A combination of factors operating at the end of the twentieth century and first few years of the twenty-first century have led to a dramatic increase in the range of petroleum resources now exploited. Many technically challenging unconventional oil and gas accumulations become economically viable as extraction techniques have improved and oil prices briefly reached peak levels (Figure 7.1). At the same time concerns about climate change have begun to create a new industry, that of carbon dioxide capture and (geological) storage. Carbon capture and storage (CCS) shares much technology in common with the petroleum exploration and extraction process and to date those companies involved in the geological storage of carbon dioxide are largely oil and gas companies. From a global perspective, little attention is given to secondary products of petroleum production. There is however one, helium, which is globally important while there are others, notably heat and lithium that have the potential to be commercially viable byproducts and more may follow. The term “unconventional” is applied to both oil and gas that cannot easily be produced from the subsurface due to the properties of the petroleum itself or the reservoir in which the petroleum occurs. Thus the term is applied to highly viscous oils and tars (so called heavy, ultra-heavy oils and tar sands). The term is also applied in circumstances when the permeability of the reservoir is low so that the gas and or oil will not flow out at economic rates without stimulation of the well to improve the permeability around the wellbore. In addition the term is applied to situations in which it would be difficult to produce the petroleum without compromising the natural seals to the accumulation as in gas hydrates and shallow gas. In some news media and parts of popular culture the term unconventional is assumed to equal risky insofar as environmental impact or safety of production are concerned. This is an unfortunate and misleading correlation, all forms of petroleum, conventional or unconventional have associated environmental impacts and all need to be produced safely. North America in particular has seen a major increase in gas (and oil) production (driven initially by high prices and energy security issues) to the extent that the USA is again near self-sufficient, which in turn has forced prices down. Prominent sources of the new gas have been tight gas reservoirs, shale-gas, coal bed, and coal mine methane. All these alternative sources of gas have grown dramatically while that from conventional reservoirs has declined year on year (Figure 7.2). The growing prominence of shale gas in particular in the USA and Canada spawned a land grab elsewhere in the world. In Europe, Poland licensed huge tracts of land for shale gas exploration. Elsewhere in the UK, Hungary, Ireland, Germany, and Sweden a combination of North American companies that missed the opportunity in the USA and Canada, together with indigenous European mid-cap (capitalized) and start-up companies, have been snapping up acreage. Few exploration wells have been drilled so far in these countries, and success has been limited. As of mid-2020 there is no shale gas production in Europe. Elsewhere in the world outside North America studies of shale-gas potential abound and exploration wells have been drilled but production is limited, with China alone beginning to produce significant quantities of shale gas (Salygin et al. 2019). Figure 7.1 Oil price trend since 1960. Source: Data from BP Statistical Review of World Energy (2016). Figure 7.2 Growth of unconventional and decline of conventional gas in the USA. Source: Compiled from: US Department of Energy (DOE) 2009 and DOE/EIA 2016. In contrast tight-gas reservoirs, coal-bed methane (CBM), and coal-mine methane have not attracted the same fervor from either exploration and production (E&P) companies or the stock markets, but production from such sources is well underway in North America, Europe, Australia, and other parts of the world. Low saturation and basin-center gas have a long history of production often by accident, as it was not always appreciated how the gas was trapped but simply produced when wells were (pressure) drawn down to sufficient degree for the gas to expand and become the continuous phase and thus able to flow. The search to find it and exploit it is now much more rigorous than once it was. “Avoid shallow gas” was, and is the drilling engineer’s motto for offshore exploration. Much care is taken with each new proposed well to survey the likely top-hole locations and avoid those that show potential for shallow gas. Of most concern is gas so shallow that it is shallower than the typical conductor put in place when a well is spudded and before the blow-out-preventer can be attached. However, the definition of shallow gas is typically that which occurs shallower than about 1 km (∼3000 ft). Onshore it would not be unusual to exploit such gas but offshore examples are few. Nonetheless companies are increasingly finding large volumes of gas in the shallow subsurface and a few have made the decision to exploit such opportunities. In the late 1980s one of us made a suggestion to the Chief Geologist of the multinational company for which we worked that we (the company) should study the potential of gas hydrates as a potential source of huge quantities of methane. The reply, filtered through the many layers of management, was to the effect that such a gas source was for our grand-children’s grand-children. As of yet that same one of us has no grandchildren but one or two localities around the world in areas of permafrost are already yielding gas from hydrates although like the basin-center gas the initial exploitation was accidental. Fire damp (methane) is an ever-present hazard for conventional coal mining. Deaths resulting from explosions of air and methane mixtures in coal mines run into many thousands over the centuries. The methane responsible for such explosions is released from coal when the confining pressure is lowered. Of course, this is what happens during mining. This phenomenon is exploited both in coal mine and CBM exploitation. For coal-mine methane the gas is simply extracted from the old workings by drilling wells into the galleries and chambers. In CBM projects wells are drilled along coal beds and the pressure drawn down until gas becomes the continuous phase and flows into the well. Like the oil shale industry, underground coal gasification (UCG) is an old technique, first tried by Sir William Ramsey at Hett Hill in Durham in 1912 (Younger et al. 2010) but as of yet there is no commercial development of UCG. UCG exploits the same technology used in decades past to generate town gas from coal. This is a straightforward process in the laboratory or power station but very difficult to control (keep the reaction going) underground and distant from the operators. There have been numerous tests around the world and outside of the Former Soviet Union these have failed to get to the industrial development stage. A small but continuous UCG program is taking place In Uzbekistan. Heavy oil is typically described as crude with API gravity of lower than 20°, grading into tar which is a semi solid under most surface conditions. Heavy oil may flow at low rate from conventional wells. Tar will not do so and like most heavy oils requires tertiary oil extraction methods to be employed; e.g. steam flood, huff, and puff, in-situ combustion. Oil shales and marls are typically immature source rock or mature source rock for which expulsion has only partially occurred. In the past they have been mined and the oil extracted by retorting although there have been a few attempts to heat the rock and expel the oil in situ; to which the rather confusing term shale-oil has been applied. The mining of oil shale is an industry that pre-dates what we now regard as normal oil industry. James (Paraffin) Young founded a company at Bathgate near Edinburgh in Scotland in 1850 to extract the oil and other products from what are now called the Lothian (Carboniferous) oil shale. However, new fracture-stimulation technology (so-called “fracking or fraccing”), first applied to shale-gas in North America, has been creating commercial quantities of oil, to the extent that it has challenged the conventional oil producers such as Saudi Arabia, and led to the sharp reduction in oil prices in 2015/2016. At first glance it may seem a little odd that underground gas storage (UGS) is a business at all. However, it is an important part of balancing the energy portfolio in many developed countries. It allows for a degree of stability that may not be possible with direct gas supply from the producing fields, particularly if a country is a net importer of gas. There are three types of gas storage facility: depleted petroleum fields, aquifers, and salt caverns. The key component in gas storage is high deliverability which typically exceeds flow rates from natural gas accumulations. Carbon or carbon dioxide storage is an embryonic industry developing in response to ever increasing levels of carbon dioxide in the atmosphere caused by burning oil, gas, and coal. The basic idea is that the CO2 is caught at source (power station or industrial complex), pressurized, transported by pipeline to a storage site and then buried as a critical fluid deep beneath the Earth’s surface. As with gas storage there are a variety of options for burial, including depleted petroleum fields, deep saline aquifers, unminable coal seams and porous mafic rocks (such as basalt and peridotite). The definition of tight gas reservoirs is at best semi-quantitative, based upon local economic criteria. As such a reservoir with mean permeability of about 1 mD in the UK’s Southern Gas Basin would be defined as tight, whereas the same reservoir onshore USA would be considered perfectly adequate. A tight reservoir onshore USA would have a permeability of 0.1 mD or less. Although of low permeability, a tight reservoir may have a perfectly reasonable storage capacity (net to gross and porosity). It is simply that the porosity is poorly interconnected (Figure 7.3) and this can occur in any reservoir lithology. In addition to reservoirs with poor permeability but moderate to high porosity there are other potential reservoirs which are low porosity (Figure 7.3). Such reservoirs also have issues with defining net pay and irreducible water saturation. Exploitation of tight gas reservoirs commonly relies upon either searching for natural high permeability conduits (layers or fractures) or artificially stimulating flow by hydraulically fracturing the reservoir. The philosophy is that these high permeability conduits will allow drainage of gas from the lower permeability portions of the fields. The Lower Permian Rotliegend sandstone reservoir of the UK and Netherland’s portions of the North Sea is in places tight and over the past 30 years a variety of methods have been used to improve gas flow rate. The Hyde Field (BP) was discovered in 1982 but not brought on stream until 1993 using horizontal wells designed to cross-cut higher permeability layers (Steele et al. 1993; Sweet and Blewden 1996). Appraisal well drilling established the permeability to lie in the range 0.01–40 mD (to air) with a modal value of 1 mD, with much of the best quality rock being eolian in origin. During the appraisal program which comprised vertical unstimulated wells, the best flow rate achieved was 12 MMSCF d−1. In late 1991 a final appraisal well was drilled. This time however the well was planned as horizontal and it was designed to cross-cut as much of the highest quality reservoir as possible. A horizontal well was favored in preference to fracture stimulation to minimize the facilities cost and remove the possibility that a fracture may have penetrated the relatively thin gas column into the water leg. Pre-spud it was calculated that a threefold improvement in flow rate could be achieved. Once on test the well outperformed expectations flowing at an unstabilized rate of 69 MMSCF d−1 (equivalent to 45–60 MMSCF d−1 stabilized). Figure 7.3 Tight gas and oil reservoirs in core and thin section (blue areas are porosity), (a) sponge spiculite reservoir Upper Jurassic, Moray Firth North Sea, Individual spicules have been dissolved and what was pore space is infilled with silica and dolomite. Porosity about 20%, permeability <1 mD. (b) isolated pore after feldspar dissolution (F), Middle Jurassic Brent Sandsone, Columba Field, UK North Sea, (c) poorly interconnected inter-crystalline porosity in Permian, Zechstein dolomite, Dutch sector North Sea, (d) Poorly connected biomouldic, vuggy porosity in Lower Carboniferous dolomite, UK land. Source: Photographs (a), (b), (c) by J. Gluyas, (d) by N. Narayan. (See color plate section for color representation of this figure). Further south in the same basin a rather different approach was adopted for development of the Clipper Field (Shell, Figure 7.4). It too flowed at low rate from vertical unstimulated wells and although many of these exploration wells were hydraulically fractured (fracked) and flowed, the process was abandoned in favor of drilling horizontal wells to intersect with natural fractures. For this particular field the well azimuth did not correlate with production rate which would have implied the presence of open fractures of a particular orientation. There were however a large number of well failures due to no flow from tight reservoir (25%). Figure 7.4 Hyde, Clipper, and Ensign gas fields, UK North Sea. Source: Petroleum Geology of North-West Europe, Vol 7. Reproduced with permission of Geological Society of London. The Ensign Field (Figure 7.4) from the same basin demonstrates current best practice. Like Clipper, Hyde, and so many other of the Southern Gas Basin fields it too has a low permeability reservoir and it too contains some naturally open fractures (Figure 7.5; Purvis et al. 2010). Although there are some open fractures the field was developed with multi-fracked horizontal wells. For a description of a tight gas appraisal and development case history for the UK’s Clipper South Field see Section 7.9. Production of shale gas has revolutionized the gas market in the USA and turned the nation from a gas importer to self-sufficient in 2015 and 2106 the nation became a gas exporter (Figure 7.6), the first time since 1957. This revolution has been a long time coming; the first shale gas production was in New York State in 1821 (Selley 2005) but it was not until the early to mid-1990s that production escalated. A milestone was reached in 2003 when the gas produced from unconventional reservoirs onshore exceeded that from conventional reservoirs. The year 2015 marked another milestone when production from shale gas alone was 14 trillion cubic feet, a figure that matched production from all other sources; conventional onshore, conventional offshore, Alaska and from CBM. When combined with tight gas, these two unconventional reservoirs delivered over 70% of US production (Figure 7.7). Much of the rest of the world is well behind the US in terms of shale gas development. Nonetheless, global in-place resources and technical reserves are currently thought to be massive (Table 7.1). The study by EIA/ARI (2011) suggested the global in place resource could be larger than 25 000 TCF (trillion cubic feet) of which more than 6000 TCF could be technical reserves (Table 7.1). These volumes compare with the global estimate of remaining conventional gas reserve of 7177 TCF as of January 1, 2019 (EIA 2020). That is to say, shale gas reserves are a little less than 40% of total (conventional plus unconventional) global gas reserves. Figure 7.5 Partially open and partially cemented fractures, Lower Permian Rotliegend Sandstone, Ensign Field, well 48/15–5, UK North Sea. Source: Purvis et al. 2010. Reproduced with permission of Geological Society of London. Table 7.1 Estimate of in-place shale gas resources EIA/ARI (2011) The term “shale gas” has in recent years become synonymous with the well-stimulation technique of hydraulic fracturing (fraccing or fracking) and in so doing has picked up significant amounts of bad press because of a perceived link with methane seepage into potable water supplies in the USA, though there is little reliable evidence to support such claims and demonstrate a causal link. It appears more likely that seepage of gas into drinking water has occurred through access of gas from old wells drilled for conventional petroleum reserves into neighboring aquifers (Davies et al. 2014). However, fracking for shale-gas will induce seismicity, some of it significant (Foulger et al. 2018). “Shale gas” is gas produced directly from what is normally thought of as a source rock. It is quite usual to record “gas shows” when drilling source rocks in conventional operations but rarely in the past have wells been engineered to flow gas to surface. Pore throat size in shales may be several orders of magnitude smaller than that seen in sandstones (and tight sandstones) and it is small pore throat size that controls the permeability of the system and hence fluid flow (Figure 7.8). Shale gas formations typically require either long, high angle (horizontal) wells or fracture stimulation (Figure 7.9) in much the same way as described for tight gas reservoirs (above) and well spacing is much closer than that for conventional oil or gas. However, even with stimulation flow may be restricted. Typically, when searching for shale gas plays geologists will be trying to determine whether or not their chosen area has any attributes that would contribute to gas flow. Shales are highly variable in their texture and rock properties. They are often thought of as clay mineral dominated and many are but most of the better performing shale gas systems have 40% or less clay mineral content. Those that are silty or rich in silica and hence brittle tend on the whole to be better targets (Figure 7.10). It has been estimated that typical shales exhibit a range of permeability (a key component in their ability to release petroleum) of seven orders, a range greater than reservoir sandstones. The mineralogy of the shale is important but the main control on permeability is the grain size distribution (Yang and Aplin 2010), with silty shales having microDarcy permeability compared with compacted clay-dominated shales having sub-nanoDarcy permeability. Shales can be highly laminated, with fine-scale layering, and may also include sandstones and carbonate interbeds. Figure 7.6 USA natural gas production and consumption. Source: Adapted from DOE/EIA 2016. Figure 7.7 USA natural gas production by source. The associated sandstones may have modest matrix permeability while carbonates may be jointed or fractured yielding permeability. It appears from the experience of producing shale-gas from source rocks in the USA that the siliceous and/or calcareous component may be a critical factor in creating a brittle shale, capable of generating clean, open fractures when stimulated. Non-siliceous and non-calcareous gas-prone source rocks are more ductile (an inherent property of clay-rich rocks) and seem less suitable for shale-gas production with current technology, as the injected fluids do not create fractures capable of delivering gas at economic rates. Figure 7.8 Pore throat sized spectrum in petroleum reservoirs. Pore throat sizes in siliciclastic rocks form a continuum from around 20 μm to less than 0.005 μm. The smallest detectable mean pore throat sizes are about 10 times the diameter of a water molecule. Source: Adapted from Nelson 2009. Figure 7.9 Multifrack well at Siedenberg Z17 (Germany). The well targeted Permian Rotliegend Sandstone. The initial flow rate following the multifrack was 14.5 MMSCF d−1, six times that achieved in vertical wells. Source: Schamp 1997. Reproduced with permission from the Oil and Gas Journal Figure 7.10 Mineralogical composition of US shale gas reservoirs (black circles) and potential UK reservoirs (gray squares). Source: Data from Hughes et al. 2016 and Newport et al. 2016. A thorough understanding of how to predict the flow characteristics of shale gas systems has yet to be achieved. There is a considerable amount of current research examining the distribution of gas within the shales. Free gas may occur within pores or fractures as may gas dissolved in the connate brine. The gas can also occur in the sorbed state on clay minerals or organic matter. Gas from fractures will be produced immediately while that adsorbed will only be produced after considerable pressure drop. Calculation of the gas content of a shale gas is critical for estimating resource and hence reserve for a particular area. Aplin (2011) has demonstrated a well-developed relationship between total organic carbon (TOC) and gas content (scf t−1, Figure 7.11). Low saturation gas is rarely directly targeted in exploration, though it may be found accidentally and it is a relatively common, though unexpected end of field bonus. The term low saturation refers to the gas occurring as a discontinuous phase in the reservoir. Residual trapping is another description of the same phenomenon. Individual bubbles of methane are trapped within pores while the pore-lining and pore-throat regions are water filled (Figure 7.12). Water is thus the continuous phase. The gas is immobile and therefore is unaffected by buoyancy. That is to say a conventional seal and trapping geometry is not required. Accumulations of low saturation gas commonly occur in tight reservoirs with less than about 1 mD mean permeability but this need not always be the case so long as water is the continuous phase. Low saturation shares much in common with basin-center gas (Section 7.2.5). Production of low saturation gas occurs when the gas becomes the continuous phase following pressure drawdown. This typically means that water must first be produced before any gas is produced. As pressure is lowered the gas bubbles expand, eventually merging to deliver the continuous phase required for production. Low saturation gas characterized Monument Oil and Gas from the Sierra Chata Field discovery in Block CNQ10 of the Neuquen Basin in Argentina. The field was discovered on the basis of seismic amplitude anomalies on 2D data. Such anomalies were later shown to be related to lithology – tight rock (Woller and Louder 1999). The discovery was in fact a fluke as was gas production from one of the first drilled wells. It was tested and flowed gas before the wireline logs were interpreted to show that the reservoir interval was largely water saturated with only low saturation gas (pers comm Lindsay Kaye 1996). Figure 7.11 Correlation between total organic carbon (TOC) and gas content. Source: Courtesy of Andy Aplin. Figure 7.12 Distribution of water and trapped gas in a low-saturation gas reservoir. In another example the Hamilton Field in the East Irish Sea Basin (Yaliz and Taylor 2003) has a wedge of low saturation gas below its gas-water contact. The wedge results from tilting of the structure in the relatively recent geological past. The interval that now contains residual gas was once above the gas-water contact and as the structure rotated some of the gas was left behind. This low saturation gas will no doubt be produced toward the end of the life of the field when the reservoir pressure has dropped sufficiently for the low-pressure gas bubbles to expand and merge. Shallow gas is a rather loosely applied term for trapped gas in near surface sediments in offshore settings. The reason the term is applied to offshore rather than onshore gas accumulations is because it has up until recently been seen as a problem rather than as an opportunity; something to be avoided because it presented a potential safety hazard. During the earliest phases of exploration in offshore areas such as the Gulf of Mexico and the North Sea, the presence of shallow gas was a serious hazard for drilling. Areas identified as being gas prone were avoided. There are a number of instances in which shallow gas was struck accidentally with resultant blow-outs. Examples include the drilling rig Sedco 700 which was involved in a shallow gas blowout, offshore Nigeria in June 2009. The posted video on You Tube shows a boiling sea as gas escapes from the sub-sea well head. Shallow gas may be trapped in the subsurface by conventional low permeability lithological seals but it can also occur beneath gas hydrate accumulations in deeper water (Chapter 3). Many shallow gas accumulations show signs of leakage to surface. These signs include gas chimneys visible on seismic data as well as sea-bed pock marks and in some instances methane can be observed bubbling from the sea floor. Other shallow accumulations including the large Peon discovery offshore Norway (Eriksen et al. 2011) show no evidence of leakage. The source of gas in shallow gas accumulations can come from bacterial reduction of organic matter in the near subsurface or from thermal degradation of organic matter at depth (Floodgate and Judd 1992; Chapter 3) coupled with migration to near surface or indeed a mixture of the two sources. Thermally derived gas and bacterially produced gas have very different and therefore distinctive carbon isotope signatures. The thermally derived gas typically has a δ13C of around −25‰ while biogenic methane is isotopically much lighter with a δ13C of −75‰ or thereabouts. Whatever the source of the gas, if large enough, the accumulation could be exploited. Drilling technology is sufficiently well developed that the potential hazards can be mitigated. For example, significant quantities of gas occur in shallow unconsolidated sands however, technological breakthrough in terms of sand control in well completions in horizontal wells has allowed such difficult reservoirs to be exploited (van de Boogaard and Hoetz 2012). This is the case with the development of shallow gas pools in the northernmost Quads (A, B, and F) of the Dutch North Sea. Three fields are already on stream and a further five in development. Thirty-eight production wells were drilled by the end of 2012 and reserves measured in excess of 10 TCF. Much of the exploration is driven by identification of “bright spots,” that is high amplitude reflectors on shallow seismic data. The mapped amplitude anomalies are then graded depending upon depth, size, and the presence or absence of dip closure. Using this approach exploration company EBN identified 152 leads of which 48 were classified as attractive and 14 present in unlicensed acreage (van de Boogaard and Hoetz 2012). The case history on the Dunlin Field at the end of this chapter illustrates the potential of shallow gas adjacent to an existing oil field and how such gas might be developed to support power production on the platform. Basin-center gas is a mildly controversial topic. Certainly, gas does occur in basin centers but the question is whether such gas accumulations deserve a separate status from conventionally trapped gas. The main arguments from the advocates of basin-center gas are that such gas is not trapped by conventional seals and that downdip water legs are not to be found. The full list of criteria for basin-center gas published by Wilson et al. (2008): Those who would challenge the existence of basin-center gas as a special category (e.g. Shanley et al. 2004a,b) point out that most of the above criteria can equally apply to conventional gas accumulations. In broad terms all of the above criteria can be accommodated in a model in which a combination of rock quality, pressure, and gas saturation combine to deliver a distributed non-connected gas phase where the effects of buoyancy are insufficient to overcome capillary entry pressure, so the gas stays where it is until wells are drilled and pressure drawdown induces flow of the gas to the production wells. It is a common occurrence for basin-center gas plays to have “sweet-spots” which are wells which flow at high rate and that such “sweet-spots” are invariably normally trapped, continuous phase gas pockets in better than regional quality rock, such as in the Elmworth giant deep gas discovery and adjacent areas in Alberta Canada (Gies 1984). Shanley et al. (2004a) re-define the basin-center gas accumulations on the USA as “tight gas” or “gas resources in low-permeability reservoir.” What is significant are the volumes of gas in such settings, estimated as between 315 and 340 TCF in US basins alone (Shanley et al. 2004b). Gas hydrate, methane hydrate, or fire ice as it is sometimes known, is a clathrate structure in which large quantities of methane are held within a water structure; (CH4)4(H2O)23 (USGS 2014; Figure 7.13). In the natural environment, such hydrates along with those containing ethane and carbon dioxide can form in marine sediments and beneath permafrost. Their presence has also been inferred on other planets and moons in our solar system. The gas hydrates form at low temperatures and high pressures (Figure 7.14, Ruppel 2007), with much of the deeper world’s oceans and seas (below about 700 m) being suitable for formation of the hydrate in the sediment column. The Ocean Drilling Program (Long et al. 2005) and similar programs has returned samples to surface where hydrates slowly decompose releasing both methane and water. The hydrates can occur disseminated throughout sediment or more rarely as lumps and veins. In some instances the abundance may be such that their impact on the acoustic properties of the sediment means that they can be seen on seismic data where their base is typically marked by a “bottom simulating reflector” which mimics the sea-bed topography. The quantity of gas trapped in such a way beneath the sea-bed is enormous, perhaps between 1000 and 5 million TCF. This volume of gas equates to about 4000 times the annual gas consumption in the USA (USGS 2014) but most of the gas is thought to be disseminated and unlikely to form a targeted resource. There is however some evidence to suggest that a few gas fields in Siberia have accidentally produced methane from gas hydrates while tapping into free gas that exists below permafrost areas. Here the pressure depletion caused by production has led to the decomposition of part of the overlying permafrost seal with release of methane. In a curious twist, natural decomposition of Atlantic margin gas hydrates at the end of the Paleocene has been cited as the cause of the mass extinction event at that time. Lovell (2008) argues that uplift of the Atlantic margin associated with a rising plume, elevated hydrate bearing sediments such that the hydrate decomposed and methane, a powerful greenhouse gas, was released into the atmosphere. Global climate warming and extinction followed. There are those who fear that the current climatic changes brought about by massive use of fossil fuels could similarly warm the oceans with resultant release of large quantities of methane.
7
Unconventional Petroleum, Gas Storage, Carbon Storage, and Secondary Products
7.1 Introduction
7.1.1 Unconventional Gas
7.1.2 Unconventional Oil
7.1.3 Gas Storage
7.2 Unconventional Gas
7.2.1 Tight Gas Reservoirs
7.2.2 Shale Gas
Continent
Shale resource (TCF)
North America
7.140
South America
4.569
Europe
2.587
Africa
3.962
Asia
5.661
Australasia
1.381
Total
25.300
7.2.3 Low Saturation Gas
7.2.4 Shallow Gas
7.2.5 Basin-Center Gas
7.2.6 Gas Hydrates
