7 NATURAL GAS Abstract Natural gas is considered as one of the primary energy sources of the world. It mainly contains methane (CH4) and is colorless and odorless. Natural gas has many uses and can be used in most energy sectors: residential, commercial, and industrial. In this chapter, we have discussed its total reserve worldwide, its origin, processing, transportation, and storage. Natural gas from the well head has to go through various processing steps before its final use. Like every other commodities, natural gas is also traded internationally and transported through pipelines across the countries. However, its transportation through pipe lines is limited and as a result its movement is generally confined among neighboring countries. Recently, natural gas is liquefied, called liquefied natural gas (LNG), and is transported via sea to distant countries. Consequently, natural gas is becoming a dominant energy source. 7.1 Introduction Worldwide consumption of natural gas in 2005 was 104 trillion cubic feet and it is expected to increase to 182 trillion cubic feet in 2030. This represents a worldwide increase of 2.5% annually. Natural gas is considered to be one of the cleanest energy sources as it can be burned more efficiently compared to coal and petroleum. The worldwide reserve of natural gas and its production and consumption rate is shown in Fig. 7.1. As shown in Table 7.1, the use of natural gas in the USA is expected to increase in all sectors; however, the main increase is expected to be in industrial sectors, such as for fertilizer production, and electricity generation. The two top users of the natural gas are the USA and China. In Table 7.2 the production and consumption rate of various countries in the last five years along with 281 T.K. Ghosh and M.A. Prelas, Energy Resources and Systems: Volume 1: Fundamentals and Non-Renewable Resources, 281-381. © Springer Science + Business Media B.V. 2009 Licensed to Jiri Martinec 282 7 Natural Gas their reserve are given. Although the data show that a considerable amount of natural gas is available, its trade or use is more regional as delivery of the natural gas through pipeline from one region to another region is costly. The international trade of natural gas among various countries is given in Tables 7.3-7.5. At the current rate of consumption, natural gas is expected to last about 65 years, unless new reserves are discovered. 1980 1985 1990 1995 2000 2005 3 Year Fig. 7.1. Reserve, production, and consumption of natural gas worldwide [1], Table 7.1. Increase of natural gas use by various sectors in the USA (in trillion cubic feet). Consump- _Year_ tion sectors 2QQ5 2QQ6 2QQ7 2QQ8 2Q1Q 2Q15 2Q2Q 2Q25 2Q25 Residential 4.83 4.37 4.73 4.83 4.81 5.01 5.15 5.19 5.17 Commercial 3.00 2.83 3.02 3.05 2.96 3.20 3.37 3.53 3.67 Industrial 6.60 6.49 6.60 6.64 6.95 7.00 6.93 6.96 6.87 Electric 5.87 6.24 6.78 6.83 6.70 6.56 5.92 5.30 4.99 power Total_22.01 21.66 22.90 23.12 23.25 23.66 23.33 22.99 22.72 Source: Reference [2], Licensed to Jiri Martinec Table 7.2. Proven reserves, consumption, and percent change of natural gas use. Countries Reserve at the end of 2006 Share R/P Production /o Consumption /o Cubic feet Cubic meter of total ratio in 2006 bcm Change from 2005 in 2006 bcm Change from 2005 USA 209.15 5.93 3.3% 11.3 524.1 2.3% 619.7 -1.7% Canada 58.77 1.67 0.9% 8.9 187.0 0.6% 96.6 5.7% Mexico 13.70 0.39 0.2% 8.9 43.4 10.6% 54.1 13.6% Total North America 281.62 7.98 4.4% 10.6 754.4 2.3% 770.3 0.1% Argentina 14.65 0.42 0.2% 9.0 46.1 1.0% 41.8 3.5% Bolivia 26.12 0.74 0.4% 66.3 11.2 7.2% - - Brazil 12.28 0.35 0.2% 30.2 11.5 1.3% 21.1 6.1% Chile - - - - - - 7.6 -11.5% Colombia 4.34 0.12 0.1% 16.9 7.3 7.6% 7.3 7.6% Ecuador - - - - - - 0.3 3.8% Peru 12.00 0.34 0.2% * - - 1.8 17.0% Trinidad & Tobago 18.71 0.53 0.3% 15.1 35.0 15.6% - - Venezuela 152.32 4.32 2.4% * 28.7 -1.0% 28.7 -1.0% Other South & Central America 2.40 0.07 Z 14.3 4.8 5.0% 22.1 14.0% Total South & Central America 242.83 6.88 3.8% 47.6 144.5 4.7% 130.6 3.9% Austria — — — — — — 9.4 -6.0% Azerbaijan 47.66 1.35 0.7% * 6.3 18.0% 9.6 8.1% Belarus - - - - - - 19.6 3.4% Table 7.2. (Continued) o CD CO CD Q. 03 CD O A 3 P- CD O 3 CD < C 8 V Countries Reserve at the end of 2006 Cubic feet Cubic meter Share of total R/P ratio Production in 2006 bcm /o Change from 2005 Consumption in 2006 bcm /o Change from 2005 Belgium & Luxembourg - - - - - - 17.0 2.4% Bulgaria - - - - - - 3.0 3.1% Czech Republic - - - - - - 8.5 -0.3% Denmark 2.72 0.08 - 7.4 10.4 -0.3% 5.1 1.8% Finland - - - - - - 4.3 7.7% France - - - - - - 45.2 -1.5% Germany 5.47 0.16 0.1% 9.9 15.6 -1.2% 87.2 1.1% Greece - - - - - - 3.2 15.2% Hungary - - - - - - 12.5 ^1.9% Iceland - - - - - - - - Ireland - - - - - - 4.5 15.6% Italy 5.63 0.16 0.1% 14.5 11.0 -9.0% 77.1 -2.1% Kazakhstan 105.90 3.00 1.7% * 23.9 2.7% 20.2 3.3% Lithuania - - - - - - 3.3 0.1% The Netherlands 47.55 1.35 0.7% 21.8 61.9 -1.6% 38.3 -3.0% Norway 102.09 2.89 1.6% 33.0 87.6 3.1% 4.4 -1.4% Poland 3.67 0.10 0.1% 24.4 4.3 -1.3% 13.7 0.6% Portugal - - - - - - 4.1 -3.9% Romania 22.17 0.63 0.3% 51.7 12.1 0.2% 17.0 -1.7% Russian Federation 1,682.07 47.65 26.3% 77.8 612.1 2.4% 432.1 6.7% Slovakia - - - - - - 5.5 -16.0% Countries Reserve at the end of 2006 Share R/P Production /o Consumption /o Cubic feet Cubic meter of total ratio in 2006 bcm Change from 2005 in 2006 bcm Change from 2005 Spain - - - - - - 33.4 3.2% Sweden 0.8 7.1% Switzerland -3.7% Turkey 100.96 2.86 1.6% 46.0 62.2 5.9% 30.5 13.5% Turkmenistan 38.83 1.10 0.6% 57.7 19.1 -1.7% 18.9 14.0% Ukraine 100.96 2.86 1.6% 46.0 62.2 5.9% 66.4 -8.8% UK 16.98 0.48 0.3% 6.0 80.0 -8.6% 90.8 -4.5% Uzbekistan 66.01 1.87 1.0% 33.7 55.4 0.8% 43.2 -1.9% Other Europe & Eurasia 15.99 0.45 0.2% 41.4 10.9 7.8% 14.7 0.7% Total Europe & Eurasia 2,263.69 64.13 35.3% 59.8 1,072.9 1.2% 1,146.3 1.9% Bahrain 3.18 0.09 Z 8.1 11.1 3.2% — — Iran 992.99 28.13 15.5% * 105.0 4.1% 105.1 2.7% Iraq 111.90 3.17 1.7% * - - - - Kuwait 62.83 1.78 1.0% * 12.9 4.9% 12.9 4.9% Oman 34.59 0.98 0.5% 39.0 25.1 27.0% - - Qatar 895.24 25.36 14.0% * 49.5 8.1% 19.5 4.3% Saudi Arabia 249.68 7.07 3.9% 96.0 73.7 3.5% 73.5 3.5% Syria 10.24 0.29 0.2% 52.3 5.5 3.3% - - United Arab Emirates 213.95 6.06 3.3% * 47.4 0.9% 41.7 1.0% Yemen 17.12 0.49 0.3% * - - - - (Continued) Table 7.2. (Continued) o CD CO CD Q. 03 CD O A 3 P- CD O 3 CD < C 8 V Countries Reserve at the end of 2006 Share R/P Production /o Consumption /o Cubic feet Cubic meter of total ratio in 2006 bcm Change from 2005 in 2006 bcm Change from 2005 Other Middle East 1.80 0.05 Z 9.0 5.6 28.1% 36.4 17.5% Total Middle East 2,593.53 73.47 40.5% * 335.9 5.8% 289.3 4.5% Algeria 159.00 4.50 2.5% 53.3 84.5 -4.3% 23.7 2.2% Egypt 68.48 1.94 1.1% 43.3 44.8 29.3% 28.7 11.4% Libya 46.45 1.32 0.7% 88.9 14.8 31.0% - - Nigeria 183.91 5.21 2.9% * 28.2 25.9% - - Other Africa 42.82 1.21 0.7% * 8.2 - 23.3 2.3% Total Africa 500.67 14.18 7.8% 78.6 180.5 9.5% 75.8 5.5% Australia 91.96 2.61 1.4% 67.0 — — 28.6 3.4% Bangladesh 15.36 0.44 0.2% 28.6 15.2 7.1% 15.2 7.1% Brunei 11.83 0.34 0.2% 27.3 12.3 6.5% - - China 86.45 2.45 1.3% 41.8 58.6 17.2% 55.6 21.6% Hong Kong - - - - - - 2.4 13.2% India 37.95 1.08 0.6% 33.9 31.8 -1.0% 39.7 4.3% Indonesia 92.91 2.63 1.5% 35.6 74.0 0.3% 39.6 5.6% Japan - - - - - - 84.6 7.0% Malaysia 87.54 2.48 1.4% 41.2 60.2 0.4% 40.3 2.5% Myanmar 18.99 0.54 0.3% 40.1 13.4 3.1% - - New Zealand 3.9 2.2% 3.7 6.4% o CD CO CD Q. 03 CD O A 3 P- CD O 3 CD < C 8 V Countries Reserve at the end of 2006 Cubic feet Cubic meter Share of total R/P ratio Production in 2006 bcm /o Change from 2005 Consumption in 2006 bcm /o Change from 2005 Pakistan 28.17 0.80 0.4% 26.0 30.7 4.8% 30.7 4.8% Philippines 2.6 -13.8% Singapore 6.6 South Korea 34.2 1.4% Papua New Guinea 15.36 0.44 0.2% * - - Taiwan 11.9 12.1% Thailand 10.63 0.30 0.2% 12.4 24.3 2.8% 30.6 2.3% Vietnam 14.12 0.40 0.2% 57.1 7.0 1.6% - - Other Asia Pacific 11.90 0.34 0.2% 48.8 6.9 -5.4% 12.1 6.3% Total Asia Pacific 523.15 14.82 8.2% 39.3 377.1 4.0% 438.5 6.5% TOTAL WORLD 6,405.48 181.46 100% 60.3 2,865.3 3.0% 2,850.8 2.5% of which: European Union 25 85.66 2.43 1.3% 12.8 190.0 ^1.9% 467.4 -1.4% European Union 27 202.7 ^1.6% 487.4 -1.3% OECD 561.29 15.90 8.8% 14.7 1,078.5 1.1% 1,419.8 0.3% Former Soviet Union 2,051.28 58.11 32.0% 74.6 779.3 2.5% 621.1 4.0% Other EMSs 1,007.5 5.6% 809.9 5.3% More than 100 years. A Less than 0.05. Less than 0.05%. n/a not available. #Excludes Estonia, Latvia and Lithuania prior to 1985 and Slovenia prior to 1991. Annual changes and shares of total are calculated in million tonnes oil equivalent figures. As far as possible, the data above represent standard cubic metres (measured at 15°C and 1,013 mbar); as they are derived directly from tones using an average conversion factor, they do not necessarily equate with gas volumes expressed in specific national terms. The difference between these world consumption figures and the world production statistics is due to variations in stocks at storage facilities plants, together with unavoidable disparities in the definition, measurement or conversion of gas supply and demand data. of oil equivalent and liquefaction Table 7.3. Natural gas trading by countries via pipeline in 2006 in North America and South & Central America (billions of cubic meter). To From Total imports To From Total imports USA Canada Mexico Argentina Bolivia North America South and Central America USA - 99.75 0.08 99.83 Argentina - 1.80 1.80 Canada 9.37 9.37 Brazil 0.46 9.00 9.46 Mexico 9.85 9.85 Chile 5.56 - 5.56 Total 19.22 99.75 0.08 Uruguay 0.12 - 0.12 imports Total imports 6.14 10.80 Source: Energy Information Administration, USA Table 7.4. Natural gas trading by countries via pipeline in 2006 in Europe (billions of cubic meter). From To Belgium Denmark Germany The Netherlands Norway UK Russian Fed. Turkmenistan Other Europe & Eurasia Total imports Austria - - 1.10 - 0.78 6.85 - - 8.73 Belgium - - 1.00 7.60 8.50 0.64 0.63 - - 18.37 Bulgaria - - - - - - 2.85 - - 2.85 Croatia - - - - - - 0.75 - 0.40 1.15 Czech Republic - - - - 2.35 - 7.13 - - 9.48 Finland - - - - - - 4.52 - - 4.52 France 1.90 - 0.10 9.50 14.50 0.20 9.50 - - 35.70 Germany - 1.92 - 21.30 26.80 3.08 36.54 - 1.20 90.84 Greece - - - - - - 2.40 - - 2.40 Hungary - - 0.83 - - - 8.32 - 1.80 10.95 Ireland - - - - - 3.40 - - - 3.40 Italy - - 2.50 8.70 7.20 0.80 22.92 - - 74.27 Latvia - - - - - - 1.70 - - 1.70 Lithuania - - - - - - 2.90 - - 2.90 Luxembourg 0.80 - 0.70 - - - - - - 1.50 Netherlands - 2.24 4.50 - 7.00 1.82 2.97 - - 18.53 Poland - - 0.35 - 0.49 - 7.00 0.21 2.52 10.57 Portugal — — — — — — — — — 2.10 (Continued) Table 7.4. (Continued) From To Belgium Denmark Germany The Netherlands Norway UK Russian Turkmenistan Fed. Other Europe & Eurasia Total imports Romania - - 1.30 - - - 3.95 - 1.00 6.25 Serbia - - - - - - 2.15 - - 2.15 Slovakia - - - - - - 6.30 - - 6.30 Slovenia - - - - - - 0.56 - 0.10 1.10 Spain - - - - 2.12 - - - - 10.74 Sweden - 0.93 0.15 - - - - - - 1.08 Switzerland - - 1.20 0.90 0.08 - 0.37 - 0.50 3.05 Turkey - - - - - - 19.65 - - 25.34 UK 1.80 - 1.00 0.60 14.10 - - - - 17.50 Others - - - - 0.08 - 1.50 - - 1.58 Flows are on a contractual basis and may not correspond to physical gas flows in all cases. Cedigaz (provisional). Data excludes trade within the Former Soviet Union and United Arab Emirates. Source: Energy Information Administration, USA Table 7.5. Natural gas trading by countries via pipeline in 2006 in Asia (billions of cubic meter). From To Turkmenistan Oman Algeria Egypt Indonesia Malaysia Myanmar Total _imports Middle East Iran 5.80 5.80 Jordan 1.93 1.93 United Arab Emirates 1.40 1.40 Africa Tunisia 1.30 1.30 Asia Pacific Singapore 4.83 1.78 6.61 Thailand_=_=_=_=_=_=_8_98_8.98 Flows are on a contractual basis and may not correspond to physical gas flows in all cases. Source: Cedigaz (provisional). Data excludes trade within the Former Soviet Union and United Arab Emirates. 292 7 Natural Gas 7.2 Formation of Natural Gas There are a number of theories on the formation of natural gas below the earth's crust [3-19]. These theories may be classified into following three categories. • Thermogenic methane • Biogenic methane, and • Abiogenic methane The thermogenic process is the most widely accepted theory for formation of methane. According to this process, fossil fuels are formed when organic matter is compressed under the earth, at very high pressure for a very long time. As a result, natural gas is usually found with the oil deposits. The amount of methane formation depends on temperature: at low temperatures (shallower deposits), more oil is produced relative to natural gas. At higher temperatures, more natural gas is created as opposed to oil. However, if the deposits are very far underground, they mainly contain natural gas rich in methane. The formation of natural gas and oil in a reservoir is shown in Fig. 7.2. Fig. 7.2. Schematic of a petroleum trap [4], Licensed to Jiri Martinec 7.3 Unconventional Sources 293 The transformation of organic matter by microorganisms can lead to the formation of methane. Methane produced in this manner is referred to as biogenic methane, which may be distinguished by its isotopic signature from thermogenic methane [4]. A third way in which methane (and natural gas) may be formed is through abiogenic processes. Extremely deep under the earth's crust, there exist hydrogen-rich gases and carbon molecules, which under certain conditions can chemically react forming methane. A number of researchers have tried to simulate the process in order to verify the theory of abiogenic process for methane formation [5]. However several observations and measurements including high temperature fluid venting from ridges at the middle of the ocean [6], seepages from regions associated with ultramafic rocks on land, fluids from Precambrian shields, and igneous rocks suggest the formation of methane in Earth's crust by abiogenic process. 7.3 Unconventional Sources Natural gas can also be produced from a number of other unconventional sources [21-33]. These unconventional sources may be divided into six categories: • Deep natural gas • Tight natural gas (tight gas sands) • Gas-containing shales • Coalbed methane • Geopressurized zones, and • Methane hydrates Among these sources, tight gas sands, gas containing shales, and coalbed methane, are widely used commercially for methane production. Improved exploration and production technologies in the oil and gas industry have made commercial production possible. In Table 7.6 the global unconventional resources for various fossil energy sources is compared. When the gas hydrate is included, the unconventional sources of natural gas are significantly higher than oil or coal. Discoveries of new conventional natural gas reservoirs are expected to be smaller in size and deeper, and thus more expensive and riskier to develop and produce. The use of unconventional resources is expected to increase dramatically. For example, Canada is a major producer of natural gas from conventional sources. However, as shown in Fig. 7.3 their Reserves/Production ratio is declining steadily. Their production of conventional natural gas peaked in 2000 and has been decreasing ever since. Currently, Canada is exploring production of natural gas from unconventional resources. Unconventional gas will have an important role to play in reducing the gap between demands and declining conventional gas production. Licensed to Jiri Martinec 294 7 Natural Gas Table 7.6. Global fossil energy reserves, resources, and occurrences in giga tons of oil equivalent (Gtoe). Consumption- Reserves Resources 1850-1990 1990 Resource Additional base occurrences Oil Conventional Unconventional Natural gas Conventional Unconventional Hydrates Coal Total 90 41 125 256 3.2 1.7 2.2 7.1 150 193 141 192 606 1,282 145 332 279 258 2,794 3,808 295 525 420 450 3,400 5,090 1,900 400 18,700 3,000 24,000 Source: Reference [34], Fig. 7.3. Natural gas production and reserve/production ratio by Canada. Source of data [35, 1], The USA is experiencing a similar trend. Unconventional gas accounted for 43% of total U.S. natural gas production in 2006. As shown in Fig. 7.4, about 43% of the total natural gas reserve in the USA is from the unconventional sources. The main sources of unconventional gases in the USA are tight gas sands, coal bed methane and gas shale. Both the National Petroleum Council and US Geological Survey made estimates of these resources. As shown in Table 7.7, there is a significant difference between these two estimates. The difference in the esti- Licensed to Jiri Martinec 7.3 Unconventional Sources 295 mates is from the uncertainty and accuracy of the measurement and the models used in the estimation. As shown in Fig. 7.5, currently natural gas from the tight gas sands is the most widely used among these three unconventional resources. 20 Total Onshore Federal Associated Uncoiweiitioii.il Domestic Conventional Offshore Gas Gas Production & Alaska (GOM) (Onshore) Fig. 7.4. US natural gas serve from unconventional sources [36], Table 7.7. Comparison of unconventional gas resource estimates in US lower 48 states in trillion cubic feet (Tcf). Advanced resources (2006)* National Petroleum Council US Geological Survey(2006) Proved reserves Undeveloped resources (2003)** Tight gas sands 73 379 131 177 Coalbed methane 20 73 46 67 Gas shales 12 128 29 60 TOTAL 105 206 304 *With data through 2005; **For accessible undeveloped resources, current technology, with data through 1998; *** Estimates for undeveloped continuous resources with data from 1995-2006. Source: Reference [37], Licensed to Jiri Martinec 296 7 Natural Gas Tiyht Gas Sauds Coalheri Methane Gas Shales Fig. 7.5. US natural gas production from unconventional sources [36], 7.3.1 Deep Natural Gas Natural gas that exists at a depth of greater than 15,000 ft is generally called Deep Natural Gas [38-44]. In 2000, the U.S. Geological Survey conducted a study to access undiscovered conventional gas and oil resources in eight regions of the world outside the U.S. The potential reserves that may be available within the next thirty years were studied. This study estimated worldwide natural gas volumes and its distribution at depth >4:5 km (15,000 ft). Two hundred forty-six assessment units in 128 priority geologic provinces, 96 countries, and two jointly held areas were assessed using a probabilistic total petroleum system approach. The distribution of the deep natural gas resources in the USA is given in Table 7.8. Worldwide estimates of deep gas of undiscovered conventional gas resource outside the U.S. are about 844 trillion cubic feet below 4.5 km (about 15,000 ft). (The U.S. Geological Survey World Petroleum Assessment 2000 Project) and are given in Table 7.9. Licensed to Jiri Martinec 7.3 Unconventional Sources 297 Table 7.8. Estimates of undiscovered natural gas by region for depths of 15,000 ft or greater from the 1995 U.S Geological Survey (USGS) National Petroleum Assessment. Data are mean estimates [45], Region Conventional Continuous-type Total gas gas resources gas resources resources (Bcf) (Bcf) (Bcf) Alaska 17,936 0 17,936 Pacific 550 2,636 3,186 Rocky Mountains 1,946 55,212 57,158 Colorado Plateau 130 570 700 West Texas- 4,705 0 4,705 Eastern New Mexico Gulf Coast 27,439 0 27,439 Midcontinent 2,264 0 2,264 Eastern 294 0 294 Total 55,264 58,418 113,682 Data includes associated gas from oil accumulations and non associated gas. Onshore regions and state waters only. Unconventional gas includes gas in low-permeability (tight) sandstones. Resource estimates based on current technology case only. Estimates do not include undiscovered gas from small fields (less than 6 Bcf). Refer to Gautier and others (1996) for detailed explanation of assessment. As can be noted from Table 7.9, the former Soviet Union has the most deep natural gas, followed by Europe. The advancement of technologies for deep drilling, exploration, and extraction is making these sources economical. 7.3.2 Tight Natural Gas When natural gas is trapped in a very tight formation underground, it is called tight natural gas [47-55]. The basin is unusually impermeable, and includes hard rock or sandstone or limestone formations and non-porous (generally called tight sand). Although a formal definition for "Tight Gas" reservoirs has not been developed, some researchers tried to characterize a tight gas reservoir based on the permeability of gas. Law and Curtis (2002) defined low-permeability (tight) reservoirs as having permeability less than 0.1 milliDarcies (mD). According to the German Society for Petroleum and Coal Science and Technology (DGMK), tight gas reservoirs are those reservoirs with an average effective gas permeability of less than 0.6 mD. Some 'ultra tight' gas reservoirs may have in-situ permeability as low as 0.001 mD. Licensed to Jiri Martinec Table 7.9. Summary data by region for estimated deep undiscovered conventional gas resources in the world from US Geological survey. Region Deep AUs/ Total gas (Tcf Total gas provinces (gas > 4.5 (Tcf) (all km/gas > 7.5 depths) _km)_ Average Average Dominant province(s) percent maximum depth of deep gas (ft) Significant regional example: AU, province, mean undisc. conv. resource, primary reservoir(s)_ Former Soviet 37/12 Union - Region 1 Mideast-North 24/11 Africa - Region 2 Asia Pacific Region 3 20/12 Europe - Region 4 18/8 N. America Region 5 (excluding USA) US portion -Region 5 12/4 101/43 343/0.5 131/0 38/0.1 142/0.7 22/0 1,611 1 370 379 312 155 55/not calculated for US 259 21 5,857 North, Middle, and South Caspian Basin provinces 10 5391 Red Sea Basin, Zagros Fold Belt, Sirte Basin, Rub Al Khali Basin 10 5915 Kutei Basin, Sichuan Basin. Tarim Basin 46 6500 North Sea Graben, Pannonian Basin. Carpathian-Balkanian Basin, Vestford-Helgeland Basin 14 5667 Villahermosa Uplift Alberta Basin 21 5898 Gulf Coast, Rocky Mts.; Northern Alaska Central Offshore, South Caspian Basin, 71 Tcf, Tertiary shelf turbidites and Jurassic reef carbonates Paleozoic Reservoirs, Rub Al Khali Basin, 47 Tcf, Permian sandstones Tarim Basin Excluding; Marginal Foldbelts; Tarim Basin, 23 Tcf; Ordovician carbonates Mid-Norway Continental Margin, Vestford-Helgeland, 70 Tcf. mixed elastics-carbonates Tamabra-Like Debris-Flow Breccia Limestone Overlying Evaporites, Villahermosa Uplift. 6.9 Tcf, Cretaceous through Tertiary carbonate reservoirs Eastern Thrust Belt, Northern Alaska, 9 Tcf, Mississippian through Early Cretaceous carbonate and clastic reservoirs Region Deep AUs/ provinces Total gas (Tcf) (gas > 4.5 km/gas > 7.5 km) Total gas (Tcf) (all depths) Average percent Average maximum depth of deep gas (ft) Dominant province(s) Significant regional example: AU, province, mean undisc. conv. resource, primary reservoir(s) Central and S. America-Region 6 42/22 88/11 487 18 6425 Eastern Venezuela Basin. Campos Basin, Middle Magdalena, Santa Cruz-Tarija Basin Sub-Andean Fold and Thrust Belt, Santa Cruz-Tarija Basin, 10 Tcf, Silurian through Tertiary clastic reservoirs Sub-Saharan Africa -Region 7 10/5 14/0 235 6 5200 West Central-Coastal Niger Delta Akata Reservoirs, Niger Delta, 8.6 Tcf, Tertiary turbidite reservoirs South Asia -Region 8 10/7 11/0.1 120 9 6100 Ganges-Brahmaputra Delta, Indus, Bombay Central Basin, Ganges-Brahmaputra Delta, 5.3 Tcf, Tertiary turbidite sandstone reservoirs Total 274/124 844/12.4 4928 17 5941 Source: Reference [46], 300 7 Natural Gas Worldwide, tight gas sand resources are speculated to be significant, but no systematic evaluation has been carried out on a global scale. According to an estimate by Holditch [56], worldwide reserve of tight gas may be about 7,406 Tcf (Table 7.10). Table 7.10. Distribution of worldwide unconventional gas reserves (in Tcf). Region Coalbed methane Shale gas Tight sand gas Total North America 3,017 3,842 1,371 8,228 Latin America 39 2,117 1,293 3,448 Western Europe 157 510 353 1,019 Central and Eastern 118 39 78 235 Europe Former Soviet Union 3,957 627 901 5,485 Middle East and 0 2,548 823 3,370 North Africa Sub-Saharan Africa 39 274 784 1,097 Pacific (Organization 470 2,313 705 3,487 for Economic Coop- eration and Develop- ment) Other Asia Pacific 0 314 549 862 South Asia 39 0 196 235 WORLD 9,051 16,112 7,046 32,560 Source: References [56, 57], The Energy Information Administration (EIA) estimated that as of January 1, 2000, 253.83 Tcf of technically recoverable deep natural gas exists in the U.S. This is a significant increase from 1998 estimate which was 37.27 Tcf (Table 7.11). This reserve of tight gas represents over 21% of the total recoverable natural gas in the USA. However, The USDOE, USGS, and other organizations have completed resource assessments of U.S. basins with tight gas accumulations indicating that a vast amount (-6,000 Tcf) of natural gas resources exists. Figure 7.6 shows the tight gas basin location in the USA. Licensed to Jiri Martinec Fig. 7.6. Locations of tight gas basins in the USA [72], O 302 7 Natural Gas Table 7.11. Tight gas reserve in various basins in the USA. Tight gas basin Reserve, billion ft3 Tight gas basin Reserve, billion (as of 1998) ft3 (as of 1998) Arkla Basin 600 Piceance Basin 1,070 East Texas 4,500 Anadarko Basin 2,280 Texas Gulf Coast 3,600 Permian Basin 2,800 Wind River Basin 600 San Juan Basin 8,150 Green River Basin 6,000 Williston Basin 300 Denver Basin 900 Appalachian Basin 4,730 Uinta Basin 740 Total 36,270 Source: Reference [58], Also it may be noted from Fig. 7.7 that some states in the USA are already producing natural gas from these basins. Appalachian Southwest Mitlcontineirt Texas Guff Coast Rocky Mountains 2000 2001 2002 2003 2004 Year Fig. 7.7. Tight gas production in the USA. Licensed to Jiri Martinec 7.3 Unconventional Sources 303 7.3.3 Gas Containing Shales Shale formations acts both as a source of natural gas and as its reservoir [60, 61]. Natural gas is stored in shale in three forms: free gas in rock pores, free gas in natural fractures, and adsorbed gas on organic matter and mineral surfaces. The process and cost of gas production depend on the shale formation. Recently, advanced drilling, completion, stimulation, and operating technologies have greatly improved the productivity and development economics of gas shale resources. Worldwide estimate of natural gas resources in shales is given in Table 7.12. Table 7.12. Worldwide estimate of shale gas reserve. Region Gas resource in fractured shales (Tcf) NAM-North America 3,842 LAM-Latin America 2,117 WEU-Western Europe 510 EEU- Eastern Europe 39 FSU-Former Soviet Union 627 MEA-Middle East Africa 2,548 AFR-Africa 274 CPA- Central Pacific 3,528 PAO- Asia and China 2,313 PAS- Other Asia Pacific 314 WORLD 16,112 Source: Reference [57], Most of the natural gas containing Devonian shale in the U.S. is located around the Appalachian Basin. However, other basins including Michigan basin, Illinois basin, Fort Worth basin, and San Juan Basin are commercially used for shale gas production in the USA .The EIA estimates that there is 55.42 Tcf of technically recoverable shale gas in the USA, representing about 5% of total recoverable resources. The regions in the USA where these basins are located and used for commercial production are shown in Fig. 7.8. 7.3.4 Coal Bed Methane Many coal seams also contain natural gas, either within the seam itself or in surrounding rocks [62-105]. It is assumed that during the coalification process, as plant materials are progressively converted to coal, large quantities of methane-rich gas is also generated which are stored within the coal. Because of its large internal surface area, coal can store six to seven times more gas than the equivalent rock volume of a conventional gas reservoir. Licensed to Jiri Martinec Fig. 7.8. Location of shale gas basins in the USA [72], 7.3 Unconventional Sources 305 The amount of natural gas present in coal increases with coal rank, with depth of the coalbed, and with reservoir pressure. The fractures and pores in coal are generally filled with water. Although the deeper the coalbed, the less water is present, the water becomes more saline. This methane is usually released when coal mining starts. Various phases of coalbed methane production are shown in Fig. 7.9. This methane can be extracted and injected into natural gas pipelines. With the current technology, this methane can be captured or produced economically. However, there are significant environmental challenges, including loss of methane to the atmosphere during underground mining, and disposal of large quantities of water, sometimes saline, that are unavoidably produced with the gas. The coalbed methane is produced by reducing the pressure of the well, and this is generally accomplished by removing water from the coalbed. Figure 7.10 shows general construction of a well for coalbed methane production. Preliminary worldwide coalbed methane resources are estimated to be in between 5,800 and 24,215 Tcf The largest potential resources, which also have the largest degree of uncertainty, are in the Former Soviet Union. Estimated resources worldwide are shown earlier in Table 7.10. The rate of coalbed methane resource development within individual countries will be highly variable due to local economic factors and government energy priorities and policies. The reserve and production of coal bed methane in the USA are given in Table 7.13. Licensed to Jiri Martinec 306 7 Natural Gas Fig. 7.10. Coalbed methane production [106], Table 7.13. Coalbed methane reserve in the USA. Year Reserve Production 2000 15,708 1,379 2001 17,531 1,562 2002 18,491 1,614 2003 18,743 1,600 2004 18,390 1,720 2005 19,892 1,732 Source: Reference [107], 7.3.5 Geopressurized Natural Gas Of all the unconventional sources of natural gas, geopressurized zones are estimated to hold the greatest amount of gas [108-122]. Most of the geopressurized natural gas in the USA is located in the Gulf Coast region. The amount technically recoverable is under dispute, however, it is estimated to be around 1,110 Tcf Licensed to Jiri Martinec 7.3 Unconventional Sources 307 Geopressured reservoirs or aquifers are deep underground reservoirs containing brine. The brine is usually saturated with methane. The methane content could be in the range of 30-80 ft3 per barrel of reservoir fluid. 7.3.6 Methane Hydrates Methane hydrates were first discovered in permafrost regions of the Arctic (Fig. 7.11). Methane hydrates (or clathrate hydrates) are ice-like crystalline molecule formed from mixtures of water and methane gas molecules and provide the greatest reservoir for organic carbon on earth (Fig. 7.12). The water (host) molecules, upon hydrogen bonding, form lattice structures with several interstitial cavities. The guest (methane) gas molecules then occupy the lattice cavities, and when a minimum number of cavities are filled, the crystalline structure becomes stable and solid gas hydrates are formed, even at temperatures well above the melting point of water ice. When gas hydrates dissociate (melt), the crystalline lattice breaks down into liquid water (or converts to ice if conditions are below the freezing point of water) and the gas is released [123-126], Although an factors controlling the type, distribution, and amount of natural hydrate accumulations are poorly understood, geologic environment is known to piny a significant role. In particular, gas hydrate formation is influenced by ^ the porosity, permeability and / degree of Mhification of the / enclosing medium. Arctic/Permafrost deposit Frozen surface ground Solid methane hydrate ice forms in bands and lenses dose to the surface deposit Trapped methane gas under pressure Depths greater Own 1.500 ...f siowsoopago 1001 of mothane ' gas from below. Sediment perhaps 4 miles doop Slow seepage of methane gas from below The hydrate stability zone [region ranges vertically between 1.000-2.000 feet, and can cover large horizontal areas. Fig. 7.11. Types of gas hydrate deposits. (Adapted from [127]). Licensed to Jiri Martinec 308 7 Natural Gas Fig. 7.12. Organic carbon reserve on earth excluding carbon in sediments and rocks. (Printed with permission from [125]). The two common forms of gas hydrates are known as structures-I and II, which have been investigated by x-ray diffraction methods by von Stackelberg and Müller [126]. These structures are shown in Fig. 7.13. Fig. 7.13. Various types of methane gas hydrates. (Printed with permission from [126]). Licensed to Jiri Martinec 7.3 Unconventional Sources 309 Methane forms a structure I hydrate with two dodecahedral (20 vertices thus 20 water molecules) and six tetrakaidecahedral (24 water molecules) water cages per unit cell. The hydratation value of 20 can be determined experimentally by MAS NMR[128]. The formation of methane hydrates depends on a host of parameters; presence of free water, temperature, and pressure [129-138]. A phase diagram depicting where methane hydrates may form in the ocean floor is shown in Fig. 7.14. CM Methane gas + Water-ice ID Methane h + Water-ice a v O CM —I L T e mpe ratu re/depth range for Hecate Strait Methane gas + Water 3 \ X ■5-CD -20 -10 10 20 30 Water/sediment Temperature (°C) Fig. 7.14. Methane hydrate phase diagram. (Printed with permission [138]). Licensed to Jiri Martinec 310 7 Natural Gas Estimates of methane hydrate reserve worldwide range anywhere from 7,000 Tcf to over 73,000 Tcf [139-157]. The oceanic deposit is estimated to be 30,000-49,100,000 Tcf, where as in Continental it is estimated to be in the range 5,000-12,000,000 Tcf. It may be noted that the conventional reserve of methane is about 13,000 Tcf. However, The worldwide estimate of methane hydrate reserves is extremely variable. As shown in Table 7.14, the estimate varied from 0.16 to 30,530 Tcf. Table 7.14. Revised inventory of global estimates of methane in submarine gas hydrate (x 1013). Best or average value References 3053 Trofimuk et al. (1973) 1573 Cherskiy and Tsarev (1977) ~ 1550 Nesterov and Salmanov (1981) 1135 Trofimuk et al. (1975) -120 Trofimuk et al. (1979) -45.4 Harvey and Huang (1995) 40 Kvenvolden and Claypool (1988) 26.4 Gornitz and Fung (1994) 20 MacDonald (1990), Kvenvolden (1988) 15 Makogon (1981), Trofimuk et al. (1981, 1983a, b), Makogon (1997) 6.8 Holbrook et al. (1996) 4 Milkov et al. (2003) 3.1 Mclver(1981) 2.5 Milkov (2004) >0.2 Soloviev (2002) >0.016 Trofimuk et al. (1977) [184] Adapted from [178], The production of methane from hydrates is challenging and new technologies and production methods need to be developed. USGS scientists believe that we will most likely not see significant worldwide gas production from hydrates for the next 30-50 years. Gas recovery from hydrates is hindered because they occur as a solid in nature and are commonly widely dispersed in hostile Arctic and deep marine environments. However, they also noted that some countries may invest and expedite the production process due to their own need within the next 5-10 years. The detailed estimate of actual reserve has been conducted by few countries so far and is given in Table 7.15. Licensed to Jiri Martinec 7.4 Composition of Natural Gas 311 Table 7.15. National and regional estimates of the amount of gas within hydrates in cubic feet. Country Amount of gas in hydrates Reference USA 317,700 x 1012 Collett(1995) Blake Ridge. 635 x 1012 Dillion etal. (1993) USA 2,471 x 1012 Dickens etal. (1997)* North Slope, Alaska 2,824 x 1012 Holbrook al. (1996)* 2,012 x 1012 Collett (2000)* 1,313 x 1012 Collett (2000) 590 x 1012 Collett (2000) India 4,307 x 1012 ONGC (1997) Andaman Sea 4,307 x 1012 ONGC (1997) Nankai Trough, Japan 1,765 x 1012 MITI/JNOC (1998) Includes associated gas [187], 7.4 Composition of Natural Gas Natural gas mainly consists of methane (CH4). However, a number of higher hydrocarbons such as ethane, propane, butane, pentane, and hexane along with inert gases including nitrogen and carbon dioxide can be present in the gas stream. A typical composition of natural gas is shown in Table 7.16. The composition can vary, although not significantly, based on its source and supplier. Natural gas may also contain hydrogen sulfide (H2S) in varying amount and is called "Sour Natural Gas" if the hydrogen sulfide content is greater than 5.7 mg/m3 at standard pressure and temperature. The sour natural gas needs to be processed further (this is also called sweetening the gas) before the gas can be utilized. Various processes are available for sweetening the gas and are discussed later in this chapter. Table 7.16. Typical composition of natural gas. Component Typical analysis (mol%) Range (mol%) Methane 94.9 87.0-96.0 Ethane 2.5 1.8-5.1 Propane 0.2 0.1-1.5 iso-Butane 0.03 0.01-0.3 Normal-butane 0.03 0.01-0.3 iso-Pentane 0.01 Trace-0.14 Normal-pentane 0.01 Trace-0.04 Hexanes plus 0.01 Trace-0.06 Nitrogen 1.6 1.3-5.6 Carbon dioxide 0.7 0.1-1.0 (Continued) Licensed to Jiri Martinec 312 7 Natural Gas Table 7.16. (Continued) Component Typical analysis (mol%) Range (mol%) Oxygen 0.02 0.01-0.1 Hydrogen Trace Trace - 0.02 Hydrogen sulfide Trace 0-5% Nitrogen Trace 0-5% Rare gases, Ar, He, Ne, Xe Trace Specific gravity 0.585 0.57-0.62 Gross heating value (MJ/m3). 37.8 36.0^0.2 dry basis* *The gross heating value is the total heat obtained by complete combustion at constant pressure of a unit volume of gas in air, including the heat released by condensing the water vapour in the combustion products (gas, air, and combustion products taken at standard temperature and pressure). In the Union Gas system, the typical sulfur content is 5.5 mg/m3. This includes the 4.9 mg/m3 of sulfur in the odorant (mercaptan) added to gas for safety reasons. The water vapor content of natural gas in the Union Gas system is less than 80 mg/m3, and is typically 16-32 mg/m3. Source: Union Gas Limited, Ontario, Canada. 7.5 Combustion Properties of Natural Gas The typical combustion properties of natural gas are shown in Table 7.17. The properties shown are an overall average of the Union Gas system. These values can vary from supplier to supplier. Table 7.17. Typical combustion properties of natural gas. Properties Values Ignition point 593°C* Flammability limits 4-16% volume percent in air Theoretical flame temperature 1,960°C (stoichiometric air/fuel ratio) Maximum flame velocity 0.3 m/s Relative density (specific gravity) 0.585 Wobbe index 1,328 7.6 Natural Gas Production The natural gas that is delivered into our homes begins with the exploration of the earth's surface to locate a reservoir for the natural gas. Once a reservoir is Licensed to Jiri Martinec 7.6 Natural Gas Production 313 discovered, it goes through a number of processes before it is delivered to homes or customers. These processes may be divided into the following categories: • Exploration • Extraction • Processing • Transportation • Storage • Distribution • Marketing 7.6.1 Exploration The search for petroleum or natural gas starts with the geologists, who use surveying and mapping to understand the surface and sub-surface characteristics, to determine which areas are most likely to contain a petroleum or natural gas reservoir [186-192]. Geologists use many tools including the outcroppings of rocks on the surface or in valleys and gorges. Geologic information obtained from the rock cuttings and samples obtained from the digging of irrigation ditches, water wells, and other oil and gas wells are used to determine areas for further exploration. Geophysicists mainly use three methods for oil and gas exploration: magnetic, gravity, and seismic exploration. The magnetometer and gravity meter are used to locate hidden, subsurface petroleum traps [194]. In seismic exploration, sound is transmitted into the ground by an explosive, such as dynamite, or by a thumper truck. Currently, seismology is the main tool used by geologists to explore an area for petroleum or natural gas [195-204]. Both on-shore and off-shore seismology techniques are available to geologists. Following exploration by these methods, exploratory wells and loggings are done to gain a better understanding of not only of the geology, but also of the total reserve. 7.6.1.1 Magnetometers In magnetic exploration a magnetometer is used to determine the strength of the earth's magnetic field at a specific point on the earth's surface. Magnetic properties vary based on the composition of the earth's layer. Underground formations can be measured using Magnetometers to generate geological and geophysical data. Magnetometers can measure the small differences in the Earth's magnetic field, which can be determined with an aerial pass of a magnetometer or on the ground using a type of magnetometer called a vertical field balance. From these readings, experts determine if there is oil or gas, because there exists a correlation between low magnetic readings and rocks that contain oil. Licensed to Jiri Martinec 314 7 Natural Gas 7.6.1.2 Gravimeters Using gravimeters, geophysicists measure and record the difference in the Earth's gravitational field at various underground locations. Minute differences in gravitational field exist due to the different underground formations and rock types. This information can help the geophysicists to determine the existence of potential reservoir for petroleum or natural gas. Gravitational methods can also be done aerially with a gravimeter or on the ground using a more precise instrument called a gravity gradiometer. The data from gravitational methods is valuable because differences in the gravitational field indicate a difference in the density of the ground which correlates to rocks that contain oil. Both of these methods are relatively low impact system because they only involve either not touching the ground at all, or by setting up stations approximately 100 yards apart using low-impact transportation. Thus the impact of non-seismic techniques is significantly lower than the impact that would be caused by drilling unnecessary wells. 7.6.1.3 Exploratory Wells Once the survey by various instruments discussed above convince geologists that there are enough indication of a high probability of petroleum formation, exploratory wells are drilled. The presence of suspected oil and gas deposits is generally confirmed by the exploratory (These wells are called wildcat wells) drilling of deep holes. The drill cuttings and fluids are analyzed by geologists to gain a better understanding of the geologic features of the area. Drilling an exploratory well is expensive and also time consuming, since wildcat wells are deeper and drilled in areas having no prior history of oil or gas deposits. Construction of access roads and drill pads are typically required to conduct these exploratory drilling operations increasing the cost of operation. A typical drilling rig is shown in Fig. 7.15. 7.6.2 Logging Samples collected from the exploratory wells go through a series of tests, generally referred to as "Logging" to allow geologists and drill operators to monitor the progress of the well drilling and to gain a better picture of subsurface formations [205-209]. The quantitative analysis of well logs can provide the following information: - Porosity - Water saturation, fluid type (oil/gas/water) - Lithology Licensed to Jiri Martinec 7.6 Natural Gas Production 315 - Permeability - Hydrocarbons-in-place - Reserves (the recoverable fraction of hydrocarbons in-place) - Mapping of reservoir Fig. 7.15. Rotary drilling rig arrangements. Source: Reference [205]. A typical logging system is shown in Fig. 7.16. There are over 100 different logging tests that can be used to monitor the drilling process and to make decision if the drilling should be continued. The most common types of logs are: • Standard log • Resistivity log • Spontaneous potential log • Gamma ray log • Neutron log • Density log • Sonic (acoustic) log Licensed to Jiri Martinec 316 7 Natural Gas Drilling Derrick Casing shoe Traveling block Winch drum and motor Surface electronics Down Hole Logging Tool or Sonde Fig. 7.16. A typical logging system with main components. (Source: Reference [210]). Standard Log Standard logging consists of examining and recording the physical properties of the drill cuttings (rock that is displaced by the drilling of the well) and core samples taken from the underground soil. These cuttings and cores are often examined using microscopes with a magnification greater than 2,000 times. Resistivity Log This log measures the bulk resistivity of the formation to determine the types of fluids present in the reservoir rocks. Resistivity is a function of porosity and pore fluid in a rock. A non-porous rock or hydrocarbon containing formation has high resistivity. By contrast, if the rock formation is porous and contain saline water, the resistivity will be low. This log is therefore used as an indicator of formation lithology. There are many different types of resistivity logs, which differ mainly in the depth to which the measurements are made. These logs are listed below. Licensed to Jiri Martinec 7.6 Natural Gas Production 317 AIT (Array Induction Tool): It measures five depths of investigation. DIL (Dual Induction Log): This log is used for deep and medium depths of investigation. DLL (Dual Latere Log): This log is used for deep and medium depths of investigation. SFL (Spherically Focused Log): This log is used for a shallow depth of investigation. SGR (Shallow Guard Log): This log is used for a shallow depth of investigation. Spontaneous Potential (SP) Log This log provides data on permeability of the rock. The electrical current that occurs naturally between the boreholes drilling fluid and the formation water that is held in pores of the reservoir rock is measured. Porous sandstones have high permeability compared to impermeable shale and thus can distinguish them. The SP log can also be used for locating bed boundaries. Gamma Ray Log Rocks contain various naturally occurring radioactive materials that emit gamma rays at various energy levels depending on the type of isotopes present in the rock. In this log the radioactivity of a formation is measured using a gamma detector. Gamma ray logs are one of the most commonly used logs for sequence strati-graphic analysis. Shale commonly have high radioactivity compared to sandstones. Also coarse grain sand, which contains little mud, is less radioactive compared to fine sand that contain significant amount of mud. The gamma ray activity is measured in an API unit, a unit of counting rate for the gamma-ray log. The difference between the high and low radioactivity sections in the API calibration pit is defined as 200 API units. One API unit is defined as the 1/200th of the difference in radioactivity from the gamma ray between zones of high and low radioactivity in the API Gamma Ray calibration pit in Houston, Texas, USA. In shale, radioactivity can be about 200 API units. Neutron Log This is also known as compensated neutron log (CNL). A neutron source, typically a californium-252 spontaneous fission source, is placed in the bore hole and a gamma detector picks up the radiation from scattering or capture reactions. The porosity of a formation is measured by using this log. The amount of hydrogen atoms present in the reservoir pores that are filled with either water or hydrocarbon (oil) is measured. The log is calibrated to limestone. The linear limestone porosity units are calibrated using the API Neutron pit in 19% porosity. The water filled limestone is defined as 1000 API units. Along with the density log, the lithology of the formation is determined using the neutron log data. Licensed to Jiri Martinec 318 7 Natural Gas Density Log The density log measures the density of the formation rocks for determination of porosity. Different lithologies can also be determined using density log as the density of rocks differs based on its contents, such as 1.2-1.8 g/cm3 for coal, 2.65 g/cm3 for pure quartz, and up to 2.75 g/cm3 for limestone. The density logs generally overestimate the porosity of rocks that contain gas and result in "crossover" of the log curves when paired with neutron logs. Sonic (Acoustic) Log This log measures the speed of sound in the formation, which can be correlated to both porosity and lithology of the formation. Sound waves travel faster through high-density shale than through lower-density sandstones. Sonic log value for sandstone is in the range of 51-56 us/ft. NMR (Nuclear Magnetic Resonance) Log This log measures the magnetic response of fluids present in the pore spaces of the reservoir rocks. Both porosity and permeability are determined from the data. The measurements are largely based on the fluid and the pore space characteristics. A better understanding of the fluids and pores is possible compared to other conventional logs like density, neutron, and sonic. Dipmeter Logs This log determines the orientations of sandstone and shale beds in the well. The direction and angle of formation dip in relation to the borehole is obtained. The data provides the geologic structure of the formation. The dipmeters can provide a detailed image of the rocks on all sides of the well hole. Caliper Logging Caliper logging provides a continuous recording of borehole diameter versus depth. These logs are generally run in uncased wells, but can be also used within casing. Caliper logs are also used to locate caved zones, casing, and the absence of casing; and permit the recognition of mud cake, (i.e., permeable zones). A number of different logs have been used in the oil and gas industry. These logs are presented in Table 7.18. Licensed to Jiri Martinec 7.6 Natural Gas Production 319 Table 7.18. Different types of logs and their purposes. Log type Log General code name for log order Electric log EL Electric log Induction log IL Electric log Micro log ML Micro log Gamma ray GR Gamma- log ray log Neutron log NTR Neutron porosity log Density log DL Density porosity log Density- DNL Density neutron log porosity log Sonic log SL Sonic porosity log Magnetic MRL Magnetic resonance log resonance porosity log Computed log CUL EPT log EPT Dipmeter log DIP Dipmeter log Gamma ray SPC Spectral log Caliper log CAL Fracture ID FID log Borehole BIL Definition imaging log Open hole log with an SP curve and typically a non-induced resistivity curve SP log with one or more induced resistivity curves (including focused and laterologs) Micro-resistivity log Log which only records natural radioactivity (logs with other curves are a different log type) Records hydrogen concentration in the formation; usually has a gamma ray curve; does not include density-neutron logs Records electron density in the formation; usually has a gamma ray curve; does not include density-neutron logs Porosity log with at least one density curve and at least one neutron curve Porosity log based on transit time of sound waves through the formation Porosity log based on measuring the signal generated by polarized hydrogen protons Any log that attempts to characterize the formation by computer analyses of multiple other logs that have been run in the well Measures propagation and attenuation of electromagnetic waves through a formation Records the attitude (dip angle and dip direction) of rock layers in the borehole Uses gamma ray energy spectrum to record potassium, uranium, and thorium in the formation Measures width of the borehole A special presentation of dipmeter micro resistivity measurements that identifies fractures High-resolution imaging of borehole circumference using closely spaced log measurements, typically of micro resistivity or sonic transit time (Continued) Licensed to Jiri Martinec 320 7 Natural Gas Table 7.18. (Continued) Log type Log code General name for log order Definition Production PRL Production Any of various logs used in completing a log log well for production RFT (repeat RFT Records formation pressure data (and ob- formation tains a small rock sample) of the formation test) log Temperature TMP Records temperature of drilling mud in the log borehole TVD log TVD TVD log Records position and attitude of borehole in deviated wells Source: Reference [211]. 7.6.3 Extraction In the extraction phase, the following issues are taken into account. • Economic considerations • Permitting, leasing, and royalties • Technology based on onshore or offshore drilling If the site and size of the basin is found large enough to be economically feasible, permitting, leasing, and royalty issues are finalized. Finally a decision is made regarding the drilling technology. There are two main types of onshore drilling: Percussion, or 'cable tool' drilling and rotary drilling. Cable tool drilling consists of raising and dropping a heavy metal bit into the ground that punches a hole down through the Earth. Cable tool drilling is usually used for shallow, low pressure formations. In rotary drilling, a sharp rotating metal bit is used to drill through the Earth's crust. This type of drilling is used primarily for deeper wells that may be under high downhole pressure. 7.6.3.1 Well Completion Before natural gas or oil is extracted from underground, the well must be completed for commercial production. The steps involved for completion of a production well are as follows: • Well casing • Completion • Wellhead • Lifting and well treatment Licensed to Jiri Martinec 7.6 Natural Gas Production 321 A series of metal tubes are installed in the freshly drilled hole to strengthen the sides of the well hole, ensuring that no oil or natural gas seeps out of the well hole as it is brought to the surface, and to keep other fluids or gases from seeping into the formation through the well. This process is called the well casing and there are five different types of well casing. They are installed in the following order: • Conductor casing • Surface casing • Intermediate casing • Liner string • Production casing Conductor casing is installed first to prevent the top of the well from caving in and to circulate the drilling fluid up from the bottom of the well. They are generally 20-50 ft long. The surface casing is installed next and fits inside the top of the conductor casing. It can be more than 2,000 ft long, and is smaller in diameter than the conductor casing. Both the conductor and surface casings are cemented into place. The primary objective of surface casing is to prevent fresh water contamination from the drilling activities. The surface casing serves as a conduit for drilling mud returning to the surface, and helps protect the drill hole from being damaged during drilling. Intermediate casing is used to protect the well from various unexpected activities from underground such as pressure change, and saltwater deposit. The intermediate casing may also be cemented into place for added protection. Liner strings are sometimes used instead of intermediate casing and generally are not cemented. Production casing, also known as oil string or long string is installed last. It extends from the surface of the well to the petroleum producing formation. The diameter of the production casing depends on the lifting equipment to be used, the number of completions required, and the possibility of deepening the well at a later time. 7.6.3.2 Completion There are six types of completion as listed below. The types of completion to be used in any formation depend on the characteristics of the formation and the targeted products. • Open hole completion • Conventional perforated completion • Sand exclusion completion • Permanent completion • Multiple zone completion • Drainhole completion Open hole completion is the most basic type of completion in which the casing is placed directly in the formation. The end of the casing is open to the formation Licensed to Jiri Martinec 322 7 Natural Gas and no protective filter is installed. The formations that are acid fractured generally use this type of completion. In conventional perforated completion, the side of the casing is perforated to allow for the flow of hydrocarbons into the well hole. The perforation is carried out in situ using a jet perforating technique. This involves small, electrically ignited charges, lowered into the well. When ignited, these charges penetrate through the casing, cementing, and any other barrier between the formation and the open well forming tiny holes. If the formation contains large amount of loose sand, sand exclusion completion is used. A screen is used to prevent flow of sand inside the casing. Sand inside the well hole can cause many complications, including erosion of casing and other equipment. Permanent completion involves permanent installation of the casing, cementing, perforating, and other completion work. This is done only once and can reduce the cost significantly. In this method there is no room for error. Multiple zone completion is generally used for oil well and if more than two formations are present in close vicinity. This type of completion is preferred if all the formations will be used for production. Oil can be extracted from the formations simultaneously without mixing them, thus reducing the production cost significantly. One of the main challenges is to keep various formations separated. Drainhole completions are commonly associated with oil wells than with natural gas wells. A horizontal well is drilled from the vertical drill allowing hydrocarbons to drain into the well. 7.6.3.3 Wellhead Natural gas in the well can be at a pressure well above 20,000 psi. The wellhead consists of various equipment mounted at the opening of the well on the surface that regulate and monitor the extraction of natural gas and oil from the underground formation. These instruments should be capable of withstanding the above pressure. The wellhead consists of three components: the casing head, the tubing head, and the 'Christmas tree'. The casing head generally supports the entire casing and also provides the sealing between casing and the surface. The tubing head provides the sealing between the tubes and also provides the mechanical support to the tubes in the well. The Christmas tree is referred to the various valves and fitting that are used in the casing head and tube head to monitor the flow of the gas or oil on the surface. 7.6.3.4 Lifting and Well Treatment Once the well is completed, the production of natural gas can proceed. Natural gas flows to the surface due to the pressure difference. Once the flow of natural gas is started, the Most Efficient Recovery (MER) rate is established. As more and more Licensed to Jiri Martinec 7.6 Natural Gas Production 323 natural gas is extracted from the formation, the production rate of the well decreases. This is known as the decline rate. At this point, lifting equipment and well stimulation may be necessary to maintain the production rate of a well. However, this is generally more common with the oil well or oil wells that have associated natural gas, than with the natural gas only well. 7.6.4 Processing The natural gas that is fed into the gas pipeline for delivery to the consumer must meet certain specifications in order for the pipeline grid to operate properly. Therefore, natural gas produced at the wellhead, which contains various contaminants and natural gas liquids, must be processed, before delivering to the high-pressure, long-distance pipelines. These specifications are given in Table 7.19. The natural gas processing subject has been discussed in great details in a number of books [211-218]. Table 7.19. Typical composition of natural gas before refining. Component Chemical formula Volume (%) Methane CH4 >85 Ethane C2H5 3-8 Propane C3H8 1-2 Butane C4H10 <1 Pentane C5H12 <1 Carbon dioxide C02 1-2 Hydrogen sulfide H2S <1 Nitrogen N2 1-5 Helium He <0.5 If the natural gas does not meet these specifications various operational problems, pipeline deterioration, or even pipeline rupture may occur. The various processing steps before delivering the natural gas into the pipeline are shown in Fig. 7.17. Some of these steps may be optional depending on the composition of the wellhead gas. The natural gas processing system may be divided into seven major sections. • Gas-oil separator • Oil and condensate removal • Dehydration • Contaminant removal • Nitrogen extraction • Separation of natural gas liquids (NGL) • Fractionation Licensed to Jiri Martinec Lease Operations Gas Reservoir Gas-Oil Separator* Oil Reservoir Condensate Separator Gas Stream 7 Oil 7 Condensate Free Water Lease or Plant Dehydrate T Water Remove Contaminants Nitrogen Extraction 7 H2S co2 etc Plant Operations Dry Gas (to Pipeline) DeMethanizer Dry (Residue) Gas (To pipeline) Fractionator Nitrogen ' Optional step, depending upon the source and type of gas stream. Natural Gas Liquids (NGLs) Ethane Propane Butane Pentanes Natural Gasoline Fig. 7.17. A typical natural gas processing plant. (Adapted from [218]). 7.6 Natural Gas Production 325 7.6.4.1 Gas-Oil Separation Pressure reduction at the wellhead is generally sufficient for separation of gas from oil using a conventional closed tank. The gas is separated from liquid hydrocarbons (oil) due to the difference in specific gravity. In some cases, however, a multi-stage gas-oil separation process is needed to separate the gas stream from the crude oil. These gas-oil separators are commonly closed cylindrical shells, horizontally mounted with inlets at one end, an outlet at the top for removal of gas, and an outlet at the bottom for removal of oil. Separation is accomplished by alternately heating and cooling by compression of the flow stream through multiple steps. Some water and condensate are also removed by this process. The design of a horizontal separator is shown in Fig. 7.18. 7.6.4.2 Oil and Condensate Removal Condensates are removed from the gas stream at the wellhead through the use of mechanical separators. The stream can be fed directly into the separator from the wellhead, if the gas-oil separation process is not needed. A Low-Temperature Separator (LTX) is most often used for wells producing high pressure gas along with light crude oil or condensate. These separators use pressure differentials to cool the wet natural gas and separate the oil and condensate. The gas stream enters the processing plant at high pressure (600 lb per in.2 gauge (psig) or greater) through an inlet slug catcher where free water is removed from the gas, after which it is directed to a condensate separator. Extracted condensate is routed to on-site storage tanks. The gas stream is rapidly expanded through a choke valve resulting in a decrease in the temperature. As gas cools, liquids present in the stream condensed out from the stream. Often, after liquid removal, the dry gas flows back through the heat exchanger and is warmed by the incoming wet gas. A schematic diagram of a low temperature separator is shown in Fig. 7.19. Vane sections remove Revolution tubes Gas outlet vortex breaker small droplets from speed up gas/liquid prevents re-entrainment the gas stream separation process of liquid phase Fig. 7.18. Horizontal dual flow separator [221], Licensed to Jiri Martinec to 1 SfiFEry I had 7^ HPKO —#---- h OPTIONAL > EXTERNAL CLASSIFIER 1 » (3-PHASE) / N-----r <* vV'/iTIR TO 1-1T I INDIRECT HEATER i i HIGH PRimiRE INLET GAS ■ IE T 3 HEAT EXCHANGER DRY OUTLET GAS -I- "AS TO SAL IS 1l.ARL 6AS I :' MM-'! FULL GA Zi LTX SEPARATOR T LJ HYDHGCAL:KC:-M v LIQUID TO 1 STORAGE WATER IÖ PIT LOW PRESSURE SEPARATOR LIM 111/4! 2 1 a Fig. 7.19. LTX hydrocarbon liquid recovery system [219]. 7.6 Natural Gas Production 327 7.6.4.3 Dehydration The dehydration process is used mainly to eliminate water vapor from the gas stream which may cause the formation of hydrates. Hydrates are solid particles that can cause a number of problems during flow through pipelines including blockage and damage to pressure boosting pumps. Under certain temperature and pressure, methane and other alkanes in the gas stream can form hydrates if free water is present in the gas stream. Two most common methods used by the natural gas industry to remove free water are: the use of ethylene glycol (glycol injection) and solid desiccant dehydration. Glycol Dehydration (Glycol Injection) [221-240] Water vapor from the natural gas stream is removed by contacting it with either diethylene glycol (DEG) or triethylene glycol (TEG) in a counter-current contractor. Lean glycol stream containing about 99% glycol is sprayed from the top of the contractor, while the gas stream is fed from the bottom. The water from the wet natural gas stream is absorbed by the glycol. The dry gas from the top of the contractor is send to the next processing unit. The diluted glycol solution (called the rich glycol stream) is fed to another contractor where water vapor is removed by heating the solution while dry air is blown through the contractor to generate the glycol solution to its original concentration. The regenerated glycol solution is recycled back to the first contractor. The schematic diagram of a glycol dehydration system is shown in Fig. 7.20. One of the concerns with the glycol dehydration system is that the rich glycol stream also contains various impurities along with a small amount of methane. During regeneration of the lean glycol stream, these impurities and methane are released to the atmosphere. The addition of flash tank separator-condensers can recover 90-99% of the dissolved methane. In the flash tank separator the pressure of the glycol stream is reduced suddenly allowing dissolved low boiling point constituents (methane and other hydrocarbons) of the solution to flash or vaporize. In order to provide good contact between the gas and the liquid, the tower either has trays or packed with the inert packing. Solid Desiccant Dehydration [241-246] In this process, natural gas is passed through a tower, from top to bottom, packed with solid desiccants. Typical desiccants used in the natural gas dehydration include activated alumina, granular silica gel or molecular sieve materials. Solid-desiccant dehydrators are generally more effective than glycol dehydrators since a very low dew point of the processed gas can be obtained. These types of Licensed to Jiri Martinec high pressure contacting system low pressure regeneration system (OPTIONAL! Tß S— GAS SKIMMER (OPTIONAL) 'cas/glycol heat exchanger Ac UWIJINSATE ä&5 sock charcoal filter filter (OPTIONAL) glycol circulation pump reflux column VAPOR OU1LET <-------i !bUX control j (optional) t ________i fuel gas glycol/glycol heat exchanger 3C ^1 2 I P3 Fig. 7.20. Glycol dehydration system [219], 7.6 Natural Gas Production 329 dehydration systems are best suited for large volumes of gas under very high pressure. They can be used on a pipeline downstream of a compressor station. Generally two or more desiccant beds (towers) are required for continuous operation. After a certain period of time (i.e., after treating certain volume of the natural gas) the bed becomes exhausted. At this point the water content of the treated gas may not meet the required specification, and the gas stream is diverted to the second bed. The exhausted bed needs to be regenerated. To regenerate the desiccant bed, a heated gas, generally air is passed through the desiccant bed removing the water from the desiccant. Following regeneration, the bed is cooled and is ready for the use. A molecular sieve based system developed by UOP is shown in Fig. 7.21. 7.6.4.4 Contaminant and Acid Gas Removal Hydrogen sulfide (H2S), C02, water vapor, helium, and oxygen present in the natural gas stream must be removed prior to feeding to the pipeline. In the presence of water, C02 forms carbonic acid which is corrosive. C02 also reduces the BTU value of gas and if the concentration of C02 is more than 2-3%, the gas is unmarketable. H2S is an extremely toxic gas that is also very corrosive to equipment. Amine sweetening processes remove these contaminants so that the gas is marketable and suitable for transportation. Amine Treatment Process [248-254] Amine has a natural affinity for both C02 and H2S allowing this to be a very efficient and effective removal process. A number of amine compounds are used for sweetening of the natural gas. Sweetening of natural gas referred to removal of acid gases: H2S, and C02. Each of the amines offers distinct advantages to specific treating problems. These amines are listed below. MEA (Monoethanolamine) Mainly used in low pressure natural gas treatment applications requiring stringent outlet gas specifications. MDEA (Methyldiethanolamme) It has a higher affinity for H2S than C02 which allows some C02 "slip" while retaining H2S removal capabilities. DEA (Diethanolamine) It is used for medium to high pressure treatment facility and does not require reclaiming, as required for MEA and DGA systems. FORMULATED (SPECIALTY) SOLVENTS A variety of blended or specialty solvents are available in the market for removal for H2S and C02. Licensed to Jiri Martinec Feed Gas Molecular Sieve Regeneration Regeneration Separator Adsorbers Gas Cooler Gas Separator Spent Fig. 7.21. Desiccant based natural gas dehydration system [247], 7.6 Natural Gas Production 331 The reactions of amines with H2S and C02 are summarized below 2 RNH2 + H2S = (RNH3)2S 2 RNH2 + C02 = RNHCOONH3R where: R = mono, di, or tri-ethanol The recovered hydrogen sulfide gas stream may be: (1) vented, (2) flared in waste gas flares or modern smokeless flares, (3) incinerated, or (4) utilized for the production of elemental sulfur using the Claus process or sulfuric acid. If the recovered H2S gas stream is not to be utilized as a feedstock for commercial applications, the gas is usually passed to a tail gas incinerator in which the H2S is oxidized to S02 and is then released to the atmosphere through a stack. The gas sweetening process is illustrated in Fig. 7.22. Sour gas enters at the bottom of the contactor or absorber tower and the lean amine solution is sprayed from the top. Purified gas flows from the top of the tower. The amine solution containing the absorbed acid gases is now considered rich stream. The lean amine and rich amine flow through the heat exchanger in counter current direction, heating the rich amine. Rich amine is then further heated in the regeneration still column by steam. The steam rising through the still liberates H2S and C02, regenerating the amine. Steam and acid gases separated from the rich amine are condensed and cooled. The condensed water is separated in the reflux accumulator and returned to the still. Hot, regenerated, lean amine is cooled in a solvent aerial cooler and circulated to the contactor tower, completing the cycle. Gas Sweetening with Amines :ive Fig. 7.22. A gas sweetening process flow diagram using amines. (Adapted from Lurgi (1/9/2009) Gas sweetening with amines. www.lurgi.com/website/fileadmin/user_upload/l_PDF/2_Technolo-gie/englisch/10_Aminwaesch en-E.pdf). Licensed to Jiri Martinec 332 7 Natural Gas 7.6.4.5 Nitrogen Extraction Once hydrogen sulfide and carbon dioxide are removed to the acceptable level, the stream is fed to a Nitrogen Rejection Unit (NRU). The stream could be further dehydrated in a NRU using molecular sieve beds. The nitrogen is cryogenically separated and vented. Another type of NRU unit separates methane and heavier hydrocarbons from nitrogen using an absorbent solvent. The absorbed methane and heavier hydrocarbons are flashed off from the solvent by depressurizing the stream. The liquid from the flash regeneration step is returned to the top of the methane absorber as lean solvent. Helium, if any, can be extracted from the gas stream through membrane diffusion in a Pressure Swing Adsorption (PSA) unit. 7.6.4.6 Natural Gas Liquid Recovery The NGL can be recovered from the stream using two methods: cryogenic and absorption (non-cryogenic) methods. The absorption and cryogenic expander processes together account for around 90% of total natural gas liquids production. In the absorption process, extraction is carried out using a lean oil absorption-mechanical refrigeration system. The refrigerated absorption process enhanced the extraction efficiency. Recently, both refrigeration and pre-saturation methods have been developed for further enhancement of the efficiency. The introduction of Joule Thompson valves and turbo expanders in 1960s made significant contributions to the achievement of cryogenic conditions. The use of reflux and the heat integration allowed high NGL recoveries. 7.6.4.7 Oil Absorption Process In this method, the natural gas is contacted with a lean oil (molecular weight of about 150) in an absorber column at a temperature of about 100°F. An absorbing oil that has high affinity for NGLs is used in the absorption column. The rich oil exiting the bottom of the absorber flows into a rich oil depropanizer which separates the propane and lighter components and returns them to the gas stream. The rich oil is then fractionated in a column, where the NGL's (C4+) are recovered as an overhead product and the lean oil is recycled to the absorber column. This process allows for the recovery of around 75% of butanes, and 85 - 90% of pentanes and heavier molecules from the natural gas stream. A schematic flow diagram of the system is shown in Fig. 7.23. Extraction of NGL can be enhanced by using refrigerated low molecular weight oil. The typical temperature with propane refrigerant is about -42°C. A lean oil having molecular weight in the range of 100-110 is generally used in this process. In the refrigerated oil absorption method, total recovery can be more than 90%, Licensed to Jiri Martinec 7.6 Natural Gas Production 333 and ethane extraction can be around 40%. Extraction of the other, heavier NGLs can be close to 100% using this process. A typical flow diagram of the process is shown in Fig. 7.24. Pipeline Gas o to < Natural Gas Feed C4 and NGL Products -► CD 4-" ra s Rich Oil Depropanizer 0 Still I 0 Fig. 7.23. Recovery of NGL using oil absorption method. (Printed with permission from Mehra YR (2004) Market driven evolution of gas processing technologies for NGLs. Advanced Extraction Technologies, http://www.aet.com/gtipl.htm [255]). Fig. 7.24. A schematic diagram of a process for enhancement of NGL recovery using refrigeration process. (Printed with permission from Mehra YR (2004) Market driven evolution of gas processing technologies for NGLs. Advanced Extraction Technologies, http://www.aet.com/ gtiplhtm [255]). Licensed to Jiri Martinec 334 7 Natural Gas A number of refrigeration processes have been developed to further lower the temperature. These methods include Cascade Refrigeration Process, Joule Thompson (JT) Expansion Process, and Turbo Expansion Process. Also, several proprietary NGL extraction processes are available in the market. The extraction efficiency was enhanced using various extraction schemes such as lean column reflux and maximum heat integration. The integration between the natural gas recovery process and liquefaction process is possible while maintaining high efficiencies for both the processes. 7.6.4.8 Fractionation The recovered NGL is further separated into different fractions to increase their product value. The process is called fractionation. The process occurs in stages and in a number of columns connected in series. The liquid feed is heated and fed to a deethanizer. This step separates the ethane from the NGL stream. In the next step, propane is separated in the depropanizer. The Debutanizer is the next step of the process. This step boils off the butanes, leaving the pentanes and heavier hydrocarbons in the NGL stream. Finally, a Butane Splitter or deisobutanizer is used to separate iso- and normal- butanes. 7.6.5Natural Gas Transport Natural gas is transported and delivered to the consumer from the production facilities mainly through a complex net work of pipelines. There are essentially three major types of pipelines along the transportation route: the gathering system, the interstate pipeline, and the distribution system. The gathering system consists of low pressure, low diameter pipelines that transport raw natural gas from the wellhead to the processing plant. Pipelines can be characterized as interstate or intrastate. Interstate pipelines carry natural gas across state boundaries, in some cases across the country. Intrastate pipelines, on the other hand, transport natural gas within a particular state. Natural gas pipelines are subject to regulatory oversight, which in many ways determines the manner in which pipeline companies must operate. The USA natural gas pipeline grid includes more than 210 mainline natural gas pipeline systems. In 2005,109 were classified as interstate systems by the Federal Energy Regulatory Commission (FERC). The remaining 101 were intrastate natural gas pipeline systems, whose operations are confined to a single State. The combined natural gas pipeline capacity on mainline intrastate systems is about 33 Bcf/d. Interstate natural gas pipeline systems account for more than 148 Bcf/d of total USA natural gas transportation capacity and approximately 213,000 miles of pipeline. Furthermore, the top 30 interstate natural gas pipeline companies alone account for more than 78%, or about 115 Bcf/d of the interstate natural gas pipeline capacity [256]. The network of the pipelines in the USA is shown in Fig. 7.25. Licensed to Jiri Martinec 336 7 Natural Gas As can be seen from Fig. 7.26, the pipeline capacity remained more or less stagnant in the USA for the last several years. However, a major expansion is planned over the next several years. The increased capacity will require addition of physical pipeline to the network. The planned addition of pipeline mileage is shown in Fig. 7.27. The natural gas pipeline network runs through several regions and also the capacity depends on the demand of the particular region. Fig. 7.28 shows the capacity of natural gas pipeline in various regions. 40000 35000 30000 t I 25000 ™ 20000 -I 1 15000 10000 5000 i-1-1— Ac1ll.ll a S ■s Al ■?1 ■i - -1-r Potential Al i- -i- f\l Year Fig. 7.26. The capacity of the pipeline and expected expansion in the USA for transportation of natural gas. 50(10 4000 J000 2000 10D0 -i-1-1-1-1-r Actual -1- Potential 338 7 Natural Gas 7.6.5.1 International Transportation of Natural Gas Natural gas is becoming a major energy source through out the world. However, a majority of countries sell their known resources. As a result, the international transportation of natural gas through pipelines is becoming a major method for trading natural gas. In Europe, Russia is the major exporter of natural gas. The pipelines that exists or being planned in Europe for transportation of natural gas are shown in Fig. 7.29. Figure 7.30 shows the pipeline in various parts of Europe. Recently, Europe is planning to transport natural gas from the Fareast through Turkey. The proposed pipeline is shown in Fig. 7.31. Various international pipelines that are under construction or proposed are given in Table 7.20. Table 7.20. International pipeline under construction or proposed. Company name Project name and Length location (miles) Cost In service ($ US million) date AFRICA NNPC/Sonatrach Saipem (Shell Dev) ASIA PACIFIC Western Australian Gov Continental Gas Pipeline. Trans China National Petroleum Corp. Dampier Bunbury Pipeline Co. PT Perusahaan Gas Negara (PGN) TransSaharan Gas 2,772 $6 billion Feasibility Ppeline No. Africa-Ben Saf-Almeria, Spain Niger Delta 214 $420 2008 Trans Continental 1,827 $3 billion Feasibility Gas Pipeline Offshore Australia to Hobart Xingang Province N/A N/A Feasibility to Guangzhou, Dampier Bunbury 122 $430 2009 Pipeline expansion South to North 328 $574 2008 Samatra Kepodang-Tambak ^30 $105 Lorok Sengkang-Makassar Indonesia East Java-West, 442 2010 Java E. Kalamantan to C. 768 2010 Java Licensed to Jiri Martinec 7.6 Natural Gas Production 339 Company name Project name and Length Cost In service location (miles) ($ US million) date PT Perusahaan Gas E. Kalamantan to 434 $1.6 billion 2007-2008 Negara (PGN) Central Java Soopec Sichuan Province China 1,008 $4.7 billion 2008 Gas Authority of Dahej-Uran 310 $330 2007-2009 India Pipeline FSU-EASTERN EUROPE Botas, D.E.P.A. IGI Pipe line 504 N/A 2010 & Edison Gas Greece to Italy FSI Energy KoRus Sakhalin Pipeline Russia 1,575 $3 billion N/A Governments of Adriatic Coastto 214 N/A Feasibility Hungary/ Croatia Hungary KazMunaiGaz Kazakhstan to china 1,890 N/A 2010 Nabucco Gas Nabucco Pipeline 2142 N/A 2011 Pipeline Int'l. Ltd Turkey to Austria Starstroi (Sakhalin Sakhalin II pipeline 504 N/A 2008 Energy) MIDDLE EAST Abu Dhabi Gas Habshan-Bu Hasa 32 $35 N/A Industries Pipeline UAE Co(GASCO) National Iranian Oil Iran-Pakistan- India 1,735 $4 billion 2010 Co Pipeline AMEC SPIE Capag Yemen Gas Pipeline 202 $200 2008 Qatar/ Pakistan* Gulf South Asia Pipeline Qatar to Pakistan 1,021 $2.7 billion N/A WESTERN EUROPE & EU COUNTRIES Gassco* Norway to Sweden N/A $1.3 billion 2008 Source: Reference [257], The exports and imports of natural gas by various countries are given in Appendix VII. Licensed to Jiri Martinec 340 7 Natural Gas Primary Russian Oil and Gas Pipelines to Europe (D) Oil pipeline Proposed oil pipeline Gas pipeline Proposed gas pipeline Russian-dominated pipeline' Tanker terminal 'i—■—i"-1-1 •All or most of the oil or gas moving through a given pipeline Is from Russia Vorth Sea Sweden iPechora •/ Krasnoleninskiyi'" ....id Murmansk mm* routes ... - yukhta . kiY Germany Lelpzii » ,Kaliningi ad f*T ' Libya Iran Syria Iraq r JofdanS Saudi Arabia 772861 Al (HO1119)1-OS Fig. 7.29. Proposed pipeline for transportation of natural gas. (Adapted from Energy Information Administration, USA, Natural Gas, Russia). Licensed to Jiri Martinec o CD CO CD Q. 03 3- CD O A 3 03 3- CD O CD < 8 V Pipelines Existing: Bucharest, Proposed Fig. 7.30. Natural gas pipeline in Europe. (Adapted from Energy Information Administration, USA). ON 2 I O P3 O g" o o' 0 Fig. 7.31. Proposed pipeline through Turkey. (Adapted from Energy Information Administration, USA). 7.6 Natural Gas Production 343 7.6.6 Storage of Natural Gas Natural gas storage facilities serve two purposes: they provide both the base load requirements and meet the peak load requirements. In order to ensure long term steady and reliable supply of natural gas, it is stored underground. There are three main types of underground storage facilities [258-266]: • Depleted gas reservoirs • Aquifers • Salt caverns However, mines and hard rock caverns are also considered for storage. These methods are shown in Fig. 7.32. D Depleted Reservoirs Source: PB-KBE,Inc. £ Hard-rock Caverns Fig. 7.32. Methods for storage of natural gas [267], 7.6.6.1 Depleted Gas Reservoirs These are original underground formation basins for natural gas. Once they are depleted, these formations are used for holding or storage of natural gas. Since the extraction network is already in place, the cost of converting a depleted reservoir into a storage facility is very economical. Depleted reservoirs are attractive because their geological characteristics are already well known and a history exists regarding their operation and maintenance. Licensed to Jiri Martinec 344 7 Natural Gas 7.6.6.2 Aquifers These are underground porous, permeable rock formations that are natural water reservoirs. These formations are reconditioned and used as natural gas storage facilities. However, these aquifers need to be characterized fully, particularly their composition and porosity before reconditioning. Once an aquifer is selected for gas storage, various infrastructures, including extraction equipment, pipelines, dehydration facilities, and compression equipment must be installed. Because of these requirements, aquifers are the least desirable and most expensive type of natural gas storage facility. 7.6.6.3 Salt Caverns Underground salt formations are another medium for natural gas storage. Salt caverns are highly non-porous and therefore loss of injected natural gas is minimal. The salt cavern storage facilities are typically located between 1,500 and 6,000 ft beneath the surface. Base load facilities are capable of holding enough natural gas to satisfy long term seasonal demand requirements. Depleted gas reservoirs are the most common type of base load storage facility. These reservoirs are larger; however the amount of natural gas that can be used from them each day is limited. The main objective is to provide steady supply of natural gas. Table 7.21. Underground storage. 2000 2001 2002 2003 2004 2005 Total 8,240,886 8,415,326 8,207,074 8,205,716 8,255,042 8,268,443 storage capacity Salt 189,043 218,483 225,958 234,601 239,990 250,532 caverns Aquifers 1,263,711 1,195,141 1,234,007 1,237,132 1,238,158 1,350,689 Depleted 6,788,130 7,001,700 6,747,108 6,733,983 6,776,894 6,667,222 fields Total 413 418 407 391 393 394 number of active fields Salt 28 28 29 30 30 30 caverns Aquifers 49 39 38 43 43 44 Depleted 336 351 340 318 320 320 fields Source: Energy Information Administration, Underground natural gas storage capacity. Licensed to Jiri Martinec 7.6 Natural Gas Production 345 Peak load storage facilities, on the other hand, are designed to have high-deliverability for short periods of time. Peak load facilities are intended to meet sudden, short-term demand increases. Salt caverns are the most common type of peak load storage facility, although aquifers may be used to meet these demands as well. Storage facilities in the USA can be found almost in all the states, but they are most concentrated in the consuming north east region of the country. The underground storage capacity by facility types are listed in Table 7.21. The distribution of these facilities in various states are given in Fig. 7.33. Consuming Wast Fig. 7.33. Underground natural gas storage facilities in the lower 48 states. (Source: Energy Information Administration (2004) Gas tran geographic information system Underground Storage Database). The natural gas is delivered to the consumer from the storage facility rather than from the gas processing plant directly. The natural gas is injected into the underground storage facility to maintain what is known as 'base gas' or 'cushion gas'. This is the volume of gas that must remain in the storage facility to provide the required pressurization to extract the remaining gas. The remaining of the gas may be called the working gas capacity. Working gas is the volume of natural gas in the storage reservoir that can be extracted during the normal operation of the storage facility. This is the natural gas that is being stored and withdrawn; the capacity of storage facilities normally refers to their working gas capacity. Periodically, underground storage facility operators may reclassify portions of working gas as base gas after evaluating the operation of their facilities. The working gas Licensed to Jiri Martinec 346 7 Natural Gas capacity by storage facility is shown in Fig. 7.34. However, as can be seen from Fig. 7.35, for daily use salt cavern and aquifers are used more than depleted reservoirs. Fig. 7.34. Working gas capacity in the USA Source: Working gas capacity by type of storage. (Source: Energy Information Administration, Natural Gas Storage in the USA, 2001). Sift Cavern Aquifer (11%) / Fig. 7.35. Daily deliverability by type of storage. (Source: Energy Information Administration, Natural Gas Storage in the USA, 2001). Licensed to Jiri Martinec 7.6 Natural Gas Production 347 7.6.7 Distribution Natural gas from intrastate pipeline is delivered to local distribution companies, which is called citigates. The pricing of natural gas is generally determined at this point. The price breakdown is shown in Fig. 7.36. Typically, local distribution companies take ownership of the natural gas at the citygate, and deliver it to each individual customer's location of use. This requires an extensive network of small-diameter distribution pipe. Fig. 7.36. Component of natural gas price. (Source: Energy Information Administration). Traditionally, local distribution companies have been awarded exclusive rights to distribute natural gas in a specified geographic area. They are also responsible for billing, safety inspection, and providing natural gas hookups for new customers. Local distribution companies must maintain the highest safety standards and are responsible for fixing problems with the distribution network. Some of the safety features that local distribution companies must provide include: • Leak detection equipment • Safety education programs • Technicians on call • Emergency preparedness • One call systems 7.6.8 Natural Gas Use Natural gas provides almost 24% of the total energy need in the USA, which is second to petroleum (39%). Fig. 7.37 shows the contribution of natural gas to the total energy need of the USA. Licensed to Jiri Martinec 348 7 Natural Gas Renewable Energy Fig. 7.37. Natural Gas use compare to other energy use. (Source: Energy Information Administration. Annual Energy Outlook 2007). Natural gas is used basically by all sectors. Fig. 7.38 gives an idea of the proportion of natural gas use per sector. Although the industrial sector uses the greatest proportion of natural gas in the United States, the residential sector and electric power generation using natural gas follow very closely. The uses of natural gas may be divided into the following categories: 1. Residential uses 2. Commercial uses 3. Industrial uses 4. Natural gas use for vehicles 5. Electricity generation Fig. 7.38. Natural gas use by various sectors in the USA. (Source: Energy Information Administration. Annual Energy Outlook 2007). Licensed to Jiri Martinec 7.6 Natural Gas Production 349 7.6.8.1 Residential Uses One of the main reasons for the wide spread use of natural gas in the residential sector is its cost compared to other sources (Fig. 7.39). The best known uses for natural gas around the home are for heating and cooking. According to the American Gas Association, in 2000, about 51% of homes in the USA (or 49.1 million households) used natural gas for heating. Also a high proportion of new homes are being built with natural gas heating. A report in 2003 by the U.S. Census Bureau on new housing indicated that 70% of single family homes completed in 2003 used natural gas for heating, followed by 27% that used electric heat, and 2% used heating oil. The new generations of natural gas ranges are efficient, economical, and versatile. In addition to heating homes, natural gas can also be used to help cool houses, through natural gas powered air conditioning. Other examples of natural gas appliances include space heaters, clothes dryers, pool and Jacuzzi heaters, fireplaces, barbecues, garage heaters, and outdoor lights. All of these appliances offer a safe, efficient, and economical alternative to electricity or other fuel. N.ilurol G.is No. 2 Heatiny Oil Kerosene Propane Electricity .79 11 .53 10 15 20 24.3 J 25 VBTU Fig. 7.39. Cost of various energy sources used by residential sector. (Source: US Department of Energy). 7.6.8.2 Commercial Uses Commercial uses of natural gas are very similar to residential uses. The commercial sector that includes public and private facilities, such as office buildings, schools, churches, hotels, restaurants, and government buildings use significant amount of natural gas. The main uses of natural gas in this sector include space heating, cooking, water heating, and cooling. The percentage usage of various sectors is shown in Fig. 7.40. Licensed to Jiri Martinec 350 7 Natural Gas Lighting Water Heating (8%)-- Cooling (12%) Space Heating (36%) Fig. 7.40. Commercial use of natural gas. (Source: Washington Policy and Analysis, Inc., Fueling the Future 2000). Natural gas based cooling systems are becoming more popular because of their energy efficiency and also some systems have the capability to enhance indoor air quality. There are three types of natural gas based cooling processes. Engine driven chillers use a natural gas engine and waste heat from the gas engine can be used for heating applications, increasing energy efficiency. The second system is called absorption chillers, which provide cool air by evaporating a refrigerant like water or ammonia. The heat is provided by using natural gas. These absorption chillers are best suited to cooling large commercial buildings, like office towers and shopping malls. The third type of commercial cooling system consists of gas-based desiccant systems. In this system, a desiccant first removes water vapor from the humid air. The humidity of the dry air is then adjusted by spraying water vapor into the stream. The exhausted desiccants are regenerated by using the natural gas. The desiccant can co-adsorb various indoor pollutants along with water vapor, thus enhancing the indoor air quality. Recently combined heating and power (CHP) or combined cooling, heating and power (CCHP) systems are found to be more energy efficient than the single unit. The energy savings come from the heat that is released from natural gas powered electricity generators. The heat can be harnessed to run space or water heaters, or commercial boilers. Licensed to Jiri Martinec 7.6 Natural Gas Production 351 7.6.8.3 Industrial Use Industry uses energy from various sources, but they are the largest consumer of natural gas, accounting for almost 43% of the total natural gas use (see Fig. 7.41). The graph below shows current as well as projected energy consumption by fuel in the industrial sector. Natural gas is consumed primarily in the pulp and paper, metals, chemicals, petroleum refining, stone, clay and glass, plastic, and food processing industries. These businesses account for over 84% of all industrial natural gas use. Natural gas is also used for waste treatment and incineration, metals preheating (particularly for iron and steel), drying and dehumidification, glass melting, food processing, and fueling industrial boilers. Other industrial applications of natural gas include infrared heating, direct contact water heating, industrial combined heat and power, and industrial co-firing. 40 10 1 1 1 1 1 1 1 1 1 1 History -1-1-1-1-P-1-1-1-1-1-1- Projection Liquids Coal Natural Gas - ■ Nuclear Electricity -- Hydroetectricrty .........i . , Other Renewables ........... 1980 1990 2000 3010 2020 2030 Year Fig. 7.41. Current and projected use of various energy sources including natural gas by industries. (Source: Energy Information Administration. Annual Energy Outlook 2007 with Projections to 2030). 7.6.8.4 Natural Gas Vehicles [268-272] According to the Natural Gas Vehicle Coalition, there are currently 130,000 Natural Gas Vehicles (NGVs) on the road in the United States, and more than 2.5 million NGVs worldwide. In fact, the transportation sector accounts for 3% of all natural gas used in the United States. All types of vehicles including Licensed to Jiri Martinec 352 7 Natural Gas passenger cars, trucks, buses, vans, and heavy-duty utility vehicles have been designed and produced to run using natural gas. Despite various advances, a number of disadvantages of natural gas vehicles prevent their mass-production. Limited range, trunk space, higher initial cost, and lack of refueling infrastructure pose impediments to the future spread of natural gas vehicles. 7.6.8.5 Electricity Generation In 2000, 23,453 MW of new electric capacity was added in the U.S. Of this, almost 95%, or 22,238 MW was generated using natural gas (see Fig. 7.42). A number of new facilities are 'combined-cycle' units. Both a gas turbine and a steam turbine are used for power generation. The hot gases released from burning natural gas turn a gas turbine and generate electricity. In combined-cycle plants, the waste heat from the gas-turbine is used for generating steam, which is then used to generate electricity using a steam turbine. Because of this efficient use of the heat energy released from the natural gas, combined-cycle plants can achieve 50-60% thermal efficiencies. 3000 500C 4500 - 4000 =. n I 3500 I 3000 2500 2000 1SS0 1990 2000 2010 Year 2020 2030 Fig. 7.42. Use of natural gas in electricity generation. (Source: Energy Information Administration. Annual Energy Outlook 2007 with Projections to 2030). 7.6.8.6 Natural Gas Use for Fertilizer Production About 5-6% of natural gas produced in the world is used for fertilizer production. Most of natural gas is used as feedstock in the production of ammonia, which is next used for production of various nitrogen-fertilizers. There is at present no Licensed to Jiri Martinec 7.6 Natural Gas Production 353 economic alternative to natural gas as a feedstock. As can be seen from Table 7.22, the cost of using other resources for fertilizer production is significantly higher than natural gas. Methane (CH4) in the natural gas is dissociated to produce hydrogen, which is then reacted with nitrogen over a catalyst to produce ammonia (NH3). Natural gas must be free from any sulfur compounds. If sulfur compounds remain in the natural gas stream, they can poison the catalysts that are used in the remaining steps. Sulfur compounds are removed either by adsorption on activated carbon in the temperature range of 15-50°C or by reaction with a zinc oxide catalyst at 350^400°C. After the sulfur compounds are removed, natural gas is reformed with steam over a nickel catalyst according to the following two reactions to produce Syngas. CH4 + H20 - CO + 3H2 CO + H20 - C02 + H2. The exit gas is heated to a temperature in the range of 750 to 850°C and pressurized in the range of about 28-35 atm (415-515 psi) before introducing it in the secondary reformer. Air, which is the source of nitrogen, is introduced in this stage. Oxygen from air reacts with CO releasing heat that drive the second reaction, which generates C02. The product of the second reforming stage is a mixture of carbon oxides, H2, N2, and other impurities. Carbon oxides are removed next. First CO is converted to C02 by the shift reaction, followed by a C02 removal step. An iron oxide-chromium oxide catalyst is used in the shift reaction. The C02 removal operation is done in two steps - a bulk C02 removal in which C02 concentration is reduced to a few parts per million and a final purification step. The most common bulk C02 removal operation is performed by scrubbing the gas with a methyldiethanolamine or monoethanolamine solution. If an ammonia production plant is associated with a nearby urea plant, the C02 may be recovered and used for urea production. The final gas mixture before introducing it into an ammonia production reactor must be ultra-pure. Therefore, any traces of C02 and CO must be removed from the gas stream. This is normally done by reacting C02 and CO with H2 gas over a nickel catalyst (the reverse of the reforming reactions) converting them to CH4. A cryogenic purification method is used to remove the methane from the gas stream. The clean gas mixture containing only N2 and H2 is compressed to between 136 and 340 atm (2,000 and 5,000 psi) and then passed over an iron catalyst where the nitrogen and hydrogen react to form ammonia by the following reaction: N2 + 3H2-2NH3. After production, ammonia may be used to produce a variety of downstream products, which include ammonium nitrate, ammonium sulfate, nitric acid, and urea. Licensed to Jiri Martinec 354 7 Natural Gas Table 7.22. Comparison of energy cost for fertilizer production normalized to the cost of natural gas. Items Natural gas Heavy oil Coal Energy consumption 1.0 1.3 1.7 Investment cost 1.0 1.4 2.4 Production cost 1.0 1.2 1.7 Source: Reference [273], 7.7 Liquefied Natural Gas (LNG) LNG is natural gas that is cooled at atmospheric pressure at a temperature -260°F (-161°C). At this condition, it is liquid. The liquefaction is accomplished using a refrigeration process in a plant. The unit where LNG is produced is called a train. Liquefying natural gas reduces its volume by a factor of 610. The reduction in volume makes the gas practical to transport and store. LNG is mostly methane (85-95%) and the rests are ethane, propane and butane (5-15%) A small amount of nitrogen can be also present. Depending on the country of origin, the composition can vary slightly. As a result, its heating value will also change. The composition of LNG based on its origin is given in Table 7.23. Table 7.23. Variation in the LNG composition based on it origin. Origin Methane Ethane Propane Butane Nitrogen (%) (%) (%) (%) (%) Algeria 87.6 9.0 2.2 0.6 0.6 Australia 89.3 7.1 2.5 1.0 0.1 Malaysia 89.8 5.1 3.3 1.4 0.3 Nigeria 91.6 4.6 2.4 1.3 0.1 Oman 87.7 7.5 3.0 1.6 0.2 Qatar 89.9 6.0 2.2 1.5 0.4 Trinidad & 96.9 2.7 0.3 0.1 0.0 Tobago Source: Reference [274], Liquefaction of LNG makes it possible to trade it internationally, since it can be transported in specially built tanks in doublehulled ships to a receiving terminal where it is stored in heavily insulated tanks. The LNG is then sent to regasifiers which turn the liquid back into a gas that enters the pipeline system for distribution to customers as part of their natural gas supply. In the USA, net imports of LNG are expected to increase from 0.6 Tcf in 2004 to more than 6 Tcf in 2025. Licensed to Jiri Martinec 7.7 Liquefied Natural Gas (LNG) 355 This will be almost 21% of total U.S. natural gas demand. As can be seen from Table 7.24, LNG imports to the USA are increasing steadily and it is projected to increase faster in the future. Table 7.24. LNG import to the USA in the last several years. Year Amount of LNG imported (MMcf) Year Amount of LNG imported (MMcf) 1990 84,193 2000 226,036 1991 63,596 2001 238,126 1992 43,116 2002 228,730 1993 81,685 2003 506,519 1994 50,778 2004 652,015 1995 17,918 2005 631,260 1996 40,274 2006 583,537 1997 77,778 1998 85,453 1999 163,430 The LNG is imported into the USA from various countries via ships. As can be seen from Fig. 7.42, LNG is imported from a number of countries over the last 30 years, however, the demand increased dramatically in the last several years. This resulted in a new international shipping routes (Fig. 7.43). Fig. 7.43. International route of LNG transportation. The thickness of the line represents relative LNG volume movement. (Adapted from [275]). Licensed to Jiri Martinec 356 7 Natural Gas 7.8 Liquefaction Process The Phillips Cascade and Air Products APCI processes are mostly used for liquefaction of natural gas [276-278]. Several new processes have been recently proposed for liquefaction, and they are; Axen/IFP (DMR) - LIQUEFIN™ [279-280] Linde AG (Statoil) - MFC® [281] Turbo-Expander (BHP) Blck & Vetch Pntchard Inc. - PRICO® [282] 7.8.1 Phillips Cascade Process The Phillips cascade process is a three-stage process [283-284]. Three pure components are used for refrigeration; (1) Propane pre-cooling, (2) Ethylene, and (3) Methane. A schematic diagram of the Phillips cascade process is shown in Fig. 7.44. The refrigeration circuits are cascaded to provide maximum LNG production. Each circuit uses two compressors. The LNG from the last-stage flash drum is sent to the tanks by the transfer pumps, where it is stored at about 70 mbar and - 161°C. Advantages of this process are low installation costs, and the use of a two - train - in - one reliability concept. However, the increase use of gas turbines and compressors also increases the maintenance costs. 7.8.2 APCI Process This process utilizes two cooling stages. In the first stage, propane is used as a cooling fluid and a mixed refrigerant is used in the second stage [285]. Generally a mixture of ethanol, propane, methanol and nitrogen obtained after splitting the C2+ is used as refrigerant. The composition of the mixture of coolants is based on the composition of natural gas in the plant. Natural gas, after passing through the pretreatment systems, is cooled in the propane vaporizer. The pressure of the propane is adjusted so that it remains cool, and no condensation occurs. The second stage is the main cryogenic coolant, which cools the natural gas through a closed circuit of mixed coolants. After liquefying, it is subcooled for storing. A schematic diagram of the process is shown in Fig. 7.45. Licensed to Jiri Martinec Phillips Raw Gas Inlet Metare ) Inlet Scrubbers ^Ship Vapors To Dock J/T Valvn Fig. 7.44. Phillips cascade process for liquefaction of natural gas. (Reprinted with permission from [277]). 00 r1 1 S 3 o o Cfl To Furnace Amine Unit O CD CO CD Q. 03 3- CD O A 3 03 3- CD O CD < C R V Sour Feed Gas Acid Gas Mercury Removal Unit HHP HP MP Dehydration OJ Unit -J Scrub Column C1 LP C3 HP Fuel Gas NGL Ránjectíon C2 XJ X Fractionation Hydrocarbon Condensate to Storage C3 Compressor Cm) LP C3 t_|x|J MPC3 HPC3 Propane Precooling ^2 '° Storage TTTT N2 C1 C2 C3 Refrigerant Make-up Multicomponent Refrigerant System Fig. 7.45. APCI propone precooled mixed refrigerant typical process. (Reprinted with permission from [270]). 7.9 Transportation and Storage of LNG 359 7.9 Transportation and Storage of LNG Specially designed containers are used for shipping of LNG. The majority of the new containers for LNG transportation via sea are in the size range of 120,000-140,000 m3. New containers with a capacity up to 260,000 m3 are now currently being constructed by several builders. There are four containment systems in use. 7.9.1 Moss Tanks These are spherical aluminum tanks and are designed by Moss Maritime, Norway. The cross-sectional view of a Moss tank is shown in Fig. 7.46 and its design characteristics are presented in Fig. 7.47. Fig. 7.46. The Kvaerner/Moss Rosenberg tank design for LNG transportation. (Adapted from Frivik P-E (2003) The Importance of Knowledge in the Changing Nature of Natural Gas Supply-Contributions from Academia and Applied Research in Industrial LNG Development. IEA Advisory Group on Oil and Gas Technology. Economic Analysis Division of the International Energy Agency Initiation of Global Dialogue on "the Future of Natural Gas Supply and Use" Exploring the Impact of Financial and Technological Drivers Washington DC, 22 January 2003 [286]). Licensed to Jiri Martinec 360 7 Natural Gas SECTION Fig. 7.47. Free standing spherical LNG transportation tank. (Adapted from [287]). 7.9.2 IHI Tanks The tank is made of aluminum and is built by Ishikawajima-Harima Heavy Industries, Japan. The IHI tank is shown in Fig. 7.48. Centerline Bhd Insulation Ballast Tank Fig. 7.48. Floating production storage & offloading unit for LNG shipment. (Adapted from [288]). Licensed to Jiri Martinec 7.10 LNG Storage Facility 361 7.9.3 GT96 The GT96 is designed by Gaz Transports. The tank consists of two membranes: a primary and secondary thin membrane. Both the membranes are made of invar which has negligible thermal contraction in the temperature range the tanks operate. The insulation is made out of plywood boxes filled with perlite. The design features are shown in Fig. 7.49. Outer Hull Fig. 7.49. Design features of a membrane tank. (Adapted from [289]). 7.9.4 TGZMark III The TGZ Mark III is a membrane type and is manufactured by Technigaz. The membrane is made out of stainless steel with baffles, which allow the thermal contraction when the tank is cooled down. The interior design of TGZ Mark III tank is illustrated in Fig. 7.50. 7.10 LNG Storage Facility There are basically two types of LNG (liquid natural gas) storage tanks: above ground, and underground. Licensed to Jiri Martinec 362 7 Natural Gas For 125,000 Cubic Meter Ships Avondale Shipyards, Inc. Polyurethane foam AI, Alloy lank planting Balsa wood Face plywood Secondary barrier Fibrous glass Steel bulkhead Polyurethane foam Back plywood PVC foam wedge Fig. 7.50. Free standing prismatic LNG tank. (Adapted from [287]). 7.10.1 Underground Storage Tank The underground storage tanks are composed of continuous diaphragm walls, side walls and base mat slabs, and each tank has different requirements of performances. 7.10.2 Above Ground Storage Tank There are three types of above ground LNG storage tanks: Single containment Double containment Full containment A Single containment tank is generally a single tank (Fig. 7.51). In some design an outer container is included. However, only the inner tank is required to meet the low temperature ductility requirements for storage of LNG. A double containment tank consists of both the inner tank and the outer tank (Fig. 7.52). Both the tanks are capable of independently containing the refrigerated liquid. Licensed to Jiri Martinec o CD CO CD Q. 03 3- CD O A 3 03 3- CD O CD < R V Bund wall loose filled insulation outer shell | not able 1o contain liquid inner tank base insulation external insulation with weather barrier inner tank wall inner tank bottom base insulation bund wall elevated concrele base concrele foundation with bottom heater Fig. 7.51. Single containment type LNG storage tank. (Printed with permission [283]). 8 CO CD Q. Q) CD O A 3 3- CD O © CD < R V rain cover insulated suspended deck prestressed concrete outer tank wall loose filled insulation i outer shell not able to contain liquid) inner tank base insulation rain cover external insulation"" with weather barrier inner tank wall inner tank bottom base insulation outer tank shell (able to contain the liquid) elevated concrete base concrete foundation with bottom heater ^1 Z I o P3 Fig. 7.52. Double containment type LNG storage tank. (Printed with permission from [283]). insulated suspended deck -—— insulation at inside outer tank - outer tank wall liner prestressed concrete outer tank inner tank outer roof loose filled insulation wall insulation -al inner side of outer tank (or loose filled insulation) inner tank wall inner tank bottom base insulation outer tank shell or prestressed concrete wall with liner Fig. 7.53. Full containment type LNG storage tank. (Printed with permission from [283]). 366 7 Natural Gas Licensed to Jiri Martinec 64 References 367 A full containment tank (Fig. 7.53) is similar in design to the double containment tank. It differs from the double containment tank in that the outer tank of a full containment tank is capable of both containing the refrigerated liquid and controlled venting of the vapor resulting from product leakage in the case of an accident. The structural aspects of the tank are shown in Fig. 7.54. The full containment type is regarded as the most advanced type and can also be constructed, in-ground or under-ground. The inner tank is manufactured with 9% nickel steel and the outer tank is composed of reinforced concrete and pre-stressed concrete. The 9% nickel steel is capable of withstanding cryogenic conditions. The concrete outer tank is designed to resist various external loads including seismic load. Insulating materials are placed between the inner and outer tank to preserve the stored LNG. References 1. BP statistical Review of World Energy, 2008 2. Energy Information Administration, USA, Report # DOE/EIA -0484, 2006 3. Whiticar MJ, Faber E, Schoell M (1986) Biogenic methane formation in marine and freshwater environments: C02 reduction vs. acetate fermentation-isotope evidence. Geochem Cosmochim Acta 50: 693-709 4. Horita J, Berndt ME (1999) Abiogenic methane formation and isotopic fractionation under hydrothermal condition. Science 285(5430): 1055-1057 5. Charlou JL, Fouquet Y, Donval J-P, Auzende JM (1996) Mineral and gas chemistry of hydrothermal fluids on an ultrafast spreading ridge: East Pacific Rise, 17° to 19° S (Naudur cruise, 1993) phase separation processes controlled by volcanic and tectonic activity. J Geophys Res 101(B7): 15899-15919 6. Anon (1911) The origin of oil and gas. Pet Rev 24: 303-304, 335 7. Berl E (1934) Origin of asphalts, oil, natural gas and bituminous coal. Science (Washington, DC) 80: 227-228 8. Berl E (1942) Origin of coal, oil and natural gas and their production from plant material. Sci Counsel 7: 35, 57 9. Boreham CJ, Golding SD, Glikson M (1998) Factors controlling the origin of gas in Australian Bowen Basin coals. Org Geochem 29: 347-362 10. Dolenko GN (1989) Origin and petroleum and natural gas and oil and gas accumulation in the Earth's crust. A reply. Izvestiya Akademii Nauk SSSR, Seriya Geologicheskaya: 138-141 11. Dolenko GN (ed) (1978) Origin and Migration of Petroleum and Gas, Kiev, Naukova Dumka 12. Gemp SD (1972) Formation of gas deposits. Geologiya i Geokhimiya Goryuchikh Iskopaemykh No. 30: 62-70 13. Geodekyan AA, Kartsev AA, Yanshin AL (1989) Origin of petroleum and natural gas and oil- and gas accumulation in the Earth's crust. A discussion. Izv. Akad. Nauk SSSR, Ser. Geol. 135-137 14. Haun JD, Lucas GB (1968) Origin and accumulation of natural gas. Memoir - Am Assoc Petrol Geol 2: 1990-1994 15. Kalinko M (1977) Origin of petroleum and natural fossil-fuel gases. Neftyanik: 32-36 Licensed to Jiri Martinec 368 7 Natural Gas 16. Kartsev AA, Tabasaranskii ZA, Subbota MI, Mogilevskii GA (1959) Geochemical Methods of Prospecting and Exploration for Petroleum and Natural Gas (Trans, from Russian) California U.P., Cambridge U.P. 17. Lur'e MA, Kurets IZ, Shmidt FK (2003) The possible abiogenic origin of oil and gas. Chem. Technol. 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Terasaki D (2006) The resources of unconventional natural gases and their world supply and demand assumption in future. J Jpn Inst Energy 85: 105-111 26. Stosur G (2007) Global scramble for natural gas and the role of unconventional gas resources. Nafta (Zagreb, Croatia) 58: 559-567 27. Johnson RL, Jr., Hopkins CW, Zuber MD (2000) Technical challenges in the development of unconventional gas resources in Australia. APPEA J 40: 450-468 28. King GR, Ertekin T (1991) State-of-the-art modeling for unconventional gas recovery. SPE Formation Evaluation 6: 63-71 29. Kurosawa A (2007) An analysis of unconventional gas and enhanced coalbed methane in long-term global energy supply. J Jpn Inst Energy: 87-93 30. Miskimins JL (2006) Unconventional natural gas reservoirs: what are the associated challenges? Nafta (Zagreb, Croatia) 57: 495-503 31. 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Hoover KV (1960) Devonian-Mississippian shale sequence in Ohio. OSTI ID: 7329188 61. Milici RC (1993) Autogenic gas (self sourced) from shales - an example from the Appalachian Basin. OSTI ID: 7052186 62. Kuuskraa VA, Brandenberg CF (1989) Coalbed methane sparks a new energy industry. Oil Gas J 87(41): 49-56 63. Abraham KS (2006) Coalbed methane activity expands further in North America. World Oil 226(8): 61-62 64. Boyer CM II (1989) The coalbed methane resource and the mechanisms of gas production. GRI Topical Report GRI 89/0266 65. Carlton DR (2006) Discovery and development of a giant coalbed methane resource, Raton Basin. Las Animas County, southeast Colorado: The Mountain Geologist 43(3): 231-236 66. Deul M, Kim AG (2002) Coal beds: a source of natural gas. Oil Gas J 100(35): 68, 70 67. Eaton SR (2006) Coalbed gas frontier being tapped: AAPG Explorer 27(11): 20, 24, http://www.aapg.org/explorer/2006/llnov/horseshoe_canyon.cfm 68. Gentzis T (2006) Economic coalbed methane production in the Canadian Foothills: solving the puzzle. Int J Coal Geol 65: 79-92 69. Hill R (2002) CBM: converting a resource into energy. World Coal 11: 50-51, 53 70. Law BE (1988) Coal-bed methane. In LB Magoon, ed, Petroleum systems of the United States. USGS Bulletin 1870: 52-53 71. Law BE (1992) Coalbed methane. In LB Magoon, ed, The petroleum system - status of research and methods. U.S. Geological Survey Bulletin 2007: 20-21 72. Law BE (1993) The relationship between coal rank and cleat spacing: implications for the prediction of permeability in coal. Proceedings of the 1993 International CBM Symposium, paper 9341: 435-442 73. Law BE, Rice DD (1993) Coalbed methane - new perspectives on an old source of energy. In S-H Chiang, ed, Coal - energy and the environment. Tenth Annual International Pittsburgh Coal Conference, Proceedings: 316-319 74. Law BE, Rice DD (eds) (1993) Hydrocarbons from coal. AAPG Studies in Geology 38:400 75. Markowski AK (1993) Coalbed methane: new energy from an old scourge. Pennsylvania Geological Survey, Pennsylvania Geol 24(2): 8-14 76. McKinnon I (2002) Canadian coalbed methane. Oil and Gas Investor 22(3): 56-59 77. Murray DK (2000) CBM in the United States: World Coal March: 61-64 78. Narasimhan KS, Mukherjee AK, Sengupta S, Singh SM, Alam MM (1998) Coalbed methane potential in India. Fuel 22: 1865-1866 79. Palmer ID, Cameron JR, Moschovidis ZA (2006) Permeability changes affect CBM production predictions. Oil Gas J 104(28): 43-50 80. Pinsker LM (2002) Coalbed methane: the future of U.S. natural gas? Geotimes 47(11): 34-35 Licensed to Jiri Martinec References 371 81. Rice DD, Law BE, Clayton JL (1993) Coalbed gas - an undeveloped resource. In DG Howell, ed, The future of energy gases: USGS Professional Paper 1570: 389-404 82. Rice DD (1997) Coalbed methane - an untapped energy resource and an environmental concern. U.S. Geological Survey, Fact Sheet FS-019-97 83. 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J Porous Mater 5(1): 43-58 273. European Fertilizer Manufacturers Association (EFMA), Brussels, Belgium 274. Groupe International Des Importateurs De Gaz Natural Liquefie 275. US Department of Energy (2005) Liquefied natural gas: understanding the basic facts. DOE/FE-0489 276. Mokhatab S, Economides MJ (2006) Process selection is critical to onshore LNG economics. Global LNG report, WorldOil Magazine: 227(2) 277. Shukri T (2004) LNG technology selection. Hydrocarbon Engineering 9: 2 278. Smaal A (2003) Liquefaction plants: development of technology and innovation. Paper presented at the 22nd World Gas Conference, Tokyo, Japan 279. Martin P-Y, Pigourier J, Boutelant P (2003) Liquefin: an innovative process to reduce LNG costs. Paper presented at the 22nd World Gas Conference, Tokyo, Japan 280. Fisher B, Boutelant P (2002) A new LNG process is now available. Presented at the GPA Europe Technical Meeting, London, England, Feb. 2002 281. 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Economic Analysis Division of the International Energy Agency Initiation of Global Dialogue on the Future of Natural Gas Supply and Use. Exploring the Impact of Financial and Technological Drivers, Washington DC, January 22, 2003 287. Office of Technology Assessment (1977) Transportation of liquefied natural gas. NTIS PB-273486 288. IHI SPB LNG FPSO, http://www.ihi.co.jp/ihimu/images/seihin/pll5-2.pdf 289. Cushing J (2006) LNG vessel safety and security. DOE LNG forum, Houston, TX, USA Licensed to Jiri Martinec Problems 381 290. Munko B (2007) Economic design of small scale LNG tankers and terminals. LNG Conference Offshore Center, Denmark 291. Yang Y-M, Kim J-H, Seo H-S, Lee K, Yoon I-S (2006) Development of the world's largest above ground full containment LNG storage tank. 23rd World Gas Conference, Amsterdam, The Netherlands Problems 1. What are the major factors affecting natural gas prices? 2. What greenhouse gas emissions are associated with natural gas in the U.S.? 3. How is natural gas stored? How is LNG used? Why use LNG? 4. Can the use of natural gas be an answer to global warming? 5. How feasible is natural gas fueled passenger car? 6. What are the challenges for use of natural gas in a vehicle? 7. Does use of natural gas affect the environment? 8. Does production of natural gas affect the environment? 9. How is natural gas distributed to consumers? 10. Are there adequate supplies of natural gas to meet future needs? 11. What percentage of natural gas is used for electricity generation? Should we build more power plants based on natural gas? What are the issues? 12. There is an attempt to promote natural gas as an alternative to petroleum. Discuss if this is viable and if there is enough resources to replace petroleum? 13. Discuss various uses of natural gas and how these will be affected if natural gas becomes unavailable at an affordable price. 14. Why it important to dry the natural gas before sending it through pipeline? 15. During natural gas processing various sulfur compounds are removed, but before selling to the consumer again a certain type of sulfur compound is added to the gas. Explain the reasons behind this practice. 16. What are the losses from the storage of natural gas? 17. Methane hydrates are considered as the major source of natural gas in the future. Discuss the issues related to its extraction from its source. What are the likely consequences? Licensed to Jiri Martinec