Underground storage operators must fully understand 2016 PIPES Act

July 3, 2017
Underground gas storage (UGS) operators need a full understanding of the recommended practices and regulations enacted by the Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2016, their interactions, and their potential impacts on the UGS industry.

L. Brun Hilbert Elizabeth Reilly
Exponent Inc.
Menlo Park, Calif.

Nicoli Ames
Exponent Inc.

Underground gas storage (UGS) operators need a full understanding of the recommended practices and regulations enacted by the Protecting our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2016, their interactions, and their potential impacts on the UGS industry.

The regulatory landscape of underground natural gas storage changed with passage of the 2016 PIPES Act. The US Pipeline and Hazardous Materials Safety Administration (PHMSA) has since exercised its federal authority to regulate all underground natural gas storage sites. PHMSA has incorporated by reference American Petroleum Institute (API) Recommended Practices (RP) 1170 and 1171 by law (49 CFR 191 and 192). RP 1170 addresses gas storage in solution-mined salt caverns, while RP 1171 covers gas storage in depleted hydrocarbon and aquifer formations.

These API recommended practices, now mandatory, are intended to serve as a foundation for minimum standards for both inter- and intrastate underground gas storage sites. UGS operators must fully understand these new regulations to determine how implementation impacts costs and operations. This article describes these new recommended practices and regulations, their interactions, and their potential impacts on the UGS industry.

The US Energy Information Administration (EIA) publishes weekly statistics on natural gas storage.1 The EIA tracks natural gas storage volumes by geographic sector and geologic medium (Fig. 1).

As of November 2016, total gas storage capacity in the US was 9,138 bcf. Storage fields require a large quantity of cushion gas (or base gas) to maintain adequate pressure and withdrawal rates, therefore only about half of design capacity is available for the marketplace. At the beginning of the most recent withdrawal season, 4,047 bcf of stored natural gas was available as working gas for the market.

The accompanying table shows the breakdown of working gas storage capacity by region. About 75% of storage volume is in depleted fields, with roughly 15% in aquifers and about 10% in salt caverns. Roughly half of the 391 depleted fields are interstate sites related to gas transport between states. The other half are intrastate sites related to gas transport or distribution within one state.

Underground storage exists worldwide, particularly in Europe and Russia. Twenty-four European countries currently host underground storage with 5,230 bcf of total working capacity. About 22% is in Ukraine and 16% in Germany. Italy, the Netherlands, France, and Austria also have large storage capacities.2 In Russia, Gazprom had 2,546 bcf of natural gas in underground storage at the beginning of the most recent withdrawal season.3

PHMSA's new UGS regulations

PHMSA has the authority to regulate the transportation of natural gas, including storage. The authority was originally granted through the Natural Gas Pipeline Safety Act (NGPSA) of 1968, which defined natural gas "transport" as including the storage of natural gas.4 However, the definition of "storage" in the NGPSA was not precise. The NGPSA allowed individual states to adopt and enhance federal pipeline standards for intrastate facilities. PHMSA enforces this through an annual certification process.

PHMSA historically only regulated surface piping up to the wellhead at interstate underground gas storage sites, not explicitly regulating downhole equipment at interstate sites. Regulations for downhole equipment consisted primarily of individual state standards that applied to intrastate storage. While underground storage regulations for many states contain integrity-testing components to determine a well's condition, most states do not have specific and consistent regulations that include all aspects of operating a UGS site. Such regulations include, for example, maintenance, integrity verification, monitoring, hazard identification and assessment, site security, emergency response and preparedness, and record keeping.

The 2016 PIPES Act mandated PHMSA to regulate UGS facilities. This law directed PHMSA to issue regulations for all interstate and intrastate UGS sites within 2 years and to consider industry standards and economic impacts. PHMSA responded to this mandate Dec. 19, 2016, publishing an Interim Final Rule (IFR) in the Federal Register5 that established federal regulations for the downhole components of underground natural gas storage sites. This rule became effective as part of the Code of Federal Regulations (CFR) on Jan. 18, 2017.

The new minimum federal standards in the IFR set the baseline fitness-for-service requirements for all interstate and intrastate facilities and continue to allow state regulators to require additional safety requirements at intrastate sites. The IFR also allows state regulators to continue exercising oversight of intrastate gas pipelines, gas transportation, and UGS sites through an annual certification process.5 Furthermore, underground gas storage is now subject to inspection by either PHMSA or a PHMSA-certified state entity.

New reporting requirements

Through the IFR, PHMSA has added reporting requirements for underground natural gas storage in CFR Part 191. Four types of reports are required from UGS operators:

• Annual Reports. Include operator information, storage location, well information, and operational data such as: gas storage volumes and pressures, well depths, gas injection and withdrawal rates, and maintenance information related to safety.

• Incident Reports. Events that involve a release of gas in addition to a death, significant personal injury, significant property damage, or unintentional loss of more than 3 MMcf of natural gas.

• Safety-Related Condition Reports. Findings that may compromise the safety, reliability, or integrity of a well or reservoir, such as: casing or tubing corrosion; cracks or other material defects; abnormal environmental loads such as earthquakes, floods, and landslides; leaks; over-pressurization events; or anything that compromises the structural integrity or reliability of a UGS site.

• National Registry information. Operators must obtain an operator identification number (OPID) from PHMSA.

API RP as requirements

Before issuing the IFR, PHMSA held public discussions in 2016 with operators and industry groups,6 and released reports documenting studies of underground gas storage.7 8 PHMSA concluded that the two recently adopted RPs from the API should be incorporated by reference into the federal pipeline safety regulations through the IFR:

• API RP 1170 "Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage"9 contains recommendations for solution-mined salt caverns used for natural gas storage service and covers geomechanical assessments, cavern well design and drilling, and solution mining techniques and operations, including monitoring and maintenance practices. This RP covers the cavern well system from the emergency shutdown (ESD) valve though the well, including wellhead, casing, tubing, cement, and completion techniques. It also covers the design and construction of the cavern itself.

• API RP 1171 "Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs"10 applies to natural gas storage in depleted oil and gas reservoirs and aquifer reservoirs, and focuses on design, construction, operation, monitoring, maintenance, integrity management, and documentation practices. This RP applies to both existing and newly built facilities.

As recommended practices, API did not intend RPs 1170 and 1171 to represent requirements, standards, or specifications. PHMSA, however, is adopting these recommended practices by reference in a manner that will make them mandatory. In the IFR, PHMSA made specific reference to this subject:5

"API elected to issue RPs 1170 and 1171 in the form of ''recommended practices,'' as opposed to ''standards.'' This presented PHMSA with the challenge of dealing with concerns about the enforceability of these practices. Accordingly, as part of incorporating the API RPs by reference, PHMSA is adopting the non-mandatory provisions of API RPs 1170 and 1171 in a manner that would make them mandatory (i.e., API provisions containing the word ''should'' or other non-mandatory language will be considered mandatory), except that operators will be permitted to deviate from the API RPs if they provide a sufficient technical and safety justification in their program or procedural manuals as to why compliance with a provision of the recommended practice is not practicable and not necessary for the safety of a particular facility."

Despite differences in the geologic settings, both RPs share common technical focus areas that PHMSA reviewed and incorporated in their regulations. PHMSA stated that they reviewed the RPs with special attention paid to design, construction, material testing, commissioning, reservoir monitoring, and recordkeeping. PHMSA's IFR, however, used the wording "regulations," rather than "recommendations," a departure from the API's intended use. This is important, since API RPs are merely recommendations, but federal regulations will now incorporate these recommendations as enforceable requirements.

PHMSA has amended 49 CFR Part 192 to incorporate API RPs 1170 and 1171 in their general entirety and specific sections. Section 192.12 addresses UGS facilities.

Subparts (a) and (c) of CFR 192 require that every solution-mined salt cavern and depleted hydrocarbon or aquifer reservoir used for gas storage constructed after July 18, 2017, must meet "all requirements and recommendations" of API RP 1170 and 1171, respectively. This wording implies that the entirety of the API RPs would be interpreted by PHMSA as requirements, not merely recommendations.

Subpart (b) requires that solution-mined cavern gas storage facilities constructed after July 18, 2017, adhere to API RP 1170 Chapters 9, 10, and 11.

RP 1170 Chapter 9 covers recommended practices for gas storage operations, which include wellhead and emergency shutdown (ESD) valves at the surface, supervisory control and data acquisition (SCADA) systems, and alarms and controls set from the data acquired by the SCADA system. Chapter 9 also recommends an overpressure protection (OPP) system to mitigate excessive pressures on the surface and subsurface components, including the cavern, and fire and gas detection systems. Chapter 9 includes recommendations for points of pressure monitoring to ensure safety and prevent overload. RP 1170 also recommends that pressures be monitored at the wellhead at least at the tubing, production casing, the annulus of the casing outside of the production casing (intermediate or surface casing), hanging strings, and logging valve. There are also recommendations for inspection and testing of the SCADA system (calibration), ESD valves (periodic testing), and other components. Chapter 9 includes recommendations for workover operations, site security, safety, operations and maintenance, emergency plans and procedures, record-keeping, and training.

RP 1170 Chapter 10 covers cavern integrity monitoring:11 "Once in operation and throughout its life, the cavern system shall be monitored to ensure the continuance of functional integrity."

The chapter includes a table (API RP 1170 Chapter 10 Table 1) summarizing integrity monitoring methods. The methods are subdivided into scopes applied to system components: cavern system, wellbore, cavern, and wellhead. The cavern system includes monitoring pressures (SCADA data) and diesel blanket depth (interface logging). Wellbore monitoring includes logging of the tubing, casing and wellbore (e.g. CBL, temperature and noise logs, caliper logs, corrosion logs, etc.). Cavern monitoring includes sonar logs, in situ pressure and temperature; and the wellhead (e.g. ultrasonic WT, pressure monitoring). Annex B of RP 1170 provides more detailed descriptions of the methods and tools used for determining system integrity.

RP 1170 Chapter 11 covers solution-mined salt cavern abandonment. This subject has added importance since the failure of a cavern and sinkhole at the Napoleonville salt dome in Louisiana after the cavern was plugged and abandoned. The 2015 edition of RP 1170 states that, "there is no industry consensus for abandoning a salt storage cavern."

The industry has performed studies showing the importance of pre-abandonment processes. The studies recommend a sufficient allotment of time between shutting in the cavern and degassing the wellbore after being plugged. This time allows brine in the cavern to equilibrate with static geothermal temperature. The appropriate length of time can be estimated from computational models.

Pressure monitoring during the equilibration period determines pressure dependence on cavern creep closure. RP 1170 recognizes that some operators elect to simply shut in a cavern, rather than abandon it. The following recommendations in RP 1170 will be required in 49 CFR 192. RP 1170 recommends that, before final plugging and abandonment, the following actions be taken: a nitrogen mechanical integrity test of the wellbore; removal of all downhole equipment; examination of casing inspection logs (CBL, caliper, corrosion log, etc.); a sonar survey of the cavern; and long-term monitoring.

Subpart (d) requires depleted hydrocarbon and aquifer gas storage facilities constructed after July 18, 2017 to adhere specifically to API RP 1171 Chapters 8, 9, 10, and 11.

RP 1171 Chapter 8 covers risk management for gas storage operations and provides recommendations for a now-mandatory risk management plan (RMP). The RMP should address data sources (geological, operating history, etc.), threat and hazard identification (see API RP 1171 Chapter 8 Table 1 of threats and consequences), risk assessment of the storage site (see API RP 1171 Chapter 8 Table 2 of preventative and mitigative programs), periodic review and reassessment, and record keeping. While most gas storage sites have an RMP, RP 1171 outlines now-required best practices and guidelines.

RP 1171 Chapter 9 covers integrity demonstration, verification, and monitoring practices. The objective is that the "operator shall maintain functional integrity of storage wells and reservoirs." Recommendations include using risk-based evaluations of wellbore integrity and storage formation based on the RMP developed according to Chapter 8. Wellbore integrity should be determined and evaluated using well historical records and logging tools similar to those described in RP 1170 for salt caverns (and as are standard for hydrocarbon wells). Reservoir integrity should be determined and then monitored using geological records, monitor (observation) wells, pressure data monitoring, and gas composition measurement.

Gas inventory, flow rate and pressure data tracking is important for not only financial reasons, but also for monitoring the integrity of the reservoir or aquifer. As with salt caverns, recordkeeping and maintenance is required.

RP 1171 Chapter 10 covers site security and safety, site inspections, and emergency preparedness and response. The recommendations include site inspections, signage, ingress and egress, emergency preparedness-emergency response, blowout contingent plan, and cyber security. Finally, RP 1171 Chapter 11 covers procedures and training.

Additional considerations

The US Department of Energy and US Department of Transportation issued a report stating that that storage wells with a single barrier, or single point of failure, have a higher risk of gas breaching from the wellbore to the environment.7 Single-barrier wells are those in which there is only one barrier between stored gas and the environment outside the wellbore. For example, a well with a casing string that is not cemented to the surface, with gas injected and withdrawn through that casing, is considered to have a single point of failure in the section of casing above the cement top.

Considering the same well, if the gas was injected and withdrawn through a tubing string with a packer inside the casing then it would be considered a double barrier wellbore. Neither API RP 1170 nor 1171 include specific references to the number of barriers for wellbores. Both do, however, refer to best practices for cementing of casing, and injection and withdrawal through tubing.

PHMSA requires that new wells incorporate more than a single barrier, but allows operators time to modify existing single-barrier wells. Some states, such as Texas and Louisiana, already require double barriers for storage wells. Texas requires a tubing and packer system for UGS wells in depleted reservoirs, and both Texas and Louisiana require double casing strings for UGS wells in salt caverns.12 13

Recommendations regarding use of subsurface safety valves (SSSVs) have become an important subject of discussion amongst regulators such as PHMSA and operators. Section 9.3.2 of RP 1171 Chapter 9 includes:

"Surface and subsurface safety valve systems, where installed, shall be function-tested at least annually. The tests shall be conducted in accordance with manufacturer's recommendations and the operator's procedures. A closed storage well safety valve system shall be manually reopened at the site of the valve after an inspection and not opened from a remote location."

While RP 1171 does not require SSSVs, some state and regulatory agencies are considering making them mandatory. Their use has been considered an additional barrier to the escape of stored gas, but their reliability has been the subject of recent discussion and research.14 SSSVs require maintenance and might require regular repair of hydraulic lines. In sand formations, SSSVs have the potential to become plugged or eroded by formation sand. Workover tasks on SSSVs also might increase the likelihood of unintended natural gas releases.


1. US Energy Information Administration (EIA), "Weekly Natural Gas Storage Report," http://ir.eia.gove/ngs/ngs.html

2. Gas Infrastructure Europe (GIE), "Storage Map," http://www.gie.eu/index.php/maps-data/gse-storage-map

3. Gazprom, "Underground Gas Storage," http://www.gazprom.com/about/production/underground-storage/

4. Public Law 90-481, "Natural Gas Pipeline Safety Act of 1968," Aug. 12, 1968, p. 720.

5. Federal Register, Vol. 81, No. 243, Dec. 19, 2016, p. 91860.

6. US Department of Energy (DOE) National Laboratories, "Workshop on Well Integrity for Natural Gas Storage in Depleted Reservoirs and Aquifers," Denver, July 12-13, 2016.

7. DOE, Final Report of the Interagency Task Force on Natural Gas Storage Safety, "Ensuring Safe and Reliable Underground Natural Gas Storage," Oct. 24, 2016.

8. DOE National Laboratories Well Integrity Work Group, "Well Integrity for Natural Gas Storage in Depleted Reservoirs and Aquifers," Sept. 2, 2016.

9. American Petroleum Institute (API), Recommended Practice (RP) 1170, "Design and Operation of Solution-mined Salt Caverns Used for Natural Gas Storage," 1st Ed., September 2015.

10. API RP 1171, "Functional Integrity of Natural Gas Storage in Depleted Hydrocarbon Reservoirs and Aquifer Reservoirs," 1st Ed., September 2015.

11. Louisiana Department of Natural Resources, "Bayou Corne Incident 2012," http://www.dnr.louisiana.gov/index.cfm?md=pagebuilder&tmp=home&pid=939

12. Texas Administrative Code, Title 16, Part 1, §3.96 and 3.97.

13. Louisiana Administrative Code, Title 43, Part XVII, §317.

14. Energyinfrastructure.org, "Underground Natural Gas Storage Integrity & Safe Operations," July 6, 2016.

The authors
L. Brun Hilbert is a principal engineer in Exponent's mechanical engineering practice in Menlo Park, Calif. He was formerly at Exxon Production Research Co. Hilbert holds a PhD (1995) in materials science and mineral engineering from the University of California, Berkeley, an MS (1981) in mechanical engineering from the University of New Orleans, and a BS (1979) in mathematics, also from the University of New Orleans. He is a licensed professional engineer in California, New Mexico, and Texas
Elizabeth Reilly ([email protected]) is a principal engineer at Exponent Inc., Menlo Park. She holds a PhD in mechanical engineering with an emphasis in mechanics of materials (2007) from the University of California, Berkeley, and a BS with honors in chemical engineering from Brown University, Providence, R.I. She is a licensed professional engineer in California, and serves on the American Gas Association's Transmission Pipeline Operations Committee. Reilly is also a project management professional (PMP) and a registered patent agent with the US Patent and Trademark Office.
Nicoli Ames is a managing engineer in Exponent's mechanical engineering practice in Denver. She holds a PhD (2007), master of science (2003), and bachelor of science (2000), all in mechanical engineering, from Massachusetts Institute of Technology, Cambridge. Ames is a licensed professional engineer in California.