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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.
- Asia (1.00)
- Europe (0.93)
- North America > United States > Texas (0.28)
- South America > Atlantic Basin (0.99)
- North America > Atlantic Basin (0.99)
- Europe > Norway > Barents Sea > Hammerfest Basin > License 100 > Block 7121/7 > Snøhvit Field > Stø Formation (0.99)
- (34 more...)
Summary In the mid-1990s, our client realized that their recent offshore find would yield viable liquefied-petroleum-gas (LPG) content. With the proposed field located more than 20 nautical miles offshore from an underdeveloped area, the option of exploitation on site was identified. Oil floating storage/offloading (FSO) units, usually adaptations of existing oil tankers, were already an established alternative to piping product ashore at that time. Therefore, tenders were invited for the provision of an LPG FSO unit. Any party tendering for this task would be covering new ground because this installation would be among the first of its kind. In particular, the physical properties of LPG demand different handling systems and techniques compared to oil. In tendering, we drew from the diverse marine enterprises within our group. We also engaged a partner specialized in offshore solutions. We had access to existing LPG tonnage of suitable capacity and our own yard for conversion work. We also had a competent technical support structure and potential within our personnel base for operational requirements. As with any new project, once tender requirements were met and accepted, evolution occurred. This evolution is of course not limited to the period leading up to commissioning but has continued through to the present. It is often the case that delivery of a specialized service holds a narrow spectrum of interest. However, it is our hope that this project, although relatively specialized, may also have value for any concern engaged in offshore storage and offloading. By this time, we have operated the unit for almost 15 years and can share some valuable experience.
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Downstream (1.00)
- Transportation > Freight & Logistics Services > Shipping > Tanker (0.34)
Leveraging a Common Infrastructure To Support Qatar's Rapid LNG Expansion
Al-Amoodi, Ahmed (Qatar Petroleum) | Felton, Keith C. (Qatargas Operating Company Limited) | Kasim, Kamal (RasGas Company Limited) | Whitehead, Mike (RasGas Company Limited) | Kouki, Khaled (Qatargas Operating Company Limited)
Summary The State of Qatar is rapidly expanding to capture almost one-third of the world's liquefied-natural-gas (LNG) market. By 2010, LNG exports from the State of Qatar are projected to reach 77 million tonnes per annum (Mt/a) (This was the outlook in late 2009). In addition to the LNG production, there will be a sizeable quantity of byproducts (condensate, propane, butane, and sulfur) as a result of the LNG production. These byproducts are expected to reach production rates of approximately 80 000 m/d [500,000 barrels per day (B/D)] of condensate, 20 000 tonnes per day (t/d) of propane, 13 000 t/d of butane, and 12 000 t/d of sulfur. To support this expansion, the State of Qatar has embarked on a pioneering approach to the storage and loading of LNG and its byproducts that will serve as an example of significant capital-investment savings, operational flexibility, and reduced land requirements. Traditionally, dedicated storage and loading facilities (infrastructure) have been designed and built to support a specific LNG production train and its associated byproducts. The State of Qatar's innovative approach has been the design and construction of a fully integrated common infrastructure to support all of the joint-venture-owned LNG production trains and other gas-related projects in Ras Laffan Industrial City (RLC). This paper will describe the unique aspects of this fully integrated infrastructure, its benefits, and the complexities and challenges associated with making the vision of a fully integrated LNG infrastructure come to fruition.
Summary Natural gas is becoming a more popular energy source worldwide and its use is expected to increase dramatically over the next 2 decades. Natural gas has been gaining wider significance as a result of sustained high oil prices, a need for energy diversification and security, the growing global awareness of environmental issues, and the development of new gas-related technologies. Traditionally natural gas has been delivered to markets using two main commercially proven methods—pipelines and liquefied natural gas (LNG). Each of these alternatives is highly capital intensive and requires considerable working terms regarding the quantities and distances to market. In other words, these two methods are economical only over a specified range of quantities and distances and not over the whole range, which opens the door to a number of alternative technologies that have the potential to make the development for smaller quantities to be transported to specific distances. The most advanced among these alternative technologies include onshore gas-to-liquid (GTL), floating LNG and GTL, natural-gas hydrates (NGH), adsorbed natural gas (ANG), and compressed natural gas (CNG). However, none of these has been developed yet and been proved on a commercial scale, although they have proved themselves viable on the basis of technical parameters. This paper will be concerned mainly with (1) marine CNG alternatives, which are currently in their final stages of commercialization, indicating the various available marine CNG technologies used worldwide; (2) the operating differences between LNG and CNG transportation; (3) technical and economic evaluation of both the obstacles facing the commercialization of marine CNG transportation and its advantages.
Summary Liquefied natural gas (LNG) is anticipated to dominate world energy trade and fill the gap between production and energy demands in a few years, especially in the US. LNG is the liquefied version of dry natural gases at ultralow temperatures (approximately -160ºC or -260ºF at atmospheric pressure), which aims at minimizing storage volume requirements needed for overseas transportation. Within this context, it is clear that technology must continue to be developed to optimize the thermodynamic processes involved in the compression, liquefaction, and revaporization of LNG and associated operational challenges. One key challenge during the production of LNG is the presence of trace amounts of heavy components in the gas feed composition is known to induce the precipitation of a solid phase during the cooling process, which presents the risk of equipment plugging and associated hazards. However, there are very few general thermodynamic tools available for the prediction of solid-liquid equilibrium for very low-temperature conditions (< 200ºF). In this study, available thermodynamic predictive tools are evaluated for the determination of LNG crystallization conditions. Previously presented crystallization prediction models are examined, and potential pitfalls identified. The results from this study are expected to provide a better understanding of the thermodynamics of LNG processes and provide a framework for subsequent work in the analysis of LNG refrigeration and liquefaction processes--typically considered the key elements of any LNG project. Introduction Imported natural gas is expected to play a dominant role in meeting the projected rise of natural gas consumption during the coming decade in many industrialized countries. Traditional pipeline transportation is not a viable method for transoceanic delivery of natural gas supplies and thus, LNG becomes the method of choice for their marketing. The world market for LNG is anticipated to become extremely competitive in a few years, with the US not the only nation set on increasing LNG imports. To close the gap between domestic production and demand, dependence on LNG imports plays a greater factor on a worldwide scale, which requires greater infrastructure for LNG capacity, including expansion of existing terminals and the construction of new facilities. Within this context, it is clear that technology must continue to be developed to optimize the thermodynamic processes involved in the compression, liquefaction, and revaporization of LNG and associated operational challenges. Proper combination of good engineering design, operation, and maintenance is what allows handling and producing LNG safely (West and Chiu 2005; Alderman 1972).
- Energy > Oil & Gas > Midstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.47)
Summary The world's first bottom-founded offshore liquefied natural gas (LNG) storage and regasification terminal is under development by affiliates of Qatar Terminal Limited, ExxonMobil, and Edison for installation in the Northern Adriatic, 15 km east of Porto Levante, Italy. This paper will describe the unique challenges faced and effort undertaken to locate and transform a casting basin to a world-class construction and integration site, including removal of the earthen wall prior to tow-out of the terminal. The concrete gravity-based structure (GBS) terminal enclosing two 125,000-m LNG tanks and supporting 8 GSCM regasification facilities will measure 180 m by 88 m and be located in 29 m of water. These dimensions, as well as proximity to Porto Levante, led to selection of the casting basin in the Spanish Bay of Algeciras as the construction and integration site. The site is under development by the Algeciras Port Authority for use as a container port, and therefore did not have the infrastructure needed to build the terminal. This paper will provide the basis for how parameters such as size, depth, layout, water and electricity supply, accessibility, dredging requirements, lease requirements, availability of workforce, and capacity for growth were established to result in an effective construction and integration site. Some of the execution technologies used for this terminal, such as removal of the earthen wall, installation of regasification facilities, and installation of the LNG tanks will also be described. The conclusions drawn in this paper can be utilized for upgrading of an existing construction site, or development of a Greenfield site into an effective facility for future GBSs, floating structures, or large-scale construction and integration projects. Background Adriatic LNG Terminal, the world's first offshore liquefied natural gas (LNG) receiving, storage and regasification terminal, is under development by affiliates of Qatar Terminal Limited, ExxonMobil, and Edison for installation in the Northern Adriatic, 15 km offshore just east of Porto Levante, Italy in 29 m of water. The substructure of the terminal consists of a concrete GBS with dimensions of 180 m × 88 m × 47 m. Two 125,000-m modular LNG tanks are housed inside the GBS, while the topsides facilities with 8 GSCM/year send-out capacity are located on the top. The export pipeline has a 30-in. diameter with a metering station near Cavarzere, Italy, tying into the Italian grid at Minerbio through a 36-in. line. The terminal will provide a berthing facility for 65,000- to 152,000-m LNG carriers. Fig. 1 shows a rendering of the terminal. The major components of the Adriatic LNG (ALNG) Terminal built by Terminale GNL Adriatico srl are the GBS substructure constructed in the bay of Algeciras, Spain; the LNG tanks fabricated in South Korea; topsides modules being fabricated in Cadiz, Singapore, and Sweden; and the mooring dolphins being constructed in Venice, Italy. Figs. 2a through 2d show photos taken at various stages of construction of these major components. The execution plan for the ALNG terminal consists of building the GBS at the deep casting basin site in Algeciras Bay, Spain, transporting the LNG tanks from South Korea to install into the GBS, transporting all the topsides modules and installing them on top of the GBS, removing the existing levee that keeps the basin dry and towing the fully integrated terminal to offshore Venice, where the mooring dolphins will be installed as well. Construction and Integration Site Selection One of the most important decisions during the execution planning of the ALNG Terminal Project was selecting the construction and integration site. In order to select the most appropriate location, more than 15 sites from western Europe through the Mediterranean to the Black Sea were evaluated based on particular criteria. All of the evaluated sites presented some advantages and challenges. For example, some of the sites were not selected because of their limited size or lack of adequate skilled labor to support a project of this magnitude. Others that were large enough and provided access to adequate labor required extensive dredging works to obtain the draft required for the execution plan (all installation and construction activities to be completed onshore). While some of the sites met the space and infrastructure requirements, because of the tow-route to offshore Venice, the available tow window was considered too restrictive. Another important criterion that led to elimination of some of the sites was the difficulty in obtaining the necessary permits for the development of the project. Last, but not least, the lease fee and availability of the site were other criteria that were evaluated before making the final decision to select the Algeciras Bay site. These criteria and how the Algeciras Bay site satisfied them are summarized in Table 1. The Algeciras Bay deep casting basin site is owned by the Algeciras Port Authority (APBA). APBA manages the 11th largest container port in Europe. Although the site is leased from APBA for construction and integration of the terminal, the Andalusian regional government and the San Roque local government also have jurisdiction over the site for regulatory purposes. The site is located in an industrial area with a refinery and chemical plant in the vicinity. The perimeter of the casting basin consists of mass concrete quay walls. The natural material behind these walls is very impermeable overconsolidated clay, which minimizes the amount of seepage into the basin. The basin was previously used for the construction of a concrete breakwater structure for Monaco and is included in APBA's plans for use as a container port. Figs. 3a and 3b show the Algeciras Bay site in November of 2003, before the ALNG Terminal Project and March 2007 after the arrival of the LNG tanks from South Korea.
Summary The need for additional underground gas storage (UGS) in Europe and in France is increasing. TOTAL has therefore undertaken feasibility studies to convert the depleted Pécorade oil field, situated in South West France, into an UGS. The Pécorade field offers a number of positive characteristics which make it a good candidate for UGS, but it is also deep at 2500 m and contains hydrogen sulphide. This paper describes some of the challenges faced by the project, including:The sizing of the working volume (volume of gas which can be stored and cycled each year), which required the acquisition and processing of a new 3D seismic program, and the construction of specific geological and reservoir models. The safety and environmental issues related to caprock integrity and sour-gas production. The conversion of existing oil and gas wells into gas injection and production wells. The processing of cycled gas (including sour-gas treatment). The cost of the project compared to more conventional UGSs. The main benefits expected from the project are:The development of a sizeable working volume, in the order of one billion cubic meters, in an ideal location to serve the French and possibly Spanish market. An improved oil recovery, as the annual cycling of the gas would induce production of an additional 20 to 30% over current projections. These studies also confirmed that the development of a sizeable UGS is a lengthy, difficult, and complex project. The decision to launch the project is mainly dependent on the results of the future preproject studies, regulations, and market conditions. Introduction While Europe's gas consumption is increasing, domestic gas production is declining, and gas imports are on the rise. Therefore Europe is eager to secure additional gas imports, cater for seasonal gas demand, and prevent supply shortages. One of the means to achieve these targets is the development of new underground gas storage (UGS), and it is estimated that Europe UGS capacity must at least double in the next 25 years (Plan Indicatif 2006). France has not been endowed with a proliferation of oil- and gas-bearing reservoirs, and as a result the vast majority of existing UGS are of the aquifer type. However, the development of this type of UGS is now facing more stringent environmental regulations, and therefore TOTAL has undertaken studies to convert the depleted Pécorade oil field into a UGS. The Pécorade field is situated in South West France, 150 km from Bordeaux, and has produced oil since 1978 (Fig. 1). The field was selected as a possible UGS after a screening study of the oil and gas fields situated in the area. Pécorade presents the following advantages:It is situated near an existing gas pipeline network. It has a proven gas capacity, as it contained an initial gas cap. It is depleted, with reservoir pressure having declined from an initial pressure of 26.5 MPa to today's 10 MPa. It has proven caprock integrity. However, the reservoir is deep by UGS standards at 2500 m and contains hydrogen sulphide. These are major disadvantages and drive the development cost of UGS up. Therefore, a feasibility study was launched and completed to assess the possibility of economically converting this oil field into a UGS. This paper describes the feasibility studies performed and the particular challenges overcome during the project evaluation.
- North America > Canada > Alberta > French Field > Arl French 16-26-64-1 Well (0.99)
- Europe > France > Nouvelle-Aquitaine > Lacq Basin > Lacq Field (0.99)
- Europe > France > Nouvelle-Aquitaine > Aquitaine Basin > Pecorade Field (0.99)
- Reservoir Description and Dynamics > Storage Reservoir Engineering > Natural gas storage (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Gas storage facility design (1.00)
Summary Liquefied natural gas (LNG) has yet to be deployed in the development of offshore fields in spite of several detailed studies completed and offshore technology development demonstrating its technical feasibility. The perceived risks associated with deploying unproven technology in a high construction cost and volatrile gas price environment have so far inhibited offshore liquefaction projects. The potential deployment of such technologies is of paramount importance considering the massive volumes of natural gas currently deemed as "stranded" and the exploitation of which is compelling not only because of the inherent economic benefit but also because of the otherwise adverse impact on oil production. It is conceivable that deep water offshore locations may contain quantities of natural gas rivalling those of onshore locations. Such a statement cannot even be confirmed because drilling for offshore natural gas reservoirs, expected to be found considerably deeper than oil reservoirs, has been unattractive exactly because of the absence of coherent exploitation strategies. If anything, the mere presence of large natural gas deposits even in the form of solution gas in oil is now often considered as largely undesirable because of the cost of just handling non-monetized natural gas. This paper discusses potential offshore LNG processes and reviews natural gas liquefaction cycles in the context of compactness, ease of operation, process safety, and efficiency. Particular attention is paid to the lower-efficiency turboexpander processes for plant capacities up to 3 million tonnes per annum (MTPA, approximately 0.43 Bcf/d). These cycles offer several advantages over the alternative optimized cascade and mixed refrigerant (MR) liquefiers for offshore applications. Introduction Increasing global demand for natural gas is supporting the rapid growth and diversification of worldwide LNG production capacity. As demand continues to grow and the value of natural gas remains high in the major consuming markets, the impetus to monetize more difficult and remote gas resources also grows. There is a drive to develop stranded gas fields that have remained undeveloped for many years to satisfy the thirsty energy markets with a cleaner fuel than coal or oil (in terms of lower emissions of greenhouse gases and other pollutants) that has kept the industry keen to develop the technology that will enable it to ultimately deploy floating liquefaction facilities on a commercial basis. Unfortunately it was the major international oil companies that conducted most of the early research, development, and feasibility studies, focused on deploying large-scale facilities to develop the very large gas reserves that are material to them. There are, however, very few giant gas fields located in remote offshore regions available to the majors for such deployments. The future potential to deploy floating liquefaction probably lies in medium size gas fields, or aggregations of smaller fields with associated gas, developed by medium sized independent companies. However, the restrictions of more stringent no-flaring rules being introduced in many countries (e.g. Nigeria and Angola) may prompt some existing offshore producers of giant volatile oil and wet gas fields to aggregate gas from several such fields and develop large-scale (> 4 MTPA capacity) floating liquefaction as an alternative to building and operating expensive gas re-injection facilities. The potential to unlock offshore gas reserves without the need to invest in capital-intensive pipeline infrastructure, infield platforms, and onshore infrastructure and to minimize exposure to geopolitical and security risks is also attractive to upstream LNG operators.
- North America > United States (1.00)
- Europe (1.00)
- Africa (1.00)
- (2 more...)
- Oceania > Timor-Leste > Timor Sea > Bonaparte Basin > JPDA 03-13 > Block 91-13 > Bayu Undan Field (0.99)
- Oceania > Timor-Leste > Timor Sea > Bonaparte Basin > JPDA 03-13 > Block 91-12 > Bayu Undan Field (0.99)
- Oceania > Timor-Leste > Timor Sea > Bonaparte Basin > JPDA 03-12 > Block 91-13 > Bayu Undan Field (0.99)
- (8 more...)
Summary Tight oil supplies, escalating oil prices, and towering energy demands have led to the revival of natural gas. It is now deemed to be the potential fuel of the near future. The trend now is toward supplying every cubic foot of inland and offshore natural gas to energy-hungry consumers. Liquefied natural gas (LNG) is recognized as the best form of gas transfer from remote inland and offshore fields to consumers around the world. The natural gas is liquefied and shipped to distant receiving terminals. The main technical features of a conventional terminal facility include LNG carrier mooring systems, unloading facilities, cryogenic LNG storage tanks, LNG regasification systems, and gas send-out systems. The United States has five such conventional terminals and is the world's largest gas market, with gas demands expected to double by 2020. This demand is leading to the expansion and refurbishment of these conventional LNG receiving terminals, with the construction of several more in various phases of planning and development. In 2005, the US Department of Energy (DOE), along with 30 energy industry players, successfully completed a research study on the concept of an offshore facility to moor LNG carriers and unload and store LNG. This concept includes storing gas in salt caverns. This technology is claimed to be highly cost-effective and process-efficient, with better delivery capacity and security than other options. This idea is being implemented through the construction of such a modern LNG receiving terminal in offshore Louisiana. Apart from the United States, LNG also offers great promise to such countries as Brazil, China, the United Kingdom, Mexico, Germany, and France. These countries are also contemplating LNG facilities development and upgrading. This paper aims to present a qualitative comparison between conventional and futuristic salt-cavern-based LNG receiving terminals. The comparison is based on the use of technology for these terminals. This approach will be ultimately useful in understanding the technology implementation required for the development and modernization of LNG receiving facilities in such countries. Introduction Gas demand in the United States is steadily outpacing domestic natural gas production. For importing natural gas from gas exporting countries by long-distance marine transport, transporting gas from distant offshore production facilities to the mainland, and developing isolated offshore gas reserves, LNG is widely recognized as the best form of natural-gas transport. LNG is obtained when natural gas is cooled to -160°C at atmospheric pressure. With this type of treatment, the natural gas is reduced to 1/600th of its original volume. Fig. 1 shows the recent history and near-future forecasted trends of natural gas consumption in the United States. Bringing the natural gas from the reservoir to the consumer market by transporting the gas over long marine distances gives rise to the well-known LNG value chain. Fig. 2 shows the LNG value chain. The principal subject of discussion in this paper is the LNG receiving terminal. A conventional LNG receiving terminal is an LNG receiving, storing, regasifying, and gas distributing facility traditionally located near shore. The United States has five such facilities in operation, with more than a dozen approved by the regulatory authorities like the Federal Energy Regulatory Commission and the Maritime Administration/Coast Guard as of October 2006. One of the five facilities currently operating is located offshore.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Oil & Gas > Midstream (1.00)
Summary A unique approach for assessing the economic viability of gas-to-liquid (GTL) plants is used. The capital expenditures (capex) are based on the production of 1 bbl of hydrocarbon liquid per day (BLPD), whereas the annual operating expenditures (opex) are expressed as percentages of capex. Both expenditures cover the range of costs envisioned by various vendors and investigators. It is assumed that the overall thermal efficiency of GTL plants is approximately 60% and that the plant operates 334 days per year. The capital expenditures used in this study are U.S. $20,000, $25,000, $30,000, $35,000, and $40,000 per BLPD. (Note: all expenditures in this paper are stated in U.S. dollars.) The annual operating expenditures used are 5, 6, and 7% of capex. Thus, the range of operating expenditures used is $3.03 to $8.48 per barrel of liquid hydrocarbon produced. Two measures of profitability are used in assessing the economic viability of GTL plants, namely rate of return (ROR) and undiscounted payout time (POT). Rates of return used in this study are 10, 15, and 20%, whereas the payout times used are 4, 5, 6, 7, and 8 years. Construction periods of 3 and 4 years are considered in the analysis. A general survey of GTL processes is also included. Introduction The conversion of natural GTL using the Fischer-Tropsch (F-T) process was first effected in 1923 with the conversion of synthesis gas (syngas) (CO+H2) into synthesis fuels (synfuels). The conversion is based on a three-step process: syngas generation, F-T synthesis, and product upgrading. The liquid products are stable at atmospheric temperature and pressure and may be transported with pipelines and/or standard tankers. Syngas Generation. The syngas-generation step involves a chemical reaction, reforming, wherein the hydrocarbon molecules of natural gas are broken down and stripped of their hydrogen atoms. Oxygen, introduced either in steam, in air, or as a pure gas, produces a mixture of hydrogen and carbon monoxide. The production of the ideal syngas calls for an H2/CO ratio of approximately 2, and both catalytic and noncatalytic processes have been developed. If necessary, the reforming step may be preceded by a feed pretreatment step to remove sulfur compounds such as hydrogen sulfide (H2S). In addition, other secondary/side reactions may proceed simultaneously during the syngas-generation step, yielding undesirable products, and thereby must be controlled (Gaffney, Cline & Assocs. 2001). These reactions may include:CO + CO à 2C + O2 (carbon formation reaction). CO + H2à C + H2O (carbon formation reaction). CO + H2O à H2 + CO2 (water/gas shift). There are three basic types of reformers: the steam methane reformer (SMR), the partial oxidation reformer (POX), and the autothermal reformer (ATR) (Doshi 2002). A new plasma reformer also has been developed for the production of syngas from natural gas whereby electricity provides the reaction energy for the endothermic process (Blutke et al. 1999). In the SMR, natural gas feedstock and steam at 20 atm and 500°C (with an exit temperature of approximately 800°C) pass over a nickel catalyst contained in tubes within a firebox. The heat of reaction is supplied by burning some of the feedstock. The SMR produces a syngas with an H2/CO ratio much higher than 2.0 and is thereby not ideally suited for producing synfuels. The theoretical H2/CO ratio is 3.0 (CH4+ H2Oà CO + 3H2), but the actual H2/CO ratio is 5.0 (75% H2, 15% CO, and 10% CO2) (Gaffney, Cline & Assocs. 2001). In the POX, natural gas and oxygen are directly reacted without a catalyst. The POX produces a syngas with an H2/CO ratio much lower than 2.0 and is thereby not ideally suited for producing liquid fuels. It operates at an existing temperature of approximately 1400°C (Robertson 1999). The theoretical H2/CO ratio is 2.0 (2CH4+O2à 2CO + 4H2), but the actual H2/CO ratio is 1.8 (62% H2, 35% CO, and 3% CO2) (Gaffney, Cline & Assocs. 2001). In the ATR, natural gas, steam, and oxygen at 1200 to 1500°C (with an exit temperature of approximately 800 to 1000°C) pass over a bed of nickel in the reaction vessel. The combustion reaction is rapid and exothermic and, therefore, autothermal. Because the ATR results in an H2/CO ratio of approximately 2.0, the process is best suited for the production of synfuels. To provide oxygen, an air-separation plant or other special provision may be required to resolve nitrogen-related problems. The theoretical H2/CO ratio is 2.3 (3CH4+H2O+O2à 3CO + 7H2), but the actual H2/CO ratio is 2.0 (64% H2, 32% CO, and 4% CO2) (Gaffney, Cline & Assocs. 2001). Table 1 provides a summary of the advantages and disadvantages of the various syngas generators (Doshi 2002; Wilhelm et al. 2001).
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (0.88)
- Facilities Design, Construction and Operation > Natural Gas Conversion and Storage > Liquified natural gas (LNG) (0.87)
- Management > Asset and Portfolio Management > Project economics/valuation (0.70)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (0.53)