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Natural Gas and Methane Hydrates Natural Gas and Methane Hydrates Report Number PH3/27 July 2000 This document has been prepared for the Executive Committee of the Programme. It is not a publication of the Operating Agent, International Energy Agency or its Secretariat. Title: Natural Gas and Methane Hydrates Reference number: PH3/27 Date issued: July 2000 Other remarks: Background to the Study The IEA Greenhouse Gas R&D programme (IEA GHG) is systematically evaluating the cost and potential of measures for reducing emissions of greenhouse gases arising from anthropogenic activities, especially the use of carbon dioxide capture and storage. Captured CO2 can be stored in geological reservoirs instead of being emitted to the atmosphere. Geological reservoirs that can be considered include: deep saline aquifers and depleted oil and gas fields. CO2 can also be injected into oil fields to enhance oil recovery (CO2-EOR) and into coal seams to enhance the release of methane (CO2-ECBM). In these the costs of storage are offset by product sales, making these storage options more attractive commercially. Another option that can be considered is the formation of CO2 hydrates. Analogous compounds, methane hydrates, are known to have existed for thousands of years in many parts of the world. Initial scientific evidence suggests that, under the appropriate conditions of temperature and pressure, CO2 hydrates form stable molecules, similar to methane hydrates. If CO2 can be stored in a similar manner, considerable quantities of CO2 could be sequestered. There are two options for CO2 storage as hydrates. The first is the direct formation of CO2 hydrates, perhaps on the ocean floor, whilst the second, and possibly more attractive, option is to combine CO2 storage with release of methane from hydrate deposits. If this approach could be achieved in practice, the storage option could be more attractive, in the same way as CO2-EOR or CO2-ECBM are more attractive than simple storage. Compared to the other storage options, knowledge on hydrate chemistry and the potential for storage of CO2 as hydrates is at an early stage of development. Hydrates are attracting considerable interest internationally and studies on the fundamental science of hydrates are now underway in many research laboratories throughout the world. To assist the international community in assessing this potential CO2 storage option, IEA GHG commissioned a small study to review the current state of knowledge about hydrates and determine where further information about CO2 storage as hydrates is needed (for example, information which could be obtained by appropriate research). This study entitled "Issues underlying the feasibility of storing CO2 as hydrate deposits" has been reported (Ph3/25) previously. A second, more extensive study to investigate the practicalities and potential for combining methane extraction from natural gas hydrates with CO2 storage has now been completed. This second study also focused on natural gas hydrate deposits in permafrost regions rather than sub sea hydrate deposits. Prof. Dendy Sloan of the Colorado School of Mines, USA, undertook this study. Results and Discussion The following areas are described in the report • A comparison of natural gas and methane hydrate reserves and resources • The composition of CO2 in natural gas reserves • The potential for exploitation of the methane hydrate resource • The potential for CO2 injection combined with methane extraction from natural gas hydrates • Costs of CO2 storage in methane hydrates i • Steps to be taken before CO2 enhanced methane hydrate extraction can be considered further. Comparison of natural gas and methane hydrate reserves and resources One of the initial objectives of the study was to compare natural gas and hydrates reserves1 and resources2 Natural gas current reserves are some 147 Trillion Cubic Metres (TCM) whilst the potential future natural gas resource could be as high as 137 TCM approximately twice the proven reserves. Estimates of the ultimate3 natural gas reserves vary between 300 and 450 TCM4. The estimated methane hydrate resource is about 21,000 TCM5. Putting this in perspective the estimated natural gas hydrate resource is about 75 times greater than current natural gas reserves and resources and some 50 times greater than ultimate natural gas resource estimates. It must, however, be noted that the estimates of methane hydrate resource are highly uncertain. Methane hydrates are widely dispersed throughout the world. Over 90% of the methane hydrates exist as finely dispersed particles on the ocean floor. The concentration of methane hydrates in the ocean sediments is typically as low as 3%. The remainder (<10%) occur in permafrost regions as hydrate capped gas reservoirs. These permafrost deposits are much more concentrated than the ocean hydrate resource. The consultant concluded that exploitation of the sea floor hydrate resource is not practical with current technology and the best option is exploitation of the permafrost hydrate resource. These findings were consistent with the conclusions in report Ph3/25. The composition of CO2 in natural gas reserves The composition of natural gas hydrates can be considered to be essentially methane. However, natural gas fields can have significant concentrations of CO2 present along with the natural gas. The average concentration of CO2 in natural gas reserves in different parts of the world is given in Table 1 below; it should be noted there can be considerable range about the mean. 1 Reserves are considered to be technically and economically recoverable with current technology and current gas prices. 2 Resources are less certain, but can be considered potentially recoverable with foreseeable technological and economic developments. 3 The ultimate resource is an estimated figure and reflects expert judgement on hydrocarbon reservoirs yet to be found and allowances for future changes in economic and operating conditions. 4 Survey of Energy Resources 1998, World Energy Council. 5 Natural gas hydrate resource figure given is on a gas equivalent basis ii Region Average CO2 content (%) North America 2.65 Latin Am. & Caribbean 2.43 Western Europe 2.20 Central & East. Europe 10.7 Former Soviet Union 9.39 Mid. East & N. Africa 5.48 Sub-Saharan Africa 5.93 Central Asia & China 17.5 Pacific OECD 9.20 Other Pacific Asia 12.68 South Asia 21.2 Table 1. CO2 concentration of known natural gas reserves. The data on CO2 concentration in conventional natural gas were considered to be approximate. The consultant identified that more accurate data will be available from a four-year US Geological Survey in mid-2000. It is worth noting that there are a few very large Malaysian reservoirs with very high 6 CO2 content, such as Natuna , which contains 71% CO2. The Natuna field has gas reserves of 6.3 3 3 3 Tm , equivalent to 4.47 Tm of CO2 and 1.83 Tm of CH4. Burning the natural gas will therefore 3 generate some 1.83 Tm of CO2. Production of natural gas from the Natuna field will generate nearly 2.5 times more CO2 than will be produced from the utilisation of the natural gas. Bringing such gas fields into production will significantly increase CO2 emissions from this sector unless the CO2 is captured and stored. Exploitation of methane hydrate resource In order to determine the best exploitation route for the methane hydrate resource, a case study was examined of a permafrost hydrate resource. Of the options examined depressurisation was considered to be the most practical and economical method for dissociation of the hydrate. Gas production rates from the field were estimated by modelling the depressurisation technique in a hydrate dissociation model. These gas production rates were used in an economic assessment of methane hydrate extraction. This economic analysis concluded that the cost of gas extraction from permafrost methane hydrate reservoirs using depressurisation were comparable with the cost of extracting free gas from an as-yet-unexploited Arctic field. However, there is currently no exploitation of this permafrost hydrate resource, because there are natural gas reserves are available which are more technically and economically viable. For permafrost exploitation to take place a gas pipeline infrastructure will need to be installed in the permafrost regions, which will require a significant capital investment. Exploitation of the permafrost methane hydrate resource is not expected to begin before 2010 at the earliest. Potential for CO2 injection combined with methane extraction from natural gas hydrates The study investigated in depth the potential for methane extraction from a permafrost reservoir combined with CO2 injection and storage. The study examined the experimental work undertaken in four Japanese laboratories and concluded that the kinetics and thermodynamics for the displacement mechanism are, at best, on the margin of being sufficient for this application. 6 Barriers to overcome in the implementation of CO2 capture and storage (1), storage in disused oil and gas fields. Ph3/22, February 2000. iii It has been found that injecting CO2 would not extract all the methane from the methane hydrate. At best some 29% of the methane will remain in the hydrate phase7. The gas produced would, therefore, contain significant quantities of CO2, as soon as the injected gas had filled the void space. Early breakthrough of CO2 to the gas producing wells could, therefore, be expected. This would add to the field capital and operating costs because CO2 separation plant would be required for treating the produced gas. Costs of CO2 storage as methane hydrates. An initial economic analysis of CO2 storage combined with methane extraction was performed. The cost of storage was found to be extremely sensitive to the amount of methane that can be extracted. The theoretical maximum extraction potential was determined as 71%. However, in practise actual recovery rates were expected to be significantly lower, possibly as low as 5-10%. Storage costs were estimated for a range of extraction rates. The storage cost estimates are given in Table 2 overleaf for a range of displacement efficiencies.
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