Monitoring is Key in Developing a Rigorous Corrosion Protection Program for Natural Gas Storage

There are a lot of moving parts to an effective corrosion control program. Operators should seek
out consultants who are experienced in this area and can perform a range
of services.
Recent recommendations from the United
States Department of Energy (DOE)
regarding corrosion protection programs for
natural gas storage will likely require action
on the part of operators around the country.
As Ernest J. Moniz, the Secretary of Energy,
wrote in the introductory pages of the DOE
Final Report of the Interagency Task Force
on Natural Gas Storage Safety1
, “Gas
storage operators should begin a rigorous
evaluation program to baseline the status
of their wells, {and} establish risk management planning…” For many operators already understaffed and
overburdened with regulatory requirements, the task of developing such a program will fall to outside
resources.
BACKGROUND
In keeping with the industry’s move to a more integrated pipeline safety culture, several new
recommendations—including those from the DOE—are impacting gas storage operations.
Recommendations include the PHMSA Advisory Bulletin (ADB-2016-02) on Safe Operation of
Underground Storage Facilities for Natural Gas; the subsequent Interim Final Rule (PHMSA 2016-0016),
which adopted both API 1170 “Design and Operation of Solution-mined Salt Caverns Used for Natural
Gas Storage” and API 1171 “Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon
Reservoirs and Aquifer Reservoirs”; and relevant state regulations. In addition to becoming a regulatory
requirement, a risk evaluation of underground storage and gathering line assets is also a prudent
business decision.
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Monitoring is Key in Developing a Rigorous Corrosion
Protection Program for Natural Gas Storage
By Lindsey Rennecker, Sr. Project Engineer &
Deborah Sus, Sr. Project Manager,
ENTRUST Solutions Group
As published in
PIPELINE & GAS JOURNAL, May 2017
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A comprehensive underground storage risk evaluation program should consider areas of potential risk
including internal and external corrosion, among other aspects. The risk evaluation plan should also
include above ground assets liketanks, wellhead equipment, gathering line piping, station piping, and
equipment—where corrosive constituents may accumulate. A robust risk evaluation plan should also
integrate monitoring methods for on-going assurance.
There are three principal types of underground storage sites in the United States—depleted natural gas
or oil fields, aquifers, and salt caverns. Depleted fields are the most prevalent and found throughout the
US; aquifers are concentrated in the Midwest; and salt caverns are found mostly in the south near the gulf
coast. Each type poses unique considerations relating to corrosion.
INTERNAL CORROSION & MONITORING
Internal corrosion is attributed to over half of onshore gathering line failures2
. In addition to the common
forms of corrosion, particular concern in storage fields may include:
• Under-deposit corrosion, a form of localized corrosion featuring deep penetration and occurring under
or around deposits of collection of material.
• Velocity/Flow-related corrosion, including erosion corrosion, which can occur when particulates
coming up from the well cause heavy abrasions.
• Environmentally Assisted Corrosion (EAC), which includes Hydrogen-Induced Corrosion (HIC),
Hydrogen Embrittlement (HE), and Stress Corrosion Cracking (SCC).
• Microbiological Induced Corrosion (MIC), caused when the biological processes of microorganisms
alter the metal’s surface by physical or chemical means.
Internal corrosion conditions can accelerate quickly in underground storage and gathering line assets. So
operators are advised to establish and heed the warnings of a robust monitoring system. With so many
variables associated with internal corrosion, operators are also advised to select an outside consulting
team with both extensive corrosion control experience and metallurgical expertise.
Because each storage field is unique, an internal corrosion monitoring program should begin with a
survey of all assets including injection/withdrawal (I/W), observation, and disposal wells along with
associated equipment and gathering lines that connect the wellhead to the storage facility. Monitoring
locations can include vessels, piping low points, stub ends, drips, I/W wells, and receivers which can also
contribute to the evaluation process.
A wide range of complementary testing methods (see sidebar) should be considered before defining the
monitoring system for each storage field and its geological and physical features.
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Non-destructive testing at gathering system
locations where corrosion is most likely to occur
provides direct measurement of internal corrosion
to support other testing methods. This can be
performed on above ground equipment or piping that
is easily accessible for routine monitoring.
ILI, which is a popular method to assess longer
transmission lines, can and has been applied to
storage gathering lines. However, the complexity of
gathering systems can make pigging a challenge.
Gathering systems can consist of various diameter
pipe, with main gathering lines ranging from 6” to 16”
and lateral pipe connecting the wells to the main line
being anywhere from 2” to 6”. Despite this challenge,
the pigging process affords some benefits for
corrosion monitoring. Besides being a good method
to remove liquid and/or debris from the gathering
lines, pigging can provide additional information regarding the internal conditions of the pipe when the
material collected in the pigging process is sampled and tested.
Internal corrosion data, once collected, can be supported by direct examinations that can include ILI
validations and visual inspection. Effective visual inspection should include removal of any scale and
cleaning of the pipe surface before making any determinations.
EXTERNAL CORROSION & CATHODIC PROTECTION
Pipeline coatings, common on horizontal lines, are the first and foremost defense against external
corrosion for pipelines. Cathodic protection (CP) complements these coatings in ensuring asset
protection. For bare steel downhole casings, a more robust CP system is necessary. While either or
both galvanic anode and impressed current systems can be used in cathodic protection, differing levels
of protection are likely needed for the pipeline versus downhole assets. Establishing the current densit
criteria in a horizontal pipeline is a very different process than one applied to a storage field. Furthermore,
current flow does not discriminate amongst assets (see Figure 1). Operators are advised to be fully aware
of all assets and deploy a CP system that is holistic. Most operators may be best served by consulting an
outside resource with a solid track record in addressing the nuances of storage field cathodic protection.
The space constraints associated with storage assets may lead to multiple ground-bed configurations.
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COMPLEMENTARY TESTING METHODS
TO DETECT INTERNAL CORROSION
• Corrosion coupons/probes
• Bacteria analysis
• Liquid/solids sampling
• Gas sampling
• Non-destructive testing
• In-Line Inspection (ILI) or downhole
well casing logs
• Visual inspection of piping cutouts
or tubing and casing joints when
removed
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Operators should take care to ensure that ground
beds are a suitable distance away from the pipe
that requires protection. However, the space
constraints within a storage field may make this
difficult to achieve. In addition, the very nature of a
storage field suggests multiple ground penetrations
and a network of interconnecting pipelines. Such
conditions may necessitate the need for several
ground beds to protect specific areas of the storage
field. Furthermore, downhole assets may pass
through several geological strata, each with different
soil characteristics and resistivity. Thus, the amount
of CP necessary for downhole and surface-level (i.e.
gathering pipelines) assets may differ significantly.
Several factors should be taken into consideration before designing the appropriate corrosion protection
system to guard against external corrosion at a storage field facility. These factors may include:
• Environment corrosivity
• Soil structure and resistivity
• Bare or coated asset and coating quality
• Metal or alloy of asset
• Asset size (diameter, length, wall thickness, etc.)
• Presence of other metallic structures and stray current
• Historic cathodic protection measures or existing systems
A cathodic protection expert can determine the proper CP current density level required for each
structure. The application of cathodic protection up to some level is beneficial—with the goal to achieve a
net current pickup along the entire wellhead length. Beyond this level, however, geologic changes along
a vertical well configuration may actually create conditions where the net current pickup is reversed—an
example of too much of a good thing becoming a negative.
For wellhead structures that can be taken off-line, a condition assessment of the metallic casings may
be performed with tools that measure the cathodic protection electrical profile (CPP) or that measure the
amount of remaining wall thickness (by using a metallic wall loss tool). To establish a CP current density
design basis, these tools can be coupled with on-grade electrical testing, such as the use of E-log-I
methodology and/or through the use and placement of remote reference cells.
Wellhead completion records aid in the understanding of relative water levels and the effectiveness of the
cement3
bond. For many wellhead systems, the cement may help polarize the exterior side of the casings
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causing the native cathodic protection level to become more negative than -0.850Vdc. An experienced
cathodic protection professional will have a solid understanding of these methods, the required criteria
levels, and be able to apply them to the operator’s unique facility asset configuration.
As with internal corrosion, monitoring of external corrosion should be an integral aspect of the evaluation
and design process. In fact, API 1170 and 1171 include stipulations relating to monitoring of external
corrosion. Monitoring methods are varied, their suitability depending on the storage field’s specific
conditions. Monitoring can include electrical isolation tests, test stations, and rectifier readings to ensure
continual operation. For locations that may not be easily accessible, remote monitoring is a good choice.
CP testing can be performed by the operator’s personnel or by an outside consultant. In some cases,
an operator may identify a consultant who can perform the evaluation on a storage system, recommend
specific monitoring methods, and perform testing.
More comprehensive services are also available from some outside consultants, including reading and
evaluation of the test results and even in-field repairs per NACE standards. Sending a NACE-certified
inspector to the field to read tests may sound extravagant, but this can sometimes be less costly than
sending an inspector and repair personnel separately.
SUMMARY
Effective monitoring programs should be continual in nature and include reassessment intervals. After all,
the corrosive environments for natural gas assets are ever-changing and the impact of these changes
can result in non-linear growth rates of corrosion. The results of the monitoring process should signify
to operators those assets that pass operators’ prescribed safe operating standards or assets trending
towards fitness-for-service (FFS) requirements. Repair and replacement to affected assets may then be
in order. An outside consultant can assist operators in making repair and replacement recommendations,
as well as perform both the rigorous evaluation and monitoring of all underground and related natural
gas assets. It is also good to make a periodic audit/review of your overall corrosion protection system.
In some cases, the review may indicate that the assets are over-protected and the operator is spending
unnecessarily on corrosion protection. In other cases, the audit may signal where more robust corrosion
protection is necessary.
As outlined above, there are a lot of moving parts to an effective corrosion control program. Operators
should seek out consultants who are experienced in this area and can perform a range of services
including risk evaluation, program design, monitoring system design, cathodic protection, testing services,
field repair, and system reviews and audits to help ensure the integrity of storage assets and the ultimate
protection of the public.
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New Arc Flash Safety Regulation?
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RESOURCES
Authors:
Lindsey Rennecker is a Senior Project Engineer at ENTRUST Solutions Group with a BS in chemical
engineering from Iowa State University. She has ten years of experience in integrity management pipeline
safety management systems and internal corrosion in the pipeline industry and is a NACE Senior Internal
Corrosion Technologist.
Deborah Sus is a Senior Project Manager at ENTRUST Solutions Group with a BS in material science
from the University of Notre Dame. She has eighteen years of engineering consulting experience,
focusing primarily on system integrity and internal corrosion and is a NACE Senior Internal Corrosion
Technologist.
1
“Ensuring Safe and Reliable Underground Natural Gas Storage: Final Report of the Interagency Task
Force on Natural Gas Storage Safety,” report published by the US Department of Energy October 2016,
page i, Message from the Secretary of Energy, Ernest J. Moniz.
2
US Department of Transportation Pipeline and Hazardous Materials Safety Administration.
3
Cement is used to seal and bond the exterior of the surface, intermediate, and production casings to the
surrounding earth.