The use of hydrogen as a sustainable alternative fuel and energy carrier is gaining more acceptance as the environmental impact of hydrocarbons becomes more significant. Hydrogen can be produced from various energy sources, such as steam reforming of naturalgas, coal gasification, water electrolysis and thermo-chemical water splitting. Hydrogen production is accomplished by steam reforming of naturalgas and other fossil primary energy at approximately 97% of total and less than 3% is based on renewable energy sources, such as solar, wind, biomass, geothermal, etc. Today, steam reforming of naturalgas is the most important and economic ways of the hydrogen production. The environmental performance of products or processes has become a key issue, which is why ways to minimize the effects on the environment are investigated. One of the effective ways for this purpose is life cycle assessment (LCA). In this paper, LCA of hydrogen production by naturalgasreforming (NGR) process are investigated for environmental affect. The investigation uses LCA, which is an analytical tool to identify and quantify environmentally critical phases during the life cycle of a system or a product and/or to evaluate and decrease the overall environmental impact of the system or product.
generation in HRSG, it is split into two streams (streams 14 and 17), recycling stream 14 back to the compressor after cooling it (14–15) by preheating the Rankine cycle working ﬂuid in HEX4 (23–24). Stream 17 is expanded further for power generation in LPT to a fairly low-pressure level (0.08 bar in this study), and the water contained is condensed and partly recycled as the Rankine cycle working ﬂuid (21). Despite the overall high system pressure ratio, the pressure ratios of the gas turbines HPT and LPT are only 15 and 12.5, respectively, the same as those in standard air-based ones. The conﬁguration of the power generation section is basically similar to the S-Graz cycle . The arrangement of the higher pressure (higher heat capacity) but lower mass ﬂow rate ﬂuid on the Rankine cycle side of the heat recovery section, with the lower pressure (lower heat capacity) but higher mass ﬂow rate ﬂuid on the Brayton cycle side is intended for reduction of heat transfer irreversibilities in the heat exchangers.
trial process for naturalgasreforming and for hydrogen and methanol production [9–11] and 80%–85% of the global hydrogen production is done through this process . SRM is an endothermic reaction, which requires steam as oxidizing agent and produces a syngas with a H 2 /CO ratio of 3 (eqn 1). This process is performed in multiple steps. In the ﬁrst step, methane reacts with steam in two different reformers at temperatures between 800°C and 1000°C and at pressures around 15–30 atm. Despite being favored at low pressures, H 2 plants require the product at high pressures . Catalysts employed in this step are mostly nickel-based cata- lysts. Then, the H 2 /CO of the syngas produced in the ﬁrst step is increased via water-gas shift reaction (WGS) (eqn 2) in two other reformers using an iron and copper-based catalysts. The products of the WGS reaction are then separated and puriﬁed. Under stoichiometric conditions (1 mol of water per mol of methane), carbon deposition is thermodynamically favored. So, steam is usually fed in excess with H 2 O/CH 4 around 2.5–3. However, it has an impact on the overall cost of the process since steam generation requires signiﬁcant amounts of energy .
at Bilbao is the first and still the largest integrated gas and power complex in Europe. Its development was made possible thanks to the extensive cooperation between three Spanish companies - EVE, Iberdrola and Repsol – and BP, the only foreign partner. BP and partners in Atlantic LNG in Trinidad provided the LNG supply contract, while BP and the Spanish partner group contributed global and local expertise in LNG regas and power generation plant construction and operation. All shared a commitment to the highest standards of safety and environmental protection.
America is in the midst of an energy revolution. As of 2012, unconventional oil and naturalgas development supported 2.1 million jobs, and it is projected to support 3.9 million jobs by 2025. In 2012, according to EIA, we surpassed Russia as the world’s energy superpower – producing more oil and naturalgas than any other country. At the same time, we’ve reduced U.S. carbon dioxide emissions to near 20-year lows thanks, in part, to the carbon advantages of naturalgas. But, for American workers, the best is yet to come. The export of liquefied naturalgas – or LNG – represents one of the most promising economic opportunities of the shale revolution. These exports will significantly reduce our trade deficit, increase government revenues, grow the economy, and support millions of U.S. jobs in engineering, manufacturing, construction, and facility operations. America is in a global race to build this infrastructure and secure a competitive position in the international market. More than 60 international LNG export projects are currently planned or under construction around the world, and those nations that act quickly to attract these investments will reap the economic rewards.
We are also focused on adapting our existing assets to the changing gas flow dynamics.
The Canadian Mainline has traditionally sourced its naturalgas primarily from the WCSB and delivered it to eastern markets. New supply located closer to the eastern markets has reduced demand for gas from the WCSB that, in turn, has reduced revenues from long haul transportation. As a result, overall tolls on the Mainline have increased and caused a reduction in the Canadian Mainline’s competitive position. We are looking for opportunities to increase its market share in Canadian domestic markets, however, we expect to continue to face competition for both the eastern Canada and U.S. northeast markets. Our current application with the NEB seeks to restructure tolls on the Canadian Mainline to correspond with pipeline flow and usage patterns resulting from new supply and demand dynamics. The hearing on our application concluded in December 2012 and a decision is expected in late first quarter or early second quarter of 2013.
• SMR compressors are products of the oil and gas process- ing industry, where hydrocarbon leakage is considered a hazard and must be minimized. Dry gas seals (DGSs) are the standard design, offering minimal leakage rates (only 1% to 10% of the leakage rate of wet gas seals). They are mostly independent from the compressor throughput. However, dry gas seals feature significantly higher com- plexity and come at a much higher cost (approximately $250 thousand USD), which is why DGSs are not com- monly used for N 2 compressors.
By proper choice of the operating conditions, surface temperatures are locally much higher than those pre- dicted by thermodynamic equilibrium calculations assuming adiabatic reactors. The occurrence of the reactions in these local environments determines in some cases conversion and selectivity values higher than those pre- dicted by the thermodynamic equilibrium at the reactor exit temperatures . Moreover, the very high surface temperatures inhibit catalyst deactivation phenomena related to chemical poison effects  . For these and other related reasons, this chemical process is carried out in very small reactors having a very high flexibility towards reactant flow variations. It has also been found that several hydrocarbon feed stocks, even containing sulfur and aromatic compounds can be fed to a SCT-CPO reactor for producing synthesis gas. Now a long term R&D effort is approaching the industrialization phase of a technology whose main advantages concern are:
The SD NaturalGas Fund™ is the result of collaboration between Sustainable Development Technology Canada (SDTC) and the Canadian Gas Association (CGA), through its venture “Energy Technology Innovation Canada” (ETIC), that will see $15 million provided by the CGA and matched by SDTC, creating a fund valued at $30 million over 3 years. The Fund will be managed by SDTC and will support the development and demonstration of new downstream naturalgas technologies. The SD NaturalGas Fund™ will invest in technology areas outlined in the Business Case and technologies that are attractive to the international export market. SDTC will accept applications to the Fund twice per year. Successful applicants will be invited to submit a detailed proposal that will be subjected to SDTC’s rigorous due diligence process, with a final funding decision made by SDTC’s Board of Directors. The Fund will support, on average, 33% of overall project costs, subject to the successful completion of project milestones.
A modified sealing concept of the injector that is used to enlarge the heat dissipating surface can be added by changing the recess depth. Consequences in terms of unwanted seconda- ry effects such as carbonization during gasoline operation must be observed here. Furthermore, the use of cooled integrated exhaust manifolds is an effective solution that is implemented in series production to reduce the thermal load of the components carrying exhaust. Figure 3 shows the wall temperatures at nominal perfor- mances within the in the non-critical range. For significantly higher power densities, additional measures are recommended that take effect as early as during combustion. Cooled exhaust gas recirculation should be considered as a corre- sponding measure. However, this complex sys- tem will probably only be used in applications if at least the powerful gasoline variants from the corresponding engine family are also equipped with this system.
Garbage trucks are popular vehicles to drive on naturalgas. They are high polluting, fuel consuming and noisy vehicles that are centrally fuelled. Naturalgas octane rating results in a much quieter sound from the diesel engine. As many garbage trucks begin early in the morn- ing, noise pollution is an important factor. The weight of storage cylinders on board the vehicle typically reduces the vehicle’s carriage weight by about 17%, which is a cause of concern for the waste management industry. Experience has shown that the selection of suitable vehicles with regard to load and axle width is diﬃcult. Therefore, most of the naturalgas garbage trucks are specially manufactured vehicles which leads to maintenance and repair problems. For exam- ple, the London Borough of Sutton has repair problems with frequent breakdowns coupled with unsatisfactory service support. Improved heavy duty vehicles are currently under development and the respective cities are awaiting results. Some garbage trucks run on biogas made from waste materials (human, agricultural, etc.). This oﬀers an opportunity to have an ‘environ- mentally closed loop’ garbage truck whereby the ‘fuel’ (waste material) is processed into naturalgas or biogas which, in turn, fuels the truck.
Whether you are a Consultant, EPC contractor, End user or looking for reliable NaturalGas solutions varying from high pressure production and transmission segments to lower pressure distribution, industrial and commercial segments, Emerson’s innovative customized skid solutions promise to improve your performance and your bottom line. By customizing your pressure-reducing and metering stations, you will reduce overall cost of ownership.
In addition to the Marcellus and Utica Shales, there are vast shale resources throughout the United States. Some, like the Barnett Shale near Fort Worth, Texas, and the Haynesville Shale in Louisiana, have been in production for the last few years. Others remain largely untapped with their potential unknown. One map of U.S. shale plays shows 29 named shale plays in 20 states. Some of these shale plays, such as the Bakken Shale (Williston Basin) in North Dakota, hold large quantities of both oil and naturalgas. While it will be many years before the full extent of U.S. gas shale resources is known, our experience to date indicates that we have tended to significantly underestimate the size of this energy resource. Naturalgas from shale is still considered an “unconventional” resource. An even less conventional energy source might be found in clathrate gas hydrates, solid formations of naturalgas trapped in crystallized ice found hundreds of feet beneath seabeds and Arctic tundra. Significant clusters of methane hydrates have been found off the coast of Alaska and in the Gulf of Mexico, as shown in the map above. 10 Methane
This unit sees that the naturalgas from the flare point is pre-treated to remove impurities or reduce them to acceptable levels for the actual GTL process. The actual GTL plant operations begin from the synthesis gas unit. For this work, the choice of pre-treatment varies for each case considered. Because of the different principles involved in the reforming of the two cases considered, their pre-treatment also differs. This difference affects the choice of their technologies and process applications. For optimal treating-complex design, process selection for the individual units must be made on the basis of an integrated approach that consider interactions
As for the history of energy demand projection in Turkey; although some efforts for the application of mathematical modeling to simulate the Turkish energy system were made during the late 1970s, the official use of such methods in energy planning and national policy making by the Ministry of Energy and Natural Resources (MENR) was realized only after 1984. The forecasts made before 1984 were simply based on various best fit curves developed by the State Planning Organization (SPO) and MENR. The year 1984 has been a milestone for energy planning and estimation of future energy demands in Turkey since, in that year, the World Bank recommended MENR use the simulation model MAED 7 (Model for Analysis of Energy Demand), which was originally developed by the IAEA (International Atomic Energy Agency) for determination of the general energy demand. Besides, the energy demand model called “EFOM-12 C Mark I” developed by the Commission of the European Communities in 1984 was applied to Turkey. Furthermore, Kouris' correlation models were also applied for forecasting the primary and secondary energy demands in Turkey. Moreover, the BALANCE and IMPACT models were used in the context of ENPEP (Energy and Power Evaluation Program) for the long term supply and demand projections. Finally, State Institute of Statistics (SIS) and SPO have developed some mathematical models .
We use a computable general equilibrium model to examine conditions under which GTL technology penetration shifts the future crude oil-naturalgas price ratio. Our results suggest that GTL penetration has an impact only under very extreme assumptions. Using conventional estimates of costs and efficiencies, the GTL technology is too expensive to enhance direct competition between the crude oil products and naturalgas as fuels in the transportation sector, which is the critical sector for crude oil use and pricing. In addition to needing GTL to be less costly and more efficient in order to have an impact, it is also necessary for naturalgas to be still cheaper to produce than the current shale revolution in the U.S. has realized. Our model results do not factor in any increasingly stringent global carbon limits, which would decrease further the prospects for GTL.
Riding the short-lived need for naturalgas import facilities on the U.S. OCS, several deepwater ports were licensed and built under the requirements of the DWPA. Several more have been approved but not yet been built, and several more are in development or are active applications. Coupled with numerous on-shore coastal LNG terminals, the United States rapidly developed a glut of LNG capacity, several times the capacity needed, to handle existing import demand. Once domestic naturalgas production began to rise, these ports became less profitable and less utilized, and ports sat idle. One deepwater port has already initiated the decommissioning process, yet three more promise to start construction within the next few years. Given the overcapacity of the U.S. market and the past year’s market shift to LNG exports and re- exports, the future of deepwater ports is clouded. Whether licensing agencies will continue to find that LNG import facilities are in the national interest when the facilities will either sit idle or be used to send domestically produced gas overseas is a question that remains unanswered. Given the rapid turnaround of export and re-export authorization requests and the pendency of several deepwater port construction projects and new applications, we will likely soon find out.
Prices of naturalgas is a huge political and economic problem. This creates not only additional costs to households and industries but also affects the corporate global competitiveness. In order to ensure that Europe is going to deal with changes in energy market, it is necessary to ensure that consumers receive a sustainable and affordable energy and industry is able to maintain its competitiveness. The purpose of this paper is to analyze pricing structure and to identify factors with the most affect on naturalgas price. To achieve this the changes in the price of naturalgas in the EU were analyzed; gas pricing structure was investigated; effects on household and organization costs for naturalgas were determined The analysis of scientific literature, statistical data, and legislation are used. A comparative and causality analysis of EU and other countries allowed to identify factors having most effect on the price.