There are three basic types of underground natural gas storage: 1) storage in depleted gas or oil reservoirs, 2) storage in aquifers, and 3) storage in salt caverns. Less used are mines and hard rock caverns. Compressed gas is pumped in to increase reservoir pressure. Subsurface requirements include a reservoir rock with adequate porosity and permeability, a trapping mechanism to capture the hydrocarbons, a seal or confining layer that keeps fluids from leaking out, and adequate pressure to flow.
The rate at
which natural gas can be withdrawn from a reservoir is known as its
deliverability. I worked at an early horizontal well in 1996 that was designed
to increase deliverability by accessing more sections of the reservoir in a depleted
gas field. I also worked at wells that drilled through existing underground gas
storage fields to access deeper oil & gas reservoirs. The filled reservoirs
that were previously hydraulically fractured showed high gas readings during
drilling and were flared temporarily for safety before being cased off. Most
gas storage production wells are vertical wells but horizontal wells are
becoming more common and can increase field deliverability.
Most U.S.
underground gas storage is in depleted oil and gas reservoirs. Most storage
fields are near highly populated gas consumption areas. Existing wells,
gathering systems, and pipeline connections are utilized for storage fields.
This can be problematic when the wells and pipelines are old and can have
issues like well casing breaches or pipeline leaks. These depleted fields are
often well-mapped during the development phase and already have cushion gas
present in the reservoir.
Aquifer
storage is common in the Midwest, particularly in Illinois, Indiana, and Iowa. These
fields require more base, or cushion gas, and have less flexibility in injecting
and withdrawing compared to depleted oil & gas fields. However, a strong
water drive component in the aquifer can enhance deliverability. A water drive
means that the water exerts pressure in the gas part of the reservoir which
drives deliverability.
Salt cavern fields are common in Louisiana, Texas, and Mississippi along the Gulf Coast. They have low base gas requirements and high deliverability rates. There are also a few salt cavern fields in Michigan, Pennsylvania, Ohio, West Virginia, and New York where the salt beds are leached out to make open caverns. Usually, the salts are solution-mined by being dissolved in water and producing the resulting brine to leave a cavern. This is more expensive than storage in depleted oil and gas fields but as noted also offers higher deliverability rates.
Interstate
pipeline companies, intrastate pipeline companies, local distribution companies
(LDCs), and independent storage service providers are commonly the owners of
natural gas storage fields. There are about 400 active underground gas storage
facilities in 30 U.S. states owned by about 120 different companies. The gas in
the storage fields may be held under lease with shippers, LDCs, or end users
who own the gas. According to the EIA, the base gas is also used to ensure supply
management:
“…interstate pipeline companies rely heavily on
underground storage to facilitate load balancing and system supply management
on their long-haul transmission lines. FERC regulations allow interstate
pipeline companies to reserve some portion of their storage capacity for this
purpose. Nonetheless, the bulk of their storage capacity is leased to other
industry participants. Intrastate pipeline companies also use storage capacity
and inventories for similar purposes, in addition to serving customers.”
LDCs often lease a part of their storage capacity to third
parties, often gas marketers. This allows them to earn extra revenue. Natural
gas storage was deregulated in 1994, allowing for such sharing of resources. This
FERC Order 636 ushered in ‘open access’ to gas storage. EIA explains:
“Open access has allowed storage to be used other than
simply as backup inventory or as a supplemental seasonal supply source. For
example, marketers and other third parties may move natural gas into and out of
storage (subject to the operational capabilities of the site or the tariff
limitations) as changes in price levels present opportunities to buy and store
natural gas when demand is relatively low, and sell during periods of
peak-demand when the price is elevated. Further, storage is used in conjunction
with various financial instruments (e.g., futures and options contracts, swaps,
etc.) in creative and complex ways in an attempt to profit from market
conditions.”
Open access favors salt cavern storage due to its high
deliverability. Independent storage providers have focused on developing
high-deliverability storage fields, both salt caverns and depleted oil &
gas fields.
Many of the
wells in gas storage fields were not originally designed to inject or produce
from gas storage fields. Factors like the age of the well and the composition
of the hydrocarbons and brine previously produced from it are important
considerations. They can affect the mechanical integrity of the wells. As can
be seen below, my state, Ohio, has by far the most gas storage wells followed
by Pennsylvania.
Base Gas (or Cushion Gas) vs. Working Gas
Volumetrics for gas storage include total gas
capacity, or how much gas the field can hold and gas in storage, which is the
gas stored at any particular time. Base gas, also known as cushion gas, “is
the volume of natural gas intended as permanent inventory in a storage
reservoir to maintain adequate pressure and deliverability rates throughout the
withdrawal season.” The working gas is the total gas capacity minus the base
gas. It represents the gas that is available to be consumed.
Deliverability and Injection Capacity
Deliverability
is another important metric. It refers to the rate at which gas can be withdrawn.
It is usually expressed as the amount of gas that can be delivered in one 24-hour
period. It is usually given in MMCF/day. According to the EIA deliverability “depends
on factors such as the amount of natural gas in the reservoir at any particular
time, the pressure within the reservoir, the compression capability available
to the reservoir, the configuration and capabilities of surface facilities
associated with the reservoir, and other factors.”
Injection
capacity refers to how much gas can be injected in a 24-hour period. Like its complement,
deliverability, it is dependent on how much gas is in the reservoir at any
given time.
EIA Gas Storage Reporting
The EIA tracks
working gas in underground storage and compares it to the 5-year maximum, the 5-year
minimum, and the 5-year average. This is reported weekly. The latest report is
shown below for the week ending August 16, 2024.
Natural Gas Storage Regulation in the U.S.
Regulation of natural
gas pipelines moving gas in and out of gas storage facilities falls under
Federal jurisdiction under the Natural Gas Pipeline Safety Act (NGPSA). The
Pipeline Hazardous Materials Safety Administration (PHMSA) regulates natural
gas storage along with states. After the Aliso Canyon incident, the PHMSA became
more involved with storage field regulation. Facilities are classified as
interstate or intrastate and are regulated differently. Interstate facilities
that link multiple states are regulated under FERC. Intrastate facilities,
entirely within one state, are regulated by rules drawn up by state public
utility commissions and state oil and gas boards.
Sometimes
jurisdiction becomes an issue. This happens when FERC or PHMSA requirements
collide with state requirements. In 2011 a task force was convened as PHMSA attempted
to codify new rules. This task force included the Interstate Natural Gas
Association of America (INGAA), the American Gas Association (AGA), PHMSA, state
agencies, and input from The American Petroleum Institute (API). They put out
recommendations in 2015 for salt cavern storage and depleted reservoir storage.
The PIPES Act provides that the State authorities may adopt additional or more
stringent safety regulations for intrastate gas storage facilities as long as
they are compatible with the Federal minimum standards. Since 90% of storage
fields are considered to be intrastate, or within the bounds of a single state,
then state requirements were reviewed to see if they met or exceeded federal
requirements.
Ensuring Gas Storage Safety and Reliability and the
Aliso Canyon Catastrophic Leak
In October
2016 the Department of Energy released a report: Ensuring Safe and Reliable
Underground Natural Gas Storage: Final Report of the Interagency Task Force on
Natural Gas Storage Safety. This report was prompted by the powerful 2015 Aliso
Canyon gas storage field leak that resulted in many people being evacuated for long
periods of time as the damaged well was addressed. A federal task force involving
Congress, the DOE, and the DOT’s Pipeline and Hazardous Materials Safety Administration
(PHMSA) was convened to address the issue following Obama’s signing of the Protecting
our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2016. The
key recommendations from the task force report are as follows:
• Gas storage operators should begin a rigorous
evaluation program to baseline the status of their wells, establish risk
management planning and, in most cases, phase-out old wells with
single-point-of failure designs.
• Advance preparation for possible natural gas leaks
and coordinated emergency response in the case of a leak can help manage and
mitigate potential health and environmental impacts of leaks when they do
occur.
• Power system planners and operators need to better
understand the risks that potential gas storage disruptions create for the
electric system
The source of
the Aliso Canyon leak was a very old well, drilled in the 1950s, that had
developed casing leaks. According to discussions I had at the time with a geologist
who worked in Appalachian gas storage, this old well should not have been used
in a gas storage field. Production wells in storage fields need high
deliverability through reservoir properties, pressure, and adequate well
construction and maintenance. This was not the case with the very old and
inadequate well that resulted in the catastrophic Aliso Canyon leak in
California. Below is a graph from the report showing the age of wells in gas
storage fields. This is concerning since most of the wells were drilled in the
1950s, 60s, and 70s. About 80% of these wells were drilled before 1980.
The Aliso
Canyon gas storage field is owned by Southern California Gas Company
(SoCalGas). The well leaked for four months. The primary public health concern was
the concentration of odorant in the ambient air. Odorants are added to natural
gas so they can be smelled when there is a leak. Odorant concentration is not
typically a concern during smaller leaks unless in confined spaces. Natural gas
may also contain hydrogen sulfide (H2S), other sulfur compounds, and benzene,
all potentially dangerous to human health. The leak initially released
approximately 53 metric tons of methane per hour or a total of approximately 1,300
metric tons of methane per day
What happened
at Aliso Canyon is known as a well integrity issue. Eight attempts to ‘top kill’
the well over the first two months of the leak were unsuccessful. The well was
eventually ‘bottom killed’ by drilling a relief well to intersect the wellbore
and divert the flow. The old well could then be cemented and plugged. Drilling
of the old well began in 1953 and was completed in 1954. Thus, the well was
about 61 years old when the leak occurred. A schematic of the well is shown below
depicting what is believed to have happened when attempts to kill the well from
the surface (top kill) failed. The accident required detailed air monitoring
for methane, VOCs, benzene, and sulfur compounds. Only one sample showed unacceptable
levels of one dangerous chemical, H2S. The vast majority showed levels of these
compounds within acceptable limits. The PHMSA issued new requirements for
storage fields. The task force report goes on to estimate the impacts of the
leak on local residents and on California natural gas prices. Then they do some
scenario analysis, noting where leaking storage fields could cause the most damage
and disruption.
Task Force Recommendations
The task force made the following recommendations regarding well integrity:
1)
Operators should phase out wells with single
point of failure designs. This refers to having just one string of casing or
tubing shielding the wellbore from the surrounding rock. This was the case with
the Aliso Canyon well where gas was moved through both the tuing and the casing
outside the tubing.
2)
Operators should undertake rigorous well
integrity evaluation programs. This is what the PHMSA recommended. They
made specific recommendations for this:
“(1) a compilation and standardization of all available well records relevant to mechanical integrity; (2) an integrity testing program that includes usage of leakage surveys and cement bond and corrosion logs to establish that all wells are currently performing as expected; (3) documentation of a risk management plan to guide future monitoring, maintenance, and upgrades; (4) establishment of design standards for new well casing and tubing; and (5) establishment of safe operating pressures for existing casing and tubing. Many operators already apply these risk management practices in their operations. These approaches should be applied industry-wide.”
3)
Operators should prioritize integrity tests
that provide hard data on well performance. This involves monitoring,
logging, and mechanical integrity testing.
4)
Operators should deploy continuous monitoring
for wells and critical gas handling infrastructure.
The task force
also recommended risk management planning and better management of well record.
They also recommended some industry knowledge-gathering steps including DOE/DOT
joint studies on downhole safety valves and casing-wall thickness assessment
tools. They also noted that gaps in available data should be addressed. Many
other recommendations addressed what should be done when a leak occurs, including
air monitoring and other public protection measures. The report also addresses
reliability concerns such as supplying gas when storage levels are low and
keeping prices from spiking. Some gas storage facilities can affect electricity
reliability if they go offline due to a leak. The Aliso Canyon accident caused gas
price spikes in California some electricity price spikes as well.
How Stored Natural Gas is Valuated and Priced
A blog post in
Edison Energy notes several different ways storage gas may be valued: 1) intrinsic
value – the difference between injected cost and withdrawal cost, minus
cost to store. This is inherent in the common “forward market” where gas is
typically bought in summer when it is cheap to store and sold in winter when it
tends to cost more, 2) extrinsic value – a complex evaluation where in
one case gas is valued according to its ability to be sold quickly into a
profitable market that may appear quickly. Salt cavern storage, with its high
deliverability and injectability, is ideal for adding extrinsic value, 3) market
conditions – more specifically this refers to regional market conditions.
In the case of New England and the Northeast the regional market conditions are
strongly affected by the inadequate pipeline capacity. Market perceptions of
the ability to meet winter weather demand is a big factor, 4) storage
service level (firm vs. interruptible) – firm storage is guaranteed
to be available during peak demand and so is valued higher than interruptible
storage which has no such guarantee, 5) market access – delivering
storage to a volatile market subject to demand spikes and subsequent price
spikes due mainly to weather events has a higher extrinsic value. Inadequate
pipeline capacity, or another deliverability problem like the unwinterized gas
system in Texas in Feb. 2021, is often the real culprit of the price spikes,
and 6) storage space vs injection/withdrawal rights – some gas storage
facilities may have access limitations for a given day so that a given storage
space may be more or less valuable depending on those limitations.
The author of
the blog summarized the valuation of gas in storage as follows:
“In today’s complex energy environment, the ability to
quantify the value and take advantage of assets like storage is a combination
of known and unknown factors that depends on how one intends to use the asset
and the flexibility storage can provide to an entity trying to avoid risk. Each variable that goes into calculating the
potential benefit of storage comes with risk and reward and varies greatly
based on known market conditions at the time, as well as unpredictable market
conditions down the road being overlaid with the term commitment of owning
storage.”
References:
The
Basics of Underground Natural Gas Storage. Energy Information Administration. November
16, 2015. The Basics of Underground Natural Gas
Storage - U.S. Energy Information Administration (eia.gov)
Fact
Sheet: Ensuring Safe and Reliable Underground Natural Gas Storage. Department
of Energy. Fact
Sheet: Ensuring Safe and Reliable Underground Natural Gas Storage | Department
of Energy
Ensuring
Safe and Reliable Underground Natural Gas Storage. Final Report of the
Interagency Task Force on Natural Gas Storage Safety. Department of Energy.
October 2016. Ensuring
Safe and Reliable Underground Natural Gas Storage (energy.gov)
Weekly
Natural Gas Storage Report. for week ending August 16, 2024. Released: August
22, 2024. Energy Information Administration. Weekly Natural Gas Storage Report - EIA
How is Natural Gas Storage Valued? Jeff
Bolyard. Edison Energy. July 11, 2019. How
is Natural Gas Storage Valued? | Edison Energy
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