By Curt Champeon
Natural Gas is the world’s fastest-growing type of energy. Its use, according to many sources such as the Wall Street Journal, is predicted to at least double between 2000 and 2020. Many factors contribute to this surge in demand. First of all, population growth is a factor – more people equal the need for more energy. Oil, although still plentiful, is getting harder to recover. With environmental concerns rising all over the world, clean-burning natural gas is seen in a more positive light than coal, oil, or nuclear power. Many countries that previously had little or no modern infrastructure are now developing it. All of these factors add up to a vastly increased demand for natural gas, and the unfortunate possibility of an equivalent price rise. Current natural gas reserves for the entire planet are estimated at 6,100 trillion cubic feet (tcf), according to EIA estimates. Of these reserves, at least half are considered stranded.
Stranded Gas – What is it?
A reserve of stranded gas is a pocket of natural gas that has been discovered but cannot be retrieved. This can be for reasons of accessibility or simple economics. This should not be confused with natural gas that is found in an oil well. This type of natural gas is referred to as “associated gas.”
The first kind of stranded gas is “physically stranded” gas. This could be a field that is located too deep in the earth to drill for, beneath the ocean or ice cap, beneath an obstruction, or is under a populated area. Economic considerations can also cause gas to be considered stranded. The economics of recovering gas might leave it stranded. A field may be too far away from a market. In this case, a pipeline could be too expensive to construct in order to move the gas. Another reason is that the gas might be in an area where supply is saturated, making the cost of moving the gas far enough away to sell too high, although it might be possible to sell it at a later date.
Stranded Gas – Where is it?
There are many places on Earth that have large reserves of stranded gas. The largest is in Russia. It has the largest gas reserves in the world, however its great size works against it because much of its land mass is located far away from any major population center, (i.e. market). Siberia, where most of this gas is located is a prime example of this. One way to exploit this gas would be to send it by pipeline across the Bering Strait to Alaska’s gas delivery system. It could also be shipped to China or to Europe. Changing diplomatic relationships with all of its neighbors make it difficult to make a commitment to any one of these options.
Alaska has a large reserve of stranded gas near its Prudhoe Bay Oil Field. It also has a large amount on its North Slope. To market the gas it needs to await completion of its Alaska Gas Pipeline to carry it to the American states located to the south of Canada. This project has been delayed due to the availability of cheap Canadian gas, environmental concerns, and the development of non-conventional gas in the United States.
Canada has a large amount of stranded gas in its Arctic Islands, Beaufort Sea, and MacKenzie Delta regions. To sell the gas would require the building of a pipeline to bring it south along the MacKenzie River. Some corporations would like to combine it with Alaska gas by creating an offshore pipeline in the Arctic Ocean. The Alaska government is resisting this because it would like to first bring the gas to the southern part of the state and then transport it across the Yukon.
Other locations worldwide that have proven reserves of stranded gas are northern Australia, Vietnam, and Indonesia.
The traditional ways of getting natural gas to market are pipelines, liquefied natural gas (LNG), and onshore gas-to-liquids (GTL). These are all very capital-intensive and are only used with projects that contain very large reserves. If the size of the field is small (production volume of less than 3 million tons per year), or if the market is more than 1,000 miles away, these methods begin to lose their cost-effectiveness. There are a number of new alternative methods to harvest smaller fields. None of these have been proven on a commercial scale, however they have been shown to be technically feasible, as stated by the U.S. Energy Information Administration.
New Technology to the Rescue
Advances can be divided into two main areas – finding new deposits of oil and gas that were previously unknown, and harvesting oil and gas from more difficult locations in more effective economic ways.
Concerning the former – technology advancements for harvesting oil from more difficult locations – one application is Compressed Natural Gas (CNG). Transport of CNG by truck is well established. The reason is simple: transporting natural gas in its natural gaseous form – not by pipeline – is not economically feasible, so it needs to be compressed before it can be shipped. There have been significant developments to increase the volume of CNG transported by ships over long distances.
Maritime applications of CNG are very useful when gas reserves are small and located far from infrastructure, making pipeline or LNG terminal development an unfeasible economic decision. With CNG, gas can be offloaded through an offshore mooring buoy, avoiding the need for expensive land-based liquefaction facilities.
Transportation costs for CNG, exclusive of field development costs are in the range of $1.00 to $2.50/MMbtu, depending on the volume of reserves, distance from market, and environmental considerations. Capital costs for a CNG delivery chain range from $500 million to $1.5 billion, 90% of which is vessel construction. The other costs are compressing, loading, and unloading facilities. This is favorable in comparison with LNG and GTL, as is the time frame for the construction for CNG. CNG, however, cannot be transported in large volumes. LNG vessels are able to transport more than three times the gas as the largest envisioned CNG vessel, according to ALS Environmental.
CNG can deliver gas more cheaply than LNG for distances of up to 2,500 nautical miles. Another advantage is that with CNG, the bulk of the investment is in movable assets, while with LNG, a large part of the investment is in fixed assets. In terms of monetary risk, CNG is a better bet than LNG. Statoil, Transcanada, and Exxon/Mobil are at the forefront of support for this technology.
New technologies are also being developed for floating LNG (FLNG). This is a combination of LNG processing and storage technology with deepwater offshore production. Ships with an LNG facilitator can be sent to harvest one field after another without having to build a facility for each. Because of the remoteness of location, property and human loss would be minimized in case of an accident. Royal Dutch Shell has been at the head of a number of companies pioneering this method.
FLNG can be divided into two main areas. First, there are LNG FSRUs (Floating Storage and Re-Gasification Units) and LNG FPSOs (Liquefied Natural Gas Floating Production Storage and Offloading Vessels).
Floating Re-Gasification Vessels have been operational since 2005. They allow for flexible transportation of LNG. Excelerate Energy, Golar LNG, and Hoegh LNG are the current global leaders in the field, although several other corporations are considering entering this market. There are currently fifteen units operating globally. These vessels will be very useful in countries with major shortfalls of gas, such as Egypt, India, and Pakistan.
There are offshore production facilities that contain both processing equipment and storage for the produced hydrocarbons. The design of these ships includes what are called “topsides,” which are located on the deck and used to process the oil or gas. The processed material is then stored in a double-walled system below decks. The hydrocarbons are then offloaded to special “shuttles” which are small tankers or introduced into the pipeline systems, according to Offshore Engineer.
While kept in place by different mooring systems, the FPSO is adept at deep and ultra-deep water harvesting. Spread-mooring systems anchor the vessel to several locations on the sea floor, while a central mooring system allows it to move with the tides on the surface. These mooring systems are able to disconnect quickly, which makes them ideal for areas that tend to experience severe weather, such as hurricanes and typhoons.
A series of in-field pipelines allows the FPSO to gather oil and gas from multiple wells. It is then transmitted to risers through flowlines. The risers then take the oil and gas from the seafloor to the ship’s turret and then to the FPSO on the surface.
On a FPSO, the processing equipment is very much like that found on a production platform, except that it is constructed in modules. Among others it can have water separation, gas treatment, oil processing, water injection, and gas compression. Gas may be either transferred to shore via pipeline or re-injected into a field to boost production.
FPSOs have a number of advantages that make them a good bet for future development. They can be un-moored in case of bad weather. They can be re-deployed once a marginal field is depleted. They are good for areas where there already is an existing pipeline infrastructure. Existing tankers can be converted into FPSOs. Lastly, their design makes them very safe.
There are also a number of floating systems that are similar, due to the fact that these inexpensive units can be tailored to any company’s situation or need. There are FSOs (Floating Storage and Offloading), FPSs (Floating Production Systems), FSUs (Floating Storage Units), and a FDPSO (Floating Drilling Production Storage and Offloading).
As of 2014, there are no actual FLNG plants in operation, however, this is about to change. Exmar and Pacific Rubiales have a vessel that will commence operations off the northern coast of Columbia in late 2015. Petronas’ first vessel will also become activated in late 2015 off the coast of Malaysia. Even though it will not be operational until 2017, the project that is getting the most attention is Shell’s Prelude. This plant will initially begin to harvest gas off the western coast of Australia.
These three projects are interesting for the different capabilities that can be used in this method. The Shell vessel is the largest, producing over 3 million tonnes per annum (mmtpa). Petronas has built a medium-sized vessel, producing 1-2 mmtpa, whereas the Exmar/Pacific Rubiales vessel is small, with an estimated 0.5 mmpta.
GTL-FPSO (Gas-to-Liquid/ Floating Production Storage and Offloading) is the same basic concept as Floating LNG. GTL is based on the Fischer-Tropsch (FT) process, which was developed in the 1920’s. It did not obtain commercial success or financial backing until the recent interest in diverse energy options. Syntroleum Corp., which was involved in the development of GTL technology in partnership with Bluewater Energy Services. BU recently completed a feasibility study of a FPSO with GTL capabilities. The vessel will have a daily production capacity of 17,000 barrels of FT products, 40,000 barrels of oil and 10,000 barrels of distillates and will have a storage capacity of 2.3 million barrels. The estimates for the construction of such a project vessel are a cost of 1.3 billion and 5 years to build, as estimated by the Journal of Petroleum Technology.
Natural Gas Hydrates (NGH) is natural gas in a solid, crystallized form. If the ability to solidify natural gas is developed and introduced on a large scale, it would create a substantial savings in the transport of natural gas over liquefied or compressed gas. A number of companies, including Mitsui, Mitsubishi, the BG Group, and Marathon Oil, among others, have been developing gas-to-solids technology for both production and shipping natural gas hydrates. NGHs are stable at 20 degrees below Celsius compared with 162 degrees below Celsius for LNG, which reduces the transportation and storage costs. One cubic meter of NGH contains roughly 160 cubic meters of natural gas, while one cubic meter of LNG contains 600 cubic meters of natural gas, limiting the amount of gas that can be transported with NGH technology, as reported in the MIT Technology Review.
Natural Gas production and technology is growing and will continue to grow. Many different technologies are being developed to obtain this product. A number of different factors have to be taken into account in this process such as population centers and their shifting demand for different kinds of power, location of the gas and obstacles in its extraction, size of the gas find as well as the continual advance of technology as this process continues. The benefits of these advances are not only for the nations with stranded gas finds, but countries with a need to purchase. It is something all energy corporations need to keep their eyes open for in order to take advantage of the numerous possibilities.
Ice Gas; The New Elephant in the Room
Ice Gas is another word for Methane Hydrate, a supply of natural gas located in a combination of sediment and ice. Although scientists have known about hydrates in general for the past 200 years, it has only been recently that naturally occurring natural gas hydrates has come to the forefront of energy industry study.
Methane Hydrates are ice-like structures with natural gas molecules in them. They are the remains of plankton that sank to the ocean floor and became part of the sediment there. They can be found on land and in the ocean, including Arctic permafrost and ocean sediment. The sea floor is the ideal place for their formation, due to the low temperature and high pressure. The methane is formed deep in the sediment where the temperature is slightly higher and then rises to the higher levels nearer the sediment surface. These hydrates appear as white ice, however when they are melted or exposed to pressure and temperature conditions outside, those where methane hydrates are stable, its solid crystalline structure turns to water and the enclosed methane molecules are released as a gas, according to World Ocean Review.
In 2012, the U.S. Department of Energy and its Japanese counterparts announced a successful field trial of methane hydrate production technologies on Alaska’s North Slope. Due to this success, the DOE is testing additional technologies that could lead to large-scale harvesting in the Gulf of Mexico. In March of this year, Japan Oil, Gas, and Metals National Corporation (JOGMEC) extracted natural gas from methane hydrates deposits from 1000 ft. under the seabed in the waters off Japan’s coast.
Although a very under-reported technology, this is something that could not just change natural gas as an industry, but change how we think of energy as a whole. As the industry stands now, stranded gas makes up 55-60% of market reserves. Ice gas changes this to at least 95%. The locations are also different – from the North Pole to Antarctica and all points in between, this product can be harvested many places. With technology advancing at breakneck speed, this product can only increase its market share and the only real question is how fast this will happen.