Imagine a legion of small, autonomous and intelligent self-powered magnetic robots zipping along miles of aging underground gas pipelines, using cameras to visually inspect the interiors of large diameter transmission lines as well as distribution mains with diameters as small as six inches. Envision these wireless robots sending a live image of a weak spot to a computer-equipped operator on the surface and then making needed repairs before it becomes a safety hazard.
Or consider a gas pipe with embedded sensors that could send an early warning when corrosion threatened to create a dangerous break, or that could automatically signal construction crews before their heavy machinery inadvertently punctured it.
Or visualize an airplane streaking across the sky with sophisticated microwave radar-imaging systems searching for invisible gas leaks from underground pipelines.
These are several of the high-tech devices being developed in the U.S. Department of Energy's Fossil Energy program to improve the safety and performance of the nation's gas delivery infrastructure.
The Department began its research efforts to make the nation's pipelines safer in September 2000 when it developed a roadmap for Natural Gas Infrastructure Reliability: Pathways for Enhanced Integrity, Reliability, and Deliverability. The roadmap was developed to identify the critical challenges of delivering natural gas and the appropriate federal action to address the challenges. The roadmap was updated in 2002 and most recently in February 2004 to reflect current changes in the industry and business environment.
The DOE program was fashioned largely in response to concerns that the nation's million-plus miles of natural gas transmission and distribution pipelines were aging, and the increasing need for efficient and reliable pipeline systems. Nearly a quarter of the nation's gas pipelines are now more than 50 years old. According to the July 2004 Interstate Natural Gas Association of America report, An Updated Assessment of Pipeline and Storage Infrastructure for the North American Gas Market, approximately $19 billion of investment will be needed for replacement of current pipe simply to maintain existing capacity. Nearly $42 billion will be needed for new pipeline and storage projects. Moreover, with the nation's gas industry facing the costly prospects of building hundreds of thousands of miles of new pipelines, there is an obvious need for lower cost, more rapid, and more precise ways to monitor the condition of pipes. In essence, an "early warning system" is needed so that potential pipeline problems can be detected and repaired before they become catastrophic and potentially life-threatening accidents.
DOE program goals are to:
- Maintain/enhance pipeline system reliability and integrity.
- Increase gas deliverability.
- Reduce environmental impact by increasing capacity of existing infrastructure.
- Reduce environmental impact of fugitive methane emissions from pipelines and facilities.
- Address gas and electric power interdependencies and infrastructure requirements.
- Develop new technology for future intelligent gas delivery systems.
- Enhance viability of LNG as an energy option for America.
A safe, reliable, expanded natural gas transmission, distribution, and storage system is critical to meet growing gas demand. Natural gas infrastructure in the United States, while robust and reliable, is facing operational challenges. In the transition to competitive energy markets, industry focused its efforts on reducing costs, often at the expense of its R&D program. The federal government, in collaboration with universities, national laboratories, and the private sector, has played a key role in performing technology R&D for enhancing energy system reliability.
The U.S. natural gas pipeline network consists of around 41,000 miles of field gathering lines, 250,000 miles of interstate transmission, plus approximately 75,000 miles of intrastate transmission. Around 80 systems make up the interstate transmission network. Another 60 systems operate strictly within individual states. These interstate and intrastate transmission pipelines feed over 1.1 million miles of regional lines in some 1,300 local distribution utility networks. Collectively, the natural gas pipeline network delivers natural gas to 62 million customers in the United States.
Natural gas pipelines serve electric generation and industrial customers directly, and link through city gates to regional distribution mains which, in turn, feed the local service lines of retail gas consumers. Distribution pipelines also connected to liquefied natural gas (LNG) receiving terminals. In addition, there over 100 active LNG satellite storage facilities in the United States, mostly in the Northeast, many located near populated areas.
Transmission and Distribution
The Office of Fossil Energy has 65 active pipeline and storage projects. As of December 2004, the total program value was about $61 million dollars with industry cost share approaching 33 percent of project costs. Since the inception of the program, 34 projects have been completed and some are ready for commercialization.
These projects are already producing unique innovations and solutions. In June 2004, an $859,000 DOE project performed a first-of-a-kind field demonstration of a self-powered, remote-controlled robot called EXPLORER. The robot successfully inspected a mile of an 8-inch diameter live natural gas distribution main and delivered real-time pictures of the pipeline's interior over a wireless connection. A robot such as the EXPLORER can enable the inspection of smaller pipeline systems that cannot be accessed by more conventional inspection systems and can eliminate the need to dig multiple holes for external inspection, a major expense in urban areas. Recently, the project team of Carnegie-Mellon University and the Northeast Gas Association was awarded a DOE project to develop the next generation of EXPLORER that will take advantage of new developments in sensor technology.
DOE funded two other sensor development projects that have undergone field tests and have been evaluated for commercial use. One project developed a prototype sensor, known as conformable array, that can quickly and inexpensively measure natural gas pipeline deterioration. The other project performed an extensive field test at DOE's Rocky Mountain Oilfield Testing Center (RMOTC) that utilized low-flying aircraft, satellites, and special ground vehicles carrying advanced leak detection sensors. Successful demonstration of these technologies can significantly enhance industry's capabilities to maintain the safety and reliability of the Nation?s pipeline system.
A DOE-funded project with the Colorado State University, also successfully field tested an innovative commercial-scale pipeline compressor in Window Rock, Arizona in September 2004. This new compressor uses micro-pilot ignition of diesel fuel, which injects micro-liter quantities of fuel into the compressor engine to initiate ignition. By doing so, this minimizes the inconsistent combustion associated with slow-speed, reciprocating natural gas compressor engines. The new compressor engine operates more efficiently, reducing operation costs, compressor engine emissions, and fuel consumption.
In December 2004, six new projects with a total value of nearly $11.3 million were selected by DOE to develop advanced technologies to enhance the integrity, reliability, and security of the Nation's natural gas pipelines. The projects include technology innovations, such as robotic platforms that are self-adjusting and aligning and can navigate through plug valves, pipeline diameter reductions and expansions, and various types of pipeline bends.
Other projects are developing advanced compressor technology to increase the capacity of the Nation's existing natural gas pipeline infrastructure without adding additional compression units. One project is investigating the use of unmanned aerial vehicles equipped with laser-based leak detection technologies that may make it possible to achieve leak detection from altitudes greater than 50,000 feet.
With the nation likely to consume 40 percent more natural gas in 2025 than it did in 2004, the integrity and reliability of the largely unseen network of pipes that lie beneath America's towns and cities will be vital to ensuring both adequate energy and the safety of the nation's citizens.
Natural Gas Storage
Each winter about one-fifth of the natural gas Americans consume comes from gas storage sites. Gas storage is the primary means for the gas industry to manage fluctuations in supply and demand.
Because of gas storage, gas production fields and transmission pipelines can function at a more constant and efficient rate. During times when consumers need less gas (typically during the summer), excess supply is sent into storage. When demand peaks (primarily during the winter) the stored gas can be withdrawn to meet the additional seasonal need. Some gas is also stored to meet short-term peaks in demand which can range from a few hours to a few days.
Today, there are about 120 gas storage operators that maintain approximately 400 underground storage facilities, with a working gas capacity of nearly 4 trillion cubic feet. For the most part, these storage sites are heavily concentrated in and near major eastern and mid-continent markets.
Natural gas can be stored in a variety of ways. Most commonly, it is held in underground formations, in depleted oil or gas reservoirs (the most common), in natural aquifers, or in cavities created in large underground salt deposits. In at least one case in the United States, a reconditioned hard rock mine was converted into a gas storage facility.
||Natural gas can be stored underground in (A) salt caverns, (B) mines, (C) aquifers, (D) depleted oil/gas reservoirs, and (E) hard rock mines. |
Gas is injected and withdrawn from these formations using much of the same type of well drilling and production equipment found in a working natural gas field. But over time, the capability to add and produce natural gas from underground formations tends to decline. On average, more than 14,000 gas storage wells in the United States lose from 3 to 5 percent of their ability to inject and withdraw gas each year. The primary problem is the buildup of inorganic scale (typically calcium carbonate), organic residue, or even bacteria on the well pipe that clogs the openings that allow gas to flow into the well.
The Department of Energy's Fossil Energy program began working with the gas storage industry in 1997 to tackle the problem of declining deliverability from gas storage sites and to examine new ways to store natural gas in the future.
Keeping Today's Gas Storage Sites Flowing
The gas storage industry spends $60 to $100 million annually to revitalize existing wells. But current methods - such as mechanically removing debris, washing, injecting acids, and creating new perforations in the well pipe - often provide only limited and temporary improvements.
In 2003, the Department selected Penn State University to establish the Gas Storage Technology Consortium (GSTC). The GSTC is an industry-driven organization that assists with the development, demonstration, and commercialization of technologies to improve the integrity, flexibility, reliability, and cost-effectiveness of the nations underground natural gas storage facilities. The primary focus of the consortium is on technologies to improve the management and deliverability of natural gas from existing underground storage facilities. A secondary focus is on man-made and non-traditional methods of storing natural gas.
The Department is sponsoring research to better identify and characterize storage well damage and develop new ways to unclog storage wells. One particular project has developed a device that emits a low-frequency, high-intensity sound wave that literally vibrates the scale off of the storage well pipe. The Sonic Tool removes damage and improves deliverability of gas storage wells. Gas storage wells across the United States are plagued by damage that can significantly reduce the well?s ability to deliver gas. Recent well test analysis and results have clearly shown that the tool removed damage and increased the flow potential of the well by roughly 30 percent. Inorganic precipitates or scale was a leading cause of storage well damage identified in a joint study by DOE and the Gas Research Institute (now known as the Gas Technology Institute), and the tool was developed to address this need.
There are over 14,000 injection and withdrawal wells in the gas storage industry that provide up to 30 percent of the U.S. deliverability during peak times in winter. The Sonic Tool could be used in thousands of wells to restore this lost deliverability. It has an added advantage over some conventional technologies in that the production tubing does not need to be removed, saving $10,000-15,000 to the gas storage operator. The Sonic Tool was used to successfully stimulate a gas storage injection/withdrawal well.
In other projects, the Department is examining how innovative fracturing technologies can be used to rejuvenate a gas storage reservoir. In conventional fields where gas flow is constrained by densely packed rock, producers often inject high pressure water or other fluids to create ribbon-thin cracks in the reservoir rock, allowing gas to flow more freely. A "proppant" (typically sand) is injected with the fluid to keep the newly-formed fractures open. The Energy Department has tested new fracturing techniques, for example replacing the water with liquid carbon dioxide. Water can often cause clays in the formation to stick together, eventually sealing off parts of the reservoir; the use of carbon dioxide avoids this problem.
Investigating New Ways to Store Gas
With the nation's demand for natural gas steadily increasing, the need for better gas storage facilities is growing. Power plants, for example, are using greater quantities of natural gas to meet new clean air standards, and gas storage sites located closer to these plants could enhance the reliability of their fuel supplies and ensure that they can meet peak demands for electricity.
For example, in the northeastern United States, the bedded salt formations are too costly to develop for gas storage primarily because of the expense of disposing of the leached brine (salt cavern storage is created by using fresh water to dissolve cavities in the salt formation which forms large quantities of brine). But the Energy Department's research is showing that by chilling the natural gas and condensing its volume, the size of the storage cavern and the amount of brine that must be handled can be dramatically reduced. This could make salt cavern storage more affordable in an area of the country where gas demand can be especially high.
Another way to expand the geographic diversity of gas storage is to look for other types of geologic formations that might be suitable. In many areas of the country, salt, limestone, or sandstone formations - the type of deposits most suitable for gas storage - aren't available. But it may be possible to create storage sites from hard rock formations such as granite.
In Sweden, a gas storage facility has been built by installing a steel tank in a cavern that has been blasted into the rock of a hill and casting concrete around the cylinder to transfer the pressure to the rock. This concept, called "lined rock caverns," could be applicable in many states in the U.S. Although more expensive than conventional means of storing gas (in depleted oil or gas fields, aquifers or salt formations), the technology allows gas to be withdrawn and injected multiple times during the year which isn't always possible with the other methods. This could make the service cost comparable to conventional storage approaches. Two facilities, a 4 billion cubic foot working gas facility near Atlanta, Georgia, and a 2 billion cubic foot working gas facility near Boston, Massachusetts, have been studied as possible sites for applying line rock cavern technology in the United States.
Chilling the natural gas to reduce its volume might also be advantageous for mined cavern storage. A concept called refrigerated mined caverns being studied incorporates chilling units to increase the gas density and allow more gas to be stored.
The chilling concept is also being taken to the extreme in other DOE-sponsored gas storage studies. One concept would freeze natural gas in the presence of water, creating hydrates. Hydrates are formed in nature in the low temperatures of the Arctic and by the high pressures on the deep ocean floor. Hydrate structures can store enormous quantities of natural gas in relatively small volumes. Theoretically, as much as 181 standard cubic feet of natural gas could be stored in a single cubic foot of hydrate.
Office of Fossil Energy
U.S. Department of Energy
Washington, DC 20585