FROZEN HEAT | Volume 2

production-testing program (Dallimore and Collett 2005). The test lasted approximately five days. Hot brine (70°C at surface / 50°C at formation depth) was circulated across a 13-metre perforated test interval. Bottomhole flowing pres- sure was maintained slightly above formation pressure. Thus the test permitted assessment of the efficiency of heat conduction into the formation (that is, with no direct heat transfer by formation fluids). With only 500 cubic metres of gas produced over the entire testing period, the 2002 Mallik test was not particularly productive. However, the objective of the test was to demonstrate the feasibility of producing gas that originated indisputably from hydrate deposits, rath- er than the maximization of such production. It suggested that thermal heating alone is likely to be a comparatively in- efficient and expensive way to produce gas hydrates over the long term. Moridis and Reagan (2007a) and Moridis et al. (2009) demonstrated through numerical simulation studies that thermal stimulation is thousands of times less effective than depressurization as a dissociation-inducing method for gas production from hydrates. Research continues into developing downhole-heating tech- niques that require lower direct-energy input and provide more effective heating of the formation (Schicks et al. 2011). Downhole heating may be beneficial, in some reservoir set- tings, to overcome endothermic cooling of the formation caused by gas hydrate dissociation and/or to manage the temperature regime of the gas stream to prevent re-forma- tion of gas hydrates in the vicinity of the wellbore and inside the tubing. For certain reservoir conditions, a combination of reservoir depressurization and supplementary in situ heating might be optimal for sustaining gas hydrate pro- duction over the longer term (Moridis and Reagan 2007b; Moridis et al. 2009). 3.4.3 Chemical stimulation Gas hydrate production by chemical stimulation involves the manipulation of gas hydrate phase-equilibrium condi- tions by injecting dissociation-inducing chemicals, such as salts and alcohols, into the reservoir. These chemicals alter the energy potential of water in contact with the solid gas hydrate phase, causing dissociation. This approach has been used for decades to maintain flow assurance in gas wells and

concern is that the free gas cooled by the endothermy of gas hydrate dissociation and by effects associated with the pres- sure reduction and the high gas velocities in the vicinity of the well (the Joule-Thompson effect) can potentially lead to the ref- ormation of gas hydrate in the well bore or production tubing, causing serious operational problems. Examples of unwanted hydrate formation plugging pipelines or processing streams are well known in the oil and gas industry and have caused costly shutdowns, sometimes for months. Technologies rou- tinely employed to reduce this problem are referred to as flow assurance. They include injection of low dose gas hydrate in- hibitors, adding heat to the system, or generating a gas hydrate slurry that can be flushed out. 3.4.2 Heating the reservoir The objective of the reservoir-heating technique is to increase the temperature within the reservoir beyond the localized pressure-temperature threshold for gas hydrate stability. The only full-scale field production test using this technique was conducted at the Mallik site as part of the 2002 gas hydrate To prove applicability of the depressurization technique as a feasible productionmethod inmethane hydrates in deepwater sediments, Japan Oil, Gas and Metals National Corporation (JOGMEC) conducted the first offshore production test off the coasts of Honshu island. A drilling vessel “Chikyu” was employed for the field program that was started in early 2012 with drilling of production and monitoring boreholes and intensive data acquisitions, and the flow test (Yamamoto et al. , 2014). OnMarch 12, 2013, JOGMEC confirmed production of methane gas estimated from methane hydrate layers after lowering the bottomhole pressure of the production hole. The pressure was reduced from the original pressure of 13.5MPa to 4.5MPa, and approximately 120,000Sm 3 of methane gas was produced until sand production forced to terminate the flow on March 18. Data from this program is still being analyzed by JOGMEC, in partnership with the National Institute of Advanced Industrial Science and Technology (AIST). Box 3.3 Testing production in offshore Japan setting: The Nankai Trough

A GLOBAL OUTLOOK ON METHANE GAS HYDRATES 71