I’d like to share a recent statement by the Keith Hutton, CEO of XTO Energy, a major natural gas exploration and development company in Texas recently acquired by Exxon Mobil.
“Low natural gas prices are lifting the U.S. economy even as many people are asking questions about its environmental impact.”
“Natural gas is revitalizing America’s steel industry, reinvigorating its petrochemical industry” and benefiting heavy-equipment makers.
Keith’s statement underscores the growing global trend in natural gas production and consumption.
When you take a look at the natural gas industry, you find an invisible link that keeps it running efficiently. This connection lies buried in sites, for every country, that relies on natural gas as a source of energy. This unseen link is natural gas storage facilities.” Storage underpins the gas industry from production to pipelines to consumers.
In the same way that stockpiling water behind dams allows farming to flourish in parts of the world, gas storage is a catalyst for impressive growth within the natural gas industry.
So today, I will present a brief overview that begins with why’s and how’s of natural gas storage and ends with its economics and future outlook.
When the idea for natural gas storage was originally conceived, the underlying principle was one of getting natural gas as close as possible to the intended markets.
Traditionally, consumption increased during the winter months for residential and light commercial heating.
However, today, consumption of natural gas has increased during the summer months – to fuel gas-fired electrical generators during demand peaks for residential, commercial and industrial cooling.
The exploration, production, and transportation of natural gas takes time. The gas that reaches its destination is not always needed right away, so it is injected into underground storage facilities.
The key driver of natural gas storage is the prerequisite for efficient and reliable natural gas supply at the end-user level. It’s a way of managing fluctuations in gas supply and demand.
Storage solves the imbalance between relatively constant natural gas production and inconsistent gas consumption. It’s a supply cushion to prevent interruptions.
This chart shows the seasonal influence of natural gas stockpiling. Operators want to inject natural gas into storage when demand is low – historically in the summer – and withdraw it during times of high demand – in the winter. Today, the chart is somewhat different with demand peaks now occurring during the hot summer months.
Natural gas might also go into storage to:
• Balance the flow in pipeline systems by ensuring pipeline pressures are kept within design parameters.
• Maintain contractual balance where shippers use stored gas to meet obligations and avoid hefty penalties.
• Ensure against any unforeseen accidents and natural disasters such as hurricanes, or malfunction OF production or distribution systems.
• Meet regulatory obligations by ensuring reliable gas supply to the consumer at the lowest cost, as required by the regulatory agency.
• Reduce price volatility by ensuring commodity liquidity at the market centers.
- injecting gas when prices are low, and
- withdrawing and selling when prices are high.
The natural gas industry is an extremely important segment of the U.S. economy. In addition to providing one of the cleanest burning fossil fuels available to all sectors, the industry provides much valuable commerce, from PRODUCTION to the end-user.
Today, the industry is composed of:
• Producers ranging from large integrated exploration and production companies with worldwide operations to small, one or two man, operators.
• Processors that remove water and gas condensate from the raw natural gas.
• Pipelines, which transport gas from producing regions to consuming regions.
• Storage, the subject of this discussion, controlled by operators who inject and withdraw stored natural gas in response to demand.
• Marketing companies, effectively operating at the citygate, are primarily concerned with selling natural gas, either to resellers or end users.
• the Local Distribution Companies or LDCs as they are known, that are primarily engaged in the retail sale and/or delivery of natural gas through the distribution system.
Prior to the mid-1980’s the U.S. natural gas industry was regulated. The regulated structure was simple with limited flexibility and few options for natural gas delivery.
Exploration and production companies explored and drilled for natural gas, selling their product at the wellhead to large transportation pipelines. These pipelines transported the natural gas, selling it to the LDCs, which in turn distributed and sold that gas to its customers.
Under regulation, the price for which producers and transportation pipelines could sell the gas was federally regulated.
Regulation of wellhead prices assured monopolies for large transportation pipelines and distribution companies. There were few incentives to improve service and innovate. Regulation of the industry also led to natural gas SHORTAGES.
With deregulation, wellhead prices were no longer regulated; meaning the price of natural gas is dependent on supply and demand.
Now, the market is much more open to competition and choices. Interstate pipelines no longer take ownership of the natural gas commodity.
Producing companies now sell too many different kinds of buyers, including industrial customers, independent marketers, LDCs, and marketing companies.
However, end users can purchase the GAS directly from producers or LDCs.
One of the primary differences in the current structure is the existence of natural gas marketers and traders that serve to facilitate the movement of natural gas from the producer to the end user.
Storage becomes the traders tool to fill in the physical gap between production and consumption and to stabilize prices that might surge when demand is high and plunge when demand slackens.
The operating characteristics of storage facilities define how they perform. Thereby, establishing the foundation for how each type of reservoir strategically fits into the supply chain.
Operating characteristics include:
• Total Capacity, which is the maximum volume of gas that can be stored in a facility.
• Base or Cushion Gas, which is the volume of gas that must remain in the reservoir to maintain adequate pressure to support deliverability. Generally, this cushion gas remains unrecoverable.
• Working Gas Capacity or Top Gas which is equal to the Total Capacity minus the Base Gas. By definition, working gas capacity is the amount of gas available to produce and sell.
This graph shows the relationship between working and cushion gas.
The top line is the reservoirs total capacity consisting of working gas shown in the upper yellow section and unrecoverable cushion gas in the lower green section.
Cushion gas is shown to average about 55% of the storage facility’s total operating capacity. This unrecoverable cushion gas both increases the capital cost to develop a facility, and reduces the quantity of revenue producing working gas.
• Deliverability is the capability of the storage facility to withdraw working Gas from the reservoir for delivery into pipelines that serve the marketplace.
• Injection Capacity refers to the rate at which the facility can inject working gas into storage.
• Cycling, which refers to the number of times that the working gas volumes can be injected and withdrawn in a year.
Traditionally, reservoir storage was designed to complete one cycle per year. Recent market trends, such as the use of natural gas electricity generation stations in the summer, have produced the need for storage facilities that cycle several times per year
How They Work
To create a sort of storage vessel underground, natural gas is injected into the formation, building up pressure as more gas is added. In this sense, the underground formation becomes a pressurized gas container.
At the storage site, the gas is filtered to remove any residual solids, passed through a gas metering station, and then to a compressor station.
The compressor station, located in a separate building, brings the natural gas to the right pressure for injection, typically up to 4790 psi (330 bar). Because the temperature of gas increases with compression, cooling units are used to bring the gas to the specified injection temperature.
Withdrawal of gas from an underground storage facility is almost the same technological process as extraction from gas producing fields.
Flowing back to the surface, the gas is received and gathered at collecting stations.
From there, the gas is supplied to a separation site for the removal of produced water and solids, and then routed to a final cleaning and drying site.
When sufficient liquid has been removed from the gas, the dried gas is routed to a trunk pipeline at a pressure approximately 940 psi (65 bar) .
Natural gas can be stored for an indefinite period of time in a number of different storage facilities for later consumption.
Many methods flopped as too expensive to build or too inefficient – gas would leak away or not enough injected gas could be withdrawn later.
The most obvious and successful solution was to store the gas underground and under pressure.
The three (3) most common types of underground storage facilities are derived from:
• depleted oil and gas fields,
• aquifers, and
• salt cavern formations.
Each of these storage facilities has distinct physical and economic characteristics which govern its suitability for a given application.
In the case of depleted gas and aquifer storage reservoirs, operational characteristics are primarily dependent on the porosity, permeability, and retention capability of the sedimentary rock formation and overlying impermeable cap layer.
The porosity of the formation determines the amount of natural gas that it may hold, while its permeability determines the rate at which natural gas flows through the formation, which in turn determines the rate of injection and withdrawal of the gas.
Depleted Gas Reservoirs
Old, depleted oil and gas fields account for about 70% of the total U.S. working gas capacity. They are the Wal-Mart, of gas storage: They’re big, almost everywhere and dominate the industry.
O&G fields that have already been exploited are particularly suitable for storing natural gas. These structures have successfully kept their hydrocarbon deposits trapped for millions of years.
They occur at depths of between 2,500 and 4,000 meters. Huge volumes can be stored, often from several hundred million to several billion cubic meters (m³).
Depleted fields require no special exploration for characterization. And as an additional benefit, conversion of a field from production to storage takes advantage of existing wells, gathering systems, and transportation infrastructure.
They also offer minimal disruption to the environment beyond that caused by original drilling operations, and require no routine service disruptions for periodic inspections.
For these reasons, depleted O&G fields are by far the most popular form of storage and the least expensive to develop and operate.
In order to maintain pressure, up to about 50% of the total capacity becomes unrecoverable cushion gas. However, they may require less injected BASE gas because some native gas still remains in the reservoirs.
Other disadvantages include:
• porosity and permeability characteristics that limit injection and withdrawal rate,
• limited capability to cycle more than a few times per year, and
• costly maintenance and reconditioning.
Aquifer storage reservoirs account for approximately 10% of the total U.S. working gas capacity.
They are the most expensive site to develop. But enable gas storage in locations where hydrocarbon reservoirs are not readily available or suitable for development.
Aquifers are geologically similar to depleted oil and gas production fields. Essentially, they are reconditioned underground water formations comprised of porous, permeable sedimentary rock layers, with an overlying impermeable cap rock.
However, their operational characteristics are not thoroughly understood. Also, because of the risk for reservoir leaks, this type of storage option requires test wells to verify the “trapping” performance and its suitability as a storage facility.
Because of the requirement to fill slowly while pushing the water back, these facilities operated with one withdrawal period per year. Their deliverability, injectivity, and cycling characteristics fall in between those of depleted reservoir and salt cavern facilities.
A significant amount of time and money goes into determining their suitability for storing gas.
Additionally, more extensive infrastructure must be developed including: installation of wells, extraction equipment, pipelines, dehydration facilities, and compression equipment.
Aquifer reservoirs have high cushion gas requirements, up to 80%. And as a result, their capital cost fluctuates with changes in the market price of natural gas. The higher the price, the more costly to develop!
And finally, poor retention capabilities and stringent environmental restrictions increase their development cost and decrease their popularity.
The hot trend in gas storage is to park the gas in new or expanded salt caverns. These storage facilities account for about 20% of the total U.S. working gas capacity.
Their competitive advantage is that the gas stored in them can be delivered quickly. This makes them ideal holding sites for gas to meet demand surges or emergencies.
They can be as large as a 1.6 km in diameter and anywhere from 450 to 18 hundred meters below the surface,
To create caverns, developers use a method called solution mining where fresh water is blasted into salt formations. This dissolves the SALT, flushes it to the surface and hollows out a chamber. The cavern is extremely air tight, allowing little injected gas to escape. Also, their WALLS have the structural strength of steel, letting them hold up over time. However, this method of construction can be quite expensive.
As compared to depleted gas reservoirs or aquifers, salt caverns offer high rates of injection and withdrawal. The result is that the working gas in salt caverns can be cycled several times per year, as much as 12.
Salt caverns also require less cushion gas; usually 20% to 30% of the facility’s working gas volume.
Their key drawbacks include their high capital cost, small size and geographic limitations.
There are also environmental issues related to brine disposal during construction.
Finally, Salt caverns can have high operating cost due to the corrosive environment.
Aboveground storage offer several advantages over alternative underground storage options.
Specifically, in regions where the geology does not support the development of underground reservoirs. They also allow the storage facility to be constructed near the customers, a great benefit in case of potential supply SLOWDOWNS.
Aboveground storage provides value to a broad range of potential customers such as peaking power producers or gas distribution companies that have limited pipeline or storage alternatives.
They align the user’s daily injection and withdrawal rates, to and from storage, to match hourly load requirements.
They are dynamic alternatives that provide high deliverability and cycling capabilities similar to salt storage reservoirs.
There are a number of ways to store natural gas aboveground:
• in the liquefied state, which I will shortly discuss in more detail
• In tank farms that play an important logistical role by helping to reduce the impact of demand spikes on power generation, and
• temporarily stored in the pipeline system by packing more gas into the pipeline via an increase in pressure.
When natural gas is cooled to about minus 161°C (-260 °F), the gas will condense and become a liquid. This is commonly referred to as liquefied natural gas or LNG. Today, LNG is the primary way of storing natural gas aboveground.
A significant portion of the world’s natural gas assets are considered “stranded” because they are located far from any market. Transportation of LNG by truck or ship is one method to bring this stranded gas to the consumer. Also, the export market of natural gas is made economically viable by liquefaction.
This is made possible because natural gas in the liquefied state has an energy density some 600 times that of the uncompressed gas. That is, packing more energy in a smaller volume.
After cooling, the liquid is pumped into A specialized insulated storage tank where it is stored at atmospheric pressure. The tank acts like a large Thermos bottle, keeping the gas cold enough to remain in the liquid form until needed.
Because LNG can be produced and stored close to the market, it provides high delivery capacity at very short notice during peak periods when market demand exceeds pipeline deliverability.
Furthermore, LNG storage facilities have no requirement for cushion gas. But they are more expensive to build and maintain than new underground storage reservoirs.
As with all infrastructural assets, in the energy sector, developing storage facilities is capital intensive. They are long-term investments with many decades of performance potential.
Many factors must be considered before project launch.
Development costs can vary by well over 100% between the least and most costly regions. The wide price range is primarily driven by the quality of the geological structure and the corresponding design and equipment requirements.
The proximity to pipeline infrastructure, permitting and environmental requirements are other critical cost considerations.
Also, of primary importance is the capacity and market price of base gas. Since this can be one of the more expensive items of a storage project, it can negatively impact the justification of facilities that have high base gas levels such as aquifers and depleted gas reservoirs.
When all these factors are taken into consideration, aquifers become the most costly, while depleted O&G fields the least expensive.
In the U.S., a depleted gas reservoir might cost from $6.7 to $13.6 million per Bcf of working gas capacity. Salt caverns are relatively expensive to develop. However, because they can be cycled many times, on a deliverability basis they can be competitive to depleted reservoirs.
Finally, in deciding what direction to take, it’s important to look at the cost differential between adding a new storage facility versus expanding an existing facility. Historically, the cost of adding new capacity is on the average about 30% greater than the cost of expanding existing fields.
Although operators are enthusiastic about new opportunities in the gas-storage industry, they are aware that challenges, such as price spreads, new regulations, location constraints, and A demanding industry and market must be overcome.
These factors, coupled with the LDCs ever-changing balancing act of supply versus demand have serious implications for the management and control of storage facilities.
Another major challenge has been finding optimal locations for storage in the right regions that have well-defined structures.
Today, more and more urban growth has brought population centers closer to physical sites. Developers now have to focus on the needs of the adjacent communities while protecting the integrity of storage facilities.
The industry is facing more regulatory hurdles as environmental groups become more empowered and demanding.
All of these factors have added to project cost, uncertainty, and timelines.
The global natural gas industry has witnessed robust growth in the last decade due to low market prices and the vast gas supply from unconventional natural gas production.
Increased consumption in the power generation sector in combination with higher demand in the industrial and transportation sectors promises significant growth and opportunities for the industry.
Also, under a scenario, that envisions a worldwide momentum towards stick policies aimed at cutting greenhouse gas emissions; electric utilities and other sectors of the economy will have no other choice but to adopt natural gas as a logical alternative.
Continuous capital expenditures on the infrastructure will be needed to support this ever increasing worldwide demand.
Developers will look for:
• more economical storage solutions,
• better ways to reduce the amount of cushion gas, and
• improved methods to extract stored gas faster to meet short-term demands.
Promising advancements include:
• Chilling salt formations to increase the capacity of working gas.
• Using hard rock formations in areas where more conventional storage types, do not exist.
• Building “lined rock caverns” for increased cycling.
• Using hydrates to further increase volumetric energy density.
Sufficient midstream natural gas assets are crucial for an effective market.
Strategically, gas storage helps maintain the transmission and distribution system’s reliability and its capability to transport natural gas supplies efficiently without interruption to seasonal demands.
When designing a storage facility the primary considerations become its capability to meet:
• base load requirements to satisfy long term seasonal demand, and
• peak load requirements to have high-deliverability for short periods of time.
The decision to construct a facility, and of which type, is dependent on geographic and cost considerations,
At the end of the day, the long-term adequacy of storage investments depends on how much price volatility customers consider acceptable.
Insufficient natural gas infrastructure and storage can reduce delivery of natural gas to consumers who value it most.
By. Dr. Barry Stevens