Natural gas, remote

Other energy sector concerns are methane emissions from unburned fuel, and from natural gas leaks at various stages of natural gas production, transmission and distribution. The curtailment of venting and flaring stranded gas (remotely located natural gas sources that are not economical to produce liquefied natural gas or methanol), and more efficient use of natural gas have significantly reduced atmospheric release. But growth in natural gas production and consumption may reverse this trend. Methane has... 

Because much of the world lacks the natural gas resources and transportation pipelines of the United States, remote natural gas must be liquefied and transported by ship. Gas-rich countries want to capture stranded gas by liquefying and shipping it to gas-poor regions as LNG. The gas-poor countries enter into contracts so that a long-term supply is available to warrant the investment in the electricity-generating infrastructure. The overall investment is enormous, not only in the liquefaction plant, but in the refrigerated tankers and the regasification plant at the deliveiy site. 

Just as oil, natural gas is also categorised as conventional and unconventional. Unlike crude oil, however, natural gas deposits are normally classified according to the economic or technical approach, i.e., all occurrences that are currently extract-able under economic conditions are considered conventional, whereas the rest are termed unconventional. Conventional natural gas includes non-associated gas from gas reservoirs in which there is little or no crude oil, as well as associated gas , which is produced from oil wells the latter can exist separately from oil in the formation (free gas, also known as cap gas, as it lies above the oil), or dissolved in the crude oil (dissolved gas). Unconventional gas is the same substance as conventional natural gas, and only the reservoir characteristics are different and make it usually more difficult to produce. Unconventional gas comprises natural gas from coal (also known as coal-bed methane), tight gas, gas in aquifers and gas hydrates (see Fig. 3.17). It is important to mention in this context so-called stranded gas , a term which is applied to occurrences whose extraction would be technically feasible, but which are located in remote areas that at the moment cannot (yet) be economically developed (see Section 3.4.3.1). 

The monetization of remote natural gas has been a key economic driver for catalysis research over the past 20 years. Significant reserves of natural gas exist in remote locations, distant from available gas pipehnes, which cannot be readily brought to market. The conversion of these resources to higher-valued, transportable products, such as methanol or polyolefins can allow the economical utilization of these stranded assets. Other low-valued natural gas streams, such as associated gas from oil production, could also provide feedstocks to such a technology. The conversion of remote gas, typically valued at US 0.50-1.50 per MMBTU, into polyolefins, valued at more than US 1000/t, via methanol has sparked the development of several MTO technologies. 

In the U.S., the primary methanol production location is in the Gulf Coast area. Methanol is also produced in Canada, South America, Europe, and the Middle East. Methanol production and price is not controlled by any single country or consortium of countries. Any country with remote natural gas reserves is a candidate for methanol production since production of methanol usually represents the most cost-effective means of developing those reserves. 

Another method of making economical use of remote natural gas reserves is to produce methanol from them. Methanol can easily be transported via ocean tanker without losses, unlike LNG. 

Another development in the diesel world is the growing interest in gas-to-liquid, or GTL, processes. Chrysler has worked with Syntroleum, a technology company that has developed a process to convert remote natural gas reserves now stranded from access to energy markets into sulfur free, aromatics free, high cetane diesel fuel that can be transported easily by tanker or pipeline to markets. This fuel has been shown to offer significant emissions decreases and customer satisfaction benefits. However, with crude oil hovering around the 26 to 30 per barrel level, the business case for the use of GTL fuels, like other alternative fuels, is difficult. 

One of the most commercially desirable appHcations for OTMs is the spontaneous partial oxidation of natural gas into synthesis gas. This latter feedstock is of major importance for its subsequent conversion to methanol and to hydrogen. Additionally, synthesis gas can be converted, via Fischer-Tropsch chemistry, into liquid fuels (gas to liquids, GTL) particularly under circumstances where natural gas is located remotely from the place of consumption. Because the resulting hquid fuels possess an intrinsically higher energy density than natural gas, they would be less expensive to transport. One prime example is the Trans-Alaska Pipeline System, which in the future could be used to transport synthetic liquid fuels derived from Alaska s vast reserves of natural gas in the Prudhoe Bay area to the Port of Valdez [36]. This is one of many remote natural gas locations around the world which could take advantage of OTM technology. 

If one is to build a plant based upon renewables or on remote natural gas associated with oil production, one must consider a small (1000-5000 bbl/day) plant. The availability of renewables... 

Transportation of natural gas is sometimes difficult if consumers are far from gas fields. Overland pipelines are economical but are mostly impractical across oceans. Sometimes pipeline transport is also problematic for political reasons, for example, from the Middle East to Europe. Transportation of remote natural gas is then only possible as liquefied natural gas (LNG) or compressed natural gas (CNG), or, alternatively, the gas is converted into valuable (and easy to transport) liquid products such as methanol or diesel oil. 

T/year. Such a spectacular rise in reactor capacity is evidently tied to the growing market demand, but its realization undoubtedly also reflects progress in both technological and fundamental areas, pressed by the booming construction activity of the sixties and early seventies. Saturated markets and the construction of production units in newly industrialized countries have slowed down this capacity increase in the eighties. The present decade saw new spectacular developments. The utilization of remote natural gas and the associated transport problems has provided a new impetus to the development and construction of giant reactors for its conversion near the production sites methanol and ammonia synthesis reactors with a capacity of 1,600,000 T/year are now in use. 

Furthermore, lower selectivity also implies larger heat of reaction and so more difficult reactor temperature control problem. Since both heat removal and supply of O2 can be very capital intensive, high selectivities are much more beneficial than low selectivities. Of course, some of the rejected heat may be recovered as surplus energy, as in steam or electricity, for export. However, the plant would then become a costly combustor. In the case of plants utilizing remote natural gas, export of surplus energy would be impractical. 

Dautzenberg, F.M., Garten, R.L., and Klingman, G. (1986) Fuels from Remote Natural Gas Defining the Research and Development Challenge , paper presented at the 21st State-of-the-Art ACS Symp. on Methanol as a Raw Material for Fuels and Chemicals, June 15-18, at Marco Island, FL. 

Capital and operating costs of synfuel complexes are known to be high and strongly dependent on the location. The total investment of the 12,000 bbl/d Bintulu project amounts to about US 660 million. A large SMDS plant using inexpensive remote natural gas will be economic at crude oil prices of about 20 US /bbl. 

Dautzenberg, F.M. (1989), Evaluation of Methanol as R D Target for the Conversion of Remote Natural Gas, in Preprints of 3B Symposium on Methane Activation, Conversion and Utilization, Pacifichem 89, Honolulu, Hawaii, p. 170. 

In recent years, offshore oil and gas exploration and field development are increasingly focused on the Arctic waters. The U.S. Geological Survey has estimated that as much as 28 percent of all recoverable resources (oil, natural gas and natural gas liquids) yet to be discovered are to be found north of the Arctic Circle (Kayrbekova et al., 2011, Bird, 2008). At the same time, the Arctic also has the harshest environmental condition for offshore activities, for instance, the remoteness, the extreme cold, dangerous sea ice, and a fragile environment. There have been some examples of moored offshore installations in ice. However, there is very little operational experience regarding DP operations in ice. 

Natural gas upgra ding economics may be affected by additional factors. The increasing use of compressed natural gas (CNG) directiy as fuel in vehicles provides an alternative market which affects both gas price and value (see Gasoline and other motor fuels Gas, natural). The hostility of the remote site environment where the natural gas is located may contribute to additional costs, eg, offshore sites require platforms and submarine pipelines. 

Absorber oil units offer the advantage that Hquids can be removed at the expense of only a small (34—69 kPa (4.9—10.0 psi)) pressure loss in the absorption column. If the feed gas is available at pipeline pressure, then Httle if any recompression is required to introduce the processed natural gas into the transmission system. However, the absorption and subsequent absorber-oil regeneration process tends to be complex, favoring the simpler, more efficient expander plants. Separations using soHd desiccants are energy-intensive because of the bed regeneration requirements. This process option is generally considered only in special situations such as hydrocarbon dew point control in remote locations. 

Although there are no new methane VPO competitive processes, current technology may be usehil for the production of impure methanol in remote areas for use as a hydrate inhibitor in natural gas pipelines (119,120). 

San Diego Gas Electric s system was originally installed as a research project. The intent of the research project was to test the hardware in this application, test the feasibility of operating such a system remotely with no local operators, and to prove the economics. Similar systems had been installed within process plants where operators were present to start and stop the system and monitor its operation. However, this was the first system installed on a natural gas transmission system with completely remote operation. 

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