Abstract:The enormous amount of methane stored in natural gas hydrates (NGHs) worldwide offers a significant potential source of energy. NGHs will be generally unable to reach thermodynamic equilibrium at their in situ reservoir conditions due to the number of active phases involved. Lack of reliable field data makes it difficult to predict the production potential and safety of CH 4 production from NGHs. While the computer simulations will never be able to replace field data, one can apply state-of-the-art modelling techniques to evaluate several possible long-term scenarios. Realistic kinetic models for hydrate dissociation and reformation will be required, as well as analysis of all phase transition routes. This work utilizes our in-house extension of RetrasoCodeBright (RCB), a reactive transport simulator, to perform a gas hydrate production case study of the Bjørnøya (Bear Island) basin, a promising field with very limited geological data reported by available field studies. The use of a reactive transport simulator allowed us to implement non-equilibrium thermodynamics for analysis of CH 4 production from the gas hydrates by treating each phase transition involving hydrates as a pseudo reaction. Our results showed a rapid propagation of the pressure drop through the reservoir following the imposition of pressure drawdown at the well. Consequently, gas hydrate dissociation and CH 4 production began in the early stages of the five-year simulation period.

Huge resources of energy in the form of natural gas hydrates are widely distributed worldwide in permafrost sediments as well as in offshore sediments. A novel technology for combined production of these resources and safe long-term storage of carbon dioxide is based on the injection of carbon dioxide injection into in situ methane hydrate-filled sediments. This will lead to an exchange of the in situ methane hydrate over to carbon dioxide-dominated hydrate and a simultaneous release of methane gas. Recent theoretical and experimental results indicate that the conversion from natural gas hydrate to carbon dioxide hydrate and mixed carbon dioxide/methane hydrate follows two primary mechanisms. Direct solid state transformation is possible, but very slow. The dominating mechanism involves formation of a new hydrate from injected carbon dioxide and associated dissociation of the in situ natural gas hydrate by the released heat. Nitrogen is frequently added in order to increase gas permeability and to reduce blocking due to new hydrate formation, and will as such also reduce the relative impact of the fast mechanism on the conversion rates. In addition to carbon dioxide also other sour gases, such as hydrogen sulfide, may follow the carbon dioxide from the sour gas removal process. Hydrogen sulfide is a very aggressive hydrate former. It is abundant in various amounts in thermogenic hydrocarbon systems. In this work we investigate the sensitivity of possible additions of hydrogen sulfide in carbon dioxide/nitrogen mixtures, and how the ability to form new hydrate changes with the additions of hydrogen sulfide. This analysis is applied to four case studies: (1) Bjørnøya gas hydrate basin, (2) the Nankai field in Japan, (3) the Hikurangi Margin in New Zealand, and (4) a gas hydrate basin in South-West Taiwan. The hydrate saturations found in these fields vary over a range from 25−80%. Pressures range from 4−22.6 MPa and temperatures from 275.15−292.77 K. For all these ranges of conditions, even 1% H 2 S will substantially increase the ability to form new hydrate from an injected CO 2 /N 2 mixture containing H 2 S. Except for the most shallow of the reservoirs (Bjørnøya) 1% H 2 S results in formation of a new hydrate for all concentrations of CO 2 in N 2 above 1%. Implementation of results from this work into a reservoir simulator is a natural follow-up which can shed light on the macroscopic consequences in term of possible local blocking of the flow due to content of H 2 S. The mass transport, mass balances, and energy balances in a reservoir simulator are also needed for a more detailed evaluation on how the content of H 2 S and CO 2 changes over time and location in the reservoir due to various processes in addition to hydrate formation. H 2 S and CO 2 dissolves significantly in pore water, and also adsorbs well on various sediment minerals.

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