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Abstract The quantity of spent hydroprocessing catalysts discarded as solid wastes in the petroleum refining industries has increased remarkably in recent years due to a rapid growth in the hydroprocessing capacity to meet the rising demand for low sulfur fuels. Due to their toxic nature, spent hydroprocessing catalysts have been branded as hazardous wastes, and the refiners are experiencing pressure from environmental authorities to handle them safely. Several alternative methods such as reclamation of metals, rejuvenation and reuse, disposal in landfills and preparation of useful materials using spent catalysts as raw materials are available to deal with the spent catalyst problem. The technical feasibility as well as the environmental and economic aspects of these options are reviewed. In addition, details of two bench scale processes, one for rejuvenation of spent hydroprocessing catalysts, and the other for producing nonleachable synthetic aggregate materials that were developed in this laboratory, are presented in this paper. Introduction Large quantities of catalysts are used in the refining industry for the purification and upgrading of various petroleum streams and residues1. The catalysts deactivate with time and the spent catalysts are usually discarded as solid wastes. The quantity of spent catalysts discharged from different processing units depends largely on the amount of fresh catalysts used, their life and the deposits formed on them during use in the reactors. In most refineries, a major portion of the spent catalyst wastes come from the hydroprocessing units. The volume of spent hydroprocessing catalysts discarded as solid wastes has increased significantly due to a steady increase in the processing of heavier feedstocks containing higher sulfur, nitrogen and metal contents, together with a rapid growth in the distillates hydroprocessing capacity to meet the increasing demand for low sulfur fuels2. In Kuwait alone around 7,000 tons of spent catalysts are generated every year as solid wastes from the hydrotreating and hydrocracking units. Environmental laws concerning spent catalyst disposal have become increasingly more severe in recent years. Spent hydroprocessing catalysts have been classified as hazardous wastes by the Environmental Protection Agency in the USA3. The most important hazardous characteristic of spent hydroprocessing catalysts is their toxic nature. Chemicals such as V, Ni, Mo and Co present in the catalyst can be leached by water after disposal and pollute the environment4. Besides the formation of leachates, the spent hydroprocessing catalysts, when in contact with water, can liberate toxic gases. The formation of the dangerous HCN gas from the coke deposited on hydroprocessing catalysts that contain
- North America > United States (1.00)
- Asia > Middle East > Kuwait (0.35)
- Materials > Chemicals > Specialty Chemicals (1.00)
- Government > Regional Government > North America Government > United States Government (0.66)
Abstract The Frigg Field is a natural gas reservoir, with associated condensate, which extends across the median line between the Norwegian and the United Kingdom (UK) sectors of the North Sea Continental Shelf. Production from the field is expected to cease during 2004. The field consist of six platforms standing in approximately 100m of water:Two steel jackets and one concrete gravity platform are located in the Norwegian sector One steel jacket and two concrete gravity platforms are located in the UK sector In addition, a number of infield pipelines and cables run on the seabed between the platforms. Small amounts of drill cuttings are located either within or around the two drilling platforms. The Frigg Field owners submitted in November 2001 a Frigg Field Cessation Plan[1] to both the Norwegian and UK authorities. A public consultation of the Cessation Plan is required in both countries before any decisions are made. This paper describes the assessment process followed in establishing the recommended disposal arrangements for the various Frigg Field facilities. It includes details of the environmental impact assessment studies undertaken, the possible reuse options considered and the evaluation of the risks attached to attempting to remove the huge concrete structures which were not specifically designed for removal. In addition, the implication of the structures being located in the maritime areas of two sovereign states, each having their own regulatory regime, is described. Lastly, a description is provided of the extensive process of consultation and dialogue with both governmental and non-governmental organisations that took place before finalising the Frigg Field Cessation Plan. One of the main results from the extensive programme of studies has been that there is considerable risk attached to attempting to remove the concrete structures. Particular attention has been given to keeping the various stakeholders informed about the progress of the studies and discussing with them the results, as they become available. Possible reuse options for the concrete structures were actively considered, and discussed with stakeholders, including an assessment of options adopted in previous removal projects. Introduction The Frigg Field is a natural gas reservoir, with associated condensate, that extends across the median line between the Norwegian and UK sectors of the North Sea Continental Shelf. Accordingly, the Frigg Field was developed in accordance with the provisions of an agreement between the governments of Norway and the United Kingdom. BLOCK 4 - - FORUM 25 251 FRIGG FIELD DECOMMISSIONING Production from the Frigg Field, which is operated from Stavanger Norway, started in September 1977. The cease of production is expected to take place some time in 2003/2004, depending upon reservoi
- Europe > United Kingdom > North Sea > Northern North Sea (1.00)
- Europe > Norway > North Sea > Northern North Sea (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > United Kingdom Government (0.34)
TRANSCENDENT STRATEGIES, A NEW VISION TO MANAGING THE PETROLEUM BUSINESS
Perez, A. (Instituto Mexicano del Petroleo, Mexico City) | Smith, W. (Instituto Mexicano del Petroleo, Mexico City) | Galina, S. (Universidad Anahuac, Mexico City) | Zelaya, E. (Universidad Anahuac, Mexico City) | Nuno, P. (Universidad Anahuac, Mexico City)
Abstract The oil industry face heightened challenges as it enters the 21st century. Five major forces are among those shaping the topography of its business landscape: increasing globalisation markets, societal demands for higher environmental performance, financial market demands for increased profitability and capital productivity, higher customer expectations, and changing work force requirements. Due to advanced technical progress and to the new competitive parameters which result from the improvement of both product performance and costs, oils companies must develop a competitive advantage through the effective use of their resources. Develop of a system of making of decisions by means of the evaluation of dimensions of impact social, environmental and economic, to carry out transcendent strategies; those which, they should be consistent between the natural-human resources and the corporate and business strategic objectives of the Petroleum industry. Amalgamating the decision maker's inputs is a new and unique decision model that can be classified as a transcendent-system and the business strategies that realise those objectives. The decision model can be applied iteratively in a define-analyse-and-refine cycle that highlights how proposed integral projects (economic, environmental & social) can be enhanced to better fulfil business-level strategic objectives. This research shows, first and foremost, that it must improve operations, with a focus on better management of the supply chain; improve efficiency in the use of resources, the reuse of recycled materials, and the generation and use of energy; balance environmental and economic considerations; and balance investments in technology by leveraging the capabilities of the society, environmental and industry as a whole trough targeted collaborative efforts in R&D. Introduction In the petroleum industry, most executives think it's good to be big in a globalizing economy. They declare that you can not look at the front pages of the news without seeing yet another megadeal in the headlines. Oils Companies seem to be combining at a rate almost unprecedented in history and on a global scale. In this sector, there's Exxon and Mobil, not to mention BP's mergers with Amoco and Atlantic Richfield. Similar merger examples can be found in industries as diverse as exploration, petrochemical, and chemical1. Pushing these huge and pricey-cross-border deals is the almost universal belief that industries will inevitable become more concentrated as the world's markets become more globalized. The spoils of the market are supposed to go to a select few in each industry. And oils companies believe that if they are going to be among the winners, they will have to shore up economi
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.35)
- Energy > Oil & Gas > Downstream (0.35)
TOWARDS UNDERSTANDING THE GENESIS AND REMOVAL OF NO X IN FCC REGENERATORS
Barth, J. O. (Institut fรผr Technische Chemie, Lehrstuhl II, Technische Universitรคt Mรผnchen, Munich, Germany) | Jentys, A. (Institut fรผr Technische Chemie, Lehrstuhl II, Technische Universitรคt Mรผnchen, Munich, Germany) | Lercher, J. A. (Institut fรผr Technische Chemie, Lehrstuhl II, Technische Universitรคt Mรผnchen, Munich, Germany)
Abstract The regeneration of FCC catalysts leads to significant NOx emissions requiring the development of novel additives that catalyze in situ the reduction of NOx to N2 in the regenerator of the FCC unit in order to fulfill existing and anticipated logistic demands. The identification of reaction intermediates is of utmost importance for understanding the mechanisms by which NOx is formed and reduced. Therefore, characterization of coke, using a wide range of physicochemical techniques (i.e., IR and NMR spectroscopy, elemental analysis, LD-/ MALDI-TOF-MS spectroscopy) has been carried out. The surface chemistry during the FCC regeneration process was investigated by temperature programmed desorption and oxidation experiments. From coke loaded spent FCC catalysts NH3 and HCN were formed via pyrolysis at temperatures above 350ยฐC. The amount of NH3 released was significantly influenced by the concentration of water in the samples. Higher water contents favor the formation of NH3, which supports the hypothesis that nitrogen containing aromatic compounds such as pyridine can react to NH3 and CO2 via hydrolysis. TPO experiments indicated that polyaromatic derivatives of pyrrole (carbazole) are cracked to CO and HCN, which can be subsequently oxidized to NO. Nitrogen and carbon containing species in the coke are oxidized sequentially during the regeneration process (C-species between 450 and 700ยฐC; N-species above 650ยฐC). Introduction Fluid catalytic cracking (FCC) is a key process in modern refineries.1 Worldwide approximately 300 FCC units are operated, converting vacuum gas oil and high boiling residues into lighter fuel products and petrochemical feedstock. Due to its central function in modern integrated refineries, a range of technological improvements has been implemented, to increase the economical benefits from FCC units.2 In addition to investments concerning the process design, new catalysts and additives have been developed to fulfill the economic demands of the market.3 However, refiners are bound to invest also in eco-efficient technologies for the production of fuels and petrochemicals with significantly reduced emissions of environmental pollutants. This is imposed by various stringent national and international regulations addressing emissions from a range of refinery processes and especially FCC regenerators, such as NO, SOx, CO and CO2 emissions from regenerator flue gases.1 Approximately 2000 t/yr NOx are released from a typical refinery. The FCC units contribute to approximately 50% of that. The concentrations of the NOx emissions from regenerator flue gases vary in the range of 50โ500 ppm 4,5 depending on the nature of the feed, the operating conditions of the FCC unit and the amount of CO promoter added. In the fluid catalyti
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Downstream (1.00)
Abstract Among the principal "customers" energy companies must please are the public officials charged with protecting the public health and the environment. The traditional dynamic between fuels companies and regulators has been characterized by incremental clean-up of traditional fuels, often in adversarial processes that drag on for years. This approach can sacrifice whole-system optimization, produce suboptimal results, and generate unnecessary costs. One example is the near-universal dichotomy between air quality and fuel efficiency regulations, making them often at odds with one another even within national jurisdictions. Whole-system, life-cycle analysis could produce a very different technology path. Today's requirements of near-zero pollution together with drastic reductions in C O2 emissions make a host of other fuels look attractive. Some of the most efficient, clean technologies, such as near-zero emission hybrids and fuel cells, want similarly clean fuels, with hydrogen as the ideal end-point. At the same time, petroleum politics are causing many countries to look to natural gas as a feedstock for the transportation sector. This paper will discuss the fuel requirements of the "public as customer", and look at clean, available alternative fuel technologies, especially gas-to-liquids, in this light. Introduction Oil and energy companies operate in a context driven first and foremost by market competition, but their other principal context is that of government regulation. Government agencies charged with protecting the public good set standards for drilling, transporting, refining, and the ultimate distribution and use of energy. There are few aspects of the petroleum business that are not profoundly shaped by governmental regulations. In defense of the public interest, government regulations have required unleaded fuels and tighter restrictions on vehicle emissions. At the same time, government regulations and programs are shaped by politics, which often support national or highly local goals, including for example pricesupports for petroleum aimed at protecting the local producer. Energy company executives must try to divine the political forces of dozens of key governments as they build their business strategies. A march toward more stringent air pollution standards will force changes in fuel specifications. Increased pressure to reduce greenhouse gases will force process and feedstock changes. National security and price volatility concerns will continue to drive the promotion of alternatives to petroleum-based fuels. These and other concerns will strongly influence patterns of investment, choices of feedstock, refinery design, and indeed set the business course for entire companies. BLOCK 3 - - FORUM 18 281 ALTERNATIVE FUELS FUELS AND TH
- Europe (1.00)
- North America > United States > California (0.29)
- Transportation > Ground > Road (1.00)
- Law > Environmental Law (1.00)
- Government > Regional Government > North America Government > United States Government (1.00)
- (4 more...)
Abstract Oil is a finite and scarce resource and it should therefore be used to the maximum extent possible to produce the high value "light" products for which it is still irreplaceable. Today's world refining industry, however, still produces by-products (petcoke or heavy fuel oil) at an average level of about 30 percent of the crude oil feedstock. In the near future, increased refinery deep conversion capacity has the potential to provide major benefits in meeting the increasing demand for light products with the environmental requirements thus optimising the use of a more and more valuable resource. The Eni Slurry Technology (EST) offers an attractive solution to maximise the heavy oil conversion to distillates limiting the by-product production to less than 2 percent. This result is achieved by integrating a slurry hydrocracking with a solvent deasphalting and handling these units in order to get a proper control of the asphaltene stability during the conversion process. The technical feasibility of this configuration, that overcomes the limit of the traditional thermal and hydrothermal conversion technologies (i.e. product stability), has been demonstrated by operating on a continuous pilot plant reproducing the whole process scheme. Very high conversion and extremely good product upgrading were obtained prolonging the run for several weeks in steady-state situation. Introduction The Refining Industry will undergo in the next years major changes due to following reasons: to meet the growing market demand for cleaner light and middle distillates, to face the declining demand for heavy fuel oil, to meet the tighter specifications for gasoline and diesel oil, to reduce the sulfur content in the fuel oil and to take in due consideration the increasing delta price between light and heavy crude oils1โ2. On the other side economic and strategic reasons will promote the utilization of the huge reserves of heavy residues and oil sands bitumen. The proven reserves of extra-heavy crude oils in the Orinoco Belt exceed 100 billion bbls; in Canada the estimated recoverable oil reserves from the oil sands bitumen are in excess of 300 billion bbls. Similarly, Mexico is addressing new efforts to increase the utilization of the Maya Crude from its huge reservoir. In summary the Refiners have to face the following challenges for the coming years: BLOCK 2 - - FORUM 10 331 UPGRADING PETROLEUM RESIDUES WITH EST PROCESS to minimize fuel oil production, while reducing at the same time its sulfur and other pollutants (nitrogen, metals) content. In this context, the fuel oil may be replaced by natural gas which generates lower amounts of CO2; to develop new technologies to suitably upgrade the heavy and extra-heavy crudes. As a matter of fact, the firing of fuel oil in the Power Plants will cause s
- North America > Canada (0.35)
- South America > Venezuela > Orinoco Oil Belt (0.24)
- North America > Mexico (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Downstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.69)
Abstract Regulations to reduce the sulfur level in gasoline and automotive diesel to less than 50 ppm are in place or planned in many countries. A number of technologies have been developed to enable production of these fuels. For instance, SCANfiningTM I is a highly selective process for reducing sulfur in fluid catalytic cracked (FCC) naphtha with minimum olefin saturation/octane loss. Recently ExxonMobil announced the development of SCANfining II, a process that can selectively reduce even the sourest FCC naphthas to ppm sulfur levels with low octane loss. Both of these processes use RTโ225, a catalyst jointly developed and commercialized by ExxonMobil and Akzo Nobel. These companies have also recently completed the development of NEBULA, a hydroprocessing catalyst with more than double the activity of any other commercial catalyst at medium-high pressures. NEBULA has recently been applied in several refinery distillate hydrotreaters and is performing as expected. Some countries are now considering reducing fuel sulfur even lower, to 10โ15 ppm or less. Achieving this ultra-low sulfur level without large additional expenditures is a major challenge. Both ExxonMobil and Akzo Nobel are continuing to develop new catalyst and process technology options to help the refining industry meet these future needs. Introduction Advanced designs of transportation vehicles to reduce air pollution have become increasingly dependent on the availability of low sulfur (S) fuels. Substantial reductions in gasoline and diesel sulfur levels have already begun to occur in some parts of North America, Europe, and Japan. This trend is expected to accelerate as additional regulations mandating 10โ50 ppm S become effective between 2004โ2008 in the U.S., Canada, Europe and elsewhere around the globe. Meeting the new low sulfur fuel specifications presents a significant challenge to the petroleum refiner. In order to minimize the cost of producing these fuels, new technology advances are needed. For gasoline, the greatest challenge is to deeply desulfurize fluid catalytic cracked (FCC) naphtha (which contributes most of the sulfur in gasoline), while minimizing the loss of octane resulting from olefin hydrogenation during the desulfurization step. For diesel, the objective is to achieve the ultra-low sulfur specifications at the lowest possible cost. The application of improved catalyst technologies, along with effective molecule management in the refinery offer the greatest potential for achieving this objective. ExxonMobil and Akzo Nobel are committed to developing cost-effective process and catalyst technology options for meeting current and future needs for mogas and diesel sulfur removal. ExxonMobil has commercialized the SCANfining process for producing ultra-low sulfur gasoline with minimum loss of oc
- North America > United States (1.00)
- Europe (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Downstream (1.00)
Abstract. In developing countries, ensuring impacted communities can achieve lasting benefits from petroleum developments becomes increasingly challenging as production declines over time and fewer resources are available. In Papua New Guinea, ChevronTexaco has learned important lessons from its efforts to assist the rural communities surrounding oilfield operations and exploration there. The license areas are surrounded by a total of 83 scattered villages and 13 language groupings in remote, tropical rainforests with limited access to basic social services such as healthcare and education. ChevronTexaco established social development programs to address the communities' needs, working with local government officials and other social development agencies wherever possible. Many of the company's earliest efforts focused on filling the gaps between community needs and the capacity of local social service providers to address them. Such direct assistance however, promotes increasing community reliance on the company's support and is not sustainable past the life of oil and gas production in the area. Internal and external reviews of lessons learned identified the need to focus efforts on capacity building of local institutions to provide sustainable development assistance to the impacted communities. ChevronTexaco recognized the importance of establishing a separate vehicle for capacity building that would be able to effectively draw upon support from a network of government and non-government organizations. In the face of declining operating budgets, such a vehicle would need to develop its own capacity to be self-sustaining over time, ensuring the social impacts of declining production and associated benefit streams can be effectively addressed in an environment of continued cost reduction. This paper identifies the lessons learned and resulting model ChevronTexaco has developed to address its strategic commitments to ensuring sustainable development is achieved in Papua New Guinea without compromising its strategic commitments to continued cost-efficiency and profitable operations. Introduction Oil companies operating in rural areas of developing countries are often faced with the challenge of addressing the social needs of the communities surrounding their operations. In the early stages of a petroleum development, the Developer's commitment to being a responsible corporate member of those communities usually results in some form of assistance to those communities to help them meet those needs. As production declines over time however, the Developer's available resources to meet those needs also decline. Communities who have become reliant on the Developer's efforts are faced with the uncertain sustainability of this support while NGOs and government BLOCK 4 - -
- Oceania > Papua New Guinea > Southern Highlands > Papuan Basin > PL 3 > Gobe Field (0.94)
- Oceania > Papua New Guinea > Southern Highlands > Papuan Basin > PL 2 > Kutubu Field (0.94)
- Oceania > Papua New Guinea > Southern Highlands > Papuan Basin > PDL 4 > Gobe Field (0.94)
- (3 more...)
Abstract 15 platforms in the Ekofisk Area in the North sea were considered redundant as a result of the Ekofisk II project and were designated Ekofisk I. A Cessation plan and an Impact Assessment were prepared by Phillips as operator for the License PL018 owners and issued to the Norwegian Authorities in October 1999. Were evaluated during the planning process, and several alternatives for each option were subjected to further studies. The recommendation was to remove all steel platforms for onshore recycling; to leave the 242 km of buried pipelines, the seven drill cutting piles and the concrete structures in-situ. The subsequent Authority approval was given in December 2001 to decommission and dispose of these platforms as recommended by year 2013, except those that may still be in operation at that time. The only remaining permit at this time is a confirmation from the Norwegian Parliament to allow the Ekofisk Tank concrete structure to be left in-situ. Decommissioning of the first platforms started in August 1998, and ten platforms have so far been permanently shut down. Well plugging operations are in progress, and three of the outlying platforms have been plugged so far. It is expected that all wells on these platforms will be plugged by end of 2003. The commercial prequalification and bidding process for removal of the first two platforms, the Tank topsides and the Tank cleaning work has been started. Contract awards are expected in 2003. Development of alternative removal technology is an integral part of this project, and bidding on the two first platform removals has been reserved for the "Single-lift" concepts. These are vessel concepts capable to remove topsides or jackets in one operation, and will, if realized, be able to rationalize the offshore removal operations considerably. The Ekofisk I Cessation Project is so far the largest offshore decommissioning project ever undertaken, and this paper explains the main challenges overcome and the ones still ahead of us. Introduction In 1969, Phillips discovered the giant Ekofisk field, almost 200 miles offshore Norway's coast in the center of the North Sea. Production from Ekofisk began in 1971, and by 1980 seven fields in the Ekofisk area were producing. The eighth field, Embla, began producing in 1993. In August 1998, Phillips began producing oil and gas through the Ekofisk II facilities, a massive redevelopment of the original Ekofisk Complex. Redevelopment of the facilities has significantly reduced operating costs. Ekofisk II will enable Phillips to produce profitably from the Norwegian North Sea through at least 2028. The 1994 Plan for (Re)Development and Operation (PDO) of Ekofisk II included the building of two new platforms to replace the older Ekofisk I installations. This included also a commitment to decommission and dispose of these installations in a safe, environmentally responsible an
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > Norway Government (0.55)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Moray Firth > Moray Firth Basin > Block 20/1 > Atlantic Field > Captain Sandstone Formation (0.89)
- (4 more...)
Introduction A "North American energy market" is not a new concept. The energy industry has long operated in a very integrated way in North America, and transportation infrastructure has been built to support that. Now, with a large and growing demand for natural gas to meet North American energy requirements, it is important that all sectors of the gas industry value chain be innovative and that an efficient transportation infrastructure supports this innovation. Enbridge How does Enbridge Inc., fit into the natural gas picture? Enbridge is a Calgary-based company that is a leader, in North America and internationally, in energy transportation and distribution. As a transporter of energy, Enbridge operates, in Canada and the U.S., the world's longest crude oil and liquids pipeline system. We are also involved in liquids marketing, and we are a major player in natural gas distribution through Enbridge Consumers Gas, which is the largest natural gas distribution company in Canada. We have also become a major player in the natural gas transmission business. As part of our westto-east strategy for gas, we were one of the original participants in the $3 billion U.S. Alliance Pipeline transporting Western Canadian gas to Chicago and the lead sponsor for Vector Pipeline which transports gas from Chicago to Michigan and Ontario. Last year we completed the acquisition of Midcoast Energy Resources of Houston. Midcoast operates 4,000 miles of transmission, gathering and end-user pipelines in 10 states and the Gulf of Mexico. Midcoast significantly increases our exposure to natural gas assets, adds to the scale of our U.S. operations, and gives us a presence in the Gulf Coast and mid-continent regions. Enbridge International includes operations in Venezuela, Colombia, Oman and Spain, and Enbridge Technology has provided advisory and training services in 40 countries around the world. Natural Gas - The In the 1990s many technical and cost efficiency gains occurred in the exploration and development Recent Past of new gas reserves in North America. This has enabled producers to keep pace with rising demand for gas with fewer drilling rigs and at a lower gas pricing structure than anticipated through much of the 1980s. As this trend continues, natural gas producers have to vigorously compete to maintain market share, as new sources of supply (e.g., Deepwater Gulf of Mexico) become available. All this production led to the construction of more than 300,000 miles of gas pipelines in the U.S. and Canada alone. The 1990s also saw increased trade between the United States, Canada, and Mexico, in part, as a result of the North American Free Trade Agreement (NAFTA). Regional markets are more open and, as a result, new opportunities began developing. New natural gas pipelines were developed in BLOCK 3 - - FORUM 14 1 EVOLVING NORTH AMERICAN ENERGY MA
- North America > United States > Illinois > Cook County > Chicago (0.45)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.24)
- Energy > Oil & Gas > Midstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.34)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Northwest Territories > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- North America > Canada > Manitoba > Western Canada Sedimentary Basin > Alberta Basin (0.99)
- (32 more...)
- Facilities Design, Construction and Operation > Pipelines, Flowlines and Risers (1.00)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Liquified natural gas (LNG) (0.49)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Compressed natural gas (CNG) (0.34)