First Field Application in Canada of Carbon Dioxide Separation for Hydraulic Fracture Flow Back Operations

Liquefied natural gas (LNG) is a small but growing share of the global natural gas market. Global consumption of natural gas rose by 2.4 per cent between 2005 and 2015. The majority (70 per cent) of consumption relies on indigenous production. Most of the rest comes from pipelines, with LNGsourced natural gas growing from seven to nine per cent of consumption between 2005 and 2015.Global LNG imports increased rapidly between 2005 and 2011, rising from 193 to 334 billion cubic metres annually. They have stayed relatively constant since, averaging 324 billion cubic metres annually. Europe and Asia and Oceania are the primary recipients of LNG imports, accounting for 90 per cent of global imports from 2005 to 2015.An increase in global LNG liquefaction terminals accompanied the rise in imports. From 2005 to 2015, the number of liquefaction terminals increased from 20 terminals in 13 countries to 38 terminals in 20 countries. Total global liquefaction capacity rose by almost 90 per cent, mostly in the Middle East.The growth in LNG is largely attributable to an increasing mismatch between areas of natural gas supply and demand. As of 2016, the world’s natural gas reserves were estimated at 194,782 billion cubic metres, with the Middle East and Russia and Eurasia having the largest shares, respectively.Despite having smaller reserves, the largest gas-producing region is North America, which accounted for 26 per cent of global production from 2005 to 2015. Production in North America – and specifically the United States – steadily increased over this period as a result of advances in horizontal drilling and hydraulic fracturing and a corresponding surge in shale gas.More so than other energy sources, the gaseous nature of natural gas has historically made it difficult to trade. This contributed to a rise in regional markets, with corresponding variation in prices. From 2010 to 2015 the LNG price in Asia was significantly higher than natural gas prices in Europe, which were in turn higher than prices in North America. These price differentials incited what was frequently referred to as the “LNG race,” with project proponents seeking to lock-in supply contracts and secure final investment decisions for new LNG liquefaction terminals.Although price differentials still remain, they have narrowed considerably since the start of the oil price crash in 2014. Lower prices, combined with a growing surplus of LNG liquefaction capacity, has led to a significant slowdown in the approval of new LNG liquefaction terminals in recent years.Looking ahead, however, another opportunity for LNG development lies on the horizon. Even if governments enact stringent measures to curb greenhouse gas emissions, natural gas production and consumption is expected to keep growing – the only fossil fuel to do so. Forecasts also suggest that the mismatch between areas of supply and demand will continue to become more pronounced.Production growth in the Middle East, Russia and Eurasia, North America and Africa is forecast to exceed growth in demand. Correspondingly, all three regions are anticipated to have a growing natural gas surplus through to 2040. In contrast, Europe and Asia and Oceania both currently have natural gas deficits that are also forecast to grow.New infrastructure will be critical to getting natural gas to consumers. While pipelines remain the cheaper option for transporting natural gas, Russia and Eurasia is the only major producing region with significant or planned pipeline access to external demand markets. As a result, it is expected that a second wave of new LNG capacity will be required by the mid-2020s.Having missed out on the first LNG race, this second development window offers the most promising opportunity for proposed Canadian export facilities to enter the global LNG market. With numerous proposals for new liquefaction terminals on standby around the globe, however, this next wave of LNG development will again be highly competitive. It is therefore important that Canadian firms and investors act now to manage investment risks and position themselves to proceed with proposed projects as soon as the next window opens. Moreover, Canadian governments have an important role in ensuring the stability of policy and regulatory environments underpinning Canada’s attractiveness as an investment destination.

Liquefied natural gas (LNG) is a small but growing share of the global natural gas market. Global consumption of natural gas rose by 2.4 per cent between 2005 and 2015. The majority (70 per cent) of consumption relies on indigenous production. Most of the rest comes from pipelines, with LNGsourced natural gas growing from seven to nine per cent of consumption between 2005 and 2015. Global LNG imports increased rapidly between 2005 and 2011, rising from 193 to 334 billion cubic metres annually. They have stayed relatively constant since, averaging 324 billion cubic metres annually. Europe and Asia and Oceania are the primary recipients of LNG imports, accounting for 90 per cent of global imports from 2005 to 2015. An increase in global LNG liquefaction terminals accompanied the rise in imports. From 2005 to 2015, the number of liquefaction terminals increased from 20 terminals in 13 countries to 38 terminals in 20 countries. Total global liquefaction capacity rose by almost 90 per cent, mostly in the Middle East. The growth in LNG is largely attributable to an increasing mismatch between areas of natural gas supply and demand. As of 2016, the world’s natural gas reserves were estimated at 194,782 billion cubic metres, with the Middle East and Russia and Eurasia having the largest shares, respectively. Despite having smaller reserves, the largest gas-producing region is North America, which accounted for 26 per cent of global production from 2005 to 2015. Production in North America – and specifically the United States – steadily increased over this period as a result of advances in horizontal drilling and hydraulic fracturing and a corresponding surge in shale gas. More so than other energy sources, the gaseous nature of natural gas has historically made it difficult to trade. This contributed to a rise in regional markets, with corresponding variation in prices. From 2010 to 2015 the LNG price in Asia was significantly higher than natural gas prices in Europe, which were in turn higher than prices in North America. These price differentials incited what was frequently referred to as the “LNG race,” with project proponents seeking to lock-in supply contracts and secure final investment decisions for new LNG liquefaction terminals. Although price differentials still remain, they have narrowed considerably since the start of the oil price crash in 2014. Lower prices, combined with a growing surplus of LNG liquefaction capacity, has led to a significant slowdown in the approval of new LNG liquefaction terminals in recent years. Looking ahead, however, another opportunity for LNG development lies on the horizon. Even if governments enact stringent measures to curb greenhouse gas emissions, natural gas production and consumption is expected to keep growing – the only fossil fuel to do so. Forecasts also suggest that the mismatch between areas of supply and demand will continue to become more pronounced. Production growth in the Middle East, Russia and Eurasia, North America and Africa is forecast to exceed growth in demand. Correspondingly, all three regions are anticipated to have a growing natural gas surplus through to 2040. In contrast, Europe and Asia and Oceania both currently have natural gas deficits that are also forecast to grow. New infrastructure will be critical to getting natural gas to consumers. While pipelines remain the cheaper option for transporting natural gas, Russia and Eurasia is the only major producing region with significant or planned pipeline access to external demand markets. As a result, it is expected that a second wave of new LNG capacity will be required by the mid-2020s. Having missed out on the first LNG race, this second development window offers the most promising opportunity for proposed Canadian export facilities to enter the global LNG market. With numerous proposals for new liquefaction terminals on standby around the globe, however, this next wave of LNG development will again be highly competitive. It is therefore important that Canadian firms and investors act now to manage investment risks and position themselves to proceed with proposed projects as soon as the next window opens. Moreover, Canadian governments have an important role in ensuring the stability of policy and regulatory environments underpinning Canada’s attractiveness as an investment destination.

Offering numerous ports with the shortest shipping distances to Europe from North America, Eastern Canada has the potential to be a player in the European liquefied natural gas (LNG) market. However, the slower-moving nature of proposed projects on Canada’s East Coast, combined with a glut of global LNG liquefaction capacity, means it will likely be difficult for Canadian projects to gain a foothold in the market in the near term. As just one player in the worldwide competitive market, Eastern Canada will face challenges keeping up with faster-moving and lower-cost entrants, particularly those on the U.S. Gulf and East Coasts. Geography, too, is a double-edged sword for proposed projects in Quebec and the Maritime provinces. While they offer the benefit of proximity to Europe, they are located significant distances from Canada’s major natural-gas-producing provinces of British Columbia and Alberta. Further, there are no direct natural gas pipelines connecting proposed projects to supply sources in either Western Canada or the Northeastern U.S. This places these projects at a significant disadvantage relative to projects on the U.S. Gulf Coast. The latter are located in a petrochemical hub, complete with major infrastructure connections to numerous sources of natural gas supply. Also working against Eastern Canadian LNG development is anti-pipeline and anti-fossil fuel sentiments across the country. These sentiments are slowing Canada’s regulatory process and have also contributed to the establishment of moratoriums on hydraulic fracturing in three Maritime provinces. This virtually rules out local supply sources of natural gas for export from Canada’s East Coast in the near term. None of this necessarily means, however, that Eastern Canada’s future in LNG exports is doomed. Reason for optimism remains and it centres on indications that European countries are looking to diversify their natural gas supply sources and are prioritizing geopolitically stable and environmentally responsible supplies. Canada is a world benchmark for that kind of stability, thus making it a dependable, reliable supplier unshaken by whichever way the geopolitical winds are blowing. The kind of stability Canada offers will be key to obtaining long-term LNG supply contracts and the financial capital accompanying them to build pipelines and LNG export facilities. In 2015 the NEB granted export licenses for six proposed LNG export facilities on Canada’s East Coast. Since then, one project was cancelled and the remaining five have repeatedly pushed back their timelines. This has left Canada in a limbo of sorts, but it can extricate itself. Market entry in the 2020s is within reach and aligns with a current opening in the European LNG contract market. Canada must move faster, however, if it is going to compete with the U.S., which currently has two operating LNG export facilities and an additional four under construction. The longer Canada’s process, the more likely that, for example, countries in Europe wanting to wean themselves off unstable Russia as a supplier, will turn to the U.S. rather than Canada. Windows of opportunity continually open and close for entrance to any LNG market. For Eastern Canada to compete in the European market it will need secure supplies of natural gas, and investment and long-term contracts to shore up the financing for building the necessary export infrastructure. For all those things to work in harmony, Canada must pick up the pace and deviate from the status quo or risk losing out entirely.

Walking the Wall

The overall objective of this project is to develop a new low-cost and energy efficient Natural Gas Liquid (NGL) recovery process - through a combination of theoretical, bench-scale and pilot-scale testing - so that it could be offered to the natural gas industry for commercialization. The new process, known as the IROA process, is based on U.S. patent No. 6,553,784, which if commercialized, has the potential of achieving substantial energy savings compared to currently used cryogenic technology. When successfully developed, this technology will benefit the petrochemical industry, which uses NGL as feedstocks, and will also benefit other chemical industries that utilize gas-liquid separation and distillation under similar operating conditions. Specific goals and objectives of the overall program include: (i) collecting relevant physical property and Vapor Liquid Equilibrium (VLE) data for the design and evaluation of the new technology, (ii) solving critical R&D issues including the identification of suitable dehydration and NGL absorbing solvents, inhibiting corrosion, and specifying proper packing structure and materials, (iii) designing, construction and operation of bench and pilot-scale units to verify design performance, (iv) computer simulation of the process using commercial software simulation platforms such as Aspen-Plus and HYSYS, and (v) preparation of a commercialization plan and identification of industrial partners that are interested in utilizing the new technology. NGL is a collective term for C2+ hydrocarbons present in the natural gas. Historically, the commercial value of the separated NGL components has been greater than the thermal value of these liquids in the gas. The revenue derived from extracting NGLs is crucial to ensuring the overall profitability of the domestic natural gas production industry and therefore of ensuring a secure and reliable supply in the 48 contiguous states. However, rising natural gas prices have dramatically reduced the economic incentive to extract NGLs from domestically produced natural gas. Successful gas processors will be those who adopt technologies that are less energy intensive, have lower capital and operating costs and offer the flexibility to tailor the plant performance to maximize product revenue as market conditions change, while maintaining overall system efficiency. Presently, cryogenic turbo-expander technology is the dominant NGL recovery process and it is used throughout the world. This process is known to be highly energy intensive, as substantial energy is required to recompress the processed gas back to pipeline pressure. The purpose of this project is to develop a new NGL separation process that is flexible in terms of ethane rejection and can reduce energy consumption by 20-30% from current levels, particularly for ethane recoveries of less than 70%. The new process integrates the dehydration of the raw natural gas stream and the removal of NGLs in such a way that heat recovery is maximized and pressure losses are minimized so that high-value equipment such as the compressor, turbo-expander, and a separate dehydration unit are not required. GTI completed a techno-economic evaluation of the new process based on an Aspen-HYSYS simulation model. The evaluation incorporated purchased equipment cost estimates obtained from equipment suppliers and two different commercial software packages; namely, Aspen-Icarus and Preliminary Design and Quoting Service (PDQ$). For a 100 MMscfd gas processing plant, the annualized capital cost for the new technology was found to be about 10% lower than that of conventional technology for C2 recovery above 70% and about 40% lower than that of conventional technology for C2 recovery below 50%. It was also found that at around 40-50% C2 recovery (which is economically justifiable at the current natural gas prices), the energy cost to recover NGL using the new technology is about 50% of that of conventional cryogenic technology.

The close of 2014 ended a lively and prodigious year for energy. This follows $1.6 trillion in energy investments “to provide the world’s consumers with energy” in 2013 — a year in which energy production and consumption levels reached “record levels for every fuel type except nuclear power.” While the 2014 statistics had yet to be released at the time this article was completed, those in the energy field and observers alike undoubtedly saw 2014 as yet another instance of energy bolstering its status as one of the preeminent global issues of the 21st century.The natural gas sector — and liquefied natural gas (LNG) particularly — saw significant movement in 2014. In fact, long-term global growth is expected on the order of up to $500 billion in LNG development by 2025. The United States is seeing a considerable portion of this development due to massive underground natural gas reserves that have been unlocked through multi-directional drilling and hydraulic fracturing, which has opened the door to natural gas exports when, only a few years earlier, the United States was projected to be a growing natural gas importer. The year 2014 was, in a way, the visible beginning of a U.S. LNG export transformation — visible in the sense that approvals were granted for, and construction started on, a number of facilities seeking to export LNG produced in the United States. The United States Department of Energy (DOE) and the Federal Energy Regulatory Commission (FERC) authorized four LNG liquefaction and export terminals (at least conditionally) to site, construct, expand, and operate those facilities and export up to several billion cubic feet per day globally. These approvals mark one of the most recent shifts in the U.S. LNG market over the last 50 years, though another wrinkle came to the forefront in the fourth quarter of 2014: oil prices slid to nearly half of their opening value at the beginning of 2014, and in the process, at least partially quelled U.S. LNG export enthusiasm.This article is a guide to exploring the U.S. LNG liquefaction and export sectors, and specifically, how these sectors progressed over 2014. Part I of this article summarizes the natural gas lifecycle from underground wells to end-users on the opposite side of the globe. Part II then provides a brief history of U.S. LNG imports and exports. Part III outlines the processes necessary to obtain authorizations from the DOE and FERC, which differ depending on where the natural gas originated and its destination. Part IV provides information and statistics regarding four U.S. LNG liquefaction and export projects that received federal approvals in 2014 to site, construct, expand, and operate LNG terminals and export LNG to Free Trade Agreement (FTA) and non-FTA nations. Part V highlights some of the environmental, security, and community concerns that are being considered by stakeholders.

While remote parts of the world are awash with hundreds of trillions of cubic feet (Tcf) of natural gas, the industrialized West and emerging economies of the East can't get enough of the clean-burning, environmentally friendly fuel. The problem is transporting this compressible fluid long distances, across major bodies of water. For markets greater than 1,500 miles, liquefied natural gas (LNG) has proved to be the most economic option. By refrigerating natural gas (primarily methane) to -260°F (-162°C), thereby shrinking its volume by 600:1, LNG can be transported in large insulated cryogenic tankers at reasonable cost. Natural gas liquefaction is a series of refrigeration systems similar to the air conditioning system in our homes consisting of a compressor, condenser and evaporator to chill and condense the gas. The difference is in the scale and magnitude of the refrigeration. A typical single-train LNG plant may cost $1.5 billion and consume 6-8% of the inlet gas as fuel. Since many of the impurities (water vapor, carbon dioxide, hydrogen sulfide, etc.) and heavier hydrocarbon compounds in natural gas will freeze at LNG temperatures, they must first be removed, and disposed or marketed as separate products. This paper will provide an overview of LNG liquefaction facilities, from inlet gas receiving to LNG storage and loading. However, the focus is on the liquefaction process and equipment. Differences among the commercially available liquefaction processes (cascade, single mixed refrigerant, propane-pre-cooled mixed refrigerant, double mixed refrigerant, nitrogen, etc.) will be discussed. The aim is to provide SPE members with a clear understanding of the technologies, equipment and process choices required for a successful LNG project.

Summary While remote parts of the world are awash with hundreds of trillions of cubic feet (Tcf) of natural gas, the industrialized West and emerging economies of the East cannot get enough of the clean-burning, environmentally friendly fuel. The problem is transporting this compressible fluid long distances and across major bodies of water. For markets more than 1,500 miles distant, liquefied natural gas (LNG) has proved to be the most economic option. By refrigerating natural gas (primarily methane) to–260°F (–162°C), thereby shrinking its volume by 600:1, natural gas in the form of LNG can be transported in large insulated cryogenic tankers at a reasonable cost. Natural-gas liquefaction is a series of refrigeration systems similar to home air-conditioning (AC) systems, consisting of a compressor, condenser, and evaporator to chill and condense the gas. The difference is in the scale and magnitude of the refrigeration. A typical single-train LNG plant may cost USD 1.5 billion and consume 6 to 8% of the inlet gas as fuel. Because many of the impurities (e.g., water vapor, carbon dioxide, hydrogen sulfide) and heavier hydrocarbon compounds in natural gas would freeze at LNG temperatures, they must first be removed and disposed of or marketed as separate products. This paper will provide an overview of LNG liquefaction facilities, from inlet gas receiving to LNG storage and loading. However, the focus is on the liquefaction process and equipment. Differences among the commercially available liquefaction processes (e.g., cascade, single mixed refrigerant, propane precooled mixed refrigerant, double-mixed refrigerant, nitrogen) will be discussed. The aim is to provide SPE members with a clear understanding of the technologies, equipment, and process choices required for a successful LNG project.

Foams have been used as hydraulic fracturing fluids to reduce water usage and minimize the potentially deleterious impact on water-sensitive formations. Traditionally, carbon dioxide (CO2) and nitrogen (N2) have been used as the internal phase in these foamed fluids. Hydraulic fracturing with natural gas (NG) is a relatively inexpensive option, particularly if NG produced from the wellhead can be used without significant processing. In an ongoing program sponsored by the US Department of Energy (DOE), an alternative fracturing process is being developed that uses NG-based foam. Previously, the optimal thermodynamic pathway was identified to transform wellhead NG into pressurized NG suitable for use as the internal phase in a foamed fracturing fluid. Recent work has focused on preparing a NG-based foam at surface conditions typically encountered in hydraulic fracturing and measuring the stability and rheological properties of the foam. In addition, the transient response of the foam during fracture initiation was simulated using a fast-acting solenoid valve. A single base-fluid mixture was prepared by combining a commercially available viscosifier and foaming surfactant with water. The base fluid was then injected into a tee using a water pump. Simultaneously, liquefied natural gas (LNG) was pressurized using a cryogenic pump, vaporized using a heat exchanger, and injected into the tee to mix with the base fluid and generate foam. The foam then flowed through approximately 300 ft of 0.312-in. inside diameter (ID) tubing equipped with pressure transducers at several locations. The test fixture included a sight glass to visually inspect the quality of the foam. This paper reports on findings related to foam stability and rheology and compares these results to previous studies on foamed fracturing fluids.

Nigeria is the latest entrant in the world LNG market. This paper evaluates the economics of Nigerian LNG in light of prevailing trends in the supply, demand and pricing of LNG worldwide. Using competitive netback pricing, the economics of the new Nigerian LNG project is analyzed with respect to the LNG markets in the USA, France, Japan and India. The economics of nearby LNG competitors from Algeria and Qatar are also analyzed. A comparison show that the gas markets in Japan and India are uneconomical for Nigerian LNG. Aggressive marketing is required in the USA and European markets for Nigerian LNG to become competitive with Algerian LNG. Finally, the future prospects for Nigerian LNG are highlighted given stability in current comparative netback prices. Introduction Natural gas is a clean burning fuel. It is the environmentally preferred fuel for power generation. A gas-fired power plant produces no particulate and less gaseous pollutants (CO, CO2 and N2) than a coal-fired plant. The introduction of new technology like the combined-cycle gas technology makes gas-based power generation more economical. A combined cycle gas turbine power plant with the most modern technology will cost less than 50% of a comparable coal fired plant.1 Combined cycle gas turbines have lower capital cost and higher efficiency. Therefore, there is an economic incentive for nations to build gas-fired power plants and diversify their energy base. Liquefied Natural Gas (LNG) has its root in electricity generation. The use of natural gas for peak shaving required the storage of the gas until it was needed for power generation. The natural gas was liquefied and stored in tanks. The liquefaction of natural gas raised the possibility of its transportation to distant destinations. In January 1959, the world's first LNG tanker (the Methane Pioneer) carried a LNG cargo from Lake Charles, LA, USA to Canvey Island, UK. Thus, the world trade in LNG began. The objective of this paper is to examine the economics of Nigerian LNG. The economics of natural gas is different from that of crude oil. It costs four times more to move natural gas by pipeline than it does to move crude oil. In the case of tankers, it cost twelve times more to move natural gas than crude oil.2 Hence, unlike oil reservoirs, gas reservoirs are usually developed in one phase. Gas surface and production facilities must be developed at the onset. This increases the up-front lump investment required for takeoff. The economics of LNG calls for emphasis on liquefaction, transportation and regasification. The LNG chain requires precision to remain viable. Everything must be in place before a contract can be signed and a gas field developed. In short, the LNG must be sold before it is produced. Contracts between buyers and sellers are often long term at fixed prices. The price is very important, requiring about $3.00 per MMBTU in June 2000 to break even. In this paper, we examine the supply, demand, pricing and future prospects of Nigerian LNG. Supply The world natural gas reserves increased by 45.18% from 109,350 bn cm (billion cubic metres) in 1986 to 158,751 bn cm in 1998. Table 1 shows the world proven natural gas reserves by country in 1998. The Middle East had 33.74% of the world proven natural gas reserves. Eastern Europe (including the former USSR) had 36.1% while Africa had 6.8%. The most prominent nations were Russia with 56,677 bn cm, Iran (24,200 bn cm) and Qatar (10,900 bn cm). The three largest fields were the North Field in Qatar and the Urengoi and Yamburg fields in Russia.

Natural gas consists primarily of mixtures of hydrocarbon gases, predominantly methane, along with smaller amounts of natural gas liquids and non-hydrocarbons. This paper provides descriptively and quantitatively a framework for evaluating and balancing the potential sources of natural gas liquids supply and demand in the province of Alberta for the period 1988 to 2000. Introduction Natural gas consists primarily of mixtures of hydrocarbon gases, predominantly methane, along with smaller amounts of ethane, propane, butanes and pentanes plus which are called natural gas liquids (NGLs), and non-hydrocarbons such as nitrogen, oxygen, water, carbon dioxide, hydrogen sulphide, and mercaptans. Ethane is a part of natural gas which can be separated out (through application of high pressure and temperatures) at gas plants. Ethane is an important petrochemical feedstock for the production of ethylene. It is also used as a miscible agent for enhanced oil recovery. Propane and butanes are by-products of natural gas and crude oil feed to distilling, which are obtained from gas plants and refineries. Propane is used primarily as a fuel and as miscible flood for enhanced oil recovery. However, in contrast to propane, butanes are used primarily as feedstock in refineries and petrochemical plants. They are seldom used in miscible floods except when entrained in NGL mixes. Pentanes plus is a by-product of natural gas which is obtained from gas plants as well as condensate from crude oil. Pentanes plus is used as a refinery feedstock and as a diluents in reducing viscosity of bitumen and conventional heavy crude oil to allow conventional pipelining. The purpose of this paper is to describe and project supply and demand for NGLs in the province of Alberta for the period 1988 to 2000. The Gas Energy Management Model (GEMM) and Energy Requirements Model of Alberta (ERMA) are used for the projections of supply and demand for NGLs, respectively. The major assumptions used for both models are adopted from the high case of "Energy Requirements in Alberta, ERCB Report 89-A ". The high case is an optimistic pricing scenario from an upper bound forecast that assumed the plant gate price of natural gas (in 1988 constant dollars) would increase to $4.36 per GJ by the year 2000 from the 1988 level of $1.57 per GJ. Because the projections of NGLs are shown in petajoules, the approximate volume equivalent of one petajoule for each liquid is as follows: List of NGLs are shown in petajoules (Available In Full Paper) In the first section of this paper, three sources of NGL supply are described. In the second section, uses of NGLs within Alberta are identified. In the third section, the projection of supply and demand for NGLs along with the major input assumptions are described. In the last section, NGL supply and demand balances are presented. Alberta Sources of Natural Gas Liquids In Alberta, the supply sources of gas co-products (NGL and sulphur) are gas processing and reprocessing plants* and crude oil refineries. The main products of gas processing plants are propane, butanes and pentanes plus.

Liquefied natural gas (LNG) exports from the United States have risen dramatically since the LNG‐export ban was lifted in 2016, and the United States is now the world's largest exporter. This LNG is produced largely from shale gas. Production of shale gas, as well as liquefaction to make LNG and LNG transport by tanker, is energy‐intensive, which contributes significantly to the LNG greenhouse gas footprint. The production and transport of shale gas emits a substantial amount of methane as well, and liquefaction and tanker transport of LNG can further increase methane emissions. Consequently, carbon dioxide (CO2) from end‐use combustion of LNG contributes only 34% of the total LNG greenhouse gas footprint, when CO2 and methane are compared over 20 years global warming potential (GWP20) following emission. Upstream and midstream methane emissions are the largest contributors to the LNG footprint (38% of total LNG emissions, based on GWP20). Adding CO2 emissions from the energy used to produce LNG, total upstream and midstream emissions make up on average 47% of the total greenhouse gas footprint of LNG. Other significant emissions are the liquefaction process (8.8% of the total, on average, using GWP20) and tanker transport (5.5% of the total, on average, using GWP20). Emissions from tankers vary from 3.9% to 8.1% depending upon the type of tanker. Surprisingly, the most modern tankers propelled by two‐ and four‐stroke engines have higher total greenhouse gas emissions than steam‐powered tankers, despite their greater fuel efficiency and lower CO2 emissions, due to methane slippage in their exhaust. Overall, the greenhouse gas footprint for LNG as a fuel source is 33% greater than that for coal when analyzed using GWP20 (160 g CO2‐equivalent/MJ vs. 120 g CO2‐equivalent/MJ). Even considered on the time frame of 100 years after emission (GWP100), which severely understates the climatic damage of methane, the LNG footprint equals or exceeds that of coal.

Simulation and Optimization of an LNG Plant Cold Section

With current technology, the majority of natural gas is transported from points of production to points of consumption in one of two ways, via pipeline or as liquefied natural gas (LNG). Pipeline networks are expensive to build, lay and maintain, such that only overland or somewhat shorter undersea routes can be considered. Cryogenic liquefaction of natural gas serves to permit transport over intercontinental distances, thereby allowing access to a much larger and more diverse market. The principal benefit of transporting natural gas in liquid state is the 600-fold reduction in volume that occurs with the vapor-to-liquid phase change. Both transport mediums require some form of gas sweetening treatment to reduce or remove impurities such as water, carbon dioxide, and hydrogen sulfide. For pipelines, however, the tolerance to contaminants is several orders of magnitude higher than for the liquefaction process. The stringent specifications applied to natural liquefaction for contaminant removal are necessary to prevent blockages in the system caused by solids development. Such gas purification not only removes the components mentioned above, but also heavier hydrocarbons. Almost all natural gases contain some components which solidify when natural gas is transformed to LNG at atmospheric pressure. Inert gases, such as argon and helium, are also removed during the cryogenic process. A cryogenic gas separation technology has been developed at Curtin University to sweeten gas using the cryogenic distillation principles [1,2].The technology results in a compact module, known as the Cryocell, which is portable and can be easily accommodated on production platforms; it is energy efficient and can process a wide variation in feed gas composition. Up to 70% carbon dioxide as a contaminant of the natural gas volume has been successfully removed down to less than 200 PPM during laboratory trials. Introduction Natural gas liquefaction (LNG) is a mature technology for monetizing remote gas. Over the past 30 years, tremendous technology advances in LNG plant configuration, efficiency, equipment design and materials of construction have been recorded. The capacity range for a single onshore LNG train, is around 4.2 MMTPY.

Dynamic spillovers among natural gas, liquid natural gas, trade policy uncertainty, and stock market