Natural Gas Storage in the US
When the idea for natural gas storage was originally conceived, the underlying fundamental was one of getting natural gas as close to the markets to be served as possible to maximize the availability of gas during high demand months. Gas usage historically peaked in the winter when residential and light commercial demand for heating peaked on cold winter days. The first natural gas storage facility in the United States was put into service in New York in 1916 at the Zoar Field (a depleted natural gas reservoir) south of Buffalo, New York. The facility remains in operation today.
With the exception of a few intrastate gas storage projects in the major gas producing states, practically all of the underground natural gas storage facilities developed in the United States since the Zoar Field have been developed under the ownership or control of large pipeline companies or regulated local gas distribution companies (LDC’s). Not surprisingly, these facilities have operated on a seasonal basis usually cycling gas once per year. Five significant marketplace changes driven by the combination of regulatory changes and technology changes have significantly altered how natural gas storage facilities will be used in the future.
The 1978 Public Utility Regulatory Act, which among other regulatory changes, provided for the creation of non-utility electric power generators
The 1990 Clean Air Act Amendment
Deregulation and unbundling of the sale and transportation of natural gas starting in the early 1980s and continuing in the 1990s
Technological improvements in gas turbine technology starting in the 1980s and continuing today
Creation of markets for trading natural gas and electricity as commodities rather than being an extension of regulated gas and electric service
As a result of the foregoing events, the use of oil, coal, hydro, and nuclear energy sources has been seriously disadvantaged, which has established a strong preference for natural gas as the energy source for meeting the country’s future energy needs. The net effect of these changes is that natural gas has become the leading choice for home and light commercial heating appliances and the fuel of choice for most new power generation. The growth in gas fired electric generation is creating a significant new gas demand peak in the summer while at the same time winter peak demand for natural gas continues to grow. In addition, the operational needs of new gas fueled electric power plants has created day and night swings in demand for natural gas as well as weekday and weekend swings in demand.
What this means for the future of natural gas storage facilities is that storage will not only have to satisfy the traditional demands for fuel supply reliability, but it will also have to satisfy the significant and expanding swings in demand for gas that can only be accommodated by high performance, multiple cycle natural gas storage facilities.
COMMON TERMS USED IN THE GAS STORAGE BUSINESS
The following terms typically apply to all types of storage:
Total Capacity is the maximum volume of gas that can be stored in an underground storage facility.
Base Gas (or Cushion Gas) is the volume of gas that must remain in the reservoir to maintain adequate pressure to support deliverability in any type of reservoir and to preserve the integrity of the working capacity in salt caverns and aquifers.
Working Gas Capacity in the reservoir is equal to the Total Capacity minus the Base Gas.
Working Gas is the volume of gas in the reservoir above the Base Gas requirements at any given time. Working Gas is the gas available to the market.
Deliverability is the capability of the storage facility to withdraw Working Gas from the reservoir for delivery into pipelines to serve the marketplace. Various terms used to refer to deliverability are delivery rate, withdrawal rate, or withdrawal capacity. Deliverability is typically expressed as a flow rate in units of “millions of cubic feet per day” (MMcf/d); “millions of British thermal units per day” (mmBtu/d) or “dekatherms per day” (dth/d). Conversely, the rate at which the facility can inject Working Gas into storage is referred to as the Injection Rate.
Cycling refers to the storage facility’s ability to complete the injection and withdrawal of Working Gas. Traditionally reservoir storage is designed to complete one cycle in each year. Recent market trends have produced the need for storage facilities capable of completing multiple cycles per year.
TYPES OF STORAGE
There are over 400 natural gas underground storage facilities in operation in the United States today with the capacity to store 3,900 Bcf. Approximately 84% of these facilities utilize depleted reservoirs. The remaining 20% utilize either salt caverns or aquifers. Each type of facility has its own advantages and disadvantages.
Source: Energy Information Administration, Form EIA-191, “Underground Gas Storage Project.”
The following map illustrates the distribution of storage throughout the United
Salt Cavern Storage
Salt caverns, sometimes referred to as salt domes, are open caverns located at depths several hundred to several thousand feet below the earth’s surface and are accessed by one or more wells per cavern. The graphic (below) depicts a typical salt cavern facility. Most of the salt cavern facilities are located in Gulf Coast regions of the United States with some bedded salt deposits located in western Pennsylvania and New York.
Some of the advantages and disadvantages of salt cavern storage facilities are described below:
Advantages
High Injection and Withdrawal Rates
Multi-cycling capability
Disadvantages
High percentage of total gas volume needed for base gas
Environmental issues related to brine disposal during construction and operation
Volume of each cavern has practical and geological limitations (typically the total cavern size is in the 5-10 Bcf working gas range
Periodic service disruptions occur due to government mandated inspections
High operating cost due to corrosive environment
Aquifer Storage
The concept of using aquifers for natural gas storage was first demonstrated in the United States by Louisville Gas and Electric Company with the development of its Doe Run facility in Meade County, Kentucky in 1946. The graphic (right) depicts a typical aquifer storage facility. Most of these facilities are located in the upper Mid-Western part of the United States. Some of the advantages and disadvantages of the aquifer type of storage facility are shown below.
Advantages
Enables gas storage development in locations where hydrocarbon reservoirs are not readily available or suitable of natural gas storage
Disadvantages
Maintaining integrity of the gas/water interface imposes limits on operating flexibility
Requires a relatively large base gas to working gas ratio
Higher potential for water supply contamination
Depleted Reservoir Storage
Depleted reservoir storage utilizes a depleted underground natural gas reservoir that originally contained oil and/or gas. Gas is injected back into the depleted reservoir in order to re-fill the reservoir. The withdrawal process for the gas in storage normally replicates the process originally used to produce gas from the reservoir in the first place. In the past, the conversion of a depleted gas reservoir for storage use traditionally involved drilling many new wells that would enable a more rapid withdrawal of gas than was originally used to deplete the reservoir. Typically, the injection and withdrawal rates are proportional to the surface area of the well bore that is exposed to the “pay zone” in the depleted reservoir.
Until the early 1990’s the development of storage facilities in depleted reservoirs involved the use of vertical wells. This meant that for a reservoir to be a candidate for development into a storage reservoir, the formation had to be fairly thick and the reservoir characteristics had to be very conducive to storage requirements.
The graphic to the right depicts a typical depleted reservoir gas storage facility using vertical wells.
everal of the advantages and disadvantages of using depleted reservoirs for storage through the old traditional use of vertical wells are listed below.
Advantages
Minimal disruption to environment beyond that caused by original drilling operations
Multiple access points to reservoir eliminating service disruptions due to well problems
Reservoir history is known
No routine service disruptions for periodic inspections
Disadvantages
Reservoir formation must be fairly thick
Reservoir characteristics (e.g., low porosity and permeability) can limit injection and withdrawal rates
Except for a few superior reservoir storage facilities, most existing reservoir storage is limited to seasonal service
On average traditional reservoir storage requires 50-60 percent of total storage capacity to be used for base gas
Salternatives Depleted Reservoir Storage
As horizontal drilling technology became commercially feasible for exploration and production of oil and gas in the late 1980s and the early 1990s, it became apparent that this same technology could be used to enhance the performance of natural gas storage facilities. By being able to drill laterally through the storage formation, a single horizontal well can achieve performance levels that make many depleted reservoirs feasible for gas storage that were previously deemed not suitable for development. The graphic to the right depicts a typical depleted reservoir storage facility utilizing horizontal wells.
Several of the advantages and disadvantages of developing depleted reservoirs into storage fields through the use of horizontal wells and Salternatives Technology are listed below.
Advantages
All of the advantages of traditional depleted reservoir storage
Enables economic storage development utilizing reservoirs that would not be feasible otherwise
Greater geographic application of storage development
High performance injection and withdrawal can be achieved
Lower base gas requirements than aquifers, traditional depleted reservoir, and shallow salt cavern storage
Disadvantages
Not all geologic formations are suitable for development with horizontal wells.
Requires the careful integration of expertise in geology, reservoir science, and drilling engineering