes, there can always be inevitable occurrences and natural elements that would in some way eventually lead to a gas leakage. There is no need to explain the possible risks and dangers natural gas leakages can bring about. In history, known gas leakages in other countries had resulted to catastrophic and tragic events. Any Columbia gas pipeline has the potential to also encounter such a problem.

Because of leak possibilities, every Columbia Gulf pipeline is regulated. Just like in all countries where there are such lines, every single Columbia gas pipeline is covered by safety and operational regulations that are set by governing and appropriate government units and authorities. The main concern of such regulations is always safety followed by functionality of the Columbia Gulf pipeline facilities.

Needless to say, there is always a need to detect or identify any Columbia gas pipeline leakage problem. Imminent danger could be hampered and reversed if only regulators and the utility firms can abruptly and immediately identify and pinpoint such leak problems.

The first and practical technique is manual inspection. This way, the Columbia gas pipeline would have to be inspected physically and manually by its assigned personnel or some designated regulators' representatives. United States regulations give owners of every Columbia Gulf pipeline the responsibility of identifying the presence and whereabouts of any possible leak. Such a practice is already being implemented in Washington, where pipeline operators are mandated and required to detect and pinpoint specific locations of leas within just minutes, in Washington's case within 15 minutes.

Another widely used technique particularly in a Columbia gas pipeline is the Computational Pipeline Monitoring System (CPM). This strategy determines information using related pressures, temperatures and flows in accordance with the forecast hydraulic behavior of the natural gas. The technique is highly technical. Satellite surveillance in any Columbia gas pipeline is also gaining popularity these days.

Article by Amelie Mag

Article Source: ArticlesBase.com - Detecting Leakage Problems in a Columbia Gas Pipeline

Pipeline Inspection : Discovery Channel Vid

2009-11-01T17:53:00.000-08:00

I'd browse through you tube and found this video, it is quite interesting! Some people are too lazy to read all those words :D , they prefer audio and graphics (well I have those attitudes..). So this video is an alternative to understand how pipelines inspection work, particularly for pipeline pigging.

Hydrostatic Testing for Pipelines

2009-10-26T08:04:00.001-07:00

After construction of a pipeline is completed, or if pipe has been replaced or relocated, it is necessary to hydrostatiscally test the pipeline to demonstrate that the pipeline has the strength required to meet the design conditions, and to verify that the pipeline leak free.

Usually operators will specify a test pressure range from 90% to 95% of the SMYS of the pipe. Some will allow test pressure as high as 100% of the SMYS of the pipe and some will test to slightly beyond the SMYS of the pipe. Specifying a test pressure at least equal to 90% of the SMYS of the pipe will qualify it for the maximum allowable operating pressure. Sometimes, the test pressure will be based on the minimum yield strength determined from the mill test report.

Referred from : Pipeline Rules of Thumb Handbook - E.W McAllister

US Patent 7066010 - Hydrostatic test system and method

2009-10-26T08:00:00.000-07:00

Inventors

* Bryant, Layton
* Burch, Eric

What is claimed is:

1. A method for hydrostatic testing of a pipeline that is not in service, comprising: hydrostatically pressurizing the pipeline; temporarily connecting at leant one portableremote telemetry unit to the pipeline for measuring variables associated with the pipeline; transmitting to a central location data corresponding to the variable measurements associated with the pipeline from the at least one portable remote telemetryunit; and disconnecting the at least one portable remote telemetry unit from the pipeline.

2. The method of claim 1 wherein the variables associated with the pipeline include the internal pressure of the pipeline and the temperature of the pipeline.

3. The method of claim 1 wherein the step of connecting comprises temporarily connecting a pressure sensor to the pipeline and temporarily connecting a temperature sensor to the pipeline.

4. The method of claim 1 wherein the at least one portable remote telemetry unit is in two-way wireless communication with a transmitter-receiver located at the central location.

5. The method of claim 1 further comprising remotely controlling the at least one portable remote telemetry unit from the central location.

6. The method of claim 1 further comprising processing the data at the central location.

7. The method of claim 6 wherein the processing includes generating logs corresponding to the variable measurements, calculating pressure loss rates, calculating pressure gain rates and reconciling data corresponding to the internal temperatureof the pipeline with data corresponding to the internal pressure of the pipeline.

8. The method of claim 6 further comprising outputting the processed data to an output device.

9. The method of claim 6 wherein the step of processing includes comparing data corresponding to at least one variable measurement with a predetermined value and activating an alarm when the data corresponding to at least one measured variableis within a predetermined range of the predetermined value.

10. The method of claim 6 further comprising transmitting the processed data from the central location and to a sewer.

11. The method of claim 10 wherein the step of transmitting the processed data comprises providing a two-way satellite link at the central location, providing a satellite in communication with the two-way satellite link and with a satellitegateway wherein the satellite gateway is in communication with the server, sending the processed data from the two-way satellite link and to the gateway via the satellite, and sanding the processed data from the gateway and to the server.

12. The method of claim 11 wherein the satellite is in two-way wireless communication with the two-way satellite link and wherein the satellite gateway is in two-way wireless communication with the satellite.

13. The method of claim 10 further comprising sending the processed data from the server and to at least one user interface.

14. The method of claim 13 wherein the processed data is sent to the at least one user interface over a data network.

15. The method of claim 1 wherein the step of hydrostatically pressurizing comprises providing a means for hydrostatically pressurizing the pipeline with water and measuring variables associated with the hydrostatically pressurizing means.

16. The method of claim 15 wherein the variables associated with the hydrostatically pressurizing means include pressure, the water flow rate and the water temperature.

17. The method of claim 15 wherein the step of measuring variables associated with the hydrostatically pressurizing means comprises transmitting to the central location data corresponding to the variable measurements associated with thehydrostatically pressurizing means.

18. The method of claim 15 wherein the step of measuring variables associated with the hydrostatically pressurizing means comprises connecting an additional portable remote telemetry unit to the hydrostatically pressurizing means andtransmitting data corresponding to the variable measurements associated with the hydrostatically pressurizing means from the additional portable remote telemetry unit and to the central location.

19. The method of claim 18 wherein the additional portable remote telemetry unit is in two-way wireless communication with a transmitter-receiver located at the central location.

20. The method of claim 15 further comprising remotely controlling at least a portion of the hydrostatically pressurizing means.

21. The method of claim 20 wherein the step of remotely controlling comprises connecting an additional portable remote telemetry unit to the hydrostatically pressurizing means and transmitting control signals form the central location and tothe additional portable remote telemetry unit.

22. The method of claim 21 wherein the additional portable remote telemetry unit is in two-way wireless communication with a transmitter-receiver located at the central location.

23. The method of claim 1 further comprising transporting a mobile control station to the central location so that die mobile control station receives the data transmitted from the at least one portable remote telemetry unit.

24. The method of claim 23 wherein the mobile control station comprises a computer for processing the data.

25. The method of claim 24 further comprising transmitting the processed data from the mobile control station and to a server.

26. The method of claim 25 further comprising sending the processed data from the server and to at least one user interface.

27. The method of claim 1 further comprising temporarily connecting at least one other portable remote telemetry unit to the pipeline for measuring variables associated with the pipeline.

28. The method of claim 27 further comprising transmitting data corresponding to the variable measurements measured by the at least one other portable remote telemetry unit from the at least one other portable remote telemetry unit end to thecentral location.

29. The method of claim 27 further comprising transmitting data corresponding to the variable measurements measured by the at least one other portable remote telemetry unit from the at least one other portable remote telemetry unit and to theat least one portable remote telemetry unit.

30. The method of claim 29 further comprising transmitting the data corresponding to the variable measurements measured by to at least one other portable remote telemetry unit from the at least one portable remote telemetry unit and to thecentral location.

31. The method of claim 27 further comprising transmitting data corresponding to the variable measurements measured by the at least one other portable remote telemetry unit from the at least one other portable remote telemetry unit and to arepeater.

32. The method of claim 31 further comprising transmitting the data corresponding to the measurements taken by the at least one other portable remote telemetry unit from the repeater end to the at least one portable remote telemetry unit.

33. The method of claim 32 further comprising transmitting the data corresponding to the variable measurements measured by at least one other portable remote telemetry unit from the at least one portable remote telemetry unit and to the centrallocation.

34. The method of claim 31 further comprising transmitting the data corresponding to the variable measurements measured by the at least one other portable remote telemetry unit from the repeater and to the central location.

35. The method of claim 27 farther comprising disconnecting the at least one other portable remote telemetry unit.

36. The method of claim 28 further comprising remotely controlling the at least one other portable remote telemetry unit.

referred from :-

http://www.patentstorm.us/patents/7066010/claims.html

Pipeline Pigging

2009-10-19T09:54:00.000-07:00

Pigging in the maintenance of pipelines refers to the practice of using pipeline inspection gauges or 'pigs' to perform various operations on a pipeline without stopping the flow of the product in the pipeline. These operations include but are not limited to cleaning and inspection of the pipeline. This is accomplished by inserting the pig into a 'pig launcher' - a funnel shaped Y section in the pipeline. The launcher is then closed and the pressure of the product in the pipeline is used to push it along down the pipe until it reaches the receiving trap - the 'pig catcher'.

If the pipeline contains butterfly valves, the pipeline cannot be pigged. Ball valves cause no problems because the inside diameter of the ball can be specified to be the same as that of the pipe.

Pigging has been used for many years to clean larger diameter pipelines in the oil industry. Today, however, the use of smaller diameter pigging systems is now increasing in many continuous and batch process plants as plant operators search for increased efficiencies.[1]

Pigging can be used for almost any section of the transfer process between, for example, blending, storage or filling systems. Pigging systems are already installed in industries handling products as diverse as lubricating oils, paints, chemicals, toiletries, and foodstuffs.

Pigs are used in lube oil or painting blending: they are used to clean the pipes to avoid cross-contamination, and to empty the pipes into the product tanks (or sometimes to send a component back to its tank). Usually pigging is done at the beginning and at the end of each batch, but sometimes it is done in the midst of a batch, e.g. when producing a premix that will be used as an intermediate component.

Pigs are also used in oil and gas pipelines: they are used to clean the pipes but also there are "smart pigs" used to measure things like pipe thickness along the pipeline. They usually do not interrupt production, though some product can be lost when the pig is extracted. They can also be used to separate different products in a multiproduct pipeline.

http://en.wikipedia.org/wiki/Pigging

Coating Thickness Measurement

2009-10-19T09:51:00.001-07:00

Coating Thickness Measurement
by David Beamish, DeFelsko Corporation

Coating thickness is an important variable that plays a role in product quality, process control, and cost control. Measurement of film thickness can be done with many different instruments. Understanding the equipment that is available for film thickness measurement and how to use it is useful to every coating operation.

The issues that determine what method is best for a given coating measurement include the type of coating, the substrate material, the thickness range of the coating, the size and shape of the part, and the cost of the equipment. Commonly used measuring techniques for cured organic films include nondestructive dry film methods such as magnetic, eddy current, ultrasonic, or micrometer measurement and also destructive dry film methods such as cross-sectioning or gravimetric (mass) measurement. Methods are also available for powder and liquid coatings to measure the film before it is cured.

MAGNETIC FILM THICKNESS GAGES

Magnetic film gages are used to nondestructively measure the thickness of a nonmagnetic coating on ferrous substrates. Most coatings on steel and iron are measured this way. Magnetic gages use one of two principles of operation: magnetic pull-off or magnetic/electromagnetic induction.

Magnetic Pull-off

Magnetic pull-off gages use a permanent magnet, a calibrated spring, and a graduated scale. The attraction between the magnet and magnetic steel pulls the two together. As the coating thickness separating the two increases, it becomes easier to pull the magnet away. Coating thickness is determined by measuring this pull-off force. Thinner coatings will have stronger magnetic attraction while thicker films will have comparatively less magnetic attraction. Testing with magnetic gages is sensitive to surface roughness, curvature, substrate thickness, and the make up of the metal alloy.

Magnetic pull-off gages are rugged, simple, inexpensive, portable, and usually do not require any calibration adjustment. They are a good, low-cost alternative in situations where quality goals require only a few readings during production.

Pull-off gages are typically pencil-type or rollback dial models. Pencil-type models (PosiPen shown in Fig 1) use a magnet that is mounted to a helical spring that works perpendicularly to the coated surface. Most pencil-type pull-off gages have large magnets and are designed to work in only one or two positions, which partially compensate for gravity. A more accurate version is available, which has a tiny, precise magnet to measure on small, hot, or hard-to-reach surfaces. A triple indicator ensures accurate measurements when the gage is pointed down, up, or horizontally with a tolerance of ±10%.

Fig. 1. Pencil-type magnetic pull-off thickness gauge.

Rollback dial models (PosiTest shown in Fig 2) are the most common form of magnetic pull-off gage. A magnet is attached to one end of a pivoting balanced arm and connected to a calibrated hairspring. By rotating the dial with a finger, the spring increases the force on the magnet and pulls it from the surface. These gages are easy to use and have a balanced arm that allows them to work in any position, independent of gravity. They are safe in explosive environments and are commonly used by painting contractors and small powder coating operations. Typical tolerance is ±5%.

Fig. 2. Roll-back dial magnetic pull-off thickness gauge.

Magnetic and Electromagnetic Induction

Magnetic induction instruments use a permanent magnet as the source of the magnetic field. A Hall-effect generator or magneto-resistor is used to sense the magnetic flux density at a pole of the magnet. Electromagnetic induction instruments use an alternating magnetic field. A soft, ferromagnetic rod wound with a coil of fine wire is used to produce a magnetic field. A second coil of wire is used to detect changes in magnetic flux.

These electronic instruments measure the change in magnetic flux density at the surface of a magnetic probe as it nears a steel surface. The magnitude of the flux density at the probe surface is directly related to the distance from the steel substrate. By measuring flux density the coating thickness can be determined.

Fig. 3. Electronic magnetic induction thickness gauges.

Electronic magnetic gages (e.g. PosiTector 6000 F Series, PosiTest DFT Ferrous) come in many shapes and sizes. They commonly use a constant pressure probe to provide consistent readings that are not influenced by different operators. Readings are shown on a liquid crystal display (LCD). They can have options to store measurement results, perform instant analysis of readings, and output results to a printer or computer for further examination. Typical tolerance is ±1%.

The manufacturer’s instructions should be carefully followed for most accurate results. Standard test methods are available in ASTM D 1186, D 7091-05, ISO 2178 and ISO 2808.

EDDY CURRENT

Eddy current techniques are used to nondestructively measure the thickness of nonconductive coatings on nonferrous metal substrates. A coil of fine wire conducting a high-frequency alternating current (above 1 MHz) is used to set up an alternating magnetic field at the surface of the instrument's probe. When the probe is brought near a conductive surface, the alternating magnetic field will set up eddy currents on the surface. The substrate characteristics and the distance of the probe from the substrate (the coating thickness) affect the magnitude of the eddy currents. The eddy currents create their own opposing electromagnetic field that can be sensed by the exciting coil or by a second, adjacent coil.

Eddy current coating thickness gages (e.g. PosiTector 6000 N Series) look and operate like electronic magnetic gages. They are used to measure coating thickness over all nonferrous metals. Like magnetic electronic gages, they commonly use a constant pressure probe and display results on an LCD. They can also have options to store measurement results or perform instant analysis of readings and output to a printer or computer for further examination. The typical tolerance is ±1%. Testing is sensitive to surface roughness, curvature, substrate thickness, type of metal substrate and distance from an edge.

Standard methods for the application and performance of this test are available in ASTM B 244, ASTM D 1400, D 7091-05 and ISO 2360.

It is now common for gauges to incorporate both magnetic and eddy current principles into one unit (e.g. PosiTector 6000 FN, PosiTest DFT Combo). Some simplify the task of measuring most coatings over any metal by switching automatically from one principle of operation to the other, depending upon the substrate. These combination units are popular with painters and powder coaters.

ULTRASONIC

The ultrasonic pulse-echo technique of ultrasonic gages (e.g. PosiTector 200) is used to measure the thickness of coatings on nonmetal substrates (plastic, wood, etc.) without damaging the coating.

Fig. 4. Ultrasonic gauge can measure the thickness
of coatings on nonmetallic substrates.

The probe of the instrument contains an ultrasonic transducer that sends a pulse through the coating. The pulse reflects back from the substrate to the transducer and is converted into a high frequency electrical signal. The echo waveform is digitized and analyzed to determine coating thickness. In some circumstances, individual layers in a multi-layer system can be measured.

Typical tolerance for this device is ±3%. Standard methods for the application and performance of this test are available in ASTM D 6132.

MICROMETER

Micrometers are sometimes used to check coating thickness. They have the advantage of measuring any coating/substrate combination but the disadvantage of requiring access to the bare substrate. The requirement to touch both the surface of the coating and the underside of the substrate can be limiting and they are often not sensitive enough to measure thin coatings.

Two measurements must be taken: one with the coating in place and the other without. The difference between the two readings, the height variation, is taken to be the coating thickness. On rough surfaces, micrometers measure coating thickness above the highest peak.

DESTRUCTIVE TESTS

One destructive technique is to cut the coated part in a cross section and measure the film thickness by viewing the cut microscopically. Another cross sectioning technique uses a scaled microscope to view a geometric incision through the dry-film coating. A special cutting tool is used to make a small, precise V-groove through the coating and into the substrate. Gages are available that come complete with cutting tips and illuminated scaled magnifier.

While the principles of this destructive method are easy to understand, there are opportunities for measuring error. It takes skill to prepare the sample and interpret the results. Adjusting the measurement reticule to a jagged or indistinct interface may create inaccuracy, particularly between different operators. This method is used when inexpensive, nondestructive methods are not possible, or as a way of confirming nondestructive results. ASTM D 4138 outlines a standard method for this measurement system.

GRAVIMETRIC

By measuring the mass and area of the coating, thickness can be determined. The simplest method is to weigh the part before and after coating. Once the mass and area have been determined, the thickness is calculated using the following equation:

T = m x 10
A x d

where T is the thickness in micrometers, m is the mass of the coating in milligrams, A is the area tested in square centimeters, and d is the density in grams per cubic centimeter.

It is difficult to relate the mass of the coating to thickness when the substrate is rough or the coating uneven. Laboratories are best equipped to handle this time-consuming and often destructive method.

MEASUREMENT BEFORE CURE

Wet-film thickness gauges help determine how much material to apply wet to achieve a specified dry-film thickness provided that the percent of solids by volume is known. They measure all types of wet organic coatings, such as paint, varnish, and lacquer on flat or curved smooth surfaces.

Measuring wet film thickness during application identifies the need for immediate correction and adjustment by the applicator. Correction of the film after it has dried or chemically cured requires costly extra labor time, may lead to contamination of the film, and may introduce problems of adhesion and integrity of the coating system.

The equations for determining the correct wet-film thickness (WFT), both with and without thinner, are as follows:

Without thinner:

WFT = desired dry film thickness
% of solids by volume

With thinner:

WFT = desired dry film thickness / % of solids by volume
100% + % of thinner added

Wet-film is most often measured with a wet film comb or wheel. The wet-film comb is a flat aluminum, plastic, or stainless steel plate with calibrated notches on the edge of each face. The gage is placed squarely and firmly onto the surface to be measured immediately after coating application and then removed. The wet-film thickness lies between the highest coated notch and the next uncoated notch. Notched gage measurements are neither accurate nor sensitive, but they are useful in determining approximate wet-film thickness of coatings on articles where size and shape prohibit the use of more precise methods. (ASTM D1212).

The gage should be used on smooth surfaces, free from irregularities and should be used along the length, not the width, of curved surfaces. Using a wet-film gage on quick-drying coatings will yield inaccurate measurements. ASTM D4414 outlines a standard method for measurement of wet-film thickness by notch gages.

A wet film wheel (eccentric roller) uses three disks. The gage is rolled in the wet film until the center disk touches the wet film. The point where it makes contact provides the wet film thickness.

Powder coatings can be measured prior to curing with a simple hand-held comb or an ultrasonic gage. The uncured powder film comb works much the same way as wet film gage. The comb is dragged through the powder film and the thickness lies between the highest numbered tooth which made a mark and has powder clinging to it, and the next highest tooth which left no mark and has no powder clinging to it. These gages are relatively inexpensive with accuracy of ±5mm. They are only suitable as a guide since the cured film may be different after flow. Marks left by the gage may affect the characteristics of the cured film.

An ultrasonic device can be used non-destructively on uncured powder on smooth metallic surfaces to predict the thickness of the cured film. The probe is positioned a short distance from the surface to be measured and a reading is displayed on the LCD of the device. Measurement uncertainty is ±5mm.

THICKNESS STANDARDS

Coating thickness gages are calibrated to known thickness standards. There are many sources of thickness standards but it is best to ensure they are traceable to a national measurement institute such as NIST (National Institute of Standards & Technology). It is also important to verify the standards are at least four times as accurate as the gage they will be used to calibrate. A regular check against these standards verifies the gage is operating properly. When readings do not meet the accuracy specification of the gage, the gage must be adjusted or repaired and then calibrated again.

SUMMARY
Film thickness in coatings can have a big impact on cost and quality. Measurement of film thickness should be a routine event for all coaters. The correct gage to use depends on the thickness range of the coating, the shape and type of substrate, the cost of the gage, and how critical it is to get an accurate measurement.

http://www.defelsko.com/technotes/coating-thickness/coating-thickness-measurement.htm

Coating Thickness Gauge

2009-10-19T09:38:00.001-07:00

1. Coating Thickness Gauges from Oxford Instruments

* For ease of use and high accuracy. come in various models (handheld, benchtop, multi-purpose)

2. Fischer FMP30-40 Coating Thickness Measurement Instrument

* These instruments integrate additional features such as more memory for numerous applications as well as extensive statistical and graphical evaluations. Tolerance limits can be entered into the calibratable applications and the production process can be analyzed statistically. The default mode can be switched to matrix mode for connected multipoint measurements.

3. Portable Coating Thickness Gauge TT210

*. Integrated probe for measurements on ferrous and non-ferrous materials, with automatic substrate recognition.

4. PosiTector 6000 Series Coating Thickness Gage

* Rugged, fully electronic coating thickness gages use magnetic and eddy current principles to measure coating thickness on both ferrous and non-ferrous metals, accurately and quickly.

5.Mikrotest 7 Digital Coating Thickness Gauge

* The new Mikrotest 7 combines the proven measuring principle of magnetic attraction with digital technology. It offers both high resolution measurement and ease of use. The measurement principle is still based on the attraction force of a permanent magnet on steel as defined in all International Standards.

6. Fischer FMP10-20 Coating Thickness Measurement Instrument

* The Fischer FMP10-20 generation of proven portable instruments with wide assortment of plug-in type probes provides precise measurements. In addition to one user created calibration application, these easy to operate and sturdy instruments are suitable for virtually any coating thickness measurement requirement

.

http://www.azom.com/equipment.asp?cat=37

Pipelines coating inspection

2009-10-09T08:18:00.000-07:00

Pipeline coating system is required to avoid corrosion. There are several number of pipeline coating pigment in the market such as:-

i. Asphalt/ Coal or Tar
ii. Tape wrap
iii. Two layer extruded polyethylene
iv. Fusion bonded epoxy coating
v. Three layer polyotefin
vi. Three layer polyethylene Two-layer extruded polyethylene

Polyguard pipeline coatings and tapes is one of the player in the marker for pipeline coating system. Others which is quite well known are Belzona and Akzo Nobel

Pipeline coating pigment can be measured by using coating thickness gauge. There are a lot of coating thickness gauge in the market. Most of the coating thickness gauge in the market use the principle of :-

i. Magnetic induction principle
ii. Eddy Current principle

The coating thickness gauge actually measured the DFT (Dry Film Thickness) of the coating system.

Typical test carried out are:-

i. Coating thickness measurement
ii. Quality of coating (or substrate) material – degradation,
porosity, voids, cracks
iii. Adhesion of coating to the substrate – quality of bond,
disbond areas, undercutting

Pipeline coating inspection must be carried out by a certified Inspector, at least Inspector which is provided by the manufacturer of the coating system. Certified coating inspector are those who have attended and pass the following educational course:-

i. NACE CIP Level 1,2 and 3
ii. BGAS-CSWIP

Alaska Pipeline Inspection

2009-10-09T08:04:00.000-07:00

source taken from :-

http://www.youtube.com/user/VJTechnologies

Pipeline Inspection

2009-10-08T05:59:00.000-07:00

Pipeline inspection is required in any new pipeline construction in order to determine the reliability of the new pipeline. There are a lot of pipeline inspection companies all around the world since pipeline inspection jobs are in demand. Pipeline construction usually associated with Oil and Gas and Water industry. The pipeline contractor usually have their own pipeline inspection team sometime they have to sub the pipeline inspection work to a company which specialize in pipeline inspection. Pipeline inspection activities required a person to have a comprehensive understanding of Pipeline Integrity Management principles.

Pipeline inspection activities include:-

i. Pipelines coating integrity
ii. Pipeline pigging
iii. Cathodic protection system
iv. NDT Testing
v. Leak detection
vi. Hydrostatic testing
vii. Pneumatic testing

"When a pipeline is built, inspection personnel may use visual, X-ray, magnetic particle, ultrasonic and other inspection methods to evaluate the welds and ensure that they are of high quality. "

(source :- http://www.ndt-ed.org/AboutNDT/SelectedApplications/PipelineInspection/PipelineInspection.htm)

"Engineers have developed devices, called pigs, that are sent through the buried pipe to perform inspections and clean the pipe. If you're standing near a pipeline, vibrations can be felt as these pigs move through the pipeline. The pigs are about the same diameter of the pipe so they range in size from small to huge. The pigs are carried through the pipe by the flow of the liquid or gas and can travel and perform inspections over very large distances. They may be put into the pipe line on one end and taken out at the other. The pigs carry a small computer to collect, store and transmit the data for analysis. "

(source :- http://www.ndt-ed.org/AboutNDT/SelectedApplications/PipelineInspection/PipelineInspection.htm)

"A pipeline inspection gauge or pig in the pipeline industry is a tool that is sent down a pipeline and propelled by the pressure of the product in the pipeline itself. There are four main uses for pigs:

physical separation between different liquids being transported in pipelines;
internal cleaning of pipelines;
inspection of the condition of pipeline walls (also known as an Inline Inspection (ILI) tool);
capturing and recording geometric information relating to pipelines (e.g. size, position)."

(source :- http://en.wikipedia.org/wiki/Pigging#Pipeline_inspection_gauge)

Pipeline Inspection

Pipeline Inspection - Ultrasound

Pipeline Inspection - Visual Inspection

Supplemental Inspection

Vibrating Piping and Line Movement Surveillance

External Visual Inspection

Thickness Measurement Inspection

Internal Visual Inspection

TYPES OF INSPECTION AND SURVEILLANCE

Insulated Piping Systems Susceptible to CUI

Corrosion Under Insulation

Pipeline Corrosion - Pt 4 (How are pipelines checked?)

Pipeline Corrosion - Pt 3 (How to protect pipelines?)

Pipeline Corrosion - Pt 2 (What causes corrosion?)

Pipeline corrosion - Pt 1 (Introduction)

Pipeline Coating and Tapes : Performance Requirements and Testing Methods

Pipeline Coating and Tapes :Tape Application to Pipe

Pipeline Coating and Tapes :Manufacturing Processes

Pipeline Coating and Tapes : System Composition and Function

Pipeline Coating and Tapes : Coating Types

Pipeline Coating and Tapes : Market

Pipeline Coating and Tapes : History

Pipeline Coating and Tapes : Introduction

Detecting Leakage Problems in a Columbia Gas Pipeline

Pipeline Inspection : Discovery Channel Vid

Hydrostatic Testing for Pipelines

US Patent 7066010 - Hydrostatic test system and method

Pipeline Pigging

Coating Thickness Measurement

Coating Thickness Measurement by David Beamish, DeFelsko Corporation

Coating Thickness Gauge

Pipelines coating inspection

Alaska Pipeline Inspection

Pipeline Inspection

Coating Thickness Measurement
by David Beamish, DeFelsko Corporation