The development of unconventional resources such as shale gas is one of the most promising trends in U.S. energy supplies that could have great potential for enhancing our energy independence and reducing carbon emissions. Many experts have called shale gas an "energy game changer" that could dramatically alter the energy supply picture for North America and potentially the world as other countries are just beginning to determine the extent of their own unconventional resources and are closely watching developments in North America. At the same time, however, the hydraulic fracturing technology that is critical to unlocking the vast tracks of shale gas located throughout the United States has drawn intense criticism from environmentalists and lawmakers concerned about the potential impact of hydraulic fracturing on water supplies and the environment. As a result of numerous health and environmental concerns raised, legislation commonly known as the FRAC Act was introduced in the 111 th Congress (2009–2010) calling for greater federal regulation over hydraulic fracturing and disclosure of the chemicals used in hydraulic fracturing operations. Additionally, in March 2010, the U.S. Environmental Protection Agency (EPA) announced that it will conduct a comprehensive research study to investigate the potential adverse impacts that hydraulic fracturing may have on water quality and public health. While the FRAC Act did not reach the floor of the 11 th Congress, some members of the 112 th Congress (2010–2012) have recently expressed their intention to re-introduce the FRAC Act in 2011. In the meantime, hydraulic fracturing continues to draw criticism from environmentalists and EPAs scrutiny over the industry is intensifying as EPAs study starts to take shape. This presentation will provide an overview of the legal, policy and environmental challenges associated with shale gas development in the United States. The presentation will first address the existing federal and state laws pertain to shale gas development in the United States and will also provide an analysis of any pending legislation. This presentation also provides a detailed analysis of the current EPA Study and the various environmental concerns that have been raised pertaining to hydraulic fracturing.

Abstract A significant challenge for Coal Bed Methane producers is dealing with the impacts of high density development needed to effectively recover the natural gas resource. One such concern is the need to meet regulatory requirements for environmental noise as stated in the Energy Resources Conservation Board (ERCB) Directive 038: Noise Control ( ERCB Directive 038 ) and Colorado Oil and Gas Conservation Commission (COGC) Aesthetic& Noise Control Regulations, Series 800 (COGCC Noise Regulations) . Anyone who has ever been involved in the process of complying with regulatory noise standards will agree that it is a complex and challenging task. Some regulated companies struggle through this process often dealing with unfamiliar considerations such as trying to predict facility noise levels before it is even built, or gambling on a best guess as to what is the right, least expensive amount of noise mitigation needed to meet regulatory requirements for environmental and occupational noise. Even the best of intentioned operators fail to hit the mark, sometimes by wide margins and end up with a situation that is potentially worse than when they started. No company wants to go through a process where in the end a lot of time, resources, and public confidence have been lost not to mention now being in a regulatory non-compliant status. This paper will elucidate valuable lessons & experience learned and case histories for the successful approach to noise solutions accepted by regulatory agencies and industry clients. In addition to discussing the complexities of acoustical engineering practices this presentation will also cover the most significant points of ERCB Directive 038 and COGCC Noise Regulations . Introduction The energy needs of North America are continuing to grow nearly exponentially and the desire to have clean energy options makes natural gas an obvious contender. Considering the maturity of conventional gas reservoirs in the Western Canadian Sedimentary Basin (WCSB) and Western United States, the most significant new source of natural gas are unconventional deposits found primarily in coal or shale seams. In the first few years of the new millennium, the base price of natural gas had been very low on the belief that there was an oversupply in the marketplace and incentives were towards renewable energy sources (NEB 2003). Although crude oil prices were rising dramatically, natural gas was not tracking this increase leading to a decline in exploration and replacement of reserves. Change started to occur slowly largely on the hypothesis that carbon dioxide (CO 2 ) from the burning of fossil fuels was the sole driver in climate change (IPCC, 2007) despite the steadily growing volume of peer reviewed scientific literature demonstrating that CO2 is an extremely minor forcing at best (2 - 37). Yet, this anthropogenic caused global warming view dominated in the media coverage and has for a time molded the development of government policy toward the reduction of CO 2 and indeed its reclassification as a pollutant. Regardless, it is becoming increasingly clear that unless we intend to return to the dark ages, North America's energy must come from some non-renewable source given the limited production capabilities of the so called renewable options such as wind and solar. Deep conventional gas reservoirs can only deliver limited supplies and new pool finds that can satisfy the demand are not likely to be discovered in the continental basin. Hence the move to coal bed methane, a readily available source of clean natural gas that can go a long way to meeting the energy demands of North America. However, for coal bed methane to reach its potential operators must find innovative ways to overcome the growing concerns of nearby communities.

Abstract This paper presents new laboratory data quantifying the catalytic effects of two common nonhydrocarbon contaminants ( i.e ., CO 2 and N 2 ) on the liquid water vaporization process as well as the water vapor content for natural gases at high-pressure, high-temperature (HP/HT) reservoir conditions. We conducted laboratory studies to measure the isothermal, equilibrium water vapor content for seven dry gas mixtures at pressures from 500 to 20,000 psia and temperatures of 300°F and 400°F. Gas mixtures evaluated in our study contained up to 20 mol% of either CO 2 or N 2 each. Principle results of our laboratory study demonstrate the following phase behavior: ?? temperature has a significant impact on the water vaporization process and the quantity of water vapor dissolved in a natural gas with no nonhydrocarbon contaminants. Increasing the temperature from 300°F to 400°F increases the equilibrium water vapor content by more than 70% above that for the gas at 300°F; ?? the presence of CO 2 in the gas phase also enhances the solubility of water vapor in a natural gas. Increasing the CO 2 content from 5 mol% to 20 mol% increases the maximum water vapor content by 20% to 40%, respectively, above that measured for the same gas with no CO 2. These increases were observed at both 300°F and 400°F; ?? the presence of CO 2 in the gas phase combined with higher temperatures further augments water vapor solubility in a natural gas. For example, the equilibrium water vapor content for the gas with 20 mol% CO 2 at 400°F increased by 80% above that measured for the same gas at 300°F; ?? the presence of N 2 in the gas phase suppresses the water vaporization process and reduces the quantity of water vapor dissolved in the gas. At 300°F, 5 mol% N 2 reduces the water vapor content from 10% to 20% of that for the same gas with no N 2 . Further increases in N 2 content reduce the water vapor content below that for the same gas with no N 2 ; ?? the enhanced water vapor solubility at higher temperatures counters the suppressive effects of N 2 in the gas phase. Increasing the N 2 content at 400°F increases the maximum water vapor content from 5% (20 mol% N 2 ) to 10% (5 mol% N 2 ) above that measured for the same gas with no N 2 . Introduction The majority of natural gas resources targeted for exploration and development activities by the oil and gas industry prior to the 1980s were at depths less than 10,000 ft, and most of these natural gas resources exhibited normal pore pressure and temperature gradients. However, the natural gas industry has continued to extend exploration and development activities to depths much greater than 10,000 ft. In some geologic basins, these depths are approaching 20,000 to 25,000 ft. Moreover, many of these deep natural gas resources are characterized by both abnormally high pore pressure and temperature gradients, i.e . high-pressure and high-temperature (HP/HT) reservoir conditions. And, natural gases at HP/HT conditions frequently contain significant quantities of nonhydrocarbon contaminants ( e.g ., CO 2 , N 2 , H 2 S, and/or water vapor).

Abstract There is concern within some factions of the energy industry about an approaching energy crisis. In the case of hydrocarbons, eventually there will be a maximum peak in global production. The question is if it will occur sooner or later, and if it will happen because of depletion or because of substitution to other energy sources - perhaps unconventional or non-fossil. This does not preclude hydrocarbon shortages that might still occur due to temporary factors such as political instability and lack of investment. Although the past is not always an indication of the future, an analysis of global market shares (i.e. the mix) for solids, liquids and gases from the year 1850 to 2005, leads to a model that permits a reasonable forecast of the global possibilities of future methane and hydrogen economies. It is concluded that if there is a supply problem in the future it will not be the result of depletion, but rather the failure of society to invest in the research and development of technology needed to provide conventional and unconventional hydrocarbons, as well as alternatives such as hydrogen, on a timely basis. Proper development of these resources will lead to sustainable and efficient global economic growth. Introduction Jules Verne (1828–1905), the father of science fiction, wrote several books using ideas that eventually became reality. Some examples include: "From the Earth to the Moon" in 1866, "Twenty Thousand Leagues Under the Sea" in 1870 where he envisions submarines, "Robur the Conqueror" in 1886 where he describes the precursor of helicopters, and "The Mysterious Island" in 1875 where he wrote: Yes, my friends, I believe that water will one day be employed as fuel, that hydrogen and oxygen which constitute it, used singly or together, will furnish an inexhaustible source of heat and light, of an intensity of which coal is not capable." Vaitheeswaran (2003) asks "could the man who forecast the development of such technological marvels as submarines, helicopters, and space travel have gotten energy right too?" We believe that the answer is most likely positive, as discussed in this paper. Hydrogen accounts for approximately 75% of the universe's mass and is the most abundant of all elements. Stars are made mainly of hydrogen. However, hydrogen does not generally exist in a free state in earth. Consequently, it has to be extracted from different materials including, for example, biomass, fossil fuels and water. This means that it takes energy to free hydrogen for use, no matter how it is produced. As a result, hydrogen is not strictly an energy source but an energy carrier much in the same way as electricity.

Abstract The demand for natural gas has pushed energy industries toward the discovery of remote offshore reservoirs. Consequently, new technologies have to be developed to efficiently produce and transport natural gas to consumption centers. Common design challenges in all gas processing methods for offshore applications are the compactness and reliability of process equipment. Water vapour is the most common impurity in natural gas mixtures. At very high gas pressures within the transportation systems hydrate can easily form even at relatively high temperatures. Gas dehydration or hydrate inhibition systems for offshore gas production/processing facilities should meet these requirements. It should also be noted that at certain pressure and composition conditions, the presence of heavy hydrocarbons (C2+) in natural gas increases pipeline flow capacity and improves compression efficiencies. Therefore, the development of a compact high pressure system capable of selectively removing water from high pressure natural gas streams without affecting the hydrocarbon content will be needed for especial applications and therefore it will be addressed in this paper. Most hydrate inhibition/water removal systems can only work below certain pressure conditions, are relatively large, and not selective towards water. Therefore, some hydrocarbon condensate is also removed during water dew pointing. The developed technique proposed in this study can be customized for the emerging marine transportation of gas in CNG form where the removal of heavier hydrocarbons might not be necessary and will be equally suitable for any other offshore/onshore natural gas production and processing including subsea production of oil and gas. This paper concentrates on the development of simulation techniques needed to accurately estimate dehydration efficiency to control hydrate in a supercritical flow using supersonic nozzles. A simulation model linked to a thermodynamic property generator is needed to predict the water removal efficiency under various flow conditions. The computer simulation results for water removal from a typical offshore natural gas stream under various conditions will be presented and compared with conventional techniques. Intensive water dew points down to about -50 to - 60 ºC can be achieved without any cryogenic cooling or use of solid adsorption techniques. Introduction Natural gas contains different amounts of water vapour, which is considered as the most common impurity in natural gas mixtures. This vapour causes operational problems such as hydrate formation, corrosion, high pressure drop, and consequently slugging flow and reduction in gas transmission efficiency. Water vapour also reduces the heating value of the gas and increases its specific value. One of the most serious problems in the gas industry is the possibility of the obstruction of gas flow due to formation of hydrates within the flow lines. A mass of hydrate is very porous and light in weight and looks like packed snow. The point at which the gas hydrate becomes a solid compound and a cause for trouble depends on temperature, pressure, gas composition, and water content [1]. The gas specific gravity, also a function of gas composition, affects the temperature at which the hydrate will form. At the very high pressure of gas within the transportation system hydrate can easily form even at relatively high temperatures (close to or above 20 ºC). One way to assure that hydrates do not form is to keep the amount of water vapour less than the amount required to fully saturate the gas. The amount of water present in the gas depends on the system pressure and temperature. When the gas contains water then the minimum temperature of the line should be kept above the hydrate point [3] or by reducing the water content, the water dew point of the gas mixture should be kept below the lowest temperature within the gas transmission/transport system. The use of hydrate inhibitors (e.g., methanol, glycols, or kinetic inhibitors) and line heating are commonly practiced to control hydrate formation in the gas transmission systems usually when the gas is transported from the wellhead to a processing facility. Liquid or solid desiccants may then be used to remove water vapour from gas streams and prepare the gas for transmission in long pipeline systems. Water removal may also be performed by reducing the gas temperature and therefore condensing the water out of the gas mixture and subsequently lowering the dew point of the gas (e.g., in LTX facilities) [6, 7].

Abstract Gas-hydrates are crystalline substances composed of water and gas, mainly methane, in which a solid water lattice accommodates gas molecules in a cage like structure. Large methane-gas hydrate reservoirs have been found on the North Slope of Alaska that can be exploited as a future energy source. Depressurization, thermal stimulation, and inhibitor injection are the methods being evaluated for commercial production of natural gas from hydrate-bearing geologic formations. An alternative method of gas hydrate production using CO2 is under investigation. This process conducts injection of CO2 in the form of microemulsion. This concept has several attractive features: CO2 is thermodynamically favored over CH4 in hydrate, the heat released by formation of CO2 hydrate is 20% greater than the heat needed for dissociation of CH4 hydrate, refilling pore space with CO2 hydrate is expected to maintain mechanical stability of the hydrate-bearing formations during production, and the process is environmental friendly, removing CO2 from the atmosphere while simultaneously producing clean-burning natural gas. This study focuses on the evaluation of a set of optimum parameters for methane recovery with simultaneous CO2 sequestration using the STOMP-HYD simulator. Series of simulations are being carried out to verify the effect of pressure, temperature, CO2-microemulsion injection rate, and the concentration of injected CO2-microemulsion on methane hydrate dissociation. Preliminary, 1-D simulations show that injection of CO2-microemulsion produces considerably more amount of methane than warm water injection alone. These results have also demonstrated that injection of liquid CO2-microemulsion helps in early and significant methane production as compared to the injection of vapor CO2-microemulsion. Initial modeling work supports the novel idea of using CO2-microemulsion for Enhanced Gas Hydrate Recovery. Introduction The world civilization needs a constant supply of energy to survive. Conventional energy sources such as coal, oil, flowing water, wind, bio-resources and nuclear sources help us in meeting our energy demands. However, it is now realized that all the energy resources on Earth are being depleted at an alarming rate and by the year 2050 these reserves will be almost exhausted. Hence, it is imperative for the world to search for non-conventional energy sources. Unless new oil fields are discovered the old reserves will be nearly consumed by 2010. As one source of energy disappears another appears in some other form. The most recent discovery of a new energy source, called as Gas Hydrates can be of great service to mankind in the future. The United States currently consumes 21 trillion cubic feet (Tcf) of natural gas (mostly methane) per year, three percent of which is imported. To meet the estimated demand of 32 Tcf of methane by 2020, imports would have to increase. The U.S. Geological Survey (USGS) estimates that the methane hydrates hidden beneath U.S. waters alone hold some 200 Tcf of natural gas, which would be enough methane to supply the entire nation's energy needs for many years at its present rate of consumption. On the North Slope of Alaska alone, the total volume of natural gas within these gas-hydrate reservoirs is estimated to be about 37 to 44 Tcf.[1] Until recently, the natural gas industry considered methane hydrates only as a nuisance, something that occasionally plugs up pipelines or causes wellbores to collapse. Oil resources becoming more expensive and difficult to exploit in the next couple of decades creates the need to prospect for new fossil fuel deposits. Thus hydrates have sparked an interest among the energy experts around the world.

Abstract By most accounts, natural gas demand in the United States (U.S.) is expected to significantly increase during the next two decades, from 23 trillion ft 3 in 2000 to over 33 Tcf in 2020. The Energy Information Administration projects that 22,000 gas wells will have to be drilled in 2020 to meet this demand - up substantially from the 15,200 wells successfully drilled and completed in 2000. Further, a significant portion of the U.S. future supply of natural gas is expected to be produced from these unconventional sources - formations that typically require hydraulic fracturing to produce at economical rates. Given this forecasted scenario, a critical and comprehensive assessment of the role that hydraulic fracturing plays in supplying natural gas in the U.S. has been initiated. Introduction Hydraulic fracturing is a widely employed method for enhancing the flow of oil and natural gas from underground formations. The exploration and production (E&P) sector of the petroleum industry has relied on hydraulic fracturing for decades to commercially develop natural gas resources that are not economically viable at "natural" flow rates and to improve the return on investment for other natural gas plays. Major oil and gas companies, oilfield service contractors, and the federal government all recognize the importance of fracturing operations and have substantially contributed to the knowledge base on the process. The fundamental understanding of the physics and theory of hydraulic fracturing, as well as rock mechanics, have evolved to where sophisticated 2-dimensional (2-D) and 3-D models are routinely employed to design, pump, and analyze treatments. It has been projected that a significant portion of the U.S. future supply of natural gas is expected to be produced from formations that typically require hydraulic fracturing in order to produce at economical rates. Given this situation, and the fact that over $1 billion may be spent each year on hydraulic fracturing, it is imperative that a critical review of the process be undertaken. The U.S. Department of Energy's National Energy Technology Laboratory (DOE/NETL) is undertaking a critical and comprehensive assessment of hydraulic fracturing. Results of the assessment will benefit: product planning, policy development, and overall strategy formulation for natural gas resource development. The objective of the paper is to provide a background to the study and set the stage for the future presentation of results and conclusions of this assessment. Discussion of the project's background, objectives, and methodologies is presented below, providing a foundation for the on-going study and forthcoming findings. Background For the last two decades, natural gas consumption in the U.S. has varied from 16 to 22 trillion ft 3 (Tcf), Fig.1. 1 However, by most accounts, natural gas demand in the U.S. is expected to significantly increase during the next two decades, from 23 Tcf in 2000 to 34 Tcf in 2020, Fig.1. 2 This significant increase in gas consumption — 48 percent or 2.4 percent growth per year - will require a concomitant growth in natural gas supplies available in the U.S., either through increased domestic production or imports. Production of natural gas (dry) in the U.S. during the last 20 years has also varied from 16 to 22 Tcf, Fig. 2. 3 Interestingly, while demand for natural gas has grown 34 percent during the last 14 years, natural gas production has lagged significantly behind, growing only 16 percent (with the difference being supplied by primarily by imported gas). In the future, it is projected that domestic natural gas production will exhibit a significant growth to match the anticipated growth in demand over the next 20 years, from 19 Tcf in 2000 to 28 Tcf by 2020, Fig. 2. 2

Abstract A country's wealth is closely related to its energy consumption. For example, the United States, the richest nation, with a per capita income of about $34,000 is also one of the highest consumers of energy with an annual per capita consumption of about 355 million British thermal units (MMBTU). Energy consumption is the most discernible national characteristic that separates rich from poor countries. The correlation between per capita energy consumption and per capita income among all nations is clear. However, the energy use in other developed countries is also a function of their geography, the makeup of those countries and even the cultural preferences of their citizens. Throughout the last two centuries, energy consumption in the creation of wealth and the form of primary energy sources, have not been constant. The process has been dynamic and technology has played a considerable role in the changing of the status of many countries, most notably Japan. Efficiencies developed elsewhere are adopted by other countries and lead to an increase in wealth.Globalization of the economy will certainly aid this process in the future. Energy consumption and heightened demand worldwide, may prove perhaps the most formidable international challenge of the twenty first century. As early as 2010, at current energy growth, chronic energy shortages are likely to emerge which may evolve into a serious energy crunch. The most logical way to prevent this situation is to transition rapidly to natural gas and, eventually, to hydrogen. In this paper, natural gas is viewed as the compelling next fuel of choice and as the necessary stepping-stone towards hydrogen. Also offered here are production, consumption and transition forecasts. Introduction The correlation is clear between the wealth and energy consumption of nations. In Figure 1, this point is shown clearly by comparing the per capita energy consumption and per capita income of the 15 largest economies (DOE/EIA, 2000, CIA, 2000). The United States, the richest nation in the group, has a per capita income of about $34,000 and is also one of the most intense users of energy with an annual per capita consumption of about 355 million British thermal units (MMBTU). When comparing Canada, a country of vast and thinly populated expanses, with the five largest European economies (Germany, France, UK, Italy, Spain) which consist of much smaller areas and highly concentrated and centralized urban centers, while all have relatively similar per capita incomes (e.g., $22,000) Canada has a very large per capita energy consumption (410 MMBTU), while the European countries have much smaller per capita energy consumptions (e.g., 160 MMBTU). China and India, the world's two most populous nations languish considerably behind with per capita incomes of $3800 and $1800 and per capita energy consumptions of 25 and 12.3 MMBTU, respectively. For China and India to catch up with the developed world, they will have to move up the curve.

Abstract Based on a 427-km seismic survey run in Gaspe in the early 1980's, well Galt # 1 was drilled to a depth of 2500 m in 1983. Several Devonian DSTs indicated the presence of 46-degree API oil in the Indian Cove formation between 993 and 1309 mKB, and gas in the Forillon formation between 2245 and 2353 mKB. The well was not considered economic at the time and was abandoned using various cement plugs. Subsequent evaluation of the log and DST data indicated that the naturally fractured Forillon limestone had been heavily damaged during drilling operations. The well was re-entered in September 1993 and following an acid job tested at approximately 1 m 3 /day of oil from the Indian Cove formation. The well was next drilled out to the Forillon formation in June 1994. It flowed at approximately 6,400 m 3 /day of gas during the extended flow period; however, gas rates in excess of 56,000 m 3 /day were recorded during the isochronal test. Due to the lack of pipeline infrastructure, the gas is being trucked to a copper smelter plant operated by Noranda at Murdochville. This replaces the propane previously used at the smelter. This paper discusses the geology of the area, the log and DST data, the compressed natural gas (CNG) system used for trucking the gas and the economics of the project. Introduction In the world of energy, the Province of Quebec is well known by its prolific hydraulic power. This reality and the lack of an efficient gas network system, combined with a complex geological setting do not encourage great efforts to develop its hydrocarbon potential. The 20 millions hectares of sedimentary rocks dating from Ordovician to Permian are equally distributed between offshore and onshore lands of Quebec. Two gas fields have been produced commercially and have been subsequently converted to underground gas storage in the Cambro-Ordovician basin, located in the St-Laurence valley where the population of Quebec is concentrated. The first well drilled in Canada was spudded in 1859 along oil seeps near the town of Gaspe. The presence of highly faulted Devonian rocks in a sparsely populated area did not help pioneers to establish any commercial production. As a result, the Gaspe area, where the Galt gas field is located is virtually non-explored. Based on the first seismic survey run is the early 1980's, well Galt # 1 was drilled to a depth of 2500 m. The well encountered gas and oil bearing Devonian carbonates from 900 m to 2500 m. A detailed reservoir characterization of the carbonate reservoirs indicated that there was reasonable oil and gas potential. In order to activate the development of the Galt field and the exploration of its 800,000-hectares land properties, Junex opted to market the gas from well Galt # 1 by trucking it using a compressed natural gas system (CNG). To achieve this, Junex built a 4-inch gathering line of 5 km to bring the gas to a treating plant located near the main road. The gas is being delivered to a near-by copper smelter operated by Noranda at Murdochville. By replacing the propane previously used at the smelter, Junex is confident to get its investment paid back within 2.5 years.

Abstract Effective removal of hydrogen sulfide (H2S) is one of the challenging problems associated with the production of natural gas. Since H2S is often present in natural gas along with varying levels of carbon dioxide (CO2), selective removal of H2S from sour gas in the presence of CO2 is very important for cost effectiveness of a scavenging operation. For over ten years, triazine based scavengers have been successfully applied in the sweetening of natural gas. However, observations of the effect of CO2 on the scavenging capacity of triazine based scavengers have not been very consistent. Initial documentation and case histories on performance of triazine based scavengers by Dillon [1,2] reported that CO2 did not have any effect on the H2S scavenging capacity of triazine. However, recent studies by GRI [3] indicate that CO2 significantly reduces the H2S removing capacity of triazine. To address this discrepancy, this paper critically evaluates the effect of CO2 on the scavenging performance of a triazine based H2S scavenger. Results from controlled laboratory experiments, using a wide range of CO2 partial pressure and H2S to CO2 ratios indicate that CO2 has very little effect on the H2S scavenging performance of a triazine based H2S scavenger. Field data supports the observations made in the laboratory experiments. Introduction H2S and CO2 are two contaminants that naturally exist in sub-quality natural gas. Removal of H2S from the gas is often required because of safety, environmental or corrosion considerations. However, these factors do not dictate the removal of CO2. Chemicals that react with H2S, very often also have an affinity for CO2. The concentration of CO2 relative to H2S in natural gas is often very large (percent levels CO2 compared to a few parts per million (ppm) of H2S), which further makes removal of CO2 less attractive and more uneconomical. The need for selective removal of H2S therefore emerged as a key criterion for cost effective sweetening of natural gas. Triazines form an important class of non-regenerable H2S scavengers. They are produced from the reaction between formaldehyde and an alkanolamine comprising 1 to 6 carbon atoms [1]. Various sour gas-sweetening processes have been used for a number of years.

Abstract The Amazon region has been demonstrating a great oil and gas potential in Brazil and in the neighboring countries, specially the field of Camisea in Peru. However, the development of feasible and economically justifiable transport systems, that can allow the flow of those resources to their potential markets, continues to be the great challenge. In this work, we present one option that can be transformed into competitive and commercial project. We describe a gas pipeline option, discussing about their technical, economic and commercial aspects. We suggest that the fields already discovered in the area should be treated in an integrated way, achieving larger economies of scale in more ambitious initiatives aiming at exports. 1.Introduction The Amazon region is a very large area, dispersed over more than five countries, and characterized by very low demographic occupation and delicate ecosystems. Those characteristics impose great difficulties upon the energy industry to fulfill the local population's energy needs. The electric systems are isolated and far from the main national electricity grids. In many cases, those isolated systems are also very obsolete and inefficient, with the predominance of thermopower generation based on expensive and unreliable fuel oil or diesel oil supply. Some major Brazilian Federal states laid over the Amazon region, for example, the states of Amazonas, Acre and Rondonia, present great unfulfilled energy demands. The lack of investments in the electricity sector and the absence of cheaper local energy sources, have always been seen as huge obstacles for the regional development. Nevertheless, the recent discoveries of large oil and natural gas fields all over the Amazon region and across the different countries have triggered important short-term transformation in the energy generation perspective for the area, with increasing interest particularly in the natural gas. This energy option has been attracting governments and investors. The relatively lower capital cost of gas-fired power plants as compared to the hydroelectric systems that can still be developed in the region is a significant positive aspect. For example, while the investment of gas-fired power plants can be as low as US$ 500/kW, the investment cost of some of the cheapest hydroelectric plants planned for the Brazilian Amazon region can reach more than US$ 1.200/kW (1). In addition, gas-fired power plants can be built quicker, approximately 2 to 3 years as compared to the 8 to 12 years needed in a hydroelectric project, usually located in very wild environment, which will still require important investments in transmission lines. The natural gas is also much more competitive when compared with the current diesel or fuel oil power generation. The electricity generation cost in the Brazilian Amazon region can be as high as 100 to 150 US$/MWh. This enormous energy cost inhibits the regional economic growth and development. By introducing gas-fired power plants, the regional generation cost could decline to about 30 to 40 US$/MWh. In this context, the development of indigenous natural gas resources and its penetration into the local markets would represent a tremendous energy cost reduction for final consumers or governments that very often must pay for those extra costs through subsidies.

Abstract World gas supply forecasting has proved difficult because its exploration, transportation, and customer bases are so heavily dependent on fluctuating economic factors. Our recent study showed that the conventional Hubbert model with one complete production cycle is not appropriate for use in forecasting gas production trends for most gas producing countries. This paper presents our forecast for the world's supply of conventional natural gas to the year 2050. We used a multicyclic Hubbert approach to develop 53 country-specific gas supply models that enable production forecasts for virtually all of the world's gas. The multicyclic modeling approach is presented in a convenient form that makes production data exhibiting two or more cycles easier to model. These models were aggregated to the regional level and to the world level. Supply models for some organizations (e.g. OPEC, non-OPEC, OECD) were also developed and analyzed. Our results indicate that the world's supply of natural gas will peak in 2014, followed by an annual depletion rate of 1%/yr. A regional analysis indicates that gas production of some regions will peak soon. North American gas production is currently (1999) at its peak. West European gas production is expected to peak in 2002. The countries of the former Soviet Union and Middle East, which comprise about 60% of world's ultimate recovery of natural gas, will be the main sources of world gas supply in the future. Introduction Natural gas is becoming an increasingly important source of the world's energy. In recent years, natural gas has become the fastest growing fossil fuel, and it will continue to grow rapidly for several decades. The US Energy Information Administration (EIA) 1 reported that the world's gas consumption grows by 3.3%/yr compared to 2.2%/yr for oil and 2.1%/yr for coal. This higher growth rate can be attributed to several factors. First, natural gas, including unconventional gas, is available in abundant quantities in many parts of the world. Second, natural gas is environmentally cleaner than coal and crude oil. Third, the lower price of gas relative to other fuels makes it attractive to many gas operators and consumers. Fig. 1 shows the U.S. wellhead prices of gas and crude oil since 1949. These data are wellhead inflation-adjusted prices based on 1992 U.S. dollars on an equivalent energy basis. The figure shows that there is a somewhat direct relationship between oil and gas prices, with a time lag of 3 to 4 years. In 1949, the gas/oil price ratio was 0.12, indicating that gas was 12% as valuable as oil on an energy basis. Since that time the trend of this ratio has been increasing generally upward, reaching the value of 0.94 in 1998. This indicates that gas has now reached a close price parity with oil. The gas industry is influenced by political events, economic factors, and its relationship with the oil industry. Fig. 2 shows the U.S. marketed gas production rate since 1918. The gas production trend from 1918 until 1970 shows an exponential growth. From 1970 to 1973, gas production continued to increase, but at a slower rate of growth. Oil production peaked in 1970. Contributing factors to the slow-down in gas rate increases might have been the oil production decline, which resulted in a decline of associated gas production, and lower gas prices. However, there were gas supply shortages in the very cold winter of 1972–1973. Actual gas production peaked in 1973, the time OPEC cut production of crude oil. Then gas production rates dropped, paralleling the decline in oil production. This drop in gas rate extended to 1975 since the gas market was based on long-term gas sales contracts with stable prices. During the 1975–1979 period, gas production showed slow growth and gas prices became more extensively regulated. In 1979, the Iranian revolution caused oil prices to increase sharply reaching the peak in 1981. This corresponded to an increase of gas prices, which peaked in 1984 (Fig. 1.) The oil/gas price time lag of three to four years possibly resulted from the moderating effect of long-term gas contracts. In 1981, with low gas demand, the " gas bubble" and gas production decreased rapidly until 1986 despite the fact that gas reserves and production capacities were high.

Abstract Enhanced Coalbed Methane Recovery (ECBM) is presently not commercial due to the high cost of compression and capture of the injection gas either carbon dioxide (CO2) or nitrogen (N2). Recently, the necessity to reduce greenhouse gas emissions has provided a dual role for coalbeds - as a source of natural gas and as a repository for CO2. The second role arises because of the storage mechanism for gas in coal. Unlike CO2-enhanced oil recovery processes, CO2 injected during ECBM recovery is strongly adsorbed onto the coal, and in a relatively homogeneous reservoir is not expected to break through to the production wells until the bulk of the coalbed methane (CBM) reservoir is swept of methane. This provides a huge CO2 storage potential in coalbeds throughout the world. However, based on current economic factors, it makes more sense to partially deplete the coal reservoir of methane before injecting CO2. The exact strategy depends on two economic factors, the costs and credits for sequestration of CO2 and the natural gas sales price. CO2 credits would have a major effect on the production strategy used for CBM, and would favor early use of ECBM. An example is used later in this paper to illustrate this point that takes into account the differences between "gross CO2" sequestered (CO2 captured), and "CO2 avoided" (net CO2 sequestered). Introduction CO2 emission from burning fossil fuels has been identified as the major contributor to the increase in atmospheric CO2 levels that can potentially lead to global climate change. The challenge for the fossil fuel industry is to find cost-effective solutions that will reduce the release of CO2 into the atmosphere. Significant reduction of CO2 emissions on a global scale may be achieved by reduction of energy intensity, by reduction of carbon intensity, or by capture and storage of CO2. A portfolio of these methods is required to achieve the large reduction required, in which the utilization of carbon dioxide sinks will play an important role. Carbon dioxide sinks can be grouped into three broad classes based on the nature, location, and ultimate fate of CO2.

Abstract In light of tighter restrictions on vehicle emissions and the existence of abundant resources, natural gas represents a highly attractive transportation fuel. Worldwide, there are currently more than 976,000 natural gas-vehicles, most of which are located in Europe and South America. At present, Compressed Natural Gas (CNG) is the technology most widely used, which stores gaseous fuel at very high pressures (about 3,000 psig). However, short driving ranges and questions of safety and cost have limited the penetration of Natural Gas Vehicles (NGV) into the transportation market in the U.S. This is in spite of the relatively lower price of natural gas compared with other fuels on an energy basis. A new technology called Adsorbed Natural Gas (ANG) is being developed, which contains the gaseous fuel in a dense form at a moderate pressure (500 psig). The lower pressure utilized by ANG allows the usage of conformable tanks which overcomes the short driving range of CNG. Nonetheless, the hope for ANG vehicles depends on further development in the areas of heat management and gas conditioning, in order to preserve the gas tank capacity. Introduction Comprising more than 90% methane by volume (Table 1), natural gas is extremely volatile. It remains as vapor regardless of the system pressure at ambient temperature. Conventionally, natural gas has been stored in tanks either as a liquid at cryogenic temperatures or as a gas at very high pressures. A recent application of solid adsorbents has been developed for NGV on-board storage systems. Activated carbons, among other materials such as: molecular sieves, silica gel, zeolites and alumina, have given the highest natural gas adsorption per unit weight and volume. When carbon is produced, it has interparticular voids as well as porous spaces consisting of micropores, mesopores and macropores (Fig. 1). Natural gas storage levels are the sum of the adsorbed phase and the compressed gas phase. The adsorbed phase is defined as the increase in particle density over gas phase density because of the presence of a wall or walls in the case of micropore filling. Consequently, the amount of gas stored by adsorption is greater than that obtained by compression in the range of low to moderate pressures (Fig. 2). Gas adsorption increases with pressure until, at a certain limiting value, the rate of increase levels off. For this reason, the filling pressure chosen for ANG systems is 500 psig. At this pressure, the coverage of natural gas on the activated carbon surfaces is roughly 75% of the saturation value. Natural gas storage capacities of 180-190 V/V at 500 psig and 77 F have been reported on activated carbons, with delivery volumes up to 155 V/V. In these tests, carbon monoliths were used to minimize voidage and mese-macropore volumes. This amount of gas delivered by ANG is 67% of that for CNG. The lower pressure required by ANG allows the use of larger and conformable gas tanks, which can fit the vehicle shape. Taking advantage of all available vehicle spaces, more fuel storage volume and longer driving ranges can be achieved by ANG. The performance of ANG tanks may be adversely affected under certain operating conditions, such as: fast filling and discharging, changes of ambient temperature, and the presence of heavy hydrocarbons and impurities in the gas. Further development in these areas is required to provide ANG with an integral design that is technically and economically superior to that of CNG. Natural Gas: Fuel of Choice The abundance of natural gas in North America (Table 2) and the existence of vast transmission and distribution systems facilitates the use of NGV as a substitute for liquid fuel powered vehicles. P. 151

Abstract The Gas Research Institute (GRI) has an R and D Program directed towards natural gas processing issues. Of particular interest is research on problems connected with small-scale subquality natural gas processing. Both fundamental, knowledge-building and applied research are carried out. Processes and hardware developments in gas processing from this program which are at or near commercial introduction are reviewed. Included are the MVC Multivariable Process Control Optimization, R-BTEX process, and lithium bromide (LiBr) absorption chiller applications in gas conditioning. Obtaining significant technical information on performance of new gas processing technology is also an important activity of GRI and selected applications in this are discussed as well. Included in this category are results of testing of commercial cellulose acetate membranes for CO2 removal from natural gas and field evaluation of Liquid Redox Sulfur Recovery processes. Introduction The Gas Research Institute (GRI) was founded in 1976 to coordinate the RD and D needs of the domestic (U.S.) natural gas industry. GRI receives funds of approximately #200 MM per year predominantly from the interstate pipeline gas consumers from which approximately $180 MM are contracted out to perform planned research with approximately 30% directed to supply issues. The producing (and gas processing) segments of the industry are adequately represented on GRI's Board and support research to lower the cost of treating natural gas to pipeline specifications. GRI initiated the program on gas processing in 1989 and the current budget for the applied program is $5.4 MM. The ultimate objective of the GRI program is to provide benefits to gas users and the gas industry through the advance of scientific knowledge and successful transfer of R and D results to commercial and noncommercial applications. The R and D results take the form of advanced natural gas products, processes, techniques and technical or analytical information. To ensure that this objective can be accomplished, GRI establishes strategic alliances with researchers, cooperating commercial firms and technology users that maximizes the probability that R and D results will be put to use. GRI has considerable flexibility in establishing these alliances and protecting the rights of the parties. GRI's program in this area has previously been reviewed in these conferences. Several of the processes introduced in that paper and since that time have recently entered field validation stages in anticipation of near-term commercialization by GRI's commercialization partners. Of particular interest in this regard is the MVC Multivariable Gas Plant Process Control Optimization, the R-BTEX VOC control technology, and applications of LiBr absorption-based chillers to gas conditioning. Status and salient results of these developments are presented below. Appropriate references for further details are given. In addition to hardware and process development research, which is given priority, a significant amount of knowledge-building research is carried out as well. This serves the dual purposes of providing information for the resource allocation process at GRI and of allowing the gas processing industry to make informed decisions on process selection. In this regard GRI's database activities for cellulose acetate CO2 removal membrane systems and Liquid Redox sulfur recovery processes are highlighted. Many other activities in gas processing are being carried out at present but cannot be covered in the span of this brief overview paper. Please feel free to contact the authors for additional information. MVC (TM) Multivariable Gas Processing Process Control Optimization System Continental Controls, Inc, (CCI), Houston, Texas, with cofunding from GRI and several GRI member companies, has been developing a PC-based multivariable, (MVC), process control optimization system for gas processing and treating applications. To date, the technology has been applied to cryogenic expansion, refrigerated lean oil absorption, NGL fractionation, amine treating and sulfur recovery processes. The use of MVC could significantly decrease the operating costs of existing and new plants with a minimal capital investment. P. 187^

Abstract The paper examines the environmental crisis facing the planet in the coming decades due to an enhanced 'greenhouse effect', its causes and impacts. It then discusses future energy demands of industrial and developing countries and shows that the latter will face a huge energy crisis with serious consequences on the environment - unless a move to cleaner fuels is adopted. It finally examines the future prospects of Natural Gas, an abundant and relatively cheap - at today's prices - primary energy source which is the most environmentally-benign of all fossil fuels. The study demonstrates why Natural Gas is regarded as the fuel of the 211 century, and our hedge against a looming environmental crisis. GLOBAL WARMING: CAUSES and IMPACTS Planet Earth is getting warmer, an indication that it is not well. The symptoms are becoming more evident, and the disease could be fatal if nothing is done about it. Yet, the cause is known, it is due to an increased 'Greenhouse effect', i.e. increased absorption in the atmosphere of the infrared radiation (heat) emitted from the earth's surface. This is a result of our altering the composition of the atmosphere through fossil fuel consumption, industrial development and agricultural expansion. The Greenhouse effect Solar radiation reaching the earth's surface warms it and it gets rid of this heat by emitting infrared radiation back to space, figure (1). There is thus a long-term balance between the incoming and outgoing radiation, which determines the mean temperature of the planet. Certain gases in the atmosphere (greenhouse gases) allow solar radiation to reach the Earth's surface unhindered but absorb some of the outgoing infrared radiation allowing less heat to escape back to space (rather like the glass of a greenhouse). Earth's temperature would be about 32C colder than now if it were not for the 'Greenhouse Effect'. It also explains the very hot conditions under the thick atmosphere of Venus and the very cold conditions under the thin weak atmosphere of Mars. The most important greenhouse gases occur naturally in the atmosphere namely : water vapour, carbon dioxide, methane, nitrous oxide and ozone. These gases are also emitted as a result of many human activities. Yet, the man-made chlorofluorocarbons (CFC's) are serious greenhouse gases beside being ozone layer killers. As we add more and more of these gases to the atmosphere, their atmospheric concentrations increase resulting in a turning up of the greenhouse thermostat and both the Earth's surface and lower atmosphere (troposphere) get warmer. Over the past century, the troposphere has warmed by about 0.5C while atmospheric CO2 has increased by over 28% from about 275 ppm (before the industrial revolution) to more than 353 ppm today. Predictions of Further Warming Figure (2) shows the contributions of the different greenhouse gases to global warming. P. 361^

Abstract Recently, considerable attention has been focused on the long term potential of natural gas. Studies have included resources that range from conventional gas in stratigraphic traps to unconventional gas locked in hydrates. However, these studies have overlooked one large and potentially productive gas resources - the methane stored in deep coal seams. Currently, the conventional wisdom is that coals below 5,000 feet will be extremely low in permeability and thus unproductive. This viewpoint stems from the early laboratory based tests of confining pressure (depth) versus permeability and from the initial field tests in the deeper portions of the Piceance Basin, U.S.A. Recent basin studies show that the resource potential in deep coal basins is considerable, both in the U.S. and worldwide. For example, in the U.S. the bulk of the 84 Tcf of coalbed methane contained in the Piceance Basin is in deep coals, below 5,000 feet. Even larger amounts of gas exist in deep coal seams in Alberta, Canada and other deep coal basins of the world. Also, comparisons of laboratory based permeability tests on coal with field results indicate that the lab tests may be unduly pessimistic. While the evidence that deep coals can be economically productive is limited, some data is now available and discussed in this paper. For example: An experimental completion of a Cretaceous age coal seam at 10,000 feet in the Deep Basin of Alberta, showed that deep coals contain substantial methane, that gas can be produced from such depths, but that the well completions are very challenging. A recently drilled 6,000 foot deep well at Pinyon Ridge (Northern Piceance Basin) had an initial gas flow of nearly a million cubic feet per day. The purpose of this paper is to examine the resource and production potential of deep coal seams and thus add this resource to the list of long-term sources of natural gas. Introduction A major portion of the coalbed methane potential of the world resides in deep coals, coals buried at depths below 5,000 feet (1,500 meters). Industry has been reluctant to pursue these "deep coals" for four reasons: limited downhole data; higher drilling costs; assumed unfavorable desorption characteristics; and concerns about low permeability. Of the four reasons for avoiding deep coals, the loss of permeability with increasing depths is the one most often mentioned. The low permeabilities encountered at GRI s Deep Coal Seam Test Site (Red Mountain, Piceance Basin), and the unfavorable depth versus permeability charts presented in various technical papers and reports (McKee and others, 1986; 1988; Koenig and others, 1989) are generally cited as supporting evidence for these concerns over the lack of permeability in deep coals.

Abstract To support the complex operation of a large gas transmission system, information must move rapidly and accurately within NOVA and between NOVA and its business partners. With the implementation and integration of systems to perform pipeline control (SCADA), commodity management, electronic flow measurement (EFM), and electronic data interchange (EDI), this goal is being achieved. This paper will follow a typical process from a customer's electronic request for gas, through the commodity management system for contractual and operational checks, to the issue of a change in flow, the control and measurement of that flow through the SCADA and EFM components, back through the commodity management system, and through to the communication of the transported commodity totals back to the customer. Introduction NOVA Corporation of Alberta is a widely held company operating internationally from headquarters in Calgary, Alberta, Canada. NOVA adds value to energy through producing, marketing and transporting natural gas and upgrading natural gas and other hydrocarbons into chemicals and plastics. NOVA's Alberta Gas Transmission Division (AGTD) is responsible for receiving, measuring, quality control, and transmission of Alberta natural gas within and exported from the province. This responsibility includes the planning, design, construction and operation of NOVA's natural gas transmission facilities in Alberta. As of December 31, 1992, the AGTD pipeline system consisted of 18,400 kilometres (11,433 miles) of pipeline, ranging in sizes from 51 mm to 1219 mm (2 to 48 inches); 825 receipt points and 149 major delivery points; and 44 compressor stations marshaling 1,040,900 horsepower of total compression. P. 217^

SPE Member Abstract Dehydration is an essential step in the processing of natural gas to meet pipeline specifications. processing of natural gas to meet pipeline specifications. Water removal is required to prevent condensation of an aqueous phase which can lead to hydrate formation and corrosion in the gas handling system. The purpose of this paper is to review commercial natural gas dehydration processes and recent developments which impact the installation and operation of these facilities. The paper will be divided into three sections — 1) review and history of gas dehydration processes, 2) water-hydrocarbon equilibrium processes, 2) water-hydrocarbon equilibrium behavior and 3) new developments in gas dehydration processes. processes. REVIEW AND HISTORY The removal of water from natural gas can be accomplished in a number of ways. Commercial methods currently employed include:Adsorption (Glycol dehydration)Adsorption (Dry desiccant)Condensation (Glycol/methanol injection) The first two methods utilize mass transfer of the water molecule into a liquid solvent (glycol solution) or a crystalline structure (dry desiccant). The third method employs cooling to condense the water molecule to the liquid phase with the subsequent injection of inhibitor (glycol or methanol) to prevent hydrate formation, Early gas production systems used line heaters to keep the gas above its water dewpoint. Since no condensation occurred, hydrates and corrosion were avoided. This was feasible since most pipelines were relatively short and fuel gas costs were pipelines were relatively short and fuel gas costs were minimal. With the advent of long distance, higher pressure transmission lines in the 1930's, a more economical method of dehydrating natural gas was needed. These early dehydration units were typically dry desiccant units employing alumina (bauxite) as the desiccant Common trade names included Florite, Dri-O-Cel and Porocel. Following World War II the natural gas transmission and gas processing industry grew rapidly. The typical dehydration installation was still dry desiccant; however, silica gel replaced activated alumina as the most popular desiccant. Silica gel had a higher capacity for water and could also be employed to remove heavier hydrocarbons (iC +) from the gas, if desired. P. 263

Abstract In seasonal modulation storages of natural gas in an aquifer, a varying fraction of the injected gas, the cushion gas, cannot be recovered. This cushion gas may represent more than half the total gas volume, and up to 70 % of the initial investment for the storage facility. Experimental studies, backed up by field experience, have shown that at least 20 % of the cushion gas can be replaced by a less expensive inert gas. Different methods are available to produce an inert gas which meets the specifications required. Recovery of natural gas air combustion products (mixture of 88 % N2 and 12 % CO2) and physical separation of air components (more or less pure N2) have been selected. For the specific needs of France inert-gas injection program, the production facilities must satisfy requirements of autonomy, operating flexibility and transportability. The technique of recovering natural gas air combustion products has been experienced in two facilities. A nitrogen production unit using the Pressure Swing Adsorption (PSA) technology will be Pressure Swing Adsorption (PSA) technology will be put into service in July 1989. This paper discusses put into service in July 1989. This paper discusses the principles of these two methods and reviews the operating characteristics of each facility. Introduction When operating an underground storage of gas in an aquifer, a more or less large part on the stored gas cannot be recovered. The gas trapped in the pores and the volume of free gas not recovered at the end of the withdrawal form the storage cushion gas whose purely mechanical role does not call for the chemical and calorific properties of natural gas. In the case of seasonal modulation storage, the cushion gas can represent up to half of the total amount of gas stored and up to 70 % of the investment necessary to create the storage. This has prompted the search for a substitute gas which is prompted the search for a substitute gas which is less costly. Different inert gases have proved to be adapted substitutes. The risks of inert gas dispersion within natural gas lead to a limit in the amount of inert gas that can enter into the cushion composition. Experimental studies along with field experience led to the conclusion that at least 20 % of the cushion gas can be replaced by inert gas without causing any inconvenience in field operations. Given the planned goals, the inert-gas must not be reactive with the products and materials with which it comes into contact : surface equipment, well completion, reservoir rocks. Thus, inert gas must be essentially free of oxydating compounds, nitrogen oxides and sulfurated products. Furthermore, it must not constitute an explosive mixture with natural gas (gas mixtures bearing more than 8 % oxygen, like air, are therefore excluded). In general, nitrogen and mixtures of nitrogen and carbon dioxide meet these requirements. Seasonal modulation storages are of limited capacity and injection operations on one site will not cover the life span of the producing plant. Given that the storage locations are scattered over France, inert gas production units developed for this application must satisfy the following requirements : – transportability from site to site at reasonablecost and delay, – adaptability to variable discharge pressures, – complete autonomy of the units : only operating power (electricity or fuel gas) is supplied from outside. P. 309