NATURAL GAS SPECIFICATION CHALLENGES IN THE LNG INDUSTRY
LNG is primarily methane, but in most cases also contains ethane, propane and heavier components. Until recently potential buyers of LNG had some flexibility in the ranges of natural gas properties they were able to accept. In many cases the LNG buyer exported electric power and not natural gas, and therefore did not have to meet the needs of natural gas consumers. But now new markets are opening up where pipelines to consumers already exist, and the consumers have specifications which lie outside the range of the LNG produced at many locations. The challenge is to understand the requirements of the potential new markets and plan ways to meet the requirements of both the LNG exporters and importers.
This paper reviews the natural gas specifications of current consumers and those
expected in the near future, such as North America and others. These specifications are compared to those of LNG being produced, and the options and problems for
conditioning the natural gas on either end of the LNG trade are explored in detail.
Natural gas contains methane, heavier hydrocarbons and inert components which affect burner performance. For this reason pipeline companies and LNG buyers specify allowable ranges of components and heating values. These requirements vary widely depending on the market location. But despite this, LNG product specifications have not been a major plant design issue. Historically, plant designs were based on long term
contracts to few buyers, and there was little need for flexibility in the plant designs, either on the liquefaction or receiving ends of the trade.
However, the situation is changing as LNG trade becomes more global. The owners of liquefaction plants are targeting more than one market, and new markets have requirements that are not always compatible with existing trades. Furthermore the growing spot market for LNG provides opportunities for buyers and sellers who have the ability to be flexible on product specifications. As a result there is now considerable
movement towards technical solutions for conditioning LNG on liquefaction and receiving ends.
WORLDWIDE NATURAL GAS SPECIFICATIONS Natural gas specifications have several purposes, including corrosion prevention, avoiding liquid drop out in pipelines, and burner performance . The specifications for corrosion prevention limit concentrations of CO2, H2S, mercaptans or total sulfur. LNG facilities treat gas down to 50 ppmv CO2 to avoid freezing in the cryogenic processing unit, and therefore meet receiving end pipeline specifications. The sulfur specifications are typically consistent with the Japanese market which limits H2S to 5 mg/Nm3 maximum and total sulfur content to 30 mg/Nm3 maximum. Meeting these specifications for Japan will also meet the requirements for Europe and the US (except California which limits total sulfur to 18 mg/Nm3).
Acid gas is typically removed in an amine unit using the principal that an alkaline solvent will remove acid gas components. CO2 is a weak acid compared to H2S, and the process of taking CO2 down to 50 ppmv often controls the acid gas removal design (H2S is a stronger acid and therefore easier to remove). The exceptions are plants with high concentrations of mercaptans in the natural gas feedstock. Mercaptans are very weak acids and are removed by means other than straight chemical absorption.
To prevent liquid dropout, natural gas pipeline companies limit the amount of butane, pentane and heavier components. LNG plants must remove heavier hydrocarbon components to prevent freezing in the liquefaction process, and the heavies removed become a natural gasoline by-product. Heavy end specifications are therefore not difficult to meet in most liquefaction plants.
Specifications to prevent corrosion and liquids dropout are fairly consistent, and requirements of the LNG plant itself (i.e. avoiding freezing during cryogenic processing) tend to make those specifications almost universal. The requirements for heating value and gas interchangeability remain. Here the specifications vary significantly, as do LNG products from worldwide sources, and it is interchangeability that is presenting the greatest challenges.
Early LNG trade was primarily to Japan from Pacific Rim and Middle East export plants and to Europe from Northern Africa. The Japanese specifications vary depending on the importing utility company, but typically have a high heating value between 39.7 and 43.3 MJ/Sm3 (Megajoules per Standard meter cubed at 1 atm and 15 degrees C,which converts to 1065 to 1160 Btu/SCF for a standard cubic foot at 14.73 psia and 60 degrees F). This relatively high range permits maximum use of infrastructure by moving
greater combustion heat capacity for a given volume. European countries typically allow
wider ranges. Spain, for example, allows a range between 35.0 and 44.9 MJ/Sm3 (940
and 1205 Btu/SCF)
In Europe a gas interchangeability index (the Wobbe Index) is also specified. The Wobbe Index is defined as HHV/ √Gas Specific Gravity (relative to Air) and is often more stringent than the heating value specification. British Standard 7859 provides all the details on standard conditions, component heating values, ideal vs. non-ideal gas calculations and more. The Wobbe Index is not a completely accurate way to predict the behavior of burners using alternate gases, but it is convenient and accurate enough for most purposes. Generally speaking, a gas in the preferred ranges of HHV and Wobbe Index will burn without combustion problems such as flame lifting, flashback, excessive NOx and CO, or yellow tipping. Figure 2 below shows the preferred Wobbe Index region and the consequences of operating in objectionable ranges
The LNG market is changing because of two players in the marketplace: the US and UK. Ironically both new players were in the LNG business in the early to mid 1970’s but a regulatory crisis in the US and North Sea discoveries in the UK resulted in both countries receiving only minimal quantities of LNG. Now the US is projecting a widening gap between gas production and demand that can only be satisfied with LNG imports projected to grow to 90 million metric tons per year (MTPY) by the year 2025.
The UK interconnecting pipelines once exported gas from the UK to the continent, but recently the flow has reversed direction. UK gas imports via pipeline and LNG are now expected for the long term, and three LNG import facilities are now under construction with a combined capacity of about 16 MTPY . LNG capacity increases via expansions of these projects or new projects should provide an additional 8 MTPY by 2013.
Clearly the US and UK demands will have quite an impact on the Atlantic Basin market which is currently at about 49 MTPY. The size of the US and UK markets are more than large enough to target, and dealing with gas quality specs is a requirement for participation. This is especially true in the Middle East where cargoes can go to either Pacific or Atlantic consumers. There are many options for modifying the quality of imported or exported LNG on both ends of the trade, and all parties involved have a high level of interest finding the best solutions for their own situations. The specifications in the US remain somewhat fluid as there is no national standard for heating value or Wobbe Index. In March 2005 the Natural Gas Council (NGC) issued interchangeability recommendations to the Federal Energy Regulatory Commission (FERC) that included a Wobbe Index maximum of 1400 Btu/SCF (52.1 MJ/Sm3). FERC made an announcement on 15 June 2006 where they recommended following the NGC
criteria on a voluntary basis. While this avoids some disruption of trade there is still the
effect of market uncertainty; who takes the risk on quality if there is a chance of mandated requirements in the future?
Natural gas specifications were covered in good detail by Bramoulle, Morin, and Capellethe of Total in their paper “LNG Quality and Market Flexibility Challenges and Solutions” (Reference 1). This paper also covered adjustments in gas quality from a global perspective of the LNG chain. Since these topics have been well covered previously, the discussion below will place more emphasis on the impact interchangeability has on the liquefaction and receiving terminals and the thought process a plant designer goes through to select a solution.
LIQUEFACTION END SOLUTIONS
Modifying heating value at the liquefaction end usually means adding or extracting ethane, propane and butane (LPG), though nitrogen may also play a part. For natural gas supplies rich in LPG components in the Atlantic Basin, a lower high heating value (HHV)
is preferred if the US and UK markets are to be the consumers. On the other hand, Pacific Rim consumers prefer a gas with increased HHV, and Pacific Rim sources that are lean in LPG components may require upward HHV adjustment. Natural gas sourced in the Middle East can go either direction to the Pacific or Atlantic markets, which raises the possibility of producing two product qualities.
Just to make a point, if the cost of liquefaction is assumed to be linear with power then the $/ton of LNG goes up by the same percentage as the specific power. The $/ton of LNG then appears 10% higher for the plant that extracts LPG even though the benefit
of LPG product sales is hidden.
For this reason it is more appropriate to use $/ton of total product including LPG for comparisons to overcome some of the inherent differences between plants with and
without extraction. However most published figures on plant costs and capacities only
provide the LNG product for reference. A similar thought process should also be applied
to specific energy which shows only a 2% difference when based on total product
compared to the 10% difference obtained using only LNG production.
Table 1 also shows the magnitude that product properties change as LPG products are
extracted. The HHV drops by 1.8 MJ/Sm3 while Wobbe Index drops by only 1.0 MJ/Sm3.
The desired Wobbe Index often controls the extent of extraction required and the index is not as sensitive to extraction as heating value (however, as discussed later Wobbe Index is more sensitive than heating value to nitrogen injection).
Another factor a design engineer considers is the optimum amount of LPG extraction.
Natural gas specifications in the design basis are usually given as a range with maximum
and minimum HHV. It is possible to target a lower HHV limit with deeper extraction, or
a higher HHV by allowing more LPG to remain. Usually the LPG netback to the exporter has a higher value as separate LPG products as opposed to components in the
LNG product and in such cases the optimum design tends towards deeper extraction and a lower HHV LNG. Also, once LPG extraction is part of the design, there are many more facilities required for the plant, such as LPG storage and loading; so higher extraction tends to be required to justify the extra cost of these new facilities.
If we extract 95% of the propane and 100% of the butane in the above example, the
HHV becomes 40.0 MJ/Sm3 and the Wobbe Index becomes 51.6 MJ/Sm3. If lower
values are needed then ethane must also be extracted. Ethane extraction has its own
difficulties and is discussed later.
Process Options for LPG Extraction. If LPG extraction is necessary several
processing options exist. The best process for a given application depends on factors
such as the feedstock composition, the degree of extraction needed, and capacity. The more basic process options are as follows:
LPG Recycle. The principle behind recycling LPG is similar to that of the lean oil plants used in gas processing; adding a cold liquid to a natural gas stream absorbs lighter components and increases the amount of recovery beyond what could be achieved solely by chilling. In LNG plants the most common “lean oil” is butane, but in some cases propane and even ethane can be recycled to increase LPG recoveries. Recycling the natural gasoline stream is not done because of the possibility of sending heavy hydrocarbons into the cryogenic exchangers and freezing as a result. A typical LPG recycle flow diagram is shown in Figure 3. The advantage of LPG recycling is that the equipment configuration changes very little from a liquefaction process without LPG extraction. The LPG extraction process is essentially integrated with liquefaction, and it is not difficult to design for operati on in both extraction and non-extraction modes. It is often possible to retrofit an existing plant for extraction even if the original plant did not include extraction, depending on the size of the fractionation equipment.
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