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Oil and Natural Gas Well Pad Asset Management

Oil and natural gas well pads are omnipresent in the different shale plays across the U.S including the Marcellus and Utica shales in Pennsylvania, Ohio, and West Virginia. A well pad is a well-tuned collection of different transmission, storage, and processing components designed to prepare the product for midstream and downstream stages. Well pads consist of a variety of corrosion resistant steel flowlines, storage vessels, and pressure components that require periodic inspection and maintenance including non-destructive testing. This article discusses some of the different deterioration mechanisms that put well pad assets at risk and some of non-destructive testing options available for well pad assets. Additionally, the important regulations as they relate to well pads, situated in the Marcellus and Utica shale plays, are discussed.

Oil and Natural Gas Well Pad Description

The well pad consists of a plurality of valves, flowline, pressure vessels, chokes, storage tanks and pipe flowline made from corrosion 43XX alloy steels or comparable. The steel casing is corrosion resistant steel pipe that is encased in cement that funnels gas flow up from the shale. The well head is connected to the casing and directs the flow of gas to the different surface facilities. After exiting the well head, the gas will flow to a sand trap or sand separator where sand and water are separated from the oil/gas mixture. The sand and water are gravity fed down to the bottom of the sand trap while the gas flows out the top to the gas production unit. Inside the gas production unit (GPU), the gas is heated through a series of coils immersed in a glycol bath. After the heating coil the gas flow is controlled by an auto choke into a three-phase separator. The separator is the final stage of filtering where water, oil, and natural gas are separated through phase density driven mechanisms. Upon leaving the three-phase separator, the natural gas flows to the sales line where the gas is metered and sold to the pipeline. The separated water is pumped to the produce water tanks where it is stored until it is hauled off and recycled.

Deterioration of Well Pad Facilities

Well pad assets degradation occurs largely through erosion and corrosion with the later possibly leading to stress corrosion cracking (SCC) or corrosion fatigue cracking. Erosion is attributed to the multi-phase liquid – sand mixture that originates in the well and travels at high velocity, under high pressure, to the sand trap where most of the sand is gravity filtered. Erosion rates are dependent upon impacting particle and steel material properties, particle velocity and impacting angle as shown below [1].

Figure 1: Flowline erosion in well pad facilities [1].

All components between the well head and the sand trap are susceptible to wear but the following areas have routinely demonstrated advanced erosion and erosion rates; elbow, tees, sand trap inlet and outlet, and sand trap deflector plates. The corrosion rates and remaining life calculations cited in API 510 Pressure Vessel Inspection Code [3] and API 570 Piping Inspection Code [4] do not apply because the corrosion rate is unpredictable and will exceed fixed asset corrosion rates by an order of magnitude.

On a well pad, corrosion driven deterioration is generally much slower than erosion related issues. Some acidic driven corrosion, derived from dissolved C02 and H2S is possible along with under deposit corrosion [3] caused by entrained solids in produced water. Problems can arise post initial production (IP), in water and oil flowline and storage tanks where low flow or stagnant conditions are observed and increase the likelihood for microbiologically induced corrosion (MIC). As corrosion advances, the risk for corrosion fatigue cracking increases and can cause sudden failure incurring human safety and environmental liabilities.

Figure 2” FEM simulation of particle velocity around a 1502 2” flowline elbow.

Flowlines and Facilities Corrosion

The well pad flowline and facilities must be designed to safely accommodate the initial production (IP) pressures. Once the IP conditions expire after 6 months or 1-year, erosion becomes less of a problem compared to chemically driven corrosion. At the lower production rates, the oil and water mixture are transferred though the equipment which results in stagnant and low velocity flow conditions. The conditions promote microbiologically influenced corrosion (MIC). MIC or biocorrosion, is corrosion affected by the presence or activity (or both) of microorganisms in biofilms on the surface of the corroding material. Shown below is MIC pitting corrosion on the inside of a well pad separator. Pitting may lead to more serious failure mechanisms like stress corrosion cracking (SCC) [5].

Figure 3: Well pad separator microbiologically influenced corrosion (MIC) pitting may lead to stress corrosion cracking.

The inspection of well pad facilities and flowline can be broken down into the following categories:


Inspections satisfy API 571 Piping Inspection Code

o 602, 1002, 1502 flow line

o Sour and standard service

o Line Pipes

Pressure Vessels

Inspections satisfy API 510 Pressure Vessel Inspection Code:

o Sand Traps

o 2 & 3-Phase Separators

o Heater Treaters

o Line Heaters

o Dehydration Contact Towers

o Coalescing Filter Separators

o Surge Tanks

o Pressurized Storage Tanks

Storage Tanks

Inspections satisfy API 653 & STI SP001 Aboveground Storage Tank Inspection Code: Compliant

o Brine Tanks

o Slop Tanks

o Water Storage Tanks

o Fuel Storage Tanks

o Acoustic Emission Testing of Valves

The following non-destructive testing options are available for in-service well pad assets:

Wireless UT monitoring in high erosion areas where blow out occurs

o Measurement accuracy of +/- 0.0004”

o Record reliable, repeatable and credible material loss due to corrosion and erosion as a function of time

o Remotely take readings on demand or on an established reporting schedule

Vibration monitoring and analysis

o Wireless vibration and temperature sensors are installed on equipment to track the real-time condition of equipment on the well pad during drilling operations.

o Accurate analysis directly predicts system repairs requirements which results in significant cost savings

Leak and Fatigue Crack Detection using Acoustic Emission

o Monitor valves for leaks

o Detect leaks in real-time

o Detect fatigue related flaws


The non-destructive testing (NDT) approach selected must be compliant with local regulations [6-7] and compliant with referenced inspection codes [3-4]. In-service non-destructive testing options including ultrasonic thickness testing, corrosion mapping with phased array dual element probes, standard ultrasonic and phased array (PAUT) weld inspections, and acoustic emission testing of pressurized components and storage tanks.


[1] 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,

[2] 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.

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

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

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

[6] PADEP Chapter 245: Administration of the Storage Tan and Spill Prevention Program

[7] West Virginia Department of Environmental Protection (WVDEP) Aboveground Storage Tank Act at W.Va. Code § 22-30-6.

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