Before we get to the topic of discussion, let's quickly look at the background of our energy demand and thus the drivers of natural gas consumption. The vast majority of new electric generation capacity has been gas-fired. In excess of 90,000 megawatts of new gas-fired power generation has come online in the last few years. Although still behind coal-fired power generation, gas-fired generation is quickly increasing its proportion of the total U.S. capacity. Further, gas continues to be the significant energy supply choice for American homes and industry.
The big question mark, especially in the lower 48 states, is supply. Energy Secretary Spencer Abraham has reported that new discoveries of natural gas in the United States have fallen for three straight years. The Mid-Continent Oil & Gas Association of Oklahoma has noted that significant long-term supplies of natural gas lie in or near the continental U.S., including off the East Coast (31 trillion cubic feet, or TCF) and West Coast (21 TCF), in the eastern Gulf of Mexico (43 TCF), in the Rocky Mountain basins (137 billion cubic feet, or BCF) and in the north slope of Alaska. However, many of these areas suffer with sociopolitical overtones that currently prohibit production, or at least make it extremely difficult. Indeed, an estimated 40 percent of potential gas resources in the United States are on federal lands that are either closed to exploration or covered by severe restrictions. A portion of the supply shortfall will come from Canada. However, Canada faces a depletion of reserves and the issue of indigenous needs; while Mexico, once expected to export gas, is currently a net importer of gas from the United States. Finally, add to this mix of data the estimate by Secretary Abraham of an additional 38,000 miles of transmission pipeline and 255,000 miles of distribution lines, at an estimated cost of $120-$150 billion, which would be needed to move gas to market from the drilling of new gas wells. Currently, our Alaskan gas fields produce about 8 billion cubic feet of natural gas a day, but it is put back into the ground, waiting until a pipeline is built to connect the Alaska fields to the U.S./Canada distribution system. The current Congressional activity indicates that some sort of Alaskan gas pipeline will be developed, but many question whether even that significant supply will be enough to meet gas demand in the years ahead. With a price tag in the tens of billions of dollars, it will make any company or consortium think twice.
A Potential Shortage
There are few who disagree that we will be looking at a gas shortage situation and high prices for the foreseeable future. If you have spent any time in the innumerable conferences, seminars and roundtables discussing electric power and natural gas that have been occurring in the U.S. over the past two years, you will have heard that liquefied natural gas is making a comeback to the market as a major part of the solution to this dilemma.
With the accompanying "situations" in the market in the last 18 months -- the retrenching of the energy trading market and corporate accounting scandals, the unfortunate combination of cold weather and production declines, the unrest in parts of the energy-rich world, and the energy crises that occurred recently -- LNG is on the tongues of most energy suppliers and consumers in the U.S. as a potential savior of the domestic gas market. LNG provides the mechanism to import natural gas from most anywhere in the world.
To briefly describe the techno-business aspects of LNG, allow me to summarize the LNG value chain. Liquefied natural gas is exactly what is says, natural gas that, through a process that brings its temperature down to minus 260 degrees Fahrenheit, has been cooled into a liquid state. At this point the volume has decreased by a factor of about 600 times, and being liquid is now transportable over long distances economically. Long distances in this case are generally considered more than 3,000 miles and over water.
Everyone in the energy industry has been hearing about "stranded" or "remote" gas or oil now for years. Obviously, over the entire life of the current energy industry, we have always tried to find the least costly (read: nearest) source of energy, and those sources are dwindling. Gas fields in remote parts of the world that are difficult to access are being considered as sources for gas import into the U.S. market. Many of these are offshore, while others are onshore, but in inhospitable or virtually uninhabited and distant areas in many countries.
Putting these last two points together, we see that the gas the U.S. will require is quite distant from our market, is in the wrong form to transport economically, and needs a physical entry into the market. As an example, natural gas in the substructure of the waters of Southeast Asia can be gathered and sent to a locally built and operated liquefaction plant to make LNG. Put the LNG on an ocean-going carrier, and import it to a U.S.-based "revaporization" facility, an import terminal that reconverts the liquid natural gas back into its original vapor form and puts it into an existing pipeline system to reach the ultimate consumer. Problem solved -- maybe!
I briefly described above the chain of getting remote gas to the U.S. market. This mechanism applies to natural gas in Africa, the Middle East, Southeast Asia and other areas. The fact that there are more than 50 new LNG ocean tankers under construction, in addition to the 191 currently operating, supports the premise that many believe that LNG is the answer. But there are two more capital-intensive pieces to the LNG chain: the export or liquefaction terminal at the origin site of the gas, and the revaporization or import terminals at the destination. The onshore export terminal capital costs are roughly in the $180 to $225/metric ton per annum (mtpa) range and since the facilities which are now routinely being contemplated are typically between 4 and 6 million tpa, these are multibillion-dollar plants in remote areas. On the other end of the chain are the import terminals, used to unload the LNG from the tankers and revaporize it and put it into the pipelines. These are less capital intensive than the export terminals, ranging from $0.30 to $0.45/million standard cubic feet (mmscfd) vaporized. The newest terminals being considered in the North American markets are typically around 1 to 2 billion scfd vaporization rates, therefore rough costs are in the $300 to $500 million range. Depending on load/unload rates and capacity of the carriers, location, and frequency of transit, the marine facilities for either of the onshore terminals could cost upwards of $200 million.
LNG's Outstanding Safety Record
Before we go any further, we must not forget safety, so let's try to put the risks associated with handling and moving LNG into perspective. In comparison with other related light hydrocarbon fuels such as liquefied petroleum gas, natural gas liquids, propane, etc, LNG is less of a hazard for explosion, fires and subsequent damage. Of course, in the gaseous state and in sufficient atmospheric concentrations, it will ignite. However, over the many years of operations, the processing systems have been designed and continuously improved to make these facilities and tankers very safe. Both the nature of the beast and the caliber of professionalism in the gas industry have contributed to the fact that the LNG industry has one of best safety records, if not the best, of any petrochemical industry. As published at a recent major energy conference, there have been more than 38,000 transits of LNG carriers in the history of the industry, without one major incident. Certainly, we should not grow complacent with this enviable record, and we should strive to continue to improve the equipment, instrumentation and procedures to maintain this achievement as the LNG market grows.
Location, Location, Location
Now, lets start putting the pieces of this puzzle together and look at the viability of onshore and offshore facilities. We need to consider costs, safety and security, difficulty of construction, politics, regulations, and then all the client-specific nuances in this process, which we will ignore at this time. Onshore import facilities are generally straightforward. A large plot is needed near the shore for access to the LNG carriers. This is true for both export and import terminals, but let's focus on import terminals in the U.S. locale. LNG tanks, although available for construction in most any size and containment strategy (single, double or full), are beginning to standardize around the 160,000 cubic meter size for these new facilities with potential sizes in excess of 200,000 cubic meters. These structures require a large area, as one, two or three tanks, each approximately 300 feet across, require significant space, especially when considering vapor dispersion intrusion upon neighboring property.
The very cold and very expensive LNG piping onshore can often run into the thousands of feet to route between the carriers, the tanks and the processing equipment. As mentioned earlier, the marine facilities, including dredging, breakwaters and jetties, can quickly account for perhaps hundreds of millions of dollars of the total cost of a facility, depending upon location.
Moving from cost, consider regulatory issues and permitting. Keep in mind that regulations are made for the good of the population, with safety at the forefront. Most people are ultimately willing to accept new chemical facilities in their "neighborhoods," given that they are designed and constructed to be safe and provide value (jobs, etc.), but the process is nonetheless difficult. There are local, state, federal and marine regulatory agencies that all must have input and be satisfied. Political and public opinion also weigh in very heavily for any new facilities, including LNG terminals. Evidence to that are the acronyms these facilities have helped spawn. NIMBY (not in my backyard), NIMTO (not in my term of office), BANANA (build absolutely nothing anywhere near anything) and others help put into perspective the difficulties in locating new facilities within eyesight of even a small populated area. All of these barriers are conquerable, and have been met for some of the most recently announced onshore facilities, but not without diligence.
Now let's consider an offshore structure for the import of LNG. Regulations, granted still for safety's sake, are now mostly governed by the U.S. Coast Guard, with lesser impact from the Federal Energy Regulatory Commission and other local authorities. There certainly isn't a figurative backyard or a population for which to politic for votes, nor really anything to be seen or affected except for some sea creatures. There is quite probably no dredging or similar related marine costs independent of the structure itself, therefore the structure cost, platform, vessel or gravity-based structure (GBS) are partially offset by reduction of the land-based costs. In some cases, they are mobile and can be positioned at most any coastal area around the nation. Finally, security and public safety can also be improved over some onshore sites. Living in Houston near the second-largest chemical infrastructure system in the world, I have become more aware that we live in unsettled times, as the protection of the Houston Ship Channel from external attack has become both a local and federal concern. Offshore-based facilities offer an improvement in security in the sense that they are or can be isolated from any population.
So, if offshore facilities were to be considered, what form might they take? Over the past few years, many companies have been looking at this and have come up with some very technically sound possibilities. First, consider the oil industry's well proven Floating Production, Storage and Offloading vessels (FPSO) as a starting point. Adapting a vessel to handle LNG revaporization, commonly called a Floating Storage and Revaporization Unit (FSRU), working in tandem with an LNG carrier, is viable. Also viable is utilizing existing, unused offshore platforms for the processing equipment and a floating storage facility. Granted, both of these must have access to a gas pipeline, which may exist in some situations or may need to be built to transport the gas from its revaporization point into a shore-based pipeline system. Another option is a gravity-based structure, or GBS.
Also found in the oil industry, a GBS could be designed to store the LNG in the structure itself with the revaporization equipment on top. Such a unit could be concrete or steel, and would probably be rectangular in shape, measuring about 1,000 feet to accommodate adequate storage capacity. Tankers could berth next to the structure, unload into the internal tanks and depart, eliminating the demurrage costs of the two previous examples. A GBS could be built in dock and towed to a location, typically just offshore of gas pipeline access and anchored into the seabed. Costs for such a facility could be competitive with land-based units, when considering the large amounts of land, piping and marine work that may be required.
Taking this same approach to an export terminal is also viable; obviously this facility is more complex and, being larger, requires more processing equipment. But the technical innovations and selection of appropriate technologies can help to minimize the amount of equipment to make an offshore export terminal an economical possibility.
These offshore operations are gaining more consideration every passing day. There are obviously many other criteria to be considered, but the drivers for the gas demand will force solutions to be found. Can offshore facilities provide enough capacity in the coming years to meet the demand? Certainly the technology exists, and the economics appear competitive, so the answer really lies in the speed in which LNG supply can be built and obtained from overseas and the corresponding import terminals can be built to meet the high demand expected in the coming years. I firmly believe that if you challenge the industry to meet the demand, we will find a way.
Dwane R. Stone is president of Black & Veatch Pritchard, Inc., the Gas, Oil & Chemicals division of Black & Veatch, and has been in the engineering and construction industry for 27 years. He is a chemical engineering graduate of the Georgia Institute of Technology, and has also earned an M.B.A. in finance. Having started in engineering during the expansive period of the mid-1970s, Mr. Stone worked in various fields including synthetic fuels (including coal gasification, coal liquefaction and oil shale retorting), natural gas and oil processing, chemicals, polymers and gas conversion (including fuels, polymers and olefins production). He has participated in technology development and has been involved with acquisitions and mergers of technology companies. Mr. Stone has also held positions in engineering and project management, and has been vice president of numerous units including Polymers, Chemicals, Plant Services, Business Development and Technology, leading to his current position at Black & Veatch.
Most Popular Articles