electromagnetic testing emt chapter 15 chemical and petroleum applications

Electromagnetic TestingChapter 14- Electromagnetic Techniques for Chemical and Petroleum Applications23th February 2015 大年初五My ASNT Level III Pre-Exam Preparatory Self Study Notes

Charlie Chong/ Fion Zhang


Chemical & Petroleum Applications


2015-2-23 大年初五

Fion Zhang at Shanghai23th February 2015

Charlie Chong/ Fion Zhang Shanghai 上海


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Chapter Fifteen:Chemical and Petroleum Applications of Electromagnetic Testing

http://fshn.ifas.ufl.edu/faculty/Percival_Lab_Site/tropical-fruit-mango.shtml


15.1 PART 1. Electromagnetic Testing of Process Tubing and Heat Exchangers

15.1.1 TubingTube testing is an important part of maintenance for the refining and petrochemical industry. Heat exchangers and condensers are designed to keep products in the tubes separate from products in the vessel (see Fig. 1). A leaking tube not only could cause a significant impact on production but also could cause a catastrophic failure and loss of life. Tube testing techniques include magnetic flux leakage testing, remote field testing, conventional eddy current testing, ultrasonic testing, laser profilometry and remote visual testing. The present discussion concentrates on electromagnetic techniques; ultrasonic and laser methods complement the electromagnetic techniques and often are used in parallel. Tube testing is typically broken down into two categories: ferrous and nonferrous. Ferrous metals are metals such as carbon steel, 400 series stainless steel and metals with similar magnetic properties; nonferrous metals are nonmagnetic and include copper, brass and most stainless steels.


Table 1 lists techniques used for tubes made of various materials. The choice of technique is mainly influenced by the type of service damage to be detected but often the technique is dictated by tube cleanliness.

For example, rotary ultrasonic testing and laser profilometry require very clean interior surfaces whereas electromagnetic tests do not. Often, electromagnetic techniques are used as screening tools before cleaning for ultrasonic or laser techniques.

Several damage mechanisms and discontinuities can occur. Some are volumetric and not connected with either surface. However, the primary discontinuities are either outside diameter or inside diameter surface breaking discontinuities. Table 2 lists various discontinuities that can be detected with the various techniques for both nonferrous and ferrous tubing materials.


TABLE 1. Applicability of electromagnetic nondestructive tests to ferrous and nonferrous metals.


TABLE 2. Discontinuity detection by nondestructive tests for ferrous and nonferrous metals in used components.


FIGURE 1. Cutaway image of typical heat exchanger, showing tube bundle.

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


Heat exchanger


(I) Eddy Current Testing

The eddy current technique works by inducing electrical currents (eddy currents) in electrically conductive materials as detailed elsewhere. Bobbin probes containing coils are used for tube testing (Fig. 2a). In theory, any discontinuities in the material such as cracks, pitting or wall loss will disrupt the flow of the eddy currents and thus be detected by the instrumentation. Saturation or special probes can be used for thin walled ferromagnetic tubing. Most tube exchanger bundles contain supports susceptible to damage in service. Multiple-channel systems are capable of suppressing or mixing out the signal responses from supports to closely interrogate the material under and near the supports. Conventional eddy current testing is used mainly on nonferrous (nonmagnetic) materials because of the effects from permeability with ferrous materials. In many cases, the owners and users of the exchangers prefer eddy current testing to internal rotary ultrasonic testing because the cleanliness of the tubes is less critical. Additionally, eddy current testing can be several times faster than internal rotary ultrasonic testing.


Keypoints:Conventional eddy current testing is used mainly on nonferrous (nonmagnetic) materials because of the effects from permeability with ferrous materials.


Eddy Current Testing


Typical Tube Defects

http://www.nde.com/ect.htm


Typical Tube Defects – Galvanic Corrosion

http://plastocor.com/wordpress/epoxy-cladding-for-tubesheets-2/


Tube Bundle Cleaning


(II) Remote Field Testing

Remote field testing was developed for ferrous or carbon steel materials and requires a special remote field eddy current probe in which the exciter coil is separated from the pickup coil by a distance of two to three times the tube diameter (Fig. 2b). The receiving or pickup coil then detects the generated flux lines that cross the tube wall twice. Because of the highly magnetic properties of ferrous materials, meaningful eddy current testing requires higher power fields.

Other eddy current techniques for ferrous tubing require complete magnetic saturation of the tube material but remote field testing does not.

The remote field testing amplifier provides the higher power output levels needed for ferrous tube testing and remote field probe coils are designed to handle the increased power levels.

Keywords:Remote field testing was developed for ferrous or carbon steel materials


Because remote field testing is transmitted through the tube wall, it is equally sensitive to discontinuities on the inside surface and outside surface of the tube. However, much like eddy current testing, the factor having the greatest effect on the signal is change in the “cross sectional area”.

Without the proper instrumentation, a 10 percent wall reduction for 360 degrees of tube surface could have a response similar to that for a 90 to 100 percent pinhole.

The owners and users of the exchangers prefer remote field testing to internal rotary ultrasonic testing because the cleanliness of the tubes is less critical. Additionally, remote field testing can be three times faster than internal rotary ultrasonic testing. Remote field testing is somewhat slower than conventional eddy current testing and the speed of travel must be as constant as possible to obtain accurate responses.


Remote Field Testing

http://www.nde.com/paper54.htm


(III) Magnetic Flux Leakage TestingMagnetic flux leakage testing uses a strong magnet inside the probe to magnetize the test object (Figs. 2c and 3). As the probe encounters a wall reduction or a sharp discontinuity, the flux distribution varies around that area and is detected with either a hall effect sensor or an inductive pickup coil. Magnetic flux leakage response is sensitive to discontinuities such as isolated pitting. Magnetic flux leakage testing has been used successfully on air cooled, finned, heat exchanger tubes of carbon steel. Magnetic flux leakage testing is less sensitive to signal effects from the aluminum fins coiled around the carbon steel tubes than remote field testing is.


Magnetic Flux Leakage Testing - Magnetic flux leakage (MFL) is a fast inspection technique, suitable for measuring wall loss and detecting sharp defects such as pitting, grooving, and circumferential cracks. MFL is effective for aluminum-finned carbon steel tubes, because the magnetic field is almost completely unaffected by the presence of such fins.

Powerful Neodymium-Iron-Boron Permanent magnet set

Axially oriented saturating magnetic field

Sturdy probe cableLead pickup coils, absolute or differential

Trail pickup coils, differential

http://www.olympus-ims.com/cs/ms-5800-tube-inspection/


FIGURE 2. Bobbin coil probes for electromagnetic testing: (a) probe for eddy current testing; (b) probe for remote field testing; (c) probe for magnetic flux leakage testing.


FIGURE 3. Magnetic flux leakage probe inserted in carbon steel tube bundleof crude petroleum processing unit.


Electromagnetic testing of Heat Exchanger - Expert at Works


Electromagnetic testing of Heat Exchanger – Differential ET


(IV) Complementary Methods

■ Internal Rotary Ultrasonic Testing - Internal rotary ultrasonic testing is well suited for petrochemical and refinery tube tests. The technique uses an ultrasonic beam to scan the tube internal surface in a helical pattern to ensure that the full circumference of the tube is tested. The system monitors the front wall and the back wall echoes to measure the tube wall thickness precisely. Essentially, a radial B-scan of the tube profiles total wall thickness and pitting on the inside or outside of the tube. A drawback of ultrasonic testing is that the tubes are required to be extremely clean and typically are sandblasted with silicon grit or soda ash. Also, ultrasonic testing can require three times as much time as an electromagnetic technique would.


Internal Rotary Ultrasonic Testing

http://www.sentinelltd.co.nz/Sentinel



http://www.olympus-ims.com/cs/ms-5800-tube-inspection/


■ Laser Profilometry of Tubing - Laser profilometry is based on the principle of optical triangulation. A laser source similar to a standard laser pointer is directed at the surface whose height is to be measured. An imaging lens collects the light reflected from the surface and focuses it onto a position sensitive detector. As the surface height changes, the position of the focused laser spot on the detector moves. The output from the detector is processed electronically to convert the detector positions to accurate height measurements that can be stored on a computer for display and analysis. Essentially, laser techniques provide information regarding the nearside surface by profiling the tube wall. Pitting and wall losses can be detected as a diameter change with a high degree of accuracy. Additionally, laser techniques are used for the detection of cracking, which appears as a disruption or distortion in the optical field.


Laser profilometry

http://www.laserfocusworld.com/articles/print/volume-46/issue-1/features/optical-surface-profiling.html


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Laser profilometry - The stage view in ZeMapper shows a business card with the test area overlay (yellow square; top) and the 3-D map of the selected area (letter e), which shows the ink is raised above the paper fibers of the card (bottom).



15.1.2 Pressure VesselsPressure vessels are continually subject to testing and are considered one of the most critical pieces of equipment in a petrochemical plant or refinery (Fig. 4). Traditional pre-service tests include radiographic and ultrasonic testing during fabrication. Traditional in-service tests include visual, ultrasonic, magnetic particle and more recently electromagnetic techniques such as eddy current testing and alternating current field measurement. Electromagnetic testing can be used for the detection, sizing and evaluation of damage mechanisms such as cracking. Industry practices for in-service tests of pressure vessels have specified visual testing, ultrasonic testing, wet fluorescent magnetic particle testing and electromagnetic testing. Electromagnetic techniques such as eddy current testing and alternating current field measurement offer distinct advantages. To perform wet fluorescent magnetic particle testing, the vessel surfaces must be prepared by sandblasting. Eddy current testing and alternating current field measurement techniques do not require sandblasting and, unlike magnetic particle testing, can also provide depth sizing information.


FIGURE 4. Gasoline processing plant: (a) external view, showing distillation columns; (b) interior view of chamber in distillation column.


Distillation Column

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


Alternating Current Field MeasurementAlternating current field measurement (Fig. 5) was developed from the alternating current potential drop ACPD technique. Potential drop testing has been used for crack sizing and crack growth monitoring for underwater applications such as offshore platforms. The alternating current field measurement technique is simple, relying on the measurement of surface magnetic fields instead of surface electric fields, thus requiring no electrical contact. This reliance on magnetic fields allows the technique to be used through coatings up to 6 mm (0.25 in.). Eddy current techniques and probes can be dramatically influenced by probe liftoff but alternating current field measurement, with its unidirectional fields, is not.

Another benefit of alternating current field measurement is that the technique requires no calibration. The technique relies on field values compared with a theoretical model and database of known crack responses.


FIGURE 5. Equipment for alternating current field measurement.


Electromagnetic Testing –Spherical Tank


15.2 PART 2. Electromagnetic Testing of Transmission and Storage Systems

15.2.1 PipelinesPipelines connect field production (gas and oil extraction) with refineries and petrochemical plants where gas and crude petroleum are processed into usable products (Fig. 6). Because pipelines cross state lines in the United States, they are governed by the Department of Transportation. The construction, maintenance and testing of these pipelines are critical to the safety of the environment and the general public. Buried pipelines not only have the potential for catastrophic failure but could contaminate lakes, rivers and underground water sources if leakage occurs. Traditional pre-service tests include radiographic and ultrasonic testing during fabrication to ensure the quality of the welding. Once a pipeline is in service, the pipeline companies depend largely on in-service testing to assess corrosion. Test strategies before 1970 included leak detection systems.


Since the late 1960s, flux leakage testing tools have been inserted into the pipelines and propelled by product flow. This expedient offers a test technique without significant interruption in pipeline production. In magnetic flux leakage testing, changes in the material mass such as corrosion or pitting cause a localized flux leakage to occur at the discontinuity. These perturbations in the magnetic field are detected by the sensors within the magnetic circuit, are recorded and later are analyzed and reviewed. Much like the baffles or supports in a tube exchanger bundle, the pipelinecircumferential welds provide abrupt signals and easy landmarks when the data are evaluated for discontinuity locations. Smart pigs are test vehicles that product flow pushes through a pipeline (Fig. 7). The technique got its name from a squealing sound from the pig moving through the pipe. At the end of the line or run, the pig is retrieved and the onboard data are then processed and analyzed. The pigs are similar to the magnetic flux leakage probes used in tube testing but the pigs are constructed to propel themselves down pipelines and collect the required test data.


Pigging - The technique got its name from a squealing sound from the pig moving through the pipe.


Pipeline


FIGURE 6. Carbon steel, 0.75 m (30 in.) outside diameter, gas transmissionpipeline.


Gas transmission pipeline.


FIGURE 7. Equipment for magnetic flux leakage testing of pipes and tubes: (a) pig tool; (b) data acquisition from pig sensors.

Permanent magnets

Pickup coils

(a)


FIGURE 7. Equipment for magnetic flux leakage testing of pipes and tubes: (a) pig tool; (b) data acquisition from pig sensors.

Legend1. Pressure.2. Ambient temperature.3. Magnetic field (magnetization).4. Surrounding magnetic flux.5. Magnetic flux leakage (stray flux).6. Odometer (distance and speed).

(b)


Magnetic flux leakage testing pig tool

https://www.nde-ed.org/AboutNDT/SelectedApplications/PipelineInspection/PipelineInspection.htm


Magnetic flux leakage testing pig tool

http://www.pipeway.com/skins/pipeway/standard.aspx?elid=82


Magnetic flux leakage testing pig tool (mfl pig)

http://www.pipeway.com/skins/pipeway/standard.aspx?elid=82


15.2.2 Magnetic Flux Leakage Testing of Aboveground Storage Tank Floors

Tank floors of aboveground storage tanks (Fig. 8) are subject to corrosion where they touch the ground. In the 1970s, ultrasonic testing was being performed on tank floors — spot ultrasonic testing using transducers on large wheels and automated ultrasonic techniques such as C-scanning. One destructive technique was to randomly cut out 0.3 × 0.3 m (12 × 12 in.) square coupons, to visually test them and then either to weld them back in place or to replace them with new patch plates. Magnetic flux leakage test techniques have been widely used in the oil field industry since the 1970s for the testing of pipe, tubing and casing, both new and used. During the 1980s, magnetic flux leakage testing for tank floor applications was introduced to the petrochemical and refining industry.


FIGURE 8. Aboveground storage tank for petroleum products.


Since 1990, this technique has been applied to aboveground storage tank floors to provide a reliable indication of overall floor condition within an economical time frame. Magnetic flux leakage floor scanners provide reliable tests at a fraction of the time and cost associated with ultrasonic thickness gauging. A tank floor test at regular intervals is required by some specifications. As with other techniques, evaluation by ultrasonic testing is required when magnetic flux leakage testing is specified. Generally, the evaluation is accomplished by ultrasonic thickness gauging and sometimes by B-scan or C-scan ultrasonic testing. For tank floor testing, a magnetic bridge is used to introduce as near a saturation of flux as is possible in the test material between the poles of the bridge. Any significant reduction in the thickness of the plate will force some of the magnetic flux into the air around the reduction area. Sensors that can detect this flux leakage are placed between the poles of the bridge (Fig. 9a).


FIGURE 9. Magnetic flux leakage test: (a) schematic of bridge; (b) tank floor scanner incorporating magnetic flux leakage test bridge.


To create leakage fields from corrosion or pitting, it is necessary to achieve near saturation of the magnetic field in the material. Near saturation is accomplished with powerful rare earth magnets, which offer more stability than electromagnets. The sensor can detect the magnetic flux leakage field caused by corrosion and pitting but cannot reliably determine if the flux leakage is caused by top or bottom indications. For uncoated materials, the top discontinuities can be verified during a simple visual test. Other methods such as ultrasonic testing are performed for coated floors. Floor scanning has problems not evident in the testing of tubular goods, where certain parameters can be closely controlled. Probably the greatest problem is that tank floors are never flat whereas tubes are always round. The unevenness of tank floors makes it hard to get reasonably consistent quantitative information. The application of rigid accept/reject criteria based on signal amplitude thresholds is also very unreliable for quantitative information. A realistic approach is required in the application of this test technique and in the design of the test equipment to ensure that fewer significant discontinuities are missed.


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15.2.2.1 Test ConditionsTo optimize the test, it is necessary to consider the environment and address the physical restrictions imposed by the actual conditions found when testing most tank floors.

(I) Climate. The range of temperature and humidity conditions varies enormously during the year and around the world. The effect on both operator and equipment must be taken into consideration.

(II) Cleanliness. Most aboveground storage tanks are dirty and sometimes dusty places to work. The conditions vary widely and depend on how much the tank operator cleans the floors in preparation for magnetic flux leakage scanning. As an absolute minimum, a good water blast is necessary and all loose debris and scale must be removed from the test surface. The surface does not have to be dry but puddles of standing water need to be removed. The cleaner the floor, the better the test.


(III) Surface Condition. Significant top surface corrosion and buckling of the floor plates represent serious limitations to both the achievable coverage in the areas concerned and also the achievable sensitivity. Although very little can be done to improve this situation before testing, it must be considered in the design of the equipment. The effect of corrosion and buckling on the sensitivity of the test must be appreciated by both the tank operator and the inspector. Any physical disturbance of the scanning system as it traverses the floor will result in the generation of noise. The rougher the surface, the greater the noise and therefore the more difficult it is to detect small indications.


15.2.2.2 EquipmentIt is important that magnetic flux leakage equipment produced for this particular application be designed to handle the environmental and practical problems always present. Figure 9b shows a mobile floor scanning unit. Powerful rare earth magnets are well suited for introducing the required flux levels into the material under test. Electromagnets by comparison are excessively bulky and heavy. They do have an advantage in that the magnetic flux levels can be easily adjusted and turned off if necessary for cleaning. Permanent magnet heights can be adjusted to alter flux levels but the bridge requires regular cleaning to remove ferritic debris. The buildup of debris can impair system sensitivity significantly. It is virtually impossible for this technique to achieve 100 percent coverage because physical access is limited. The equipment should be designed so that it can scan as close as possible to the lap joint and shell. The wheel base of the scanner is an important consideration on floors that are not perfectly flat. Smaller scanning heads can be used in confined spaces to increase coverage.


MFL Equipment

http://www.mfeenterprises.com/product-category/mfe-mark-3-tank-floor-scanners/


15.2.2.3 SensorsTwo types of sensors are used for magnetic flux leakage of aboveground tanks: coils and hall effect sensors. Both can detect the flux leakage fields caused by corrosion on tank floors. There is a fundamental difference, however, in the way that they respond to leakage fields and generate a response. Coils are passive devices and follow Faraday’s law in the presence of a magnetic field. As a coil passes through a magnetic field, a voltage is generated in the coil. The level of this voltage depends on the number of turns in the coil and the rate of change of the flux leakage. Scanning speed has a direct effect on the rate of change of the magnetic flux leakage passing through the coils (scanning speed needs to be constant.) Hall effect sensors are solid state devices that form part of an electrical circuit. When passed through a magnetic field, the voltage in the circuit varies with the flux density. It is necessary to carry out some cross referencing and canceling with this type of sensor so that true signals can be separated from other causes of large variations in voltage levels generated by the test. Hall effect sensors are more sensitive than coils and so result in false calls when surface conditions are imperfect. For tube testing, on the other hand, coils are adequately sensitive and are more stable and reliable than hall sensors.


15.2.2.4 Interpretation of Indications

(I) Surface Differentiation. Magnetic flux leakage testing cannot differentiate between indications from the top and bottom of the test object. Some attempt has been made to use the eddy current signals from top discontinuities for the purposes of surface differentiation. Such discrimination is unreliable on real tank floors because the test surface is uneven and dirty. In most cases, visual testing is adequate. Contrary to what is expected, the flux leakage response from a top indication is significantly lower in amplitude than that from an equivalent bottom indication. To some degree, the influence of the top indications can be tuned out to assess the bottom indications.


(II) Quantitative Assessment. Magnetic flux leakage testing is not quantitative but is a reliable, qualitative detector of corrosion on tank floors. Because of environmental and physical restrictions during tests, no reliable quantification of indications is possible. Amplitude alone does not indicate remaining wall thickness because it depends on volume loss. Discontinuities exhibiting various combinations of volume loss and through-wall dimension can give the same amplitude signal. This difficulty plus the continually changing spatial relationship of magnets, sensor and test surface makes an accurate assessment of remaining wall thickness virtually impossible. Quantitative results can be obtained by using ultrasonic testing as a follow up test.

Keypoints:Amplitude alone does not indicate remaining wall thickness because it depends on volume loss. Discontinuities exhibiting various combinations of volume loss and through-wall dimension can give the same amplitude signal.


(III) Misuse of Signal Threshold. Expediency has sometimes motivated accept/reject criteria using a signal threshold but signal amplitude alone is not a reliable indicator of remaining wall thickness. Significant indications can be completely missed where there is a single threshold or where the equipment does not provide a real time display to the operator during the test. To carry out a reliable test, the operator must have as much information as possible available in a real time display that is easy to interpret.

(IV) Computerized Signal Mapping. Mapping of flux leakage signals to tank floor layout is available on some systems. These maps can be used to plan further tests, for corrosion surveys and for hard copy reporting. The usefulness of this equipment must be weighed against the risk of electrical equipment inside storage tanks.

http://www.mfeenterprises.com/product-category/mfe-mark-3-tank-floor-scanners/


(V) Training and Qualification. Training available to inspectors using magnetic flux leakage testing on tank floors is limited. Training must be specific to the equipment. The ultrasonic test must be carried out by personnel who are adequately trained and qualified. It must be remembered that this is not just thickness measurement but rather corrosion evaluation and the technician must have a full understanding of the damage mechanisms and the test technique.


15.2.2.5 ConclusionsMagnetic flux leakage MFL testing is a reliable and economical means of qualitatively assessing the condition of tank floors. The environment and physical restrictions must be addressed in the design of the equipment. Despite the greater sensitivity of hall effect sensors, coils are more reliable for this application. Amplitude of flux leakage signals is an unreliable indicator of remaining wall thicknesses. Quantitative information can be obtained by applying ultrasonic testing to the areas indicated by magnetic flux leakage.


Keypoints:

MFL - Amplitude alone does not indicate remaining wall thickness because it depends on volume loss. Discontinuities exhibiting various combinations of volume loss and through-wall dimension can give the same amplitude signal.

RFT - Because remote field testing is transmitted through the tube wall, it is equally sensitive to discontinuities on the inside surface and outside surface of the tube. However, much like eddy current testing, the factor having the greatest effect on the signal is change in the “cross sectional area”. Without the proper instrumentation, a general 10% wall reduction for 360° of tube surface could have a response similar to that for scattered or isolated 90% to 100% thru wall thickness pinholes.


15.3 PART 3. Electromagnetic Testing of Drill and Coil Pipe15.3.1 Drill Pipe TestingDrill pipe is manufactured from various grades of seamless carbon steel tube, with tool joints of different steel grades friction welded on at either end. Details of chemistry, sizes and grades for both the pipe body and tool joints can be found in various specifications. Drill pipe has also been manufactured from aluminum, a material not addressed here.


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Drilling

http://www.statoil.com/en/About/Worldwide/UnitedKingdom/UKUpstream/Pages/Mariner.aspx


Drilling


(I) Testing in Manufacturing PlantsTo detect material discontinuities, the carbon steel tube body is 100 percent tested by magnetic flux leakage testing, by shear wave ultrasonic testing or by both and may be repaired by discontinuity removal to leave a remaining wall of at least 87.5 percent of the specified wall thickness. The test sensitivity for new tube body is determined from API SPEC 5D.

Acceptable pipe then is upset at each end and the box and pin tool joints are friction welded in place. Tool joints are threaded, one end as a pin connection and the other as a box connection (Fig. 10). The excess metal on the inner and outer surfaces from this process is removed by machining. Then, the friction welds between the pipe body and the tool joints may be tested with conventional shear wave ultrasound for material discontinuities.


FIGURE 10. Diagram for drill pipe testing. (See Table 4.)


(II) In-service TestingTable 3 shows criteria applied to used drill pipe according to API RP 7G. Several points need particular attention.

1. In the case of outside surface cuts and gouges, the remaining wall thickness shall be (a) not less than 80 percent for premium pipe, (b) not less than 70 percent for class 2 pipe with longitudinal discontinuities and (c) not less than 80 percent for class 2 pipe with transverse discontinuities. Discontinuities may be ground out provided (a) the remaining wall is not reduced to less than 80 percent for premium pipe, (b) the remaining wall is not reduced to less than 70 percent for class 2 pipe and (c) the removal by grinding is approximately faired, or smoothed, into the outer contour of the pipe.

2. Where cracks are found, the pipe is considered unfit for further drilling. 3. The average adjacent wall is determined by measuring the wall thickness on each

side of the cut or gouge adjacent to the deepest penetration. 4. String shot refers to discontinuities caused by expansion of the pipe wall after a

controlled explosion to dislodge drill pipe stuck in the hole.

Figure 10 shows the various parts of a drill pipe. Table 4 lists problems that occur with different parts of used drill pipes.


TABLE 3. Acceptance criteria for three classes of inservice drill pipe according to API RP 7G.


TABLE 4. Testing of areas of used drill pipe. (See Fig. 10 for parts of pipe.)


(III) Tube Body TestingThe original form of drill pipe testing was visual, with an optical gage for the critical areas at the ends. Then, for many years, drill pipe tube bodies were tested by magnetizing the tube longitudinally and scanning it with rings of inductive coil or hall sensors (Fig. 11). This simple magnetic flux leakage test is sensitive to discontinuities with a transverse or volumetric component, such as internal pitting, external pitting, drilling rig slip marks and fatigue cracks. Inflatable magnetic rubber balloons were also used to detect fatigue cracks on the inside surface. A conductor would also be passed through the pipe, a shot of current fired and the tube magnetized circularly before magnetic flux leakage or magnetic particle testing over the tube body. Figure 12 shows a typical signal from such a test. Additionally, the tool joints could be tested with the residual circular field for longitudinal imperfections such as cracks from string shot and longitudinal heat check cracking on the tool joints. Circular magnetization has been accomplished by using capacitive discharge units. Spinning gamma ray pipe wall thickness gages are used to measure the wall thickness of the tube in a spiral pattern. This test does not cover the tool joints and scans only a limited part (2 to 30 percent) of the tube wall but is extremely effective in detecting wall thinning from wear and pipe eccentricity.


In magnetic flux leakage testing for transverse discontinuities, a coil magnetizes the pipe wall longitudinally to saturation and detector coils or hall effect sensors ride inside the magnetizing coil as close to the tube outside surface as they can be placed. Usually, they are mounted in brass shoes that have the same radius as the pipe and have a layer of tungsten carbide as a wear plate. The axis of the coil is generally perpendicular to the pipe axis, as in Fig. 11. This form of sensor is somewhat tuned to short range magnetic flux leakage and so is effective in reducing longer range noise. It should be noted that magnetic flux leakage induces eddy currents in brass shoes. The signals are filtered and the largest is fed to a chart recorder. This simple system has been effective for many years. In operation, the inspector first backs the test head as far as it will go onto the pipe tool joint connection area, then reverses the direction and scans the entire pipe to the other upset. Often, signals from the internal and external upsets can interfere with imperfection signals and interpretation is difficult in these areas. Ultrasound represents a better option for end regions.


For the longitudinal discontinuity test, two forms of magnetization occur. In one, an internal conductor rod is passed through the pipe, which is then magnetized by one or many shots, often from a capacitor discharge system. It is then scanned by rotating sensors and tested by the resulting residual circular induction. This test is relatively problematic because signals from permeability variations tend to mask serious discontinuities unless signal processing is performed. Of more value is a rotating pole yoke so that the test can be performed in an active induction, where the magnetic flux leakage from imperfections can be many times in magnitude what they were in residual induction.


FIGURE 11. Tube is scanned by ring of transverse sensors: (a) longitudinal section diagram; (b) photograph of equipment.

(a)


FIGURE 11. Tube is scanned by ring of transverse sensors: (a) longitudinal section diagram; (b) photograph of equipment.

(b)


FIGURE 12. Typical signal for flat, parallel coil.


Experts at Work


(IV) Magnetic Measurement of Wall Thickness.For the simple drill pipe field test that uses only longitudinal magnetization, one problem has been the lack of a measurement of the wall thickness, especially on worn drill pipe. Erosion on the inside and outside surfaces is a common problem. The tube body wall is measured with an ultrasonic thickness gage at sample points, which may not include the thinnest part of the wall. No wall thickness measurement is taken by magnetic flux leakage testing, so one improvement effected in the 1990s was the inclusion of an encircling coil inside the magnetizing coil and connected to an integration circuit.


Magnetic wall thickness has also been measured by adding a pickup coil and an integration circuit to measure the total magnetic flux Φ in the magnetizing coil (Fig. 13).

FIGURE 13. Encircling coil total flux system for magnetic flux leakage testing of tubes.


With the air term (the flux in the air between the coil and the pipe and inside the pipe) subtracted by calibration, the total flux Фsteel in the steel is measured:

Фsteel = Bsteel × Asteel

If the longitudinal saturation flux density Bsteel in the steel is a constant, the cross sectional area Asteel of the steel is calculated:

Asteel = π tav (Dmeas − tav )

The average wall thickness tav can also be calculated from Eq. 2.

The measured outside diameter Dmeas of the drill pipe might not include the minimum wall thickness in the case of eccentric seamless tubular goods and eccentrically worn tubes. Outside diameter measurement, however, does help to determine wall thickness of drill pipe by a magnetic noncontact technique and is very effective in locating the thinner regions of the pipe. This technique is then used to measure the average wall thickness of oilfield tubing asit is pulled from a well.


An improvement to the outside diameter measurement technique is to add hall sensors to the magnetic flux leakage shoes and measure the tangential magnetic field immediately above the pipe wall. This technique effectively places the encircling coil close to the pipe surface and collects localized signals (Fig. 14).


FIGURE 14. Tangential magnetic field immediately above pipe wall is measured by hall sensors in magnetic flux leakage shoes. This technique places encircling coil close to pipe surface to collect localized signals.

LegendHc = magnetic fieldHd = demagnetizing fieldP1 and P2 = sensor locations


(V) Tool Joint TestingBecause drill pipe threads suffer tension and consequently often stretch, measurement with a mechanical lead gage is performed to determine the amount of stretch. If the connection is made loose and the pipe is used in deviated wells, there is a possibility of fatigue cracking in the last engaged thread region. The end of the tool joint can be tested by two techniques. The tool joint is wrapped in a coil, magnetized and then tested by the wet fluorescent magnetic particle method. Formulas for the magnetization have been given by Moyer. Careful cleaning of the threads is essential before applying the particle suspension. The critical area may be searched for transverse cracks with multiple-transducer ultrasonic systems.


(VI) Pipe ThreadsAn area that requires special attention during the testing of used drill pipe is the threaded region of the pin and box connections (see Fig. 10). Common problems in these regions include fatigue cracking from overtorquing at the pin thread roots and stretching of the thread metal. Automated systems that use both active and residual magnetic flux leakage techniques can be used for detecting such discontinuities. The stretching and cracking of threads is a common problem. For example, when tubing, casing and drill pipe are overtorqued at the coupling, the threads are in their plastic region. Metallurgical changes in the metal can create regions where stress corrosion cracking takes place in highly stressed areas at a faster rate than in areas of less stress. Couplings between tubes may become highly stressed. Drill pipe threads are a good example of where such stress can cause plastic deformation and thread root cracking.


(VII) Analysis of Magnetic Flux Leakage Signals from CoilsIn one study,4 flat coil signals from internal pitting in drill pipe and other oil country tubular goods were analyzed. It was found that the amplitude of the magnetic flux leakage signal, defined as only the upper part of Fig. 12,

(1) generally increases as the pit deepens or the remaining wall above it lessens,

(2) often decreases as the pit becomes longer and (3) increases as the pit widens.


These competing variations lead to scatter diagrams such as the one in Fig. 15, which indicate that trying to assess discontinuity depth from such amplitude based curves is relatively pointless. The plot in Fig. 15 was actually performed for American Petroleum Institute grade J-55 tubing, a carbon steel with 380 MPa (5.5 × 104 lbf·in.–2) yield strength.25 The general trend is for deeper pits to give bigger amplitude signals because deeper pits also tend to be wider. Such spreads have also been reported by others in assessing pipeline pigging signals. Better assessments are generally made by treating the signal amplitude as the maximum distance between the peak and valley on a signal such as the one in Fig. 12. Such signals generally have one valley deeper than the other because the discontinuity is asymmetrical.


FIGURE 15. Scatter plot of magnetic flux leakage test signals for 73 mm (2.9 in.) outside diameter pipe.


(VIII) Standardization of Magnetic Flux Leakage UnitsDrill pipe test units are often standardized by running the sensors over a 1.6 mm (0.06 in.) diameter through drilled hole in a test standard at the same speed as the pipe to be tested (such coil based signals are speed dependent) and setting the resulting amplitude at some convenient height on a moving chart. For testing of new casing and tubing, electric discharge machined notches are generally used and the test units are expected to show some signal amplitude consistency when the reference indicator is located at twelve, three, six and nine o’clock positions on the pipe. The signals confirm that the pipe is running centrally through the testing unit. Data such as those shown in Fig. 15 indicate the danger of using the amplitude from magnetic flux leakage reference indicators to decide whether to perform further evaluation of the indication.


15.3.2 Coiled TubingCoiled tubing and line pipe are made from electric welded carbon steel manufactured in various grades for use in oil and gas well servicing, coiled tubing drilling and installed well tubing. Tubing sizes are typically 25 mm (1 in.) to 89 mm (3.5 in.) outside diameter with wall thicknesses varying from 2 mm (0.08 in.) to 6.3 mm (0.25 in.). Outside diameters of coiled line pipes range from 13 to 165 mm (0.5 in. to 6.5 in.). Strips are spooled onto drums. Strings are made by welding strips together, end to end, and then passing the strip through a high frequency induction electric resistance welding mill. The result is often a coiled string of length 6 to 10 km (4 to 6 mi). The testing of new coiled product is usually conducted according to American Petroleum Institute specifications.16,28,29 Conventional nondestructive test methods are used: radiographic, ultrasonic and liquid penetrant testing, as well as electromagnetic techniques. The testing of used coiled tubing is different because the anticipated discontinuities differ from those for new product. However, the equipment for inservice testing follows from the desirability of noncontact testing of wall thickness, ovality, pitting, erosion and other damage.


Coiled Tubing


Five types of electromagnetic testing are important for the tubing body:

1. An electromagnetic sensing system for diameter measurement detects ballooning, necking and ovality. Standard eddy current standoff measurement sensors are mounted in a ring to detect changes in outside diameter (Fig. 16). Such ovality measurements are used in collapse pressure calculations. This measurement requires an unpitted outside surface or much compensation and averaging circuitry.

2. A magnetic reluctance wall thickness measurement system enables the thickness of the ambient wall (not localized pits) to be measured along the string, with thin areas caused by erosion, general corrosion and rubbing against the side of the well. These results can then be used for cross sectional area computations and maximum tensile forces for each section of a string. In this method, the field intensity measured with rings of hall effect sensors, placed next to the tube wall, is related to the wall thickness immediately below it as shown in Fig. 14. In principle, the number of poles at locations P1 and P2 affects the demagnetizing field Hd, which in turn affects the tangential field in the sensor ring.


3. The same rings of sensors are also used for detection of pitting, gouges and transverse discontinuities by measuring their magnetic flux leakage. Signals from localized pitting can be electronically removed. Sensitivity to small surface imperfections depends on the liftoff from the tubing surface to the electromagnetic center of the sensor.

4. A standard eddy current (3 kHz) system can be used to detect longitudinal discontinuities and areas of heavy cycling in the tubing surface.

5. Because tubing stretches, it is important to know where the highly fatigued areas are, irrespective of where a length indicator says they are. Such areas may be removed if the fatigue life is higher than that of the rest of the tubing. The same eddy currents that respond to damage within the metal through changes in the electrical conductivity are used.

Electromagnetic test results may be confirmed with visual, liquid penetrant, magnetic particle, radiographic or ultrasonic testing.


FIGURE 16. Eight eddy current liftoff sensors measure ovality of coiled tubing from fixed distance.


15.4 PART 4. Eddy Current Testing of Offshore WeldsEddy current testing can be used for manual inservice nondestructive testing of welds in marine environments. Eddy current testing of underwater welds has become common for oil and gas companies in Europe and the United States.

15.4.1 Method Selection

(I) Nondestructive Test MethodsNondestructive testing methods each have advantages and limitations for detecting various types of weld indications.


Eddy Current Testing of Welds


1. Magnetic particle testing is used for detecting short length and shallow surface breaking indications. Its sensitivity, however, is reduced in detection of indications through coatings of 0.2 to 0.4 mm (0.008 to 0.016 in.). Magnetic particle testing is difficult to use on wet surfaces.

2. Ultrasonic testing is used for detecting volumetric indications. It is generally not as sensitive as magnetic particle testing for detection of fine, surface breaking indications.

3. Radiographic testing is used for volumetric detection of indications. It cannot, however, detect laminar indications. Radiographic testing requires special safety precautions.

4. Eddy current testing is used for detecting surface breaking indications through coating thicknesses as great as 2 mm (0.08 in.) and can be used on wet surfaces. However, because only the area under the probe is being tested at one moment, several scans must be used for complete coverage.


Underwater NDT


(II) Eddy Current Testing and Magnetic Particle TestingConsideration must be given to the component being tested and to the type and size of indication requiring detection - during fabrication, in service or during repair tests. For example, for in-service tests on offshore structures, the predominant indications are surface breaking, mostly in the toe of the weld. Because magnetic particle testing is ideally suited for detection of this type of indication, it has been the method most widely used. Its main drawback, however, is its inability to see through certain coating thicknesses; nor can magnetic particle testing be used on wet surfaces - for example, on surfaces wet from rain. Eddy current testing has the ability to overcome both of these disadvantages. Magnetic particle testing loses its sensitivity when applied through most coatings, so the coating must be removed and reapplied if magnetic particle testing is to be used. In contrast, eddy current testing can be reliably performed through 2 mm (0.08 in.) of nonconductive coating. Both wet and dry magnetic particle testing techniques are difficult or impossible to implement in wet or windy environments.


Portable eddy current instruments can be placed into lightweight, waterproof enclosures. Eddy current probes are inherently waterproof and can be used on wet surfaces.

Magnetic particle testing is a two-handed operation. This constraint does not matter for most applications but is difficult for projects where the inspector must hold the yoke overhead. In contrast, lightweight eddy current probes can be held for scanning with one hand. Using a lightweight instrument of about 3 kg (6 lb), the eddy current technique is suitable for rope access and for overhead applications (Fig. 17). Eddy current testing can be used with minimal visibility as in, for example, the underwater testing of jack supports. To verify any eddy current indications, however, visibility must return for magnetic particle testing to be performed (Fig. 18). Magnetic particle testing produces a residue of particles in the environment. Although particles (wet and dry) may be nontoxic, they may require workers to wear protective equipment to reduce airborne particle inhalation. This may be an important consideration for nuclear applications.


FIGURE 17. Rope access for eddy current testing through coatings.


FIGURE 18. Eddy current testing of welds in marine environment: (a) eddy current scanning through coatings and on damp surfaces; (b) magnetic particle testing verifies eddy current results (arrows point to magnetic particle indication).


Eddy current testing of welds in marine environment


(III) Limitations of Eddy Current Testing

Eddy current testing has distinct limitations compared with other test methods.

1. Compared to other surface breaking indication detection methods (primarily magnetic particle testing), eddy current testing requires a higher inspector skill level for accurate interpretation of signals.

2. Eddy current testing requires the probe to be close to the indication for detection. Specific scanning patterns must be used for the heat affected zone, for the toe of the weld and for weld surface tests. Careful attention must be given to geometry, access and full testing of the part.

3. If equal surface preparation, normal access and a need to test the entire weld (not just one weld toe) are assumed, eddy current testing is slow.


4. Unlike magnetic particle testing, eddy current testing does not produce a visible indication on the test object. Eddy current indications require verification with magnetic particle testing. Typically, the eddy current indication is cleaned to bare metal by using hand tools or a needle gun (an electric, handheld de-scaling tool) before testing.

5. On extremely corroded, rough surfaces, eddy current test performance is degraded by low ratio of signal to noise.

6. Eddy current testing is not suitable for evaluation of indications by grinding because detection is unreliable for indications that are extremely shallow, less than 0.5 mm (0.02 in.).

Before being allowed to perform tests, eddy current inspectors should be independently qualified by performing practical demonstrations on test specimens having indications in the range of sizes and geometries of those to be found in the field.


15.4.2 Other ConsiderationsAs part of a joint industry project in the 1990s, a procedure using lightweight commercial eddy current equipment and weld testing probes was developed. Using qualified recommended practices and personnel, results of eddy current testing were found to be in agreement with results of magnetic particle testing.


(I) Speed of TestingWith efficient practices and inspectors, magnetic particle testing is faster than eddy current testing on bare metal. However, operational factors, surface condition and cost are important. Magnetic particle testing works on the assumption that the area between the yoke legs, about 150 mm (6 in.) wide and 75 mm (3 in.) long, is fully tested in one yoke placement. To test a weld completely, the yoke must be placed in two directions. The scanning rate for magnetic particle testing is about 5 mm·s–1 (1 ft·min–1) for transverse indication scans and about 2.5 mm·s–1 (0.5 ft·min–1) for indications parallel with the weld, such as toe cracks, centerline cracks and cracks parallel in the base metal. Eddy current testing interrogates only the area directly under the probe. Five eddy current scans are typically used for weld testing: two for the base metal (parallel and transverse), one specifically targeted for the weld toes and two for the weld face (parallel and transverse). Additionally, rough weld faces typically will decrease scan speed because of increased signal complexity. Eddy current scanning rates vary with the size and profile of the weld face.


(II) AccessEddy current testing is easier to use from rope access. If most of the testing is in the overhead position, the one-handed eddy current technique is ergonomically easier than magnetic particle testing.


(III) SensitivityOf the two methods (magnetic particle testing and eddy current testing), magnetic particle testing has a slightly greater sensitivity for indication detection. One recommended practice34 gives the sensitivity of magnetic particle testing as 6 mm (0.25 in.) long and 1 mm (0.04 in.) deep. According to a European standard,35 current testing of welds has a sensitivity of 5 mm (0.2 in.) long and 1 mm (0.06 in.) deep. The slight difference in sensitivity between magnetic particle testing and eddy current testing is sometimes not critical. Eddy current testing should be considered for tests of intact coatings in the following circumstances:

(1) where magnetic particle testing would require coating removal and reapplication,

(2) for wet or damp surfaces (bare metal or painted) when the surface would have to be dried to perform magnetic particle testing,

(3) for operations using rope access and (4) for underwater operations where visibility limits the use of magnetic

particle testing.


Eddy current testing of welds in marine environment


15.4.3 ConclusionA combination of eddy current and magnetic particle testing has been successfully used on a number of applications, including the top structural testing of painted offshore oil rigs, large aboveground storage tanks and the testing of painted ship details. The inspector should select the best technique to achieve safety, the required sensitivity and the desired cost effectiveness. Written practices for eddy current weld testing and qualification of inspectors should be specified so that the eddy current test procedures are documented.


Chemical & Petroleum Applications


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electromagnetic testing emt chapter 15 chemical and petroleum applications

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