PEH:Monetizing Stranded Gas
Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume VI – Emerging and Peripheral Technologies
H.R. Warner Jr., Editor
Copyright 2007, Society of Petroleum Engineers
Chapter 8 – Monetizing Stranded Gas
Introduction: Gas – The Fuel of the 21st Century
Natural gas is the fastest growing primary energy source. Its use is projected to double between 1999 and 2020. The mix of fossil fuels used to provide energy and petrochemicals is shifting toward natural gas (or just "gas") and away from coal. Natural gas is the more hydrogen-rich fuel. The worldwide increase in demand for natural gas is driven by the abundance of natural gas reserves, continued technological advances in exploration and production, and the desire for low-carbon fuels and cleaner air. The global demand for gas is increasing at more than twice the rate of oil demand. In the near future, one can envision an economy powered by gas. There are approximately 150 trillion m3 of proven natural gas reserves available worldwide as of the year 2000.  Table 8.1 compares the worldwide fossil fuel reserves. At current consumption rates, the worldwide reserves-to-production ratio for gas is approximately 65 years, compared with 38 years for crude oil.
Many factors support the growth of the use of gas. Natural gas is a clean-burning fuel. It has a higher ratio of hydrogen to carbon compared with fuels like coal and oil; therefore, it releases less carbon dioxide per unit energy output compared with oil and coal. If sulfur is present in natural gas, it is removed at the source gas-processing facility. Therefore, natural gas combustion results in negligible sulfur dioxide emissions. Additionally, natural gas can be burned with more controlled flame temperature compared with other fossil fuels, resulting in lower NOx emissions. These inherent properties of natural gas make it the fuel of choice compared with coal and oil for achieving reductions in greenhouse emissions.
On the down side, the disadvantage of natural gas is that it is more expensive to transport. The calorific value of oil in relation to the volume it occupies, at ambient conditions, is 1,000 times greater than that of gas. Fundamentally, it is this handicap that the oil and gas industry has to address for gas to fulfill its potential as the fuel of the near future. This limitation on gas usage is evident from the fact that only 23% of the world gas production is traded internationally vs. 57% for oil. Gas exploration has generally been limited by the cost to transport the gas to the market; hence, the current reserves of natural gas significantly underestimate the available gas resources. Continued technology development is lowering the cost of production, which, when combined with advances in technology for transporting gas and gas-based products to the market, has increased the focus on gas exploration. This is expected to lead to increasing gas reserves deliverable to the market.
Associated and Nonassociated Gas
There are two primary sources of gas: associated gas reserves and nonassociated gas reserves. The economic drivers for monetizing gas from these two basic sources are quite different and are likely to lead to different gas utilization routes. Hence, it is useful to understand the difference in economic characteristics of these two broad categories of gas sources. Nonassociated gas reserves are developed primarily to produce natural gas. There may or may not be condensate production together with the gas. Under these conditions, it is essential that there be a profitable market to which to deliver the gas.
Associated gas is gas produced as a byproduct of the production of crude oil. Associated gas reserves are typically developed for the production of crude oil, which pays for the field development costs. The reserves typically produce at peak levels for a few years and then decline. Associated gas is generally regarded as an undesirable byproduct, which is either reinjected, flared, or vented. According to U.S. Energy Information Admin. 1999 statistics,  worldwide approximately 15 Tcf/yr of gas was flared, vented, or reinjected. The need to produce oil and dispose of natural gas (as is the case with associated gas) requires unique approaches in the field-development plans. With increasing focus on sustainable development, flaring may cease to be an option. Some countries have already legislated against gas flaring. For example, current Nigerian policy requires all flaring to be eliminated by 2008. This policy is expected to eliminate the waste of a valuable resource for Nigeria and attendant negative impacts on the environment. Consequently, several key gas utilization projects have either been recently completed or are at various stages of implementation in Nigeria. Examples of such projects include the Obite Gas Plant, ChevronTexaco Escravos GTL project, West African gas pipeline project, and the Nigeria liquefied natural gas (LNG) project. 
Natural gas reserves are plentiful around the world, but many are too small or too remote from sizable population centers to be developed economically. Estimates of remote or stranded gas reserves range from 40 to 60% of the world's proven gas reserves.  These massive global gas reserves are largely untapped, and conventional means of development face logistical and economic barriers. The local market for gas is usually too small, or the gas field is too far from the industrialized markets. Stranded gas is essentially gas that is wasted or unused. Sometimes excess gas reserves can be classified as stranded because they may result in oversupply of the market. Most stranded gas reserves are in gas fields that are totally undeveloped. It is claimed that there are approximately 1,200 such fields, of different sizes, worldwide.  A recent study identified approximately 450 Tcf of natural gas stranded in fields greater than 50 Bcf that can be produced and gathered for less than 0.50 U.S. $/million Btu.  Most larger stranded gas fields can produce gas even cheaper. The sources of stranded gas are discussed next.
Associated Gas Reserves
Associated gas accounts for approximately 25% of the worldwide proven reserves of natural gas. This is down from approximately 35% in the 1970s, mainly because of the stabilization of the level of oil reserves in Middle Eastern countries and exploration in zones more favorable to nonassociated gas. The proportion of gas flared has been reduced significantly during the last twenty years. This trend has been achieved through the efforts of countries in recovering incremental quantities of associated gas.
Deep Offshore Gas Reserves
A growing share of the proven gas reserves is from offshore gas reserves in the Arctic regions and Siberia, which represent regions in which access is difficult. In recent years, the industry has been pushing even further offshore and into increasingly deep waters, successfully making larger discoveries and developing some of them. Development of these resources will be of importance in the future.
Marginal Gas Fields
In 1999, in western and southern Africa (excluding Nigeria), there were eight gas fields with reserves of between 0.5 to 1 Tcf, another eight between 0.25 and 0.5 Tcf, and more than 85 fields with reserves of less than 0.25 Tcf. 9 Identifying commercial processes that make marginal gas reservoirs viable is a challenge. Marginal gas fields account for approximately 15% of the world's proven gas reserves, and approximately 20% of this can be considered as stranded.
Remote Gas ReservesGas reserves that are distant from consuming areas fall into this category. Examples of such fields are in Africa, South America, and northern Siberia. A significant number of the Middle Eastern fields are also considered too remote to be exploited economically at this time. A rough estimate of the amount of remote gas reserves to be considered as stranded is in the range of 15 to 25% of overall gas reserves.  Table 8.2 summarizes the potential for stranded gas.
Overview of Gas Transportation Options
Natural gas is of little value unless it can be brought from the wellhead to the customer, who may be several thousand kilometers from the source. Because natural gas is relatively low in energy content per unit volume, it is expensive to transport. The cost to transport energy in the form of gas is significantly greater than for oil. This is one of the key hurdles to the increased use of gas. The most popular way to move gas from the source to the consumer is through pipelines. For onshore and near-shore gas, pipeline is an appropriate option for transporting natural gas to market. However, as transportation distances increase, pipelines become uneconomical.
Fig. 8.2 reviews the four primary ways of bringing the energy potential of gas to the market: transportation as gas, solid, or liquid, and transmission as electric power.
Gas to GasThere are three gas-to-gas (GTG) options to bring gas to market as gas: pipelines, compressed natural gas, and liquefied natural gas. In pipelines, the gas is treated to meet pipeline quality requirements and compressed for transport and distribution through a network of pipelines. In compressed natural gas, the gas is treated, compressed, and shipped as compressed natural gas to the consumers. In liquefied natural gas, the gas is treated, liquefied, shipped, and regasified at the destination. The GTG options take advantage of the reduction in volume of the gas to economically transport the gas. Table 8.3 compares the volume reduction for the various physical-conversion-based gas monetization options.
Gas to Solids
In the gas-to-solids (GTS) option, the gas is transformed into a solid form called natural gas hydrates (NGH) and transported to the market as a solid or slurry. Regasification of the hydrate is required at the receiving end.
Gas to LiquidsIn contrast to the GTG and GTS gas monetization options, which are based on a physical conversion process, gas to liquids (GTL) is a chemical conversion route involving rearrangement of molecules. GTL processes are classified into direct and indirect processes.
Direct GTL Processes. Considerable research is ongoing worldwide on direct routes of converting gas into a liquid;  however, these routes have not yet been commercialized. Methane is a molecule in which one carbon atom is bound to four hydrogen atoms by strong chemical bonds. Hence, the chemical reactivity of methane is low, making it difficult to directly convert to a liquid. Direct conversion processes have the potential for achieving a higher efficiency than indirect (syngas-based) processes. However, the key issue with these processes is poor selectivity or conversion leading to low yields of the desired products. Some of the direct GTL routes being explored include the following.
Cold Flame Oxidation. Cold flame oxidation involves the conversion of a pressurized mixture of methane and oxygen at moderate temperatures. The main reaction is the oxidation of methane to methanol; however, further oxidation of methanol to formaldehyde often takes place simultaneously.
Direct Oxidation. Direct oxidation involves the catalytic coupling (oxidative coupling) of methane and an oxidant in the presence of a catalyst at moderate temperatures and approximately atmospheric pressure to produce C2+ hydrocarbons.
Oxychlorination. Oxychlorination involves the catalytic reaction of methane with a mixture of hydrogen chloride and oxygen to produce methyl chloride. The methyl chloride is then reacted over a zeolite catalyst to produce a mixture of aliphatic and aromatic hydrocarbons.
Indirect Oxidation. This process involves indirect oxidation of methane to ethylene at high temperatures with the use of various reducible metal oxides as oxygen carriers as well as catalysts.
Catalytic Pyrolysis. Direct methane conversion through catalytic pyrolysis involves contacting methane with a catalyst at a relatively high temperature to form ethylene.
Indirect GTL Process. Fig. 8.3 shows the indirect GTL routes to gas monetization. These routes involve the conversion of natural gas to synthesis gas (also called syngas), which is primarily a mixture of carbon monoxide and hydrogen. The syngas is then converted to liquid products such as methanol, dimethylether (DME), and Fischer-Tropsch (FT) liquids. The conversion of natural gas to syngas could be catalytic or noncatalytic. There are various technologies available for the conversion of natural gas to syngas. Several publications cover these technology options extensively. The key parameters in the selection of a suitable syngas generation process are H2:CO ratio in the syngas, O2 /feed-gas ratio, methane slip, steam/carbon ratio, CO2 production, uses integration options and capital, and operating costs.
The syngas is converted to liquid products through various routes: oxygenate-based route, FT-based route, and other chemicals. The oxygenate route produces oxygen-containing products such as methanol (and its derivatives) and dimethylether (DME).  The FT route to liquid products produces hydrocarbon products like diesel, naphtha, kerosene, lubes, and other specialty products. Syngas also can be converted to chemicals like ammonia and their various derivatives.
Gas to PowerThe gas-to-power (GTP) option, often known as gas to wire (GTW), involves the conversion of natural gas to electrical power and transmission of this power to consumers.
There are several options for transporting gas to the market. The distance of the stranded gas from the market plays a key role in selection of the gas utilization option. Fig. 8.4 shows the fraction of the gas traded, by volume, in 2001 compared with the total gas consumed worldwide. Of the gas that is traded, approximately 74% is moved through pipeline. Pipelines are generally considered the cheapest option up to 2500 km, except in cases of smaller volumes in which power generation and transmission could be a viable alternative. For distances greater than 2500 km, pipelines could still be an option; however, depending on the size of the gas field, LNG and GTL could be more attractive options. For more than 4000 km, pipelines are generally not suitable. LNG, GTL, and chemicals are more viable options. Direct GTL and NGH routes are not considered viable at this time and are not discussed further. DME is also not considered practical because of infrastructure-related issues.
A vast fraction of the world's gas is brought to the market through pipelines. Several large pipeline projects are currently being evaluated.  Pipelines can be over land or under water. Underwater pipelines have been used in the North Sea. However, water depth is a critical parameter that poses difficult challenges. When considering the pipeline option, factors such as distance, throughput capacity, compressor-station requirements, pipeline size, water depth, and topographical profiles have to be considered in the economic analysis.
Pipelines typically operate at pressures ranging from 70 to 100 bar. As a general rule, the initial compressor stations for pipelines require two-stage compression for boosting pressure from 40 to 140 bar, while intermediate compressor stations require single-stage compression from 100 to 140 bar. Some pipelines operate at high pressures. High-pressure pipelines are defined as overland gas pipelines operating at pressure higher than 100 bar and in the range of 100 to 200 bar. At the receiving station of the pipeline, the gas may have to be scrubbed and metered for custody transfer purposes. The pressure of the gas may have to be adjusted to meet the requirements of the gas distribution pipeline network.
Several publications discuss the economics of pipelines relative to other gas utilization options.  Aside from economics, pipeline transit fees and political risk are key issues that should be considered when evaluating this option for monetizing gas. Additionally, pipeline routes are fixed and are exposed to acts of terrorism, high transit tariffs, or the potential for gas flow being shut off during a dispute involving one of the transit countries.
In the pipeline option, especially in remote locations, it should be considered that a pipeline is a single system and requires the entire pipeline to be serviceable for any gas to flow. Disruption of any part of the pipeline disrupts all service through that system. Pipeline maintenance is another area that requires attention. Pipeline sections, which are essentially out of sight, represent a risk over the long life of the gas project. The primary concern is corrosion; however, mechanical damage also can be an issue.
Newer pipeline technology and growing energy consumption of nearby markets are the key drivers for transporting gas through pipeline. The development of high-pressure pipelines has brought down costs by the more efficient use of steel pipe. Traditionally, X-65 grade of carbon steel has been used for pipeline construction. Carbon steel grades of up to X-100 are currently available and will be field proved in the coming years. This will reduce the cost of pipeline installation by approximately 10%. Alternative new metallurgy, possibly including the use of composites, is expected to make pipelines a more competitive option by not only lowering the cost of the pipe itself, but also by resulting in lower logistics and installation costs, which are significant in difficult and inaccessible areas. Recent developments regarding deepwater pipelines are expected to open up new marine pipeline competition for LNG. Modern materials can face the new challenges of the deepwater pipelines crossing harsh environments.
Compressed Natural Gas
Compresses natural gas (CNG) transportation is used in very small systems in environmentally sensitive areas. Trucks, ships, or barges transport the gas from a remote well to a pipeline or from a pipeline to a customer location. Sometimes the gas is transported to remote filling stations for CNG-fueled vehicles. Large-scale transportation of CNG is not yet commercialized but is considered economically feasible and is being pursued actively by several companies.
In the 1960s, Columbia Natural Gas of Ohio tested a CNG carrier. The ship was to carry compressed natural gas in vertical pressure bottles; however, this design failed because of the high cost of the pressure vessels. Since then, there have been several attempts at developing a commercially viable CNG carrier. In the past five years, several competing CNG ocean transport designs have evolved. Each design proposes a unique approach to optimizing gas transport while using as much off-the-shelf technology as possible to keep costs competitive.
The CNG Process
The CNG chain consists of the following components.
Production. The production facility for CNG is simpler than other remote gas utilization options such as LNG, GTL, ammonia, or methanol. It typically consists of compression, cooling, dehydration, and possibly LPG separation. The extent of compression and cooling is different for the various CNG processes. The scope of the production facility depends on the quality of the gas and reservoir pressure, but is a small fraction of that of a comparably sized LNG or GTL facility.
Transportation. A large portion of the CNG carrier's capital cost is the gas containment system and associated safety and gas control systems. The means for transporting CNG differentiates the various CNG processes that have emerged over the last few years. These processes include Coselle CNG carrier,  volume-optimized transport and storage (VOTRANS),  coiled-pipeline (CPL) carrier,  gas transport modules,  and the pressurized natural gas concept.
The central idea behind the Coselle CNG carrier, patented by Cran and Stenning Technology Inc., is to create a large but compact CNG storage with a pipe. A Coselle consists of several miles of small-diameter pipe coiled into a carousel, hence the name Coselle. Enersea Transport LLC is commercializing the VOTRANS technology. VOTRANS consists of long, large-diameter pipes encased in an insulated shell. The technology is different from other CNG concepts in terms of the lower compression requirements because of lower pressure and temperature of storage. C-Natural Gas's CPL carrier uses a coiled-pipeline configuration, which is easily adaptable to existing maritime shipping with nominal modifications to the off-the-shelf ship design. The pressure and temperature at which CNG is stored vary depending on the CNG process. A typical range of storage pressures is 140 to 200 bar.
Receiving. The CNG ship unloads gas into a pipeline at the receiving station. The CNG receiving terminal is relatively simple and includes a dock with high-pressure pipeline connections and possibly an expander to allow energy to be recovered from the high-pressure gas. A scavenging compressor may be needed to empty the ships below the pressure of the pipeline. This will make it possible to transport larger quantities of gas, which will reduce the number of ships required to transport a given quantity of gas.
Storage. Storage at the production and receiving terminal is required to maintain continuous operation. Assuming that the time between shipments is not great, a practical approach may be to have extra ships and keep them in the port for storage purposes.
Screening Criteria. The volume reduction for CNG depends on the conditions at which the compressed gas is stored but is typically in the range of 250 to 300, compared with gas at atmospheric conditions. CNG is considered a viable transportation option for markets that are 1000 km or less from the source of the gas. As the distance from the market increases, LNG or GTL becomes more favorable assuming sufficient volume of gas is available. The threshold volumes required for CNG are expected to be relatively smaller compared with LNG and GTL. CNG can handle gas volumes ranging from less than 100 MMscf/D to more than 1 Bscf/D. The CNG design is modular. By adding ships, the volumes handled can grow with growing demand. The CNG process is energy efficient with energy consumption approximately half of that of an LNG project and significantly lower compared with syngas-based generation routes.  The fuel required for the compression of the gas at the production facility ranges from approximately 0.5 to 1.0% of the feed gas depending on the feed-gas pressure.
Additional fuel consumption during transportation is a function of the distance of the market from the source. The cost of transportation is dependent on specific-project conditions, shipping distance, and number of ships. A Coselle study indicates that the cost of transporting 300 MMscf/D over a distance of 1,100 miles is U.S. $1.4/million Btu excluding the cost of gas at the wellhead.  Because there are no commercial CNG units in operation at this time and the technology is still under development, cost of these projects are not yet predictable and should be verified on a project-specific basis.
Key Consideration. The key issue with CNG as a gas monetization option has been the ability to obtain financial backing for a real project. As with all new technologies that are not commercialized, CNG faces the first-adopter syndrome. It has been difficult to put a project together that is financially attractive and at the same time not too large to be considered too risky to be the "first mover." One of the key variables that affects the cost of the CNG option is the cost of ships. The ship cost is a function of the amount of steel, which in turn depends on the safety factor used for the design of the containment system. Currently, there are no specific codes that govern CNG carriers. The regulations that determine the safety factor used to design the containment system could have an impact on the economics of CNG projects. Other issues with the CNG option include evaluation of controlled loading, unloading and emergency depressuring to confirm the use of carbon steel as the material of construction, and safety-related concerns.
Liquified Natural Gas
LNG is the liquid form of natural gas at cryogenic temperature of −265°F (−160°C). When natural gas is turned into LNG, its volume shrinks by a factor of approximately 600. This reduction in volume enables the gas to be transported economically over long distances.
Over the past 30 years, a considerable world trade in LNG has developed. Today, LNG represents a significant component of the energy consumption of many countries and has been profitable to both the exporting host countries and their energy company partners. The total LNG production capacity as of year 2001 is approximately 106 million tonnes per annum. LNG accounts for only 4% of the total gas consumption but 25% of internationally traded gas. Asia remains a dominant player in the world LNG market, both as an importer and an exporter. Japan is the world's larger importer of LNG, with 53% of the total production capacity.  Indonesia is the largest exporting nation, with 27% of all exports.
In 1914, Godfrey Cabot patented a river barge for handling and transporting liquefied gas. As early as 1917, liquefaction was used in the United States for the extraction of helium. However, it was not until 1959–60 that the Methane Pioneer, a converted cargo vessel, first demonstrated the technique of bulk LNG transport by successfully and safely carrying seven LNG cargoes from Lake Charles, Louisiana, in the United States, to Canvey Island in the U.K. The first commercial LNG plant in Algeria became operational in 1964 and exported LNG to western Europe. Currently, 12 countries have liquefaction facilities with 64 LNG trains, and 38 receiving terminals are operating in 10 countries. 
LNG ProcessThe key components of the LNG chain include a gas field, liquefaction plant, LNG carriers, receiving and regasification terminal, and storage.
Liquefaction Plants. Fig. 8.8 shows the main components of a typical LNG liquefaction plant. LNG liquefaction plants are generally classified as baseload or peak shaving, depending on their purpose and size.  This discussion is directed toward baseload LNG plants. The process for the liquefaction of natural gas is essentially the same as that used in modern domestic refrigerators, but on a massive scale. A refrigerant gas is compressed, cooled, condensed, and let down in pressure through a valve that reduces its temperature by the Joule-Thomson effect. The refrigerant gas is then used to cool the feed gas. The temperature of the feed gas is eventually reduced to −161°C, the temperature at which methane, the main constituent of natural gas, liquefies. At this temperature, all the other hydrocarbons in the natural gas will also be in liquid form. In the LNG process, constituents of the natural gas (propane, ethane, and methane) are typically used as refrigerants either individually or as a mixture. Feed pretreatment and refrigerant component recovery are normally included in the LNG liquefaction facility. LPG and condensate may be recovered as byproducts.
Table 8.7 summarizes the market share (based on tonnage of LNG produced) as of year 2001 of the different liquefaction processes. Economies of scale are driving single-train sizes up from approximately 1 million tonnes per annum in 1960 to 5 million tonnes per annum in 2001.
LNG Carriers. LNG is shipped commercially in a fully refrigerated liquid state. The fundamental difference between LNG carriers and other tankers is the cargo containment and handling system. The combination of the metallic-tank containment and insulation needed to store LNG is called a "containment system." There are two main types of containment systems: self-supporting tank and membrane tanks. Current LNG vessels have 135 thousand m3 carrying capacity (approximately 60 thousand metric tons) and cost approximately U.S. $160 million These carriers either consume boiloff gas or reliquefy the gas and use diesel as fuel.
Receiving, Regasification Terminal and Storage. The function of an LNG import terminal is to receive LNG cargos, store LNG, and revaporize the LNG for sale as gas. Odorant injection may be required if gas is to be exported through a transmission grid. There are two main systems used for LNG vaporization: submerged combustion vaporizers and open-rack vaporizers (ORVs). In submerged combustion vaporizers, the LNG passes through tubes immersed in a water bath, which is heated by submerged burners. In ORVs, water runs down the outside of the vaporizer tubes (usually vertical) as a film. River water or seawater is normally used.
Screening CriteriaThe costs of delivering large quantities of gas by pipeline rise rapidly with distance. At some point, it becomes more economical to transport the gas as LNG. Several comparisons of pipeline and LNG have been published that point to the fact that LNG is competitive with pipelines for distances greater than 2500 km. Compared with pipelines, LNG has the benefits of modular buildup and few border/right-of-way issues.
The LNG plant size can be determined by the gas-field size. Approximately, 1 Tcf of feed gas is required to produce 0.8 million tons per annum (mtpa) of LNG for 20 years. Hence, 5 million tons per annum of LNG production will require a gas-field size of approximately 6 Tcf. The typical gas consumption for the production of LNG from feed gas in the liquefaction plant can be calculated on the basis of 10% of the feed gas used for internal fuel consumption. The total energy required for the plant comes from the feed gas itself. Table 8.8 summarizes the loss of feed gas as fuel in the LNG chain (excluding the gas production facility, which may include extraction of liquids and nonhydrocarbon gases):
The LNG carriers are typically designed for speeds of 17 to 20 knots. The number of ships required for 1 mtpa can be quickly estimated by
where n = the number of ships and L = the one-way distance in nautical miles. 
The following are some considerations in evaluating options for transportation of gas as LNG.
Long-Term Contracts. LNG is a mature industry and has established a niche for itself by matching remote gas supplies to markets that lack indigenous gas reserves. Currently, the majority of the LNG is not traded like a commodity. LNG trading requires coordination of principals in the production, export, shipping, and import segments of the trade. As a result, long-term contracts for LNG dominate the industry. The requirement for long-term (20 to 25 years) contracts is seen by some as a possible hurdle in the growth potential for LNG.
Economics of the LNG Chain. The costs to produce and supply LNG can be divided among the major elements that make up the supply chain.
- Gas production facilities. In view of the high cost of liquefaction and shipping of LNG, it is essential to have low-cost feed gas to produce LNG competitively. Gas production cost typically varies from U.S. $0.25/million Btu to more than U.S. $1.0/million Btu. A production cost of less than U.S. $1.0/million Btu is desirable to make the LNG option economically viable.
- Baseload liquefaction plant with storage and export facilities. LNG projects are inherently capital intensive. The liquefaction plant is the largest cost component, accounting for approximately 50% of the total cost of the LNG chain.  Fig. 8.9 shows the typical capital cost breakdown of a grassroots LNG liquefaction facility. The capital cost of the liquefaction facilities is dependent on several factors such as plant location, size of plant, site conditions, and quality of feed gas. The contribution of the liquefaction plant cost to the cost of delivery of LNG ranges from U.S. $1.5 to $2.0/million Btu.  The cost of a liquefaction plant is a significant component of the cost of the LNG chain; hence, cost reduction of the liquefaction facility is an important issue. The thermodynamics of the liquefaction processes are well developed. Thus, further advances and cost reductions in this industry come from refinement of equipment to better service (make more efficient) the liquefaction process and/or support infrastructure (utilities). Several publications discuss cost reductions in liquefaction plants. 
- LNG tanker ships (transportation). The fleet of tankers for an LNG project is a significant portion of the total cost of the LNG chain. The number of ships and, hence, the cost of shipping is dependent on the distance between the liquefaction facility and the market. A typical contribution of the shipping cost to the cost of delivered LNG is approximately U.S. $0.5 to $1.2/million Btu.
- Import terminal with storage and regasification facilities. The receiving terminals with tanks, vaporization equipment, and utilities contribute approximately U.S. $0.3 to $0.4/million Btu to the delivered price of LNG. These costs are highly dependent on design practices (especially the design of the storage tanks) and specific site conditions.
Future Trends. For LNG to become the energy source of choice, the cost of the LNG chain has to be competitive with alternative fuel sources. The trend is toward large liquefaction-train sizes and fit-for-purpose plants to reduce the capital cost of the liquefaction facilities. On the terminal side, there is a high level of interest in moving facilities offshore because of environmental and permitting issues. Several companies have proposed concepts for offshore storage and regasification terminals. Other areas of interest are integration of receiving terminals with facilities such as power plants or air separation units.
Gas to Ammonia and Urea
Ammonia is the second largest chemical product produced in the world, behind sulfuric acid. The demand for ammonia is driven by the demand for fertilizers. Of the world's nitrogen demand, 85% is for fertilizer primarily derived from ammonia in the form of urea, ammonium nitrate, phosphate, and sulfate. Other uses of ammonia include fibers, resins, refrigeration, and pulp and paper industries. Ammonia can be produced from different hydrocarbon feedstocks such as natural gas, coal, and oil. Over the years, natural gas has been the preferred feedstock over others because more than 95% of the tonnage is based on this feed. The preference for natural gas is primarily because of the following two reasons:
- It is intrinsically the most hydrogen rich and, therefore, contributes more hydrogen compared with other feedstocks on a unit weight basis.
- The heavier feedstocks, like coal and oil, are more complex to process; therefore, the capital costs are higher compared to natural gas.
A relatively small volume (10%) of ammonia that is produced is traded as ammonia.  This is a result of the difficulty of using ammonia directly as a fertilizer. Most farmers prefer a solid fertilizer. These factors drive the producers of ammonia to either develop regional markets for ammonia or convert the ammonia to urea, a dry solid that can be stored and moved relatively easily and cheaply. For stranded gas, away from the regional markets, the integration of the ammonia and urea plants makes commercial sense. It should be noted that the production of urea requires CO2 (in addition to ammonia), which is a byproduct of ammonia production.
In year 2000, ammonia was a 131 million metric tons per year industry. Worldwide annual growth is anticipated to be approximately 1.6 to 2%. Urea is a 107 million metric tons per year industry directly derived from ammonia.  The end uses for urea are primarily in fertilizers, with small quantities in formaldehyde-urea resins, plastics, and fibers.
The first commercial ammonia plant was commissioned in the early 20th century on the basis of the fundamental research work of Haber.  Bosch and his engineering team developed the ammonia-synthesis process with a promoted iron-based catalyst. Since then, there has been no fundamental change in the ammonia-synthesis reaction itself. A mixture of hydrogen and nitrogen reacts on the iron catalyst at elevated temperatures in the range of 400 to 500°C operating at pressure above 100 bar.
The unconverted part of the synthesis gas is recirculated (after the removal of ammonia) and supplemented with fresh synthesis gas to compensate for the amount of nitrogen and hydrogen converted to ammonia. The production of ammonia synthesis gas, consisting of pure hydrogen and nitrogen, is the largest single contributor of the production cost of ammonia. Hence, in contrast to the ammonia-synthesis section, dramatic changes have been made over the years in the technology for the generation of synthesis gas. Net energy consumption has been reduced progressively, from approximately 88 GJ/ton ammonia in the days of coke-based water-gas generators to approximately 28 GJ/ton ammonia today with the use of natural gas in a steam reforming unit. 
Ammonia ProcessFig. 8.10 shows the three principal steps in the production of ammonia from natural gas.
Syngas Generation. A synthesis gas with a 3:1 final H2:N2 mole ratio is required for the synthesis of ammonia. This syngas is generated by steam reforming of natural gas under pressure. Sulfur compounds, if any, in the feed gas have to be removed before the reforming process. The basic reactions involved in the steam reforming of methane, which is the main constituent of natural gas, are represented by the following reactions:
The required stoichiometric hydrogen-to-nitrogen ratio is achieved by introducing air into the process. It is typically done by splitting the reforming into two steps: primary reforming and secondary reforming. In primary reforming, the natural gas is reformed with steam in furnace tubes packed with nickel catalyst. Natural gas burners in the furnace radiation box supply the intense heat needed for the endothermic reaction. The reaction is controlled to achieve only a partial conversion, leaving approximately 14% methane in the effluent gas (dry basis) at temperatures of approximately 750 to 800°C. The effluent gas is then introduced into a secondary reformer, a refractory-lined vessel filled with nickel catalyst, in which it is mixed with a controlled amount of air introduced through a burner. This raises the temperature of the gas sufficiently to complete (as much as possible) the reforming of the residual methane without any further addition of heat. It also introduces the nitrogen needed for the synthesis of ammonia. The gas usually leaves the secondary reformer at a temperature of approximately 850 to 1,000°C, depending on the process technology.
There are several variations to the conventional syngas generation scheme defined here in an attempt to improve energy efficiency and reduce cost. These include use of prereformers, heat exchange reforming, and fully autothermal reforming. 
Syngas Purification. This is the second key step in the ammonia production process. The syngas from the secondary reformer contains CO and CO2, which must be removed before syngas is sent to the ammonia-synthesis section to avoid damaging the ammonia-synthesis catalyst. Reformed gas is typically purified with high and low temperature shift of CO to CO2, CO2 removal by solvent absorption, or methanation. There are several alternative routes for the purification of syngas, which include pressure-swing adsorption and cryogenic methods. 
Ammonia Synthesis. The final key step in ammonia production is ammonia synthesis. In this step, the purified syngas mixture of hydrogen and nitrogen is compressed and synthesized to produce ammonia.
Various technology licensors offer technology for the production of ammonia. Haldor Topsoe and Uhde typically use conventional two-stage reforming, primary tubular reforming followed by air-blown secondary reformer. Both use conventional magnetite catalysts for ammonia synthesis. KBR offers different technology options including conventional, KBR Advanced Ammonia Process (KAAP™), KAAP™ with purifier, and KAAPplus™. The last three use processes based on ruthenium catalyst.
The Urea ProcessThere are several process/technology options for producing urea. Fig. 8.11 shows a simplified block-flow diagram for the production of urea from ammonia. Only a brief outline of the generic technology options is given here. Urea (NH2CONH2) is produced from liquid ammonia and carbon dioxide gas through a rapid exothermic reaction that leads to the formation of an intermediate liquid product called ammonium carbamate (NH2COONH4). This intermediate product dehydrates into urea and water through a slow and slightly endothermic reaction. Unreacted feed components and the intermediate product are recovered to maximize the product yield by stripping, recirculation, or recycling. Vacuum evaporation is used to concentrate the urea product and remove water to create a high-weight-percentage "melt." The melt can be used to produce either prilled or granular products.
Different urea technologies use somewhat different process steps to maximize product yield and energy efficiency. Major licensors of process technologies are Snamprogetti, Stamicarbon, and Toyo Engineering Corp.
The capacities of ammonia and urea plants are generally not limited by gas availability. The single-train plant capacities of currently operating ammonia plants are approximately 2000 metric tons per day (mTPD). The gas consumption for a stand-alone ammonia plant of this size is approximately 29 million Btu per metric ton of ammonia product based on the lower heating value (LHV) of the feed gas. For a feed gas with LHV of 917 Btu/scf, a 2000-mTPD ammonia plant requires approximately 63 MMscf/D of feed gas. If the entire ammonia product is converted to urea, the gas consumption will increase to approximately 36 million Btu per metric ton of ammonia product. 3500 mTPD of urea will be produced. Hence, for an ammonia/urea complex with a capacity of 2000 mTPD of ammonia, the feed-gas consumption will be approximately 79 MMscf/D. A gas field of at least 0.7 Tcf is required to support this gas consumption over a project life of 20 years. The ammonia/urea complex is typically self-sufficient in utilities, depending on the choice of the plant cooling medium.
Ammonia and urea have been produced in large quantities from natural gas since approximately 1950. It is a mature technology with minimal technology risk. The ammonia/urea industry is characterized as a commodity producer in a mature market. The demand for fertilizers is driven by population growth; however, economics as well as politics can drive fertilizer projects.
The quantity of gas required for a single train is small compared with LNG, GTL, and even large-scale methanol plants. The use of this option, by itself, is not suitable for large gas fields. However, for large gas fields, this could be an appropriate option in combination with other options. The production of ammonia in conjunction with other gas utilization options may offer synergies that could result in reducing the cost, as well as the product market risk, of the total project.
The combined costs of feedstock and energy for a steam-reforming plant are the principal determinant of the overall production cost of the plant. Capital cost of the plant is another significant factor that needs to be considered. The supply and demand of ammonia play a critical role in determining ammonia prices. When supplies are tight, prices rise dramatically. Fertilizers are a relatively small cost component in agriculture and cannot be avoided. The cost of ammonia production is somewhat determined by the cost of feedstock, which for the majority of the ammonia plants is natural gas. New ammonia projects tend to be cyclical, driven by product demand and positioned where feedstock prices are low.
The future trend in ammonia plants is clearly toward larger plants (capacities ranging from 3000 to 4000 mTPD) and locations with low-cost gas supplies.
Gas to Liquids-Fischer-Tropsch Route
GTL through the FT route to monetize stranded gas has received increasing attention over the past few years. FT technology is a process that rearranges carbon and hydrogen molecules in a manner that produces a liquid, heavier hydrocarbon molecule. In general, GTL through the FT route refers to technology for the conversion of natural gas to liquid; however, GTL is a generic term applicable to any hydrocarbon feedstock. This section focuses on GTL processes based on natural gas feedstock. The FT GTL process produces petroleum products such as naphtha, kerosene, and diesel. Lubricants, solvents, waxes, and other specialty products also can be produced, if required.
FT chemistry originated during the early 1920s from the pioneering work of Franz Fischer and Hans Tropsch at the Kaiser Wilhelm Inst. for Kohlenfirschung in Germany. They used a precipitated-cobalt catalyst at normal pressure. It was further developed by various German companies with sintered and fused iron catalyst, resulting in the manufacturing in Germany during World War II of 600,000 tonnes per annum of FT products, mainly motor fuels. Further development in the FT GTL process took place in Brownsville, Texas, producing 365,000 tonnes per annum from a fluidized-bed process during 1948–1953. Subsequently, Sasol in South Africa developed various FT plants with fixed-bed; circulating fluidized-bed; and recently, slurry-type reactor with iron, as well as cobalt, catalysts. The Sasol GTL process for the production of middle distillates is known as the slurry phase distillate process.  Later, between 1973 and 1990, Shell developed a cobalt-based process in their Amsterdam research facility. Shell's GTL technology is based on the Shell middle distillate synthesis (SMDS) process.  ExxonMobil's research, which ultimately led to today's AGC-21™ process,  started in the early 1980s. Besides Sasol, Shell, and ExxonMobil, several major oil companies, as well as smaller companies, are developing their own GTL technology.
Gas-To-Liquid ProcessFig. 8.12 shows the three major steps in a GTL process. These steps are described here.
Syngas Generation. The first step in a GTL process is to convert the natural gas feed into synthesis gas or syngas. Before being fed to the syngas generation unit, the natural gas is typically processed to remove impurities such as sulfides, mercaptans, mercury, and any impurities that will poison the various catalysts that are used in the GTL conversion steps. The cleaned feed gas is then fed to a syngas generation unit. In this step, the bond between the carbon and hydrogen is broken, and two separate molecules (CO and H2) are formed. The ratio of H2 to CO in the syngas is a critical factor in the FT process.
There are several ways to produce synthesis gas from natural gas and air or oxygen. These include steam reforming of feedstock in the presence of a catalyst,
and the partial oxidation process in which air or oxygen is burned together with natural gas at high temperatures and pressure. No catalyst is used.
For GTL plants that require large quantities of oxygen, a cryogenic air separation plant is currently the most economical option. Natural gas and oxygen are preheated and compressed (if necessary) to required conditions before being sent to the synthesis gas reactor.
The syngas fed to the downstream FT synthesis unit must have a ratio of H2 to CO of approximately 2. This ratio has favored the development of partial oxidation and autothermal reformer (ATR) processes (by themselves or in combination with other processes) over the steam-reforming process because the latter requires additional processing to achieve the desired H2:CO product ratio. Even though the technology for syngas generation is considered proven, its application in GTL plants is complex and costly. Significant research is ongoing in this area to reduce cost.
Fischer-Tropsch Synthesis. The FT synthesis section involves the conversion of synthesis gas to long-chain, heavy paraffinic liquid. paraffin is a mixture of high-molecular-weight alkanes (i.e., saturated hydrocarbons with the general formula CnH2n+2, where n is an integer). Large quantities of water are produced as a byproduct, which is required to be treated before disposal or reuse. Small quantities of CO2, olefins, oxygenates, and alcohols are also produced as byproducts. The reaction is highly exothermic, with heat of reaction of approximately −39.4 kcal/gmol of CO. Large quantities of heat are generated in the process that must be removed. This energy is partially recovered by the production of steam.
The product slate from a FT reactor is dependent on the type of catalyst and the operating conditions of the reactor. Generally, an iron-based or cobalt-based catalyst is used for FT synthesis. The choice of the catalyst is to some extent related to the type of feed to the GTL plant. For natural gas feed, a cobalt-based catalyst is more likely to be used.
There are several different reactor types to produce FT products: fixed-bed, fluidized-bed, and slurry-phase reactors. Several publications discuss the pros and cons of the various reactor designs. The operating conditions of the FT reactors typically range from 220 to 250°C and pressure of 20 to 60 bar. The operating conditions vary depending on the desired product mix, type of catalyst, and reactor type. The FT product is totally free of the sulfur, nitrogen, metals, asphaltenes, and aromatics that are normally found in the petroleum products produced from crude oil. Table 8.9 compares the quality of the products from the FT process with that of conventional refinery-based products.
Product Upgrading. The hydrocarbon products produced in the FT reactor consist of a mix of light hydrocarbons; olefins; liquid hydrocarbons; and waxy, long-chain paraffinic molecules that cannot be sold directly as products. These products are processed further in the product-upgrading unit to primarily produce naphtha, kerosene, and diesel. There is a variety of specialty products such as solvents, wax, and lube oils that can be produced from FT products; however, the market for these products is limited. The product-upgrading step involves processes very similar to processes used in a crude-oil refinery.
Besides the three process steps detailed in this section, the GTL facility includes a large utility plant, offsites, and infrastructure. GTL production can be described as utility intensive; it is both a large producer and consumer of energy. The magnitude of the utilities for a GTL plant is evident from the large amount of power required to operate these plants. A 74,000 bbl per stream day SMDS-based GTL plant requires approximately 360 MW of power. 
The GTL plant is not based on just one technology but brings together several technologies on a large scale. These technologies include gas processing, industrial gas production, syngas generation, catalytic reactors, refining, power generation, and effluent treatment.
The size of GTL plants can vary from small (5 to 15,000 B/D) to large (> 50,000 B/D). GTL plants produce petroleum products, which are sold in a commodity market. The size of the market is large, on the order of 1,240 million tonnes per annum. A world-scale GTL plant with a capacity of approximately 50,000 B/D (1.95 million tonnes per annum) contributes a very small fraction of the total market. GTL technologies available from different licensors differ in process configuration, thermal efficiencies, and capital cost; hence, the amount of gas required to produce a specific amount of liquid varies. The gas consumption for a GTL plant ranges from 8,500 to 12,000 scf/bbl. The range of 8,500 to 10,000 scf/bbl is typical of oxygen-based GTL processes. 
Economics. The key parameters that determine the economic viability of a GTL plant are gas price, capital cost, and operating cost. Other parameters that play a key role in the economics of a GTL plant are product premiums, tax incentives, shipping cost, crude prices, and environmental aspects.
Gas Price. With only two commercial GTL plants built in the past 10 years, there is little information available on the capital cost of these facilities. However, it is widely believed that technology developments in syngas generation, FT reactor, and catalyst technology have resulted in significant reduction in capital costs of GTL plants in recent years.
Capital Costs. Capital costs are also dependent on factors such as location of the plant, infrastructure requirements, plant capacity, technology selected, quality of gas, and site development. GTL plants benefit significantly from economies of scale, which is driving most technology suppliers toward building larger plants. All major technology suppliers have announced GTL plants in the capacity range from 50,000 to 100,000 B/D. The capital cost of the GTL plants quoted by various technology suppliers for a fuels-based plant range from U.S. $20,000 to $35,000 per bbl per stream day (U.S. Gulf Coast location), depending on the plant capacity and technology.  The production of specialty products in a GTL plant, while improving revenue, will increase the capital cost of the plant.
Operating Costs. Operating costs vary depending on several factors such as location, technology (catalyst), and product slate. Typically, the operating cost of a GTL plant ranges from U.S. $3 to $5/bbl excluding the cost of feed gas.
Commercialization of Gas-to-Liquid Technology. Although the FT process was developed in the 1920s, the commercialization of this technology is still evolving, with only three companies currently operating commercial plants. There is currently a great deal of interest in GTL, and a number of companies believe that this is a technology whose time has come.
Proprietary Nature of Technology and Licensing. Technology providers consider GTL technology highly proprietary. There are significant barriers to new entrants developing GTL processes because of the high cost of technology development and the extensive patent protection of existing processes. Currently, the technology for GTL is not widely licensed. Most technology suppliers leverage their technology to gain access to gas assets.
Crude-Oil Pricing. The products from a GTL facility are in direct competition with products produced by crude-oil refining; therefore, the growth of GTL is dependent on the price of crude oil. One way to review GTL products is to compare the cost of producing these GTL products with the cost of products from a crude-oil refinery. Hence, a minimum crude-oil price level will be required to support future GTL projects. GTL technology providers claim that a crude-oil price of U.S. $15 to $20/bbl results in a profitable GTL project.  The impact of crude-oil price on GTL product prices is one of the major obstacles to widespread commercialization of GTL.
GTL is an emerging technology. Although there are few plants in construction phase, there is considerable activity around the world by major oil companies. Reduction in capital costs and reasonable projections of the crude-oil price will be instrumental in the success of GTL as a gas monetization option.
Gas to Methanol
Methanol is a primary liquid petrochemical made from renewable and nonrenewable fossil fuels containing carbon and hydrogen. Containing one carbon atom, methanol is the simplest alcohol. It is a colorless, tasteless liquid and is commonly known as "wood alcohol." Natural gas is the feedstock used in most of the world's production of methanol. Methanol is a chemical building block used to produce formaldehyde, acetic acid, and a variety of other chemical intermediates. Fig. 8.3 shows the range of products derived from methanol. A significant amount of methanol is used to make methyl tertiary butyl ether, an additive used in cleaner-burning gasoline. Methanol is one of a number of fuels that could substitute for gasoline or diesel fuel in passenger cars, light trucks, and heavy-duty trucks and buses. Because of its outstanding performance and fire safety characteristics, methanol is the only fuel used in Indianapolis-type race cars. Methanol is also widely considered a leading candidate as the fuel of choice for vehicular fuel-cell applications.
Stranded gas can be monetized by producing chemical (or fuel grade) methanol and transporting it to the market. Since the 1980s, there has been a significant change in the way the methanol market has worked. Remote producers of methanol have begun to gain market share over long-established production sites close to the customers. Gas economics has been the driving force behind these changes. As gas demand has risen, the methanol producers in North America and Europe have been squeezed out. Because methanol can be transported easily, methanol production has moved to remote locations where gas is cheaper.
Methanol was first produced by destructive distillation of wood. As demand grew, synthetic processes were developed to produce methanol economically. BASF, which did most of the pioneering work on syngas chemistry, was awarded the first patent on the production of methanol in 1913. The first commercial-scale synthetic methanol plant was started in 1923 at BASF's Leuna works. The methanol manufacture process was based on a zinc/chromia catalyst that converted carbon oxides and hydrogen into methanol at pressures of 300 bar and temperatures exceeding 300°C. The high pressure not only imposed limitations on maximum size of equipment but also resulted in high energy consumption per tonne of product. The early 1970s saw the commercialization of the low-pressure methanol synthesis developed by ICI, which was based on a copper catalyst operating at lower pressures (< 100 bar) and temperatures (200 to 300°C). The process was called ICI's low-pressure methanol process.
The Methanol Process
Methanol production typically requires three steps: syngas preparation, methanol synthesis, and methanol purification/distillation.
Syngas Preparation. Syngas preparation is very similar to the FT GTL process, but a major difference is the scale at which syngas is produced. Syngas for methanol synthesis can be prepared either with partial oxidation (POX) or steam reforming of the natural gas feedstock. For a natural gas feedstock with little heavy-hydrocarbon and sulfur impurity in it, a steam-reforming-based plant is considered most cost effective, with better reliability and higher energy efficiency. POX-based units are generally more suited for syngas generation from heavy-hydrocarbon feedstocks (e.g., fuel oil). A POX-based unit for natural gas feed requires a larger air separation plant and typically produces substoichiometric syngas, which requires additional processing for methanol synthesis.
Natural gas can be steam reformed with any of the following schemes: tubular reforming with a fired reformer furnace; combined reforming with a fired reformer furnace followed by an oxygen-blown ATR; and heat-exchange reforming without a tubular reformer furnace, but with ATR.
Methanol Synthesis. All the commercial methanol plants currently use gas-phase synthesis technology. The synthesis loop pressure, reactor type used, and method of waste-heat recovery broadly differentiate gas-phase methanol-synthesis schemes. All the modern large-capacity methanol processes use low-pressure synthesis loops with copper-based catalysts. Quench-type, multibed intercooled, or isothermal reactors are used to minimize reactor size and maximize recovery of process waste heat.
Methanol Purification/Distillation. Crude methanol, received from a gas-phase synthesis reactor that uses syngas with a stoichiometric number [stiochiometric number is molar ratio of (H2 – CO2)/(CO + CO2)] of 2 or higher, will have excessive water (25 to 35%). Besides removing the lighter components in a topping column, this water and other heavies are removed in a refining column. Reboiler heat duty is typically obtained by cooling the syngas in the front end of the plant. A two- or three-column distillation scheme is typically used.
Methanol distillation schemes used by different licensors are similar. The two-column distillation scheme offers low capital expenditures, and the three-column distillation scheme offers low-energy-consumption features. The scheme that integrates better with the syngas preparation and synthesis section is normally selected. Several technology providers license the process technology for methanol: Synetix, Lurgi, Haldor Topsoe, Mitsubishi Chemicals, and KBR.
Until a few years ago, the size of a large-scale single-train methanol plant was considered to be 2000 to 2500 metric tons per day. However, economies of scale and market conditions are driving the trend toward building larger-sized plants with capacities in excess of 3,000 thousand tons per day. Two plants with capacities of 5000 metric tons per day are currently under construction, and several large methanol plants are under discussion. The typical gas consumption for a world-scale methanol plant ranges from 28 to 31 million Btu per metric ton of product based on LHV of the feed;  therefore, a 5000 metric tons per day methanol plant will use approximately 157 MMscf/D of gas. For a project lifetime of 20 years, a gas-field size of at least 1.15 Tcf is required to support a plant of this size.
The economics of methanol are very dependent on the cost of production and the selling price of methanol. The market for methanol is volatile and competitive with large swings in the price. The main components of the production cost of methanol are gas price and the investment cost of the plant. A number of literature sources present the investment costs for steam-reforming-based methanol plants. The investment costs for large-scale methanol plants based on advanced syngas generation technologies are expected to be lower. A producer in a remote location must also consider shipping costs for transporting the methanol product to the market.
Methanol Demand. Methyl tertiary butyl ether (MTBE) phaseout in the United States will have an effect on the worldwide methanol demand; however, the phaseout is expected to be slow and prolonged. The methanol market is currently saturated with adequate available capacity. New large-capacity plants are expected to be on stream by 2004–2005.
The methanol market is saturated; however, it is expected that new plants will be built. In the future, new low-cost production will displace existing high-cost producers unless new applications for methanol are established. Besides the traditional markets, methanol has the potential to be used in a variety of applications: power generation by fuel cells, as a transportation fuel directly or by fuel cells, and as a feedstock for the production of olefins. These new applications, if established, could lead to a surge in demand for methanol plants.
Gas to Power
One of the options for gas monetization is GTP, sometimes called gas to wire (GTW). Electric power can be an intermediate product, such as in the case of mineral refining in which electricity is used to refine bauxite into aluminum; or it can be an end product that is distributed into a large utility power grid. This discussion focuses on electricity as the end product. The primary issues related to GTP are the relative positions of the resource and the end market and transmission methods. The scale or volume of gas and/or power to be transported influences each of these issues.
The most common method to generate power from natural gas uses gas turbine generators (GTGs), either in simple-cycle or combined-cycle configurations. Gas-turbine-based power generation has proven to be the lowest-life-cycle-cost alternative to date for large-scale electric power generation from natural gas.
Simple-cycle plants use GTGs without heat recovery. Combined-cycle plants use GTGs and recover the waste heat from their exhaust-gas streams with heat-recovery steam generators to make steam to run steam turbine generators, thus producing additional power. Simple-cycle installations are lower in capital costs but are less efficient (higher heat rate); whereas, combined-cycle installations have higher capital costs but higher efficiency (lower heat rate).
There are a number of categories of GTGs: aeroderivatives, standard, advanced units such as the F-class, and the so-called G-class and H-class turbines with steam-cooling features. Most GTGs fall into the standard category on the basis of their metallurgy and firing temperatures. The F-class and higher units are generally considered advanced technology units because of their higher firing temperatures and special blade-cooling technologies.
Aeroderivative units are typically more expensive on a unit cost ($/kW) basis and are more efficient than comparable GTGs. Aeroderivative units have the highest power density and typically are limited to approximately 50 MW in individual-unit capacity. They are used for power generation and mechanical drive applications but are typically most prevalent in offshore platform and marine transportation applications in which power density is a significant issue. For GTP, the standard and advanced GTGs are the most likely candidates because of their individual size or scale and the large quantities of power generation involved. Most large power generation facilities are constructed on land. Offshore power generation, either on stationary platforms or floating vessels, is considerably more expensive in terms of unit cost, primarily because of the increased cost of the support structure and other infrastructure costs.
The standard way to transmit large quantities of electricity onshore uses high-voltage alternating current (AC) transmission lines. The power is stepped up in voltage with transformers at the generation sites, transmitted over the transmission lines, and then stepped down in voltage with additional transformers for distribution. AC power transmission is done in three phases at various standard high-voltage levels from 69 kV up to 500 kV.
The capacity and length of large AC transmission systems is limited by technical and economic factors. There are electrical losses in the AC transmission of power because of the inefficiencies in the transformers and simple line reactance and resistance (impedance). The primary alternative to high-voltage AC power transmission is high-voltage direct current (DC) transmission. High-voltage DC systems have been in commercial operation for approximately 30 years and are seeing increased application. The DC transmission system consists of transformers and converters to change the AC power into high-voltage DC power, the transmission lines, and then additional converters and transformers to convert the DC power back into AC for local distribution.
Offshore electric power transmission is usually by marine or subsea cabling. The transmission of limited power capacity over limited distances may use an AC cable system; however, AC cabling has limitations. Moderate- to long-distance marine transmission systems use high-voltage DC systems to manage the technical and cost issues. Subsea DC cables are simpler with fewer conductors.
The amount of power available from a fixed quantity of feed gas depends on several factors including the type of turbine, mode of operation, and transmission system. With regard to long-distance power transmission, there are general rules in relation to the "break-even" distance at which the DC alternative has an advantage over the AC alternative. For power transmission by subsea cable, either shore-to-shore or shore-to-platform, DC transmission is typically favored at distances longer than approximately 50 km (30 miles). For onshore transmission of large quantities of power, DC systems are typically favored at distances longer than 600 to 800 km (300 to 500 miles), depending on system capacity. These are general rules of thumb, and each specific application should be evaluated for its particular characteristics.
With regard to the economic merits of AC vs. DC transmission systems, initial-cost and operating-cost factors should be evaluated. The transmission lines for DC are less costly than AC; however, there are the added costs for the AC/DC conversion systems. Although there are some losses in the conversion of AC to DC and vice versa, the conductor losses for DC are lower. Therefore, the overall system losses for DC can be less than those of AC systems, particularly for long-distance transmission. The various factors have to be weighed to determine the best solution for any given application.
Evaluation of Gas Monetization Options
The evaluation of gas monetization options is a multidimensional problem requiring a systematic approach to selecting the optimal option. In addition to the technical considerations discussed in this chapter, commercial issues and market conditions play a key role in the evaluation process. Fig. 8.13 shows the key steps, as well as the various parameters, involved in the process of selecting gas monetization options.
Evaluation of the Asset (Reserves)
The starting point for any gas monetization study is the evaluation of the gas field to ascertain the quantity and quality of gas. The cost of gas production should be estimated at this stage. In addition to the technical evaluation, a study of the geopolitical situation and business issues is also essential.
Data Gathering for Screening Purposes
If the evaluation in the first step is positive, the next step is to gather adequate information for the screening of the various gas monetization alternatives. An economic model, which could be refined later during the final selection stages, should be developed to evaluate the options. The data gathering during this stage of the evaluation process is fairly extensive, even though the quality of information may be preliminary in nature. The depth and breadth of knowledge that is required may not be available within most companies. The need for assistance from outside consultants and contractors should be evaluated. Consideration of issues related to risk and market analysis should be initiated at this stage of the evaluation process.
Short Listing of Options
A short list of the alternatives is essential to minimize the amount of resources required for more-detailed analysis of the options. The short list should be limited to two or three options.
Data Validation and Collection
Once the short list is complete, a more-detailed evaluation of the alternatives is necessary to select the optimum route to monetize gas. Some of the gas monetization options, such as LNG, ammonia, methanol, and GTL, are unique businesses in themselves and could potentially pose challenges to companies that do not operate in that business segment. Hence, a clear set of evaluation criteria should be defined. This is essential to ensure a good fit with corporate strategies and objectives. The data collected during the screening stage should be verified, and additional data should be collected to support a more-detailed evaluation of the options. External consultants may be required to support the financial, marketing, and business management aspects of the gas monetization options.
The data collected in the previous step form the basis for performing a detailed economic analysis of the options. Risk and market analyses are done in parallel. Risk analysis includes technical, political, market, and financial risk.
Selection of Option
The results of the economic analysis, risk review, and market considerations form the basis for the selection of the final gas monetization option.
Several factors need to be considered in the evaluation and selection of the gas monetization options. These factors include technical, business, and market considerations. Site-specific conditions have a significant impact on the selection process; therefore, no one solution can be considered optimal for all situations. As the gas economy of the future develops, technology advances—including the application of gas and derived products to new markets—will have a significant impact on the selection of the best alternative for monetizing gas.
|L||=||one-way distance, L, nautical mile|
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|CII||—||integral incorporated cascade process|
|CNG||—||compressed natural gas|
|GTG||—||gas to gas|
|GTL||—||gas to liquids|
|GTM||—||gas transport module|
|GTP||—||gas to power|
|GTS||—||gas to solids|
|GTW||—||gas to wire|
|LNG||—||liquefied natural gas|
|LPG||—||liquefied petroleum gas|
|MMscf/D||—||million standard cubic foot per day|
|mtpa||—||million tons per annum|
|mTPD||—||metric tons per day|
|NGH||—||natural gas hydrates|
|NGL||—||natural gas liquid|
|ORV||—||open rack vaporizer|
|PNG||—||pressurized natural gas|
|SMDS||—||Shell middle-distillate synthesis|
|VOTRANS||—||volume-optimized transport and storage|
SI Metric Conversion Factors
|bar||×||1.0+||E + 05||=||Pa|
|bbl||×||1.589 873||E – 01||=||m3|
|Btu||×||1.055 056||E + 00||=||kJ|
|ft3||×||2.831 685||E – 02||=||m3|
|°F||(°F − 32)/1.8||=||°C|
|hp||×||7.460 43||E – 01||=||kW|
|kcal/g mol||×||4.184*||C + 03 13||=||kJ/kmol|
|knot||×||5.144 444||E – 01||=||m/s|
|mile||×||1.609 344*||E + 00||=||km|
|million Btu/hr||×||2.930 711||E – 01||=||MW|
|nautical mile||×||1.852*||E + 00||=||km|
|quad||×||1.055 056||E + 12||=||MJ|
|ton||×||9.071 847||E – 01||=||Mg|
|ton, metric||×||1.0*||E + 00||=||Mg|
|tonne||×||1.0*||E + 00||=||Mg|
Conversion factor is exact.