Abstract
Natural gas hydrate (NGH) technology is an attractive alternative to capture associated gas on FPSO's to solve the stranded and marginal gas problem in the oil industry. Based on estimates for land-based plants, the capital cost of hydrate technology is considerably lower than LNG, methanol and syncrude technologies. Offshore-based hydrate plants are also expected to be lower in costs. Crude/hydrate slurry processes are being developed for use on FPSO's. NGH technology is safe, environmentally friendly and easily scaleable.
Introduction
A prevalent question in the oil industry is what to do with the associated gas in fields where there is no gas pipeline. The oil industry has seemingly come to a point where new field developments will not be undertaken unless the associated gas problem is solved. Several such associated gas situations can be identified. The term stranded gas has been used for situations where the field to be produced is remote or where the field is located in deep water. The term marginal gas has been used for situations where the field is too small to justify a gas pipeline for long-term production. These associated gas situations apply also to non-associated gas.
The common practice of reinjecting stranded and marginal gas is increasingly being questioned. Ways are being sought to bring stranded and marginal gas to market. The most common current method of bringing non-associated gas to market from distant locations, is also being considered for stranded and marginal gas; that is, LNG (liquefied natural gas) technology. Recent examples include studies reported by Naklie (1997) and Hickman (1997). It was reported by Naklie (1997) that a floating LNG plant design has been developed, which is technically feasible, economical, safe and reliable. However, it was stated by Hickman (1997) that the key technical hurdle in offshore LNG is the development of a suitable safe and reliable loading system, for transferring of LNG at -162 C from the production facility to LNG carriers. For marginal fields in Norway it was stated by Helgøy et al. (1997) that offshore LNG was not considered a competitive solution.
Converting stranded and marginal gas to liquid products other than LNG, has received considerable attention in recent years. For offshore conditions in Norway, both methanol and syncrude are considered viable to solve the marginal gas problem (Helgøy et al. 1997). Syncrude options for remote locations have been presented by Singleton (1997). Gas-to-liquids (GTL) technologies and projects have been presented by Knott (1997), Skrebowski (1998) and Thomas (1998).
Natural Gas Hydrate (NGH) technology provides an attractive option to solve the associated gas problem in the oil industry. While the oil industry is familiar with hydrate deposits in pipes and equipment, the industry is less familiar with the business opportunity offered by NGH technology. Gas hydrates form in pipelines and equipment carrying natural gas, associated gas and mixtures of associated gas and oil, provided liquid water is present. The solid hydrates form readily at temperatures below 20 C and pressures commonly found in pipelines and process equipment.
The storage and transport of gas as frozen hydrate at atmospheric pressure has been studied at the Norwegian University of Science and Technology (NTNU) since 1990. Results have been reported by Gudmundsson et al. (1994), Gudmundsson et al. (1995a, 1996), Børrehaug and Gudmundsson (1996) and Gudmundsson et al. (1997).
Hydrate Applications
Natural gas hydrates contain 150 Sm3 (practically achievable) of gas per m3 of hydrate and can therefore be used to store and transport natural gas. The gas content of hydrates depends on many factors, not least the formation pressure. The pressure suitable for making hydrates (formation pressure) will be in the range 60-90 bar, depending on temperature. The equilibrium lines for methane hydrate and a typical mixture hydrate are shown in Fig.1. The nature and properties of natural gas hydrates are briefly presented in Appendix A. Gas hydrates can be stored at atmospheric pressure, provided the temperature is a few degrees below the freezing point of water. This has opened for cost-effective storage and transport of associated gas in the form of hydrate (Gudmundsson 1990, 1996). Hydrate technology has potential applications in the following situations:
Capturing associated gas - Including hydrate slurry concept. In situations where associated gas is produced in locations without a pipeline: (a) associated gas is converted into frozen dry hydrate and transported as such at atmospheric pressure in shuttle tankers (b) associated gas is converted into frozen hydrate and mixed with refrigerated crude oil and transported as slurry at atmospheric pressure in shuttle tankers (c) associated gas is converted into hydrate and mixed with crude oil and transported as slurry under pressure in a pipeline.
Long-distance transport of natural gas - Dry hydrate concept. In situations where gas fields are located far away from gas markets, natural gas can be converted to frozen dry hydrate. The frozen hydrate is transported at atmospheric pressure in large bulk carriers to market, where the hydrate is melted and the natural gas recovered. Such NGH (natural gas hydrate) technology competes in the same market as LNG (liquefied natural gas) technology.
Gas storage. In situations where gas storage is required, natural gas can be converted to hydrates and stored at atmospheric pressure and refrigerated. The storage operations can be small or large, and can be land-based or offshore. Land-based storage competes in the same market as conventional gas storage operations. Offshore-based storage competes with gas storage by reinjection into reservoir formations.
Natural gas processing. In situations where natural gas and associated gas contain a lot of nitrogen, carbon dioxide and hydrogen sulphide, hydrate technology can potentially be used to separate these gases from the source gas. This because gas hydrates are thermodynamic equilibrium products. Mass transfer operations can be designed to carry out separation and cleaning processes.
Desalination and water treatment. In situations where saline and brackish water need to be cleaned, gas hydrates can be produced and separated from the concentrated solution. This because gas hydrates consume just water and gas, not other constituents such as dissolved salts and biological materials.
VOC recovery. In situations where volatile organic compounds (VOC) need to be recovered, for example on oil tankers and receiving terminals, the hydrate forming gases can be captured in the form of hydrate. The hydrate can be stored and then melted when the VOC gases can be used as fuel or blended with other hydrocarbons.
Carbon dioxide disposal. In situations where carbon dioxide disposal is needed, hydrate technology can be used to capture the gas in the form of a hydrate. Carbon dioxide hydrate can be transported by shuttle tankers and released at depth into the ocean. Because it is heavier than seawater, the carbon dioxide hydrate will sink to the bottom. Provided the depth is greater than 250 m, the carbon dioxide should stay stable for practical purposes.
Dry Hydrate Concept (Feasibility Study)
Hydrate technology can be used to store and transport large volumes of natural gas at atmospheric pressure, in competition with LNG technology. The dry hydrate is produced from natural gas and refrigerated to typically -15 C and then conveyed to bulk carriers. The bulk carriers take the frozen hydrate to distant gas markets where the hydrate is melted and the gas recovered. The hydrate can also be stored at other temperatures below the freezing point of water.
Several conceptual and feasibility studies have been carried out and reported in the literature, the most recent being that of Børrehaug and Gudmundsson (1996) and Gudmundsson and Børrehaug (1996). These were based on a feasibility study carried out by Aker Engineering in 1995 and completed in early-1996 (Aker Engineering 1996) for a NGH chain to transport 400 MMscf/d of natural gas over 3,500 nautical miles, assuming European conditions. This case was selected to make possible comparison with a LNG chain for the same duty. The production part of the NGH chain was assumed to be located on land with loading facilities for large hydrate carriers. The transport part was by bulk carriers specially designed for dry hydrate. The regasification part of the dry hydrate was taken at a receiving terminal located close to markets for natural gas.
Costing procedures established in the offshore industry were used to arrive at the total capital cost of the NGH chain (production, ships, regasification). The aim of the costing work was to find out to what extent NGH technology has the potential to compete with LNG technology. The capital cost (US dollars) of the NGH chain is shown in Table 1.
The cost numbers are for 400 MMscf/d (in 4 parallel trains, 100 MMscf/d each) transported 3,500 nautical miles, based on mid-1995 conditions in Europe. Also shown in the table is the capital cost of an LNG chain for the same duty. It was found that the NGH chain will be 24 percent lower in total capital cost than the LNG chain. This result has provided the main impetus for continued work on hydrate technology.
Comparison of Alternatives
The most common method of transporting natural gas to market is by pipeline. When the distance to market becomes large, it becomes more economical to transport natural gas in the form of LNG (liquefied natural gas). Other options (alternatives) exist for transporting natural gas to market. However, these other options require that the natural gas can be converted into another more transportable product. Examples of such other products are hydrate, methanol and syncrude. The oil industry is working hard to find out under what conditions these other options will be more feasible than the traditional methods of pipeline and LNG transport (see Introduction). A rough comparison of the established (pipeline and LNG) and alternative options will be presented below. The purpose of this comparison is to find out where the NGH (natural gas hydrate) alternative stands in relation to other methods. The capital costs will be presented in terms of transport distance and production capacity.
Transport Distance. In the dry hydrate feasibility study presented above (NGH chain compared to a LNG chain) the capital cost of the production and regasification plants were estimated, as was the transport costs by ship (Børrehaug and Gudmundsson 1996, Gudmundsson and Børrehaug 1996). These cost data can be plotted as shown in Fig. 2. The figure shows the capital costs for the NGH and LNG plants (production plus regasification) plotted at zero distance. The transportation distance assumed was 3500 nautical miles, which equals 6475 km. By adding the capital costs of the ships to the plant costs, the total capital costs for a chain distance of 6475 km can be plotted. Therefore, Fig. 2 shows also how the total capital cost of an NGH chain and a LNG chain depend on transport distance. The two lines diverge a little with distance because the NGH ships were estimated lower in capital costs than the LNG ships.
Two other lines were plotted in Fig. 2. The line identified "Pipe", represents the capital cost of a typical pipeline transporting natural gas. The capital cost was estimated for a 20 inch pipeline on the sea bottom, assuming Norwegian offshore conditions, based on data presented by Gunnarsen (1996). The pipeline cost was taken 1 million US dollars per km (1 US$ = 7.5 NOK). The capacity of such a pipeline is greater than the 400 MMscf/d in the 1995 feasibility study, so Fig. 2 illustrates the overall relationship between pipeline costs and transport by ship. For example, the figure shows that for distances greater than about 1000 km, the capital cost of a pipeline is higher than for NGH. In the case of LNG the cross-over distance is about 1800 km. For reference, the capital cost of pipelines on land is about twice the cost of same diameter pipelines offshore (Berger, 1998).
The fourth line in Fig. 2, identified "Syncrude", represents the capital cost of a natural gas transportation chain based on syncrude. Two preliminary assumptions were necessary to plot the syncrude line. First, that the capital cost of the syncrude production plant was 30% higher than the LNG plan (production and regasification). The cost data in Table 2 could also have been used, but the scale-up would have been uncertain. Second, that the transportation cost was about 30% of the transportation cost of LNG. This assumption means that the capital cost of syncrude ships is about 30% of the capital costs of LNG ships.
Support for the assumptions made was found in a recent study by Kikkawa and Aoki (1998). They compared the capital and operating costs of LNG chain to that of DME (dimethyl ether) chain, an alternative liquid fuel. Kikkawa and Aoki (1998) reported that the break-even transportation distance was between 5000 to 7000 km, depending on the transported volume. Fig. 2 shows that the cross-over distance from LNG to syncrude is about 6000 km; that is, in the middle of the range reported. That syncrude is lower in cost than LNG for long distances has been stressed by Singleton (1998).
Production Capacity. The alternatives to natural gas transport by pipeline and LNG mentioned above include hydrate, dimethyl ether, methanol and syncrude. Nordic Consulting Group (1997), in association with Aker Maritime, carried out a study for the World Bank on the commercialisation of marginal gas field in West Africa. Included in the study was the capital cost estimation for on-land and off-shore plants to produce DME, methanol and syncrude. The results of the Nordic Consulting Group (NCG) study can be used to obtain a relative ranking of the capital cost of the alternatives DME, methanol and syncrude. The NCG results are presented in Table 2 and 3
for on-land and off-shore plants, respectively.
In the tables the production capacity is given in the units reported in the NCG study and also the thermal capacity estimated using the lower heating value data given in Table 4. The last column of the Tables 2 and 3 show the fuel capacity of the alternatives as TOE per day. The fuel capacity was estimated assuming that 1 MW thermal equals 2 TOE/d (TOE = 42300 MJ), based on a standard Norwegian crude (Ministry of Industry and Energy, 1995). It was necessary to use the fuel values because of the difference in the lower heating value of the alternatives (methanol, DME, syncrude).
The capital cost (M$) of on-shore production of methanol, DME and syncrude from Table 2 are plotted in Fig. 3 against fuel capacity (TOE/day). The capital costs of methanol and syncrude plants are shown to be similar, but the syncrude data extends to larger capacities. The DME plant data indicates lower capital costs than either methanol or syncrude. The costing methodology in the Nordic Consulting Group (1997) report gives the total costs of building a land-based plant on the basis of US Gulf Cost costs. The following was assumed: 340 operating days per year, economy of scale exponent 0.65, capital cost battery limits plus 50% for offsites and plus 20% for interests during construction and other pre-operational expenses, 3% annual maintenance costs, 25 years plant life, operating costs based on experience from suppliers and consultants.
Also plotted in Fig. 3 is the capital cost of an NGH plant, shown to be about one-half that of the costs plotted for the other alternatives. The NGH capital cost was taken from the dry hydrate feasibility study discussed above (Aker Engineering 1996) for a land-based plant in Norway. In the feasibility study the 400 MMscf/d hydrate production plant was assumed to be in four equally-sized trains, each sized for 100 MMscf/d of natural gas. The gas was assumed to have a lower heating value of 40.5 MJ/Sm3 as used in Norwegian statistics (Ministry of Industry and Energy, 1995). This translates into 1327 MW thermal and 2654 TOE/d. From Table 1 the capital cost of the NGH plant (production and regasification) was taken as 277 million US dollars; one-fourth of the 400 MMscf/d plant costs.
Nordic Consulting Group (1997) did also make a capital cost estimate for off-shore production of methanol and syncrude; that is methanol-FPSO and syncrude-FPSO. The cost data are shown in Table 3 and plotted in Fig 4. The figure shows that the off-shore capital costs are below that estimated for on-shore plants. The methanol and syncrude plants were assumed placed on a FPSO (Floating Production, Storage and Off-loading) unit producing and processing crude oil. It was assumed that the oil production and processing included most of the facilities necessary, equivalent to the off-sites costs for a land-based plant. Therefore, the methanol-FPSO and syncrude-FPSO alternatives were assumed to carry lower facilities costs than the ordinary oil production and processing; that is, plus 25% instead of plus 50% for offsites.
The methanol-FPSO and the syncrude-FPSO capital costs in Fig. 4 are similar to the land-based costs. It seems reasonable that the hydrate-FPSO alternative would also have capital costs not very different from the land-based costs. Therefore, the hydrate-FPSO alternative will be about 50% of the cost of the methanol-FPSO and syncrude-FPSO alternatives. This difference in estimated capital costs, although approximate, is large enough to provide an incentive to study the natural gas hydrate alternative for capturing associated gas on FPSO’s.
Hydrate Slurry Concept
A hydrate-based concept to capture associated gas on floating production units has been proposed by Gudmundsson (1995) and reported by Gudmundsson et al. (1995b). In the concept, hydrate is produced from the associated gas and refrigerated to typically -10 C. The crude oil is also refrigerated to -10 C and mixed with the hydrate. The resulting slurry will be stable at near-atmospheric pressure, and can be pumped and transported by shuttle tankers to shore. At the receiving terminal the slurry is heated to melt the hydrate, and the mixture is separated into gas, oil and water. A feasibility of this early-version of the hydrate slurry concept will be presented below.
Early Feasibility Study. One of the early slurry concepts was evaluated for floating production in a marginal offshore field (Gudmundsson et al. 1995b). Crude oil production of 6000 Sm3/day with a GOR of 150 was assumed. Two options were considered. First, compression and reinjection of the associated gas. Second, the crude oil/gas hydrate slurry concept. Mass and energy balances were carried out for both of the options, and the incremental costs estimated. The incremental cost in the first options includes the compressor and injection well. The incremental cost in the second option was the hydrate production process offshore, the shuttle tankers and the land-based receiving terminal.
For the first option, oil production with reinjection, it was found that 7.9 % of the associated gas would be used in the process (to run the compressor, primarily). For the second option, the hydrate slurry option, it was found that 15.2 % of the associated gas would be used in the process (offshore production, shuttle tanker, receiving terminal). The incremental capital cost for the slurry option was estimated to be 656 million NOK higher than the reinjection option. This number was taken directly from Gudmundsson et al. (1995b) with a costs adjustment suggested by Laading (1998). However, in the slurry option, the recovered associated gas will be sold (802 million Sm3/d for export). Assuming a gas price of 0.6 to 0.8 NOK/ Sm3 the gas sales income amount to 164 to 218 million NOK per year, giving a pay-back time of 3-4 years.
The 656 million NOK incremental capital cost estimated above included 90 million NOK for shuttle tankers and 450 million NOK for a receiving terminal. Shuttle distances from 150 to 500 km were assumed. The total capital cost of the hydrate-FPSO process (not the FPSO itself) was estimated 1137 million NOK, equivalent to 152 million US dollars. The exported gas was estimated to have a thermal capacity of 376 MW and fuel capacity of 752 TOE/d. These values cannot be compared to the methanol-FPSO and syncrude-FPSO values in Fig. 4 because the hydrate-FPSO values include the facilities costs (excluded in Fig. 4). Nevertheless, the hydrate-FPSO capital costs are below the methanol- and syncrude-FPSO costs.
Process Block Diagram. The production of a crude/hydrate slurry on an FPSO can be achieved in several ways. One possible production scheme was assumed in the hydrate slurry feasibility study presented above. Another possible production scheme will be described in the following; the process block diagram is shown in Fig. 5. The fluids enter the process from the production wells and are piped to a separator. For the sake of simplicity, it is assumed that produced water is either not present or is separated in the separator. It is possible to use produced water in the hydrate process, but this option will not be discussed further. In the separator the gas phase and liquid phase are separated. The quality of this separation is not crucial.
The operating pressure and temperature of the separator depends on the field and well conditions. Both variables have an impact on the hydrate process. For example, separator pressure 50-60 bar and temperature 50-60 C. The higher the pressure the less gas compression required; the higher the temperature the more cooling required. The gas from the main separator enters a compressor and the pressure is increased to 60-90 bar. The compressed gas is cooled as much as feasible, before it enters a hydrate reactor and cooling unit.
The crude oil from the main separator at 50-60 bar and 50-60 C enters a heat exchanger and is cooled as far down as practicable. The crude oil is under pressure and contains gas in solution, so operational difficulties due to low viscosity and waxing are expected to be manageable. The heat exchange system will be designed to minimise difficulties arising from handling cold crude oil. Assuming that the hydrate reactor and cooling unit operates at 60-90 bar the cold crude must be pumped to the same pressure, and then mixed with the crude oil recycle (see later).
In the hydrate slurry process, natural gas hydrate is formed/produced from associated gas and liquid water. In principle, the water used in the process can be fresh water, seawater or produced water. Using fresh water has several advantages. Fresh water can be supplied from a shuttle tanker returning from a slurry receiving terminal, preferably at low temperature and saturated with natural gas. The water will be stored in tanks on the FPSO, this water is further cooled before it enters the hydrate reactor and cooling unit.
The streams entering the hydrate reactor and cooling unit will be cooled gas, cooled crude oil (mixed with cooled recycle oil) and cooled fresh water. Several reactor and cooling unit designs are possible and are under development at Aker Engineering and NTNU. The function of the reactor and cooling unit is to bring gas and water into intense contact at 60-90 bar and low temperature, to make hydrate. The gas and water and hydrate are suspended in a liquid hydrocarbon phase, the crude oil and recycled oil. All phases entering the reactor and cooling unit contribute to the cooling needed to form hydrate, which is large. It takes about 410 kJ/kg to form a natural gas hydrate; this compares to 333 kJ/kg to make ordinary ice.
A multiphase mixture, consisting of excess gas, solid hydrate, excess water and crude oil, exits from the reactor and cooling unit at 15-20 C. The multiphase mixture enters a traditional horizontal tank separator, for example, and the excess gas is separated and recycled into the process; that is, to the gas compression stage. The quality of this separation is not crucial. The slurry leaving the tank separator consists of solid hydrate, excess water and crude oil. The volume of excess water in the overall process will be kept to a minimum. The bulk volume of the slurry, therefore, will primarily be crude oil and solid hydrate; the crude volume will be about double the hydrate volume (due to recycle).
From the tank separator, the solid hydrate and crude oil slurry enter a bank of hydrocyclones, where the slurry concentration is increased. The slurry concentration will be increased to about 50/50 volume crude/hydrate slurry, depending on its properties and field conditions. The density of the crude/hydrate slurry leaving the hydrocyclones will be in the range 900-950 kg/m3 while the density of the crude oil leaving the hydrocyclones will be in the range 800-850 kg/m3. The density of hydrate is almost 950 kg/m3.
The crude oil liquid phase leaving the hydrocyclones will be recycled into the hydrate reactor and cooling unit. Its purpose is to provide cooling and to make slurry transport easier. First is will be cooled from its 15-20 C to as low a temperature as practicable. The recycle crude oil will be mixed with the crude oil from the main separator, as described above.
The crude/hydrate slurry from the hydrocyclones will be at 15-20 C and a pressure below the reactor and cooling unit operating pressure of 60-90 bar. The whole slurry flow needs to be cooled and refrigerated to about -10 C and atmospheric pressure. This will be achieved in a pressure reduction and refrigeration unit. Several designs of this unit are under development at Aker Engineering and NTNU. The crude oil volume of the slurry contains dissolved gas corresponding to less than the 60-90 bar operating pressure of the hydrate process. This gas will be liberated in the pressure reduction and refrigeration unit. The whole mixture will be fed to the slurry storage tanks on the FPSO in such a way that each tank works as a gas/slurry separator at atmospheric pressure. The separated gas can be recycled and/or used as a fuel on the FPSO.
The storage tanks on the FPSO need to have some insulation, to maintain the crude/hydrate slurry at -10 C. The pressure in the tanks will be close to atmospheric pressure. Typically, the crude/hydrate slurry will be transferred from the FPSO tanks to a shuttle tanker at regular intervals. Slurry pump will be used for this purpose.
The crude/hydrate slurry production process has been described above. A shuttle tanker will transfer the slurry product to a receiving terminal on land. The shuttle distance can be short or long, depending on the situation. The tanks of the shuttle tanker need some insulation. At the receiving terminal the crude/hydrate slurry will be pumped to a recovery process. A block diagram of such a process is shown in Fig. 6. The slurry is pumped to storage and from there to a heating process. Several designs of such a process are possible. In the heating process the crude/hydrate slurry is heated to a temperature suitable to hydrate melting and subsequent three-phase separation. The recover process delivers natural gas saturated in water vapour, crude oil saturated in gas and water, and liquid water saturated in natural gas.
NGH at NTNU
A hydrate laboratory has been built at NTNU to study continuous production of natural gas hydrates. The hydrate laboratory has been described by Gudmundsson et al. (1997). It is placed in a constant temperature room (0 to 20 C) and is Ex-II classified. The equipment is tested to 150 bar pressure, for operation up to 120 bar. The NTNU hydrate laboratory has a 9 litre stirred tank reactor and a 18 litre separator vessel. The design capacity of the laboratory is 1 kg/hour of natural gas hydrate. The produced hydrates can be separated in a filter arrangement that can be disconnected for freezing and sample taking. The hydrate laboratory is built such that various types of equipment and methods can be tested. The particle size distribution of hydrates can be studied. An analytical calorimeter is available for measuring the thermophysical properties of natural gas hydrates and to monitor the quality of hydrates produced. A joint industry project called NGH at NTNU has been established, to provide the data necessary to evaluate the feasibility of hydrate processes, including the building of a pilot plant.
Concluding Remarks
Acknowledgements
This paper was written as a part of the joint industry project NGH at NTNU, supported by the following companies: Aker Engineering, Amerada Hess, ARCO, Neste Petroleum, Phillips, Shell and Total. The work is also supported by the Research Council of Norway through contract UTBYGG contract 32706/211. The NGH at NTNU project has the web-address: http://www.ipt.unit.no/~ngh
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Figures and Tables
Appendix A - Nature and Properties of Hydrates
Natural gas hydrates are often likened to frozen water. They form at temperatures above the freezing point of water because the gas molecules stabilise the crystal structure. Furthermore, natural gas hydrates need pressure to be formed. The structure of hydrates has similarities to that of frozen water, except that gas molecules are located inside the crystal structure (not in the space between individual crystals). Books on gas hydrates have been written by Berecz and Bella-Achs (1983), Cox (1983), Makogon (1981, 1997) and Sloan (1997).
Three structures have been identified for gas hydrates: sI, sII and sH. These structures consists of several types of cages, where each cage has the potential to contain one gas molecule. A cage is made of several water molecules held together by hydrogen bonds. If all the cages are filled with a gas molecule, sI will contain 46 water molecules per 8 gas molecules, sII will contain 136 water molecules per 24 gas molecules, and sH will contain 34 water molecules per 6 gas molecules. The ratio of water molecules to gas molecules (called the hydrate number) is 5.75 for sI and 5.67 for sII and sH.
The hydrate number for sI, sII and sH above is the maximum, assuming that all the cages contain a gas molecule. However, that is not the case in real systems. Gas hydrates are non-stoichiometric, which gives variation in their composition. The hydrate number of gas hydrates depends on many factors, including gas composition, pressure and temperature, and formation (production) conditions. The amount of gas contained in a hydrate is sometimes called the degree of filling.
The main natural and associated gas hydrate formers are methane (sI), ethane (sI), propane (sII) and isobutane (sII). Other gas molecules also form hydrates, but then in mixtures with the main hydrate formers just mentioned. Hydrates formed from natural gas and associated gas have structure II. Structure H hydrates are formed from mixtures of gases, where one of the gases must be a help gas, for example methane. The methane stabilises the structure, making it possible for larger cages to form to accommodate larger molecules than found in sI and sII hydrates.
Hydrates are formed from natural gas and associated gas in the presence of liquid water, provided the pressure and temperature are above the equilibrium line. The equilibrium line represents the thermodynamic equilibrium between a gas mixture and water and hydrate. Hydrates formed in natural gas and associated gas will have a different gas composition from the source gas, because of the phenomenon of equilibrium. Two equilibrium curves are shown in Fig. 1 (main text). They are based on model calculations using the program CSMHYD by Sloan (1990). The two equilibrium lines represent methane (sI) and a typical methane/ethane/propane (sII) mixture (C1 92 mol.%, C2 5 mol.%, C3 3 mol.%).
