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PEH:Hydrate Emerging Technologies
Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume VI – Emerging and Peripheral Technologies
H.R. Warner Jr., Editor
Copyright 2007, Society of Petroleum Engineers
Chapter 11 – Hydrate Emerging Technologies
Hydrates are a possibility in oil/gas exploration, production, transportation, or processing, which involves water and molecules smaller than n-pentane. When small (< 9 Å) nonpolar molecules contact water at ambient temperatures (typically < 100°F) and moderate pressures (typically > 180 psia), a water crystal form may appear—a clathrate hydrate. Hydrate structures and formation conditions (pressures, temperatures, and compositions) are specified in the chapter on phase behavior of water + hydrocarbon systems in the General Engineering volume of this Handbook.
The purpose of this chapter is to summarize hydrate applications in the energy industry. Readers who wish a more detailed understanding are directed to recent hydrate monographs (Several available sources) for research understanding or to the abbreviated process handbook for case studies, calculation examples, and software.
In the petroleum industry, there are four clathrate hydrate technological areas: safety and flow assurance in oil/gas drilling, production, and transmission lines; stranded-gas transmission to market in a hydrated state; seafloor stability, affecting subsea-equipment foundations and climate; and energy recovery from hydrates in permafrost and in deep-sea locations.
Because of the industrial predominance of the first application, it is discussed at length in Sec. 11.2, while a brief overview is given on the other three applications with references for further reading. Also, in Sec. 11.2, there is a review and discussion on state-of-the-art technology and how it forms the foundation for applications. Subsequent sections are presented entirely as emerging technology because there are no common industrial practices in these new fields. However, before considering applications in this chapter, the reader may wish to review the hydrate-structure portion in the chapter on phase behavior of water + hydrocarbon systems. Applications can be better understood in terms of the microscopic hydrate structures.
Safety and Flow Assurance in Oil/Gas Pipelines, Drillstrings, and Processing
The most pragmatic hydrate technologies concern new methods of obtaining safe flow assurance in flow channels and drillstrings. The prevention of hydrate-plug formation and safe removal of hydrate plugs represent 70% of deepwater flow-assurance challenges; the remaining 30% deal with waxes, scale, corrosion, and asphaltenes. Before considering prevention of hydrate plugs, it is important to consider safety problems involving hydrate-plug removal.
Safety in Hydrate-Plug RemovalIn addition to the more immediate operating safety hazards, such as plugging blowout preventers, blocking drillstrings, and collapsing casing and drilling annuli, there are less obvious but very important safety hazards for removing hydrate plugs from flow channels. Frequently, improper removal of hydrate plugs results in damage to equipment and threats to safety of personnel. Hydrates cause safety problems for two reasons (both of which are shown schematically in Figs. 11.1a and 11.1b): upon removal, when hydrate plugs are depressurized improperly, with large pressure gradients across the plug, hydrate projectiles frequently erupt from pipes; and when hydrates are heated, large confined pressure increases cause pipe ruptures. 
Fig. 11.1a—Hydrate safety(hydrate projectiles frequently erupt through pipes)(after King et al. 
The most common way to remove a hydrate plug from a flow channel is by depressurization. Flow is stopped, and the line is slowly depressurized from both ends of the plug. At atmospheric pressure, the hydrate stability temperature is invariably less than that of the surroundings, so heat flows from the environment into the hydrate plug. The plug melts radially inward, detaching first at the pipe wall.
Any pressure gradient across the detached plug causes it to act like a projectile, as shown in Fig. 11.1a, with measured plug velocities up to 180 miles/hr for short distances. The hydrate has the density of ice, almost twice that of the surrounding fluid, so at the line velocity, the plug momentum is twice that of the surrounding fluids. When the hydrate projectile encounters an obstruction or change in flow direction, such as a pipe elbow, bend, or valve, the resulting impact or pressure increase frequently causes line rupture, equipment damage, fire, and potential injury or loss of life.
Example 11.1: A Common Plug-Removal Hazard
A Siberian incident, in February 2000, illustrates the second common plug-removal hazard, shown in Fig. 11.1b. A pipe fitter was attempting to remove a hydrate plug by heating an exposed pipeline with a torch. The gas pressure from a dissociated mid-hydrate plug rose rapidly, perhaps being confined by the plug ends. The pipeline exploded, and, in the resulting fire, one man died; four others were badly injured.
Hydrate-plug dissociation should always be done slowly and with great care. Rules-of thumb for safe hydrate-plug removal may be summarized as:
- Always assume multiple hydrate plugs; there may be pressure between the plugs.
- Attempting to move hydrate (or ice) plugs can cause ruptures in pipes and vessels.
- While heating a plug is not normally an option for a buried or submerged pipeline, heating should always be done with great care from the ends of the plug. Heating should be done only with assurance that the plug ends will not contain the pressure.
- Depressurizing a plug gradually from both ends is recommended as a safer alternative to single-sided depressurization. However, it may be impossible to depressurize from both sides, as when only one plug end is accessible or when a very long time is are required to depressurize a large upstream volume. In such cases, very careful single-sided dissociation may be done by experienced personnel.
Recommended remediation procedures are discussed further in Subsection 11.2.3.
Prevention of Hydrate-Plug Formation
What is a typical pressure at which hydrates will form? Hydrate-formation data, at a typical deep seafloor temperature of 39°F, were averaged for 20 natural gases (listed in Chap. 6 of Sloan) with an average formation pressure of 181 psia. Of the 20 gases, the lowest hydrate-formation pressure was 100 psig for a gas with 7 mol% propane, while the highest value was 300 psig for a gas with 1.8 mol% propane. Because systems usually operate at much higher pressures than 181 psia to obtain an economic energy density, hydrates are a possibility whenever small (n-butane or smaller) hydrocarbons come into contact with water.
In the chapter on phase behavior of water + hydrocarbon systems in the General Engineering volume of this Handbook, a hand calculation method, accurate to 75%, is given for hydrate formation. For more-accurate stability estimates using hand and computer calculation methods, see Chaps. 4 and 5 of Clathrate Hydrates of Natural Gases and Chap. 2 of Hydrate Engineering.
There are four techniques to prevent hydrate formation: remove the free and dissolved water from the system with separators, glycol dehydrators, molecular sieves, or other methods; maintain high temperatures so that hydrates do not form; maintain low pressures to keep all phases fluid; and inject some inhibitor to prevent hydrate formation.
The first of these methods of prevention is the most reliable; however, it may not be viable to remove water because of remote locations, submersion, or other factors, so flow channels are frequently operated with inhibitor injection at the well, followed by dehydration at a downstream point. The prediction accuracy of hydrate formation (for the second and third prevention techniques) is acceptable for the energy industry, within 10% pressure for well-defined fluids at temperatures greater than 32°F and pressures below 5,000 psig. In the fourth method, predictions can also indicate the free-water concentration of thermodynamic inhibitors, such as methanol (MeOH), monoethylene glycol (MEG), or salts (in drilling fluids), which are injected to compete with the hydrate structure for water molecules.
A hand calculation method for inhibitor concentration in the free-water phase is discussed later in the chapter. Remember that inhibitors are also in small, but significant, concentrations in vapor and liquid hydrocarbon phases. Because the total-flow fractions of these latter two phases are so large, much of the injected inhibitor is consumed in the vapor and liquid hydrocarbon phases.
Inhibitor partitioning is also summarized with hydrate inhibition in Example 11.2.
Example 11.2: Hydrate Formation in a PipelineNotz provided a case study of hydrate formation, shown in Fig. 11.2, for a Gulf of Mexico pipeline fluid.  To the right of the diagram, hydrates will not form, and the system will exist in the fluid (hydrocarbon and water) region. However, hydrates will form in the region at the left of the line marked "Hydrate-Formation Curve," and hydrate-prevention measures should be taken.
Fig. 11.2—Case study of hydrate formation in a gulf of Mexico pipeline fluid(after Notz et al. 
Pipeline pressure and temperature conditions were predicted using a pipeline prediction program such as OLGA® or PIPEPHASE®, and those conditions are shown as the almost horizontal line, superimposed on the hydrate conditions in Fig. 11.2. At small pipeline distances (e.g., 7 miles) from the subsea wellhead, the flowing stream still retains some reservoir heat so that no hydrate forms. The ocean cools the flowing stream, and, at about 9 miles, a unit mass of flowing gas and associated water enters the hydrate region to the left of the hydrate-formation curve, remaining in the uninhibited hydrate area until 45 miles. Such a distance may represent several days of residence time for the water phase, so that hydrates would undoubtedly form, if inhibition steps were not taken.
In Fig. 11.2, by 25 miles, the temperature of the pipeline system is within a few degrees of the ocean-floor temperature, so that approximately 23 wt% methanol is required in the freewater phase to prevent hydrate formation and pipeline blockage. Methanol-injection facilities are not available at the needed points (9 through 45 miles) along the pipeline. Instead, methanol is injected into the pipeline at the subsea wellhead. In the case of the pipeline, shown in Fig. 11.2, sufficient methanol is injected at the wellhead so that an excess of 23 wt% methanol will be present in the free-water phase over the entire pipeline length.
As vaporized methanol flows along the pipeline in Fig. 11.2, it dissolves into any produced water or water condensed from the gas. Hydrate inhibition occurs in the free water, usually at accumulations where there is a change in flow geometry (e.g., a bend or pipeline dip along an ocean-floor depression) or some nucleation site (e.g., sand or weld slag).
Hydrate inhibition occurs in the aqueous liquid, rather than in the bulk vapor or oil/condensate. While most of the methanol dissolves in the water, a significant amount of methanol either remains with the vapor or dissolves into the liquid hydrocarbon phase. Even though the concentration of methanol in the vapor or liquid hydrocarbon is small, with low water amounts, the majority of methanol may be consumed by the vapor or liquid hydrocarbons because the hydrocarbon-phase fractions are much larger than the water-phase fraction.
In Fig. 11.2, Notz showed that the gas temperature increases from 30 to 45 miles with warmer (shallower) water conditions. From 45 to 50 miles, however, a second cooling trend is observed because of the Joule-Thomson gas-expansion effect. Methanol exiting the pipeline in the vapor, aqueous, and condensate phases is usually counted as a loss because of the expense of regeneration. However, a few companies are considering methanol recovery from the aqueous phase.
Drilling Fluids and Drillstrings. Hydrates can plug drillstrings, blowout preventers, chokes, and other equipment, sometimes requiring the abandonment of drilling operations because of safety constraints.  Water-based drilling fluids are particularly susceptible to hydrate formation. The most important variable affecting hydrate formation is the activity of the water, which is decreased by chemicals that dissolve by bonding to water molecules. Water hydrogen bonds with alcohols or glycols or forms coulombic bonds with salt ions, which are very strong. These bonds effectively compete with water hydrate bonds and prevent hydrate formation until much lower temperatures are reached, in the same way that, in winter, ice is prevented by the addition of antifreeze (glycol) to a car radiator.
It is important to recognize that other nonsoluble drilling-fluid components (e.g., mud solid particles or fluidizers) may affect the kinetics or rate of hydrate formation to determine how rapidly hydrates will form or decompose. However, the hydrate-formation temperature and pressure conditions are determined by water-molecule availability, as impacted by the water-soluble components. An interesting example of a kinetically inhibited drilling fluid was recently proposed by the use of lecithin, which prevented hydrate dissociation in an Arctic hydrate well application.  See the discussion on kinetic inhibition.
Technologies for Hydrate-Plug Prevention. With the state-of-the-art methods of hydrate prevention, we turn to hydrate-plug prevention technology. In addition to the conventional inhibitors MeOH and MEG, there are three new types of hydrate inhibitors, sometimes called low-dosage hydrate inhibitors, which were tested in the field during the 1990s. However, even with the low inhibitor concentrations, for long tiebacks between wellheads and platforms, chemicals typically represent the most expensive flow-assurance solution. Slurry flow and heating/insulation represent, respectively, the fourth and fifth methods of hydrate prevention. A discussion of each method follows.
Deep ocean temperatures are fairly uniform at about 39°F, except for some anomalous deepwater current environments. Gulf of Mexico deepwater wellhead pressures represent some of the highest in the world, at 15,000 psia. Such a combination of low temperatures and high pressures provides high driving forces for hydrate formation. Hydrate-plug prevention requires a system that can withstand a substantial subcooling (ΔT = hydrate equilibrium temperature minus typical deepwater temperature of 40°F) of up to 35°F; high-pressure pipelines have high hydrate-equilibrium temperatures.
Dispersants or Antiagglomerants. The object of these chemicals is to convert water into finely dispersed hydrate particles that can be transported in a hydrocarbon liquid. These chemicals are typified as long-chain quaternary ammonium salts, which easily form hydrates, replacing part of both the water and guest frameworks. While three of the four branches of a quaternary nitrogen salt form as a part of the hydrate structure, the fourth acts as a long tail that protrudes from the hydrate structure and prevents agglomeration of the hydrates into a larger mass. There must be substantial hydrocarbon liquid to disperse the hydrates; the maximum water volume is 40% of the total liquid phase.
The commercial use of dispersants began in the Gulf of Mexico in 2001, after laboratory studies showing ΔT = 45°F subcooling.  These dispersants are particularly effective in hydrate-plug protection upon line shut-ins and restarts. However, more-extensive field testing should be done. As these inhibitors come into commercial use, environmental concerns for water purity will have to be resolved.
Kinetic Inhibitors. These chemicals are polymers with carbon backbones and pendant groups, which adsorb into partially formed hydrate cages to keep the polymer anchored along the hydrate-crystal surface. Growing hydrate crystals are forced to grow around the polymer, stabilizing the hydrates as small particles in the aqueous phase. No liquid hydrocarbon need be present. Field tests have shown these chemicals to be effective at subcoolings up to ΔT = 20°F, at dosages from 550 to 3,000 ppm in the water phase.  There is concern about these chemicals with respect to performance on shut-in and restart; also, a substantial amount of hydrate normally forms upon inhibitor failure.
Emulsifiers. These chemicals work by stabilizing small hydrate particles in an oil phase. Some oils contain natural emulsifiers such that, even with favorable hydrate formation conditions, the water, which might convert to hydrates, is stabilized within the oil phase.  To date, efforts to identify the stabilizing components, remove them, and re-insert them in a noninhibited oil have been unsuccessful. Artificial emulsifiers have been shown to be effective, preventing hydrate plugs in flow loops.  There are concerns about these chemicals regarding the expense of tailoring them for each oil application and the cost associated with emulsion breaking.
Slurry Flow. This method uses the concept from Austvik: hydrates that form in the fluid phases will not adhere to the pipe wall. The ideal slurry system has the use of a subsea separator to remove the majority of produced water and subsequent rapid heat exchange to seafloor temperatures in the hydrate region, causing rapid hydrate formation as a liquid-phase slurry. It should be noted that subsea/downhole separation will help every hydrate-prevention scheme, by removal of most of the free-water fraction that forms hydrates.
A substantial industrial research effort is being spent on development of rapid techniques for hydrate-slurry formation in the fluid. Slurry tests of several proprietary systems have been sponsored by a consortium of energy companies. While this method is the most economical of the hydrate-inhibition techniques, it is also the most ambiguous, in terms of likelihood of success. In particular, there is a concern about agglomeration of hydrate particles during shut-ins.
Insulation and Heating. Because fluids come from the reservoir at high temperatures, a lowcost solution is to preserve the reservoir temperature (or add heat to the line) to keep the system out of the hydrate region. There are three types of insulation listed in ascending order of cost: coatings applied to pipes; pipe-in-pipe (PIP) or bundling; and vacuum-insulated pipes or pipes with insulating gases. Of the three types, the last is so expensive that it is not in commercial use, and with the PIP method, the repair of leaks is a concern. If a bare pipe is considered as the baseline cost, insulation can easily double to quadruple the installed-pipe cost. At the 2000 SPE Flow Assurance Forum, it was estimated that insulation was less efficient than expected approximately 50% of the time. For example, a recent Gulf of Mexico flowline experienced an overall-heat-transfer coefficient of 2 Btu/(hr-ft2-°F), while the design coefficient was 0.176 Btu/(hr-ft2-°F), the latter being a typical value for such applications.
In combination with insulation, line heating may be done through resistance or induction heating, with practice favoring the former. Heating costs are very high, second only to chemical treatment, and the power for heating is generated on platforms, where typically only 5 to 10 MW may be available. There is evidence that short lines (< 20 miles) can be handled with heat management; however, heating solutions may not be practical at line lengths greater than 50 miles.
Several recommendations regarding hydrate-plug removal are summarized next:
- Monitor the system from early hydrate warnings, such as slush in pigging returns; changes in water rates and fluid compositions at the separator; pressure-drop increases; and acoustic signals (pinging) of hydrates hitting the pipelines. Before the line plugs inject methanol or glycol to prevent full flow blockage.
- Pigging partially plugged lines and backpressuring plugged lines should be used with care because plug compaction or "snowplow" accumulation may occur.
- Locate the hydrate-plug midpoint through pressure cycles, monitoring the rate of change of upstream pressures upon reduction or increase of the downstream pressure, as shown on pages 46 and 47 of Sloan.
- Slow depressurization from both sides of hydrate plugs is the preferred method of removal. One-sided depressurization should be done very slowly and cautiously and, then, only if two-sided depressurization is not an option. See the safety cautions in Subsection 11.2.1. In some cases, the fluid hydrostatic pressure must be removed from the face of a plug to enable depressurization; this may be done using coiled tubing as indicated in the following subsection.
- Hydrate plugs melt radially upon slow, two-sided depressurization. It is possible to predict the time for two-sided hydrate dissociation, to determine the size of the annulus between the plug and the pipe, for both dissociation and inhibitor injection past the plug.
- Unlike some cases with wax plugs, hydrate-plugged lines have always been freed from obstruction. However, safety concerns, time, and patience to wait days or weeks are required for hydrate dissociation after depressurization. Attempts to make hourly changes are ineffective. Some solutions, such as attempting to "blow the plug out of the line," can make the situation worse with a larger, compacted hydrate plug.
- Methanol or glycol injection is usually ineffective because of the necessity of having the inhibitor contact the hydrate-plug face. When hydrates form in a vertical portion of a channel, such as a riser or well string, it may be possible to inject glycol or to place a heater at the plug face to promote hydrate dissociation.
Hydrate-plug-removal case studies are detailed in Appendix C of Sloan. With the above state-of-the-art summary for hydrate-plug removal, we turn to emerging hydrate-plug-detection and -removal technology.
Emerging Technology for Hydrate-Plug Detection and Removal. The emerging methods are divided into plug detection and plug removal.
Plug Detection. There are several methods of determining the temperature and pressure along various points in a flow line.  These involve sophisticated methods using fiber optics, Raman spectroscopy, Brillouin backscattering, Bragg grating pressure sensors, and acoustic hydrophones. To date, these methods have been demonstrated only under research conditions. For hydrates in lines above the water, it is possible to locate the hydrate plug on depressurization, using infrared sensors to determine the low temperature caused by the endothermic heat of dissociation. (See Fig. 3.7 on page 44 of Sloan.)
Plug Removal. Coiled tubing represents the primary mechanical means of freeing the hydrate plug, but the maximum coiled-tubing distance is currently approximately 5 miles. Coiled tubing may be used to remove a substantial liquid hydrostatic head at the hydrate face to enable depressurization. Coiled tubing may also be used to inject methanol or glycol at the face of a hydrate plug, when density is insufficient to drive the inhibitor to the plug face.
In order of industrial significance, flow-assurance and flow-channel safety concerns surpass all other concerns by several orders of magnitude. The second (transporting stranded gas) and third (seafloor stability and environment) concerns are more eminent than the fourth (energy recovery). Because none of the three are in current industrial practice, they have no state-of-the-art exposition—they are all considered emerging technologies.
Transporting Stranded Gas as Hydrates
When natural gas is discovered far from a pipeline and when the quantity of gas is insufficient to justify a liquefaction facility, it may be possible to transport gas by conversion into hydrates. The concept is that the hydrate concentrates gas by a factor of about 164, without the cost of compressing and transporting gas at high pressure.
In shipping, preservation of hydrated gas is vital to prevent losses. Recent measurements have shown that only a mild amount of refrigeration (e.g., to 20°F) will prevent rapid hydrate dissociation, with rates that are several orders of magnitude less than values interpolated from lower or higher temperatures.  The cause for this anomalous hydrate self-preservation effect is most likely uncertain because of an outer ice barrier that prevents inner-particle dissociation. The ice protective shell happens because the water from the melted hydrate surface, caused by endothermic hydrate melting, freezes.
Laboratory measurements and calculations indicated that hydrated-gas transportation is economical for distances that are greater than approximately 400 km.  British Gas Ltd. has a pilot facility to convert gas to hydrate. The Japanese Natl. Marine Research Inst. began a similar project, and there will be further investigation of transportation economics compared to liquefied natural gas.
A schematic diagram of stranded-gas-hydrate formation, transportation, and dissociation system is shown in Fig. 11.3.  In the first block, gas and seawater are combined to form hydrates on a floating production, storage, and offloading (FPSO) vessel. The second block is concerned with transportation and storage, and the third deals with hydrate dissociation and integration into the gas distribution system at a port. There are three factors to this approach becoming an economic process: initial formation of large amounts of gas hydrates to prevent high-pressure recompression on recycle; reproducible, rapid conversion of water to hydrate so that a minimal amount of water is transported; and transportation of hydrated gas to port with small amounts of refrigeration and dissociation. This is perhaps one of the more innovative emerging techniques for gas transportation.
Fig. 11.3—Schematic diagram of a stranded-gas-hydrate formation, transportation, and dissociation system (after Shirota et al.
Gas Hydrates in Nature: Seafloor Stability
For a more thorough understanding of this subject, refer to a recent monograph review of the geology, geophysics, and geochemistry of hydrates and seafloor stability.  Only a brief summary is given here.
In natural settings, such as the ocean bottom, when buried organic matter decomposes to methane and dissolves in water, clathrates form at temperatures greater than 277 K (4°C or 39°F). Biogenically produced methane, in dissolved water, forms hydrates very slowly because of mass-transfer limitations. Over geologic time, the total enclathrated methane in the oceans has been estimated at 2.1 × 1016 standard cubic meters (SCM)—twice the energy total of all other fossil fuels on Earth.  The amount of hydrated methane in the northern latitude permafrost is relatively small (7.4 × 1014 SCM), within the error margin of ocean hydrate estimates.
Fig. 11.4 shows world hydrate deposits in the deep ocean and permafrost, most of which were determined by indirect evidence such as seismic reflections called bottom simulating reflectors (BSRs). These seismic signals are caused by velocity inversions because of gas beneath some higher-velocity barrier, such as a hydrate deposit. The hydrates contribute only in a minor way to the signal. Substantial efforts are currently underway to perform multidimensional seismic studies to determine the geographic extent. 
Fig. 11.4—Hydrate deposit locations in the deep ocean and permafrost(after Kvenvolden
Fig. 11.5—Seafloor sediment slump off the Carolina coast associated with hydrate decomposition(after Dillon et al. 
Because the atmosphere warmed by 4°F with shallow oceans in the Late Paleocene (55 million years ago), there is evidence for the hypothesis of Dickens et al. that ocean methanehydrate dissociation caused a large greenhouse-gas warming of 14°F, significantly impacting evolutionary processes. Atmospheric-induced changes in the ocean-floor temperature are not likely to occur in current times because deeper oceans effectively constrain temperature changes. Such factors as geologic tectonism and warm-ocean-current circulation may contribute to modern ocean-hydrate disruption.
The concern for seafloor safety is considerably impacted by the fact that BSR indications of hydrates are not totally reliable. For example, on DSDP Leg 164 drilling off the Carolinas, close to the slump (shown in Fig. 11.5) three holes were drilled—one without a BSR, one with a weak BSR, and one with a very strong BSR. Hydrates were found in all three wells. Such hydrated sediments are fairly dispersed—typically 3.5 vol% in sediments. A more significant concern is the fact that there is not a single clear BSR in the Gulf of Mexico while coring hydrates, one of the most active oil/gas exploration and production regions in the western hemisphere. 
Without a clear BSR, but with evidence of near-mudline hydrate deposits, the safety of subsea-equipment foundations is of concern. Companies with subsea equipment typically obtain "drop cores" in the area/route of interest to determine if hydrates are in the vicinity of the foundations. The evidence to date in the Gulf of Mexico suggests that gases have percolated along salt diapirs or geologic faults from deep within the Earth to form hydrates close to the ocean bottom. Gas evolution from the seafloor marks a primary suspected seafloor-hydrate location.
Gas Hydrates in Nature: Energy Recovery
Unfortunately, because hydrates in ocean sediments are dispersed (typically < 3.5 vol%), substantial ingenuity is required for economic energy recovery. A recent workshop concluded that most critical in-situ issues arise because hydrates are ill-defined in four respects in the geophysical/chemistry domain: detection, distribution, sediment properties, and hydrate controls.  For example, sonic waves are the principal detection tool for ocean hydrate deposits, but sonic quantification and frequently qualitative detection of hydrate is inaccurate, as suggested with BSRs in the Gulf of Mexico. Field tests are required to bound the problem in the field, which will be verified by laboratory experiments.
Pilot drilling, characterization, and production testing of hydrates have begun in permafrost regions that have higher hydrate concentrations (e.g., 30 vol% in the 1998 Mallik 2L-38 well in Canada), with a third Mallik well completed in March 2002. These permafrost-hydrate exploration and production tests will aid the understanding of how to approach the more-dispersed, but far larger, ocean resource in the future. Finite-difference reservoir recovery models indicate that production is only economic at rates greater than 0.5 × 106 SCM/d. 
There are three principal energy-recovery methods, as shown schematically in Fig. 11.6: depressurization, thermal stimulation, and inhibitor injection. The most producible permafrost hydrate deposits are those lying in direct contact with a gas reservoir, such that free-gas production causes hydrate dissociation by decreasing reservoir pressures below the hydrate stability pressure. Heat from the Earth allows hydrate decomposition to slowly replenish the gas reservoir. Makogon indicated that the Messoyakha, a Siberian permafrost reservoir, was produced for almost a decade in this manner during the 1970s. With the Siberian exception, no commercial production of hydrates has occurred.
The second and third hydrate production methods are thermal stimulation and inhibitor injection, both of which have also been tried in the former Soviet Union. However, both methods are very expensive, relative to depressurization. Economic estimates indicate that depressurization alone is not viable. Gas production from hydrates requires both depressurization and thermal/inhibitor stimulation.
Production from stand-alone hydrates in the permafrost or in the ocean is much more costly but technically feasible. Bil suggested that the best course of action is for the industry not to invest funds in research of hydrated-energy recovery, until more research is done to provide technical breakthroughs.
Well-documented gas production from hydrates close to conventional permafrost reservoirs will probably begin in the Western hemisphere during the next decade at incremental costs over normal gas production. A new Mallik 3L-38 production test well was drilled in the MacKenzie delta of Canada in the first quarter of 2002, with depressurization and thermal stimulation to recover the hydrated gas. The objective of the well is to extend those findings to recover gas from leaner hydrate deposits off the shore of Japan, and, as such, the work is heavily funded by Japanese and other national hydrate programs. Many national projects (e.g., Japan, India, Korea, and the United States) are currently seeking to find viable methods to recover gas from hydrates.
Summary and Future Hydrate Research Directions
Wherever small molecules contact water, the potential for a hydrate phase should be considered. As a minimum, hydrates should be included as one extreme in models of fluid phase behavior. In many cases, solid hydrates may control the system phase behavior.
Industrial problems with pipeline flow assurance will continue to provide the major incentive for development of hydrate technologies. The new, high-pressure challenges of deepwater gas stability and production require extensions of the existing thermodynamic database, along with better understanding of hydrate inhibition. Accurate means of determining in-situ hydrate detection, distribution, sediment properties, and controls are needed for a comprehensive picture to draw together the two communities interested in hydrates inside and outside pipelines. Hydrate time-dependent behavior (involving mass and heat transfer, and kinetics) is problematic, but the best work emanates from a three-decade effort at U. Calgary under Prof. Raj Bishnoi.
Transporting stranded gas as hydrate is currently being investigated. It is likely that useful production information will be obtained by studying ocean hydrate effects on sediment slumping, related to subsea-structure foundations and the climate, which are currently largely unknown. During the next decade, gas production will begin from permafrost hydrates associated with conventional gas reservoirs. However, efficient production of ocean hydrates is problematic, and an engineering breakthrough is required for energy recovery from hydrates to be economically feasible. Yet, the potential to tap the Earth's largest hydrocarbon energy resource cannot be ignored.
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SI Metric Conversion Factors
|Å||×||1.0*||E – 10||=||m|
|°F||(°F – 32)/1.8||=||°C|
|Btu/(hr-ft2-°F)||×||1.761 102||E + 03||=||kW/(m2•K)|
|mile||×||1.609 344*||E + 00||=||km|
|psi||×||6.894 757||E + 00||=||kPa|
Conversion factor is exact.