原文节选自论坛的一本书HANDBOOK OF NATURAL GAS TRANSMISSION AND PROCESSING
有点长
1.8 运输
由于储存的困难，天然气从气藏开采出来需要立即运输至消费地(Cranmore and Stanton, 2000a)。将天然气从油气田输送至市场有几种方式(Rojey et al., 1997; Thomas and Dawe, 2003)，包括管道输送，液化天然气(LNG)，压缩天然气(CNG)，天然气制固体 (GTS) ，如水合物，天然气转换成能源(GTP)，如电力，天然气制合成油(GTL)，包括一系列可能的产品如清洁燃料、塑料先导制品或甲醇，天然气制矿产品(GTC)，如铝、玻璃、水泥或铁。
此后章节分别阐述了天然气能源运输的几种技术方法，并包含了一些需要研究的要点。
1.8.1 管道运输
管道输送是将气从资源集中地区输送到消费地的一种非常便利但不太灵活的方式(Cranmore and Stanton, 2000b)。因为气体不容易储存，所以如果运输管道一旦关闭，生产、接收装置和炼化厂一般也需关闭，除非将管道压力以一定的比例提升才可解决。在过去10年中，（我们）平均每年都新建了超过12，000米的输气管道，其中大多数是跨国管道。如果政局稳定，管道输送可作为长期运输的解决方案之一。这种方法的一个例子即待建的从阿曼到印度的深水管道(EIA, 2002)。但是，此种管道的修建成本尚不明确。海底地形复杂造成管道安装困难、维护费用高昂、沿线再压缩难度大，而技术改变仍是奢望。截至目前，敷设超过2000米的海底管道都是不经济的。如果（我们）能够逾越技术和经济障碍，管道运输将会非常有用。
1.8.2 液化天然气
从七十年代中期起液化天然气技术的有效性已经得到了证明。LNG是天然气的液态形式。当气体被冷却到-162℃时即可被液化并只有室温下天然气体积的1/600。但是天然气的液化需要带有可动部件的复杂机器，成品也需要特制的冷藏船将LNG运至市场。由于1980s中期热力效率的大幅提高，修建液化天然气站场的成本已降低，这使液化天然气成为世界范围的出口天然气的主要方式，很多站场得到扩建，并新建了很多站场。储存LNG需要大容量的低温储罐。低温储罐一般直径70m，高45米，容量为100，000m³LNG。在消费终端，需要一些基础设施将大量天然气从LNG中回收，这些设施同样昂贵，并且易遭破坏。
目前，最大的特制冷藏船能携带135，000m³LNG——相当于28.6亿立方英尺的天然气——不过花费巨大。大容量和连续不断运作才能使热力学效率高、成本降到最低，但这也使小规模的海上储存和小范围的商业使用变得困难。因此，蕴含少量天然气的气源对于进行天然气液化的主要供应商而言是不划算的。但是，一种小型绝热的LNG集装箱正在研究中，如果成功，少量的LNG也能够和油槽车运汽油一样将LNG从LNG储存库往外运输。既便如此，LNG在一段时间储存后应保持较小的油气蒸发损耗。
LNG将会在崛起的天然气领域扮演重要角色，如大多数国家，尤其是石油净进口国，一直都对提高天然气储量高度重视，但是庞大大的能源自立、不断增长的可利用的国内石油储备和环境方面的问题，使LNG的利用进退两难。
1.8.3 压缩天然气
气体在高压下可以装在容器中运输，一般富气（含大量乙烷，丙烷等）需要1800psig的压力，贫气（主要是甲烷）需要3600psig的压力。在此压力下，气体被称作压缩天然气（CNG）。在某些国家，CNG可代替汽车所用的常规燃料（汽油、柴油）。管输天然气为加气站提供气源，但用于将天然气压力升至3000psig的压缩机无论在购买、维护或是运行方面都非常昂贵。另一个选择是把干燥、压缩、冷却后的天然气充入长的大管径直管中，并将管道放入绝热冷藏的轮船货运箱。
通过严格的温度控制，满足容量限制、管材数量质量要求的情况下（按压力和安全考虑），任意指定有效负载能力的船可以运输更多的天然气。压缩机需要合适的压缩机和冷却器，这些设备比天然气液化所需要的设备更便宜，并且由于更具标准化而使成本进一步最小化。CNG的支持者说，它们的终端设备也会比LNG的更简单、更便宜。目前，有两个公司正在分别推广他们各自的新型CNG运输技术，这将在后面谈到(Fischer, 2001)。
“VOTRANS”是EnerSea 运输公司的一项新的海上运输技术。工程研究表明，运用此技术可使装载20亿立方英尺气体、行程超过4000英里的轮船的运输总成本大大低于LNG运输船。这项技术采用了卷成盘状的大直径管结构，本质上是一种航海用管道。为了保持温度，管道结构被放置于充满氮气的绝热室中，从而可以更有效的在低压缩的情况下储存CNG（大约为LNG的40%）。此举增大了容器储存能力，同时降低成本，并且贫气和富气都可以运输。最重要的是，VOTRANS将处理和运输中的气体损耗从LNG的20%降低到了7%以下。
“Coselle”是Cran & Stenning技术公司的CNG运输技术。Coselle系统将长10.6英里，直径6英尺，壁厚0.25英尺的常规直管放入镀锡卷板中。而当储存参数为50℉，3000psi的时候，装载量为330-MMcfg的CNG船可以携带108个镀锡卷板。美国航运局/船级社和挪威船级社得出的结论为Coselle船只“和其他CNG运输船同样安全”。这些船只可在简易的港口设施装卸，包括用软管连接至陆地或平台压缩机站在近海浮标的地方转运(Stenning, and Cran, 2000)。《经济学人》杂志已经对“Coselle” and “VOTRANS”这两种技术做了技术和经济分析，它们可能会成为未来CNG高压储存和运输技术的商用走向。
CNG技术为天然气的短距离运输提供了一条可行之路。此技术旨在使无法安装管道或当选用LPG过于昂贵而无法生产的离岸储量货币化。从技术上说，CNG的对设备的配置、基础设施的要求都更低。有结果表明，当运输距离为2500英里时，运输CNG的成本为每MMBTU $0.93 到 $2.23，而运输LNG的成本根据实际距离为每MMBTU $1.5 到 $2.5。而当运输距离大于2500英里时，CNG的运输成本会高于LNG，原因是两种技术对于气体运输不同容积的差异。
1.8.4 天然气制水合物
天然气可以以固体方式，即天然气水合物(Børrehaug and Gudmundsson, 1996; Gudmundsson, 1996; Gudmundsson and Børrehaug, 1996; Gudmundsson et al., 1995, 1997)来运输。天然气水合物（NGH）是天然气和水所形成的外形像冰的稳定结晶物。虽然NGH仍在试验阶段，但它被认为是除LNG、CNG、管道输送外的又一种将天然气从资源区域运输到消费区域的可行方法。天然气以固体方式输送（GTS）包括3个阶段：生产，运输，再蒸发。某些气体分子，特别是甲烷、乙烷、丙烷，当它们与水分子中的氢结合形成三维晶格结构时就形成天然气水合物。在这种水合物中，晶格由稳定氢键所支撑的水合物构成，而气体分子分布在晶格内部空腔里。水合物外形呈雪花状，需要在有液态水存在、压力高于且温度低于气水相图平衡线的情况下才能形成。在石油天然气领域，水合物是管道杀手并对安全产生威胁。在没有预防措施（如注甲醇）的情况下，操作者必须严格控制管道状态以免生成水合物而阻塞管道。然而，在永冻区和海床纵深500米（1500英尺）以下发现了大量的天然气水合物，如果进行合理开采，水合物将会成为未来30年的主要能源。
对天然气的输送来说，可以人为地将天然气和水在80到100bar、2到10℃条件混合以生成天然气水合物。若此混合物保持-15℃冷藏，它在常压下的分解非常缓慢。如此，水合物浆可以装在简单绝热容器中船运至消费市场。在终端市场，通过控制温度混合物可将水合物浆分解为天然气和水，将气体适当干燥后可用于发电或其他用途。根据制造处理工艺的不同，每吨天然气水合物浆最多可产出160m³天然气。从理论上说，水合物浆的生产只是简单的将冷的水和气体混合在一起。在实际生产中，脱硫天然气被输入水合物生产站场，经过一系列反应装置后转变为水合物浆。每一个反应器都将水合物浆进一步提炼，最后装入运输容器。在接收站，水合物被解离，气体可按需求使用。如果当地水资源缺乏水可再次使用或将其重新注入水合物生成器。因为水已被气体饱和所以它不会将更多气体带入溶液。
水合物混合物可以在常温（0到-10℃）1到10大气压下存储。在此条件下，1m³水合物可生成160m³天然气。这个气体浓度非常吸引人，因为相比于1m³CNG释放200m³气体（3000psig的高压条件）、1m³LNG释放637m³气体（-162℃的低温），水合物在生产上更便利更安全也更便宜。在相对低压下储存天然气水合物更有效率，因为当压力下降时每单位体积的水合物中包含的气体比气体在游离状态或者压缩状态时多得多。相对于管输天然气或LNG，水合物运输需要的启动资金和在不利条件下运输天然气的运营成本更低。由于水合物消除了运输时需要低温和将气体由低压压缩至高压，这是一种非常有效的运输和储存天然气的方式。在标况下1m³干燥水合物小球生成160m³气体，1m³LNG生成637m³天然气。单独来看，体积会造成相当大的不便（以现今的运送成本来说），使用相对便宜的海运来运输水化物会更经济。
1.8.5 天然气发电
如今，运至消费区的天然气大多用于燃料燃烧或者发电。所以在资源地用天然气发电用电缆将电传输到消费地（GTP）是可行的。因此，海上或独立的气井开采的气可作为陆地发电厂的气源，发的电可出售给陆上或其他海上消费者。但是，因为敷设到达海岸线的高能管线和管道敷设差不多一样昂贵，GTP
长距离传输电的电缆的能量损失非常巨大，当传输交流电时的能量损失比输送直流电的损失更大。另外，当直流电转换成交流电，传输中的高压电转换成用户所需的低压电时都会产生能量损失。一些人认为像电流和天然气一样在消费端再处理更具灵活性和热力学效率，因为可将废热用于当地加热和淡化水。从经济学角度也验证了这个意见的正确性，因为每发1千万瓦的电需要每天消耗1百万标准立方英尺的天然气，所以即使发电量很大的发电厂也无法消耗完大点规模的油气田的气体因此气体供应商的销售额也不是很大。但是，GTP在美国仍被当作将阿拉斯加天然气和油田产生的能源传输到人口居住区域的一个可行方案得到广泛关注。
人们还有更实际的考虑，例如如果气体是伴生气，如果发电机停产并且发电厂没有其他气体出口，那么整个的石油生产设备可能都必须被停车，或者气体被释放。同样，如果在发电厂内部出现操作问题，发电机必须迅速停车（大概60s内），以免使小失误酿成大事故。另外，关闭系统自身必须是可靠的，所以如果一个关闭系统在关闭前还需要一次净化循环或冷却系统，这个系统无疑是不合适的(Ballard, 1965)。最后，如果该发电厂关闭操作不简洁或/而且需要迅速被启动（1小时之内），操作者会因为害怕电力分销商追究的经济补偿而在关闭站场产生犹豫。
1.8.6 天然气制合成油
在气体制合成油运输过程中，天然气被转换成为液体，如合成原油甲醇、氨水，并按液体形式输送(Knott, 1997; Skrebowski, 1998; Thomas, 1998; Gaffney Cline and Associates, 2001)。将天然气转换为合成油并不是一项新技术。首先，采用合适的新的催化剂技术将甲烷和蒸汽混合制成合成气（一氧化碳和氢气的混合物）(Cranmore and Stanton, 2000a)。然后将合成气使用Fischer-Tropsch处理工艺（在催化剂存在的情况下）转换成合成油。合成油可用作燃料（一般为清洁燃烧的发动机燃料），润滑油，氨水，甲醇或塑料制造业的先行原料（如同样被用作运输用燃料、LPG替代品、发电用燃料、化学品制造原料的尿素和二甲醚）。
这项复杂的能源密集型处理工艺包含了几百种更新和专利，并且仍在不断发展。大多数最近的修正都关于降低基本建设费用和处理工艺所需的能量消耗，尤其是私人拥有的催化剂和氧充入系统的方式。甲醇是从四十年代就开始使用的气体制合成油。由于原始的制甲醇工艺是一个效率相对比较低的转换过程，其他优化技术已用于提高其效率。甲醇可用作内燃机燃料，但是甲醇作为燃料在现今市场存在局限性，即使为机动车发明的燃料电池或许会对此有所改观。甲醇的最佳用途是作为塑料制造的化工原料。其他GTL处理工艺被发展用于从天然气中生产清洁燃料，如合成油、柴油及包括润滑油和蜡在内的其他产品，但需要复杂和昂贵的采用新兴催化技术的化工厂。
1.8.7 天然气制产品
在像铝、玻璃、砖、水泥和铁块等工业产品的生产过程中需要大量的能量。在GTC概念中，天然气被转换为热力学或电力能量为这类在市场上销售的产品的生产功能。这只是从天然气中获取能量，从电力和直接燃烧中获取热能，而不是通常意义上的GTC概念。从本质上说，气体的能量通过消费品的运输实现转移，但是存在需要需要全面评估的市场风险。GTC站场的建设成本很高，工业消费品生产的原材料，如铁矾土、硅土、石灰石可能在进口方面的可靠性很低。因此，若按此方法出售气体在项目启动前必须经过深思熟虑(Thomas and Dawe, 2003)。
按前面所讨论的内容，将天然气从油气田出口至需求市场有很多种选择。任意一种方式都需要巨额的基础建设投资费用和至少20年的
长期“fail-proof”合同。但是哪种才是将天然气换成钱的最佳选择？天然气资源丰富的国家目前正处于充满挑战的抉择中。一般有两个选择，一是为那些处于困境（没有市场）的气藏选择目标市场，二是为那些不能燃烧或不能重新注入或者开采不经济的小气藏的伴生气选择市场。
天然气按水合物或CNG方式运输比按LNG运输灵活且成本也更低，也可以到达管道敷设不可行的地区。过程的简单是GTS或CNG相对于其他非管输方式最具竞争力的优势，这让GTC或CNG更容易实现低资本费用安装，并为和气体销售商的谈判提供了更大的具有经济吸引力的市场机会。政府和商业企业在选择运输方式时不仅应考虑经济风险，同样也应该从长远上把消极影响，如可能的恐怖袭击、政权变动、贸易禁运考虑在内。Thomas and Dawe (2003)包含了大多数基本的技术要点和广泛的经济指示。一些富天然气国家国内天然气需求已经得到满足，并想依靠出口将储备资本化，他们就需要考虑这些经济暗示。
——节选自《天然气运输和处理手册》
Saeid Mokhatab
William A. Poe
James G. Speight
原文节选自论坛的一本书HANDBOOK OF NATURAL GAS TRANSMISSION AND PROCESSING
1.8 TRANSPORTATION
Gas, as a result of the storage difficulties, needs to be transported immediately to its destination after production from a reservoir (Cranmore and Stanton, 2000a). There are a number of options for transporting natural gas energy from oil and gas fields to market (Rojey et al., 1997; Thomas and Dawe, 2003). These include pipelines, liquefied natural gas (LNG), compressed natural gas (CNG), gas to solids (GTS), i.e., hydrates, gas to power (GTP), i.e., electricity, and gas to liquids (GTL), with a wide range of possible products, including clean fuels, plastic precursors, or methanol and gas to commodity (GTC), such as aluminum, glass, cement, or iron.
The following section examines some of these technical methods by which natural gas energy can be transported and covers many of the essential points needed to enter the discussion.
1.8.1 Pipelines
Pipelines are a very convenient method of transport but are not flexible as the gas will leave the source and arrive at its (one) destination (Cranmore and Stanton, 2000b). If the pipeline has to be shut down, the production and receiving facilities and refinery often also have to be shut down because gas cannot be readily stored, except perhaps by increasing the pipeline pressure by some percentage. In the last decade, on average, over 12,000 miles per year of new gas pipelines have been completed; most are transnational. If political stability can be guaranteed, pipelines may be able to provide a long-term solution for transportation. An example of this approach is a proposed deep water pipeline from Oman to India (EIA, 2002). However, the cost of building such a pipeline remains unclear. Subsea lines over 2000 miles have, until recently, been regarded as uneconomic because of the subsea terrain making pipeline installation and maintenance expensive and any recompression along the route difficult, but changes are in the air! If technical and economic hurdles can be overcome, these pipelines can become effective.
1.8.2 Liquefied Natural Gas
Liquefied natural gas technology has been proven to be effective since the mid-1970s. LNG is the liquid form of natural gas. Gas cooled to approximately −162◦C liquefies and has a volume approximately 1/600 that of gas at room temperature. However, facilities for liquefying natural gas require complex machinery with moving parts and special refrigerated ships for transporting the liquefied natural gas to market (Cranmore and Stanton, 2000b). The costs of building a liquefied natural gas plant have lowered since the mid-1980s because of greatly improved thermodynamic efficiencies, making liquefied natural gas a major gas export method worldwide, and many plants are being extended or new ones are being built in the world. Large cryogenic tanks are needed to store the liquefied natural gas; typically these may be 70 m in diameter, 45 m high, and hold over 100,000 m3 of liquefied natural gas. At the consumer end, an infrastructure for handling the reprocessing of vast quantities of natural gas from LNG is required, which is also expensive and vulnerable to sabotage.
The current largest specially built refrigerated tankers can carry 135,000 m3 of liquefied natural gas, equivalent to 2.86 billion scf of gas, but are very expensive. This makes it difficult for liquefied natural gas to use smaller isolated (offshore) reserves and to serve small markets commercially because it is this large capacity and continuous running that keep thermodynamic efficiency high and costs to a minimum. Thus small volumes of intermittent gas are not economically attractive to the major gas sellers for liquefied natural gas facilities. However, a small well-insulated liquefied natural gas container trade is being investigated, and, if successful, small quantities of liquefied natural gas may be able to be delivered from liquefied natural gas storage, just like the gasoline tankers of today. Even so, liquefied natural gas must be stored for periods of time (months) without significant boil-off losses, which is difficult. LNG will likely play an increasing role in the development of giant gas fields, as most countries, especially net oil importers, are keen on developing their gas reserves, however stranded, for greater energy independence and extending domestic oil reserves where applicable, as well as for environmental reasons.
1.8.3 Compressed Natural Gas
Gas can be transported in containers at high pressures, typically 1800 psig for a rich gas (significant amounts of ethane, propane, etc.) to roughly 3600 psig for a lean gas (mainly methane). Gas at these pressures is termed compressed natural gas. Compressed natural gas is used in some countries for vehicular transport as an alternative to conventional fuels (gasoline or diesel). The filling stations can be supplied by pipeline gas, but the compressors needed to get the gas to 3000 psig can be expensive to purchase, maintain, and operate. An alternative approach has dedicated transport ships carrying straight long, large-diameter pipes in an insulated cold storage cargo package. The gas has to be dried, compressed, and chilled for storage onboard. By careful control of temperature, more gas should be transported in any ship of a given payload capacity, subject to volume limitation and amount and weight of material of the pipe (pressure and safety considerations). Suitable compressors and chillers are needed, but would be much less expensive than a natural gas liquefier and would be standard so that costs could be further minimized. According to the proponents, the terminal facilities would also be simple and hence less expensive. Two new types of CNG transport are being promoted by their respective companies and are discussed next (Fischer, 2001): “VOTRANS” is a new type of CNG marine-transport technology from EnerSea Transport, L.L.C. Its engineering studies indicate that it can move up to 2 Bcf per ship over distances up to 4000 miles at significantly lower total costs than LNG. The technology comprises large-diameter pipe structures manifolded together in tiers, essentially a sea-going pipeline. To maintain temperature, the pipe structures are contained within a nitrogen-filled, insulated chamber. It can store CNG more efficiently at significantly lower compression (∼40% compared to LNG), increase vessel capacities, reduce costs, and transport both lean and rich gas. Finally, VOTRANS minimizes gas losses during processing and transport to less than 7% compared to as much as 20% for LNG.
“Coselle” CNG technology is from Cran & Stenning Technology Inc. The system uses conventional, 10.6-mile-long, 6-in diameter, 1/4-in wall thickness line pipe in large coils (coselles). Such a CNG carrier may have 108 coselles with a 330-MMcfg capacity. Stored gas temperature is 50◦F at 3000 psi. American Bureau of Shipping and Det Norske Veritas have concluded that a Coselle CNG carrier is “at least as safe as other gas carriers.” These ships can be loaded at relatively simple marine facilities, including offshore buoy moorings, through flexible hoses connected to onshore or on-platform compressor stations (Stenning, and Cran, 2000). “Coselle” and “VOTRANS” are two would-be commercial, highpressure gas storage and transport technologies for CNG. Technical and economic analyses of these two technologies were done by Economides et al. (2005).
Compressed natural gas technology provides an effective way for shorter-distance transport of gas. The technology is aimed at monetizing offshore reserves, which cannot be produced because of the unavailability of a pipeline or because the LNG option is very costly. Technically, CNG is easy to deploy with lower requirements for facilities and infrastructure. Results show that for distances up to 2500 miles, natural gas can be transported as CNG at prices ranging from $0.93 to $2.23 per MMBTU compared to LNG, which can cost anywhere from $1.5 to $2.5 per MMBTU depending on the actual distance. At distances above 2500 miles the cost of delivering gas as CNG becomes higher than the cost for LNG because of the disparity in the volumes of gas transported with the two technologies (Economides et al., 2005).
1.8.4 Gas to Solid
Gas can be transported as a solid, with the solid being gas hydrate (Børrehaug and Gudmundsson, 1996; Gudmundsson, 1996; Gudmundsson and Børrehaug, 1996; Gudmundsson et al., 1995, 1997). Natural gas hydrate is the product of mixing natural gas with liquid water to form a stable water crystalline ice-like substance. NGH transport, which is still in the experimental stage, is believed to be a viable alternative to liquefied natural gas or pipelines for the transportation of natural gas from source to demand. Gas to solids involves three stages: production, transportation, and regasification. Natural gas hydrates are created when certain small molecules, particularly methane, ethane, and propane, stabilize the hydrogen bonds within water to form a three-dimensional, cage-like structure with the gas molecule trapped within the cages. A cage is made up of several water molecules held together by hydrogen bonds. Hydrates are formed from natural gas in the presence of liquid water, provided the pressure is above and the temperature is below the equilibrium line of the phase diagram of the gas and liquid water. The solid has a snow-like appearance. In the oil/gas industry, natural hydrates are a pipeline nuisance and safety hazard. Considerable care must be taken by the operators to ensure that these hydrates do not form, as they can block pipelines if precautions, such as methanol injection, are not taken. However, vast quantities of gas hydrate have been found in permafrost and at the seabed in depths below 500 m (1500 ft) and, if exploited properly, could become the major energy source in the next 30 years.
For gas transport, natural gas hydrates can be formed deliberately by mixing natural gas and water at 80 to 100 bar and 2 to 10◦C. If the slurry is refrigerated to around −15◦C, it decomposes very slowly at atmospheric pressure so that the hydrate can be transported by ship to market in simple containers insulated to near-adiabatic conditions. At the market, the slurry is melted back to gas and water by controlled warming for use after appropriate drying in electricity power generation stations or other requirements. The hydrate mixture yields up to 160 m3 of natural gas per ton of hydrate, depending on the manufacture process. The manufacture of the hydrate could be carried out using mobile equipment for onshore and ship for offshore using a floating production, storage, and off-loading vessel with minimal gas processing (cleaning, etc.) prior to hydrate formation, which is attractive commercially. Conceptually, hydrate slurry production is simply mixing chilled water and gas. In practice, processed gas is fed to a hydrate production plant, where a series of reactors convert it into hydrate slurry. Each reactor further concentrates the hydrate slurry. It is then stored and eventually offloaded onto a transport vessel. At the receiving terminal, the hydrate is dissociated and the gas can be used as desired. The water can be used at the destination if there is a water shortage or returned as ballast to the hydrate generator; because it is saturated with gas, will not take more gas into solution.
The hydrate mixture can be stored at normal temperatures (0 to −10◦C) and pressures (10 to 1 atmosphere) where 1 m3 of hydrate should contain about 160 m3 gas per m3 of water. This concentration of gas is attractive, as it is easier to produce, safer, and less expensive to store compared to the 200-m3 per 1 m3 of compressed gas (high pressure ca. 3000 psig) or the 637-m3 gas per 1 m3 of liquefied natural gas (low temperatures of −162◦C). Gas storage in hydrate form becomes especially efficient at relatively low pressures where substantially more gas per unit volume is contained in the hydrate than in the free
state or in the compressed state when the pressure has dropped. When compared to the transportation of natural gas by pipeline or as liquefied natural gas, the hydrate concept has lower capital and operating costs for the movement of quantities of natural gas over adverse conditions. Thus, gas hydrate is very effective for gas storage and transport as it eliminates low temperatures and the necessity of compressing the gas to high pressures. Dry hydrate pellets yield about 160 m3 of gas at standard conditions from 1 m3 of hydrate compared to the 637-m3 per 1 m3 of liquefied natural gas. This is a considerable volume penalty (and hence transport cost) if considered in isolation; with less expensive ships for hydrate transport, the process could be economic.
1.8.5 Gas to Power
Currently, much of the transported gas destination is fuel for electricity generation. Electricity generation at or near the reservoir source and transportation by cable to the destination(s) (GTP) is possible. Thus, for instance, offshore or isolated gas could be used to fuel an offshore power plant (may be sited in less hostile waters), which would generate electricity for sale onshore or to other offshore customers. Unfortunately, because installing high-power lines to reach the shoreline appears to be almost as expensive as pipelines, that gas to power could be viewed as defeating the purpose of an alternative less expensive solution for transporting gas.
There is significant energy loss from the cables along the long-distance transmission lines, more so if the power is AC rather than DC; additionally, losses also occur when the power is converted to DC from AC and when it is converted from the high voltages used in transmission to the lower values needed by the consumers. Some consider having the energy as gas at the consumers’ end gives greater flexibility and better thermal efficiencies because the waste heat can be used for local heating and desalination. This view is strengthened by economics, as power generation uses approximately 1 million scf/day of gas for every 10 MW of power generated so that even large generation capacity would not consume much of the gas from larger fields and thus not generate large revenues for the gas producers. Nevertheless, gas to power has been an option much considered in the United States for getting energy from the Alaskan gas and oil fields to populated areas. There are other practical considerations to note such as if the gas is associated gas, then if there is a generator shutdown and no other gas outlet, the whole oil production facility might also have to be shut down or the gas released to flare. Also, if there are operational problems within the generation plant the generators must be able to shut down quickly (in around 60 s) to keep a small incident from escalating. Additionally, the shutdown system itself must be safe so that any plant that has complicated processes that require a purge cycle or a cool-down cycle before it can shut down is clearly unsuitable (Ballard, 1965). Finally, if the plant cannot shut down easily and/or be able to start up again quickly (perhaps in an hour), operators will be hesitant to ever shut down the process for fear of financial retribution from the power distributors.
1.8.6 Gas to Liquids
In GTL transport processes, the natural gas is converted to a liquid, such as syncrude methanol and ammonia, and is transported as such (Knott, 1997; Skrebowski, 1998; Thomas, 1998; Gaffney Cline and Associates, 2001). The technology of converting natural gas to liquids is not new. In the first step, methane is mixed with steam and converted to syngas or synthetic gas (mixtures of carbon monoxide and hydrogen) by one of a number of routes using suitable new catalyst technology (Cranmore and Stanton, 2000a). The syngas is then converted into a liquid using a Fischer-Tropsch process (in the presence of a catalyst) or an oxygenation method (mixing syngas with oxygen in the presence of a suitable catalyst). The produced liquid can be a fuel, usually a clean-burning motor fuel (syncrude) or lubricant, or ammonia or methanol or some precursor for plastics manufacture (e.g., urea, dimethyl ether, which is also used as a transportation fuel, LPG substitute, or power generation fuel, as well as a chemical feedstock).
Hundreds of modifications and patents have been applied to this complex, energy-intensive process, and further developments continue to the present day. Most recent modifications generally involve lowering capital expenditures and the overall energy required for processing, especially through the use of proprietary catalysts and the manner in which oxygen is added to the system. Methanol is a gas-to-liquids option that has been in commission since the mid-1940s. While methanol produced from gas was originally a relatively inefficient conversion process, optimized technology has improved the efficiency. Methanol can be used in internal combustion engines as a fuel, but the current market for methanol as a fuel is limited, although the development of fuel cells for motor vehicles may change this. Methanol is best used as a basic chemical feedstock for the manufacture of plastics. Other GTL processes are being developed to produce clean fuels, e.g., syncrude, diesel, or many other products, including lubricants and waxes, from gas but require a complex (expensive) chemical plant with novel catalyst technology.
1.8.7 Gas to Commodity
Commodities such as aluminium, glass, bricks, cement, and iron bars all require large quantities of energy in their making. In the gas-to-commodity concept, the gas is converted to thermal or electrical power, which is then used in the production of the commodity, which is then sold on the open market. It is the energy from the gas, heat via electricity or direct combustion, and not the components of the gas-to-liquids concept that is used. The gas energy is, in essence, transported via the commodity, but there are many market risks, which should be fully assessed. The cost of a GTC plant is very high and raw materials for conversion to commodities, e.g., bauxite, silica sand, and limestone, may be difficult to import to sites with reliability. Therefore, much thought has to be given before embarking on the project(s) and monetizing the gas by this route (Thomas and Dawe, 2003).
As discussed earlier, there are a number of options of exporting natural gas energy from oil and gas fields to market. Any gas energy export route requires a huge investment in infrastructure and long-term “fail-proof” contracts, covering perhaps 20 years or more. But which is the best way to monetize the gas? Gas-rich countries are currently in this challenging debate. There could be options for handling niche markets for gas reserves that are stranded (no market) and for associated gas (on- or offshore) that cannot be flared or reinjected or for small reservoirs that cannot otherwise be exploited economically.
Transportation of natural gas as a hydrate or CNG is believed feasible at costs less than for LNG and where pipelines are not possible. The competitive advantage of GTS or CNG over the other nonpipeline transport processes is that they are intrinsically simple, making them much easier to implement at lower capital costs, provided economically attractive market opportunities can be negotiated to the gas seller. The transport options preferred by governments and companies must not only take the economic risks into account, but must also consider the negative effects of possible terrorist activity, political changes, and trade embargos over long periods of time. Thomas and Dawe (2003) cover many of the essential technical points and broad economic pointers needed to enter the discussion of gas-rich states that do not need the gas for domestic use, but wish to monetize their reserves by export.
