Abstract
A hydrate slurry process is being developed for capturing associated gas on FPSO's. Natural gas hydrate contains 180 Sm3 of gas per m3 solid hydrate. It is this property that makes hydrates attractive for storage and transport of natural gas. Hydrate mixed with crude oil and refrigerated to -10 C remains stable at atmospheric pressure, for practical purposes. A capital cost estimate for a FPSO-based hydrate slurry process was carried out for 1,440,000 Sm3 associated gas and 16,000 Sm3 crude oil. The marginal capital cost was 160 million US dollars (the hydrate process only). The cost estimate was expanded to a hydrate slurry chain consisting of FPSO-based production, shuttle tanker transport and land-based receiving teminal. The hydrate chain costs were compared to transporting natural gas by a subsea pipeline. It was argued that hydrate slurry technology should be used for distances greater than 220 km. Introduction Stranded gas refers to gas located far away from an existing gas pipeline, and situations where a gas pipeline cannot be built and operated economically. In some cases the gas may be close to markets, but the reserves are too small to justify large investments for a pipeline or a Gas-to-Liquid (GTL) plant. Such situations are found in the Barents Sea, West of Shetlands, Gulf of Mexico, West Africa and offshore West Australia.Associated gas and stranded gas are increasingly becoming synonym in the oil industry. Associated gas produced in fields in remote locations cannot be piped to gas markets. Flaring of such gas is no longer accepted; instead, the gas is re-injected into reservoir structures. However, because of the commercial value of stranded gas, ways are being sought to bring stranded gas to market. GTL technologies are being developed for this purpose world-wide (Helgøy et al. 1997; Knott 1997; Singleton 1997; Skrebowski 1998 and Thomas 1998).
Natural Gas Hydrate (NGH) technology provides an attractive option to solve the stranded 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. Aspects of the NGH slurry technology under development at the Norwegian University of Science and Technology (NTNU) will be presented in this paper.
HydrateProperties
Natural gas hydrate (NGH) contains about 180 Sm3 of gas per m3 of hydrate and can be used to store and transport natural gas. The hydrate needs to be refrigeration to a temperature in the range -20 C to -10 C to be stable at near-atmospheric pressure. The pressure suitable for making hydrates (formation pressure) will be in the range 80-100 bar, depending on temperature. Natural gas hydrates formed at equilibrium conditions contain about 15% wt. gas and 85% wt. water.
The exact pressure-temperature conditions for hydrate formation and decomposition are governed by thermodynamic equilibrium. Equilibrium curves for methane hydrate and a mixture hydrate (93% mol methane, 5% mol ethane and 3% mol propane) are shown in Fig.1 (Gudmundsson et al. 1998). Methane hydrate needs higher pressure to form than mixture hydrate; similarly, methane hydrate decomposes into gas and water at higher pressure than mixture hydrate.
The stability of NGH is closely related to the heat of formation (and decomposition). The heat of hydrate formation is about 410 kJ/kg (Selim and Sloan 1990) compared to 333.5 kJ/kg for ice. The higher heat of formation of hydrate is due to the inclusion of gas molecules in the ice-like hydrate structure. It follows that considerable heat must be removed before natural gas hydrate forms. In subsea flowlines and pipelines, the surrounding seawater provides the cooling.
In industrial processes, the hydrate heat of formation must be removed in heat-exchange equipment. When heat is removed, hydrate will also be formed, provided the pressure is above the equilibrium line. This is one of the major challenges in designing commercial NGH processes.
The high heat of NGH formation contributes also its stability at atmospheric pressure. NGH particles at temperature in the range -20 C to -10 C and atmospheric pressure will be below the equilibrium line. Given enough time, the refrigerated particles will decompose into gas and water. However, hydrate particles refrigerated -20 C to -10 C and stored in large-volume tanks will be surrounded by other hydrate particles. If the large-volume tanks are insulated, there will be no or limited heat flow from the outside. The refrigerated hydrate particles will therefore not receive the heat needed to melt. In effect, NGH remains sufficiently stable for commercial storage and transport (Gudmundsson et al. 1994).
Hydrate Applications
Hydrate slurry. In situations where associated gas is produced in locations without a pipeline, associated gas can be converted into frozen hydrate and mixed with refrigerated crude oil and transported as slurry at atmospheric pressure in shuttle tankers. The associated gas can also be converted into hydrate and mixed with crude oil and transported as slurry under pressure in a pipeline, subsea or over land.
Dry hydrate. 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. NGH (natural gas hydrate) technology will compete in the same market as LNG (liquefied natural gas) and synthetic crude (syncrude) technologies.
Gas storage. In situations where gas storage is required, natural gas can be converted to hydrates and stored at atmospheric pressure and refrigerated. NGH can also be stored in rock caverns under pressure. 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 re-injection into reservoir formations.
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 is stored and then melted when the VOC gases are to be used as fuel or blended with other hydrocarbons.
Other uses. In situations where carbon dioxide needs to be captured and stored, hydrate technology can be used. Carbon dioxide hydrate is heavier than seawater; large-scale storage at depths greater than 250 m offers a potential solution to carbon dioxide disposal. In situations where natural gases need to be cleaned or concentrated, hydrate technology can be used for separation purposes; hydrates are equilibrium products, thus providing an opportunity to separate gases. In situations where fresh water is needed, hydrate technology can be used to form a hydrate from a selected gas and seawater. Dissolved salts are excluded from hydrate formation; the hydrate is then separated and melted elsewhere to release the gas (recycled) and fresh water.
Hydrate Laboratory
A laboratory has been built at the Norwegian University of Science and Technology (NTNU) to study the production rate and properties of natural gas hydrates. The main units of the laboratory are a 9 litre continuous stirred tank reactor (CSTR), a 18 litre tank separator, a shell-and-tube heat exchanger, a centrifugal pump, and a mass flow rate meter, making a circulation loop.
A schematic flow diagram of the NTNU hydrate laboratory is shown in Fig.2. The laboratory is place in a constant temperature room capable of maintaining 0-20 C, with the possibilities of taking the process temperature down to -25 C in the shell-and-tube heat exchanger. The equipment was designed for operation up to 120 bar and is Ex-II classified. The signals from all instruments are transferred to a pc-based data acquisition system.
Hydrates are produced in the 9 litre CSTR where gas is injected into a well stirred liquid; the reactor is baffled. Liquid water and water-in-oil emulsions have been tested. The stirring enhances the heat and mass transfer properties for hydrate formation. The fluid leaving the CSTR contains liquid water (or oil), gas and solid hydrate. The excess gas is separated in the 18 litre separator and the remaining liquid phase and solid hydrate exit as a slurry. The separated slurry can be circulated back to the CSTR through the shell-and-tube heat exchanger and centrifugal pump and mass flow rate meter (Coriolis).
The hydrate slurry can also be passed through various test units. For example, the slurry can be filtered to remove solid hydrate for analysis. The slurry can be passed through a pipe viscometer to determine the rheological properties in laminar and turbulent flow. The various test units operate at the same pressure and temperature as the main circulation loop.
A freezing room and several freezing cabinets are a part of the NTNU hydrate laboratory facilities. The freezing room is used to freeze hydrates under pressure (in filter unit) before pressure release and samples recovery at atmospheric pressure. The freezing cabinets are used to store hydrate samples under controlled temperature and environment (gas blanket and humidity) conditions. Desiccators are used in the freezing cabinets.
In addition to the main hydrate laboratory, the hydrate facilities at NTNU include also a Seteram BT2.15 heat-flow calorimeter. The calorimeter is capable of 100 bar pressure and temperature from -196 C (liquid nitrogen) to 200 C. Samples volumes in the range 8-12 cm3 can be used.
Details of experiments carried out in the NTNU hydrate laboratory have been presented by Gudmundsson et al. (1999), Andersson and Gudmundsson (1999) and Levik and Gudmundsson (1999).
Offshore Slurry Process
Results from the NTNU hydrate laboratory have been used in the development of hydrate production processes; in engineering and feasibility studies. The work has shown that a slurry-based process will be feasible for use on Floating Production, Storage and Offloading (FPSO) units for capturing associated gas. Hydrate slurry produced and stored on a FPSO can be transferred to a shuttle tanker or pumped through a pipeline to shore.
An offshore slurry process will be the first link in a slurry-based hydrate chain consisting of production (and storage), shuttle tanker transport to shore, and shore-based receiving terminal. An illustration of a hydrate slurrry chain is shown in Fig.3. Hydrate slurry is produced offshore from associated gas and crude oil. In addition to the NGH process the FPSO will also have living quarters and other ship and process-related facilities, turret-based production wells, oil and gas process facilities and the NGH slurry process and storage.
Hydrate particles produced in the NTNU hydrate laboratory have been small enough for the slurry to be treated homogeneous. In addition to the small particle size, the small difference in fluid-to-solid density, enhances the homogeneous nature of the hydrate slurries. Hydrate-in-water slurry has a density ratio of 950/1000 and hydrate-in-oil slurry has a density ratio of 950/800, for example. Hydrate slurry mixtures in turbulent flow will exhibit an effective viscosity similar to that of the liquid phase (Andersson and Gudmundsson, 1999b).
In the shuttle tanker option shown in Fig.3, the tanker brings liquid water as ballast from the land-based receiving terminal. After unloading the water the hydrate slurry is pumped to the shuttle tanker and then shipped to the receiving terminal. At the receiving terminal the hydrate slurry is pumped to storage. From the storage tanks the hydrate slurry is fed continuously to heating and melting units and the gas, crude oil and water separated using conventional separation equipment, resulting in gas, crude oil and water. The receiving terminal can be purpose built or integrated into an existing refinery complex. Unless the natural gas is used on-site (refinery/chemical process, power plant) it will be piped through a gas transportation and/or distribution network.
The main units of a FPSO-based hydrate slurry production process are shown in Fig.4. The fluids enter the process from the production wells and are piped to a separator. For the sake of simplicity, it was assumed that produced water was not present. 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. A separator pressure of 20 bara and temperature 30 C were assumed in the cost estimated presented below. 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 90-100 bara
The crude oil from the main separator at 20 bara and 30 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 through traditional means; for example, chemical additives. The heat exchange system will be designed to minimise difficulties arising from handling cold crude oil. Assuming that the hydrate reactors and cooling units operates at 90-100 bara the crude oil must be pumped to the same pressure.
In the hydrate slurry process, natural gas hydrate is 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 receiving terminal, preferably at low temperature and saturated with natural gas. The water will be stored in tanks on the FPSO and further cooled before it enters the hydrate reactors and cooling units.
The streams entering the hydrate reactors and cooling units will be separated gas, cooled crude oil and cooled fresh water. Several reactor and cooling unit designs are possible. The function of the reactors and cooling units is to bring gas and water into intense contact at 90-100 bara and low temperature to make hydrate.
The storage tanks on the FPSO need to have some insulation, to maintain the crude/hydrate slurry at refrigerated conditions. 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 pumping will be used for this purpose.
A shuttle tanker will transport the slurry product to a receiving terminal on land. The shuttle distance can be short or long, depending on the situation. At the receiving terminal the crude/hydrate slurry will be pumped to a recovery process. The slurry is pumped to storage (insulated tank or rock cavern) and from there to a heating (melting) process.
Several designs of receiving terminal 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 recovery process delivers natural gas saturated in water vapour, crude oil saturated in gas and water, and liquid water saturated in natural gas.
FPSO Slurry vs. Gas Pipeline
The early use of NGH technology will depend on many factors, including cost comparison with other technologies. In a 1995 hydrate slurry study by Gudmundsson et al. (1995), the cost comparison was gas reinjection. In a 1996 study on dry hydrate (Børrehaug and Gudmundsson, 1996), the cost comparison was LNG technology. In a 1998 associated gas study (Gudmundsson et al. 1998), the cost comparison was the alternatives methanol and syncrude. In the following, FPSO-based slurry technology will be compared to gas transport by a subsea pipeline. The assumptions and estimates were made within the NGH at NTNU joint industry project.
For the offshore slurry process described above, the capital cost was estimated for a typical FPSO-based situation for an oil production rate of 100,000 bbl/day (=16,000 Sm3/day), a gas-oil-ratio (GOR) of 100 Sm3/Sm3, giving a gas production rate of 1,600,000 Sm3/day. Gas for fuel purposes was assumed 10% of the total gas rate. Therefore, the gas converted to hydrate was 1,440,000 Sm3/day. The gas volume 1,440,000 Sm3 corresponds to 8000 m3 of hydrate if the specific gas content is taken as 180 Sm3/m3. The volume of the slurry will be the oil volume 16,000 m3 and the hydrate volume 8000 m3, in total 24,000 m3.
The capital cost estimate was made on the assumption that a NGH slurry process was placed on a FPSO built to produce oil and gas in a conventional manner. The capital cost estimated for the NGH slurry process was the marginal cost; that is, the additional cost associated with placing the slurry process on the deck of the FPSO. The marginal capital cost of the NGH slurry process was estimated to be 160 M$ (exchange rate, 1$=7.5 NOK).
Oil tankers in class 800,000 bbl (=127,200 m3) were estimated to cost about 110 M$ for North Sea service. Gas (LPG) carriers of similar size were estimateed to cost about 125 M$. It is expected that a NGH shuttle tanker will have a price in the range between the two types of ships. A shuttle tanker sailing 15 knots (nautical mile) per hour will cover a distance of 666 km/day.
A hydrate slurry shuttle tanker 127,200 m3 in size will be able to carry 5 days production, assuming 25,600 m3 of slurry per day (crude oil and hydrate). Assuming it takes 1 day to fill the tanker (at the FPSO) and 1 day to empty the taker (at the receiving terminal), the tanker has "available" 3 days sailing per trip, assuming the volumes given above. This means 1.5 days sailing each way, which means 999 km (speed 15 knots). Normally it takes 12-15 hours to fill and empty crude oil shuttle tankers in the North Sea; therefore, the above assumption is conservative.
The storage tanks on a typical FPSO will be about 145,000 m3 in volume. Therefore, spare storage volume on the FPSO will be less than one day production rate if one shuttle tanker is used and the distance is 1000 km (999 km). For a distance of 2000 km at least two shuttle tankers will be required. The operators of offshore production units and shuttle tankers want a greater spare capacity than one day production. Hovever, a greater spare capacity was not taken into consideration in the present cost estimates.
The capital cost of a receiving terminal depends on the infrastructure already there. It was estimated that the cost of new receiving terminal will be about 60 M$. If the receiving terminal will be integrated into an existing oil refinery and storage facility, the total capital cost will be about 30 M$. The total capital cost of the NGH chain (FPSO, shuttle tanker, new receiving terminal) was therefore 345 M$.
The capital cost of a hydrate slurry chain can be compared to gas transport by pipeline, both FPSO-based. If the pipeline is to be connected to a FPSO, the export riser system and the pipeline landing cost will be about 15 M$. Gas compression and drying of 1.440,000 to 1,600,000 Sm3/day of natural gas will cost about 20 M$. The additional cost, therefore, will be about 35 M$ in total. The cost of a 16" subsea gas pipeline will be about 1 M$/km.
A subsea gas pipeline 100 km in length will cost 100 M$, and a longer pipeline proportionally more. These costs can be compared to the NGH slurry marginal costs per transport distance. The marginal capital cost (capex in M$) for a NGH slurry chain and the capital cost for a gas pipeline are shown in Fig.5. The gas pipeline costs start (0 km) at 35 M$ and increase with distance. The hydrate slurry costs start at 220 M$ (FPSO process and receiving terminal) and increase "linearily" with distance (based on 999 km and 125 M$ for shuttle tanker). It is assumed that other tanker sizes and numbers can be used for other distances. In reality, the shuttle tanker costs for a NGH slurry chain will not be linear, because each shuttle tanker represents a finite capital cost.
The gas pipeline and hydrate slurry lines in Fig.5 cross at about 220 km. It means that if the transport distance is less than 220 km a gas pipeline costs less than a NGH chain. Similarly, for distances greater than 220 km, a NGH chain will have a lower capital cost than a gas pipeline. The annual operating costs of a gas pipeline will be about 2% of the capital cost; the annual operating costs of a NGH slurry chain will presumably be higher. The real cross-over distance, therefore, will be greater than 220 km. It should be noted that the capital cost of the NGH slurry chain in Fig.5 is the marginal cost, while the gas pipeline costs are the total capital costs.
Concluding Remarks
Technology for the use of hydrates for the storage and transport of natural gas is being developed. The use of hydrates to capture associated gas on offshore platforms, especially when the gas is stranded, is a candidate for an early application of hydrate technology. The cost of hydrate technology will in the end determine whether it will be used instead of the competing technologies. Therefore, parallel with scientific and engineering studies, it is important to carry out cost studies for comparison purposes.
For offshore applications, NGH technology is expected to be much lower in cost than the gas-to-liquid technologies reported in the literature. For land-based applications, it is less clear how hydrate technology stands in comparison with established and new technologies. It is expected that hydrate technology will compete with liquefied natural gas technology in certain markets, especially for small and medium-sized applications (less than one typical LNG train). The disadvantage with hydrate technology is that it is not yet proven. Other gas-to-market technologies such as compressed natural gas and conversion to electricity (gas-to-wire) are noteworthy alternatives.
The use of hydrate technology on an FPSO is an attractive alternative for stranded gas applications. In situations where hydrate slurry can be transported to a refinery complex with access to an established gas market, the prospects for an early application is promising. Such situations are found in several locations in Europe and world-wide. When the capital cost of hydrate technology is referenced to marginal costs for a slurry plant on a FPSO, its competitive advantage becomes important for distances of hundreds of km. For distances of thousands of km, hydrate technology offers lower costs than a gas pipeline.
Acknowledgements
The work reported stems from the joint industry project NGH at NTNU, supported by Aker Engineering, Amerada Hess, ARCO, Fortum, Phillips, Shell and Total. The Research Council of Norway supports the work through Dr.Ing. contracts 32706/211 and 125482/212.
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Fig.1 - Equilibrium curve for methane hydrate and mixture hydrate (92% methane, 5% ethane, 3% propane).
Fig.2 - NTNU hydrate laboratory.
Fig.3 - Illustration of NGH slurry chain.
Fig.4 - Block diagram of hydrate slurry process.
Fig.5 - Capital costs for gas pipeline and margina capital costs for NGH slurry chain.
