Gas Hydrates (Methane Hydrate): Formation, Reserves in India, Extraction and Climate Risk

Methane Hydrate: Formula, Fire Ice and Crystal Structures

Why Methane Hydrate Is Called Fire Ice: Formula and Energy

A clathrate is a cage compound in which the water molecules form the cages and the gas molecules sit inside them. The structure looks like ice, yet a piece brought to the surface and lit will burn, because the methane escapes from the melting cage and catches fire. That is why methane hydrate is called fire ice.

The nominal composition is CH₄·5.75H₂O, or 4CH₄·23H₂O, which means one mole of methane for every 5.75 moles of water. By mass this is about 13.4 per cent methane. The density is around 0.9 g/cm³, so a free lump of hydrate would float, which is why hydrate on the seabed has to be held down by sediment.

The energy density explains the interest. One litre of fully saturated methane hydrate holds about 120 grams of methane, and one cubic metre of hydrate yields about 160 to 164 cubic metres of methane at the surface, together with 0.87 cubic metres of fresh water, when it breaks down.

Crystal Structures of Gas Hydrates (sI, sII and sH)

Gas hydrates form three crystal structures, named by the shape and number of water cages in one repeating unit (the unit cell). Methane, the commonest guest in nature, fits structure I. Small gases such as nitrogen and oxygen, and larger or mixed hydrocarbons, build the other two.

Structure H hydrate is thought to occur in the Gulf of Mexico, where heavy hydrocarbons formed by heat are common. In oceans, most hydrate is methane in a structure I crystal, and more than 99 per cent of the gas in this common type is methane made by microbes in the sediment.

How Methane Hydrate Forms and Where It Occurs

Pressure, Temperature and the Gas Hydrate Stability Zone

Methane hydrate forms when methane and water meet at high pressure and low temperature. On the hydrate stability curve, at 4 °C the hydrate forms above a pressure of about 50 atmospheres, which corresponds to roughly 500 metres of sea depth. Below that pressure, or above the limiting temperature, the cage does not hold.

The depth range in which these conditions are met is the gas hydrate stability zone. Its upper edge in the ocean lies where bottom-water temperature is near 0 to 2 °C, at water depths greater than about 300 metres. Its lower edge is set by the geothermal gradient, because the rock becomes too warm for hydrate as depth below the seafloor increases. Along continental margins the zone is on average about 500 metres thick, and the zone reaches at most about 2,000 metres below the seafloor. A region of low geothermal heat flow gives the thickest zone, and a region of high heat flow gives a thinner one.

The gas itself comes from two sources. Microbes in the sediment make methane, and methane also rises along faults from deeper sediments. Hydrate crystallises where this methane meets cold, high-pressure water in the seabed. A hydrate system therefore needs a gas supply, water, and the right pressure and temperature, all in the same place.

Bottom-Simulating Reflector: The Seismic Signature

Hydrate cannot be seen from a ship, so explorers read it from seismic reflection profiles. The key sign is the bottom-simulating reflector (BSR), a seismic reflection that copies the shape of the seafloor and marks the base of the hydrate stability zone. It appears because hydrate-bearing sediment, normal sediment and sediment holding free gas differ in density and in how fast sound travels through them. Drilling results show that a BSR approximately marks the base of the hydrate-bearing sediment, and that the reflection is mainly caused by free gas lying below the hydrate.

Two features separate a BSR from ordinary layering. It has the opposite polarity to the seabed reflection, and it often cuts across the bedding of the sediment layers. Its depth, together with the pressure and temperature needed for stability, can be used to work out the geothermal gradient.

A BSR is a pointer, not proof. It shows where hydrate and gas may be, and drilling, coring and logging then test the site. In India's second expedition, explorers combined a BSR with seismic amplitude studies to find sand-rich systems inside the stability zone.

Where Gas Hydrates Occur: Seafloor, Permafrost and Lakes

About 95 per cent of natural gas hydrate lies beneath the seafloor, mostly in the sediments of continental margins. Deposits also occur on land in polar regions, and in a few deep fresh-water lakes.

• Marine sediments: Hydrate is found within the sediments of continental margins, in water deeper than about 300 metres where bottom water is around 2 °C. It may occur as massive layers, nodules, veins in fractures or grains within pores. It can sit within the sediment or near the sediment-water interface and may cap even larger deposits of free gas.
• Arctic permafrost: Continental deposits have been located in Siberia and Alaska, in sandstone and siltstone beds at depths of less than 800 metres. The Mallik site in the Beaufort Sea region of Canada's Mackenzie Delta is the best-studied permafrost site.
• Deep lakes: Fresh-water Lake Baikal in Siberia can host gas hydrate.

At Mallik, three main hydrate intervals lie between 890 and 1,160 metres, more than 110 metres thick in total, in medium-grained sands where hydrate fills 50 to 90 per cent of the pore space. That sand-hosted setting matters for production, because sand lets gas and water flow and clay does not.

Global Gas Hydrate Resources and National Programmes

How Much Methane Hydrate Exists: Estimates and Their Uncertainty

Estimates of the global hydrate inventory vary widely and have fallen over the decades. Modern estimates put it at 1 to 5 × 10¹⁵ cubic metres of methane, which is 500 to 2,500 gigatonnes of carbon. Earlier researchers proposed 10,000 to 11,000 gigatonnes of carbon. The present range is smaller than the 5,000 gigatonnes of carbon in all other fossil fuel reserves but much larger than the roughly 230 gigatonnes of carbon in other natural gas sources. Arctic permafrost is estimated to hold about 400 gigatonnes of carbon in hydrate. For scale, the atmosphere holds around 800 gigatonnes of carbon.

Estimates by volume show the same spread. One survey of published figures, old and new, gives a range of about 2,800 to 80,00,000 trillion cubic metres, which it describes as speculative and spanning three orders of magnitude; the modern range sits near its lower end. Conventional natural gas, counting both reserves and undiscovered technically recoverable resources, totals about 440 trillion cubic metres. The sedimentary hydrate reservoir probably holds 2 to 10 times the known conventional natural gas.

Japan, China, Canada and the United States: National Hydrate Programmes

Several countries with limited conventional gas or large Arctic and marine deposits have funded hydrate research.

• Japan: Japan estimates at least 1.1 trillion cubic metres of methane in the Nankai Trough, enough for more than ten years of the country's needs. Hydrate there occurs about 290 to 300 metres below the seafloor (about 1,240 metres below sea level) in an active subduction zone; a national research consortium called MH21 was set up to establish commercial production processes.
• China: In August 2006 China announced a plan to spend 800 million yuan over ten years on hydrate research and later ran marine production tests in the South China Sea.
• Canada: Canadian and Japanese researchers produced a steady stream of gas from the Mallik site in 2008.
• United States: A potentially economic accumulation in the Gulf of Mexico may hold about 100 billion cubic metres of gas, and Alaska's North Slope has hosted test wells since 2007.

India's National Gas Hydrate Programme

NGHP: Institutions, Mandate and Policy Status

The Ministry of Petroleum and Natural Gas formulated the National Gas Hydrate Programme (NGHP) in 2000. Its aim is to support research, share knowledge and scientific data, and keep Indian scientists abreast of international developments.

The programme is steered by the Ministry with the Directorate General of Hydrocarbons (DGH), the Oil and Natural Gas Corporation (ONGC) and other national oil companies and research institutes. The Ministry and DGH have signed memoranda of understanding with various agencies over the years. ONGC planned and ran the second expedition on behalf of the Ministry. The National Institute of Ocean Technology (NIOT), an autonomous society under the Ministry of Earth Sciences, has a gas hydrate technology group that also works for the related offshore industries.

On policy, the Ministry told Parliament in November 2014 that there was no proposal for a national policy on methane hydrates because the subject was at the research and development stage. Gas hydrate is, however, covered in the Hydrocarbon Exploration and Licensing Policy (HELP) of 2016, which lets companies explore and produce all kinds of hydrocarbons, including shale oil and gas, coalbed methane and gas hydrate, under a single licence.

NGHP Expedition 01 (2006): Krishna-Godavari, Mahanadi and Andaman

The first expedition ran from 28 April to 19 August 2006 aboard the drilling vessel JOIDES Resolution. In 113.5 days it drilled or cored 39 holes at 21 sites, penetrated more than 9,250 metres of sediment and recovered nearly 2,850 metres of core.

The expedition showed that a fully developed gas hydrate petroleum system exists in all three basins where hydrate occurred. Most of the hydrate in this first round occurred as fracture-filling material in clay-rich, fine-grained sediment, or as grains spread through the sediment. That type is hard to produce, which is why the next expedition changed its target.

NGHP Expedition 02 (2015): Hunting Sand-Hosted Hydrate

After the first expedition, planners decided that the next one should look for deep-water hydrate in sand-dominated settings, since sand carries gas and water and so offers the best production chance. Before drilling, geologists studied three areas of the Krishna-Godavari Basin, called Areas B, C and E, using 3D seismic data. They adapted conventional petroleum methods of seismic amplitude evaluation to find sand-rich systems within the stability zone. In Area B, work focused on a large anticlinal structure with a prominent BSR; in Area C, on a very large deep-water channel-levee-fan system; in Area E, on high-amplitude events within channel-levee sequences. The 22 most promising sites were prioritised to investigate 17 identified hydrate prospects.

The expedition ran from 3 March to 28 July 2015, a total of 147 days, using the Japanese scientific drilling vessel Chikyu. It drilled, cored or surveyed 42 holes at 25 sites in four areas along the eastern margin: Area A in the Mahanadi Basin (three sites), Area B in the northern Krishna-Godavari Basin (twelve sites), Area C in the central part (six sites) and Area E in the southern part (four sites). Almost every site showed hydrate, but the concentration varied greatly, and concentrated hydrate was mostly in coarser, sand-rich sediment.

The expedition reached three main findings.

• Extensive sand-rich deposits exist throughout the deep-water parts of the Krishna-Godavari and Mahanadi basins.
• Areas B and C of the Krishna-Godavari Basin hold substantial hydrate in sand-rich systems and are ideal candidates for future production testing.
• In the Mahanadi Basin the reservoirs are extensive, but gas supply at the sites was too small to fill them with hydrate.

The cores are archived at the National Gas Hydrate Core Repository in Mumbai.

India's Prognosticated Gas Hydrate Resource

India's prognosticated gas hydrate resource has been put at 1,894 trillion cubic metres, an estimate made in 2014 from the geological and geophysical data then available. It is a resource, not a proven reserve, and no Indian hydrate deposit has yet reached that stage. Other estimates are far smaller: Hydrate Energy International put India's resource potential at 933 trillion cubic feet, about 26 trillion cubic metres.

The official figure of 1,894 trillion cubic metres is also provisional. In August 2015 the government told Parliament that the gas hydrate potential of the Bay of Bengal as a whole had not yet been assessed, so the national estimate will change as the results of the two expeditions and later surveys are worked out. In short, India's hydrate resource is very large on paper, concentrated in the Krishna-Godavari Basin, and not yet commercially recoverable.

Extracting Methane Hydrate: Methods, Tests and Challenges

Extraction Methods: Depressurisation, Heat, Inhibitors and Carbon Dioxide Exchange

Because hydrate is stable only under pressure and in cold, producing gas means upsetting that balance in a controlled way and then collecting the methane.

Depressurisation is the leading method because it needs much less energy than heating, and in the 2008 Mallik test researchers produced gas by lowering the pressure without heating. In the carbon dioxide route, researchers at the University of Bergen developed a way of injecting carbon dioxide into hydrate so that it replaces the methane in the cage and the methane is released by direct exchange. Its attraction is that it could produce methane and leave carbon dioxide stored in the hydrate.

World Production Tests: Mallik, Nankai Trough, Alaska and South China Sea

The history of hydrate production is a short list of field tests, almost all in sand-rich reservoirs.

• 2002, Mallik (Canada): The first full-scale production test, by heating the reservoir, with modest gas flows.
• 2007 to 2008, Mallik: Canada and Japan returned in winter to test pressure drawdown; the six-day programme in 2008 achieved sustained gas flow to the surface and proved that conventional oil and gas production methods, modified for hydrate, can work.
• 2012, Alaska: ConocoPhillips and the Japan Oil, Gas and Metals National Corporation (JOGMEC) field-tested the carbon dioxide exchange method, which had reached the injection phase by March 2012.
• 2013, Nankai Trough (Japan): On 12 March 2013 JOGMEC announced the world's first offshore production of gas from methane hydrate, by drilling into the deposit and depressurising it. The hydrate field lies 50 kilometres off central Japan, about 300 metres below the seafloor, and the gas was piped to the surface and ignited.
• 2017, Japan and China: Both countries ran marine production tests. In May 2017 China announced a breakthrough when it extracted methane from hydrate in the South China Sea. Japan's 2017 test evaluated alternative well-completion technologies.
• 2020, Shenhu (China): A further test in the Shenhu area of the South China Sea evaluated well-completion technologies for producing gas from hydrate.

Challenges: Cost, Dispersed Deposits and Pipeline Blockage

Methane hydrate is a future resource, not a present one, for four reasons.

• High production cost: Offshore deposits lie under deep water, and the cost of producing a cubic metre of gas has not been brought down enough for commercial use. Industry consensus is that commercial-scale production remains years away.
• Dispersal: In most sites the deposits are thought to be too dispersed for economic extraction, and clay-rich or fracture-dominated reservoirs cannot be produced with existing technology.
• Finding the right reservoir: Viable reserves are hard to detect, and technology for extraction is still developing. India's second expedition deliberately targeted sand-rich systems for this reason.
• Environment: Methane may escape to the sea or the air if a well or the reservoir fails during production.

Hydrate also troubles the gas industry in a different way. When liquid water condenses in the presence of methane at high pressure, hydrate forms inside pipelines and processing equipment and can block them. The American engineer E. G. Hammerschmidt discovered this in 1934, and it led to research on preventing hydrate formation. Operators remove a plug by lowering the pressure, heating it, or dissolving it with chemicals such as methanol, and must do so carefully because a plug that suddenly breaks down releases a large volume of gas.

Hydrates are also studied for seawater desalination, gas storage, carbon dioxide capture and storage, and cooling for data centres and district cooling. Deep-sea deposition of carbon dioxide hydrate has been proposed as a way of removing carbon dioxide from the atmosphere.

Methane Hydrate, Climate Change and Geohazards

Methane as a Greenhouse Gas: GWP and Atmospheric Life

Methane is a potent greenhouse gas. In the IPCC Sixth Assessment Report its global warming potential (GWP) is about 81 times that of carbon dioxide over 20 years and about 28 times over 100 years; the 20-year value is higher because methane stays in the air for a much shorter time than carbon dioxide. For fossil methane the report's values are slightly higher, 82.5 over 20 years and 29.8 over 100 years. Methane's atmospheric lifetime is about 12 years. In the air it breaks down to carbon dioxide and water, which is why the climate effect of a methane pulse is strong at first and fades over a decade or two.

Methane is both a fuel and a climate risk. Burning it gives carbon dioxide, so using hydrate gas adds to carbon emissions, but methane that escapes unburned warms the planet far more.

Clathrate Gun Hypothesis: What Science Says Now

The clathrate gun hypothesis proposes that changes in the temperature of ocean waters caused methane hydrate on upper continental slopes to build up and, at times, to be released. This would have had an immediate effect on global temperature, and the idea was put forward to explain periods of rapid warming in the Quaternary. In the scenario, warming melts undersea hydrate, the released methane causes more warming, and the cycle repeats as a positive feedback.

Hydrate releases have been linked to some past events, including the Paleocene-Eocene Thermal Maximum and the Permian-Triassic extinction. During the last deglaciation, the Bølling-Allerød warming was followed by the disappearance of the whole hydrate deposit in the Barents Sea within 5,000 years, yet most of the methane appears to have stayed in the seawater, with very little entering the atmosphere.

For the present century, the IPCC Sixth Assessment Report judges the hydrate risk to be low. Deep sediments warm very slowly, over thousands of years, so only a small part of the existing hydrate could be destabilised in the coming century. Even when methane leaves the hydrate, most of it is expected to be consumed and oxidised to carbon dioxide in the ocean before it reaches the air; the most complete modelling suggests a release of less than 2 per cent of current human-caused methane emissions.

The report concludes that it is very unlikely that clathrates in deeper permafrost and under the sea will cause a detectable departure from the emissions trajectory this century. Thawing Arctic permafrost soil is a more important extra source of heat-trapping gases than undersea hydrate.

Submarine Slope Failure: The Storegga Slide

Hydrate matters to engineers as well as climate scientists, because the cemented sediment holds a slope together. If hydrate dissociates, the sediment may lose strength. The Storegga Slides on the edge of Norway's continental shelf are the best-known case. Three underwater landslides, in about 6225 to 6170 BCE, involved a stretch of shelf about 290 kilometres long and 3,500 cubic kilometres of debris, and caused a tsunami in the North Atlantic. The trigger is thought to have been an earthquake that caused a sudden expansion of methane hydrate and weakened the surrounding rock; another theory holds that thick glacier-fed sediment had piled up on the shelf edge and an earthquake alone could then have made it collapse.

Drilling into hydrate therefore needs care: A change in pressure can destabilise the deposit around the well, and a sudden fall in pressure after a landslide can release more gas.

Unconventional Natural Gas in India: Shale Gas and Coalbed Methane

Conventional and Unconventional Natural Gas in India

Natural gas is found with petroleum deposits and is released when crude oil is brought to the surface. It is used as a household and industrial fuel, in power generation, as transport fuel (CNG), as cooking fuel (PNG) and as raw material for chemicals, petrochemicals and fertilisers. India's major gas reserves are in the Mumbai High and allied fields along the west coast, supplemented by finds in the Cambay Basin. On the east coast, new reserves have been found in the Krishna-Godavari Basin.

The 1,700 km Hazira-Vijaipur-Jagdishpur pipeline, built by GAIL (set up in 1984 as the Gas Authority of India Limited), linked Mumbai High and Bassein with fertiliser, power and industrial complexes in western and northern India.

Unconventional gas is gas from sources other than a conventional gas field, namely shale gas, coalbed methane, tight sandstone gas and methane hydrate. The Krishna-Godavari Basin matters twice over, since it holds conventional gas and also India's best-studied hydrate prospects.

Shale Gas in India: Basins, Policy and Environmental Issues

Shale gas is natural gas trapped within shale formations. Since the 1990s, horizontal drilling combined with hydraulic fracturing (fracking) has made large volumes economical to produce.

In India, mature organic-rich shale makes shale oil and gas likely in basins such as Cambay, Krishna-Godavari and Cauvery. Various international agencies assessed probable in-place shale gas of 100 to 200 trillion cubic feet (about 2.8 to 5.7 trillion cubic metres) in five Indian sedimentary basins, and later estimates differ widely.

In 2015 the Ministry of Petroleum and Natural Gas listed four estimates, which differ in what they measure.

• US Geological Survey (USGS), 2012: 6.1 trillion cubic feet of technically recoverable gas in three basins.
• US Energy Information Administration (EIA), 2011: 290 trillion cubic feet of gas in place in four basins.
• EIA, 2013: 584 trillion cubic feet of gas in place in four basins, with shale oil put at 87 billion barrels.
• ONGC, 2013: 187.5 trillion cubic feet of shale gas in five basins.

Gas in place is a resource, not a reserve, so the claim that shale can meet India's needs for a quarter century refers to the gas present, not to gas that can be produced.

The policy history explains why tapping has been slow.

1. On 14 October 2013 the government announced guidelines allowing the National Oil Companies, ONGC and Oil India (OIL), to explore shale gas and oil in the blocks held under nomination.
2. By 2015, 55 blocks had been awarded (ONGC 50, OIL 5); by November 2016, ONGC had identified 50 and OIL 6, a total of 56 blocks, mostly in Gujarat (28), Andhra Pradesh (10) and Tamil Nadu (9). ONGC had drilled 20 assessment wells.
3. In 2016 HELP brought every kind of hydrocarbon under one licence.
4. On 1 August 2018 the Cabinet approved a policy letting contractors in existing production sharing contracts and coalbed methane (CBM) blocks explore unconventional hydrocarbons in the same areas, ending the earlier rule that a CBM contractor could not exploit any other hydrocarbon.

Exploration was still at an early stage in 2015, and the main issues are environmental and technical.

• Water demand of fracking: Fracking uses large quantities of water, which is a serious problem in water-short regions, even though the amount is small compared with overall use in many areas.
• Pollution: Surface water can be polluted by spills, and groundwater can be contaminated if fracturing and formation fluids escape; methane can leak into groundwater and air.
• Induced earthquakes: Fracking causes tiny induced tremors, usually too small to detect at the surface, while waste-water disposal wells have been responsible for earthquakes up to magnitude 5.6 in Oklahoma and other US states.
• Technology and data: Indian shale is complex and the technology is still at an early stage, so reliable estimates of recoverable gas are lacking.

Coalbed Methane and a Comparison of Unconventional Gases

Coalbed methane, or coal-seam gas, is natural gas extracted from coal beds. Most of the gas is adsorbed on the coal. When a well starts producing, the water in the fractures is pumped off first, which lowers the pressure and frees the gas from the coal. CBM is mostly methane, with only small amounts of heavier hydrocarbons such as propane or butane. The water pumped out first is often saline and has to be disposed of safely.

In India, coalbed methane became commercially available on 14 July 2007 when Great Eastern Energy Corporation, the first company with an approved field development plan, completed 23 vertical production wells. By April 2015 the government had awarded 33 CBM blocks in four rounds of bidding and on nomination, with prognosticated resources of about 63.3 trillion cubic feet, of which 9.9 trillion cubic feet was established as gas in place.

Sources

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• USGS: Gas hydrate production testing, knowledge gained
• Press Information Bureau: Methane hydrates reserves (2014)
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