Natural Gas: Exploration and Properties

By Harald Osel

Natural Gas: Exploration and Properties is the 1st volume in a series of textbooks to be continued with Natural Gas: Operations and Transport (2nd volume), as well as Natural Gas: Customers and Consuming Industries (3rd volume). This series will end with a 4th volume Natu

• Language: English
• Publisher: Aurora House
• Release date: Dec 2, 2020
• ISBN: 9780994286161

Book preview

1

Natural Gas: Introduction and General Environment

The natural gas industry in its operational set-up shows great similarities with the oil and gas industry, while the exploration for and production of hydrocarbons is commonly referred to as E&P business. Natural gas itself exhibits on the other hand quite distinct and specific properties, chemical features, production technologies, transport requirements and customer markets. A brief introduction to the working and market environment associated with natural gas projects and customers will be presented in this introductory chapter.

1.1. Natural Gas Projects: Working Environment

Natural gas is a term used in the petroleum industry in a broader context. Natural gas essentially represents a group of hydrocarbons originating from a subsurface reservoir. Natural gas is produced from the wellhead in a gaseous state, together with other, non-hydrocarbon gases or gas contaminants. This natural gas mix is sometimes also referred to as raw gas instead of natural gas. The distinction in terminology makes senses in so far as raw gas requires treatment in a specialized gas plant prior to being shipped as methane, whereas natural gas through pipelines to the customer markets, where it could be sold as feedstock or fuel.¹

In order to explore and produce that gas a number of professionals and scientists have to work together to bring a gas field on-stream. Exploration engineers — geologists and geophysicists — need to identify and assess a drillable prospect, based on evaluating seismic surveys, electric logs and other wireline tools. Drilling engineers could subsequently prepare for the spud-in of an exploration well, while being supported by drilling-related service personnel, such as for those involved in mud engineering, mud logging, cementing, drilling fluid services, casing running, well testing, coring, well head installation, completion and others. In case such an exploration well has been drilled successfully into a hydrocarbon reservoir, a delineation of that reservoir is required by drilling further appraisal wells. Given that a commercial discovery could be confirmed during appraisal, a number of additional development wells would have to be drilled subsequently to bring the hydrocarbons onstream.

Activities connected with preparation for the commencement of the production of hydrocarbons are either carried out during the exploratio-, appraisal- or development phase. Once field development has been finalised, the production — or operations phase — commences until decommissioning of the facilities at the end of field life during abandonment phase. As highlighted in the following schematic, the entire period for a gas field project is considerably longer than in case of an oil field.

(Source: Energy Sequel)

In the above example — linked to a gas field development and LNG exports — it takes sixteen years from the commencement of exploration activities to gas exports, while it takes only nine years for an offshore oil project.

During all phases of a project reservoir engineers try drawing conclusions on reservoir characteristics such as porosity, permeability, wettability or saturation and other reservoir- as well as reservoir rock characteristics. During the exploration phase the reservoir engineers utilize results derived from hydrocarbon flow and pressure readings observed during well testing. In addition, data acquired during the running of the wireline logs and the analysis of fluid,- as well as rock , samples could be used. Downhole and surface gauges could be further installed for the continuous monitoring of key parameters such as temperature and pressure at various stages of fluid flow. At this point the aim of the reservoir engineer remains to be the appraisal of the size of the reservoir and the features of the hydrocarbon fluids contained within it.

Throughout the subsequent development phase the optimal location for the drilling of the development wells needs to be determined. Once production from a well has commenced, optimal production conditions and rates are further established with the support of reservoir engineers. Following continued production, the displacement of fluids within the reservoir could additionally be monitored by utilizing 4D seismic tools. Ultimately, when the field’s primary drive mechanism has weakened, enhanced recovery techniques have to be applied in order to prolong the field’s economic life prior to abandonment. The development of production rates for oil and gas — associated with the various stages during field life — have been highlighted in the following schematic.

In fact, it is only at the end of production that the reserves recoverable from a reservoir could be firmly determined. A saying often quoted in the E&P business is that once production has commenced from a reservoir the only thing known with certainty is that the production forecast would be wrong.

Unless for ideal, purely theoretical cases it is consequently impossible to evaluate the commerciality of a gas reservoir by drilling a single exploration well. Substantial further investment would be required (which could — especially offshore — be easily in the order of USD 100 MM plus) prior to being able to evaluate the quality and quantity of the oil or gas contained within the reservoir. In order not to expose itself to the entire exploration risk, E&P companies tend to form a joint venture for risk-sharing purposes. One of the companies participating in the joint venture gets further appointed as the operator and carries out operations on behalf of the other, non-operating, members of the joint venture.

Since field development (following the exploration and appraisal phase) is generally costing much more than what has been spent earlier, a reliable gas marketing concept is required prior to commencement of field development. In less mature gas markets, a Gas Sales and Purchase Agreement (GSPA) represents the standard contract type for long term sales. Ideally a Memorandum of Understanding (MoU) on GSPA terms was already in place before field development starts. Simultaneously, a field development plan (FDP) needs to be submitted by the Joint Venture Partners — respectively the Operator — to the relevant authorities in the country of operations. Following their approval development work could commence.

During field development production engineers remain focused on the development of an optimal production system. This system aims at optimiszing the flow of hydrocarbons from reservoir to surface, the transportation of fluids from the producing wells through field-lines to a gathering station and the onward shipment from there to the fluid treatment facilities in the gas plant. At the outlet of that plant, treated gas is compressed and shipped via transmission lines to a gas market. Liquefaction technology could alternatively be applied for the onward shipment of LNG by LNG carriers.

Field development and production might be relatively straightforward onshore but becomes substantially more complicated in an offshore environment. Due to the high costs of offshore installations, all facilities need to be installed under space constraints on the platform in order to reduce costs. E&P companies operating offshore try to further carry out drilling and production activities by involving a minimum of platforms by drilling, for example, numerous deviated wells from a central drilling platform.

All facilities required for gas production, treatment, processing, and compression should be shifted onshore, whenever possible, due to cost reasons. Ideally, gas could be brought onshore without much offshore treatment and compression. In order to be able to achieve this target, operators need to accept a degree of complication with offshore operations, such as two- or multiple phase fluid flow in subsea-pipelines. While such a solution would not be opted for onshore, the shipment of non-separated reservoir fluids in a multi-phase pipeline is common practice in an offshore environment.

For the production of gas offshore the installation of gas processing units still remains an exception, while most offshore gas is shipped onshore for processing. Offshore oil production has otherwise adapted with increased efficiency to offshore conditions since the development of floating production and system offloaders (FPSOs) and associated subsea completion systems.²)

Facilities engineers further design and operate oil and gas units such as plants for gas treatment (including fluid separation, dehydration, gas sweetening and removal of gas contaminants) and natural gas liquids recovery units.

Pipeline engineers are concerned with the subsequent transporting of gas to industrial customers and the distribution centers for commercial and residential markets. Gas liquefaction technology might alternatively be required for liquefied natural gas, LNG, production and shipment to the customer markets.

A variety of additional engineering,-, scientific- and other personnel — including laboratory researchers, marine engineers, helicopter pilots, roustabouts, roughnecks etc. — provide further technical support during an oil and gas production project.

At the same time lawyers design and negotiate a huge variety of different contracts with a number of parties and state authorities in order to enable a gas production project to come into reality (e.g. production sharing contracts (PSC), built-own-transfer (BOT) agreements or gas sales and purchase agreements).

Commercial personnel needs to further streamline the marketing arrangements, arrange for the financing of the project and engage in other activities such as accounting, cost control, insurance and tax optimiszation. A very important commercial task — especially at the beginning of a new project — is the setting up of an economic model and the calculating of project economics. This model receives continuous upgrades along with additional information becoming available during the progress of the project.³)

Safety and environmental aspects of handling natural gas is otherwise taken care of during operations by dedicated health-safety-security and environment (HSSE) personnel. Specialized quality engineers need to be further involved during processes such as the commissioning of a plant or facility. Finally, the management team of a project needs to supervize the overall development and progress of the work, while taking into consideration the different aspects of a variety of highly specialized disciplines at work. Each of these disciplines actually represents a science by itself, all of which need to be brought together in order to make a petroleum project come into reality.⁴

Gas exploration and production (E&P) activities are typically carried out by an integrated oil and gas company, some of which have a strong bias in their portfolio towards natural gas projects. Companies specializing in handling natural gas are otherwise more common for gas transmission and distribution, rather than in the E&P business. Long distance gas transport could either be carried out through specifically dedicated pipelines or via LNG-carriers, while the distribution of natural gas typically involves a gas utility company.⁵)

The text in hand aims to provide an overview of upstream exploration with an emphasis on natural gas from all the above aspects of the petroleum industry. Physical principles such as gas laws and the properties of natural gas will also be introduced to the reader. Prior to discussing the geological environment of natural gas in a bit more detail, the general environment of the natural gas market shall be briefly introduced.

1.2. Natural Gas and Fossil Fuels: Global Market Environment

Fossil fuels include oil, gas and coal. These three carriers of energy provide the bulk of energy produced and consumed worldwide. Nuclear energy, hydropower and renewable energy (e.g. wind energy or solar power) provide additional sources of energy although with a limited share in total energy generation. Other forms of renewable energy — such as the burning of wood or cow dung (although still important for many households worldwide) — provide only a negligible fraction of the primary sources of energy produced worldwide.

1.2.1. Reserves

By the end of 2014, the proven reserves of natural gas were in the order of 187.1 trillion cubic meters, or TCM (respectively 6,606.4 TCF) worldwide. Given a global consumption in 2014 of 3.393 TCM, these natural gas reserves could last — in a world without change — for about fifty-five years. This forecast consequently does not take the future discovery of new gas reservoirs into consideration.

In the case of oil, the corresponding proven reserves — and production figures in 2014 are 239.8 billion metric tons (bn t) with respect to global reserves, while annual production was 4.22 billion tonnes. These figures suggest — in the theoretical case of a static world — that worldwide oil reserves would last for about fifty-seven more years.

For coal, the remaining consumption period is substantially higher since 891.5 billion metric toe of global reserves and an annual production of 3.9 billion toe (tonnes of oil equivalent) leaves us in 2014 with almost 227 years of possible future consumption.

Table 1 below could provide an idea on how these reserves are regionally distributed.⁶)

The world’s largest natural gas reserves are located in Iran, which holds 18.2% of total reserves worldwide followed by Russia with 17.4% and Qatar with 13.1%. The Middle East holds 42.7% of natural gas reserves worldwide, while about 31.0% are located in the Europe and Eurasian region, including Turkmenistan with 9.3%. In total these two regions count for almost 75% of global gas reserves.

In North America (holding 6.5% of global reserves) the largest reserves are located in the USA with 5.2%. In South and Central America (4.1%) Venezuela’s share of global reserves is 3%. Africa (7.6%), Nigeria (2.7%), and Algeria (2.4%) exhibit the highest reserves available on this continent. Distribution of reserves in the Asia-Pacific region (8.2%) is quite diverse with Australia (2%) and China (1.8%) holding more reserves than the traditional gas producing countries including Indonesia (1.5%) and Malaysia (0.6%).

Countries where substantial gas reserves are further located include Saudi Arabia (4.4%), UAE (3.3%), Iraq (1.9%), Canada (1.1%), Norway (1%), Egypt (1%), and Kuwait (1%). The share of all other countries in proven natural gas reserves worldwide — including for example Kazakhstan (0.8%), Libya (0.8%), India (0.8%), Uzbekistan (0.6%), Azerbaijan (0.6%), the Netherlands (0.4%) and Oman (0.4%) — is otherwise below 1%.

In comparison, the largest oil reserves (as a percentage, %, of global, proven reserves) are located in: Venezuela (17.5%), Saudi Arabia (15.7%), Canada (10.2%), Iran (9.3%), Iraq (8.8%), Kuwait (6%), UAE (5.8%), Russia (6.1%), Libya (2.8%), USA (2.9%), Nigeria (2.2%), Kazakhstan (1.8%), Qatar (1.5%), China (1.1%) and Brazil (1%). Reserve estimates include the Orinoco Belt reserves of Venezuela (occasionally also referred to as Orimulsion) as well as oil sands, especially in the case of Canada.

Concerning coal, it is the USA (26.6%) holding the world’s largest coal reserves, followed by Russia (17.6%), China (12.8%), Australia (8.6%), India (6.8%), Germany (4.5%), Ukraine (3.8%), Kazakhstan (3.8%), South Africa (3.4%) and Indonesia (3.1%). While the coal reserves in Germany and Indonesia are largely of sub-bituminous, lignite quality the coal reserves in South Africa consist almost entirely of high quality anthracite.

1.2.2. Production

Figure 1 (below) further describes graphically the world’s energy production over the last decade in terms of billion metric tons of oil equivalent (bn toe).

Fig.1 shows a substantial increase of global energy consumption of 24% during the period 2004 to 2014. For the fifteen year period from 2000 to 2014, that increase is 41%. Fig.1 further indicates a slight decline from 2008 to 2009, which was due to the global financial crisis at that time. Although that decline is, with about minus 1%, relatively moderate, it was the first decline in energy production and consumption since 1982.

From the 13.05 billion tonnes of oil equivalent (bn toe) produced in 2014 globally, 4.2 bn toe originate from oil production, 3.9 bn toe from coal, 3.1 bn toe from natural gas, while 0.88 bn toe comes from hydropower, 0.57 bn boe from nuclear energy production and 0.32 bn toe from renewable forms of energy. Renewable sources of energy include, biomass, wind, geothermal, solar and waste but exclude the burning of wood, cow dung or peat.

When converting production figures to barrels of oil equivalent, boe, it needs to be considered that — due to factors such as different API gravities — the number of barrels (bbl) corresponding to one metric ton (t) could vary from below 7 to above 8 (bbl/t). For US crude an average figure of 7.33 bbl per metric ton has been specified.⁷) Applying this conversion factor to the global energy production of 13.05 bn toe in 2014 reveals a daily production of roughly 262 million boe per day (out of which about 32.3% refer to oil, 24.0% to natural gas, 30.1% to coal, 6.7% to hydropower, 4.4% to nuclear and 2.4% to renewable energy). The daily production rate of the world’s largest oil producer — Saudi Arabia — for 2014 was in comparison 11.5 mn barrels of oil per day.

With a view to total energy produced in 2014 in terms of calorific value, the conversion to heating values, (measured in million British thermal units, MM BTU) depends again on the crude quality. The calorific value for various types of crude oil differs within a range of about 5.6 MMBTU to 6.3 MMBTU per barrel. For US crude a nominal conversion factor of 5.8 MMBTU per barrel has been applied as an approximation for high heating values, HHV, which reflect the energy content equivalent to one barrel of crude oil.⁸) On the basis of this figure (5.8 MMBTU/bbl) the high heating value of one metric ton corresponds to 42.5 MMBTU.⁹) World energy production in oil equivalent terms was in 2014 in the order of 13.05 bn boe, which translates to about 547 quads (with one quad being equivalent to one quadrillion, 10¹⁵, BTU).

However, it needs to be considered that the calorific value of coal and gas on a metric ton basis — rather than on a metric ton oil equivalent basis — would differ from that of oil. The calorific values of coal actually vary between 10 MMBTU to 30 MMBTU per metric ton, depending on coal quality. The lower values correspond to lignite coal, while high values are an indicator for anthracite coal. Average values for coal such as 25.2 MMBTU per short ton and 27.8 MMBTU per metric ton have further been used. For US coal an average value of 20.9 MMBTU per short ton could be assumed.¹⁰

Natural gas — containing mainly (although not entirely) methane — exhibits an average gross heating value between 900 and 1100 BTU per standard cubic foot, SCF. For natural gas in the US an average value of 1028 BTU per SCF was calculated.¹¹

Industry-wide the standard approximation used for the gross heating value of natural gas is 1000 BTU/SCF. 6000 cubic feet (~170 cubic meters) of natural gas is otherwise often used as a rough measure to convert standard cubic feet to barrel of oil equivalent, while 1 boe = 6000 SCF.¹²

The annual gas production in 2014 (100%) was 3.46 trillion cubic meters (TCM) or roughly 122 TCF. North America has produced 27.4% of this quantity out of which 21% came from the United States, the worlds biggest gas producer in 2014. South and Central America have produced 5.1% with Trinidad and Tobago being the largest producers with a global market share of 1.2%. In Europe and Eurasia, 29% of total quantities were produced with Russia dominating Eurasian production with a global market share of 16.7%. Middle East production was otherwise at 17.4% with Qatar (5.1%), Iran (5%) and Saudi Arabia (3.1%) being the largest regional producers. In Africa (5.9%) most of the gas production came from Algeria (2.4%) and Egypt (1.4%). The Asia-Pacific had a share of 15.3% in global production, while China (3.9%), Indonesia (2.1%), Malaysia (1.9%) and Australia (1.6%) were the main gas producers in this region.

Countries with substantial gas production (in terms of %-share in 2014-production) further include: Canada (4.7%), Norway (3.1%), Turkmenistan (2%), Mexico (1.7%), UAE (1.7%), Uzbekistan (1.7%), Netherlands (1.6%), Thailand (1.2%), Pakistan (1.2%), UK (1.1%), Nigeria (1%) and Argentina (1%), while all other countries remain below the 1% threshold.

1.2.3. Consumption

Natural gas consumption in 2014 has reached globally an amount of 3.39 trillion cubic meters (TCM) or roughly 120 TCF. This difference of consumption, being about 2% lower than production, is due to factors such as natural gas and LNG in storage (as well as disparities in the measurement and conversion).

Regional gas consumption in 2014 was in North America at 28% of total consumption out of which the USA has counted for 22.4%, as the world’s largest consumer of natural gas. South and Central America has consumed 5% of global amounts, while Argentina (1.4%) was the largest consumer in this region. In Europe and Eurasia — with 29.8% the words leading gas consuming region — Russia was the largest consumer with 12.1% of global consumption — followed by the industrial nations of Western Europe, particularly Germany (2.1%), the UK (2%), Italy (1.7%) as well as Turkey (1.4%), Uzbekistan (1.4%) the Ukraine (1.1%) and France (1.1%). (The relatively low gas consumption in France could be explained with France’s extraordinary high share in nuclear energy production.) It is worthwhile to note that Euroasia was the only region worldwide having reduced its gas consumption vis-à-vis last year by about 5%. Western European countries in comparison have reduced their natural gas consumption by about 10 to 15%.

In the Middle East (13.7%) the country with the highest natural gas consumption was Iran (5%) followed by Saudi Arabia (3.2%) and the UAE (2%). In Africa (3.5%) the prime gas consumer is Egypt (1.4%). For the Asia Pacific Region (20%) the largest consumers were China (5.5%), Japan (3.3%), South Korea (1.4%), Thailand (1.6%) and India (1.5%). Other countries with a substantial share in world gas consumption in 2014 were: Canada (3.1%), Mexico (2.5%), Uzbekistan (1.4%), Pakistan (1.2%), Malaysia (1.2%), Brazil (1.2%), Ukraine (1.1%), Indonesia (1.1%) and Algeria (1.1%). All other countries — including Venezuela (0.9%) and Australia (0.9%) — remain below 1% of global consumption in 2014.

The world’s largest gas consumers in 2014 have consequently been the USA (22.4%), Russia (12.1%) and Iran (5%). (The high gas consumption of oil producing countries such as Iran could partially be explained by the use of natural gas for injection purposes to boost up pressure in oil reservoirs.)

In case of oil, the USA (19.9%) has again been the largest consumer followed by China, incl. Hong Kong (12.8%) and Japan (4.7%).

When it comes to coal China has consumed in 2014, with 50.8% of global consumption, half of the coal produced worldwide, followed by the U.S. (11.7%), India (9.3%) and Japan (3.3%).

With respect to the consumption of nuclear energy, the USA takes the lead again with 33.1%, followed by France (17.2%), Russia (7.1%), South Korea (6.2%), China (5%), Canada (4.2%) and Germany (3.8%). It is worthwhile to note that Japan, which had up to 2009 a share in global nuclear consumption of about 10%, has since drastically reduced its exposure to nuclear power and has consumed in 2013 only 0.6% of nuclear energy produced worldwide. By 2014 Japan’s share has reduced to 0% since it has become the first industrial nation that has abandoned commercially generating nuclear power.

The consumption of hydropower is otherwise highest in China (27.4%), which has massively expanded its hydro-generating capacity during the last decade. Canada (9.7%) and the USA (6.7%) otherwise had a combined share of 16.4% of global consumption of hydropower in 2013, while Brazil follows with 9.5%.

Concerning the consumption of renewable energy, in 2014 the US has consumed 20.5% of global supplies, whereas China has consumed 16.8% and Germany 10%.

The global consumption of primary energy in 2014 (including all of the above sources of energy) was almost 13 billion tonnes of oil equivalent (12.93 bn toe) out of which China’s share was highest with 23% followed by the USA (17.8%), Russia (5.3%), India (4.9%), Japan (3.5%), Canada (2.6%) and Germany (2.4%).

1.2.4. Natural Gas: Production — Consumption — Balance

The country with the largest surplus of natural gas production over consumption is Russia, which had in 2014 the potential to export 169.5 billion cubic meters (BCM) or 6 trillion cubic feet (TCF). Qatar had an export potential of 4.7 TCF followed by Norway (3.7 TCF) and Canada (2 TCF). The export potential of other large gas producers has been listed in Table 2 below.

The country with the largest imports of natural gas was Japan, which has consumed in 2014 about 3.9 TCF more than what it has produced (see following Table 3). Other large gas importers were Germany (2.2 TCF), China (1.8 TCF), Italy (1.8 TCF), Turkey (1.7 TCF) and South Korea (1.7 TCF). Even the USA — the world’s largest gas producer — has produced during recent years less than the amount of natural gas it has consumed, with that difference being in 2014 about 1.1 TCF (as indicated in Tab.3 below).

Saudi Arabia, Pakistan and Venezuela have otherwise produced in 2014 almost the same amount of natural gas as consumed. Kuwait had to import a rather small amount of 0.1 TCF, while imports for the UAE and Argentina were 0.4 TCF. The natural gas consumption of the UK was in comparison by about 1.3 TCF higher than its production. (A more detailed breakdown by country has been provided in the Appendix¹³ to this section).

1.2.5. Pricing

Natural gas is generally priced according to its calorific value. US Dollar per million BTU ($/MMBTU) is one of the most commonly applied units of reference for gas pricing. Prices further deviate according to regional differences in gas markets. Two price indexes — the German Import Price (G-Import) and the gas price at Henry Hub (HH) in Louisiana — are two gas reference prices commonly used.

In the case of oil the quotations in US Dollars per barrel ($/bbl) for West Texas Intermediate (WTI) and Brent (North Sea) quality crude are the two most renowned reference prices for crude oil.

Concerning coal prices, the Northwest Europe marker price (NWE) and the US Central Appalachian coal spot price index (CAAP) represent two standard price indexes (in USD per metric ton, $/t) for coal.

Table 4 below provides in three sections an overview of the development of these prices during the last 25 years from 1990 to 2014.¹⁴

On the basis of heating values the above prices could further be converted to a common unit in terms of barrel of oil equivalent, boe. By applying the conversion factor of 5.8 MMBTU per barrel the above gas prices could be quoted in boe-terms. For coal, the conversion factor used was 27.8 MMBTU per metric ton (in connection with a value of 5.8 MMBTU per boe) in order to arrive at a coal price on an energy equivalent boe-basis. Figure 2 (below) provides in a schematic form the result of such conversions to common boe values.

Apart from general price fluctuations in the energy markets the following tendencies become viable as a result of an analysis of Fig.2:

1. In terms of boe, the energy content of one boe of coal, gas or oil is the same (i.e. 5.8 MMBTU). The huge variations in prices for different types of fuel — although with an equivalent heating value — need to be explained through regional and quality differences, as well as transport barriers (especially in the case of natural gas) that prevent market prices from converging.

2. The price gap for different types of fuel in Fig.2 was rather narrow in the 1990s. During this period the relative equality in terms of energy content was reflected as well by energy prices. Since about 2000, the gap between different fuels (with equivalent heating values in terms of boe) has dramatically widened over the years. European energy prices for oil (Brent), gas (G-import) and coal (NEW) have traded during more recent years markedly above comparable prices in the US (WTI, HH, CAAP). This deviation of prices on both sides of the Atlantic was less pronounced during previous years (prior to 2006).

3. While energy prices in Europe fluctuate largely in tandem with movements in the oil market, the pricing structure in the US seems not to entirely correspond to this pattern. Natural gas at Henry Hub has traded (on the basis of energy equivalent prices) since the mid 1990s for about one decade in proximity with fluctuations in oil prices.

During more recent years, the Henry Hub gas price has become largely unlocked from oil price mechanisms and has since moved rather towards coal price levels. (Only during 2014 an increase in Henry Hub gas prices vis-à-vis coal prices could be monitored, while German gas import prices in 2014 came slightly down.) These low gas prices have been supported by the shale gas boom in the United States. The US was in 2014 again the world’s largest gas producer. Gas prices in Europe have been comparably high during recent years, causing independent power producers to run their plants on coal rather than natural gas. The diversification of energy supplies, as well as a re-evaluation of shale gas opportunities in Europe, seems to remain a decisive factor to keep European economies at a competitive level.

Appendix: Natural Gas: Production — Consumption — Balances

References (1)

1) Not every commonly used term in the oil and gas industry has been fully explained in this text, especially when not specifically related to natural gas. The reader is advised to use supplemental literature for a brief explanation of oil industry terms such as: "A Dictionary for the Petroleum Industry, 3rd ed., University of Texas at Austin, Petroleum Extension Service, PETEX, Austin (TX), 1999 or R. D. Langenkamp, Handbook of Oil Industry Terms & Phrases, 5th ed., PennWell, Tulsa, 1994. A more recent PETEX edition in this context is: A Dictionary for the Oil and Gas Industry", 1st ed., University of Texas at Austin, Petroleum Extension Services, PETEX, Austin (TX), 2005.

2) For an overview see: Ron Baker: A Primer of Offshore Operations, 3rd ed., Univ. of Texas, Austin, 1998.

3) The principles associated with economic modeling in the oil and gas industry have been summarized in R. D. Seba’s Economics of Worldwide Petroleum Production, 2nd printing, OGCI Publications, Oil & Gas Consultants International, Tulsa (OK), 1998, p.155-202.

4) For a general overview of the operational aspects of the oil and gas industry see: C. F. Conaway’s, The Petroleum Industry. A Nontechnical Guide,, PennWell, Tulsa, 1999.

5) For a description of integrated oil companies, natural gas companies and gas utilities with a focus on North America see: J. Duarte, Successful Energy Sector Investing. Every Investor’s Complete Guide, Prima Ventura, Roseville, 2002, pp. 121-152, pp.239-281 and pp. 341-387.

6) See: BP Statistical Review of World Energy June 2015, BP p.l.c, London, 2015, p. 6, 20, 30 (for reserves figures) and p. 10, 24, 32 for production-, respectively pp. 11, 25, 33-41 for consumption figures.

7) See: US Department of Energy, International Energy Annual 1993, Energy Information Administration Report DOE/EIA-0219(93), Washington DC, 1995.

8) With reference to the conversion factor of 1 BOE = 5.8 MMBTU see: A. H. Cooper, US Internal Revenue Service publication, Part III — Administrative, Procedural, and Miscellaneous, Section 29(d)(5) and (6), p.3.

9) This conversion factor corresponds to data published by the International Institute for Applied Systems Analysis but otherwise deviates from data published by the OECD, which sets the HHV for crude oil at 39.68 MMBTU per metric ton. For more details see: 2010 American Physical Society, Site: Energy Units, Conversion factors for oil.

10) See: US Department of Energy, Annual Energy Review 1995, Energy Information Administration Report DOE/EIA-0384(95), Washington D.C., 1996.

11) See: US Department of Energy, Annual Energy Review 1995, Energy Information Administration Report DOE/EIA-0384(95), Washington D.C., 1996.

12) See: United States Geological Survey (USGS), US Geological Survey World Energy Assessment Team, US Geological Survey World Petroleum Assessment 2000 — Description and Results, Table AR-1). Converting one BOE to 6000 SCF and applying the conversion factor of 1028 BTU per SCF results in 6.2 MMBTU per BOE, which deviates from the figure of 5.8 MMBTU per BOE, as applied by the US Internal Revenue Service.

13) Natural gas production figures for France, Japan and South Korea (all 2012 est.) are from: Central Intelligence Agency (CIA), The World Factbook, Country Comparison: Natural Gas Production / Consumption. The natural gas production figure for Turkey (2012) has otherwise been taken from: G. Rzayeva, Natural Gas in the Turkish Domestic Energy Market: Policies and Challenges, The Oxford Institute For Energy Studies, University of Oxford, Feb. 2014, p.42. Natural gas consumption figures for Nigeria and Oman (2013) are from O&G World Oil and Gas Review 2014 issued by ENI, Rome, 2014, p.55. All other figures are from: BP Statistical Review of World Energy June 2015, BP p.l.c, London, 2015, p. 22-23.

14) Brent and WTI prices are published daily by a variety of organizations and specialized publishing companies such as Platts. The German Import Price is published by the German Federal Office of Economics and Export Control (Bundesamt für Wirtschaft und Ausfuhrkontrolle, BAFA), while the Henry Hub gas price could, for example, be gained from Natural Gas Week published by the Energy Intelligence Group. NWE-marker prices are otherwise based on data provided by McCloskey Coal Information Services. CAAP fob prices are based on data published by Platts. (The value of CAAP as a 12,500 BTU per pound coal corresponds to 27.6 MMBTU per metric ton.) The sources and prices as above have been quoted after BP Statistical Review of World Energy June 2015, BP p.l.c, London, 2015, p. 15, 27 and 30.

2

Natural Gas: Origins and Geological Environment

Raw gas accumulates in rock formations in the earth’s crust. The gases contained in raw gas are mainly hydrocarbon gases, as well as nitrogen, carbon dioxide, hydrogen, hydrogen sulfide and, infrequently, noble gases (especially helium and argon). In addition to these gases water vapor is usually present as well in raw gas.

Occasionally, raw gas is also referred to as natural gas with a view to the hydrocarbon gases contained within it.

The term natural gas is otherwise often used with reference to hydrocarbon gases with less than five carbon (C) atoms, which are produced from a reservoir and appear on the surface in a gaseous state. These gases are: methane (C1), ethane (C2), propane (C3) and butane (C4). Condensate (C5+) is often produced together with natural gas and condenses out on surface as a liquid, while accumulating in the reservoir in the vapor phase.

For the purpose of gas marketing the treated and processed gas (i.e. sales gas) is called natural gas or methane-natural gas, since it consists primarily of methane. In context with other fossil fuels — such as oil and coal — natural gas is sometimes simply referred to as gas.

Raw gas originates from a hydrocarbon reservoir where it is contained within the pore space of a reservoir rock. These fossil natural gas deposits in porous rocks represent the main source of natural gas reserves worldwide. Raw gas could either be found in a gas reservoir or accumulate together with oil in an oil reservoir. Other sources of methane include coalbed methane, gas hydrate accumulations, biogas and manufactured gas.

This chapter is mainly concerned with an introduction to the geological origins of fossil natural gas in reservoir rocks, including a brief overview of unconventional gas resources such as biogenic gas, tight sands, gas shale, coalbed methane and gas hydrates.

2.1. Geological Principles and Parameters

The origins of natural gas and the geological environment concerning gas reservoirs are going to be briefly discussed in the following section.

2.1.1. Origins of Natural Gas

Almost all theories dealing with the origins of natural gas — respectively hydrocarbon fluids in general — regard hydrocarbons to have formed from organic material (such as plankton) that has been buried during a sedimentation process (biogenic theory). Sedimentary basins consequently form the prime target for the exploration of hydrocarbons.

Theories associated with abiotic- or abiogenic gas, (which hint at the origins of natural gas on earth from lifeless, inorganic material) have otherwise not received widespread recognition. According to proponents of this theory, notably Thomas Gold, natural gas forms on the basis of a reaction of meteoritic carbon with hydrogen during the entering of meteors in the earth’s atmosphere. (In this context it might also be worthwhile to note that hydrocarbon substances, especially bitumen, have been identified in meteorites as well.) Abiogenic gas has further been explored for in Sweden, in depths below 6,000 meters, where gas deposits were expected in fractured granite, basement rocks. In 1986-1987 the theory of abiogenic gas was tested when Vattenfall has drilled the Gravberg-1 well to 6,700 m in the Siljan Ring area in Sweden, which was formed by meteorite impact. Although traces of methane — together with hydrogen and helium — were found at various depths, this well has ultimately failed to sufficiently support the theory of the abiotic origin of natural gas on earth. When the Stenberg-1 well was drilled subsequently this result could be confirmed (although some gas was produced in non-commercial quantities).

Although for the formation of hydrocarbons on earth the biotic theory applies, it should be kept in mind that methane — necessarily of abiotic origin — exists on many planets and moons of our solar system.

An example for hydrocarbon gases of abiotic origin could be provided with the liquid hydrocarbon lakes of Titan (Saturn VI, the 6th moon of Saturn). These lakes are considered to mainly consist of liquid methane.¹ Temperatures on Titan need consequently to remain below the boiling point of methane (minus 162°C) in order for these lakes to remain stable on surface. Titan is a moon with an atmosphere that consists of about 1.6 to 2% methane. While water, or H2O, is the condensable liquid circulating between surface and atmosphere of the earth it was originally considered by scientists to be replaced by methane (CH4) in the case of the atmosphere of Titan. The atmosphere of Titan was further believed to consist of about 98% nitrogen, 2% methane, as well as traces of other hydrocarbons and non-hydrocarbon gases. In this context the lakes of Titan were believed to be replenished by methane rain and liquid methane rising from Titan’s subsurface. Cryovolcanism — i.e. volcanic activity involving cryogenic temperatures — has further been assumed to play an important role in influencing the atmosphere of Titan.

When the Huygenes space-capsule landed in 2005 on Titan, robots measured only vast desert areas but no liquid methane lakes or oceans. From further measurements of Saturn’s space probe, Cassini, the conclusion has otherwise remained that vast liquid accumulations exist on Titan but below surface. As Titan turns around its axis with varying speed — causing Titan’s days to differ in length — the question remains as to what causes these irregular rotations. A huge liquid accumulation, possibly liquid methane, between the core and the crust of Titan is currently believed to cause these rotational irregularities.

Evidence of methane in the atmosphere of Mars was also reported in connection with the mission of Mars Express Orbiter in 2004. Makemake, a dwarf planet in the Kuiper belt, is otherwise considered exhibiting an atmosphere containing methane. Since the surface temperature of Makemake is only minus 243°C it is believed to be covered with methane and ethane ice, as well as nitrogen ice.

For Pluto and Eris (another Kuiper belt object) the presence of methane has also been reported. Copolymer molecules — known as tholin — formed through ultraviolet irradiation of nitrogen and methane could as well be found on Titan and Triton (a moon of Neptune). Tholin is a substance (originating from methane), which could not be found naturally on earth. Astronomers otherwise consider HR 4796A, — a stellar system in a distance of 220 light-years from earth, — to contain tholin as well. (This proposition was based on data received from the near-infrared part of the light spectrum.) On the basis of electromagnetic radiation, methane could also be detected as a component of interstellar clouds outside our solar system. HD 189733 b — an extrasolar planet about sixty-three light-years away from earth — is thought to contain methane in its atmosphere.

Another indication for the existence of abiotic, methane gas in the universe is provided by certain Jovian planets (more commonly referred to as gas giants). These gas giants are planets that consist primarily of gases instead of solids or rocks although they contain a solid core. In our solar system four such planets exist, which are Jupiter, Saturn, Uranus and Neptune. Although the gases of Jupiter and Saturn consist mainly of hydrogen and helium they contain ammonia and methane ice, which also goes for Uranus and Jupiter. Methane is otherwise thought to be present on Comet Hyakutake as well and was identified in traces on Halley’s Comet.

Hydrocarbon gases of abiotic origin consequently exist in large quantities in the universe. Audacious theorizers have even tried to link cosmic, abiotic gas to a biotic origin by arguing that methane in space represents the remains of life previously existing in the universe.

Based on biotic theory all hydrocarbons on earth are regarded as originating from organic matter. Biotic theory considers kerogen to form as an intermediate substance from the originally buried organic material. Kerogen, gaining hydrogen from its surroundings, forms the basic building block for the formation of hydrocarbons. In a hydrogen-poor environment mature kerogen is otherwise the base material for the formation of graphite.

The decay of organic material that is required to generate hydrocarbon reservoirs needs to be further anaerobic, which means that it takes place without the presence of oxygen (from air).

2.1.2. Formation: Temperature, Pressure, Depth, Age and Origins

Two fundamental environmental conditions for the formation of hydrocarbons are provided by the surrounding temperature- and pressure. In a geological environment dominated by sedimentation these temperature and pressure conditions are influenced by depth, which could be linked to geological age.

Tab.1 represents an attempt to describe a relationship between temperature, pressure, depth and geological age in connection with the depth of certain types of reservoir fluids.².

At original reservoir conditions prior to production, the reservoir pressure could be assumed to be in the geostatic (or lithostatic) pressure range, as indicated in Tab.1. The values for the geostatic pressure gradient in Tab.1 represent an assumption, which has been made in order to illustrate general tendencies. Actual reservoir pressure — i.e. shut in bottomhole pressure — needs though to be determined individually via well testing since every pressure and temperature gradient should be viewed upon as unique and valid only for a specific geological environment.

As long as actual reservoir pressure has not been measured, the general assumption made for the prevailing pressure regime is hydrostatic pressure. Hydrostatic pressure is dominated by the weight of the fluid column above the formation rocks. In terms of bar and meterers, a pressure build-up of 100 bar per kilometer of depth has to be taken into consideration in case of hydrostatic pressure. This increase in pressure corresponds to a pressure increase in tandem with water depth in an ocean where pressure increases by 1 bar for every 10m of water depth. (In a water depth of 1000 meter the prevailing pressure would consequently be about 100 bar.)

As highlighted earlier, the assumption of a hydrostatic pressure regime is only an estimate linked to a geological world associated with sedimentation. Movements of the earth’s crust, especially the movement of plates (plate tectonics), could substantially increase formation pressure, due to additional tectonic pressure.

2.1.2.1. Temperature-, Geothermal- and Pressure Gradients

With an increasing distance from surface to the interior of the earth the temperature and pressure increases.

Temperature: Under average conditions of heat flow within the earth’s crust a rough indication for the geothermal gradient could be provided by assuming an increase in temperature of about 1.5°F with every 100 feet of incremental depth, which corresponds to about 50ºF or 10ºC per kilometer (see Fig.1 below). Temperature gradients of individual reservoirs remain otherwise influenced by a number of factors such as the formation’s conductivity for heat and the regional heat flow. According to the second law of thermodynamics, heat flows from hot to cold i.e. from the interior of the earth to surface. Especially where the tectonic plates collide the geothermal gradients are considerably higher.

Pressure: Two pressure regimes can generally be identified as influencing formation pressure. One is characterized by lithostatic pressure — also called geostatic pressure — while the other one is the hydrostatic pressure regime.

Hydrostatic pressure refers to the weight of the water column above a reference point of measurement and is characterized by a pressure increase per foot of depth of 0.433 psi/ft in fresh water and 0.465 psi/ft in saline water. If pressure throughout the geological section is determined by a column of either fresh or saline water, the associated pressure regime is referred to as normal hydrostatic pressure.

An oil column would otherwise exert a pressure of only 0.346 psi/ft whereas in the case of natural gas the pressure exerted by the gas column above was only 0.043 psi/ft. The average density for these pressure gradients would be 0.8 g/cm³ for oil and 0.1 g/cm³ for gas. Confined reservoirs exhibiting a pressure regime corresponding to a hydrocarbon fluid column are consequently determined by conditions of underpressure.

Underpressurized zones are usually preceded by a transitional zone where the formation pressure shifts e.g. from normal hydrostatic pressure to underpressure. Drilling through an underpressured zone with a mud weight corresponding to hydrostatic pressure could consequently cause formation damage through loss of drilling fluid to the formation. (In case such fluid losses occur suddenly the pressure within the wellbore reduces quickly from hydrostatic pressure to atmospheric pressure and the casing used must be strong enough to avoid collapse.)

Lithostatic pressure is otherwise due to the weight of the rock strata above, whereas hydrostatic pressure is due to the weight of the fluid,- or rather water column, above. Hydrostatic pressure could also come from an aquifer below the reservoir once formation pressure has reduced due to continuing production. At this point water from the aquifer can flow into the reservoir and increases formation pressure. The pressure of an aquifer could otherwise be estimated to be at hydrostatic levels ( since the compressibility of water is negligible).

Geostatic pressure (i.e. lithostatic pressure) is caused by the weight of the overburden of the sediments. This pressure represents the maximum pressure the rock strata could sustain without failure.

In petroleum operations fracking technologies could further be applied, which aim at increasing formation pressure above geostatic pressure. During fracing operations so called frac-fluids are pressed into the reservoir in order to exceed lithographic pressure and to fracture the rock formation, which improves permeability and hence fluid flow to the wellbore.

Geological movements of tectonic plates could also cause formation pressure to exceed the original, geostatic pressure level.

On the basis of the assumptions made in Tab. 1, an average geostatic pressure gradient could be derived. This average is estimated to be reflected by an increase of about 1 psi per incremental foot of depth. That increase in pressure corresponds to more than twice the increase in hydrostatic pressure as indicated by the gradients in Fig. 2 below.

All rock formations with a prevailing pressure regime in between hydrostatic and geostatic pressure (i.e. above normal hydrostatic pressure) are referred to as overpressured formations. That overpressure corresponds to an overburden pressure, which indicates the amount of additional stress exerted on the rock matrix.³ Fluids from a reservoir located in an overpressure zone flow to the wellbore with abnormally high pressure. Once reservoir fluids have been produced the stress on the rock matrix due to overpressure increases. That difference between geostatic and normal hydrostatic pressure is of added importance for gas reservoirs since gas is compressed by additional lithostatic pressure, (while liquids remain almost incompressible).

Compression due to the movement of rocks linked to plate tectonics, as well as rapid deposition of sediments, (which creates an additional thickness of sediments) represents the two major causes of overpressure.

Similar to underpressured formations reservoirs with overpressure are usually preceded by a transitional zone where the pressure regime changes within the rock strata; this time from hydrostatic to geostatic pressure.

Fig. 3 aims to provide an indication for the tendency in the relationship between hydrostatic-, geostatic- and overburden pressure with reference to depth and measurement in terms of bottomhole pressure.

Drilling unprepared into an overpressured formation creates a major hazard for the drilling crew. When drilling for example with water-based mud in a cased-hole, where the casing is sealing off the wellbore from formation pressure around it⁴), the pressure within the borehole remains purely hydrostatic (unless a weighting agent was added to the mud). With oil-based mud the oil hydrostatic pressure is even lower than the water hydrostatic pressure. When a reservoir with a geostatic pressure regime is drilled by using a drilling fluid with a lower hydrostatic pressure, the reservoir fluids swiftly press towards bottom-hole and continue flowing up the wellbore. If there is no restriction to flow the entire mud column (governed by hydrostatic pressure) gets moved upwards, which leaves the reservoir fluids to flow unrestricted to surface and blow out there. Only if the blowout preventer (i.e. BOP stack) can be closed in time such a scenario could be avoided by stopping all fluid flow at the wellhead. In order to avoid such a situation from occurring the weight respectively density of the drilling mud needs to be increased by the using agents that increase the weight of the mud such as barite, i.e. barium sulfate, BaSO4,⁵ in case of water- based mud.

Once a well is completed (and all casing has been cemented into place) a flowpath can be established through the tubing and reservoir fluids can be produced safely from the wellhead at surface. During production, the pressure- and temperature conditions for the flowing reservoir fluid change from a high pressure / high temperature environment in the reservoir (respectively bottomhole) to a low pressure / low temperature environment at the surface. When production continues reservoir pressure decreases as well due to depletion.

2.1.2.2. Geological Depth and Petroleum

With reference to Tab.1, it could be pointed out that the horizons associated with the Paleozoic Era are not considered to be highly prolific in terms of holding hydrocarbon reservoirs. Most of the source rocks of hydrocarbon reservoirs date back to rock layers of the Mesozoic Era. During the Mesozoic it was especially the Cretaceous period that was most productive.

The order of deposition of the sedimentary layers — as in Tab.1 (suggesting for geologically younger layers to

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