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What We Do and How We Do It

Tundra Gas is focussing exclusively, and for the foreseeable future, on the extraction of methane hydrate (also known as methane clathrates) in regions where permafrost conditions prevail. The Russians are the pioneers of methane hydrate extraction, and as they have the practical experience and have proven their expertise, our company focuses on implementing the techniques they have developed, particularly at the Messoyakh gas field. To enhance this technology we have integrated improvements made by our Japanese research partners, particularly modifications for gas extraction in areas prone to earthquakes.

One of the main arguments in favor of exploiting onshore methane hydrate deposits, concerns climate change. With many parts of the world, especially the permafrost regions, experiencing increases in temperature, methane is slowly being released from these deposits into the atmosphere. The permafrost is melting at an accelerating pace and thus the release of methane is increasing exponentially. As methane is a "greenhouse" gas that has a much greater impact on global warming than carbon dioxide, it is imperative to prevent as much of this methane as possible from escaping into the atmosphere. Extracting the methane hydrate for use as fuel, serves a doubly important purpose: it provides a much needed fuel at a time when global oil supplies appear to be dwindling, and it saves the world from possibly disastrous sudden rises in temperature. By coincidence, Qinghai (the site of our first methane hydrate production project) has been identified in scientific studies as the place with the fastest rising temperatures in the world.

  • Methods

    In-situ gas hydrate conversion into gas phase and the subsequent use of traditional natural gas recovery techniques are presently considered as basic development techniques. So far, four methods of gas hydrate dissociation to produce free gas have been made available:

    • Lowering reservoir pressure below equilibrium
    • Rising reservoir temperature above equilibrium
    • Injection of inhibitors to promote gas hydrate dissociation
    • High-frequency field treatment

  • Figure 1. Gas hydrate deposit development using radioactive thermal liquid:

    • 1. Impervious Bed
    • 2. Radioactive Effluent
    • 3. Gas Hydrate Layer
    • 4. Packer
    • 5. Cement Bridging
    • 6 & 7. Producing and Injection Wells
    • 4. Packer

  • Figure 2. Gas hydrate deposit development using hot water techniques:

    • 1. Gas Hydrate Layer
    • 2. Producer
    • 3 & 4. Horizontal Wells (Injectors)
    • 5. Surface Gas Production Equipment
    • 6. Surface Equipment For Hot Water Injection

  • The Technology

    The choice of technology is based on particular reservoir conditions (i.e. the presence of free gas below the hydrate deposit) and the rate of hydrate overcooling (i.e. difference between the reservoir and equilibrium hydrate formation temperature). Costs of gas production and gas recovery need to be comparable with those for conventional gas fields.

    Lowering reservoir pressure below equilibrium appears to be the most cost-effective technology of gas hydrates development so far. This method of hydrate development was first introduced in the Messoyakh gas field.

    However, for those offshore hydrate deposits located in the young sediments - when hydrate itself serves as a binding matrix - it would be generally impossible to lower reservoir pressure below equilibrium, since hydrate dissociation could cause sea floor instability.

    Falling reservoir temperature attributable to hydrate dissociation could become a limiting factor at high overcooling and hydrate saturation rates in the reservoir rock. It is well known that specific heat of gas hydrates dissociation is about 0.5 MJ/kg, which exceeds specific heat of ice melting. Assuming hydrate dissociation is substantial would imply that due to increased heat exchange with the surrounding rock, the pay zone will cool down to the equilibrium temperature of hydrate formation (which short-stops hydrate dissociation), or to the ice formation temperature (which leads to the sharp drop in reservoir rock permeability). Also, this process is complicated by the fact, that matrix rocks with over 60% hydrate content appear to be gas-tight.

    Thus, to maintain stable gas hydrate dissociation within the porous media, one should provide continuous heat flow to the pay zone. This approach can offer new prospects for employment of thermal techniques for gas hydrate development. In 2001, the Gas & Gas/Condensate Fields Development Department of the Gubkin Oil & Gas University (Moscow) proposed several new technologies for gas hydrate deposits heat treatment, aiming to improve hydrocarbon recovery.

  • Techniques

    The first new technique of this sort is based on injection of a thermal liquid below impervious hydrate-bearing layer bottom. This implies the formation of a radioactive effluent underground storage below the impervious reservoir bottom. Such underground storage should comprise a cluster of horizontal/slanted wells to improve heat exchange efficiency (see Figure 1). "Smart wells" are highly recommended in this case.

    Active life span for liquid radioactive waste should be "synchronized" with the lifetime of a gas hydrate field. The advantages of this thermal liquid are: production of vast amounts of heat and low operating costs. The main disadvantage is attributable to its high environmental risks associated with field development. Also, this technique implies the use of intensive heat exchange systems between the heat source (thermal liquid) and the reservoir, since natural heat exchange via impervious reservoir bottom is very slow.

  • Figure 3. Gas hydrate deposit development using thermal water

  • Figure 4. Gas hydrate deposit development using hydro fracturing:

    • 1. Impervious Bed
    • 2. Fracture
    • 3. Gas Hydrate Layer
    • 4 & 5. Producing and Injecting Wells

  • The second thermal technique provides for construction of dual-head multi-hole wells for simultaneous production of gas from hydrate layer and heat-carrier injection into pay zone (see Figure 2). Hot water, gas, superheated steam, and other agents can be used as heat-carrier. Heat-carrier is injected into the reservoir via injection wells, and the produced dissociated gas is recovered from a producing well.

    The first stage of this technique ensures hydrate dissociation in the bore hole vicinity, which produces an "artificial gas reservoir" with restored rock permeability, and the second provides for gas production from the reservoir using traditional techniques.

    The simplest method for producing natural gas from hydrate deposits is centered on hot water injection into the reservoir. However, this technique would be only applicable when cumulative consumption of energy used for in-situ hydrate dissociation does not exceed the energy produced while burning the produced gas. This condition can be meet by injecting cheaper thermal water produced from underlying seams.

    Hydro thermal water can be also used as thermal liquid while gas hydrate fields development, and, in particular, hot formation water, steam-water mixture, or dry steam. According to its temperature at the wellhead, hydro thermal water can be classified as: hot (308 - 348 K), high-temperature (348 - 373 K), and superheated (over 373 K). According to their thermal performance (and well productivity), hydro thermal fields are subdivided into: small-less than 4.18·103 J/hr (1,000 m3/ day), medium - 4.18·103 - 2.09·104 J/hr (1,000 - 3,000 m3/day), and big - over 2.09·104 J/hr (over 3,000 m3/day). However, the development of hydro thermal energy resources is at present at its earliest phase (Kamchatka, Caucasus, West Siberia, Central Asia, Lake Baikal).

    According to the proposed method (see chart in Figure 3), thermal water is flowing up into the upper-laying gas hydrate deposit via the cluster of designer wells. Natural gas released while hydrates dissociation is collected on the surface, while cool water is re-injected into the underlying seam. This thermal water technique was first put into operation under development of extra-heavy oil in the Uzen field as far back as 1975.

    The merit of this method is the possibility to adjust and control water injection using intelligent wells, but its shortcomings come from introduction of additional water into the pay zone, which leads to lowering gas layer's relative permeability.

    Significant improvements with in-situ hydrate dissociation are likely obtainable from increasing heat and mass transfer surface. Thus, hydro fracturing produces another promising way for development of gas hydrate deposits. Formation of conjugated fractures while hydro fracturing assists creating the convection fluxes in the reservoir and, accordingly, improving heat and mass transfer (see Figure 4). Also, a set of horizontal/inclined injection wells will help improve these important parameters.

    Current Activity

    Currently, the Gas & Gas/Condensate Fields Development Department of the Gubkin Oil & Gas University is engaged in extensive R&D concerning the theory of gas hydrate deposits development. Methods aimed to provide radiation safety and minimize the environmental risks while thermal gas production from hydrate deposits are under development at present. Also, a software package for modelling of gas hydrate reservoir development - based on the equations of multi-dimensional, multi component and non isothermal filtration (allowing for hydrates dissociation kinetics and thermodynamics) - is under development as well. Tundra Gas will be taking full advantage of any improvements the university can provide.

    Introduction of these thermal techniques is believed to facilitate the development of non-conventional hydrocarbon sources (such as gas hydrate deposits) which could dramatically change the oil and gas industry development trends in the near term.

    One improvement Tundra Gas has been able to add to the pioneering work of the Russians concerns is in terms of horizontal extraction.

    Horizontal drilling is used whenever practical because it extracts the methane gas present underneath the ice without disrupting the ice seal. An additional bonus is that extraction of gas in this manner will reduce the buoyancy pressure exerted on the overlying hydrate, so the seal integrity is better preserved as more underlying gases are produced.

    The company is confident it has proven, cost-effective technology at its disposal for methane hydrate extraction. The next challenge is choosing the best possible sites for gas extraction. There are five countries with proven inland methane hydrate reserves: the USA, Canada, Russia, India and China.

    Most of America's known onshore methane deposits are at North Slope in northern Alaska, an area that many environmental activists do not want exploited by energy companies. This is just one aspect of the biggest obstacle to commercial methane hydrate extraction in America - politics. Put simply, the political situation in America with regards to energy sourcing is so volatile it adds an unacceptable level of risk to any venture seeking to extract hydrocarbons that is not backed by very influential local corporations and/or politicians. To make matters worse, the Deep water Horizon incident in 2010 showed American politicians and senior oil company executives lining up to blame and demand money from BP whilst ignoring the culpability of American contractors and personnel in the accident. As a foreign company, and a corporation that will continue to be perceived as foreign even if we achieve our goal of one day listing on an American stock exchange, this makes America a very unattractive place to extract methane hydrate even though it is the biggest market in the world.

    In many respects, Canada is an ideal country for an oil and/or gas company to do business. There are extensive methane hydrate deposits, the Government is very accommodating to energy firms and there is excellent infrastructure in place. Unfortunately, Canada has so much oil in the form of shale and sands it doesn't need another controversial type of hydrocarbons in its territory. Oil sands generates so much money the Government is able to contain widespread concerns about the environmental impact of this admittedly rather dirty industry. Canada remains a long term target for Tundra Gas, perhaps after a decade of proven, clean and profitable business elsewhere.

    Russia has the largest known onshore methane hydrate deposits - possibly enough gas to fuel the world for centuries. However, there is no point in considering this country until foreign investors enjoy a reasonable level of protection. Furthermore, the infrastructure needs drastic improvements to make most deposit sites viable.

    India has some methane hydrate deposits onshore in Kashmir, which is too unstable and violent an area to consider for the foreseeable future. Moreover, the country has much larger offshore deposits that are of more interest to the Government.

    This leaves one potential site for business - China. In September 2009, a huge deposit of methane hydrate was discovered in province of Qinghai. This remote western province is about the same size as Texas or France and forms the northern part of the Tibetan plateau. Qinghai is home to approximately 70% of China's 2.15 million square km of permafrost. The area is notoriously vulnerable to seismic activity, so we are relying on proven Japanese technology for working in this sort of environment. The methane hydrate deposits in the Tibetan plateau alone, are estimated to equal at least 35 billion tones of crude oil - enough to power China for the next 90 years.

    Lowering reservoir pressure below equilibrium appears to be the most cost-effective technology of gas hydrates development so far. This method of hydrate development was first introduced in the Messoyakh gas field.

    However, for those offshore hydrate deposits located in the young sediments - when hydrate itself serves as a binding matrix - it would be generally impossible to lower reservoir pressure below equilibrium, since hydrate dissociation could cause sea floor instability.

    Falling reservoir temperature attributable to hydrate dissociation could become a limiting factor at high overcooling and hydrate saturation rates in the reservoir rock. It is well known that specific heat of gas hydrates dissociation is about 0.5 MJ/kg, which exceeds specific heat of ice melting. Assuming hydrate dissociation is substantial would imply that due to increased heat exchange with the surrounding rock, the pay zone will cool down to the equilibrium temperature of hydrate formation (which short-stops hydrate dissociation), or to the ice formation temperature (which leads to the sharp drop in reservoir rock permeability). Also, this process is complicated by the fact, that matrix rocks with over 60% hydrate content appear to be gas-tight.

    Thus, to maintain stable gas hydrate dissociation within the porous media, one should provide continuous heat flow to the pay zone. This approach can offer new prospects for employment of thermal techniques for gas hydrate development. In 2001, the Gas & Gas/Condensate Fields Development Department of the Gubkin Oil & Gas University (Moscow) proposed several new technologies for gas hydrate deposits heat treatment, aiming to improve hydrocarbon recovery.

  • Reports and Resources

    All of the information in these reports was correct at the time of writing.

  • For a technical report on Qinghai's geophysical characteristics, please click here.
  • For a second technical report on Qinghai's methane hydrate deposits, please click here.
  • For a technical report showing Japanese innovations that can improve methane hydrate extraction, please click here.
  • For a map of Qinghai, please click here.
  • For a map of China, please click here.

One of the main arguments in favor of exploiting onshore methane hydrate deposits concerns climate change. With many parts of the world, especially the permafrost regions, experiencing increases in temperature, methane is slowly being released from these deposits into the atmosphere. The permafrost is melting at an accelerating pace and thus the release of methane is increasing exponentially. As methane is a "greenhouse" gas that has a much greater impact on global warming than carbon dioxide, it is imperative to prevent as much of this methane as possible from escaping into the atmosphere. Extracting the methane hydrate for use as fuel serves a doubly important purpose: it provides a much needed fuel at a time when global oil supplies appear to be dwindling and it saves the world from possibly disastrous sudden rises in temperature. By coincidence, Qinghai has been identified in scientific studies as the place with the fastest rising temperatures in the world.

Zhang Hongtao, chief engineer at China’s Ministry of Land and Resources, was quoted in March 2010 as saying he expected commercial exploitation of methane hydrate in Qinghai could begin within 10-15 years. Developments since then, make it likely Tundra Gas could begin production much sooner, possibly by the end of 2012.

Firstly, CNPC - China's largest oil and gas producer - signed an agreement with Qinghai provincial government to invest 23 billion yuan in the province over the following five years. Wang Yilin, a deputy manager of CNPC, said that the investment would boost CNPC Qinghai oil fields production to at least 8.5 million tons per year by 2015. Wang said that it also has agreed to provide Qinghai with natural gas amounting to 15 billion cubic meters from 2010 to 2015.

Wang also revealed that to ensure a stable supply of energy to the quake zone CNPC would build 12 petrol stations and a 6,000-cubic-meter oil storage tank in Yushu along with a terminal to receive liquefied gas in Gyegu. He added, further, the company, which is also the parent of PetroChina, would expand the capacity of an oil storage tank by 48,000 cubic meters while building 120 petrol stations and 40 gas stations.

In other words, much needed infrastructure is being developed at a faster-than-expected pace.

Second, substantial, recoverable deposits have been found at Muli (also called Wuli) in central Qinghai. This is an area that has already been exploited for its coal deposits, including huge open cast mines. As these mines have already led to substantial environmental degradation, the local government has offered generous methane hydrate extraction licenses in return for commitments to repair some of the damage caused by coal mines. Muli is a major transit point on the Qinghai-Tibet railway and highway, so nearly everything is in place to begin preliminary work prior to gas extraction.

Muli has been designated the first extraction site by Tundra Gas, with more remote sites dependent upon infrastructure improvements that are due to be completed by 2010. It is estimated Muli has sufficient methane hydrate deposits to keep Tundra Gas and its Chinese partners occupied for at least 15 years.