Problem: A serious misconception concerning the principles of two nondestructive testing methods and their use in the inspection of Oil Country Tubular Goods (OCTG), and drill pipe, seriously threatens the performance of casing, tubing and the drill string. The two NDT methods concerned are electromagnetics (EMI) and gamma radiation (RT-RAM).
While using gamma radiation in an attempt to find rejectable loss of metallic area (LMA) in OCTG, many defects are not located. A much higher rejection rate is obtained using EMI as a detection technique to obviate failures in the well directly related to reduced cross sectional area. Loss of metallic area may result both from service induced factors and from the original manufacturing of the tubular. An explanation of the gamma radiation tool is necessary in order to compare it to the electromagnetic wall loss device.
Basic Gamma Device
All typical gamma pipe inspection systems incorporate a radioactive source housed inside a tungsten camera which is then mounted on a rotating spool. Pipe passes through the spool’s center on a conveyor. There are various camera models with varying levels of quiescent radioactive leakage. Most sources have a value of 1.5 or greater Curies of Cesium 137 (137Cs). Many use 10 curies of 137Cs. A moveable shutter facilitates the opening of the camera’s aperture. Once the camera’s aperture is opened it is spun around the pipe’s exterior. The camera’s source produces a narrow collimated beam of radiation which impinges the steel wall of the tubular. Based upon the thru-put speed of the tubular and normal rotating R.P.M., a helix of up to 18″ will be produced. Many wall loss areas in oilfield tubulars are shorter than this helix. The radioactive beam has a difficult time reporting such a flaw since surface coverage ranges only from 2-35%.(1) Gamma is the predominant method used for the inspection of LMA at this time.
Gamma signal processing electronics are slow to react since the ionization of a phosphor (Thallium activated sodium iodide mounted crystals) (Nal TI) must take place within a photomultiplier. The crystals convert incidence radiation into photons of light scintillations, which are then transformed into an electrical signal. This process is not efficient for three reasons revealed by one manufacturer of photomultiplier tubes. (I)”The light output of NAL (TI) per unit of energy absorbed is non-linear…”. (II)The crystals are temperature sensitive. “A Nal (TI) crystal also exhibits a change in light output per unit energy absorbed as the temperature of the crystal is changed. In the range 20° to 145°C the light output will decrease by approximately 0.20 percent per degree C.” (III)”The characteristics of the photomultiplier tube also change as a function of temperature”.(2)
According to a manufacturer of pipe inspection units using gamma, “We recommend calibrating the wall thickness readout every 25 joints or at 40 minute intervals, whichever is sooner, to ensure accuracy. This is due to the drift effect of the scintillation tube and has to do with temperature changes and length of time in operation”.(3)
Exxon Production Research in a published report revealed, “The gamma ray units make a helical scan of the pipe body which only covers a small percentage of the total surface area, sometimes missing small areas of thin wall such as mill grinds. Verification of defects must be done manually, which may result in over grinding, and many internal defects cannot be measured at all.” “For example, tubing with a wall loss of 30% (at the pit location) has only a 50% chance of being rejected if a 15% wall loss (sample) is used as the rejection criteria.” Even this performance revelation was optimistic since the length of the sample wall loss used for standardization was greater than much of the distinct LMA. Exxon states, “The inspection limitations (of gamma) are especially severe in measuring wall loss of used tubing.” (4)
Historical Gamma Methods
Field inspection systems that use gamma to nondestructively test for eccentricity in new OCTG were prominent in the 1970’s and 80’s. Even today the tool sold to inspection companies incorporates a radioactive source (in an approved camera housing) mounted on a rotating mechanical device. OCTG from 2-3/8″ OD through 13-3/8″ OD with differing cross sections are introduced into the emitted radioactive beam. As the new tubular passes through the inspection station, one of four methods of detecting eccentricity can be employed:
(I) Back scatter.
(II) Two wall thru-transmission.
(IV) One wall thru-transmission.
The back-scatter (reflection) method involves the radioactive absorption and reflectance from the near surface of the tubular. The two wall thru-transmission device positions the photomultiplier tube opposite the camera, electrically averaging the two cross sections. The resultant output value can be misleading when using industry standard rejection criteria to calibrate this method. A chordal method focuses on two points of the pipe’s curvature believing that this produces a more accurate rendition of eccentricity; while the one wall thru-transmission positions the radioactive source outside the tubular, directing the radioactive beam through the wall to the photomultiplier tube positioned on a lance inside.
Among other deficiencies, all of these methods suffer from one or more of the following:
a) lack of sensitivity to wall reductions close to nominal wall values,
b) constant decay of the radioactive source, (which negatively influences standardization against a known wall loss sample)
c) slow inspection speed due to electrical characteristics of the processing electronics and d) wall coverage of only 2- 35%.
Poor Results On Drill Pipe
“Several pipe inspection companies have tried to examine wall losses in used drill pipe and used production tubing with a four-function EMI system.”(5) The rigid design of field portable equipment and the sinuous movement of drill pipe tool joints along the conveyor path, up and over “V” shaped conveyor drive rollers impedes proper location of the pipe in the path of the radioactive beam. Critical to the success of this primitive method is the camera’s distance from the pipe surface. Changes in proximity yield varying results. Fixed installations with reciprocating conveyor rollers only achieved marginal additional success. The majority of inspection systems used today are field portable with rigid conveyors. In addition, small diameters present a targeting problem for the radioactive beam.
Expensive Safety Requirements
Safety in possessing a Cesium-137 source is paramount to reducing liability from employee over exposure, and encapsulation leakage. “Because CsCl (Cesium Chloride) is a soluble powder, special precautions must be taken to keep the (radioactive) material from leaking out of its capsule. The technique recommended….calls for double encapsulation with inner and outer containers made of silver-brazed, Type 316, stainless steel”.(6)
There are employee worn film badges which need processing. In addition, radiation surveys must be performed periodically to comply with state laws in monitoring the camera’s radioactive “leakage”. Mechanical damage to a gamma camera can cause overexposure to workers. Also, a company’s radiological safety officer (RSO) must be trained at an approved school. This is often a problem in today’s uncertain economy with companies watching labor costs closely. And few pipe inspection service company owners have the time to be their own RSO.
Pipe inspection units displaying radioactive placards draw more attention than necessary. State Health Departments highly regulate pipe inspection systems incorporating radioactive devices. Annual fees are charged for source possession and can be quite expensive. In addition unannounced regulatory inspections may take place. Fines for non-compliance are expensive.
Internationally the radioactive pipe inspection device is received with lackluster interest. Radioactivity of any kind is generally equated with liability and many governments frown on its importation. Conversely, an electromagnetic wall loss device is a welcome alternative posing no adverse risk.
Industry Recommended Practices Support Less Effective Method
There are written specifications dealing with the use of gamma radiation wall thickness inspection. Two specifications followed by pipe inspection service companies are the (I)American Petroleum Institute’s Recommended Practice 5A5 (RP5A5) and (II)Standard DS-1™ Drill Stem Design and Inspection, Second Edition, March 1998 put together by TH Hill Associates, Inc. In DS-1 under table 3-1 “Inspection Methods Covered By This Standard”, there is mentioned in paragraph 5, “Electromagnetic 2” that, “…full length tube wall thickness” will be performed on used drill pipe.(7) According to API RP5A5 under 15.2 the text states, “API Specifications 5CT and 5D contain provision for the verification of seamless pipe body wall thickness, excluding end areas. The gamma ray wall thickness measurement meets that requirement”.(8) It is interesting to read further and in 15.3 understand that, “Surface coverage is typically not 100 percent.” In addition, 5A5 proffers “…a minimum and maximum thickness” (on the reference standard) “shall be determined using a micrometer or properly standardized ultrasonic thickness gauge”. It continues, “The (gamma system’s) readout’s minimum thickness value should be adjusted to be within ± 0.010 inch of the minimum thickness selected on the reference standard. The maximum thickness of the standard should be clearly distinguishable on the readout”.(9)
Verification? Measurement? Reality!
The Random House College Dictionary defines verification as, ” a formal assertion of the truth of something”. Also, “to prove the truth of; confirm”. Measurement is defined as “the act of measuring, a measured dimension, extent, size, etc., ascertained by measuring”. The word measure defines as ” the act or process of ascertaining the extent, dimensions, quantity etc., of something, especially by comparison with a standard;…”. ” Size, dimensions, quantity, etc., as thus ascertained”.(10) In reality, a typical readout for gamma (when dealing with multifunction pipe inspection systems) is a paper graph written on with pen and ink or thermal stylus. There are no precise measurement increments, only the indication of thick or thin wall deviating from a fluctuating baseline. Manufacturers of typical gamma systems suggest a 10% differential between minimum and maximum wall. Lesser separation poses a difficulty for the gamma system to display differences meaningfully.
Additionally, source decomposition, antiquated electronics, poor graphical apparatus, and a narrow, spiraling radioactive beam all reduce the possibility of actually finding areas of wall loss. Yet, industry specifications enforce the use of the radioactive method, even when a superior device is available. No mention in any reference material is made in acceptance of the more accurate electromagnetic wall loss detection method.
The solution to this incongruity is available in a unique nondestructive electromagnetic inspection (EMI) technique which quickly locates LMA in OCTG, drill pipe, used or new. Locating areas of LMA which include rod wear, mill grinds, erosion, large pits (which can be shallow or deep), or internal mandral marks eliminates them as risk factors. The EMI technique exceeds gamma as a qualified method for full length eccentric or localized wall loss detection.
Old Habits Die Hard
The EMI nondestructive testing method for detecting wall loss in production tubing was first used in 1990. This method is generally made part of a dual function inspection system which is also capable of inspecting drill pipe for service induced fatigue cracks. Pipe service companies using solid state sensor equipment can inspect the entire running circumference to detect wall loss such as sucker rod wear in tubing or corrosion pitting in drill pipe. Sucker rod wear will vary in length and is usually much greater in area than erosion or shallow corrosion pits, making it readily detectable. Smooth-sided, gradually sloping pits 10mm in diameter and only 5% of nominal wall are clearly displayed on a computer screen. Results may be hard copy printed in color. Coverage is more than 100%. It is incongruous that gamma radiation systems are still allowed to perform LMA inspection after nearly a decade of electromagnetic wall loss detection proficiency.
Small Electromagnetic Device Plays Major Roll
The sensing device employed is a linear solid state small area magnetic sensor (Hall). These sensors are packaged as an integrated semiconductor circuit. In application they are standardized within an applied magnetic field to a known value of wall loss, generally machined into a referencing pipe. The smallest magnetic field reduction detectable causes the sensors to be excited. Excitation produces a linear signal. Linearity permits monitoring of the magnetic field and its direction. Sensor linearity provides repeatability; the most important component of any testing device. “Thus, Hall detectors can be arranged to select any desired directional component of the magnetic field intensity B in three-dimensional space. The face of the Hall device is simply placed perpendicular to the direction of the magnetic flux lines to be measured.”(11) A 10% wall loss area will produce approximately twice the graphic output display that a 5% wall loss area produces. Full length eccentricity and mechanical damage are also readily observed. An associated computer processes the real time signals and presents to the inspector a color graph of the flaw along with all inspection system settings.
Once located the operator will prove-up suspected LMA. Additionally, one computerized portable EMI system using solid state sensors provides “auto-stopping” at the defect site as a patented feature.
When electromagnetic wall loss inspection was introduced in the USA and Europe the quality of tubulars inspected for future use increased. Inspection companies often work for the same customer, inspecting their pipe repeatedly, after service, during the course of its useful life. Interesting revelations were quickly exhibited when comparing the capabilities of gamma to those of electromagnetics. System proficiency, or lack thereof, was noted quickly by companies which owned one inspection device of each type.
In 1993 a German based pipe inspection company performed and published inspection comparisons of wall loss detection using their own portable EMI equipment. The backscatter system employed used a 10 Curie source of 137 Cs and was properly calibrated. The electromagnetic wall loss inspection system was a retrofit into another of this company’s portable pipe inspection systems. Used production tubing was first inspected with the gamma unit and no wall loss rejects were detected. Then the same tubing was inspected with their electromagnetic wall loss system. A large number of internal service induced, rejectable, wall loss areas were immediately located. Rejectable defects of 20% and greater were detected. A 99% wall loss flaw the shape and size of an almond would be the most note worthy corrosion pit located. Eccentric cross section caused separately by corrosion/erosion and sucker rod wear in many tubes were additionally detected. Some of the longest ID reduction was very gradual and measured more than 12″ in length. The spiral of the gamma system simply passed around these reduced areas without detecting them.
Electromagnetics, when applied to new or used tubulars has proven to be more effective in locating loss of metallic area than any radioactive device. Production speeds are enhanced. Difficult LMA is clearly seen and reported via computer. 360° of the pipe’s circumference is investigated with equal sensitivity and resolution to the cross sectional area. Electromagnetics eliminates the requirements for a radiation safety program, making EMI of LMA much more cost effective. In some cases initial equipment costs are cut by more than 50% when eliminating the rotating head on which the radioactive camera is mounted.
One rarely uses a manual typewriter when a word processor is available. Increased consumer awareness in the retail electronics sector inspires the use of equipment which provides better clarity, quality, higher processing speed and safety. For example, portable CD players now have an anti-shock circuit which virtually obsoletes older units. Our gas and oil industry should be no less interested in technological advancements in tubular inspection than in the consumer electronics which we all desire. Industry specifications which enforce the use of this potentially dangerous, costly and antiquated radioactive inspection method should be evaluated.
A good source for information about electromagnetic wall loss inspection can come from pipe inspection service companies. When choosing a company to inspect drill pipe, tubing or casing the end user should inquire about the EMI sensors which are so important to the detection of anomalies. (I) Ask if the sensors are digitally coupled to a computer which can provide real-time digital signal processing of the suspected defects, not just a graphical display on a computer screen. (II) Require a demonstration of the equipment showing its ability to meet or exceed specifications set out in nondestructive testing standards such as API RP7G, RP5A5 and DS-1. (III) Hire a third party inspection company which has a demonstrated background in EMI nondestructive wall loss testing. (IV) Interview the individual who will monitor the inspection. (V) And lastly make a test standard for use in qualifying tubular inspection service companies. This test piece is not costly when compared to the savings gained through the proper nondestructive testing of OCTG.
For pipe inspection companies “time is money”. These tubular pipe inspection service companies are paid by the number of tubulars completely inspected. Systems typically incorporating a gamma wall loss system hamper real production. The slow to react gamma system reduces inspection speeds to 45-60 feet per minute. Compare this to an electromagnetic sensor wall loss device which can easily inspect at 140-200 feet per minute.
Many users of gamma to inspect OCTG do not realize how little coverage the device provides. A 2-35% surface coverage is not optimum. Electromagnetics offer more than 100% coverage. At its best gamma is 65% worse than EMI in determining wall loss. This is a percentage which rental companies, pipe sales facilities and drilling contractors should remember when providing or putting OCTG and drill pipe to work.
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Leakage flux: “Magnetic flux of the (magnetizing) coil that does not link with the test object; the magnetic flux that leaves a saturated or nearly saturated specimen at a discontinuity.”(12)
Hall detector: “A semiconductor element that produces an output electromotive force proportional to the product of the magnetic field intensity and a biasing current.”(13) “When an external magnetic field with a normal induction acts perpendicularly upon the face of the rectangular layer, the charge carriers are deflected by the force acting transversely (across the width of the layer, between the two signal electrodes). The control current paths are no longer longitudinal, but instead are bent to one side by the magnetic field. The two signal electrodes are no longer at the same voltage potential. Instead, a voltage difference known as the Hall voltage, appears across the signal electrodes. The Hall voltage is proportional to the product of the control current magnitude and the magnitude of the normal component of the external magnet field.”(14)
Low Test Frequencies: “Hall effect detectors developed for electromagnetic test systems can be used for very low test frequencies including DC magnetization, and they provide constant sensitivity to magnetic field magnitudes over the operating range from DC to 100 kHz.”(15) e.g. such as those contained in loss of metallic area.
Linear Hall Arrays: “As another example, linear arrays of Hall detectors can be positioned around the circumference of an encircling coil” (magnetizing coil) “(through which circular bars or tubes are passed longitudinally), and used to provide a sensitive electromagnetic inspection” (both for flaws and LMA) “of the entire 360 degree surface in one pass.”(16)
Small Size of Hall Element: “The main advantage of the” (Hall element) “is the small size of its active area.” The second advantage of such devices is that they can be aligned to measure the normal or tangential component of the flux leakage from a discontinuity, with an amplitude that is not dependent on the speed of the sensor over the discontinuity.”(17)
* * * * *
1 Edens, C. Wade, “Electromagnetic Inspection: Wall Loss and Flaw Location in Oil Country Tubular Goods”, presented at the 1991, America Society for Nondestructive Testing, Petroleum Industry Inspection Technology II topical conference, Houston, Texas, June 25-27, 1991.
2 “Bicron, Nal (TL) SCINTILLATION DETECTORS”, ll. Characterisitcs of Nal (TI) Detectors, p. 6, 1974, Bicron Corporation, Newbury, Ohio 44065.
3 Wilsalog 5000 Operations Manual, Wm. B. Wilson Mfg. Co. 1981, Chapter III, p. 20.
4 Moyer, M.C., Peterson, C.W., “The Importance of Quality Tubular Inspection”, presented at the 1981 IADC Drilling Technology Conference, Calgary, Alberta, Canada, March 10-12, 1981.
5 Ibid., 1 above.
6 McMaster, Robert C., “Isotope Radiation Sources”, Section 15, p. 22, Nondestructive Testing Handbook, Volume 1, American Society for Nondestructive Testing, The Ronald Press Company, 1963.
7 Standard DS-1ä, “Drill Stem Design and Inspection”, Second Edition, March 1998, Section 3.8.5 and 3.8.7., TH Hill Associates, Inc.
8 Field Inspection of New Casing, Tubing and Plain End Drill Pipe, American Petroleum Institute, API Recommended Practice 5A5, Sixth Edition, December 1997 (Effective Date: March 1, 1998), Section 15, “Gamma Ray Wall Thickness Inspection”.
9.Ibid., 8 above, p. 36.
10 The Random House College Dictionary, Revised Edition, 1982.
11 Nondestructive Testing Handbook, Second Edition, Volume Four, Electromagnetic Testing, p. 318, American Society for Nondestructive testing.
12 Nondestructive Testing Handbook, Second Edition, Volume Four, Electromagnetic Testing, American Society for Nondestructive Testing, 1986, Glossary and Tables, p. 656, “Electromagnetic Tests with Hall Devices”.
13 Ibid., p. 656
14 Ibid., p. 317
15 Ibid., p. 318
16 Ibid., p. 319
17 Ibid., p. 639
18 Ludlum Measurements, Inc., Instruction Manual for Ludlum Model 3240 Rotating Tube Wall Caliper, March 25, 1981.
GAMMA “GAME” RULES
Here are a few considerations which the user of a gamma radiation device must be aware of:
a.) Typical spiral is 18 inches (you are going to miss a lot of flaws)
b.) Radiation is always present at the source whether the source holder (camera) is on or off. So, keep your radiation exposure badge on at all times when in close proximity to the source.
c.) Instrument electronics should be turned on for a minimum of two hours prior to use with the source ON.
d.) Do not place any part of your body directly in the radioactive path. It has been known that pipe inspection operators who have frequently been exposed to radiation will sometimes not wear their radiation badges for fear that they will be unable to operate the inspection system once the badge is read and a report issued to their employer. This provides ample liability exposure when that employee litigates over his cancer or other malady possibly connected to radiation over exposure. (Remember asbestos?)
e.) Due to the short half-life of CS-137 the source strength must be adjusted often.
f.) Under no circumstance is maintenance to be performed if damage occurs to the source holder. Call the manufacturer of the gamma system or your State’s Department of Health. (How would you like to make that call!)
g.) Special rules apply to transportation and shipment of radioactive materials. Confirm that the person you are shipping the gamma camera to has a valid radioactive license before shipment.
h.) Every 6 months perform a radiation leak test. If any radiation reading above background occurs, use emergency procedures.
i.) Emergency Procedure: Notify law enforcement and your regulatory agency. (Again, who would want to make that call!)
j.) Record maintenance: Maintain records of source, leak/wipe tests and serial numbers of source holders.
k.) Schooling is required in emergency procedure, survey instruments and personnel monitors. A test will be administered. You must pass the test.18
This paper was presented at the ASNT International Chemical and Petroleum Industry Inspection Technology (ICPIIT) VI Topical Conference, held June 7-10, 1999, Houston, Texas, USA.
Wade Edens M.Sc., B.Sc.
President, Oilfield Equipment Marketing, Inc. 4711 Dodge Street
San Antonio, Texas 78217 Tel: 210-657-7607 Fax: 210-657-3660
State University of New York; Syracuse University
LIFETIME MEMBER: American Society for Nondestructive Testing (ASNT)