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LNG and GTL drive 50 years of technology evolution in the gas industry

07.01.2012  |  Castel, J. ,  Technip, Paris, FranceGadelle, D. ,  Technip, Paris, FranceHagyard, P. ,  Technip, Paris, FranceOuld-Bamba, M. ,  Technip, Paris, France

The technologies needed to shape an industry transformation exist and have been proven on a large scale, the authors say.

Keywords: [LNG] [GTL] [NGL] [natural gas] [gasification] [liquefaction]

While humankind has been aware of the existence of natural gas since ancient times, its industrial use is relatively recent, with the first natural gas wells drilled in North America in the 19th century. The first “true” natural gas processing plants began operating in Canada at the beginning of the 20th century, but they produced gas mainly for local heating and lighting.

Natural gas has become increasingly popular since the 1940s, and its consumption has grown steadily. Fig. 1 shows increasing gas consumption over the 45 years to 2010. Natural gas is, and will remain, a vital component of the global energy supply, helped by its environmental advantage over other fossil fuels and by growing demand from developing countries. Numerous factors have contributed to the evolution of the natural gas industry over time:

  • The need to handle increasingly difficult resources—e.g., high-contaminants-content reserves, stranded reserves, resources in harsh geographical locations or climates, and subsea reserves
  • Energy-efficiency improvements with regard to economic constraints and environmental regulations
  • Plant capacity increases to limit project costs, requiring equipment scale-up
  • Development of new technologies and processes reaching maturity
  • Tighter oil and gas industry health, safety and environment (HSE) standards and regulations
  • Economic and political developments.

  Fig. 1. Global natural gas consumption,

The gas value chain

Natural gas is a valuable resource, not only as a clean fuel for power and heat generation, but also as a key raw material for the petrochemical and chemical industries. Once cleaned of its impurities, natural gas can be separated into its major components—methane, ethane and liquefied petroleum gas (LPG)—and used as pipeline gas, liquefied for export or converted to liquid fuels or synthesis gas (syngas) for the fertilizer industry, as illustrated in Fig. 2. Natural gas also is a major source of ethane and LPG for the production of olefins via steam cracking.

  Fig. 2.  The natural gas value chain.

In this article, we discuss the evolution of gas processing plants to satisfy ever-growing demand, with a focus on liquefaction and GTL plants.

Natural gas processing

The first step at the majority of the world’s gas processing plants is to eliminate impurities and to recover components heavier than methane. This is done to meet environmental regulations, to avoid corrosion, to maximize revenue, and to comply with product specifications. Gas treatment generally involves a number of steps, as shown in Fig. 3 and listed below:

  • Separation of liquids (hydrocarbons and free water)
  • Acid gas removal (CO2 and/or H2S, when present)
  • Removal of other sulfur compounds (e.g., carbonyl sulfide and mercaptans)
  • Final dehydration for the removal of water to sub-ppm level, which makes the gas acceptable for the downstream cryogenic unit or for export requirements
  • Mercury (Hg) is removed to protect aluminum-based equipment often present in cryogenic units, such as cryogenic heat exchangers; it also may be removed for HSE considerations when the feed gas Hg level is high
  • Heavy hydrocarbons (including benzene) are often separated from the gas since they tend to freeze at the low temperatures encountered in cryogenic sections
  • Natural gas liquids (NGLs), such as ethane and/or LPG, might be extracted to meet product gas specifications (heating value), or because of their inherent economic value.

  Fig. 3.  Process flow of a typical natural gas
  processing plant.

Over the last 100 years, natural gas processing has steadily evolved due to continual scientific and technical advances in related fields:

  • Process design tools and simulation software incorporating more accurate thermodynamic models
  • Research work conducted by chemists to develop new solvents, adsorbents and catalysts, in view of improving natural gas purification performance and economics
  • Development of membrane separation technologies to provide economical and compact designs for high-CO2-content gases (Fig. 4)
  • Developments in the technology and manufacturing of high-efficiency and compact heat exchangers, mass transfer internals, compressors and pumps, etc.
  • Computer-assisted design (CAD) and advances in automation and control facilities.

  Fig. 4.  Cakerawala gas treatment platform with
  CO2 removal on membranes,
  Malaysia/Thailand   joint development area.

Gas/liquids separation has benefited from more efficient internals and mass transfer devices that have been developed with the aid of computational fluid dynamics. The incentive to produce compact equipment to reduce platform costs in the North Sea’s hostile environment, starting in the 1970s, has provided the gas industry with solutions enabling single-train sizes of up to 1,350 million standard cubic feet per day (MMscfd).

Today, CO2 and H2S are commonly removed with one of the formulated amines that have largely replaced hot carbonate, MEA and caustic soda, which were once standard solutions. Formulated MDEAs, possibly mixed with a physical solvent, enable decreased energy consumption, improved performance and reduced corrosion through lower output of heat-stable salts. MDEAs also increase the amount of gas that can be treated in a single column by allowing higher acid gas loading in the solvent.

Sulfur recovery continues to rely on the Claus process, although the application of modern acid gas enrichment and tail gas treating processes means that recovery rates above 99% can be attained even with the most challenging feed gases. Additionally, the dehydration of gas upstream of the cryogenic units is presently done using zeolites—molecular sieve material that has efficiently replaced silica gel and the glycol systems that were first implemented.

Finally, modern, highly optimized cryogenic fractionation processes using turboexpanders and compact heat exchangers allow for the recovery of NGLs, such as ethane and LPG, and the simultaneous removal of heavy hydrocarbons, including benzene.

The gas processing industry has developed a number of improved processes that offer reduced equipment count, improved efficiency and/or reduced operating cost, therefore making it possible to produce gas from challenging reservoirs. Such reservoirs include sour gas fields containing high levels of acid components, such as those encountered in Russia, Kazakhstan, the Middle East (H2S and CO2) or the Far East (CO2); deepwater fields (as found offshore Brazil, Norway, Russia, Australia, the Middle East, Africa, etc.); and fields located in the Arctic.

With the unequal distribution of natural gas reserves around the world, the monetization of some of these resources via pipeline distribution grids or power generation plants can be limited or even impossible. This opens the door for the liquefaction of methane for export as liquefied natural gas (LNG), or for shipment to plants that convert natural gas into syngas for methanol, ammonia and urea synthesis. More recently, the conversion of natural gas into synthetic liquid fuels (synfuels) in gas-to-liquid (GTL) plants has been industrialized at a large scale.

Rapid growth in LNG

Natural gas liquefaction dates back to the late 19th century at an experimental level. LNG technology was developed alongside helium recovery from natural gas in the early 1920s, but it took until 1941 before a commercial peakshaving plant started producing LNG in Cleveland, Ohio for storage in atmospheric tanks.

The possibility of shipping large quantities of LNG to distant consumers was demonstrated for the first time in 1959 by the world’s first LNG carrier, the Methane Pioneer. This event demonstrated that large quantities of LNG could be transported safely across the ocean, creating a market opportunity for the large gas reserves discovered in North Africa’s Hassi R’Mel field and in the Cook Inlet area of Alaska.

The LNG industry is considered to be a young industry since the first baseload export plants were put into operation only in the mid-1960s. The world’s first baseload LNG export plant was the Camel plant in Arzew, Algeria.1 It started up in September 1964, liquefying natural gas from the Hassi R’Mel gas field using a propane-ethylene-methane cascade-refrigeration process. The train capacity was 400,000 tons per year (tpy) of LNG, with production exported primarily to France and the UK.

The opening of the Camel plant marked the beginning of the commercial LNG industry. This facility was followed in 1968 by the startup of the Kenai LNG plant in Alaska, which exported product to Japan. It was also based on pure-component cascade technology, although it used gas turbines for the compressor drivers.

Motivated by the industry’s need for larger production scales and lower equipment count, mixed-refrigerant (MR) processes soon dominated the LNG sector. The Single Mixed Refrigerant (SMR) process was adopted by Esso for the Marsa El Brega plant in Libya in 1970, and the Tealarc double mixed-refrigerant process was developed. Meanwhile, Sonatrach adopted the Dual Pressure SMR Tealarc process for its LNG plant in Skikda, Algeria in 1972, and the Propane Precooled MR (C3MR) process was first licensed by Shell Brunei in 1972.

The LNG industry has grown relentlessly since 1964, undergoing considerable changes. The most prominent of these changes is the increase in single-train capacity, as illustrated in Fig. 5. Individual LNG train capacity was multiplied by a factor of nearly 20 with the 2009 startup of the LNG mega-trains at Ras Laffan, Qatar. These mega-trains—used for Qatargas Trains 4, 5, 6 and 7 and RasGas Trains 6 and 7—each produce 7.8 million tons per year (MMtpy) of LNG.

  Fig. 5.  The evolution of baseload LNG train
  capacity over time.

The continual increase in LNG single-train capacity has been driven by strong demand, and by the industry’s efforts to reduce specific investment and operating costs and to take advantage of larger equipment sizes and improvements in efficiency and technology, including:

  • New refrigerant cycles
  • Larger, more efficient refrigerant compressor drivers
  • Cooling systems that strike a balance of efficiency, cost, reliability and environmental impact
  • Integration of heat and power systems.

Table 1 depicts key features of baseload LNG plants developed over the last 50 years. In the early years of baseload LNG export plants, steam turbines were the drivers of choice for refrigerant compressors, since large turbines were previously developed for the power generation industry and were already widely used in the HPI.

A major breakthrough was achieved in the 1980s with the adaptation of the large, heavy-duty gas turbines used in power generation for mechanical drive, a change that introduced new opportunities for the LNG industry. These heavy-duty gas turbines allowed for high power output, better overall efficiency and reduced capital cost by avoiding excessive water use for steam condensation. At the same time, the use of air cooling for heat rejection appeared as a viable and lower-capital-intensive solution for plants with difficult or no access to seawater cooling, such as the North West Shelf plant in Australia. This trend was maintained in the 1990s and afterward with the use of more powerful gas turbines, which has been a key factor in boosting individual LNG train capacity.

The first decade of the new millennium saw the introduction of large electrical motors—a driver solution with high reliability and good efficiency when power generation is based on a combined cycle. Even though the capital expenditure for such a system can appear quite high, it reflects an industrial vision increasingly focused on reliability and the monitoring of atmospheric emissions. This configuration for large-capacity plants has been applied once, in the Snøhvit LNG plant in Norway.

Of course, the evolution of compressor driver technology is not the sole focus point of the LNG industry’s remarkable progress. The sector also has benefited from continual technology improvements in a number of other areas:

  • Optimization of process configuration and energy integration, which reduces overall cost while improving efficiency
  • Developments in gas processing technologies applicable to the LNG industry, such as high-performance sour gas sweetening solvents, and zeolites and adsorbents for gas contaminant removal to trace levels; these technologies make compliance with stringent product specifications and environmental regulations possible
  • Improvements in the capacity and efficiency of refrigerant compressors
  • Progress in metallurgy and the ability to manufacture, transport and install heavy pieces of equipment, such as the amine absorbers in Qatargas Trains 4 and 5; each absorber weighs 1,450 tons, is 7.4 m in diameter, and rises 46 m high (Fig. 6)
  • Improvements in heat exchanger technology—including large spool-wound exchangers; high-pressure aluminum plate-fin exchangers of large capacity; and high-flux heat exchangers involving special tube design, such as the enhanced tubes, which allow for very low temperature approaches4
  • Progress in CAD (process and thermal design simulation software, dynamic simulation tools, 3D modeling, etc.) allows designers to optimize and check solutions for process configuration, pipe routing and equipment layout.

  Fig. 6.  Amine absorber shell for Qatargas II
  Trains 4 and 5.

To conclude this overview of the evolution of LNG base-load plants, it is worth noting that, while energy efficiency has made significant progress over the past 50 years, this can be mainly attributed to the better integration of power and heat facilities. Improvements in equipment and process configuration represent only 30%, as illustrated in Fig. 7.

  Fig. 7.  Contributions to energy efficiency

Another interesting feature of LNG baseload plants is that most of the project costs are dictated by site-related parameters (e.g., quality of feed gas, climatic conditions, site topography, extent of marine works, local construction environment, accessibility and availability of infrastructure, economic and political conditions, environmental constraints, etc.). The technical design has no influence on these parameters and can only adapt to them. Although technology selection does not have the weight in the total project cost that might be expected, it remains a key parameter for the operation and efficiency of the plant.

Same-capacity LNG trains, separated 50 years

Nearly five decades lie between the 1964 construction of the Camel LNG plant in Algeria and the 2012 startup of the Ningxia Hanas mid-scale LNG plant in China. Both plants have approximately 400,000-tpy individual train capacities (Fig. 8).2

  Fig. 8.  The Camel plant (left) and the Ningxia
  Hanas SSLNG plant (right).

Despite the industry’s tendency to design and build individual liquefaction trains of ever-increasing capacity to improve plant economics, there is a renewed interest in small-scale LNG (SSLNG) plants for monetizing small gas reserves and for supplying isolated communities or areas where the installation of a natural gas distribution grid is too costly. China, India and Brazil have implemented or are planning to install SSLNG plants like the one developed at Ningxia Hanas.

While the Camel plant was designed to process raw natural gas from a field and is dedicated to overseas LNG export via tanker, the Ningxia Hanas plant processes pipeline gas that is already pretreated for contaminants and NGL recovery. The facility’s feed gas requires compression prior to liquefaction, and production is delivered via road tanker. Thus, besides the similarity in capacity, the processing schemes and plant features of the Camel and Ningxia Hanas LNG trains have little in common, as illustrated in Table 2.

This comparison reflects the way the LNG industry has evolved, driven by the need to minimize equipment count and processing steps to reduce capital investment while at the same time obtaining the highest possible efficiency to preserve resources.

A giant leap from Skikda to Qatargas II

An interesting comparison also can be made between the Skikda and Qatargas II LNG projects (Fig. 9). Each one was a pioneering development in its time, but the plants were built and commissioned 36 years apart. Table 3 shows a comparison of the two facilities, which were built in 1972 and 2009, respectively.

  Fig. 9.  The Skikda plant (left) and Qatargas II
  Trains 4 and 5 during construction (right).

Between the first trains of the Skikda plant and the mega-trains of Qatargas II, the individual LNG throughput per train has multiplied by a factor of close to 8, and the overall plant capacity by a factor of 5, leading to a proportional increase in terms of construction quantities. However, fuel gas consumption has been multiplied by only 2.8, reflecting the significant increase in energy efficiency achieved over the period.

The overall duration of the construction and commissioning phases also has been reduced despite the increased workload, the number of simultaneous construction projects in the Ras Laffan area, and the more complex configuration of the Qatargas units due to the presence of H2S and organic sulfur components in the feed gas. The excellent overall efficiency of Qatargas II is due to the use of gas turbines and the deep integration of heat and power systems that recover heat energy from gas turbine exhaust and also use excess compressor driver output for electric power generation.

The industry’s next challenge: FLNG

In recent years, progress in exploration and subsea production technologies has enabled the development of LNG projects that monetize gas reserves located in difficult-to-reach offshore and deepwater locations. An FPSO can be used when oil is discovered, but the associated gas usually must be reinjected because export by pipeline is not economical.

The concept of floating liquefied natural gas (FLNG) is now seen as a leading solution to monetize these types of gas resources. Shell was the first company to invest in FLNG, for the development of its Prelude field offshore Australia. Today, practically all major oil and gas companies have launched FLNG programs. The development of FLNG technology has built on the combination of expertise gained from large oil ​FPSOs, the latest developments in liquefaction processes, experience with production on floating platforms and LNG storage, and innovation in new offloading technologies. Challenges to LNG development in a marine setting include:

  • LNG tank sloshing
  • Offloading LNG between two vessels in the open sea
  • Importing large quantities of high-pressure feed gas through a swivel.

The adaptation of large gas processing facilities to marine environments includes:

  • Compact designs
  • Development of equipment for motion—a challenge for large columns and separation equipment
  • Stringent environmental regulations
  • High reliability and reduced maintenance
  • High flexibility and turndown.

Several FLNG projects are at conceptual or advanced FEED stages for various locations around the world (Fig. 10). Shell’s Prelude FLNG (Fig. 11), one of the first FLNG projects, will be operating 200 km offshore Australia.3 Prelude is designed to produce 3.6 MMtpy of LNG from sulfur-free natural gas, along with LPGs and C5+ condensate.

  Fig. 10.  FLNG project regions and incentives.

  Fig. 11.  Shell Prelude FLNG 3D model.


The Fischer-Tropsch (FT) conversion process is a technology for the production of long-chain paraffins from a syngas mainly composed of H2 and CO. The liquid products from FT conversion can be processed into high-value liquid fuels, lube oils and specialty waxes. The syngas feeding the FT conversion unit can be sourced from any carbon-containing primary feed, such as solid feeds (coal, coke, biomass, etc.), heavy hydrocarbon liquid residues from oil refineries or natural gas.

While the conversion of coal to motor fuels—or coal-to-liquids (CTL) production—was the focus of original FT technology developments around 80 years ago, the main interest is now directed toward gas-to-liquids (GTL)—i.e., the conversion of abundant natural gas resources to competitively priced, high-quality liquid products. Fig. 12 depicts the production process for GTL.

  Fig. 12.  GTL production process flow diagram.

It is only in the last 15 years that industry attention has seriously focused on this monetization route. LNG and GTL are complementary industries. The interest of major oil and gas companies in GTL is supported by multiple incentives, as listed below.

  • GTL can be an alternative solution to crude oil market tensions when oil prices are high worldwide, driven by increasing demand for transportation fuels in developing economies. Gas is more abundant and, depending on location, prices are low relative to oil. In particular, the shale gas revolution in North America promises a durably low-cost feedstock.
  • Demand for low-sulfur diesel is increasing, and there is interest in GTL-based kerosine for aviation use. GTL products are valuable blending components for the diesel and jet fuel pools, enabling refiners to meet the most stringent requirements.
  • Zero-flaring policies are in force in many countries.
  • GTL can provide a solution for monetizing stranded gas reserves.
  • Infrastructure for the transport and distribution of liquid fuels is already in place and can be used to market GTL products.

GTL has benefited from general developments in gas processing technology that have been driven, to some extent, by the LNG sector. Specific GTL developments that have contributed to the technology’s strong position include innovation in reactor and catalyst designs by Sasol and Shell, and the development of large air separation units and methane reformers for syngas production.

Proven commercial technologies for the generation of FT syngas from natural gas are available from applications in the fertilizer and refining industries:

  • Steam methane reforming for a high H2:CO ratio in syngas
  • Autothermal reforming for an intermediate H2:CO ratio
  • Partial oxidation for a low H2:CO ratio.

The optimum solution must be determined on a case-by-case basis, but the industry’s interest is focused on autothermal reforming and partial oxidation configurations, with the potential combined use of gas-heated reformer technology.

GTL technology developments have centered on different FT reactor concepts (fixed bed, fluidized bed or slurry) and catalysts (iron or cobalt based). Although several technologies are at the demonstration-plant stage, only two commercially and technically proven technologies are in use at large-capacity plants.

Sasol has strong experience in FT from coal gasification in South Africa, and it operates two GTL plants: the 23,000-bpd Mossel Bay GTL refinery in South Africa and the 34,000-bpd Oryx GTL plant (Fig. 13). Oryx GTL, a joint venture with Qatar Petroleum, was the first GTL plant in Ras Laffan, Qatar. It was commissioned in 2006.2 This plant processes treated gas produced from neighboring gas plants in Ras Laffan. Meanwhile, Shell technology has been applied at the 14,700-bpd Bintulu GTL plant in Malaysia and also at the 140,000-bpd Pearl GTL plant in Ras Laffan, Qatar. The Pearl GTL facility, which opened in 2011, is the largest in the world.

Fig. 13.  Oryx GTL plant, Qatar.

A positive outlook for gas

The use of natural gas on a large scale appeared relatively late in the 90-year period since Hydrocarbon Processing was first published.

With high and rapidly increasing proven gas reserves worldwide, we anticipate that the natural gas industry will continue to grow and to diversify into markets where usage is still developing. Gas will represent a larger share of the energy mix in fast-growing economies such as India and China, and a significantly bigger share of the transportation fuel market worldwide, either as LNG or as synthetic liquid fuel.

The technologies needed to shape this transformation exist and have been proven on a large scale. New innovations that drive down costs and increase efficiency, while at the same time adapting to the challenges of harsh offshore and Arctic environments are needed. HP


Technip has a longstanding involvement in this gas value chain and has been a partner in many first-of-a-kind developments in gas production and processing. Projects include oil and gas field development; gas treatment; natural gas liquids recovery; liquefied natural gas production (both in onshore and offshore locations); gas-to-liquids production; and applications for ammonia/urea, hydrogen, ethylene and petrochemical derivatives. Technip, founded in 1958, has a history that follows a period of gas industry globalization and intense growth to which the company contributed many landmark projects.


1 Designed and built by Technip
2 Built by Technip
3 Technip, in collaboration with Samsung is executing the first FLNG project
4 Technip/Wieland enhanced tubes

The authors

Joëlle Castel is the chief process engineer and technology officer for gas and sulfur technologies at Technip in Paris, France. She has more than 35 years of experience in the oil and gas industry, either as a process manager or as a technical advisor. Ms. Castel holds degrees in chemical engineering from Ecole Nationale Supérieure des Mines, France and IFP School, France.

Dominique Gadelle is the deputy vice president of the process and technologies division at Technip in Paris, France. He has more than 15 years of experience in the oil and gas industry, and he was previously in charge of the LNG process engineering department at Technip in France. He is a member of the Gas Processors Association and the author of several papers and presentations. Mr. Gadelle received a BS in chemical engineering from Université de Technologie de Compiègne in France.

Philip Hagyard is the senior vice president of Technip’s LNG/GTL product business unit. Mr. Haygard joined Technip in 1982 and has been working in the LNG sector for most of his career. He was the manager of gas and LNG process engineering at Technip in France during Nigeria LNG, Yemen LNG and the Qatargas projects. In his current role, he has helped position Technip for recent awards in LNG, FLNG and mid-scale LNG. Mr. Haygard is a chartered chemical engineer in the UK.

Mohamed Ould-Bamba has served as the vice president of Technip’s LNG/GTL product business unit since 2007. He has spent most of his career in process engineering, covering all aspects of process design, conceptual studies and detailed design of the gas value chain. He also has experience in site activities for gas treatment plants, and he served as the process manager for Technip’s EPC contract for Qatargas II. Mr. Ould-Bamba is a member of the Gas Processors Association Europe management committee and is the author of several papers and presentations. He holds degrees in chemical engineering from Ecole Nationale Supérieure des Industries Chimique, France and IFP School, France.

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Very good TECHNICAL overview and congrats to authors. We didn't read it to support market assumptions/strategy.


It is difficult to exegragate the significance of this shift and its consequences for the business model of the big gas suppliers.LOL. It is not difficult for you to exegragate the significance of any bubble Mark. Keep in mind that the shale producers have lost massive amounts of money because their cost of production is much higher than the market prices that are attracting the new investments that you are touting. One side or the other has to be wrong. In all probability both will likely prove to be wrong. Not only will US exports be cheap – they could also be plentiful. How the hell can you export product at a price that is lower than the cost of production? Is this some economic model that you are touting?Eight projects with a total export capacity of 120m tonnes a year have been proposed, according to Wood Mackenzie, a consultancy. If all are approved and built, the US could become one of the world’s biggest LNG producers.Wells cost $5-$10 million to drill. They are depleted within two years. The EUR is too high and the real recovery rate is insufficient to generate a positive cash flow. That makes this one massive bubble just like tech and hosing were. And once again you tend to ignore the reality.

Sudip Kumar Ganguly

An excellent treatise on Gas processing. It is extremely informative and well compiled, my congratulations to all the authors.



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