Abstract
Use of gas hydrates in the storage and transport of natural and associated gas offers new opportunities to the oil and gas industries. A feasibility study of long distance transport of large volumes of natural gas has already shown a capital cost saving of 24% compared to LNG technology. On-going work on associated gas applications in marginal oil fields indicates that hydrate technology can be developed for use on floating production units.
Introduction
The oil and gas industries are familiar with hydrate deposits in pipes and equipment. 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. Hydrate deposition causes operational and safety problems, which explains the considerable R&D in this field of study. Two international conferences have been devoted to gas hydrates, in New York 1993 and Toulouse 1996 (see end of References) . Books on gas hydrates have been written by Makogon (1981), Berecz and Balla-Achs (1983), Cox (1983), and Sloan (1990). A literature review of gas hydrates has been written by Englezos (1993).
The oil and gas industries are less familiar with the opportunities inherent in the properties of gas hydrates. Because gas hydrates contain typically 150 Sm3 of gas per m3 of hydrate, they can be used to store and transport natural gas and associated gas. The gas content of hydrates depends on many factors, not least the formation pressure. The pressure needed to make hydrates (formation pressure) is in the range 60-80 bara, depending on temperature. In recent years it has become apparent that gas hydrates can be stored at atmospheric pressure, provided the temperature is 10 to 20 C below the freezing point of water. This has opened for cost-effective storage and transport of natural and associated gas in the form of hydrate.
The storage and transport of gas as hydrate at atmospheric pressure has been in focus at the Norwegian University of Science and Technology (NTNU) since 1990. The early work has been reported by Gudmundsson et al. (1994) and more recent work by Gudmundsson et al. (1995, 1996) and Børrehaug and Gudmundsson (1996). The purpose of the present paper is to present some of the opportunities provided by the physical and chemical properties of gas hydrates. Two Dr.Ing. projects are on-going at NTNU on the use of hydrates in the storage and transport of natural and associated gas. Information about literature used in the hydrate work at NTNU can be found on the World-Wide-Web under http://www.ipt.unit.no/~ngh/index.html.
Gas Hydrates
Gas hydrates are often likened to frozen water. When produced in the laboratory, gas hydrates are white like snow (not grey like ice). Gas hydrates form at temperatures above the freezing point of water because the gas molecules stabilise the crystal structure. Furthermore, gas hydrates need pressure to be formed. The structure of gas 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).
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 in 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 a hydrate. The equilibrium depends on many factors, including water composition, gas composition, pressure and temperature. Hydrates formed in natural gas and associated gas will have a different gas composition from the source gas, because of the phenomenon of equilibrium. Three equilibrium curves are shown in Figure 1. They are based on model calculations using a new version of the program CSMHYD developed by Sloan (1990). The three equilibrium lines represent methane (sI), a methane/neohexane mixture (sH) and a methane/ethane/propane (sII) mixture. The values for the methane/ethane/propane mixture are shown in Table1
In batch experiments, the relative volumes of the gas phase and liquid water phase affect the equilibrium compositions (hydrate phase and gas phase). The equilibrium curves in Figure 1, are based on constant gas composition (infinite gas volume). In industrial processes, however, the liquid water and gas volumes are finite, and the gas composition and hydrate composition change with time and location (temporal and spatial changes). Different process configurations will have different changes in composition.
Compositional changes are expected to be greater in batch processes compared to continuous processes. On-going and planned work at NTNU will investigate how and to what extent equilibrium conditions prevail in batch and continuous operations, where natural gas and associated gas are in contact with liquid water solutions. The work takes aim of hydrate production for the storage and transport of natural gas and associated gas.
Properties and Laboratory
Gas hydrates have properties that make them useful in many kinds of applications. The volumetric property of interest is that gas hydrate contains 150 Sm3 of gas per m3 of solid hydrate (higher values are obtainable). The mass property of interest is that gas hydrate contains about 15 wt.% gas and 85 wt.% water. The density of a typical hydrate is about 950 kg/m3. The exact numbers depend on the gas composition and the formation (production) pressure and temperature.
The state that is difficult in gas hydrate applications is pressure. That is, pressure is required to prevent gas hydrate from decomposing into gas and liquid water. The equilibrium line for the natural gas mixture in Figure 1 is shown in Table1. When the temperature is 10 C, the pressure needed is 27 bara. When the temperature is 20 C, the pressure needed is 105 bara. The table shows also the equilibrium values below the freezing point of water. When the temperature is -10 C, the pressure needed is 5.5 bara. When the temperature is -20 C, the pressure needed is 3.6 bara. Other natural gas and associated gas compositions will be represented by a different equilibrium line.
The focus of the gas hydrate work at NTNU has been the storage and transport of natural gas and associated gas hydrate at atmospheric pressure. It was first postulated and then observed in the laboratory, that gas hydrate will not decompose when kept below the freezing point of water (Gudmundsson et al. 1994). Experimental work at NTNU in the early 1990's showed that natural gas hydrate stored at atmospheric pressure and -15 C, for example, did not decompose even though it was below its equilibrium line. The storage of natural gas and associated gas hydrate below the equilibrium line at near-atmospheric pressure and below 0 C has been patented (Gudmundsson, 1990, 1996).
It is expected that the process conditions in hydrate production will affect the volumetric and mass properties. Hydrate reactor, heat exchange and hydrate/water separation technologies are considered important in gas hydrate production. On-going and planned work at NTNU will investigate the many parameters needed to build a gas hydrate production process plant.
A hydrate laboratory has been built at NTNU to study continuous production of gas hydrates. The hydrate laboratory is shown in Figure 2. It is placed in a constant temperature room (0 to 20 C) and is Ex-II classified. The equipment is tested to 150 bara pressure, for operation up to 120 bara. 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 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.
Applications
Associated gas in marginal fields. In situations where associated gas is produced in oil fields, the gas can be flared, reinjected or converted into some transportable product. One such transportable product is gas hydrates. Three situations are envisaged: (a) associated gas is converted into frozen hydrates 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 an transported as slurry under pressure in a pipeline. Condensate could also be used as the liquid phase.
Long-distance transport of natural gas. In situations where gas fields are located far away from gas markets, natural gas can be converted to frozen 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.
Storage of natural gas and associated gas. In situations where gas storage is required, natural and associated 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. The use of structure H hydrates has considerable potential in gas storage operations. The gas to be stored would be methane, while the large molecule that gives structure H would be regenerated.
Natural gas processing and sweetening. In situations where natural gas and associated gas contain a lot of nitrogen, carbon dioxide and hydrogen sulphide, hydrate technology can 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.
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 relatively stable for a long time.
Associated Gas
A hydrate-based concept to capture associated gas on floating production units is under study at NTNU. 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. Preliminary work indicates that the crude oil/gas hydrate slurry has shear-thinning properties, so pumping should not be a problem. At the receiving terminal the slurry is heated to melt the hydrate, and the mixture is separated into gas, oil and water.
The crude oil/gas hydrate slurry concept has been evaluated for a particular case of floating production in a marginal offshore field (Gudmundsson et al., 1995). 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). For the second option, the 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 CAPEX for the slurry option was estimated to be 272 million NOK higher than the reinjection option. However, in the slurry option, the recovered associated gas will be sold. Assuming a gas price of 0.5 to 0.7 NOK/ Sm3 the gas sales amount to 144 to 202 million NOK per year, corresponding to a pay-back time of 1.5 to 2 years.
Natural Gas
A hydrate-based concept to store and transport natural gas at atmospheric pressure is under study at NTNU. 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).
The frozen hydrate method is considered suitable for large scale transport of natural gas over long distances. A feasibility study has been carried out for a NGH (natural gas hydrate) chain for the transport of 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 is assumed to be located on land with loading facilities for large hydrate carriers. The transportation part is by bulk carriers specially designed for frozen hydrate. The regasification part of the frozen hydrate takes place at a receiving terminal located close to markets for natural gas.
The hydrate carriers were assumed to be 357 m long, 60 m wide and with 20 m draught, having a net loading capacity of 322,000 tonne and with a cargo volume of 460,000 m3. The design service speed was assumed 15 knots in transit and 15.8 knots in ballast. Each carrier has 12 box shaped cargo tanks and 12 ballast tanks (140,000 m3) and double bottom. It was assumed that each round trip would take almost 30 days (loading 4 days, unloading 4 days, transit journey 10 days, ballast journey 10 days, waiting 2 days).
Several methods have been studied for the regasification of the frozen hydrate. These include mechanical self unloaders, melting in the carriers, and slurry pumping. The feasibility study was based on melting in the carriers. However, later work has shown that slurry pumping will cost about the same but with the added functionality of hydrate storage at the receiving terminal.
Costing procedures established in the offshore industry were used to arrive at the total capital cost of the NGH chain. The aim of the costing work has been 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 2. 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 is the capital cost of an LNG chain for the same duty. It was found that the NGH chain is 24 percent lower in total capital cost than the LNG chain.
Conclusions
· The oil and gas industries are familiar with hydrate deposits in pipes and equipment, but less familiar with the opportunities inherent in the chemical and physical properties of gas hydrates.
· The refrigeration of gas hydrates to temperatures below the freezing point of water makes possible the storage and transport of natural and associated gas in hydrate form at atmospheric pressure.
· A hydrate laboratory has been built at NTNU to study the continuous production of natural and associated gas hydrates at conditions planned in pilot plant and full scale production processes.
· The use of gas hydrate technology for the conversion of associated gas into a transportable product (crude oil/gas hydrate slurry) is being investigated for marginal oil fields.
· A feasibility study of gas hydrate technology for the transport of natural gas in large volumes for long distances gives a capital cost 24% below that of LNG.
Acknowledgements
The work reported is supported by Aker Engineering (Dr.Ing. Student O.I. Levik) and the Research Council of Norway (Dr.Ing. Student V. Andersson), UTBYGG project 32706/211.
References
Berecz, E. and Balla-Achs, M. (1983): Gas Hydrates, Elsevier, Amsterdam.
Børrehaug, A. and Gudmundsson J.S. (1996): Gas Transportation in Hydrate Form, EUROGAS 96, 3-5 June, Trondheim, 35-41.
Cox, J.L. (1983): Natural Gas Hydrates - Properties, Occurence and Recovery, Butterworths, Woburn (USA).
Englezos, P. (1993): Clathrate Hydrates, Ind. Eng. Chem. Res., 32 (7), 1251-1274.
Gudmundsson, J.S. (1990): Method and Equipment for Production of Gas Hydrate, Norwegian Patent No. 172080.
Gudmundsson, J.S. (1996): Method for Production of Gas Hydrate for Transportation and Storage, U.S. Patent No. 5,536,893.
Gudmundsson, J.S. and Børrehaug, A. (1996): Frozen Hydrate for Transport of Natural Gas, Proc. 2nd International Conf. Natural Gas Hydrates, June 2-6, Toulouse, 415-422.
Gudmundsson, J.S., Hveding, F. and Børrehaug, A. (1995): Transport of Natural Gas as Frozen Hydrate, Proc. 5th International Offshore and Polar Engineering Conf., The Hague, June 11-16, Vol. I, 282-288.
Gudmundsson, J.S., Korsan, K. and Børrehaug, A. (1995): Cruce Oil/Gas Hydrate Slurry - Concept Evaluation, Department of Petroleum Engineering and Applied Geophysics, Norwegian Institute of Technology (now Norwegian University of Science and Technology), Trondheim.
Gudmundsson, J.S., Parlaktuna, M. and Khokhar, A.A. (1994): Storing Natural Gas as Frozen Hydrate, SPE Production and Facilites, 69-73.
Makogon, Y.F. (1981): Hydrates of Natural Gas, PennWell, Tulsa.
Sloan, E.D. (1990): Clathrate Hydrates of Natural Gases, Marcel Dekker, New York. 1st International Conference on Natural Gas Hydrates, New Paltz, New York, June 20-24, 1993.
2nd International Conference on Natural Gas Hydrates, Toulouse, France, June 2-6, 1996.
Figures and Tables
