Ultrasonic Measurement

Key Takeaways

• Ultrasonic pipe wall thickness measurement using pulse-echo (P-E) or through-transmission techniques is one of the most widely deployed NDT applications in the oil and gas industry, providing quantitative corrosion monitoring data on production tubing, flowlines, and pressure vessels without requiring removal of the pipe from service or excavation of buried pipelines: the pulse-echo method uses a single transducer that transmits an ultrasonic pulse into the pipe wall and detects the echo returned from the back wall of the pipe, with the time-of-flight between the transmitted pulse and the back-wall echo (divided by twice the ultrasonic velocity in the pipe material) giving the wall thickness; measurement accuracy is typically plus or minus 0.1-0.5 mm for clean, smooth internal surfaces, but degrades significantly in the presence of internal scale or corrosion products that attenuate the signal and shift the echo timing; automated ultrasonic testing (AUT) systems using phased array ultrasonic transducers (PAUT) that can electronically steer and focus the ultrasonic beam provide C-scan images of corrosion extent and depth across a pipe section in minutes, compared to the days required for conventional manual ultrasonic inspection; the integration of ultrasonic wall thickness data with corrosion rate calculations (comparing current wall thickness to the original nominal wall thickness and to previous measurement data) provides the remaining life calculation that drives pipeline repair, replacement, or risk-based inspection decisions under API 570 (piping inspection), API 653 (tank inspection), and ASME PCC-2 (pressure vessel repair) standards.
• Ultrasonic flow measurement using transit-time and Doppler techniques has replaced positive displacement and turbine meters in many oil and gas pipeline and process applications due to their lack of wetted moving parts (which eliminates mechanical wear and the need for maintenance in dirty or corrosive fluids), their compatibility with bidirectional flow measurement, and their ability to be clamped to the outside of an existing pipe without process interruption for retrofit installations: transit-time ultrasonic meters work by measuring the difference in travel time of ultrasonic pulses transmitted in the downstream direction (with the flow, faster travel time) and the upstream direction (against the flow, slower travel time), with the time difference being proportional to the fluid velocity; Doppler ultrasonic meters measure the frequency shift of the reflected signal from entrained particles or bubbles in the flowing fluid (the Doppler effect), with the frequency shift being proportional to the bubble or particle velocity (approximately equal to the fluid velocity); transit-time meters are preferred for clean liquids and gases where particle content is insufficient for Doppler operation, while Doppler meters are preferred for highly loaded slurries, produced water streams with solids, and two-phase gas-liquid flows; the accuracy of transit-time meters for natural gas custody transfer applications (typically plus or minus 0.5-1.0% of reading) has been demonstrated to be equivalent to orifice plate meters, leading to their widespread adoption in natural gas transmission pipelines and LNG loading terminals where their maintenance advantage over mechanical meters is commercially significant.
• Ultrasonic borehole imaging (UBI) tools for wellbore characterization provide a full 360-degree acoustic reflectivity and transit time image of the borehole wall in oil-based mud environments where resistivity-based microresistivity imaging tools (which require an electrically conductive mud for the measurement current to flow between the pad electrodes and the formation) cannot be used: the UBI tool rotates a single focused transducer as the tool is pulled up the wellbore, transmitting an ultrasonic pulse toward the borehole wall and receiving the reflected pulse, with the travel time from the transducer to the borehole wall giving the borehole radius at each azimuthal and depth position and the amplitude of the reflected signal giving the acoustic reflectivity (which depends on the impedance contrast between the mud and the formation surface, with hard formations giving stronger reflections and rugose or fractured surfaces giving weaker or scattered reflections); the resulting images of borehole radius (caliper image) and acoustic reflectivity provide information on borehole shape (used for wellbore stability analysis and bit size selection for the next section), natural and induced fracture orientation and aperture, bedding plane dip, and formation stress orientation from the pattern of breakout (stress-induced enlargement of the borehole in the minimum horizontal stress direction) that is visible in the caliper image; UBI images in high-temperature HPHT wells (where mud temperatures above 150 degrees Celsius degrade the performance of other imaging tools) provide the structural formation data that supports geosteering and completion design decisions in some of the most technically challenging well environments.
• Ultrasonic cement evaluation tools using pulse-echo (UCE) or flexural wave attenuation (FA) measurement principles assess the mechanical quality of the cement sheath in the annulus between the casing and the formation, providing the cement bond quality data that determines whether the primary cementing job has achieved the zonal isolation required for the well's production and regulatory compliance: pulse-echo cement evaluation tools (Schlumberger USIT, Halliburton CAST-V) transmit an ultrasonic pulse from a transducer on the tool, which propagates through the casing wall and is reflected from the cement-casing interface and the cement-formation interface; the amplitude and frequency content of the reflected signal characterizes the acoustic impedance of the material in the annulus (cement, micro-annulus gap, or gas-filled channeled cement), with well-bonded cement producing a specific acoustic impedance signature that is distinguishable from the signatures of free pipe (air or mud behind the casing), micro-annulus (thin gap), or channeled cement; the flexural attenuation measurement (used in the Schlumberger Isolation Scanner and equivalent tools) uses a lower frequency flexural wave that propagates along the casing and is attenuated by the mechanical coupling of the cement to the casing, with high attenuation indicating good cement bond and low attenuation indicating poor bond; interpretation of ultrasonic cement evaluation requires distinguishing gas-filled channels (which look similar to free pipe on some ultrasonic measurements) from micro-annulus (which can look similar to cement on traditional acoustic bond logs but represents a pressure seal risk), with the multi-physics combination of ultrasonic and conventional acoustic measurements providing the best discrimination between these conditions.
• Subsea pipeline inspection using ultrasonic pig technology (smart pigs or intelligent pigging) provides wall thickness profiles along the entire length of production pipelines and gathering systems, identifying areas of internal corrosion, external corrosion beneath coating, dents, and mechanical damage that pose integrity risks over the remaining pipeline service life: magnetic flux leakage (MFL) and ultrasonic testing (UT) smart pigs are propelled through the pipeline by the flow of oil or gas, with their sensor arrays recording data along the entire pipe length (potentially hundreds of kilometers per run) and the onboard data storage capturing the inspection results for post-run analysis; ultrasonic smart pigs use either pulse-echo transducers coupled to the pipe through a water slug (required because dry transducers cannot efficiently transmit ultrasound across an air gap) or electromagnetic acoustic transducers (EMATs) that generate ultrasonic waves directly in the pipe wall through electromagnetic induction without requiring liquid coupling; the wall thickness data from ultrasonic smart pig inspections is analyzed to identify and size corrosion defects using standards including ASME B31.8 (gas pipelines) and API 1160 (hazardous liquid pipelines), with the calculated remaining strength of each defect (using criteria from ASME B31G or modified B31G) determining whether the defect requires immediate repair, monitoring, or acceptance without repair; the economics of intelligent pigging, though significant (a smart pig run on a major pipeline system can cost several hundred thousand to several million dollars including pig mobilization, pipeline preparation, and data analysis), are justified by the cost of unplanned pipeline failure (repair costs, environmental cleanup, regulatory fines, and production losses) that exceeds the inspection cost by orders of magnitude.