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LEGAL MEMORANDUM - CONFIDENTIAL
Date: 09/11/2016
To: General Counsel
From: Chad D Colton, Esq., Junior Counsel
Re: New requirements for underground gas storage projects.
Question Presented
How does the Commission’s PROPOSED TEXT OF EMERGENCY REGULATIONS under
Chapter 4, Subchapter 1, Article 3, Sections 1724.9(a)-(h), henceforth referred to as “the
Regulations,” affect the operation of our current underground gas storage facility and our
proposed underground gas storage project?
Short Answer
The Regulations promulgate standards for system integrity tests, testing intervals, and ongoing
monitoring criteria for underground gas storage wells. The Regulations also promulgate
reporting intervals, a compliance schedule, and mandatory development of a Risk Management
Plan for all storage facilities. If adopted, the Regulations will apply to both pre-existing facilities
and projects currently in development upon the effective date of the Regulations. Compliance
with the Regulations may result in increased infrastructure, personnel, administrative, and legal
costs.
Background
On October 23 2015, employees of Southern California Gas Company reported a severe leak at
an underground gas storage facility located in Aliso Canyon near Porter Ranch in Los Angeles
County. The leak was sealed on February 18, 2015. The leak resulted in the release of 95,000
tons of methane. Parent company Sempra estimated the cost of the leak at $717 million. In
response, the California Public Utilities Commission (CPUC) has issued emergency gas storage
facility regulations codified in 1724.9(a)-(h) and enforced by the appropriate local Division. The
Regulations apply to all underground gas storage projects, both pre-existing and those currently

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in development. 1724.9(a). The CPUC has stated a phasing schedule for the reporting and
monitoring of existing facilities. The schedule deadlines begin upon the effective date of the
Regulations. 1725.9(c).
Analysis
The Regulations require our firm to complete a number of measures in order for our facilities and
projects to achieve compliance. Each measure must be “phased in” within a specified period of
time once the Regulations become effective. The phasing schedule applies to pre-existing
facilities currently in operation. Projects in development must demonstrate compliance with the
Regulations prior to commissioning. The Regulations do not address penalties for non-
compliance. Compliance with the increased monitoring, inspection, and reporting scrutiny
required by the Regulations may result in significant capital expenditures, as well as personnel
and administrative costs. Additionally, publication of these Regulations may result in increased
public scrutiny of the underground gas storage industry in general, which may increase the threat
of litigation from both stakeholders and interest groups. This memo analyzes the measures in
chronological order necessary for compliance.
21 days to comply. Create and submit an inspection and leak detection protocol. Inspections
must be performed daily. The scope of inspection must include the wellhead assembly, the
attached pipelines for each of the wells, and a 100’ radius of the wellhead unless that area is
obstructed. The inspections should be conducted using comprehensive infrared imaging. Leaks
must be reported to Division immediately. The protocol must pass California Air Resources
Board (CARB) standards. 1724.9 (e)
1 month to comply. Begin monitoring the tubing-casing annulus, in addition to the testing
requirements under 1724.10(j). This entails daily measuring and recording of annular pressure
and annular gas flow when the well is not being used for withdrawal. Anomalies must be
reported to Division immediately. 1724.9 (c)
3 months to comply. Function test surface and subsurface safety valve systems. The testing
must be performed every six months. Division must witness the testing, and must be notified 48
hours prior to testing for notice to be adequate. A closed valve system must be manually re-

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opened at the site of the valve after an inspection. The valve cannot be opened remotely. An
inoperable surface or subsurface safety valve must either be repaired or removed, or the well
must be temporarily plugged, within 90 days of detection. The Division may approve a longer
timeframe. 1724.9 (d)
3 months to comply. Test the operation of the master valve and wellhead pipeline isolation
valve. Documentation of the test must be submitted within 10 days of the test. This test must be
performed annually. Division must be immediately notified if a test reveals that any valves are
non-functional. 1724.9 (f)
6 months to comply. Develop and implement a Risk Management Plan. The Plan must perform
the following functions:
- Identify potential threats and hazards to well and reservoir integrity.
- Assess risks based on potential severity and estimated likelihood of occurrence of each
threat.
- Identify the preventive and monitoring processes employed to mitigate the risk associated
with each threat.
- Specify a process for periodic review and reassessment of the risk assessment and
prevention protocols.
- Specify a reporting schedule to the Division. 1724.9 (g).
The Plan must contain the following elements:
- Ongoing verification and demonstration of the mechanical integrity of storage wells and
wells intersecting the reservoir, accounting for age, construction, and operation. 1724.9
(g)(1).
- Corrosion monitoring and evaluation that accounts for tubular integrity and identification
of defects, wellbore produced fluids and solids, annular and packer fluid, current flows
associated with cathodic protection systems, formation fluids, un-cemented casing annuli,
and pipelines and other production facilities. 1724.9 (g)(2).
- Protocols for evaluation of wells and attendant production facilities that account for

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monitoring of casing pressure changes at the wellhead, analysis of facility flow erosion,
hydrate potential, individual facility component capacity and fluid disposal capability at
intended gas and liquid rates and pressures, and analysis of the specific impacts that the
intended operating pressure range could have on the corrosive potential of fluids in the
system. 1724.9 (g) (3).
- Ongoing verification and demonstration of the integrity of the reservoir, including
demonstration that reservoir integrity will not be adversely impacted by operating
conditions. 1724.9 (g) (4).
- Identification of potential threats and hazards, accounting for likelihood of events and
consequences, risk ranking to develop preventive and mitigating measures,
documentation of risk evaluation and description of the basis for selection of preventive
and mitigating measures, data feedback and validation, and periodic risk assessment
reviews. 1724.9 (g)(5).
- Prioritization of risk mitigation efforts. 1724.9 (g)(6)
As soon as is practicable. Ensure that required project data is complete and current. Operators
must provide project data detailing:
- Any data required under Section 1724.7.
- Characteristics of the storage including petrophysical properties, mechanical properties,
maps of the cap rock including areal extent, isopach thickness, structure contour,
formation fracture gradient, primary and secondary permeability, lithology and lithologic
variation, threshold pressure, locations and characteristics of faults and fractures, and
impacts of intended minimum reservoir pressure as it relates to geo- mechanical stress,
reservoir liquid influx, surface facility gas cleaning and liquid handling, and liquid
disposal. 1724.9(a)(1) and 1724.9(b)(2).
- The oil and gas reserves of storage zones prior to start of injection, including calculations.
1724.9(a)(2).
- The proposed surface and subsurface safety devices, tests, and precautions. 1724.9(a)(3).
- Proposed wastewater disposal method. 1724.9(a)(4).

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Projects in development must submit this information prior to commissioning for compliance.
All projects must possess a Project Approval Letter. The Letter shall state the maximum and
minimum reservoir pressure limits. The limits must be based on the pressure required to inject
intended gas volumes at total inventory. The limit shall not exceed the design pressure limits of
the reservoir, wells, well heads, piping or associated facilities. 1724.9(b)(1). The minimum
reservoir pressure shall not be designed less than historic minimum operated pressure, unless
reservoir geo-mechanical competency can be demonstrated to the Division’s satisfaction. The
Letter must include the data and calculations used to determine these limits. 1724.9(b)(2).
Conclusion
The Regulations promulgate standards for system integrity tests, testing intervals, and ongoing
monitoring criteria for underground gas storage wells. The Regulations also promulgate
reporting intervals, a compliance schedule, and mandatory development of a Risk Management
Plan for all storage facilities. If adopted, the Regulations will apply to both pre-existing facilities
and projects currently in development upon the effective date of the Regulations. Compliance
with the Regulations may result in increased capital, administrative, personnel, and legal costs.
This document is for informational purposes only and is not intended to serve as a substitute for
a comprehensive review of the Regulations.