A Practical Way to Incorporate the New PHMSA Underground Gas Storage Requirements Into your MI Program

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Tags: Damage Mechanisms Inspection Mechanical Integrity Process Safety Management Regulation Risk Analysis Risk Based Inspection Risk Management


PHMSA has out a new rule for underground natural gas storage facilities (UNGSFs). This is practical approach to incorporating gas wells into your mechanical integrity program with the rest of your surface and subsurface assets.

TODO

In January 2021, I made you aware of new jurisdictional requirements for "Midstream Processing Facilities". The other new requirements came from PHMSA (Pipeline and Hazardous Materials Safety Administration) in a new rule for underground natural gas storage facilities (UNGSFs). The tie with my previous article is that many of these underground storage facilities include midstream processing facilities as the first destination of the gas from the wellhead. In this article, I provide the reader with a practical approach to incorporating gas wells into your mechanical integrity program with the rest of your surface and subsurface assets.

The trigger for this new rule was a large scale leak at the California, Aliso Canyon underground gas storage facility that occurred in October 2015.

"The Aliso Canyon Natural Gas Storage Facility (Aliso Canyon), located in the Santa Susana Mountains of Los Angeles County, is the largest natural gas storage facility in California. Southern California Gas Company (SoCalGas) crews discovered a leak at a natural gas storage well at Aliso Canyon on October 23, 2015. After several attempts, SoCalGas stopped the leak on February 12, 2016, sealing the well on February 15, 2016."(1)

Congress issued the mandate to PHMSA to require it to establish minimum safety standards for UNGSFs within two years of the PIPES Act issuance on June 22, 2016. To meet the mandate's deadline, PHMSA published the interim final rule (IFR) with a 60-day comment period. The IFR went into effect on January 18, 2017 and the rule was finalized July 23, 2020.

This new rule applies to three types of underground storage facilities:

  • Depleted oil and gas fields
  • Depleted aquifers
  • Solution mined salt caverns

and references in their entirety API RP 1170 and 1171. API RP 1170(2) applies to solution mined salt caverns and API RP 1171(3) to depleted oil and gas fields as well as depleted aquifers. Both of these RPs set out integrity requirements for the three parts of a UNGSF which are:

  • The formation or cavern
  • The downhole tubing and casing
  • The wellhead

It is evident that each recommended practice emphasizes different requirements for each of the three different parts. One would think that the well head and down hole tubing and casing requirements for both recommended practices would be the same, but they are not. Therefore, Asset Optimization Consultants, Inc. (AOC) advocates the use of the RP 1171 requirements for wellheads and down hole tubing and casing for both types of storage facilities. This does not apply to the actual cavern or formation where the gas is being stored. Owner/Users need to follow the requirements in their respective recommended practices.

This sets up Asset Optimizations Consultants, Inc.'s (AOC) recommended work process for underground storage facilities. The good news is that it's exactly the same as the one we use for downstream facilities like refineries or chemical plants as illustrated in Figure 1, below.

fig 1. Work Process for Underground Storage Facilities

Figure 1. Work Process for Underground Storage Facilities

To apply this work process to underground storage facilities we need to deal with the unique requirements for the following steps in the diagram:

  • Identify Equipment
  • Damage Mechanism/Threat Review
  • Integrity Operating Windows (IOW)
  • Risk Analysis
  • Equipment Strategies
  • Reliability Work Plan (RWP)

The first step, identify equipment, is pretty easy. The recommended practices hint at an equipment and component structure. Each well becomes a single piece of equipment which has four components. Using some downstream industry practices like API 510 or API 570 we can break a well into four components:

  • The wellhead
  • The tubing string
  • The casing string
  • The cavern or formation

This is necessary so that the rest of the above steps can be performed correctly. Components share:

  • Damage mechanisms/Threats and rates
  • Materials of construction
  • Operating temperature, pressure, and fluid phase

Because of these common characteristics, the component is where the following are performed:

  • Damage Mechanism/Threat Review
  • Risk Analysis

Both API RP 1170 and 1171 specify, at a high level, the requirements for performing the Damage Mechanism/Threat Review step but only 1171 has "Table 1 – Potential Threats and Consequences". AOC recommends using this table and expanding it when performing the Damage Mechanism/Threat Review for each well. The part that needs expanding is the "Category of Review" containing "Wells" and only the first row as shown below:

Table 1: Potential Threats and Consequences
Category of ReviewThreat of HazardThreat/Hazard DescriptionPotential Consequences
WellsWell integrity (corrosion, material defects, erosion, equipment failure, annular flow)Gas containment failure due to inadequately sealed storage well(s), e.g. casing corrosion, cement bond failure, material defect, valve failure, gasket failure, thread leaks, etc.
  • Loss of stored gas inventory
  • Damage to well site facilities and equipment
  • Safety hazard to company personnel and the public
  • Loss of use of water sources and/or wells
  • Decrease of loss of field performance

The problem with this part of the table is that it groups all the specific damage mechanisms or threats that could affect well integrity together. Borrowing from the downstream refining standards, this row should be expanded to account for all potential damage mechanisms in API RP 571(4). Therefore Table 1 and API RP 571 need to both be considered in this step.

Once the Damage Mechanism/Threat Review has been accomplished we can move on to risk. Again, both API RP 1170 and 1171 specify, at a high level, the requirements for performing the Risk Analysis. However, they do not provide a methodology for how to do it. While there have been models proposed by various individuals and organizations, these models are not inclusive of any surface equipment associated with gas storage facilities. We must use models that can not only run risk for the surface equipment but can be modified to run risk for the subsurface equipment. To do this we must use API RP 580(5) and 581(6). The API 580 recommended program elements and some of the API 581 risk models for the POF of various damage mechanisms and COF have been well proven in the refining sector. The 581 models that have been applied to surface pipe can also be applied to subsurface pipe. Therefore, AOC recommends this for performing risk on wells. This will allow for a holistic approach for all asset types either surface or subsurface for any gas producer or gas storage facility.

The next thing we need to do is create equipment/component strategies based upon risk for the predictive, preventative, condition based, and mitigating tasks we are going to perform on each well. Unfortunately, API RP 1170 and 1171 fall short of the necessary information for doing this. Both recommended practices are missing some of the parts required for these strategies, however Table 1 in 1170 and Table 2 in 1171 are a good start. So, what is a strategy? Strategies are written documents of recommendations based upon risk level, damage mechanism, and component type which include:

  • Task methods
  • Task extent categorized for various probabilities of detection (API 581 Categories: A=90%, B=70%, C=50%, D=40%, E= Ineffective/0%)
  • Task frequencies needed to mitigate potential damage mechanisms/threats.

These documents, which should be part of your mechanical integrity program procedures, are the rules by which risk is consistently translated into action.

Generating recommendations for mitigating tasks based upon risk is easy. An equipment might have several components all of which will get individual recommendations for each damage mechanism/threat. That is where the strategies come in. We then must consolidate all of these component recommendations to the equipment level in order to create the Reliability Work Plan (RWP) in the most conservative and cost effective manner. Each individual equipment will have its own RWP with its own tasks. Each task must have the following minimum information as per API RP 572 Inspection Practices for Pressure Vessels(7):

Table 2: RWP - minimum information required
Asset ID/Equipment IDRisk Level (Risk associated with the damage mechanism/threat)Task Frequency
Equipment DescriptionTask MethodTask Last Completion Date
RBI Component Description (Governing)Intrusive (Y/N) (Take out of service required?)Task Due Date
Damage Mechanism/ThreatRecommended Task ExtentPreparations required to execute the Task
Primary Areas susceptible to the Damage MechanismsSafe accessibility of Equipment or parts of the EquipmentOn-stream monitoring requirements

Once the Owner/User has developed the RWPs for each piece of equipment in its mechanical integrity program, then the rest is simple, just follow the remaining steps in Figure 1 making sure that any changes are considered.

The whole point of incorporating these new equipment types into the mechanical integrity program is so that they can be managed in one place. It would be very inefficient and ineffective to have one methodology for wells, another for pipelines, and another for surface facilities. This could create the situation where relative risk cannot be compared for all equipment types and therefore the allocation of maintenance and capital resources becomes difficult. Therefore, AOC believes that the process proposed above is the most efficient and effective way to incorporate these new rules into your mechanical integrity program and remain in compliance.

Let's continue the conversation! I am interested in your feedback. Please comment below or contact me directly to start the conversation:


REFERENCES
  1. California Public Utilities Commission (January 26, 2021), Aliso Canyon Well Failure, https://www.cpuc.ca.gov/default.aspx.
  2. American Petroleum Institute (July 2015), API RP 1170 - Design and Operation of Solution Mined Salt Caverns Used for Natural Gas Storage, First Edition, https://publications.api.org/documents/1170_e1-PubAcc/html5.html.
  3. American Petroleum Institute (September 2015), API RP 1171 - Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs, First Edition, https://publications.api.org/documents/1171_e1-PubAcc/html5.html.
  4. American Petroleum Institute (2020), API RP 571 - Damage Mechanisms Affecting Fixed Equipment in the Refining Industry, Third Edition, https://www.apiwebstore.org/publications/item.cgi?436acc6b-ad87-4f10-990f-db14afd6186f.
  5. American Petroleum Institute (2016), API 580 - Risk-Based Inspection, Third Edition, https://www.apiwebstore.org/publications/item.cgi?7051b364-69a7-4add-8194-0a4316c870d5.
  6. American Petroleum Institute (2016), API 581 - Risk-based Inspection Methodology, Third Edition (A1), https://www.apiwebstore.org/publications/item.cgi?41d3dd48-8625-4120-b844-1e70acb1bfd3.
  7. American Petroleum Institute (2016), API RP 572 – Inspection Practices for Pressure Vessels, Fourth Edition, https://www.apiwebstore.org/publications/item.cgi?4e19396d-8f57-4202-bda3-871ce2f8b6d4.

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