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Natural Gas Dehydration Unit Asset Integrity Management

Natural gas dehydration units are typically installed at well pads to remove water vapor from the natural gas stream. These “dehy” units help prevent pipeline corrosion, hydrate formation, and other issues associated with water content in the gas. The dehydration process can involve various technologies such as glycol dehydration, molecular sieve adsorption, or membrane separation. There are many pieces of expensive equipment used for NG dehydration that require periodic inspection using non-destructive testing , condition based maintenance, and stress analysis.  This article explores the natural gas dehydration process, the individual assets, and the applicable non-destructive testing techniques.  The inspection of the different pressure vessels and piping systems should be performed to API-510 [1] and API-570 [2], respectively. 

Description of the Process

From a pressure bearing perspective, the dehydration unit consists of a series of pressure vessels and piping systems [3].  As shown in the figure below, wet gas enters the contact tower where it interacts with lean glycol that absorbs moisture from the gas and exits the contact tower as rich glycol.  As the Glycol moves through the contactor tower, it absorbs moisture from the natural gas.   Dry gas exits the contact tower and may be processed further or used.   Natural gas only travels through the inlet scrubber and the contactor tower.  All the other equipment is used to regenerate the Glycol.  

Figure 1: The natural gas dehydration unit pressure vessel and piping isometric drawing is produced during an initial field survey.  Non-destructive testing, condition based maintenance, and stress analyses points are identified on the drawing where applicable.
Figure 1: The natural gas dehydration unit pressure vessel and piping isometric drawing is produced during an initial field survey. Non-destructive testing, condition based maintenance, and stress analyses points are identified on the drawing where applicable.

The wet Glycol is processed through a flash separator where water vapor, particle contaminants, and oils are removed.  After this stage it moves towards the reboiler where the wet Glycol is distilled to a high level of purity.  The lean Glycol is returned to the contact tower.   The pressure vessels and piping are constructed to ASME Sec VII [4] and ASME B31.3 [5], respectively.   A standard contactor tower height and diameter are 34’ and 36”, respectively with operating pressured in the 1400 PSI range.

Deterioration Mechanisms of Natural Gas Dehydrations Units

The pressure bearing capacity of dehydration units are affected by metal loss, and possible crack formation, due to erosion and corrosion.  The latter may lead to stress corrosion cracking (SCC) or corrosion fatigue cracking (CFC).  The erosion of the corrosion resistance steel alloys used is partially due to liquid and solid particulate mixture that originates upstream and travels through the dehydration unit.  Erosion rates are dependent upon impacting particle and steel material properties, particle velocity and impacting angles [4].   In a dehy unit, corrosion drives metal loss and progresses much slower than erosion.  Corrosion may be initiated by dissolved C02 and/or H2S.     As corrosion progresses, the risk for corrosion fatigue cracking increases which can accelerate time to failure.  Original manufacturing defects may also be present in the pressure vessel and piping cold worked steel that was used to construct the assets.  These include delamination in the base metal and welding defect including porosity, lack of fusion, slag and other flaws.  These defects may act as stress concentration at which cracks may initiate.

Figure 2:  General corrosion on the OD of the pressure vessel with a maximum pit depth of 1/32”.
Figure 2: General corrosion on the OD of the pressure vessel with a maximum pit depth of 1/32”.

Non-destructive Testing of Natural Gas Dehydrations Units

The most common non-destructive testing methods for natural gas units are external visual inspection (VT) and ultrasonic thickness testing (UTT).   External visual inspection is used primarily to assess the condition of the paint coating and outside diameter corrosion.  Generalized or pitting corrosion at areas where there has been coating breakdown for an extended period of time.  Figure 2 is an example of generalized corrosion over an approximate area of 2” x 2” with a maximum metal loss of 1/32”.

Ultrasonic thickness testing of contact tower, reboiler, surge tank, and flash tank is used to assess inside diameter metal loss.  Numerous measurement points are taken on the pressure vessel shell, heads, and nozzles using a 0.5” diameter ultrasonic transducer.  The actual area tested if very small compared to the total area of vessels and inside diameter corrosion may be missed.   Lately, there has been increased demand for high resolution phased array ultrasonic testing (PAUT) thickness testing with large aperture dual element probes.  The footprint of PAUT dual element probe is approximately 2” x 1” which is significantly larger than a standard 0.5” diameter ultrasonic transducer used for thickness testing.  Additionally, encoded scan may be used to map out the inside diameter corrosion at high resolution.  Example high resolution phased array data is shown below for inside diameter corrosion.  The same non-destructive testing methods may also be applied to piping.  

Figure 3:  Phased array ultrasonic testing (PAUT) dual element probe high resolution scan. 

Condition Based and On-stream Monitoring Solutions

Condition based maintenance (CBM) monitoring, on-stream monitoring, or structural health monitoring may be performed depending on the cost ratio of the asset to monitoring cost or downtime cost to monitoring cost.   Low and/or high frequency acoustic emission testing may be instrumented onto the vessels and piping systems to assess active deterioration mechanisms which include generalize corrosion, pitting corrosion and corrosion fatigue cracks.   In the example below, the pressure vessels is instrumented with numerous acoustic emission sensors strategically places on the vessel shell, head, and adjacent to nozzle.  Over a period of 24-hours, the vessel is monitored for acoustic emission sources generated from the mechanisms cited above.    

Figure 4:  Pressure vessels may be monitored for corrosion and fatigue cracking using acoustic emission instrumentation.


Natural gas dehydration pressure vessel and piping required periodic inspections to ensure that that can operate desired pressure with the intended safety factor.   In addition to visual inspections, periodic non-destructive testing methods like standard and phased array ultrasonic testing may be used assure that vessels are safe to operate.  For high value assets, condition based or on-stream acoustic emission instrumentation may be used.  Immediate derating of pressure may be required depending on the testing conclusions.


  1. API 510 Pressure Vessel Inspection Code: In-service Inspection, Rating, Repair, and Alteration, American Petroleum Institute 2020.

  2. API 570 Piping Inspection Code: In-service Inspection, Repair, and Alteration of Piping Systems, American Petroleum Institute 2020.

  3. API SPEC 12GDU 2021, Specification for Glycol-Type Gas Dehydration Units

  4. ASME BPVC Section VIII-Rules for Construction of Pressure Vessels Division 1BPVC.VIII.1 – 2023

  5. ASME B31.3-2022 Process Piping

  6. P.P. Shitole, S.H. Gawande, G.R. Desale, B.D. Nandre, Effect of impacting particle kinetic energy on slurry erosion wear, J. Bio-Tribo-Corros. 1 (2015) 29,

  7. Bruce Craig; David Blumer; Sytze Huizinga; David Young; Marc Singer, Management of Corrosion in Shale Development, Paper Number: NACE-2019-13189 at the CORROSION 2019, Nashville, Tennessee, USA, March 2019.

  8. [5] Heaver, E., “Internal Stress Corrosion Cracking of Shale Gas Flowlines”, Mat. Perform., 56: 50 (2017).

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